The geological factors responsible for the compartmentalisation and the heterogeneity phenomena: a case study from the lower Zubair reservoir in Bahrah Field, Kuwait

ABSTRACT

This study investigates the effect of compartmentalisation in the Lower Cretaceous Zubair Formation in the Bahrah Field in Kuwait, with proven plays’ success ranging from 50 to 60% due to irregular trapping configurations and fluid retention resulting from reservoir compartmentalisation and heterogeneity. An integrated analysis was conducted, including facies mapping, core data, sedimentological and petrographic assessments, pressure measurements and fluid contacts correlated with the structure map that was subjected to cross-fault juxtaposition analysis to test fault sealing capability. It’s found that the main reservoir units Z10 and Z23 are trapped on the upper down-dip side of the Bahrah Anticline by a set of NW-SE trending faults exhibiting effective sealing. Vertically, the reservoirs are sealed by internal Zubair shales. The Z10 unit is highly compartmentalised by strong lateral sealing from the Ratawi shale, while the Z23 unit experiences some hydrocarbon leakage through fault planes. Core data indicate reservoirs have an average porosity of 14.2% (7.6–20%), shale volume of 12.8% (7.2–20.3%), water saturation of 42.2% (19.5–100%) and permeability of 1080 mD (.01–6180 mD). Pressure measurements, fluid contacts and sedimentological analysis support lateral heterogeneity. The traps are a combination of structural and stratigraphic mechanisms related to the fluvio-deltaic depositional environment and subsequent deformation.

KEYWORDS:

• Zubair Formation
• Bahrah oil field
• reservoir pressure
• reservoir compartmentalization
• petrophysical characterisations

1. Introduction

The Cretaceous petroleum system is the primary contributor to oil production in Kuwait, with sources including the Late Jurassic Sargelu, Najmah and Marrat formations (Al-Khamiss et al., 2009; N. S. Aladwani, 2021; N. S. Aladwani et al., 2022; Jassim & Goff, 2006; Meyer & Nederlof, 1984; Stern & Johnson, 2010). Potential Cretaceous reservoirs include Ratawi Limestone, Zubair, Burgan, Mauddud, Wara, Ahmadi and Mishrif formations. The Lower Zubair, discovered in 1952, is a major producing horizon in northern Kuwait. However, many Zubair penetrations have been unsuccessful in Bahrah Field, attributed to the deposition nature of the Zubair Formation (N. S. Aladwani, 2022; Azim et al., 2019; Hawie et al., 2022). The formation was deposited during non-deposition periods in the Cretaceous age, leading to four main flooding events and four reservoir facies inside the lithotype section Azim et al. (2015). The Zubair section is overlain by the Shuaiba limestones, which are porous and karstified. Intraformational seals in the Zubair Formation may be provided by field-wide correlable shales, but these are only effective in the shale-rich Lower Zubair (Cross et al., 2022). Understanding the distribution geometry of the Zubair Formation is crucial for developing future production from this formation. Additionally, understanding the fault system that affected the field is necessary to compartmentalise the Lower Zubair reservoir.

The reservoir compartmentalisation phenomenon is the separation of petroleum accumulation into several distinct fluid or pressure compartments (Ejeke et al., 2017). This compartmentalisation and heterogeneity play a crucial role in identifying bypassed oil areas. It can occur due to static or dynamic sealing mechanisms. Static sealing occurs when the strata develop the capacity to seal over time, trapping the petroleum column. On the other hand, dynamic sealing happens when the oil flow rate decreases to a non-economic level due to changes in facies or permeability (El-Dakak et al., 2021; James et al., 2004; Mofti et al., 2018; Yielding et al., 2010). Determining reservoir compartmentalisation involves studying the structure of the area, identifying faults, testing fault sealing capacity, creating pressure distribution maps, analysing variations in fluid contacts and examining facies distribution (Abdel-Fattah et al., 2019; Diab & Khalil, 2021). The juxtaposition algorithm is a commonly used mechanism that tests a fault’s sealing capacity by obtaining the lateral continuation of the reservoirs in the fault area (N. Aladwani, 2022; Go et al., 2014). Furthermore, the heterogeneity in reservoirs, particularly in the Zubair reservoir, is a significant factor contributing to compartmentalisation, resulting from the deposition of a heterogeneous succession of fluvial-deltaic sandstones, siltstones and mudstones (N. S. Aladwani, 2022; N. S. Aladwani et al., 2022). The heterogeneity patterns of sandstone reservoirs are controlled by the internal structure, grain size, sorting and amount of bioturbation of the deposited sand bodies and refer to vertical and lateral variations in porosity (Gallagher, 2014; Morad et al., 2010).

The main contribution of this work is determining the degree of compartmentalisation of the Lower Zubair reservoir using multidisciplinary analyses. First, we determined the main structure of Bahrah Oil Field in the north of Kuwait (Figure 1) and the internal structure of Zubair’s succession. Then, the fault sealing analysis was carried out on the resulting faults from the structure analysis to test their sealing capacity. Besides, we used the reservoir’s facies map, thickness map, mineral composition analysis and pressure data to support the results. The investigation of Lowe Zubair Reservoir compartmentalisation will help in understanding the reservoir geometry and predicting the locations of play zones for future drilling. Additionally, we discussed reservoir deposition, its charging source rock, migration pathways, petrophysical properties and entrapping styles to validate its potentiality.

Figure 1. (A) Location of the study area (Bahrah Field) in Kuwait (from EIA 2016); (B) map showing the distribution of the wells in the field.

2. General geology

Kuwait’s stratigraphic section has a thickness range between 23,000 ft and 27,000 ft, representing the deposition of time ranges from the Late Palaeozoic to the Quaternary (Figure 2). The lower Cretaceous formations belonging to the Thamama Group were deposited through the period from the Late Jurassic to the Late Aptian/Early Albian regression. In this period, a significant transgression occurred over the evaporate-dominated Gotnia Formation (Tithonian). It ended with a regional unconformity representing the top of the Shuaiba Formation due to a regional regression A. Alsharhan and Nairn (1986). The Thamama Group in Kuwait is composed of Minagish (calciclastics), Ratawi (mixed), Zubair (siliciclastics) and Shuaiba (calciclastics, dolomitised) formations. T. K. Al-Ameri et al. (1999) reported that the bituminous deposits that characterise the Thamama Group’s lowermost formation, the Sulaiy Formation (Valanginian-Berriasian), are being thought to originate within the distal dysoxic-anoxic shelf to the suboxic-anoxic basin. On the passive margin of the Arabian Plate and Neo-Tethys Ocean, the Minagish Formation was deposited on a wide, shallow intra-shelf to the inner mid-ramp environment (Abdullah et al., 1997; Davies, 2000). Ratawi Oolite, Ratawi Limestone and Ratawi Shale make up the Ratawi Formation, which is assumed to have been deposited in a low-angle ramp setting with a deepening trend towards the east and northeast (Archuleta et al., 2010).

Figure 2. General stratigraphic column of the cretaceous age in the northern basin of Kuwait showing the depositional environments (modified from Abdullah et al., 1997; Cross et al., 2021).

According to Tanoli and Al-Ajmi (2010), the lower part of Ratawi Shale is seen as shallow marine to offshore deposits (limestone-interbedded), while the upper part is estuarine/fluvial sediments (sandstone-interbedded). Overlying the Ratawi Formation is the Zubair Formation (Hauterivian to Barremian), divided into Lower, Middle and Upper Zubair. We interpret it as delta top swamp and marsh, delta front, prodelta and marine platform environments, based on micropalaeontological evidence (T. Al-Ameri & Batten, 1997; Nemcsok et al., 1998). The Zubair Formation is dominated by clastic sediments, including sandy shales interbedded with argillaceous and clean sandstones. The Shuaiba Formation (Aptian), the Thamama Group’s topmost unit, marks a return to a carbonate-dominated deposition regime and is regarded as deposits from normal-marine shallow-shelf environments (A. Alsharhan, 1995).

Since the Paleozoic, the Arabian plate has been subjected to various plate tectonic events that have shaped the structure of North Kuwait. From the Paleozoic through the Triassic, the Arabian plate was a passive border. The Arabian Plate was then split from the Pan-African plate by an extensional event that lasted from the Triassic to the Jurassic. A compressional event formed between the Arabian and Eurasian plates from the Jurassic to the present (Al-Eidan et al., 2010; Carman, 1996). Because of intermittent tilting of the Arabian Plate to the east, frequent flooding events of the platform from the plate boundary to the high ground of Western Saudi Arabia have occurred, which is also the source of all clastic deposits in the Bahrah Field (Harland et al., 1989). The Bahrah anticline is the northern extension of the Greater Burgan high ridge, which runs north–south (Al-Sulaimi & Al-Ruwaih, 2004; N. Aladwani, 2022). However, a major shear zone to the south of the Bahrah structure isolates it from the main Burgan trend, leading to the Bahrah structure’s northwest-southeast inclination (Figure 3). On the other hand, the seismic section displays a positive flower structure that arose from the transpression caused by the right lateral shear zones stretching out from the Zagros. It linked the formation of structures and shear zones throughout the Oligocene to the convergence of the Arabian and Iranian plates (Rao et al., 2013).

Figure 3. Subsurface structural elements of onshore Kuwait (Carman, 1996).

3. Method and materials

Different approaches are utilised to examine and identify compartmentalisation phenomena, such as reservoir structure interpretation, fault seal analysis, pressure data and fluctuations in gas/water and/or oil/water contacts. Pressure fluctuations within a reservoir indicate the existence of distinct fluid compartments, with distinct gradients or differentials between different sections. This indicates limited communication or barriers between these compartments, indicating compartmentalisation, where fluids are constrained from unrestricted circulation between them (Abdel-Fattah et al., 2019). Moreover, the fluctuations in fluid contacts in a reservoir can indicate compartmentalisation, such as changing the positions of distinct fluids in different wells. Also, the abrupt changes in fluid contacts indicate distinct compartments, causing obstacles to fluid movement. Continuously varied fluid contacts over time indicate minimal communication between compartments, indicating barriers that hinder fluid blending. Besides, we used the wireline logs with the Formation Microimager Tool (FMI) available in 14 wells distributed over the field (Figure 1) to identify reservoir zones and their internal structure and estimate clay percentage, porosity, permeability, water saturation and hydrocarbon saturation. The wireline logs are Resistivity ($R_t$), Gamma-ray (GR), Density (${\rho }_b$), Neutron (${\mathit{\hspace{0.17em}}}_N$), Sonic (ΔT), Calliper and composite logs.

3.1. Reservoir structure and fault seal analysis

We carried out structural interpretation to get a depth map of the reservoir horizon, showing the fault network in the field. A seismic structure attribute is a quantity retrieved or produced from seismic data that may be studied to improve the information that would otherwise be lost in a typical seismic picture, resulting in a better interpretation of the data (Chopra & Marfurt, 2007). Then, we applied the fault sealing analysis to the resulting faults using the juxtaposition algorithm. Juxtaposition is a concept that describes the juxtaposition of high permeability reservoir units with rock units with differing lithology and permeability. The sealing capacity of a fault is linked to the clay content of lithic fragments of faulted rocks. Numerous fault seal algorithms are used to calculate and predict clay content in seismic-scale faults. These algorithms include Juxtaposition, Cataclasis, Cementation and Clay Smearing (James et al., 2004). Cataclasis is the process in which small grains migrate and occupy empty spaces, resulting in a reduction in porosity. Cementation is the process in which ions in the formation water combine and solidify, creating new crystalline material that fills the spaces between sedimentary grains. Clay smearing potential is used to evaluate the thickness profile of shale during faulting. This study employed the juxtaposition and SGR algorithms (equations 1, 2 & 3) to examine the sealing capacity during faulting process.

(1) $\mathit{Clay}\mathit{smear}\mathit{potential}\left(\mathit{CSP}\right)=\sum \frac{S\mathrm{hale}T\mathrm{hicknes}{s}^2}{\mathit{Vertical}\mathit{Distance}\left(\mathit{Throw}\right)}$(1)

(2) $\mathit{Shale}\mathit{Smear}\mathit{Factor}\left(\mathit{SSF}\right)=\frac{\mathit{Fault}\mathit{Throw}}{\mathit{Shale}\mathit{thickness}}$(2)

(3) $\mathit{Shale}\mathit{Gauge}\mathit{Ratio}\left(\mathit{SGR}\right)=\frac{\sum \left({\mathit{V}}_{\mathit{cl}}\mathit{x}\mathrm{\Delta z}\right)}{\mathit{Fault}\mathit{Throw}}\mathit{x}100\mathrm{\%}$(3)

$\mathrm{where}{V}_{\mathit{cl}}\mathrm{is}\mathrm{the}\mathrm{volume}\mathrm{of}\mathrm{clay}\mathrm{in}\mathrm{the}\mathrm{faulted}\mathrm{bed}\mathrm{and}\mathrm{z}\mathrm{is}\mathrm{the}\mathrm{total}\mathrm{clay}\mathrm{thickness}$

Furthermore, we integrated the Mud log with the facies log that was found in the wireline logging data to make a facies map explaining the reservoir facies’ lateral distribution. Finally, we used the recorded pressure gradient data that was recorded by the Reservoir Description Tool (RDT™) that has been developed to collect the fluid samples from the reservoir and measure the pressure. The pressure gradient has been measured at the isolated fault closures to spot permeability barriers. Meanwhile, the reservoir oil-water contacts were measured and modelled for each fault compartment separately, which was used for prediction in the future flow simulation.

3.2. Petrophysical analysis

The Zubair Formation’s petrophysical characteristics in this study were computed to define reservoir zones and estimate clay percentage, porosity, permeability, water saturation and hydrocarbon saturation. The calculated values were calibrated using the lab measurements of the core samples.

The volume of shale ($V_{\mathit{sh}}$) was computed from the GR-log using Larinov’s equation (4) for old rocks in Asquith et al. (2004), and the results from Neutron-Density logs were confirmed.

(4) $V_{\mathit{sh}}=0.33\ast \left[2^{\left(2\ast {\mathit{I}}_{\mathit{GR}}\right)}-1\right]$(4)

(5) $I_{\mathit{GR}}=\frac{\left(\mathit{G}{\mathit{R}}_{\mathit{log}}-\mathit{G}{R}_{\mathit{min}}\right)}{\left(\mathit{G}{R}_{\mathit{max}}-\mathit{G}{R}_{\mathit{min}}\right)}$(5)

where:

$I_{\mathit{GR}}$ is the gamma-ray index; $\mathit{G}{R}_{\mathit{log}}$ is the reading of the GR curve in the reservoir formation; $\mathit{G}{R}_{\mathit{min}}$ is the minimum reading of the GR curve in front of clean sand; GR_max is the maximum reading of the GR curve at shale lithology.

The total porosity was calculated as the average of the neutron porosity (${\mathit{\hspace{0.17em}}}_{\mathit{Ncorr}}$) derived from equation (6) of Tiab and Donaldson (2015), and the porosity derived from the bulk density log (${\mathit{\hspace{0.17em}}}_D$) using the equations (7) of Wyllie et al. (1958).

(6) ${\mathit{\hspace{0.17em}}}_{\mathit{Ncorr}}={\mathrm{\Phi }}_N-\left(V_{\mathit{sh}}\ast {\mathrm{\Phi }}_{\mathit{Nsh}}\right)$(6)

where ${\mathit{\hspace{0.17em}}}_{\mathit{Ncorr}}$ is the corrected porosity for clean rock from shale and ${\mathit{\hspace{0.17em}}}_{\mathit{Nsh}}$ is the neutron porosity value for shale.

(7) ${\mathrm{\Phi }}_D=\frac{\left({\mathit{\rho }}_{\mathit{ma}}-{\rho }_b\right)}{\left({\rho }_{\mathit{ma}}-{\rho }_f\right)}$(7)

Then, the effective porosity (${\mathit{\hspace{0.17em}}}_e$) was derived from the average total porosity by equation (8) of Schlumberger (1998).

(8) ${\mathrm{\Phi }}_e={\mathrm{\Phi }}_t\ast \left(1-{\mathrm{V}}_{\mathit{sh}}\right)$(8)

where ${\rho }_{\mathit{ma}}$ is the density of the matrix, ${\rho }_b$ is the bulk density measured from the log, ${\rho }_f$is the fluid density, ${\mathit{\hspace{0.17em}}}_t$ is the total porosity, which is the average value of ${\mathit{\hspace{0.17em}}}_{\mathit{Ncorr}}$ and ${\mathit{\hspace{0.17em}}}_D$, and ${\mathit{\hspace{0.17em}}}_e$ is effective porosity.

Archie’s equation (Archie, 1952) (eq. 9) was used to calculate the water saturation.

(9) $S_w={\left[\left(\frac{\mathit{a}}{\mathit{Fm}}\right)\ast \left(\frac{R_w}{R_t}\right)\right]}^{\left(\frac{1}{n}\right)}$(9)

where $S_w$ is water saturation, $\mathit{Fm}$ is the formation factor (= 1/Ф^m), $R_w$ =.0016 ohmmeter, $R_t$ is observed deep resistivity and a, b and c are Archie’s coefficients that are derived from the Pickett plot.

Wyllie and Rose (1950) propose the empirical equation (10) to calculate the permeability of the reservoirs.

(10) $\mathit{K}={\left(250\ast \left(\frac{{\mathrm{\Phi }}^3}{S_{\mathit{wir}}}\right)\right)}^2$(10)

where $\mathit{K}$ is permeability in millidarcy (mD), Ф is porosity (decimal), and $S_{\mathit{wir}}$ is irreducible water saturation (decimal). The irreducible water saturation is the amount of water in the oil zone calculated from equation (11).

(11) $S_{\mathit{wir}}=\left[\mathit{C}/\left(\mathrm{\Phi }/\left(1-\mathrm{Vsh}\right)\right)\right]$(11)

where $\mathit{C}$ is Buckles’s constant.

3.3. Petrographic analysis

A series of thin sections were made from the core samples to preserve the original fabric and enable a reasonably accurate visual assessment of porosity (Core Laboratories International B.V. Kuwait Branch, 2017). Soxhlet extraction in toluene was used to clean the samples, which were then dried and impregnated with blue-dyed epoxy. Thin sections were created by affixing the impregnated sample’s cut and polished surface to a glass slide, then cutting, lapping and polishing the sample to a thickness of 30 microns. To better understand the texture, composition and distribution of porosity in reservoir rocks, researchers employ a scanning electron microscope (SEM). It helps detect microporosity distribution, X-ray diffraction identification of interstitial clays and minerals that might cause formation damage if they react with drilling or completion fluids (Sun et al., 2019). The crystalline components were also detected using X-ray diffraction (XRD) analysis.

4. Results

4.1. Depositional environment and sequence stratigraphy

Three intervals separated by significant gaps represent the Zubair Formation. These intervals are represented by packages dominated by cross-stratified sandstones and ripple-laminated sandstones. They are interrupted by relatively thin zones of muddy sandstone, heterolithic deposits, sandy mudstone and mudstone, locally with trace fossils and plant remains (Figure 4). The Zubair Formation sandstones are interpreted from the core and log data to be of fluvio-deltaic origin (Core Laboratories International B.V. Kuwait Branch, 2017). The sands are deposited as distributary channels, mouthbars, tidal bars and shorefaces. In contrast, shale and silt intervals and heterolithics have predominantly been deposited in interdistributary bays, estuaries and prodelta settings. The reservoirs are highly layered, and the shales capped the Middle Zubair and Lower Zubair, representing flooding episodes (Figure 5). Four flooding events leading to deposit accumulation because of the Transgressive System Tract (TST) overlined the Lowstant System Tract (LST) deposits, which resulted from rising the seal level (Sharland et al., 2001) (Figure 5). The core data analysis indicates that Zubair’s facies are associated towards the top with scour-based clean sandstones, argillaceous carbonaceous sandstones, sandy carbonaceous shales locally with rootlets, coal clasts and amber fragments. These facies grade up into mud to sand-dominated heterolites like blocky, fine-grained, carbonaceous clay-laminate sandstones with rare Paleophycus. XRD analysis of these heterolites/rhythmites detects between 18.4 wt.% dolomite and 76.1 wt.% total clay. The Lower Zubair Member comprises sandy shales with sideritic and glauconitic at the upper part, argillaceous, bioturbated, bioclastic sandstones in the middle and clean bioclastic sandstones at the bottom. This facies order indicates that the deposits of the top Lower Zubair Formation represent proximal offshore (outer ramp) deposits, offshore transitional to lower shoreface (mid ramp) deposits (fair- and storm-weather wave bases) and above fair-weather wave bases at the bottom of the Zubair Formation, respectively. XRD analysis of these argillaceous facies detects 5.0 to 10.2 wt.% siderite, 22.3 to 29.8 wt.% calcite and 8.0 to 10.4 wt.% total clay. Generally, the XRD analysis (Figure 6) shows a decrease in the clay percentage and increased quartz minerals towards the bottom of the Lower Zubair lithotype succession. We used the XRD diffraction method, scanning electron microscopy (SEM) and thin sections to identify the clay minerals existing in the cored samples from the Zubair Formation (Sun et al., 2019). By comparing the data presented in Figures 5 and 6), we found that the intervals (10554–10557) and (10573–10579) have a low clay percentage, high resistivity and high permeability. These intervals are equivalent to the first two flooding events at the Lower Zubair Formation, where the potential reservoir zones (Z10 and Z23) were deposited in Upper Shoreface environment.

Figure 4. Stratigraphic succession of the Zubair Formation extracted from the well BH-A8.

Figure 5. The detailed lithology of the Zubair Formation associated with the depositional environment, cyclicity and facies analysis. The different facies represented by core photographs and thin sections show the detailed composition of the rocks. Besides, the log and core gamma ray, density, neutron, resistivity, measured porosity and permeability are plotted opposite each lithology.

Figure 6. Schematic illustrates the whole rock diffractogram of well BH-A8 (Core Laboratories International B.V. Kuwait Branch, 2017).

4.2. Reservoir compartmentalization and heterogeneity

We have carried out an integrated study to investigate the compartmentalisation phenomenon of the Lower Zubair reservoir. This study included the identification of faults, making sealing analyses for these faults, tracing the gradient pressure in different compartments, determining the oil-water contact (OWC) and distributing the facies around the reservoir and their physical properties.

4.2.1. Facies heterogeneity

The Lower Zubair Z10 and Z23 units are the only ones to succeed in production because they comprise channel sands, mouthbars and shoreface sands as a primary lithology in unit Z10 and are sealed by Z10 top shale, while the Z23 unit comprises mainly interdistributary bays, overbanks and splays, which make it a heterolithic unit (Figure 7). The Lower Zubair correlation (see Figure 7) is relatively straightforward due to the relatively layered architecture. The transgressive marine Ratawi Shales are being succeeded by regressing and slightly backstepping cycles of a deltaic system in the lower Zubair. The distributary channels in the Zubair often align in the NE direction as well as from W to E. These channel deposits are characterised by lateral discontinuous sand bodies pinching out towards the southern and central parts of Bahrah Field.

Figure 7. Two maps of the middle of zones Z10 and Z23, showing the different facies distribution of Zubair Reservoir (top) and corresponding cross-section (bottom) through the Bahrah Field.

4.2.2. Structure elements and fault seal analysis

2D and 3D seismic data interpretation produced a detailed structure map (Figure 8). The Bahrah Field shifted from the Burgan/Kuwait Arch trend by an E-W strike-slip fault resulting from the NE-SW shear force. The dominant structure in the field is described as an asymmetrical plunging and faulted anticline. The anticline’s axis is running NW-SE and dipping to the NW direction with a 1950 ft difference in elevation from the highest point (6500 ft.) to the SE of the field and the lowest point (8450 ft.) to the NW of the field. The western flank of the anticline is steeper in dip magnitude (4 to 5 degrees) than the eastern flank (2 to 3 degrees). Three main fault trends dissected the anticline: first, the NW-SE fault trend runs parallel to the axis of the anticline from the NW to the SE direction and throws to the SW and NE directions. This trend is considered the main fault trend in Bahrah Field. Second, the NE-SW fault trend runs almost perpendicular to the NW-SE fault trend and throws to the NW and SE directions. Thirdly, the E-W fault trend is defined as a shear zone in Bahrah, as indicated in the regional structure of Kuwait (Figure 3) and the lateral shift to the west of Bahrah anticline along with this trend. Generally, the field seems compartmentalised due to a large number of faults dividing the field into blocks (Figure 8).

Figure 8. Structure contour map of the top Zubair Formation, showing the faults network in the field; the enlarged area shows the compartmentalisation phenomena that characterised the reservoir resulting from the faulting mechanism.

We performed juxtaposition fault seal analysis on these faults to see if they may leak oil through the fault planes (Figure 9). The Lower Zubair, which is shale-rich and has several separate shale intervals, has some working seals. Carbonate cemented sandstones to argillaceous limestones, and Ratawi marine shales appear to have good seals. The most successful seal discovered for the Z10 reservoir unit is a juxtaposition seal using reverse faults, which opposes the sands to the Ratawi Shale.

Figure 9. Fault seal analysis, showing the juxtaposition mechanism of the faults that led to excellent sealing of the Z10 unit of the reservoir while leaking in the Z23 unit due to the thin shale lamination.

The Zubair interval (10450 ft. to 10,600 ft.) was analysed using the FMI image (Figure 10). The internal structural dip is defined by bedding in facies/lithotypes that are thought to have been deposited horizontally or nearly horizontally. The laminated shale dominates these facies. On a stereonet, the selected dips are plotted, and poles for these dips are defined. The calculated average dip angle is 3.2°/2.8°. Natural fractures that appear partially closed or mineralised are known as partial fractures. Therefore, image logs may appear as partially bright and partially dark traces. According to the fracture identification criteria, there are 10 discontinuous resistive fractures in the image interval between 10,450 and 10,600 ft, with a NE-SW strike (Figure 10).

Figure 10. Composite layout well BH-A5, including the gamma-ray mirror image, dipmeter, FMI image, rose diagram and dip plot diagram. This layout shows the four main structural zones with a calculated dip attitude of 3.2°/2.8°. The gamma-ray and FMI images show the lamination of shale in the zubair formation.

4.2.3. Pressure and fluid contact

The virgin pressure data for the wells in each fault closure exhibit one oil accumulation in Mauddud and Burgan reservoirs. At the same time, there is complete isolation between Mauddud/Burgan and Zubair Formation (Figure 11). Also, there is a 3000-psi pressure differential over Ratawi Shale, demonstrating the strong sealing potential of Ratawi Shale. On the other hand, the pressure measurement of the different intervals of the Zubair Formation shows vertical isolation between Upper, Middle and Lower Zubair members (Figure 12. A). In the Z23 reservoir, the well BH-A13, drilled on the flank of the BH-A3 structure, does exhibit a formation pressure similar to the original pressure observed in BH-A3 (Figure 12. B). In the Z10 reservoir, the original reservoir pressure observed in well BH-A14 in the west is only 20 psi lower than the pressure for well BH-A13 in the east. Also, we observed that the pressure deployed rapidly due to the production, which indicated small accumulations. The measurement of the pressure gradient for the different oil accumulations appeared in Figure (8), shows different gradients, and the drilled wells exhibit a formation pressure similar to each other, supporting the supposed compartmentalisation. Further, we found that the Oil Water Contact (OWC) in well BH-A3 is 10,098 ft, 9956 ft in well BH-A14 and 9916 ft in well BH-A8, indicating exposure to different hydrostatic pressures in each compartment.

Figure 11. Measured pressure data in Mauddud, Burgan, Zubair, Ratawi and Minagish formations.

Figure 12. (A) Measured pressure data through the Upper, Middle and Lower Zubair Formation shows the different pressure values, which indicates the highly vertical heterogeneity of the Zubair Formation; (B) the measured pressure gradient inside the Z10 and Z23 reservoir units show the compartmentalisation of the reservoirs.

4.3. Petroleum geology

4.3.1. Reservoirs

The clean sandstone is dominated by intergranular pores with oil staining in the Upper and Middle Zubair members and is characterised by good quality. The organic clay laminae may limit vertical connections within sand bodies. The microporosity of the carbonaceous argillaceous sandstones and sandy shales is because of the presence of porosity inside a clay-rich matrix. Meanwhile, the clean sandstones of the Lower Zubair Member have good reservoir quality because it partially occluded by mild cementation (Figure 4). The Lower Zubair reservoir characterised by porosity ranges between 7.6% and 20% (Avg. 14.2%), clay content ranges between 7.2% and 20.3% (Avg. 12.8%), water saturation ranges between 19.5% and 100% (Avg. 42.2%) (Table 1) and (Figure 13), and an average core permeability of 1080 mD (.01 mD −6180 mD). The net and pay cut-offs for this study have been defined as 40% shale volume, 5% Porosity and 50% water saturation. The petrophysical maps show a wide range of clay percentage, effective porosity and water saturation, which reflect the heterogenic reservoir facies distribution. Also, there are no wells targeting the Lower Zubair reservoir in southern Bahrah Field because of the high-water saturation, where there has been no proven success yet outside the shear zone in the middle and north of the field where the produced compartments of the reservoir.

Figure 13. Layers of petrophysical parameters of the lower zubair reservoir showing the distribution of; the volume of shale (Vsh), effective porosity (Фe) and water saturation (Sw).

Table 1. Petrophysical parameters of Lower Zubair reservoir.

Wells	Top	Bottom	Gross	Net Reservoir	Net Pay	N/G	Av Phi	Av Sw	Av Vcl	Phi*H
BH-A6	11388	11420	32	10.5	10.5	0.328	14	38	13	1.42
BH-A5	10367.51	10591.2	223.69	32.25	2	0.009	7.6	19.5	7.2	0.15
BH-A10	9916	10176	260	79.25	5	0.019	20.00	35.00	11.00	1.44
BH-A9	9947.23	10191.32	244.09	118.45	29.25	0.120	17.4	18.6	20.3	5.1
BH-A3	10072.8	10300	227.2	26.25	0	0.116	13.2	100	12.5	3.47

4.3.2. Source

Oil samples across the field show different characteristics (API samples from 24 to 42 API), indicating multiple charge phases. The source rocks of Kuwait’s hydrocarbons are believed to be the Early Cretaceous Sulaiy (Makhul) and Jurassic Najmah and Sargelu Formations (Abeed et al., 2011; Al-Khamiss et al., 2009; Al-Wazzan et al., 2022; Jassim & Goff, 2006). The total organic content (TOC) values for Sulaiy Formation are approximately 2% with mainly Type II Kerogen, >6% for Najmah Formation with Kerogen of Type II and 1–2% TOC in Sargelu Formation, which has kerogen of Type II (Al-Qaod, 2017; Surdashy, 1999).

4.3.3. Migration pathways and sealing

The Bahrah Field represents a part of the regional structure that covers the northern part of Kuwait. To understand this structure, we used a long seismic line that passed through the northern oil fields. This seismic line was extracted from a high-quality onshore 3D seismic volume that was calibrated by an extensive number of drilled wells. The seismic survey was carried out by Western Geco between 2012 and 2014 and covered an area of about 6460 km2. The survey extends from the northern side of Kuwait Bay to the northern border with Iraq and extends westward to a distance of 30–40 km from the border with Saudi Arabia. It has been found that the kitchen areas of the hydrocarbon are believed to lie in the fore-deep areas of the Mesopotamian Foredeep Basin under the Zagros Fold Belt to the east of Kuwait. Migration into the North Kuwait fields is interpreted to have started 50–60 Ma years ago and is continuing to the present day. Bahrah Field lies near the top of the Kuwait Arc, while the super-giant fields of Raudhatain and Sabriyah lie north down-dip of Bahrah Field (Figure 14(A). The oil fills the anticlines of Raudhatain and Sabriyah fields to spill-out point to Bahrah Anticline (Figure 14(B). The migration is expected to be laterally from the north along the axis of the Burgan Arch. However, there is a probability of vertical migration through the faults directly from the underlying source rocks.

Figure 14. (A) Scheme of the subsurface under northern Kuwait, joining the raudhatain and sabriya fields on the down-dip of the anticline, and the Bahrah Field lies at the top where the oil spilled out from the down-dip fields to the top; (B) E-W seismic section corresponding to the above scheme, showing the shape of oil trap of the three fields on the seismic.

The Zubair Formation and Zubair Sand Thickness Map (Figure 15) indicates that the thickness of Zubair’s shale laminations is larger than the thickness of the sand. Also, Figure 12(A) shows that the shale units isolate the sand bodies vertically and represent a vertical seal for the underlying sands. For example, the potential sealing shale on top of the Z23 is present all over Bahrah.

Figure 15. Thickness map for the Zubair Formation and the cumulative Zubair Sand Thickness, showing that the Zubair Formation thickness ranges between 1220 and 1440 ft, while the net sand thickness ranges from 25 to 165 ft.

4.3.4. Entrapping styles

While it appears that structural style variations account for much of the oil distribution in the Bahrah Field, stratigraphic pinch-outs cannot be ruled out (Figure 16). In these shallow marine to deltaic deposits, the main determinant of the facies transition from shale to sandstone is sediment influx, which forms the stratigraphic component of Zubair Sandstone. While the structure element is the Bahrah anticline, which is considered the northern extension of the Greater Burgan high ridge and trends in a north–south direction, the Bahrah anticline is a part of the regional anticline (Kuwait Arc) that appeared in the Late Jurassic and was exposed to many tectonic events during the Cretaceous, leading to faulting the area by normal faults and a significant shear zone to the south of the structure. Consequently, a faulted anticline dominates Bahrah Field, associated with three fault trends: the SE to NW trend of longitudinal extensional faults that primarily down-throw the SW; the E-W trend represents the shear zone of the field; and an N-S trend with a little throw. In addition, the fault sealing capacity analysis indicates the accumulation of oil in the Z10 reservoir unit, the most potential reservoir, at the highest compartments in the centre of the field due to leaking the oil through the fault’s plains to the highest compartments. On the other hand, the sealing capacity of the Z23 reservoir unit is excellent due to the thick side shale of the Ratawi Formation, which forms the Z23 reservoir compartmentalised. Thus, all working traps are interpreted to have at least one fault component, and possibly the SW-NE trending faults are more effective.

Figure 16. Scheme shows the structure and stratigraphic traps of the Cretaceous reservoirs in northern Kuwait. It’s showing that the traps are a mixed between stratigraphic pinch-outs, shallow marine to deltaic deposits and faulted anticline with a regional dipping of the strata.

5. Discussion

To provide a better understanding of the bypass oil scenario in the Zubair Formation, we integrated the resulting structure map (Figure 8) with the fault seal analysis (Figure 9) and thickness maps (Figure 15) to determine the reservoir compartments most likely to trap oil accumulation. Also, we obtained the lateral and vertical heterogeneity in the Zubair Formation (Figure 7). By comparing the results with the produced wells, we found that the main reservoir units, Z10 and Z23, are trapped on the upper down-dip side of the Bahrah Anticline by a set of NW-SE trending faults that exhibit effective sealing (Figure 8). The reservoirs are vertically sealed by internal Zubair shales. However, the Z10 unit is highly compartmentalised due to strong lateral sealing from the Ratawi shale, while the Z23 unit experiences some hydrocarbon leakage through fault planes (Figures 4 and 5). The pressure gradient analysis in Figure (12) suggests the presence of compartmentalisation in the Lower Zubair reservoir. The variation in initial pressure among different wells and the rapid depletion of pressure indicate that the reservoir is divided into distinct compartments. This further supports the findings of lateral sealing and hydrocarbon leakage discussed earlier. The facies maps presented in Figure (7) demonstrate the heterogeneity of reservoir facies within the Lower Zubair formation. This heterogeneity is attributed to the variety of depositional environments during the formation’s sedimentation, which likely provides additional information on the specific depositional environments and their spatial distribution within the reservoir (Figure 5). Indeed, the deposition of the Lower Zubair reservoir was influenced by a variety of sedimentary environments, as indicated by the presence of channel sands, mouthbars, shoreface sands, interdistributary bay sands, overbank deposits, splay sands and interdistributary bay muds. These different sediment sources contribute to the heterogeneity observed in the reservoir facies maps (Figure 7). The combination of different facies resulting from various depositional environments contributes to the overall heterogeneity of the reservoir. This heterogeneity can influence fluid flow characteristics, such as porosity, permeability and fluid connectivity, which can impact reservoir performance and the distribution of hydrocarbons.

The contrasting behaviour between the Z10 and Z23 units in terms of fault sealing and compartmentalisation highlights the importance of understanding the reservoir’s sealing mechanisms and heterogeneity. It also emphasises the need for careful well placement and development strategies to optimise oil production from different units within the Lower Zubair reservoir. The effective fault sealing observed in the Z10 unit plays a crucial role in trapping the oil within all compartments in the accumulation area. This means that the oil is contained within the individual compartments, allowing for successful oil production from wells targeting the Z10 unit. The strong lateral sealing provided by the Ratawi shale helps in compartmentalising the Z10 unit and preventing significant hydrocarbon leakage. On the other hand, the weak sealing of the Z23 unit results in oil spilling to the highest compartments. This means that the hydrocarbons in the Z23 unit are not as effectively trapped as in the Z10 unit, leading to limited oil production from specific wells. The hydrocarbon leakage through fault planes further contributes to the limited oil production from the Z23 unit.

The drilling uncertainty is related to the trapping complexity due to the combined effect of stratigraphic and structural components (Diab et al., 2023). Despite the dominant entrapment being structural elements, faulted anticline, the sediment influx coming from the west in a deltaic environment at the Barremian Age was responsible for the deposition of the stratigraphic traps. Similar to the Middle Miocene sediment influx in Egypt’s Gulf of Suez, the Miocene Belayim and Kareem Reservoirs are distinguished by the presence of a combined stratigraphic and structural trap in the Badri Field (Abdel Fattah et al., 2020). The reservoir heterogeneity characterised many of the reservoirs worldwide, and the geologists worked hard and in different ways to try to reach the reservoir’s geometry, such as Zhang et al. (2022) who used 3D seismic structure modelling, different computational attributes and petrophysical analysis to reach the reservoir distribution in the Kadanwari Field, Middle Indus Basin, Pakistan. Moreover, the timing, geometry and extent of the faults are important parameters in understanding the faulting process, as in the Northumberland Trough in England (Jenkins & Torvela, 2020). Also, the fault sealing capacity is an essential factor in determining the drilling location to avoid dry compartments.

All previous studies were applied to the Bahrah Field to understand the reservoir geometry, effectiveness of the faults to retain the liquid and existence of the complete petroleum system elements. Here, the Lower Cretaceous Makhoul/Sulaiy Formation and the Late Jurassic Sargelu and Najmah formations are the potential source rocks underlining the Cretaceous Zubair reservoir. Also, the architecture of the field allowed for both lateral migration from the northern Raudhatain and Sabriya fields and vertical migration through the faults directly from the underlying source rocks (Figures 14 and 15). Finally, the complexed structure and stratigraphic traps are found in the form of channel sands, shoreface and mouthbar but are exposed to folding and faulting mechanisms. Thus, the other petroleum system elements, such as reservoir quality, the existence of potential source rock, the right migration timing and internal cap rocks, indicate that the Zubair Formation is a promising reservoir for further exploration and investigation.

6. Conclusion

• This study investigates the reservoir compartmentalisation and heterogeneity phenomenon, which may lead to success chances ranging from 50 to 60% in Bahrah Field.

• To create a structural depth map and thickness map for the Zubair Formation, we performed 2D and 3D seismic data interpretation encompassing the research area. The fault-sealing mechanism was then analysed using the cross-fault juxtaposition method.

• The facies map, core data analysis, FMI interpretation, reservoir pressure measurements and sedimentological and petrographic assessment were integrated to validate the reservoir’s compartmentalisation.

• Two main reservoirs in the Lower Zubair Member, Z10 and Z23 units, lie on the down-dip of the Bahrah anticline. the reservoir quality is good, with an average porosity of 14.2% (7.6–20%), clay content average of 12.8% (7.2–20.3%), water saturation average of 42.2% (19.5–100%) and average core-permeability of 1080 mD (.01–6180 mD).

• The reservoir contains oil of API range from 24 to 42, indicating multiple charge phases, and may be oil migrated from different sources, such as the Lower Cretaceous Makhul and Jurassic Nahmah and Sargelu formations. The oil is sealed vertically by the internal Lower Zubair shale.

• The Z10 reservoir unit is completely compartmentalised due to the juxtaposition of the reservoir facies with the thick side shale of the Ratawi Formation, while the oil is leaking through the fault planes in the Z23 reservoir unit, which makes it connected to the oil.

• This study should increase the success rate of Zubair play in the Bahrah Field because of the better understanding of the reservoir heterogeneity and facies distribution through the field.

Disclosure statement

No potential conflict of interest was reported by the author(s).