GeoArabia, Vol. 7, No.

1, 2002
Gulf PetroLink, Bahrain

Accurate reservoir characterization to reduce drilling risk in

Khuff-C carbonate, Ghawar field, Saudi Arabia

Shiv N. Dasgupta, Ming-Ren Hong and Ibrahim A. Al-Jallal

Saudi Aramco

ABSTRACT

The Khuff-C reservoir in the Ghawar field is a stratified sequence of cyclic carbonate-
evaporite deposits within the Permian Khuff Formation. The reservoir is heterogeneous,
complex, and influenced by syndepositional diagenesis. Wells drilled into the Khuff-C
in the ‘Uthmaniyah sector of Ghawar are usually prolific producers of non-associated
gas but some have intersected poor-quality reservoir intervals with little or no gas
production. The Khuff-C reservoir rocks were deposited in a peritidal setting where
slight changes in sea level created locally exposed highs. The exposure in an arid climate
resulted in outliers of porosity occlusion formed by evaporite cements within the
Khuff-C reservoir. The outliers are variably sized and randomly distributed and the
challenge is to predict their occurrence in order to avoid them in development drilling.
Inverse modeling of the ‘Uthmaniyah 3-D seismic data has identified the tight-porosity
outliers as areas of anomalously high acoustic impedance. Integration of 3-D seismic
analyses with petrophysical and other well data has improved the reservoir
characterization and reduced the drilling risk.

INTRODUCTION

The supergiant Ghawar field is located in eastern Saudi Arabia in the eastern part of the Arabian
Platform (Figure 1). The Permian Khuff-C carbonate gas reservoir in the ‘Uthmaniyah sector of the
Ghawar field was discovered in 1982. The reservoir is a prolific producer of non-associated gas and
some condensate. In addition to the Khuff-C, the Khuff-A and Khuff-B reservoirs also produce gas in
the Ghawar field. The Lower Silurian Qusaibah shale is considered to be the source rock for the Khuff
reservoir. A mid- to late-Mesozoic phase of gas yield charged the Khuff traps that existed prior to the
formation of the Zagros uplift (Bishop, 1995). The hydrocarbon migration pathways to the Khuff
reservoirs are believed to be deep-seated vertical faults as seen in 3-D seismic data.

The reservoir porosity and permeability distribution is complex and is primarily controlled by the
distribution of the depositional facies and by later diagenesis. The Khuff sediments were deposited in
a subtidal and gently dipping tidal flats in an extremely arid environment. The Khuff-C reservoir
facies vary in their reservoir quality as a result of their diagenetic history. Khuff-C porosity varies
from about 30 percent to less than 5 percent, which is the economic cutoff. Parts of the reservoir facies
have been dolomitized and later leached, and this resulted in good reservoir development. Some
dolograinstone facies, however, have been cemented by anhydrite that destroyed the reservoir porosity
and permeability.

These variably sized anhydrite-cemented ‘outliers’ within the Khuff-C reservoir facies are distributed
randomly throughout the field. The challenge is to predict their occurrence between wells in order to
avoid them during the development-drilling program.

Khuff-C reservoir well spacing in this area of Ghawar is at least 2 km. With such a coarse well spacing
it is difficult to characterize the reservoir heterogeneity from well data alone. The integration of 3-D
seismic data with petrophysical information and the reservoir simulation history has improved our
understanding of the reservoir complexity and the porosity distribution of the Khuff-C reservoir. This
has permitted us to define the local tight porosity facies of the Khuff-C reservoir throughout the field.
Amplitude inversion of the 3-D seismic data corresponded to high acoustic impedance (velocity x
density) in the vicinity of wells that intersect tight Khuff-C reservoir intervals. The seismic inversion

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 Rimthan
IRAN
Wafra
Fuwaris Marjan
South Lawhah
Dibdibah Safaniya Hamur Hasbah N Kangan
Jauf Ribyan Maharah
Dasgupta et al. Sadawi Harqus North Pars

Suban Sharar Manifa Karan

Hab Kurayn
Wari’ah
Abu Hadriya Jurayd
Watban
Juraybi’at Jana
Arabian
El Haba Gulf
Bakr Khursaniyah Abu Sa’fah
Jaladi Berri
Faridah Fadhili
Dhib
Samin Qatif
Al-Rayyan

Dammam BAHRAIN
Al-Shaheen
Abqaiq
Fazran Awali
Jaham

’Ain Dar
SAUDI ARABIA Shedgum

Figure 4 Doha
’Uthmaniyah
Dukhan
Khurais
Ghawar QATAR

Hawiyah
Abu Jifan Qirdi
Riyadh Farhah Manjurah
Mazalij Harmaliyah
Reem Jafura
Haradh
Mazalij-24
Sahba Tinat
Ghazal Wudayhi
Dilam
Shaden
Raghib Waqr
Abu Shidad Niban Lughfah
Tinat South
Shiblah Abu Rakiz Shamah Jawb
Hilwah Mulayh
Abu Markhah
Khuzama
Burmah
Nisalah Nuayyim
Hawtah
Hazmiyah
ARABIAN
Ghinah
N Sabha N
PLATE
Umm Jurf 0 150
Layla Usaylah Oil field
Faydah km
Gas field
Arabian
Shield
Location map

Figure 1: Regional setting of the Ghawar field in

Saudi Arabia and location of the study area in the
0 500 ‘Uthmaniyah sector.
Km

results also indicated the localized high acoustic impedance-low porosity anomalies (or outliers) that
are distributed sporadically throughout the field. These results were used to locate development
wells over areas with good reservoir quality and to avoid tight facies. Subsequent drilling results
have been extremely successful––all 10 wells that have been drilled using the integrated reservoir
model, intersected the porous and productive Khuff-C reservoir as predicted (Dasgupta et al., 2001).
The results also verified the interwell heterogeneity of the reservoir properties predicted from seismic
inversion (Dasgupta et al., 2000).

KHUFF FORMATION

Stratigraphy

The Khuff Formation represents the earliest period of major carbonate sedimentation in the area of the
Ghawar field, resulting from the Permian transgression of the Neo-Tethys Ocean over the eastern part
of the Arabian Plate (H.S. Talu and F.A. Abu Ghabin, 1987, unpublished Saudi Aramco Report no.
117). The generalized stratigraphic column (Figure 2) shows the stratigraphic position of the Khuff

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 Khuff-C carbonate reservoir characterization, Saudi Arabia

FORMATION MEMBER GENERALIZED RESERVOIR

STRATIGRAPHY LITHOLOGY
TRIASSIC
LOWER

Sudair Lower
Khuff A
Khuff A

Tatarian Khuff B Khuff B

UPPER
PERMIAN

Khuff
Khuff C Khuff C

Kazanian

Khuff D

Khuff E
Kungurian Unayzah A
LOWER

Artinskian A

Sakmarian Unayzah Unayzah B

B
U
CARBONIFEROUS

Figure 2: Part of a
generalized Paleozoic
M

stratigraphic column for

Tournasian-
Asselian Saudi Arabia showing
the stratigraphic
L

Berwath
position of the Khuff
Formation.

Formation. During the Permian, the Arabian Plate was part of Gondwana near latitude 30ºS (Bambach
et al., 1980) and most of the Arabian Peninsula was covered by a restricted evaporite-carbonate shelf-
platform sea.

Five depositional members were recognized within the Khuff Formation in Saudi Arabia
(Al-Jallal, 1995); in descending order they are, Khuff-A, -B, -C, -D, and -E, as shown in the stratigraphic
column Figure 2. The Khuff-A to -D members show cyclic sedimentation. Each cycle starts with a
gradual transgression of subtidal grainstones that make up the Khuff reservoirs and ends with the
gradual deposition of a regressive unit of intertidal and supratidal muddy and evaporitic deposits
that constitutes the seal. In contrast, the transgressive Khuff-E consists of the ‘basal Khuff clastics’.

The Khuff Formation is within Arabian Plate tectonostratigraphic megasequence AP6 of Sharland et
al. (2001), the base of which is the pre-Khuff unconformity dated at 255 Ma. The depositional cycles in
the Khuff Formation can be correlated with the global Late Permian eustatic cycles of Haq et al. (1987).
Based on the correlation of maximum flooding surfaces, the Khuff-A, -B, -C, and -D cycles were
identified by Sharland et al. (2001). The Khuff-C reservoir is within the Khuff-C member in a sequence
of cyclic carbonate-evaporite deposits. The reservoir interval consists of interbedded, tight and porous
limestone and dolomite beds sandwiched between thick anhydrite-rich layers that act as seals.

Depositional Environments and Facies

Figure 3 shows the major facies and environments of deposition for the Khuff Formation (Al-Jallal,
1995). The depositional environments were predominantly intertidal and sabkha together with subtidal
carbonate sand shoals, lagoons, and sandbars. The arid conditions that exist today along the southern

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 Dasgupta et al.

Coral-algal
reefs
Deep-marine
argillaceous
Evaporitic limestones N
carbonates and 0 km 500
siliciclastics

Evaporitic
carbonate Radiolarite
shelf

Lower slope
debris apron
Arabian
Gulf Cephlopod
12 limestone

Ghawar

Slope
deposits
Arabian Coral-algal
Shield reefs

Shallow shelf Shallow

break carbonate
shelf

Siliciclastics

Mixed carbonates
and siliciclastics Arabian Sea
Red Sea

Figure 3: Environments of deposition and major facies of the Khuff Formation (after Al-Jallal, 1995).

shore of the Arabian Gulf prevailed at the time of deposition of the Khuff Formation. Sabkha features
similar to those of today have been seen in Khuff cores (Al-Jallal, 1989).

Several wells in the ‘Uthmaniyah sector of the Ghawar field have penetrated the prolific Khuff-C gas
reservoir (Figure 4). Two of these wells, A and B, intersected tight Khuff-C reservoir intervals. Cores
from the Khuff-C in these wells show that anhydrite has cemented the dolograinstone matrix. To the
east of wells A and B, a stratigraphic zero porosity edge was interpreted as the limit of preservation of
Khuff-C reservoir porosity in the area. A west-to-east cross-section through the field, based on logs
from wells 16, 1, and B, illustrates the heterogeneity of the reservoir (Figure 5) with tight well-B being
on its eastern margin. Based on this original interpretation of the well control, the eastern flank of the
Khuff anticline in the area was considered to be tight (Figure 4) and was removed from development-
drilling plans for the Khuff-C reservoir. However, this interpretation has recently been revised through
the integration of 3-D seismic and petrophysical data described in this present study.

The cores of the Khuff-C reservoir interval from several wells in the ‘Uthmaniyah area were studied
for composition, texture, lithology, facies, porosity type, and cementation, and were calibrated to
wireline logs. Thin sections from the cores were examined for textural details and for diagenetic
overprints. Cores from porous Khuff-C reservoir intervals are composed of grainstone, dolograinstone,
and dolomudstone (Figure 6). Lateral depositional facies regionally control the reservoir distribution.
Localized diagenetic changes played a dominant role in the porosity distribution as cementation has,

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 Khuff-C carbonate reservoir characterization, Saudi Arabia

00
2,2
-1 000 ,800 00
2, -11 1,
6
-1 -1
0
,40 N
-11
0
,20
-11
Khuff-C stratigraphic
18 porosity edge
00

-13,200
-13,000
0,8

-12,800
17

-12,400
-12,600
-1

-12,000
-12,200
-11,800
14
- 10 , 6 0 0
0
,40
-10

Figure 5 1
Y Y’
10,200

16 A
Figure 12
2
B
X X’
3 Figure 10
-11,400 -11,600

5
6
-11,000 00

4
Z Z’
-11,2

12 7 15 Figure 13
8
10 9
Khuff-C
gas-water contact
11

13
00
-11,200

Figure 4: The stratigraphic porosity edge as

00
-11,4
-11,6
0

originally interpreted before 3-D seismic

,00
-11

amplitude inversion was performed. Khuff

0 km 10 depth contours are referenced to sea level.
(See Figure 1 for location.)
Well location

West East
WELL-16 WELL-1 WELL-B
Sonic Sonic Sonic
80 msec/ft 40 80 msec/ft 40 80 msec/ft 40

Figure 5: Khuff-C
porosity distribution.
West-to-east cross-
Khuff-C reservoir section through wells
200 ft 0 ft
170 ft
16, 1, and B to illustrate
62 ft the heterogeneity of the
Khuff-C reservoir in the
‘Uthmaniyah sector of
4 km 7 km
the Ghawar field (see
Figure 4 for location).
Porous intervals vary in
thickness from 170 ft in
well-1 to zero in well-B.

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 Dasgupta et al.

(a) Porous Well-3

Gamma- Core Core

Compo-

Poro-
Density

Cement
Permeability Porosity %

Drilled

type
depth

sition

Layers
Ray

sity
Drilled
depth
0 API 50 g/cc Sonic Rock Grain Well-3
Unsmoothed 30 Unsmoothed 0 Type size
Caliper Porosity 80 msec/ft 40 10,000 0.1 CPI Porosity M I B BQ Notes
0 inch 24 30 NPHI -15 mD 30 % 0 QP PC T
MWP L G B C S V F MC V G

12,090 12,090
C-2 (Top
Khuff-C)
12,100 12,100
2A

12,110 12,110
C-3
3A
12,120 12,120

3B
12,130 12,130

3C
12,140 12,140

12,150 12,150
3D

12,160 12,160

12,170 12,170

3E
12,180 12,180

C-4 (cycle
12,190 12,190 boundary)
4A
12,200 12,200

12,210 12,210 4B

12,220 12,220

4C
12,230 12,230

12,240 12,240
4D
C-5
12,250 12,250
5A

12,260 12,260

5B
12,270 12,270

12,280 12,280 5C To top

Khuff-D
12,290 12,290
5D at 12,350 ft

Figure 6: Core logs from Khuff-C: (a) porous well-3 and (b) tight well-B. In (a) porous Khuff-C consists
of grainstone and some dolomite with up to 30 percent core porosity; in (b) tight Khuff-C has a dolomite
matrix with pores filled with anhydrite cement.

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 Khuff-C carbonate reservoir characterization, Saudi Arabia

(b) Tight Well-B

Gamma- Core Core

Compo-

Poro-
Density

Cement
Permeability Porosity %

Drilled

type
depth

sition

Layers
Ray

sity
Drilled
depth
0 API 50 g/cc
Sonic Rock Grain Well-B
Unsmoothed 30 Unsmoothed 0 Type size
Caliper 80 msec/ft 40 10,000 0.1
Porosity CPI Porosity M I B BQ Notes
0 inch 24 30 NPHI -15 mD 30 % 0 QP PC T
MWP L G B C S V F MC V G

12,030 12,030
C-2 (Top
Khuff-C)

2A
12,040 12,040

C-3
12,050 12,050 3A

12,060 12,060
3B

12,070 12,070
3C

12,080 12,080

3D
12,090 12,090

12,100 12,100

12,110 12,110
3E

12,120 12,120 C-4 (cycle

boundary)

12,130 12,130 4A

12,140 12,140
4B

12,150 12,150

12,160 12,160 4C

12,170 12,170

4D
12,180 12,180
C-5
5A

12,190 12,190

5B To top
12,200 12,200
Khuff-D
at 12,274 ft
Composition Well/Moderate Cemented
Limestone Calcite Anhydrite
Dolomite Dolomite Dolomite+Anhydrite
Anhydrite

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 Dasgupta et al.

in places, destroyed the reservoir porosity (Talu and Abu-Ghabin, 1989). Microscopic examination of
thin sections from Khuff-C reservoir cores show intergranular and intercrystalline porosity in well-3
that contrasts with core from well-B in which anhydrite cement occludes the intergranular pores
(Figure 7). Anhydrite cementation is a common phenomenon in the Khuff reservoirs. It usually occurred
almost contemporaneously with deposition as saturated fluids percolated downward and precipitated
anhydrite in the underlying grainstone pore spaces and in the intercrystalline porosity of mudstones.
The grainstones of this type are usually dolomitized. A simplified model of the diagenesis and
cementation process is shown as Figure 8.

(a) WELL-3 (b) WELL-B

0 mm 1 0 mm 1

Figure 7: Photomicrograph of cores from wells 3 and B. (a) Well-3 has intergranular and
intercrystalline porosity; (b) in well-B, intergranular pores are filled with anhydrite.

INTEGRATION OF RESERVOIR CHARACTERISTICS

Methods

Sonic and density logs from existing wells in the area were processed for petrophysical information
and field-wide calibration and correction. Stratigraphic markers at and near the objective reservoir
zone were correlated on wireline logs for the wells and converted to two-way travel time to aid the
interpretation of seismic data.

Seismic data
3-D seismic data were acquired in order to understand the reservoir framework in the study area,
delineate the complexity of the reservoir, and map the porosity distribution. The seismic survey
parameters were designed to better image the deeper Khuff and pre-Khuff objectives down to 16,000
ft. Five vibrators were used at each source point, with a 12-sec up-sweep and a sweep frequency of 8
to 80 Hz. The cable length was 3,600 m. The field geometry created a 144-fold stack with 24-fold
in-line and 6-fold cross-line. The surface coverage was 200 source points per sq km and the Common
Depth Point bin size was 25 by 25 m. The total seismic survey area was approximately 850 sq km. The
data were processed through a stratigraphic flow sequence in order to preserve the relative amplitudes.
The final Dip Moveout-processed, time-migrated seismic stack volume was loaded onto workstations
for interactive interpretation.

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 Khuff-C carbonate reservoir characterization, Saudi Arabia

Arid climate

Khuff-C island
Rapid evaporation
Sea leve
l
l
Se a leve

flow
Exposed Khuff-C age in eflux
Seep age r
Ceme Seep
nted
pores

ion
ipitat
rite prec
A nhyd
te
ydri
f-D Anh
f
Khu

Figure 8: Conceptual model of Khuff-C diagenesis. Khuff-C islands were subaerially exposed—
rapid evaporation took place in a hot arid climate and, consequently, rock pores were filled with
evaporite cement.

Seismic calibration
The seismic to well-log calibration was a critical step in the amplitude inversion process that included
wavelet extraction and the generation of synthetic seismograms to tie recorded seismic traces near
each well. This calibration was performed for all wells in the area that had sonic and density logs.

Wavelets were extracted using the available well-log interval and the impedance logs and stack seismic
traces over a window centered on the reservoir. The wavelets derived from the well-log calibration
indicated a consistent waveform similar to a Ricker wavelet of 35 Hz. The phase variation for the
wells analyzed was within 20º of the theoretical Ricker wavelet. Minor variations in the extracted
wavelets from well to well were believed to have been caused by residual random and coherent noise
in the seismic data. A representative wavelet from well-3 was computed for the seismic volume, and
synthetic seismograms and acoustic impedance were computed along the target reservoir level for the
entire seismic volume. The wells were calibrated to tie the picked geological markers to seismic horizons
and a wavelet was derived from the seismic-to-well calibration.

Interpretation

Seismic data
The Khuff-C reservoir is 170 to 250 ft thick in the depth range of 12,000 to 14,000 ft in the study area.
This is within the resolution of the 30 Hz dominant frequency of the seismic data. The interpretation
of the seismic data showed an abrupt termination of amplitude in the vicinity of wells A and B that
had tight reservoir intervals.

Synthetic seismograms generated from the well logs indicated a sharp waveform contrast and an
amplitude trough associated with wells having porous Khuff-C. Tight Khuff-C intervals corresponded
to high acoustic impedance and diminishing amplitude or, in some cases, to a reversal of polarity. The
sharp waveform contrast that were observed in the synthetic seismograms from porous to tight
Khuff-C reservoir intervals (Figure 9), provided a basis for delineating porosity variations within the
reservoir.

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 Dasgupta et al.

1.0
(a)

0
Porous Well-3

-50 -25 0 25 50
msec
P-wave (ft/sec) Seismic traces
Depth Density (g/cc) from the 3-D volume Time
Synthetic
(ft) 2.0 2.5 3.5 10,000 20,000 seismogram 964 970 976 986 (sec)

6,566
6,757
6,948 1.1
Hadriya
7,118 Reservoir
7,303
7,451
Lower
7,627
Fadhili
7,786 1.2

7,967
8,146

8,337
8,520
8,690 1.3

8,858
9,031
9,184

9,334
9,495 1.4

9,667
9,840 Base Jilh
Dolomite
10,020

10,189
10,357 1.5

10,533

10,690 Top Sudair

10,810
10,920 Base
1 1,046 Sudair 1.6

1 1,170
1 1,344 Top Khuff
1 1,536 Formation

1 1,747 Khuff-C
1 1,951 1.7

12,132
12,344

Figure 9: Sonic and density logs, synthetic seismograms and seismic traces from the Khuff-C reservoir.
(a) Porous well-3: synthetic seismograms show a trough representing the porous Khuff-C.

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 Khuff-C carbonate reservoir characterization, Saudi Arabia

1.0
(b)

Tight Well-B 0

-50 -25 0 25 50
msec
Depth Seismic traces Time
Density (g/cc) P-wave (ft/sec)
Synthetic from the 3-D volume
(ft) (sec)
2.0 2.5 3.0 10,000 20,000 seismogram 1,088 1,096 1,104

5,595

5,766
5,936
Hadriya
6,118
Reservoir
6,286 1.1
Lower
6,472 Fadhili
6,655

6,834
7,023

7,215 1.2
7,388
7,559
7,736
7,888

8,038 1.3
8,197
8,394 Base Jilh
Dolomite
8,559
8,729
8,902 1.4
9,061
9,240
9,402
9,540 Top
Sudair
9,646 1.5
9,777
Top Khuff
9,890 Base formation
Sudair
10,037

10,233
Khuff-C
10,432 1.6
10,646
10,864

11,081

11,081

(b) Tight well-B: the reflection event corresponding to Khuff-C is characterized by diminishing
amplitude in the synthetic seismogram and by poor seismic amplitude.

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 Dasgupta et al.

West Seismic Line X—X’

East
WELL-3 WELL-B

Jilh
1.6 1.6

1.7 1.7
Two-way Time (sec)

Top Khuff
1.8 1.8
Top Khuff-B

Termination of seismic event

1.6 1.6

1.7 1.7
Khuff-C
Top Khuff

1.8 1.8
Khuff-B

Khuff-C
Acoustic impedence
Figure 10: Seismic line X–X’ (see Figure 4 for location) from 3-D (g/cc) x (ft/sec)
data through porous Khuff-C well-3 and tight well-B; note that
amplitude abruptly terminates east of well-3. The inversion 58,675 34,585
indicates low acoustic impedance in the porous well and high 54,660 30,570
50,645 26,555
impedance in the tight well. Low impedance again occurs to 46,630 22,540
the east of tight well-B suggesting the presence of porous 42,615 18,525
Khuff-C on the originally interpreted tight east flank. Well logs 38,600
are acoustic impedence.

Figure 10 shows seismic line X–X’ through well-3 (porous Khuff-C) and well-B (tight Khuff-C)
approximately 2.5 km to the east (Figure 4). The seismic data show strong amplitudes that correspond
to the Khuff-C reflector in well-3. They terminate abruptly to the east of well-3 but reappear to the east
of well-B. The acoustic impedance is low for the seismic line at well-3 and increases abruptly to the
east in the vicinity of well-B. This suggests that amplitude diminishment is localized in the vicinity of
wells that have tight Khuff-C porosity.

An initial model-based 3-D seismic amplitude inversion was performed on the data using calibrated
sonic and density logs that were available in 17 wells. The initial model assigned an impedance log
for every trace in the seismic volume by interpolating impedance values between the well-control
points. The iterative inversion process to match the amplitudes for each trace in the seismic-volume
time window then updated the model. The amplitude inversion was thus target oriented, iterative,
and constrained by acoustic impedance computed at the wells.

Acoustic impedance and reservoir porosity

Areal distribution of the Khuff-C impedance (Figure 11) illustrates the heterogeneity of the reservoir
quality; this information would not have been available from well data alone. The Khuff-C reservoir
porosity was predicted from the 3-D inversion with blue and green representing higher levels of porosity,
and yellow and red showing low levels. The acoustic impedance versus porosity cross plots from well
logs indicate a linear trend. An example of a tight location is well-16 in Figure 12, this being one of the
wells drilled before the seismic inversion modeling. The computed impedance indicates a highly
variable reservoir quality along the line. A porous location was identified in the continuous low-

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 Khuff-C carbonate reservoir characterization, Saudi Arabia

Acoustic
1 impedance
16 (g/cc) x (ft/sec)

A 57,000
2
Khuff-C stratigraphic N 56,375
55,750
porosity edge
B 55,125
K-1 54,650
3
53,875
K-2 5 K-7 53,250
4 6 52,625
K-3 52,000
12 K-4 51,375
7 50,750
8
Khuff-C 50,125
gas-water contact 15 49,600
9 48,875
10 48,250
47,625
K-5 47,000
K-6
46,375
45,750
11 45,125
13 K-8 44,500
43,875
43,250
K-9
0 5 42,625
km
K-10 42,000

Figure 11: Computed acoustic impedance; the original porosity edge is superimposed for
reference. High impedance (tight porosity) is localized in the vicinity of the two tight Khuff-
C wells A and B. East of these wells (originally assumed to be beyond the limits of reservoir
porosity), good porosity (green and yellow) is indicated on the impedance map. This map
was used to program drilling location for wells K-1 to K-10, all of which intersected porous
Khuff-C reservoir intervals as predicted.

acoustic impedance zone shown in Figure 13. The corresponding seismic line and the acoustic
impedance for the initial model derived from the wells and interpolated between wells are also shown.

The acoustic impedance map (Figure 11) shows that high impedance/low porosity is localized in the
vicinity of the two tight wells A and B. The area to the east of these wells, originally interpreted to be
beyond the limits of Khuff-C reservoir porosity, shows good porosity (greens and yellows) on the
impedance map. These results imply that Khuff-C porosity extends to the entire eastern flank of the
‘Uthmaniyah sector and thus opens up a large fairway for porous Khuff-C reservoir delineation
(Dasgupta et al., 1999, 2000). Thus, the Khuff-C gas reservoir volume in this area is significantly larger
than was originally interpreted based on the well data alone.

Observed reservoir pressure versus simulation

The original reservoir simulation of the Khuff-C gas reservoir in the study area used a geological
model with zero porosity thickness to the east of wells A and B that intersected a tight Khuff-C reservoir
interval. Figure 14 shows the reservoir simulation model study for the period from the start of gas
production in 1984 until 1998. The results indicate that the observed reservoir pressures (ranging
from 7,000 to 6,200 psi) were consistently higher by 700 to 800 psi than the modeled pressures (green
curve in Figure 9). This additional pressure suggests extra sources of Khuff-C reservoir energy (P.
Hsueh and M. Al-Shammari, 1996, unpublished Saudi Aramco Report RSD3.058). In order to achieve
a history match with the observed pressure at the wells, the gas saturated porosity thickness φ − h × Sg
(where φ = porosity; h = thickness; and Sg = gas saturation) of the reservoir was globally increased by
40 percent. The modeled pressure profile (blue curve in Figure 14) at the new reservoir volume can be

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 Dasgupta et al.

West East
Subline Y-Y’
WELL-16
(a)
1.60

1.62

1.64

1.66

Acoustic
1.68
impedence
2 (g/cc) x (ft/sec)
Two-way Time (sec)

1.60
3
4 63,723
1.62 61,745
5
59,787
6
1.64 57,789
7 55,811
8 53,833
1.66 9
10 51,855
11 49,877
1.68 12
13 47,899
45,921
1.70
43,943
41,965
1.72 39,987
Khuff-C 38,009
1.74 36,031

WELL-16

(b)

1.55
Two-way Time (sec)

1.60

Acoustic
1.65 impedence
(g/cc) x (ft/sec)

55,000
1.70 52,500
50,000
47,500
Khuff-C 45,000
42,500
1.75 40,000
37,500
35,000
32,500
30,000

Figure 12: Example of a tight Khuff-C location on seismic line Y–Y’ (see Figure 4 for location);
well-16 was drilled prior to seismic inversion and intersected poor Khuff-C reservoir conditions.
(a) Seismic line from 3-D volume is overlain by acoustic impedance in color (from well data) and
shows the 13 layers in the intial model used in the inversion process; (b) Corresponding acoustic
impedance computed from seismic data; high acoustic impedance values in the Khuff-C interval
indicate low porosity.

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 Khuff-C carbonate reservoir characterization, Saudi Arabia

West East
Subline Z-Z’
WELL K-3
(a)
1.50

1.52 2
3
1.54
4
5
1.56
6
1.58 7
8
9 Khuff-C
1.60 10
11 Reservoir
12
Two-wayTime (sec)

1.62 13
Acoustic
1.64 impedence
(g/cc) x (ft/sec)
1.66

1.68 62,630
60,413
1.70 58,296
56,178
1.72 54,062
51,945
1.74 49,828
47,711
1.76 45,594
43,477
1.78 41,360
39,243
37,126
36,009
WELL K-3 32,892

(b)

1.55
Two-wayTime (sec)

1.60

Acoustic
1.65 impedence
(g/cc) x (ft/sec)

55,000
1.70 52,500
50,000
47,500
45,000
Khuff-C 42,500
1.75 40,000
37,500
35,000
32,500
30,000

Figure 13: Example of a porous Khuff-C location on seismic line Z-Z’ (see Figure 4 for location).
(a) Seismic line from 3-D volume is overlain by acoustic impedance in color (from well data) and
shows the 13 layers in the intial model used in the inversion process; (b) Corresponding acoustic
impedence computed from the seismic data constrained by the initial model from well logs; good
Khuff-C porosity is identified with the continuous low impedance zone. Drilling results at
well K-3 indicated 206 ft of porous Khuff-C, as predicted from inversion results.

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 Dasgupta et al.

(a)
Million cu ft/day 75

50

25

0
1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998
Year
(b)
8,000

Final model
Pounds/sq inch

7,000
Observed pressure

6,000

5,000
Initial model

4,000
1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998
Year
Figure 14: Reservoir simulation model from the start of gas production in 1984 until 1998. (a) Gas
production rate; (b) Pressure. Observed pressures are consistently higher than initial (modeled)
pressures. To achieve a history match with observed pressures at the wells, the pore volume or gas-
saturated porosity thickness φ − h × Sg (where φ = porosity; h = thickness; and Sg = gas saturation)
of the reservoir was increased by 40 percent. The blue curve represents the modeled pressure
profile at the increased reservoir volume.

explained by increasing the pore volume or reserves. The inclusion of reservoir porosity beyond the
original zero porosity accounts for increased pore volume of the Khuff-C reservoir.

DRILLING RESULTS

Development Drilling Program

The distribution of impedance of the reservoir interval was used as a guide for predicting reservoir
quality and in assisting future well placement. The acoustic impedance map (Figure 11) was used
qualitatively as a guide in planning the sub-surface location of development drilling program. The
results of the development drilling were highly successful. Ten wells have been drilled so far using
the acoustic impedance from seismic inversion and each of them intersected porous Khuff-C gas
reservoir intervals (Figure 15).

Well-18

Khuff-C reservoir heterogeneity and localized tight facies were verified in a recent well in the
‘Uthmaniyah area. Evaluation well-18 was located before the integration of seismic data
(see Figure 4). Sonic and density logs from the well had showed virtually no porosity in the Khuff-C
(Figure 16). However, the seismic data showed a local amplitude anomaly at well-18 that was
surrounded by normal amplitudes and low acoustic impedance corresponding to porous Khuff-C.
This suggested that the well had intersected a tight Khuff-C ‘island’ (see Figure 8) but was surrounded

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 Khuff-C carbonate reservoir characterization, Saudi Arabia

K-7
K-1
K-3
K-6 K-8
K-2 K-4 K-5 K-10
K-9

Khuff-C stratigraphic
porosity edge

Khuff-C
gas-water contact
1 A
16 3 B 5
2 6
4 7 8 15
9
10
12 13
11

Acoustic
impedence
(g/cc) x (ft/sec)
65,000
60,000

55,000

50,000

45,000

40,000

Figure 15: Acoustic impedance layers averaged over 6 msec each from the Khuff-C in the study
area. Wells K-1 to K-10 were located over low impedance Khuff-C zones and all 10 penetrated the
porous gas-bearing reservoir as predicted.

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 Dasgupta et al.

WELL-18

Gamma-Ray
API Density Sonic Flow Rate
0 50 (million cu ft/day)
Caliper g/cc msec/ft
0 inch 15 2 3 80 40 5 10 15

Top Khuff-C reservoir

12,350

12,400
Figure 16: Density and
sonic logs from well-18
indicated poor porosity
Depth (ft)

in Khuff-C. The seismic

data, however, showed
normal amplitudes
suggesting good reservoir
12,450 quality. The anomalous
amplitude corresponding
Base Khuff-C reservoir to tight porosity is only
localized at the well.
Based on the seismic
observations, the Khuff-C
reservoir interval was
tested and flowed nearly
15 million cu ft gas/day in
this well after acidizing.

by good quality reservoir. Based on the interpretation of the 3-D seismic data, well-18 was tested over
the Khuff-C reservoir interval and yielded a flow rate of nearly 15 million cu ft of gas per day (Figure
16). Fractures in the reservoir that intersected the wellbore permitted gas to flow inspite of the tight
Khuff-C in the well. The well, that would previously have been plugged and abandoned, will now be
put into production.

CONCLUSIONS

The integration of 3-D seismic acoustic impedance, petrophysical data from wireline logs, core analysis,
geological interpretation, and reservoir simulation history-match results, has redefined the stratigraphic
porosity edge of the Khuff-C reservoir over the ‘Uthmaniyah sector of the Ghawar field. The integration
of observations from various disciplines has resulted in a synergy that has reduced, if not eliminated,
the ambiguity in the interpretation of results from each individual discipline. The stratigraphic porosity
edge, interpreted from the well data on the eastern flank of the field, has been revised. The results
conclude that Khuff-C porosity extends to the entire eastern flank of Khuff anticline. This improved
reservoir characterization model has increased the pore volume of the Khuff-C reservoir in the area
and has added significantly to the gas and condensate reserves. Reservoir pore volumes in the new
model also provide a more accurate prediction of reservoir performance. Since the completion of this

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 Khuff-C carbonate reservoir characterization, Saudi Arabia

study, 10 wells (K-1 to K-10 in Figure 16), have been drilled in the area with the Khuff-C gas reservoir
as the objective. Each well location was optimized to penetrate the low impedance/high-quality
Khuff-C reservoir. All 10 wells have encountered porous reservoir intervals as predicted by the model.

ACKNOWLEDGMENTS

We thank the management of Saudi Aramco for their support and for permission to publish this paper.
George Grover, Mohammed Amoudi, Abdul-Jaleel Al-Khalifa and the members of the Khuff Gas
Evaluation team are thanked for their suggestions and comments during the study. We also thank
GeoArabia’s editors and two anonymous reviewers who greatly improved the paper. The design and
drafting of the final figures was by Gulf PetroLink.

An unrefereed version of this paper (Reservoir characterization of Permian Khuff-C carbonate in the
supergiant Ghawar Field of Saudi Arabia, by Shiv N. Dasgupta, Ming Ren Hong and Ibrahim A.
Al-Jallal) was published in The Leading Edge, v. 20, no. 7, p. 706–717 (July 2001).

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ABOUT THE AUTHORS

Shiv N. Dasgupta is a Geophysical Consultant in the Reservoir

Characterization Department of Saudi Aramco. He has advanced degrees
from St. Louis University, Washington University, St. Louis and Southern
Illinois University. He has been employed with Saudi Aramco since the
early 1980s. He previously worked in exploration for Amoco Production,
Mitchell Energy & Development, and Conoco. Shiv’s professional interests
include the integration of geophysical techniques for reservoir development
and production optimization.
Corresponding author. E-mail DASGUPSN@aramco.com.sa

Ming-Ren Hong is a Geophysical Consultant with Saudi Aramco. He has

a BSc in Atmospheric Physics (1973) and an MSc in Geophysics (1977)
from the National Central University, Taiwan. He received his PhD in
Geophysics from the University of Texas at Dallas in 1982. He joined Saudi
Aramco in 1991. He had worked at the Center for Lithospheric Studies,
University of Texas at Dallas as a Research Engineer from 1982 to 1984,
and from 1984 to 1991, he was a Senior Research Geophysicist with Arco
Oil and Gas Company. Ming-Ren is a member of SEG and SPE. His
professional interests include seismic modeling and inversion, reservoir
characterization, and integrated interpretation.
E-mail: HONGMX@aramco.com.sa

Ibrahim A. Al-Jallal is Chief Geologist of Southern Area Reservoir

Characterization in Saudi Aramco. He received his BSc in Geology/
Chemistry from King Saud University, Riyadh (1973) and an MSc in
Geology from Western Michigan University (1979). He was awarded a
PhD in Petroleum Geology from Imperial College, London in 1990 for a
study of the Khuff Formation. His PhD study was the deposition, diagenesis,
and reservoir prediction of the Khuff Formation in Ghawar field, Saudi
Arabia. He recently extended this study regionally to include all the Gulf
States. Ibrahim has experience in wellsite operation, reservoir development,
prediction, layering and depositional modeling. His involvement in
geological R&D and reservoir characterization projects have included reservoir characterization
support for field development and geological studies, and participation with international consortia
in E&P activities. He was in charge of a team that studied the Jauf reservoir in the North Ghawar
Reservoir Characterization project that included implementation of sequence statigraphy and
integration of 3-D seismic interpretation. In 2000, he became the Chief Geologist for Southern
Area Fields Characterization that includes Ghawar, Abqaiq and the Arab-D in central Saudi Arabia.
E-mail: jallalia@aramco.com.sa

___________________________________________________________________________________

Manuscript Received May 20, 2001

Revised October 13, 2001
Accepted October 22, 2001

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