Tight Hydrocarbon Reservoirs Research Articles

Experimental evaluation of the impact of induced fractures on cyclic solvent injection performance in low-permeability hydrocarbon reservoirs

Recovery factors associated with primary recovery (pressure depletion) schemes are often small (<5–10%) for low-permeability hydrocarbon reservoirs. As a result, cyclic solvent injection (CSI) schemes, using CO2 and produced gas, are currently being considered for enhanced hydrocarbon recovery (EOR). Fracture networks, generated during hydraulic fracturing stimulation, affect both primary and enhanced recovery by increasing the surface area contacted with the low-permeability reservoir matrix. However, experimental studies of the impact of induced (hydraulic) fractures on CSI performance are sparse, particularly those that provide a realistic representation of the fracturing process by inducing fractures under stress to better represent fracture conditions (e.g., fracture surface area, fracture surface roughness). Therefore, the primary objective of this work is to develop a laboratory-based workflow for evaluating the effectiveness of fracture system in tight oil reservoirs to enhance the oil recovery during a typical CSI cycle using a combination of core-scale techniques.An in-house core-flooding methodology, that combines ‘in situ’ fracturing and cyclic gas injection, was applied. The experimental procedure includes: 1) performing multiple cycles of lean gas (i.e., 80% C1 + 20% C2) injection into an oil-saturated ‘intact’ core plug until maximum oil recovery (5%) is reached, 2) artificially fracturing the core plug under stress, 3) repeating multiple cycles of lean gas injection into the artificially-fractured core plug, under similar experimental conditions as those used for the intact core, until maximum oil recovery (23%) is reached, and 4) measuring the fractured-core liquid permeability. A well-characterized tight siltstone core plug sample obtained from the Canadian Montney Formation was analyzed as an example. The experimental results indicate that 1) fracturing under stress results in an increase in surface area and permeability, and 2) the recovery factor is enhanced by ∼ 18% after fracturing (e.g., from ∼ 5% for intact core plug to ∼ 23% for artificially-fractured core plug).This study provides a proof-of-concept experimental approach for evaluating the impact of induced fractures on CSI recovery using an identical core plug sample (intact and fractured). The proposed experimental methodology could serve as a workflow for laboratory-scale evaluation of the impact of induced fractures on CSI performance in tight hydrocarbon reservoirs.

Quantifying micro-proppants crushing rate and evaluating propped micro-fractures

Micro-proppants used in reservoir stimulation to enable oil and gas recovery from tight hydrocarbon reservoirs can be delivered deeper with slick water and prop microfracture networks during hydraulic fracturing. The production of a multi-fractured well system depends on fracture permeability, which is ultimately a function of proppant strength and concentration. However, it is challenging to evaluate the performance of micro-proppants due to their tiny particle size. This paper proposed a practical method for assessing micro-proppant strength based on micro-proppant crushing rates and optimizing micro-proppant delivery to achieve effective concentrations in the pad fluid to prop up the micro-fractures more effectively. Micro-proppants undergo two crushing steps when transported in the fluid and when hydraulic fractures close. Under a pressure of 70 MPa, the crushing rate is 12%–25% of the hydraulic loading, and 42%–66% of the solid loading for three types of micro-proppants. The concentration of micro-proppants in the pad fluid should be higher than 0.9 lbm/gal to maintain economic permeability under high closure stress of 50 MPa. The numerical simulation results demonstrate that adding micro-proppants to the pad fluid will increase the effective propped fracture area, and the initial productivity and stable productivity increase by more than 40% and 20%, respectively. This study has a guiding value for selecting micro-proppants and the number of micro-proppants used in hydraulic fracturing.

Flue gas injection into depleted tight hydrocarbon reservoirs in the context of global warming mitigation: Computed evolution of some reservoir parameters

• Injecting flue gas captured after oxy-combustion in depleted tight hydrocarbon reservoir can lead to the oxidation of the residual hydrocarbons. • The temperature increase due to the oxidation exothermicity depends strongly on the heat capacity of the rocks. • A high heat capacity makes the temperature increase negligible. • Thermal conductivity and its potential anisotropy have almost no impact on temperature profile. CO 2 storage in depleted tight hydrocarbon reservoir seems to be a promising solution to mitigate greenhouse gas emissions. However, flue gas contains not only CO 2 but also minor gaseous impurities due to CO 2 production or capture processes. In the case of oxy-combustion, the main impurity can be O 2 in concentration up to 7%. O 2 injection into the reservoir can lead to the oxidation of the residual hydrocarbons and therefore, it is necessary to assess the thermal consequences on the reservoir. COMSOL Multiphysics® has been used to model an axisymmetric fractured porous reservoir with its cap and base rocks and containing n- octane as a model compound of residual oil. A global kinetic model for n- octane oxidation has been derived from a previous detailed free-radical model, and implemented into the reservoir model. Simulated injections of N 2 /O 2 mixture (representing a simplified flue gas) have been performed to compute temperature, pressure and n- octane concentration profiles. The results show that the oxidation exothermicity may have a strong influence on temperature profile, especially when the heat capacity of the rock is rather low. In these conditions, the remaining hydrocarbons may be consumed in some months. However, the influence of the thermal conductivity seems negligible. Therefore, it appears safer to select reservoirs whose rocks compositions, in particular the cap and base rocks, have a high heat capacity to promote heat dissipation. It is a criterion to consider when selecting a storage site containing residual hydrocarbons, especially for CO 2 captured after oxy-combustion.

Comparison of diagenesis and reservoir quality of microporous lime mudstones (Aptian) between anticline crest and flanks: Abu Dhabi, United Arab Emirates

The impact of in-situ and migrated oil on diagenesis and reservoir quality of microporous (porosity ≤ nil to 26%; permeability ≤ nil to 3 mD) intra-shelf basinal lime mudstones (Aptian) is constrained by comparing samples from anticline crest (i.e. oil zone) versus flanks (i.e. water zone), Abu Dhabi, United Arab Emirates. Higher porosity and permeability and larger pore-throat radii in the crest than in the flank mudstones is attributed to retardation of calcite cementation in the crest due to oil emplacement. Calcite cement has precipitated as syntaxial micro-overgrowths around micrite particles and as equant microspar in moldic pores and small vugs. Deviation of a large number of samples from this crest versus flanks porosity and permeability trend reflects the impact of other parameters, including: (i) subtle grain-size variations (ii) proportion of intact (i.e. with intragranular pores), versus broken coccolith tests, and (ii) degree of calcite cementation. Calcite cement was sourced by stylolitization of the limestones, which is more frequent and extensive in the flanks than in the crest. Similar bulk δ18OVPDB values of calcite in the crest (−7.3‰ to −4.6‰) and flanks (−6.9‰ to −5.5‰) is attributed to closed diagenetic system in the microporous mudstones, which masks the role of burial temperature in fractionation of oxygen isotopes during continued cementation of the water-saturated flank mudstones. The presence of miscellaneous saddle dolomite in the crest and flanks is attributed to the field-wide flow of hot basinal fluids along fractures and stylolites. A conceptual model unravelling the diagenetic and related reservoir-quality evolution pathways of mudstones across an oilfield anticline has been developed. This model has important implications for exploration of tight hydrocarbon reservoirs and improves our understanding of oil migration and emplacement in source rocks.

Geoscience Poster G6: Petrophysical characterisation of the Neoproterozoic and Cambrian successions in the Officer Basin

Poster G6 The Neoproterozoic–Paleozoic Officer Basin, located in South Australia and Western Australia, remains a frontier basin for energy exploration, with significant uncertainty due to a paucity of data. As part of Geoscience Australia’s Exploring for the Future (EFTF) program, the objective of this study is to derive the petrophysical properties and to characterise potential reservoirs in the Neoproterozoic–Cambrian sedimentary succession in the Officer Basin through laboratory testing and well log interpretation using both conventional and neural network methods. Laboratory measurements of 41 legacy core samples provide the relationships between gas permeability, Klinkenberg corrected permeability, and nano-scale permeability, as well as grain density, effective and total porosity for various rock types. Conventional log interpretation generates the volume fraction of shale, effective and total porosity from gamma ray and lithology logs. A self-organising map (SOM) was used to cluster the well log data to generate petrophysical group/class index and probability profiles for different classes. Neural network technology was employed to approximate porosity and permeability from logs, conventional interpretation results and class index from SOM modelling. The Neoproterozoic−Cambrian successions have the potential to host both conventional and tight hydrocarbon reservoirs. Neoproterozoic successions are demonstrated to host mainly tight reservoirs with the range in average porosity and geometric mean permeability of 4.77–6.39% and 0.00087–0.01307 mD, respectively, in the different sequences. The range in average porosity and geometric mean permeability of the potential Cambrian conventional reservoirs is 14.54−26.38% and 0.341−103.68 mD, respectively. The Neoproterozoic shales have favourable sealing capacities. This work updates the knowledge of rock properties to further the evaluation of the resource potential of the Officer Basin. To access the poster click the link on the right. To read the full paper click here

Petrophysical characterisation of the Neoproterozoic and Cambrian successions in the Officer Basin

The Neoproterozoic–Paleozoic Officer Basin, located in South Australia and Western Australia, remains a frontier basin for energy exploration, with significant uncertainty due to a paucity of data. As part of Geoscience Australia’s Exploring for the Future (EFTF) program, the objective of this study is to derive the petrophysical properties and to characterise potential reservoirs in the Neoproterozoic–Cambrian sedimentary succession in the Officer Basin through laboratory testing and well log interpretation using both conventional and neural network methods. Laboratory measurements of 41 legacy core samples provide the relationships between gas permeability, Klinkenberg corrected permeability, and nano-scale permeability, as well as grain density, effective and total porosity for various rock types. Conventional log interpretation generates the volume fraction of shale, effective and total porosity from gamma ray and lithology logs. A self-organising map (SOM) was used to cluster the well log data to generate petrophysical group/class index and probability profiles for different classes. Neural network technology was employed to approximate porosity and permeability from logs, conventional interpretation results and class index from SOM modelling. The Neoproterozoic−Cambrian successions have the potential to host both conventional and tight hydrocarbon reservoirs. Neoproterozoic successions are demonstrated to host mainly tight reservoirs with the range in average porosity and geometric mean permeability of 4.77–6.39% and 0.00087–0.01307 mD, respectively, in the different sequences. The range in average porosity and geometric mean permeability of the potential Cambrian conventional reservoirs is 14.54−26.38% and 0.341−103.68 mD, respectively. The Neoproterozoic shales have favourable sealing capacities. This work updates the knowledge of rock properties to further the evaluation of the resource potential of the Officer Basin.

Micro-proppant placement in hydraulic and natural fracture stimulation in unconventional reservoirs: A review

Tight hydrocarbon reservoirs require stimulation to improve the recovery of oil and gas resources. Hydraulic fracturing is a technique extensively employed in the oil and gas industry to generate fractures including primary and secondary fractures. To keep these fractures open, proppants are used. However, some of these ractures are very narrow for conventional proppants to penetrate and prop, hence smaller proppants called micro-proppants are required. These micro-proppants can improve the hydraulic conductivity of both, the primary fractures and the untouched microfractures, leading to enhanced oil and gas recovery.This paper presents a critical review on the progress of current micro-proppants models, technologies and field applications (sub 100˗mesh proppants) with a particular attention to micro-proppants placement in hydraulic and natural fractures. The impact of various factors on micro-proppant placement in the fractures is analyzed. These factors include proppant concentration (i.e., volume fraction of solid proppant), proppant size, fracturing fluid chemistry, and confining stress (causing proppant deformation and proppant embedment into the rock). This review concludes that using micro-proppants can improve the efficiency of the hydraulic fracturing treatment, leading to enhanced oil and gas production.

Socio-Inspired Multi-Cohort Intelligence and Teaching-Learning-Based Optimization for Hydraulic Fracturing Parameters Design in Tight Formations

Abstract Hydraulic fracturing is one of the revolutionary technologies widely applied to develop tight hydrocarbon reservoirs. Moreover, hydraulic fracture design optimization is an essential step to optimize production from tight reservoirs. This study presents the implementation of three new socio-inspired algorithms on hydraulic fracturing optimization. The work integrates reservoir simulation, artificial neural networks, and preceding optimization algorithms to attain the optimized fractures. For this study, a tight gas production dataset is initially generated numerically for a defined set of the fracture half-length, fracture height, fracture width, fracture conductivity, and the number of fractures’ values. Secondly, the generated dataset is trained through a neural network to predict the effects of preceding parameters on gas production. Lastly, three new socio-inspired algorithms including cohort intelligence (CI), multi-cohort intelligence (multi-CI), and teaching learning-based optimization (TLBO) are applied to the regressor output to obtain optimized gas production performance with the combination of optimum fracture design parameters. The results are then compared with the traditionally used optimizers including particle swarm optimization (PSO) and genetic algorithm (GA). The results demonstrated that the multi-CI and TLBO converge at the global best position more often with a success rate of at least 95% as compared to CI, PSO, and GA. Moreover, the CI, PSO, and GA are found to stuck many times at the local maximum. This concludes that the multi-CI and TLBO are good alternatives to PSO and GA considering their high performance in determining the optimum fracture design parameters in comparison.

Experimental and computational evaluation of cyclic solvent injection in fractured tight hydrocarbon reservoirs

Multi-fractured horizontal wells have enabled commercial production from low-permeability (‘tight’) hydrocarbon reservoirs but recoveries remain exceedingly small (< 5–10%). As a result, operators have investigated the use of solvent (gas) injection schemes, such as huff-n-puff (HNP), to improve oil recovery. Previous HNP laboratory approaches, classified primary as ‘flow-through-matrix’ and ‘flow-around-matrix’ typically (1) are not fully representative of field conditions at near-fracture regions and (2) require long test times, even when performed on fractured cores. The objectives of this proof-of-concept study are to (1) design and implement a new experimental procedure that better reproduces HNP schemes in near-fracture regions and (2) use the results, simulated with a compositional lab-calibrated model, to explore the controls on enhanced hydrocarbon recovery in depleted tight oil plays. Performing multiple CO2 and (simplified) lean gas HNP cycles, the integrated experimental and simulation approach proposed herein achieves the ultimate recovery factors in a significantly shorter time frame (25–50%) compared to previous studies. The integrated experimental and computational approach proposed herein is valuable for core-based evaluation of cyclic solvent (CO2, CH4) injection in tight hydrocarbon reservoirs for (1) hydrocarbon recovery and (2) subsurface greenhouse (CO2, CH4) gas disposal/storage applications.

The effect of thermal gradients on adsorption

Molecular simulations of confined hydrocarbons have significantly contributed to advances in the study of alternative energy systems, such as natural gas, to reduce environmental impacts and green-house gas emissions. Adsorption and structural properties of confined media impact all production steps from gas recovery to its storage. To understand the possible changes on adsorption behavior caused by the geothermal gradient to which the tight hydrocarbon reservoirs are subjected, we apply non-equilibrium molecular dynamics to simulate methane, pentane, and their binary mixture confined between calcite nanopores. We impose a temperature gradient perpendicular to the surface by using the calcite crystals as thermal walls to emulate the geothermal gradient. Surface-fluid interactions are modified by the presence of the gradient, and the adsorption behavior unexpectedly differs from the one at local temperature isothermal conditions. We, therefore, show by means of molecular dynamics simulations that the density profile is not only dependent on temperature, but it also depends on the local temperature gradient. We also calculate the orientation of pentane molecules inside the pore, and report its capillary condensation at subcritical conditions in a dual-pore simulation. We expect these results to improve the knowledge of the coupling between confinement and thermal gradients.

Application of focal-time analysis for improved induced seismicity depth control: A case study from the Montney Formation, British Columbia, Canada

Characterization of induced seismicity and associated microseismicity is an important challenge for enhanced oil recovery and development of tight hydrocarbon reservoirs. In particular, accurately correlating hypocenters of induced events to stratigraphic layers plays an important role in understanding the mechanisms of fault activation. Existing methods for estimating focal depth, however, are prone to a high degree of uncertainty. A comprehensive analysis of inferred focal depths is applied to induced events that occurred during completions of horizontal wells targeting the Montney Formation in British Columbia, Canada. Our workflow includes a probabilistic, nonlinear global-search algorithm (NonLinLoc), a hierarchical clustering algorithm for relative relocation (GrowClust), and depth refinement using the recently developed focal-time method. The focal-time method leverages stratigraphic correlations between P-P and P-S reflections to eliminate the need for an explicit velocity model developed specifically for hypocenter depth estimation. We find that this approach is robust in the presence of noisy picks and location errors from epicenters obtained using a global-search algorithm, but it is limited to areas where multicomponent 3D seismic data are available. We have developed a novel method to determine statics corrections to ensure that the passive seismic observations and 3D seismic data share a common datum in areas of moderate to high topography. Our results highlight the importance of transverse faults, which appear to provide permeable pathways for activation of other faults at distances of up to 2 km from hydraulic fracturing operations.

Pore characteristic responses to categories of depositional microfacies of delta-lacustrine tight reservoirs in the Upper Triassic Yanchang Formation, Ordos Basin, NW China

Primary depositional variations interact with diagenetic modifications to exert strong control on pore networks in tight hydrocarbon reservoirs. However, the linkage between pore characteristics and depositional microfacies remains enigmatic, which restricts the prediction of high-quality reservoir distributions. The continental tight reservoirs of the Yanchang Formation in the Ordos Basin are targeted to clarify and estimate the sensitivity of pore characteristics to depositional microfacies. A multi-methodical approach utilizing petrographic assessments, logging evaluations, digital imaging analyses and high-pressure mercury intrusion experiments enables us to reveal the high microheterogeneity of pore types, pore-size distribution and pore fractal features. The results identified the microfacies including distributary channels (DCs), mouth bars (MBs), interdistributary bays (IBs), sheet sands (SSs), turbidite fans (TFs), shallow lacustrine mudstones (SLMs) and semi-deep lacustrine mudstones (SDLMs) from the Chang 8 to Chang 6 members. Dominated by residual intergranular pores and microfractures, the main storage spaces of the DC and MB microfacies are within mesopores, which provide 62%–92% and 81% of the total pore volume, respectively. However, the micropores that are mainly composed of clay intercrystalline pores and feldspar dissolved pores provide 55%–70%, 52%–62% and 53%–80% of the total pore volume for the IB, SLM and SDLM microfacies, respectively. In addition, the pore fractal dimension results indicate that the mesoporous structure of the argillaceous microfacies (IB, SLM and SDLM) is more heterogeneous than that of the arenaceous microfacies (DC, MB and TF). Therefore, the dominant reservoir spaces of the different depositional microfacies are distributed over diverse pore-radius ranges, and the varying degrees of mesoporous development are a crucial factor affecting the reservoir capacity. Moreover, the fractal dimensions have a significant negative correlation with pore volume in the meso-micropore range. Characterized by lower pore sorting coefficients, broader skewness and more abundant rigid siliceous grains, the arenaceous microfacies with lower fractal dimensions and higher pore volume have better reservoir capacity than argillaceous microfacies that are rich in ductile minerals. Microscopic observations show that the muddier reservoirs of interdistributary bays and lacustrine mudstones are more susceptible to pore-filling chlorite and illite, which can deteriorate the reservoir quality. These results indicate that the controlling effect of depositional microfacies on pore characteristics is fundamentally caused by differences in mineralogical composition and depositional texture, and these results could provide new insights into the mechanisms of microfacies controls on reservoir quality.

Experimental Study of Crack Propagation in Cracked Concrete

The intersection of cracks has an important role in the key technology of hydraulic fracturing for enhancing the recovery of tight hydrocarbon reservoirs. On the basis of digital image correlation technology, three-point bending tests of concrete beams with an edge crack and a central preset crack were conducted to investigate the propagation of cracks after intersection in concretes. Concrete beams with cracks of different positions, lengths, and approach angles were tested, and results were analyzed. In conclusion, the crack positions, crack lengths, and approach angles significantly influence the crack propagation in naturally cracked concrete. A large distance between the crack tip and central point at the preset transverse crack and crack length indicate a high possibility of the edge crack vertically crossing the preset crack. In particular, the crack restarts from the preset crack tip after intersection when the distance between two cracks is smaller than 30 mm and when the preset crack length is smaller than 40 mm. A large approach angle corresponds to a large carrying capacity of the beam and a high possibility of the crack propagating perpendicularly. An improved criterion of restart cracking after interaction is proposed, and the restart points of all tested beams are predicted and compared with the experimental results. A good agreement is observed, which proves that this criterion is reliable.

Detecting the propped fracture by injection of magnetic proppant during fracturing

Hydraulic fracturing is key to enhancing the productivity of shale and tight hydrocarbon reservoirs, as well as geothermal resources from hot dry rock. Assessing the range and efficiency of hydraulic fracturing is very important for onsite fracturing operations and decision making on subsequent fracturing plans and well-pattern deployment. The idea of injecting fluid mixed with magnetic material into a formation to detect subterranean structure has been considered for a long time. The detectability of the characteristics of propped fractures using magnetic field measurement is discussed and evaluated with an analytical model. The magnetic proppants synthesized with superparamagnetic nanoparticles should be “silent” during injection and could be activated by an external current. By measuring the magnetic field before and after the fracture was created and the magnetic proppants were magnetized, the magnetic anomalies can be obtained. The result indicates that the magnetic field caused by a fracture filled with magnetic proppants is very weak, so that magnetometers with higher precision and resolution should be used to capture such subtle signal. The higher susceptibility contrast of the magnetic nanoparticles is, the stronger external magnetic induction field could be detected. It is suggested that the superparamagnetic nanomaterial with effective magnetic susceptibility contrast of greater than 0.4–0.5 should be used for fracture monitoring in deep wells. To infer the fracture characteristics with the magnetic anomaly, the ground and adjacent wells’ monitoring practices are recommended.

Lower limits of petrophysical parameters allowing tight oil accumulation in the Lucaogou Formation, Jimusaer Depression, Junggar Basin, Western China

Abstract In this study, we investigate the petrophysical parameter values above which oil can accumulate, using a tight oil reservoir in the Jimusaer Depression, Junggar Basin, as an example. Statistical analysis of well-drilling data and effective porosity measurements is integrated with numerical simulations of force balance to illuminate the mechanisms that place a lower limit on the petrophysical parameters of tight hydrocarbon reservoirs. Further, we discuss the factors that influence these limits. The results show that when porosity is observed to be less than 5%, corresponding to a pore-throat radius of more than 0.2 μm, exploratory wells reach reservoirs comprising only water layers. The lower limit for oil accumulation is reached when irreducible water saturation reaches 100% and porosity is approximately 5%. This fits well with the values arrived at by modeling the force balance. In the reservoirs under consideration, oil charging is driven by excess pressure resulting from hydrocarbon generation and is resisted by capillary force. When the pore-throat radius is larger than 0.2 μm, the capillary force will be greater than the driving force, and tight reservoirs cannot be charged with oil. This corresponds to a porosity of approximately 5%, matching the results derived from observations. The values of these lower limits depend on many factors, such as source rock quality, depth, temperature, hydrocarbon-generation kinetics, and interfacial tension, and hence vary under different geological conditions. Thus, in lacustrine basins in China with type I kerogen-dominated source rocks, the lower limits are smaller than in those where other types dominate. Differences in the geothermal gradient mean that, at similar hydrocarbon-generation temperatures, the lower limits for reservoirs in Western China are smaller than for those in the east. There is also a smaller lower limitation porosity in tight gas reservoirs than in tight oil reservoirs due to the difference in interfacial tension.

Numerical Analysis of Hydrofracturing Behaviors and Mechanisms of Heterogeneous Reservoir Glutenite, Using the Continuum‐Based Discrete Element Method While Considering Hydromechanical Coupling and Leak‐Off Effects

AbstractHydrofracturing technology has been widely used to stimulate the tight hydrocarbon reservoirs that usually comprise heterogeneous glutenites. Hydromechanical coupling and leak‐off are essential characteristics of this process and need to be properly addressed in numerical simulation, which plays an important role in quantitatively evaluating the efficiency of this technology. Due to the challenges in accurately representing the complex structure and physical properties of heterogeneous glutenites as well as hydraulic‐driven crack propagation, however, the hydromechanical coupling, leak‐off, and material heterogeneity have not yet been handled satisfactorily. To overcome these challenges, we use the continuum‐based discrete element method (CDEM) to simulate the hydraulic fracturing of heterogeneous glutenites, considering hydromechanical coupling and leak‐off effects. The CDEM models are constructed using the geometrical and physical parameters that were extracted from natural heterogeneous glutenites using computed tomography, X‐ray diffraction, and triaxial tests, based on image processing and reconstruction approaches. The CDEM models are composed of hydraulic fractures and microscale pores, and Darcy's law was integrated within the model to govern fluid leak‐off; this is a nontraditional approach to leak‐off effects. The coupled finite element‐discrete element‐finite volume approach is used to determine the fracturing behaviors of heterogeneous models. The fracturing crack propagation and distribution patterns of homogeneous and heterogeneous models under various horizontal in situ stress differences are characterized by fractal theory, and the models are compared to assess the influences of material heterogeneity and in situ stresses on the hydraulic fracturing of heterogeneous glutenites.

Adaptive finite element-discrete element method for numerical analysis of the multistage hydrofracturing of horizontal wells in tight reservoirs considering pre-existing fractures, hydromechanical coupling, and leak-off effects

Multistage fracturing is widely used to improve gas production in tight hydrocarbon reservoirs. As a sequential process that interacts with pre-existing fractures, multistage fracturing must be properly addressed in numerical simulations, which are important in evaluating and optimising fracturing technology. The challenges of accurately representing the complex fracture structures and physical properties of naturally fractured reservoirs cause that the interaction between hydraulic and pre-existing fractures has not yet been resolved satisfactorily. In this study, we adopt an adaptive finite element-discrete element method to simulate the multistage fracturing of a naturally fractured reservoir by improving the mesh auto-refinement and identification of multiple fracture propagation. The numerical model considers interactions among hydraulic fractures, pre-existing fractures, and microscale pores, and integrates the nonlinear Carter leak-off criterion to describe fluid leak-off and hydromechanical coupling effects during multistage fracturing. The proppant transport equation for idealised parallel plate flow in fractures is introduced, and Darcy's law is adopted to analyse the seepage flow in the fracture network and determine the gas recovery. The fracture network and consequent fluid flow induced by the hydrofracturing of unfractured and naturally fractured models are compared to assess the influence of pre-existing fractures on multistage fracturing behaviour and gas production.

Adaptive Finite Element‐Discrete Element Analysis for Microseismic Modelling of Hydraulic Fracture Propagation of Perforation in Horizontal Well considering Pre‐Existing Fractures

Hydrofracturing technology of perforated horizontal well has been widely used to stimulate the tight hydrocarbon reservoirs for gas production. To predict the hydraulic fracture propagation, the microseismicity can be used to infer hydraulic fractures state; by the effective numerical methods, microseismic events can be addressed from changes of the computed stresses. In numerical models, due to the challenges in accurately representing the complex structure of naturally fractured reservoir, the interaction between hydraulic and pre‐existing fractures has not yet been considered and handled satisfactorily. To overcome these challenges, the adaptive finite element‐discrete element method is used to refine mesh, effectively identify the fractures propagation, and investigate microseismic modelling. Numerical models are composed of hydraulic fractures, pre‐existing fractures, and microscale pores, and the seepage analysis based on the Darcy’s law is used to determine fluid flow; then moment tensors in microseismicity are computed based on the computed stresses. Unfractured and naturally fractured models are compared to assess the influences of pre‐existing fractures on hydrofracturing. The damaged and contact slip events were detected by the magnitudes, B‐values, Hudson source type plots, and focal spheres.

Petroleum accumulation: from the continuous to discontinuous

Based on the extensive studies of conventional and unconventional hydrocarbon accumulations, the concept, classification and formation as well as distribution of petroleum reservoirs are discussed. The revised concept defined the petroleum reservoir as a continuous hydrocarbon accumulation in a single or a set of reservoirs with an independent or uniform pressure system. In terms of the pattern of hydrocarbon accumulation and distribution, the hydrocarbon accumulations are classified into three basic types, i.e., the continuous accumulation, the quasi-continuous accumulation and the discontinuous accumulation. The hydrocarbon accumulation was demonstrated as a process from continuous accumulation to discontinuous accumulation, and therefore these three basic types of hydrocarbon accumulations were identified. The continuous hydrocarbon accumulation is principally formed in source rocks, and typical examples are shale hydrocarbon reservoirs and coal-bed methane reservoirs; it is mainly characterized by tight-ultra tight reservoirs with permeability of nanodarcy to millidarcy; the hydrocarbons occurred in free, adsorbed or dissolved state; a continuous accumulation comprises actually only a single reservoir, and hydrocarbons are extensively and continuously distributed within the scope of effective source rocks; the accumulation has neither defined boundaries nor bottom or edge water; oil and gas mainly accumulate in situ or near the generation of hydrocarbons with no prominent migration; this hydrocarbon accumulation process is basically not controlled by traps. The quasi-continuous hydrocarbon accumulation mostly occurs in the tight reservoirs adjacent to source rocks, and typical examples are most of tight hydrocarbon reservoirs; the hydrocarbons are distributed quasi-continuously in large areas, and each quasi-continuous hydrocarbon accumulation includes numerous adjacent small- to medium-size reservoirs; reservoirs of this kind of hydrocarbon accumulation have no defined boundaries, no or only local edge and bottom water distribution, and no regional oil-gas-water inversion; hydrocarbons are pervasively charged in large areas, and oil and gas accumulation is caused by primary migration and short-distance secondary migration; the hydrocarbon migration and accumulation is principally driven by non-buoyant forces in non-Darcy flow; and the hydrocarbon accumulation is basically not controlled by anticline traps, but largely by non-anticline traps, especially lithological traps. The discontinuous hydrocarbon accumulation is also named as the hydrocarbon accumulation of the conventional-trap type, and typically occurs in conventional reservoirs, but some tight hydrocarbon reservoirs, coalbed methane reservoirs and even possible shale hydrocarbon reservoirs also belong to this kind of hydrocarbon accumulation; the hydrocarbon reservoirs are distributed discontinuously, and have clear boundaries and complete edge water or bottom water; the hydrocarbon migration and accumulation is mainly driven by buoyancy and secondary migration is usually indispensable; the hydrocarbon accumulation is strictly controlled by various traps, especially structural traps. In a petroliferous basin, above three types of hydrocarbon accumulation may coexist, andhydrocarbons are often derived from a common source kitchen(s). Therefore, these three types of hydrocarbon accumulation should be considered and studied as a whole to maximize hydrocarbon exploration efficiencvy.

Pressure transient responses study on the hydraulic volume fracturing vertical well in stress-sensitive tight hydrocarbon reservoirs

Based on the characteristics of stimulated zone and un-stimulated zone after hydraulic volume fracturing of vertical well, as well as considering the stress-sensitive characteristic of the tight oil reservoir, the two-zone composite pressure transient responses model is built. The inner zone represents the stimulated reservoir volume region and is modeled as a dual-porosity radial reservoir, while the outer zone represents the un-stimulated reservoir volume region and is modeled as a single porosity reservoir. The model is solved by the method of superposition, Laplace integral transformation, Stehfest numerical inverse algorithm, and the perturbation technique. Thus the analytical solutions to the model are obtained. On the basis of the field example verification of the model, the flow regimes of the hydraulic volume fracturing vertical well are analyzed. The results of the study show that the new model can provide the reliable pressure transient responses model for hydraulic volume fracturing vertical well, and the flow regimes can be divided into five stages, including the wellbore storage stage, transition flow from matrix system to fracture system, radial flow of SRV zone, transition flow from UN-SRV zone to SRV zone, and radial flow of whole reservoir system. The new model and study are conducive to the well test interpretation of hydraulic volume fracturing vertical well in stress-sensitive tight oil reservoir.