Shale optimization improves

D. NATHAN MEEHAN, Senior Executive Advisor, Baker Hughes

Living in Asia the last year-and-a-half has been a particularly edifying experience for my wife and me. I began writing this article in Hyderabad, India, and am finishing it in Ulaanbaatar, Mongolia. I have been fortunate to have traveled much of the world in my life, but living in Hong Kong and working on the projects that I have been able to support has been a life-changing opportunity. I am reminded of the Chinese saying, “there are no rivers to one who has crossed the ocean, and no clouds to one who has passed Mount Wu.” This generally means that one who has seen the world isn’t stopped by small challenges. The oil and gas services sector of the energy industry has crossed every ocean and passed high peaks over the years, and continues to evolve technological solutions to the most complex challenges facing the sector.

The extraordinary impact of unconventional resources on what we do as an industry has quickly moved from a few areas in North America to nearly every country with hydrocarbon resources. I once described my area of specialization as “long, high-permeability pathways in low-permeability rocks” to include both horizontal wells and hydraulic fracturing. These two technologies have merged to result in a sea change in activity. Massive shale projects with complex wells and scores of hydraulic fracturing treatments marry pressure pumping techniques that were born in the 1950s with nanotechnology structured metallic composite frac balls that allow operators to safely implement multiple treatments and then effectively disappear.

Understanding shale reservoirs. One substantial problem with the challenge of optimizing the exploitation of shale reservoirs doesn’t hinge exclusively on the hardware and operational expertise associated with the costly developments. It hinges on understanding the complexities and heterogeneities of the reservoirs, themselves. We know how to drill and complete a given well; however, the variability in performance from one well to the next can be so large, that some believe it is impossible to predict offset well performance, except on a statistical basis. Part of this variability is due to greater complexity in the mechanisms of hydrocarbon production. Variability in conventional well performance is often reasonably correlated to measurable quantities (permeability, porosity, thickness, etc.), as well as spatial heterogeneities in these parameters.

The controlling parameters for shale reservoirs are at once less clear and more difficult to measure. Complicating this problem is the “factory approach” to well drilling, in which advanced petrophysical measurements are often sacrificed to lower the costs of high numbers of similarly designed wells. In principal, the spacing of wells, and size and spacing of fracture treatments, could be optimized if the results could be quantitatively forecast on a consistent basis. This would require technological advances, both in the reservoir measurements made (over various scales) and in how to interpret these to predict reservoir performance. If we cannot make reasonable predictions from measured reservoir parameters that explain how individual wells will perform, how can we argue in favor of 25 fracture treatments versus 35? Wellbore lengths of 5,000 ft or 8,000 ft? Where to geosteer? What size and type of treatments to perform? How much can we measure, and how much must remain empirical?

We have only recently proved consistently that improved measurements can, and have, accelerated our learning curve in identifying the quality of shale reservoirs and identifying parameters (or at least acceptable proxies) to improve the selection of drill site locations. Increasingly, client experience shows that actually making the measurements on individual wells, and integrating the reservoir engineering and geoscience skills required to understand these data, provides insights well beyond high-level statistical views of the performance of a group of wells. Unfortunately the massive number of wells drilled in a “typical” shale development means that even the largest operators would be hard-pressed to analyze all of the wells in as much detail as required to fully understand the reservoir. Cost optimization in the factory approach (by deleting measurements) may well have longer-term cost and recovery impacts that will be difficult to quantify.

Improving failure rates. Operators globally have identified shale resources that, at first glance, hold the technical potential (based on TOC, thickness, brittleness, fractures, thermal maturity, etc.) to produce significant hydrocarbons. A careful examination of most shale developments, to date, shows that a significant number of wells are commercial, if not technical failures. In most plays, this failure rate is higher than what would be acceptable by international standards. In areas with higher well costs than the U.S. counterparts, the relative value of additional reservoir measurements and analysis will be easier to justify.

I am very optimistic about the improvements in predicting individual well and field performance. At first, shale reservoirs seem so dramatically different from conventional reservoirs that existing reservoir description and analysis methods appear almost hopeless. But as the geomechanics, petrophysics, geophysics, geology, completions and reservoir engineers continue to work on shale reservoirs, their variability (whether from field-to-field or well-to-well) becomes easier to explain. It wasn’t that long ago that the basic tools for quantifying reservoir heterogeneity were first used on a widespread basis. Remember, there are no clouds to one who has passed Mount Wu.