Shale Volume Research Articles

The application of archival borehole data to recognizing the primary mineral composition and diagenetic changes in Jurassic sandy rocks of the Polish Basin

With emphasis being placed on the re-examining of mature petroleum basins and reduction of the negative impact of the industry on the environment, the use of archival data in geological exploration is essential. This is especially important in regions where the old, Soviet-type tools were used in the past and which are now using modern, western logging equipment. The application of archival geological, geochemical and geophysical data allows recognition of reservoir formations without the use of modern measurements. For the purpose of this research, Jurassic sandy rocks identified in the archival borehole Z-GN4 were analysed. They appear to be a perfect target for further petroleum and geothermal exploration in the Polish Basin; however, variable mineral composition and diagenetic features can cause difficulties while estimating their reservoir properties. The difference between gamma ray and spontaneous potential shale volume parameter (clay difference) was applied together with gamma ray measurement to determine the impact of primary and diagenetic features on each sandy petrofacies. Based on an integration of detailed petrographic analysis of available core samples from Z-GN4 borehole with archival borehole logs, four different sandy petrofacies were distinguished. Moreover, deep resistivity and sonic logs were used to highlight the carbonate-cemented intervals. This study shows how the application of petrofacies analysis in archival datasets can support the interpretation of uncored intervals and upgrade the level of reservoir characterization.

A Thermal-Hydraulic-Gas-Mechanical Coupling Model on Permeability Enhancement in Heterogeneous Shale Volume Fracturing

Heat treatment on shale reservoirs can promote the development of secondary fractures in a matrix on the basis of hydraulic fracturing, forming multi-scale gas–water seepage channels and strengthening the gas desorption. Experimental evidence shows that heat treatment can enhance gas recovery in the same mining life. Heat treatment on a shale gas reservoir is a multi-physical and multi-phase coupling process. However, how the thermal stimulation interacts with nonlinear two-phase flow in heterogeneous shale volume fracturing has not been clear. In this paper, a fully coupled THGM model for heating-enhanced shale-gas recovery in heterogeneous shale reservoirs is proposed. First, the governing equations are formulated for the shale-reservoir deformation involving both gas adsorption and thermal expansion, the permeability evolution model for the cracking process of fractured shale, the gas–water two-phase continuity equation considering the effects of gas solubility and the heat transfer equation for heat conduction and convection. The interactions among stress, temperature and seepage in a heterogeneous shale reservoir were studied. Secondly, a test on shale permeability after 50 °C temperature treatment was conducted. The evolution of temperature, capillary pressure, water and gas saturation and the permeability of shale during the heat treatment of the reservoir were numerically analyzed. Finally, the gas production from a shale gas reservoir was numerically simulated with this THGM model. The numerical results indicated that the thermal-induced fracturing, gas desorption and separation from water make predominant contributions to the evolution of permeability. The heat treatment can enhance cumulative gas production by 58.7% after 27.4 years of heat injection through promoting gas desorption and matrix diffusion.

Reservoir characterisation of unconventional rock units in the middle jurassic Sargelu Formation, atrush field, zagros folded belt

The heterogeneous lithological components of the Middle Jurassic Sargelu Formation in the Atrush field of the high folded zone were examined using rock samples, conventional wireline logs, mud logs and well test results throughout two wells. The Sargelu Formation is 45 m thick and has been divided into three units based on lithological characteristics and shale volume. The upper unit of the Sargelu Formation is composed of argillaceous limestone with intercalation of dolostone and anhydrite beds. The middle unit of the Sargelu Formation is composed of organic rich laminated shales, which contain residual bitumen, whilst the lower unit of the formation is dominated by argillaceous limestones. Lithological variation, mineralogy and organic matter contents are shown to be essential factors in controlling the reservoir matrix porosity and permeability. The maximum matrix porosity and permeability were observed within the dolomite plug samples (13.40%, 10.40 mD) and the lowest values were recorded in the anhydrite samples, both found in the upper unit of the Sargelu Formation. The fracture permeability is three orders of magnitude higher than the matrix permeability and the hydrocarbon production is predominately derived from the fractured intervals throughout the Sargelu Formation. The interconnected fracture pathways are influenced by the lithological variation and mineralogical components of the formation along with the tectonic position of the field. It was found that as the confining pressure increased the fracture permeability reduced. The different lithologies were also found to be sensitive to increases in the confining pressure. The clastic shale rich rocks are most sensitive to increases in confining pressure, whilst the more carbonate rich rocks showed the lowest variation as a function of confining pressure.

Characterization of the Giant Chicontepec Tight Oil Paleochannel in Mexico and Integration with Actual Cumulative Oil Production

Summary The Chicontepec paleochannel contains unconventional tight oil shaly sandstone reservoirs also characterized by natural fractures of tectonic origin. Chicontepec ranks as a giant reservoir with volumes of original oil in place (OOIP) ranging between 137,300 and 59,000 million STB (Guzman 2019). Although the cumulative oil is significant (440.38 million STB), it only represents 0.32 to 0.75% of the OOIP. The objective of this study is to develop a new characterization methodology with a view to increase oil recovery from Chicontepec. OOIP in Chicontepec paleochannels was estimated originally at 137,300 million STB. Despite several studies using state-of-the-art methodologies and contracting major oilfield services companies to test new technologies and significant investments, the OOIP was decreased recently to 59,000 million STB due to lack of any significant success on the implemented projects. This study shows that the key to success is understanding the contribution of natural fractures. This is demonstrated for the case of Chicontepec with a new dual-porosity petrophysical model for naturally fractured laminar shaly sandstone reservoirs developed in this study. The model assumes that matrix and fractures are in parallel. Laminar shaliness is handled with a parameter (Alam) that is a function of true and shale resistivities, and fractional shale volume (Vsh). The methodology integrates data from observations in outcrops, quantitative evaluation of cores, well logs, and actual production data. Past Chicontepec studies have assumed that the porosity exponent (m) in Archie and shaly sandstone equations is constant. However, core studies indicate that Chicontepec m values become smaller as porosity decreases. The proposed dual-porosity petrophysical model, when applied to actual Chicontepec wells, matches properly the laboratory values of m and generates results that generally compare well with actual production data (e.g., the larger the value of fracture partitioning, the larger is the cumulative oil production). Pattern recognition allows estimating fracture intensity with a partitioning coefficient, which is calculated as the ratio of fracture porosity to total porosity. The new contribution of this manuscript is the development of a petrophysical dual-porosity model for naturally fractured shaly sandstone reservoirs that integrates variable values of m from cores, fracture intensity, and cumulative production of individual Chicontepec wells. Our detailed review of the literature indicates that this methodology has not been published previously.

Formation evaluation and reservoir quality assessment of the Albian clastic sequence in the SWM Oilfield, Southwest the Mesopotamian Basin, Iraq

This work intends to delineate the petrophysical properties and the reservoir quality of the Albian sequence in the Mesopotamian Basin which has been deposited as a siliciclastic sequence. The well log data (including the caliper, gamma-ray, density, photoelectric factor 'PEF', neutron, sonic, and resistivity logs), derived from eight wells in the SWM (Southwest Mesopotamian) Oilfield, was studied and interpreted using the appropriate software (IP3.6). These borehole data indicate the necessity to divide the sequence into five reservoir rock units (U1, U2, M, L1, and L2 units). This enabled depicting the porosity, shale volume, water saturation, and net-pay thickness in the vertical and horizontal directions. It is indicated that the M and L1 units are the most promising units with good to very good porosity (∅ ≥ 17.2%), low water saturation (Sw ≤ 28.0%), and acceptable shale volume (Vsh ≤ 8.4%). The net-pay thickness varies between 32.8 and 77.4 m in the different wells of the SWM Oilfield. The well log data were supported by more detailed conventional core data including porosity (∅He) and permeability (k), from which the reservoir quality parameters were estimated precisely. In the present study, reservoir quality assessment based on conventional core data is considered for the first time for evaluating and discriminating the Albian–Aptian sequence in the Southwest Mesopotamian field into reservoir zones and hydraulic flow units. The estimated reservoir parameters include the Flow Zone Indicator (FZI), the Reservoir Quality Index (RQI), and the effective pore radius (R35). Based on the available core data and the estimated reservoir quality parameters, the studied sequence was divided into three reservoir rock types (RRT1–3). The best petrophysical properties have been assigned for the medium-grained sandstone of the RRT1 that dominates in the L1 and the M units (av. ∅He = 23.0%, av. k = 1581 mD, av. R35 = 23.7 μm, av. FZI = 7.368 μm, and av. RQI = 2.304 μm). On the other side, the fine-grained sandstone of the RRT3 is characterized by the lowest petrophysical properties and reservoir quality parameters (av. ∅He = 17.1%, av. k = 5.49 mD, av. R35 = 0.92 μm, av. FZI = 0.603 μm, and av. RQI = 0.136 μm). The integration between the well log and core data of the studied Albian sequence stated that the M and L1 units are the most promising reservoir units. They are predominated by medium-grained and fine to medium-grained sandstones of the RRT1 and the RRT2, respectively. This well log-core data integration is applicable to the different oilfields in the different fields in the Mesopotamian Basin and other basins in south Iraq and elsewhere.

Improved Water-Based Mud Rheological Properties and Shale-Inhibition Behavior by Using Aluminum Oxide and Iron Oxide Nanoparticles

Nanotechnology can be used to develop drilling fluid additives that can improve the drilling fluid's properties. Using two types of nanoparticle (NP) additives in water-based drilling fluids have been studied in this paper. Three major drilling mud systems, namely potassium chloride (KCl) as a basic mud, KCl/aluminum oxide (Al2O3) NPs, and KCl/iron (Fe2O3) NPs, were prepared and studied for enhancement of rheological properties and shale inhibition. It was found that the drilling mud contained NPs in concentrations of 0.25, 0. 5, 0.75, and 1 g. Al2O3 and Fe2O3 NPs added to KCl/polymer mud systems resulted in a 50% and 30% change in shale volume, respectively. The results demonstrated that incorporating NPs into the KCL mud system enhanced shale inhibition. Adding NPs to the KCL-WBM increased yield point, plastic viscosity, and gel strength. The COF of KCL-polymer was reduced by 48% and 34% when added Al2O3 and Fe2O3 NPs at 0.5 and 0.75g, respectively. When Al2O3 and Fe2O3 NPs were used, particularly at 1g, the amount of mud filtration decreased from 13.1ml to 8.8 ml and 8.4 ml, respectively. Overall, it was found that adding Al2O3 and Fe2O3 NPs to the KCl-WBM can improve rheological, swelling, and filtration properties as well as lubrication.

Calculating Volume of Clay and/or Shale From Wireline Logs

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Adaptive boosting of random forest algorithm for automatic petrophysical interpretation of well logs

The power of Machine Learning is demonstrated for automatic interpretation of well logs and determining reservoir properties for volume of shale, porosity, and water saturation respectively for tight clastic sequences. Random Forest algorithms are reputed for their efficiency as they belong to a class of algorithms called ensemble methods, which are traditionally seen as weak learners, but can be transformed into strong performers and they promise to deliver highly accurate results. The study area is located offshore Australia in the Poseidon and Crown fields situated in the Browse Basin, which are gas fields in tight complex clastic reservoirs. There are 5 wells used in this study with one well manually interpreted which is subsequently used in developing a machine learning model which predicts the output for the other 4 wells. The basic open hole logs namely Natural gamma ray, Resistivity, Neutron Porosity, Bulk Density, P-wave and S-wave sonic travel-time, are used in interpretation. One of the wells has a missing S-wave travel-time log which was also predicted by developing a Random Forest Machine Learning model. The results indicate a very robust improvement in performance when Random Forest algorithm was combined with Adaptive Boosting when interpreting the well logs. The training accuracy using Random Forest alone was 98.21%, but testing was 77.62% which suggested over-fitting by the Random Forest model. The Adaptive Boosting of the Random Forest algorithm resulted in the overall training accuracy of 99.40% and an overall testing accuracy of 97.03%, indicating a drastic improvement in performance. S-wave travel-time log was predicted by preparing a training set consisting of Natural gamma ray, Resistivity, Neutron Porosity, Bulk Density, and P-wave travel-time logs for the 4 wells using Random Forest which gave a training accuracy of 99.79% and a testing accuracy of 98.54%. Machine learning algorithms can be successfully applied for interpreting well log data in complex sedimentary environment and their performance can be drastically improved using Adaptive Boosting.

Hydrocarbon Reservoir Characterization Using Well Logs of Nahr Umr Formation in Kifl Oil field, Central Iraq

This study aims to determine the petrophysical characteristics of the three wells in the Kifl Oilfield, central Iraq. The well logs were used to characterize hydrocarbon reservoirs to assess the hydrocarbon prospectivity, designate hydrocarbon and water-bearing zones, and determine the Nahr Umr Formation's petrophysical parameters. The Nahr Umr reservoir mainly consists of sandstone at the bottom and has an upper shale zone containing a small proportion of oil. The geophysical logs data from three oil wells include gamma-ray, resistivity, neutron, density, acoustic, and spontaneous potential logs. A gamma-ray log was employed for lithology differentiation, and a resistivity log was used to determine the response of distinct zones' productivity. The petrophysical parameters of shale volume, total porosity, effective porosity, water saturation, hydrocarbon saturation, and flushed zone saturation were evaluated using computer processing analyses (CPI). These parameters were plotted by interactive petrophysics (IP) software. The effective porosity (PHE) in the sandstone unit ranges between 3.2 and 31.2%, water saturation (SW) ranges between 6.6 and 100%, and hydrocarbon saturation and (Sh) range from 6 to 65%. The Nahr Umr Formation has moderate to low reservoir characteristics in the lower sandstone unit.

Petrophysics based Reservoir Evaluation of the Cretaceous Lower Goru “C” Sands, Middle Indus Basin, Sindh, Pakistan

This study demonstrates the reservoir investigation of the Cretaceous Lower Goru “C” sand interval using exploratory well data from the middle Indus basin of Sindh. The petrophysical parameters including volume of shale, effective porosity, and water saturation of the investigated reservoir interval were calculated. The shale volume calculation results in 30–35% of non-clean (shale) lithology, which is high as compared to Sawan-01 and Sawan-08 wells. The effective porosity ranges from 12–16%, while the average value of water saturation in the complete interval of “C” sand falls in the range of 50–60%. However, certain zones with relatively lower water saturation values of around 30-50% are also observed. These zones are considered better pay zones in comparison to the other intervals. A “gas effect” phenomenon observed on cross plots represents the area of neutron-density cross-over indicating the presence of lighter hydrocarbons in this reservoir zone interval.

Determination of the Maxx Prospect Zone Petrophical Parameters in MA06 Well MA Field with Log Data Analysis

The well logging method is one of the methods used in petrophysical analysis to assess the formations used in obtaining information and shadows related to a reservoir. In addition, in an effort to determine success in the oil and gas field, this method is also included for calculating petrophysical values such as permeability, water saturation, and porosity. Then this value will be used in finding the initial oil reserves (OOIP) and initial gas reserves (GIIP) in the MA field. This will be very helpful in developing further oil and gas fields because materials are available as a basis for reference. This study analyzes the MA field precisely at the MA-06 Well by utilizing the qualitative and quantitative petrophysical analysis method by only referring to log data because there is no availability of core data. To find out the depth of the prospect zone and what fluid is in the formation, the authors analyze it in a qualitative way, namely by determining the permeable zone, then looking at the resistivity value, then determining the type of fluid on track 3. While in obtaining petrophysical values such as shale volume, porosity, water saturation and rock permeability the authors chose to use quantitative methods to analyze them. So that the results of the analysis carried out, it was found that the MAXX well has a net sand thickness of 36 feet and a net pay of 36 feet with an average value of shale volume, porosity, water saturation and permeability in that zone respectively 34.8%. , 18.03%, 35.3%, and 38.31 mD.

Assessment of Fault Sealing in the Gabo Field, Niger Delta, Nigeria

This research assesses the sealing of the fault bounded stratigraphy of the Gabo Field, Niger Delta, Nigeria. Materials used comprises of 3D seismic volume in seg-y, ditch cuttings and well logs. The methods applied are standard fault plane evaluation techniques and they include seismic interpretation, well correlation, XRD analysis, and application of the Yielding et al., (1997) shale gouge ratio (SGR) algorithm for fault seal analysis. The tectonic framework was interpreted in terms of deformational, depositional and post-depositional structures. The order of magnitude of stress is SHmax > σv > Shmin. The juxtaposed strata relationships were analyzed by taking cross sections A-A1 and B-B1 and this showed the structural framework across the field. Cross section A-A1 showed that the depositional and post depositional structures are pinchouts (channel abandonment or switching) and shale smears respectively. The cross section B-B1, showed that the deformational structures are faults F1 and F2 – recognized as closely spaced normal faults and F3 is a syn-depoitional growth fault. The well correlation showed the vertical stratigraphy of the wells are comprised of cyclic succession of sands and shales and the shale thickness increased in intermediate sections. The X-ray diffraction (XRD) analysis of the shales showed that the predominant minerals are kaolinite, rutile, gypsum, albite, microcline and quartz. The rock property analysis showed that the net to gross ranges from 26.28 – 82.0% with an average of 73.7%. The volume of shale ranges from 18 – 73.72% with an average of 63.59%. The bulk density of the shales ranges from 2.379 – 2.692g/cc with an average of 2.46g/cc. The total porosity ranges from 0.159 – 0.317 with an average of 0.167 in the shales and 0.272 in the sand. The effective porosity range from 3.58 – 22.71 with an average of 6.028 in the shale and 20.13 in the reservoir. The drawdown mobility and temperature range is 2.2 – 4124.4mD/cP and 63.3 – 80.1oF respectively, while the average is 569mD/cP and 70.63oF respectively. The estimated pore pressure ranges from 0.4213 – 0.4762psi/ft with an average of 0.47psi/ft in the shales and 0.428 psi/ft in the sand. The fault seal analysis showed that the shale gouge ratio range from 0.2 – 0.7 and the stratigraphic juxtapositions are predominantly sand to sand, sand to shale and shale to shale. The results of this research reduces the fault seal uncertainty in the planning of oilfield development projects and enhanced pressure support for the recovery of bypassed hydrocarbons, most especially in compartmentalized reservoirs. In addition, the results of this research can be applied to similar deltaic successions around the world.

An integrated source rock potential, sequence stratigraphy, and petroleum geology of (Agbada-Akata) sediment succession, Niger delta: application of well logs aided by 3D seismic and basin modeling

We investigated the source rock potential, sequence stratigraphy, and characterized hydrocarbon reservoirs at Otumara field, Niger delta, using integrated 3D seismic, wireline log analysis, and basin modeling. The burial history and thermal maturity were modeled, the reservoirs were delineated, and the petrophysical parameters were also estimated from the wireline logs. The Passey “ΔLog R” method for estimating the preliminary evaluations of the total organic carbon (TOC) from integrating sonic, neutron, and density with resistivity has been used. The results indicate that the primary source rock of hydrocarbons is the Upper Akata Formation, despite a higher TOC percentage in the Agbada Formation. Based on sequence stratigraphy analysis, TA4, TB1, TB2, and TB3 second-order supercycles were obtained in the studied well TD46. The results also revealed that the field has two large net pays with high-quality reservoir facies: a deltaic slope fan at the upper shoreface and a river mouth sandbar at the lower shoreface. Furthermore, the reservoirs were faulted by a series of growing faults that faulted the basin slope. The reservoir facies are characterized by an average of 18% porosity, 1200 mD permeability, 16% volume of shale, and high hydrocarbon saturation of about 85%. Finally, the petroleum system elements have been defined for improved hydrocarbon exploration. In the absence of complete or partial core samples, this case study emphasizes the importance of using wireline logs to estimate organic richness and investigate sequence stratigraphy in clastic sediments.

The potential of offshore Nile Delta Basin natural gas reserves: a case study of Messinian reservoir in Baltim field

The offshore part of the Nile Delta Basin (NDB) is a prolific provenance for gas exploration. The present study aims to perform a geophysical evaluation for the Messinian Abu Madi sandstones along the Messinian paleo-valley in Baltim field as a case study. The seismic interpretation step exposed that the Abu Madi incised valley displays NNW-SSE trend with width ranges from 5 to 8 km and a length of 32 km. The petrophysical appraisal for five drilled wells (BE-2, BE-3, BE-5, BN-1 and BN-2) in Baltim Field has been performed. The findings of this assessment revealed that the most promising intervals in the studied wells have gross-thicknesses vary between 25 and 49 m; net pay thicknesses range within 15 m and 38.5 m; net/gross ratio of 0.54–0.90; effective porosity of 15–40%; shale volume is less than 20; and water saturation ranges between 25 and 50%. Such notably talented and converging values of these parameters across the examined zones reflects the relative homogeneity and lateral continuity of the Abu Madi reservoir across the inspected paleo-valley. The results of this study can help for a better understanding of the petrophysical characteristics for the Messinian reservoir over the offshore NDB. Therefore, the Messinian sandstones could exhibit possible targets for future gas exploration over the offshore NDB together with the Pliocene sandy levels, which represent the main and the recent discoveries of gas accumulations.

Well Log Interpretation and Petrophysical Modeling to Evaluate Zubair Reservoir in North-Rumaila Oil Field

This study uses well log interpretation and petrophysical modeling, which is one of the most influential tools for the evaluation of Zubair Reservoir in the X Oil Field. Understanding reservoir parameters and boosting output by picking the optimal location for future drilling candidates will be helped by these interpretations and modeling. 3D seismic and well log data were used to create and describe a petrophysical model in this investigation. Each parameter was upscaled when interpreting well logs and calculating petrophysical characteristics. The petrophysical model was created using geostatistical approaches such as Gaussian simulation, variogram, and Monte Carlo simulation. Techlog, Petrel, and HRS Software were used in this study. As a result, we analyzed porosity, shale volume, and water saturation for four wells named A, B, C, and C using a set of commercial software and applying the different well logs like; gamma-ray (gr) log, spontaneous potential log, porosity logs (Density Log, Neutron Log, and Sonic Log), and resistivity log. The range of porosity values is 0.23 to 0.30, the water saturation is around 10% in the crest and 60% in the flank, and Vsh is interbedded with sand and the value is decreasing 25% in the clean sand bed. This formation is characterized by clean sand and is interbedded with a sharp boundary. The sand in the main pay is characterized by homogeneous and uniform porosity patterns. The homogeneous nature of the sand leads to uniform saturation of water to fill this entire sand unit with oil and the absence of a transition zone.

Controlling Factors and Quantitative Characterization of Pore Development in Marine-Continental Transitional Shale

Abstract The pore characteristics are studied in the overmatured marine-continental transitional (MCT) shale and simulated shale under different thermal maturity conditions, based on transitional and simulated shale samples in the eastern margin of Ordos Basin. The work uses high-pressure mercury intrusion (MICP), field emission scanning electron microscopy (FESEM), helium-mercury method, X-ray diffraction of whole-rock minerals, and hydrocarbon-generating thermal simulation to quantitatively analyze pore characteristics and main controlling factors of pore development. The results show that the shallow bay and lake facies (SBLF) shale has great exploration potential, while the delta facies (DF) shale has poor exploration potential. The SBLF shale is mainly characterized by pie shale, high quartz and carbonate, low clay, high porosity, and pore volume. The DF shale mainly develops dot shale with low quartz and carbonate content, high clay content, low porosity, and pore volume. Kaolinite has the strongest inhibition on MTC shale pore development. The pore volume of MTC shale decreases first and then increases with maturity. The pie shale is more conducive to the increase of pore volume than the dot shale. The effect of doubled TOC on porosity is greater than that of maturity in the dot shale. The effect of doubled TOC on porosity is less than that of maturity in the pie shale. Organic matter (OM) has the greatest impact on pore development, controlled by the OM content, sedimentary facies, and maturity. OM content, sedimentary facies, and maturity can be used to jointly characterize the MTC shale pore development, providing guidance for multiparameter quantitative characterization of pore development and determining the enrichment area of shale gas.

Fracture Properties and Their Impacts on Performance in Carbonate Reservoir, Central Block B on the Right Bank of Amu Darya

Abstract The Callovian-Oxfordian carbonate reservoir in central Block B on the right bank of Amu Darya is composed of different mechanical and petrophysical layers, where the tectonic fractures have major influences on both the performance and production of the low-permeability reservoir. The development of the tectonic fractures is mainly controlled by the mechanical properties of rocks (e.g., lithology, rock texture, porosity, and shale volume), and the differences in the development of tectonic fractures leading to the high production intervals are restricted preferentially due to fractured mechanical layers. Our study results show that the three main tectonic fracture systems are developed in the Callovian-Oxfordian Stage, including the fracture systems caused by extension movement, compression movement, and fold deformation. Specifically, high-angle extensional fractures and conjugate shear fractures are generally caused by extension movement, which are of small apertures and are mostly fully mineralized and have little impact on fluid flow. Medium- and low-angle extensional fractures as well as conjugate shear fractures are generally caused by compression movement where the strike is nearly parallel to the present-day maximum horizontal stress. These fractures have large aperture and good connectivity with strong flow conductivity of the fluid. However, fewer tectonic fractures are caused by fold deformation. The main properties of natural fractures, such as fracture length, fracture density, fracture aperture, fracture porosity, and stress sensitivity as well as their impacts on the Callovian-Oxfordian reservoir performances, are described herein. We conclude that the tectonic fractures have slight impacts on porosity albeit significant impacts on permeability. Hence, the well placement and well type are optimized under the guidance of the study results.

Reservoir characterization of the middle Miocene Kareem sandstones, Southern Gulf of Suez Basin, Egypt

In this study, we have assessed the petrographical and petrophysical characteristics of the progradational, syn-rift Middle Miocene Rahmi sandstone gas reservoir (Lower Kareem Formation) from the East Matr and Amal hydrocarbon fields, southern Gulf of Suez by integrating sidewall cores and wireline logs. We interpreted a reservoir gas gradient of around 0.09 psi/ft from the downhole pressure measurements. Based on well log-based petrophysical analyses, we interpreted that the Rahmi reservoir in the East Matr field has a 0.10–0.18 v/v total porosity, 0.08–0.14 v/v effective porosity, 0.08–0.17 v/v shale volume along with water saturation ranging between 0.09 and 0.32 v/v. The correlated reservoir in the Amal field is observed to have higher porosities (0.17–0.22 v/v total porosity and 0.15–0.19 v/v effective porosity), although it exhibits higher water saturation (0.38–0.54 v/v). The reservoir consists of very fine to coarse grained, poorly to moderately sorted, subangular to subrounded, poorly cemented and moderately compacted sublithic, subarkosic and arkosic arenites with moderate to good intergranular porosity. Abundant lithic fragments and poor textural maturity of the Rahimi sandstones imply a high energy shoreface depositional environment in close proximity to the hinterland. Porosity reduction is attributed to dolomite cementation, kaolinite, formation of pseudomatrix by mechanical compaction of argillaceous lithics, and quartz overgrowth. Long and concavo-convex intergranular contacts indicate that silica needed for quartz cementation was derived by moderate degree of chemical compaction of the quartz grains. Partial to near-complete dissolution of the labile grains (feldspar and lithics) and dolomite attributed to the reservoir quality improvement. Scattered dolomite cements prevented more severe mechanical and chemical compaction.

Petro-physics Analysis and Rock Physics Modeling for Estimation of Gas Hydrate Saturation: A Case Study in the Mahanadi Offshore Basin

Abstract Gas hydrate saturation (Sh) is the most challenging key parameter of petrophysical evaluations for reservoir characterization. In total three wells were used (namely, NGHP-01-19, NGHP-01-09, and NGHP-01-08) to compute the petrophysical parameters in the gas hydrate-bearing sediments of the Mahanadi offshore basin. Initially, effective porosity and volume of shale are computed using conventional log data varying from 11-36% and 55-75% respectively. The most prominent technique responding to the physical property has been used to compute the Sh by using Archie’s empirical electrical resistivity method. The presence of gas hydrate, free gas, and other lithology affects the sonic velocity which is widely used to quantify the hydrate saturation. Therefore,an attempt is made to quantify the Sh from the wellbore sonic velocity using a rock physics model at higher porosity (~62%) for unconsolidated marine sediments below the seafloor. The model is best suited for gas hydrate zones where velocity increases with the hydrate saturation but underestimates the saturation for free gas zones below the bottom simulating reflector. In the study area,Sh ranges from 5-13% in the depth interval of 175-200 mbsf for well NGHP-01-19 whereas, small amount of 3-10%and 2-8% for well NGHP-01-09 and NGHP-01-08 respectively. The Sh obtained from the rock physics model is insignificantly mismatched with the saturation obtained from temperature and resistivity data due to the presence of an isotropic layer with fracture filling sediments having anisotropic properties.

Reservoir Characterization of Eocene Carbonates of Central Indus Basin, Pakistan

The present study is based on petrophysical analysis of the Eocene Sui Main Limestone (SML) penetrated in wells of Qadirpur Gas Field, Central Indus Basin, Pakistan. The analyzed petrophysical property of SML includes shale volume, total porosity, effective porosity, water saturation, hydrocarbon saturation and net pay thickness. The result from the study shows that the Sui Main Limestone reservoir is capable of yielding appreciable hydrocarbon. The petrophysical interpretation revealed that the studied SML has productive reservoir characteristics with average (total and effective) porosity is in K-1, 15% in K-2 15% and 17% in K-3, average saturated hydrocarbon in SML is (70-100%) indicating that zones in wells are purely saturated with hydrocarbon, and average volume of shale in the zone of K-1, 23% in K2, 27% and in K-3, 25% respectively delineating clean formation. Facies modeling revealed that the studied Eocene formation consist of clean limestone, shaly limestone and shals. The isopach thickness map and stratigraphic correlation helps to understand the thickness of Sui Main Limestone in the field.