Gas Reserve Estimation of Offshore Producible Shut-in Leases in the Gulf of Mexico: A Report (1976)

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APPENDIX B RESERVE ESTIMATES NARRATIVE PORTION OF REPORT BY ATWATER, CARTER, MILLER & HEFFNER, NEW ORLEANS, LOUISIANA TO PANEL ON GAS RESERVE ESTIMATION ESTIMATED PHYSICALLY PRODUCIBLE GAS THIRTY-THREE SHUT-IN LEASES GULF OF MEXICO OFFSHORE LOUISIANA AND TEXAS AS OF MARCH 1, 1974 Summary of Report All data available as of March 1, 1974, on 33 shut-in leases in the Gulf of Mexico, offshore Louisiana and Texas, were studied in order to determine, using normal industry practice, the "physically producible" gas in each reservoir on each of the 33 leases. Similar data from adjacent leases that provided additional control for establishing productive limits were also studied. The term "physically producible" gas was used to convey the understanding that no economic parameters were included in any of the determinations. In this study, all gas determined to be physically producible from a reservoir where some form of flow test or bottle test has been conducted on or before March 1, 1974, is designated as "proved." Where no flow or bottle test had been conducted, the physically producible gas is designated as "probable." The physically producible gas was estimated for each reservoir on each of the 33 shut-in leases studied by the volumetric method. A total of 111 122

123 reservoirs were determined to contain physically producible gas. The total gas recoverable from the 33 shut-in leases is estimated at 451,230 MMcf of which 318,882 MMcf are designated as proved and 132,348 MMcf as probable. In addition to determining the physically producible gas, a range of estimates (high and low) were calculated for each reservoir and lease by applying factors reflecting the quantity and quality of the available data. For the 33 shut-in leases studied, the high estimate is 410,047 MMcf proved and 186,140 MMcf probable for a total of 596,187 MMcf. The low estimates totaled 326,623 MMcf of which 240,225 MMcf are designated as proved and 86,398 MMcf as probable. Introduction This report presents the results of a study of 33 shut-in leases in the Gulf of Mexico, Offshore Louisiana and Texas. The study was made at the request of the Program Officer, Dr. Robert S. Long, Executive Secretary of the Board on Mineral Resources, National Academy of Sciences. It was made in compliance with the technical directions contained in Section A— Scope of Work of the contract and other instructions from the Panel on Gas Reserve Estimation which were transmitted by Dr. Long. The data are presented herein in accordance with the instructions and on the forms furnished by Dr. Long. The work was performed by the four partners in the consulting firm, namely 0. R. Carter, E. E. Miller, R. E. Heffner and W. G. Sinclair, each with more than 20 years experience appraising oil and gas properties with special emphasis on South Louisiana. All data available as of March 1, 1974, on the 33 leases were studied in order to determine, using normal industry practices, the "physically

124 producible" gas in each reservoir on each lease. These data included lease and well files, copies of all logs, core analyses and descriptions, drill stem tests, pressure data and other test information from each well on every lease included in the study. Similar data from adjacent leases that could provide additional control for establishing productive limits of reservoirs were also studied and the available structurally contoured seismic maps were reviewed. All data studied were from the files of the U.S. Geological Survey and were examined in their offices in Metairie, Louisiana. The data were generally of good quality. There was an induction- electrical log, one or more porosity logs, a dip log and a number of sidewall cores for most wells. The quantity of data was more than might be expected on shut-in leases. Even on leases with one reservoir, hydro- carbon bearing in only one well, there were in most instances several other wells either on the lease or on adjacent leases. The term "physically producible" gas was used to convey the meaning that no economic parameters were considered in the reserve determinations. This definition is in contrast to normal practice where the term "gas reserves" implies economically recoverable gas. In this study all gas determined to be physically producible from a reservoir where some form of flow test or bottle test had been conducted on or before March 1, 1974, is designated as "proved". Where no flow test or bottle test had been conducted the physically producible gas is designated as "probable". The general procedure followed in studying each lease was to first review the lease files (correspondence, plan of development, etc.) and the file on each well. The logs were correlated and the total net feet of sand and the net effective feet of hydrocarbon bearing sand were

125 determined. These data were then used to construct structural and iso- pachous maps. The volume of sand containing physically producible gas was determined from the structural and isopachous maps for 107 of the reservoirs studied. On the other four reservoirs there were insufficient data avail- able to construct adequate structural and isopachous maps, and sand volumes were estimated based on an arbitrary assignment of a reasonable productive area and an average net sand thickness. The physical properties of the reservoirs and the properties of the hydrocarbons contained therein were determined using all available informa- tion. Using these properties and standard industry methods, the volume of gas in place per acre foot of sand volume was calculated for each reservoir. The total volumes of gas in place were calculated by the volumetric method, multiplying the gas per acre foot by the sand volumes determined from the structural and isopachous maps or acreage assignments and average sand thickness. For each reservoir the volume of gas in place was then multiplied by a calculated recovery factor to estimate the volume of physically producible gas. The total physically producible gas for the 111 reservoirs on the 33 shut-in leases studied is estimated to be 451,230 MMcf of which 318,882 MMcf are designated as proved and 132,348 MMcf as probable. In addition to determining the physically producible gas in each reservoir and lease, a range of estimates (high and low) was calculated by applying factors reflecting the quantity and quality of the data available for determining sand volumes in as much as by definition physically producible gas does not consider economics. The high estimates totaled 596,187 MMcf of physically producible gas, of which 410,047 MMcf are

126 designated as proved and 186,140 MMcf as probable. The low estimates totaled 326,623 MMcf of gas, 240,225 MMcf proved and 86,398 MMcf probable. 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 occur in the application of recovery factors, the anticipated amount of the gas in place in a reservoir to be recovered at the surface. For gas reservoirs these differences may be on the order of 25 percent and could be more than 100 percent for oil reservoirs in the event one appraiser assumes a water drive mechanism and the other assumes a depletion drive. Although determinations of the net sand in each well are expected to vary on the order of only 10 percent, the average thickness of the reservoir and the sand volume may vary substantially 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 good data available to experienced appraisers the closer will be their estimates. The single

127 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. Determination of Volume of Sand Containing Physically Producible Gas The volume of sand containing physically producible gas was de- termined from structural and isopachous maps for 107 of the 111 reser- voirs studied. Sand volumes were determined for the other four reser- voirs by the acreage assignment method. Structural maps were used to determine the limits or areal extent of the gas or oil accumulations. In order to construct these maps the induction-electical logs of all wells on a lease and the logs of wells on adjacent leases that could provide additional control were correlated to determine the depths of all reservoirs in each well, the depths and magnitude of faults and depth of salt if reached. On directionally drilled wells (holes drilled other than vertically) the depths read from the logs were converted to true vertical depths. Dip logs were reviewed to determine the direction and amount of dip. To determine the total and net effective porous and permeable sand in each reservoir in each well all pertinent material, induction - electrical logs, porosity logs, sidewall core and test data were evaluated. The data were tabulated by reservoir and transferred to map overlays used in conjunction with loca- tion plats showing the surface and bottom hole location of each well. The available seismic interpretations, producer and other structural interpretations in the U. S. Geological Survey files, were reviewed.

128 Fault contour maps and top of the salt maps were prepared where con- sidered necessary for determination of reservoir limits and where there was adequate well control for constructing such maps. Structural maps from which the limits of the individual hydrocarbon accumulations were determined were then constructed for each reservoir. The downdip, or lower limit, of each accumulation was either a gas-water contact or an oil-water contact observed on the well logs, or the base of hydrocarbon bearing sand in the lowest well in the reservoir where a water contact was not seen. For discontinous sand reservoirs, where the areal ex- tent of the sand is a limit, the position of that limit was determined from total net sand isopach maps constructed using the total net sand counted in each well, or the sand pinchout mid-point method was employed, whichever was more appropriate considering the quantity of information available. A net sand isopach map was constructed for each reservoir based on the net effective hydrocarbon bearing sand counted in each well, using the total sand isopachous map and using the structural map. The structural map provided the position of outer limits of the accumula- tion and the position of the gas-water, gas-oil or oil-water contacts on the top and base of the sand. The volume of sand containing physically producible gas was determined from a planimetric survey of the net sand isopachous map. The planimeter form showing the determinations for each reservoir are included in this report. Using this method the area of each hydrocarbon accumulation was determined in acres and the average thickness in feet. Multiplying the area by the average thickness results in the sand volume in terms of acre feet.

129 In four reservoirs the available data were insufficient for the preparation of maps necessary to sand volume determination as described above. For each of these four reservoirs an acreage assignment and an average sand thickness was used to determine the sand volume. The total estimated physically producible gas for these four reservoirs is 5,466 MMcf. Determination of the Physical Properties of the Reservoirs The four physical properties of the reservoirs used directly in estimating the physically producible gas by the volumetric method are porosity, interstitial water saturation, pressure and temperature. Perm- eabilities were considered only with regard to the ability of hydrocarbons to flow from a sand into the well bore. All available information was studied and only the data consider- ed most reliable were used to determine the average porosity for each reservoir. A substantial number of sidewall core analyses were avail- able and there were porosity logs on most wells. Weighted average porosities from the sidewall cores were used for most of the reservoirs studied. The average porosity for a few reservoirs with either no data or data considered unreliable were estimated from a plot of porosity versus depth based on 17,367 conventional cores taken in wells located in South Louisiana. The average porosity for the 111 reservoirs studied was 28.8 percent. The average is somewhat lower than would be esti- mated for comparable depths using the plot of conventional core data. This tends to confirm the impression gained in studying all the logs,

130 core data and core descriptions that the hydrocarbon bearing sands in the areas studied are generally of poorer quality than the average productive sands of like depth in South Louisiana. Permeabilities were used in this study only qualitatively in de- termining if a hydrocarbon bearing sand could produce. In calculating average porosities from sidewall cores, those cores having a permeabil- ity of less than 10 millidarcies were omitted on the basis that the perm- eability was insufficient for the hydrocarbons to flow from the sand into the well bore with adequate flowing pressures and at significant rates. The permeability from the sidewall cores was used in a similar manner in counting the net sand in each well, in that sand of less than 10 millidarcies permeability was not counted as effective sand. The interstitial water saturation (Sw) was determined for every reservoir from the relationship between the resistivity of hydrocarbon bearing sand (RT) and sand 100 percent salt water bearing (RQ), using the formula Sw 1.73 = R0/RT. The water saturations ranged from eight to 52 percent which is within the limits normally expected in South Louisiana when appraising a large number of reservoirs from widely scattered locations. The average water saturation for the 111 reser- voirs studied is 25.5 percent. In calculating gas in place the intersti- tial water factors (1-SW) used are shown on the schedules on pages 1 through 5. Some shut-in bottom hole pressures measured during drill stem tests or bottle tests were available for estimating proved producible gas and bottom hole pressures were calculated from shut-in tubing pressures.

131 However, for most reservoirs the pressures were estimated based on a normal pressure gradient of 0.465 psi per foot of depth. For the relatively few reservoirs indicated by drilling mud weights to be abnormally pressured the bottom hole pressures were estimated based on the weight gradient of the mud used less an adjustment to account for a safe overbalance to prevent blowouts. Most of the formation temperatures were estimated using gradients obtained from the American Association of Petroleum Geologists geothermal survey. These gradients are expressed in degree Fahrenheit per 100 feet of depth. In order to determine reservoir temperature 74°F mean surface temperature was added. A few measured temperatures recorded during drill stem test operations were available. An additional 460° must be added to the Fahrenheit temperature to express reservoir temperature in degrees Ranklne. Determination of the Properties of Reservoir Hydrocarbons In accordance with instructions, the "physically producible" gas contained in each reservoir was determined from all available data, in- cluding flow tests, drill stem tests, bottle tests, sidewall core analyses and/or sidewall core descriptions. The physically producible gas was then categorized into the three possible classes of gas accumulation: Non- associated (NA) gas (no oil in the reservoir); Associated (A) free gas accumulation above an oil rim; or Solution (S) gas occurring within oil in a reservoir.

132 The four properties of the hydrocarbons contained in the non- associated and/or associated gas reservoirs used directly in estimating the physically producible gas by the volumetric method are: the specific gravity of the separator gas; specific gravity of the separator condensate; the gas-condensate ratio and the condensate vaporizing volume ratio. All of the above data are utilized ultimately though a series of calculations and procedures to obtain the gas deviation or compressibility factor (z) since no gas hydrocarbon analyses were available for any of the reservoirs studied. The following procedure was used to determine the gas deviation factor for each reservoir. The specific gravity of the separator gas was either given in the results of an actual test or was assumed to be 0.61. The specific gravity of the condensate expressed in "API and the gas- condensate ratio expressed in cubic feet per barrel were either reported on an actual test or were estimated by analogy with actual test data ob- tained from other reservoirs in the same field. In the absence of re- ported data, a condensate gravity of 50° API was used. When the gas was reported to be dry, a gas-condensate ratio of 500,000 cubic feet per barrel (equivalent to a condensate yield of 2 barrels per MMcf of gas) was used. The various mathematical equations and steps required to calculate the specific gravity of the full well stream gas are shown in detail for each reservoir on the form entitled "Calculation of Z Factor". All equations shown are commonly used in the industry and are explained in many of the reference books on reservoir engineering. It should be noted that the equation for the gas-condensate ratio (V ) contains the Louisiana c

133 statutory pressure base of 15.025 psia instead of the required 14.73 psia. Vc is used to calculate the shrinkage factor and the specific gravity of the full well stream gas. Since all of the gas reservoirs are exceptionally dry, the effect of using a pressure base of 15.025 psia is so inconsequential that the shrinkage and the full well stream gas gravity do not change in the four significant numbers calculated. As a result, the form was not changed to reflect the different base. After calculation of the full well stream gas gravity as shown, it is necessary to obtain the critical pressure (P ) and the critical temp- erature (Tc) graphically from a well known and widely used plotl of these crtical constants versus full well stream gas gravity (redrawn from Brown et al). The pseudoreduced pressure (Pr) is calculated by dividing the reservoir pressure by the critical pressure and the pseudoreduced temperature (Tr) is calculated by dividing the reservoir temperature by the critical temperature. The pseudoreduced pressure and temperature obtained are then used to graphically determine the appropriate gas deviation factor (compressibility factor) from a well known and widely used plot2 Of compressibility versus pseudoreduced pressure for various pseudoreduced temperatures. The shrinkage factor expressed as a fraction of dry gas to wet gas is calculated as follows. Rc + Vc Shrinkage Factor = *c where: R£ = gas-condensate ratio, cubic feet/bbl Vc - condensate vaporizing volume ratio, cubic feet/bbl Brown, G. G., D. L. Katz, G. G. Oberfell and R. C. Alden, 1948, Natural Gasoline and the Volatile Hydrocarbons, Natural Gas Association of America, Tulsa, Oklahoma 2Standing, M. B. and D. L. Katz, 1942, Density of Natural Gas, Transactions, AIME

134 The gas compressibility factor and the shrinkage factor determined in accordance with the above procedures and equations complete the determination of properties of hydrocarbons in nonassociated and associated gas reservoirs required to determine the dry gas volume originally in place per unit of reservoir rock. The two properties of the hydrocarbons required to calculate solution gas in place by the volumetric method in oil reservoirs are the solution gas-oil ration (Rg) and the reservoir volume factor (RVF). The solution gas-oil ratio expressed in cubic feet per barrel was either reported on a test or was estimated by analogy with test data obtained from other reservoirs in the same field. The reservoir volume factor was obtained graphically from an industry accepted chart by Standingl (California Research Corporation). Estimation of Physically Producible Gas All of the 33 leases studied were shut-in and had not produced as of March 1, 1974, except for short tests in the case of proved reservoirs. As a result, it was necessary to determine the volume of physically producible dry gas by the volumetric method. This was accomplished by first calculating the original volume of dry gas in place per unit of reservoir rock by the following standard equation for associated and nonassociated gas reservoirs. G = 43,560 (0) (1-SW) (pTsc/pscTz) (SF) - 1,000 where: G = dry gas in place, Mcf/acre foot 0 = porosity Sw = interstitial water saturation p = original reservoir pressure, psia T = original reservoir temperature, °R Psc= pressure, standard conditions, 14.73 psia Standing, M. B., 1952, Volumetric and Phase Behavoir of Oil Field Hydrocarbon Systems, Chart 3, Reinhold Publishing Corp., New York, New York

135 Tsc = temperature, standard conditions, 60° F or 520° R z = gas deviation factor (compressibility factor) SF ™ shrinkage factor 43,560 = number of cubic feet per acre foot 1,000 = number of cubic feet per Mcf By substituting the known values of pressure and temperature at standard conditions together with the conversion constants the above equation can be reduced to the following. G = 1537.76 (0) (1-S,,) (P/TZ) (SF) The unknown factors in this equation all relate to the physical pro- perties of each individual reservoir and the properties of the hydrocarbons contained in the reservoir. In the case of oil reservoirs, it was necessary to calculate the volume of solution gas in place that was dissolved in the oil per unit of reservoir rock by the following standard equation for solution gas. G 7758 (0) (l-Sw) (Rs) S RVF where: G_ = solution gas in place, Mcf/acre foot 8 0 porosity s • connate water saturation Rg - solution gas-oil ration Mcf/bbl RVF = reservoir volume factor The unknown factors in the equation also relate to the physical pro- perties of each reservoir and the properties of the hydrocarbons contained therein.

136 It is therefore necessary to determine these unknown physical pro- perties of each reservoir and the properties of the hydrocarbons con- tained therein for all three types of gas accumulations; nonassociated gas, associated gas and solution gas. These data were determined from detailed examination of all the available information by applying normal industry accepted practices and are recorded on the form entitled "Basic Data". The methods and procedures used to determine these necessary reservoir and fluid characteristics were discussed in detail on pages 8 through 13. The weighted average gas volume originally in place for the 90 non- associated and associated gas accumulations stidies was 1,736 Mcf per acre foot. This weighted average is somewhat lower than would be estimated for comparable depths and connate water using a plot the appraisers constructed utilizing gas in place per acre-foot versus depth for numerous South Louisiana sand reservoirs. This also confirms our impression gained in studying all the logs, core data and core descriptions that the hydrocarbon bearing sands in the areas studied are generally of poorer quality than the average productive sands of comparable depth in South Louisiana. After determination of the volume of dry gas originally in place per unit of reservoir rock by the appropriate porcedure described above, the total volume of gas originally in place was then calculated by the following equation. v = (G) (A) (h) 1,000 where: V - total volume gas originally in place, MMcf G = gas in place, Mcf/acre foot A = area of reservoir, acres h = average net thickness, feet 1,000 = number of Mcf per MMcf

137 The product of the area of the reservoir area (A) and the aver- age thickness (h) represents the total volume of productive reservoir rock. The procedures followed in making this determination were ex- plained in detail on pages 7 and 8. The estimated recoverable gas for each reservoir was then determined by applying a recovery factor to the calculated volume of gas originally in place. The recovery factor was calculated for each reservoir by the following equation. a_q _ c \ bw brg; R.F. where : (l-Sw> R. F. = recovery factor Sw = interstitial water saturation Srg = residual gas saturation Based on years of experience gained in appraising sand reservoirs in South Louisiana, the residual gas saturation was assumed to be 25 percent (0.25) and utilized throughout. This method of calculating recovery factors is in accordance with industry accepted practice for reservoirs which exhibit 100 percent effective water drive producing mechanisms. All but the abnormally pressured reservoirs will produce under this type mechanism or under a com- bined producing mechanism with a high degree of effective water influx. Of the 111 reservoirs studied, 11 have abnormally high reservoir pressures of varying degrees. Even though these type reservoirs produce under depletion drive mechanisms, the recovery factors for abnormally pressured reservoirs tend to be less than expected for normal pressured depletion reservoirs as a result of the adverse effect on the various rock characteristics as the

138 pressure is reduced. The weighted average recovery factor for all 111 reservoirs studied is 67 percent which is based on experience is reasonable for both water drive and abnormally pressured depletion drive reservoirs. The range of recoveries was 48 percent to 73 percent which is within the limits normally expected in South Louisiana. The total volume of physically producible gas for the 111 reservoirs on the 33 shut-in leases included in this study is estimated to be 451,230 MMcf of which 318,882 MMcf are designated as "proved" and 132,348 MMcf are designated as "probable". In addition to determining the estimated recoverable gas in each reservoir and lease, it was requested that a range of reasonable estimates (high and low) be determined by applying factors reflecting the quantity and quality of the data available for determining sand volumes. These high and low factors were estimated individually for each of the 111 reservoirs studied. The factors were expressed as a ratio to the estimated recoverable gas and the high and low estimates were calculated by application of these ratios to the best estimate of recoverable gas. The high estimates totaled 596,187 MMcf of physically producible gas, of which 410,047 MMcf were designated as proved and 186,140 MMcf as probable. The low estimates total 326,623 MMcf of gas, 240,225 MMcf proved and 86,398 MMcf probable.

139 NARRATIVE PORTION OF REPORT BY KEPLINGER AND ASSOCIATES, INC., TULSA, OKLAHOMA TO PANEL ON GAS RESERVE ESTIMATION STUDY OF PRODUCIBLE SHUT-IN LEASES IN THE OUTER CONTINENTAL SHELF Introduction The purpose of this report is to present the results of our study of the producible shut-in leases in the outer continental shelf of the Gulf of Mexico. The data that were used in this study include all information collected on or before March 1, 1974. Included in this report will be a summary of results, a general narrative, a discussion of procedure and exhibits detailing by reservoir the gas reserve estimates for each lease. Summary of Results Total gas in place for the 34 leases investigated was estimated to be 989,647 MMcf, while total recoverable gas was estimated to be 651,037 MMcf on the side to 943,960 MMcf on the high side. All gas reserves stated in this report are calculated at standard conditions of 14.73 psia and 60 degrees Fahrenheit. The recoverable reserves are "dry" gas.

140 General Narrative All data which were available for similar studies conducted by the Federal Power Commission and the U.S. Geological Survey were made available to Keplinger and Associates, Inc. and were examined in the offices of the U.S. Geological Survey. Certain worksheets of information derived from an examination of the data were taken from the offices for further study, interpretation, and calculation. However, none of these worksheets contained lease designations or other directly identifying characteristics. All work- sheets are coded, and a cross-reference lease-code file is being retained in the U. S. Geological Survey offices. It should be noted that the phrase "producible shut-in leases" is used in this report as per our contract with the National Academy of Sciences. This phrase should not be construed to mean that the reserves indicated herein are currently accessable through existing wellbores. All of these reserves were accessable at one time or another through wells drilled on the leases investigated. In some cases, though, the wells have been plugged and abondoned and major expenditures would be necessary to produce the reserves a°signed herein. As per our contract, however, we have included no economic parameters in our calculation of reserves. The reservoirs included in this report have never been produced on the leases investigated. However, some were actually tested by a flow test or a bottle test thereby indicating "proved" reserves. The "probable" reserves have not been tested but have been inferred from well logs and other engineering and geological data.

141 Since there is no pressure or production history on which to base performance type reserve estimates such as the pressure or production decline curve analysis methods, the reserves were estimated by the volumetric method. It should be noted that the volumetric type estimates are generally not as reliable as the performance type estimates. The volumetric method consists of estimating the volume of the reservoir rock and the amount of producible hydrocarbons contained therein. This is accomplished as follows: (1) A structure map on top of the reservoir sand is drawn in order to determine the productive area or areal extent of the reservoir. A structure map is similar to a topographic map, except that a structure map shows the configuration of a subsurface bed or horizon rather than the configuration of the surface. In some cases, where there is in- sufficient subsurface geological well control or seismic control, an appropriate productive area is assigned based on experience, judgement and analogy to other nearby and similar reservoirs. (2) The average net effective pay sand thickness is determined by counting the net pay sand thickness from available electric logs and core analysis data for each well that penetrates the reservoir. Then an isopachous (sand thickness) map of net effective pay sand within the productive limits of the reservoir is drawn. In some cases, where subsurface control is lacking or sparse, an average sand thickness based on experience and judgement is assigned over the productive area.

142 (3) The reservoir bulk volume is calculated by planimetering the isopachous map or by multiplying the number of acres within the productive limits of the reservoir times the average net effective pay sand thick- ness. This reservoir bulk volume is usually expressed in acre feet. (4) The reservoir bulk volume is then reduced to the amount of reservoir space that is available to store or contain hydrocarbons (oil, gas and condensate). This is done by estimating the porosity or void space between the sand grains and that portion of pore space that is hydrocarbon saturated from either core analysis or electric log calculations. The hydrocarbon saturation is determined by estimating from core volume that is occupied by interstitial or formation water and subtracting this water saturation percentage from 100 percent. (5) Based on the physical and chemical parameters of the hydro- carbons contained in the reservoir such as pressure, temperature, hydro- carbon composition and constituents, and supercompressibility factor (accounts for deviation of hydrocarbon gases from ideal gas laws), the hydrocarbons in place are calculated. An appropriate recovery factor is then applied to the hydrocarbons in place to obtain original recoverable hydrocarbons. For gas reservoirs, the recoverable "wet" gas is further reduced by a shrinkage factor which accounts for volume losses incurred when liquid hydrocarbons (condensate or distillate) drop out of the gaseous mixture as a result of pressure and temperature reduction. Also, there are normally losses incurred through surface separation and gathering facilities and lease fuel use. The "wet" gas thus adjusted for shrinkage is designated as "dry" gas.

143 Discussion of Procedure The U.S. Geological Survey made available all well logs in their Mettairie, Louisiana office files for every pertinent well which had been drilled prior to March 1, 1974. Well logs from adjacent leases were utilized in addition to the logs from wells on the leases investigated. The U.S.G.S. also provided a base map for each area of interest, worksheets used by the Federal Power Commission for its evaluation, and seismic interpretations made by the U.S.G.S. for its own use. Since the U.S.G.S. base maps could not be removed from their offices, tracing paper was placed over their maps in order to locate well bores. Electrical logs were correlated for subsurface control which was used in conjunction with seismic data and available dip meter surveys to draw structure maps on the various productive horizons. The seismic data were used in conjunction with the dip meter surveys to obtain general dip directions, proximity to salt domes, and fault trace patterns. For these maps the downdip productive limit was considered to be the lowest known gas (either a gas/oil, oil/water, or gas/water contact) or the base of a sand in those cases where a hydrocarbon/water contact was not definitely established. Isopachous or sand thickness maps were drawn by placing tracing paper over the top of the structure maps and tracing the productive area. The net pay sand for each well within the productive outline was estimated by using combinations of porosity logs (density, sonic, and micrologs) and core analyses. In some cases, only the SP (Self Potential)

144 of electric logs was available for use in counting net pay sand, Angle corrections for hole deviation and bed dips were made where applicable to get true bed thickness. Porosities were calculated from available porosity logs and core analyses. Interstitial water saturations were calculated from electric logs and core analyses or by analogy. Other basic data were gathered from well tests, fluid and gas analyses, and area pressure and geothermal gradients. The recovery and shrinkage factors were estimated based on judgment, experience and analogy. All of this information was then combined to calculate the reserves from each reservoir considered on the 33 leases. The previously discussed structure and isopachous maps were drawn to reflect the most reasonable interpretation of the productive limit and sand thickness of each reservoir. The high-low estimates of reserves were based on variations from this most reasonable estimate. For example, the downdip limit of production could be extended from the lowest known gas level in the absence of a downdip dry hole. Also, where there is uncertainty in the fault traces of the intercept of a sand and a salt mass either a more liberal or a more conservative interpretation could be made for the productive limits of the reservoir. In estimating sand counts for a given well, there are cases where a sand is quite shaly and either a more liberal or more conservative sand count could be made. Finally,

145 the recovery efficiency is subject to being interpreted either higher or lower based on judgement, experience and analogy for any given reservoir. All of these factors were considered in making our best, high, and low estimates for each reservoir. In summary, the best-high-low estimates were made based on the following definitions: (1) Best: Most reasonable interpretation relative to available data. (2) High: Most optimistic variation from the best estimate defined above relative to placement of fault trace pattern, downdip limits, dip rates, stratigraphic sand pinchouts, salt/dome/sand intercepts, and net sand distribution within the productive limits that are considered probable or appropriate within the framework of the available data. (3) Low: Most conservative variation from the best estimate defined above relative to place- ment of fault trace pattern, downdip limits, dip rates, strategraphic sand pinchouts, salt dome/sand intercepts, and net sand distribution within the productive limits that are considered probable or appropriate with- in the framework of the available data.

146 DATA FORMS Field Parish Well Operator Reservoir BASIC DATA Datum: _ Feet Original Reservoir Pressure: psig Reservoir Temperature: °R Average Porosity: % Average Connate Water: % Separator Gas Gravity: Original Z Factor: Condensate Gravity: ° API Molecular Weight Condensate: Gas Equivalent per Bbl. Condensate: SCF/STB Shrinkage Factor:

147 WORK SHEET FOR DETERMINATION OF NET GAS SAND VOLUME & PRODUCTIVE AREA PLANIMETER NOTES SAND UNIT AREA UNIT TRACT SEGMENT AVERAGE ISOPACH PLANIMETER READINGS ISOPACH 1 2 3 FINAL INITIAL DIFF. FINAL INITIAL DIFF. FINAL INITIAL DIFF. FINAL i INITIAL DIFF. FINAL INITIAL DIFF. FINAL INITIAL DIFF. FINAL INITIAL DIFF. FINAL INITIAL DIFF. ACRES CONSTANT - k - PLAN. RDG. SAND VOLUME Interval PRODUCTIVE AREA PRODUCTIVE VOLUME

148 Field Parish Well Operator Reservoir CALCULATION OF Z FACTOR SPECIFIC GRAVITY OF FULL WELL STREAM - Gm r, + 46Q8 GC vc I Rc Gs = Specific Gravity of Separator Gas = Gc = Specific Gravity of Separator Cond. = °API 141.5 m 141.5 API-I- 131.5 * ( ) + 13l.5 Rc = Gas Cond. Ratio = ft3/bbl Vc s Condensate Vaporizing Volume Ratio ' nRT8C/P8C 350.5 x Gc 10.73 x 520 Mc X 15.025 = 130,160 GC/MC Mc= 44.29 Gc/1.03-Gc = (2938.81) x(l.03-Gc) SCF/STB CRITICAL CONSTANTS - BASED ON FWS SPECIFIC GRAVITY

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APPENDIX C GAS RESERVOIRS AND GAS RECOVERY GAS RECOVERY FACTORS Murray F. Hawkins Gas recovery factors are the ratios of gas recovered or produced to gas initially in place. They are sometimes based on experience with other gas reservoirs in the same area, at similar depths and/or of the same geologic age. At other times, they are estimated from a consideration of the more important factors known to affect gas recovery. Non-Associated Gas Reservoirs Among these factors is the reservoir producing mechanism. For non-associated gas reservoirs at the time of discovery, the choice is usually between (1) the depletion mechanism, i.e., gas expansion with no water drive from an adjacent aquifer and (2) the complete or active water drive mechanism, with no gas expansion. This choice is based on experience and geologic evidence. It is an important decision because recovery factors for depletion gas reservoirs lie in the range of 70 to 90 percent, whereas in active water drive reservoirs, the usual range is 30 to 60 percent. As development proceeds and appreciable production occurs, the correctness of the choice is revealed. In many cases, the mechanism is found to be partial water drive, which also implies partial depletion (gas expansion). Recovery factors for partial water drive gas reservoirs lie between those for depletion and complete water drive reservoirs. 156

157 \ Depletion gas reservoirs are produced until they reach the economic limit at which income derived drops below operating cost. At this time, average reservoir pressure will have dropped to a level called the abandonment pressure. The gas recovery factor is approximately equal to the decline in reservoir pressure divided by the initial pressure. Thus, for an initial pressure of 8000 psia and an abandonment pressure of 2000 psia, the recovery factor is approximately (8000-2000)/8000, or 75 percent. When compressors are not used, the minimum abandonment pressure is essentially the operating pressure of the pipeline into which the wells flow, usually 500 to 1,000 psi. In addition to causing gas to move into the pipeline, reservoir pressure must be available to move gas from the reservoir to the well bores and to overcome the frictional and head losses as gas flows up the tubing in the well. Some engineers estimate abandonment pressure at 100 psi per 1000 feet of depth. Thus for a reservoir at a depth of 10,000 feet, the abandonment pressure is estimated at 1,000 psi. For an initial reservoir pressure of 5,000 psi, the recovery factor is approximately (5000-1000)75000 or 80 percent. When the gas well flow rates reach the economic limit, gas compressors may be installed to decrease the abandonment pressure and increase recovery. Compressors may also be installed when rates fall below desired production rates, such as sales contract rates or maximum efficient producing rates. The economics may thus be improved by production acceleration or additional recovery, or both. It is exactly equal to the decline in the gas potential p/z divided by initial gas potential. The gas potential is the absolute pressure divided by the gas deviation factor z.

158 The economics of gas production are often complex, for they depend upon a great many factors. For example, a single offshore gas reservoir must be sufficiently large to justify a platform and pipeline connection, but a smaller reservoir may be economically producible if it occurs in a multireservoir field. Economic flow rates are likewise affected by such circumstances. For this apparent reason, the Federal Power Commission reports are based, not on economically recoverable gas, but on physically recoverable gas, which is always the larger. For a depletion gas reservoir, the physically recoverable gas is essentially 100 percent, because given enough time and allowing production at very low rates, nearly all of the gas will eventually flow out of a reservoir. Complete or active water drive reservoirs are those whose pressures are maintained at essentially initial values by water which invades the reservoir from an adjoining aquifer. Gas wells in such reservoirs produce at essentially initial full rates until the invading water reaches the wells and, usually soon thereafter, drowns them out. Unfortunately, invading water does not drive all of the gas out of the pore spaces of rock. Residual gas saturations in the rock pores after water displacement are usually in the range of 15 to 45 percent of pore space. Laboratory measurements on core samples can help to determine this factor. However, a residual gas saturation of 15 to 45 percent does does not mean gas recoveries of 85 to 55 percent, respectively, because the reservoir rock contains interstitial or connate water. Connate water saturations, i.e., before water invasion, usually lie in the range of 10 to 35 percent of pore space. In terms of the connate water and residual gas saturations, the recovery factor is given by: