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Net pay determination

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The goal of the net-pay calculations is to eliminate nonproductive rock intervals and, from these calculations at the various wellbores, provide a solid basis for a quality 3D reservoir description and quantitative hydrocarbons-in-place and flow calculations.

Calculating net-pay

The determination of net pay is a required input to calculate the hydrocarbon pore feet, FHCP, at a wellbore and its input to the overall reservoir original oil in place (OOIP) or original gas in place (OGIP) calculations. The total FHCP at a well is the point-by-point summation over the reservoir interval with Eq. 1. The top and base of the reservoir interval are defined by geologists on the basis of core descriptions and log characteristics.

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In the FHCP calculation, net pay, hni, at each data point has a value of either 1 (pay) or 0 (nonpay). The "net-to-gross ratio" or "net/gross" (N/G) is the total amount of pay footage divided by the total thickness of the reservoir interval (for simplicity, the well is assumed here to be vertical). A N/G of 1.0 means that the whole of the reservoir interval is pay footage. In this formula, any foot (or half foot) that is defined as nonpay contributes absolutely nothing to the subsequent reservoir-engineering OOIP (or OGIP) and reserves calculations, even if it contains some amount of hydrocarbons. The net-pay determination should be performed in a reasonable practical manner, but it should be recognized that when any cutoff is used, the result will, to some extent, be arbitrary.

Conceptual bases for net-pay calculations

Several conceptual bases for the petrophysical calculations of net pay are described here. At one limit, the whole of the reservoir interval can be treated as net pay (i.e., N/G equals 1.0). Another reasonable engineering approach is to define some lower limit on flow, below which each foot or half foot of the reservoir interval is deemed to be nonpay. A third approach is to use one or more log cutoffs that have been used historically within the petroleum industry. The advantages and disadvantages of these various approaches will be discussed in this section.

Full interval as net pay

One approach is to calculate the OOIP or OGIP assuming that all the reservoir interval is pay to determine the total volume of hydrocarbons present within the reservoir interval. When using an N/G = 1 approach, the technical team needs to ensure that the calculations of porosity, permeability, and Sw are quantitatively reasonable over the whole range of values for each of these parameters. This calculation could be called a determination of the "total hydrocarbon resource" within the reservoir interval, and it provides a value for the total hydrocarbon potential of the reservoir. Some of these hydrocarbons will have low mobilities and will contribute little or nothing to hydrocarbon recovery. But, with this value available, the engineer has a measure of how well the reservoir is producing overall and what resources should be considered for improved-recovery-project evaluations. This value can be viewed as the ultimate "prize."

Another reason for setting N/G to 1.0 is that, with modern reservoir-engineering tools, it is technically feasible to treat the entire reservoir interval as pay. For example, with modern reservoir-engineering tools, a million (or more) cell reservoir-simulation model can be constructed in which a very detailed description of the vertical and horizontal variations in the reservoir-rock properties are incorporated. In this approach, the very-poor-quality portions of the reservoir are assigned low porosities, low permeabilities, and higher water-saturation values. Then, in the OOIP or OGIP calculations, these portions contain only small volumes of hydrocarbons and will contribute their appropriate, albeit small, share to pressure maintenance and recoverable hydrocarbons. This is in contrast to defining these poor-quality intervals as nonpay and defining a priori that they contribute nothing to OOIP or OGIP or reserves.

Mobility or permeability cutoff approach

From first-principle calculations using Darcy’s law, a reservoir engineer can define net pay by applying a fluid-flow cutoff. The choice of this cutoff would be related directly to the hydrocarbon mobility (rock permeability divided by hydrocarbon viscosity) in the different portions of the reservoir interval. With this approach, the net-pay permeability cutoff used in the point-by-point log calculations would be quite different between that for a gas reservoir (very low gas viscosity of approximately 0.02 cp), that for a light-oil reservoir (oil viscosity of 1 to 10 cp), and that for a heavy oil reservoir (oil viscosity of 10,000 cp or more). [1] Any portion of the reservoir interval that has a permeability at reservoir conditions below the cutoff would be defined to be nonpay. In the next section, the gas-reservoir situation is discussed separately from that for oil reservoirs.

The arbitrary nature of any net-pay cutoff is apparent when one notes the flow implications of using a permeability cutoff. If a rock interval has a permeability 1% greater than the cutoff value, it is included as net pay. However, if another rock interval has a permeability 1% less than the cutoff value, it is excluded as nonpay. The difference between the fluid-flow contributions from these two rock intervals is only 2%, yet one is allowed to contribute to the subsequent OOIP or OGIP and reserves calculations, while the other is not.

If a permeability cutoff is chosen, its application to the various wellbore data (cores and logs) generally takes three steps. [2] The first step is to apply the permeability cutoff to the routine-core-analysis permeability data. In this step, there are two checks that need to be made. First, a permeability/porosity plot needs to be prepared and outlier points identified. The outlier points need to be individually checked for validity. For example, a very-low-porosity shale sample may have dried out and a parting developed between the shale layers. This may lead to a very high permeability value that is not consistent with the rest of the rock characteristics. Bad routine-core-analysis data points should be excluded from the database. A second consideration is that often during the routine core analysis, the shale intervals are not sampled at the same frequency of core plugs as the other lithologies. This likelihood must be kept in mind in reviewing the routine-core-analysis database and in comparing the results of pay/nonpay calculations between cores and logs. The subsequent steps—the conversion of a permeability cutoff to a porosity or Vsh cutoff including the calibration of logs to the core standard, and the calculations from the logs of net pay for all wells over the reservoir interval—are discussed later on this page.

Gas reservoirs

For a gas reservoir being produced under pressure-depletion drive, any permeability cutoff applied should be very low. This is quite evident by the successful development of tight gas-sandstone reservoirs producing nearly 10 Bcf/D from 85,000 wells in the US, some with average permeabilities in the microdarcy range (see tight gas sands). In conventional gas reservoirs in which higher-quality rock intervals are interbedded with the poorer-quality ones, gas in the poorer-quality rocks will flow to the higher-quality rock intervals if there is any permeability between the two. An example calculation for gas flow from a 1-microdarcy layer with a pressure difference of 2,000 psi, over a thickness of 10 ft for an area of 10 acres, and for a period of 1 year shows that this layer would contribute 1 Bcf per year.

Because pressure-depletion-drive gas reservoirs are produced for decades and, if found at significant depths, have abandonment pressures less than 10% of their initial pressures, there are both long times and large pressure differentials to cause gas to flow from very-low-permeability and low-porosity rock intervals into higher-permeability conduits and on to the production wellbores. In many instances, the distance traveled to reach a higher-permeability layer is just a few feet vertically.

Oil reservoirs

For oil reservoirs, any permeability cutoff will be significantly higher than that for a gas reservoir, generally by a factor of 10 or 100 or more. A second aspect of oil reservoirs is that typically, only 10 to 20% of the OOIP will be produced by pressure-depletion drive (without assistance from gravity drainage) in which the pressure differential will affect all portions of the reservoir. However, during waterflooding, overall oil/water displacement efficiency will depend, in part, on how much of this displacement process occurs in poorer-quality oil-bearing rock intervals. Hence, the choice of oil-reservoir permeability cutoff needs to account for the oil/water relative permeability effects. Interwell injector/producer connectivity (or "floodability") is not a topic of this chapter. Connectivity will affect recovery but is considered a separate issue apart from individual-wellbore calculations of net pay.

Any permeability cutoff cannot be directly applied to foot-by-foot log calculations of net pay because there is no log that quantitatively measures permeability. A permeability cutoff typically is converted to a porosity cutoff and is subsequently applied to the logs through:

  • Log porosity
  • Bulk density
  • GR
  • Vsh cutoffs

The procedures for applying a permeability cutoff to the logs are discussed later in this section.

Other historical net pay cutoffs

The technical literature shows that a number of net-pay-cutoff approaches have been used over the years by petrophysicists, geologists, and reservoir engineers. [1][2][3][4] These cutoffs are often simply stated as a particular value for porosity, Vsh, and/or Sw. The justification for those cutoffs is rarely stated. Geologists often provide their foot-by-foot pay/nonpay identifications ("picks") with their detailed core descriptions.

In all cases, chosen cutoffs generally exclude poorer-quality rock intervals. The key issues become whether the cutoff is applied in an accurate, consistent, and systematic manner through net-pay calculations using log data and the volume of hydrocarbons that are excluded in the net-pay calculations. For example, geologists often define shales, and possibly siltstones and very shaly sandstones, as nonpay intervals; then the GR logs can be calibrated to this nonpay standard. A value of the geologists’ core descriptions in the net-pay determination is that core descriptions are generally more continuous than are the routine-core-analysis data.

Like the geologist’s criteria, porosity and Vsh cutoffs also exclude poorer-quality rocks because lower-porosity rocks also generally have lower permeability, higher water saturations, and little, if any, mobile oil. Higher Vsh values are generally indicative of more clay-mineral-rich rocks that also tend to have lower porosities, lower permeabilities, higher water saturations, and little, if any, mobile oil. If these two cutoffs are applied without consideration for flow implications, then some rock intervals containing significant volumes of hydrocarbons that can contribute significantly to production may be excluded before OOIP, OGIP, or reserves calculations.

An Sw cutoff is sometimes also used as a nonpay cutoff, often in addition to a porosity and/or Vsh cutoff. An Sw cutoff is typically justified on the basis that, at high Sw, gas or oil is immobile on the basis of relative permeability considerations. This approach does not account for, at original reservoir conditions, high-Sw rock intervals that contain lower hydrocarbon saturations but with those hydrocarbons in the larger pores of the rock. These hydrocarbons will have mobility and contribute to production, particularly for gas reservoirs in which, as the pressure declines, the gas phase expands (and gas saturation increases) and results in gas flow toward the production-well pressure sinks.

The difficulty with the use of porosity, Vsh, or Sw cutoffs, without reference to flow considerations, is that rock intervals evaluated to contain hydrocarbons may be excluded from the other reservoir-engineering calculations. Each of these approaches, when applied to the logs, requires that underlying physical relationships between log readings and these cutoffs be understood. Also, complications on logs need to be quantified and treated appropriately in net-pay calculations, for example:

  • Intervals of heavy minerals
  • Radioactive minerals other than clay minerals
  • Hole washouts

Geologic considerations in net-pay determination

The primary geological considerations in determining pay and nonpay in the reservoir interval are depositional environment and hydrocarbon and structural history. The depositional environment provides a picture of whether the overall reservoir interval is sand rich (high N/G) or shale rich (low N/G) and the nature of the interbedding of high-quality rock with poor-quality rock. If the reservoir interval is quite interbedded with high-quality rock intimately layered with poor-quality rock on the scale of a few inches to a few feet, the poor-quality rock intervals, if they contain hydrocarbons, will likely contribute to production. However, if the layering is on a much larger scale with thick high-quality rock intervals separated from thick low-quality rock intervals, then the poor-quality rock intervals are much less likely to contribute significantly to production.

Regarding hydrocarbon and structural history considerations in net pay calculations, several fields have relict-oil intervals below the current oil/water contact (OWC) (e.g., Prudhoe Bay, Alaska North Slope, U.S.A.; San Andres carbonate reservoirs, west Texas, US) [5][6][7] or relict-gas intervals below the current gas/water contact (GWC) (e.g., North Morecambe field, Irish Sea, UK). [8] These relict-oil columns would generally be considered to be nonpay intervals because of their high mobile-water saturations and lack of oil mobility. This is true for either primary production or waterflooding; however, for CO2 enhanced oil recovery, the west Texas San Andres relict-oil intervals have been considered for development. A more significant situation is that of relict-gas saturations below the current GWC. This gas does not have immediate mobility; but if the aquifer is not strong, this gas will expand and can contribute to production as the reservoir pressure declines. Hence, a relict-gas interval should not necessarily be excluded in net-pay calculations.

George and Stiles[4] published an excellent example of the complications of net-pay calculations concerning the heterogeneous Clearfork carbonate oil reservoirs in west Texas, US. Their approach was to develop an empirical relationship between "actual pay" and "apparent pay" as a function of porosity in order to redetermine net pay to improve OOIP calculations and to obtain a reasonable distribution of net pay. They defined two net-pay cutoffs. The "actual pay" was defined as the net thickness of core samples with permeabilities greater than 0.1 md, and an "apparent pay" was defined as the net thickness of core samples with porosity greater than a specific cutoff. Fig. 1 shows the relationship of actual pay to apparent pay as a function of porosity. On the basis of this analysis, at a porosity level of 8% BV, 75% of the rock samples would be pay, while at a porosity level of 1% BV, 50% of the rock samples would be pay. By this methodology, wells with low porosity levels will not be all nonpay, but will be given a limited amount of pay. The purpose of their method was "to achieve a better distribution of porosity-feet" and "both total original oil in place and distribution of PV throughout the field will be realistic." [4]

Finally, the technical team needs to determine the implications of any net-pay cutoff. This is best done by plotting the cumulative hydrocarbon pore feet (FHCP) percentage as a function of porosity and as a function of permeability (see Figs. 2 and 3 for respective examples of these two types of plots). In this way, it is possible to determine what percentage of the hydrocarbons within the reservoir interval would be excluded by any particular net-pay cutoff. While this net-pay sensitivity method is a logical approach, the evaluation of porosity and water saturation is more uncertain in low-porosity rocks. Log calculations may indicate hydrocarbon saturations in rocks where no hydrocarbon actually exists.

Application of net-pay cutoffs to well logs

The four main steps in the application of a net-pay cutoff to a particular reservoir interval are to establish a standard, calibrate one or more logs to the chosen standard, confirm that the calibration step produces results consistent with the standard, and apply the calibrated model to all wells.

Establish a standard

As discussed previously, the choice of the standard for the net-pay calculations should be reasonable but is, to some degree, arbitrary. The choice should be a single concept, such as a permeability cutoff, a porosity cutoff, or geologists’ calls of pay/nonpay from core descriptions. The use of multiple cutoffs will lead to a very conservative result that eliminates rock intervals that are likely to contribute to production, particularly for gas reservoirs. This underestimation occurs because each of the individual cutoffs will, to some extent, define different datapoints as nonpay. Even after the best possible depth matching of the logs involved, remaining depth mismatches always occur, resulting in the double counting of nonpay at bed boundaries. The following discussion assumes that an air-permeability cutoff of 0.1 md has been chosen.

Calibrate logs to chosen standard

Once the 0.1-md air-permeability cutoff has been chosen, it needs to be converted into a methodology that can be applied to foot-by-foot log calculations. Typically, this is done by converting the permeability-cutoff value into a porosity-cutoff value by a permeability-vs.-porosity semilog crossplot of routine-core-analysis data converted to reservoir conditions. Also, plots are made of the core permeability data vs. the various available log parameters to determine if there is a strong correlation that can be used. Alternatively, a multivariate regression technique might be used to calibrate multiple logs to permeability. If a porosity cutoff is developed from the permeability cutoff, then it needs to be defined as a log-related cutoff, such as a log-derived porosity or density log cutoff, or a Vsh or GR-log cutoff. There are several variations on how this calibration step can be undertaken. The alternatives are not discussed here because each reservoir situation has unique characteristics.

Confirm the calibration step

After the calibration step is completed, the resulting log calculations of pay/nonpay need to be checked against the core standard in the cored wells. This is needed to determine that the log calculations and their cutoffs do not overstate or understate the calibration standard of net pay of the reservoir interval. The goal is to develop the "best estimate" values in the reservoir-engineering calculations, not the "low estimate" or the "high estimate."

Apply the calibrated model

After the first steps have been successfully completed, the finalized net-pay log model can be applied to all wells’ valid log data in the reservoir interval to develop point-by-point pay/nonpay determinations. For optimal results, it may be necessary to have different models in different areas of the reservoir. The results for each zone over the reservoir should be quality controlled. Maps should be examined looking for "bulls-eyes" that may represent either real geological effects, artifacts in the database, or bad calculations.

In the subsequent steps of calculating porosity, Sw, and permeability, those calculations will be made only for pay intervals. The nonpay intervals will be excluded from the core and SCAL database and the log database. In cases in which the depth matching of cores and logs presents difficulties, it is prudent to retain both core- and log-defined nonpay in the database. This will enable appropriate samples to be selected for various analyses, such as the evaluation of SCAL petrophysical properties.

Nomenclature

FHCP = hydrocarbon pore feet, L, ft [m]
Sw = water saturation, %PV

References

  1. 1.0 1.1 Cobb, W.M. and Marek, F.J. 1998. Net Pay Determination for Primary and Waterflood Depletion Mechanisms. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisianna, 27–30 September. SPE-48952-MS. http://dx.doi.org/10.2118/48952-MS.
  2. 2.0 2.1 2.2 Pirson, S.J. ed. 1958. Oil Reservoir Engineering, 443–445. New York City: McGraw-Hill Book Co. Inc.
  3. MacKay, Virginia ed. 1994. Determination of Oil and Gas Reserves, 45-46. Petroleum Soc. of the Canadian Inst. of Mining, Metallurgy, and Petroleum: Calgary, Canada.
  4. 4.0 4.1 4.2 George, C.J. and Stiles, L.H. 1978. Improved Techniques for Evaluating Carbonate Waterfloods in West Texas. J Pet Technol 30 (11): 1547–1554. SPE-6739-PA. http://dx.doi.org/10.2118/6739-PA
  5. Erickson, J.W. and Sneider, R.M. 1997. Structural and Hydrocarbon Histories of The Ivishak (Sadlerochit) Reservoir, Prudhoe Bay Field. SPE Res Eng 12 (1): 18-22. SPE-28574-PA. http://dx.doi.org/10.2118/28574-PA
  6. Lucia, F.J. 2000. San Andres and Grayburg Imbibition Reservoirs. Presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 21-23 March 2000. SPE-59691-MS. http://dx.doi.org/10.2118/59691-MS
  7. Thai, B.N., Hsu, C.F., Bergersen, B.M. et al. 2000. Denver Unit Infill Drilling and Pattern Reconfiguration Program. Presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 21-23 March 2000. SPE-59548-MS. http://dx.doi.org/10.2118/59548-MS
  8. Cowan, G. and Boycott-Brown, T. 2003. The North Morecambe Gas Field. In United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. London: Geological Soc.

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See also

Layer thickness evaluation

Fluid identification and characterization

Water saturation determination

Petrophysical data sources

Petrophysical analysis case studies

Petrophysics

PEH:Petrophysics

PEH:Petrophysical_Applications