International Journal of Coal Geology

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1 International Journal of Coal Geology 100 (2012) Contents lists available at SciVerse ScienceDirect International Journal of Coal Geology journal homepage: Geochemical characterization of solid bitumen (migrabitumen) in the Jurassic sandstone reservoir of the Tut Field, Shushan Basin, northern Western Desert of Egypt Mohamed Ragab Shalaby a, Mohammed Hail Hakimi b,c,, Wan Hasiah Abdullah b a Petroleum Geoscience Department, Faculty of Science, University Brunei Darussalam, Brunei b Department of Geology, University of Malaya, Kuala Lumpur, Malaysia c Geology Department, Faculty of Applied Science, Taiz University, 6803 Taiz, Yemen article info abstract Article history: Received 3 June 2012 Accepted 5 June 2012 Available online 13 June 2012 Keywords: Solid bitumen Kaolinite Deasphalting Khatatba reservoir Shoushan Basin Asphaltene-rich solid bitumen was identified within the pore spaces of the Middle Jurassic Khatatba sandstone reservoir in the Tut Field, Shoushan Basin, Egypt. Despite good reservoir properties have been detected, the solid bitumen forms barriers in the reservoir, which prevents economic petroleum production. Petrographical and organic geochemical techniques were applied in order to characterize the source rock of the bitumen and its formation mechanisms. Organic geochemical results confirm the presence of actively migrating non-biodegraded hydrocarbons within the Khatatba sandstones. Biomarker data suggest that the solid bitumen originated from a marine shale source rock that was deposited in mildly anoxic to suboxic conditions. Biomarker oil-source rock correlation with the organic rich sediments of the Khatatba Formation indicates that the shale and coaly shale within the Khatatba Formation are an effective source rock in the area. The natural deasphalting is the predominant mechanism for the formation of the asphaltene rich solid bitumen in the Khatatba sandstones. Adsorption of asphaltenes onto authigenic kaolinite played a major role in the fixation of bitumen. Furthermore, gas deasphalting caused by gas injection may have contributed to a phase change in the reservoir fluid and deposition of solid bitumen. The injected gas is generated from Khatatba Type III kerogen or older source rocks in the Shoushan Basin during the mature stage of hydrocarbon generation Elsevier B.V. All rights reserved. 1. Introduction Solid reservoir bitumen (pyrobitumen, migrabitumen, tar, etc.) is an immovable and highly viscous material that occurs in carbonate and siliciclastics reservoir rocks. Different definitions of bitumen can be found in the published literature. Organic geochemists define bitumen as the portion of organic matter that is soluble in organic solvents (Tissot and Welte, 1984). Organic petrologists define bitumen as solid organic matter filling voids and fractures in rocks and classify it based on reflectance, fluorescence intensity, and micro-solubility (Jacob, 1989). Reservoir bitumen differs from source rock bitumen in that it is formed from petroleum in the reservoir through natural or artificial alteration processes such as thermal cracking of oil (pyrobitumen), gas deasphalting of oil (asphaltene precipitation), and biodegradation. The solid bitumen occurs in carbonate and siliciclastics petroleum reservoirs in many basins throughout the world (Horstad and Larter, 1997; Huc et al., 2000; Jones and Speers, 1976; Wilhelms and Larter, 1995). However, solid bitumen in the northern Western Corresponding author at: Department of Geology, University of Malaya, Kuala Lumpur, Malaysia. address: ibnalhakimi@yahoo.com (M.H. Hakimi). Desert of Egypt has never been previously reported. The solid bitumen is present in the sandstone reservoir rocks of the Khatatba Formation in the Tut Field. The area that forms the scope of this study lies in the Shoushan Basin, northern Western Desert, Egypt (Fig. 1). The Shoushan Basin contains sediments of Jurassic and younger age (Fig. 2). Potential hydrocarbon source rocks in the Shoushan Basin are found in the Jurassic and Cretaceous successions (Alsharhan and Abd El-Gawad, 2008; El Ayouty, 1990; El-Nady et al., 2003; Ghanem et al., 1999; Khaled, 1999; Shalaby et al., 2011, 2012, in press; Sharaf, 2003). The Middle Jurassic sandstones of the Khatatba Formation are an attractive petroleum exploration target in the northern Western Desert. The Middle Jurassic Khatatba Formation is composed mainly of sandstones interbedded with coals, and organic-rich shales. The organic-rich sediments of the Khatatba Formation are considered to have sourced the oil and gas within the Khatatba sandstone reservoirs (Shalaby et al., in press). The objective of this study is to describe the organic geochemical characteristics and to discuss the origin of the solid bitumen. This is important, because the significant volumes of solid bitumen may cause major economic problems because of the reduction of permeability in the reservoir and leading to erroneous oil-in-place calculations and /$ see front matter 2012 Elsevier B.V. All rights reserved. doi: /j.coal

2 M.R. Shalaby et al. / International Journal of Coal Geology 100 (2012) Fig. 1. Location map of Mesozoic basins in the northern Western Desert of Egypt, showing Shoushan Basin including the Tut field. lower-than-expected oil recovery (Sorenson et al., 1999). The study will also help to understand the formation mechanisms of these economically important barriers to fluid flow. The study involves petrographic and organic geochemical data, including pyrolysis data, bitumen extraction and vitrinite reflectance data. In addition, biomarker distributions were used to assess the depositional environment, age and thermal maturity of the potential source rocks. Furthermore, the biomarker compositions facilitated correlation of the solid bitumen with source rocks. 2. Samples and methods Twenty core samples were selected from Tut-22 well in the Tut Field, Shoushan Basin, including organic-rich shales and bitumenbearing sandstones from the Middle Jurassic Khatatba Formation (Table 1). The collected samples were analyzed using the Source Rock Analyzer (SRA-Weatherford)-TOC/TPH instrument (equivalent to Rock-Eval equipment). Parameters measured include TOC, S 1,S 2, S 3 and temperature of maximum pyrolysis yield (T max ). Following pyrolysis analysis, the samples were selected for further geochemical analyses and microscopic examinations. Thin sections and polished blocks were prepared from the samples and were used to evaluate mineral composition, cements, and the pore space. The reflection of solid bitumen and vitrinite maceral reflectance measurements were performed on polished whole rock blocks using a Leica DM6000M microscope and Leica CTR6000 photometry system equipped with fluorescence illuminators. The percentage of incident light reflected from the vitrinite particles and bitumens in the samples were measured in comparison to a known standard of 0.589% using an X50 oil immersion objective, based on an average of at least 25 points for each sample. For geochemical analyses, representative portions of the core material were crushed in a steel mortar and extracted for approximately 72 h using an azeotropic mixture of dichloromethane (DCM) and methanol (CH 3 OH) (93:7). Asphaltenes were precipitated from a hexane dichloromethane solution (95:5) and separated by centrifugation. The fractions of the hexane soluble organic matter were separated into, saturated hydrocarbons, aromatic hydrocarbons and NSO compounds by liquid column chromatography. Saturated hydrocarbon fractions were analysed by FID-gas chromatography (HP-5MS column, temperature programmed from 40 to 300 C at a rate of 4 C/min, and then held for 30 min at 300 C). GC MS analyses were performed on a HP 5975B MSD mass spectrometer with a gas chromatograph attached directly to the ion source (70 ev ionization voltage, 100 milliamps filament emission current, 230 C interface temperature). For the analysis of biomarkers, the fragmentograms for steranes (m/z 217) and triterpanes (m/z 191) were recorded. Individual components were identified by comparison of their retention times and mass spectra with published data (Peters and Moldowan, 1993; Philp, 1985). Relative abundances of triterpanes and steranes were calculated by measuring peak heights in the m/z 191 and m/z 217 fragmentograms, respectively.

3 28 M.R. Shalaby et al. / International Journal of Coal Geology 100 (2012) Fig. 2. Generalized stratigraphic column of north Western Desert including Shoushan Basin.

4 M.R. Shalaby et al. / International Journal of Coal Geology 100 (2012) Table 1 Bulk geochemical results of Rock-Eval/TOC analysis of the solid bitumen and an effective source rock samples. Wells Samples Depth (ft) Lithology TOC wt.% Pyrolysis data S 1 (mg HC/g rock) S 2 (mg HC/g rock) S 3 (mg HC/g rock) T max ( C) PI Tut-22 Well Csh Shale Sh Shale Csh Shale Csa Bitumen-bearing sandstones C Shale Csh Coaly shale Csa Bitumen-bearing sandstones Csa Bitumen-bearing sandstones Csh Shale Cmu Shale C Shale Csa Bitumen-bearing sandstones Csa Bitumen-bearing sandstones Csa Bitumen-bearing sandstones C Coaly shale Csh Shale Csa Bitumen-bearing sandstones Csa Bitumen-bearing sandstones Csa Bitumen-bearing sandstones Csa Bitumen-bearing sandstones TOC: Total organic Carbon, wt.%. S 1 : Volatile hydrocarbon (HC) content, mg HC/g rock. S 2 : Remaining HC generative potential, mg HC/g rock. S 3 : carbon dioxide yield, mg CO 2 /g rock. PI: Production Index=S 1 /(S 1 +S 2 ). 3. Results and discussion 3.1. Petrography and occurrence of bitumen The main reservoir sandstone in the Tut-22 well forms part of the Khatatba Formation. Thinsection petrography shows that the Khatatba sandstones are coarse grained and rich in quartz, more than 95%, with a non-quartz content of around b3% (feldspar). The sandstones are cemented by calcite, kaolinite, solid bitumen (Fig. 3b d) and silica (in the form of quartz overgrowths; Fig. 3a). Therefore, the porosity of the sandstones is reduced by the cements. The quartz grains are often broken and the fractures are also cemented by carbonate or/and solid bitumen (Fig. 4a and b). Solid bitumen and kaolinite with a booklet structure fill the pore spaces of the Khatatba sandstone (Fig. 4c and d). The solid bitumen also coats authigenic kaolinite (Fig. 4c and d). The textural relationships indicate that the deposition of the solid bitumen post-dates the formation of the authigenic kaolinite. The bitumen is brittle and can be polished easily. The bitumen is fluorescing (Fig. 4 e and f) and displays reflectance values ranging from 0.42 to 0.50% Ro (Table 2). Based on the classification proposed by Alpern et al. (1994), the solid bitumen is vitribitumen (grahamite) based on reflectance values and fluorescence intensity (Fig. 4e andf) Bulk organic geochemistry Total organic carbon and pyrolysis Total organic carbon (TOC) and pyrolysis analyses (Peters and Cassa, 1994) were performed on solid bitumens and selected samples from potential source rock. The TOC results are reported as weight percentages and document the organic richness of samples (Peters, 1986). The TOC content of the analyzed samples is ranging from 0.41 to wt.% (Table 1). Measured Rock-Eval parameters (S 1,S 2, S 3 and T max ) are shown in Table 1. Rock-Eval parameters (S 1 relative to S 2 ) lend supporting evidence for migration of hydrocarbons and the depletion of the S 2 pyrolysis yield indicates that hydrocarbons have been nearly entirely released from source rock (Peters, 1986). Most of the solid bitumen samples have S 1 pyrolysis yields greater than the corresponding S 2 pyrolysis yields (Table 1), which is indicative of migrated hydrocarbons. In contrast, source rock samples have a high S 2 pyrolysis yields than the associated S 1 pyrolysis yields (Table 1), which is generally indicative of in-situ organic material although degraded bitumens can appear as S 2 hydrocarbons (Peters, 1986). Production index (PI) and pyrolysis T max were also used to estimate the nature of the hydrocarbon products (i.e., generated or migrated). The production index (PI) represents the ratio of distillable organic matter to the total amount of organic matter generated from a sample by pyrolysis [S 1 /(S 1 +S 2 )]. High production index values are probably due to migrated hydrocarbons (HasenhuÈttla et al., 2011). The production index (PI) and pyrolysis T max values of the solid bitumen represented within the pore space of the Khatatba sandstones indicate that the solid bitumen could have predominantly been generated from an effective Khatatba source rock, and subsequently migrated into the sandstone reservoir rocks as shown in Fig Molecular composition of solid bitumen The amount of soluble organic matter (SOM) together with the relative proportions of saturated and aromatic hydrocarbons, NSO compounds and asphaltenes have been calculated and tabulated (Table 2). The SOM yields range from 2834 to 6336 ppm. The SOM in samples with solid bitumen is represented mainly by asphaltenes (31 70%), whereas saturated hydrocarbons range from 12% to 27% and aromatic hydrocarbons from 11% to 30%. The amount of NSO compounds is low (7 12%). The high asphaltene content is commonly due to the presence of solid bitumen within the pore spaces of the sandstones. The percentages of different fractions are plotted in Fig. 6 in order to show the relationships and help to understand the origin and formation mechanisms of the asphaltene-rich solid bitumen within the sandstone reservoir. The results generally reveal good negative correlations between the proportions of asphaltenes and all other fractions. In contrast, positive correlations have been observed between the saturated, aromatic hydrocarbons and NSOcompounds. This may indicate that the high asphaltene content is due to the enrichment in asphaltenes (e.g. deasphalting) rather than the removal of any other fractions (e.g. biodegradation and thermal alteration). The significance of high proportions of asphaltenes will be discussed in the origin of solid bitumen section.

5 30 M.R. Shalaby et al. / International Journal of Coal Geology 100 (2012) Fig. 3. Thin section photomicrographs under transmitted light of Khatatba sandstones showing the common cements recognized in the Khatatba sandstones: (a) syntaxial quartz overgrowth; (b) calcite developed in the intergranular pore; (c) authigenic kaolinite filling in the intergranular pore spaces; and (d) coarse-grained quartz with bitumen filling intergranular porosity (black color) Biomarker distributions of the saturated fraction n-alkanes and isoprenoids Gas chromatograms of saturated fractions from representative solid bitumen samples are shown in Fig. 7a and derived parameters are listed in Table 3. The chromatograms indicate that saturated hydrocarbons are dominated by n-c 12 n-c 35 n-alkanes and isoprenoids pristane (Pr) and phytane (Ph). The n-alkane distribution shows a unimodal to slightly bimodal distribution with a predominance of medium molecular weight compounds (n-c 14 n-c 24 ). The presence of waxy alkanes (n-c 25 -n-c 35 ) with absence of odd-carbon preference (hence have low CPI values; Table 3), suggest relatively higher marine organic matter and lower terrestrial organic matter contribution (Ebukanson and Kinghorn, 1986; Murray and Boreham, 1992; Tissot et al., 1978). Acyclic isoprenoids are present in the analyzed samples with lower relative abundance compared with n-alkanes. Pristane and phytane concentrations are always lower than n-c 17 and n-c 18, thus giving distinctively low pristane/n-c 17 and phytane/n-c 18 ratios of and , respectively. In addition, the Pr/Ph ratio is one of the most commonly used geochemical parameters and has been widely invoked as an indicator of the redox conditions in the depositional environment and source of organic matter (Chandra et al., 1994; Didyk et al., 1978; Large and Gize, 1996). Organic matter originating predominantly from terrestrial plants would be expected to have high Pr/Ph >3.0 (oxidizing conditions), low Pr/Ph ratios of b0.6 indicate anoxic conditions, and values between 1.0 and 3.0 suggest intermediate conditions (suboxic conditions) (Amane and Hideki, 1997; Basent et al., 2005; Hakimi et al., 2011; Powell, 1988; Sarmiento and Rangel, 2004). The Pr/Ph ratios of the analyzed samples range from 0.71 to 1.20 (Table 3), suggesting that these solid bitumens derived from source rocks deposited in a marine environment under anoxic to suboxic conditions Triterpanes and steranes The distributions of steranes and triterpanes can be studied by GC MS by monitoring the ions m/z 217 and m/z 191, respectively. These two fragment ions are used to examine steranes (m/z 217) and hopanes (m/z 191) as well as tricyclic terpanes (m/z 191), tetracyclic terpanes (m/z 191) and diasteranes (m/z 217) (Peters et al., 2005). Overall, the observed distributions of triterpanes and steranes are very similar in all of solid bitumen samples (Figs. 8aand9a). Peak assignments are listed in Appendix A and the derived parameters are listed in Tables 3 and 4. All solid bitumen samples exhibit high proportions of hopanes relative to tricyclic terpanes. The relative abundance of n-c 29 norhopane is generally higher than that of n-c 30 hopane in most of the studied samples (Fig. 8a), with C 29 /C 30 17α (H) hopane ratios in the range of (Tables 3 and 4). The predominance of n-c 29 norhopane is frequently associated with carbonate source rocks, but this is not always the case (Waples and Machihara, 1991) and the enhanced norhopane input may also be associated with land plant input (Rinna et al., 1996). The homohopanes are dominated by the C 31 homohopane and decrease with increasing carbon number (Fig. 8a). This is thought to indicate that the solid bitumen was derived from marine source rock deposited under suboxic conditions (Peters and Moldowan, 1991). Typically such a distribution usually represents clastic facies (Obermajer et al., 1999; Waples and Machihara, 1991), and this statement is also consistent with the source rock of the analyzed solid bitumen samples. In addition, the high diasterane concentrations relative to regular steranes (Fig. 9a) also is indicative of a clay-rich source (Gürgey, 1999).

6 M.R. Shalaby et al. / International Journal of Coal Geology 100 (2012) Fig. 4. Photomicrographs of the Middle Jurassic Khatatba sandstones under transmitted light (a d) and oil immersion reflected light (polish block; e f); (a) bitumen associated with calcite filling secondary porosity (open fracture); (b) bitumen filling secondary porosity (open fracture); (c) solid bitumen with booklet kaolinite filling the pore spaces; (d) the solid bitumen coats authigenic kaolinite and fills pore space; (e) and (f) UV reflected light examination showing bright greenish-orange fluorescing migrabitumen (grahamite). Table 2 Depth of core samples, porosity (%), reflectance of solid bitumen (in % Ro), soluble organic matter (SOM) yields (ppm), relative proportions of saturated hydrocarbon fractions, aromatic hydrocarbon fractions, NSO compounds, and asphaltenes of the SOM (in wt.%). Wells Samples Depth (ft) Tut-22 Well Porosity (%) Bitumen reflectance (%) SOM yield (ppm) Saturated HC (%) Aromatic HC (%) Saturate/ aromatic Csa 6 12, Csa 11 12, Csa 12 12, Csa 18 12, Csa 19 12, Csa 20 12, Csa 30 12, Csa 33 12, NSO (%) Asphaltene (%)

7 32 M.R. Shalaby et al. / International Journal of Coal Geology 100 (2012) Fig. 5. Plot of pyrolysis T max versus production index (PI), showing the maturation and nature of the hydrocarbon products of the solid bitumen and Khatatba source rock samples. All solid bitumen samples possess consistently low Ts/Tm ratios ( ). Tm and Ts are well known to be influenced by maturation, type of organic matter and lithology (e.g. Moldowan et al., 1985; Seifert and Moldowan, 1979). Considering the source of the analyzed samples contains a mixture of land and marine-derived organic matter, the Ts/Tm ratios thus appear to be more strongly influenced by maturity rather than source input. The distributions of diasteranes and regular steranes (C 27,C 28 and C 29 ) are shown by the m/z 217 ion chromatograms (Fig. 9a). Peak assignments are listed in Appendix A and the derived parameters are listed in Tables 3 and 4. The distributions of C 27 C 29 regular steranes can be used to indicate depositional setting (Philp, 1985). The distributions of C 27 C 29 regular steranes are very similar for all samples (C 27 >C 29 >C 28 )(Table 3). The higher abundance of C 27 steranes suggests a primary contribution from marine organic matter. This is supported by sterane/hopane ratios ranging between 0.8 and 1.0 and the presence of tricyclic terpanes (Fig. 8a). In addition, these samples have C 29 20S/(20S+20R) and the C 29 αββ(αββ+ααα) ratios in Fig. 6. Cross-plots of different hydrocarbon fractions of rock extracts. The good correlations indicated that the high asphaltene contents are due to enrichment in asphaltenes and not due to the removal of any other fractions.

8 M.R. Shalaby et al. / International Journal of Coal Geology 100 (2012) the range of and , respectively, suggesting that the solid bitumen is thermally mature Oil-source rock correlation To investigate the genetic link between solid bitumen and source rock extracts, the biomarker distributions (Figs. 7 9) were compared Fig. 7. Gas chromatograms of saturated hydrocarbon fractions of the solid bitumen and the Khatatba source rock extracts.

9 34 M.R. Shalaby et al. / International Journal of Coal Geology 100 (2012) Table 3 Summary of biomarker parameters of solid bitumen samples extracts in the Tut Field, Shoushan Basin. n-alkane and isoprenoids ratios Triterpanes and terpanes (m/z 191) Steranes and diasteranes (m/z 217) Sterane/ hopane Samples ID Regular sterane C 29 / Diasterane/regular C 27 sterane ratio C 27 C 28 C 29 Sterane C 29 ββ/ (ββ +αα) Sterane C 29 20S/ (20S +20R) 30 Moretane/ 30 hopane C 29 /C 30 hopane ratio Ts/ Tm C 32 22S/ (22S+22R) RatioPh/ n-c18 Pr/ n-c17 CPI Pr/ Ph Csa Csa Csa Csa Csa Csa Csa Csa CPI =(2(C23+C25+C27+C29)/[C22 +2(C24 + C26+C28) +C30]). Pr: pristane. Ph: phytane. using key biomarker parameters (Table 4) and supported by plots of Pr/n-C 17 versus Ph/n-C 18 and C 29 sterane 20S/(20S+20R) versus αββ(αββ+ααα) (Figs. 10 and 11, respectively). Four of the effective Khatatba source rock samples (Shalaby et al., in press) have a largely unimodal distribution of n-alkanes with low concentrations of pristane and phytane isoprenoids (Fig. 7b). The Pr/Ph ratios range from 1.20 to 1.66 (Table 4), indicating suboxic depositional conditions. Pristane and phytane concentrations are always less than n-c 17 and n-c 18, thus giving distinctively low pristane/n-c 17 and phytane/n-c 18 ratios, which are relatively consistent with observations for the solid bitumen (Fig. 10). The diasterane/sterane and sterane/hopane ratios were also evaluated (Table 4), and relative homohopane abundances decreased from C 31 to C 35, similar to what we seen in the migrated solid bitumen as mentioned above (Figs. 8 and 9). The C 29 sterane 20S/(20S+20R) and αββ(αββ+ααα) ratios differ from sample to sample, these ratios are mainly used as indicators of maturity but can be used in source rock-migrated material correlation as well (Fig. 11). The relative abundance of the C 27,C 28, and C 29 steranes was also determined for use in oil-source rock correlation. The samples show a range of values, with an average of 44% C 27, 24% C 28, and 32% C 29, relatively consistent with observations for the solid bitumen (Fig. 12). These ratios and other biomarker ratios (e.g. Ph/Pr, pristane/n-c 17, phytane/n-c 18, sterane/hopane) strongly reflect a close genetic relationship between the solid bitumen in the Khatatba sandstones and the Khatatba source rocks 3.5. Origin of solid bitumen (migrabitumen) Solid bitumen can be derived from any one of the following precursors: crude oil, asphaltenes, heavy bitumen or tar mats (Stasiuk, 1997), and expelled from source rocks in a mobile form. There are several possible geological processes leading to the deposition of solid bitumen in reservoirs. The principal processes of solid bitumen formation have been discussed in the literature, including thermal alteration, oil mixing, deasphalting, and biodegradation (Huc et al., 2000; Hunt, 1996; Larter et al., 1990; Leythaeuser and Rückheim, 1989; Rogers et al., 1974; Wilhelms and Larter, 1994, 1995). One mechanism responsible for solid bitumen formation is direct thermal cracking of petroleum hydrocarbons which usually occurs at great depth with a geological temperature reaching 170 C or higher (Huc et al., 2000; Milner et al., 1977; Waples, 2002). Hence, thermal maturity assessments also were necessary to clarify whether or not the formation of the solid bitumen in the Khatatba reservoir was related to the thermal degradation of the petroleum hydrocarbons. Thermal maturity was evaluated based on vitrinite reflectance (R o ) and burial history modeling (Shalaby et al., 2011). Based on the burial/thermal histories models studied by Shalaby et al. (2011), the Khatatba reservoir has a temperature of C in the present day as shown in Fig. 13. The geothermal gradient in the basin show that the temperature of the maximum burial did not exceed 150 C (Fig. 13). Therefore, the Khatatba petroleum hydrocarbons originated from source rocks, with no evidence for in-reservoir thermal alteration. Biodegradation may occur in an oil reservoir, and the process dramatically affects the fluid properties of the hydrocarbons (e.g., Miiller et al., 1987). Specifically, oil biodegradation typically increases the asphaltene content (asphaltene-rich solid bitumen). The early stages of oil biodegradation are characterized by the loss of n-alkanes or normal alkanes followed by loss of acyclic isoprenoids (e.g., pristane and phytane). Compared with those compound groups, other compound classes (e.g., highly branched and cyclic saturated hydrocarbons as well as aromatic compounds) are more resistant to biodegradation (Larter et al., 2005). In this study, geochemical data exclude biodegradation as possible processes for the formation of the solid bitumen in the Khatatba sandstone reservoir. The solid bitumen contains a complete suite of n-alkanes in the low-molecular weight region and

10 M.R. Shalaby et al. / International Journal of Coal Geology 100 (2012) Fig. 8. The m/z 191 mass fragmentograms of saturated hydrocarbon fractions of the solid bitumen and the Khatatba source rock extracts. acyclic isoprenoids (e.g., pristane and phytane; Fig. 8a). The solid bitumens generally contain more saturated hydrocarbons than aromatic hydrocarbons with saturated/aromatic hydrocarbons ratios >1 (Table 2). Therefore, there is little or no sign of biodegradation in the Khatatba reservoirs. Based on similar biomarker distributions, we propose that the solid bitumen in the Khatatba sandstones was derived from petroleum hydrocarbons originating from the Khatatba source rocks (Table 4). Among the possible mechanisms described in previous sections, biodegradation and thermal alteration do not appear to be

11 36 M.R. Shalaby et al. / International Journal of Coal Geology 100 (2012) Fig. 9. The m/z 217 mass fragmentograms of saturated hydrocarbon fractions of the solid bitumen and the Khatatba source rock extracts. responsible for the formation of the solid bitumen in the Khatatba reservoirs. In-reservoir deasphalting was more probably responsible for precipitation of the solid bitumen in the high-porosity and permeable sandstone reservoir. Considering that kaolinite has a very high adsorption capacity for asphaltenes (e.g. Pernyeszi et al., 1998), natural deasphalting due to adsorption onto kaolinite surfaces is an obvious mechanism (Sachsenhofer et al., 2006). The close relationship between solid bitumen and kaolinite within the Khatatba sandstones is obvious (Fig. 4c and d). This is indicated that the natural deasphalting due to adsorption onto clay (kaolinite) surfaces is probably responsible for precipitation of the solid bitumen in sandstone of the Khatatba

12 M.R. Shalaby et al. / International Journal of Coal Geology 100 (2012) Table 4 Summary of biomarker parameters of the solid bitumen and effective Khatatba source rock extracts. Samples ID Solid bitumen a Reservoir/ source rocks age Middle Jurassic Khatatba sandstones CPI Pr/Ph Pr/ n-c17 Ph/ n-c18 C29/C30 hopane ratio Sterane C29 20S/ (20S+ 20R) Sterane C29 ββ/ (ββ+α α) Regular sterane C29/C27 Diasterane/ C27 C28 C29 regular sterane ratio Sterane/ hopane ratio (8) a (8) a (8) a (8) a (8) a (8) a (8) a (8) a (8) a (8) a (8) a (8) a (8) a Csh2 b Middle Jurassic Khatatba source rock Sh3 b Csh4 b Csh10 b a b Number of data analyzed from this study. Same samples from Shalaby et al. (2012a). reservoir. However, it is not necessarily the only one whereby gas injection related asphaltene-rich bitumen precipitation is also a considered possible mechanism (Wilhelms and Larter, 1995). Gas injection into a reservoir that contains oil under-saturated with respect to gas can cause asphaltene precipitation (Milner et al., 1977; Wilson et al., 1936). Gas injection results in compositional changes, reducing the overall solvent capacity of the oil, which in turn decreases asphaltene solubility (Wilhelms and Larter, 1994). The origin of gases in the Khatatba reservoir is unclear, but possible sources for gas in the Shoushan Basin include Khatatba and Ras Qattara shales with Type III kerogen (Shalaby et al., 2011) or Alam El-Bueib Type III kerogen (Shalaby et al., 2012). Thus, gases were probably generated from Alam El-Bueib Type III kerogen or older source rocks (Khatatba and Ras Qattara) in the Shoushan Basin during the mature and late mature stages of hydrocarbon generation (Shalaby et al., 2011, 2012). 4. Conclusion Based on the results obtained from this integrated study, the following conclusions can be made with regard to the origin and formation of solid bitumen in the Middle Jurassic Khatatba sandstones in the Tut Field, Shoushan Basin. (1) The Khatatba sandstones have a good reservoir quality and the porosity and permeability are highly variable throughout the reservoir because of the occurrence of impermeable solid bitumen and cementation by calcite and kaolinite. Fig. 10. phytane to n-c 18 alkane (Ph/n-C 18 ) versus pristane to n-c 17 alkane (Pr/n-C 17 ) plot (modified after Shanmugam, 1985). Fig. 11. Cross-plot of sterane biomarker parameters sensitive to thermal maturity of the solid bitumen and Khatatba source rock extracts. Fig. 12. Relationship between regular sterane compositions, source input and depositional environment for the analyzed Khatatba samples (modified after Huang and Meinschein, 1979).

13 38 M.R. Shalaby et al. / International Journal of Coal Geology 100 (2012) Fig. 13. Burial history curves with palaeo-temperature zones in the Shams Field, Shushan Basin showing geothermal gradient of the Khatatba Formation (bold lines) (after Shalaby et al., 2011). (2) The solid bitumen in the Khatatba reservoir is fluorescing, with measured reflectance values ranging from 0.42 to 0.50% Ro. The bitumen is classified as vitribitumen (grahamite). (3) Core extracts from the Khatatba reservoir, especially solid bitumen, are dominated by asphaltenes with significant amounts of saturated and aromatic hydrocarbons and low amount of NSO components. (4) There are no differences in the molecular composition of the saturated hydrocarbons in the extracts of solid bitumen and Khatatba source rocks. The GC fingerprints and biomarker parameters indicated that the solid bitumen was derived from a source rock that was deposited in slightly anoxic to suboxic conditions and contained marine organic matter. These results suggest that the most likely source of the solid bitumen is the organic-rich shales of the Khatatba Formation. (5) The temperature in the reservoir shows that thermal alteration was not a factor in the formation of solid bitumen. (6) Organic geochemical results exclude that biodegradation was responsible for the deposition of solid bitumen in the Khatatba reservoir. The data imply that the reservoir oils formed the bitumen by natural deasphalting. Adsorption onto kaolinite clay surfaces played a major role in the fixation of asphaltenes and during deasphalting. Gas injection from Khatatba Type III kerogen or deeper source rocks may have contributed to bitumen precipitation. Acknowledgments The authors would like to thank the Khalda Oil Company, Egypt for providing the rock samples for this study. The authors are most grateful to the Department of Geology, University of Malaya for providing facilities for organic geochemical and petrographic analyzes to complete this research. Review by Mr. Peter Abolins improved the revised manuscript and is profoundly acknowledged. Special thanks are offered to anonymous referees for their careful and useful comments that improved the revised manuscript. Appendix A Peak assignments for alkane hydrocarbons in the gas chromatograms of aliphatic fractions in the m/z 191 (I) and 217 (II) mass fragmentograms Compound Abbreviation (I) Peak no. Ts 18α(H),22,29,30-trisnorneohopane Ts Tm 17α(H),22,29,30-trisnorhopane Tm 29 17α,21β(H)-norhopane C29 hop 30 17α,21β(H)-hopane hopane 3M 17 β,21α (H)-Moretane C30Mor 31S 17α,21β(H)-homohopane (22S) C31(22S) 31R 17α,21β(H)-homohopane (22R) C31(22R) 32S 17α,21β(H)-homohopane (22S) C32(22S) 32R 17α,21β(H)-homohopane (22R) C32(22R) 33S 17α,21β(H)-homohopane (22S) C33(22S) 33R 17α,21β(H)-homohopane (22R) C33(22R) 34S 17α,21β(H)-homohopane (22S) C34(22S) 34R 17α,21β(H)-homohopane (22R) C34(22R) 35S 17α,21β(H)-homohopane (22S) C35(22S) 35R 17α,21β(H)-homohopane (22R) C35(22R) (II) Peak no. a 13β,17α(H)-diasteranes 20S Diasteranes b 13β,17α(H)-diasteranes 20R Diasteranes c 13α,17β(H)-diasteranes 20S Diasteranes d 13α,17β(H)-diasteranes 20R Diasteranes e 5α,14α(H), 17α(H)-steranes 20S ααα20s f 5α,14β(H), 17β(H)-steranes 20R αββ20r g 5α,14β(H), 17β(H)-steranes 20S αββ20s h 5α,14α(H), 17α(H)-steranes 20R ααα20s References Alpern, B., Oudin, J.L., Pinheiro, H.J., Pittion, J.L., Zhu, X., Me thode d'e tude optique des hydrocarbures extraits et fixe s dans la re sine des sections polies de roches. Influence de la richesse en huile sur la reflectance des keroge`nes. In: Curnelle, R., Se ve rac, J.-P. (Eds.), Pe trologie Organique, Colloque International des Pe trographes Organiciens Francophones, Pau, : Bulletin des Centres de Recherches Exploration-Production Elf Aquitaine, vol. 18. Publication Spe ciale, pp

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