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Pei, Yanli (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin / Sim Tech LLC) | Sepehrnoori, Kamy (The University of Texas at Austin) | Gong, Yiwen (Sim Tech LLC / The Ohio State University) | Xie, Hongbin (Sim Tech LLC) | Wu, Kan (Texas A&M University)
The extensive depletion of the development target has triggered the demand for infill drilling in the upside target of multilayer unconventional reservoirs. To optimize the hydraulic fracturing design of newly drilled wells, we need to investigate the stress changes in the upside target induced by parent-well production. In this work, an integrated parent-child workflow is presented to model the spatial-temporal stress evolution and propose the optimal development strategy for the upside target using a data set from the Permian Basin. The stress dependence of matrix permeability and fracture conductivity is determined based on available experimental data and incorporated in our reservoir simulation with the aid of an embedded discrete fracture model (EDFM). With calibrated reservoir properties from history matching of an actual well in the development target (i.e., 3rd BS Sand), we run the finite element method (FEM) based geomechanics simulator to predict the 3D spatial-temporal evolution of the local principal stresses. A displacement discontinuity method (DDM) hydraulic fracture model is then applied to simulate the multi-cluster fracture propagation in the upside target (i.e., L2BSSh) with the updated heterogeneous stress field. Numerical results indicate that stress field redistribution associated with parent-well production not only occurs within the development target but also vertically propagates to the upside target. A smaller parent-child horizontal offset induces a severer deviation of child-fractures towards the parent wellbore, resulting in more substantial well interference and less desirable oil and gas production. The parent-child fracture overlapping ratio in our study is in 0.6 ~ 0.8 for the 400 ft horizontal offset and 0.2 ~ 0.5 for the 600 ft horizontal offset. Varying the parent-child vertical offset gives the same trend as we change the horizontal offset. But with a delayed infill time, placing child-well in different layers causes more significant variation in the ultimate recovery. Moreover, infill operations at an earlier time are less affected by parent-well depletion because of the more homogeneous stress state. The candidate locations to implement infill-wells are suggested in the end for different infill timing by co-simulation of the parent-child production. With the reservoir-geomechanics-fracture model, this work provides a general workflow to optimize the child-well completion in multilayer unconventional reservoirs. The conclusions drawn from this study are of guiding significance to the subsequent development in the Permian Basin.
Rosenhagen, Nicolas M. (Colorado School of Mines) | Nash, Steven D. (Anadarko Petroleum Corporation) | Dobbs, Walter C. (Anadarko Petroleum Corporation) | Tanner, Kevin V. (Anadarko Petroleum Corporation)
Abstract The volume of stimulation fluid injected during hydraulic fracturing is a key performance driver in the horizontal development of the Niobrara formation in the Denver-Julesburg (DJ) Basin, Colorado. Oil production per well generally increases with stimulation fluid volume. Often, operators normalize both production and fluid volume based on stimulated lateral length and investigate relationships using "per-ft" variables. However, data from well-based approaches commonly display such wide distributions that no useful relationships can be inferred. To improve data correlations, multivariate analysis normalizes for parameters such as thermal maturity, depth, depletion, proppant intensity, drawdown, geology and completion design. Although advancements in computing power have decreased cycle times for multivariate analysis, preparing a clean dataset for thousands of wells remains challenging. A proposed analytical method using publicly available data allows interpreters to see through the noise and find informative correlations. Using a data set of over 5000 wells, we aggregate cumulative oil production and stimulation fluid volumes to a per-section basis then normalize by hydrocarbon pore volume (HCPV) per section. Dimensionless section-level Cumulative Oil versus Stimulation Fluid Plots ("Normalization" or "N-Plot") present data distributions sufficiently well-defined to provide an interpretation and design basis of well spacing and stimulation fluid volumes for multi-well development. When coupled with geologic characterization, the trends guide further refinement of development optimization and well performance predictions. Two example applications using the N-Plot are introduced. The first involves construction of predictive production models and associated evaluation of alternative development scenarios with different combinations of well spacing and completion fluid intensity. The second involves "just-in-time" modification of fluid intensity for drilled but uncompleted wells (DUC's) to optimize cost-forward project economics in an evolving commodity price environment.
Oraki Kohshour, Iman (University of Wyoming) | Leshchyshyn, Tim (FracKnowledge/Fracturing Horizontal Well Completions Inc.) | Munro, Jason | Yorro, Meaghan Cassey (Forum Energy Technologies) | Adejumo, Adebola T (Halliburton) | Ahmed, Usman (Unconventional Oil and Gas Technology and Development and WellDog) | Barati, Reza (University of Kansas) | Kugler, Imre (IHS Markit) | Reynolds, Murray (Ferus) | Cullen, Mike (Ferus) | McAndrew, James (Air Liquide) | Wedel, Dave (Air Liquide)
Summary With increasingly stringent regulations governing the use of fresh water in hydraulic fracturing, operators are struggling to find alternative sources of fracture fluid for hydraulic fracturing operations. In some regions of the world where abundant fresh water is not available, such as the Middle East and China, using large amounts of fresh water for fracturing is not possible to develop fields. FracKnowledge Database tracking of USA water usage per well indicates that, on average, a well requires 3 to 6 million gallons of water, even up to 8 million for the entire life cycle of the well based on its suitability for re-fracturing. This depends on the number of fracturing stages and particular characteristics of the producing formation. The same industry sources also suggest that about 30 to 70% of injected water remains in the formation with unknown fate and potential consequences to formation damage. Sourcing, storage, transportation, treatment, and disposal of this large volume of water could account for up to 10% of overall drilling and completion costs. As a transition to a reliable and complete replacement for water in the fracturing fluid, mixtures of fresh water with produced and brackish water are being applied. On the other hand, waterless fracturing technology providers claim their technology can solve the concerns of water availability for shale development. These waterless or minimal water methods have been used for decades, but are higher cost than conventional water fracturing techniques and have usually been used in water sensitive formations that required the technology. This study reviews high-level issues and opportunities in this challenging and growing market and evaluates key drivers behind water management practices such as produced and flow-back water, waterless fracturing technologies and their applications in terms of technical justification, economy and environmental footprint, based on a given shale gas play in the United States and experience gained in Canada. Water management costs are analyzed under a variety of scenarios with and without the use of fresh water. The results are complemented by surveys from several oil and gas operators. With low economic margins associated with shale resource development, operators need to know which practices give them more advantages and whether waterless methods are capable of fracturing the wells at optimal conditions. Based on a high-level economic analysis of cost components across the water management value chain, we can observe relative differences among approaches. Our analysis does not consider the effect of fracture fluid on productivity, which can be considerable in practice. Bearing this limitation in mind, as one might expect, fresh water usage offers the greatest economic return. In regions where water sourcing is a challenge, however, the short-term economic advantage of using non-fresh water-based fracturing outweighs the capital costs required by waterless fracturing methods. Until waterless methods are cost competitive, recycled water usage with low treatment offers a similar NPV to that of sourcing freshwater via truck, for instance. Despite positive experiences with foamed fracturing techniques in Canada, and the potential improvements offered by these techniques, the technology is still challenging to apply in large scale fracturing jobs in the United States, primarily due to operators' perceived level of technology complications, safety, economics, and other logistics. However, if these emerging technologies become widely accepted, the development of shale resources, especially in those basins exposed to drought, has the potential to grow both nationally and internationally. Although environmentally friendlier than using fresh water, the environmental aspects of these technologies must be clarified and deserve closer examination. Such variables must be reviewed based on specific shale reservoir characterizations before implementation on a large scale, and there are numerous other supply logistics and HSSE-SR (Health, Safety, Security, Environment, and Social Responsibility) issues that need additional discussion. Conclusions regarding current and future shale development have been proposed based on results from comprehensive technical, environmental, economic, and regulatory evaluations.
Abstract Although high gas flow rates from shales are a relatively recent phenomenon, the knowledge bases of shale-specific well completions, fracturing and shale well operations have actually been growing for more than three decades and shale gas production reaches back almost one hundred ninety years. During the last decade of gas shale development, projected recovery of shale gas-in-place has increased from about 2% to estimates of about 50%; mainly through the development and adaptation of technologies to fit shale gas developments. Adapting technologies, including multi-stage fracturing of horizontal wells, slickwater fluids with minimum viscosity and simultaneous fracturing, have evolved to increase formation-face contact of the fracture system into the range of 9.2 million m (100 million ft) in a very localized area of the reservoir by opening natural fractures. These technologies have made possible development of enormous gas reserves that were completely unavailable only a few years ago. Current and next generation technologies promise even more energy availability with advances in hybrid fracs, fracture complexity, fracture flow stability and methods of re-using water used in fracturing. This work surveyed over 350 shale completion, fracturing and operations publications, linking geosciences and engineering information together to relay learnings that will identify both intriguing information on selective opening and stabilizing of micro-fracture systems within the shales and new fields of endeavor needed to achieve the next level of shale development advancement.