Ashutosh Narayan PandeySr Reservoir Engineer

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

• 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

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

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

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

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).

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

3500

4500

-2 0 2 4 6 8 10 12 14-100

900

History plot (Pressure, Liquid Rate vs Time)

4600

5600

-2 0 2 4 6 8 10 12 14

-1000

0

History plot (Pressure, Liquid Rate vs Time)

4972

4982

4992

5002

-10 10 30 50 70 90-200

1800

History plot (Pressure, Gas Rate vs Time)

4945

4965

4985

5005

-5 5 15 25 35 45 55 65 75-200

1800

History plot (Pressure, Gas Rate vs Time)

4945

4965

4985

5005

-2 3 8 13 18 23 28-500

History plot (Pressure, Liquid Rate vs Time)

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])

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

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

Reality Model

Reservoir Reservoir RockRock

HydrocarbonHydrocarbonss

FaultsFaults

Pressure Plots

Mathematicalequations

Analysis

R&D

fn kct, rw, etc)

q

Well&

Reservoirp

q

t

0p

t

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

mh

qB6.162k

23.3

rc

klog

m

pp151.1s

2wt

10hr1i

BASIC EQUATION OF PRESSURE BUILD UP TEST:

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

Elapsed time, hrs

Early-timeregion

Middle-time

region

Late-timeregionP

res

sure

ch

ang

e, d

eriv

ati

ve, p

si

Sealing Fault and Constant Pressure

Boundary

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

Naturally Fractured System - Dual Porosity

System

Hydraulically Fractured Wells

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.

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

1. Model Recognition2. Parameter Estimation3. Model Validation

Constant Well-bore storage and skin producing from a homogenous reservoir in the presence of multiple boundaries (Faults and Constant Pressure)

K = 700 mD, Skin = -3.4

Distance to first boundary, d1 (No-flow) = 200 m

Distance to second boundary, d2 (Constant Pressure) = 225 m

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

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