Unconventional Shale Reservoirs Research Articles

Optimization Method for Fracture-Network Design under Transient and Pseudosteady Conditions Using Unified-Fracture-Design and Deep-Learning Approaches

Summary In unconventional shale and tight reservoirs, the concept of stimulated reservoir volume (SRV) is used to correlate the volume of total injected proppant with well performance. The SRV configuration consists of primary fractures connected to the wellbore and secondary fractures intersecting primary fractures. SRV productivity is determined by fracture conductivity, fracture dimensions, and network complexity, which also vary with time. This work presents an extension of the unified-fracture-design (UFD) approach to account for not only the pseudosteady state (PSS) but also transient flow regimes and ultimately optimize SRV for maximizing well performance. A generalized productivity index (PI) for both the transient and PSS regimes is presented to improve well performance by searching for the maximum PI over time. In addition, a surrogate model is developed to accelerate the optimization. This study demonstrates that the UFD enables the determination of the optimal fracture network conductivity and complexity that contribute to the maximum PI with a given proppant volume. The optimal SRV design is time-dependent until the PSS is reached. The surrogate model not only improves the computational efficiency but also delivers high precision, which means far less computational burden than the traditional parametric-sensitivity analysis.

Machine learning prediction of methane, ethane, and propane solubility in pure water and electrolyte solutions: Implications for stray gas migration modeling

AbstractHydraulic fracturing is an effective technology for hydrocarbon extraction from unconventional shale and tight gas reservoirs. A potential risk of hydraulic fracturing is the upward migration of stray gas from the deep subsurface to shallow aquifers. The stray gas can dissolve in groundwater leading to chemical and biological reactions, which could negatively affect groundwater quality and contribute to atmospheric emissions. The knowledge of light hydrocarbon solubility in the aqueous environment is essential for the numerical modelling of flow and transport in the subsurface. Herein, we compiled a database containing 2129 experimental data of methane, ethane, and propane solubility in pure water and various electrolyte solutions over wide ranges of operating temperature and pressure. Two machine learning algorithms, namely regression tree (RT) and boosted regression tree (BRT) tuned with a Bayesian optimization algorithm (BO) were employed to determine the solubility of gases. The predictions were compared with the experimental data as well as four well-established thermodynamic models. Our analysis shows that the BRT-BO is sufficiently accurate, and the predicted values agree well with those obtained from the thermodynamic models. The coefficient of determination (R2) between experimental and predicted values is 0.99 and the mean squared error (MSE) is 9.97 × 10−8. The leverage statistical approach further confirmed the validity of the model developed.

Evaluating the impact of artificial maturation on the petrophysical and geochemical properties of unconventional shale formations by integrating dielectric and NMR measurements

This paper addresses challenges in characterizing unconventional shale reservoirs. For the first time, the nuclear magnetic resonance (NMR) and dielectric responses are integrated to characterize intact, saturated, and kerogen-rich subsurface shale samples at various maturation stages. The NMR and dielectric were measured separately using independent pieces of equipment, and all NMR and dielectric measurements were carried out at surface conditions. A comprehensive assessment is provided to address the changes induced by maturation through combined geochemical and petrophysical analyses. Shale samples from the Upper Cretaceous sequence of Jordan were characterized using Rock-Eval analysis, before and after maturation treatments. The total organic carbon (TOC) was decreased from 17.4 to 13.8 and 11.3 wt% and the pyrolyzed sulfur content was decreased from 3.32 to 0.25 and 0.15 3.18%, after maturing the samples at 250 °C for 1 and 5 days, respectively. The study employed NMR to track changes in pore structure via T2 relaxation time and measured dielectric properties and conductivity dispersion across frequencies from 10 MHz to 1 GHz using a wideband open-ended coaxial probe. After the maturation treatments, the dielectric constant of saturated shale samples doubled, and the conductivity increased by over three times. These changes in dielectric properties can be attributed to increased fluid-rock interfacial polarization and the formation of new pore spaces during maturation. NMR findings also indicated the emergence of a new pore system within the organic matter and the development of new fractures, resulting in a 6 to 12% increase in total porosity. The results obtained indicate that maturation-induced microstructural changes have a more significant influence on the dielectric responses than alterations on total organic carbon.

Geochemical and mineralogical characterizations of Silurian “Hot” shales: Implications for shale gas/oil reservoir potential in Jeffara basin-southeastern Tunisia, North Africa

The Silurian organic-rich hot shale deposits represent the origin of 80–90% Paleozoic sourced hydrocarbons on the entire Saharan Platform. As such, it is an area of significant interest for exploring its potential as an unconventional reservoir and gaining new insights into its properties. In this study, the geochemical and mineralogical analysis of eighty-two borehole samples from three studied wells (T, B, and M) located in Jeffara Basin, in southeastern Tunisa, distributed over a depth between 1200 m and 2200 m, show that the hot shale layer has significant potentials of an unconventional shale gas reservoir. According to the rock-eval and GCMS results, the total organic carbon (TOC) of the hot shale deposits is good to great, ranging between 0.54 wt% and 23.86 wt%, and the average hydrogen index (HI) is around ∼200 mg HC/g of TOC, which indicates that the hot shales were originally rich in type II/III organic matter (OM). The thermal maturity of the preserved OM is determined by the kerogen type with values varying from 0.4% to 1%, and Tmax values reaching 460 °C in T, B, and M wells which indicate that the hot shales preserved early mature to mature OM placed within oil/gas generation window. The calculated geochemical parameters reveal an average hydrocarbon generation potential (HGP) for the three studied wells of 20.37 kg HC/ton rock. In addition, the transformation ratios (TR) in T, B, and M wells are, respectively, 21.12%, 30% and 35.25%. However, only B and M wells show a cross-over layer, with oil saturation index (OSI) exceeding 100%, with significant potential as a hydrocarbon saturated source rock, making it a considerable target for unconventional oil exploration. Relevant results of Rock-Eval, biomarkers and XRD exhibit coherent features that reflect reducing marine conditions during the lower Silurian period. Moreover, the mineralogical composition was investigated to estimate the importance of frackable mineral fractions such as quartz (∼15%) and carbonates (calcite-dolomite). Mineral brittleness index (MBI) was calculated and compared to a well-known unconventional reservoir in the Neal shale member of the Floyd shale group in the Black Warrior Basin (US), which displays moderate to low MBI. The hot shales in the study area have a considerable MBI, which could be easily enhanced by hydraulic fracturing to liberate oil/gas from the potentially saturated unconventional shale reservoir.

Research Progress on the Microfracture of Shale: Experimental Methods, Microfracture Propagation, Simulations, and Perspectives

The fracture network generated by hydraulic fracturing in unconventional shale reservoirs contains numerous microfractures that are connected to macroscopic fractures. These microfractures serve as crucial pathways for shale gas to flow out from micro- and nano-scale pores, playing a critical role in enhancing shale gas recovery. Currently, more attention is being given by academia and industry to the evolution of macroscopic fracture networks, while the understanding of the microfracture mechanisms and evolution is relatively limited. A significant number of microfractures are generated during the hydraulic fracturing process of shale. These microfractures subsequently propagate, merge, and interconnect to form macroscopic fractures. Therefore, studying the fracture process of rock masses from a microscale perspective holds important theoretical significance and engineering value. Based on the authors’ research experience and literature review, this paper provides a brief overview of current progress in shale microfracture research from five aspects: in situ observation experiments of microfractures in shale, formation and evolution processes of discontinuous microfractures, the impact of inhomogeneity on microfracture propagation, measurement methods for microscale mechanical parameters and deformation quantities in shale, and numerical simulation of shale microfractures. This paper also summarizes the main challenges and future research prospects in shale microfracture studies, including: (1) quantitative characterization of in situ observation experimental data on shale microfractures; (2) formation and evolution laws of macroscopic, mesoscopic, and microscopic multi-scale discontinuous fractures; (3) more in-depth and microscale characterization of shale heterogeneity and its deformation and fracture mechanisms; (4) acquisition of shale micro-mechanical parameters; (5) refinement and accuracy improvement of the numerical simulation of microfractures in shale. Addressing these research questions will not only contribute to the further development of microfracture theory in rocks but also provide insights for hydraulic fracturing in shale gas extraction.

Comments: Unconventional Shale Reservoirs Meet Cancer Genome Sequencing

The cross-industry development and application of technologies is the epitome of innovation and ingenuity. The more divergent the industries are, the more the unique ways of thinking strike us as remarkable. Technology transfer between the oil and gas industry and other sectors isn’t new. Many examples can be found in medical science, space exploration, and renewable and sustainable technologies. In this JPT issue, the technologies of Oceaneering Space Systems and Impossible Sensing Energy are featured. A case study presented at the 2023 SPE Annual Technical Conference and Exhibition took medical science to a new low—into the depths of the Permian Basin for downhole reservoir drainage diagnostics (RDD). The coauthors, a subsurface and wells manager and a chapter manager, surveillance, analysis, and optimization and pilots at Chevron Technology Ventures (CTV), described using genome sequencing for cancer detection and treatment in a successful proof-of-concept (POC) test conducted from 2017 to 2019. Nampetch Yamali and Daniel Emery explained in SPE 215052 how in 2017 CTV was given the task of identifying technology to assess vertical drainage dimensions to estimate drainage volumes from fractured wells. The goal was to minimize interference from offset wells and co-developments to optimize reservoir recovery in unconventional fields. At that time, the technologies and their capabilities were limited. Although subsurface microbial DNA sequencing for upstream assets has found applications in enhanced biocide and corrosion inhibition, reservoir sweet spot indicators, and tracer technology, use of the technique was thought also to have potential in horizontal well development planning via RDD. Learning of a genomic sequencing technique for cancer cell identification in humans at the biology and biochemistry department at the University of Houston, the wheels started turning at CTV with thoughts it could be developed and adopted for RDD. Similarities were seen because RDD uses in-situ subsurface microbial DNA to infer the depths from which fluids drain after fracturing a horizontal well and optimizes well spacing on a pad, especially in stacked reservoirs. The predictive analytics platform mapped the hydrocarbon footprints of geologic subzones by using noninvasive DNA testing tools. The unique DNA markers for RDD were extracted from mud and cuttings from the horizontal and vertical drilling sections. DNA from produced fluids was also collected. The authors wrote, “Produced fluids collected at two-to-four-week intervals at the wellhead are mapped to the RDD framework. They are ‘lineage traced’ back to shale and tight rock. Drainage heights and percentage of contribution from these locations is computed adapting DNA sequencing and data analytics pipelines which were developed for lineage tracing cancer cells, breaking off from the primary tumor and metastasizing to distant sites back to the tissue of origin.” After validating the DNA extractions, CTV conducted a blind test using only the DNA data to determine the landing zones for each of the four wells in the pad. Using clustering methods, the results of the blind test accurately identified all landing zones within an acceptable margin, according to Yamali and Emery. The next step in the trial analyzed the DNA of the produced fluids. “Preliminary results showed drainage height estimates for each horizontal well.” In 2021, the study continued with an additional four new field trials in the Permian Basin for application of the technique to zonal production identification. The authors wrote, “Although the results from the POC were positive, subsurface DNA RDD technology is a novel technique within the oil and gas industry, and advanced applications are still evolving. This combination naturally gives rise to more general skepticism and a need to thoroughly evaluate the technology from operational, economic, and accuracy perspectives.” The paper describes the ongoing cross-disciplinary work being done by petroleum engineers, geologists, microbiologists, and stratigraphers to fully evaluate this method of RDD. It further details CTV’s wider approach to “accelerate the innovation life cycle, from pilot stages to widespread adoption at scale,” emphasizing the need for leaders’ support for nonconventional thinking and approaches. As the close of 2023 approaches, I’d like to take this opportunity to wish you the best in 2024 on behalf of the JPT Editorial Review Board and the JPT staff. We’ll be kicking off the new year with the commemoration of JPT’s 75th anniversary. Each issue will include an article dedicated to the evolution of technology and industry practices over the seven and a half decades JPT has covered the upstream industry. In January, Trent Jacobs and Stephen Rassenfoss will revisit technological advancements since JPT’s 50th anniversary in 1999. Since then, over 25 million B/D have been added to the global supply thanks in very large part to advancements in drilling, completions, and reservoir technologies. Join us as we explore these along with some predictions made 25 years ago and the surprising realities of where the industry stands today.

Long-term production forecast in tight and shale reservoirs: Adapting probability density functions for decline curve analysis

Decline curve analysis (DCA) is a popular method for predicting the production of oil and gas wells over time. It involves using historical data to match a mathematical function with the production data, which can then be used to forecast future production. However, DCA in unconventional tight and shale reservoirs poses unique challenges. Unlike conventional reservoirs, these unconventional reservoirs exhibit a production decline that is both faster and more erratic. This behavior, combined with the inherent complexities of the reservoir properties and fluid flow mechanisms, makes it challenging for traditional DCA models to provide accurate predictions of future production.This study proposes a new approach for forecasting long-term production in tight and shale reservoirs, using probability density functions (PDFs) that have been adapted and evaluated for this purpose. The PDF-based DCA models were tested against traditional DCA models using data from over 80 wells in different unconventional basins across North America.Results show that the PDF-based models outperformed the traditional models, with the Dagum and Beta prime models achieving the highest performance scores on various statistical measures, especially in wells with limited production history for model training. To ensure accuracy, appropriate statistical tests should be used to validate the PDF-based decline curve analysis, such as calculating the mean absolute error (MAE) or other relevant metrics.Our research introduces a novel method of adapting PDFs for decline curve analysis, specifically tailored for tight and shale reservoirs. This adaptation offers a more accurate and comprehensive prediction of future production by effectively capturing the inherent uncertainty and variability seen in unconventional reservoirs. One of the standout features of our proposed PDF-based approach is its versatility. Unlike traditional models that may struggle with erratic data, our models can seamlessly fit production data, whether it possesses peaks or not. This approach could be valuable for producers and investors who want to make informed decisions about drilling and production in unconventional reservoirs.

Controls on Barite (BaSO4) Precipitation in Unconventional Reservoirs.

Barite (BaSO4) precipitation is one of the most ubiquitous examples of secondary sulfate mineral scaling in shale oil and gas reservoirs. Often, a suite of chemical additives is used during fracturing operations to inhibit the accumulation of mineral scales, though their efficacy is widely varied and poorly understood. This study combines experimental data and multi-component numerical reactive transport modeling to offer a more comprehensive understanding of the geochemical behavior of barite accumulation in shale matrices under conditions typical of fracturing operations. A variety of additives and conditions are individually tested in batch reactor experiments to identify the factors controlling barite precipitation. Our experimental results demonstrate a pH dependence in the rate of barite precipitation, which we use to develop a predictive model including a pH-dependent term that satisfactorily reproduces our observations. This model is then extended to consider the behavior of three major shale samples of highly variable mineralogy (Eagle Ford, Marcellus, and Barnett). This data-validated model offers a reliable tool to predict and ultimately mitigate against secondary mineral accumulation in unconventional shale reservoirs.

Paleogeographic approach for the oil and gas potential assessment of the Khadum Formation (Lower Oligocene) in Pre-Caucasus basin

Authors used the paleogeographic approach to identify the different facies generation potential, mark out the areas with the highest organic matter and its types, analyse the reservoir quality for oil and gas potential assessment of the Pre-Caucasus basin Khadum formation. The greatest prospects in the Western and Central parts of the basin characterized by terrestrial and partly mixed organic matter types and are associated with the facies of the Sarpinsk-Armavir channel where discharge currents from the Volga-Don basin occurred. The same organic matter types can be related to clastic fans drawn from the north. In the Eastern part the main prospects are associated with unconventional black shale reservoirs with the predominantly aquatic organic matter, isolated on the top and base by the thick series of seal rock.

Environmental controls on trace-fossil distribution in the Upper Jurassic-Lower Cretaceous Vaca Muerta Formation (Argentina): Implications for the analysis of fine-grained depositional systems

Over the past years, the interest in organic-rich, fine-grained depositional systems has been growing due to the increasing relevance of unconventional shale reservoirs and several breakthroughs in the study of mud. However, the paleoenvironmental application of ichnologic analyses of these systems is still hindered by the scarcity of discrete trace fossils, small burrow size, and difficulty in obtaining fresh rock samples. The Upper Jurassic-Lower Cretaceous, Vaca Muerta Formation is the most important fine-grained unconventional reservoir in South America, and hence, contains a large density of cores that provide fresh cross-section views with detailed information on mudstone. An ichnologic analysis was carried out on cores and outcrop to develop an integrated ichnologic-sedimentologic model and to understand environmental controls on trace-fossil distribution. The Vaca Muerta Formation shows indistinct bioturbation represented by biodeformational structures generating irregular-laminated and massive mudstone fabrics, and discrete bioturbation and biodeposition structures mostly associated with tuff and heterolithic successions. Trace fossils were grouped into nine ichnocoenoses that illustrate organism responses to environmental controls. Abundant biodeformational structures in mudstone are associated with soupy substrates, whereas a change to softgrounds or loosegrounds occurs during coarser-grained sedimentation (associated with contourite drift, fluid mud flow, slope hemipelagic, and volcanic ash sedimentation), enhancing preservation of discrete traces. Locally, higher-energy events associated with exhumation of consolidated sediment generated firmgrounds colonized by the producers of the Thalassinoides isp. ichnocoenosis. In terms of oxygen, increased bioturbation index, penetration depth, burrow size, and ichnodiversity record an increase in bottom and interstitial water oxygenation. Moreover, an overall food-rich environment precluded specialized feeding and the development of tiered communities. The present study provides a clear picture of the relationship between substrate and oxygen controls in trace-fossil composition and distribution, contributing to the understanding of taphonomic controls and paleoecologic dynamics in fine-grained depositional systems, and providing an additional tool to refine sedimentologic and sequence stratigraphic analyses in similar mudstone successions elsewhere.

Unconventional shale gas potential of lower visean organic-rich formations in Glynsko-Solohivskyi petroleum region

Exploration of unconventional gas resources in Ukraine is highly relevant and important for achievement energy independence of Ukraine and Europe. Production of current oil & gas fields and alternative energy resources are not able to cover our needs nowadays. Now we can not fully fill these gaps by energy resources. In this article geological environments, age, mineralogy composition and maturity of unconventional shale and carbonate gas reservoirs of Lower Visean in one of the biggest field of Dnipro-Donets Basin (DDB) were studied. The hydrocarbon potential of two main target horizons V-23 and V-24-25 by using integrated approach of analyzing available core analysis data were performed. The results of the geochemical analysis show that the maturity level of shale of the Rudov beds (V-23) appear in oil window (Ro~0.8%) which can generate oil in the early mature phase. Visean carbonates (V-24-25) have the similar level of maturity - (Ro~0.77%). Target rocks are characterized by high total organic content (TOC): average values vary from 2% for organic-rich carbonates to 5.6% for shales which indicates relatively good to excellent source rock generative potential. According to X-ray diffraction analyses (XRD) of black shale formation domination of silica minerals (54.6%), calcite and clays (25.6%) with minor amounts of albite, feldspar and pyrite were observed. Carbonate platform V-24-25 logically is characterized by much higher calcite content of 52.2 % with low amount of dolomite – 5.5%. Quite high quartz content is also observed – average value is of about 30.7%. Clay minerals are not identified in every sample, but average values are of about 18.9%, pyrite content – 6.8%. It shows that Visean target formation of Glynsko-Solohivsky Petroleum region is characterized by anoxic environment. This data verified that V-23 and V-24-25 horizons are the brittle formations and favorable for multistage fracking. Thin section analysis confirms our results from mineralogical point of view. The presence of fractures in core samples is additional indicator for hydraulic fracturing and producing gas from such unconventional reservoirs. As a conclusion, the Lower Visean organic-rich formations V-23 and V-24-25 from Glynsko-Solohivsky Petroleum region are mature, are characterized by a high content of organic carbon, have enough thickness (30-120 m) and large areal extent. They should be regarded as a potential shale gas target.

Casing Leak Repair Allows Continued Hydraulic Fracturing

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212933, “Casing Leak Repair To Continue Hydraulic Fracture Stimulation,” by Gaston Oscar Ciminari, Gonzalo Cabo, SPE, and German Rimondi, Pluspetrol, et al. The paper has not been peer reviewed. _ The authors introduce a successful alternative for repairing casing failures on an unconventional well that allows hydraulic fracture continuity to accomplish the original fracturing plan, considering well-integrity conditions throughout the entirety of well production life as the main intervention objective. The resulting well production was higher than the expected estimated ultimate recovery (EUR) for the landing zone. Introduction In December 2020, during the execution of hydraulic fracturing on a three-well pad in the Vaca Muerta unconventional shale reservoir, an annular communication suddenly occurred in one of the wells. This event took place during the execution of the ninth fracturing stage of 33 planned. After a thorough pressure analysis of this event and verification that all pressure barriers were correct and in place, it was decided to stop fracturing treatments in this well and complete pending fracturing stages in the other two wells of the pad until the problem was well understood and a solution was found. Diagnostics The initial good condition of the well barrier was verified by a positive casing-integrity test (CIT) at 13,000 psi before the first fracturing pump. Maximum treatment pressure was kept under the CIT pressure, with an acceptable safety factor margin maintaining the well with annular communication, and was continuously pressure monitored. Once the fracturing fleet finished the intervention and left the pad, the engineering focus of the completion was oriented to determine the location and geometric characteristics of the casing leak. It was decided to start from the simplest to most-complex diagnostics interventions. The diagnostics interventions, and their results, are detailed in the complete paper. A bullheading pumping test was executed, and an increase in Section B pressure was observed. This showed clear communication between both sections. During circulation tests, it was observed that, by reducing pressure in Section B, Section A pressure response followed the pressure trend; opposite pressure changes in Section A, however, did not reflect on Section B pressure changes. Based on flow-test behavior, it was believed that a casing mechanical failure with a flow area of 0.044 in.2, equivalent to a 0.23-in. orifice, was the reason for the annular communication. With the aid of a coiled tubing (CT) unit and a bottomhole assembly (BHA) principally conformed with a multiple-set mechanical packer, it was possible to apply testing pressure below and above the packer seals at different depths to confirm the casing-leak position. A unique failure was located in the zone between 998 and 1002 m. A casing joint was located at 999.5 m; thus, it was assumed that a mechanical problem existed on this casing-joint connection. A wireline BHA composed of an injection-logging tool and a temperature sensor was used to reduce the zone of uncertainty. As a result of this log, the failure zone was located between 999.4 and 1000.4 m. The failure evidently was near the joint but not in it. Immediately after well-fluid changeout, the real-time downhole camera was run on wireline and showed what appeared to be a small hole 1 ft over the casing joint.

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.

Laboratory evaluation methods of water saturation in shales

The reservoir water content is one of the key parameters to following reliable hydrocarbon reserves estimation of low-permeable shale reservoirs with unconventional hydrocarbon reserves. The extensive review of applied direct and indirect laboratory methods for determining the water saturation in unconventional shale reservoirs is presented in this article. The essence, advantages, disadvantages and limitations of methods are described in detail. It was demonstrated that direct laboratory methods (retort method, Zaks, Dean–Stark) which were originally developed for traditional reservoir rocks, give results with an error of up to 50% for rocks samples of unconventional reservoirs. On the other hand the Evaporation Method specifically developed for low-permeable rocks takes less time and provides more accurate (error up to 6.8%) gravitational and bonded water determination moreover, it requires up to 5 times less rock material for analysis.

Influence of the bedding plane on the propagation of multiple hydraulic fractures

The presence of bedding planes (BPs) in unconventional shale reservoirs is common and widespread. BPs always affect fracture propagation. The objective of this study was to investigate the impacts of BPs on multiple hydraulic fracturing. The BPs were assumed to be perpendicular to the direction of the fractures. Based on the block distinct element method, we established a numerical model to simulate multiple fracture propagation in reservoirs with BPs. The model considered the fluid partitioning of multiple fractures and the fracture interaction by stress shadow. The numerical simulations clearly showed that the BPs reduced the non-uniform growth of multiple fractures. The results indicated that when hydraulic fractures met BPs, the BPs likely prevented the hydraulic fractures from passing through the formation with a smaller stress contrast. When hydraulic fracturing in a formation containing BPs, the key problem is how to reduce the obstructive effects of the BPs to increase the length of the main fractures.

An Improved Computational Learning-Based Model for Estimating Total Organic Carbon in Unconventional Shale Reservoirs

Unconventional resources have emerged as one of the crucial alternatives to the rapidly depleting of conventional hydrocarbon resources. The hydrocarbon potential of shale source rocks is assessed by the percentage of the organic index such as total organic carbon (TOC). Correct estimation of TOC is very important since minor deviations in anticipated results can lead to wastage of investments and time. A slight improvement in estimation practices, on the other hand, can increase the value of an exploration project. Therefore, the objective of this study is to present an improved classification and regression tree (CART) computational learning-based model as an improved alternative in estimating TOC from well logging data. Conventional well logs suite of bulk density, gamma-ray, deep resistivity, sonic transit time, spontaneous potential, and neutron porosity from Mihambia, Mbuo and, Nondwa, Formations of the Mandawa Basin Tanzania, were used as input variables. Results from the developed CART TOC model were compared with the random forest (RF) and backpropagation neural network (BPNN). It was observed that the proposed CART model trained better while generalizing better through unused testing data compared with RF and BPNN. CART model achieved R, RMSE, and MAPE values of 0.9615, 0.0840, and 0.5035 for training and 0.9703, 0.1162, and 0.3722 for testing respectively. The proposed model work with higher accuracy with the sensitivity analysis indicating that gamma-ray, deep resistivity, and sonic transit time significantly influenced the model outcome.

IN-DEPTH ANALYSES OF POSTHYDRAULIC FRACTURING PROCESSES IN UNCONVENTIONAL TIGHT RESERVOIRS

Hydraulic fracturing is the most widely used approach for unconventional tight or shale oil production. An appropriate postfracturing process usually refers to a certain shut-in period, which could be of critical importance to enhance ultimate oil recoveries. The shut-in period comprises processes of fluid filtration and spontaneous imbibition. In this study, the pressure decay characteristics during the fluid filtration process after hydraulic fracturing were studied. First, a pore-scale imbibition model with forced pressure was constructed on the basis of capillary model and fractal theory. Then, in addition to the theoretical model, coreflooding tests were performed in the core samples for optimizing the injection pressure difference with the assistance of low-field nuclear magnetic resonance (LF-NMR). Furthermore, the fluid filtration process was modeled and evaluated through another coreflooding test, which was conducted with declining injection pressure. It was found from the theoretical model and experiments that the synergistic effect of the displacement and capillary pressure was maximized for improving oil recovery with an optimized pressure difference of 5 MPa. Moreover, the pressure decay process was divided into fast-declining, transitional, and steady periods. The lab-scale shut-in time was determined to be 30 hours, which was exactly the time when the pressure decay reached the stable stage. This study will support the foundation of more general applications pertaining to hydraulic fracturing, especially fluid filtration processes in unconventional tight or shale oil reservoirs.

Megareservoirs of hydrocarbons are accumulation of giant by oil and gas deposits

The priority direction for the development of the oil and gas complex of Russia is the search for and development of giant oil and gas fields in terms of reserves, confined to natural megareservoirs of sedimentary strata. The article considers: conventional megareservoirs of oil and gas bearing basins (OGB), in which giant and unique oil and gas deposits are accumulated (on the example of the Pokur suite of Western Siberia); megareservoirs associated with commercial vanadium-bearing heavy oils and natural bitumen in unconventional reservoirs: bituminous sands in the province of Alberta (Western Canadian OGB), Permian natural bitumen in the Volga-Ural (Republic of Tatarstan) OGB, Cambrian bitumen in Eastern Siberia; megareservoirs of unconventional low-pore shale reservoirs. These accumulations of hydrocarbons (HC) can be considered megareservoirs: due to their vast areas and high saturation with kerogen. It is shown that accumulations of hydrocarbons in megareservoirs of shale formations, high-viscosity oils and natural bitumens accumulate ore concentrations of industrially valuable metals; an integrated approach to field development is economically in demand in the present conditions. Keywords: megareservoirs; collector; gigantic accumulations; oil and gas bearing basins; trace elements; natural bitumen; shale formations.

Geochemical characteristics of shale gas formation and the potential for carbon storage in Thailand: An example from the Triassic Huai Hin Lat Formation

An evaluation of the potential shale gas play and geological carbon dioxide (CO2) storage from the Triassic Huai Hin Lat Formation in Thailand was performed based on field observations and mineralogical and geochemical data. This study was mainly focused on mudstone samples in some parts of the Huai Hin Lat Formation. The samples can be divided into three groups based on their mineral compositions as follows: coaly mudstone, carbonate-siliceous mudstone, and carbonate mudstone. The brittleness index based on their mineral compositions indicates that the samples show ultra-high carbonate and quartz contents, which suggests a good hydraulic fracture candidate. Total organic carbon and extractable organic matter of the samples represents poor to excellent generation potential for hydrocarbon source rock with type III kerogen. The depositional environment shows that the Huai Hin Lat Formation occurs in anoxic to suboxic conditions in an aquatic depositional environment. The formation is suitable for geological CO2 storage, which may reduce CO2 during petroleum production and increase the production rate. Consequently, results from this study are useful for unconventional shale reservoir exploration and carbon storage technology in Thailand and adjacent countries.

Geological controls on the pore system of lacustrine unconventional shale reservoirs: The Triassic Chang 7 member in the Ordos Basin, China

The complex pore system of lacustrine organic-rich shales poses challenges to the assessment of shale oil and gas resources. To better understand the pore system and its controls of the lacustrine unconventional shale reservoirs, 12 oil mature shale samples with varying organic matter contents from the Triassic Chang 7 Member in the Ordos Basin were analyzed using elemental, petrographical, petrophysical, and fractal methods. The results showed that macro- and meso-pores are the main pore space in the lacustrine Chang 7 Shale. Pore diameter peaks are dominantly distributed around 0.7 and 37 nm. The intragranular pores in clays and intergranular pores between organic matter (OM) and minerals are well developed. Whereas the pores in OM are rarely observed. The fractal dimensions of the lacustrine shale's pore structure suggest that D2 is better than D1 in reflecting pore heterogeneity. OM shows negative effects on the total pore volume, while quartz promotes the development of macro- and meso-pores. Total pore volume shows an oscillation with clay mineral content (pore volume increases first up to 45% clay content and decreases thereafter). Both quartz and clays show negative effects on the heterogeneity of meso- and macro-pores, and positive effects on the micro-pore heterogeneity. A new critical maturity point of 0.8% Ro is observed for the change of the pore system of the lacustrine shale reservoirs during the early oil window. Both the fractal dimensions (D1 and D2) and pore structure proxies show the inverse trends before and after this critical value. These observations are probably controlled by the compaction processes coupled with hydrocarbon generation and expulsion, which helps better understand the pore system evolution in the lacustrine shales. The positive role of quartz, 45% clay mineral content and 0.8% Ro as the critical points contribute to the high-quality reservoir or sweet spot identification in lacustrine shales.