MARCH 1998 INA GAS LIFT SCHOOL PRESENTATIONGas Lift System Design
Advantages & disadvantages of gas lift
Basic introduction to gas lift principles
Continuous flow unloading sequence
INJECTION GAS
PRODUCED FLUID
PRESSURE (PSI)
FBHP
SIBHP
INSTRUCTORS - RB
ATTENDEES / BACKGROUNDS
FINISH FRIDAY LUNCH TIME
Running and pulling gas lift valves
Gas lift valve mechanics
Gas lift mandrels, latches, kickover tools
Surface flow control equipment
FBHP
SIBHP
CONSTANT FLOW GAS LIFT WELL
FIRST DAY WE WILL HAVE CONCENTRATED ON FLUID MECHANICS & ONLY BRIEFLY ON EQUIPMENT.
DAY 2 = APPLYING FLUID PRINCIPLES TO A GAS LIFT DESGIN (SPM SPACING & VALVE CALCS)
THIS FIRST DESIGN CAN BE DONE COLLECTIVELY (PREFERRED) OR INDIVIDUALLY
EQUIPMENT : SPMS - CUT-AWAYS
LATCHES - LATCH PROFILES
EXAMPLES OF FLUID DAMAGE
INJECTION GAS
PRODUCED FLUID
PRESSURE (PSI)
FBHP
SIBHP
CONSTANT FLOW GAS LIFT WELL
BY DAY 3 WE WILL KNOW THE FLUID MECHANIC PRINCIPLES OF GAS LIFT AND THE PERFORMANCE & RELIABILITY OF GAS LIFT EQUIPMENT.
WE ARE NOW IN A POSITION TO DISCUSS WHAT OTHER CONSIDERATION SHOULD BE CONSIDER IN GAS LIFT.
NOW HAVE THE SET OF SKILLS REQUIRED TO DISCUSS GAS LIFT MONIOTING & OPTIMISATION.
‘USING THE SKILL TO OPTIMISE OIL PRODUCTION / REVENUE’
WILL DISCUSS INDIVIDUAL WELL OPTIMISATION & MORE IMPORTANTLY FULL SYSTEM OPTIMISATION. - NEED TO MENTION OUR CREDENTIALS AT BP, DNO, MOBIL LASMO
CLOSE THE DAY BY INITATING A GAS LIFT DESIGN - INDIVIDUALLY.
Schlumberger, 2001
DAY 4
Flowing gradient exercises.
FBHP
SIBHP
CLOSEOUT GAS LIFT DESIGN
GENREALLY - V.RELIABLE
DEMONSTRATION OF RELIABILITY - EMPHASIS MOVED FROM OIL COMPANIES TO SERVICE COMPANIES.
CAMCO’S ELECTRONIC DATA BASE
SPECIAL USES OF GAS LIFT PRINCIPLES & EQUIPMENT
COMPUTER GENERATED GAS LIFT DESIGN - NODAL ANALYSIS TO GENERATE VLP CURVES. STILL SAME PRINCIPLE AS BY HAND - JUST MORE CONTINGENCIES CAN BE CONSIDERED - THEREFORE MORE ACCURATE LIFE OF WELL DESIGNS
Schlumberger, 2001
DAY 5
Gas lift trouble-shooting techniques
Course summary
INJECTION GAS
PRODUCED FLUID
PRESSURE (PSI)
FBHP
SIBHP
CLOSEOUT GAS LIFT DESIGN
GENREALLY - V.RELIABLE
DEMONSTRATION OF RELIABILITY - EMPHASIS MOVED FROM OIL COMPANIES TO SERVICE COMPANIES.
CAMCO’S ELECTRONIC DATA BASE
SPECIAL USES OF GAS LIFT PRINCIPLES & EQUIPMENT
COMPUTER GENERATED GAS LIFT DESIGN - NODAL ANALYSIS TO GENERATE VLP CURVES. STILL SAME PRINCIPLE AS BY HAND - JUST MORE CONTINGENCIES CAN BE CONSIDERED - THEREFORE MORE ACCURATE LIFE OF WELL DESIGNS
Schlumberger, 2001
UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:
Name the 4 major forms of artificial lift.
Fully describe the operation of each.
Site at least 3 advantages and 3 disadvantages of each lift method.
Identify the most appropriate lift method for a given application.
Understand the business relevance of each lift method to Schlumberger.
GAS LIFT OF WATER WELLS.
CONTINUOUS LIFT = STEADY STATE FLOW. MECHANISMS ARE LOWERING DENSITY, EXPANDING GAS & PUSHING TO SURFACE. BUT P & T FOR PROCESS PLANT CONSTANT
INT & PLUNGER = BATCH PRODUCTION, VARING COMPRESOR LOADS AND DESIGNED FOR SLUG/BATCH PRODUCTION. FOR LOW PRODCTIVITY WELLS. MAJOR PROCESS PROBLEMS. PLUNGER USES MECHANICAL INTERFACE. MECHANISM RELIES TOTALLY ON ESTABLISHING A LIQUID GAS INTERFACE & PISTONING LIQUID TO SURFACE
WITHIN GAS LIFT - REQUIRE FLEXIBILITY AS CONDITIONS CHANGED THEREFORE EQUIPMENT IS DESIGNED TO BE RETRIEVED WITHOUT PULLING TUBING TUBING - THEREFORE WIRELINE RETRIEVABLE GAS LIFT EQUIPMENT WILL BE DISCUSSED.
Schlumberger, 2001
‘HORSES FOR COURSE’
ROD PUMPS - MOST ABUNDANT BUT DO NOT ACCOUNT FOR A LOT OF PRODUCTION
RODS = PISTONS/BUCKET FLUID TO SURFACE LAND WELLS, NON DEVIATED, LOW ENERGY USAGE, THEREFORE EFFICIENT FOR LOW RATES
HYD & ESP PUMPS = SAME BUT DIFFERENT METHOD OF POWERING HYD PUMP HAS UMBILICAL LINE WITH HYD. FLUID ROTATING A SHAFT - ESP HAVE ELECTRIC ROTATING SHAFT. ROTATING EQUIPMENT IN LINE OF FLOW & NO PREVENTATIVE MAINTENANCE. CONCERNS WITH SAND & GAS HANDLING. GOOD CONTROL & GOOD FOR LOW RES PRESSURE.
GAS LIFT CONCENTRATE ON LIGHTENING HEAD AS OPPOSED TO REMOVING HEAD.
ACCOUNTS FOR APPROX 60 - 70% OF ART.LIFT PRODUCTION. NEED GAS & RES PRESSURE
GAS LIFT CONTINUATION OF THE WAY A WELL NATURALLY FLOWS - CONCEPT OF BUBBLE POINT
Schlumberger, 2001
EXAMPLE
Average production: 1800 bbls/D @ 10% water cut.
Average production depth: 5500 ft MD
2-7/8” 6.5# tubing x 7-in 29# casing
Dogleg: 5 degrees / 100 ft.
BHT = 300 deg. F, Anticipated FBHP of 500 psi
1 Safety Barrier (SCSSV)
It will not be necessary to access reservoir until re-completion.
Stable formation on primary recovery.
Fluid Viscosity = 50 cp, GOR = 500 scf/bbl, VLR = 0.07
Sand production = 15 ppm
Electric power generation using natural gas for fuel
All well service via workover rig and snubbing unit.
GAS LIFT OF WATER WELLS.
CONTINUOUS LIFT = STEADY STATE FLOW. MECHANISMS ARE LOWERING DENSITY, EXPANDING GAS & PUSHING TO SURFACE. BUT P & T FOR PROCESS PLANT CONSTANT
INT & PLUNGER = BATCH PRODUCTION, VARING COMPRESOR LOADS AND DESIGNED FOR SLUG/BATCH PRODUCTION. FOR LOW PRODCTIVITY WELLS. MAJOR PROCESS PROBLEMS. PLUNGER USES MECHANICAL INTERFACE. MECHANISM RELIES TOTALLY ON ESTABLISHING A LIQUID GAS INTERFACE & PISTONING LIQUID TO SURFACE
WITHIN GAS LIFT - REQUIRE FLEXIBILITY AS CONDITIONS CHANGED THEREFORE EQUIPMENT IS DESIGNED TO BE RETRIEVED WITHOUT PULLING TUBING TUBING - THEREFORE WIRELINE RETRIEVABLE GAS LIFT EQUIPMENT WILL BE DISCUSSED.
Schlumberger, 2001
KEY LEARNING OBJECTIVES
UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:
Describe the two different types of gas lift and where they are applied.
List the surface and sub-surface components of a typical closed rotative gas lift system.
Describe, in detail, the continuous unloading sequence.
Explain the purpose of unloading valves in a continuous gas lift well.
GAS LIFT OF WATER WELLS.
CONTINUOUS LIFT = STEADY STATE FLOW. MECHANISMS ARE LOWERING DENSITY, EXPANDING GAS & PUSHING TO SURFACE. BUT P & T FOR PROCESS PLANT CONSTANT
INT & PLUNGER = BATCH PRODUCTION, VARING COMPRESOR LOADS AND DESIGNED FOR SLUG/BATCH PRODUCTION. FOR LOW PRODCTIVITY WELLS. MAJOR PROCESS PROBLEMS. PLUNGER USES MECHANICAL INTERFACE. MECHANISM RELIES TOTALLY ON ESTABLISHING A LIQUID GAS INTERFACE & PISTONING LIQUID TO SURFACE
WITHIN GAS LIFT - REQUIRE FLEXIBILITY AS CONDITIONS CHANGED THEREFORE EQUIPMENT IS DESIGNED TO BE RETRIEVED WITHOUT PULLING TUBING TUBING - THEREFORE WIRELINE RETRIEVABLE GAS LIFT EQUIPMENT WILL BE DISCUSSED.
Schlumberger, 2001
CONTINUOUS LIFT = STEADY STATE FLOW. MECHANISMS ARE LOWERING DENSITY, EXPANDING GAS & PUSHING TO SURFACE. BUT P & T FOR PROCESS PLANT CONSTANT
INT & PLUNGER = BATCH PRODUCTION, VARING COMPRESOR LOADS AND DESIGNED FOR SLUG/BATCH PRODUCTION. FOR LOW PRODCTIVITY WELLS. MAJOR PROCESS PROBLEMS. PLUNGER USES MECHANICAL INTERFACE. MECHANISM RELIES TOTALLY ON ESTABLISHING A LIQUID GAS INTERFACE & PISTONING LIQUID TO SURFACE
WITHIN GAS LIFT - REQUIRE FLEXIBILITY AS CONDITIONS CHANGED THEREFORE EQUIPMENT IS DESIGNED TO BE RETRIEVED WITHOUT PULLING TUBING TUBING - THEREFORE WIRELINE RETRIEVABLE GAS LIFT EQUIPMENT WILL BE DISCUSSED.
Schlumberger, 2001
TO ENABLE WELLS THAT WILL NOT FLOW NATURALLY TO PRODUCE
TO INCREASE PRODUCTION RATES IN FLOWING WELLS
TO UNLOAD A WELL THAT WILL LATER FLOW NATURALLY
TO REMOVE OR UNLOAD FLUID IN GAS WELLS
TO BACK FLOW SALT WATER DISPOSAL WELLS
TO LIFT AQUIFER WELLS
Schlumberger, 2001
Simplified well completions
Can best handle sand / gas / well deviation
Intervention relatively less expensive
MOST PEOPLE SUGGEST IT IS CHEAPEST - BUT COST OF ADDITIONAL PIPEWORK, CONTROL VALVES & COMPRESSOR & INCREASE IN SAFETY REQUIREMENTS IS NOT CHEAP. HOWEVER, THESE COSTS CAN BE SHARED BY NUMMEROUS WELLS - SO IN MOST CASE IT IS THE LOWEST CAPITAL & OPERATING COST PER UNIT WELL IN A LOT OF CASES
FLEXIBILITY IS SURPRISING - 10 blpd PWOULD BE INTERMITTENT LIFT
IN THE FURTURE HANDLING SAND, GAS & DEVIATION WILL BE IMPORTANT.
Schlumberger, 2001
Imported from other fields
Possible high installation cost
Compressor installation
Limited by available reservoir pressure
and bottom hole flowing pressure
PUMPS HAVE MORE CONTROL AND REMOVE THE HEAD FROM THE RESERVOIR. IF PUMPS HAD INFINITE RUN LIVES - THEN ESPS WOULD BE ALMOST EXCLUSIBVELY USED. LIMITATIONS ON THE PUMP OOPERATING CONDITIONS MAKE GAS LIFT THE PREFERRED IN THOSE CASE. DECISION IS PUIRELY COMMERCIAL,.
Schlumberger, 2001
INJECTION GAS
PRODUCED FLUID
PRESSURE (PSI)
ENGINEERS BIBLE = P v D PLOT
GO THROUGH AXES AND WHERE GAS IS COMING FROM & HOW GAS IS ROUTED TO THROUGH THE WELL
FACTORS DICTATING POINT OF INJECTION - CHP, WHP, RES PRESSURE
CAN INFLUENCE POINT OF INJECTION WITH GAS INJECTION RATE.
AFFECT OF CHANGES IN WATER CUT
AFFECT OF CHANGE IN WHFP
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INJECTION GAS
PRODUCED FLUID
PRESSURE (PSI)
OPERATING GAS LIFT
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CONTINUOUS FLOW UNLOADING SEQUENCE
CONTINUOUS FLOW GAS LIFTED WELLS ARE DESIGNED TO OPERATE STABILY AND AT STEADY STATE CONDITIONS - THE ONLY TIME IT IS DESIGNE DTO PERATE UNSTABILY (SLUGGING) IS DURING THE UNLOADING SEQUENCE.
NOTE - IN THIS SECTION WILL NEED TO USE FIGURE 3 TO ILLUSTRATE A SINGLE POINT INJECTION DESIGN.
NEED TO DISCUSS THE MERITS OF UNLOADING VALVES VERSUS ADDITIONAL COMPRESSOR
- HIGH PRESSURE GAS LINE RATINGS, COST OF ADDITIONAL COMPRESSOR, OPERABILITY PROBLEMS (SIZE OF SLUG = LENGTH OF LFUID x ENERGY BEHINDTHE SLUG)
Schlumberger, 2001
INJECTION GAS
Schlumberger, 2001
NOTE - IN THIS SECTION WILL NEED TO USE FIGURE 3 TO ILLUSTRATE A SINGLE POINT INJECTION DESIGN.
NEED TO DISCUSS THE MERITS OF UNLOADING VALVES VERSUS ADDITIONAL COMPRESSOR
- HIGH PRESSURE GAS LINE RATINGS, COST OF ADDITIONAL COMPRESSOR, OPERABILITY PROBLEMS (SIZE OF SLUG = LENGTH OF LFUID x ENERGY BEHINDTHE SLUG)
Schlumberger, 2001
1 - 2 bbl per min
Maximize production choke opening
Monitor well clean up and stability
Get to target position
Optimize gas injection rate
Schlumberger, 2001
KEY LEARNING OBJECTIVES
UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:
Explain the procedure for running and pulling gas lift valves from a side pocket mandrel.
Describe the precautions that should be taken during running and pulling operations.
Explain the operation of the OK series kickover tool.
Explain the operation of the BK-1 latch.
List and describe the different latch profiles available and explain the importance of latch / pocket compatability.
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KICKOVER TOOL
THE KICKOVER TOOL IS RUN ON WIRELINE AND USED TO PULL AND SET GAS LIFT VALVES. THE ABILITY TO WIRELINE CHANGE-OUT GAS LIFT VALVES GIVES GREAT FLEXIBILITY IN THE GAS LIFT DESIGN
KICKOVER TOOLS - SHOW THE KICKOVER MODEL
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UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:
Understand the purpose of a gas lift valve latch.
Identify key latch components.
Schlumberger, 2001
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END DAY 1
CONTINUOUS FLOW GAS LIFTED WELLS ARE DESIGNED TO OPERATE STABILY AND AT STEADY STATE CONDITIONS - THE ONLY TIME IT IS DESIGNE DTO PERATE UNSTABILY (SLUGGING) IS DURING THE UNLOADING SEQUENCE.
NOTE - IN THIS SECTION WILL NEED TO USE FIGURE 3 TO ILLUSTRATE A SINGLE POINT INJECTION DESIGN.
NEED TO DISCUSS THE MERITS OF UNLOADING VALVES VERSUS ADDITIONAL COMPRESSOR
- HIGH PRESSURE GAS LINE RATINGS, COST OF ADDITIONAL COMPRESSOR, OPERABILITY PROBLEMS (SIZE OF SLUG = LENGTH OF LFUID x ENERGY BEHINDTHE SLUG)
Schlumberger, 2001
DAY 2
Gas lift mandrels
Surface flow control equipment
FBHP
SIBHP
CONSTANT FLOW GAS LIFT WELL
FIRST DAY WE WILL HAVE CONCENTRATED ON FLUID MECHANICS & ONLY BRIEFLY ON EQUIPMENT.
DAY 2 = APPLYING FLUID PRINCIPLES TO A GAS LIFT DESGIN (SPM SPACING & VALVE CALCS)
THIS FIRST DESIGN CAN BE DONE COLLECTIVELY (PREFERRED) OR INDIVIDUALLY
EQUIPMENT : SPMS - CUT-AWAYS
LATCHES - LATCH PROFILES
EXAMPLES OF FLUID DAMAGE
UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:
Understand the features / benefits, operation and nomenclature of:
Orienting-style mandrels.
Non-orienting mandrels.
Conventional mandrels.
Identify an appropriate SPM based on its nomenclature.
Explain advantages and disadvantages of oval / round GLM’s.
Understand SPM manufacturing processes.
MANDREL - HOLDS THE TOOL IN THIS CASE THE VALVE
CONVENTIAONL V’S WIRELINE RETRIEVABLE
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DISCUSS THE DIFFERENT METALLURGIES AND DIFFICULTIES WITH WELDING & TREATING ESPECICALLY INCONEL.
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R
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KEY LEARNING OBJECTIVES
UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:
Derive the formula for opening pressure based on knowledge of valve mechanics and the force-balance equation.
Describe models, operation, features/benefits, pros and cons of:
Unloading Valves
Schlumberger, 2001
3 basic types of gas lift valve, each available in 1” & 1-1/2” sizes:
Dummy valves
Orifice valves
Unloading valves
Square edged
Venturi (nova)
Throttling/proportional response valves
Normally required during unloading phase only
Open only when annulus and tubing pressures are high enough to overcome valve set pressure
Valve closes after transfer to next station
May be spring or nitrogen charged
UNLOADING VALVES - DESIGNED TO CLOSED. PRESSURE REGULATORS - DIFFERENT CLOSING MECHANISMS *WHY SPRING? WHY NITROGEN)
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Pressure Regulator
Downstream/Tubing
BASICALLY A PRESSURE REGULATOR OR PRV -SET TO RELIEVE PRESSURE FROM THE CASING.
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TO OPEN IT…..
Pd
Pc2
TO CLOSE IT…..
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OPENING FORCES (IPO VALVE) Fo1 = Pc (Ab- Ap)
Fo2 = Pt Ap
Pc (Ab - Ap) + Pt Ap = Pb Ab
Pb - Pt (Ap/Ab)
Pt = Tubing pressure
Pc = Casing pressure
Ab = Area of bellows
Ap = Area of port
VALVE OPENING & CLOSING PRESSURES
NOTE ; ‘UNBALANCED’ OPENING FORCE IN TERMS OF THE CASING PRESSURE IS DIFFERENT THAN THE CLOSING PRESSURE IN TERMS OF THE CASING PRESSURE. THE FORCES REMAIN CONSTANT BUT THE AFFECTED AREAS ON WHICH THE CASING ORESSURE ACTS CHANGES
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INJECTION GAS
PRODUCED FLUID
0
2000
6000
8000
10000
12000
14000
4000
1000
2000
R = 0.038 1-R = 0.962
TUBING P.
Chevron
Packing
Stack
Pt
Pc
Pb
Dome
Bellows
Chevron
Packing
Stack
Chevron
Packing
Stack
Atmospheric
Bellows
Chevron
Packing
Stack
Spring
Adjustment
always open - allows gas across 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
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ORIFICE VALVES
SQUARED EDGED ORIFICE
One-way check valve for tubing integrity.
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NOVA VALVE
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EQUIPMENT SUMMARY
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UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:
Describe models, operation, features/benefits, pros and cons of:
Flow Control Valves
Adjustable Choke Valves
Tailor talk to group/issues. Commerical, technical, strategic, organisational, business position, etc.
Intro: Who I am, in the next xx minutes, we’ll talk about:
Fundamental roles of Clients, GeoMarkets and Segments in the new org.
The risk of ‘commodotization’ in well completion.
Our vision of the future products of SLB as a completions company, and ultimately a ‘Res Mon & Control’ company.
A ‘Capability’ we will need to get there: Reserv Compl Syst Group, it’s charter and makeup.
A vision for WCP in the Areas/GeoMarkets in the future.
WCP Marketing Challenges this year and some specifics on our Multilaterals and Intelligent completions hardware.
And finally a game for everyone: Where was the upstream value added?
Discussion along the way is welcome.
Schlumberger, 2001
Primary Purpose
Control and measure flow from a producing oil and gas well, secondary recovery water or gas injection well and injected gas in a gas lift field operation.
Secondary Purpose
Real time flow control measurement which allows precise valve positioning from a remote RTU by use of an electric actuator with 4-Milliamps or digital hart communication control.
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Platform gas lift manifolds
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Packing and trim changed without removing body from line
Easy-to-read indicator
Variety of trim sizes,
CN00998
Floating seat acts as check valve to prevent reverse flow
Camco/Merla FCV flow control valve
CN00998
CN00998
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Applicable for service with other high-temperature gas or liquids
Easy-to-read 1/64 in. indicator scale
Rated to 3500 psi at 700°F
2-in. angle body with various trim sizes and materials
CN01000
Long throat seat controls turbulence and erosion
Adjustable hand wheel calibrated in 1/64 in. with
easy-to-read indicator
CN01026
Three body sizes for accurate match to flow rate
ACV-5, ACV-8 and ACV-12
Available with API or ANSI flanges, socket weld, butt weld
or threaded connections
No stem leaks with spring-loaded, bubble-tight sealing system
CN00997
CN01002
CN01003
ACV-5
ACV-8
ACV-12
3/4-in., 1-in. and 11/4-in. port sizes
Maximum Cv values:
19.3 to 35
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1-in., 11/2-in. and 2-in. port sizes
Maximum Cv values: 30.8 to 85.8
High differential pressure applications
Optional positive choke bean
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Maximum Cv values: 124 to 285
High differential pressure applications
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Reduce cavitation or erosion damage
Cavrosion trim
Actuators for electric control and automation systems
Available for FCV and ACV series valves
120 Vac or 24 Vdc with low current draw for remote applications
High modulation rate for precise positioning
4-20 ma or Digital Hart communication control
Corrosion resistance housing
Beans easily replaced with body in flow line
In-line feature for bi-directional flow
Camco/Merla positive in-line choke
Motor valves for on-off service
Intermittent lift control
Plunger lift control
Pressure regulators
SLB International locations
High pressure niche market
Complete 10k product design for speciality markets
Schlumberger, 2001
Current Projects
Performing test with FCV/Jordan electric actuators using different material combinations, and thread types with and without special antigauling coating.
Complete conversions of all flow control products to sherpa.
Schlumberger, 2001
END DAY 2
CONTINUOUS FLOW GAS LIFTED WELLS ARE DESIGNED TO OPERATE STABILY AND AT STEADY STATE CONDITIONS - THE ONLY TIME IT IS DESIGNE DTO PERATE UNSTABILY (SLUGGING) IS DURING THE UNLOADING SEQUENCE.
NOTE - IN THIS SECTION WILL NEED TO USE FIGURE 3 TO ILLUSTRATE A SINGLE POINT INJECTION DESIGN.
NEED TO DISCUSS THE MERITS OF UNLOADING VALVES VERSUS ADDITIONAL COMPRESSOR
- HIGH PRESSURE GAS LINE RATINGS, COST OF ADDITIONAL COMPRESSOR, OPERABILITY PROBLEMS (SIZE OF SLUG = LENGTH OF LFUID x ENERGY BEHINDTHE SLUG)
Schlumberger, 2001
DAY 3
“WELL PERFORMANCE”
INJECTION GAS
PRODUCED FLUID
PRESSURE (PSI)
FBHP
SIBHP
CONSTANT FLOW GAS LIFT WELL
BY DAY 3 WE WILL KNOW THE FLUID MECHANIC PRINCIPLES OF GAS LIFT AND THE PERFORMANCE & RELIABILITY OF GAS LIFT EQUIPMENT.
WE ARE NOW IN A POSITION TO DISCUSS WHAT OTHER CONSIDERATION SHOULD BE CONSIDER IN GAS LIFT.
NOW HAVE THE SET OF SKILLS REQUIRED TO DISCUSS GAS LIFT MONIOTING & OPTIMISATION.
‘USING THE SKILL TO OPTIMISE OIL PRODUCTION / REVENUE’
WILL DISCUSS INDIVIDUAL WELL OPTIMISATION & MORE IMPORTANTLY FULL SYSTEM OPTIMISATION. - NEED TO MENTION OUR CREDENTIALS AT BP, DNO, MOBIL LASMO
CLOSE THE DAY BY INITATING A GAS LIFT DESIGN - INDIVIDUALLY.
Schlumberger, 2001
KEY LEARNING OBJECTIVES
UPON COMPLETION OF THIS SEGMENT, YOU SHOULD BE ABLE TO:
Use the linear PI relationship to predict a well’s production.
Explain the difference between a linear and non-linear IPR relationship.
Understand the factors affecting a well’s inflow performance.
Understand the factors affecting a well’s outflow performance.
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Predicting Flowrates and Pressure Transients for Different Cases
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INJECTION GAS
PRODUCED FLUID
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TYPES OF RESERVOIR DRIVES
Dissolved / solution gas drive
Water drive
RESERVOIR DRIVE MECHANISM - HOW FLUID IS DRIVEN FROM THE EXTRIMITY OF THE RESERVOIRS TO THE WELL BORES
DEPLETION DRIVE WILL BE MENTION.
THIS IS CLASSICAL RES ENG - AND NORMALLY THE TOTAL DRIVE IN ARESERVOIR WILL INCLUDE ELEMENTS OF EACH TYOE
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CONCEPT = PRESSURE DROPS DUE TO LOSS OF VOIDAGE, THIS ENCOURAGES GAS TO BREAKOUT AND THE LIQUD TO EXPAND. AS GAS OCCUPIES LARGE VOL THAN THE LIQUID THE LIQUID IS PUSHED THROUGH THE MATRIX
INEFFICENT DRIVE MECHANISM.
DISSOLVED / SOLUTION GAS DRIVE
No gas cap
PI not linear
Least efficient with circa 15% recovery
GAS IS DISSOLVED - AS GAS ESCAPES FROM OIL - BUBBLES EXPAND AND THIS PRODUCES A FORCE ON THE OIL DRIVING IT TO WELL.
LEAST EFFECTIVE
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HYDRO-CARBON IS SATURATED/SUPER-SATURATED WITH GAS. THE EXCESS GAS MIGRATE OVER GEOLOGICAL TIME TO THE TOP OF RESERVOIR. THE EXPANDING MOTION OF THE GAS MAINTAINS FLUID FLOW TO THE WELL BORE.
WILL ONLY RECOVER 25% OF OIP.
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GAS CAP DRIVE
Excessive drawdown can cause coning
PI usually not linear
Circa 25% recovery
SURPLUS GAS…