For what seems like forever, the upstream universe has awaited the emergence of Argentina's Vaca Muerta Shale as the international answer to US shale. In many regards, it already holds its own. In others, there is still much work to be done. Either way, 2018 and 2019 will mark a promising step forward for the play, according to data from research and consulting firm Rystad Energy. US shale plays grew exponentially during their development phases, with the number of horizontal wells completed shooting up year-to-year in their first 5 years of relevancy.
Chesapeake Energy is partnering with RS Energy Group to improve operational efficiency and capital discipline by employing advanced analytics and machine learning. RS Energy is a Calgary-based energy research firm founded in 1998 covering more than 150 operators in the major North American and international oil and gas regions, including the US shale plays. It provides technical analysis of basins, including completions and production, as well as asset evaluations for operators considering acreage additions. All of this is done within the context of shifting capital markets. Chesapeake announced the pact fresh off its $4-billion merger with WildHorse Resource Development, which bolstered its position in the Eagle Ford Shale of South Texas.
Much has been made recently about the disparities in production between parent and child wells in US shale basins. The increased attention on the issue is part of broader concern among investors about the ability of operators to maintain high levels of output over the next few years. However, Doug Suttles, Encana president and chief executive officer, assures that shale executives are acutely aware of the parent-child challenge. His company has been "very public about this for 5 years now," he said before an audience largely consisting of the investor community at CERAWeek by IHS Markit this week in Houston. He ultimately doesn't think it's "a big threat" to the shale sector.
The US upstream space may be more than 3 years removed from the apparent bottom of a generational oil-price slump, but the number of shale operators filing for Chapter 11 bankruptcy protection continues to grow. The latest two are Sanchez Energy and Halcón Resources, both based in Houston. For Halcón, it is the company's second time in 3 years. Sanchez's voluntary filing on 11 August "follows an extensive review of strategic alternatives to align its capital structure with the continued low-commodity-price environment," the company said in a news release. The Eagle Ford Shale producer will continue to operate as usual with an additional $175 million in newly committed financing, of which $25 million will be used to repay borrowings and replace a letter of credit.
The current oil and gas commodity prices have posed several challenges to oil and gas companies operating in shale plays trying to generate revenue or even becoming cash neutral. Shale drilling, as opposed to conventional drilling, requires many more wells to produce similar volumes of oil or gas due to the significantly smaller wellbore drainage area and the tight nature of the reservoir. For these projects to be economically viable, a high volume of low-cost and quickly drilled and completed wells is required, which cannot be achieved with a conventional oil and gas mindset. By implementing a Lean Well Manufacturing Management System and by having a dedicated Productivity Improvement team embedded in the operations driving changes, BHP Billiton was able to reduce drilling and completion (D&C) costs by 49% in the Eagle Ford Basin and 50% in the Permian Basin over an 18-month period (Figure 1). These results are similar to those reported by other operators in similar plays that also incorporated lean management principles to their operations.
Frac hits were once a painful cost of doing business for Abraxas Petroleum. But today, the San Antonio, Texas-based shale producer has softened the blows dealt by this widespread and challenging problem. Its approach, called "active well defense," has been put to the test amid the rolling hills of the company's North Fork oil field in McKenzie, North Dakota. "Necessity is the mother of invention--and that's our story here," said Peter Bommer, vice president of engineering at Abraxas, who noted that the driver of its strategy was not production declines, as it has been for others. Instead, active well defense is designed to prevent temporary, yet costly, production stoppages caused by unabated frac hits filling parent wells with sand. The company starts by injecting produced water at low pressures into older, parent wells.
But is there an appetite to put it all together and redefine what it means to be a shale producer? This is the key question looming over the future of enhanced oil recovery for tight shale reservoirs, or simply shale EOR. To answer it, unconventional oil producers are trying to weigh the options from what amounts to a complicated pros-and-cons list. Developing a shale EOR program may mean drawing resources away from new exploration projects that have quicker returns, the same conundrum that has stymied the US refracturing market. On the other hand, shale EOR boasts impressive economics for companies willing to reinvest in land and wells already paid for.
Almost all gas wells that co-produce liquids share a common and troublesome fate: liquid loading. A new artificial lift technology is being tested across different US shale plays with Equinor to avoid this inevitability. If successful, the system will become a viable alternative to the way in which these wells are produced today. Liquid loading crops up as the natural drive provided via early-stage gas production falls below the point required to move the associated water and/or natural gas liquids to the surface. The problem is progressive, and ultimately leads to a water column in the well.
As far as I am concerned, 2018 became the year I dealt with some aspect of enhanced oil recovery (EOR) every week. I had noticed that, in recent years, interest in bringing EOR to field operations had been growing everywhere. As operators and asset owners worked continually to increase efficiency in oil production, they all realized that part of efficiency improvement is increasing recovery factors. Everybody now is extremely focused on recovering more from the reservoirs they have. Of course, limited exploration and maturing fields are some of the motives behind that new attitude.
Gas-injection huff'n' puff enhanced-oil-recovery (EOR) techniques have the potential to improve liquid hydrocarbon recovery in ultratight, unconventional reservoirs. This paper studies the technical and economic viability of this EOR technique in Eagle Ford shale reservoirs using natural gas injection, generally after some period of primary depletion, typically through long, hydraulically fractured horizontal-reach wells. A compositional, fine-scale, dual-porosity, dual-permeability, symmetry-element numerical model was used in this study to model the current primary depletion and the EOR huff'n' puff process. In this study, the element of symmetry, which represents the bottom half of a cluster within a fracturing stage, is being extended to include three wells to allow the investigation of the effect of interference and containment on pad-level cyclic-gas-injection deployment. Production and injection of the entire well come from all active stages in each well, with equal weighting.