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CHAPTER III PRINCIPAL FINDINGS MISLEADING TERMINOLOGY Proved and Probable "Reserves" The terms resource and reserve are among the most misused technical expressions associated with discussions of mineral or energy commodities. There terms have been defined in a joint USGS-USBM release (April 15, 1974) as follows: Resource: A concentration of naturally occurring solid, liquid or gaseous materials in or on the earth's crust in such form that economic extraction as a commodity is partly or potentially feasible. Reserve: That portion of the identified resource from which a usable mineral or an energy commodity can be economically and legally extracted at the time of determination. The term ore is also used for reserves of some minerals. Inclusion of the economics of extraction in each definition is considered essential to the intended meaning of the terms. Gas reserves so defined, can also be classified further as proved or probable. If conclusive formation tests are available or if gas is actually being produced, a reserve is considered to be proved. If neither of these conditions is present, the reserves are designated as probable. The FPC report describes the term proved reserves to mean "the estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known natural oil and gas reservoirs under existing economic and operating conditions" (FPC II: page 4). The definition is changed substantially, 23
24 however, by a footnote on the same page which states that "for purpose of this report all volumes physically recoverable are considered to be economically producible." Correspondingly, in the FPC report the term probable reserves refers to "the established quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known natural oil and gas reservoirs under existing economic and operating conditions." Again, the same qualification with regard to economics is applied (FPC II: page 4). Thus all "reserve" figures given in the FPC report are defined on a physical basis rather than an economic one and all volumes of gas that are physically recoverable are considered to be economically recoverable. In the estimates of physically producible gas, it is assumed that a well will be located on the highest point of the structure (which would be fortuitous) and that the rate at which the gas can be extracted without problems will not be taken into consideration. Thus, in using the term physically producible gas, no consideration is given either to the economics of extraction or the time required to recover the gas. (It may be noted that the amount of physically recoverable gas will not be the same as that of gas in place, because the former depends upon the nature of the mechanism driving the gas and whether the gas is associated, non-associated, or solution gas.) Thus, the usage of "reserve" in the FPC report, even in the restricted connotation of a physically recoverable volume of gas, is misleading and tends to confuse professional and non-professional readers alike.
25 Gas in "Paying Quantities" A producible shut-in lease is defined as follows: (1) at least one well has been drilled on it; and (2) It is determined by USGS to be capable of producing in paying quantities; and (3) a suspension of production or operation has been approved by the USGS Supervisor. For purposes of determining paying quantities in connection with the production of oil or gas in the Gulf of Mexico area of the outer continental shelf, the criteria identified in USGS-OCS Order No. 4 (August 28, 1969) specify the following requirements: "A well may be determined to be capable of producing in paying quantities when the requirements of either (1) or (2) below have been met. 1. Production Tests - A deliverability test of at least two hours duration, following stabilization, or a four-point back-pressure test, is required. 2. Production Capability a. An induction-electric log of the well, clearly showing a minimum of 15 feet of producible sand in one section which does not include any interval which appears to be water saturated. All of the section counted as producible must exhibit the following properties: (1) Electrical spontaneous potential exceeding 20 negative millivolts beyond the shale base line. If mud conditions prevent a 20 negative millivolt reading beyond the shale base line, a gamma ray log deflection of at least 70 percent of the maxi- mum gamma ray deflection in the nearest clean water bearing sand may be substituted. (2) A minimum true resistivity ratio of the producible section to the nearest clean water sand of at least 5:1, provided the producible section exhibits a minimum resistivity of 2.0 ohm-meters. (3) A porosity log indicating porosity in the producible section.
26 b. Sidewall cores and core analysis which indicate that the section is producible. c. A wire line formation test or evidence that an attempt was made to obtain such a test. The test results must indicate that the section is producible. d. All logs run must support other evidence that the section is producible." Thus, qualification requirements for gas well classification as "capable of producing in paying quantities," according to 0CS order No. 4, are based upon physical parameters only and constitute a definition of the term without mention of economic considerations. The term paying quantities, however, is an economic term and refers to the production of crude oil or natural gas in an amount sufficient to enable the operator to realize a profit. Depending upon the usage of the term in an oil or gas lease, the economic criteria for achieving paying quantities differ. For purposes of keeping a lease in force after expiration of the primary term, paying quantities refers to the production sufficient to yield a return in excess of operating costs without regard to cost incurred in the drilling of the producing well or in the acquisition of other capital equipment. For purposes of determining the duties of the lessee under the covenants of the lease, however, the term paying quantities means production sufficient to yield a return in excess of drilling, development, and operating costs. Paying quantities, therefore can be based on different economic criteria, and the context of the usage must be determined to understand the specific intended meaning of the term. Although it is not explicitly stated in OCS Order No. 4, it is reasonable to assume that the term paying quantities is used in the context of return
27 in excess of operating costs. In this context, no consideration is given to either the cost of drilling the production well or the cost of installation of the production platform, the gathering pipeline, the gas compressors and other capital equipment and use of the term paying quantities as an economic classification without mention of economic criteria is misleading. Relevant comment on misleading economic implications of the terms producible shut-in and paying quantities is offered in the FPC report: "It is obvious from the staff investigation that very few of the wells on producible shut-in leases are capable of being produced. Almost all the wells were temporarily abandoned or plugged and abandoned after qualifying as'a well capable of producing in paying quantities.1 These wells were initially temporarily abandoned by having cement plugs spotted in accordance with USGS regulation and were left with under- water casing stubs extending above the sea floor with marking buoys extending to the sea surface. If the operator does not plan to re-enter and actually complete the well within a reasonable period of time, the USGS requires the removal of the underwater casing stub because it is a hazard to the shipping, fishing and shrimping industries. When the underwater casing stub is removed, additional cement plugs are spotted and all pipe is shot off a minimum of 15 feet below the mud line. There is little or no possibility of re-entry into the well. Indeed, it may even be difficult to locate the well again. It can generally be stated that the lease operator normally never intended that all the wells drilled on producible shut-in leases would be
28 completed as actual producing wells. Many of these exploratory wells are classified as 'expendable holes' which are drilled solely to develop geological data from which to plan the location of drilling and production platforms and to formulate development programs. On occasion, one of the temporarily abandoned wells is situated at the planned location of a platform, Great difficulty can be encountered in positioning the platform in exactly the correct spot over the well, so it is rare when an expendable hole can be utilized in this manner. After a platform is set, the operator will often drill all the wells in his program without completing any of them as a producer. After the drilling program is finished, the operator will then selectively complete the wells capable of production." (FPC II: p.. 19)
29 GAS ESTIMATION Techniques and Procedures Volumetric gas reserve estimates are based on estimated thickness and areal extent of gas-bearing reservoir rocks, modified principally by factors of rock porosity, interstitial water content, and recoverability. Estimates of gas reserves for the producible shut-in leases in the Gulf of Mexico can only be of the volumetric type due to lack of production history. The designation of lease status as "producible shut-in" indicates that at least one well has been drilled on the lease that has been tested for or given other evidence of producible gas; but it also implies that for one reason or another commercial drilling development of the lease has been held up. (see p. 18). Consequently, because most of such leases lack the estensive well information that is commonly available for producing leases, their reserves cannot be as reliably estimated. Estimates can be expected to vary considerably from one competent investigator to another owing to the lack of factual information about many of the factors on which estimates are based. Atwater, Carter, Miller, and Heffner, commented on estimate variation in their report as follows: "There is no way to develop sufficient high quality data on a hydrocarbon reservoir so that two competent appraisers will independently produce the same estimate of reserves. All of the physical parameters used in a reserve determination are subject to interpretation to some degree depending upon the quantity and quality of the data available. The Impact of interpretation is greater for some parameters than for others. For instance, the determination of porosity and connate water saturations may result in a variation on the order of 10 to 15 percent in the reserve numbers of different appraisers. Significant differences commonly
30 occur in the application of recovery factors, the anticipated amount of the gas reservoirs these differences may be on the order of only 10 percent, the average thickness of the reservoir and the sand volume may vary subtantially depending upon the methods used in constructing the isopachous maps and the structural configuration of the reservoirs. With only a few wells it is not uncommon in the industry for one estimate to be two or three times the estimate of another appraiser using the same data. The more data available to experienced appraisers the closer will be their estimates. The single parameter most likely to cause the widest difference in estimates is the reservoir size, and the fewer wells there are, the more likely that difference will be great" (Appendix B). The major controlling factors of thickness and areal extent of the offshore gas-bearing reservoirs in this highly fractured area, when only a few wells are available to supply data, must be based on extensive extrapolation of structural and sedimentational conditions, guided by experience in the area. Opinions on interpretation of sparse data in such a geologically complex area may reasonably vary quite widely. The variables of reservoir acreage and thickness are not independent, since the sand thickness is usually a function of the shape and size of the reservoir. The acreage is very much independent upon the degree of informational control of the structure by well or geophysical data. The principal cause for the higher "reserves" shown by FPC as compared with those estimated by the consultants appears to be FPC's consistently larger estimate of the areal extent of the gas-bearing reservoirs in this highly fractural area. In general, this appears to be due to greater optimism in the interpretation of geologic structure resulting perhaps from pressing time demands for the task and less offshore estimation experience. In general the FPC has also tended to use somewhat greater sand thickness. In the area under consideration, the reservoirs are mostly sand bodies of
31 varying thickness, bounded by faults or changes in permeability. Most of the reservoirs are associated with salt structures; the movement of the salt has not only deformed the rock units but has caused many faults that limit the size of the individual reservoirs. Any given lease may contain a number of separate reservoirs at similar depths or at quite different depths. Another factor contributing to the difference in estimates is the number of sands reported. In the FPC report, sand thicknesses less than nine feet were not included unless they had been tested, whereas in some instances the consultants included sands as thin as two feet. Sand bodies separated by shale stringers were sometimes grouped into a single reservoir and sometimes treated separately. (Discrepancies between the estimates of the two consultants themselves, in the few cases where they are large, appear to be due largely to differences in structural interpretation and in number of sands considered.) Figures for porosity and interstitial water content are likewise dependent on well information, although they should be somewhat less subject to variation between different investigators, because they are based on more or less standard methods of determination from such well logs or samples as are available. Very similar porosity figures have been used by all three estimators, but consistency in porosity is offset by surprisingly wide variations in figures for interstitial water content. The figures assumed by the different estimators for the degree of water saturation sometimes varied by as much as 64 percent. This variation contributed to the difference in gas estimates. The recovery factor that is assigned
32 by different investigators is also a more subjective factor for offshore leases without a production history and may vary considerably between individual estimators. On the average, the FPC staff used a gas recovery factor of about 78 percent. That used by Atwater averaged about 63 percent; that used by Keplinger averaged about 66 percent. This would result in the FPC results being larger by 12 to 15 percent even if all other factors were equal (see Appendix C for discussion of recovery factor). Both high and low estimates as well as a most likely estimate have been provided by the consultants for this report to allow for the uncertainties involved in determining the amount of physically producible gas in a reservoir. These uncertainties, reflect reasonable and rational differences in the interpretation of available data. The high and low estimates for each reservoir thus present a more realistic picture of the uncertainties associated with the determination of physically producible gas. Estimates of Physically Producible Gas The Panel made a detailed analysis of variation in estimates for 19 of the 33 leases examined by FPC and the consultants with special attention given to those in which variations in "reserve" estimates were large. (See Table 4) The differences in "reserve" estimates can be attributed mostly to errors and different values used for reservoir acreage, reservoir thickness, and the gas recovery factor. The Panel found a number of errors in the calculations of acreage of reservoirs. In five cases, the FPC personnel made errors in calculating acre feet from planimeter data. In one instance, the data from two wells were plotted wrongly giving a fictitious structure. In several cases a reservoir
33 TABLE 4: EXAMPLES OF VARIATION IN ESTIMATES Lease Code Recoverable Dry Gas (MMcf) Atwater Keplinger FPC 005 762 8,275 12,345 Variation due to poor control. 019 187 752 60,365 FPC estimate la too high because of planlneter error and Inadequate data. Atwater claimed that using IES as only available data, no way to assign any type of gas reserves to any sand numbers between 7880-8120 where FPC had large quantities. 024 8,928 9,815 8,668 Data adequate, interpretations essentially the same. 027 7,272 12,804 52,538 In this case FPC assumed no geologic faults in the structure while both consultants did, but in different places. Electric logs con- sistent with faulting although channelling or pinchout is possible. 035 826 3,165 8,029 FPC Included entire volume of reservoir rather than only that part or lease in question, thus obtains large value. Keplinger varies dip and fault azimuth and Is larger than Atwater. 043 41,612 188,488 211,163 The very large variation here is due to differences in interpretation of faults. Atwater used both well and seismic Information, it ia not clear If full advantage was taken of all available data by the others. Keplinger plotted one fault on the wrong side of a producing well. The Panel favored Atwater's interpretation. 049 407 4,235 8,583 Variation* due to generally poor geological control. 056 5,863 777 11,449 FPC error In planlmeter calculations resulted In about 50 percent increase in acre feet. Other variations due to lack of control â nearest well is 8,000 feet distant. Considerable differences in contouring result from this. 073 105,959 69,737 316,143 Here again It appears that FPC included the acreage of the whole reservoir, not just the portion on the lease in question. This not' only increases the acreage, but also the mean sand thickness. 093 3,678 20,812 96,425 As a result of misplottlng the data from two wells, FPC reservoir is on the opposite side of a fault from that of consultants. In addition, FPC and Keplinger have an extra reservoir and identify one reservoir as non-associated gas that Atwater calls solution. 098 7,921 9,424 16,930 Data are reasonable, differences due to contouring and recovery factor. 102 5,651 8,146 33,139 Poor control, faults drawn by consultants at right angles to those of FPC. Atwater and FPC had one simllar fault, but with reservoir on opposite sides. Keplinger indicates more faulting would reduce estimates. 117 116,056 167,751 175,076 Difference between high and low estimates reflects a combination of a 10 percent difference in recovery factor, 25 percent difference in acreage and 10 percent difference in thickness of sands. This is coupled with reasonable variations in interpretations. 121 21,050 14,189 56,071 This is a complex lease with fairly good control. The big difference is in sand thickness. Keplinger appears to have left out one sand body. If included, it would approximately double the estimate. 123 1,895 7,971 45,435 Consultants varied in acreage and thickness in their Interpretation but both appeared reasonable. The Panel could not understand the rationale for the FPC interpretation which was on the opposite side of a fault and a doraal reservoir rather than a fault sliver. 126 56,817 18,579 84,613 There were major differences in interpretation on this lease. All seem possible on basis of control. There has been no further development on this lease suggesting that the lowest estimate may be most reasonable.
34 was planimetered across a lease line; the portion that fell in the other lease was included with the lease in question. In one case, Keplinger grouped two sands together and then used the thickness of only one sand in calculating acre feet. In all cases but the last, the errors increased the "reserve" estimates. In general throughout this offshore region, experience shows that more data tends to reveal a more complex geologic structure with more subdivision of reservoirs by structural fracturing. Estimates of reservoir volume for the 33-lease representative sample taken for examination by the Panel from the total of 168 leases classified as "producible shut-in" by the USGS as of January 1974 are shown in Figure 3. Estimates of dry recoverable gas are shown in Figure 4 and in Table 5. Comparative summary data giving figures used in calculating dry recoverable gas for individual leases and reservoirs in the 33-lease sample is presented in Appendix B. Dry Recoverable Gas (MMcf) Estimator Range Proved Probable Total Percent FPC FPC Best 1,073,421 386,853 1,460,274 100.0 Atwater High Best Low 410,047 318,882 240,225 186,140 132,348 86,398 596,187 451,230 326,623 30.8 Keplinger High Best Low 603,711 441,161 348,577 340,249 209,876 189,430 943,960 651,037 538,007 44.6 Table 5. Estimates of recoverable gas for 33-lease representative sample of producible shut-in leases.
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37 The outstanding point shown by the foregoing data is that for almost all individual leases the FPC estimates are higher (in certain cases markedly so) than those of either of the two consultants. As a consequence, the total "reserves" given by FPC for the 33-sample leases are from two to three times higher than those given by either of the two consultants. The two consultants are, with only a few exceptions, in close agreement with each other.
