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Years in the making, the recent steady rise in drilling in the Powder River Basin of northeast Wyoming is generating excitement reminiscent of the early days of currently more-established US onshore oil plays. The upturn in activity is resulting in double-digit production growth. Wells are bubbling over with oil, and operators are bubbling over with enthusiasm. This has been most evident in recent industry presentations, where decision makers from the basin's exclusive club of operators have gushed over what is becoming a core asset in their portfolios. Given the basin's oil richness, multiple stacked horizons, and well performance and economics, "we think it's comparable and competitive with the big-name basins--whether it's the Permian, SCOOP, or STACK," Joseph DeDominic, president and chief operating officer of Anschutz Exploration, said at a recent SPE Gulf Coast Section meeting on the basin.
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.
Zhan, Lang (Shell International Exploration and Production Inc.) | Tokan-Lawal, Adenike (Shell Exploration and Production Co.) | Fair, Phillip (Shell International Exploration and Production Inc.) | Dombrowski, Robert (Shell International Exploration and Production Inc.) | Liu, Xin (Shell International Exploration and Production Inc.) | Almarza, Veronica (Shell Exploration and Production Co.) | Girardi, Alejandro Martin (Shell Exploration and Production Co.) | Li, Zhen (Shell Exploration and Production Co.) | Li, Robert (Shell Exploration and Production Co.) | Pilko, Martin (Shell Exploration and Production Co.) | Joost, Noah (Shell Exploration and Production Co.)
Summary Hydraulic fractures play a central role in the performance of multistage fractured horizontal wells (MFHWs) in tight and shale reservoirs. Fracture conductivity variations and connection quality between fractures and wellbore (i.e., choking skins) strongly affect well productivity. However, convincing and high-quality evaluations of hydraulic fractures for these reservoirs are rare in literature because quantifying fracture properties requires decoupling them from fracture geometry and formation properties, a difficult task in most field conditions. A data gathering and hypothesis testing program was implemented using six multifractured horizontal wells in a pad in the Delaware Basin to improve our ability to reliably forecast well performance. A systematic approach utilizing production, shut-ins, and bottomhole pressure measurements (BHP) was conducted and used to evaluate the apparent flow capacity of hydraulic fractures. Two independent techniques were used in the data analyses to characterize the hydraulic fractures; namely, pressure transients for individual wells and significant well-to-well interference signals. Both techniques render similar decline rate interpretations for the sets of fracture conductivity/permeability from analysis of the pressure data, but there is a large difference in the uncertainty of the estimated results from these two methods. The first method used a radial/linear flow regime in successive pressure buildups in three of the six wells. Simulations and theoretical analysis show that this flow regime allows decoupling fracture conductivity from fracture geometry and matrix properties. This flow regime yields the total apparent fracture conductivity (TAFC), which represents the lump sum effect of fracture conductivity. In addition, this technique characterizes the connection condition between the dominant fractures and borehole, which can be estimated from the early derivative horizontal line in pressure transient log-log diagnostic plots with minimum assumptions. Specifically, the estimated TAFC ranges from 1,140 to 1,630 md-ft at early time of well life to 525 to 855 md-ft after 100 to 139 days in production, or about a 45 to 61% reduction among these wells. The second method uses time-lag of pulse interference responses between an active and observation well. With assumptions of low, mid, and high values of fracture porosity, fracture compressibility, and fluid viscosity, characteristic fracture permeability can be estimated. Because of the large uncertainty related to the assumed fracture porosity and fracture compressibility, the pulse interference method is not likely to deliver the same certainty range as successive pressure buildups using the radial/linear flow regime. The results of this work provide a better understanding of the mechanisms of flow transport inside hydraulic fractures and at the connection between the hydraulic fractures and wellbore. The estimated TAFC and its significant decline help improve hydraulic fracturing designs and build representative reservoir models for more reliable well performance modeling and forecasting.
Abstract The completion design process for most horizontal wells in shale reservoirs has become a statistical evaluation process, rather than an engineering-based process. Our paper presents an alternative approach using an engineering approach to define the reservoir properties and the effectiveness of the fracture treatments. We then use these results in an economic analysis that allows the engineer to be predictive with respect to how capital is spent in the completion process. This paper presents a methodology for both the evaluation of the reservoir and the design of the well completion where the engineer can make economic decisions and determine the change in the return on investment as a function of the change in capital expenditure. The engineer can then be able to “optimize” the completion and fracture treatment designs based on Net Present Value, Return on Investment or any other economic parameter desired. We use a rate transient analysis approach to estimate reservoir and fracture properties. We present case histories in the paper, and the interpretation of the production analyses of these case histories yields information about the formation permeability and the effective lengths and number of hydraulic fractures created during the completion process. With knowledge of the reservoir and fracture properties in hand, the engineer can then determine the “optimum” completion design for future wells. This understanding can be achieved much quicker and for much less money than the cost to drill the number of wells necessary to make statistical analysis meaningful. The results of the case histories indicate that many completion designs are not in the “optimum” range. Too much capital is being spent increasing stage count when it should be going to increased effective length. The focus on early-time production has ignored the effect that more fractures has on ultimate recovery. The results and conclusions in this paper will run contrary to much of the direction most unconventional completion designs have been evolving over the past 5 to 10 years. A much greater emphasis on achieving increased effective lengths will be demonstrated and that increased stage count can prove detrimental to economic success over the well's life. Processes in the paper will also prove valuable for smaller operators that do not have a large well counts that are usually required to achieve a meaningful statistical evaluation.
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.
Abstract Unconventional completions in North America have seen a paradigm shift in volumes of proppant pumped since 2014. There is a clear noticeable trend in both oil prices and proppant volumes – thanks to low product and service costs that accompanied the oil price crash in early 2015. As the industry continues to recover, operators are reevaluating completion designs to understand if these proppant volumes are beyond what is optimal. This paper analyzes trends in completion sizes and types across all major unconventional oil and gas plays in the US since 2011 and tracks their impact on well productivity. Completion and production data since 2011 from more than 70,000 horizontal wells in seven major basins (Gulf Coast, Permian, Appalachian, Anadarko, Haynesville, Williston and Denver Julesburg basins) and 11 major oil/gas producing formations were analyzed to examine developments in proppant and fluid volumes. Average concentration of proppant per gallon of fluid pumped was used to understand transitional trends in fracturing fluid types with time. Production performance indicators such as First month, Best 3 or Best 12 months of oil and gas production were mapped against completion volumes to evaluate if there are added economic advantages to pumping larger designs. In general, all major basins have seen progressive improvements in average well performance since 2011, with the Permian Basin showing the highest improvement, increasing from an average first-six-months oil production of 25,000 bbl in 2011 to 75,000 bbl in 2017. The Gulf Coast basin, where the Eagle Ford formation is located, has seen a 6-fold increase in proppant volumes pumped per foot of lateral since 2011 while the Permian and Appalachian basins hit peak proppant volumes in 2015 and 2016 respectively. In Permian and Eagleford wells, higher proppant volumes in general have resulted in better production up to a certain concentration. In Williston and Denver basins, most operators are moving away from gelled fluids, and reduced average proppant concentration per fluid volume pumped shows inclination toward hybrid or slickwater designs. While some of these observations are tied to reservoir quality, proppant volumes have begun to peak as operators have either reached an optimal point or are in the process of reducing volumes. Demand for proppant is expected to nearly double by 2020. As oil prices continue to recover, well AFEs continue to increase, despite multiple efforts to improve capital efficiency. The need for enhanced fracture conductivity and extended half-lengths on EURs are been discussed by combining actual observed production data and sensitivities using calibrated production models. The industry is moving toward large-volume slickwater fracturing operations using smaller proppants, but he operating landscape is expected to see a correction when such designs become less economical.
Panja, Palash (Department of Chemical Engineering, and Energy & Geoscience Institute, University of Utah) | Velasco, Raul (Energy & Geoscience Institute, University of Utah) | Deo, Milind (Department of Chemical Engineering, University of Utah)
Abstract In this work, we estimate the Stimulated Original Oil In Place (SOOIP) of hydraulically fractured horizontal wells in prominent shale plays. This is done by compiling production data from hundreds of wells belonging to the Bakken, Niobrara, Wolfcamp, Eagle Ford, Bone Springs, and Woodford totaling over 2,500 wells. Additionally, we present probabilistic distributions of SOOIP with mean, standard deviation, P10, P50, and P90 estimates for each play. To circumvent the challenge of data availability for each well, we use the findings of a previous study where all reservoir unknowns are grouped into two major parameters. One of these parameters, alpha, is a function of the stimulated reservoir volume, compressibility, and pressure drawdown, where the last two are unknowns. While alpha is determined with high confidence for each well, we account for the uncertainty of compressibility and drawdown values across wells by assuming a normal distribution for these parameters. Lastly, by incorporating 1 million Monte Carlo samplings and a Mersenne Twister random number generator we estimate SOOIP distributions for each play with varying degrees of confidence. The final results show that the Niobrara and Bakken have the highest mean SOOIP values per well while the values for the Woodford and Bone Springs are the lowest among all six plays considered. Volumetric calculations using data from the literature qualitatively corroborate these findings. New insight on the stimulated volumes per well for prominent shale plays can be derived from these results as they correlate to horizontal well length, formation thickness, and hydraulic fracture half-lengths in each play.
Bhattacharya, Srimoyee (Shell International Exploration & Production Inc.) | Lake, Ed (Shell Exploration & Production Co) | Liu, Xin (Shell International Exploration & Production Inc.) | Dombrowski, Robert (Shell International Exploration & Production Inc.) | Cao, Richard (Shell Exploration & Production Co) | Girardi, Alejandro (Shell Exploration & Production Co)
Abstract Economic production from unconventional reservoirs depends upon efficiently designed horizontal drilling and hydraulic fracturing treatment. Implementation of fracture treatments requires consideration of various design parameters. These parameters include pumping rates, treating pressure, surface horse power, and volume and type of materials, such as fracture fluid and proppant. While the cost ramifications of a design can be easily calculated, revenue impact is harder to forecast. In this work, engineering optimization is performed using subsurface models and treatment costs. The discussed approach considers the uncertainty in perforation cluster efficiency from plug and perforation completions. This paper outlines an automated approach for engineering optimization. The approach integrates fracture and reservoir simulator models. A 3D fracture simulator generates spatially variable fracture properties with nonrectangular fracture geometry, which are subsequently imported into a dynamic reservoir model. Further, this model is linked to an optimizer for evaluating several well and completions parameters and determining the best design,. These optimal parameters may include well spacing, well orientation, landing depth, stage spacing, perforation cluster spacing, etc. The uncertainty in perforation cluster efficiency from plug and perforation completions is studied by considering three cluster efficiency cases:uniform fractures, non-uniform fractures, and c) dominant fractures. In case of uniform fractures, it is assumed that all clusters per stage contribute to production. In nonuniform fractures, around 50% of the clusters per stage contribute to production, whereas in dominant fractures, only one long fracture is producing per stage. We have generated 1000's of multi-well fracture cases corresponding to different completion design parameters, and identified optimal designs with improved NPV, and reduced cost. The results for optimal cases were demonstrated using pareto front plots of NPV and CAPEX corresponding to different cluster efficiency cases. A comparison of optimal cases suggests that the optimal design for uniform fractures is easier to achieve than that of non-uniform and dominant fractures. Further investigation shows that optimal cases for non-uniform and dominant fractures are cases with complementary placed long fractures from adjacent wells which cover maximum drainage area but can be difficult to execute in the field. Also, uniform fracture cases tend to provide significant value as compared to non-uniform and dominant cases, which conforms with the observed best practices from field applications. The data from Shell's Permian asset wells were used to calibrate the models.
The independent holds around 400,000 net acres in the DJ Basin and hopes to increase production to more than 400,000 BOE/D by 2021. But the existing out here is dedicated for midstream. Relatively few Everybody kind of knows who has what, Denver-Julesburg (DJ) companies have large positions in the and we do development around that." Basin and overlapping Niobrara Shale. Denver also serves surge, attention has been drawn to the nearby competitors. Operators have flocked to West of SRC Energy, previously known as Synergy like in the Bakken and Permian where Texas, southeastern New Mexico, and Resources and one of the region's labor costs and turnover can be high. We don't have a lot of disposal leaner era for the industry. The expansive good rate of return" due mainly to low issues," which are common in areas such Permian alone, which covers more than well and takeaway costs, which makes it as the Permian. "The key is the big players--Anadarko, bulk of US oil production increases and He previously served as completions Noble, and PDC--feel the economics mergers and acquisitions over the last manager for Anadarko Petroleum's DJ compete with the best shale economics couple of years.
Abstract To economically and efficiently develop unconventional resource plays, the industry has been spending tremendous resources to optimize completion and well spacing by piloting – a trial-and-error approach. However, the approach tends to take long time and cost significant amount of money. As the complex fracturing modeling technology advances, we question: "Can we use the latest complex fracturing modeling and reservoir simulation technologies to optimize completion and well spacing?", so that the industry can significantly save piloting time and money, and quickly find the optimal well spacing and corresponding optimal completion. A recent case study in Permian Basin has answered the question well. For a Wolfcamp well completed with crosslinked gel and wide cluster spacing in 2012, we first built a 3-D geological and geomechanical model, and a full wellbore fracturing propagation model, and then calibrated it with multi-stage fracturing pumping history; the resulting complicated fracture network model was then converted into an unstructured grid-based reservoir simulation model, which was then calibrated with the well production history. During the process, discrete natural fracture network (DFN) and stress anisotropy were systematically evaluated to study their impact on fracture growth. Microseismic and tracer log data were used to validate the hydraulic fracturing modeling results. To test if the calibrated geomechanical and reservoir models can be used to optimize well completion design, we then ran the fracturing model with the latest completion design (tighter cluster spacing, slick-water, and more fluid and proppant) and forecasted the well performance. We found out that the resulting well performance is very similar to the performance of those wells with similar completion designs in the same area. After establishing the confidence on the capacity of those models, we then further studied the impact of different completion designs on fracture dimensions and well performance. We examined the distributions of fracture length along the wellbore resulted from different cluster spacings, fracturing fluid types and volume, and proppant amount. We found out (1) the hydraulic fracture length and network complexity mainly depend on DFN and stress anisotropy, and fracturing fluid viscosity; and (2) the fracture length of those fractures initiated from different perforation clusters along wellbore is in a log-normal distribution depending on completion designs, which provides crucial insights to well interference and furthermore on well spacing. Therefore, we can reasonably model complicated fracture propagation and corresponding well performance with the latest modeling technologies, and then optimize well spacing, which should help operators save significant time and money on well completion and spacing piloting projects, and thus speed up field development decision. The paper demonstrates our novel workflow as an effective way to optimize completion design and well spacing by integrating advanced multi-stage fracture modeling with reservoir simulation in unconventional resource plays.