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WorldOil


JULY 2014

Vol. 235 No.7

SHALE TECHNOLOGY REVIEW

Factory drilling is no substitute for formation evaluation

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.

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The oil industry is buzzing with talk of implementing “factory drilling” to reduce costs. Everyone agrees that for unconventional shale plays to be economically viable, production cost must be reduced. But will the “groupthink” approach to optimization lead operators to the winning path?

Reducing operating costs is important. However, formation quality is a major factor in profitability. Low-cost wells alone are not the solution. Drilling costs can be reduced, while simultaneously investing to understand the formations.

Yes, costs are too high for shale plays to continue to be economically attractive, but what are the big underlying questions? To optimize a process, operators need to understand the major variables. At this point, we may not have even identified all of the critical factors. We need to pause to think about what we know and what we don’t know. Unconventional plays are different, and we need to think outside the box in identifying important reservoir characterization questions and in devising ways to obtain answers.

Shale plays are not continuous. Let’s start with the misnomer of referring to shale plays as “continuous plays.” If they were really continuous (in contrast with conventional plays, in which traps and seals are essential), you would have an equally good chance of drilling a profitable well anywhere the shale formation is sufficiently thick and thermally mature. Drilling results do not support that hypothesis. Production data indicate that good wells differ from bad wells by more than just the differences in how the wells were stimulated and completed. Research has documented the economic importance of “sweet spots” in shale plays and explained that a key factor in profitable shale oil production is being able to identify these ahead of the drill bit, and preferably before leasing.1

Even in the face of solid evidence to the contrary, some erroneous geologic concepts can persist for decades. I’m old enough to have been taught in school that wind sculpted the deserts, and that it was mere coincidence that the continents appeared to fit together across the Atlantic. Throughout history, there are ample examples of experts overlooking the obvious, and convincing the public that they are correct.

Rare but significant events are important in earth sciences. Water is scarce in the desert, but sporadic floods are now known to be the major factor in shaping the desert landscape. Analogously, shales are not homogeneous, and infrequent events play an important role in shale properties. Although extremely fine sediments comprise the bulk of shale formation, the hundred-year (or longer interval) storm that transports larger particles can have a major impact on the permeability and porosity. Localized alteration, due to igneous events and faulting, can lead to variations in kerogen (organic matter) maturity and rock properties.2, 3 In turn, these differences lead to major variations in hydrocarbon properties and permeability. A key challenge is to identify ahead of the drill bit the areas with greater ability to produce hydrocarbons.

Identifying sweet spots. Seismic technology has been the workhorse of the industry for decades, but is it the most cost-effective way to identify the so-called sweet spots in shale plays? In exploration for conventional resources, in which precise determination of traps and seals is essential, seismic is the best tool, so geophysics groups are dominated by seismologists. Experts of all types naturally look at how their own expertise can be extended to address new problems. Seismologists are often convinced that with its better resolution, seismic studies are the best tools for reservoir characterization.

For many years, seismology has been, by an overwhelming margin, the chosen method for analyzing subsurface structure. Seismic surveys can provide information on numerous factors, including details of subsurface structure and rock properties. Given the resolution of information provided by seismic surveys, seismologists often see little reason to bother with other methods. However, seismic surveys are expensive and ground access is required, so restricted access may result in partial coverage. In common with many technologies, the interpretations of seismic data can be ambiguous.

Taking a macro approach. In shales, detailed knowledge of traps and seals is not required. Therefore, seismology may not be the most effective method of providing answers to questions that are critical to reducing costs. On the macro scale, better decisions might be made with less expensive screening data gathered over larger areas, when combined with insights obtained from detailed studies on samples from some key wells.

We have macro-scale techniques that may not be as precise as seismic, but have the potential to be much more cost-effective and have the added benefit of not requiring as many “boots on the ground.” These techniques can provide valuable information at lower cost than seismic surveys. Gravity and magnetics can identify deep tectonic structures that are associated with regional faulting. Satellite imagery, coupled with advanced computing, may be adequate in identifying the tectonic structures, regional faulting and fractures that serve as conduits for hydrothermal fluids. We need to be more open-minded in identifying both the key factors that make an area a sweet spot and the least expensive ways of characterizing those factors.

The unconventional plays are a reminder of many factors we don’t understand about kerogen (organic material) maturation and expulsion. We don’t really even understand how hydrocarbons escape from the low-permeability source rock to begin their migration to conventional reservoirs. When we recover shale samples, we can’t be sure which of the carefully photographed micro features existed in situ. The only fractures that we know for certain existed in place are those with evidence of natural cements. The timing and volume of gas generation during maturation of the kerogen could play an important role in migration. We need to think broadly about the important unknowns and have an open mind as to the most cost-effective ways to obtain solutions.

Unfortunately, it can be difficult to persuade old hands to try new tricks. When there is a focus on cost cutting, it becomes difficult to get the funding to test new or less frequently used characterization technologies, even if those technologies promise to be much more cost-effective. Staff experts want to preserve their research programs, not bring in new technologies from outside their field of expertise.

The tendency of experts to focus their search for solutions on their own discipline also contributes to emphasis on the “manufacturing process” and “factory drilling”. Drilling and production dominate the cost of a well, so management turns to those groups to save money. However, the biggest way to cut costs is to understand the factors that create sweet spots, and to avoid drilling in geologically less promising areas.

Cutting drilling costs by drastically curtailing collection of formation evaluation data in poorly understood formations is short-sighted. Immediate costs are reduced, but the lack of information about the producing formation leads to higher costs in the long run.

To improve the economics of shale plays, we must invest in characterizing and understanding what makes some areas sweet spots, and what is the most cost-effective technologies are for predicting their locations, before implementing low-cost “factory drilling.” We need to be open-minded and question the pre-conceived assumptions we have been working with for years. wo-box_blue.gif

REFERENCES

1. Berman, A., “Reflections on a decade of shale gas, examples from the Haynesville and Eagle Ford,” presentation to the Houston Geological Society, Sept. 30, 2013.

2. Edman, J., “How local variations in thermal maturity affect shale oil economics and producibility,” World Oil, Vol. 233, No. 3., pp. 47–53.

3. Newman, J., J. Edman, J. Howe and J. LeFever, “The Bakken at Parshall field: Inferences from new data regarding hydrocarbon generation and migration,” Unconventional Resources Technology Conference, No. 1578764, 2013.


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