welltesting for non reservoir enginners
TRANSCRIPT
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Ashutosh Narayan PandeySr Reservoir Engineer
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Objectives: Well Productivity/deliverability (IPR, AOF etc) Reservoir Fluid Sample collection for PVT analysis Evaluate Reservoir parameters (Permeability, Reservoir
pressure) Evaluate Well Damage (Skin Factor) Reservoir Characteristics and Hetrogenities Reservoir Geometry (presence of Faults/ Fluid contacts and
their distances) Estimating Inplace Hydrocarbon Volumes
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• permeability is a property of the porous medium and is a measure of the capacity of the medium to transmit fluids
• Commonly used unit is millidarcy (mD)
Well Testing gives Effective Permeability
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Effective permeability: is a measure of the conductance of a porous medium for one fluid phase when the medium is saturated with more than one fluid.
The porous medium can have a distinct and measurable conductance to each phase present in the medium
Effective permeabilities: (ko, kg, kw)
Effective Permeability
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Skin Effect
Skin is an additional pressure change due to heterogeneities close to the wellbore.
Possible causes:+ve skin Invasion of mud filtrate or cement during drilling or
completion Non-ideal perforations - too low shot density - plugged Limited entry - partial penetration Turbulent gas flow
-ve skin Acidization or stimulation
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Skin Factor
Skin factor is a variable used to quantify the magnitude of the skin effect.It is a dimensionless variable.
Skh
qBps
1412.
In approximate terms:
A skin of +8 will cut the flow rate in half A skin of –4 will double the flow rate
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Process: Lowering Pressure Gauges in the wellbore. Introduce Abrupt change in Flow rate of the well. measure P, T, and Q vs time (pressure, temperature, and flow rates, respectively).
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1. Build-up Test
2. Falloff Test
3. Flow After Flow Test / Multi rate Test
4. Isochronal Test
5. Modified Isochronal Test
6. Interference Test
7. Interference Pulse Test
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3500
4500
-2 0 2 4 6 8 10 12 14-100
900
History plot (Pressure, Liquid Rate vs Time)
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4600
5600
-2 0 2 4 6 8 10 12 14
-1000
0
History plot (Pressure, Liquid Rate vs Time)
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4972
4982
4992
5002
-10 10 30 50 70 90-200
1800
History plot (Pressure, Gas Rate vs Time)
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4945
4965
4985
5005
-5 5 15 25 35 45 55 65 75-200
1800
History plot (Pressure, Gas Rate vs Time)
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4945
4965
4985
5005
-2 3 8 13 18 23 28-500
History plot (Pressure, Liquid Rate vs Time)
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4955
4965
4975
4985
4995
[psia
]
0 20 40 60 80 100 120 140 160
0
1000
[ST
B/D
]
History plot (Pressure [psia], Liquid Rate [STB/D] vs Time [hr])
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Wellbore Storage
•When we open the master valve at the beginning of a welltest, the well may produce at a constant rate at the surface. However, the flow rate from the reservoir in to the wellbore may not be constant at all.
•When we shut the well with master valve, the well still flows at the sandface.
C V Cw w where :Vw is the wellbore volume
and Cw the well fluid compressibility
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Early Time Region provides Near Wellbore Information (Affected by Wellbore Storage)
Middle Time Region gives Permeability,Skin& Reservoir Characteristics etc
Late Time Region gives Boundaries Information, Reservoir Pr. Inplace HC volumes
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Reality Model
Reservoir Reservoir RockRock
HydrocarbonHydrocarbonss
FaultsFaults
Pressure Plots
Mathematicalequations
Analysis
R&D
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fn kct, rw, etc)
q
Well&
Reservoirp
q
t
0p
t
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Fluid flow in a porous medium is governed by:
Combining:Darcy’s LawConservation of mass Diffusivity EquationEquation of state. 2p/r2 + 1/r (p/r) = (Ctk) p/t
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mh
qB6.162k
23.3
rc
klog
m
pp151.1s
2wt
10hr1i
BASIC EQUATION OF PRESSURE BUILD UP TEST:
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Log-log plots are used in welltest interpretation
It is a plot of pressure change Vs log∆t
In wellbore storage affected region it gives unit slope line
Since 1983, log-log derivatives are used in welltest interpretation. Derivatives are differentiation of pressure change wrt time
Boundary effects are evident by late time variation of the derivative value
Log ∆t
Log ∆P
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Elapsed time, hrs
Early-timeregion
Middle-time
region
Late-timeregionP
res
sure
ch
ang
e, d
eriv
ati
ve, p
si
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Sealing Fault and Constant Pressure
Boundary
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Composite Rectangle
Sealing fault 1 - derivative increasesSealing fault 3 - derivative continues to increaseConstant pressure 2 - derivative drops graduallyInfinite 4 - maintains some support
Sealing fault
Sealing fault
Infinite
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Naturally Fractured System - Dual Porosity
System
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Hydraulically Fractured Wells
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OPERATIONAL SEQUENCE: Production (Oil) - personnel to flow the well and ensure that the well
is on uninterrupted production through existing bean for 48 hours. During this period, flow rate & GOR should be measured and well head pressures to be recorded at regular intervals. 2-3 Master samples to be collected and sent to Chemical Laboratory for determination of API gravity of oil, percentage of water content, viscosity of oil and pour point (o C).
Chemical department to run in BHP gauge and record FBHP data at 500, 1500, 3000 and 3752 m for 0.5 hrs each and at 3902 m for 2 hrs.
Production (Oil) personnel to shut in well for 80 hours (tool at 3902 m).
Chemical department to record SBHP at 500, 1500, 3000 and 3752 m prior to pull out of tool.
Run in bottom-hole sampler to 3902 m and collect 2 semi static samples.
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Basic Inputs
Flow rate and Pressure measurement vs time
PVT properties
Rock properties
Perforation data
In Oil India, Software used for Well test Interpretation is WELTEST 200 developed by Schlumberger
KAPPA’s SAPHIR and FAST WELLTEST by Fekete are the most widely used Welltest Interpretation softwares
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1. Model Recognition2. Parameter Estimation3. Model Validation
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Constant Well-bore storage and skin producing from a homogenous reservoir in the presence of multiple boundaries (Faults and Constant Pressure)
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K = 700 mD, Skin = -3.4
Distance to first boundary, d1 (No-flow) = 200 m
Distance to second boundary, d2 (Constant Pressure) = 225 m
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It includes Test Objectives Test Type Test duration
Radius of Investigation
Distance a pressure transient has moved into a formation following a rate change in a well tt
i c
tk
c
tkr
94800105.0
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Build-up test could be done in already Shut-in wells !!
After Shut-in, pressure builds up rapidly, so 24 hours shut-in is maximum for Well Test
Lowering of Pressure gauge after shut-in of Well
Well Test could be done in Artificial Lift wells.
No need to shut the well for Sample collection for PVT analysis
Flow rate measurement with time is not Important
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