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Reservoir Characterization Research & Consulting (UK) Ltd., P.O. Box: 46800, Abu Dhabi, U.A.E.

Abstract

The Diyab Formation (Oxfordian to mid-Kimmeridgian) is widely distributed in Abu Dhabi. It consists of argillaceous lime mudstones/ wackestones (rich in organic matter) in the west, which change laterally eastward into oolitic packstones and grainstones. Its thickness reaches up to 1300 ft (395 m) towards the southern onshore Abu Dhabi. Geochemical evaluation of the Diyab Formation was carried out using analytical data from five different laboratories. Source rock screening indicated the presence of a rich source-rock interval in the lower part of the formation in western Abu Dhabi, which becomes a lean source-rock in eastern Abu Dhabi. The Diyab source rock contains oil- and gas-prone kerogen, and was deposited in an intrashelf basin that was enclosed by the Diyab shelfal facies sediments, which restricted water circulation, causing anoxic conditions below wave base.

A combination of geological and geochemical information was used to reconstruct burial and thermal histories of the potentially petroliferous intervals in the Diyab source rock. This source rock was sufficiently mature in the southwestern onshore Abu Dhabi to generate hydrocarbons since Late Cretaceous time. Currently, this formation lies within the gas generation window for most of onshore and southern offshore Abu Dhabi.

Comparative analysis of oil and source-rock characteristics, using both bulk and molecular parameters, carbon-isotope analysis, gas chromatography (GC), and gas chromatography-mass spectrometry (GC-MS), was carried out. The oils from both the Thamama Group and the Arab Formation have the characteristic of oils derived from carbonate source rocks. However, Arab oils are less mature and have lower concentration of saturate, and are isotopically lighter than Thamama oils at equivalent reservoir depth.

The secondary migration scheme was based on a series of structure and paleostructure maps at the top of the Arab-D level. The migration direction of the Arab Formation was controlled mainly by the presence of western synclinal structures. East of these synclines, oil migration is predominantly northeastward. The early Tertiary (50–40 Ma) was the major expulsion phase, with more than 75% of the total oils being generated from Diyab source rock, approximately 95% of which comes from the Lower Diyab section.

Crude oil and extract analysis resulted in identification of four main oil families. The Simsima-reservoired oil appears to originate from the Shilaif source rock, whereas the Thamama oils are sourced from the Shuaiba Basinai Facies (Bab Member) and the Diyab Formation. The Arab oils were sourced mainly from the Diyab Formation, and the Araej oil was sourced mainly from the Diyab Formation and possibly from an unknown pre-Diyab source rock.

Introduction

The main objectives of this study are (1) to evaluate the qualitative and quantitative source-rock potential of the Upper Jurassic Diyab Formation, (2) to conduct comprehensive maturation modeling to establish the timing of hydrocarbon expulsion from the Diyab source rock, (3) to investigate the lateral and vertical hydrocarbon migration and distribution, and (4) to detect the genetic oil families of Abu Dhabi and relate these oils to their probable sources. A source-rock evaluation of the Diyab Formation was carried out using integrated and averaged analytical data from five different laboratories. The data used in this part of the study include more than 70 oil samples and source-rock extracts, in addition to hundreds of core chips and thousands of cutting samples from more than 40 wells covering the study area (Fig. 1). Sequence stratigraphical analyses of well and core data and lithofacies description and depositional setting were used.

Fig. 1.

—Map of the United Arab Emirates showing the area of study and the location of the wells.

Fig. 1.

—Map of the United Arab Emirates showing the area of study and the location of the wells.

Very little published work exists on the Diyab Formation. Murris (1980), Ayres et al. (1982), Droste (1990), and de Matos and Hulstrand (1995) have addressed the origin and development of the Diyab intrashelf, and Hassan and Azer (1985) discussed the source-rock potential of the formation. The lithologic description of Diyab Formation on a microscopic scale and an environmental facies interpretation were carried out by Whittle and Alsharhan (1996).

The Upper Jurassic Diyab Formation in offshore Abu Dhabi is the equivalent of the Dukhan Formation of onshore areas. It is also equivalent to the Hanifa and Jubailah Formations of Qatar and Saudi Arabia, respectively (see Alsharhan and Nairn 1997).

The Lower Cretaceous and the Middle-Upper Jurassic contain some of the most important stratigraphic successions of Abu Dhabi. The porous carbonate sections constitute the main reservoirs, whereas the dense carbonate layers act as intraformational seals and, in part, potential source rocks. The Albian Nahr Umr Shale and the Tithonian Hith Anhydrite form the regional seals for the Thamama and Arab hydrocarbon accumulations (Fig. 2).

Fig. 2.

—Lower Cretaceous and Upper Jurassic lithostratigraphy in Abu Dhabi, U.A.E.

Fig. 2.

—Lower Cretaceous and Upper Jurassic lithostratigraphy in Abu Dhabi, U.A.E.

Late Jurassic tectonic differentiation in response to the combination of a eustatic sea-level rise and differential subsidence over the platform resulted in the development of the Diyab intrashelf basin in western Abu Dhabi (Alsharhan and Kendall, 1986). This Diyab basin was filled with bituminous lime mudstones, which pass laterally into non-source, shallow-water platform carbonates (de Matos and Hulstrand, 1995; Taher, 1997). As the intrashelf basin shallowed during the Late Jurassic, platform carbonates extended across the basin to form the major reservoir units of the Arab Formation. By Tithonian times, a sabkha environment had developed, and with increasing aridity the evaporites of the Hith Formation were widely deposited across western Abu Dhabi. A gradual return to a more humid climate in the Early Cretaceous coincided with the reestablishment of the Early and middle Cretaceous shelf carbonate depositional environment.

Stratigraphic Framework

The Diyab Formation is underlain by the Middle Jurassic Araej Formation and overlain by the upper Kimmeridgian Arab Formation. From paleontological and palynological evidence, the Diyab Formation has been dated as Oxfordian to mid-Kirnmeridgian (Alsharhan, 1989). The Diyab Formation varies in thickness from 750 ft (229 m) at well I to 1350 ft (411 m) at well D among the studied wells (Figs. 3, 4) and is interpreted to have been deposited in an intrashelf basin, slope, shelf margin, and shelf interior (de Matos and Hulstrand, 1995; Whittle and Alsharhan, 1996; Taher, 1997).

Fig. 3.

—Gamma ray-total organic carbon (TOC%) correlation section, offshore Abu Dhabi.

Fig. 3.

—Gamma ray-total organic carbon (TOC%) correlation section, offshore Abu Dhabi.

Fig. 4.

—Gamma ray-total organic carbon (TOC%) correlation section, onshore Abu Dhabi.

Fig. 4.

—Gamma ray-total organic carbon (TOC%) correlation section, onshore Abu Dhabi.

The Diyab Formation consists of argillaceous lime mudstones wackestones (rich in organic matter) that change laterally eastward into peloidal packstones and grainstones. The formation thickens to over 1300 ft (411 m) southward (i.e., toward the south of present onshore Abu Dhabi), showing a gradational facies change, where it consists of lime mudstones. Grainstones and dolomitic limestones occur toward the east. In western and northwestern Abu Dhabi, the Diyab exhibits highly organic shales and carbonates. Total organic carbon (TOC) values show a good correlation with the gamma-ray response (Figs. 3, 4). The regional distribution of the Diyab Formation argillaceous limestones indicates that it was deposited in an intrashelf basin that was enclosed by the Diyab shelf sediments (Figs. 567). However, part of the increased gamma ray can be attributed to other sources of radiation in the Diyab argillaceous limestones. In Abu Dhabi, the Diyab Formation was subdivided into three informal members: lower, middle, and upper (Figs. 3, 4) based on lithology and gamma-ray signatures (Azer, 1989; Whittle and Alsharhan, 1996; de Matos and Hulstrand, 1995).

Fig. 5.

—Isopach in feet (A), depositional model (B), and net source-rock thickness in feet (C), and average TOC % (D) of lower member, Diyab Formation in Abu Dhabi.

Fig. 5.

—Isopach in feet (A), depositional model (B), and net source-rock thickness in feet (C), and average TOC % (D) of lower member, Diyab Formation in Abu Dhabi.

Fig. 6.

—Isopach in feet (A), depositional model (B), net source-rock thickness in feet (C), and average TOC % (D) of middle member, Diyab Formation in Abu Dhabi.

Fig. 6.

—Isopach in feet (A), depositional model (B), net source-rock thickness in feet (C), and average TOC % (D) of middle member, Diyab Formation in Abu Dhabi.

Fig. 7.

—Isopach in feet (A), depositional model (B), net source-rock thickness in feet (C), and average TOC % (D), of upper member, Diyab Formation in Abu Dhabi.

Fig. 7.

—Isopach in feet (A), depositional model (B), net source-rock thickness in feet (C), and average TOC % (D), of upper member, Diyab Formation in Abu Dhabi.

The lower member thickens toward the east, ranging from 300 ft (91 m) in the western offshore to 700 ft (213 m) in the eastern onshore (Fig. 5A). The thickening found in the east is mainly related to the development of high-energy shelfal deposits of the Hadriya reservoir (Fig. 5B), and follows a nearly north-south belt that prograded laterally westward towards the Diyab intrashelf basin.

The lower member can be further subdivided into two lithological units: the lower and upper units. The lower unit, which is the lowermost part of the Diyab Formation, is overlain gradationally by the upper unit and is underlain by the Araej Formation (Figs. 3, 4). The lower unit in the eastern and parts of the central Abu Dhabi areas is characterized by an intermediate gamma-ray response compared with very high gamma-ray of the upper unit and low gamma-ray of the Upper Araej Member (Figs. 3, 4). The lower unit ranges in thickness from 8 ft at well S to approximately 300 ft at well X. It reaches its maximum thickness in eastern Abu Dhabi (Figs. 3, 4), which suggests that the lower unit has a gradational relationship with the overlying upper unit.

The lower unit consists of peloidal bioclastic packstones and grainstones with minor wackestones over the study area. A facies change from an open-marine shelf during lower Diyab deposition to basinal slope condition is recorded in the western and central Abu Dhabi, whilst to the east the high-energy limestone section reflects deposition in an open marine shelf above wave base (Fig. 5B).

The upper unit is characterized by very high gamma-ray response in the western parts of Abu Dhabi. It is regarded as a very important potential source rock facies for the Arab and some Thamama oils in Abu Dhabi. The top of the upper unit over most of the western area and parts of the central area is easily picked at a contact of the beginning of increasing gamma-ray response with a relatively low one of the overlying cleaner middle member (Figs. 3, 4).

The upper unit has a lower gamma-ray response in the eastern area and parts of the central area than in the western area. However, the upper unit can be positively correlated in the western area on the basis of regional well-log correlation, and the interpreted paleoenvironmental model is consistent. The upper unit of the lower member in the western area (wells S, P, U, and W) and parts of the central area (well N) is composed of thinly laminated bituminous limestone, interbedded with distinct thin anhydrite layers, representing deposition in an intrashelf basin to basinal slope environment with euxinic conditions. In parts of the central and the eastern areas (wells X, D, and G; Figs. 3, 4), the upper unit consists predominantly of mudstone/wackestone deposited under an open-marine shelf condition, although it is completely dolomitized at wells Y and H.

The middle member is characterized by low gamma-ray response over the study area (Figs. 3, 4). The paleoenvironment can be interpreted as a series of regressive sequences. The member is composed of bioclastic, peloidal mudstone and wackestone in the western and parts of the central area, in wells V, S, and U, representing deposition under open marine conditions. A la-goonal condition, enabling development of oolite shoals, seems to have prevailed over the eastern Abu Dhabi, especially at wells D and K. In this area, the member consists mainly of oolitic, peloidal, bioclastic (corals, stromatoporoids, green algae, fora-minifera) grainstones/packstones/wackestones, and considerable dolomitization (partly with oolite ghost texture) is present in wells Y and G. The member, which accumulated under in shoal conditions, has good reservoir characteristics (e.g., well I). The member thickens eastward to more than 250 ft (76 m), and thins westward to less than 125 ft (38 m) (Fig. 6A). The thickening in the east is related mainly to the development of high-energy shelf-margin deposits of Hanifa reservoir (Fig. 6B).

The upper member is characterized by relatively high gamma-ray response over the study area. In the western and eastern areas the gamma-ray response of the member is higher than that of the underlying middle member and the overlying lower Arab-D Member (Figs. 3, 4). In the central area (wells I, T and D), the gamma-ray response of the upper member is relatively low. On the basis of regional paleoenvironment analysis (Fig. 7B) the cleaner interval is interpreted to represent a shallow shelf with shoal environments. Lithologically, in the western area the member consists dominantly of bioclastic mudstone/wackestone, indicating deposition on an open marine shelf below wave base. In the central area, at wells J, Z, T and D, it is composed of bioclastic, peloidal, and oolitic grainstone/packstone/ wackestone in the cleaner intervals, with subordinate lagoonal mudstone to wackestone. To the east, the upper member in wells Y and G is made up of dolomite, although its original texture is obscured by the considerable dolomitization; ghosts of pellets and ooids suggest deposition over banks with a lagoonal character.

The abnormal thickening of the upper member to the west, over the previous intrashelf basin (Fig. 7A) is most probably related to tectonic uplift and erosion in the east, while sedimentation continued in the western part of the study area, creating a lowstand wedge (Fig. 7B).

Source-Rock Potential

The large geochemical database created by several contractors was reviewed and reinterpreted to evaluate the source-rock richness, distribution, and quality, which in turn allowed an assessment of the depositional setting and conditions favorable for the Diyab Formation source-rock potential.

Paleoenvironment

The Diyab Formation was deposited during a marine transgression, resulting from regional subsidence. The sea-level rise allowed rapid up-building of a carbonate rim, while the basin floor lagged behind, because of lower rates of sedimentation (Read, 1985). The Diyab basinal facies of western Abu Dhabi consists of pelagic lime mudstone with abundant planktonic microfossils. The regional distribution of the Diyab basinal facies indicates that it was deposited in an intrashelf basin that was enclosed by the Diyab carbonate shelfal facies sediments. This resulted in restricted water circulation, anoxic conditions, and depositionbelow wave base (Murris, 1980; Whittle and Alsharhan, 1996). The shelfal facies are located mainly in the east and are represented by the present-day Hanifa and Hadriya reservoirs (Fig. 3). The lower and middle members of Diyab shelfal facies seem to have prograded laterally westward into their time-equivalent basinal facies deposits (Figs. 5B, 6B).

A drop of sea level, possibly associated with the tectonic uplift to the east, resulted in exposure of the middle member (Hanifa Reservoir) in the shelf interior and the shelf margin (Fig. 7B). The upper member (Jubaila) constitutes a low stand wedge, which is interpreted to have been deposited after the drop of sea level below the middle member (Hanifa) shelf break. This caused a lowstand wedge (Fig. 7B) infilling the bathymetric low of the middle member (de Matos and Hulstrand, 1995). Following deposition of the lowstand wedge, a marine transgression deposited open marine sediments of the Arab Formation with more oxygen-rich, less saline waters as carbonate production gradually increased.

Source-Rock Richness and Thickness Distribution

Lower Member.—

This member shows significant organic richness in the western part of Abu Dhabi, with an average TOC of up to 1.2% by weight (Fig. 5D). However, the present-day high maturity of the analyzed rock samples suggests that the original source potential could have had higher TOC values than those recorded in the current analysis. Using estimates of kinetic maturity the thermal modeling method suggests that the original average may have been approximately 30–50% higher than recorded today.

Samples from the lower member in wells I, H, Y, E, D, and C of eastern Abu Dhabi have very low pyrolysis yields, ranging between 0.5 and 0.2 gm/kg. Also, average residual TOC contents are very low (< 0.3 wt %), indicating that the Diyab in eastern Abu Dhabi did not have any significant source potential.

The variation and distribution of net source thickness of the lower member reflect patterns similar to the distribution of organic richness. The lower-member source rock becomes thicker, about 150 ft (46 m) to the west, probably as a result of higher sedimentation rates, but the source rock thins rapidly to nothing towards the east (Fig. 5C).

The lower member has only poor source-rock productivity, with maximum S2 yields of only 1.1 and 2 kg/ ton in wells X and O, respectively. However, the data suggest that the lower member may formerly have been rich source rock in wells N and M, with average source-rock potential yield up to 11.5 kg/ton (Table 1), and this might have been the original source rock potential of 5 kg/ton.

Table 1.

—Volumetric calculations of oil migrated from Diyab source rocks.

Table 1.1—Volumetric calculations of oil migrated from Diyab source rocks up to Maastrichtian (Simsima) time

Diyab FormationDrainage AreasMature Area(km2)Net Source Thick, (m)Source Rock Potential (kg/ton)Source Rock Conversion (%)Oil Migration Efficiency (%)Volumes of oil available to trap (Billion Barrels)
Upper Area-A 6330 22.9 0.3 0.4 0.4 0.0 
 Area-B 1265 24.4 0.5 0.45 0.4 0.0 
 Area-C 4906 21.3 0.5 0.5 0.4 0.0 
 Area-D 3797 7.6 0.0 0.2 0.4 0.0 
MIDDLE Area-A 6330 21.3 3.0 0.4 0.35 0.7 
 Area-B 1265 22.9 5.0 0.45 0.35 0.6 
 Area-C 4906 15.2 0.5 0.5 0.35 0.0 
 Area-D 3797 4.0 0.0 0.2 0.35 0.0 
LOWER Area-A 6330 59.4 8.0 0.4 0.3 10.2 
 Area-B 1265 61.0 11.0 0.45 0.3 3.6 
 Area-C 4906 48.8 11.5 0.5 0.3 13.3 
 Area-D 3797 21.3 3.0 0.2 0.3 0.0 
Total 28.3 
Diyab FormationDrainage AreasMature Area(km2)Net Source Thick, (m)Source Rock Potential (kg/ton)Source Rock Conversion (%)Oil Migration Efficiency (%)Volumes of oil available to trap (Billion Barrels)
Upper Area-A 6330 22.9 0.3 0.4 0.4 0.0 
 Area-B 1265 24.4 0.5 0.45 0.4 0.0 
 Area-C 4906 21.3 0.5 0.5 0.4 0.0 
 Area-D 3797 7.6 0.0 0.2 0.4 0.0 
MIDDLE Area-A 6330 21.3 3.0 0.4 0.35 0.7 
 Area-B 1265 22.9 5.0 0.45 0.35 0.6 
 Area-C 4906 15.2 0.5 0.5 0.35 0.0 
 Area-D 3797 4.0 0.0 0.2 0.35 0.0 
LOWER Area-A 6330 59.4 8.0 0.4 0.3 10.2 
 Area-B 1265 61.0 11.0 0.45 0.3 3.6 
 Area-C 4906 48.8 11.5 0.5 0.3 13.3 
 Area-D 3797 21.3 3.0 0.2 0.3 0.0 
Total 28.3 

Middle Member.—

The member in well X is a moderately rich source rock in the west but becomes a lean source rock in the eastern part of the study area. The low source-rock potential (0.2–0.8% TOC by weight; Fig. 6D) as determined by previously analyzed rock samples (in 1982 and 1988) is confirmed by the latest analysis (in 1992). No significant organic richness was detected in any samples of the middle member analyzed from the H, Y, D, and C wells. It averages less that 0.2% TOC by weight (Fig. 6D).

The effective source thickness of the middle member varies from 25 to 50 ft (8 to 15 m) (Fig. 6C). The maximum source thickness of about 75 ft (23 m) is found in the west and adjacent to the shoreline area, possibly representing a pinchout in the central part of Abu Dhabi.

Upper Member.—

This member is generally organically lean and has a residual TOC of less than 0.8%, (Fig. 7D), with the average net source thickness of 25 to 100 ft (8 to 30 m) (Fig. 7C). It is not anticipated that this member has major source potential.

Source Quality and Kerogen Type

In addition to organic richness, it is necessary to consider the nature and origin of the organic matter in the rocks of the Diyab Formation. The geochemical data show a general trend from high hydrogen indices (HI) at low maturity (around 200–250 HI) to low values at high maturity (around 50 HI). These values compare well with the mapped maturity (and depth) trends, and are consistent with the visual kerogen typing, which suggests that amorphous kerogen is the main type in most of the samples examined. In some cases, recognizable but very degraded marine sapropelic kerogen is present in much of the interval. A thick interval in wells V and W appears to contain spent oil-prone kerogen. From a study of the petroleum geochemistry of Abu Dhabi, Lijmbach et al. (1992) concluded that the Upper Jurassic Diyab (Dukhan) Formation is an excellent Type II, post-mature source rock for oil.

Maturity

Maturation modeling was used to investigate the time at which generation and expulsion of petroleum occurred in the Abu Dhabi area, in order to produce maps for a migration study. Geothermal modeling was undertaken for 27 wells throughout Abu Dhabi using an in-house (ADNOC) program based on the Lopatin-Waples algorithm (Waples, 1980) and the Arrhenius equation (Wood, 1988; Hunt et al., 1991). The study was started by reconstructing the burial history of 27 key wells (Fig. 8), which are spaced such that they represent maturity variations. The input data for reconstruction of these burial-history profiles consist of present-day depth maps of the key horizons, formation thickness, and age and formation temperature. In the reconstruction of the burial history, unconformities were also accounted for. In southeast onshore Abu Dhabi, however, much of the Upper Cretaceous section is absent, resulting in a significant time gap of up to 45 million years (Taher, 1997). The paleo-thickness of the partially eroded Aruma and Wasia groups of southeastern onshore Abu Dhabi were estimated using a complete reference section in western Abu Dhabi.

Fig. 8.

—Burial history and hydrocarbon generation curves for four representative wells.

Fig. 8.

—Burial history and hydrocarbon generation curves for four representative wells.

The stratigraphic development of the area was taken as a passive infill, and thus a constant surface temperature of 86°F was assumed for offshore wells and 80°F for onshore wells. The input data for reconstruction of the thermal history consist of geothermal gradients, rock conductivity, fluid distribution, and porosity versus depth.

The data on geothermal gradient in the study area show a gradual increase in heat flow southwards that ranges between 1.5°F/100 ft in the north offshore and 2.3°F/100 ft in the southern onshore (Taher, 1997). The high geothermal gradient in the southern onshore is probably related to shallow depth of the basement, rock conductivity, and fluid distribution.

The thermal modeling was calibrated with available optical and statistical data to render it more useful for predicting maturation boundaries in the study area where no analytical data are available. The calibration includes the calculation of the thermal alteration index (TAI) and the vitrinite reflectance (R0). Vitrinite-reflectance data for the Diyab Formation in ten key wells (Fig. 9) indicate that the offshore wells G, Q, P, K, and I are within the oil-generation window, and well H is still in the immature stage or at the onset of oil generation. Onshore wells X, M, and D are within the gas-generation window, and well AE is overmature. Significant hydrocarbon generation and expulsion occured in southwestern onshore Abu Dhabi at the end of Maastrichtian time, about 65 Ma (Fig. 10A), with major expulsion of hydrocarbon at the end of Eocene time from most of the onshore and southern offshore area (Fig. 11A). The present-day maturity map of the Diyab Formation indicates that the study area is within the gas-generation window (Fig. 12A).

Fig. 9.

—Maturity of the Diyab Formation in Abu Dhabi.

Fig. 9.

—Maturity of the Diyab Formation in Abu Dhabi.

Fig. 10.

—Diyab oil generation and migration. A) Diyab paleo-maturity map; B) top Arab-D paleo-structure map in Maastrichtian time.

Fig. 10.

—Diyab oil generation and migration. A) Diyab paleo-maturity map; B) top Arab-D paleo-structure map in Maastrichtian time.

Fig. 11.

—Diyab oil generation and migration. A) Diyab paleo-maturity map; B) top Arab-D paleo-strucrure map in Eocene time.

Fig. 11.

—Diyab oil generation and migration. A) Diyab paleo-maturity map; B) top Arab-D paleo-strucrure map in Eocene time.

Fig. 12.

—Diyab oil generation and migration. A) Diyab maturity map; B) top Arab-D structure map at present day.

Fig. 12.

—Diyab oil generation and migration. A) Diyab maturity map; B) top Arab-D structure map at present day.

Volumetric Calculations

Volumetric calculations were performed using Piggot’s (1982) method and Goff’s (1983) equation. The calculations require an estimate of source-rock richness, thickness, and productivity (kg/ton). In considering the evidence that the Diyab Formation is a potential oil source rock, the initial potential organic-matter content prior to maturation was estimated using present TOC % vs. percentage generation of hydrocarbon. It is concluded that the TOC values were doubling in the overmature areas, whereas in the immature areas, the present TOC values remain unchanged. The paleomaturity maps were created by projecting the maturity effect back to the Maastrichtian and Eocene (Figs. 10B, 11B). The resulting maturity kitchens were subdivided into five drainage polygons (A, B, C, D, and E; Fig. 11), which appear to be in different structural positions and isolated from each other. Volumetric calculations were made separately for the Maastrichtian, the Eocene, and the present day (Tables 13). Migration efficiency was assumed on the basis of similar cases studied previously in the area with consideration of the distance between the kitchens and the reservoirs. On the basis of these assumptions the total predicted oil-in-place that migrated from the Diyab source rock amounts to 175 billion barrels.

Table 1.2

—Volumetric calculations of oil migrated from Diyab source rocks between Maastrichtian to Eocene (Dammam) time

Diyab FormationDrainage AreasMature Area(km2)Net Source Thick, (m)Source Rock Potential (kg/ton)Source Rock Conversion (%)Oil Migration Efficiency (%)Volumes of oil available to trap (Billion Barrels)
Upper Area-A 16706 16.8 0.4 1.00 0.4 0.0 
 Area-B 7340 25.9 1.5 0.80 0.4 1.1 
 Area-C 9112 22.9 1.8 1.00 0.4 3.1 
 Area-D 7594 7.6 0.4 0.85 0.4 0.0 
 Area-E 3037 21.3 0.1 1.00 0.4 0.0 
MIDDLE Area-A 16706 18.3 1.0 1.00 0.35 0.8 
 Area-B 7340 18.3 1.9 0.80 0.35 1.3 
 Area-C 9112 15.2 1.8 1.00 0.35 1.8 
 Area-D 7594 4.0 0.4 0.85 0.35 0.0 
 Area-E 3037 15.2 0.0 1.00 0.35 0.0 
LOWER Area-A 16706 42.7 6.5 1.00 0.3 45.7 
 Area-B 7340 53.3 8.0 0.80 0.3 24.7 
 Area-C 9112 47.2 11.0 1.00 0.3 49.4 
 Area-D 7594 25.9 2.0 0.85 0.3 2.0 
 Area-E 3037 38.1 5.0 1.00 0.3 5.5 
Total 135.4 
Diyab FormationDrainage AreasMature Area(km2)Net Source Thick, (m)Source Rock Potential (kg/ton)Source Rock Conversion (%)Oil Migration Efficiency (%)Volumes of oil available to trap (Billion Barrels)
Upper Area-A 16706 16.8 0.4 1.00 0.4 0.0 
 Area-B 7340 25.9 1.5 0.80 0.4 1.1 
 Area-C 9112 22.9 1.8 1.00 0.4 3.1 
 Area-D 7594 7.6 0.4 0.85 0.4 0.0 
 Area-E 3037 21.3 0.1 1.00 0.4 0.0 
MIDDLE Area-A 16706 18.3 1.0 1.00 0.35 0.8 
 Area-B 7340 18.3 1.9 0.80 0.35 1.3 
 Area-C 9112 15.2 1.8 1.00 0.35 1.8 
 Area-D 7594 4.0 0.4 0.85 0.35 0.0 
 Area-E 3037 15.2 0.0 1.00 0.35 0.0 
LOWER Area-A 16706 42.7 6.5 1.00 0.3 45.7 
 Area-B 7340 53.3 8.0 0.80 0.3 24.7 
 Area-C 9112 47.2 11.0 1.00 0.3 49.4 
 Area-D 7594 25.9 2.0 0.85 0.3 2.0 
 Area-E 3037 38.1 5.0 1.00 0.3 5.5 
Total 135.4 
Table 1.3

—Volumetric calculations of oil migrated from Diyab source rocks between Dammam time until present day

Diyab FormationDrainage AreasMature Area(km2)Net Source Thick, (m)Source Rock Potential (kg/ton)Source Rock Conversion (%)Oil Migration Efficiency (%)Volumes of oil available to trap (Billion Barrels)
Upper Area-A 17520 15.2 0.5 1.0 0.4 0.0 
 Area-B 15232 19.8 1.0 0.8 0.4 0.0 
 Area-C 10750 12.2 0.7 1.0 0.4 0.0 
 Area-D 7040 6.1 0.5 0.85 0.4 0.0 
 Area-E 4350 4.6 0.9 1.0 0.4 0.0 
MIDDLE Area-A 17520 15.2 1.0 1.0 0.35 0.7 
 Area-B 15232 12.2 0.6 0.8 0.35 0.0 
 Area-C 10750 10.7 0.0 1.0 0.35 0.0 
 Area-D 7040 3.0 0.5 0.85 0.35 0.0 
 Area-E 4350 3.0 0.9 1.0 0.35 0.0 
LOWER Area-A 17520 42.7 1.0 1.0 0.3 1.7 
 Area-B 15232 39.6 2.6 0.8 0.3 8.7 
 Area-C 10750 39.6 0.0 1.0 0.3 0.0 
 Area-D 7040 18.3 1.0 0.85 03 1.0 
 Area-E 4350 18.3 1.5 1.0 0.3 0.0 
Total 11.8 
Diyab FormationDrainage AreasMature Area(km2)Net Source Thick, (m)Source Rock Potential (kg/ton)Source Rock Conversion (%)Oil Migration Efficiency (%)Volumes of oil available to trap (Billion Barrels)
Upper Area-A 17520 15.2 0.5 1.0 0.4 0.0 
 Area-B 15232 19.8 1.0 0.8 0.4 0.0 
 Area-C 10750 12.2 0.7 1.0 0.4 0.0 
 Area-D 7040 6.1 0.5 0.85 0.4 0.0 
 Area-E 4350 4.6 0.9 1.0 0.4 0.0 
MIDDLE Area-A 17520 15.2 1.0 1.0 0.35 0.7 
 Area-B 15232 12.2 0.6 0.8 0.35 0.0 
 Area-C 10750 10.7 0.0 1.0 0.35 0.0 
 Area-D 7040 3.0 0.5 0.85 0.35 0.0 
 Area-E 4350 3.0 0.9 1.0 0.35 0.0 
LOWER Area-A 17520 42.7 1.0 1.0 0.3 1.7 
 Area-B 15232 39.6 2.6 0.8 0.3 8.7 
 Area-C 10750 39.6 0.0 1.0 0.3 0.0 
 Area-D 7040 18.3 1.0 0.85 03 1.0 
 Area-E 4350 18.3 1.5 1.0 0.3 0.0 
Total 11.8 

Secondary Migration Model

Migration models can be used as a predictive tool for exploration, enabling explanation of the known distribution of hydrocarbons in the study area. In addition, it should account for the absence of petroleum where valid structures are known to exist. The secondary-migration model relies on the paieostrucrure maps of the top Arab-D Member, because this is the carrier bed above the Diyab source rock and below the Hith Anhydrite regional seal.

The paieostrucrure maps were constructed from the present-day top of Arab-D Member structure map by subtracting isopach maps of shallower sections. The paleostructure maps produced were not corrected for compaction, but their overall form reflects the general features of the reservoir at any time and they are therefore a most useful tool for examining secondary migration directions.

The paleostructure maps of the Arab-D Member (Late Kimmeridgian) for the Maastrichtian, the Eocene, and the present day (Figs. 101112) indicate that the study area can be subdivided into five drainage polygons (A, B, C, D, and E). These polygons are located in different structural positions and have been isolated from each other from Late Cretaceous time until the present.

Migration of Petroleum in Maastrichtian Time

The paleo-maturity map of the Diyab Formation during Maastrichtian time indicates that the formation was mature for oil generation only in the southwestern onshore area (Fig. 10A). Oil generated in this area migrated into the Arab reservoir of the surrounding structures (e.g., wells X, M, N, and W; Fig. 10B).

From the assumptions for the volumetric calculations (Tables 1–3), approximately 95% of the predicted oil-in-place was generated and migrated from the lower Diyab member source rock of Abu Dhabi, of which 40% was generated and migrated within Area A, approximately 45% within Area C, and 15% within Area B (Tables 1–3).

Migration of Petroleum in Eocene Time

The paleo-maturity map of the Diyab Formation during Eocene time shows that the Diyab source rock at that time was mature for oil generation over most of Abu Dhabi (Fig. 11A). The northern offshore was at the onset of oil generation, and the southwestern onshore synclines were within the gas-generation window.

The major expulsion phase of petroleum was in the early Tertiary (50–40 Ma) with more than 75% of the total oils generated from Diyab source rock having migrated during that time, with 95% having migrated from the lower member. Oil generated in Area A represents 35% of the total oil generated at that time, and this migrated mainly northwards towards the western offshore structures (Fig. 11B, Table 3). Migration direction in Area B (20%) was towards the northern offshore structures. Migration direction in Area C at that time was towards the onshore central highs into the N and M structures. The updip migration direction in the central high at that time was towards northeast Abu Dhabi. Approximately 15–20% of the oil accumulated in Area C possibly re-migrated out of this area towards the Hith edge, then towards the central offshore area into the K structure. Oil generated in Area D migrated into the southeast onshore structures, whereas oil generated in Area E migrated mainly into the K structure (Fig. 11B).

Migration of Petroleum at Present

The present-day maturity map of Diyab Formation (Fig.l2A) indicates that the formation is mature for gas generation in most onshore and southern offshore areas. However, the Diyab Formation is still actively generating oil in the northern offshore area.

The migration pathways were affected by late Tertiary tectonics. The late Tertiary seems to be characterized by a fill-and-spill migration mechanism between the structures rather than direct hydrocarbon migration from the Diyab source rock. During the late Tertiary to present day, a gas-generation phase occurred that possibly emplaced the previously trapped oil, especially in the onshore and southern offshore structures. Also, we have noticed that the late Tertiary tilting completely reversed the migration direction in the central onshore high (M and N structures) from the northeast (Fig. 11B) towards the south (Fig. 12B). Consequently, the main phase of oil spillage in Area C was southward rather than towards the Hith edge.

Analyses of Oils and Extracts

A geochemical investigation was carried out on the crude-oil samples and source-rock extracts from Abu Dhabi. The data include gas chromatography mass spectrometry (GSC-MS), and bulk and molecular parameters analyzed by five different laboratories. The data were integrated and reinterpreted in order to increase our understanding of the genetic oil families in Abu Dhabi area.

Oil-Oil Correlation

Bulk Parameters.—

The bulk parameters used in the oil-oil correlation include sulfur content, API gravity, and the δ13C value of the saturate fractions (Fig. 13). The API gravity vs. depth shows considerable variations. These differences are presumably related to the maturity of the oil when API gravity increases with depth. These oils show also a decreasing sulfur content with increasing API gravity (Fig. 13). In addition the carbon-isotope saturates of these oils become isotopically heavier with increasing reservoir temperature. However, the reservoir temperatures are not sufficiently high to have caused significant cracking of the oils in the reservoirs. These differences may therefore be ascribed mainly to different sources, which were categorized into four groups (A, B, C, and D).

Fig. 13.

—Relationship between sulfur (wt %) API gravity, and carbon saturates (%o PDB) vs. depth for different oils in Abu Dhabi.

Fig. 13.

—Relationship between sulfur (wt %) API gravity, and carbon saturates (%o PDB) vs. depth for different oils in Abu Dhabi.

Molecular Parameters.—

The molecular parameters, which include sterane distribution, saturates, total aromarics, and asphaltenes, indicate that the oil accumulations in the Lower Cretaceous reservoirs are different from those in the Upper Jurassic reservoirs (Fig. 14). The Arab oils (Group C) are generally less mature (Fig. 15), have a lower saturate and higher aromatic content, and are isotopically lighter than Thamama oils (Group B) at equivalent reservoir depth (Fig. 14).

Fig. 14.

—Ternary diagram showing the gross composition of Abu Dhabi oils.

Fig. 14.

—Ternary diagram showing the gross composition of Abu Dhabi oils.

Fig. 15a.

—Triterpane fragmentograms of the oil sample from the Shuaiba Formation and Thamama-Zone C, which correlate with the Bab Member and Shuaiba basinal facies, respectively.

Fig. 15a.

—Triterpane fragmentograms of the oil sample from the Shuaiba Formation and Thamama-Zone C, which correlate with the Bab Member and Shuaiba basinal facies, respectively.

Fig. 15b.

—Triterpane and sterane fragmentograms of the oil sample from Simsima Formation and Arab-Zone C, which correlate with Shilaif and Diyab Formations source rocks, respectively.

Fig. 15b.

—Triterpane and sterane fragmentograms of the oil sample from Simsima Formation and Arab-Zone C, which correlate with Shilaif and Diyab Formations source rocks, respectively.

The highly mature Thamama oil in structure F is isotopically similar to that found in the Middle Jurassic Araej oil (Group D) and the Upper Jurassic, Diyab/Hanifa oil in structure C (Fig. 15). These oils are isotopically similar to each other and most probably were sourced from pre-Diyab, Mesozoic sections. The Upper Cretaceous Simsima oils (Group A), which were sourced from the Shilaif Formation, are isotopically similar to the low-maturity Thamama oil of structure A.

Oil-Source Rock Correlation

Carbon-Isotope Ratio.—

The carbon-isotope compositions of the saturated and aromatic fractions (Fig. 15) display considerable variation, with δ13C ranging from -28 to -23‰ PDB. These values reflect the genetic differences that existed between the samples analyzed. However, the distribution patterns show that Group B (Thamama oils) represents the major group, which is characterized by oil gravity between 25 and 45° API and δ13C values from -27 to -24 ‰ PDB. Group A comprises the low-maturity Thamama oils in the southeast onshore Abu Dhabi (structures A, B, and C) and Simsima (Maastrichtian) oils in south onshore (structure A, B, and C) and are characterized by relatively low oil gravity (30–35°API) and high sulfur content (1.5%). Group C appears to be related mainly to Arab oils, which have moderate oil gravity (35°API) and moderate sulfur content (0.5–1%) and are isotopically heavier than Thamama oils. Group D comprises the Araej Formation, oils in the north offshore Abu Dhabi with highly mature Thamama oils in structure F and this group characterized by high oil gravity (40–50°API) with low sulfur content (< 0.5%).

The isotopic data of the different oils indicate that Group A oils are sourced mainly from the Cenomanian (Shilaif Formation). Group B comprises mainly the Lower Cretaceous, Thamama-reservoired oils, and seems to be sourced from the Oxfordian Diyab and Aptian basinal facies of the Bab Member, Shuaiba Formation (Fig. 15). Groups C and D oils are sourced mainly from the Diyab source rocks. It is also noted that Diyab and Shuaiba basinal facies source rocks are compositionally similar, which creates difficulties in differentiating between the oils from these two sources.

Gas Chromatography-Mass Spectrometry of Alkanes.—

Sterane and triterpane distribution patterns obtained by GC-MS show many differences between the Thamama and Arab oils and among Thamama oils themselves (Shuaiba and Thamama Zone C, Fig. 16). These differences cannot be simply related to the facies variation and different maturity levels.

Fig. 16.

—Carbon-isotope ratios of aromatics vs. saturates showing four major oil families in the Abu Dhabi area.

Fig. 16.

—Carbon-isotope ratios of aromatics vs. saturates showing four major oil families in the Abu Dhabi area.

The correlation between these oils and the different sources found in the study area indicates that the Simsima, Shuaiba, and Kharaib formations oils show a good correlation with Shilaif Formation and Bab Member (Shuaiba basinal facies) source rocks, respectively, and the Arab oils seems to be correlate with the Diyab source rock. The Diyab source rock correlation is influenced by the high maturity level of the formation. This is indicated by the fact that only post-mature Diyab samples are available.

Hydrocarbon Distribution

The north-south cross section of Abu Dhabi (Fig. 17) indicates that the mid- and Upper Cretaceous section seems to be completely absent in the southeast onshore Abu Dhabi. The Shilaif Formation source rock, which is part of the mid-Cretaceous Wasia Group, onlaps onto the Thamama Group. Therefore, a lateral hydrocarbon charge from the younger Shilaif into the Thamama reservoir is possible. The tectonic setting of southeast onshore Abu Dhabi is consistent with geochemical results suggesting that the Thamama oils of structure A are sourced from the Shilaif Formation.

Fig. 17.

—Lithostratigraphic-structural cross section in Abu Dhabi showing oil and gas accumulation in the Jurassic-Cretaceous and hydrocarbon migration pathway.

Fig. 17.

—Lithostratigraphic-structural cross section in Abu Dhabi showing oil and gas accumulation in the Jurassic-Cretaceous and hydrocarbon migration pathway.

Hydrocarbon distributions in the central onshore highs are difficult to account for solely by vertical hydrocarbon migration from the Diyab source rock, because at least six cycles of intercalated gas and oil can be recognized (Fig. 18), which reflect the presence of intraformational seals in this area. This intercalation between oil and gas reflects hydrocarbon migration from different mature kitchens that were located at different stratigraphic levels.

Fig. 18.

—Lithostratigraphic-structural cross section in onshore Abu Dhabi showing updip hydrocarbon migration and distribution.

Fig. 18.

—Lithostratigraphic-structural cross section in onshore Abu Dhabi showing updip hydrocarbon migration and distribution.

Conclusions

  1. The major expulsion phase of petroleum from Diyab Formation source rock was during the Early Tertiary.

  2. The migration pathways of the oil generated from the Diyab source are interpreted to have been mainly towards the offshore and central onshore structures.

  3. The amount of Diyab oil that migrated into the lower Thamama through the Hith edge represents less than 25% of the total oil migrated from Diyab source rock.

  4. The upper unit of the lower Diyab member in the western part of Abu Dhabi is a prolific oil-prone source rock, which has generated more than 90% of the total oil expelled and migrated from the Diyab Formation.

  5. Four major oil families (A, B, C, and D) are defined and correlated with the Diyab, Shuaiba basinal facies, Bab Member, and Shilaif source rocks.

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ACKNOWLEDGMENTS

The authors express sincere appreciation to the management of Abu Dhabi National Oil Company (ADNOC) for allowing us to publish this paper. Thanks also to many colleagues in ADNOC Exploration Division and U.A.E. University who provided significant stimulating discussions during the preparation stages of this paper. Our sincere thanks to Dr. C. G. St. C. Kendall, Dr. J. Connan, Dr. Peter Nederlof, and Dr. Robert W. Scott for reading and correcting the early drafts of this manuscript.

Figures & Tables

Contents

GeoRef

References

References

Alsharhan
,
A.S.
,
1989
,
Petroleum geology of the U.A.E.
:
Journal of Petroleum Geology
 , v.
12
, p.
253
288
.
Alsharhan
,
A.S.
Kendall
,
C.G.Si.C
,
1986
,
Precambrian to Jurassic rocks of Arabian Gulf and adjacent areas: Their facies, depositìonal setting, and hydrocarbon habitat
:
American Association of Petroleum Geologists, Bulletin
 , v.
70
, p.
977
1002
.
AisharhaN
,
A.S.
Nairn
,
A.E.M.
,
1997
,
Sedimentary Basins and Petroleum Geology of the Middle East
:
Amsterdam
,
Elsevier Science
,
940
p.
Ayres
,
M.G.
Bilal
,
M
Jones
,
R.W.
Slentz
,
L.W.
Tartir
,
M.
Wilson
,
A.O.
,
1982
,
Hydrocarbon habitat in main producing areas, Saudi Arabia
:
American Association of Petroleum Geologists, Bulletin
 , v.
66
, p.
1
9
.
Azer
,
S.
,
1989
,
Preliminary investigation into possible stratigraphic traps, offshore Abu- Dhabi
:
5th Middle East Oil Show
 ,
Bahrain
,
SPE 17999
, p.
739
753
.
de Matos.
,
J.E.
Hulstrand
,
R.F.
,
1995
,
Regional characteristics and depositional sequences of the Oxfordian and Kimmeridgian—Abu Dhabi
, in
Husseini
,
ML
, ed.,
Middle East Petroleum Geosciences (Geo 94)
 :
Gulf PetroLink
,
Bahrain
, v.
1
, p.
346
356
.
Droste
,
H.
,
1990
,
Depositional cycles and source rock development in an epeiric intra-platform basin—The Hanifa Formation of the Arabian Peninsula
:
Sedimentary Geology
 , v.
69
, p.
281
296
.
Goff
,
J.C.
,
1983
,
Hydrocarbon generation and migration from Jurassic source rock in the east Sheltand Basin and Viking Graben of the northern Sea
, in
Demaison
,
G.
Murris
,
R.J.
, eds.,
Petroleum Geochemistry and Basin Evaluation: American Association of Petroleum Geologists, Memoir 35
 , p.
273
302
.
Hassan
,
T.H.
Azer
,
S.
,
1985
,
The occurrence and origin of oil in offshore Abu Dhabi
:
Proceedings of 4th SPE Middle East Oil Show
 ,
Bahrain
, p.
143
155
.
Hunt
,
J.M.
Lewan
,
M.D.
Hennet
,
R.J.C.
,
1991
,
Modeling oil generation with time-temperature index graphs based on the Arrhenius equation
:
American Association of Petroleum Geologists, Bulletin
 , v.
75
, p.
795
807
.
Lijmbach
,
G.W.M.
Buiskool
,
Toxopeus, J.M.A.
Rodenburg
,
T.
Hermans
,
L.J.P.C.M.
,
1992
,
Geochemical study of crude oils and source rocks in onshore Abu Dhabi
:
5th Abu Dhabi Petroleum Conference, Proceedings, SPE 24513 (ADSPE 305)
 , p.
295
422
.
Murris
,
R.J.
,
1980
,
Middle East: Stratigraphic evolution and oil habitat
:
American Association of Petroleum Geologists, Bulletin
 , v.
64
, p.
597
618
.
Piggo
,
N.
,
1982
,
Volumetric Assessment of Petroleum Generation in Basins
:
British Petroleum Exploration School
 , GCB/22/82.
Read
,
J.F.
,
1985
,
Carbonate platform facies models
:
American Association of Petroleum Geologists, Bulletin
 , v.
69
, p.
1
21
.
Taher
,
A.K.
,
1997
,
Delineation of organic richness and thermal history of the Lower Cretaceous Thamama Group, east Abu Dhabi
:
GeoArabia
, v.
2
, no.
1
, p.
65
88
.
Waples
,
D.W.
,
1980
,
Time and temperature in petroleum formation: Application of Lopatin’s method to petroleum exploration
:
American Association of Petroleum Geologists, Bulletin
 , v.
64
, p.
916
926
.
Whittle
,
G.L.
Alsharhan
,
A.S.
,
1996
,
Diagenetic history and source rock potential of the Upper Jurassic Diyab Formation
,
offshore Abu Dhabi, United Arab Emirates
:
Carbonates and Evaporites
 , v.
11
, p.
145
154
.
Wood
,
D.A.
,
1988
,
Relationships between thermal maturity indices calculated using Arrhenius equation and Lopatin’s method: implications for petroleum exploration
:
American Association of Petroleum Geologists, Bulletin
 , v.
72
, p.
115
134
.

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