COMPLETION ESSENTIALS II Professor Babs Oyeneyin b.oyeneyin@rgu.ac.uk 01224-262327 Room C412 1 © The Robert Gordon University 2007 Content Details SECTION 2 • Completion Functions, Operations & Design Process • Completion Architecture & Equipment Selection • Tubing Specification & Equipment Material Selection © The Robert Gordon University 2007 2 Well Completions • Design and installation of equipment and treatment cum procedures required to bring a well to production − Driven by company objective. • Decision Areas − Specification of bottom hole completion technique − Selection of production conduit − Assessment of completion string facilities − Evaluation of well performance © The Robert Gordon University 2007 3 Well Completion Objectives • Drill a borehole through reservoir section • Create the necessary efficient hydraulic connection between borehole & reservoir • Install necessary equipment to allow production or injection • Provide safe and reliable system for efficient operation to take place with minimum NPT in line with company objectives © The Robert Gordon University 2007 4 Completion Objectives [Cont.] • Maximise safety of production & Injection system − Install flow control devices − Block fluid escape • Maximise production & injection efficiency − Maximise well flow potential • • • • • Tubing size Gas or water shutoff Leakage control Reservoir monitoring Flow assurance − Optimisation of capital expenditure − Minimisation of operational expenditure − Minimise downtime[NPT] © The Robert Gordon University 2007 SAFE & EFFICIENT PLUMBING JOB! 5 Functional Need of Completion • • • • • • • • Circulation Isolation & Control Reservoir monitoring Reservoir protection during shutoff Flow, pressure, temperature, etc monitoring Intervention Barrier for uncontrolled fluid escape Tubing stress tolerance © The Robert Gordon University 2007 6 SUMMARY OF • COMPLETION STEPS Total production rate desired − − AOF? IPR • Need to minimise slugging in tubing = Optimum Tubing Size • Define tubing size based on desired production rate, and operating conditions[GLR, Depth, etc] • • • • • • • • • − VLP − − − Flow Control Isolation, interventionetc Monitoring, Artificial lift, etc Define type of completion [Open Hole, Perforated Completion, Sand Control, etc] Define Operational Objectives Process Design Select Completion Jewels Stress Analysis Installation Procedure Vendor Sourcing Costing to AFE AFE = Authorisation for Expenditure © The Robert Gordon University 2007 7 Example Completion Schematic CONTROL LINE FLOW COUPLING SCSSSV CAMCO SPM. Valve to be activated by wireline OTIS ‘XA’ OTIS SSD XN LANDING NIPPLE OTIS ‘XA’ SSD 95/8in OTIS ‘RDH’ PACKER BAKER‘FB-1’ PACKER WITH GRAVELPACK EXTENSION BAKER ‘H’ LOCATOR & ‘FA-1’ PACKER BAKER ‘G’ LOCATOR SEAL ASSEMBLY STRING B SQUEEZE PACK OTIS BLAST JOINT LOCATOR SEAL ASSEMBLY BAKER ‘FB-1’ PACKER WITH GRAVELPACK EXTENSION OTIS XN LANDING NIPPLE WIRE-WRAPPED SCREEN BAKER ‘H’ LOCATOR & ‘FA-1’ PACKER BRIDGE PLUG © The Robert Gordon University 2007 8 Completion Factors • Well Objectives − Exploration Well • Reservoir Fluid Type − Appraisal Well • Well Testing for Pressure, rock flow properties − Development Wells • Production, Injection or Observation • Environmental, Geological, Topographical & Legal − − − − Onshore vs Offshore [Platform based or Subsea] Permit Transport [FPSO Hookup, Subsea tieback] Environment • Type of Reservoir • No. of Pay zones • Production strategy − Operating procedure − Monitoring − Possibility of Artificial Lift © The Robert Gordon University 2007 9 Type of Completion • Interface between reservoir & wellbore − − − − Open hole Slotted Liner Perforated Liner Cased hole [Perforated completion] • Method of production − Natural or Pumped • No. of zones − Single or Multiple © The Robert Gordon University 2007 10 Open Hole Completion • For Competent Formation • Production Casing to top of pay sand • Open hole barefoot or with slotted liner or perforated liner • Best for optimum flow potential • Low capital cost • Less completion time • Large wellbore radius − Reduced friction pressure • Poor isolation of gas or water − Swellable packers? • Limited by lack of selective production from same wellbore contact − May be possible with flow control devices in intelligent wells © The Robert Gordon University 2007 11 Open hole Completion Application • Low Cost & High number of wells development • Naturally fractured & competent reservoirs • High Cost Wells − Horizontal Well − Extended Reach Wells − Multilaterals © The Robert Gordon University 2007 12 Slotted or Perforated Liner Completion • Open hole with liner or screen − Slotted liner − Predrilled or perforated liner − Screen, etc • • • • Uncemented Liner tieback to casing Retrievable Supports wellbore − Unconsolidated sands/HW & MLs Production Tubing Production Packer Liner Packer Slotted Liner • Poor reservoir management © The Robert Gordon University 2007 13 Cased Hole Completion • Perforated Zone Production Casing − Allows selective or multiple production − Co-mingling or no comingling option − Possibility of zonal isolation − Most popular? − Most efficient? No! − Depends on • Perforation Density [Shots per foot] • Perforation penetration • Perforation size © The Robert Gordon University 2007 Cement Perforation Production Liner 14 Perforated Completion Application • • • • • Heterogeneous reservoirs Water or Gas management Selective completion High intervention cost areas High operating cost © The Robert Gordon University 2007 15 Natural vs Pumped Production • Natural Production − Best. Based on reservoir energy − Less facilities & complexity − Optimisation by • Pumped Production • Artificial Lift with Gas or Pump • minimising resistance to flow • Optimise production • Reservoir treatment © The Robert Gordon University 2007 16 Number of Zones • Single Zone − One pay zone • Multiple Zones Multiple pay sections Selective or simultaneous production Produce through multiple string [No co-mingling] Several zone producing to a single string[Comingling] − Multilateral proction − − − − • Multiple zones into a single bore © The Robert Gordon University 2007 17 Single Zone Completion • Tubingless Casing Flow − − − − Simple and low cost, High Rate Wells No longer in use Disadvantages • High Fluid Slippage and Friction Loss • Casing Contact/Corrosion • Casing Burst at Wellhead • Tubing Flow with Annular Isolation − Most Popular − Use of Isolation Packer − Max. Well Security • Casing & Tubing Flow − Better Well Control − Circulation Capability © The Robert Gordon University 2007 18 Single Zone Completion Casing Production © The Robert Gordon University 2007 Casing & Tubing Production Tubing production with packer Isolation 19 STRATIGRAPHIC COLUMN[Multiple Pay] © The Robert Gordon University 2007 20 Multiple Completion • > One Pay Section. • Co-Mingling from Various Zones • segregated Flow but Multiple Depletion • Alternate Zone Completion • Multilateral Completion © The Robert Gordon University 2007 21 Dual Single String + Annular Flow DUAL ZONE , ANNULAR FLOW © The Robert Gordon University 2007 DUAL ZONE , CROSS-OVER FLOW 22 Multiple Completion DUAL STRING © The Robert Gordon University 2007 SINGLE STRING, SELECTIVE PRODUCER TRIPLE COMPLETION 23 Completion String Facilities • FUNCTIONS − Control of anticipated flowing pressure and hydraulic pressure − isolation of Annulus − Wellbore Fluid and Remote Control − isolation of tubing − Circulation between Annulus and Tubing − Tubing Detachment − Controlled Fluid Injection − Suspension of Monitoring Equipment(BHP Gauge, Thermometers, etc) © The Robert Gordon University 2007 24 COMPLETION DESIGN PROCESS © The Robert Gordon University 2007 25 Design Process Initial Design Completion Technique Well Productivity or Injectivity Production Conduit or Artificial lift Completion String Facilities Cost Casing String Design Completion Architecture [Conceptual Design] Intervention Strategy Risk assessment Performance Optimisation Equipment Specification & Selection © The Robert Gordon University 2007 Final Design Installation & Integrity Testing Tubing Stress Analysis 26 Initial Design • Type of Completion − Open Hole or Perforated • Tubing Size − Nodal Analysis • Artificial lift requirements • Production or Injection Target © The Robert Gordon University 2007 27 Design Process [Coint.] • Prelim Equipment Selection Riusk Assessment Cost Casing Design Equipment features Suitable Well Architecture Well Intervention/Maintenance − Workover strategies − Re-Entry Options, etc − − − − − − © The Robert Gordon University 2007 • Well Performance Optimisation − Production optimisation @ minimum energy − Response to reservoir pressure, GLR, etc − Optimum rate − Maximum recovery 28 Final Design • • • • • • • Final specification Final verification Tubing stress analysis Erosion checks Condition monitoring options Installation procedures Tendering- Equipment, services − Costing − Organisation tasks • Asset Team − 2nd , 3rd party review − Independent review? • Flexibility − New ideas, new techniques or equipment − Field peculiarity • Design against failure − Injury, death, pollution [Spillage] Formalised Approach © The Robert Gordon University 2007 Quality Assurance 29 COMPLETION ARCHITECTURE © The Robert Gordon University 2007 30 Completion Components Two Sections C O M P L E T IO N U pp er • Upper Completion • Lower Completion CO M PO NENT F U N C T IO N T u b in g h a n g e r S u sp e n d th e strin g /c o m p o n e n ts S a f ety sy ste m s C o n ta in p ro d u c tio n flu id s Packer Iso la te / c o n ta in flu id s T u b in g T ra n sp o rt/c o n ta inm e n t of fluid s A rtificia l lift sy ste m s A id /e n h a n c e p ro d u c tio n D a ta a c q u isitio n sy ste m W ell/re se rv o ir m a n a g em e n t S lid in g sle ev e s W ell c irc u la tio n / saf e ty P e rf o ra tin g E sta b lish c om m u n ic a tio n b e tw e e n w e llb o re a n d re se rv oir S a n d c o n tro l S to p /c o n trol so lid s p ro d u c tio n F ra c tu rin g E n h a n c e p ro d u c tio n Iso la tio n sy ste m s R e se rv oir iso la tio n / sa f e ty Low er © The Robert Gordon University 2007 31 Upper Completion Methods & Equipment used above reservoir to surface • Functions − Effective lifting of produced fluids to surface − Fluid containment for safety − Minimise energy losses from production or injection © The Robert Gordon University 2007 32 Lower Completion • Interface between reservoir & wellbore • Functions − Long term integrity of wellbore − Full access to reservoir • • • • Monitoring Surveillance Management Performance improvement − Address specific requirements • Sand Control • Selective production, etc © The Robert Gordon University 2007 33 Completion Component Sequence XMAS REE Flow Control & Isolation WELLHEAD Tubing & Casing Suspension S.S.S.V SIDE POCKET MANDREL SLIDING SIDE DOOR [SSD] SEAL ASSEMBLY Safe isolation downhole Circulation or Fluid Injection Circulation Accommodate Tubing Stress PACKER Annular Isolation NIPPLE Tubing Isolation PERFORATED JOINT Alternate Entry for flow NIPPLE Landing Gauges W.E.G Wireline Re-Entry © The Robert Gordon University 2007 34 Completion Schematic CONTROL LINE FLOW COUPLING SCSSSV CAMCO SPM. Valve to be activated by wireline OTIS ‘XA’ OTIS SSD XN LANDING NIPPLE OTIS ‘XA’ SSD 95/8in OTIS ‘RDH’ PACKER BAKER‘FB-1’ PACKER WITH GRAVELPACK EXTENSION BAKER ‘H’ LOCATOR & ‘FA-1’ PACKER BAKER ‘G’ LOCATOR SEAL ASSEMBLY STRING B SQUEEZE PACK OTIS BLAST JOINT LOCATOR SEAL ASSEMBLY BAKER ‘FB-1’ PACKER WITH GRAVELPACK EXTENSION OTIS XN LANDING NIPPLE WIRE-WRAPPED SCREEN BAKER ‘H’ LOCATOR & ‘FA-1’ PACKER BRIDGE PLUG © The Robert Gordon University 2007 35 Facilities Functions • PRESSURE AND FLOW CONTROL • CIRCULATION CAPABILITY − Xmas Tree- For pressure containment within production casing, tubing wellhead, surface valve closing system • − Packer Isolation − Tubing Selection - Stable Production • ANNULAR ISOLATION − Packers − Prevents Pressure Exertion on • Wellhead © The Robert Gordon University 2007 − Well Control capability • • • • Sliding Side Door(SSD) Sliding Sleeve Side Pocket Mandrel Ported Nipple TUBING ISOLATION − SEAL ASSEMBLY − Supplement to SSSV • Used when SSSV is to be removed • Lands and locks in a wireline nipple inside tubing string. . DOWNHOLE ISOLATION OF PRODUCTION TUBING − Subsurface safety valve 36 Facilities [Cont.] • DOWNHOLE TUBING DETACHMENT − removable locator device which seals with rest of tubing left in well. • DOWNHOLE HANGER SYSTEM Suspends tubing beneath well Head • POLISHED BORE RECEPTACLE(PBR) - TUBING STRESS COMPONENTS • WIRELINE NIPPLE - LANDING NIPPLE System for holding pressure and Temperature Gauges, etc © The Robert Gordon University 2007 37 Completion String Components – XMAS TREE © The Robert Gordon University 2007 38 Xmas Tree • Combination of Valves pressure control systems located at Wellhead • Interface control barrier between Reservoir/Well & Topside facilities • Controller of Production/Injection • Permit Well kill prior to workover • Permit deployment of intervention strings © The Robert Gordon University 2007 39 Types of Xmas Tree Surface vs Subsea Surface • Conventional Flanged Trees − Land − Offshore wells • Solid Block Trees − − − − − Offshore Application HPHT High rate wells Reduces potential leaks For turbulent conditions = Y configuration Subsea • Conventional Dual bore trees − 2 vertical bores for tubing access and annulus • Horizontal/Spool trees • Inclined Trees [New] − Housed within wellhead • Horizontal /Spool Trees © The Robert Gordon University 2007 40 Trees Schematic © The Robert Gordon University 2007 41 Wellhead Functions − Transfers casing/completion loads to ground or platform − Provides seal system and valve to control tubing & annular access © The Robert Gordon University 2007 • Selection Factors − Loads − Requirements for annular injection − Exposure to nasty annular fluid − Annular pressure monitoring 42 Subsurface Safety Valves • Installed below wellhead to prevent uncontrolled flow in emergency situation [Prevent Blowout!] • Remote Controlled − Tubing retrievable − Wireline Retrievable − Surface Controlled (SCSSSV) • Closed and held open by external pressure @ surface • Pressure controlled most popular • Electric, electromagnetic & acoustic versions • Direct Controlled − Designed to be opened at preset differential pressure, flow or well pressure − Subsurface controlled (SSCSSSV) − Less reliable than surface controlled © The Robert Gordon University 2007 43 Subsurface Safety Valves • CATEGORIES − According to Closure Mechanism − Wireline or tubing Retrievable − Non-equalising or self Equalising Concentric or Rod Piston • Single Control Line or Dual Balanced Line © The Robert Gordon University 2007 TUBING RETRIEVABLE WIRELINE RETRIEVABLE 44 Subsurface Safety Valves FLAPPER TYPE © The Robert Gordon University 2007 BALL TYPE 45 Joints & Couplings • FLOW COUPLING - FC − These are short sections of thick-walled pipes used to withstand any erosion caused by turbulent flow through different tubing sizes − FC below & above landing nipple useful close to SSSV • BLAST JOINTS − Couplings designed to withstand external erosion − Usually positioned either side of a Sliding Sleeve situated at perforated production zones or lateral joints in Multilateral completions. • PUP JOINTS − Short tubing joints that give flexibility in attaining a desired tubing length such as spacing out completion © The Robert Gordon University 2007 46 Landing Nipples • Short tubular sections with an internally machined profile that provide location points for various flow control devices and gauges in the production string • When holding pressure monitoring systems they are called Gauge mandrels • Applications include: − Plugging tubing for pressure testing − setting hydraulic set packers − Zonal isolation − installation of downhole chokes − Landing off BHP recorders © The Robert Gordon University 2007 47 Landing Nipples No-Go Nipples © The Robert Gordon University 2007 Non-Selective Selective Wireline Operated 48 Side Pocket Mandrels(SPM) − These are joints having offcentre pockets with ports in the wellbore annulus. − Applications include: • As Gas Lift Madrels − As Chemical Injection Valves − Circulation Devices for kill fluids − Usually activated by annular pressure © The Robert Gordon University 2007 49 Sliding Sleeves or SSD • System that allows − Communication between tubing and the annulus for well kill operation − Circulation for tubing or annulus − Selective zone © The Robert Gordon University 2007 50 Polished Bore Receptacle/Expansion Joint Seal • PBR - Useful where large tubing movement is anticipated. • ELTSR – Inverted PBR. − Run with permanent packers © The Robert Gordon University 2007 51 Anchor Seal Nipple • Anchoring & sealing device − Connects retrievable tubing string to upper bore of production packer − Provides sealing barrier at tubing bottom − Facilitates workover of damaged tubing − Provides tubing anchor to minimize movement − Assists well killing operation by providing +ve safety barrier. © The Robert Gordon University 2007 52 Packers • TYPES − Based on Retrievability • PERMANENT PACKERS • RETRIEVABLE PACKERS − Based on Setting Mechanism • • • • Mechanical Setting - Tubing Rotation Compression or Tension Setting Hydraulic setting Electrical - Special Adaptor/Settiong Tool − Based on Packer Bore • Single, Dual and Triple Bores © The Robert Gordon University 2007 53 Packer Classifications • SEAL WITHOUT TUBING MOVEMENT − External Rubber Seal element • SEAL WITH TUBING MOVEMENT − Locator Seal assembly − Extra Long tubular Seal receptacle - ELTSR − Travel Joint - Inverted ELTSR − PBR- Polished Bore Receptacle © The Robert Gordon University 2007 54 Packer © The Robert Gordon University 2007 55 Tubing Specification & Equipment Selection © The Robert Gordon University 2007 56 Tubular Nomenclature • Nominal Size = Outside Diameter, OD − − − • Tubings : 11/20’’ to 4-1/2’’ Casings : 4-1/2’’ + Different IDs depending on strength & Wall thickness Length Range® − Tubings − Casings • R1 = 20-24ft • R2 = 28 – 32ft API Spec. • R3 = 32-48ft - Mill • R1 = 16-25ft • R2 = 25-34ft • R3 = 32-48ft © The Robert Gordon University 2007 • • • WT/ft − − Dictates mechanical strength Nominal ID depends on OD & WT/ft! − Max. size of equipment to pass thru tubular Drift ID Coupling OD − − • Maximum OD of tubing Applied when estimating clearances to install tubing GRADES − − − − Single or Double letter prefix XT155 = Xtra tough 155kpsi strength material API Class: N80 = 80Kpsi Yield Not Ultimate strength 57 Tubular Design Factors • Adopted to ensure tubing is selected and used in manner to prevent premature failure • DF based on: − Service loads − Allowance for unexpected events − Effect of packer setting, temperature, buckling, corrosion • Design Loads − − − − Burst Collapse Axial Triaxial – Axial, Radial, Tangential © The Robert Gordon University 2007 58 Mechanical Design • Four failure modes: − Parting of tubing under axial load • [Bending, overpull, dogleg friction] • DF = 1.1 − Bursting due to internal pressure • Corrosion & erosion effects • [DF = 1.1] − Collapse under external pressure • DF = 1.0 − Combined stress[Triaxial] exceeding yield of tubing • DF = 1.1 © The Robert Gordon University 2007 59 Tubular Design Factors RatedAxial Tension Axial = Actual Axial Calculated Burst Rating Burst = [ Internal Pr essure − Ext . Pr essure ] Calc . Collapse Pr essure Collapse = [ External Pr essure − Int . Pr essure ] Material API Yield Triaxial = Triaxial Stress © The Robert Gordon University 2007 60 Tubing Design Considerations • Maximum & Optimum flow rate • • • • • • • − Size determination Maximum surface pressure [Flowing & Shut-in] Corrosion potential over life of string Erosion potential Well intervention effects E.g Stimulation Necessary Tensile stress Burst & Collapse Loading Forces − Determine Wt. & Grade of tubing material • Tubing movement − Tubing components © The Robert Gordon University 2007 61 Mechanical Loads on Tubing Strings • Changing forces = Changing in movement/Length • Key Factors contributing: − − − − − Weight Pressure Fluid Friction Ballooning Temperature • Loads excluded from axial stress: − Ballooning & Temperature © The Robert Gordon University 2007 62 FWT = W ' TVD Tubing Forces • Axial Forces = Sum of forces for free system + Forces induced by resistance to length change • W’ = WT/FT • W = Weight © The Robert Gordon University 2007 FWT = W '*TVD N = W sin A 63 ∆L = LF E ( Ao − Ai ) Tubing Movement • Piston Effect = Changes in length caused by the pressure forces acting on the tubing ∆L = Tubing extension • L= Measured Length of Tubing • F= Force due to plug, etc. • E = Young’s Modulus • Ao= External area • Ai= Internal area © The Robert Gordon University 2007 ∆L = LF E ( Ao − Ai ) 64 Tubing Movement • Temperature Effect • CT = Coeff. Of Thermal Expansion, 1/oF • DT = Temperature Change, oF • L = Tubing Length, Ft • If Tubing is Free, − Faxial = 0 • For Anchored tubing − Faxial = FTemp ∆ L TEM P = C T ∆ T L n FTEMP = − ∑ CTi Ei ∆Ti ( Aoi − Aii ) i =1 • For Combination Completion • i = individual components © The Robert Gordon University 2007 65 Buoyancy Effect • FB = Buoyancy Effect • FB = - p* [Ao – Ai] © The Robert Gordon University 2007 66 Ballooning Effect • Radial expansion or contraction caused by pressure change • Result = Length Change! • Computation is essential for each section with same OD & wall thickness © The Robert Gordon University 2007 67 Poisson Effect µ = Poisson ration ∆p = Change in pressure compared to base case • Lp = Length to packer • For combination system, add cumulative lengths to packer point • For Anchored Tubing − 2µLP (∆pi Ai − ∆po Ao ) ∆LBAL = E( Ao − Ai ) FBAL = 2µ( Ai∆pi − Ao∆po ) − Faxia = FBAL © The Robert Gordon University 2007 68 Fluid Friction • Friction by fluids moving inside the tubing and the associated friction between the fluid and the tubing wall • Fluid Flowing Down = Lengthening of tubing • Fluid Flowing up = Shortening of Tubing • Frictional Pressure Force = FFR F FR • Change in Length, DLFR ∆ L FR © The Robert Gordon University 2007 − ∆p = Ai L ∆L ⎤ ⎡⎛ − ∆p⎞ 2 ⎢ ⎜⎝ ∆ L ⎟⎠ L p A i ⎥ ⎥ = ⎢ ⎢ 2 E (Ao − Ai )⎥ ⎥⎦ ⎢⎣ 69 RADIAL & TANGENTIAL STRESSES • Radial Stresses pi Ai − po Ao ( pi − po ) Ai Ao σr = − ( Ao − Ai ) A ( Ao − Ai ) • Tangential Stresses pi Ai − poAo ( pi − po ) Ai Ao σt = + ( Ao − Ai ) ( Ao − Ai ) A For inner radius, A = Ai & σr = - pi For outer radius, A = Ao & σr = -po σ t ,i σ t ,o © The Robert Gordon University 2007 pi ( Ai + Ao ) − 2 p o Ao = Ao − Ai 2 pi Ai − p o ( Ai + Ao ) = Ao − Ai 70 Helical Buckling Effect • Excess Axial Force • -ve Effective Force = Helical Buckling • Neutral Point = Depth at which FEFF = 0 moving up from packer © The Robert Gordon University 2007 71 Helical Effect • Effective Force FEFF = FTOTAL + ( po Ao − pi Ai ) F EFF = A p ( p o − p i ) • If free to move • Ap = Packer ID • • • • • n = Neutral Point Gio = Fluid Gradient [in or annulus] W’ = WT/FT C = Radial clearance b/w casing and tubing E = Youngs Modulus © The Robert Gordon University 2007 • Elongation or Compression? n = • For free tubing and n within string ∆ LHB = • F EFF W '+ G i A i − G o A o − C 2 FE F F 2 8 E I (W ' + G i A i − G o A o ) For n >Lp − C 2 F EFF 2 L ⎡L ⎛ ∆ L HB = − 2 ⎜ 8 EI (W ' + G i A i − G o A o ) ⎢⎣ n ⎝ n I = [ OD 4 − ID 4 ] 64 π 72 ⎞⎤ ⎟⎥ ⎠⎦
