Tilted Original Oil/Water Contact in the Arab-D Reservoir, Ghawar Field, Saudi Arabia

GeoArabia, Vol. 8, No. 1, 2003 Gulf PetroLink, Bahrain Tilted OOWC, Arab Reservoir, Ghawar field

Tilted original oil/water contact in the Arab-D reservoir, Ghawar field, Saudi Arabia

Bruno Stenger, Tony Pham, Nabeel Al-Afaleg and Paul Lawrence

ABSTRACT

A review of the electrical logs, fluid properties, and production history of 195 flank wells drilled in the Arab-D carbonate reservoir of the Ghawar field, Saudi Arabia, showed that the original oil/water contact was regionally tilted. The contact was about 200 ft higher in the southern Haradh sector than in the northern Shedgum and ‘Ain Dar sectors. In Haradh, the fluid contact was also locally tilted down from west to east by as much as 800 ft. In the reservoir, the oil and aquifer densities changed from lighter oil and denser water in the north to lighter water and denser oil in the south. Decreasing methane content caused the increase in oil density and a reduction in the water density was the result of a salinity decrease. The evolution of fluid densities was closely correlated to a decreasing regional-scale geothermal gradient, probably indicating that temperature controlled the distribution of fluid densities. Simple analytical calculations showed that the magnitude of the observed tilt of the original oil/water contact from north to south might be explained by changes in fluid densities. On the western flank of central Haradh, the Arab-D reservoir water was anomalously young and fresh and this created a large salinity gradient between the western and eastern aquifer legs. This anomaly was explained by pressure-dependent vertical leakage along the Wadi Sahba structural trough between the Arab-D reservoir and the shallower Biyadh aquifer. Consequently, the integrity of the Hith Formation seal above the Arab-D reservoir might be locally compromised under particular conditions. A full-field reservoir simulation model, specific geological features, and examples from the technical literature supported a static interpretation of the tilted original oil/water contact in the Arab-D reservoir of Ghawar through the combined effects of changes in oil and water densities.

INTRODUCTION

In fully buried reservoirs, trapped fluids are generally in a static condition prior to production, and the Original Oil/Water Contact (OOWC) would normally be horizontal. However, naturally occurring tilted OOWCs have been described. The most commonly accepted explanations are ‘frozen-in’ diagenetic trapping combined with late-tectonic tilting (‘forced’ static tilt), or regional hydrodynamic aquifers (dynamic tilt).

Wilson (1977) introduced the idea that diagenetic porosity reduction in the aquifer combined with tectonic tilting may create tilted OOWCs. Yeats (1983) and Carlos and Mantilla (2000) interpreted tilted OOWCs as a result of tectonically induced rapid development of structural folding or tilting in reservoirs of low absolute permeability. Willingham and Howald (1965), Pelissier et al. (1980), Wells (1987, 1988), Winterhalder and Hann (1991), Beckner et al. (1996), Gauchet and Corre (1996) and Luebking et al. (2001) relied on aquifer hydrodynamics to account for tilted original contacts.

For a geological formation that crops out at a high topographic elevation, rainwater infiltrates into the aquifer. If the aquifer system is also outcropping at a lower elevation, differences in the hydraulic head will induce water flow. Where hydrocarbons are trapped deeper in the sedimentary basin, the flow in the aquifer leg may lead to the dynamic tilting of the OOWC.

Dickey (1963), Dickey and Soto (1974) linked aquifer activity with chemical composition at the scale of the sedimentary basin, and showed that highly saline brines are characteristic of static aquifers. Of special importance for this paper was the concept introduced by Bond (1973, 1975) of aquifers in static equilibrium even though changes in hydraulic head were measured. The apparent paradox was explained by variable salinity at the regional scale. To the best of our knowledge, this concept had not been applied to tilted OOWC prior to the work of Stenger (1999).

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40 50 60 TURKEY Caspian 48°E49° 50° Arabian Gulf Sea BAHRAIN SYRIA Med Sea IRAN N Manama IRAQ 0 300 Abqaiq

JORDAN km 30 Fazran 30 KUWAIT 26° A ra G bian ulf Awali BAHRAIN QATAR EGYPT Arabian UAE Shield OMAN SAUDI ARABIA 'Ain Dar 20 20 Shedgum Red SUDAN Sea

ERITREA YEMEN Arabian Sea QATAR

ETHIOPIA Gulf of Aden 40 50 10 Khurais Uthmaniyah Dukhan Ghawar 25° 25°N

Hawiyah Abu Jifan Qirdi

Riyadh Farhah Manjurah

Harmaliyah Mazalij Mazalij-24 Jafura Haradh Reem

N Sahba 05024° Ghazal 24° Wudayhi Tinat Dilam km Shaden Waqr Raghib Lughfah Abu Shidad Tinat South Niban Abu Rakiz Shamah Jawb 47° 48° 49° 50°

Figure 1: Ghawar field location map. From north to south the Ghawar field is divided into the following sectors: ‘Ain Dar, Shedgum, Uthmaniyah, Hawiyah, and Haradh.

We propose to interpret the tilted OOWC in the Ghawar Arab-D reservoir by the combined effects of changes in oil and water densities in and around the Ghawar field. After discussing the regional setting, the tilted OOWC in Ghawar Arab-D reservoir will be described through field observations. A discussion on the static or dynamic nature of the tilted OOWC will review different mechanisms and interpretations. Finally, conclusions on the origin of the tilted OOWC will be submitted together with a brief review of implications for the on-going development of the southernmost area of Ghawar. As indicated by Aramco (1959) and discussed by Stenger (1999) and Stenger et al. (2001), the tilted OOWC in Ghawar does not lend itself to a straightforward classification.

GHAWAR FIELD

History

The Arab-D carbonate reservoir of the Upper Jurassic Arab Formation in the onshore Ghawar field was discovered in 1948. Following further separate discoveries along the structure’s main axis, five production areas were quickly identified as parts of the giant Ghawar oil field (Figure 1): from north to south they are ‘Ain Dar, Shedgum, Uthmaniyah, Hawiyah and Haradh. At the Arab-D level, the field is a NNE-trending composite anticline 230 km long and about 30 km wide (Figure 2a). The gently dipping crestal region is composed of several sub-parallel axes. The anticline is asymmetric and fairly steep-sided (up to 10º dip). In the southernmost extension of Ghawar (southern part of South Haradh) the west flank is steeper (Figure 3). Farther north, for example in central Haradh and Uthmaniyah, the eastern flank is steeper. Figure 2b is a regional depth map of the top Jurassic.

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TOP ARAB-D FORMATION

Figure 2a (left): Top Arab-D depth map of Ghawar 49 E 49 30' 26 26 N showing the composite nature of the anticline with several subparallel crestal axis. North Haradh has 'Ain Dar 4,800 been producing since 1996, whereas the development of central Haradh is on-going. Ghawar shows 5,000 changing cross-sectional assymetry along its Shedgum N-S strike e.g. in central Uthmaniyah and south 5,200 Hawiyah, the east flank is more sleeply dipping, 5,400 whereas in northern Hawiyah and south Haradh it is the western flank that dips more steeply 5,600 (Figure 3). 5,800

6,000

6,200

Depth (ft subsea) 6,400

6,600

6,800

7,000 Uthmaniyah 7,200 48°E 50 52

7,400 28°N 28 25 25

Hawiyah 26 26

Ghawar

North 0 24 24

Haradh

Central 7,000

N 030 South 22 Depth (ft subsea) 22 km

14,000 24 WESeismic Line 24 48 50 52 Figure 3 49 49 30' Figure 2b: Top Jurassic regional depth map. Points north and east of the red line are extrapolated.

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SEISMIC TIME CROSS-SECTION, SOUTH HARADH West East

1.0 1.0 Two-way Time (sec) Two-way

2.0 2.0

West East

Aruma

Ahmadi

Shu'aiba 1.0 1.0

Arab-D Two-way Time (sec) Two-way

Jilh

2.0 2.0

05km

Figure 3: Seismic cross-section through the southernmost part of the Ghawar field in South Haradh (see Figure 2a). In this part of Ghawar, the west flank is more steeply dipping than the east flank.

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According to Wender et al. (1998), the growth history of the Ghawar structure consisted of the following four main phases: Hercynian Orogeny (Carboniferous); Zagros rifting (Early Triassic); Early Alpine Orogeny (Late Cretaceous); and Late Alpine Orogeny (Tertiary). Post-Jurassic tectonic activity was generally mild and limited to the multistage rejuvenation (uplift and erosion) of the Ghawar structure— a part of the greater En Nala Anticline—that is bounded by major N-trending Hercynian basement faults.

The ‘Ain Dar and Shedgum areas went on stream in 1951 and development progressed southward by stages. Due to the lack of aquifer support, peripheral gravity water-injection was started in the late 1960s to maintain the reservoir pressure at an adequate level. Since the early 1980s, powered seawater injection has replaced gravity injection in a bid to conserve freshwater resources.

During the last fifty years, thousands of vertical wells have been drilled on 1-km spacings. Most of these wells have open-hole completions. In the last five years, the use of horizontal drilling has intensified, especially in the southernmost area where the degraded reservoir quality limits the productivity of vertical wells. At the time of writing (2002), the Arab-D reservoir development is reaching the southernmost Haradh area (Figure 2a). North Haradh has been producing since mid 1996 at the established plateau rate, and the Central Haradh drilling is scheduled for completion in early 2003.

To support the on-going field development and management, Saudi Aramco is applying the latest technologies in reservoir characterization, modeling, and 3-D visualization. For instance, a modeling challenge lies in the sheer size of the Ghawar Arab-D reservoir that requires several reservoir sector models to be maintained. Thanks to the development by Saudi Aramco of POWERS––a reservoir simulation software based on massive parallel processing––a single multimillion-cell model may now be used to describe the fluid-flow mechanisms of entire giant fields (Dogru et al., 2001). Meyer et al. (2000) and Cantrell et al. (2001) proposed innovative interpretations for the origin and distribution of dolomitic super-permeability (super-k) intervals in the Ghawar Arab-D reservoir that are responsible for anomalously high production rates. According to Cantrell et al. (2001), their distribution is not correlatable to the rock facies but rather to a degree of structural control. Al-Shahri et al. (1998), Al-Ajmi et al. (2001), and Phelps et al. (2000, 2001) have evaluated optimal production strategies for the Arab-D reservoir by taking into account such geological complexities as super-k intervals and fracture clusters/swarms.

Arab-D Reservoir

In Ghawar, the Arab-D reservoir is divided from top to bottom into lithostratigraphic Zones 1 to 4, with Zones 2 and 3 being subdivided into subzones A and B (Figure 4). The best reservoir quality is in Zone 2, described as having been formed in a shallow-marine, high-energy environment. The sharp decrease of the Arab-D reservoir properties below the middle of Zone 3A, has had an adverse effect on the oil saturation as recorded by logging tools (Figure 5). As porosity and permeability drop, open-hole readings of water saturation increase rapidly to 100 percent due to large capillary pressures (pore-size effect). In the Ghawar field, the pay porosity cutoff is 4 percent.

From north to south, the quality and thickness of the Arab-D reservoir steadily decrease and the productivity of vertical open-hole producers drops four-fold (Figure 6). At the time of writing (2002), all known static and dynamic data on Ghawar indicate lateral reservoir continuity across the entire field. In particular, fault throws mapped from 3-D seismic are not large enough to create reservoir compartmentalization. However, the Arab-D reservoir is a seismic reflector of variable quality and lineaments derived from the 3-D seismic are generally better defined at shallower or deeper levels. Image logs have shown that natural fracturing is present throughout the Arab-D reservoir in the Ghawar field (e.g. Phelps and Strauss, 2000). Borehole breakouts and fractures have been analyzed in vertical and horizontal wells. The azimuth of the (present-day) maximum horizontal in situ stress varies from N60ºE in Uthmaniyah to N110ºE in the south (Figure 7a). In Haradh, natural fracturing shows a complex tectonic history with the existence of three main families of fractures having trend directions of N10ºE, N80ºE, and N130ºE (Figure 7b).

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ARAB-D RESERVOIR ZONATION AND QUALITY In eastern Saudi Arabia, most of the units above the Arab Formation are composed of carbonate Open-hole Logs Open-hole Flowmeter rocks. Thus, by knowing the thermal conductivity Porosity 50% 0 of the upper units, it is possible to compute an Water Saturation Oil 100% 0 0 100% average geothermal gradient from the near surface to the Arab Formation, as the thermal conductivity will be fairly uniform. Although no Zone 1 direct heat flow data are available, the average Zone 2A geothermal gradient can be calculated from the difference between the reservoir temperature and a depth below the Earth’s surface where the Zone 2B change in temperature due to solar radiation is negligible. It is assumed that the baseline temperature is 50oF at a depth of 30 ft. A total of

Zone 3A 110 geothermal gradients was used to construct the geothermal gradient map (Figure 8a). The map shows a high of 3.2ºF/100 ft on the Dammam

Zone 3B Dome and a decreasing geothermal gradient from 2.5ºF/100 ft in northern Ghawar to 1.8ºF/100 ft in the south. Zone 4 From 1970 to 1983, the Haradh area was Figure 4: Typical Arab-D open-hole log producing by primary depletion. This caused the response showing reservoir quality and reservoir pressure and temperature on the reservoir zonation. Flow contribution below western flank of Central Haradh to fall by 700 psi reservoir Zone 2B is limited. and 34ºF, respectively. From 1983 to 1990, the Haradh sector was mothballed following a OPEN-HOLE LOG WATER SATURATION sustained drop in the international demand for NORTH GHAWAR oil and the reservoir temperature recovered to its 6,100 initial value. A 1991 temperature map of the Haradh area shows a remnant area of lower 'Ain Dar A 'Ain Dar B temperature on the west flank (Figure 8b). 6,200 The salinity of the regional Arab-D aquifer is a Well Locations function of the Arab-D burial depth and 6,300 geothermal gradient as shown by the good 'Ain Dar A 2 010 coefficient of correlation (r = 0.86) using a km two-parameter linear regression (Figure 9). 6,400 B However, a poor match exists between the C average measured (42,000 ppm Total Dissolved D Solids––TDS) and calculated (102,000 ppm TDS) 6,500 Shedgum salinity on the west flank of Central Haradh. The

6,100 regression also overestimates the measured salinity on the western flank of southern 'Ain Dar C 'Ain Dar D Depth (ft subsea) Hawiyah. A closer look at the Ghawar aquifer 6,200 salinity shows a strong contrast between the isolated western and eastern aquifer legs

6,300

Figure 5: The effect of reservoir quality on the oil- 6,400 water contact can be demonstrated by the water saturation logs in the ‘Ain Dar area. Water saturation increases sharply at the bottom of the 6,500 reservoir section due to decreasing reservoir quality.

0 0.2 0.4 0.6 0.8 0 0.2 0.4 0.6 0.8 1 The original oil water contact cannot be accurately Water Saturation (Fraction) determined in any of these wells.

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PRODUCTIVITY INDEX ARAB-D RESERVOIR (Figure 10), although the scarcity of early salinity data in and around Ghawar does not allow a 49 E 49 30' 26 N 26 definitive picture to emerge. The largest salinity 200 contrast is across Central Haradh. This is an increase from 30,000 ppm TDS in the west to 'Ain Dar 180 152,000 ppm TDS in the east. In 1981, a repeat formation test run in a southernmost Ghawar Shedgum delineation well, indicated a water-pressure 160 gradient of 0.457 psi/ft, equivalent to a salinity of 75,000 ppm TDS. On average, the aquifer 140 water-pressure gradient decreases from 0.50 to 0.45 psi/ft from north to south Ghawar. 120 In a bid to better understand the salinity change δ18 100 in Ghawar, stable isotopes of oxygen ( O) and hydrogen (deuterium, δD) have been quantified for several aquifer samples. W.J. Carrigan and 80 S.H. Al-Sharidi (unpublished Saudi Aramco

Productivity Index (stb/d/psi) Productivity Index memo HSD 188-98, 1998) showed that Arab-D 60 aquifer water samples from the western flank of Central Haradh fall on the Pleistocene meteoric 40 water line (6,000 to 20,000 years ago) and are clearly different from the δ18O/δD isotopic range Uthmaniyah of the Arab-D Formation water (Figure 11). In 20 Central Haradh, a water sample was taken recently from the shallower Wasia Formation 0 (Middle Cretaceous) in a water well. The isotope 25 25 analysis of this sample is remarkably close to the anomalous Arab-D water sample taken from the west flank of Central Haradh (Figure 11).

From north to south Ghawar, the in situ oil pressure gradient increases from 0.302 to 0.328 Hawiyah psi/ft (Figure 12) in relation to a total gas/oil ratio decrease from 636 to 346 standard cubic feet/ stock-tank barrel. A variable concentration in methane is primarily responsible for the observed change in the oil pressure gradient. Using a simple linear regression, we noted a good correlation coefficient (r2 = 0.79) between the North regional geothermal gradient and the changes in oil density throughout Ghawar (Figure 13). In our interpretation, the geothermal gradient is the Haradh main control on the oil density distribution in Ghawar. Central The initial Ghawar Arab-D reservoir pressure of about 3,215 psi at a datum depth of 6,100 ft, was South close to the hydrostatic range. In ‘Ain Dar, the

N 030 24 24 Figure 6: The productivity index of vertical km producers and injectors in the Arab-D reservoir drops on average by 75 percent from north to south. The injectivity index has been converted to an 49 49 30' equivalent productivity index.

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STRUCTURAL TRENDS a Figure 7a (left): Multi-well composite rose diagrams 49 E 49 30' 26 26 N (green) illustrate the dominant easterly to east- northeasterly natural fracture strike in Ghawar. Locally, N 030fracture trends vary considerable (Figure 7b). Present-day stress (pink, in situ stress), as measured from borehole km breakouts, changes direction along the Ghawar anticline. It varies from approximately WNW to E-W in the north and south, to NE in the central part. Note: geometrical correction for directional drilling bias was not applied to this data.

'Ain Dar Shedgum 6 wells 3 wells 999 fractures ~30 breakouts Figure 7b (below): Tentative fracture map (blue lines) indicates possible distribution of fracture swarms. Single- well composite-fracture rose diagrams indicate locally varying fracture trends in Haradh. Fractures were analyzed using borehole image logs. The west flank has more NW-striking fractures whereas the east flank is dominated by ENE-NE-trending fractures. The Uthmaniyah asymmetrical fracture strike on the east and west flanks of Ghawar is also present in the northern parts of the field (e.g. Uthmaniyah and ‘Ain Dar). Note: correction for 39 wells 16 wells directional drilling bias was not applied to this data. 1,502 fractures 419 breakouts b 49 E 49 10' HARADH 25 FRACTURE DIRECTIONS 24 40'N 24 40'

Hawiyah

4 wells 16 wells N 24 breakouts 5,986 fractures 05

24 30' 24 30'

Haradh

4 wells 23 wells 41 breakouts 3,550 fractures

24 20' 24 20' 24

49 49 30'

49 49 10'

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GEOTHERMAL GRADIENT, JURASSIC FORMATION RESERVOIR TEMPERATURE ARAB-D 49°E 50° Kurayn Jana Jurayd 49° Abu Hadriya Berri Jaladi Khursaniyah Bakr 24°30' 24°30' 27°N27Fadhili Abu Sa'fah °

Samin Qatif 168 170

Dammam 172 174 Abqaiq Fazran 176 Awali ° 26° 26 178 180 'Ain Dar Shedgum F) 182 ° 184

Dukhan 186 188 Khurais 'Uthmaniyah Ghawar 190 Temperature ( Temperature 25° 1.3 192

Hawiyah 194 1.5 Qirdi Harmaliyah 196 1.7 Manjurah Mazalij 198 Jafura 200 1.9 24 24°

F/100 ft) Mazalij 24 ° N 202 2.1 Haradh 010 204 2.3 24° Sahba 24° km Wudayhi Tinat Control Ghazal 49° 2.5 Waqr point Shaden Tinat South Niban Lughfah 2.7 Figure 8b: 1991 reservoir temperature Shamah 2.9 N Jawb map, Arab-D reservoir, Haradh. Note

Geothermal ( gradient 050 3.1 the cooler area on the west flank of km 49° 50° Central Haradh. 3.3 Figure 8a: Geothermal gradient map of the Arab Formation in and around Ghawar. The geothermal gradient decreases from 2.5°F/100 ft in the north to 1.8°F/100 ft in the south of Ghawar. A high geothermal gradient is evident in the area of the Dammam Dome. The map is based on 110 measurements.

AQUIFER SALINITY AND GEOTHERMAL GRADIENT CORRELATION 300,000

250,000

200,000

r2 =0.86 150,000

100,000 Aquifer salinity (ppm TDS) salinity (ppm Aquifer

50,000 Largest discrepancy between measured and correlated on west flanks of Hawiyah and Central Haradh.

0 1.50 1.70 1.90 2.10 2.30 2.50 2.70 2.90 3.10 3.30 Geothermal gradient (°F/100 ft) Figure 9: Two-parameter linear regression between aquifer salinity, geothermal gradient and sampling depth. The sampling depth (not shown) indicates the salinity is, in general, vertically segregated in the Arab-D aquifer. Note the good coefficient of correlation (r2) and the poorest match achieved on the west flanks of Hawiyah and Central Haradh (South Ghawar).

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JURASSIC AQUIFER SALINITY 0 49 E Kurayn 50 Jurayd Jana 30,000 Abu Hadriya Berri 60,000 Jaladi Khursaniyah Bakr 90,000 Abu Sa'fah 27 N Fadhili 27

Samin 120,000 Qatif 150,000

Dammam 180,000 Salinity (ppm TDS) Salinity (ppm 210,000

Fazran Abqaiq Awali 26 26 240,000

270,000 'Ain Dar 300,000 Shedgum Khurais Control point

Uthmaniyah Ghawar 25 Hawiyah 25

Qirdi Figure 10: Jurassic Harmaliyah aquifer salinity map showing that the largest salinity

Haradh contrast between N the western and 24 05024 Tinat eastern aquifer km Niban legs of the Ghawar Tinat South Lughfah oil field occurs in 49 50 the Haradh area.

GHAWAR FIELD: ISOTOPIC COMPOSITION OF FORMATION WATERS

30 Injected Sea Water

10 Arab-D water North Ghawar

%) -10 Wasia water Modern Global Meteoric Line Arab-D water Uthmaniyah east flank

D (

δ North Haradh Wasia water -30 Central Haradh Umm er Radhuma water Uthmaniyah -50 Arab-D water west flank Central Haradh -70 -8.0 -6.0 -4.0 -2.0 0.0 2.0 4.0 6.0 8.0 δ18Ο (%) Figure 11: Stable isotopic analysis of Arab-D, Wasia, and Umm Er Radhuma water samples in the Ghawar area. Injected seawater is plotted for reference. Note the close relationship between isotopic compositions of Arab-D and Wasia waters on the west flank of Central Haradh. However, these two aquifers have a large difference in total salinity. The Wasia water sampled farther north in the Uthmaniyah area also shows a different isotopic composition than that in Central Haradh.

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IN SITU OIL PRESSURE GRADIENT Figure 12 (left): In situ oil pressure gradient in the 49 E 49 30' 26 N 26 Arab-D reservoir of the Ghawar field. Decreasing methane content from north to south is responsible for the increased oil pressure gradient. 'Ain Dar

0.302 OIL PRESSURE AND GEOTHERMAL Shedgum GRADIENT CORRELATION 0.330

y = -0.0204x + 0.359 0.325 0.308 r2 = 0.795

0.320

0.314 0.315

0.310 Oil pressure gradient (psi/ft) Oil pressure gradient 0.32 0.305 1.70 1.80 1.90 2.00 2.10 2.20 2.30 2.40 2.50 Pressure Gradient (psi/ft) Pressure Gradient Geothermal gradient ( F/100 ft) Figure 13 (above): Monolinear correlation between oil 0.326 Uthmaniyah pressure gradient and geothermal gradient, Arab-D reservoir, Ghawar field. Coefficient of correlation (r2) is 0.795.

INITIAL PRESSURE 25 25 ARAB-D AT -6,100 FT

49 E

24 30'N 24 30'

Hawiyah

Control point

North

Control Haradh point Figure 14 (right): The Central pre-production (pre- 1957) pressure measure- 05N ments in the Arab-D of South km Haradh indicate a 24 24 possibly slightly lower N 030 initial reservoir pressure 24 24 on the west flank. With km the exception of those taken on the west flank, 3,212 - 3,227 psi all pressure data have a 49 49 30' 49 3,198 - 3,212 psi range of 14.7 psi.

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OIL WATER CONTACT (OWC) AND FREE WATER LEVEL (FWL)

(a) OWC = FWC (b) Transitional (c) Fractures Swi Swi Swi

FWL OWC (fracture) Transition OWC = FWL Zone FWL (matrix) Depth Depth Depth FWL fracture

Figure 15: Sketches illustrating the concept of Oil/Water Contact (OWC) and Free Water Level (FWL). (a) In good-quality reservoir sections where capillary pressures may be neglected, OWC and FWL are superimposed. Original Water Saturation (Swi) is a step function. (b) Due to capillary effects in less permeable reservoir units, the OWC is distinguished from the FWL. The OWC may be considered to be any depth where oil is mobile in the transition zone. Swi is a smooth curve in the Transition Zone. (c) Poor-quality reservoir sections with fluid-conductive fractures may show two different FWLs, one for the matrix and one for the fractures. This creates additional uncertainty when determining OWCs in a reservoir. Logs might indicate hydrocarbons over a particular interval as they ‘see’ the matrix. However, when the formation is tested over this particular interval it produces water as the highest permeability is in water-filled fractures.

original reservoir pressure in 1948, in discovery well ANDR-1, was 3,204 psi at a depth of 6,100 ft. However, this value was reportedly influenced by production in the nearby Abqaiq field and was less than the original estimate of 3,226 psi at 6,100 ft (Aramco, 1959). Discovery well HRDH-1 was production tested in April 1949, with a pressure build-up of 60 hours. The initial reservoir pressure was 2,925 psi at −5,200 ft. After correcting for the reservoir oil gradient of 0.323 psi/ft, this gave the initial reservoir pressure in Haradh as 3,216 psi at 6,100 ft. A map of the Haradh pre-production pressure measurements shows a weak east-west trend (Figure 14).

TILTED ORIGINAL OIL/WATER CONTACT

Oil/Water Contact and Free Water Level

Due to capillary effects, the Oil/Water Contact (OWC) is distinguished from the Free Water Level (FWL). Whereas the former may be considered to be any depth where oil is mobile in the transition zone, the latter is synonymous with the zero-capillary pressure surface (Figure 15). In good reservoir sections where capillary pressures may be neglected, OWC and FWL are superimposed. The purpose of this paper is to investigate the Ghawar Arab-D FWL as observed in clean reservoir sections. However, for the sake of simplicity, we will use the OWC/OOWC acronyms in the following discussion.

Historical Definition of OOWC in Ghawar

Early in the development of the Ghawar field, Aramco became suspicious that the OOWC picks on open-hole logs (Figure 16) were surprisingly close to the top of the low-permeability reservoir section (Figure 17) (unpublished Aramco report, 25-N, File Gh-1.2, June 1953). For the sake of visual clarity, the OOWC surface is interpolated over the whole Ghawar field area although the aquifer physically exists only along the edge of the reservoir. This raised legitimate doubts as to the validity of the contact identification. Further complications were added to the definition of the OOWC, identified

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TILTED OIL/WATER CONTACT FROM OPEN-HOLE PICKS, ARAB-D RESERVOIR, GHAWAR FIELD

49 E 49 30' 49 E 49 30' 26 N 26 26 N 26

5,700 'Ain Dar 5,700 'Ain Dar

5,800 5,800 Shedgum Shedgum 5,900 5,900

6,000 6,000

6,100 6,100

6,200 6,200

6,300 6,300

6,400 6,400 Original Oil/Water Contact (ft subsea) Original Oil/Water Contact (ft subsea) Original Oil/Water 6,500 6,500

6,600 6,600

Control Control Uthmaniyah point point Uthmaniyah

25 25 25 25

Hawiyah Hawiyah

North North

Haradh Haradh

Central Central

South South N N 030 030

24 km 24 24 km 24

49 49 30' 49 49 30'

Figure 16: The Arab-D Oil/Water Contact depth Figure 17: Depth map of the bottom of the map as determined from open-hole logs. In western good-quality reservoir section in Arab-D (cut- Haradh the oil/water contact is about 800 ft higher off 4% porosity). Note the similarity with the than in the northern and eastern part of Ghawar. oil/water contact depth map of Figure 16. 21

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in early studies as, “the lowest level above which clean oil would be produced from a well during a drill stem or production test”. From a comparison of Drill Stem Test (DST) data with induction/ electric well log analyses, Aramco found that this “producing OOWC coincides, in good quality Arab-D rock, with an interpreted open-hole log water saturation of 35%”; that is, close to the top of the transition zone. DSTs in the good reservoir sections produced only clean oil whereas those in the tighter sections produced salty crude. It was also noted that intervals tested as producing salty crude during DSTs produced clean oil for several years after completion. The salt content measured during the DSTs had been interpreted as interstitial formation water––not aquifer water––being mobile due to the larger drawdown imposed on the Arab Formation. In those days, the salt content of the crude oil was a major cause of disruption to the catalytic process used in the refineries.

Reviewing OOWC Picks in Ghawar

Due to operational constraints, a precise delineation of the OOWC was not always a primary consideration as, in general, the interface was expected to be horizontal––and to recognize it once was enough, providing that the reservoir was not compartmentalized. In Ghawar, several factors have affected the delineation of the tilted OOWC in the Arab-D reservoir. For example, the OOWC is only present at the edge of the oil accumulation. This, combined with the steep flanks (for instance in the west in Central Haradh) (Figure 3), has made it difficult to drill delineation wells that intersect the OOWC in areas where it is unaffected by large capillary pressure effects, such as in Zone 2.

In the early days of the field appraisal, the increase in water saturation in Zone 3 was considered to be due to the proximity of the water leg, regardless of the quality of the reservoir rock, and this led to wrong picks for the OOWC. For instance, in the absence of any other information, the OOWC might be picked at a depth of 6,470 ft in well ANDR-A (west flank) and at 6,580 ft in well SDGM-B (east flank), which would result in a 110 ft west-to-east tilted OOWC (Figure 18). A careful review of the open-hole logs in ‘Ain Dar and Shedgum (North Ghawar) showed that a west-east tilt of the OOWC was almost impossible to determine. Another difficulty that arises when trying to assess the OOWC tilt comes from picking an Oil-Down-To (ODT) in wells already affected by water encroachment caused by updip production. SDGM-C was one of the key wells to demonstrate the existence of a west-east component of the tilt in North Ghawar. However, the well was drilled in May 1969, or 11 years after production started, and was completed in an area of extensive updip production. Looking now at the open-hole logs, some lagging oil can be spotted below the picked ODT. Therefore, if the OOWC is taken to be below the deepest lagging oil zone, the west-east tilted fluid contact cannot be substantiated.

Revising OOWC Picks in Ghawar

DST and production data, core descriptions, and open-hole logs were integrated to reduce the uncertainty attached to each type of data. In this study, it was proposed to look for the FWL depth in the early Ghawar flank wells. Where the identification of the FWL was obscured by the presence of low-permeability rocks, the ODT and Water-Up-To (WUT) depths were picked. The OOWC review started with the examination of the open-hole logs from all possible flank wells irrespective of their drilling dates. This gave 102 wells on the west flank and 93 wells on the east flank (Figures 19a,b). As expected, some scattering was apparent when plotting the ODT and WUT picks against the depth of the good reservoir section (4% porosity cutoff). Although several ODT and WUT picks were superimposed, or close to the base of the good reservoir section, they showed with a reasonable confidence that the OOWC shallows from a depth of 6,650 ft in the north (‘Ain Dar) to 6,400 ft in the south (Haradh). In Central Haradh, the west flank OOWC was shallowest at 5,800 ft whereas, at the same latitude, the east flank OOWC was located between 6,532 ft and 6,631 ft. This gave a OOWC downward tilt from west to east of between 700 and 800 ft.

In order to ascertain further the trends identified above, a subset of flank wells was chosen with the proviso that the well had been drilled before any significant cumulative production had occurred in the area. The subset consisted of 19 wells on the west flank and 15 wells on the east. In addition to open-hole logs, 12 of the wells had DST’s, two had Repeat Formation Tester logs, and 18 were cored. The subset confirmed the OOWC trends noted earlier with the shallowest OWC in well HRDH-A (Figure 20a) and the deepest in well ANDR-D (Figure 20b).

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OIL/WATER CONTACT PICKS, NORTH GHAWAR (a) 'Ain Dar-A (b) Shedgum-B 6,100 6,100 (c) Shedgum-C 6,400 010 'Ain Dar-A km 6,200 6,200 6,450

Shedgum-B

6,300 6,300 6,500 OWC May 1969

6,400 6,400 Shedgum-C 6,550 Depth (ft ss)

6,600 Lagging oil/ 6,500 6,500 OOWC

OWC 6,650 6,600 6,600 Porosity Pay Zone Water Saturation Bottom 6,700 6,700 6,700 0 0.2 0.4 0.6 0.8 1 0 0.2 0.4 0.6 0.8 1 0 0.2 0.4 0.6 0.8 1 (Fraction) Water Saturation Water Saturation Figure 18: Examples of how the Oil/Water Contact (OWC) was picked in the past: (a) and (b): At 35% water saturation (gray vertical line) the oil water contact was picked at the horizontal red line, and the bottom of the pay zone at the horizontal green line; (c): The OWC as determined from open-hole logs in May 1969 (horizontal blue line) above the interpreted Original Oil/Water Contact (OOWC: orange line).

This extensive revision confirmed earlier studies dating back to Aramco’s early field appraisal (Aramco, 1959). The elimination of uncertain evidence allowed the tilt geometry to be clarified. The tilt of the Ghawar Arab-D OOWC has the following major components:

• a field-wide SSW-NNE low-gradient tilt with a 200 ft deepening of the OOWC from south to north Ghawar, a distance of 230 km; and • a localized W-E high-gradient tilt with up to 800 ft deepening of the OOWC from west to east Central Haradh, a distance of 25 km.

INTERPRETATIONS

In the past 20 years, several concepts have been proposed to explain tilted OOWC worldwide. We reviewed several of these that may explain the tilted OOWC in the Ghawar Arab-D reservoir. In order of decreasing importance for our discussion they are as follows:

• fluid properties and static equilibrium; • dynamic aquifer; • tectonic tilting and frozen-in diagenetic traps; and • Earth’s gravity and inertial forces.

Fluid Properties and Static Equilibrium

Following the geothermal gradient, the reservoir oil and water densities steadily change across the Ghawar field. As the reservoir temperature decreases from north to south, the oil density increases by 6 percent and the water density decreases by 10 percent. The proposed explanation is that at

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South OIL/WATER CONTACT, WEST FLANK WELLS North

5,800 a x

x 6,000 x Free Waterx Level

6,200 x x xx x x x x x 6,400 x x x x x x x x x x x x x x xx x x x x x x xxxx x Depth (ft subsea) x x xx x x x x xx x xx x 6,600 x x x x x xx x x x x x x x x 6,800 x x x HARADH HAWIYAH UTHMANIYAH 'AIN DAR 7,000 24°N 25° 26° Figure 19: N-S profiles of the Oil/Water Contact (OWC) in the Arab-D of Ghawar. (a) West flank (102 wells); note that the shallowest OWC is in Central Haradh.

5,700 a HRDH-B

5,800 HRDH-A HRDH-D 5,900

(Flows oil) HRDH-E

6,000

Original Oil 6,100 HWYH-D Water Contact

HRDH-K HWYH-C 6,200 ANDR-C HWYH-A/B Depth (ft subsea)

6,300 UTMN-C UTMN-D HRDH-J ANDR-A HRDH-I HRDH-L 6,400

Free Water Level 6,500 ANDR-B UTMN-A

6,600 UTMN-B

6,700

HARADH HAWIYAH UTHMANIYAH 'AIN DAR 6,800 24°N25° 26° Figure 20: Oil/Water Contact in the Arab-D of the west flank of Ghawar utilizing Drill Stem Tests, Repeat Formation Tester (RFT), cores, and open-hole logs. (a) West flank; this subset of 19 wells reproduces the trend of the 102 wells in Figure 19a.

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South OIL/WATER CONTACT, EAST FLANK WELLS North

5,800 b

Water-Up-To (WUT) 6,000 Oil-Down-To (ODT) x Bottom Pay Zone 6,200

Free Water Level (calculated) x 6,400 x x xx x x x x x x x Depth (ft subsea) x x xx x 6,600 x xxx x x x x x x x x x x x x x xx x x x x x x xx xx x x x xx x xx x x x x x x x x 6,800 x x x x x x HARADH HAWIYAH UTHMANIYAH SHEDGUM 7,000 24°N 25° 26° (b) East flank of Ghawar (93 wells).

5,700 b

DST (Oil show) Residual Oil Open oil 5,800 Core (Oil show) Hole Tight Logs RFT Water section

5,900

6,000

6,100

6,200

Depth (ft subsea) HRDH-M 6,300 (Upper Zone) UTMN-E

UTMN-B 6,400 Free Water Level HRDH-F UTMN-D UTMN-A

6,500 (Flowed HRDH-N Clean Oil ANDR-F 1998) SDGM-D ANDR-E SDGM-A (Flowed Oil 1974) Dolomite ANDR-D Original Oil Water Contact 6,600 UTMN-C

6,700 SDGM-B

HARADH HAWIYAH UTHMANIYAH SDGM-C SHEDGUM/ 'AIN DAR 6,800 24°N25° 26° (b) East flank; this subset of 15 wells reproduces the trend of the 93 wells in Figure 19b.

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higher temperatures, water salinity (and thus ORIGINAL OIL/WATER CONTACT water density) is higher. Conversely, reservoir 6,360 oil density is lower at higher temperature due to thermodynamic segregation. The existence + of opposite trends in water and oil densities

implies that the weight of the oil and water 6,380 column changes throughout the field. In the + case of a horizontal OOWC with constant fluid + density, the isobaric surfaces related to the Oil gradient pressure exerted by the oil column are + 0.323 psi/ft horizontal. Given the variable oil and water 6,400 densities as measured in Ghawar, these surfaces +

are tilted. Stenger (1999) suggested the ) + following: OOWC subsea 6,420 + • At some distance from the Ghawar field, isobaric surfaces must return to the + Depth (ft horizontal in the Arab-D Formation by mirroring the vertical segregation of water + salinity at the basin scale. Chiarelli (1973) 6,440 provided evidence for this by describing the Water gradient Jurassic aquifer of Saudi Arabia as being a 0.457 psi/ft rejecting and passive system in contrast to + the recharging and dynamic aquifers of 6,460 + Cretaceous and Eocene age. Therefore, and + as shown by the available data (Figure 9), aquifer water density (salinity) should be + mainly a function of reservoir depth and temperature in the Arab-D reservoir. 6,480 3,240 3,250 3,260 3,270 3,280 3,290 • Aquifer waters of different salinities or (psig) temperatures do not easily mix in a porous Figure 21: Original Oil/Water Contact (OOWC) medium. This leads to the possibility of determination using Repeat Formation Tester at fresh water introduced from shallower HRDH-J. This is the southernmost Ghawar well aquifers as ‘floating’ on top of the more to intersect the oil/water contact in a ‘clean’ saline water. reservoir section and in an area with no production prior to logging date of December 1981. Dickey (1963) formulated similar ideas when discussing the general topic of underground waters and oil exploration. He later repeated the idea that a tilted OOWC does not necessarily imply hydrodynamics, especially in basins where the aquifer salinity shows high contents of chlorides, calcium, and total dissolved solids that indicated stagnant aquifers (Dickey, 1968, 1988). Bond (1973) defined a variable density aquifer as one in which the density of the interstitial water varies from point to point. He concluded that observed (hydraulic) gradients of a few feet per mile in the saline part of the aquifer probably had little or no significance with respect to flow. Aramco (1959) indicated that, “there may be a possibility of large-scale vertical salinity stratification” in the Arab-D aquifer.

It is possible to calculate the equilibrium of the oil and water columns across the structure based on the above assumptions (Stenger, 1999). At the northern end of Ghawar (salinity 225,000 ppm TDS), the OOWC is 6,650 ft deep, whereas the calculated OOWC (from an average salinity of 65,000 ppm TDS) is 6,368 ft at the southern end of the Haradh sector. This is within the OOWC approximation of 6,420 ft, as observed in the southernmost Haradh delineation well (HRDH-J) by RFT (Figure 21). It is important to note that if a salinity of 35,000 ppm TDS is used for Haradh, as observed on the west flank of Central Haradh, the shallowest OOWC would be at a depth of 5,835 ft. This is within the observed estimates of from 5,863 ft (HRDH-A) to 5,820 ft (HRDH-B) for the west flank of Central

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Haradh. Calculated and observed OOWC tilts show similar trends (Figure 22), although on a well- by-well basis some discrepancies are irreconcilable due to local and minor irregularities not accounted for in this interpretation. The map of the calculated OOWC (FWL) is from a simple extrapolation of the equilibrium calculation performed on the N-S cross-section. A similar exercise in the west-to-east direction would require more data on the oil and aquifer water densities than is presently available. It is important to note that any discernable change in water salinity between the aquifer legs will lead to a tilted interface. Appendix A gives an example of an analytical calculation for a theoretical structure.

Dynamic Aquifer

Hydrodynamics affect water-bearing reservoirs outcropping on structural highs where rainfall controls the recharging process. When sufficient reservoir permeability combines with a discharge area (springs), fluid flow can be sustained from the structurally high recharge area to the structurally low discharge area. Water flowing in such aquifers usually has low salinity and is young. According to Dickey and Soto (1974), in hydrodynamic aquifers “meteoric waters may be defined as waters that have been part of the hydrologic cycle recently, geologically speaking”. In recognized hydrodynamic aquifers, the existence of fluid pressure isopleths is consistent with the direction of aquifer flow and the tilt of the contact. Hydrocarbon pools with bottom dynamic aquifers usually have a high degree of natural pressure support throughout their production history, as discussed for instance by Winterhalder and Hann (1991).

In the case of the Arab-D reservoir of Ghawar, V.V. Valleroy (unpublished Exxon Production Research Letter ER-82-25, 1982) proposed that hydrodynamics caused the tilted OOWC (Figure 23) and that hydraulic pressure gradients from 1.8 to 10 psi/km were necessary to explain the observed tilts. A regional Arab-D reservoir simulation model reproduced the tilted OOWC by an aquifer flow of 5,000 barrels of water per day over a period of 20,000 years. The results showed that the average pressure gradient was about 8 psi/km between ‘Ain Dar (North Ghawar) and Haradh (South Ghawar). However, this translated into an original pressure difference of 1,300 psi before production started (Figure 24a) whereas pre-production pressures measured in exploratory wells in ‘Ain Dar and Haradh did not show any pressure gradient that substantiated a dynamic aquifer flow from south to north. Another simulation run attempted to reduce the pressure gradient by lowering the injection rate (100 barrels of water per day over a period of 135,000 years). Although the pressure difference between ‘Ain Dar and Haradh was reduced to 200 psi, the magnitude of the tilted contact could not be reproduced (Figure 24b). In Central Haradh, a minimum pressure difference of 90 psi would be necessary to maintain the observed W-E tilted OWC. Again, the initial reservoir pressures measured in Haradh did not show such a difference.

Clearly, slow fluid movement occurs naturally in a reservoir over geological time. However, it is of a very different magnitude to the situation in a dynamic aquifer where significant flow and pressure gradients are obvious on a production time scale. In retrospect, the lack of aquifer support in the Arab-D reservoir should have been another indication that hydrodynamics was not a robust explanation for the tilted OOWC in Ghawar. In addition, the issue of the discharge area located northeast of Ghawar on Figure 23 and apparently draining into the central low of the sedimentary basin, was not solved.

Tectonic Tilting and ‘Frozen-in’ Diagenetic Traps

Tilting or folding of subsurface structures has been proposed to explain the tilted OOWC in the oil fields of southern California (Yeats, 1983). Low matrix permeability normally requires extensive periods of time to recreate the gravitational fluid segregation, but the tectonic activity in California increases the likelihood of such occurrences. Carlos and Mantilla (2000) claimed to have evidence of a tilted OOWC caused by tectonics but their case was weakened by a lack of pre-production pressure data, a strong bottom aquifer drive, and reservoir permeability of about 300 mD.

The Ghawar area shows little evidence of sub-recent tectonic activity. In Haradh, Aramco (1959) stated that, ”the only suggestions of disturbance, and these are virtually unsupported, are found in

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TILTED OIL/WATER CONTACT Calculated Model

49 E 49 30' 49 E 49 30' 26 N 26 26 N 26

5,700 Shedgum Shedgum 5,800

5,900 'Ain Dar 'Ain Dar 6,000

6,100

6,200

6,300

6,400 Original Oil/Water Contact (ft subsea) Original Oil/Water 6,500

Uthmaniyah Uthmaniyah 6,600

6,700

25 25 25 25

Figure 22: Modeled Oil/ Figure 23: Hydrodynamic Hawiyah Water Contact (OWC) in Hawiyah model used to explain the Arab-D using variable tilted Original Oil/Water fluid densities. The Contact (OOWC) in the W-E tilt of the OWC in Arab-D reservoir in Central Haradh was Ghawar. Aquifer flow modeled by varying the originates from Central water salinity from Haradh’s west flank and North 65,000 to 35,000 ppm North proceeds along both sides total dissolved solids of the structure. Note the from north to south, aquifer flow intersecting Haradh respectively. Haradh the field in the ‘Ain Dar and Shedgum sectors. Central Central

South South N N 030 030

24 km 24 24 km 24

(after V.V. Valleroy: unpublished Exxon Production Research Letter ER-82-25, 1982)

49 49 30' 49 49 30'

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SIMULATED PRESSURE DIFFERENCES

(a) 20,000 years (b) 135,000 years Figure 24: Simulated pressure 49 E 50 49 50 differences: (a) After 20,000 years of dynamic aquifer flow in a regional Arab-D reservoir simulation model. Aquifer flow was simulated by an 26 N 26 injection rate of 5,000 barrels of water per day in the southwestern corner of this model. It resulted in an average pressure gradient of about 8 psi/km between ‘Ain Dar (North Ghawar) and Haradh (South Ghawar).

-1,500 -600 (b) After 135,000 years of dynamic aquifer flow 25 25 (100 barrels of water per day). A source point in the lower left corner of the model was used to simulate the aquifer flow along Ghawar flanks. No 0 0 significant oil/water contact tilt resulted, even Pressure (psi) Pressure (psi) though the N-S pressure 24 24 difference of the model exceeded the initial 030N 030N reservoir pressure

km km observed in Ghawar prior 49 50 49 50 1,500 1,200 to the start of production.

ORIGINAL OIL/WATER CONTACT DISTRIBUTION 5,700 49° E 5,800 B OOWC equilibrium with 35,000 ppm C A 5,900 A H E B 6,000 D D 6,100 Transition curve y = 6369 + 0.004272 (x - 50)3 6,200 G F C G Depth (ft subsea) 6,300 I OOWC equilibrium with 65,000 ppm J I 6,400 F N 010 24°N 6,500 WUT ODT H km 6,600 49°E J 0 5 10 15 20 25 30 35 40 45 50 Distance to highest OOWC (km) Figure 25: Distribution of Original Oil/Water Contact (OOWC), Arab-D reservoir, Central Haradh. Note that all wells on Haradh west flank are within a cubic function of the distance to the shallower OOWC. Wells F and H are located on the east flank of Haradh and do not fall between the two salinity curves.

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the Wadi Sahba area (see Figures 27 and 30) where drainage, originally toward the north and northeast may have been diverted toward the east and perhaps southeast. The timing of this tilting should be early Pleistocene and perhaps even late Pliocene. Regional slopes are so gentle, however, that effects on the oil field must have been very slight.”

For the following reasons we agree with Aramco (1959) that tectonic tilting cannot explain the observed west-to-east tilt of the OOWC in the Haradh area.

• The shallower OOWC observed on the west flank of the Haradh sector is extremely localized and the contact steepens rapidly in all directions (Figure 25). • The relatively high reservoir permeability in the Arab-D of Haradh (300 mD), cannot equate with a long re-equilibration period––with structural tilting dated as Pleistocene, equilibrium should have been achieved within a few thousand years and the OOWC should now be horizontal. • T.R. Pham and A.S. Al-Muhaish (unpublished Saudi Aramco ‘Udhailiyah Reservoir Management Division Internal Memo, 1998) interpreted residual oil as being present in dolomitic stringers below the current OOWC on central Haradh’s western flank. This would mean that oil was previously present at a deeper level than is observed today on the west flank and would contradict the possibility of clockwise tectonic tilting to explain the observed tilted OOWC in Haradh. • The possibility that the OOWC was ‘frozen-in’ following the diagenetic destruction of porosity in the aquifer does not seem likely for Ghawar.

So far, no drastic porosity or permeability reductions have been recorded in the Arab-D aquifer, and the reservoir pressure has been maintained efficiently through a peripheral water injection scheme since the late 1960s. Furthermore, the Abqaiq and Harmaliyah fields located north and east of Ghawar (Figure 1) are in hydraulic communication through the Arab-D aquifer leg.

Earth’s Gravity and Inertial Forces

The acceleration due to gravity (g) is not uniform over the Earth’s surface (Figure 26) and is used in the traditional equation for determining hydrostatic head. The main axis of the Ghawar anticline is perpendicular to the isogals and has a minimum acceleration of 32.113 ft/s-2 (9.788 m/s-2) at Haradh in the south and a maximum close to 32.119 ft/s-2 (9.790 m/s-2) at ‘Ain Dar in the north. The acceleration due to gravity decreases by 0.16 percent from ‘Ain Dar to Haradh, a negligible amount compared to the changes in fluid density discussed above. As such, Earth’s gravity can be dismissed as a cause for the tilted OOWC in Ghawar.

It has been suggested that the rotation of the Earth affects large objects such as the Arab-D reservoir in Ghawar and may have caused the observed west-to-east OOWC tilt. However, the Earth has a counter-clockwise rotation by reference to the North Pole and, if effective, the inertial forces should cause a deeper OOWC on the west flank of the Ghawar field. On the contrary, field observations show that the contact is deeper on the eastern flank.

DISCUSSION

Assuming that Arab-D aquifer waters are vertically segregated according to salinity, we have shown numerically (see example in Appendix A) that a static equilibrium may account for the observed tilted OOWC along the main axis of the Ghawar field from south to north. This fits with the known pressure behavior of the field. However, the large west-to-east tilt in Central Haradh is more difficult to explain by the same calculations, as the depth to the equilibrium surface in the aquifer would be much greater. The shallow OOWC noted on Central Haradh’s west flank is localized and appears to be a physical singularity (Stenger, 1999). Fresh, recent aquifer waters have been sampled in this area and temperature variations seem to correlate with production-related pressure variations. In addition, the Wadi Nisah-Sahba fault zone (Figure 27) is near to all of these subsurface observation points. Although a strong correlation is no proof of cause, the authors believe that it is worth presenting the following interpretation that links all the available information.

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REGIONAL GRAVITY MAP

45°E5550° °

N 0 200

km (m/s-2)

30°N 30° 9.800 9.799 9.798 9.797 9.796 9.795 9.794 9.793 9.792 9.791 9.790 9.789 9.788 ° ° 25 25 9.787 9.786 9.875 9.784 9.783 9.782 9.781 9.780 9.779 9.778 45° 50° 55° 9.777 9.776 Figure 26: Gravity map of the Gulf region (data courtesy of International Gravimetric Bureau, http://bgi.cnes.fr). The N-S gravity decrease of 0.16 percent from ‘Ain Dar to Haradh can be dismissed as a cause for the tilted original oil water contact in Ghawar.

• Wadi Sabha is clearly visible on satellite images (Figure 27). It is the easternmost extension of the larger Central Arabian Graben System, “an arcuate 560-km intraplate fault zone” (Al-Kadhi and Hancock, 1980) initially described by Powers et al. (1966). Most authors related the formation of the graben system to an extensional stress field (Vaslet et al., 1991). Weijermars (1998) however suggests that the Wadi Nisah-Sabha zone is the result of compressional forces creating a strike- slip fault system with about 8 km left-lateral displacement. According to Weijermars (1998) a substantial part of the movement on the Wadi Nisah-Sahba fault zone took place in the Pliocene- Quaternary. This was after the Arab-D trap had formed and presumably filled with hydrocarbons. A post-migration movement on the fault zone could explain how some oil remained trapped in oil- wet dolomitic stringers on the Haradh sector’s western flank well below the present OOWC. • As discussed above, the possibility of fluid flow along the flanks of the Ghawar field is inconsistent with the field’s initial pressure data, the lack of aquifer support during production, and the conclusions reached by Dickey (1963) and Chiarelli (1973) concerning stagnant aquifers. • The Pleistocene-aged aquifer water sampled from Central Haradh’s western flank was recently claimed (T.H. Keith, 1999, and S.W. Amos, 2002, personal communications) as proof of hydrodynamics with a recharge effect from the Arab-D outcrop near Riyadh, about 200 km to the west. We disagree with this interpretation for the following reasons: 1. Chiarelli (1973) described the Arab-D aquifer in Saudi Arabia as rejecting system. With the exception of the western flank of Central Haradh, both the high chloride-calcium content and the isotopic signature of the Arab-D formation water around Ghawar indicate a stagnant aquifer. 2. Pre-production static pressures do not show a pressure gradient across the Haradh area that would substantiate even localized hydrodynamics.

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TERRAIN ELEVATION ACROSS THE ARABIAN PENINSULA WITH OUTLINE OF THE GHAWAR FIELD

27°

26°

25°

24°

42° 43° 44° 45° 46° 47° 48° 49° 50°

27°

Az-Zilfi lineament

26°

Ghawar field C en tra l A rab ian 25° Gr aben Syste Figure 30 m Riyadh

24° N 0 120 Wadi Sabha

Figure 27: Terrain elevation image across central Saudi Arabia with outline of the Ghawar field. The Central Arabian Graben System and its eastward extension into Wadi Nisah-Sahba appears to abut against the west flank of Central Haradh. (Image courtesy of National Imagery and Mapping Agency, USA; http://geoengine.nima.mil).

3. Should hydrodynamics be active on Central Haradh’s western flank, the reservoir temperature would not drop when the pressure fell during the primary depletion phase. 4. There is no obvious water outlet that would allow a hypothetical aquifer flow in the Arab-D. 5. The Arab-D reservoir is a low-compressibility system and any significant rate of water movement would result in a large pressure gradient, as reproduced by the reservoir simulation model presented earlier (Figures 24a,b).

• The large W-E tilt seen on Central Haradh’s western flank is more likely to have been caused by limited vertical dumping from a shallower aquifer through fractures linked to the Wadi Sahba fault zone. This would explain the arrival of fresher, cooler water observed during the primary depletion of the reservoir. In this regard, it was noted that after the Haradh primary depletion and subsequent field shut-in in the early 1980s, only the pressure behavior of the west flank observation well HRDH-A could not be history-matched satisfactorily with the full-field reservoir simulation model (T.R. Pham, personal communication, 1999). Measured static pressures in HRDH-A showed

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PRESSURE DIFFERENCE BETWEEN ARAB-D AND BIYADH AQUIFERS

3,200

3,100

3,000 110 psi Flat 2,900 pressure

2,800 Rapid pressure 2,700 recovery until 1988 Biyadh Static pressure at -6,100 ft (psi) 2,600 Measured

Simulated (full-field model) 2,500 Field back In Field shut South Ghawar production mothballed (October 1990) 2,400 1960 1966 1972 1978 1983 1984 1990 1996 2002 Figure 28: In 1989, a 110-psi pressure difference existed between the Arab-D and shallower Biyadh aquifer. The low Arab-D pressure in observation well HRDH-A is due to the primary depletion of the Haradh area until the field was shut-in in the early 1980s. Note the inability of the full-field model to reproduce both the sharp increase and sudden flattening of the measured pressure.

a period of rapid pressure recovery until November 1988 when the pressure suddenly flattened out until the field was reopened in October 1990 (Figure 28). The well’s unique pressure behavior is interpreted as resulting from a degree of additional pressure support limited in time and space. • Within a given reservoir, pressure-dependent communication across fault planes may start to leak fluids when a sufficient pressure difference––the pressure threshold––is applied to both sides of the fault (Zubari and Al-Awainati, 1997). In the case of Central Haradh’s western flank, the threshold pressure concept may be applied to a fault zone vertically linking the hydrostatic Jurassic Arab-D reservoir and a charged shallower aquifer such as the Cretaceous Biyadh (Figure 29). The value of the threshold pressure should be about 110 psi according to static pressures recorded when both the Biyadh aquifer and Arab-D reservoir were not under any production influence during the late 1980s (Figure 28). The Biyadh is the nearest shallower aquifer (Figure 29) having water salinity values almost identical to the salinity on the west flank of Central Haradh, and being affected by hydrodynamics. Natural dumping into the hydrostatic Arab-D reservoir from the shallower Biyadh would require a high potential to overcome the threshold and the Arab-D hydrostatic head. • No water samples from the Biyadh aquifer that could confirm the match with the Arab-D water on the western flank of Central Haradh are available for isotopic analysis. This is because the Biyadh sandstones are unconsolidated and prone to instability. Hence there is an understandable reluctance to sample this particular reservoir while drilling. Although no pre-production pressure measurements were available for the Biyadh aquifer, the initial pressure of the immediately overlying Wasia aquifer (Figure 29) had been recorded near Central Haradh in 1953 before any local water production occurred. After converting the measured Wasia pressure of 1,115 psi at a depth of 1,166 ft to the Arab-D pressure datum (water gradient of 0.443 psi/ft), the Wasia initial pressure was 3,299 psi at 6,100 ft, compared with the original 3,216 psi of the Arab-D reservoir. Therefore, the Wasia aquifer was over-pressured by 83 psi compared to the Arab-D reservoir, a value that was consistent with the concept of a threshold pressure estimated at about 110 psi from later Biyadh pressure observations. • The concept of the vertical dumping of water from a shallower aquifer into a deeper reservoir is not new. Khalaf (1989) proposed this for the Awali Arab-D field of Bahrain with the Cretaceous Shu’aiba aquifer dumping water into the Jurassic Arab-D reservoir. He described concomitant production problems such as plugging as a result of the deposition of asphaltenes due to reservoir

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cooling. In North Africa, Edmunds (1980) studied LITHOSTRATIGRAPHIC COLUMN the geochemistry of the Miocene aquifer system in the Sirte Basin of onshore Libya. He identified Ter- tiary “a striking feature * * * a well-defined channel of 1,406 m fresh water, which can be traced in three Lina Member dimensions across the main aquifer for some 130 Hajajah Aruma Member km * * * and represents recharge from a former Formation wadi * * * this groundwater, with an age of Late Khanasir mbr Disconformity Cretaceous 1,230 7,800 +/- B.P., is chemically, isotopically and Wasia Fm * chronologically distinct from the older Pleistocene Major disconformity 1,188 Huraysan ground waters of the aquifer.” Edmunds’ Member * description is similar to our current understanding Sallah Member of the impact at the Arab-D level of the Wadi Sahba

fault, and his work shows that waters of different Biyadh salinities do not mix easily in a porous medium. Sandstone Dughum • The possibility of a vertical communication Member * between the Ghawar Arab-D reservoir and a shallower aquifer remains controversial as the Late

Thamama Group 788 Jurassic Hith Formation is believed to provide a Early Cretaceous Buwaib very good seal to the Arab reservoirs (M.S. Ameen, Formation 743 2001, personal communication). However, as Yamama Formation 686 discussed above, the Wadi Sabha trough is the Sulaiy eastward extension of the 95-km-long Nisah Formation graben that is part of the Central Arabian Graben Disconformity 576 (Hith System (Figures 27 and 30). As such, the normal Arab-C Member ubc Anhydrite carbonate facies faults that bound the Sabha trough might have and Arab Arab-D Member Formation) lbc * provided sufficient vertical offset to allow for carbonate facies 456 partial vertical communication between the Jubaila Arab-D and the Biyadh aquifers. Limestone 340 • The Mazalij and Ghazal Arab-D oil fields are Late Jurassic Ulayyah Member located 80 km west from Haradh (Figure 1) on the Hanifa Formation Hawtah northern and southern sides respectively, of the Member 212 Wadi Sahba fault system. Recent 2-D seismic Group Shaqra interpretation showed that normal faults have Tuwaiq down-thrown the Arab-D reservoir by 400 ft south Mountain Limestone of Wadi Sahba (R. Geier and N. Al-Afaleg, personal Middle communications, 2002; 2-D seismic interpretation Jurassic 28 Dhruma Upper Dhruma 0 by S. Dasgupta, 2001). The oil/water contact is Formation (Hisyan Member) also 400 ft deeper in the Ghazal Arab-D field in ubc = upper breccia complex Known karst features the southern fault compartment compared to the lbc = lower breccia complex Aquifer Mazalij Arab-D field in the north. This observation adds credence to the assumption that the tilted oil/ Figure 29: Lithostratigraphic column based water contact in Haradh is linked to a post- on outcrop mapping in central Saudi Arabia migration tectonic event along the Wadi Sahba (Vaslet et al., 1991). Due to the solution of trough. Further, open-hole logs in Mazalij wells evaporites, the Arab Formation in outcrop show that all Arab reservoirs A, B, C and D are is about 100 m thinner than in subsurface as charged with oil in the wells closest to Wadi Sahba, measured about 90 km east of Riyadh in the whereas the northernmost wells are oil-bearing in Abu Jifan field (see Figure 30). the Arab-D reservoir only. This indicates that the Arab-D might have ‘leaked’ oil into shallower reservoirs in the vicinity of the Wadi Sahba fault. The observations made in the Mazalij and Ghazal Arab-D reservoirs show that surface observations related to the Wadi Sahba trough extend to the subsurface and have a significant impact on the Arab-D reservoir.

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SOLUTION AND COLLAPSE ALONG CENTRAL ARABIAN GRABEN IN OUTCROP 25°N

Abu Jifan Biyadh oil field Sandstone Wasia and Aruma Riyadh formations Arab Fm Umm er Radhuma Formation

Dahl Hith Jubaila, Hanifa Sulaiy, and Tuwaiq Yamama Mountain and Buwaib Limestone formations formations

C entra l Arab Wad ian Gra i Sa ben System bha

Wadi Nisah

N 020 Large-scale km Sink hole solution collapse 24° 46°30'E 47° 47°30' 48° Figure 30: Significant and widespread karst features are associated with solution along the outcrop belt of Upper Jurassic formations and the Central Arabian Graben system. It is proposed that karst features extend east into the sub-surface below Wadi Nisah-Sabha and create conduits that extend vertically for several hundred meters. In places this could bring, for example, the Biyadh and Arab aquifers into communication, so bypassing the Hith seal. Redrawn after Vaslet et al. (1991).

• In the nearby Awali oil field of Bahrain, Samahiji and Chaube (1987) described how tectonic breaching of the Hith Formation had allowed partial oil migration from the Jurassic Arab Formation to Cretaceous reservoirs. The conditions on the west flank of Central Haradh may be an intermediate situation in which the possibly leaking E-trending Wadi Sahba fault zone is intersected by the NW-trending Abu Jifan regional fault (Al-Husseini, 2000). This would explain why vertical communication could exist west from Haradh while the Arab-D trap was still fully charged with oil in Ghawar. • It is the authors’ view that the concept of a vertical pressure threshold across the Wadi Sahba fault zone is reconciled with the observations. Specifically, it would explain how limited water dumping in the past may have created the west-to-east tilted OOWC in Central Haradh with a source point close to well HRDH-A. More likely, however, is vertical aquifer communication through the widespread and extensive karstic dissolution and collapse features (e.g. caves and sinkholes) known in Wadi Sabha and the eastward extension of the Central Arabian Graben (Figure 30). Collapse structures associated with the dissolution of Arab Formation evaporites were mapped by Vaslet et al. (1991) over an area of several thousand square kilometers (Figure 30). Two large karst features that have created 150-m-deep vertical fluid conduits through the Arab evaporite section, are present at the Hith Anhydrite reference section in a cave-like sinkhole at Dahl Hith and in another 3.5 km to the southeast (Vaslet et al., 1991). Other large sinkholes have been mapped and described, for example at ‘Ayn as-Dihl, Samah, and Umm Khisah near Al ‘Uyun, southwest of Al Kharj. The potential vertical extent of such karst features might be indicated by the collapse features mapped in the Dughum Member of the Biyadh Sandstone about 50 km east of Riyadh. Assuming these

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3-D SEISMIC AMPLITUDE MAP, AHMADI FORMATION

26°N N 0 10

Figure 31a: 3-D seismic amplitude map of the Ahmadi Formation in northern Ghawar (‘Ain Dar and Shedgum). Fairly regularly distributed NW- trending structural lineaments occur on the west flank of the structure. They probably represent fracture zones or minor faults. White line shows outline of field. 49°15'E 49°30'

3-D COHERENCY ANALYSIS MAP, AHMADI FORMATION

26°N 0 N 10

Figure 31b: 3-D seismic coherency analysis map of the Ahmadi Formation in northern Ghawar (‘Ain Dar and Shedgum). The circular features aligned along the structural lineaments are interpreted as sinkholes. It is probable that movement of fluids along fractures and faults caused dissolution and subsequent collapse. 49°15'E 49°30'

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sinkholes, several square kilometer in size, are associated with the localized solution of the Arab evaporites in the subsurface, a vertical conduit of more than 600 m has been created. • In the Ghawar subsurface, coherency analysis performed on 3-D seismic data, circular dissolution cavities that might be sinkholes were interpreted at several geological horizons. For instance, the shallower Cretaceous Ahmadi level shows sink holes apparently aligned on structural lineaments (Figures 31a,b). Therefore, karstic dissolution and collapse features could have a role in establishing a partial and vertical communication between the Arab-D and Biyadh aquifers.

CONCLUSIONS

The simplest mechanism that could account for the creation of the west-to-east tilted OOWC in Haradh is as follows: • Tectonic activity along the Wadi Sahba fault zone allowed local and partial communication between the Biyadh and Arab-D aquifers on the western flank of Haradh. • Due to its hydrodynamic regime, the higher-than-hydrostatic head of the Biyadh aquifer forced Biyadh water into the Arab-D on Haradh’s western flank and pushed the oil column up. • Intrusion of water stopped after pressures came to equilibrium (less the threshold pressure effect), thus accounting for the static equilibrium and lack of pressure gradient observed today. • Only when the Arab-D pressure dropped below the threshold pressure (as during the primary depletion phase in Haradh) did the dumping begin again.

In summary, regional evidence shows that the Hith anhydrite seal might be partially leaking to allow a remigration of oil from the Arab-D to shallower reservoirs, as in the Awali (Bahrain) and Mazalij oil fields. The geological and tectonic conditions under which the Hith anhydrite seal may have leaked are being reviewed at the basin scale and will form the basis of a future presentation.

The better understanding of the tilted OOWC in Ghawar has provided an answer to the problem identified by earlier workers in the field that, “Some type of static equilibrium is indicated by the high contents of dissolved solids in water, but its nature is not yet understood” (Aramco, 1959). Benefits become apparent in the ongoing development drilling of Central Haradh. The placement of producer and injector wells on the flanks of the Haradh sector using a minimum of delineation wells, the maintenance of reservoir pressure, and balanced production are all dependent on a correct appreciation of the tilted OOWC.

ACKNOWLEDGMENTS

We thank the management of Saudi Aramco for their support and for permission to publish this paper. In particular, we thank N.G. Saleri, E.H. Bu-Hulaigah, and A.A. Al-Abdulkarim of Saudi Aramco for their support and encouragement. The authors are indebted to Moujahed Al-Husseini, Joerg Mattner and David Grainger of GeoArabia, Denis Mougenot, Abdulazeem Al-Towailib, and three anonymous referees, whose reviews allowed a major revision of the initial manuscript. The design and drafting of the final figures was by Gulf PetroLink.

REFERENCES

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APPENDIX A

Static Equilibrium with Variable Fluid Densities

The pressure exerted by a column of fluid may be expressed as follows:

ρ × − Pf = f (z2 z1) …………………………………………………………….(A-1)

Equation A-1 implies, however, that the fluid pressure gradient is constant over the area of application. Solving the pressure equilibrium equation for a structure filled with oil in its crest is equivalent to a traditional U-tube experiment, providing the assumptions of equation A-1 are fulfilled.

If the fluid pressure gradient is changing across a reservoir trap, equation A-1 has to be rewritten in an incremental form as: δ ρ × δ Pf = f(x) z…………………………...... ………………...... (A-2) The difference in altitude between two points is related to the horizontal distance as: δz = slope(x) × δx……………………...... ………………...... (A-3) The cumulative fluid column pressure may be approximated as a finite summation over the structural axis, as follows: Σ ρ × × ∆ Pf = f (x) slope(x) x………………………………………………….(A-4)

Equation A-4 means that for a variable oil pressure gradient, the isobaric surfaces would be tilted in the oil zone according to the magnitude of the oil density change. If aquifer and oil densities are variables, the field equilibrium is found by calculating the depth in the aquifer (if any) at which the isobaric surfaces will return to the horizontal. A simple numerical application is shown below for a cross-section of a reservoir with variable oil and aquifer water densities (Figure A-1). Below the OWC on each side of the structure, the water pressure gradient is taken as constant. As shown in Table A-1, the combined weight of the oil and water column is in equilibrium at a depth of −7,691 ft on both sides of the cross-section with the selected OWC at −6,650 ft and −6,420 ft.

For the numerical application in Figure A-1 (constant absolute structural slope) and in the oil zone,

Equation A-4 can be simplified between two successive points (x1 and x2) as follow: − × − × × − × Po (x2) = Po(x1) slope (x2 x1) [ao (x1 + x2)/2 + bo 75 ao]...... (A-5)

Table A-1 shows the numerical application of static equilibrium at variable fluid densities. It is possible to derive and apply Equation A-5 to compute the pressure exerted by the oil column shown in the sixth column of Table A-1. The determination of the equilibrium depth is made with trivial additions to the water column weight until the pressure exerted by the total fluid column is identical on each side on the structure.

Nomenclature

Pf = pressure exerted by fluid column, psi P = pressure exerted by oil column, psi ρo f = fluid pressure gradient, psi

ao = oil pressure gradient change, psi/ft/km

bo = intercept of oil pressure gradient change, psi/ft x = horizontal distance, ft z = vertical distance, ft slope = terrain slope, ft/km f = fluid (o oil, w water)

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WATER PRESSURE GRADIENTS AND SIMPLIFIED STRUCTURE 0.550 0 Point 1 Point 2

-1,000 0.500 Water Gradient

0.450 -2,000

0.400 -3,000

-4,000

0.350 Depth (ft ss)

Oil Gradient Pressure gradient (psi/ft) Pressure gradient -5,000 0.300

Oil Pool Profile

0.250 -6,000

0.200 -7,000 0 20 40 60 80 100 120 140 160 180 200 220 240

Distance (km) Figure A-1: Ghawar oil- and water-pressure gradients and simplified structure.

Table A-1 Numerical Application of Static Equilibrium with Variable Fluid Densities

Distance Incremental Oil pool Elevation Terrain Pressure exerted Pressure exerted from point 1 distance profile difference slope by oil column by oil column from from point 1 highest elevation

(km) (km) (ft) (ft) (ft/km) (psi) (psi) Point "1" 0 0 -6,650 0 -13.8 0 502 24 24 -6,320 +330 -13.8 99 404 48 24 -5,990 +330 -13.8 199 304 72 24 -5,660 +330 -13.8 299 203 96 24 -5,330 +330 -13.8 400 102 120 24 -5,000 +330 -13.8 502 0 144 24 -5,330 -330 +13.8 400 103 168 24 -5,660 -330 +13.8 296 207 192 24 -5,990 -330 +13.8 191 311 216 24 -6,320 -330 +13.8 86 416 Point "2" 223 7 -6,420 -100 +13.8 54 448

Oil pressure gradient (psi/ft) Water pressure gradient (psi/ft) x (km) o = a(x - 75) + b x (km) w = a(x + 75) + b ao 1.00 × 10-4 aw -2.00 × 10-4 bo 0.306 bw 0.518

Water leg pressure gradients (psi/ft) Pressure exerted by total fluid column (psi) Pw1 0.503 Point 1 1,026 Pw2 0.455 Point 2 1,026 Equilibration depth (ft) EqDepth -7,691

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ABOUT THE AUTHORS

Bruno Stenger is a Senior Petroleum Engineer with Saudi Aramco working in the North Uthmaniyah Unit, ‘Udhailiyah Reservoir Management Division. He has a BSc in Geological Engineering (1989) from the École Nationale Superieure de Géologie, France and an MSc in Geomechanics (1990) from the Institut National Polytechnique de Lorraine. Before joining Saudi Aramco in October 2000, Bruno was the Chief Reservoir Engineer for H.O.T. Engineering, an oil and gas consulting company in Austria. [email protected]

Tony Pham is a Petroleum Engineering Consultant with the Haradh and Harmaliyah Unit, ‘Udhailiyah Reservoir Management Division of Saudi Aramco. He has a BSc in Petroleum Engineering from Texas A&M University. Pham joined Saudi Aramco in 1982. He is involved in the development of drilling operations and planning for Central and South Haradh. [email protected]

Nabeel Al-Afaleg is a Supervisor in the Haradh and Harmaliyah Unit, ‘Udhailiyah Reservoir Management Division. He has a BSc in Petroleum Engineering (1988) from King Fahd University of Petroleum and Minerals, Dhahran, and an MSc (1992) and a PhD (1996) in Petroleum Engineering from the University of Southern California. Nabeel Joined Saudi Aramco in October 1987. [email protected]

Paul Lawrence is a Geological Specialist with the Southern Fields Characterization Division of Saudi Aramco. He has a BSc in Geology (1976) from Kent State University and an MSc in Geology/Geophysics (1978) from Wright State University, USA. Before joining Saudi Aramco in 1991, Paul was a Seismic Interpreter for Atlantic Richfield, Terra Resources, and Marathon Petroleum Tunisia. He is working on reservoir characterization and interpretation of 3-D seismic data in Ghawar field. [email protected]

For additional information about the authors see Geoscience Directory at www.gulfpetrolink.com

Manuscript Received December 15, 2001 Revised July 16, 2002 Accepted July 18, 2002

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