well control manual
advertisement
WELL CONTROL MANUAL Introduction and How to Use Volume 1 Procedures and Guidelines Volume 2 Fundamentals of Well Control BP EXPLORATION © 1995 British Petroleum Company PLC Text originated by BP Drilling Department Manual produced by ODL Publications, Aberdeen, Tel (01224) 637171 BP WELL CONTROL MANUAL WELCOME Click here to zoom in on text, then click on text to scroll through Ladies and Gentlemen: Following is the Second Edition of the “BP Well Control Manual” first issued in 1987. When issued it was expected to be a living document, accounting for changes in technology and experience, it still is. Now, eight years later, horizontal and extended reach wells, coil tubing drilling and under balance drilling have or will become part of our kit for improved profitability. Our objective with this Second Edition is to bring three changes to the operating groups: 1) Issue the manual in an electronic version as a pilot which may lead to collecting all of the manuals on a server or CD-ROM. 2) Make available Excel based well control worksheets which have been incorporated into the manual. 3) Modify parts of Volume I Chapters 1 and 6 for high angle and horizontal well operations. In a separate file we have issued the “HTHP Well Control Manual”. Future updates will tie this manual with the “BP Well Control Manual”. Publication of the manual in electronic format should make the abundance of information in it more accessible to you. A powerful search capability and “hot button” references are part of the software package we have selected. Software used is compatible with Macintosh, MS-DOS and DEC hardware platforms making it accessible to BP and our contractors when needed. Electronic publishing makes modifications easier and we solicit your suggestions for correction, clarification, change or addition to the manual. If we have not managed to make the resource more useful and clear to you we have failed our objective. Your views on how well we have done are important. To open and use the manual please read the section below. While use of the electronic version of the manual is encouraged there is still the option of printing a hard copy of the manual. Hard copies can still be obtained from ODL in Aberdeen at a cost for printing and shipping. Originally this manual was not issued as “policy”. In the October 1994 Drilling Managers Meeting this and two other documents, the “Drilling Policy Manual” and “Casing Design Manual”, were designated as the three core policy documents covering our operations. Every effort has been made in this edition to tie to the other two documents. March 1995 BP WELL CONTROL MANUAL HOW TO USE This manual has been converted into Adobe Acrobat software and is a ‘read only’ version, ie you cannot make any changes to text or figures, you can copy the text and figures and paste them in to another application. Navigating through the Manual When you have read this you will be able to navigate quickly through the manual, to and from volumes, sections, subsections and figures. Clicking the mouse on the `Main Contents' button at the bottom of this page will take you to the Well Control Manual overall contents list, ie Volume 1 or 2. For additional help use the Acrobat Help files. The header at the top of each page has been hot spotted, to return you to the Main Contents page of the Volume you have selected. To go back or forward to a previous move you have made, use the Acrobat arrows in the Menu Bar. Once you have reached the section you require (e.g. 1.1 General), the hand cursor will appear with an arrow inside it. Press the mouse button on the section you require to read, and you will be zoomed into the section, press it again and it will scroll through that section, at the end of the section it will reset to the beginning of the section. Excel Worksheets Each example of a Worksheet in the manual is linked to a blank Excel Template for you to use for your own calculations, just click on the example Worksheet and Excel will automatically open. To return to the manual, simply Quit out of Excel. Printing When printing to a US Letter size printer please click on the “Shrink to Fit” box in the Print dialogue box. Printing of Excel Worksheets is through Excel. Manual Contents March 1995 BP WELL CONTROL MANUAL Volume 1 – Contents Nomenclature Abbreviations 1 PREPARATION Section 1.1 1.2 1.3 1.4 1.5 Page INSTRUMENTATION AND CONTROL MANPOWER ORGANISATION DRILLS AND SLOW CIRCULATING RATES USE OF THE MUD SYSTEM KICK TOLERANCE 1-1 1-9 1-15 1-27 1-35 2 THE PREVENTION OF A KICK Section 2.1 2.2 2.3 CORRECT TRIPPING PROCEDURES MAINTAIN SUITABLE HYDROSTATIC PRESSURE CONTROL LOST CIRCULATION 2-1 2-9 2-17 3 WARNING SIGNS OF A KICK Paragraph 1 2 3 4 5 GENERAL DRILLING BREAK INCREASED RETURNS FLOWRATE PIT GAIN HOLE NOT TAKING CORRECT VOLUME DURING A TRIP 6 CHANGE IN PROPERTIES OF RETURNED MUD 7 INCREASE IN HOOKLOAD 8 CHANGE IN PUMP SPEED OR PRESSURE 3-2 3-2 3-2 3-3 3-4 3-6 3-6 March 1995 BP WELL CONTROL MANUAL 4 ACTION ON DETECTING AN INFLUX Section 4.1 4.2 4.3 Page SHALLOW GAS PROCEDURE SHUT-IN PROCEDURE DURING SHUT-IN PERIOD 4-1 4-9 4-17 5 WELL KILL DECISION ANALYSIS Paragraph 1 2 3 4 5 6 7 GENERAL PIPE ON BOTTOM PIPE OFF BOTTOM – (Drillpipe in the Stack) PIPE OFF BOTTOM – (Drillcollar in the Stack) NO PIPE IN THE HOLE WHILE RUNNING CASING OR LINER UNDERGROUND BLOWOUT 5-2 5-2 5-2 5-5 5-5 5-7 5-9 6 WELL KILL TECHNIQUES Section 6.1 6.2 6.3 March 1995 STANDARD TECHNIQUES – Wait and Weight Method – Driller’s Method SPECIAL TECHNIQUES 1. Volumetric Method 2. Stripping 3. Bullheading 4. Snubbing 5. Baryte Plugs 6. Emergency Procedure COMPLICATIONS 6-1 6-2 6-3 6-31 6-33 6-47 6-67 6-75 6-84 6-93 6-97 BP WELL CONTROL MANUAL NOMENCLATURE SYMBOL DESCRIPTION UNIT A a An b c C Cp Ca CL CR D Dshoe Dwp dbit dh dhc do di dcut dc F Fsh FPG g G Cross sectional area Constant Total nozzle area Constant Constant Annular capacity Pipe capacity Cuttings concentration Clinging constant Closing ratio Depth Shoe depth Depth of openhole weak point Bit diameter Hole diameter Hole/casing ID Pipe OD Pipe ID Average cuttings diameter Drilling exponent (corrected) Force Shale formation factor Formation Pressure Gradient Gravity acceleration Pressure gradient Gi H Hi Hp ITT K L λ MR M m MW Influx gradient Height Height of influx Height of plug Interval Transit Time Bulk modulus of elasticity Length Rotary exponent Migration rate Matrix stress Threshold bit weight Mud weight in.2 – in.2 – – bbl/m bbl/m % – – m m m in. in. in. in. in. in. – lb – SG – psi/ft psi/m SG psi/ft m m m µsec/m m – m/hr psi lb SG March 1995 BP WELL CONTROL MANUAL SYMBOL DESCRIPTION UNIT N OPG P Rotary speed Overburden Pressure Gradient Pressure ∆P Pa ∆Pbit Pcl Pdp Pf Pfrac Pfc Pi Pic Plo Pmax S Sg Sw t Adjustment pressure Annulus pressure Bit pressure drop Choke line pressure loss Drillpipe pressure Formation pressure Fracture pressure Final circulating pressure Hydrostatic pressure of influx Initial circulating pressure Leak off pressure Maximum allowable pressure at the openhole weak point Wide open choke pressure Pore pressure Slow circulating rate pressure Plastic Viscosity Flowrate Mud flowrate Gas flowrate Reynolds number Resistivity Resistivity of water Rate of Penetration Shale factor Overburden pressure Gas saturation Water saturation Time rpm SG psi/SG (The units of subsurface pressure may be either psi or SG) psi psi psi psi psi psi/SG psi/SG psi psi psi psi/SG TR T Transport Ratio Temperature TD TVD V Total Depth True Vertical Depth Kick tolerance Poc Pp Pscr PV Q Qmud Qgas Re R Rw ROP March 1995 psi/SG psi psi/SG psi cP gal/min gal/min gal/min – ohm-m ohm-m m/hr meq/100g psi Fractional Fractional seconds min – degrees C, F, R m m bbl BP WELL CONTROL MANUAL SYMBOL DESCRIPTION V Volume v vmud vp vs W w w wb wcut WOB x YP Z µ ν σ’1 σ’t Ø Ø600 β ρ ρb UNIT bbl cc ml l Velocity m/min m/s Mud velocity m/min Average pipe running speed m/min Slip velocity m/min Weight gm kg lb Weight lb/ft lb/bbl SG Weight of pipe lb/ft Baryte required for weighting up lb/bbl Average cuttings weight SG Weight on Bit lb Offset () Yield Point lb/100ft2 Compressibility factor – Viscosity cP Poissons’s Ratio – Maximum effective principle stress psi/SG Tectonic stress psi/SG Porosity Fractional Fann reading lb/100ft2 Tectonic stress coefficient – Density SG Bulk density SG March 1995 BP WELL CONTROL MANUAL ABBREVIATIONS API RP BHA BOP BRT DWT ECD EMW H2S IADC ID KTOL LCM LMRP LO MAASP OBM OD PMS PV ROP SCR SG SPM YP March 1995 American Petroleum Institute Recommended Practice Bottomhole Assembly Blowout Preventer Below Rotary Table Dead Weight Tester Equivalent Circulating Density Equivalent Mud Weight Hydrogen Sulphide International Association of Drilling Contractors Internal Diameter Kick Tolerance Lost Circulation Material Lower Marine Riser Package Leak off Maximum Allowable Annular Surface Pressure Oil Base Mud Outside Diameter Preventive Maintenance System Plastic Viscosity Rate of Penetration Slow Circulating Rate Specific Gravity Strokes per Minute Yield Point BP WELL CONTROL MANUAL 1 PREPARATION Section Page 1.1 INSTRUMENTATION AND CONTROL 1-1 1.2 MANPOWER ORGANISATION 1-9 1.3 DRILLS AND SLOW CIRCULATING RATES 1-15 1.4 USE OF THE MUD SYSTEM 1-27 1.5 KICK TOLERANCE 1-35 March 1995 BP WELL CONTROL MANUAL 1.1 INSTRUMENTATION AND CONTROL Paragraph Page 1 General 1-2 2 Pressure Gauges 1-2 3 Pump Control 1-4 4 Fluid Measurement 1-6 Illustrations 1.1 Suggested Instrumentation for a Floating Rig 1-3 1.2 Suggested Instrumentation for a Fixed Installation 1-5 1.3 Suggested Fluid Measurement System 1-7 1-1 March 1995 BP WELL CONTROL MANUAL 1 General It is essential that an appropriate level of control equipment is provided on every rig in order that a well that is under pressure can be accurately monitored. In general, during a well control incident, there is a necessity for more accurate instrumentation than under conditions encountered during routine drilling. The level of instrumentation on every rig therefore must be evaluated in order to assess its␣ s uitability for well control purposes. This evaluation should ideally be carried out in␣conjunction with the pre contract rig audit and any deficiencies made good prior to contract␣award. The purpose of this section is to highlight the important aspects of instrumentation and control and to recommend a standard level of equipment for all rig types. The level of instrumentation that is recommended will ensure that a suitable level of control is afforded during unusually critical operations, and that adequate back-up is provided. Therefore, much of this equipment would not be necessary in routine circumstances. However equipment failure is most likely when the equipment is highly stressed. It is in these situations that serious incidents can develop if a suitable level of back-up instrumentation and control equipment is not to hand. 2 Pressure Gauges When a well is under pressure it is important that accurate pressure measurements can be made. Each rig will normally be equipped with gauges to read standpipe pressure and annulus pressure. The gauges that are fitted to the choke panel and at the driller’s console are often the only gauges available for well control purposes. Although the standpipe and choke manifold will generally be fitted with ‘Cameron’ gauges, these are considered to be so inaccurate as to have little application to well control. All of these gauges will have a fullscale deflection that is at least equal to the working pressure rating of the equipment. In all cases, this means that it will be necessary to install gauges of lower rating in order that relatively low pressures can be accurately recorded. This will be especially important with high pressure equipment. It is also important that suitable pressure gauges are installed at the choke manifold in case the well has to be controlled from this position. This will apply to land rigs which may be equipped only with manual chokes and the majority of rigs that are equipped with both manual and remote operated chokes. Accurate readout of pump pressure and choke pressure is, in the majority of cases, all that is required. However an extra pressure reading is required on a floating rig in order that the wellhead pressure can be monitored through the kill line. In order to be able to install additional pressure gauges it may be necessary to fabricate manifolds and install high pressure instrument hose between the choke panel and the standpipe/choke manifold. All this equipment must be rated to the working pressure of the␣equipment. 1-2 March 1995 BP WELL CONTROL MANUAL Figure 1.1 Suggested Instrumentation for a Floating Rig STANDPIPE 1 CAMERON GAUGE STANDPIPE 2 1/4in NEEDLE VALVE D TRANSDUCER K CHECK VALVE C STANDPIPE MANIFOLD HYDRAULIC FLUID INLET CHOKE PANEL CAMERON GAUGE D SW K C AC O PUMP OUTPUT MONITOR KILL LINE REMOTELY OPERATED CHOKE CHOKE MANIFOLD MANUAL CHOKES CHOKE LINE BUFFER TANK FROM BOP DRAIN OVERBOARD LINE D – DRILL PIPE K – KILL LINE POORBOY DEGASSER C – CHOKE LINE – 1/4in NEEDLE VALVES FLOWLINE – CHECK VALVE/HYDRAULIC FLUID INLET WEOX02.001 1-3 March 1995 BP WELL CONTROL MANUAL So in general: • There must be gauges available to read choke pressure, standpipe pressure and kill line static pressure in the case of a floating rig. • The above gauges must be readable from the manifold if manual chokes are fitted to the manifold. • It must be possible to easily install and remove low range pressure gauges at the choke panel and at the choke manifold. Suggested pressure recording systems for a floating rig and a fixed installation are shown in Figures 1.1 and 1.2. The proposed systems can also be used for measuring slow circulating rate pressures (SCRs). The following points should be noted from the proposed systems: • A good selection of gauges should be available. Gauges should be calibrated on a regular basis with a Dead Weight Tester. It is suggested that the gauges are checked at each BOP Test and at this stage the pressure monitors in the mud logging unit should be checked against the rig equipment. • It must be easy to change the gauges. • A hydraulic fluid hand pump should be available to purge the lines at suitable points as shown. • Consideration should be given to completely isolating the supplementary pressure monitoring system from that originally fitted to the rig. This would ensure that the original system was closed and hence in no way susceptible to leaking needle valves or misuse of the supplementary system. • Sensitive low pressure rated gauges should be removed from the system unless required. The piping and manifolding should be permanently installed. It would be a good idea to fabricate a cover for the manifolding at the choke manifold and choke panel. • The gauges that are used to measure the slow circulating rate pressures should be used to monitor well pressures in the event a kick is taken. • A stroke counter, similar to the battery operated ‘Swaco’ unit, is recommended for remote installation at the choke manifold. It should be removed when not required. A suitably isolated terminal should be located at a convenient point at the choke manifold, in order that the signal from the limit switches on the pumps can be transmitted to the counter. 3 Pump Control It is desirable that the remote control of the pump used to kill a well that is under pressure is located reasonably close to the choke operator. In most cases the rig pumps will be used. Generally, the Driller will control these pumps from a position that is close to the choke panel. Most choke panels contain a meter that displays the cumulative output of the pump. Therefore, in the majority of cases, if the well is controlled with a remote operated choke, the man on the pump will be able to co-ordinate with the choke operator. 1-4 March 1995 BP WELL CONTROL MANUAL Figure 1.2 Suggested Instrumentation for a Fixed Installation TO STANDPIPE TO STANDPIPE STANDPIPE MANIFOLD D C D C CHOKE PANEL D SW AC O 1/4in HYDRAULIC FLUID FILLED HIGH PRESSURE HOSE TO PUMP/ CHOKE PANEL FROM BOP CHOKE CHOKE PRESSURE GAUGE TO DEGASSER TO BURN PIT REMOTELY OPERATED CHOKE TO BURN PIT TRANSDUCER CHOKE MANIFOLD CAMERON GAUGE TO BURN PIT TO DEGASSER C – CHOKE LINE D – DRILL PIPE – 1/4in NEEDLE VALVES – CHECK VALVE/HYDRAULIC FLUID INLET WEOX02.002 1-5 March 1995 BP WELL CONTROL MANUAL However, if the choke manifold contains manual chokes, the choke operator may be some considerable distance from the man on the pump and a monitor of the pump output. In such cases, it is recommended that a remote pump output meter is positioned at the choke manifold. This will be especially important on land rigs which may be equipped only with manual chokes and where often the choke manifold is located at some distance from the rig floor. A further complication may arise if a kill pump or cement pump is used during a well control operation. It may become necessary to use these pumps on any rig, but the use of a relatively small displacement pump will be standard well control procedure on a floating rig that is drilling in deep water. Therefore, on a floating rig, it is desirable that it is possible to control and monitor the kill/cement pump from the rig floor. 4 Fluid Measurement During stripping operations, as well as during a volumetric kill, it is important to be␣able to accurately measure small volumes of fluid bled from, or pumped into the␣well. API RP 53 recommends that ‘a trip tank or other method of accurately measuring the drilling fluid bled off, leaked from, or pumped into a well within an accuracy of half a barrel is␣required’. Most rigs will not have suitable equipment to do this. It is usually assumed that the choke manifold lined up across a manual choke to the trip tank␣is a suitable fluid measurement system. However , in most cases this will not be a satisfactory arrangement because of the relatively large volume in the line between the choke and the tank. In general, there is a requirement for a line from the well, terminating at a manual choke positioned directly above a measuring cylinder, such as the trip tank (hydraulically activated chokes are not suitable for this application). However a bleed line from the well to the mixing tanks on the cement/kill pump may be sufficient. The most satisfactory arrangement is to use a strip tank as shown in Figure 1.3. This tank would typically have a 3 to 4 bbl capacity so that very small volumes of fluid can be measured. After bleeding into the strip tank, the tank contents can be emptied into the trip tank where the total volume of mud bled from the well, together with the mud leaked past the preventers, can be measured. Although it is not ideal, it may be sufficient to use a Lo-Torq valve instead of a␣manual choke to bleed fluid to the tank. However, during a long operation this is likely to wash out and so provision should be made to easily and quickly replace the valve. It is not recommended to bleed mud into a measuring tank that is situated in a confined area when there is a possibility that gas is entrained in the mud. 1-6 March 1995 BP WELL CONTROL MANUAL PRESSURE GAUGE FROM CHOKE MANIFOLD/BOP MANUAL CHOKE 3in PIPE LEVEL INDICATOR STRIP TANK (3 – 4bbl capacity) LARGE ID DRAIN WORKING PLATFORM FLOWLINE RETURNS TRIP TANK WEOX02.003 Figure 1.3 Suggested Fluid Measurement System 1-7/8 1-7 March 1995 BP WELL CONTROL MANUAL 1.2 MANPOWER ORGANISATION Paragraph Page 1 General 1-10 2 Individual Responsibilities 1-10 3 Communication 1-12 Illustrations 1.4 An Example Communication System 1-13 1-9 March 1995 BP WELL CONTROL MANUAL 1 General This section is intended to provide a guideline for the allocation of individual responsibilities during a well control incident. It is Company policy that a well control contingency plan should include the allocation of individual responsibilities. The contingency plan should be drawn up in conjunction with the drilling contractor and should be regularly reassessed. Well control drills provide an opportunity to assess the effectiveness of the contingency plan and to identify and make good any inadequacies. 2 Individual Responsibilities The well control contingency plan must allocate the responsibilities of all those concerned in the operation. Circumstances at the rigsite may dictate that these responsibilities be modified in the event of an incident; however, the following can be used as guidelines for the allocation of responsibilities in the event of a well control incident: (a) The Company Representative • Once the well has been shut-in and is being correctly monitored, to organise a pre-kill meeting for all those involved in the supervision of the well control operation. • To provide specific well control procedures, using the contingency plan as a guideline. • To monitor and supervise the implementation of these procedures. • To be present on the rig floor at the start of the kill operation. Either the Toolpusher or the Company Representative should be present at all times on the rig floor during the operation. • To maintain communication with the Operations base. • The Company Representative has the right to assume complete control of the work required to regain control of the well. • To assign the responsibility of keeping a diary of events. (b) The Company Drilling Engineer • Will provide technical back-up to the Company Representative. • To keep a diary of events. (c) The Senior Contractor Representative • Has the overall responsibility for all actions taken on the rig. • Has the responsibility for supervising the contractor staff that are not directly involved in the well control operation. 1-10 March 1995 BP WELL CONTROL MANUAL • However, in the event that the well gets out of control, the Company Representative has the right to assume complete control and supervise the work required to regain full control of the well. (This entitlement is a standard condition of Company drilling contracts.) (d) The Contractor Toolpusher • Has overall responsibility for the implementation of the well control operation. • Has the responsibility for ensuring that the driller and the drill crew are correctly deployed during the well control operation. • Must be present at the rig floor during the start of the kill operation. Either the Toolpusher or the Company Representative should be present at all times on the rig floor during the operation. • Has the responsibility for briefing the off duty drill crew prior to starting a new␣shift. (e) The Driller • Has the responsibility for the initial detection of the kick and closing in the well. • Has the responsibility for supervising the drill crew during the well control operation. (f) The Mud Engineer • Has continuous responsibility for monitoring the mud system and the conditioning of the mud. It may be prudent to send an extra Mud Engineer to the rig in the event of a well control incident to ensure constant supervision of the mud system. (g) The Cementing Engineer • Will ensure that the cement unit is ready for operation at any time. • Will operate the cement unit at the discretion of the Company Representative. (h) The Subsea Engineer (where appropriate) • Should be available for consultation at all times during the well control operation. • Has the responsibility for checking all the BOP equipment during the operation. (j) The Mud Logging Engineers • Have the responsibility for continuously monitoring the circulating system during the well control operation. • One member of the crew must keep a diary of events. 1-11 March 1995 BP WELL CONTROL MANUAL 3 Communication One of the Company Representative’s responsibilities is to organise a pre-kill meeting once the well has been shut-in. The purpose of this meeting is to ensure that all those involved in the supervision and implementation of the well control operation are familiar with the procedures that will be used to kill the well. This meeting is also the first stage in the process of communication during the well control operation. Experience has shown that even the most well conceived well control procedures can go badly wrong if communication before and during the operation is not properly organised and effective. It is therefore most important that the well control contingency plan details the method and line of communication for each individual involved in the operation. The objectives of a suitable system of communication are: • To ensure that all information relevant to the well control operation is communicated to the Company Representative. • To ensure that those involved in the supervision of the operation are at all times in communication with the Company Representative. • To ensure that all those involved in the operation are aware of the line and method of communication that they should use. • To ensure that communication equipment on the rig is adequate, and is used during the well control operation in the most effective manner possible. Figure 1.4 shows an example of a possible communication system on a semi-submersible␣rig for use during standard well control operations. The following can be noted from this example: • After the kick is taken, the well is shut-in and closely monitored. • The Company Representative calls a pre-kill meeting of those involved in the supervision of the operation. • Responsibilities are allocated to those involved in the operation by the supervisors who attended the meeting. • Each line and method of communication is defined. It should be noted that: – The rig telephone system is not overloaded. – The most important lines of communication to and from the Company Representative (denoted by those inside the broken line) are best maintained with the use of hand held radios. – The use of intrinsically safe hand held radios ensures that all those inside the broken line can listen in on each others communication. – Depending on the type of operation it may be necessary to include others within the broken line. 1-12 March 1995 BP WELL CONTROL MANUAL Figure 1.4 An Example Communication System (1) KICK TAKEN – WELL SHUT-IN – WELL BEING MONITORED (2) PREKILL MEETING COMPANY REPRESENTATIVE COMPANY DRILLING ENGINEER SENIOR CONTRACTOR REPRESENTATIVE TOOLPUSHER MUD ENGINEER MUD LOGGING ENGINEER (3) ALLOCATE RESPONSIBILITIES OFF DUTY DRILL CREW SENIOR CONTRACTOR REPRESENTATIVE MUD ENGINEER TOOLPUSHER SUBSEA ENGINEER CONTRACTOR STAFF MATES CONTRACTOR SHOREBASE DRILLER DRILL CREW PUMPMAN/ DERRICKMAN (4) MAJOR LINES/METHOD OF COMMUNICATION DURING THE WELL CONTROL OPERATION DRILL CREW CONTRACTOR SHOREBASE DRILLER MARINE STAFF PUMPMAN/ DERRICKMAN RT RT RT SENIOR CONTRACTOR REPRESENTATIVE TOOLPUSHER S/S MUD ENGINEER H/H H/H S/S H/H COMPANY REPRESENTATIVE RT RT SUBSEA ENGINEER COMPANY SHOREBASE RT – RIG TELEPHONE SYSTEM SERVICE COMPANY ENGINEERS S/S – SHIP TO SHORE MUD LOGGING ENGINEER H/H – HAND HELD SET WEOX02.004 1-13/14 1-13 March 1995 BP WELL CONTROL MANUAL 1.3 DRILLS AND SLOW CIRCULATING RATES Paragraph Page 1 General 1-16 2 BOP Drills 1-16 3 D1: Kick while Tripping 1-17 4 D2: Kick while Drilling 1-17 5 D3: Diverter Drill 1-19 6 D4: Accumulator Drill 1-19 7 D5: Well Kill Drill 1-21 8 Slow Circulating Rate Pressures, SCRs 1-22 9 Choke Line Losses 1-23 Illustrations 1.5 SCR Pressure Plot 1-23 1.6 Choke Line Pressure Loss Data Sheet 1-25 1.7 An example Determination of Choke Line Losses 1-26 1-15 March 1995 BP WELL CONTROL MANUAL 1 General Both BOP Drills and the recording of slow circulating rate pressures will be carried out on a routine basis on all rigs. This section covers the reasons why it is necessary to carry out BOP Drills, to regularly record SCRs, as well as recommended procedures. 2 BOP Drills The purpose of BOP Drills is to familiarise the drillcrews with techniques that will be implemented in the event of a kick. One of the major factors that influences the wellbore pressures after a kick is taken is the volume of the influx. The smaller the influx, the less severe will be the pressures during the well kill operation. In this respect, it is important that the drillcrew react quickly to any sign that an influx may have occurred and promptly execute the prescribed control procedure. Drills should be designed to reduce the time that the crew take to implement these procedures. The relevant Drills should be carried out as often as is necessary, and as hole conditions permit, until the Company Representative and the Contractor Toolpusher are satisfied that every member of the drillcrew is familiar with the entire operation. Every effort must be made to ensure that the Drill is carried out in the most realistic manner possible. Where practical, there should be no difference between the Drill and actual control procedures. Once satisfactory standards have been achieved, the Drills (D1, D2 and D3, as appropriate) should be held at least once per week. If standards fall unacceptably, the Company Representative should stipulate that the Drills are conducted more frequently. It is important that returning drillcrews have frequent Drills. The following Drills should be practised where applicable: D1 – Tripping D2 – Drilling D3 – Diverter D4 – Accumulator D5 – Well Kill (Suffix R to be included if the remote panel was used) These codes should be used to record the results of the Drill on the BOP Drill Record Proforma. This form should be sent to the Drilling Superintendent fortnightly. The results of each Drill must also be recorded on the IADC Drilling Report. 1-16 March 1995 BP WELL CONTROL MANUAL 3 D1: Kick while Tripping The purpose of this Drill is to familiarise the crew with the shut-in procedure that will be implemented in the event of a kick during a trip. This Drill should only be conducted when the BHA is inside the last casing string. Before the trip is started, the Standing Orders to the Driller will have been posted. This will detail the action that the crew should take in the event a kick is detected. When directed by the Company Representative, the Contractor Toolpusher will instruct the Driller to assume that a positive flowcheck has been conducted, and to implement the prescribed control procedure as detailed in the Standing Orders. Shut-in procedures to be adopted in the event of a kick while tripping are detailed in Chapter␣4. However, as a guideline the following procedure should be initiated: • Without prior notice, the Company Representative will start the Drill by manually raising the trip tank float to indicate a rapid pit gain. • The Driller is expected to take the following steps to shut in the well: 1. Stop other operations. 2. Install the drillpipe safety valve. 3. Open the choke line valve. 4. Close the annular preventer. 5. Record the casing and drillpipe pressure. 6. Notify the Company Representative that the well is shut-in. 7. Record the time for the Drill on the IADC Drilling Report. The Contractor Toolpusher must ensure that the crew are correctly deployed and that each individual completely understands his responsibilities. The time taken for the crew to shut in the well should be recorded. Having shut-in the well, preparations should be made to strip pipe. These preparations should include lining up the equipment as required, assigning individual responsibilities and preparing the Stripping Worksheet. 4 D2: Kick while Drilling The purpose of this Drill is to familiarise the crew with the control procedure that will be implemented in the event of a kick while drilling. This Drill may be conducted either in open or cased hole. However if the drill is conducted when the drillstring is in openhole, the well will not be shut-in . 1-17 March 1995 BP WELL CONTROL MANUAL When the pipe is on bottom, the following procedure can be used as a guideline for the drill: • Without prior notice, the Company Representative gradually increases the apparent pit level by manually raising the float. • The Driller is expected to detect the pit gain and take the following steps: 1. Pick up the kelly (or topdrive) until the tool joint clears the BOPs and the kelly cock is just above the rotary table. 2. Shut down the pumps. 3. Check the well for flow. 4. Report to the Company Representative. 5. Record the time required for the crew to react and conduct the Drill on the IADC drilling report. When the bit has been tripped to the previous casing shoe, a further Drill may be conducted that will result in the well being shut-in. Therefore after tripping the bit to the shoe, the following procedure may be used as a guideline for this Drill: • Stop tripping operations and install the kelly (or topdrive) and start circulating. • Having been instructed to do so by the Company Representative, the Driller is expected to take the following steps to shut-in the well: 1. Pull up until the tool joint clears the BOPs. 2. Shut down the pumps. 3. Open the choke line valve. 4. Close the annular preventer. 5. Record the casing and drillpipe pressure. * 6. Double check spaceout, close and lock hang-off rams and hang-off pipe and check that the kelly cock is just above the rotary table. 7. Notify the Company Representative that the well has been shut-in. 8. Record the time taken for the crew to shut-in the well on the IADC drilling report. * If on a floating rig The procedures adopted during these Drills should be in line with the shut-in procedures as outlined in the Standing Orders. These procedures are outlined in Chapter 4. 1-18 March 1995 BP WELL CONTROL MANUAL 5 D3: Diverter Drill If shallow gas is encountered and the well kicks, blowout conditions may develop very quickly. It is therefore important that crew initiate control procedures as soon as possible in the event of a shallow gas kick. Diverter Drills should therefore be carried out to minimise the reaction time of the crews. A further objective of the Drill is to check that all diverter equipment is functioning correctly. The time taken for each diverter function to operate should be recorded. A Drill should be carried out prior to drilling out of the conductor casing. The procedures that should be implemented in the event of a shallow gas kick are covered in Chapter 4. Drills should be designed in line with the specific procedure that will be adopted in the event of a shallow gas kick. The Contractor Toolpusher must ensure that the drill crew, and marine staff (offshore), are correctly deployed during the Drill and that each individual understands his responsibilities. The time recorded in the log should be the time elapsed from initiation of the Drill until the rig crew (and marine staff) are ready to initiate emergency procedures. 6 D4: Accumulator Drill The purpose of the Accumulator Drill is to check the operation of the BOP closing system. The following specific tests are recommended: (a) Accumulator precharge pressure test This test must be conducted on each well prior to spudding and approximately every 30␣days thereafter at convenient times. On closing units with two or more banks of accumulator bottles, the hydraulic fluid line to each bank must have a full opening valve to isolate individual banks. The valves must be in the open position except when accumulators are isolated for testing, servicing or transporting. The precharge test should be conducted as follows: 1. Shut-off all accumulator pumps. 2. Drain the hydraulic fluid from the accumulator system into the closing unit fluid reservoir. 3. Remove the guard from the valve stem assembly on top of each accumulator bottle. Attach the charging and gauging assembly to each bottle and check the nitrogen precharge. 4. If the nitrogen precharge pressure on any bottle is less than the minimum acceptable precharge pressure listed below, recharge that bottle (with nitrogen gas only) to achieve the specified desired precharge pressure. 5. If the nitrogen precharge on any bottle is greater than the maximum acceptable precharge pressure listed below, a sufficient volume of nitrogen gas must be bled from the accumulator bottle to provide the specified desired precharge pressure. 1-19 March 1995 BP WELL CONTROL MANUAL Accumulator Working Pressure Rating Desired Precharge Pressure Min. Acceptable Precharge Pressure Max. Acceptable Precharge Pressure 1500 psi 2000 psi 3000 psi 750 psi 1000 psi 1000 psi 750 psi 950 psi 950 psi 850 psi 1100 psi 1100 psi (b) Accumulator closing test This test should be conducted before BOP stack tests. The test should be conducted as follows: 1. Position a joint of drillpipe in the blowout preventer stack. 2. Close off the power supply to the accumulator pumps. 3. Record the initial accumulator pressure. The pressure should be the designed operating pressure of the accumulators. Adjust the regulator to provide 1500 psi operating pressure to the annular preventer. 4. Operate the sequence of functions as relevant to the rig type. For a land rig: Close the annular preventer and one pipe ram (sized for the pipe in the stack). Open the HCR valve on the choke line. For the floating rig: Close and open all the well control functions (apart from blind/shear rams). Duplicate the operation of the blind/shear rams. After each function, record the volume used, the time taken, and the residual accumulator pressure. The residual accumulator pressure after completing all the tests must be at least 200 psi greater than the precharge pressure. 5. Turn on the accumulator pumps. Having completed the tests, recharge the accumulator system to its designed operating pressure. Record the time taken to recharge the system. (c) Closing unit pump test Prior to conducting any tests, the closing unit reservoir should be inspected to be sure it does not contain any foreign fluid or debris. The closing unit pump capability test should be conducted before BOP stack tests. This test can be conveniently scheduled either immediately before or after the accumulator closing time test. The test should be conducted according to the following procedure. 1. Position a joint of drillpipe in the blowout preventer stack. 2. Isolate the accumulators from the closing unit manifold by closing the required valves. 1-20 March 1995 BP WELL CONTROL MANUAL 3. If the accumulator pumps are powered by air, isolate the rig air system from the pumps. A separate closing unit air storage tank should be used to power the pumps during this test. When a dual power (air and electric) source system is used, both power supplies should be tested separately. 4. Close the annular preventer and open one choke line failsafe valve (or␣HCR valve). Record the time (in seconds) required for the closing unit pumps to close the annular preventer plus open the choke line valve and obtain 200 psi above the accumulator precharge pressure on the closing unit manifold. It is recommended that the time required for the closing unit pumps to accomplish these operations does not exceed two minutes. 5. Close the choke line failsafe (or HCR valve) and open the annular preventer. Open the accumulator system to the closing unit and charge the accumulator system to its designed operating pressure using the pumps. 7 D5: Well Kill Drill The objective of this Drill is to give drillcrews the most realistic type of well control␣training and a feel for the equipment and procedures that they would use to kill a well. This Drill should be carried out prior to drilling out the intermediate and production strings. It should never be carried out when openhole sections are exposed. The following procedure is recommended: 1. Run in hole and tag the top of cement. 2. Pull back one stand and install the kelly (or install topdrive). 3. Break circulation and establish slow circulating rate pressures. (Consider circulating bottoms up prior to this if the annulus may contain contaminated mud). 4. Carry out standard BOP Drill D2, resulting in the well being shut-in. 5. Consider applying low pressure to the casing (typically 200 psi), bring the pump up to kill speed controlling the drillpipe pressure according to a predetermined schedule. It is important that this opportunity to circulate across a choke is used to maximum effect. A drillpipe pressure schedule should be drawn up and carefully adhered to. It is important that the choke operator develops a feel for the lag time between manipulation of the choke and its subsequent effect on the drillpipe pressure. The lag time should be recorded, so that it can be used for reference should a kick be taken in the next hole section. 1-21 March 1995 BP WELL CONTROL MANUAL 8 Slow Circulating Rate Pressures, SCRs There are many reasons why a kick should be displaced from the hole at a rate that is considerably slower than that used during normal drilling. These include: • To minimise the pressure exerted on the openhole. • To allow weighting of the mud as the kick is displaced. • To permit adequate degassing of the returned mud. • To limit the speed of required choke adjustments. • To reduce the pressure exerted on well control equipment. All these factors must be taken into account when deciding at what rate to displace the kick. However the absolute upper limit for the displacement rate may be restricted by the pressure rating of the surface equipment, in particular the setting of the pump relief valve. It should be noted that it is potentially hazardous to displace a kick from the hole when the surface pressure is close to the relief valve setting. In order to estimate the circulating pressures during the displacement of a kick, it is necessary to know the friction pressure in the circulating system at low rates. For this reason, it is useful to have determined the SCR pressure before a kick is taken. At a given rate of circulation, the initial circulating pressure can be estimated from the sum of the shut-in drillpipe pressure and the SCR pressure. Company policy states that SCRs should be conducted regularly and at least: • Once per tour (or at 300m intervals during the tour). • When the bit is changed. • When the BHA is changed. • When the mud weight or properties are changed. The range of circulation rates used will be dependent upon many factors, but should fall within the limits of 1/2 and 4 barrels per minute. If oil base mud is in the hole, when back on bottom after a trip, circulate bottoms up before measuring SCRs. At these relatively low pump speeds the volumetric efficiency of the rig pumps may be significantly less than at normal speeds used during drilling. It is therefore recommended that the volumetric efficiency of the rig pumps is checked at low pump speed, such as when pumping a slug prior to a trip. It is useful to plot the SCRs on a graph as shown in Figure 1.5. The drillstring internal friction should be calculated at the SCRs and used to determine the annulus frictional pressure as shown. The annulus frictional pressure is a major factor that will influence the rate at which the kick will be displaced from the hole (using standard well control procedure the annulus frictional pressure will be added to wellbore pressure as the pump is brought up to speed to kill the well). 1-22 March 1995 STANDPIPE PRESSURE (psi) BP WELL CONTROL MANUAL PSCR3 Drillstring internal pressure drop PSCR2 Annulus pressure drop PSCR1 SCR1 SCR2 SCR3 PUMP OUTPUT (bbls/min) (stks/min) Other SCRs can be selected to displace the kick WEOX02.005 Figure 1.5 SCR Pressure Plot A graph similar to Figure 1.5 aids the selection of circulation rates other than these actually measured and also provides a guide to the size of the annulus circulating losses over a range of circulation rates. 9 Choke Line Losses The frictional pressure caused by circulating through the choke line, while displacing a kick from the well, can cause additional pressures to act in the wellbore. These pressures are not significant in the case of land, platform and jack-up rigs, but can be critical in the case of a floating rig. In most cases however, if the correct procedures are adhered to, the choke line frictional pressure should be accounted for as the kick is displaced out of the hole. The recommended method is to monitor the wellhead pressure through the kill line as the pump is started. If the wellhead pressure remains constant as the pump is brought up to speed then the choke line friction will in most cases be automatically compensated for. (This technique is outlined in detail in Chapter 6.) It is also possible to account for the choke line losses by reducing the choke pressure by an amount equal to the choke line loss as the pump is brought up to speed. This method is not considered to be as reliable as using the kill line monitor. 1-23 March 1995 BP WELL CONTROL MANUAL It is important that the choke line frictional pressure is accurately known at a wide range of circulating rates. From this information the additional load on the wellbore can be assessed at a range of displacement rates and subsequently the most suitable rate can be selected. The following procedure should be implemented in order to properly assess the choke line frictional pressures at slow circulating rates. This procedure should be carried out initially when the BOP and riser are installed and before drilling out of each subsequent casing shoe. 1. Install suitable pressure gauges to record standpipe and choke pressures during circulation. 2. Record SCR pressure at a range of rates from 1/2 to 4 bbl/min down drillpipe and up the riser. 3. Open choke line valves. 4. Line up choke manifold to route flow across a fully opened remote operated choke. Route returned flow through the poorboy gas separator to the shakers. 5. Space out to ensure no tool joint is opposite annular preventer. 6. Close annular preventer. 7. Circulate down the drillpipe and up through the choke line until returns are uniform. 8. Record SCR pressure at same rates as before. Record the choke pressure at each rate. 9. Calculate the choke line frictional pressure at each rate. Figure 1.6 shows a form that can be used to record the data. The form also shows how to determine the choke line friction pressure from the recorded data. Figure 1.7 shows an example determination of choke line losses. The choke line losses should be adjusted for changes in mud weight as shown on the form. The accuracy of this adjustment is however questionable over a wide range of mud weights. In order to verify choke line losses after drilling out of the casing shoe, it is acceptable to isolate the well and pump down the choke line at the range of slow circulating rates. 1-24 March 1995 WELL No 25 RIG 19 RIG WELL STATUS DURING TEST DATE 25/7/87 133/8in CASING RUN AND TESTED / 135/8in STACK INSTALLED AND TESTED PROPERTIES OF THE MUD IN THE HOLE DURING THE TEST 1.4SG OBM/PV24CP/YP100 lb/100ft2 RECORDED BY CORRECTED CHOKE LINE LOSS CORRECTED CHOKE LINE LOSS 1.4 SG AT…………… MUD WEIGHT (psi) AT…………… MUD WEIGHT (psi) AT…………… MUD WEIGHT (psi) AT…………… MUD WEIGHT (psi) 1-25 6.5 ……………in LINER PUMP RATE ……………in LINER PUMP RATE SCR PRESSURE UP RISER (bbl/min) (SPM) (SPM) (psi) 4.78 40 RIG PUMPS: NATIONAL 12 - P - 160 985 1435 80 370 3.58 30 680 985 250 2.39 20 400 590 CHOKE PRESSURE AT SCR (psi) 55 40 150 CEMENT PUMP - HT - 400 (4in PLUNGER) 1.00 120 190 25 45 0.5 0.25 50 65 10 0 0 0 0 (1) (2) (3) (2)-(1)-(3) 0 March 1995 WEOX02.006 BP WELL CONTROL MANUAL CORRECTED CHOKE LINE LOSS CIRCULATION RATE SCR PRESSURE UP CHOKE LINE (psi) J. P. MEASURED CHOKE LINE LOSS Figure 1.6 Choke Line Pressure Loss Data Sheet CHOKE LINE PRESSURE LOSS DATA SHEET BP WELL CONTROL MANUAL Figure 1.7 An example Determination of Choke Line Losses CIRCULATING @ 20SPM UP RISER CIRCULATING @ 20SPM UP CHOKE LINE (CHOKE WIDE OPEN) 400 600 PSCR @ 20SPM = 400psi POC = 50psi 50 PCL = PSCR (up choke line) – PSCR (up riser) – POC = 600 – 400 – 50 PCL = 150psi where PSCR = Slow Circulating Rate Pressure (psi) PCL = Choke Line Pressure Loss at SCR (psi) POC = Choke Pressure recorded at SCR with choke wide open (psi) WEOX02.007 1-26 March 1995 BP WELL CONTROL MANUAL 1.4 USE OF THE MUD SYSTEM Paragraph Page 1 General 1-28 2 Pit Management 1-28 3 Building Mud Weight 1-29 4 Dealing with Gas at Surface 1-31 5 Chemical Stocks 1-34 Illustrations 1.8 An example Mud Gas Separator – operating at maximum capacity 1-32 1-27 March 1995 BP WELL CONTROL MANUAL 1 General Well control contingency plans should outline the manner in which the mud system will be utilised during standard well control operations. This section is intended to highlight the major factors that will determine the most satisfactory arrangement of the mud system in such circumstances. 2 Pit Management The following guidelines should be considered when specifying pit arrangements: (a) While drilling a critical hole section • Keep the active mud system surface area as small as is practical to ease kick detection. Any reserve mud stocks in the tanks should be positively isolated from the active system. Ensure that the gates on the trough are sealing properly. • Adequate reserve stocks of mud should be held; the volume and weight of which will be determined by the nature of the next hole section. • Ensure all pit level systems and tank isolating valves are working correctly before drilling into possible gas-bearing zones. • Keep all mud treatments and pit transfers to the absolute minimum at critical sections of the well. Ensure that the Driller and the Mud Logging Engineer are aware in advance of any changes to the system. • Crew safety meetings should discuss the problem of gas kicks, especially if oil based mud is in use, and emphasise the importance of early detection. Mud engineering and mud logging personnel should attend these meetings. (b) When displacing a kick The major factors that will determine the most satisfactory pit arrangement for displacing a kick include the following: • The technique that will be used to displace the kick. • The usable surface pit volume in relation to the hole volume. • The method of weighing up the mud. • How to deal with the kick when it is displaced to the surface. • How to deal with the pit gain caused by influx expansion during displacement. • How to deal with contaminated returns. • The nature and toxicity of the influx fluid. • The monitoring of pit levels in the active system. 1-28 March 1995 BP WELL CONTROL MANUAL The kick can be displaced from the hole using either the Wait and Weight Method or the Driller’s Method. The most satisfactory arrangement of the pits will be different for each technique and clearly will be rig-specific. There are three different stages at which the mud can be weighted up for these two techniques: • • The Wait and Weight Method – In a typical situation when it is impractical to weight up a complete hole volume prior to displacement of the kick. This will therefore entail that some mud is weighted while the kick is displaced from the hole. The volume that is weighted prior to displacement of the kick will depend, for a given hole capacity, on the rate at which baryte can be added into the system in relation to the desired rate of displacement. – In the unusual situation when there is adequate surface volume, a complete hole volume of kill mud can be prepared before displacement of the kick. The Driller’s Method – In this case the mud is weighted either while the kick is displaced with original weight mud or after the first circulation depending on the availability of baryte and tank space. 3 Building Mud Weight (a) Baryte delivery to the mud pits The rate at which baryte can be added to the original mud influences the time required to increase the weight of a volume of mud. For this reason it is important to measure the rate at which both the conventional hopper system and the high rate system (if fitted) can supply baryte. If the Driller’s Method is used this will determine the time required to build the mud weight after the kick has been displaced from the hole. If the Wait and Weight Method is used, the maximum rate at which baryte can be supplied to the mud will: • Determine the time required to weight the hole volume of mud before the kick is displaced. • Or it may limit the rate at which the kick can be displaced, if the mud is weighted as the kick is displaced. The maximum rate at which the mud can be weighted can be determined for a given required mud weight increase from the following formula: Maximum possible rate = at which the mud can be weighted (bbl/min) Baryte delivery rate (lb/min) Baryte required to weight up (lb/bbl) 1-29 March 1995 BP WELL CONTROL MANUAL Therefore for the following example: Required mud weight increase = 0.2 SG (from 1.5 SG to 1.7 SG) Baryte required = 1490 X (1.7 - 1.5) = 117 lb/bbl 4.25 - 1.7 If the maximum barytes delivery rate for the rig = 350 lb/min Then: Maximum rate at which the = 350 = 3 bbl/min mud can be weighted 117 This figure therefore gives an indication of the maximum displacement rate if the mud is weighted as the kick is displaced from the hole. (b) Baryte storage When possible at least one full barytes storage tank should be pressured up at all times and the bulk delivery system tested regularly. The bulk system should be included in the rig PMS (Preventive Maintenance) system. (c) Building viscosity into the mud There may be well control situations which require that considerable volumes of weighted mud are built from a water or oil base. This may be the case in the following situations: • If considerable losses are experienced. • If the required volume of kill weight mud is greater than the surface stocks of active and reserve weighted mud. • If the returns are severely contaminated and have to be dumped. The limiting factor for an oil base mud may be the rate at which viscosity can be built into the base oil. Building viscosity is usually a less important factor when water base muds are used. Shear equipment is required for building viscosity using clay viscosifiers in new base oil. Some offshore rigs have jet line mixers to help build viscosity. In circumstances in which large volumes of new oil mud must be built, it would be useful to know the rate at which new mud can be sheared to a level at which barytes can be suspended. This rate is determined by shearing a known volume of new mud until the minimum viscosity is reached. As a guideline, the minimum viscosity would be represented by a yield point of 10, and a 10 second gel reading of 3. In emergency situations, viscosity can be built quickly using an oil mud polymer (Baroid’s LFR 2000 as an example) at 4 lb/bbl in conjunction with organophilic clays. However, it is recognised that these polymers can cause high temperature gelation of the mud, and as such, they are not recommended for use in high temperature wells. 1-30 March 1995 BP WELL CONTROL MANUAL (d) Volume increase due to baryte addition The volume of a given amount of mud will increase as baryte is added to it. This may be significant when large mud weight increase is required in a large volume of mud. The volume increase due to baryte addition can be determined from the following relationship: Volume increase = 1.48 bbl per metric ton of baryte added Therefore in the following situation: The required addition of baryte = 200 lb/bbl Volume to weight up = 600 bbl Volume increase due to baryte addition = 600 X 200 X 1.48 = 80 bbl 2205 4 Dealing with Gas at Surface It is important that suitable equipment is available on the rig to deal with the influx once it is displaced to surface. Returns should be piped through the mud gas separator and then on to the degasser for further treatment. (a) The mud gas separator (poorboy) The mud gas separator should be lined up at all times when a kick is being displaced. The separator is used to remove large gas bubbles from the mud and to deal with a flow of gas once the influx is at surface. There will be a limit to the volume of gas that each separator can safely deal with. When this limit is exceeded, there exists the possibility that gas will blow through into the shaker header box. An estimation can be made of the maximum gas flowrate that the separator can handle. The limiting factors will be the back pressure at the outlet to the vent line in relation to the hydrostatic head of fluid at the mud outlet of the separator. When the back pressure due to the gas flow is equal to, or greater than, the hydrostatic head available at the mud outlet, the gas will blow through to the shaker header tank. See Figure 1.8. In order to minimise the possibility of a gas blow-through, the vent line should be as straight as possible and have a large ID. The mud outlet should be configured to develop a suitable hydrostatic head (minimum recommended head is 10 feet). See Figure 1.8. 1-31 March 1995 BP WELL CONTROL MANUAL The back pressure due to the flow of gas should be monitored with a pressure gauge as shown in Figure 1.8. Some warning of the possibility of a gas blow-through will be given when the registered pressure approaches the hydrostatic head of the fluid in the discharge line. It should be noted that the maximum hydrostatic head available may not be that of the mud in the event that large volumes of oil or condensate are displaced to␣surface. If the safe operating limit of the separator is approached, the choke can be closed in (while ensuring that the well is not overpressured) or the flow switched to the overboard line or the burn pit. GAS OUTLET 8in ID MINIMUM GAS BACK PRESSURE REGISTERED AT THIS GAUGE (Typically 0 to 20psi) STEEL TARGET PLATE INLET INSPECTION COVER APPROX HEIGHT 1/2 OF A SECTION A-A TANGENTIAL INLET 30in OD A 4in ID INLET-TANGENTIAL TO SHELL FROM CHOKE MANIFOLD BRACE 10ft MINIMUM HEIGHT INSPECTION COVER HALF CIRCLE BAFFLES ARRANGED IN A ‘SPIRAL’ CONFIGURATION TO SHAKER HEADER TANK MAXIMUM HEAD AVAILABLE DEVELOPED BY THIS HEIGHT OF FLUID eg: 10ft HEAD AT 1.75 SG GIVES 7.6psi MAXIMUM CAPACITY 10ft APPROX 8in NOMINAL ‘U’ TUBE 4in CLEAN-OUT PLUG 2in DRAIN OR FLUSH LINE Figure 1.8 An example Mud Gas Separator – operating at maximum capacity 1-32 March 1995 WEOX02.008 BP WELL CONTROL MANUAL (b) The degasser The degasser should be lined up at all times during the well control operation. The degasser is designed to remove the small bubbles of gas that are left in the mud after the mud has been through the mud gas separator. It is important that the degasser is working properly and as such it should be tested every tour. While drilling with gas cut returns, the degasser can be checked as follows: 1. Measure actual (gas cut) mud weight at the shaker header box using a non pressurised mud balance. 2. Measure actual mud weight at the degasser outlet using a non pressurised mud balance. If the actual mud weight at the outlet of the degasser is greater than the actual mud weight at the inlet, then the degasser is working. If the mud weight at this stage is not equal to the active system mud weight, then either the degasser is not working properly, or the returns are at a lower weight than the mud in the active system. If the actual mud weight measured at this stage is equal to the active system mud weight, then the degasser is working properly. 3. Measure mud weight at the degasser outlet and the shaker header box using a pressurised mud balance. If the actual mud weight at the outlet of the degasser is equal to the reading on␣the pressurised mud balance, the degasser has removed all the gas from the mud. (c) Overboard lines/Flare lines It is recommended that a second method of dealing with severely gas cut returns be available at the rigsite, whether on land or offshore. This will generally be either an overboard line, or a flare line to the burn pit on land. It should be easy to switch the returns from the mud system to the flare line. It may be necessary to use the flare line during a well control operation in the following situations: • The gas flowrate is too high for the mud gas separator. • Hydrates are forming in the gas vent line from the mud gas separator. • The gas is found to contain H2S. • The mud system is overloaded. Lines that are required to handle high velocity gas must be as straight as possible to minimise erosion. Significant erosion is likely to occur in the path of high velocity gas and solids, therefore the redundancy in flowlines and manifolds downstream of the choke must be analysed on all rigs. 1-33 March 1995 BP WELL CONTROL MANUAL 5 Chemical Stocks (a) Baryte and mud chemical stocks Company policy details the minimum stocks of baryte and mud chemicals that should be held at the rigsite. The policy states that: ‘Sufficient weighting material stocks must be maintained on site such that the entire mud circulating volume can be raised by a minimum of 0.25 SG (See formula in Paragraph 3). Reserve stocks of bentonite or viscosifier must also be on site to enable this increase in mud weight to be effected’. ‘Where transport and logistics are not assured (offshore and remote locations) the minimum onsite weighting material stock must be 100 tonnes’. This is a minimum standard, and as such, the Company Representative may wish to stock a greater quantity of baryte and chemicals. (b) Cement stocks Cement stocks should not drop below the quantity of cement and additives that will be required to set 2 X 150m of cement plugs in the hole section being drilled. Additionally, in high pressure wells, an abandonment plug recipe should be onsite prior to drilling into the reservoir. Batch mix tanks should also be onsite during the drilling of such reservoir sections. 1-34 March 1995 BP WELL CONTROL MANUAL 1.5 KICK TOLERANCE Paragraph Page 1 General 1-36 2 Kick Tolerance Calculation Methods 1-36 3 Procedure for Kick Tolerance Calculations 1-37 4 Considerations for High Angle and Horizontal Wells 1-40 5 When to Calculate Kick Tolerance 1-41 6 Excel Kick Tolerance Calculator 1-42 Illustrations 1.9 Kick Tolerance Values Through a Zone of Increasing Pore Pressure 1.10 Excel Kick Tolerance Calculator – Example Calculations 1-43 1-44 1-35 Rev 1 March 1995 BP WELL CONTROL MANUAL 1 General Many definitions of kick tolerance have been used in the drilling industry. Within BP, Kick Tolerance is defined as the maximum volume of kick influx that can be safely shut-in and circulated out of the well without breaking down the formation at the openhole weak point. It is now an accepted part of the Company Casing Design policy to determine the casing setting depth by the Limited Kick Method. It is therefore particularly important that the kick tolerance in critical hole sections be accurately monitored. This section explains how to calculate kick tolerance and when to calculate kick tolerance. In critical hole sections, it is important to calculate kick tolerance on a regular basis. This is because kick tolerance changes as a function of hole depth, BHA geometry, mud weight, formation pressure and influx type, etc. 2 Kick Tolerance Calculation Methods Depending upon how kick tolerance is defined, a number of methods exist for kick tolerance calculations. In general, these methods can be classified into two categories: 1 Simple Methods In these methods kick tolerance calculations are simplified based on several assumptions: • The kick influx is a “single bubble”. • At the initial shut-in condition, the influx is at the bottom of the openhole. • The effects of the gas migration, gas dispersion, gas solubility, downhole temperature and the gas compressibility are ignored. Although these assumptions may seem unrealistic, the simple methods have gained wide acceptance in the drilling industry because they are simple and generally yield conservative (safer) kick tolerance. However these methods have an inherent shortcoming: they do not measure how quickly an influx will grow. This is to say that in some cases formation deliverability may be such that the well could not be shut in before the kick tolerance volume was exceeded. Therefore the same kick tolerance between two wells may not mean that they share the same level of risk ! 2 Computer Kick Simulators In the recent years many sophisticated computer simulators have been developed which can provide a good approximation of kick conditions from the stage when it flows into the wellbore to that when it is circulated out. In the simulations, assumptions used in the simple methods are replaced by mathematical models. Among many other applications, the kick simulators can be used for kick tolerance calculations. They can predict the maximum pressures at any point of the annulus and the results are more accurate and less conservative than using the simple methods. In addition, as simulators can simulate how quickly an influx will flow into the wellbore, they can predict how much time the rig crew have to shut in the well before the influx exceeds the kick tolerance limit. Therefore simulators can be used to provide direct indications in the level of risk involved under various scenarios. 1-36 March Rev 1 1995 March 1995 BP WELL CONTROL MANUAL However, due to complexity, kick simulators are recommended only in the situations where kick tolerance is considered critical based on the simple methods. Some computer kick simulators are available from the Drilling & Completions Branch, BP Exploration, Sunbury. 3 Procedure for Kick Tolerance Calculations The method illustrated in the following is one of the simple methods. The method calculates the maximum allowable kick influx volume when the well is shut in. The method considers two scenarios: • When the influx is at the bottom of the hole at the initial shut in condition • When the top of the influx has been displaced to the openhole weak point (with the original mud weight) The following procedure can be used to calculate the kick tolerance: 1 Estimate the safety factor to be applied to the Maximum Allowable Annular Surface Pressure (MAASP) When the influx is displaced from the hole, there will be additional pressures acting in the wellbore. The following are some of the possible causes of such additional pressures during circulation: • Choke operator error (depending upon the choke’s condition, operator ’s experience,␣etc.) • Annular friction pressure (depending on the hole size, mud properties, etc.) • Choke line losses (in particular on floating rigs) The safety factor (SF) to be applied to the MAASP will be the sum of these additional pressures. The drilling engineer must use his/her judgement to determine the most appropriate safety factor. 2 Calculate the Maximum Allowable Annular Surface Pressure (MAASP) Without Breaking Down the Weak Point Formation: MAASP = Pleak – 1.421 x MW x TVD wp – SF (psi) where: MAASP MW Pleak SF TVDwp Maximum allowable annular surface pressure (psi) Mud weight in hole (SG) Leak-off pressure at the openhole weak point (psi) Safety factor (psi) Vertical depth at the openhole weak point (m) It should be seen that MAASP is determined based on the consideration of the formation fracturing pressure at the openhole weak point. So it is considered only when there is a full mud column from the weak point to the surface (i.e. the influx is still below the weak point). If lighter fluids (such as a gas influx) occupy the annulus above the weak point, the surface pressure in excess of MAASP may not cause downhole failure. Therefore from the moment the top of an influx has been displaced past the openhole 1-37 Rev 1 March 1995 BP WELL CONTROL MANUAL weak point, MAASP is no longer a consideration and may be exceeded by a margin which should be determined based on the casing burst strength and the pressure ratings of BOP stack and choke manifold. The method for estimating the position of the influx top is described in Vol.I, Chapter 6, Section 6.1. 3 Calculate the maximum allowable height of the influx in the openhole section: H max = where: Hmax Gi Pf TVD h 4 MAASP – ( Pf – 1.421X MW X TVD h) 1.421 X (m) (MW – Gi) Maximum allowable height of the influx (m) Influx gradient (SG) Formation pore pressure (psi) Vertical depth of openhole (bit) (m) Calculate the maximum allowable influx volume that Hmax corresponds to at the initial shut-in conditions Vbh = H max where: Vbh C1 θ bh x C1 / cos(θ bh) (bbl) Maximum allowable influx volume at initial shut-in condition (bbl) Annular capacity around BHA (bbl/m) Hole angle in the bottom hole section (degree) If the bottom hole section is horizontal (or above 90 degree), the hole angle used in the calculation should be the openhole angle immediately above the horizontal section. The kick tolerance should be the sum of the calculated volume (Vbh ) plus the annular volume of the horizontal section. In cases where Hmax /cos(θbh ) is greater than the length of BHA, the maximum allowable volume (Vbh) should be calculated partly based on the annular capacity around BHA and partly around drillpipe. 5 Calculate the maximum allowable influx volume that Hmax corresponds to when the top of the influx is at the openhole weak point Vwp = Hmax where: Vwp C2 θwp x C2 / cos(θ wp) (bbl) Maximum allowable influx volume when top of the influx is at the openhole weak point (bbl) Annular openhole capacity around drillpipe (bbl/m) Hole angle in the openhole section below the weak point (degree) In cases where Hmax /cos(θwp ) is greater than the openhole drillpipe length below the weak point, the maximum allowable influx volume (Vwp) should be calculated partly based on the annular openhole capacity around drillpipe and partly around BHA. 1-38 March 1995 1995 Rev 1 March BP WELL CONTROL MANUAL 6 Convert the maximum allowable influx volume at the weak point (Vwp ) to what would be at the initial shut in condition Based on Boyle’s law, the maximum allowable influx volume at initial shut-in corresponding to Vwp will be: V bh' = V wp X Pleak Pf 7 (bbl) The actual kick tolerance should be the smaller of Vbh (Step 4) and Vbh' (Step 6) Example: Bit depth: Current hole size: Hole angle: Mud weight in hole: BHA length / OD: Drillpipe OD: Estimated pore pressure at 4000 m: Last casing shoe: Leak-off test EMW: Annular back pressure at SCR: Safety margin for choke operator error: 4000 m 12-1/4" Vertical 1.60 SG 182 m / 8" 5" 1.58 SG 2695 m 1.72 SG 70 psi 150 psi 1. Estimate the safety margin to be applied to MAASP: SF = 70 + 150 = 220 psi 2. Calculate MAASP: Leak-off pressure, Pleak = 1.421 x 1.72 MAASP = 6587 - 1.421 x x 2695 = 6587 psi 1.6 x 2695 - 220 = 240 psi 3. Calculate the maximum allowable influx height in the openhole section: Pore pressure gradient, P f = 1.421 x 1.58 H max = 240 - (8981 - 1.421X 1.6X 4000) x 4000 = 8981 psi = 178m 1.421 X (1.60 - 0.2) 4. Calculate the maximum allowable influx volume at the initial shut-in condition: Annular capacity around BHA, C1= (12.252 - 8 2) / 313.8 = 0.2743 (bbl/m) As the BHA length (182 m) is longer than Hmax (178 m), so the influx is around BHA only when it is at the bottom of the hole. Therefore: Vbh = 178 x 0.2743 = 49 bbl 5. Calculate the maximum allowable influx volume when the top of influx is at the casing shoe: Annular capacity around openhole DP, C2= (12.252 - 5 2) / 313.8 = 0.3985 (bbl/m) Openhole DP length = 4000 - 2695 - 182 = 1123 m ( > H max of 178 m) 1-39 Rev 1 March 1995 BP WELL CONTROL MANUAL Vwp = 178 x 0.3985 = 71 bbl 6. Convert Vwp to the initial shut-in condition: Vbh' = 71 x 6587 / 8981 = 52 bbl 7. Therefore the actual kick tolerance is 49 bbl. 4 Considerations for High Angle and Horizontal Wells In high angle and horizontal wells, reservoirs are often drilled at a high or horizontal angle with the last casing or liner string set on top of the reservoir. When considering kick tolerance for the reservoir section, it is often the case that the maximum allowable gas height (determined by step 3 in the previous section) extends from the openhole bottom to inside the casing/liner. This implies that the well can tolerate an infinite volume of gas influx without fracturing the openhole weak point. On the other hand, because of the long openhole section through the reservoir in a high angle or horizontal well, the influx volume can be potentially high. So when the influx is circulated to surface, it may fill up the entire annuli of the vertical and low angle sections and result in very high choke pressures at surface. Therefore, the kick tolerance volume in this case should be determined not only by the formation fracture gradient at the openhole weak point but also by the maximum allowable surface pressure based on the casing burst strength and the pressure ratings of the surface equipment. When drilling a high angle or horizontal well, the following procedure should be used to determine the kick tolerance: a. Calculate kick tolerance volume as V1 using the method as described in the previous section (Step 1 through 7) b. Determine the maximum allowable surface pressure Psurf based on the casing burst strength and the pressure ratings of the surface equipment (BOP stack, choke manifold, etc.). Note its difference with MAASP which is based on the formation fracture gradient at the weak point. c Calculate the maximum allowable gas height Hmax when the gas influx top has reached the surface: H max = where: Gi Pf SF TVD h (Psurf - SF) - (Pf - 1.421X MW X TVD h) 1.421 X (MW - Gi) Influx gradient (SG) Formation pore pressure (psi) Safety factor mainly determined by the choke operator error margin (psi) Vertical depth of openhole (bit) (m) 1-40 March 1995 1995 Rev 1 March BP WELL CONTROL MANUAL d Calculate the influx volume that Hmax corresponds to when the gas influx top has reached the surface: Vsurf = Hmax x Ccsn (bbl) where: Vsurf Ccsn Maximum allowable influx volume when the influx top reaches surface (bbl) Annular capacity in the casing near surface (bbl/m) e Convert Vsurf to the corresponding volume at the initial shut-in condition: V 2 = V surf X f Psurf (bbl) Pf The actual kick tolerance volume is the smaller of V2 (step e) and V 1 (step␣a). 5 When to Calculate Kick Tolerance Company policy states that: “The kick tolerance of the weakest known point of the hole section being drilled must be updated continuously whilst drilling. If the kick tolerance is less than 50 bbl the Drilling Superintendent must be informed. If the kick tolerance is less than 25 bbl for offshore wells or 10 bbl for land wells, drilling may only continue when dispensation has been given by the Manager Drilling in town.” Kick tolerance will change if there is a change in hole depth, mud weight, formation pressure or BHA. Therefore kick tolerance must be constantly re-evaluated as the well is drilled, not only based on the current condition but also on the future conditions which are expected to occur deeper in the well. The frequency with which the kick tolerance should be re-evaluated is dependent on the nature of the well. However, in hole sections where kick tolerance is likely to be a critical factor, the following guidelines should be considered: • After LO test, evaluate the kick tolerance at suitable intervals throughout the next hole section with a number of mud weights that are likely to be used. • If the hole section contains a zone of rapid pore pressure increase, the kick tolerance should be evaluated frequently based on the anticipated pore pressure. • If any factors that affect the kick tolerance (such as mud weight, BHA) change as the section is drilled, the kick tolerance below that point in the section should be re-evaluated. • At each stage in the hole section, the Company Representative and the Drilling Engineer must assess the possibility of the pore pressure developing in a manner different to that predicted and hence its effect on the kick tolerance. 1-41 Rev 1 March 1995 BP WELL CONTROL MANUAL Figure 1.9 shows an example of the type of calculations that should be worked. The kick tolerance figures shown are those that would typically be calculated before a transition zone. As shown, the current bit depth is 3500 m and the kick tolerance has been calculated at various intervals across the zone of increasing pore pressure. The kick tolerance has been calculated for the mud weight currently in use, for the maximum mud weight anticipated for the section, and intermediate weight. From these figures, it is clear that a serious situation would develop if a kick was taken from the high pressure zone with the mud weight currently in the hole. This might occur if either the pore pressure developed more rapidly than predicted, or if the steady increase in pore pressure was undetected at the surface. The kick tolerance figures for the intermediate mud weight show that even at this weight, the kick tolerance would be small if the high pressure zone was unexpectedly encountered. The kick tolerance is finally calculated at the maximum mud weight. These figures show a final minimum kick tolerance of 50 bbl at that mud weight. The table also shows the kick tolerance if the pore pressure developed higher than predicted of 1.6 SG. In general these figures indicate that drilling should proceed cautiously through the zone of increasing pore pressure. On the basis of these figures, it may be decided to weight up the mud a certain amount before the predicted increase in pressure occurs. The decisions that are made on the basis of kick tolerance figures such as these will be largely dependent upon the particulars of each situation, including the level of confidence placed in the pore pressure prediction. 6 Excel Kick Tolerance Calculator Figure 1.10 is an Excel Kick Tolerance Calculator, which can be activated to calculate the kick tolerance by entering data into green-shaded cells. The kick tolerance volume, together with a range of other parameters, will be displayed automatically. The calculator is based on the same method as described in the previous sections, except that it uses the pressures at the mid-point of the gas influx. So the calculator is slightly less conservative. 1-42 Rev 1 1995 March 1995 March BP WELL CONTROL MANUAL Figure 1.9 Kick Tolerance Values though a Zone of increasing Pore Pressure PORE PRESSURE (psi) 3000 4000 5000 6000 7000 8000 9000 CASING SHOE Maximum Allowable Pressure 13.8ppg EMW 9000 9.2ppg 10,000 DEPTH (ft) 11,000 CURRENT BIT DEPTH MW = 9.6ppg 12,000 9.2ppg 11.3ppg 13.2ppg 13,000 FOR CURRENT MW (9.6ppg) TVD (ft) MW (ppg) 11,480 12,470 12,630 12,795 12,960 12,990 13,123 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.2 9.2 10.2 11.3 12.3 12.4 13.2 12,960 9.6 13.2 FOR MUD AT 12ppg TVD (ft) MW (ppg) 600 600 460 215 30 7 (0) 11,480 12,470 12,630 12,795 12,960 12 12 12 12 12 9.2 9.2 10.2 11.3 12.3 13,123 12 (0) 12,960 13,123 12 12 PORE KTOL PRESSURE (bbl) (ppg) FOR MUD AT 13.3ppg TVD (ft) MW (ppg) 600 600 450 246 112 11,480 12,470 12,630 12,795 12,960 13.3 13.3 13.3 13.3 13.3 9.2 9.2 10.2 11.3 12.3 600 600 450 280 153 13.2 10 13,123 13.3 13.2 50 13.2 13.3 10 (0) 13,123 13,123 13.3 13.5 13.3 13.2 35 40 PORE KTOL PRESSURE (bbl) (ppg) PORE KTOL PRESSURE (bbl) (ppg) WEOX02.009 1-43 Rev 1 March 1995 BP WELL CONTROL MANUAL Figure 1.10 Example Calculations using Excel Kick Tolerance Calculator KICK TOLERANCE CALCULATOR For Vertical, Deviated or Horizontal Wells Version 1.2, March 1995 Example Calculation Well: Kick Zone Parameters: 1 2 3 4 5 6 7 UK Units: (UK/US): Input Messages: Openhole Size ? Measured Depth ? Vertical Depth (m) ? Horizontal Length (Angle>87 deg) ? Tangent Angle Above Horizontal ? Min Pore Pressure Gradient ? Max Pore Pressure Gradient ? (inch) (m) (m) (m) (deg) (sg) (sg) 12.25 4000 4000 0 0 1.580 1.600 (m) (m) (deg) (sg) 2695 2695 0 1.720 Bottom Hole Assembly OD ? Bottom Hole Assembly Length ? Drillpipe OD ? Gas Hydrostatic Pres Gradient ? Pressure Safety Factor ? Mud Weight in Hole ? (inch) (m) (inch) (sg) (psi) (sg) 8 182 5 0.2 220 1.600 Annular Capacity Around BHA: Annular Capacity Around DP: Fracturing Pres at Weak Point: Max Allowable Shut-in Csg Pres: (bbl/m) (bbl/m) (psi) (psi) Min Pore Pressure at Kick Zone: Maximum Allowable Gas Height: Kick Tolerance at Min Pore Pres: (psi) (m) (bbl) 8981 178 48.7 Max Pore Pressure at Kick Zone: Maximum Allowable Gas Height: Kick Tolerance at Max Pore Pres: (psi) (m) (bbl) 9094 120 33.0 Non-Horizontal Weak Point Parameters: 8 9 10 11 Measured Depth ? Vertical Depth ? Section Angle (<87 deg) ? Fracture Gradient / EMW ? Other Parameters: 12 13 14 15 16 17 0.27426 0.39854 6587 240 Comments: Pore Pressure Gradient 1.60 1.60 1.59 33 41 49 1.59 1.58 1.60 1.59 1.58 1.58 1.57 33 41 Kick Tolerance (bbl) For more infor or help, please contact YUEJIN LUO, BP Exploration, Sunbury, Tel: 853-2424, Fax: 853-4183 1-44 March 1995 1995 Rev 1 March 49 BP WELL CONTROL MANUAL Figure 1.10 Example Calculations using Excel Kick Tolerance Calculator (cont'd) APPENDIX: Maximum Allowable Gas Influx Volume Based on Surface Equipment Rating & Casing Burst Max Allowable Surface Pressure ? Casing ID in Surface Section ? (psi) (inch) 5000 12.515 Annular Capacity: (bbl/m) 0.419456 At Minimum Pore Pressure Gradient: Maximum Allowable Gas Height When Gas Arrives at Surface: Max Allowable Gas Vol. on Shut-in: Comments: (m) (bbl) 2460 613 At Maximum Pore Pressure Gradient: Maximum Allowable Gas Height When Gas Arrives at Surface: Max Allowable Gas Vol. on Shut-in: (m) (bbl) 2403 547 Pore Pressure Gradient 1.60 1.60 547 580 613 1.59 1.60 1.59 1.58 1.59 1.58 540 550 560 570 580 590 600 610 620 Max Allowable Gas Volume on Shut-in (bbl) For more infor or help, please contact YUEJIN LUO, BP Exploration, Sunbury, Tel: 853-2424, Fax: 853-4183 1-45 Rev 1 March 1995 BP WELL CONTROL MANUAL 2 THE PREVENTION OF A KICK Section Page 2.1 CORRECT TRIPPING PROCEDURES 2-1 2.2 MAINTAIN SUITABLE HYDROSTATIC PRESSURE 2-9 2.3 CONTROL LOST CIRCULATION 2-17 Formation pressures are contained by the hydrostatic pressure of a column of drilling fluid – this is primary well control. If primary control is lost the blowout preventers are closed and secondary well control techniques are used to kill the well. Primary control is maintained by ensuring that a full column of drilling fluid of an appropriate weight is allowed to exert its full hydrostatic pressure in the hole. Industry wide experience has shown that the most common causes of loss of primary control and hance the well kicks are: • Swabbing during trips. • Not adequately filling the hole during a trip. • Insufficient mud weight. • Lost circulation. The evidence also shows that the majority of kicks have occurred during trips. This chapter outlines the measures that are required to eliminate or minimise the risk of a kick due to the above causes, and to minimise influx volumes if a kick occurs. March 1995 BP WELL CONTROL MANUAL 2.1 CORRECT TRIPPING PROCEDURE Paragraph Page 1 General 2-2 2 Prior to Tripping 2-2 3 Tripping Procedure 2-5 4 Special Procedure for Oil Base Muds 2-8 Illustrations 2.1 Typical Trip Tank Hook-up – on a floating rig 2-3 2.2 BP Trip Sheet – example of a completed sheet 2-4 2.3 Example of Standing Orders for Driller 2-6 2-1 March 1995 BP WELL CONTROL MANUAL 1 General Industry wide experience has shown that the majority of well control problems have occurred during trips. It is therefore particularly important that special attention is paid to ensuring correct tripping procedure. During tripping the potential exists for a significant reduction in bottomhole pressure due to the following effects: • Reduction in ECD as the pumps are stopped. • Swab pressures due to pipe motion. • Reduction in height of the mud column as pipe is removed from the well. The procedures required to deal with an influx when the pipe is off bottom are not so straightforward as when the pipe is on bottom. Every effort must therefore be made to ensure both that the well is stable prior to initiating a trip out of the hole, and that correct tripping procedure is strictly adhered to. 2 Prior to Tripping Considerable preparation is required before the trip is commenced. The following are among the most important actions that should be carried out prior to tripping: • Circulate the hole – The mud should be conditioned to ensure that tripping will not cause excessive swab/ surge pressures. – Any entrained gas or cuttings should be circulated out. – The mud weight should be such as to ensure an adequate overbalance will exist at all times during the trip. • Determine the maximum pipe speed – Swab/surge pressures should be calculated at various tripping speeds using the appropriate formulae. (See Chapter 3, Volume 2.) – The maximum average pipe speed should be selected bearing in mind the estimated overbalance or trip margin. • Line up the trip tank – Company policy states that: “A trip tank must be available on every rig and be complete with a mechanically operated indicator of the trip tank level, visible from the Driller’s position. The trip tank level must also be monitored from the Mud Logger’s cabin.” 2-2 March 1995 BP WELL CONTROL MANUAL TRIP TANK LEVEL INDICATOR REMOTE CONTROL VALVE RIG FLOOR OVERBOARD ROTARY TABLE DIVERTER RETURNS TO SHAKERS HOLE FILL UP LINE FLOWLINE TELESCOPIC JOINT FROM MISSION PUMPS RISER CHECK VALVE DRAIN TRIP TANK PUMP WEOX02.010 Figure 2.1 Typical Trip Tank Hook-up – on a floating rig Figure 2.1 shows a typical trip tank hook-up on a floating rig. – It is considered unsafe to trip without a trip tank and as such, spare parts for the hole fill pump/motor should be kept at the rig site. – In order that maximum use is made of the trip tank on trips in and out of the hole, a trip sheet should be used to record the mud volumes required to keep the hole full. • Fill in the trip sheet – Company policy states that: “A trip sheet will be filled out by the Driller on every trip.” 2-3 March 1995 BP WELL CONTROL MANUAL Figure 2.2 BP Trip Sheet – example of a completed sheet TRIP SHEET WELL No 26 RIG HOLE DEPTH RIG 20 DATE AND TIME CHANGE BIT No 20 REASON FOR TRIP 15.30 27/8/87 A.C.E. 3250m 5 in DRILLPIPE : 0.0246 bbl/m : 0.697 bbl/stand DISPLACEMENT OF 5 in : : bbl/m : 1.60 7.35 bbl/stand 91/2 in 0.0564 0.2624 bbl/m DISPLACEMENT OF HEAVYWEIGHT DRILL COLLARS DISPLACEMENT OF in : bbl/ : DISPLACEMENT OF in : bbl/ : Trip On: Doubles Stands NO OF STANDS TO TOP OF BHA AT THE STACK STAND STAND ……… ……… No Increment 1 2 3 5 7 10 15 20 25 1 1 1 2 2 3 5 5 5 Single Double Stands Single Double Stands Measured Hole Fill/Disp Trip Tank Volume increment (bbl) (bbl) 30.5 30.0 29.4 28.6 27.2 25.9 23.8 20.1 16.6 13.2 1 3250m INITIAL BIT DEPTH DISPLACEMENT OF Singles SHEET No DRILLER : bbl/stand bbl/stand bbl/stand NO OF STANDS TO CASING SHOE 53 STANDS 108 STANDS AND 1 SINGLE Calculated Fill/Disp Discrepancy Remarks accum (bbl) increment (bbl) accum (bbl) increment (bbl) accum (bbl) 0.5 0.6 0.8 1.4 1.3 2.1 3.7 3.5 3.4 0.5 1.1 1.9 3.3 4.6 6.7 10.4 13.9 17.3 0.7 0.7 0.7 1.4 1.4 2.1 3.5 3.5 3.5 0.7 1.4 2.1 3.5 4.9 7.0 10.5 14.0 17.5 -0.2 -0.1 +0.1 0 -0.1 0 +0.2 0 -0.1 -0.2 -0.3 -0.2 -0.2 -0.3 -0.3 -0.1 -0.1 -0.2 (1) (2) (3) (4) (1)-(3) (2)-(4) WEOX02.011 2-4 March 1995 BP WELL CONTROL MANUAL – Figure 2.2 shows a completed example of the BP trip sheet. This trip sheet should be used if the contractor cannot provide a similar sheet. The basic requirement for a trip sheet is that a clear method of comparing calculated with actual hole fill volumes is provided. The cumulative discrepancy between the two values should also be recorded. – The trip sheet for the last trip out of the hole should be available for comparison. • Provide the Driller with the necessary information – The Driller should be told the reason for the trip. – He should be told of any indicators of increasing pore pressure or near balance that were identified during drilling before, or since, he came on shift. – He should be fully aware of the procedures to be adopted in the event of a kick while tripping. – An example of the standing orders that should be provided to the Driller is shown in Figure 2.3. • Drill floor preparation – Crossovers should be available on the rig floor to allow a full opening drillpipe safety valve to be made up to each tubular connection that is in the hole. – A drillpipe safety valve (kelly valve) should be available on the rig floor. It should be kept in the open position. – A back-up safety valve, such as a Gray valve, should be available close to the rig floor. This valve should only be used in the event that the drillpipe safety valve does not hold pressure, or if stripping in the hole is required and no dart sub is fitted. – The rig crew should be completely familiar with, and practiced in, their responsibilities in the event of a kick. 3 Tripping Procedure Having completed the preparations as outlined in the previous section, the trip out of the hole can be started. The following procedure is proposed as a guideline: 1. Flow check the well with the pumps off to ensure that the well is stable with the ECD (equivalent circulating density) effect removed. 2. Pump a slug. This enables the pipe to be pulled dry and the hole to be accurately monitored during a trip. 2-5 March 1995 BP WELL CONTROL MANUAL Figure 2.3 Example of Standing Orders for Driller STANDING ORDERS TO DRILLER WHILE TRIPPING WELL NO 15 ORDERS EFFECTIVE DATE 15/6/87 RIG RIG 12 ON ALL TRIPS COMPANY REP K.D. SMB TOOLPUSHER IF ANY OF THE FOLLOWING OCCUR: 1. HOLE NOT TAKING CORRECT VOLUME DURING THE TRIP 2. THE WELL IS FLOWING 3. …………………………………………………………………………… 4. …………………………………………………………………………… 5. …………………………………………………………………………… 6. …………………………………………………………………………… 7. …………………………………………………………………………… 8. …………………………………………………………………………… Or if there is any other possible indication of a kick. 1. STOP TRIPPING OPERATIONS 2. FLOWCHECK THE WELL IF NECESSARY YES IS THE WELL FLOWING? NO 1. NOTIFY COMPANY REPRESENTATIVE AND TOOLPUSHER 1. SET THE SLIPS …………………………………………………………… 2. INSTALL OPEN DP SAFETY VALVE …………………………………………………………… 2. PROCEED AS DIRECTED 3. CLOSE DP SAFETY VALVE …………………………………………………………… 4. OPEN CHOKE LINE VALVE (S) …………………………………………………………… 5. CLOSE ANNULAR PREVENTER …………………………………………………………… 6. CHECK THAT WELL IS SHUT IN …………………………………………………………… 7. NOTIFY COMPANY REPRESENTATIVE …………………………………………………………… 8. INSTALL KELLY …………………………………………………………… 9. LINE UP STANDPIPE MANIFOLD …………………………………………………………… 10. OPEN DP SAFETY VALVE …………………………………………………………… 11. RECORD DP AND CSG PRESSURE …………………………………………………………… 12. IF IN OPENHOLE: ENGAGE …………………………………………………………… BUSHINGS, ROTATE THE PIPE …………………………………………………………… 13. PROCEED AS DIRECTED …………………………………………………………… …………………………………………………………… WEOX02.012 2-6 March 1995 BP WELL CONTROL MANUAL The following formula can be used to calculate the volume of slug to ensure a length, L, of dry pipe: Vsl = MW X L X Cp (bbl) (MWsl – MW) where Vsl L Cp MWsl MW = = = = = volume of slug (bbl) length of dry pipe (m) internal capacity of the pipe (bbl/m) slug weight (SG) mud weight in the hole (SG) As a general rule, the slug should be mixed to maintain a minimum of 2 stands of dry pipe. It is important to accurately displace the slug to the pipe. In this manner, the Driller will know the weight, depth and height of the slug at all times during the trip. 3. For the first 5 – 10 stands off bottom, monitor the hole through the rotary. This is to check that the annulus is falling as pipe is removed from the hole. The pipe wiper should therefore be installed only after the first stands have been pulled. The trip tank should not be overfilled at this stage to ensure that swabbing is clearly indicated, should it occur. The circulating pump should be switched off at this stage and the hole filled from the trip tank, after each stand. 4. Circulate the hole across the trip tank and continue to trip out, monitoring hole volumes with the aid of the trip sheet. 5. Conduct a flowcheck when the BHA is into the casing shoe. 6. Conduct a flowcheck prior to pulling the BHA through the stack. Be aware that the required hole fill volume per stand of heavy weight and drill collars will be greater than for drillpipe as the BHA is being removed from the hole. If unsure of the overbalance, consideration should be given to conducting a short round trip. Once back on bottom, the overbalance can be assessed from the level of the trip gas at bottoms up. If the hole does not take the correct amount of fluid at any stage in the trip, a flowcheck should be carried out. If the flowcheck indicates no flow and the cause of the discrepancy cannot be accounted for at surface, the string should be returned to bottom while paying particular attention to displacement volumes. After circulating bottoms up, it may be necessary to increase the mud weight before restarting the trip out of the hole. If the flowcheck is positive, the well should be shut-in according to the procedure indicated in the standing orders. Subsequent action will be dependent upon the conditions at the rigsite (See Chapter 5). 2-7 March 1995 BP WELL CONTROL MANUAL 4 Special Procedure for Oil Base Muds When oil base mud is in use, gaseous fluids have a tendency to go into solution with the mud at high temperature and pressure. Experience has shown that once an influx has gone into solution, it will not break out of solution until the bubble point is reached, typically at 1000 – 1500psi (this will depend on the fluids concerned). The possible consequence of this is that a small influx that was undetected at depth may suddenly break out of solution close to the surface. This may cause a dangerous liberation of gas at surface as well as significant reduction in hydrostatic pressure in the well. Consideration should also be given to the possibility of thermal expansion of the mud at high temperatures. This can cause a reduction in effective mud weight and hence in the overall hydrostatic head. It is therefore recommended that tripping procedures are modified to take account of this potential problem when oil base mud is in use in the following situations: • When drilling or coring in a potential pay zone. • On prediction of an increase in pore pressure. • On detecting significant levels of gas in the mud. In these circumstances the following procedure is recommended prior to pulling out of the hole: 1. Flow check the well. 2. Circulate bottoms up. 3. Check trip to the shoe monitoring hole volumes. 4. Flow check at the shoe and run back to bottom. 5. Circulate bottoms up. Close in the BOP and circulate through the choke when the potential influx is at 500m below the stack, watching for any pit gain. 6. If necessary increase the mud weight and perform a further check trip. This procedure can be relaxed if, after several trips under the same conditions, the well remains stable. The following procedure is recommended in these circumstances after a round trip. 1. When back on bottom prior to any further drilling or coring, circulate bottoms up to check for trip gas. 2. Circulate until potential influx is at 500m below the stack, watching for any pit gain. 3. Close in the well and circulate the potential influx through the choke. 2-8 March 1995 BP WELL CONTROL MANUAL 2.2 MAINTAIN SUITABLE HYDROSTATIC PRESSURE Paragraph Page 1 General 2-10 2 Gas Cutting 2-10 3 Cuttings Contamination 2-14 Illustrations 2.4 Bottomhole Pressure Reduction – due to gas cutting 2-12 2-9 March 1995 BP WELL CONTROL MANUAL 1 General Primary well control is achieved by controlling formation pressures with the hydrostatic pressure of the drilling fluid. The drilling fluid may be contaminated with cuttings and formation fluids during drilling. These contaminants can significantly alter the effective hydrostatic pressure exerted by the drilling fluid, and in certain circumstances, this can cause loss of primary control. Hydrostatic pressure will be reduced once drilling stops as a result of the loss of annulus frictional pressure and the removal of cuttings from the annulus. The settling of cuttings to the bottom of the hole may significantly reduce the hydrostatic pressure further up the hole. This section outlines the techniques that can be used to predict the effect of drilling fluid contamination on the hydrostatic pressure. 2 Gas Cutting When drilling through a formation that contains gas, it is inevitable that the mud will become contaminated with gas from the drilled formation even if the formation is penetrated overbalance. Drilled gas will enter the mud system at a rate determined by the following factors: • Rate of penetration, ROP (m/hr) • Hole diameter, d h (in.) • Formation porosity, Ø (fractional) • Gas saturation, Sg (fractional) The rate of gas entering the mud at bottomhole conditions, Qgas (gal/min), is given by the following formula: Qgas = dh 24 2 X (gal/min) 1.285 X ROP X Ø X Sg Therefore as an example in the following conditions: ROP dh Ø Sg Bottomhole pressure Hole depth and depth at which gas enters the mud, D Qgas = 12.25 24 2 X = = = = = = 3020m 1.285 X 25 X 0.2 X 0.75 = 1.26 gal/min at 6000psi 2-10 March 1995 25 m/hr 12 1/4 in. 0.2 0.75 6000psi BP WELL CONTROL MANUAL Therefore at atmospheric pressure the gas flowrate is given by: Qgas = 1.26 X 6000 = 514 gal/min at atmospheric pressure 14.7 This simplified calculation treats the gas as ideal and does not consider the effects of temperature. In this hole section the flowrate of mud is 700 gal/min; the actual mud weight at surface can be calculated using the following formula: MW act = MW X where MWact MW Qmud Qgas = = = = Qmud Qmud + Qgas actual mud weight at surface (SG) uncut mud weight (SG) flowrate of mud (gal/min) flowrate of gas (gal/min) Therefore in this case the actual (or gas cut) mud weight at surface is given by: MW act = 1.4 X 700 = 0.81 SG 700 + 514 It should be stressed that this figure is an estimation of the actual mud weight at the flowline and as such will not reflect the actual density of the mud in the hole. The percentage gas cutting is given by: Percentage cut = MW – MWact X 100 MW Which in this case gives a figure of: Percentage cut = 1.4 – 0.81 1.4 X 100 = 42% cut The following formula can be used to estimate the bottomhole pressure reduction due to gas cut mud: ∆P = 14.7 (MW – MW act) ln (96.46 X MW X D) MW act 1000 (psi) where ∆P = bottomhole pressure reduction due to gas cutting (psi) D = depth at which gas enters the mud (m) Figure 2.4 shows the effect of various levels of gas cutting for two different mud weights using the above formula. It should be noted that these curves represent an ideal gas; temperature and solubility effects are not considered. In this case: ∆P = 14.7 (1.4 – 0.81) ln (96.46 X 1.4 X 3020) 0.81 1000 (psi) ∆P = 64psi 2-11 March 1995 BP WELL CONTROL MANUAL Figure 2.4 Bottomhole Pressure Reduction – due to gas cutting 0 20 40 60 80 100 0 -1000 -2000 TRUE VERTICAL DEPTH (m) 2.1 SG 1.05 SG -3000 2.1 SG 1.05 SG 2.1 SG -4000 1.05 SG 2.1 SG 1.05 SG -5000 2.1 SG 1.05 SG -6000 2.1 SG 1.05 SG 5% 10% 20% 30% 40% 50% PERCENT GAS CUT AT THE FLOWLINE -7000 0 20 40 60 80 100 DECREASE IN BOTTOMHOLE PRESSURE (psi) WEOX02.013 2-12 March 1995 BP WELL CONTROL MANUAL Therefore the average mud weight in the hole is equal to: MW = (6000 – 64) = 1.38 SG 3020 X 1.421 It can be seen that what appeared to be significant gas cutting, at 42%, caused a very small reduction in the bottomhole pressure and actually only reduced the effective mud weight by 0.02 SG, or by a factor of 1.4%. The actual reduction in bottomhole pressure is caused by the gas when it has considerably expanded. This expansion does not occur until the gas has been circulated to near the surface. As can be seen from the previous example, this near surface expansion has a small effect on the bottomhole pressure in a deep well for moderate levels of gas cutting. However the effect of near surface expansion may be critical in relatively shallow hole sections. The effect of gas cutting in a relatively shallow hole is demonstrated with the following example: dh Instantaneous ROP D MW = = = = 24 in. 80 m/hr 300m 1.13 SG Ø Sg Pump output Formation pressure = = = = 0.3 0.7 750 gal/min 1.03 SG Gas enters the mud system at a rate given by: = 24 24 2 X 1.285 X 80 X 0.3 X 0.7 = 21.6 gal/min at bottomhole conditions Gas flowrate at surface is given by: 21.6 X 1.03 X 1.421 X 300 = 645 gal/min 14.7 The actual mud weight at surface is given by: 750 750 + 645 X 1.13 = 0.61 SG Corresponding to a pressure reduction of: 14.7 X (1.13 – 0.61) ln (96.46 X 1.13 X 300) = 44 psi 0.61 1000 The average mud weight in the hole is given by: (1.13 X 1.421 X 300) – 44 = 1.02 SG 300 X 1.421 Quite clearly the potential exists for the well to kick in this situation, given that the pore pressure at this depth is assumed to be normal at 1.03 SG. 2-13 March 1995 BP WELL CONTROL MANUAL Industry experience has shown that excessive gas cutting in shallow hole has in many cases been the cause of shallow gas blowouts in offshore environments. The previous example shows the possible effect of gas cutting in shallow hole. However it should also be noted that in shallow hole the annulus pressure loss during circulation will be negligible, and the expansion of the gas may cause mud to be unloaded at surface, thereby further reducing the hydrostatic head of the mud column. It is therefore important that the ROP is restricted in shallow hole. High pump output should also be maintained to disperse the gas within the mud to minimise variations in SG. 3 Cuttings Contamination One of the most important functions of the drilling fluid is to transport cuttings from the bit to the surface. The presence of cuttings in the annulus will increase the effective hydrostatic pressure of the fluid column. If this increase is excessive, it can cause losses which may possibly lead to the loss of primary control. It is therefore useful to be able to estimate the additional pressure caused by the cuttings in the annulus. In order to be able to estimate this additional pressure, a measure of the ability of the drilling fluid to remove the cuttings from the well is required. The cuttings slip velocity is defined as the velocity of the cuttings relative to the velocity of the mud. There are many factors that influence the cuttings slip velocity, however the following relationship can be used to estimate its value: Slip Velocity, v s = 108 where vs µ MW wcut dcut = = = = = X d cut X (wcut – MW) MW 0.333 X µ0.333 0.667 slip velocity (m/min) average viscosity (cP) mud weight (SG) average cuttings weight (SG) cutting average diameter (in.) However, if the particle Reynolds number is greater than 2000, the following formula should be used to calculate the slip velocity: vs = 34.56 dcut (w cut – MW) 1.5 X 1 2 MW The particle Reynolds number, Re is given by: Re = 422.78 X MW X v s µ X d cut 2-14 March 1995 BP WELL CONTROL MANUAL The transport ratio is defined as the ratio of the actual cuttings velocity to the mud velocity; it is therefore determined as follows: Transport ratio, TR = v m – vs vm where vm = Q 0.134(d hc 2 – do 2) (m/min) and vm = mud velocity (m/min) Q = pump output (gal/min) dhc = hole/casing ID (in.) do = pipe OD (in.) The concentration of cuttings in the annulus can be calculated from the following formula: Ca = ROP X d bit2 X (1 – Ø) 448.4 X Q X TR where ROP = rate of penetration (m/hr) dbit = diameter of the bit (in.) Ø = porosity The extra pressure caused by the cuttings in the annulus is given by the formula: ∆P = (w cut – MW) X 1.421 X sum (L X Ca) where L = the length of each section (m) The cuttings concentration must therefore be determined for each section of hole. Consider the following example for a 17 1/2 in. hole section drilled from a floating rig. Casing shoe at 900m Casing ID = 22 in. Riser ID = 22 in. Bit size = 17.5 in. Drillpipe OD = 5 in. Collar OD/length = 8 in./180m Mud weight = 1.5 SG The slip velocity Average viscosity Pump output ROP Openhole length Cuttings density Cuttings diameter = 50 cP = 700 gal/min = 50 m/hr = 180 m = 2.5 SG = 0.3 in. = 108 X 0.3 X (2.5 – 1.5)0.667 1.50.333 X 50 0.333 = 7.7 m/min The velocity of the mud in 17 1/2 in. hole is given by: Velocity = 0.134 X 700 (17.5 2 – 82) = 21.6 m/min In the 22 in. section: Velocity = 0.134 X 700 (22 2 – 52) = 11.4 m/min 2-15 March 1995 BP WELL CONTROL MANUAL This gives a transport ratio of 64% in 17 1/2 in. hole and of 32% in 22 in. hole. The cuttings concentration, Ca, in the 17 1/2 in. hole is given by: Ca = 50 X 17.5 2 448.4 X 700 X 0.64 = 0.076 (= 7.6%) In the 22 in. hole section: Ca = 50 X 17.5 2 448.4 X 700 X 0.32 = 0.152 (= 15.2%) The porosity is not considered. The additional hydrostatic pressure due to the cuttings is determined as follows: ∆P = (2.5 - 1.5) X 1.421 X [(0.076 X 180) + (0.152 X 900)] ∆P = 214 psi This additional pressure therefore increases the effective mud weight to a figure given␣by: MW = (1.5 X 1.421 X 1080) + 214 1080 X 1.421 = 1.64 SG 2-16 March 1995 BP WELL CONTROL MANUAL 2.3 CONTROL LOST CIRCULATION Paragraph Page 1 General 2-18 2 Causes of Lost Circulation 2-18 3 Classification of Lost Circulation 2-19 4 Identification of Loss Zone 2-19 5 General Procedure for Spotting Plugs 2-20 6 Lost Circulation Decision Analysis 2-23 7 Drilling Blind 2-27 Illustrations 2.5 Balanced Plug Technique 2-22 2.6 Lost Circulation Remedies 2-24 2-17 March 1995 BP WELL CONTROL MANUAL 1 General Lost circulation can occur as a result of the following: • Unconsolidated or highly permeable low pressure formations (including depleted reservoirs and at the base of long permeable reservoirs). • Natural fractures. • Induced fractures. • Cavernous formations. Lost circulation is undesirable primarily for three reasons. Firstly, that a loss of hydrostatic head may lead to the well kicking and secondly, that the cost of the replacement mud required may be considerable. Thirdly, it precludes accurate monitoring of the hole. This section is intended to outline how to identify the different types of loss zone and, in each case, to determine the most appropriate remedy. 2 Causes of Lost Circulation These are as follows: • Setting intermediate casing too high Optimum casing design ensures that weak formations are isolated prior to drilling into known areas of higher pressure. • Drilling with excessive overbalance • Drilling too fast Overloading the annulus can cause excessive ECDs or the formation of mud rings as the concentration of cuttings increases. • Swab/surge pressures when running pipe The mud properties and tripping procedures must be controlled to ensure that surge pressures are not excessive when running pipe. Care should be taken when breaking circulation, possibly by breaking circulation at several depths on the trip in the hole. • Mud cake build up In severe cases, mud cake can reach a level where the hole packs-off around the drillstring. To minimise this problem good fluid loss control and maximum use of the solids-control equipment must be coupled with a low fluid-loss mud. The drilled solids content of the mud must be carefully controlled, by dilution if necessary. 2-18 March 1995 BP WELL CONTROL MANUAL 3 Classification of Lost Circulation The severity of the loss zone can be assessed as follows: • Seepage Losses (0.25 – 10 bbl/hr) This takes the form of very slow losses or sometimes undetectable loss to a permeable formation. In some instances, this may be due to filtration loss due to poor fluid loss control. (The identification of seepage losses may be confused with the removal of cuttings from the mud at the shakers.) Curing this level of loss is sometimes not economical if a cheap mud is in use and the rig rate is high. If pressure constraints are tight the losses may have to be cured. Other factors such as the need for a good cement job, formation damage or the risk of possible stuck pipe need to be considered in specific cases. • Partial Losses (10 – 500 bbl/hr) Because these losses are more severe the cost of the mud in use becomes more important and so it is more likely to be economical to take some rig time to cure them. Drilling with losses can be considered if the fluid is cheap and the pressures are within operating limits. • Complete Losses (500 bbl/hr – No returns) If complete loss of returns is experienced, immediately pump water down the annulus, monitoring the volumes required to fill the hole. From the volume required, the hydrostatic head that the hole can maintain should be determined. When drilling in top hole sections with high ROP, complete losses may be caused by overloading the annulus. In this case consideration should be given to pulling out and circulating in stages to clean the hole. If efforts to cure the losses are unsuccessful, consideration may be given to drilling blind. 4 Identification of Loss Zone The formation type determines the most appropriate remedial treatment required to cure losses. It is therefore important that the loss zone is correctly identified. Each type of lost circulation zone will exhibit certain characteristics which can be outlined as follows: • Unconsolidated formations Occur mainly at shallow depth. For whole mud to be lost to a formation, in the absence of fractures, requires permeability of the order of 10 Darcies. Will cause a gradual loss of mud to the hole, however, may worsen if no remedial action is taken. 2-19 March 1995 BP WELL CONTROL MANUAL • Natural fractures Can occur in many rock types. May cause a gradual loss of mud to the hole, however if drilling proceeds and more fractures are exposed, complete losses may be experienced. • Induced fractures Horizontal fractures may be induced at relatively shallow depths after the formation of mud rings and by overloading the annulus. The formation of a mud ring will be indicated by an increase in pump pressure and the drillstring becoming tight. Vertical fractures may occur at greater depth and may be caused by any pressure surge on the formation. Usually indicated by sudden and complete losses. • Cavernous formations Normally only experienced in limestone formations. Loss of returns may be sudden and complete. May be accompanied by the bit dropping up to several feet depending on the height of the cavern. • Underground blowout Condition where the act of shutting in on a kick induces a fracture in the openhole above the point of influx. Kick fluids flow, usually from the lower active zone to the zone which has been fractured. Generally indicated by unstable pressure readings at surface. The depth of the loss zone must be established in order to calculate the hydrostatics involved and to determine the remedial action required. The loss zone can be located using a Temperature Survey, which operates by identifying a discontinuity in the temperature gradient within the wellbore. A noise log may also be used. Correlation with the known lithology at the confirmed loss zone is very important to identify the type of formation that has been fractured. 5 General Procedure for Spotting Plugs Accurate placement of plugs downhole is vital if the loss zone is to be sealed. To do this, accurate measurement of pump efficiencies and internal pipe sizes must be made. When drilling in areas of potential lost circulation, large nozzles should be fitted to the bit. However, coarse LCM must not be pumped through a bit with nozzles. When the bit in the hole contains small nozzles and an LCM pill is required, consideration should be given to tripping the pipe and running a bit with large nozzles or even open ended drillpipe. The use of bits with a centre jet will also increase the area available for spotting plugs. When the plug is being spotted, keep the pipe moving to avoid getting stuck. When placing plugs containing cement, wherever possible the slurry formulation should be tested by the cementing contractor to determine thickening time. 2-20 March 1995 BP WELL CONTROL MANUAL The best displacement method for placing plugs is to use the balanced plug technique. This is however not always possible to achieve or desirable, depending on the rate of loss or the type of slurry to be pumped. In general, placement techniques will be as follows (refer to Paragraph 6 for recipes): (a) Conventional circulation Used for techniques 2A and 2B. Place the plug through open ended pipe (if possible) opposite the loss zone. Pump at 1.0␣bbl/min until the losses cease. (b) Balanced plug Used for techniques 3A, 3B, 3C, 4A, 4B, 4C and 4D. The balanced plug method should be used for the above techniques. However, if cement in any of the above techniques and it becomes necessary to spot the plug through a bit, the balanced plug technique should not be used. In this case, the bit should be tripped into the casing and the non-balanced plug technique used (See/(c)). The basic requirement for a balanced plug is that the correct volume of spacer is pumped behind the slurry, to ensure that the hydrostatic pressure in the annulus is balanced with that in the pipe before the pipe is pulled out of the plug. The pipe is then pulled out of the plug. If it is decided to squeeze the plug, 2 bbl should be pumped down the pipe, the BOPs closed and then squeeze pressure applied on the annulus below the rams. Balanced plugs can be allowed to lose to the formation under the hydrostatic head of the column alone, or by squeezing. It may be desirable to reverse circulate the pipe contents, if this is possible after pulling out of the plug. Plug balancing calculations are as follows: • Calculate the volume of cement plug for the required height of plug Volume (bbl) = height (m) X hole capacity (bbl/m) X factor for excess No of sacks required = volume (bbl) slurry yield (bbl/sk) 2-21 March 1995 BP WELL CONTROL MANUAL TUBING MUD L SPACER where h = height of spacer (m) H = height of plug (m) L = drillpipe/tubing length (m) h H PLUG WEOX02.014 Figure 2.5 Balanced Plug Technique • With the volume of spacer ahead known calculate the height and volume of spacer behind (See Figure 2.5) If the same fluid is used before and after the plug: h = Spacer vol ahead (bbl) annulus capacity (bbl/m) Spacer vol behind (bbl) = h X pipe capacity (bbl/m) where h = height of spacer (m) 2-22 March 1995 BP WELL CONTROL MANUAL • Calculate the height of the cement plug before the pipe is pulled out H(m) = Volume of slurry(bbl) annulus cap (bbl/m) + pipe cap (bbl/m) where H = height of the plug (m) • Calculate the plug displacement volume Displacement volume (bbl) = (L – H – h) X pipe cap (bbl/m) where L = Drillpipe/tubing length (m) (c) Non-balanced plug Used for techniques 5A, 5B, 6, 7A and 7B or whenever using techniques 3C, 4A, 4B and 4C through a bit. Where the loss zone depth is known with certainty then the pipe can be placed approximately␣50m above it. The slurry is displaced to the end of the pipe and the BOP is closed. For a downhole mixed plug, pump simultaneously down the annulus and pipe at 2␣bbl/min. For a spotted plug pump the slurry out of the pipe plus 5 bbl excess, then pump down the annulus only. 6 Lost Circulation Decision Analysis Figure 2.6 can be used as a guide to determining the most suitable method of dealing with a lost circulation problem. The techniques referred to in Figure 2.6 are specified below. • Technique 1 Pull up and wait The bit should be pulled up to safety inside casing and the hole left static for 4 to 8/hours without circulation. (While waiting, a lost circulation pill can be mixed (eg/2A or 2B), at comparatively low cost, for use in case the zone does not self heal.) This technique is only likely to succeed in zones of induced fractures. It is therefore not applicable to naturally occurring horizontal loss zones eg/gravels, natural fractures, vugs and caverns where the overburden is self-supporting. • Technique 2A LCM pill Mix a 100 – 500 bbl pill as follows: 100 – 500 bbl mud 15 lb/bbl fine walnut/sawdust/etc 10 lb/bbl fine fibres (wood, mica or cane) 5 lb/bbl medium to fine fibres (wood, cane, mica or similar) 5 lb/bbl large cellophane flakes (1.0 in. diameter) Pump the pill as recommended in Paragraph 5. Repeat if the hole still takes fluid. If the hole is still not filling go on to use a ‘High filter loss slurry squeeze’. 2-23 March 1995 BP WELL CONTROL MANUAL LOST CIRCULATION REMEDIES TYPE OF LOSS SEVERITY OF LOSS, bbl/hr Seeping 1 – 10 to horizontal loss zones** to induced vert fractures Partial 10 – 500 to horizontal loss zones** LOSS ZONE GEOMETRY to induced vert fractures Complete 500 – complete to horizontal loss zones** Long honeycomb or caverns (only in limestones) Complete to horizontal loss zones** Deep induced fractures Complete Vertical in WBM or OBM in WBM in WBM in WBM in OBM in OBM in OBM * Usually not in use where loss zones are horizontal. They consist of porous sands and gravels, natural fractures, and honeycomb and caverns. EFFECTIVE IN LOST CIRCULATION REMEDIAL TECHNIQUE Technique 2A – Plug of fine bridging agents in mud Technique 3A – High-filter-loss slurry squeeze with fine bridging agents Technique 1 – Pull up and wait (primarily for induced vertical fracture) Technique 2B – Plug of medium bridging agents in mud Technique 3A – High-filter-loss slurry squeeze with coarse bridging agents Technique 3B or 3C – High-filter-loss slurry squeeze with coarse bridging agents Technique 4B – Thixotropic cement or other cements (4A, 4C, 4D) Technique 5B – Mud + diesel-oil-bentonite plus cement Technique 5A – Downhole-mixed soft plug (mud-diesel oil-bentonite) Technique 7B – Downhole-mixed hard plug (sodium silicate, calcium chloride, cement squeeze Flo-Check) Technique 3A, 3B or 3C – High-filter-loss slurry squeeze with 25 – 35 lb/bbl or coarse bridging agents Technique 5B – Downhole-mixed soft/hard plug continuously mixed in large amounts Technique 1 – Pull up and wait Technique 5B – Downhole-mixed soft/hard plug Technique 5A – Downhole-mixed soft plug Technique 7B – Downhole-mixed hard plug (sodium, silicate, calcium chloride, cement squeeze, Flo-Check) Technique 3B or 3C – High-filter-loss slurry squeeze with coarse bridging agents Technique 4A – Neat portland cement Technique 7B – Downhole-mixed plug (sodium, silicate, calcium chloride, cement squeeze, Flo-Check) WBM OBM* yes yes yes yes yes partial yes yes yes yes yes yes yes no yes no yes yes yes yes yes no yes yes yes yes partial no no yes yes yes yes yes yes yes WBM – water-base mud OBM – oil-base mud Figure 2.6 Lost Circulation Remedies • Technique 2B LCM pill As above but using larger concentrations of coarse materials eg coarse mica, wood, walnut or cellophane. • Technique 3A High filter loss slurry squeeze (Diearth, Diaseal M etc) 100 bbl water 15 lb/bbl bentonite or 1.0 lb/bbl Drispac (or 1.0 lb/bbl XC Polymer) 0.5 lb/bbl lime 50 lb/bbl Diearth, Diaseal M 15 – 20 lb/bbl fine mica, walnut, cellophane or similar material as can be mixed and remain pumpable. 2-24 March 1995 BP WELL CONTROL MANUAL • Technique 3B High filter loss slurry squeeze As Technique 3A but include the following: 15 – 30 lb/bbl medium and coarse LCM • Technique 3C High filter loss slurry squeeze As Technique 3A but include the following: Reduce Diearth concentration to 10 – 25 lb/bbl Use barytes as inert filler at 300 lb/bbl Add cement at 70 lb/bbl Place in 30 bbl slugs into loss zone with 200 psi squeeze pressure. Note: • Wherever possible, slurry formulations should be tested prior to spotting to eliminate possible premature setting. When this is the case, always be aware of the thickening time and avoid leaving cement in or opposite the pipe beyond this time. Technique 4A Neat cement slurry Neat cement slurries give high compressive strength plugs. Mix Class G cement at 1.90 SG in water • Technique 4B Extended cement slurry (using bentonite) Prehydrated bentonite slurry gives a degree of fluid loss control and ‘plating effect’ to help stop lost circulation. Coupled with this, a lightweight slurry can be formulated (1.58 SG) which helps in areas of serious lost circulation. A further benefit is that reasonable compressive strength characteristics are found with slurries of this type. Add 10 lb/bbl bentonite to pre-treated fresh water (with 0.25 lb/bbl caustic and 0.25/lb/ bbl soda ash). Mix cement up to 1.58 SG. • Technique 4C Aggregated cement slurry (with sand or ground coal) Add aggregrate to the neat cement slurry at 1.90 SG up to a maximum weight of 20 – 35 lb/sack of cement in the mix. 2-25 March 1995 BP WELL CONTROL MANUAL • Technique 4D Thixotropic cements Cement of this type exhibits good flow characteristics when being pumped and a quickly developing gel strength when stationary. This thixotropic behaviour is beneficial for the following reasons: – A plug of cement displaced past the loss zone is self supporting and does not fall back under its own weight. – The cement will tend to remain next to the wellbore when squeezed into fractures due to their rapidly developing gel strength. Due to the temperature and chemical formulation sensitivity of this type of slurry, it is not recommended to use this cement without rigorous quality control and testing prior to each job. Halliburton Thixset 1 or 2 are examples of this type of cement. • Technique 5A Downhole mixed soft plug This type of lost circulation pill is designed to mix with a water base mud or formation water in the downhole environment and subsequently be squeezed into the formation. Mix 10.5 gal of diesel or base oil to 100 lb of bentonite. Granular or fibrous LCM may be added to this mix if required, ie mica at 10 ppb plus walnut at 10 ppb. This mixture must be kept away from contact with water until it is placed out of the drillpipe. To do this, a 10 bbl oil spacer is pumped ahead of a plug, followed by 10 bbl after the plug. The principle of this plug is to form a rubbery plug whenever the mixture contacts the water base mud. Formation water will assist the hydration of the bentonite. • Technique 5B Downhole mixed soft/hard plug This type of lost circulation pill is designed to mix with a water base mud or formation water in the downhole environment. It can be designed to form an initially fluid mixture of a soft or semi-hard nature depending on its composition, and can be squeezed into the formation where it will harden and develop compressive strength. The proportion of mud to the pill in the final mix downhole will determine the strength of the plug. For example, a 1:1 mix with fresh water will result in a soft plug, whereas a 1:3 (water/mix ratio) mix will result in a hard plug. In every case however, pilot tests should be carried out at surface for various mixes, prior to spotting the pill. Mix on surface 300 lb of G neat cement and 158 lb of bentonite to 1 bbl of diesel or base oil. All water should be excluded from the mix on surface. 2-26 March 1995 BP WELL CONTROL MANUAL • Technique 6 Downhole mixed soft plug Oleophilic clay and water This type of plug formulation is designed for use in an oil base mud. It works by the same principle as 5A, except that the clay disperses in water and hydrates in oil (the opposite of a bentonite squeeze). Mix on surface 280 lb of oleophilic clay to 1 bbl of water. Add lignosulphonate at 4/lb/ bbl water. An example of oleophilic clay is Baroid Geltone. The spacers ahead and behind this plug must be water based. • Technique 7A Surface mixed soft plug (polymer type) These formulations are mixed on surface, where polymers are blended with activators and extenders, to give a delayed thickening reaction. This allows enough time to place the plug in the loss zone before the chemical reaction takes place. Haliburton Temblok is an example of this type of material. This treatment is only temporary and the yield strength breaks down fairly quickly. It should be followed by a cement slurry to effect a permanent seal. • Technique 7B Downhole mixed hard plug Haliburton Flocheck can be used for this. This is a Sodium Silicate material which on contact with calcium ions forms insoluble Calcium Silicate. By pumping a CaCl 2 brine to the formation, followed by the Flocheck material, plugging of the formation occurs when the two chemicals mix in the formation matrix. Placement as follows: Pump 50 bbl 10% (by weight) CaC12 followed by 10 bbl fresh water. Then pump 35/bbl␣of Flocheck followed by a further 10 bbl fresh water. Care must be taken to ensure that CaC1 2 does not come into contact with Flocheck on surface as it will go hard in the pits. This treatment, whilst permanent, may be reinforced by a cement slurry. 7 Drilling Blind In certain circumstances it may become necessary to drill ahead without any returns at surface, ie drilling ahead blind. This may be required if all attempts as laid out in Paragraph 6 have failed. Once the decision to drill blind has been made, the main objective will be to set casing in the first competent formation penetrated. 2-27 March 1995 BP WELL CONTROL MANUAL Although no cuttings will be obtained while drilling blind, casing seat can be located by logging and by keeping up a penetration log whilst drilling ahead. The hole has to be logged frequently, for example every 100m or whenever the penetration rate suggests a formation change. Once a competent formation has been identified, the new formation has to be penetrated by at least 20m to successfully set and cement the next casing string. Whilst drilling blind the following precautions must be taken: • Use one pump for drilling as normal with the other continuously filling the annulus with water. • Assign personnel to monitor the flowline for returns at all times. • Pick the drillstring up off bottom every 2m drilled to ensure that the hole is not packing off above the bit. • Keep one pit full of viscous mud at all times ready to pump to the hole. • If one pump requires repair, use the cement unit to fill the annulus continuously. • After drilling each single, wipe the hole over a full single and kelly length prior to drilling ahead. Wipe the hole over the length of a stand if using a topdrive. If overpull is experienced wipe the hole 3 or 4 times. Spot a viscous pill around the bit prior to making each connection. This pill should be balanced in and outside the pipe. • If, during drilling, the fluid in the annulus reaches surface, stop drilling immediately. Pick up the drillstring so that the BOPs can be closed if required. Stop the pump on the drillpipe and the annulus. Close in and observe for any pressure build up. – If there is no pressure on the annulus, start up the pump on the drillpipe and circulate bottoms up through a fully opened choke (if this is possible). The loss zone may be plugged with drill cuttings. Drill ahead if everything is normal to a predetermined depth, if the area is well known. Stop and log if the area is not well known to determine if a suitable casing seat has been found and has been sufficiently penetrated. – If there is pressure on the annulus be prepared to adopt procedures for an underground␣blowout. At all times be prepared to cement the well. If tripping is required when complete loss of returns exists then the following precautions must be taken: • Spot a viscous pill across the openhole section. • Before tripping, stop the pumps on drillpipe and annulus and observe the well for 30␣minutes. Keep the string moving and be prepared to close in the well if necessary . • Drop the dart into the drop-in dart sub. • Fill up the annulus continuously during the trip. • Monitor the flowline at all times. 2-28 March 1995 BP WELL CONTROL MANUAL • Stop the pumps and monitor the well whenever the bit is pulled into the previous casing shoe. • Be prepared to shut in at all times during the trip. If wireline logging is required when complete loss of returns exists then the following precautions must be taken. • When logging, the pump should be kept continuously on the hole. The only exception is when static fluid level has to be established. • Logging is best conducted using through drillpipe logging tools, with open ended drillpipe run to the casing shoe. 2-29/30 2-29 March 1995 BP WELL CONTROL MANUAL 3 WARNING SIGNS OF A KICK Paragraph Page 1 General 3-2 2 Drilling Break 3-2 3 Increased Returns Flowrate 3-2 4 Pit Gain 3-3 5 Hole not Taking Appropriate Volume During a Trip 3-4 6 Gas Cut Mud 3-4 7 Increase in Hookload 3-6 8 Change in Pump Speed or Pressure 3-6 3-1 March 1995 BP WELL CONTROL MANUAL 1 General When drilling with returns to surface, a kick cannot occur without any warning sign. This Chapter outlines and explains the signs that indicate either that a kick has occurred or that a kick may soon develop. 2 Drilling Break One of the first indications that a kick may occur is an increase in penetration rate, or a drilling break. Many factors influence the rate of penetration, but an increase in penetration rate can be caused by an increase in formation porosity, permeability or pore pressure. A change in all or one of these formation parameters may create the conditions in which a kick could occur. For this reason any drilling break should be checked for flow. Even if the flowcheck indicates no flow, the reason for each drilling break should be determined. As an example, a drilling break could be caused by drilling into an impermeable transition zone above a permeable reservoir. Because the formation is impermeable, it is unlikely that any significant flow would be noticed during a flowcheck. However, the formation may be considerably underbalanced by the mud column. If drilling continued and the reservoir was penetrated, a kick would be taken. Consideration must therefore be given to circulating bottoms up before drilling ahead after a negative flowcheck, especially in critical sections of the well. 3 Increased Returns Flowrate The first confirmation that a kick is occurring is an increase in returns flowrate while the pumps are running at constant output. However, this increase may not be detected if the influx flowrate is particularly slow. In this case a slight pit gain may be the first detectable confirmation of the kick. If low gravity formation fluids enter the wellbore during drilling, the hydrostatic pressure in the annulus will decrease rapidly as more influx enters and when the influx expands as it is circulated up the hole. As a result, rapid influx flowrates can quickly develop, even though the initial influx flowrate might have been very low. The length of formation exposed also has direct bearing on the rate of flow into the well. The greater the length of formation exposed, the larger the flowrate. It is therefore important that surface equipment be able to reliably detect a small increase in returns flowrate. 3-2 March 1995 BP WELL CONTROL MANUAL 4 Pit Gain (a) While Drilling A gain in pit volume, that was not caused by the movement of mud stocks at surface, is confirmation that a kick is occurring or has occurred. This is the most reliable indicator of a kick. Consequently, every effort must be made to ensure that pit levels are accurately monitored at all times. Very small influx volumes may not be detected at surface as they occur. This may be due to the fact that, either the initial influx was particularly small, or the influx flowrate was very slow. This could be the case if the formation has low permeability or if a more permeable formation was only very slightly underbalanced. In such cases, the influx may be detected before it is circulated to the surface if it expands significantly as it rises up the hole. In general, the greater the amount of gas that is contained in the influx, the greater the expansion of the influx will be as it rises up the hole. As a result, the greater the proportion of gas in the influx, the more likely it is that the influx will be detected as it is circulated up the hole. Consequently, a low volume influx heavy oil or brine that does not contain any appreciable quantity of gas, will be relatively difficult to detect at surface. However, if the active system is accurately monitored, pit gains of less than 10 bbl should be detected reliably, even on floating rigs. (b) During a Connection An influx may only occur during a connection due to the reduction in bottomhole pressure as the pumps are shut down and the pipe pulled off bottom. If the well flows only during a connection, it is likely that the influx flowrate will be slow initially, resulting in only a small pit gain. Therefore, early detection of flow during a connection may be difficult. However, it is important to check for flow during a connection, because if a close to balance situation is developing, it is most likely to show initially during a connection. The first signs are likely to be increasing connection gases. However, if the underbalance develops very rapidly and the bottoms up time is considerable, then it is possible that an influx may occur before the connection gases are detected at surface. In this instance, flow during a connection may be the first indication of an underbalanced situation. The detection of a small pit gain during a connection is complicated by the volume of mud in the flowline returning to the pit after the pumps have been shut down. This will cause an increase in pit level during each connection. It is important therefore to establish the volume of mud that is contained in the flowline during circulation. For instance, this volume might be 10 bbl and as such, a 10 bbl pit gain during a connection would not be significant. However, a 15/bbl gain may indicate that a 5 bbl influx has occurred. 3-3 March 1995 BP WELL CONTROL MANUAL 5 Hole not Taking Appropriate Volume During a Trip As pipe is pulled from the hole, it is essential that the appropriate volume of mud is used to keep the hole full. This is essential in order that both a full head of mud is maintained in the hole and that if an influx is swabbed into the hole, it is detected immediately. Before every trip, a trip sheet (See Page 2-4) should be filled out. This must clearly show the expected hole fill volumes as the pipe is pulled out of the hole. As the trip proceeds, actual hole fill volumes should be entered in the trip sheet alongside the expected volumes. If the hole takes less mud than expected, this should be taken as positive indication that an influx has been swabbed into the hole. A flowcheck should be carried out immediately or, if in a reservoir section, the well should immediately be shut in. A negative flowcheck at this point is not necessarily confirmation that an influx has not occurred. It is quite possible, even if an influx has been swabbed into the well, that the well will not flow if the pipe is stationary. Therefore, if at any stage in a trip the hole does not take the correct volume of mud, the pipe should be run back to bottom, using the trip tank, and bottoms up circulated. The problems associated with dealing with a kick when the pipe is off bottom can be considerable, and so every effort must be made to ensure that significant swab pressures are avoided during a trip. Swabbing is minimised by ensuring that the mud is in good condition prior to pulling out of␣hole and that predetermined speeds are not exceeded at any stage in the trip (see Chapter␣3, Volume 2). 6 Gas Cut Mud A kick is confirmed at surface as an increase in returns flowrate and a pit gain. However, a minor influx that is not detected as a pit gain may first be identified at surface in the returned mud. Formation fluids and gas in the returned mud may therefore indicate that a low volume influx is occurring or has occurred, even though no gain has been detected. Returned mud must be monitored for contamination with formation fluids. This is done by constantly recording the flowline mud density and accurately monitoring gas levels in the returned mud. Gas cut mud does not in itself indicate that the well is kicking (gas may be entrained in the cuttings). However, it must be treated as early warning of a possible kick. Therefore the pit level should be closely monitored if significant levels of gas are detected in the mud. An essential part of interpreting the level of gas in the mud is the understanding of the conditions in which the gas entered the mud in the first place. 3-4 March 1995 BP WELL CONTROL MANUAL Gas can enter the mud for one or more of the following reasons: • As a result of drilling a formation that contains gas even with a suitable overbalance. • As a result of a temporary reduction in hydrostatic pressure caused by swabbing as pipe is moved in the hole. • Due to the pore pressure in a formation being greater than the hydrostatic pressure of the mud column. Gas due to one or a combination of the above, is classified as follows: (a) Drilled Gas As porous formations containing gas are drilled, it is inevitable that a certain quantity of the gas contained in the cuttings will enter the mud. Any gas that enters the mud, unless in solution with oil base mud and above the bubble point, will expand as it is circulated up the hole, causing gas cutting at the flowline. Gas cutting due to this mechanism will occur even if the formation is overbalanced. Raising the mud weight will not prevent it. However, drilled gas will only be evident during the time taken to circulate out the cuttings from the porous formation. (b) Connection Gas Connection gases are detected at surface as a distinct increase above background gas, as the hole is circulated bottoms up after a connection. Connection gases are caused by the temporary reduction in effective total pressure of the mud column during a connection. This is due to pump shut down and the swabbing action of the pipe. In all cases, connection gases indicate a condition of near balance. Consequently, when connection gases are identified, consideration should be given to weighting up the mud before drilling ahead and particularly prior to a trip. (c) Trip Gas Trip gas is any gas that entered the mud while the pipe was tripped and the hole appeared static. Trip gas will be detected in the mud on circulating bottoms up after a round trip. If the static mud column is sufficient to balance the formation pressure, the trip gas is caused by swabbing and gas diffusion. Significant trip gas may indicate that a close to balance situation exists in the hole. (d) Gas due to Inadequate Mud Density Surface indications of an underbalanced formation depend on the degree of underbalance, as well as the formation permeability. The penetration of a permeable formation that is significantly underbalanced will cause an immediate pit gain. 3-5 March 1995 BP WELL CONTROL MANUAL A permeable formation that is only slightly underbalanced may only cause a small flow into the well. The first evidence of this at surface is likely to be gas cut mud, accompanied by a small pit gain. The initial pit gain may be so small that it is only detected as it expands as it is circulated up the hole. In the case a tight formation is underbalanced, there may be little or no actual flow of gas into the wellbore. Therefore, drilling such a formation may show only gas cut mud, even if the underbalance is relatively high. This is a relatively difficult situation to detect and is also potentially dangerous. 7 Increase in Hookload If an influx occurs while drilling, an increase in hookload may be noticed at surface. Influx fluids will generally be lighter than the drilling fluid, especially so if the influx is gas. Displacement of the drilling fluid by the influx will reduce the buoyancy of the bottomhole assembly. This will increase the effective weight of the drillstring, a change that is likely to be registered as an increase in hookload. An increase in hookload may only be noticed after a considerable volume of influx has occurred. It is not therefore a reliable method of detecting a kick at an early stage. 8 Change in Pump Speed or Pressure Pump pressure may decrease with a corresponding increase in pump speed if an influx occurs during drilling. This indication is caused as a result of the U-tube effect, caused by light fluids flowing into the annulus. However, it is only likely to become noticeable as the influx is circulated up the hole. A washout in the drillstring will cause the same decrease in pump pressure and increase in pump speed. However, if these signs are noticed, the Driller should first assume that a kick may have occurred and flowcheck the well. 3-6 March 1995 BP WELL CONTROL MANUAL 4 ACTION ON DETECTING AN INFLUX Section Page 4.1 SHALLOW GAS PROCEDURE 4-1 4.2 SHUT-IN PROCEDURES 4-9 4.3 DURING SHUT-IN PERIOD 4-15 March 1995 BP WELL CONTROL MANUAL 4.1 SHALLOW GAS PROCEDURE Paragraph Page 1 General 4-2 2 Gas encountered whilst drilling without a riser from a Floating Rig 4-3 Gas encountered whilst drilling for surface casing from a Floating Rig with a riser 4-4 Gas encountered whilst drilling for surface casing from a Bottom Supported Rig 4-6 Onshore Shallow Gas 4-7 3 4 5 4-1 March 1995 BP WELL CONTROL MANUAL 1 General Offshore shallow gas accumulations are normally associated with recently laid down sand␣ l enses that are totally enveloped by mudstones. When encountered at shallow depths,␣lenses tend to be highly porous, permeable and relatively unconsolidated. They are␣commonly thin, flat and normally pressured. However , overpressured lenses have been encountered. Overpressure at this depth is generally caused by inclination of the lens which has the effect of increasing the height of the lens and hence the pore pressure gradient at the top of the lens. In some areas, shallow gas has been associated with buried reefs or vuggy limestone which can be extremely porous and almost infinitely permeable. Shallow gas kicks are generally caused by loss of hydrostatic head due to one or a combination of the following: • Overloading the annulus with cuttings and hence causing losses. • Drilled gas expanding and unloading the annulus. • Improper hole fill while tripping. Consequently it is strongly recommended to take the following general precautions to minimise the possibility of inducing a shallow gas flow: • Drill pilot hole • Drill riserless • Restrict ROPs • Accurately monitor the hole Shallow gas flows are often extremely prolific, producing very high flow rates of gas and considerable quantities of rock from the formation; particularly so when a long section of sand has been exposed. In the event of a shallow gas flow, the Company Representative must immediately liaise with the Senior Contractor Representative to make preparations to evacuate initially non-essential personnel from the rig. The eventuality of having to completely evacuate the rig must also be addressed (the contractor’s emergency evacuation procedures will be implemented). A well should not be drilled through a shallow seismic anomally (bright spot), which may indicate the presence of shallow gas. If a bright spot is present at the proposed drilling location it is good practice to move the rig to avoid the hazard. The new drilling location should, if possible, be located on a shallow seismic shot point. It should be noted that the absence of bright spots does not rule out the possibility of the existence of shallow gas. Further to this, the absence of shallow gas in one well of a series drilled from a surface location does not guarantee the absence of shallow gas in subsequent directional wells drilled from the same surface location. 4-2 March 1995 BP WELL CONTROL MANUAL 2 Gas encountered whilst drilling without a riser from a Floating Rig Company policy states that surface hole will be drilled riserless unless the particular conditions as outlined in Drilling Policy and Guidelines Manual are applicable. Drilling riserless ensures that the major cause of blowouts from shallow, normally pressured gas reservoirs – namely, the loss of hydrostatic head – is eliminated. There remains however, the danger of penetrating an overpressured reservoir. A contingency plan must be developed, prior to spud, in conjunction with the Drilling Contractor to cover the following situations: • The procedures to be adopted in the event of a shallow gas flow. • The procedure for winching the rig off location. The contingency plan must be discussed in detail at the pre-spud meeting. A gas blowout in open water produces a 10 degree cone of low density water and a discharge of highly flammable gas. The intensity of the blowout depends to a large extent on the water depth and current. The plume is likely to become more dispersed with greater water depth, whilst the effect of a current would be to displace the plume away from the rig. Within a plume of expanding gas, a floating vessel will suffer some loss of buoyancy; however, this diminishes rapidly with water depth such that the effect on a semi-submersible at operating draft would be negligible. The eruption of the gas would tend to displace a vessel, and if constrained by its moorings, might cause a drillship to keel towards the plume, thereby reducing its freeboard further. Under calm conditions, the gas cloud would disperse slowly and would constitute a fire hazard if the gas became entrapped in a confined area. The severity of the hazard can only be assessed at the time, and whilst there is unlikely to be an immediate danger to crew or vessel, the following precautions or considerations should be addressed before and whilst the surface hole is open: • The rig should be moored with length of moorings remaining in the locker to allow the rig to be winched 400 ft away from the plume. If practical, the windlasses should be held on their brakes and the chain stoppers only applied after surface casing is set. • All hatches should be secured to prevent invasion of voids by inflammable gas or downflooding if the freeboard is reduced by loss of buoyancy or heel. This is critical for a drillship. • Facilities and personnel should be continuously available at short notice to slack off the moorings closest to the plume and heave in those up current (but not down wind). Before spudding, a contingency plan should be prepared detailing individual responsibilities and duties. • Drill pilot hole, limiting the ROP and circulate at a high rate to distribute the cuttings and drilled gas. • A float valve should always be run in the drillstring. • Sufficient mud should be kept on site to fill the hole volume twice. (Typically at 1.15/SG.) 4-3 March 1995 BP WELL CONTROL MANUAL • Weather conditions and current should be continuously monitored and the sea surface should be checked for evidence of gas. If a shallow gas flow is detected: If there is no immediate danger to personnel or the rig: 1. Attempt to control the well by pumping mud/seawater at a maximum rate. If the gas flow is endangering personnel or the rig: 2. Drop the drillstring or shear the pipe (See Section 6.2). 3. Winch the rig to a safe position outside the gas plume. 3 Gas encountered whilst drilling for surface casing from a Floating Rig with a riser In relatively shallow offshore environments, the conductor is usually set in a formation that is too weak to contain the pressure of a gas kick. If a kick is detected in such circumstances, the well should be diverted in order to avoid an underground blowout and the possibility of the gas broaching around the conductor shoe. It is Company policy that where the situation demands that a riser is to be used when drilling for the surface casing, an annular preventer and subsea dump valves are installed at the mudline, in addition to the normal diverter system at surface. Industry experience has shown that current diverter systems cannot be relied upon to safely control shallow gas blowouts. As a result, shallow gas flows should be controlled at the seabed, using the subsea dump valves at the mudline and annular preventer. Immediate preparations should then be made to unlatch the pin connector or LMRP and winch off location, up current but not down wind. A contingency plan must be developed, prior to spud, in conjunction with the Drilling Contractor to cover the following situations: • The procedures to be adopted in the event of a shallow gas flow. • The procedure for winching the rig off location. • The procedure to be adopted in the event of failure of any of the major components of the BOP/riser/diverter system. The contingency plan must be discussed in detail at the pre-spud meeting. The surface diverter system ensures that there is a back-up system available in the event of a failure of the subsea system. It can also be used to divert gas which may be in the riser above the stack. 4-4 March 1995 BP WELL CONTROL MANUAL The following precautions, in line with those listed in Paragraph 2, should be taken routinely whilst the surface hole is open: • The rig should be moored with length of moorings remaining in the locker to allow the rig to be winched 400 ft away from the plume. If practical, the windlasses should be held on their brakes and the chain stoppers only applied after surface casing is set. • All hatches should be secured to prevent invasion of voids by inflammable gas or downflooding if the freeboard is reduced by loss of buoyancy or heel. This is critical for a drillship. • Facilities and personnel should be continuously available at short notice to slack off the moorings closest to the plume and heave in those up current (but not down wind). Before spudding, a contingency plan should be prepared detailing individual responsibilities and duties. • Care should be taken to ensure that the annulus does not become overloaded with cuttings, causing losses or cuttings liberated gas, and hence the possibility of unloading the annulus. This is achieved by drilling a pilot hole, limiting the ROP and circulating at a high rate to distribute the cuttings and drilled gas. • Facilities should be continuously available to fill the annulus rapidly from surface in the event of sudden losses. • Care should be taken to monitor the hole and ensure that it remains full whilst tripping. • A float valve should always be run in the drillstring. • Sufficient mud should be kept onsite to fill the hole volume twice. (Typically 1.15/SG.) Should the well start to flow, the following procedure can be used as a guideline: 1. Open the subsea dump valves. 2. Close the annular preventer and allow the gas to vent at the seabed. If there is no immediate danger to personnel or the rig: 3. Attempt to control the well by pumping sea water/mud at a maximum rate. If the gas flow is endangering personnel or the rig: 4. Consider dropping the drillstring or shearing prior to (5) (See Section 6.2). 5. Unlatch the LMRP or pin connector and winch the rig to a safe position outside the gas plume. In the event of failure of the subsea diverter system there remains the option to divert at surface or to unlatch the LMRP or pin connector, thereby venting the gas at the wellhead. Diverting at surface is not recommended, however if it becomes absolutely necessary to divert at surface, proceed as follows: 1. Maintain maximum pump rate. 2. Space out so that the lower kelly cock is just above the rotary table. 3. Open the diverter lines, close the shaker valve and diverter element thereby diverting returns overboard. 4-5 March 1995 BP WELL CONTROL MANUAL 4. Shut down all non-essential equipment and machinery to minimise potential sources of ignition. Deploy fire hoses beneath the rig floor . 5. Prepare to unlatch the pin connector or LMRP and winch to a safe position. If the situation is deteriorating and loss of control is imminent: 6. Consider dropping the drillstring or shearing the pipe prior to (7) (See Section 4.3). 7. Release the pin connector or LMRP and winch the rig to a safe position outside the gas plume. 4 Gas encountered whilst drilling for surface casing from a Bottom Supported Rig Shallow gas reservoirs are potentially much more hazardous when penetrated from a jack-up or platform. Because the conductor extends almost to the rig floor, the products of a kick are discharged directly into a hazardous zone. In the event of a shallow gas flow, the diverter will immediately be closed in order to direct the flow overboard. The reliability of the diverter system while subject to the stress of a shallow gas flow is uncertain and so the possibility of equipment failure at this stage must be considered. On a bottom supported rig, a hazardous situation is created if a restriction forms in the diverter line. The subsequent pressure build up may cause gas to broach around the casing to the seabed. In this event there is a real risk that the seabed becomes fluidized, thus inducing a sudden reduction in spudcan resistance. The following precautions should be taken routinely whilst the surface hole is open: • Care should be taken to ensure the annulus does not become overloaded with cuttings, thus causing losses or gas to be liberated from the cuttings to such an extent that the annulus unloads. This is achieved by drilling pilot hole, limiting the ROP, and circulating at a high rate to distribute the cuttings and drilled gas. • Facilities should be continuously available to rapidly fill the annulus from surface in the event of sudden losses. • Facilities should be available and care taken to monitor the hole and ensure that it remains full whilst tripping. • A float valve should always be run in the drillstring. • A means of diverting the flow away from hazardous zones, without restricting flow or imposing backpressure on the well, should be available for immediate activation. • Sufficient mud should be kept onsite to fill the hole volume twice. 4-6 March 1995 BP WELL CONTROL MANUAL Should the well start to flow, the following procedure may be used as a guideline: 1. Maintain maximum pump rate. 2. Space out such that the lower kelly cock is just above the rotary table. 3. Ensure that diverter lines are open, close shaker valve and diverter element thereby diverting returns overboard. 4. Shut down all non-essential equipment and machinery to minimise potential sources of ignition. Deploy fire hoses beneath the rig floor. 5. Evacuate all non-essential personnel. 6. Monitor the sea for evidence of gas breaking through outside the conductor. (Evacuate all personnel if any evidence is detected.) 5 Onshore Shallow Gas The shallow geology of onshore locations varies widely, but shallow gas is a rare occurrence onshore. Geological control is usually sufficient to predict formations accurately and, when necessary, specific contingency plans should be made to counter potential problems. Shallow onshore reservoirs are generally older, more consolidated and less permeable than those offshore, which will tend to restrict the flow potential of a shallow kick onshore. Onshore, most wells are spudded through a thin layer of weathered formation into a bed rock. The conductor and surface casing strings are normally set in competent formation which can permit secondary well control by normal means. However, if it is not possible to positively exclude the possibility of either a shallow gas accumulation or a weak casing shoe, a means of diverting the flow away from the rig should be provided. Provision should also be made to ensure an adequate supply of water is available to pump to the hole at a high rate without taking returns. Diverter procedures for an onshore well will be similar to those for a bottom supported offshore rig. However, if water supply is known to be limited, a baryte plug may be the only practical method of halting a shallow gas flow. Most flows from shallow onshore reservoirs are associated with aquifers that outcrop at higher elevations (or indeed lower elevations if air or foam drilling fluid is in use). A water flow of this type is usually predictable and of limited consequence. Severe shallow flows have been encountered in the past as a result of a shallow zone becoming charged by a lower high pressure zone; the shallow zone having been charged by a faulty cement job in a previously drilled well. 4-7/8 4-7 March 1995 BP WELL CONTROL MANUAL 4.2 SHUT-IN PROCEDURES Paragraph Page 1 General 4-10 2 Fast Shut-in 4-10 3 Shut-in Procedure 4-11 Illustrations 4.1 Kick while Drilling, Floating Rig, Fast Shut-in 4-12 4.2 Kick while Drilling, Fixed Rig, Fast Shut-in 4-13 4.3 Kick while Tripping, Fast Shut-in 4-14 4-9 March 1995 BP WELL CONTROL MANUAL 1 General It is Company policy that a well kick will be shut in and controlled at the BOP stack on hole sections below the surface casing. The procedures to be adopted in the event of a kick while drilling ahead from the surface casing shoe are drawn up at the discretion of the Company Representative and the Company Drilling Superintendent. There are various methods of shutting in a well that is flowing. In general, the best method is that which ensures that the well is safely shut in and the influx volume is minimised. The smaller the volume of influx, the lower will be the pressures in the wellbore and at surface throughout the kick control process. It is the responsibility of the Company Representative to ensure that the Contractor is made aware of the procedures that should be initiated in the event of a well kick. The speed with which the Drillcrew carry out these procedures is a critical factor. In this respect, if a primary indicator of a kick, such as either a pit gain or an increase in returns flowrate is detected, no time should be spent flowchecking the well. In such circumstances, the kelly (or topdrive) should be picked up, the pumps stopped and the BOP closed immediately. Speed and proficiency are achieved by regular drills. It is a further responsibility of the Company Representative that he ensures these drills are carried out at suitable intervals to ensure the drillcrews are proficient at implementing the shut-in procedures. The forms illustrated in Figures 4.1 to 4.3 should be used to make absolutely clear the shut-in procedures that will be used on each rig. These forms are intended primarily for the Driller, however copies should be distributed to other relevant personnel including the Toolpusher and, where appropriate, the Subsea Engineer. When a standard shut-in procedure is finalised, this procedure should be written on a large notice board that will be positioned prominently on the rig floor. 2 Fast Shut-in Drilling management have issued the following guideline: The fast shut-in is the preferred method of shutting in a well. In order to implement the fast shut-in, the equipment should be set up as follows: • The remote operated choke closed and isolated by a high pressure valve immediately upstream. (Ensure that the choke pressure can be monitored in this position.) • One remote operated chokeline valve closed. (Outer failsafe on a floating rig and HCR valve on a fixed rig.) In the event that a kick is detected, or suspected, the choke line valve(s) are opened and the BOP closed. 4-10 March 1995 BP WELL CONTROL MANUAL On a floating rig, the annular BOP will be used to initially shut-in the well. On a fixed rig, the pipe rams may be used to initially shut-in the well, in order to speed up the procedure, if the position of the tooljoint in relation to the pipe ram is known with confidence. The advantage of this method is quite clear, namely that the operation is relatively simple in comparison with the soft shut-in. Consequently, mistakes are unlikely and the time taken to close in the well will be minimised. At all times, be aware that the pressure rating of the standpipe equipment is generally less than that of the BOP stack and the choke manifold. 3 Shut-in Procedure It is the responsibility of the Company Representative and the Company Drilling Superintendent to define the shut-in procedure that will be implemented in the event of a␣kick. The following forms are examples of the information that should be provided to the Driller: Figure 4.1: Kick while Drilling, Floating Rig, Fast Shut-in. Figure 4.2: Kick while Drilling, Fixed Rig, Fast Shut-in. Figure 4.3: Kick while Tripping, Fast Shut-in. 4-11 March 1995 BP WELL CONTROL MANUAL Figure 4.1 Kick while Drilling, Floating Rig, Fast Shut-in STANDING ORDERS TO DRILLER WELL NO 24 RIG ORDERS EFFECTIVE DATE RIG 20 THROUGH 121/4in HOLE SECTION 10/3/87 COMPANY REP S.M.B. K.D. TOOLPUSHER IF ANY OF THE FOLLOWING OCCUR: 1. DRILLING BREAK *2. INCREASED RETURNS FLOWRATE *3. PIT GAIN 4. CHANGE IN PUMP SPEED OR PRESSURE 5. SUDDEN CHANGE IN PROPERTIES OF RETURNED MUD 6. …………………………………………………………………………… 7. 8. 9. 10. …………………………………………………………………………… …………………………………………………………………………… …………………………………………………………………………… …………………………………………………………………………… Or if there is any other possible indication of a kick. LOWER KELLY COCK IS ………………………… 2.5m 1. PICK UP UNTIL ………………………… ABOVE ROTARY UPPER PIPE (Space out to ensure that a tool joint is clear of ………………………… rams) 2. SHUT DOWN THE PUMPS 3. FLOWCHECK THE WELL IF NECESSARY (Do not flowcheck if 2* or 3* as above have been detected.) YES IS THE WELL FLOWING? NO 1. NOTIFY COMPANY REPRESENTATIVE AND TOOLPUSHER 1. OPEN UPPER CHOKE LINE …………………………………………………………… FAILSAFE (S) …………………………………………………………… 2. PROCEED AS DIRECTED 2. CLOSE UPPER ANNULAR …………………………………………………………… 3. CHECK WELL IS SHUT IN …………………………………………………………… 4. NOTIFY COMPANY REPRESENTATIVE …………………………………………………………… 5. CHECK SPACEOUT …………………………………………………………… 6. CLOSE UPPER PIPE RAMS …………………………………………………………… 7. ADJUST ANNULAR CLOSING …………………………………………………………… PRESSURE …………………………………………………………… 8. HANG OFF ON UPPER PIPE RAMS …………………………………………………………… 9. CLOSE RAMLOCKS …………………………………………………………… 10. PROCEED AS DIRECTED …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… WEOX02.015 4-12 March 1995 BP WELL CONTROL MANUAL Figure 4.2 Kick while Drilling, Fixed Rig, Fast Shut-in STANDING ORDERS TO DRILLER WELL NO 28 RIG ORDERS EFFECTIVE DATE RIG 15 FOR WELL No 28 15/9/87 COMPANY REP J.B.H. J.P. TOOLPUSHER IF ANY OF THE FOLLOWING OCCUR: 1. *2. *3. 4. 5. 6. 7. 8. 9. 10. DRILLING BREAK INCREASED RETURNS FLOWRATE PIT GAIN CHANGE IN PUMP SPEED OR PRESSURE SUDDEN CHANGE IN PROPERTIES OF RETURNED MUD …………………………………………………………………………… …………………………………………………………………………… …………………………………………………………………………… …………………………………………………………………………… …………………………………………………………………………… Or if there is any other possible indication of a kick. LOWER KELLY COCK IS ………………………… 2m 1. PICK UP UNTIL ………………………… ABOVE ROTARY 5in PIPE (Space out to ensure that a tool joint is clear of ………………………… rams) 2. SHUT DOWN THE PUMPS 3. FLOWCHECK THE WELL IF NECESSARY (Do not flowcheck if 2* or 3* as above have been detected.) YES IS THE WELL FLOWING? NO 1. NOTIFY COMPANY REPRESENTATIVE AND TOOLPUSHER 1. OPEN CHOKE LINE VALVE (S) …………………………………………………………… 2. CLOSE ANNULAR PREVENTER …………………………………………………………… 2. PROCEED AS DIRECTED 3. CHECK THAT WELL IS SHUT IN …………………………………………………………… 4. RECORD DP AND CSG PRESSURE …………………………………………………………… 5. NOTIFY COMPANY REPRESENTATIVE …………………………………………………………… 6. PROCEED AS DIRECTED …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… WEOX02.016 4-13 March 1995 BP WELL CONTROL MANUAL Figure 4.3 Kick while Tripping, Fast Shut-in STANDING ORDERS TO DRILLER WHILE TRIPPING WELL NO 28 ORDERS EFFECTIVE DATE RIG RIG 10 ON ALL TRIPS 23/7/87 COMPANY REP A.J.N. H.H. TOOLPUSHER IF ANY OF THE FOLLOWING OCCUR: HOLE NOT TAKING CORRECT VOLUME DURING THE TRIP THE WELL IS FLOWING …………………………………………………………………………… …………………………………………………………………………… 5. …………………………………………………………………………… 6. …………………………………………………………………………… 7. …………………………………………………………………………… 8. …………………………………………………………………………… Or if there is any other possible indication of a kick. 1. 2. 3. 4. 1. STOP TRIPPING OPERATIONS 2. FLOWCHECK THE WELL IF NECESSARY YES IS THE WELL FLOWING? NO 1. NOTIFY COMPANY REPRESENTATIVE AND TOOLPUSHER 1. SET THE SLIPS …………………………………………………………… 2. INSTALL OPEN DP SAFETY VALVE …………………………………………………………… 2. PROCEED AS DIRECTED 3. CLOSE DP SAFETY VALVE …………………………………………………………… 4. OPEN CHOKE LINE VALVE (S) …………………………………………………………… 5. CLOSE ANNULAR PREVENTER …………………………………………………………… 6. CHECK THAT WELL IS SHUT IN …………………………………………………………… 7. NOTIFY COMPANY REPRESENTATIVE …………………………………………………………… 8. INSTALL KELLY …………………………………………………………… 9. LINE UP STANDPIPE MANIFOLD …………………………………………………………… 10. OPEN DP SAFETY VALVE …………………………………………………………… 11. RECORD DP AND CSG PRESSURE …………………………………………………………… 12. IF IN OPENHOLE: ENGAGE …………………………………………………………… BUSHINGS, ROTATE THE PIPE …………………………………………………………… 13. PROCEED AS DIRECTED …………………………………………………………… …………………………………………………………… WEOX02.017 4-14 March 1995 BP WELL CONTROL MANUAL 4.3 DURING SHUT-IN PERIOD Paragraph Page 1 General 4-16 2 Record Pressure Data 4-16 3 Record drillpipe pressure with a Float Valve in the string 4-17 4 Trapped Pressure 4-19 5 Identify the Influx Type 4-20 6 Influx Migration 4-21 7 Control Influx Migration 4-24 Illustrations 4.4 Shut-in Pressure Build-up Curve – showing the effect of influx migration 4-17 4.5 Well Control Operations Log 4-18 4.6 An Example Calculation – showing how to evaluate the type of influx fluid 4-22 An Example of the possible increase in wellbore pressure due to influx migration 4-23 4.7 4-15 March 1995 BP WELL CONTROL MANUAL 1 General When a flowing well is shut in by closing the BOPs, the flow will continue until shut-in pressures have built up to balance the static reservoir pressure. In most cases, this will mean that the flow will stop almost immediately the BOPs are closed and that the shut-in pressure will stabilise within a few minutes. In general, only if the well has been flowing for some time will the kick zone pressure take time to build up to a maximum after the well has been shut in. In most cases, when a kick is taken, the inflow into the wellbore occurs for only a short time and the drawdown is relatively small. As a result, pressure in the wellbore will stabilise quickly after the well is shut in. However, there have been many cases of surface pressures taking several hours to stabilise. The reasons for this can be one, or all, of the following: • The influx originated from a low permeability zone. • The influx created instability in the wellbore, leading to the hole sloughing and packing␣of f. • The influx is migrating up the hole. • The surface lines or subsea choke line is partially packed off. This section covers the procedures that may be required during the time the well is shut in prior to circulation. 2 Record Pressure Data As soon as the well is shut in, a person must be assigned to record the drillpipe and casing pressures. The pressures should be recorded initially at 1 minute intervals until the pressures have stabilised. It is important to record the data frequently in order that any change in the rate of build-up be clearly identified. Usually, the rate of build-up is relatively fast until the well begins to stabilise. Once the pressures have begun to stabilise, any further significant increase in surface pressures can be indicative of influx migration. The drillpipe pressure reflects the difference between the kick zone pressure and the effective hydrostatic pressure of the mud column in the drillpipe, assuming that the influx has not entered the drillpipe. It can therefore be used to determine the kick zone pressure. When the surface pressures take a considerable time to stabilise, it is often difficult to determine the drillpipe pressure that truly reflects the actual bottomhole pressure. There are no hard and fast rules that apply to determine the correct value for the relevant drillpipe pressure reading, however, frequent and accurate pressure readings will aid the interpretation of build-up data. Figure 4.4 shows a pressure build-up curve which shows signs of influx migration. The kick zone EMW is determined from the drillpipe pressure during the stabilised period. 4-16 March 1995 BP WELL CONTROL MANUAL INITIAL PRESSURE BUILDUP STABILISED PERIOD INFLUX MIGRATION OCCURRING SURFACE PRESSURE (psi) ANNULUS PRESSURE DRILLPIPE PRESSURE TIME ELAPSED AFTER SHUT-IN WEOX02.018 Figure 4.4 Shut-in Pressure Build-up Curve – showing the effect of influx migration Figure 4.5 shows a form that can be used to record the build-up of drillpipe and casing pressure. This form should also be used to keep a complete record of events during the well control operation. 3 Record drillpipe pressure with a Float Valve in the string If a non-ported float valve is in the string and a kick is taken, the valve will close against the differential pressure and no pressure will be recorded at the standpipe. In order to open this valve and allow the pressure to be transmitted to the surface, the following procedure can be implemented: 1. Line up the pump to the drillpipe. 4-17 March 1995 BP WELL CONTROL MANUAL Figure 4.5 Well Control Operations Log WELL CONTROL OPERATIONS LOG WELL NO 28 FIRST READING AT TIME (hr min) RIG / RIG 9 DRILLPIPE CHOKE PIT LEVEL/ PRESSURE PRESSURE VOLUME (psi) (psi) (bbl ) 03.00 03.01 03.02 03.03 03.04 03.05 03.06 03.07 03.08 03.09 03.10 03.11 03.12 03.13 03.14 03.15 03.16 03.17 03.20 03.25 03.30 03.45 04.00 04.30 05.00 05.10 05.15 300 360 420 460 520 590 630 700 720 740 760 770 775 775 780 780 780 780 780 780 780 780 780 782 782 782 782 450 500 560 600 660 730 770 840 860 880 900 910 920 920 925 925 925 925 925 925 925 925 925 925 925 925 925 120 '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' 05.20 05.24 05.30 05.40 05.50 06.00 06.10 782 1085 1010 880 755 630 450 925 925 910 903 930 945 950 '' 120 SHEET NO 1 3/7/87 03.00 1 MINUTE UNTIL PRESSURES STABILISE DATE AND TIME INTERVAL BETWEEN READINGS REMARKS WELL SHUT IN – 10bbl GAIN INFORM COMPANY REP – PRESSURES STABILISED START MIXING KILL WEIGHT MUD @ 1.75 SG 100bbl 1.75 SG MUD MIXED IN TANK No 1 VERIFY EQUIPMENT CORRECTLY LINED UP – CO REP AND TOOLPUSHER TO RIG FLOOR START CIRCULATION – BRING PUMP UP TO 25 SPM PUMP UP TO SPEED – RETURNS THROUGH DEGASSER KILL WEIGHT MUD TO BIT WEOX02.019 4-18 March 1995 BP WELL CONTROL MANUAL 2. Carefully monitoring both the pump and casing pressure, pump to the hole at a controlled rate (very slow). 3. Record the increase in pump pressure and the volume of mud pumped. The relationship between the pump pressure and the volume of mud pumped will be linear as the mud in the drillpipe is compressed. If pumping is continued after the pressure equalises across the float valve, the valve will open. As the valve opens, the pump pressure will increase slower than before; this change should be easily recognisable at slow pump rates. Stop the pump when this change is noticed. The casing pressure is also likely to show an indication of the valve opening. 4. Isolate the pump at the standpipe. 5. Record the shut-in drillpipe pressure as the pump pressure recorded immediately before the float valve opened. 6. If the casing pressure rises at any stage, immediately stop the pump. Isolate the pump. Bleed off the excess pressure from the casing. As an example, if the casing pressure rose 50 psi and this extra pressure was considered undesirable, bleed 50␣psi from the casing and record the shut-in drillpipe pressure as 50 psi less than the final pump pressure. The utmost care must be taken in carrying out this procedure. As outlined, this procedure involves pumping into a closed well. The well is pressurised at the start of the operation, and so any excessive additional pressurisation caused by pumping into the well may overpressure the openhole section. 4 Trapped Pressure In some circumstances it is possible that pressure, in excess of that caused by the kick zone, can be trapped in the well. There are three possible causes of this phenomenon: • The pumps were left running after the well was shut-in. • The influx is migrating up the hole. • Pipe has been stripped into the well without bleeding the correct volume of mud. Trapped pressure of this kind will result in surface pressures that do not reflect the actual kick zone pressure. However if the surface pressure built up at any point after the well was␣shut-in, this is confirmation that there is no trapped pressure in the well. Pressure may be trapped in the well if the surface pressure appears constant and no pressure build has been seen. The drillpipe pressure is used to determine the kick zone pressure and hence the mud weight used to kill the well. An artificially high drillpipe pressure reading, used to determine the kill mud weight, will result in overkilling the well. 4-19 March 1995 BP WELL CONTROL MANUAL The following procedure can be used to check for trapped pressure: 1. Ensure that accurate pressure gauges are fitted to the drillpipe and annulus. Carefully monitor the drillpipe and casing pressure. 2. Using a manual choke, bleed a small volume of mud from the annulus to a suitable measuring tank. (1/2 barrel is a suitable amount.) 3. Shut in the well. Allow pressure to stabilise. If pressure has been trapped in the well, the drillpipe pressure and casing pressure will have fallen. If the drillpipe pressure does not drop after bleeding mud from the annulus, no pressure is trapped in the well. Be aware that, if there is no trapped pressure in the well, each increment of mud bled from the well will cause a further influx into the well. Therefore, if no reduction in drillpipe pressure is detected after bleeding 2 – 3/bbl from the well, no more mud should be bled off. An increase in casing pressure is a sure sign that additional influx has entered the well. Therefore, if this occurs, no more mud should be bled from the well. 4. If both the drillpipe pressure and casing pressure have decreased, continue to bleed mud from the well in 1/2 bbl increments. 5. When the drillpipe pressure no longer decreases as mud is bled from the well, record the drillpipe pressure as the shut-in drillpipe pressure. Stop bleeding mud from the well. It should be stressed that bleeding mud from a well that has kicked is an operation that must be carefully implemented. Whilst it is undesirable to overkill the well, it is potentially hazardous to increase the size of the influx, which is clearly a possibility if this procedure is not properly carried out. A firm recommendation is that the volumes bled from the well at this stage are kept to a minimum, unless influx migration is obviously occurring. If there is some doubt as to the true shut-in drillpipe pressure, even after bleeding mud from the annulus, it may be prudent to use the Driller’s Method to circulate out the kick, rather than continue bleeding mud. This procedure is not recommended if the kick zone is suspected to have low permeability. Bleeding even very small quantities of mud from the annulus may reduce the pressure of a tight kick zone below its final shut-in pressure. The drillpipe pressure will continue to decrease, giving the false impression at surface that the bottomhole pressure is still greater than the actual kick zone pressure. A possible consequence is that the operator may inadvertantly reduce the bottomhole pressure significantly below the kick zone pressure and cause a further influx into the wellbore. 5 Identify the Influx Type The shut-in pressures recorded on the drillpipe and the casing after a kick is taken are generally not equal. This is because the effective hydrostatic pressure of the fluid in the annulus will be reduced below that in the drillpipe. It is unlikely that any kick fluid will␣enter the drillpipe, because this is effectively a closed system if the kick was taken while drilling. 4-20 March 1995 BP WELL CONTROL MANUAL The pit gain at surface provides a guide to the volume of the kick. With this information, together with the annular geometry and the surface pressures, it is possible to estimate the␣influx density . The type of influx fluid can then be evaluated, using the following as a␣guide: Influx fluid Calculated Influx gradient (psi/ft) Gas Oil Water 0.05 – 0.2 0.3 – 0.4 > 0.4 Figure 4.6 shows an example of how to determine the influx type. This calculation is only an approximation, for the following reasons. Firstly, it is assumed that the influx is a discrete bubble, whereas it is more likely to be eccentric to the hole and contaminated with mud. Secondly, the effective mud weight in the annulus is not likely to be the same as in the drillpipe, due to cuttings loading the annulus, and possibly, contamination of the mud with formation fluid. Thirdly, the hole may be out of gauge. It is important, however, that this calculation is carried out for the additional reason that it provides a check of the validity of the kick data. It is useful to know the type of influx before circulation is initiated. Although most formation fluids, including formation water, contain some gas, the calculated influx gradient provides a guide to the proportion of gas in the fluid. The proportion of gas in the influx determines two important factors, firstly, the well bore pressures during displacement, and secondly, the pit gain during displacement. If the gas contains sufficient heavy hydrocarbon molecules at reservoir conditions, condensate fluids may be formed as the gas is displaced from the hole. This will not occur for a dry gas that does not contain a sufficient proportion of heavy molecules. Gas will come out of solution from an oil influx when the influx pressure reduces below the bubble point pressure during displacement. For light oils, a significant quantity of gas will be produced. It is recommended that all kicks are assumed to contain a certain proportion of gas. Prior to circulation therefore, an estimation should be made of the maximum pressures that will be encountered during circulation, and provision should be made for a pit gain during this period. (See Chapter 5, Volume 2 for hand calculation techniques.) 6 Influx Migration After a kick is taken, there is usually a tendency for the influx to migrate up the hole. This␣tendency is caused by the dif ference in density between the influx fluid and the mud. Influx migration up a closed-in well can cause excessive pressures within the wellbore if suitable control procedures are not implemented. Figure 4.7 shows an example of the potential increase in bottomhole pressure caused by gas migration. 4-21 March 1995 BP WELL CONTROL MANUAL Figure 4.6 An Example Calculation – showing how to evaluate the type of influx fluid HOLE DRILLSTRING DIMENSIONS 855 PRESSURE BALANCE 2. Determine the hydrostatic pressure of the influx 1. Determine the bottomhole pressure 500 ANNULUS DRILLPIPE SURFACE PRESSURE SURFACE PRESSURE 1.7SG MUD + + MUD MUD HYDROSTATIC PRESSURE OF MUD IN THE DRILLPIPE 81/2in HOLE HYDROSTATIC PRESSURE OF MUD IN ANNULUS + 61/4in COLLARS = 20bbl INFLUX INFLUX HEIGHT OF BHA = 195m 4000m INFLUX HYDROSTATIC PRESSURE = BOTTOMHOLE PRESSURE BOTTOMHOLE PRESSURE Identify the influx fluid as follows: 1. Determine the bottomhole pressure Bottomhole pressure = = = = Drillpipe pressure + mud hydrostatic pressure 500 + (1.7 x 1.421 x 4000) 500 + 9663 10,163psi 2. Calculate the height of the influx in the annulus Influx volume = Recorded pit gain = 20bbl Annular capacity at collars = 0.1058bblm Height of influx = 20/0.1058 = 189m 3. From pressure balance Annulus surface pressure + Hydrostatic pressure of the mud + Hydrostatic pressure of the influx = Bottomhole pressure 855 + 1.7 x 1.421 x (4000 – 189) + Pi = 10,163psi Pi, hydrostatic pressure of the influx = 10,163 - 855 - 9206 = 102psi Influx gradient = Pi/height of the influx = 102/(189 x 3.2808) = 0.16psi/ft Therefore the influx is mainly gas 4. The following formula can also be used routinely to calculate the influx density Density of the influx (SG) = MW – Pa – Pdp h x 1.421 = 1.7 – 855 – 500 189 x 1.421 = 0.378 SG – – 0.16psi/ft WEOX02.020 4-22 March 1995 BP WELL CONTROL MANUAL SURFACE PRESSURE 250psi 3195psi 6180psi 0 GAS @ 6180psi 1.4SG MUD 1500m GAS @ 6180psi 2975m GAS @ 6180psi 3000m BOTTOMHOLE PRESSURE BOTTOMHOLE EMW (SG) 6180psi 1.45 9160psi 2.15 (12140psi) (2.85) WEOX02.021 Figure 4.7 An Example of the possible increase in wellbore pressure due to influx migration Influx migration does not always occur, but when it does, the rate at which the influx rises up the hole is dependent on several variables. Experiment has shown that a gas bubble will migrate up one side of the annulus as mud falls down the opposite side. Bearing this process in mind, it is clear that the factors that predominantly affect the rate of rise of the influx will be the following: • The viscosity of the drilling fluid. The more viscous the mud, the more difficult it is for the mud to fall down the annulus to allow the influx to migrate. • The difference in density between the mud and the influx. The buoyancy force causes the influx to migrate. • Any interaction between the mud and the influx fluid. Migration will be slowed if the viscosity of the mud is increased as a result of contamination with the influx fluid. In severe cases, migration may be completely prevented. 4-23 March 1995 BP WELL CONTROL MANUAL 7 Control Influx Migration There are many possible reasons that a well that has kicked may be left shut-in for extended periods. Procedures for relieving bottomhole pressure, should migration occur during this period, will depend both on the position of the drillstring in the hole and whether or not the drillpipe pressure can be used to monitor bottomhole pressure. In both cases however, it is necessary to control the well using the Volumetric Method. This technique ensures that the bottomhole pressure is maintained slightly above the kick zone pressure at all times. This is accomplished by bleeding suitable volumes of mud from the annulus to allow for expansion of the influx as it migrates up the hole. This control procedure is greatly simplified if the drillstring is on bottom and in communication with the annulus. In this case, the bottomhole pressure can be monitored with the drillpipe pressure gauge. It is simply necessary to ensure that the drillpipe pressure stays at a suitable value above the final shut-in pressure (that value recorded before migration started) by bleeding mud from the annulus. If the drillstring is off bottom, the bit is plugged, or there is a washout in the drillstring, it is not possible to monitor bottomhole pressure with the drillpipe pressure gauge. In this event, the annulus pressure is the only reliable guide to subsurface pressures. The principle behind the control of the annulus is that an increase in annulus pressure caused by influx migration, must be relieved by an equivalent reduction in the hydrostatic pressure of the mud in the annulus. Thus, if the annulus pressure rises 100 psi, then a volume of mud corresponding to a hydrostatic pressure in the annulus (at the top of the influx) of 100 psi must be bled from the well at constant choke pressure. The procedure for implementing the Volumetric Method is covered in detail in Chapter 6. 4-24 March 1995 BP WELL CONTROL MANUAL 5 WELL KILL DECISION ANALYSIS Paragraph Page 1 General 5-2 2 Pipe on Bottom 5-2 3 Pipe off Bottom (Drillpipe in the Stack) 5-2 4 Pipe off Bottom (Drillcollar in the Stack) 5-5 5 No Pipe in the Hole 5-5 6 While Running Casing or Liner 5-7 7 Underground Blowout 5-9 Illustrations 5.1 Preparations for the Well Kill 5-3 5.2 Decision Analysis – Pipe off Bottom (Drillpipe in the Stack) 5-4 Decision Analysis – Pipe off Bottom (Drillcollar in the Stack) 5-6 5.4 Decision Analysis – No Pipe in the Hole 5-8 5.5 Decision Analysis – Flow to a Fracture above a High Pressure Zone 5-10 Decision Analysis – Flow to a Fracture or Loss Zone below a High Pressure Zone 5-12 5.3 5.6 5-1 March 1995 BP WELL CONTROL MANUAL 1 General This Chapter is intended to provide guidelines to the decision making process in the event that a kick is taken in a variety of different situations. In reality, the specific conditions prevailing at the rigsite at the time that the kick is taken will determine the best course of action to take in order to kill the well. This Chapter should therefore not be used as a guide at the moment that a kick is taken. However, it is anticipated that general familiarity with the analysis presented in this Chapter will enable rigsite personnel to be better prepared to deal with a situation in which the well has kicked. The techniques referred to in this section are covered in detail in Chapter 6, Well Kill Techniques. 2 Pipe on Bottom If a kick is taken with the pipe on bottom, the well will be shut-in immediately unless the decision has previously been made to divert. Having established that the well is safely closed in, it will be necessary to decide on the most appropriate method of killing the well. This decision is the responsibility of the Company Representative. Having decided on the most appropriate course of action, the Company Representative is responsible for ensuring that contractor personnel are made aware of the procedures that will be used to kill the well. The general procedure that is presented in Figure 5.1 represents the steps that should be taken in preparation to kill the well. These steps are applicable to any situation in which a kick is taken. 3 Pipe off Bottom (Drillpipe in the Stack) If an influx is taken during a trip it will generally be necessary to return the drillstring to bottom before the well can be killed. The surface pressure will be a major factor in determining the most suitable method of returning the pipe to bottom. It must be considered in relation to the string weight and the pressure rating of the BOPs. The first option that should be considered is stripping the pipe to bottom with the rig equipment. Annular stripping is the most satisfactory method, however ram combination stripping may have to be considered if surface pressures are approaching the pressure rating of the annular. On a floating rig, ram combination stripping is a particularly difficult operation. The limitations imposed by the rig BOP system may dictate that stripping the pipe to bottom is impractical. In this case, snubbing must be considered. Figure 5.2 represents an analysis of the decision making process in the event the well kicks with the pipe off bottom. 5-2 March 1995 BP WELL CONTROL MANUAL Figure 5.1 Preparations for the Well Kill KICK TAKEN WELL SHUT-IN MONITOR THE WELL CONTINUOUSLY PREKILL MEETING • • DECISION MADE AS TO MOST APPROPRIATE METHOD OF KILLING THE WELL DRILLING SUPERINTENDENT IN TOWN SHOULD BE MADE AWARE OF THE SITUATION ALLOCATE INDIVIDUAL RESPONSIBILITIES • ESTABLISH THE LINES OF COMMUNICATION COMPLETE PREPARATIONS • • • CHECK EQUIPMENT ENSURE PERSONNEL ARE BRIEFED VERIFY COMMUNICATIONS START UP KILL PROCEDURE • COMPANY REPRESENTATIVE CONTROLS THE OPERATION THROUGH THE CONTRACTOR TOOLPUSHER WEOX02.022 5-3 March 1995 BP WELL CONTROL MANUAL Figure 5.2 Decision Analysis – Pipe off Bottom (Drillpipe in the Stack) WELL KICKS PIPE OFF BOTTOM (Drillpipe in stack) IS IT POSSIBLE TO STAB A SAFETY VALVE? WELL IS FLOWING UP THE DRILLSTRING NO DROP THE PIPE AND SECURE THE WELL YES STAB AND CLOSE FULL OPENING SAFETY VALVE HANG OFF OPEN CHOKELINE VALVE SHEAR PIPE CLOSE ANNULAR INSTALL DP DART OR INSIDE BOP THE SEVERITY OF THE SITUATION DICTATES THAT STRIPPING WITH RIG EQUIPMENT IS IMPRACTICAL MONITOR SURFACE PRESSURE – ROTATE THE PIPE YES ATTEMPT TO REDUCE SURFACE PRESSURE – CONSIDER: • VOLUMETRIC • LUBRICATION • BULLHEADING • CIRCULATE OUT INFLUX POSSIBLE TO REDUCE SURFACE PRESSURE? NO YES CONSIDER SNUBBING SURFACE PRESSURE EXCEEDS PRESSURE RATING OF ANNULAR? NO REDUCE ANNULAR CLOSING PRESSURE ATTEMPT TO LOWER PIPE THROUGH STACK ATTEMPT TO REDUCE SURFACE PRESSURE – CONSIDER: • VOLUMETRIC • LUBRICATION • BULLHEADING • CIRCULATE OUT INFLUX YES POSSIBLE TO REDUCE SURFACE PRESSURE? NO CONSIDER FEASIBILITY OF RAM TO RAM STRIPPING CONSIDER SNUBBING NO POSSIBLE TO LOWER PIPE THROUGH ANNULAR? YES POSSIBLE TO LOWER TOOLJOINT THROUGH ANNULAR? YES IMPLEMENT ANNULAR STRIPPING NO ATTEMPT TO REDUCE SURFACE PRESSURE – CONSIDER: • VOLUMETRIC • LUBRICATION • BULLHEADING • CIRCULATE OUT INFLUX YES POSSIBLE TO REDUCE SURFACE PRESSURE ? NO CONSIDER FEASIBILITY OF ANNULAR TO RAM STRIPPING WEOX02.023 5-4 March 1995 BP WELL CONTROL MANUAL 4 Pipe off Bottom (Drillcollar in the Stack) Every effort should be made to ensure that well control problems are avoided when the BHA is across the stack. Regaining control from a situation in which the well has kicked when the BHA is across the stack can present serious complications. If the kick was swabbed in, it may be possible to bring the well under control by bleeding gas and lubricating mud into the well. It is however, undesirable to leave the collars in the stack for an extended period during a well control operation. In any event, it is likely that the pipe will have to be stripped to bottom before the well can be killed. There are considerable operational problems presented by attempting to strip the BHA through the annular; these include: • Many BOP stacks, especially on land, have only one annular BOP. The BOP element will be subject to considerable stress as the spiralled collars are stripped through it. If the element fails there is no back-up. • Stabilizers in the BHA may prevent stripping completely. Further complications that may arise in this situation are numerous, but include the following: • There is not sufficient weight of collars to strip through the annular BOP. • Well pressures force the collars out of the hole. • An internal blowout through the drillstring. The appropriate course of action required in these situations will depend to a large extent on the particular conditions and equipment at the rigsite. However Figure 5.3 is intended as a guide to dealing with such situations. 5 No Pipe in the Hole Correct tripping procedures will ensure that an influx is detected before the pipe is completely out of the hole. Should an influx remain undetected during tripping and the well is shut in with no pipe in the hole, it may not be possible to re-introduce drillpipe into the hole in order to strip to bottom. The limiting factor is the surface pressure in relation to the weight of the drillstring above the stack. A simple calculation will determine whether it will be possible to overcome the wellbore pressures with the weight of the string. There is quite clearly a limited weight that can be applied at a surface stack. If the influx is immediately below the stack, it may be possible to either kill the well by lubricating mud into the well, or to reduce the surface pressures such that it becomes possible to re-introduce pipe into the hole. 5-5 March 1995 BP WELL CONTROL MANUAL Figure 5.3 Decision Analysis – Pipe off Bottom (Drillcollar in the Stack) WELL KICKS (Drillcollar in the stack) IS IT POSSIBLE TO STAB A SAFETY VALVE? NO DROP THE PIPE AND SECURE THE WELL WELL IS FLOWING UP THE DRILLSTRING YES STAB AND CLOSE A FULL OPENING SAFETY VALVE OPEN CHOKE LINE VALVE(S) CLOSE ANNULAR YES INCREASE ANNULAR CLOSING PRESSURE IS THE ANNULAR LEAKING? NO MINOR LEAK LEAK STOPS IS THE PIPE FORCED OUT OF THE HOLE? INCREASE ANNULAR CLOSING PRESSURE YES NO NO INSTALL INSIDE BOP LEAK THREATENS RIG FLOOR AREA IS THE PIPE FORCED OUT OF THE HOLE? YES MAKE UP DRILLPIPE TO COLLARS IS IT POSSIBLE TO LOWER PIPE INTO THE HOLE? OPEN CHOKE LINE YES STRIP IN UNTIL DRILLPIPE IN THE STACK CHECK INTEGRITY OF ANNULAR PREVENTER DROP THE PIPE AND SECURE THE WELL NO ATTEMPT TO LOWER SURFACE PRESSURE CONSIDER LUBRICATING BULLHEADING STRIP IN THE HOLE YES IS IT POSSIBLE TO LOWER PIPE INTO THE HOLE? OPEN CHOKE LINE NO CONSIDER SNUBBING DROP THE PIPE AND SECURE THE WELL WEOX02.024 5-6 March 1995 BP WELL CONTROL MANUAL However, if the influx is someway down the hole, it may not be possible to reduce the surface pressure significantly. If the influx is migrating up the hole, it may be possible to kill the well by implementing the Volumetric Control Method. On fixed offshore and land rigs, the only practical method of controlling the well may be with the use of a snubbing unit. Snubbing units have been used in exceptional circumstances on floating rigs. Figure 5.4 represents a full analysis of the decision making process in the event that a kick is taken with no pipe in the hole. 6 While Running Casing or Liner Before pulling out of the hole prior to running casing, every effort will be made to ensure that the mud is conditioned and the well is under control, thereby minimising the possibility of well control problems during the casing operation. However, possible causes of well control problems while running casing include the following: • A kick that was swabbed in on the last trip of the hole. • Swabbing in a kick on a connection while running the casing. • Surge pressures while running casing leading to losses and hence inducing a kick. • When casing is run to cure a well control problem, such as after drilling with a floating mud cap or after controlling an underground blowout. Particular attention should therefore be paid to these aspects. In critical well sections, consideration should be given to installing casing rams in the BOP stack prior to running casing; this is only practical in surface stacks. Specialist shear rams are available that can shear up to 13 3/8 in. casing; these may be considered applicable in certain situations. It is impractical to detail the procedure required in the event that a kick is taken while running casing or a liner. The immediate priority however will be to close in the well, but the most suitable control technique can only be determined bearing in mind the particular conditions at the rigsite. The subsequent options available can be summarised as follows: • Cross over to drillpipe (unless current string weight is too great) and strip to bottom to kill the well. • Cross over to drillpipe, strip in until drillpipe is in the stack and kill the well at current shoe depth. • Kill the well with the casing across the stack. • Drop the casing. • Shear the casing. 5-7 March 1995 BP WELL CONTROL MANUAL Figure 5.4 Decision Analysis – No Pipe in the Hole WELL SHUT IN – NO PIPE IN THE HOLE MONITOR SURFACE PRESSURE IS THE INFLUX IMMEDIATELY BELOW THE RAMS? NO YES LUBRICATE MUD INTO THE HOLE AND BLEED GAS ALL GAS BLED FROM RAMS? NO YES IS THERE ANY PRESSURE UNDER THE RAMS? NO YES ATTEMPT TO REDUCE THE SURFACE PRESSURE BY LUBRICATING OR BULLHEADING POSSIBLE TO REDUCE SURFACE PRESSURE? NO DO SURFACE PRESSURES INDICATE THAT INTRODUCING PIPE INTO THE HOLE IS POSSIBLE? YES YES NO IMPLEMENT VOLUMETRIC CONTROL METHOD YES IS THERE EVIDENCE OF INFLUX MIGRATION? NO BULLHEAD KILL MUD INTO THE WELL PREPARE CONTINGENCY TO DEAL WITH THE FRACTURED ZONE KILL WELL NO IS SNUBBING A PRACTICAL CONSIDERATION? YES SNUB IN PIPE KILL THE WELL STRIP IN THE HOLE KILL WELL FLOWCHECK THE WELL OPEN THE RAMS WEOX02.025 5-8 March 1995 BP WELL CONTROL MANUAL The major factors that will determine the most appropriate course of action will include the following: • The length and type of casing run. • The possibility and consequences of the casing becoming stuck. • The possibility and consequences of collapsing the casing. • The feasibility of circulating out a kick by conventional means. (The relatively small annular clearance may cause excessive pressures in the annulus, or may possibly completely restrict circulation.) • The feasibility of killing the well by other means such as bullheading or by volumetric control. • The BOP stack configuration and ram types. • The likelihood of the casing being forced out of the hole by the well pressure. 7 Underground Blowout (a) Flow to a Fracture above a High Pressure Zone The majority of underground blowouts in the past have been as a result of a fracture to a weak zone up the hole as high pressure zone is penetrated. Figure 5.5 shows a decision analysis for identifying and dealing with an underground blowout of this type. If an underground blowout is suspected, on no account should attempts be made to control the well using standard techniques. If the annulus is opened, reservoir fluids will be allowed to flow up the wellbore to surface, thereby increasing surface pressures. The first action, after shutting in the well, will be to perform a positive test. The purpose of this test is to determine whether or not the hole is a closed system. A small displacement pump is lined up to the drillpipe and a small amount of fluid is pumped. If the drillpipe and casing pressure increase, there is no indication of fracture in the openhole. If the drillpipe pressure does not increase, or if any increase is not evident on the casing, then a fracture in the openhole is indicated. In order to halt an underground flow, it is necessary to pump fluid at a high rate down the drillpipe and up the annulus; thus effecting a dynamic kill. The fluid will eventually have to be at kill weight in order to balance the kick zone EMW. However, it will also have to be as thin as possible to ensure that it can be pumped at high rate without excessive surface circulating pressures. Generally the kill mud must flow at least as fast as the underground flow if it is not to be dispersed by the flow as it passes out of the bit. The kick zone EMW can at best be estimated because reliable drillpipe pressure will not be available. The mud weight required to kill the well will depend on the position of the fracture in the wellbore and the average weight of the fluid occupying the annulus between the fracture and surface. 5-9 March 1995 BP WELL CONTROL MANUAL Figure 5.5a Decision Analysis – Flow to a Fracture above a High Pressure Zone SHUT IN THE WELL MONITOR SURFACE PRESSURES REASSESS THE SITUATION NO EVIDENCE OF UNDERGROUND BLOWOUT IMPLEMENT STANDARD TECHNIQUES TO KILL THE WELL SUSPECT UNDERGROUND BLOWOUT BECAUSE: 1. DRILLPIPE ON VACUUM 2. PRESSURE BUILDUP CLEARLY INDICATES FORMATION HAS FRACTURED 3. ANNULUS PRESSURE FLUCTUATING RUN POSITIVE TEST RUN TEMPERATURE AND/OR NOISE LOG TO IDENTIFY FLOW IF NECESSARY NO UNDERGROUND BLOWOUT CONFIRMED ? YES 1. DO NOT BLEED FLUID FROM ANNULUS 2. LINE UP ONE PUMP TO THE ANNULUS. LINE UP MUD AND IF NECESSARY WATER SUCTION IF ANNULUS PRESSURE IS NOT EXCESSIVE LEAVE ANNULUS SHUT IN IF ANNULUS PRESSURE IS BUILDING, PUMP MUD AT SLOW RATE DOWN ANNULUS. IF ANNULUS CANNOT SUPPORT MUD, PUMP WATER CONTINUALLY MONITOR ANNULUS CONTINUED ON FOLLOWING PAGE WEOX02.026 5-10 March 1995 BP WELL CONTROL MANUAL Figure 5.5b Decision Analysis – Flow to a Fracture above a High Pressure Zone (continued) PREPARE 2 x ANNULUS VOLUME OF KILL WEIGHT MUD (AT MIN PV AND YP – USE FRICTION REDUCER IF AVAILABLE). REMOVE KELLY – INSTALL HP CIRCULATING LINE IMPLEMENT DYNAMIC KILL USING BARYTES PLUG • • • 1. CHECK MUD IS AT KILL WEIGHT 2. REDUCE MUD VISCOSITY 3. REDUCE DRILLSTRING INTERNAL FRICTION 4. PUMP LARGER PLUG PUMP KILL WEIGHT MUD AT MAXIMUM RATE KEEP PUMPING UNTIL ALL THE MUD IS USED STOP ONLY IF SURFACE PRESSURES BECOME EXCESSIVE DRILLPIPE AND ANNULUS PRESSURES INDICATE THAT UNDERGROUND FLOW HAS CEASED? TRY AGAIN YES TAKE STEPS TO SECURE WELL OPTIONS: 1. CEMENT BHA IN PLACE 2. POOH TO PLUG FRACTURE 3. POOH TO RUN CASING NO 1. MIX LCM PILL (100bbl MIN FOR LARGE ANNULUS) 2. MIX 2 x ANNULUS VOLUME OF KILL WEIGHT MUD 3. PUMP LCM PILL DOWN ANNULUS UNTIL JUST ABOVE FRACTURED ZONE IMPLEMENT DYNAMIC KILL • • • 1. CHECK MUD IS AT KILL WEIGHT 2. REDUCE MUD VISCOSITY 3. REDUCE DRILLSTRING INTERNAL FRICTION 4. PUMP LARGER PLUG TRY AGAIN PUMP KILL MUD AT MAXIMUM RATE DOWN DRILLPIPE PUMP LCM PILL DOWN ANNULUS AND INTO FRACTURE KEEP PUMPING UNLESS SURFACE PRESSURE LIMITS ARE REACHED DRILLPIPE AND ANNULUS PRESSURES INDICATE THAT UNDERGROUND FLOW HAS CEASED? YES TAKE STEPS TO SECURE WELL OPTIONS: 1. CEMENT BHA IN PLACE 2. POOH TO PLUG FRACTURE 3. POOH TO RUN CASING NO OPTIONS: 1. BACK OFF, STRIP UP INTO CASING, SQUEEZE HIGH FILTER LOSS CEMENT SLURRY TO PLUG WELL 2. IF CIRCULATION IS POSSIBLE ON BOTTOM, PUMP FRESHWATER AT MAXIMUM RATE TO SLOUGH HOLE YES IS THE PIPE STUCK ? NO OPTIONS: 1. STRIP UP INTO CASING. HAVING INSTALLED DART SQUEEZE HIGH FILTER LOSS CEMENT SLURRY TO PLUG WELL 2. PUMP FRESHWATER AT MAXIMUM RATE TO SLOUGH HOLE WEOX02.027 5-11 March 1995 BP WELL CONTROL MANUAL Figure 5.6 Decision Analysis – Flow to a Fracture or Loss Zone below a High Pressure Zone • DRILLING AHEAD • LOSSES EXPERIENCED SHUT DOWN ROTARY OR TOP DRIVE CURE LOSSES DRILL AHEAD • CANNOT CONTROL LOSSES • WELL STARTS TO FLOW • SHUT IN WELL POSSIBLE UNDERGROUND BLOWOUT INDICATORS: • NO SURFACE PRESSURE • ANNULUS AND DRILLPIPE ON VACUUM (ANNULUS PRESSURE MAY BUILD UP) RUN POSITIVE TEST RUN NOISE AND/OR TEMPERATURE LOG IF NECESSARY UNDERGROUND BLOWOUT CONFIRMED? NO REASSESS THE SITUATION YES • DO NOT BLEED FLUID FROM ANNULUS • LINE UP ONE PUMP TO THE ANNULUS. SUPPLY MUD AND IF NECESSARY WATER SUCTION CONTINUALLY MONITOR ANNULUS OPTIONS TO CONTROL THE FLOW: • PUMP LCM PILL • SET CEMENT PLUG ON BOTTOM • CIRCULATE THE HOLE TO LIGHT MUD. DRILL UNDER PRESSURE WITH ROTATING HEAD NO SURFACE PRESSURE LOGS INDICATE THAT UNDERGROUND FLOW HAS CEASED ? YES TAKE STEPS TO SECURE WELL 5-12 March 1995 WEOX02.028 BP WELL CONTROL MANUAL The fracture may only support a column of water, in which case it will be necessary to balance the kick zone pressure with the sum of the hydrostatic pressure of the kill weight mud from the kick zone to the fracture and the hydrostatic pressure of the water above the fracture. If the first attempt to control the flow is unsuccessful, the most likely causes will be␣either that the volume or the velocity of kill mud was insufficient. Subsequent options therefore include increasing the volume of the kill mud pumped and pumping at a greater rate. If the rig pumps have been operating at maximum output there remains the options to bring more pumps to the rigsite or to reduce the frictional resistance of the drillstring by such measures as: • Removing the nozzles of the bit with a charge run on wireline. • Perforating the BHA close to the bit. • Pumping a lighter, less viscous mud ahead of the kill weight mud in order to reduce the velocity of the inflow. As indicated in Figure 5.5, if these measures do not bring the well under control, there remains the option to mix an LCM pill or soft plug (See Chapter 2, Section 2.3) and displace it down the annulus and into the fracture as the kill weight mud is pumped down the drillpipe. The pump rates on the drillpipe and the annulus should be such as to ensure that the LCM pill is completely displaced into the fracture over the period of time that will be required to pump the prepared volume of kill weight mud. Past experience has shown that in many cases, having halted the underground flow, a further flow has been initiated by attempts to pull off bottom. If the decision is made to pull off bottom having halted an underground flow, extreme care should be taken. The industry has given the term ‘Baryte plug’ to the heavy weight pills required to deal with underground blowouts. The recommended procedure for mixing and spotting a baryte plug, to deal with an underground blowout, is covered in Chapter 6. (b) Flow to a Fracture or Loss Zone below a High Pressure Zone The most likely cause of an underground blowout that flows down the wellbore from a high pressure zone is that a naturally fractured or cavernous formation is drilled into. The resultant losses reduce the hydrostatic head of the drilling fluid to such an extent that a permeable zone higher up the wellbore begins to flow. When the well is shut-in, it is unlikely that any pressure will be recorded on either the drillpipe or the casing. However, the casing pressure may increase if gas migrates up the casing/drillpipe annulus; this rise in pressure is prevented by pumping mud down the annulus. Figure 5.6 shows the decision analysis for identifying and dealing with an underground blowout of this type. Having established that the flow is downwards to a loss zone, there are two options that should be considered for halting the flow: • Set a plug on bottom. • Reduce the mud weight and drill ahead under pressure. 5-13 March 1995 BP WELL CONTROL MANUAL Drilling under pressure will however only be used in circumstances in which lost circulation of this type has been anticipated, the high pressure zone has low permeability and the correct equipment, including a rotating head, is available onsite. See Chapter 2, Section 2.3 for LCM and cement plug recipes. 5-14 March 1995 BP WELL CONTROL MANUAL 6 WELL KILL TECHNIQUES Section Page 6.1 STANDARD TECHNIQUES 6.2 SPECIAL TECHNIQUES 6-1 6-31 2.1 Volumetric Method 6-33 2.2 Stripping 6-47 2.3 Bullheading 6-67 2.4 Snubbing 6-75 2.5 Baryte Plugs 6-84 2.6 Emergency Procedure 6-93 6.3 COMPLICATIONS 6-97 March 1995 BP WELL CONTROL MANUAL 6.1 STANDARD TECHNIQUES Paragraph Page 1 General 6-2 2 Kick Circulation Methods 6-2 3 Kick Sheet 6-3 4 Implementation of the Wait & Weight Method 6-5 5 Implementation of the Driller’s Method 6-8 6 Procedures For High Angle or Horizontal Wells 6-11 7 Floating Rig Procedure 6-14 8 Accounting for Choke Line Losses in Deep Water 6-23 Illustrations 6.1 An Example Completed Kick Sheet 6-14 6.2 The Kill Line Monitor 6-21 6.3 Subsea BOP Gas prior to Removing Gas from Below the Preventers 6-24 Removing Gas from a Subsea BOP Stack – Lower pipe rams closed hang off rams opened 6-25 Removing Gas from a Subsea BOP Stack – Kill and choke lines displaced to kill weight mud 6-26 Removing Gas from a Subsea BOP Stack – Kill and choke lines displaced to water 6-27 Removing Gas from a Subsea BOP Stack – Gas pressure bled down, gas occupies choke line 6-28 Removing Gas from a Subsea BOP Stack – Diverter is closed, the annular is opened and the gas is displaced from the stack 6-29 The Effect of Choke Line Losses – Casing pressure greater than choke line pressure 6-30 6.4 6.5 6.6 6.7 6.8 6.9 6.10 The Effect of Choke Line Losses – Casing pressure after initial circulation is less than choke line loss 6-31 6-1 Rev 1 March March 1995 1995 BP WELL CONTROL MANUAL 1 General This section covers the basic steps that are required to implement the Driller’s Method, the Wait & Weight Method on both a fixed installation as well as a floating rig. Further discussions on the theories behind the methods are covered in Vol.2, Chapter 5. Company policy is that a contingency plan must be developed regarding the implementation of the well control methods for both Company operated rigs and rigs that are under a Company contract. This section is intended to assist in drawing up these contingency plans. All the well control techniques are designed to ensure that: Bottom hole pressure is maintained constant and equal to, or slightly greater than, the formation pressure. This is the key to well control practice. These techniques use the principle that: The drillpipe pressure is used to monitor bottom hole pressure. In the event of any well control incident it is important that a diary of events is kept. The Well Control operations log can be used initially for this (See Figure 4.5). A full report should eventually be issued and submitted to Line Management. 2 Kick Circulation Methods (a) The Wait & Weight Method When conditions permit, it is recommended that the Wait & Weight Method be used in preference to other methods, in particular for vertical and low angle wells. With the Wait & Weight Method, the mud is weighted up to the kill weight after the well is shut in. Then circulation is started and the kick displaced from the hole with kill weight mud. So the well can be killed with one complete circulation. Circulation can be started immediately if the rig mud weighting system is able to weight up the mud at a rate greater than or equal to the mud SCR. Therefore the advantages of the Wait & Weight Method are as follows: • The surface pressure will be lower than using other methods if the kill weight mud enters the annulus before the influx is circulated out. This difference is most significant for influx containing gas, and for high intensity (large under-balance) kicks. This is illustrated in Figure 5.5 in Vol.2, Chapter 5. • The pressure exerted on the casing shoe (or the weak point in the openhole) will be lower than using other methods if the kill mud starts up the annulus before the top of the influx is displaced to the shoe (or openhole weak point). This is illustrated in Figure 5.6 in Vol.2, Chapter 5. • The well will be under pressure for the least time. 6-2 Rev March 1 March 1995 1995 BP WELL CONTROL MANUAL (b) The Driller’s Method In certain circumstances, it may not be practical to implement the Wait & Weight Method. These include: • There are insufficient stocks of weighting material at the rigsite. • The rig mud weighting system is not capable of increasing the active mud weight to kill weight as the kick is displaced. • There is some considerable doubt as to the mud weight required to kill the well. • Impending bad weather dictates that the kick must be displaced from the hole as quickly as possible. • Increasing surface pressures indicate the influx is rising rapidly in the annulus Under the above circumstances, the Driller’s method should be considered. The Driller’s Method requires that two complete hole circulations are carried out before the well can be killed. After a kick is taken and the well shut-in, the kick is displaced from the hole by the first circulation with the original mud. In the mean time the mud is weighted up to kill weight, and the second circulation carried out to kill the well. The advantages of the Driller’s Method over the Wait & Weight Method are: • The kick can be displaced from the hole soon after the well is shut-in. • The earlier circulation may reduce the risks of stuck pipe and other hole problems. • Influx fluids can be displaced from the well, even if suitable mud weighting material is not available. • It avoids the need to initiate a volumetric control during the waiting period. 3 Kick Sheet The kick sheet should be used to record all the relevant well and kick data. Figures 6.1a, 6.1b and 6.1c show an example kick sheet. The procedures for completing the kick sheet are shown in Figure 6.1d. The general well data, drillstring/annulus contents, circulating times and the mud pump data should be recorded routinely and available at all times in the kick sheet. In case a kick is taken, the relevant kick data should be recorded in the kick sheet. The shut-in procedure and the interpretation of the pressure data are covered in Chapter 4. Based on the kick data, a decision should be made regarding what method be used to kill the well. In addition to the standard methods which have been described in the previous paragraphs, some special techniques should be also considered. These special techniques are discussed in Section 6.2. If the decision is made to displace the kick from the hole by using one of the standard methods, the relevant parameters should be calculated and recorded in the kick sheet. 6-3 Rev 1 March March 1995 1995 BP WELL CONTROL MANUAL (a) Determine the kill weight mud Circulation may be initiated with the original weight mud, or with the kill weight mud, depending on the kill method to be used. The weight of the mud that would exactly balance the kick zone pressure is calculated from the shut-in drillpipe pressure as follows Pdp TVD x 1.421 Kill Mud Weight, MW2 = MW1 + where (SG) Pdp = Stabilised shut-in drillpipe pressure (psi) MW1 = Original mud weight (SG) TVD = True vertical depth of kick zone (m) It is not recommended practice to weight the mud any higher than the kill weight during the well killing operation. After the well has been killed however, the mud weight should be raised to provide suitable overbalance. (b) Calculate the baryte quantity required to weight up the mud This calculation is necessary in order to determine if adequate stocks of baryte are available on site. The amount of baryte required to weight up the mud can be calculated from the following formula: Baryte required, Wb = 1490 x (MW2 - MW1) (4.25 - MW2) (lb/bbl) Total quantity of baryte required (lb) = Wb x Total Active Mud Volume Total active mud volume = Drillstring Vol + Annulus Vol + Surface Active Vol (lb) (bbl) The stocks of baryte at the rigsite must be at least 10% greater than the calculated quantity of baryte required. (c) Develop annulus pressure profile It is useful to estimate the maximum pressures that will occur during circulation. The areas of particular importance will be the maximum pressure that will be exerted at the shoe (or openhole weak point) and the maximum surface pressure. It is not however essential to carry out these calculations prior to circulation. An approximate technique can be used to estimate the maximum pressure at a weak point in the openhole, as well as the maximum surface pressure during displacement. This has been presented in Vol.2, Chapter 5. The actual pressures will generally be lower than those predicted by the technique. Computer software that utilises the exact technique is also available at the Drilling and Completions Branch, BP Exploration, Sunbury. The software includes the effects that the conventional approximate technique has neglected. These include the gas solubility in oil-based muds, downhole temperature, gas dispersion and slip, etc. So the software can provide more realistic predictions of pressures and flows in the wellbore than the approximate techniques. The software can be also used to investigate the impacts of operational parameters, formation characteristics and human factors on the overall well control operation. These include the kick detecting volume, the formation permeability and over-pressure, the time required for the rig crew to shut-in and the mud SCR, etc. 6-4 Rev 1 1995 March 1995 March BP WELL CONTROL MANUAL 4 Implementation of the Wait & Weight Method Prior to implementing the Wait & Weight Method, the relevant sections of the Kick Sheet as covered in Paragraph 3 should be completed. The Wait & Weight Method accomplishes the kill operation in one complete circulation. It requires weight up of the mud after the well is shut in, followed by circulation with the kill weight mud. So several calculations are necessary prior to initiating circulation. These are as follows: (a) Determine the circulation rate The upper limit for the circulation rate is generally set by the maximum rate that baryte can be mixed into the mud. The following formula can be used to estimate the maximum possible circulation rate: Maximum circulation rate = Baryte delivery rate (lb/min) (bbl/min) Baryte required to weight up mud (lb/bbl) A limiting factor, particularly in the case of oil mud, may be the rate at which viscosity can be built in the mud. This, and associated problems of building mud weight are discussed in Chapter 1 in ‘Use of the Mud System’. Having established the maximum possible circulation rate, the actual circulation rate will be determined on the basis of several factors. These factors are detailed in Chapter␣1 in ‘Drills and SCRs’. The chosen SCR and the relevant pumping data should be recorded in the kick sheet. (b) Calculate the initial circulating pressure The initial drillpipe circulating pressure, Pic, should be calculated in order to estimate the circulating pressure that will be required to maintain constant bottom hole pressure at the start of the circulation. The initial circulating pressure recorded after the pump has been brought up to speed␣should be the sum of the shut-in drillpipe pressure and the SCR pressure at the chosen rate: P ic = P dp + P scr where Pic Pdp Pscr = Initial circulating pressure (psi) = Stabilised shut-in drillpipe pressure (psi) = Circulating pressure at SCR with MW1 (psi) (c) Calculate the final circulating pressure As the drillpipe is displaced with kill weight mud, the standpipe pressure must be reduced to take into account the increased hydrostatic pressure of the mud in the pipe. The standpipe pressure must also compensate for the additional friction pressure in the drillpipe and across the bit as the kill weight mud displaces the original mud. Once the drillpipe has been completely displaced to kill weight mud, the static drillpipe pressure required to balance the kick zone will be zero. At this stage therefore the␣␣circulating pressure can be estimated by determining the SCR pressure for the kill weight mud. 6-5 Rev 1 March March 1995 1995 BP WELL CONTROL MANUAL The final circulating pressure can be estimated as follows: Pfc = P scr (at MW1) x MW2 MW1 where P fc = Final circulating pressure (psi). (d) Determine the displacement times and the cumulative pump strokes At all times during circulation, it is important to know the position of the influx in the wellbore, as well as the volume of hole that has been circulated to kill weight mud. The key points during the circulation are as follows: • When the kill weight mud reaches the bit. • When the top of the influx is circulated to the casing shoe or openhole weak point. • When the influx is circulated to the choke. Before circulation is started, the estimated circulating time and the corresponding total pump strokes to each point should be calculated. Pumping time to reach point = of interest Total strokes to reach point = of interest Volume to be displaced (bbl) (min) Pump rate (bbl/min) Volume to be displaced (bbl) (stk) Pump output per stroke (bbl/stk) (e) Plot standpipe pressure schedule To ensure that the standpipe pressure is adjusted correctly as the kill weight mud is circulated down the drillpipe, a plot should be made of the required standpipe pressure (See Figure 6.1b). The initial circulating pressure should be plotted corresponding to zero strokes. The final circulating pressure should be plotted corresponding to total strokes equivalent to complete displacement of the drillpipe. The two points on the graph can be joined up with a straight line to produce the standpipe pressure schedule. (Note: for high angle or horizontal wells, the graph is not a straight line. See Paragraph 6.) In practice standpipe pressure is most easily controlled by reducing the pressure in small steps, rather than continuously. (f) Procedure for the displacement of the kick 1 Bring the pump up to kill speed • Line up the pump to the drillpipe and route returns through the choke manifold to the mud gas separator. • Zero the stroke counter on the choke panel. • Open the remote operated choke at the same time as the pump is started on the hole. Consider stroking the drillstring up at this point. 6-6 March Rev 1 1995 March 1995 BP WELL CONTROL MANUAL • Maintain the choke pressure equal to the original shut-in casing pressure as the pump is slowly brought up to speed. This may take 1/2 to 1 minute. • Once the pump is up to speed record the initial circulating pressure. If the actual initial circulating pressure is considerably different from the calculated value, stop the pump, shut in the well and investigate the cause. If the actual initial circulating pressure is equal to, or reasonably close to the calculated value, continue the displacement and adjust the standpipe pressure schedule accordingly. Any marginal difference between the actual and calculated initial circulating pressure is most likely to be due to the fact that the SCR pressure used to calculate the initial circulating pressure was inaccurate. The actual SCR pressure, and hence the corrected final circulating pressure, Pfc, can be determined from the initial circulating pressure as follows: Pscr = Pic – Pdp The standpipe pressure schedule can therefore be corrected to take into account the adjusted circulating pressures. 2 Circulate the influx from the well maintaining constant bottom hole pressure As the drillpipe is displaced with kill weight mud, the standpipe pressure should be stepped down according to the standpipe pressure schedule. (The standpipe pressure will have a natural tendency to drop as the kill weight mud is displaced down the drillpipe.) Once the drillpipe has been displaced to kill weight mud, the drillpipe pressure should be maintained at the final circulating pressure for the rest of the circulation. The pit gain, drillpipe pressure, choke pressure and all other relevant information should␣ b e recorded during displacement using the Well Control Operations Log (See␣Figure 4.5). These will help to determine the down hole condition during all stages of the kill operation. As the influx is displaced up the hole, the drillpipe pressure will tend to drop as the influx expands. (This expansion will not occur if the influx is water or oil.) This effect will be especially marked if the influx contains a significant quantity of gas. The choke should therefore be adjusted to compensate for this. For example, if the drillpipe pressure drops by 70 psi below that required, the choke pressure should be increased by approximately 70 psi. The pressure on the drillpipe will increase after a lag time which can typically be 2 seconds per 300m of drillstring depth. This technique will be most effective at the early stages of displacement; and less so at later stages of the displacement, if the well contains a significant proportion of gas. When the influx reaches the choke, the choke pressure will start to decrease due to the differences in density and viscosity between the influx and the mud. If the influx contains significant quantities of gas, the drop in choke pressure may be quite substantial, and the choke will have to be closed down quickly. As the influx is circulated from the well and mud is circulated to the choke, the choke pressure will begin to rise rapidly. The choke should therefore be opened to allow the choke pressure to drop sufficiently to re-establish the final circulating pressure on the drillpipe, and hence maintain constant bottom hole pressure. 6-7 Rev 1 March 1995 BP WELL CONTROL MANUAL Once the hole has been circulated to kill weight mud, the pump should be stopped, the well shut-in, and the casing and drillpipe checked for pressure. There should be no pressure on either the casing or the drillpipe. However, if there is still some pressure on the casing, circulation should be restarted to clear the contaminated mud from the annulus. Once the well has been completely killed, a flowcheck on the choke line return should be carried out before the rams are opened. If this flowcheck indicates no flow, the rams should be opened and a further flowcheck on the annulus carried out. In line with Company policy, a further complete hole circulation should be carried out prior to continuing operations. A suitable overbalance can be added to the mud at this␣stage. 5 Implementation of the Driller’s Method Prior to implementing the Wait & Weight Method, the relevant sections of the Kick Sheet as covered in Paragraph 3 should be completed. The Driller’s method is a two complete circulation method. The kick is circulated out of the hole by the first circulation with the original mud. The second circulation is carried out with the weighted mud to kill the well. Prior to the first circulation, the following calculations are necessary: (a) Determine the circulation rate The circulation rate for the first circulation of the Driller’s Method is not limited by the baryte mixing capacity of the rig. Limiting factors will include the additional wellbore pressures due to circulation, and further practicalities as outlined in Chapter 1. Record the chosen circulating rate SCR and the corresponding pumping data in the kick sheet. (b) Calculate the initial circulating pressure The initial circulating pressure at the start of the first circulation is calculated in the same manner as the Wait and Weight Method, although the drillstring displacement volume/time is not significant in this case. The initial circulating pressure will be maintained constant throughout the first circulation since the mud weight is not changed. (c) Determine the displacement times and corresponding pump strokes These figures are calculated in exactly the same manner as the Wait and Weight Method. (d) Plot the standpipe pressure schedule The standpipe pressure is held constant throughout the first complete circulation at the initial circulating pressure. 6-8 March Rev 1 1995 March 1995 BP WELL CONTROL MANUAL The following steps can be used as a guide for the procedure for the displacement of the␣kick: 1 Bring the pump up to speed for the first complete circulation • Line up the pump to the drillpipe and route returns through the choke manifold to the mud gas separator. • Set the stroke counter on the remote choke panel to zero. • Open the remote operated choke at the same time as the pump is slowly brought up to speed. Consider stroking the drillstring up at this point. • Maintain the choke pressure equal to the original shut-in casing pressure as the pump is slowly brought up to speed. This may take 1/2 to 1 minute. • Once the pump is up to speed record the initial circulating pressure. If the actual initial circulating pressure is considerably different from the calculated value, stop the pump, shut-in the well and investigate the cause. If the actual initial circulating pressure is equal to, or reasonably close to the calculated value, continue the displacement, holding the standpipe pressure at the value recorded when the pump was first brought up to speed. Any marginal difference between the actual and calculated initial circulating pressure is most likely to be due to the fact that the SCR pressure used to calculate the initial circulating pressure was inaccurate. The actual SCR pressure can be determined from the initial circulating pressure as follows: Pscr = Pic − Pdp This adjusted value for the SCR pressure should be used for estimating the circulating pressures for the second complete circulation. 2 Circulate the influx from the well maintaining constant bottom hole pressure Influx behaviour during circulation will be similar to the Wait and Weight Method requiring similar choke manipulation. Choke pressures will inevitably be higher than if the Wait and Weight Method had been␣used. These higher pressures will be reflected downhole, causing greater stress in the openhole. Once the influx has been displaced from the hole, the shut-in drillpipe and shut-in casing pressure should be equal. If the casing pressure is higher than the drillpipe pressure, this is evidence that there is still some kick fluid in the annulus, or the mud weights are out of balance. Prior to circulating kill weight mud into the hole, the calculations as outlined in Paragraph␣3 “Kick Sheet” should be carried out. The following further calculations are then worked: (a) Determine the circulation rate for the second circulation The circulation rate is determined on the same basis as if the Wait and Weight Method had been used. 6-9 Rev 1 March 1995 BP WELL CONTROL MANUAL (b) Calculate the initial circulating pressure The initial circulating pressure will be the same as for the first circulation. The initial circulating pressure is therefore calculated as follows: Pic = P dp + Pscr where Pic Pdp Pscr = Second circulation initial circulating pressure (psi) = Drillpipe pressure recorded prior to second circulation (psi) = Slow circulating rate pressure (psi) (c) Calculate the final circulating pressure As with the Wait and Weight Method, the circulating pressure must be adjusted to compensate for the kill weight mud. Pfc = P scr (at MW1) x where MW2 MW1 Pfc = Second circulation final circulating pressure (psi) MW1 = Original mud weight (SG) MW2 = Kill mud weight used for second circulation (SG) (d) Determine the displacement times and corresponding cumulative pump strokes These figures will be the same as for the first circulation. (e) Plot the standpipe pressure schedule The standpipe pressure schedule for the second circulation is drawn up in the same manner as for the Wait and Weight Method (Figure 6.1b). The following can be used as a guide for the procedure of circulating the hole to kill weight mud: 1 Bring the pump up to speed for the second complete circulation • Change pump suctions without stopping the mud pump, and begin pumping the kill weight mud. (An alternative is to stop pumping and then restart using the procedure for the Wait and Weight Method.) • Zero the stroke counter on the choke panel. • Once the pump has been switched to the kill mud, record the initial circulating pressure. The initial circulating pressure should be the same with the standpipe pressure during the first complete circulation. If this is the case, continue the displacement and adjust the standpipe pressure schedule accordingly. If the initial circulating pressure has changed considerably, stop the pump, shut in the well, and investigate the cause. 6-10 Rev 1 1995 March 1995 March BP WELL CONTROL MANUAL 2 Circulate the hole to kill weight mud maintaining constant bottom hole pressure As the drillpipe is displaced with kill weight mud, the standpipe circulating pressure should be stepped down according to the standpipe pressure schedule. Once the drillpipe has been displaced to kill weight mud, the final drillpipe circulating pressure is held constant by manipulating the choke. As kill weight mud is circulated up the annulus, the drillpipe pressure will tend to increase. The choke should be adjusted to ensure that the drillpipe pressure is maintained at the final circulating pressure; thereby ensuring constant bottom hole pressure. When the returned mud is at kill weight, the pump should be stopped and the well shut-in. The well should be checked for pressure. Once the well has been killed, a flowcheck on the choke line return should be carried out before the rams are opened. If this flowcheck indicates no flow, the rams should be opened and a further flowcheck on the annulus carried out. In line with Company policy, a further complete hole circulation should be carried out␣prior to continuing operations. A suitable overbalance can be added to the mud at this stage. 6 Procedures For High Angle or Horizontal Wells (a) Implementation of Kick Circulation Methods The procedures for implementing one of the standard kick circulation methods are essentially the same for both the vertical and high angle or horizontal wells (as covered in the previous paragraphs). However, there are several points which should be considered before and during a well killing operation in a high angle or horizontal well. • The advantages of the Wait & Weight Method over the Driller’s Method are less important in a high angle or horizontal well. This is because the weighted mud will not reduce the surface and casing shoe pressures until it has passed the horizontal or high angle section. By then the kick may have entered into the casing or been out of the well. • The circulation should be started using the Driller’s Method once the well has been␣shut in and the stabilised shut-in pressures are established. In the mean time, the kill weight mud is prepared in the reserve mud pits. The earlier start of the circulation will reduce the risks of stuck pipe and other hole problems associated with the stagnant mud. • Once the mud weight has been increased to the kill weight, the circulation should be switched to the kill weight mud, even if the influx is still in the annulus. The circulation continues until the kick is circulated out and the kill mud returns to surface. This will minimise the well pressures as well as the time of dealing with the kick. 6-11 Rev 1 March March 1995 1995 BP WELL CONTROL MANUAL (b) Standpipe Pressure Schedule When pumping down the kill mud through the drillpipe in a vertical well, the surface pump pressure should be reduced linearly from the initial circulating pressure (ICP) to the final circulating pressure (FCP), in order to maintain the bottom hole pressure constant. Thereafter, the pump pressure is kept constant at FCP until the kill mud returns to surface. Therefore, the pressure schedule during pumping the kill mud through the drillpipe can be obtained by simply joining a straight line between ICP and FCP. This has been covered in the previous paragraphs. However, this is not the case in a high angle or horizontal well because the change in the hydrostatic pressure due to the kill mud is not linear. For example, when the front of the kill mud is going through a horizontal section of the drillpipe, the hydrostatic pressure at the hole bottom does not change at all. So in this case the pump pressure should be kept constant (or increased slightly due to friction pressure increase with kill mud). Therefore, the standpipe pressure schedule should be modified to take into account the effect of hole angle. To achieve this, the standpipe pressures when the kill mud reaches several critical depths in the drillpipe should be calculated. These include the depths at the kick-off, end-build, end-tangent, etc. The calculations can be performed as follows: i. Calculate the drillpipe size factor and the friction constant. This is necessary in order to calculate the friction pressure increase due to the kill weight mud. α1 = L 1 / ID15 where: α1 L1 ID1 = Size factor for drillpipe section 1, (m/in 5) = Length of drillpipe section 1, (m) = ID of drillpipe section 1, (inch) If there is more than one drillpipe section (tapered string), then the size factor should be calculated for each of the sections. BHA can be treated as part of the drillpipe section. Pfc - P scr α 1 + α2 β= where: β α1 α2 Pfc Pscr = = = = Drillpipe friction constant, (psi.in 5/m) Drillpipe size factors for section 1 and 2, (m/in5) Final circulating pressure (psi) Slow circulating pressure with original mud MW1 , (psi) ii. Calculate the friction pressure increase when the kill mud reaches each of the critical depths in the drillpipe (kick-off, end-build, end-tangent, etc.). • If the critical depth is above/at the drillpipe section cross-over point, then: ∆P friction = β x • MD ID 1 5 If the critical depth is below the drillpipe section cross-over point, then: ∆P friction = β x [α 1 + (MD - L1 ) ] ID 25 where: ∆P friction = Friction pressure increase due to kill weight mud, (psi) 6-12 March Rev 1 1995 March 1995 BP WELL CONTROL MANUAL MD = Measured depth at the critical depth, (m) iii. Calculate the static drillpipe pressure when the kill weight mud reaches each of the critical depths: Pstatic = Pdp x (1.0 where: Pstatic Pdp TVD TVD h TVD ) TVD h = Static drillpipe pressure, (psi) = Drillpipe pressure before the kill weight mud is circulated, (psi) = Vertical depth at the critical depth, (m) = Vertical depth at the open hole kick zone, (m) iv. Calculate the standpipe pressure when the kill weight mud reaches each of the critical␣depths. Pstand = P scr + ∆Pfriction + Pstatic where: Pstand = Standpipe pressure, (psi) The results of the above calculations should be recorded in the Kick Sheet. These calculations should be carried out if the hole has a maximum angle greater than 30␣de grees. Figures 6.1a shows an example of a completed kick sheet for a high angle well. Figure␣6.1b sho ws the standpipe pressure schedule for pumping down the kill weight mud. It shows that the standpipe pressures required to maintain a constant bottom hole pressure are lower for a high angle well (with build-hold profile) than if the well was vertical. So if the standpipe pressure schedule for a vertical well was used (dotted straight line in Figure 6.1b), excessive high well pressures would result, which would increase the risk of fracturing the formation at the casing shoe or openhole weak point. (c) Trapped Gas in Inverted or Horizontal Hole Section If a kick containing free gas occurs in an inverted hole section (i.e. the hole angle is greater than 90 degrees), then the free gas will be trapped there unless the mud is circulated fast enough to flush the gas out of the inverted section. Similar scenarios also occur in washouts or undulations of a horizontal hole section. A combination of the following is a possible indication that a kick has occurred in the inverted or horizontal hole section: • There is an increased mud return flowrate • There is a positive pit gain • When the well is shut in, the drillpipe pressure and the casing pressure are the same (under-balanced kick) or both are zeros (swabbed kick) • The casing pressure is stable (no gas migration) However the kick influx density/type (gas, water or oil) can not be determined based on the above data (as using the method described in Section 4.3). A gas kick is recognised when it is being circulated through the low angle or vertical hole section, where gas expansion causes a continuous increase in the casing pressure. So the first attempt to kill the well should be using one of the standard techniques. 6-13 Rev 1 March March 1995 1995 BP WELL CONTROL MANUAL If the kick can not be circulated to surface using the standard techniques, it indicates that the kick influx is free gas which has been trapped in the inverted or horizontal hole section. To remove the trapped gas, the mud must be circulated with an annular velocity above a critical value. This critical annular velocity is about 100 ft/min when the hole angle is between 90~95 degrees. In an 8-1/2" hole, this corresponds to a critical flow rate of 4.6 bbl/min, which is higher than the normal range of SCR during a well control operation. So prior to drilling an inverted or horizontal hole section, the pump pressure at a SCR corresponding to 100~150 ft/min should be recorded in the kick sheet. The following procedures may be attempted to remove the trapped gas from the inverted or horizontal hole section: • Start circulation with the original mud at a flow rate corresponding to an annular mud velocity of 100~150 ft/min until the entire horizontal hole section has been displaced; • Reduce the flow rate to a normal SCR and proceed using one of the standard well killing techniques. • After one complete circulation, stop the pump and shut in the well to check the pit␣gain. • If there is still a positive pit gain, that indicates that some gas is still trapped downhole. Repeat the previous procedures. In cases where the high flow rate can not be achieved to remove the trapped gas, consider bullheading the gas back into the formation. As the trapped gas should stay near the kick formation, bullheading is more likely to succeed in an inverted hole section. The bullheading technique is described in Section 6.2. 7 Floating Rig Procedure Well control on a floating rig presents special problems that are not encountered on land and fixed offshore rigs. The main difficulties stem from the fact that the well must be killed while circulating through a small diameter choke line. The problems presented can be summarised as follows: • The frictional pressure generated by circulating through the choke line may cause excessive pressures in the wellbore or in the circulating system. • The entry of the influx into the choke line may cause an uncontrollable drop in bottomhole pressure. • As the mud displaces the influx from the choke line the rapid increase in hydrostatic pressure in the annulus may cause excessive pressures in the openhole. These problems are particularly acute in deep water. However, well control procedures should be modified in line with those described here, even in relatively shallow water, to take account of these problems. The drillpipe pressure is still used to monitor bottomhole pressure. 6-14 March Rev 1 1995 March 1995 BP WELL CONTROL MANUAL Figure 6.1a An Example of Completed Kick Sheet An Example of Completed Kick Sheet Well No. Well No. Rig Name: 8-1/2" 1003 50 Hole Size: MAASP (psi): Barytes on Site (MT): Rigname 27-Oct-94 Date: 9-5/8" Casing Size: Shoe Depth (m): TVD= 1535 1.44 40 Max Eqiv. Mud Weight (sg): On Order (MT): 13:10 Time: TD= 4291 10900 300 Casing Burst (psi): Total Reserved Mud Vol (bbl): DRILLSTRING CONTENTS DP/DC Section ID 5" DP 5" HWDP 6-1/4" DC Capacity (bbl/m) 4.276 3 2.25 Length (m) 0.0583 0.0287 0.0161 5180 60 60 Vol (bbl) Cumulative Volume (bbl) 301.82 1.72 0.97 303.5 304.5 ANNULUS CONTENTS Hole/Casing Section ID 5"DP - 9-5/8"csg 5"DP - Hole 6-1/4" DC - Hole Capacity (bbl/m) 8.681 8.5 8.5 Surface Equipment Vol (bbl): 6 5-1/2" 5-1/2" 30 40 50 Cumulative Volume (bbl) 831.5 837.9 100 2.9 Vol (bbl): 350 Surface Active Mud Vol (bbl): 4723 4723 Max Pres (psi): Max Pres (psi): PUMP 1 SPM Length (m): 1151 Vol (bbl) 688.6 142.9 6.3 1501 Total Active Mud Vol (bbl): Pump 2 Liner: 4291 949 60 Choke Line ID: 3.0 Total Circulating System Vol (bbl): Pump 1 Liner: Length (m) 0.1605 0.1506 0.1058 Eff (%): 97 Stroke Vol (bbl/stk): Eff (%): 97 Stroke Vol (bbl/stk): PUMP 2 bbl/min Pscr 2.565 3.42 4.275 350 590 890 SPM TRAVEL TIMES (MIN / STROKES) bbi/min Pscr Surface to Bit Bit to Shoe 2.565 3.42 4.275 355 600 900 119 / 3567 89 / 3567 71 / 3567 58 / 1746 44 / 1746 35 / 1746 Depth (m): TVD= 1667 TD= 5300 400 1.15 Annulus Pres (psi), Pa= Stroke Vol (bbl/stk): 0.086 30 40 50 0.0855 0.0855 Shoe to Choke Total 268 / 8055 445 / 13368 201 / 8055 334 / 13368 161 / 8055 267 / 13368 KICK DATA Time of Kick: 15:25 Shut-in DP Pres (psi), Pdp= Kill Mud Weight (sg), MW2= Chosen Pump SPM: Time Started: 30 15:30 Mud Weight (sg), MW1= Barytes Required (lb/bbl): SCR (bbl/min): 750 Initial Circ Pres (psi), Pic= 460 81.1 2.565 Pit Gain (bbl): Total (MT): Pscr (at MW1)= 0.98 20 55 350 psi 410 Final Circ Pres (psi), Pfc= For High Angle or Horizontal Wells ( > 30 deg) Drillpipe Size ID 5" DP + BHA 4.276 Section Point MD (m) Length (m) Size Factor 5300 Drillpipe Friction Constant 3.708 16.27 STANDPIPE PRESSURE WHEN PUMPING DOWN KILL MUD Surface: Kick Off: End Build 1: TVD (m) Vol (bbl) Strokes Pstatic (psi) Pfriction (psi) 0 350 1328 350 1000 20 77 239 905 316 160 4 15 5300 1667 309 3612 0 60 0 0 0 =Pdp 0 Standpipe Pressure (psi) Pic= 750 670 525 Pfc= 410 DP Cross-Over: End Tangent 1: End Build/Drop 2: Bit: 6-15 March 1995 0 239 905 3612 800 6-16 Standpipe Pressure (psi) 750 750 670 525 410 750 410 700 Kick off 650 600 If The Well Was Vertical 550 500 End Build 450 400 Bit 350 0 500 1000 1500 2000 Pump Strokes 2500 3000 3500 4000 BP WELL CONTROL MANUAL Figure 6.1b An Example of Kick Sheet March 1995 STANDPIPE PRESSURE SCHEDULE BP WELL CONTROL MANUAL Figure 6.1c An Example of Kick Sheet Figure 6.1c: An Example of Kick Sheet SUMMARY OF FORMULAE 1. MAASP = P wp - 1.421 x MW 1 x D wp For High Angle or Horizontal Wells 2. Pipe Internal Capacity (bbl/m) = ID 2 / 313.8 10. 3. Annular Capacity (bbl/m) = (DH 2 - DP 2) / 313.8 Drillpipe 1 Size Factor, 1 = L 1 / ID15 Drillpipe 2 Size Factor, 2 = L 2 / ID25 Pdp 4. Kill Mud Weight (sg), MW2 = MW 1 + 1.421 x TVDh 11. Pfc - Pscr Drillpipe Friction Constant, = 1+2 (MW2 - MW1 ) 5. Baryte Required (lb/bbl) = 1490 x (4.25 - MW 2) 12. Static Pressure When Kill Mud at TVD (psi): Pstatic = P dp x (1.0 - TVD / TVDh ) 6. Initial Circulating Pressure (psi), Pic = P dp + P scr 7. Final circulating Pressure (psi), P fc = P scr MW 2 x MW 1 13. Friction Pressure Increase When Kill Mud at MD (psi): a. When MD above/at DP cross-over point: MD Pfriction = x ID 15 8. Pumping Time to Reach Depth of Interest (min): Volume to be displaced (bbl) = Pump output (bbl/min) b. When MD below DP cross-over point: (MD - L1) Pfriction = x [ 1 + ] ID 25 9. Pump Strokes to Reach Depth of Interest (stk): Volume to be displaced (bbl) = Pump stroke volume (bbl/stk) 14. Standpipe Pressure at Depth of Interest (psi): Pstand = P scr + Pfriction + Pstatic SYMBOLS AND UNITS D wp DH DP ID L MAASP MD MW 1 MW 2 Pdp Pfc Pic Pscr Vertical depth at openhole weak point (m) Hole diameter or casing ID (inch) Drillpipe OD (inch) Drillpipe ID (inch) Length of drillpipe with same size (m) Pstand Pstatic Pwp TVD TVD h Maxi mum allowable annulus surface pressure (psi) Measured depth at depth of interest (m) Original (unweighted) mud weight (sg) Kill mud weight (sg) Shut-in drillpipe pressure (psi) Final circulating pressure (psi) initial circulating pressure (psi) Standpipe pressure at solw circulating rate with original mud (psi) Pfriction Standpipe pressure (psi) Static (drillpipe) pressure (if well was shut in) when pumping kill mud (psi) Leak off pressure at openhole weak point (psi) True vertical depth at depth of interest (m) True vertical depth of open hole (m) Drillpipe size factor Drillpipe friction constant Friction pressure increase with kill mud (psi) Subscripts for ID, L and : 1 Drillpipe size 1 2. Drillpipe size 2 6-17 March 1995 BP WELL CONTROL MANUAL Figure 6.1d An Example of Kick Sheet COMPLETION OF KICK SHEET GENERAL WELL DATA (Routinely Recorded) These include well No, rig, date, time, hole size, casing size, shoe depths, MAASP, max mud weight, casing burst pressure, barite quantities and reserved mud volume. • MAASP [psi] = (Leak-off pressure, psi) − 1.421 x (Mud weight in hole, sg) x (Leak-off TVD, m) • Max mud weight (Shoe frac grad) [sg] = (Leak-off pressure, psi) / [ 1.421 x (Leak-off TVD, m) ] DRILLSTRING / ANNULUS CONTENTS (Routinely Recorded) These include the drillstring, annulus contents, surface volumes and the total active mud volume. The drillstring contents include OD, ID, capacity, length and volume. The annulus contents include hole/casing sizes (with drillstring OD), hole/casing ID, capacity, length and volume). • Drillstring capacity [bbl/m] = (Pipe ID, inch)2 / 313.8 • Annulus capacity [bbl/m] = [ (Hole size, inch) − (Pipe OD, inch) 2 ] / 313.8 2 • Volume [bbl] = (Capacity, bbl/m) x (Length, m) • Total active mud volume [bbl] = (Total circulating system vol, bbl) + (Surface active mud vol, bbl) CIRCULATION TIME AND PUMP STROKES (Routinely Recorded) These include the liner size, rated pressure, volume efficiency and stroke volume. Record at least three slow circulating rates and the corresponding standpipe pressures. Calculate circulation times and number of pump strokes: • Surf → Bit [min] = (Total drillstring volume, bbl) [stk] = (Total drillstring volume, bbl) / (Pump output, bbl/min) / (Pump stroke volume, bbl/stk) • Bit → Shoe [min] = (Total open hole annular volume, bbl) [stk] = (Total open hole annular volume, bbl) • Shoe → Choke [min] = (Total casing annular volume, bbl) [stk] = (Total casing annular volume, bbl) / (Pump output, bbl/min) / (Pump stroke volume, bbl/stk) / (Pump output, bbl/min) / (Pump stroke volume, bbl/stk) KICK DATA Record all the relevant kick data (time, hole depths, mud weight, shut-in DP & casing pressures, pit gain). All the kill parameters should be calculated. • Kill mud weight [sg] = (Mud weight in hole, sg) + [(SIDPP Pdp, psi) / [ 1.421 x (Hole TVD, m)] (Kill mud weight, sg) − (Mud weight in hole, sg) • Barite required [lb/bbl] = 1490 x 4.25 − (Kill mud weight, sg) • Total quantity of barite required [MT] = (Total active mud volume, bbl) x (Barite required, lb/bbl) / 2205 • Initial circulating pres P ic [psi] = (SIDPP Pdp, psi) + (SCR pres P scr , psi) • Final circulating pres P fc [psi] = (SCR pres P scr , psi) x (Kill mud weight, sg) 6-18 March 1995 / (Mud weight in hole, sg) BP WELL CONTROL MANUAL Figure 6.1d An Example of Kick Sheet (cont'd) HIGH ANGLE OR HORIZONTAL WELLS (Angle > 30 deg) No need to complete this section if the well is vertical (or angle<30 deg). In this case, the standpipe pressure schedule can be obtained by joining a straight line between the initial and the final circulating pressures. Otherwise, the standpipe pressures should be calculated for pumping down the weighted kill mud to each of the depths at kick-off, end-build, drillpipe cross-over, end-tangent, etc. After the kill mud has reached the bit depth, the standpipe pressure should be maintained constant at the final circulating pressure. • DP size factor, α = (Drillpipe section length, m) / (Drillpipe ID, inch)5 (Calculate for each of the drillpipe IDs) (Final circ pres P fc , psi) − (SCR pres P scr , psi) • DP Friction Const, = (DP Size 1 factor α1) + (DP Size 2 factor α2) Calculate the pump stroke and the corresponding standpipe pressure when the kill mud has reached the depth at MD/TVD (the point for calculation such as kick off, end-build, etc.): • Volume [bbl] = (Drillstring capacity, bbl/m) x (Measured depth MD, m) • Pump stroke [stk] = (Volume, bbl) / (Pump stroke volume, bbl/stk) (TVD, m) • Static (shut-in) pressure Pstatic [psi] = (SIDPP Pdp, psi) x [ 1.0 − ] (Hole TVD, m) • Friction pressure increase (due to kill mud) ∆Pfriction : - If MD (point for calculation) is above or at DP1/DP2 cross-over point: ∆P friction [psi] = (DP Friction Const, β) x (MD, m) / (Top drillpipe ID, inch) 5 - If MD is below DP1/DP2 cross-over point: [ (MD, m) − (Top DP1 length L 1 , m) ] ∆P friction [psi] = β x [ (DP1 size factor, α1 ) + (DP2 ID, inch) 5 • Standpipe Pressure Pstand [psi] = (SCR pres P scr , psi) + (∆Pfriction , psi) + (Pstatic , psi) STANDPIPE PRESSURE SCHEDULE Draw up the standpipe pressure schedule on the graph paper by: 1. Choose appropriate scales for the horizontal pump stroke and the vertical standpipe pressure. 2. Mark each of the calculated standpipe pressures against the corresponding pump strokes. The initial circulating pressure should be plotted corresponding to zero stroke and the final circulating pressure corresponding to the strokes for the kill mud to reach the bit. 3. Join the marked points with straight lines. From the final point onward (after the kill mud has reached the bit), draw a horizontal line. For vertical or low angle wells, there are only two marked points (i.e. the initial & final circulating pressures) and therefore the pressure schedule is a straight line before the kill mud reaches the bit. For high angle or horizontal wells, there should be more than two points and the pressure schedule is not be a straight line . 6-19 March 1995 BP WELL CONTROL MANUAL Choke line losses are generally not significant at slow circulating rates in shallow water and so the calculations required during the implementation of both the Driller’s Method and the Wait and Weight Method on a floating rig, drilling in shallow water, do not account for choke line losses. The calculations as covered in Paragraphs 4 to 6 (which cover the normal implementation of the Wait and Weight Method and the Driller’s Method) are therefore still applicable. In deep water, when choke line losses can be significant, it is necessary to assess the effect of choke line losses on wellbore pressures during circulation. In which case further calculations, as covered in Paragraph 8, ‘Accounting for Choke Line Losses in Deep Water’, are required to account for choke line losses. Standard procedure (as detailed in Paragraphs 4 to 6) should be modified along the following lines when using either the Wait and Weight Method or the Driller’s Method on a floating␣r ig: 1 2 Bring the pump up to speed • Line up to monitor wellhead pressure through the kill line. See Figure 6.2 for a schematic␣of the kill line monitor . (Bear in mind that the kill line may not contain mud at this stage.) • Line up the pump to circulate down the drillpipe and route returns through the choke manifold to the mud gas separator. • Set the stroke counter on the choke panel to zero. • Record the pressure registered on the kill line monitor. • Open the remote operated choke at the same time as the pump is started on the hole. • Hold the kill line monitor pressure constant as the pump is brought up to speed. • Once the pump is up to speed the initial circulating pressure should be checked. Circulate the kick to the wellhead maintaining constant bottomhole pressure In the case of the Wait and Weight Method the standpipe pressure will be reduced in line with the standpipe pressure schedule. In the case of the Driller’s Method the standpipe pressure is maintained at initial circulating pressure as the kick is displaced from the hole. When the total strokes pumped indicates that the influx is approaching the wellhead the kill line monitor should be carefully checked for any sudden drops in pressure. A drop in pressure registered on this gauge indicates that the influx has entered the choke line, however this drop may not always be detected. 3 Circulate the influx out of the well maintaining constant bottomhole pressure It is recommended that the influx is displaced up the choke line at a considerably reduced rate in order that the choke does not have to be adjusted at an unrealistic rate. This may involve shutting in the well at this point and restarting the displacement at the minimum pump speed. A considerable increase in choke pressure will generally be required as gas or lightweight influx displaces mud from the choke line. 6-20 March 1995 BP WELL CONTROL MANUAL Figure 6.2 Use of Kill Line Monitor for Wellhead Pressure on Floating Rig DRILLPIPE PRESSURE GAUGE PUMP KILL LINE MONITOR CHOKE PRESSURE GAUGE VALVE OPEN VALVE CLOSED RETURNS SEA KILL LINE (KILL LINE VALVES OPEN) CHOKE LINE SEABED KEY MUD VALVE OPEN GAS VALVE CLOSED WEOX02.030 6-21 Rev 1 March March 1995 1995 BP WELL CONTROL MANUAL An increase in the pressure recorded at the kill line monitor may indicate that the original mud behind the influx has started up the choke line. In the case of the Wait and Weight Method, once the returns are at kill weight, the pump should be stopped and the well checked for pressure. In the case of the Driller’s Method, the well will be circulated to kill weight mud prior to step (4). 4 Remove BOP gas It is quite possible that some gas will have accumulated under the closed BOP during␣displacement of the kic k. This gas must be removed from the stack before the BOP is opened. The recommended technique is to isolate the well, displace the kill and choke lines to water (maintaining the BOP gas at original pressure), bleed gas up choke line, open the annular and allow riser to U-tube, displacing the gas up the choke line. Diesel may be used instead of water if low mud weights have been used to kill the well. (Adequate facilities should be available to deal with the returned diesel.) For the example stack shown in Figure 6.4, for which trapped gas has the potential to be a serious problem, this technique is implemented as follows: • Isolate the well from the BOP stack by closing the lower pipe rams. (See Figure␣6.4.) • Circulate kill mud down the kill line, across the stack and up the choke line. Route␣ r eturns through the degasser. Record the kill line circulating pressure. (See␣Figure 6.5.) • Shut the well in. Line up to circulate water down the kill line and up the choke line. • Slowly displace the kill line to water. As the kill line is displaced to water increase the kill line circulating pressure by an amount equal to the difference in hydrostatic pressure between the kill mud and water at the depth of the stack. (This will ensure that the gas pressure is unchanged.) • Keep pumping water across the stack and maintain the final circulating pressure.␣W hen the returns are clear water, stop the pump and shut in at the choke. (See Figure␣6.6.) • Close the subsea kill line valve(s). • Bleed pressure from the choke line. (See Figure 6.7.) (The pressure that has been trapped in the gas bubble is used to ensure that the gas bubble expands as the choke is opened to displace all the water from the choke line. Having bled all the pressure from the choke line the gas bubble should be almost at atmospheric pressure.) • Close the diverter. Line up the trip tank/pump to circulate the riser under the diverter. • Slowly bleed back the upper annular closing pressure. Open the annular. • Allow the riser to U-tube. Take returns up the choke line. Fill the hole as required. (See Figure 6.8.) Be prepared to deal with gas in the riser. • Displace the riser and kill and choke lines to kill weight mud. 6-22 March 1995 BP WELL CONTROL MANUAL • Open the lower pipe rams. • Open the diverter and flowcheck the well. 8 Accounting for Choke Line Losses in Deep Water In line with the standard procedure for floating rigs, an attempt will always be made to compensate for choke line losses with the use of the kill line monitor. However, the effect of choke line losses should be assessed in any situation in which choke line losses are considered significant. This is most likely to occur only in deep water. (See Chapter 1, Section 1.3 for the techniques for measuring choke line pressure losses.) The following procedure can be used to account for choke line losses for the Wait and Weight Method (however the same principles are applicable to the Driller’s Method): 1 Assess the effect of choke line losses at pump start up In order to determine the most suitable circulation rate, the additional pressure acting in the wellbore due to choke line friction should be estimated at a range of circulating rates. The following two cases may be applicable at this point: Case A: When shut-in casing pressure is greater than the choke line friction pressure at the desired slow circulating rate. (See Figure 6.9.) Case B: When the shut-in casing pressure is less than the choke line friction pressure at the desired slow circulation rate. (See Figure 6.10.) In Case A the choke line friction pressure will be fully compensated for until such time during the displacement that the required choke pressure is less than the sum of choke line friction pressure and the wide open choke pressure. In most cases this will occur only when the original mud behind the influx is passing the choke, at which time subsurface pressures are unlikely to be critically high. Therefore, if Case A is applicable, the choke line losses should not impose a limitation on the circulation rate. However Case B represents a situation in which part of the choke line frictional pressure will be applied on the openhole. The choke line frictional pressure can be compensated for up to the amount equal to the difference between the shut-in annulus pressure and the wide open choke pressure. The additional pressures exerted in the wellbore due to choke line losses at pump startup can be determined as follows: For Case A: there should be no additional pressures in the wellbore due to choke line friction at pump start-up For Case B: additional wellbore pressure due to choke line friction = Pcl – Pa + Poc where: = annulus shut-in pressure (psi) = choke pressure at SCR recorded with the choke wide open (psi) = choke line frictional pressure at SCR (psi) Pa Poc Pcl 6-23 March 1995 BP WELL CONTROL MANUAL Figure 6.3 Subsea BOP Stack prior to Removing Gas from Below the Preventers KILL LINE CHOKE LINE MUD UPPER ANNULAR GAS VALVE OPEN VALVE CLOSED LOWER ANNULAR BLIND/SHEAR PIPE RAM PIPE RAM PIPE RAM PIPE RAM WEOX02.031 6-24 March 1995 BP WELL CONTROL MANUAL Figure 6.4 Removing Gas from a Subsea BOP Stack – Lower pipe rams closed hang off rams opened KILL LINE CHOKE LINE MUD UPPER ANNULAR GAS VALVE OPEN VALVE CLOSED LOWER ANNULAR BLIND/SHEAR PIPE RAM PIPE RAM PIPE RAM PIPE RAM WEOX02.032 6-25 March 1995 BP WELL CONTROL MANUAL Figure 6.5 Removing Gas from a Subsea BOP Stack – Kill and choke lines displaced to kill weight mud KILL LINE CHOKE LINE MUD UPPER ANNULAR GAS VALVE OPEN VALVE CLOSED LOWER ANNULAR BLIND/SHEAR PIPE RAM PIPE RAM PIPE RAM PIPE RAM WEOX02.033 6-26 March 1995 BP WELL CONTROL MANUAL Figure 6.6 Removing Gas from a Subsea BOP Stack – Kill and choke lines displaced to water KILL LINE CHOKE LINE MUD GAS UPPER ANNULAR WATER (OR DIESEL) VALVE OPEN VALVE CLOSED LOWER ANNULAR BLIND/SHEAR PIPE RAM PIPE RAM PIPE RAM PIPE RAM WEOX02.034 6-27 March 1995 BP WELL CONTROL MANUAL Figure 6.7 Removing Gas from a Subsea BOP Stack – Gas pressure bled down, gas occupies choke line KILL LINE CHOKE LINE MUD UPPER ANNULAR GAS WATER (OR DIESEL) VALVE OPEN VALVE CLOSED GAS PRESSURE BLEEDS DOWN TO DISPLACE WATER FROM CHOKE LINE RESULTANT GAS PRESSURE IS CLOSE TO ATMOSPHERIC LOWER ANNULAR BLIND/SHEAR PIPE RAM PIPE RAM PIPE RAM PIPE RAM WEOX02.035 6-28 March 1995 BP WELL CONTROL MANUAL Figure 6.8 Removing Gas from a Subsea BOP Stack – Diverter is closed, the annular is opened and the gas is displaced from the stack KILL LINE CHOKE LINE MUD GAS UPPER ANNULAR WATER (OR DIESEL) VALVE OPEN VALVE CLOSED LOWER ANNULAR BLIND/SHEAR PIPE RAM PIPE RAM PIPE RAM PIPE RAM WEOX02.036 6-29 March 1995 BP WELL CONTROL MANUAL Figure 6.9 The Effect of Choke Line Losses – Casing pressure greater than choke line pressure INITIAL SHUT-IN CONDITIONS CIRCULATION STARTED AT 40SPM CHOKE PRESSURE DROPS BY CHOKE LINE PRESSURE DROP DRILLPIPE PRESSURE INCREASES BY SCR PRESSURE 800 400 800 800 1385 430 KILL LINE PRESSURE HELD CONSTANT BOTTOMHOLE PRESSURE STAYS APPROXIMATELY CONSTANT KEY MUD GAS SCRS AND CHOKE LINE LOSSES SPM 20 30 40 PSCR 400 680 985 PCL 150 250 370 MINIMUM RATE FOR PUMP WEOX02.037 6-30 March 1995 BP WELL CONTROL MANUAL Figure 6.10 The Effect of Choke Line Losses – Casing pressure after initial circulation is less than choke line loss INITIAL SHUT-IN CONDITIONS CIRCULATION STARTED AT 30SPM CHOKE PRESSURE DROPS BY CHOKE LINE PRESSURE DROP DRILLPILE PRESSURE INCREASED BY SCR PRESSURE 400 100 400 400 780 150 KILL LINE PRESSURE HELD CONSTANT BOTTOMHOLE PRESSURE STAYS APPROXIMATELY CONSTANT INFLUX CIRCULATED OUT WITH ORIGINAL MUD WEIGHT CIRCULATION STARTED AT MINIMUM RATE, 20SPM DRILLPIPE PRESSURE EQUALS THE SUM OF THE ORIGINAL SHUT-IN DRILLPIPE PRESSURE PLUS THE SCR PRESSURE PLUS THE CHOKE LINE LOSS PLUS THE WIDE OPEN CHOKE PRESSURE MINUS THE SHUT-IN CASING PRESSURE 100 100 100 200 CHOKE PRESSURE WITH CHOKE WIDE OPEN 600 50 UNABLE TO KEEP THE KILL LINE PRESSURE CONSTANT. EVEN WITH THE CHOKE WIDE OPEN THE KILL LINE PRESSURE INCREASES BY THE SUM OF CHOKE LINE LOSS AND WIDE OPEN CHOKE PRESSURE MINUS THE ORIGINAL SHUT-IN PRESSURE BOTTOMHOLE PRESSURE INCREASES SCRS AND CHOKE LINE LOSSES SPM 20 30 40 PSCR 400 680 985 PCL 150 250 370 MINIMUM RATE FOR PUMP KEY MUD GAS WEOX02.038 6-31 March 1995 BP WELL CONTROL MANUAL These pressures as well as the annulus frictional pressure will act at all points in the wellbore and circulating system. The effect of these additional pressures must therefore be analysed at all points in the system and in particular at the openhole weak point. 2 Calculate the initial circulating pressure The initial circulating pressure is calculated to estimate the standpipe pressure once the pump is up to speed. 3 For Case A: the initial circulating pressure = Pdp + P scr For Case B: the initial circulating pressure = Pdp + P scr + P cl + P oc – P a where: = show circulating rate pressure (psi) = shut-in drillpipe pressure that reflects the kick zone pressure (psi) = choke line frictional pressure at SCR (psi) = annulus shut-in pressure (psi) = choke pressure recorded while circulating at SCR with the choke wide open (psi) Pscr Pdp Pcl Pa Poc Calculate the final circulating pressure The final circulating pressure, when kill weight mud reaches the bit, for each case is calculated as follows: For Case A: Final circulating pressure = Pscr X For Case B: Final circulating pressure = (Pscr where X MW2 MW1 MW2) + Pcl + Poc – P a MW1 MW2 = weight of the kill mud (SG) MW1 = weight of the original mud (SG) 4 Monitor pressure at the kill line monitor as the pump is brought up to speed For Case A, the pressure at the kill line monitor is held constant as the pump is brought up to speed. The choke pressure will decrease by an amount equivalent to the choke line friction pressure once the pump is up to speed. For Case B, the pressure at the kill line monitor will be constant as the pump is brought up to speed. However at some point before the pump is up to the SCR the kill line monitor pressure will start to increase. Once the pump is up to speed the choke will be wide open and the pressure at the kill line monitor will have risen by the proportion of the choke line friction pressure that is not compensated for. (The increase will be equivalent to Pcl + P oc – P a.) 5 Check the initial circulating pressure once the pump is up to speed If the initial circulating pressure is significantly different from the calculated value, the pump should be stopped, the well shut in and the cause for the discrepancy determined. If the initial circulating pressure is equal to or reasonably close to the calculated value, the displacement should be continued. Any marginal difference is likely to be due to the fact that the actual SCR pressure is different from the value used to calculate the initial circulating pressure. The actual SCR pressure can be established from the initial circulating pressure recorded when the pump is up to speed. 6-32 March 1995 BP WELL CONTROL MANUAL For Case A, the actual SCR pressure can be determined from the initial circulating pressure as follows: P scr = Pic – P dp For Case B, the actual SCR pressure can be determined as follows: P scr = Pic – P dp – P cl – P oc + P a For the Wait and Weight Method the final circulating pressure must be recalculated as follows: For Case A, the final circulating pressure can be determined as follows: Pfc = Pscr X MW2 MW1 For Case B, the final circulating pressure is determined as follows: Pfc = (Pscr X MW2)+ Pcl – P a + Poc MW1 The standpipe pressure should therefore be redrawn to take into account these adjusted figures. 6 Assess the effect of choke line losses at the latter stages of kick displacement For Case A: In the latter stages of the displacement the choke pressure required to maintain constant bottomhole pressure will drop. This drop will be most significant once the original mud behind the influx is at the choke. If the required choke pressure drops below the sum of the choke line loss and the wide open choke pressure, it will no longer be possible to completely compensate for the choke line losses. The resultant increase in wellbore pressure at this stage will be given by: Increase in pressure = Pcl + P oc – P a In practice, the choke will be wide open at this stage and the standpipe pressure will rise above final circulating pressure. When the hole has been circulated to kill weight mud, the circulating pressure will have increased by the sum of the choke line losses and the wide open choke pressure. For Case B: As the influx expands the choke pressure required at surface will increase. As the required choke pressure increases it will be possible to compensate for a greater proportion of the choke line losses. If the required choke pressure increases to a value equal to the sum of the choke line loss and the wide open choke pressure it will be possible to compensate for the complete amount of the choke line losses. It should be noted that the most critical period in terms of downhole pressures is likely to occur at early stages in the displacement. In this respect the change in choke line loss compensation at latter stages in the displacement is unlikely to be a critical factor. 6-33/34 6-33 March 1995 BP WELL CONTROL MANUAL 6.2 SPECIAL TECHNIQUES Subsection Page 2.1 VOLUMETRIC METHOD 6-37 2.2 STRIPPING 6-51 2.3 BULLHEADING 6-71 2.4 SNUBBING 6-79 2.5 BARYTE PLUGS 6-89 2.6 EMERGENCY PROCEDURE 6-97 6-35/36 6-35 March 1995 BP WELL CONTROL MANUAL 6.2 SPECIAL TECHNIQUES Subsection 2.1 VOLUMETRIC METHOD Paragraph Page 1 General 6-38 2 Static Volumetric Method (Drillpipe pressure used to monitor bottomhole pressure) 6-38 Static Volumetric Method (Choke pressure used to monitor bottomhole pressure) 6-40 4 Lubrication 6-46 5 Dynamic Volumetric Control 6-47 3 Illustrations 6.12 Static Volumetric Method – an example of control of bottomhole pressure at the choke 6-42 6.13 Static Volumetric Control – illustrating the consequences of improper procedure 6-43 6.14 Volumetric Control Worksheet – an example for a land rig 6-44 6.15 Static Volumetric Method – choke pressure used to monitor bottomhole pressure 6-45 6.16 Dynamic Volumetric Method – used to remove gas from below a stack 6-49 6-37 March 1995 BP WELL CONTROL MANUAL 1 General The Volumetric Method can be used to control the expansion of an influx that is migrating during shut-in periods. It can therefore only be used if significant migration is occurring. This may occur only in the case of gas kicks. This method can be used during shut-in periods prior to displacement, or as a means of safely venting an influx from a well in which circumstances prevent the implementation of normal well control techniques. Situations in which the Volumetric Method may be applicable therefore include: • During any shut-in period after the well has kicked. • If the pumps are inoperable. • If there is a washout in the drillstring that prevents displacement of the kick. • If the pipe is a considerable distance off bottom, out of the hole or stuck off bottom. • If the bit is plugged. • If the pipe has been dropped. There are four techniques that may be required to deal with an influx that is migrating up the hole. These are as follows: • Static Volumetric Control: When the drillpipe is on or near bottom and can be used to measure bottomhole pressure. • Static Volumetric Control: When the drillpipe cannot be used to measure bottomhole pressure. • Lubrication: When the influx has migrated to the stack this technique is used to replace the influx with mud as the influx is bled at the choke. • Dynamic Volumetric Control: This technique may be used as an alternative to the above but is most applicable as an alternative to lubrication on a floating rig. The following Paragraphs can be used as guidelines for the implementation of the above mentioned procedures. 2 Static Volumetric Method (Drillpipe Pressure used to monitor bottomhole pressure) This procedure is the most simple to implement in that the drillpipe pressure is available to monitor bottomhole pressure. It may be necessary to implement this procedure during any time that the well is shut-in after a kick has been taken. This situation may arise while preparations are being made to kill a well or when operations have to be suspended due to bad weather or equipment failure. 6-38 March 1995 BP WELL CONTROL MANUAL The following guidelines can be used: 1 Record the shut-in drillpipe and choke pressures After the well has been shut-in the surface pressures can be used to identify the influx type. These calculations are covered in Chapter 4. If the influx contains a significant proportion of gas, it will be necessary to allow the influx to expand considerably as it migrates up the hole. 2 Develop annulus pressure profile The annular pressures during migration of the influx will be similar to those resulting from circulation with the Driller’s Method. In this respect, a PC or programmable calculator can be used to develop the annulus pressure profile as for the Driller’s Method. The maximum wellbore pressures can therefore be estimated along with the anticipated pit gain. 3 Determine migration rate After the surface pressures have built up to values which reflect the kick zone pressure, further increases will be due to migration. The rate of migration can be estimated from two pressure readings, recorded either both on the drillpipe or both on the casing, taken at a known time interval apart. The distance D (m), migrated up the annulus of constant cross section in the time interval T (min) is given by: D= P2 – P1 MW X 1.421 where P1 P2 MW T MR = = = = = (m) surface pressure at start of interval (psi) surface pressure after interval T (psi) mud weight in the hole (SG) time interval (min) migration rate (m/hr) The migration rate can therefore be estimated as follows: MR = D X 60 (m/hr) T 4 Allow drillpipe pressure to build by overbalance margin The drillpipe pressure should be allowed to build by a suitable overbalance margin. This margin will be registered on the drillpipe as an increase in pressure over and above the final shut-in pressure. The overbalance margin may typically be in the range 50 to 200 psi. 5 Allow drillpipe pressure to build up by operating margin The drillpipe pressure should be allowed to build by a further margin to ensure that the overbalance is maintained as mud is bled from the well. The operating margin may also typically be in the range 50 – 200 psi depending on the resultant wellbore pressures at each stage in the operation. 6-39 March 1995 BP WELL CONTROL MANUAL 6 Bleed increment of mud from the annulus to reduce drillpipe pressure After the drillpipe pressure has built by the sum of the overbalance margin and the operating margin, the kick zone will be overbalanced by the sum of these two values. Mud should then be bled from the annulus to reduce the drillpipe pressure to a value representing the final shut-in pressure plus the overbalance margin. A manual choke should be used for this operation to ensure adequate control. It is strongly recommended that small volumes of mud are bled off at a time to allow time for the drillpipe pressure to respond. There will be a considerable delay time between choke and drillpipe pressure in a deep well and especially if the influx contains gas. 7 Continue process until influx migrates to the stack This process should be repeated until the influx migrates to the stack. Arrival of the influx at the stack may be preceded by bleeding gas cut mud from the well. However, if gas is observed at the choke, the well should be shut-in and mud lubricated into the well. If gas is bled from the well the bottomhole pressure will drop and eventually cause a further influx. When the influx has migrated to the stack, surface pressures should no longer rise as migration will cease to occur. This may not be the case on a floating rig when some migration may occur up the choke line. Use the Volumetric Control Worksheet to record all the relevant data (See Figure 6.14.) 8 Lubricate mud into the hole or implement the Dynamic Volumetric Method See Paragraphs 4 and 5 as follows. 3 Static Volumetric Method (Choke pressure used to monitor bottomhole pressure) This technique may be required if the drillstring is stuck off bottom, out of the hole or too far off bottom to be stripped back or if the bit is plugged. In these cases, it will not be possible to monitor the bottomhole pressure with the drillpipe during the control process. The choke pressure is therefore used in conjunction with the volume of mud bled from the well to infer the bottomhole pressure. The principle of this procedure is that the bottomhole pressure is maintained slightly over kick zone pressure by bleeding mud from the annulus to allow the influx to expand as it migrates up the hole. Mud is bled in increments from the well as the choke pressure rises due to migration. The amount of mud bled off for each increment is determined from the increase in choke pressure. 6-40 March 1995 BP WELL CONTROL MANUAL For example, if the choke pressure increases by 100 psi, a volume of mud equivalent to a hydrostatic pressure in the annulus of 100 psi is bled at the choke at constant choke pressure. In this manner, control over the bottomhole pressure is achieved. It should be noted that this method is only applicable if the influx is migrating as the mud is bled from the well . The rate of influx migration determines the time required to bleed each increment of mud from the well. Figure 6.12 illustrates this technique. In this example, the following conditions apply: Operating margin = 150 psi Annulus = 8 1/2 in. Mud weight = 1.85 SG X 5 in. Hydrostatic equivalent of mud = 445.7 – 1.85 (72.25 – 25) = 17.5 psi/bbl Therefore bleed 150 = 8.5 bbl of mud 17.5 As can be seen from Figure 6.12, the influx must migrate (1824 – 133 =) 1691m while the 8.5 bbl of mud is bled from the well. It is clear that this operation will take several hours. If the operating margin was quickly bled from the well, the original influx would expand by approximately 0.4 bbl before the bottomhole pressure drops to the original kick zone pressure. If the remaining 8.1 bbl were bled from the well, this would cause a further influx of 8.1 bbl, as shown in Figure 6.13. As the influx migrates further up the hole, the time required to bleed the 8.5 bbl increment from the well will decrease significantly. In this example, the influx must migrate 570m (approximately 2 hours) as the next increment is bled from the well. If the rate of influx migration is maintained, this time will continually reduce until the influx is at surface. Volumetric control is similar to the Driller’s Method although the influx moves up the hole under the influence of migration. The resultant wellbore pressures as well as the required pit gain will be similar for the two techniques. The following guidelines can be used: 1 Record shut-in choke pressure 2 Develop annulus pressure profile 3 Determine migration rate The first three steps are carried out in the same manner as for the previous technique. 4 Calculate hydrostatic pressure of mud per barrel The hydrostatic pressure of the mud per barrel should be calculated at the point in the annulus directly above the influx. It can be calculated as follows: Hydrostatic pressure per barrel = 445.7 X MW (d hc 2 – d o2 ) (psi/barrel) where MW = mud weight in the hole (SG) dhc = hole/casing ID (in.) do = drillstring OD (in.) 6-41 March 1995 BP WELL CONTROL MANUAL Figure 6.12 Static Volumetric Method – an example of control of bottomhole pressure at the choke 1. AT INITIAL SHUT-IN 2. INCREASE IN SURFACE PRESSURE FOR OVERBALANCE MARGIN 850psi Pa 650psi Pa PRESSURE IN BUBBLE 10,000psi HEIGHT OF INFLUX 66m VOLUME OF INFLUX 10bbl VOLUME OF INFLUX 10bbl DEPTH 3615m 76m BHP = Pf = 10,000psi BHP = 10,200psi T=0 T = 15 min (assuming migration rate of 300m/hr) 3. INCREASE IN SURFACE PRESSURE FOR OPERATING MARGIN 4. 8.5bbl BLED OFF WHILST HOLDING CHOKE PRESSURE CONSTANT 1000psi Pa 1000psi Pa PRESSURE IN BUBBLE NOW 5405psi PRESSURE IN BUBBLE 10,000psi VOLUME OF INFLUX 18.5bbl VOLUME OF INFLUX 10bbl KEY 1824m MUD 133m GAS BHP = 10,350psi T = 25 min MUD BLED AT CONSTANT CHOKE PRESSURE BHP = 10,200psi T = 6 hours WEOX02.039 6-42 March 1995 BP WELL CONTROL MANUAL 3a. BLEED MUD FROM WELL INSTANTANEOUSLY 4a. 8.5bbl BLED OFF INSTANTANEOUSLY, WELL SHUT-IN Pa DROPS BELOW 1000psi Pa > 1000psi VOLUME OF INFLUX = 10.4bbl VOLUME OF INFLUX = 10.4bbl VOLUME OF SECONDARY INFLUX = 8.1bbl BHP = 10,000psi T 25 min BHP DROPS BELOW 10,000psi BHP = 10,000psi T 25 min KEY MUD GAS WEOX02.040 Figure 6.13 Static Volumetric Control – illustrating the consequences of improper procedure 5 Allow choke pressure to build by overbalance margin The choke pressure should be allowed to build by an overbalance margin that may typically be in the range 50 – 200 psi. 6 Allow choke pressure to build by operating margin The choke pressure should be allowed to continue building a further similar amount to provide an operating margin. The total margin will depend on the resultant wellbore pressures at each stage in the operation. 7 Bleed increment of mud from the well at constant choke pressure A suitable volume of mud should be bled from the well to reduce the bottomhole pressure by an amount equivalent to the operating margin. 6-43 March 1995 BP WELL CONTROL MANUAL Figure 6.14 Volumetric Control Worksheet – an example for a land rig VOLUMETRIC CONTROL WORKSHEET For worksheet calculation enter information into shaded cells. WELL NO 26 RIG UK Units (US/UK): Rig 10 Version 1/1 1Q'95 by ODL/C. Weddle DATE AND TIME MUD WEIGHT IN THE HOLE, sg 1.85 15:30 LUBRICATING MUD WEIGHT, sg HYDROSTATIC PRESSURE PER BARREL OF 1.85 HYDROSTATIC PRESSURE PER BARREL OF sg MUD in 5 X sg MUD in 8.5 X 20/08/95 SHEET NO ANNULUS: 17.46 psi/bbl ANNULUS: psi/bbl HYDROSTATIC PRESSURE PER BARREL OF sg MUD in HOLE: psi/bbl HYDROSTATIC PRESSURE PER BARREL OF sg MUD in HOLE: psi/bbl P1 psi Distance, (m) 3.743701 OVERBALANCE MARGIN: TIME ( hr 200 psi OPERATION If DP pressure can't be read see page 6-36 of Vol. 1 of BP Well Control Manual min) 19:00 OPERATING MARGIN: Choke or DP Choke Monitor Pressure (psi) Change in Monitor Pressure (psi) 150 Hydrostatic of Mud Bled/ Lubricated (psi) (psi) Volume of Mud Bled/ Lubricated (bbl) Time (min) P2 0 0 100 0 200 0 100 19:25 Influx Migrating 1000 150 0 350 0 100 Bleed Mud at Choke 1000 0 -150 200 8.5 108.5 Influx Migrating 1150 150 0 350 0 108.5 Bleed Mud at Choke 1150 0 -150 200 8.5 117 Influx Migrating 1300 150 0 350 0 117 3:30 / 4:45 4.:55 4:55 / 5:30 Bleed Mud at Choke 1300 0 -150 200 8.5 125.5 Influx Migrating 1450 150 0 350 0 125.5 Bleed Mud at Choke 1450 0 -150 200 8.5 134 + ve increase - ve decrease - ve bled + ve overbalance + ve bled + ve lubricated - ve underbalance - ve lubricated WEOX02.199 6-44 March 1995 11.2311 Total Volume of Mud (bbl) 200 3:30 20 5 Rate, (mpm) 850 1:35 0 Overbalance 2 Influx Migrating 1:35 / 3:15 0 Migration Rate 19:15 19:25 / 01.25 650 1 1.85 BP WELL CONTROL MANUAL The choke pressure must be held constant as the mud is bled from the well. As an example (refer to Figures 6.12 and 6.13): Operating margin = 150 psi Annulus = 8 1/2 in. X 5 in. Mud weight = 1.85 SG Hydrostatic equivalent of mud = Therefore bleed 150 17.5 445.7 – 1.85 = 17.5 psi/bbl (72.25 – 25) = 8.5 bbl of mud As can be seen from the example in Figure 6.12 the bottom of the influx has had to migrate from 133m off bottom, to 1824m off bottom, whilst bleeding off 8.5 bbl of mud. This could take considerable time. If the operating margin, in this case 150 psi (8.5 bbl), had been quickly bled off and assuming no migration during this period, the bubble would have expanded by only about 0.36/bbl before bottomhole pressure (BHP) dropped to kick zone pressure. This would result in a further influx of 8.14 bbl. Subsequent volumes bled from the well will require less migration distance, ie for an␣increase of bubble size to 27 bbl (after next bleed off), the distance from bottom will be 2395m. 2200 GAS MIGRATING TO SURFACE PRESSURE BUILDUP 2050 INFLUX MIGRATING 1900 1750 MUD BLED AT CHOKE (at constant choke pressure until volume bled off corresponds to Operating Margin) CHOKE PRESSURE (psi) 1600 1450 OPERATING MARGIN 1300 1150 OPERATING MARGIN 1000 OPERATING MARGIN 850 OVERBALANCE MARGIN 650 FINAL SHUT-IN ANNULUS PRESSURE 0 8.5 17 25.5 34 42.5 51 59.5 68 76.5 VOLUME OF MUD BLED FROM ANNULUS (bbl) WEOX02.041 Figure 6.15 Static Volumetric Method – choke pressure used to monitor bottomhole pressure 6-45 March 1995 BP WELL CONTROL MANUAL 8 Continue the process until the influx migrates to the stack This process should be repeated until the influx migrates to the stack. When the influx has migrated to the stack surface pressures should no longer rise as migration will cease to occur. This may not be the case on a floating rig when some migration may occur up the choke line. Use the Volumetric Control Worksheet to record all the relevant data. Figure 6.14 shows a completed example. 9 Lubricate mud into the hole or implement the Dynamic Volumetric Method See Paragraphs 4 and 5. If this process has been implemented because the pipe was off bottom, it may be feasible to circulate the influx out of the hole when the influx has migrated to the bit. See Figure 6.15 for a typical choke pressure schedule for the Static Volumetric Method. 4 Lubrication This technique may be used to vent the influx from below the stack while maintaining constant bottomhole pressure. Lubrication is most suited to fixed offshore and land rigs. It can be used to vent gas from the stack after implementing the Static Volumetric Method, as well as to reduce surface pressures prior to an operation such as stripping or bullheading. Lubrication is likely to involve a considerable margin of error when implemented on a floating rig because of the complication of monitoring the bottomhole pressure through the choke line. When the influx has migrated to the stack it is quite possible that the choke line will become full of gas cut mud. In this situation it is impractical to attempt to maintain control of the bottomhole pressure with the choke. However lubrication is simpler to implement than the Dynamic Volumetric Method. For this reason alone, it may be considered for use on a floating rig. The following guidelines can be used to lubricate mud into a well: 1 Calculate the hydrostatic pressure per barrel of the lubricating mud This is done in the same manner as for the Volumetric Method. 2 Slowly lubricate a measured quantity of mud into the hole Line up the pump to the kill line. Having determined the safe upper limit for the surface pressure, the pump should be started slowly on the hole. Mud should be lubricated into the well until pump pressure reaches a predetermined limit. At this point the pump should be stopped and the well shut in. The well should be left static for a period while the gas migrates through the mud that has been lubricated into the well. 6-46 March 1995 BP WELL CONTROL MANUAL The exact amount of mud lubricated into the well should be closely monitored. 3 Bleed gas from the well Gas should be bled from the well to reduce the surface pressure by an amount equivalent to the hydrostatic pressure of the mud lubricated into the well. If the surface pressure increased as the mud was lubricated into the well, the amount that the pressure increased should be bled back in addition. Ensure that no significant quantity of mud is bled from the well during this operation. If mud appears at the choke before the surface pressure has been reduced to its desired level, shut the well in and let the gas percolate through the mud. Returns should be lined up through the mud gas separator to the trip tank to ensure that any volume of mud bled back with the gas is recorded and accounted for. 4 Repeat this procedure until all the influx has been vented from the well This procedure should be repeated until all the gas has been vented from the well. It is likely that it will be necessary to reduce the volume of mud lubricated into the well at each stage during this procedure. This is due to the reduction in volume of gas in the well. If the influx was swabbed into the well and the mud weight is sufficient to balance formation pressures, the choke pressure should eventually reduce to zero. However, if the mud weight in the hole is insufficient, the final choke pressure will reflect the degree of underbalance. It will then be necessary to kill the well. 5 Dynamic Volumetric Control This technique can be used as an alternative to the Static Volumetric Method. However, it should only be used only as a method of safely venting an influx from below a subsea stack, due to both the complexity of the operation and the level of stress imposed on well control equipment during circulation. Experience has shown that the Dynamic Volumetric Method is the most reliable method of venting gas from a subsea stack, if the drillpipe cannot be used to monitor bottomhole pressure. The principle of the procedure is identical to the Static Volumetric Control, however the implementation is considerably different. In this case, circulation is maintained across the wellhead, whilst the surface pressure and pit gain are controlled with the choke. The kill line pressure is used to monitor the well. It is very important that the active tank be a suitable size to resolve very small changes in level. It should be possible to reliably detect changes of the order of one barrel. Having identified that the influx is at the stack, the following guidelines can be used to implement the Dynamic Volumetric Method: 1 Ensure that the kill line is full of mud If there is any possibility that the kill line contains gas, the well should be isolated and the kill line circulated to mud. This will ensure that the pressure at the stack is accurately monitored during the operation. 6-47 March 1995 BP WELL CONTROL MANUAL 2 Circulate down the kill line and up the choke line Ensure that it is possible to monitor the active pit level accurately. Route returns through the mud gas separator. 3 Bring the pump up to speed As the pump is brought up to speed, the kill line (or pump pressure) must increase by an amount equal to the kill line pressure loss. However if it is not possible to compensate for the choke line pressure loss, the kill line pressure will inevitably increase by more than the kill line pressure loss. The kill line circulating pressure will be monitored during the operation to remove gas from the well. 4 Reduce kill line pressure in line with drop in pit level As gas is bled from the well, the pit level will drop while the choke operator adjusts the choke to maintain a constant kill line circulating pressure. This will result in mud being lubricated into the well. If the kill line circulating pressure is held constant as mud is lubricated into the well (as gas is removed), the bottomhole pressure will increase. Therefore, as the pit level decreases, the kill line pressure should be reduced to account for the greater hydrostatic pressure in the annulus. As an example: Drop in pit level = 10 bbl Annulus = 8 1/2 in. X 5 in. Mud weight = 1.85 SG Hydrostatic equivalent of mud = 445.7 X 1.85 (72.25 – 25) = 17.5 psi/bbl Therefore reduce kill line circulating pressure by 17.5 X 10 = 175 psi This procedure should be continued until all the influx has been vented from below the stack. This will be indicated by a constant pit level. If the well has been completely killed by removing gas from the stack, the final circulating kill line pressure will be equal to the sum of the kill line pressure loss, the choke line pressure loss and the wide open choke pressure. If the well is not yet completely killed at this point, the final circulating kill line pressure will be greater than this value. See Figure 6.16 for an example kill line pressure schedule for this technique. 6-48 March 1995 BP WELL CONTROL MANUAL Figure 6.16 Dynamic Volumetric Method – used to remove gas from below a stack KILL LINE PRESSURE (psi) (PIT GAIN TO ALLOW FOR GAS EXPANSION) GAS IS REMOVED FROM THE WELL, MUD IS LUBRICATED IN ORIGINAL KILL LINE PRESSURE ONCE PUMP IS UP TO SPEED SLOPE OF LINE = HYDROSTATIC PRESSURE PER BARREL OF MUD GAIN IN PIT LEVEL ORIGINAL PIT LEVEL ONCE PUMP IS UP TO SPEED DROP IN PIT LEVEL CHANGE IN PIT LEVEL (bbl) WEOX02.042 6-49/50 6-49 March 1995 BP WELL CONTROL MANUAL 6.2 SPECIAL TECHNIQUES Subsection 2.2 STRIPPING Paragraph Page 1 General 6-52 2 Monitoring Well Pressures and Fluid Volumes 6-52 3 Annular Stripping 6-56 4 Annular Stripping Procedure 6-57 5 Ram Combination Stripping 6-59 6 Ram Combination Stripping Procedure 6-61 7 Dynamic Stripping Procedure 6-67 Illustrations 6.17 A Guide to Interpretation of Surface Pressure Changes during Stripping 6-54 6.18 The Effect of the Pipe/BHA Entering the Influx 6-55 6.19 Surge Dampener Fitted to the Closing Line of an Annular BOP 6-57 6.20 Example Stripping Worksheet – showing effect of migration and BHA entering the influx 6-60 6.21 Surface BOP Stack Suitable for Ram Combination Stripping 6-62 6.22 to 6.25 Annular to Ram Stripping 6-63 to 6-66 6.26 Equipment Rig-up for Dynamic Stripping 6-68 6-51 March 1995 BP WELL CONTROL MANUAL 1 General Stripping is a technique that can be used to move the drillstring through the BOP stack when the well is under pressure. Stripping places high levels of stress on the BOPs and the closing unit, and requires a particularly high level of co-ordination within the drillcrew. Company policy is that a contingency plan must be developed regarding stripping procedure for both Company operated rigs and rigs that are under a Company contract. This Section is intended to aid in the drawing up of this contingency plan and as such the following are proposed as the most important considerations: • How to move the tool joint through the BOP. • Wear on BOP elements and the control unit. • The level of redundancy in the BOP and the control system. • Wellbore pressures in relation to the maximum allowable pressure for equipment and the formation. • The monitoring of pressure and fluid volumes. • The organisation and supervision of the drillcrew. • Controlling increases in wellbore pressure due to surge pressure. • The condition of the drillpipe. (Drillpipe rubbers should be removed and any burrs smoothed out.) • The possibility of sticking the pipe. • The control of influx migration. • Manufacturers’ information regarding minimum closing pressures for annular preventers. (This information should be available at the rig site.) • The procedure to be adopted in the event that the surface pressure approaches the maximum allowable as the pipe is stripped into the influx. See Figure 5.2 in Chapter 5 for a decision analysis related to stripping operations. 2 Monitoring Well Pressures and Fluid Volumes During stripping operations, a constant bottomhole pressure is maintained by carefully controlling the surface pressure and the volume of mud bled from or pumped into the well. The equipment required for this operation is described in Chapter 1, ’Instrumentation and Control’. 6-52 March 1995 BP WELL CONTROL MANUAL Accurate monitoring of the well is required for the following reasons: (a) To compensate for the volume of pipe introduced into the hole To avoid over pressuring the well, a volume of mud equal to the volume of pipe and tool joints (the volume of metal plus the capacity) introduced into the well, must be bled off. Where possible, mud should not be bled from the well while the pipe is stripped in. It is recommended that mud is bled from the well during each connection. This ensures that there is a clear indication at surface of the BHA entering the influx. However it is recognised that there may be situations when it is impractical to bleed mud from the well at connections. Such situations include: • If the surface pressures are close to maximum allowable prior to the stripping operation. • If a high pressure water kick is taken. In these circumstances the effective compressibility of the fluid in the hole will be low and as such there may be a very large pressure rise as pipe is stripped into the well. • If the pipe has to be stripped out of the hole. In this case, there will be a tendency for the volume of metal removed from the well to be replaced by influx fluid. In these circumstances it may be necessary to implement the dynamic stripping technique. (b) To compensate for influx migration. To compensate for influx migration, it is necessary to bleed mud from the well. This is in addition to the volume of mud bled from the well when introducing the pipe into the hole. Normally, the required volume of mud will be very small in comparison to the volume bled off to compensate for the introduction of pipe into the hole. Influx migration is indicated by a gradual increase in surface pressure even though the correct volume of mud is being bled from the well (however this may be due to the BHA entering the influx). It is confirmed by increasing surface pressure when the pipe is stationary (See Figure 6.17). Influx migration is controlled by implementing the Volumetric Method. (c) To allow an increase in surface pressure as the BHA enters the influx. When the BHA is run into the influx, the height of the influx will be considerably increased. This can cause a significant decrease in hydrostatic pressure in the annulus, requiring a greater surface pressure to maintain a constant bottomhole pressure (See Figure 6.18). A potential problem arises if this condition is undetected. The choke operator may continue to bleed mud from the well to maintain a constant surface pressure and inadvertantly cause further influx into the wellbore. It is therefore important to accurately monitor the total volume of mud bled from the well. It is recommended that the potential increase in surface pressure resulting from entering the influx should be estimated before stripping into the hole. 6-53 March 1995 BP WELL CONTROL MANUAL Figure 6.17 A Guide to Interpretation of Surface Pressure Changes during Stripping START STRIPPING IN PRESSURE INCREASES AS PIPE IS STRIPPED IN CONTINUE STRIPPING BLEED VOLUME OF MUD EQUAL TO VOLUME OF PIPE STRIPPED SURFACE PRESSURE DROPS TO ORIGINAL VALUE? NO SURFACE PRESSURE DROPS TO VALUE GREATER THAN ORIGINAL YES NO CONTINUE STRIPPING CONTINUE STRIPPING SURFACE PRESSURE INCREASES WHILE PIPE IS STATIONARY? HAS THE CORRECT VOLUME OF MUD BEEN BLED FROM THE WELL? NO YES YES INFLUX IS MIGRATING PIPE HAS ENTERED INFLUX BLEED MUD TO COMPENSATE FOR MIGRATION NO NO IS THE PIPE ON BOTTOM? YES SURFACE PRESSURE LIMIT APPROACHED? YES CIRCULATE OUT TOP OF GAS BUBBLE USING THE DRILLER'S METHOD KILL THE WELL WEOX02.043 6-54 March 1995 BP WELL CONTROL MANUAL Figure 6.18 The Effect of the Pipe/BHA Entering the Influx 1. Start stripping 2. BHA has entered influx • • • KEY GAS INFLUX MUD Height of influx in annulus has increased Overall hydrostatic in annulus decreases Surface pressure required to balance formation pressure increases GAS INFLUX GAS MUD MUD WEOX02.044 6-55 March 1995 BP WELL CONTROL MANUAL 3 Annular Stripping There are two stripping techniques, Annular and Ram combination stripping. The decision analysis presented in Chapter 5, ‘Pipe off Bottom – Drillpipe in the Stack’ outlines the basis upon which the most suitable stripping technique is selected. Annular stripping is considered to be the most satisfactory technique. It involves less risk than ram combination stripping for the following reasons: • Annular stripping is a relatively simple technique. • During annular stripping the only item of well control equipment that is subject to high levels of stress is the annular element. • The control system is not highly stressed during the operation (as is the case during ram combination stripping). • The annular element can be changed out on a surface stack when pipe is in the hole by inserting a split element. • The upper annular preventer, on a floating rig, is the only stack component that is subject to wear and this can be changed without pulling the complete BOP stack. Ram combination stripping is possible on all types of rig but involves significantly more risk when implemented on a floating rig. The surface pressure is the overriding factor which determines whether or not it will be possible to implement annular stripping. However, it is also necessary to consider that the operating life of an annular element is severely reduced by increased wellbore pressure. Field tests* carried out on Hydril and Shaffer 5K Annulars, show good performance at 800 psi wellbore pressure, but at 1500 psi and above the performance was severely reduced and unpredictable. If surface pressures indicate that annular stripping is not possible, attempts should be made to reduce the pressures in order to enable annular stripping to be used. The most appropriate technique will depend on the position of the influx in the hole. The options are; to circulate out the influx, to lubricate the influx from the well or to bullhead. To ensure that the annular is not subjected to excessive pressures as the tool joint is stripped through the element, a surge dampener must be placed in the closing line (See Figure 6.19). This may not be necessary on a surface stack if the pressure regulator can respond fast enough to maintain a constant closing pressure as a tool joint is stripped through the annular. As a word of caution, some drilling contractors have installed check valves in the control lines to the BOPs; the purpose being to ensure that the BOP stays closed if the hydraulic supply is lost. However, if a check valve is installed in the closing line to an annular BOP, it will not be possible to reduce the closing pressure once the annular has been closed. In order to reduce the annular closing pressure, in this case, it will be necessary to open the annular having closed another ram to secure the well. * Tests carried out by Exxon Prod. Research 1977. 6-56 March 1995 BP WELL CONTROL MANUAL OPENING LINE SURGE DAMPENER (precharged to 50% of required closing pressure) CLOSING LINE WEOX02.045 Figure 6.19 Surge Dampener Fitted to the Closing Line of an Annular BOP 4 Annular Stripping Procedure Having shut in the well, the following procedure can be used as a guideline for the implementation of annular stripping. 1 Install drillpipe dart Allow the dart to fall until it seats in the dart sub. To check that the dart is functioning properly, bleed off pressure at the drillpipe (restrict volumes bled off to an absolute minimum, typically 1/2 – 1 bbl). If the dart does not hold pressure allow more time for the dart to drop or consider circulating the dart into place (restrict volumes pumped to a minimum). If the dart still does not hold pressure, install a Gray valve in the string. 6-57 March 1995 BP WELL CONTROL MANUAL 2 Monitor surface pressures Surface pressures should be monitored after the well has been shut-in to check for influx migration. If the influx is migrating it will be necessary to implement volumetric control during the stripping operation. If the pipe is off bottom, it will not be possible to identify the type of influx in the usual manner. However, a high surface pressure caused by a relatively small underbalance usually indicates that the influx contains a significant quantity of gas. 3 Determine the capacity and displacement of the drillpipe It will be necessary to bleed mud from the well to compensate for the volume of pipe introduced into the hole. This volume is equal to the sum of the capacity and the displacement of the pipe. There are various tables which outline these quantities, but a reasonable estimation can be made as follows: Displacement and capacity = do2 X 0.003187 (bbl/m) where do = outer diameter of the pipe (in.) Allowance should also be made for the extra volume of metal in the tool joints. 4 Calculate hydrostatic pressure per barrel of mud Should migration occur, it will be necessary to bleed from the well at constant choke pressure to allow the influx to expand. The hydrostatic pressure equivalent of the mud in the hole is calculated as follows: Hydrostatic pressure equivalent = 445.7 X MW (d hc2 – d o2) (psi/bbl) where MW = mud weight in the hole (SG) dhc = hole/casing ID (in.) do = drillstring OD (in.) or if the pipe is above the influx: Hydrostatic pressure equivalent = 445.7 X MW dhc 2 (psi/bbl) For more details on this technique, See Sub-section 2.1 ‘Volumetric Method’ in this chapter. 5 Estimate increase in surface pressure due to BHA entering the influx It is possible to estimate the maximum possible pressure increase due to the BHA entering the influx as follows: Max possible surface = 445.7 pressure increase where MW Gi V dhc do = = = = = X (MW – G i) V X 1 – (d hc2 – d o2) mud weight in the hole (SG) influx gradient, converted to SG (water = 1 SG) volume of influx (bbl) hole/casing ID (in.) BHA OD (in.) 6-58 March 1995 X 1 dhc 2 (psi) BP WELL CONTROL MANUAL 6 Allow surface pressure to increase by overbalance margin An overbalance of 50 to 200 psi should be maintained throughout the stripping operation. If the influx is not migrating, the overbalance margin can be applied by bleeding a volume of mud that is less than the volume of pipe introduced into the hole, at the start of the operation. 7 Reduce annular closing pressure The BOP manufacturers recommend that the closing pressure is reduced, prior to stripping, until a slight leakage occurs through the BOP. This reduces the wear on the annular by lubricating the element during stripping. 8 Strip in the hole The pipe should be slowly lowered through the annular while the surface pressure is accurately monitored. The running speed should be reduced when a tool joint passes through the annular. Mud should be bled from the well at each connection, unless surface pressure limitations dictate that this should be carried out more frequently. The pipe should be filled with mud at suitable intervals, typically every 5 stands. Use original mud weight. A person should be posted at the Driller’s BOP Control Panel at all times to be ready to shut-in the well in the event of failure of the annular preventer. 9 Monitor surface pressure Surface pressures and all relevant data should be recorded on the Stripping Worksheet. (See Figure 6.20.) Use Figure 6.17 as an aid to the interpretation of changes in surface pressure. 10 Strip to bottom. Kill the well The only sure method of killing the well will be to return the string to bottom and implement standard well kill techniques. 5 Ram Combination Stripping There are two types of ram combination stripping; annular to ram, and ram to ram. Both techniques must be considered if either the tool joint cannot be lowered through the annular or the surface pressure is greater than the rated pressure of the annular and this pressure cannot be reduced to within safe limits. Annular to ram stripping is preferable to ram to ram, unless surface pressures indicate that the annular cannot operate reliably. For both ram combination techniques there is a requirement that: • There is sufficient space for the tool joint between the two stripping BOPs. 6-59 March 1995 BP WELL CONTROL MANUAL Figure 6.20 Example Stripping Worksheet – showing effect of migration and BHA entering the influx STRIPPING WORKSHEET Units (US/UK) For worksheet calculation enter information in shaded cells. WELL NO 3 RIG MUD WEIGHT IN HOLE INITIAL BIT DEPTH Rig 10 uk Version 1/1 1Q'95 by ODL/C. Weddle DATE AND TIME 1.75 10/7/87 10:30 LUBRICATING MUD WEIGHT 2000 HOLE DEPTH SHEET NO 1 1.75 2250 STRIPPING DATA VOLUME OF MUD DISPLACED BY OVERBALANCE MARGIN 5 120 Inch Pipe Drillpipe psi 0.0797 bbl/m : OPERATING MARGIN 150 psi 2.15 bbl/stand (Max) VOLUMETRIC CONTROL DATA HYDROSTATIC PRESSURE PER BARREL OF SG MUD IN 5 x 8.5 ANNULUS 16.52 psi/bbl HYDROSTATIC PRESSURE PER BARREL OF 1.75 SG MUD IN 6.5 x 8.5 ANNULUS 26.01 psi/bbl HYDROSTATIC PRESSURE PER BARREL OF 1.75 SG MUD IN 8.5 HOLE HYDROSTATIC PRESSURE PER BARREL OF TIME OPERATION 1.75 1.75 SG MUD IN Choke or Dp Change in Choke Monitor Monitor Pressure 10.80 8.75 HOLE Bit 10.80 Pipe Stripped Depth psi/bbl psi/bbl Hydrostatic of Mud Bled/ Overbalance Lubricated Volume of Total Mud Bled/ Volume Lubricated of Mud Pressure ( hr 10:05 min) (psi) Well Shut In-Pressures (psi) 550 ( ) ( ) bbl 2000 (psi) (psi) (bbl) (bbl) N/A Stabilized 10:20 Drillpipe Dart Installed 10:30 Strip in Stand No 1 770 120 2000 2027 27 2.2 N/A 120 0 0.0 10:36 Strip in Stand No 2 890 120 2054 54 4.4 N/A 240 0 0.0 10:40 Bleed Mud at Connection 770 -120 2054 54 4.4 N/A 120 2.2 2.2 10:45 Strip in Stand No 3 890 120 2081 81 6.6 N/A 240 0 2.2 10:48 Bleed Mud at Connection 770 -120 2081 81 6.6 N/A 120 2.2 4.4 10:53 Strip in Stand No 4 890 120 2108 108 8.8 N/A 240 0 4.4 10:57 Bleed Mud at Connection 770 -120 2108 108 8.8 N/A 120 2.2 6.6 11:00 Strip in Stand No 5 950 180 2135 135 11.0 N/A 240 0 6.6 8.8 (Assume BHA has entered flux) 11:05 Bleed Mud at Connection 830 -120 2135 135 11.0 N/A 120 2.2 11:10 Strip in Stand No6 1080 250 2162 162 13.2 N/A 240 0 8.8 11:15 Bleed Mud at Connection 960 -120 2162 162 13.2 N/A 120 2.2 11.0 11:20 Strip in Stand No 7 1330 250 2189 189 15.4 N/A 240 0 11.0 11:25 Bleed Mud at Connection 1210 -120 2189 189 15.4 N/A 120 2.2 13.2 11:28 Strip in Stand No 8 1460 250 2216 216 17.6 N/A 240 0 13.2 11:33 Bleed Mud at Connection 1340 -120 2216 216 17.6 N/A 120 2.2 15.4 11:40 Strip in Stand No 9 1590 250 2243 243 19.8 N/A 240 0 15.4 11:45 Bleed Mud at Connection 1470 -120 2243 243 19.8 N/A 120 2.2 17.6 +ve increase M -ve decrease - ve bled +ve +ve lubricated overbalance M + ve bled -ve lubricated NA if bled to - ve compensate for pipe underbalance WEOX02.197 6-60 March 1995 BP WELL CONTROL MANUAL • There is an inlet at the stack between the two BOPs used for stripping. • There is a suitable level of redundancy in the stack to ensure the lowest BOP is not used during the stripping operation. API RP 53 (issued 1984) states: “The lowermost ram should not be employed in the stripping operation. This ram should be reserved as a means of shutting in the well if other stack components of the blowout preventer fail. It should not be subjected to the wear and stress of the stripping operation.” In a critical situation, it may be possible to modify a surface stack to suit these conditions after a kick has been taken. An example surface stack that is suitable for ram combination stripping is shown in Figure 6.21. The risks involved in ram combination stripping can be assessed by considering the following points: • The high level of drillcrew co-ordination required. • The level of stress placed on the BOP elements. • The level of stress placed on the BOP control system. (During ram combination stripping, the accumulators are charged to maximum operating pressure and isolated from the BOP. The pumps are used for operational functions.) • The possibility of replacing the worn BOP elements during operation. • On a floating rig, the reduction in level of redundancy within the subsea BOP stack as the ram preventer is used. 6 Ram Combination Stripping Procedure The following procedure can be used as a guideline for the implementation of annular to ram stripping. The procedure for ram to ram stripping will be similar. (For details of Steps 1 to 6 See ‘Annular Stripping Procedure’) 1 Install drillpipe dart 2 Monitor surface pressures 3 Determine the capacity and displacement of the drillpipe 4 Calculate hydrostatic pressure per barrel of the mud 5 Estimate the increase in surface pressure due to the BHA entering the influx 6 Check ram spaceout To confirm the distance BRT of the two preventers that will be used for stripping. 6-61 March 1995 BP WELL CONTROL MANUAL Figure 6.21 Surface BOP Stack Suitable for Ram Combination Stripping ANNULAR BLIND RAM FLANGED ACCESS POINT TO STACK FOR USE DURING RAM COMBINATION STRIPPING PIPE RAM PIPE RAM WELLHEAD ACCESS POINT WEOX02.046 6-62 March 1995 BP WELL CONTROL MANUAL Figure 6.22 Annular to Ram Stripping – stop stripping in when tool joint is above the annular MUD VALVE OPEN ANNULAR VALVE CLOSED BLIND RAM TO PUMP CHOKE PIPE RAM PIPE RAM WEOX02.047 6-63 March 1995 BP WELL CONTROL MANUAL Figure 6.23 Annular to Ram Stripping – close pipe ram – bleed ram cavity pressure MUD VALVE OPEN ANNULAR VALVE CLOSED BLIND RAM PRESSURE BLED OFF AT CHOKE PIPE RAM PIPE RAM WEOX02.048 6-64 March 1995 BP WELL CONTROL MANUAL Figure 6.24 Annular to Ram Stripping – strip in until tool joint is just below annular MUD ANNULAR VALVE OPEN VALVE CLOSED BLIND RAM PIPE RAM PIPE RAM WEOX02.049 6-65 March 1995 BP WELL CONTROL MANUAL Figure 6.25 Annular to Ram Stripping – use rig pump or cement pump to equalize across pipe ram MUD VALVE OPEN ANNULAR VALVE CLOSED BLIND RAM FROM PUMP PIPE RAM PIPE RAM WEOX02.050 6-66 March 1995 BP WELL CONTROL MANUAL 7 Isolate the accumulator bottles at full operating pressure The accumulators should be kept as back-up in the event of pump failure. 8 Allow the surface pressure to increase by the overbalance margin 9 Reduce annular closing pressure and strip in 10 Stop when tool joint is above annular (See Figure 6.22.) 11 Close pipe ram at normal regulated manifold pressure 12 Bleed ram cavity pressure Before the annular is opened it will be necessary to bleed down the pressure below it. (See Figure 6.23). 13 Reduce ram operating pressure 14 Open annular. Lower pipe 15 Stop when tool joint is just below annular (See Figure 6.24.) 16 Close annular at maximum operating pressure 17 Pressurise ram cavity to equalise across ram (See Figure 6.25.) Do not use wellbore pressure to equalise across the ram. 18 Reduce annular closing pressure 19 Open pipe ram 20 Continue to strip in according to the above procedure. Kill the well Fill the pipe as required. 7 Dynamic Stripping Procedure The situations in which it may be necessary to implement Dynamic Stripping are outlined in Paragraph 2. The purpose of this technique is to maintain constant choke pressure as the pipe is stripped into the hole. This is achieved by circulating at a constant rate across the end of the choke line. A manual choke should be used and the equipment rigged up as shown in Figure 6.26. For this technique to be effective the pump output must be considerably greater than the rate at which the volume of pipe is introduced into the well. If the pump rate is too low, pressure surges will be caused at the choke as the pipe is stripped in, and the choke pressure will fluctuate. The same is true for stripping out of the hole, in which case the choke pressure may drop as pipe is stripped from the well, if the pump rate is too low. This may cause further influx to occur. 6-67 March 1995 BP WELL CONTROL MANUAL Figure 6.26 Equipment Rig-up for Dynamic Stripping MUD VALVE OPEN ANNULAR VALVE CLOSED BLIND RAM PIPE RAM MONITOR PRESSURE GAUGE MANUAL CHOKE PIPE RAM MUD TANK PUMP WEOX02.051 6-68 March 1995 BP WELL CONTROL MANUAL The main problem associated with this technique is that migration and entrance into the gas bubble may not easily be detected at surface. If no allowance is made for these complications, further influx may be allowed to occur. To avoid this, the mud tank levels should be closely monitored to ensure that the levels rise, or drop, in direct relation to the volume of pipe that has been stripped into, or out of, the well. If any discrepancy is noticed, the well should be shut-in and the surface pressures verified. Influx migration should be dealt with using the Volumetric Method. The Dynamic Stripping technique can be used during either annular or ram combination stripping. For annular stripping it is implemented along the following lines: (For details of Steps 1 to 6, See Paragraph 4 ‘Annular Stripping Procedure’) 1 Install drillpipe dart 2 Monitor surface pressures 3 Determine the capacity and displacement of the drillpipe 4 Calculate hydrostatic pressure per barrel of the mud 5 Estimate the increase in surface pressure due to the BHA entering the influx 6 Allow the surface pressure to increase by the overbalance margin 7 Line up the pump to the choke line (See Figure 6.26.) 8 Ensure that the manual choke is fully closed. Open choke line valve(s) 9 Open the manual choke at the same time as the pump is brought up to speed 10 Maintain final shut-in pressure on the choke 11 Reduce annular closing pressure 12 Strip in the hole 13 Monitor surface pressures and pit level If the choke pressure increases significantly as the pipe is stripped into the hole, either reduce the pipe running speed or increase the circulation rate. Use the Stripping Worksheet to record all the relevant data. It is very important to accurately record pressures and mud volumes while stripping. 14 Strip to bottom. Kill the well Fill the pipe as required. 1-69/70 6-69 March 1995 BP WELL CONTROL MANUAL 6.2 SPECIAL TECHNIQUES Subsection 2.3 BULLHEADING Paragraph Page 1 General 6-72 2 When to Bullhead 6-72 3 The Important Factors 6-72 4 Procedure 6-73 Illustrations 6.27 Well Shut-in after Production – tubing full of gas prior to bullheading 6-74 6.28 Example Guide to Surface Pressures during a Bullheading Operation 6-75 6.29 Well during Bullheading Operations 6-76 6.30 Well after Bullheading Operations tubing displaced to kill weight brine 6-77 6-71 March 1995 BP WELL CONTROL MANUAL 1 General Bullheading is a technique that may be used in certain circumstances during drilling operations to pump an influx back into the formation. This technique may or may not result in fracturing the formation. Bullheading is however a relatively common method of killing a well during workover operations. This technique is generally used only during workover operations when there is adequate reservoir permeability. 2 When to Bullhead During operations, bullheading may be considered in the following situations: • When a very large influx has been taken. • When displacement of the influx by conventional methods may cause excessive surface pressures. • When displacement of the influx by conventional methods would result in an excessive volume of gas at surface conditions. • If the influx in suspected to contain an unacceptable level of H2 S. • When a kick is taken with the pipe off bottom and it is not considered feasible to strip back to bottom. • When an influx is taken with no pipe in the hole. • To reduce surface pressures prior to implementing further well control operations. 3 The Important Factors Bullheading during drilling operations will be implemented when standard well control techniques are considered inappropriate. During such situations, it is unlikely that accurate information is available regarding the feasibility of bullheading. In most cases therefore, the likelihood of successfully bullheading an influx will not be known until it is attempted. However, the major factors that will determine the feasibility of bullheading include the following: • The characteristics of the openhole. • The rated pressure of the well control equipment and the casing (making allowance for wear and deterioration). • The type of influx and the relative permeability of the formation. • The quality of the filter cake at the permeable formation. • The consequences of fracturing a section of the openhole. • The position of the influx in the hole. 6-72 March 1995 BP WELL CONTROL MANUAL 4 Procedure In general bullheading procedures can only be drawn up bearing in mind the particular circumstances at the rigsite. For example there may be situations in which it is considered necessary to cause a fracture downhole to bullhead away an influx containing H2S. In another situation with shallow casing set, it may be considered totally unacceptable to cause a fracture in the openhole. During a workover operation a procedure for bullheading will be drawn up along the following lines: 1 Calculate surface pressures that will cause formation fracture during bullheading Calculate also the tubing burst pressures as well as casing burst (to cover the possibility of tubing failure during the operation). 2 Calculate static tubing head pressure during bullheading 3 Slowly pump kill fluid down the tubing. Monitor pump and casing pressure during the operation As an example consider the following well (See Figure 6.27). Well information: • Depth of formation/perforations at 3100 m Formation pressure Formation fracture pressure Tubing 4 1/2 in. N80 Vam Internal capacity Internal yield Shut-in tubing pressure Gas density = = = = = = 1.06 SG 1.66 SG 0.0499 bbl/m 8430 psi 3650 psi 0.1 psi/ft Total internal volume of tubing = 3100 X 0.0499 (bbl) = 155 bbl • Maximum allowable pressure at pump start up = (1.66 X 3100 X 1.421) – (0.1 X 3.2808 X 3100) (psi) = 6300 psi • Maximum allowable pressure when the tubing has been displaced to brine at 1.06 SG = (1.66 – 1.06) X 3100 X 1.421 (psi) = 2640 psi 6-73 March 1995 BP WELL CONTROL MANUAL Figure 6.27 Well Shut-in after Production – tubing full of gas prior to bullheading 3650 psi 4 1/2in N80 TUBING PACKER PERFORATIONS @ 3100m – 1.06SG FORMATION PRESSURE FORMATION FRACTURE GRADIENT – – 1.66SG KEY BRINE VALVE OPEN GAS VALVE CLOSED WEOX02.052 6-74 March 1995 BP WELL CONTROL MANUAL • Static tubing head pressure at initial shut-in. = 3650 psi • Static tubing head pressure when tubing has been displaced to brine = 0 psi (ie the tubing should be killed) The above values can be represented graphically (as shown in Figure 6.28). This plot can be used as a guide during the bullheading operation. Figures 6.29 and 6.30 show a schematic of the well at two stages of the operation. 10000 10000 TUBING BURST 9000 9000 SURFACE PRESSURE (psi) 8430 8000 8000 WORKING PRESSURE RANGE DURING BULLHEADING OPERATION 7000 7000 STATIC TUBING PRESSURE THAT WOULD FRACTURE FORMATION 6300 5800 6000 INCLUDING 500psi SAFETY FACTOR (if fracturing is a consideration) 5000 5000 4000 4000 3650 3000 2640 2000 2140 1000 1000 STATIC TUBING PRESSURE TO BALANCE FORMATION PRESSURE 0 0 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 155 VOLUME OF TUBING DISPLACED (bbl) WEOX02.053 Figure 6.28 Example Guide to Surface Pressures during a Bullheading Operation 6-75 March 1995 BP WELL CONTROL MANUAL Figure 6.29 Well during Bullheading Operations 4000psi 60bbl OF THE TUBING DISPLACED (FROM FIG 6.28, TUBING PRESSURE WITHIN ACCEPTABLE LIMITS) BULLHEAD BRINE 4 1/2in N80 TUBING PACKER PERFORATIONS KEY BRINE VALVE OPEN GAS VALVE CLOSED WEOX02.054 6-76 March 1995 BP WELL CONTROL MANUAL Figure 6.30 Well after Bullheading Operations – tubing displaced to kill weight brine 0psi 4 1/2in N80 TUBING PACKER GAS TRAPPED UNDER PACKER PERFORATIONS KEY BRINE VALVE OPEN GAS VALVE CLOSED WEOX02.055 1-77/78 6-77 March 1995 BP WELL CONTROL MANUAL 6.2 SPECIAL TECHNIQUES Subsection 2.4 SNUBBING Paragraph Page 1 General 6-80 2 Snubbing Units 6-80 3 Selection of a Snubbing Unit 6-82 Illustrations 6.31 Rig Assisted Snubbing Unit 6-81 6.32 Concentric Cylinder Snubbing Unit 6-83 6.33 Multicylinder Snubbing Unit 6-84 6.34 Force Diagram for Snubbing Pipe 6-85 6-79 March 1995 BP WELL CONTROL MANUAL 1 General Snubbing is a technique used to force pipe into a shut-in well when the upthrust due to well pressure makes it impossible to strip the pipe through the BOP under its own weight. Snubbing is relatively common in some areas in workover operations, when the well may be allowed to continue flowing as remedial work is carried out. Snubbing may be considered during drilling operations for well control purposes, either when it is impossible to introduce pipe into a well that is under pressure, or if the rig BOP system is not considered adequate to provide reliable pressure containment during a prolonged stripping operation. A snubbing unit can be used to introduce a range of sizes of pipe into the well. It can be used to snub tubing, drillpipe and even casing in exceptional circumstances. The lowermost components of the snubbing unit are the snubbing BOPs, which are made up to the top flange of the annular preventer on the rig’s stack. This flange is often poorly maintained because it is normally made up to the bell nipple and does not generally need to form a pressure seal. It must therefore be inspected and, if necessary, repaired before the snubbing BOPs are nippled up. The snubbing BOPs are likely to be too tall to fit underneath the rotary table and too wide to go through it. To overcome this problem, the snubbing company can provide suitable spacer riser sections to bring the assembly above the rig floor. The weight of the snubbing unit is supported by the wellhead. Guy lines from the work platform prevent lateral movement. Snubbing units can therefore be rigged up on land rigs and fixed offshore installations in a relatively straightforward manner. Snubbing units are not commonly used on floating rigs, however they have been used successfully in the past for well control operations. In order to use a snubbing unit on a floating rig, pressure containment must be established between the rig BOP and the unit on the rig floor. Drillpipe or tubing may provide this pressure containment, in which case small diameter tubing may be run into the well through the drillpipe or tubing. An operation of this type can only be carried out in relatively calm seas so that the rig heave does not cause excessive movement of the snubbing unit. 2 Snubbing Units (a) The Rig Assisted Type The rig assisted unit uses the travelling blocks to generate the snubbing force through a series of pulleys and cables. (See Figure 6.31.) The rig assisted unit can handle larger diameter pipes such as casing up to 13 3/8 in. and have snubbing capacities of 80,000 lb to 400,000 lb. These were the first snubbing units used and the few that are currently available are operated by Otis and Cudd Pressure Control. 6-80 March 1995 BP WELL CONTROL MANUAL Figure 6.31 Rig Assisted Snubbing Unit TRAVELLING BLOCK BALANCE WEIGHT TRAVELLING SNUBBERS SNUB LINE STATIONARY SNUBBERS PLATFORM STRIPPING OR SNUBBING PREVENTERS PUMP INLET SAFETY PREVENTERS WELL PRESSURE WEOX02.056 6-81 March 1995 BP WELL CONTROL MANUAL The unit consists of a set of travelling snubbers which are connected to the travelling block. The travelling snubbers grip the pipe and force it into the well as the blocks are raised. A set of stationary snubbers grip the pipe while the travelling snubbers are being raised (by the counter balance weights) for a new bite on the pipe. Once sufficient pipe has been run to reach the balance point, the travelling snubbers will be removed and the pipe will be run in by conventional stripping. (b) The Hydraulic Self Contained Type Hydraulic snubbing units are the most common type available. They are completely self contained and can be used either inside the derrick or when there is no rig on location. There are two different types of hydraulic unit available, these being: • The concentric cylinder unit (See Figure 6.32) for snubbing capacities up to 30,000 lb and for pipe up to 5 1/2 in. OD. • The multicylinder type (See Figure 6.33) for snubbing capacity up to 150,000 lb and for pipe up to 7 5/8 in. OD. The units are operated from the work platform which is on top of the hydraulic jack assembly. From this position the speed of the pipe and the slips are controlled as can be the rotary table, if required. Stationary and travelling slips are operated in sequence to grip the pipe as it is snubbed into the well. One operator will control the BOPs and equalising valves. Another operator will co-ordinate the pipe handling, using the counter balance system. 3 Selection of a Snubbing Unit The following are the criteria that should be used to determine the most suitable unit for a given application: • Snubbing Force This is the force that the unit must exert to push the pipe into the hole. The snubbing force will be a maximum for the first joint of pipe and decrease gradually as the weight of the pipe in the hole increases in normal conditions. 6-82 March 1995 BP WELL CONTROL MANUAL Figure 6.32 Concentric Cylinder Snubbing Unit WORKBASKET WITH CONTROLS TRAVELLING SLIPS (CLOSED) TRAVELLING SLIPS (OPEN) PISTON STATIONARY SLIPS (CLOSED) STATIONARY SLIPS (OPEN) ACCESS WINDOW STATIONARY SLIPS (OPEN) SNUBBING UNIT BLOWOUT PREVENTER STACK KEY HYDRAULIC CONTROL FLUID WELL PRESSURE PISTON EXTENDED AND TRAVELLING SLIPS CLOSED PRIOR TO FORCING PIPE INTO WELL PISTON RETRACTED AND TRAVELLING SLIPS OPEN BEFORE PISTON IS AGAIN EXTENDED WEOX02.057 6-83 March 1995 BP WELL CONTROL MANUAL Figure 6.33 Multicylinder Snubbing Unit POWER TONGS BOP CONTROL PANEL CONTROL PANEL COUNTERBALANCE WINCH WORK PLATFORM TRAVELLING SLIPS FOUR OPERATING CYLINDERS TELESCOPING MAST STATIONARY SLIPS WINDOW – for stripper bowl or annular BOP SPOOL HANGER FLANGE PUMP INLET SNUBBING UNIT BLOWOUT PREVENTER STACK WEOX02.058 6-84 March 1995 BP WELL CONTROL MANUAL The snubbing force is calculated as follows: – Snubbing force, Fs = F p + Ff – (w a – Ly X 3.281) – (wb X L z X 3.281) where Fp = Pw – Ao (See Figure 6.34) where F s Fp Ff wa wb Ly Lz Ao = = = = = = = = required snubbing force (lb) force due to well pressure (lb) frictional force (lb) weight of pipe (lb/ft) buoyant weight of pipe (lb/ft) length of pipe above BOP to the travelling snubber (m) length of pipe in the hole (m) outside cross sectional area of pipe (in.2) COMPRESSION FORCE Fs POINT OF APPLICATION OF TRAVELLING SNUBBERS Fs wa Ly Ff PIPE (SNUBBING UNIT STROKE) SNUBBING BOP Ff (wa)(Ly) wb Pw Lz WELLBORE Fp Fp (wb)(Lz) Equilibrium Equation (from ∑ Forces = 0) Therefore: Fs = Fp + Ff – (wa) (Ly) – (wb) (Lz) Where Fs Fp Ff wa wb Ly Lz = required snubbing force (lb) = force due to well pressure (lb) = frictional force (lb) = weight of pipe (lb ft) = bouyant weight of pipe (lb ft) = length of pipe above BOP to the travelling snubber (m) = length of pipe in the hole (m) WEOX02.059 Figure 6.34 Force Diagram for Snubbing Pipe 6-85 March 1995 BP WELL CONTROL MANUAL – Snubbing force for the first joint of pipe. In this case, the length of pipe in the hole (Lz) is zero, and the length of pipe above the BOP is considered insignificant. Consider the following example: The well is shut in with a wellhead pressure of 5000 psi. 2 7/8 in. tubing produces a frictional force of 3000 lb at the stripping rams. The area of pipe exposed to the wellbore pressure therefore equals 6.492 in. Snubbing force, F s = Fp + F f = (6.492 X 5000) + 3000 (lb) = 35,460 lb – The snubbing force, Fs, if there is already some pipe in the hole. In this case the length of the pipe above the BOP is again considered insignificant. As an example: 2 7/8 in. tubing of 6.5 lb/ft is run empty to 1000 metres in 1.2 SG mud. The wellhead pressure is 5000 psi. Drag in the hole is 2000 lb, friction at the BOPs is 5000 lb. Ai Ao wi wo wa wb D = = = = = = = internal cross sectional area area of pipe (in.2 ) outside cross sectional area area of pipe (in.2 ) weight of fluid inside the pipe (SG) weight of fluid in annulus (SG) weight of pipe in air (lb/ft) buoyant weight of pipe (lb/ft) depth of tubing (m) wb = wa + (w i X Ai) – (wo X Ao) wb = 6.5 + (O X Ai) – (1.2 X 62.4 X 6.492) 144 (lb/ft) wb = 3.12 lb/ft Therefore the snubbing force is given by: Fs = Fp + Ff – (wa X Ly) – (w b X L z) Fs = (6.492 X 5000) + 2000 + 5000 – (3.12 X 1000 X 3.281) (lb) = 29,200 lb • Size of the Unit The dimensions of the unit must be checked against the internal dimensions of the derrick, if the unit is to be used with a rig on location. • Lifting Force The unit must be able to provide a reasonable overpull, over and above the weight of the maximum string weight. 6-86 March 1995 BP WELL CONTROL MANUAL • Tubular Selection If there is already pipe in the hole, this will determine the most suitable type of pipe to be used. Drillpipe can be used, however the following points should be considered: – Drillpipe will require a relatively high snubbing force because of its large crosssectional area at the tool joints. – Drillpipe does not have gas-tight connections. – The drillpipe must be in good condition and inspected thoroughly before running in. Tubing is more commonly used for snubbing for the following reasons: – The force required to snub it in is very much less, and the unit required corresponding smaller. – External flush tubing can be run through the stripper rubbers without the need for sequencing the rams. The following points must also be considered: – The limitations imposed by the ID of the tubing on the maximum pump rate. – External upset tubing will be slower to run, but will be easier to control, if it starts to be forced out of the well. – Premium connections are desirable because they are gas tight. – The collapse strength of the tubing. – The susceptibility of the tubing to failure due to buckling. 6-87 1-87/88 March 1995 BP WELL CONTROL MANUAL 6.2 SPECIAL TECHNIQUES Subsection 2.5 BARYTE PLUGS Paragraph Page 1 Characteristics of Baryte Plugs 6-90 2 Deflocculation 6-92 3 Pilot Tests 6-92 4 Slurry Volume 6-92 5 Pumping and Displacement Rate 6-93 6 Preparation of a Baryte Plug 6-93 7 After Pumping a Baryte Plug 6-93 8 Baryte Plug Procedure 6-94 Illustrations 6.35 Field Mixing of Baryte Plugs 6-91 6-89 March 1995 BP WELL CONTROL MANUAL 1 Characteristics of Baryte Plugs (a) Hydrostatic Kill Since baryte settling is inherently slow and since the results of settling are quite unpredictable, the use of a settling recipe should not be a dominant factor in designing a well control operation. In general, the goal in using a baryte kill slurry should be the same as with any other kill weight mud – achieving a hydrostatic kill. Three factors contribute to achieving a hydrostatic kill: the density of the fluid, the volume of the fluid, and the rate at which the fluid is pumped. The density and volume of the kill weight mud must be high enough to control the formation, and the pump rate during the kill must exceed the influx rate by sufficient margin so that the kill weight mud is not blown out of the wellbore. The properties of the fluid pumped should be chosen with these three factors in mind. The ideal kill weight mud would be inexpensive and simple to mix and handle over a wide range of densities. Deflocculated baryte slurries fit this description except that the settling of the baryte can be a problem in surface handling and pumping. (b) Bridging effect It has been suggested that a baryte plug can stop unwanted flow by a bridging effect and that achieving a hydrostatic kill is not necessary. Some field experiences support this view; there are cases where a well has stopped flowing after being treated with a small baryte plug. Nonetheless, it is imprudent to rely on baryte bridging when attempting to kill a well. Laboratory tests show clearly that even very low gas volumes (0.01 Mcf/d at bottomhole conditions) can flow through a settling baryte plug. This fact, as well as field experience, shows that the bridging action of a baryte plug is not dependable. For this reason, the design of a baryte plug should be based on achieving a hydrostatic kill. The strength of the settled baryte is another significant factor in well control. Laboratory tests show that the strength of a settled baryte plug is quite variable. Settled baryte can appear rock-solid when pushed hard and yet move slowly out of the way of a persistent gently force. This behaviour is actually a well understood property of deflocculated cakes. A baryte plug can fail unexpectedly if a hydrostatic kill condition is not maintained. (c) Settling/Non-settling Since baryte settling is of little value downhole and troublesome on the surface, it should be an optional feature of the slurry recipe. Figure 6.35 shows two recipes for baryte slurries. The recipes are identical except that one contains XC polymer to eliminate baryte settling. It would seem reasonable to use the settling recipe for small jobs or where the settling baryte might really be helpful downhole. For large kill operations, the non-settling recipe would be preferred. Bentonite or some polymer other than XC could be used to suspend the baryte in a slurry. The particular recipe in Figure 6.35 was selected because it is prepared easily in both fresh and seawater and because XC solutions are shear-thinning enough to allow good pumpability while adequately suspending the baryte in the pits. 6-90 March 1995 BP WELL CONTROL MANUAL Figure 6.35 Field Mixing of Baryte Plugs (a) For use with water based muds 1. Prepare mix water equal to 54 percent of final volume of slurry required. Recipes below are for one barrel of mix water: • Setting recipe 1 bbl water (fresh or sea) 15 lb lignosulphonate 2 lb/bbl of caustic (pH = 10.5 to 11.5) • Non-setting recipe 1 bbl water (fresh or sea) 15 lb lignosulphonate 1 lb XC polymer Defoamer (octanol or other) 2 lb/bbl of caustic (pH = 10.5 to 11.5) 2. Add baryte to mix water to prepare final slurry. For 1 bbl of 2.5 SG slurry, mix 0.54 bbl mix water 700 lb baryte (b) For use with oil based muds 1. Prepare mix oil equal to 47 percent of final volume of slurry required. Recipes below are for one barrel of mix oil: • Setting recipe 1 bbl base oil 1.5 US gal oil wetting agent • Non-setting recipe 1 bbl base oil 4 lb organophilic clay 1.5 US gal oil wetting agent 2. Add baryte to mix oil to prepare final slurry. For 1 bbl of 2.5 SG slurry, mix 0.54 bbl mix water 700 lb baryte 6-91 March 1995 BP WELL CONTROL MANUAL Baryte-plug-type slurries can be prepared with all of the baryte substitutes which are now on the market. In general the recipes in Figure 6.35 do not require change except that, in some cases, the higher density of the substitue allows higher slurry weights than were possible with baryte. For example, hematite slurries can be prepared to 3.00 SG using the non-settling recipe in Figure 6.35. Replace the baryte with 870 lb hematite per final bbl of slurry. The non-settling recipe is strongly recommended for hematite slurries because of the relatively coarse grind of oil-field hematite. 2 Deflocculation For years it has been standard practice to add a thinner to baryte slurries used for well control. Both lignosulphonates and phosphates have been used, with the phosphate SAPP having the widest acceptance. Chemicals of either type can deflocculate a baryte slurry to improve pumpability and allow settling into a firm cake. The choice of deflocculant will influence the baryte slurry properties as follows: • Use of SAPP gives a slurry with fairly high fluid loss (50cc). SAPP will not deflocculate in sea water or in the presence of some contaminants which occur in natural baryte. • Use of lignosulphonate gives a slurry with low fluid loss (5cc). Lignosulphonate is effective in sea water and tolerates both contamination and elevated temperatures. Use of a high fluid loss baryte slurry is advantageous, possibly because it might dehydrate and plug the wellbore, or promote, perhaps, hole instability. On the other hand, a low fluid loss slurry would reduce the chances of differential sticking. Faced with this choice, prudence suggests using the more reliable lignosulphonate rather than the somewhat unpredictable SAPP. The recipes in Figure 6.35 contain lignosulphonate. 3 Pilot Tests Because of variation and possible contamination of ingredients throughout the world, it is always advisable to pilot test a baryte slurry. Prepare a sample of the slurry using the recipe chosen and the ingredients at the wellsite. After being stirred well, the sample should have the expected density and be easily pumpable. If the baryte needs to settle in the wellbore, this should also be checked ahead of time. Reasonable settling is 2 in. in a mud cup after a 15 minute wait. The settled cake should be hard and somewhat sticky rather than soft and slippery. The settling test is not a guarantee that the baryte pill will form an effective plug under downhole conditions, but will certainly give an indication of the settling characteristics. 4 Slurry Volume Slurry volumes depend upon the amount of openhole and the severity of the kick. These volumes normally range from 40 bbl to 400 bbl. The slurry volume should be 125 to 150 percent of the annular capacity necessary to give the height of plug desired, but should not be less than 40 bbl. If a second baryte plug is required, the slurry volume should be greater than the first. 6-92 March 1995 BP WELL CONTROL MANUAL 5 Pumping and Displacement Rate Baryte plugs should always be pumped with the drillpipe close to the bottom of the hole. If there is any significant volume of mud under the baryte slurry then the baryte slurry will mix with the mud because of the large differences in density. If the influx zone is somewhat above the bottom of the hole, then the baryte slurry should be pumped to bottom and then above the influx zone far enough to provide the desired hydrostatic kill height. A baryte plug should be pumped and displaced at a rate somewhat higher than the kick rate. If the kick rate is unknown, a reasonable rate (5 to 10 bbl/min) should be used for the first attempt although very large blowouts can ultimately require kill weight mud placement at greater than 50 bbl/min. 6 Preparation of a Baryte Plug For field preparation of either a settling or non-settling baryte slurry, it is best to prepare the mix water first and then add baryte to the desired density. The equipment needed on location to prepare and pump a baryte plug is a cementing unit equipped with a high pressure jet in the mixing hopper, a means of delivering the dry baryte to the cementing unit, and sufficent clean tankage for the mix water so that the lignosulphonate and caustic soda can be mixed in advance. The non-settling slurry may be recirculated through the mixing hopper several times if necessary to obtain a particular weight; service companies are reluctant to recirculate settling baryte slurries through their equipment. It is possible to weight-up to 2.5 SG in one pass provided the mix water is fed to the hopper␣at 600 to 1000 psi. Hopper nozzles and feed rate should be selected to give this pressure drop. Settling-type baryte slurries may only be stored in ribbon blenders or similar equipment which provide continuous, thorough agitation. Non-settling slurries may be stored in standard␣mud tanks although even these slurries may drop out a few in. of baryte per day if not stirred. The baryte slurry may be pumped into the drillpipe either through a cementing head or␣through the standpipe and kelly . In either case, the pump tie-in to the drillpipe should contain provisions for hooking up both the cementing unit pump and the rig pump so that either can be used to displace the slurry. If this is not done, and the cementing unit breaks down, the baryte may settle in the drillpipe before the mud pump tie-in can be made or the cementing unit repaired. Blockage of the drillstring by baryte settling will complicate the well control problem. 7 After Pumping a Baryte Plug Baryte plugs may be used in a variety of situations, it is not possible to give one fixed␣procedure which will always work. There will always be a need for local decisions and good judgement. This is especially true in deciding what to do after a baryte plug has been pumped. 6-93 March 1995 BP WELL CONTROL MANUAL The decision after placing a baryte plug is whether to pull pipe or not. The goal of pumping a high-density slurry is to achieve a hydrostatic kill; the decision whether to pull pipe depends on an assessment of the success of this kill. If a hydrostatic kill was probably achieved then it is usually best to pull up above the slurry and try circulating mud. If there is doubt about the hydrostatic kill it may be better to stay on bottom to be ready to pump a larger baryte plug if needed. The risk in pulling out is that the pipe may become stuck off bottom or may have to be stripped back to bottom if the baryte plug fails. The risk of staying on bottom is that the pipe may become stuck or plugged. It is possible to keep the pipe free by moving it (especially in a non-settling plug) but there is no way to circulate (to avoid plugging) unless the pipe is pulled above the top of the baryte slurry. 8 Baryte Plug Procedure (a) Leave Pipe in Place 1 Mix and pump the slurry at the appropriate rate Monitor the slurry density with a densometer in the discharge line or a pressurised mud balance. Displace the slurry immediately at the same rate. 2 Overdisplace the slurry by 5 bbl to clear the drillstring Continue to pump 1/4 bbl at 15 min intervals to keep the drillstring clear. 3 Verify that underground flow has stopped A noise log may be used. It is more definitive than temperature logs. Temperature surveys can be used in addition or if the noise log is not available. If temperature surveys are used, wait 6 to 10 hr for the temperatures to stabilise. The survey will show a hotter than normal temperature in the zone of lost returns. Wait another 4 hr, run a second survey. If the underground flow has stopped, the temperature in the lost returns zone will have decreased. 4 After it has been determined that the flow is stopped, bullhead a cement slurry through the bit to provide a permanent seal Observe the annulus during the pumping. If the casing pressure begins varying appreciably, or if a sudden change in the pumping pressure occurs, the baryte plug may have been disturbed. Overdisplace the cement to clear the drillstring. Additional cementing to obtain a squeeze pressure might be desirable. 5 Plug the inside of the drillstring The cement in step 4 can be underdisplaced, but a wireline bridge plug set near the top of the collars is preferred. Cement should be dump bailed on the wireline bridge plug for additional safety. 6 Pressure test the inside plug 6-94 March 1995 BP WELL CONTROL MANUAL 7 Perforate the drillstring near the top of the baryte plug. Attempt to circulate It may be difficult to tell whether the well is circulating or flowing from charged formations. Pressure communication between the drillpipe and annulus is one clue; a pressure increase should have appeared on the drillpipe from annulus pressure or on the casing from hydrostatic pressure in the drillpipe when the perforation was␣made. Consideration should be given to circulating with lighter mud because of the known lost returns zone. • Well will circulate: – Use drillpipe pressure method to circulate annulus clear of formation fluid. – Run a free-point log. – Begin fishing operations. • Well will not circulate: – Squeeze cement slurry through perforation. Cut displacement short on final stage to provide an interior plug or set wireline bridge plug. WOC and pressure test plug. – Run free-point log. – Perforate the pipe near the indicated free point. – Circulate using drillpipe pressure method until annulus is clear. If well will not circulate, squeeze perforations with cement or set a wireline bridge plug above perforations and perforate up the hole. (b) Pull Out of Plug (High Pressure, Low Permeability Formation) 1 Mix and pump the slurry Monitor the slurry weight with a densometer in the discharge line or a pressurised mud balance. If mixing is interrupted for any reason, immediately begin displacement of the slurry using either the cement unit pumps or the rig pumps. Work the pipe while pumping and displacing. 2 Displace the slurry with mud at the same rate Cut the displacement short by 2 or 3 bbl to prevent backflow from the annulus. If a non-ported, drillpipe float is in the drillstring, overdisplace the slurry. 3 Immediately begin pulling the pipe It may be necessary to strip the pipe through the annular preventer. Pull at least one stand above the calculated top of the baryte slurry. 6-95 March 1995 BP WELL CONTROL MANUAL 4 Monitor the annulus • If no pressure is on the annulus, continue working the pipe, and observe annulus mud level. – If the annulus is full, begin circulating at a low rate keeping constant watch on pit levels. – If the annulus is not full, fill annulus with water and observe. If annulus will stand full, begin circulating at a slow rate. Consider cutting mud weight, if feasible. • If pressure is on the annulus, circulate the annulus using normal well control techniques. Continue working the pipe. – If returns become gas-free, the baryte plug was successful and the well is dead. – If returns do not become essentially gas-free after circulating two or three annular volumes, the baryte plug was not effective. A second plug will be necessary. 5 Trip out of the hole after verifying that the well is dead If the bottom part of the hole is being abandoned, then a cement plug should be placed on top of the baryte. 6-96 March 1995 BP WELL CONTROL MANUAL 6.2 SPECIAL TECHNIQUES Subsection 2.6 EMERGENCY PROCEDURE Paragraph Page 1 Use of Shear Rams 6-98 2 Dropping the Pipe 6-99 6-97 March 1995 BP WELL CONTROL MANUAL 1 Use of Shear Rams Shear rams can be used to cut drillpipe and then act as a blind ram in order to isolate the drilling rig from the well. Shearing the pipe is a technique that will be required only in exceptional circumstances. The use of the shear rams can be considered in the following situations: • In preference to dropping the pipe in the event of an uncontrollable blowout up the drillstring (an internal blowout). • When it becomes necessary to move a floating rig off location at short notice. • When there is no pipe in the hole, the shear rams can be used as blind rams. Most shear rams are designed to shear effectively only on the body of the drillpipe. Procedures for the use of shear rams must therefore ensure that there is no tool joint opposite the ram prior to shearing. Be aware that many subsea stacks have insufficient clearance between the top pipe rams and the shear rams to hang off on the top rams and shear the pipe. Specialist shear rams, such as the Cameron Super Shear Rams, are available that are designed to shear 7 in. drillcollars and casing up to 13 3/8 in. OD. It is clearly important however, that rigsite personnel are aware of the capabilities and operating parameters of the shear rams installed in the rig’s BOP stack. Optimum shearing characteristics are obtained when the pipe is stationary and under tension. It is therefore recommended practice that the pipe weight is partially hung off prior to shearing. Hanging the pipe off also ensures that there is no tool joint opposite the shear rams. Maximum operating pressure should be used to shear the pipe. The following procedure can be used as a guideline for shearing the pipe in the case of an internal blowout: 1 Space out to ensure that there is no tool joint opposite the shear rams 2 Close the hang-off ram 3 Hang off on the rams Ensure that the pipe above the hang-off rams remains in tension. 4 Prepare to operate the shear rams 5 Close the shear rams at maximum accumulator pressure 6 Monitor the well. Implement appropriate control procedures 6-98 March 1995 BP WELL CONTROL MANUAL 2 Dropping the Pipe Situations in which it will be necessary to drop the pipe will be extremely rare. Dropping the pipe is an emergency procedure and as such it is a procedure that will only be required as a last resort when the safety of the rig and personnel is threatened. Situations that may require the pipe to be dropped include: • If an internal blowout occurs on a rig that has no shear rams. • If an internal blowout occurs when the drillcollars are in the stack. • As an alternative to the use of shear rams in the event of an internal blowout when drillpipe is in the stack. • If the pipe is pushed out of the hole under the influence of wellbore pressure. • If a BOP develops a leak and there is no back-up available. Once the pipe has been dropped the well is shut-in with the blind/shear rams. However, re-establishing control of the well in this situation will be time consuming and costly. It is clearly important to be sure that the pipe will clear the stack once it has been dropped (especially on a floating rig in deep water). The possibility of damaging the ram packings must also be considered. There are two techniques that can be used to drop the string: (a) Unlatch the elevators 1 Lower the string until the elevators are at a manageable distance from the␣floor 2 Ensure that the BOP is closed at maximum operating pressure 3 Attach a tugger line to the elevators 4 Clear the floor 5 Open the choke line to bleed down surface pressure 6 Open the elevators 7 Open the BOP. Allow the string to drop 8 Close the blind/shear ram 9 Close the choke 6-99 March 1995 BP WELL CONTROL MANUAL (b) Back off a tool joint 1 Set the slips 2 Break a tool joint. Ensure that the joint can support the weight of the string 3 Pull the slips 4 Run the joint below the rotary 5 Set the slips 6 Ensure the BOP is closed at maximum closing pressure 7 Open the choke line to reduce the surface pressure 8 Turn the rotary to the left to back off the joint 9 Open the BOP and allow the pipe to drop 10 Close the blind/shear ram 11 Close the choke Both of these techniques involve a certain amount of risk. The most suitable method in each case will depend on the particular conditions at the rigsite. 6-100 March 1995 BP WELL CONTROL MANUAL 6.3 COMPLICATIONS Paragraph Page 1 Plugged Bit Nozzle 6-102 2 Plugged Choke 6-102 3 Cut Out Choke 6-102 4 Pump Failure 6-103 5 Pressure Gauge Failure 6-103 6 String Washout 6-103 7 Stuck Pipe 6-104 8 Well Control Considerations in Horizontal Wellbores 6-104 9 Hydrates 6-105 10 Surface Pressures Approach the MAASP 6-109 11 Impending Bad Weather 6-110 12 Loss of Control 6-111 13 Well Control Considerations in Slim Hole Well 6-111 Illustrations 6.36 Temperature at which Gas Hydrates will Freeze (Katz) 6-106 6.37 Natural gas expansion – Temperature reduction curve (NATCO) 6-107 6.38 Height of 10 bbl Gas Influx in Annulus 6-113 6.39 Reduction in Bottom Hole Pressure Due to 10 bbl Gas Influx 6-114 6.40 Annular Friction Pressure Drop 6-115 6.41 Swab Pressure in a 1000 m Hole 6-116 6-101 March 1995 BP WELL CONTROL MANUAL 1 Plugged Bit Nozzle A plugged nozzle in the bit is indicated by an unexpected increase in drillpipe pressure with little or no change in the choke pressure. The choke operator may be tempted to open the choke in an attempt to reduce the drillpipe pressure to the original circulating pressure. This will result in a drop in choke pressure and a corresponding drop in bottomhole pressure. Therefore should a plugged bit nozzle be suspected, the pump should be stopped, the well shut-in and the pump restarted to establish the increased standpipe pressure that will maintain a suitable bottomhole pressure. An increase in drillpipe pressure could also be caused by the hole packing off around the BHA. This would be likely to cause increased, though fluctuating, circulating pressures. The drillstring should be reciprocated in order to clear this problem. If the bit becomes totally plugged, this will cause an abrupt and continually increasing drillpipe pressure, with little or no change in choke pressure. In this event, if increased drillpipe pressure does not clear the problem, the string must be perforated as close as possible to the bit in order to re-establish circulation. It is good practice, especially in critical hole sections, to run a circulating sub above the bit or above a core barrel. 2 Plugged Choke A plugged choke is indicated by an unexpected increase in choke pressure accompanied by an equal increase in drillpipe pressure. Some plugging of the choke is to be expected if the annulus is loaded with cuttings. Clearly the first course of action is to open the choke in an attempt to both clear the restriction in the choke and to avoid overpressuring the well. If this action is not successful the pump should be stopped immediately. After switching to an alternate choke the excess pressure in the well should be bled at the choke and the displacement restarted in the usual manner. One of the reasons for displacing a kick at slow circulation rates is to avoid overpressuring the well if cuttings plug the choke. In this respect, circulation rates should be minimised in critical conditions if the annulus is likely to contain a substantial volume of cuttings. 3 Cut Out Choke A choke is unlikely to suddenly cut out. In this respect, there will not be any dramatic indication that this problem is occurring. As a choke wears it will become necessary to gradually close it in to maintain circulating pressure. If the operator finds that he has to gradually close in the choke to maintain circulating pressure, the first reaction should be to check the pit volume to ensure that lost circulation is not occurring. 6-102 March 1995 BP WELL CONTROL MANUAL Having established that there is no loss of circulation a worn out choke should be suspected. There may come a stage when it is no longer possible to maintain a suitable circulating pressure even with the choke apparently fully closed. At, or preferably before this stage, the flow should be switched to another choke and repairs effected to the worn choke. 4 Pump Failure The most obvious indicator of failure at the fluid end is likely to be erratic standpipe pressure together with irregular rotary hose movement. This may be preceded by an unexplained drop in circulating pressure. If pump failure is suspected, the pump should be stopped and the well shut-in. The displacement should be continued with the second rig pump, or if necessary, the cement pump. The faulty pump should be repaired immediately. 5 Pressure Gauge Failure Every effort should be made to ensure that all pressure gauges are working correctly, and that back-up gauges are available in the event of failure of a pressure gauge during a well control operation. Should gauge failure occur during a well control operation it is important that the defective gauge be replaced as quickly as possible. If no back-up gauge is immediately available, stop the operation and shut in the well. 6 String Washout A washout in the drillstring may be indicated by an unexpected drop in standpipe pressure, while the choke pressure remains unchanged. The recommended procedure in the event of a drillstring washout is to stop the pump and shut the well in. Every effort must be made to ensure that the washout is not enlarged by extended circulation and drillstring manipulation. The most critical situation would be in the event of a washout close to the surface. Should this occur, it is unlikely that it will be possible to displace the influx from the hole effectively, unless the influx is above the washout. If the washout is identified as being near the bottom of the well, it may be possible to displace the kick from the well effectively. In this case, there will of course be the risk of parting the drillstring with continued circulation. Regardless of the depth of the washout, it will be necessary to re-establish the correct circulating pressure if the pump is restarted. Excessive downhole pressures may be caused if the original circulating pressure is maintained at the standpipe. It is advisable to periodically re-establish the circulating pressure, if the circulation is contained for prolonged periods through a washout. 6-103 March 1995 BP WELL CONTROL MANUAL 7 Stuck Pipe The complication of stuck pipe during a well control operation can cause serious problems, most especially if the pipe is stuck off bottom. Unfortunately, the likelihood of the pipe becoming stuck during a well control operation is increased if the pipe is off bottom. The pipe should be rotated, to minimise the risk of sticking the pipe, if the well is shut-in with the pipe off bottom and the BHA in openhole. Due to the relatively high wellbore pressures during a well control operation, the most likely cause of stuck pipe is differential sticking. However, mechanical sticking may result if the hole sloughs and packs-off as a result of the contact with the influx fluids. If the pipe is differentially stuck with the bit on bottom, continue the operation because it is most likely that circulation can still be carried out in order to kill the well. Efforts to free the pipe can be made once the well has been killed. Should the pipe be differentially stuck with the bit off bottom, the situation is complicated in that it will generally not be possible to reduce the wellbore pressure at that depth by circulation. It may be possible to free the pipe by spotting a freeing agent. However, if the influx was swabbed in, it may be possible to regain control of the well by volumetric control. If the pipe is mechanically stuck, a combination of working the pipe and spotting a freeing agent can be used in attempting to free the pipe. 8 Well Control Considerations in Horizontal Wellbore Well control procedures in horizontal wellbores use the same basic principles as those for vertical or deviated holes. Downhole equivalent mud weights are calculated using the true vertical depth, as always. There are however several additional points to consider, these are as follows: • The purposes of drilling a horizontal well are to improve hydrocarbon recovery and to maximise the area of reservoir exposed at the wellbore, in order to maximise production rates. It must therefore be considered that influx flowrates, in the event of a kick, will be considerably greater than for a well drilled vertically through the reservoir. Particular attention must be paid to tripping procedures when the reservoir is exposed. • It is possible that shut-in pressures in the event of a kick will be identical on both drillpipe and annulus, although a large influx has been taken; this would depend on the length of the horizontal openhole section. This is not a problem, however it does mean that it is not possible to check the validity of kick data. The possibility that the wellbore contains a large influx should therefore be addressed in such circumstances. 6-104 March 1995 BP WELL CONTROL MANUAL • There is a greater potential for swabbing when a large surface area of reservoir is exposed. Correct tripping procedure must be rigorously adhered to. It is quite feasible, in a horizontal well, that the horizontal section is full of reservoir fluid and yet the well be dead. It is therefore recommended that extreme caution be paid when tripping back into such a reservoir after a round trip. When back on bottom it is recommended to circulate bottoms up through the choke manifold. In the event of a kick whilst tripping it may not be possible to drop or pump down the dart. This will depend on the hole angle at the dart sub position. If it is not possible to install the dart into the dart sub, the ‘Gray’ valve can be used. 9 Hydrates Natural gas hydrates have the appearance of hard snow and consist of chemical compounds of light hydrocarbons and liquid water. They are formed at temperatures above the normal freezing point of water at certain conditions of temperature and pressure (See Figure 6.36). This formation process is accelerated when there are high gas velocities, pressure pulsations or other agitations, such as downstream of a choke and at elbows, which cause the mixing of hydrocarbon components. During well control operations, gas hydrates may cause the following serious problems: • Plugging of subsea choke/kill lines, preventing opening and closing of subsea BOPs, sealing off wellbore annuli and immobilising the drillstring. There have been recorded incidences of such occurrences with subsea stacks in water depths of 350m and deeper. • Plugging of surface lines at and downstream of the choke or restriction. This is particularly hazardous when high gas flowrates are experienced through low pressure equipment (such as the poorboy separator and gas vent line). The formation of hydrate plugs under these conditions can rapidly overpressure low pressure well control equipment. The major factors which determine the potential for hydrate formation are gas composition, liquid content and pressure and temperature. The formation of hydrates can be predicted using Figure 6.36. It should be noted that the conditions for hydrate formation can be created at a subsea stack operating in a cold water environment. Figure 6.37 can be used to predict the temperature drop associated with a pressure drop (across a choke, for example). As an example, if gas at 3000 psi and 90°F was choked to 1800 psi, the temperature would be expected to drop to 55°F, in which case, hydrate formation could be expected. 6-105 March 1995 BP WELL CONTROL MANUAL Figure 6.36 Temperature at which Gas Hydrates will Freeze (Katz) The purpose of this chart is to determine the temperature below which hydrates will form, when sufficient liquid water is present. 4000 3000 1000 NE HA 900 800 ET M 700 600 500 400 AV R 6 0. G 300 7 0. 0. 8 PRESSURE FOR HYDRATE FORMATION (psia) 2000 200 9 1. 0 0. 100 90 80 70 60 35 40 45 50 55 60 65 70 75 80 85 TEMPERATURE (°F) Example: With 0.7 specific gravity gas at 1000psia, hydrates may be expected at 64°F. At 200psia this would be 44°F. WEOX02.061 6-106 March 1995 GAS TEMPERATURE (°F) 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 0 6 0 50 00 60 00 50 1000 00 55 00 45 00 40 00 35 00 30 2 00 15 0 0 20 MP 2000 0 50 TE D ET CO 0 ES SU R OP PRESSURE (lb/in ) 3000 2 S VE 4000 HYDRATE EXPECTANCY DEGREES FAHRENHEIT R ED R CU S PY GA L A T TH U F EN 0 C T 0 N 0 TA U/1 NS BT 0 50 DU 00 10 P RO R OP INITIAL TEMP RISE 150 00 70 105° - 80° = 25° 160 NATURAL GAS EXPANSION – TEMP REDUCTION CURVE BASED ON 7 SP GR GAS (From NATCO) 5000 EXAMPLE REQUIRED: REDUCE GAS PRESSURE FROM 2400 # PSI AT 80°F TO 1500 # PSI DETERMINE INITIAL TEMPERATURE RISE NECESSARY SO THAT AFTER EXPANSION TO 1500 # PSI THE FINAL TEMPERATURE WILL BE 75°F BASE LINE 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 BP WELL CONTROL MANUAL Figure 6.37 Natural Gas Expansion – Temperature reduction curve (NATCO) WEOX02.062 6-107 March 1995 BP WELL CONTROL MANUAL Hydrates can be combated by one or a combination of the following: • Injecting antifreeze agents such as methanol into the gas flow; this has the effect of dissolving liquid water deposits, and thus lowering the temperature at which hydrates would be expected to form. Methanol is often injected at the subsea test tree during well testing operations from a floating rig. The most appropriate place to inject methanol at surface is at the choke manifold. The point of injection should be upstream of the choke. High pressure chemical injection pumps (as manufactured by Texsteam) are suitable for this application. • Heating the gas above the temperature at which hydrate will form. During gas well testing operations, a steam exchanger will usually be provided for this purpose. Experience has shown that this is the most effective and reliable method of preventing the formation of hydrates. The combination of heating and antifreeze injection is ideal. • Reducing line pressure in order to allow the hydrates to melt. This is a temporary measure and not always practical. Once hydrates have formed, it often takes a considerable length of time to clear the line. It is important that adequate contingency is provided, along the above lines, to deal with hydrates, if it is suspected that the potential exists for hydrate formation. Subsea water temperatures and pressures should be checked as well as the potential for hydrate formation at surface in the event of a gas kick. 10 Surface Pressures Approach the MAASP The MAASP is defined as the maximum allowable annular surface pressure. Bearing in mind the method that is used to calculate its value (i.e. assuming that MAASP is calculated from LO Test result), it is clear that the MAASP is a consideration only when there is a full column of mud from the openhole weak point to the surface. Surface pressures in excess of the MAASP therefore may not cause downhole failure if lighter fluids (such as a hydrocarbon influx) occupy the annulus above the openhole weak point. Consequently, during a well control operation, from the moment that the top of an influx is displaced past and above the openhole weak point, the MAASP is no longer a consideration and may be exceeded. In the event that surface pressures exceed the MAASP when the kick is still below the openhole weak point, consequently causing excessive downhole pressures, there are two distinct options: • Hold the choke pressure so as to maintain bottomhole pressure equal to, or slightly greater than, the kick zone pore pressure. • Reduce the choke pressure and limit it to the MAASP. 6-108 March 1995 BP WELL CONTROL MANUAL The consequences of overpressuring the openhole weak point as in the first option can be assessed, bearing in mind the following factors: • The depth of the casing shoe. • The quality of the cement job. • By how much the openhole weak point will be overpressured. • The length of time that the openhole weak point will be overpressured. • The characteristics of the openhole weak point. • Any safety factor included in the calculation of the MAASP. • The possibility of broaching around the casing. The consequences of underbalancing the formation as in the second option can be assessed, bearing in mind the following factors: • The type of kick zone fluid. • The permeability of the kick zone. • The degree of underbalance. • The length of time that the kick zone will be underbalanced. The appropriate course of action should therefore be selected on the basis of these factors. However, in general, a kick zone should only be underbalanced in exceptional circumstances such as when the zone is known to have low permeability. This can often be assessed from the rate of pressure build after shutting in a well that has kicked. 11 Impending Bad Weather Bad weather is most likely to cause serious problems as regards well control on offshore␣rigs. For example, it may not be possible to offload baryte supplies or remove excess personnel in bad weather. On a floating rig, a critical situation is reached should it become necessary to unlatch the riser during a well control operation. In this situation it will not be possible to monitor the well and hence control the migration of the influx, should this occur. Should weather conditions deteriorate with very little warning, the following procedure can be implemented: 1 Attempt to bullhead the influx back to the formation 2 Displace the drillstring to kill weight mud 3 Close lowermost pipe rams (in addition to the hang-off rams). Shear the pipe rams 4 Prepare to unlatch, monitoring wellbore pressures until it becomes necessary to unlatch 6-109 March 1995 BP WELL CONTROL MANUAL If additional time is available, consideration should be given to spotting a heavy pill or plug on bottom to either kill the well hydrostatically or provide a barrier to migration. Bad weather may cause problems regarding the supply of chemicals and barytes to all types of rigs. In this respect, it may be necessary to implement the Driller’s Method, should there not be adequate chemical stocks at the rigsite. In certain areas of the world, severe cold may cause operational problems. Points of particular concern are, BOP operating fluid, manifolds and flowlines. 12 Loss of Control Loss of control during a well control operation may result from excessive loading of pressure control equipment or exposed formations. However there are recorded incidents of equipment failure at pressures significantly below rated values. These failures have been attributed to faulty manufacture, lack of proper maintenance, or corrosion. High pressure equipment is considered particularly susceptible to failure when exposed to corrosive fluids such as H2 S. It is not possible to detail specific procedures in the event of loss of control during a well control operation. However, in critical situations, action should be taken bearing in mind that the absolute priority is the safety of rigsite personnel. 13 Well Control Considerations in Slim Hole Well A slim hole is commonly defined as one in which 90% or more of the length of the well is drilled with drill bits less than 7" in diameter. A well with hole sizes smaller than those in a conventional well is also broadly considered as a slim hole well. Whilst the immediate difference between a conventional well and a slim hole well is their hole sizes, other major characteristics of a slim hole include the practice of long sections of continuous coring and the requirements of higher drillpipe rotary speeds, lower weights on bit, lower mud flow rates and special mud systems. So a slim hole well requires significant changes in the well design, well operation and the well control procedures. (a) Slim Hole Characteristics In terms of well control, a slim hole well has the following characteristics when compared with a conventional well: • Greater Influx Length Due to the reduced annular size in a slim hole, the same volume of formation influx will occupy a longer section of the annulus in a slim hole well than in a conventional well. As shown in Fig.6.38, a 10 bbl influx occupies 66 m long annulus in a conventional 8.5"x5" well and 523 m long in a 3.5"x2.5" slim hole well. 6-110 Rev 1 March March 1995 1995 BP WELL CONTROL MANUAL • Greater Bottom Hole Pressure Reduction As the result of the greater influx length, the same volume of formation influx will result in a greater reduction in the bottom hole pressure in a slim hole well. As␣shown in Fig.6.39, a 10 bbl gas influx will reduce the bottom hole pressure by about 743 psi in a 3.5"x2.5" slim hole well and only 94 psi in a conventional 8.5"x5" well. • Higher Annular Friction Pressure Also due to the reduced annular size, the annular friction pressure drop can be many times higher in a slim hole well than in a conventional well, as shown in Fig.6.40. Therefore the friction pressure drop can become significant during well control operations in a slim hole well whereas it is all but ignored in the case of a conventional well. • Higher Swab and Surge Pressures Fig.6.41 compares the swabbing pressure in both slim hole and conventional wells. It can be seen that the swabbing pressure is much higher in a slim hole well than in a conventional well. Also the swabbing pressure increases more rapidly in a slim hole well with increasing the trip speed. • Effect of High Drillpipe Rotational Speed During a slim hole drilling operation, the drillpipe is often rotated at a much higher rate than that during a conventional drilling operation. Due to the high rotational speed together with the small annular size, the drillpipe rotation can result in a significant increase in the annular friction pressure and the ECD. This effect must be taken into account in the well control procedures. Otherwise, the weak formation may be broken down when the drillpipe starts to rotate, or a kick influx be induced when rotation stops (whilst still maintaining circulation). (b) Kick Detection System As described above, a small volume of influx can occupy a long section of the annulus in a slim hole well and thus greatly reduce the bottom hole pressure. This will cause the influx flow to intensify continuously. As the result, a kick can develop more rapidly in a slim hole well than in a conventional well. Therefore it is important to be able to detect a kick at a very early stage during a slim hole well operation. Although the basic principles in the kick detection technique remain the same for slim holes, the sensitivity of the detection system must be enhanced. The basic requirements for a slim hole kick detection system are: • The system must be able to detect a small volume of pit gain (typically 1 or 2 bbl). This technique is most reliable when the influx flow is slow (low kick intensity). • The system must be able to detect the difference between the mud flow in and out of the well (typically 25 gpm). When the influx flow is fast, this technique is more sensitive and reliable than the pit volume detection technique. • The system must be able to detect a kick whilst making a connection. The high annular friction pressure creates a high ECD during drilling ahead. So the most likely time for a kick to occur will be when the pumps are shut down to make a connection. 6-111 Rev 1 March March 1995 1995 BP WELL CONTROL MANUAL (c) Well Kill Technique As the annular friction pressure is small in a conventional well, it is used as a safety factor during the well kill operation to ensure that the bottom hole pressure stays slightly above the formation pressure. So the annular friction pressure is usually ignored in the conventional well control calculations. In a slim hole well however, the annular friction pressure may be so high that when used as a safety factor, it will break down the formation at the weak point and cause lost circulation. Therefore a decision that must be made when drilling a slim hole is whether the␣ c onventional well kill technique can be applied. This can be made in the following␣steps: • Estimate the annular friction pressure at the slow circulating rates and add this to the maximum static pressure (i.e. the sum of the mud hydrostatic pressure and the surface casing pressure) at the weak point in the wellbore. • Compare the total wellbore pressure with the breakdown pressure at the weak point. Will lost circulation be likely? • If lost circulation is unlikely, the conventional well control technique can be applied. Otherwise the slim hole well control technique must to be used. (d) Slim Hole Well Control Manual This section briefly summarises the key differences in well control for slim holes. A BP Slim Hole Well Control Manual is available that details the principles and procedures for kick prevention, kick detection, well shut-in and the well kill technique for slim holes. The manual can be obtained from the Drilling and Completions Branch, BP Exploration, Sunbury. 6-112 Rev 1 March March 1995 1995 Reduction In BHP (osi) 1.0 sg Mud 1 0 400 8.5 x 5 66 94 8.5 x 5 10 6 x 4.5 199 283 6 x 4.5 3.5 x 2.5 523 743 3.5 x 2.5 Height of Gas Influx (m) Gas Influx Height (m) 10 200 Friction Pressure (psi) Brine: 4.0 cPMud: PV=15/YP=10 13.8 31.2 523 m 199 m 0 66 m 8.5 x 5 6 x 4.5 Size of Annulus (inch) 3.5 x 2.5 41 128.6 68.9 254.3 BP WELL CONTROL MANUAL 6-113 Annular Size (inch) Figure 6.38 Height of 10 bbl Gas Influx in Annulus Figure 6.38a: Height of 10 bbl Gas Influx in Annulus Gas Influx 600 Volume (bbl) Rev 1 March March 1995 1995 (1.0 SG Density Difference Between Mud and Gas) 800 254.3 Reduction in BHP (psi) 6-114 128.6 400 743 psi 200 283 psi 0 94 psi 8.5 x 5 6 x 4.5 Size of Annulus (inch) 3.5 x 2.5 BP WELL CONTROL MANUAL Mud: PV=15/YP=10 31.2 600 Figure 6.39 Reduction in Bottom Hole Pressure Due to 10 bbl Gas Influx March Rev 1 March 1995 1995 Figure 6.38b: Reduction in Bottom Hole Pressure Due to 10 bbl Gas Influx swab pressures 200 Brine: 4.0 cP 150 sec/std Mud: PV=15/YP=10 129 100 50 0 31.2 41 13.8 8.5 x 5 6 x 4.5 Size of Annulus (inch) 8.5/5 300 250 200 150 100 50 40 30 25 20 15 6/4.5 40.9 41 41.3 68.9 41.7 42.5 44.8 46.2 3.5 x 2.5 48.3 55 58.8 64.8 3.5/2.5 45.8 46 46.3 48.8 47.8 50.9 52.5 55.1 66.4 92.2 147 90 90.8 92.1 94.2 98.5 110 117.7 128.4 168 238 368 BP WELL CONTROL MANUAL 6-115 Friction Pressure Drop (psi/1000m) 254 250 Swab Pressure (psi/1000m) Height of Ga (m) (Mud Annular Velocity = 150 ft/min) 300 Figure 6.40 Annular Friction Pressure Drop Figure 6.38c: Annular Friction Pressure Drop Rev 1 March March 1995 1995 Reduction in (psi) (Mud: 1.0 SG, PV=15 cP, YP=10 lbf/100sqft) 300 3.5"x2.5" 6-116 90 90.8 92.1 94.2 98.5 110 117.7 128.4 168 238 368 Swab Pressure (psi/1000m) 3.5/2.5 1 8 08 . 5 / 5 6.0"x4.5" 120 8.5"x5.0" Annulus 60 0 90 60 30 Trip Speed (sec/30m std.) 0 BP WELL CONTROL MANUAL 240 Figure 6.41 Swab Pressure in a 1000 m Hole March 1995 1995 Rev 1 March Figure 6.38d: Swab Pressure in a 1000 m Hole BP WELL CONTROL MANUAL Volume 2 – Contents Nomenclature Abbreviations 1 THE ORIGINS OF FORMATION PRESSURE Section Page 1.1 INTRODUCTION 1-1 1.2 NORMAL FORMATION PRESSURE 1-9 1.3 SUBNORMAL FORMATION PRESSURE 1-11 1.4 ABNORMALLY HIGH FORMATION PRESSURE 1-17 1.5 SHALLOW GAS 1-33 2 FORMATION PRESSURE EVALUATION Section 2.1 INTRODUCTION 2-1 2.2 FORMATION PRESSURE EVALUATION DURING WELL PLANNING 2-5 FORMATION PRESSURE EVALUATION WHILST DRILLING 2-25 FORMATION PRESSURE EVALUATION AFTER DRILLING 2-69 2.3 2.4 March 1995 BP WELL CONTROL MANUAL 3 PRIMARY WELL CONTROL Paragraph 1 GENERAL 3-2 2 HYDROSTATIC PRESSURE 3-2 3 EQUIVALENT MUD WEIGHT, EMW 3-2 4 CIRCULATING PRESSURES AND ECD 3-4 5 CALCULATING THE CIRCULATING PRESSURE LOSSES 3-7 6 SWAB AND SURGE PRESSURES 3-10 7 SWAB AND SURGE CALCULATIONS 3-12 4 FRACTURE GRADIENT Paragraph 1 GENERAL 4-2 2 STRESSES IN THE EARTH 4-2 3 FRACTURE ORIENTATION 4-3 4 FRACTURE GRADIENT PREDICTION 4-4 5 DAINES’ METHOD OF FRACTURE GRADIENT PREDICTION 4-4 6 AN EXAMPLE PRESSURE EVALUATION LOG 4-7 7 LEAK OFF TESTS 4-9 8 LEAK OFF TEST PROCEDURE 4-10 9 INTERPRETATION OF RESULTS 4-11 March 1995 BP WELL CONTROL MANUAL 5 BASICS OF WELL CONTROL Paragraph 1 GENERAL 5-4 2 DISPLACING A KICK FROM THE HOLE 5-4 3 FACTORS THAT AFFECT WELLBORE PRESSURES 5-9 4 SUBSEA CONSIDERATIONS 5-20 5 SAFETY FACTORS 5-25 6 CALCULATING ANNULUS PRESSURE PROFILES 5-29 6 WELL CONTROL EQUIPMENT Section 6.1 WELLHEADS 6-1 6.2 BLOWOUT PREVENTER EQUIPMENT 6-5 6.3 CONTROL SYSTEMS 6-43 6.4 ASSOCIATED EQUIPMENT 6-57 6.5 EQUIPMENT TESTING 6-67 March 1995 BP WELL CONTROL MANUAL NOMENCLATURE SYMBOL DESCRIPTION UNIT A a An b c C Cp Ca CL CR D Dshoe Dwp dbit dh dhc do di dcut dc F Fsh FPG g G Cross sectional area Constant Total nozzle area Constant Constant Annular capacity Pipe capacity Cuttings concentration Clinging constant Closing ratio Depth Shoe depth Depth of openhole weak point Bit diameter Hole diameter Hole/casing ID Pipe OD Pipe ID Average cuttings diameter Drilling exponent (corrected) Force Shale formation factor Formation Pressure Gradient Gravity acceleration Pressure gradient Gi H Hi Hp ITT K L λ MR M m MW Influx gradient Height Height of influx Height of plug Interval Transit Time Bulk modulus of elasticity Length Rotary exponent Migration rate Matrix stress Threshold bit weight Mud weight in.2 – in.2 – – bbl/m bbl/m % – – m m m in. in. in. in. in. in. – lb – SG – psi/ft psi/m SG psi/ft m m m µsec/m March 1995 m – m/hr psi lb SG BP WELL CONTROL MANUAL SYMBOL DESCRIPTION UNIT N OPG P Rotary speed Overburden Pressure Gradient Pressure ∆P Pa ∆Pbit Pcl Pdp Pf Pfrac Pfc Pi Pic Plo Pmax S Sg Sw t Adjustment pressure Annulus pressure Bit pressure drop Choke line pressure loss Drillpipe pressure Formation pressure Fracture pressure Final circulating pressure Hydrostatic pressure of influx Initial circulating pressure Leak off pressure Maximum allowable pressure at the openhole weak point Wide open choke pressure Pore pressure Slow circulating rate pressure Plastic Viscosity Flowrate Mud flowrate Gas flowrate Reynolds number Resistivity Resistivity of water Rate of Penetration Shale factor Overburden pressure Gas saturation Water saturation Time rpm SG psi/SG (The units of subsurface pressure may be either psi or SG) psi psi psi psi psi psi/SG psi/SG psi psi psi psi/SG TR T Transport Ratio Temperature TD TVD V Total Depth True Vertical Depth Kick tolerance Poc Pp Pscr PV Q Qmud Qgas Re R Rw ROP psi/SG psi psi/SG psi cP gal/min gal/min gal/min – ohm-m ohm-m m/hr meq/100g psi Fractional Fractional seconds min – degrees C, F, R m m bbl March 1995 BP WELL CONTROL MANUAL SYMBOL DESCRIPTION V Volume v vmud vp vs W w w wb wcut WOB x YP Z µ ν σ’1 σ’t Ø Ø600 β ρ ρb March 1995 UNIT bbl cc ml l Velocity m/min m/s Mud velocity m/min Average pipe running speed m/min Slip velocity m/min Weight gm kg lb Weight lb/ft lb/bbl SG Weight of pipe lb/ft Baryte required for weighting up lb/bbl Average cuttings weight SG Weight on Bit lb Offset () Yield Point lb/100ft2 Compressibility factor – Viscosity cP Poissons’s Ratio – Maximum effective principle stress psi/SG Tectonic stress psi/SG Porosity Fractional Fann reading lb/100ft2 Tectonic stress coefficient – Density SG Bulk density SG BP WELL CONTROL MANUAL ABBREVIATIONS ASN BHA BHC BHT BGG BRT CDP CEG CG DE DIL DRG DST ECD EMW ES FDC FIT HCR ID ITT LMRP MWD OD PV RFT RMS ROP SLS TD TG UV WOB YP Amplified Short Normal Bottomhole Assembly Borehole Compensated Tool Bottomhole Temperature Background Gas Below Rotary Table Common Depth Plot Cation Exchange Capacity Connection Gas Drilling Engineer Dual Induction Laterolog Designated Resident Geologist Drillstem Test Equivalent Circulating Density Equivalent Mud Weight Electrical Survey Formation Density Compensated Tool Formation Interval Tester High Closing Ratio Internal Diameter Interval Transit Time Lower Marine Riser Package Measurement while Drilling Outside Diameter Plastic Viscosity Repeat Formation Tester Root Mean Squared Rate of Penetration Long Spacing Sonic Tool Total Depth Trip Gas Ultra Violet Weight of Bit Yield Point March 1995 BP WELL CONTROL MANUAL 1 THE ORIGINS OF FORMATION PRESSURE Section Page 1.1 INTRODUCTION 1-1 1.2 NORMAL FORMATION PRESSURE 1-9 1.3 SUBNORMAL FORMATION PRESSURE 1-11 1.4 ABNORMALLY HIGH FORMATION PRESSURE 1-17 1.5 SHALLOW GAS 1-33 March 1995 BP WELL CONTROL MANUAL 1.1 INTRODUCTION Paragraph Page 1 General 1-2 2 Subsurface Pressures 1-2 3 Pressure Seals 1-6 4 Pressure Gradients 1-7 Illustrations 1.1 1.2 Composite Overburden Load for Normally Compacted Formations 1-4 Schematic Diagram of Subsurface Pressure Concepts 1-5 Types of Formation Pressure Seals 1-6 Tables 1.1 1-1 March 1995 BP WELL CONTROL MANUAL 1 General All formations penetrated whilst drilling a well exert pressures of varying magnitudes. To gain an understanding of the origins of these pressures, it is neccesary to define and explain certain subsurface pressure concepts. These are explained in this Section. 2 Subsurface Pressures (a) Hydrostatic Pressure Hydrostatic pressure is defined as the pressure due to the unit weight and vertical height of a fluid column. The size and shape of the fluid column do not affect the magnitude of this pressure. Mathematically: P=rXgXD where P ρ g D = = = = (1-1) hydrostatic pressure average fluid density gravitational acceleration vertical height of fluid column Relating this to drilling operations and commonly used oilfield units gives: P = C X MW X D where P MW D C = = = = (1-2) hydrostatic pressure (psi) fluid density or mud weight (lb/gal or ppg) vertical depth (ft) conversion constant (psi/ft per lb/gal) The constant, C, is necessary to allow the use of oilfield imperial units (psi, ft, lb/gal). It has a value of 0.052 psi/ft per lb/gal and is derived as follows: Using consistent units (pressure in lb/sq.ft, length in ft, density in lb/cu.ft) and rearranging equation 1-2, C would be numerically equal to 1: C= P D X MW = 1 lb/sq.ft/ft per lb/cu.ft Substituting the standard conversion constants of 144 sq.in/sq.ft and 7.48/gal/cu.ft gives: C=1 X C = 0.052 7.48 144 lb/sq.ft ft X lb/cu.ft X sq.ft/sq.in cu.ft/gal lb/sq.in ft X lb/gal C = 0.052 psi/ft per lb/gal 1-2 March 1995 BP WELL CONTROL MANUAL So in imperial oilfield units (psi, ft, lb/gal), equation 1-2 becomes: P = 0.052 X MW – D (1-3) For the Company’s system of units (psi, SG, m): P = C' X SG X D (1-4) where SG = specific gravity of the fluid (no units) D = vertical depth (metres) C' = conversion constant (psi/m) NOTE: Specific gravity (SG) is not a unit of density. It is the ratio of the density of a␣fluid to the density of fresh water at a specified temperature, and hence has no units. The constant, C', has a value of 1.421 psi/m and is derived as follows: To express equation 1-2 in terms of SG (as in equation 1-4), the constant C' must be related to the density of fresh water, which is 8.33 lb/gal. Hence for fresh water: C' = C X 8.33 psi/ft/lb/gal X lb/gal C' = 0.052 X 8.33 psi/ft C' = 0.433 psi/ft (1-5) Expressing this in terms of metres using 3.2808 ft/m gives: C' = 0.433 X 3.2808 psi/ft X ft/m C' = 1.421 psi/m Equation 1-4 thus becomes: P = 1.421 X SG X D (1-6) (b) Overburden Pressure Overburden pressure is the result of the combined weight of the formation matrix (rock) and the fluids (water, oil and gas) in the pore space overlying the formation of interest. It was originally assumed that overburden pressure increases uniformly with depth. The average density of a thick sedimentary sequence is equivalent to an SG of 2.3. Hence, the overburden pressure (S) is given by: S = 0.433 X SG X D (1-7) where D = vertical depth (ft). The overburden pressure gradient (OPG) is given by: OPG = S D = 0.433 OPG = 0.433 X X SG 2.3 = 1.0 psi/ft 1-3 March 1995 BP WELL CONTROL MANUAL Figure 1.1 Composite Overburden Load for Normally Compacted Formations 1. 2. 3. 4. Constant gradient 1.0psi/ft Gulf of Mexico, Texas and Louisiana, USA Santa Barbara Channel, California, USA North Sea area 0 1 4 2 3 1 DEPTH 1000m 2 3 4 5 6 0.7 0.8 0.9 1.0 1.05 OVERBURDEN GRADIENT psi/ft WEOX02.063 1-4 March 1995 BP WELL CONTROL MANUAL However, because the degree of compaction of sediments varies with depth, the overburden pressure gradient is not constant. Worldwide experience indicates that the probable maximum overburden gradient in clastic rocks (fragmental sedimentary rocks ie sandstone, shale) may be as high as 1.35 psi/ft. Onshore, with more compact sediments, the overburden pressure gradient may be assumed to be close to 1 psi/ft. Offshore however, overburden gradients at shallow depths will be much less than 1 psi/ft due to the effect of the depth of sea water and large thickness of unconsolidated sediment. Figure 1.1 shows average overburden gradient for various areas. PRESSURE AL RM NO OS VE R TA B U TIC R D EN GR DEPTH DR HY O G AD R A T IEN SUBNORMAL PRESSURES (Subpressures) D IE N T ABNORMALLY HIGH PRESSURES (Surpressures) Formation Pressure, Pf Matrix Stress, M Overburden Pressure, S = Pf + M WEOX02.064 Figure 1.2 Schematic Diagram of Subsurface Pressure Concepts 1-5 March 1995 BP WELL CONTROL MANUAL (c) Pore Pressure Pore pressure is the pressure acting on the fluids contained in the pore space of the rock. This is the strict meaning of what is generally referred to as formation pressure. Formation pressure is related to overburden pressure as follows: S = Pf + M (1-8) where S = overburden pressure (total vertical stress) Pf = formation pressure (pore pressure) M = grain-to-grain pressure (matrix stress) All sedimentary rocks have porosity to some extent. If the pore spaces of the rocks are freely connected from surface, then the formation pressure at any depth will be equal to the hydrostatic pressure exerted by the fluid occupying the pore spaces. In this ‘normal’ pressure situation, the matrix stress (grain-to-grain contact pressure) supports the overburden load. Any departure from this situation will give rise to ‘abnormal’ formation pressures. Formation pressures less than hydrostatic are called subnormal (subpressures) and formation pressures greater than hydrostatic are termed abnormally high formation pressures (surpressures) (See Figure 1.2). 3 Pressure Seals For abnormal pressures to exist, there must be a permeability barrier which acts as a pressure seal. This seal restricts or prevents the movement of pore fluids and thus separates normally pressured formations from abnormally pressured formations. The origins of a pressure seal may be physical, chemical or a combination of the two. The types of formation pressure seals are listed below in Table 1.1. Type of Seal Nature of Seal Examples Vertical Massive siltstones Shales Massive salts Anhydrite Gypsum Limestone, marl, chalk Dolomite Gulf Coast, USA, Zechstein in North Germany, North Sea, Middle East, USA, USSR. Transverse Faults Salt and shale diapirs Worldwide Combination Table 1.1 Worldwide Types of Formation Pressure Seals 1-6 March 1995 BP WELL CONTROL MANUAL 4 Pressure Gradients As indicated previously in Paragraph 2(b) under ‘Overburden Pressure’, it is common practice to express subsurface pressures in terms of pressure gradients, or pressure per unit depth, psi/ft or psi/m. It should be realised that densities such as mud weights in lb/gal or␣SG, also express pressure gradients. These units can easily be converted to psi/ft or psi/m using the conversion constants derived earlier in Paragraph 2(a). Rearranging equation 1-3 gives: PG = P D = 0.052 X MW (1-9) where PG = pressure gradient (psi/ft) at depth D (ft), and rearranging equation 1-6 gives: PG = P D = 1.421 X SG (1-10) where PG = pressure gradient (psi/m) at depth D (m). Or, PG = P D = 0.433 X SG (1-11) where PG = pressure gradient (psi/ft) at depth D (ft). By converting subsurface pressures to gradients relative to a fixed datum, it is possible to directly compare formation pressures, fracture pressures, overburden pressures, mud weights and equivalent circulating densities (ECDs) on the same basis (See Chapter 3). The datum chosen is usually sea/ground level for initial planning purposes. Once a rig has been allocated for the well, then the datum chosen for final well planning and whilst drilling is the rotary table level (since mud hydrostatic pressure starts from just below this level). During drilling operations, it is standard practice to express all pressure gradients in terms of equivalent mud weight (EMW) either in lb/gal or SG. This allows direct comparison of downhole pressures to the weight (density) of the mud in use. EMWs can be calculated from rearrangements of equations 1-9 to 1-11: EMW (lb/gal) = P (psi) 0.052 X D (ft) (1-12) EMW (SG) = P (psi) 1.421 X D (m) (1-13) EMW (SG) = P (psi) 0.433 X D (ft) (1-14) NOTE: From this point on ppg will be used instead of lb/gal as the abbreviated version of pounds per gallon. Example: For a formation pressure of 5970 psi at 3500m BRT, what is the formation␣pressure gradient in psi/ft? What is the equivalent mud weight in ppg and SG? 1-7 March 1995 BP WELL CONTROL MANUAL Formation pressure gradient, FPG = FPG = 5970 3500 X 3.2808 pressure depth = 0.52 psi/ft Equivalent mud weight from equation 1-12 EMW = 5970 (ppg) 0.052 X 3500 X 3.2808 EMW = 10.0 ppg From equation 1-13 EMW = 5970 1.421 X 3500 = 1.20 SG 1-8 March 1995 BP WELL CONTROL MANUAL 1.2 NORMAL FORMATION PRESSURE Paragraph Page 1 General 1-10 2 Magnitude and Examples 1-10 Average Normal Formation Pressure Gradients 1-10 Tables 1.2 1-9 March 1995 BP WELL CONTROL MANUAL 1 General Normal formation pressure is equal to the hydrostatic pressure of water extending from the surface to the subsurface formation. Thus, the normal formation pressure gradient in any area will be equal to the hydrostatic pressure gradient of the water occupying the pore spaces of the subsurface formations in that area. 2 Magnitude and Examples The magnitude of the hydrostatic pressure gradient is affected by the concentration of dissolved solids (salts) and gases in the formation water. Increasing the dissolved solids (higher salt concentration) increases the formation pressure gradient whilst an increase in the level of gases in solution will decrease the pressure gradient. For example, formation water with a salinity of 80,000 ppm sodium chloride (salt) at a temperature of 25°C, has a pressure gradient of 0.465 psi/ft. Freshwater (zero salinity) has a pressure gradient of 0.433 psi/ft. Temperature also has an effect as hydrostatic pressure gradients will decrease at higher temperatures due to fluid expansion. In formations deposited in an offshore environment, formation water density may vary from slightly saline (1.02 SG, 0.44 psi/ft) to saturated saline (1.19 SG, 0.515 psi/ft). Salinity varies with depth and formation type. Therefore, the average value of normal formation pressure gradient may not be valid for all depths. For instance, it is possible that local normal pressure gradients as high as 0.515 psi/ft may exist in formations adjacent to salt formations where the formation water is completely salt saturated. The following table gives examples of the magnitude of the normal formation pressure gradient for various areas. However, in the absence of accurate data, 0.465 psi/ft is often taken to be the normal pressure gradient. Formation Water Pressure (psi/ft) Gradient (SG) Example Area Fresh water 0.433 1.00 Rocky Mountains and Mid-continent, USA Brackish water 0.438 1.01 Salt water 0.442 1.02 Most sedimentary basins worldwide Salt water 0.452 1.04 North Sea, South China Sea Salt water 0.465 1.07 Gulf of Mexico, USA Salt water 0.478 1.10 Some areas of Gulf of Mexico Table 1.2 Average Normal Formation Pressure Gradients 1-10 March 1995 BP WELL CONTROL MANUAL 1.3 SUBNORMAL FORMATION PRESSURE Paragraph Page 1 General 1-12 2 Causes of Subnormal Formation Pressure 1-12 3 Magnitude of Subnormal Formation Pressures 1-15 4 Summary 1-16 Illustrations 1.3 1.4 1.5 Relationship between Piezometric Surface and Ground Level for an Aquifer System 1-13 Temperature-pressure-density diagram for Water illustrating Subnormal Pressures caused by Cooling an Isolated Fluid 1-14 Formation Foreshortening 1-15 1-11 March 1995 BP WELL CONTROL MANUAL 1 General Subnormal formation pressure is defined as any formation pressure that is less than the corresponding pore fluid hydrostatic pressure. A subnormal formation pressure gradient is thus any gradient less than the pore fluid hydrostatic gradient. Subnormal formation pressures are often termed subpressures. 2 Causes of Subnormal Formation Pressure Subnormal formation pressures occur less frequently than abnormally high formation pressures. They may have natural causes related to the stratigraphic, tectonic and geochemical history of an area, or may be caused artificially by producing reservoir fluids. (a) Depleted Reservoirs Producing large volumes of reservoir fluids causes a decline in pore fluid pressure unless compensated for by a strong water drive. Depleted reservoirs may thus have pore pressures less than hydrostatic. For example, the original reservoir formation pressure in BP’s Forties Field was 3215␣psi at a depth of 2175m subsea. This equates to a formation pressure gradient of 0.451␣psi/ft, which is the normal hydrostatic gradient. After twelve years production from the field and even with pressure boosting by water injection, the reservoir formation pressure dropped to approximately 2750 psi. This gives a subnormal pressure gradient of 0.385␣psi/ft. (b) Piezometric Surface A piezometric or potentiometric surface is an imaginary surface that represents the static head of ground water and is defined by the level to which the ground water will rise in a well. For example, the water table is a particular potentiometric surface. In very arid areas such as the Middle East, the water table may be deep. The hydrostatic pressure gradient commences at the water table giving a subnormal pressure gradient from the surface. A piezometric surface is dependent on the structural relief of a formation and can result in subnormal or abnormally high formation pressures. The piezometric surface for an aquifer system is shown in Figure 1.3. Drilling in mountainous areas may thus encounter subnormal pressure gradients due to the surface elevation being higher than the water table elevation or formation water potentiometric surface. (c) Temperature Reduction A reduction in subsurface temperature will reduce the pore pressure in an isolated fluid system where the pore volumes (and thus fluid density) remains constant. This may cause subnormal pressures. 1-12 March 1995 BP WELL CONTROL MANUAL INTAKE AREA ABNORMALLY HIGH PRESSURES SUBNORMAL PRESSURES PIEZOMETRIC SURFACE GROUND LEVEL HYDROSTATIC HEAD AQUIFER DISCHARGE AREA RESERVOIRS WEOX02.065 Figure 1.3 Relationship between Piezometric Surface and Ground Level for an Aquifer System The temperature-pressure-density diagram for water shown in Figure 1.4 illustrates this concept. Both temperature and pressure are dependent on depth. For a normal fluid (non-isolated) which is allowed to expand and contract freely, a temperature reduction associated with a depth change would follow the path indicated (which in this example corresponds to a temperature gradient of 2.5°C/100m). A lower pressure would result but it would still be equal to the normal hydrostatic pressure. In an isolated fluid system (ie/completely sealed shales), cooling must take place along a constant density path as shown. The pressure corresponding to the lower temperature is thus subnormal. If gas is present in the pores, the effects of temperature reduction will be greater as gas pressure is much more sensitive to temperature changes than water. Mechanisms which may create a reduction in subsurface temperature include uplift, erosion or a combination of uplift and erosion. (d) Decompressional Expansion Decompressional expansion is the term used to describe the combined effects of uplift and erosion. In shales, uplift and overburden removal by erosion may cause a reduction in pore fluid pressure. This reduction may be due to an increase in pore volume and removal of free water from the pore space by adsorption in clay minerals as the overburden pressure decreases. Water adsorption due to mineral transformations (eg/illite to montmorillonite) may also occur due to the decrease in temperature. (This is the reverse of ‘Clay diagenesis’ as described in Section 1.4 of this Chapter.) 1-13 March 1995 BP WELL CONTROL MANUAL DENSITY 0.98 1.0gm/cc 11 0.877 = Conditions at depth 2 0.909 = Initial conditions at depth 1 2 0.933 1 0.962 Figure 1.4 Temperature-pressure-density diagram for Water illustrating Subnormal Pressures caused by Cooling an Isolated Fluid 10 2.5 °C/ 100 m 9 8 PRESSURE 1000psi 7 6 PRESSURE AT DEPTH 1 1 5 PRESSURE AT DEPTH 2 FOR NORMAL FLUIDS 2 4 3 NORMAL FLUIDS ISOLATED FLUIDS 2 PRESSURE AT DEPTH 2 FOR ISOLATED FLUIDS 1 2 T2 0 50 T1 100 150 200 250 TEMPERATURE °C WEOX02.066 1-14 March 1995 BP WELL CONTROL MANUAL OVERPRESSURED A SUBNORMAL PRESSURE BED A P BED B P P B P OVERPRESSURED BED C C WEOX02.067 Figure 1.5 Formation Foreshortening This pressure reduction may be sufficient to cause subnormal pressures which would be transmitted to any reservoir rocks associated with the shales. (e) Formation Foreshortening This is a tectonic compression mechanism. It is suggested that during a lateral compression process acting on sedimentary beds, upwarping of the upper beds and downwarping of the lower beds may occur. The intermediate beds must expand to fill the voids left by this process, as shown in Figure 1.5. It is then possible for more competent intermediate beds, such as shales, to have subnormal pressures due to the increase in pore volume. This mechanism is thought to occur in areas of recent tectonic activity, such as along the flanks of the Rocky Mountains. (f) Osmosis Osmosis is the spontaneous flow of water from a more dilute to a more concentrated solution when the two are separated by a semi-permeable membrane. In the subsurface environment, clays and clayey siltstones can act as semi-permeable membranes. If salinity differences exist between the fluids in the sediments on either side of clay beds, then osmotic flow can occur. If the flow is from a closed volume, the pressure will decrease and may become subnormal. Likewise, if the flow is into a closed volume, abnormally high pressures may result. Osmosis is discussed in more detail in Section 1.4 of this Chapter. 1-15 March 1995 BP WELL CONTROL MANUAL 3 Magnitude of Subnormal Formation Pressures By definition, subnormal formation pressures must be lower than the normal hydrostatic pressure for the location. In terms of pressure gradients, subnormal pressures will have gradients less than normal (0.433 to 0.465 psi/ft depending on the particular area). As previously discussed, the Forties Field reservoir is now subnormally pressured at 0.385␣psi/ft. Subnormal gradients of 0.36 to 0.39 psi/ft have been quoted for areas of the Texas Panhandle (NW Texas) with one case as low as about 0.23 psi/ft thought to be the result of a low piezometric surface. One of the lowest formation pressure gradients encountered is 0.188 psi/ft which was recorded in the Keyes gas field in Oklahoma. 4 Summary The various suggested causes of subnormal formation pressures can be classed as ‘artifically caused’ or ‘naturally caused’. ‘Depleted reservoirs’ and ‘piezometric surface’ (where pressure regime depends on the surface location of the well) may be classed as artificial causes, since these subnormal pressures do not originate in the subsurface formation, but are externally influenced. Conversely, the other causes of subnormal pressure discussed have origins in the formations themselves and can be thought of as being naturally caused. It is unlikely that any one of these processes may be the sole cause of subnormal pressures in any particular area. It is probable that a number of processes have contributed to produce the subnormal pressures, particularly in the light of the dependency of the processes on depth and temperature. 1-16 March 1995 BP WELL CONTROL MANUAL 1.4 ABNORMALLY HIGH FORMATION PRESSURE Paragraph Page 1 General 1-18 2 Causes of Abnormally High Formation Pressure 1-18 3 Magnitude of Abnormally High Formation Pressures 1-30 4 Summary 1-31 Illustrations 1.6 Typical Formation Pressures caused by Compaction Disequilibrium 1-19 1.7 Interlayer Water and Cations between Clay Platelets 1-20 1.8 Schematic of Reaction of Montmorillonite to Illite 1-21 1.9 Water Distribution Curves for Shale Dehydration 1-23 1.10 Diagenetic Stages in the alteration of Montmorillonite to Illite 1-23 1.11 Abnormal Formation Pressures caused by Tectonic Compressional Folding 1-24 1.12 Abnormal Pressure Distribution around a Piercement Salt Dome 1-26 1.13 Schematic Diagram of a Mud Volcano 1-26 1.14 Abnormally High Pressure due to Reservoir Structure 1-28 1.15 Schematic Diagram illustrating Osmotic Flow 1-30 1-17 March 1995 BP WELL CONTROL MANUAL 1 General Abnormally high formation pressure is defined as any formation pressure that is greater than the hydrostatic pressure of the water occupying the formation pore spaces. Abnormally high formation pressure gradients are thus any formation pressure gradient higher than the pore fluid hydrostatic pressure gradient. Abnormally high formation pressures are also termed surpressures, overpressures and sometimes geopressures. More often, they are simply called abnormal pressures. 2 Causes of Abnormally High Formation Pressure Abnormally high formation pressures are found worldwide in formations ranging in age␣from the Pleistocene age (approximately 1 million years) to the Cambrian age (500 to 600␣million years). They may occur at depths as shallow as only a few hundred feet or exceeding 20,000␣ft (6100m) and may be present in shale/sand sequences and/or massive evaporite-carbonate sequences. The causes of abnormally high formation pressures are related to a combination of geological, physical, geochemical and mechanical processes, as discussed in the following paragraphs. (a) Depositional Causes • Compaction Disequilibrium Compaction disequilibrium is also known as ‘undercompaction’ or ‘sedimentary loading’. It is the process whereby abnormal formation pressures are caused by a disruption in the balance between the rate of sedimentation of clays and the rate of expulsion of the pore fluids, as the clays compact with burial. Freshly deposited clays have adsorbed water layers and the solid clay particles do not have direct physical contact. The pore pressure is hydrostatic as the pore fluid is continuous with the overlying sea water. As sedimentation proceeds, a gradual compaction occurs and as the clay particles are pressed closer together, pore water is expelled. The clay sediment has high porosity and is permeable in this initial state. So as long as the expelled water can escape to surface or through a porous sand layer, pore pressures will remain hydrostatic. For this equilibrium to be maintained, a balance is required between the rate of sedimentation and burial, and the rate of expulsion and removal of pore fluids. If the rate of sedimentation is very slow, then hydrostatic pressures will be maintained. The initial porosity of clays is 60 to 90%, depending on the type of clay, whereas compacted clay/shale has a porosity of less than 15%. Thus a vast amount of water must be removed from clay sediments during burial. If the equilibrium between rate of sedimentation and rate of fluid expulsion is disrupted, such that fluid removal is impeded, then an increase in pore pressure will result. This could occur either by an increase in the rate of sedimentation or by a reduction in the rate of fluid removal (caused by a reduction in permeability or by the deposition of a permeability barrier such as limestone). 1-18 March 1995 BP WELL CONTROL MANUAL The ‘excess’ pore fluids help support the increasing overburden load, thereby retarding compaction further, and resulting in abnormally high pressured formations. Abnormal pressures resulting from this process will have a gradient no greater than the overburden gradient. This is because these pressures are produced by the excess overburden load being supported by the pore fluids. If beds of permeable sandstone that are hydraulically connected to zones of lower fluid pressure are present within an overpressured zone, adjacent clays will dewater to the sand bed. The adjacent clays will compact and decrease in permeability and porosity thus restricting further dewatering of the clay beds. The local pressure gradient across these clay/sand boundaries will be significantly higher than the overall pressure gradient, but are caused purely by ‘leakage’ from the clays to the sand. Figure 1.6 illustrates typical overpressures caused by compaction disequilibrium. Areas in which abnormal formation pressures associated with high sedimentation rates have been encountered include the North Sea, the Gulf of Mexico, and the Gulf of Papua. Hydrostatic pore pressure Overburden pressure Actual formation pressure DEPTH Very high local pressure gradient adjacent to permeable zones due to low permeability of the clays CLAY Overall formation pressure parallels the overburden pressure gradient, but may not reach extrapolated pressure gradient due to leakage from the clays SAND CLAY SAND Extrapolated initial formation pressure (parallel to overburden pressure gradient) CLAY SAND Overpressured sandstone (hydrostatic gradient within sandstone) CLAY SAND PRESSURE WEOX02.068 Figure 1.6 Typical Formation Pressures caused by Compaction Disequilibrium 1-19 March 1995 BP WELL CONTROL MANUAL • Rock Salt Deposition Continuous rock salt deposition over large areas can cause abnormal pressures that may approach overburden pressure. Salt is totally impermeable to fluids and behaves plastically at relatively low temperatures and pressures, thereby exerting pressures equal to the overburden load in all directions. The fluids in the underlying formations can not escape as there is no communication to the surface and thus the formations become overpressured. Massive rock salt deposits are commonly found in the southern North Sea with abnormally high formation pressures sometimes being encountered in formations below or within these massive salts. For instance, one BP southern North Sea well required mud weights up to 1.94 SG (0.84 psi/ft) to control a saturated salt water flow from an anhydrite formation at the boundary between the Z2 and Z3 Units of the Zechstein halite formation. (b) Diagenesis Diagenesis is the alteration of sediments and their constituent minerals during burial after deposition. Diagenetic processes include the formation of new minerals, the redistribution and recrystallisation of the substances within the sediments, and lithification (sediments turning into rocks). Negative Charge Imbalance CLAY SHEET H H H H H H O H H H H H Na + O O O H H H O O H H O Na + Ca + + O O H Ca + + H O H O About 4 Layers of Structured Water O O Na + H 1 or 2 Layers of Adsorbed Water H H H H H H O H O O H H H H O O Ca + + H H H H H CLAY SHEET WEOX02.069 Figure 1.7 Interlayer Water and Cations between Clay Platelets 1-20 March 1995 BP WELL CONTROL MANUAL • Clay Diagenesis The major constituents of marine shales are bentonitic clays of which montmorillonite is by far the most common. Montmorillonite has a swelling (expanded) lattice structure and contains approximately 70 to 85% water at initial burial in sea floor sediments. This water is present in the form of at least four layers of molecules adsorbed between clay platelets and up to ten layers held on the outside of the platelets. The clay platelets have a negative charge imbalance due to their structure. This causes the adsorption of interlayer water together with various cations (positively charged ions), principally sodium (Na +) and calcium (Ca++). The interlayer water is shown schematically in Figure 1.7. The environment at this initial burial stage would be alkaline, rich in calcium and magnesium (and of course sodium from salt water), but poor in potassium. After further burial, compaction expels most of the free pore water (non-adsorbed) and the water content of the sediment is reduced to about 30%. As burial progresses and the temperature increases, eventually all but the last layer of structured (adsorbed) water will be desorbed to the pore spaces. This causes the clay lattice to collapse and with the availability of potassium, montmorillonite diagenesis to illite occurs. This reaction is shown schematically in Figure 1.8. It involves adsorption of potassium at the interlayer and surface sites as well as the release of a small amount of silica. O O M A O O A A W + W W W W W + W W 3 LAYER SHEET W W W W + W W Add K Substitute Al for Si and Mg K INTERLAYER SITES A Charge Satisfied O 3 LAYER SHEET A A O O A A O ILLITE Ky AL4 (Si8-y, Aly) O20 (OH)4 = Oxygen M = Magnesium = Silicon W = Water O = Hydroxyl (OH) K = Potassium A = Aluminium + = Cation eg Ca ++, Na+ MONTMORILLONITE (Al4-x Mgx)(Si8-y, Aly) O20 (OH)4 Negatively charged plates satisfied by interlayer water and cation adsorption WEOX02.070 Figure 1.8 Schematic of Reaction of Montmorillonite to Illite 1-21 March 1995 BP WELL CONTROL MANUAL The reaction is temperature (and hence depth) dependent. Initial dehydration may occur at temperatures as low as 6°C. Most of the interlayer water is liberated between 100°C and 250°C, but some of the more structured water remains to about 300°C. Water distribution curves showing the various shale dehydration stages are shown in Figure 1.9. At the second dehydration stage (See Figure 1.9), the water that is released expands due to a density reduction from the highly structured phase to the pore phase. Thus abnormally high pressures may result, particularly if the rate of expulsion of free pore water from the clay body is less than the rate of water release from the clay interlayers. Figure 1.10 is a schematic diagram showing the stages of alteration of montmorillonite to illite. If water escape from the clay body is restricted, the silica released in the diagenetic process will precipitate in the pore spaces. This may further reduce permeability and so assist in developing abnormal pressures. • Sulphate Diagenesis Diagenesis in sulphate formations (gypsum, anhydrite) may cause abnormal pressures by creating permeability barriers, a fluid source and/or a rock volume change. Carbonate reservoirs are commonly overlain by evaporite sections (salt, anhydrite). Anhydrite (calcium sulphate, CaSO4) is formed by the dehydration of gypsum (CaSO4.2 H 2O) which liberates large amounts of water. There is a 30% to 40% shrinkage in formation thickness associated with this process. If this occurs at depth and in the presence of a permeability barrier, abnormal formation pressures may result. (The anhydrite itself is totally impermeable and may act as a vertical permeability barrier.) This process may have been the cause of the high pressure salt water flow discussed under ‘Rock Salt Deposition’ in (a) ‘Depositional Causes’. Here, a mud weight of 1.94 SG (0.84 psi/ft) was required to control a saturated salt water flow from an anhydrite section sandwiched between massive salt sections. The process is, however, reversible. Anhydrite can take on water to form gypsum. There is an intermediate semi-hydrate stage (CaSO4.1/2 H2O) in which the rock volume would increase by 15 to 25%. If such rehydration was to occur at depth in a closed system, very high abnormal pressures could be developed. • Diagenesis of Volcanic Ash Diagenesis of volcanic ash results in three main products: clay minerals, methane and carbon dioxide. Thus formations that originally contained large amounts of volcanic ash may become overpressured due to the production of gases from the volcanic ash. Areas in which this process has occurred include the NW coast of the USA and areas of the South China Sea region (Java, etc). 1-22 March 1995 BP WELL CONTROL MANUAL WATER ESCAPE CURVE (SCHEMATIC) WATER CONTENT OF SHALES WATER AVAILABLE % WATER FOR MIGRATION 0 10 20 30 40 50 60 70 80 SEDIMENT SURFACE PORE WATER BURIAL DEPTH (SCHEMATIC) PORE AND INTERLAYER WATER EXPULSION 1st DEHYDRATION AND LATTICE WATER STABILITY ZONE LATTICE WATER STABILITY ZONE INTERLAYER WATER 2nd DEHYD'N STAGE INTERLAYER WATER ISOPLETH 3rd DEHYDRATION STAGE DEEP BURIAL WATER LOSS 'NO MIGRATION LEVEL' WEOX02.071 Figure 1.9 Water Distribution Curves for Shale Dehydration STAGE 1 Before diagenesis (about 3000 – 6000ft, below 60°C) porosity = 20 to 35% clay is 70% montmorillonite 10 mixed layer 20% other MOST WATER IS BOUND WATER LOW POROSITY STAGE 2 FREE PORE WATER FROM DESORBED INTERLAYER WATER During alteration to illite (100 – 200°C) high porosity = 30 to 40% clay is 20% montmorillonite 60% illite 20% other CLAY RELEASES SILICA, ADSORBS POTASSIUM NOTE PARTICLE COLLAPSE STAGE 3 After diagenesis and compaction (over 200°C) porosity = 10 to 20% clay is 70% illite 10% montmorillonite 20% other LOW POROSITY VERY LITTLE BOUND WATER VOLUME LOST WEOX02.072 Figure 1.10 Diagenetic Stages in the alteration of Montmorillonite to Illite 1-23 March 1995 BP WELL CONTROL MANUAL (c) Tectonic Causes • Compressional Folding Tectonic compression is a compacting force that is applied horizontally in subsurface formations. In normal pressure environments, clays compact and dewater in equilibrium with increasing overburden pressures. However, in a tectonic environment, the additional horizontal compacting force (tectonic stress) squeezes the clays laterally. If conditions are such that the pore fluids can still escape, then pore fluid pressures will remain normal. However, it is more likely that the increase in stress will cause disequilibrium. The pore fluids will not be able to escape at a rate equal to the reduction in pore volume, resulting in an increase in pore pressure. Abnormal pressure distribution within a series of compressional folds is shown in Figure 1.11. Abnormally high pressures occur initially within the hinge portion of each compressional fold in a thick clay sequence. EXTENSION EXTENSION COMPRESSION COMPRESSION COMPRESSION COMPRESSION AMOUNT OF SHORTENING POSSIBLE OVERPRESSURED ZONES WEOX02.073 Figure 1.11 Abnormal Formation Pressures caused by Tectonic Compressional Folding An example of overpressures associated with steep tectonic folding is the oilfields of Southern Iran where local pressure gradients as high as 1.00 psi/ft can be encountered. Also, one of the highest formation pressures reported of 1.3 psi/ft was recorded in the tectonically folded Himalayan foothills in Pakistan. 1-24 March 1995 BP WELL CONTROL MANUAL • Faulting Faults may cause abnormally high formation pressures in the following ways: – Slippage of formations along a fault may bring a permeable formation, eg a sand bed, laterally against an impermeable formation such as a clay. Thus, the flow of pore fluids through the permeable zone will be inhibited and abnormally high formation pressures may result. – Non-sealing faults may transmit fluids from a deeper permeable formation to a␣ s hallower formation. If this shallower formation is sealed, then it will be␣ p ressured up by the deeper formation. (See ‘Char ged Formations’ in (d) ‘Structural Courses’). • Uplift If a normally pressured formation is suddently uplifted, abnormally high pressures may be generated. Uplift is not a unique cause of abnormal pressure as the process that uplifts a buried formation will also uplift the overburden. For abnormal pressures to occur, there must be a concurrent geological process that reduces the relief between the buried formation and the surface. Such processes may be piercement salt domes, shale diapirs, faulting or erosion. Note that uplift and erosion may also cause subnormal formation pressures, depending on the type of formation and the amount of cooling that the formation undergoes. (See ‘Temperature Reduction’ and ‘Decompressional Expansion’ in Section 1.3 of this Chapter.) • Salt Diapirism Diapirism is the piercement of a formation by a less dense underlying formation. Salt will behave plastically at elevated temperatures and pressures and due to its lower density, will move upwards to form piercement salt domes in overlying formations. This upward movement disturbs the normal layering of sediments and overpressures can often occur due to the associated faulting and folding action. Additionally, the salt may act as an impermeable seal and inhibit lateral dewatering of clays thereby further contributing to the generation of abnormal pressures. The typical distribution of abnormal pressure zones around a piercement salt dome is shown in Figure 1.12. Abnormally high formation pressures associated with salt domes have been encountered worldwide, both onshore and offshore. • Shale Diapirism As with salt diapirism, this mechanism refers to the upward movement of a less dense plastic formation. In this case, high porosity (high water content) shales behave␣plastically causing the formation of shale diapirs called ‘mud volcanoes’ (See Figure 1.13). In practice, wherever mud volcanoes occur, there has been rapid Tertiary and/or late Cretaceous sedimentation. This rapidly loads underlying shales of low shear strength causing the formation of mud volcanoes. Formation pressures are abnormally high. For example, pressure gradients of 0.9 psi/ft have been measured around mud volcanoes on Aspsheron Peninsula in Azerbaidzhan, USSR. 1-25 March 1995 BP WELL CONTROL MANUAL SAND HORIZON BASIN WARD A A B C HORIZON B C D E D E SALT ABNORMAL PRESSURE WEOX02.074 Figure 1.12 Abnormal Pressure Distribution around a Piercement Salt Dome MUD VOLCANO UPPER MIOCENE SEA LEVEL MIDDLE MIOCENE LOWER MIOCENE 0 Mile 5000ft 1 WEOX02.075 Figure 1.13 Schematic Diagram of a Mud Volcano 1-26 March 1995 BP WELL CONTROL MANUAL • Earthquakes Earthquakes may cause compression in subsurface formations which causes a sudden increase in pore fluid pressures. For example, the 1953 earthquake in California caused production in the nearby Mountain View oil field to double over a period of several weeks after the earthquake. (d) Structural Causes • Piezometric Surface This is defined in Section 1.3. A regionally high piezometric surface, such as that caused by artesian water systems, will result in abnormally high pressures as shown in Figure 1.3. Artesian systems require a porous and permeable aquifer sandwiched between impermeable beds. The aquifer intake area must be high enough for the abnormal pressure to be caused by the hydrostatic head. Examples of areas where abnormally high pressures are caused by artesian systems are the Artesian Basin in Florida and the Great Artesian Basin in Queensland, Australia. • Reservoir Structure In sealed reservoir formations containing fluids of differing densities (ie water, oil, gas), formation pressures which are normal for the deepest part of the zone will be transmitted to the shallower end where they will cause abnormally high pressures. Examples of such formation are lenticular reservoirs, dipping formations and anticlines. Abnormal formation pressures will only be generated if fluids less dense than the pore water are present, such as in oil/gas reservoirs. The pressure at the top of a fluid zone is given by: P fT = PfB – [Gf X (DB where P fT P fB Gf DT DB = = = = = X D T)] (1-15) formation pressure at top of zone (psi) formation pressure at bottom of zone (psi) pressure gradient of fluid in zone (psi/ft or psi/m) vertical depth to top of zone (ft or m) vertical depth to bottom of zone (ft or m) In the example shown in Figure 1.14, the formation pressure at the oil/water contact is normal hydrostatic pressure with a gradient of 0.452 psi/ft. Using equation 1-15, the pressure at the gas/oil contact is 4850 psi which gives an abnormally high formation pressure gradient of 0.462 psi/ft. Similarly, the pressure at the top of the reservoir is 4784 psi giving an abnormal gradient of 0.486 psi/ft. Obviously, in very large structures, especially in gas/water systems with long gas columns, the overpressures developed at the top of the gas column may be very high. Indeed one documented example in Iran quotes a pressure gradient of 0.9 psi/ft (approaching overburden gradient) at a depth of only 640 ft (195m). 1-27 March 1995 BP WELL CONTROL MANUAL DEPTH CAP ROCK TOP OF GAS CAP D = 3000m (D = 9842ft) GAS (Gf = 0.1psi/ft) GAS/OIL CONTACT D = 3200m (D = 10500ft) OIL (Gf = 0.325psi/ft) OIL/WATER CONTACT D = 3450m (D = 11319ft) WATER (Gf = 0.452psi/ft) At top of reservoir: Pf = 4850 – 0.1 x (10500 – 9842) Pf = 4784psi . . . FPG = 4784 = 0.486psi/ft 9842 At gas/oil contact: Pf = 5116 – 0.325 x (11319 – 10500) Pf = 4850psi . . . FPG = 4850 = 0.462psi/ft 10500 At oil/water contact: NORMAL HYDROSTATIC PRESSURE GRADIENT OF 0.452psi/ft Pf = 11319 x 0.452 Pf = 5116psi WEOX02.076 Figure 1.14 Abnormally High Pressure due to Reservoir Structure • Charged Formations Normally pressured, or low pressured porous and permeable formations at shallow depths, may be pressured up by communication with deeper higher pressured formations. This ‘charging’ of the shallower formations may take place by fluid communication along non-sealing faults behind casing in old wells, or wells with faulty cement jobs, and whilst drilling a sequence of permeable formations with very large differences in pore fluid pressures (causing recharge salt water flows). Abnormal pressures caused by recharge can be very high, especially if gas is the medium that transmits the pressure (same mechanics as gas reservoir in ‘Reservoir Structure’, but over greater depth differences). Mud weights as high as 19 ppg (2.28␣SG, 0.988 psi/ft) have been quoted as sometimes required for drilling through shallow charged zones. (e) Thermodynamic Effects Thermodynamic processes may be considered as contributing factors in most of the causes of abnormally high formation pressure already discussed. Formation temperature increases with depth in any geological system and if the system is essentially closed, thermodynamic effects will add to the build up of abnormal pressures. • Aquathermal Pressuring Referring to the temperature-pressure-density diagram for water (Figure 1.4), a temperature increase in an isolated fluid system must take place along a constant density path. The increase in pressure is thus very rapid and only small increases in temperature are required to produce large overpressures. 1-28 March 1995 BP WELL CONTROL MANUAL However, shales are not totally impermeable and the time taken to heat the shales during burial should be sufficient to allow most of the excess pressures developed to leak away. The main effect of heating during burial is to retard compaction, and aquathermal pressuring is not thought to be a major cause of abnormally high formation pressures. • Thermal Cracking At high temperatures and pressures caused by deep burial, complex hydrocarbon molecules will break down into simpler compounds. Thermal cracking of hydrocarbons will increase the volume of the hydrocarbons in the order of two to three times the original volume. If contained in an isolated system, this would result in high overpressures being developed. However, there is no conclusive evidence that thermal cracking is a significant cause of abnormal formation pressures. • Permafrost In arctic regions, drilling and production operations may cause extensive thawing of the permafrost. If this thawed permafrost refreezes later in the life of the well, ‘freezeback’ pressures, high enough to damage the casing, may result. Obviously, this situation may be avoided by proper well planning and casing design. Freezeback pressure gradients ranging from 0.66 psi/ft to as high as 1.44 psi/ft have been recorded in Alaska. • Osmosis As defined in Section 1.3, osmosis is the spontaneous flow of water from a more dilute to a more concentrated solution when the two are separated by a suitable semi-permeable membrane. This action is represented schematically in Figure 1.15. For a given solution, the osmotic pressure (differential pressure across the membrane) is almost directly proportional to the concentration differential; and for a␣given␣concentration dif ferential the osmotic pressure increases with temperature. Theoretically, osmotic pressures of up to 4500 psi can be produced across a semi-permeable membrane with solutions of 1.02 gm/cc NaCl in water and saturated NaCl␣brine. Clay and clayey siltstone beds can act as semi-permeable membranes. If salinity differences exist in the sediments above and below such beds, then osmotic flow can occur. If the flow is into an isolated system, then a pressure increase will occur in this system. Alternatively, the osmotic pressure developed across these beds may inhibit the vertical flow of water from compacting shales, thereby contributing to the development of abnormal pressures. However, the efficiency of clay beds as semi-permeable membranes in the sub-surface environment is unknown. It is thus currently believed that osmosis is a minor cause of abnormal formation pressures. 1-29 March 1995 BP WELL CONTROL MANUAL LIQUID PRESSURE DECREASES LIQUID PRESSURE INCREASES 0 0 3 1 3 2 1 2 H2O H2O H2O Na+ H2O CINa+ SALINE WATER H2O CLAY MEMBRANE FRESH WATER CI- H2O OSMOTIC H2O FLOW WEOX02.077 Figure 1.15 Schematic Diagram illustrating Osmotic Flow 3 Magnitude of Abnormally High Formation Pressures As defined, the magnitude of abnormally high formation pressures must be greater than the normal hydrostatic pressure for the location, and may be as high as the overburden pressure. Abnormally high pressure gradients will thus be between the normal hydrostatic gradient (0.433 to 0.465 psi/ft) and the overburden gradient (generally 1.0 psi/ft). However, locally confined pore pressure gradients exceeding the overburden gradient by up to 40% are known in areas such as Pakistan, Iran, Papua New Guinea, and the USSR. These superpressures can only exist because the internal strength of the rock overlying the superpressured zone assists the overburden load in containing the pressure. The overlying rock can be considered to be in tension. In the Himalayan foothills in Pakistan, formation pressure gradients of 1.3 psi/ft have been encountered. In Iran, gradients of 1.0 psi/ft are common and in Papua New Guinea, a gradient of 1.04 psi/ft has been reported. In one area of Russia, local formation pressures in the range of 5870 to 7350 psi at 5250 ft (1600m) were reported. This equates to a formation pressure gradient of 1.12 to 1.4 psi/ft. 1-30 March 1995 BP WELL CONTROL MANUAL In the North Sea abnormal pressures occur with widely varying magnitudes in many geological formations. The Tertiary sediments are mainly clays and may be overpressured for much of their thickness. Pressure gradients of 0.52 psi/ft are common with locally occurring gradients of 0.8 psi/ft being encountered. An expandable clay (gumbo) also occurs which is of volcanic origin and is still undergoing compaction. The consequent decrease in clay density would normally indicate an abnormal pressure zone but this is not the case. However, in some areas, mud weights of the order of 0.62 psi/ft (1.43 SG) or higher are required to keep the wellbore open because of the swelling nature of these clays. This is almost equal to the low overburden gradients in these areas. In the Mesozoic clays of the Central Graben, overpressures of 0.9 psi/ft have been recorded. One BP well encountered a formation pressure gradient of 0.91 psi/ft in the Jurassic section. In the Jurassic of the Viking Graben, abnormal formation pressure gradients up to 0.69␣psi/ft have been recorded. In Triassic sediments, abnormally high formation pressures have been found in gas bearing zones of the Bunter Sandstone in the southern North Sea. Also in the southern North Sea, overpressures are often found in Permian carbonates, evaporates and sandstones sandwiched between massive Zechstein salts. 4 Summary Of all the processes that may be responsible for causing abnormally high formation pressures, it is unlikely that any one will be the sole cause in any particular area. The effects of several processes will probably combine to cause the observed abnormal pressure. Certain processes are thought to be either ineffective or uncommon as causes of abnormal pressures. These include uplift (as a sole mechanism), osmosis, thermal cracking, permafrost and earthquakes. A recent report(6) has found that the most significant cause of abnormally high formation pressures in depositional basins is compaction disequilibrium, with aquathermal pressuring contributing to a small extent. Clay dewatering (diagenesis) was found to have little effect. However conditions within clays during dewatering are very similar to these developed during undercompaction; and the two processes probably occur concurrently, while undercompaction is recognised as the primary mechanism. The significance of aquathermal pressuring as a cause of abnormal pressure is temperature and hence depth dependent. This is also true of the diagenetic process. With increasing depth aquathermal pressuring is thought to be a contributory factor in all cases of abnormal pressure generation. 1-31 1-31/32 March 1995 BP WELL CONTROL MANUAL 1.5 SHALLOW GAS Paragraph Page 1 General 1-34 2 Definition 1-34 3 Origins of Shallow Gas 1-34 4 Characteristics of Shallow Gas 1-35 1-33 March 1995 BP WELL CONTROL MANUAL 1 General Shallow gas accumulations present a major hazard to drilling operations. Gas influxes taken at shallow depths cannot generally be shut-in for fear that the pressures involved will fracture the formation at the previous casing shoe, thereby causing an underground blowout, or flow around the casing to the seabed. 2 Definition For the purposes of drilling operations, shallow gas can be defined as any gas accumulation encountered at any depth before the first pressure containment casing string is set. For well planning purposes, possible gas bearing zones at shallow depths may be identified from shallow seismic sections (‘bright spot’ technique – See Section 2.2 of Chapter 2). These are normally used down to a depth of about 1000m below surface or mudline. 3 Origins of Shallow Gas There are two potential origins of shallow gas: (a) Biogenic Generation This is the production of gas at shallow depths of burial from the degradation of organic matter within the sediment. An example of this would be the Pleistocene section of the North Sea which contains some organic rich clays and occasional peat/lignite formations. Thus a biogenic origin is considered likely for shallow gas accumulations in the North␣Sea. (b) Petrogenic Generation This is the thermocatalytic degradation of kerogen which occurs under conditions of elevated temperature and pressure at greater depths. (Kerogen is a complex hydrocarbon formed from the biogenic degradation of organic matter which also gives gas as stated above.) Sufficient depth of burial to produce the heat necessary for this process to operate is probably not reached in the shallow depths considered here ie down to 1000m. However, migration of gas from deeper petrogenic sources may be possible. This could occur naturally, along non-sealing faults for example, or even through the natural permeability of clays at shallow depths. Alternatively, artificial migration paths may be produced in poorly cemented casing annuli allowing gas from petrogenic sources to accumulate in shallower formations. This could result in shallow gas accumulations forming later in the life of a producing field when early wells showed no indication of shallow gas. 1-34 March 1995 BP WELL CONTROL MANUAL 4 Characteristics of Shallow Gas (a) Composition Shallow (biogenic) gas has the following typical composition (provided by BP/Sunbury): 99% + methane (CH 4) 0.5% carbon dioxide (CO2 ) less than 0.5% nitrogen (N2 ) less than 0.1% ethane (C 2H6 ) and higher hydrocarbons. Hydrogen sulphide (H 2S) may also be present. Petrogenic gas associated with the generation of oil should contain a larger proportion of ethane and higher hydrocarbons. (b) Configuration of Shallow Gas Accumulations Shallow gas accumulations are commonly found in sand lenses which are inferred to have been deposited in a shallow marine shelf environment with tidal influence. In this environment, the sands would tend to be in the form of sand waves, sand patches and ridges resulting in a discontinuous and patchy distribution. These sand lenses could thus be sealed by the surrounding clay sediments. This patchy distribution of shallow gas is very important. It must not be assumed that because several wells have penetrated a potential shallow gas zone successfully, then all future wells will also be free of shallow gas hazards. (c) Pressures and Volumes Most shallow gas accumulations tend to be normally pressured. However, the classic area where overpressured shallow gas sands are encountered is the Gulf of Mexico, USA. In this area, overpressuring is thought to be the result of undercompaction of shales due to rapid deposition (See ‘Compaction Disequilibrium’, Section 1.4 of this Chapter.) One instance of overpressured shallow gas in the North Sea was reported for a well in the SE Forties area where a gas kick from a sand at about 800m subsea gave a calculated formation pressure gradient of at least 1.20 SG (0.52 psi/ft). Shallow gas accumulations resulting from migration of petrogenic gas may well be overpressured (See ‘Charged Formations’, Section 1.4). Also, overpressured shallow gas may result from long ‘tilted’ sand lenses, in an identical manner to that described under ’Reservoir Structure’, also in Section 1.4. It is difficult to estimate the volumes of gas present in shallow gas accumulations. However, estimates have been made from shallow gas discharges. In one North Sea incident, it has been estimated that 8 mmscf of gas was vented. At a depth of about 410m subsea and 600 psi pressure, this corresponds to a bulk rock volume of 20,000 cubic metres, assuming a porosity of 30%. For a 5m thick sand, this corresponds to an area of only 70m in diameter. The flowrate of gas in the above incident was estimated at 40 to 50 mmscfd. Flowrates of over 100 mmscfd have been reported for shallow gas blowouts in the Gulf of Mexico. These high flowrates are as a result of the high porosity and permeability in shallow large grain sand deposits. 1-35 March 1995 BP WELL CONTROL MANUAL Suggestions for further reading: 1. ‘EXLOG’, 1981. Theory and Evaluation of Formation Pressures. Exploration Logging Inc., USA. 2. ‘EXXON’, 1975 Abnormal Pressure Technology. Exxon Company, USA. 3. FERTL, W.H., 1976. Abnormal Formation Pressures. Elsevier Scientific Publishing Company, Amsterdam. 4. FERTL, W.H. and CHILINGARIAN, G.V., 1976. Importance of Abnormal Pressures to the Oil Industry. Soc. Petrol. Eng., Paper 5946. 5. ‘GEARHART’, 1986. Overpressure. Gearhart Geodata Services Ltd., Aberdeen. 6. MANN, D.M., 1985. The Generation of Overpressures During Sedimentation and Their Effects on the Primary Migration of Petroleum. Report GCB/156/85. BP Research Centre, Sunbury. 7. SELLEY, R.C., 1985. Elements of Petroleum Geology. W.H. Freeman and Company, New York. 8. SHEPHERD, M., 1984. Forties Field: Shallow Gas Hazards in the Main Field Area. Report GL/AB/1880. BPPD Aberdeen. 1-36 March 1995 BP WELL CONTROL MANUAL 2 FORMATION PRESSURE EVALUATION Section 2.1 INTRODUCTION 2-1 2.2 FORMATION PRESSURE EVALUATION DURING WELL PLANNING 2-5 2.3 FORMATION PRESSURE EVALUATION WHILST DRILLING 2-23 2.4 FORMATION PRESSURE EVALUATION AFTER DRILLING 2-65 March 1995 BP WELL CONTROL MANUAL 2.1 INTRODUCTION Paragraph Page 1 General 2-2 2 The Transition Zone 2-2 Techniques used to Predict, Detect and Evaluate Formation Pore Pressures 2-3 Table 2.1 2-1 March 1995 BP WELL CONTROL MANUAL 1 General Knowledge of formation pore pressure is of prime importance in the planning, drilling and evaluation of a well. Good estimates of formation pore pressures and fracture pressures are required to optimise casing and mud weight programmes, and to minimise the risk of well kicks, stuck pipe, lost circulation and other costly drilling problems. The following sections describe the techniques used to predict, detect and evaluate formation pore pressures at the various stages of drilling a well. Table 2.1 summarises these techniques. Methods for predicting and evaluating fracture pressure are covered separately in a later section of this Manual. Abnormally high pressured zones are by far the most common encountered, and the most important, in drilling operations. This Chapter is therefore mainly concerned with methods of predicting, detecting and evaluating abnormally high formation pressures. 2 The Transition Zone Formation pressure gradients are considered to be the normal hydrostatic gradient for the area until a depth is reached where various pressure indicators suggest the onset of either a subnormally or an abnormally high pressured zone. The zone in which the formation pressure gradient changes from normal to subnormal or abnormally high gradient is known as the transition zone. In shales, the transition zone is the equivalent of the pressure seal discussed in Section 1.1 of Chapter 1. Since perfect seals of zero permeability rarely occur (except, for example, salt and anhydrite), transition zones are normally present. The differential pressure across a transition zone causes pore fluid flow through the transition zone. However, the flow rate through the zone will be extremely low, due to the very low permeability within the zone. The thickness of the transition zone depends on the permeabilities within and adjacent to the overpressured formation and the age of the overpressure ie, the time available for fluid flow and pressure depletion since the overpressure developed. The presence of the transition zone is very important in formation pressure evaluation. Formation properties in this zone often show a change away from normally pressured depth related trends. The magnitude of the change in the trend can sometimes be used to estimate the change in the formation pressure gradient. The parameters used to monitor the trends in formation properties are listed in Table 2.1. It must be realised that the start of the transition zone marks the onset of abnormal pressures. Every effort must be made to recognise the start of this zone both in well planning and during drilling. 2-2 March 1995 BP WELL CONTROL MANUAL Table 2.1 Techniques used to Predict, Detect and Evaluate Formation Pore Pressures Data Source Pressure Data/Indicators Stage of Well Offset wells Mudloggers reports Mud weights used Kick data Wireline log data Wireline formation test data Drillstem test data Planning (also used for comparisons whilst drilling) Geophysics Seismic (interval velocity) Planning Drilling parameters Drilling rate Drilling exponents Other drilling rate methods Torque Drag MWD logs While drilling Drilling mud parameters Gas levels Flowline mud weight Flowline temperature Resistivity, salinity and other mud properties Well kicks Pit levels Hole fill-up Mud flow rate While drilling (delayed by the time required for mud return) Cuttings parameters Bulk density Shale factor Volume, shape and size Miscellaneous methods While drilling (delayed by the time required for mud return) Wireline logs Sonic (int. transit time) Resistivity log Density log Other logs After drilling Direct pressure measurements Wireline tests (RFT/FIT) Drillstem tests Well testing or completion 2-3/4 2-3 March 1995 BP WELL CONTROL MANUAL 2.2 FORMATION PRESSURE EVALUATION DURING WELL PLANNING Paragraph Page 1 General 2-6 2 Offset Well Data 2-6 3 Seismic Data 2-8 3.1 Abnormal Pressure Evaluation from Seismic Data 2-9 4 3.2 Identifying Shallow Gas Hazards 2-20 Summary 2-21 Illustrations 2.1 Pressure/Depth Plot 2-7 2.2 Schematic Diagram illustrating Seismic Reflection System and Seismic Traces 2-9 2.3 Schematic Diagram showing Common Depth Point (CDP) Seismic Ray Paths 2-10 Schematic Plot of Offset versus Two Way Travel Time for Common Depth Point System 2-11 2.5 Example Seismic Velocity Analysis Plot 2-13 2.6 Example of Stacking Velocity Data on a Seismic Section 2-14 2.7 Seismic and Sonic ITT versus Depth Plots for Abnormally Pressured Well 2-17 2.8 Log-log Plot of Seismic Interval Transit Time 2-18 2.9 ITT Departure versus Formation Pressure Gradient 2-19 2.4 2.10 ITT Ratio versus Formation Pressure Gradient 2-20 2.11 Example of Drilling Hazard Log over Shallow Section 2-22 Table 2.2 Calculation of Depths and Interval Transit Times 2-16 2-5 March 1995 BP WELL CONTROL MANUAL 1 General At the planning stage of a well, several early decisions are made that are directly influenced by the predicted formation pore pressure profile for the well. The magnitude of the expected formation pressure influences the pressure rating of the casing and wellhead/BOP equipment to be used, and can ultimately influence drilling rig selection. Casing programme design and mud weight programmes should be tailored to the predicted formation pressures for the␣well. Other related aspects of well planning that are influenced include, cement programmes, completion equipment, contingency stocks of casing, and mud chemicals/baryte stocks to be held. Thus, accurate formation pressure predictions are required in order to optimise well planning. Good well planning will, in turn, help to minimise the risk of costly problems whilst drilling. There are normally (but not always) two sources of formation pressure information for the well location being considered. The first and most widely used is offset well data. However, in areas where there are no offset wells or they are considered to be too far away to give reasonable data, then seismic data may be used to predict formation pore pressures. Seismic analysis may also be useful in validating offset well data for the location being considered. 2 Offset Well Data Pressure data from nearby wells are commonly used to predict the pore pressure profile. The data are often direct measurements which will give accurate pressures for the particular offset well location. Pressures can also be calculated or inferred from other well data available in well reports. The most commonly used sources of pressure data from offset wells are listed at the top of Table 2.1. The methods used to calculate formation pressures from other well data, such as wireline logs, are described in Sections 2.3 and 2.4. The measured and calculated/inferred formation pressures are then applied to the same formations in the well being planned. Additional information, such as the pressure gradient of the expected reservoir fluid, is also used to finally arrive at a predicted formation pressure profile for the well. This information is presented as a pressure depth plot, an example of which is shown in Figure 2.1. (Fracture pressure information is also presented in the form of formation leak off tests from offset wells.) The accuracy of the pore pressure prediction from offset well data will depend on the type of well that is to be drilled. The following two cases can be considered: • Appraisal/development wells The offset well data should usually be reliable as the offset wells will normally be fairly close to the proposed well location and usually drilled on the same structure. For development wells, the pore pressure profile should be accurately defined from data from the appraisal wells. 2-6 March 1995 BP WELL CONTROL MANUAL Figure 2.1 Pressure/Depth Plot WELL No: 3/10b-a AREA: UKCS North 0 Leak Off Test 30/4–1 Leak Off Test 30/4–2 500 Predicted Formation Pressure 3/10b-a 1500 TERTIARY TO RECENT Holocene to Eocene 1000 Palaeocene 2000 SG EQUIVALENT 3500 psi ft 3000 Upper 4500 Lower JURASSIC 2.61 1.128 2.51 1.085 2.41 1.042 2.31 0.998 2.21 0.955 2.1 0.911 4000 5000 psi ft 0.477 0.434 0.564 0.521 1.6 1.7 1.8 1.9 0.651 0.607 0.738 0.694 0.781 5500 0 Middle Lower SG EQUIVALENT 1.0 1.1 1.2 1.3 1.4 1.5 CRETACEOUS Upper DEPTH (m) 2500 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 PRESSURE (psi) WEOX02.078 2-7 March 1995 BP WELL CONTROL MANUAL • Exploration wells In well explored regions, such as certain areas of the North Sea, the offset well data should be reliable enough for a good estimate to be made of the pore pressure profile for the proposed exploration well. However, if the nearest offset wells are far away, then the pressure data should be treated with caution when applying it to the proposed well. If there are insufficient pressure data available for any one profile to be predicted, then the alternatives should be considered and the ‘worst case’ evaluated for each particular aspect of well planning. Analysis of seismic data may be required to back-up the pressure profile predicted from offset wells. In areas where there is no offset well information or they are too far away to be of any use, then seismic data analysis may be the only method available to predict the pore pressure profile (See Paragraph 3, ‘Seismic Data’). In exploration areas where there is a well established Company office, the predicted pressure profile is usually compiled by the Designated Resident Geologist (DRG) for the well. The pressure depth plot should be obtained as soon as possible and the data must be checked immediately by the Drilling Engineer responsible for planning the well. The DE must ensure that the pressure data is the best available, whilst also accepting that the accuracy of the data will vary depending on the number and proximity of nearby wells. In areas where there is no established exploration office, or where the pressure profile is required prior to compilation by the DRG, then the well planning DE will have to predict the formation pressure profile. The DRG or Area Geology Group must be consulted. The DRG or Area Geology Group will determine which offset wells are most ‘geologically similar’ to the proposed well and hence the best source of formation pressure data. Also, geological features such as faults and unconformities in the area will be identified. These may affect the way in which the pressure data are applied to the proposed well. Notes on formation pressures from offset wells are often given in the ‘Drilling Proposal’ document, together with the lithological prognosis and other pertinent data (well location, target depths, total depth etc). Petroleum Engineers should also be consulted, as they may have additional pressure information, especially regarding expected reservoir pressures. 3 Seismic Data In hydrocarbon exploration, seismic data are mainly used to identify and map prospective reservoir traps and to estimate the depths of formation tops in the lithological column. Seismic data can also be used to predict formation pressures quantitatively, or at least to give an indication of the entrance into abnormally high pressures. In new or relatively unexplored areas, seismic data are often the only information available from which pore pressure data can be derived. Seismic data can also be used to indicate the possible presence of shallow gas bearing sands. This is done using data from high resolution shallow seismic surveys which are normally used down to a maximum depth of about 1000m below surface or the mudline. 2-8 March 1995 BP WELL CONTROL MANUAL 3.1 Abnormal Pressure Evaluation from Seismic Data (a) Basic Theory A seismic wave is an acoustic wave propagated in a solid material - normally a rock. The velocity at which the wave travels depends upon the density and elasticity of the rock, and the type of fluid occupying the pore spaces of the rock. Thus the formation type, formation fluid type, and degree of compaction (ie depth) will determine the seismic velocity in an particular formation. Knowledge of seismic velocities in particular formations over a range of depths enables geophysicists to make fairly reliable formation lithology predictions from seismic data. It is also the seismic velocity of shale sequences that permits the use of seismic data for predicting the presence of overpressured formations, and to estimate the magnitude of the overpressure. Time Refl C Refl B 1 2 3 4 5 6 Up hole time Refl A 7 First breaks 8 9 10 11 12 Shot Moment Geophones Shot Point Geophones V1 A V2 Interval Velocities B Reflecting Beds V3 C WEOX02.079 Figure 2.2 Schematic Diagram illustrating Seismic Reflection System and Seismic Traces 2-9 March 1995 BP WELL CONTROL MANUAL With increasing depth and compaction, the density and elasticity of shales increases which results in increasing seismic velocity with depth. Overpressured shales are undercompacted. This results in lower density and elasticity for that depth. The seismic velocity in overpressured shales is thus lower than in normally pressured shales at similar depths. Thus we need formation interval seismic velocity data to detect and evaluate overpressured shales. These data are readily available from seismic surveys. Seismic data are acquired by creating acoustic waves, by some form of explosion (or␣implosion), and measuring the time taken for the wave to travel down to subsurface reflecting beds and back to the surface. The surface point of origin of the wave is called␣the shot point and the reflected waves are detected at surface by a series of geophone (or hydrophones if offshore) placed at known distances from the shot point. The system is shown schematically in Figure 2.2, together with the seismic traces recorded by the geophones. The whole system is moved across the surface and the measurements are repeated from a new shot point. The process is continued along a pre-determined ‘seismic line’. By using the geometric relationships between the shot points and geophone positions, it is possible to identify a series of seismic traces that have approximately the same reflection point on a reflecting bed. This point is known as a common depth point (CDP), and the seismic paths associated with this point are shown in Figure 2.3. For clarity, only the first reflecting bed is shown, but obviously the deeper reflecting beds will also have corresponding CDPs vertically below, the reflections from which will appear on the series of seismic traces. The distance between the shot point and any particular geophone is termed the ‘offset’. Offset Shot Points Geophones Surface Reflecting bed A COMMON DEPTH POINT (CDP) Figure 2.3 Schematic Diagram showing Common Depth Point (CDP) Seismic Ray Paths 2-10 March 1995 BP WELL CONTROL MANUAL Figure 2.4 Schematic Plot of Offset versus Two Way Travel Time for Common Depth Point System Offset, x to Time, t A C Reflecting Beds B D E The equations of the dashed lines through the seismic reflections are of the form: x = V √ t2 - to2 where to = vertical two way reflection time to reflecting beds (ie offset, x = o) V = stacking velocity (average velocity) Thus the stacking velocity, V, is the variable defining the hyperbolae which best fit the seismic reflections. WEOX02.081 2-11 March 1995 BP WELL CONTROL MANUAL In practice, the seismic traces from the same CDP are collected together to form a ‘gather’ in which seismic traces at the various offsets are plotted against the reflection time. A simplified schematic plot of offset versus reflection time is shown in Figure 2.4. With greater offset, the path length of the wave is longer (See Figure 2.3) and the reflection time for the same reflecting bed increases. Curves can be drawn through the peaks on the seismic traces, corresponding to the same reflecting beds, as shown by the dashed lines in Figure 2.4. The geometry of the CDP seismic system is such that the equation of the curve through the seismic peaks (known as a ‘seismic event’) from a horizontal reflector should be a hyperbola. The variable defining the shape of the hyperbola is called the ‘stacking velocity’ or the ‘normal moveout velocity’. In practice, the peaks on the seismic traces do not lie exactly on a hyperbola. Velocity analyses are performed to determine the velocity value that gives a ‘best fit’ hyperbola to the data. This is done by investigating the hyperbolic function with a range of stacking velocities at increasing time increments, and comparing the result to the actual data from the seismic traces on the gather. The results from the velocity analysis are output in the form of a plot of stacking velocity versus reflection times. A typical example plot from an actual analysis is shown in Figure 2.5. The plot appears as a series of ‘contours’ defining a number of ‘peaks’. Due to the mathematical computations involved in the analysis, the peaks represent the ‘best fit’ stacking velocity values and the corresponding vertical two-way reflection times for each reflecting bed. The stacking velocities obtained are not the true average velocities from the surface to the reflecting bed. However, the stacking velocity is usually considered to approximate to the root mean square (RMS) velocity (as indicated on the horizontal axis in Figure␣2.5). The RMS velocity is the average velocity along the actual path of the seismic wave. In many cases, this is also considered to be equal to the vertical average velocity from the surface to the subsurface reflecting bed. Thus, the velocity-time pairs (as they are called) from the velocity analysis can be used to calculate the depths of the reflecting beds. The stacking velocities are used to compute the vertical two-way reflection times for each of the seismic traces on the seismic gather. The seismic gather can then be ‘stacked’ to form one ‘complete’ seismic trace for that particular CDP. A seismic section is then produced by displaying the stacked traces for each CDP along a seismic line. The stacking or RMS velocities are also used to calculate the interval velocities between reflecting beds, which is the property that we require to detect and evaluate abnormal pressure. (b) The Method Before attempting to predict a formation pore pressure profile from seismic data, the Drilling Engineer must discuss the seismic data and velocity analyses with the Area Geophysicist and Geologist. This will help to identify potential problems such as poor seismic data, lithology complications, errors introduced by formation dip, etc. The DE should then have a better understanding of the problems involved in predicting a pore pressure profile for the well being planned. 2-12 March 1995 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2 4000 5000 6000 BP WELL CONTROL MANUAL 7000 9000 10000 12000 13000 RMS VELOCITY (ft/sec) 8000 2-13 11000 Figure 2.5 Example Seismic Velocity Analysis Plot TWO-WAY TRAVEL TIME (millisecs) WEOX02.082 March 1995 BP WELL CONTROL MANUAL Figure 2.6 Example of Stacking Velocity Data on a Seismic Section SP 561 VINT 1470 1470 1527 1685 1986 2218 2368 2668 2750 2850 2851 2930 3150 1470 1635 1809 2320 2942 3098 4923 3416 3972 2866 3165 3479 LINE CB-82-41 VRMS 0 200 300 650 1150 1450 1700 1850 2050 2200 2350 3100 5000 LINE CB-82-39 SP 870 202 TIME 140 550 146 600 WEOX02.083 2-14 March 1995 BP WELL CONTROL MANUAL The first step in the method is to obtain the stacking velocity data for a range of CDPs near to the proposed well location. The stacking velocities used for these CDPs should be given in panels displayed above the surface line on the seismic section. An example is shown in Figure 2.6. At this point, it is worth checking the stacking velocities given in the panels against the velocities obtained from the CDP velocity analyses. This is because stacking velocities are chosen to produce a good CDP stack (‘clean’ appearance) and may not be equal to the values that would be obtained from a velocity analysis such as that in Figure 2.5. A geophysicist should be consulted to decide which stacking velocities should be used, although more often than not, the velocities given in the panel on the seismic section will suffice. The interval velocities are then calculated from the two-way time and stacking velocity (average velocity) using Dix’s formula: (V i12)2 = where Vi12 t1 t2 V1 V2 t 2(V 2)2 – t 1(V 1)2 t 2 – t1 = = = = = (2-1) interval velocity between reflecting beds 1 and 2 (m/s) two-way travel time for reflecting bed 1 (s) two-way travel time for reflecting bed 2 (s) average velocity to reflecting bed 1 (m/s) average velocity to reflecting bed 2 (m/s) In the example shown in Figure 2.6, the interval velocities have already been computed using Dix’s formula. The depths to the reflecting beds are calculated from: D = t.V 2 (2-2) where D = depth of the reflecting bed (m) t = two-way travel time for the reflecting bed (s) V = average velocity to reflecting bed (m/s) Note that the two-way time in the panel in Figure 2.6 is given in milliseconds (ms). This needs to be converted to seconds for use in equation (2-2) (1ms = 10 3 sec). A table should be drawn up as shown in Table 2.2. The final step in the calculations is to convert interval velocities, a term used by geophysicists, into interval transit times which is a term more familiar to drilling engineers. This is done by simply taking the reciprocal of the interval velocity. Note that interval transit times are expressed in micro-seconds per metre (µsec/m) (1µsec = 10-6 sec). A plot of interval transit time (ITT) versus depth can then be constructed. The interval transit time is plotted as a vertical line over the depth interval, for which it was calculated. This results in a plot similar to a sonic log plot but in which the data are averaged over long sections and not, as with the wireline sonic log, over a few feet only. A plot of the data from Table 2.2 is shown in Figure 2.7. The corresponding wireline sonic log plot is also shown for comparison. Note that ITT is plotted on a logarithmic scale and depth on a linear scale. The types of scales that are used are discussed further in (c) ‘Interpretation’. 2-15 March 1995 BP WELL CONTROL MANUAL Two-way time Depth Int. velocity (Dix’s formula) Int. transit time t (millisecs) Average (stacking) velocity V (m/s) D (m) Vi (m/s) ∆ti (µsec/m) 0 1470 0 1470 680 200 1470 147 1635 612 300 1527 229 1809 553 650 1685 548 2320 431 1150 1986 1142 2942 340 1450 2218 1608 3098 324 1700 2368 2013 4923 203 1850 2668 2468 3416 293 2050 2750 2819 3972 252 2200 2850 3135 2866 349 2350 2851 3350 3165 316 3100 2930 4542 3479 287 5000 3150 7875 Table 2.2 Calculation of Depths and Interval Transit Times (c) Interpretation As stated, overpressured shales have lower interval velocities, and therefore higher interval transit times than normally pressured shales at the same depth. The normal shale compaction trend line on the ITT depth plot decreases with depth. Thus an increase in interval transit time away from the normal trend line indicates the presence of abnormal pressures. This is shown by the shaded section in Figure 2.7. From the seismic ITT plot (‘stepped’ profile), the top of the abnormal pressures would probably be estimated to be at 2300m to 2500m. When the well was drilled the top of the abnormal pressures was found to be at about 2000m. There is a certain amount of conflict surrounding the types of scale that should be used for plotting ITT data. The format used in Figure 2.7 assumes that the normal compaction trend is a straight line on semi-logarithmic scales. This method is recommended by Fertl(17), as it enables ITT data to be directly compared with other pressure indicators that are plotted using the same linear depth scale (composite plots). Alternatively, Pennebaker(25) suggested that the normal compaction trend should be a straight line on log-log scales. An example plot of this format is shown in Figure 2.8. 2-16 March 1995 BP WELL CONTROL MANUAL Figure 2.7 Seismic and Sonic ITT versus Depth Plots for Abnormally Pressured Well LITHOLOGY 500 SEISMIC DATA siltstone with mudstone 1000 SONIC LOG 1500 calcareous mudstone and siltstone Overpressure Top: Actual sandstone limestone Predicted 2500 3000 mudstone and siltstone com pac tion tren d lin e 3500 mal 4000 sandstone Nor DEPTH (metres) 2000 mudstone and siltstone 4500 100 200 300 400 500 600 800 INTERVAL TRANSIT TIME (µsec/m) WEOX02.084 2-17 March 1995 BP WELL CONTROL MANUAL NORMAL TREND DEPTH TOP OF OVERPRESSURE T, Interval Transit Time WEOX02.085 Figure 2.8 Log-log Plot of Seismic Interval Transit Time Both the semi-log and log-log plots of ITT versus depth will show approximately the same top of abnormal pressures. However, a major difference between the two methods arises when the plots are used to estimate the magnitude of the abnormal pressures. Charts relating the magnitude of formation pressures to some function of the ‘departure’ of the observed ITT values from the extrapolated normal ITT values are available for both methods. For the semi-log plot, the difference between the observed and normal ITT values is used to estimate formation pressures from a chart such as the one shown in Figure 2.9. For the log-log plot, Pennebaker(25) presented a chart that required the ratio of observed ITT to normal ITT in order to estimate the magnitude of the abnormal pressures, as shown in Figure 2.10. Thus, the two methods of plotting ITT data require entirely separate empirically derived charts to estimate the magnitude of abnormal pressures. It is most important that the correct chart is used when estimating formation pressures. The chart from one method should never be used with an ITT plot from the other method. It should also be noted that different geological areas have vastly different correlations between ITT departure and formation pressure (See Figure 2.9). Hence, it is most important to obtain the correct correlation for the area that is being investigated. It may be necessary to determine a new correlation for the area of interest. This can only be done using actual well data on a regional basis and with the assistance of the geologists and geophysicists. In completely unexplored areas, this may not be possible at all. 2-18 March 1995 BP WELL CONTROL MANUAL Another major problem in interpreting seismic ITT plots is the placing of the normal compaction trend line. Referring to Figure 2.7, it would be most difficult to determine the exact position and gradient of the normal compaction trend line from the seismic data alone. The various non-shale lithologies affect the data quite considerably and even with the actual sonic log from the well overplotted, the correct position of the normal compaction trend line is still open to debate. One possible solution to this problem is to make numerous seismic ITT (and sonic log ITT, if available) plots for the region being investigated. It may then be possible to determine the position and gradient of an average normal compaction trend line for the region. A full discussion of other problems associated with the interpretation of seismic ITT␣plots is given by Barr (2) and are further discussed in relation to sonic log plots in Section 2.4 of this Chapter. 1.0 0.9 2.25 ST COA OX ILC XAS ST TE WARE DELA BASIN 2.00 WE 0.8 RG T 2 BU FR VI AS 0.7 1.75 IO S CK EA CO NA LF H 1.50 A SO 0.6 S I CH UT GU PRESSURE GRADIENT psi/ft W H RT SE (FRIO, VICKSBURG, AND WILCOX – SOUTH TEXAS GULF COAST AREAS) NO 1.25 EQUIVALENT MUD WEIGHT SG GULF 0.5 1.00 0.4 0 10 20 30 SONIC LOG DEPARTURE 40 50 abnormal t pressured – shale 60 70 80 normal t pressured , u sec/ft shale WEOX02.086 Figure 2.9 ITT Departure versus Formation Pressure Gradient To summarise, seismic ITT data may be of use in determining the possible existence of overpressures at the planned well location. Depending on the degree of knowledge of compaction trends/formation pressure relationships for the area, it may be possible to use the seismic ITT data to estimate the magnitude of formation pressures. However, it must not be assumed that abnormal pressures do not exist because of a lack of indications from the seismic ITT data. The construction and interpretation of seismic ITT plots should always be done in conjunction with the local geophysicists and geologists. 2-19 March 1995 BP WELL CONTROL MANUAL 0.4 0.5 1.25 0.6 PORE PRESSURE GRADIENT psi/ft 1.50 0.7 EQUIVALENT MUD DENSITY SG 1.75 0.8 2.00 0.9 2.25 1.0 1.2 1.4 T/ 1.6 Tn Note: See warning in (c) Interpretation. WEOX02.087 Figure 2.10 ITT Ratio versus Formation Pressure Gradient 3.2 Identifying Shallow Gas Hazards Detailed high resolution seismic surveys as well as conventional seismic data are used to identify potential gas bearing zones at shallow depths by using a technique known as ‘bright spot’ analysis. The high resolution seismic data are acquired over a survey grid with perhaps only 150m between seismic lines, the grid covering an area of only a few square kilometres around a proposed well location. The data are processed to produce detailed seismic sections usually down to a maximum depth of about 1000m. 2-20 March 1995 BP WELL CONTROL MANUAL Gas bearing formations may produce high amplitude ‘anomalies’ on the seismic reflection traces of the seismic section. These high amplitudes (relative to the other seismic reflections) are caused by strong seismic reflections due to the velocity impedance contrast between the gas bearing formation and the overlying formations. These amplitude anomalies appear visually on the seismic section as bright areas. The lateral extent of the bright spots can be mapped on a horizontal section, or sections, and the area of the proposed well location examined in detail. It may be necessary to move the well location to avoid drilling into a possible shallow gas zone as indicated by a bright spot. It must be noted that the high resolution seismic technique cannot usually detect a gas sand that is less than 2 to 3 metres thick, although such a thickness of gas accumulation may be enough to cause a shallow gas blowout. Also, the absence of bright spots does not mean that there will be no shallow gas and conversely, bright spots do not always contain gas. However, it is wise to avoid drilling through any bright spots if possible. Ideally, the Geophysicists must be responsible for analysing the shallow seismic data at the proposed well location. Once the well location has been finalised, the Drilling Engineer should liaise closely with the Geophysicists and Geologists to produce a drilling engineering hazard log over the depths covered by the shallow seismic survey. An example hazard log is shown in Figure 2.11. It will not be possible to predict formation pressures for shallow gas formations from the seismic data. However, drilling personnel should always be aware that shallow gas bearing formations may be overpressured, though this is not normally the case. 4 Summary The importance of reliable formation pressure data must be stressed. It is the responsibility of the well planning DE to ensure that the pressure data used are the most accurate available. Whenever possible, pressure data from offset wells should be used to predict the pore pressure profile for well planning. Direct pressure measurements such as those from RFTs, drillstem tests and well kicks should give more accurate data than pressures derived from well logs. Seismic methods of pressure prediction should only be used in the absence of offset well data. Occasionally, seismic analysis may be necessary to endorse the data from offset wells, although there is no guarantee that this will be successful. A recent development by Geochemistry Branch at Company Research Centre, Sunbury is worthy of note. A compaction model has been developed that may have an application for predicting formation pressures. This model may be useful for pressure prediction in areas with very few or no offset wells, especially if used in conjunction with seismic data. At present, the model is being validated against actual well data. 2-21 March 1995 BP WELL CONTROL MANUAL Figure 2.11 Example of Drilling Hazard Log over Shallow Section CASING DEPTH (m) RTE 0 SEABED 100 DRILLING HAZARD 200 210 230 BASE OF NEAR SURFACE SEDIMENT POSSIBLE SHALLOW GAS 350 FAULT 30in (320m) 400 SAND, LENSES, POSSIBLE GAS 470 18 5/8in (580m) 600 620 SAND AND SHALE 800 850 1000 FAULT BASE OF SHALLOW SURVEY 2-22 March 1995 WEOX02.088 BP WELL CONTROL MANUAL 2.3 FORMATION PRESSURE EVALUATION WHILST DRILLING Paragraph Page 1 General 2-25 2 Drilling Parameters 2.1 Rate of Penetration 2.2 Drilling Exponents 2.3 Other Drilling Rate Methods 2.4 Hole Characteristics 2-25 2-25 2-27 2-38 2-42 3 Drilling Mud Parameters 3.1 Gas Levels 3.2 Temperature 3.3 Resistivity/Conductivity/Chlorides 3.4 Flowline Mud Weight 2-43 2-43 2-52 2-53 2-53 4 Cutting Parameters 2-53 5 Measurement While Drilling (MWD) Techniques 2-60 6 Mud Logging Service 2-61 7 Summary 2-64 Illustrations 2.12 Example showing Increase in Penetration Rate on Entering an Abnormally High Pressure Zone 2-26 2.13 Effect of Lithology Variation on Penetration Rate 2-27 2.14 Effect of Bit Condition on Penetration Rate when Drilling into an Overpressured Zone 2-28 2.15 Schematic Diagram showing Typical response of Corrected d-exponent in Transition and Overpressured Zones 2-30 2.16 Schematic Diagrams showing Various Typical d c-exponent Responses 2-31 2.17 Schematic Diagram showing dc-exponent Response to Overcompaction caused by Ice Sheet Loading 2-33 2.18 Example of Formation Pressure Determination from the d c-exponent plot using the ‘Ratio Method’ 2-34 2-23 March 1995 BP WELL CONTROL MANUAL Illustrations 2.19 Example showing the ‘Equivalent Depth Method’ for Formation Pressure Determination from dc-exponent Plots 2-36 2.20 Example showing Formation Pressure Determination from the dc-exponent Plot using Lines Constructed from the ‘Eaton Equation’ 2-49 2.21 Example showing the ‘Normalized Penetration Rate’ Method for Determination of Formation Pressures 2-40 2.22 Schematic Diagram showing Mud Gas Levels as an Indicator of Formation Pressures 2-45 2.23 Example of Mud Gas Levels showing Trip Gas, Kelly Gas (Kelly Cut), and Recycled Trip Gas 2-46 2.24 Schematic Diagram showing Theoretical Geothermal Gradients and Temperature Profile through an Overpressured Zone 2-49 2.25 Schematic Diagram showing Expected Flowline Temperature Response on Drilling through an Overpressured Zone 2-49 2.26 Example Flowline Temperature Plots showing Raw Data Plot, End-to-end Plot and Trend-to-trend Plot 2-50 2.27 Example ‘Horner’ Temperature Plot for Estimation of True Bottomhole Temperature (BHT) 2-51 2.28 Example of Typical Response of Differential Mud Conductivity/Delta Chlorides 2-53 2.29 Schematic Shale Bulk Density/Depth Plot 2-54 2.30 Variable Density Column for Measuring Shale Bulk Density 2-55 2.31 Response of Shale Bulk Density/Depth Plots in Overpressures caused by Various Mechanisms 2-56 2.32 Shale Factor/Depth Response to Overpressure caused by Compaction Disequilibrium and Clay Diagenesis 2-58 2.33 Characterisation of Shale Cavings Caused by Underbalanced Conditions and Stress Relief 2-59 2.34 Mud Logging Unit Functions and Information Flow Diagram 2-62 Table 2.3 General Mud Logging Sensor Specifications 2-24 March 1995 2-63 BP WELL CONTROL MANUAL 1 General The aim of formation pressure evaluation whilst drilling is to determine the optimum mud weight to contain any formation pore pressures encountered, whilst maximising rates of penetration and minimising the hazards of lost circulation and drillstring differential sticking. To achieve this, formation properties have to be closely monitored in order to detect any changes that may indicate the transition from a normally pressured zone to an abnormally pressured zone or vice versa. Abnormally pressured zones may exhibit several of the following properties when compared to normally pressured zones at the same depths. • Higher porosities • Higher temperatures • Lower formation water salinity • Lower bulk densities • Lower shale resistivities • Higher interval velocities • Hydrocarbon saturations may be different (ie higher saturation) Any measureable parameter which reflects the changes in these properties may be used as a means of evaluating formation pressures. The parameters commonly used to evaluate formation pressures while drilling are listed in Table 2.1. It should be remembered however, that the above properties also vary with differing lithologies. Lithological variations should always be taken into account when interpreting changes in drilling and mud parameters. As the aim of formation pressure evaluation whilst drilling is to reduce the risk of taking well kicks, this section concentrates on the techniques used to achieve this. The pressure evaluation techniques in Table 2.1 that are associated with kicks are not discussed here. 2 Drilling Parameters 2.1 Rate of Penetration Rate of penetration varies with the weight on the bit, rotary speed, bit type and size, hydraulics, drilling fluid properties and formation characteristics. If the weight on bit, rotary speed, bit type, mud density and hydraulics are held constant, then the rate of penetration (ROP) in shales will decrease uniformly with depth. This is due to the normal compaction increase in shales with depth. However, the undercompaction present in transition and abnormally pressured zones, together with the reduction in differential pressures across the bottom of the hole, result in an increase in penetration rate. It should also be noted that slower penetration rates have often been observed in the ‘cap rock’ (pressure seal) overlying transition zones. 2-25 March 1995 BP WELL CONTROL MANUAL The increase in ROP on drilling into a transition zone can be best seen on a plot of ROP versus depth. The average ROP over 0.5 to 2m depth increments (depending on whether the␣drilling is slow or fast) is plotted as shown in Figure 2.12. A normal compaction trend can be established in shales as shown. A new trendline must be established for each new bit␣ r un. An increase in penetration rate away from the normal compaction trend may indicate␣abnormal pressures provided that the drilling and mud parameters, and lithology , remain constant. ROP DEPTH NORMAL SHALE TREND LINE NEW BIT TOP OF OVERPRESSURES WEOX02.089 Figure 2.12 Example showing Increase in Penetration Rate on Entering an Abnormally High Pressure Zone Complications arise due to lithology changes and bit dulling. Sandstone usually drills much faster than shales. This is normally shown by a sharp increase in ROP as the sandstone is penetrated. This effect, known as a ‘drilling break’ is shown schematically in Figure 2.13. The normal compaction trend must be established over the shale sections only. Drilling breaks must always be flow checked regardless of whether the current estimated pore pressure gradient is less that the mud weight. Occasionally, the transition zone may be only a few metres thick if there is a very good pressure seal. This may make it very difficult to identify an increase in ROP as being one due to increased pore pressure, because it may be masked by a drilling break. 2-26 March 1995 BP WELL CONTROL MANUAL ROP sand shale DEPTH NORMAL SHALE COMPACTION TREND LINE WEOX02.090 Figure 2.13 Effect of Lithology Variation on Penetration Rate Bit dulling can also mask penetration rate changes due to pore pressure increases. A comparison of ROP curves in an overpressured section for a dull bit and a sharp bit are shown in Figure 2.14. The dull bit continues to show the normal compaction trend in the transition zone whilst the sharp bit clearly shows a gradual increase in ROP. The dull bit ROP may even show a decrease in the overpressured zone if the bit is very worn and close to being pulled. In practice, drilling parameters are rarely held constant, as they are purposefully varied in order to maximise the penetration rate. Thus, ROP curves alone tend to be of limited use in identifying overpressured zones. They may, however, provide additional information when used in conjunction with other abnormal pressure indicators. 2.2 Drilling Exponents From the preceding discussion on ROP curves, it is clear that a method of accounting for the effect of drilling parameters is desirable in order to make ROP a better indicator of abnormal pressures. The ‘d-exponent’ attempts to achieve this. 2-27 March 1995 BP WELL CONTROL MANUAL SHARP BIT ROP DULL BIT ROP sand DEPTH shale TOP TRANSITION ZONE WEOX02.091 Figure 2.14 Effect of Bit Condition on Penetration Rate when Drilling into an Overpressured Zone (a) d-Exponent In 1965, Bingham(4) proposed a generalised drilling rate equation to relate all the relevant drilling parameters: ROP = a WOB N B where ROP N B WOB a d = = = = = = d (2-3) penetration rate (ft/min) rotary speed (rpm) bit diameter (ft) weight on bit (lb) rock matrix strength constant (dimensionless) formation drillability exponent (dimensionless) 2-28 March 1995 BP WELL CONTROL MANUAL Jorden and Shirley (21) rewrote equation 2-3 for ‘d’, the drillability exponent. They inserted constants to allow the use of more common oilfield units and let the matrix strength constant, ‘a’, equal 1. This removed the need to derive values for the matrix strength constant, but made d-exponent lithology dependent: log ROP 60N d= 12WOB log 106 B where d ROP N B WOB = = = = = drillability exponent (d-exponent) (dimensionless) penetration rate (ft/hr) rotary speed (rpm) bit diameter (in.) weight on bit (lb) NOTE: The constant 106 is simply a scaling factor inserted in the equation in order to give values of d in a convenient workable range, normally about 1.0 to 3.0. In constant lithology, d-exponent will increase with depth as the ROP decreases due to the increased compaction and differential pressures across the bottom of the hole. However, when an overpressured zone is penetrated, compaction and differential pressure will decrease and will result in a decrease in d-exponent. Hence d-exponent is, in general, related to the differential pressure at the bottom of the hole which in turn is dependent on pore pressure. (b) Corrected d-Exponent Since the differential pressure across the bottom of the hole is affected by the mud␣weight also, then changes in the mud weight will produce unwanted changes in d-exponent. Hence Rehm and McClendon (27) proposed the following correction to the d-exponent to account for mud weight variations: dc = d X FPG N ECD (2-5) where dc = corrected or modified d-exponent (dimensionless) FPGN = normal formation pressure gradient (ppg, SG) ECD = equivalent circulating density (ppg, SG) This correction has no theoretical basis but has been successfully used worldwide. ECD should be used whenever possible but use of the actual mud density has been found to be acceptable. The response of d-exponent in overpressure is shown schematically in Figure 2.15. The dc-exponent may be plotted with either semi-log or linear co-ordinate axes. Either system will produce an approximately linear, normal compaction trendline, as indicated in Figure 2.15. In practice, the semi-log co-ordinate system gives a more efficient data display (values of dc are normally in the range 0.5 to 2.0) and is a more suitable format for making formation pressure estimates from dc-exponent. A d c-exponent plot should be commenced as soon as drilling begins. Values should be calculated at 0.5 to 2m intervals, depending on penetration rate. This is normally done automatically by the Mud Logger’s computer and displayed as required. The values may also be plotted up automatically to enable trends to be spotted as early as possible. 2-29 March 1995 BP WELL CONTROL MANUAL NORMAL CONCEPTION TREND UNE DEPTH NORMAL PRESSURE TRANSITION ZONE OVERPRESSURED ZONE WEOX02.092 dc Figure 2.15 Schematic Diagram showing Typical response of Corrected d-exponent in Transition and Overpressured Zones The ‘normal’ dc trendline should be established as soon as possible in order that transition zones to abnormal pressures can be recognised as they are being drilled. However, it is often difficult to precisely establish the normal dc trendline due to scatter in the dc values calculated. This variation in d c values is mainly caused by: • Lithology As previously stated, d-exponent increases with depth and compaction in constant lithology. This implies that d-exponent is mainly applicable to shales. Changes in␣lithology will thus cause changes in the value of d c. If the lithology change is relatively minor, such as silty shales, then a slight decrease in dc values may be observed which may not affect the overall trend significantly. Cuttings analysis should help to identify ‘true’ shale points for use in establishing the normal trend if the dc values show a large␣scatter . 2-30 March 1995 BP WELL CONTROL MANUAL Figure 2.16 Schematic Diagrams showing Various Typical dc-exponent Responses (a) (b) MUDSTONE SILTY MUDSTONE DEPTH CALCITIC MUDSTONE MUDSTONE NORMAL PRESSURE NORMAL PRESSURE DEPTH SOFT CLAY SAND MUDSTONE SAND MUDSTONE OVERPRESSURE OVERPRESSURE CALCITIC MUDSTONE MUDSTONE CALCITIC MUDSTONE MUDSTONE SAND MUDSTONE dc dc (c) (d) ROCK BIT 12 1/4in / 25 000 lb W/B = 2040 lb/in SMOOTHED CURVE SMOOTHED CURVE DEPTH DEPTH RAW DATA INSERT BIT 12 1/2in / 10 000 lb W/B = 1178 lb/in ROCK BIT RAW DATA dc dc (e) (f) OVERPRESSURE NEW BIT NORMAL PRESSURE DEPTH DEPTH NEW BIT NEW BIT dc FRESH BIT DULL BIT dc WEOX02.093 2-31 March 1995 BP WELL CONTROL MANUAL For major lithological variations, such as interbedded sandstone/shale, the normal trend must be developed through the shale sections only. The increased ROP in sand sections will give sharply decreased dc values. (It may be possible to develop normal trendlines for the various other lithologies but these are of little use in overpressure evaluation and may only serve to confuse matters.) The important message here is that lithology variations must be taken into account when interpreting dc-exponent plots. The response of d c in various lithologies is shown schematically in Figure␣2.16 (a) and (b). • Hydraulics Changes in drilling hydraulics may produce changes in dc-exponent. This also applies to formations that are susceptible to jetting. Therefore, it is often impossible to establish a normal dc trend in soft, unconsolidated sediments, such as those commonly drilled in offshore top hole sections. • Bits The different drilling actions of different types of bits, ie mill tooth or insert, can cause variations and trend shifts in dc. It is sometimes necessary to plot a ‘smoothed’ curve to account for trend shifts as shown schematically in Figures 2.16 (c) and (d). Changes in hole size will also produce a trend shift in dc. The effect of bit wear is to produce an increase in dc values towards the end of the bit run, as indicated in Figure 2.16(e). The new bit should give a new dc trend that continues along the previous trend provided that it is the same type of bit and none of the other parameters have varied significantly. The effect of drilling into an overpressured zone as the bit dulls is shown schematically in Figure 2.16 (f). A dull bit may mask the decrease in dc which would be expected if the bit was fresh. In extreme cases, bit dulling may totally mask or even produce an increase in dc values even though an overpressured zone has been penetrated. Thus it can be seen that the position of normal trends should be established with great care, as should the practice of shifting trends from raw data to produce smoothed curves. Two further noteworthy phenomena that may cause difficulty in interpreting the plots␣are: • Unconformities/Disconformities The presence of an unconformity/disconformity in the geological age of formations being drilled will often change the character of the normal trendline. The different compaction histories and sedimentary conditions of the formations above and below an unconformity/disconformity may result in not only a shifted normal dc trendline, but also a change in slope. A new trendline should be established after drilling through an unconformity/disconformity. 2-32 March 1995 BP WELL CONTROL MANUAL dc – EXPONENT 0.5 SG 1.3 1.5 2.0 G 1S 1. 1.2 1.0 SG DEPTH OVERCOMPACTED NORMAL COMPACTION TREND NORMALLY COMPACTED OVERPRESSURED WEOX02.094 Figure 2.17 Schematic Diagram showing dc-exponent Response to Overcompaction caused by Ice Sheet Loading • Ice Sheet Compaction Ice sheet compaction can often cause a good normal compaction trend to be established at shallow depths in top hole sections. This is due to the increased compaction of the near surface sediments caused by the weight of a once present overlying ice sheet. This may lead to a normal d c trend being developed through dc values that are too high. The compacting influence of the ice sheet is often dissipated after the first few hundred metres and the d c-exponent then appears to decrease to a new normal trend, falsely indicating an increase in pore pressure. This effect is shown schematically in Figure 2.17. (c) The Calculation of Formation Pressures using dc Once the normal compaction trend has been firmly established on the dc-exponent plot, then d c values that decrease away from this line may indicate abnormal formation pressures. This is, of course, provided that there have been no significant changes in lithology or in any of the other relevant parameters. 2-33 March 1995 BP WELL CONTROL MANUAL • The ratio method The magnitude of the formation pressure can be related to the dc deviation on the semi-log plot using the ‘ratio method’: FPG O = FPGN X dcN dcO (2-6) where FPG O = actual formation pressure gradient at depth of interest (psi/ft, SG or ppg) FPG N = normal formation pressure gradient (psi/ft, SG or ppg) dcO = observed corrected d-exponent at depth of interest dcN = expected corrected d-exponent on normal trendline at depth of interest Normal shale trend line Normal formation pressure Gradient is 1.08 SG SANDS DEPTH 2.04 SG 1.80 1.56 1.44 1.32 1.20 1.08 SG TYPICAL TRANSITION ZONE Maximum formation press gradient is 1.43 SG Maximum formation press gradient is 1.66 SG dc – EXPONENT (SEMI-LOG SCALE) WEOX02.095 Figure 2.18 Example of Formation Pressure Determination from the dc-exponent plot using the ‘Ratio Method’ Equation 2-6 is only valid for the semi-log dc plots as it is assumed that dc is an exponential function of depth. By rearranging the above equation into: dcO = d cN X FPG N FPG O (2-7) 2-34 March 1995 BP WELL CONTROL MANUAL and substituting known values of FPG N and dc at various depths, it is possible to calculate a series of values of dcO , equivalent to various values of formation pressure gradient, FPGO. These series of values of dcO can be plotted on the semi-log dc plot as lines parallel to the normal d c trendline. The formation pressure gradient at any desired depth can then be estimated directly from the dc plot. Figure 2.18 shows an example d c plot with equivalent formation pressure gradient lines drawn in. NOTE: Transparent overlays ready marked with equivalent formation pressure gradient lines are sometimes available for reading formation pressures directly off the dc plot. As it is never certain exactly what depth and dc scales were used to construct these overlays, their use should be avoided in making formation pressure gradient estimates. The ratio method is a very simple method of making formation pressure estimates from dc-exponent. However, it ignores the effect of the variable overburden gradient (See ‘Overburden Pressure’ in Chapter 1, Section 1.1), which controls compaction trends. This effect is reflected in the d c-exponent trend, but is considered not accurately defined by it. An alternative method of calculating formation pressures from the dc plot is the equivalent depth method. • Equivalent Depth Method Due to the increase in compaction with depth, the formation matrix stress also increases, and the formation becomes harder to drill. In overpressured formations the compaction and matrix stresses are less than would be normally expected at that depth. The equivalent depth method attempts to relate these values to the depth at which they would be normal. The method assumes that the matrix stress (grain to grain contact pressure) is equal at all depths having the same value of dc. Matrix stress (M) is related to pore pressure (P f) and the overburden pressure (S) as shown by equation 1-8 (See Chapter 1, Section 1.1). This equation can be rearranged to give: Pf = S – M (2-8) This equation holds at any depth. Therefore, referring to the example dc plot in Figure 2.19, the actual formation pressure gradient (FPG O) at the depth of interest (D O) is given by: FPGO = PfO = DO SO – M O D O DO FPGO = OPGO – MO DO where OPG O MO (2-9) = overburden pressure gradient at depth of interest (psi/ft) = matrix stress at depth of interest (psi) The overburden pressure gradient is known because it is continually estimated by the Mud Loggers and updated from wireline formation density or sonic logs. (The␣overburden gradient is required for estimating fracture pressures as well as for making pore pressure estimates.) However, the value of the matrix stress at the depth of interest is unknown. 2-35 March 1995 BP WELL CONTROL MANUAL A line is then constructed vertically upwards from the value of dc at the depth of interest until it crosses the normal dc trendline at ‘the equivalent depth’ (DE), as shown in Figure 2.19. At this equivalent depth, both the pore pressure and the overburden pressure are known. Thus, equation 2-8 can be solved for the matrix stress (ME) at the equivalent depth (DE): ME = SE – PfE (2-10) In terms of gradients: ME = SE = PfE = OPG E – FPG E DE DE DE ME = DE (OPGE – FPG E) (2-11) where OPGE = overburden gradient at equivalent depth (psi/ft) FPGE = formation pressure gradient at equivalent depth (psi/ft) which also equals the normal formation pressure gradient at the equivalent depth FPGNE (psi/ft) dc – EXPONENT 0.5 1.0 1.5 2.0 DEPTH DE NORMAL COMPACTION TREND DO WEOX02.096 Figure 2.19 Example showing the ‘Equivalent Depth Method’ for Formation Pressure Determination from dc-exponent Plots 2-36 March 1995 BP WELL CONTROL MANUAL Since the matrix stress at the depth of interest and equivalent depth are considered equal (equal d c values), then substituting equation 2-11 into equation 2-9 gives: FPGO = OPGO – D E (OPGE – FPG NE) DO where FPG O OPG O OPG E FPG NE DO DE = = = = = = (2-12) formation pressure gradient at depth of interest (psi/ft) overburden pressure gradient at depth of interest (psi/ft) overburden pressure gradient at equivalent depth (psi/ft) normal formation pressure gradient at equivalent depth (psi/ft) depth of interest (ft) equivalent depth (depth at which dc is equal to value at DO) (ft) NOTE: Equation 2-12 can be used directly with gradients in SG, lb/gal or psi/ft and depths in metres or ft. The equivalent depth method has been successfully used to estimate formation pressures from both semi-log and linear scale d c plots. However a major flaw in the theory occurs when the equivalent depth of a particular overpressured formation is found to be above the rig floor. This will be the case if high overpressures are developed at relatively shallow depths. Also, the method relies on determining the intersection point of a vertical line with the normal compaction trendline. It therefore becomes inaccurate when the normal compaction trendline is very steep, as is usually the case on the semi-log dc plot. • The Eaton Method The most accurate estimates of formation pressure from dc-exponent are considered to be obtained from the Eaton equation. This empirical equation was again developed from the basic relationship between pore pressure, overburden pressure, and matrix stress (equation 2-8). For normal pressure conditions: MN = S O – PfN (2-13) Eaton then introduced a term to relate the dc-exponent (drilling rate) response in overpressures to the reduction in matrix stress: MO = MN DcO d cN 1.20 (2-14) Combining equations (2-13) and (2-14) gives: MO = (SO – PfN) dcO d cN 1.20 (2-15) Rewriting equation 2-13 for an abnormally pressured situation gives: MO = S O – PfO (2-16) Substituting equation 2-16 into equation 2-15 then gives the Eaton equation: PfO = SO – (SO – PfN) DcO d cN 1.20 (2-17) 2-37 March 1995 BP WELL CONTROL MANUAL Dividing through by the depth (D), gives the equation in terms of gradients: PfO = SO – SO – PfN DO DO DO DO dcO d cN 1.20 FPGO = OPGO (OPGO – FPGN) dcO d cN 1.20 where FPGO, FPGN, OPGO, dcO and dcN are the same terms as explained for equations 2-6 and 2-12. By rearranging equation 2-18 and substituting known values of FPGN, d cN and OPG, it is possible to plot a series of d cO lines equivalent to various values of FPG O (in a similar manner to that previously explained for the Ratio method). An example of this construction is shown schematically in Figure 2.20. Formation pressure gradients can then be read directly from the dc plot. Eaton originally developed the equation for use in estimating formation pressures from shale resistivity plots (See Section 2.4), but found that it applied equally to␣corrected d-exponent. The value of the exponent, 1.20, was derived from actual well data. All the methods for estimating formation pressures from dc-exponent plots rely on correct placement of the normal compaction trend. The difficulties in achieving this have previously been discussed and highlight the fact that identification of overpressured zones should not be based on dc-exponent calculations alone. Other abnormal pressure indicators, which are often more basic in nature than dc-exponent calculations, should always be checked. These indicators must support, as far as possible, any formation pressure conclusions drawn from the dc plot. Drilling factors that are not accounted for by dc-exponent are drilling hydraulics, bit tooth efficiency (bit wear) and matrix strength (lithology dependent). Also, the relationship between ROP and the various drilling parameters is not so simple as is implied by the dc-exponent equation. These factors have led to the development of more refined drilling exponents in which attempts have been made to model the various drilling/formation interactions more closely. In particular, mud logging companies have developed their own drilling exponents from which they make formation pressure estimates. Exlog’s ‘Nx’ (normalised exponent) and ‘Nxb’, and Anadrill’s ‘A’ exponent are examples of these more refined drilling exponents. The theory of these drilling exponent methods will not be discussed in detail here as their formulae are of a proprietary nature and are not generally available. Suffice it to say that the methods still rely on estimating a normal compaction trend and spotting deviations from it caused by pore pressure changes and not by lithology or drilling changes. 2.3 Other Drilling Rate Methods There are a number of other drilling rate methods for estimating formation pressures that are worthy of note. As these methods are generally more complex than d-exponent methods, they have not gained wide acceptance and thus tend only to be used by their originators. 2-38 March 1995 BP WELL CONTROL MANUAL Figure 2.20 Example showing Formation Pressure Determination from the dc-exponent Plot using Lines Constructed from the ‘Eaton Equation’ dc – EXPONENT 0.5 1.80 1.68 1.56 1.44 1.0 1.33 1.20 1.08 1.5 SG DEPTH NORMAL TREND TOP OF OVERPRESSURE WEOX02.097 2-39 March 1995 BP WELL CONTROL MANUAL (a) Normalised Penetration Rate This method was developed in 1980 by Prentice(26) from work done originally by Vidrine and Benit(32). The method uses a drilling rate equation to ‘normalise’ the effects of the variables controlling ROP. The only variable not normalised is differential pressure across the bottom of the hole. If the ECD is then considered to be fairly constant over short intervals of the hole, a change in ‘normalised’ penetration rate reflects a change in formation pressure. 2960 NEW BIT 1.08 SG ECD = 1.25 SG 2990 ECD = 1.25 SG 3020 1.08 SG 8.53m/hr 4.11m/hr DEPTH (metres) NEW BIT 3050 1.28 SG CIRCULATED 1.38 ECD ALL AROUND NEW BIT ECD = 1.38 SG 1.28 SG 8.23m/hr 3080 6.1m/hr 1.37 SG CIRCULATED 1.5 ECD ALL AROUND 12 8 4 4100 0 NORMALIZED PENETRATION RATE (m/hr) WEOX02.098 Figure 2.21 Example showing ‘Normalized Penetration Rate’ Method for Determination of Formation Pressures 2-40 March 1995 BP WELL CONTROL MANUAL As drilling proceeds, a plot of normalised penetration rate against depth is constructed. The observed penetration rate is mathematically corrected to the normalised penetration rate by applying arbitrarily chosen normal parameters according to the equation: ROPN = ROPO where ROP W N ∆Pbit Q m λ = = = = = = = WN – m WO – m X X NN NO λ X ∆PbitN QN ∆PbitO QO (2-19) penetration rate (ft/hr or m/hr) weight on bit (lb) rotary speed (rpm) bit pressure drop (psi) mud flow rate (gpm) ‘threshold’ bit weight (weight necessary to initiate formation failure) (lb) rotary exponent and the subscripts N O = ‘normal’ values = observed values Values of λ and m are given by Prentice(26). If the ‘normal’ conditions are chosen so that most of a bit run can be drilled at these conditions, then no corrections will be necessary and ROPN will equal ROPO. Each bit run is treated as an individual unit and is plotted up as shown in the example in Figure 2.21. Changes in mud weight are also plotted separately. Drilling trends are fitted to each bit run, or part bit run, at constant ECD, as shown in the example. Provided that the ECD and formation pressure remain constant, the bit will dull and the ROPN will follow the dulling trend. If a deviation from the dulling trend is noted at constant ECD, this then indicates either a lithology change or a change in formation pressure. Lithology changes are generally abrupt, and easily identified. Formation pressure changes show a more gradual deviation from the dulling trend, as shown in the example plot at about 9950 ft and 10,100 ft. Vidrine and Benit (32) developed a graphical relationship between differential pressure across the bottom of the hole and the percentage decrease in ROP caused by this overbalance. Using this relationship, the extrapolated dulling trend ROP N and the observed ROPN at a particular depth are used to estimate the actual formation pressure at that depth. The method is detailed in full by Prentice(26) together with worked examples and a comprehensive discussion of the theory behind the method. The method is quoted as being the most responsive of all methods used to indicate the changes in formation pressure, but no data are presented to support this claim. (b) Sigmalog This method was developed by AGIP and Geoservices(3). Basically, it is a plot of a calculated rock strength parameter versus depth. The method is based on the following drilling rate equation (developed by AGIP): 0.5 0.25 √σ t = WOB . N B . ROP0.25 (2-20) where √σt = ‘raw’ rock strength parameter and WOB, N, B and ROP are as previously defined. The ‘raw’ rock strength is then corrected to the rock strength parameter, √σo, using experimentally derived relationships to account for depth and bottomhole differential pressure (assuming a normal formation pressure gradient). The Sigmalog is then constructed by plotting √σo versus depth. 2-41 March 1995 BP WELL CONTROL MANUAL In normally pressured formations, √σo will increase with increasing depth and compaction. A normal compaction trend can be established and a decrease in √σo away from the normal trend will indicate an increase in formation pressure. When this occurs, the relationship used to correct √σt to √σo is reworked to determine the true bottomhole differential pressure (not the assumed one). The formation pressure can then be calculated from the differential pressure and the ECD for the mud weight in use. Various factors such as faults, unconformities/disconformities, poor bit efficiency, coring etc, cause ‘shifts’ in the normal trend. However all the normal trends have the same slope, and the shifts of the trendlines are proportional to the shifts in the values of √σo. Correct shifting of the normal trendlines is thus of prime importance in calculating formation pressures from the Sigmalog. Despite this problem, it is claimed that the Sigmalog is an excellent formation pressure evaluation tool and can be applied both in shale and non-shale lithologies. The Sigmalog is commonly used by Geoservices to estimate formation pressures. (c) Other Methods Several other methods of formation pressure evaluation from drilling rate equations have been put forward. These include methods by Combs (10) , Zoeller (33) , and Bourgoyne (5). These are not discussed here but are referenced in case of interest to the␣reader . 2.4 Hole Characteristics (a) Drag and Torque Drag is the excess hook load over the free hanging load required to move the drillstring up the hole. Drag may be caused by bit and stabiliser balling, dog legs, insufficient hole cleaning, etc, and also by overpressure effects in shales. Overpressured shales often behave plastically and creep into the borehole. This reduces the wellbore diameter and will cause an increase in drag as the bit/stabilisers are moved up through the section. In an underbalanced drilling situation, an increased volume of cuttings may come into the wellbore. This may result in an increase in drag when picking up the drillstring to make a connection, especially if the cuttings are not circulated above the drillcollars prior to picking up. Normal drag after drilling new hole is usually of the order of 10,000 to 20,000 lb, depending on the hole and BHA geometries. Consistent drag values much higher than this may indicate borehole instability caused by abnormal pressures. In deviated holes however, consistently higher drag will invariably be seen. Torque usually increases gradually with depth due to the increase in wall-to-wall contact between the drillstring and borehole. If underbalanced conditions exist then an increase in torque may be observed due to excess cuttings entering the hole. A reduced wellbore diameter caused by overpressured shales may also result in an increased torque, especially if full gauge stabilisers are being used. However, increased torque resulting from underbalanced conditions is virtually unseen when the pressure differential into the wellbore is less than 1 ppg (0.12 SG) equivalent pressure gradient. If an increase in torque is taken to indicate underbalanced conditions, then concurrent increases in drag and hole fill (see below) should also be expected. 2-42 March 1995 BP WELL CONTROL MANUAL Torque can be useful in detecting large increases in pore pressures, for example when crossing a fault line into overpressured formations. However, sudden large increases in torque can also be caused by a locked cone on the bit, a sudden change in formation type, and by stabilisers ‘hanging up’ on hard stringers. Both torque and drag are not considered to be valid overpressure indicators when drilling high angle deviated holes. Also, increases in torque due to abnormal pressures are difficult to distinguish from the normal torque increase with depth. When drilling from a floating rig the vessel motion and varying offset from the wellhead tend to produce significant torque fluctuations that make interpretation very difficult. (b) Hole Fill Hole fill after making a connection or after a trip out of the hole may indicate abnormal pressures. As discussed above, overpressured shales may squeeze into the wellbore and reduce its diameter. Then, as the bit is run in the hole to bottom after a connection or trip, it removes the shale which is pushed to the bottom of the hole. Cavings caused by underbalance conditions may also enter the wellbore during a connection or a trip and cause hole fill. Hole fill may also be the result of insufficient hole cleaning caused by poor mud properties, or by not circulating all the cuttings out of the hole prior to tripping. However, any excessive hole fill after making a connection or a trip should be noted and other abnormal pressure indicators evaluated to determine if overpressures are actually being encountered. 3 Drilling Mud Parameters 3.1 Gas Levels Hydrocarbon gases enter the mud system from various sources during the drilling of a well. The gases in the return mud stream are extracted from the mud for analysis in the mud logging unit. There is no quantitative correlation between measured gas levels and formation pressure. However, changes in gas levels can be accounted for by relating them to the actual drilling operation in progress (drilling, tripping etc) and the mud weight in use. Tentative pore pressure estimates may then be made. The main sources of gas in the mud system are: • Gas liberated from drilled cuttings. • Gas flowing into the wellbore due to underbalanced conditions. The gas levels from these sources are dependent upon the formation gas saturations, the mud weight and the particular drilling operation. 2-43 March 1995 BP WELL CONTROL MANUAL Gas levels are categorised as follows: (a) Background Gas (BGG) This is the total level of gas extracted from the return mud stream whilst drilling ahead. It originates primarily from the unit volume of formation cut by the bit. Hydrocarbons are often generated within shales and migrate to more porous formations such as sandstones where they may be trapped. Gas in shale cuttings is released into the mud stream due to the reduction in pressure as the cuttings are circulated up the hole. If hydrocarbons are present in any porous formations drilled, there will be relatively high levels of background gas in the mud stream. However, if the mud weight in use causes a high overbalance, there may be little, if any, entry of gas into the mud. The high overbalance will cause the mud filtrate to ‘flush’ the gas away from the wellbore. In underbalanced drilling conditions, gas may enter the mud at a rate that depends on the permeability of the formations being drilled. Shales may shown an increase in background gas levels, due to an increase in cavings caused by the underbalanced conditions. Background gas levels normally show a gradual increase as a transition zone to abnormal pressures is drilled. Background gas can not be used quantitatively to estimate formation pressures since the levels depend on mud circulation rate, efficiency of gas extraction from the return mud stream (gas trap efficiency) and also on the gas composition. However, if mud properties, drilling conditions, and lithology remain fairly constant, then increasing background gas levels may well indicate that the formation pressure gradient is approaching, or possibly exceeding the mud weight gradient. (b) Connection Gas (CG) When circulation is stopped to make a connection, the bottomhole pressure of the mud column is reduced by an amount equal to the annulus pressure loss i.e. the effective mud weight is reduced from the ECD to the static mud weight. This reduction in pressure may be enough to allow a small amount of gas to be produced into the mud column. This is known as connection gas. Also, connection gas may also be caused by ‘swabbing’ when picking up the drillstring to make a connection. When this gas reaches the surface, it appears as a peak above the background gas level on the total gas trace recorded in the mud logging unit. Connection gas peaks are generally short and sharp depending on the ‘bottoms up’ time, i.e. the longer the bottoms up time, the wider the peak will be. It is possible to correlate connection and background gas levels with the mud weight to give a fairly accurate estimate of the formation pressure. This is shown schematically in Figure 2.22. As the pore pressure approaches the bottomhole dynamic pressure, connection gas peaks begin to appear, probably due to swabbing. As the pore pressure increases further, the background gas level also begins to increase and the connection gas peaks become higher. It is reasonable to assume at this point that the pore pressure slightly exceeds the dynamic bottomhole pressure (ECD). A slight increase in the mud weight at this point then causes a sudden decrease in the background gas and the connection gas peaks disappear, indicating that a slight static overbalance has been established. 2-44 March 1995 BP WELL CONTROL MANUAL PRESSURE PROFILES MUD WEIGHT GAS LEVELS C Connection C Bottomhole Dynamic Pressure DEPTH C C Background Gas Pore Pressure Connection Gases C C Increase in BGG Level C C C C C C – Indicates connection WEOX02.099 Figure 2.22 Schematic Diagram showing Mud Gas Levels as an Indicator of Formation Pressures One major problem with this type of interpretation is to distinguish connection gas peaks caused by effective mud weight reduction due to stopping circulating, from gas swabbed into the wellbore when the drillstring is picked up. Swabbing effects are much more difficult to quantify than simple reductions from the ECD to static mud weight. This may result in higher than actual pore pressure estimates being made, especially if the connection gases observed are entirely due to swabbing. Clearly, it is good practice to use connection procedures that minimise swabbing. If used consistently, this will aid in the interpretation of connection gas levels. (c) Trip Gas (TG) This gas is produced by the same mechanism as connection gas, but the effect of swabbing due to pulling the drillstring from the hole will generally be greater. This is because the cuttings will have been circulated from the annulus and pipe speeds will be greater. A trip gas peak will be observed on circulating bottoms up after a round trip or non-drilling operation. Swabbing, due to pulling the drillstring out of the hole, may cause the whole of the openhole section to be underbalanced. Thus the observed trip gas may not come from the bottom of the hole but from somewhere higher in the openhole section, and two or more gas peaks may be observed. This effect may also appear for connections if there is a high degree of swabbing or the hole is underbalanced. Lag time calculations should locate the depths/formations causing the gas peaks. 2-45 March 1995 BP WELL CONTROL MANUAL Due to the complex causes of trip gas, it may only be used qualitatively in estimating formation pressures. The early onset of trip gas after circulation is resumed may indicate that much of the openhole is slightly underbalanced. Other abnormal pressure indicators must be consulted to confirm this. (d) Miscellaneous Gases These are mainly ‘kelly gas’, recirculated trip gas and carbide gas. GAS LEVEL TOTAL GAS 10 20 MUD WEIGHT 30 40 50 60 70 60 70 60 70 RECYCLED TRIP GAS 20 30 40 50 TIME 10 KELLY CUT TRIP GAS 10 20 30 40 50 CIRCULATION STARTED WEOX02.100 Figure 2.23 Example of Mud Gas Levels showing Trip Gas, Kelly Gas (Kelly Cut), and Recycled Trip Gas 2-46 March 1995 BP WELL CONTROL MANUAL Kelly gas (also known as ‘kelly cut’) is caused by air being circulated around the system from a partly empty drillstring or kelly after a trip or connection. The air is pumped into the borehole as a slug of mud aerated with compressed air. This enhances any gas diffusion effects from formations to the borehole and may result in enrichment of the aerated mud with the hydrocarbon gases. A gas peak will thus be recorded when this mud is circulated back to the surface. Kelly gas due to connections is rarely seen as the kelly is usually kept full of mud during connections by closing the lower kelly cock. Kelly gas after a trip is sometimes observed (as shown in Figure 2.23) but should be easily distinguishable from other gas peaks by experienced Mud Loggers. Although indicating the presence of hydrocarbon gases, kelly gas is of no value for formation pressure evaluation. Recirculated trip gas (or any other recirculated gas) behaves in a similar way to kelly gas, and should be anticipated by the Mud Loggers from knowledge of the mud system total circulation time. An example is shown in Figure 2.23. Carbide gas is used to check the calculated total circulation time and is caused by the Mud Loggers putting calcium carbide down the drillpipe at a connection. The carbide reacts with the water in the mud to produce acetylene, a hydrocarbon gas that is detected as a large sharp gas peak when circulated round to surface. The circulation time can then be used to back calculate the openhole volume and thus to check for hole enlargement. It must be noted that evaluation of formation pressures from gas levels relies entirely on hydrocarbon gases being present to some extent in the well being drilled. Occasionally, very ‘dry’ holes are drilled which may be overpressured, but show very low background gas levels. In these wells, it is very difficult to use gas levels as a reliable formation pressure indicator. 3.2 Temperature Due to the radial flow of heat from the earth’s core to the surface, the subsurface temperature increases with increasing depth. The geothermal gradient is the rate at which the temperature increases with depth and is usually assumed to be constant for any given area. However, it has been found that the temperature gradient across abnormally pressured formations is generally higher than that found across normally pressured formations in the same area. This phenomenon can be explained by considering the thermal conductivity of the formations. Since water has a thermal conductivity of about one-third to one-sixth that of most formation matrix materials, then formations with a higher water content (higher porosity) will have a lower thermal conductivity. These formations will thus have a higher geothermal gradient across them. Overpressured shales usually have a higher water content than normal and will thus have higher than normal geothermal gradients across them. The top of an overpressured shale should therefore be marked by a sharp increase in geothermal gradient. This may often be reflected by an increase in the temperature of the return mud in the flowline. Also, the caprock immediately above a pressure transition zone often shows a reduced geothermal gradient due to increased compaction (higher thermal conductivity) and a lower than normal temperature at the top of the transition zone. This effect is shown schematically in Figure 2.24. Again, this may be reflected in the flowline mud temperature by a reduced flowline temperature gradient. In some cases, the flowline temperature may even fall (negative gradient) and be then followed by a large increase as the overpressured zone is penetrated, as shown schematically in the plot of flowline temperature versus depth in Figure 2.25. 2-47 March 1995 BP WELL CONTROL MANUAL The example in Figure 2.25 is, of course, an idealised case. The flowline temperature very clearly reflects the changes in formation temperature and there are no other influences on the mud temperature. In practice, there are many other factors that affect the flowline temperature and make the interpretation of flowline temperature plots very difficult, especially offshore. Such factors include: • Circulation rate. • Rate of penetration. • Time elapsed since the last trip (the mud in the hole heats up during a trip). • Volume of the mud system. • Surface treatments such as adding water, mud chemicals or weighting material. • Ambient temperature (diurnal temperature changes, such as those encountered in desert regions, may cause large fluctuations in flowline temperatures). • Lithology effects (sandstones and limestones generally have higher thermal conductivities than shales). • Cooling effect of the sea around long marine risers. Various methods are used to improve the interpretation of temperature-depth plots. Surface effects can be minimised by measuring the temperature of the mud in both the flowline and the suction pit (mud temperature into the hole), and then plotting lagged differential temperature. A sharp increase in differential pressures may then indicate entry into a pressure transition zone. However, the temperature trends (flowline and differential) are still found to be obscured by discontinuities at bit trips, wiper trips and other periods with no circulation. These discontinuities split the temperature depth plot into a series of unconnected depth segments, as shown in the left hand curve in Figure 2.26. Since overpressure indications are based on temperature gradient changes rather than on the magnitude of the flowline temperature, each depth segment on the temperature-depth plot can be investigated separately for gradient changes. It may, however, be helpful to plot the segments end to end, disregarding the absolute temperatures, to produce a ‘smoothed curve’. Also, end to end plotting of the individual segment trendlines may be of value, but care is required to ensure that this technique does not smooth out obvious gradient changes within an individual segment. The three techniques for plotting flowline temperature are shown in Figure 2.26. 2-48 March 1995 BP WELL CONTROL MANUAL GEOTHERMAL GRADIENT DEPTH GEOTEMPERATURE OVERPRESSURE WEOX02.101 DEPTH Figure 2.24 Schematic Diagram showing Theoretical Geothermal Gradients and Temperature Profile through an Overpressured Zone TOP OF OVERPRESSURED ZONE WEOX02.102 FLOWLINE TEMPERATURE Figure 2.25 Schematic Diagram showing Expected Flowline Temperature Response on Drilling through an Overpressured Zone 2-49 March 1995 BP WELL CONTROL MANUAL NEW BITS NB NB DEPTH NB NB NB NB NB NOTE TEMPERATURE REDUCTION GRADIENT NB NB NB NB TOP OF OVERPRESSURE NB RAW DATA END-TO-END PLOT FLOWLINE TEMPERATURE TREND-TO-TREND PLOT WEOX02.103 Figure 2.26 Example Flowline Temperature Plots showing Raw Data Plot, End-to-end Plot and Trend-to-trend Plot Due to the many factors affecting the flowline mud temperature, it is very difficult to interpret temperature-depth plots to evaluate formation pressures. At least, changes in the gradient of the plots may suggest that an overpressured zone has been penetrated. It is unlikely that flowline temperature will be the primary indication of abnormal pressures, though it may well be useful to support other pressure indicators. (a) Bottomhole Formation Temperature (BHT) The actual formation geothermal gradient can not be estimated from surface mud temperature measurements. Downhole formation temperatures are required. However, it is only possible to measure the downhole mud temperature. This is normally done during wireline logging runs as most logging tools contain a maximum recording thermometer. Mud temperatures recorded from consecutive logging runs are used to predict the actual bottomhole formation temperature, assuming that the maximum temperature is at the bottom of the hole. 2-50 March 1995 BP WELL CONTROL MANUAL T tL LOG tc + tL tL 241 257 262 4.25 7.00 9.50 0.260 0.178 0.133 300 290 RECORDED TEMPERATURE, T (°F) TRUE BHT IS 288°F 280 270 260 250 240 230 0 0.1 0.2 0.3 0.4 0.5 LOG tc + tL tL WEOX02.104 Figure 2.27 Example ‘Horner’ Temperature Plot for Estimation of True Bottomhole Temperature (BHT) When drilling, the formations in the lower section of the hole are cooled by the mud in circulation. When circulation stops, the mud temperature begins to rise and gradually approaches the formation temperature. It is estimated that about four days are required for the mud temperature to reach equilibrium with the formation temperature. A modified Horner expression is used to model the temperature increase with time. By extrapolating 2-51 March 1995 BP WELL CONTROL MANUAL the temperature increases to infinite time, it is possible to estimate the formation temperature. The Horner temperature expression is: T = Tf – c.log where T Tf c tC tL tC + t L tL (2-21) = measured temperature (°F or °C) (from each wireline logging run) = actual formation temperature (°F or °C) = constant = circulation time at TD = time since circulation stopped A plot of T versus log ((tC + tL)/tL) should thus give a straight line, as shown in Figure␣2.27. At ‘infinite time’ after circulation was stopped (i.e. tL = infinity), the value of log (t C ␣+␣t L)/tL) equals zero. Hence, extrapolating the plot to intercept the temperature axis gives the estimated actual formation temperature, as shown in Figure 2.27. The geothermal gradients between the logging run end points can then be calculated. Increases in the geothermal gradient may indicate the presence of abnormal pressures. Unfortunately the actual formation temperature can only be estimated at logging points. Thus, only three or four formation temperatures can be estimated from which geothermal gradients can be established. These gradients are thus average gradients over significant depth intervals and they can only be established after each hole section has been drilled. Hence, they are generally of little use in pressure evaluation while drilling, but may confirm any flowline temperature trends that were noticed earlier. 3.3 Resistivity/Conductivity/Chlorides The resistivity of a formation depends on the porosity and the dissolved salts concentration in the formation pore water. Due to their higher pore water content, overpressured shales generally have lower resistivities than normally pressured shales at the same depths. When using water base muds, an attempt can be made to monitor this formation property by measuring the mud conductivity (conductivity is simply the inverse of resistivity). The mud conductivity at the flowline and suction pit can be measured and a conversion made to chlorides. An increase in the differential chlorides, known as ‘delta-chlorides’, may then indicate abnormal pressures. It is doubtful whether an increase in mud conductivity due to the release of pore water from drilled cuttings would be measurable. This is due to the volume of pore water released being minute compared to the volume of mud. However, pore water influxes from more permeable formations may be seen as changes in mud conductivity or delta-cholrides. Hence, a warning of underbalanced conditions may be given. The system is best suited to situations where there is a large difference between pore water and mud salinity. In these situations, the response of differential mud conductivity is similar to that of mud gas levels showing influx peaks at connections or a gradual increase due to underbalanced conditions. This is shown schematically in Figure 2.28. Obviously, mud conductivity as an abnormal pressure indicator has many limitations. A large salinity contrast between mud filtrate and formation fluids is required. Thus, the method is of little use in saline mud systems, unless of course, the mud filtrate salinity is much greater than the formation water salinity. This could be the case with saturated salt and potassium chloride (KCl) mud systems, and may well result in a mirror image plot to that shown in Figure 2.28. 2-52 March 1995 BP WELL CONTROL MANUAL ZERO LOSS GAIN MUD CONDUCTIVITY DEPTH MUD CHLORIDE INFLUX AT CONNECTION CONTINUOUS INFLUX INCREASE MUD DENSITY MUD CONDUCTIVITY MUD CHLORIDE WEOX02.105 Figure 2.28 Example of Typical Response of Differential Mud Conductivity/Delta Chlorides 3.4 Flowline Mud Weight Continuous recording of the flowline mud weight will show mud density changes due to gas cutting or formation influxes. Some influxes are not always picked up by an increase in return mud flow or by an increase in mud pit level, especially if the influx occurs gradually due to a very low permeability formation. Thus, an underbalanced situation due to abnormal pressures may be indicated by a slight reduction in the flowline mud weight. 4 Cuttings Parameters (a) Shale Bulk Density The bulk density of normally compacted shales increases with depth. Overpressured shales are generally undercompacted and thus have higher porosities and lower bulk densities than would be expected. If shale bulk density is plotted against depth as drilling progresses, then a normal compaction trendline can be established. A decrease in shale bulk density away from the normal compaction trendline may then indicate the presence of an overpressured zone. A schematic shale bulk density plot is shown in Figure 2.29. 2-53 March 1995 BP WELL CONTROL MANUAL The magnitude of abnormal pressures can be calculated from shale bulk density plots using the equivalent depth method (as described previously for d-exponent plots). DEPTH NORMAL SHALE TREND LINE TOP OF OVERPRESSURES 2.4 2.5 SHALE DENSITY (gm/cc) 2.6 WEOX02.106 Figure 2.29 Schematic Shale Bulk Density/Depth Plot Alternatively empirical curves, relating observed bulk density deviation from the normal trend to formation pressure gradient, can be used. However, such curves are area dependent, so can only be used if the appropriate area curve is available. Hence it will usually be necessary to use the equivalent depth method if formation pressure magnitudes are required from shale bulk density plots. 2-54 March 1995 BP WELL CONTROL MANUAL The most common methods of measuring shale bulk density at the rigsite are: • Mud Balance Shale cuttings are added to the mud balance cup until the balance reads 1.0 SG (8.33␣ppg) with the cap on. The cup is then topped up with fresh water and re-weighed (W). The shale bulk density is then given by: Bulk density (SG) = • 1 2–W (2-22) Density Column A graduated column of fluid is prepared from a mixture of two fluids of different densities such that the density of the mixture varies with column height. The column is calibrated using beads of known density which settle at different heights in the column. Selected shale cuttings are then dropped into the column and the height at which they settle is converted to shale density using the calibration curve. The method is illustrated in Figure 2.30. 250 200 SG 2.2 150 2.3 Shale 2.65 100 Shale Density 2.48 FLUID LEVEL cc 2.38 50 0 2.2 2.3 2.4 2.5 2.6 2.7 2.8 DENSITY (gm/cc or SG) WEOX02.107 Figure 2.30 Variable Density Column for Measuring Shale Bulk Density The mud balance method has the advantage of being fast and simple and uses a good quantity of cuttings to obtain a good average bulk density. The density column, however, requires selection of individual cuttings and multiple determinations to obtain an average density value. The mud balance method is probably the more representative method. 2-55 March 1995 BP WELL CONTROL MANUAL Use of shale bulk densities for the detection and evaluation of formation pressures frequently has the following limitations: • Presence of shale gas in the cuttings decreases the bulk density values determined. • Cavings from higher up the hole may be part of the sample. • The reliability of the data depends on the consistency and care taken by personnel, when carrying out the density determinations. • Formation age boundaries and unconformities may cause shifts in the normal compaction trendline. It may be necessary to determine individual normal compaction trends for each geological age unit. • Variations in the lithology, such as high carbonate content, silty/sandy shales etc, may cause significant variations in the bulk density determinations. Only good clean shales should be plotted. The presence of high density minerals, such as pyrite, will increase bulk density values and may mask the onset of abnormal pressures. • Density measurements on cuttings from water base muds are usually low due to the absorption of water by the cuttings. Less reactive muds, such as oil base muds and highly inhibited water base muds, will give more accurate cuttings densities. SHALE DENSITY DEPTH NORMAL PRESSURE OVERPRESSURE COMPACTION DISEQUILIBRIUM CLAY DIAGENESIS AQUATHERMAL PRESSURING TECTONIC PRESSURING WEOX02.108 Figure 2.31 Response of Shale Bulk Density/Depth Plots in Overpressures caused by Various Mechanisms 2-56 March 1995 BP WELL CONTROL MANUAL • The response of shale bulk density values in abnormal pressured zones will vary with the type of mechanism that caused the overpressure. This is illustrated by the idealised plots shown in Figure 2.31. However, as most overpressures in shales are caused by compaction disequilibrium and aquathermal pressuring, the most common response will be a decrease in shale bulk density at the top of an overpressured zone. (See Chapter 1 Section 1.4 for explanations of the various causes of abnormal formation pressures.) Despite the above limitations, shale bulk density plots can be a very valuable indicator of abnormal pressures. They should be constructed during the drilling of all exploration and appraisal wells, and are most useful when long shale sections are encountered. (b) Shale Factor Shale factor is a measure of the cation exchange capacity (CEC) of shales. The CEC of a shale is dependent on the montmorillonite content. This in turn depends on the degree to which montmorillonite conversion to illite has progressed in the shale since montmorillonite has a much higher CEC than illite (See ‘Clay Diagenesis’, in Chapter␣1 Section 1.4). The CEC is expressed in milli equivalents per 100 grams of sample (meq/100gm), and is termed the shale factor. The shale factor of a sample of shale cuttings is determined using the methylene blue test. Basically, a suspension of powdered sample (in water) is titrated against a solution of methylene blue dye of known concentration. The end point of the titration is when the sample suspension water first turns blue. The shale factor is then calculated from: shale = 100 factor sample wt (meq/100gm) (gm) X titrant vol (ml) X titrant normality (2-23) Pure montmorillonite clays have a high shale factor of about 100 meq/100gm. This is due to the presence of many loosely bound cations (Na+ , Ca++) between the clay platelets. However, pure illite clays, due to their tightly bound cation (K+ ) between clay patelets, have low shale factors of 10 to 40 meq/100gm. Thus, shale factor can be used to identify the montmorillonite/illite content of shale samples. For abnormal pressure evaluation, however, the use of shale factor is limited as it is dependent on the various mechanisms that may cause overpressures. Generally, shale factor decreases with depth as montmorillonite is converted to illite. In␣ o verpressured intervals caused by compaction disequilibrium (see Chapter 1 Section␣1.4 ) clay dewatering has been restricted, which in turn restricts montmorillonite diagenesis to illite. Thus a larger proportion of montmorillonite will be present in the overpressured zone, resulting in an increase in shale factor. This is shown schematically in Figure 2.32␣(a). However, overpressures caused by clay diagenesis (montmorillonite dehydration) will show a decrease in shale factor on entering the overpressured zone. The proportion of montmorillonite has been reduced by conversion to illite, with the release of large amounts of water. This causes increased pore pressure if water escape is restricted. This shale factor response is shown schematically in Figure 2.32 (b). 2-57 March 1995 BP WELL CONTROL MANUAL Since compaction disequilibrium is thought to be the major contributing mechanism to overpressure development in shales, the shale factor response of Figure 2.32 (a) will probably be the most dominant. However, the contribution of other overpressure mechanisms will complicate the interpretation of shale factor plots. This often results in shale factor being of little use in the detection of abnormal pressures. DEPTH SHALE FACTOR DEPTH SHALE FACTOR MONTMORILLONITE CONTENT INCREASE MONTMORILLONITE CONTENT DECREASE OVER PRESSURES (a) COMPACTION DISEQUILIBRIUM OVERPRESSURES (b) CLAY DIAGENESIS WEOX02.109 Figure 2.32 Shale Factor/Depth Response to Overpressure caused by Compaction Disequilibrium and Clay Diagenesis (c) Cuttings Character The presence of cavings in drilled cuttings samples is an indication that the borehole wall is unstable. Cavings are much larger than normal drilled cuttings and are readily seen at the shale shakers. They are thought to be produced by two different mechanisms which result in cavings of different shapes and sizes, these two mechanisms are: • Underbalanced drilling • Borehole stress relief In underbalanced drilling conditions, the pore pressure in the formation adjacent to the borehole is greater than the pressure in the borehole. In impermeable formations, such as shales, the pressure differential due to an underbalance may be high enough to exceed the tensile strength of the shales. The shale will thus fail in tension and form cavings which fall into the borehole. These cavings are usually long, splintery, concave and delicate, as illustrated in Figure 2.33 (a). 2-58 March 1995 BP WELL CONTROL MANUAL The natural stresses that are present in the earth’s crust vary regionally and with depth, lithology etc. Drilling a hole through formations will relieve some of these stresses depending on the hole angle and direction in relation to the principal formation stresses. The result may be that the formation stress at the borehole wall is greater than the stress (pressure) due to the mud column. The borehole wall may then fail either in compression from vertical stresses or in tension due to horizontal stresses, or a combination of both. Cavings produced in this manner tend to be blocky and rectangular in shape, as shown in Figure 2.33 (b). Thus, the presence of cavings in cuttings samples will not necessarily mean that the hole is underbalanced. However, other overpressure indicators should always be examined in detail to confirm whether abnormal pressures are being encountered. Even if it can not be confirmed that the hole is underbalanced, it may still be necessary to increase the mud weight to regain hole stability, and avoid the problems caused by excessive amounts of cuttings/cavings being present in the hole. FRONT SIDE MAY BE STRIATED FRONT SIDE SCALE 0.5in to 1.5in TYPICALLY CRACKED DELICATE SPIKY SHAPE BLOCKY RECTANGULAR SHAPES PLAN PLAN CONCAVE SURFACE (a) Typical shale caving produced by underbalanced conditions (b) Typical shale caving produced by stress relief WEOX02.110 Figure 2.33 Characterisation of Shale Cavings Caused by Underbalanced Conditions and Stress Relief (d) Other Methods Several other methods of formation pressure evaluation based on measurements on shale cuttings have been developed. These include shale cuttings resistivity, filtration rate of shale cuttings slurry, filtrate (shale water) colour index, shale cuttings moisture index, redox and pH potential of cuttings slurry and slurry filtrate. These methods are fairly complex and time consuming and thus have not gained wide acceptance as rigsite techniques. A more detailed discussion of these techniques is given by Fertl(17). 2-59 March 1995 BP WELL CONTROL MANUAL 5 Measurement While Drilling (MWD) Techniques Measurement While Drilling (MWD) tools are now able to provide continuous downhole drilling parameter data and electric log data whilst drilling is in progress. The use of MWD data in formation pressure evaluation follows the same principles as previously discussed for surface measured drilling parameters, as outlined for wireline log data in Section 2.4 of this Chapter. The advantage of MWD data is that actual downhole drilling parameters (weight-on-bit, torque) are measured and the formation log data are obtained very shortly after the formation has been drilled. Thus, formation log data and conventional ‘whilst drilling’ techniques can be combined to evaluate formation pressures as drilling progresses. The downhole drilling parameters of most relevance are: • Weight-on-bit The actual downhole weight-on-bit (WOB) is usually less than recorded at surface due to the drag in the hole. Using the actual downhole WOB will give more accurate values for d-exponent or the drilling rate method that is being used as a formation pressure indicator. • Downhole Torque Variations in torque at the bit may be used to indicate bit wear. This in turn may be used to account for bit wear in more complex drilling rate methods for estimating formation pressures. • Downhole Temperature The difference between downhole annulus temperature and flowline temperatures will give an indication of the amount of heat transferred from the formation to the mud. A similar effect to that described in ‘Differential Temperature’ on Page 2-50, should be observed on drilling into an overpressured zone. The MWD formation logs presently available for formation pressure evaluation are gamma ray, resistivity and most recently, porosity. The gamma ray log is used to identify lithology. Shales show a high level of radioactivity, whereas sands and evaporites (except for complex salts) show a low level. Hence the gamma ray log can be used to pick clean shale sections for overpressure determination by any of the shale related parameters previously discussed. In particular, the gamma ray log can be used in conjunction with the MWD resistivity log to plot shale resistivities whilst drilling. The theory and method of formation pressure evaluation from shale resistivities is discussed further under ‘Wireline Logs’ in Section 2.4 of this Chapter. The gamma ray log itself has been used as a formation pressure indicator. A normal depth related compaction trend was established with departures from this trend indicating the magnitude of overpressures. However, it would appear that this method may only be valid for US Gulf Coast shales. More recently, an MWD porosity log has become available. Thus shale porosities may be measured whilst drilling and a normal compaction trend established. Again, overpressured shales will show an increase in porosity away from the decreasing normal trend. The MWD gamma ray log will also be required to pick clean shales, from which the porosity values can be plotted. 2-60 March 1995 BP WELL CONTROL MANUAL The combination of MWD logging techniques and downhole/surface measured drilling parameter techniques should enhance the ability to detect and evaluate formation pressures whilst drilling is in progress. Developing MWD technology is continually assessed by Drilling Division, and reports periodically issued. 6 Mud Logging Service The function of the wellsite mud logging service is twofold: • Sampling and description of drilled cuttings, and hydrocarbons detection and evaluation. • Monitoring and interpretation of drilling data for drilling optimisation and formation pressure evaluation. These functions, and their relation to information flow through a typical mud logging unit,␣are illustrated in Figure 2.34. The level to which the latter function is required depends on the␣ t ype of well being drilled. Usually exploration and appraisal wells require mud logging␣ s ervices capable of a higher level of formation pressure evaluation than for development wells. (a) Pressure Evaluation Service In most mud logging services, there is a Pressure Evaluation Geologist or Engineer permanently on duty in the mud logging unit. It is this individual’s responsibility to closely monitor all the available formation pressure indicators and to communicate this information to the Company supervisory personnel at the rigsite. He should also make formation pressure estimates based on all the available pressure indicators (and discussions with Company personnel), and be able to support these estimates with sound reasoning. The Pressure Evaluation Geologist/Engineer holds a very responsible position amongst the various rigsite personnel and should have many years experience in rigsite mud logging work. It is important that a good level of communication is established and maintained with the person(s) concerned in order that reliable formation pressure estimates are obtained and their implications speedily acted upon. (b) Composite Logs As part of the pressure evaluation service, the Pressure Evaluation Geologist/Engineer will prepare ‘composite logs’ showing well depth versus various selected overpressure␣indicators. These logs are potentially most useful as they show graphically the response of the various overpressure indicators to differing lithologies and formation␣pressure regimes. It is most important that these logs are kept up to date to enable up-to-the-minute pressure estimates to be made based on the information given by the logs. 2-61 March 1995 BP WELL CONTROL MANUAL Figure 2.34 Mud Logging Unit Functions and Information Flow Diagram KELLY POSITION DEPTH GAS FROM MUDSTREAM PENETRATION RATE CARBON DIOXIDE H2S PUMP RATE MICRO GAS MUD FLOW TOTAL GAS HYDROCARBONS UV BOX CHROMATOGRAPH COMPUTATION DISPLAY DATA STORAGE MUD pH/PHS REMOTE DATA DISPLAY MUD RESISTIVITY EVALUATION MUD WEIGHT FORMATION CUTTINGS MUD TEMPERATURE PIT LEVEL/PVT DENSITY GEOCHEMICAL ANALYSIS DRILLING PARAMETERS KELLY HEIGHT HOOK LOAD BIT REVOLUTIONS DRILL RATE WEIGHT ON BIT ROTARY SPEED TORQUE TOTAL DEPTH STANDPIPE PRESSURE CASING PRESSURE CEC MUD PRESS FORMATION LOG MISC ENGINEERING DATA PRESSURE LOG WIRELINE LOG DATA GEOCHEMICAL LOG BASIC ADDITIONAL REMOTE DATA TRANSMISSION WEOX02.111 2-62 March 1995 BP WELL CONTROL MANUAL (c) Mud Logging Equipment The equipment contained within a modern mud logging unit is very complex, and there are numerous differrent types of sensors available for measuring the various drilling parameters. Different methods are also employed to relay the measured data to the mud logging unit. It is not the intention of this manual to discuss the equipment used by the individual mud logging service companies. General sensor specifications are however given in Table 2.3. Parameter to be Measured Required Accuracy Preferred Sensor Type +/- 0.1% +/- 1ppm +/- 0.5% Flame ionisation Solid state semi-conductor instrument Flame ionisation +/+/+/+/+/+/+/+/+/+/+/+/+/+/+/- Heave and tide compensation independent of kelly, for trip monitoring Pressure transducer (strain gauge) Proximity switch Hall effect current sensor Gamma ray Strain gauge Strain gauge Non-intrusive flow meter Paddle type flow meter Non-intrusive flow meter Proximity switches Platinum resistance Ultrasonics Ultrasonics Mud Logging Service Total gas Hydrogen sulphide Constituent gases Drilling Data Service Depth Kelly position Hookload Rotary speed Rotary torque Mud weight Standpipe pressure Choke pressure Flow rate in Flow rate out Flow rate out Pump rate Mud temperatures Pit volumes Trip tank volume Table 2.3 10 cm 10 cm 200 lb 1 rpm 5 amp 0.01 SG 10 psi 10 psi 20 gpm 50 gpm 20 gpm 1 SPM 1°C 5 bbl 0.5 bbl General Mud Logging Sensor Specifications (d) Mud Logging Unit Suitability The suitability of a mud logging unit for a Company drilling operation depends essentially on the level of pressure evaluation service required, which in turn depends on the type of well that is to be drilled. The basic geological sampling and mud logging service should not vary significantly with the well type. Once the required levels of mud logging and pressure evaluation services have been defined, then the suitability of individual mud logging units can be evaluated. The current specifications against which the mud logging units/services should be evaluated, are contained in BP report DTG/D/4/86 (24).These specifications cover the basic mud logging service (sampling, cuttings description etc), drilling data service (including pressure evaluation and drilling optimisation), reporting, software, data storage and personnel requirements. 2-63 March 1995 BP WELL CONTROL MANUAL 7 Summary The majority of the ‘whilst drilling’ formation pressure indicators discussed are only applicable to massive shale sections interbedded with sandstone/siltstones. However, as most of our drilling occurs in sedimentary basins containing such sections, then the techniques discussed are of direct relevance to our drilling operations. The most reliable abnormal pressure indicators in shales are probably d-exponent (or other drilling rate method) in combination with gas levels and cuttings character (cavings). Occasionally, one indicator may be particularly effective in showing the onset of abnormal pressures, but this will probably not be apparent until drilling has progressed well into the overpressured zone. It is stressed that all formation pressure indicators must be carefully examined to confirm the possible abnormal pressures that may be implied by a particular overpressure indicator. Also, the possibility of lithological changes should always be borne in mind when sharp changes in abnormal pressure indicators are observed. 2-64 March 1995 BP WELL CONTROL MANUAL 2.4 FORMATION PRESSURE EVALUATION AFTER DRILLING Paragraph Page 1 General 2-66 2 Formation Pressures from Wireline Logs 2.1 Sonic Log 2.2 Resistivity Log 2.3 Density Log 2.4 Other Logs 2-66 2-66 2-70 2-75 2-77 3 Direct Pressure Measurements 3.1 RFT/FIT Data 3.2 Drillstem Test Data 2-77 2-77 2-82 4 Summary 2-84 Illustrations 2.35 Schematic diagram showing the Operating Principle of the Sonic (BHC) Logging Tool 2-67 2.36 Schematic diagram showing Shale Sonic Interval Travel Time Response in Overpressures 2-68 2.37 Schematic Shale Resistivity/Depth Plot showing Response in Overpressures 2-71 2.38 Shale Resistivity/Depth Plot illustrating the Problems Associated with Formation Pressure Interpretation 2-73 2.39 Empirical Correlations for Estimation of Formation Pressures from Shale Resistivity Ratio 2-74 2.40 Log-derived Shale Bulk Density Plot on Semi-logarithmic Scales 2-76 2.41 Schematic diagram showing the RFT Pre-test and Sampling Principle 2-78 2.42 Diagram showing the Operation of the RFT Sample Probe 2-79 2.43 Example of an RFT Analogue Pressure Recording 2-79 2.44 Example of a Typical Drillstem Test String (for high pressure gas well) showing Position of Gauges 2-81 2.45 Example of a Typical Pressure Chart from a Mechanical Gauge placed below the Tester Valve in the DST String 2-83 2-65 March 1995 BP WELL CONTROL MANUAL 1 General After each intermediate and reservoir hole section has been drilled, the formations are electrically logged to evaluate their physical characteristics and hydrocarbon potential. Some of these logs can be used to estimate formation pressures to confirm (or otherwise) the estimates made whilst the hole sections were being drilled. Formation pressures calculated from wireline logs are estimates only. Direct formation pressure measurements are normally taken in the reservoir hole section(s) using a wireline repeat formation test (RFT) tool. Also, formation pressures are directly measured in the ‘shut-in’ (pressure build-up) periods during drillstem testing (DST) of potential reservoir formations. 2 Formation Pressures from Wireline Logs 2.1 Sonic Log The sonic logging tool measures the time, ∆t, required for a compressional sonic wave to travel through one foot (or metre) of formation. This is known as the interval transit time (ITT) and is the reciprocal of formation interval velocity. The principle of operation of the sonic tool (borehole compensated (BHC) tool) is shown in Figure 2.35. Sonic pulses from two transmitters travel through the formation, and are picked up by two pairs of receivers. The time difference between sonic arrivals at each pair of receivers is measured. The average time difference is then recorded to compensate for borehole geometry and tool tilt. As discussed in Section 2.2 of this Chapter, overpressured shales show a higher sonic ITT than normally pressured shales at the same depth. Thus, a plot of sonic ITT in shales versus depth on semi-logarithmic axes should show a straight line compaction trend in normally pressured shales. Departures from this line towards higher shale ITT values indicates abnormal pressures. The normal compaction trend and sonic log departure in overpressures are shown in the schematic sonic log plot in Figure 2.36. A discussion of the problems associated with the interpretation of ITT depth plots, is given in relation to seismic ITT data in Section 2.2 of this Chapter. The main problem areas are: • Scales Two types of formats have been proposed for plotting ITT-depth data. These are log-log plots (as suggested by Pennebaker(25)), and semi-log plots, as suggested above. The semi-log format is recommended as the linear depth scale enables direct comparison of sonic ITT data with other overpressure indicator plots. • Normal Trend Line It is sometimes very difficult to confidently establish the position of the normal shale␣compaction trend line. The depth interval over which the sonic log data are obtained in normally pressured upper hole sections is often too small to reliably establish the normal compaction trend. This is because logs are normally only obtained from below surface casing. 2-66 March 1995 BP WELL CONTROL MANUAL T UPPER TRANSMITTER R1 R2 t1 PAIRED RECEIVERS R1 + R3/R2 + R4 t = t2 – t1 R3 t2 MUD CAKE R4 T LOWER TRANSMITTER WEOX02.112 Figure 2.35 Schematic diagram showing the Operating Principle of the Sonic (BHC) Logging Tool Different lithologies frequently have vastly different sonic ITTs. Care should be taken to ensure that the normal compaction trend line is established through ITT values in good clean shale sections only. It may be necessary to make sonic log plots from several wells (if data are available) in the area of interest. These may then be used to determine the position and gradient of an average regional normal compaction trend line. • The BHC sonic tool has a ‘depth of investigation’ of only a few inches into the borehole wall. Hence, reactive shales that absorb water from the drilling mud, may exhibit higher ITT values (higher porosity) than would be recorded if the shales were non-reactive. These higher ITT values may falsely indicate the presence of abnormal formation pressures. A deeper reading ‘long spacing sonic’ (SLS) tool is sometimes run. When available, the sonic log data from this deeper reading tool should be used in preference to those from the BHC sonic tool. 2-67 March 1995 BP WELL CONTROL MANUAL Figure 2.36 Schematic diagram showing Shale Sonic Interval Travel Time Response in Overpressures DEPTH NORMAL COMPACTION TREND LINE TOP OF OVERPRESSURES SHALE INTERVAL TRAVEL TIME, t WEOX02.113 2-68 March 1995 BP WELL CONTROL MANUAL • Unconformities/disconformities may produce a marked sudden shift in sonic ITT values and may require a second separate normal compaction trend line to be established. Once the position of the normal compaction trend lines has been firmly established on the semi-log sonic ITT-depth plot, then the depths and magnitudes of suspected abnormal pressures may be calculated. Several methods are available for estimating the magnitude of abnormal pressures from sonic log plots: (a) Empirical Correlations Charts relating the magnitude of formation pressures to the difference between the observed shale ITT value and the extrapolated normal ITT value are available. These empirical correlations are area dependent, as shown by the examples in Figure 2.9. Note that the correlation developed by Pennebaker (25) (Figure 2.10) should not be used with semi-log ITT plots. This was developed for use in conjunction with log-log seismic ITT plots and is probably only valid for the US Gulf Coast. The empirical correlations are quick and easy to use as formation pressure gradients are read directly from the charts. However, the correlations are area dependent, so their use is limited to areas for which correlations are available. (b) Equivalent Depth Method When no empirical correlation is available, the equivalent depth method may be used. A full discussion of the method is given in connection with d c-exponent plots, in Section␣ 2 .3 of this Chapter. Equation 2-12 is also used for formation pressure calculations from sonic ITT plots: FPGO = OPGO – DE (OPGE – FPGNE) DO where FPG O OPG O OPG E FPG NE DO DE (2-12) = formation pressure gradient at depth of interest (psi/ft) = overburden pressure gradient at depth of interest (psi/ft) = overburden pressure gradient at equivalent depth (psi/ft) = normal formation pressure gradient at equivalent depth (psi/ft) = depth of interest (ft) = equivalent depth (depth at which sonic ITT is equal to value at DO) (ft) NOTE: Equation 2-12 can be used directly with gradients in SG, ppg or psi/ft and depths in metres or feet. It is necessary to obtain overburden pressure gradient data for the well being investigated in order to use the equivalent depth method. These data should be available in the form of an overburden gradient-depth plot in the Mud Logger’s report for the well. The advantages and disadvantages of this method are discussed in Section 2.3 of this␣Chapter . 2-69 March 1995 BP WELL CONTROL MANUAL (c) Eaton Equation The following equation was presented by Eaton(12) for calculation of formation pressures from sonic ITT plots, the derivation of which is exactly analogous to equation 2-18, which was developed for dc-exponent plots: FPGO = OPGO – (OPGO – FPGN) ∆t N ∆t O 3.0 (2-24) where FPGO and OPGO are as defined above and, FPG N = normal formation pressure gradient (psi/ft) ∆t N = extrapolated normal trend sonic ITT at depth of interest (µsec/ft) ∆t O = observed sonic ITT at depth of interest (µsec/ft) The value of the ITT ratio exponent, 3.0, was derived from actual well data. Despite the problems outlined earlier, it is considered that the use of sonic ITT data provides the most reliable method of formation pressure evaluation from well logs. The use of an empirical correlation provides the quickest method of estimating the magnitude of abnormal pressures from sonic ITT plots. However, if a correlation is not available for the area of interest, it will be necessary to use either the equivalent depth method or the Eaton equation (or both). These latter methods require overburden pressure gradient data which should be readily available in Mud Loggers’ reports for the well(s) under investigation. 2.2 Resistivity Log The resistivity of shales depends on the following factors: • Porosity • Salinity of pore water • Temperature Temperature varies approximately linearly with depth and hence formation resistivities can be corrected for temperature. Also, the salinity of the pore water should not vary significantly with depth. Porosity is thus the major factor controlling shale resistivity. Under normal compaction (i.e. in normal pressure environments), shale resistivity increases with depth since porosity decreases. A plot of shale resistivity versus depth will thus show an increasing trend with depth. In clean shale sections, any departure from this normal trend towards lower shale resistivities may indicate an increase in porosity and hence overpressures. Shale resistivity (Rsh) is plotted on a log scale versus depth on a linear scale. The shape and slope of the normal trend line will vary with the age and type of shales present. This will lead to individual normal compaction trends being developed for each area investigated. It is unlikely that any two areas will have identical normal compaction trends. A schematic shale resistivity-depth plot is shown in Figure 2.37. The normal compaction trend line may be a curve or may approximate to a straight line over certain depth intervals, depending on the area under investigation. 2-70 March 1995 BP WELL CONTROL MANUAL Figure 2.37 Schematic Shale Resistivity/Depth Plot showing Response in Overpressures DEPTH NORMAL COMPACTION TREND LINE CAP ROCK TOP OF OVERPRESSURE 0.4 0.6 0.8 1.0 1.5 2.0 3.0 SHALE RESISTIVITY, Rsh (ohm-m) WEOX02.114 2-71 March 1995 BP WELL CONTROL MANUAL Originally, shale resistivities were plotted from the amplified short normal (ASN) curve of the now absolute ES (electrical survey) logging suite. Today, a variety of resistivity logging tools are run, from which shale resistivity plots may be made. The tools are designed for various depths of investigation from shallow to very deep. The deep reading tools record the true resistivity of virgin formation and thus near borehole effects (shale hydration, mud filtrate invasion in permeable zones) do not affect the resistivity values recorded. The deep reading logs that should be used for resistivity plots are the ILd curve from the dual induction laterolog (DIL) tool and the LLd curve from the dual laterolog (DLL) tool. The dual laterolog tool requires a conductive mud, so it will not work in oil base muds. The dual induction laterolog will work in oil base or water base muds and tends to be the resistivity log that is normally run. Possible problems that may be encountered with shale resistivity plots are: • Only shale resistivities in thick clean shales must be plotted. It may be necessary to consult a geologist in order to pick good clean shales from the well logs. Use the deepest reading resistivity curve available to plot true shale resistivities. • It may be very difficult to firmly establish the shape and position of the normal compaction trend line from the resistivity plot for just one well. An average regional trend may have to be established from the resistivity plots of many wells in the area of interest. Unconformities/disconformities and variations in geological age may show sudden changes in shale resistivities which will affect the position of the normal trend line. • Changes in formation water salinity may give false pressure indications. For example, shales in the proximity of large salt masses (e.g. salt domes) have very low resistivities due to increased pore water salinity. This may indicate higher-than-actual formation pressures. Also, shales at depths less than 1000m below surface or the mudline, usually contain formation water fresher than sea water. This results in high resistivity values that may indicate lower-than-actual formation pressures. The problems associated with interpreting shale resistivity plots are illustrated in Figure␣2.38. Once the normal compaction trend has been firmly established, it is possible to estimate the magnitude of any abnormal formation pressures indicated by the shale resistivity plot. Again, there are several methods available: (a) Empirical Correlations At depths where the observed shale resistivity values (Rsh(O)) diverge from the normal trend value (Rsh(N) ), the ratio of normal to observed shale resistivity (Rsh(O)/R sh(N)) is calculated. The corresponding formation pressure gradient is then read from a chart such as the one shown in Figure 2.39. As can be seen from this chart, the correlations are area-dependent and the appropriate chart is required for the particular area under investigation. 2-72 March 1995 BP WELL CONTROL MANUAL Fresh water shales Normal pressure environment Region 'A' limey shales DEPTH ne o Err s tr ou Pressure top d en nd l tre rma No Abnormally high pressure environment Region 'B' Lithology, not pressure, change 0.1 0.5 1.0 5.0 Rsh (ohm-m) WEOX02.115 Figure 2.38 Shale Resistivity/Depth Plot illustrating the Problems Associated with Formation Pressure Interpretation (b) Equivalent Depth Method This method is identical to that previously discussed for dc-exponent plots (Section␣2.3 ) and sonic log plots (earlier this Section). Again, equation 2-12 is valid for use with shale resistivity plots: FPGO = OPGO – DE (OPGE – FPGNE) DO (2-12) where DE = equivalent depth (depth at which shale resistivity is equal to the value at the depth of interest, DO) (ft) and FPG O, OPG O, DO, OPGE, and FPGNE are as previously defined in connection with dc-exponent plots and sonic ITT plots. As explained previously, overburden gradient data must be obtained (from Mud Loggers’ report) in order to use this method. 2-73 March 1995 BP WELL CONTROL MANUAL 0.4 0.5 Reservoir FPG, psi/ft 1.25 0.6 North Sea (limited data) (Timko, 1972) 1.50 0.7 HottmanJohnson, 1965 South China Sea (Limited data) Timko, 1972 1.75 0.8 East Cameron Timko-Fertl, 1970 Equivalent mud weight, SG E Riverton area, Wyo (Timko, 1972) 2.00 0.9 Eaton, 1972 (Range) 2.25 1.0 10 15 20 30 Normal R(sh)/observed R(sh) 40 50 WEOX02.116 Figure 2.39 Empirical Correlations for Estimation of Formation Pressures from Shale Resistivity Ratio (c) Eaton equation Equation 2-25 was proposed by Eaton (12) for calculating formation pressures from␣ s hale resistivity plots (derivation analogous to equation 2-18, developed for dc-exponent plots): FPG O = OPGO – (OPG O – FPGN) Rsh(N) 1.20 R sh(O) where FPGO, OPGO and FPGN are as defined for equation 2-24 (sonic log plots), and Rsh(N) = extrapolated normal trend shale resistivity at depth of interest (ohm-m) Rsh(O) = observed shale resistivity at depth of interest (ohm-m) Again, the value of the shale resistivity ratio exponent, 1.20, was derived from actual well data. Overburden pressure gradients for the well are also required (from Mud Loggers’ well report) in order to use equation 2-25. 2-74 March 1995 BP WELL CONTROL MANUAL (d) Formation Factor Method This method was proposed by Foster and Whalen,(18) and is based on the equation: Fsh = Rsh Rw (2-26) where F sh = shale formation factor (dimensionless) Rsh = shale resistivity (ohm-m) Rw = formation water resistivity (ohm-m) Basically, the method involves computing a formation water resistivity (Rw) depth profile from the SP (spontaneous potential) curve in clean, shale free water sands. Values of Rsh are then obtained from thick, clean shales from whichever resistivity log is available (ILd or LLd curve). Values of Fsh at depths corresponding to the Rsh values are then calculated from equation 2-26. A plot of Fsh versus depth on semi-log scales (linear depth scale) then shows a straight line trend in normally pressured formations, F sh increasing with depth. Departure from the normal trend towards decreasing Fsh values then indicates abnormal pressures. The magnitude of any abnormal pressures can then be calculated using the equivalent depth method (as discussed in (b) above). The major drawback with this method is the calculation of R w values from the SP curve. The method is subject to inaccuracies, is difficult and is very time consuming. The advantage of this method is that it takes into account changes in formation water resistivity, R w. Other methods rely on the assumption that formation water resistivity remains relatively constant with depth. The method is detailed in full by Foster and Whalen(18) and Fertl(17). All the pressure evaluation methods using resistivity logs were developed for the US Gulf Coast and would appear to work quite well for this region. However, they have been found to be of limited use in the North Sea. Formation water salinity variations cause erratic tool responses which make it virtually impossible to construct a normal compaction trend. 2.3 Density Log The formation density logging tool consists of a radioactive source which bombards the formations with medium-energy gamma rays. The gamma rays collide with electrons in the formation which cause the gamma rays to scatter. The degree of scattering is directly related to the electron density and therefore the bulk density of the formation. The scattered gamma rays that return to the borehole are picked up by detectors in the logging tool. In the FDC (formation density compensated) logging tool, the gamma ray source and two detectors are mounted on a skid that is pushed against the borehole wall by an eccentering arm. The skid has a plough shaped leading edge to cut through any mud cake present on the borehall wall. Any mud cake that is not removed will effect the tool reading. The dual detectors of the FDC tool automatically compensate for mud cake effects. The corrected bulk density (Pb) and the correction made (∆ρ) are recorded on the FDC log. 2-75 March 1995 BP WELL CONTROL MANUAL Figure 2.40 Log-derived Shale Bulk Density Plot on Semi-logarithmic Scales DEPTH NORMAL COMPACTION TREND LINE CAP ROCK TOP OF OVERPRESSURES 2.0 2.1 2.2 2.3 2.4 2.5 2.7 SHALE BULK DENSITY (gm/cc) WEOX02.117 2-76 March 1995 BP WELL CONTROL MANUAL A plot of shale bulk density versus depth on either linear or semi-log scales will show a straight line normal compaction trend. Since the bulk density of shales is inversely proportional to porosity, and an increase in shale porosity indicates abnormal pressures, then a decrease in shale bulk density from the normal compaction trend line will indicate abnormal pressures. The semi-log type plot is shown schematically in Figure 2.40. The densities from non-washed-out pure shale sections should be plotted. After the normal compaction trend line has been established, the equivalent depth method (See ‘Sonic’ and ‘Resistivity Logs’) may be used to estimate the magnitude of formation pressures. The use of shale bulk density trends from the formation density log should be a fairly reliable overpressure indicator. However, it has been found that unless borehole conditions are ideal (uniform gauge hole), the formation density log will not be as accurate or reliable for pressure evaluation as other techniques based on sonic or resistivity logs. 2.4 Other Logs Other wireline logs that have been used to evaluate formation pressures include the spontaneous potential (SP) log, the neutron porosity log (CNL), the thermal neutron decay time log (TDT), and also downhole gravity and nuclear magnetic resonance (NMR) logs. These techniques are discussed further by Fertl(17). Also, the use of an MWD gamma ray log for formation pressure evaluation of US Gulf Coast shales, has been discussed by Zoeller(34). 3 Direct Pressure Measurements 3.1 RFT/FIT Data The repeat formation tester (RFT) is an electric wireline tool designed to measure formation pressures and to obtain fluid samples from permeable formations. After it has been run in the hole, the tool can be ‘set’ any number of times. This enables a series of pressure readings to be taken and permits the Logging Engineer to ‘pre-test’, or ‘probe’ the formation for permeable zones before attempting to take a fluid sample or a pressure recording. The RFT was developed from the formation interval tester (FIT) which is only able to take one, less accurate, pressure measurement whilst taking a sample. However, the FIT is able to take a pressure measurement/sample in cased hole by using a shaped charge to perforate the casing. A schematic diagram of the RFT pre-test and sampling principle is shown in Figure 2.41. 2-77 March 1995 BP WELL CONTROL MANUAL FILTER PROBE PACKER FLOWLINE PRESSURE GAUGE EQUALIZING VALVE (TO MUD COLUMN) CHAMBER No 1 CHAMBER No 2 PRETEST CHAMBER SEAL VALVE (TO LOWER SAMPLE CHAMBER) SEAL VALVE (TO UPPER SAMPLE CHAMBER) WEOX02.118 Figure 2.41 Schematic diagram showing the RFT Pre-test and Sampling Principle When the tool is set, a packer moves out on one side and back-up pistons move out on the opposite side. This forces the packer against the borehole wall and holds the body of the tool away from the wall to reduce the chances of differential sticking. The probe is then forced into the formation and opened by retracting the filter probe piston. This operation is shown in Figure 2.42. The two pre-test chambers are then operated sequentially, each sampling a small volume (10cc) of the formation fluid at different rates (assuming that the formation is permeable). A filter in the flowline probe prevents sand entry into the tool and the piston cleans the filter when the tool is retracted. A strain gauge pressure transducer monitors the pressure during the pre-test. The pressure is continuously recorded at surface in both analogue and digital form. An analogue pressure recording from a typical pre-test is shown in Figure 2.43. 2-78 March 1995 BP WELL CONTROL MANUAL MUD CAKE PACKER UNCONSOLIDATED SAND PROBE PISTON FLOWLINE FILTER PROBE CLOSED DURING INITIAL SET PROBE OPEN AND SAMPLING WEOX02.119 Figure 2.42 Diagram showing the Operation of the RFT Sample Probe FLOWRATE, Q q2 SHUT-IN q1 TIME, t PRESSURE, P t=0 t1 t2 HYDROSTATIC PRESSURE FORMATION PRESSURE P1 P2 TIME, t WEOX02.120 Figure 2.43 Example of an RFT Analogue Pressure Recording 2-79 March 1995 BP WELL CONTROL MANUAL The initial pressure (See Figure 2.43) before the tool is set is the hydrostatic pressure of the mud column. When the tool is set, the pressure rises slightly due to the compression of the mud cake by the packer. The probe piston then retracts giving a drop in pressure due to the flowline volume expansion and communication with the formation. When the piston stops retracting, there is a slight pressure rise because the packer continues to compress the mud cake until the tool is fully set. The pressure then drops again as the first 10cc pre-test piston starts to retract (at time tO). After about 15 seconds, the first pre-test chamber is full (at time t1) and the second piston begins moving at a rate 2.5 times faster than the first piston. The pressure thus drops further until the second pre-test chamber is full (at time t2 ). The pressure then builds up towards a final pressure, which is usually that of the original formation pressure(30). Finally, the probe and packer are retracted and the mud hydrostatic pressure is again measured. Thus, the RFT provides three distinct pieces of pressure data: • The mud column hydrostatic pressure (two readings). • The formation pressure. • The pressure transient induced by the withdrawal of a small sample of formation fluid (2 x 10cc). The two mud hydrostatic pressure readings are compared to verify the stability of the tool’s recording system. The two values should be within a few psi of each other. The formation pressure is used to verify estimates made whilst drilling the well and to construct a reservoir pressure profile. This will yield data on the pressure gradients and nature of the reservoir fluids. The pressure/flowrate/time data from the pre-test sample withdrawal can be used to calculate reservoir characteristics, such as permeability. Hence, the RFT provides accurate data on formation pressures. However, formation pressure data can only be obtained from permeable formations such as reservoir sandstones. These formations may or may not be at the same pressure as adjacent shales. RFTs are normally run at the request of the Geologists/Petroleum Engineers to seek information on potential reservoir formations. However, in deep high pressure wells, the RFT is being increasingly run to obtain accurate formation pressures before potentially troublesome drilling operations (such as coring) are commenced. Accurate knowledge of formation pressures in such wells allows fine mud weight adjustments to be made to minimise the risk of swab/surge pressure problems. 2-80 March 1995 BP WELL CONTROL MANUAL Figure 2.44 Example of a Typical Drillstem Test String (for a high pressure gas well) showing Position of Gauges DESCRIPTION Flowhead Tubing Lubricator Valve Tubing 5in PIPE RAMS 5in Slick Joint Tubing 5in Slick Joint MUD LINE Tubing Downhole Safety Valve (surface controlled) Tubing Annulus pressure operated Downhole Shut-in Tool (including tubing reverse-out facilities) Tubing Nipple Tubing (2 joints) Crossover Pressure Gauge Carrier + 2 Gauges Drill Collar (1 joint) Pressure Gauge Carrier + 2 Gauges Drill Collar (1 joint) Pressure Gauge Carrier + 2 Gauges No-Go Shoulder of Seal Assembly Permanent Packer Millout Extension Seal Assembly Seal Bore Extension Liner WEOX02.121 2-81 March 1995 BP WELL CONTROL MANUAL 3.2 Drillstem Test Data Whenever drillstem tests are carried out on potential reservoir formations, various pressure gauges are run in the hole with the test string. The purpose of these pressure gauges is to record the downhole pressure during the sequence of flow and shut-in periods that comprise the drillstem test (DST). The pressures recorded during the test are used to calculate reservoir characteristics such as formation pressure, permeability, skin damage and productivity index. Various types of pressure gauges are available. These are run in conjunction with clocks and recorders, and include: • Mechanical gauges – normally bourdon tube (BT) type pressure gauges with mechanical clocks and recorders. • Electronic gauges – strain gauge, quartz crystal or bourdon tube type pressure gauges with electronic clocks. Data are recorded on various types of electronic memories and read from the gauge on surface after the test by a special reader. • Electronic surface read out (SRO) gauges – strain gauge or quartz crystal type pressure gauges linked by cable to the surface where downhole pressures are continuously monitored and recorded. The mechanical and electronic gauges can be run in various ways/positions in the test string: • Set in a wireline nipple (hence retrievable during or after a test). • Hung off in the tailpipe (below the packer) using a DST hanging kit. • Placed in a ‘bundle carrier ’ or ‘gauge carrier’ in various positions in the string. The SRO gauges are always placed above the tester valve (above the packer) as they are connected to surface equipment by a cable. A typical DST string is shown in Figure 2.44 (for a gas well test). This illustrates the various positions of the pressure gauges in the DST␣string. After a DST has been successfully completed, the test string is pulled and the pressure gauges are retrieved for the pressure charts to be read. A typical valid pressure chart from a mechanical gauge placed below the tester valve is shown in Figure 2.45. Note that a linear plot of the pressures recorded by an electronic gauge should have the same general form, without the baseline. The significant events during the test (marked by capital letters) on Figure 2.45 are as follows: A: Atmospheric pressure at surface. A-B: The gauge is run in the hole with the test string and records increasing hydrostatic pressure. The early ‘steps’ effect is the result of pauses to pump the water cushion into the test string. B: At test interval depth, the gauge records the hydrostatic pressure of the mud column. C: The packer is set, squeezing the sump below the packer and causing an increase in pressure. D-E: The tester valve is opened and the gauge is suddenly subjected to the reduced hydrostatic pressure of the water cushion alone. 2-82 March 1995 BP WELL CONTROL MANUAL C D B N M G PRESSURE L I E F H J K A TIME O BASE LINE WEOX02.122 Figure 2.45 Example of a Typical Pressure Chart from a Mechanical Gauge placed below the Tester Valve in the DST String E-F: The influx of reservoir fluid into the test string adds to the pressure of the partial water cushion. F: The tester valve is shut after an initial 5 to 10 minute short flow period. F-G: The reservoir pressure slowly builds up. After 30 minutes, no more build up is seen. The gauge now gives an estimate of the virgin reservoir pressure (G). G-H: The tester valve is now opened again and the reservoir is exposed to hydrostatic pressure of the fluids in the test string. H-I: The reservoir flows again and the gauge pressure increases until the water cushion reaches the surface. I-J: As the reservoir fluid replaces the water cushion in the test string, the gauge pressure decreases until all the water cushion has been unloaded (J). J-K: The pressure continues to fall due to wellbore effects before steadying out as the flow into the wellbore becomes radial. K: The tester valve is closed at the end of the second flow period. K-L: The reservoir pressure starts to build up again as it returns to equilibrium. L-M: The packer is unset at the end of the second build up period and the pressure gauge again reads the pressure of the annulus mud column. N-O: The test string is pulled out of the hole and the gauge pressures reduces. O: Finally, the gauge is back on surface and reads atmospheric pressure. 2-83 March 1995 BP WELL CONTROL MANUAL Analysis of the pressure build up data from the shut-in periods can then give accurate estimates of the reservoir formation pressure. An example of this analysis is given in the BP Guide to Testing Operations. Thus, data from drillstem tests can give accurate estimates of formation pressures. However, the pressure data can only be obtained from permeable reservoir formations that are considered to have sufficient hydrocarbon potential to warrant the expense of a drillstem test. As with RFT pressure data, the reservoir pressure calculated from DST data may or may not be the same as the pressures in adjacent shales. 4 Summary The most accurate estimates of formation pressures are obtained from wireline RFT measurements and drillstem test pressure data. However, these direct measurements are only possible in permeable formations such as sandstones and limestones. These methods are clearly not applicable to impermeable shale sections (where the majority of overpressures are developed). Conversely, estimates of formation pressures from wireline logs are restricted to shale␣sections, with assumptions made as to the pressures in any adjacent permeable sections. The recognition of a normal shale compaction trend line is of vital importance when␣estimating formation pressures from log-derived shale properties. Of the various logs available, the sonic log is usually the best log for quantitative pressure evaluation as it is␣ r elatively unaf fected by changes in hole size, formation temperature, and formation water␣salinity . Section 2 References 1. ANSTEY, N.A., 1976. the New Seismic Interpreter – Videotape Manual, International Human Resources Development Corporation, Boston, Massachusetts, USA. 2. BARR, M.V., 1983. An Appraisal of Seismic Reflection Techniques for the Recognition and Prediction of Abnormal Formation Pressures. Report PEB/55/83. BP Research Centre, Sunbury. 3. BELLOTTI, P. and GERARD, R.E., 1976. Instantaneous Log Indicates Porosity and Pore Pressure. World Oil, Oct. 1976. 4. BINGHAM, M.G., 1965. A New Approach to Interpreting Rock Drillability. Oil and Gas Journal, Nov. 2 1964?Apr. 5 1965. 5. BOURGOYNE, A.T., 1971. A Graphic Approach to Overpressure Detection While Drilling. Pet. Eng. 43(9): 76?78. 6. “BP”, 1985. A Guide to Testing Operations. BP Exploration Co. Ltd., Operations Support Division, London. June 1985. 7. “BP”, 1986. A Wellsite Guide to Logging Operations. BP Exploration Co.Ltd., Logging Operations Branch, London. January 1986. 8. “BP”, 1985. Resident Geologists Manual. BPPD Aberdeen. 2nd Edition, Sept. 1985. 9. COCHRANE, D.F. and HARDMAN, P., 1986. Shallow Gas Hazards in Drilling Operations. Report DTG/L/1/1986. BPPD London. 2-84 March 1995 BP WELL CONTROL MANUAL 10. COMBS, G.D., 1968. Prediction of Pore Pressure from Penetration Rate. SPE Paper␣2162. 11. DIX, C.H., 1955. Seismic Velocities from Surface Measurements. Geophysics, 20: 68?86. 12. EATON, B.A., 1975. The Equation of Geopressure Prediction from Well Logs. SPE␣Paper␣5544. 13. “EXLOG”, 1980. Field Geologist’s Training Guide. Exploration Logging Inc., USA. 14. “EXLOG”, 1979. Mud Logging: Principles and Interpretations. Exploration Logging Inc., USA. 15. “EXLOG”, 1981. Theory and Evaluation of Formation Pressures. Exploration Logging Inc., USA. 16. “EXXON”, 1975. Abnormal Pressure Technology, Exxon Company, USA. 17. FERTL, W.H., 1976. Abnormal Formation Pressures. Elsevier Scientific Publishing Company, Amsterdam. 18. FOSTER, J.B., amd WHALEN, H.E., 1966. Estimation of Formation Pressures from Electrical Surveys – Offshore Louisiana. SPE Paper 1200. 19. “GEARHART”, 1986. Overpressure. Gearhart Geodata Services Ltd., Aberdeen. 20. HOTTMAN, C.E., and JOHNSON, R.K., 1965. Estimation of Formation Pressures from Log-derived Shale Properties. Journal of Petroleum Technology, 17: 717-723. 21. JORDEN, J.R., and SHIRLEY, O.J., 1966. Application of Drilling Performance Data to Overpressure Detection. Journal of Petroleum Technology, 18: 1387-1394. 22. LESSO, W.G. and BURGESS, T.M., 1986. Pore Pressure and Porosity from MWD Measurements. IADC/SPE Paper 14801. 23. MANN, D.M., 1985. The Generation of Overpressures During Sedimentation and their␣Ef fects on the Primary Migration of Petroleum. Report GCB/156/85. BP Research Centre, Sunbury. 24. MINTON, R.C., 1986. Technical Specification for Drilling Mud Logging Service. Report␣DTG/D/4/86. BPPD Aberdeen. 25. PENNEBAKER, E.S., 1968. An Engineering Interpretation of Seismic Data. SPE Paper␣2165. 26. PRENTICE, C.M., 1980. Formation Pressures from Normalized Penetration Rate Plots. Prentice and Records Enterprises, Inc., Lafayette, Louisiana, USA. 27. REHM, W.A., and McCLENDON, R., 1971. Measurement of Formation Pressure from Drilling Data. SPE Paper 3601. 28. ROESLER, R.F., BARNETT, W.C., and PASKE, W.C., 1986. Theory and Applications of an MWD Neutron Porosity Sensor. SPE/IADC Paper 16057. 29. “SCHLUMBERGER”, 1972. Log Interpretation Volume 1 – Principles. Schlumberger Ltd., New York, USA. 30. “SCHLUMBERGER”, 1981. RFT – Essentials of Pressure Test Interpretation. Schlumberger Ltd., 2-85 March 1995 BP WELL CONTROL MANUAL 31. SINGH, J., 1987. A Review of Measurement-While-Drilling Systems. Report DTG/L3. BPPD London. 32. VIDRINE, D.J., and BENIT, E.J., 1967. Field Verification of the Effect of Differential Pressure on Drilling Rate. SPE Paper 1859. 33. ZOELLER, W.A., 1970. The Drilling Porosity Log “DPL”. SPE Paper 3066. 34. ZOELLER, W.A., 1983. Pore Pressure Detection from the MWD Gamma Ray. SPE␣Paper␣12166. 2-86 March 1995 BP WELL CONTROL MANUAL 3 PRIMARY WELL CONTROL Paragraph Page 1 General 3-2 2 Hydrostatic Pressure 3-2 3 Equivalent Mud Weight, EMW 3-2 4 Circulating Pressures and ECD 3-4 5 Calculating the Circulating Pressure Losses 3-7 6 Swab and Surge Pressures 3-10 7 Swab and Surge Calculations 3-12 Illustrations 3.1 Hydrostatic Pressure 3-3 3.2 The Effect of Flowline Elevation – shown in relation to calculation of formation pressure 3-5 Example Calculation of the Equivalent Circulating Density (ECD) 3-6 3.3 3.4 3.5 Theoretical Variation in Swab/Surge Pressure – when tripping pipe at constant speed 3-11 Pressure Surges associated with Lowering Pipe into a Borehole 3-12 3-1 March 1995 BP WELL CONTROL MANUAL 1 General Primary well control is maintained by controlling formation pore pressures with the hydrostatic pressure of the drilling fluid. Primary well control is exercised between two distinct limits; these being the maximum formation pore pressure gradient and the minimum fracture pressure gradient in a section of openhole. This Chapter is intended to outline the various factors that can influence the actual pressure exerted by the drilling fluid in the wellbore during routine drilling operations. The effect of the following is considered: • Flowline elevation. • Circulation. • Tripping pipe. Easy to use formulae are presented to predict the effects of these factors. 2 Hydrostatic Pressure The hydrostatic pressure of a column of drilling fluid is determined, in theory, by the density, and vertical height of the fluid above a point of interest. The density of the drilling fluid and the height of the fluid column are related to the hydrostatic pressure as follows: Hydrostatic pressure (psi) = MW (SG) X D (m) X 1.421 Figure 3.1 shows a sample calculation. 3 Equivalent Mud Weight, EMW The most convenient method of describing downhole pressure is in terms of an equivalent mud weight (EMW). EMW is used in order that downhole pressure can easily, and without confusion, be related to the density of a mud column. EMW can therefore be used to describe a formation pressure as well as a pressure applied by a column of mud. The hydrostatic pressure of the mud column acts as a result of the height of fluid between the flowline and the point of interest in the wellbore. The EMW must therefore be referenced to the flowline. 3-2 March 1995 BP WELL CONTROL MANUAL Figure 3.1 Hydrostatic Pressure B A VERTICAL DEPTH = 1000m MEASURED DEPTH = 1200m MUD @ 1.5 SG The hydrostatic pressure at total depth in well A and well B = Density of the (SG) x vertical depth (m) x 1.421 = 1.5 x 1000 x 1.421 = 2130 psi WEOX02.123 3-3 March 1995 BP WELL CONTROL MANUAL It is important therefore that the effect of flowline elevation be considered when describing formation pressures in terms of an equivalent mud weight. This is because formation pressures are originally referred to sea-level, or the surface elevation, depending on whether the well is offshore or on land. Figure 3.2 shows an example of the calculation of the EMW of a normally pressured formation referenced to the flowline of a semi-submersible drilling rig. 4 Circulating Pressures and ECD When the well is static, the applied pressure at a given point in the well is equal to the hydrostatic pressure exerted by the head of fluid above that point. Therefore if the hole is full to the flowline of 1.5 SG fluid, the EMW at any point in the hole, referenced to the flowline, is 1.5 SG. However, if the pumps are started, the EMW at every point in the well will no longer be equal to the weight of the mud. The EMW will be greater than 1.5 SG at every point in the wellbore. The increase in EMW is due to the frictional pressure resulting from the flow of the mud up the annulus. At each point in the well the EMW is increased by a factor reflecting the total frictional pressure above that point. Consider the example of a land well in Figure 3.3. As shown, when the well is being circulated, the downhole pressures are described as equivalent circulating density or ECD. There are many factors that can affect the ECD in a particular well, however the most fundamental factors are: • The hole depth. • The circulation rate. • The mud weight. • The rheology of the mud. • The size of the hole. • The OD of the drillstring. • The quantity of cuttings in the annulus. (The presence of cuttings and drilled solids in the mud will have the effect of increasing the effective mud weight and changing the mud rheology.) It is clearly important to be able to estimate circulating pressure losses in order to be able to predict both the pump pressure and downhole ECD at specified circulating rates. The next paragraph details the formulae that can be used to estimate circulating pressure␣losses. 3-4 March 1995 BP WELL CONTROL MANUAL Figure 3.2 The Effect of Flowline Elevation – shown in relation to calculation of formation pressure 1 NORMALLY PRESSURED SHOWING SAND @ 300m BELOW SEA LEVEL 2 SAND EQUIVALENT MUD WEIGHT REFERENCED TO THE FLOWLINE OF A SEMISUBMERSIBLE DRILLING RIG FLOWLINE ELEVATION SEA LEVEL 25m 100m SEA BED 200m Formation pressure at 325m BRT = 1.03 x 1.421 x 300 = 439psi Normal pore pressure gradient = 1.03 SG Formation pressure at this point referenced to the flowline, in EMW = 439 = 1.421 x 325 = 0.95 SG WEOX02.124 3-5 March 1995 BP WELL CONTROL MANUAL Figure 3.3 Example Calculation of the Equivalent Circulating Density (ECD) A HOLE STATIC B HOLE BEING CIRCULATED PUMP 1.5 SG MUD IN THE HOLE 2000m Pressure drop = 100psi 500m Total pressure at shoe = (1.5 x 2000 x 1.421) + 100 = 4363psi ECD at shoe = 4363 2000 x 1.421 = 1.54 SG Pressure drop = 150psi Hydrostatic pressure EMW = 1.5 SG Total pressure at TD = (1.5 x 2500 x 1.421) + 250 = 5579psi ECD at TD = 5577 2500 x 1.421 = 1.57 SG Hydrostatic pressure EMW = 1.5 SG WEOX02.125 3-6 March 1995 BP WELL CONTROL MANUAL 5 Calculating the Circulating Pressure Losses There are various models that attempt to describe the rheology of drilling fluids. The most widely used are the Bingham, Power Law and Modified Power Law Models. The best results have been obtained using the Modified Power Law to model the behaviour of water base drilling fluids. Very large discrepancies have been recorded between predicted and actual circulating pressures when using the Modified Power Law to model the behaviour of oil base drilling fluids. The cause of this discrepancy is considered to be primarily the variation in rheological characteristics of the oil mud under the influence of downhole conditions. The Bingham Model is considerably easier to use than the Modified Power Law and, as a result, it is recommended for field use when the BP Hydraulics Programme is not available. It is recognised that, at low velocity, the Bingham model may overestimate the friction pressure of a mud that exhibits low gel strength. The following procedure can be used to approximate circulating pressure losses using the Bingham Model. (a) For use inside the pipe: 1. Calculate PV and YP. PV = Ø600 – Ø300 and YP = Ø300 – PV 2. Calculate the mud velocity. v = 7.47 X Q d i2 (m/min) 3. Calculate the pressure loss for the pipe section, assuming laminar flow. P= L X PV X v 8361.5 X d i2 + L X YP 68.6 X d i (psi) 4. Calculate the effective viscosity. µ = 8361.5 X P X d i2 (centipoise) LXv 5. Calculate the Reynolds number. Re = 422.8 X MW µ X v X d i2 The critical Reynolds number is assumed to be 2000 for Bingham fluids. If Re is␣less than 2000, the flow is assumed to be laminar and the pressure loss is calculated␣using the formula in step 3. If Re is greater than 2000, the flow is assumed to be non␣laminar and the pressure loss must be re-calculated using the formulae in steps 6 and 7: 3-7 March 1995 BP WELL CONTROL MANUAL 6. Calculate the Fanning friction factor. f= 0.079 Re 0.25 7. Calculate the pressure loss for the pipe section in non laminar flow. P= f X L X MW X v 2 315.8 X d i (psi) 8. Calculate the critical velocity. (ie the velocity above which the flow will be non laminar) vc = 7.76 X PV + [7.76 X (PV2 + (102.79 MW X di X YP X 1 MW X di2 ) )2 ] (m/min) (b) For use in the annulus: 1. Calculate the mud velocity. v = 7.47 X Q dhc 2 – d o2 (m/min) 2. Calculate the pressure loss for the section of annulus assuming laminar␣flow . P= L X PV X v + L X YP 5574.32 (dhc – d o)2 60.96 (dhc – do ) (psi) 3. Calculate the effective viscosity. µ= 5574.32 X P X (dhc – d o)2 LXv (centipoise) 4. Calculate the Reynolds number. Re = 422.8 X MW X µ v X (dhc – d o) The critical Reynolds number is assumed to be 3000 for Bingham fluids. If Re is less than 3000, the flow in this section of the annulus is assumed to be laminar and the pressure loss is calculated using the formula in step 2. If Re is greater than 3000, the flow is assumed to be non laminar and the pressure loss must be re-calculated using the formulae in steps 5 and 6: 5. Calculate the Fanning friction factor. f = 0.079 Re 0.25 6. Calculate the pressure loss for the section of the annulus in non laminar flow. P= f X L X MW X v 2 315.8 X (dhc – d o) (psi) 3-8 March 1995 BP WELL CONTROL MANUAL 7. Calculate the critical velocity. (The velocity above which the flow will be non laminar) vc = 11.63 X PV + [11.63 X (PV2 + (51.46 X MW MW X (dhc – do) X 1 YP X (dhc – do)2))2 ] (m/min) (c) To calculate the pressure drop across the bit: 1. Calculate the nozzle velocity. vn = Q An X 10.23 (m/sec) 2. Calculate the bit pressure loss. ∆Pbit = where v vn Q di dhc do L PV YP MW µ Ø600 Ø300 An P ∆Pbit vn2 X MW (psi) 12.49 = = = = = = = = = = = = = = = = mud velocity (m/min) nozzle velocity (m/min) pump output (gal/min) ID of pipe (in.) ID of hole/casing (in.) OD of pipe (in.) length of section of pipe/annulus (m) plastic viscosity (centipiose) yield point (lb/100ft2) mud weight (SG) effective viscosity (centipiose) Fann viscometer reading at 600 rpm (lb/100ft2) Fann viscometer reading at 300 rpm (lb/100ft2) total nozzle area (in.2) section pressure loss (psi) bit pressure loss (psi) These formulae can be used to estimate the pressure drop in each section of pipe and annulus. The standpipe circulating pressure can be estimated from the sum of the pressure losses across the bit and in all sections of the pipe and the annulus. The ECD at the bottom of the hole can be estimated from the total annulus pressure loss. The annulus pressure losses may also be estimated when circulating by subtracting the calculated pressure drop in the drillstring and the bit from the actual standpipe pressure (accounting also for surface pressure losses). This technique is likely to yield a more accurate estimate of the annulus pressure losses for the following reasons: • The inside measurements of the drillstring are more accurate than the openhole internal diameter. • The pressure drop through the bit is accurately modelled by the formula presented. • The effect of loading the annulus with cuttings is measured directly. 3-9 March 1995 BP WELL CONTROL MANUAL The main disadvantage of this technique stems from the fact that the majority of the pressure loss in the system is in the drillstring and across the bit. Therefore, a small error in the calculated pressure drop will cause a relatively large error in the estimate of the annulus pressure loss. 6 Swab and Surge Pressures Swab and surge pressures are caused by the movement of pipe in and out of the wellbore. Traditionally swab and surge pressures have been calculated using a steady state model that is based on the assumption that swab and surge pressures are caused by three effects: • Viscous drag of the mud as the pipe is moved. • Inertial forces of the mud when the speed of the pipe is changed. • Breaking the mud gel. Therefore the factors that determine the magnitude of swab and surge pressures are assumed to be: • The annular clearance. • The viscosity of the mud. • The gel strength of the mud. • The speed of the pipe. • The length of low clearance pipe in the hole. • The position of the low clearance pipe in the hole in relation to the point of interest. • The acceleration or deceleration of the pipe. On the basis of these assumptions, typical variations in wellbore pressure due to swab and surge pressures whilst tripping pipe are shown in Figures 3.4 and 3.5. Recent studies however, have shown that steady state models are not adequate to model the behaviour of the mud while the pipe is tripped. It has been shown that swab and surge pressures are best modelled as a transient, rather than a steady state phenomenon. The transient model assumes that a pressure wave is propogated at the instant that the pipe begins to move; the wave then travels down the well at the speed of sound and is reflected back up the hole. As a result of this effect, the pressure at a point in the well oscillates. The oscillations will continue until either the pipe reaches a steady speed, or the pipe has stopped and the reflected pressure waves have diminished. 3-10 March 1995 BP WELL CONTROL MANUAL Figure 3.4 Theoretical Variation in Swab/Surge Pressure – when tripping pipe at constant speed 1 RUNNING IN THE HOLE 2 PULLING OUT OF THE HOLE 1 Increase due to BHA 4 Reduction due to removal of BHA from the hole MAX SURGE PRESSURE WHEN BIT IS AT POINT OF INTEREST A 3 Decrease as BHA passes point A 4 Constant stage pressure due to drillpipe in the casing SURGE PRESSURE AT A 3 Reduction due to removal of drillpipe from the hole BIT DEPTH A BIT DEPTH 2 Increase due to drillpipe MAX SWAB PRESSURE WHEN BIT IS AT POINT OF INTEREST 2 Influence of BHA 1 Constant swab pressure due to drillpipe in the casing SWAB PRESSURE AT A WEOX02.126 3-11 March 1995 BP WELL CONTROL MANUAL D A Negative Surge – Pipe Lifted from Slips B Positive Pressure to Break Mud Gel C Minimum Pipe Velocity D Maximum Pipe Velocity E Negative Surge – Sudden Pipe Stoppage PRESSURE B 0 C E A TIME WEOX02.127 Figure 3.5 Pressure Surges associated with Lowering Pipe into a Borehole The latest swab/surge software models the behaviour of the mud as a transient phenomenon and also accounts for the following factors: • The compressibility of the mud. • The elasticity of the wellbore. • The change in rheological properties of the mud with pressure and temperature. • The temperature profile in the wellbore. • The elasticity of the pipe. 7 Swab and Surge Calculations The swab/surge software that is able to model the transient response of the mud to pipe movement has been developed by Sunbury. The software used by mud logging companies currently uses a steady state model. The swab/surge pressures predicted by this model are subject to inaccuracy; especially in deep wells when the transient response of the mud is most significant. 3-12 March 1995 BP WELL CONTROL MANUAL The formulae used for the steady state model are relatively easy to use and, as such, may be used in the field to approximate swab/surge pressures. The following procedure should be used to calculate swab/surge pressure for either open or closed pipe: 1. Estimate the velocity of the mud for a given pipe running speed. For closed pipe: v = CL + For open pipe: v = CL + do 2 dhc2 – do 2 X do 2 – di 2 dhc2 – do 2 – di 2 vp X vp where v = velocity of the mud (m/min) CL = clinging constant vp = average running speed of the pipe (m/min) The clinging constant, K, is assumed to equal 0.45 in the absence of detailed formula that are used to predict this quantity. 2. Determine the maximum mud velocity. The maximum mud velocity is generally taken to be 1.5 calculated in (1)). X the average velocity (as 3. Determine the swab/surge pressures due to the pipe movement. The swab/surge pressure resulting from the pipe movement can be estimated by substituting the maximum annular mud velocity as calculated in (2) into the formulae for annular pressure loss (Bingham or Power Law). The swab/surge pressure is added to the hydrostatic pressure of the mud if the pipe is being run into the hole and subtracted if the pipe is being pulled. Therefore: EMW at point of interest = MW ± sumP (SG) D X 1.421 where sumP = total swab/surge pressure (psi) D = vertical depth to point of interest (m) Preston Moore’s method can be used to approximate swab/surge pressures due to the movement of a drillstring that contains a bit with nozzles. The range of values for the resultant swab/surge pressure that are predicted by this technique should be treated with some caution, as it is generally assumed that it will predict low values of swab/surge pressures. The upper limit for swab/surge pressures for a drillstring with a bit and nozzles will be represented by the value calculated for closed pipe. 3-13 March 1995 BP WELL CONTROL MANUAL The procedure for calculating swab/surge pressures for a drillstring that contains a bit and nozzles is as follows: 1. Calculate the velocity of the mud around the drillpipe for open pipe. Use the formulae as shown for the previous technique. 2. Calculate the swab/surge pressure generated by the drillpipe due to the pipe movement. The swab/surge pressure can be calculated by substituting the annular mud velocity in the formulae for annular pressure loss (Bingham or Power Law). 3. Calculate the velocity of the mud around the collars. Use the following formulae: v(drillcollar) = v(drillpipe) X Adp Adc where Adp = cross-sectional area of drillpipe annulus (in.2) Adc = cross-sectional area of drillcollar annulus (in.2 ) 4. Calculate the swab/surge pressure generated at the collars due to pipe␣movement. Use the formulae for annular pressure loss (Bingham or Power Law) and v(drillcollar) as calculated in (3). 5. Calculate the total annular swab/surge pressure. This is equal to the sum of the swab/surge pressures at the drillpipe and the collars, or the sum of (2) and (3). 6. Calculate the swab/surge pressure inside the drillstring. Using Preston Moore’s assumption that the fluid level outside the pipe equals the level inside the pipe, the velocity of the mud inside the pipe equals the velocity outside. 7. Calculate the swab/surge pressure generated inside the drillpipe. Assuming that the mud velocity outside the pipe equals that inside the pipe, use the formulae for internal pressure loss (Bingham or Power Law). 8. Calculate the swab/surge pressure generated inside the drillcollar. Assuming that the mud velocity outside the drillcollar equals that inside the collar, use the formulae for internal pressure loss (Bingham or Power Law). 9. Calculate the swab/surge pressure generated at the bit. Using the formulae: vn = Q An X 10.23 ∆P bit = vn2 X MW 12.49 (m/sec) (psi) where in this case the mud flowrate, Q, is equal to the mud flowrate through the collars. 3-14 March 1995 BP WELL CONTROL MANUAL 10. Calculate the total internal swab/surge pressure due to the pipe movement. This is equal to the sum of the swab/surge pressures inside the drillstring, (6) plus (8), plus the bit swab/surge pressure as calculated in (9). 11. Estimate the actual swab/surge pressure due to the pipe movement. It is assumed that the actual swab/surge pressure will be between the values calculated in (5) and (10). The resultant swab/surge pressure is added to the hydrostatic pressure of the mud if the pipe is being run into the hole and subtracted if the pipe is being pulled. Therefore: EMW at the point of interest = MW ± D sumP X 1.421 (SG) where sum P = total swab/surge pressure (psi) D = vertical depth to point of interest (m) 3-15/16 3-15 March 1995 BP WELL CONTROL MANUAL 4 FRACTURE GRADIENT Paragraph Page 1 General 4-2 2 Stresses in the Earth 4-2 3 Fracture Orientation 4-3 4 Fracture Gradient Prediction 4-4 5 Daines’ Method of Fracture Gradient Prediction 4-4 6 An Example Pressure Evaluation Log 4-7 7 Leak Off Tests 4-9 8 Leak Off Test Procedure 4-10 9 Interpretation of Results 4-11 Illustrations 4.1 Principal Stress Orientation 4-3 4.2 Poisson’s Ratio for Different Lithologies 4-5 4.3 An Example Pressure Evaluation Log 4.4 A Typical Fracture Test 4-12 4-1 March 1995 BP WELL CONTROL MANUAL 1 General The absolute upper limit of primary well control is the point at which the wellbore pressure equals the fracture pressure of the exposed formation. At this point a fracture is initiated and the wellbore can no longer be considered to be a closed system. This will lead to loss of mud from the hole and the possibility of the loss of primary control. In order to drill a well safely therefore, it is useful for the Drilling Engineer to be able to predict and measure fracture pressures. At the well planning stage, the fracture gradient can be estimated from offset well data. If␣this information is not available then Daines’ Method can be used to predict the fracture gradient. As the well is drilled, Leak Off Tests are carried out to assess the mud holding capability of the openhole. It is Company policy that these tests be carried out to leak off point, which in most cases will represent a pressure that is less than the actual fracture initiation pressure. The leak off pressure is converted to an equivalent mud weight which determines the upper limit of primary control for the next hole section. LO tests are generally carried out once in each openhole section after drilling out of the shoe. However the test should be repeated when weaker zones are drilled into. It is not practical to conduct a leak off test at every change in formation and consequently it is useful to be able to predict the fracture gradient of new formations without conducting further leak off tests. Before covering the techniques that are used to predict fracture gradient, it is appropriate to explain the origins of the stresses that occur naturally below the surface of the earth. 2 Stresses in the Earth At any point below the earth’s surface, the resultant stress in the rock can be resolved into three principal stresses that act at right angles to each other; these being: • The maximum stress. • The intermediate stress. • The minimum stress. In most cases, the maximum stress will be vertical, due to the pressure of the overlying rock and pore fluid. This is defined as the overburden pressure. In a tectonically relaxed area the maximum stress will, in most cases, be vertical and the stresses in the horizontal plane will be equal. At shallow depths however, the horizontal stress may be greater than the vertical stress, even in a tectonically relaxed area. Figure 4.1 shows the effect of tectonic forces on the principal stresses. A small tectonic force ensures that the two principal stresses in the horizontal plane are no longer equal. This has the effect of creating an actual intermediate stress. 4-2 March 1995 BP WELL CONTROL MANUAL σ'1 = maximum principal stress σ'2 = intermediate principal stress σ'3 = minimum principal stress σ'3 σ'1 σ'1 σ'2 σ'2 σ'3 σ'3 1 – Tectonically relaxed area – σ'1 is vertical – σ'2 = σ'3 – induced fractures will be vertical σ'2 2 – under the influence of a small tectonic stress – σ'1 is vertical – σ'2 = σ3 an actual intermediate stress is created σ'1 3 – in an area that is significantly affected by tectonic stress – σ'1 is horizontal – induced fractures will be horizontal WEOX02.128 Figure 4.1 Principal Stress Orientation In an area where tectonic stresses are particularly high, it is possible that the maximum principal stress acts horizontally. This may be the case, for example, in a mountainous region where the formations may be severely folded. However, this is unlikely to occur at great depths where the overburden pressure is generally the predominant factor. 3 Fracture Orientation A fracture will be created if wellbore pressures exceed the minimum principal stress at any point in the openhole. The fracture will propogate along the path of minimum resistance, which will be at right angles to the direction of the minimum principal stress. Fractures will therefore be vertical when the minimum principal stress is horizontal, and horizontal if the minimum principal stress is vertical. (See Figure 4.1). Consequently induced fractures will be vertical in areas where tectonic forces are negligible, except possibly at very shallow depths. However horizontal fractures may be formed in areas where tectonic forces are significant. In effect, it is necessary for the applied pressure to lift the weight of the overburden for horizontal fractures to be formed. This is unlikely to occur at depth when overburden pressure will, in most cases, be greater than pressures due to tectonic forces. 4-3 March 1995 BP WELL CONTROL MANUAL 4 Fracture Gradient Prediction Many different techniques can be used to estimate fracture gradients. Hubbert and Willis were the first to derive a method, but they were followed, amongst others, by Ben Eaton whose technique is currently used by Anadrill, Geoservices and Gearhart. Eaton’s Method was refined by Daines, in 1982, whose technique has since been used by Exlog. Eaton’s Method is most applicable to predicting fracture pressures in areas where a great deal of data relating to subsurface stress regimes is already available. Eaton’s Method relies on the availability of accurate locally calculated stress coefficients to predict fracture pressures. When such information is available, such as in the Gulf Coast, this method has been shown to be very accurate. However, in areas where the subsurface stress regime is relatively unknown, it is not possible to use Eaton’s Method with any degree of accuracy. Daines’ Method is particularly useful in wildcat areas, because the result of the first LO test carried out in a competent formation is used to measure the subsurface stress regime directly. The coefficients that are used to calculate the fracture pressures are specific to each lithology, but are applicable worldwide. As a result, once the first LO test has been carried out, it is possible to predict the fracture pressure in subsequent formations with reasonable accuracy. This technique has proved particularly accurate in wildcat wells in the North Sea. 5 Daines’ Method of Fracture Gradient Prediction Having conducted the first LO test in a competent formation, Daines’ Method can be used to predict fracture pressures in all types of formation types, with the use of the values for Poisson’s ratio as shown in Figure 4.2. The following procedure can be used after the first LO Test (assuming the maximum effective stress to be vertical and due to the overburden): 1. Calculate the magnitude of the tectonic stress. The magnitude of the tectonic stress is calculated at the depth of the first LO test. This is done using the following formula: σt = Pfrac – σ'l where σt = Pfrac = σ'1 = µ = Pf = µ – Pf l–µ tectonic stress (psi) fracture pressure (psi) maximum effective principle stress (psi) Poisson’s ratio for the rock formation pore pressure (psi) and σ'1 = S – Pf where S = overburden pressure (psi) 4-4 March 1995 BP WELL CONTROL MANUAL Figure 4.2 Poisson’s Ratio for Different Lithologies Clay, very wet 0.50 Clay 0.17 Conglomerate 0.20 Dolomite 0.21 Greywacke: coarse fine medium 0.07 0.23 0.24 fine, medium medium, calcarenitic porous stylolitic fossiliferous bedded fossils shaley 0.28 0.31 0.20 0.27 0.09 0.17 0.17 coarse coarse, cemented fine very fine medium poorly sorted, clayey fossiliferous 0.05 0.10 0.03 0.04 0.06 0.24 0.01 Calcereous (<50% CaC03) dolomitic siliceous silty (<70% silt) sandy (<70% sand) kerogenaceous 0.14 0.28 0.12 0.17 0.12 0.25 Limestone: Sandstone: Shale: Siltstone 0.08 Slate 0.13 Tuff: Glass 0.13 From Weurker H.G: “Annotated Tables of Strength and Elastic Properties of Rocks,” Drilling, reprint Series SPE Dallas (1963). 4-5 March 1995 BP WELL CONTROL MANUAL The overburden pressure is determined from density logs, or from bulk densities determined from the cuttings. 2. Calculate the tectonic stress coefficient. The tectonic stress coefficient can be calculated as follows: β = σt / σ'1 where β = tectonic stress coefficient This value is used to predict the magnitude of the tectonic stress throughout the next␣hole section until the next LO test can be used to recalculate the figure. It is however generally the case that σ'1 remains directly proportional to σt throughout the well, if the rock strata are horizontal and the basin structure does not change significantly with depth. Having calculated the above figures at the first LO test, the fracture pressure can be calculated as drilling proceeds in the following manner: 3. Calculate the maximum principal stress at the point of interest. The magnitude of the maximum principal stress is calculated from the pore pressure and the overburden pressure as follows: σ'1 = S – Pf where S = overburden pressure (psi) Pf = pore pressure (psi) The overburden pressure can be calculated from density logs, or from the bulk density values determined from the cuttings. 4. Calculate the tectonic stress at the point of interest. The magnitude of the tectonic stress is calculated from the maximum principal stress and the tectonic stress coefficient as follows: σ t = σ'1 X β 5. Calculate the fracture pressure at the point of interest. Using Figure 4.2 to determine a value for the Poisson’s ratio for the rock, the fracture pressure can be calculated from the following formula: Pfrac = σt + σ'l µ + Pf l–µ (psi) where P frac = fracture pressure at the point of interest (psi) This procedure can be repeated as the well is drilled in order to map the trend in fracture gradient with depth. 4-6 March 1995 BP WELL CONTROL MANUAL 6 An Example Pressure Evaluation Log Figure 4.3 (contained in wallet) shows an example Pressure Evaluation Log produced by Exlog for a well drilled in the North Sea. From the 30 in. casing point to the 18 5/8 in. casing point, the formation is mudstone. From␣the log, the fracture pressure appears to be greater than overburden pressure from the seabed to approximately 1450m. This is a typical feature of young unconsolidated clays which can behave as a liquid and as such have relatively high Poisson’s ratio of the order of 0.5. Such clays possess negligible shear strength and, as a result, the formation may only be fractured by actually lifting the overburden. The calculated fracture gradient at shallow depths should therefore be greater than the overburden; as shown in the following calculation using Daines’ formula: Pfrac = σt + σ'l µ + Pf l–µ (SG) at 600m BRT the fracture pressure is calculated: Pfrac = 0.4 (1.79 – 1.00) + (1.79 – 1.00) 0.44 + 1.0 l – 0.44 P frac = 1.93 SG An interesting case would be to estimate the fracture gradient of a sand at these conditions and at this depth. Using the same formula, but substituting a Poisson’s ratio of 0.01 for a typical shallow marine sand, the fracture gradient is calculated as follows: Pfrac = 0.4 (1.79 – 1.00) + (1.79 – 1.00) 0.01 + 1.0 l – 0.01 P frac = 1.32 SG The possible variation in fracture gradients at these depths is therefore quite significant. After 1450m, the clays have sufficiently dewatered due to compaction to support a horizontal stress. As a result, the fracture gradient is reduced to a value that is less than the overburden gradient. This means that vertical fractures may be formed at pressures lower than the overburden pressure. The tectonic stress coefficient is calculated from the result of the LO test carried out at the 18 5/8 in. casing shoe. This is the first point at which the clays are assumed to be adequately compacted so as to predict a reasonable figure for the tectonic stress coefficient as follows: σt = Pfrac – σ'l µ – Pf l–µ (SG) 4-7 March 1995 BP WELL CONTROL MANUAL from the result of the LO test: σt = 1.8 – (1.95 – 1.53) 0.2 – 1.53 l – 0.2 = 0.165 SG therefore the tectonic stress coefficient is given by: β= σt σ'1 = 0.165 = 0.39 (1.95 – 1.53) and this value of – is used to calculate the tectonic stress in subsequent rock strata. From the 18 5/8 in. shoe to 2880m, the fracture gradient increases in line with the overburden gradient. At 2880m, the pore pressure gradient begins to decrease, causing a reduction in the calculated fracture gradient to 1.88 SG at 3100m. At 3120m, the formation changes to a sandstone interbedded with siltstone. A Poisson’s ratio of 0.06 is chosen for these loose fine grained sands which results in a reduction in the calculated value of the fracture gradient to approximately 1.72 SG. At 3220m, the formation changes to limestone, for which a Poisson’s ratio of 0.28 is used. Therefore at 3400m, the fracture gradient is calculated as follows using Daines’ formula: Pfrac = σt + σ'l µ + Pf l–µ (SG) where σ'1 = S – Pp = 2.24 – 1.25 = 0.99 SG σ t = 0.39 – 0.99 = 0.39 SG Therefore: Pfrac = 0.39 + 0.99 0.28 + 1.25 l – 0.28 Pfrac = 2.03 SG The LO test at the 13 3/8 in. shoe shows a fracture gradient of 2.13 SG, which is slightly higher than the predicted figure. The fracture pressure then increases with depth and pore pressure throughout the 12 1/4 in. section to a calculated maximum of 2.23 SG at the 9 5/8 in. casing point. The LO test at this point confirms a 2.21 SG fracture gradient. Mud was lost to the sandstone stringers at the base of the limestone (4200m) at an ECD of 2.06 SG. This figure is therefore taken to be the minimum fracture gradient in the 8 1/2 in. hole. However, the actual fracture gradient of the mudstone increases with depth and in line with the pore pressure, to 2.205 SG at 4429m. A Poisson’s ratio of 0.06 is used to calculate the fracture gradient in the sandstone section after 4429m. The fracture pressure in the sand remains constant at 2.16 SG until the formation becomes interbedded with mudstone, at which point, the calculated fracture pressure increases to 2.22 SG. The underlying mudstone has a calculated fracture gradient of 2.22 SG. 4-8 March 1995 BP WELL CONTROL MANUAL 7 Leak Off Tests The purposes of carrying out a leak off test are: • To establish the upper limit of primary control for a section of openhole. • To test the effectiveness of a cement job. Company policy is that: “Leak off tests or competency tests will be performed prior to drilling each new hole section (except for conductors).” The following guidelines are offered: “Leak off tests should be performed after drilling 3 to 5m of new hole below any casing␣shoe. Leak off tests should be taken to leak off unless: • The pressure exceeds that to which the casing was tested. • (On a development well) where the pressure may be limited to that required to drill safely the next section of hole (competency test). When drilling through sands, or permeable rock, at any point below the casing shoe, consideration should be given to carrying out a further LO test to ascertain the new rock strength, and thus, the ability of the hole to contain a kick. Leak off tests should not be conducted in brittle formations (eg fractured limestone).’’ Company policy is therefore to restrict applied pressures to a maximum represented by the LO point. The reason for this is that, in many cases, it is not certain that an induced fracture will heal completely to withstand the pressure that originally caused it to fracture. Field evidence, however, suggests that in most cases induced fractures will heal completely. However it is difficult to predict the circumstances in which fractures will not heal completely and hence permanently weaken the formation. It has been suggested that the drilling process locks additional stresses into the rock around the wellbore, thereby increasing the pressure required to cause a fracture. If a fracture is created, these additional stresses are released and consequently the pressure required to reopen the fracture may be less than that originally required. It is accepted, however, that particularly brittle rocks, such as limestone, will show very little inelastic behaviour prior to fracture. As a result, there may be no clear leak off before a fracture occurs. A brittle formation may be permanently weakened by an induced fracture and consequently it is not recommended to conduct LO tests in such formations. 4-9 March 1995 BP WELL CONTROL MANUAL 8 Leak Off Test Procedure The following general procedure is recommended for conducting LO tests: 1. Ensure that suitable pressure gauges are available. The gauges should be of a suitable range and have been recently calibrated with a Dead Weight Tester. 2. Assess the upper limit for the test. It may not be necessary to conduct a leak off test in a development well when pore and fracture pressures are well defined; in which case, a limit test will suffice. The absolute upper limit for all types of test will be the overburden gradient at current depth. NOTE: This may be lower than 2.31 SG or 1 psi/ft, as is common in deep water offshore. 3. Determine the estimated fracture pressure. The mud logging company will provide an estimate of the fracture pressure at current depth. This figure may be used as an upper limit for the test, or to interpret any anomalies observed during the test. 4. Test the casing prior to drilling out of the shoe. An estimate of the volume of fluid required to pressurise the hole can be determined from the bulk modulus of elasticity of the fluid that is in the hole. ∆V = ∆P X V K when ∆V V ∆P K = = = = volume required to pressurise hole (bbl) volume to be pressurised (bbl) required increase in pressure (psi) bulk modulus of elasticity (psi) The bulk modulus of elasticity of a drilling fluid is determined by the characteristics of␣the base fluid as well as the solids content of the fluid. The following figures can be␣used: K, water = 290,000 – 335,000 psi K, BP H3HF Base Oil = 160,000 – 260,000 psi The bulk modulus of actual drilling fluids will be greater than these figures by an amount related to solids content. Plot a graph of pressure versus mud pumped to establish linearity prior to the LO test. 5. Drill out of the shoe and 3 to 5 m of new hole. 6. Circulate and condition the mud. 7. Pull up into the casing. 8. Line up the pump to the annulus and displace all lines to the well to mud. 9. Close the BOP. 4-10 March 1995 BP WELL CONTROL MANUAL 10. Run the pump at a constant 0.3 to 0.5 bbl/min. Monitor the pressure build up, and accurately record the volume of mud pumped. Plot pressure versus volume of mud pumped. 11. Stop the pump when any deviation from linearity is noticed between pump pressure and volume pumped. Record the final pump pressure and calculate LO EMW. 12. Bleed back mud from the well and compare with the volume pumped. 9 Interpretation of Results Figure 4.4 shows the result of a typical fracture test carried out in a consolidated low permeability formation in a tectonically relaxed area. NOTE: It is Company policy that the test is stopped at leak off point. From points 1 to 2, the exposed rock is deforming elastically as the relationship between pressure and volume pumped is linear. At point 2, the pressure in the wellbore at the exposed formation is equal to the sum of the pore pressure and the minimum horizontal effective stress. In other words, any cracks that exist at the wellbore and in the vertical plane will be in a state of equilibrium, the applied pressure exactly counteracting the naturally occurring compressive forces. At point 3, which represents the leak off point (because it is the first noted deviation from the linear relationship), the pump would normally be stopped and the pressure bled down in line with Company policy. If the pump was left running, the pressure would eventually build to fracture pressure as shown. From points 2 to 4, the formation is deforming plastically, in that for the same increment of applied stress (pressure), a greater level of strain (volume) is produced. The difference between the pressure at point 2 and the pressure at point 4 represents the pressure required to initiate the fracture. If the pump was stopped at point 4, as is shown on the diagram, the fracture would not propogate further into the formation and the pressure will drop to point 5. The pressure at point 5 should be equal to the pressure at point 2. If the pressure is then bled down, the returned volume should be equal to the volume pumped into the hole; if it is significantly less, then the fracture may be still be open. If the pump was kept running after point 4, the fracture would propogate into the formation at a pressure slightly lower than point 4, or the fracture propogation pressure. 4-11 March 1995 BP WELL CONTROL MANUAL FRACTURE PRESSURE (pump stopped) 4 5 3 GAUGE PRESSURE, psi 2 LEAK OFF PRESSURE (the pump would normally be stopped at this point) PRESSURE BLED DOWN 1 1 1 2 bbl PUMPED 2 3 4 TIME, MINUTES 3 WEOX02.130 Figure 4.4 A Typical Fracture Test 4-12 March 1995 BP WELL CONTROL MANUAL 5 BASICS OF WELL CONTROL Paragraph Page 1 General 5-3 2 Displacing a Kick from the Hole 5-3 3 Factors that Affect Wellbore Pressures 5-8 4 Subsea Considerations 5-19 5 Safety Factors 5-24 6 Calculating Annulus Pressure Profiles 5-27 Illustrations 5.1 Choke and Standpipe Pressure – during the first circulation of the Driller’s Method 5-5 5.2 Pit Gain – during the first circulation of the Driller’s Method 5-5 5.3 Shoe Pressure – during the first circulation of the Driller’s Method 5-6 5.4 Choke and Standpipe Pressure – during the second circulation of the Driller’s Method 5-6 Choke and Standpipe Pressure – during the Wait and Weight Method 5-7 5.6 Shoe Pressure – during the Wait and Weight Method 5-8 5.7 Choke Pressure – during the Driller’s Method for various influx volumes 5-9 Choke Pressure – during the Wait and Weight Method for various influx volumes 5-9 Shoe Pressure – during the Driller’s Method for various influx volumes 5-11 5.5 5.8 5.9 5.10 Shoe Pressure – during the Wait and Weight Method for various influx volumes 5-11 5.11 Choke Pressure – during the Wait and Weight Method and the Driller’s Method for two different influx volumes 5-12 5.12 Choke Pressure – during displacement of a gas kick using the Driller’s Method for various kick intensities 5-12 5.13 Choke Pressure – during displacement of a gas kick using the Wait and Weight Method for various kick intensities 5-13 5-1 March 1995 BP WELL CONTROL MANUAL 5.14 Choke Pressure – during displacement of a gas kick using the Wait and Weight Method for various kick intensities 5-13 5.15 A Comparison of the Shoe Pressure – during displacement using the Driller’s and Wait and Weight Method for two gas kicks of different intensities 5-14 5.16 A Comparison of Shoe Pressures – during displacement of a 20 barrel gas kick for various shoe depths 5-15 5.17 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 3000m 5-15 5.18 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 2500m 5-16 5.19 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 2000m 5-16 5.20 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 1500m 5-17 5.21 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 1000m 5-17 5.22 Choke Pressure – during displacement of a water kick using the Wait and Weight Method 5-19 5.23 Comparison of Choke Pressures – during displacement of a gas kick on a fixed rig and a floating rig 5-20 5.24 Choke Pressure for various Water Depths – during displacement of a gas kick 5-21 5.25 Determination of the Required Rate of Choke Manipulation for a Deep Water Subsea Well 5-22 5.26 Estimated Choke Line Losses (psi) for Various Choke Line Lengths (3in. ID) 5-24 5.27 Annulus Pressure Loss for various Well Configurations 5-25 5.28 Choke Pressure – during displacement of a gas kick with overbalanced mud 5-26 5.29 Shoe Pressure – during displacement of a gas kick with overbalanced mud 5-26 5.30 Annulus Pressure Worksheet 5-31 5.31 Graph of Pseudo-critical Temperature and Pressure for Hydrocarbons 5-33 5.32 Compressibility Factors for Natural Gas 5-34 5-2 March 1995 BP WELL CONTROL MANUAL 1 General When a kick is taken with the pipe on bottom, the well can be killed using either the Wait and Weight Method or the Driller’s Method. The Wait and Weight is the preferred method. The procedures used to implement these techniques on either a floating or a fixed rig are detailed in Volume 1. Both these methods ensure that the bottomhole pressure is maintained constant and equal to, or slightly greater than, the kick zone pressure. In order to fully understand the implementation of these methods, it is important to understand the surface and downhole pressures that are caused by displacing a kick from the hole using either the Driller’s Method or the Wait and Weight Method. This chapter is intended to cover the variations in surface and subsurface pressures during these methods, and to explain the most important factors that affect the magnitude of these pressures. All the pressure plots shown in this chapter are developed by computer programme. The pressures are determined by simulating the displacement of a gas kick from a well with the model of a discrete bubble of gas. The actual pressures seen when a kick is taken may be different from those predicted by the programme; however the plots can demonstrate the influence of the major factors that affect the wellbore pressures during circulation. The pressure plots contained in this chapter are generated on the basis that the bottomhole pressure is constant and exactly equal to the kick zone pressure. 2 Displacing a Kick from the Hole (a) Driller’s Method The Driller’s Method requires that two complete hole circulations are carried out before the well is killed. The original mud weight is used to displace the kick from the hole and then the mud is weighted to kill weight for the second circulation. During the first circulation, the drillpipe circulating pressure is held constant at a value equal to the shut-in drillpipe pressure plus the circulating pressure loss in the system at the slow circulating rate. During the second circulation, the drillpipe circulating pressure is adjusted to account firstly for the increased circulating pressure due to the heavy mud, and secondly for the reduction in underbalance as the drillpipe is displaced. Once the drillpipe has been displaced to kill weight mud, the circulating pressure is held constant. The pressure at each point in the annulus will vary significantly as the kick is displaced from the hole. Once the well has been shut-in, the major factors that determine the pressure at any point in the annulus during displacement of the kick are the height of the influx in the annulus and the relative position of the influx in the annulus. 5-3 March 1995 BP WELL CONTROL MANUAL Figure 5.1 shows the choke pressure during the displacement of a kick with the Driller’s Method for a surface BOP. Point A represents the shut-in casing pressure. From point A to point B, the casing pressure drops as the influx is displaced past the BHA. This drop is caused by a reduction in height of the influx as the influx is displaced from the BHA annulus to the drillpipe annulus. The choke operator will open the choke to maintain the appropriate standpipe pressure. From point B to point D, the influx is expanding as it is circulated up the hole and hence the choke pressure required to balance the kick zone pressure is increasing. The choke operator will therefore close in on the choke to maintain the correct standpipe pressure. At point C, the gas has expanded to occupy its original height in the annulus when opposite the BHA. At point D, the gas arrives at the choke; the choke operator will have to close in on the choke to ensure that the choke pressure does not drop significantly as the low density gas passes across the choke. From point D to point E, the gas is passing the choke; the choke operator will have to open the choke to reduce the choke pressure to maintain the correct standpipe pressure. The choke pressure required to balance the kick zone pressure reduces as the gas passes the choke because the column of gas in the annulus is continually decreasing in height. At point E, the gas has been displaced from the well and the choke pressure will stabilise at a value determined by the degree of underbalance. Figure 5.2 shows the pit gain, or the volume of the kick, as it is displaced to the choke. Figure 5.3 shows the pressure at the casing shoe as the kick is displaced from the hole. From point P to point Q, the pressure drops as the influx is displaced past the BHA. From point Q to point R, the pressure increases as the influx expands as it is circulated up to the casing shoe. At point R, the top of the influx has arrived at the casing shoe and from point R to point S the influx is circulated past the casing shoe. Once the influx has been circulated past the shoe, the pressure at the shoe will remain constant as the influx is circulated to the choke, as long as the choke is correctly manipulated. It can be seen from Figure 5.3 that, in this case, the shoe pressure was at maximum when the well was shut-in. In other words, the influx did not expand to its original height in the annulus before it arrived at the choke. However, if the shoe was shallower, the maximum shoe pressure might have been when the influx was circulated to the shoe. Figure 5.4 shows the standpipe and choke pressure during the second circulation during which the well is circulated to kill weight mud. Having established the initial circulating pressure, the standpipe pressure must be reduced as the drillpipe is displaced to kill weight mud. In practice, very little choke manipulation will be required at this stage because the standpipe pressure will drop automatically as the kill weight mud is pumped down the drillpipe. Once the kill weight mud starts up the annulus, the choke size will have to be increased so that the correct final circulating pressure is maintained. Once the hole has been displaced to kill weight mud, the choke pressure required to maintain the final circulating pressure will be zero. In practice therefore, the choke will be wide open at this point and it may not be possible to keep the standpipe pressure down to the final circulating pressure. 5-4 March 1995 BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20bbl GAS 2000 1800 SURFACE PRESSURE (psi) 1600 D 1400 1200 STANDPIPE PRESSURE A 1000 B SCR1 800 C E 600 CHOKE PRESSURE 400 P DRILLPIPE 200 0 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.131 Figure 5.1 Choke and Standpipe Pressure – during the first circulation of the Driller’s Method WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG 0 200 BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20bbl GAS 100 90 PIT GAIN (bbl) 80 70 60 50 40 30 20 10 0 400 600 VOL MUD PUMPED (bbl) 800 WEOX02.132 Figure 5.2 Pit Gain – during the first circulation of the Driller’s Method 5-5 March 1995 BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20bbl GAS 6600 6400 SHOE PRESSURE (psi) 6200 6000 P 5800 R Q 5600 S 5400 5200 5000 4800 0 400 200 600 800 VOL MUD PUMPED (bbl) WEOX02.133 Figure 5.3 Shoe Pressure – during the first circulation of the Driller’s Method WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG 6 1/4in/180m 5in DP DRILLER'S BHA: PIPE: TECH: 2000 1800 SURFACE PRESSURE (psi) 1600 1400 1200 1000 SCR1 800 600 STANDPIPE PRESSURE 400 P DRILLPIPE CHOKE PRESSURE SCR2 200 0 0 DRILLPIPE VOLUME 200 400 ANNULUS VOLUME 600 800 VOL MUD PUMPED (bbl) Figure 5.4 Choke and Standpipe Pressure – during the second circulation of the Driller’s Method 5-6 March 1995 WEOX02.134 BP WELL CONTROL MANUAL (b) Wait and Weight Method During the Wait and Weight Method, the kick is displaced from the hole with kill weight mud. The most significant advantages of the Wait and Weight Method in relation to the Driller’s Method are: firstly that wellbore pressures during displacement of the kick are generally lower than for the Driller’s Method, and secondly that the well is under pressure for a significantly shorter period. Figure 5.5 shows the choke and standpipe pressure during displacement of the influx with kill weight mud. The choke pressure during the Driller’s Method is included for comparison. As can be seen, the choke pressure during both techniques is the same until the kill weight mud starts up the annulus at point B. (This is because the bottomhole pressure is kept equal and constant for both methods.) From this point onwards, the pressure at every point in the annulus will be lower than if the Driller’s Method had been used. Between points D and E, the volume of original mud behind the influx is displaced from the well until, at point E, the kill weight mud arrives at the choke. WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP W+W 20bbl GAS 2000 1800 SURFACE PRESSURE (psi) 1600 1400 C 1200 A 1000 SCR1 800 B CHOKE PRESSURE (DRILLER'S METHOD) 600 400 P DRILLPIPE D SCR2 200 0 0 DRILLPIPE VOLUME 200 400 STANDPIPE PRESSURE (W + W METHOD) CHOKE PRESSURE (W + W METHOD) E 600 800 VOL MUD PUMPED (bbl) WEOX02.135 Figure 5.5 Choke and Standpipe Pressure – during the Wait and Weight Method Figure 5.6 illustrates the pressure at the casing shoe for both the Wait and Weight Method and in comparison with the Driller’s Method. Between point P and point Q, the shoe pressure decreases as the influx is displaced past the BHA. The influx expands as it is circulated to the shoe at point R, after which, the pressure at the shoe decreases. At point S, the kill weight mud starts up the annulus and hence reduces the choke pressure below that for the Driller’s Method. Between point T and point U, the original weight mud is displaced past the shoe until point U, when the kill weight mud arrives at the shoe. The pressure at point U is equal to the kick zone equivalent mud weight, and thus represents the minimum pressure that the shoe will see once the well has been killed. 5-7 March 1995 BP WELL CONTROL MANUAL In this case therefore, the maximum shoe pressure is unaffected by the technique used to kill the well, however, the shoe will be under pressure significantly longer if the Driller’s Method is used. WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 6600 6400 SHOE PRESSURE (psi) 6200 6000 P 5800 R S Q 5600 DRILLER'S METHOD 5400 T 5200 WAIT AND WEIGHT METHOD U 5000 4800 0 DRILLPIPE VOLUME 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.136 Figure 5.6 Shoe Pressure – during the Wait and Weight Method 3 Factors that Affect Wellbore Pressures (a) Influx Size The most fundamental factor that affects the wellbore pressures during circulation, is the volume of the influx. The greater the volume of influx, the greater will be the wellbore pressures during circulation. Figure 5.7 shows the choke pressure as various influx volumes are displaced from the well using the Driller’s Method. Figure 5.8 shows the choke pressure as the same influx volumes are displaced from the well using the Wait and Weight Method. Figures 5.7 and 5.8 quite clearly show that, regardless of the technique used to kill the well, the wellbore pressures will be lower the smaller the influx volume. 5-8 March 1995 BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20, 30, 40, 50bbl GAS 2000 1800 CHOKE PRESSURE (psi) 1600 1400 50bbl 40bbl 1200 30bbl 1000 20bbl 800 600 400 200 0 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.137 Figure 5.7 Choke Pressure – during the Driller’s Method for various influx volumes WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP W+W 20, 30, 40, 50bbl GAS 2000 1800 CHOKE PRESSURE (psi) 1600 1400 50bbl 40bbl 1200 30bbl 1000 20bbl 800 600 400 200 0 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02.138 Figure 5.8 Choke Pressure – during the Wait and Weight Method for various influx volumes 5-9 March 1995 BP WELL CONTROL MANUAL Figure 5.9 shows the shoe pressures as various influx volumes are displaced from the well using the Driller’s Method. Figure 5.10 shows the shoe pressures as the same influx volumes are displaced using the Wait and Weight Method. Figure 5.11 shows a comparison of choke pressure during the Wait and Weight Method against the Driller’s Method for influx volumes of 20 bbl and 50 bbl. Influx volume is therefore a variable that has significant influence on wellbore pressure during the displacement of a kick. However, it is the only variable that the rig crew have some control over for a given kick situation; it is therefore particularly important that shut-in procedures are implemented as quickly as possible, even if there is some doubt as to whether the well is flowing. (b) Kick Intensity The intensity of a kick is a measure of the degree of underbalance recorded after the kick has been shut-in. This can be determined from the drillpipe pressure. The intensity of the kick will be a major factor in determining the wellbore pressures during displacement of the kick. Close attention to the indicators of increasing pore pressure will ensure that kicks of high intensity are avoided. Figure 5.12 shows the choke pressure during the displacement of a range of high and low intensity kicks by the Driller’s Method. Figure 5.13 shows the displacement of the same kicks, using the Wait and Weight Method. It can therefore be seen that the Wait and Weight Method is more effective in reducing choke pressures for kicks of relatively high intensity. Figure 5.14 shows a comparison of the two techniques for a low intensity kick, as well as a high intensity kick. Figure 5.14 shows clearly that it is especially important to use the Wait and Weight Method for kicks of relatively high intensity. Figure 5.15 shows a comparison of the shoe pressures during displacement of the same two kicks. In this case, the Wait and Weight Method does not reduce the maximum pressure that the shoe experiences during displacement, but in the case of the high intensity kick, the shoe pressure is significantly reduced once the kill weight mud starts up the annulus. (c) Hole Configuration The maximum surface pressure during displacement of a kick will always be lower if the Wait and Weight Method is used, given that kill weight mud will start up the annulus before the kick arrives at the choke. The maximum shoe pressure is not necessarily affected by the technique used to displace the kick (in most cases the maximum shoe pressure will be at initial shut-in and as such is not dependent on the technique used to kill the well). However in a long openhole section it is possible that the maximum shoe pressure may occur as the influx is displaced to the shoe. In this instance, if kill weight mud is to have an effect on the maximum pressure at the shoe, the hole configuration must be such that the kill weight mud starts up the annulus before the kick is displaced past the shoe. 5-10 March 1995 BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20, 30, 40, 50bbl GAS 6600 6400 SHOE PRESSURE (psi) 6200 50bbl 40bbl 6000 30bbl 5800 20bbl 5600 5400 5200 5000 4800 0 400 200 600 800 VOL MUD PUMPED (bbl) WEOX02.139 Figure 5.9 Shoe Pressure – during the Driller’s Method for various influx volumes WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP W+W 20, 30, 40, 50bbl GAS 6600 6400 SHOE PRESSURE (psi) 6200 50bbl 40bbl 6000 30bbl 5800 20bbl 5600 5400 5200 5000 4800 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.140 Figure 5.10 Shoe Pressure – during the Wait and Weight Method for various influx volumes 5-11 March 1995 BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20, 50bbl GAS 2000 1800 CHOKE PRESSURE (psi) 1600 1400 50bbl 1200 1000 20bbl 800 DRILLER'S METHOD 600 400 WAIT AND WEIGHT METHOD 200 0 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.141 Figure 5.11 Choke Pressure – during the Wait and Weight Method and the Driller’s Method for two different influx volumes WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.75, 1.79, 1.83, 1.87, 1.91SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20bbl GAS 2000 1800 CHOKE PRESSURE (psi) 1600 1400 1200 1.91SG 1000 1.87SG 800 1.83SG 600 1.79SG 400 1.75SG 200 0 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02.142 Figure 5.12 Choke Pressure – during displacement of a gas kick using the Driller’s Method for various kick intensities 5-12 March 1995 BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.75, 1.79, 1.83, 1.87, 1.91SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP W+W 20bbl GAS 2000 1800 CHOKE PRESSURE (psi) 1600 1400 1.9SG 1200 1.87SG 1000 1.83SG 800 1.79SG 600 1.75SG 400 200 0 0 400 200 600 800 VOL MUD PUMPED (bbl) WEOX02.143 Figure 5.13 Choke Pressure – during displacement of a gas kick using the Wait and Weight Method for various kick intensities WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.75, 1.91SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 2000 1800 CHOKE PRESSURE (psi) 1600 1.91SG 1400 1200 1000 800 600 DRILLER'S METHOD 1.75SG 400 200 WAIT AND WEIGHT METHOD 0 0 200 400 600 VOL MUD PUMPED (bbl) 800 WEOX02.144 Figure 5.14 Choke Pressure – during displacement of a gas kick using the Wait and Weight Method for various kick intensities 5-13 March 1995 BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.75, 1.91SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 6600 6400 SHOE PRESSURE (psi) 6200 1.91SG DRILLER'S METHOD 6000 5800 5600 WAIT AND WEIGHT METHOD 1.75SG 5400 DRILLER'S METHOD 5200 5000 WAIT AND WEIGHT METHOD 4800 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02.145 Figure 5.15 A Comparison of the Shoe Pressure – during displacement using the Driller’s and Wait and Weight Method for two gas kicks of different intensities Once the kill weight mud starts up the annulus, shoe pressures will be lower than if the Driller’s Method is used. As discussed in (b), the higher the kick intensity, the more marked the difference between wellbore pressures during the Wait and Weight Method and the Driller’s Method. However, for a given kick intensity the significance of the difference between the two techniques is also influenced by the depth of the shoe. The shallower the shoe, the more significant is the effect of the kill weight mud on pressure reduction at the shoe. The hole configuration therefore can influence the pressures seen at the shoe during displacement. Figure 5.16 shows a comparison of the shoe pressures for the same kick, for various lengths of openhole. A 20 barrel kick is taken at 3500m and is then displaced from the hole; Figure 5.16 shows the pressure variations at 1000m, 2000m and 3000m. As can be seen from Figure 5.16, if the shoe had been at 3000m, the maximum pressure at the shoe is clearly at initial shut-in. However, if the shoe was at 1000m, the shoe pressure is actually greater than at initial shut-in when the influx is displaced to the shoe. This situation is brought about when the influx expands to occupy a greater height in the annulus than it did at initial shut-in before it is displaced to the shoe. This generally requires a considerable length of openhole. Figures 5.17 to 5.21 compare the shoe pressures during displacement of a gas kick for a range of shoe depths, using both the Driller’s and the Wait and Weight Methods. 5-14 March 1995 BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: 3500m 1000m, 2000m, 3000m MW1: 1.7SG KICK ZONE EMW: 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20bbl GAS +100 CHANGE IN SHOE PRESSURE (psi) INITIAL (SHUT IN PRESSURE) 0 -100 SHOE AT 3000m -200 SHOE AT 2000m SHOE AT 1000m -300 -400 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.146 Figure 5.16 A Comparison of Shoe Pressures – during displacement of a 20 barrel gas kick for various shoe depths WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 3000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 8300 SHOE PRESSURE (psi) 8200 Q P 8100 8000 R 7900 DRILLER'S METHOD S WAIT AND WEIGHT METHOD 7800 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02.147 Figure 5.17 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 3000m 5-15 March 1995 BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2500m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 7100 SHOE PRESSURE (psi) 7000 6900 6800 DRILLER'S METHOD 6700 6600 WAIT AND WEIGHT METHOD 6500 6400 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.148 Figure 5.18 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 2500m WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 5900 SHOE PRESSURE (psi) 5800 5700 5600 DRILLER'S METHOD 5500 R 5400 5300 WAIT AND WEIGHT METHOD 5200 5100 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02.149 Figure 5.19 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 2000m 5-16 March 1995 BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 1500m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 4700 4600 P SHOE PRESSURE (psi) 4500 4400 DRILLER'S METHOD 4300 4200 4100 4000 WAIT AND WEIGHT METHOD 3900 3800 0 400 200 600 800 VOL MUD PUMPED (bbl) WEOX02.150 Figure 5.20 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 1500m WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 1000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 3500 3400 P SHOE PRESSURE (psi) 3300 3200 DRILLER'S METHOD 3100 3000 2900 2800 WAIT AND WEIGHT METHOD 2700 2600 2500 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02.151 Figure 5.21 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 1000m 5-17 March 1995 BP WELL CONTROL MANUAL Figure 5.17 shows the shoe pressure for a 20 barrel kick taken at 3500m for the shoe at 3000m. From initial shut-in to point P, the pressure decreases as the influx is displaced past the BHA; from point P to point Q the pressure increases as the influx expands as it is displaced up towards the shoe. At point Q, the top of the influx arrives at the shoe and from point Q to point R the pressure at the shoe drops as the influx is displaced past it. From point R to point S, the pressure at the shoe remains constant as the original mud occupies the annulus from the bottom of the hole to the shoe. However, the pressure at the shoe is further reduced at point S when, in the case of the Wait and Weight Method, the kill weight mud starts up the annulus. Figure 5.18 shows the shoe pressure for the shoe at 2500m. A similar pressure profile is shown to that in Figure 5.17; however in this case the influx expands more before it arrives at the shoe due to the greater length of openhole. Figure 5.19 shows the shoe pressure profile for the shoe at 2000m. In this case, the kill weight mud starts up the annulus at point R, when the tail of the influx is passing the shoe. Figure 5.20 shows the shoe pressure profile for the shoe at 1500m. In the case of the Driller’s Method, the shoe pressure almost reaches its original shut-in value. In the case of the Wait and Weight Method however, the kill weight mud starts up the annulus at point P, before the influx arrives at the shoe. The shoe pressure is reduced by the kill weight mud from this point on. Figure 5.21 shows the shoe pressure profile for the shoe at 1000m. In the case of the Driller’s Method, the shoe pressure now increases past the shut-in value as the influx is circulated to the shoe. However, in the case of the Wait and Weight Method, the kill weight mud starts up the annulus at point P, and this has the effect of reducing the maximum pressure that the shoe experiences. Figures 5.17 to 5.21 show that the Wait and Weight Method has only a small influence on the maximum shoe pressure for wells of this type, even when the shoe is relatively shallow. The most important point however is that the time that the shoe is subject to high pressure is substantially reduced when the Wait and Weight Method is used. The reduction in shoe pressure due to the kill weight mud is most significant when there is a long section of openhole (as is seen in Figures 5.17 to 5.21). (d) Influx Type All the pressure profiles in Figures 5.1 to 5.21 represent the displacement of gas kicks. As can be seen from the pressure profile, the expansion of the gas as it is displaced from the well significantly affects the resultant wellbore pressures. A water kick will behave in a different manner. Water is essentially incompressible and␣consequently will not expand appreciably as it is displaced up the well. This will mean that the wellbore pressures will not be significantly affected by the displacement of the influx, unless the water contains a significant quantity of gas. However a water kick may cause special problems as a result of hole deterioration as it is displaced from the hole. 5-18 March 1995 BP WELL CONTROL MANUAL Figure 5.22 shows a typical choke pressure profile for a salt water kick displaced from the hole by the Wait and Weight Method. From point P to point Q, the choke pressure remains relatively constant as the drillpipe is displaced to kill weight mud. From point Q to point R, the choke pressure drops as the kill weight mud starts up the annulus. This is in marked contrast to the gas kick where the expansion of the kick at this stage tends to increase the choke pressure. From point R to point S, the influx passes the choke with a corresponding drop in choke pressures. From point S to point T, the choke pressure drops as the original mud behind the influx passes the choke. At point T, the kill weight mud arrives at surface. 500 CHOKE PRESSURE (psi) 400 300 P Q 200 R 100 S T 0 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02.152 Figure 5.22 Choke Pressure – during displacement of a water kick using the Wait and Weight Method An oil kick is likely to behave in a similar manner to the gas kick when displaced from the well. The term ‘oil’ covers a large variety of fluids, ranging from viscous black oil that contains very little gas, to very light oils that have very high gas oil ratios. Most oil will contain gas at reservoir conditions which will come out of solution and expand as it is displaced up the hole. Essentially, therefore, the majority of oil kicks will behave similarly to a gas kick. 4 Subsea Considerations If a kick is taken from a floating rig, the influx will be displaced to the surface through a small diamater choke line that is attached to the drilling riser. The fundamental difference between well control procedures on a fixed and a floating rig originate from the necessity of having to circulate through this choke line. 5-19 March 1995 BP WELL CONTROL MANUAL The potential problems caused by circulating through the choke line can be summarised as␣follows: (a) Choke pressures will be significantly higher than for an equivalent well drilled from a fixed rig. This is due to the fact that the height of the influx is considerably increased as it is displaced from the annulus to the choke line. Figure 5.23 shows a comparison between the choke pressure during displacement of a gas kick from a well drilled in 1000m of water and a similar well drilled from a fixed rig. The influence of the choke line is apparent in that the maximum choke pressure is increased from 1200 psi to approximately 2600 psi. FIXED RIG: WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW, MW2: 3500m 2000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS FLOATING RIG: WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW, MW2: 3500m 2000m 1.7SG 1.83SG CHOKELINE: BHA: PIPE: TECH: INFLUX: 1000m/3in ID 6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS 2800 2400 FLOATING RIG CHOKE PRESSURE (psi) 2000 1600 1200 FIXED RIG 800 400 0 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.153 Figure 5.23 Comparison of Choke Pressures – during displacement of a gas kick on a fixed rig and a floating rig 5-20 March 1995 BP WELL CONTROL MANUAL Figure 5.24 shows the choke pressures during displacement of the same 20 bbl influx for a variety of water depths. It can be seen that the choke pressure is not, in this case, significantly affected by a water depth of 100m. FIXED RIG: WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW, MW2: 3500m 2000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS FLOATING RIG: WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW, MW2: 3500m 2000m 1.7SG 1.83SG CHOKELINE: BHA: PIPE: TECH: INFLUX: 1000m, 500m, 100m/3in ID 6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS 2800 1000m WATER 2400 CHOKE PRESSURE (psi) 2000 500m WATER 1600 100m WATER 1200 800 FIXED RIG 400 0 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.154 Figure 5.24 Choke Pressure for various Water Depths – during displacement of a gas kick (b) The rate of increase of choke pressure required as the gas enters the choke line may be unrealistically high at normal displacement rates. As can be seen from Figure 5.25 the increase in choke pressure required as the influx is displaced up the choke line is equivalent to 64 psi/bbl. This can be converted to a rate of choke manipulation for various displacement rates as follows: At 4 bbl/min At 3 bbl/min At 1 bbl/min At 0.1 bbl/min = = = = 64 64 64 64 x x x x 4 3 1 0.1 = = = = 256 psi/min 192 psi/min 64 psi/min 6.4 psi/min 5-21 March 1995 BP WELL CONTROL MANUAL It can therefore be seen that normal displacement rates have the potential to require an unrealistic rate of manipulation of the choke. In this case, the most satisfactory rate of displacement would be of the order of 1 bbl/min. As gas invades the choke line: p = bbl/pumped 1800 28 = 64psi/bbl 2000 28 = 71psi/bbl As the mud behind the gas enters the choke line p = bbl/pumped WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG CHOKELINE: BHA: PIPE: TECH: INFLUX: 1000m/3in ID 6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS 2800 CHOKE PRESSURE (psi) 2400 2000 1800psi 1600 2000psi 1200 800 400 0 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.155 Figure 5.25 Determination of the Required Rate of Choke Manipulation for a Deep Water Subsea Well It should be noted however that these calculations are based on the assumption that the gas influx enters the choke line as a discrete bubble without mixing with the mud ahead of it. This may not always be the case, however the figures quoted above certainly indicate that the normal kick displacement rates have the potential to cause such complications. A further problem exists in that when the gas enters the choke line, the drillpipe pressure will only register the drop in bottomhole pressure after the lag time, which can be substantial in deep wells. 5-22 March 1995 BP WELL CONTROL MANUAL On a fixed rig, the lag time will not be so problematical because the required rate of choke manipulation is generally lower. In other words, the bottomhole pressure will drop only very slightly before the drillpipe pressures registers that drop and the choke operator closes in the choke (to increase the choke pressure and hence the bottomhole pressure). The lag time between the choke and the drillpipe pressure gauges is generally considered to be of the order of 2 seconds per 300m of drillstring length. This lag time, however, will be significantly affected by the type and size of the influx in the hole. It can be seen therefore that there may be a lag time of approximately 20 seconds in deep wells. If the required rate of choke manipulation is 420 psi/min as the influx is displaced up the choke line, the bottomhole pressure may have dropped 130 psi before the drillpipe pressure gauge registers this drop. Clearly this is an additional reason for displacing the influx through the choke line at a rate that is substantially slower than normal slow circulation rates. (c) The rate of decrease of choke pressure required as the mud behind the gas reaches the base of the choke line may be unrealistically high. In a similar manner, the required rate of choke manipulation as the mud behind the influx enters the choke line may be unrealistically high at normal slow circulating rates. In this case, the potential problem is that the well may be overpressured, leading to the possibility of fracturing the exposed formation. Figure 5.25 shows that the choke pressure would theoretically have to be reduced at 71␣psi/bbl which corresponds to the following rates for various displacement rates: At 4 bbl/min At 3 bbl/min At 1 bbl/min At 0.1 bbl/min = = = = 71 71 71 71 x x x x 4 3 1 0.1 = = = = 284 psi/min 213 psi/min 71 psi/min 7.1 psi/min This is clear indication that normal displacement rates are unsuitable when displacing a gas influx through a long choke line. (d) The frictional pressure as a result of circulating through the choke line may be significant at slow circulating rates. Choke line frictional pressure may be significant, when added to the wellbore pressures resulting from the displacement of a kick. In certain circumstances, it may be of a magnitude such as to cause formation breakdown. There are special techniques that can be used to eliminate the effect of choke line losses during displacement of a kick. One such technique, namely the use of the kill line monitor, is described in Chapter 6 of Volume 1. Choke line losses are generally insignificant in relatively shallow waters, but can be significant in waters of 500m or greater. Figure 5.26 shows a table of estimated choke line losses for various choke line lengths. When very slow displacement rates are used, (such as 1 bbl/min) choke line losses are generally insignificant, even in deep water. 5-23 March 1995 BP WELL CONTROL MANUAL 3 bbl/min MUD WEIGHT (SG) 1.5 1.7 1.9 2.1 1000 m 120 200 220 245 500 m 90 100 110 125 100 m 17 19 22 25 1.5 1.7 1.9 2.1 1000 m 260 295 325 360 500 m 130 145 165 180 100 m 26 30 33 36 CHOKE LINE LENGTH (m) 4 bbl/min MUD WEIGHT (SG) CHOKE LINE LENGTH (m) Figure 5.26 Estimated Choke Line Losses (psi) for Various Choke Line Lengths (3 in. ID) 5 Safety Factors During well control operations, it is clearly necessary to maintain the bottomhole pressure slightly greater than the kick zone pressure. This will provide a margin of error for the choke operation that will prevent a second influx occurring. However, excessive additional pressure may needlessly overpressure the wellbore and possibly cause the formation to fracture. In general, every effort should be made to ensure that no additional pressures are applied to the openhole at early stages in the displacement of the kick when downhole pressures will generally be at a maximum. The following are possible causes of additional pressures during the displacement of a kick: (a) Annulus Frictional Pressure During displacement of a kick, the annulus back pressure will always provide a safety margin over and above the kick zone pressure. Standard well control techniques do not take annulus frictional pressure into account, and consequently the use of these techniques ensures that the bottomhole pressure is maintained at the kick zone pressure plus the annulus frictional pressure. Figure 5.27 shows a series of estimations of annulus frictional pressures for various well configurations. 5-24 March 1995 BP WELL CONTROL MANUAL 13 3/8in @ 1500m 12 1/4in hole 180m of 8in collars TD 1800m 7in @ 3200m Annulus pressure loss at 3 to 4bbl/min for mud weight range 1.3 SG to 1.7 SG = 20 to 25psi 9 5/8in @ 3200m 9 5/8in shoe @ 3500m 8 1/2in hole 270m of 6 1/2in collars TD 4000m 3 1/2in drillpipe Annulus pressure loss at 3 to 4bbl/min for mud weight range 1.7 SG to 2.1 SG = 100 to 125psi 7in @ 4200m 200m 4 3/4in collars 6in hole TD 4500m Annulus pressure loss at 3 to 4bbl/min for 1.5 SG mud = 150 to 180psi 2.1 SG mud = 190 to 240psi WEOX02.157 Figure 5.27 Annulus Pressure Loss for various Well Configurations It can be seen from these figures that the annulus frictional pressure may vary considerably from well to well in a kick situation. The significance of the annulus friction pressure must be assessed before a kick is displaced. (b) Heavier than Kill Weight Mud The use of heavier than kill weight mud will result in higher wellbore pressures than if kill weight mud is used, when standard techniques are used to displace a kick. This is because additional choke pressure must be applied to account for the fact that the drillpipe and annulus will be out of balance as the hole is circulated to heavier than kill weight mud. The maximum additional pressure will be applied when the heavier than kill weight mud arrives at the bit. The use of heavier than kill weight mud is not recommended. Figure 5.28 shows the choke pressure during displacement of a kick for various mud weights, in comparison to the Wait and Weight Method. Figure 5.29 shows the equivalent shoe pressures. 5-25 March 1995 BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: MW1: 3500m 2000m 1.7SG 1.83SG 1.83, 1.85, 1.87, 1.9SG 6 1/4in/180m 5in DP OVERBALANCED MUD INFLUX: 20bbl GAS BHA: PIPE: TECH: 1600 1400 CHOKE PRESSURE (psi) 1.9SG 1200 1000 800 1.87SG 1.85SG 600 1.83SG MUD (WAIT AND WEIGHT) 400 200 0 0 400 200 600 800 VOL MUD PUMPED (bbl) WEOX02.158 Figure 5.28 Choke Pressure – during displacement of a gas kick with overbalanced mud WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: MW2: 3500m 2000m 1.7SG 1.83SG 1.83, 1.85, 1.87, 1.9SG 6 1/4in/180m 5in DP OVERBALANCED MUD INFLUX: 20bbl GAS BHA: PIPE: TECH: SHOE PRESSURE (psi) 5000 4800 4600 1.9SG MUD 1.87SG MUD 4400 1.85SG MUD 1.83SG MUD (WAIT AND WEIGHT) 4200 4000 3800 0 200 400 600 800 VOL MUD PUMPED (bbl) Figure 5.29 Shoe Pressure – during displacement of a gas kick with overbalanced mud 5-26 March 1995 WEOX02.159 BP WELL CONTROL MANUAL Heavier than kill weight mud is often considered in order to either add a small overbalance after the kick has been displaced from well or to kill an underground blowout. From the examples in Figures 5.28 and 5.29 it can be seen that even a relatively small overbalance will increase the wellbore pressures during kick displacement. Overbalance should be added to the mud after the well has been killed. (c) Additional Choke Pressure An increase in choke pressure will exert an additional pressure throughout the circulating system. Therefore if the choke pressure is increased by 100 psi, the pressure at the casing shoe, at the bottom of the well and at the standpipe will increase by 100 psi. The choke pressure can therefore be used to apply a safety margin to the kick zone during displacement of the influx. However, care should be taken to avoid applying several safety factors while displacing the kick. Additional choke pressure should therefore only be considered if the annulus frictional pressure is known to be insignificant. Additional choke pressure should never be applied to the well at an early stage in the displacement when downhole pressures will generally be maximum. The advantage of using additional choke pressure to create a safety margin is that it can be controlled during displacement. For example, it may be applied only at a late stage in the displacement, when the influx is in the casing, kill weight mud has started up the annulus and consequently pressures on the openhole are at a minimum. 6 Calculating Annulus Pressure Profiles The annulus pressure profiles shown in this Chapter have been developed by computer. The software used applies Boyle’s Law to the original influx at the bottom of the hole and then calculates the pressures in the wellbore and at surface in order that bottomhole pressure is maintained constant and exactly equal to the kick zone pressure. The benefit of the computer is that it can process a great deal of calculations in a relatively short time. At the rigsite, it is not essential to have made all these calculations prior to displacing a kick from the hole. It is however useful to have a simple method of handcalculating both the maximum pressures that may be experienced at the openhole weak point, and at surface, before the kick is displaced from the hole. The annulus pressure worksheet shown in Figure 5.30a provides a means of determining these pressures. The techniques for using these sheets are described on the reverse side of this sheet, in Figure 5.30b. Figures 5.31 and 5.32 should be used in conjunction with the annulus pressure worksheet. The benefit of using this worksheet is that it can help in developing an understanding of the pressures involved during the displacement of a kick. It is not the simplest and quickest method. 5-27 March 1995 BP WELL CONTROL MANUAL The formulae that are presented as follows are recommended for use at the rigsite for quick estimations of annulus pressures during the displacement of a kick, if a computer is not available for this purpose: (a) Wait and Weight Method Use: 2 PD = S + K X 1.421 X MW2 4 C 1 2 –S 2 (psi) where: S = (TD – D) MW2 X 1.421 – H1 X 1.421 (MW2 – MW1) + Pi – Pf (psi) and: K= PO X VO X Z D ZO X TO X TD or: K = PO X and D PD TD ZD PO TO ZO VO MW2 MW1 C TD H1 Pi Pf VO (if temperature and compressibility effects are ignored) = = = = = = = = = = = = = = = depth to the top of the influx (m) pressure at the top of the influx (psi) influx temperature for influx at depth, D (°R) influx compressiblity factor for influx at depth, D original influx pressure (psi) original influx temperature (°R) original influx compressibility factor original inlfux volume (bbl) kill mud weight (SG) original mud weight (SG) annular capacity immediately below the influx (bbl/m) well total depth (m) height of original mud below influx (m) hydrostatic pressure influx (psi) kick zone pressure (psi) Therefore to determine the choke pressure at gas to surface, use D = O. To determine the pressure at the openhole weak point when the top of the influx is at the openhole weak point, use D = depth of openhole weak point. The hydrostatic pressure of the influx is assumed to remain constant during displacement. However it may be adjusted for substantial changes in annular capacity using the following formula: Pi1 = P i2 X C2 C1 where Pi1 Pi2 C1 C2 = = = = hydrostatic pressure of influx at original conditions (psi) hydrostatic pressure of influx at point of interest (psi) original annular capacity (bbl/m) annular capacity at point of interest (bbl/m) 5-28 March 1995 BP WELL CONTROL MANUAL (b) Driller’s Method This formula can be used both for the Driller’s Method and for the Wait and Weight Method when kill weight mud has not yet been circulated to the bit. Use: 2 P = S + K X MW1 X 1.421 4 C 1 2 –S 2 (psi) where: S = (TD – D) MW1 X 1.421 + Pi – Pf (psi) (c) For a Subsea Well In order to calculate the choke pressure with gas to surface for a subsea well, it is necessary to include into the formula the effect of the choke line. The formulae presented in (a) and (c) are equally applicable for calculating the pressure at the top of the influx before it is circulated to the subsea wellhead. The formulae presented as follows are used only to calculate choke pressure at gas to surface: Use for the Weight and Wait Method: 2 Pchoke = S + K X MW2 X 1.421 C 4 1 2 –S 2 (psi) where: S = H1 X 1.421 X MW1 + (TD – H1 – Dwhd + V cl ) MW2 C X 1.421 + Pi – Pf (psi) Use for the Driller’s Method: 2 Pchoke = S + K X MW1 X 1.421 4 C 1 2 –S 2 (psi) where: S = (TD – Dwhd +V cl ) MW1 X 1.421 + Pi – Pf (psi) C and Pchoke Dwhd Vcl C = = = = choke pressure at gas to surface (psi) wellhead depth below rotary table (m) internal volume of choke line (bbl) annular capacity immediately below the influx (bbl/m) 5-29 March 1995 BP WELL CONTROL MANUAL (d) A completed example Estimate the maximum choke pressure during displacement of a gas kick taken on a floating rig for the following conditions: Volume of influx, VO = 20 bbl gas Kill mud weight, MW2 = 1.83 SG Original mud weight, MW1 = 1.7 SG Annular capacity below the influx, C = 0.1604 bbl/m Well total depth, TD = 3500m Hole/Casing ID = 8.68 in. Drillstring: 5 in. drillpipe, BHA 180m/ 6 1/4 in. OD/ 2 3/4 in. ID Choke line:1000m/3 in. ID Capacity of the drillstring = (3370 X 0.05827) + (180 X 0.0239) = 201 bbl Height of this volume in the annulus, H1 = 201 = 1253m 0.1604 If the Weight and Wait Method is used: S = H1 X 1.421 X MW1+ (TD – H1 – D whd +V cl ) MW2 X 1.421 + Pi – Pf C = (1253 X 1.421 X 1.7) + (3500 – 1253 – 1000 + 28.5 ) 1.83 0.1604 X (psi) 1.421 + 59 + 9101 = -2310 psi Substituting into: 2 Pchoke = S + K X MW2 X 1.421 C 4 2 Pchoke = -2310 + 20 4 X 1 2 –S 2 9101 X 1.83 X 1.421 0.1604 (psi) 1 2 – -2310 2 (psi) = 3225 psi Therefore the maximum anticipated pressure during displacement is 3225 psi. It would however be anticipated that this figure represents the maximum possible pressure at surface and, as such, the actual maximum pressure would be expected to be lower than this value. (For derivation of these formulae ref: Blowout Prevention, Theory and Application by Peter Mills, 1984, D. Reidel Publishing Company.) 5-30 March 1995 Units (US/UK): For worksheet calculation enter information into shaded cells. Rig Name: bbl Date: Kick Zone Depth: TVD,ft Annulus, in. ID X OD length, ft bbl/ft Volume bbl Casing Shoe Depth: Annulus, in. ID X OD length, ft bbl/ft Volume bbl Kick Zone Pressure: TVD,ft = psi Original Mud Weight: ppg ppg Shut in Drill Pipe Pressure: Annulus, in. ID X OD length, ft bbl/ft Volume bbl Casing Pressure: = psi Mud Weight to Displace Kick: ppg Annulus, in. ID X OD length, ft bbl/ft Volume bbl Pit Gain = bbl Surface Temp: °F Annulus, in. ID X OD length, ft bbl/ft Volume bbl Influx Height = ft Temp Grad: °F/ft Total Annulus Volume bbl Influx Hydrostatic = psi Kill Mud Height of Hydro Pressure Below Influx Below Original Mud Pressure (psi) Mud Below Influx ( ) of Mud Below Influx ( psig ) Influx Hydrostatic (psi) Influx Mid-point Pressure (psia) °F °R (7) (8) (9) (10) (11) (12) (13) Vol (bbl) Height ( ) Pressure (psi) Vol (bbl) Height ( ) (1) (2) (3) (4) (5) (6) Influx Temp Influx Size Original Mud Hydro- above influx Req'd Back Pressure (psi) Pressure at the Shoe (psi) (20) (21) Factor Vol (bbl) Height ( ) Height ( ) Pressure (psi) static of Annulus Fluids (psi) (14) (15) (16) (17) (18) (19) ft ft Z 5-31 ft ft ft WEOX02.196 BP WELL CONTROL MANUAL Original Mud Volume of Mud Pumped (bbl) Annulus Pressure Worksheet Drillstring Internal Volume Well No: Figure 5.30a Version 1/1 1Q'95 by ODL/C. Weddle ANNULUS PRESSURE WORKSHEET March 1995 BP WELL CONTROL MANUAL Figure 5.30b Annulus Pressure Worksheet The worksheet provided can be used to estimate annulus pressures during the displacement of a kick. The worksheet can be used as follows for the Wait and Weight method: (if the Drillers method is used (5), (6) and (7) are left out of the calculation) (1) Barrels (bbl) of kill weight mud Estimate the volume of kill mud pumped for the gas to arrive at the point of interest. (2-4) Original mud below gas This volume is equal to the volume of kill weight mud pumped until the drillpipe is displaced. At this point and subsequently this volume will remain constant at the drillpipe internal volume. Convert this volume to height and hydrostatic pressure equivalent, in the annulus. (5-7) Kill mud below original mud This volume is zero until the internal volume of the drillstring has been displaced. Once the kill mud starts into the annulus, its height and hydrostatic pressure should be calculated. (8) Metres of mud below gas The total height of mud below the influx. (9) Pressure of mud below the gas Equal to (4) + (7). (10) Gas hydrostatic pressure In a constant annulus size it is assumed that the gas hydrostatic pressure remains constant as the influx expands. The gas hydrostatic must however be corrected for substantial changes in annular dimensions using the following relationship: Gas hydrostatic (2) = Gas hydrostatic (1) X (11) Annular capacity (2) Annular capacity (1) Gas mid point pressure This is equal to the kick zone pressure minus the total hydrostatic pressure of the mud below the influx and half of the gas hydrostatic pressure. (12-13) The gas temperature This is estimated from the surface pressure and the temperature gradient in the well unless more detailed information is available. The temperature in °F can be converted to °R by adding 460. Use Figure 5.31 (BP Well Control Manual, Volume 2) to determine the pseudo critical temperature and pressure of the gas (assume gravity is 0.7 unless logging unit has detected presence of CO2 or H 2S or unusually heavy hydrocarbon components). The pseudo reduced values are then calculated as follows: P pseudo reduced = P absolute (psia) P pseudo critical and T pseudo reduced = (14) T(°R) T pseudo critical Z factor The compressibility factor, Z, can be determined from Figure 5.32 (BP Well Control Manual, Volume 2) using the calculated values of pseudo reduced pressure and temperature. (15-16) Influx volume and height The expanded volume of the influx can be calculated using Gas law relationships as follows: V2 = T2 X Z2 X P1 X V1 P2 X T1 V T P Z = = = = Influx volume (bbl) Influx temperature (°R) Influx pressure (psia) Compressibility factor The influx height is determined as follows: Influx height = Influx volume Annular capacity (19) Total hydrostatic pressure of annulus fluids (20) Required back pressure (21) Pressure at the shoe This equal to (9) + (10) + (18). This is the difference between the kick zone pressure and the total hydrostatic pressure of the fluid in the annulus (19). The pressure at the shoe is determined by either: • Subtracting the hydrostatic pressure of the annulus fluids from the bottomhole to the shoe from the bottomhole␣pressure • Adding the hydrostatic pressure of the fluids from the shoe to the surface to the required back pressure (20) This procedure will be repeated until the influx is positioned at the appropriate point in the well. For example if the first calculation shows that the top of the influx is above the shoe (assuming that the point of interest is when the top of the influx arrives at the shoe), the calculation should be reworked for a smaller volume of mud pumped. For the first approximations it is a good idea to neglect the effect of temperature and compressibility in order to speed the calculation. 5-32 March 1995 BP WELL CONTROL MANUAL Figure 5.31 Graph of Pseudo-critical Temperature and Pressure for Hydrocarbons 700 Miscellaneou Pseudo Critical Pressure psia s gases Cond 650 ensat e well fluids 600 550 500 es Pseudo Critical Temperature °R as o ne lla 450 e isc g us M ell ew sat ds flui den Con 400 350 300 0.5 0.6 0.7 0.8 0.9 1 1.1 1.2 Gas Gravity (air = 1) WEOX02.162 5-33 March 1995 BP WELL CONTROL MANUAL Figure 5.32 Compressibility Factors for Natural Gas PSEUDO REDUCED PRESSURE 0 1 2 3 4 5 6 7 8 1.1 1.1 PSEUDO REDUCED TEMPERATURE 1.05 3.0 1.0 2.8 2.4 2.6 1.0 2.2 2.0 0.9 0.95 1.5 1.9 1.8 1.3 1.2 1.1 1.4 1.7 1.6 0.8 1.7 1. 05 1.5 1. 1 1.45 1.6 1.35 2 1. 1.3 0.6 3 1. 1.5 1.25 4 1. 1.5 1.6 1.7 1.2 0.5 .15 1.9 1 1.8 2.0 1.4 COMPRESSIBILITY FACTOR Z COMPRESSIBILITY FACTOR Z 1.4 0.7 2.2 1 1. 0.4 2.4 1.3 2.6 3.0 1.2 1. 05 0.3 0.25 3.0 2.8 1.1 2.6 2.2 1.9 1.0 1.1 2.4 2.0 1.8 1.1 1.05 1.2 1.0 1.7 1.6 January 1, 1941 1.4 1.3 0.9 0.9 7 8 9 10 11 12 13 14 15 PSEUDO REDUCED PRESSURE WEOX02.163 5-34 March 1995 BP WELL CONTROL MANUAL 6 WELL CONTROL EQUIPMENT Section Page 6.1 WELLHEADS 6-1 6.2 BLOWOUT PREVENTER EQUIPMENT 6-5 6.3 CONTROL SYSTEMS 6-43 6.4 ASSOCIATED EQUIPMENT 6-55 6.5 EQUIPMENT TESTING 6-64 Blowout preventers and associated equipment provide the means of controlling a well after primary control has been lost. The basic requirements for effective BOP equipment include: • A properly designed and cemented casing string that can contain pressures encountered whilst drilling. • A properly designed and installed wellhead assembly that can support, and seal between, the casing string and the BOP stack. • BOPs securely anchored to the wellhead and capable of closing off the annulus against openhole or any tool that is run into the hole. • A control system to operate the BOPs which features adequate redundancy and acceptable closing times. • A choke system that can maintain a variable back pressure on a well whilst it is circulated. • A kill system which gives flexibility to pump to the hole via the annulus or drillstring. • Instrumentation that allows control of the well killing operation. March 1995 BP WELL CONTROL MANUAL 6.1 WELLHEADS Paragraph Page 1 Surface Wellheads 6-2 2 Subsea Wellheads 6-2 6-1 March 1995 BP WELL CONTROL MANUAL 1 Surface Wellheads A conventional wellhead for use on land, platform and jack-up rigs, comprises a series of spools and is based on a starting head. The starting head is anchored to the surface string of casing, with the weight of the casing transferred to the cement, or mud line hanger. Additional support may be provided by the conductor. The major components of the surface wellhead are as follows: (a) Spools Conventional wellhead spools generally incorporate the following features: • API standard flanges, or hub to suit a clamp, top and bottom. The flange face has a machined groove, often inlaid with stainless steel, to suit an API gasket. • A set of seals, sometimes energised with plastic packing, in the base of the spool, to pack off around the preceding casing stub. • A bowl to accommodate the next casing string slips. • Studded or flanged side-arms below the bowl,which provide communication to the casing annulus. Often the side-arm is threaded to accept a plug to facilitate valve removal. • Lock down screws are provided in the top flange of most spools, to retain, and sometimes to energise the pack-off, and also to retain the bore protector. • Ports are provided to allow the pressure testing of the flange seals (i.e. the void between the slip and seal assembly, the upper spool seals, and the ring gasket). (b) Slip and Seal Assembly The weight of the casing string is transferred onto the preceding spool via casing slips. The assembly incorporates a packer, which is weight or jack screw energised, and seals the annulus between casing and spool. As an alternative to the conventional stack of spools, several manufacturers offer a more compact system, in which the conventional stack of spools is replaced by wellhead housing in which successive casing slips/hangers are stacked. Such a system greatly simplifies and speeds wellhead installation; it can be similar in concept to a subsea wellhead. 2 Subsea Wellheads A subsea wellhead as used on floating rigs, consists of one or two wellhead housings, casing hangers/pack-offs and a guide base. It is positioned just above the seabed. The wellhead housings are normally made up onto the conductor and 13 3/8 in. casing in the case of a 2 stack system, or onto the conductor and surface casing in the case of a single stack system. They perform four functions: • Support of casing strings by means of an internal upset on which the first casing hanger lands. Subsequent casing hangers land off on the previous seal assembly. 6-2 March 1995 BP WELL CONTROL MANUAL • Pressure isolation of the casing annulus from the wellbore by providing a polished bore on which the seal assembly packs off. • Pressure containment between the wellhead housing and the BOP, by provision of a polished stainless steel inlaid profile for a gasket in the hub bore. • Support of the stack which lands on the hub and latches onto a profile on the outside of the hub. Commonly 21 1/4 in. housings are rated to 2000 or 5000 psi, 16 3/4 in. housings to 5000 or 10,000 psi, 18 3/4 in. and 13 5/8 in. housings to 10,000 psi or 15,000 psi. The following are the major items of equipment associated with the subsea wellhead: (a) Casing Hangers Casing hangers are screwed on to the top of the casing string, and are landed in the wellhead on a retrievable handling string. (b) Seal Assembly The seal assembly provides a means of isolating the casing annulus by sealing between the hanger and the wellhead housing. In most systems, the packer is energised with weight or by right hand torque, although some deep water designs are set hydraulically. Generally, the energised packer is locked into a recess in the housing. (c) Stack Connector The BOP stack is connected to the wellhead by means of a hydraulically actuated connector which clamps on to a profile on the outside of the hub. The connector should have the same pressure rating as the stack. The connector retains a metal gasket that is weight and pressure energised, to seal between the wellhead and connector. (d) Permanent Guide Base A permanent guide base is locked onto and run with the 30 in. wellhead housing. It acts as an anchor for the guidelines, and a guide for locating the stack connector precisely over the wellhead. For deep water guidelineless operations, the standard square four posted guide base is replaced by a funnel, or petal shaped guide box. 6-3/4 6-3 March 1995 BP WELL CONTROL MANUAL 6.2 BLOWOUT PREVENTER EQUIPMENT Paragraph Page 6-7 1 Annular Preventers 2 Ram Type Preventers 6-15 3 BOP Stack Size and Pressure Rating 6-20 4 Stack Configurations 6-23 5 Choke and Kill Lines 6-29 6 Choke and Standpipe Manifolds 6-36 7 Diverters 6-39 Illustrations 6.1 Annular Preventer Sealing Elements 6-8 6.2 Hydril Annular Preventer Type MSP 6-9 6.3 Hydril Annular Preventer Type GK 6-10 6.4 Hydril Annular Preventer Type GL 6-11 6.5 Shaffer Annular Preventer 6-12 6.6 Cameron Annular Preventer Type D 6-13 6.7 Packing Unit Selection (from Hydril) 6-14 6.8 Secondary Rod Seal – Cameron Type U 6-17 6.9 Ram Preventer Opening and Closing Ratios 6-18 6.10 Approved BOPs for Company Operations 6-21 6.11 Availability and Bore of Blowout Preventers by Major Manufacturers 6-22 6.12 5M Surface BOP Stack 6-25 6.13 10M/15M Surface BOP Stack 6-26 6.14 Four Inlet/Outlet 10M/15M Subsea BOP Stack 6-27 6.15 Three Inlet/Outlet 10M/15M Subsea BOP Stack 6-28 6.16 Specifications for BOP Flanges, Ring Gaskets, Flange Bolts and Nuts 6-34 6-5 March 1995 BP WELL CONTROL MANUAL 6.17 Hydril Drilling Spool Data 6-35 6.18 Choke Manifold, 10M/15M 6-38 6.19 Standpipe Manifold 6-39 6.20 Subsea Diverter Stack 6-40 6-6 March 1995 BP WELL CONTROL MANUAL 1 Annular Preventers Annular preventers have a doughnut shaped elastic element with bonded steel internal reinforcing. Extrusion of the element into the wellbore is effected by upwards movement of a hydraulically actuated piston. The element is designed to seal around any shape or size of pipe and to close on openhole. (See Figure 6.1.) An important function of annular preventers is to facilitate the stripping of the drillpipe in or out of the well, with pressure on the wellhead. Undue wear of the element is avoided by the use of pilot-operated hydraulic regulator, which controls closing pressure. The majority of annular preventers currently in use are manufactured by Hydril (Types MSP, GK, GL, GX), Shaffer (Spherical) and Cameron (Type D), these are illustrated below (See Figures 6.2 to 6.6) together with a summary of major operating features. The following are the most important aspects of the operation of annular preventers: • To obtain maximum sealing element life, hydraulic closing pressures should conform to the manufacturer’s recommendations for pressure testing and operational use of the preventers. Excessive closing pressures, when coupled with wellbore pressure sealing effects, cause high internal stresses in the element and reduce element life. • Cavities should be flushed out and the element inspected following each well. Preventers should be stripped and inspected annually. Seals should be replaced and all sealing surfaces inspected. • Cap seals should be replaced when changing elements. • Drilling tools, especially rock bits, should be run cautiously through BOPs to minimise element damage. Elements of annular preventers do not, on occasions, retract fully. • The type of elastomer (natural rubber, synthetic rubber, neoprene) used in the packing␣element should be the most suitable for a particular wellhead environment. See Figure 6.7. • Although most models and sizes of annular preventer will seal an openhole in an emergency operation, it is not recommended as such gross deformation of the elastomer causes cracking and accelerated wear. • Closing pressures should be regulated to the pressures specified by the manufacturers. This information should be available at the rigsite. • When stripping, the closing pressure should be regulated to the minimum required for a slight weeping of mud past the element. Closing pressures higher than this will increase element wear. The pipe should be moved slowly, particularly as tool joints pass through the element. The manufacturers also provide information regarding recommended closing pressures during stripping operations. Surge vessels on the closing ports will help to smooth-out surge pressures as tool joints pass through the element. 6-7 March 1995 BP WELL CONTROL MANUAL Figure 6.1 Annular Preventer Sealing Elements SPHERICAL SEALING ELEMENT (SHAFFER) CUTAWAY DRAWING SHOWING HOW RUBBER IS MOULDED AROUND STEEL SEGMENTS (HYDRIL) (CAMERON) OPEN CLOSED ON PIPE CLOSED ON PIPE WEOX02.164 6-8 March 1995 BP WELL CONTROL MANUAL PACKING UNIT PISTON OPENING CHAMBER CLOSING CHAMBER Operating Features: 1. 2. 3. 4. 5. Will close on open hole and hold 2000psi (but not recommended). Primary usage is in diverter systems. Automatically returns to the open position when closing pressure is released. Sealing assistance is gained from the well pressure. Good stripping capability of the packing unit since (fatigue) wear occurs on the outside of the packing unit. Figure 6.2 Hydril Annular Preventer Type MSP WEOX02.165 • Most annular preventers are designed to use wellbore pressure to assist in maintaining closure. In some circumstances and depending on the preventer size, the well pressure can maintain closure without any closing hydraulic pressure being applied. An annular preventer should never be operated without some closing hydraulic pressure applied. The reason is that with only well pressure maintaining closure, the packing unit may suddenly open with only a small surge or reduction in well pressure. Also, the pressure seal may be lost around the body of the drillpipe after a tool joint passes through the element during stripping operations. 6-9 March 1995 BP WELL CONTROL MANUAL Figure 6.3 Hydril Annular Preventer Type GK PISTON TRAVEL INDICATOR HOLE PACKING UNIT PISTON OPENING PORT CHAMBER CLOSING CHAMBER Operating Features: 1. 2. 3. 4. 5. Will close on open hole (but not recommended). Sealing assistance is gained from the well pressure. Requires high closing pressures when used in subsea installations. Has provision to measure piston travel to gauge element wear. Available with a bolted top. WEOX02.166 6-10 March 1995 BP WELL CONTROL MANUAL Figure 6.4 Hydril Annular Preventer Type GL PACKING UNIT OPENING CHAMBER PISTON PRIMARY CLOSING CHAMBER SECONDARY CHAMBER Operating Features: 1. 2. 3. 4. 5. 6. Will close on open hole (but not recommended). Some sealing assistance is gained from well pressure. Bolted cover for easier element charge. Primarily designed for subsea operations. Has provision to measure piston travel to gauge element wear. Has a secondary chamber which can be connected four ways to achieve different effects: a. Minimise closing/opening fluid volumes; b. Reduce closing pressure; c. Automatically compensate (counterbalance) for marine riser hydrostatic pressure effects in deep water; and d. Operate as a secondary closing chamber. WEOX02.167 6-11 March 1995 BP WELL CONTROL MANUAL PACKING UNIT UPPER ADAPTER HEAD OPENING CHAMBER PISTON CLOSING CHAMBER Operating Features: 1. 2. 3. 4. 5. 6. Will close on open hole (but not recommended). Requires higher closing pressure in subsea applications. Some sealing assistance is gained from the well pressure. No provision for measuring piston travel. Currently the most common annular preventer for subsea use. Important to check seals in upper adapter head when changing an element and replace if necessary. WEOX02.168 Figure 6.5 Shaffer Annular Preventer • Cameron’s Type D annular preventer requires 3000 psi hydraulic closing pressure for positive closure with no pipe in the preventer. This reqires a bypass arrangement around the 1500 psi annular regulator on 3000 psi closing units. Hydril’s and Shaffer’s annular preventers are claimed to provide positive closure with 1500 psi closing unit pressure when the rubber elements are new. • If the annular packing element wears out during stripping or well killing operations, the element can be changed without pulling the pipe. After the pipe rams are closed and locked below the annular preventer and the hydraulic and well pressure bled off, the cover of the preventer can be unbolted and the packing element lifted out with a hoist line. With the element above the preventer, the damaged unit can be split and removed from the pipe. New packing elements for Hydril and Shaffer annular preventers can be split in the field and installed in reverse order. Cameron has recently developed a packing element for their Type D annular preventer which can be split in the field. 6-12 March 1995 BP WELL CONTROL MANUAL • A 1 in. valve can be installed on both the opening and closing lines next to the annular preventer. These valves must be in the open position at all times except when testing hydraulic lines and hydraulic chamber seals. These valves can be used to verify seal leaks between the opening and closing chambers of an annular preventer. PACKING UNIT OPENING CHAMBER PISTON CLOSING CHAMBER Operating Features: 1. 2. 3. 4. 5. 6. Quick-release top latch for easy element change. Most sizes use less closing fluid than Shaffer and Hydril annular preventers. Overall height is less than Hydril and Shaffer annular preventers. Two piece packing unit. Operational problems have been experienced with this preventer. Requires 3000psi closing pressure to close an openhole. WEOX02.169 Figure 6.6 Cameron Annular Preventer Type D 6-13 March 1995 BP WELL CONTROL MANUAL IDENTIFICATION PACKING UNIT TYPE Colour Code OPERATING TEMP RANGE DRILLING FLUID COMPATIBILITY NATURAL RUBBER Black NR -30°F – 225°F Waterbase fluid NITRILE RUBBER Red Band NBR -20°F – 190°F Oil base/oil additive fluid NEOPRENE RUBBER Green Band CR -30°F – 170°F Oil base fluid Figure 6.7 Packing Unit Selection (from Hydril) • Only packing elements which are supplied by the manufacturer of the annular preventer should be used. New or repaired units obtained from other service companies should not be used since the preventer manufacturers cannot be held responsible for malfunction of their equipment unless their elements are installed. Closing pressures must be adjusted when annular preventers are operated subsea. The manufacturers’ recommendations for the required adjustment pressure are summarised below: • For Hydril GK and MSP, the adjustment pressure is related to the mud weight, the water depth, and the water density as follows: ∆P = (MW where ∆P MW ρw D CR = = = = = X 1.421 X D) – ρ (w CR X D X 1.421) (psi) adjustment pressure (psi) mud weight in the riser (SG) sea water density (SG) water depth (m) annular closing ratio and CR = Closing chamber area Closing chamber area – Opening chamber area For example CR for Hydril 13 5/8 in. 5M GK = 2.56 CR for Hydril 21 1/4 in. 2M MSP = 4.74 and so: Subsea closing pressure = Surface closing pressure + Adjustment pressure • For Hydril GL operated subsea (with the secondary chamber connected to the opening␣line): Adjustment pressure as for Hydril GK in subsea operation. 6-14 March 1995 BP WELL CONTROL MANUAL • For Hydril GL operated subsea (with the secondary chamber connected to the closing␣line): Adjustment pressure = K X Adjustment pressure (as determined for Hydril GK) where K = • Closing chamber area Closing chamber area – Secondary chamber area For Hydril GL operated subsea (with secondary chamber in hydraulic communication with the riser): No adjustment required. • For the NL Shaffer annular operated subsea, tests carried out by Exxon indicated that the required adjustment to the closing pressure is given by the following: For the 16 3/4 in. 5M: ∆P = (0.335MW – 0.335)D For the 18 3/4 in. 5M: ∆P = (0.339MW – 0.318)D 2 Ram Type Preventers Ram type BOPs have two hydraulically actuated horizontally opposed rams which are either designed to seal off an openhole or an annulus against a pipe of specific diameter. Variable bore pipe rams are also available for most ram preventers. At least one preventer should be fitted with rams to suit each size of drillpipe in the hole. However, it is not considered necessary to install casing rams under normal circumstances; annular preventers suffice for closing on casing, unless conditions are exceptional. On subsea stacks, pipe rams should be designed to support the string weight, (i.e. to hang-off on) and at least one set of blind/shear rams installed. The working pressure of ram preventers should be at least equal to the maximum anticipated surface pressures, plus a margin for pumping to the well. There are several different types of ram preventer, as outlined below: (a) Pipe Rams Standard pipe rams are designed to centralise and pack-off around one specific size of drillpipe or casing. (b) Variable Pipe Rams Variable pipe rams are available for some models. One set of variable rams will provide back-up for two different pipe rams, e.g. 3 1/2 in. and 5 in. or 5 in. and 7 in. Some variable rams have a limited hang-off capacity, which is dependent on relative tool joint size and ram range. 6-15 March 1995 BP WELL CONTROL MANUAL Cameron offer the following sizes of variable bore rams: BOP Bore Pipe Size Range 11 in. 11 in. 13 5/8 13 5/8 16 3/4 16 3/4 18 3/4 18 3/4 5 5 7 5 7 5 7 5 in. in. in. in. in. in. in. – 2 7/8 in. 1/2 in. – 3 1/2 in. in. – 4 1/2 in. in. – 2 7/8 in. in. – 3 1/2 in. in. – 2 7/8 in. 5/8 in. – 3 1/2 in. in – 2 7/8 in. (c) Hanging Rams Pipe rams with enhanced load-bearing capabilities (usually rated to 600,000 lb) can be furnished for floating operations. Sometimes this involves special hardening of the bearing area, which might render the ram unsuitable for sour service. (d) Blind/Shear Rams These are designed to cut drillpipe and then seal as blind rams. The pipe stub is accommodated in a recess. Shearing of drillpipe should be carried out with the pipe stationary, which involves hanging off on floating rigs, and in tension, if practical. Care should be taken to ensure that the pipe body, not a tool joint, is opposite the rams. On some preventers, it may be necessary to increase operating pressure above 1500 psi to shear. Blind/shear rams should be specified when ordering a preventer, as some preventers require oversized cylinders or other special features. Some models of blind/shear ram are unsuitable for sour service. (e) Offset Rams Offset rams and dual offset rams are available for dual completions, and should be used where appropriate. The majority of ram-type preventers in present day use are manufactured by Cameron (Types U and T), NL Shaffer (Types LWS and SL) and Hydril (Types V and X). Although the detailed design of products from the three manufacturers varies, most models share the following basic features: • Self Feeding Action of Elastomer The front elements of ram seals have steel plates bonded to the rubber. As the rams are␣ b rought together , these steel plates meet before the preventer is fully closed. Further␣movement of the ram bodies causes extrusion of the rubber element, thereby effecting a seal. If the rams are used for stripping pipe, the front face of the ram sealing element will wear. The self-feeding action, brought about by the steel plates, will ensure that rubber from the packing element moves forwards to replace that which is worn away. • Ram Locking Devices Hydraulically operated ram preventers are provided with locking-screw stem extensions and large diameter hand wheels similar to the operating screws of manually closed preventers. The main purpose of the locking screws is to manually lock the rams in the 6-16 March 1995 BP WELL CONTROL MANUAL closed position after they are shut hydraulically. In an emergency, the screws can be used to close the rams if the hydraulic system fails. If the locking screws are used to close the rams, the hydraulic closing unit valve handle should be turned to the closed position. This will eliminate the possibility of hydraulic oil being trapped on the opening side of the actuating pistons. An optional hydraulic lock mechanism (Cameron’s Wedge Lock, Shaffer’s Poslock and Hydril’s MPL) can be used in place of locking screws to lock the rams in the closed position. The hydraulic lock holds the rams closed until unlocking pressure is applied even though the primary control pressure is released. The hydraulic ram lock was developed for subsea BOP stacks and can be used on land rigs in place of the manually operated locking screws. BACK-UP RINGS (IN 10000 AND 15000psi WP PREVENTERS ONLY) PLASTIC INJECTION SCREW CHECK VALVE ENERGISING RING HYCAR LIP SEAL RETAINER RING AND LOCKING RING PLASTIC PACKING RING 'O' RING VENT TO ATMOSPHERE OPERATING CYLINDER PREVENTER BODY PREVENTER BONNET WEOX02.171 Figure 6.8 Secondary Rod Seal – Cameron Type U • Secondary Shaft Seals All ram preventers with rated working pressure 5000 psi or higher, should be equipped with secondary piston rod seals, see Figure 6.8, in case the primary rod seals fail. Due to routine wear, the primary rod seal may leak under excessive pressure during well control operations. The secondary seal is plastic which is stored in a cavity until it is activated by forcing it around the ram rod. This plastic seal is used only during emergency situations. The secondary seal is designed for static conditions and movement of the rod causes rapid wear of both the seal and rod. The primary rod seal must always be repaired when the emergency is over. During the initial pressure testing of a BOP stack, the secondary seals on each ram preventer should be removed to assure that the main rod seals are tested. The secondary seal can be removed by unscrewing the energising plug, removing the check valve and digging out the plastic packing. 6-17 March 1995 BP WELL CONTROL MANUAL SIZE 7 1/16 in. 9 in. 11 in. WP (psi) 3,000 5,000 10,000 15,000 Cameron U Open Close 2.3 2.3 2.3 2.3 6.9 6.9 6.9 6.9 Shaffer ‘SL’ Open 3.37 Hydril Ram Close Open Close 7.11 1.5 1.5 1.7 6.6 5.4 5.4 8.2 7.6 2.6 2.6 5.3 5.3 6.8 6.8 7.6 7.6 2,000 3,000 5,000 10,000 2,000 3,000 5,000 10,000 15,000 2.5 2.5 2.5 2.5 2.2 7.3 7.3 7.3 7.3 9.9 7.62 2.8 7.11 7.11 2.0 2.0 2.4 3.24 13 5/8 in. 3,000 5,000 10,000 15,000 2.3 2.3 2.3 5.6 7.0 7.0 7.0 8.4 3.00 3.00 4.29 2.14 5.54 5.54 7.11 7.11 2.1 2.1 3.8 3.56 5.2 5.2 10.6 7.74 16 3/4 in. 2,000 3,000 5,000 10,000 2.3 2.3 2.3 6.8 6.8 6.8 2.03 2.06 5.54 7.11 2.41 10.6 18 3/4 in. 10,000 15,000 3.6 4.1 7.4 9.7 1.83 1.68 7.11 10.85 1.9 2.15 10.6 7.27 21 1/4 in. 2,000 3,000 5,000 10,000 1.3 1.3 5.1 4.1 7.0 7.0 6.2 7.2 0.98 0.98 1.9 5.23 5.2 10.6 2,000 3,000 1.0 7.0 26 3/4 in. 1.63 7.11 Figure 6.9 Ram Preventer Opening and Closing Ratios • Closing Ratios Ram-type preventers have specially designed opening and closing ratios, as shown in Figure 6.9. These are the ratios between the well pressures and the operating pressures needed to open or close the rams. Closing ratios are generally in the range of six-to-one to nine-to-one. This means that a preventer having a closing ratio of six-to-one would require 500 psi closing pressure to close the preventer when the wellbore pressure is 3000 psi. Opening ratios are much lower because the wellbore pressure acts behind the ram to oppose opening. Opening ratios of two-to-one are common. 6-18 March 1995 BP WELL CONTROL MANUAL It should also be noted that, for high wellbore pressures, pressures greater than 3000 psi may be required to open some ram preventers. • Bonnet Seals Bonnet (or door) seals are exposed to wellbore pressures and fluids. Since they can be subjected to high pressures and temperatures without being backed-up by another seal, bonnet seals are critical to the integrity of the BOP system. The seals are generally of fibrous/rubber construction and require careful handling and installation. Manufacturers’ recommendations should be observed meticulously. – Bonnet seals should be replaced each time bonnets are opened. – Bonnet seals should be handled carefully, particularly on installation, and be stored at controlled temperatures in darkness. They should be discarded after storage for one year. – Bonnet bolts should be made up to manufacturers’ recommended torques, which can be extremely high with some compression-type seals. Due regard should be paid to the type of lubricant used, eg make-up torque is reduced by approximately 50% if a molybdenum disulphide lubricant, rather than an API5A lubricant, is used. – Bonnet faces, preventer faces and seal grooves should be clean and dry before seal installation and make-up. – Bonnet seals should be tested after installation. The following are the most important aspects of the care and maintenance of ram preventers: • Pipe rams should not be closed on openhole or on mis-matched pipe. This would induce excessive extrusion of the elastomer and can cause cracking or bonding failures. • Ram recesses should be washed out and the ram element inspected following each well. Preventers should be stripped, inspected (particularly all sealing surfaces) and seals replaced annually. • When in good operating condition, ram preventers should close with 300 psi or less hydraulic pressure without wellbore pressure. If high closing pressure is required during test operations, the preventer should be checked first for debris in the ram cavity and then inspected for piston rod misalignment or other mechanical problems. • Wellbore pressure helps close ram preventers. They are designed to hold pressure from the lower side and will not seal properly if installed upside down. Also, ram preventers are not designed to be pressure tested from the top side and this can damage the preventer. Field experience has proven that ram preventers are more likely to leak with a low␣wellbore pressure than a high pressure. For this reason, they should be tested at 200/300␣psi prior to the rated working pressure test. • Ram preventers will close faster than annular preventers, especially in the larger sizes. Usually, ram preventers require only one-third or less of the hydraulic fluid volume to close compared to an annular. In instances where mechanical problems prevent rapid closure of the annular preventer, a ram preventer should be closed immediately to minimise additional well flow. • The main closing unit control handle for operating blind or blind/shear rams should always be protected against accidental closure with pipe in the hole. Numerous costly incidents have resulted from accidentally closing the blind rams and flattening or cutting 6-19 March 1995 BP WELL CONTROL MANUAL the drillpipe during well control or drilling operations. A flip-up cover without locking device should be used. If the handle is locked in the open position, it prevents closing the preventer from a remote station. Shear rams are not recommended for land rig operations. • When aluminium drillpipe is used, special consideration must be given to ram size selection. For example, 5 in. aluminium drillpipe has an outside body diameter of 5.150 in., versus a 5.000 in. body diameter for 5 in. steel pipe. Thus, regular 5 in. ram blocks must be slightly modified to seal and not damage the main tube section of aluminium pipe. In addition, 5 in. aluminium pipe has a tapered transition zone for a length of 41 in. to 46 in. on both the box and pin ends from 5.150 in. OD up to 5.688 in. OD. Standard rams will not seal on the tapered end sections. Variable bore rams can be used to seal on the body and end sections of aluminium drillpipe. • Ram preventers can be used to strip drillpipe in or out of the hole under pressure, but it is necessary to use two preventers which have sufficient distance between rams to isolate a tool joint box. The drilling spool provides this space in a five preventer stack. The upper and lower rams of a double ram preventer are too close together for this purpose. Excessive hydraulic pressure should not be applied on the rams when stripping pipe under pressure because it tends to wear the resilient material of the ram. The lowest ram in the BOP stack should never be used for stripping since it is always considered the master valve. 3 BOP Stack Size and Pressure Rating The following stacks are available: • • Single stack systems Bore Working Pressure 21 1/4 in. 18 3/4 in. 16 3/4 in. 10M (virtually obsolete) 10M or 15M 5M or 10M Multiple stack systems Bore Working Pressure 21 1/4 in. 13 5/8 in. 11 in. 2M or 5M 5M, 10M or 15M 5M, 10M or 15M Figure 6.10 shows a summary of approved BOPs. Figure 6.11 shows the availability and bore of BOPs from the major manufacturers. 6-20 March 1995 BP WELL CONTROL MANUAL OFFSHORE DIVERTER SYSTEMS Hughes Offshore Hughes Offshore Type KFDS (Floating) Type KFDJ (Platform) Hydril C Type FSP (Floating and Platform) (with Flow Selector) ANNULAR PREVENTERS ACCEPTABLE RUBBERS* Cameron – Type D Nitrile – Water and Oil Muds Hydril – MSP, GK, GKS, GS, GL, GX The following types of Hydril rubbers are available: 1. Natural rubber (black) – Water base muds 2. Synthetic rubber (red) – All muds 3. Neoprene rubber (green) – Low temperature service and oil muds Shaffer – Spherical The following types of Shaffer rubbers are available: 1. Natural rubber (black) – Water base muds 2. Nitrile (blue) – Oil and water base muds RAM PREVENTERS ACCEPTABLE RUBBERS* Cameron – Type QRC Cameron – Type U Super Wear – Water and oil muds Super Wear – Water and oil muds Hydril – Type Ram Nitrile – Water and oil muds Shaffer – Type LWP Shaffer – Type LWS Shaffer – Type SL The following types of Shaffer rubbers are available: 1. Natural rubber (black) – Water base muds 2. Nitrile (blue) – Oil and water base muds Koomey – Type PL PB * All BOP manufacturers specify their rubber elements and rams as H2S resistant; however, H 2S exposure reduces the service life of rubber products. The performance of these products can vary significantly, depending on the extent of exposure and H2S content. ** Shaffer Type 70 ram blocks are not acceptable because of metallurgical and rubber packer failures. Figure 6.10 Approved BOPs for Company Operations 6-21 March 1995 Cameron U Cameron QRC Cameron D Hydril GK Hydril GL Hydril GX Hydril HSP Hydril Ram Shaffer LWS Shaffer SL Shaffer Spherical Koomey 3,000 5,000 10,000 15,000 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. – – 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. – – – – – – – – – – – – 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. – 7 1/16 in. 7 1/16 in. – – – – 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. – 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. 9 in. 9 in. 9 in. 9 in. 2,000 3,000 5,000 10,000 – – – – – 9 in. 9 in. – – – – – – 9 in. 9 in. 9 in. – – – – – – – – 9 in. – – – – 9 in. 9 in. – – – 9 in. – – – – – – 9 in. 9 in. – – – – – 11 in. 11 in. 11 in. 11 in. 11 in. 2,000 3,000 5,000 10,000 15,000 – 11 in. 11 in. 11 in. 11 in. – 11 in. 11 in. – – – 11 in. 11 in. 11 in. 11 in. – 11 in. 11 in. 11 in. – – – – – – – – – 11 in. 11 in. 11 in. – – – – – 11 in. 11 in. 11 in. 11 in. – 11 in. 11 in. – – – – – 11 in. 11 in. – 11 in. 11 in. 11 in. – – 11 in. 11 in. 11 in. 11 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 3,000 5,000 10,000 15,000 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. – – – 13 5/8 in. 13 5/8 in. 13 5/8 in. – 13 5/8 in. 13 5/8 in. 13 5/8 in. – – 13 5/8 in. – – – – 13 5/8 in. 13 5/8 in. – – – – 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. – – – – 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. – 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 16 3/4 in. 16 3/4 in. 16 3/4 in. 16 3/4 in. 2,000 3,000 5,000 10,000 – 16 3/4 in. 16 3/4 in. 16 3/4 in. 16 3/4 in. – – – – 16 3/4 in. 16 3/4 in. – 16 3/4 in. 16 3/4 in. 16 3/4 in. – – – 16 3/4 in. – – – – – – – – – – – – 16 3/4 in. – – – – – – 16 3/4 in. 16 3/4 in. – – 16 3/4 in. – – – – – 18 3/4 in. 18 3/4 in. 18 3/4 in. 5,000 10,000 15,000 – 18 3/4 in. 18 3/4 in. – – – 18 3/4 in. 18 3/4 in. – – – – 18 3/4 in. – – – 18 3/4 in. – – – – – 18 3/4 in. 18 3/4 in. – – – – 18 3/4 in. 18 3/4 in. 18 3/4 in. – – – 18 3/4 in. 18 3/4 in. 21 1/4 in. 21 1/4 in. 21 1/4 in. 21 1/4 in. 2,000 3,000 5,000 10,000 21 1/4 in. 20 3/4 in. 21 1/4 in. 21 1/4 in. – – – – – 21 1/4 in. – – – – – – – – 21 1/4 in. – – – – – 21 1/4 in. – – – 21 1/4 in. 20 3/4 in. 21 1/4 in. – 21 1/4 in. 20 3/4 in. – – – – – 21 1/4 in. 21 1/4 in. – 21 1/4 in. – 21 1/4 in. 20 3/4 in. 21 1/4 in. 21 1/4 in. 26 3/4 in. 26 3/4 in. 2,000 3,000 – 26 3/4 in. – – – – – – – – – – – – – – – – – – – – – – 29 1/2 in. 500 – – – – – – 29 1/2 in. – – – – – 30 1,000 – – – – – – 30 in. – – – – – Working Pressure 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. BP WELL CONTROL MANUAL 6-22 Figure 6.11 Availability and Bore of Blowout Preventers by Major Manufacturers March 1995 Blowout Preventer Nominal Size BP WELL CONTROL MANUAL The test pressure rating of BOP equipment is a one off test, conducted on the BOP (or valve) body at the time of manufacture to a pressure 50% greater than the working pressure. In service, working pressure ratings should not be exceeded. It is acceptable to use annular preventers rated at 5000 psi less than the rams for certain 10M and 15M applications. 4 Stack Configurations Company policy regarding minimum stack configurations for all categories of land and offshore operations is detailed in the Drilling Policy and Guidelines Manual. Figures 6.12 to 6.15 show examples of acceptable stacks for various applications. The particular details of each well will however dictate the most suitable stack for each application. (a) 5M Surface BOP Stack (Figure 6.12) The following points should be considered regarding this stack: • Two ram preventers and one annular preventer in line with Company policy. • Facility for stripping pipe through annular preventer. • No facility for ram combination stripping is available on this stack. • If surface pressures exceed the pressure rating of the annular preventer, the pipe rams are closed and the blind rams changed to pipe. The upper pipe rams are closed, the lower pipe opened and the kick circulated out through the choke line. • Annular access below the lowermost ram possible through wellhead outlet. • Lowermost ram not used for stripping operations and only used when no other ram available for this purpose (i.e. when changing ram elements and in the event of failure of rams above). • If casing rams are required they should be positioned in the top ram preventer cavity. The rams should be changed out on the trip out of the hole prior to running casing, before pulling the BHA through the stack. The bonnet seals are tested against the test plug and the annular prior to running casing. (b) 10M/15M Surface BOP Stack (Figure 6.13) The following points should be considered regarding this stack: • Three ram preventers and one annular preventer in line with Company policy. • Pipe can be stripped through annular preventer and between annular and upper pipe␣ram. • Ram preventer combination stripping is possible if blind rams are replaced with pipe rams, if suitable space is available between top two ram type preventers. • A line must be rigged up to the flange between the top two ram preventers to facilitate ram combination stripping. • Annular access below the lowermost ram is possible through wellhead outlet. 6-23 March 1995 BP WELL CONTROL MANUAL • Well can be circulated either under the annular preventer or under the upper pipe rams. • Lowermost rams not used for stripping operations and only used when no other ram available for this purpose. • If casing rams are required they should be positioned in the upper pipe ram preventer cavity. The rams should be changed out on the trip out of the hole prior to running casing, before pulling the BHA through the stack. The bonnet seals are tested against the test plug and the annular prior to running casing. (c) Four Inlet/Outlet 10M/15M Subsea BOP Stack (Figure 6.14) The following points should be considered regarding this stack: • Four ram preventers, two annular preventers in line with Company policy for minimum requirements for high pressure subsea BOP stacks. • Four inlet/outlets provided in order to maximise flexibility of the stack. • For normal kill procedure drillstring is hung off on pipe ram no. 2 and well circulated through upper choke line. • There should be adequate space between the blind shear and pipe ram no. 2 to shear on pipe body when the pipe is hung off on pipe ram no. 2. (This may not be possible if the top two ram type preventers are a double.) It is important to have the facility to shear the pipe quickly and reliably during a well control operation, especially so on a dynamically positioned vessel. • The lower kill line is used as the kill line monitor (See Standard Techniques, Chapter␣6, Volume 1). • In the event of failure of pipe ram no. 2, or the upper choke line upstream of the failsafes, the well can be shut-in on and hung off on pipe ram no. 3 and returns taken up the lower kill line. • In the event of failure of the choke line downstream of the failsafes, the well can be circulated through the kill line. • The fact that there is an inlet/outlet, that can be used as a choke line, immediately below pipe ram no. 2 and 3, means that the possibility of trapped gas, after a well control operation, is minimised. • Variable bore rams can be fitted in the ram preventers below the blind/shear rams. The hang off capability of these rams should be checked against maximum anticipated string weights. • BOP gas can be removed from this stack using the technique described in Chapter␣6 of Volume 1, taking returns up the lower kill line as the riser is U-tubed. • The upper (primary) annular preventer can be recovered with lower riser package for element replacement. • Lowermost ram only used when no other ram available is for this purpose. The concept for use of this ram is similar to that of the master valve on a production tree. • The lower choke line is used primarily for pressure testing and monitoring the well. In line with Company policy it should not be used for extended periods of circulation. (If this line fails during the displacement of a kick there is no back-up available.) 6-24 March 1995 BP WELL CONTROL MANUAL Figure 6.12 5M Surface BOP Stack FLOWLINE FILL UP LINE 8 ANNULAR BOP BLIND RAMS 5 KILL LINE CHOKE LINE CHOKE MANIFOLD 4 3 7 6 PIPE RAMS SECTION A 1 CASING SPOOL 1 2 1. Flanged gate valves – 2in minimum ID – same working pressure as 'A' section. The outside valve is the working valve during drilling operation. This valve is removed and reused after completion. 2. Tee with tapped bullplug, needle valve, and pressure gauge. 3. Flanged gate valve – 2in minimum ID – same working pressure as BOP stack. 4. As 3. or flanged spring-loaded type check valve – 2in minimum ID – same working pressure as BOP stack. 5. Drilling spool – two flanged side outlets – 3in choke and 2in kill line minimum IDs. 6. Flanged hydraulically controlled gate valve – 3in minimum ID – same working pressure as BOP stack. 7. Flanged gate valve – 3in minimum ID – same working pressure as BOP stack. Top of annular preventer must be equipped with API flange ring gasket. All flange studs must be in place or 8. holes filled in with screw type plugs. NOTES: • Unless specified otherwise in the Bid Letter and/or Contract, the contractor will furnish and maintain all components shown except the 'A' section and items 1 and 2, which will be furnished by the Company. • The choke line between the drilling spool and choke manifold should not contain any bend or turn in the pipe body. Any bend or turn required should be made with a running tee with a blind flange or welded bullplug. All connections should be flanged or welded. All fabrications requiring welding must be done by a certified welder. Welds should be stress relieved. WEOX02.175 6-25 March 1995 BP WELL CONTROL MANUAL Figure 6.13 10M/15M Surface BOP Stack 9 FLOWLINE FILL UP LINE 8 ANNULAR BOP BLIND RAM OUTLET FLANGE (USED ONLY FOR RAM COMBINATION STRIPPING) UPPER PIPE RAM 5 KILL LINE 4 DRILLING SPOOL 4 CHOKE LINE 7 6 CHOKE MANIFOLD LOWER PIPE RAM 3 3 1 1 SECTION B 2 SECTION A 2 1. Flanged gate valves – 2in minimum ID – same working pressure as 'A' section. The outside valve is the working valve during drilling operation. This valve is removed and reused after completion. 2. Tee with tapped bullplug, needle valve, and pressure gauge. 3. Flanged gate valve – 2in minimum ID – same working pressure as 'B' section. 4. Flanged gate valve – 2in minimum ID – same working pressure as BOP stack. 5. Drilling spool – two flanged side outlets – 3in choke and 2in kill line minimum IDs. 6. Flanged hydraulically controlled gate valve – 3in minimum ID – same working pressure as BOP stack. 7. Flanged gate valve – 3in minimum ID – same working pressure as BOP stack. 8. Top of annular preventer must be equipped with API flange ring gasket. All flange studs must be in place or holes filled in with screw type plugs. 9. The ID of the bell nipple must be less than the minimum ID of the BOP stack. NOTES: • Unless specified otherwise in the Bid Letter and/or Contract, the contractor will furnish and maintain all components shown except the 'A' and 'B' sections and items 1 and 2, which will be furnished by the Company. • The choke line between the drilling spool and choke manifold should not contain any bend or turn in the pipe body. Any bend or turn required should be made with a running tee with a blind flange or welded bullplug. All connections should be flanged or welded. All fabrications requiring welding must be done by a certified welder. Welds should be stress relieved. WEOX02.176 6-26 March 1995 BP WELL CONTROL MANUAL Figure 6.14 Four Inlet/Outlet 10/15M Subsea BOP Stack KILL LINE CHOKE LINE UPPER ANNULAR BOP RISER CONNECTOR LOWER ANNULAR BOP BLIND/SHEAR RAMS PIPE RAM No 2 PIPE RAM No 3 PIPE RAM No 4 WELLHEAD CONNECTOR WEOX02.177 6-27 March 1995 BP WELL CONTROL MANUAL Figure 6.15 Three Inlet/Outlet 10/15M Subsea BOP Stack KILL LINE CHOKE LINE UPPER ANNULAR BOP RISER CONNECTOR LOWER ANNULAR BOP BLIND/SHEAR RAMS PIPE RAM No 2 PIPE RAM No 3 PIPE RAM No 4 WELLHEAD CONNECTOR WEOX02.178 6-28 March 1995 BP WELL CONTROL MANUAL • Annular and ram combination stripping is possible with this stack. Ram combination stripping is however considered impractical from a floating rig. The lowermost ram is not used for stripping operations. Disadvantages: • Reliance is placed on the annular preventers when running casing. • Unless variable or suitable sized pipe rams are installed initially, the stack must be pulled and redressed before using tapered strings. Annular preventers are not to be considered an adequate substitute for pipe rams when using tapered strings. • The requirement to have the facility to hang off on pipe ram no. 2 and shear on the pipe body generally means that it is not possible to use a double preventer for these two rams. • If it is not possible to shear on the pipe body when the drillstring is hung off on pipe ram no. 2, the drillstring should be hung off on pipe ram during well control operations. This is undesirable and reduces the flexibility of the stack. (d) Three Inlet/Outlet 10M/15M Subsea Stack It is recommended that 4 inlets/outlets are provided for high pressure subsea stacks in order to provide a high level of flexibility/redundancy within the stack. However it is recognised that many subsea stacks incorporate only 3 inlets/outlets, and that the cost of conversion to a 4 inlet/outlet configuration may be prohibitive, especially for short term contracts. Figure 6.15 shows an acceptable configuration of a 3 inlet/outlet high pressure subsea stack. The majority of the comments relating to the 4 inlet/outlet stack are applicable in this case with the obvious exception that there is no line entering the stack below the lowermost ram. No inlet/outlet is provided below the lowermost ram because it is considered that the benefit of such a line is insignificant compared to the reduction in the flexibility of the stack that this would entail. 5 Choke and Kill Lines The variations in contractor furnished equipment and the requirements of individual areas are such that specification of a standard layout is not feasible. However, it is essential that equipment specifications should suit a particular well, satisfy Company policy and local legislation. In particular, the choke and kill lines should never be rated to a lower working pressure than the stack. It is recommended that ultrasonic testing equipment is held on each rig in order that the wall thickness of pipework, including choke and kill lines, can be regularly checked. (a) Surface BOP Stacks The location of kill and choke outlets on a BOP stack will be influenced primarily by the number of rams used and their sizes. 6-29 March 1995 BP WELL CONTROL MANUAL • Choke and Kill Outlets To comply with Company policy, the choke line must have a minimum ID of 3 in., the kill line may be as small as 2 in. (but this might restrict operational flexibility should it be required to substitute for a washed out choke line). During normal operations, the inner (manual) choke and kill line valves should be open and the outer (HCR) valves closed. • Remote Kill Line On a land rig, a remote kill line can be tied in to the kill line so that it may be used whichever preventer is closed. The remote kill line should be rated at the pressure rating of the BOP stack and should terminate at a similarly rated flanged valve, at least 100 ft from the well. The purpose of this line is to enable a pump truck to be tied into the well in an emergency situation. • Wellhead Outlets It is recommended that wellhead spool outlets are not used for a choke and kill line tie-ins. Each wellhead spool should have dual valve isolation on one side and valve removal plugs (VRP) should be installed on the non-active side. • Check Valves Traditionally, a check valve has been installed outboard of the stack valves on the kill line. Now many rigs, particularly jack-ups, have the facility to use the kill line to augment, or replace, the choke line. In such a hook-up, check valves are omitted. Company policy is that check valves are not mandatory on the kill line. Choke and kill lines are generally fabricated in line with the following specifications: • All connections should be flanged, clamped or welded. Screwed fittings, unions and chicksans should not be used on the choke lines, although minimal use is acceptable on kill lines. • All welding should be carried out under shop conditions with machine cut weld preparations. All welding should be conducted by certified welders to approved weld procedures and all welds should be suitably non destructively tested and pressure tested prior to use. • Lines, particularly the primary choke line should be installed with the minimum number of bends. Where bends are required, targeted tees, or block tees should be used. Swept bends are undesirable. • Choke lines should be well braced, to withstand severe vibration. Supports should be fitted as required, but these should not be welded to the choke line. (b) Subsea BOP Stacks Subsea choke and kill lines differ from surface systems in that: • Subsea choke and kill lines require flexible connections at the ball/flex joint, and at the telescopic joint. • All subsea choke and kill line valves are fail safe and hydraulically actuated. • Subsea choke and kill lines are much longer. Depending on water depth, line size and mud properties, pressure losses in the lines might be significant. 6-30 March 1995 BP WELL CONTROL MANUAL Choke and kill lines are tied into BOP outlets, not to drilling spools or the wellhead. Generally BOP stacks for exploration wells should have 4 ram, and 2 annular preventers. This provides some flexibility in case a ram or element fails during a well killing operation. On some rigs, a hydraulically actuated cement dump valve is provided on the kill line. This valve may be used to dump cement returns, thereby avoiding long circulation times up the riser in deep water. It can also be used to flood the riser if it becomes evacuated and in danger of collapsing. However, the dump valve should be treated with caution. Misuse, or inadvertent opening, could cause considerable loss of hydrostatic head in the well. Often dump valves are considered to be unnecessary and are omitted on most rigs. The following points should be noted regarding the major choke and kill line components: • All valves should be failsafe. Two valves are required per outlet. Valves should be installed␣ as close to the BOP outlets as possible, and preferably in line with the outlets. Side-arms and valves should be well protected by the framework around the stack. • Targeted tees should be used for all 90 degree bends. • Choke and kill connections at the lower riser disconnect should be rigidly supported by the framework, so that they will not part when full working pressure is applied simultaneously to both lines. • The choke and kill line across the ball/flex joint should be flexible and not restrict movement of the joint up to its maximum designed deflection. • Riser couplings and the LMRP stab plates should be designed to withstand induced loadings when full working pressure is applied simultaneously to both lines. • The choke and kill lines across the telescopic joint should be able to accommodate the maximum designed travel of the joint. • All surface connections should be flanged, clamped or welded. Screwed fittings, chicksans and unions should not be used. • Lines should be installed with the minimum number of bends. Where bends are required, targeted tees or block tees should be used. Swept bends are not desirable. • Choke lines should be anchored to withstand vibration. Supports should be fitted as required, but these should not be welded to the choke line. • Both the choke and kill line should be tied into the choke manifold to allow one to replace or augment the other. (c) Hydraulically Operated Valves A remotely operated valve is installed on the choke line adjacent to the BOP stack to rapidly shut off hazardous flow in the event of downstream equipment failure. Another advantage for remote operation is that this valve is usually located at an elevated working level in the substructure which makes hand operation difficult and unsafe. Specifically designed hydraulically controlled gate valves (HCV) are extensively utilised for this service. The valve must be rated WOGM which means that it is serviceable for water, oil, gas or mud flow. The hydraulic actuator must be designed for 3000 psi maximum working pressure; however, the actuator should fully open the valve with 1500 psi control pressure for maximum design conditions. The 3000 and 1500 psi design 6-31 March 1995 BP WELL CONTROL MANUAL pressures are required for compatible operations with standard BOP closing units. The choke line valve must be operable from both the main and remote closing units. As an optional feature, hydraulically operated valves are available with stem and handle for manual operation (to close but not open) in case of hydraulic system failure. Although numerous companies manufacture HCVs, Cameron Iron Works and NL Shaffer supply the majority of remotely operated choke line valves since they are initally ordered as a component of the BOP stack. On most rigs, the hand operated gate valves used for the choke manifold and kill line are usually the same type as the HCV. Cameron introduced the HCR (High Closing Ratio) as the first remotely controlled valve for choke line service. This valve has the same basic design and operational features as a Cameron QRC preventer. The HCR valve has been used so extensively throughout the industry that most oil field personnel refer to any make of remotely controlled valve as the HCR. Because the HCR is limited to 5000 psi working pressure, the advent of 10,000 psi and higher working pressure BOP required additional valve development. Currently, Cameron’s type F hydraulically operated gate valve is probable the most widely used and is available with rated working pressures from 3000 psi to 15,000 psi. NL Shaffer’s choke line valve is the type DB which is rated for 5000, 10,000 and 15,000 psi working pressures. Other reputable valve manufacturers’ equipment may be acceptable for choke line service; however, prior well control reliability and experience should be verified. (d) Subsea Failsafe Valves These valves are made by a number of companies including Cameron, NL Shaffer, WKM, Rockwell and Vetco. Generally, these are gate valves closed with a spring operated, sometimes pressure assisted, closing mechanism. Two of the more important parameters used in evaluating these valves for floating drilling operations are their susceptibility to forming hydraulic blocks when used in tandem and the water depth sensitivity of their operators. The latter is important because when used subsea, hydrostatic head alone may be sufficient to hold the valves open (in the absence of closing pressure) if a means is not available to balance the hydrostatic forces acting on the operator and stem. • NL Shaffer Valve The operating characteristics of the NL Shaffer Model CB, bi-directional sealing valve is governed by the selection of either a short or long sea chest. The Model CB valve with the short sea chest and a pressure-balancing tail rod will failsafe closed at rated working pressure regardless of water depth; however, a pressure-assist hydraulic line is required for normal closure. When equipped with a long sea chest, the valve requires a single hydraulic line for opening, and closure is obtained by spring action plus limited line pressure-assist. Line pressure assists the spring closing action because the pressure balancing tail rod is 1/4 in. smaller in diameter than the stem. The pressure-assist feature limits the long sea chest valve to a maximum 2400m water depth for failsafe spring closure. • Rockwell Valve The Rockwell (McEvoy) valve has unique features of a split gate, long slip fit seats to minimise wear in the valve body, and a sealant that is injected to complete the seal. The seal is always on the downtream side of the gate. 6-32 March 1995 BP WELL CONTROL MANUAL Prior to a modification made in June, 1972, the valve was marginally failsafe in 440m of water; but now a modified version, Model EDU, is available that is independent of water depth. • WKM Valve (Model M with D-2-C Operator) This valve will fail safe closed in 570m water depth. It has no balancing stem; therefore, the body volume decreases when the valve opens. WKM claims that the body cavity is so large compared with this change that pressure locking is no problem. The problem of body lock is solved in the same way as fluid lock when the valves are in tandem. Basically, flow paths within the body allow redistribution of the small volume change resulting from valve stem movement. • Cameron Valves Cameron has three subsea valve designs: 1) the Type A valve has a solid gate for uni-directional sealing, 2) The Type AF valve has bi-directional sealing capability with a ported outlet in the lower body cavity to prevent liquid locking, and 3) the type DF valve is bi-directional with a balancing stem ported to the sea and a vertical fluid passageway on the outer surface of the gate to prevent pressure locking. Cameron rates the Type A and the AF valves for service in water depths to 300m. The Type DF valve is rated by Cameron for service to a water depth of 1800m. All valves were originally designed with a dog attached to the gate to rotate the seats a fraction of a turn when the valve was opened, which reportedly would provide uniform seat wear. Cameron now recommends removal of the dog since its action can induce stresses which may cause the seat to fracture if settled baryte and/or drilled solids prevent seat rotation. • Vetco Type VS Valve The Vetco Type VS subsea gate valve is a full-bore, through-conduit gate valve. A metal-to-metal seat is provided between the moving sealing member (gate) and the stationary seats. Since the valve lacks a balancing stem, the manufacturer limits the valve to water depths of 900m to ensure failsafe closure. (e) BOP Stack Connections There are three types of connections available for blowout preventer units: flanged, studded or clamped. Bolted flanges or studs are the most common type of connection used. The tensile rating of the bolts used in these connections must be sufficient to withstand the maximum load which may be imposed. The torque applied to the nuts and bolts must meet API recommended values to maintain the pressure seal. 6-33 March 1995 RATING OF BOP STACK APPROVED FLANGES 5000 psi wp Installations API Type 6B with Type R Flat Bottom Groove or API Type 6BX w/Type BX Groove 10,000 psi wp Installations API Type 6BX with Type BX Groove MAXIMUM BOLT ** STRENGTH MINIMUM NUT STRENGTH API Type RX ASTM Grade B-7 ASTM Grade 2-H API Type RX or API Type BX w Type 6BX Flange ASTM Grade B-7 ASME Grade 2-H API Type BX ASTM Grade B-7 ASTM Grade 2-H * Acceptable material for flange ring gaskets as per API Spec 6A, ‘Wellhead Equipment’. Sweet Oil – Low Carbon Steel Sour Oil or Gas – Type 316 stainless steel preferred but Type 304 stainless steel acceptable except for high risk H2S wells. ** In some H2S applications, ASTM A-193 Gr B M a maximum Rockwell hardness of 22 may be acceptable. If used, flanges should be derated per Table 1.4B of API 6A. BP WELL CONTROL MANUAL API Type 6B with Type R Flat Bottom Groove 6-34 2000 psi wp and 3000 psi wp Installations APPROVED * RING GASKETS Figure 6.16 Specifications for BOP Flanges, Ring Gaskets, Flange Bolts and Nuts March 1995 All blowout preventers, drilling spools, adapter flanges will be furnished with the specific API ring joint flange equipment listed below: BP WELL CONTROL MANUAL Figure 6.17 Hydril Drilling Spool Data B A WEOX02.180 BORE CONNECTIONS SIDE OUTLETS WEIGHT (lb) (approx) (A) HEIGHT (in.) (B) SPOOL CENTRE LINE TO FLANGE OR HUB FACE (in.) 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. 9 in. 9 in. 9 in. 9 in. 11 in. 11 in. 11 in. 11 in. 11 in. 11 in. 11 in. 11 in. 11 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. 20 3/4 in. 20 3/4 in. 20 3/4 in. 20 3/4 in. 21 1/4 in. 21 1/4 in. 21 1/4 in. 21 1/4 in. 21 1/4 in. *29 1/2 in. *29 1/2 in. *30 in. *30 in. 7 1/16 in. 3,000 Flange 7 1/16 in. 3,000 Flange 7 1/16 in. 5,000 Flange 7 1/16 in. 5,000 Flange 7 1/16 in. 5,000 Flange 7 1/16 in. 10,000 Flange 7 1/16 in. 10,000 Flange 7 1/16 in. 15,000 Flange 9 in. 3,000 Flange 9 in. 3,000 Flange 9 in. 5,000 Flange 9 in. 5,000 Flange 11 in. 3,000 Flange 11 in. 3,000 Flange 11 in. 5,000 Flange 11 in. 5,000 Flange 11 in. 10,000 Flange 11 in. 10,000 Flange 11 in. 10,000 Hub 11 in. 10,000 Hub 11 in. 15,000 Flange 13 5/8 in. 3,000 Flange 13 5/8 in. 3,000 Flange 13 5/8 in. 5,000 Flange 13 5/8 in. 5,000 Flange 13 5/8 in. 5,000 Hub 13 5/8 in. 5,000 Hub 13 5/8 in. 10,000 Flange 13 5/8 in. 10,000 Flange 13 5/8 in. 10,000 Hub 13 5/8 in. 10,000 Hub 20 3/4 in. 3,000 Flange 20 3/4 in. 3,000 Flange 20 3/4 in. 3,000 Flange 20 3/4 in. 3,000 Hub 21 1/4 in. 2,000 Flange 21 1/4 in. 2,000 Flange 21 1/4 in. 2,000 Flange 21 1/4 in. 2,000 Hub 21 1/4 in. 2,000 Hub 29 1/2 in. 500 Flange 29 1/2 in. 500 Flange 30 in. 1,000 Flange 30 in. 1,000 Flange 3 1/16 in. 3,000 Flange 3 1/16 in. 5,000 Flange 3 1/16 in. 5,000 Flange 3 1/16 in. 5,000 Flange 4 1/16 in. 5,000 Flange 3 1/16 in. 10,000 Flange 4 1/16 in. 10,000 Flange 4 1/16 in. 15,000 Flange 3 1/16 in. 3,000 Flange 3 1/16 in. 5,000 Flange 2 1/16 in. 5,000 Flange 3 1/16 in. 5,000 Flange 3 1/16 in. 3,000 Flange 3 1/16 in. 5,000 Flange 3 1/16 in. 5,000 Flange 4 1/16 in. 5,000 Flange 3 1/16 in. 10,000 Flange 4 1/16 in. 10,000 Flange 3 1/16 in. 10,000 Hub 4 1/16 in. 10,000 Hub 4 1/16 in. 15,000 Flange 3 1/16 in. 3,000 Flange 3 1/16 in. 5,000 Flange 3 1/16 in. 5,000 Flange 4 1/16 in. 5,000 Flange 3 1/16 in. 5,000 Hub 4 1/16 in. 5,000 Hub 3 1/16 in. 10,000 Flange 4 1/16 in. 10,000 Flange 3 1/16 in. 10,000 Hub 4 1/16 in. 10,000 Hub 3 1/16 in. 3,000 Flange 3 1/16 in. 5,000 Flange 4 1/16 in. 5,000 Flange 3 1/16 in. 3,000 Hub 7 1/16 in. 2,000 Flange 3 1/16 in. 5,000 Flange 4 1/16 in. 5,000 Flange 3 1/16 in. 5,000 Hub 4 1/16 in. 5,000 Hub 7 1/16 in. 500 Flange 12 in. 500 Flange 7 1/16 in. 5,000 Flange 12 in. 1,000 Flange 510 525 510 500 525 1025 1075 1400 700 725 710 725 950 975 1065 1290 2190 2215 1285 1310 1710 1055 1080 1755 1780 1050 1075 3325 3355 1925 1950 2590 2615 2540 2565 1850 1800 1850 1850 1825 2380 2320 2500 2450 16.50 16.50 16.50 19.75 19.75 21.12 21.12 22.38 18.12 18.12 18.12 18.12 18.62 18.62 23.38 22.38 25.12 25.12 25.12 25.12 29.75 19.38 19.38 22.38 22.38 22.38 22.38 27.75 27.75 27.75 27.75 27.12 27.12 27.12 27.12 23.38 23.38 23.38 23.38 23.38 31.75 31.75 40.00 40.00 13.25 13.25 13.50 13.50 13.50 15.18 15.18 16.44 15.00 15.00 15.25 15.25 16.50 16.50 17.25 17.25 18.62 18.62 18.62 18.62 22.50 17.25 17.25 19.00 19.00 19.00 19.00 20.88 20.88 20.88 20.88 22.52 22.52 22.52 22.52 21.75 21.75 21.75 21.75 21.75 25.25 25.00 27.52 27.52 6-35 March 1995 BP WELL CONTROL MANUAL API high-pressure connections are pressure sealed by means of ring-joint gaskets made of soft iron, low-carbon steel or stainless steel. API Type RX and Type BX ring-joint gaskets are pressure-energised seals but are not interchangeable. Rings that have been coated with Teflon, rubber or other resilient materials are not acceptable. All flanges in the stack and side-outlets should be fitted with new ring-joint gaskets each time they are assembled. It is important that the ring groove in the flange be clean and dry prior to flanging up. API Standard 6A, ‘Wellhead Equipment’, provides specifications for flanged wellhead fittings. API Type 6B flanges are available in the following pressure ratings: 2000 psi to 5000 psi range. API Type 6BX flanges are available for the 5000 psi to 30,000 psi range. Figure 6.16 lists specifications for BOP flanges, ring gaskets and bolts. Bolts must always be the right size – not larger and not smaller than required for the specific bolt holes. Hub and clamp connectors are principally used on subsea BOP stacks to reduce the weight and height. The bolts are designed for easier make-up, especially in cramped quarters, because the wrench movement is downward instead of horizontal. When clamp connectors were first used there were numerous problems with the clamp loosening during drilling operations and creating a hazard in well control situations. This problem has been greatly reduced by the manufacturer furnishing recommended bolt torque make-up values and the avialability of power torque wrenches on the rigs. Cameron Iron Works clamp connections are installed on most major manufacturers’ hub and clamp preventers. When a clamp connected BOP stack is used, recommended torque requirements should be obtained from the manufacturer and all bolts should be made up to the required torque with power wrenches. (f) Drilling Spools Drilling spools are recommended for choke and kill line outlets on all BOP stack␣arrangements (subsea BOP stacks and low pressure surface stacks are excluded). The spool provides space between ram preventers to facilitate stripping operations and localises possible erosion during well control operations in the less expensive spool rather than the preventer body. Drilling spools should be designed and fabricated in␣accordance with API 6A, ‘Specifications for Wellhead Equipment’. Most wellhead manufacturers can fabricate drilling spools to any dimensions required although lead time is usually several weeks. Figure 6.17 shows dimensional data for Hydril’s drilling␣spools. 6 Choke and Standpipe Manifolds (a) Choke Manifold A typical choke manifold layout is shown in Figure 6.18. It features inlets for the primary choke line, the kill or secondary choke line and from the kill pump; two remotely adjustable chokes, two manually adjustable chokes, a straight choke bypass, a buffer chamber and outlets to the pits, direct or via the poorboy degasser. Valves upstream of the chokes should be rated to the working pressure of the BOPs, lower rated valves are acceptable downstream. Each choke can be isolated by two valves on the high pressure side. The system offers complete redundancy, (except of the buffer tank) since flow can be directed via an alternative route whilst a section is repaired. 6-36 March 1995 BP WELL CONTROL MANUAL A bypass line to the poorboy degasser is provided in order to be able to deal with returns in the event of failure of the buffer tank. It is recognised that the majority of choke manifolds installed on drilling rigs comprise a buffer tank into which all the lines downstream of the chokes are tied. Field personnel should be aware that this design compromise seriously reduces the flexibility/redundancy of the manifold. If the buffer tank cuts out, the manifold is in effect rendered useless. Consideration should therefore be given to installing split buffer tanks and separate flare lines or, as previously mentioned, a bypass line upstream of the buffer tank. All connections should be flanged, welded, or clamped. Field welding is not acceptable. Company policy specifies that choke manifolds should incorporate at least two variable chokes on offshore rigs, one of which must be remotely adjustable. On some manifolds, mandatory in some areas, an additional outlet from the buffer chamber is provided, so that hydrocarbons can be directed via a production separator to a flare. An inlet to facilitate the tying-in of a specialised choke manifold during formation testing is also provided. On wells where there is a possibility of encountering hydrogen sulphide, all equipment and material should be suitable for sour service. The control panel for the chokes should be near the Driller’s station, and should have read-outs for standpipe manifold pressure, choke manifold pressure and pump stroke counters. A pressure gauge reading standpipe pressure should be located at the choke manifold if manual chokes are used during a well kill operation. The MAASP function, where fitted, should not be used. A recording chart for standby pressure and choke manifold pressure, may also be considered. This chart can be used when testing BOPs, or when handling kicks. Under normal drilling conditions, valves on the choke line and manifold should be left open up to the valve immediately upstream of the remotely operated choke that will be used in the event of a kick. The valves downstream should be open to the poorboy degasser and mud tanks. The remote adjustable choke(s) should be left closed. The outer choke (HCR or failsafe) valve on the BOP stack should be closed during drilling. It must be possible to record choke pressure when the well is shut-in with the choke manifold lined up in this manner. (b) Standpipe Manifold A typical arrangement of standpipe manifold showing connections to the choke manifold is illustrated in Figure 6.19. This manifold, for example, permits one mud pump to be lined up on the annulus, (through kill line perhaps via the choke manifold) and the second to kelly, or circulating head, to facilitate control of severe lost circulation. For 10,000 and 15,000 psi BOP systems, it is acceptable to use 5000 psi standpipe manifolds, but the isolation valve should be the same pressure rating as the BOP stack, as should connecting pipework. 6-37 March 1995 BP WELL CONTROL MANUAL Figure 6.18 Choke Manifold, 10M/15M BYPASS TO POORBOY DEGASSER OR TRIP TANK TO POORBOY DEGASSER TO MUD PITS 2 4 2 3 PRIMARY CHOKE LINE BOP STACK KILL OR SECONDARY CHOKE LINE 1 1 1 1 2 CHOKE BYPASS LINE 1 2 1 3 RESERVE PIT (DERRICK FLARE OFFSHORE RIGS) BUFFER CHAMBER FROM KILL PUMP TO GAUGE 2 4 MANUAL CHOKE LINE 1. 2. 3. 4. 10000psi gate valves. 5000psi gate valves. Remote controlled chokes. Manually adjusted chokes. FROM DST CHOKE MANIFOLD DST LINE 2 BURNING LINE (PRODUCTION GAS SEPARATOR OFFSHORE RIGS) WEOX02.181 6-38 March 1995 BP WELL CONTROL MANUAL SECONDARY STANDPIPE PRIMARY STANDPIPE ISOLATION VALVE SAME RATING AS CHOKE MANIFOLD TO REMOTE PRESSURE GAUGE 1 1 2 2 1 1 AUXILIARY TIE-IN POINT TO HOLE/FILL LINE OR TRIP TANK 1 TO CHOKE MANIFOLD OR PRESSURE GAUGE MUD PUMP 1. 5000psi gate valves. 2. Gate valve to suit pressure rating of standpipe manifold. MUD PUMP WEOX02.182 Figure 6.19 Standpipe Manifold 7 Diverters If a kick is taken when conductor is set in incompetent formation, the well will not be shut-in, but instead, will be diverted. A surface diverter system, consisting of an annular preventer and vent lines, allows the flow to be directed to a safe area, away from the rig and personnel. Vent lines should be as large (12 in. minimum on offshore rigs) and as straight as practical, so as to minimise back pressure, erosion and the risk of plugging by well debris. The lines should be sufficiently braced to absorb severe shock loadings; sections likely to suffer erosion e.g. bends, should be reinforced. There should be no restriction to the bore, any valves in the lines should be full opening ball valves. Periodically, the lines should be flushed through to ensure that they remain unobstructed. To prevent the well being inadvertently shut in, any valves in the vent line should be designed to automatically open when the diverter is closed. An acceptable alternative is to elevate the vent line above the flowline, so that no valves are necessary. If the BOP stack is installed, the control panels should be clearly marked that the well is not to be closed in, but that the diverter is to be actuated. 6-39 March 1995 BP WELL CONTROL MANUAL Figure 6.20 Subsea Diverter Stack 21in HST RISER COUPLING PIN MUD BOOST LINE CONNECTION 211/4in – 2000 MSP ANNU-FLEX FLEX JOINT ANNULAR BOP 21in HYDRAULIC CONNECTOR 211/4in – 2000 SHEAR RAM OUTLET NOZZLE(S) 211/4in – 2000 FSS SPOOL BLIND FLANGE C/K VALVE 30in LATCH WEOX02.183 6-40 March 1995 BP WELL CONTROL MANUAL The working pressures of the diverter and vent lines is not of prime importance (particularly on floating rigs where the slip joint packing may be the limiting factor); 500 psi is a typical rating. Company policy states that subsea wells should be drilled riserless until a pressure containment string is set. This is to avoid allowing shallow gas flow to the rig. If however it becomes necessary to drill for surface casing with a riser, Company policy states that the well will be diverted subsea in the event of a shallow gas flow. The most likely stack up that will be used to divert subsea will comprise the following: • Pin connector with subsea dump valves (minimum ID 10 in.). • LMRP with annular preventer. This will be a relatively inexpensive stack that will in most cases be made up mainly from existing rig equipment. In the event of a shallow gas flow the dump valves will be opened and the annular closed to divert subsea. In order to move the rig the LMRP can be disconnected and the well allowed to flow at the seabed. Various stacks have been custom made for diverting subsea in areas of high incidence of shallow gas. An example is shown in Figure 6.20; the diverter stack comprising: • Flex joint • Annular preventer • Hydraulic connector • Blind/shear ram • Spool piece with two outlets with dump valves • Choke/kill line • Hydraulic connector In the event of a shallow gas flow, the dump valves will be opened and the annular closed. In order to move the rig off location the blind/shear rams can be closed and the connector released. 6-41/42 6-41 March 1995 BP WELL CONTROL MANUAL 6.3 CONTROL SYSTEMS Paragraph Page 1 General 6-44 2 Power Source 6-44 3 Control Manifolds 6-46 4 Accumulators 6-47 Illustrations 6.21 Subsea Stack Function Schematic 6-45 6.22 Annular Preventers – fluid required to operate 6-48 6.23 Ram Preventers – fluid required to operate 6-50 6.24 Compressibility Factor – Nitrogen 6-51 6-43 March 1995 BP WELL CONTROL MANUAL 1 General The Control System provides the means to individually close and open each BOP and valve, conveniently, rapidly, repeatedly and at the correct operating pressure. The equipment should be designed to operate when, in emergencies, primary rig power may not be available. The essential elements of a control system are: • Power Source(s) • Control Manifolds • Accumulators • Connecting Pipework/Hose Bundle and Wiring Detailed specifications for a particular application will be governed by the number, size and pressure rating of BOPs. Water depth considerations will also influence the design of subsea BOP control systems. An example arrangement for subsea BOP systems is shown in Figure 6.21. 2 Power Source (a) Primary Power Source The primary power source should be an electrically driven pump (or pumps) located at the main control manifold. For 3000 psi accumulator systems, the pump(s) should incorporate a pressure switch set to cut in and out at 2800 psi and 3000 psi respectively. Diesel driven pumps may be substituted for land rig applications. The electric pump output should be twice that of the secondary air pumps. The combined electric and air pumps should be sufficient to charge the accumulator system from pre-charge to operating pressure in less than 15 minutes, also to close an annular preventer (without accumulator assistance) in less than 2 minutes. (b) Secondary Power Source The secondary power source should be an air power pump system, located at the main control manifold. For 3000 psi accumulator systems, the pump(s) should incorporate a pressure switch set to cut in and out at 2750 psi and 3000 psi respectively. A standby diesel driven air compressor piped to the pumps should be provided at a location away from the primary rig power source, and where possible, 150 ft from the well axis. (c) Battery Packs Where electric panels are used, and for electro-hydraulic systems, a battery pack is required. This should be located, where possible, 150 ft from the well axis. 6-44 March 1995 BP WELL CONTROL MANUAL DRILLER’S PANEL DRILLER’S PANEL MINI PANEL OPEN BLOCK CLOSE RIG POWER 120V ac ACCUMULATORS DRILLER’S PANEL MINI PANEL OPEN BLOCK CLOSE ACCUMULATORS RIG POWER 120V ac RESERVOIR MINI PANEL OPEN BLOCK CLOSE RIG POWER 120V ac ACCUMULATORS RESERVOIR RESERVOIR SOLENOIDS RIG AIR COMPRESSOR 3000psi PUMP RIG AIR COMPRESSOR 3000psi PUMP KR KR YOUR RIG RIG AIR COMPRESSOR 3000psi PUMP POD SELECTOR AIR VALVE YOUR RIG KR YOUR RIG PILOT REGULATOR POD MOUNTED REGULATOR POD SELECTOR SPM VALVE KR KR KR REDUNDANT POD REDUNDANT POD REDUNDANT POD MALE POD CONNECTOR FEMALE POD CONNECTORS POD LATCH SHUTTLE VALVE RAM PREVENTER CLOSING LINE BOP RAM PREVENTER OPENING LINE WELLHEAD RAMS CLOSED BLOCK POSITION (RAMS CLOSED, NO PRESSURE) 3000psi Accumulator Fluid Pressure 125psi Rig Air Pressure Vent/or No Pressure RAMS OPENED Regulated KR Fluid Pressure WEOX02.184 Figure 6.21 Subsea Stack Function Schematic 6-45 March 1995 BP WELL CONTROL MANUAL (d) Manual Closing of BOPs For surface BOP installations, extension arms and wheels should be provided for ram type BOPs. 3 Control Manifolds The BOP control systems should ideally be equipped with 3 control manifolds or panels. (a) Central (Main Control) Manifold This manifold should be located away from the rig floor area and in an accessible location. It may be all hydraulic, air-hydraulic or electro-hydraulic. The accumulators and charge pumps are usually located with this manifold. Required features include: • A regulator to reduce accumulator pressure to manifold (operating) pressure for the ram preventers and valves. • A regulator to reduce accumulator pressure to the variable operating pressure for annular preventers. • Control handles, or switches, for all functions. An additional function is required on subsea stacks to transfer command between hose bundles or pods. A hinged cover should be placed over critical functions (shear/blind rams, wellhead disconnect). A locking device should not be used. • Pressure gauges for accumulator, manifold and annular pressures. • A valve to bypass the manifold regulator. • Tie-in points for accumulators, charge pumps, remote panels, and air lines. • A vent line for bleeding off accumulator fluid to the storage tank. • A relief valve for the hydraulic and electric pumps. • A flowmeter to indicate the volume of fluid used in operating a function (essential on subsea stacks, desirable on surface stacks). (b) Driller’s Control Panel The panel should be located on the rig floor within easy access of the Driller’s station. It should be air or electric operated. Explosion-proofing is required for electric panels. Required features include: • Controls for each BOP stack function and to adjust the manifold regulators. • Read-outs for the accumulator pressure, regulated manifold and annular pressures and flowmeter. • Air supply pressure read-out. • A schematic of the BOP arrangement showing kill and choke line outlets, and having ram sizes marked. 6-46 March 1995 BP WELL CONTROL MANUAL • Covers, or interlocks, for critical functions, eg shear rams, wellhead disconnect. • Visual and/or audible warning devices for low accumulator pressure, air pressure, or fluid levels. • Where applicable, controls for diverter functions. (c) Remote Manifold (or Panel) This panel should be located a safe distance from the well axis. For offshore rigs, it is normally located in the Toolpusher’s office. It should be air or electric operated. Required features include: • Controls for each BOP stack function. • A schematic of the BOP arrangement showing kill and choke line outlets and having ram sizes marked. • Covers, or interlocks, for critical functions. • Visual and/or audible warning devices for low accumulator pressure, air pressure or fluid levels. 4 Accumulators The hydraulic fluid required to operate the BOP functions is stored in accumulators, pressurised against a nitrogen inflated bladder. The accumulators should be located near the main control manifold location. The purpose of the accumulators is to provide a store of hydraulic energy and a high rate supply of hydraulic fluid to the BOP functions. The response time of the BOP functions is therefore independent of the output of the pumps. For subsea installations, at least two accumulators should be isolated from the main bank to provide pilot line pressure. Also, to ensure acceptable response times, additional accumulators should be mounted on the BOP stack. Accumulator bottles should be used as surge dampeners on annular preventers for stripping operations on both surface and subsea BOP stacks. (a) Accumulator/Precharge Operating pressure of accumulators is generally 3000 psi. The optimum bladder inflation, or precharge pressure, is governed by the minimum acceptable pressure remaining in the accumulators after operation of the preventers. About 1200 psi is required to hold some annular preventers closed. A precharge of 1000 psi will retain a small liquid reserve in the accumulator when pressure in the system falls to 1200 psi. (b) Sizing of Accumulators Company policy for surface stacks specifies that the total accumulator volume should be 1 1/2 times that required to close one pipe ram and one annular preventer and open one hydraulically activated choke and still retain accumulator pressure equal to 200 psi above pre-charge pressure, without pump assistance. 6-47 March 1995 BP WELL CONTROL MANUAL The following is an example of the technique that can be used to size accumulators for a surface stack (comprising one Hydril GL 18 3/4 in. 5M annular and 3 Hydril 18 3/4 in. 10M ram preventers): Volume to close: 1 Annular 1 Ram 1 HCR valve = 44 gal = 17.1 gal = 0.6 gal (See Figures 6.22 and 6.23) Total fluid required = 61.7 gal X 1.5 = 92.55 gal Precharge to 1000 psi, maximum operating pressure = 3000 psi, minimum operating pressure = 1200 psi ANNULAR PREVENTERS GALLONS OF FLUID REQUIRED TO OPERATE AN OPEN HOLE NL Shaffer Hydril Size and Working Pressure GL GK Inches psi Close Open 6 6 7 1/16 8 8 10 10 11 11 12 13 5/8 13 5/8 13 5/8 16 16 16 3/4 16 3/4 16 3/4 18 18 3/4 20 20 20 21 1/4 30 30 3,000 5,000 10,000 3,000 5,000 3,000 5,000 5,000 10,000 3,000 3,000 5,000 10,000 2,000 3,000 3,000 5,000 10,000 2,000 5,000 2,000 3,000 5,000 5,000 1,000 2,000 2.9 3.9 9.4 4.4 6.8 7.5 9.8 Close Open Close Open 2.2 3.3 4.6 4.6 3.2 3.2 3.0 5.8 5.6 8.0 7.2 11.1 11.0 18.7 5.0 8.7 6.8 14.6 25.1 11.4 9.8 23.5 14.7 18.0 34.5 17.5 21.0 14.2 24.3 12.6 14.8 19.8 19.8 8.2 23.6 47.2 17.4 37.6 28.7 19.9 33.8 33.8 17.3 33.0 25.6 21.1 14.4 44.0 44.0 20.0 48.2 32.6 37.6 17.0 58.0 58.0 29.5 61.4 47.8 Figure 6.22 Annular Preventer – fluid required to operate 6-48 March 1995 Spherical Balancing March 1995 psi 4 1/16 6 6 7 1/16 7 1/16 8 8 10 10 10 11 11 11 12 13 5/8 13 5/8 13 5/8 13 5/8 13 5/8 13 5/8 13 5/8 16 16 3/4 16 3/4 16 3/4 16 3/4 18 18 3/4 20 20 20 20 21 1/4 21 1/4 21 1/4 21 1/4 21 1/4 21 1/4 26 3/4 26 3/4 10,000 3,000 5,000 10,000 15,000 3,000 5,000 3,000 5,000 5,000 10,000 10,000 15,000 3,000 3,000 3,000 5,000 5,000 10,000 10,000 15,000 2,000 3,000 5,000 5,000 10,000 2,000 10,000 2,000 2,000 3,000 3,000 2,000 2,000 7,000 7,500 10,000 10,000 2,000 3,000 QRC U Close Open Close Open 1.22 1.22 1.22 1.22 1.17 1.17 1.17 1.17 0.81 0.81 0.95 0.95 3.31 3.31 4.23 3.31 4.23 5.54 5.54 3.16 3.16 4.03(S) 3.16 4.03(S) 5.42 5.20 5.54 6.78 5.54 6.78 11.70 5.42 6.36(S) 5.42 6.36(S) 11.29 10.16 10.16 12.03 12.03 9.45 9.45 11.19(S) 11.19 2.36 2.36 2.77 2.77 4.42 6.00 6.00 24.88 8.11 23.00 7.61 8.11 9.35 8.11 9.35 20.41 23.19 26.54 30.15 10.50 10.50 7.61 8.77(S) 7.61 8.77(S) 17.78 20.20(S) 21.14 27.42(S) 9.84 9.84 Cylinder Size LWS 2.70 2.70 3.18 3.18 5.10 Close Open Inches 0.59 0.52 1.19 6.35 6.35 2.58 2.58 1.74 2.98 0.99 5.89 5.89 2.27 2.27 1.45 2.62 6 6.5 6.5 14 14 8.5 8.5 8.5 8.5 8.23 7.00 5.50 4.50 7.05 Hydril SL Close E Open Manual (a) Close Open 2.75 2.75 2.3 2.3 2.75 2.75 3.25 3.25 Close Open 1.9 3.7 1.8 3.4 5.2 5.2 5.4 11.5 5.4 11.5 11.8 11.8 4.9 11.2(S) 4.9 11.2(S) 11.8 11.8(S) Auto (a) Close Open 12.0 5.9 12.0 12.9 12.9 5.9 4.9 11.2(S) 4.9 11.2(S) 11.8 11.8(S) 2.3 2.3 2.7 2.7 10 14 14 8.5 10 9.45 9.40 7.00 8.10 5.44 4.46 10 14 14 5.44 11.00 9.45 4.46 10.52 7.00 14 8.5 11.56 10.52 10 14 14 6.07 11.76 14.47 4.97 10.67 12.50 15.6 14.1 14.55 13.21 17.1 15.6 3.55 2.9 3.55 2.9 3.65 3.0 7.05 5.07 7.80 5.07 16.88 4.46 6.68 4.46 15.35 14 8.5 10 8.5 14 14.42 16.05 12.65 13.86(P) 14 14 BP WELL CONTROL MANUAL 6-49 Inches NL Shaffer Cameron Size and Working Pressure Figure 6.23 Ram Preventers – fluid required to operate RAM PREVENTERS GALLONS OF FLUID REQUIRED TO OPERATE ONE SET BP WELL CONTROL MANUAL Therefore: P1 = 1000 + 15 = 1015 psi P2 = 1200 + 15 = 1215 psi P3 = 3000 + 15 = 3015 psi Z1 = 1.00 Z3 = 1.06 Z3 = 1.06 T = 80°F V1 = 10 gal (11 gal bottle minus 1 gal bladder replacement) (See Figure 6.24) where: P1 P2 P3 V1 V2 V3 Z = = = = = = = precharge pressure (psi) minimum operating pressure (psi) maximum operating pressure (psi) bladder internal volume at precharge pressure (gal) bladder internal volume at P2 (gal) bladder internal volume at P3 (gal) compressibility factor for nitrogen Using the gas law: P X V = constant TXZ So in this case: 1015 X 10 1.00 = 1215 X V2 1.02 = 3015 X V3 1.06 V2 = 8.52 gal V3 = 3.57 gal The useable volume per bottle is given by: V2 – V3 = 8.52 – 3.57 = 4.95 gal/bottle Therefore there is a requirement for: 92.55 4.95 = 19 bottles (c) Subsea Accumulators Accumulators can be mounted on subsea BOP stacks to perform three separate functions: • Response Improvement With increasing water depths, the speed with which subsea preventers may be operated decreases. This is caused by expansion of the fluid supply hoses and pressure losses in the lines. (Note that response time will be a function of the hose length and not water depth). Response times can be improved by mounting accumulators directly on the BOP stack. Space and weight constraints will limit the number of accumulators which can be stack-mounted. 6-50 March 1995 BP WELL CONTROL MANUAL 2.2 0°F AFTER SAGE 6 LACY API PROJECT No 37 2.1 2.0 100°F COMPRESSIBILITY FACTOR 1.9 200°F 1.8 300°F 1.7 400°F 500°F 1.6 600°F 700°F 800°F 1.5 1.4 1.3 1.2 1.1 1.0 0.9 2000 4000 6000 8000 10000 12000 14000 PRESSURE POUNDS PER SQUARE INCH ABSOLUTE 16000 18000 WEOX02.187 Figure 6.24 Compressibility Factor – Nitrogen • Emergency Use All floating rigs are generally equipped with an acoustic back-up control system. For dynamically positioned rigs and rigs to be used in hazardous (e.g. ice flow) areas this is essential equipment. In such installations, stack-mounted accumulators should be at least capable of closing one set of rams, one annular preventer and releasing the riser disconnect upon receipt of a command from the acoustic system. The accumulators should be manifolded at the stack, so that fluid is not lost should the supply lines from the rig be severed. The acoustic system and accumulator system should be tailored to the stack configuration. For subsea stacks, a tie in should be provided for diver or ROV assistance. This will ideally be for shear ram activation and will also include LMRP disconnect and wellhead connector disconnect. 6-51 March 1995 BP WELL CONTROL MANUAL • Surge Dampening Surge vessels should be provided for subsea annular preventers to facilitate stripping, according to manufacturers’ recommendations. Some preventers require surge vessels on the opening as well as closing sides. Nominal 10 gal capacity accumulators should be used. (d) Sizing of Subsea Accumulators Company policy for the sizing of the accumulators for a subsea stack is more rigorous than for a surface stack. The accumulator capacity should be 1.5 times the volume required to open and close all the well control functions and still retain accumulator pressure at 200 psi above initial pre-charge pressure. The majority of the accumulators will be located at surface, however a small quantity maybe located on the stack in order to speed the response of the system. The total volume of accumulators required will be determined by Company policy (or local legislation, if more rigorous). The total volume will be provided by the sum of the fluid available at surface and subsea, at the stack. The surface located accumulators are sized as previously described however a different technique is used for subsea accumulators. The basic difference between designing for surface operation and for subsea operation is that the precharge pressure must be altered to take account of the hydrostatic pressure of the fluid in the supply lines. The useable volume from each subsea accumulator bottle will be lower than the equivalent surface bottle. The deeper the water, the greater will be the reduction in useable volume from the accumulators. The following is a technique that can be used to size accumulator bottles for subsea operation for 500 m water depth (for 18 3/4 in. 10M stack): Volume to close: 1 Annular = 1 Ram = 4 Failsafes = 44 gal 17.1 gal 2.4 gal (See Figures 6.22 and 6.23) Total fluid required = 63.5 gal Precharge to 1000 psi plus the hydrostatic of the control fluid. Therefore: P1 P2 P3 where: = = = = 1000 1747 1200 3000 + 15 + (500 X 1.03 X 1.421) psi Z1 = 1.01 + 15 + 732 = 1947 psi Z2 = 1.00 + 15 + 732 = 3747 psi Z3 = 1.09 P1 = precharge pressure (psi) P2 = minimum operating pressure (psi) P3 = maximum operating pressure (psi) V1 = bladder internal volume at P1 (gal) V2 = bladder internal volume at P2 (gal) V3 = bladder internal volume at P3 (gal) Z = compressibility factor for nitrogen 6-52 March 1995 T1 = 80°F T2 = 40°F T3 = 40°F BP WELL CONTROL MANUAL Using the gas law: PXV TXZ = constant (T in °R) So in this case: 1747 X 10 1.01 X 540 = 1947 X V2 1.02 X 500 = 3747 X V3 1.06 X 500 V2 = 8.23 gal V3 = 4.66 gal The useable volume per bottle is given by: V2 – V3 = 8.23 – 4.66 = 3.57 gal/bottle Therefore there is a requirement for: 63.5 3.57 = 18 bottles (e) Pipework/Hose Bundles and Wiring For surface stacks, the simplest hook-up is to assign a dedicated high capacity conduit to each individual function. When a particular function is selected, fluid flows from the acccumulators, through a regulator, directly to the function. Concurrently, the opposite function is vented and the displaced fluid is returned to the reservoir. When considering a surface hook-up, the following should be noted: • Company policy (after API RP53) recommends that the system ensures ram and small annular preventers (less than 20 in.) close within 30 seconds and larger annular preventers within 45 seconds. • Control lines should be seamless steel tubing of 1 in. minimum nominal size and of␣a pressure rating at least equal to the working pressure of the control system (usually 3000 psi). • Unions and swivels should be used in the BOP stack area to preclude stressing of the␣lines. • BOP closing and opening lines should be routed so as to minimise the risk of damage in the event of a fire or falling debris. Flammable hoses should not be used on surface installations. A simple hook-up is impractical for subsea applications – too many individual lines to be handled easily and the pressure drop through the length of line would be too great for acceptable reaction times. Instead, hose bundles are employed, which contain one high capacity (1 in.) conduit (to transfer the hydraulic fluid required to operate all functions and recharge the subsea accumulators) and up to 64 pilot (3/16 in.) lines (to direct and control the flow of fluid to a particular function). The bulk line is “teed” with the subsea accumulators and terminates at a regulator which reduces the accumulator pressure to operating pressure. The output of the regulator is manifolded to the pilot valves. The pilot lines terminate in function dedicated pilot (SPM) valves which respond to accumulator pressure when a function is selected. Each then allows regulated fluid to flow, via a shuttle valve, to a particular function. The displaced fluid from the opposite function is vented at its pilot valve. 6-53 March 1995 BP WELL CONTROL MANUAL The pilot valves and regulators are housed in a wireline retrievable pod, which is duplicated to provide complete redundancy. A shuttle valve located at each function allows control by either pod. When considering a subsea system, the following should be noted: • Company policy (after API RP53) recommends that the systems ensure ram preventers close within 45 seconds and annular preventers within 60 seconds of surface actuation. Electro-hydraulic systems will be required where water depths preclude satisfactory closing times with all hydraulic systems. • Systems should be duplicated in all hydraulic and electric lines from the main control panel to the BOP stack functions, i.e. there should be 100% redundancy. The Driller’s panel and the remote panel should be designed to select and operate either system. • Dynamically positioned vessels and rigs operating in hazardous areas should have an acoustic back-up system to secure the well and release the riser. • Any unused functions (such as when the low pressure stack in a two stack system is run) should be blanked off to ensure that fluid is not vented by inadvertent operation of that function. (f) Operating Fluids For subsea systems where the fluid from the main supply line is dumped when it is vented, the fluid should be potable water, with the recommended percentage of soluble oil added to prevent corrosion. Control line fluid is in a closed system and hence is not replaced. It is therefore important to flush out the control lines with the recommended fluid mix when the pods are pulled, prior to rerun. In all cases, the fluid mix should be maintained year round such that the fluid will not freeze at the minimum anticipated temperature for the year. Pure ethylene glycol should be added to prevent freezing when necessary – under no circumstances should sea water be used. The reservoir should be self filling, with an automatic mixing system for additives. Operating fluids must be non-pollutant and bacteria resistant. Most surface installations employ a simple closed system, with the operating fluid returned to the reservoir when it is vented. Either a light hydraulic oil or a subsea type fluid is suitable. The accumulator fluid reservoir should have a capacity of twice the working liquid volume of the accumulators. 6-54 March 1995 BP WELL CONTROL MANUAL 6.4 ASSOCIATED EQUIPMENT Paragraph Page 1 Mud Control and Monitoring Equipment 6-56 2 Mud Gas Separator 6-57 3 Drillstring Valves 6-60 4 Rotating Heads 6-62 Illustrations 6.25 Typical Trip Tank Hook-up – on a floating rig 6-57 6.26 An example Mud Gas Separator 6-59 6.27 Grant Rotating Head 6-63 6-55 March 1995 BP WELL CONTROL MANUAL 1 Mud Control and Monitoring Equipment Proper installation and operation of this equipment is fundamental to effective primary and secondary well control. The following are the most important aspects: (a) Pit Volume Measurement A pit volume measurement device (PVT) should be provided. A calibrated read-out and audio alarm should be installed at the Driller’s station. The following measurement devices are required for all tanks: • A float for the PVT system. It should be possible to isolate other floats when the trip tank is in use. • An internal calibrated ladder-type scale. • A remote ladder-type scale, visible from the Driller’s station for the trip tank. A small wireline can be used to connect a float in the tank to the scale on the rig floor. (b) Flowline Measurement A device should be provided for measurement of flowline mud return rate. This (Flo Show) device should have a read-out and alarm at the Driller’s station. (c) Trip Tank Trip tanks are used to fill the hole on trips, measure mud or water into the annulus when circulation has been lost, monitor the hole when tripping, logging or other similar type operations. The industry uses two basic types of trip tanks – gravity feed and pump. The pump type system is recommended because it provides for safer and more expedient trip operation. The trip tank would be isolated from the surface mud system to prevent inadvertant loss or gain of mud from the trip tank due to valves being left open. In the past, most blowouts occurred due to swabbing or not keeping the hole filled while tripping the drillstring out of the hole. To provide more exact fluid measurements for pipe displacement, trip tanks were developed to accurately measure within ± 1.0 barrel the influx or efflux of fluid from the wellbore. As the drillstring is pulled from the hole, the mud level will drop due to the volume of metal being removed. If mud is not added to the hole as pipe is pulled, it is possible to reduce hydrostatic pressure to less than formation pressure. When this happens, a kick will occur. Swabbing can occur when pipe is pulled too fast, and friction between the pipe and the mud column causes a reduction in hydrostatic pressure to a value less than formation pressure. To prevent loss of hydrostatic pressure it is necessary to fill the hole on a regular schedule, or continuously, using a trip tank and to keep track of the fluid volume required. The metal volume of the pipe being pulled can be calculated, but mud additions necessary to replace hole seepage losses due to filtration effects can only be predicted by comparison to the mud volumes required to keep the hole properly filled on previous trips. For this reason, it is imperative that a record of mud volume required versus number of stands pulled be maintained on the rig in a trip book for every trip made. 6-56 March 1995 BP WELL CONTROL MANUAL TRIP TANK LEVEL INDICATOR REMOTE CONTROL VALVE RIG FLOOR OVERBOARD ROTARY TABLE DIVERTER RETURNS TO SHAKERS HOLE FILL UP LINE FLOWLINE TELESCOPIC JOINT FROM MISSION PUMPS RISER CHECK VALVE DRAIN TRIP TANK PUMP WEOX02.188 Figure 6.25 Typical Trip Tank Hook-up – on a floating rig As illustrated in Figure 6.25, a centrifugal pump takes suction from the trip tank and fills the hole through a line into the bell nipple. The pump runs constantly while the drillstring is pulled from the hole. The hole stays full as each stand of pipe is pulled and excess mud returns to the trip tank through an outlet on the main flow line. A valve must be installed in the flow line downstream of this outlet to block all flow to the shale shakers while making a trip. This closed circulation system can be monitored by a float system and a digital readout in 1-barrel increments on the Driller’s console. 2 Mud Gas Separator The separator is installed downstream of the choke manifold to separate gas from the drilling fluid. This provides a means for safely venting the gas and returning usable liquid mud to the active system. 6-57 March 1995 BP WELL CONTROL MANUAL Basically, there are two types of mud gas separators: Atmospheric and Pressurised. The atmospheric type separator is standard equipment on virtually all rigs and is referred to in the field as a ‘gas buster’ or ‘poorboy’ separator. The main advantage of this type of separator is its operational simplicity which does not require control valves on either the gas or mud discharge lines. A pressurised mud gas separator is designed to operate with moderate back pressure, generally 50 psi or less. Pressurised separators are utilised to overcome line pressure losses when an excessive length of vent line is required to safely flare and burn the hazardous gas an extended distance from the rig. The pressurised separator is considered special rig equipment and is not usually provided by the contractor. This type of separator is installed on rigs drilling in high risk H2S areas and for drilling underbalanced in areas where high pressure, low volume gas continually feeds into the circulating fluid. During well control operations, the main purpose of a mud gas separator is to vent the gas and save the drilling fluid. This is important not only for economic reasons, but also to minimise the risk of circulating out a gas kick without having to shut down to mix additional mud volume. In some situations the amount of mud lost can be critical when surface volume is marginal and on-site mud supplies are limited. When a gas kick is properly shut in and circulated out, the mud gas separator should be capable of salvaging most of the mud. There are a number of design features which affect the volume of gas and fluid that the separator can safely handle. For production operations, gas oil separators can be sized and internally designed to efficiently separate gas from the fluid. This is possible because the fluid and gas characteristics are known and design flow rates can be readily established. It is apparent that ‘gas busters’ for drilling rigs cannot be designed on the same basis since the properties of circulated fluids from gas kicks are unpredictable and a wide range of mixing conditions occur downhole. In addition, mud rheological properties vary widely and have a strong effect on gas environment. For both practical and cost reasons, rig mud gas separators are not designed for maximum possible gas release rates which might be needed; however, they should handle most kicks when recommended shut-in procedures and well control practices are followed. When gas flow rates exceed the separator capacity, the flow must be bypassed around the separator directly to the flare line. This will prevent the hazardous situation of blowing the liquid from the bottom of the separator and discharging gas into the mud system. Figure 6.26 illustrates the basic design features for atmospheric mud gas separators. Since most drilling contractors have their own separator design, the Drilling Foreman must analyse and compare the contractor’s equipment with the recommended design to ensure the essential requirements are met. The atmospheric type separator operates on the gravity or hydrostatic pressure principle. The essential design features are: • Height and diameter of separator. • Internal baffle arrangement to assist in additional gas breakout. • Diameter and length of gas outlet. • A target plate to minimise erosion where inlet mud gas mixture contacts the internal wall of the separator, which provides a method of inspecting plate wear. • A U-tube arrangement properly sized to maintain a fluid seal in the separator. 6-58 March 1995 BP WELL CONTROL MANUAL GAS OUTLET 8in ID MINIMUM GAS BACK PRESSURE REGISTERED AT THIS GAUGE (Typically 0 to 20psi) STEEL TARGET PLATE INLET APPROX 1/2 OF HEIGHT INSPECTION COVER SECTION A-A TANGENTIAL INLET 30in OD A A 4in ID INLET-TANGENTIAL TO SHELL FROM CHOKE MANIFOLD BRACE 10ft MINIMUM HEIGHT INSPECTION COVER HALF CIRCLE BAFFLES ARRANGED IN A 'SPIRAL' CONFIGURATION TO SHAKER HEADER TANK MAXIMUM HEAD AVAILABLE DEVELOPED BY THIS HEIGHT OF FLUID eg: 10ft HEAD AT 1.5 SG GIVES 6.5psi MAXIMUM CAPACITY 10ft APPROX 8in NOMINAL 'U' TUBE 4in CLEAN-OUT PLUG Figure 6.26 2in DRAIN OR FLUSH LINE WEOX02.189 An example Mud Gas Separator The height and diameter of an atmospheric separator are critical dimensions which affect the volume of gas and fluid the separator can efficiently handle. As the mud and gas mixture enters the separator, the operating pressure is atmospheric plus pressure due to friction in the gas vent line. The vertical distance from the inlet to the static fluid level allows time for additional gas breakout and provides an allowance for the fluid to rise somewhat during operation to overcome friction loss in the mud outlet lines. As shown on Figure 6.26, the gas-fluid inlet should be located approximately at the midpoint of the vertical height. This provides the top half for a gas chamber and the bottom half for gas separation and fluid retention. The 30 in. diameter and 16 ft minimum vessel height requirements have proven adequate to handle the majority of gas kicks. The separator inlet should have at least the same ID as the largest line from the choke manifold, which is usually 4 in. Some separators use tangential inlet, which creates a small centrifugal effect on the gas-fluid mixture and causes faster gas breakout. 6-59 March 1995 BP WELL CONTROL MANUAL The baffle system causes the mud to flow in thin sheets which assists the separation process. There are numerous arrangements and shapes of baffles used. It is important that each plate be securely welded to the body of the separator with angle braces. A 6 in. minimum ID gas outlet is recommended to allow a large volume of low pressure gas to be released from the separator with minimum restriction. Care should be taken to ensure minimum back pressure in the vent line. On most offshore rigs, the vent line is extended straight up and supported to a derrick leg. The ideal line would be restricted to 30 ft in length and the top of the line should be bent outward about 30 degrees to direct gas flow away from the rig floor. If it is intended that the gas be flared, flame arresters should be installed at the discharge end of the vent line. As previously mentioned, when the gas pressures in the separator exceeds the hydrostatic head of the mud in the U-tube, the fluid seal in the bottom is lost and gas starts flowing into the mud system. The mud outlet downstream of the U-tube should be designed to maintain a minimum vessel fluid level of approximately 3 1/2 ft in a 16ft high separator. Assuming a 1.44 SG mud and total U-tube height of 6 ft, the fluid seal would have a hydrostatic pressure equal to 3.7 psi. This points out the importance for providing a large diameter gas vent line with the fewest possible turns to minimise line frictional losses. The mud outlet line must be designed to handle viscous, contaminated mud returns. As shown in Figure 6.26, an 8 in. line is recommended to minimise frictional losses. This line usually discharges into the mud ditch in order that good mud can be directed over the shakers and untreatable mud routed to the waste pit. In recent years, there have been a number of serious accidents caused by the failure of mud gas separators during well control situations. Primarily these have resulted from drilling contractors not updating their separator design and personnel training standards to handle high pressure gas kicks for deeper drilling operations. It is important that drilling personnel understand the limitations of all well control equipment and are trained to take remedial action before pressure or capacity limitations occur. The key initial decision that must be made is the pump rate at which the kick will be circulated out. Large influx, high pressure gas kicks should always be pumped out at low rates (generally 1 bbl/minute or less) to minimise the gas release rate at the surface where rapid gas expansion occurs. Circulating out at a slow rate reduces the risk of exceeding pressure limitations for the well control equipment and provides additional decision reaction time. 3 Drillstring Valves Drillpipe valves are used to close in the well on the drillpipe bore and to protect surface equipment. The valves may be permanently in place, or installed at surface when required and may be of a manual shut-off or automatic check valve type. Drillstring valves should be rated to the same pressure as the BOP and tested at the same frequency. Some of the drillstring valves impose restrictions on future operations when installed. For example, both the inside BOP and drop-in valve, when in place, prevent access below them to the drillstring bore. 6-60 March 1995 BP WELL CONTROL MANUAL The following are the most commonly used drillstring valves: (a) Kelly Valves Kelly valves should be full opening valves to allow running of wireline. Wrenches for operating the valves should be held on the rig floor. Both upper and lower kelly valve should be function tested daily. The upper kelly valve is placed between the swivel and the kelly, the upper kelly valve provides a means of closing in the drillstring when the kelly is down through the rotary table and cannot be lifted. The lower kelly valve, which is placed between the kelly and the drillstring, allows the closing-in of the drillstring and removal of the kelly if required. The kelly valve provides a means of isolating the kelly if the drillpipe pressure approaches the pressure rating of the kelly. (b) Float Valves Float valves are frequently used in top hole to prevent backflow during connections and flow up the drillstring in the event of a kick. Ported floats should be run whilst drilling below surface casing. When installed, a float valve is a permanent part of the drillstring. If a float is run while drilling below surface casing, the valve should be ported. The following points should be considered: • The valve can be flapper or plunger type with facility to lock open whilst running in␣hole. • The valve requires regular inspection to check for damage, due to fluid erosion, whilst downhole. • The valve will prevent U-tubing, that may be required to free differentially stuck pipe. It should not be used whilst drilling highly overbalanced permeable sections without due consideration. • Use of the valve may make reading of drillpipe pressures difficult when a kick has been taken, especially when handling gas migration. • If a ported float is used when drilling from a floating rig, it will be necessary to install a further valve in the string when hanging off in the BOP stack. (c) Drop-in Valves An automatic check valve that is held on surface until required and can then be dropped or pumped downhole to a special landing sub. It is Company policy that a landing sub will be run in all strings. In the event of a kick while the pipe is off bottom, the drop-in valve can be used to allow the pipe to be stripped to bottom. The following points should be considered: • The valve will have limited ID which may plug, preventing further circulation and continuation of control procedures. • When in place, prevents access to the drillstring bore below it, but may be retrieved by wireline with some designs. • The valve is not subject to erosion prior to use, as would be the case with a permanently installed flapper valve, as it can be held on surface until required. 6-61 March 1995 BP WELL CONTROL MANUAL • All the items in the drillstring above the landing sub must have sufficient ID to allow the check valve to pass. This includes kelly cocks, mud savers etc. (d) Drillpipe Safety Valve A safety valve to be installed at surface on detection of a kick, allowing the drillstring to be closed in. The valve should be a fullbore valve, typically a lower kelly valve to allow easy stab-in wireline access if required. Crossovers between the safety valve and all other tubulars in hole must be held on the drillfloor. It is Company policy that such a valve should at all times be available on the rig floor. (e) Inside BOP A surface installed check valve to close off the drillstring bore. Commonly called a Gray valve and in accordance with Company policy, should always be available on the rig floor as a back-up for the drillpipe safety valve, or the drop-in check valve. Prevents access to the drillstring bore below it and cannot be removed if below the rotary, or under pressure (unless a drillpipe safety valve is installed below it). 4 Rotating Heads When used, rotating heads are installed above the BOP stack. They provide a seal on the kelly or drillpipe. A drive unit, attached to the kelly, locates in a bearing assembly above the stripper rubber. Some applications for rotating heads are: • Drilling with air or gas, to divert the returns through a “Blooey line”. • To permit drilling with underbalanced mud, by maintaining a back pressure on the wellbore. • As a diverter for surface hole. • To keep gas away from the rotary table. This is especially important where Hydrogen Sulphide can be expected. Realistic working pressures for rotating heads are 500 to 700 psi. It is recommended that they are not installed for routine gas cap drilling (unless sour gas is expected) since their use precludes observation from the rig floor of annulus fluid level. Figure 6.27 shows a schedule of the Grant Rotating Head. 6-62 March 1995 BP WELL CONTROL MANUAL Figure 6.27 Grant Rotating Head KELLY BUSHING SWING-BOLT CLAMP ASSEMBLY DRIVE BUSHING ASSEMBLY SHOCK PAD DRIVE RING AND BEARING ASSEMBLY BOWL STRIPPER RUBBER OUTLET FLANGE INLET FLANGE WEOX02.190 6-63/64 6-63 March 1995 BP WELL CONTROL MANUAL 6.5 EQUIPMENT TESTING Paragraph Page 1 General 6-66 2 BOP Equipment and Wellheads 6-66 3 An Example Test Procedure 6-67 4 Test Frequency 6-71 5 Pressure Tests of Casing 6-71 Illustrations 6.28 Choke Manifold Schematic 6-68 6.29 An example BOP/Choke Manifold Test Procedure 6-69 6.30 Schematic of BOP Pressure Tests 6-70 6.31 An example BOP Equipment Test Report 6-72 6-65 March 1995 BP WELL CONTROL MANUAL 1 General The consequences of a failure of BOP equipment under operating conditions can be far reaching. Rigorous BOP testing procedures are required in order that problems may be identified under test conditions, and rectified before an emergency arises. Equipment should be tested at the time of installation on the wellhead and at regular intervals thereafter, in accordance with Company standard policies and guidelines (unless contradicted by local policies). Common causes of failure include: • Casing wear. • Plugging of lines with baryte. • Wellhead or BOP connections working loose through vibration. • Deterioration of seals in valves and BOPs. • Leaks and faults occurring in control systems. The recommended procedures in this section cover BOP stack installations at surface and␣subsea. 2 BOP Equipment and Wellheads Preferably, pressure testing should be conducted with water against a solid type plug which is supported by the wellhead and seals either above or below the pack-off. All high pressure tests should be preceded by a low pressure test (e.g. 300 psi) and the final test pressure reached in increments. Normally, a wellhead/BOP test pressure that holds stable for 10 minutes is considered satisfactory. The bore of the test string or the casing valve should be open during testing to prevent pressure being applied to the casing or formation, in the event of the test plug leaking. The rate of pressure increase due to volume pumped, should be closely monitored to determine whether the pack-off is leaking, and warn of the possible risk of collapsing the casing. (a) Initial Pressure Test If possible, the initial pressure test of all BOP functions should be conducted on a test stump prior to installation. However, if a stump is not available, the test should be conducted on the wellhead immediately after installation. It should be conducted to the working pressure of the wellhead or ram preventers, or the burst pressure of the strongest casing to be run, whichever is the lowest. Annular preventers should be tested to a maximum of 70% of their working pressure. Where possible, the initial sequence of tests should be arranged so as to minimise the volume of fluid pressurised (e.g. the initial test of the wellhead connector should be against the lowest pipe rams); thereby minimising the damage caused by fluid cutting, in the event of a leak. 6-66 March 1995 BP WELL CONTROL MANUAL After latching a subsea stack, a tensile test should be applied to ensure connectors are properly latched before any pressure testing. A pressure test should be carried out to the pressure rating of the wellhead or connector, on initial installation of the stack; thereafter, the connector will be tested during BOP tests to the pressure that the BOPs will be tested to. Also, the control system should be function tested on both pods. (b) Routine Pressure Tests Routine testing of the BOP (pipe rams and valves) and wellhead pack-offs should be conducted to either the maximum anticipated wellhead pressure, 80% of the casing burst pressure, the wellhead rated pressure or the BOP rated pressure, whichever is lowest. Annular preventers should not be tested to more than 70% of their working pressure. The blind/shear rams are tested on installation and after the 13 3/8 in. and 9 5/8/in. casing have been run. At subsequent BOP tests, the blind/shear rams should be function tested according to Company policy. If the hole is open, the BOPs should be tested with the drillstring at the shoe, suspended from the test plug. Tests should be carried out using, in rotation, the main control panel, Driller’s panel and remote panel. (c) Pressure Testing of Associated Equipment The upper and lower kelly cocks, choke and standpipe manifolds, drillpipe safety valve, inside BOP and circulating head should all be tested to the lower of the maximum anticipated wellhead pressure or their rated working pressure. A test sub is required for testing the string tools from below. Accumulator pre-charge pressures should be checked according to the manufacturer’s recommendations. To test whether the accumulator and charge pumps are working correctly, the procedures as outlined in Chapter 1, ‘Drills and SCRs’ in Volume 1 should be adopted. 3 An Example Test Procedure The following is an example test procedure for a four ram preventer subsea stack and associated choke manifold. All the components of the choke manifold, in this example, are rated to the same pressure as the stack, and so all the components of the manifold (buffer tank etc) can be tested at the same time, and to the same pressure, as the stack. The kill pump is used as the test pump and is tied into the manifold at point A and point B as shown in Figure 6.28. Test pressure is applied both at point A and point B at all tests other than 4 and 5, when it is applied at point A only. The inner and outer choke and kill line failsafes can be tested from the outside before the stack test is started as these tests do not require a test plug in the stack. The blind/shear rams are not tested on a routine basis in line with Company policy. This means that the failsafes on the upper kill line can only be tested from the inside to the test pressure of the annular, until the blind/shear rams are tested. 6-67 March 1995 BP WELL CONTROL MANUAL Gauge Transmitter 2in 2202 Weco Female 18 31 32 30 5 19 26 13 8 6 3 1 From Mud Manifold 4 33 From Kill Pump B Gauge Transmitter 27 23 20 14 9 Choke Line 2 28 24 21 15 10 7 From Kill Pump A Auto Choke Manual Choke 29 25 Kill Line Auto Choke Manual Choke 16 11 17 12 2in 1502 Weco Female 35 34 To Production Test Facility 36 22 To Mud Gas Separator To Drain To Diverter Overboard From Cement Pump WEOX02.191 Figure 6.28 Choke Manifold Schematic Figure 6.29 shows the procedure for the test as well as details of each component tested at each stage. Figure 6.30 shows how the stack is lined up for each test. Figure 6.28 shows a schematic of the choke manifold. As previously stated all the components of this manifold, that are shown on the diagram, are rated to the full working pressure of the stack. Many other manifolds incorporate piping and valves downstream of the chokes that are rated at a lower pressure than the stack; in such cases, it is necessary to conduct a separate test of these components. The following operational guidelines should also be considered for these tests: • The test pressures used for each test are determined to be in line with Company policy for pressure testing of well control equipment. • On landing the BOP, only one full working pressure test need be made against one pipe ram. This is to confirm the integrity of the wellhead connector. • All subsea pressure tests will be conducted using openbore test tools. 6-68 March 1995 BP WELL CONTROL MANUAL • All tests will be carried out using a suitable test plug with only the specified drillcollar␣weight below; i.e. test plugs will not be run on top of a bottomhole assembly except when testing the blind/shear rams agains a backed-off test plug, if tested on a separate run. • When pressure testing blind/shear rams against casing consideration should be given to pressure differential that already exists due to any difference in the weight of the mud inside and outside of the casing. • All tests should be recorded on a chart. • When testing blind/shear rams against a backed-off test plug, monitor volumes pumped␣closely . TEST CHOKE MANIFOLD VALVES CLOSED BOP LINE UP FAILSAFES 1 3, 7, 9, 15, 18, 20, 24, 26, 30, 32, 33 2 2, 30 UPPER ANNULAR, UPPER INNER KILL, LOWER INNER KILL 3 2, 30 LOWER ANNULAR, UPPER OUTER KILL, LOWER OUTER KILL 4 3, 5, 12, 17, 19, 22, 30, 34 UPPER PIPE RAMS, UPPER OUTER KILL, UPPER INNER CHOKE, LOWER INNER CHOKE 5 3, 6, 11, 13 UPPER PIPE RAMS, UPPER INNER KILL, UPPER OUTER CHOKE, LOWER OUTER CHOKE 6 2, 13, 14, 19, 20, 23, 27, 31 MIDDLE PIPE RAMS, LOWER OUTER KILL, UPPER OUTER CHOKE 7 3, 7, 12, 17, 19, 22, 33, 35, 36 8 4, 7, 8, 10, 16, 19, 21, 25, 29 9 1, 7, 8, 26, 28 LOWER PIPE RAMS, LOWER INNER KILL, UPPER INNER CHOKE Figure 6.29 An example BOP/Choke Manifold Test Procedure 6-69 March 1995 BP WELL CONTROL MANUAL Figure 6.30 Schematic of BOP Pressure Tests 2 KILL 3 CHOKE KILL 4 CHOKE KILL UPPER ANNULAR LOWER ANNULAR TEST VALVE TEST VALVE TEST VALVE TEST VALVE LOWER ANNULAR TEST VALVE LMRP CONNECTOR LMRP CONNECTOR LMRP CONNECTOR BLIND SHEAR RAM BLIND SHEAR RAM BLIND SHEAR RAM UPPER PIPE UPPER PIPE MIDDLE PIPE MIDDLE PIPE MIDDLE PIPE LOWER PIPE LOWER PIPE LOWER PIPE CONNECTOR CONNECTOR CONNECTOR 5 6 7 KILL CHOKE KILL UPPER ANNULAR TEST VALVE CHOKE UPPER ANNULAR LOWER ANNULAR CHOKE KILL UPPER ANNULAR TEST VALVE TEST VALVE LOWER ANNULAR CHOKE UPPER ANNULAR TEST VALVE TEST VALVE LOWER ANNULAR LMRP CONNECTOR LMRP CONNECTOR LMRP CONNECTOR BLIND SHEAR RAM BLIND SHEAR RAM BLIND SHEAR RAM UPPER PIPE UPPER PIPE MIDDLE PIPE TEST VALVE TEST VALVE MIDDLE PIPE LOWER PIPE LOWER PIPE CONNECTOR CONNECTOR CONNECTOR WEOX02.193 6-70 March 1995 BP WELL CONTROL MANUAL 4 Test Frequency Pressure testing of BOP equipment should be carried out according to Company policy, however in general: • After installation of the wellhead component and BOP stack and prior to drilling out each casing string. • At intervals not exceeding 14 days. • At any time requested by the Company Drilling Representative. Results of pressure tests should be recorded on IADC reports, and on the BOP test form. An example of a typical BOP test form is presented as Figure 6.31. The following additional points should be considered: • Annular and ram (pipe) preventers should be operated on each trip into the hole with the bit at the shoe (perhaps as part of a kick drill). • Blind (but not blind/shear) rams should be operated each time the bit is out of the hole. Choke line pressure should be monitored before re-opening the rams. • Kelly cocks should be operated daily. • Choke and kill valves should be operated daily, and lines pumped through. • Choke manifold line-up should be checked each tour. 5 Pressure Tests of Casing The integrity of casing strings is fundamental to effective well control. Casing design is based on maximum anticipated pressures caused by a limited kick volume. Wear or corrosion of the casing bore will reduce burst and collapse strengths of casing and undermine the basis for the design. The rate of wear depends on the type and duration of operations, and is accelerated by rough hardbanded drillpipe, high rotary speeds, and crooked hole. Pressure testing of casing is required to prove the string’s original integrity and that wear does not subsequently reduce casing strength below an acceptable level. • Initial Test Normally, the casing should be tested to prove the string’s integrity when bumping the top plug, following cementing. Applied test pressure should be the maximum wellhead pressure anticipated before the next casing string is set (i.e. casing design pressure). However, if the additional tensile loading caused by the pressure test risks parting the string, the plug should be bumped with a nominal pressure and the full test pressure applied after the string has gained support from the cement prior to drilling out the shoe track. • Subsequent Tests Where significant casing wear is possible, a ditch magnet should be installed to monitor metal returns. If severe casing wear is suspected, actual wear should be measured by wireline calliper tools and then the casing tested to the minimum acceptable pressure. 6-71 March 1995 BP WELL CONTROL MANUAL Figure 6.31 An example BOP Equipment Test Report 1 BOP STACK PRESSURE TEST Unit Type Size WP Pressure applied Remaining Pressure Test Duration Annular Annular Blind Shear Ram Pipe Ram Pipe Ram Pipe Ram UL Choke Line CL Inner Valve CL Outer Valve UL Kill Line KL Inner Valve KL Outer Valve Remote Kill Line Diverter 2 CASING PRESSURE TEST Casing in hole: Pressure Applied Pressure Remaining Test Duration Mud Weight: 3 4 CHOKE MANIFOLD PRESSURE TEST CHARGE PUMPS Packer Depth: Date Previous Test: Pressure Applied: YES NO All valves tested Manifold good for H2S Valves last serviced: All chokes operated Water left in manifold Setting max. allowable pressure on remote choke: Handles on all valves Water left in K&C lines Standpipe manifold tested K&C lines pumped through Pressure applied Manifold line-up OK after test Eletric pump cut in: Accumulator pressure: Electric pump cut-out: Manifold pressure: Filters checked Air pump cut-in: U Annular pressure: Storage tank level checked Air pump cut-out: L Annular pressure: Mixing unit checked Total accumulator volume: Panel used for BOP test: Low level alarms checked Usable accum. vol. (3000-1200psi): Precharges last checked: Recharge time (1200-3000psi): 5 ACCUMULATOR PERFORMANCE CHECK YES NO Test Duration: YES NO Functions left in correct mode Remote compressor available Accumulators and Pumps UNIT Time to Close Volume Pressure Initial Final Accumulators only Time to Close Volume Pressure Initial Final Annular Annular Blind Shear Ram Pipe Ram Pipe Ram Pipe Ram CL Inner Valve CL Outer Valve KL Inner Valve KL Outer Valve 6 EQUIPMENT CHECK TEST Are the following items on the rig, in good operating condition and pressure tested? YES NO YES NO YES NO Circulating head Kelly saver sub & rubber Trip tank DP Safety Valve Hang-off tool PVT and alarms XOs to DCs for DPSV Gas buster Flo-show and alarms Inside BOP De-gasser Nitrogen for precharge Drop in BOP sub + dart Gas detector Engine H2O spray and s/d 7 FAULTY EQUIPMENT Mention here leaks experienced in testing parts used, faulty or missing equipment and remedial action 8 SIGNATURES Driller: Toolpusher: 6-72 March 1995 Company Drilling Rep:
