Wellhead Systems Introduction to Wellhead Systems SECTION 1 weatherford.com Weatherford Wellhead Systems Training December 5, 2014 Revision Date: Page 2 of 17 11-10- Well: CONTENTS Wellhead Assembly.......................................................................................................................... 3 Wellheads and Associated Equipment............................................................................................. 4 Casing Head.................................................................................................................................... 5 Test Plug.......................................................................................................................................... 6 Wear Bushing aka (bowl protector).................................................................................................. 6 Casing Hangers (slip and seal assembly)......................................................................................... 6 Automatic Seal, Slip-Type Casing Hanger......................................................................................... 7 Non-Automatic Seal, Slip-Type Casing Hanger.................................................................................8 Secondary Seal Assemblies............................................................................................................. 8 Casing Spool.................................................................................................................................... 8 Tubing Head (aka Tubing Spool)....................................................................................................... 9 Tubing Hangers.............................................................................................................................. 10 Hanger Flanges........................................................................................................................... 10 Slip-Type Tubing Hanger.............................................................................................................. 10 Wrap Around Tubing Hangers..................................................................................................... 10 Mandrel Tubing Hanger............................................................................................................... 11 Flanges and Seal Connections....................................................................................................... 12 API Ring Gaskets............................................................................................................................ 13 Type R Ring Gasket..................................................................................................................... 13 Type RX Ring Gasket................................................................................................................... 13 Type BX Ring Gasket................................................................................................................... 13 NON-API Connections.................................................................................................................. 14 Wellhead Systems for Unique Applications....................................................................................15 Weatherford Wellhead Systems Training December 5, 2014 Revision Date: Page 3 of 17 11-10- Well: WELLHEAD ASSEMBLY A wellhead is part of an oil well that terminates at the surface, whether on land or offshore. The primary role of the wellhead is pressure containment and to hold the casings and the production tubing. Every oil or gas well has some type of wellhead. Conventional wellhead assemblies include the casing head, casing hangers, spool sections, tubing head, tubing hanger, valves and fittings. The assembly of valves and fittings that sit on top of the wellhead are also known as the Christmas tree. Wellheads provide for a safe and adequate means for supporting and attaching blowout control equipment during drilling. It also provides sealing between casing strings and a connection for the Christmas tree, which controls the flow of fluids from the well. Lastly, the wellhead provides an additional opening into the well which may be utilized for stimulation treatments, circulating fluids, producing the well and other emergency or miscellaneous uses that might arise during the life of the well. Figure 1.1 shows a typical wellhead and tree assembly. 200 300 0 0 100 0 4000 500 0 0 Figure 1.1 Conventional Wellhead and Christmas Tree Assembly Section D Production Tree Section C Tubing Spool Section B Casing Spool Section A Casing Head with Landing Base Conductor Pipe Surface Casing Intermediate Casing Production Casing Production Tubing Weatherford Wellhead Systems Training December 5, 2014 Revision Date: Page 4 of 17 11-10- Well: WELLHEADS AND ASSOCIATED EQUIPMENT A casing head should be installed on the first string of casing requiring blowout preventers (BOP) for further drilling. The BOP Assembly is no better than: The The The The casing to which it is attached primary cement jobs breakdown strength of the formations at the casing seat wellhead between the casing and the preventers Surface casing is important blowout protection because it is the anchor and base for the blowout preventers. The annular space between the conductor and the surface casing should be filled with cement to center the wellhead beneath the rotary and to stabilize the blowout preventer assembly. The wellhead holds in position the BOP equipment used for well control during drilling operations. It is the vital link between preventer equipment and the casing strings required to drill and produce the well. The wellhead assembly serves several important purposes: To support a large part of the weight of the subsequent casing strings Provide a pressure seal between the outer and inner casing strings Provide an outlet to bleed off pressure that might accumulate between the two strings. Figure 1.2 BOP Stack Made Up to Wellhead Weatherford Wellhead Systems Training December 5, 2014 Revision Date: Page 5 of 17 11-10- Well: CASING HEAD The A-Section, the lowermost wellhead section, may be attached to the casing by either a female thread or a slip-on and weld connection to fit the particular size casing. Threaded connections are simple to install and permit easy removal, but they require that the casing be run and set with the threaded coupling at precisely the desired elevation. Because spacing out the connection at the desired elevation is often a problem, a slip-on and weld connection is usually preferred (Figure 1.3). This requires welding services for installation. Also, routine field welding on grades higher than K-55* is not recommended. When installing the casing head, great care should be taken to assure that the casing head is level and aligned with the rotary table. In turn the derrick should be Figure 1.3 level. This will eliminate contact between the Kelly and Slip On Weld (SOW) Casing Head Installed the BOP/casing head system during subsequent drilling which could cause damage to the seal and support areas. After installation, based on rated pressures of the pipe and flanged fittings, the casing head/casing connection should be hydrostatically tested. The casing head usually provides one or more side openings that provide access to each casing annulus and can be used for bleeding off pressure or for pumping into a well. Continued pumping of mud through these fittings might erode them so badly that they would not hold well pressure when needed. Presence of pressure should be checked periodically. Casing head side outlets may be screwed, studded, clamp hub, or flanged. Casing heads with screwed outlets are acceptable for service up to and including 5,000 psi working pressure, provided that the casing head working pressure rating is the same. Some companies require flanged or studded connections for all 5,000 psi and higher working pressure heads. In sizing casing heads, the top flange must be sized to permit drilling the desired hole size and subsequent running and hanging of casing strings. Usually the flange opening is sized to equal or exceed the casing inside diameter of the casing string on which it is installed. Adapter spools or flanges to connect blowout preventers of different sizes or pressure ratings to the casing head are not desirable, though sometimes they are necessary. Adapters constitute another joint in the assembly that might leak. Also, it is not good practice to use a preventer too large for the casing head. Large preventers are heavy and sometimes cause flanges to leak because of vibration and shaking. Figure 1.4 Casing Head with Base Plate Weatherford Wellhead Systems Training December 5, 2014 Revision Date: 11-10- Well: Page 6 of 17 Most A-Sections are designed for universal use for most types of completions. They can hang the most casing strings without being permanently damaged and in the event of a dry hole can be salvaged and used again after being refurbished. In some locations, a landing base or base plate may be required to help support the wellhead load. In water or marsh locations, the drive pipe must normally support a portion, if not all, of the total tubular load. A landing base, also called base plate is usually required on the first string of casing out of the drive pipe to facilitate this transfer of load. The particular wellhead manufacturer should be consulted for load ratings of various size landing bases. On land locations for deep wells, landing bases may also be desirable or necessary. In these types of applications it may be appropriate to provide a reinforced concrete cellar floor to help support the landing base. TEST PLUG Once the casing head is installed and the BOP stack is attached, all connections must be tested. As shown in Figure 1.5, a test plug is lowered through the BOP stack on a joint of drill pipe and landed in the casing head bowl. This isolates the surface casing from test pressure and allows the top flange of the casing head and all the equipment above it to be tested. The test plug is designed to match the profile of the casing head bowl, land properly on the load shoulder and seal against the bore of the casing head. It is important that the correct size and profile of test plug be used. After a satisfactory test, the test plug is retrieved and drilling commences. WEAR BUSHING AKA Figure 1.5 Running a Test Plug (BOWL PROTECTOR) A wear bushing is used to protect the load shoulder which will support the next casing string. This protector is run and landed through the BOP assembly with a running tool. The running tool is retrieved before drilling starts. In some cases, the test plug serves dual duty: test plug one way, but if turned upside down, it becomes a combo running and retrieving tool for the wear bushing. Lock screws are often desirable to keep the bowl protector from spinning along with the drill pipe. Lock screws can either be ordered as part of the casing head or included in a special adapter flange made up between the casing head and the BOP stack. Figure 1.6 Installing a Wear Bushing The BOP must be tested periodically during the drilling process and each time the bowl protector must be retrieved in order to run a test plug. Weatherford Wellhead Systems Training December 5, 2014 Revision Date: Page 7 of 17 11-10- Well: CASING HANGERS (SLIP AND SEAL ASSEMBLY ) The casing hangers, which are most generally used in standard operations, are the slip-packoff types of which there are two general categories: Weatherford Wellhead Systems Training December 5, 2014 Revision Date: 11-10- Well: Page 8 of 17 1. Those that may be set through preventers but require removal of preventers to establish a seal; 2. Those that may be set and sealed without removing blowout preventers, the automatic type. The type chosen depends upon casing loads and operating conditions. Either of these categories of hangers will permit setting casing at desired depths without the use of pup joints. AUTOMATIC SEAL, SLIP-TYPE CASING HANGER Typical automatic slip style wrap-around casing hangers (Figures 1.7 and 1.8) are hinged and feature a weight-set seal which automatically energizes when the hanger is properly landed. Slip hangers are installed on the casing joint by wrapping around the pipe, latching the hanger together, releasing the internal wedge-shaped slips and lowering through the blowout preventers into the casing head. When the weight of the suspended casing is transferred to the hanger slips and to the casing head, the elastomer seal is compressed and extrudes to seal between the rough casing and the smooth bore of the casing head. Most designs which do not incorporate a method to limit extrusion of the seal or downward movement of the slip Figure 1.9 Non-Automatic Seal, WFT-21P Slip-Type Casing Hanger with manually energized seal segments have a maximum design load which the combination of casing weight and test pressure must not exceed. Figure 1.7 Automatic Seal, WFT-22 Slip-Type Casing Hanger Weatherford Wellhead Systems Training December 5, 2014 Revision Date: 11-10- Well: Page 9 of 17 Another result of excessive casing load can be impingement of the casing by the slips. Often, a controlled suspension technique (dulled teeth on the back of the slips) increases friction between the slips and the hanger body and prevents the slips from moving far enough downward to deform the casing. These hangers (Figure 1.8) are designed for heavy casing loads and are, therefore, recommended for long strings where the automatic sealing feature is also required. Generally, the longer the slips, the greater the safe load carrying capacity. Slip manufacturers have extensive test data on their slip design supporting their recommended safe hanging loads. NON-AUTOMATIC SEAL, SLIP-TYPE CASING HANGER With the non-automatic casing hanger, the wrapped around hanger is lowered through the preventers to suspend the pipe. The pack-off seal must be tightened after removal of preventers. The seal is Figure 1.11 Casing Spool expanded, depending upon the make, by cap screws on top of the packing (Figure 1.9) or by external lock screws. This design of manually sealed slip-type hanger is recommended for shallow or medium depth wells where casing weight is not enough so automatic sealing is not possible. SECONDARY SEAL ASSEMBLIES To increase the pressure rating in the upper portion of the wellhead, it is necessary to provide isolation from the lower pressure section below. This is commonly achieved by a secondary seal assembly known as a pack-off or o-ring secondary seal in the lower portion of the next spool to be added after the casing is landed and cut. With secondary seal in place, any pressure applied to the upper portion of the spool does not affect the bottom flange. Figure 1.10 shows a typical pressureenergized seal assembly. Test ports should be provided to test the secondary seal as well as the flanged connection. These secondary seals can be supplied in various nominal casing sizes in one of two ways: as a separate bushing or integral to the bottom flange of the mating spool. CASING SPOOL 1.10 FigureFigure 1.8 Heavy Pressure-Energized Duty Automatic Seal, WFT-29 Slip-TypeSeal Casing Hanger Secondary with extra slips to suspend heavier casing strings Weatherford Wellhead Systems Training December 5, 2014 Revision Date: 11-10- Well: Page 10 of 17 If a protection string is required to drill deeper, an intermediate casing spool is installed after the casing is hung off and cut. This B-Section, shown in Figure 1.11, usually includes one or more secondary seals as discussed above. External flanged or studded outlets should be used for 5,000 psi working pressure and higher service. Designing a casing spool closely follows the design of the wellhead housing. The top flange must permit drilling the desired hole diameter and hanging the next string of casing or tubing. The top flange may have the next higher pressure rating over the mating flange on the bottom when a secondary seal assembly is used. This casing spool provides the bowl for suspending and sealing the production casing string. Blind flanges and VR (valve removal) plugs should be installed in studded or flanged outlets for all casing heads and spools, which are not equipped with a valve. Nipples with special internal VR threads (often referred to as reinstallation nipples) are sometimes used in screwed outlets. Such devices permit installation of a valve under well pressure conditions. TUBING HEAD (AKA TUBING SPOOL) In a three-string wellhead, the production casing is run, hung and sealed in the B-Section in the same manner as the intermediate string. After removing the BOP assembly, the casing is suspended, cut, and the primary annulus seal is installed and tested. In a two-string wellhead, as illustrated in Figure 1.12, when the protection string is not required and/or a liner is set in lieu of bringing the production casing back to surface, the B-Section will not be required. In this case, after the production casing is landed, the tubing head is installed above the A-Section. In highpressure wellhead assemblies, a crossover pack-off flange may be required. Often, a smaller size and higher working pressure BOP assembly is utilized for completion work. Tubing, like casing, is run through blowout preventers and hung-off in the tubing head. The design of the tubing spool is similar to that for a casing spool. The bottom flange must have the same size and pressure rating as the mating flange. The upper flange may be one pressure rating higher if a secondary seal is used in the lower flange to isolate it. Some customers prefer studded outlets for 5,000 psi and higher working pressures. The top flange size and minimum bore through the spool should be selected to permit running full casing ID tools. When liners or contingency strings are provided in a drilling plan, it should be noted that it is essential for safe workover operations that the tubing spool bore be sufficiently large enough to allow packers, bridge plugs, etc., to pass through and set in any casing size exposed in the well. On a pumping well, practically any tubing head is acceptable as long as it meets the pressure and strength requirements of the well. It should not be so tall that an elevated foundation is required for the pumping unit. Injection well tubing head selection is usually not critical. Any spool that meets the pressure and strength requirements should be adequate. The pressure rating should be high enough to safely contain the maximum anticipated injection pressure as this pressure could be applied to the tubing head in the event of a tubing leak. For shallow (less than 3000 feet) low Weatherford Wellhead Systems Training December 5, 2014 Revision Date: 11-10- Well: Page 11 of 17 pressure (less than 1500 psi), short life (5 to 10 years) wells, the screwed and capped tubing heads are acceptable for flowing, pumping or injection wells. An example of a low pressure flowing well is shown in Figure 1.12. Figure 1.12 Two-String Wellhead with Hanger Flange Wrap-Around Tubing Hanger Weatherford Wellhead Systems Training December 5, 2014 Revision Date: Page 12 of 17 11-10- Well: TUBING HANGERS There are numerous methods available to hang tubing strings. The most suitable all purpose hanger is the mandrel type, internally grooved or threaded for a back pressure valve. Hangers should normally be EUE (external upset end) to provide a standard connection but some customers prefer to have the same thread top and bottom even when an exotic or premium thread is being used. HANGER FLANGES Use of internally threaded tubing head adapter flanges (aka hanger flanges), shown in Figure 1.12, should be restricted to low pressure single completion oil wells. The primary disadvantage is lack of well control due to the fact that there is no back pressure valve (BPV) preparation. Also, this hanger may cause a minor space out problem if the well is equipped with a packer or mechanically set tubing anchor. SLIP-TYPE TUBING HANGER A slip-set hanger is acceptable for relatively shallow (8,000 feet or less), low pressure (less than 1,000 psi) oil wells. The slips and packing gland hold and seal the tubing. A stripper rubber can be installed in the tubing head spool for low pressure well control while handling the tubing. In general, slip type hangers should be avoided except on shallow wells. The slip crushing loads that may occur as the result of a shallow rod failure should be considered. WRAP AROUND TUBING HANGERS The “wrap-around” tubing hanger is not really a hanger since it supports no weight. Instead it is a split, wraparound packoff that allows reciprocation of the tubing string to displace fluid, set packers, etc. while maintaining complete control of annulus pressure. The design of the hanger relies upon a resilient seal energized by the lock screws of the tubing head causing the compression of the seal on the non-machined OD of the tubing. A wrap-around tubing hanger is used in conjunction Figure 1.13 Wrap-Around Tubing Hanger with a Hanger with either a hanger flange (Figure 1.12) or a tubing hanger Coupling coupling (Figure 1.13) which allows the use of a back pressure valve. Weatherford Wellhead Systems Training December 5, 2014 Revision Date: Page 13 of 17 11-10- Well: MANDREL TUBING HANGER The mandrel type hanger with internal preparation for BPV (back pressure valve), as shown in Figure 1.14, should be used on all wells of 5,000 psi and higher working pressure. An extended neck which seals into the tubing head adapter flange should also be used. Mandrel type hangers require lock screws in the top flange of the tubing spool to hold the hanger in place and to activate the annulus seal between the hanger and the bowl. On dual wells, a segmented mandrel type hanger is preferred. The design of this type of hanger permits well control by use of a back pressure valve, provides maximum clearance through the tubing head, allows running or pulling of either string and assures positive hanger orientation. Wells requiring more than two strings of tubing are very unusual and the hanger designs will be customized. For injection wells, a slip type hanger may be acceptable unless the well is capable of flowing back large quantities of injection fluid which could be damaging to the environment or personnel. In this case, a mandrel type hanger prepared for a back pressure valve should be used. Depending on the type of fluid, it may be advisable to make the hanger out of stainless steel or other similar non-corrosive material. Figure 1.14 Mandrel Tubing Hanger with extended neck Weatherford Wellhead Systems Training December 5, 2014 Revision Date: Page 14 of 17 11-10- Well: FLANGES AND SEAL CONNECTIONS The most common end connections used in the oil industry aside from welds and threads are flanges. Most companies will only use API flanges on wellheads, Christmas trees, blowout preventers, rotating heads, valves connected to them and other drill-through components. API flanges are pressure sealed by means of ring joint gaskets made of soft iron, low-carbon steel or stainless steel. Per API, all flanges in the stack, wellhead, tree and side-outlet flanges should be fitted with new ring joint gaskets each time they are assembled. API ring joint gaskets are also used for the smaller lines and fittings leading away from the preventer stack. The oval or round type R ring gasket was the first ring type joint gasket designed by API. API Flange specifications are tabulated below: 7,500 Weatherford Wellhead Systems Training December 5, 2014 Revision Date: Page 15 of 17 11-10- Well: API RING GASKETS TYPE R RING GASKET The R ring-type joint gasket is energized by compression as the mating flanges are made up and is not energized by pressure. The gasket is actually crushed against the ring groove to create a metal seal. Sealing takes place along narrow bands of contact between the grooves and the gasket on both the OD and ID of the gasket. The gasket may be either oval or octagonal in cross section. The R design does not allow face-to-face contact between the hubs or flanges, so external loads are transmitted through the sealing surfaces of the ring. Vibration and external loads may cause the small bands of contact between the ring and the ring grooves to deform plastically, so much so that the joint may develop a leak unless the flange bolting is periodically tightened. If additional weight is added to the upper half of a flange, such as in a wellhead assembly, it may crush the ring additionally and have the same effect as loosening the flange bolts. Standard procedure with type R ring joints in the BOP stacks is to check and re-tighten the flange bolting weekly. API recommends that a new gasket be used each time the connection is made up. TYPE RX RING GASKET The RX gasket is a pressure-energized ring that fits the standard API flange ring groove and has been accepted by API as an alternate form of ring gasket. The RX ring evolved during the development of 15,000 psi working pressure flanges. It was determined when testing with octagonal rings that when the ratio of the height of the ring to the height of the sealing surfaces was 3 to 1 or greater, the seal was energized by pressure. That is, the internal pressure tended to expand the ring gasket against the outer sides of the ring groove with sufficient force to energize a seal. To insure that initial contact is made between the sealing surfaces of the ring and the outer surfaces of the ring groove, the pitch diameter of the ring is made slightly larger than the groove, and the ring height is generally greater in proportion than the conventional octagonal ring. The advantages of the RX ring are: 1. Less bolt load is required as the ring does not have to be overly crushed to affect the seal; 2. It is pressure energized. The fact that the ring does not require excessive crushing while tightening permits faster tightening of the flanges as a reduced number of rounds of bolt tightening is required. This is especially helpful when working with large flanges in a limited working space such as with blowout preventers and drill-through equipment underneath the derrick floor. It is important to point out that care should be exercised to have the bolts tightened securely to prevent breathing of the flange and subsequent galling of the flange seals. Figure 1.15 The evolution of the API steel ring joint gasket from the original oval R to the square, pressure-energized BX Weatherford Wellhead Systems Training December 5, 2014 Revision Date: Page 16 of 17 11-10- Well: TYPE BX RING GASKET The 15,000 psi working pressure BX flange design was developed by AWHEM (the Association of Wellhead Equipment Manufacturers) for the industry. The seal ring, although it is square, has a 3: 1 height to seal pressure energizing ratio. The BX flange now adopted by API is different from the standard flange in that the raised faces touch when tightened, as shown in Figure 1.15. The old API ring and flange design would have to be tremendously large for 15,000 psi working pressure. This BX flange design results in substantial weight savings and the technique has been extended to the 5,000 and 10,000 psi working pressure flanges for some sizes. NON-API CONNECTIONS Various proprietary connections are commonly used throughout the industry for pressure sealing wellhead and blowout preventer Figure 1.16 Grayloc Clamp Connection equipment, particularly in underwater drill-through hookups. API has developed specifications for a clamp tree connector. These are covered in API Specification 6A for 5,000 psi and 10,000 psi working pressure connections. This type of clamped connection uses the API RX ring gasket. It should be noted that API clamped connectors can be provided on 2,000 psi and 3,000 psi working pressure equipment. The connectors are the same as 5,000 psi working pressure but do not increase the rated working pressure of the equipment. The Grayloc style clamp connection (Figure1.16) utilizes a well bore type of seal and thus does not have a ring groove. It is pressure energized and is no longer a proprietary connection. The advantages of this type of connection are: 1. Reduced area exposed to pressure, thus reducing end thrust; 2. Quick connecting, thus time saving; 3. Reusable seal ring; 4. Lighter weight. A disadvantage is that the bore of the seal ring may be subject to damage from tools and direct washing action of fluids. The Grayloc style of ring gasket and clamps is marketed under different names for both the US and international markets. Weatherford Wellhead Systems Training December 5, 2014 Revision Date: Page 17 of 17 11-10- Well: WELLHEAD SYSTEMS FOR UNIQUE APPLICATIONS Multi-Bowl Wellheads (aka split speed heads, compact wellheads, etc.) should be considered where time savings, improve safety, and reduced wellhead height are desired. One time consuming activity is disconnecting/reconnecting (nipple down/nipple up) of the BOP stack. This is usually performed after each casing string is run when the subsequent wellhead spool is added to the stackup. Multi-bowl wellheads reduce the number of times the BOP has to be manipulated by providing support and seal capabilities for more than one casing string in one wellhead assembly. The wellhead assembly consists of two full-bore housings installed as one unit (Figure 1.17) where the hangers stack on top of each other and are supported by one large support shoulder. Multibowls allow uninterrupted blowout preventer protection while providing improved safety to personnel and the environment. If the mandrel hanger does not land properly due to improper casing space-out, the wellhead sections can be separated to allow for use of conventional sliptype casing hanger to suspend the casing. For offshore applications, similar systems have been developed which feature special large connectors for diverters (part of the offshore drilling mud circulation system). Figure 1.17 Multi- Bowl Two Stage System