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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.
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.
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.
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.
SPE's recent Liquids-Rich Basins Conference rewarded attendees with far-reaching insight into how to economically exploit liquids-rich plays. Based on the theme "New Technology for Old Plays," SPE held the conference in Midland, Texas, from 11 to 12 September. The 29 speakers explored a wide range of topics and points of view from macro to detailed perspectives, centered on strategic thinking; current understanding of reservoir characteristics; proper application of completion, stimulation, and production techniques and tactics; and case histories. This is the third year the conference has been presented. Almost 300 attendees gathered at the Midland Convention Center to listen to four technical sessions--each with three speakers--each day; interact with four Knowledge-Sharing Poster speakers who presented during four half-hour breaks; hear a keynote speaker at Thursday's luncheon; and investigate the offerings of more than 20 exhibitors. Two training courses were also given--a 2-day course Monday and Tuesday, 9 and 10 September, titled "Modern Production Data Analysis for Unconventional Reservoirs"; and a 1-day course Friday, 13 September, titled "An Overview of Microseismic Imaging of Hydraulic Fracturing." The first session highlighted commercial and financial interests in oil resource plays and price pressures imposed by limited transportation in the areas of rapid development. Dave Pursell, managing director of Tudor Pickering Holt, kicked off the conference with his presentation, "US Crude Oil Production Growth and the Impact on Price Differentials… or Get Me off This Rock!" "'Liquids-rich' is my least favorite term," he said. Basically, he said further, what people are talking about is natural-gas liquids (NGLs): "If it's crude, they're going to say it." When considering the question of why Brent crude is at USD 110/bbl, he said, "Risk premium is the last possible answer before the shoulder shrug." He assured the audience that global crude fundamentals are fine, with crude inventories pointing to a balanced global market and global refined inventories below 10-year norms. The big story is taking place in the US. While US crude production has grown from around 7 million B/D in 2005 to around 9 million B/D in 2012, non-US, non-Organization of Petroleum Exporting Countries' (OPEC) crude production during the same period has remained fairly stagnant at around 44 million B/D. Organisation for Economic Cooperation and Development (OECD) countries' demand, which hovered at around 50 million B/D from 2000 to 2007, has tapered down to around 46 million B/D in 2012 and non-OECD demand has grown precipitously from less than 30 million B/D in 2000 to close to 45 million B/D in 2012. "When considering global growth," said Pursell, "it is really important to note that the only real growth in crude production is happening in the US."
SPE’s recent Liquids-Rich Basins Conference rewarded attendees with far-reaching insight into how to economically exploit liquids-rich plays. Based on the theme “New Technology for Old Plays,” SPE held the conference in Midland, Texas, from 11 to 12 September. The 29 speakers explored a wide range of topics and points of view from macro to detailed perspectives, centered on strategic thinking; current understanding of reservoir characteristics; proper application of completion, stimulation, and production techniques and tactics; and case histories.
This is the third year the conference has been presented. Almost 300 attendees gathered at the Midland Convention Center to listen to four technical sessions—each with three speakers—each day; interact with four Knowledge-Sharing Poster speakers who presented during four half-hour breaks; hear a keynote speaker at Thursday’s luncheon; and investigate the offerings of more than 20 exhibitors.
Two training courses were also given—a 2-day course Monday and Tuesday, 9 and 10 September, titled “Modern Production Data Analysis for Unconventional Reservoirs”; and a 1-day course Friday, 13 September, titled “An Overview of Microseismic Imaging of Hydraulic Fracturing.”
The first session highlighted commercial and financial interests in oil resource plays and price pressures imposed by limited transportation in the areas of rapid development.
Crude and Liquids Growth in the US. Dave Pursell, managing director of Tudor Pickering Holt, kicked off the conference with his presentation, “US Crude Oil Production Growth and the Impact on Price Differentials… or Get Me off This Rock!” “‘Liquids-rich’ is my least favorite term,” he said. “It’s as accurate as calling a dog a non-cat.”
Basically, he said further, what people are talking about is natural-gas liquids (NGLs): “If it’s crude, they’re going to say it.”
When considering the question of why Brent crude is at USD 110/bbl, he said, “Risk premium is the last possible answer before the shoulder shrug.” He assured the audience that global crude fundamentals are fine, with crude inventories pointing to a balanced global market and global refined inventories below 10-year norms.
The big story is taking place in the US. While US crude production has grown from around 7 million B/D in 2005 to around 9 million B/D in 2012, non-US, non-Organization of Petroleum Exporting Countries’ (OPEC) crude production during the same period has remained fairly stagnant at around 44 million B/D. Organisation for Economic Cooperation and Development (OECD) countries’ demand, which hovered at around 50 million B/D from 2000 to 2007, has tapered down to around 46 million B/D in 2012 and non-OECD demand has grown precipitously from less than 30 million B/D in 2000 to close to 45 million B/D in 2012.