Introduction

Assessment of petroleum system aspects in terms of time, depth, and interaction to assess undiscovered oil and gas resources can significantly increase world oil production (Magoon and Dow 1994). The petroleum system study covers hydrocarbon generation, migration, accumulation, and entrapping styles (Magoon and Schmoker 2000). Estimating the amount of accumulated hydrocarbon in the prospect, its source rock, and the level of thermal maturity of total organic materials is the most typical technique to analyse the petroleum system in a specific location (Aladwani 2021; Meyer and Nederlof 1984). In the case of deep burial, there is a need to determine the migration path, especially in the thick stratigraphic column (Abdel-Fattah et al. 2019; Selley 1998). We usually assess the quality and quantity of organic content in the source rock and their maturity in the laboratory using chemical and microscopic analysis of core samples (Zhao et al. 2016, 2017).

Kuwait covers an area of 17,800 km2 and is located in the north-eastern corner of the Arabian Peninsula, on the north-western coast of the Arabian Gulf (Aladwani 2021; Alsharhan et al. 2014). It lies at the southwestern intersection of the large Mesopotamian Foredeep Basin of the Arabian Platform, joining parts of Iraq, Syria, Iran, Kuwait, and the Arabian Gulf (Fig. 1A). This basin occupies the Interior Arabian Platform in the west and Zagros Fold Belt in the east. Without a significant stratigraphic break, a complete and thick sedimentary succession characterizes the foredeep basin. The thickness of the units increases to the east and reaches 8 km as a maximum (Cross et al. 2021; Aqrawi et al. 2010). The environments of the deposited Mesozoic and Cenozoic sediments, which range from shallow to open marine environments, reflect the Neo-Tethys passive margin (Fig. 1B–D) (Yildiz 2022; Azim et al. 2019; Alsharhan and Nairn 1986; Sharland et al. 2001). Kuwait’s stratigraphic section comprises three petroleum systems: The Cretaceous petroleum system, which is the primary system that contributes to production (Behbehani et al. 2019; Al-khamiss et al. 2009), and the Jurassic petroleum system, which is separated from the above Cretaceous system by the thick evaporates of Gotnia and Hith formations of about 2300 ft thickness (Aladwani 2022a; Al-Wazzan et al. 2022; Fox and Ahlbrandt 2002), and the Paleozoic petroleum system. However, there is insufficient information about the Paleozoic system because its high depth is not penetrated in the boreholes except in very few wells. The Cretaceous succession comprises complete petroleum system elements (Fig. 2). The oil migrates from the Sulaiy Formation (Upper Jurassic-Lower Cretaceous) to the Cretaceous reservoirs; Zubair, Burgan, Mauddud, Wara, Ahmadi, and Mishrif formations, while the oil has been produced unconventionally from the Jurassic source rocks (Asadi et al. 2021; Fox and Ahlbrandt 2002; Stern and Johnson 2010; Jassim and Goff 2006).

Fig. 1
figure 1

A The extension of Mesopotamian Foredeep Basin over Iraq, Kuwait, and SW Iran and location of the study area (Bahrah Field) in Kuwait (from Aqrawi et al. 2010); B–D The position of Kuwait on the Neo-Tethys passive margin at 125 Ma, 45 Ma, and the recent position, respectively (Brune et al. 2016)

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Fig. 2
figure 2

(Modified from Cross et al. 2021 and Abdullah et al. 1997)

General Cretaceous stratigraphic column in the Northern Basin of Kuwait showing the depositional environments of the Cretaceous formations

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The Bahrah area covers approximately 300 km2 and is located in the centre of an established Cretaceous petroleum system. The field is situated on the Burgan Arch, a north–south lineament that hosts the Greater Burgan, Sabriyah, and Raudhatain fields. In the Bahrah Field, the Mauddud carbonate reservoir has a considerable production history and focuses on ongoing field development (Cross et al. 2022). Despite producing over 17 million barrels of oil, the upper Burgan reservoir is still being explored because of the uncertainty of oil distribution and in-place volumes. In addition, the oil was discovered in the Zubair reservoir in a significant pay interval in BH-0047 and BH-0043 wells, drilled in 2016 and 2017, respectively (Hawie et al. 2022).

This study aims to investigate the Cretaceous total petroleum system in north Kuwait in terms of burial history and thermal maturity of the source rock and characterize the hydrocarbon potential of the Bahrah Field as a part of the northern basin in Kuwait. Furthermore, we studied the potential Cretaceous reservoirs through the wireline logs, core samples, pressure data, and geochemical analysis of the reservoir fluid to better understand the depositional environments using commercial software packages. Hence, we defined the petroleum elements and their interaction, which will help further the development of the Bahrah Field and the neighbourhood fields.

General geology

Gravity and magnetic maps (Fig. 3A) and drilled wells show that a sedimentary column varying in thickness from 6 km in the south to 8 km in the north underlies the Kuwait region, with ages ranging from Triassic to Pleistocene. In northern Kuwait, the Cretaceous sediment thickness reaches 4 km (Aqrawi and Badics 2015).

Fig. 3
figure 3

A Bouguer residual depth map showing the locations of the anticlines in Kuwait and squared the Bahrah anticline (Aladwani 2021); B Subsurface Structural Elements of onshore Kuwait (Carman 1996)

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Structure setting

The structural elements of Kuwait (Fig. 3B) range between structural arches, regional highs and lows, anticlines and synclines, regional gradients, and faults. The Bahrah Field, in northern Kuwait, sits on the Arabian Plate’s middle eastern boundary. The tectonic history of the Arabian Plate has been complicated, with eustatic sea-level variations playing a prominent role (Carman 1996; Aladwani 2022b). The plate boundary and shelf edge were 500 km northeast of Bahrah Field during the mid-Cretaceous. The Arabian platform was tectonically quiet during the Hercynian orogeny (late Devonian to Carboniferous). Following this, we have only modest tilts to the northeast on the Arabian Plate, which is sinking gently under the weight of the sedimentary cover. Regional eustatic sea-level variations dominated the sedimentary pattern and regime because of intermittent tilting to the East, leading to frequent flooding of the platform from the plate boundary to the high ground of Western Saudi Arabia, which is also the source of all clastic deposits in the Bahrah Field (Cross et al. 2022). The large anticline structure known as the Burgan Arch grew episodically inside this solid platform. It is a prominent north–south structure that first appeared in the Late Jurassic period (Azim et al. 2019; Behbehani and Hollis 2015). Apparently, there was some movement in the Albian Age, most likely during the deposition of the Middle Burgan Formation and subsequently during the Late Cretaceous, when the Burgan Arch underwent considerable tectonic expansion. Regionally, the Bahrah anticline feature is considered the northern extension of the Greater Burgan high ridge (Aladwani 2022b; Al-Sulaimi and Al-Ruwaih 2004) and trends north–south direction. However, a significant shear zone to the south of the Bahrah structure separates it from the main Burgan trend leading to a northwest-southeast tendency of the Bahrah structure.

Stratigraphy and petroleum system

The depositional environments of the stratigraphic column facies range from the Paleozoic to the Cenozoic (Fig. 4), with thicknesses varying from 3 km in the west to 8 km in the northwest (Aqrawi and Badics 2015). The Triassic units are characterized by the deposition of thick carbonate platform due to the widespread transgression that occurred through the Triassic and lasted to the Early Jurassic due to the rapid movement of the Arabian Plate towards the Eurasian continental (Hawie et al. 2022; Zeinalzadeh et al. 2019; Sharland et al. 2001). The Jurassic and Cretaceous time was characterized by forming shallow intra-shelf basins on the passive margin of the Arabian Plate. As a result, the Sulaiy and Minagish formations were deposited on a broad, shallow intra-shelf to the inner mid-ramp environment on the passive margin of the Arabian Plate and Neo-Tethys Ocean (Abdel-Fattah et al. 2022; Nairn and Alsharhan 1997; Alsharhan and Naim 1986). The Minagish Formation is divided into three members: Upper, Middle, and Lower. The Lower Member of the Minagish Formation and the Sulaiy Formation consider the primary source rock for the oil accumulated in the Cretaceous reservoirs, including the Middle Minagish oolitic limestone reservoir (Aladwani 2022a; Abdullah et al. 1997). The Ratawi Formation comprises siliciclastic mudstones and calcareous siliciclastic mudstones with tiny lime-mudstone intercalated with thin, muddy sandstones. The entire Ratawi Shale interval is thought to have been deposited in calm offshore circumstances with intermittent bottom current interruptions, most likely due to storms (Azim et al. 2019; Arasu et al. 2012). The Lower Cretaceous period recorded two transgressive–regressive cycles: the older cycle spanning Minagish and Ratawi formations and the younger cycle spanning Zubair and Shuaiba Formations (Haq and Al-Qahtani 2005; Sharland et al. 2001). The younger regression cycle led to the deposition of the clastic sediments, represented by the Zubair, Burgan, Wara, and Ahmadi formations (Cross et al. 2022; Aladwani 2021). The transgression system tracts followed the falling system tracts, forming Shuaiba, Mauddud, and Mishrif. These formations, deposited due to the falling and transgressive systems, represent the potential Cretaceous reservoirs facies.

Fig. 4
figure 4

Schematic chronostratigraphic section of the Cretaceous across the northern gulf area (Sharland et al. 2001)

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Most potential reservoirs are deposited in the mid-Cretaceous (Bahman 2022; Mofti et al. 2018; Cross et al. 2021, 2010; Al-Ameri et al. 2009; Strohmenger et al. 2006; Al-Eidan et al. 2001). The Arabian Plate shifted northwards and rotated over the Phanerozoic, leaving Kuwait in an equatorial environment that may have been subtropical, with significant rainfall and episodic monsoon-like climatic oscillations that would indeed alter local sedimentary patterns. In this period, Zubair, Burgan, and Mauddud formations were deposited. The Mauddud Formation (Upper Albian Age) overlies the Burgan Formation and conformably underlies the Wara shale (Figs. 2, 4). It is 250 ft thick, consists mainly of limestone with shale and calcareous sandstone interbeds, and contains three major reservoir units based on reservoir characterization, Upper, Middle, and Lower Mauddud. The Burgan Formation is a fluvial-deltaic succession of the Lower Cretaceous deposited along Neo-Tethys’s passive western margin. It represents the erosion of the Arabian Shield situated to the west and easterly transport to the margin marine setting of the present-day northern Arabian Gulf. The Zubair Formation comprises mainly quartz arenites (quartz-dominated) based on micropaleontological evidence (Al-Ameri and Batten 1997). Its facies cyclicity indicates delta lobe progradation with facies including distributary low sinuosity channels and marsh/swamps (Ali and Aziz 1993; Khaiwka 1990). The Shuaiba Formation (Aptian) overlaid the Zubair Formation, which records a return to the carbonate-dominated deposition regime and is interpreted as normal-marine deposits. The Late Cretaceous formations mark a transition to foreland deposition due to the ophiolite obduction onto the Arabian Margin (Sadooni and Aqrawi 2000). During the Cenozoic, fine to coarse grains of sandstone and conglomerate were deposited in the fast subsiding of Zagros foredeep, resulting in continued foreland deposition (Jassim and Goff 2006). At the top of the sedimentary column, these deposited clastics consider the transition from marine to continental environments.

Method and materials

Seismic data interpretation

Seismic reflection interpretation’s primary goal in hydrocarbon exploration is to build a comprehensive framework for the area’s subsurface structure. As a result, the availability and quality of data, particularly seismic and well log data, are crucial to the interpretation’s effectiveness (Sukmono and Ambarsari 2019). It is preferable to operate 2D/3D seismic interpretation on the depth domain data rather than time data in order to support the static model with horizons and fault sticks directly from the seismic data set and reduce the uncertainty of human error in the case of building the fault model in the static model from the polygons extracted from time-domain results. The study is based on a high-quality onshore 3D pre-stack depth migration seismic volume calibrated by an extensive well database. Geco-Prakla conducted the seismic survey between 1996 and 1998, covering 385 km2. The seismic data were reprocessed in 2013 by CGGVeritas. The geological targets in the Bahrah area are the upper Jurassic levels (Najmah and Gotnia) and the lower Cretaceous formations (Ratawi, Zubair, Burgan, and Mauddud). The Late Triassic (Minjur) and Late Cretaceous (Hartha, Tayarat) levels are also potential targets.

Reservoir characterizations

In this investigation, we used 14 wells located around the area. The wireline logs (Resistivity (Rt), Gamma-ray (GR), Density (ρb), Neutron (ФN), Sonic (ΔT), Caliper, and composite logs), geochemical logs, and pressure data are available in all wells, and core samples are available in four. Commercial software was used to identify reservoir zones and estimate clay percentage, porosity, permeability, water saturation, and hydrocarbon saturation. The laboratory measurements of the core samples were used to calibrate the computed values for the Zubair and Ratawi formations.

The volume of shale (Vsh) was computed from the GR-log using Larinov’s Eq. (1) for old rocks in Asquith et al. (2004), and the results from Neutron-Density logs were confirmed.

$$V_{{{\text{sh}}}} = 0.33*\left[ {2^{{\left( {2*I_{{{\text{GR}}}} } \right)}} {-} \, 1} \right]$$
(1)
$$I_{{{\text{GR}}}} = \left( {{\text{GR}}_{\log } - {\text{GR}}_{\min } } \right)/\left( {{\text{GR}}_{\max } {-}{\text{GR}}_{\min } } \right)$$
(2)

where IGR is the gamma-ray index; GRLog is the reading of the GR curve in the reservoir formation; GRmin is the minimum reading of the GR curve in front of clean sand; GRmax is the maximum reading of the GR curve at shale lithology.

The total porosity was calculated as the average of the neutron porosity (ФNcorr) derived from Eq. (3) of Tiab and Donaldson (2015), and the porosity derived from the bulk density log (ФD) using Eqs. (4) of Wyllie et al. (1958).

$$\Phi N_{{{\text{corr}}}} =\Phi N{-}\left( {V_{{{\text{sh}}}} *\Phi N_{{{\text{sh}}}} } \right)$$
(3)

where ФNcorr is the corrected porosity for clean rock from shale and ФNsh is the neutron porosity value for shale.

$$\varPhi_{{\text{D}}} = \left( {\rho_{{{\text{ma}}}} {-}\rho_{{\text{b}}} } \right)/\left( {\rho_{{{\text{ma}}}} {-}\rho_{{\text{f}}} } \right)$$
(4)

Then, the effective porosity (Фe) was derived from the average total porosity by Eq. (5) of Schlumberger (1998).

$$\varPhi_{{\text{e}}} = \varPhi_{{\text{t}}} *\left( {1 - V_{{{\text{sh}}}} } \right)$$
(5)

where ρma is the density of the matrix, ρb is the bulk density measured from the log, ρf is the fluid density, Фt is the total porosity which is the average value of ФN and ФD, and Фe is effective porosity.

Archie’s equation (Archi 1952) (Eq. 6) is used to calculate the Water saturation.

$$S_{{\text{w}}} = \left[ { \, \left( {a/{\text{Fm}}} \right)*\left( {R_{w} / \, R_{t} } \right)} \right]^{(1/n)}$$
(6)

where Sw is water saturation, Fm is the formation factor (= 1/Фm), Rw = 0.0016 Ω-meter, Rt 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 Eq. (7) to calculate the permeability of the reservoirs.

$$K = \left( {250 \times \left( {\varPhi^{3} /S_{{{\text{wir}}}} } \right)} \right)^{2}$$
(7)

where K is permeability in millidarcy (mD), Ф is porosity (decimal), and Swir is irreducible water saturation (decimal). The irreducible water saturation is the amount of water in the oil zone calculated from Eq. (8).

$$S_{{{\text{wir}}}} = \left[ {C/\left( {\varPhi /\left( {1 - V_{{{\text{sh}}}} } \right)} \right)} \right]$$
(8)

where C is Buckles’s constant.

The geochemical logs allow for continuous high-speed analysis of C1 to C5 and CO2 every 30 s. The background liberated and produced gases were monitored for use in formation and safety evaluations. We interpreted some of the gases ratios, such as (C1/C2), to distinguish between producing and non-producing zones and oil gravity and (C4 + C3/C1) for oil saturation percentage and oil–water contact. The SRS Bottomhole sample performed several studies to determine the reservoir fluid’s phase behaviour. Quality and validity checks of the bottomhole sample, compositional analysis, constant composition expansion at reservoir temperature, differential liberation study at reservoir temperature, multi-stage separation test under specified conditions, and viscosity measurements at reservoir temperature are all included in the detailed analyses (Schlumberger Reservoir Laboratories 2017). The analysis was carried out on the fluid sample at a depth of 10,062 ft, under the pressure of 4892 psi, and at a temperature of 201° F. Also, the SARA analysis was applied to split the Saturates, Aromatics, Resins, and Asphaltenes on the flashed oil sample. These analysis results were compared with the petroleum system modelling to better understand hydrocarbon migration and reservoir charging.

Core and petrographic analysis

Seven core samples with 4 inches diameter conventional cores were acquired from the well BH-A11. Out of these, three cores total of 166.2 ft. were from the Zubair Formation, 36 ft. from the Ratawi Shale, 96 ft. from the Ratawi Limestone, and 100 ft, was from the Minagish Formation (Table 1). The acquired conventional core in this well shifted to match the depths of the open hole logs. A set of thin sections were prepared from the core samples to retain the original fabric and allow for a somewhat accurate visible measurement of porosity (Core Lab 2018). These samples were cleaned by soxhlet extraction in toluene, dried, and impregnated with blue-dyed epoxy. Thin sections were made by affixing a cut and polished surface of the impregnated sample to a glass slide, then cutting, lapping, and polishing the sample to a thickness of 30 microns. In a solution of Alizarin red and potassium ferricyanide, the thin slices were stained for carbonates and cobalt nitrate, and sodium nitrate for potassium feldspars. In addition, we used the scanning electron microscope (SEM) to understand better the texture, content, and distribution of porosity in reservoir rocks. The SEM can examine the microporosity distribution and inner structure visualization using micro-CT by giving us three-dimensional pictures created in stereo mode. It is beneficial for determining the distribution of microporosity, identifying interstitial clays via X-ray diffraction, and identifying minerals that could cause formation damage if they react with drilling or completion fluids. Also, the X-ray diffraction (XRD) analysis was used to detect the crystalline materials.

Table 1 Conventional Core Acquisition Summary for well BHSE-2
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We used the mud logs to determine the different stratigraphic units and their depth and thickness. Then, an integrated approach, including petrographic analysis of 71 samples for thin sections around the field, six samples for SEM, and six samples for XRD, was performed and employed to refine the core description and build the depositional model (Fig. 5). This approach sketch is supported by the detailed study that investigated the deposition environments of the Cretaceous formations, such as Bahman (2022), Cross et al. (2022), Hawie et al. (2022), and Aladwani (2022a, b).

Fig. 5
figure 5

Schematic illustrates the different depositional environments that deposited the sediment section under Bahrah Field, and the corresponding thin sections extracted from the core data

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Burial history

The 1D-Airy isostasy backstripping technique and petroleum systems modelling software simulated a basin reconstruction using the data in Table 2. This modelling aimed to identify hydrocarbon sources, reservoirs, and seals concerning the depositional and tectonic events that shaped the basin. For each time, we calculated total subsidence as the sum of the thicknesses of the units. Then, using Eq. (9) of Steckler and Watts (1978), the tectonic subsidence component was extracted from the total subsidence. This approach is explained by Lee et al. (2019), Müller et al. (2018), Diab and Khalil (2021), and Aladwani (2021).

$$z_{n} = s_{n} *\left\{ {\frac{{\rho_{{\text{m}}} - \rho_{{{\text{b}} }} }}{{\rho_{{\text{m}}} - \rho_{{\text{w }}} }}} \right\} + {\text{Wdi}} - \left\{ {\Delta {\text{SLi}}\frac{{\rho_{{\text{m}}} - \rho_{{{\text{b}} }} }}{{\rho_{{\text{m}}} - \rho_{{{\text{w}} }} }}} \right\}$$
(9)

where Wdi Paleo-water depth; ∆SLi Sea level Variation; ρm Mantle density and equal 3300 kg/m3; ρb The bulk density of each unit after applying the de-compaction correction; ρw Water density and equal 1000 kg/m3; and sn Total subsidence of the basin at time n. As a result of this equation, we tracked the total and tectonic subsidence with time.

Table 2 Input data used in basin simulation and 1D-Airy isostasy backstripping technique
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Results

Cretaceous depositional environment

The Cretaceous sediments deposited on an extended carbonate ramp formed during the Jurassic period. The environments on this ramp altered between outer-ramp, mid-ramp, inner-ramp, tidal channel, upper shoreface, foreshore, and distributary channel (Fig. 5). On the passive edge of the Arabian Plate and Neo-Tethys Ocean, the Minagish Formation was deposited on a broad, shallow intra-shelf to the inner mid-ramp environment (Abdel-Fattah et al. 2022; Cross et al. 2022; Al-Ameri et al. 2009; Al-Fares et al. 1998; Kadar et al. 2012; Filak et al. 2017; Youssef et al. 2014). The Ratawi Formation is divided into two sections: The Ratawi Shale and the Ratawi Limestone, consisting primarily of clean muddy limestones ranging from well-indurated skeletal wackestones to mud-rich packstones characterized by a diverse benthic faunal assemblage, often micritized and deposited in shallow, low-energy, protected carbonate mid-ramp conditions. Overlying the Ratawi Formation is the Zubair Formation (Hauterivian to Barremian), divided into Lower, Middle, and Upper Zubair. It can be considered a significant lowstand to a transgressive unit, although increased sediment supply (tectonic control) and climatic changes in the source area also influenced deposition (Figs. 4, 5). Clastic sediments dominate the Zubair Formation, including sandy shales interbedded with argillaceous sandstones and clean sandstones, formed in tidally influenced deltaic environments. In some locations, these pure sandstones, mostly quartz arenites, are interbedded with carbonaceous-rich sandstones and shales (Fig. 5). The clean sandstones were deposited as distributary channels on the delta plain and stacked to form amalgamated multilateral and multi-storied sand bodies.

The Thamama Group deposited in a humid climate than the preceding Late Jurassic Gotnia Evaporites and Hith Anhydrite deposits. It comprised an extensive carbonate platform or shelf around the Arabian shield. The Thamama Group’s uppermost interval, the Shuaiba Formation (Middle to Late Aptian), indicates a return to carbonate-dominated deposition, followed by erosion and unconformity surface (Alsharhan and Nairn 1986). Over the Shuaiba carbonates, a regional drop in sea level led to a deposition flux of a significant influx of terrigenous clastic, which formed the Burgan Formation (Fig. 4). In contrast, the Mauddud Formation, deposited on a low-angle carbonate ramp, comprises three classes; inner ramp deposits above fair-weather wave base, mid-ramp deposits zone that falls between fair weather and storm weather wave base, and deposits of an outer ramp which is defined as the zone below storm weather wave base (Fig. 5). The Wara Formation was formed in fluvial-deltaic to estuarine environments impacted by tides. Six depositional habitats have been identified on cores, with the bay head fluvial delta dominating landward and laterally passing into tidal estuarine mouth bars and sandy estuarine bay. In the Late Albian to Early Cenomanian, the Tuba Member, which comprises a carbonate reservoir, was deposited and overlined by a regional seal of the Ahmadi Shale Member, which deposited it in an inner-middle neritic marine environment. The Rumaila/Mishrif carbonate is deposited in a marine environment, while the contact between them occurs when the Rumaila facies transition to shallower Mishrif facies. Mishrif’s shallower facies are bioclastic wackestone to packstone with coralline fragments, providing a fair/good grade reservoir.

The Aruma group was deposited in the Upper Cretaceous period (Santonian—Maastrichtian) in shallow marine and lagoonal environments where Khasib and Murtiba formations were deposited. The Sadi, Hartha, and Qurna formations were deposited as the middle formations in the Aruma group, where the environment shifted to more open marine conditions. In contrast, the Tayrat Formation at the end of the Aruma group was deposited in relatively deep marine conditions dominated by shales and marly limestones (Al-Kahtany et al. 2016).

Petroleum system

The Bahrah Field in the north of Kuwait has two main petroleum systems: the Late Jurassic unconventional petroleum system and the Cretaceous conventional petroleum system. The thick Gotnia Evaporites and Hith Anhydrite separate the two petroleum systems (Aladwani 2021; Abdulla and Kinghton 1996; Abdel-Fattah et al. 2020). The Cretaceous reservoirs are the main contributor to the net hydrocarbon produced in Kuwait (Fig. 6), where the unconventional Jurassic Sargelu, Najmah, and Marrat reservoirs contributed recently to oil production (Abdullah and Connan 2002).

Fig. 6
figure 6

Schematic illustrates the total petroleum system elements in Bahrah Field

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Reservoir rocks

In the Bahrah Field, the confirmed reservoirs include the Mauddud, Burgan, Zubair, and Ratawi formations. The Mauddud Formation, a carbonate ramp succession deposited in the Upper Albian, is being explored. On the other hand, the Lower Albian Burgan Formation is a prominent exploration target in this area. The deeper Lower Cretaceous reservoirs are the Zubair, Ratawi, and Minagish formations. According to the 1D-Airy isostasy backstripping results, the reservoirs throughout the Cretaceous period were subjected to a variety of tectonic movements that varied in strength and timing, affecting subsidence and sedimentation rates and petrophysical characteristics, which affected the reservoir quality (Fig. 7). The Upper Albian Mauddud Formation was started to deposit from 104.5 Ma and lasted for 7.5 Ma, exposing to a minor tectonic event on the south Tethyan margin, subsiding it at a rate of 0.13 mm/year, and a major tectonic event due to thrusting the Arabian Plate beneath the Tethys oceanic lithosphere, subsiding it at a rate of 0.25 mm/year, (Fig. 7). In addition to the tectonic events that affected the Mauddud Formation, the Lower Albian Burgan Formation deposited from 112 to 104.5 Ma, lasted for 7.5 Ma, and was exposed to another minor tectonic event that occurred on the south Tethyan Margin, resulting in a subsidence rate of 0.06 mm/year The Barremian Zubair Formation began to deposit between 130.1 and 122.4 Ma, lasting 7.7 Ma, and was exposed to a third minor tectonic event on the south Tethyan Margin, resulting in a subsidence rate of 0.09 mm/year, on top of the preceding three tectonic movements. The Hauterivian/Valanginian Ratawi Formation began to deposit from 137.5 Ma. It lasted for 7.4 Ma, followed by a major tectonic event of breaking up at the northern Tethyan Margin, resulting in a significant subsidence rate of 0.26 mm/year. According to Zeiza et al. (2012), Zhou et al. (2016), and Donaldson et al. (1995), the differential subsidence rates are related directly to the sediment accumulation at a particular site, the source and the types of sediments, the erosion processes and sediments transportation.

Fig. 7
figure 7

The subsidence rate [mm/yr] was calculated from the 1-D backstripping technique using Python, showing the main tectonic events that affected the Cretaceous reservoirs related to their deposition time

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Mauddud reservoir

Based on integrating core analysis, wireline logs, and geochemical data, the Mauddud reservoir is described as highly layered and heterogenous on a pore to reservoir scale, ranging from MaA to MaJ units and mainly carbonate-dominated. Davies et al. (2002) interpret the maximum flooding surface (K110 of Sharland et al. 2001) of the lower Mauddud transgression. Above this, the carbonate-dominated strata of reservoir zones MaD and MaC show a progradational upward shallowing stacking pattern, corresponding to deposition in a highstand systems tract. The primary flow units have been coming from MaD and MaE units. The first unit is a MaD member that is a thick bed of grainstones, and clean packstones extend over the field area with excellent porosity (Avg. 15.3%, 13–17%), low shale volume (Avg. 6.75%, 3–11%), moderate water saturation (Avg. 39.5%, 28–65%), and moderate permeability of 10 mD (Fig. 8). The second unit is MaE Member and is not extended field-wide, concentrated in the southeast wells and some wells in the centre of the field. Its reservoir quality is less than the underlying MaD reservoir unit, with a mean porosity of 12.4%, average water saturation of 47.5%, and the same clay percentage as the MaD unit.

Fig. 8
figure 8

Layers of Petrophysical Parameters of Mauddud (MaD) reservoir showing the distribution of; the volume of shale (Vsh), effective porosity (Фe), and water saturation (Sw)

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Burgan reservoir

The Burgan Formation is a fluvial-deltaic succession of the Lower Cretaceous age, represents the erosion of the Arabian Shield situated to the west, and easterly transport to the margin marine setting of the present-day northern Arabian Gulf (Al-Eidan et al. 2001). Its thickness is about 1100 ft and consists of alternating cycles of sandstone and shale sequences. The Burgan Formation in Bahrah Field is subdivided—from top to bottom—into Upper Burgan shale (Top seal), Upper Burgan Reservoir, Middle Burgan reservoir, and Lower Burgan reservoir. The upward coarsening progradational complex of the Upper Burgan suggests highstand conditions (Fig. 4) which characterized the reservoir by mean porosity of 21%, mean water saturation of 32.1%, and mean clay percentage of 12.5% (Fig. 9). Core-permeability values derived from core-analysis data range from roughly 10 to over 1,500 mD (Avg. 513 mD). The lowstand deposition is most likely responsible for the Lower Burgan’s high net-gross fluvial channel complex, with incisions and hinterland regrowth coming from relative sea-level decline. The transition of the Middle Burgan to a more marine succession represents a new transgression. The Upper Burgan reservoir is the largest in the field, with a net pay of 11 ft, while we find the reservoir facies in the Middle and Lower Burgan in the central area of the field, with net pay ranging from 5 to 12 ft. Porosity ranges characterize the Middle and Lower Burgan reservoirs from 18 to 23%, water saturation ranges from 29 to 36%, and shale volume ranges between 11 and 17%.

Fig. 9
figure 9

Layers of Petrophysical Parameters of upper Burgan reservoir showing the distribution of; the volume of shale (Vsh), effective porosity (Фe), and water saturation (Sw)

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Zubair reservoir

The Zubair Formation has a heterogeneous reservoir quality, with sandy shales/mudstones ranging from insignificant to tight. The argillaceous sandstone facies have microporosity, clay matrix, and modest intergranular porosity. Clean sandstones, on the other hand, are porous, with intergranular cementation largely occluded. Because of the thick shale seal in the Lower Zubair Member and its presence in many wells throughout the field’s centre and southern sections, the Lower Zubair Member is the producing member of the Zubair Formation in Bahrah Field. In contrast, the Upper Zubair reservoir units are found in two wells in the north; besides, it is a high risk to development because of the probability of cross-fault oil leakage causing breached accumulations during structural re-activation. The Lower Zubair reservoir is characterized by average porosity of 14.2% (7.6–20%), average clay content of 12.8% (7.2–20.3%), average water saturation of 42.2% (19.5–100%) (Fig. 10), and average core-permeability of 1080 mD (0.01 mD–6180 mD). The resulted porosity showed a high correlation to the measured porosity from Routine Core Analysis (RCA) for the cores that have been collected from three wells (BH-A2, BH-A11, and BH-A13) in the south and the north of the field (Fig. 11).

Fig. 10
figure 10

Layers of Petrophysical Parameters of Lower Zubair reservoir showing the distribution of; the volume of shale (Vsh), effective porosity (Фe), and water saturation (Sw)

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Fig. 11
figure 11

Wells correlation joins wells BH-A2, BH-A11, and BH-A13 and shows good matching between the log-derived porosity and RCA Core for Zubair Formation

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Ratawi reservoir

The reservoir facies in Ratwai Formation is Lower Ratawi Limestone Member, where the limestones predominate, with textures ranging from mudstone to grainstone. Wackestone texture dominates, with mud-rich packstone areas alternating. Skeletal grains comprise the main structure within the packstones and wackestones, whereas non-skeletal peloids are modest to moderate. The reservoir potential is generally poor to negligible, especially in shale argillaceous mudstones, poor in marls due to abundant clay matrix, and moderate in clean lime mud-rich carbonate facies. This carbonate facies is predominantly microporous and associated within a matrix and micritized bioclasts with minor oil-stained intrafossil, mouldic, and vuggy pores and open fractures towards the tops of cycles (Fig. 12). An average net pay thickness of 47 ft characterizes the Ratawi Limestones reservoir. It has a mean porosity of 5.3% (3.7–6.7%), mean slay volume of 4.9% (1.2–7.6%), mean water saturation of 35.6% (28.7–47.4%), and average core-permeability of 20 mD, ranging from 0.01 to 1330 mD.

Fig. 12
figure 12

Layers of Petrophysical Parameters of Ratawi Limestone Reservoir showing the distribution of; the volume of shale (Vsh), effective porosity (Фe), and water saturation (Sw)

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Source rocks

The Early Cretaceous Sulaiy (Makhul) and Jurassic Najmah and Sargelu Formations are thought to be the source rocks for Kuwait’s hydrocarbons. Each source rock’s total organic content (TOC) varies regionally (Al-Wazzan et al. 2022; Bahman 2022; Aladwani 2022b; Al-khamiss et al. 2009; Jassim and Goff 2006; Abeed et al. 2011). The Sulaiy Formation’s TOC is typically around 2% across Kuwait with kerogen Type II (oil-prone) and Type II/III (oil/gas prone). Meanwhile, the Najmah Formation’s TOC is substantially wealthier, with values of > 6% and a dramatic decline in richness towards the western half of Kuwait. Najmah’s kerogen is Type II (oil-prone) and underlined by the Sargelu Formation, which has a 1–2 percent TOC, with Type II kerogen content decreasing towards western Kuwait (Al-Qaod 2017; Surdashy 1999). The burial history was created for the thick sedimentary Sect. (23,000–27,000 ft) in the northern basin and calibrated by the vitrinite reflectance (Ro) model of Burnham et al. (2017) (Fig. 13). The results show that the Ro for the hydrocarbon in the Permian Khuff Formation is over-maturated. The Sudai, Jilh, and Minjur formations show a dry gas Ro and wet gas to light oil in the Jurassic Marrat, Dhruma, Sargelu, and Najmah formations. Meanwhile, the oil expelled to the Cretaceous reservoirs maturated in the Lower Cretaceous Sulaiy and Minagish formations. It entered the oil generation window in the Middle Cretaceous before the migration time [50–60 Ma], where the vitrinite reflectance ranges between 1% Ro and 1.5% Ro, and the temperature ranges between 137 and 156 °C.

Fig. 13
figure 13

Burial history for well BH-A11 calibrated by overlying vitrinite reflectance (Ro) and showing the migration time

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Migration and sealing

To the east and offshore Kuwait, the more basinal locations and the fore-deep areas linked with the Zagros edge are thought to be kitchen sites for source rock maturation. Given the region’s prolific nature, the issue of source rock availability and proper migration is virtually moot. The deep-seated faults are most likely to charge the field directly from the underlying source rocks where the oil trap charge is most likely to originate. NNW-SSE longitudinal extension and transnational faults dominate the Bahrah Field. Migration into the North Kuwait fields began 50–60 million years ago and is still ongoing (Cross et al. 2010). Most of the oil has been migrated to Bahrah Field by spilling out from Sabriyah Field to the north as it fills until the spill point (Fig. 14A). In terms of trap size, the oil traps in Bahrah are considerably different from those in Sabriyah and Raudhatain fields. Long-range lateral migration from northern basinal areas filled the large anticlinal structures in the Sabriya and the Raudhatain fields to the point of spillover.

Fig. 14
figure 14

A Scheme of the large anticline under the Northern Basin joining the giant field (Raudhatain and Sabriya) on the down-dip of the anticline, while the Bahrah Field lies at the top of it and accumulates the oil spilled out from the down-dip fields; B E-W cross section across the Bahrah Field showing the mild throw of the faults that hit the anticline

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Further up-dip migration towards the Burgan arch filled the more subtle fault-bounded structural traps in Bahrah, like many other fields in the region. In Mauddud Formation, the primary vertical seals result from the layers with intense cementation associated with flooding events, where the sedimentation rates have been significantly reduced. Pro-deltaic mud rocks and minor sandstones seal the top of the Upper Burgan prior to carbonate deposition in the overlying Mauddud Formation. The vertical seal for the Zubair reservoirs is a thick shale throughout the entire Zubair and the thickest in Lower Zubair. In contrast, the Ratawi shale considers an excellent regional vertical seal for the Ratawi limestone that underlays the shale member.

Entrapping styles

The Bahrah Field is an onshore faulted anticline on Kuwait Bay’s north side. It is one of many comparable structural areas on the north–south Kuwait axis, a Paleozoic basement arch that has been intermittently reactivated from the mid-Cretaceous to the Tertiary (Carman 1996). As shown in the cross section (Fig. 14B), the Bahrah Field structure is an open closure, and the entrapment of oil is through small-scale subtle closures associated with faulting. As a result, individual closures have their oil–water contacts. The Bahrah structure is prone to three different types of faulting (Fig. 15A). First, there is a SE to NW trend of longitudinal extensional faults that primarily down-throw the SW. These faults are mostly found in the field’s northwest boundary and connect to similar faults in Sabriyah Field’s southern half. This pattern persists throughout the Bahrah structure, but throws are limited, and seismic characterization is unknown (Fig. 15B). A second substantial trend crosses the Bahrah Field from east to west, indicating a complex shear zone that is poorly delineated on seismic data. In the southern section of the field, the shear zone runs. The third set of faults runs parallel to the main extensional faults, from north to south. Due to their limited throw, these cross-faults provide rigid connections and are poorly imaged in seismic data. Nevertheless, they represent field-wide discontinuities observed clearly in seismic coherency.

Fig. 15
figure 15

A Structure depth contour map for top Zubair Formation showing the three sets of fault trending: SE–NW, E–W, and N–S; B E–W Seismic section showing the trapping anticline and its faulting system and shows the weakness of the amplitude at a depth of 8000 ft

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Reservoir fluid analysis

The analysis of reservoir gas values (Table 3) indicates that the Cretaceous reservoirs most likely have the same hydrocarbon source rock. The results show the presence of medium gravity oil with API 35.1 and under-saturated oil for the fluid collected from the different reservoirs. As a result of the SARA analysis (Fig. 16A), two different gas analysis detectors have detected the gaseous mixtures: one is a natural gas configuration, and the other is an extended gas configuration (Fig. 16B). The natural gas arrangement uses helium as a carrier gas and includes packed columns and a Thermal Conductivity Detector (TCD) detector where N2, CO2, H2S, C1 to nC4 can be detected. The extended gas arrangement uses helium as a carrier gas and includes a capillary column and a Flame Ionization Detector (FID) detector (Fig. 16C). The detection range covers C1 to C15, including the corresponding common isomers, and the temperature programming is non-isothermal, ramping to 464 °F.

Table 3 Reservoirs gas composition using a thermal conductivity gas chromatograph
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Fig. 16
figure 16

A SARA Analysis of the bottom-hole fluid sample shows its saturation with Saturates, Aromatics, Resins, and Asphaltenes; B Thermal conductivity detector (TCD) gas chromatogram of flashed gas of the bottom-hole sample; C Flame ionization detector (FID) gas chromatogram of flashed gas of the bottom-hole sample

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Discussion

Our finding was correlated to the previous studies that handled the petroleum geology of the Cretaceous age in Kuwait, such as Jassim and Goff (2006), Aqrawi and Badics (2015), Aqrawi et al. (2010), Abdulla and Connan (2002). At the end of Jurassic time, Kuwait became a part of an extended carbonate ramp formed at the northern east margin of the Arabian Plate as a top surface of thick carbonate sediments which deposited during the Jurassic time on the Neo-Tethys passive margin (Fig. 1B–D) (Alsharhan and Nairn 1986; Sharland et al. 2001). Consequently, the Cretaceous deposits formed on a carbonate ramp in environments alternate between outer-ramp/open marine, mid-ramp, inner-ramp, deltaic/lagoonal, and braided channels (Fig. 5). As a result, it deposited many sand intervals, such as Zubair, Burgan, and Wara formations representing the major Cretaceous reservoirs besides the Mauddud and Ratawi Limestone reservoirs (Figs. 2, 4). The 1D-Airy isostasy backstripping technique indicated that the Cretaceous reservoirs’ exposure to two major tectonic events resulted from thrusting the Arabian Plate under the Tethys oceanic lithosphere and breaking up in the northern Tethyan Margin. Besides, the area was exposed to three minor tectonic events on the south Tethyan Margin (Fig. 7). These tectonic events caused an abrupt change in the subsidence rates, which affected the reservoir facies as a decrease in porosity and permeability; consequently, the quality of the reservoirs has been changed due to the various subsidence rates associated with these tectonic movements. As a result, the Cretaceous reservoirs, from up to down, Mauddud, Burgan, Zubair, and Ratawi Limestone, show a different reservoir quality (Figs. 8, 9, 10, 12). This variety in the reservoir quality is due to the different depositional environments, which range from the braided channel on the tidal flat (Burgan and Zubair formations) passing through the inner to mid-ramp (Mauddud Formation), ending by the outer-ramp for Ratawi limestone Formation (Fig. 5).

The geochemical analysis of the oil produced from the different reservoirs shows a similar API of 32–35 (Table 3), indicating most likely the same source rock of the expelled oil. The source rock of these reservoirs is considered the Berriasian Sulaiy/Makhoul Formation because of the thick Gotnia Evaporites and Hith Anhydrite at the Jurassic-Cretaceous boundary separate the Cretaceous formations from the Jurassic Najmah and Sargelu formations. The hydrocarbon reached oil maturity in the Middle Cretaceous and expelled the oil in the Late Cretaceous (50–60 Ma) (Fig. 13). The hydrocarbon is believed to mature in the basinal area to the east offshore area at the Zagros margin and then migrate to the large anticlines under the North Kuwait, a part of the Kuwait Arc (Al-Eidan et al. 2001). To the north of the Bahrah Field, the super-giant fields of Raudhatain and Sabriyah lie down-dip and are filled to spill-out points, then migrated laterally to the Bahrah anticline (Fig. 14A). On the other hand, we cannot avoid the possibility of vertical migration through the extended faults. The Bahrah anticline’s axis runs NW–SE with an NW dip direction. It has a difference of 1950 ft in elevation between the highest point (6500 ft) to the SE and the lowest point (8450 ft) to the NW of the field. The anticline’s western flank has a steeper dip magnitude (4–5°) than the eastern flank (2–3°) (Figs. 14B, 15A). Also, the seismic shows three sets of longitudinal extensional faults; SE-NW, E-W, and N-S trending (Fig. 15A, B). However, due to a lack of 3D seismic coverage, the anticline’s southeast end is not delineated.

Conclusion

  • This study investigated the Cretaceous total petroleum system in the Bahrah oil field, one of the largest three fields in the northern basin of Kuwait.

  • The wireline logs were used to define and delineate the reservoir facies in the Cretaceous succession and produce petrophysical maps for the Mauddud, Burgan, Zubair, and Ratawi Limestone reservoirs.

  • The core data were used to investigate the reservoir porosity, permeability, and depositional environments. Besides, the burial history model and backstripping technique were used to simulate the basin reconstruction and better understand the petroleum system and tectonic events that affected the area.

  • We carried out the chemical analysis of the reservoir fluid for all the Cretaceous reservoirs due to the differentiation between their fluid content.

  • The results of this research indicated that the potential reservoirs in the Cretaceous period are Mauddud (MaD and MaE), Upper Burgan, Lower Zubair, and Ratawi Limestone reservoir. In contrast, other non-productive Cretaceous reservoir facies contain residual oil.

  • Secondly, the Sulaiy (Makhoul) and Minagish formations appear to be the same source rocks for the prolific oil in the Cretaceous, with the probability of vertical migration of the oil from the Jurassic Sargelu and Najmah formation through the faults that appeared on seismic.

  • Thirdly, the primary trapping style in the field is faulted anticline with some stratigraphic traps in the Burgan and Zubair formation due to the fluvio-deltaic deposition environment.

  • Finally, the quality of the reservoirs decreased as going downwards during the Lower Cretaceous towards the Ratawi Limestone reservoir due to exposing them to various tectonic events, making them different in their petrophysical properties because of their significant difference in the burial.

  • This study provided a better understanding of the subsurface scenario for the oil generation, migration, and accumulation in the Cretaceous age by delineating the reservoir facies that have more potential to store this oil.