Given the current scrutiny surrounding reserves estimates, good formation evaluation is critical.

The objectives of the Securities and Exchange Commission (SEC), in part, are to administer federal security laws and issue rules and regulations to provide protection for investors and ensure the securities markets are fair and honest. As part of this effort, the SEC promotes full and effective disclosure to the investing public. The SEC definition of proved reserves is intended to support their objectives of full and fair disclosure of reserves to the investing public.

The SEC specifically defines proved oil and gas reserves and further defines two categories of proved reserves: Proved Developed and Proved Undeveloped.

There are three primary petrophysical sources of information used in reserve classification: well tests, core analysis and well logs. Each source of data contributes a different element to the classification of reserves. A diverse data set combination is good and, in general, the more diverse the better (Figure 1).

Production and well test data

The most compelling information for determining reserve classification is sustained, long-term production at economic rates. Reserve bookings can often be reasonably assessed through conventional decline curve or P/Z analysis. In such situations, core and log data may play a minor role in the reserve classification process. However, when reserves are booked early in an appraisal or development drilling program, short-term production tests and drill stem tests often play the primary role in satisfying the condition for "conclusive formation tests." These tests are also used for the classification of reserves that will not be included in the initial completion efforts. In situations where multiple reservoirs are penetrated, the decision is often made to leave one or more productive intervals behind pipe to be completed following the depletion of other higher value reservoirs.

Important considerations in the planning of a well test are the demonstration of an economic production rate and the demonstration of areal reservoir continuity. The longer the production and subsequent pressure buildup period in the well test, the greater the radius of investigation that can be demonstrated through pressure transient analysis. Often, economic, mechanical or operational constraints during the drilling and completion process preclude the implementation of long-term testing procedures. Short-term, low-volume drill stem tests provide information concerning productivity but are not as compelling in demonstrating reservoir continuity over large areas. Information from well logs, cores and properly selected analogy wells is useful in the evaluation of a real continuity when long-term test data are not available.

Recent tool developments have greatly increased the quality of data available from wireline formation tests. These modern tools have pump-through capability that allows for the drilling mud filtrate to be minimized before a sample is taken, thus increasing the quality and quantity of the reservoir fluids recovered. These tools also have additional downhole measurements that allow the evaluation of sample quality and bubble-point pressure as well as the recovery of single-phase samples. Also, formation rate analysis allows the evaluation of the quality of pressure measurements, thus resulting in improved formation pressures and gradients for estimating fluid contacts and pressure-volume-temperature (PVT) properties. Pressure transient analysis of the pressure data recorded with the wireline test tools can be used to estimate permeability.

Core analysis data

Core analysis data provide a means to establish ground truth for the other formation evaluation measurements. It is essential for the calibration of well log-based mineralogy, porosity and permeability and for the establishment of productivity in situations where well test data are limited or unavailable. From a reserve classification standpoint, core data provide the best evidence for the establishment of rock property analogies. A fully analyzed core can provide information concerning porosity, permeability, fluid content, shale and clay distribution, mineral content, sorting, grain size, grain size distribution, grain shape (roundness and sphericity), clay-fluid sensitivity, relative permeability characteristics, capillary pressure behavior, wettability, pore structure, pore size distribution, dual porosity flow behavior, pore volume compressibility, net reservoir thickness, seismic parameters, environment of deposition, stratigraphic age and diagenetic history. Core collected early in a development program in conjunction with well test data can be used to establish analogies for later wells where well test data may be limited. Analysis beyond the routine porosity, permeability and residual saturation analysis should always be considered.

Core analysis data are very important in situations where significant uncertainties exist in the interpretation of openhole well log data. Examples of a few of these include interpretation of low porosity carbonates, intervals where only logging-while-drilling (LWD) data exist, and situations where there is significant relative bed dip in thinly laminated sand-shale sequences logged with induction tools. Dead-end pores may be present in low porosity carbonates. In some cases, the dead-end pores are filled with immobile bitumen. Formation water contained in dead-end pores does not contribute significantly to electrical conductivity; therefore, the resistivity of an interval containing a significant volume of dead-end pores may be high. Saturation calculations carried out with the measured resistivities and log-derived porosities may yield optimistic estimates of the hydrocarbon pore volume. Production from low-porosity carbonates often comes from fractures rather than the pore network. Capillary pressure measurements are very useful in assessing the productivity of non-fractured, low-porosity rock.

Sidewall cores should be obtained and analyzed in any reservoir of possible interest. In situations where reservoirs are missed during full diameter coring operations or there has been insufficient core recovery, sidewall cores provide a relatively inexpensive alternative. Many reserve classification controversies could be avoided if a sufficient number of sidewall cores were collected during the formation evaluation program. Currently, rotary (or drilled) sidewall cores are dramatically underutilized in the industry.

Percussion sidewall core data are more commonly available than either full-diameter or rotary sidewall core data. A typical percussion sidewall analysis report consists of porosities, permeability estimates, residual fluid saturations and general rock descriptions. Both rotary and percussion sidewall cores may provide some estimate of shale distribution, such as laminar versus structural, and whether the production will likely be oil or gas. Porosities from sidewall samples are often suspect as a result of the potential for impact damage during coring. With some additional analysis, formation grain density measurements can be made with sidewall samples, and these data can be used along with the density log data to refine log-based porosity estimates. The reported permeabilities for percussion sidewall cores are rarely measured. They are usually based on correlations involving visual grain size and sorting analysis. The presence of diagenetic pore-lining and pore-filling clays cannot be observed by the analyst without further rock characterization work. These clays can severely reduce the permeability of the formation.

Well log data

Well log information is the most commonly available data. Spontaneous potential (SP), gamma ray, resistivity, bulk density, neutron porosity and acoustic log measurements are the most common and will not be discussed here. A few other logging technologies will be mentioned that may be useful from the standpoint of reserve classification.

While well log technology has made significant and continuous advances over the years, well logs by themselves generally do not fulfill the requirement for reasonable certainty according to the SEC. The SEC provides the following interpretive guidance: "In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test." The lower the porosity, the more complex the mineralogy and reservoir, the greater the need for supporting core and well test information. Well logs plus core generally provide the means of developing analogies from known producing reservoirs to reservoirs one may want to classify as proved.

Thinly bedded and laminated reservoirs represent a major interpretation challenge. Figure 2 depicts the resolution problem in a thinly bedded sand-shale sequence. Shale laminations can exist over several different size scales (from millimeters to feet) as can the thicknesses of the interlaminar sands. This resolution problem is compounded by the fact that the vertical resolution of the various SP, gamma ray, resistivity and porosity measurements are generally not the same. The introduction of array induction logging and processing technologies along with high-resolution processing technologies for the acoustic, bulk density and neutron measurements has helped to reduce problems associated with the resolution mismatch between the various logging tools. Accurate water saturation and porosity modeling requires accurate laminar shale volume estimates. A variety of shale volume models have been proposed which utilize the various openhole logging measurements. Microresistivity and acoustic borehole imaging logs are also useful in this respect. Recently, borehole image logging has become feasible in synthetic or oil-base mud. Image analysis technology can be used to make shale volume estimates from acoustic or micro-resistivity images. Certainty in log or image-based shale volume estimates can be increased with calibration to full-diameter core. The introduction of a triaxial induction logging instrument 3 years ago offers an alternative approach to the thin bed resolution problem.

Spectral gamma ray measurements are useful in situations where uranium is present in the formation or where potassium feldspars make the conventional interpretation of the gamma ray data difficult. Spectral gamma ray measurements are particularly valuable in carbonate reservoirs where natural radiation from sources other than shale is common.

Recent advances in the use and application of nuclear magnetic resonance (NMR) logs have improved the evaluation of reservoir quality and producibility. These tools can provide valuable information concerning porosity, fluid content and clay-bound water volume. In many situations, when properly calibrated with core data, NMR data can be used to estimate permeability.

When information is unavailable in open hole, through-casing pulsed neutron logging, carbon-oxygen logging and testing may be considered under the appropriate circumstances. This may increase the reasonable certainty of hydrocarbon content. As noted above, cores should also have been previously taken in these intervals of interest as cores cannot be obtained through casing.

It is important to gather data necessary to support geological and seismic interpretation efforts early in the formation evaluation program. These data would include conventional bulk density and acoustic measurements, formation dip measurements, vertical seismic profiles and check-shot surveys. Measurements from modern dipole acoustic logs can provide estimates of shear wave anisotropy. This type of data can be very useful for amplitude variation with offset (AVO) analysis.

Conclusions

The principles of analogy and data diversity should be a part of the data acquisition design strategy. Reasonable certainty increases when it can be demonstrated that data from a variety of independent sources support consistent conclusions concerning the volume of hydrocarbons in place, hydrocarbon productivity and reservoir continuity.

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