All about Reserves Estimation
Moderator: moderators
• the maturity of a property,
• the general methods used to estimate reserves for the property
• the range of uncertainty in the reserve estimate.
Methods to estimate reserves are categorized here as:
• analogy/statistical (identified by Arps as the "barrels-per-acre period," or Period I);
• volumetric (identified by Arps as the "barrels-per-acre-foot period," or Period II); and
• performance (identified by Arps as the "decline-curve period" or Period III).
The performance method includes material balance analysis and performance/decline curve analysis.
• the general methods used to estimate reserves for the property
• the range of uncertainty in the reserve estimate.
Methods to estimate reserves are categorized here as:
• analogy/statistical (identified by Arps as the "barrels-per-acre period," or Period I);
• volumetric (identified by Arps as the "barrels-per-acre-foot period," or Period II); and
• performance (identified by Arps as the "decline-curve period" or Period III).
The performance method includes material balance analysis and performance/decline curve analysis.
Volumetric Methods
Volumetric methods are used when subsurface geologic data are sufficient for structural and isopachous mapping of the objective field or reservoir. One of the objectives of this mapping is to estimate oil and gas initially in place. The fraction of oil and gas initially in place that is commercially recoverable may be estimated using a combination of analogy and analytical methods. In a relatively uncomplicated geologic setting, it may be possible to make a reasonably accurate estimate of oil and gas initially in place with relatively sparse subsurface control. In contrast, in a complex geologic settin (e.g., one characterized by extensive faulting and/or complex stratigraphy) it may not be possible to make accurate maps until the field is almost completely developed.
Volumetric methods are used when subsurface geologic data are sufficient for structural and isopachous mapping of the objective field or reservoir. One of the objectives of this mapping is to estimate oil and gas initially in place. The fraction of oil and gas initially in place that is commercially recoverable may be estimated using a combination of analogy and analytical methods. In a relatively uncomplicated geologic setting, it may be possible to make a reasonably accurate estimate of oil and gas initially in place with relatively sparse subsurface control. In contrast, in a complex geologic settin (e.g., one characterized by extensive faulting and/or complex stratigraphy) it may not be possible to make accurate maps until the field is almost completely developed.
Performance Methods
Performance methods may be used after a field, reservoir, or well has been on sustained production long enough to develop a trend of pressure and/or production data that can be analyzed mathematically. The analysis may involve material balance calculations or it may involve curve fitting trends of oil and/or gas production, pressure, water/gas ratio (WGR), water/oil ratio (WOR), gas/oil ratio (GOR), or combinations of these performance indicators. The curve fitting procedure is based on the assumption that those factors that control the fitted trend will continue in the future.
Performance methods may be used after a field, reservoir, or well has been on sustained production long enough to develop a trend of pressure and/or production data that can be analyzed mathematically. The analysis may involve material balance calculations or it may involve curve fitting trends of oil and/or gas production, pressure, water/gas ratio (WGR), water/oil ratio (WOR), gas/oil ratio (GOR), or combinations of these performance indicators. The curve fitting procedure is based on the assumption that those factors that control the fitted trend will continue in the future.
Material Balance Methods
Material balance methods may be used to estimate reserves when there are sufficient reservoir pressure and production data to perform reliable calculations of hydrocarbons initially in place and to determine the probable reservoir drive mechanism. For reliable material balance calculations, the reservoir should have reached semisteady state conditions, i.e., pressure transients should have affected the entire initial hydrocarbon accumulation. Depending on reservoir fluid and rock properties and on the reservoir drive mechanism, this could require cumulative production of as much as 5 to 10% of the hydrocarbons initially in place.
Reliable application of this method requires accurate historical production data for all fluids (oil, gas, and water), accurate historical bottomhole pressure data, and pressure-volume-temperature (PVT) data representative of initial reservoir conditions. If computer simulation is being considered, historical bottomhole pressure data may be required for each well in the reservoir, depending on the degree of reservoir complexity and the purpose of the simulation study.
For volumetric gas reservoirs, a graphical form of the material balance equation may be used to estimate gas initially in place and reserves. For dissolved gas-drive oil reservoirs, the material balance equation may be used to estimate oil and gas initially in place and the probable drive mechanism. To estimate reserves, the material balance equation usually is combined with gas/oil relative permeability data in one of the prediction methods, either Tamer (1944) or Muskat (1945). In partial water drive reservoirs, it may be preferable to use a computer simulation model.
In high-permeability reservoirs, where reservoir pressure does not exhibit large areal variations, "zero-dimensional" or "tank" model material balance calculations usually are acceptable. In low-permeability reservoirs, where reservoir pressure may exhibit large areal variations, or in geologically complex reservoirs, it may be necessary to use a multidimensional reservoir simulation model.
Material balance methods may be used to estimate reserves when there are sufficient reservoir pressure and production data to perform reliable calculations of hydrocarbons initially in place and to determine the probable reservoir drive mechanism. For reliable material balance calculations, the reservoir should have reached semisteady state conditions, i.e., pressure transients should have affected the entire initial hydrocarbon accumulation. Depending on reservoir fluid and rock properties and on the reservoir drive mechanism, this could require cumulative production of as much as 5 to 10% of the hydrocarbons initially in place.
Reliable application of this method requires accurate historical production data for all fluids (oil, gas, and water), accurate historical bottomhole pressure data, and pressure-volume-temperature (PVT) data representative of initial reservoir conditions. If computer simulation is being considered, historical bottomhole pressure data may be required for each well in the reservoir, depending on the degree of reservoir complexity and the purpose of the simulation study.
For volumetric gas reservoirs, a graphical form of the material balance equation may be used to estimate gas initially in place and reserves. For dissolved gas-drive oil reservoirs, the material balance equation may be used to estimate oil and gas initially in place and the probable drive mechanism. To estimate reserves, the material balance equation usually is combined with gas/oil relative permeability data in one of the prediction methods, either Tamer (1944) or Muskat (1945). In partial water drive reservoirs, it may be preferable to use a computer simulation model.
In high-permeability reservoirs, where reservoir pressure does not exhibit large areal variations, "zero-dimensional" or "tank" model material balance calculations usually are acceptable. In low-permeability reservoirs, where reservoir pressure may exhibit large areal variations, or in geologically complex reservoirs, it may be necessary to use a multidimensional reservoir simulation model.
Combination Methods
Usually, more than one method is used to estimate reserves. Typically, in the early stages of development and production of a field or reservoir, reserves are estimated using a combination of analogy and volumetric methods. In some areas, it may be feasible to utilize seismic data to help determine reservoir or field size before there are sufficient well data to prepare reliable geologic maps. As development continues, and the early wells begin to develop pressure/production trends, reserves for those
Usually, more than one method is used to estimate reserves. Typically, in the early stages of development and production of a field or reservoir, reserves are estimated using a combination of analogy and volumetric methods. In some areas, it may be feasible to utilize seismic data to help determine reservoir or field size before there are sufficient well data to prepare reliable geologic maps. As development continues, and the early wells begin to develop pressure/production trends, reserves for those
Reconciliation Between Methods
Analogy and volumetric methods for estimating reserves are static methods and may yield results significantly different from performance methods, which are dynamic methods.
Field case histories have attested to many situations where well and reservoir performance differed significantly from that estimated prior to initiating production. See, for example, Buchanan and Hoogteyling (1979), Cronquist (1984), Hazeu et al. (1988), Markum et al. (1978), and Van Rijswijk et al. (1981).
In the North Sea Thistle Field, for example, Nadir and Hay (1978) reported that the first seven development wells encountered reservoir conditions in excellent agreement with conditions predicted by the operator
Analogy and volumetric methods for estimating reserves are static methods and may yield results significantly different from performance methods, which are dynamic methods.
Field case histories have attested to many situations where well and reservoir performance differed significantly from that estimated prior to initiating production. See, for example, Buchanan and Hoogteyling (1979), Cronquist (1984), Hazeu et al. (1988), Markum et al. (1978), and Van Rijswijk et al. (1981).
In the North Sea Thistle Field, for example, Nadir and Hay (1978) reported that the first seven development wells encountered reservoir conditions in excellent agreement with conditions predicted by the operator