Gas Reserve Estimation of Offshore Producible Shut-in Leases in the Gulf of Mexico A Report (1976) / Chapter Skim
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APPENDIX B: RESERVE ESTIMATES
APPENDIX B: RESERVE ESTIMATES
Pages 122-158
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From page 122... ...
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.
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From page 123... ...
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.
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From page 124... ...
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.)
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From page 125... ...
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.
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From page 126... ...
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.
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From page 127... ...
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 location plats showing the surface and bottom hole location of each well.
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From page 128... ...
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.
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From page 129... ...
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.
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From page 130... ...
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.
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From page 131... ...
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, including flow tests, drill stem tests, bottle tests, sidewall core analyses and/or sidewall core descriptions.
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From page 132... ...
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 gascondensate ratio expressed in cubic feet per barrel were either reported on an actual test or were estimated by analogy with actual test data obtained from other reservoirs in the same field.
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From page 133... ...
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.
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From page 134... ...
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.
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From page 135... ...
(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 properties of each reservoir and the properties of the hydrocarbons contained therein.
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From page 136... ...
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.
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From page 137... ...
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)
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From page 138... ...
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".
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From page 139... ...
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.
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From page 140... ...
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.
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From page 141... ...
(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.
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From page 142... ...
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.
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From page 143... ...
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.
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From page 144... ...
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.
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From page 145... ...
(3) Low: Most conservative variation from the best estimate defined above relative to placement 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 within the framework of the available data.
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From page 146... ...
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:
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From page 147... ...
RDG. SAND VOLUME Interval PRODUCTIVE AREA PRODUCTIVE VOLUME
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From page 148... ...
+ 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)
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From page 149... ...
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From page 150... ...
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From page 153... ...
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From page 154... ...
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From page 156... ...
. Recovery factors for partial water drive gas reservoirs lie between those for depletion and complete water drive reservoirs.
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From page 157... ...
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)
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From page 158... ...
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.
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