Shale Volume Research Articles

Enhancing Characterization of Reservoirs Within the Niger Delta Basin Using Integration of Seismic and Well Logs

This research utilized well logs and seismic to unravel the reservoir architecture of a field within the offshore depolbelt of Niger Delta. Gamma ray and resistivity log responses were used for lithology and hydrocarbon reservoirs identifications. The principle of similarity in log signatures was used for correlation across the three studied wells. Pertinent reservoir parameters such as shale volume, effective porosity, permeability, hydrocarbon saturation and water saturation were calculated using well-established equations consistent with the geology. Seismic structural interpretation that will give insight to deformation of the field involves the identification and mapping of faults and horizons from seismic sections. By integrating information from seismic and wells, 3D geological modelling was done using geostatistical methods of Sequential Gaussian Simulation and Indicator. The general stratigraphy of the studied field comprises of intercalation of sands and shales which is typical of Agbada formation. Three reservoirs designated as AA, BB and CC were identified and mapped. Only reservoir CC was laterally continuous across the three wells. Reservoir AA has average shale volume of 13%, effective porosity 26%, hydrocarbon saturation 46% and permeability 1328 mD. Reservoir BB has shale volume of 10%, effective porosity 28%, hydrocarbon saturation 43% and permeability 1616 mD. Reservoir CC has shale volume of 21%, effective porosity 20%, hydrocarbon saturation 89% and permeability 580 mD. Twenty faults comprising of both major and minor faults were mapped. The faults mapped were majorly normal faults. The result of the seismic structural interpretation shows that the probable structures harboring oil and gas are a combination of four-way closure and fault assisted anticlinal structures. The modelling of facies and petrophysical parameters into maps aided the understanding of parameter’s influence on oil and gas production. Reservoir CC has oil and gas in commercial quantities with 2520 MMcf and 622Mbbls respectively. The result shows the reservoir has high performance system and is therefore recommended for development and production. The resulting models will aid placement of production wells and monitoring of future performance of the reservoirs.

Seismic interpretation and hydrocarbon assessment of the post-rift Cenomanian Bahariya reservoir, Beni Suef Basin, Egypt

The geophysical interpretations for a collection of high-quality 2D seismic data plus well logging data for six drilled wells exposed the structural controls and the hydrocarbon potentiality of the Beni Suef Basin, north Western Desert, Egypt. The created structural map on the top of the Early Cenomanian Bahariya Formation (the significant oil reserve in north Western Desert), exhibits a series of NW–SE normal faults as well as a master ENE strike-slip major fault. The extensional faults formed horst structures while the strike-slip fault created a negative flower structure in the central part of the study area. These structural features represent the main petroleum traps within Beni Suef Basin. The reservoir quality was assessed through the petrophysical analysis of the Bahariya Formation in wells; Azhar A2, Azhar E-2X, Azhar E3, Yusif-4X, Fayoum-2X and Beni Suef W-1X. This analysis proved that the Lower Bahariya unit has better reservoir quality than the Upper Bahariya reservoir, with shale volume less than 10%; effective porosity between 10 and 20%, water saturation between 25 and 75% and total pay thickness between 11 and 88 ft. The obtained results encourage drilling more exploratory wells in Beni Suef Basin to enhance the productivity from the sandstones of the Lower Bahariya reservoir.

The Effect of Tectonic Stress and Thermal Evolution on Shale Pores of Devonian and Carboniferous Shales in Southern China

Many sets of Paleozoic marine organic-rich shale strata are developed in southern China. However, the exploration and development degree of these strata are different. Cambrian shale and Ordovician-Silurian shale are two horizons with high degree of exploration, while Devonian shale and Carboniferous shale exploration is deficient. Based on XRD, FE-SEM, and gas adsorption experiment, pore development characteristics and controlling factors of Devonian and Carboniferous shale are investigated. There are mainly four lithofacies in Devonian and Carboniferous shale: mixed shale (M), carbonate/siliceous mixed shale (M-1), argillaceous/siliceous mixed shale (M-2), and argillaceous-rich siliceous shale (S-3). Reservoir characteristics of both two sets of shale strata are quite different. The averages of porosity, pore volume, and specific surface area of Devonian shale are 3.81 % , 9.7 × 10 − 3 cm3/g and 11.8 m2/g, while those of Carboniferous shale are 3.57%, 17.3 × 10 − 3 cm3/g and 19.8 m2/g. Thermal evolution (Ro) and tectonic preservation conditions are the main factors affecting the pore development. Carboniferous shale ( Ro ≈ 2 % ) is in the stage of producing a large number of organic pores. Devonian shale ( Ro ≈ 3.5 % ) is having difficulty preserving organic pores due to high thermal evolution. Meanwhile, Devonian shale (well GTD1) is strongly affected by tectonic movement; tectonic fractures and calcite veins are developed. Carboniferous shale (well GRY1) is in relatively stable area; tectonic fractures are not developed. Under the influence of compaction, the pore volume and specific surface area of Carboniferous shale are 78.3% and 67.8% higher than those of Devonian shale, respectively. This research can provide reference for clarifying shale pore development and evolution mechanism and similar shale gas exploration both in study area and around the world.

Petrophysical characterizations and shale distribution analysis of Kissenda reservoir sands, Gabon

A gas field in western Gabon is penetrated by an exploration site N field with a major fault dividing the well locations. The upthrown block and the downthrown block have different characterization based on the history of Gabon Basin located in Equatorial West Africa, as part of the salt basin complex. In addition to major fault separating the blocks, four wells are selected in this study to identify each block. Petrophysical properties was undertaken by using wireline logs to generate each well composite. These properties include shale volume, total porosities, water saturation and permeability. The presence of shale in sandstone reservoir can affect the producibility rate of the reservoir. Shale volume and density porosity are cross-plotted using the Thomas-Stieber method to determine the shale distribution of both blocks, including the distribution types of laminar shale, dispersed shale and structural shale. Based on this method, the upthrown block has relatively small grain diameters with mostly laminar-dispersed shale distributions, while in downthrown block the grain diameters are four times larger with more dynamic shale distributions.

Petrophysical evaluation for development of a marginal oil field in the onshore Niger Delta, Nigeria

Petrophysical evaluation was conducted on an onshore marginal field in Niger Delta with the aim of evaluating the rock and fluid properties to boost hydrocarbon production in the field. Five well logs suite from five wells and core log data for two wells were utilized for this study. Petrophysical properties evaluated included; porosity, net to gross, formation factor, irreducible water saturation, permeability, water saturation, hydrocarbon saturation and pay thickness. The well logs suite contained the following logs: Gamma ray log for lithology identification; Resistivity log for fluid type discrimination and determination of water saturation; Density log for porosity determination; and Neutron log in combination with density log for hydrocarbon types. A total of seven reservoir sands (, Sand A, B, C, D, E, F and G) were identified and correlated across all five wells on the basis of gamma ray and resistivity log motifs. The reservoir gross thicknesses ranged from 62.55 to 228.50 ft, shale volume from 7.0 to 24.60%, net to gross from 0.76 to 0.93%, effective porosity from 20.78 to 26.22%, water saturation from 35.80 to 62.30% and permeability ranged from 545.94 to 2821.97 mD. This shows that the reservoirs are of good quality for hydrocarbon productionacross the field.

Integrating rock physics and sequence stratigraphy for characterization of deep-offshore turbidite sand system

Definition and understanding deep water depositional environment is essential, especially in exploration and development phase. This study is aimed at improving characterization and environment of deposition assessment of deepwater turbidite sands systems as a way of evaluating reservoir geometry and quality in “NOJA” field, deep-offshore Niger Delta. The data used for the analysis comprise 3D full angle stack seismic, biofacies and logs from five wells. Seismic sequence analysis using reflection termination patterns were used for the mapping of depositional sequences. The sequences have internal reflection geometries ranging from parallel, subparallel and chaotic. Seismic structural maps gave insight into rock deformation and hydrocarbon potential of the field. The probable structure responsible for the trapping of oil and gas was a faulted anticlinal structure. Amplitude maps of the two stratigraphic surfaces gave insight into sand and shale distributions and possible environment of sediment deposition. Rock physics concepts were utilised to evaluate reservoir continuity, diagenetic and environment of deposition effects influencing reservoir properties. Two reservoirs (R1 and R2) of interest occurred at a depth interval of 2398–2461 m. Reservoir (R1) has average volume of shale of 22%, effective porosity 20%, hydrocarbon saturation 53%, and permeability 556 mD. Reservoir (R2) has average volume of shale of 10%, effective porosity 26%, hydrocarbon saturation 79%, and permeability 1044 mD. Environment of sediment deposition of the reservoirs was weakly confined with distributary channel complexes. Reservoir (R1) had low degree of connectivity (loosely amalgamated turbidite sand system) and reservoir (R2) possessed high degree of connectivity (highly amalgamated turbidite sand system). Rock physics templates of constant, contact and friable showed that the reservoir sands were poorly cemented to unconsolidated. These models indicated that the reservoir sands were both influenced by depositional and depth related diagenetic effects.

Estimation of reservoir properties based on core plugs, lithofacies, and well logs for Nahr Umr Formation in Noor oilfield, southern Iraq

The Nahr Umr Formation, one of the most important Cretaceous formations and one of the main generating reservoirs in southern Iraq and neighboring regions, was chosen to study and estimate its petrophysical properties using core plugs, lithofacies, and well logs from five wells in the Noor oilfield. Reservoir properties and facies analyses are used to divide the Nahr Umr formation into two-member (limestone in the upper part and main sandstone in the lower). Limestone members are characterized by low reservoir properties related to low effective porosity and permeability while the main sandstone member is considered as a reservoir. Four lithofacies were recognized in the main sandstone member of the Nahr Umr Formation according to petrographic observation with gamma-ray. They are well-sorted quartz arenite sandstone, poorly sorted Quartz arenite sandstone, Sandy shale, and Shale Lithofacies.
 Calculation of the various reservoir properties (shale volume, effective porosity, permeability, and water saturation) using the (Interactive Petrophysics v3.5) program and linking them with the lithofacies by computer processed interpretation (CPI) of available of the available wells. Divided the sandstone member into three units are A, B, and C. Each unit consists of many reservoir sandstone subunits separated by shale and streaks of limestone. Average reservoir properties of units A and B are good to very good related to high porosity, permeability, and economy hydrocarbon saturation (low water saturation). While these properties are decreased in unit C. The Sandston member of borehole No-5 was the best reservoir characterization, especially in the thickness of the reservoir units and the low shale content.

Geophysical Well Log Appraisal of Okpella Field within Offshore Niger Delta Basin of Nigeria

The Production data of Okpella Field, located within the Offshore Niger Delta Basin, Nigeria, revealed that the Okpella Field attained peak annual hydrocarbon production of 430175 MBO (Million Barrel of Oil) in 2008, and the production has presently dropped to 7839 MBO per annum. Therefore, an appraisal study was conducted to identify opportunities for reversing the low production. The sought opportunities were bypassed reservoirs with pay zones. This study uses geophysical Well log data, Biostratigraphic data, and Production data to appraise Okpella Field. The hydrocarbon production data were analyzed for the produced reservoirs to establish the positive effects of the Bypassed hydrocarbon reservoirs zone within Okpella Field Offshore Niger Delta Basin. Before this study, the operating company had previously identified six reservoirs. They were named major reservoirs Sand A to F, of which major reservoirs B, C, and E are gas-bearing, major reservoir D bears gas and oil, and major reservoir F bears condensates. Three additional reservoirs with pay zones were identified within this study, and they were named Bypassed A to C. Bypassed A is gas bearing, Bypassed B is oil and gas and Bypassed C is oil-bearing. The petrophysical analysis of the wells within Okpella Field determined the various reservoir properties such as the gross thickness, net thickness, net to gross ratio, the volume of shale, porosity, and hydrocarbon saturation of the major reservoir and bypassed reservoir zones. Some of the reservoirs are amalgamated upward coarsening sand bodies of distal fan lobes within the Low-stand systems tract. Others are leveed channel proximal. The Biostratigraphy data were integrated with the stacking pattern of the Gamma-ray log motif, revealing the sequence boundaries and inferring the possible depositional environment. The reservoirs within the Okpella Field were deposited within the Low-Stand System Tract (LST), reflecting a high energy environment, possibly the shoreface depositional environment.

Predicting Shale Volume from Seismic Traces Using Modified Random Vector Functional Link Based on Transient Search Optimization Model: A Case Study from Netherlands North Sea

Predicting Shale Volume from Seismic Traces Using Modified Random Vector Functional Link Based on Transient Search Optimization Model: A Case Study from Netherlands North Sea

Applications of well logging techniques to evaluate the groundwater aquifers in the area between southwest Bani Sweif and west Asyoute governorate, upper Egypt.

The relevance of detecting aquifer characterization and aquifer potential has risen with the application of well logging techniques as the demand for water has increased. Apart from pumping data, 16 geophysical well logs (resistivity, gamma ray, self-potential, and nuclear logs) are utilized to achieve the main goal of estimating petrophysical parameters (porosity (∅), effective porosity (∅𝑒𝑓𝑓), hydraulic conductivity (k), permeability (K) and shale volume (𝑉𝑠ℎ)) of the Apollonia (Eocene fractured limestone aquifer), Upper and Lower Bahariya (Nubian sandstone aquifer) formations. The findings show that the Eocene fractured limestone aquifer has a carbonate in soft chalk with high K and ∅ as well as high k of 4974.39 mD at well ST-188 (a highly productive aquifer), whereas the Lower Bahariya formation is mostly fine to medium-grained sandstone and clay, suggesting that it formed in shallow marine environments with low K. On the other hand, Upper Bahariya was noted that having poor sand succession. As results shown, K of the most examined wells ranges from 2609.69 to 1486.812 mD at ST-258 and ST-38 wells respectively. The study appears that 𝑉𝑠ℎ, along with ∅ and K features, is regarded as an important attribute in aquifer evaluation where, estimated 𝑉𝑠ℎ over the studied area is ranges between 5.96% and 31.7% at ST-48 and WBS1 wells respectively. Overall, this study provides an important insight into the importance of evaluating groundwater aquifers over time to help in making decisions to save and protect groundwater aquifers in the future.

Petrophysical evaluation of Kati Formation at Seri Iskandar area, Perak, Malaysia

Non-linear relationships for shale volume estimation are designed for a specific area or formation age and most of the time they are optimistic in calculating low shale volume. This study evaluates some petrophysical properties of Late Paleozoic Kati Formation in Seri Iskandar area based on well logs and core plug samples from well CTW-01 drilled within University Teknologi PETRONAS campus. Shale volume is calculated using gamma ray log and calibrated with that obtained by sedimentation method in the lab. Porosity is determined from sonic log and calibrated with that measured in lab using Helium Porosimeter on core plugs. The shale volume equation derived from the lab analysis and well log data is Vsh = 1.0157 (IGR) - 0.0158 and achieved a correlation coefficient, R2, greater than 0.99. Shale volumes estimated from GR log using this model are in good agreement with laboratory measurements. Since the porosity is ranging between 0.5% and 2%, the reservoir rocks of the study interval are classified as tight sandstones.

Quantitative Gas‐in‐place Comparison of Original and Bitumen‐free Lacustrine Shale

AbstractResidual bitumen in organic‐rich shale of oil windows exists widely, and its effect on the gas storage capacity of shale could be two‐fold. Bitumen could occupy and block the nanopores of shale, thereby reducing the gas storage capacity. On the other hand, gas could be dissolved in bitumen in shale gas reservoirs, leading to enhanced gas storage capacity. To quantify the effect of bitumen on the gas‐in‐place (GIP) estimation of lacustrine organic‐rich shale, the micropore characteristics and methane sorption capacity of original and bitumen‐free shale from the Triassic Yangchang Formation of the Ordos Basin, combined with the methane dissolution capacity for the isolated bitumen, were analyzed and compared. GIP for the original and bitumen‐free shale in the depth range of 500–2500 m was evaluated. The results show that micropores in the shale samples were mainly related to organic matter. Clay mineral‐hosted pores contributed slightly to microporosity. Bitumen significantly reduced the micropore surface area and volume of the original shale, with average percentages of 28.09% and 51.26%, respectively. The methane sorption capacity decreased after bitumen removal. When normalized to the original shale mass, the sum of the methane sorption capacity for bitumen‐free shale and the methane dissolution capacity for isolated bitumen was similar to the methane sorption capacity of the original shale, indicating that the lack of methane absorbed on bitumen is the main reason for the decrease in methane sorption capacity after bitumen removal. The contribution of absorbed methane on bitumen to sorbed methane in shale could be higher than 36.23%. Dual effects of bitumen on shale GIP were observed. A high content of bitumen (1.12%) increased the GIP of the shale samples, with an average percentage of 23.5% in the depth range of 500–2500 m, while a low content of bitumen (0.06%) decreased the GIP, with an average percentage of 13.6%.

Identification of low-resistivity-low-contrast pay zones in the feature space with a multi-layer perceptron based on conventional well log data

In the early exploration of many oilfields, low-resistivity-low-contrast (LRLC) pay zones are easily overlooked due to the resistivity similarity to the water zones. Existing identification methods are model-driven and cannot yield satisfactory results when the causes of LRLC pay zones are complicated. In this study, after analyzing a large number of core samples, main causes of LRLC pay zones in the study area are discerned, which include complex distribution of formation water salinity, high irreducible water saturation due to micropores, and high shale volume. Moreover, different oil testing layers may have different causes of LRLC pay zones. As a result, in addition to the well log data of oil testing layers, well log data of adjacent shale layers are also added to the original dataset as reference data. The density-based spatial clustering algorithm with noise (DBSCAN) is used to cluster the original dataset into 49 clusters. A new dataset is ultimately projected into a feature space with 49 dimensions. The new dataset and oil testing results are respectively treated as input and output to train the multi-layer perceptron (MLP). A total of 3192 samples are used for stratified 8-fold cross-validation, and the accuracy of the MLP is found to be 85.53%.

Evaluation of Lithological Influence on Seismic Wave Velocity in Part of Niger Delta, Nigeria

This study is aimed at evaluating the influence of lithology on seismic wave velocity in part of Niger Delta. A suite of geophysical well log comprising of gamma ray, sonic and density logs in Log Ascii Standard (LAS) format from two exploratory wells (OKO 5 and OKO 7) within the study area was used for this study. Gamma ray log was used to identity and delineate the lithology into shale and sand units, seismic wave velocity was categorized into compressional wave velocity Vp and shear wave velocity Vs. The former was computed from interval transit time while the later from compressional wave velocity. The results of this study show that seismic wave velocity is very much affected by difference in the lithology of formation. Compressional wave velocity (Vp) is higher than shear wave velocity (Vs) in shale and sand lithologies in the two wells. The values of the compressional wave velocity, shear wave velocity, percentage volume of shale and percentage volume of sand ranges from 3485 to 6620m/s, 2159 to 3932m/s, 2682 to 5323m/s, 1736 to 3161m/s, 11 to 60%, 13 to 59%, 40 to 89% and 29 to 87% for the two wells respectively. The knowledge of this study can be applied in civil engineering and engineering geophysics activities like foundation for high rise buildings, dams, bridges and road construction.

Reservoir Properties of the Upper Sand Member of the Zubair Formation in North Rumaila Oil Field

The Zubair Formation is main prolific reservoirs in the Rumaila oilfield in southern Iraq. The petrophysical assessment of the Zubair Formation was carried out using a suite of open-hole logs from eight wells along with the Rumaila North oil fields, in Basra. Based on THE neutron, density and Gamma Ray logs, the Upper Sand Member of the Zubair Formation is divided into the alternate units of the sand and shale and defining their boundaries. Based on the obtained results, the Upper Sand Member was divided into three main pay units: AB, DJ, and LN, separated by two insulating shale units designated C and K. The unit DJ was subdivided into four secondary reservoir units: D, F, G, H, and the LN unit, which is split into L, M, and N. High porosity, high oil saturation and a high net-to-gross ratio were found in the petrophysical investigation. The porosity types are good (from 15 to 20%), very good (20-25%) and excellent (more than 25%) except wells R-559 and R-256, which has medium permeability, all the wells have good to excellent permeability. The net pay for the reservoir unit thickness ranges from 5 to 59m in all wells, resulting in significant hydrocarbon productivity due to strong hydrocarbon saturation, good effective porosity, and low shale volume.

Evaluation of oil reservoir of Hartha Formation in Y and J field, North Iraq

Afield development plan (FDP) of the Y and J oil fields for cretaceous reservoir (Harth Formation) evaluation and the production of hydrocarbons in the near future in two Y and J oil fields.
 Open hole logs namely (Gamma ray, Resistivity, Sonic, Caliper and Density) logs were used to determine petrophysical parameters. The parameters determined are; volume of shale, porosity, water saturation, irreducible water saturation and bulk volume of water. The thickness of the reservoir varies between (40 and 120) m. Determining the porosity depending on the porosity of the log (16-28)% and core Average porosity (18-37)% values vary between; generally decreasing with depth. Average porosity 33.3%.test is flow crude oil 1000 bll /d.in J field basically water saturation calculation5-16%. And oil saturation (90-80) % and the oil were carried out at a rate of 1000 barrels / day in the complete test of well Y. The amount of the original oil storage OOIP (1039 * 10^6) standard cubic meters.
 This study provides an insight into reservoir quality prediction in the study area and other carbonate reservoirs undergone different the development of Hartha reservoir in south Mosul north Iraq as a new reservoirs in the study as Tertiary reservoir producing as old degassing stations enabling facilities from the 1950s are being" surface facility", This study's aimed at making available petrophysical data the computer processed interpretation(CPI) for Hartha reservoir.

Integrated organic geochemical/petrographic and well logging analyses to evaluate the hydrocarbon source rock potential of the Middle Jurassic upper Khatatba Formation in Matruh Basin, northwestern Egypt

The present national and international pursuit of converting Egypt into a regional hub of natural gas in the East Mediterranean region resulted in conducting extensive exploration activities in several areas of northern Egypt. Therefore, organic petrographic, geochemical, and geophysical analyses were carried out on the upper Khatatba Formation from the OBA 2-2A well in the Matruh Basin.Restoration of the original sedimentological and geochemical characteristics of the upper Khatatba Formation suggest deposition of this formation in deltaic settings. Few shale and partly calcareous shale units of the Upper Safa and the uppermost Zahra members accumulated in TST in prodelta settings under dysoxic-anoxic conditions. These shale units had an original gas/oil-prone organic facies BC. Other shales and partly calcareous shales of the Upper Safa and Zahra members accumulated in HST in deltafront settings under relatively oxic conditions and had an original lower gas-prone organic facies C.The Upper Safa Member had an original active fair to excellent organic richness (0.76–7.35, avg. 3.38 TOCo(live) wt%) and hydrocarbon source rock potential (S2o: 2.22–17.97, avg. 8.05 mg HC/g org. C). It was characterised mainly by original active mixed gas/oil-prone kerogen type IIIo(live)-IIo(live) (HIo(live): 200.27–297.34, avg. 238.03 mg HC/g TOCo(live)) and subordinately by gas-prone kerogen type IIIo(live) (HIo(live): 181.50 mg HC/g TOCo(live)). The Upper Safa Member had original poor to fair proportions of active oil-prone (0.15–1.47, avg 0.68 TOCo(live, oil) wt%) and higher fair to very good proportions of active gas-prone (0.61–5.88, avg. 2.70 TOCo(live, gas) wt%) kerogens. The Upper Safa Member originally possessed poor to very good oil (S2o(oil): 0.44–3.59, avg. 1.16 mg HC/g org. C) and good to very good gas (S2o(gas): 1.77–14.37, avg. 6.44 mg HC/g org. C) generation potential. The carbonates and partly calcareous shales of the uppermost Safa and the Zahra members possessed poor oil and gas generation potential due to their organic-lean status.The present-day organic geochemical characterization indicates that the Upper Safa Member still shows active fair to excellent organic richness (0.68–6.75, avg. 3.11 TOCpd(live) wt%). However, this member shows a relatively lower present-day good to very good/excellent source rock potential (S2pd: 1.33–10.78, avg. 4.83 mg HC/g rock) and lower active kerogen quality IIIpd(live) (HIpd(live): 115.97–198.21, avg. 151.07 mg HC/g TOCpd(live)). This is related to the current high thermal maturation (gas-window: Tmax: 459–468, avg. 469 °C, thermal alteration index: TAI of 4-) and conversion of the original kerogen IIIo(live)-IIo(live) into oil and gas. The present-day high organic richness, high remaining generative potential, high shale volume of the thermally mature gas-prone kerogen, classify the Upper Safa Member as an active fair to excellent shale gas play in the Matruh Basin. Intrabasinal and interbasinal correlations across northwestern Egypt indicate that the upper Khatatba Formation shows locally and regionally dual source and reservoir rock characteristics due to the lateral facies changes.

Three-Dimensional Structural Modeling (3D SM) and Joint Geophysical Characterization (JGC) of Hydrocarbon Reservoir

A complex structural geology generally leads to significant consequences for hydrocarbon reservoir exploration. Despite many existing wells in the Kadanwari field, Middle Indus Basin (MIB), Pakistan, the depositional environment of the early Cretaceous stratigraphic sequence is still poorly understood, and this has implications for regional geology as well as economic significance. To improve our understanding of the depositional environment of complex heterogeneous reservoirs and their associated 3D stratigraphic architecture, the spatial distribution of facies and properties, and the hydrocarbon prospects, a new methodology of three-dimensional structural modeling (3D SM) and joint geophysical characterization (JGC) is introduced in this research using 3D seismic and well logs data. 3D SM reveals that the field in question experienced multiple stages of complex deformation dominated by an NW to SW normal fault system, high relief horsts, and half-graben and graben structures. Moreover, 3D SM and fault system models (FSMs) show that the middle part of the sequence underwent greater deformation compared to the areas surrounding the major faults, with predominant one oriented S30°–45° E and N25°–35° W; with the azimuth at 148°–170° and 318°–345°; and with the minimum (28°), mean (62°), and maximum (90°) dip angles. The applied variance edge attribute better portrays the inconsistencies in the seismic data associated with faulting, validating seismic interpretation. The high amplitude and loss of frequency anomalies of the sweetness and root mean square (RMS) attributes indicate gas-saturated sand. In contrast, the relatively low-amplitude and high-frequency anomalies indicate sandy shale, shale, and pro-delta facies. The petrophysical modeling results show that the E sand interval exhibits high effective porosity (∅eff) and hydrocarbon saturation (Shc) compared to the G sand interval. The average petrophysical properties we identified, such as volume of shale (Vshale), average porosity (∅avg), ∅eff, water saturation (SW), and the Shc of the E sand interval, were 30.5%, 17.4%, 12.2%, 33.2% and, 70.01%, respectively. The findings of this study can help better understand the reservoir’s structural and stratigraphic characteristics, the spatial distribution of associated facies, and petrophysical properties for reliable reservoir characterization.

Pore Structure and Fractal Characteristics of Deep Shale: A Case Study from Permian Shanxi Formation Shale, from the Ordos Basin.

Pore structure has certain significance for the preservation and enrichment of shale gas. However, less attention is paid to deep shale (>3000 m) which has unique pore characteristics that distinguish it from the shallow and medium layers. In order to study the pore structure characteristics of deep shale, 10 samples of the Shanxi Formation are collected from well YP-1 within the depth of 3550–3610 m in the Fuxian block of the Ordos Basin. The pore structure characteristics of shale samples are quantitatively studied by scanning electron microscopy (SEM), low-temperature nitrogen adsorption–desorption, and high-pressure mercury injection experiments. The pore surface area (SA) and pore volume (PV) of the deep shale of Shanxi formation are low, with average values of 4.282 m2/g and 0.0126 mL/g, respectively. The content of total organic carbon (TOC) is high, which is in the high over mature stage, with undeveloped organic pores and developed microfractures. The main mineral components are clay (51.6%∼89.1%) and quartz (8%∼41.7%). By establishing the relationship between SA, PV, and TOC for quartz and clay minerals, it is found that these three parameters have little contribution to SA and PV. The pore diameter is mainly mesoporous, 2.5–4 nm and 8–11 nm. The complexity of pore structure is discussed through the fractal dimension calculated by the fractal Frenkel–Halsey–Hill (FHH) model. The pore fractal dimension D2 (2.6240) is greater than D1 (2.5608), and the complexity of the pore structure is greater than that of the pore surface. The fractal dimension of deep shale in Shanxi is negatively correlated with TOC content and weakly correlated with quartz and clay minerals. It shows that the mineral composition of deep shale in Shanxi Formation in the study area has little effect on pore development, and the development of microfractures is the main contribution of SA and PV.

Geophysical appraisal of the Abu Madi gas reservoir, Nile Delta Basin, Egypt: Implications for the tectonic effect on the lateral distribution of petrophysical parameters

The tectonic deformation has a significant influence on the hydrocarbon reservoirs properties. The effect of this process focuses on the lateral distribution of the petrophysical parameters characterizing the hydrocarbon reservoirs. The main objective of the current study is to perform a petrophysical examination of the Abu Madi gas reservoir which is the greatest gas-bearing reservoir at Nile Delta Basin in order to examine how far the Messinian tectonics affected the lateral variations of these petrophysical parameters. This petrophysical evaluation was performed based on the wireline log data acquired for five wells, namely, Abu Madi-2, Abu Madi-7, El Qara-3, Nidoco-7, and Nidoco-9 drilled within the Abu Madi Paleo-Valley. The petrophysical assessment for the most promising zone intervals within the Abu Madi sandstones in the inspected wells show that the total porosity varies between 17% and 22%, the effective porosity ranges from 7% to 19%, the shale volume fluctuates between 16% and 30%, hydrocarbon saturation varies from 37% to 76%, and the bulk volume of water varies between 0.02 and 0.09. These significant variations in the petrophysical properties of the Abu Madi reservoir are attributed to the tectonic influence during the deposition of the Abu Madi Formation as a part of the Late Miocene syn-rift megasequence in the Nile Delta Basin. This conclusion confirms that the petrophysical properties of sandstone reservoirs are function of tectonic and structural deformation.