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ABSTRACT The industry is facing significant challenges due to the recent downturn in oil prices, particularly for the development of tight reservoirs. It is more critical than ever to 1) identify the sweet spots with less uncertainty and 2) optimize the completion-design parameters. The overall objective of this study is to quantify and compare the effects of reservoir quality and completion intensity on well productivity. We developed a supervised fuzzy clustering (SFC) algorithm to rank reservoir quality and completion intensity, and analyze their relative impacts on wells' productivity. We collected reservoir properties and completion-design parameters of 1,784 horizontal oil and gas wells completed in the Western Canadian Sedimentary Basin. Then, we used SFC to classify 1) reservoir quality represented by porosity, hydrocarbon saturation, net pay thickness and initial reservoir pressure; and 2) completion-design intensity represented by proppant concentration, number of stages and injected water volume per stage. Finally, we investigated the relative impacts of reservoir quality and completion intensity on wells' productivity in terms of first year cumulative barrel of oil equivalent (BOE). The results show that in low-quality reservoirs, wells' productivity follows reservoir quality. However, in high-quality reservoirs, the role of completion-design becomes significant, and the productivity can be deterred by inefficient completion design. The results suggest that in low-quality reservoirs, the productivity can be enhanced with less intense completion design, while in high-quality reservoirs, a more intense completion significantly enhances the productivity. Keywords Reservoir quality; completion intensity; supervised fuzzy clustering, approximate reasoning,tight reservoirs development
ConocoPhillips announced today that it has made a new oil discovery offshore Norway. Located about 14 miles north-northeast of the Heidrun Field in the Norwegian Sea, the newly tapped Slagugle prospect is estimated to hold a recoverable volume of 75 to 200 million BOE, according to ConocoPhillips. The discovery well was drilled in 1,165 ft of water to a total depth of 7,149 ft by the Leiv Eiriksson drilling rig. ConocoPhillips is the operator of the prospect with an 80% stake. Norway-based Pandion Energy is the license partner with a 20% working interest.
"Down but not out" is how Westwood Global Energy Group described exploration drilling in an article based on its State of Exploration 2020 Report. The Baker Hughes rig count provides supporting details. On 12 May, the data showed 339 active rigs in the United States--the lowest level since the rig count was introduced in 1987. On 1 June, the US count plunged to 301 in its 12th week of losses. At the worst of the 2014–2016 oil bust--the previous lowest point on record--404 rigs were operating.
Things are so bad in the oil and gas business that ExxonMobil said it may reduce its reserves by 4.5 billion BOE. The major that has traditionally resisted reserves writedowns said low prices and reduced spending on exploration and production are forcing it to follow the lead of other companies that have reduced their estimate of how much oil and gas they can profitably produce. "It is possible that reductions to proved reserves could amount to approximately 20 percent of the Corporation's 22.4 billion oil-equivalent barrels reported at year-end 2019," ExxonMobil said in a filing with the US Securities and Exchange Commission. The company mentioned two of its upstream operations which have declined in value in that filing and a related filing by its Imperial Petroleum arm in Canada. High-cost heavy-oil production in Canada is likely to be written down, "primarily proved bitumen reserves at Kearl."
Global discovered oil and gas resources and big project sanctions are expected to remain on the upswing through next year, according to separate industry outlooks from Rystad Energy and Wood Mackenzie. Internalizing lessons from a difficult last few years, operators are choosing investments more wisely and now better prepared to deal with volatile oil markets, the consultancies concluded. "Oil and gas companies can cope with whatever is thrown at them in 2019," said Tom Ellacott, Wood Mackenzie senior vice president. "Portfolios are set to weather low prices, and the recent slide in prices justifies the sector's conservative mindset." While exploration spending rose in 2018, the figure was down 61% compared with 2014, aided by a decrease in exploration costs, Rystad data indicate.
Chevron announced that it will purchase all outstanding shares of independent producer Noble Energy in an all-stock transaction valued at $5 billion. Including Noble's debt, the deal is valued at about $13 billion. The deal strengthens Chevron's position in the Permian Basin with about 92,000 largely contiguous acres near its own assets in the region. Noble's offshore assets in Israel, including the Leviathan field, the largest natural gas field in the eastern Mediterranean, and Equatorial Guinea, add to Chevron's strength in those regions. Chevron also picks up land in the DJ Basin and Eagle Ford and an integrated midstream business through its stake in Noble Midstream.
Whatever the pace of the energy transition, the world will continue to rely on oil and gas for much of its energy needs until well beyond 2040. Exploration will be critical in meeting this future demand. Yet exploration is widely perceived as discretionary, even unwarranted. Doubters see a world of risk, declining demand, enormous existing resources, and a supply pecking order that ranks exploration squarely in last place. Andrew Latham and Adam Wilson, both of Wood Mackenzie Global Exploration, offered a different perspective in their June 2020 report "Exploration's Future in a Low-Cost, Low-Carbon World."
Summary Reserves estimation is an essential part of developing any reservoir. Predicting the long-term production performance and estimated ultimate recovery (EUR) in unconventional wells has always been a challenge. Developing a reliable and accurate production forecast in the oil and gas industry is mandatory because it plays a crucial part in decision-making. Several methods are used to estimate EUR in the oil and gas industry, and each has its advantages and limitations. Decline curve analysis (DCA) is a traditional reserves estimation technique that is widely used to estimate EUR in conventional reservoirs. However, when it comes to unconventional reservoirs, traditional methods are frequently unreliable for predicting production trends for low-permeability plays. In recent years, many approaches have been developed to accommodate the high complexity of unconventional plays and establish reliable estimates of reserves. This paper provides a methodology to predict EUR for multistage hydraulically fractured horizontal wells that outperforms many current methods, incorporates completion data, and overcomes some of the limitations of using DCA or other traditional methods to forecast production. This new approach is introduced to predict EUR for multistage hydraulically fractured horizontal wells and is presented as a workflow consisting of production history matching and forecasting using DCA combined with artificial neural network (ANN) predictive models. The developed workflow combines production history data, forecasting using DCA models and completion data to enhance EUR predictions. The predictive models use ANN techniques to predict EUR given short early production history data (3 months to 2 years). The new approach was developed and tested using actual production and completion data from 989 multistage hydraulically fractured horizontal wells from four different formations. Sixteen models were developed (four models for each formation) varying in terms of input parameters, structure, and the production history data period it requires. The developed models showed high accuracy (correlation coefficients of 0.85 to 0.99) in predicting EUR given only 3 months to 2 years of production data. The developed models use production forecasts from different DCA models along with well completion data to improve EUR predictions. Using completion parameters in predicting EUR along with the typical DCA is a major addition provided by this study. The end product of this work is a comprehensive workflow to predict EUR that can be implemented in different formations by using well completion data along with early production history data.
Since selling its assets in the Marcellus in 2014, PDC Energy has undergone a major strategic shift in its hydraulic fracturing operations, focusing primarily on its acreage in Colorado's Wattenberg field while entering the Delaware Basin in west Texas. As the independent exploration and production company enters the third year of this new operational focus, its top executive said there is plenty of reason for optimism. Speaking at a luncheon co-hosted by the Independent Petroleum Association of America and the Texas Independent Producers and Royalty Owners Association, PDC President and Chief Executive Officer Bart Brookman gave an overview of recent developments at the company. Brookman described the Wattenberg as a highly productive region for PDC, and that the company hopes to increase efficiency in the operation of its 96,000 acres. Brookman said the company plans to drill each new well with monobore technology, saving approximately 1 day in spud-to-release times.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 198192, “Production Performance Evaluation From Stimulation and Completion Parameters in the Permian Basin: Data-Mining Approach,” by Mustafa A. Al-Alwani, SPE, and Shari Dunn-Norman, SPE, Missouri University of Science and Technology, and Larry K. Britt, SPE, NSI Fracturing, et al., prepared for the 2019 SPE/AAPG/SEG Asia Pacific Unconventional Resources Technology Conference, 18–19 November, Brisbane, Australia. The paper has not been peer reviewed. The complete paper uses 3,782 unconventional horizontal wells to analyze the effect of proppant volume and the length of the perforated lateral on short- and long-term well productivity across the Permian Basin. Tying cumulative production to completion and stimulation practices showed that increasing pumped proppant per well from 5 million to less than 10 million lbm yielded a 34% increase in 5-year cumulative average barrels of oil equivalent (BOE). Raising the pumped proppant per well to 10 million-15 million lbm and 15 million-20 million lbm increased 5-year cumulative BOE from the previous proppant range group to 27% and 18.5%, respectively. Introduction For this study, stimulation chemical data from Permian (Midland) Basin wells were downloaded from FracFocus for all horizontal wells completed and stimulated between 2012 and 2018. The data were then subjected to rigorous cleaning and processing, a process detailed in the complete paper, and then combined with DrillingInfo completion and production parameters. Combining these data provided ample parameters for stimulation, completion, and production data. The objective of the study was to investigate the production performance of Permian Basin wells as a result of different ranges of stimulation and completion parameters. Fig. 1 shows a database representation of the major counties in the Permian Basin with the number of wells in each county. Results and Discussion To substitute for any quantities of produced gas, all production data have been converted to BOE by using the conversion factor of 1 BOE=6 Mcf. The amount of proppant being pumped and the length of the perforated lateral length have been selected to represent the stimulation size and the completion magnitude, respectively.