Key Geological Factors Research Articles

Key geological factors governing sweet spots in the Wufeng-Longmaxi shales of the Sichuan Basin, China

Production performance of the Wufeng-Longmaxi shales varies significantly among Fuling, Weirong, and Wulong fields in the Sichuan Basin. Total organic carbon (TOC) content, mineralogy, and organic matter (OM) pore characteristics are investigated to identify key factors governing sweet spots. Siliceous shales with good preservation conditions in the Fuling Field exhibit large thickness, high TOC content and thin-section porosity (TSP), and well-developed OM macropores, thus high initial production and estimated ultimate recovery (EUR). Thin carbonate-containing siliceous shales with good preservation conditions in the Weirong Field feature medium-to-high TOC and well-developed OM macropores but low TSP, leading to high initial production but low EUR. Siliceous shales with poor preservation conditions in the Wulong Field are characterized by large thickness, high TOC, low TSP and poorly-developed OM macropores, causing low initial production and EUR.Both sedimentary and preservation conditions are intrinsic decisive factors of sweet spots, as they control the mineral composition, TOC, and OM macropore development. Deep-water shales in transgressive systems tracts (TSTs) exhibit better-developed OM macropores and greater TOC compared to highstand systems tracts (HSTs). OM macropores are most prevalent in siliceous shales, followed by carbonate-containing siliceous shales and then argillaceous shales. Furthermore, good preservation conditions are conducive to retain OM macropores with low pore aspect ratio (PAR). Comparison among the three fields shows that high-TOC silicious shales with good preservation conditions are the highest in TSP and EUR. Therefore, organic richness, lithofacies, and preservation conditions are the major factors which determine OM pore development, governing the sweet spots of the Wufeng-Longmaxi shales.

Bedrock Fractures Control Groundwater‐Driven Mountain Slope Deformations

AbstractSeasonal deformation of mountain rock slopes can be driven by groundwater infiltration and depletion. Such processes could explain our field observation in the Aletsch Valley, Switzerland, where GNSS‐derived 3D annual displacement amplitudes reach 3.4 cm. However, the physical mechanisms behind such groundwater‐driven surface displacements are not well understood. Here, we develop a fully coupled hydromechanical model to simulate the relevant processes in a valley slope embedded with numerous fractures of variable sizes. The magnitude and orientation of transient annual slope surface displacement obtained from our model are in overall agreement with the field observations. The key geological factors controlling the type and magnitude of reversible mountain slope deformations are fracture network geometry, fracture aperture, and regional stress field. We show that the heterogeneity and anisotropy of bedrock hydromechanical responses, originating from depth‐dependent variations of fracture properties, play a critical role in groundwater recharge and valley slope deformation. During recharge events, pore pressure perturbations migrate downward from the groundwater table and toward the receiving stream and the deep subsurface. This process driven by pressure diffusion and poroelastic stressing develops in the subsurface with a great reach of up to a few kilometers, called critical hydromechanical response zone, and controls surface deformation patterns. During groundwater recession, this hydromechanical response zone expands downward and ground surface displacement vectors rotate upwards. Our results suggest that slope surface deformation can inform about subsurface permeability structures and pore pressure fluctuations, which have important implications for understanding groundwater flow in fractured bedrock slopes.

Improving the Understanding of Landslide Development in Alpine Forest Regions Using the InSAR Technique: A Case Study in Xiaojin County China

Employing a small baseline subset Interferometric Synthetic Aperture Radar (SBAS-InSAR) and hotspot analysis, this study identified 81 potential landslides in a 768.7 km2 area of Xiaojin county, eastern Tibetan Plateau. Subsequent time-series deformation analysis revealed that these potential landslides are in the secondary creep stage. The newly identified landslides were compared to a landslide inventory (LI), established through field surveying, in terms of causative factors, including altitude, slope, relief amplitude, distance to river, distance to road, and slope curvature. From the comparison, the InSAR technique showed the following advantages: (1) it identified 25 potential landslides at high altitudes (>3415 m) in addition to the low-altitude landslides identified through the field survey. (2) It obtained approximately 37.5% and 70% increases in the number of potential landslides in the slope angle ranges of 20°–30° and 30°–40°, respectively. (3) It revealed significant increases in potential landslides in every relief amplitude bin, especially in the range from 58 m to 92 m. (4) It can highlight key geological factors controlling landslides, i.e., the stratigraphic occurrence and key joints as the InSAR technique is a powerful tool for identifying landslides in all dip directions. (5) It reveals the dominant failure modes, such as sliding along the soil–rock interface and/or interfaces formed by complicated combinations of discontinuities. This work presents the significant potential of InSAR techniques in gaining deeper knowledge on landslide development in alpine forest regions.

Influence of key geological factors on fluid production behaviors in marine natural gas hydrate reservoirs: A case study

Accurate geological model of hydrate reservoir is the prerequisite of obtaining the credible prediction results. Not only stress sensitivity and anisotropy of permeability but also non-uniformity in hydrate saturation and permeability distribution are key geological factors influencing fluid production behaviors. However, they have been overlooked to some extent in previous numerical simulations. To highlight the significance of these factors, this study develops a robust production model at site AT1 based on geological data and laboratory tests. Then we systematically investigate the effects of the aforementioned factors on production performance. The simulation results exhibit that all the factors have notable impacts on fluid production behaviors, especially the non-uniform hydrate saturation and permeability distributions. Ignoring the permeability stress sensitivity and adopting the homogeneous simplification of hydrate saturation may overestimate gas and water production. Besides, various characterization methods of reservoir permeability can give rise to the significantly different production behaviors for heterogeneous hydrate reservoirs. The stronger the reservoir permeability anisotropy, the better the production performance. In order to achieve the reliable predictions, the geological model built should properly incorporate these factors during numerical modeling. These findings provide valuable guidance for constructing robust models and optimizing production strategies for natural gas hydrate reservoirs.

Experimental Studies on the Crack Initiation and Propagation of Hydraulic Fracturing with Different Coal Structure Combinations.

Coal structure is one of the key geological factors that affects the effect of coal reservoir stimulation. Based on the geological spatial combination characteristics, thickness, and proportion of different coal structures, the coal reservoir is divided into different coal structure combination types. The hydraulic fracturing device is used to carry out indoor fracturing experiments and dissect the crack initiation and expansion characteristics with different coal structure combinations. The results show that the coal structure combination is of the binary type (undeformed coal + granulated coal or cataclastic coal + granulated coal), and the undeformed coal (cataclastic coal) can overcome the tensile strength and minimum principal stress when it is driven by the high-pressure fluid. The undeformed coal (cataclastic coal) ruptures and forms longitudinal cracks. The increasing proportion of granulated coal inhibits crack expansion and promotes the transverse deformation of coal. The interface contact point between the undeformed coal (cataclastic coal) and granulated coal easily fractures along the cross section of the specimen. When the coal structure combination is the triplex type (undeformed coal + granulated coal + cataclastic coal or cataclastic coal + granulated coal + cataclastic coal), the undeformed coal or cataclastic coal is transformed. The forming fractures in the undeformed coal (cataclastic coal) can cut through the soft coal when the thickness of the undeformed coal (cataclastic coal) is large and the thickness of granulated coal is thin. On the contrary, it is not easy to cut through. When the coal structure combination is granulated coal + cataclastic coal + granulated coal, the cataclastic coal fails under shear stress and forms the crack along the cross section of the coal sample. The granulated coal inhibits the crack expansion at both ends. The research results have an important indicative significance for further understanding the fracture initiation and propagation mechanism of hydraulic fracturing with complex coal structures in coal reservoirs.

Geochemical characteristics of the braided river reservoir in block 19 of the sulige gas field

The sand body structure and geochemical characteristics of braided river reservoirs are the key geological factors affecting gas production and development effects. The Sulige gas field in the Ordos Basin is an important large-scale gas-producing layer. Owing to the control of sedimentary facies, the geological structure of the sand body changes greatly and its connectivity is poor. The geological characteristics have not yet been elucidated, and this is an important problem restricting the development of the Sulige Gas Field. To solve this problem, this study focuses on the braided river reservoir of the Shihezi Formation in Block 19 of the Sulige Gas Field, conducts geological surveys in the study area, analyzes the geological and geochemical characteristics of the reservoir, and obtains samples through drilling. Through a thin-section test, gas-water two-phase experiment, and simulation test, the braided river reservoir configuration and pore and gas-water characteristics are obtained. The results show that the reservoir lithology in the study area is mainly composed of quartz sandstone, lithic sandstone, and quartzy lithic sandstone, with a porosity of 3%–13% and a permeability of (0.05–0.7) × 10−3 m2. The reservoir has low porosity and low permeability. After drilling samples were obtained, 32 thin-section rock samples were selected. The pore types of the block reservoir mainly (82.9%) consisted of intragranular and intergranular dissolved pores. The difference in pore structure was mainly reflected by the size and distribution of the throat. The distribution of physical properties was 6%–10%, the gas saturation was 61%, the NMR effective porosity was 7.49%, the permeability was 4.08 × 102 μm2, and the physical properties were relatively good. In terms of the study area, the average thickness of the single braided channel in the lower section of He 8 was 4.7 m, the average width of the channel was 963 m, and the composite channel was distributed in a potato shape, parallel to the direction of the main flow. The average length of the channel was 2,147 m and the average width was 844 m. As the porosity increased, the efficiency of gas-driven water also increased, and there was a linear positive correlation between porosity and gas-driven water efficiency. With the increase in movable water saturation, the water-air ratio became larger and water production was greater. In low-amplitude structures and under low-permeability background conditions, for reservoirs with good local pore structure and physical properties, the water remaining at the bottom of the reservoir or sand body was controlled by the accumulation conditions or the weak structural differentiation after accumulation. In terms of the gas and water produced simultaneously in the study area, gas production was less than 2 × 104 m3/d and water production was relatively large at more than 10 m3/d; gas and water were mainly distributed in the downdip part of the main channel structure or in the island lens-shaped permeable sand bodies trapped by the surrounding tight layers. The study results provide theoretical data support for the exploration and production of the Sulige Gas Field.

Heterogeneity of a Sandy Conglomerate Reservoir in Qie12 Block, Qaidam Basin, Northwest China and Its Influence on Remaining Oil Distribution

In view of the key geological factors restricting reservoir development, the reservoir heterogeneity of an alluvial fan sandy conglomerate reservoir in the Qie12 block of Qaidam Basin, Northwest China, and its influence on remaining oil distribution, were studied according to geology, wireline logging data, and dynamic production data. This study illustrates that the difference in pore structures, which are controlled by different sedimentary fabrics, is the main cause of reservoir microscopic heterogeneity. Besides, the temporal and spatial distribution of architectural units in the alluvial fan controls reservoir macroheterogeneity. Our results show that the thick sandy conglomerate develops two types of pores, two types of permeability rhythms, two types of interlayers, two types of interlayer distribution, two types of effective sand body architecture, and four types of sand body connecting schemes. The strongest plane heterogeneity is found in the composite channel unit formed by overlapping and separated stable channels of the middle fan, and the unit’s permeability variation coefficient is >0.7. However, the variation coefficient in the range of 0.3–0.5 is found in the extensively connected body unit sandwiched with intermittent channels of the inner fan. The distributions of the remaining oil vary significantly in different architectural units because of the influence of reservoir heterogeneity, including distribution patterns of flow barriers, permeability rhythm, and reservoir pore structures. The composite channel unit formed by overlapping and separated stable channels, or the lateral alternated unit with braided channel and sheet flow sediment of the middle fan, is influenced by the inhomogeneous breakthrough of injection water flowing along the dominant channel in a high-permeability layer. The microscopic surrounding flow and island-shaped remaining oils form and concentrate mainly in the upper part of a compound rhythmic layer. Meanwhile, in the extensively connected body unit sandwiched with intermittent channels of the inner fan, poor injector–producer connectivity and low reservoir permeability lead to a flake-like enrichment of the remaining oil.

Formation conditions of natural gas fields in the lacustrine basin in eastern China: Insights into the first discovery within the Bohai Bay Basin

The hydrocarbon source of Bohai Bay Basin is dominated by oil-prone kerogens of type II2-II1 within semi-deep and deep lacustrine facies. In the Neogene period, faults were well-developed via significant structural activity. The Bohai Sea is generally considered to have no geological basis for the formation of large natural gas fields. Through analogous analysis of domestic and international gas fields, the key geological factors that restrict formation in continental rift lacustrine basins were studied, including gas source, preservation conditions, and reservoirs. A natural gas enrichment and accumulation model within a petroliferous basin is presented. The model indicates that rapid subsidence and high-intensity gas generation within petroliferous sags during the late stages were main contributors to natural gas field formation. Archean metamorphic buried hill reservoirs and thick, overpressure mudstone with strong vertical sealing ability provided favorable storage space and preservation, respectively. Using the model, an integrated Archaean metamorphic buried hill condensate gas reservoir, Bozhong 19–6, was discovered in the Bohai Bay Basin. The natural gas reserves are about 450×109 m3, equivalent to oil production of 800 ×106 m3, and signify a breakthrough in natural gas exploration of continental rift lacustrine basins in China.

PETROLEUM SYSTEMS ANALYSIS OF THE EASTERN ARABIAN PLATE: CHEMOMETRICS BASED ON A REVIEW OF THE GEOCHEMICAL CHARACTERISTICS OF OILS IN JURASSIC – CENOZOIC RESERVOIRS

This paper presents the results of an integrated geochemical study of oils in Jurassic – Cenozoic reservoirs in the eastern region of the Arabian Plate. The main objective was to analyze the active petroleum systems at a regional scale across the study area which extends from NE Iraq to SE Oman and includes the entire Persian Gulf. The dataset for the study consisted of more than 500 crude oil samples from 112 oil fields and 11 different reservoir units. This dataset was compiled from both the literature and re‐evaluated geochemical and stable isotope analyses, augmented by new analytical studies.The study documents regional variations and trends in the bulk and molecular properties and stable isotope ratios of the oil samples. Two overall clans and twelve genetic oil families and sub‐families were distinguished using multivariate statistical analysis (chemometrics) based on biomarker parameters. The age, lithology, depositional setting and organic matter type of the respective source rocks for each family/sub‐family was inferred from oil geochemical fingerprints.The results provide insights into the key geological factors that control the number, size and geochemical character of oil fields in the eastern Arabian Plate. The geographical extent of the various oil families was assessed and used to evaluate charge access and to predict migration directions and migration pathways in the study area.The results indicate the value of implementing multivariate statistical analysis on “big data” along with state‐of‐the‐art geological petroleum systems analysis and interpretation of biomarker and oil composition data to investigate complex and extended petroleum systems.

Sealing capacity evolution of gypsum salt caprocks under multi-cycle alternating stress during operations of underground gas storage

Caprock sealing ability is one of the key geological factors to ensure the stable and safe operation of the underground gas storage (UGS). Gypsum salt rock is the high-quality caprock for oil and gas reservoirs, however, the effect of cyclic stress on its sealing capacity is still unclear, which restricts the construction progress of this kind of UGS. Therefore, taking the H UGS in the Sichuan Basin in China as an example, this paper analyzes the initial sealing capacity of gypsum salt caprock using cast thin section, conventional physical property test, nuclear magnetic resonance and breakthrough pressure tests. On this basis, study the variation characteristics of physical and mechanical parameters of gypsum salt caprock under cyclic stress using cyclic stress loading and unloading experiment, and then analyze the evolution law of its sealing capacity. The results show that gypsum salt caprocks of H UGS can be used as a good tight caprock with the porosity less than 1.0%, permeability less than 0.005 mD, breakthrough pressure greater than 6.0 MPa and triaxial compressive strength greater than 210 MPa. In addition, the physical properties of gypsum salt caprock become worse and the sealing capacity increases under cyclic stress, and physical and mechanical changes of gypsum salt caprock mainly occur in the first 30 cycles accounting for about 75%. Moreover, with the increase of cycles, the Poisson's ratio increases by 88% while the change range of elastic modulus is only 6.4%, indicating that gypsum salt caprocks mainly expands laterally and still maintain good elasticity. However, when the cycle times reach a certain threshold of 1002, the cumulative plastic strain of gypsum salt rock will become larger and larger until fracture. And the gypsum salt caprocks can be effective cover in the 184 cycles of loading and unloading with the maximum pressure threshold of 18 MPa and minimum pressure threshold of 1 MPa. This research results can provide theoretical guidance for cap rock stability analysis and operation parameter design of gas reservoir.

The importance of incorporating geology, soil, and landscape knowledge in freshwater farm planning in Aotearoa New Zealand

Over half of Aotearoa New Zealand’s (NZ’s) land area is under agriculture or forestry production. Long term monitoring has shown declines in freshwater quality in regions with the most intensive agriculture. The New Zealand government has historically focused on reducing the impact of agriculture on water quality through its Resource Management Act 1991. Lack of improvement in freshwater quality has resulted in the 2020 Essential Freshwater package of reforms which will require all pastoral farms >20 ha in size and all arable farms > 5 ha in size to develop a Freshwater Farm Plan (FFP) by a certified Freshwater Farm Planner. As far as we are aware, New Zealand is the first country in the world to mandate compulsory FFPs. This paper describes the key geological, soil, and landscape factors that need to be considered in an FFP for it to be successful in meeting the 2020 Essential Freshwater objectives. We argue that a greater emphasis should be placed on understanding a farm’s natural resources, as they provide the physical interface between the farming system and both the freshwater and atmospheric ecosystems. Documenting our learning in this area could assist other countries considering Freshwater Farm Planning as a strategy to reduce the impact of agriculture on freshwater quality.

Evaluating the efficiency of the development of boundary oil rims in the depletion drive

Every year, the relevance of developing oil rims, which were not previously involved in development due to the need to use expensive technologies, is growing. However, at present time the development of oil rims is determined by the depletion of light oil reserves. The massive gas cap and the high gas factor in oil rims don't allow to accurately determine the possibility of developing an oil rim in the depletion drive. The aim of the article is to develop a tool for evaluating the effectiveness of the development of boundary oil rims in the depletion drive. The key geological and physical factors that have the greatest impact on the efficiency of the development of oil rims were identified; analogous deposits were analyzed, on the basis of which geological and hydrodynamic models were built. We evaluated the role and influence of studied factors, such as permeability, angle of inclination of the oil rim, volume of the gas cap, thickness of the oil rim. A tool has been developed to assess the effectiveness of the development of boundary oil rims in the depletion drive and the use of the tool has been demonstrated.

Effects of key geological factors in the long-term transport of CH4 and the CH4-hydrate formation behavior with formation dip

Methane hydrates (MH) are widely distributed below seafloor at marine locations. Most MH bearing geological deposits have dip angles because of the complicated geological structure and diagenesis. In this study, the impact of formation dip on CH4 migration and the associated MH formation was systematically investigated numerically. A numerical model was set up based on the geological information in the Shenhu area of Baiyun Sag in the northern South China Sea (SCS) to simulate the long-term transport of CH4 and the associated MH formation with formation dip. We further conducted a sensitivity analysis and a statistical analysis on three key geological parameters (i.e., dip angle, CH4 leakage rate, and water salinity). The results indicate that the dip angle (θ) of the reservoir promotes the lateral migration of CH4. The total accumulated amount of MH decreases 2.45% with θ increasing from 0° to 10°. Sensitivity analysis suggested that the formation of MH predominantly depends on the CH4 leakage rate (RCH4) in inclined reservoirs. The lateral migration distance of CH4 increases 13.1% but the total accumulated amount of MH decreases 8.8% with increasing water salinity (Xi) from 3.0 wt% to 3.5 wt%. We further analyzed the effect of heterogeneity, which shows that the inclined reservoir with alternating sand and clay layers favors MH formation more than a uniform reservoir with an 8.8% increase in the total MH. Understanding the effect of formation dip on the transport of CH4 and MH formation provide a useful reference in the identification of marine MH resources and the design of safe and effective exploration strategies.

Delineating the Controlling Factors of Hydraulic Fracturing-Induced Seismicity in the Northern Montney Play, Northeastern British Columbia, Canada, With Machine Learning

Abstract Recent studies confirm that the distribution of injection-induced earthquakes (IIE) can be related to both natural (e.g., tectonic, geological, and hydrological) settings and operational details. However, the relative importance of operational factors with respect to the natural ones has not been fully understood for the western Canada sedimentary basin. In this study, we train the eXtreme Gradient Boosting (XGBoost) machine-learning algorithm to comprehensively evaluate six geological and seven industrial operational factors suspected to be correlated with the distribution of IIE in the northern Montney play (NMP), British Columbia. We then derive the Shapley Additive Explanations values to quantitatively interpret the outputs from XGBoost. Our results reveal that operational and geological factors have comparable contributions to the IIE distribution. The top four features that contribute most to the seismicity pattern are horizontal distance to the Cordilleran deformation front, cumulative injected volume, shut-in pressure and vertical distance to the Debolt formation (with respect to the hydraulic fracturing [HF] depth). Features with secondary influence are the thickness of the Montney formation, breakdown pressure, cumulative fault length per unit area, and vertical distance to the basement (with respect to the HF depth). Other remaining features (e.g., the average treating pressure and injection rate) appear the least related. Our results provide critical information to establishing a comprehensive susceptibility model that includes key geological and operational factors affecting the IIE distribution in the NMP area.

Experimental study on reservoir characteristics and oil-bearing properties of Chang 7 lacustrine oil shale in Yan’an area, China

Abstract The Chang 7 Member shale of the Upper Triassic Yanchang formation in the Ordos basin is a hot spot in petroleum geology research. In this study, considering the Chang 7 shale in the Yan’an area as an example, the full-scale pore size characterization of lacustrine shale was realized based on the scanning electron microscopy image gray correction method, nitrogen and carbon dioxide adsorptions, and high-pressure mercury intrusion tests. In addition, the pore structures and oil-bearing properties of the Chang 7 shale were systematically studied. The results show that the Chang 7 shale is rich in organic matter, with an average total organic carbon value of 4.69% and an average R 0 value of 0.9%. It is in the mature-wet gas (crude oil-associated gas) stage. There are certain differences in the development characteristics and pore size distribution of different types of pores in shale. The statistical results showed that the pore diameters of the intergranular pores and intragranular dissolved pores were significantly larger than the intercrystalline pores of clay minerals and the organic pores. The organic pores in solid bitumen are extremely developed, whereas the organic pores in kerogen are relatively underdeveloped. The lower limit of the effective pore size of shale is 20 nm. The network system composed of inorganic pores-microcracks-organic matter-organic pores and siltstone laminae provides important channels and retention spaces for the migration of shale oil and gas within the source. This study found that the proportion of movable oil in sandy layers is relatively high, followed by shale with sandy laminae, whereas pure shale has the lowest proportion of movable oil. Therefore, the degree of sandy laminar development, the abundance of organic matter, and the degree of thermal evolution are the key geological factors that control the porosity and oil-bearing properties of shale oil reservoirs.

Quantitative assessment of the sweet spot in marine shale oil and gas based on geology, engineering, and economics: A case study from the Eagle Ford Shale, USA

Shale oil and gas have become important areas of petroleum exploration and development. Successful shale oil and gas exploration depends on the accurate evaluation of sweet spots, which are the commercial targets. This paper proposes a comprehensive new method for sweet spot evaluation based on average estimated ultimate recovery in barrels of oil equivalent (EUR_BOE) in conjunction with key geological factors, engineering and technical conditions, and economic and technical indicators. Research results from 72 systematically cored wells, 991 sets of core analyses, and production data from 1317 horizontal wells in the lower Eagle Ford Shale (EFS) of the U.S. Gulf Basin show that marine shale oil and gas sweet spots depend primarily on four key factors: oil and gas resources, oil and gas storage capacity, fluidity, and fracability. These conclusions are based on quantitative evaluation models relating to EUR_BOE and key geological parameters. Model outcomes are controlled by inputs for total organic carbon (TOC), vitrinite reflectance (%Ro), original formation and hydrostatic pressure difference (ΔPf–h) or formation pressure gradient (Pindex), effective shale thickness (Heshale), clay volume content (Vclay), fracture porosity (Φf)and other geological parameters pertaining to EUR_BOE. Shale oil and gas sweet spots in non-fractured zones must satisfy certain conditions including TOC ≥2.3 wt%, Ro ≥ 0.9%, Heshale ≥ 15 m, Vclay ≤ 25 vol%, and ΔPf–h between ∼3 and 35 MPa or Pindex between ∼1.15 and 1.85 MPa/100 m. Defining shale oil and gas sweet spots in fractured zones is more complex, because developing fractures and the application of advanced engineering technology will increase EUR_BOE; sweet spots are impacted by sealing conditions, fracture and fault development, and technical engineering conditions. The proposed method for evaluating shale oil and gas sweet spots is validated through the determination of sweet spots in the lower EFS, and provides a basis for the evaluation of shale oil and gas sweet spots in similar marine deposits.

Machine learning to identify geologic factors associated with production in geothermal fields: a case-study using 3D geologic data, Brady geothermal field, Nevada

In this paper, we present an analysis using unsupervised machine learning (ML) to identify the key geologic factors that contribute to the geothermal production in Brady geothermal field. Brady is a hydrothermal system in northwestern Nevada that supports both electricity production and direct use of hydrothermal fluids. Transmissive fluid-flow pathways are relatively rare in the subsurface, but are critical components of hydrothermal systems like Brady and many other types of fluid-flow systems in fractured rock. Here, we analyze geologic data with ML methods to unravel the local geologic controls on these pathways. The ML method, non-negative matrix factorization with k-means clustering (NMFk), is applied to a library of 14 3D geologic characteristics hypothesized to control hydrothermal circulation in the Brady geothermal field. Our results indicate that macro-scale faults and a local step-over in the fault system preferentially occur along production wells when compared to injection wells and non-productive wells. We infer that these are the key geologic characteristics that control the through-going hydrothermal transmission pathways at Brady. Our results demonstrate: (1) the specific geologic controls on the Brady hydrothermal system and (2) the efficacy of pairing ML techniques with 3D geologic characterization to enhance the understanding of subsurface processes.

Key geological factors controlling the estimated ultimate recovery of shale oil and gas: A case study of the Eagle Ford shale, Gulf Coast Basin, USA

Based on 991 groups of analysis data of shale samples from the Lower Member of the Cretaceous Eagle Ford Formation of 1317 production wells and 72 systematic coring wells in the U.S. Gulf Basin, the estimated ultimate recovery (EUR) of shale oil and gas of the wells are predicted by using two classical EUR estimation models, and the average values predicted excluding the effect of engineering factors are taken as the final EUR. Key geological factors controlling EUR of shale oil and gas are fully investigated. The reservoir capacity, resources, flow capacity and fracability are the four key geological parameters controlling EUR. The storage capacity of shale oil and gas is directly controlled by total porosity and hydrocarbon-bearing porosity, and indirectly controlled by total organic carbon (TOC) and vitrinite reflectance (R o ). The resources of shale oil and gas are controlled by hydrocarbon-bearing porosity and effective shale thickness etc. The flow capacity of shale oil and gas is controlled by effective permeability, crude oil density, gas-oil ratio, condensate oil-gas ratio, formation pressure gradient, and R o . The fracability of shale is directly controlled by brittleness index, and indirectly controlled by clay content in volume. EUR of shale oil and gas is controlled by six geological parameters: it is positively correlated with effective shale thickness, TOC and fracture porosity, negatively correlated with clay content in volume, and increases firstly and then decreases with the rise of R o and formation pressure gradient. Under the present upper limit of horizontal well fracturing effective thickness of 65 m and the lower limit of EUR of 3×10 4 m 3 , when TOC<2.3%, or R o <0.85%, or clay content in volume larger than 25%, and fractures and micro-fractures aren’t developed, favorable areas of shale oil and gas hardly occur.

Geological controls on geothermal resources for power generation

Threats posed by the climate crisis have created an urgent need for sustainable green energy. Geothermal resources have the potential to provide up to 150 GWe of sustainable energy by 2050. However, the key challenge in successfully locating and drilling geothermal wells is to understand how the heterogeneous structure of the subsurface controls the existence of exploitable fluid reservoirs. In this Review, we discuss how key geological factors contribute to the profitable utilization of intermediate-temperature to high-temperature geothermal resources for power generation. The main driver of geothermal activity is elevated crustal heat flow, which is focused in regions of active magmatism and/or crustal thinning. Permeable structures such as faults exercise a primary control on local fluid flow patterns, with most upflow zones residing in complex fault interaction zones. Major risks in geothermal resource assessment and operation include locating sufficient permeability for fluid extraction, in addition to declining reservoir pressure and the potential of induced seismicity. Advanced computational methods permit effective integration of multiple datasets and, thus, can reduce potential risks. Future innovations involve engineered geothermal systems as well as supercritical and offshore geothermal resources, which could greatly expand the global application of geothermal energy but require detailed knowledge of the respective geological conditions. Successful discovery and operation of geothermal resources requires a thorough understanding of the heterogeneous geological subsurface. This Review discusses the key geological factors that contribute to the effective exploration of intermediate-temperature to high-temperature geothermal resources used for power generation and direct use applications.

Key geological factors controlling oil displacement efficiency of CO2 injection in low-permeability reservoirs

Carbon dioxide (CO2) flooding is an effective method to enhance oil recovery in low-permeability reservoirs. Studying key geological factors controlling oil displacement efficiency is of great significance to the CO2 injection scheme design in low-permeability reservoirs. Focusing on low-permeable H reservoir in Songliao Basin, China, this paper describes the contact and connection of sand bodies, natural fractures and high-permeability zones with core samples, log data and experiment firstly. After that, the impact of interaction of sand body connection, natural fracture and high-permeability zone on oil displacement efficiency is determined by using geological and dynamic data in CO2 injection area. Results indicate that the connection of single sand bodies between injectors and producters wells primarily controls CO2 flooding in low-permeability reservoirs. Furthermore, coupling of sand body connection, natural fractures and high-permeability zones is the key geological factor governing oil displacement efficiency of CO2 injection in low-permeability reservoirs, where well or generally-connected sand bodies can improve the efficiency significantly. Meanwhile, the dominant seepage channels in other directions have no influence on producers, which is beneficial to improve CO2 flooding efficiency.