The document discusses the estimation of petroleum reserves using various methods, emphasizing the importance of geological and engineering data. It outlines the classifications of reserves into proved and unproved categories, detailing the factors influencing recoverability. Additionally, it explains the calculations for original hydrocarbon in place and recovery factors, alongside methodologies for forecasting production rates.

1. RESERVES ESTIMATION
(VOLUMETRIC METHOD)
Presenter Shivshambhu Kumar
Date 29 April 2017
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2. 1. INTRODUCTION
 Reserves are those quantities of petroleum which are anticipated to be
commercially recovered from known accumulations from a given date forward.
 All reserve estimates involve some degree of uncertainty.
 The uncertainty depends mainly on the amount of reliable geologic and engineering
data available at the time of the estimate and the interpretation of these data.
 The relative degree of uncertainty may be conveyed by placing reserves into one of
two principal classifications, either proved or unproved .
 Unproved reserves are less certain to be recovered than proved reserves and may be
further sub-classified as probable (2P) and possible (P10) reserves to denote
progressively increasing uncertainty in their recoverability.
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3. 1. INTRODUCTION
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4. 1. INTRODUCTION
Estimating hydrocarbon reserves is a complex process that involves integrating geological and
engineering data. Depending on the amount and quality of data available, one or more of the following
methods may be used to estimate reserves:
• Volumetric
• Material balance
• Production history
• Analogy
Volumetric estimates of OOIP and OGIP are based on a geological model that geometrically describes the
volume of hydrocarbons in the reservoir. However, due mainly to gas evolving from the oil as pressure and
temperature are decreased, oil at the surface occupies less space than it does in the subsurface. Conversely, gas
at the surface occupies more space than it does In the subsurface because of expansion. This necessitates
correcting subsurface volumes to standard units of volume measured at surface conditions.
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5. 2. RECOVERABLE HYDROCARBON
1. Porosity
2. Water Saturation
3. Net Pay
4. Area
5. Pressure
6. Formation Volume Factor
7. Original Hydrocarbon in Place
8. Recovery Factor
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6. ORIGINAL HYDROCARBON IN PLACE
1. For Oil,
OOIP = N =
𝑣 𝑏∗∅∗(1−𝑠 𝑤𝑖)
𝐵 𝑜𝑖
Where,
N = Original Oil in Place (Stock Tank Bbls)
𝑣 𝑏 = Reservoir Bulk Volume (Bbls)
∅ = porosity
𝑠 𝑤𝑖 = Initial water saturation
𝐵 𝑜𝑖 = Oil Formation Volume Factor (Res. Vol./ S.T. vol.)
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7. ORIGINAL HYDROCARBON IN PLACE
2. For Gas,
OGIP = G =
𝑣 𝑏∗∅∗(1−𝑠 𝑤𝑖)
𝐵 𝑔𝑖
Where,
N= Original Gas in Place (Standard Cubic Feet)
𝑣 𝑏 = Reservoir Bulk Volume (Bbls)
∅ = Porosity
𝑠 𝑔𝑖 = Initial Gas Saturation
𝐵 𝑔𝑖 = Gas Formation Volume Factor (Res. Vol./ S.T. vol.)
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8. RECOVERY FACTOR (RF)
 The basic equation to calculate recoverable oil reserves is
Recoverable Oil reserves = OOIP x RF
Where, RF = Recovery Factor = RFp + RFs
RFp is primary recovery which depends on drive mechanism
RFs is secondary mechanism = EDxEAxEV
ED is Displacement efficiency
EA is Areal sweep efficiency
EV is vertical sweep efficiency
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9. RECOVERY FACTOR (RF)
The basic equation to calculate recoverable gas reserves is
Recoverable Gas reserves = OOIP x RF
Where, RF = Recovery Factor = RFp + RFs
The recovery factor (RF) is typically higher than for oil reservoirs; it is often
near unity for dry gas reservoirs.
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10. 3. PRODUCTION RATES AND FORECASTING
1. Permeability
2. Relative Permeability
3. Viscosity
4. Pressure Drop
5. Drainage Area
6. Radial Flow Equation
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11. RADIAL FLOW EQUATION
1. For Oil
𝑞 𝑜 =
7.08𝑘 𝑜ℎ(𝑃𝑒−𝑃 𝑤)
µ 𝑜 𝐵 𝑜ln(𝑟𝑒/𝑟 𝑤)
Where, 𝑞 𝑜 = Oil Flow Rate, (Stock Tank Bbls/day)
𝑘 𝑜 = Effective Oil Permeability (mD)
h = Net Pay (ft)
Pe = Reservoir Pressure (psia)
Pw = Bottomhole well flowing pressure (psia)
µ 𝑜 = Viscosity of oil (cP)
𝐵𝑜 = Formation Volume Factor (Res Vol./ S.T. Vol)
re = Drainage Radius (ft)
𝑟𝑤 = Wellbore radius (ft)
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12. RADIAL FLOW EQUATION
2. For Gas
𝑞 𝑔=
0.703𝑘 𝑔ℎ(𝑃𝑒−𝑃 𝑤)
µ 𝑔TZln(𝑟𝑒/𝑟 𝑤)
Where, 𝑞 𝑔 = Gas Flow Rate, (Standard cubic feet/ day)
𝑘 𝑔 = Effective Gas Permeability (mD)
h = Net Pay (ft)
Pe = Reservoir Pressure (psia)
Pw = Bottomhole well flowing pressure (psia)
µ 𝑔 = Viscosity of gas (cP)
T = Temperature
Z = Compressibility Factor
re = Drainage Radius (ft)
𝑟𝑤 = Wellbore radius (ft)
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13. 4. SOURCE OF DATA
1. Offset and Regional Data
2. Mud Logs
3. Electrical logs
4. Drill Stem Test
5. Production Test
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14. 5. CONCLUSION
 Introduction of Reserves Estimation
 Parameter for estimating hydrocarbon reserves
 Variables in forecasting in production rates
 Data sources used to determine viability
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15. T H A N K Y O U
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