Gas Lift Presentation #1

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
Natural gas laws applied to gas lift.
Flowing gradient exercises.
FBHP
SIBHP
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.
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DAY 4
Gas lift design methods.
IPO Gas lift design
PPO Gas Lift Design
Gas lift trouble-shooting techniques
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
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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.
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‘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
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EXAMPLE
Average production: 1800 bbls/D @ 10% water cut.
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.
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KEY LEARNING OBJECTIVES
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.
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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
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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.
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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,.
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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)
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INJECTION GAS
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1 - 2 bbl per min
Maximize production choke opening
Monitor well clean up and stability
Get to target position
Optimize gas injection rate
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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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Understand the purpose of a gas lift valve latch.
Identify key latch components.
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END DAY 1
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DAY 2
Gas lift mandrels
Surface flow control equipment
FBHP
SIBHP
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
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
T
A
EC
W
V
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
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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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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.
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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
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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.
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END DAY 2
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DAY 3
Natural gas laws applied to gas lift.
Flowing gradient exercises.
FBHP
SIBHP
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.
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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 FORMS CAP
GAS CAP SOURCE OF ENERGY
YOU CAN PULL SO HARD ON RESERVOIR THAT YOU WILL GET GAS OUT BEFORE OIL - CONING
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IS WIDELY ADUNDANT MECHANISM IN LARGE PROLIFIC FIELDS. EITHER AN AQUIFER OF COMPRESSED WATER DISPLACES AND HENCE DRIVES THE HYDROCARBON/RESERVOIR FLUIDS TO THE WELL BORE.
VERY EFFICIENT METHOD - AS SURFACE CONTACT AND A SWEEP ACTION
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WATER DRIVE
Water 1 in 2500 per 100 psi
PI more constant
GOR more constant
Often supplemented by water injection
Most efficient with upto 50% recovery
COMPRESSIBILTY OF WATER IS DRIVE MECHANISM
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DEPLETION DRIVE
Natural flow initially
Continuous gas lift
Intermittent gas lift
FOUND WHERE THE RESERVOIR IS ISOLATED THROUGH FAULTS/FRACTURES. BECAUSE THE VOID IS LIMITED THE RESERVOIR PRESSURE QUICKLY DEPLETS.
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Effects at boundaries
Position of well
Non homogeneous reservoir
Depletion if reservoir
Flow restrictions (skin)
Straight line productivity index (PI)
Inflow performance relationship (IPR)
PRODUCTIVITY INDEX
The relationship between well inflow rate and pressure drawdown can be expressed in the form of a Productivity Index, denoted ‘PI’ or ‘J’, where:
q
Pws - Pwf
kh(Pav - Pwf)
FACTORS AFFECTING PI
1. Phase behaviour
Bubble point pressure
Dew point pressure
2. Relative permeability behaviour
Ratio of effective permeability to a particular fluid (oil, gas or water) to the absolute permeability of the rock
3. Oil viscosity
Viscosity increases as gas comes out of solution
4. Oil formation volume factor (bo)
As pressure is decreased the liquid will expand
As gas comes out of solution oil will shrink
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Laminar > turbulent flow
WELL & RESERVOIR INFLOW PERFORMANCE
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INFLOW PERFORMANCE RELATIONSHIP
Normalized pseudo pressure
THERE ARE NUMMEROUS METHODS FOR CONSIDERING THE ONFLOW FROM A WELLBORE. THE MOST COMMONLY USED IN GAS LIFT ARE STRAIGHT LINE PI & VOGEL
VOGEL ACCOUNTS FOR THE LOSS OF PERMEABILITY TO LIQUIDS WHEN GAS HAS BROKEN OUT OF SOLUTION AND IS COMPTEING FOR THE PORE THROATS. - HENCE SUB-BUBBLE POINT
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VOGEL
Q/Qmax = 1 - 0.2(Pwf/Pws) - 0.8(Pwf/Pws)2
Qmax = the maximum liquid rate for 100% drawdown
Pwf = bottom hole flowing pressure, psi
Pws = the reservoir pressure, psi
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Sheet: Sheet1
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MULTIPHASE FLOW
OUTFLOW PERFORMANCE
Vertical flowing gradients
Horizontal flowing gradients
FACTORS WHICH AFFECT THE PREDICTION OF PRESSURE DROPS IN MULTI-PHASE FLOW
FLUID VISCOSITY AND DENSITY HAS GREATER EFFECT ON VERTICAL HYDRAULIC PERFORMANCE THAN FACTORS SUCH AS FRICTION FACOR OF PIPE. VISCOSITY IS VERY COMPLICATED DEPENDING ON TEMP, PRESS, EMULSION ETC ETC. NEED TO TUNE.
LOOK AT FLOW REGIMES. / REYNOLDS NUMBER.
HORIZONTAL IMPORTANT
LOOK AT VELOCITIES - BP EXPERIENCE IS THAT VELOCITIES OF GREATER THAN 12 ft/sec ADDS TO EROSION/CORROSION. 3.5” SECTION OF FALP COMPLETIONS.
CORRELATIONS - WILL DEPEND ON CRUDE & TYPE OF FLOW. MOST RECENT CORRELATION PREDICT THE FLOW REGIME AND THEREFORE THE PVT DATA IS CRITICAL
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Vertical flowing gradients
Horizontal flowing gradients
Select correct tubing size
Design artificial lift systems
Determine maximum depth of injection
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Tubing id
Wall roughness
Mass energy per unit mass in = energy out
(+ - exchange with surroundings)
Integrated each section
Z
(P/(Z
TOTAL
PRESSURE
DIFFERENCE
GRAVITY
TERM
ACCELERATION
TERM
FRICTION
TERM
THIS EQUATION IS THE CORE PRINCIPLE IN NODAL ANALYSIS. THE MAJORITY OF THE PRESSURE DROP IN AN OIL WELL IS DUE TO GRAVITY WHOCH IS DEPENDENT ON PVT. FRICTION ACCOUNTS FOR ONLY 5 - 20 %
IN GAS WELL FRICTION IS THE MOST IMPORTANT.
PVT DESCRITPIONS OF THE OIL IS VERY IMPORTANT.
(P/(Ztotal = g/gc(cos( + f(v2/2gcd + (v/gc[(P/(Z]
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Errors would be accumulative
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OVERLAY OF THE INFLOW & OUTFLOW CURVE PREDICTS THE FLOWRATE FORM THE WELL. AS CAN BE SEEN TO SOME POINT - USING COMPUTATIONAL TECHNIQURES - THIS IS AN ITEREATIVE PROCESS.
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FROM THE PREVIOUS CURVE FOR THE TUBING CURVE AT DIFFERENT GAS INJECTION RATE ONE CAN PLOT THE FLOW RATES AND IT GIVE A PERFORMANCE CURVE
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Predict the casing pressure at depth for a gas lift well.
Predict the gas passage through a square-edged orifice.
Explain the relationship between a valve’s bellows pressure and its temperature
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Gas injection pressure at depth
Gas volume stored within a conduit
Temperature effect on bellows-charged dome pressure
Volumetric gas throughput of a choke or g.L. Valve port
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GAS INJECTION PRESSURE AT DEPTH
S.G. x L
P@L = P@Se
S.G. = Gas Specific Gravity
and average pressure
GAS INJECTION PRESSURE AT DEPTH
“Rule of thumb” Equation based on S.G. of 0.65,
a geothermal gradient at 1.60F/100ft and a surface
temperature of 700F
100 1000
P@S = Pressure at surface, psia
L = Depth, feet
Internal capacity of a single circular conduit
Q(ft3/100ft.) = 0.5454 di2
Q(barrels/100ft.) = 0.009714 di2
Q(ft3/100ft.) = 0.5454 di2 - do2
Q(barrels/100ft.) = 0.009714 di2 - do2
do = outside diameter in inches
THIS CALCULATION TOGETHER WITH THE NEXT SLIDE IS OF PARTICULAR PERTINENCE TO INTERMITTENT GAS LIFT LIFT & ALSO FOR CALCULATING THE INVENTORY OF GAS IN ASV APPLICATIONS.
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To find the volume of gas contained under specific
well conditions):
Where: b = gas volume at base conditions
V = capacity of conduit in cubic feet
P = average pressure within conduit
Tb= temperature base in degrees Rankin
Z = compressibility factor for average pressure and
temperature in a conduit (see Figure 3.2)
Pb= pressure base (14.73 psi)
T = average temperature in the conduit in degrees Rankin
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Major Advantages of Nitrogen
P2 = P1 X Tc
P2 = Pressure resulting from change of temperature
Tc = Temperature correction factor
Tc = --------------------------------
Where : T1 = Initial temperature, Deg F
T2 = Present temperature, Deg F
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VOLUMETRIC GAS THROUGHPUT OF A CHOKE OR A GAS LIFT VALVE PORT
Equation based on Thornhill-Craver Studies
Page 3-13
obtaining an approximate gas passage rate for a
given port size
THERE HAS BEEN DISCUSSION BETWEEN USING THE CRANE EQUATION WITH DISCHARGE COEFFICIENT COMPARED WITH THE THORNHILL -CRAVER
TUALP COMING UP WITH EQUATION TAKING INTO ACCOUNT TEMP AROUND BELLOWS, THROTTLING FLOW ETC ETC.
REYNOLDS NUMBER - IF HIGH OR IF MIST FLOW CAUSES EXTRA FRICTION - LESS OUT BUT MORE STABLE
ORIFICE FLOW - NEEDS 30 PIPE DIAMETERS - FROM RESTRICTION TO BE IN GOOED FLOW. IN GAS LIFT VALVE THIS IS NOT POSSIBLE, HENCE HIGHER THAN EXPECTED (AND EMPIRICALLY DERIVED ARE BEST) DISCHARGE COEFFICIENTS ARE USED.
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PRESSURE (PSI)
GAS INJECTION RATE (MMSCF/D)
GAS PASSAGE THROUGH A GLV DEPENDS ON THE TYPE OF VALVE. HERE IT COMPARES A THROTTLING TYPE VALVE (PROP RESP) TO A SQUARE-EDGED ORIFCE CASING PRESSURE OPERATED VALVE
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THIS ILLUSTRATES THAT THE ACCURACY OF PREDICTING THE FLOW THROUGH A SQUARE-EDGED ORIFICE IS HIGH COMPARED WITH EXPEREIMENTAL DATA.
26.unknown
END DAY 3
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DAY 4
IPO Gas lift design
PPO Gas Lift Design
Gas lift trouble-shooting techniques
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
Perform a gas lift design for a well utilizing injection pressure operated gas lift valves.
List at least 3 possible sources of design bias in an IPO gas lift design.
Explain the purpose of design bias and its effect on a gas lift design.
Understand how a gas lift design can be developed to accommodate changing conditions over time.
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MANDREL SPACING
For unloading
For flexibility
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Pmax / P min
Casing Pressure drop
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Introduce ‘design bias’
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Fixed rate design
Optimum rate design
FIGURE 1
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DEPTH OF WELL (MID PERFS)
S.I.B.H.P.
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FLOWING GRADIENT 2000 BPD, 99% W.C.,0 GLR
S.I.B.H.P.
F.B.H.P.
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FLOWING GRADIENT 2000 BPD, 99% W.C.,1000:1 GLR
S.I.B.H.P.
F.B.H.P.
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0.465 psi/ft
MANDREL #1
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0.465 psi/ft
F.B.H.P. #1
MANDREL #1
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0.465 psi/ft
MANDREL #2
F.B.H.P. #2
MANDREL #1
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MANDREL #2
MANDREL #3
0.465 psi/ft
F.B.H.P. #3
MANDREL #1
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MANDREL #4
MANDREL #2
0.465 psi/ft
F.B.H.P. #4
MANDREL #1
MANDREL #3
Schlumberger, 2001
FIGURE 10
MANDREL #4
MANDREL #2
0.465 psi/ft
MANDREL #5
F.B.H.P. #5
MANDREL #1
MANDREL #3
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Valve #1
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GRADIENT CURVE - MANDREL SPACING
WATERCUT : 50 %
SHUT IN BOTTOM HOLE PRESSURE : 2800 psig
PRODUCTIVITY INDEX : .65 stb/d/psi
AVAILABLE GAS FOR INJECTION : 1 MMSCF/D
TEMPERATURE @ DEPTH : 210O F
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Tubing head pressure
Re-opening valves / Valve interference
Differential at bottom point
Gas passage
Ptmin-Ptmax Method - with Design Bias
FIGURE 1
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S.I.B.H.P.
STATIC GRADIENT (0.465 PSI/FT)
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CAMCO GAS LIFT TECHNOLOGY - EXAMPLE DESIGN
S.I.B.H.P.
F.B.H.P.
Schlumberger, 2001
FLOWING GRADIENT 2000 BPD, 99% W.C.,1000:1 GLR
S.I.B.H.P.
F.B.H.P.
Schlumberger, 2001
0.465 psi/ft
MANDREL #1
Schlumberger, 2001
0.465 psi/ft
F.B.H.P. #1
MANDREL #1
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Ptmin1
0.465 psi/ft
MANDREL #2
F.B.H.P. #2
MANDREL #1
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Ptmax2
MANDREL #2
0.465 psi/ft
F.B.H.P. #3
MANDREL #1
MANDREL #3
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MANDREL #2
0.465 psi/ft
F.B.H.P. #4
MANDREL #3
MANDREL #1
MANDREL #4
Schlumberger, 2001
FIGURE 10
MANDREL #2
0.465 psi/ft
MANDREL #5
F.B.H.P. #5
MANDREL #1
MANDREL #3
MANDREL #4
Schlumberger, 2001
Perform a gas lift design for a well utilizing production pressure operated gas lift valves.
Explain the purpose of the “Design Line” in a PPO gas lift design.
Explain the purpose of the “DP Line” in a PPO gas lift design.
Understand the benefits and liabilities of PPO gas lift designs.
Explain where a PPO gas lift installation would most likely be run and why.
Schlumberger, 2001
List 5 tools that can aid in the trouble-shooting of gas lift wells.
Understand the relationship between gas passage, valve mechanics, well performance and casing pressure.
Utilize gradient curves, valve mechanics and gas passage to predict the point (or points) of injection in a gas lift well.
Explain the cycle of instability in a well which is injecting in sub-critical flow across a square-edged orifice.
Explain how to determine if the tubing and casing are in communication.
Schlumberger, 2001
GAS INJECTION (PRODUCTION ANNULUS) PRESSURE
GAS INJECTION RATES
TUBING HEAD PRESSURE
TEMPERATURE
SLUGGING : AN UNSTABLE SYSTEM SHOULD BE INVESTIGATED. SEVERE SLUGGING IS A MAJOR CONCERN.
THE INITIAL START-UP AND LOADING IS THE WHEN THE WELL IS AT IT’S MOST UNSTABLE.
DIAGNOSING 1) THERE IS A PROBLEM 2) WHAT IS IT 3) HOW DO WE FIX IT.
SINGLE MOST IMPORTANT READING IS CASING PRESSURE.
Schlumberger, 2001
INJECTION PRESSURE :
AND THE MAXIMUM DEPTH OF INJECTION
CHANGE IN THE INJECTION PRESSURE CAN MEAN
RESTRICTIONS TO THE GAS FLOW, UPSTREAM OF THE GAS INJECTION CIRCULATING VALVE.
OPENING OF THE UNLOADING VALVE.
A CHANGE IN THE TUBING PRESSURE AT DEPTH (CHANGE IN WATER CUT)
A CHANGE IN THE GAS INJECTION RATE
A RESTRICTION IN THE CIRCULATING VALVE
THE CIRCULATING VALVE’S PORT HAS BEEN FLOW CUT.
LOSS OF PRESSURE INTEGRITY IN EITHER THE TUBING OR THE INJECTION GAS FLOW LINE
Pt
Pb
Pc
INABILITY TO INJECT GAS.
GAS INJECTION IS RESTRICTED.
WE ARE OPERATING AT THE UNLOADING VALVE.
Schlumberger, 2001
WELL TESTS
MULTI-RATE TESTING - BETTER UNDERSTANDING OF THE WELL
WATER CUTS
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TUBING PRESSURE :
THE TUBING HEAD PRESSURE (THP) & WELL HEAD TEMPERATURE INDICATE THE WELL IS FLOWING.
A DECREASE IN TUBING PRESSURE CAN INDICATE A LOSS OF PRODUCTION DUE TO :
A CHANGE IN THE INJECTION DEPTH
AN INCREASE IN WATER CUT.
AN INCREASE IN TUBING PRESSURE :
COULD BE AS A RESULT OF EXCESS GAS INJECTION
CAN AFFECT THE CASING PRESSURE.
TUBING INSTABILITY CAN BE CAUSED BY :
CASING PRESSURE INSTABILITY (MULTI-POINTING OR INCORRECTLY SIZED CIRCULATING VALVE)
TOO LARGE A TUBING SIZE.
Schlumberger, 2001
Compressor fluctuations
SUMMARY OF WHERE THE PROBLEM MAY BE & WHAT THEY COULD BE.
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Method
Well flowing in heads
Valve hung open
Echometer surveys
Multi-rate test analysis
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Gas passage calculations
Well temperature effect
Frictional/downhole pressure effects
Failed Gas
Lift Valve
Casing Bridge
G.L.V. Setting
Too High
Surface Gas
Input Problem
G.L.V. Design
Subsurface
Problem
Subsurface
Schlumberger, 2001
CASE #1
Corrective Action Taken
Acquired fluid level in casing.
Wireline ran in well with impression block to confirm valve was out of pocket. Attempted to re-set valve.
Flowing gradient survey ordered.
WELL NO: A -11D
DESIGN PRODUCTION RATE:
R = Ap/Ab; Ap = Area of the port. Ab = Area of the bellows.
1) Pvc @ Depth=[OP @ Depth (1-R)]+ (Pc @ L x R)
Pc@L = Casing Pressure at Valve Depth
D Pc = Casing Pressure @ Depth - Casing Pressure @ Surface; psi
DESIGN GAS INJECTION RATE:
7) TRO =
1 - R
TYPE VALVES:
1) OP @ Depth =
Pvc @ Depth - (PtR)
1350 bbls/d
R = Ap/Ab; Ap=Area of the port./ Ab = Area of the bellows.
1-R
D Pc = Casing Press. @ Depth - Casing Press. @ Surface; psi
2) OP @ Depth = Pso + D Pc
DESIGNED GAS INJECTION:
3) Pvc @ Depth = Pd @ Depth
.580 MMCF/D
4) Pvc @ Depth = Psc + D Pc
Pd = Dome Pressure @ Depth of Valve: psi
5) Pvc @ Depth=[OP @ Depth (1-R)]+ (Pt R)
Ptro = Test Rack Opening; psi
6) Pd @ 60 F = (TCF) (Pd @ Depth)
TYPE VALVES:
7) TRO =
$535.00
$2,140.00
1.0
$275.00
$275.00
5.0
$90.00
$450.00
DISTRICT
AGENT
$ 535.00
$ 2,140.00
1.0
$ 275.00
$ 275.00
5.0
$ 90.00
$ 450.00
VLV #
MD
TVD
PORT
TRO
1.0
1850.0
1837.0
3/16"
945.0
2.0
2820.0
2698.0
3/16"
940.0
3.0
3640.0
3305.0
3/16"
935.0
4.0
4500.0
3902.0
3/16"
930.0
5.0
5370.0
4502.0
1/4"
N/A
6.0
6260.0
5106.0
Leave Valve in Place
Set up as per above design and deliver to Leeville dock by 5:00 PM Wednesday 6/3/98.
TOTAL
$2,865.00
MBD000061BD.unknown
MBD00011815.unknown
MBD0016219E.unknown
MBD00019AEA.unknown
MBD0000E839.unknown
WELL NO: A -11D
DESIGN PRODUCTION RATE:
1) Pvc @ Depth=[OP @ Depth (1-R)]+ (Pc @ L x R)
Pc@L = Casing Pressure at Valve Depth
D Pc = Casing Pressure @ Depth - Casing Pressure @ Surface; psi
DESIGN GAS INJECTION RATE:
7) TRO =
1 - R
TYPE VALVES:
1) OP @ Depth =
Pvc @ Depth - (PtR)
1350 bbls/d
R = Ap/Ab; Ap=Area of the port./ Ab = Area of the bellows.
1-R
.580 MMCF/D
6) Pd @ 60 F = (TCF) (Pd @ Depth)
TYPE VALVES:
7) TRO =
$535.00
$2,140.00
1.0
$275.00
$275.00
5.0
$90.00
$450.00
DISTRICT
AGENT
$ 535.00
$ 2,140.00
1.0
$ 275.00
$ 275.00
5.0
$ 90.00
$ 450.00
VLV #
MD
TVD
PORT
TRO
1.0
1850.0
1837.0
3/16"
945.0
2.0
2820.0
2698.0
3/16"
940.0
3.0
3640.0
3305.0
3/16"
935.0
4.0
4500.0
3902.0
3/16"
930.0
5.0
5370.0
4502.0
1/4"
N/A
6.0
6260.0
5106.0
Leave Valve in Place
Set up as per above design and deliver to Leeville dock by 5:00 PM Wednesday 6/3/98.
TOTAL
$2,865.00
MBD0000E839.unknown
MBD00019AEA.unknown
MBD0016219E.unknown
MBD00011815.unknown
MBD000061BD.unknown
Start
End
SCSSV @ 398 ft. MD (1.9 in.)
Figure 2
Schlumberger, 2001
Case #1
Figure 3
Schlumberger, 2001
CASE #1
SUMMARY & CONCLUSIONS
As figure 2 shows, the fluid level was found at the 4th mandrel. The well has failed to unload to the orifice.
As figure 3 illustrates, there is sufficient pressure differential at depth to unload to the orifice in mandrel #5.
Wireline operations confirmed the valve in mandrel #4 was out of pocket, preventing the well from unloading.
Schlumberger, 2001
CASE #2
Well has been severely heading with tubing pressures ranging between 120 - 350 psi. Casing pressures have varied between 900 - 1000 psi.
Well believed to be multi-point injecting between 2 or more valves.
Schlumberger, 2001
CASE #2
1.000
834.0
0.0
130
904.0123
1034
1034.0122999999999
904
0
0
N/A
5.0
5418.0
5333.0
149.0
0.839
3/16"
.094
.906
878.0
82.4442
146
889.0123
1035
1051.2836331530734
905
868
958
960.0
6.0
5939.0
5805.0
156.0
0.829
3/16"
.094
.906
867.0
81.4113
159
874.0123
1033
1050.216311665379
891
856
945
945.0
7.0
6491.0
6313.0
163.0
0.819
3/16"
.094
.906
867.0
81.4113
172
859.0123
1031
1048.0090497737556
876
844
932
930.0
8.0
7012.0
6794.0
170.0
0.809
3/16"
.094
.906
859.0
80.6601
185
844.0123
1029
1046.6308354486257
862
832
919
920.0
9.0
7563.0
7306.0
174.0
0.803
3/16"
.094
.906
854.0
80.1906
198
829.0123
1027
1044.9417282860609
847
825
910
910.0
10.0
8115.0
7829.0
N/A
N/A
3/16"
.094
970.0
VARIABLES DESCRIPTION:
1) OP @ Depth =
Pvc @ Depth - (PtR)
Unload to kick-off flowing oil well.
1-R
.500 MMCF/D
6) Pd @ 60 F = (TCF) (Pd @ Depth)
TYPE VALVES:
7) TRO =
$560.00
5040
1.0
$300.00
300
10.0
$120.00
1200
$ 560.00
$ 5,040.00
1.0
$ 300.00
$ 300.00
10.0
$ 120.00
$ 1,200.00
VLV #
MD
TVD
PORT
TRO
1.0
1802.0
1802.0
3/16"
1005.0
2.0
3111.0
3110.0
3/16"
995.0
3.0
4105.0
4087.0
3/16"
980.0
4.0
4803.0
4747.0
0.0
N/A
5.0
5418.0
5333.0
3/16"
960.0
6.0
5939.0
5805.0
3/16"
945.0
7.0
6491.0
6313.0
3/16"
930.0
8.0
7012.0
6794.0
3/16"
920.0
9.0
7563.0
7306.0
3/16"
910.0
10.0
8115.0
7829.0
1/4"
970.0
Set up valves as per above design and send to Camco Lafayette by 2:00 PM. They will take to PHI Heliport.
Contact Greg Stephenson for meet in Patterson.
TOTAL
$6,540.00
Mandrel #1 @ 1802 ft. MD (8.9 in.)
Mandrel #2 @ 3111 ft. MD (15.4 in.)
Mandrel #3 @ 4105 ft. MD (20.4 in.)
Mandrel #4 @ 4803 ft. MD (23.8 in.)
Figure 5
Schlumberger, 2001
CASE #2
Schlumberger, 2001
CASE #2
As figure 5 illustrates, the well has unloaded to the orifice in mandrel #4.
Figure 6 is a 2-pen chart showing both tubing and casing heading, typical of multi-point injection and/or un-regulated gas passage due to communication.
The flowing survey in figure 7 indicates gas passage through valves # 1,2,3 & 4.
Schlumberger, 2001
CASE #2
The casing pressure analysis in figure 8 shows that all unloading valves should be closed at the given pressures and temperatures.
Well appears to be multi-point injecting through leaking or cut-out valves.
Appears to be error in bottom three survey points.
Schlumberger, 2001
CASE #2
Valves were sent to shop and replaced. The seats in each of the unloading valves were confirmed to be cut out
After replacing cut-out valves, well was returned to production. Total fluid rate increased by over 150 bbls/d (60 BOPD).
4 training sessions were then scheduled for field personnel to better inform them about proper unloading / operating procedures.
Schlumberger, 2001
CASE #3
Schlumberger, 2001
CASE #3: Inflow Performance
Figure 1 - Inflow performance. The above IPR curves were generated to represent conditions at present and at the time of the last pressure survey (11/98). Based on the estimated IPR, the current Pwf would have to be approximately 2627 psi to correspond with the current production rate of 5204 bbls/d.
Schlumberger, 2001
CASE #3: Casing Pressure Analysis
Figure 2 - Gas passage. The above curves show that the gas passage of valves 1 & 2 roughly total what is currently being injected.
Schlumberger, 2001
CASE #3: Gradient Plot
Figure 3 - Gradient plot. The above gradient plot shows that the well can not inject deeper than the 2nd mandrel under current conditions.
Schlumberger, 2001
CASE #3: Gas Passage Analysis
Figure 4 - Gas Passage. The above gas passage curves show that the combined gas passage of the top two unloading valves is less than the current gas injection rate. This indicates that the well may be injecting through a hole in the tubing or a valve which is leaking or out of pocket.
Chart1
0
0
86.5
90.8
173
181.6
259.5
272.4
346
363.2
432.5
454
519
544.8
605.5
635.6
692
726.4
778.5
817.2
865
908
867.8595540006
1436.0932147348
867.8595540006
1436.0932147348
867.8595540006
1436.0932147348
867.8595540006
1436.0932147348
867.8595540006
1436.0932147348
867.8595540006
1436.0932147348
861.570581595
1425.686518677
817.1242419103
1352.1388040189
721.2805522907
1193.5411695245
546.0159362369
903.5215174531
0
0
Fig 1
Figure 1 - Inflow performance. The above IPR curves were generated to represent conditions at present and at the time of the last pressure survey (11/98).
Based on the estimated IPR, the current Pwf would have to be approximately 2627 psi to correspond with the current production rate of 5204 bbls/d.
&A
PRODUCTION RATE:
5204 bbls/d @ 58% WC
OP = Operating Pressure @ Depth of Valve; psi
5) Ptr = (Pd - Pc)/(1 - R) + Pc(R)
GAS INJECTION RATE:
4.8 MMSCFD
TCF =Temperature Correction Factor
TYPE VALVES:
Ptr = Tubing pressure required to re-open valve at given casing pressure.
Camco R-20, RDO
Pcr = Casing pressure required to re-open valve at given tubing pressure.
DATE:
11/05/00
Figure 2 - IPO Trouble-shooting spreadsheet. The above spreadsheet shows that, based on valve mechanics alone, all of the gas lift valves should be closed. This indicates that the well is most likely injecting through a leaking or damaged gas lift valve
&A
Fig 3
Figure 3 - Gradient plot. The above gradient plot shows that the well can not inject deeper than the 2nd mandrel under current conditions.
&A
Pdown
Q
Pdown
Q
psia
mscfd
psia
mscfd
0
867.8595540006
0
1436.0932147348
86.5
867.8595540006
90.8
1436.0932147348
173
867.8595540006
181.6
1436.0932147348
259.5
867.8595540006
272.4
1436.0932147348
346
867.8595540006
363.2
1436.0932147348
432.5
867.8595540006
454
1436.0932147348
519
861.570581595
544.8
1425.686518677
605.5
817.1242419103
635.6
1352.1388040189
692
721.2805522907
726.4
1193.5411695245
778.5
546.0159362369
817.2
903.5215174531
865
0
908
0
Figure 4 - Gas Passage. The above gas passage curves show that the combined gas passage of the top two unloading valves is
less than the current gas injection rate. This indicates that the well may be injecting through a hole in the tubing or a valve which
is leaking or out of pocket.
&A
Fig 5
Figure 1 - System deliverability. The above performance curve shows that the well is over-injecting at present. Note: this performance curve assumes
single-point injection at the 2nd mandrel and is only an estimate. Because the well is multi-point injecting and / or unstable, the actual performance capability
of the well may actually be greater than is shown above. However, the general trend should be similar to that shown above.
&A
Figure 6 - System deliverability. The above performance curve was developed assuming injection at the 4th mandrel. As this figure shows, under these
conditions, the well would be able to produce an estimated 6400 bbls/d, an uplift of approx. 1200 bbls/d (360 bopd) while injecting 2.0 MMSCFD.
While this would add an increment of approximately 360 bopd, it would also conserve approximately 3.6 MMSCFD.
&A
CASE #3: System Deliverability
Figure 5 - System deliverability. The above performance curve shows that the well is over-injecting at present. Note: this performance curve assumes single-point injection at the 2nd mandrel and is only an estimate. Because the well is multi-point injecting and / or unstable, the actual performance capability of the well may actually be greater than is shown above. However, the general trend should be similar to that shown above.
Schlumberger, 2001
CASE #3
Casing pressure analysis indicates all valves should be closed.
Gradient analysis indicates only valves #1 & 2 have sufficient differential to inject.
Gas passage analysis indicates that current injection rate exceeds combined capacity of top 2 valves.
Well suspected to be injecting through hole in tubing – this was confirmed by bleeding down casing.
If communication can be repaired, gain of approximately 360 bopd may be achieved.
Schlumberger, 2001
VALVE PROBLEMS
OPTIMUM TUBING SIZE TO RIGHT OF STABLE POINT BUT NOT TOO MUCH FRICTION.
INTERSECTION NEAR OR LEFT OF MIN = INSTABILITY.
WELL WILL HEAD AND SLUG - CYCLIC BUILD UP AND PERIODIC LIFTING OF SLUGS BY ACCUMULATED PRESSURE AND TRAPPED GAS.
INACCURACIES IN FLOW CORRELATIONS - DIFFICULT TO PREDICT
Schlumberger, 2001
INSUFFICIENT GAS INJECTION RATES
THE WELL COULD BE MULTI-POINTING
Schlumberger, 2001
Schlumberger, 2001
INJECTION GAS
PRODUCED FLUID
PRESSURE (PSI)
OPERATING GAS LIFT
Schlumberger, 2001
INSTABILITY - The perpetuation of slugging (whilst sub-critical flow across the operating valve)
Fluctuation in Tubing pressure
Decreased fluid density
Increase TBG pressure
Slight decrease in CSG pressure until drop in gas inj. rate
Increased gas inj. rate
Decreased gas inj. rate
Increased fluid density
Decrease TBG pressure
Slight increase in CSG pressure until sufficient to increase gas inj. rate
General Increasing
Production Rate
General Decreasing
Production Rate
THE TUBING INSTABILITY CYCLE : WHILST THE OPERATING VALVE’S GAS PASSAGE IS DEPENDENT ON THE TUBING PRESSURE - THE CYCLE IS SLEF PERPETUATING. NEED TO BREAK THE DEPENDENCE OF GAS PASSAGE ON THE TUBING PRESSURE.
Schlumberger, 2001
PRESSURE (PSI)
GAS INJECTION RATE (MMSCF/D)
THE FLOW THROUGH A SQUARE-EDGED ORIFICE IS CLASSICAL. IF WE CONSIDER FLOW THROUGH A VENTURI OR NOZZLE TYPE RESTRICTION WE HAVE DIFFERENT PERFORMANCE. BOTH HAVE ADVANTAGES. UP UNTIL RECENTLY THE PERFORMANCE OF A NOZZLE WAS DIFFICULT TO REPLICATED DUE TO THE TURBULANCE OF THE GEOMETYR OF GAS LIFT VALVE. ALSO - MEANS OF CALCULATING PRESSURE DROP IN A NOZZLE WAS NOT AVAILABLE.
Schlumberger, 2001
Schlumberger, 2001
STABILITY CHECK
INFLOW
RESPONSE
Well
Casing
Wellhead
Flowing
Total
Gas
Productivity
Total
79556
22.00
Comments
PLEASE NOTE THAT ABOVE STABILITY CRITERIA WERE CALCULATED BY USING WELL TEST DATA ONLY!
Schlumberger, 2001
LOSS OF PRODUCTION
NORMALLY INJECTION RATE EXCEEDS ECONOMIC INJECTION RATE
ADDITIONAL LOAD ON COMPRESSOR
INCREASE UPSTREAM PRESSURE FOR SAME INJECTION RATE (ADDITIONAL LOAD ON COMPRESSOR = REDUCE COMPRESSOR THROUGHPUT)
Schlumberger, 2001
NOVA VALVE
Schlumberger, 2001
SUB-CRITICAL
FLOW
THE FLOW THROUGH A SQUARE-EDGED ORIFICE IS CLASSICAL. IF WE CONSIDER FLOW THROUGH A VENTURI OR NOZZLE TYPE RESTRICTION WE HAVE DIFFERENT PERFORMANCE. BOTH HAVE ADVANTAGES. UP UNTIL RECENTLY THE PERFORMANCE OF A NOZZLE WAS DIFFICULT TO REPLICATED DUE TO THE TURBULANCE OF THE GEOMETYR OF GAS LIFT VALVE. ALSO - MEANS OF CALCULATING PRESSURE DROP IN A NOZZLE WAS NOT AVAILABLE.
Schlumberger, 2001
Large sub-critical flow regime
Gas passage dependent on downstream pressure until 40 - 50% pressure lost
Poor pressure recovery = large pressure drop & large energy loss
CHARACTERISTICS - DEMONSTRATE DRAW BACK ON BEING DEPENDENT ON TUBING PRESSURE
1091.unknown
THE VENTURI DESIGN ALLOWS THE FOLLOWING :
BETTER PRESSURE & ENERGY RECOVERY
CRITICAL VELOCITY (VELOCITY OF PRESSURE TRANSMISSION/SONIC VELOCITY) ATTAINED WITHIN 10% PRESSURE DROP
REDUCES INFLUENCE OF DOWNSTREAM PRESSURE ON GAS PASSAGE = REDUCED RISK TO PROPAGATING INSTABILITY
Schlumberger, 2001
COURSE SUMMARY
0
200
400
600
800
1000
1200
1400
1600
02004006008001000
Casing Operated Valves and Choke Control of Injection Gas
0
200
400
600
800
1000
1200
1400
1600
1800
2000
Gas Drive Reservoir (after Vogel)
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
1.00
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
1.00
Q/Qmax
Pbhf/Pbhs
d
P/
d
Z
R
V
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
4.50
5.00
0.00
200.00
400.00
600.00
800.00
1000.00
1200.00
1400.00
1600.00
1800.00
2000.00
Calculated Flowrate
Measured Flowrate
Calculated Flowrate
Measured Flowrate
Calculated Flowrate
Measured Flowrate
Calculated Flowrate
Measured Flowrate
Gas Passage through a RDO-5 Orifice Valve with a 1/2" Port
(163 deg F, Gas S.G. 0.83, Discharge Coefficient 0.84)
0
1
2
3
4
5
6
7
8
9
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
ROUND MANDREL DESIGN
TEST PRESSURE INTERNAL
TENSILE STRENGTH (EOEC)
0
0
0
500
500
500
1000
1000
1000
1500
1500
1500
2000
2000
2000
2500
2500
2500
3000
3000
3000
3500
3500
3500
4000
4000
4000
0
0
200
200
400
400
600
600
800
800
1000
1000
1200
1200
1400
1400
Flow Rate (Mcf/d)
Flow Rate (Mcf/d)
900 psi Upstream
900 psi Upstream
5541853331490.8393/16".094960
6593958051560.8293/16".094945
7649163131630.8193/16".094930
8701267941700.8093/16".094920
9756373061740.8033/16".094910
1081157829N/AN/A3/16".094970
118021005911340.0940.906032971139.8559121065Closed
23110995901587.0940.906055995147.8429571071Closed
34087980888822.0940.9060771020158.82610011075Closed

Documents

Gas Lift Presentation #1