A Visualization Study of Fracture Propagation in Tight Sandstone Under Triaxial Loading

ABSTRACT: Shale oil in northeast China is about to enter the stage of large-scale hydraulic fracturing. Cement sheath integrity must be ensured for horizontal shale oil wells. In this paper, the mechanical parameters of cement sheath are measured. A numerical model of casing - cement sheath - formation assembly is established to analyze the stress law of cement sheath. The integrity of the cement sheath is analyzed. The results show that the elastic modulus of cement is 6 GPa and the Poisson’s ratio is 0.17. The compressive strength and tensile strength of cement after cyclic loading are 90MPa and 7.5mpa ~ 11.25mpa respectively. The maximum radial stress of cement sheath increases with the increase of fracturing pressure, the decrease of displacement, and the increase of elastic modulus. The maximum tangential stress of cement sheath increases with the increase of fracturing pressure and elastic modulus of cement. The tensile strength of cement sheath cannot meet hydraulic fracturing requirements. The elastic modulus of cement should be reduced to 4 GPa or the tensile strength should be increased to be higher than 15 MPa. This study would guide the shale oil wells in northeast China. 1. INTRODUCTION As hydraulic fracturing technology matures and international oil prices recover, more and more unconventional oil and gas resources are being developed, such as shale gas, conglomerate reservoirs, and shale oil. In particular, shale oil resources are becoming a new direction of exploration and development of unconventional oil and gas resources in China. Shale oil has been developed scaled in Jimsar block, in Inner Mongolia, and Tianjin district. At the same time, shale oil resources have been successfully explored in northeast China and will soon enter the stage of large-scale development. Based on the development experience of shale gas and other unconventional oil and gas resources over the past few years, casing deformation and sustained casing pressure are the most common problems in horizontal wells during multistage fracturing (Adams, 2017; Atkinson, 2020; Chaojie Zhao, 2020; Xi Yan, 2021.). Well integrity issues have a significant impact on the safety and production of horizontal wells. Fig. 1 shows the casing deformation logging results of Wel-Wei204H39-6 in the Weiyuan block and Well-JHW033 in Jimsar Block, Xinjiang respectively. Logging results showed casing deformation in both wells. One of the wells is a shale gas horizontal well and the other is a shale oil horizontal well. Thus, shale oil wells face the same well integrity issues as shale gas wells.

Experiments and analysis on the influence of multiple closed cemented natural fractures on hydraulic fracture propagation in a tight sandstone reservoir

A review of the current status of induced seismicity monitoring for hydraulic fracturing in unconventional tight oil and gas reservoirs

Accurate modeling of hydrocarbon production is a necessary, yet challenging step for economic exploitation of unconventional resources. One of the main challenges is to model flow to a horizontal well from a complex network of hydraulic and natural fractures. Many unconventional reservoirs comprise well-developed natural fracture networks with multiple orientations and complex hydraulic fracture patterns based on microseismic data. Conventional dual porosity and dual permeability models are not adequate for modeling these complex networks of natural and hydraulic fractures. Also, it is neither practical nor advantageous to model a large number of pre-existing fractures with a discrete fracture model. Therefore, an appropriate approach to model production from low-permeability reservoirs is to perform discrete fracture modeling for hydraulic fractures and employ a dual continuum approach for numerous natural fractures. We have developed a coupled dual continuum and discrete fracture method to simulate production from unconventional oil and gas reservoirs. Large-scale hydraulic fractures (macro-fractures) are modeled explicitly using a discrete fracture model, called EDFM, and numerous small-scale natural fractures (micro-fractures) are modeled using a dual continuum approach. The hybrid model includes three domains: matrix, discrete-fracture, and continuum-fracture domains. A systematic approach is devised to calculate transport parameters between all three domains. Moreover, EDFM allows for not only transverse and longitudinal hydraulic fractures but also macro-fractures of any orientation. Thus, the coupled model provides an effective and reliable environment to improve stimulation designs and completion strategies. We present several examples in this study to show the applicability, robustness, and performance of the hybrid method for the simulation of unconventional oil and gas reservoirs. We examine multi-stage hydraulic fractures with multiple configurations in the presence of numerous pre-existing fractures. Simulations show a noticeable contribution from natural fracture networks on total production. Furthermore, for the tight oil reservoir examined in this study, the stimulation scheme with longer hydraulic fractures improves cumulative oil production compared to the scheme with larger number of shorter hydraulic fractures. We also examine production from a tight gas reservoir wherein hydraulic fractures partially penetrate the formation height. Simulations indicate that inefficient fracture treatment can result in significant loss of production.

The development of unconventional oil and gas resources is becoming increasingly challenging, with artificial intelligence (AI) emerging as a key technology driving technological advancement and industrial upgrading in this field. This paper systematically reviews the current applications and development trends of AI in unconventional oil and gas exploration and development, covering major research achievements in geological exploration; reservoir engineering; production forecasting; hydraulic fracturing; enhanced oil recovery; and health, safety, and environment management. This paper reviews how deep learning helps predict gas distribution and classify rock types. It also explains how machine learning improves reservoir simulation and history matching. Additionally, we discuss the use of LSTM and DNN models in production forecasting, showing how AI has progressed from early experiments to fully integrated solutions. However, challenges such as data quality, model generalization, and interpretability remain significant. Based on existing work, this paper proposes the following future research directions: establishing standardized data sharing and labeling systems; integrating domain knowledge with engineering mechanisms; and advancing interpretable modeling and transfer learning techniques. With next-generation intelligent systems, AI will further improve efficiency and sustainability in unconventional oil and gas development.

Editor's column The growth in unconventionals production and the spotlight on hydraulic fracturing have heightened public concern about oil and gas industry operations and raised the stakes for those working in the industry. News media reports, movies, Internet blogs, and political debate have combined to add scrutiny to upstream operations and their potential impact on health, the environment, and local communities. It has become not only an industry and company issue, but an individual one as well. Many engineers and other staff in the industry are getting questions about their companies’ operations from neighbors and others in their communities. Hydraulic fracturing is usually the focal point. Even though fracturing has been used by the industry since the late 1940s, many believe it is a new technology that potentially threatens water supplies and spawns other negative effects. Anti-fracturing initiatives are currently being proposed in numerous cities and states around the United States. A number of resources are available to help members of the industry answer these questions. SPE’s www.energy4me site offers information on hydraulic fracturing and other industry technologies, classroom resources for teachers, and industry careers. Other industry-affiliated associations, including the American Petroleum Institute (API) and the Independent Petroleum Association of America, provide materials as well. The API recently issued what it calls the “gold standard” for how companies and management should engage with communities affected by exploration and development of unconventional oil and gas resources. ANSI-API Bulletin 100-3 was released after 3 years of discussions with producers, community leaders, US state regulators, property owners, and other stakeholders.

The development of most unconventional oil and gas resources relies upon subsurface injection of very large volumes of fluids, which can induce earthquakes by activating slip on a nearby fault. During the last 5 years, accelerated oilfield fluid injection has led to a sharp increase in the rate of earthquakes in some parts of North America. In the central United States, most induced seismicity is linked to deep disposal of coproduced wastewater from oil and gas extraction. In contrast, in western Canada most recent cases of induced seismicity are highly correlated in time and space with hydraulic fracturing, during which fluids are injected under high pressure during well completion to induce localized fracturing of rock. Furthermore, it appears that the maximum-observed magnitude of events associated with hydraulic fracturing may exceed the predictions of an often-cited relationship between the volume of injected fluid and the maximum expected magnitude. These findings have far-reaching implications for assessment of inducedseismicity hazards.

Surrogate-assisted hydraulic fracture optimization workflow with applications for shale gas reservoir development: a comparative study of machine learning models

Hydraulic fracturing technology is being widely used within the oil and gas industry for both waste injection and unconventional gas production wells. It is essential to predict the behavior of hydraulic fractures accurately based on understanding the fundamental mechanism(s). The prevailing approach for hydraulic fracture modeling continues to rely on computational methods based on Linear Elastic Fracture Mechanics (LEFM). Generally, these methods give reasonable predictions for hard rock hydraulic fracture processes, but still have inherent limitations, especially when fluid injection is performed in soft rock/sand or other non-conventional formations. These methods typically give very conservative predictions on fracture geometry and inaccurate estimation of required fracture pressure. One of the reasons the LEFM-based methods fail to give accurate predictions for these materials is that the fracture process zone ahead of the crack tip and softening effect should not be neglected in ductile rock fracture analysis. A 3D pore pressure cohesive zone model has been developed and applied to predict hydraulic fracturing under fluid injection. The cohesive zone method is a numerical tool developed to model crack initiation and growth in quasi-brittle materials considering the material softening effect. The pore pressure cohesive zone model has been applied to investigate the hydraulic fracture with different rock properties. The hydraulic fracture predictions of a three-layer water injection case have been compared using the pore pressure cohesive zone model with revised parameters, LEFM-based pseudo 3D model, a Perkins-Kern–Nordgren (PKN) model, and an analytical solution. Based on the size of the fracture process zone and its effect on crack extension in ductile rock, the fundamental mechanical difference of LEFM and cohesive fracture mechanics-based methods is discussed. An effective fracture toughness method has been proposed to consider the fracture process zone effect on the ductile rock fracture.

The Australian Government’s $35.4 million Geological and Bioregional Assessment (GBA) Program is assessing the potential impacts of shale, tight and deep coal gas development on water and the environment in the Beetaloo, Isa and Cooper GBA regions. This paper compares the outcomes of impact assessments for the Beetaloo and Cooper GBA regions, highlighting the role that local geology, hydrogeology, ecology and regulatory regimes play when assessing potential impacts of unconventional gas development. Unconventional gas development activities between basins are broadly consistent, involving drilling, stimulation of the reservoir (typically through hydraulic fracturing), production and processing of hydrocarbons, export to market and decommissioning and rehabilitation. The characteristics of these activities and their potential impacts are strongly influenced by local factors including the geology, environment, industry practices and regulatory regimes. While subsurface impacts associated with hydraulic fracturing and well integrity are considered unlikely in both regions, regional geology means there is greater stratigraphic separation between target resources and overlying aquifers in the Beetaloo Sub-basin than in the Cooper Basin. Local ecological conditions and species influence the nature of potential impacts on protected matters in the two basins, which are mostly associated with surface disturbance and spills or accidental release of fluids. A key similarity between the two regions is the broadly consistent regulation and management of potential impacts in the two basins. Preliminary results of the causal network analysis indicate that mitigation measures are available for all pathways in which unconventional gas resource development activities may have the potential to impact on endpoints.

As conventional gas resources are depleted, unconventional gas (UG) resources (gas from tight sands, coal beds, and shale) are becoming increasingly important to U.S. and world energy supply. The volume of UG resources is generally unknown in most basins outside North America. However, in 25 mature North American basins, UG resources have been produced for decades, and resources and reserves are well characterized. The objective of this work was to evaluate recoverable UG resources and determine the quantitative relations between known conventional and unconventional hydrocarbon resources in mature North American basins, with the goal of using these relations to estimate unconventional hydrocarbon resources in basin outside North America, which we call frontier basins.We used data from the U.S. Geological Survey, Potential Gas Committee, Energy Information Administration, National Petroleum Council, and Gas Technology Institute to evaluate relations among hydrocarbon resource types in the Appalachian, Black Warrior, Greater Green River, Illinois, San Juan, Uinta-Piceance, and Wind River basins. We chose these seven basins for preliminary analysis of relations between conventional and unconventional gas resources because they are mature basins for both conventional and unconventional oil and gas production. To conduct this analysis, we wrote a computer program that we call PRISE (Petroleum Resources Investigation Summary and Evaluation). Input data for PRISE, obtained from the published data sources, were the values of technically recoverable resources, which were the sum of the following resource categories: cumulative production, proved reserves, growth, and undiscovered recoverable resources. We then compared technically recoverable conventional and unconventional resources for each basin to evaluate relationship between conventional and unconventional resource volumes in these seven basins.For the seven basins studied, we found that 10% of the total recoverable hydrocarbon resources are conventional oil and gas, whereas 90% of the recoverable hydrocarbons are unconventional resources. We propose that the results of this study may be used to estimate recoverable resources from unconventional gas reservoirs in target (frontier) basins, where conventional oil and gas resources are known but unconventional resources have not been evaluated.

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 131786, ’Integration of Microseismic and Other Post-Fracture Surveillance With Production Analysis: A Tight Gas Study,’ by C.R. Clarkson, SPE, University of Calgary, and J.J. Beierle, SPE, Talisman Energy, prepared for the 2010 SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania, 23-25 February. The paper has not been peer reviewed. Quantitative production analysis of tight gas reservoirs is a challenge because of complex reservoir characteristics, induced-hydraulic-fracture properties in vertical wells, operational complexities, and data quality. These challenges make extracting reservoir and hydraulic-fracture properties (i.e., fracture half-length, xf, and fracture conductivity) solely from production and flowing-pressure data difficult, often resulting in nonunique answers. Many tight gas reservoirs are exploited with horizontal wells, often stimulated with multiple hydraulic fractures, imparting greater complexity to the analysis. Flow-regime identification, which is critical to correct analysis, becomes more complicated because of the variety of flow regimes that could be encountered in such wells. Introduction Development of tight gas, shale gas, and coalbed methane (collectively referred to as unconventional gas reservoirs) benefits from advances in drilling, completions, and stimulation technology; formation evaluation; and during-/post-stimulation-surveillance technology. Formation-evaluation techniques enable determining critical parameters such as matrix permeability in ultratight rock from cores, and adsorbed- and free-gas content in shale and coalbed methane from cores and cuttings. During-/post-fracture-stimulation-surveillance technology (such as microseismic monitoring) aids identifying the hydraulic-fracture geometry created in unconventional reservoirs (hydraulic-fracture growth), particularly in coals and shales. Predicting hydraulic-fracture geometries is complicated by heterogeneities, such as natural fractures (healed or open) and layering (with associated contrasts in mechanical properties), and in some cases, by nonlinear elastic behavior. Advanced production-analysis techniques, such as production type curves, supplement reservoir and stimulation information obtained from pressure-transient analysis (well testing) in conventional oil and gas reservoirs and even some unconventional reservoirs such as coalbed methane and tight gas. However, applying these methods to tight gas and shale reservoirs that are produced through multifractured horizontal wells has been difficult because of the complexity of the system, poor quality of flowing-pressure and rate data, and the lack of sufficient data to characterize the system fully. Even if the production and flowing-pressure data were of sufficient quality to identify flow regimes, as in pressure-transient analysis, without additional surveillance information, it is difficult to ascertain how the flow regimes relate to the reservoir and hydraulic-fracture system. If the flow regimes are misinterpreted, then the extracted information will be incorrect. A workflow is proposed to improve the quality of information extracted from production-data analysis (PDA) of hydraulically fractured horizontal wells completed in tight gas reservoirs.

The global development of unconventional gas resources is progressing at a remarkable pace, owing to technology advancements, supportive regulatory environments, and expectations of favourable long-term market conditions. In Australia, the sheer scale of the resource potential, the increase in political and public will towards CO2 emissions reduction, and an immediate desire for greater local economic production suggests that exploration and production activity is likely to accelerate in the coming years. The unconventional gas sector, however, has been affected by negative publicity, with attention drawn to the potential environmental impacts and public burden associated with development practices—especially hydraulic fracturing. Stakeholder concerns regarding the significant water requirements, emissions footprint, and infrastructure impacts across the development lifecycle represent significant challenges. This extended abstract focuses on the use of structured decision-making approaches used in the appraisal phase of unconventional gas developments in the US to identify and manage the technical and especially non-technical risks that impact a development’s cost, schedule, and profitability across its lifecycle. An unconventional gas development from the US is presented, where a framework for integrating commercial, public, and environmental concerns from corporate and external stakeholders into field concept development and selection has been successfully applied. The development, which faces resource and regulatory challenges related to water management, air emissions, and local infrastructure impacts, employed fit-for-purpose decision-making tools that quantified non-technical development risks to inform the evaluation and selection of concepts that best met economic, corporate, and stakeholder expectations.

In tight gas sandstone, relative permeability is an essential special core analysis dynamic test that can be used to estimate injectivity, secondary recovery, production rate, reservoir simulation, residual gas saturation, and effective water management. Having about 65% of hydraulic fracturing fluid not to flow back and stay in the reservoir results in having the tight sandstone gas reservoir to involve multi-phase flow, namely water and gas. During the hydraulic fracturing job both imbibition and forcibly imbibition processes take place while during fracturing fluid cleanup and gas production drainage flow becomes dominant. The steady state flooding process was used to measure the relative permeability curves for tight sandstone core sample collected from Travis Peak Formation at a depth of 8707 ft. The measurement process involved the performance of a series of steady state experiments with different gas-water injection ratio. The fractional flow curve has been plotted, based on the measured relative permeability, and used to calculate the displacement efficiency for the flow through such type of tight porous media. The measurement showed relatively high irreducible water saturation (31%) and low residual gas saturation (6%). The measured gas relative permeability decreased slowly at a constant rate with increased wetting fluid saturation. The obtained fractional flow curve does not follow the s-shape behavior observed in conventional reservoir. The obtained results showed that displacement efficiency can be enhanced by increasing water viscosity.

Reliable estimates of hydraulic fracture geometry help reduce the uncertainty associated with estimated ultimate recovery (EUR) forecasts and optimize field developing planning in unconventional reservoirs. For these reasons, operators gather information from different sources with the objective to calibrate their hydraulic fracture models. Microseismic data is commonly acquired by operators to estimate hydraulic fracture geometry and to optimize well completion designs. However, relying solely on estimates derived from microseismic information may lead to inaccurate estimates of hydraulic fracture geometry. The objective of this study is to efficiently calibrate hydraulic fracture geometry by using microseismic data, physics-based fracture propagation models, and the embedded discrete fracture model (EDFM). We first obtain preliminary estimates of fracture geometry based on microseismic events’ spatial location and density with respect to the perforation cluster location. We then tune key completion parameters using an in-house fracture propagation model to provide hydraulic fracture geometries that are constrained by the microseismic cloud. In the history matching process, we included the effect of natural fractures, using the microseismic events location as natural fracture initiation points. Finally, we used cutoff coefficients to further reduce hydraulic fracture geometries to match production data. The results of this work showed a fast and flexible method to estimate fracture half-lengths and fracture heights, resulting in a direct indicator of the completion design. Additionally, hydraulic-natural fracture interactions were assessed. We concluded that the inclusion of cutoff coefficients as history matching parameters allows to derive realistic hydraulic and natural fracture models calibrated with microseismic and production data in unconventional reservoirs.