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Parent-Child, Multilateral Well and Fracture Flow Interactions

Our industry is confronting headwinds driven by uncertainty, confusion and fear, and quite likely, will be prone to act before all the facts are in. Drillers and field engineers believe that they have uncovered new physical phenomena. Rapid production declines, unlike those in past decades, certainly point to new possibilities in petrophysics - governances of Nature that we have little time to explore and tackle. The evidence is there. Just look around. The town folk are amassing. The consequences are disastrous. But big data, machine learning and artificial intelligence just might mine deeper insight. Problem solved. And the lone cowboy rides off into the sunset.

Additional questions raised. But the evidence is circumstantial. What is real are advances in hydraulic fracturing that have supported resurgences in oilfield activity. High permeability conduits created in the formation have accelerated the production of oil just about everywhere. Reserve estimates were predicted to escalate. But these increases would suddenly drop, much to the consternation of producers and bankers, destroying cash flow forecasts and independents' ability to continue loan payments. However, all of this would not be unexpected.

Unless an underground reservoir is continuously replenished by pressure drives charged by additional pools of oil (and these do, by the way, exist - e.g., see Mahfoud and Beck (1995)), any production must result from "sealed reservoirs" with initially high pressure. Thus, the amount of recoverable oil or gas is limited. Much of the reservoir is occupied by matrix rock and immovable fluids. The volume that remains is finite. Fractures remove movable fluids rapidly and leave the reservoir high and dry quickly. And so, fast declines will remain a fact of life.

In 2014, the senior author attended a meeting at a large oil service company where one of its clients was asked, "How do you determine fracture density?" This individual, a well respected industry spokesman, reluctantly admitted, "If your neighbor does 'N' number of fracs, you do '2N.'" So there was little after-thought in making operational decisions. There was neither time nor leeway to analyze. If your choice increased production, if only for a short duration, that was fine. And that's human nature, until the unavoidable reality sets in.

Problem identified. In recent years, there has been a proliferation of papers addressing the issues cited above. We will not offer any comprehensive summaries or reviews. Readers are encouraged to search for relevant case studies using keywords identified below. To highlight present industry confusion, several publications are discussed, with our comments, if only to illustrate the degree of confusion.

An interesting analysis appears in "To Solve Frac Hits, Unconventional Engineering Must Revolve Around Them," T. Jacobs, Journal of Petroleum Technology, April 2019, pp. 27 - 31. Noting that "the U.S. shale sector is expected to drill about 20,000 horizontal wells in 2019," the author observes that, "The impetus for an engineering overhaul is being forced by the prevalent well-to-well fracture interactions known as frac hits. These events are the subject of intensifying study by U.S. and Canadian shale producers that have attributed them to lowering oil recovery factors from new child wells by 20 - 40% while inflicting even higher losses on older, yet less productive, parent wells."

And a scientific overhaul is seriously needed. The senior author, an experienced reservoir engineer with major operating and oil service company experience, has never seen a comprehensive reservoir engineering assessment addressing production issues. For instance, "What well constraints were applied to parent wells, before and after, and in child wells after development? Details about drive mechanisms, well layouts, intervention activities, initial reservoir pressures?" What of supporting numerical simulations? Most computer models are difficult to use, require highly trained personnel, and unfortunately, are limited in the complexity of the physical features that can be easily described.

And catch-all terms like "frac hits" are coming under increased scrutiny. "We know they are entrenched, but honestly, they don't mean much," said George King, an industry expert, making a point that well interactions in question are not all the same. "Some are harmful, some are helpful, some are temporary, some are long-term." The paper also lists multiple strategies, e.g., "wider well spacing," "staggered wells (wine rack configuration)," "cube development," "rolling development," and "slowback," all of which should be studied using physics-based models evaluated under a wide combination of input parameters.

Another useful discussion is offered in "The Problem with Bigger Fracs in Tighter Spaces," S. Rassenfoss, Journal of Petroleum Technology, December 2017, pp. 28 - 31. The author identifies issues that should be addressed. "How does fracturing affect the reservoir between tightly spaced wells?" "How do we explain sudden drops in production?" "Could an existing well have produced the reserves without the infill well?" "How are surges of fluids flowing well-to-well through connected fracture systems described?" The paper also offers two self-explanatory visuals, reproduced in Figures 1.1 and 1.2. The last paragraph in Figure 1.2 is enlightening and supports the authors' contentions above, namely, that existing models are difficult to use, requiring inputs that are either difficult to obtain or simply non-existent. The present book hopes to convey two ideas - (1) the main influencers are available, and (2) simple, but rigorous, analyses are possible that address most physical effects, requiring minimal effort or specialized training, assuming the level of an undergraduate petroleum engineer.

The article "In the Battle Against Frac Hits, Shale Producers Go to New Extremes," T. Jacobs, Journal of Petroleum Technology, August 2018, pp. 35 - 38, interestingly describes one of the "new extremes" utilized in drilling practice. According to the author, "Most in the shale business know these projects as 'cube developments.' Their scope of work has moved operators away from developing wells one at a time to a half dozen or more at a time. Each cube project is done from supersized well pads that host four to six rigs, two pressure pumping fleets, and hundreds of people every day."

But just a year later, in "A Fracking Experiment Fails to Pump as Predicted," Wall Street Journal reporter Bradley Olson, on July 4, 2019, described how one company's supersized operation, one that two years earlier was thought to represent the future of the U.S. drilling boom, would lose its attractiveness. To reduce costs and avoid production problems when wells are spaced closely together, the company pioneered its "Cube Model" for reservoir development using numerous multilateral wells. Initial results were promising. However, subsequent results differed from those expected.

A more tractable idealization of this problem is presented later in Chapter 6 in which the development plan in Figure 1.3 is replaced by a nine multilateral well system with three wells residing in three separate rows. A full-field analysis is presented, requiring all but several minutes of simulation time on a Windows i5 computer - but just as important, a simpler, much less expensive drilling configuration using only two deviated wells, was identified offering the same production. Cube models do reduce drilling expenses through obvious economies of scale, but ultimately, the reservoir only contains as much oil as the volume holds. In this sense, careful cash flow management is still a must.

In the cautionary article "Factory Drilling is No Substitute for Formation Evaluation," E. Sprunt, World Oil, July 2014 warned, as early as five years ago, of the dangers behind methods that may not be grounded in physical principles. Ms. Sprunt, who holds a Doctorate from the Massachusetts Institute of Technology, is the president-elect of the American Geosciences Institute, and was the President of the Society of Petroleum Engineers (SPE) in 2006. In that article, she emphasizes that, "In a push to reduce costs in unconventional shale play reservoirs, some in the industry are racing to systematize development processes, even before understanding many of the aspects that play a role in shale production. This "manufacturing approach" is not a substitute for a comprehensive understanding of a formation."

The present authors agree - and, further, that "understanding of a formation" means reservoir modeling as much as it does petrophysical analysis. As emphasized earlier, a rigorous, easy-to-use Darcy flow simulator that allows rapid, convenient and rigorous model for problems containing heterogeneities, general drive models, arbitrary systems of vertical, horizontal and multilateral wells, liquids and gases, is not readily available in the industry, until now. This book, through detailed discussions in Chapters 4 - 9, will credibly fill this void.

A recent trade journal article "Physics-based or...