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Weijers, Leen (Liberty Oilfield Services) | Wright, Chris (Liberty Oilfield Services) | Mayerhofer, Mike (Liberty Oilfield Services) | Pearson, Mark (Liberty Resources) | Griffin, Larry (Liberty Resources) | Weddle, Paul (Liberty Resources)
Abstract Hydraulic fracturing has been a part of oil & gas development in North America for seven decades. Hydraulic fracturing was first conducted in 1947. Commercial operations began in 1949. After over twenty years fracturing took a large step up in the late-1970s with its application to tight gas sand formations. The game changer that brought discussion of hydraulic fracturing to dinner tables, bars and sidelines of soccer games is the recent advances that enable commercial extraction of natural gas and oil directly from shale source rocks. Since the start of shale fracturing in the early-1990s, fracturing technology and the pressure pumping industry's efficiency in delivering fracturing services have changed almost beyond recognition. The result has been the world-changing Shale Revolution. Through researching industry databases, the authors have compiled an industry-wide review of North American hydraulic fracturing activity dating back to the first work done in the late 1940s. Yearly stage count in the 1950s through the early 1990s was 10,000 – 30,000 stages/year, while recent peak levels show a step change in activity aproaching 500,000 stages/year (Fig. 1). While the North American industry's fracturing horsepower grew about 10-fold between 2000 and 2018, yearly frac stage count grew 20-fold in North America and proppant mass pumped grew 40-fold. The authors show how the industry achieved a step-change in reducing service delivery cost through innovation and efficiency, allowing sustained economic development of unconventional resources at decreasing breakeven production costs. Technological changes, as assisted by a better understanding through frac diagnostics, integrated modeling and statistical analysis have enabled the large cost reduction to commercially produce a barrel of oil. As a result, shale frac designs have focused on higher intensity completions with tighter stage and cluster spacing, improved diversion through extreme limited entry perforation design and simultaneous and zipper frac'ing, increasing proppant mass per well, utilizing next-generation frac fluids to increase produced water recycling and using cheaper lower-quality proppant. At the same time, the environmental footprint of oil & gas production has been shrinking and will continue to do so as operational changes continue to make our industry a better neighbor, for example through faster well construction utilizing fewer pad locations, development of quiet fleets, greener frac chemistry, frac focus disclosure, etc. Together, oil and gas operators and their service providers have used technology & innovation to improve efficiencies and increase the overall daily pump time per frac crew. However, there is plenty of room for further improvements in technology and efficiency. We believe this is the first industry database of its kind covering hydraulic fracturing activity in the United States, going back to the 1940s. We hope this paper provides a unique perspective of how our industry has changed through the Shale Revolution.
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 3rd 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 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.
Moore, Joseph (DowDuPont Industrial Biosciences) | Massie-Schuh, Ella (DowDuPont Industrial Biosciences) | Wunch, Kenneth (DowDuPont Industrial Biosciences) | Manna, Kathleen (DowDuPont Industrial Biosciences) | Daly, Rebecca (Colorado State University) | Wilkins, Michael (Colorado State University) | Wrighton, Kelly (Colorado State University)
Abstract Hydraulic fracturing presents an ideal breeding ground for microbial proliferation due to the use of large volumes of nutrient-rich, water-based process fluids. Bacteria and/or archaea, when left uncontrolled topside or in the reservoir, can produce hydrogen sulfide, causing biogenic souring of hydrocarbons. In addition, microbial populations emerging from the downhole environment during production can colonize production equipment, leading to biofouling, microbially influenced corrosion (MIC), produced fluid separation issues, and HS&E risks. Mitigating these risks requires effective selection and application of biocides during drilling, completion, and production. To this end, a microbiological audit of a well completion operation with the objective of determining the effectiveness of a tandem chlorine dioxide (ClO2) and glutaraldehyde/quaternary ammonium (glut/quat) microbial control program was carried out. This paper describes the rationale behind selection of sampling points for a comprehensive microbiological field audit and provides the resulting critical analysis of biocide efficacy in the field using molecular assays (qPCR, ATP) and complementary culturing techniques (microtiter MPN and culture vials—commonly termed "bug bottles"). Due to the comprehensive nature of sampling and data collection, it was possible to make much more applicable and relevant observations and recommendations than it would have been using laboratory studies alone. First, multiple sources of microbial contamination were identified topside, including source waters, working tanks, hydration units, and guar. Additionally, critical analysis of biocide efficacy revealed that ClO2 treatment of source water was short-lived and ineffective for operational control, whereas glut/quat treatment of fracturing fluids at the blender was effective both topside and downhole. Analysis of the microbial load at all topside sampling points revealed that complete removal of ClO2 treatment could be offset by as little as a 10% increase in glut/quat dosage at the blender. This is a highly resolved microbiological audit of a hydraulic fracturing opration which offers new, highly relevant perspectives on the effectiveness of some biocide programs for operational control. This overview of biocide efficacies in the field will facilitate recommendations for both immediate and long-term microbial control in fractured shale reservoirs.
Owens, Matt (Extraction Oil & Gas) | Silva, Jesse (Extraction Oil & Gas) | Volkmar, Matt (Extraction Oil & Gas) | Poppel, Ben (Liberty Oilfield Services) | Siegel, Joel (Liberty Oilfield Services) | Losacano, Tony (Liberty Oilfield Services) | Weijers, Leen (Liberty Oilfield Services)
Abstract The Denver-Julesburg Basin has been going through a new cycle of development with horizontal drilling and high-intensity hydraulic fracturing. Since the first horizontal wells in 2008, more than 4,000 horizontals have been drilled, leading to a four-fold production increase between 2008 and 2012. While completion practices have been fairly similar across the basin over these early-development years, several operators are now starting to experiment with different completion designs. The objective of this paper is to discuss the benefits of these new designs and further evaluate what completion changes deliver the most "bang for the buck" in a challenging pricing environment. Use of a novel completion design and development of a low-cost ultra-low concentration fluid system resulted in significant cost saving while maintaining or improving overall production, thus lowering $/BOE in a challenging industry environment. Lowering cost per BOE drove a process of completion design changes that started with fluid compatibility testing, including regained permeability testing in proppant load cells, which showed that a light and more cost-effective Borate Guar can result in similar or better cleanup than a CMHPG-Zirconate system traditionally used in the DJ basin. Multi-variate analysis results from an extensive petrophysical / completion / production database showed production in the basin predominantly benefits from increase proppant volume and higher stage intensity. Field implementation of this system and a design with more proppant and stage intensity focused on consistently being able to place higher proppant loadings with less polymer. More than 150 horizontal wells were completed between mid-2014 and early 2016 in T5-6N R64-67W while implementing this strategy. When compared to about 350 other horizontal wells, mostly completed without these changes, overall results of the new completion strategy have been very encouraging: Higher injection rates and improved pump time to downtime resulted in a 20+% reduction in days required to complete a typical 8-well pad. Over a period of about 130 pumping days, more than 2,100 frac stages were completed. Supply chain efficiency improvements were implemented to keep up with proppant demand averaging 3.5 million pounds of sand every day, occasionally peaking to above 8 million pounds of sand per day; A new ultra-low concentration Guar Borate system was developed that could be crosslinked at concentrations down to 8 lbs/Mgal. Together with high rate, this fluid system enables placing proppant concentrations up to 6 PPA, making the system significantly cheaper and cleaner than the conventional 20+ lbs/Mgal CMHPG systems that were routinely used in the DJ Basin. Overall production in both Codell and Niobrara was above results for nearby peers over a wide range of production metrics. A petrophysical workflow was developed to arrive at a proper apples-to-apples comparison of historical production response in the area as compared with the results associated with this new strategy. Through various statistical analysis tools such as multi-variate analysis, the authors evaluated the importance of both reservoir and completion changes, and identified several key characteristics that are closely tied to the highest production responses in the DJ Basin.
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.