The North American oil and gas industry has undergone a milestone transformation over the past 10 years as unconventional plays have demonstrated some phenomenal economic potential. Despite currently depressed oil prices, the good news for the industry and its investors is that the prospects seem bright for improved production volumes and reserve growth for at least several decades.

The evidence from the Bakken, Eagle Ford, Permian, Utica and other shale plays has given the former conventional wisdom of “peak oil” a rather nasty black eye. Although shale plays for many years were considered nonstarters with respect to their commercial viability, we now see the industry moving to “strategically” restructure business models to focus on shale—and all for the good, generally.

However, investors should keep one thing in mind: conventional wisdom often proves risky when betting too heavily on any one business model. We believe that, despite the ongoing industrywide shift to unconventional plays, conventional reservoirs will continue to offer important commercial opportunities.

They should not be overlooked in the race to create business models founded disproportionately on the shale plays.

Subsurface analysis is one key, if not the key, to establishing and sustaining a competitively viable upstream value chain. Anything that can be done to mitigate errors during the evaluation of what is, admittedly, the often-bewildering, complex array of geologic, chemical, petrophysical, engineering and business variables is not only desirable but can differentiate success from failure for the upstream enterprise.

Yes, production volumes from conventional plays and reservoirs have declined, but there is still significant recoverable oil in many mature basins, such as the Permian Basin. Most of the carbonate conventional fields in the Permian, as well as in most other major conventional locations across North America, were identified in the 1920-1940 era. The venerable Permian has been declared dead or dying many times as production volumes have ebbed and flowed through the years.

Induced error’s effect

The strategic impact of induced error is best understood by reviewing the generally accepted wisdom of each era over more than 100 years of the life cycle of plays like the Permian. In the 1930s, the viable life expectancy of the Permian with respect to recoverable oil was estimated at 30 years. By the 1960s, the life expectancy remained the same. Yet, here we are with the Permian’s production volumes from unconventional and conventional rocks still giving us recovered oil more than 90 years beyond what the calculations forecasted.

Historically, Permian Basin carbonate reservoirs range in size from less than 1 million barrels of oil equivalent (MMboe) cumulative production volume to some with greater than 1 billion boe. The record shows that most of these reservoirs exhibit low ultimate recovery efficiencies of 30% or less, even under waterflood.

This suggests that the original oil in place (OOIP) for the fields was grossly miscalculated, the production mechanisms were misunderstood and therefore flawed, and field developments were frequently mismanaged, all of which negatively affected ultimate recovery. Today some individual horizontal wells in the Permian have estimated EURs of 1 MMboe.

Induced error happens in many ways and across a wide range of business, scientific and engineering practices (geology, geochemistry, petrophysics, mathematics, engineering). This can skew our judgments as to OOIP and the volumes of recoverable oil from reservoirs. We have simply been wrong too often in our approach to collecting data and using that data. We have made faulty assumptions on the values of factors in equations used to make sensitive calculations of porosity, volumes of minerals present in complex lithologies, and other critical petrophysical values.

The full range of potential sources of induced error is far too much to catalog here. To illustrate the issue, however, we’ll briefly mention a few of the more common examples.

For starters, the management team’s preconceptions of what is important and its assumptions regarding recoverable oil potential are fundamental to success. The development process is too often shaped and defined by budget constraints, rather than by insights drawn from effective subsurface analyses and judgment. Too often, the budget defines investment realities and dictates subsurface and value chain activity, sacrificing accuracy to meet the timeline or other constraints.

An example is when frantic efforts are made to select projects so that capital can be spent before the end of a year-end budget cycle.

Technical drivers

From a technical perspective, there is a family of common drivers of induced error.

The first pertains to data. In the Permian Basin and elsewhere, acreage positions have been bought and sold so many times among a host of operators that have come and gone that data has been lost, corrupted, misunderstood or even ignored by subsurface teams. This has created a continuum of costly trial and error experiences that have clouded the interpretation process across the Permian domain. Acquiring core data is expensive. And core data collected in the mid-20th century was often faulty because of the technology and process used in that era, making some data suspect if not completely unusable.

A particularly egregious technical issue is the practice of using assumed values (“plug numbers”) when calculating rock porosity, mineral volumes present in the lithologies of the Permian’s many reservoirs, and a host of other complex equations. The net result? Significant errors in the solutions of these calculations. This issue is exacerbated by the massive workforce turnover today as more inexperienced personnel struggle with the complex equations and scientific knowledge needed to develop accurate evaluations. To be fair, however, even long-term industry professionals often fall back on the use of plug numbers for very sensitive values in equations. This can produce wildly misleading and incorrect solutions.

The human factor

Another commonly observed class of error results from a family of human interactions among subsurface functions: geology, reservoir engineering, geophysics, petrophysics, geochemistry, logging service providers and other technical specialties. This is characterized by errors attributable to nomenclature confusion, process effectiveness-discipline, internal company politics, physical location of talent, staffing levels, organizational priorities, culture(s), and interpersonal dynamics among the subsurface team, to name but a few of the most common factors.

In our more than 30 years of experience with upstream organizations, these factors are often the most challenging of root-cause issues to resolve. And, here we speak only of the scientific-engineering functional dimensions with respect to induced error—not the broader organization.

Compounding the problem, induced errors in reservoir engineering have been endemic in contributing to suboptimal recovery of oil in conventional reservoirs in the Permian as well as in many other conventional reservoir domains across North America and beyond.

Four factors—pay thickness, porosity, permeability and oil saturation—are fundamental to the evaluation of complex reservoirs. In basins like the Permian, OOIP calculations have been grossly misjudged for generations, thus clouding the estimated ultimate recovery (EUR) potential of the many reservoirs scattered across this vast areal domain.

Once the areal extent of a reservoir is defined, errors typically are caused by the inability to accurately determine each of the four factors defined above and to achieve accurate solutions at a reasonable cost.

The most common drivers of induced error that get subsurface teams in trouble are:

• Lack of data (none to insufficient);

• Inability (physical or economic) to access data;

• Inability to decipher data (insufficient knowledge, experience or financial resources) using the full range and suite of mathematics required;

• Management or financial bias (a belief in prevailing conventional wisdom—seeing the world through the lens of assumptions considered as “settled” knowledge);

• Rigid time constraints or deadlines for evaluation to meet business budgeting requirements.

The recovery factor

In practice, OOIP isn’t what drives capital investments in drilling programs. The promise of recoverable oil is what fuels the willingness to spend the vast sums of money required to get oil to the surface and then to market. To have confidence to place what can be franchise-limiting bets on specific drilling programs and projects, executives and investors need quality information supporting these strategic decisions.

Most smaller- to medium-size discoveries do not have sufficient delineating wells to properly define the reservoir boundaries or sufficient penetrations to understand the number of pay horizons, which has been a principal factor in the Permian Basin’s longevity.

Black oil gravity drainage is the most ineffective driving mechanism and has the lowest recovery factor (5% to 15%). Gas drive promotes recovery of 5% to 30%. Gas cap drive yields about 20% to 40% recovery and, finally, water drive improves recovery to 40% to 60%. However, fluid properties, lithology, formation damage, reservoir heterogeneity and many other factors can radically change realized recovery.

We all know that we must determine the porosity (Phi) of the producing formation correctly. In practice we see that the required values are not measured directly, mostly because of insufficient core data. Instead, they are calculated based on logs. By ignoring the mineralogy and in the process applying the dolomite matrix to the selected sonic, neutron and/or density tool to estimate porosity of the reservoir formation that actually contains 10% gypsum, we can induce error in the assessment of reservoir porosity by about 10%.

Oil saturation (So) in a producing carbonate formation is often misunderstood. In the absence of accurate direct fluid measurements, the industry commonly turns to Archie’s Equation to create an approximation of the oil saturation.

To use Archie’s Equation, we need to know the electrical properties of the formation, namely, the cementation exponent (M) and the saturation exponent (N). While the saturation exponent (N) is normally between 2 plus or minus 0.5, the cementation exponent (M) can range from a little over 1 to 5. Knowing Archie’s Equation is highly sensitive to this level of variability, we frequently observe general practitioners choosing m = 2 when the core analysis data are not available. This can result in an error of 50% or more. (If certain conditions exist, the cementation exponent [M] can sometimes be calculated with precision without core data).

The logs of many of the discovery wells in mature oil and gas fields were either lost or nonexistent due to the age of discovery, and older reserve calculations were too simplistic and sometimes based on partial and incomplete data.

As technology has advanced, we now know that porosity calculations often depend on the lithology and mineralogy of the formations, and water saturation calculations depend heavily on the physics and chemistry of the rock formations plus their interaction with the fluid.

Induced errors have profound consequences for the industry, individual operating companies and specific well programs and projects. Anything that can be done to mitigate those errors will enable better business performance.

Because success in the upstream industry depends so heavily on the performance of subsurface teams, it makes sense for investors and executives to ensure that every effort is made to mitigate errors that are otherwise avoidable, given proper functional capacity, skill and discipline of the organization charged with this critical value chain function.

In the case of many mature oilfields, such as those found in the Permian Basin, better subsurface performance may allow recovery of even more oil from conventional reservoirs.

James Miller is chairman and CEO of XCEL Partners, chairman and CEO of AOME Engineering, and director of XPST (proprietary subsurface analysis and interpretation), which provide strategic business and technical services to upstream companies worldwide. He may be contacted at jm@xcelpartners.com. This article is the second in a series on conventional reservoir management. The first appeared in the July issue.

Comments