AGI Training Module, Determination of Net Pay

Net-Pay Cutoff
The two most critical issues in the determination of net pay are permeability to reservoir fluids and water saturation. In many cases analysts use other criteria for net pay, such as porosity and shale volume. Although porosity is an important input in the net-pay determination process, if the researcher has a good permeability model, a separate porosity criterion is unnecessary. In many cases the use of a porosity criterion alone for net pay can lead to erroneous calculations of net pay because permeability is a function of both porosity and irreducible water saturation. If the irreducible Bulk Volume Water (BVW) (the product of porosity and water saturation) is not a constant value within the reservoir, the porosity-permeability relationship will not be consistent either.

High irreducible BVW zones require higher porosity values to achieve the same permeability as lower porosity low irreducible BVW zones. Clay volume is an input to the process as well, refining both porosity and water saturation calculations. It is unnecessary to have clay volume as a separate net-pay criterion after permeability and Sw models have been calibrated.

Permeability to Reservoir Fluids
Permeability is the ability of fluids to move in the reservoir. The net-pay cutoff should be based on how effective permeability is to reservoir fluids under reservoir conditions. Most core permeability data concern air-at-surface conditions, and adjustments should be made to these values to reflect in situ conditions. In dry gas reservoirs, reasonable estimates can be obtained from core data analyzed under net overburden stress conditions using Klinkenberg corrections. This type of analysis is not generally cost prohibitive, and not all samples need it.

Excellent correlations can commonly be obtained on a subset of the total core data set that allows the net overburden Klinkenberg corrections to be applied to all samples. Correlations can also be done in oil reservoirs; however, significantly more expense and effort are required. Determining the values of effective permeability to oil and water is a useful exercise. Part of this effective-permeability determination process is estimating irreducible water saturation and relative permeability to oil and water. These issues will be discussed in the next section. In the absence of special core analysis in oil zones, a reasonable calibration can be made to pressure transient data. In this case it is important to use the value of permeability-thickness from the well test and to match the log-derived permeability thickness, rather than the assumed permeability value. The permeability value from a well test requires an input of net pay that may or may not be valid before proper calibration.

Factors Affecting the Permeability Cutoff
Type of completion is an issue because lower permeability zones having hydraulic fractures can be economically produced, whereas identical zones having no stimulation may not be. Many of the low-permeability gas zones in the U.S. had little or no net pay before hydraulic fracturing was introduced, although today these same reservoirs are responsible for a good deal of the total gas produced. If the zone cannot be stimulated, the amount of skin damage expected becomes a factor. Lower permeability zones that can be drilled without skin (using techniques such as underbalanced drilling) can be economically produced, whereas equivalent permeability zones with high skin damage may not. In the case of hydrocarbon zones close to water zones, one zone may contain net pay if sufficient stress contrast exists between the hydrocarbons and the water, although an identical zone may not be considered net pay because a hydraulic fracture would result in uneconomic water production. The viscosity of the produced fluid is also an issue, gas reservoirs requiring permeabilities to produce economically that are significantly lower than those of oil reservoirs. Reservoir pressures and flowing well-bore pressures are also an issue. Zones having high reservoir pressures and high drawdowns can be produced economically at lower permeabilities than can lower pressure and drawdown zones having equivalent permeabilities. All of these factors go into the permeability cutoff for net-pay determination. A detailed discussion of these is beyond the scope of this exercise, and it is assumed here that this value has been determined by the reservoir engineer and petrophysicist for the field. If additional background is needed for establishing permeability and Sw criteria for net pay, a review of the references is recommended.

Water Saturation
Water saturation (Sw) is the second key parameter that must be estimated to determine net pay. Three water saturation values need to be specified to determine net pay adequately. The first is irreducible water saturation for the formation, or Swirr, which is the water bound by capillary forces to the matrix that will not move. The second is water saturation in the reservoir at the time the well logs were obtained, or Sw. If Sw is equal to the irreducible Sw, then the zone should produce no water. As Sw increases above Swirr, higher and higher water cuts can be expected. At some point the third Sw value (Swcritical) is reached, where the water cut is unacceptable. This impacts net pay determination is the Sw where water cuts become uneconomic. Because the SPE definition of reserves includes an economic caveat, factors such as water-disposal costs and lifting costs enter into the equation. The current Sw is generally calculated from log data once the Sw model has been calibrated to irreducible Sw data. The Swirr can be obtained from core capillary-pressure data and from core-calibrated Nuclear Magnetic Resonance (NMR) log data. The NMR log should have a calibrated T2 value to discriminate mobile and nonmobile fluids because the default value of 33 ms does not apply to all reservoirs. Swcritical can be obtained from core relative-permeability data and fractional flow calculations if available. A more commonly used technique is to compare Sw values from the logs with actual water cuts in the field. Once the Sw model is calibrated to Swirr from core capillary-pressure data or NMR log data, the Sw in the reservoir that results in uneconomic produced water cuts is probably a reasonable first estimate of the critical Sw value in the absence of relative permeability and fractional flow data from cores. This Sw value is typically in the 50- to 70-percent range in most light oil and gas reservoirs where high water cuts are unacceptable, the lower Sw critical values usually being associated with higher permeability rocks. The value is also a function of viscosity, for heavy-oil values as low as 25 to 30 percent Sw have resulted in uneconomic water cuts.

Intermediate Steps to Calculating Water Saturation and Effective Permeability

The basic inputs to calculating water saturation and effective permeability are shale volume, apparent porosity, and resistivity. Shale volume will be used to convert apparent porosity to an effective porosity value. It will also be used to correct the resistivity value for the effect of shale. A discussion of these three parameters is in order.

Shale Volume
The volume of shale or clay in the rock can be determined from gamma-ray (GR), spontaneous-potential (Sp), resistivity, neutron, neutron and density, sonic, or NMR data. In some cases a combination of indicators is required where either the minimum or a specialized average is used. In the exercise provided it is assumed that gamma ray will be used. A discussion of other techniques can be found in Asquith.

The basic process is to determine a value of the tool measurement that corresponds to sand and a value that corresponds to shale. The percentage of shale is determined by finding the difference between the actual value and the clean value divided by the total difference between the sand and shale values. In the case of the more commonly used gamma ray, there is not a linear relationship as the equation provided in the exercise indicates. The key calibration value for the volume of shale is the X-Ray Diffraction technique (XRD). This technique measures the bulk volume of shale as a percentage of total rock volume. The Scanning Electron Microscope technique also provides a clay volume by a direct examination of core slices. It is not recommended for the calibration of log-based shale volume if XRD data are available.

Apparent Porosity and Effective Porosity

The next key input to calculating effective permeability and net pay is apparent porosity. Apparent porosity is the raw porosity input with no shale corrections. In most cases this value is obtained from the average of neutron and density porosity values or the square root of the average of the values squared for gas wells. Density porosity alone can often be used, as it is in the exercise in this module. Sonic porosity can also be used, as can neutron or MRIL data. In the case where no porosity logs are available, a correlation can often be obtained in fluvial-deltaic systems between an assumed value of maximum porosity as a function of depth and as a function of shale volume. This correlation has been successfully applied in the Miocene in several reservoir characterization studies. Once the apparent porosity value is determined, it should be corrected for shale volume. There are two main techniques applied here. The first quick-look technique is to reduce the apparent porosity by the percentage of shale in the rock or multiply it by one minus the shale percentage. A more technically correct method is to estimate the porosity in the shales and reduce the apparent porosity by the product of the shale porosity and shale volume. This is the technique applied in the exercise. Asquith provides an excellent discussion of the techniques and equations involved.

The net-pay criteria are established by the reservoir engineer and petrophysicist. In this exercise, they have calibrated the log-analysis model to core and determined that permeabilities over 0.001 md will provide economic flow rates. Figure 1 (below) shows a log calibration to core, and in this case there is reasonable agreement between core-calculated values and log calculations. They have also determined that water saturations over 60 percent will result in uneconomic water-production volumes. Other necessary information for determining net pay includes bulk density, gamma ray, caliper, and resistivity. The equations necessary to determine whether each of the provided samples presented qualifies as net pay can be found in the glossary. Ultimately this determination will require a calculation of effective porosity, water saturation, and permeability to gas. All of the steps leading up to these calculations must be done first.