Shale Hydrocarbon Research Articles

Organic Matter of the Wufeng–Longmaxi Formation Shales Using Scanning Electron Microscopy

Fine-grained organic matter (OM) particles are commonly widely dispersed in shale deposits. However, carrying out investigations of pores hosted by OM particles and the nature of grain interactions in OM particles and associated detrital grains using optical microscopy is difficult at best. Scanning electron microscopy (SEM) is much better suited for characterizing the microstructure of dispersed OM particles and has found wide application in the study of unconventional oil and gas systems. Scanning electron microscopy was used to define the types of OM contained in marine shale deposits of the Wufeng and Longmaxi Formations spanning the Ordovician–Silurian transition in South China. Of particular interest was the development of OM-hosted pores and the identification of the factors that controlled their formation. The dominant OM type contained in the studied deposits is pyrobitumen, with subordinate graptolitic OM and sparse OM of unknown origin. Pyrobitumen is present in four forms, including pore fillings among authigenic quartz grains, within framboidal pyrite, and between authigenic clay grains and massive material. Diagenetic alteration has given rise to OM pores of differing morphology, size, and time of formation. Common small, equisized circular or oval OM pores are most developed and appear to have formed in association with the generation of hydrocarbons. Shale deposits containing abundant pyrobitumen filling interparticle pores among authigenic quartz crystals display robust reservoir and fracturing capacity. A sedimentary environment appears to have been the main factor affecting the type of OM and the nature of its association with detrital and authigenic minerals. Results of this study demonstrate that a sedimentary environment is a primary requisite for the formation of highly prospective/high-yielding hydrocarbon shale reservoir deposits.

Controlling factors and models of shale oil enrichment in Lower Permian Fengcheng Formation, Mahu Sag, Junggar Basin, NW China

Based on the combination of core observation, experimental analysis and testingand geological analysis, the main controlling factors of shale oil enrichment in the Lower Permian Fengcheng Formation in the Mahu Sag of the Junggar Basin are clarified, and a shale oil enrichment model is established. The results show that the enrichment of shale oil in the Fengcheng Formation in the Mahu Sag is controlled by the organic abundance, organic type, reservoir capacity and the amount of migration hydrocarbon in shale. The abundance of organic matter provides the material basis for shale oil enrichment, and the shales containing types I and II organic matters have good oil content. The reservoir capacity controls shale oil enrichment. Macropores are the main space for shale oil enrichment in the Fengcheng Formation, and pore size and fracture scale directly control the degree of shale oil enrichment. The migration of hydrocarbons in shale affects shale oil enrichment. The shale that has expelled hydrocarbons has poor oil content, while the shale that has received hydrocarbons migrated from other strata has good oil content. Lithofacies reflect the hydrocarbon generation and storage capacity comprehensively. The laminated felsic shale, laminated lime-dolomitic shale and thick-layered felsic shale have good oil content, and they are favorable lithofacies for shale oil enrichment. Under the control of these factors, relative migration of hydrocarbons occurred within the Fengcheng shale, which leads to the the difference in the enrichment process of shale oil. Accordingly, the enrichment mode of shale oil in Fengcheng Formation is established as “in-situ enrichment” and “migration enrichment”. By superimposing favorable lithofacies and main controlling factors of enrichment, the sweet spot of shale oil in the Fengcheng Formation can be selected which has great significance for the exploration and development of shale oil.

Geochemistry and mineralogy of the Upper Ordovician Wufeng formation, Southwestern China: Implications for Paleoclimate construction

Wufeng Formation shale is an important source rock of unconventional hydrocarbons in the Lower Paleozoic shales of Sichuan Basin. However, the study on its provenance and paleoclimate is still relatively limited. In this study, mineralogical and geochemical data of the shales from the Upper Ordovician Wufeng Formation in southwestern China has been used to interpret the provenance and conditions of weathering and paleoclimate. The Wufeng shales have intermediate to high SiO2 (57.72–82.38 wt. %, av. = 68.84 wt. %) and Al2O3 (5.26–16.17 wt. %, av. = 10.62 wt. %), are rich in transition metal elements (i.e. V, Ni, Cu, Co and Cr) and Y as well as moderate depletion in Na2O and Sr, relative to the concentrations of the upper continental crust (UCC). In the chondrite-normalized (CN) rare earth elements (REE) distributions, these rocks display light REE (LREE) enrichment (La/YbCN = 6.69–12.63, av. = 9.28), flat heavy REE (HREE) (Gd/YbCN = 1.35–2.41, av. = 1.70), and clearly negative Eu anomalies (Euan = 0.50–0.66, av. = 0.58), showing similar characteristics with the CN post-Archean Australian Average Shales (PAAS). Wufeng Formation shales are immature composition without evident recycling sediments, and they are originated from an intermediate-felsic igneous source composed of tonalite–trondhjemite–granodiorite (TTG), granitic and andesitic igneous rocks. The chemical weathering conditions of studied shales decreased from moderate to low in the provenance region, suggesting a gradual cooling trend of the climate at Late Ordovician Thus, this article will be helpful to discern the provenance and variations of chemical weathering conditions and paleoclimate of Wufeng Formation shales.

Pore Structure and Fluid Evaluation of Deep Organic-Rich Marine Shale: A Case Study from Wufeng–Longmaxi Formation of Southern Sichuan Basin

Deeply buried (>3500 m) marine shale has become a focus point for the future exploration and exploitation of shale hydrocarbon in China. Low-temperature nitrogen adsorption (LTNA), scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and other experiments were combined to characterize the pore structure and fluid division in deep-marine shale of the southern Sichuan Basin in this study. The results suggest that the deep-marine shale had a relatively developed nanopore network, especially with honeycomb organic pores. These organic pores were largely macropores with good connectivity in three-dimensional space and constituted the major reservoir space of the deep-marine shale gas. Microfractures were predominantly clay-mineral-related fractures, and the development degree of microfractures connected with organic pores was low, which contributed to the preservation of organic pores. Within the deep-marine shale interval, the pore volumes of Section 1 and Section 3 were higher. Pore volume was predominantly contributed by pores above 10 nm, where macropores accounted for a large proportion. Based on a combination of high-speed centrifugation and gradient temperature drying, the pore fluid of deep-marine shale reservoirs was quantitatively classified into four types: clay-bound fluid, capillary-bound fluid, free-flowing fluid, and closed-pore fluid. The clay-bound fluid existed in pores of less than 4.25 nm, which cannot be exploited. Quantitative division of the shale pore system could be realized by using the pore space differences of different types of fluids.

Effects of clay minerals and organic matter on pore evolution of the early mature lacustrine shale in the Ordos Basin, China

Pores related to organic matter and clay minerals provide significant storage space for hydrocarbons in organic-rich shales. However, the pore structure evolution and its related influencing factors at the early oil window stage are unclear. This study attempts to reveal the controls of organic matter and clay minerals on the pore structure of the lacustrine organic-rich Chang 7 Shale by using thin-section observational, organic petrological, elemental, scanning electron microscopy/Energy Dispersive Spectrometer (SEM/EDS) analyses, and mineralogical analyses combined with the pore structure characterization of gas adsorption and mercury injection capillary pressure (MICP). The results show that micropores (<2nm) and mesopores (2-50 nm) contribute to the main storage space in organic-rich intervals of the Chang 7 Shale. Organic matter content controls the development of micro-pores while no effects on porosity in the early mature lacustrine shale. Shrinkage OM pores related to the expulsion of hydrocarbons are better developed than the complex pores and sponge pores. Total clay content is correlated with mesopores volume in organic-rich lacustrine shale. Multiple stepwise linear regression model between mesopores volume and different clay minerals shows that the pores with diameters in the ranges of 2-5 nm are controlled by illite, chlorite, and kaolinite, and the pores with diameters in the ranges of 5-10 nm and 10-20 nm are controlled by illite, while 20-50 nm pores rely on illite/smectite mixed layer (I/S) and illite. Thermal maturity shows a positive effect on pore volume and porosity. There are three types of transformations of clay minerals in lacustrine shale, including the smectite-illite conversion, smectite-illite-chlorite conversion, and anorthite/albite-to-kaolinite/illite conversion. These clay mineral conversions all show positive effects on pore volume, especially the anorthite/albite-to-kaolinite/illite conversion, while the smectite-illite conversion shows some negative effects on the connectivity of the pore system. Additionally, the control of macropore volume, porosity, and pore throat radius by chlorite cannot be ignored. The findings from this study contribute to a clear insight into the pore structure evolution of lacustrine shale.

Effect of Formation Pressure on Pore Structure Evolution and Hydrocarbon Expulsion in Organic-Rich Marine Shale

Exploring the relationship between formation pressure and shale pore evolution is helpful for the enrichment and development of marine shale gas accumulation theory. The thermal evolution experiment was carried out on the Xiamaling Formation (Pr3x) lowly matured marine shale, which has a similar sedimentary environment to the Longmaxi Formation (S1l) highly matured marine shale. Comparative experiments of open and semi-closed pyrolysis and multiple pore structure characterization techniques, including CO2 and N2 physisorption, mercury intrusion porosimetry, and field emission scanning electron microscopy, were conducted. The marine shale pore evolutionary model under formation pressure is proposed by characterizing pore evolution, and hydrocarbon expulsion and retention for shales under and without formation fluid pressures. The results show that the existence of formation pressure increases the percentage of quartz and reduces the content of clay minerals. The change in formation pressure has no obvious effect on the maturity evolution of shale samples. With the increase of formation pressure, the pore morphology of shale gradually changes from narrow slit pores to ink bottle-shaped pores. The retained hydrocarbons in shale mainly occupy the mesopore space, and the existence of formation pressure promotes hydrocarbon expulsion, especially the hydrocarbon expulsion in the mesopore. In addition, formation pressure improves pore connectivity, especially in the high-over mature stage of shale. With the increase of formation pressure, the micropore volume decreases slightly, the mesopore volume increases significantly, and the macropore volume changes have two stages.

Interpreting the effects of shale rock properties on seismic anisotropy by statistical and machine learning methods

The elastic anisotropy of unconventional shale reservoirs plays a crucial role in their economic hydrocarbon production. The strong anisotropy of organic-rich shale rocks, characterized by clay platelets, elongated pores, and organic material, presents challenges for traditional reservoir characterization methods, which are designed for isotropic or weakly anisotropic conventional sandstone reservoirs. To effectively describe the geomechanical behaviors of organic-rich shales and estimate changes in stress caused by hydraulic fracturing, it is necessary to develop practical methods for predicting anisotropy parameters from conventional rock property logs. This study proposes a statistical approach for predicting independent elastic stiffness coefficients for vertically transverse isotropic (VTI) shale from three shale rock properties: clay volume fraction, kerogen volume fraction, and total porosity. The results of this study show that the stiffness coefficients, C11 and C33, are related to P-wave anisotropy and porosity has a greater impact on P-wave anisotropy than clay and kerogen volume fractions. In contrast, changes in clay volume have a more sensitive effect on C44 and C66, providing S-wave anisotropy information that can help detect lithology changes. Furthermore, kerogen variation has a greater influence on both C12 and C13 than the effects of porosity and clay variations. From these relationships, we develop exponential nonlinear regression (ENLR) models for predicting independent elastic stiffness coefficients from three shale rock properties. These models are validated with the Midland Basin log data, and we improve the accuracy of the C13 estimation model using the deep feedforward neural network (DFNN) method. The results show that the statistical approach can help understand the effect of shale rock components on seismic anisotropy variations and better predict the variations in lithology, fluid, and organic contents in shales from anisotropic seismic data. Furthermore, the methodology can provide robust estimates of the stress changes from hydraulic fracturing, supporting the efficient and economically viable production of shale hydrocarbons.

Wettability of different clay mineral surfaces in shale: Implications from molecular dynamics simulations

Shale contains a lot of clay minerals. Clay minerals mainly exist in nano- and micro-meter sized particles, and the pore structure is complex, which leads to its extremely complex wettability. The surface wettability of clay minerals significantly affects the oil and gas-bearing capacity of shale reservoirs. Therefore, studying the wettability of common clay minerals in shale at the nanoscale is of great significance for shale hydrocarbon exploration and development. In this study, the wetting behavior of water in n-hexane and toluene on different clay mineral surfaces at the nanoscale was systematically studied using Molecular dynamics (MD) simulation. And the influencing factors of wettability were analyzed. Through the analysis of the morphological changes of water, relative concentration of water, RDF and interaction energy, it is concluded that the following order of water wettability on the surfaces of clay minerals: montmorillonite > chlorite > kaolinite > illite. Through the analysis of interaction energy, it is concluded that the hydrophilicity of four clay minerals is stronger than that of lipophilicity. And the main interactions between water and oil and the mineral surfaces were van der Waals force and electrostatic force. In addition, the temperature, liquid hydrocarbon type, and mineralization of water affected the wettability of clay minerals. The concentration of water on the surfaces of montmorillonite, kaolinite, and illite decreased with increasing temperature, and the water wettability decreased. At 298 K, the hydrophilicity of the surfaces of the clay minerals in toluene follows the order montmorillonite > chlorite > kaolinite > illite. The higher the NaHCO3 concentration in water, the weaker the wettability of the clay mineral surfaces to water. By comparing the previous experimental results with the MD simulation results, similar wetting characteristics were obtained, and the reliability of the simulation results was verified. MD simulation was used to explore the water wetting of the surfaces of four clay minerals in a shale reservoir from the micro level. This makes up for the lack of experimental means for clarifying the flow and production mechanisms of shale oil and gas and effectively improves the evaluation technology of shale.

Thermal and nonthermal effect of microwave irradiation on the pore microstructure and hydrocarbon generation of organic matter in shale

In situ heating conversion is the most effective means to develop medium-low maturity shale oil. Herein, the effects of microwave irradiation on the shale pore structure and hydrocarbon generation of organic matter were studied using an independent development microwave device in combination with Rock-Eval, Leco analysis, X-ray diffraction, field emission scanning electron microscopy, low-temperature N2 adsorption/desorption, nuclear magnetic resonance, Fourier transform infrared spectroscopy and kinetic simulation of hydrocarbon generation. The results show that microwave irradiation can effectively heat shale and the temperature can rise to hundreds of degrees Celsius in a short time (10 min), with 400 °C as the best temperature for in situ conversion of medium-low maturity shale, at which the pore volume and surface area reach the maximum. Microwave irradiation is conducive to pyrolysis and hydrocarbon generation of aliphatic structure in shale organic matter. There are differences in the response of different organic components to the nonthermal effect of microwave irradiation, which reduces the activation energy of hydrocarbon generation during organic matter pyrolysis. Heating shale by microwave irradiation can effectively promote organic matter pyrolysis and hydrocarbon generation, improve rock reservoir and seepage capacity, and is of great significance for the efficient development of shale oil.

Distribution and occurrence of pore water and retained oil in nanopores of marine-terrestrial transitional shales during oil generation and expulsion: Implications from a thermal simulation experiment on shale plug samples

The distribution and occurrence of pore water and retained oil in shale nanopores is a key scientific issue confronting the evaluation, exploration and development of shale hydrocarbon resources. At present, however, relevant researches are scarce, especially on marine-terrestrial transitional (MTT) shales. In this study, a thermal simulation experiment was performed on a set of water-saturated shale plug samples prepared from a low-maturity MTT shale. The pore water and retained oil contents of the artificially matured samples were quantified, and the pore structures under moist, dried, and solvent extracted conditions were investigated. The results show that the pore water content of the shale decreases with Ro increasing from 0.75% to 0.97% and then increases with Ro further increasing to 1.53%, which exhibits a negative correlation with the retained oil content during the oil generation and expulsion. The pore water occurs mainly in filling, adsorption and water-cluster states in micropores (<2 nm), small non-micropores (2–10 nm), and large non-micropores (>10 nm), respectively. The retained oil is mainly in a filling or dissolved state in the micropores and small non-micropores and in an oil-cluster state in the large non-micropores. The pore water and retained oil in shale micropores are stored in the inorganic matter (IM) and organic matter (OM) micropores, respectively. During oil generation and expulsion, the IM micropores are fully saturated by the pore water that is barely expelled, and most of the pore water is stored in non-micropores, especially in large non-micropores. With increasing maturity, the distribution of retained oil in nanopores changes obviously. The retained oil in non-micropores tends to be stored in the large non-micropores at low-maturity stages, occurs uniformly in both the small and large non-micropores at mature stages, and is dominantly reserved in the small non-micropores and micropores at high-maturity stages. These results have significances for understanding the accumulation mechanism of shale oil and gas resources under geological conditions and evaluating their resource potential.

Estimating Geophysical Parameters Using Petrophysical Algorithm to Enhance Hydrocarbon Recovery in Lokaka Field, Niger Delta, Nigeria

Adoption of Enhanced Oil Recovery (EOR) to boost the hydrocarbon saturation (Sh) of reservoirs has caught the interests of many researchers in Geosciences. Evidence from literature shows that both primary and secondary recovery methods have failed to account for about 60% hydrocarbon (HC) that is trapped in the reservoirs and getting to discover large productive new fields has become a herculean task. This study identified the fluid nature and boundaries of reservoirs using some relevant geophysical (petrophysical) parameters and reservoir rocks physical features such as shale volume (Vsh), permeability (K), water and hydrocarbon saturation (Sw&amp; Sh). Petrophysical data were sourced from the data bank of the Department of Geology, Obafemi Awolowo University, Ile-Ife, Nigeria. Analysis of data was done using the PETREL 2010 and OpendTect 4.6.0 versions for quality checking, delineation of identified reservoirs, fluid contacts demarcation and fluid types’ determination. The interpreted data were thereafter loaded into Microsoft Excel environment in order to adopt suitable statistical relations for the estimation of Vsh, K, Sw and Sh. Exploration of about 59.4% HC with NaOH, 64.5% HC with KOH, 69.5% HC with NH4OH and 78.5% HC with LiOH were discovered after the (EOR) flooding process. Comparison of the Vsh, K, Sw and Sh values before EOR with the values after EOR further showed that the reservoirs produced more HC with EOR. This study concluded that more hydrocarbon saturation can be achieved from reservoirs when EOR is carried out.

Depositional Environment and Hydrocarbon Distribution in the Silurian–Devonian Black Shales of Western Peninsular Malaysia Using Spectroscopic Characterization

The present study aimed to evaluate the hydrocarbon functional groups, aromaticity degree, and depositional environment in the Silurian–Devonian Kroh black shales of western peninsular Malaysia. Fourier transform infrared spectroscopy (FTIR) was applied to measure the hydrocarbon functional groups in the sedimentary succession and associated organic matter of the black shale samples. The results showed that aromatic C=C stretching, aromatic C-H out-of-plane, aromatic C-H in-plane, and aliphatic =C–H bending are the major hydrocarbon functional groups in the Kroh shales. Also, ultraviolet-visible spectroscopy (UV-Vis) was used to evaluate the type of humic substance and analyze the sample extract ratios of E4/E6. It was revealed that the methanol-treated Kroh shale samples ranged from 0.00048 to 0.12 for E4 and 0.0040 to 0.99 for E6. The lower E4/E6 ratio (&gt;5) indicates the dominance of humic acid over fulvic acid in the Kroh shales. The Kroh shale samples’ total organic carbon content (TOC) ranges from 0.33 to 8.5 wt.%, analyzed by a multi-N/C 3100 TOC/TNb analyzer. The comparison study revealed that the TOC content of the Kroh shale has close obtainable values for the Montney shales of Canada. Furthermore, both hydrocarbon functional groups from FTIR, and the E4/E6 ratio from UV-Vis show no correlation with TOC content. It is revealed that humic acid, aromatic, and aliphatic hydrocarbons are not the controlling factors of the enrichment of organic matter in the Kroh shales. Conversely, a positive correlation between aliphatic and aromatic hydrocarbons in the Kroh shales indicated that organic matter is thermally overmatured. The presence of humic acid and enrichment of aromatic hydrocarbons in the Kroh shales demonstrated that the organic matter in these shales contains plant-derived hydrophilic minerals, i.e., terrestrial in origin. These findings may provide clues on the depositional and thermal maturation of organic matter for the exploration efforts into the pre-Tertiary sedimentary successions of the peninsular.

Rock physics analysis from predicted Poisson's ratio using RVFL based on Wild Geese Algorithm in scarab gas field in WDDM concession, Egypt

Some of the important rock physics parameters, such as the shear-wave velocity and Poisson's ratio, are conventionally calculated from compressional and shear sonic well logs. Although these parameters are vital for geomechanical purposes, these types of shear sonic logs are rarely recorded for most wells. Therefore, this study aims to use ordinary well log and seismic data to predict the Poisson's ratio using some of the machine learning algorithms that are based on a proposed model calculated from a modified version of the Random Vector Functional Link (RVFL) using the Wild Geese Algorithm (WGA). This is applied as a case study in the Scarab gas field in the West Delta Deep Marine (WDDM) concession, Egypt. The main aim of using WGA is to determine the best configuration from the parameters of RVFL to enhance the process of prediction. The rock physics templates are used for interpreting the lithology and pore-fluid from well log data and RVFL-WGA. This is achieved using the cross-plot of P-impedance versus Poisson's ratio, Lambda-Rho versus Mu-Rho, Poisson's ratio versus bulk modulus and P-impedance versus Vp/Vs ratio from both methods. All cross plots are color-coded by the shale volume and hydrocarbon saturation.

Origin of microbial–hydrothermal bedded dolomites in the Permian Lucaogou Formation lacustrine shales, Junggar Basin, NW China

Dolomite is widely developed in the shale sequences of saline lakes and has significance in paleoenvironmental, paleoclimatic, and petroleum geology research. In this study, a new end-member type of dolomite is discovered from the Permian Lucaogou Formation in the Junggar Basin, northwest China, along with its geological significance. The microbial–hydrothermal origin of the bedded dolomite is evident from the development of hydrothermal minerals (including barite and cubic pyrite) and methanogenic micro-organisms. In terms of geochemistry, the bedded dolomite has high (Ba/La)N ratios (~2.8) and Sr contents (~594.9 ppm) and positive Sr anomalies (Sr/Sr* ~3.8). Chondrite-normalized rare earth element (REE) patterns exhibit light REE enrichment, heavy REE depletion, slightly positive Ce anomalies, and negative Eu anomalies. The bedded dolomite has relatively low 87Sr/86Sr ratios (~0.705283), high δ13C values (~6.63‰ ), and low δ18O values (~−9.92‰ ). All these indicate that the dolomitizing fluid is a mixed source of hydrothermal fluids and lake waters, and the hydrothermal fluids and microbial methanogenesis provided the Mg2+ and C, respectively. The combination of microbial and hydrothermal activity overcame the limitation of dolomitization hydration shells around Mg2+. In terms of geological significance, the studied Lucaogou Formation was deposited in an extensional tectonic setting under hot–arid climatic conditions, which controlled the high-frequency interbedding and meter-scale cyclicity of sediment deposition of dolomites and shales. The combined effects of tectonism and paleoclimate may be important factors for the formation of bedded dolomite, enrichment of organic matter and hydrocarbons in saline lacustrine shales.

Deviation from Darcy Law in Porous Media Due to Reverse Osmosis: Pore-Scale Approach

Shale and tight hydrocarbons are vital to global energy dynamics. The fluid flow in sub-micron pores of tight oil reservoirs varies from bulk fluid flow. The Darcy law is widely accepted to model creeping flow in petroleum reservoirs. However, traditional reservoir modeling approaches fail to account for the sub-micron mechanisms that govern fluid flow. The accuracy of tight oil reservoir simulators has been improved by incorporating the influence of sub-micron effects. However, there are still factors that affect sub-micron fluid mobility that need investigation. The influence of a chemical potential gradient on fluid flow in sub-micron pores was modeled by solving Darcy and the transport and diluted species equations. The findings indicate that when a chemical potential gradient acts in the opposite direction of a hydraulic pressure gradient (reverse osmosis), there exists a limiting pressure threshold below which a non-linear flow pattern deviating from the Darcy equation is observed. Furthermore, the simulation based on tight reservoir pore parameters shows that when the effect of a chemical potential gradient is added, the resultant flux is 8–49% less. Hence, including the effect of the chemical potential gradient will improve the accuracy of sub-micron pressure dynamics and flow velocity.

Reservoir characteristics and light hydrocarbon channeling revealed by production data: A case study of liquid rich Duvernay shale play with emphasis in Fox Creek area, Alberta Canada

This paper reports the findings on the major factors affecting the hydrocarbon productivity and ultimate resource recovery from the liquid-rich Duvernay Shale play in the Fox Creek area. Essential drilling and completion parameters, production rate, estimated ultimate reserves from monthly production time series and key geological variables were mapped and combined with statistical data analysis to reveal their spatial variation and statistical relationships among these parameters and variables. We found that fluid type of the hydrocarbons in shales is essential for hydrocarbon productivity and estimated ultimate recovery (EUR) in this area. Although production rate and EUR are proportional to measures of hydraulic treatment, not all the completion parameters are equally effective in enhancing productivity and recovery. Fracking water volume seems to boost productivity and recovery the most. Parameters from organic geochemistry and geology are essential for mapping the boundary of the resource play, and determining the hydrocarbon fluid types and their spatial variations. And high positive correlation of HCPV with monthly average production rate and EUR indicates the importance of those geological factors for the productivity and ultimate recovery of the study area. Gas-to-oil ratio (GOR) mapping from produced fluids in the first 12 months reveals high anomalous GOR channels or linear zones in low maturity areas that are inconsistent with thermal maturity trends spatially, indicating intra-formation migration of hydrocarbon fluids in the source rock along permeable networks. Major earthquake swarms induced by hydraulic fracturing appear to be associated with crossing formation faults, and are spatially coincident with reduced productivity and ultimate recovery in de-pressured reservoir spot. These findings provide insights to better understand the distribution of production sweet spots and for production optimization strategies to facilitate a low carbon energy transition.

Reservoir Characterization of Eocene Carbonates of Central Indus Basin, Pakistan

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

Dynamic Accumulation of the Quaternary Shale Biogas in Sanhu Area of the Qaidam Basin, China

Biogas resources in the Sanhu area of the Qaidam Basin have great potential, but there are few studies on biogas from shale, especially on the accumulation conditions of shale biogas. The study of biogas accumulation conditions of quaternary shale in the Sanhu area is of great significance to the theory of biogas accumulation and the guidance of exploration and development. This paper takes Quaternary shale in the Sanhu area as the research object. It is analyzed from multiple perspectives of shale hydrocarbon generation conditions, reservoir conditions, as well as hydrodynamic and structural conditions. Through the experiments of soluble organic carbon analysis and porosity and permeability analysis, the accumulation conditions of shale biogas reservoirs are clarified. The results show that the quaternary shale has a high soluble organic carbon content and high salinity formation water, which is conducive to late methane biochemical generation. Quaternary shale has the characteristics of high porosity and low permeability, mainly developing intergranular pores and intragranular pores. The large pore volume and specific surface area provide a lot of storage space for free gas and adsorbed gas, and the reservoir conditions are good. Under the structural characteristics of high in the south and low in the north and the action of formation hydrodynamics, biogas migrated from the south and deep to the north of the basin. The north slope is the main biogas-rich zone. On the whole, the quaternary shale in the Sanhu area has the characteristics of continuous hydrocarbon generation and dynamic accumulation, which has huge resource potential and exploration and development value.

Enhancing Characterization of Reservoirs Within the Niger Delta Basin Using Integration of Seismic and Well Logs

This research utilized well logs and seismic to unravel the reservoir architecture of a field within the offshore depolbelt of Niger Delta. Gamma ray and resistivity log responses were used for lithology and hydrocarbon reservoirs identifications. The principle of similarity in log signatures was used for correlation across the three studied wells. Pertinent reservoir parameters such as shale volume, effective porosity, permeability, hydrocarbon saturation and water saturation were calculated using well-established equations consistent with the geology. Seismic structural interpretation that will give insight to deformation of the field involves the identification and mapping of faults and horizons from seismic sections. By integrating information from seismic and wells, 3D geological modelling was done using geostatistical methods of Sequential Gaussian Simulation and Indicator. The general stratigraphy of the studied field comprises of intercalation of sands and shales which is typical of Agbada formation. Three reservoirs designated as AA, BB and CC were identified and mapped. Only reservoir CC was laterally continuous across the three wells. Reservoir AA has average shale volume of 13%, effective porosity 26%, hydrocarbon saturation 46% and permeability 1328 mD. Reservoir BB has shale volume of 10%, effective porosity 28%, hydrocarbon saturation 43% and permeability 1616 mD. Reservoir CC has shale volume of 21%, effective porosity 20%, hydrocarbon saturation 89% and permeability 580 mD. Twenty faults comprising of both major and minor faults were mapped. The faults mapped were majorly normal faults. The result of the seismic structural interpretation shows that the probable structures harboring oil and gas are a combination of four-way closure and fault assisted anticlinal structures. The modelling of facies and petrophysical parameters into maps aided the understanding of parameter’s influence on oil and gas production. Reservoir CC has oil and gas in commercial quantities with 2520 MMcf and 622Mbbls respectively. The result shows the reservoir has high performance system and is therefore recommended for development and production. The resulting models will aid placement of production wells and monitoring of future performance of the reservoirs.

Application of machine learning algorithms in predicting pyrolytic analysis result

Introduction. Geochemical studies of organic matter in oil source rocks play an important role in assessing oil and gas accumulation in any territory. These studies play a particularly important role in forecasting unconventional resources and oil and gas reserves (so-called shale hydrocarbons). It is recommended to carry out pyrolytic studies by the Rock-Eval method for rocks saturated with organic matter on samples before and after their extraction with chloroform. However, extraction is a laborious and time-consuming process, and the load on laboratory equipment and the time required for analysis is doubled.Aim. To get a working model for predicting pyrolytic parameters of extracted samples, without carrying out extraction analysis.Materials and methods. In this paper, machine learning regression algorithms are applied for predicting one of the pyrolysis parameters of extracted samples based on the pyrolytic analysis results of the extracted and non-extracted samples. To develop the prediction model, 5 different machine learning regression algorithms were applied and compared, including multiple linear regression, polynomial regression, support vector regression, decision tree, and random forest.Results. The prediction result showcases that the relationship between the parameters before and after extraction is complex and non-linear. Some methods have shown their incompatibility with the assigned tasks, others have shown good and satisfactory results. Those algorithms can be applied to predict all geochemical parameters of extracted samples.Conclusions. The best machine learning algorithm for this task is the Random forest.