Exploration Wells Research Articles

Lithological and geochemical characteristics and sedimentary environments of the Cambrian high-carbon deposits in the east of the Siberian platform (Kyulenke river basin)

Relevance. The need to study high-carbon deposits as potential sources of hydrocarbons and ore minerals that can significantly increase the mineral resource of Russia. In addition, the analysis of lithological and geochemical features and the reconstruction of the sedimentation conditions of the Kuonamka Formation make it possible to more accurately judge the nature of the Lower and Middle Cambrian paleobasin in the east of the Siberian Platform. Aim. To identify lithological and geochemical features of the composition and determine the sedimentation environment of the Kuonamka Formation. Object. High-carbon deposits of the Kuonamka Formation uncovered by exploration wells on the eastern margin of the Mun arch of the Siberian platform in the Kulenke river basin. Methods. Lithological description of core material; mineralogical and petrographic analysis; X-ray diffraction, X-ray fluorescence and microelement analysis; determination of the content of sulfur and iron forms by wet chemistry; scanning electron microscopy using X-ray spectral microprobe; analysis of petrochemical modules. Results. It was established that the Kuonamka Formation in the studied sections has a consistent structure of four well-defined lithological-stratigraphic horizons. The composition of the deposits is predominantly mixed and is determined by variations in three main mineral groups: clay, carbonate and siliceous, in addition organic matter. The paper demonstrates different forms of organic matter confirming the mixed algal-bacterial genesis of the biocenosis of the Kuonamka basin. The revealed lithological features and lithochemical data indicate the accumulation of high-carbon deposits at a considerable distance from the drift sources in the depression zone of the open sea basin with weak circulation of bottom waters in anoxic conditions. The geochemical euxinic environment was dominant in carbonate-siliceous muds. Sedimentation occurred during one major transgressive-regressive sedimentation cycle being a typical sequence of filling a uncompensated deep depression.

Hydrocarbon micro‐migration and differential enrichment mechanism of shale oil in upper Cretaceous Qingshankou Formation in Songliao Basin

Shale reservoir has strong heterogeneity in mineral composition and oil content even at a short distance in the same interval. To better understand the accumulation mechanism of shale oil and hydrocarbon migration tendency in the interval, and explore the main influencing factors of distribution. This paper employed various methods, including thin‐section observation, TOC (total organic matter (OM)) analysis, rock pyrolysis, Soxhlet extraction, group component separation, and GC–MS (gas chromatography mass spectrometry) analysis of saturated hydrocarbons. The shale oil samples were collected from an exploratory well in the Songliao Basin, and the distribution and enrichment characteristics of shale oil interlayers were analysed. The results show that the first member of Qingshankou Formation (K2qn1) could be divided into six small layers. From Q1 to Q6, the lithofacies could be divided into three types: high‐frequency laminar shale, massive shale, and bioclastic shale. The lacustrine matrix shale of K2qn1 in Songliao Basin has medium TOC, and high oil contents, OM conversion rate. The TOC ranges from 1.5 to 4.2 wt%, S1 varies between 1.4 and 4 mg/g, S2 falls within the range of 4 to 10.6 mg/g, Tmax ranges from 351 to 497°C, and the OSI varies between 57 and 115.34 mg HC/g rock. The lower part of the K2qn1, Q1–Q4, characterized by high‐frequency laminar shale, contained residual shale oil, while the upper part of the K2qn1, Q5 and Q6, characterized by bioclastic shale and massive mudstone, and are dominated by in‐situ type shale oil. The crude oil in K2qn1 is homologous, and primarily undergoes micro‐migration. The Q5–Q6 section has the highest light oil content, while other regions with notable light components are located in the middle of Q1, the upper sections of Q2, Q3, and Q4.Q1–Q4 are primarily composed of residual shale oil, whereas Q5–Q6 is primarily composed of in‐situ shale oil, and the primary micro‐migration direction of shale oil occurs laterally within Q1–Q4. The lateral migration of each section mainly occurs at the upper part of Q3 and Q4, the lower part of Q1 and Q2, the bottom of Q5, and the interface between Q6 and the second member of Qingshankou formation (K2qn2). The block mudstone retains in‐situ shale oil, especially light hydrocarbons. Within the high‐frequency laminar shale, there is strong horizontal connectivity, and lateral hydrocarbon expulsion serves as the primary mechanism for micro‐migration in Q1–Q4. This paper can provide reference values for K2qn1 Formation shale oil and the migration and differential reservoir formation of medium and high‐maturity matrix shale oil.

An Evaluation of the Coalbed Methane Mining Potential of Shoushan I Mine Based on the Subject–Object Combination Weighting Method

The parameters of coalbed methane reservoirs have large differences, and the precise values cannot represent the resource and production characteristics of the whole block. In order to address these problems, an index system for evaluating the production potential of coalbed methane blocks was constructed, the weights of evaluation parameters were determined, and a model for the preferential selection of coalbed methane blocks based on the subjective–objective combination of weights method was established. The main coal seams (No. 2-1 and No. 4-2) of the Pingdingshan-Shoushan I Mine Block were taken as the research objects to rank the development potential of CBM blocks in a preferential way. The results show that the six resource and production parameters of No. 2-1 coal are gas content, top and bottom rock properties, coal seam thickness, coal seam depth, coal body structure, and tectonic conditions, in descending order of importance, and the parameters of No. 4-2 coal are gas content, coal body structure, coal seam thickness, top and bottom rock properties, coal seam depth, and tectonic conditions, in descending order of importance. It is predicted that the favorable CBM gas development sweet spot areas of the No. 2-1 coal seam and No. 4-2 coal seam will be located along the exploration wells W15–W29 and W31, respectively. This paper aims to make a multi-dimensional and more comprehensive evaluation of coalbed methane mining potential in the Shoushan I mine, and provide a technical basis for the next step of coalbed methane mining in the study area.

Architecture and exploration target areas of the Senegal Basin, West Africa

The recent discovery of large oil and gas fields in the deep-water of the Senegal Basin has drawn global attention. Despite this, several exploration wells in this area fail, which can be primarily contributed to a lack of understanding of the basin's structures and hydrocarbon accumulation conditions. This study examines these characteristics utilizing gravity, seismic and drilling data, and finally makes a comparison with the Cote d’Ivoire Basin, a typical transform margin basin in the South Atlantic. The results suggest that the Senegal Basin, influenced by multiple transform faults and a weak Paleozoic basement, experienced three evolutionary stages: rifting, transitional, and drifting. Each stage contributed to the development of distinct depositional sequences - syn-rift sequences, sag sequences, and continental margin sequences, respectively. The Triassic - Early Jurassic rifting stage predominantly formed continental deposits, like fluvial, lacustrine, and deltaic deposits, in the syn-rift sequences. The Middle-Late Jurassic transitional stage, influenced by transform faults, witnessed the formation of marginal ridges or submarine uplift zones. These zones, in conjunction with landward high terrains, formed a restricted environment promoting the development of source rocks in the sag sequences. During the drifting stage, three types of reservoirs, namely platform carbonate rocks, deltas, and slope-floor fans were formed. Notably, large-scale hydrocarbon reservoirs have been found in the deltas and the slope-floor fans both in the Senegal Basin and the Cote d’Ivoire Basin. The Upper Jurassic - Aptian platforms exhibit thick carbonate rocks and organic reefs on their edges, suggesting substantial potential for hydrocarbon exploration in the Senegal Basin.

Temporal variability of water chemistry in the Cherkashinskaya well No. 36-RG (Tobolsk district, Tyumen region)

This article focuses on a temporary change in the chemical composition of water in the Cherkashinskaya well No. 36-RG, which is located in the Tobolsk district near the village of Shestakovo. The impact of underground mineral waters on catchments and watercourses can be caused by the open gushing of orphaned geological exploration wells. This can lead to the disturbance of the hydrochemical regime of neighbouring water systems. Publications on this topic are available not only in Tyumen region, but also throughout the Russian Federation. For example, scientific articles and conference proceedings, such as "Groundwater of the East of Russia" (2018), "Issues of studying surface and groundwater of Siberia" (2021), and the International Conference "Underground Waters 2023", are available. The study highlights the behavior of various components of water composition. The article presents changes in the mineralization of groundwater and identifies the main sources of negative impact on its quality. In 2019, the chemical composition of the water in the containing well underwent a transformation. This article focuses on the changes in the chemical composition of water from the Cherkashinskaya well No. 36-RG and its impact on the surrounding areas.

The Classification and Evaluation of an Interlayer Shale Oil Reservoir Based on the Fractal Characteristics of Pore Systems: A Case Study in the HSN Area, China

The evaluation of shale reservoir quality is of great significance for the exploration and development of shale oil. To more effectively study the distribution characteristics of shale reservoir quality, thin-section observation, scanning electron microscopy and pressure-controlled porosimetry were used to obtain the pore structure characteristics of shale in Chang 7, including pore types, pore size distribution, etc. In addition, the fractal dimensions of the shale samples were calculated based on pressure-controlled porosimetry data. The results show that residual interparticle pores, dissolution pores and clay-dominated pores were the main pore types. The overall pore size was mainly distributed between 3 nm and 50 μm. The pore system was divided into four types using fractal features, and the shale reservoir was divided into four types based on the proportion of different types of pore system. In different types of reservoirs, the production capacity of exploration wells varies significantly, as does the production capacity of horizontal wells. The classification of shale reservoirs using mercury intrusion fractal analysis proved to be suited for the efficient development of Chang 7 shale oil reservoirs.

Olenek–Anabar Composite Tectono-Sedimentary Element, northern East Siberia

Abstract The Olenek–Anabar Composite Tectono-Sedimentary Element (OLA CTSE) is located in the northern part of the Siberian Craton. Its structure and depositional history is controlled by two main tectonic events: (i) Mesoproterozoic rifting and (ii) Ediacaran–Cambrian (to Middle Devonian?) post-rift thermal subsidence. The sedimentary succession is mainly represented by Mesoproterozoic–Cambrian strata, including the black shales of the lower–middle Kuonamka Formation. The hydrocarbon potential of the OLA CTSE is defined by the presence of large superficial bitumen fields, anticlinal structures, large reefal build-ups and direct proximity to the potential source rock (Kuonamka Formation). A very scarce grid of seismic profiles and a lack of exploration wells limit the knowledge of the petroleum potential. The lack of seals and broad occurrences of faults, causing significant vertical permeability of sediment cover, and abundant occurrences of mafic and kimberlite magmatism are limiting factors with regard to the petroleum potential. Wells drilled during the Soviet era did not recover any commercial discoveries.

ABOUT THE MAIN RESULTS OF DEEP DRILLING IN THE TERRITORY OF THE PREDVERKHOYANSKAYA OIL AND GAS AREA

This article presents the results of drilling wells in the Predverkhoyanskaya oil and gas area, where deep exploratory drilling for oil and gas was started in 1954 at the Kitchan, Sangar and Ust-Vilyu structures pre-pared by the seismic survey in combination with structural core drilling.According to the results of deep drilling in the Predverkhoyanskaya oil and gas area, the section of the sedimentary cover was studied, and ideas about the material composition of the foundation upper part were obtained. The pro-spects of oil and gas potential are evaluated: the reservoir properties are possessed by rocks of the subsalt Nizhnevendsky, Vendian-Lower Cambrian terrigenous and carbonate complex-es, which are associated with industrial oil and gas potential in nearby fields.The following fluid-bearing complexes are distinguished in the sedimentary section of the Preverkhoyanskiy trough: Permian (P), Lower Triassic (T1), Triassic-Lower Jurassic (T2–3–J1), Middle Upper Jurassic (J2-3), Lower Cretaceous (K1).Deposits of the Lower Triassic aquifer complex are deposited on Permian formations. The capacity of the complex is variable, due to the structural features of the Lower Triassicsediments, and it has not been established with-in the Predverkhoyanskiy trough. Thermobaric data were not obtained during the test. Reser-voir pressures are close to hydrostatic. Reser-voir temperatures, as in the Permian complex, increase from west to south-east to the Predverkhoyanskiy trough from 50 °C to 95 °C.The deposits of the Middle-Upper Triassic – Lower Jurassic aquifer complex are more widely developed. During the sampling and test-ing of oil and gas exploration wells, water and gas inflows were obtained from the deposits of the complex, including industrial ones on Ust-Vilyuiskaya, Sobo-Khainskaya Square. The flow rates of water inflows reached 300 m3/day (Sangarskaya 2), gas inflows up to 1800000 m3/day (Ust-Vilyuiskaya area). In the Sobo-Khainskaya 1 well, an industrial gas in-flow was obtained from the interval of 1328–1349 m.The prospects for oil and gas exploration at the Preverkhoyanskaya oil and gas area are associated with its northern part (Setas struc-ture), on which the Setas parametric well No. 1 with a design depth of 4000 m is being laid, and its southern part, where it is advisable to drill 2 parametric wells with a planned depth of 3000 m.

East Barents Basin and Admiralty High Composite Tectono-Sedimentary Elements, Barents Sea

Abstract The East Barents Sea (E Barents Sea) includes two major tectonic elements, the East Barents Basin (EB Basin) and the Admiralty High, which are, in the context of the volume, characterized as composite tectono-sedimentary elements. Whereas they share some stratigraphy, their early history may differ. The EB Basin is a dominant structural feature of the Barents Shelf, and one of the largest and deepest sedimentary basins in the Arctic. Admiralty High rims the EB Basin in the east. The advance in understanding the E Barents Sea geology was achieved during 1980s and 1990s mainly due to a significant amount of multichannel reflection seismic data and a number of drilled deep exploration wells. These wells tested many large anticlinal structures and made several large gas discoveries including a giant Shtokman gas and gas condensate accumulation. In the following decades, many important geological results were published in the international and Russian literature. In this chapter we provide a summary of the geology and petroleum geology of the E Barents Sea based on published results and public-domain geological reports.

Analysis of Relatively Short Variable Rate “Noisy” Well Test Data Using Non-Linear Deconvolution

Short well test data are pressure-rate-time data that are not long enough to be used to infer the reservoir boundary model and are very common in the oil and gas industry. Short rate well test data may occur when companies try to cut costs of well test jobs or mostly due to improper well test design. Nevertheless, one may wish to extract the most amount of information from this limited data because the de-convolve response can allow the reservoir engineer to make the best use of the available data in selecting a suitable interpretation model by narrowing down the possible boundary models and also providing a reliable estimates of model parameters. The aim of this study is to demonstrate the usefulness and significance of pressure-rate deconvolution in analyzing relatively short variable rate data using a hypothetical case study. The simulation was carried out using Sapphire’s test design module by assuming the presence of an exploratory well in an oil reservoir above bubble point pressure. Further assumption is that the reservoir is homogenous, therefore the possibility of a changing wellbore model was neglected from the analysis. The computer codes for the simulation were inputted using python programming language. We observed from the study that although pressure and flow rate relationship can be nonlinear, the problem can be formulated as a linear problem and the nonlinearity is expressed in the features of the reservoir. The simulation results were satisfactory using the test case and deviations between model parameters and actual reservoir parameters used in simulation was shown to have an absolute value less than 8% which is within acceptable engineering limits.

Electrical facies of the Asmari Formation in the Mansouri oilfield, an application of multi-resolution graph-based and artificial neural network clustering methods

Electrofacies analysis conducted the distribution effects throughout the reservoir despite the difficulty of characterizing stratigraphic relationships. Clustering methods quantitatively define the reservoir zone from non-reservoir considering electrofacies. Asmari Formation is the most significant reservoir of the Mansouri oilfield in SW Iran, generally composed of carbonate and sandstone layers. The stratigraphical study is determined by employing 250 core samples from one exploratory well in the studied field. Five zones with the best reservoir quality in zones 3 and 5 containing sandstone/shale are determined. Moreover, multi-resolution graph-based and artificial neural network clustering involving six logs are employed. Utilizing Geolog software, an optimal model with eight clusters with better rock separation is obtained. Eventually, five electrofacies with different lithological compositions and reservoir conditions are identified and based on lithofacies describing thin sections, sandstone, and shale in zones 3 and 5 show high reservoir quality. According to the depth related to these zones, most of the facies that exist in these depths include sandstone and dolomite facies, and this is affected by the two factors of the primary sedimentary texture and the effect of the diagenesis process on them. Results can compared to the clustering zone determination in other nearby sandstone reservoirs without cores.

Research on slim-hole drilling technology for shale gas geological survey in China

Over the last 10 years, the China Geological Survey has deployed 137 slim-hole shale gas geological exploration wells for coring entire wellbores. These wells are primarily located in new blocks and geological formations where neighboring well data are insufficient, beyond the scope of developed oil fields in China, or outside of oil and gas company mining-right areas. The drilling rig equipment, coring tools, and core drill bits of slim-hole shale gas drilling technology are different from those associated with traditional petroleum drilling. Many studies have been conducted on non-coring slim-hole drilling technology. This paper focuses on coring technology and drilling safety, summarizing a set of high-efficiency shale gas drilling equipment and technology systems based on geological drilling equipment and techniques (that can be used for solid mineral exploration). We report on: 1) an improved vertical shaft drilling rig adapted to shale gas well control safety; 2) high-efficiency core drilling techniques, focusing on coring tools, and techniques incorporating an inverted tower drilling tool combination, air circulation follow-through technology, and expanded casing technology; 3) research progress on high-efficiency core drill bits, including non-planar tooth polycrystalline diamond compact bits and impregnated diamond core bits, along with their application effects. This research provides substantial advances in drill-core technology and improvements in exploration efficiency. Moreover, it provides a reference frame for well structural design and selection of construction technology for shale gas exploration drilling projects.

Assessment of fracturing and blockiness of the Pshenychne gabbro deposit massif

Proper development of the deposit and the choice and use of effective technologies for block stone extraction are impossible without evaluating the structural indicators of the massif. It consists in studying the propagation of cracks in the array, orientation of the main crack systems, studying the anisotropic properties of stone, and predicting the yield of commercial stone blocks in the deposit. This allows both to increase the efficiency of block extraction and to reduce the loss of stone during its extraction, which increases the economic performance of field development. The assessment of fracturing and blockiness of the Pshenychne gabbro deposit was carried out based on the results of studying the core documentation of 11 exploration wells and the documentation of a pilot production quarry. Rose diagrams, pie charts, and fracturing plans were constructed in isolines, and crack systems common in the field were identified.

Analysis of Potential Environmental Risks in the Hydraulic Fracturing Operation in the “La Luna” Formation in Colombia

This article presents an in-depth analysis of potential environmental risks associated with hydraulic fracturing operations within the “La Luna” formation in Colombia. Using the Conesa methodology, it assesses the environmental impacts of unconventional reservoir production in Colombia, including water usage, chemical additives, air emissions, and the potential for groundwater contamination. This study incorporates comprehensive data on geological characteristics, operational procedures, and environmental conditions specific to the region. This analysis highlights the need for a proactive approach to managing potential environmental risks associated with hydraulic fracturing in Colombia. The findings underscore the importance of implementing robust regulatory measures, comprehensive monitoring systems, and the industry’s best practices to mitigate and prevent adverse environmental impacts. This research contributes to the ongoing global dialogue on the environmental implications of hydraulic fracturing in regions with sensitive ecological conditions. The environmental impacts of unconventional reservoirs are widely recognized as a general consensus; however, the absence of applied studies with the rigor of an explicit methodology in Andean countries highlights the need for specific research in this region. This article addresses this gap by proposing a detailed and structured methodology to assess and mitigate environmental impacts in unconventional reservoirs. Emphasizing the importance of knowing the characteristics of reservoir fluids, this research highlights that this critical information is only revealed by drilling exploration wells and PVT (pressure, volume, and temperature) analysis. Obtaining this data is crucial for shaping specific mitigation measures, thus allowing for the formulation of a robust environmental management plan tailored to the conditions of the reservoirs in the Andean region. This precise and contextualized approach contributes to closing the knowledge gap and promotes more sustainable practices in the exploitation of unconventional reservoirs in this specific geographical context. The methodology used in this study proved its effectiveness by accurately quantifying the risks associated with each of the environmental alterations inherent to the hydraulic fracturing process in the La Luna formation. The results obtained allowed for the identification of the critical points most susceptible to environmental impacts, serving as a solid basis for the elaboration of an environmental management plan. This strategic approach not only enabled the delineation of specific mitigation measures but also facilitated the selection of the most appropriate locations for the implementation of the plan, maximizing the effectiveness of corrective actions. It is noteworthy that the successful application of the Conesa methodology in this unconventional reservoir context evidences the versatility and applicability of this approach, consolidating it as a valuable tool for environmental assessment and effective planning in the hydraulic fracturing industry.

Geological and hydrogeological structure of the Sheshma terrigenous complex of the Belsky uplift

Relevance. The importance of industrial and technical water supply to an oil field in the north-east of Perm region. The requirements to subsoil use and environment protection demand a sanitary restriction zone of the water supply source in the northern part of the field. The current study of a geological structure and groundwater conditions and circulation of Sheshma aquifer complex will assess its resources and elaborate on organization of water supply to the oil field. Aim. To study geological structure and groundwater conditions of Sheshma aquifer complex. Objects. Formations rocks and groundwater conditions of Sheshma terrigenous complex. Methods. Studying the archival records, conducting a hydro-geological survey of the territory, drilling groundwater exploration wells, conducting pilot-filtration works on groundwater exploration wells in the flooding and low-water period. Results. The authors have discovered Sheshma formation thickness, which ranges from 100–150 to 300 m, and lithological composition of rocks and groundwater conditions of Sheshma aquifer complex. It was established that groundwater is deposited as a system of separate isolated water-bearing interlayers and blocks within the Durinsky trough. The most water-bearing zones were identified. Two aquifers of fine-grained and coarse-grained sandstones were detected in low-permeability thickness of Sheshma formation. The aquifers are not hydraulically connected and are separated from each other by a 40 m thick layer of water-resistant mudstones. Groundwater is deposited as strata with Neumann's boundary conditions, orientated sublatitudinally, from west to east. The obtained data can be further used to solve the issues of water supply within the area under study and the rational use of these waters.

Geochemistry of Liquid Hydrocarbons and Natural Gases Combined with 1D Basin Modeling of the Oligocene Shale Source Rock System in the Offshore Nile Delta, Egypt.

The current study aims to integrate the geochemical characteristics of the Oligocene shale source rock system, oil, condensate, and natural gas samples in the Oligocene sandstone reservoirs from three exploration wells located in the offshore Nile Delta, East Mediterranean Sea, using organic geochemistry and a 1D basin modeling scheme. The Tineh shales exhibit total organic carbon values ranging between 0.90 and 1.89 wt %, along with hydrogen index values in the range of 54-240 mg hydrocarbon/g rock. The geochemical characterization suggests that the shale intervals of the Oligocene Tineh Formation contain type II-III and type III kerogens and, thereby, could be regarded as promising oil- and gas-prone source rocks with high contributions of gas generation potential. The study also reconstructs the 1D thermal and burial history models, showing that the Oligocene Tineh source rock system is in the main oil and wet gas generation phases from the late Miocene to the present time. The simulated basin models reveal the transformation (TR) of 10-50% kerogen to oil during the late Miocene-early Pliocene period and that the Oligocene Tineh source rock system has larger oil generation and expulsion competency, with a TR value of up to 65% during the early Pliocene-Pleistocene time period. The thermogenic gas was also formed during this time and continued to the present day. This study also investigated the presence of oil and condensate in the Oligocene sandstone reservoir samples and revealed that they were generated from mature source rock, ranging from moderately to highly mature stages. This source rock unit was deposited in fluvial to fluvial-deltaic environments under oxic mixed organic conditions and accumulated during the Tertiary time, as evidenced by the presence of the oleanane biomarker dating indicator. The molecular and isotope compositions of natural gases revealed that most of the natural gases in the Oligocene sandstone reservoir are mainly thermogenic methane gases that were generated from mainly mixed organic matter. The thermogenic methane gases were formed mainly from secondary cracking of oil and gas, with small contributions of primary kerogen cracking. The properties of natural gases together with oil and condensate in the Oligocene reservoir rocks suggest that most of the thermogenic methane gases and associated liquid hydrocarbons are derived primarily from the Oligocene shale source rock system and formed by primary kerogen cracking and secondary oil and oil/gas cracking in different thermal maturity stages. Therefore, the Oligocene Tineh Formation can be regarded as self-source generation and self-reservoir rock; hence, an intensive oil exploration and production program can be recommended whenever the Tineh source rock system is is well developed and deeply buried.

Study on thermal‐hydro‐mechanical coupling and stability evolution of loess slope during freeze–thaw process

AbstractDisasters occurring at loess slopes in seasonal frozen regions are closely related to changes in the thermo‐hydro‐mechanical (THM) state in loess by freeze–thaw (FT) action. Current research on FT‐induced soil slope failure focuses on frozen stagnant water effects, while the intrinsic connection between the FT‐induced stagnant water effect and soil strength deterioration remains unclear. In this study, by taking the FT‐induced loess slope failure as an example, field surveys, boreholes, exploratory wells, and 3D topographic mapping were used to reveal the landslide features and stratigraphic information; Furthermore, the temporal and spatial variation of water and heat in loess slope was revealed by on‐site monitoring data; A THM coupled model of frozen soil was established using COMSOL Multiphysics simulation software to reconstruct the frozen stagnant water process of shallow loess slope, as well as the influence of THM field on loess landslide. The results show that the effects of FT in the seasonally frozen region occurred in the shallow layer of the loess slope. The water‐ice phase transition during FT process broke the phase equilibrium of loess. Numerical calculations and field monitoring indicated a continuous migration of water to the freezing front, creating a water‐enriched zone inside the loess. Both the impact of the frozen stagnant water and changes in the stress field led to the degradation of loess structure and reduced the strength properties, thus threatening the stability of the loess slope. The study results can contribute to an in‐depth understanding of the mechanism underlying FT loess landslides in seasonal frozen regions, and provide a scientific basis for the evaluation and prevention of FT landslides.

Basin analysis study of block 53 in the Masilla Basin, Yemen, using a 1D-backstripping method

Basin study of 1D-backstrripping analysis was performed on the sediments in in the four exploration wells (Bayoot S1, Bayoot Sw3, Sharyoof 2, and Sharyoof 9) from Block-53, Masilla Basin. 1D backstripping analysis resulted in many curves of the subsidence of the basement during the deposition of the stratigraphic units. The 1D basin models show that the Masilla basin exhibited a complex subsidence history over a period of about 155 Ma and includes three stages of subsidence. The first stage was occurred at 132-155 Ma and shows high subsidence rate about 6.2 cm per1000 years) and deposition rate about 6.13 cm per 1000 years in the southwest part of Block-53. This stage formed as a result of thinning in the curst during the lithospheric extension. The second stage of subsidence was occurred at 66-128Ma and shows decrease the subsidence rates in the range of 1.99- 1.11 cm/1000 years and deposition rates between 1.19 and 0.69 cm/1000 years during the post-rift deposits, which is represented by Qishn Clastic and Carbonate formations (.At the third stage, the subsidence and deposition rates are high in the southwest of block-53 and found to be about 9.3 cm/1000 years and 9.2 cm/1000 years, respectively . The rapid in the subsidence rates during this stage is primary related to the cooling of lithosphere and loading of the sediments

Characterizing deep groundwater using evidence from oil and gas exploration wells in the Lower Kutai Basin of Indonesia

Groundwater at depths exceeding 500 m can be an important source of freshwater. However, the characteristics of deep groundwater in many regions of the world, including Indonesia’s sedimentary basins, remain vaguely defined. This study investigates the pressure regimes, hydraulic head distributions, salinity, and hydrochemical facies of deep groundwater using available evidence from oil and gas exploration wells in the Lower Kutai Basin of Indonesia. Pressure measurements and wireline log data reveal three pressure regimes within the basin: hydrostatic, overpressure, and underpressure. The top of the overpressure varies, from close to the surface onshore to depths of ~4.5 and ~3.8 km in the Mahakam Delta and offshore, respectively. Computed hydraulic heads at the top of the overpressure range from ~191 m above sea level onshore to ~71 m below sea level offshore, and are indicative of regional groundwater flow. The observed salinity of deep groundwater within the basin indicates predominantly brackish or saline conditions. Fresh (total dissolved solids < 1 g/L) groundwater to a depth of ~2 km is found at a small minority of wells onshore and in the delta; no fresh groundwater is found offshore. Four hydrochemical facies are observed: Na+/Cl–, Ca2+/Cl–, Na+/HCO3–, and Na+–Ca2+/HCO3–. This study indicates that deep fresh groundwater in the Lower Kutai Basin is of localized occurrence. Recharge from meteoric water may replenish deep fresh groundwater within the hydrostatic zone and sustain water supplies, whether brackish or fresh. Water produced from clay diagenesis is also cited as a possible process of freshening deep groundwater.

Influence of tectonic preservation conditions on the nanopore structure of shale reservoir: A case study of Wufeng-Longmaxi Formation shale in western Hubei area, south China

Tectonism is one of the dominant factors affecting the shale pore structure. However, the control of shale pore structure by tectonic movements is still controversial, which limits the research progress of shale gas accumulation mechanism in the complex tectonic region of southern China. In this study, 34 samples were collected from two exploratory wells located in different tectonic locations. Diverse experiments, e.g., organic geochemistry, XRD analysis, FE-SEM, low-pressure gas adsorption, and high-pressure mercury intrusion, were conducted to fully characterize the shale reservoir. The TOC, Ro, and mineral composition of the shale samples between the two wells are similar, which reflects that the shale samples of the two wells have proximate pores-generating capacity and pores-supporting capacity. However, the pore characteristics of shale samples from two wells are significantly different. Compared with the stabilized zone shale, the porosity, pore volume, and specific surface area of the deformed zone shale were reduced by 60.61%, 64.85%, and 27.81%, respectively. Moreover, the macroscopic and fine pores were reduced by 54.01% and 84.95%, respectively. Fault activity and uplift denudation are not conducive to pore preservation, and the rigid basement of Huangling uplift can promote pore preservation. These three factors are important reasons for controlling the difference in pore structure between two wells shales. We established a conceptual model of shale pores evolution under different tectonic preservation conditions. This study is significant to clarify the scale of shale gas formation and enrichment in complex tectonic regions, and helps in the selection of shale sweet spots.