Gas-bearing Zones Research Articles

PNN Enhanced Seismic Inversion for Porosity Modeling and Delineating the Potential Heterogeneous Gas Sands via Comparative Inversion Analysis in the Lower Indus Basin

Seismic inversion has been in use for the last two decades to measure inverted impedances using an integrated data set approach. This research focuses on the application of multi-attribute seismic inversion and the geostatistical probabilistic neural network (PNN) approach for determining rock properties and litho-fluid classification in the Mehar-Mazarani Field of the Lower Indus Basin (LIB), Pakistan. The study compares five different inversion techniques, including model-based inversion (MBI), colored inversion (CI), linear sparse spike inversion (LSSI), band-limited inversion (BLI), and maximum likelihood sparse spike inversion (MLSSI). The inverted outputs, such as acoustic P-impedance (Zp), density (ρ), porosity (φ), and shale volume (Vsh), were analyzed in Paleocene and Cretaceous geological complex reservoirs to identify gas-bearing zones. The results indicated the existence of gas between 1630 and 1700 ms (ms) and corresponding depth ranges from approximately 3200 m up to 4200 m with varying thickness. Amongst the inversion techniques, MBI demonstrated greater accuracy, with inverted density volumes showing a strong correlation coefficient of 0.98 and the lowest root mean square error (RMSE) and relative error of 0.10 m/s * g/cc. A geostatistical PNN approach was employed to estimate variations in Vsh and φ within the sand reservoir. MBI again yielded more reliable results, with a strong correlation between the measured and inverted attributes. High φ and low Vsh were observed in predetermined low-impedance zones. Overall, MBI is proven to be the most accurate and reliable technique, providing clear identification of the gas occurrence. This research highlights the effectiveness of seismic inversion, particularly the application of MBI, in determining rock properties and identifying gas-bearing zones within the Mehar-Mazarani gas field.

Current condition, geological structure and prospects of oil and gas resources in the Aral sea

The article presents the results of the analysis of the current state of study of the Aral Sea region by geological exploration works, and in more detail – of the Aral Sea aquatory. An attempt has been made to correlate new geological data based on the works of Uzbek geologists and materials of seismic surveys of the Kazakh part of the Aral Sea, since the West Aral oil and gas condensate field has been discovered in the Uzbek part of the Aral Sea water area, the productivity of which is associated with the Middle-Upper Jurassic deposits. Taking into account the history of geological development of the territory and formation of oil and gas bearing zones, it is necessary to carry out geological exploration works in the perspective of the unified model of the Aral Sea basin. On the basis of the discussed model of geological structure the prospects of oil and gas potential of separate structural-tectonic zones were predicted, and a series of recommendations were issued.

A comprehensive study on optimizing reservoir potential: Advanced geophysical log analysis of zamzama gas field, southern indus basin, Pakistan

This study investigates the hydrocarbon and gas potential of the Pab Formation's Late Cretaceous reservoir in the Zamzama Gas Field (ZGF) situated in Pakistan's Southern Indus Basin (SIB). Vital insights to support Pakistan's escalating energy requirements. Petrophysical characteristics of the Pab Formation (PFm) zones of interest in the ZGF were determined by evaluating geophysical logs from four wells. Various techniques were employed to analyze the reservoir rock type (RRT), lithofacies, and spatial distribution of petrophysical parameters. The petrophysical assessment reveals that gas-bearing zones primarily consist of sandstone with intermittent shale layers. These reservoirs exhibit distinguishing attributes, including clean sand composition, high resistivity, total porosity (∅T), good permeability (K), minimal shale content (Vsh), and low water saturation (Sw). The total porosity ranges from 12% to 16%, permeability from 14 mD to 19 mD, water saturation levels between 34% and 44%, and hydrocarbon saturation (Sh) from 56% to 66%. The findings suggest significant gas reserves within the studied sand units of the Zamzama Block. Overall, this research provides a detailed and comprehensive understanding of reservoir characteristics, thereby increasing the potential for further hydrocarbon exploration and production in the study area.

Experimental investigation on fracture growth for integrated hydraulic fracturing in multiple gas bearing formations

The key to extracting multiple natural gases from coalbed methane, shale and other tight gases through integrated hydraulic fracturing in coal measure strata (CMS) is determining whether hydraulic fracture can connect different gas-bearing zones. In this paper, several groups of combination samples comprised of artificial rocks were prepared. True triaxial hydraulic fracturing experiments were conducted to stimulate the hydraulic fracture propagation and penetration behavior. The effects of in-situ stress, injection rate, natural fracture and well type on fracture growth were studied. The main results were as follows: (1) Fracture geometries in CMS exhibited strong asymmetric, nonplanar extension and unilateral expansion features in the vertical plane. (2) Higher values of the vertical stress difference coefficient and injection rate led to larger vertical fracture extension and an increased likelihood of fracture connection to adjacent gas-bearing layers. (3) The behavior of the hydraulic fracture varied significantly between vertical and horizontal wells. In vertical wells, the main fracture presented a "+” shape and fully communicated natural coal cleats system, while in horizontal wells, fracture height growth was limited, resulting in fracture patterns that presented vertically as “H” or “T” shape due to the hydraulic fracture's tendency to turn direction when propagating to natural weak planes. The study found that the fracture vertical extension ability increased with rising vertical stress difference coefficient. (4) Natural fractures could induce fracture turning and branching, which improved fracture network complexity but also caused fracturing fluid loss and hydraulic energy dissipation. Therefore, choosing shale or coal layer with developed natural fractures as fracturing layer was unhelpful for integrated fracturing operation. Finally, higher fracturing fluid viscosity, injection rate and gradient sanding could enhance fracturing operation efficiency. These results could provide theoretical guidance for integrated fracturing operation in CMS.

Contribution of Fluid Substitution and Cheetah Optimizer Algorithm in Predicting Rock-Physics Parameters of Gas-Bearing Reservoirs in the Eastern Mediterranean Sea, Egypt

AbstractIn this study, the elastic characteristics of reservoir rocks and their relationship to porosity and pore fluid were predicted using the fluid substitution method in combination with machine learning techniques. We first discarded the data at gas points to remove the erroneous effect of gas on the prediction process of Poisson’s ratio using the three proposed machine learning models. Then, the prediction was carried out after substituting the gas zones by oil and by water. As a result, the prediction was enhanced and showed stronger correlation coefficient values. The integration of fluid substitution and machine learning methods was applied in the reservoir of Scarab field as a case study from the Eastern Mediterranean to detect the effect of different pore fluids (gas, oil, and water) on Poisson's ratio estimation. The main objective of the study was to analyze the seismic and well log data to estimate and predict the Poisson’s ratio in four fluid-content cases; these are gas-bearing reservoir, reservoir after removal of log data of gas-bearing zones, and reservoirs after gas-substitution with oil and with water. These four cases were dealt with directly and by using the machine learning algorithms based on the proposed model of random vector functional link (RVFL), which was enhanced by the Cheetah optimizer (CO). This study shows how the performance of RVFL is affected by the presence or absence of gas zones. It is shown that the Poisson’s ratio value increases when gas is substituted with water more than when gas is substituted with oil. For validation of these results, regression analysis technique was used and the correlation coefficient of the CO–RVFL model increased after removing well log data of gas zones and was more enhanced after fluid substitution from gas to oil or to water.

Prospect Evaluation of the Cretaceous Yageliemu Clastic Reservoir Based on Geophysical Log Data: A Case Study from the Yakela Gas Condensate Field, Tarim Basin, China

This paper evaluated the oil and gas potential of the Cretaceous Yageliemu clastic reservoir within the Yakela condensed gas field lying in the Kuqa Depression, Tarim Basin, China. The petrophysical properties of the interest zones in the Kuqa area were characterized using geophysical logs from five wells. The results reveal that the gas-bearing zones are characterized by high resistivity, good permeability (K) and effective porosity (Φeff), low water saturation (Sw), and low shale concentration (Vsh), reflecting clean sand. The shale distribution model showed that these shales have no major influence on porosity and fluid saturation. The average shale volume, average effective porosity, and hydrocarbon saturation indicate that the Cretaceous Yageliemu Formation in the studied area contains prospective reservoir properties. The spatial distribution of petrophysical parameters, reservoir rock typing (RRT), and lithofacies were analyzed using the cross plots of litho saturation (volumetric analysis), iso-parametric representations of the petrophysical characteristics, cluster analysis, and self-organizing feature maps, respectively. The southeastern and northeastern regions of the research area should be ignored because of their high water and shale concentrations. The sediments in the southwest and northwest include the most potential reservoir intervals that should be considered for the future exploration and development of oil and gas fields in the study area.

Geological characteristics and exploration potential of the coal measure gas from Shan 2 of the Shanxi formation in the eastern Ordos Basin

“Coal measure gas,” excluding tight (low-permeability) sandstone gas, refers in this study to the self-sourcing unconventional natural gas stored in coal, shale, and fine siltstone. It is characterized by various types of occurrences and reservoirs, a distinct cyclic succession of coal measure strata, widely distributed mosaic hydrocarbon accumulations, three types of coal measure gas accumulations, and configurations of vertically multiple-stacked gas-bearing reservoirs. Coal measure gas from Shan 2 can be divided—according to the grain size of sandstone, configurations of sandstone–coal–mudstone association, thickness, and layers—into four types: thick massive sandstone–coal–mudstone (type I), fine siltstone–coal–mudstone (type II), thin sandstone–mudstone–sandstone (type III), and coal–mudstone (type IV). Comprehensive evaluation suggests that the coal measure gas in the Suide-Mizhi area of the southern Ordos Basin presents an important and favorable accumulation option, characterized by coalbed methane, shale gas, and tight gas stored in sandstone–mudstone–coal strata. Therefore, it is essential to conduct full future assessments for the coal beds, shale, and tight gas controlling exploration for the “vertical gas-bearing zone” by three-dimensional exploration.

E&P Notes (December 2022)

E&P Notes (December 2022)

Petrophysical analysis and hydrocarbon potential of the lower Cretaceous Yageliemu Formation in Yakela gas condensate field, Kuqa Depression of Tarim Basin, China

The present study based on petrophysical computations assess the conventional fuel resources of the Yageliemu Formation. The Yageliemu Formation was evaluated using log data from four wells (YK19, YK20, YK21, and YK32) and observed over the entire reservoir interval. Yageliemu Formation originates from the Lower Cretaceous reservoir, which is located in the Yakela gas condensate field, Kuqa Depression of Tarim Basin China. The studied gas bearing zones are primarily composed of sandstone, with small amounts of shale and clay contents. The petrophysical properties of the gas-bearing zones were carefully examined, which are rated to be better quality sand layers with average effective porosities varying from 7 to 10%, permeability varying from 3 to 8.6 mD, average water saturation values ranging from 43 to 59%, and the average range of gas saturation is 40–57%. The Yageliemu Formation cutoff outcomes for shale volume (Vsh), effective porosity, water saturation, and permeability were characterized at 40% and 5%, 65%, and 0.1 mD, respectively. Thomas Stieber model was used to successfully identify shale structural behavior in reservoirs and it revealed that the dominant shale is mainly laminated with a minor volume of structural and dispersive shale. Lithofacies and axial variations of reservoir properties are assessed by constructing self-organizing maps, isoparametric maps of the petrophysical properties, and litho-saturation cross-plots, respectively. The reservoir characteristics of the Yageliemu Formation demonstrate that the prospective region for hydrocarbons accumulation trends is in the southwestern and northwestern parts of the research area. The study techniques can be used in the Tarim Basin and similar basins around the world to estimate the petrophysical properties of oil and gas wells and comprehend reservoir prospects.

Fluid identification based on geophysical well logs in ultralow-porosity tight sandstone reservoirs

Deep tight sandstone reservoirs typically exhibit ultralow porosity and permeability owing to their small pore size, narrow pore throats, and poor pore connectivity. In heterogeneous tight formations, well-log interpretation is uncertain, and it is difficult to identify fluid types using the classic picket-plot (resistivity versus porosity crossplot) method. To better identify and characterize gas-bearing zones in heterogeneous tight sandstone reservoirs, effective sensitivity factors for fluids need to be constructed. From the conventional logging principle, the acoustic neutron porosity difference, density-neutron porosity difference, and triple-porosity ratio are all sensitive parameters for gas-bearing layers. In addition, the density and nuclear magnetic resonance (NMR) porosity difference and [Formula: see text] geometric mean of the movable fluid are sensitive to gas saturation. Based on these parameters, a series of fluid typing crossplots was constructed, and their effectiveness was compared. In contrast, the interpretation results from NMR logging are better, and the dual-porosity difference and triple-porosity ratio methods from conventional logs also are effective when NMR logging is not available. In practice, these methods are used to provide their results, and then they are combined using a voting strategy according to the performance of each crossplot. In two case studies of the Kuqa Depression of the Tarim Foreland Basin, China, the new fluid typing method proved effective, and it provides an alternative method for fluid identification using nonelectrical logs (when electrical logs are not available or applicable).

Seismic frequency controls to characterize the lower-cretaceous incised-valley system, Indus Basin, SW Pakistan: Spectral decomposition as a direct hydrocarbon indicator

Seismic properties can assume a vigorous part in the portrayal of the incised-valley reservoirs the world over. But, accurately optimizing the attributes within the stratigraphically heterogeneous fluvial system is significant, and thus, delineating the porous sandstone is the challenge for prospect delineation. During the forecast of stratigraphic traps, the resolve is to select the frequency band, which can accurately image the thickest part of the reservoirs. The continuous wavelet transforms (CWT) of spectral decomposition (SD) tool is applied for enlightening the incised valley from Miano gas field, SW Pakistan. The seismic and root-mean-square (RMS) amplitudes deliver insufficient reservoir qualities. The CWT technique detects the low-frequency shadow zone at 37 Hz, which indicates the presence of a gas-bearing zone along the fault. The instantaneous frequency model detects a ∼ 35 m thick sandstone lens encased within the erosional sediments, which was corroborated by a 37 Hz tuning cube. The acoustic impedance-based instantaneous spectral thickness model brightens the high-porosity zones within the thick valley-plugged reservoirs of 40 m and 30 m at 37 Hz and 48 Hz.

Lithofacies types, reservoir characteristics and silica origin of marine shales: A case study of the Wufeng formation–Longmaxi Formation in the Luzhou area, southern Sichuan Basin

Shale, which is a fine-grained sedimentary rock, differs in reservoir quality (RQ) and completion quality (CQ) as the result of variations in its mineral and organic-matter compositions. The RQ and CQ directly affect shale gas exploitation. Therefore, classification of the lithofacies types of shale, analysis of the reservoir differences of different lithofacies, and identification of the superior shale lithofacies with the best RQ and CQ are important for decisions on well placement, targeting the “sweet spot” zone and optimizing the expected ultimate recovery of a shale gas well. In this study, several methods including microscopic observation of thin sections, X-ray diffraction analysis, core analysis and elemental geochemistry were used to investigate the lithofacies types, reservoir characteristics and silica origin of the marine shales of the Wufeng Formation–Longmaxi Formation (WF Fm.–LMX Fm.) in the Luzhou area, southern Sichuan Basin, China. The lithofacies characteristics exhibit marked differences through the WF–LMX shale succession. Specifically, the lower gas-bearing zone (LMX-1) is mainly composed of siliceous shales and siliceous–argillaceous mixed shales, whereas the upper gas-bearing zone (LMX-4) mostly contains argillaceous shales and argillaceous–siliceous mixed shales. The lower shale gas reservoirs have a higher silica content and lower clay and carbonate contents than the upper zones, and thus superior petrophysical qualities. The upper part of the WF Fm. (WF-2) and the lower part of the LMX Fm (LMX-1, LMX-2) are rich in bio-chemical authigenic silica, whereas the silica minerals of other intervals are mainly derived from allochthonous terrigenous material. The siliceous shales and siliceous–argillaceous mixed shales with a biogenic quartz content greater than 40% have the best RQ and CQ and are the most promising lithofacies for shale gas in the Luzhou area. Although the upper gas-bearing zones represented by LMX-4 are also good shale gas reservoirs, the RQ, CQ and gas content are generally worse than those of the lower gas-bearing zones because of the silica origin and lithofacies types; thus, extracting shale gas from the upper zones would be a greater challenge.

Impact of Reservoir Heterogeneity on the Control of Water Encroachment into Gas-Condensate Reservoirs during CO2 Injection

Abstract The paper evaluates application of CO2 injection for the control of water encroachment from the aquifer into gascondensate reservoir under active natural water drive. The results of numerical simulations indicated that injection of CO2 at the initial gas-water contact (GWC) level reduces the influx of water into gas-bearing zone and stabilizes the operation of production wells for a longer period. The optimum number of injection wells that leads to the maximum estimated ultimate recovery (EUR) factor was derived based on statistical analysis of the results. The maximum number of injection wells at the moment of CO2 break-through into production wells for homogeneous reservoir is equal to 6.41 (6) and for heterogeneous – 7.74 (8) wells. Study results indicated that with the increase of reservoir heterogeneity, denser injection well pattern is needed for the efficient blockage of aquifer water influx in comparison to homogeneous one with the same conditions. Gas EUR factor for the maximum number of injection wells in homogenous model is equal 64.05% and in heterogeneous – 55.56%. Base depletion case the EURs are 51.72% and 49.44%, respectively. The study results showed the technological efficiency of CO2 injection into the producing reservoir at initial GWC for the reduction of water influx and improvement of ultimate hydrocarbon recovery.

Analysis and Estimation of an Inclusion-Based Effective Fluid Modulus for Tight Gas-Bearing Sandstone Reservoirs

Due to the special petrophysical properties of tight reservoirs, such as poor connectivity and low porosity, conventional rock physics models show limitations. Based on an inclusion-based method, a new formula containing fluid pressure is derived without an equilibration assumption of fluid pressures in the inclusions. Then, the formula is simplified with an equivalent pore structure to yield a new fluid identification parameter, the inclusion-based effective fluid modulus (IEFM). By analysis, this fluid identification factor is quite sensitive to water saturation for different pore connectivity. A well-logging data test shows the superiority of the proposed model in identifying tight gas-bearing zones. Seismic data application also demonstrates the validity of the proposed model and the predicted results match well with the well-logging data. In fluid identification, two probabilistic estimation methods are used: Bayes posterior prediction framework is a combination of Bayes’ theory and a deterministic rock physics model; Bayes discriminant method is a statistical rock physics method. The proposed IEFM is a novel identification parameter for tight gas-bearing reservoirs, which can have many applications in the exploration of tight reservoirs.

New prospective gas plays in pliocene sands, offshore Nile Delta Basin: A case study from Kamose-1 well at North Sinai Concession, Egypt

The Pliocene sands in the offshore parts of the Nile Delta Basin represent significant gas reservoirs. Several targets have been recently discovered in different places along the offshore Nile Delta Basin. The present work focuses on the possibility of discovering new natural gas resources at North Sinai Concession through an integrated method between seismic and well logs data interpretations. A case study from Kamose-1 Well at Kamose Field, North Sinai Concession has been examined. The quantitative explanation for the well log data of Kamose-1 Well has revealed two zones expected to be gas-bearing zones. These intervals are located between depths; 1174–1186 m (zone I) and between 1429 and 1503 m (zone II). The calculated petrophysical parameters for these zones exhibit low water saturation (24–43%), high effective porosity (30–31%), low shale volume (21–26%), high total porosity (37–38%) and low bulk volume of water (0.07–0.12). Zone II (74 m thick) shows a clear bright spot on the seismic profiles covering the study area, while, zone I is beyond seismic resolution (12 m thick). Several seismic bright spots have been outlined on the seismic data nearby Kamose-1 Well. The comparison between the newly outlined seismic bright spots with the drilled one in Kamose-1 Well exhibited a great similarity. Accordingly, these prospects are expected to be new targets for gas exploration in the Pliocene succession at North Sinai Concession.

Application of maximum likelihood and model-based seismic inversion techniques: a case study from K-G basin, India

AbstractSeismic inversion is a geophysical technique used to estimate subsurface rock properties from seismic reflection data. Seismic data has band-limited nature and contains generally 10–80 Hz frequency hence seismic inversion combines well log information along with seismic data to extract high-resolution subsurface acoustic impedance which contains low as well as high frequencies. This rock property is used to extract qualitative as well as quantitative information of subsurface that can be analyzed to enhance geological as well as geophysical interpretation. The interpretations of extracted properties are more meaningful and provide more detailed information of the subsurface as compared to the traditional seismic data interpretation. The present study focused on the analysis of well log data as well as seismic data of the KG basin to find the prospective zone. Petrophysical parameters such as effective porosity, water saturation, hydrocarbon saturation, and several other parameters were calculated using the available well log data. Low Gamma-ray value, high resistivity, and cross-over between neutron and density logs indicated the presence of gas-bearing zones in the KG basin. Three main hydrocarbon-bearing zones are identified with an average Gamma-ray value of 50 API units at the depth range of (1918–1960 m), 58 API units (2116–2136 m), and 66 API units (2221–2245 m). The average resistivity is found to be 17 Ohm-m, 10 Ohm-m, and 12 Ohm-m and average porosity is 15%, 15%, and 14% of zone 1, zone 2, and zone 3 respectively. The analysis of petrophysical parameters and different cross-plots showed that the reservoir rock is of sandstone with shale as a seal rock. On the other hand, two types of seismic inversion namely Maximum Likelihood and Model-based seismic inversion are used to estimate subsurface acoustic impedance. The inverted section is interpreted as two anomalous zones with very low impedance ranging from 1800 m/s*g/cc to 6000 m/s*g/cc which is quite low and indicates the presence of loose formation.

Gas-generative potential for the post-Messinian megasequence of Nile Delta Basin: a case study of Tao Field, North Sinai Concession, Egypt

The main aim of the article is to evaluate the gas potentiality for the post-Messinian megasequence in TAO Field, North Sinai Concession, offshore Nile Delta Basin. The detailed petrophysical analysis for three deviated wells in the study area (Tao-3 ST1 Well, Tao-5 STA Well and Tao-7 Well) revealed that the Pliocene Kafr El-Sheikh Formation includes eleven gas-bearing zones. These zones were named: A, B, C in Tao-3 ST1 Well and D, E, F in Tao-5 STA Well. In Tao-7 Well, the interesting zones are named G, H, I, J and K. All of these sandy intervals are relatively shallow in depth and differ in thickness between 4 and 56 m. These zones are characterized by shale volume (10%), total porosity (30–40%), effective porosity (30–35%), gas saturation (50–90%), high effective permeability to gas and low permeability to water. The seismic data displayed that listric faults and the associated rollover folds have an important role in forming structural traps for the examined gas-bearing zones in Tao Field and its surroundings. This work revealed that the success rate in discovering new gas prospects within the Pliocene–Pleistocene succession at North Sinai Concession is very high.

Lithology Identification, Shale Volume Estimation and Formation Wate Saturation of Fenchuganj Gas Field Using Wireline Log Data

This study has been undertaken with a view to interpreting and analyzing different types of logs, detecting hydrocarbon-bearing sand zone, identifying the lithology, estimating shale volume, and determining water saturation of the formation of the Fenchuganj gas field. Fenchuganj gas field is in the southern part of Bangladesh in the Sylhet division. It lies in the Surma basin and characterized as a water drive gas field. Gamma Ray (GR) log and Spontaneous Potential (SP) log analysis help to interpret the formation lithology. After interpreting lithology, the gamma-ray log and SP log were analyzed further, and the hydrocarbon-bearing zone was detected. From the analysis of different logs, for well 4, so many gas-bearing sand zones have been detected. The gas-bearing zones are found between (1585-1595) m, (1600-1610) m, (2409-2420) m, (2265-2270) m, (2295-2303) m, (2435-2450) m, (2465-2480) m, (3150-3155) m, (2955- 2960) m. These are the gas-bearing zones of fenchugonj well-4 determined from the composite log of this field. Water-bearing sand zones are between (1708-1714) m and the fully compacted shale zone is between (1920-1930) m. From the analysis of different logs, for well 5, so many gas-bearing sand zones have been detected. The gas-bearing zones are found between (2365-2385.5) m, (1820-1830) m, (1782-1803) m, (305-308) m, (336.5-338.5) m, (607.5-609.5) m. These are the gas-bearing zone of fenchugonj well-5 determined from the composite log of the field. Shale volume has been estimated from the gamma-ray log and from resistivity logs by the true resistivity method. In well 4, the calculated value of shale volume by Gamma Ray method and true Resistivity methods were respectively 15% and 6%, in well 5 these values were 7.25% and 7.64%. Formation water resistivity was determined from the formula and taken as 0. 1ohm-m and mud filtrate resistivity 0.76 ohm-m. for well-4 and for well-5 it was taken as 0.7 ohm-m (from the provided composite log of well 4 and 5). Formation true resistivity Rt was estimated directly from the ILD log and true resistivity log. The average value of Rt for well-5 was 33.75 ohm-m and for well-4 the value is 34.09 ohm-m. From the RFOC log, flushed zone resistivity Rxo was calculated directly. Water saturation has been determined by three different techniques named Archie, Indonesia, and Simandoux method. For well 5, the value of average water saturation found from Archie, Indonesia, and Simandoux model was 8.5%,22%, and 24.84%, and for well-4. The value of average water saturation was found as 7.3%,18%, 20.51%respectively.

Predicting the gas resource potential in reservoir C-sand interval of Lower Goru Formation, Middle Indus Basin, Pakistan

Abstract The integrated study of seismic attributes and inversion analysis can provide a better understanding for predicting the hydrocarbon-bearing zones even in extreme heterogeneous reservoirs. This study aims to delineate and characterize the gas saturated zone within the reservoir (Cretaceous C-sand) interval of Sawan gas field, Middle Indus Basin, Pakistan. The hydrocarbon bearing zone is well identified through the seismic attribute analysis along a sand channel. The sparse-spike inversion analysis has efficiently captured the variations in reservoir parameter (P-impedance) for gas prospect. Inversion results indicated that the relatively lower P-impedance values are encountered along the predicted sand channel. To further characterize the reservoir, geostatistical techniques comprising multiattribute regression and probabilistic neural network (PNN) analysis are applied to predict the effective porosity of reservoir. Comparatively, the PNN analysis predicted the targeted property more efficiently and applied its estimations on entire seismic volume. Furthermore, the geostatistical estimations of PNN analysis significantly predicted the gas-bearing zones and confirmed the sand channel as a major contributor of gas accumulation in the area. These estimates are in appropriate agreement with each other, and the workflow adopted here can be applied to various South Asian regions and in other parts of the world for improved characterization of gas reservoirs.

To the issue of oil and gas potential in the decompression zones of the Dnieper-Donets depression

Formulation of the problem. Currently, interest in the foundation as a gas and oil field facility has increased significantly. The low efficiency of oil and gas exploration in the basement rocks is usually explained by the absence of a generally accepted hypothesis about the genesis of oil and gas and as a result of migration and accumulation of hydrocarbons. One of the main factors of accumulation is the presence of decompression zones of the foundation, as potential hydrocarbon traps. The article is devoted to the problem of identifying oil and gas bearing zones of foundation decompression. Analysis of recent research and publications. A number of scientific articles on the composition, age, structure and oil and gas potential of the foundation are analyzed. The first step in identifying decompression zones is to conduct gravimetric and magnetic surveys and apply various techniques to interpret the resulting mathematical model of the wave field pattern in order to localize the sources of its anomalies. Identification of previously unresolved parts of a common problem. In order to save money when conducting prospecting and exploration for oil and gas, the foundation proposes an improvement in the methodology for separating gas-bearing “vaulted” parts of decompression zones. Formation of the purpose of the article. The aim of the work is to establish a seismic pattern of anomalies in the geophysical fields of the base decompression zones. The object of research is the zone of decompression of the foundation on the northern side of the Dnieper-Donets depression. The subject of the study is a seismic drawing of the anomaly of the geophysical field of the gas-bearing zone of decompression of the foundation of the Rozsoshinsk structure. Report of the main material. The article analyzes a few materials to identify areas of base decompaction in various oil and gas regions. It was found that for localization of decompression zones, the Berezkin “singular points” method and the correlation method of separation of geophysical anomalies are most effective. The essence of these methods is a kind of filtering of field anomalies, where against the background of the "structural" factor, one can distinguish the "non-structural factor", i.e. decompression zone. This zone in wave fields (∆g and ∆Т) is fixed by a seismic pattern, where minima are usually fixed over hydrocarbon accumulations in relation to contouring maxima. Based on the results of the application of these methods, the structure-testing ground of the gas-bearing decompression zone is established. As an illustrative example of the successful localization of ∆g and ∆Т, data are presented on modeling the foundation softening zone in one of the oil and gas regions of the northern side of the Dnieper-Donets depression.