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This application will calculate original gas in place and estimate recoverable gas reserves based on a user supplied recovery factor. This application is useful in areas where there is a large uncertainty in reservoir parameters or where drive mechanism is unknown.
The Gas Reserves - Simple is intended for volumetric, depletion drive type reservoirs. The program estimates recoverable gas reserves based on original and abandonment reservoir conditions. Basic reservoir engineering formulas are used to calculate original gas in place (OGIP) and the remaining gas volume is recalculated based on the abandonment pressure. The gas gravity is adjusted to account for the liquid condensate, since the gas produced at the surface is not representative of the gas gravtiy in the reservoir were the condensate is in the gas phase. The amount of reservoir volume occupied by the gas condensate is estimated by converting the gas condensate to a gas equavilent. These adjustments are transparent to the user and are tedious calculation often overlooked, but can significantly affect the results at higher condensate yields.
Description of Inputs
Gas gravity is a measure of the density of a gas relative to air. Gas gravity is usually based on a gas composition analysis. Gas gravity must be between 0.55 and 1.10.
Gas impurities such as carbon dioxide (CO2), hydrogen sulfide (H2S), and Nitrogen (N2) should be input as mole percent. These values are usually determined from a gas analysis. These values are used to adjust the critical temperature and pressure of the gas to account for these impurities. For the calculations to be valid, the sum of CO2, H2S and N2 must be less than 100% and the sum of CO2 and H2S must be less than 80%.
There are two options for gas type miscellaneous or condensate. This determines what correlation is used to calculate the critical pressure and temperature for the gas. Gas type will not greatly affect the results of the calculation at low gas gravity. However at higher gas gravity it can be significant.
Base pressure is the pressure at which gas is measured for sales or custody transfer. For Example: 14.65 psia in Texas and 15.025 psia in Louisiana and Offshore federal leases. Base Temperature is assumed to be 60F.
Porosity is a measure of the amount of pore space in the reservoir. It is calculated by dividing the volume of pore space by the total volume of the reservoir rock. Porosity has no units and is usually presented as a percent(%). It is usually determined from core measurements or log calculations. Porosity must be between 0% and 100%. Porosity above 40% is probably unrealistic. The upper limit of 100% has been left for program flexibility.
Water Saturation is the percent of the reservoir pore space that is occupied by water. Water Saturation has no units and is usually presented as a percent(%). It is usually measured from core samples or calculated from well logs. Water saturation must be between 0% and 100%.
Condensate yield is the ratio of condensate production to gas production at surface conditions. The units are barrels of condensate per million cubic feet of gas (BC/MMCF). There are no input limitation for condensate yield. However, realistically it should be limited to between 0 and 500 BC/MMCF.
Average pressure in the reservoir. This value can be determined from pressure build up test, shut in bottom hole pressure or it can be estimated from mud weights during drilling. Bottom hole pressure can be estimated by the following formula: Bottom Hole Pressure (psig)= True Vertical Depth (ft) * Mud weight (ppg) *0.052 Reservoir pressure must be between 10 psia and 20,000 psia.
Average temperature in the reservoir. This value can be estimated from a well log header. Reservoir temperature can also be measured during a shut in bottom hole pressure measurement. Reservoir temperature must be between 50°F and 500°F.
Recovery factor is an estimate of the percent of original gas in place that will be recovered. It can be as high as 95% for depletion drive reservoirs and as low as 40% for strong water drive reservoirs. Recovery factor must be between 0% and 100%.
Reservoir volume is the total volume of the reservoir. This includes the volume updip of the well as well as the volume downdip. Units are Acre-ft. There is no input limitation for reservoir volume.
Description of Results
OGIP is the original gas in place per unit volume. The units are thousands of cubic feet per acre foot (MCF/Acre-ft). Displaying this value per acre foot gives you an idea about the quality of the reservoir without being influenced by the volume.
OGIP is the original gas in place. This is the total amount of gas in the reservoir before any production. Units are million cubic feet (MMCF).
OOIP is original oil in place. In gas volumetrics it refers to condensate that falls out of gas as it drops in pressure and temperature. Units are thousands of barrels (MBO).
Recoverable Gas is the gas that can be produced from a reservoir per unit volume. The units are thousands of cubic feet per acre foot (MCF/Acre-ft).
Recoverable Gas is the total gas that can be produced from a reservoir. Units are million cubic feet (MMCF).
Recoverable Oil is the oil that can be produced from a reservoir. Units are thousands of barrels (MBO). In gas volumetrics this refers to condensate not really oil.
Bg is the gas volume factor and is defined as the ratio of the volume of gas at standard pressure and temperature to the volume at reservoir conditions. Units are standard cubic feet per reservoir cubic feet (scf/rcf).
Calculations
The Simple Gas Volumetrics application calculates original gas in place (OGIP) and then applies the Recovery Factor supplied by the user to determine the recoverable reserves. The following equations are used to calculate the volume occupied by condensate in the reservoir.
The gas gravity is adjusted to account for condensate by the following equation:
If there is no condensate associated with the gas then there is no need to adjust the gas gravity.
OGIP (MCF/Acre-ft) is calculated by the following equations. The Shrink equation adjusts the gas volume for condensate.
OGIP (MMCF) is calculated by multiplying OGIP (MCF/Acre-ft) by the Reservoir Volume (Acre-ft) and dividing by 1000 to adjust for units. OOIP (MBO) is calculated by multiplying the OGIP (MMCF) by the yield and dividing by 1000 to account for units.
Recoverable Gas per acre ft is calculated simply by multiplying the OGIP (MCF/Acre-ft) by the Recovery Factor.
Recoverable Gas (MMCF) is calculated by multiplying the Reservoir Volume (Acre-ft) by Recoverable Gas (MCF/Acre-ft) and dividing by 1000 to account for units. Recoverable Oil (MBO) is calculated by multiplying the Recoverable Gas (MMCF) by the yield and dividing by 1000 to adjust for units.