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Two places that illustrate the mounting challenges facing the shale business are the Bakken Shale in North Dakota, where the number of working rigs is one-third what it was a year ago, and the Fayetteville Shale in Arkansas, where there are no more working rigs. An analysis of thousands of fracturing treatments in major plays in the United States provides insights into how fracture designs have changed over time.
Many methods exist for forecasting the production rate from unconventional reservoirs, but all have limitations. Recently, several publications have appeared relating the expected ultimate recovery (EUR) to the initial rate or the cumulative production after 3, 6, or 24 months. In the complete paper, these publications are reviewed, and their learnings extended, to several unconventional reservoirs. Work in 2018 studied 147 MFHWs covering many formations in the Permian Basin and a wide range of input variables and determined EUR using rate transient analysis, numerical simulation, and decline-curve analysis. The authors of that work compared the EUR with various cumulative production intervals (3, 6, 12, and 24 months) and concluded that the correlation with 3 months was poor; 24 months’ cumulative production was an accurate predictor of EUR but was not considered to be an early-enough predictor.
Summary In a previous work, we introduced a three-parameter scaling solution that models the long-term recovery of dry gas from a hydrofractured horizontal well far from other wells and the boundaries of a shale reservoir with negligible sorption. Here, we extend this theory to account for the contribution of sorbed gas and apply the extended theory to the production histories of 8,942 dry-gas wells in the Marcellus Shale. Our approach is to integrate unstructured big data and physics-based modeling. We consider three adsorption cases that correspond to the minimum, median, and maximum of a set of measured Langmuir isotherms. We obtain data-driven, independent estimates of unstimulated shale permeability, spacing between hydrofractures, well-drainage area, optimal spacing between infill wells, and incremental gas recovery over a typical well life. All these estimates decrease to varying extents with increasing sorption. We find that the average well with median adsorption has a permeability of 250 nd, fracture spacing of 16 m, 30-year drainage length of 79 m, and a 30-year incremental recovery of 67%. Introduction Since 2012, the Marcellus Shale has been by far the most productive US shale play. Producing 25% of the total US dry natural gas, the Marcellus Shale currently produces at least three times more natural gas than any other major US shale play, including, in order of decreasing production, the Permian, Haynesville, Utica, Eagle Ford, Barnett, Woodford, Fayetteville, and Antrim shales (Figure 1). This high productivity has attracted significant attention from developers. The majority of drilling activities have taken place in two sweet spots: northeastern Pennsylvania, which primarily contains dry gas, and southwestern Pennsylvania and northern West Virginia, which produce liquid-rich gas (Popova 2017). Since leading US shale-gas production for the first time in 2012, the Marcellus Shale currently produces three times more than the Permian Basin, the runner-up shale-gas producer. Given how important Marcellus is to the US economy and energy security, it seems worthwhile to comb through the available production data and attempt to extract key information from the wells that are active and productive.
Bian, Xiaobing (Sinopec Research Institute of Petroleum Engineering) | Ding, Shidong (Sinopec Research Institute of Petroleum Engineering) | Jiang, Tingxue (Sinopec Research Institute of Petroleum Engineering) | Xiao, Bo (Sinopec Research Institute of Petroleum Engineering) | Su, Yuan (Sinopec Research Institute of Petroleum Engineering) | Li, Shuangming (Sinopec Research Institute of Petroleum Engineering) | Wei, Ran (Sinopec Research Institute of Petroleum Engineering) | Wang, Haitao (Sinopec Research Institute of Petroleum Engineering) | Du, Tao (Sinopec Research Institute of Petroleum Engineering)
Relatively, the gas production is low for fractured horizontal wells in normal pressure shale gas plays with a quick production decrease, resulting in larger difficulty for commercial breakthrough and economic development. Accordingly fracturing technology is under study urgently.
On condition that production increased and engineering cost decreased, together with feasible and practical fracturing technology, the production potential is studied to put forward several hydraulic fracturing treatment. Firstly, cluster spacing is decreased, while increasing cluster number per stage, thus, there are more total clusters for one well with less stages, the influence of induced stress could be strengthened especially using plane perforation. Secondly, using high viscosity gel as pre fluid or flushing fluid among injecting period, to extend fracture through layers vertically. Thirdly, by use of ultra-low density small mesh proppant, increasing net pressure sharply by plugging the front of fracture. Fourthly, increasing ratio of lower viscosity slick water, small mesh proppant and higher viscosity gel, to improve hydraulic fracturing pumping pattern and technological parameter by varying viscosity, varying displacement, varying mesh proppant, so multiscale fracture propagate and propped with corresponding size of proppant. Fifthly, deminishing lower effective and non-effective clusters through studying geological and engineering sweetness.
Aiming at production increased and engineering cost decreased, the production potential is studied to put forward several hydraulic fracturing treatment, which is feasible and practical. Good result was observed in pilot application of D well and L well, providing theoretical support for developing effectively and economically in similar shale gas play.
Singh, Amit (Chevron Corporation) | Liu, Xinghui (Chevron Corporation) | Wang, Shugang (Chevron Corporation) | Tan, Yunhui (Chevron Corporation) | Li, Yan (Chevron Corporation) | Naik, Sarvesh (Chevron Corporation) | Rijken, Peggy (Chevron Corporation)
Successful development of unconventional resources (UCR) depends on the planning and execution of economic and efficient hydraulic fracturing stimulation. In the last decade, multistage hydraulic fracturing technologies have significantly improved and matured with more than 50,000 wells being drilled and completed every year across different UCR resources. Still, opportunities exist for continuous improvement and optimization of multiple design parameters of hydraulic fracturing job planning and execution. Solutions have been developed for these opportunities to maximize productivity and Estimated Ultimate Recovery (EUR) with economic development practices.
The key components of hydraulic fracturing in UCR wells were reviewed to identify opportunities for improvement in efficiency and effectiveness. This covered design and decisions regarding horizontal well landing, number of fracture clusters per stage, proppant and frac fluid type and quantity, propped and unpropped fracture contribution, fracture interaction and stress evolution during well life. Collection & analysis of various diagnostic data along with application of fit-for-purpose software tools in area of numerical geomechanics, fracture modeling, Computational Fluid Dynamics (CFD) modeling and reservoir simulations were used to study the mechanisms and gain learnings. In-house tools and integrated workflows are developed to achieve solutions for optimum stimulation design and develop best practices for each of opportunities identified in hydraulic fracture stimulation of UCR wells.
The integrated solution has provided economic and efficient design to maximize productivity and EUR by capturing all segments of hydraulic fracturing process. The integrated workflow showed the importance of incorporating geomechanical parameters in addition to geologic and geophysical properties while selecting best rock for horizontal well landing to ensure maximum coverage of good quality rock with fracture and fracture to wellbore connectivity. The case specific optimum perforation cluster design using in-house developed fracture entry optimization tool reduced cost with ability to successfully pump up to 15 cluster per stage with increased fracture placement efficiency. The proppant transport study in wellbore and fracture using CFD modeling highlighted the optimum combination of fracture fluid viscosity range and proppant type (size and density) to maximize proppant transport for required propped and unpropped conductivity as per formation petrophysical properties. The analysis of stress evolution during fracturing and production life of well due to depletion using numerical coupled geomechanics provided quantification of effective stress on proppant for selection of low-cost local sand as proppant and drawdown management solution.
The integrated analysis of individual component of overall stimulation process provided many key learnings and best practices to achieve economic improvement of productivity and EUR. The fit-for-purpose tools and workflows provided optimum economic solution to maximize both early time production and EUR with ability to successfully pump 10-14 clusters per stage using smaller local sands and slickwater in horizontal wells landed in best rock and produced at optimum drawdown.
Liang, Feng (Aramco Services Company: Aramco Research Center—Houston) | Han, Yanhui (Aramco Services Company: Aramco Research Center—Houston) | Liu, Hui-Hai (Aramco Services Company: Aramco Research Center—Houston) | Saini, Rajesh (Aramco Services Company: Aramco Research Center—Houston) | Rueda, Jose I. (Saudi Aramco)
Hydraulic fracturing has been widely used in stimulating tight carbonate reservoirs to improve oil and gas production. Improving and maintaining the connectivity between the natural and induced microfractures in the far-field and the primary fracture networks are essential to enhancing the well production rate because these natural and induced unpropped microfractures tend to close after the release of hydraulic pressure during production. This paper provides a conceptual approach for an improved hydraulic fracturing treatment to enhance the well productivity by minimizing the closure of the microfractures in tight carbonate reservoirs and enlarging the fracture aperture.
The proposed improved fracturing treatment was to use the mixture of the delayed acid-generating materials along with microproppants in the pad/prepad fluids during the engineering process. The microproppants were used to support the opening of natural or newly induced microfractures. The delayed acid-generating materials were used in this strategy to enlarge the flow pathways within microfractures owing to degradation introduced under elevated temperatures and interaction with the calcite formation.
The feasibility of the proposed approach is evaluated by a series of the proof-of-concept laboratory coreflood experiments and numerical modeling results. First, one series of experiments (Experiments 1–3) was designed to investigate the depth of the voids on the fracture surface generated by the solid delayed acid-generating materials under different flow rates of the treatment fluids and different temperatures. This set of tests was conducted on a core plug assembly that was composed of half-core Eagle Ford Sample, half-core hastelloy core plug, and a mixture of solid delayed acid-generating materials [polyglycolic acid (PGA)] along with small-sized proppants sandwiched by two half-cores. Surface profilometer was used to quantify the surface-etched profile before and after coreflood experiments. Test results have shown that PGA materials were able to create voids or dimples on the fracture faces by their degradation under elevated temperature and the chemical reaction between the generated weak acid and the calcite-rich formation. The depth of the voids generated is related to the treatment temperature and the flow rate of the treatment fluids. Experiment 4 was conducted using two half-core splits to quantify the improvement factor of the core permeability due to the treatment with mixed sand and PGA materials.
Simulations of fluid flow through proppant assembly (inside of the microfractures) using the discrete element method (DEM)–lattice Boltzmann method (LBM) coupling approach for three different scenarios (14 cases in total) were further conducted to evaluate the fracture permeability and conductivity changes under different situations such as various gaps between proppant particulates and different depths of voids generated on fracture faces: (1) fluid flow in a microfracture without proppant, (2) fluid flow in a microfracture with small-sized proppants, and (3) fluid flow in a microfracture supported by small-sized proppants and generated voids on the fracture walls. The simulation results show that with proppant support (Scenario 2), the microfracture permeability can be increased by tens to hundreds of times in comparison to Scenario 1, depending on the gaps between proppant particles. The permeability of proppant-supported microfracture (Scenario 3) can be further enhanced by the cavities created by the reactions between the generated acid and calcite formation.
This work provides experimental evidence that using the mixture of the solid delayed acid-generating materials along with microproppants or small-sized proppants in stimulating tight carbonate reservoirs in the pad/prepad fluids during the engineering process may be able to effectively improve and sustain permeability of flow pathways from microfractures (either natural or induced). These findings will be beneficial to the development of an improved hydraulic fracturing treatment for stimulating tight organic-rich carbonate reservoirs.
Bailey, Adam H.E. (Geoscience Australia) | Jarrett, Amber J.M. (Geoscience Australia) | Bradshaw, Barry (Geoscience Australia) | Hall, Lisa S. (Geoscience Australia) | Wang, Liuqi (Geoscience Australia) | Palu, Tehani J. (Geoscience Australia) | Orr, Meredith (Geoscience Australia) | Carr, Lidena K. (Geoscience Australia) | Henson, Paul (Geoscience Australia)
The Isa Superbasin is a Paleoproterozoic to Mesoproterozoic succession (approximately 1670-1575 Ma), primarily described in north-west Queensland. Despite the basin's frontier status, recent exploration in the northern Lawn Hill Platform has demonstrated shale gas potential in the Lawn and River supersequences. Here, we characterise the unconventional reservoir properties of these supersequences, providing new insights into regional shale gas prospectivity.
The depths, thicknesses and mappable extents of the Lawn and River supersequences are based on the 3D geological model of Bradshaw et al. (2018). Source rock net thickness, total organic carbon (TOC), kerogen type and maturity are characterised based on new and existing Rock-Eval and organic petrology data, integrated with petroleum systems modelling. Petrophysical properties, including porosity, permeability and gas saturation, are evaluated based on well logs. Mineralogy is used to calculate brittleness (see also
Abundant source rocks are present in the Isa Superbasin succession. Overall, shale rock characteristics were found to be favourable for both sequences assessed; both the Lawn and River supersequences host thick, extensive, and organically rich source rocks with up to 7.1 wt% total organic carbon (TOC) in the Lawn Supersequence and up to 11.3 wt% TOC in the River Supersequence. Net shale thicknesses demonstrate an abundance of potential shale gas reservoir units across the Lawn Hill Platform.
With average brittleness indices of greater than 0.5, both the Lawn and River supersequences are interpreted as likely to be favourable for fracture stimulation. As-received total gas content from air-dried samples is favourable, with average values of 0.909 scc/g for the Lawn Supersequence and 1.143 scc/g for the River Supersequence
The stress regime in the Isa Superbasin and the surrounding region is poorly defined; however, it is likely dominated by strike-slip faulting. Modelling demonstrates limited stress variations based on both lithology and the thickness of the overlying Phanerozoic basins, resulting in likely inter- and intra-formational controls over fracture propagation. No evidence of overpressure has been observed to date, however, it is possible that overpressures may exist deeper in the basin where less permeable sediments exist.
This review of the shale reservoir properties of the Lawn and River supersequences of the Isa Superbasin significantly improves our understanding of the distribution of potentially prospective shale gas plays across the Lawn Hill Platform and more broadly across this region of northern Australia.
Zeng, Wenting (PetroChina Coalbed Methane Company) | Sun, Qian (Petroleum Engineering, Texas A&M University at Qatar) | Zhou, Linlang (PetroChina Southwest Oil and Gasfield Company) | Wang, Yuhe (Petroleum Engineering, Texas A&M University at Qatar)
The unique composition and structure of shale kerogen, which bear considerable amount of absorbed gas, greatly complicate the recovery mechanisms of natural gas and challenge the energy industry for efficient and environmentally friendly energy exploitation. In this study, the adsorption and diffusion characteristics of CH 4, CO 2 and their mixtures in kerogen matrix are investigated using GCGM (Grant Canonical Monte Carlo) and MD (Molecular Dynamics) simulations. The results verify that pressure has a positive effect on CH 4 and CO 2 adsorption capacity, while the effect of temperature is negative. It is found the isosteric heat of CO 2 is larger than CH 4, indicating a higher affinity of CO 2 to kerogen. The greater interaction between CO 2 and kerogen matrix causes the self-diffusion coefficient of CH 4 being larger than CO 2 at the same conditions. The competitive adsorption of CO 2 over CH 4 is higher at lower CO 2 model fraction, suggesting less amount of CO 2 is required to recover the same amount of CH 4 at the early stage of CO 2 injection. Due to the energetically heterogeneous characteristics of kerogen surface, with increasing pressure the adsorption selectivity goes up first and then declines. We hope that this work may server as a reference for the development of shale reservoirs by injecting CO 2 .
The objective of this research was to identify hydraulic fracturing regulations from a range of jurisdictions, verify the grounds for regulatory intervention within the scientific literature and categorize the statements according to the geospatial application. Specific regulations constraining aspects of hydraulic fracturing activities from jurisdictions across the world were collated to identify common features relating to environmental protection, administrative requirements and grammatical structure. Regulations from 55 jurisdictions including states in the US, provinces in Canada, Australian states, European countries, Africa and South America were assessed and common focus areas identified, allowing for the development of a regulatory suite of universal application. Regulations could be ascribed to partitions of the environment including the lithosphere, the atmosphere, the hydrosphere, biosphere and the social framework. Some 32 distinct elements were identified as frequent constraints to hydraulic fracturing located in three geospatial zones: off-site; wellsite; and, wellhead. The scientific literature for each of these areas was critically assessed and summary reviews developed as a comprehensive and wide ranging review of environmental impacts. The specific use of open ended risk regulation as part of control documents (a permit or regulatory framework) appears to have been promoted as a catchall in the absence of knowledge within the regulatory agency as if there is a lack of evidence supporting directed regulation.