The petroleum industry has written extensively on the risk associated with exploration. Very little has been published, however, addressing the risks associated with acquisition and operation of producing properties. Because capital budgets usually depend on the income a company realizes from its producing properties, and because current conditions have been interpreted by many to favor the acquisition of existing oil reserves over exploring for new ones, the risk in estimating reserves and in estimating future cash flows for producing properties has taken on a new importance.The risks associated with estimating the reserves and value of a hydrocarbon-producing property are divided into three classifications: (1) the technical risk that the hydrocarbon values estimated by the geologists and engineers do exist in the ground and that the recoverable amounts can be recovered within the time frame projected by the engineers; (2) the economic risk that product prices, operating costs, equipment costs, inflation, and market conditions will be in reasonable agreement with the assumptions used in the economic analysis; and (3) the political risk that world economics, international political stability, taxation, and regulations will not be significantly different than projected in the evaluation.This paper focuses on these risk categories and presents methods for implementing risk estimates in the evaluation of a producing property, taking into account the maturity of the technical data, the location, and the life of the property. A Glossary of important terms is included.

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleum engineering. Introduction The life-style of 20th-century man has been influenced more by oil and gasthan any other natural resource, and indications are that oil and gas reserveswill increase in importance the remainder of this century. Oil and gasproduction provides inexpensive portable energy and supplies feedstock to anportable energy and supplies feedstock to an international petrochemical industry that manufactures synthetic textiles and medicines and supports worldagriculture. Crops are planted, cultivated, treated with pesticides, fertilized, harvested, moved to market, and pesticides, fertilized, harvested, moved to market, and cooked with oil and/or gas. Wars have been fought to ensure petroleum availability, and reserveestimates have dictated actions of governments, entire industries, individual companies, lending institutions, and private investors. Many petroleum engineers spend a major part of their professional lives developing estimatesof reserves professional lives developing estimates of reserves and production capabilities, along with new methods and techniques for improving theseestimates. To understand the confidence levels and risks of the estimates, aclear and consistent set of reserve classifications must be used. The confidence levels and the techniques implemented by the petroleum engineer depend on the quantity and the maturity of the data available. The dataquality, therefore, establishes the classification assigned to the reserve estimates and indicates the confidence one should have in the reserveestimates. Almost all applications of oil and gas reserve estimates require, in thefinal analysis, an economic evaluation that considers the predicted production capacity and the capital and operating cost estimates. The economic analysis isthe thermometer used to indicate the health of the reserves owner and will berepresentative and reliable only if the data, reserve estimating procedures, and reserve classifications are understood and applied properly. Reserve Classification and Nomenclature The need for one universal classification and nomenclature system forpetroleum reserves has long been recognized by the various technical societies, professional organizations, governmental agencies, professional organizations, governmental agencies, and the petroleum industry. In spite of the need for astandardization of definitions and concepts, differences in definitions continue to cloud the absolute meaning of reserve definitions published bytechnical societies and regulatory bodies. The societies have established studygroups to recommend a classification system; however, a universal systemacceptable to all estimators and users has not been agreed upon. A study group established in 1980, consisting of representatives of oilproducing countries, recommended a set of definitions and classifications. Ajoint committee of SPE, AAPG, and API developed a set of definitions and aglossary of terms in 1981. These definitions, considered consistent with U.S.DOE and Securities and Exchange Commission (SEC) definitions, are presentedhere along with my comments on their use. Proved Reserves. Proved reserves of crude oil, Proved Reserves. Provedreserves of crude oil, condensate, natural gas, or natural gas liquids areestimated quantities as of a specific date, which geological and engineering data demonstrate with a reasonable certainty to be recoverable in the futurefrom known reservoirs under existing economic conditions. JPT P. 373

Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering. Summary Fair-market-value (FMV) determination is now used not only to set a purchaseprice but also to determine the best investment. Various methods fordetermining an FMV have been used, all in attempts to protect a purchaseragainst the uncertainties that might render an acquisition imprudent. Thispaper reviews frequently used FMV guidelines and presents a method for theirsimultaneous use to evaluate a hydrocarbon-producing property. Introduction The current acquisitional tendencies of the U.S. oil industry have increasedthe importance of determining the best investment among many options. FMVdetermination is now used not only to set a price, but also to select theinvestment. The FMV for a producing property is not a unique value derived bysolving an equation; rather, it is a subjective estimate reflecting theexpectations of the buyer and the seller at the time of trade. Any change inthe economic outlook will likely change the estimated FMV, but not necessarilythe method used to derive it. The various methods used to estimate the FMVnever yield exactly the same value, but they usually establish a range. Becausean FMV may be required to estimate a collateral value for a bank loan, tosettle litigation, or to establish tax liability, the appraiser isusuallequired to establish a single value estimate rather than a range. Theappraiser estimating the FMV, therefore, must have a good knowledge of thevarious FMV guidelines used in the industry and must know their strengths andweaknesses to narrow the range. Definition There have been several definitions of FMV, but the one cited mostfrequently in the petroleum industry is "the amount a willing buyer will pay awilling seller, with the property or interest exposed to the market for areasonable period, neither the buyer nor the seller being under a compulsion tobuy or to sell, both being competent and having reasonable knowledge of thefacts." Unfortunately, this ideal situation rarely, if ever, exists. The sellerusually is under pressure to liquidate some asset. There may be a cash needwithin the company, or a more attractive investment opportunity may arise. Inprivate companies, the proprietor may reach retirement age. The acquisitionsvice president of the buying company may need to purchase something to confirmthe importance of his job. The definition also assumes that the buyer isknowledgeable. The seller of the property, who is associated with theoperations of the subject property, is usually in a better position to know thepositive and negative aspects of the property. The negative may not bepresented to the prospective purchasers, while the positive certainly will be. Of course, there are times when the property may have greater value to thepurchaser than to the seller. This sometimes occurs when the purchaser is theend-user of the oil or gas and is buying the production to ensure a feedstockor an energy source for day-to-day operations. Steel mills, breweries, andglass plants have purchased gas-producing properties to guarantee a source ofeconomical energy during potential periods of fuel shortage. Confusionsometimes exists about the terms present worth (PW) and FMV. Too often, non-petroleum-industry personnel think that the PW of a hydrocarbon-producingproperty is the FMV, or the value at which the property would change hands. This notion is understandable because, when we speak of almost any item we own(e.g., an automobile). its PW is its price. The difference. of course, is thatmost items we buy or sell are not incomeproducing. The meaning of PW changeswhen we speak of values that result from income to be received in the future. In this instance, PW is merely the value today of those future revenues. Methods for Determining FMV The various methods for determining FMV fall into four generalcategories:comparative sales, rule-of-thumb. income forecast, and replacementcost. All the methods attempt to establish a fair price for a property thatprotects the buyer against all foreseeable business uncertainties and risks. These uncertainties, which may render the purchase imprudent, includetechnological, economic, and political concerns. The technologicaluncertainties include the possibility that the reserves might not be recoveredin the amounts or at the rates forecast.

Rodgers Jr., John S., Member AIME, This paper was prepared for the 41st Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Dallas, Tex., Oct. 2–5, 1966. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Pressure transient tests when properly conducted and interpreted, offer valuable information to any exploration, development or production venture. Determinations of hydrocarbon volume initially in place, stabilized reservoir pressure, distance to a reservoir rock or fluid discontinuity, distance to impermeable barriers, extent and orientation of a fracture system, porosity-thickness, completion efficiency, formation damage and permeability-capacity are often obtainable from one or more of the various types of pressure transient tests. Knowledge of these factors when considering alternate investment opportunities can enable prudent decisions. A pressure transient is a pressure gradient or disturbance created by altering the equilibrium of a reservoir system. This occurs not only when new wells are completed, but each time the flow rate of a producing well is altered. In pressure transient can be analyzed to reveal the above factors. The mathematical analysis can be facilitated if the transient is established under controlled conditions. Transient tests are usually designed to meet the requirements imposed by the mathematics describing fluid flow through a porous media for the reservoir system being considered. For the purposes of this paper, only radial systems are discussed because they have the most application. A pressure transient test in a hydrocarbon reservoir has been compared to throwing a stone in a pond of water. When a stone hits the water ripples move out radially at a fixed rate contingent on the environmental conditions. The size of the stone will affect the amplitude of the transient but amplitude will not alter the speed of its propagation. If the wave hits a barrier such as the edge of the pond, it will be reflected. A similar occurrence is observed in the reservoir when the rate of production from a well is altered. A pressure transient radiates from the wellbore at a velocity which is a function of both reservoir rock and fluid properties. As in the case of the pond, if the transient encounters an environmental alteration, it will be reflected to the well. The amplitude of the transient is not related to the radial velocity of the transient; therefore, the analysis of the transient is theoretically independent to its amplitude.

Introduction The natural-gas industry in the United States had its beginning in 1826 when natural gas was used for lighting the city of Fredonia, N. Y. The first natural-gas pipeline was a 25-mile wooden line constructed from hollow logs connecting West Bloomfield and Rochester, N. Y. There are no records indicating that a gas deliverability study was ever made here to determine the economics of installing this line, but it is recorded that an attempt was made to determine the capacity of the wells by measuring the time required to fill a large balloon. Thus, since the inception of the gas industry, engineers and operators have endeavored to develop easier methods for making deliverability studies. A gas deliverability study may be considered a projection of the annual rates at which volumes of gas reserves may be received into a gathering system. Such a study may cover a 20-year period and involve calculations on scores of wells. Studies have been and are being made manually - the repetitive calculations requiring thousands of man-hours. Manually, these calculations involve the use of curves and tables. The reading of these through many repeated calculations is slow and lends itself to inaccuracy if not to error. Because deliverability studies are required by the Federal Power Commission when gas transmission companies propose expansion, are used internally by companies for cash forecasts and budgets, are necessary in evaluating proposed line extensions into new gas supply areas and are foundations for gas-property financing, we, as petroleum consultants, are frequently asked to perform such studies. Because of the widely different possible uses of such studies and the infinite number of variables involved such as allowable, price escalation, producing practices, contract variables, field rules, etc., it is impractical to develop a program so general as to handle every and all situations. Likewise, it has proved inconvenient to completely rewrite a new program for each situation. THE NEW PROGRAM The program I offer for your inspection is one which covers several situations and one which I feel can be modified to fit almost all conditions. It is divided into blocks. The applicable ones for a specific problem provide a complete calculating procedure. A flow diagram for the blocks is presented in Figs. 6 and 7. The procedure has been programed in FOR-TRANSIT language and can handle up to 20 well reservoirs on the IBM 650 and 50 well reservoirs on the IBM 704. A larger system might store all the program blocks and utilize internal switching to develop the complete calculating procedure for a greater number of wells; however, the number 20 is not too restrictive, because similar wells can be lumped together in groups and handled as one well. The program considers allowables set by regulatory bodies or will generate an allowable based on the well's absolute open-flow potential. In the past, manual calculations to eliminate trial-and-error solutions have been based upon increments of reservoir pressure or increments of production. An engineer would arbitrarily assign an increment and solve for the resulting well deliverabilities. The well deliverabilities then were obtained related to production or pressure increments, but not in terms of time.