Uncertainties in Reserve Estimates

Estimates of oil and gas reserves are inherently uncertain. The extent and nature of commercially recoverable hydrocarbons from the subsurface cannot be determined with a high degree of precision. Recovery from subsurface reservoirs depends largely on the heterogeneities of the reservoir rock and the type of reservoir drive mechanism. Neither of these factors can be determined with a reasonable degree of certainty until after an accumulation has been developed and placed on production. Desorcy (1979) has discussed the source and probable magnitude of many of the errors associated with estimates of oil and gas reserves.

In addition to these physical uncertainties, there are commercial uncertainties. In the long run, oil and gas recovery is controlled by

· the costs to acquire exploration and development rights

· the costs to produce, treat, and transport oil and gas to market

· the market value of the volumes sold

Typically, these costs are incurred over a period of many years, with significant expenditures frequently being required a year or more before any income is realized.

The commercial environment — and the associated uncertainties-in which oil and gas reserves must be estimated is no less important than the physical environment. In today’s oil and gas industry the commercial environment may be subject to more uncertainty than the physical environment.

The range of uncertainty in estimates of reserves depends mainly on

· the degree of geologic complexity

· the maturity of the property

· the quality and quantity of geologic and engineering data

· the operating environment.

Geologic Complexity

The degree of geologic complexity in a group of properties may vary widely. At one extreme, the properties may be in an area of low structural relief, little or no faulting, no unconformities, and oil and gas reservoirs in the same general type of depositional unit (e.g., the lower Tuscaloosa (Cretaceous) trend in the southeastern USA). At the other extreme, the properties may be in an area of considerable structural relief, extensive faulting, numerous unconformities, and multiple depositional units (e.g., the North Sea).

Maturity

We can describe the maturity of an oil and gas property in terms of three stages of development and production:

· Geologic delineation/reservoir characterization, including

· discovery of the oil and gas accumulation and the period required for delineating the major geologic features controlling the extent of the accumulation

· determining the characteristics of the reservoir rock-fluid systems.

· Reservoir optimization, including the period of additional development, sustained production, and reservoir surveillance required for

· determining reservoir drive mechanisms and probable recovery efficiencies

· establishing optimum well spacing and production policy

· implementing improved recovery projects, if needed, to increase commercial recovery of oil and gas.

· Settled production, including the period during which wells have responded to fluid injection (if any) and have developed performance/production trends that may be analyzed to estimate reserves.

Quality and Quantity of Data

The minimum data necessary to estimate reserves with a reasonable degree of confidence vary widely from one property to the next and depend, in part, on the geology and maturity of the property. For a property that is monitored from its discovery and produces by primary reservoir drive mechanisms, acquisition of most or all of the following data is recommended:

· sufficient seismic data to identify and delineate major geologic features and probable reservoir limits

· sufficient subsurface control (wells) to delineate major structural and stratigraphic features, fluid contacts, and reservoir limits

· drillstem, wireline, or cased-hole formation tests on all zones not placed on production

· full-diameter cores in key wells in all major reservoirs

· sufficient wireline logs to identify all zones potentially productive of oil or gas and to characterize the lithology, net thickness, porosity, saturation, hydrocarbon type, and probable productivity of each zone

· sufficient sidewall samples to supplement full-diameter cores and help resolve log interpretation problems

· initial potential tests as each well completion is placed on production

· bottomhole transient pressure test on each well zone placed on production, preferably during the initial test period

· samples of reservoir fluids from all major reservoirs to define hydrocarbon fluid composition, saturation pressure, and other physical properties, with sufficient samples to ensure representative data and determine possible spatial variations in fluid properties;

· special core analysis data (depending on the nature of the reservoir rock-fluid system and drive mechanism), including water/gas, water/oil, or gas/oil relative permeability, capillary pressure data, pore volume compressibility versus net overburden pressure, etc.

· monthly production of oil, gas, and water, and production method for each well

· monthly potential tests on all wells

· sufficient historical bottomhole pressure data to determine reservoir drive mechanisms and to identify possible discontinuities between wells completed in the same reservoir

· historical data on all downhole remedial work, including stimulation, and same zone and new zone recompletions

· through-casing monitoring program (in multiple-zone fields) to detect possible drainage of behind-pipe zones, especially in water drive fields

· historical operating data, including revisions to downhole pumping and surface processing equipment that have affected the production rate of oil, gas, or water

· current sales prices and sufficient historical operating cost data to facilitate estimating average current and future costs

· costs to drill and complete wells, and to install treating and processing facilities

· operator’s plans (if any) to drill or work over wells or to modify, or augment, production equipment

· historical, current, or anticipated future restrictions on market conditions or processing or transportation facilities.

In reservoirs with improved recovery projects, this list should be expanded to include surveillance of monthly injected volumes and pressures from each injection well. Data requirements for improved recovery projects tend to be method and project specific. Talash (1988) has discussed data requirements for waterflood projects. The National Petroleum Council (1984) has published an extensive bibliography of papers on improved recovery methods which can provide insight into data requirements for such methods.

Operating Environment

The operating environment of an oil and gas property is one of the major factors controlling the costs of developing and operating the property. These costs, and the market price of the production, have a direct impact on the minimal size of a commercially exploitable accumulation and, thus, whether any portion of the accumulation may be classified as "reserves."

In the North Sea, for example, an accumulation containing 30 million barrels of oil in place was considered marginal (Home et al. 1988). It was a candidate for commercial exploitation only because it was near an existing production platform and could be produced from satellite facilities. In contrast, in West Texas — an area with an extensive infrastructure — accumulations less than one percent of that size are commercially exploitable.