Average Permeability Research Articles

Predicting oil field performance using machine learning programming: a comparative case study from the UK continental shelf

Predicting the performance of a subsurface oil field is a large, multivariant problem. Production is controlled and influenced by a wide array of geological and engineering parameters which overlap and interact in ways that are difficult to unravel in a manner that can be predictive. Supervised machine learning is a statistical approach which uses empirical learnings from a training dataset to create models and make predictions about future outcomes. The goal of this study is to test a number of supervised machine learning methods on a dataset of oil fields from the United Kingdom continental shelf (UKCS), in order to assess whether, (a) it is possible to predict future oil field performance and (b), which methods are the most effective. The study is based on a dataset of 60 fields with 5 controlling parameters, (gross depositional environment, average permeability, net-to-gross, gas–oil ratio and total number of wells) and 2 outcome parameters (recovery factor and maximum field rate) for each. The choice of controlling parameters was based on a PCA of a larger dataset from a wider project database. Five different machine learning algorithms were tested. These include linear regression, robust linear regression, linear kernel support vector regression, cubic kernel support vector regression and boosted trees regression. Overall, 83% of the data was used as a training dataset while 17% was used to test the predictability of the algorithms. Results were compared using R-Squared, Mean Square Error, Root Mean Square Error and Mean Absolute Error. Graphs of predicted responses v. true (actual) responses are also shown to give a visual illustration of model performance. Results of this analysis show that certain methods perform better than others, depending on the outcome variable in question (recovery factor or maximum field rate). The best method for both outcome variables was the support vector regression, where, depending on the kernel function applied, a reliable level of predictability with low error rates were achieved. This demonstrates a strong potential for statistics-based prediction models of reservoir performance. Thematic collection: This article is part of the Digitally enabled geoscience workflows: unlocking the power of our data collection available at https://www.lyellcollection.org/topic/collections/digitally-enabled-geoscience-workflows

Diagenesis and the effects of cataclastic deformation on the Permo-Triassic New Red Sandstone, Isle of Arran, Scotland

Diagenesis in the Permo-Triassic New Red Sandstone, Isle of Arran is characterized by early cementation of hematite, clay, and calcite minerals, followed by burial compaction, quartz, feldspar, and pyrite cementation. Cataclasis post-dated the quartz and feldspar cementation and reduced the grain and pore aperture size in deformed samples. Samples with cataclastic bands typically have 18% porosity and 8.81 mD permeability on average. Whereas, undeformed samples have an average porosity of 22% and an average permeability of 381 mD. Cataclasis was not as important as diagenesis in controlling sandstone porosity and permeability. However, cataclasis resulted in lower porosity and very poor to medium permeability in deformed samples. Cataclastic bands compartmentalize reservoir sands and cause a high heterogeneity in undeformed porous sandstones. Poikilotopic and blocky calcite cement postdates early clay and hematite cement. In addition, burial quartz and feldspar overgrowths also postdate the early clay and hematite. However, the poikilotopic calcite fills in framework grains that have larger void volumes than the grain/grain contacts where quartz overgrowths are present. Cataclasis resulted in fracturing of quartz and feldspar overgrowths. Therefore, the cataclasis occurred after the development of quartz and feldspar cementation. Dissolution postdated the formation of authigenic feldspar and pyrite formation resulted from hematite reduction. The distributions of grain and pore sizes against cumulative mercury volumes in studied samples shows a high level of reduction of grain and pore aperture sizes for deformed samples from single-cataclastic and multi-cataclastic bands. The distribution of apex volumes illustrates that the effective mercury porosity of the multi-cataclastic band sample may be reduced up to > 2 times in comparison to undeformed samples. However, the sample of a thin single cataclastic band has only a slightly lower apex volume in comparison to the host sample.

Formation conditions and the main controlling factors for the enrichment of shale gas of Shanxi Formation in the southeast of Ordos Basin, China

Based on the dissection of the geological characteristics of typical shale gas wells, the relationship between reservoir-forming factors and shale gas enrichment is deeply analyzed, and the controlling factors of shale gas enrichment are summarized. An analysis of data from drilling, logging, testing, and shale sample has revealed that the factors contributing to the formation of shale gas reservoirs in marine–continental transitional facies of Shanxi Formation in the southeast of Ordos Basin are highly heterogeneous. This is mainly reflected in the rapid spatial change of shale organic matter, physical properties, and other parameters of the shale in this area. The shale found in the Shanxi Formation has a high content of organic carbon (TOC), with an average of 2.24%. The kerogen type is mainly type Ⅲ, and the average value of RO is 2.48%, indicating that it is in the high mature-overmature stage and is a high-quality source rock. The rock composition is rich in clay (40.5%–88.5%), mainly composed of illite-mongolian mixed layer and kaolinite, and its relatively high specific surface area is beneficial for improving the gas adsorption capacity of the shale. Thin sandstone interbeds, measuring less than 3 m are widely distributed in the Shanxi Formation and have good physical conditions. With an average porosity 3.37% and an average permeability of 0.1 mD. The natural gas generated by the shale can be transported to these sandstone interlayers (laminae) in a short distance, which is beneficial for improving the gas-bearing property of the shale. The gas-bearing property of the Shanxi Formation in the study area is affected by different lithologic assemblages. The gas-bearing property of the thick mudstone-coal assemblage of the second member of the Shanxi Formation is the best, with more than 80% of the samples having a gas content of over 1 m3/t. This study suggests that the high thermal evolution degree of shale, special marine–continental transitional facies reservoir conditions, and good preservation conditions are the main factors affecting the enrichment of shale gas in the study area. This makes the shale gas of the Shanxi Formation in the southeast of the Ordos Basin have certain potential for exploration and development, and delineates the enrichment targets of shale gas in the Zichang-Yan'an-Fuxian and Yichuan areas.

Experimental study on the effect of salt crystallization on multi-scale transportation of shale gas

Salt crystallization will block the pores and fractures of shale reservoirs. It is one of the important reasons for the rapid decline of shale gas wells' initial production. Pressure pulse decay tests show that shale permeability is significantly decreased due to salt crystallization. Salt crystallization primarily block macropores and natural fractures, resulting in an average permeability reduction rate of 79.26%. The major salt crystallization formed after the salt crystallization experiment is CaSO4, and the overall size of the crystallization is 30–50 μm.

A Comparative Study on the Microstructure and Petrophysical Properties of Undeformed and Naturally Deformed Shales

Structural deformation is one of the main impacts responsible for understanding the hydrocarbon accumulation mechanism. Predicting its function in gas storage and migration in a microscopic scale is thus a significant issue in predicting reservoir quality. The purpose of this article is to make a comparative study on the microstructure and petrophysical properties of undeformed and naturally deformed shales developed in the Southeast Sichuan Basin. The results show that (1) organic pores, ranging from 10 to 200 nm, are more developed in undeformed shale, whereas carbonate solvopores, clay-hosted pores, and microfractures are dominant in deformed shale. (2) Undeformed shales have Dubinin–Radushkevich (DR) CO2 adsorbed contents ranging between 0.009 and 0.018 g, DR CO2 micropore surface areas of 3.90–15.59 m2/g, and Dubinin–Astakhov (DA) CO2 micropore volumes of 0.002 and 0.035 cc/g. Naturally deformed shales have larger DR CO2 adsorbed contents, DR CO2 micropore surface areas, and DA CO2 micropore volumes, typically in the ranges of 0.019–0.031 g, 13.15–20.97 m2/g, and 0.006–0.012 cc/g, respectively. (3) Undeformed shales have N2 adsorbed contents ranging between 1.94 and 6.03 cc/g, Brunauer–Emmett–Teller (BET) N2 mesopore and macropore surface areas of 0.55–7.35 m2/g, and Barrett–Joyner–Halenda (BJH) N2 mesopore and macropore volumes of 0.002 and 0.006 cc/g. Naturally deformed shales have larger N2 adsorbed contents, BET N2 mesopore and macropore surface areas, and BJH N2 mesopore and macropore volumes, typically in the ranges of 5.72–14.45 cc/g, 7.47–17.64 m2/g, and 0.005–0.015 cc/g, respectively. (4) All samples have a unimodal micropore size distribution with a distinct peak associated with a 1.5 nm micropore fraction and have a multimodal mesopore and macropore size distribution. Naturally deformed shales show more homogeneous pore size distribution curves with morphological consistency than undeformed shales, indicating that structural deformation can significantly influence pore structural heterogeneity. (5) Deformed shales exhibit higher porosity and permeability compared to the undeformed samples due to the open pore-fracture network associated with the inorganic pores and microfractures. Average porosity and permeability in deformed shales can be 1.8 and 15 times higher than those in the undeformed shales. We conclude that the microstructural heterogeneity from strong to weak and the changes of a relatively single organic pore-dominated pore system to complex pores and microfractures dominated the pore-fracture system within shales due to structural deformation being the key cause of the quantitatively and qualitatively studied microstructure and petrophysical property differences.

Fouling behaviours and mitigation in pressure-retarded osmosis processes with geothermal water/brine-based draw solutions

In this study, we examined pressure-retarded osmosis (PRO) performance using naturally high temperature NaHCO3-enriched geothermal water (i.e., capturing CO2 waste gas) and geothermal brine. The results showed that increasing draw solution temperature from 20 °C to 60 °C, NaHCO3-enriched geothermal water facilitated improving water flux (Jw) without compromising reverse salt flux (Js), leading to lower Js/Jw ratios compared to NaCl-based solution. With NaHCO3-enriched geothermal water (60 °C) as draw solution, periodically physical cleaning (clean water flushing with/without air sparging, osmotic backwashing) displayed ∼17 % lower permeability recovery ratio (p < 0.05), dissimilar foulant morphology and inorganic compositions compared to chemical cleaning (acid, base, NaClO); while the average permeability levels under both cleaning conditions were comparable (p > 0.05). However, the recovery ratio decreased with extending cleaning cycle, resulting in an almost comparable permeability to that without cleaning after 60-h operation. In addition, the presence of Ca2+ at 5 mM in the NaHCO3-enriched geothermal water (60 °C) led to more significant water flux drop and less reverse flux decrease compared to those with Ca2+ at 0 and 30 mM, possibly due to its dense fouling layer formed by smaller-sized CaCO3 precipitates. When geothermal brine (low or high salinity, pH = 3 or 9.7, 60 °C) was used as draw solution, it was noticed that (1) with low salinity brine, basic pH levels led to higher water fluxes; (2) with high salinity brine, the water flux was impacted by the ionic compositions of draw solutions, instead of pH levels.

Reservoir Characterization and an Integrated Approach of Reservoir Modeling for Miano Gas Field, Middle Indus Basin

The hydrocarbon-bearing formation of Miano gas field belongs to the Early Cretaceous and it is bounded by two shale intervals, which are considered as maximum flooding surfaces (MFS). The hydrocarbon-bearing interval includes two reservoir units: a tight gas reservoir and its overlying conventional reservoir. Core samples, borehole logs, and well production performance revealed that the two reservoirs present reversed trends in reservoir quality through the gas field without obvious barriers. The average shale volume of the tight gas reservoir changes from 24.3% to 12.2% and the average permeability changes from 32.65 mD to 0.02 mD from the south to north. However, the average effective porosity of the overlaying conventional reservoir increases from 20% to 26% and the average permeability increases from 10 mD to 300 mD. The reversed trends in the two reservoirs lead to challenges in production forecast and development well proposals in the tight gas reservoir. Therefore, reservoir characterization and a predictive reservoir model are essential for further exploitation of Miano gas field. The geological genesis analysis integrating cores, borehole logs, and three-dimensional (3D) seismic data reveals that the producing interval of the tight gas reservoir is tidal-influenced shore facies deposition with intergranular pore space reduced by mineral cementation during burial diagenesis, while the overlaying conventional reservoir is fluvial-influenced deltaic deposition with abundant, well-connected intergranular macropores, which leads to a better reservoir quality. A reservoir model containing both the tight gas reservoir and the conventional reservoir is constructed considering the reservoir nature understanding, and the accuracy of the model is confirmed by reservoir surveillance activities with the simulation model. The study will be critical to the further reservoir development and hydrocarbon production in Miano gas field.

Along-Strike Reservoir Development of Steep-Slope Depositional Systems: Case Study from Liushagang Formation in the Weixinan Sag, Beibuwan Basin, South China Sea

Seismic, core, drilling, logging, and thin-section data are considered to analyze the reservoir diversity in the east, middle, and west fan of the Liushagang Formation in the steep-slope zone of the Weixinan Sag, Beibuwan Basin. Three factors primarily affect the reservoir differences for steep-slope systems: (1) Sedimentary factors mostly control reservoir scales and characteristics and the drainage system and microfacies. Massive high-quality reservoirs have shallow burial depths. Channel development and sediment supply favor the formation of these reservoirs. The sedimentary microfacies suggest fan delta plain distributary channels. (2) Lithofacies factors primarily control reservoir types and evolution. The diagenesis of high-quality reservoirs is weak, and a weak compaction–cementation diagenetic facies and medium compaction–dissolution diagenetic facies were developed. (3) Sandstone thickness factors primarily control the oil-bearing properties of reservoirs. The average porosity and permeability of high-quality reservoirs are large, the critical sandstone thickness is small, the average sandstone thickness is large, and the oil-bearing capacity is high. Furthermore, the reservoir prediction models are summarized as fan delta and nearshore subaqueous fan models. The high-quality reservoir of the fan delta model is in the fan delta plain, and the lithology is medium–coarse sandstone. The organic acid + meteoric freshwater two-stage dissolution is developed, various dissolved pores are formed, and a Type I reservoir is developed. The high-quality reservoir of the nearshore subaqueous fan model is in the middle fan, and the lithology is primarily medium–fine sandstone. Only organic acid dissolution, dissolution pores, and Type I–II reservoirs are developed. Regarding reservoir differences and models, the high-quality reservoir of the steep-slope system is shallow and large-scale, and the reservoir is a fan delta plain distributary channel microfacies. Weak diagenetic evolution, good physical properties, thick sandstone, and good oil-bearing properties developed a Type I reservoir. The study of reservoir control factors of the northern steep-slope zone was undertaken in order to guide high-quality reservoir predictions. Further, it provides a reference for high-quality reservoir distribution and a prediction model for the steep-slope system.

Effective permeability of fractured porous media with fracture density near the percolation threshold

This study investigates the effective permeability of fractured porous media with fracture density near the percolation threshold. A new equivalent matrix-fracture network (EMFN) model was introduced, the code was used to efficiently deal with the huge number of modeling works for steady state flow in fractured porous media. The numerical model was verified by comparing with two previous seepage methods. We conducted a series of Monte Carlo simulations to explore the relationship between permeability discontinuity and three factors, namely fracture density, contrast between fracture and matrix permeability, and the scale of research domain. It was found that the effective permeability presents a bimodal distribution with specified fracture density in the transition regime. Each bimodal function can be subdivided into two well-fitting log-normal functions according to the percolation state to obtain analyzable average permeabilities. The results revealed significant differences between percolating and non-percolating configurations in the response to the change of each of the three factors mentioned above. More importantly, the finite-size effect plays an important role when fracture density is lower than or close to the percolation threshold; but this effect disappears gradually as the increase of fracture density. A stereoscopic approach is introduced to rationalize the scale effect.

Analysis of Channeling-Path Phenomena in a Complex Fault-Block Reservoir with Low Recovery Factor and High Water-Cut Ratio

Current methods for the analysis of channeling-path phenomena in reservoirs cannot account for the influence of time and space on the actual seepage behavior. In the present study, this problem is addressed considering actual production data and dynamic characteristic parameters quantitatively determined in the near wellbore area by fitting the water-cut curve of the well. Starting from the dynamic relationship between injection and production data, the average permeability is determined and used to obtain a real-time quantitative characterization of the seepage behavior of the channeling-path in the far wellbore area. For the considered case study (Jidong oilfield), it is found that the seepage capacity of the channeling-path in the far wellbore area is far less (10 times smaller) than that of the channeling-path in the near wellbore area. The present study and the proposed model (combining near wellbore area and far wellbore area real-time data) have been implemented to support the definition of relevant adjustment measures to ultimately improve oil recovery.

Kinetics of water sorption in single Sterculia and Bauhinia fibers at ambient temperature

Fundamental study on material properties of lignocellulose fiber is important to understand the performance of composite materials. In this study, we explored several material properties of untreated, commercial and wood ash alkali retted fiber obtained from relatively less studied and traditionally important wild plant species Sterculia villosa (local name Murgilo or Mudilo) and Bauhinia vahlii fibers (local name Bharlo). Water sorption kinetics in all fiber types was measured at ambient temperature. Fickian model then was used to fit experimental sorption kinetic data and information on diffusion coefficients at early and late stages of sorption, average diffusion coefficient, sorption coefficient, and water permeability were obtained. The average diffusion coefficient (D) for untreated, wood ash alkali and commercial alkali treated Sterculia was found to be 10.6 × 10-13 m2/sec, 3.08 × 10-12 m2/sec, and 2.35 × 10-12 m2/sec; respectively. The corresponding values for Bauhinia fiber were found to be 6.8 × 10-13 m2/sec, 3.80 × 10-12 m2/sec, and 3.46 × 10-12 m2/sec; respectively. The equilibrium water sorption in the alkali treated fiber was significantly reduced due to removal of cementing materials and also increase of crystallinity. Significant decrease in mechanical strength of fiber in sorbed state was found. These findings will be useful to understand stability of fiber and potential end products such as paper sheets and reinforced composite materials exposed under different moisture conditions.

Evaluation of Hydrocarbon Reservoir in the “SIMA” Field of Niger Delta Nigeria from Interpretation of 3D Seismic and Petrophysical Log Data

3D seismic and petrophysical log data interpretation of reservoir sands in “SIMA” Field, onshore Niger Delta has been undertaken in this study to ascertain the reservoir characteristics in terms of favourable structural and petrophysical parameters suitable for hydrocarbon accumulation and entrapment in the field. Horizon and fault interpretation were carried out for subsurface structural delineation. In all, seven faults (five normal and two listric faults) were mapped in the seismic section. These faults were major structure building faults corresponding to the growth and antithetic faults in the area within the well control. The antithetic fault trending northwest-southeast and the normal fault trending northeast-southwest on the structural high in the section act as good trapping mechanisms for hydrocarbon accumulations in the reservoir. From the manual and auto-tracking methods applied, several horizons were identified and mapped. The section is characterized by high amplitude with moderate-to-good continuity reflections appearing parallel to sub-parallel, mostly disturbed by some truncations which are more fault related than lithologic heterogeneity. The southwestern part is, however, characterized by low-to-high or variable amplitude reflections with poor-to-low continuity. Normal faults linked to roll-over anticlines were identified. Some fault truncations were observed due to lithologic heterogeneity. The combination of these faults acts as good traps for hydrocarbon accumulations in the reservoir. Reservoir favourable petrophysical qualities, having average NTG, porosity, permeability and water saturation of 5 m, 0.20423, 1128.219 kD and 0.458 respectively.

Petrophysical Analysis of Mars Field Offshore Dahomey Basin Nigeria

Petrophysical evaluation of the Mars Field in the Dahomey Basin, Nigeria was done to identify and analyze petrophysical properties of the reservoirs in the field. This was achieved by the use of 3 wells from the field. This research determines the lithology, shale volume (Vsh), porosity (Φ), permeability (K), fluid saturation. Two hydrocarbon-bearing reservoirs age from three wells were identified which was then subdivided into different levels in this research. The average permeability value of the reservoirs is 20.0140md while porosity value ranges between 18%-39%. Fluid types within the reservoir were identified to be Gas, Oil, Condensate and water based on the Neutron-Density log motif. The petrophysical analysis of the field reveals that reservoir porosity ranges from 11-26%, hydrocarbon saturation ranges from 0.07-0.91, water saturation ranges from 0.93-0.09, volume of shale ranges from 0.09-0.22 and net-to-gross ranges from 0.46-0.878. From this research it was identified that the prolific reservoir within the Dahomey basin is within the Turonian and Cenomanian reservoir with good quality reservoir and producible hydrocarbon saturation. Keywords:Dahomey/Benin Basin; Petrophysics; Volume of shale; Porosity; Water saturation; Potential reservoir; Turonian; Cenomanian.

Analysis and study of the migration pattern of microplastic particles in saturated porous media pavement

This work aims to establish an analytical and comparative model of pavement stormwater runoff and determine how to solve water pollution in saturated porous media pavements. Heavy metal element particles in the stormwater runoff due to the rainfall will cause inevitable environmental pollution. First, the pavement runoff and materials of saturated porous media are analyzed. Besides, particle migration laws and separation effects of different materials are compared. Based on this, microplastics are selected as the primary material for pavement filling. Then, the adsorption effect of microplastics and the parameters of rainwater infiltration rate and infiltration ratio are analyzed to propose a multi-level ecological integrated treatment system for pavement runoff. Specifically, the environmental resource pollution and saturated porous media materials are analyzed. In addition, the adsorption effect of microplastic particles is analyzed to establish a model to study the selection process of the optimal adsorption material. The main contribution of the research is to analyze the migration process of metal particles in the soil in combination with the internal particle migration rules of plastic granular materials. The research results demonstrate that the rain runoff coefficient gradually increases with the expansion of the permeable area of the pavement. The rain runoff coefficient reaches the maximum value under the pavement of 120 square meters. In addition, a comparative analysis of three street pavements is conducted on the residential street pavement (RSP), commercial street pavement (CSP), and active street pavement (ASP). When comparing the two sets of data, the overall average permeability of the RSP is better than CSP and ASP. The research materials are compared under isothermal conditions. The particle adsorption effect of the same material at 50 °C is significantly better than that at 30 °C. Therefore, it is feasible to resolve the pavement runoff water pollution through technical schemes.

A novel gas sands characterization and improved depositional modeling of the Cretaceous Sembar Formation, Lower Indus Basin, Pakistan

The Lower Indus Basin of Pakistan has substantial hydrocarbon potential with the Cretaceous Sembar Formation as its principal source rock. While studies have identified the shale gas potential of the Sembar Formation, no extensive research has been conducted to evaluate the hydrocarbon potential of thick packages of sands encountered within it. This study is intended to fill this research gap by identifying the hidden-untapped thick packages of sands of the Sembar Formation for the first time in the Khewari and Gambat areas. We use well log and seismic reflection data to define the thickness, depth distribution, and petrophysical properties for reservoir characterization. This integrated modeling identifies favorable zones for gas production and the spatial distribution of sand packages with excellent reservoir properties in thickness (≈200 m), almost continuous sand packages suitable for hydrocarbon exploration. The Suleman-01 well has a very good hydrocarbon reservoir potential with 70% sand volume, approximately 13% effective porosity, 3.57 millidarcys average permeability, and approximately 58–60% hydrocarbon saturation. We suggest that the post-collisional tectonics of the Indian and Eurasian plates affected the depositional geometry of the Sembar Formation in such a way that it trends from shallower to deeper from western to eastern parts of the study area. Similarly, reservoir quality sands follow the positive upward trend from west to east toward the Indian shield. We propose that the approach implemented in this study is applicable to the entire Lower Indus Basin and further toward the Rajasthan Basin in India in the east and Zagros fold-and-thrust belt in Iran in the west. This approach would help assess the undeveloped hydrocarbon potential of the Sembar Formation sands and related formations in South Asia and worldwide.

Pore Structure Characteristics and Permeability Stress Sensitivity of Jurassic Continental Shale of Dongyuemiao Member of Ziliujing Formation, Fuxing Area, Eastern Sichuan Basin

A shale condensate gas reservoir with a high clay content and a high formation pressure was found in the Jurassic shale of the Dongyuemiao Member in the Fuxing area of the eastern Sichuan Basin. Reservoir characteristics and formation pressure have a significant influence on optimal development. The present study investigated the continental shale of the Dongyuemiao Member in Well F. The petrological properties, physical properties, and pore structure of the Dongyuemiao Member were studied using X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), N2 adsorption, and mercury intrusion porosimetry (MIP). The permeability stress sensitivity characteristics of the shale reservoirs are discussed based on the change in shale porosity and permeability under overburden pressure. The tested shale samples yielded total organic carbon (TOC) and S1 + S2 values ranging mainly from 1.0 wt.% to 1.5 wt.% and from 0.39 to 2.28 mg/g, respectively, which was in the high maturity stage of the thermal evolution of organic matter (OM). The shales of the Dongyuemiao Member were found to contain high average clay mineral contents (more than 50%) of calcite and quartz, as well as albite, pyrite, dolomite, and halite. The main developments were identified as silica-rich argillaceous shale lithofacies, argillaceous shale lithofacies, and mixed argillaceous shale lithofacies. The pores were found to mainly be plate-like and flake-like interlayer pores of clay minerals and OM pores with various shapes. The pore size was mainly concentrated below 110 nm, and the pore volume increment increased in flakes with pore diameter. The average porosity and permeability of shale were found to be 4.827% and 0.243 mD, respectively. Clay minerals and quartz are beneficial for improving the porosity and permeability of reservoirs, while carbonate minerals have the opposite effect. The permeability of the shale showed a negative exponential change with increasing effective stress under overburden pressure. When the effective confining pressure was greater than 20 MPa, the decline rate of the shale permeability decreased with increases in the effective stress. The higher the clay mineral and TOC content, the stronger the stress sensitivity of shale permeability. The higher the carbonate mineral content, the weaker the stress sensitivity of shale permeability. The porosity sensitivity exponent indicates that matrix pores and micro-fractures are both developed in the Dongyuemiao Member, and the development of internal fractures is the main factor in the strong stress sensitivity of the shale permeability in the study area.

Induced microearthquakes predict permeability creation in the brittle crust

Predicting the evolution of permeability accurately during stimulation at the reservoir scale and at the resolution of individual fractures is essential to characterize the fluid transport and the reactive/heat-transfer characteristics of reservoirs where stress exerts significant control. Here, we develop a hybrid machine learning (ML) model to visualize in situ permeability evolution for an intermediate-scale (∼10 m) hydraulic stimulation experiment. This model includes an ML model that was trained using the well history of flow rate and wellhead pressure and MEQ data from the first three stimulation episodes to predict average permeability from the statistical features of the MEQs alone for later episodes. Moreover, a physics-inspired model is integrated to estimate in situ fracture permeability spatially. This method relates fracture permeability to fracture dilation and scales dilation to the equivalent MEQ magnitude, according to laboratory observations. The seismic data are then applied to define incremental changes in permeability in both space and time. Our results confirm the excellent agreement between the ground truth and model-predicted permeability evolution. The resulting permeability map defines and quantifies flow paths in the reservoir with the averaged permeability comparing favorably with the ground truth of permeability.

A novel approach for measuring membrane permeability for organic compounds via surface plasmon resonance detection

Well-known methods for measuring permeability of membranes include static or flow diffusion chambers. When studying the effects of organic compounds on plants, the use of such model systems allows to investigate xenobiotic behavior at the cuticular barrier level and obtain an understanding of the initial penetration processes of these substances into plant leaves. However, the use of diffusion chambers has disadvantages, including being time-consuming, requiring sampling, or a sufficiently large membrane area, which cannot be obtained from all types of plants. Therefore, we propose a new method based on surface plasmon resonance imaging (SPRi) to enable rapid membrane permeability evaluation. This study presents the methodology for measuring permeability of isolated cuticles for organic compounds via surface plasmon resonance detection, where the selected model analyte was the widely used pesticide metazachlor. Experiments were performed on the cuticles of Ficus elastica, Citrus pyriformis, and an artificial PES membrane, which is used in passive samplers for the detection of xenobiotics in water and soils. The average permeability for metazachlor was 5.23 × 10−14 m2 s−1 for C. pyriformis, 1.34 × 10−13 m2 s−1 for F. elastica, and 7.74 × 10−12 m2 s−1 for the PES membrane. We confirmed that the combination of a flow-through diffusion cell and real-time optical detection of transposed molecules represents a promising method for determining the permeability of membranes to xenobiotics occurring in the environment. This is necessary for determining a pesticide dosage in agriculture, selecting suitable membranes for passive samplers in analytics, testing membranes for water treatment, or studying material use of impregnated membranes.

Depositional Model for the Early Triassic Braided River Delta and Controls on Oil Reservoirs in the Eastern Junggar Basin, Northwestern China

The Triassic Jiucaiyuan Formation is a vital oil and gas exploration target in the eastern part of the Junggar Basin. In this work, cores, thin sections, particle sizes, and conventional physical properties were analyzed in order to understand the sedimentary characteristics and depositional model of the Jiucaiyuan Formation in the Beisantai Uplift and to clarify the factors controlling reservoir development. The results demonstrate that the Jiucaiyuan Formation can be divided into seven lithofacies, namely massive bedding gravel, massive bedding sandstone, trough bedding sandstone, plane bedding sandstone, wavy bedding sandstone, parallel bedding siltstone, and massive bedding mudstone. Braided river delta facies dominate the Jiucaiyuan Formation. Nine main subtypes of facies were observed: flood plain, braided channel above lake level, natural levees above lake level, braided channel under lake level, interdistributary bays, natural levees under lake level, mouth bars, prodelta mud, and beach bar. The braided channel under lake level, mouth bar, and beach bar reservoirs exhibited the best physical properties, with average porosities of 16.54%, 19.83%, and 20.41%, respectively, and average permeabilities of 3.43 mD, 9.91 mD, and 12.98 mD, respectively. The physical properties of reservoirs in the study area are mainly controlled by sedimentation. Braided channels under lake level, mouth bars, and beach bars are favorable facies for the development of high-quality reservoirs. The results of this study are expected to serve as a theoretical basis for further exploration and development of oil and gas in the study area.

Reasons for low flowback behaviors of water-based fluids in tight sandstone gas reservoirs

Water-based working fluids are widely applied in the development of tight gas formations. However, these fluids’ flowback rate is generally low than 50%, resulting in a large amount of water retention to dramatically decline the gas delivery. Typical tight sandstone core samples are selected in this study to perform the gas-driven water displacement experiment to investigate the underlying mechanisms for the low water flowback behaviors in tight gas reservoirs. Results show that the average water flowback rate for 15 tight sandstone samples by gas-driven water displacement is obtained to be only 31.31%, which in turn causes an average gas permeability damage rate of 58.94%. Analysis suggests that multiscale pore structures, ultra-low connate water saturation phenomenon, filling of hydrophilic clay minerals, and insufficient pressure drop contribute to the congenitally unfavorable geological factors of low water flowback capacity. On the other hand, irreversible formation damages like water phase trapping, salting out issues, and residual water film effect caused by water retention are the main elements that restrict water removal during a gas-flow drying process. The findings of this study provide useful insights into the control mechanisms of low water flowback behaviors and the formation damages induced by water invasion in tight sandstone gas reservoirs.