Unconventional Shale Research Articles

Developing an efficient ester-based drilling fluid based on Calophyllum Inophyllum oil for eco-friendly drilling of unconventional shale formation

The ester-based drilling fluids has been emerged as an alternative to diesel and mineral oil-based drilling fluids and are preferred due to their high biodegradability and low toxicity. In this research study, a novel environment-friendly ester-based drilling fluid has been developed from non-edible vegetable oil. The crude oil extracted from Calophyllum inophyllum seed is transformed into Calophyllum inophyllum methyl ester through two-step esterification and transesterification processes. The physiochemical results suggest the successful synthesis of methyl ester having significantly low kinematic viscosity and higher flashpoint. The Calophyllum inophyllum methyl ester is used as a continuous phase for the formulation of ester-based drilling fluid. A comprehensive experimental study is carried out to evaluate the performance of formulated ester-based drilling fluid at ambient and reservoir conditions. The drilling fluid is examined for its rheological behaviour, filtration characteristic, electrical stability, and viscoelastic properties. The formulated drilling fluid display efficient performance with improved rheological characteristics, reduced filtration loss, high emulsion stability, and enhanced viscoelastic properties. The drilling fluid also performs well at high-temperature conditions and meets the API requirements. The flow behaviour and rheological modelling of drilling fluid are investigated at varying temperatures (25–100 °C) and shear rates (0.1–1200 s−1). The obtained results affirm the non-Newtonian and shear-thinning behaviour of the drilling fluid. The shear-thinning behaviour is quantified using the Herschel–Bulkley model. Oil-based drilling fluid is formulated and tested for comparison. The ester-based drilling fluid exhibit satisfactory rheological characteristics with better filtration and emulsion stability compared to the oil-based drilling fluid. The results exhibit that the formulated drilling fluid can be a viable technical and environmental alternative to diesel and mineral oil-based drilling fluids.

Pore types, genesis, and evolution model of lacustrine oil-prone shale: a case study of the Cretaceous Qingshankou Formation, Songliao Basin, NE China

A comprehensive characterisation of the pore structure in shale oil reservoirs is essential for forecasting oil production and exploration risks. This study forecasted these risks in the oil-rich Songliao Basin using combination of high-resolution field emission scanning electron microscopy and quantitative X-ray diffraction to analyze the pore genesis and evolution mode within the first member of the Cretaceous Qingshankou Formation (K2qn1). The results showed the dominance of inorganic pores over organic pores, wherein diagenetic processes, such as compaction, pressure solution, and cementation, were responsible for the destruction of pore structure in the formation. Notably, the pores formed by dissolution and shrinkage cracks resulting from clay mineral transformation improved the oil storage space. Furthermore, according to the geochemical data and clay composition, the K2qn1 shale is in the middle diagenetic stage A, which can be further subdivided into A1 and A2 stages from top to bottom. The porosity slowly decreased in both sub-stages A1 and A2, wherein the decrease was stable in the latter. The diagenetic observations in this study are significant for the exploration of unconventional shale oil in petroliferous basins worldwide.

Evaluating Stimulation Effectiveness with Permanent Optical Fiber and Sealed Wellbore Pressure Monitoring: Bakken Shale Case Study

Summary In 2019, the operator embarked on a data acquisition project in the Bakken, an unconventional shale play in the USA, with the goal of mapping far-field drainage and characterizing completion performance. The project consisted of a six-well pad (10,000-ft laterals) with a dedicated observation lateral located in the Three Forks formation instrumented with cemented pressure gauges and external optical fiber along the 10,000-ft lateral. The observation lateral was offset by Middle Bakken (MB) wells ~450 ft on either side (~900-ft MB-MB well spacing). One of the offset MB wells was instrumented with external optical fiber for cluster-level completion measurements and fracture hit detection. Characterizing hydraulic fracture geometry is critical to improving completion designs and optimizing well spacing. Until recently, microseismic has been the primary diagnostic for estimating “bulk” or stage-level fracture geometry (Warpinski 2009) and parent-child interactions for modern multicluster plug-and-perf completions (Cipolla et al. 2018). However, microseismic cannot provide details on individual fractures or cluster-level measurements. With the continued advances in fiber-optic technologies, we can measure cluster-level fracture behavior at the wellbore and in the far field (Ugueto et al. 2016, 2019). Characterizing the relationship between wellbore and far-field fracture geometry, referred to as fracture morphology, is important when simultaneously optimizing completion design and well spacing. Microseismic and fiber optics are very robust, but expensive, technologies, and this limits the frequency of their application. The recent introduction of sealed wellbore pressure monitoring (SWPM) enables lower-cost, higher-volume data acquisition but may not provide the same level of detail compared with microseismic and fiber-optic measurements. This paper presents a case history that details the application of permanent fiber optics and SWPM to characterize fracture geometry and morphology using distributed acoustic sensing (DAS) for near-wellbore (NWB) measurements along with SWPM and crosswell strain for far-field investigation. This is the first example of both NWB and far-field optical fiber measurements being used to evaluate cluster efficiency in conjunction with SWPM. The SWPM results compared favorably with the fiber measurements; stages with more uniform distribution based on the NWB DAS data also had higher volume to first responses (VFRs) measured using crosswell strain and SWPM.

Chemostratigraphy of unconventional shale reservoirs: A case study of the Niobrara Formation within the Denver-Julesburg basin

The Upper Cretaceous carbonate-rich Niobrara Formation is a prominent petroliferous unconventional reservoir that is generally characterized by fine-scale heterogeneities that complicate local and regional correlation of target zones, well placement and completion strategies. Within rhythmically interbedded reservoirs like the Niobrara Formation, the occurrence of thin marl and chalk beds within chalk- or marl-dominated intervals respectively, further impedes identification of marl or chalk benches. This study uses a combination of petrophysical and geochemical data from 6 oil and/or gas wells within the Niobrara interval of the DJ basin to identify and correlate eight (8) chemozones (C1, C2, C3, C4, M1, M2, M3 and M4) and four (4) chemostratigraphic packages (Sharon Springs, Smoky Hill, Fort Hays and Codell Sandstone) that are essential for constructing a robust and dynamic stratigraphic framework.The results showed synchronous variation in petrophysical trends, elemental, mineralogical and organic composition at contacts, ubiquitous cyclicity within, and across the Niobrara Formation in the northern DJ basin. The stratigraphic units are geochemically separated based on TOC, total clay, total carbonate, and quartz + feldspars, and Ca, Sr, Si, Al, Ti, Rb, Zr, Nb, K, and Cr, while the internal stratigraphic units within the Niobrara Formation are defined by integrating gamma-ray (GR), resistivity, carbonate proxy, marl proxy, carbonate/marl proxy and terrigenous input. The chalk and limestone units (C1–C4) have higher Ca, Sr, total carbonate concentrations and relative brittleness index relative to the marl units (M1-M4). This multiproxy approach reveals variable calcareous and terrigenous/detrital input, and paleoredox conditions as the main controlling factors behind the changing lithologies/cyclicity within the Niobrara Formation. Hence, an adequate characterization and correlation of inherent heterogeneities within marls and chalks of the Niobrara Formation may require incorporation of a multiproxy approach at various scales. By integrating color scale, geochemistry, TOC and wireline well log curves responses, higher resolution identification of chalk reservoirs and marl source beds can be achieved. Spatial distribution of chalks and marls consistently show a trend of total carbonate and Ca increasing southwards towards the Tethys Sea with highest average concentrations recorded in Fort Hays Limestone while quartz + feldspars, and total clay concentrations increasing northwards, suggesting a southern and northern provenance, respectively.

Nano- to macro-scale structural, mineralogical, and mechanical alterations in a shale reservoir induced by exposure to supercritical CO2

Considering the importance of carbon neutrality, UCCUS which is underground carbon capture, utilization, and storage has been widely adopted to mitigate climate change. Studies are being conducted to improve this process, however, there is still a lack of knowledge on the multiscale physicochanical alterations that the storage reservoirs may endure due to the long-term exposure to supercritical CO2 (ScCO2). These changes happen from nano- to macro-scale in mineralogy and pore structures which will impact mechanical and petrophysical attributes of the host rock. Since unconventional shale reservoirs have become the target of CO2-EOR and CO2 storage, it is imperative to understand the long-term impact of these alterations due to ScCO2 exposure. This study coupled experimental and theoretical modeling to investigate continuous nano- to macro-scale changes in mechanical, mineralogical, and structural alterations in the Middle Bakken by exposing samples to ScCO2 for 3, 8, 16, 30 and 60 days. Qualitative analysis of electron micrographs pre and post exposure confirmed certain minerals have evolved while image processing showed a quantitative change in pore structures. Moreover, nanomechanical changes pre and post exposure were inspected via nanoindentation method. Furthermore, we assessed how mineral content was impacted during the exposure using X-ray diffraction analysis. Next, we adopted two rock physics models based on mechanical and mineralogical observations to upscale mechanical properties to the macro scale. Analyses of the results indicate that long-term ScCO2 exposure induces mineral dissolution, precipitation and the development of fractures in the host reservoir. Further, CO2 induced alterations can lead to long-term macro-scale weakening causing a loss in mechanical integrity of the Middle Bakken by decreasing its elastic modulus (DS model = –33 %, MT model = -30 %) and increasing its Poisson’s ratio (DS model = +38 %, MT model = +32 %). Overall, this study can provide new insights for a better design and implementation of UCCUS projects in shale reservoirs, most especially in the Middle Bakken and other similar formations, where a lack of understanding of these variations and project planning could lead to potential CO2 leakages and environmental hazards.

A Guide to Nanoindentation

Nanoindentation is a new technology slowly gaining acceptance in the oil and gas community. In an effort to accelerate its adoption, we review its capabilities and applications. The technology was developed to study thin film and semiconductor properties. It became attractive to the oil and gas industry when focus switched to unconventional shales. Because of the friability and instability of shales, retrieving core plugs for standard measurements became impossible in many cases. Nanoindentation is perfectly adapted to measuring the properties of fine-grained materials and material fragments. We document how nanoindentation can be used to measure Young’s modulus, hardness, shear modulus, anisotropy, creep, and fracture toughness and to examine the fluid sensitivity of these properties in shale.

Evaluation of Parameters Influencing Potential Gas Flow to the Mine in the Event of a Nearby Unconventional Shale Gas Well Casing Breach

Evaluation of Parameters Influencing Potential Gas Flow to the Mine in the Event of a Nearby Unconventional Shale Gas Well Casing Breach

Estimation of in situ stresses from PP-wave azimuthal seismic data in fracture-induced anisotropic media

Horizontally transverse isotropy (HTI) induced by vertical or subvertical aligned fractures is common for unconventional fractured porous shale oil or gas reservoirs. Compared with the unfractured rocks, the seismic response characteristics of PP-wave azimuthal amplitudes are usually disturbed by the fractures and the in situ stresses. Knowledge of fracture properties, as well as in situ stresses, is required to optimize horizontal well planning and hydraulic fracturing during production, and the seismic inversion for in situ stresses from the PP-wave azimuthal amplitude data in fracture-induced anisotropic media is an essential step. Using the linear-slip theory and the effective stress law, we derive the fluid-saturated effective elastic stiffness tensors parameterized by background elastic moduli, the effective stress coefficient of isotropic host rocks, fluid modulus, porosity, and fracture parameters based on the anisotropic Gassmann’s fluid substitution equation. Combining the perturbations in saturated stiffness tensors and scattering theory, we formulate the reflection coefficient equation of PP-wave data as a function of background porosity-related stress parameter and two (i.e., normal and shear) fracture weakness parameters. Following Bayes’ rule, we estimate the porosity-related stress parameter and fracture weaknesses using the inversion method of azimuthal Fourier coefficients. Finally, we compute the effective horizontal and vertical in situ stresses using the estimated elastic moduli, porosity-related stress parameter, and fracture weaknesses. Synthetic and real data sets demonstrate that our proposed inversion approach based on the derived reflection equation provides us another way to obtain reasonable estimates of in situ stresses in a complex-fractured porous shale reservoir.

Produced Gas and Condensate Geochemistry of the Marcellus Formation in the Appalachian Basin: Insights into Petroleum Maturity, Migration, and Alteration in an Unconventional Shale Reservoir

The Middle Devonian Marcellus Formation of North America is the most prolific hydrocarbon play in the Appalachian basin, the second largest producer of natural gas in the United States, and one of the most productive gas fields in the world. Regional differences in Marcellus fluid chemistry reflect variations in thermal maturity, migration, and hydrocarbon alteration. These differences define specific wet gas/condensate and dry gas production in the basin. Marcellus gases co-produced with condensate in southwest Pennsylvania and northwest West Virginia are mixtures of residual primary-associated gases generated in the late oil window and postmature secondary hydrocarbons generated from oil cracking in the wet gas window. Correlation of API gravity and C7 expulsion temperatures, high heptane and isoheptane ratios, and the gas geochemical data confirm that the Marcellus condensates formed through oil cracking. Respective low toluene/nC7 and high nC7/methylcyclohexane ratios indicate selective depletion of low-boiling point aromatics and cyclic light saturates in all samples, suggesting that water washing and gas stripping altered the fluids. These alterations may be related to deep migration of hot basinal brines. Dry Marcellus gases produced in northeast Pennsylvania and northcentral West Virginia are mixtures of overmature methane largely cracked from refractory kerogen and ethane and propane cracked from light oil and wet gas. Carbon and hydrogen isotope distributions are interpreted to indicate (1) mixing of hydrocarbons of different thermal maturities, (2) high temperature Rayleigh fractionation of wet gas during redox reactions with transition metals and formation water, (3) isotope exchange between methane and water, and, possibly, (4) thermodynamic equilibrium conditions within the reservoirs. Evidence for thermodynamic equilibrium in the dry gases includes measured molecular proportions (C1/(C1 − C5) = 0.96 to 0.985) and δ13C1 values significantly greater than δ13CKEROGEN. Noble gas systematics support the interpretation of hydrocarbon–formation water interactions, constrain the high thermal maturity of the hydrocarbon fluids, and provide a method of quantifying gas retention versus expulsion in the reservoirs.

Multiple experimental studies of pore structure and mineral grain sizes of the Woodford shale in southern Oklahoma, USA

Pore structure study is an important part of unconventional shale reservoir characterization, since the pore system provides the primary petroleum storage space and fluid flow pathways. Previous studies have suggested that the pore structure is related to the total organic carbon (TOC) content, mineral compositions, and the maturity of the organic matter (OM). However, few studies have focused on the mineral grains, the primary grains being deposited but before cementation, which are the building blocks of shale. Eight Woodford Shale outcrop samples from southern Oklahoma were chosen to study the effects of mineral grain size on the pore structure characterization, using multiple and complementary experimental approaches, including laser diffraction, mineralogy, TOC, pyrolysis, liquid immersion porosimetry, mercury intrusion porosimetry, gas physisorption, (ultra) small angle X-ray scattering, scanning electron microscopy, and spontaneous imbibition. The results from different experiments of eight samples show that the Woodford Shale has the mean mineral grain diameters at 3–6 μm, a wide range of porosity at 3–40% and pore diameters at 50–1,000 nm, and various pore connectivity. Grain size variation was probably caused by the sea-level fluctuation during its deposition, which affect the porosity, pore size distribution, and pore connectivity. With decreasing mineral grain sizes, the porosity tends to increase while the pore connectivity worsens. The results also indicate that OM and carbonates in this low-maturity Woodford Shale could block the pores and decrease the porosity. Coupling with the grain size analyses, the control of depositional environment on grain sizes and subsequent effects on pore structure is identified. The pore structure characteristics over a wide pore-diameter range provided by multiple experiments could improve the understanding of storage space and fluid flow in the Woodford Shale to further increase its petroleum production.

THE ROLE OF CLAY MINERALS IN HYDROCARBON GENERATION, MIGRATION AND ACCUMULATION

This study focuses on the understanding of the role of clay minerals in hydrocarbon generation, migration and accumulation. Clay minerals are involved in the formation of kerogen, catalytic cracking of kerogen into petroleum, migration of crude oil, and the continued change to hydrocarbon composition in petroleum reservoirs. In kerogen formation, clay minerals act as catalysts and sorbents to immobilize organic matter through ligand exchange, hydrophobic interactions and cation bridges by the mechanisms of Maillard reactions, polyphenol theory, selective preservation and adsorptive protection. Clay minerals also serve as catalysts in acid-catalyzed cracking of kerogen into petroleum hydrocarbon through Lewis and Bronsted acid sites on the clay surfaces. The amount and type of clay mineral affect the composition of the petroleum. Bronsted acidity of clay minerals is affected by the presence and state of interlayer water, and displacement of this water is a probable driver in crude oil migration from source rocks. During crude oil migration and accumulation in reservoirs, the composition of petroleum is continually modified by interaction with clay minerals. Clay minerals remain the most difficult of all earth materials to study and characterize. Their sheet structure results in features that can only be resolved at the sub-micron scale. They are also subtly variable in chemical composition (Fe, Mg, K, Al, et cetera) and can be confused with each other and other silicates. The recent innovative analytical tools and modern analysis techniques, example., micro- and nano-X-ray Computed Tomography (XCT), QEMSCAN (Automated Mineralogy and Petrography), FIB/SEM (Focused Ion Beam/Scanning Electron Microscope), EDS (Energy-dispersive X-ray spectroscopy), etc., have the capability of quantitative and qualitative characterizing nano-pore features and mineralogy of fine grained shale rocks, which create new era of studying clay minerals for facilitating unconventional (shale) reservoir exploration. Even though there have been reports about the application of clay minerals in the oil and gas exploration, surprisingly little work has been documented. Keyword: clay mineral, organic matter, generation, vitrinite, kerogen, montmorillonite.

Compressional and shear wave velocities relationship in anisotropic organic shales

Understanding the relationship between compressional and shear wave velocities and their anisotropic characteristics in self-resourcing reservoir shales is of considerable interest for petrophysical, geophysical, and geomechanical applications of unconventional resources exploration and production. We compile laboratory measurements on the ultrasonic velocity of known shale reservoirs worldwide. Their compressional and shear wave velocities propagating in the vertical and horizontal directions can be characterized by a linear model with the coefficients of determination (R2) close to 0.9. The P-to-S-wave velocity ratio in the vertical direction is overall higher than that in the horizontal direction. The P-to-S-wave velocity ratio decreases with decreasing P-wave velocity due to the increasing organic matter content and hydrocarbon-filled porosity. Mineralogy influences the relationship between compressional and shear wave velocities to a minor degree. Carbonate-rich shales have a higher P-to-S-wave velocity ratio than silica-rich shale when the P-wave velocity is lower than 4 km/s and a lower ratio when the P-wave velocity is higher than 5 km/s. By employing anisotropic fluid substitution, we justify that the model derived from the laboratory measurements can apply to shale reservoirs containing gas or volatile oil. We apply the linear models to predict the shear wave velocity in two vertical wells of shale reservoirs. The predictions of shear wave velocity in the targeted reservoirs have less than 3% errors, demonstrating that the proposed linear models, to the first order, can predict shear wave velocity in unconventional shale reservoirs.

Acoustic Dispersion in Low Permeability Unconventional Reservoir Rocks and Shales at In Situ Stress Conditions

Utilizing laboratory measurements on dry and fully brine-saturated well-lithified shale reservoir rocks and comparing them to log data and theoretical modeling, we find no statistically significant intrinsic dispersion from seismic to sonic and laboratory measurement frequencies due to fluid effects. Under in situ stress conditions, the Gassmann zero-frequency P-wave velocity prediction for a Permian basin sample was within 0.3% of the measured velocity on the brine-saturated sample at an ultrasonic frequency. At deviatoric stresses ranging from 1.7 to 70 MPa on the same sample, the percent error in the Gassmann P-wave velocity prediction ranges from 0.3 to 2.2%. These results are consistent with the lack of significant dispersion in the reported velocities and theoretical predictions in the Cotton Valley shale. Based on the Biot–Gassmann model, the characteristic frequency in both formations occurs at ~1010 Hz. Applying a squirt flow model also predicts transition to the high-frequency regime occurring at ~109 Hz for both formations. The comparison of the sonic log measurements for four different shale/tight rock formations to ultrasonic measurements taken from core samples under in situ stress conditions confirms these findings. To our knowledge, this is the first extensive comparison of the sonic log to ultrasonic core data measurements. For these rocks, there is no clearly observable or predicted significant dispersion due to fluid effects at in situ stress conditions within the frequency range for which measurements are made.

Impact of Supercritical CO2 on Shale Reservoirs and Its Implication for CO2 Sequestration

Hydraulic fracturing has transformed the international energy landscape by becoming the go-to method for the exploitation of natural gas from unconventional shale reservoirs. However, in the recent years, the search for an alternative method of shale-gas exploration has intensified, because of various problems (e.g., contamination of ground and surface water, overexploitation of precious water resources, air pollution, etc.) associated with the usage of water-based fracturing techniques. The use of CO2 for shale gas exploitation has emerged as a better alternative to aqueous-based gas exploration techniques. CO2 when injected into deep shale reservoirs, transitions into supercritical CO2 (SC-CO2) when temperature and pressure condition exceeds the critical point, i.e., 31.1 °C and 7.38 MPa. In this paper, we comprehensively review the impact of SC-CO2 on shale gas reservoirs during the different stages of shale-gas exploration, i.e., (i) drilling, which involves the superiority of SC-CO2 over water-based drilling fluids, in terms of achieving under-balanced well condition, higher rates of penetration, and resistance to formation damage; (ii) fracturing, which involves factors affecting the tortuosity of fractures created by SC-CO2 fracturing, breakdown pressure, and proppant-carrying capacity; and (iii) injection, which involves the twin-headed benefit of enhanced recovery due to CO2/CH4 competitive adsorption and geological sequestration, CO2 vs CH4 excess sorption as a function of pressure, etc. Several research works have indicated discrepancies on how SC-CO2 impacts different shale properties. Some studies show low-pressure N2-gas-adsorption-derived surface area and total pore volume to be increasing with SC-CO2 imbibition, while others show a decreasing trend for the same. Similarly, for some shales, the quartz content, along with the clay mineral contents, decreased as the exposure to SC-CO2 increased, while in some other studies, with similar long-term exposure to SC-CO2, the quartz content was observed to increase along with the decrease in clay content and vice versa. Essentially, the increased exposure to SC-CO2 results in the dissolution of primary porous structures and fractures, and reformation of newer porous structure and conduits in shales. Nonetheless, these changes in the mineralogy weaken the microstructure of the rock bringing significant changes in the mechanical properties of the shales with implications on the wellbore stability and fracturing efficiency. The mechanical properties such as uniaxial compressive strength (UCS), Young’s modulus, and tensile strength decrease as the SC-CO2 saturation period increases. However, some studies have shown factors like bedding angle and phase-state of CO2 having varying effect on the strength behavior of the shales. Moreover, changes in the structure of shales caused by the creation of fractures and the reduction of their strength can also pose major risks, because of potential leakage of CO2 through these created pathways. How these processes would interact at field scale would control the sealing capacity, especially at field-scale for addressing long-term seepage of CO2.

Machine-learning-based well production prediction under geological and hydraulic fracture parameters uncertainty for unconventional shale gas reservoirs

Shale gas production prediction under history-matching-based geomodel is crucial to achieve reliable assessment and economic management of unconventional shale resources, however, conventional history matching is generally performed through repeatedly running high-fidelity reservoir simulations and therefore presents intensive computation-cost in practical applications. Without the need of history matching step, this work presents an efficient and robust post-history production forecasting framework using a latent-space learning-based direct forecast approach, e.g., referred to as LS-LDFA. A novel dimensionality reduction method, e.g., convolutional autoencoder, is employed to regularize the multi-well time-series data by low-order representation within a latent space. Once the machine-learning proxy is trained offline, the online post-history production forecast can be efficiently achieved by input history data. This paper presents some comparative studies between LS-LDFA and model-based history matching. This approach is tested on two examples with an increasing complexity, e.g., a multi-fractured horizontal well and a naturally fractured reservoir model with multi-well-pad-production based on synthetic shale formation. The results confirm that the method achieves high robustness and computational efficiency simultaneously in comparison with the conventional history matching. The application of learning-based direct forecast approach can effectively fuse information from history data and thus support reliable decision-making and risk assessment.

Comparing the performance of supercritical CO2 fracking with high energy gas fracking in unconventional shale

Comparing the performance of supercritical CO2 fracking with high energy gas fracking in unconventional shale

Oil migration, retention, and differential accumulation in “sandwiched” lacustrine shale oil systems from the Chang 7 member of the Upper Triassic Yanchang Formation, Ordos Basin, China

To extract hydrocarbons from unconventional shale systems, it is necessary to assess oil retention and accumulation. This study presents experimental findings on oil retention, migration, and accumulation in a lacustrine shale system from the Chang 7 member of the Upper Triassic Yanchang Formation, Ordos Basin. 68 core samples were collected from the target layer to investigate the migration behavior of trapped hydrocarbons by organic geochemical, petrological, and petrophysical methods. The amount of oil retention and generation potential was determined using total organic carbon and programmed pyrolysis analysis. The pore structure and pore connectivity were quantified using scanning electron microscopy and micro-computed tomography scanning. Shale samples were also fractionated to determine the chemical composition of extracted hydrocarbons using a ternary azeotropic solvent extraction system. The effects of lithofacies, mineral compositions, organic matter, and pore structure on oil retention and accumulation were studied based on these findings.The findings revealed that lithofacies have a significant impact on the composition and amount of oil stored in the “sandwiched” shale systems. As oil is sorbed by organic matter, organic-rich shale lithofacies retain a large amount of oil. However, due to the developed dissolution-related pores in feldspar, the interbedded organic-lean siltstones have a higher oil saturation index and contain more free oil. Pore diameters and pore connectivity are also larger in the thin organic-lean siltstones. Shale oil intrasource migration and charging are observed in the Chang 7 member lithofacies assemblages during primary migration: oil is generated in organic-rich source rocks and expelled in short distances to adjacent siltstones. The thin organic-lean siltstones act as reservoir units for petroleum that has migrated from organic-rich shale units. Simultaneously, oil in thin siltstone intervals enriches in aliphatic and aromatic compounds, while petroleum from source rocks enriched in asphaltenes and resins, due to migration fractionation. This research shows oil migration and differential accumulation in the “sandwiched” shale systems in the Chang 7 member of the Upper Triassic Yanchang Formation, enhancing our knowledge of shale oil accumulation.

A kinetic model for multicomponent gas transport in shale gas reservoirs and its applications

An accurate gas transport model is of vital importance to the simulation and production optimization of unconventional gas reservoirs. Although great success has been achieved in the development of single-component transport models, limited progress has been made in multicomponent systems. The major challenge of developing non-empirical multicomponent gas transport models lies in the absence of the quantification of the concentration impact on the fluid dynamic properties. To fill such a gap, this work presents a comprehensive transport model for multicomponent gas transport in shale and tight reservoirs. In developing the model, we first conducted molecular dynamic simulations to qualitatively understand the differential release of hydrocarbons from unconventional shale and tight reservoirs. It is found that the gas slippage, differential adsorption, and surface diffusion are the primary transport mechanisms in the working range of Knudsen number during reservoir production. Based on the molecular dynamic study, a quantitative transport model has been developed and validated, which extends existing models from single-component systems to multiple-component systems. The kinetic theory of gases is adopted and modified to model the multicomponent slippage effect. A generalized Maxwell–Stefan formulation with extended Langmuir adsorption isotherm is used to model the multicomponent surface diffusion process. The accuracy of the proposed model is above 90% for low to moderate Knudsen numbers in modeling the differential release phenomenon in unconventional reservoirs.

The influence of acidizing on propped fractures for productivity enhancement: Eagle Ford laboratory study

Hydraulic fracturing of tight formations and placing proppants within induced fractures are commonly performed in unconventional shale reservoirs all over the world, especially in North America. However, the overall recovery of these oil and gas resources is very low and hence, production enhancement is inevitable.This study investigated the acidizing of propped fractures as a recovery enhancement method in Eagle Ford shale samples. Experiments were designed using sample slabs having proppants between them. Differing parameters were examined to optimize the fracture conductivity through acidizing. For a range of confining pressures, the fracture conductivity was maximized by minimizing the proppant embedment. A higher acid injection rate was achieved with a 5 % HCl concentration. Proppant concentration and proppant size were found to affect fracture conductivity inversely. However, this trend was not observed to be monotonic. In terms of production parameters, the skin factor determined the optimized conditions at a constant confining pressure. Overall, the optimum conditions for acidizing in the propped fractures were determined while having 5 % HCl concentration, 1 lb/ft2 (4.88 kg/m2) proppant concentration, 600–710 μm of proppant size and 8 ml/min acid injection rate. These findings confirmed the applicability of the method for hydraulic fracturing optimization in Eagle Ford shale samples. It can also be regarded as a primary enhancement method due to its low cost and the process simplicity in comparison to hydraulic fracturing operations. The experimental results of this study would correspondingly enlighten their potential field applications through facilitating appropriate modification with regards to specific operational conditions.

A comparative study on outlier detection techniques for noisy production data from unconventional shale reservoirs

Decline curve analyses (DCA) and rate transient analyses (RTA) are widely used to characterize the fluid flow through porous media and forecast future production. Oil and gas production data are routinely analyzed for history matching and optimizing the well stimulation methods in hydrocarbon exploration and production lifecycle. However, outliers add significant uncertainty and non-uniqueness to results from production data analysis. This study provides a structured and comprehensive overview of five widely used outlier detection (OD) techniques for identifying and removing outliers in production data. Each OD technique measures deviation differently and, therefore, has a different outcome even when applied to the same dataset, creating the need to test several methods and find the optimal technique for identifying and removing outliers from production data. First, we generated production data from a typical multi-fractured horizontal well using a numerical reservoir simulator and added random noise to the data. Then, we used five different OD techniques to identify the prelabeled outliers from the synthetic production data. Finally, we identified the best-performing OD algorithm by comparing the various evaluation metrics such as the mean absolute error (MAE), precision, sensitivity, and F1 score. Results showed that the angle-based OD (ABOD) had the best MAE, precision, sensitivity, and F1 score of 8%, 85%, 98%, and 0.90, respectively. The next best-performing OD technique was distance-based OD (DBOD), with MAE, precision, sensitivity, and F1 score of 16%, 71%, 100%, and 0.83, respectively. We tested the ABOD method on several field production datasets by assuming different outlier thresholds (fraction of the data points likely to be outliers). Visual inspection of the processed data showed that the ABOD method effectively identified and removed the outliers from a relatively clean dataset (outlier threshold of 20%) and a highly noisy dataset (outlier threshold of 80%). This algorithm is intuitive and can effectively identify and remove outliers from the field production data to improve production forecasting, reserves estimation, and rate transient analysis for multi-fractured horizontal oil and gas reservoirs.