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CYAN MAGENTA YELLOW BLACK

Injecting oil back into a reservoir might seem an

odd thing to do but it has given a boost to reservoir

characterization in Turkey. Instead of creating a

flow-rate perturbation by producing the well, the

Turkish Petroleum Corporation (TPAO) and

Schlumberger put their heads together and came

up with the unusual idea of carrying out an

equivalent test by injecting oil into the formation -

a technique normally reserved for water injectors.

Jorge Torre, Schlumberger Chief Reservoir

Engineer for the Middle East, with Erol Memioglu

and Can S. Bakiler of TPAO’s Reservoir

Engineering Department, outline the tests and

explain the results. Jorge and Mahmoud Latif of

Egypt’s Gulf of Suez Petroleum Company (GUPCO)

also show how tests using water injection have

helped in measuring abnormally low formation

parting pressures in a multi-layered reservoir. In

addition, they explain how pulse tests in water

injectors, normally used to check a formation’s

hydraulic connectivity, have been harnessed to aid

reservoir characterization in the Gulf of Suez.

Contributions by Eric Standen,

Schlumberger, Egypt.

Injection booster for testin

g


42 Middle East Well Evaluation Review

Istanbul

Ankara

Adana

Malatya

Diyarbakir

Ak-Pinar Field

Cendre Field

B.Firat Field

K.Karakus Field

Gerger

Karakus Field Guney Karakus

Field Besikli Field

Narinca

Kahta

Firat

Firat T U R K E Y

Ka ta h

Injection revives Turkey'slow-energy wells

In naturally flowing wells,

conventional shut-in

testing is relatively easy.

But what happens when a

reservoir has such low

energy that a well will not

flow naturally to the

surface? This was the

problem facing TPAO's

reservoir engineers on the

Karakus Field when they

tried to use pressure

transient testing for

reservoir characterization.

Open-hole log information had

shown that the tight carbonate

reservoir in the Karakus Field

was highly fractured and that a dual-

porosity system existed. Determining

the matrix and fracture permeabilities

and storativities was therefore essential

before a complete model of the entire

field could be set up. But how could

these figures be obtained?

The conventional method of testing

non-flowing wells, using a Drill Stem

Test (DST), involves lowering a DST

string into the borehole and setting a

packer near the perforations. A valve in

the DST is opened to allow reservoir

fluid to enter the wellbore. Just before

the borehole fluid pressure equals that

of the formation (at which point flow

would stop), the well is shut in to create

a build-up period. Unfortunately, the

maximum flow period that can be

attained in Turkey’s non-producing

wells is not long enough to promote full

radial flow in the reservoir.

This means that an analysis of DST

results from this kind of well would nor-

mally give erroneous results (ie. values

of reservoir permeability and skin that

are too high). The problems are even

worse in fractured reservoirs because

the drawdown period has to be kept

much longer to give sufficient time for

radial flow to develop before shut-in

(see box on page 46).

TPAO and Schlumberger decided to

test the non-flowing wells by introduc-

ing a perturbation through injection of

oil into the formation prior to shut-in.

This gave them control of the flow peri-

od and size of perturbation (injection

rate).

Injecting oil in this way is costly but

the fluid returned to the formation is

usually recovered when the well is put

back on stream.

Deciding the length of time neces-

sary to attain full radial flow was one of

the main problems during test design.

The engineers also wanted to guard

against fluctuations in injection rate.

Both difficulties were overcome by

using surface read-out and combined

downhole flow and pressure measure-

ments (Middle East Well EvaluationReview Special Supplement on ReservoirTesting, January 1991).

These simultaneous readings with

the Production Logging Tool (PLT*)

allowed the engineers to spot the devel-

oment of full radial flow prior to well

shut-in. In addition, the continuous

flow measurements enabled the ana-

lysts to remove any noise in the pres-

sure response which might have arisen

due to flow rate variations. Accurate

information about the reservoir charac-

teristics could then be reliably extract-

ed from the pure reservoir signal (see

box overleaf).

The engineers faced another prob-

lem. How could they be sure that radial

flow did not start during the early time

when the pressure response is dominat-

ed by wellbore storage effects? The best

way to minimize these effects was to

use downhole shut in.

A Schlumberger Cyber Service Unit

(CSU*) logging truck was used to moni-

tor real-time injection and pressure

measurements in the well during the oil

injection phase. A Dowell Schlumberger

pumping unit supplied fluid at a rela-

tively constant rate to the perforated

area of the wellbore (figure 4.3).

A Pressure-Controlled Tester (PCT*)

valve allowed full-bore access into the

well. This enabled the Production Log-

ging tool (PLT*) to be passed through

the DST string. In addition, downhole

memory gauges were positioned

beneath the packer in readiness for

43Number 12, 1992.

monitoring the pressure build up. (The

wireline tools have to be removed

before shut in).

Since it was difficult to predict when

the distinctive dip in the derivative

curve might appear, two downhole

memory pressure gauges had to be

used. One gauge was triggered at the

start of the test and recorded at a low

sampling rate (one measurement every

15 minutes for the duration of the test).

The other gauge was programmed to

start sampling at high rate just before

the shut in and had enough memory to

store two hours of pressure fall-off data.

The test engineers faced several

practical problems. Injecting oil evenly

into the well prior to shut in was diffi-

cult as the oil had to be conveyed to the

site in a relay of tanker trucks. It was

also very difficult to predict how long it

would take before full radial flow was

achieved. Eventually, for practical pur-

poses, it was decided to inject oil for

just 10 hours at a rate of 2400B/D.

Fig. 4.2: Comparison

of a flow profile

obtained from an

open-hole PLT

survey with the

fracture porosity and

fracture apertures

derived from

Formation

MicroScanner*

images using the

Fracview* program

on a computer

workstation. The

flow increases

considerably in the

fractured section of

the reservoir.

Fig. 4.1: FACING UP TO FRACTURES (Above): Author Erol Memioglu examines fractures

in statues in the ancient ruined city of Nemrut which lies close to the Karakus Field in

Eastern Turkey. The fractured section of core (right) was taken from the Karakus Field

reservoir rocks.

50m

PLTflowprofile

KARAKUS IN ANUTSHELLThe Karakus Field is located in

Turkey’s most prolific oil-producing

area. It lies close to the city of Adiya-

man, near the famous ruined city of

Nemrut (figure 4.1). The field is

bounded to the northwest by the left

lateral Adiyaman wrench fault. To the

south, a parallel left lateral strike-slip

fault separates the field from the

neighbouring Güney Karakus Field.

The anticlinal structure of the Karakus

Field is highly deformed by the

wrench fault system that has devel-

oped under compressive stress.

Oil is found in Lower Cretaceous

Mardin Group carbonates which over-

lie the Cambrian-age clastic Sosink

Formation. The Mardin Group is sub-

divided into five main units - the Are-

ban, Sabunsuyu, Derdere, Karababa

(A, B & C members) and Karabogaz

formations. The most important oil-

bearing unit is the 100m-thick Derdere

Formation which comprises low-to-

medium porosity dolomite (lower por-

tion) and tight limestone (upper

portion).

The upper formations in the field

are ordered from bottom to top as fol-

lows: The Sayindere, Kastel, Germav

formations, the Midyat Group and the

Selmo Formation. None of these for-

mations has any hydrocarbon poten-

tial.



Most of the fluid that first enters a well

in a fractured reservoir comes from

fracture storage. Any oil contained in

the lower-permeability matrix tends not

to move until the fractures become

depleted. At this point a pressure differ-

ence is set up between the fractures

and matrix that 'sucks' oil out of the

tighter rock. Eventually the two systems

(matrix and fractures) start to reach

equilibrium and the pressure distribu-

tion becomes analogous to that of a

homogeneous system.

These three distinct phases can be

clearly seen in the measured pressure

response at the well. Figure 4.4 shows

DUAL POROSITY DETECTION

MIRV

SSARV

PCT

HRT

Safety jointPositrieve

packer

Perforated tail pipe

Wireline entry guide

Downhole memory

gauge

Crystal

PLT

DS

10

1

10-1

10-2

Dim

ensi

onle

ss p

ress

ure

grou

ps

10-1 1 10 102 103 104 105 106

tD/CD

Build-up Drawdown, transitional Drawdown, homogeneous

tpD/CD=3x105

10

1

10-1

10-2

Dim

ensi

onle

ss p

ress

ure

grou

ps

10-1 1 10 102 103 104 105 106

tD/CD

Drawdown, transitional Drawdown, homogeneous

Build-up (tp/C)D=25 Build-up (tp/C)D=100

tpD/CD=25

tpD/CD=100

the pressure and pressure-derivative

response of a drawdown test. The first

horizontal portion of the derivative

curve represents radial flow in the frac-

ture network. A dip in the derivative

curve occurs when the matrix begins to

contribute to the fluid flow, after most of

the fractures have been drained. The

time at which the dip appears on the

derivative curve depends mainly on the

contrast between the matrix and frac-

ture permeabilities (λ). The size of the

dip is controlled by the ratio of the

matrix and fracture storativity values

(ω). The smaller the fracture storativity,

the bigger the dip and vice versa. The

second horizontal portion in the deriva-

tive curve indicates homogeneous

behaviour and characterizes the total

system response.

Fig. 4.3: Tool

string used

during the

downhole

testing

operation in

the Karakus

Field.

Fig. 4.4: In this double-porosity reservoir the derivative of the pressure

curves can be used to match build-up data to drawdown type curves

even though the pressure curves do not match.

Fig. 4.5: This illustrates the effect of insufficient drawdown time prior to

build-up. The well was shut in during fissure flow.

D Bourdet et al; World Oil Oct. 1983.

D Bourdet et al; World Oil Oct. 1983.

45Number 12, 1992.

Fig. 4.7: The tests helped the

Karakus Field engineers to

detect two impermeable

boundaries near to the

well.

10-4 10-3 10-2 10-1 100 101 102 100

101

102

103

104

∆p a

nd d

eriv

ativ

e gr

oups

, psi

∆t, hr

Pressure derivative

Pressure response

Matrix contributes to fluid flow

Figure 4.5 shows two build-up pres-

sure and pressure-derivative respons-

es for two tests performed in the same

dual-porosity reservoir but with differ-

ent drawdown periods prior to shut-

in. Note that the shape and time at

which the dips occur are now affected

by the length of the flowing period

prior to shut-in.

It is essential that the flow period is

long enough to encourage full radial

flow to develop in the reservoir

before shut-in. This ensures that the

obtained values of λ and ω remain

independent of the length of the draw-

down.

One of the difficulties in conven-

tional surface testing of dual porosity

systems arises when the contrast

between the fracture and matrix per-

meabilities is such that the dip in the

derivative curve occurs at early time.

If this happens, wellbore storage

effects will mask the appearance of

the dip. Therefore, the analyst will

lose all the valuable information

about fracture characteristics which is

reflected in the shape and time of

occurence of the dip. Downhole test-

ing techniques significantly reduce

wellbore storage effects and guard

against this danger.

However, moving downhole does

not eliminate all the problems. The

shape of the derivative curve in a

build-up test is not only a function of

the wellbore-reservoir system but

also of the previous flow history (fig-

ure 4.5). The most accurate well test

data is obtained by having a long peri-

od of stable well flow before the well

is shut in. This allows full radial flow

to develop throughout the fracture

network and matrix during drawdown

and minimizes the effects of produc-

tion prior to shut in.

Schlumberger and TPAO decided

that the best method of achieving a

stable flow rate perturbation in the

non-flowing wells was to have a con-

stant negative well flow - in other

words inject oil into the well. In this

way the flow rate and its duration

could be controlled and the reservoir

could be subjected to a bigger pertur-

bation, giving accurate results.

The results shed a great deal of light on

the reservoir’s behaviour. Figure 4.6

shows a comparison of the real data

and the simulated results. There is an

excellent agreement between both

curves, suggesting that the selected

model and its parameters reliably

describe the reservoir's dynamic

behaviour.

By analysing the pressure data, the

engineers obtained the characteristic

parameters of the fracture system and

also detected two parallel impermeable

boundaries: one 245ft and the other

710ft from the well (figure 4.7).

-165

0 -1700

-1750

-1800

-1850

-190

0

Reliable results

Fig. 4.6: A comparison of the real data and the simulated results. There is an excellent

agreement between both curves, suggesting that the selected model and its parameters

reliably describe the reservoir’s dynamic behaviour.

Test results:

Distance to nearest boundary = 245 ftDistance to furthest boundary = 710 ftλ = 1.4x10-7

ω = 0.20Wellbore storage coefficient = 0.0116 bbl/psikh = 36880 md-ftSkin = -2.57



0 50 km

N Suez

G u l f o f S

u e z

El Tur

Badri Field

Producer

Injector

5200

5400

5600

5600 5800

5800

6000

6200

6400

5600

5600

5500

El Morgan Field

Fig. 4.8: DOUBLE

TROUBLE: Injection-

based well testing had

to be carried out in

Egypt's Badri and El-

Morgan Fields to help

understand problems

of formation

breakdown.

The primary oil

trapping mechanism

for the Badri Field is

thought to be a

combination of block

faulting and folding

with local stratigraphic

variations. The

Belayim Formation

consists predominantly

of sandstone

interbedded with finer-

grained dolomitic silts

and shales. The

sandstone beds are

separated by mudstone-

shale intervals.

The El-Morgan

Field is an elongated

northwest-trending,

faulted anticlinorium

containing two major

structural faults. The

main producing

horizon is the Kareem

Formation which

consists of stacked

coarsening-upwards

sequences that

represent the

progradation of deltaic

sand lobes and open-

marine mudstones.

Fig. 4.9: TAKE A BREAK: To

determine the fracture

pressure gradient, the

injection pressure is plotted

against the injection rate.

When the fractures open in

the formation, they produce

a distinct break in slope on

the plot indicating an

increase in injectivity. This

point also marks the fracture

pressure gradient. In this plot,

the fracture pressure gradient

is 0.468psi/ft.

3100

3000

2900

2800

2700

2600 1 2 3 4 5 6 7 8 9 10 11

Injection rate (rps)

Inje

ctio

n pr

essu

re (

psia

)

FG=0.468psi/ft

49Number 12, 1992.

1000 8000

3000

13000

Wat

er in

ject

ion

(BW

PD

) T

ool p

ositi

on

6700

6545

6440

Dep

th (

ft)

HF1

HF3

Aconventional way of measuring

the fracture parting pressure is

to carry out a Step Rate Test

(SRT). During an SRT, the injection rate

into the entire formation is increased in

steps while the injection pressure is

measured downhole. When fracturing

starts there is a sudden change in the

flow rate and this can be used to esti-

mate the fracture gradient.

The injection pressure is plotted

against the injection rate (figure 4.9).

Two clear slopes can be seen. The first

line represents the injectivity of the for-

mation before parting occurs. The sec-

ond slope indicates the increase in

injectivity due to the presence of

induced fractures.

However, the Badri Field consists of

multiple sandstone layers with different

degrees of depletion. Therefore, the

simultaneous flooding of all these layers

during an SRT would provide inaccu-

rate parting pressures. To overcome

this problem, the engineers decided to

opt for a Layered Reservoir Test (LRT).

This involved lowering the PLT to

various points above and between the

producing layers to measure changes in

injection rate and pressure. The prima-

ry oil-trapping mechanism for the Badri

Field is thought to be a combination of

Finding out about formation breakdown

block faulting and folding with local

stratigraphic variations. The Belayim

Formation consists predominantly of

sandstone interbedded with finer-

grained dolomitic silts and shales. The

sandstone beds are separated by mud-

stone-shale intervals. This study investi-

gated two continuous beds - Hammam

Faraun 1 and 3 (HF1 and HF3).

The Badri Field has 21 producing

and 10 injection wells (figure 4.8). The

Badri D3 injection well was selected as

the active well for the test which con-

sisted of four transients: changing the

well-head injection rate from

7,000BWPD to 3,000BWPD, then to

8,000BWPD, to 13,000BWPD and finally

to zero by shutting-in the well. The two

selected reference positions for the PLT

were in the maximum flow zone (above

the top perforation) and between layers

HF1 and HF3.

Figure 4.10 shows the injection rate

sequence and the tool’s position

throughout the test. In each case the

PLT was moved into its new position 30

minutes before the injection rate was

changed and was left there during the

transient. Injection rates and stationary

readings between the perforations were

taken at the end of each transient.

Fig. 4.10: Sequence of events during the layered reservoir test. The shaded

areas represent the four transients and the arrows show the positions and times

of the flow profile surveys.

High injection rates are normally

used to improve the performance

of waterflood operations. But

sometimes the resulting high

pressures can induce fractures that

seriously affect the vertical and

horizontal sweep efficiencies.

In Egypt’s Badri Field this

problem is particularly acute

because formation breakdown

begins at very low injection

pressures.

A layered reservoir test was the

most cost-effective way of

calculating the optimum injection

rates that could be safely used

without fracturing the formation.

Using this technique, it was

possible to determine the

formation parting pressure for each

producing interval.



Watching the formationfracture

The first transient test was created

when the injection rate was allowed to

drop from 7,000BWPD to 3,000BWPD.

The pressure decline was measured

with the tool between HF1 and HF3, at

6545ft. As the pressure drops, the frac-

tures close. This event can be seen in

figures 4.11 and 4.12. Flow rate and

pressure decrease for 1.5 hours, after

which the flow rate stabilizes and the

pressure suddenly increases by 100psi.

This value of pressure gives a fracture

gradient of 0.413psi/ft. After 4.4 hours,

fractures open in the top layer, causing

the injection rate and the pressure to

drop suddenly. This fracturing hap-

pened when the pressure reached

2,497psi, giving a fracture gradient of

0.44psi/ft.

The second transient was created by

increasing the injection rate from

3,000BWPD to 8,000BWPD. Prior to

changing the rate, the tool was moved

to a position above both layers at

6,440ft. Two main events occurred (fig-

ure 4.13). At 0.075 hours into the tran-

sient, there is a sudden increase in

injectivity without a noticeable increase

in the formation pressure.

This suggests that there is less resis-

tance to water flow into the formation.

The pressure continues to increase up

to 0.6 hours into the test, when it sud-

denly starts to drop. This is probably

caused by either two fractures opening

in succession, or vertical extension of

the first fracture. This gives pressure

gradients of 0.465psi/ft and 0.479psi/ft

respectively.

2800

2710

2620

2530

2440

2350

Pre

ssur

e (p

sia

and

spin

) D

im

10-3 10-2 10-1 100 101 102

Elapsed time (hr)

FG = 0.44 psi/ft

p vs dt Scaled spin vs dt

500

400

300

200

100

0

Rat

e no

rmal

ized

pre

ssur

e va

riatio

ns

0.4 0.6 0.8 1.0 1.2 1.4 Superposition time function (*104)

1.6 1.8 2.0 2.2

Dt = 0.06 hours

Transient 2 SUPPOS.FUN: 7.dd

Dt = 0.03 hours

2850

2770

2690

2610

2530

2450

Pre

ssur

e (p

sia

and

spin

) D

im

10-3 10-2 10-1 100 101 102

Elapsed time (hr)

FG = 0.46 psi/ft

p vs dt Scaled spin vs dt FG = 0.48 psi/ft

500

400

300

200

100

0

Pre

ssur

e va

riatio

ns (

psi)

0 2 4 6 Spinner variations (rps)

8 10 12

Dt = 1.5 hours

m = 92 psi/rps

Fig. 4.12: (Top right): During the first transient the pressure

suddenly increases by 100psi when the fractures close.

Fig. 4.11: (Top left): This shows an injectivity of 92psi/rps for the

bottom layer. At 1.5 hours into the transient, the fracture closure is

marked by a sudden drop in injectivity.

Fig. 4.13: (Left):

During the second

transient there is a

sudden increase in

flow rate but no

corresponding

pressure increase.

There is also a

sudden pressure drop

at 0.6 hours into the

test.

Fig. 4.14: (Left):

This generalized

Horner plot of the

second transient

indicates that

radial flow only

occurs prior to

fracturing.

2880

2850

2820

2790

2730

2700

Pre

ssur

e (p

sia

and

spin

) D

im

2760

10-3 10-2 10-1 100 101 102

Elapsed time (hr)

p vs dt NSPINDT

FG = 0.49 psi/ft

Fig. 4.15: During

the third

transient,

fractures open at

0.39 hours into

the test and this

causes a pressure

drop but the flow

rate remains

constant.

51Number 12, 1992.

Poisson's ratio 0.5 0

Bulk compressibility (psi)0.0 2.5

Young's modulus (psi)0 20

Pore press gradient (ps/f)

1 0

Parting press grd (ps/f)1 0

Overburden press grd (ps/f)1 0

Delta T compressional (us/f)

240 40

Delta T shear (us/f)240 40

HydrocarbonWaterSandShale

Dolomite

Volume of clay (pu)

0 100

Porosity (pu)100 0

In an isotropic and homogeneous

reservoir the pressure needed to initi-

ate a fracture can be estimated using

a relationship which links minimum

and maximum horizontal stresses, the

rocks tensile strength, Biot’s elastic

constant and pore pressure. However,

the minimum horizontal stresses can-

not be measured with current technol-

ogy. Assuming the reservoir is a

horizontally constrained isotropic

elastic model, and neglecting deforma-

tions due to thermal variations, mini-

mum horizontal stress can be written

as a function of the overburden pres-

sure, Poissons ratio, Biot's constant

and pore pressure†.

Poisson's ratio and Biot’s elastic

constant can be derived from the seis-

mic shear and compressional wave

travel times (∆ts and ∆tc). ∆ts was not

recorded at the time the injector wells

were drilled, but new producer wells

higher up in the structure have ∆ts

data.

These mathematical relationships

together with data from neighbouring

wells have been used to investigate

the effect of pressure depletion on

fracture gradient reduction. The

results show fracture gradients con-

siderably higher than the recorded

values obtained from the LRT test (fig-

ure 4.16). Therefore, the assumptions

that the reservoir stresses are horizon-

tally uniform and that thermal varia-

tions cause negligible deformations

cannot be justified. This leads us to the

conclusion that both the tectonic

nature of the area and thermally

induced stress reduction, due to cold

water injection (see box on page 53),

must be considered in any theoretical

calculations.

PREDICTING FRACTURE GRADIENTS

Fig. 4.16: IN THE RED: Mechanical properties log (MECHPRO*) obtained from a

producing well in Badri Field. The fracture parting pressures are shown in red in the

second track. These are computed using log-derived rock mechanical properties

(track 1) and a horizontally constrained elastic model.

The rapid drop in pressure and flow

rate at about 4 hours is due to a surface

problem, and not a reservoir response.

Figure 4.14 is the generalized Horner

plot of the test. The slope of the straight

line is greater than that plotted from the

later fall-off test after the effect of well-

bore storage and fractures have disap-

peared. This suggests that radial flow is

happening in only a part of the tested

interval. This portion of the tested inter-

val might be related to the height of the

induced fractures.

For the third transient, the injection

rate was increased to 13,000BWPD. The

tool was left in its position above the

two layers for this part of the test. The

response of the flow rate and pressure

to the increasing injection rate can be

seen in figure 4.15.

†GR Coates and SA Denoo, 1981;Mechanical Properties Program UsingBorehole Analysis and Mohr's Circle,SPWLA 22nd Ann. Log. Symp. Trans.



Injection period HF1 HF2 Wellbore pressure

rate rate potential

(B/D) (B/D) (psi)

1 1100 2023 2471.1

2 2380 4857 2736.1

3 2483 5496 2713.1

4 4050 9254 2836.0

5 392 -392 1706.4

3000

2600

2200

1800

1400

1000

Inje

ctio

n pr

essu

re p

oten

tial (

psia

)

-1 0 2 4 6 Injection rate (BWPD *103)

8 10

Top reservoir - HF1 Bottom reservoir - HF3

Fig. 4.19: The

fracture gradients

can be calculated

from this plot of

pressure potentials.

Table 4.1: The

measured

injection rates for

each of the two

reservoirs.

1200

1000

800

400

200

0

Pre

ssur

e va

riatio

n (r

ps)

600

0 5 10 15 20 25 Spinner variations (rps)

m = 18 psi/rps

m = 18 psi/rps

Dt = 0.03 hours

Fig. 4.17: As

the injection

rate decreases

the fractures

begin to close

at 0.03 hours.

Fig. 4.18: By 0.06

hours the

injection rate has

fallen to zero and

the well has gone

on vacuum.

3100

2820

2540

2260

1980

1700

Pre

ssur

e (p

sia

and

spin

) D

im

10-3 10-2 10-1 100 101 102

Elapsed time (hr)

Change in injectivity

Falloff p vs dt Scaled spin vs dt

Well goes on vacuum

At 0.39 hours into the test, a fracture

opens or grows in one of the two layers

and the pressure begins to drop. The

flow rate remains constant as the tool is

above the layers. This occurs at a pres-

sure of 2,844psi and gives a fracture gra-

dient of 0.48psi/ft.

For the final transient, the injection

rate was reduced to zero by shutting in

the well with the tool stationed between

the layers at 6,545ft. As the injection

rate decreases, the plot of flow rate

against pressure (figure 4.17) shows

that at 0.03 hours into the fall-off, frac-

tures are beginning to close. This is sig-

nalled by a sudden change in

injectivity. This event can also be seen

in figure 4.18, at a pressure of 2,667psi.

The pressure pattern at 0.06 hours

shows the injection rate has fallen to

zero and the well begins to go on vacu-

um (when the pressure in the wellbore

equals that of the formation). From then

onwards, until the spinner stops, the

injectivity is almost identical to that

observed in the first transient before

the fractures close.

Parting shots

Table 4.1 summarizes the measured

injection rates for each of the two reser-

voirs, HF1 and HF3, and the corre-

sponding wellbore pressure potentials.

This is shown graphically in figure 4.19.

By extrapolating the lines into the

region where they intersect, engineers

calculated that the fracture gradients

lay somewhere between 0.43psi/ft and

0.48psi/ft. Patterns established by the

transient data showed that the changes

in injectivity were caused by fractures.

53Number 12, 1992.

Seawater is the first choice of injection

fluid in the Gulf of Suez area. It reach-

es the reservoir at temperatures

between 80°F and 90°F. This is much

colder (by up to 100°F) than the reser-

voir itself. As a result, the reservoir is

rapidly cooled from its original tem-

perature and this introduces compres-

sive stress and reduces the fracture

gradients.

A recent study of these effects on

the Prudhoe Bay Field, Alaska, USA†,

reported a maximum reduction in hor-

izontal stress of 0.08psi/ft after one

year’s cool-water injection. This theo-

retical prediction was validated with

field data. Waterflooding operations in

this field result in temperature reduc-

tions of 130°F and fracture gradient

reductions from 0.63psi/ft before

waterflooding to 0.55psi/ft after water

injection.

As temperature reductions in the

Gulf of Suez area are known to be less

severe, the minimum horizontal stress

value of 0.08psi/ft can be used as an

upper limit for the formations. If the

Belayim Formation is considered to be

horizontally uniform but is assumed to

have a constant horizontal stress

reduction of 0.08psi/ft due to water

cooling, the theoretical fracture gradi-

ents (TFG) and measured fracture gra-

dients (MFG) for the two layers HF1

and HF3 would be:

Fracture gradients (psi/ft)

HF1 HF3

TFG 0.63 0.70

MFG 0.44 0.45

Stressful times ahead

So, including thermally induced stress

in the mathematical model still does

not account for the fracture gradients

obtained through well testing. The dif-

ference between the above values for

each layer must be attributed to tecton-

ic imbalances. In other words, uneven

stress distribution. These can be

observed in the caliper log in figure

4.20 which shows borehole elongation

over the entire Belayim Formation.

Fig. 4.20: OVAL AND OUT: Caliper logs

showing that the borehole cross section

has an oval shape (see diagram left).

† AM Garon, CY Lin and VADunayevsky, 1988: Simulationof Thermally-InducedWaterflooding Fracturing inPrudhoe Bay; SPE paper17417.

SEAWATER ON THE ROCKS

Minimum stress

Calipers6" 16"

100ft



C - 5 C - 4

C - 8

C - 7

C - 1

C - 3

Modelled reservoir area

No-flow boundary

Pressure maintenance Pulse tests solveinjection problems

Apulse test was carried out on the

Belayim Formation in the Badri

Field to find the degree of

hydraulic communication between the

producing and test wells. It was also

used to establish a mathematical model

and its parameters for part of the reser-

voir.

The test involved six wells, Badri C1,

C3, C4, C5, C7 and C8. Well C3 was cho-

sen as the injection well, C5 as the pro-

ducing well, and the others were used

for observation. Figure 4.21 shows the

layout of the production/injection wells.

Water was injected into C3, which lies

south of the producing wells. C3 was

subjected to an alternating sequence of

injection and shut-in periods of 36

hours. The consequent pressure

response in the observation wells was

monitored for 12 days.

The regions around two of the wells

were mathematically modelled accord-

ing to their pressure responses. The

data from C7 indicated that the reser-

voir could be modelled as being rectan-

The operator of Egypt's

Badri Field suspected a

leak towards the

neighbouring El-Morgan

Field and a lack of

communication between

injectors and producers.

Could pulse testing shed

some light on these

problems?

gular, of constant thickness, whereas C1

was best modelled as a circular reser-

voir with its centre at the observation

well. The response in the other wells

was tested against the best of these

models.

The pulse test sequence in well C3

consisted of four injection and three

shut-in periods. After shutting in all the

wells in the test, crystal gauges with

extended memories were run in each

observation well (C1, C4, C5, C7 and C8)

and set 20ft above the top perforations.

Water injection began at C3 at a flow

rate of 10,400BWPD, and lasted for 35

hours. This well was then shut in for 36

hours before being opened for another

injection period of 10,900BWPD for 36

hours. The well was re-opened again,

and injection was resumed at a flow

rate of 10,800BWPD for 47 hours. The

final shut-in was for 25 hours before re-

opening to a 36-hour injection at

10,700BWPD. The resulting pressure

changes in the observation wells were

recorded.

Fig. 4.21: This

schematic of Egypt's

Badri Field shows the

configuration of

producing and

injection wells. The

yellow rectangle

delineates the area

modelled in the

reservoir study.

55Number 12, 1992.

Figure 4.22 shows both the test injec-

tion and shut-in periods (blocks on the

x axis), and the corresponding response

of well C7 (dots). As the reservoir pres-

sure trends affect the recorded pressure

signals at each well, they are subtracted

before analyzing the data. All the figures

in this article are adjusted in this way.

The pressure response at C7 was

analyzed using history matching, ie by

finding the mathematical model that

shows the identical response when sub-

jected to the same disturbances as the

real system. This turned out to be

equivalent to a rectangular reservoir of

constant thickness, with two sides hav-

ing pressure maintenance and the other

two sides with no-flow boundaries (fig-

ure 4.21). The C7 reservoir model is

defined by the parameters in table 4.2.

The flow capacity (kh) was derived

from the following equation:

kh = 162.6Bwµw/m'

Storativity(φhct) was estimated by

means of the time match equation:

φhct = 0.0002637kh/µwAtm

where A is the reservoir area in

square feet.

0 26 52 78 104 130 156 182 208 234 260

50

45

40

35

30

25

20

15

10

5

0

Elapsed time (hr)

Pre

ssur

e va

riatio

ns -

psi

Observed pressure variations - psi Simulated pressure variations - psi Test rate sequence - psi

15.0

13.5

12.0

10.5

9.0

7.5

6.0

4.5

3.0

1.5

0.00 30 60 90 120 150 180 210 240

Observed pressure variations - psi Simulated pressure variations - psi Test rate sequence - BWPD 10,000

Elapsed time (hr)

Pre

ssur

e va

riatio

ns -

psi

Fig. 4.22: The sequence of tests and corresponding well C7 response. Fig. 4.23: The sequence of tests and the corresponding well C1 response.

Nomenclature.Bw = water formation volume factor

Bx = reservoir length

By = reservoir width

kh = flow capacity

m’ = slope of superposition plot

r = distance between active and observation

wells.

rD = r/rw, dimensionless wellbore radius

re = radial distance to external boundary

reD = re/rw, dimensionless distance to

external boundary

re = wellbore radius

xa = x coordinate of active well

xob = x coordinate of observation well

ya = y coordinate of active well

yob = y coordinate of observation well

φ = porosity

ψ = pressure potential

φhct = storativity

µw = water viscosity

Table 4.2: Parameters and equations defining the C7 and C1 model reservoirs.

Badri C7 model Badri C1 model

Bx 9,800 ft ReD 7,400

By 8,375 ft RD 5,150

xa/Bx 0.47 re 2,590 ft

ya/By 0.48 r 1,804 ft

xob/Bx 0.55 m’ 6.5E-03 psi/B/D

yob/By 0.83 tm 3.23E-03 1/hr

tm 5.56E-04 l/hr kh 11,140 md-ft

m' 9.00E-03 psi/B/D φhct 1.00E-04 ft/psi

φhct 1.06E-04 ft/psi

kh 8,044 md-ft

Table 4.3: Reservoir and fluid parameters:

Average porosity, φ = 0.25

Average net pay thickness, hc3-c7 = 76 ft

Average net pay thickness, hc3-c1 = 110 ft

Water viscosity, µw = 0.44 cp

Water formation volume factor, Bw = 1.012

Total compressibility, ct = 6.2E-06 1/psi

Wellbore radius, rw = 0.35 ft

Initial flowing pressure, pwfc7 = 1750.51 psia @ 7052 ft

Initial flowing pressure, pwfc1 = 1485.49 psia @ 5594 ft

Once the model had been defined,

the simulated response was plotted

together with the real pulse test data.

The close fit, and consequently the

accuracy of the model, can be seen in

figure 4.22. The response of well C1 to

the pulse test is shown in figure 4.23.

There is a good fit between actual data

and the response simulated by a pro-

posed circular reservoir model with a

constant pressure boundary at a radial

distance of about 2,765ft. The model’s

parameters are given in table 4.2.



PONDERINGPRESSUREIf there is hydraulic communication

across a formation, pressure changes

in one area of the field will have

repercussions in more distant places.

The presence of gas between wells

can act as a shock absorber and can

dampen the pressure pulse as it is

transmitted through the reservoir.

Pulse testing gives the reservoir a

sudden, sharp shock. The test is a

special form of multiple well testing

and uses a series of short-rate pertur-

bations at the active wells. The test

may last a few hours or several days.

Pulses are created by alternating peri-

ods of injection/production and shut-

in. The pressure responses to the

pulses are measured in one or more

observation wells and since the puls-

es are of short duration, the pressure

response is usually small. This means

that special equipment is needed to

measure the small pressure varia-

tions. The main advantages of the

pulse test compared with interference

tests are:

• The short duration of the pulse

• Reservoir pressure trends and

noise can be automatically removed

using appropriate analysis tech-

niques.

A simple way of understanding

pulse testing is to imagine what hap-

pens when a stone is dropped into

the middle of a duck pond. The rip-

ples spread radially away from the

stone and reach ducks floating on the

pond at slightly different times and

magnitudes, depending on the loca-

tion of the bird. As with wells connect-

ed by reservoirs of oil or water, the

arrival of the ripples tells the ducks

that a stone has been thrown.

A duck sitting in a reed bed will

experience events differently. Its posi-

tion is analogous to an observation

well being separated from the injec-

tion well by free gas. The duck feels a

disturbance which is much distorted

and reduced due to absorption of the

wave energy by the reeds. This duck

is aware that something has disturbed

the pond, but not much more. Anoth-

er exception would be a duck floating

behind a nearby concrete jetty. This

duck, like the well separated by a

fault or break in the fluid connection,

will not feel any of the ripple caused

by the splash of the stone.

Fig. 4.24: Gamma-Ray and Density-Neutron logs of wells C1 and C7. Note the clear

difference of 70ft in the formation tops between wells.

100f

t Top of formation

Top of formation

57Number 12, 1992.

2.0

1.8

1.6

1.4

1.2

1.0

0.8

0.6

0.4

0.2

0.00 16 32 48 64 80 96 112 128 144 160

Elapsed time (hr)

Pre

ssur

e va

riatio

ns -

psi

Model derived from C3-C7 and Sg=0.05 Observed pressure response - psi Simulated pressure response - psi

Fig. 4.26: Modelled response assuming a 5% gas saturation.

25.0

22.5

20.0

17.5

15.0

12.5

10.0

7.5

5.0

2.5

0.00 16 32 48 64 80 96 112 128 144 160

Elapsed time (hr)

Pre

ssur

e va

riatio

ns -

psi

Model derived from C3-C7 Observed pressure response - psi Simulated pressure variations - psi

Fig. 4.25: Recorded and simulated pressure response of well C8.

However, the responses of both

wells cannot be matched with one

model. This is partly due to different

reservoir trends of C1 and C7 (see table

4.3). Also, the initial flowing pressures

(pwf) of these wells are not the same

and, even with gravitational terms

removed, there is still a difference in

pressure potential (ψ) between them:

∆ψ =pwfc7

- pwfc1

- 0.433∆h

where ∆h = 70ft

∆ψ = 235psi

Logs from both boreholes show a dif-

ference in elevation of 70ft between the

wells (figure 4.24). This difference in

pressure potential indicates that there is

fluid movement from well C7 to well C1.

The reservoir model used in C7 seems

to give a better represention of the over-

all area.

The next step was to use the model

derived from C7 well to predict the

responses of wells C5 and C8. These

could then be compared to the actual

pulse test results. Plots of the simulated

response for each well indicate that the

characteristics of the area between C3

and C7 are quite distinct from that

around wells C5 and C8. Figure 4.25

shows the comparison between record-

ed pressure variations at well C8 and

values simulated by the C7 model. The

lack of fit between both data sets are

due to changes in the flow rate and/or

storativity (φhct) over the zones of influ-

ence of wells C8 and C5, compared with

those between wells C7 and C3.

No response to injection was seen in

well C5, indicating the likelihood of a

sealing barrier between C5 and C3.

Shock-absorbing gas

The absolute pressures measured in

wells C5 and C8 are about 400psi below

the bubble-point pressure. This suggests

that the small amplitude of the signal

observed at well C8, and the lack of

response from well C5, could be due to

the presence of free gas towards the

northwest of the reservoir area.

To test this theory, a simulation was

made to determine the pressure

response at well C8 with a gas satura-

tion (Sg) of 5%. Figure 4.26 shows the

results, together with the actual

response at well C8. Although the

curves do not fit particularly well, their

magnitudes are comparable. So the free

gas assumption seems to hold true.

The analysis techniques used

throughout this article assume that the

reservoir is isotropic and homogeneous

in the region influenced by the test

wells. This assumption may well be

valid when we are dealing with reser-

voirs that are single-phase (eg totally

oil- or gas-filled) or multi-phase when

the fluid properties are similar. But in

the situation where there are two dis-

tinctly different fluids - ie gas and oil -

the analytical solution does not hold

true.

Therefore, the presence of free gas

precludes us from obtaining a reliable

answer using analytical solutions. In

such cases, a numerical model must be

used but this approach is more costly

and time-consuming.

Pulse testing in the Badri Field has

shown there is hydraulic communica-

tion between wells C3, C1, C7 and C8,

but not between these wells and C5.

Therefore the producing well may lie

behind a fault or other sealing bound-

ary, preventing it from responding to

injection. The responses showed that

the wells are in hydraulic communica-

tion and this enabled the reservoir engi-

neers to create a model for the area.

The presence of gas towards the north-

west of the Badri Field was also detect-

ed. These two results also proved that

there were no leaks into the El-Morgan

Field as originally suspected.

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