A SYSTEMATIC APPROACH TO RESERVES AUDITING, TRACKING

Peter Cockroft
Pertamina-Canada
Northwest Energy (South Sumatra) Ltd.
Jakarta

Joseph R. de Kehoe
GeoMark Research Inc.
Houston

A major source of confusion in the oil and gas industry is the different perceptions of reserves, not only within a company-an explorationist's estimate is usually quite different from an engineer's-but also at different stages of development of the hydrocarbon resource.

This commonly bemuses managers and outsiders, particularly bankers, who are accustomed to relatively straightforward inventory control in other industries.

Similarly reserves reports for an area omit hydrocarbon volumes that are considered uneconomic under existing fiscal conditions, e.g. subcommercial discoveries. Strictly speaking, subcommercial accumulations should be excluded from the reports; however, these volumes represent potential future value to a company and are essential for, among other things, determining the fair market value of an area the design and positioning of surface facilities, and allocation of human as well as capital resources.

If logically presented, inclusion of potential hydrocarbons with reserves data provides managers, government officials, and lenders with a clearer picture of an area's known and potential value.

Our proposed method of reporting the total hydrocarbon resource of an area at different stages of discovery and development (Table 1) is consistent with the current classifications recognized by the Securities & Exchange Commission, Society of Petroleum Engineers, World Petroleum Congress, American Association of Petroleum Geologists, and government regulatory bodies, and this audit report methodology is now being used by a number of governments and some ma or oil companies.

This system was precipitated by a senior government official asking one of the authors, "Why does my energy ministry continuously report oil and gas 'discoveries,' but there is no change to my country's anticipated production?"

In addition to providing a clear summary of total hydrocarbons within a geographical area or business unit, our method can accommodate any method of calculating resource volume from single-point "most likely" input values, through multipoint values (i.e. proved, probable, possible) to the continuous function or expectation curve.

RECOVERY VARIABLES

Reserves are commonly defined as "the economically recoverable portion of the hydrocarbon resource."

During assessment and development of a field, beginning with subsurface maps of an undrilled structure and ending with the depletion of the field, the original resource, called "oil-or gas-in-place" or "hydrocarbons-in-place" (HIP), does not change. Only our perception of the reserves portion of the volume varies, usually with changes in the viability of extracting the hydrocarbons, commonly due to fluctuations in the commodity (oil and gas) prices, and the technical/mechanical efficiency of producing the hydrocarbons.

In other words, the variables affecting recovery factor, and thus reserves, are principally technical and economic. These variables are often independent and imply that a two dimensional matrix ("spreadsheet") could be used for description (Table 1).

Categories in Table 1 describe the same resource but reflect uncertainties inherent in the assessment. The level of uncertainty is highest before the prospect is drilled and is reduced with the increase in data. It is the uncertainty and risk attached each category-or cell in the table that are used to classify volumes.

Although there is no scale, the horizontal axis is a measure of time, increasing from right to left, and reflects the increasing amount of data available as an area is mapped, drilled, and either abandoned or developed.

By classifying volumes of oil, gas, or natural gas liquids (NGL) according to the degree of risk and uncertainty and assigning them to cells in the table, a reserves audit report (Table 2) can be readily prepared that provides a comprehensive tabulation of hydrocarbon volumes at any stage of exploration or development.

'CANYON FIELD' HISTORY

In this example, for simplicity, the "Canyon" structure is comprised of three fault blocks and occupies nearly the entire concession area.

The same methods apply, however, to large concessions containing multiple undrilled structures, producing fields, and subcommercial discoveries.

Here is a took at a hypothetical concession history, divided into the following time segments:

• Conceptual, play evaluation

• Leads and prospects

• Drilled prospect-discovery

• Appraised discovery

• Field delineation and development

• Field extensions

• Pressure maintenance/waterflood

• Improved recovery-EOR

PLAY EVALUATION, LEADS

The exploration department evaluates the concession and although seismic coverage is sparse and closure is yet to be confirmed determines that a lead exists, that further exploration is warranted, and preliminary maps are then made. Respective values for reserves and in-place numbers are placed in cells L4 and L6.

Each time a number is added to the table, revised, or moved from one cell to another, it should be conscientiously referenced with footnotes that then become an integral part of the table. The footnotes are important in following the history and derivation of the reserves numbers.

A good practice is to keep a separate binder as a detailed reference to back up all the data. For instance, structure maps on which areal extent and closure were measured should be contained in the file, as should logs and log analyses that are the basis for gas/oil and oil/water contacts, porosity and water saturation, PVT analyses, and any other data that serve as a background for estimates. Workers assigned to the project in later years may not always agree with previous analyses, but there should be no doubt in their minds as to how the numbers were derived.

In practice, it is usually more informative and realistic to carry potential reserves as a range of values, i.e. 235-285 million bbl of oil, and to round numbers off to the nearest five or 10 millon bbl for hydrocarbons in the "discovery," "prospect," or "leads" categories.

PROSPECT STAGE

A Comprehensive seismic program is conducted and integrated with other available data. Down-dip limits of the structure are delineated, the feature is mapped as having four-way dip closure, and two normal faults are identified. The structure is now sufficiently well defined to be designated a prospect, and values in L4 and L6 are revised and moved to P4 and P6, respectively.

Often, when a large seismic program is carried out, more than one lead is identified, thus some values would remain in the "leads" category. For simplicity, we will ignore this situation.

PROSPECT-DISCOVERY

Wildcat well Canyon-1 is drilled, and although some isolated gas sands are encountered in a shallow section, the well unexpectedly encounters a thick oil bearing reservoir and flows oil at significant rates.

Commerciality is yet to be determined. Based on areal distribution of the reservoirs, and log analysis, Fault Block 1 volumetric estimates can be moved to D4 and D6.

APPRAISAL

Appraisal wells Canyon-2 and Canyon-3 are drilled. The results of these wells are sufficient to encourage the operator to deem the prospect to be a commercial oil field.

Volumes in the drainage areas of the three wells can now be assigned to D3 (undeveloped). The remaining hydrocarbons in Fault Block I are potentially recoverable and are assigned to D4.

A gas sand (tested) was also intercepted by these wells, but as there is no ready market or plan to produce the gas, these are also placed in D4.

Potential reserves in Fault Blocks II and III remain in cell P4.

DELINEATION, DEVELOPMENT

Plan of Development for Canyon field (Fault Block 1) is approved by management, partners, and government regulatory bodies. Blocks II and III are not considered for development at this stage. Oil volumes can now be transferred to cells F3, F4, and F6, while the gas categories are unchanged (D4) as gas commercially is yet to be determined.

FIELD EXTENSIONS

Fault Block I is developed (development wells Canyon-4 and -5 are drilled) and placed on production (volumes in Fl, F2, and F6). Fault Block II is successfully appraised by well Canyon-6, but not yet developed (volumes in F3 and F6. Block III is still undrilled (volumes in P4 and P6). Gas is still unchanged.

PM, WATERFLOOD

Reservoir simulation indicates that water injection could increase ultimate recovery. These could be placed in the D4 or P4 categories. Infill drilling with gas lift is also deemed to be able to improve recovery.

As a waterflood requires some capital expenditure, no approval can be obtained until the next budget year. Since some infill drilling is currently economic (and some not), F3 and F4 volumes are calculated. Also, it is believed that some tertiary EOR may also improve ultimate recovery, and P5 volumes are calculated accordingly.

A pilot waterflood is approved for Block II. Some of the water injection volumes can then be transferred from F4 to F3. A further appraisal well, Canyon-7, proves Block III to be dry below the oil-water contact, so these volumes are deleted.

IMPROVED RECOVERY-EOR

Laboratory screening tests as well as operational conditions (source availability, etc.) confirm the suitability of the tertiary EOR, hence the P5 volume can be transferred to F5. The pilot water injection wells are drilled, so some volumes can be transferred from F3 to F2, as can some volumes influenced by infill drilling and a planned (but not yet approved) gas lift project (some gas volumes can be moved from D4 to F3.

There is an overall rise in oil prices that is thought to be relatively consistent, causing further infill wells to become economic (some further volumes are then moved from F4 to F3). The gas lift scheme is approved and implemented so gas volumes can be moved from F3 to F2.

The waterflood project is successful and a full scale flood is planned, approved, and started (further F3 can be moved to F2). Thus more volumes can be transferred from F4 to F3. An EOR pilot is approved and begun, although this does not allow any transfer of volumes as the method is not deemed to be relatively certain of technical success (remains in F5).

CHANGES IN FISCAL TERMS

The fiscal terms are changed by the host government, which means that further infill drilling is not economically justifiable (remaining F3 is moved to F4).

Also, the EOR pilot is technically successful, but the change in terms means that a full scale project is not viable, so volumes are transferred from F5 to F4.

FIELD ABANDONMENT

Canyon field is no longer economic to keep on production (F2 = 0), but some further infill wells may be economic if the price increases substantially (retain in F4), however the EOR is not viable even if the price varies substantially (drop from F4).

Of course these economics will change even further if the field is temporarily abandoned, as some capital will be needed for further start-up. If this investment is deemed to be too expensive, only Fl and F6 are retained for Canyon field.

CONCLUSION

We have presented a relatively simple reserves tracking and auditing method that could be used by different organizations for different reasons.

This method is an attempt to resolve the problem if inconsistencies of reserves evaluations between different disciplines and elements of uncertainty, with either deterministic or probabilistic procedures equally valid.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.