Introduction to Oilfield Economics – Part I
Posted by D Nathan Meehan January 12, 2011

The oil and gas industry has invested billions of dollars in finding, discovering, developing, producing, transporting and refining hydrocarbons for more than a century and has long been an enormous source of wealth creation.  In countries such as the United States where a great deal of the ownership of subsurface mineral rights are privately owned, individuals and corporations have been able to generate significant wealth through the extraction of oil and gas.  In most countries such mineral ownership resides with the state. Historically, major international oil and gas companies (IOCs) played the major role in taking the risks of exploring for oil and gas around the world providing risk capital, development capital, expertise and personnel to many nations who were the owners of their resources. Such sovereign nations established national oil companies (NOCs) to both manage the relationships with IOCs and ultimately develop resources independently of the IOCs. The most technically advanced and financially capable of such NOCs can now and do compete technically and financially on the global stage. Over the last few decades, the “super majors” and recently even relatively small independent oil companies have found niche positions exploring for and developing oil and gas resources around the world. Many of the projects the largest independent oil companies pursue were once reserved for the major IOCs. The playing ground has been leveled by the widespread access to technology often provided by Universities, research organizations and service companies.  Service companies have also participated in developing and (less frequently) producing oil and gas fields around the world.

Reservoir engineering deals with all phases of the production of oil and gas. Most of this book deals with the physics associated with fluid flow in porous media, estimating future recoveries and enhancing both rates of recovery and ultimate recovery. Reservoir engineers must also fully comprehend the economics associated with oil and gas decisions. Lester C. Uren is credited with writing the earliest textbooks in petroleum engineering, and in the Preface of his book Petroleum Production Engineering he states:

“The engineer is both a technologist and an economist. In his professional work, his objectives require not only an application of science to the needs of industry but also achievement of these objectives within economic limits that will result in financial profit.”

In most cases, reservoir engineers serve as analysts who make recommendations individually or (more typically) as part of a team. The economic decisions they make must be comprehensible to decision makers, reflect value and risk correctly and properly compare alternatives. While many economists have excellent skills in this area it is the role of the integrated team to capture the best technical decisions and translate them into proper decisions.  Integrated asset teams comprise reservoir and production engineers, geologists, geophysicists and other specialists such as geomechanics and petrophysics experts.

In the next few posts, typical decisions that reservoir engineers routinely must evaluate are discussed. The way reservoir engineers evaluate cash flows, capital investments and decisions under uncertainty (risk) are described. Finally, a series of advanced topics including typical alternative schemes for shared risk and revenue are illustrated.

The following is the first in a series of examples  used to illustrate typical questions a reservoir engineer may be called on to answer. We will revisit some of these examples to understand the calculation of economic parameters and decision making criteria.

If there is interest expressed from the readers I will include basic and perhaps even advanced economic principles and examples. Let me know what you think.

Tight Gas Optimal Spacing Example
In a natural gas reservoir, even a tight gas reservoir the ultimate theoretical technical recovery (neglecting reservoir heterogeneities[i], liquid loading, etc.) may not be a strong function of spacing. Figure 1 shows the results of a series of reservoir simulation runs in a tight gas reservoir with an average permeability of 0.008 md and a thickness of 55 feet. The same hydraulic fracture lengths and the same absolute fracture conductivities are used in each case. These cases resulted in varying ratios of fracture length to drainage radius; however this primarily affected the transient behavior and length of time before boundary effects were felt. The reservoir spacing for the cases ranged from 40 acres per well to 640 acres per well meaning that in one square mile there could be as few as one well or as many as sixteen wells. In practice these wells would be drilled over time and the earliest wells would produce higher rates and ultimate recoveries than the later wells. In this simplified example, no maximum total production constraint is imposed on the entire field; i.e. it is assumed that there are no gathering system, facilities, compression or sales constraints.  It is also assumed that each of the wells is ideally spaced with respect to location. This can rarely be done in practice. This example oversimplifies the problem for illustration purposes but can be solved more accurately by incorporating timing, heterogeneities, varying hydraulic fracturing results, well location issues, etc.

Gas rates for each case are plotted as a function of time; each case represents the combined production from all wells in the drainage area. The initial rate of the 40-acre case is approximately sixteen times the initial rate of the 640-acre case because the early transient behavior of each well is essentially identical.  The length of time required for each well to reach an estimated minimum rate of 20 Mcf/D varies from less than 9 years in the 40-acre case to more than 100 years in the 640 acre case. The simulations were not allowed to run in excess of 100 years.  Ultimate recovery varies relatively little between these cases. The question the operator must ultimately answer is “How many wells should I drill?”

Figure 1: Comparison of rates as a function of time for different well spacings in homogeneous tight gas sand

Figure 2: Economic life, ultimate gas recovery and number of wells required as a function of well spacing

The reader may have an instinctive belief that recovering 11.8 Bcf in 41 years (from four wells on 160-acre spacing) is significantly better than recovering a similar quantity in 87 years (from two wells on 320-acre spacing); does the improved value of accelerating gas recovery warrant the costs of two additional wells?  It is more difficult to decide whether relatively modest acceleration such as the difference in the 40- and 80-acre or 80- and 160-acre cases are worth doubling or quadrupling the amount of cash required for capital investments.

It is up to the integrated efforts of the reservoir engineer and economist (and many reservoir engineers function as both) to identify the optimal capital investment for this project and to rank such an investment with respect to alternative capital investments.  The answer to this problem is a function of many factors including future product prices, limits on the surface constraints, regulatory constraints, the capital costs of the wells, operating expenses, completions including tubular and liquid handling issues, reservoir heterogeneities, etc. In practice, reservoir engineers and geologists often underestimate the level of complexity of reservoirs leading (in the case of most tight gas reservoirs) to an optimal well spacing that is tighter (higher well density) together than that indicated in a homogeneous reservoir model. Similarly, drilling additional wells in very similar geologic environments can lead to substantial efficiencies and optimization of drilling and completion practices.  Higher well densities provide redundancy that may be beneficial if one or more producing wells fail mechanically and the cost to restore the damaged wells to production cannot be justified. Repairing or replacing drills late in a reservoir’s life may also be technically more difficult as the low reservoir pressures present drilling and completion challenges. While these problems are commonplace, it is difficult to quantify which, if any will occur.

In the next few posts we will examine the economic parameters and approaches used to evaluate optimizing well spacing. What do you think is the most important consideration?


[i] This is in reality a terrible assumption. Most infill efforts work precisely due to the heterogeneities that exist in essentially all tight gas reservoirs.

4 responses | Add Yours

Responses

Keith Barnett says:

Are the legend descriptions reversed in Figure 1? The plum colored line seems to describe 1 – 640 acre well while the blue line would describe 16 – 40 acre wells and so on for the 2 and 8 well case.

D Nathan Meehan says:

Excellent catch. I had noticed it before and fixed it (but wound up uploading the old picture anyway). Thanks for the help… Of course this case is highly oversimplified —-I think it is an interesting assignment to do the following things.
First, do the optimization when there is a maximum rate constraint. Also, do the assignment when infill acticity occurs over time. This introduces a new problem in optimal well placement.

Rodolfo Galecio says:

Probably we will need an entire set of economic parameters to deal with this problem, but at the end all these measures are designed to evaluate the project as a lonely entity, its relationship with the company goals or even necessities could drive our decision making process!

D Nathan Meehan says:

Good observation. Once we have gone through the various tools used in analysis, then the understanding of portfolio management becomes an important measure. This is particularly true when companies’ opportunities and risky activities are dominated by projects whose risks are highly correlated. Somethimes (most times) the correlation of risk is underestimated.

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