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Transcript of COPYRIGHTcloud1.activelearner.com/contentcloud/portals/hosted3/PetroAcademy/... · Operators must...
Transient Testing and Artificial Lift
Nodal Analysis Workshop
Oil zone
Valve closed
Expandable rubber packer
Perforated anchor pipe
DST – Tools Run In
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DST – Open to Flow
Oil zone
Valve open
Packer set
DST Pressure / Time Profile
Sequence of events reflected on pressure-time recording during a drill stem test.
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Hydraulic Diffusivity Equation
2
2
1 p 1 p + = ...........
r 0.0002637 ttcp
r r k
Fig. 5.1 – Idealized rate and pressure history for a pressure buildup test.
Idealized Rate & Pressure
Right before shut in we have a rate and flowing bottom hole pressure
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Horner Plot – Buildup Test Data
Horner Type Plot
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
1.0 10.0 100.0 1000.0
Horner Pressure Buildup Plot
Pws (psia)
P* = 2820
Pws1 = 2660
Pws2 = 2500
P1hr = 2450
(t + Δt) / Δt
Slope = (2660‐2500)/(1‐2)
m = 160 psi/cycle
m = 160 = 162.6qoμoBo/koh
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Permeability from slope (k in mD):
Skin:
Flow Efficiency:
162.6 o o o
o
q Bm
k h
s 1.151P
1Hr P
wf m
logk
o
oc
tr
w
2
3.23
PSkin
0.87 m s
FlowEfficiency P
r P
wf P
Skin
Pr P
wf
Pskin :
Parameters from Buildup Tests
Radius of Investigation
1
2
948it
ktr
c
2948 ti
ct r
k
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Type Curve Application
Summary
Transient Analysis should provide good values for K and S (assuming the right data for h was used).
This information can go into building a Theoretical Inflow Model.
The flowing bottom hole pressure and the pre-shut in rate (for a buildup) can be used to calibrate the model.
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What is happening when there is no curve intersection of well inflow performance and tubing string performance curve?
Reservoir energy has depleted and proper selection and design of the appropriate artificial lift system is necessary.
Artificial Lift – Defining the Need
Electronic Controller
DriveHead
Low rates Heavy oil
Some sandLow gas
High ratesGas supply
Offshore prod
Gas well Dewatering
Final depletionVery low cost
Heavy oilSome sand
Low gasHigh viscosity
Power fluidTemp testsHigh cost
SelectionGuide
Very high rates No sand, Low gas
Power source
Major Types of Artificial Lift Illustrated
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Surface Performance Analysis
Down Hole Performance Analysis
Rod Pump Well Completion
Rod Pump System Components
Surface equipment
Sucker rods
Downhole pump
Analytical techniques for:• Prime mover system• Rods• Pump at reservoir depth
Reservoir inflow from producing zone
Gas Lift
Continuous gas lift works by injection of high pressure gas into the casing annulus which enters the tubing at the operating valve and reduces the liquid gradient in the tubing, thus creating drawdown.
Pressure
Dep
th
PWF SIBHP
Gas in casing
annulus
Gas lift valves
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Gas lift mandrels with gas lift valves
Gas Lift
Gas lift valves in a tubing string side pocket mandrel provide the mechanical devices required for gas lift. Lift gas enters the tubing through the valves. There may be as many as 5–10 gas lift mandrels and valves in a tubing string.
The gas lift valve sits inside the mandrel pocket
Packing
Latch
Packing
Gas exits through holes in the valve nose
Gas enters through holes in the valve
OperationGas from the casing enters the area between the seals through holes in the mandrel
Mandrel pocket
Casing
G.L.GAS
Gas Lift
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Important Valve Components
Valve bellows grow in length with pressure
Dome area which holds nitrogen pressure charge
Valve seat
Schematic is an injection pressure operated (IPO)
valve (a.k.a. pressure valve)
Valve choke
Check valve retains nitrogen charge
Valve stem with ball tip
Check valve seats when gas lift valve is not pressured
Gas Lift
Gas Lift Design<> Unloading Valveso Operating Valve
<>
<>
<>
<><>o
Pressure (psig)
Tru
e V
ertic
al D
epth
(ft)
Gas Lifted Zone Depth PresPwf
Pftp
GL DesignFlowing Tubing Gradient
Gas Lift Completion Design
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Gas injected into the casing / tubing annulus results in the pressure pushing the fluid through each of the gas lift valves which are wide open.
This is a particularly dangerous time for the valves; if the differential pressure is too high, the liquid velocity can be enough to cut the valve seat; then, the valve will not be able to close and the design won’t work.
Gas Lift
Pressure
Dep
th
SBHP
QGL
Pressure
Dep
th
SBHP
Fluid may leave the top end of the tubing, or be pushed back into the reservoir.
Gas Lift
Operators must allow sufficient time for unloading and apply API RP 11V5 which states: (a) take 10 minutes for each 50 psi increase in casing pressure up to 400 psi, after which, (b) a 100 psi increase every 10 minutes is acceptable until gas injects into the tubing, and (c) to reach 1000 psi should require at least 2 hr, 20 min: a good practice is to assign an operator to the well for the duration of this operation.
QGL
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Gas Lift
Pressure
Dep
th
SBHP
Once the fluid level is below the top valve, gas will enter the tubing and begin lifting the well; if the tubing pressure is less than the SBHP, the reservoir will begin to contribute; first production from the reservoir is normally recovered completion fluid.
QGL
Pressure
Dep
th
SBHP
Gas Lift
When the second valve is uncovered, gas will begin to enter the tubing.
QGL
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gas from casing 500
mcfd
gas tocasing 500
mcfd
gas fromcasing 500
mcfd
+500
-500
With more gas leaving casing than entering, the injection pressure must fall.
-500
Looking at just the top two gas lift valves
Gas Lift
With IPO valves, the injection gas rate into the well at the surface must be regulated to control the gas entry to approximately the design rate of onevalve; when two valves share injection gas, the pressure in the casing annulus will fall.
Pressure
Dep
th
SBHP
Gas Lift
When the casing pressure falls enough, with a good design, the top valve will close, based on valve mechanics.
QGL
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Pressure
Dep
th
SBHP
Gas Lift
Since there is still more casing pressure than tubing pressure at the bottom valve, and, the bottom valve is still open, the injection gas will continue to displace the fluid in the annulus until the third valve is uncovered.
QGL
Pressure
Dep
th
SBHPWhat happens if the third valve injects too much gas?
Gas Lift
Once again, with injection gas leaving the annulus through two valves, the casing pressure will fall until the second valve closes. If there are more valves deeper, the unloading process continues.
QGL
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Pressure
Dep
th
Gas Lift
The gas lift completion has completed the unloading of the completion fluid and is now set up in operating mode. Gas lift technicians now carefully monitor the performance of the completion and make minor adjustments accordingly.
QGL
Pw
f
Rate
A B C
Gas Lift
Observe the effect of injecting different injection rates into the well.
Case “ A” is a small amount of lift gas, case “B” is an increased amount of gas, and case “C” is a further increase in gas rate injected.
These 3 cases would generate three production rates.
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Pro
duct
ion
Rat
e
Gas Injection Rate
A
BC
Gas Lift
A graph of production rate vs the three different gas lift gas injection rates produces the lift gas performance curve.
Pro
duct
ion
Rat
e
Injection Rate
technical optimum
economic optimumoptimum within
constrained group
Gas Lift
In most cases, there is a limited amount of gas available for all the wells.
The optimum rate must be determined within the constraints of the total gas available for a group of wells.
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ESPAn electric submersible
pump consists of downhole equipment
Pump
Intake
Motor
Cable
Equalizer
And...
ESP
Cutaway view of pump diffuser section, gas separator, and cable
Diffuser
ESP
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ESP Principle
Using Bernoulli’s equation* (expressed in “energy per unit mass” in steady state) in presence of a pump.
ρg ∆H + ρ ∆V2/2 + ∆Pp = > constant <
=> ∆Pp = ρ ∆V2/2
Where: g = gravitational acceleration constant, in m/s2
∆H = altitude variation, in m∆Pp = pressure increase provided by the pump, in Pa ρ = density of the fluid, in kg/m3
V = velocity at the impeller outlet, in m/s
Hence: The dynamic head ∆H is independent of the densityThe pump delivery pressure depends on the density of the pumped fluid.
* The increase in the speed of a fluid occurs simultaneously with a decrease in pressure or a decrease in the fluid’s potential energy.
Thus, for a given impeller at a given rotational speed, the more rate, the less head as shown on the plot of the pump curve on the TDH vs. Rate graph below.
The pump curve quantitatively shows the head that the pump can supply at a given rate (and rotational speed).
TD
H
Rate
Pump Curve
ESP
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Vendors show an operating range on their pump curves that do not define the safe range, but a range inside of the highest efficiency.
The relationship of the most efficient range to the danger areas of upthrust and downthrust is not known in most pumps, so the efficiency limits are used instead.
Rate
TD
H
UpthrustDownthrust Efficient
ESP
Total Dynamic Head (Primary Design Requirement)
The TDH required to pump the reservoir inflow capacity refers to the sum of the following:
1. Net well lift component - HL
2. Well tubing friction loss component - HF,
3. Wellhead discharge component - HD
with all expressed in pressure units of head (in feet/meters).
TDH = HL + HF + HD
GAS SEPARATOR
HL
HD
HF
ESP Total Dynamic Head – TDH
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H-27ESP
PumpCurve
ESP PUMP Curve For 5-1/2” Well Casing
BHP
Head Capacity
Pump Efficiency
ESP Manufacturer Pump Curve
Progressing Cavity Pump
Applications:• Heavy oil • Stripper well rates• Varying inflow• High water cut• Gas well dewatering
•
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Plunger Lift Unloads fluids from low
energy wells.
Plunger travels to well bottom and “swabs” fluid to the surface.
Continual removal of wellbore fluids reduces BHP.
System operates on continuous cycle.
Lubricator
Solar Panel
Controller
Motor Valve
Plunger
Plunger Catcher
Gas
Bottom Hole BumperSpring Standing Valve
Well Fluid
Seating Nipple / Tubing Stop
Plunger Lift System Components
Surface
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