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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.
Denver-based Civitas Resources announced today that it is acquiring Crestone Peak Resources in an all-stock transaction. Civitas was formed last month through the announced merger of Denver-Julesburg (DJ) Basin operators Bonanza Creek Energy and Extraction Oil & Gas. On a pro forma basis, the three-way merger will create a firm with an enterprise value of nearly $4.5 billion and a production profile of almost 160,000 BOE/D. Crestone's assets will bring Civitas' position in the DJ Basin to more than 500,000 net acres. In addition, the combination with Crestone is expected to realize nearly $45 million in expected annual synergies.
US shale producers Cabot Oil & Gas and Cimarex Energy are the latest to declare a "merger of equals" in a deal valued at around $17 billion, based on recent equity prices. Announced today, the terms of the deal will result in Cimarex shareholders owning about 50.5% of the combined company and Cabot shareholders owning approximately 49.5%. The deal brings together Houston-based Cabot's gas-rich portfolio, comprising almost 173,000 acres in the Marcellus Shale, with Cimarex's oil-dominated 560,000 net acres in the Permian Basin and Anadarko Basin. On a pro forma basis, the merged company will produce around 600,000 BOE/D from the three basins. The companies expect $100 million in savings to materialize within 2 years of the deal closing and to generate around $4.7 billion in free cash flow from 2022 to 2024.
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.
Potapenko, Dmitriy Ivanovich (Member) | Hart, Timothy Brian (Fremont Petroleum Corporation) | Waters, George Alan (Member) | Lewis, Richard E. (Member) | Utter, Robert J. (New Ventures Energy Consulting) | Brown, J. Ernest (Member) | Goudy, Guy Thomas (Formerly Fremont Petroleum Corporation) | Jelsma, Henk H (Radial Drilling Services, Inc.)
Abstract This paper describes the first application of a novel reservoir-stimulation methodology that combines oriented extended perforation tunnels of lengths up to 300 feet with specially designed hydraulic fracturing operations in the Niobrara Formation in the Florence Field in Colorado. The technology was extensively tested in two vertical wells completed with two and five pairs of the extended perforation tunnels respectively. Extended perforation tunnels were jetted using radial drilling technique with the tools deployed using micro coil tubing. The jetting operation on each well was followed by a fracture stimulation treatment. The use of radial drilling technology to create extended perforation tunnels for the vertical wells offered a cost-effective way to significantly increase the reservoir contact area of the wellbore, making it similar to that of horizontal wells in the area. The engineered fracture treatments were performed at low treating pressures, and low proppant and fluid volumes. The stabilized production rates of both project vertical wells included in this technology test exceeded expectations and are comparable to the stabilized production rate of the offset horizontal well that was completed in the same zone with significantly higher volumes of proppant and fluid. The initial evaluation of the completion efficiency of this novel reservoir stimulation technology showed that its deployment delivered an improved stabilized production rate to cost ratio for the second vertical well, compared to the reference horizontal well. Based on the test results from the two wells, we conclude that the proposed reservoir stimulation methodology leads to substantial improvements in well production performance compared to traditional reservoir stimulation methods. Both the applied cost-effective approach for increasing the reservoir contact and the significantly lower resource intensity required for the hydraulic fracturing treatment further improve the economic benefits of this methodology. This novel reservoir stimulation methodology opens the way for reconsidering well completion practices in the Niobrara Formation and holds significant potential for improving the hydrocarbon production economics in the Florence Field.
The Rumaila Field is in southeast Iraq and contains multiple reservoir intervals, including the Upper Cretaceous Mishrif carbonate reservoir, one of the major reservoirs in the world, that has been producing for more than 50 years. One of the key challenges in the Mishrif is to characterize the pore-structure distinction between primary and secondary porosity. The secondary porosity in the form of large pores, if present, dominates the petrophysical properties, especially permeability. Advanced logs, e.g., nuclear magnetic resonance (NMR) and image logs, can be used to understand the variations in pore structure, both qualitatively and quantitatively. In this paper, we focused primarily on four new wells with very comprehensive logging and coring programs. NMR logs were acquired using different tools and pulse sequences. This resulted in uncertainty in porosity and T2 distributions and, consequently, complications in the NMR interpretation. We observed two key issues: porosity deficit due to lack of polarization and T2 distribution truncation due to the low number of echoes. We used a single pore model to reproduce the NMR response in different pore sizes and fluid types for different pulse sequences. The results showed that the NMR response, especially in water-filled (water-based-mud filtrate) large pores, is sensitive to polarization time, echo spacing, and tool gradient strength. NMR log data confirmed the modeling results. We recommended an optimum pulse sequence and tool characteristics to fully capture the heterogeneous rock and fluid system in this carbonate reservoir. NMR logs, when available, were the primary tools to identify the large pores. We present a consistent workflow for NMR log analysis that was developed to identify and quantify large pores and extended to all wells in the field. We used advanced NMR interpretation techniques, e.g., factor analysis (NMR FA) (Jain et al., 2013), in a series of oil wells drilled with water-based mud. Using factor analysis, we identified a cutoff value of 847 ms for large pore volumes. In this manuscript, we also present an integration of laboratory measurements, e.g., NMR, mercury intrusion capillary pressure (MICP) data, whole-core CT scanning, and thin-section analysis, in our interpretation workflow. We also compared the large pore volume from image logs with NMR logs and other laboratory data and observed very consistent results. All the available information was integrated to build an “NMR-based” petrophysical model for porosity, rock type, permeability, and saturation determination. The NMR-based model was very comparable with the classic flow zone indicator (FZI) rock typing. The results of this study were used to modify the NMR acquisition program in the field and to build a petrophysical model based on only NMR and image log measurements for carbonate reservoirs. In this paper, we will discuss NMR modeling and corresponding log data from various wells to confirm the results. Furthermore, we will present a novel interpretation workflow integrating laboratory measurements and log data, which led to the modification of the NMR acquisition program in the field and the creation of a data-driven petrophysical model based on only NMR and image log measurements for carbonate reservoirs.
Summary “Fracture hit” was initially coined to refer to the phenomenon of an infill-well fracture interacting with an adjacent well during the hydraulic-fracturing process. However, over time, its use has been extended to any type of well interference or interaction in unconventional reservoirs. In this study, an exhaustive literature survey was performed on fracture hits to identify key factors affecting the fracture hits and suggest different strategies to manage fracture hits. The impact of fracture hits is dictated by a complex interplay of petrophysical properties (high-permeability streaks, mineralogy, matrix permeability, natural fractures), geomechanical properties (near-field and far-field stresses, tensile strength, Young’s modulus, Poisson’s ratio), completion parameters (stage length, cluster spacing, pumping rate, fluid and proppant amount), and development decisions (well spacing, well scheduling, fracture sequencing). It is difficult to predict the impact of fracture hits, and they affect both parent and child wells. The impact on the child wells is predominantly negative, whereas the effect on parent wells can be either positive or negative. The “child wells” in this context refer to the wells drilled with pre-existing active/inactive well(s) around. The “parent well” refers to any well drilled without any pre-existing well around. Overall, fracture hits tend to negatively affect both the production and economics of lease development. The optimal approach rests in identifying the reservoir properties and accordingly making field-development decisions that minimize the negative impact of fracture hits. The different strategies proposed to minimize the negative impact of fracture hits are simultaneous lease development, thus avoiding parent/child wells (i.e., rolling-, tank-, and cube-development methods); repressuring or refracturing parent wells; using far-field diverters and high-permeability plugging agents in the child-well fracturing fluid; and optimizing stage and cluster spacing through modeling studies and field tests. Finally, the study concludes with a recommended approach to manage fracture hits. There is no silver bullet, and the problem of fracture hits in each shale play is unique, but by using the available data and published knowledge to understand how fractures propagate downhole, measures can be taken to minimize or even completely avoid fracture hits.
Extraction Oil & Gas announced today that it has filed for bankruptcy protection in a Delaware court which will allow it to reorganize its debt and gain a fresh start upon its exit. The Denver-based firm was expecting to be cash-flow-positive this year but instead finds itself dealing with significantly lower commodity prices as a result of the COVID-19 pandemic that has slowed the world's largest economies. Founded in 2012, Extraction said in earnings reports filed in May that it produced just over 38,500 B/D last quarter, primarily from Colorado's Wattenberg field that lies within the Denver-Julesburg Basin. The firm also reported a net income of $9 million compared with a debt load nearing $1.5 billion. That same month, Extraction withdrew its 2020 guidance as it missed an interest payment on bonds that do not expire until 2024, triggering a 30-day grace period that allowed the company time to mull its options.
The plunge in well completions has exceeded the drop in the number of active drilling rigs, and operators are rethinking how they fracture wells now that oil is selling for half of what it did 6 months ago. For Mike Vincent, an independent consultant who teaches fracturing courses, it led to a change in his lesson plans. "One class I am teaching this summer is titled, 'How should we complete a well in a low-cost environment?'" he said. "We need to do things differently. There should be a different optimal design if a well is drilled when oil is USD 50/bbl versus USD 100/bbl." Financially the goal is simple: find a way to earn an acceptable profit on each dollar invested.
Discussions of produced-water handling and the emerging water midstream sector typically focus on the Permian Basin, but water is an issue for a number of other basins. The needs of producers in these areas are driving greater investment in pipeline infrastructure. "Every discussion that we're having with every customer we've contracted to long term is about moving pipe," said Brad Morgan, board chairman of Expedition Water Solutions, a midstream company that handles more than 100,000 BWPD in the Denver-Julesburg (DJ) and Powder River Basins. Morgan said water volumes and the push by regulators get water-hauling trucks off the road have fueled this push to build more pipe. Expedition has more than 100 miles of pipeline in greenfield expansion planned through 2020.