Initial oil in place example
The construction of 3-D static reservoir models based on the understanding of facies and their relationships, through the integration of all available data have been used to enhance the understanding and qualification of the uncertainties. Standard evaluation of uncertainties in the spread of petrophysical parameters like porosity, hydrocarbon saturation and Net-to-Gross ratio was carried out and compared with the multiscenrio concepts incorporated in the geological models. Pressure, Volume and Temperature PVT parameters were derived for the reservoir based on analogy and correlations constrained with production and test data. An attempt has also been made in comparing results from the probabilistic volumetric evaluation of this reservoir and the deterministic best estimate method. In field development planning, it is routine to identify and quantify the impact of major subsurface uncertainties such as, the oil in place volumes and their distribution Egwebe, ; Ayoola,
Reservoir-Engineering-Handbook-4ed-
Welcome To C rain's P etrophysical H andbook. Ross Crain, P. This webpage version is the copyrighted intellectual property of the author. Do not copy or distribute in any form without explicit permission. OIL and gas in place anD reserves Calculating oil or gas in place from petrophysical analysis results is a simple matter of calculating volumes from reservoir thickness, porosity, and water saturation.
The area of the reservoir is usually contoured from maps of the reservoir properties. For single well analysis, a spacing unit is usually defined as acres for oil wells and acres 1 square mile for gas wells. These dimensions are approximately , and 2,, square meters in Metric units. Reserves are defined as the amount of oil or gas that can be produced from a reservoir with current technology at current prices and current costs. Since these change on a daily basis, economic reserves can vary with time, increasing or decreasing with changes in the overall world economic conditions.
Decline curve analysis and material balance methods are used to calculate remaining reserves based on actual production and pressure data. Coupled with the volumetric analysis from petrophysical data, a reasonable solution can usually be found, although differences between the results from the three models may lead to a revised reservoir description.
Additional data might be needed to resolve discrepancies, such as additional production history, new wells, better PVT data, or a new geological interpretation. In some parts of the world, oil is measured in metric tonnes instead of barrels or cubic meters. Remember to round your answers to two or three significant digits, which you started with. Tar Assay Reserves Weight Tar or bitumen, and sometimes heavy oil, is measured by weight of tar in place as opposed to volume of oil in place.
Some Former Soviet Union countries record conventional oil reserves in tonnes. The following formulas are for use in areas where reserves are measured in metric tonnes, or as weight fraction or weight percent. To obtain tonnes in place, multiply by area in square meters. To obtain reserves, multiply this result by a recovery factor.
To compare log analysis results to core, eliminate the water term from WTrock. The "tar" equations provide the conversions needed. WTtar - 0. Methane CH4. Ethane C2H6. Propane C3H8. The volume of hydrocarbon in a gas hydrate js a function of the hydrocarbon type and the porosity only.
Water saturation is meaningless. This is equivalent to cubic feet for methane per cubic foot of pore space or m3 per cubic meter of pore space at standard temperature and pressure, for methane, and 60 cubic feet of propane per cubic foot of pore space, regardless of depth of burial. Crain, P. All Rights Reserved.
1) Initial oil in place. 2) Oil in place after volumetric depletion to abandonment pressure. 3) Oil in place after water invasion at initial pressure. 4) Oil reserve by. initial oil column thickness = 80 ft. hp = 20′ Calculate initial oil in place N. N = A ϕ h Results of Example Total Production Rate Is STB/day.
Welcome To C rain's P etrophysical H andbook. Ross Crain, P. This webpage version is the copyrighted intellectual property of the author.
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Hydrocarbon reserve can be defined as those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. The latter is roughly defined as sum of recoverable and unrecoverable volumes of hydrocarbon in place.
Oil Recovery Prediction
Hydrocarbon exploration or oil and gas exploration is the search by petroleum geologists and geophysicists for deposits of hydrocarbons , particularly petroleum and natural gas , in the Earth using petroleum geology. Visible surface features such as oil seeps , natural gas seeps, pockmarks underwater craters caused by escaping gas provide basic evidence of hydrocarbon generation be it shallow or deep in the Earth. However, most exploration depends on highly sophisticated technology to detect and determine the extent of these deposits using exploration geophysics. Areas thought to contain hydrocarbons are initially subjected to a gravity survey , magnetic survey , passive seismic or regional seismic reflection surveys to detect large-scale features of the sub-surface geology. Features of interest known as leads are subjected to more detailed seismic surveys which work on the principle of the time it takes for reflected sound waves to travel through matter rock of varying densities and using the process of depth conversion to create a profile of the substructure.
Material balance in oil reservoirs
Related Topics. Volumetric analysis is a technique that employs geological observations and information to estimate original fluids-in-place. Volumetric calculations are typically used prior to production to estimate reserves, and after considerable production to determine the efficiency of recovery, the areal extent of the reservoir, and as a basis for advanced studies such as reservoir simulations. A comprehensive geologic study of the prospect is necessary to increase the confidence and reliability of determined reservoir properties such as volume, porosity, and fluid saturations. In calculating the volume of the reservoir, accurate determinations of the areal extent and thickness must be made with respect to the geological structure and depositional environment. The use of isopach maps in combination with planimetering is a commonly used method in the determination of reservoir volume. Conclusions drawn concerning lithofacies and depositional settings are used to provide an assessment of porosity, while wireline log and core data provide the analyst with measurements of fluid saturations. Historically, in a gas reservoir, only free gas-in-place was considered. Because of this, only one name was required: OGIP. The name OGIP has been retained to describe the total original gas-in-place.
Volumetric is a method to estimate fluid in reservoir based on volume of pore space in a rock and water saturation.
Rock properties are determined by performing laboratory analyses on cores from the reservoir to be evaluated. The cores are removed from the reservoir environment, with subsequent changes in the core bulk volume, pore volume, reservoir fluid saturations, and, sometimes, formation wet- tability.
Volumetric Method To Estimate Volume In Place and Reserves
Oil initially in place OIIP is the amount of crude oil first estimated to be in a reservoir. Oil initially in place differs from oil reserves, as OIIP refers to the total amount of oil that is potentially in a reservoir and not the amount of oil that can be recovered. Calculating OIIP requires engineers to determine how porous the rock surrounding the oil is, how high water saturation might be and the net rock volume of the reservoir. The numbers for the aforementioned factors are established by conducting a series of test drills around the reservoir. Oil initially in place is known more simply as oil in place OIP. It is also referred to by a few variations. Stock tank oil initially in place STOIIP is the same volumetric calculation with it being made explicit that the volume being estimated is the volume filled by the extracted oil at surface temperature and pressure rather than the compressed volume the crude oil fills in the reservoir due to geological pressure. Original gas in place OGIP is again the same volumetric calculation but for natural gas reservoirs. Finally, hydrocarbons initially in place HCIIP is the generic term that can be used for both oil and gas when doing a volumetric calculation to estimate the contents of a potential drill site. Determining oil initially in place is one of the major components taken into account by analysts determining the economics of oil field development. Oil initially in place hints at the potential of a reservoir. This is a critical data point, but it is only the start of the analysis prior to the decision to drill or sit on a lease. Oil in initially in place gives an oil company an estimate of the total number of barrels sitting under the various leases. If all the oil initially in place was recoverable , then oil companies would just need to start at their biggest reservoir and work their way down to the smallest, trying to keep drilling costs fixed along the way. In reality, only a portion of the oil initially in place will ever be recovered and characteristics of the formation will impact drilling costs.
Hydrocarbon exploration
Oil in place OIP not to be confused with original oil-in-place OOIP is a specialist term in petroleum geology that refers to the total oil content of an oil reservoir. As this quantity cannot be measured directly, it has to be estimated from other parameters measured prior to drilling or after production has begun. Prior to oil production from a new reservoir, volumetric methods are used to estimate oil-in-place. A series of test drills are used to map the rock conditions at and around the drilling site and to estimate the size of the oil-bearing rock field. The oil in place is calculated as the product of the volume of porous oil-bearing rock, the porosity of the rock, and its saturation. In this case, stock tank barrels refers to the volume of oil after production, at surface pressure and temperature as opposed to reservoir conditions. After production has begun, the change in reservoir pressure over time and the history of production from that reservoir can be used to estimate the total oil-in-place using the materials balance method. Alternatively, the production history can be fitted to a curve to estimate future oil production decline curve method.
