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ABSTRACT: We carried out a geomechanical study of three, co-located wells in the DJ Basin of Colorado, one each in the Niobrara A, Niobrara C and Codell sandstone, to investigate how stress variations of the least principal stress with depth affect vertical hydraulic fracture growth and shear stimulation of pre-existing fractures. We demonstrate that the change in stratigraphic depth along the lateral portion of the Niobrara A well causes it to traverse regions of both high and low values of the least principal stress. As a result of this, the implications of microseismic data for hydraulic fracture growth near the heel and toe of the well are noticeably different. Specifically, upward hydraulic fracture growth from stages near the heel of the well (where the least principal stress is higher) is more pronounced than those near the toe. In addition, in the Codell sandstone, which is in a state for normal faulting frictional equilibrium, injection-related shear events start sooner than in the Niobrara A and C, which require higher pore pressure to stimulate shear slip. 1. Introduction In this paper we report a geomechanical study principally related to understanding hydraulic fracture containment and vertical growth in the Niobrara A, Niobrara C and Codell sandstone formations in the Denver-Julesburg (DJ) Basin. There were two principal components of the study. First, we utilized microseismic data to examine hydraulic fracture containment and vertical containment growth in terms of five DFIT stress measurements made at the toe of horizontal wells in each of the three formations of interest. Second, we analyzed the horizontal variations in the stresses due to the lateral well traversing lithostratigraphic facies. We have successfully shown that the hydraulic fractures in the heel of the well were initiated in a region of high least principal stress while in the toe of the well, the least principal stress was as much as 6 MPa lower. The evidence for this assertion is the timing of the events and the distance of the events from the centers of the stages. This study illustrates how important knowledge of the stress state is for understanding the characteristics of hydraulic fractures.
Sochovka, Jon (Liberty Oilfield Services) | George, Kyle (Liberty Oilfield Services) | Melcher, Howard (Liberty Oilfield Services) | Mayerhofer, Mike (Liberty Oilfield Services) | Weijers, Leen (Liberty Oilfield Services) | Poppel, Ben (Liberty Oilfield Services) | Siegel, Joel (Liberty Oilfield Services)
Abstract The shale industry has changed beyond recognition over the last decade and is once again in rapid transition. While we are unsure about the nature of innovations to make US shale ever more competitive, we are certain that the current downturn will drive a further reduction in $/BO – the total cost to lift a barrel of US shale oil to the surface. As a result of an increase in scale and industry efficiency gains, the all-in price charged by service companies to place a pound of proppant downhole has come down from more than $0.50/lb in 2012 to about $0.10/lb today. In this paper, we discuss what components have contributed to this reduction to date and use several case studies to illustrate the potential for further cost reductions. The authors used FracFocus data to study a variety of placement and production chemicals for about 100,000 horizontal wells in US liquid rich basins, including the Williston, Powder River, DJ, Permian basins, as well as SCOOP/STACK and Eagle Ford. All chemicals used were averaged on a per-well basis into a gallon-per-thousand gallons (gpt) metric. In the paper, we first provide an overview of trends by basin since 2010 for these chemical additives. Then, we perform Multi-Variate Analysis (MVA) to determine if groups of these chemicals show an impact on production performance in specific basins or formations. Finally, through integration of lab testing (on fluid systems and proppants), a liquid-rich shale production database and FracFocus tracking of industry trends, the authors developed a list of case histories that show modest to significant reductions in $/BO. In this paper we focus on proppant delivery cost – the cost to place a pound of proppant in a fracture downhole, where it can contribute to a well's production for years to come. The last decade saw a 10-fold increase in horsepower, a 20-fold increase in yearly stages pumped and a 40-fold yearly proppant mass increase. One result of this increase in scale, was a gain in efficiencies, which led to an average 3-fold fracturing cost decrease to place a pound of proppant downhole. We will document this trend in detail in the paper. A significant industry trend over the last decade has been a "viscosity for velocity" trade. The change to smaller mesh regional proppants, in combination with an increase in pump rates on frac jobs in the US, has allowed fluid systems to become more "watery". At the same time, the industry is moving from guar systems to polyacrylamide-based systems that exhibit higher apparent viscosities at low to ultra-low shear rates. These newer High Viscosity Friction Reducer (HVFR) systems show superior proppant carrying capacity over traditional slickwater fluid systems. Regained conductivity testing has shown that these HVFR systems are generally cleaner for fracture conductivity than guar systems. Along with changes to base chemistry, a 2- to 5-fold increase in disposal costs and an overall "green initiative" over the last decade have resulted in a push to maximize recycled water usage on these HVFR jobs. These waters can be in excess of 150,000 TDS (Total Dissolved Solids) which present challenges across the board when designing a compatible fluid system that fits the needs in terms of viscosity yield, scale inhibition and microbial mitigation etc. – all while keeping costs low. Specialty chemicals, such as Hydrochloric Acid (HCl) substitutes that have similar efficacy as HCl but significantly lower reactivity with human skin, have helped significantly to improve operational safety around previously-categorized hazardous chemicals, and have helped reduce cost and improve pump time efficiency. Measurement of bacterial activity during and after fracture treatments can help with the best economic selection of the appropriate biocide. These simple measurements can help further reduce what is spent on the necessary chemical package to effectively treat a well. This paper provides a holistic view of fluid selection issues and shows a real-data focused methodology to further support a leaner approach to hydraulic fracturing.
Chen, Ming (China University of Petroleum, China) | Zhang, Shicheng (China University of Petroleum, China) | Zhou, Tong (Research Institute of Petroleum Exploration and Development, Sinopec) | Ma, Xinfang (China University of Petroleum, China) | Zou, Yushi (China University of Petroleum, China)
Summary Creating uniform multiple fractures is a challenging task due to reservoir heterogeneity and stress shadow. Limited‐entry perforation and in‐stage diversion are commonly used to improve multifracture treatments. Many studies have investigated the mechanism of limited‐entry perforation for multifracture treatments, but relatively few have focused on the in‐stage diversion process. The design of in‐stage diversion is usually through trial and error because of the lack of a simulator. In this study, we present a fully coupled planar 2D multifracture model for simulating the in‐stage diversion process. The objective is to evaluate flux redistribution after diversion and optimize the dosage of diverters and diversion timing under different in‐stage in‐situ stress difference. Our model considers ball sealer allocation and solves flux redistribution after diversion through a fully coupled multifracture model. A supertimestepping explicit algorithm is adopted to solve the solid/fluid coupling equations efficiently. Multifracture fronts are captured by using tip asymptotes and an adaptive time‐marching approach. The modeling results are validated against analytical solutions for a plane-strain Khristianovic-Geertsma de Klerk (KGD) model. A series of numerical simulations are conducted to investigate the multifracture growth under different in‐stage diversion operations. Parametric studies reveal that the in‐stage in‐situ stress difference is a critical parameter for diversion designs. When the in‐situ stress difference is larger than 2 MPa, the fracture in the high‐stress zone can hardly be initiated before diversion for a general fracturing design. More ball sealers are required for the formations with higher in‐stage in‐situ stress difference. The diverting time should be earlier for formations with high in‐stage stress differences as well. Adding more perforation holes in the zone with higher in‐situ stress is recommended to achieve even flux distribution. The results of this study can help understand the multifracture growth mechanism during in‐stage diversion and optimize the diversion design timely.
Abstract Distributed acoustic sensing (DAS) inter-stage vertical seismic profiling (VSP) data were acquired during the stimulation of two horizontal shale wells in the Denver-Julesburg (DJ) Basin’s Hereford field. These data were analyzed to obtain induced fracture heights and fracture densities for use in fracture modeling and Stimulated Rock Volume (SRV) calculations. Inverted inter-stage VSP (also referred to as rapid time-lapse DAS VSP) data, transformed to an anisotropic seismic velocity model via rock physics relationships, were used to estimate stage-by-stage fracture height and density. Comparison of fracture height from multiple sources confirm the validity of fracture height calculations for the Niobrara fiber well, and the deeper Codell fiber well. When combined with other independent diagnostics such as microseismic, tilt (microdeformation), seismic rock properties, pressure, and distributed acoustic/temperature sensing (DAS/DTS) data, these estimates are validated for use in developing an optimized completion plan, as well as for use in calculating stage-by-stage stimulated rock volumes. Introduction The Hereford field is located in the northern DJ Basin, Colorado, just south of the Wyoming state line. Similar to the giant Wattenburg field to the south, Hereford produces from the unconventional reservoirs of the Upper Cretaceous Niobrara Formation and the Codell Member of the Carlile Shale (Figure 1). Early in the life of the Hereford field, it was understood that the "complexity of the fracture system" would require significant analysis in order to understand and realize the reserve potential of the field (Anderson et. al., 2015). Early wells in the field, drilled between 2010 and 2012, were completed with relatively small completions and primarily accessed oil in the natural fracture systems. The very tight 0.5 to 3.0 mD permeability in the Niobrara B Chalk requires larger completion rates and volumes to access the matrix oil. The Hereford Field contains pervasively naturally fractured zones as well as more matrix dominated areas. A production optimization project was initiated by HighPoint Resources in 2019 to understand the best practices for maximizing production from both the pervasively natural fractured parts of the field, as well as the more matrix dominated portions of the field, while performing completions in 23 wells on four pads within the field. This project was designed to shorten the cycle-time needed to optimize completions. Rather than execute well-by-well parameter variations that can take years to evaluate, this project was designed to test numerous completion scenarios with a variety of diagnostic tools in a short period of time. Evaluation of these completion parameter changes give the best chance of success. In addition to distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) on fiber optic cables cemented behind casing, numerous other techniques were utilized to evaluate these wells including surface microseismic, tilt (microdeformation), pressure gauges, micro-imaging, and a pilot well with a quad combo and dipole sonic. Additionally, the 2009-vintage seismic data were reprocessed and merged with adjacent surveys in 2019 including a new pre-stack inversion. (Raw data courtesy of Seitel).
Abstract The objective of this paper is to highlight the preconceived notions that both ultra-low polymer cross-linked gels and high viscosity polyacrylamide fluid systems are difficult to work with or damaging to formations. The paper discusses when such systems are beneficial as well as define some design restrictions. Historically these types of fluid systems have fallen into a gray area of technology that have now become accepted by some operators in the current low-cost market. The fluids technology discussed in this paper have blossomed not solely because of their technological advancement, but also due to the market. Industry downturns have forced operators and service companies to find more cost-effective means to stimulate the reservoirs in question. This paper examines the use of these new systems in two regions (Williston and DJ Basins), where hundreds of wells have been pumped with these new systems as well as regained conductivity tests performed in 3 party labs. We also compare production results of thousands of stages pumped with these new systems versus a more traditional approach. Over the past decade the DJ Basin has be primarily been stimulated with high-priced low pH zirconate CMHPG fluid systems, as a result of the notion that they leave less residue in the fractures. However, with the very cost sensitive market and the new ultra-low polymer systems testing with higher regained conductivity than the incumbent system, change was inevitable. In the Williston Basin high rate slickwater jobs have become more commonplace. Hybrid designs have been used to increase proppant loadings. However, a new trend to use significantly higher FR concentrations to achieve a system capable of placing higher proppant concentrations is gaining market share. This leads to the current obstacles for both systems’ further use in the field. These obstacles are threefold: The notion that the system is contaminating the proppant pack with residue. Lab testing shows this not to be the case. Reconditioning field personnel to run the new systems as designed. Ensure that these systems are not used in designs that do not fit the operational criteria without understanding the limitations. The success of all of these items remain attached to the final product, a well producing as much as, or more, for a lower total cost than the more traditional method. This paper uses data from the lab and field to challenge many of the preconceived notions about what it takes to successfully place a solid stimulation package. Also, it will address how some of the largest barriers to new technology are predominantly mental, while the new products are technically sound and economically superior.
Kosters, Bryan (APEX Petroleum Engineering LLC) | Shaw, Kevin (APEX Petroleum Engineering LLC) | D'Souza, Shodan (APEX Petroleum Engineering LLC) | Clark, Justin (APEX Petroleum Engineering LLC) | Besler, Monte (FRACN8R Consulting, LLC) | Barham, Michael (Helis Oil & Gas Company, LLC)
Abstract In the era of unconventional oil and gas drilling, time constraints often fast-track projects that lack sound completion practices. A multi-year production study of the Codell Sandstone in Laramie County, Wyoming has developed better completion practices that improved production and Estimated Ultimate Recovery (EUR). Helis Oil and Gas Co., LLC formed a team of experts to identify and execute best completion engineering practices for their horizontal Codell wells. Utilizing data from the production study and leaning on experience, the team identified seven core areas for improving Codell completions. The team (1) recommended performing fracture diagnostics, (2) investigated methods to increase Stimulated Reservoir Volume (SRV), (3) optimized the job size, (4) reviewed proper chemical additive selection, (5) included on-site real-time micromanagement of treating pressure, (6) reviewed wireline procedures, and (7) performed post-fracture treatment analysis. The Laramie County comparative study included 247 wells completed during the 4-year time period of 2014 to 2018. Helis Oil and Gas Co., LLC completed a total of 13 wells with the enhanced workflow. Considering normalized average cumulative production per well metric, Helis wells outperformed offset wells by 58% in the first 6 months of production. Extending the time frame to the first 12 months of production, on average, the Helis wells produced 75% more oil. A total of 5 Helis wells outpaced the P10 normalized production curve within the first year of production. Examining normalized decline curves, Helis wells continued to outperform. Furthermore, 10 of the 13 Helis wells outperformed the P10 normalized decline curve after 12 months of production. These techniques help get out of the mindset of the cookie cutter approach with assembly line frac designs. Focusing on these core principles and systematically applying engineered completion techniques to the Codell workflow has helped Helis Oil and Gas Co., LLC achieve superior production and outperform all other operators in the area.
Abstract Multi-stage hydraulic fracturing has gained popularity all over the world as more tight geologic formations are developed economically for hydrocarbon resources. However, due to the stages' operating complexity, different kinds of disruptions in fracturing operations may occur and even result in great economic loss. Screenout is one of the issues caused by the blockage of proppant inside the fractures. This paper presents a screenout classification system based on Gaussian Hidden Markov Models (GHMMs), trained on simulated data, that predicts screenouts and provides early warning by learning pre-screenout patterns in the simulated surface pressure signals. The simulated data are generated in a hydraulic fracturing software using a horizontal well with three fracturing stages landing in the Niobrara B shale, Denver-Julesburg (DJ) Basin. During the 270 simulations, various synthetic fracturing treatment data are forward modeled for both screenout and non-screenout scenarios. The classification system consists of two Gaussian Hidden Markov Models (screenout and non-screenout), each of which is fitted and optimized by its respective training set. Both Hidden Markov Models are assigned with two 1D Gaussian probability density functions to represent the distribution of their associated simulated surface pressure signals. During the classification process, once a new surface pressure sequence is observed, the maximum log likelihood is calculated under both fitted models and the model with a greater likelihood will be predicted as the class of this new observation. The classification system is validated with a hold-out testing data set from the simulations and the statistics of the performance is visualized in a confusion matrix. The results indicate the classification system achieves an overall classification accuracy of 81% and an accuracy of 86% for successfully predicting screenout events around 8.5 minutes prior to screenout occurring in the simulation. The described methodology is demonstrated to be a useful tool for early screenout detection and shows its promising feasibility of other fracturing time-series data analysis.
Abstract The objective of this research was to identify hydraulic fracturing regulations from a range of jurisdictions, verify the grounds for regulatory intervention within the scientific literature and categorize the statements according to the geospatial application. Specific regulations constraining aspects of hydraulic fracturing activities from jurisdictions across the world were collated to identify common features relating to environmental protection, administrative requirements and grammatical structure. Regulations from 55 jurisdictions including states in the US, provinces in Canada, Australian states, European countries, Africa and South America were assessed and common focus areas identified, allowing for the development of a regulatory suite of universal application. Regulations could be ascribed to partitions of the environment including the lithosphere, the atmosphere, the hydrosphere, biosphere and the social framework. Some 32 distinct elements were identified as frequent constraints to hydraulic fracturing located in three geospatial zones: off-site; wellsite; and, wellhead. The scientific literature for each of these areas was critically assessed and summary reviews developed as a comprehensive and wide ranging review of environmental impacts. The specific use of open ended risk regulation as part of control documents (a permit or regulatory framework) appears to have been promoted as a catch-all in the absence of knowledge within the regulatory agency as if there is a lack of evidence supporting directed regulation. As an output of this research a Driver-Pressure-State-Impact-Response model was developed reflecting the substantial literature base that extends well back into the 1970s, with the initial development of coalbed methane in the Rockies and the Southern States and since the 1990s with shale. The paper calls into question claims of "We don't know enough".
Abstract Well-to-well interference is an increasingly discussed issue. Previously drilled and producing “parent” wells and recently drilled “child” wells are yielding a reduction in recovery rates in both short and long-term cases due to interference. A primary contributor to the variability in production is the presence of pressure sinks as the result of production depletion in the parent wells. Infill drilling will continue to occur in the development of unconventional plays, and it is crucial to gain an understanding of the impacts of well-to-well interference on hydraulic fracture generation. This paper discusses a detailed approach to investigating well-to-well interference based on integrating hydraulic fracture modeling and reservoir simulation in two different formations, the Niobrara and Codell, in the Denver-Julesburg Basin. The geomechanical properties were calibrated by DFIT data and pressure matching of the parent well treatments. The resulting parent well fracture geometries were incorporated into a numerical reservoir model to determine the pressure depletion envelopes. The imported depletion model allows for the simulation of the child well treatments and associated impacts of the pressure sinks on fracture generation and the interaction between child and parent wells. The resulting depletion model provided a framework to investigate various methods to mitigate the effects of well-to-well communication in subsequent development. The developed workflow of well-to-well interference is applicable in understanding the effects of infill development in other producing basins. The modeled child well treatments resulted in a clear indication of well-to-well communication with the parent wells that was attributable to pressure depletion. Actual field bottom-hole pressure measurements validated these results in the parent wells captured during the time of the child well treatments. Resulting proppant concentrations of the child well fractures indicated that the majority of the proppant transports towards the parent wells. Very little effective conductivity exists in the opposing direction of the depleted regions. Slickwater treatment simulations indicate extremely asymmetric fractures that stay isolated to their respective target bench. For child wells in the same bench as the parent wells, fractures propagate directly toward the parent wells, with little to no fracture growth in the opposite direction. Protection frac simulations indicate beneficial or detrimental results depending on the amount of repressurization that is achieved and the distance that the pressure transient extends into the reservoir. Re-pressurizing the reservoir surrounding the parent wells by 1,000 psi resulted in a reduction of well interference. A 500-psi scenario resulted in increased well interference between the parent wells. Several wells communicated with both parent wells due to the repressurization being insufficient to offset the depletion. Natural repressurization of the reservoir to mitigate the effect of well interference was also investigated by using the reservoir model. Simulation of the parent wells being shut-in for three months prior to the child well treatments resulted in a pore pressure increase of only 280 psi. Based on the protection frac sensitivity of 500 psi, this is not a large enough repressurization to mitigate well-to-well interference successfully in the modeled scenarios.
Abstract This paper presents a rigorous method to scale rate-time profiles of multi-fractured horizontal wells (MFHW) to a set of reference reservoir and completion properties. Scaling is required for development of accurate production forecasts and typical well production profiles (type wells) with minimum uncertainty. We use a modified version of commonly-used type curves, notably the Wattenbarger type curve, to fit production data. The fit requires that production profiles exhibit a negative half slope during transient linear flow followed by negative unit slope during boundary-dominated flow on a rate vs. material balance time plot. The horizontal and vertical displacement required to fit observed data to the type curve define the scaling factors for individual wells. We present a set of equations to scale a given well's production profile to that of a reference well with specified effective permeability, fracture length, lateral length, net-pay thickness, drawdown, and fracture stage spacing. Just as we can scale a group of wells to common reference conditions, we can also rescale to predict the performance of a well with specified properties, such as average properties determined from wells analyzed or wells with completion designs different from those analyzed. While it is common and clearly important to normalize (scale) rate profiles for lateral length, we demonstrate that it is also crucial to scale production profiles in rate and time to account for differences in permeability, fracture spacing and thus, the duration of flow regimes. We provide examples of successful scaling based on publically reported production data from Marcellus, Barnett, Niobrara, Midland Basin (Wolfcamp) and Eagle Ford resource plays. Most of the methods used to assess the performance of MFHW's in resource plays rely on having a statistically significant number of analogs. However, datasets of sufficient size are often either unavailable or limited by the large variety of completion designs and well performance characteristics. Our approach to scale production can dramatically increase the number of analogs available to characterize a geologically similar area and thus reduce the uncertainty in production forecasts.