Sequence Reservoir Research Articles

Structural assessment and petrophysical evaluation of the pre-Cenomanian Nubian sandstone in the October Oil Field, central Gulf of Suez, Egypt

The low quality of the seismic resolution of the studied Cambrian Pre-Cenomanian formations, which rest directly on the basement in the October Field in the Gulf of Suez, requires study, and the structure pattern controlling these formations is uncertain. The poor quality of the seismic data resolution in the Gulf of Suez is due to the presence of thick sequences of evaporites represented by the South Gharib and Zeit formations. Therefore, the current study used seismic reflection data integrated with well-log data to define the structural-stratigraphic setting of the pre-Cretaceous Nubian reservoir sequence. The study aims at locating and delineating zones having excellent reservoir potential within the Nubian sequence horizons (Nubian Transition, main Nubian, Nubian marker-1, and Nubia marker-2, referred to as NT, MN, M1 and M2, respectively) through the integration of the 3D static modelling and the petrophysical parameters deduced from the well-log data processing. A detailed petrophysical analysis, based on the wireline logs of some wells, was performed to determine the lithological units using two types of cross plots (Neutron-Density and M-N plots), and the different petrophysical parameters that characterize the various Nubian horizons were also computed. 3D modelling was used to visualise the lateral and vertical changes of the reservoir characteristics. The seismic mapping reveals that the Nubian structure is controlled by an NW-SE trending (Clysmic trend) of an NE-plunging asymmetrical anticlinal feature unconformably resting on a basement horst. The main structure is affected by two major normal faults, which trend NW, andis cut by two smaller sub-parallel faults that disturb the core of the structure, which is unaffected by the easterly oriented faults of the Aqaba trend. The petrophysical analyses indicate that the Nubian sandstones have intervals of good reservoir quality, with a total net-pay thickness of about 500 m, net sand ratios (60–90 %), effective porosity (10–25 %), and hydrocarbon saturation (85%), which may encourage further drilling, especially in the southeast portion. The result of this study can be extended to the other Nubia sandstones resting on the basement complex in the Gulf of Suez.

Structural framework of the Caswell Sub-basin, North West Shelf, Australia

The Caswell Sub-basin, situated within the Browse Basin in the North West Shelf constitutes one of Australia’s primary hydrocarbon producing regions, with notable gas-condensate producing fields including Ichthys and Prelude. Jurassic syn-rift sandstones are extensively distributed across the basin and serve as one of the major reservoirs. However, reservoir sequences are typically intensely faulted and exhibit heterogeneity in thickness and lithofacies, with some areas experiencing localised erosion on uplifted fault blocks (e.g. Northern Caswell Sub-basin). Hence, understanding the nature of the 3D fault patterns and their growth history is crucial for evaluating the reservoir characteristics for field development and additional exploration activities. This study, therefore, aims to evaluate the structural framework and the tectonic evolution of the Caswell Sub-basin. Detailed structural interpretation of Paleozoic and younger sequences was conducted using multiple 3D seismic datasets extending over Ichthys, Prelude, Lasseter, and Crown fields. Our study focuses mainly on Mesozoic faulting patterns and kinematics evaluated from interpreted structural maps, thickness changes of each stratigraphic interval and fault throw profiles of major bounding faults. The extensional phase during the Early–Middle Jurassic triggered the development of NE–SW trending faults and the deepening of the Brewster Graben. While, from the Late Jurassic to the Early Cretaceous, the development of E–W trending faults in the north of the Crown and Lasseter fields indicate a shift in the regional stress regime. We highlight the importance of evaluating the structural linkage from basement to cover sequences to achieve a comprehensive understanding of reservoirs and associated petroleum systems.

The Rafael gas-condensate discovery – a potential game-changer in the Canning Basin

The Rafael 1 exploration well discovered an abnormally high-pressured gas-condensate pool in the Kimberley region in late 2021. Data supports a minimum gross gas column of 165 m at the well location trapped within a large faulted four-way closure in a dolomite reservoir sequence with strong similarities and age equivalent to the oil-bearing Ungani Dolomite reservoir in the Ungani Field. A successful production test in March 2022 resulted in sustained natural flows of gas and condensate to surface. The presence of thick sandstones of the Anderson Formation and a complete Laurel section beneath the Meda Unconformity were unexpected based on the pre-drill interpretation. Serendipitously, it provided the perfect geological setting for a significant hydrocarbon accumulation and emphasised the need to consider multiple geological scenarios when evaluating prospects to capture the full range of uncertainties and potential pool sizes. Although the range in size of the contingent resources is wide and requires further drilling for refinement, the Rafael 1 discovery could be one of the most significant onshore gas discoveries since Waitsia 1 and provides impetus and incentive for continued exploration in the basin. Several pathways for commercialisation have been identified linked to the resource size. A comprehensive appraisal program is underway including the recently completed acquisition of a 200 km2 3D seismic survey to optimally locate wells, and plans for drilling to reduce uncertainty and support the first phase of development based on a low case contingent resource that could underpin the energy needs of the Kimberley region.

Seismic Sequence and Source Analysis of Typical Sandstone Reservoirs

Seismic Sequence and Source Analysis of Typical Sandstone Reservoirs

Application of unsupervised learning and deep learning for rock type prediction and petrophysical characterization using multi-scale data

This study integrates well log data, routine core analyses, microcomputed X-ray tomography (μCT) images, and sedimentary petrography to accurately characterize and evaluate the carbonate reservoirs of the Barra Velha formation (Aptian) of the Santos Basin within Brazilian pre-salt region. In these carbonate reservoirs, the porous system is extremely diverse and variable, making it challenging to establish rock typing with comparable petrophysical properties. Based on this integrated study, the reservoir sequences were characterized and a precise definition of four reservoir rock types (RRTs) was performed by integrating the petrophysical values from the plugs and their corresponding well log data of two cored wells using K-means unsupervised classification algorithm. The classification results were combined with various conventional techniques to evaluate the quality and geological characteristics of the studied sequence. This evaluation encompassed different parameters such as flow and storage capacity, reservoir quality index, flow zone indicator, pore spaces interpretation, and average pore and throat radius. The study involved a detailed analysis of thin sections to identify various facies, including shrubstones, reworked, and spherulitestone, and to classify various forms of porosity such as interparticle, intraparticle, intercrystalline, vug, moldic, fracture, and growth framework porosity. Pore Network Modeling from μCT analysis of plugs was used specifically for the characterization of pores and throats of plug samples from each RRT. These datasets were utilized as supporting evidence to offer a more accurate and inclusive knowledge of reservoir quality. The study aimed to develop predictive models by implementing deep learning and machine learning algorithms trained on well log data to estimate plug porosity and rock type. Two deep learning models, ResNet and 1D CNN, were trained and evaluated for plug porosity prediction, with the 1D CNN model showing superior performance. Additionally, the XGBoost algorithm was applied to predict rock type, achieving high accuracy on both the training and validation datasets. The predicted results were compared with actual data to evaluate the effectiveness of the models and were then utilized to estimate plug permeability values. The results demonstrate the potential of deep learning and machine learning approaches in reservoir characterization and management, enabling the evaluation of subsurface reservoir properties even with incomplete datasets, which could lead to an improved understanding of the reservoir properties and better management of the reservoir. This integrated study provides deeper insight into the complex reservoir properties and can help improve decision-making processes and optimize management and production strategies in the challenging pre-salt carbonate reservoirs or similar complex reservoirs.

Geochemical characteristics and genetic types of crude oils from a variety of geological reservoir rocks (Cretaceous–Palaeogene) in the Melut Basin, southern Sudan based on biomarker and carbon isotope composition

This study uses physical and geochemical characteristics of crude oil samples representing the Cretaceous and Palaeogene reservoir sequence of the Melut Basin, southern Sudan to gain information about source rock properties, including organic matter characters, depositional environment and thermal maturity. The overall results show that the Melut Basin's oils have API values between 14.6° and 33.3° and indicate that most of oils are not biodegraded; except one heavy oil sample with low API gravity of 14.6°, which is likely biodegraded. The studied oils were generated from clay‐rich source rocks, containing a blend of organic matter derived primarily from a mixed organic matter of aquatic and terrestrial origin and deposited in a lacustrine setting under suboxic to relatively oxic conditions as demonstrated by their biomarker and carbon isotopic compositions (δ13C). The biomarker maturity indicators show that most of the Melut Basin's oils were generated in the main stage of oil generation, exhibiting a range of peak‐mature to late‐mature. The biomarker environmental indicators reveal that the shale source rocks of the Al‐Gayger and Galhak formations contributed to these oil samples.

Implication of the micro- and lithofacies types on the quality of a gas-bearing deltaic reservoir in the Nile Delta, Egypt

The Messinian Qawasim sequence, as one of the most important reservoirs in the Egyptian Nile Delta, represents a typical gas-bearing deltaic reservoir sequence. It aims at delineating the implication of the litho- and microfacies associations on the reservoir characteristics of the different stages of the fluvial deltas including the prodelta, proximal/distal delta front, and the delta plain depositional sequences. The studied reservoir sequence was divided into two units; upper and lower clastic units. The petrophysical properties of these two units were studied on the borehole scale using the gamma-ray, caliper, sonic, density, neutron, and resistivity logs to estimate the reservoir parameters including the total and effective porosities, water saturation, shale volume, and the net-pay thickness. For more details, they are also examined on the plug-scale using the core dataset including helium porosity, density, permeability, and fluids saturations, where the flow zone indicator, the reservoir potentiality index, the reservoir quality index, and the average reservoir pore radius were then estimated. The entire sequence is divided into five reservoir rock types (RRT1-RRT5) where, the best quality is assigned to the first RRT (the upper reservoir unit), and the lowest quality is assigned to the RRT5 of the lower reservoir unit. Based on core description and the petrographical studies five lithofacies and four microfacies have been identified. The lithofacies are (1) laminated mudstones/siltstones, (2) ripple laminated sandstones, (3) cross-laminated sandstones, (4) cross-bedded sandstones, and (5) pebbly massive sandstones. These lithofacies are primarily composed of four microfacies; sublithic arenites, subarkose arenite, glauconitic quartz wacke, and sandy mudstone/siltstone. Based on this study, the pebbly massive and the cross-bedded sandstones of the upper unit which is composed of the sublithic and subarkose arenites (RRT1-RRT2) have the best reservoir quality. On the other hand, the lowest quality is assigned to the RRT5 (sandy mudstone/siltstone microfacies) which is represented on the macro scale by the laminated mudstones/siltstones lithofacies. The integration between multi-scale datasets (core-well, petrography, well logs, and seismic) gives a precise picture of the deltaic Qawasim reservoir rock units in the Nile Delta. This workflow has never been applied to the deltaic system in the onshore Nile delta and North Africa. Thereby, this study is considered a standard case study for the deltaic sequences and its proposed workflow is applicable to the Nile Delta elsewhere and worldwide for similar reservoir sequences.

The Method for Selecting Analogous Reservoirs Based on SEC

To support remaining economic recoverable reserves and undeveloped reserves compliant with SEC rules, different types of recovery analogous reservoir sequences need to be established. Based on the SEC reserves estimation standards and the actual development characteristics of the oilfield, a classified and optimal evaluation method of analogous reservoirs, which can select a reasonable analogous reservoir fast, has been proposed. This method mainly includes 7 steps to select analogous reservoirs. With practical application in an oilfield, this method has obtained good effects. Selection results can cover all the typical reservoir blocks, and it provides a reliable basis for analogizing the target reservoir in the future. The method herein could provide a new method to select analogous reservoirs based on SEC, and it can be widely used in other oil fields.

Upscaling of geological properties in a world-class carbonate geothermal system in France: From core scale to 3D regional reservoir dimensions

The greater Paris area has some 12 million inhabitants and 48 heating network production units that exploit the heat capacity of a 1.5 km deep aquifer, the Bathonian limestone. This is one of the most productive aquifers in the world for district heating, with an annual output of about 1.7 TWh of energy. The current challenge for Paris is to triple the number of heating networks using geothermal energy so as to reduce dependence on fossil fuels (40% in 2020 in France). As no detailed geothermal reservoir model is available, drilling involves geological risk. A recent well, drilled at Grigny (20 km south of Paris), turned out to be a failure in transmissibility because the bed of permeable limestones it tapped into was very thin (meter-scale). The main aim of this study is to create a digital database and a 3D geological model of this aquifer to minimize geological risks and optimize the location of future geothermal operations around Paris. By compiling data from 168 wells, a high-resolution 3D geological model of 360 km3 size is constructed (about 40 km x 50 km x 0.2 km), made up of 12.2 million cells and displaying sedimentary facies, sequence stratigraphy, porosity (Φ) and permeability (k). About 20% of the oolitic and bioclastic facies are of good reservoir quality (Φ > 13% and k > 350 mD), especially in two targeted, high-quality reservoir sequences. These facies of interest probably correspond to giant dunes and a shoal/barrier prograding from east to west. In these facies, permeable zones are generally 4 m thick and form patches of 1600 m x 1100 m, on average, elongated perpendicular to the depositional slope. 2D and 3D maps of temperature, salinity, porosity, transmissivity, and permeability allow us to understand the areas of interest for geothermal exploration, as demonstrated around Grigny. This model helps us to apprehend better the heterogeneous character of the reservoir for geothermal prospection and to reduce the risk of future doublets during well implantation. Detailed local models may be extracted to anticipate better the implantation of new doublets in areas with already densely spaced existing wells.

A Discussion on the relationship between prominent unconformities on the SCS shelf margins and the end of seafloor spreading in the South China Sea

In an effort to reconcile different data sources (seafloor spreading, seismic and gravity images, well calibrations, outcrop studies) in the South China Sea (SCS), we reviewed the unconformity records, in particular in the context with the shut-off of seafloor spreading in the SCS. With respect to the start of spreading, there is a consensus: ca. 34-41 Ma. Recent data infer an end of spreading, near to the magnetic Anomaly 5 = ca. 15.5 Ma (Langhian age). In Northwest Borneo, it is suggested that this event is coeval with the Deep Regional Unconformity (DRU) in Sabah and Brunei, and the Mid-Miocene Unconformity (MMU) in Sarawak. The MMU is also recognized in offshore Vietnam and Palawan, on the Western and Southeastern margins of the SCS, respectively. The MMU/DRU may constitute the border between active margin and passive margin deposits within the marine SCS sub-basins. The progradation of clastic shelves post-MMU/DRU may have hampered growth of bioherms whilst creating prolific sandstone reservoir sequences offshore Northwest Borneo and Vietnam.

A petroliferous Ediacaran microbial-dominated carbonate reservoir play in the central Sichuan Basin, China: Characteristics and diagenetic evolution

Some of the largest gas accumulations in the central Sichuan Basin, south China are hosted in the Ediacaran microbial-dominated dolomite reservoirs. However, recent exploration of the Secondary Member of the Ediacaran Dengying Formation (Z2dn2) has been hampered by an overall lack of understanding of the microbial-dominated dolomite reservoir and its diagenetic evolution process due to its prolonged burial history and complex diagenetic alternation. On the basis of detailed petrographic and geochemical analysis, we have conducted an in-depth investigation on the characteristics, diagenetic sequence and pore evolution process of the microbial-dominated dolomite reservoirs. The main reservoir comprises thromatolitic dolomite, stromatolitic dolomite and straticulate dolomite. Five generations of cement are identified in the microbial dolomite lithofacies. Multiple dissolution, cementation, differential dolomitization, recrystallization and silicification are recognized. Based on elemental geochemistry, carbon and oxygen isotope characteristics, as well as fluid inclusion homogenization temperatures, cements are attributed to six diagenetic stages. The coupling of high-energy deposition, early supergene karsting and dolomitization processes are found to be essential for developing some world-class favorable high-quality microbial-dominated dolomite reservoirs in Z2dn2 in the central Sichuan Basin.

Lithofacies and reservoirs in sequence stratigraphic framework of Lower Palaeozoic carbonate, offshore Bohai Bay Basin, eastern China

A set of marine carbonates was deposited in the Palaeozoic of the North China Craton, which is the dominant sequence for buried hill hydrocarbon exploration. This study focuses on the lithofacies and reservoirs developed in the sequence. Based on the data of cores, thin sections, drilling, and logging, the characteristics of the sequence stratigraphic framework and its control on lithofacies and reservoirs of the Lower Palaeozoic buried hills in the offshore Bohai Bay Basin are discussed. The results show that there developed 4 second‐order sequences and 21 third‐order sequences in the study area. Due to the deep burial depth, the dolomite is more likely to form high‐quality reservoirs than limestone in the study area, and we define the dolomitic tidal flat‐dominant sequences as ‘favorable reservoir sequences’. There developed unconformity‐related reservoirs and inner reservoirs in the buried hill, and the ‘favourable reservoir sequences’ present obvious control on both reservoirs, showing: (i) ‘favourable reservoir sequences’ and weathering interface control on the scale of the unconformity‐related reservoir jointly, and (ii) the inner reservoirs developed within ‘favourable reservoir sequences’ as well, and the top and bottom of the high‐frequency sequences are the predominant areas for the bedding karst reservoir distribution.

Implementation of lithofacies and microfacies types on reservoir quality and heterogeneity of the Late Cretaceous Upper Bahariya Member in the Shurouk Field, Shoushan Basin, North Western Desert, Egypt

The Late Cretaceous Upper Bahariya Member is one of the most prolific reservoir sequences in the North Western Desert of Egypt. In this paper, we describe core samples of the Upper Bahariya Member, including core photos, conventional core analysis, petrographical description, scanning electron microscope images, and XRD analysis. Samples for this study are from the reservoir sequence in four wells selected from the Shurouk Field in the Shoushan Basin to delineate the impact of the constraint mineral composition on the reservoir quality. The objective of this study is to get an accurate reservoir characterization of this reservoir by applying the rock typing technique to the studied sequence where four Lithofacies Associations (LFA1, LFA2, LFA3, and LFA4) and four corresponding Reservoir Rock Types (RRT1, RRT2, RRT3, and RRT4) were assigned. These are defined as 1) very fine massive sandstone (LFA1, RRT1), 2) laminated, cross-bedded and bioturbated sandstone (LFA2, RRT2), 3) laminated, highly argillaceous and ferruginated sandstone and siltstone (LFA3, RRT3), and 4) laminated and ferruginated siltstone and well cemented bioturbated limestone (LFA4, RRT4). Petrographically, these lithofacies were categorized into five microfacies; 1) glauconitic quartz arenite, 2) subfeldspathic arenite, 3) glauconitic sublithic arenite, 4) ferruginated subfeldspathic wackes, and 5) sandy fossiliferous packstone microfacies. Conventional core samples include bulk and grain densities (ρb and ρg, respectively), helium porosity (∅He), and horizontal and vertical permeabilities (kH and kV, respectively). The application of the Dykstra-Parsons technique to the available permeability data indicates that the studied sequence is extremely heterogeneous (heterogeneity factor (V) = 0.90). Based on the available samples, the normalized porosity index (∅z), reservoir quality index (RQI), flow zone indicator (FZI), and the discrete rock type values (DRT) were estimated to determine the reservoir quality. The RRT1 samples are characterized by the best reservoir properties (av. ∅He = 14.7%, av. kH 42.0 = md, av. RQI = 0.47 µm, av. FZI = 2.87 µm, and av. DRT = 13), whereas the lowest reservoir quality is assigned to the RRT4 samples (av. ∅He = 18.8%, av. kH 0.30 = md, av. FZI = 0.15 µm, av. RQI = 0.04 µm, and av. DRT = 7). The low reservoir quality of the RRT4 is primarily attributed to the predominance of lower quality features (compaction effect, cementation, and presence of glauconite and authigenic minerals). Following the Improved Stratigraphic Modified Lorenz (ISML plot), the Upper Bahariya reservoir is subdivided into five Hydraulic Flow Units (HFUs) such as the HFU-2, and the HFU-4 that are considered superconductive flow units that alternate with three poorly hydraulic conductive HFUs (HFU-1, HFU-3, and HFU-5). The present integrated sedimentological and petrophysical workflow is considered a significant study of the Shoushan basin which can improve exploration activities as well as production optimization. In addition, dividing the studied clastic sequence into five microfacies association and four reservoir rock types can be extended to other equivalent subsurface Late Cretaceous clastic sedimentary rocks in the vicinity and other basins.

Geochemical characteristics of diagenetic fluid and densification model of tight gas sandstone reservoirs in Linxing area, eastern margin of Ordos Basin, China

Quasi-continuous tight gas sandstone reservoirs have been discovered widely in the eastern margin of Ordos Basin (Linxing area) within the marine-continent transitional strata in the upper Paleozoic. Differences in formation water chemical properties, water-rock reactions, and diagenetic evolutions between the Taiyuan Formation and the Lower and Upper Shihezi Formations are attributed to various degrees of densification of sandstones, which significantly restrain the exploration and development of tight gas reservoirs. This study utilizes the petrographic features, electron probe, X-ray diffraction, and chemical properties of formation water to establish the diagenetic sequence of tight sandstone reservoirs and finds that the diagenetic systems of the Taiyuan Fm. were more closed than those of the Shihezi Fms., with enrichments in Ca2+and depletions in Mg2+ and Fe2+. Here, we suggest that the dissolution of feldspars and rock fragments, the siliceous cementation, and the transformation of clay minerals are controlled by the K+/H+ ratios of the formation water. In the Taiyuan Fm., the low K+/H+ ratios resulted in a complete illitization reaction in the closed CaCl2 type formation water, and the migration rate of K+ controlled the proportion of the illite contents in the open NaHCO3 type formation water. In the Lower Shihezi Fm., the rapid consumption of H+ caused the elevation of the K+/H+ ratios, leading to the cease of illitization reaction and preservation of kaolinites and K-feldspars. In the Upper Shihezi Fm., the illitization reaction was inefficient, and smectites were transformed to chlorites. Hence, differentiated sandstone densification models are established to characterize different water-rock reaction systems. Typically, clay minerals and ferrous carbonate cements could form seepage barriers around the thick sandstone layers and promote the formation of independent closed high-pressure micro-diagenetic systems. Consequently, the overpressured reservoirs that underwent relatively weak compaction, dissolution, and cementation (Type Ⅰ) and the chlorite-enriched overpressured reservoirs (Type Ⅱ) tend to preserve partially primary pores and form secondary pores, which should be treated as the “sweet spot” target area for the further exploration of tight gas.

Integrated petrophysical and microfacies analyses for a reservoir quality assessment of the Asmari Dolostone sequence in the Khesht Field, SW Iran

The Asmari Formation is one of the most important prolific reservoirs along both sides of the Persian Gulf. The present study aims to characterize the fractured dolomite of the Asmari reservoir sequence in SW Iran. Such characterization can be achieved through a petrophysical reservoir characterization using core data integrated with a detailed microfacies analysis and a detailed study on the dominant diagenetic features. The detailed microfacies analysis indicates that the Asmari reservoir can be discriminated into seven non-clastic microfacies (laminated to massive anhydrite, sandy dolomudstone, peloidal bioclastic dolowackestone, peloidal foraminiferal dolowackestone/dolopackstone, peloidal bioclastic dolopackstone/dolograinstone, framestone, and dolograinstone microfacies). These microfacies have been primarily deposited in tidal flat, lagoonal, and carbonate shoal depositional environments. Petrophysically, some X-Y plots were established to present the available petrophysical core data (porosity ∅He, horizontal and vertical permeabilities, kH and kV, respectively) to enable a mathematical reservoir modeling. Besides, the reservoir quality has been defined using the flow zone indicator (FZI), reservoir quality index (RQI), and the effective pore radius (R35). Based on these petrophysical core data and quality parameters, the studied samples can be subdivided into five reservoir rock types (RRTs). Also, reservoir zonation on the borehole scale using the improved stratigraphic modified Lorenz technique (ISML) indicated that the characterized reservoir can be subdivided into four hydraulic flow units (HFU-1, HFU-2, HFU-3, and HFU-4). The HFU-2 (dolograinstone, dolopackstone, and framestone samples) is characterized by the best reservoir quality (average ∅He = 7.8%, kH = 95.2 md, RQI = 0.84 µm, FZI = 15.9 µm, and R35 = 10.5 µm); it is composed of RRT1 and RRT2 samples. On the other side, the lowest reservoir quality is assigned to the HFU-3 which is composed of the RRT5 (dolomudstone and evaporates, average ∅He = 11.5%, kH = 0.24 md, RQI = 0.04 µm, FZI = 0.22 µm, and average R35 = 0.21 µm). The prevailed reservoir characteristics of the Asmari dolostone sequence in SW Iran are mostly controlled by replacive and pervasive dolomitization, fracturing, and cementation by anhydrite.

Primary deposition and early diagenetic effects on the high saturation accumulation of gas hydrate in a silt dominated reservoir in the Gulf of Mexico

On continental margins, high saturation gas hydrate systems (>60% pore volume) are common in canyon and channel environments within the gas hydrate stability zone, where reservoirs are dominated by coarse-grained, high porosity sand deposits. Recent studies, including the results presented here, suggest that rapidly deposited, silt-dominated channel-levee environments can also host high saturation gas hydrate accumulations. Here we present several sedimentological data sets, including sediment composition, biostratigraphic age from calcareous nannofossils, grain size, total organic carbon (TOC), C/N elemental ratio, δ13C-TOC, CaCO3, total sulfur (TS), and δ34S-TS from sediments collected with pressure cores from a gas hydrate rich, turbidite channel-levee system in the Gulf of Mexico during the 2017 UT-GOM2-1 Hydrate Pressure Coring Expedition. Our results indicate the reservoir is composed of three main lithofacies, which have distinct sediment grain size distributions (type A-silty clay to clayey silt, type B-clayey silt, and type C-sandy silt to silty sand) that are characteristic of variable turbidity current energy regimes within a Pleistocene (< 0.91 Ma) channel-levee environment. We document that the TOC in the sediments of the reservoir is terrestrial in origin and contained within the fine fraction of each lithofacies, while the CaCO3 fraction is composed of primarily reworked grains, including Cretaceous calcareous nannofossils, and part of the detrital load. The lack of biogenic grains within the finest grained sediment intervals throughout the reservoir suggests interevent hemipelagic sediments are not preserved, resulting in a reservoir sequence of silt dominated, stacked turbidites. We observe two zones of enhanced TS at the top and bottom of the reservoir that correspond with enriched bulk sediment δ34S, indicating stalled or slowly advancing paleo-sulfate-methane transition zone (SMTZ) positions likely driven by relative decreases in sedimentation rate. Despite these two diagenetic zones, the low abundance of diagenetic precipitates throughout the reservoir allowed the primary porosity to remain largely intact, thus better preserving primary porosity for subsequent pore-filling gas hydrate. In canyon, channel, and levee environments, early diagenesis may be regulated via sedimentation rates, where high rates result in rapid progression through the SMTZ and minimal diagenetic mineralization and low rates result in the stalling of the SMTZ, enhancing diagenetic mineralization. Here, we observed some enhanced pyritization to implicate potential sedimentation rate changes, but not enough to consume primary porosity, resulting in a high saturation gas hydrate reservoir. These results emphasize the important implications of sedimentary processes, sedimentation rates, and early diagenesis on the distribution of gas hydrate in marine sediments along continental margins.

Reservoir quality discrimination of the Albian-Cenomanian reservoir sequences in the Ivorian basin: a lithological and petrophysical study

Reservoir quality discrimination of the Albian-Cenomanian reservoir sequences in the Ivorian basin: a lithological and petrophysical study

Implementation of a Petrographical and Petrophysical Workflow Protocol for Studying the Impact of Heterogeneity on the Rock Typing and Reservoir Quality of Reefal Limestone: A Case Study on the Nullipore Carbonates in the Gulf of Suez

AbstractThis study focuses on the heterogeneity of the middle Miocene syn‐rift Belayim nullipore (reefal) marine sequences in the Gulf of Suez and its impacts on reservoir quality. The sequences consist of coralline algal reef limestones with a highly complex dual‐porosity system of primary and secondary porosities of widely varying percentages. To achieve a precise mathematical modeling of these reservoir sequences, a workflow protocol was applied to separate these sequences into a number of hydraulic flow units (HFUs) and reservoir rock types (RRTs). This has been achieved by conducting a conventional core analysis on the nullipore marine sequence. To illustrate the heterogeneity of the nullipore reservoir, the Dykstra‐Parsons coefficient (V) has been estimated (V = 0.91), indicating an extremely heterogeneous reservoir. A slight to high anisotropy (λk) has been assigned for the studied nullipore sequences. A stratigraphic modified Lorenz plot (SMLP) was applied to define the optimum number of HFUs and barriers/baffles in each of the studied wells. Integrating the permeability‐porosity, reservoir quality index‐normalized porosity index (RQI‐NPI) and the RQI‐flow zone indicator (RQI‐FZI) plots, the discrete rock types (DRT) and the R35 techniques enable the discrimination of the reservoir sequences into 4 RRTs/HFUs. The RRT4 packstone samples are characterized by the best reservoir properties (moderate permeability anisotropy, with a good‐to‐fair reservoir quality index), whereas the RRT1 mudstone samples have the lowest flow and storage capacities, as well as the tightest reservoir quality.

Tightness Mechanism and Quantitative Analysis of the Pore Evolution Process of Triassic Ch-6 Tight Reservoir, Western Jiyuan Area, Ordos Basin, China.

Exploring the tightness mechanism through a quantitative analysis of the pore evolution process is the research hotspot of tight oil reservoirs. The physical characteristics of Chang 6 (Ch-6) sandstones in the western Jiyuan area have the typical features of a tight oil reservoir. Based on the reservoir physical property, lithological characteristics, diagenetic types and sequence, and burial and thermal evolution history, this study analyzes the factors leading to reservoir tightness and establishes the model of the pore evolution process. The results show that the sedimentary microfacies type controls the reservoir detrital material and further affects its physical properties. The high content of feldspar and rock fragments and the fine grain size are the material cause for the reservoir tightness. The sandstones of the main underwater distributary channel are the dominant sedimentary bodies for the development of a high-quality reservoir. In terms of diagenesis, compaction is the primary cause for reservoir tightness, and the porosity reduction by cementation is weaker than that by compaction. Meanwhile, the quantitative calculation results indicate that the porosity losses by compaction, carbonate cementation, kaolinite cementation, chlorite coatings, and siliceous cementation are 23.5, 3.1, 3.8, 3.0, and 0.8%, respectively. In addition, dissolution is significant to improve the reservoir physical property, and the increase of dissolved porosity is around 3.2%. More significantly, this study uses a detailed and systematic method for analyzing the tightness mechanism and the pore evolution process of the Ch-6 sandstones in the western Jiyuan area, Ordos Basin, China.

EOCENE VOLCANICLASTICS IN THE KARTLI BASIN, GEORGIA: A FRACTURED RESERVOIR SEQUENCE

In the broader Caucasus region, multiple extrusive volcanic units are present within the Jurassic, Cretaceous, Eocene and Miocene sedimentary successions. Partial reworking of volcanic material from various provenance areas into Eocene, Oligocene and Miocene reservoir units is commonly observed in the Eastern Black Sea and in the Rioni, Kartli and Kura Basins of onshore Georgia. Reservoir quality has in general been negatively affected by volcanic rock fragments which may have undergone complex diagenetic alteration. However, despite concerns regarding reservoir quality, oil at the Samgori field, the largest field in Georgia (∼200 MM brl recovered), is hosted in altered Middle Eocene volcaniclastic sandstones interbedded with deep‐water turbidites. Previous studies of core material from numerous wells in this field showed that most of the oil is contained in altered, microfractured, laumontite‐rich tuffs which have fracture and cavernous net porosities averaging 12% and average permeability of 15 mD. The laumontite tuffs comprise only up to 20% of a tuffaceous sandstone section and occur as isolated lenses or pods on a sub‐seismic scale (i.e. 5‐10 m thick), causing highly variable oil productivity from one well to another.The petrographic analysis of samples of Middle Eocene volcaniclastic sandstones from outcrops in the central part of the Kartli Basin around Tbilisi broadly confirms the main conclusions of studies completed some 30 years ago which were based on the analysis of subsurface samples. However, the surface samples analysed show that zeolitization events typically did not improve, but actually reduced, reservoir quality due to extensive zeolite cementation. The poor reservoir properties of the plug samples, which are age‐equivalent to the proven subsurface Middle Eocene reservoir interval, highlight fracturing as a key factor controlling the presence of exceptional producers (up to 9000 b/d) in the Samgori field complex. The study therefore underlines the critical role of fracturing of the Middle Eocene volcaniclastic reservoir sequence in the Kartli Basin.