Conventional U.S. reservoirs were once the gold standard for the oil and gas industry. But a commonly held notion today is that “the easy oil from conventional reservoirs has pretty much been found.”

Maybe it’s time to reconsider that assumption, however. After all, we’ve known for 100 years or more that shale rocks are oily. So why did it take us so long to get around to developing shale plays (unconventional oil and gas)?

Proponents of the “peak oil” theory, beginning with M. King Hubbard in 1956, include analysts, academics and journalists who have subsequently carried the torch for this influential prediction. Colin Campbell and Jean Laherrere, in their article “The End of Cheap Oil,” published in Scientific American in March 1998, echoed Hubbard’s theory. In 2005, the late industry guru Matt Simmons, in his book Twilight in the Desert, took Hubbard’s theory to new heights. He used the logic of the extremely sharp decline curves observed in most conventional plays to dispute what he described as overly optimistic reserve forecasts for Saudi Arabia and across the rest of the industry. His primary conclusion: We’re fast running out of oil.

But are we? A careful reading of the peak oil theorists reveals a fundamental error of omission. Unconventional oil was nearly always eliminated as a feasible solution to declining production, because the cost was simply accepted as an impenetrable commercial barrier, making this type of oil recovery a non-starter.

In fact, for many years oil demand grew much more rapidly than discoveries and production of oil from conventional reservoirs. And, lifting oil from conventional reservoirs had long since become more challenging as enhanced oil recovery (EOR) methods increasingly were required to get the oil to the surface, raising lifting costs and eroding margins across the industry.

Other long-held tenets also were difficult to relinquish. For decades, we were true believers that the only feasible well design was a vertical one, that the pursuit of more conventional reservoirs was our only practical growth alternative, that the only proper strategy was an ultra-aggressive pursuit of the competitive imperative to be the low-cost operator, that the use of advanced EOR methods was our chief innovation frontier, and that shale plays weren’t feasible. The claim by virtually every upstream operator that it aspired to be the “low-cost operator” was the standard mantra of the times.

All the while, unconventional oil was waiting to be discovered, lifted and moved to market. But we were trapped in a fixed belief system.

When major companies such as Exxon, Amoco, BP, Arco, Mobil, Shell and Texaco watched their costs continue to rise and their production fall more precipitously year after year, they felt safe in assuming that the party was over in the Permian, California, Oklahoma, the shallow Gulf and other locations where conventional oil had made them successful.

Peak oil’s legacy

In retrospect, the peak oil theory catalyzed some very unfortunate business decisions.

The impact of peak oil conventional wisdom in the painful demise of Sun Oil Co. is a classic example of what can happen when a theory becomes an all-encompassing popular strategy in the corporate boardroom. In a much-publicized press release that was widely celebrated at the time as visionary, Sun announced the pivotal decision to diversify its business beyond the heritage oil and gas industry. H. Robert Sharbaugh, the company’s CEO in the mid- to late 1970s, decided to break the company into 14 lines of business. He then proceeded to buy a trucking company, a hospital supply company, and even venture into an experimental prawn farm business, among other endeavors.

Later, Sun spun off its entire E&P unit to form Oryx, an independent. The CEO of Oryx, Robert P. Hauptfuhrer, authorized a massive stock buy-back transaction and concluded an expensive acquisition that burdened the company with what proved to be an insurmountable mountain of debt. Sadly, even with an experienced, talented and very motivated cadre of management and professional staff, including Jim McCormick (who became the CEO of Oryx, but too late to save the company), Oryx withered and died, primarily because of its leaders’ mistaken belief in peak oil. Most of Oryx’s assets were subsequently acquired by Kerr-McGee.

Some large upstream companies jettisoned their North American acreage positions and raced out to international plays or pursued costly forays into deepwater for which they were woefully ill-prepared. In the mid-1990s, for example, two well-known large integrateds committed to deepwater exploration but had to pull back when it became clear that their organizations were not ready for such a complex undertaking.

Dino Nicandros, the brilliant former CEO of Conoco, Rob McKee, the visionary Conoco executive vice president who led the renaissance of its upstream business, L. Paul Teague, the regional vice president for Texaco USA operations, and John Whitmire, the former executive vice president of Phillips and later the CEO of Union Pacific Oil and Gas were a few of the many exceptional upstream executives we admire. Each cautioned strongly against making strategic asset sales simply because other operators were fleeing North America.

Apache, Oxy, Pioneer, Concho and others have accumulated what are now seen as superb, franchise-making business positions in the Permian Basin by snapping up acreage formerly held by Texaco, Mobil, Amoco, Arco, Exxon, BP, Chesapeake and Shell, most of which sold out to pursue international “easy oil” in the form of large conventional reservoirs. Shareholders of each of these companies were assured that the Permian Basin was universally believed to be depleted.

Upon closing the purchase of BP’s Permian asset, G. Steven Farris, Apache’s then chairman and CEO, said, “This is a rare opportunity to acquire a legacy position from a major oil company, with oil and gas production, acreage, infrastructure, seismic data, field studies, exploration prospects and other essential aspects of our business.” He was certainly correct. Apache quickly translated this strategic acquisition and several others into a formidable business position in the Permian Basin.

On the other side of the transaction, BP group chief executive Tony Hayward said, “We have achieved an excellent price for a set of properties that are worth more to others than to BP. This is a good first step which underlines our ability and determination to get maximum value for everything we sell.” In fairness, BP needed to sell this position as a consequence of its Macondo event in the Gulf of Mexico.

Recently, however, ExxonMobil, Shell and other large companies have had to buy their way back into many of the plays that they had abandoned.

The good news is that the rebirth of the Permian Basin is now beyond dispute. Abundant oil and gas was always there; we simply didn’t know how to find it and get it to market. The Permian is emblematic of other U.S. onshore and North American plays and what we believe can be done in a number of mature conventional plays across the U.S., Canada and Mexico.

Scott Sheffield, CEO of Pioneer Resources, has said repeatedly at Hart Energy’s DUG events and in analyst presentations that “the Permian Basin’s oil production could be as high as 3.5 million barrels a day within 10 years. People will be going after these zones for the next 100 years. The Permian will end up being the largest field in the U.S. and one of the top 10 largest in the world.”

Similar enthusiastic projections are routinely advanced in analyst meetings pertaining to the Eagle Ford, Bakken and some of the other emerging shale plays.

A key finding from our experiences with the upstream industry over the past 30 years is that there is often more hidden value in companies’ acreage positions than prevailing wisdom would lead us to believe.

Conventional reservoirs have been the backbone of the industry and will always be important. We don’t want to see the industry race from one extreme mindset to another. Our assertion is that there may well be significantly more incremental realizable value in reexamining each of these conventional reservoirs.

This hypothesis, however, will be viable only if we can define and then execute better approaches to analyzing conventional reservoirs. Otherwise, we are likely to continue to see the predictable decline of mature conventional plays. If we rethink and redesign some of our long-standing practices and utilize advancements in science, mathematics and collaborative processes, we may be able to extend the commercial value of existing conventional reservoirs and, perhaps, find a few reservoirs that have been overlooked during a century of exploration and development.

A complex array of related technical and business issues makes subsurface analysis challenging.

Extracting value

If we are to create incremental value from conventional reservoirs, we must work together in a thoughtful, collaborative process similar to what has occurred over the past decade in the shale plays. What would such a process look like?

We present here a handful of the more chronic challenges encountered in our nearly four decades of experience with the industry’s general approach to subsurface analysis and the risking of conventional reservoirs. Error introduced from multiple sources of subsurface analysis activity ultimately plays out in the form of missed business opportunities, wasted capital and lower-than-expected production and reserve additions.

If we want more reserves and production from our conventional reservoirs, we need to ratchet up our performance in each of 10 broad areas:

• Improve the accuracy of interpretation with respect to the variety and volume of minerals present in the targeted complex lithologies of conventional reservoirs, to better understand complex attributes such as porosity, permeability and pore distribution.

• Improve tool selection and onsite application of tools for better data integrity and analysis.

• Address problems that chronically bedevil the technical disciplines required to analyze complex lithologies in the struggle to fully integrate the disparate, but critical, insights developed by each into a complete and accurate assessment of hydrocarbon potential. The root causes for these many complex problems pertain to organizational culture, lack of technical training/skills, lack of effective collaborative techniques and inadequate analysis of historical data.

• Move beyond the “tight-hole” mindset and practices that tend to keep subsurface teams in inner-focused “mini-cultures” within the broader organizations of most companies. This mindset often creates serious issues for capital-intensive functions such as drilling, completions, facilities and land groups, resulting in disconnects, errors of omission and, eventually, lower IPs, higher costs and lost revenues.

• Provide flexibility in the budget process. Most E&Ps are driven by a semi-rigid budget planning schedule that may not be fully compatible with the realities of subsurface analysis and processes of subsurface teams. The budget process shouldn’t drive premature or incomplete assessments of subsurface potential just to conform to a fixed schedule. Doing so can result in significant errors when projects rushed to execution are approved with insufficient subsurface analysis and interpretation.

• Plan for the capacity-capability vacuum. The large numbers of professionals exiting the industry, coupled with the equally large number of new hires in geology, geophysics, geochemistry, reservoir engineering, subsurface instrumentation and petrophysics, has created a capacity-capability vacuum. This vacuum can significantly alter the performance of subsurface functions in the upstream industry.

• Ongoing M&A activity in both the operator and the service-provider components of the industry, as well as the decade-long expansion of drilling activity in the shale plays, have resulted in serious inconsistencies in the quantity and quality of talent that can be applied to subsurface projects in both conventional and unconventional plays. Loss of corporate memory with respect to knowledge of specific conventional plays and reservoirs has become more prevalent. Moreover, recent oil price declines have resulted in staff downsizings, compounding the issue of finding talent capable of providing the quality of support needed for subsurface analysis.

• Address the need for integrated technical training in major universities. Universities tend to train students in technical disciplines using clearly defined and structured scientific engineering courses designed to teach core concepts, functional methods and science that pertain to specific disciplines. Students then come to the industry with a good grounding in the basics of one discrete discipline, but they often lack even an elementary understanding of other essential subsurface prerequisite functions. Most have little or no training in business management skills.

In practice, each of these functional disciplines represents essential, but otherwise incomplete, pieces of the requisite subsurface analysis solutions process, experience in pattern recognition, and integrated solutions needed to support effective business decisions. Apart from the behavioral-cultural-political dynamics implied in this cultural issue, the de facto blending of these various technology disciplines often results in confusion over terminology, data interpretation, calculations and conclusions. The induced error rate in the final recommendations to management can be significant.

• Make room in the capex budget for investment in a more robust form of subsurface analysis in and around mature, proven reservoirs as well as in higher-risk expoitation/exploration acreage—especially in the large acreage holdings of some of the larger players. Some upstream companies now view their conventional reservoirs as harvest assets with increasingly marginal long-term strategic value. While this may, in fact, be a prudent way to manage the conventional reservoir, it may also be a major error of omission when we fail to fully consider other options for these assets.

• Investigate the application of horizontal well technologies in conventional reservoirs. The industry’s prevailing approach to conventional well design remains vertically oriented. Pioneer Resources has given us a model in its work in the Midland Basin, where wells have been drilled in both vertical and horizontal configurations in its Wolfberry drilling and completion projects. Can the horizontal well design be applied effectively in traditional conventional exploitation and development wells?

Proving the methods for addressing each of these factors clearly requires a more in-depth demonstration of alternative approaches. This article merely provides a framework for overhauling a long-standing process for subsurface analysis functions that we hope will facilitate further discussion around the potential inherent in conventional reservoirs.

Our wish is that additional innovations in the form of better applied technologies, better subsurface analysis and credible proof-of-concepts will begin to nibble away at the fringes of our conventional reservoir wisdom so that greater value is realized for all. It’s time to refocus our business strategies to more thoughtfully address the potential of conventional reservoirs not as an “either-or” proposition, but rather as a “both-and” process relative to building and maintaining reserves and production volumes.

For now, informed investors should take note of acreage positions in the known major basins such as the Permian. Large acreage holders may be sitting squarely on another value component that will affect the investment strategies of capital providers, operators, service providers, shareholders and other stakeholders.

James Miller is chairman and CEO of XCEL Partners, chairman and CEO of AOME Engineering, and director of XPST (proprietary subsurface analysis and interpretation). These firms provide strategic business and technical services to upstream companies worldwide. He may be contacted at jm@xcelpartners.com.

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