RUSSIAN VENTURES-4 EVALUATING OIL, GAS VENTURES IN W. SIBERIA: FEASIBILITY STUDIES

Jack A. KrugQuesta Engineering Corp. Golden, Colo.

WilLIam ConnellyPangea International Inc. Golden, Colo.

This article discusses the methodology and calculations used in performing the economic evaluations for a typical western Siberia oil project venture. The discussion of taxes, funds, depreciation, and costs assumes the venture is a stock company and that economics are calculated on a project basis.

Venture structure, bidding procedures, and requirements for registration are discussed in the next article. Most ventures available to western companies are delineated oil fields that are not yet developed or producing. We focus on this type of property.

The required elements for an economic evaluation include original-oil-in-place (OOIP) and recoverable reserves; development plan and associated production forecast; and capital requirements and operating costs. The level of evaluation-i.e., screening, preliminary feasibility study, Technical Efficiency of Organization (TEO), or full feasibility study-determines the detail needed for each of these elements. Several economic analyses of a venture should be made to evaluate the sensitivity of alternative development plans, joint venture deal terms, capital requirements, operating costs, product prices, and taxation variables.

The first three parts of this five part series dealt with (1) log and core data, (2) reservoir description and (3) flow tests and reservoir performance, and provided a technical foundation for the evaluation of oil and gas ventures in western Siberia. 1 2 3

RECOVERABLE RESERVES,

PRODUCTION FORECASTS

The OOIP, reservoir drive mechanism (i.e., depletion drive, waterflood, or gas injection), and recovery factor (RF) determine the production forecast. Computation of OOIP was discussed in part two of this series and is based on geophysical, log, core, and map data.

The production mechanism for western Siberia oil fields typically is depletion drive and/or waterflood. Two extremes of recoverable reserves and associated production forecasts are used to calculate the possible range of economics. The minimum case assumes a depletion drive mechanism with low production rates and RF. The maximum case assumes improved production rates and RF through a secondary recovery pressure maintenance development program.

For the minimum case, the primary recovery forecast is estimated using the Tracy method of material balance. This method assumes fluid expansion is the dominant drive mechanism.

The material balance approach provides an acceptable forecast of primary recoveries only if the reservoir pressure gradients are not too large and the reservoir does not have an active water drive or large gas cap.

The pressure gradients typical of Siberia reservoirs are not too large because permeability is sufficiently high to allow uniform drainage throughout the reservoir. Tracy material balance calculations generally indicate expected primary recoveries range between 7% and 15% of the OOIP.

With a depletion drive reservoir, the production rate rapidly declines exponentially with time. The resulting cash flow estimates have the lowest value.

For secondary recovery development programs using waterflood, the RF is lower for thin sands than for thick sands because sweep efficiency is better in thicker sands. The RF for a reservoir is not consistent across a structure because of stratigraphic inhomogeneities, structural boundaries (e.g., faults) and transition zones, all of which cause variations in flood efficiency across a field.

Oil companies use general guidelines for minimum pay thickness considered economically productive or likely to respond to waterflood. The first step in estimating recoverable oil is partitioning the bulk reservoir volume according to pay thickness; for example, net pay intervals that are less than 3 m thick and those greater than 3 m thick.

Thin pay zones in a reservoir are considered non-floodable and are assigned an RF range from zero to 10%. Recovery from these thin zones is assumed to result only from fluid expansion (depletion drive). To justify development of thin pay zones, they must be economic on their own merit or they must be developed in conjunction with thicker pay zones elsewhere in the wellbore.

If a thin zone will be penetrated while drilling to a deeper objective, for economic calculations, the zone is assumed to be perforated and produced; however, the waterflood efficiency will be very poor in this area so an RF of 7% to 10% is used.

An alternative to water injection is gas injection for pressure maintenance. While gas injection has many advantages over water (especially in cold environments), generally there are not suitable gas supply and/or infrastructure to transport gas to the field for injection. Therefore gas injection is not considered a viable alterative for preliminary feasibility evaluations.

Waterflood efficiency for thicker pay zones is a function of reservoir continuity, injection rates, well spacing, and mobility ratios. Reservoir continuity needs to be studied carefully on stratigraphic cross-sections.

However for preliminary evaluations, there generally is insufficient time and/or data to adequately evaluate the continuity of sands. Based on our experience, Megion sands often have some of the best continuity, Achimov sands have the worst, and Vasyugan sands range from good to poor.

The waterflood efficiency can be estimated by (1) empirical Siberia correlations, 4 (2) analogy with mature producing fields, or (3) reservoir simulation studies.

The empirical method is used for screening studies and estimates a waterflood RF as a function of oil and water viscosities, permeability, well spacing, porosity, permeability variation, and net pay thickness. This method is based on multi-variate analyses of the actual performance of waterflooded Siberia fields (though not necessarily optimized).

The preferred method for preliminary studies is the analogy method. While reviewing and gathering data for the field evaluation, it is important to identify analogous fields proximal to the property being evaluated.

Production and injection histories, flood patterns, well counts, reservoir rock, and fluid characteristics provide valuable information for estimating production performance and ultimate recovery factors in undeveloped fields.

These data are used to calculate the moveable and recoverable oil as a function of the injected water volume.

In our experience, the older developed producing fields in western Siberia were placed on waterflood early in their lives. The production and injection histories, fluid properties, saturations, well spacing, and flood pattern can be used effectively as an analogy for an offset field. The following summarizes some of the results of evaluating multiple mature waterfloods:

• Producibility: 6-11 b/d/ft of net pay

• Injectivity: 25-32 b/d/ft of net pay

• Moveable oil: 40-50% of OOIP

• Ultimate recovery factor: 14-34% of OOIP

From these performance correlations, the future oil production rates are estimated for various production and injection development scenarios. The production forecast calculations use the method of Chesnut, Cox, and Lasaki.5

The analogy method provides the best estimate for expected performance of un-development nonproducing fields assuming similar reservoir management. Production and injection for mature fields typically indicate they are overinjected; thus by using the analogy method, a degree of conservatism is included in the RF and production forecast. With improved reservoir monitoring and management, recovery factors should improve.

Recoverable reserves may also be estimated through reservoir simulation studies. Simulation studies tend to have better application for fields with significant production histories because these models are constrained by matching theoretical and actual oil and water production histories. We recommend simulation studies for fields with production histories, but not for fields that are delineated but not yet producing.

Recovery factors are 20-27% for reasonably well-managed mature Siberia waterfloods with good reservoir continuity. The better-managed floods have RFs ranging as high as 35%. In our experience, Russians generally make reasonable estimates of OOIP, but due to unreasonably high recovery factors, their estimates of recoverable oil often are too high.

DEVELOPMENT PLAN

The two extreme case development plans are formulated for a delineated field assuming two reservoir management strategies:

(1) Primary production with only depletion drive recovery mechanism; and

(2) Secondary production using pressure maintenance from waterflooding.

The development plan and scheduling for the two extreme cases are approached from a relatively conservative viewpoint.

The drilling time required for a well is estimated based on local Russian experience with time added to account for mechanical breakdowns, lack of supplies, etc. In western Siberia, Russians report a deviated 2,700 m TVD (2,950 m NO) well requires about 15 days to drill, core, log, and system test.

Most wells are directionally drilled from pads. After a pad is fully developed (eight to 12 wells), the rig is moved to the next pad.

Rig moves between wells on the same pad require less than one day. Moves between pads require three to four weeks. Using these times as a guide, a development drilling schedule is created.

The time required for building infrastructure (such as interfield and intrafield roads, pipelines, oil and water processing facilities, power lines, and housing) typically is less than the time required for development drilling and completion of all wells in the field; therefore, the critical path to first production is controlled by drilling and completion rather than infrastructure.

Any time required to mobilize western equipment and supplies to the field before drilling begins must be incorporated into the development time estimates. Most of the fields we have reviewed in Siberia are not near existing roads. Transportation of heavy equipment and supplies to fields must occur in winter when rivers and wet lands are frozen.

During summer months, transportation is mainly with aircraft. Optimizing the delivery of equipment and supplies has a major impact on the development schedule, and the economics.

The more proximal a field is to existing cities, supplies, roads, railways, pipelines, airports, and rivers, the sooner it may go on production. For remote fields, it generally is assumed all wells are drilled before production begins. If a "temporary" pipeline can be laid and made operational early in a field's development, project economics will be improved because of oil sales acceleration.

ECONOMIC ANALYSIS

COSTS

Cost estimates for development and operation of oil fields in Siberia are a moving target due to the changing tax laws, import restrictions, duties, and inflation.

For evaluation purposes we use Western exploration, development, and operating costs to calculate the economics of a field. Typically Russian costs are less than Western costs, so economics will improve if a ruble contribution is included.

The following are guidelines we use for estimating costs in western Siberia; depending upon field and development constraints, costs are adjusted accordingly.

• Drilling cost: Dry hole costs range from $700,000 to $1.1 million for a 2,700 m (MD) deviated well with a 2,500 ft departure.

• Completion cost: Costs range from $250,000-350,000/well. Completion cost varies depending upon whether wells are completed with sucker rod pumps or electric submersible pumps. Most wells are placed on sucker rod pumps early in their lives. About 20'/o of Siberia wells are high volume and use electric submersible pumps.

• Intrafield and interfield roads: Costs are estimated at $75,000/mile.

• Pipelines: Intrafield and interfield costs are estimated based upon U.S. average costs and range from $40,000-200,000/mile, depending upon size and terrane.

• Camps and housing: All housing is assumed to be portable camps that are moved from pad to pad with the drilling and completion rigs.

• Western staff: Western personnel are maintained at a minimal number and are in supervisory positions. For start-up, additional Western staff are budgeted for training and equipment operation. After about one year, the number is decreased.

• Operating costs: Estimated production costs range from $2.50-4.50/bbl depending upon the method of operation. Transportation costs (i.e., pipeline tariffs) range from 80 cts-$2.50/bbl depending on the region and the distance to market. Pipeline losses are estimated between 5-12%, also depending upon the region, transportation distance, and the blending of the various crudes in the pipeline.

• Capital cost of equipment: Equipment such as casing, tubing, wellheads, pumps are cost estimated at Western prices.

ECONOMIC CALCULATIONS

The economics assume all revenues generated by the project result from oil sales. Additional revenues may be realized from the processing of associated gas produced with the oil.

The dry gas can provide fuel for electric generation (including cogeneration projects) in the field and/or can be used for gas lift operations if there is sufficient supply. Excess gas can be reinjected into the reservoir for pressure maintenance.

The hydrocarbon liquids recovered through gas processing can be mixed and sold with the oil. The value of these liquids is not included in the oil revenue calculation, therefore, these volumes may provide an upside to project economics.

Oil price is held constant throughout the project and ranges between $18-22[bbl depending upon the investor's philosophy.

The table shows a sequence of calculations for a typical western Siberia project. Some of the costs in the calculation are summarized below.

TAXES

• Royalty tax. Royalty tax (or use tax) typically ranges between 8-16% depending on negotiations or bidding. This tax is based on the gross revenue from the oil sales and is identical to royalty calculations in the U.S.

• Profits tax. The Russian federation has levied a tax on taxable "profit." Taxable profit is the amount remaining after subtracting royalty, funds, capital cost, depreciation, and operating expenses from the gross revenue. A 32% profits tax is calculated from the taxable profit. Previous years' tax credits are carried forward until used.

• Excise tax. Government Decree 847 established an excise tax that limits the profitability of a project to about 20%. This is a negotiable tax rate based upon the project. For calculation purposes, the excise tax is included in the Profit Tax.

• Export Tax. Export tax also referred to as the "value added tax" is 21 European currency units (ECUs) per ton of oil and condensate (which is equivalent to about $5/bbl). This tax is calculated based on the world price of oil and therefore fluctuates. This tax has previously been negotiated to a lesser amount for some joint ventures.

• Repatriation tax and/or fee. Repatriation tax is assessed on the currency repatriated from Russia to the Western investor. This tax ranges from 4 1/2% to 15% depending on the country from which the foreign partner's company originates.

  Cyprus currently has a favorable treaty with Russia, and the repatriation tax rate is 41/2%. The fifth article in this series will discuss this further as it relates to the current U.S.-Russia Tax Treaty status.

FUNDS

The following are typical funds created in the joint venture documents. The Reserve Fund is the only mandatory fund.
• Research and exploration fund. Typically 5% of the income after deduction of the revenue tax operating costs, intangible investment, and depreciation is designated for the Research and Exploration Fund. This fund is used for further investigative costs necessary to explore for and develop additional reserves.

• Reserve fund. Five percent of the income remaining after the research fund deduction is designated for the Reserve Fund. This fund is designed to mitigate the variability of revenue and to assist in paying fixed costs and is used to cover losses if insufficient revenue is generated by the project. It is required the reserve fund be maintained at a minimum of 25% of the charter fund (additional discussions of the charter fund will be in the final article).

• Social fund. Typically 5% of the remaining income after the reserve fund deduction is designated for the social fund. This fund pays for food and housing, pension and social benefits camps, medical, equipment, schools, and other costs related to maintaining the infrastructure and improving the lifestyle of the workers. The "infrastructure cost" expended during the development phase is characterized as part of the social fund.

OTHER

• Bonus. A bonus payment made the first year is customary and is a means for the autonomous republics, oblasts, okrug, or krays to receive cash prior to the project having a cash flow or generating a profit.

• Land rental. Land rental, also called lease rental, is paid for the surface use of the land, and use of gravel, timber, and water for camp and field operations.

• Depreciation. AU capital tangible items are depreciated on a three-year, straight-line schedule. All intangible items are expensed the year they are incurred.

• Tax holiday. Joint ventures approved in 1992 do not qualify for tax holidays because of the tax law changes; however many joint ventures are requesting a holiday (based on the old laws) in order to improve the project economics.

• Environmental. Costs may need to be included in the cash flow calculations to account for environmental studies and also for environmental work in the fields and/or the area of the joint venture.

The cash flow calculation sequence in the table is for a waterflood development project. Development of the field is estimated to take seven years to drill. Production begins in year two and continues for about 36 years, at which time the field reaches an economic limit for the assumed taxes and costs.

The table only shows the cash flow calculations for the first 20 years. These calculations are for the western partner on an after-tax basis and assume all the required capital is provided by the western partner.

For this example, during a 20 year life, approximately 120 million bbl of crude are produced. This results in a gross revenue to the western partner of $1.513 billion, assuming a constant oil price of $20/bbl. After the deductions for revenue tax operating costs, funds, and total taxes, the project returns to the investor an estimated undiscounted $112 million.

The project has a payout of about 8.6 years and has an internal rate of return of 13.3%. These calculations assume all of the beforementioned taxes and funds are deducted from the revenues. The table shows the western partner has gross revenues of $1.513 billion, pays $801 million in taxes and funds, about $300 million in operating costs, and nets a cash flow of about $112 million.

The current taxes and taxation rates have a significant effect upon the economics for these projects. Sensitivity analyses of the taxation rates shows project economics can be greatly improved by small changes in current tax rates.

Tentative joint venture structures bidding procedures, registration procedures, and tax treaties will be discussed in the final article in this series.

REFERENCES

1. Connelly, William, and Krug, J.A., Evaluating oil, gas opportunities in western Siberia-log and core data: OGJ, Nov. 23, 1992, p. 97.

2. Connelly, William, and Krug, J.A., Evaluating oil, gas opportunities in western Siberia-reservoir description: OGJ, Dec. 7, 1992, p. 83.

3. Krug, J.A., and Connelly, William, Here are considerations in evaluating Russian flow tests, reservoir performance: OGJ, Dec. 28, 1992, p. 102.

4. Ivanova, M.M., Semin, E.I., Surguchev, M.L.,and Baishev, B.T., Ways to improve oil field development schemes based on operation experience analyses, All Union Oil-Gas Research Institute, Vol. 10, 1 Dmitrovsky St., Moscow.

5. Chesnut, D.A., Cox, D.O., and Lasaki, G., A practical method for waterflood performance prediction and evaluation, Pan American Congress of Petroleum Engineering, Mexico City, Mar. 19-23, 1979.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.