|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Melcher, Howard (Liberty Oilfield Services) | Mayerhofer, Michael (Liberty Oilfield Services) | Agarwal, Karn (Liberty Oilfield Services) | Lolon, Ely (Liberty Oilfield Services) | Oduba, Oladapo (Liberty Oilfield Services) | Murphy, Jessica (Liberty Oilfield Services) | Ellis, Ray (Liberty Oilfield Services) | Fiscus, Kirk (Liberty Oilfield Services) | Shelley, Robert (RF Shelley LLC) | Weijers, Leen (Liberty Oilfield Services)
Summary Selecting appropriate proppants is an important part of hydraulic‐fracture completion design. Proppant selection choices have increased in recent years as regional sands have become the proppant of choice in many liquid‐rich shale plays. But are these new proppants the best long‐term choices to maximize production? Do they provide the best well economics? The paper presents a brief historical perspective on proppant selection followed by various detailed studies of how different proppant types have performed in various unconventional onshore US basins (Williston, Permian, Eagle Ford, and Powder River), along with economic analyses. As the shale revolution pushed into lower‐quality reservoirs, the concept of dimensionless conductivity has pushed our industry to use ever lower‐quality materials—away from ceramics and resin‐coated proppant to white sand in some Rocky Mountain plays, and more recently from white sand to regional sand in the Permian and Eagle Ford plays. Further, we compare early‐to‐late‐time production response and economics in liquid‐rich wells where proppant type changed. The performance of various proppant types and mesh sizes is evaluated using a combination of different techniques, including big‐data multivariate statistics, laboratory‐conductivity testing, detailed fracture and reservoir modeling, as well as direct well‐group comparisons. The results of these techniques are then combined with economic analyses to provide a perspective on proppant‐selection criteria. The comparisons are anchored to permeability estimates from production history matching and diagnostic fracture injection tests (DFITs) and thousands of wellsite‐proppant‐conductivity tests to determine dimensionless conductivity estimates that best approach what is obtained in the field. Dimensionless fracture conductivity is the main driver of well performance because it relates to proppant selection thanks to the inclusion of the relationship of fracture conductivity provided by the proppant relative to the actual flow capacity of the rock (the product of permeability and effective fracture length), which is supported by the production analyses in the paper. The paper shows how much fracture conductivity is adequate for a given effective fracture length and reservoir permeability and then looks at the economics of achieving this “just‐good‐enough” target conductivity, either through less proppant mass with higher‐cost proppants or more proppant mass with lower‐cost proppants, as well as mesh‐size considerations. This paper does not rely on a single technique for proppant selection but uses a combination of various data sources, analysis techniques, and economic criteria to provide a more holistic approach to proppant selection.
Successful cement placement in horizontal wellbores requires solutions for several technical challenges. Zonal isolation provided by cement is considered an important factor for efficient stimulation. A cement system was designed and recently introduced in unconventional developments to mitigate hydraulic isolation challenges encountered when cementing horizontal wellbores. Herein, we disclose recent results that show the efficiency of the interactive cementing system (
At the 2018 SPE Annual Technical Conference, Kolchanov et al. described the
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.
Abstract A database has been compiled and analyzed, summarizing more than 100 field studies in which restimulation treatments (hydraulic refracs) have been performed, along with the production results. Field results demonstrate that refrac success can be attributed to many mechanisms, including: –Enlarged fracture geometry, enhancing reservoir contact –Improved pay coverage through increased fracture height in vertical wells –More thorough lateral coverage in horizontal wells or initiation of more transverse fractures –Increased fracture conductivity compared to initial frac –Restoration of fracture conductivity lost due to embedment, cyclic stress, proppant degradation, gel damage, scale, asphaltene precipitation, fines plugging, etc. –Increased conductivity in previously unpropped or inadequately propped portions of fracture –Improved production profile in well; preferentially stimulating lower permeability intervals [reservoir management] –Use of more suitable fracturing fluids –Re-energizing or re-inflating natural fissures –Reorientation due to stress field alterations, leading to contact of "new" rock Although less frequently published, unsuccessful restimulation treatments are also common. Documented concerns illustrated in this paper include: –Low pressured, depleted wells (especially gas wells) posing challenges with recovery of fracturing fluids –Low pressured or fault-isolated wells with limited reserves –Wells in which diagnostics indicate effective initial fractures and drainage to reservoir boundaries –Wells with undesirable existing perforations, or uncertain mechanical integrity of tubing, casing, or cement This paper will explore the common problems that lead to unsatisfactory stimulation, or initial treatments that fail over time. Guidelines for evaluating refrac candidates and improving initial treatments will be reviewed. The paper summarizes restimulation attempts in oil and gas wells in sandstone, carbonate, shale and coal formations. This organized summary of field results and references will provide significant value to readers evaluating or designing restimulation treatments.