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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
Design of Intermittent Lift Installation
Design of Intermittent Lift Installation
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)
Design of Intermittent Lift Installation
• 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
Design considerations
Design considerations
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
Design considerations
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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Gas Lift Survey Examples0
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re FGas Lift Survey Examples
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.
Gas lift Optimization
Gas lift Optimization
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
Design considerations
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
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