VOLUMETRIC ESTIMATION Volumetric estimation is also known as the "gcologist's method" as it is based on cores, analysis

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Volumetric Estimation Volumetric Estimation Is Also Known As The Gcologist S Method As It Is Based On Cores Analysis 1 (63.8 KiB) Viewed 69 times

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VOLUMETRIC ESTIMATION Volumetric estimation is also known as the "gcologist's method" as it is based on cores, analysis of wireline logs, and geological maps. Knowledge of the depositional environment, the structural complexities, the trapping mechanism, and any fluid interaction is required to: Estimate the volume of subsurface rock that contains hydrocarbons. The volume is calculated from the thickness of the rock containing oil or gas and the areal extent of the accumulation (Figure 1) - Determine a weighted average effective porosity (Figure 2). - Obtain a reasonable water resistivity value and calculate water saturation. Figure 1: Areal extent of rock volume accumlation Figure 2. Weighted average effective porosity Original oil-in-place or original gas-in-place volumes can be calculated: (1) For OIL RESERVOIRS the original oil in place (OOIP) volumetric calculation is OOIP (STB) = Rock Volume X 7758 XØX (1 - S/B Where: Rock Volume (acre-feet) - A Xh A=Drainage area, acres h = Net pay thickness, feet 7758 = API Bbl per acre-feet (converts acre-feet to stock tank barrels) = Porosity, fraction of rock volume available to store fluids Su = Volume fraction of porosity filled with interstitial water B. - Formation volume factor (Reservoir Bb/STB) Reserves - STOOIP X RF (Recovery Factor (estimated) As wells are drilled on the field, the seismic interpretation becomes refined so that an accurate structure contour map can be drawn. Log and test data establish the oil water contact and hence the thickness of the hydrocarbon column The porosity is calculated from wireline logs calibrated from core data, and the water saturation is calculated from the resistivity logs. The recovery factor is hard to estimate even if the performances of similar reservoirs in adjacent fields are available. Estimate of the recovery factor (generally 30% or more for sands and 10-20% for carbonate reservoirs). The recovery factor will vary according to well spacing, reservoir permeability, fluid viscosity, and the effectiveness of the drive mechanism Generally, several hundred bbl/acre-ft of oil may be recovered. Recovery Factors OIL - Poor reservoir (low poro-perm) <10% - Dual Porosity (low matrix reservoir quality) -- 20% - Good Poro-Perm (Primary = Secondary) -30%
- Excellent reservoir (good water support): - 40-50% - Ideal (good reservoir quality, management) - 60-70% - Tar Sands (mined) - 100% GAS - CBM, Shale Gas <10% (generally -Good Quality (depletion): 70% (GOM average) - Excellent Reservoir (depletion, compression): 90%+ (Lake Arthur Ex.) The FVF converts a stock tank barrel of oil to its volume at reservoir temperatures and pressures. It depends on oil composition, but this dependence can generally be approximated by calculating the FVF's dependence on the solution gas: oil ratio (GOR) and oil density (API gravity). The FVF ranges from 1.08 for low GORs and heavy crudes to values of more than 2,0 for volatile oils and high GORs. (2) For GAS RESERVOIRS the original gas in place (ОGIP) volumetric calculation is: OGIP (MMCF) -Rock Volume X 43560 X OX (1-S.)/B. Where: Rock Volume (acre-feet) = A Xh A Drainage area, acres (I acre - 43560 sq. ft) h = Net pay thickness, feet 0 -Porosity, fraction of rock volume available to store fluids S. -Volume fraction of porosity filled with interstitial water Trapezoidal Volume V (AA)) R-Recovery Factor B = Formation volume factor (Reservoir BbUSTB) To calculate recoverable gas volumes, the OGIP is multiplied by a recovery factor Volumetric depletion of a gas reservoir with reasonable permeability at conventional depths in a conventional area will usually recover 70 to 90% of Frustum of a pyramid V(43)*( AAVAA the gas-in-place. However, a reservoir's recovery factor can be significantly reduced by factors such as: low permeability, low production rate, overpressure, soft sediment compaction, fines migration, excessive formation depth, water influx, water coning and/or behind pipe cross flow, and the position and number of producing wells. As an example, a 60% recovery factor might be appropriate for a gas accumulation Fruitum of a cone V-3)******* overlying a strong aquifer with near perfect pressure support Figure 3: Volumetric rules: Trapezoidal, pyramidal, and cone. Rock Volume Calculations (A Xh) Reservoir volumes can be calculated from net pay isopach maps by planimetering to obtain rock volume (A Xh). To calculate volumes it is necessary to find the areas between isopach contours. Planimetering can be performed by hand or computer generated. Given the areas between contours, volumes can be computed using: Trapezoidal rule, Pyramidal rule and/or the Peak rute for calculating volumes (Figure 3). Net pay Net pay is the part of a reservoir from which hydrocarbons can be produced at economic rates
home imioni பாகா pw E 5 GhA+CD- BCDEF G D NS Figure 4: Gross and net pay distinction (Etris and Stewart, 2003) Ex 1. Calculate STOOIP and Reserves if you know BV = 144 Msm Average porosity 0.23 Average S=0.16 B. - 1.03 RF = 0.31 NG=0.57 Ex2: The following data for the Hout Oil Field in Saudi Arabia, calculate initial oil in place & recoverable oil Area = 26,700 acres Net productive thickness - 49 Porosity = 8% Average Sw = 45% B. = 1.68 bbUSTB RF -44% Ex 3: Given the following data for the Bell Gas Field, calculate initial gas in place & recoverable gas Arca - 160 acres Net productive thickness = 40 ft Porosity = 22% Connate water = 23% Initial gas FVF = 0.00533 A/SCF RF = 85% Ex 4: Calculate Recoverable of oil if you know Bulk volume of sample = 19 cc Weight of dried sample=22 gm Sand grain density = 2.67 gm/cc S.=0.19 B=1.05 RF = 0.33
The following factors are included in volumetric calculation in the petroleum industry: Gross rock volume (GRV) Total volume under consideration Fluid contact OWC, GWC, GOC, Bulk volume (BV) total volume of rock between contacts and between contact and the top of the trap Net/gross (N/G) Proportion of bulk volume which has good reservoir quality Net rock volume NRV = BV X N/G Net pore volume NPV = NRV X Porosity Water saturation (Sw) Proportion of water mixed in the gas or oil Hydrocarbon pore volume HCPV = NPV X (1-Sw) Expansion factor b. (oil), B (gas) Stock tank oil originally in place STOOIP = HCPV X B. Recovery factor (RF) Proportion of HC that can be extracted Reserves Reserves = STOOIP X RF