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Two online seminars planned by IPIECA, the global oil and gas industry association for advancing environmental and social performance, will examine efforts to address the greenhouse gases methane and carbon dioxide. Set for 9 December, the first seminar will look at carbon capture, utilization, and storage (CCUS) as a way to achieve net-zero emissions and meet the goals of the Paris agreement. Samantha McCulloch, head of the CCUS unit at the International Energy Agency (IEA), will present recent IEA publications related to CCUS, examining how CCUS is a critical technology in delivering cost-effective pathways to meeting the goals of the Paris agreement. She will focus on the IEA Energy Technology Perspectives (ETP) 2020; the IEA ETP special report CCUS in Clean Energy Transitions, for which she was lead author; and how CCUS facilitates the sustainable development and net-zero 2050 scenarios of the IEA World Energy Outlook 2020. The second seminar planned by IPIECA, set for 10 December, will look at reducing methane emissions in the oil and gas industry through improved operations.
Produced water is water that is brought to surface during oil and natural-gas production. It includes formation, flowback, and condensation water. Produced water varies in composition and volume from one formation to another and is often managed as a waste material requiring disposal. In recent years, increased demand for, and regional variability of, available water resources, along with sustainable water-supply planning, have driven interest in reusing produced water with or without treatment to meet requirements within the industry or by external users. Reuse of produced water can provide important economic, social, and environmental benefits, particularly in water-scarce regions. It can be used for hydraulic fracturing, waterflooding, and enhanced oil recovery, decreasing the demand for other sources of water.
The exceptional year that has been 2020 highlights the fact that the world can change quickly, and a challenging macroenvironment brings into focus the need to maximize the use of our natural resources and the value that can be derived from them. Even without the black swan event of COVID-19, the industry must critically examine the technical, commercial, and operational bases of the projects it proposes and executes. A logical, reasonable, ethical, and philosophical approach is critical to underpin good decision making and value creation. Paper SPE 196252 delivers a comprehensive discussion of the issues to consider in the management of mature oil fields that are becoming increasingly important as older fields decline and approach abandonment. The discussion makes direct reference to assessing the late-life economic limit within the context of the Petroleum Resources Management System.
US Job Numbers Up for OFS and Equipment Industry, But Outlook Remains Unclear The increase in OFS and equipment sector jobs over the past 2 months came amid higher oil and gas production. But increases in COVID-19 cases are causing uncertainty about when and how much demand will rise. Texas Regulator To Place New Limits on Allowable Flaring Oil and gas producers in the state are being asked to submit data and economic analysis on why they cannot sell natural gas before they are granted permission to flare it. UAE Has Become World’s Newest Producer of Unconventional Gas The first delivery of shale gas in the UAE marks a major milestone toward its goal of reaching 1 Bcf/D by 2030. It also signals the expansion of hydraulic fracturing in the UAE’s conventional fields.
In tight unconventionals, oil and gas rates often are measured daily at separator conditions. Consequently, converting these rates reliably to volumes at standard conditions is necessary in cases where direct stock-tank measurements are not available. Because of changes in producing-wellstream compositions and separator conditions, the separator-oil shrinkage factor (SF) can change significantly over time. The complete paper presents a rigorous and consistent method to convert daily separator rates into stock-tank volumes. Recommendations for developing field-specific shrinkage correlations using field test data also are proposed.
New wet-sand systems such as the one shown here may be the next big cost-cutting step for the unconventional sand sector. By eliminating the drying step, US operators can save up to $10 per ton of sand. Then it gets wet again. Such is the unassuming life cycle of most every grain of sand ever pumped down a horizontal well along with millions of gallons of water and into the freshly opened fractures of a tight-rock formation in the US. But what if the sand never had to be dried?
In 2019, an analysis of 16,000 unconventional wells operated by 29 of the largest producers in Texas and North Dakota revealed that these companies spent $112 billion more in cash over the past 10 years than they generated from operations. A primary contributor to this shortfall was optimistic production forecasts based on a small number of early wells. These types of projections lead companies to commit to development projects before they understand the true variability in well performance and, most importantly, whether the average well will be commercial (i.e., able to pay for the cost to drill, complete, and tie in). Commercial is defined here as attaining a present value greater than zero at the corporate discount rate. If this is 10%, a net present value (NPV) of zero equates to a 10% rate of return.
A British independent bet its future on proving that fractured basement formations could produce large amounts of oil and gas. Based on its first two wells, the proposition that these highly fractured layers of awful-quality reservoir rock can produce billions of barrels of oil is looking very unlikely, but there might be something of value down there. Last April, Hurricane Energy predicted those two development wells could easily produce 17,000 B/D of oil from rock it said held “half a billion barrels of oil.” Now Hurricane’s ambitious plans and its identity as “basement reservoir specialists” are in tatters. The initial wells were productive but much of what was coming out of the lower one—205/21a-7z—was water.
ExxonMobil announced on Monday a capital spending plan that is focused squarely on the company’s highest-potential developments. The company also issued a warning to investors about a major impairment to many of its dry-gas projects. ExxonMobil plans to spend between $16 billion and $19 billion next year and between $20 billion and $25 billion annually up to 2025. These figures represent a considerable reduction from ExxonMobil’s March capital plan that forecast $30 to $35 billion in exploration and development spending. In addition to its marquee developments offshore Guyana and the Permian Basin in Texas and New Mexico, the new capital program will also focus on “targeted exploration” projects in Brazil and the company’s chemicals division, according to a statement from ExxonMobil.
Sinopec recorded China’s highest daily output of shale gas at 20.62 million cubic meters (Mcm) at its Fuling shale-gas field in Chongqing, China, a key gas source for the Sichuan-East gas pipeline. The first major commercial shale-gas project in China, Fuling has continuously broken records for the shortest gasfield drilling cycle while significantly increasing the drilling of high-quality reservoirs covering more than 3 million m, according to Sinopec. Gasfield production construction was also expanded to raise production capacity. The company said the field maintains a daily output of 20 Mcm, producing an estimated 6.7 Bcm per year. Apache filed appraisal plans for its Maka and Sapakara oil discoveries in block 58 offshore Suriname.