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ABSTRACT: Tight project economics and cracking pace operations are the common factors worldwide recognized when dealing with the development of gas shale play. Very often being able to identify critical parameters quickly is the only possibility to make a project a successful one. In the unconventional world where thousands of operations have to be repeated in a sort of assembly line more than in other different scenarios production optimization play the lead role impacting the overall field performances, investments and economical value of the project. Meeting the target requires identifying easy, reliable and repeatable technologies, fine tuning existing approaches, testing the ability to predict the productivity of shale gas reservoir and managing high efficiency production. One of the biggest challenges facing the industry has been identifying which drilling and completion strategy will create the most efficient fracture network in order to maximize hydrocarbon productivity and recovery. Some other parameters such as wells lateral length and its production efficiency and interference have to be accurately studied not to over or under stimulate formation. This paper addresses some of these major questions by starting from analysis of real case studies and will try to identify not the final answer but the correct path that should be followed in order to find the economical optimum of a complex system. The analysis begins with reservoir evaluation, followed by drilling and completion design and actual production optimization. Explanations of how the data gained from modeling will be built into future budgets and drawing conclusions from these performance indicators will help in predictions about new areas to be deployed.
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.50)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.31)
US shale producer Chesapeake Energy announced on Wednesday that CEO Doug Lawler is stepping down. The interim chief will be Mike Wichterich who was appointed by the company's creditors as its new chairman upon its exit from bankruptcy in February. "On behalf of the Board of Directors, Chesapeake's employees and its shareholders, I would like to thank Doug for the vision and leadership he provided for the past 8 years. He guided Chesapeake through a difficult period, repositioned Chesapeake's portfolio of assets, and built a corporate culture which will serve as a platform for future success. I firmly believe that the investment thesis supporting Chesapeake is compelling, and my confidence in the renewed strength of the company continues to grow," Wichterich said in a statement.
Equinor has agreed to sell its Bakken Shale operation for $900 million, ending a decade long struggle to make money in the US shale oil business. The buyer, Grayson Mill Energy, is acquiring wells producing around 48,000 BOE/D and 242,000 operated and non-operated acres in North Dakota and Montana. The Norwegian oil company's remaining shale holdings are in the gas producing Marcellus and Utica Shale formations in the eastern US, which it has been paring in recent years. "We are taking action to improve the profitability of Equinor's international oil and gas business," said Al Cook, executive vice president of development and production international at Equinor. He added that Grayson Mill agreed to hire Equinor's Bakken field team and a "significant number of the support teams."
- North America > United States > North Dakota (0.93)
- North America > United States > Montana (0.93)
- North America > United States > West Virginia (0.57)
- (3 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play (0.93)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (13 more...)
The issue of water needs for shale resource development has largely focused on public concern about possible constraints on water supplies, particularly in areas suffering from drought. A new study suggests that without technological breakthroughs or changes in how the oil and gas industry manage water, development of shale production could be hampered in areas with the largest estimated reserves. Some cities in the United States suffering from drought have imposed bans on hydraulic fracturing, even though oil and gas industry water use compares favorably with that of other industries (see Beyond the Headlines, July 2014 JPT, p. 20). The new report issued by the World Resources Institute, titled "Global Shale Development: Water Availability and Business Risk," focuses not on public concerns, but energy company risk instead. It contends that water-availability challenges could limit shale resource development on six continents, including in areas with some of the greatest potential for shale production. The report's executive summary looks at three countries in particular and assesses the potential water challenges.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Trimming the time that exists from the day drilling begins to the delivery of first oil represents a largely overlooked opportunity for US shale producers to improve free cash flow. In the Delaware Basin alone, accelerating this cycle time would save the shale sector more than a billion dollars. This is according to a recently published study from Westwood Global Energy Group and the Project Production Institute (PPI), a San Francisco-based non-profit that promotes a method called “operations science” for major capital planning and management projects. Their findings offer a new quantitative look at the hidden costs of the shale sector’s nonproducing asset base. The biggest issues boil down to two periods in the life of a shale well: when it is a drilled-but-uncompleted (DUC) well, and after it is completed but still waiting to be attached to a sales line. Holding too large an inventory of these dormant properties means locking up large sums of capital indefinitely. On the other hand, a lower balance of DUCs coupled with achieving initial production on a quicker basis frees more of that sunk capital to generate revenue. DUCs and completed wells awaiting hookup are categorized in the study as a single measurable called “work in process.” This metric includes drilling and completions, but it is the nonoperational days where producers have the most room to improve. Excessive work in process also includes drilling permits sitting idle, pads that are built but not yet drilled upon, well design lead times, and other delays. Amanda Goller, who leads research for PPI, acknowledges that while overall cycle times have remained relatively constant in spite of larger well pads and longer laterals, nonoperational time on multiwell pads is steadily creeping higher. This is attributed to the fact that, generally, the shale sector has not considered work in process an effective way to benchmark capital management•performance. “Most oil companies have scheduling software to track what their work in process is—but that won’t tell them what it should be,” she explained, adding that, as a result, “The industry does not control its work-in-process inventory.” Goller is both the director of analysts communications at PPI and the director of analytics with Strategic Project Solution, which develops operations science software. She said this class of software deviates from traditional planning programs because it “uses mathematical formulas to tell you pretty much in real time, where everything should be every day.” The PPI website offers this definition: “Operations science focuses on the interaction between demand and production and the variability associated with either or both.” As evidence that operational practices are a difference maker, Goller points to the wide disparity of cycle times among the 15 largest unconventional operators in the Delaware Basin. The study found that mean cycle times across the basin are 154 days, with the poorest performers averaging 233 days from spud to initial production. The top percentile sees first oil in 88 days.
- North America > United States > Texas (0.48)
- North America > United States > New Mexico (0.48)
- North America > United States > California > San Francisco County > San Francisco (0.25)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)