Gas in Place

The quantity of all gas originally present in a reservoir prior to production, expressed as the volume expanded to standard conditions. 

Classification of gas reserves and resources recommended by the World Petroleum Congress in 1987 

Calculation of amounts of gas in discovered deposits based on data obtained by the drilling of one or more boreholes. 

Geological reserves are calculated that are suitable for exploitation, together with the amounts that can be extracted under existing economic and operating conditions with a probability of confirmation of 90 % or above. 

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The typical compressibility of gas is 500 10 psi, compared to oil at 10 10 psr, and water at 3 10 psi When a volume of gas is produced (8V) from a gas-in-place volume (V), the fractional change in pressure (8P) is therefore small. Because of the high compressibility of gas it is therefore uncommon to attempt to support the reservoir pressure by injection of water, and the reservoir is simply depleted or blown down . 

The definitions above are an abbreviated version of those used in a veiy complex and financially significant exercise with the ultimate goal of estimating resei ves and generating production forecasts in the petroleum industry. Deterministic estimates are derived largely from pore volume calculations to determine volumes of either oil nr gas in-place (OIP, GIP). This volume when multiplied by a recovery factor gives a recoverable quantity of oil or natural gas liquids—commonly oil in standard barrels or natural gas in standard cubic feet at surface conditions. Many prefer to use barrels of oil equivalency (BOE) or total hydrocarbons tor the sum of natural gas, natural gas liquids (NGL), and oil. For comparison purposes 6,000 cubic feet of gas is considered to be equivalent to one standard barrel on a British thermal unit (Btu) basis (42 U.S. gallons). 

That proportion of the initial gas in place which can be recovered under actual technical and economic conditions. 

A method of estimating initial gas in place using the relation between pressure decline and produced gas volume. 

A method of estimating original gas in place using the results of drilling (structural assessment, effective thickness, porosity, gas saturation, pressure, temperature, gas characteristics, and the boundaries of the accumulation). These data may be supplemented by geological or geophysical data on the shape of the reservoir. 

Howard and Hulett Jour. Phys. Ghem. Oct. 1924) brought forward additional evidence in favour of this hypothesis by determining the apparent densities of charcoals with helium gas in place of an immersion liquid with the following results ... 

A negative oxygen balance is frequently designed into these propellant mixtures to obtain CO gas in place of COi. CO is lighter and will produce greater thrust, all other things being equal. However, the full oxidation of carbon atoms to CO j evolves more heat, so some trial-and-error is needed to find the optimum ratio of oxidizer and fuel [8]. 

The petroleum engineer should determine the type of fluid very early in the life of his reservoir. Fluid type is the deciding factor in many of the decisions which must be made regarding the reservoir. The method of fluid sampling, the types and sizes of surface equipment, the calcula-tional procedures for determining oil and gas in place, the techniques of predicting oil and gas reserves, the plan of depletion, and the selection of enhanced recovery method are all dependent on the type of reservoir fluid. 

A set of equations known collectively as gas material balance equations has been devised to determine original gas in place and predict gas reserves. These equations were derived for dry gases and can be used for wet gases, if care is taken in defining the properties of the wet gases. The equations are applicable to retrograde gases only at reservoir pressures above the dew point. 

By modeling with SimSim original gas in place and reservoir dynamics was updated, clarified. 

There are no other forces, with the exception of gravity, to hold a gas in place. 

If no suitable depleted zone or large aquifer is readily available near the sour gas plant, then disposal into a producing horizon is feasible because the amount of gas returned to the zone is usually a small fraction of the total gas in place. 

When iron reacts with the gas chlorine, a compound known as iron chloride is produced. If copper was to react with the gas in place of iron, we would have. . 24... 

One of the most critical properties controlling the gas-in-place volume as well as gas productivity is the in-situ connate water saturation. Because of their low permeability and porosity, quantification of water saturation is especially important in tight gas sands since very small volumes of water can dramatically and adversely affect rock flow and storage properties. Quantification of water saturation was also important for evaluation of Bossier exploration prospects. Accordingly, a comprehensive program was initiated to measure and verify water saturations in the Dew/Mimms Creek Fields. 

Specifically, this technique was used to estimate the range of gas-in-place volumes—i.e. the key parameter—and their probabihty of oecurrence. Equations (12) and (14) are the models defining the gas volumes computed from the mass balance and conventional reservoir engineering techniques, respectively. 

The major difference between the SRC process and the SRL process is the option (in the latter process) of using synthesis gas in place of hydrogen. This is, in fact, an opportune application since the low-rank high moisture lignites provide the necessary moisture for the water-gas shift reaction. 

If the mixing ratio of Xe/HCl/Ne is varied, the electron energy distribution in the discharge plasma changes. As a result, formation of precursors Xe+, Xe, Ne+, andNe is greatly affected. If helium is used as a diluent gas in place of Ne, the electron temperature also changes, resulting in a different pathway for the XeCl(B) formation and a less effective formation than that of the Ne diluent. 

Natural gas is measured in either volumetric or energy units. As a gas, it is measured by the volume it displaces at standard temperatures and pressures, usually expressed in cubic feet. Gas companies generally measure natural gas in thousands of cubic feet (Mcf), millions of cubic feet (MMcf), or billions of cubic feet (Bcf), and they estimate resources such as original gas-in-place in trillions of cubic feet (Tcf). 

Original gas-in-place—The entire volume of gas contained in the reservoir, regardless of the ability to produce it. 

Note Information presented in this table, such as original gas-in-place and technically recoverable resources, is presented for general comparative purposes only. The numbers provided are based on the sources shown and this research did not include a resource evaluation. Rather, publicly available data was obtained from a variety of sources and is presented for general characterization and comparison with other shale gas plays. Resource estimates for any basin may vary greatly depending on individual company experience, data available at the time the estimate was performed, and other factors. Furthermore, these estimates are likely to change as production methods and technologies improve. 

The area of the Fayetteville Shale play is nearly double that of the Barnett Shale at 9000 square miles, with well spacing ranging from 80 to 160 acres per well and play zone thickness averaging between 20 and 2(X) feet. The gas content of the Fayetteville Shale has been measured at 60 to 220 scf/ton, which is less than the 300 to 350 scf/ton gas content of the Barnett Shale. The lower gas content of the Fayetteville has resulted in lower estimates of the original gas-in-place and technically recoverable resources 52 Tcf and 41.6 Tcf, respectively. 

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