Gas Lift Course

BASICS IN GAS LIFT OPERATIONS FORTIES GAS LIFT SUPPORT TEAM VIJAY POTHAPRAGADA SURVEILLANCE ENGINEERS OWEs

FORTIES GAS LIFT SUPPORT TEAM

OBJECTIVES DESCRIBE

MAIN RESERVOIR DRIVES EXPLAIN WHY/WHEN DO WE NEED ARTIFICIAL/GAS LIFT EXPLAIN

BASICS IN GAS LIFT OPERATION

UNLOADING OPERATIONS OPTIMIZATION

FAMILIARIZE WITH GAS LIFT

EQUIPMENT EQUIPMENT DEVELOP SOME BASIC TROUBLESHOOTING SKILLS

CONTENTS WELL

AND RESERVOIR INFLOW PERFORMANCE OUTFLOW PERFORMANCE AND MULTIPHASE FLOW TYPES OF ARTIFICIAL LIFT GAS LIFT CONTINUOUS

FLOW UNLOADING SEQUENCE GAS LIFT VALVE MECHANICS GAS

LIFT WELL OPERATION GAS LIFT WELL OPTIMIZATION GAS

LIFT WELL TROUBLESHOOTING HEADING-INSTABILITY-SLUGGING

WELL AND RESERVOIR INFLOW PERFORMANCE

WELL & RESERVOIR INFLOW PERFORMANCE TYPES OF RESERVOIR DRIVES 

DISSOLVED / SOLUTION GAS DRIVE



GAS CAP DRIVE



WATER DRIVE

DISSOLVED GAS DRIVE

WELL & RESERVOIR INFLOW PERFORMANCE 

DISSOLVED / SOLUTION GAS DRIVE  CONSTANT VOLUME  NO WATER ENCROACHMENT  TWO PHASE FLOWING RESERVOIR BELOW BUBBLE POINT  NO GAS CAP  PI NOT LINEAR  PI DECLINES WITH DEPLETION  FORMATION GOR INCREASES WITH DEPLETION  LEAST EFFICIENT WITH 15% TO 25% RECOVERY

GAS CAP DRIVE

WELL & RESERVOIR INFLOW PERFORMANCE 

GAS CAP DRIVE  GAS FROM SOLUTION WILL FORM GAS CAP  WITH PRODUCTION GAS CAP INCREASES PROVIDING DRIVE  EXCESSIVE DRAWDOWN CAN CAUSE CONING  PI USUALLY NOT LINEAR  GOR CONSTANT EXCEPT NEAR DEPLETION  25% TO 50% RECOVERY

WATER DRIVE

WELL & RESERVOIR INFLOW PERFORMANCE WATER

DRIVE  NOT CONSTANT VOLUME  RESERVOIR PRESSURE MORE CONSTANT EXPANSION OF WATER 1 IN 2500 PER 100 PSI  PI MORE CONSTANT  GOR MORE CONSTANT  COMBINATION OF WATER DRIVE & GAS CAP EXPANSION  OFTEN SUPPLEMENTED BY WATER INJECTION  MOST EFFICIENT WITH UPTO 70% RECOVERY

WELL & RESERVOIR INFLOW PERFORMANCE 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 = J(Pws - Pwf)

or 

q J = -----------------Pws - Pwf 

WELL & RESERVOIR INFLOW PERFORMANCE INFLOW PERFORMANCE CURVE 3000    ]    i   s   p 2000    [   e   r   u   s   s   e 1000   r    P

0 0

10000

20000

Production Rate [stbo/d]

Vogel

Straight Line

30000

WELL & RESERVOIR INFLOW PERFORMANCE SUMMARY OF FACTORS AFFECTING PREDICTION OF WELL PRODUCTION  PRESENCE OF THREE PHASE FLOW 

NATURE OF DRIVE MECHANISMS



PHYSICAL NATURE OF RESERVOIR (NON HOMOGENEOUS)



AVAILABILITY OF STABILIZED FLOW



CHANGES OVER TIME & DRAWDOWN



INCREASED GAS SOLUTION NEAR WELLBORE



STABILISED FLOW NEAR WELLBORE



FLOW REGIME NEAR WELLBORE



CRITICAL FLOW AT WELLBORE

OUTFLOW PERFORMANCE AND MULTIPHASE FLOW

OUTFLOW PERFORMANCE AND MULTIPHASE FLOW MOVEMENT OF A MIXTURE OF FREE GASES AND LIQUIDS 

VERTICAL FLOWING GRADIENTS HORIZONTAL FLOWING GRADIENTS

SURFACE PRESSURE

PRODUCED FLUID

INJECTION GAS

WELL OUTFLOW RELATIONSHIP (VLP) or (TPC)

RESERVOIR PRESSURE

SANDFACE PRESSURE BHFP

WELL INFLOW (IPR)

OUTFLOW PERFORMANCE AND MULTIPHASE FLOW 

VERTICAL FLOWING GRADIENTS  HORIZONTAL FLOWING GRADIENTS 

SELECT CORRECT TUBING SIZE  PREDICT WHEN ARTIFICIAL LIFT WILL BE REQUIRED  DESIGN ARTIFICIAL LIFT SYSTEMS  DETERMINE BHFP  DETERMINE PI  PREDICT MAXIMUM AND/OR OPTIMUM FLOW RATE RATE  DETERMINE MAXIMUM DEPTH OF INJECTION

ARTIFICIAL LIFT

TYPES OF ARTIFICIAL LIFT 

ROD PUMPS



HYDRAULIC PUMPS



ELECTRIC SUBMERSIBLE PUMPS



GAS LIFT

GAS LIFT

TYPES OF GAS LIFT 

CONTINUOUS FLOW GAS LIFT CONTINUOUS TUBING FLOW / ANNULAR FLOW



INTERMITTENT GAS LIFT INTERMITTENT



PLUNGER LIFT



CONVENTIONAL & WIRELINE RETRIEVABLE



GAS LIFT EQUIPMENT

APPLICATIONS OF CONTINUOUS FLOW GAS LIFT 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

ADVANTAGES OF GAS LIFT 

INITIAL DOWNHOLE EQUIPMENT COSTS LOWER



LOW OPERATIONAL AND MAINTENANCE COST



SIMPLIFIED WELL COMPLETIONS



FLEXIBILITY - CAN HANDLE RATES FROM 10 TO 80000 BPD



CAN BEST HANDLE SAND / GAS / WELL DEVIATION

DISADVANTAGES OF GAS LIFT  MUST HAVE A SOURCE OF GAS

IMPORTED FROM OTHER FIELDS PRODUCED

GAS - MAY RESULT IN

START UP PROBLEMS 

POSSIBLE HIGH INSTALLATION COST

TOP

SIDES MODIFICATIONS TO EXISTING PLATFORMS

COMPRESSOR 

INSTALLATION

LIMITED BY AVAILABLE RESERVOIR PRESSURE

AND BOTTOM HOLE FLOWING PRESSURE

CONSTANT FLOW GAS LIFT WELL ELL

PRODUCED FLUID

INJECTION INJ ECTION GAS GAS

0

PRESSURE (PSI) 1000

2000

0

1000

2000

   )    D 3000    V    T    T    F    (    H    T    P 4000    E    D

F     L   O     W     I     N     G     T     U     B     I     N     G     P     R     E     S     S     U     R     E     G     R     A     D    I     E     N     T    

CASING PRESSURE WHEN WELL IS BEING GAS LIFTED

OPERATING GAS LIFT VALVE

5000

6000

   P    H    B    I    S

7000

FBHP

CONSTANT FLOW GAS LIFT WELL

PRODUCED FLUID

INJECTION INJ ECTION GAS

0

PRESSURE (PSI) 1000

2000

0

1000

2000

   )    D 3000    V    T    T    F    (    H    T    P 4000    E    D

5000

F     L   O     W     I     N     G     T     U     B     I     N     G     P     R     E     S     S     U     R     E     G     R     A     D     I     E     N     T    

CASING PRESSURE PRESSURE WHEN WELL IS BEING GAS LIFTED

OPERATING GAS LIFT VALVE

6000

   P    H    B    I    S

7000

FBHP

ANNULAR FLOW

TUBING FLOW PRODUCED FLUID

INJECTION GAS INJECTION GAS

PRODUCED FLUID

GAS LIFT SYSTEM CONSIDERATIONS          

SAND PRODUCTION PRODUCED WATER WATER CONING ANNULAR SAFETY  SYSTEM CORROSION EFFECTS HYDRATES ASPHALTINES BUBBLE POINT CHEMICAL INJECTION SCALE

GAS CAPACITY AND AVAILABI AVAILABILITY  LITY   CASING INTEGRITY   RESERVOIR PERFORMANCE  SYSTEM OPTIMISATION  WELL STABILITY   WELL START UP  PLANT CONSIDERATIONS  GAS QUALITY   TRAINING 

CONTINUOUS FLOW UNLOADING SEQUENCE

 TO SEPARATOR/STOCK TANK 

PRESSURE PSI 0

1000

2000

3000

4000

5000

6000

7000

INJ ECTION GAS CHOKE CLOSED

2000

TOP VALVE OPEN

SECOND VALVE OPEN

THIRD VALVE OPEN

4000

   D    V    T    T    F    H    T    P    E    D

6000

8000

C    A   S    I    N    G    T    P    U    R  E    B    I    S    N    S    G    U    R  E    P    R  E    S    S    U    R  E   

10000 FOURTH VALVE OPEN

12000

14000

TUBING PRESSURE

FIGURE 3-1

CASING PRESSURE

SIBHP

The fluid level in the casing and the tubing is at surface. No gas is being injected into the casing and no fluid is being produced. All the gas lift valves are open. The  pressure to open the valves is provided by the weight of the fluid in the casing and tubing.  Note that the fluid level in the tubing and casing will be determined by the shut in bottom hole pressure (SIBHP) and the hydrostatic head or weight of the column of  fluid which is in turn determined by the density. Water has a greater density than oil and thus the fluid level of a column of water will be lower than that of oil.

 TO SEPARATOR/STOCK TANK 

PRESSURE PSI 0

1000

2000

3000

4000

5000

6000

7000

INJ ECTION GAS CHOKE OPEN

2000

4000

TOP VALVE OPEN

SECOND VALVE OPEN

THIRD VALVE OPEN

   D    V    T    T    F    H    T    P    E    D

6000

8000

10000 FOURTH VALVE OPEN

12000

14000

TUBING PRESSURE

FIGURE 3-2

CASING PRESSURE

SIBHP

Gas injection into the casing has begun. Fluid is U-tubed through all the open gas lift valves. No formation fluids are being produced because the pressure in the wellbore at perforation depth is greater than the reservoir reservoir pressure i.e. no drawdown. All fluid produced is from the casing and the tubing. All fluid unloaded from the casing passes through the open gas lift valves. Because of this, it is important that the well be unloaded at a reasonable rate to prevent damage to the gas lift valves.

PRESSURE PSI

 TO SEPARATOR/STOCK TANK 

0

1000

2000

3000

4000

5000

6000

7000

INJ ECTION ECTION GAS CHOKE OPEN

2000

4000

TOP VALVE OPEN

SECOND VALVE OPEN

THIRD VALVE OPEN

   D    V    T    T    F    H    T    P    E    D

6000

8000

10000 FOURTH VALVE OPEN

12000

14000

TUBING PRESSURE

FIGURE 3-3

CASING PRESSURE

SIBHP

The fluid level has been unloaded to the top gas lift valve. This aerates the fluid above the top gas lift valve, decreasing the fluid density. This reduces the pressure in the tubing at the top gas lift valve, and also reduces pressure in the tubing at all valves below the top valve. This pressure reduction allows casing fluid below the top gas lift valve to be U-tubed further down the well and unloaded through valves 2, 3 and 4. If this reduction in pressure is sufficient to give some drawdown at the perforations then the well will start to produce formation fluid.

PRESSURE PSI

 TO SEPARATOR/STOCK TANK 

0

1000

2000

3000

4000

5000

6000

7000

INJ ECTION GAS CHOKE OPEN

2000

4000

TOP VALVE OPEN

SECOND VALVE OPEN

THIRD VALVE OPEN

   D    V    T    T    F    H    T    P    E    D

6000

8000

10000 FOURTH VALVE OPEN

12000

14000

DRAWDOWN

TUBING PRESSURE

FIGURE 3-4

CASING PRESSURE

FBHP

SIBHP

The fluid level in the annulus has now been unloaded to just above valve number two. This has been posssible due to the increasing volume of gas passing through number one reducing the pressure in the tubing at valve two thus enabling the U-tubing process to continue.

 TO SEPARATOR/STOCK TANK 

PRESSURE PSI 0

1000

2000

3000

4000

5000

6000

7000

INJ ECTION ECTION GAS CHOKE OPEN

2000

4000

TOP VALVE OPEN

SECOND VALVE OPEN

THIRD VALVE OPEN

   D    V    T    T    F    H    T    P    E    D

6000

8000

10000 FOURTH VALVE OPEN

12000

14000

DRAWDOWN

TUBING PRESSURE

FIGURE 3-5

CASING PRESSURE

FBHP

SIBHP

The fluid level in the casing has been lowered to a point below the second gas lift valve. The top two gas lift valves are open and gas being injected through both valves. All valves below also remain open and continue to pass casing fluid. The tubing has now been unloaded sufficiently to reduce the flowing bottom hole pressure (FBHP) below that of the shut in bottom hole pressure (SIBHP). This gives a differential pressure from the reservoir to the wellbore producing a flow of formation fluid. This pressure differential is called the drawdown

PRESSURE PSI

 TO SEPARATOR/STOCK TANK 

0

1000

2000

3000

4000

5000

6000

7000

INJ ECTION ECTION GAS CHOKE OPEN

2000

4000

TOP VALVE CLOSED

SECOND VALVE OPEN

THIRD VALVE OPEN

   D    V    T    T    F    H    T    P    E    D

6000

8000

10000

FOURTH VALVE OPEN

12000

14000

DRAWDOWN

TUBING PRESSURE

FIGURE 3-6

CASING PRESSURE

FBHP

SIBHP

The top gas lift valve is now closed, and all the gas is being injected through the second valve. When casing pressure operated valves are used a slight reduction in the casing pressure causes the top valve to close. With fluid operated and proportional response valves, a reduction in the tubing pressure at valve depth causes the top valve to close. Unloading the well continues with valves 2, 3 and 4 open and casing fluid being removed through valves 3 and 4.

PRESSURE PSI

 TO SEPARATOR/STOCK TANK 

0

1000

2000

3000

4000

5000

6000

7000

INJ ECTION GAS CHOKE OPEN

2000

4000

TOP VALVE CLOSED

SECOND VALVE OPEN

THIRD VALVE OPEN

FOURTH VALVE OPEN

   D    V    T    T    F    H    T    P    E    D

6000

8000

10000

12000

14000

DRAWDOWN

TUBING PRESSURE

FIGURE 3-7

CASING PRESSURE

FBHP

SIBHP

The No. 3 valve has now been uncovered. Valves 2 and 3 are both open and passing gas. The bottom valve below the fluid level is also open.  Note that the deeper the point of injection the lower the FBHP and thus the greater the drawdown on the well. As well productivity is directly related to the drawdown then the deeper the injection the greater the production rate.

PRESSURE PSI

 TO SEPARATOR/STOCK TANK 

0

INJ ECTION GAS CHOKE OPEN

1000

2000

3000

4000

5000

6000

7000

2000

4000 TOP VALVE CLOSED

SECOND VALVE CLOSED

THIRD VALVE OPEN

FOURTH VALVE OPEN

   D    V    T    T    F    H    T    P    E    D

6000

8000

10000

12000

14000

DRAWDOWN

TUBING PRESSURE

FIGURE 3-8

CASING PRESSURE

FBHP

SIBHP

The No. 2 valve is now closed. All gas is being injected through valve No 3. Valve No 2 is closed by a reduction in casing pressure for casing operated valves or a reduction in tubing pressure for fluid operated and proportional response valves. Valve No 3 is the operating valve in this example. This is because the ability of the reservoir to produce fluid matches the ability of the tubing to remove fluids (Inflow/Outflow Performance). The operating valve can either be an orifice valve or can be a gas lift valve. The valve in mandrel No 4 will remain submerged unless operating conditions or reservoir conditions change.

FIGURE 3-8: Example of the Unloading Sequence Casing Operated Valves and Ch oke Con trol of Injection Injection Ga 2000

1800 1600

1400    i   s 1200   p   e   r   u 1000   s   s   e   r    P 800

600

400 200

0 12:00 AM

03:00 AM

06:00 AM

PRESSUR SSURE CASI CASING

09:00 AM

Time

PRESSUR SSURE TUBING

12:00 PM

03:00 PM

06:00 PM

GAS LIFT VALVE MECHANICS

GAS LIFT VALVE MECHANICS

INJECTION PRESSURE (CASING) OPERATED VALVES PRODUCTION PRESSURE (FLUID) OPERATED VALVE THROTTLING/PROPORT THROTTLING/PROPORTIONAL IONAL RESPONSE VALVES THROTTLING/PROPORTIONAL ORIFICE VALVES NOVA ORIFICE VALVE

Diaphragm/ Atmospheric Bellows Spring

Stem

Upstream/ Casing

Stem Tip Upstream

Downstream Port Downstream/Tubing

Pressure Regulator 

Spring Operated Gas Lift Valve

GAS LIFT VALVE MECHANICS CLOSING FORCE (IPO VALVE)

Fc = PbAb

OPENING FORCES (IPO VALVE)

Fo1 = Pc (Ab- Ap) Fo2 = Pt Ap

TOTAL OPENING FORCE

Fo = Pc (Ab - Ap) + Pt Ap

JUST BEFORE THE VALVE OPENS THE FORCES ARE EQUAL Pc (Ab - Ap) + Pt Ap = Pb Ab

SOLVING FOR Pc

WHERE:

Pb - Pt (Ap/Ab) Pc = -------------------------1 - (Ap/Ab) Pb Pt Pc Ab

= Pressure in bellows = Tubing pressure = Casing pressure = Area of bellows

Pb Dome

Dome

Chevron Packing Stack 

Chevron Packing Stack 

Bellows

Bellows

Pc

Pb

Stem Tip (Ball) Square Edged Edged Seat

Pc

Stem Tip (Ball) Square Edged Seat

Pt Chevron Packing Stack 

Check Valve

Pt

Chevron Packing Stack 

Check Valve

N i ttrr o g e n C h a r g e d B e l l o w s T y p e Nitrogen Charged Bellows Type I n je je c t i o n P r e s s u r e ( C a s i n g ) O p e r a t e d G a s L i ft ft V aProduction lve Pressure (Fluid) Operated Gas Lift Valve

Dome

Pb Atmospheric Bellows

Spring

Chevron Packing Stack  Bellows

Chevron Packing Stack 

Pc

Spring Adjustment Nut & Lock Nuts

Large T.C. Ball Tapered T.C. Seat Chevron Packing Stack 

Pc

Pt

Check Valve Valve

Nitrogen Charged Bellows T ype Pr oportional Response Gas Lift Valve

Stem Tip (Ball) Square Edged Seat Chevron Packing Stack 

Pt

Check Valve

Spring Operated Injection Injection P ressure (Casing) Operated Gas L ift Valve Valve

) D/ F C S M M(

E T A R N OI T C E J NI S A G

SUB-CRITICAL FLOW

ORIFICE FLOW

  N   I  O   G   R  E   N  G   I    T  L    T   R  O   H    T PTUBING

PRESSURE (PSI)

= 55%

PCASING

RDO-5 Orifice Valve, 32/64" Port, Cd = 0.76

8.00

7.00

6.00

   d    /    f   c 5.00   s   m   m    (   e    t   a 4.00   r   w   o    l    F   s   a    G 3.00

2.00

Calcu Calcula late ted d Flow Flowrat rate e

Measu Measure red d Flowra Flowrate

Calcu Calcula late ted d Flow Flowrat rate e

Measu Measure red d Flowra Flowrate

Calcu Calcula late ted d Flow Flowrat rate e

Measu Measure red d Flowra Flowrate

Calcu Calcula late ted d Flow Flowrat rate e

Measu Measure red d Flowra Flowrate

1.00

0.00 0

200

400

600

800

1000

1200

Downstream Pressure (psig)

1400

1600

1800

2000

5 1/2” MMRG-4, 1 1/2” POCKET ROUND MANDREL DESIGN Orienting Sleeve

Tool Discriminator 

ENGINEERING DATA PART NUMBER SIZE MAX O.D. MIN I.D. DRIFT I.D. THREAD TEST PR PRESSURE IN INTERNAL TEST TEST PRES PRESS SURE URE EXT EXTER ERNA NAL L LATCH TYPE KICKOVER TOOL RUNNING TOOL PULLING TOOL MATERIAL TENSILE STRENGTH (EOEC) ©CAMCO 1996

05712-000-00001 5 1/2” 7.982” 4.756” 4.653” 17 LB/FT MANN BDS B x P 7740 PSI 6280 6280 PSI PSI RK, RK-1, RKP, RK-SP OM-1, OM-1M, OM-1S RK-1 15079 1 5/8” JDS 15155 410 S.S., 13 CR 22 HRC MAX 490,000 LBS

‘G’ Latch Lug

Polished Seal Bore

GAS LIFT WELL OPERATION

GAS LIFT WELL OPERATION 

UNLOAD WELL CAREFULLY 50 PSI (3.5 BAR) PER 10 MINS / 1 BBL PER MIN



OPEN PRODUCTION CHOKE



GRADUALLY INCREASE GAS INJECTION RATE



MONITOR WELL CLEAN UP



PERFORM STEP RATE PRODUCTION TEST



OPTIMISE GAS INJECTION RATE

GAS LIFT WELL OPERATION 



MONITOR, RECORD AND REPORT (DAILY) 

PRODUCTION RATES



WATER CUT



LIFT GAS INJECTION RATE



GAS LIFT INJECTION PRESSURE



FLOWING TUBING HEAD PRESSURE



VARIATIONS IN ABOVE PARAMETERS

PERFORM PERIODIC PRODUCTION TESTS

GAS LIFT WELL OPTIMIZATION

GAS LIFT WELL OPTIMISATION 

SURFACE FACILITIES WELLHEAD/FLOWLINE SEPARATOR

PRESSURES

COMPRESSOR

SINGLE

CHOKES

DISCHARGE PRESSURE/THROUGHPUT

WELL PERFORMANCE CURVES

THEORETICAL/COMPUTER MULTIRATE

MODELS

TESTS



FIELD PERFORMANCE CURVES



FIELD MODELS

GAS LIFT WELL TROUBLESHOOTING

THE GAS LIFT SYSTEM

GAS LIFT WELL TROUBLESHOOTING INLET

PROBLEMS

CHOKE

SIZED TOO LARGE

CHOKE

SIZED TOO SMALL

LOW

CASING PRESSURE

HIGH

CASING PRESSURE

VERIFY LOW

GAUGES

GAS VOLUME

EXCESSIVE

GAS VOLUME

COMPRESSOR

FLUCTUATIONS

GAS LIFT WELL TROUBLESHOOTING

OUTLET VALVE HIGH

PROBLEMS RESTRICTIONS

BACK PRESSURE

SEPARATOR

OPERATING PRESSURE

GAS LIFT WELL TROUBLESHOOTING DOWNHOLE HOLE

PROBLEMS

IN TUBING

OPERATING

PRESSURE VALVE BY SURFACE CLOSING

METHOD WELL

BLOWING DRY GAS

WELL

WILL NOT TAKE ANY INPUT GAS

WELL

FLOWING IN HEADS

INSTALLATION

STYMIED AND WILL NOT UNLOAD

VALVE

HUNG OPEN

VALVE

SPACING TOO WIDE

GAS LIFT WELL TROUBLESHOOTING TROUBLESHOOTING CALCULATIONS FLOWING

TWO

- ANALYSIS OF CASING PRESSURE

PRESSURE AND TEMPERATURE SURVEYS

ECHOMETER TAGGING

TECHNIQUES

SURVEYS

FLUID LEVEL

PEN PRESSURE RECORDER CHARTS

MULTI-RATE

TEST ANALYSIS

HISTORICAL

WELL TEST ANALYSIS

COMPUTER EXAMPLES

MODELLING

-HEADING-INSTABILTIES-SLUGGING-

HEADING - INSTABILITIES - SLUGGING 

TUBING HEADING PHENOMENON



CASING HEADING PHENOMENON



SLUGGING ON START UP - FORTIES/FOINAVEN



VALVE PROBLEMS

TUBING HEADING TUBING PRESSURE

CASING PRESSURE

CASING/ANNULUS HEADING TUBING PRESSURE

CASING PRESSURE PRESSURE