Abstract
The fluid distribution is considerably influenced by the reservoir homogeneity. This study analyzes carbonate reservoir heterogeneity and hydrocarbon accumulation processes in the Khasib reservoirs in AB oilfield in the Middle East to discuss factors controlling the distribution of fluid and the effects of this distribution on the productivity of single wells. The Khasib reservoirs in the AB oilfield show uniform vertical distributions, with a large difference in the longitudinal pore throats, and the upper part of the reservoir is better than the lower one. Because the hydrocarbon accumulation is multiphasic, the heterogeneity of crude oil is based on whether traps are formed in the early or late stage of source rock formation during accumulation. Moreover, the longitudinal physical differences in crude oil properties are mainly attributed to the longitudinal differences in the pore throats. The difference in the pore throat and physical properties of crude oil affords differences in the productivity of horizontal wells in different subzones.
1 Introduction
High-viscosity heavy oil is widely distributed throughout the world, and its genesis is mainly divided into primary and secondary heavy oil reservoirs. Primary heavy oil is formed by the direct accumulation of immature to low-maturity crude oil generated in the early stages of source rocks. Secondary heavy oil is conventional oil accumulated in the early stage and is subsequently altered, for example, through repeated long-distance migration and biodegradation [1,2,3,4,5]. Some oil reservoirs are formed through a combination of both the sources: immature or low-maturity crude oil was captured in the early stages of trap formation and conventional crude oil subsequently accumulated in the same reservoir. Thus, the early heavy oil was diluted and transformed into thicker normal crude oil [6,7]. Based on the fluid characteristics of Khasib reservoirs of AB oilfields in the Middle East, this study discusses the influence of reservoir heterogeneity on fluid distributions and production behavior. Currently, certain results have been reported for the Cretaceous Khasib Formation in the AB oilfield. Through a biomarker comparison, Du et al. inferred that the oil source in the AB oilfield is the Chia Gara Formation and proposed several charging phases from the Late Cretaceous to the Neogene [8], with generally decreasing oil viscosities over time as the source became more thermally mature. Based on the microscopic observation, fluorescence color, infrared spectrum, and homogenization temperature measurement of fluid inclusions, Fu et al. hypothesized four periods of fluid activities related to oil charging and accumulation in the oilfield [9]. Chen et al. described the distribution of heavy oil in the reservoir by recording the corresponding characteristics [10]. Other researchers have focused on the Cretaceous Khasib Formation in the Balad and East Baghdad oilfields in central Iraq. The Khasib Formation primarily consists of bioclastic limestone, and the reservoir space is composed of intercrystalline dissolved pores and microfractures, which later underwent dissolution. Because of a strong vertical heterogeneity in the Khasib reservoir, which considerably impacts oil generation and storage, this study discusses the difference in the accumulation of the Khasib reservoir based on its detailed investigation [11,12].
2 Geological setting
2.1 Structural location and stratigraphy
The AB oilfield is located in southern Iraq between the towns of Nomina and Al-Kut, 180 km southeast of Baghdad and within the main oil reservoir belt in Iraq [13,14]. Structurally, the oilfield lies to the southwest of the deformation zone of the Zagros fold, within the Mesopotamian zone (Figure 1). The Khasib reservoirs of AB oilfields are characterized by a low-amplitude elongate anticline structure, striking along the northwest–southeast direction. The oilfield has three high tectonic landforms (in the northwest, center, and southwest), but the structuration is gentle with small dip angles.
Structural location of the AB oilfield (modified according to Iraq’s petroleum geology and exploration potential).
The main stratigraphy of the AB oilfield comprises 15 formations (Figure 2), presented below from top to bottom:
Stratigraphic context of the AB oilfield.
Paleogene: Allji, Dammam, and UP. Kirkuk Formations.
Upper Cretaceous: Ahamadi, Rumaila, Mishrif, Khasib, Tanuma, Sadi, Hartha, and Shiranish Formations.
Lower Cretaceous: Zubair, Shuaiba, Nahrumr, and Mauddud Formations.
The thick Cretaceous stratigraphy of the AB oilfield includes four main carbonate reservoir intervals, corresponding to the Mauddud, Rumaila, Mishrif, and Khasib Formations. This study focuses on the Khasib Formation, which forms the main development target of the oilfield. The Khasib Formation can be divided into four zones (from top to bottom: Kh1, Kh2, Kh3, and Kh4). Kh2 is the main reservoir section and has been subdivided from top to bottom into Kh2-1, Kh2-2, Kh2-3, Kh2-4, and Kh2-5 subzones [15]. The Khasib Formation in the AB oilfield is identified as a whole third-order sequence. The maximum flooding surface, characterized by high gamma ray (GR), spontaneous potential (SP), and low density, is identified in the shale interval developed in the middle of the Kh4 Member. The lower Kh4 is identified as a transgressive systems tract, composed of argillaceous limestone and planktonic foraminiferal limestone formed in the outer ramp and shelf environments. The upper Kh4, Kh3, Kh2, and Kh1 members are identified as the highstand system tract. The upper Kh4, Kh3, Kh2-5, and Kh2-4 are mainly composed of planktonic foraminiferal packstone and wackestone formed in the outer ramp. The Kh2-3, Kh2-2, and Kh2-1 are composed of packstone and grainstone formed in mid-ramp environment. Kh1 is composed of packstone intercalated in argillaceous wackestone and mudstone formed in the inner ramp environment [16].
The source rock that charged the AB oilfield was primarily the Upper Jurassic Chia Gara Formation [17], the reservoir is the Upper Cretaceous Khasib gentle-slope facies limestones, and the top seal is formed by mudstones of the Tanuma Formation. This makes the Khasib reservoir a good source–reservoir–cap relationship.
2.2 Depositional history and evolution of tectonic traps
The AB oilfield is located in the central part of the Mesopotamian Basin on the northern stable shelf area of the Persian Gulf Basin, which lies on the northern edge of the fragmenting Gondwana supercontinent. The Mesopotamian Basin was dominated by carbonate deposition during the Cretaceous. Most of the Cretaceous carbonate rocks of the AB oilfield were formed in a medium- to low-energy, gently sloping environment. Based on lithological characteristics and assemblages, three main sedimentary subphases can be identified: outer gentle slopes, banks, and inner gentle slopes [18,19].
The seismic reflection interface uses synthetic seismic records, and the interface tracking is performed in the study area. The structural evolution of the target reservoir zone can be assessed by leveling the horizons of the Damman and Lower Fairs (Figure 3). Sedimentation continued steadily after the deposition of the Khasib Formation. At the end of the Cretaceous, shear extrusion associated with the convergence of the Indian and Arabian plates began to form low-amplitude tectonic structures in the east-central part of the study area. As tectonic convergence and extrusion continued, the resulting tectonic structures became enhanced and a microamplitude tectonic trap was formed in the east-central part when the Dammam Formation was deposited [20].
Tectonic evolution and tectonic features of the AB oilfield.
At the beginning of the Neotectonic movement, the convergence between the Eurasian and Arabian plates into the Cenozoic closed the Neo-Tethys Ocean and led to the northeast–southwest tectonic extrusion. This further modified the structural features of the study area (after deposition of the Lower Fairs), affording a backslope structure with the central part of the study area forming a high point. This tectonic transformation continued through the Middle Miocene and under the strong effect of the Neotectonic movement, eventually settled into an elongated lower slope with a northwest–southeast alignment, with high points in the southeast, center, and northwest. The highest point of the backslope is the southeastern high. The entire backslope is gently inclined (a dip of less than 2°) and shows two asymmetrical flanks, with the northeast flank slightly steeper than the southwest one (Figure 3). The closure height is ∼60 m, and the closure area is 160 km2.
2.3 Diagenetic evolution and pore structure
The Khasib Formation concerned in this article is still in the middle-shallow burial stage, the sedimentary strata are relatively new, the structure is relatively stable, and the diagenetic evolution and tectonic activities experienced by the reservoir have not completely changed the pore throats formed in the original depositional environment spatial appearance. The pore-throat space of the reservoir is still based on the original pore-throat space and is the result of the diagenetic evolution and the short-term epigenetic karstification during the burial process after the depositional period [21]. Dissolution pores account for an important proportion of the total pore space, and at the same time, dissolution plays an important role in expanding and dissolving pore throats and plays an important role in the transformation of pore structure. Therefore, based on the above analysis and test data, it is believed that the intergranular dissolved pores, moldic pores, intragranular dissolved pores, and other dissolved pores are formed by the selective dissolution of the reservoir during the contemporaneous or quasi-contemporaneous period under the mixing action of atmospheric freshwater and seawater. It constitutes the basis of the pore-throat space of the reservoir and determines the difference and type of the pore-throat structure of the reservoir. However, the epigenetic karstification exposed by the later tectonic uplift is the modification in the pore-throat structure formed in the earlier stage. This may be related to the relatively short duration of karstification.
Therefore, we believe that the main factors causing the difference in reservoir pore structure are the rock fabric and the dissolution of the contemporaneous or quasi-contemporaneous period, while the epigenetic karst has a certain transformation effect, and the influence of other diageneses is relatively weak. The pore-throat structure of the reservoir is based on the original pore formed by sedimentation by contemporaneous or quasi-contemporaneous dissolution and reformation and is formed by the later epigenetic karstification [16].
3 Methodology
For the type and composition of the reservoir rocks and minerals, the combination of conventional thin-section identification and description and electron probe quantitative analysis was used to determine the rock composition and mineral composition. The petrophysical data used include conventional core analyses and mercury injection test performed by commercial laboratories. The samples were selected to represent the ranges of depth and lithofacies in each of the cored intervals. The thin sections were described using a set of standard categories of information recorded in spreadsheet format. Biotic assemblages, cement, and stylolites were noted by a system of numerical scoring. Percentages of visible porosity and total cement were estimated using comparator charts.
4 Results
4.1 Reservoir characteristics
Existing research indicates that the study area is located in a carbonate, gently sloping sedimentary environment [22]. Within each small layer within the AB oilfield, no obvious changes are observed in the lateral depositional environment, so all subzones in the field are in the same sedimentary microfacies zone. Moreover, diagenesis did not induce considerable differences in the reservoirs. The Kh2 layer of the AB oilfield reservoir is primarily composed of a set of open-sea, gently sloping facies depositions. The overall reservoir performance is poorer from the lower outer, gently sloping deposits (comprising planktonic mudstone and limestone) of the lower Kh2-5 subzone and improves into the Kh2-1 inner, gently sloping subzone (deposits of sand-clastic granular limestone and sand-clastic muddy limestone) [23,24]. The lithology of the sedimentary rocks developed in the Kh2 layer primarily includes sand-clastic granular limestone, sand-clastic mud-grain limestone, bioclastic mud-grain limestone, bioclastic algal mud-grain limestone, bioclastic marl, and planktonic marl (Figure 4).
Reservoir quality characteristics of the Kh2 zone.
4.1.1 Kh2-5
This subzone is mainly deposited on the lower part of the outer gentle slope. The lithology is dominated by striped grain marlstones with a matrix-supporting structure and planktonic foraminifera as the principal grains. The reservoir space comprises micropores and intragranular pores, with an average porosity of 23.5%. Overall, the pore throats are extremely narrow (<0.04 μm) and the average permeability is 1.47 mD. The core shows that this subzone exhibits a low oil content, and the result of the oil and gas test shows a dry layer.
4.1.2 Kh2-4
This subzone is dominated by striped bioclastic mudstone–limestone and planktonic granular mudstones and is deposited on the upper and outer gentle slopes. The lower part mainly comprises planktonic granular marlstone with a bioclastic content of ∼30–40% and an upwardly increasing component of algal debris. The total content of bioclasts and algal debris is in the range of 55–65%, locally exceeding 70%. The storage space is mainly composed of micropores and intragranular pores, with few algal–mold-enlarged pores and intergranular pores, showing an overall average porosity of 25%. The mercury injection test shows that the reservoir drainage pressure in this section is high and the dominant pore throats of the reservoir range between 0.04 and 1 μm. Generally, pore throats are finer in the lower part than in the upper part. The average permeability is 3.5 mD.
4.1.3 Kh2-3
The primary lithology of this subzone is clumped green algal mudstone–limestone with a high content of green algal debris, with algal shoal deposits with moderate and gentle slopes. White clumps are filled with micrites that appear as compact clumps, with only a few late-stage dissolved cavities and microcracks. Pores of algal clastic limestone are developed among the clumps. The inner pores of the algal grains are the most common (with pore diameters up to 1.5 mm), followed by foraminifer body cavities, and occasional grain-moldic pores and microcracks. The pore sizes range between 0.15 and 0.50 mm, with an average porosity of 24.8%. Based on the mercury injection test, the reservoir drainage pressure in this subzone is medium–high and the throat sizes are mainly 0.04–4 μm. The reservoirs in this section are highly heterogeneous with an uneven pore distribution. The pore throats are predominantly microfine throats with a few medium-thick throats, and the permeability ranges from 0.5 to 476 mD, with an average of 16.5 mD. The reservoir properties show that the production capacity of this subzone is slightly higher than that of the Kh2-4 subzone.
4.1.4 Kh2-2
This subzone comprises bioclastic mud, sand-clastic mud, and algal mud limestones, with bioclastic shoal deposits in the inner gentle slope. The lithology is homogeneous with well-developed pores (primarily intergranular and intragranular pores) and an average porosity of 24%. The mercury injection test shows a moderate displacement pressure with medium and large pore throats (dominant throat size: 1–4 μm). The distribution of pore throats is homogeneous, and the displacement pressure is low (0.06–0.3 MPa). The permeabilities range between 3 and 30 mD, with an average of 14.1 mD. In production tests, Kh2-2 outperforms Kh2-3 in terms of production capacity.
4.1.5 Kh2-1
This subzone includes sand-clastic granular, sand-clastic mud-grain, and bioclastic mud-grain limestones, with bioclastic shoal deposits on the inner gentle slope. The lower part of this subzone shows the highest rock fragment content, whereas the upper part is dominated by bioclastic and sand debris; the overall lithology is uniform. The lower section mainly develops intergranular pores, and the upper section develops intergranular, intragranular, and moldic expansion pores. The average porosity of the upper section (20%) is slightly higher than that of the lower section (19%). The mercury injection test shows a medium-to-low displacement pressure and dominantly coarse pore throats (1–25 μm). Furthermore, the physical property test results of the lower part are considerably better than the upper part. The average permeability through the lower part is 249 mD, in contrast to 10.5 mD in the upper part. The production testing confirmed that this subzone shows the highest production capacity, particularly the high permeability section at the underlying strata.
4.2 Fluid distribution characteristics
The current burial depth of the Khasib reservoir of AB oilfield is ∼2,500–2,800 m, and the geothermal gradient is 2.26°C/100 m, which is a normal or slightly low formation temperature gradient. The reservoir pressure coefficient (ratio of original reservoir pressure to hydrostatic column pressure) ranges from 1.12 to 1.14, which can indicate a normally pressured system.
The density of the surface condition crude oil in the reservoir ranges from 0.867 to 0.981 g/cm3, with the main distribution range of 0.884–0.94 g/cm3, which can be classified as medium density crude oil. On the plane, the density of crude oil is high in the southeast high point (average: 0.931 g/cm3), somewhat lower in the central area (average: 0.919 g/cm3), and lowest in the northwest (average: 0.895 g/cm3). The overall production performance gradually decreases from the southwest to the northeast.
The oil viscosity shows similar characteristics. Crude oil in the southwest shows an average viscosity of 28.37 cP at 80°C. In the central area, it is 9.91 cP, and in the northwest area, the average viscosity is 5.97 cP. Similarly, the asphaltene content is high in the southeast and low in the northwest. The average asphaltene content is 7.2% (main range: 5.3–10.7%) in the southeast, 3.5% (main range: 1.21–6.64%) in the central part, and 2.6% (main range: 0.39–2.89%) in the northwest, which is the lowest.
The production of wells in the southwest shows some significant vertical differences in the physical properties of crude oil in each subzone. In particular, oil produced from the upper subzones is less dense than that obtained from the lower subzones. In particular, the density of crude oil in the Kh2-1 and Kh2-2 subzones is low (0.929 and 0.930 g/cm3, respectively). In contrast, the density of crude oil in the Kh2-3 and Kh2-4 subzones is relatively high (0.935 and 0.935 g/cm3, respectively). The corresponding test results show that the oil viscosity in the upper subzones is lower than that in the lower subzones, with values 11.41, 12.34, 17.89, and 31.65 cP for Kh2-1, Kh2-2, Kh2-3, and Kh2-4, respectively.
5 Discussion
5.1 Spatial variations in oil properties
Geochemical analysis suggests that the AB oilfield mainly comprises source rocks of the Upper Jurassic Chia Gara Formation. This set of source rocks entered the immature to low-maturity oil hydrocarbon generation stage at the end of the Cretaceous. With continuing subsidence and deeper burial stage, the source rock entered the main hydrocarbon generation window, producing and expelling large volumes of crude oil. It has now reached the high maturity stage [30].
Reservoir formation studies have shown that at the end of the Cretaceous, the source rocks were producing immature to low-maturity oil (with heavy crude and a high asphaltene content) [23,24,25]. A subtle structural trap was initially formed in the southeastern part of the oilfield, and the early hydrocarbons migrated through the faults into the trap to form the oil reservoirs. As the depth of the formation increased, the source rocks entered the main hydrocarbon generation stage and the entire oilfield trap pattern was established. The conventional crude oil was produced during this main hydrocarbon generation stage, accumulated in the enhanced trap, and mixed with the immature to low-maturity crude oil accumulated in the southeast. Because the early immature to low-maturity crude oil had a high asphaltene content and specific gravity, after mixing with the normal crude oil, the crude oil in the southeast showed high density, asphaltene content, and viscosity. Although the later tectonic movement modified the trap, it only strengthened the existing structure and the overall pattern did not change considerably. Therefore, the late adjustment had a slight impact on the early distribution characteristics of the crude oil. The crude oil in the southeastern part of the oilfield retained its high asphaltene content, specific gravity, and viscosity, whereas that in the northwestern part showed low asphaltene content, specific gravity, and viscosity with flat distribution characteristics (Figure 5).
Simplified reservoir evolution model for the Kh2 zone. (a) Early Paleogene, (b) early Neogene, and (c) now.
5.2 Vertical heterogeneity
As described in Section 3, the Khasib Formation shows considerable reservoir heterogeneity [26]. The Kh2-1 and Kh2-2 subzones are dominated by intergranular and dissolution pores, with large pore throats (size: 1–4 μm). The reservoir spaces of the Kh2-3 and Kh2-4 subzones are dominated by intragranular pores, algal–mold pores, and micropores, with locally developed dissolution pores. The pore throats are relatively narrow and dominated by throat diameters 0.04–1 μm. Some medium-thick pore throats are developed in the Kh2-3 subzone.
Furthermore, the accumulation analysis reveals that the Khasib reservoir has undergone two stages of oil and gas charging and adjustments. The first stage involved the charging of immature to low-maturity oil from the end of the Cretaceous to the early Paleogene. The second stage involved the filling of normal crude oil from the late Paleogene to the early Neogene [27,28]. The early charging accumulated mainly in the southeast of the oilfield to form a paleoreservoir, which was later diluted by normal crude oil. The Kh2-1 and Kh2-2 subzones were characterized by large pores and coarse pore throats, allowing the mixing and dilution of different oil charges. In contrast, the Kh2-3 and Kh2-4 subzones showed relatively small pore diameters and fine pore throats, making oil mixing and dilution less effective. Therefore, after the second recharging of crude oil and subsequent reservoir adjustment, a lower proportion of the early-stage oil (immature to low-maturity oil) remained in the upper reservoir interval (Kh2-1 and Kh2-2). In the lower subzones (Kh2-3 and Kh2-4) where mixing was less effective, the proportion of the early-stage oil remained higher. The asphaltene content, viscosity, and density of the crude oil are higher in the lower, less permeable parts of the reservoir.
5.3 Controls on well performance
Under production, the Khasib Formation in the AB oilfield behaves as a typical edge-water, layered reservoir. The thickness and physical properties of each zone remain uniform across the field [29,30,31]. Vertically, there are considerable facies-related differences in the physical properties between the subzones. The pore-throat structure of the upper subzones is significantly better than that of the lower subzones. Accordingly, horizontal wells developing in the Kh2-1 are significantly more productive than those in the Kh2-4. For example, wells WN5-3H and WN10-5H are closely spaced and their horizontal sections have the same length. However, well WN5-3H is located in Kh2-1, whereas well WN10-5H is located in Kh2-4. In terms of productivity, the initial output of well WN5-3H was more than 2,000 oil barrels, whereas well WN10-5H produced less than 800 oil barrels (Figure 6). This difference is because of the sedimentary face that the upper reservoir pore throat is better than the lower reservoir pore throat.
Productivity differences between horizontal wells located in the upper (Kh2-1) and lower (Kh2-4) subzones in the northwestern part of the study area.
The horizontal wells located in the upper subzone show an average initial production of 1,545 barrels/day in the southeast and 1,504 barrels/day in the northwest, indicating an insignificant productivity difference. This is consistent with the distribution characteristics of the reservoirs in the southeast and northwest, with similar pore-throat structures and oil properties.
For horizontal wells located in the lower subzones, oil production is difficult in most wells in the southeast or the production is extremely low. However, horizontal wells in the northwest show high initial production rates (average: ∼800 barrels/day). The pore-throat structure of the subzones is similar in both areas, indicating that the pore-throat structure is not the main controlling factor. Moreover, the fluid properties show more differences between the two areas: the density, asphaltene content, and viscosity of oil in the lower subzones in the southeast are higher than those in the northwest, making oil production difficult in southeastern wells. The differences in the well productivity in the lower reservoir between the two areas are attributed to differences in oil properties.
6 Conclusions
The main productive section of the Khasib Formation shows strong vertical heterogeneity between different reservoir subzones but little horizontal heterogeneity within each subzone across the AB oilfield. The upper reservoir is typified by coarse pore throats and good permeability, whereas the lower reservoir shows fine pore throats and relatively poor permeability.
The oil products are heterogeneous both vertically and horizontally across the field. The asphaltene content, density, and viscosity of the crude oil in the southeast are higher than those in the northwest. The asphaltene content, density, and viscosity of oil in the upper part of the southeast region are lower than those in the lower part of the southeast region.
Immature to low-maturity oil remains mainly concentrated in the early traps in the southeast, resulting in higher asphaltenes, density, and viscosity of oil in the southeast of the field than in other areas. The dilution and displacement of the early-stage oil by more mature oil during a later charge phase was more effective in zones with a higher pore-throat thickness and less effective in less permeable zones. The differential dilution effect resulted in a lower asphaltene content, density, and viscosity of oil in the higher reservoir zones than in the lower ones.
The main reason for the vertical difference in the productivity of single wells in the northwest is that the upper part of the reservoir has larger pore throats than the lower part of the reservoir. The pore throats in the upper part of the southwest are larger than those in the lower part, and the crude oil in the upper part is better than that in the lower part, which is the main reason for the difference in the vertical production capacity.
Acknowledgments
This work was supported by the National Science and Technology Major Special Project “Research and Application of Key Technologies for Waterflooding Development of Large-scale Bioclastic Limestone Reservoirs in Iraq” (2017ZX05030-001).
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Author contributions: Qiang Wang is the main researcher and writer of this article. Tao Wen provided corresponding support in research technology and research methods. Hongxi Li and Jun Xin were responsible for the research on reservoir correlation. Xingzhi Wang provided professional suggestions to the thesis and made specific changes to the presentation. Xinyao Zeng, Li Sun, Chunpu Wang, and Yuezong Zhou were responsible for the basic research and drawing modification in this article.
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Conflict of interest: Authors state no conflict of interest.
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