8000

8050

8100

8150

8200

In Saudi Arabia, intense surveillance of a wateflooding

scheme in a complex carbonate reservoir has come up

with a few surprises. For example, it has shown that fluid

flow in a large and highly stratified reservoir appears to be

much simpler than the geology indicates. The monitoring

programme has also revealed how the production strategy

has influenced the vertical and horizontal water sweep.

This has prompted Saudi Arabian Oil Company to further

investigate water encroachment patterns in the reservoir.

Mahmood Rahman, Petroleum Engineering Specialist with

Saudi Aramco and consultant Manfred Wittmann outline

how the peripheral waterflooding scheme has been

monitored and explain how this mass of data is now being

incorporated into a geological model of the reservoir that

will form the basis for 3-D simulation studies.

This article is based on SPE Paper 21370, Case Study: Performance of a Complex Carbonate Reservoir Under Peripheral Water Injection, by M. Rahman, M. B.

Sunbul and M. D. McGuire of Saudi Aramco presented at the SPE Middle East Oil Show, Bahrain, 16-19 November 1991.

44 Middle East Well Evaluation Review

Producer well

Injection well

Observation well

8400

8300

8200

8100

7900

7800

7700

8000 8100

8200

Efficient reservoir management

relies on a good understanding of

a field’s characteristics and per-

formance. Using open hole logs as a

datum, this knowledge can be built up

over a field’s life with carefully planned

monitoring programmes. But this is

often too late. What a manager really

needs is a comprehensive and accurate

model to help predict a reservoir’s

response to drilling and recovery meth-

ods.

This article takes a practical look at

the development of a major carbonate

field in Saudia Arabia. The 25 km long

by 15 km wide anticlinal reservoir was

discovered in 1964. Exploitation was

started in 1970 and has been achieved

by flooding the field with water injected

through a series of wells on the north-

ern periphery of the reservoir.

Over the past 20 years a fifth of the

original oil in place has been produced.

But, evaluation of areal and vertical

sweep has shown areas of the reservoir

where oil is not being effectively dis-

placed by the peripheral waterflooding

technique. The observed performance

has been incorporated into a geological

model of the reservoir and forms the

basis of a 3-D simulation of the entire

field which has been built to guide

future reservoir drainage management.

The producing formation is one of a

number of Late Jurassic shallowing-

upward sequences in this region of

Saudi Arabia (see Middle East WellEvaluation Review, 1991 Number 11).

The fine, permeable, carbonate grain-

stones become gravel-sized towards the

top of the formation giving most wells

typical shallowing-upward and/or

coarsening-upward porosity profiles

(figure 4.2). This is a favourable perme-

ability distribution for peripheral water-

flooding as the gravity pull is offset by

the lower resistance to flow at the top

of the reservoir.

During deposition, the field area

straddled a gently sloping carbonate

platform margin (figure 4.3). This sepa-

rated a broad, flat area of shallow water

(a carbonate shelf) from a deeper,

restricted basin. Carbonate grainstones

formed quickly on the northern shelf.

Below, in the basin, a slow rain of

pelagic sediments produced fine-

grained rocks with poor permeability. A

transitional zone developed between

these two depositional environments.

This variation in deposition is responsi-

ble for the rapid facies changes from

grainstones on the northern ramp to

mudstones in the basin. Associated

with this is a reduction in reservoir

quality from north to south.

The geometry of the depositional lay-

ers was affected by the gentle slope of

the margin (1-2 degrees). As a result,

the geologic layers were not originally

deposited as flat, horizontal beds, but

were sigmoid-shaped similar to those

shown in figure 4.3.

Fig. 4.1: MONITORING

PERFORMANCE:

Exploitation of this Saudi

Arabian reservoir started in

1970. Since then, a fifth of

the oil-in-place has been

produced. However,

saturation monitoring has

shown areas where potential

oil reserves have been

missed by the peripheral

waterflooding technique.

45Number 13, 1992.

8000

8100

8200

8300

8400

8500

0 100 2.0 3.0 Gamma Ray API Bulk density g/cc

Top of formation

Base of formation

Depth ft

Variations in sea level during the

Late Jurassic also affected the shape

and make up of geologic layers. This

resulted in highstand, lowstand and

transgressive sequence system tracts

(figure 4.3). Geologic layers, deposited

during highstand sea level, built out

toward the basin and draped succes-

sively over one another like tiles on a

roof. As a result, the reservoir facies

within the highstand layers remained in

close contact. During the following low-

stand time there was little or no deposi-

tion on top of the shelf or at the outer

ramp. Instead, layers filled up the basin.

As the sea level began to rise again a

series of transgressive backstep grain-

stones were deposited at the top of the

reservoir. As these backstep grain-

stones incompletely overlapped one

another, the uppermost part of the

reservoir is made up of different aged

grainstones across the field.

South North

Outer ramp Basin Outer ramp margin A

B C C'

E' G H

I

X/F

Transgressive system tract

Lowstand system tract

Highstand system tract

Time line

Depositional cycle

Organic rich lime mudstones

Packstones/ wackestones

Boundstones

Gravels

Grainstones

Fig. 4.2: Typical log

showing the

shallowing-upwards

sequence in the

reservoir.

Fig. 4.3: BLAME IT ON THE RAIN: The reservoir is situated in Late Jurassic sediments which straddle the edge

of a gently sloping carbonate platform. Porous carbonate grainstones formed in the shallow waters to the

north. In the deeper waters to the south, a fine rain of pelagic sediments formed fine-grained mudstones with

poor permeability. The two different types of rock are separated by a transitional zone which developed

between these two different depositional environments.

0 600 300

South North Well X Permeability (md)

0 600 300

Well Y Permeability (md)

0 600 300

Well Z Permeability (md)

K>20

K<20

K>20

K<20

8000

Depth ft

8080

8000

8160

8320

46 Middle East Well Evaluation Review

CYAN MAGENTA YELLOW BLACK

As predicted by the depositional

model, the reservoir is better devel-

oped in the north and progressively

thins and degrades to the south. The

relatively low oil viscosity (0.5 cp at

reservoir condition, about twice the vis-

cosity of the injection water) together

with the end-point relative permeability

to oil being considerably higher than to

water, gives the waterflood a favourable

mobility ratio.

In the developed northern area of

the field, productivity is generally high.

However, the reservoir is highly hetero-

geneous and consists of a mixture of

lithologies. Porosities vary between 10%

and 23%, while permeabilities range

from 5 md to 500 md. This is not uncom-

mon in a carbonate reservoir where

permeability depends on both porosity

and rock type. For the same porosity,

calcareous grainstones have permeabili-

ties that are an order of magnitude

higher than fine-grained micritic rocks.

The reservoir is also highly stratified

with large permeability variations

between layers. Figure 4.4 is a core

porosity and permeability plot for a typ-

ical crestal well. Even in the well-devel-

oped upper portion of the reservoir

there is a large permeability variation.

The reservoir heterogeneity is illus-

trated in the north-south cross-section

shown in figure 4.5. It illustrates the

essential reservoir characteristics, ie

high variability and a general deteriora-

tion of quality from north to south.

Core permeability

Permeability md Porosity %

Core porosity

0.1 10,000

<10 md

10-100 md

100-1000 md

50

Measured depth ft. 7950

8000

8050

8100

8150

8200

0

>10%

Fig. 4.4: Core

permeability and

porosity plot

from a typical

crestal well.

There is

a large

permeability

variation in the

top part of the

reservoir.

Fig. 4.5: This

'fence'

permeability

diagram

clearly

indicates the

wide range

of

permeability

across the

field.

47Number 13, 1992.

1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990

4200

3800

3400

3000

2600

Pre

ssur

e, P

sig

Year

Pressure

Decline and build-up

Immediately after production started in

1970, the reservoir pressure fell dramat-

ically (figure 4.6). To stem the fall, a

waterflood pressure maintenance pro-

ject was initiated in January 1973 using

injection water from a shallow, rela-

tively fresh, aquifer. Injection wells

were drilled close to the trailing edge of

the OOWC and completed open hole.

The objectives were clear:

• To ensure the reservoir pressure

remained above the bubble point.

• To keep wells flowing at high water

cuts to obviate the need for

pumps or gas lift.

• To move the oil towards producing

wells situated in the updip area.

Two years after injection started,

water began to breakthrough in the first

row of producers. Initially these wet

wells had to be shut in or recompleted

to drier zones towards the top of the

reservoir. However, water production

was allowed from 1981 when wet crude

handling facilities were installed. Since

then, the field’s average water cut has

only increased to around 20% although

the flood front has advanced to the cre-

stal area. This low water cut is main-

tained because all wells flow naturally,

so when an individual well’s water cut

increases to between 60% and 70%, it

becomes water logged, stops flowing

and dies. Hence, the total water (and

oil) production is reduced. To sustain

the overall oil rate, new wells are

drilled and dead wells worked over and

recompleted to drier zones. By

December 1989, a total of 75 wells had

been drilled. Of these 42 were produc-

ers, 15 were injectors and the remain-

der were observation wells.

Fig. 4.6: WEAK AQUIFER: As soon as production started in 1970, the

reservoir presure went into rapid decline. At this rate, bubble-point

pressure would have been reached within two years. To prevent this, the

operator embarked on a peripheral waterflood scheme which successfully

managed to reverse the pressure decline.

Fig 4.7: Since the injection wells are located outside the trailing

edge of the OOWC - and because of the favourable mobility ratio -

large banks of high salinity aquifer or formation water advance

through the reservoir ahead of the injection water. This results in

an increase in TDT log readings followed by a decrease as the

formation water is replaced by less saline flood water.

Dire

ctio

n of

floo

d

Time (distance) 0

1.0

Sw

Connate water saturation.

Residual oil saturation.

Producer Injector

48 Middle East Well Evaluation Review

1977 1984 1985 1988

Porosity PNL PNL PNL PNL

90 0 % 40 0 40 0 40 0 40 0 CU CU CU CU ft

7922

8000

8100

8200

Top of Res.

Base of Res.

Depth

Neutrons and networks

Extensive monitoring has been used to

observe the waterflood sweeping across

the reservoir. The principal saturation

monitoring tool has been the Pulse

Neutron Capture Log (PNL). This log

has been run on a routine basis since

the mid-1970s when flood water started

to break through in the outer producing

wells.

Because of the high formation water

salinity of 240,000 ppm total dissolved

solids (TDS), PNL logs have been very

effective in tracking the advance of the

flood front through the reservoir (fig-

ures 4.7 and 4.8). In addition to produc-

ing and observation wells, PNL logs

have been run in 25 deep wells and

these have provided excellent water-

flood observation points as they are not

hampered by fluid invasion, acid or

other effects.

Once the high salinity flood front has

passed through a monitoring point, it is

followed by the relatively fresh injec-

tion water - salinity 24,000 ppm TDS.

The resultant mixed salinity environ-

ment makes quantitative interpretation

of PNL logs difficult - the calculation

depends on a known water salinity fac-

tor†.

Further complications arise when a

zone is just starting to deplete and con-

tains both oil and formation water while

another zone in the same well has

already been swept and contains a mix-

ture of formation and injection water. In

this situation it is difficult to distinguish

one zone from another using PNL logs.

To overcome this mixed salinity

problem, a network of key wells has

been established. These wells are fre-

quently logged to monitor qualitatively

the displacement of oil-first by forma-

tion water which causes an increase in

PNL response, and then by the injection

water which causes a decrease in PNL

response.

In addition, wet wells are routinely

tested and samples of produced water

collected for geochemical analysis.

From this, the proportion of injection

and formation water in the wet produc-

ing zones of the well is estimated.

Finally, flowmeter surveys with gra-

diomanometers are conducted to obtain

the flow profile and identify water pro-

ducing zones (see Go with the flow in

this issue).

Well performance, geochemical data

and flowmeter-gradio results are com-

bined with the PNL log interpretation

for each well to establish:

• Zones that are sweeping or

responding to the peripheral flood,

and;

• Zones indicating no significant

movement or sweep.

Figure 4.8 is an example of this typeof surveillance data. It shows theprogress of the waterflood as observedfrom time-lapse PNL logging of a typicalflank well.

Another important aspect of the

waterflood monitoring effort is the eval-

uation drilling program that was started

in the late 1980’s. This is aimed at evalu-

ating the sweep in the reservoir’s

undrilled areas, between the injectors

and first row producers. In addition to

cores and open- hole logs, these wells

provide the opportunity to selectively

test individual layers to determine fluid

content and salinity and to run wireline

multiple-pressure testers, such as

Repeat Formation Tester (RFT), across

the reservoir.

Over the past four years, a total of

eight evaluation wells have been

drilled. Integrating data from these wells

with routine surveillance data from the

67 existing wells gave a good under-

standing of the reservoir’s water

encroachment patterns and flow charac-

teristics. It also produced a good assess-

ment of the areal and vertical sweep

across the reservoir, which was the pri-

mary objective in evaluating the perfor-

mance of the waterflood.

Fig. 4.8: SALT

SURVEILLANCE:

These time-lapse

pulsed neutron logs

give a clear indication

of the movement of

the waterflood front

across a section of the

field.

†Such measurements have been made easier with

the arrival of the Reservoir Saturation Tool (RST*)

into the Middle East (see Middle East Well

Evaluation Review, Number 11, 1991).

49Number 13, 1992.

The effectiveness of a reservoir water-

flooding scheme depends on three basic

factors - the microscopic displacement,

and the areal and vertical sweep efficien-

cies. For best results, these factors

should be determined by a detailed

reservoir study which includes simula-

tion. However, a quick assessment of the

waterflood performance can be made by

assigning a value between 0.0 and 1.0 for

each of the three efficiency factors.

The overall waterflood efficiency can

then be computed by multiplying these

three values. For example, a reservoir

with microscopic, areal and vertical

sweep efficiencies of 0.6, 0.7 and 0.5

respectively would have an overall flood

efficiency of 0.21. In other words, only 21

percent of the oil-in-place would be

recovered.

Microscopic displacement efficiency

is a measure of how easily the oil can be

removed from the rock pores. Efficiency

values can be obtained from laboratory

core studies or the Log-inject-Log tech-

nique using equipment such as the

Thermal Decay Time tool. The use of

surfactants, which improve the rock wet-

tability and reduce the interfacial tension

in the system, can increase displace-

ment efficiency.

Areal sweep efficiency is a measure

of how much of the reservoir has been

in contact with the flood water in an

areal plane.

Vertical sweep efficiency is a mea-

sure of the uniformity of water invasion

in a vertical cross section.

Both the areal and vertical sweep are

dependent on a large number of factors:

the distribution of horizontal and vertical

permeability, anisotropy, wettability,

reservoir thickness, fluid characteristics,

the injection/production rates, the place-

ment of perforations, type of injected

fluid (water or gas), the well spacing etc.

Proper planning of a waterflood

should take into account most of these

parameters and the predictions are usu-

ally based on model studies (both

numerical and laboratory). The actual

waterflood performance can be esti-

mated by examining saturation data

from in-fill and observation wells and

tracer surveys. In a tracer survey, chem-

ical or mildly radioactive tracers are

added to the injection water and their

arrival time at the producing well is

noted.

Today, reservoir simulation studies

are playing an increasingly important

role in determining the areal and vertical

movement of the injected water. They

also help to guide drilling programmes

aimed at maximising the sweep effi-

ciency of the waterflood.

A CLEAN SWEEP

Injection wells

Producer

Oil

Water Water

Areal sweep

Water Oil

Sand Water Oil

Fig. 4.9: AREAL

SWEEP: A

measure of how

much oil is left

behind in areas

not swept by the

waterflood.

Fig. 4.10:

VERTICAL

SWEEP: Defined

as the cross-

sectional area

contacted by the

injected fluid

divided by the

cross-sectional

area enclosed in

all layers behind

the fluid front.

Fig. 4.11:

MICROSCOPIC

DISPLACEMENT:

Relates to the

removal of oil by

water on the pore-

scale.

CYAN MAGENTA YELLOW BLACK

50 Middle East Well Evaluation Review

B M L

N

K

C'

P Q R B'

B C D

E F

H I

A

A A' G

J

N

O'

The term sweep, as used here, implies

that a part of the reservoir has been

contacted by formation or injection

water. Because of the problem of mixed

salinity, no effort was made to evaluate

displacement efficiency.

As there was no reliable simulation

model available, sweep was evaluated

by generating a series of cross sections

parallel and perpendicular to the struc-

ture (figure 4.12). Water encroachment

data from individual wells was superim-

posed on these sections and the swept

and unswept zones identified and corre-

lated from well to well.

The reservoir was then divided into

a number of layers, based on perme-

ability. For each of these layers, maps

were drawn showing the swept and

unswept zones. In addition, net oil

isopachs were prepared to estimate the

volume of unswept oil. From this water-

flood evaluation, which is mainly based

on observed performance, several

important conclusions can be drawn:

1. In spite of the complexity and sig-

nificant variation in rock-type and per-

meability, all facies with a permeability

greater than 20 md responded to the

peripheral flood. Upper and middle sec-

tions of the reservoir, which contained

most of the permeable layers, were

flooding together almost as one pack-

age.

2. The lower part of the reservoir,

where the permeability is generally less

than 10 md, was not flooding at all. In

spite of being completely overlain by

flood water in the permeable zones

above, there was no noticeable

encroachment of water or displacement

of oil from these tighter facies. It is pos-

sible that the tight lower zones that are

not flooding may be more oil wet than

the more permeable zones above.

However there is no wettability data to

support this (see box on page 55).

3. On the northern flank of the field,

there was unswept oil in the permeable

upper part of the reservoir.

4. Although early PNL and resistivity

logs showed water breakthrough in the

highest permeability zones, there are no

major fingers anywhere in the reser-

voir. This is believed to be due to good

vertical permeability, favourable mobil-

ity ratio and the field operating strategy

of restricting the producers ahead of the

flood front.

A good way to illustrate water

encroachment in a reservoir is through

cross sections (figures 4.13 to 4.16).

The east-west section AA' represents

the northern flank, an area that is close

to the injectors, and had more injection

water pass through it. This section is

shown both stratigraphically (figure

4.13) and structurally (figure 4.14).

There are two distinct permeability

zones - the lower zone with permeabil-

ity generally less than 10 md and the

upper zone which ranges from 20 to 500

md. Individual log sections show the

porosity profile on the left track. On the

right track, injection wells show the

flowmeter profile while producing or

observation wells show the PNL log

response. These sections clearly show

that:

• Water is entering more or less

uniformly into the permeable zones

(K>20 md). It then gravitates down

to the base of the permeable zone

and continues to ride on top of the

tight zone (K<10md).

• The flood water is sweeping

through the middle section of the

reservoir with oil above and below.

• Time-lapse PNL logs show that the

oil at the top is still moving,

although at a slow pace.

• The oil in the tight facies (K<10 md)

is not sweeping at all.

The cross section BB' (figure 4.15)

goes through the crestal area from east

to west flank. It shows a dry crestal pro-

ducer with a flood front approaching

from both sides. This cross section

shows a similar flooding pattern as

observed in section AA'. However,

there are differences:

• The injection wells have a poor

flow profile because the permeable

facies have become thinner on the

flanks. But even then, the flood

water is sweeping through the

permeable zones (K>20 md) but

completely by-passing the tighter

zone (K<10 md) below.

• The thickness of the unswept oil at

the top is much thinner (20 ft) than

the unswept oil column (80 ft)

observed in the northern cross

section, AA'. This, as will be shown

later, is primarily due to better

drainage in the crestal area

compared to the northern flank.

The north-south cross section, A'C'

(figure 4.16) which goes from the injec-

tion well in the north flank to the dry

wells in the south, confirms the sweep

pattern observed in the two east-west

cross sections, AA' and BB’.

Fig. 4.12: ON THE WATERFRONT: Prior to the development of a reservoir simulation model, the

only way to assess the efficiency of a waterflooding scheme was to generate a series of cross-

sections across the field. These helped to locate the swept and unswept zones. This map shows

the approximate location of each of the sections presented in figures 4.13 through 4.16.

51Number 13, 1992.

Well - L

PO

R

FB

S

PO

R

TD

T

PO

R

TD

T

PO

R

TD

T

PO

R

TD

T

PO

R

TD

T

PO

R

FB

S Well - M Well - N Well - O Well - P Well - Q Well - R

Injector Injector

W E Swept zone

Top res.

Base res.

Oil

K = 20-500 K = 10

Water

Flood front

Flood front

FB

S

Well - A P

OR

FB

S Well - B

PO

R

TD

T Well - C

PO

R

TD

T Well - D

PO

R

TD

T Well - E

PO

R

TD

T Well - F

PO

R

TD

T Well - G

PO

R

FB

S

Injector Injector

Oil

Oil

Top res

Base res

K = 20 - 500 K=10

W E Swept zone

Well - K Well - J Well - I Well - H Well - F Well - G

PO

R

TD

T

Top res

Base res

PO

R

TD

T

PO

R

TD

T

PO

R

TD

T

PO

R

TD

T

PO

R

FB

S Dry Wet

Flood front

Swept zone Injector

Oil

Oil

K 20-500

K =10

Water

S N

Well - A Well - B

Oil

Well - D Well - E

Well - F

Well - G

OOWC OOWC

PO

R

FB

S

PO

R

TD

T

PO

R

TD

T P

OR

TD

T

PO

R

TD

T

PO

R

TD

T

PO

R

FB

S

Water

Well - C

K = 20 K = 10

W E

Top res

Base res

Swept zone

Fig. 4.13: East-west

stratigraphic cross

section showing two

distinct permeability

zones. The flood

water is sweeping

through the middle

of the reservoir,

leaving oil above

and below.

Fig. 4.14:

Structural

section

along the

same line as

that of figure

4.13.

Fig. 4.15:

East-west

cross section

through the

crestal area

revealing a

dry producer

with the

flood front

approaching

from both

sides.

Fig. 4.16: This

north-south

section confirms

the sweep pattern

which was

observed in the

east-west sections.

A

B

A

C'

A'

A'

B'

A'

CYAN MAGENTA YELLOW BLACK

52 Middle East Well Evaluation Review

The best evidence of good vertical

permeability can be obtained from RFT

pressure profiles of wells drilled in both

producing and non-producing areas of

the reservoir. Twelve recently tested

wells showed a uniform pressure pro-

file across the permeable section of the

reservoir. Figure 4.17 illustrates a pres-

sure profile of a crestal evaluation well.

There is no differential depletion and

the pressure profile across the perme-

able section of the reservoir is uniform.

This confirms the absence of extensive

horizontal barriers and indicates that

there is enough vertical communication

between layers to allow movement of

oil and water across the reservoir.

The average mobility ratio of the

waterflood is estimated at 0.4. Based on

experience with other waterfloods,

such a favourable mobility ratio has a

very positive impact on areal and verti-

cal sweep since it eliminates any possi-

bility of viscous channelling (or

fingering) of water through the oil, caus-

ing early water breakthrough in the pro-

ducing wells.

Also, reservoir management has

been a key factor in ensuring good

areal and vertical sweep. A producing

strategy was implemented in 1982. This

restricted or shut in dry producers

ahead of the flood front and preferen-

tially produced the wet wells to the

rear. As shown by the water arrival

isochrones in figure 4.18, this slowed

down the rate of advance of the flood

front, avoiding water breakthrough

along high permeability streaks and

allowing gravity forces to smooth out

the effect of stratification. This is why

there is no evidence of fingering in the

reservoir even though the early resis-

tivity and PNL logs showed water

breakthrough in thin, highly permeable

zones (figure 4.19).

RFT Pressure-Psig

3700 3800 3900

Gradient = 0.30 Psi/ft

Oil/Water interface

Gradient = 0.42 Psi/ft

Gradient = 0.52 Psi/ft

Gradient = 0.30 Psi/ft

Supercharged ?

Resid. HCarbon

Moved Water

50 % 0

Depth ft

7850

7900

7950

8000

8050

DST 3950 Bbl/day

0% cut

DST 843 Bbl/day

56% cut

DST 278 Bbl/day

0.3% cut

1974 1976

1978 1980 1986

Flood front

Producer well

Injector well

Observation well

1990

Fig. 4.17: VERTICAL EQUILIBRIUM: RFT

pressure profile of a crestal evaluation well

indicates absence of barriers.

Fig. 4.18: FLOOD FRONT ADVANCE:

Movement of the flood front across the

field was slowed down by preferentially

producing the wet wells and restricting

the dry crestal wells.

53Number 13, 1992.

Porosity Depth

ft

8000

8100

8200

PNL Playback

1977 Sigma cu

1984 Sigma cu

1988 Sigma cu

50 % 0

40 0

40 0

40 0

Dry oil

Swept zone

Flood

front

0 25 50 75

50

50

25 0

Unswept oil

Flood front

A sweeping improvement

There is a column of dry oil at the top of

the reservoir that is sweeping very

slowly (figures 4.8 and 4.13). These

unswept zones were identified and

isopach maps showing the thickness

and extent of this unswept oil were

drawn for each layer.

To investigate the reason for this

lack of sweep in the permeable upper

portion of the reservoir, especially in

the NE flank where there is adequate

injection support, all possible factors

that may have a bearing on sweep were

critically reviewed. Structure, gross pay,

pressure, permeability, cumulative

injection/withdrawal, current injec-

tion/production etc are some of the fac-

tors that were examined (figures 4.21 to

4.26). However, the parameter that gave

the closest correlation with poor sweep

is poor drainage.

Currently, most of the producing

wells are located in the crestal area of

the reservoir. There is very little with-

drawal from the NE flank where the oil

at the top has stopped moving. This is

partly due to the reservoir being flat

(formation dip 1° - 1.5°) and also

because the crestal production is effec-

tively supported by injection water

moving through the highly permeable

middle section of the reservoir.

Therefore, there is no horizontal pres-

sure gradient to drive oil from the NE

flank to the producing wells in the cen-

tral area.

Plans are underway to improve

recovery of the unswept oil by provid-

ing more drainage points in the NE

flank. This will be done by recompleting

existing wells and drilling infill wells.

However, because of the relatively thin

oil column and underlying water, wells

are expected to cone water. Therefore,

horizontal wells are being planned and

eventually artificial lift will be required

to produce these wells at higher water

cuts.

As regards the unswept oil in the

tighter lower part of the reservoir, it is

believed that the current peripheral

flood will recover very little oil from

this facies. Developing these tighter

facies may require waterflooding at

very close spacing or some other recov-

ery technique.

Fig. 4.19: EARLY WARNING: Water breakthrough in the thin, highly permeable zones

can be clearly seen in this early log. However, the producing strategy was designed to

prevent this from occurring in the crestal area of the field.

Fig. 4.20:

Thickness and

areal extent of

the unswept

oil zone.

CYAN MAGENTA YELLOW BLACK

54 Middle East Well Evaluation Review

8300

8200

81

00

8000

79

00

7800

7700

Unswept oil

Flood front

30

40

40 30

20

4000

38

00

3600

3400

psig

Fig. 4.23: Isobaric map versus unswept oil in

layer BB1.

Looking to the future

The performance characteristics of the

field have now been incorporated into

a new geological reservoir description

which forms the basis of a 3-D simula-

tion model of the entire field. Reservoir

simulation is now in progress and will

be used as a key reservoir management

tool. It will not only be used to predict

future performance but also to optimize

Fig. 4.22: Gross Pay versus unswept oil in

layer BBI.

Fig. 4.21: Structure versus unswept oil in

layer BBI.

60 80

100 md

120

140 120

400

300

200 100

300

400

500

600

400

30 15 5

Unswept oil

160

180

Fig. 4.24: Permeability versus unswept oil in

layer BBI.

Flood front

Producer Injection well Observation well Unswept oil

Flood front

Producer Injection well

Observation well Unswept oil

Fig. 4.25: Cumulative production/ injection

versus unswept oil in layer BBI.

Fig. 4.26: Current drainage/injection

versus unswept oil in layer BBI.

the producing and development strate-

gies for the field.

Acknowledgement

Appreciation is given to the Saudi Arabian Ministry of

Petroleum and Mineral Resources and to Saudi Aramco

for permission to publish this paper.

55Number 13, 1992.

Wettability is an extremely important

factor as it controls the location, flow

and distribution of fluids in a reser-

voir. It is a measure of the preference

that the rock exhibits for either oil or

water and has been defined as ‘the

tendency of one fluid to spread on or

adhere to a solid surface in the pres-

ence of other immiscible fluids’.

If a rock is water wet, the water

will tend to occupy small pores and

be in contact with most of the rock

surface - the ideal situation for any-

one wishing to extract oil from a

reservoir. In an oil-wet system, the

rock retains the oil in its small pore

spaces, making production more diffi-

cult.

There are several ways of assess-

ing wettability. One relies on measur-

ing the contact angle which is formed

when a drop of water is placed on a

rock surface immersed in oil (see fig-

ure). If the rock is water wet, the con-

tact angle is less than 90°. In an

oil-wet system, the angle exceeds 90°.

Wettability measurements on core

samples are not always reliable

because it is difficult to retain the

original wetting character of the rock

during sampling or in the laboratory.

Logging techniques, which measure

the difference in resistivity between

oil- and water-wet rocks, can provide

some estimates of in-situ wettability mea-

surements.

WET....WET....WET

Rock

Oil

Waterθc

Water wet (θc > 90˚)

θc

Rock

Oil

Water

Oil wet (θc < 90˚)

Fig. 4.27:

In water-wet

systems, the

contact

angle is less

than

90°.

Fig. 4.28: In

oil-wet

rocks, the

converse is

true.

Further reading:

Wettability Literature Survey -

Part 1: Rock/Oil/Brine Interactions and the

Effects of Core Handling on Wettability by W.G.

Anderson in Journal of Petroleum Technology,

Oct. 1986, page 1125.