Gas Lift Production

Gas LiftGas LiftGas LiftGas Lift

Gas Lift Concept

Density Reduction

Reducing Flowing Bottom Hole Pressure

Improving The Gas To Liquid Ratio

Increasing The Mixture Velocity

Changing Flow Regime

Reducing Liquid Holdup

Reducing Wellhead Pressure

Advantages of Gas Lift System Low Cost

Design to Lift Different Rate

Injection and Producing Rate Controlled at Surface

Sand Production Doesn’t Affect G.L. Equipment

Not Affected by Wellbore Deviation

Operating Costs are Relatively Low

Gas Compressor Easily Inspected and Maintained

Limitation Of Gas Lift System

Gas Availability

Source of High Pressure Gas

Treat or Dry the Gas Before use.

Heavy oil (Gas will be channel)

Gas Lift System

Types of Gas Lift

Continuous Flow

Tubing Flow

Annular Flow

Intermittent Flow

Low Reservoir Pressure

Tighter reservoir (low Pwf)

Gas Lift Design Methods

1. Continuous Flow Design

Graphical Method

Unloading line method

2. Intermittent Design

Fallback method

Percent load Method

Fluid operating valve

Gas Lift Design

Continuous Flow Design

Design Parameter

Out flow Curve

Injection Gas Gradient

Water Gradient

Temperature profile

Factors That Affect Outflow Performance

Fluid Characteristics

Well Configuration

Wellhead Back Pressure

Pipe Roughness

Fluid Velocity

Outflow Correlation Duns and Ros

(Large diameter tubing, high GLR, low & mist flow rates)

Orkiszewski

(Slug flow, moderate liquid volume fractions)

Griffith and Wallis

(High liquid volume , low GLR)

Outflow Correlation, Continue

Beggs and Brill

(Small diameter from 1 to 1.5 in)

Hagedorn and Brown

H&B, Duns and ROS preferred with mist flow

Gas Gradient gas density(Ib/Ft3 )

G-grad.(Psi/Ft) =

144 (in2/ft2(

gas density(Ib/Ft3 )

G-grad.(Psi/Ft) =

144 (in2/ft2(

Mw*P

RT

pgas =SG. pair PV=nRT (n=m/Mw)

PV= (m/Mw)*RT

Pair (m/V)=

Pair=

Pgas= S.G*

pgas =SG. pair PV=nRT (n=m/Mw)

PV= (m/Mw)*RT

Pair (m/V)=

Pair=

Pgas= S.G*

28.97*PRT

28.97*PRT

Where:P =Pressure , PsiR= 10.73T=Teperature RO )460+T)

Gas Gradient Chart

Graphical Method DesignOP

V1

V2

WHP

V3

Operating valves

Water Grad=0.45

Whisky valves

V5

V4

P max

Gas Grad

AFE = (Pmax-Pmin)X (B/A)

Continuous GLD Equations

• AFE = (Pmax-Pmin)X (TEF)

• POL = Pg- AFE

• PBT = POL (A)+PTM(B)

• PVO = PBT/ A

• PSurf = PVO* Ct

A=1-(AV/AB)B=(AV/AB)

TEF=(B/A)

Ct= 1

1+0.00215(Tv-60)

Ct=Pv @ 60 F

Pv @ Well Temp

Continuous Design Using Unloading Line Method

Unloading line

PD=PWH+0.2(Pg-PWH)WHP PD OP

Design line

Disadvantage

gives large number of valves

Design of Intermittent Lift Installation

Percent Load Method

Gas Pressure Gradient

Percent Load Line (60% of Gas Pressure)

Pbt (Nitrogen Charged Valve)

Psp (Spring Loaded Valve)

Pvo (Valve Opening Pressure in Tester)

Decrease Set Pressure of Bottom Valve 25-30 psi (Flagging the bottom valve)

Percent Load Method

Pg1

Pg2

Pg3

Pg4

Pg5

WHP 60 % line

OP

Pp1

Pp5

Pp4

Pp3

Pp2

0.45Percent load line= 60% of gas line

• PBT = Pg (A) + Pp(B)

• PVO = PBT/ A

• PSurf = PBT* Ct

A

• Psp = Pg (A)+ Pp(B)

• PVOsur = Psp/ A

Where R=B A=1-R



Fallback Method

Spacing Factor Gradient (Unloading Gradient)

Function of Production Rate and Tubing Size

Gas Pressure Gradient

Valve Closing Pressure Gradient

Temperature Correction

Decrease Set Pressure of Bottom Valve 25-30

psi (Flagging the bottom valve)


• PSurf = Pvc* Ct

A

OP0.45

WHP 60 % line

Closing pre = - 100 of OP

Pvc1

Pvc4

Pvc4

Pvc3

Pvc2

Intermittent sapcing factor from

chart function of (rate & tbg size)

Fallback Method

Design of Intermittent Lift

Fluid Operating

Casing Operating

Fluid Operating Valve

Fluid Operating Valve Design

• AFE = (Pmax-Pmin)X (TEF)

• POL = Pg- AFE

• PBT = POL (B)+PTM(A)

• PVO = PBT/ A

• PSurf = PVO* Ct

A=1-(AV/AB)B=(AV/AB)TEF=(B/A)

Dual Gas Lift Installation

Both tubing strings take gas from the same gas source

System allow extra gas to go in one side than other. Results in one or both zones producing at less than optimum

Use injection pressure-operated in one side and production pressure operated in the other

Design considerationsPrediction of inflow & outflow

- Above BPP.

- Below BPP

Suitable tubing size

- Small size gives high friction losses.

- Large gives excessive gas slippage

Kick off pressure & operating pressure - operating pressure commonly used.

Design considerationsTemperature

- Don't use geothermal gradient.

* Draw straight line from WHT to BHT, then,

WHT-It is better to use actual survey. If not

available, If Not

BHT

Amb

Geothermal Grad

WHTAmb

Unloading depth

* WHTamb= WHTamb- 0.4(WHT- 80)

Design considerations

Valve Spacing

- Closer in high rate wells.

- Wider in low rate wells.

Valves

- Bellows Type. (Need temperature correction- Spring Type (may not sufficient in high pressure setting

Temperature (Cont….

- Temp. is rate sensitive, if

- Design temp > actual upper valve will remain open .- Design temp < upper valve will close.

Gas Volume How You Can Calculate Required GV ?

1. Use Nodel analysis to select optimum GLR.

GLR 500GLR 700

GLR 400GLR 1000

Q,BPD

Press



2. Required Gas Vol = Design GLR*BFPD- FGOR*BOPD MSCF

Port size-You can select your port size based on required gas

volume (see the following chart)-it is recommended to increase port size as go deeper

Correction Factor= 0.0544 GT

Qactual = Qchart/ corr. factor

Where

G : Gas Gravity

T : Temperature

Gas Passage


unloading

• Unloading

It is displacing killing/completion fluid to depth of operating valve.

• Kick off

when well is shut , fluid level rise to level equal to res. Press.

opening gas on the well till the well start to produce called

kick off.

Recommended Practices Prior To Unloading

Clean the well of mud prior to running G.L. Valves to avoid damage

Reverse circulation should not be used (Injection gas pressure operated valves)

Clean injection gas line before connected to the well

Check separator capacity, stock tank liquid valves and connections at wellhead

Unloading procedures

• Install two pin chart on recording both annulus and tubing side

• Open gas on well gradually to minimize velocity

across 1st valve to avoid valve cut.

• Pressure incremental by 50 psi every 8-10 min till pressure reach 400 psi. then pressure incremental

100 psi every 8-10 min.

If you has gas rate controller: thenIf you has gas rate controller: then

- Use 30 % of design gas for upper two valve

- 60 % for next two valves

- Then 90 % for the other , finally 100 %.

Unloading procedures (cont….

• You may increase the gas above the design gas just to unload the well.

Unloading procedures (cont…. • Casing pressure you will see drop in casing pressure at each valve.

Problems during unloading

• Gas couldn’t go deeper (couldn’t reach valve # 1)?

• Well circulating lift gas through valve # 1 ?

Effect of deepening POI

Problem : well has the following data:

Problem : well has the following data:

Production Rate 1000 BFPD

WC 50 %

Pr 3000 psi

Pwf 2500 psi

Poi V # 5 @ 6000 Ft TVD

V # 6 @ 6500 Ft TVD

What will be production rate if V # become POI?

Gas Lift System Evaluation

Analysis of Wellhead Data.

Reservoir Performance

Pressure & Temperature Flowing Gradient (Gas lift Survey)

Gas Lift Survey Objective Get Point of Gas Injection

Determine Possibility of Deeper POI

Get Valves Leak (Gas passes at more than one point)

Mandrels Plugging Condition

Gas Injection Optimization

Gas Lift Design Evaluation

Select the Type of G.L. System

Gas Lift Survey Procedure

Stop at Surface (Get WHP, WHT)

Get Gas Lift and Formation Gradient

Stop above and below Mandrels

Stop at Mid Point of Perforation

Gas Lift Survey Examples

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Continuous Flow G.L. Redesign Gas Injection Pressure

Temperature Survey

Gas Volume

Production Decline

Gas lift Optimization

Gas Utilization Factor GUF

It is the ratio between net oil divided by injection gas.

Incremental Gas Utilization Factor GUFIt is ratio of incremental oil divided by incremental injection gas.

High GUF reflect efficient lift gas.

Low GUF reflect inefficient lift gas.

Maximum GUF: obtained by drawing tangent line from orign to The optimization curve.


Optimum Gas Injection Rate:It is the point on the economic curve with rate of return

consistence with the company objectives.

Economic Injection Rate Limit:It is the point on the economic curve with slop equal to 1.

- Above this point oil gain compansated by cost incremental i.e ROR=0

Economic CurveIt constructed by plotting Revenue Vs costs.

- Costs include: - Treatment , handling of oil - Compression and processing of gas

Gas Lift Optimization (cont….)

Gas Optimum Per FieldConstrains which limit the maximum production of

the wells, Reservoir or entire field.

Individual well rate may be limited in order to avoid gas/water coning or sand production.

Individual well rate may be limited meet the economic criteria (i.e economic limit , Min ROR).

Low GUF well may be produced in preference to high GUF to ensure proper areal drainage of specific reservoirs..

Max. offtake of specific res may be limited to ensure proper reservoir management.

Gas Optimum Per Field

Max. offtake of specific res may be limited to ensure proper reservoir management. (gas or water injection rate)

Max. offtake of specific res may be limited due to water disposal limitation.

Constrains cont……….

Gas Optimum Per FieldSo, Two Cases are consider when allocating the gas:

Case 1 :All wells must be kicked off

- Applied when reservoir management exist.

Case 2 :Not all wells must necessarily be kicked off and produce, but wells with high GUF will be kick off in preference to wells with a lower GUF.

- applied when maximum oil is the main objective

Case One- All Wells Producing

The required amount of kick off gas is allocated to all wells

The remaining amount of gas is allocated to the rank of decreasing additional GUF’S.

gas first allocated to wells of high GUF, then allocated to

wells of second highest GUF (may be same well)

In both cases it is first necessary to establish the gas lift performance curve for all wells and if possible –the economic curve.

Case Two- Preferential Wells Kick Off Well are ranked in term of maximum GUF (see the next fig)

Well with highest max. GUF is the first well to be kicked off

The next additional GUF of this well is then compared with the maximum GUF of remaining wells, If - If the next additional GUF is > the other max GUFs then the

gas further allocated to the same well, otherwise

-The gas lift allocated to the well with next highest GUF (i.e second well kick off) ----- continue till

Continue with comparing the additional GUF of kick off wells with max. GUF of wells not yet kicked off till all gas has been used

Maximum GUF

Gas Lift Equipments

Bellows

Stem

Seat (Port)

Check Valve

V-Packing

VALVE Fig

Gas Lift Valves

Checks, Latches & Mandrels

Checks (Check Valve)

To prevent back flow from tubing and fill-in the casing annulus

Latches

Screw to the top of the valve provides the neck for wireline tool engagement

Mandrels (Side Pocket)

Running Procedures

Pulling Operation

Whole System Design


All system should be design carefully according field requirements (current &future) Facilities to

- Avoid high back pressure- Deliver sufficient , clean gas volume

Choose the best correlation

Great -Base case- selecting the best correlation that fit your data

Beggs , brill

Duns,roseHag, brawon

Q,BPD

Press

Match point

Hag, brwon is the best

Sensitivity To Injection Depth

At the base case make sensitivity to injection depth

UP=1000

UP=1500

Bop

d

IG MMSCF

UP=1500

dep

th

UP=1000Well perf @ 20 wc

Well loading prediction

WC 40 %

WC 20 % Base

Q,BPD

Press

WC 50 % well loaded

UP=1000

UP=1500

Bop

d

IG MMSCF

Well perf @ 50 wc

Parameters selection

Q TOTAL: After calculate the amount of gas required for every well, Then the total amount of gas can be calculated

The upstream (O.P) will be selected based on economic study (additional oil VS additional cost)

Pressure Losses

- Separator to compressor Weymouth equation

- Compressor to the well panhandle equation

Horse Power Requirement

Gas Lift Production

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