COPYRIGHT. Gas Lift Fundamentals. This section will cover the following learning objectives:

Transcription

1 Learning Objectives Gas Lift Fundamentals This section will cover the following learning objectives: Explain the role of gas lift in a real performance analysis process Explain the principles of multi-phase flow and the principle of gas lift Identify the advantages and disadvantages of gas lift as an artificial lift method Identify gas lift equipment Estimate the production rate achievable by the gas lift Identify gas lift design methods Establish well unloading procedures Outline gas lift surveillance and optimization processes 1

2 Module Contents Introduction Inflow and Outflow Performance Review Gas Lift Theory Gas Lift Applications Gas Lift Equipment Valve Mechanics Well Performance Calculations with Gas Lift Gas Lift Well Unloading Process Gas Lift Design Outline Gas Lift Surveillance and Optimization Gas Lift Case Study Conclusions Module Schedule S. No. Topic of Discussion Activity Time (min) 1 Pre-Assessment Assessment 30 2 Skill Module Introduction Narrated Slideshow 4 3 Gas Lift Video 2 4 Gas Lift Design Introduction Video 3 5 Principles of Gas Lift, Gradient Calculations and Nodal Analysis Virtual Session Well Inflow Performance Narrated Slideshow 9 7 Flowing Gradient Exercise 10 8 Well Outflow Performance Narrated Slideshow 13 9 Gas Lift Requirement Exercise Kickover Tool Gas Lift Valve Setting Procedure Video 1 11 Retrieval of Dummy Valve Video 2 12 Gas Lift Equipment Narrated Slideshow IPO Gas Lift Valve Pressure Setting Exercise Orifice Gas Valve Gas Passage Exercise Gas Lift Design, Troubleshooting and Valve Mechanics Virtual Session Gas Lift Surveillance and Optimization Narrated Slideshow 8 17 Gas Lift Case Study Exercise Skill Module Summary Narrated Slideshow 4 19 Post-Assessment Assessment Gas Lift Fundamentals Survey Survey 15 Total Duration 7 hours 1 min 2

3 Gas Lift Fundamentals Virtual Session 1 Gas Lift Principles Definition, Advantages, Completions 3

4 Natural Flow Well vs. Gas Lifted Well NATURAL FLOW WELL GAS LIFTED WELL Higher magnitude of production Tubing Production; Annular Gas Lift Injection Fluid column weight reduced by formation gas in a natural flow well INJECTION GAS PRODUCED FLUID DEPTH (FT TVD) (305 m) 2000 (610 m) 3000 (914 m) 4000 (1219 m) Fluid column weight reduced by formation and injected gas: a gas lift well Lower back pressure of formation Lower flowing bottom hole pressure CONTINUOUS FLOW GAS LIFT WELL PRESSURE (PSI) 1000 (6895 kpa) 2000( kpa) CASING PRESSURE WHEN WELL IS BEING GAS LIFTED 5000 (1524 m) OPERATING GAS LIFT VALVE 6000 (1829 m) 7000 (2133 m) SIBHP FBHP 4

5 Gas Lift Definition Gas lift is a means of artificial lift involving the injection of high pressure gas downhole into the produced fluid column. The injected gas increases the gas-liquid ratio, reduces the fluid density and column weight of the produced fluids, creating a pressure differential between the wellbore and reservoir Aeration or lightening of fluid column (density reduction) Gas expansion, assisting the fluid to move to surface Types of Gas Lift Continuous flow gas lift Intermittent gas lift CONDITION CONTINUOUS FLOW INTERMITTENT FLOW Production Rate (bbl/day) ,000 Up to 500 Static BHP (psi) > 0.3 psi/ft (6.79 kpa/m) < 0.3 psi/ft (6.79 kpa/m) Flowing BHP (psi) > 0.08 psi/ft (1.81 kpa/m) 150 psi ( kpa) and higher Injection Gas (scf/bbl) (m 3 /m 3 ) ( ) per 1000 ft (304.8 m) of lift ( ) per 1000 ft (304.8 m) of lift Injection Pressure (psi) > 100 psi ( kpa) per 1000 ft (304.8 m) of lift < 100 psi ( kpa) per 1000 ft (304.8 m) of lift Gas Injection Rate Larger volumes Smaller volumes 5

6 Continuous Flow Gas Lift A steady flow of high pressure gas is injected into the production tubing to aerate and lighten the fluid column. A series of gas lift valves are run to allow the deepest possible lift point Production rates can range from 200 BLPD (31.8 m 3 ) through 2" (0.05 m) tubing up to 50,000 BLPD ( m 3 ) in 7" (0.18 m) tubing Gas Lift Advantages Proven method Cost of downhole equipment low Can be installed and serviced without workover Flexible to changes in operating conditions Unaffected by sand, scale and asphaltenes Good for deviated wells Allows downhole chemical injection Good in hot wells Can use compressors designed for other use Tolerates high GOR Open tubing for PLT 6

7 Gas Lift Disadvantages Gas supply needed More gas to handle May be slow to start up after shutdown Gas supply flowline needed to each well Tubing, casing and wellhead design should withstand high pressure gas Safety hazard Hydrates Drawdown less than ESPs Valve interference; heading Gas Lift Costs Provision of gas supply Gas compression Power provision Gas piping to the wellhead Gas lift completion (sometimes dual) Gas lift string installation High capex, low opex 7

8 Gas Lift Completions: Conventional Valves Conventional valves require the tubing to be pulled to service the valves Wireline Retrievable Valves Wireline retrievable require kickover tools to be run down the tubing to service the valves Tubing does not have to be pulled Tubing open to full flow Used extensively offshore Gas Lift Conventional Injection Pressure Operated Valves Time-Cycle Controller and Motor Valve Conventional Mandrel With Gas Lift Valve Conventional Mandrel With Gas Lift Valve Conventional Mandrel With Gas Lift Valve Conventional Mandrel With Gas Lift Valve Packer Landing Nipple Gas Lift Wireline Retrievable Valves Adjustable Choke Subsurface Safety Valve Side Pocket Mandrel With Gas Lift Valve Side Pocket Mandrel With Gas Lift Valve Side Pocket Mandrel With Gas Lift Valve Sliding Sleeve Packer Landing Nipple 8

9 Side String for Injection No pressure on casing Easily controlled More expensive to set up Stable and not subject to surging and heading High Rate Annular Completions Annular flow can be 30,000-60,000 bpd ( m 3 ) if annulus is big enough Well integrity/safety issues Gas Lift Retrievable Valves Side Pipe Injection Adjustable Choke Gas Injection Conduit Side Pocket Mandrel With Gas Lift Valve Side Pocket Mandrel With Gas Lift Valve Side Pocket Mandrel With Gas Lift Valve Packer Landing Nipple Gas Lift Wireline Retrievable Valves Annular Flow Adjustable Choke Side Pocket Mandrel With Gas Lift Valve Side Pocket Mandrel With Gas Lift Valve Side Pocket Mandrel With Gas Lift Valve Bull Plug 9

10 Dual Zone Completion If two zones isolated and gas lift used, it can be hard to split injection gas as desired on a design basis Gas Lift Wireline Retrievable Valves Dual Zone Adjustable Choke Subsurface Safety Valves Intermittent Gas Lift Side Pocket Mandrel With Gas Lift Valve Dual Packer Landing Nipple Blast Joint Packer Landing Nipple 10

11 Pressure Gradient (1) Gradient Calculations Single Phase, Multi-phase Flow The pressure change per unit length is called the pressure gradient and is expressed as psi/ft For incompressible single phase flow, for a constant flow rate, the pressure drop can be expressed as a constant pressure change per unit length However, within the flowing well, two phase vertical flow is encountered and hence a constant pressure gradient cannot be used as the pressure gradient changes with depth Many equations are required to determine the two-phase pressure gradient and so a graphical representation in the form of a pressure-depth traverse is the simplest 11

12 Pressure Gradient (2) Pressure (psi) = Fluid gradient (psi/ft) x Vertical fluid column length (ft.) Fluid gradient (psi/ft) = Specific gravity x psi/ft (2.99 kpa/m) Fluid gradient (psi/ft) = x Density (lbs/gal) Oil gradient (psi/ft) x psi / ft API Static Pressure Gradient Exercise Static pressure measurements are available from a vertical well shut-in for the last six months Calculate: The static BHP of the well The water, oil and gas gradient The water-oil interface and oilgas interface depths Suggest a single point gas lift depth if lift gas is available at 1400 psia ( kpa) (gas gradient 45 psi/1000 ft) (1.02 kpa/m) Depth, Ft Measured pressure in psia Xmas tree ( kpa) 1000 (304.8 m) 251 ( kpa) 2000 (609.6 m) 602 ( kpa) 3000 (914.4 m) 976 ( kpa) 4000 ( m) 1349 ( kpa) 5000 (1524 m) 1725 ( kpa) 6000 ( m) 2148 ( kpa) 7000 ( m) 2600 ( kpa) 8000 ( m) 3048 ( kpa) Tail pipe (EOT) 8800 ( m) 3407 ( kpa) Mid-perf 9100 ( m) 12

13 Static Pressure Gradient Exercise Solution BHP at mid-perf depth = 3540 psi ( kpa) (extrapolated from 8800 ft ( m) to 9100 ft ( m)) Static gradients: Water = ( )/2000 = 0.45 psi/ft. (10.18 kpa/m) Oil = ( )/2000 = psi/ft. (8.48 kpa/m) Gas = ( )/1000 = psi/ft. (0.59 kpa/m) (should be much less; data suspect) Interface depths: Water-oil: ~5500 ft. ( m) (refer to graph) Oil-gas: ~1000 ft. (304.8 m) (refer to graph) Single point gas lift depth: 4000 ft. ( m) (refer to graph) Static Pressure Gradient Exercise GL KO Pressure, Measured pressure in Wireline psia psia depth, Ft ( kpa) ( kpa) ( kpa) 251 ( kpa) 1000 (304.8 m) 1490 ( kpa) 602 ( kpa) 2000 (609.6 m) 1535 ( kpa) 976 ( kpa) 3000 (914.4 m) ( ( kpa) kpa) ( m) ( ( kpa) kpa) 1670 ( kpa) 1715 ( kpa) 1760 ( kpa) 1796 ( kpa) 2148 ( kpa) 2600 ( kpa) 3048 ( kpa) 3407 ( kpa) 5000 (1524 m) 6000 ( m) 7000 ( m) 8000 ( m) Pressure, psia (kpa) Gas Oil Interface ΔP Solution 8800 ( m) Annulus Gas gradient Oil Water Interface 13

14 Nodal Analysis Nodal Analysis Finding the Possible Production Rates Estimate the inflow performance Perform pressure drop calculation for a number of different flow rates = generate family of pressure traverse curves Calculate VLP = wellbore flowing pressures for different flow rates against a constant WHP Solve simultaneous equations defined by VLP and IPR, giving unique solution at selected solution node The intersection of the VLP and IPR curves denotes the operating point of the system 14

15 Operating Point ( kpa) For a given flowrate, drawdown yields BHFP much less than required by tubing to lift against WHP: not enough energy ( kpa) ( kpa) ( kpa) ( kpa) For a given flowrate, drawdown yields BHFP much greater than required by tubing to lift against WHP: too much energy Operating point = stable equilibrium (11.92 m 3 /Day) (23.85 m 3 /Day) (35.77 m 3 /Day) (47.70 m 3 /Day) Reservoir fluid PVT Summary Curves Reservoir fluid PVT property curves vs. pressure 15

16 Nodal Analysis Modeling of GL Well Session Summary Gas Lift: How does it work Costs and challenges associated with setting up gas lift operations Static vs. flowing gradient Multi-phase flow and stability Flowing Gradient plots Gas Lift well modeling Gas Lift initiation & operating point Gas Lift sensitivities: Tubing size GL Injection depth (Lift gas pressure) GL Injection rate Flowing wellhead pressure Water-cut Requirements for gas lift well Multiphase flowing gradient Gas Lift modeling & Sensitivities 16

17 The Production System OUTFLOW Well Inflow Performance Prediction Methods INFLOW 17

18 Inflow Performance The Inflow Performance Relationship (IPR) describes the ability of the reservoir to deliver fluid (i.e. rate) for a prescribed pressure drop between reservoir and wellbore (drawdown) The IPR is independent of the tubulars. The IPR can be evaluated using: Analytical Methods Empirical Methods Inflow: Steady-state Radial Flow Darcy Law C k h Pres pwf Qo Bo In re / rw S IPR=Inflow Performance Relationship Oilfield: C = & Q o in BOPD Metric: C = & Q o in m 3 /d Applicable for non-compressible single phase flow S = classic mechanical skin (dimensionless) 18

19 Inflow: Semi-steady-state Radial Flow Darcy Law (corrected for non-darcy skin) kh Pres pwf Qo Bo In re / rw 0.75 S Dq Productivity Index (PI) where Q o J * P res P wf and J PI or Productivity Index, Oilfield Units Simplest and most widely used relationship Straight line Units stbpd/psi For oil/water wells above bubble point Not applicable to gas wells (kpa) Straight Line PI 1600 (11 032) 1400 (9653) 1200 (8274) 1000 (6895) 800 (5516) 600 (4137) 400 (2758) 200 (1379) (31.8) (63.6) (95.4) (127.2) (159) (190.8) Rate (STBLPD)(SCM/Day) Test Point PI Test Point Pressure (psi) Q PI = P r P wf PI= Productivity Index 19

20 Vogel IPR Originally developed for saturated oil reservoirs / solution gas drive by Alfred Vogel Applicable below bubble point Need Q and P wf from well test Calculate Q max Use Q max to calculate complete IPR Q P P wfs wfs Q P P max r r (kpa) Pressure (psi) Vogel IPR 1800 (12 410) 1600 (11 032) 1400 (9653) 1200 (8274) 1000 (6895) 800 (5516) 600 (4137) 400 (2758) 200 (1379) (15.9) (31.8) (47.7) (63.6) (79.5) (95.4) (111.3) Rate (STBLPD) (SCM/Day) Combined IPR for Under-saturated Reservoir Above P bp, use straight line IPR Below P bp, use a combination of both Total Oil Prod = Q oil at P bp + Q oil Vogel (a) (b) Pwf Test Point Pb Pwf Pwf Q PI Pr Pb PI Pb Pb 2 2 Pressure P res P wf (a) (b) P bp Rate Q max 20

21 Back to Work Suggestions <Course Well Inflow Title> Performance Leverage the skills you ve learned Leverage by the discussing skills you ve the skill learned module by discussing objectives the with skill module your supervisor objectives to develop with your a supervisor personalized to plan develop to implement a personalized the job. plan Some to implement suggestions the are job. provided. Some suggestions are provided. Do you have reliable production data? Do Identify you have a few good wells reservoir in your pressure asset where data? the production decline appears to be Do mainly you have due average to change reservoir in inflow pressure data as performance. a function of time Suggest which possible can be ways used as for a proxy improving to determine production. the hydrocarbons in Review place? the variation of PI observed with Do time you have good fluid properties measurements? Do you have good correlations which we can use to predict the fluid properties? 21

22 The Production System OUTFLOW Well Outflow Performance Prediction Methods INFLOW 22

23 System Pressure Drop P P Pressure (psi) P res P wf P ftp Pflowline Psep inlet Produced Fluids Moving Through The System Multiphase Flow Reservoir Skin?? Perfs Tubing Wellhead Choke Pst tank Flowline Manifold Separator Stock tank The three components of the total pressure loss are given by the following equation ( m represents the properties of the mixture): dp dz total g = m sin g c hyd mvmdv gcdz hydrostatic: gravitational component friction: irreversible heat loss due to work acceleration: expansion/kinetic component Vertical: sinθ = 1 horizontal: sinθ = 0 Whilst hydrostatic and acceleration can be determined analytically, friction has to be determined from correlations m acc f m 2 mv m 2gcD fr 23

24 VLP Multi-phase Flow Regimes (609.6 m) ( m) (A) BUBBLE FLOW (B) SLUG FLOW (C) SLUG-ANNULAR TRANSITION (D) ANNULAR-MIST FLOW Ideal Flow regimes or categories for multiple flow as illustrated by Orkiszewski. First published in the JPT, June 1967 Tubing Performance: Pressure Traverse Affected by wellhead pressure flow rate tubular properties (diameter, roughness) fluid properties/pvt (holdup, slip) well inclination GOR water cut viscosity ( m) calculated ( m) Measured (FGS)? (3048 m) ( kpa) ( kpa) ( kpa) ( kpa) ( kpa) ( kpa) ( kpa)( kpa) 24

25 Vertical Lift Performance Measured Depth (ft) (609.6 m) ( m) ( m) ( m) (3048 m) Pressure traverse curves for curves Q = 0, for 50, Q 100, 300 = 0, 50, stb/d 100, 300 stb/d (47.7 m 3 /Day) ( kpa) Pressure Pressure at Selected Node Depth ( kpa) ( kpa) ( kpa) ( kpa) Vertical Lift Performance VLP Tubing Performance relationship TPR (11.93 m 3 /Day) selected node depth ( kpa) ( kpa) ( kpa) Commonly Used Flow Correlations Poettman and Carpenter (1952) Gilbert (1954) Griffith and Wallis (1961) Duns and Ros (1961) Fancher and Brown (1965) Hagedorn and Brown (1965) Orkiszewski (1967) Govier and Azis (1972) Beggs and Brill (1973) Gray Mechanistic (BAX, EPS) (23.85 m 3 /Day) (35.77 m 3 /Day) (47.70 m 3 /Day) Total Production Rate (STB/day) 25

26 General Multi-phase Flow Correlations Different correlations give reasonable match for different wells: There is no universal correlation that will fit for all conditions Correlation selection is mostly by field experience Data required for curves includes: Conduit Size Producing Rate Flowing wellhead pressure Water Cut API Gravity Water Specific gravity Gas Specific gravity and Average flowing temperature Applications of Gradient Curves Flowing pressure gradient curves were extensively used before nodal analysis programs became available Framed for different production rates, water cuts, gas oil ratios Typical use of gradient curves: Estimate Flowing Bottom Hole Pressure (FBHP) Calculate Productivity Index (PI) Predict maximum flow rates from well Evaluate optimum gas lift rates Determine maximum depth of injection Evaluate the effect of Flowing Well Head Pressure (FWHP), Tubing Size, Gas Lift Injection pressure and water cut on FBHP and flow rates 26

27 (2758) (5516) (8274) (11 032) (13 790) (16 547) (19 305) Pressure in 100 PSIG (kpa) (304.8) (610) (914) (1219) (1524) (1829) (2134) (2438) (2743) (3048) (304.8) (610) (914) (1219) (1524) (1829) Length in 1000 feet (meters) Length in 1000 feet (2758) (5516) (8274) (11 032) (13 790) (16 547) (19 305) Pressure in 100 PSIG (meters) (kpa) (102 mm) (636 m 3 /Day) (2134) (60 C) (2438) (2743) (3048) (3048) 27

28 (2758) (5516) (8274) (11 032) (13 790) (16 547) (19 305) Pressure in 100 PSIG (kpa) (304.8) (610) (914) (304.8) (610) (914) (1219) (1524) (1829) (2134) (2438) Length in 1000 feet (1219) (1524) (1829) (2134) (2438) (2743) (3048) Length in 1000 feet (meters) (2758) (5516) (8274) (11 032) (13 790) (16 547) (19 305) Pressure in 100 PSIG (kpa) For a formation producing from a well under the conditions in the box, these curves provide the P wf to produce 4000 BOPD (636 m 3 /Day) at different producing GOR s (102 mm) (636 m 3 /Day) (60 C) (2743) (3048) 28

29 (2758) (5516) (8274) (11 032) (13 790) (16 547) (19 305) Pressure in 100 PSIG (kpa) (304.8) (610) (914) (1219) (1524) (1829) (2134) (2438) (2743) (3048) Length in 1000 feet (meters) (304.8) (610) (914) (1219) (1524) 180 Generating similar curves For with a formation nodal producing analysis program from a allows well under you to the prepare an exact conditions pressure traverse in the box, using: these curves provide Actual the fluid P wf to produce properties 4000 BOPD Wellhead at different pressure producing GOR s Expected production rate Water cut Other conditions (2758) (5516) (8274) (11 032) (13 790) (16 547) (19 305) (1829) (2134) (2438) (2743) Note: For more examples, refer to the Tubing Gradient and Appendix PDFs under Resources. (3048) 29

30 Back to Work Suggestions Well Outflow Performance Leverage the skills you ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided. Do you have reliable production data? Do Matching you have with good the reservoir measured pressure BHP data? or FGS data for a well, identify the preferred Do correlation you have average that gives reservoir a reasonable pressure match data as Review a function the of FTP time of wells which in can your be used area as and a proxy identify to determine wells with the excessive hydrocarbons back in pressures. place? Suggest action plan to reduce Do back you pressure have good in fluid an economically properties measurements? attractive way. Do you have good correlations which we can use to predict the fluid properties? 30

31 Gas Lift Equipment Gas Lift Mandrels, Valve Types, Valve Mechanics Gas Lift Mandrels The depth at which the mandrel is included in the completion is Orienting determined by: Sleeve Casing pressure Body Dome Tubing pressure POC Flowing gradient expected in tubular Tubing Bellows Tubing size Ab Other parameters Casing Pressure Tool Discriminator Latch Lug Seat Two types Tubing of mandrels commonly used are: Pressure Conventional mandrel Side pocket mandrel Polished Bore Pocket Conventional Mandrel Side Pocket Mandrel 31

32 Gas Lift Mandrels Orienting Sleeve Dome Body Tubing Tubing Pressure POC Ab Conventional Mandrel Side Pocket Mandrel (140 mm) (38 mm) 5 1/2 MMRG-4, 1 1/2 POCKET ROUND MANDREL DESIGN Orienting Sleeve ENGINEERING DATA Bellows Casing Pressure PART NUMBER SIZE 5 1/2 (140 mm) MAX O.D (216 mm) MIN I.D (134 mm) DRIFT I.D (134 mm) THREAD 17 LB/FT MANN BDS B x P (25 kg/m) TEST PRESSURE INTERNAL 7740 PSI ( kpa) TEST PRESSURE EXTERNAL 6280 PSI ( kpa) LATCH TYPE RK, RK-1, RKP, RK-SP KICKOVER TOOL OM-1, OM-1M, OM-1S RUNNING TOOL RK PULLING TOOL 1 5/8 JDS (41 mm) MATERIAL 410 S.S., 13 CR 22 HRC MAX TENSILE STRENGTH (EOEC) 490,000 LBS( kg) CAMCO 1996 Seat Tool Discriminator G Latch Lug Tool Discriminator Latch Lug Polished Bore Pocket Side Pocket Mandrel Polished Seal Bore CAMCO 32

33 GLV in SPM Side Pocket Mandrel Latch Upper Packing SPM Gas inlet port GLV Gas inlet port Lower Packing Nose (Gas Exit) 33

34 Kickover Tool The kickover tool is run on wireline and used to pull and set gas Orienting lift valves Sleeve Body The ability to wireline change-out Dome gas lift valves gives great flexibility in the gas lift design Tubing Tubing Pressure POC Ab Conventional Mandrel Bellows Casing Pressure Seat Kickover Tool GLV Pulling Procedure Tool Discriminator Latch Lug Polished Bore Pocket Side Pocket Mandrel 34

35 Gas Lift Straddles Tubing Pressure Kickover Tool GLV Setting Procedure Note: Please view the kickover setting procedure video and the retrieving the dummy valve video. Used for gas lifting wells that are not equipped with gas lift Orienting mandrels in the original completion or do not have a mandrel at Sleeve the required depth Body Dome Gas lift straddle installed using wireline (e-line or Slickline) POC Tool Utilizes Tubing a conventional Bellows or wireline retrievable valve or concentric Discriminator Ab gas lift valve (selected based on application) Can have more than one Casing gas lift straddles installed Pressure Retrievable pack-offs available Seat Latch Lug Polished Bore Pocket Conventional Mandrel Side Pocket Mandrel 35

36 Gas Lift Pack-off Straddle Assembly Typical gas lift pack off consists of: Upper tubing stop Upper pack off assembly Gas lift mandrel with GLV/Check valve (with spacer pipe) Lower pack off assembly Lower collar stop Tubing is perforated at a pre-determined depth (without damaging casing) before setting the straddle Will restrict the tubing ID Gas Lift Valve Types Gas Lift Unloading valves Injection Pressure Operated: IPO (Pressure Valves) Production Pressure Operated: PPO (Fluid Valves) Operating Valves Orifice Valves Venturi valves Production Casing Production Tubing Upper Pack off Gas Lift valve Tubing Perforations Lower Pack off Dummy Valves Special Application Valves Constant Flow Valves Proportional Response Valves Pilot Valves Surface Controlled Valves 36

37 Gas Lift Valve Types Gas Lift Unloading valves Injection Aid the Pressure removal Operated: of the heavy IPO weight (Pressure completion Valves) fluid inside Production the tubing Pressure and the Operated: annulus PPO (Fluid Valves) Work in a sequence to help unload the valve and allow the Operating lit gas Valves to reach the operating point Orifice Valves Venturi valves Dummy Valves Special Application Valves Constant Flow Valves Proportional Response Valves Gas Lift Valve Types Gas Lift Unloading valves Pilot Valves Surface Controlled Valves Injection Pressure Operated: IPO (Pressure Valves) Production Pressure Operated: PPO (Fluid Valves) Operating Valves Orifice Stay Valves open all the time injecting the required volume of gas Venturi from valves the annulus into the tubing Dummy Valves Special Application Valves Constant Flow Valves Proportional Response Valves Pilot Valves Surface Controlled Valves 37

38 Injection Pressure Operated Valve Production Pressure Check Valve Seat Ball Stem Injection Pressure Unattached Bellows and Stems/Balls Bellows Mechanical Stop Nitrogen The closing force in an unloading valve is offered by a compressed spring or a bellows charged with nitrogen gas Bellows is a sensitive element of the gas lift valve It should not be exposed to significant differential pressure during the life of the gas lift valve Valve Bellows Two stems with balls 38

39 Unloading Gas Lift Valve Normally required during unloading phase only Valve closes after transfer to next station Valve opens only when annulus and tubing pressures are high enough to overcome valve set pressure May be spring or nitrogen charged Operating Gas Lift Valve Upper Packing Lower Packing Typically an orifice type gas lift valve Always open - allows gas passage whenever correct differential exists Gas injection controlled by size and differential across replaceable choke Back-check prevents reverse flow of well fluids from the production conduit Upper Packing Lower Packing 39

40 Dummy Valves Used to blank off mandrels Typical applications: Sealing off the pocket of side-pocket mandrel, preventing communication between casing and tubing Blanking off the tubing for production until gas-lift valves are required Pressurizing the tubing Isolating tubing and casing flow during single-alternative production and for test purposes during multi-point water- or gas-injection floods IPO Valve Schematic Dome Chevron Packing Stack Bellows Stem Tip (Ball) Square Edged Seat Chevron Packing Stack Po Check Valve 40

41 PPO Valve Schematic Dome Chevron Packing Stack Opening Forces Bellows Stem Tip (Ball) Square Edged Seat Chevron Packing Stack Check Valve Force Balance at Opening P d A B P t A p P c ( A B -A p ) Dome (Loading Element) Po Bellows (Responsive Element) Area of Bellows P c, Casing Pressure P t, Tubing Pressure A p, Area of Port 41

42 Closing Forces Force Balance at Closing P d A B P C A B Valve Opening And Closing Pressures (1) 1. Calculate the bellows pressure at downhole temperature, P bt 2. Correct this P bt to a bellows pressure at 60 F (16 C), Pb@60F 3. Calculate a test-rack opening pressure, PTRO CLOSING FORCE (IPO VALVE) F C = P B A B OPENING FORCES (IPO VALVE) Fo 1 = P C (A b A P ) Fo 2 = P t A P TOTAL OPENING FORCE A b P 1 Fo = P C (A b A P ) + P t A P JUST BEFORE THE VALVE OPENS THE FORCES ARE EQUAL P d A p P c (A b -A p ) + P t A p = P b A b SOLVING FOR P C P b -P t (A p /A b ) P c = (A p /A b ) WHERE: P b = Pressure in bellows P t = Tubing pressure P c = Casing pressure A b = Area of bellows = Area of port A p P C 42

43 Test Rack Opening Pressure 60F 0 TROP b P t A p /A b P c R 1 A p /A b 60F TRO 1 R Note: P 60F = (T c ) Depth) Note: P b is same as P d Tester Bleed Valve Atmospheric Pressure High pressure air or gas Gas Lift valves for high pressure applications Based on the demand for sub-sea wells and deep water applications, Schlumberger developed new Series High pressure gas lift valves 1.75 (60 mm) OD XLift Barrier Series High pressure gas lift valves XLO-B Orifice valve XLO-R-B Rupture disk orifice valve XLI-B Injection pressure operated valve Orifice valves rated for injection pressure of 7500 psi ( kpa) at depth IPO valve rated for injection pressure of 5000 psi ( kpa) at depth Barrier-qualified positive sealing check system Check valve test pressure: max differential 10,000 psi ( kpa) 1.5 OD (54 mm) Barrier Series High Pressure valves Allows deeper-set valves and higher drawdown Enhanced wellbore integrity Similar products now available from other companies as well 43

44 Gas Lift Surface Equipment Gas lift injection (typical) Gas lift header valve Gas injection metering GL choke Check valve Wing valve Pressure, temperature sensors Liquid removal (if needed) Heat tracing, antifreeze (if needed) Oil and gas production Wing valve(s), Header valve(s) Production choke (generally not used) Casing Pressure at Depth Casing pressure or gas lift injection pressure at depth pressure will be required Crawford Equation: P d = P s [ g/(tz) ] h P d = Pressure at Depth, psi P s = Pressure at Surface, psi g = Gas gravity (Air = 1.0) T = Average temperature of the gas column, (Ts+Td)/2; R =( F + 460) z = Average compressibility factor h = Depth in feet Gas Gradient Note: This spreadsheet is available for your use in the resources section. 44

45 Gas Pressure at Depth Chart 1 (304.8 m) (609.6 m) (914.4 m) ( m) (1524 m) ( m) ( m) ( m) ( m) (3048 m) Gas Passage Calculation ( ( ( ( ( ( ( ( ( kpa) kpa) kpa) kpa) kpa) kpa) kpa) kpa) kpa) Thornhill-Craver Equation can be used to calculate the gas passage through a square-edged orifice: Q (2/ ) (( 1)/ ) ( / 1) [ k k xc k d xaxp g k k x r r ] GxT Q = Gas Flow in Mscf/Day at 60 DegF and 14.7 psia (101.3 kpa) C d = Discharge coefficient A = Area of opening, Sq inches P 1 = Upstream pressure, psia P 2 = Downstream pressure, psia g = Acceleration of gravity = 32.2 ft/sec 2 (10 m/s 2 ) k = Ratio, Cp/Cv, Sp heat at const press / Sp heat at const volume r = Ratio P 2 / P 1 r o r o = Critical Flow pressure ratio, [2/(k+1)] k/(k-1) G = Specific gravity (Air = 1.0) T = Inlet temperature, Deg R 45

46 Unloading Valve vs. Orifice: Gas Passage Comparison Orifice Maximum Flow Throttling Range Unloading Valve P tbg Differential Range Orifice vs. Nova Valve: Gas Passage Comparison Nova Valve Orifice Valve P up / P down ratio = 0.53 Critical Flow P up / P down ratio = 0.90 Critical Flow Sub-critical Flow Q gi P csg Q gi P csg P tbg 46

47 Valve Geometry Data Available from Supplier (15.6 C) 47

48 Back to Work Suggestions <Course Gas Lift Equipment Title> Leverage the skills you ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided. Do you have reliable production data? Do Review you have the good gas lift reservoir valve data pressure that data? is maintained in your asset. Is GLV failure a Do common you have observation? average reservoir Any specific pressure data as pointers a function contributing of time which to valve can be failures? used as a proxy Review to determine the the percentage the hydrocarbons of success of in gas place? lift valve change out jobs. What sort Do of you impact have this good has fluid on properties oil production? measurements? Do you have good correlations which we can use to predict the fluid properties? 48

49 Gas Lift Fundamentals Virtual Session 2 Gas Lift Unloading Using Multiple Unloading Valves 49

50 Continuous Flow Unloading To Separator/Stock Tank Gas in INJECTION GAS CHOKE CLOSED (609.6 m) Tubing Pressure Casing Pressure 4000 ( m) TOP VALVE OPEN SECOND VALVE OPEN THIRD VALVE OPEN FOURTH VALVE OPEN Continuous Flow Unloading Gas in INJECTION GAS CHOKE OPEN To Separator/Stock Tank TOP VALVE OPEN SECOND VALVE OPEN 6000 ( m) Depth 8000 ( m) 10,000 (3048 m) 12,000 ( m) 14,000 ( m) (609.6 m) 4000 ( m) 6000 ( m) Depth 8000 ( m) ( ( ( kpa) SIBHP kpa) 8 kpa) kpa Pressure kpa kpa Tubing Pressure Casing Pressure THIRD VALVE OPEN FOURTH VALVE OPEN 10,000 (3048 m) 12,000 ( m) 14,000 ( m) ( ( ( ( kpa) ( ( kpa) SIBHP kpa) kpa) Pressure kpa) kpa) 50

51 Continuous Flow Unloading To Separator/Stock Tank Gas in INJECTION GAS CHOKE OPEN (609.6 m) Tubing Pressure Casing Pressure 4000 ( m) TOP VALVE OPEN SECOND VALVE OPEN THIRD VALVE OPEN FOURTH VALVE OPEN Continuous Flow Unloading Gas in INJECTION GAS CHOKE OPEN To Separator/Stock Tank TOP VALVE OPEN SECOND VALVE OPEN 6000 ( m) Depth 8000 ( m) 10,000 (3048 m) 12,000 ( m) 14,000 ( m) (609.6 m) 4000 ( m) 6000 ( m) Depth 8000 ( m) ( ( ( ( ( ( SIBHP kpa) 8 kpa) Pressure kpa) kpa) 7 kpa) kpa) Tubing Pressure Casing Pressure THIRD VALVE OPEN FOURTH VALVE OPEN 10,000 (3048 m) 12,000 ( m) 14,000 ( m) DRAWDOWN FBHP ( ( ( ( kpa) ( ( SIBHP kpa) kpa) 8 kpa) Pressure 7 kpa) kpa) 51

52 Continuous Flow Unloading To Separator/Stock Tank Gas in INJECTION GAS CHOKE OPEN (609.6 m) Tubing Pressure Casing Pressure 4000 ( m) TOP VALVE OPEN SECOND VALVE OPEN THIRD VALVE OPEN FOURTH VALVE OPEN Continuous Flow Unloading Gas in INJECTION GAS CHOKE OPEN To Separator/Stock Tank TOP VALVE CLOSED SECOND VALVE OPEN 6000 ( m) Depth 8000 ( m) 10,000 (3048 m) 12,000 ( m) 14,000 ( m) (609.6 m) 4000 ( m) 6000 ( m) Depth 8000 ( m) DRAWDOWN FBHP ( ( ( ( kpa) ( ( SIBHP kpa) kpa) 8 kpa) Pressure 7 kpa) kpa) Tubing Pressure Casing Pressure THIRD VALVE OPEN FOURTH VALVE OPEN 10,000 (3048 m) 12,000 ( m) 14,000 ( m) DRAWDOWN FBHP ( ( ( ( kpa) ( ( SIBHP kpa) kpa) 8 kpa) Pressure 7 kpa) kpa) 52

53 Continuous Flow Unloading To Separator/Stock Tank Gas in INJECTION GAS CHOKE OPEN (609.6 m) Tubing Pressure Casing Pressure 4000 ( m) TOP VALVE CLOSED SECOND VALVE OPEN THIRD VALVE OPEN FOURTH VALVE OPEN Continuous Flow Unloading Gas in INJECTION GAS CHOKE OPEN To Separator/Stock Tank TOP VALVE CLOSED SECOND VALVE CLOSED 6000 ( m) Depth 8000 ( m) 10,000 (3048 m) 12,000 ( m) 14,000 ( m) (609.6 m) 4000 ( m) 6000 ( m) Depth 8000 ( m) DRAWDOWN FBHP ( ( ( ( kpa) ( ( SIBHP kpa) kpa) 8 kpa) Pressure 7 kpa) kpa) Tubing Pressure Casing Pressure THIRD VALVE OPEN FOURTH VALVE OPEN 10,000 (3048 m) 12,000 ( m) 14,000 ( m) DRAWDOWN FBHP ( ( ( ( kpa) ( ( SIBHP kpa) kpa) 8 kpa) Pressure 7 kpa) kpa) 53

54 Continuous Flow Unloading To Separator/Stock Tank Gas in INJECTION GAS CHOKE OPEN (609.6 m) Tubing Pressure Casing Pressure 4000 ( m) TOP VALVE CLOSED SECOND VALVE CLOSED THIRD VALVE OPEN FOURTH VALVE OPEN Continuous Flow Unloading Gas in INJECTION GAS CHOKE OPEN To Separator/Stock Tank TOP VALVE CLOSED SECOND VALVE CLOSED 6000 ( m) Depth 8000 ( m) 10,000 (3048 m) 12,000 ( m) 14,000 ( m) (609.6 m) 4000 ( m) 6000 ( m) Depth 8000 ( m) DRAWDOWN FBHP ( ( ( ( kpa) ( ( SIBHP kpa) kpa) 8 kpa) Pressure 7 kpa) kpa) Tubing Pressure Casing Pressure THIRD VALVE CLOSED FOURTH VALVE OPEN 10,000 (3048 m) 12,000 ( m) 14,000 ( m) DRAWDOWN FBHP ( ( ( ( kpa) ( ( SIBHP kpa) kpa) 8 kpa) Pressure 7 kpa) kpa) 54

55 Casing Pressure and Tubing Pressure Trends during Unloading Process ( ) ( ) ( ) (kpa) (9652.6) (8273.7) (6894.7) (5515.8) (4136.8) (2757.9) (1378.9) Gas Lift Design Gas Lift Design Techniques, Safety Margins, Computer Assisted Gas Lift Designs 55

56 Gas Lift Design Objectives Allow lift gas to be injected as deeply as possible Conserve as much injection pressure as possible Ensure all upper unloading valves are closed after the final point of injection has been reached Be able to unload the well with available injection pressure regardless of the liquid level in the tubing Ensure that the operating valve passes the correct amount of gas to achieve the required gas lift gradient Ensure that the above objectives can be met under present as well as near-future conditions Gas Lift Design Steps 1. Collect data 2. Identify tubing sizing and mandrel spec (valve OD) 3. Design mandrel spacing 4. Position the operating valve 5. Position the unloading valves 6. Specify the unloading valve specs (port size and pressure setting) 7. Select the orifice valve port size 8. Validate the design 56

57 Gas Lift Well with No Unloading Mandrel Pressure GL Kick off Pressure TVD Single GLM Perforations Unloading Gradient Operating Injection Pressure Gas Lift Design with Unloading Valves (IPO) 1. Gather all data 2. Plot gas lift injection gradient 3. Plot well fluid gradient (starting from P wf ), choosing the proper flowing gradient curve 4. Plot operating valve P using operating casing pressure 5. Plot design gradient or trigger line with safety factor (P1, P2) for valve transfer 6. Use casing pressure safety factor for valve closing 7. Space out mandrels using the available gas lift pressure at depth, the trigger line and kill fluid gradient. Locate the first (kick off) valve and other unloading valves down to operating valve 8. Include dummy valves in the spare mandrels below the operating point 9. Determine unloading valve port size and Ptro 10. Finalize the orifice valve specs and the expected operating casing pressure 57

58 Graphical Gas Lift Design (IPO) Expected gradient Design gradient w/ transfer bias TVD Pressure GL kick off pressure Operating Casing pressure Unloading kill fluid gradient Operating Depth Minimum mandrel spacing (Future) FBHP (P wf ) Drawdown Gas Lift Design with Unloading Valves (PPO) SBHP (P res ) 1. Gather all data 2. Plot gas lift injection gradient 3. Plot well fluid gradient (starting from Pwf), choosing proper flowing gradient curve 4. Plot operating valve P using operating casing pressure 5. Plot objective design gradient or trigger line with safety factor (P1, P2). Note that there is some 20-25% safety factor at surface for the trigger line as the valves will close sensing the reduction in tubing pressure. The casing pressure will not be reduced for every mandrel station in case of PPO design. 6. Space out mandrels using the available gas lift pressure at depth, the trigger line and kill fluid gradient. Locate the first (kick off) valve and other unloading valves down to operating valve 7. Include dummy valves in the spare mandrels below the operating point 8. Determine unloading valve port size and Ptro 9. Finalize the orifice valve specs and the expected operating casing pressure 58

59 Graphical Gas Lift Design (PPO) Pressure Expected gradient Design gradient GL kick off pressure Operating Csg pressure Unloading gradient TVD Design Exercise 1: Single Mandrel Gas Lift Operating Depth Minimum mandrel spacing (Future) FBHP (P wf ) Drawdown SBHP (P res ) Following well parameters are available: Well depth 9000 ft. ( m) (Vertical) FWHP: 250 psi ( kpa) Average flowing gradient above point of injection: 0.2 psi/ft (4.52 kpa/m) Gas lift available at well location: 1500 psi ( kpa), 120ºF (48.9 ºF) Gas weight is 45 psi/1000 ft (1.02 kpa/m) P required through the operating valve: 100 psi (689.4 kpa) Locate the gas lift mandrel station depth if The gradient can be reduced to 0.3 psi/ft (6.79 kpa/m) by pumping Nitrogen through coiled tubing for well kick off, prior to placing on gas lift The available gas lift system has to be used for unloading the well. When shut-in, the fluid gradient in tubing may rise to 0.43 psi/ft (9.61 kpa/m) 59

60 Design Exercise 2A: Gas Lift IPO Unloading Tubing size 4-1/2 (0.11 m) Casing Size 9-5/8 (0.24 m), 47 lb/ft (70 kg/m) Deviation Vertical well Desired production 5000 BLPD (794.9 m 3 /day) Watercut 50% Desired TGLR 1000 scf/stb (178.1 m 3 /m 3 ) Oil gravity 35 API Water gravity 1.07 Gas gravity 0.65 Flowing wellhead pressure, temp 200 psig ( kpa), 140 F (60 C) Gas lift kick off pressure 1400 psi ( kpa) at wellhead Average reservoir pressure 3000 psi ( kpa) Reservoir temperature 225 F (107 C) Liquid PI 4 Bpd/psi drawdown (0.09 m 3 /kpa) Formation GOR 400 SCF/STB (71.2 m 3 /m 3 ) Mid perforation depth 8000 ft ( m) Bottom mandrel depth (max depth) 7800 ft ( m) Design Exercise 2B: Gas Lift IPO Unloading Tubing size 3-1/2 (0.09 m) Casing size 9-5/8 (0.24 m), 47 lb/ft (70 kg/m) Deviation Vertical well Desired production 2000 BLPD ( m 3 ) Watercut 50% Desired TGLR 1000 scf/stb (178.1 m 3 /m 3 ) Oil gravity 35 API Water gravity 1.07 Gas gravity 0.65 Flowing wellhead pressure 200 psig ( kpa) Surface temperature static / flowing 80 / 150 F (27 / 66 C) Gas lift kick off pressure 1200 psi ( kpa) at wellhead Avg reservoir pressure, temperature 3000 psi ( kpa), 216 F (102 C) Liquid PI 2 Bpd/psi (0.05 m 3 /kpa) drawdown Formation GOR 400 SCF/STB (71.2 m 3 /m 3 ) Mid perf depth 7500 ft (2286 m) Bottom mandrel depth 7200 ft ( m) Completion fluid weight 8.6 ppg ( kg/m 3 ) 60

61 Recall - Gas Lift Design Steps 1. Collect data Gas Lift Unloading Design Using IPO Valves: Worked Example Example 2A 2. Identify tubing sizing and mandrel spec (valve OD) 3. Design mandrel spacing 4. Position the operating valve 5. Position the unloading valves 6. Specify the unloading valve specs (port size and pressure setting) 7. Select the orifice valve port size 8. Validate the design 61

62 Design Exercise 2A: Gas Lift IPO Unloading Depth (TVD), Ft. (m) 2000 (610) Tubing size 4-1/2 (0.11 m) GLM with 1.5 pocket will be used Casing Size 9-5/8 (0.24 m), 47 lb/ft Deviation Vertical well Desired production 5000 BLPD (794.9 m 3 /day) Watercut 50% Desired TGLR 1000 scf/stb (178.1 m 3 /m 3 ) Oil gravity 35 API Water gravity 1.07 Gas gravity 0.65 Flowing wellhead pressure, temp 200 psig ( kpa), 140 F (60 C) Gas lift kick off pressure 1400 psi ( kpa) at wellhead Average reservoir pressure 3000 psi ( kpa) Reservoir temperature 225 F (107 C) Liquid PI 4 Bpd/psi drawdown (0.09 m 3 /kpa) Formation GOR 400 SCF/STB (71.2 m 3 /m 3 ) Mid perforation depth 8000 ft ( m) Bottom mandrel depth (max depth) 7800 ft ( m) 4000 (1219) 6000 (1829) Pressure, psi (1379) (kpa) (8274) (9653) (11 032) (2758) (4137) (5516) (6895) Prepare a mm Graph sheet, taking Pressure along the horizontal axis and Depth along the vertical axis Mark the mid perf and bottom mandrel (max injection) depths Bottom Mandrel Depth (7800 Ft) [2377 m] 8000 (2438) Mid Perforation Depth (8000 Ft) [2438 m] 62

63 Defining the two gradients Depth (TVD), Ft. (m) 2000 (610) Expected Flowing Gradient Generate the expected flowing gradient for the gas lifted well (after gas lift unloading): By modeling the GL well using a Nodal Analysis program Using estimated flowing gradient (from similar wells), OR Using published gradient curves Plot the tubing pressure traverse vs. True vertical depth (TVD) Expected GL gas gradient Calculate the casing pressure profile starting with GL Kick off pressure (using equation or Chart) Plot downhole casing pressure vs. True vertical depth (TVD) 4000 (1219) Pressure, psi (1379) (kpa) (8274) (9653) (11 032) (2758) (4137) (5516) (6895) Expected flowing gradient Expected GL Gas gradient (Kick off) 6000 (1829) 8000 (2438) Bottom Mandrel Depth (7800 Ft) [2377 m] 1372 Mid Perforation Depth (8000 Ft) [2438 m] 1445 (P wf )

64 Location of Top Mandrel Depth (TVD), Ft. (m) Unloading will begin by U-tubing, where the top of standing fluid level is found in the well (a function of reservoir pressure, THP and fluid gravity) Fluid column in the well: 3000 psi / 0.45 psi/ft = 6667 ft. (2032 m) Fluid level from surface = = 1333 ft (if THP = 0 psig). The worst case scenario is the well standing full up to surface The mandrel spacing will be performed for the worst case scenario. The well will unload even if the reservoir pressure is higher 2000 (610) 4000 (1219) Pressure, psi (1379) (kpa) (8274) (9653) (11 032) (2758) (4137) (5516) (6895) 2600 Ft. GLM-1 [792.5 m] Unloading kill fluid gradient, 0.45 psi/ft (10.2 kpa/m) ΔP:60 psi 6000 (1829) Locate the top GLM by U tubing : draw the kill fluid gradient from the FWHP and determine the location of first GLM by allowing about 60 psi ΔP across the unloading valve (Pc >Pt) 8000 (2438) Bottom Mandrel Depth (7800 Ft) [2377 m] 1372 Mid Perforation Depth (8000 Ft) [2438 m] 1445 (P wf )

65 Depth (TVD), Ft. (m) 2000 (610) Pressure, psi (1379) 320 (kpa) (8274) 1370 (9653) (11 032) (2758) (4137) (5516) (6895) Tubing Design Line 2600 Ft. GLM-1 [792.5 m] 4000 (1219) 6000 (1829) 8000 (2438) Depth (TVD), Ft. (m) 2000 (610) 4000 (1219) 4250 Ft. GLM-2 [ m] Casing safety factor (1.5 OD IPO): Drop Pc by 30 psi for every mandrel (to close the upper valve) Tubing Safety factor: Draw tubing design line by taking 10% safety factor at P1 (Ptbg design = FWHP * (Pcsg Ptbg) Bottom Mandrel Depth (7800 Ft) [2377 m] 1372 Mid Perforation Depth (8000 Ft) [2438 m] Pressure, psi Pcsg available for second mandrel 1445 (P wf) 1660 (1379) 320 (kpa) (8274) 1370 (9653) (11 032) (2758) (4137) (5516) (6895) 2600 Ft. GLM-1 [792.5 m] 4250 Ft. GLM-2 [ m] Starting from the tubing design line at GLM 1, draw the kill fluid gradient to determine the location of GLM 2. Use the reduced casing pressure ΔP 6000 (1829) 8000 (2438) Bottom Mandrel Depth (7800 Ft) [2377 m] 1372 Mid Perforation Depth (8000 Ft) [2438 m] 1445 (P wf )

66 Depth (TVD), Ft. (m) Pressure, psi (1379) (kpa) (8274) (9653) (11 032) (2758) (4137) (5516) (6895) 2000 (610) 2600 Ft. GLM-1 [792.5 m] 4000 (1219) 6000 (1829) 4250 Ft. GLM-2 [ m] 5450 Ft. GLM-3 [ m] Using the same approach locate other deeper mandrels. Continue till the ΔP becomes less than 100 psi (689.5 kpa). Bottom Mandrel Depth (7800 Ft) [2377 m] (2438) Mid Perforation Depth (8000 Ft) [2438 m] Depth (TVD), Ft. (m) 2000 (610) 4000 (1219) Pressure, psi Starting from the tubing design line at GLM 2, draw the kill fluid gradient to determine the location of GLM 3. For every mandrel drop Pc by 30 psi (206.8) 1445 (P wf ) 1660 (1379) (kpa) (8274) (9653) (11 032) (2758) (4137) (5516) (6895) 2600 Ft. GLM-1 (792.5 m) 4250 Ft. GLM-2 ( m) 5450 Ft. GLM-3 ( m) 6000 (1829) 8000 (2438) 6250 Ft. GLM-4 (1905 m) 6850 Ft. GLM-5 ( m) 7200 Ft. GLM-6 ( m) 7500 Ft. GLM-7 (Inactive) (2286 m) 7800 Ft. GLM-8 (Inactive) ( m) Mid Perforation Depth (8000 Ft) [2438 m] Allow mandrels at bracket spacing ( ft) [ m] at bottom as required Mandrel Spacing Complete (P wf )

67 Mandrel Spacing Design Results Depth (TVD), Ft. (m) 2000 (610) 4000 (1219) Eight gas lift mandrels required: 5 Unloading valves (GLM-1 thru 5) 1 Orifice valve (GLM-6) 2 Dummy Valves (GLM 7-8) Next Steps Determine Valve port size for the IPO valve selected (based on gas passage requirements during unloading) Perform valve pressure setting calculations for each of the unloading valve Determine the Orifice port size Pressure, psi (1379) (kpa) (8274) (9653) (11 032) (2758) (4137) (5516) (6895) 2600 Ft. GLM-1 (792 m) 4250 Ft. GLM-2 (1295 m) Read tubing design pressures and casing pressures at each mandrel station depth 5450 Ft. GLM-3 (1661 m) 6000 (1829) 8000 (2438) 6250 Ft. GLM-4 (1905 m) 6850 Ft. GLM-5 (2088 m) 7200 Ft. GLM-6 (2195 m) 7500 Ft. GLM-7 (Inactive) (2286 m) 7800 Ft. GLM-8 (Inactive) (2377 m) Mid Perforation Depth (8000 Ft) [2438 m] (P wf )

68 Depth (TVD), Ft. (m) 2000 (610) Pressure, psi (kpa) (1379) (5516) (6895) (8274) (9653) (11 032) (2758) (4137) Temperature, F C 37.8 C 82.2 C C Draw the static and flowing Gas Lift kick off temperature gradients from pressure mid perf to surface 2600 Ft. GLM-1 (792 m) Static Flowing Operating casing pressure 4000 (1219) 6000 (1829) 8000 (2438) Depth (TVD), Ft. (m) 2000 (610) 4000 (1219) 4250 Ft. GLM-2 (1295 m) 5450 Ft. GLM-3 (1661 m) 6250 Ft. GLM-4 (1905 m) 6850 Ft. GLM-5 (2088 m) 7200 Ft. GLM-6 (2195 m) 7500 Ft. GLM-7 (Inactive) (2286 m) 7800 Ft. GLM-8 (Inactive) (2377 m) Mid Perforation Depth (8000 Ft) [2438 m] 1445 (P wf ) Pressure, psi (kpa) (1379) (5516) (6895) (8274) (9653) (11 032) (2758) (4137) Temperature, F C 37.8 C 82.2 C C 2600 Ft. GLM-1 (792 m) 4250 Ft. GLM-2 (1295 m) Read the temperatures at mandrel depths (static for GLM 1 2 and flowing for deeper mandrels) Ft. GLM-3 (1661 m) 6000 (1829) 8000 (2438) 6250 Ft. GLM-4 (1905 m) 6850 Ft. GLM-5 (2088 m) 7200 Ft. GLM-6 (2195 m) 7500 Ft. GLM-7 (Inactive) (2286 m) 7800 Ft. GLM-8 (Inactive) (2377 m) Mid Perforation Depth (8000 Ft) [2438 m] 1445 (P wf )

69 Unloading valve Calculations For GLM-1, select R-20, port size 0.25 (6.35 mm) Valve Type Port Size (in.) R 1 R R (6.35 mm) R (7.9 mm) Calculate Pb Pb = Pc (1-R) + Pt (R) = 1485 (0.934) (0.066) = 1432 psi (9873 kpa) Calculate Pb@60 F (15.6 C) Pb@60 F = Pb * Ct (Temperature Correction Factor) Ct is (from Temperature Correction Chart for a temperature of 140 F (60 C) using static gradient at GLM-1 depth) Pb@60 F = 1214 psi (8370 kpa) Calculate Test rack opening pressure (TRO) Ptro = Pb@60 F / (1-R) = 1214/0.934 = 1300 psi (8963 kpa) Repeat calculations for Mandrels 2-5 Notes: Used static temperature gradient for the top two unloading valves Orifice valve Calculations Perform orifice sizing calculations using tubing pressure and casing pressure at operating depth (GLM-6) Using gas passage program (or spreadsheet / chart), determine by trial and error the size of the orifice valve that Will be able to inject set point lift gas rate (4.0 MMscf/Day ( m 3 /day)), and Give a noticeable reduction in casing pressure when the well transfers to operating point Results: Orifice size: 0.5" (12.7 mm) Estimated casing pressure at surface after unloading: 1250 psi (8618 kpa) Validate the design (QC) to ensure well will unload Prepare the gas lift valve table to be sent to Gas Lift Shop 69

70 Orifice Valve Sizing ( ) ( ) ( ) ( ) ( ) ( ) (SCM/Day) (84 951) (56 634) (28 317) (1379) Gas Lift Design Results (Example 2A) GLM No Mandrel Depth, Ft. (m) 2600 (792) 4250 (1295) 5450 (1661) 6250 (1905) 6850 (2088) 7200 (2195) 7500 (2286) 7800 (2377) Gas Lift Gas Lift Valve Valve Type Port Size (1.5 OD) (mm) R 20 R 20 R 20 R 20 R 20 Orifice Dummy 1/4" (6.4) 1/4" (6.4) 1/4" (6.4) 1/4" (6.4) 5/16 (7.9) 1/2 (7.9) Casing pressure at depth, psig (kpa) 1485 (10 239) 1510 (10 411) 1515 (10 446) 1510 (10 411) 1505 (10 377) 1480 (10 204) Tubing design pressure at depth, psig (kpa) 675 (4654) 900 (6205) 1060 (7308) 1175 (8101) 1250 (8618) 1310 (9032) (2758) (4137) (5516) (6895) (8274) (9653) (11 032) (kpa) Temperature used for design, F (Ct) Pb@T Psig Pb@T= [Pc*(1 R) +Pt*(R)] Pb@60 Psig Pb@60= (Pb@T)*Ct PTRO Psig Ptro = (Pb@60F)/ (1 R) 140 (0.853) (0.814) (0.771) (0.761) (0.752) NA Dummy Gas Lift Design Complete 70

71 Unloading Guidelines Gas Lift Operations and Diagnostics Unloading Procedures, Gas Lift Efficiency, Surveillance and Troubleshooting 1. Hook up the tubing pressure, casing pressure and gas lift injection rates to chart recorders / trend display devices 2. Bleed tubing down into the oil manifold 3. Start injecting +/- 300 MCFPD (8, scm/day). Slowly increase injection so it takes 10 minutes for a 50 psig (344.7 kpa) increase in casing pressure. Continue until top valve passes gas 4. Slowly increase injection to allow casing pressure to build-up in 100 psig (689.4 kpa) increments every 10 minutes 5. Maintain injection rate about half of set point until the orifice is reached. 6. Once the well is cleaned up and there is a notable drop in surface casing pressure indicating that the well has unloaded to the orifice, increase injection rate to set point 71

72 IPO Design: Valves Close With Drop In Casing Pressure ( kpa) (3447 kpa) (6895 kpa) ( kpa)( kpa)( kpa) ( kpa) 1000 (304.8 m) 2000 (609.6 m) DEPTH FTTVD 3000 (914.4 m) 4000 ( m) 5000 (1524 m) 6000 ( m) 7000 ( m) Gas Lift Response Curve Total Liquid Rate (stb/lpd) (SCM/Day) (190.8) (159) (127.2) (95.4) (63.6) (31.8) TUBING PRESSURE CASING PRESSURE FBHP DRAWDOWN SIBHP (5663) (11 327) (16 990) (22 653) (28 317) (33 980) (39 643) (45 307) (50 970) (56 634) (62 297) (67 960) Gas Lift Rate: QG (Mscf/Day) (SCM/Day) Economic limit of gas injected is often ½ of that needed for max oil rate IPR Base 72

73 Improving Lift Efficiency 3500 (556.5) Production Rate (bbls/d (SCM/Day) 3000 (477) 2500 (397.5) 2000 (318) 1500 (238.5) 1000 (159) 500 (79.5) 0 Shallow injection depth Deep injection depth (14 158) (28 317) (42 475) (56 634) (70 792) Gas Lift Efficiency Checklist Gas Injection Rate (MMSCFD) (SCM/Day) Single point lifting Deeper lift (high gas lift pressure, OR using the available lift gas pressure) Low tubing head pressure (reduced back pressure) Optimum gas lift injection rate Optimum sized tubing and surface flowline Clean tubing and surface piping Corrosion / Scale monitoring Surveillance / Optimization systems in place 73

74 Troubleshooting: Surface Tools When Strip gas-lifted charts producers (electronic) are losing continuous fluid production, display identify if the problem Flowing is: Tubing pressure Inflow related Casing (Gas Lift injection) pressure Outflow related Gas lift injection rate Other data (e.g., flowline temperature) Other data (manifold pressure, flowline temperature, etc.) Production Well Tests CO 2 Tracer Echometer Troubleshooting: Downhole Tools Flowing bottom-hole pressure and temperature surveys To optimize gas lift To gather periodic data Flowing pressure / temperature gradient surveys Identify lift problems in the string Optimize gas lift in the well Update / Calibrate well flow model Production Logging / Temperature logging Identify plugged up / non-contributing perfs Water production profile of the producing zone Pressure build up surveys Evaluate skin data Estimate average reservoir pressure FGS Survey: Extremely valuable! 74

75 Flowing gradient surveys performed with Wireline Example Well-08A Surface Equipment 1. Wireline Stuffing Box 2. Upper Section 3. Quick Union 4. Rope Blocks 5. Telescopic Gin Pole 6. Middle Section 7. Lower Section 8. Bleed-off Valve 9. Wireline Valve 10. Wireline Pulley 11. Wellhead Connection 12. Weight Indicator 13. Load Binder and Chains 14. Wellhead Adapter Reservoir Details Formation Black Gold Layer pressure 2850 psia ( kpa) Productivity Index- ( PI) STB/psi dd (0.08 m 3 /kpa) P- GOR 450 SCF/STB (80.1 m 3 /m 3 ) Production Total fluid 4935 STBLPD (784.6 m 3 /day) Oil 296 STBOPD (47.06 m 3 /day) BS&W 94%. Pressures Kick off pressure psia ( kpa) Operating casing pressure psia ( kpa) Tubing pressure 195 psia ( kpa) Completion 5 1/2 (0.14 m) Tubing 9 5/8 (0.24 m) Production casing Vertical Producer Gas Lift Design Total Mandrel 11 Unloading valves R-25 P1 PPO valves Lifting Point GLM -11, RCC- 5/8 (0.02 m) Flowing Gradient Survey carried out to ascertain the gas lift performance 75

76 Three Pen Chart at Surface Well 08A Blue Casing pressure Green Lift gas injection rate Red tubing pressure FGS Showing Healthy Gas Lift Performance Tubing Gradient (685.8 m) ( m) Gas Lift Design for Well 08A Corr: B &B (S); Lf=0.74; P bar=2850 psia; Pwf=1162 psia; PI=3.48: (4 C) (27 C) Casing Gradient (49 C) (71 C) (93 C) (116 C) Temperature Gradient ( m) Opening pressures of PPO unloading valves [8274] ( m) [2758] [5516] [kpa] [11 032] [13 790] [16 547] 76

77 FGS Helps Identify Gas Lift Inefficiency in Wells [38 C] [60 C] [82 C] [104 C] [127 C] [149 C] Gas Injection Pressure (762 m) (1524 m) (2286 m) (3048 m) CO 2 Tracer Survey Expected pressure gradient Measured pressure gradient Measured temperature gradient Expected temperature gradient (4137 kpa) (8274 kpa) ( kpa) ( kpa) ( kpa) WellTracer allows to quickly determine lift gas entry points in the well without running downhole tools Detect operating lift depth Detect multiple points of injection / tubing leaks WellTracer creates a snapshot of the well performance by introducing a small volume of CO 2 into the injection line then measuring CO 2 concentration flowing back at the well head The method has some limitations 77

78 CO 2 Tracer Survey Set-up schematic CO 2 Tracer Survey Results Survey showing single lift point Survey showing multiple lift points SPE

79 Session Summary Gas Lift Well Unloading Gas Lift Design using single gas lift mandrel Gas Lift Design using multiple mandrels Design with IPO Unloading valves Design with PPO Unloading valves GL Design Example well Mandrel spacing Valve selection Pressure setting design Orifice sizing Surveillance and Trouble shooting Maintaining Efficiency Surface tools Sub-surface tools GL Well Unloading GL Design with IPO valve string Trouble shooting with Flowing Gradient Surveys 79

80 Gas Lift Optimization Gas Lift Surveillance, Optimization and Three Levels of Optimization Real Time Optimization (RTO) Level I: Individual well performance optimisation More a question of maximising productivity, and not strictly speaking an exercise in resource distribution Completion, stimulation, artificial lift designs, troubleshooting Level II: Allocation of resources to maximise production from a group of wells Can take into consideration costs as well as revenue in deciding where to allocate resources Lift gas allocation, electrical submersible pump (ESP) power distribution Level III: Optimising overall performance of a production system True optimisation problem taking into account various possibilities for revenue generation and different constraints present in the production system System automation through dynamic modelling linked to SCADA 80

81 Lift Gas Allocation (Level II) Available lift gas will be allocated to maximize oil production, considering gas lift efficiency of the wells Excess gas available: Increase lift gas to wells with high GL Efficiency Gas Lift shortage (e.g., compressor issues): Decrease lift gas to wells with low GL efficiency (wells with very low efficiency may be shut-in during the period) GL Efficiency: Volume of oil produced for unit volume of lift gas injected (e.g., BOPD/MMscfd) A Well Efficiency ranking list maintained for this purpose Used to manage short term variations of lift gas supply. Pressure drop in flowlines not taken into account A Typical Gas Lift System Prod Manifold Prod Manifold Lift Gas Manifold Prod Manifold Water Lift Gas Oil Export Gas Fuel Gas External Fuel Supply 81

82 Total System Optimization A total system optimization should consider: Updated well performance with reservoir management considerations Effect of pressure drop in production system Effect of pressure drop in gas lift supply system Compression horsepower, performance, availability and costs An iterative optimal solution with all input constraints considered, to determine: Optimum gas lift rate Optimum gas lift pressure Optimum production separator pressure Include any constraints from reservoir management Production Optimization Cycle Implement new set points; Stabilize wells Gather field data (production/injection); Quality check the data Feed data to asset models and calibrate models Perform optimization calculations and generate new set points SPE