Reservoir Units Research Articles

Permeability's response to dolomitization, clues from Permian–Triassic reservoirs of the central Persian Gulf

Understanding the pattern of spatial permeability distribution in carbonate reservoirs strongly depends on its relationships to geological factors. Despite this importance, the relationship between dolomitization and permeability changes is poorly understood. This study represents the effects of dolomitization on permeability variations in carbonate Permian–Triassic strata of the central Persian Gulf. Porosity and permeability measured on 1389 plug samples using Boyle and Darcy lows, respectively. Petrographical studies under a polarizing microscope showed that various types of facies are recognizable including boundstone, mudstone, wackestone, packstone and grainstone. Dolomitization and dissolution are the main diagenetic processes. Permeability increases along with dolomite content in the samples with higher than 1 mD permeability. Dolomitization of the allochems increased the interparticle spaces and so improved the pore connectivity. High permeability is also due to the intercrystalline pores between dolomite crystals and vuggy porosities which have been created as the result of high degree of dolomitization. Classifying the dolomitic rocks based on dolomite crystal shapes indicates that nonplanar dolomites are more frequent in the samples with less than 0.001 mD permeability while samples with more than 1 mD permeability have more euhedral dolomites. The subhedral dolomites are more frequent in the sample with 0.1–1 mD permeabilities. Nonplanar dolomites are more abundant in K1 and K3 units which are non-reservoir parts. Also, pore spaces in coarse crystal dolomites are connected to each other more effectively, which mainly occurs in K2 and K4 reservoir units. Pore typing in the studied carbonates demonstrates that moderate amounts of dolomites (about 50%) connect the other pore types while they produce a contiguous pore network in higher quantities. In the samples with more than about 60% dolomites, the intercrystalline pores are combined together and touching vugs are created, which strongly increase the permeability of the samples.

Rate transient analysis for coupling Darcy flow and free flow in bead-string fracture-caved carbonate reservoirs

Fluid flow dynamics in fracture-caved carbonate reservoirs are usually simulated using the traditional continuum flow theory. With the presence of large karst caves, fluid flow in these reservoirs may not always obey the Darcy law. Actually it follows the pipe flow, free flow or Darcy law-coupled free flow. The continuum flow theory is therefore not able to accurately capture the underlying flow dynamics within the large karst caves. Large caves in fracture-caved reservoir are widely interconnected with a series of tectonic fractures, which resembles a string of beads and is thus defined as a multi-cave multi-fracture reservoir unit. By simplifying the configuration of actual fracture-caved carbonate reservoir as a multi-cave multi-fracture series connection domain, this paper develops a novel mathematical model to accurately describe the complicated fluid behaviors coupling Darcy flow and free flow, among of which the fluid flow in fractures still obeys the Darcy law while that in large caves is assumed to free flow. A semi-analytical solution of the proposed model is then derived in order to plot the dimensionless typical curve for rate transient analysis (RTA) in fracture-caved reservoir. Factors affecting the characteristics of the RTA typical curve are further investigated. Finally, case study in a bead-string fracture-caved reservoir unit is performed to estimate the reservoir and well properties using the proposed model. The deep understandings can provide good insights for reasonable exploitation of this type of fracture-caved carbonate reservoirs.

Controls on hydrocarbon accumulation by facies and fluid potential in large-scale lacustrine petroliferous basins in compressional settings: A case study of the Mesozoic Ordos Basin, China

Large-scale lacustrine basins in compressional settings are an important type of petroliferous basin, and the study of the characteristics of hydrocarbon accumulation in such basins is of great significance. This synthesis paper takes the Mesozoic Ordos Basin (central China) as a case study to establish lateral and vertical hydrocarbon accumulation patterns in this basin type, and highlights how facies and fluid potential control hydrocarbon accumulation in such basins. Based on systematic analyses of the Mesozoic source rocks, sedimentary facies, migration and accumulation patterns, and characteristics of the oil reservoirs, the hydrocarbon accumulation characteristics in the Mesozoic Ordos Basin are discussed. The analysis indicates that sedimentary facies controlled the characteristics and distribution of hydrocarbon source rocks and reservoirs, while diagenetic facies controlled the quality and distribution of the reservoirs. Excess pressure and fluid potential controlled hydrocarbon migration directions and paths, whereas facies and potential controlled the locations of oil accumulations and traps. It is concluded that source rocks controlled oil-bearing regions, sedimentary facies controlled oil-bearing plays, and fluid potential controlled the locations of accumulations. For shallow intervals, because fluid migration is mainly controlled by buoyancy, paleotopographic highs played an important role in controlling hydrocarbon accumulations. For deep layers (Chang 7 to Chang 10 members), since buoyancy is less than the capillary pressure, excess pressure caused by the undercompaction of mudstone and hydrocarbon generation at depth provides the driving force for lateral and vertical migration of oil, and becomes the main migration force. The reservoir accumulation characteristics differ laterally between regions of the basin; at the periphery of the basin, reservoir units are stacked in a step-wise manner, whereas at the center of the basin, multiple reservoir intervals are vertically stacked in the form of multistorey accumulations. Vertically, layers with different burial depths have different accumulation characteristics; the paleotopography controlled hydrocarbon accumulation in shallow intervals; instead excess pressure, fluid potential, and paleotopography controlled accumulation in deep intervals. This understanding could be used to inform prospecting in other large-scale lacustrine petroliferous basins in compressional settings such as the Eocene Green River Basin in the U.S.A. and the Middle Triassic Gunnedah Basin in Australia.

Sandbody architecture analysis of braided river reservoirs and their significance for remaining oil distribution: A case study based on a new outcrop in the Songliao Basin, Northeast China

The reservoir architecture analysis of braided rivers, especially falling-silt seam forms, has played a key role in predicting remaining oil distributions. However, no studies have used architecture analyses that document braided river outcrops and researched the tapping of the few remaining oil distributions based on outcrops in the Songliao basin, northeast China. In this paper, the architecture characteristics and remaining oil distribution of braided river reservoirs are studied using a combination of an outcrop, modern deposition and subsurface well data. The new 8–13 m thick Lower Cretaceous Quantou Formation outcrop of the Songliao basin is a braided fluvial succession arranged in one large fining-upward cycle. Eight facies (Gt, St, Sm, Sh, Sp, Sw, Fl and Fm), four architecture elements (CH, DA, LV, and FF), and three orders of bounding surfaces (third-, fourth-, and fifth-order) are recognized. A new distribution pattern of falling-silt seams and a braided river architecture model are presented according to the analysis of the outcrop. In the mid-channel bar, the falling-silt seams thin from the mid-bar to the bar tail following the flow direction. Each falling-silt seam is oriented tangentially to the basal surface of the mid-channel bar, and the upper falling-silt seam extends farther than the lower one. In a Daqing Oilfield exploitation block in the Songliao basin, while channels and bars are the main reservoir units, they have different remaining oil distribution patterns. For bars, water injection wells located at the mid-bar, zonal injection technology, the drilling of horizontal wells, and proper well patterns are proposed. Fourth-order bounding surfaces, single braided channels, stacking patterns, and the lateral blocking of levees and floodplains are the key factors affecting the remaining oil distribution in channels.

Sedimentological analysis and reservoir characterization of an estuarine bar: An example from the El-Basant Gas field, Nile Delta, Egypt

Estuarine tidal bar reservoirs are challenging due to their complex architecture and limited examples. This study represents an integrated sedimentological analysis and reservoir characterization for estuarine bars using an example from El-Basant Gas Field (East Nile Delta). In this study, the sedimentological analysis and neural network techniques are employed to characterize hydraulic flow units of an estuarine bar reservoir using core, borehole image, and log data. The available integrated core and borehole image data help to subdivide the estuarine bar into six sedimentary facies types and are grouped into four facies associations: proximal tidal bar, distal tidal bar, estuarine mud, and tidal channel. The estuarine bar reservoir is subdivided into three main flow units based on the sedimentary fabric. Flow unit 1 characterizes the mud-free sandstones of proximal tidal bar and tidal channel associations. Flow units 2 and 3 characterize the mud-rich sandstones of the distal tidal bar and the upper part of the tidal channel. The diagenetic impact appeared in the reduced quality of the tidal bar deposits due to patch cementation and mud-filled, small-scale fractures and faults.

Non-destructive techniques for linking methodology of geochemical and mechanical properties of rock samples

Inadequate conventional core data, increasing cost of native sampling techniques, economic downturn in the oil sector, sparse distribution of modern well log suites in horizontal wells, and data acquisition challenges are few among the reasons driving innovation in the use of drill cuttings for determining rock properties and adequate characterization of reservoir units. In this paper, we propose a rock strength proxy based on the correlation between rock strength and elemental geochemistry. The technique uses a combination of X-ray fluorescence and rebound impulse hammer measurements to establish links between the geochemical and mechanical properties of the sampled rocks. We identified five chemo-mechanical facies (CMF) that are formation specific. Furthermore, a cross-validation approach was used to build a predictive model based on acquired elemental and impulse hammer measurements. Consequently, the model was used to predict elastic property and results were encouraging with R2 of 0.83, 0.87, and 0.89 for training, validation, and testing respectively. This proposed method was developed using core plugs retrieved from subsurface formations. It will be useful for examples in rapid assessment of drill cuttings for the determination of rock strength, especially where the only available data is elemental geochemical data.

Uncertainty Quantification through Dropout in Time Series Prediction by Echo State Networks

The application of echo state networks to time series prediction has provided notable results, favored by their reduced computational cost, since the connection weights require no learning. However, there is a need for general methods that guide the choice of parameters (particularly the reservoir size and ridge regression coefficient), improve the prediction accuracy, and provide an assessment of the uncertainty of the estimates. In this paper we propose such a mechanism for uncertainty quantification based on Monte Carlo dropout, where the output of a subset of reservoir units is zeroed before the computation of the output. Dropout is only performed at the test stage, since the immediate goal is only the computation of a measure of the goodness of the prediction. Results show that the proposal is a promising method for uncertainty quantification, providing a value that is either strongly correlated with the prediction error or reflects the prediction of qualitative features of the time series. This mechanism could eventually be included into the learning algorithm in order to obtain performance enhancements and alleviate the burden of parameter choice.

Forecasting shale gas performance using the Connected Reservoir Storage Model

Characterized by rock sediments and complicated storage mechanisms, shale reservoir development is to create flow systems comprised of complex natural fissures and hydraulic fracture stimulation such that the hydrocarbons in the reservoir can be recovered economically. The prediction of shale reservoir production performance is critical for reservoir management and challenging due to the compounding nature of multiple flow mechanisms one encounters during the life of a shale gas well. Given empirical nature, many models based on curve-fitting historical production data prone to inaccurately forecast well's rates in shale gas reservoirs, particularly when the production history of a well is short. This paper further extends the applicability of the Connected Reservoir Storage Model (CRSM) to shale reservoirs. The CRSM was derived from diffusivity theory by using historical production rate and bottomhole flowing pressure (BHFP) to determine the reservoir behavior and unit pressure response, and it can be conveniently used to predict production performance under variable operating conditions. The CRSM is mathematically robust and easy for application since it can be determined with limited reservoir information without knowing the reservoir geometry or reservoir permeability. This study uses the operational history of a shale gas well to demonstrate the CRSM's capability in rate prediction and couples the model with stochastic methods to approximate the most probable outcome under variable operating conditions.

Geological model Construction for Yamama Formation at Faihaa Oil Field- South of Iraq

A construction of a 3D geological model of Yamama Formation to explain the distribution of petrophysical properties (shale volume, effective porosity and hydrocarbon saturation) by using Petrel software. Five wells were selected in order to build structural and petrophysical models based on interpretation of well logs and petrophysical properties. Yamama reservoir is divided into four main units (YA, YB, YC, and YD), YA is divided into five secondary reservoir units (YA1, YA2, YA3, YA4, and YA5), YB is divided into two secondary reservoir units (YB1 and YB2), YC is divided into two secondary reservoir units (YC1 and YC2) and YD is divided into three secondary reservoir units (YD1, YD2, and YD3). Structural model showed Faihaa oil field represented by anticlinal fold with double plunging. Petrophysical models (shale volume, effective porosity and hydrocarbon saturation) constructed for each subunit of Yamama reservoir using sequential Gaussian simulation executed with Petrel software. According to data analyzes and the results from modeling, the subunits for both YB and YB are good reservoir units regarding its good petrophysical properties (high effective porosity and high hydrocarbon saturation) and considered as the most important productive units in Yamama Formation

Estimating reservoir geomechanical parameters for enhanced reservoir characterization: case study of “Tobi” field, Niger Delta

Reservoir geomechanical parameters in “Tobi” Field, Niger Delta were estimated using well log data with the intention of improving reservoir characterization and establishing stress regime of the field. A suite of well log data were interpreted, reservoirs were identified and correlated across three (3) wells and their geomechanical parameters computed from empirical relations. Three (3) reservoir units were delineated from these wells that falls within the hydrocarbon windows (Agbada Formation). We estimated several geomechanical parameters, which include, but is not limited to, Young’s modulus, Poisson’s ratio, bulk compressibility, unconfined compressive strength (UCS), shear modulus, heat production, vertical stress (overburden), minimum horizontal stress, maximum horizontal stress, shear stress normal to fault plane, shear stress in direction of dip, and shear stress in direction of strike. The bivariate crossplots of heat production and Young’s modulus indicated that the amount of heat produced by the shaly materials affects the elastic properties of the reservoir units and flow rate. The crossplots of Poisson’s ratio versus compressional velocity are expressly well-defined and exponentially decaying with the compressional velocity, indicating an inverse relationship between the two (2) parameters. For stress tensor analysis, the study confirmed the defining condition of Sv > SHmax > Shmin as normal fault, which is fault regime prevalent in the study area, in line with Andersen’s classification. Rotation of principal stresses on fault plane showed negative shear stress in strike direction. This research concluded that geomechanical parameters of hydrocarbon reservoirs in “Tobi” field are diagnostic in reservoir characterization and in establishing the type of faults in reservoirs.

Reservoir Potential Evaluation of the Middle Paleocene Lockhart Limestone of the Kohat Basin, Pakistan: Petrophysical Analyses

The Lockhart Limestone is evaluated for its reservoir potential by utilizing wireline logs of Shakardara-01 well from Kohat Basin, Pakistan. The analyses showed 28.03% average volume of shale (Vsh), 25.57% average neutron porosity (NPHI), 3.31% average effective porosity (PHIE), 76% average water saturation (Sw), and 24.10% average hydrocarbon saturation (Sh) of the Lockhart Limestone in Shakardara-01 well. Based on variation in petrophysical character, the reservoir units of the Lockhart Limestone are divided into three zones i.e., zone-1, zone-2 and zone-3. Out of these zones, zone-1 and zone-2 possess a poor reservoir potential for hydrocarbons as reflected by very low effective porosity (1.40 and 2.02% respectively) and hydrocarbon saturation (15 and 5.20%), while zone-3 has a moderate reservoir potential due to its moderate effective porosity (6.50%) and hydrocarbon saturation (52%) respectively. Overall, the average effective porosity of 3.31% and hydrocarbon saturation of 24.10% as well as 28.03% volume of shale indicated poor reservoir potential of the Lockhart Limestone. Lithologically, this formation is dominated by limestone and shale interbeds in the Shakardara-01 well. Cross-plots of the petrophysical parameters versus depth showed that the Lockhart Limestone is a poor to tight reservoir in Shakardara-01 well and can hardly produce hydrocarbons under conventional drilling conditions.

Reservoir Potential Evaluation of the Middle Paleocene Lockhart Limestone of the Kohat Basin, Pakistan: Petrophysical Analyses

The Lockhart Limestone is evaluated for its reservoir potential by utilizing wireline logs of Shakardara-01 well from Kohat Basin, Pakistan. The analyses showed 28.03% average volume of shale (Vsh), 25.57% average neutron porosity (NPHI), 3.31% average effective porosity (PHIE), 76% average water saturation (Sw), and 24.10% average hydrocarbon saturation (Sh) of the Lockhart Limestone in Shakardara-01 well. Based on variation in petrophysical character, the reservoir units of the Lockhart Limestone are divided into three zones i.e., zone-1, zone-2 and zone-3. Out of these zones, zone-1 and zone-2 possess a poor reservoir potential for hydrocarbons as reflected by very low effective porosity (1.40 and 2.02% respectively) and hydrocarbon saturation (15 and 5.20%), while zone-3 has a moderate reservoir potential due to its moderate effective porosity (6.50%) and hydrocarbon saturation (52%) respectively. Overall, the average effective porosity of 3.31% and hydrocarbon saturation of 24.10% as well as 28.03% volume of shale indicated poor reservoir potential of the Lockhart Limestone. Lithologically, this formation is dominated by limestone and shale interbeds in the Shakardara-01 well. Cross-plots of the petrophysical parameters versus depth showed that the Lockhart Limestone is a poor to tight reservoir in Shakardara-01 well and can hardly produce hydrocarbons under conventional drilling conditions.

Cretaceous petroleum system modeling of Kairouan Basin in eastern Tunisia

Upper Cretaceous deposits in central eastern Tunisia represent a potential proven source rocks from Cenomanian–Albian Fahdene and Turonian Bahloul Formations and reservoir rocks of Turonian Bireno, Douleb, and Campanian–Maastrichtian Abiod Formations. The latter form the main oil and gas field systems in onshore and offshore central eastern Tunisia. Seismic tectonics and seismic stratigraphy based on 2D seismic analyses calibrated to the petroleum well’s wireline logging led to the identification of source rock and reservoir sequence distribution between high platforms and subsiding basin areas. This structuring has been created by inherited deep-seated transtensive and transpressive flower faults (Kairouan-Sousse, Hdadja, El Jem, Mahdia, etc.) that are intruded by Triassic halokinetic evaporites. Geochemical analyses and modeling of the well and pseudo-well deposits using BasinMod 1D software from a plate river had permitted to differentiate kitchen areas, within the basin areas, that have high maturity level (late oil to gas generation phase) of Fahdene and Bahloul Cretaceous source rocks. The neighboring high flank structures might constitute good traps to accumulate expelled materials. The large-scale fault system and the dense fracture network related to the Kairouan Basin borders represent a preferential pathway for fluids to reach updip flank reservoir units. The geochemistry modeling was performed in order to characterize the maturity, generation, and expulsion timing of hydrocarbons. In addition, this study highlights the great gas shale potential steel remaining in the subsiding basin kitchens.

Hartha Formation divisions Based on Well Logs Analysis in Majnoon Oil Field, Southern Iraq

This study aims to evaluate reservoir characteristics of Hartha Formation in Majnoon oil field based on well logs data for three wells (Mj-1, Mj-3 and Mj-11). Log interpretation was carried out by using a full set of logs to calculate main petrophysical properties such as effective porosity and water saturation, as well as to find the volume of shale. The evaluation of the formation included computer processes interpretation (CPI) using Interactive Petrophysics (IP) software. Based on the results of CPI, Hartha Formation is divided into five reservoir units (A1, A2, A3, B1, B2), deposited in a ramp setting. Facies associations is added to well logs interpretation of Hartha Formation, and was inferred by a microfacies analysis of thin sections from core and cutting samples. The CPI shows that the A2 is the main oil- bearing unit, which is characterized by good reservoir properties, as indicated by high effective porosity, low water saturation, and low shale volume. Less important units include A1 and A3, because they have low petrophysical properties compared to the unit A2.

Petrophysical analysis of well logs data for identification and characterization of the main reservoir of Al Baraka Oil Field, Komombo Basin, Upper Egypt

The current study presents the log analysis results from two vertical onshore wells in Al Baraka oil Field, Komombo basin, upper Egypt. The Geophysical logs comprising gamma ray (GR), caliper (Cali), resistivity (LLD, LLS, and MSFL), photoelectric effect (PEE), neutron (NHPH) and density (RHOB) are used to study the petrophysical characteristics of the main identified reservoirs in this field. The key purpose of well logging analysis and interpretation is to obtain petrophysical properties of reservoirs such as shale volume, porosity, hydrocarbon saturation, net pay thickness, etc., for hydrocarbon exploration. Petrophysical analysis of well logs reveals that Al Baraka wells consist of three types of lithology: sand, shale, and siltstone. The obtained results show that there are two hydrocarbon-bearing zones named (S-E) and (S-D) zone for Al Baraka-4 well and Al Baraka-14 well, respectively; both had hydrocarbon reservoir bearing oil and lie in Six Hills Fm of the Lower Cretaceous. The generated cross-plots showed that the main reservoir lithology is composed of shaley sandstone to sandstone. The computed petrophysical parameters for the identified and characterized reservoir layers reveal that they have a total porosity range of 18.2–20.1%, water saturation of 57.7–36.6%, shale volume of 20–8.5% for (S-E) and (S-D) zone, respectively. The hydrocarbon saturation reaches to 42.5% for (S-E) zone and 36.6% for (S-E) zone; both hydrocarbons in these zones are movable. The net reservoir pay thickness is high in (S-E) zone reach to 24 ft. Below and above the oil-bearing reservoirs, there is a thick shale bed which acts as potential source rock or as a seal rock. The overall results indicated that the sandy reservoir units of ‘Al Baraka’ Field have the potential to contain significant accumulations of hydrocarbon, essential oil. It is recommended to integrate more wells and seismic data to better evaluate the reservoirs.

Healing Behavior of Simulated Fault Gouges From the Groningen Gas Field and Implications for Induced Fault Reactivation.

We investigated the frictional strength recovery (healing) and subsequent reactivation and slip‐weakening behavior of simulated fault gouges derived from key stratigraphic units in the seismogenic Groningen gas field (N. E. Netherlands). Direct‐shear, slide‐hold‐slide (SHS) experiments were performed at in situ conditions of 100 °C, 40 MPa effective normal stress and 10–15 MPa pore fluid pressure (synthetic formation brine). Sheared gouges were allowed to heal for periods up to 100 days before subsequent reshearing. The initial coefficient of (steady) sliding friction μ was highest in the Basal Zechstein caprock (μ = 0.65 ± 0.02) and Slochteren sandstone reservoir (μ = 0.61 ± 0.02) gouges, and the lowest in the Ten Boer claystone at the reservoir top (μ = 0.38 ± 0.01) and in the Carboniferous shale substrate (μ ≈ 0.45). Healing and subsequent reactivation led to a marked increase (∆μ) in (static) friction coefficient of up to ~0.16 in Basal Zechstein and ~0.07 in Slochteren sandstone gouges for the longest hold periods investigated, followed by a sharp strength drop (up to ~25%) and slip‐weakening trajectory. By contrast, the Ten Boer and Carboniferous gouges showed virtually no healing or strength drop. Healing rates in the Basal Zechstein and Slochteren sandstone gouges were significantly affected by the stiffness of different machines used, in line with the Ruina slip law, and with a microphysical model for gouge healing. Our results point to marked stratigraphic variation in healed frictional strength and healing rate of faults in the Groningen system, and high seismogenic potential of healed faults cutting the reservoir and Basal Zechstein caprock units, upon reactivation.

Reservoir Rock Properties of the Upper Cretaceous Shiranish Formation in Taq Taq Oilfield, Iraqi Kurdistan Region

Reservoir rock properties of the tight carbonate of Upper Cretaceous Shiranish Formation was studied in three selected wells in Taq Taq Oilfield/ Iraqi Kurdistan Region. The penetrated thickness of the formation by the studied wells of TT-04, TT-20, and TT-21 were 249, 290.8, and 236m respectively. The available logs and core test data were mainly dependant in characterizing the formation. The dominant limestone lithology of the formation was identified using Neutron-Density and M-N crossplots. The shale content, as calculated from the Gamma ray log, appeared to be highest in the lower part of the formation with about 15-30%. The shale content of Shiranish Formation are mainly consists of Glauconite, Illite, and Micas with a little contribution from other kinds of clay minerals like Montmorillonite. The total porosity of Shiranish Formation is generally less than 10% whereas the lower part of the formation has the lowest porosity (less than 5%). The calculated permeability through Multiple Regression Analysis method and by using the available core test data showed that The formation is generally of less than 10mD permeability. The lower part of the formation (at the two wells of TT-20 and TT-21) has relatively higher permeability compared to the middle and upper part of the formation. Three distinctive reservoir units were identified in this study in Shiranish Formation depending on variations in the shale content, porosity, and permeability. Reservoir unit (RU-1) at the upper part of the formation in the well TT-21is considered to be of the best reservoir property among the identified reservoir units in the three studied wells. The expected contribution of minor and large fractures in enhancing the permeability of the formation approved through output of the existed Formation Micro Image log for the lower part of the formation in the well TT-21.

PETROLEUM SYSTEMS OF THE BONGOR BASIN AND THE GREAT BAOBAB OILFIELD, SOUTHERN CHAD

The Bongor Basin in southern Chad is an inverted rift basin located on Precambrian crystalline basement which is linked regionally to the Mesozoic – Cenozoic Western and Central African Rift System. Pay zones present in nearby rift basins (e.g. Upper Cretaceous and Paleogene reservoirs overlying Lower Cretaceous source rocks) are absent from the Bongor Basin, having been removed during latest Cretaceous – Paleogene inversion‐related uplift and erosion. This study characterizes the petroleum system of the Bongor Basin through systematic analyses of source rocks, reservoirs and cap rocks.Geochemical analyses of core plug samples of dark mudstones indicate that source rock intervals are present in Lower Cretaceous lacustrine shales of the Mimosa and upper Prosopis Formations. In addition, these mudstones are confirmed as a regional seal. Reservoir units include both Lower Cretaceous sandstones and Precambrian basement rocks, and mature source rocks may also act as a potential reservoir for shale oil. Dominant structural styles are large‐scale inversion anticlines in the Lower Cretaceous succession whilst underlying “buried hill” ‐type basement plays may also be important. Accumulations of heavy to light oils and gas have been discovered in Lower Cretaceous sandstones and basement reservoirs.The Great Baobab field, the largest discovery in the Bongor Basin with about 1.5 billion barrels of oil in‐place, is located in the Northern Slope, a structural unit near the northern margin of the basin. Reservoirs are Lower Cretaceous syn‐rift sandstones and weathered and fractured zones in the crystalline basement. The field currently produces about 32,000 barrels of oil per day.

Petrophysical characterization of the tertiary oil reservoir, Northern Iraq

This paper introduces a comprehensive petrophysical study to re-evaluate reservoir quality of ‘Main Limestone’ reservoir units for one Iraqi oil field using modern software and techniques. In this study, we discussed many subjects, such as petrophysical effects on hydrocarbon accumulation, hydrocarbon mobility, and hydrocarbon productivity of the field. The determining reservoir properties include formation porosity, hydrocarbon, and water saturation, as well as net/gross thickness ratio, which is determined depending on wire-line logs data. For reservoir description, full sets of well log data such as gamma-ray, resistivity, neutron log, form three wells were interpreted and analyzed. The performed analysis includes many subjects such as lithology description, reservoir identification, reservoir fluid type identification, well correlation, reservoir porosity, saturation (for hydrocarbon and water) determination. Petrophysical properties parameter of ‘Main Limestone’ reservoir rocks exposed that unit 'B' has better properties compared with other units. The most overall porosity type was primary porosity through the entire formations and units. Water saturation and shale volume estimations indicated the water saturation significantly affected by an increase in the shale quantity if shale volume exceeds 10%.

Geomechanical characteristics of potential carbon dioxide sinks and seals in the DeSoto Canyon Salt Basin, eastern Gulf of Mexico

Recent studies indicate vast storage capacity exists in Cretaceous and Paleocene–Miocene sandstones in the eastern Gulf of Mexico. Understanding the geomechanical integrity of reservoirs and associated seals is useful for reducing the risk of migration of injected CO2 out of the storage complex. In this study, we investigated the rock mechanical properties and reservoir-seal integrity of three potential reservoir units in the DeSoto Canyon Salt Basin using geophysical well logs. Geomechanical analysis shows the Cretaceous reservoir units contain competent carbonate cap rocks that arrest possible fracture propagation from injection. Results of reservoir and seal integrity analyses indicate all three potential reservoirs and associated seals are geomechanically stable. The injection pressure of CO2 should stay below the minimum horizontal stress to prevent the occurrence of tensile hydraulic fractures. The three candidate reservoir units are ranked according to reservoir geomechanics for long-term commercial carbon storage. Future work should focus on geomechanical simulation of the reservoir units and additional assessment of leakage risk to further ensure safe carbon storage during and after CO2 injection. Laboratory core tests are recommended to confirm the accuracy of the empirical geomechanical analysis of the candidate reservoir and seal rocks.