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Oil and gas executives across the North American shale sector are continuing to come to the table and negotiate a steady stream of deals to consolidate portfolios. During the second quarter, the deal making amounted to more than $33 billion in mergers and acquisitions, according to data from Enverus. The energy-focused analytics firm said last month in its quarterly review the combined figure represents more than 40 deals, with seven of them topping $1 billion each. The third quarter has so far not seen any announced transactions surpass the $1-billion mark. Instead, most deals struck in July were between mid-sized and small US-based operators.
Colorado oil production is surging to record levels, outpacing the other major producing US states in year-over-year gains on the backs of the steady-and-predictable Denver-Julesburg (DJ) Basin and overlapping Niobrara Shale. As overall US oil output continues to surge, attention has been drawn to the Permian Basin and SCOOP and STACK plays. Operators have flocked to West Texas, southeastern New Mexico, and central Oklahoma to stake claims to land they believe will usher them into a new, leaner era for the industry. The expansive Permian alone, which covers more than 75,000 sq miles, has accounted for the bulk of US oil production increases and mergers and acquisitions over the last couple of years. Although they are intertwined and together encompass parts of Colorado border states Wyoming, Nebraska, and Kansas, the DJ and Niobrara offer a fraction of the acreage and prospective resources of the Permian.
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.
Abstract Improvements in drilling and completion technology have resulted in significant increases in production rates from new horizontal wells in the United States. Observations over many years show that a well’s initial rate often has a predictable relationship to decline trends indicating a rate related bias in decline trends. This paper studies the relationship between initial flow rates and related decline trends and reserves forecasts for many of the major horizontal development plays in the United States and confirms that there is a rate related bias. Early decline trend forecast methods considering rate bias lead to improved reserve estimates and fewer revisions to estimates as wells mature. The study does not provide a methodology for determining peak rates but focuses on bias in decline trends related to known peak rates. Introduction For years, reviews of oil and gas reserves estimates have shown that downward revisions on high rate wells (Lee 2017, Lee 2019) have been more common than upward revisions indicating a rate related bias. Various authors have discussed methods to correct various biases (SPEE 2010, 2016) (Freeborn 2012, 2013) which tend to result in overestimating production forecasts. Our experience is that forecast bias to the high side is more significant for high rate wells than for low rate wells. This rate Figure 1. Twelve areas for which peak month rate to decline trends relationships are presented. dependency raises the question of whether a rate dependent bias can be documented and corrected. This paper focuses on one factor: the relationship between peak month rates and decline trends or rate dependent decline trend bias. Results are presented for twelve areas noted in Figure 1 with an attempt to minimize rate dependent estimation bias. Theory/Methods High rate bias was documented with production data from a group of similar wells which was sorted from high peak rate to low peak rate and binned for analysis. This ranking minimizes time sequence bias which results when the best wells are drilled first with poorer wells later or if the better wells are drilled toward the end of a study period. The peak rate ranked wells are divided into approximately equal bins with each bin analyzed to determine the expected decline trends for the bin. The decline trends of the bins are then compared to the bin’s peak month rate to document the relationship between decline trends and peak rates.
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 (ICS) in both laboratory and field case studies. Specifically, decreased communication between stages and improved production compared to offsets. At the 2018 SPE Annual Technical Conference, Kolchanov et al. described the ICS improving zonal isolation in wells that would otherwise contain mud channels symptomatic of the cleaning methods used in unconventional developments (SPE-191561-MS). The scaled performance tests disclosed in that publication are further evaluated to build on the relationship between the laboratory test and realistic downhole scenarios. Literature data indicate that >30% of stages have communications with previously treated zones. The ICS was shown to eliminate interstage communication during stimulation operations when compared to conventional cement systems. To investigate the effect of the ICS on completion quality, five wells cemented with the ICS and stimulated by multistage hydraulic fracturing were compared with numerous offset wells drilled, cemented, and stimulated during the last 2 years in the same producing zone within a 10-mile radius. The early normalized production data have been analyzed, and they indicate a statistically significant increase of production for the ICS-treated wells. This shows the importance of an integrated approach in well construction process, especially for challenging horizontal wells.
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 The successful development of unconventional resources requires an integrated approach using multiple data sets to characterize and optimize recoveries. This study evaluates geological and completion drivers impacting well productivity within the Denver-Julesburg (DJ) Basin of eastern Colorado and southeastern Wyoming, focusing on the Core Wattenberg and Peripheral regions. Understanding these complex relationships is required to explain well performance variability across the play and optimize economics. Over 4,000 producing horizontal wells were analyzed across the study area. Completion data including lateral length, fluid intensity, proppant intensity, stage spacing and vertical well density were put though a comprehensive scrubbing process to identify and remove outliers. Oil and gas type curves were built for individual wells using RS Energy Group's proprietary software. Geological parameters for individual wells were derived from maps generated from over 2,000 digital wells logs, including TVD, hydrocarbon pore volume, isopach, geothermal gradient, clay volume and mud weight-derived pressure gradient, using bottomhole locations. Bayesian, boosted decision tree, linear and decision forest multivariable regression models were tested, and the model with the highest coefficient of determination was used. Permutation feature importance (PFI) method was used to rank variables by impact on recovery. The decision forest regression model was selected for the Core Wattenberg Niobrara and Core Wattenberg Codell sub-regions, whereas the boosted decision tree was chosen for the Peripheral DJ Niobrara and the linear regression model was selected for the Peripheral DJ Codell sub-region. Based on the selected models, fluid intensity and formation TVD were the highest-ranked variables across the entire basin. Introduction DJ Basin breakevens are competitive among North American plays, averaging $35/bbl WTI in 2017, behind the Midland and Delaware basin averages of $32/bbl and $33/bbl. Data analytics using a multidisciplinary approach offers both qualitative and quantitative techniques to characterize variables that influence well productivity. By integrating geological and completion data sets, regional trends are observed along with the key drivers that yield better recoveries. This analysis highlights optimal geological and completion parameters within the Niobrara and Codell formations that drive recoveries in both the Core Wattenberg and Peripheral DJ regions.
Abstract Most of the shale reservoirs in US land are naturally fractured. The fracture intensity and types vary from one shale to another. Even within the same shale in the same field, the heterogeneity of fracture intensity can be often expected to be high in a horizontal well. The current popular geometrical completion design can potentially ignore the existence of natural fractures. Hence, maximizing stimulation efficiency without understanding existing natural fractures can be a challenge. In this paper, study was made of the majority of the published case studies related to natural fractures in the US shales in the last 20 years. The evidence of natural fractures from either outcrops or subsurface data, i.e. core, borehole images, or other data is summarized for each studied shale. The latest studies show that the hydraulic fracture propagation can be strongly influenced by existing natural fractures regardless of whether they are open or closed. The roles of existing fractures in the shales include: 1) providing enhanced reservoir permeability for improved productivity if they are open and effectively connected by hydraulic fractures; 2) promoting much better fracturing network complexity regardless of whether they are open or closed prior to the stimulation; 3) giving possible negative impact sometimes, i.e. high water cut, if they are connected with wet zones below or above the reservoirs. It can be concluded that engineered completion designs that employ accurate knowledge of natural fracture data, in-situ stresses, and other reservoir and completion quality indicators as inputs can provide opportunities for enhancing stimulation efficiency and fracturing network complexity. This in turn can lead to better connectivity to a larger reservoir volume and access to more drainage area in the shales. Introduction The US shale gas story actually featured natural fractures. William Hart, a local gunsmith, drilled the first commercial natural shale gas well in US in Fredonia, Chautauqua County, NY in 1821, in shallow, low-pressure rock with fractures. The well was first dug to a depth of 27ft in a shale which outcropped in the area, then later drilled to a depth of 70ft using 1.5 inch diameter borehole. The produced gas was piped to an innkeeper on a stagecoach route. Then the well was produced without any stimulation for 37 years until 1858 when it supplied enough natural gas for a grist mill and for lighting in four shops. It was a combination of the idea from Mr. Hart to drill the well and the presence of the natural fractures in the gas shale that made the 1 commercial shale gas discovery possible in shale gas history.
Abstract Low permeability reservoirs contain a significant and growing portion of the world oil reserves, but their exploitation is often associated with poor recovery even after waterflood. Miscible or immiscible gas injection is usually the first choice in terms of EOR methods but it is not always feasible for instance due to lack of adequate supply. In such cases chemical EOR is often considered. In this paper we propose to examine the specific challenges of chemical EOR in low permeability reservoirs by reviewing the well documented chemical EOR field operations that were implemented in reservoirs ranging from conventional low permeability (around 100 mD) to so-called tight reservoirs (few mD). Shale plays where permeability is in the µD range and which only produce when simulated by hydraulic fractures are not considered in our investigation. We show that what works at the lab scale in low permeability plugs cannot be automatically transposed to the field scale. In particular low permeability can lead to injectivity issues and uncontrolled fracturing due to near wellbore plugging or simply to the high pressures required to propagate the injected chemical over large distances. Another challenging aspect of chemical EOR in low permeability reservoirs is the high chemical adsorption due to important surface to volume ratio and specific mineralogy, as in the case of carbonates (fractured or not). Success and failures of chemical EOR pilots in such challenging reservoirs, including innovative approaches such as wettability alteration, are reviewed. Overall, this review will provide the reader with an updated view of past and on-going developments in chemical EOR applied to low permeability reservoirs. It should help operators determine whether a given low permeability reservoir is eligible to such processes or not.