# Predicting hydrocarbon recovery

Series Exploring for Oil and Gas Traps Treatise in Petroleum Geology Predicting the occurrence of oil and gas traps Predicting reservoir system quality and performance Dan J. Hartmann, Edward A. Beaumont Web page AAPG Store

The volume of hydrocarbon contained in a reservoir is a function of pore volume and water saturation (Sw). Reservoir size and porosity determine pore volume. Pore throat size (see Pore and pore throat sizes) distribution, pore geometry, and hydrocarbon column height determine Sw. Estimating hydrocarbon volume in place before drilling a well is a matter of predicting pore volume and Sw. Recovery of hydrocarbons depends on the efficiency of the reservoir drive mechanism. Predicting recovery depends on predicting reservoir quality and reservoir drive.

## Calculating oil volume in place

To calculate volume of original oil in place (OOIPoriginal oil in place)in barrels from volume measured in acre-feet, use the following formula: ${\text{OOIP}}={\frac {7758\times {\text{A}}\times {\text{h}}\times \Phi \times (1-{\text{S}}_{{\text{w}}})}{{\text{B}}_{{\text{oi}}}}}$

where:

• 7758 = conversion factor from acre-ft to bblbarrels
• A = area of reservoir, acres from map data
• h = thickness of reservoir pay, ft
• Φ = porosity (decimal, not percent)
• Sw = water saturation (decimal, not percent)
• Boi = formation volume factor = 1.05 + (N × 0.05), where N = number of ft3 of gas produced per bblbarrels of oil (gas-oil ratio or GOR). For example, if a well has a GORgas-oil ratio of 1,000, then Boi = 1.05 + (10 × 0.05) = 1.1.

## Calculating gas volume in place

To calculate volume of original gas in place (OGIPoriginal gas in place) in cubic feet from volume measured in acre-feet, use the following formula: ${\text{OGIP}}=43,560\times {\text{A}}\times {\text{h}}\times \Phi \times (1-{\text{S}}_{{{\rm {w}}}})\times \left({\text{depth}}\times {\frac {0.43}{15}}\right)$

where:

• 43,560 = conversion factor from acre-ft to ft3

## Estimating recoverable volume of oil or gas

Estimating recoverable oil or gas depends on predicting reservoir quality and reservoir drive. Reservoir analogs help narrow the range of values for variables that determine recovery factor (R.F.). Use the equation below to estimate the recoverable oil or gas in a reservoir: ${\text{Recoverable oil or gas}}={\text{OHIP}}\times {\text{R.F.}}$

where:

• OHIP = original hydrocarbons in place

## Estimating recovery factor

Drive mechanism has the greatest geological impact on recovery factor. (See Drive mechanisms and recovery.) Narrowing the range in recovery factor is a matter of estimating how much difference pore type and reservoir heterogeneity impact the efficiency of the drive mechanism. To estimate the recovery factor, use the procedure below:

1. Decide which drive mechanism is most likely from the geology of the prospective reservoir system and by comparing it with reservoir systems of nearby analog fields or analog fields in other basins.
2. Multiply OOIPoriginal oil in place or OGIPoriginal gas in place by the recovery factor for the expected drive.
3. Narrow the recovery factor range by predicting the thickness of the reservoir by port type. Port type affects recovery rate. For example, in a reservoir with strong water drive and macroporosity, recovery will be up to 60%, mesoporosity recovery will be up to 20%, and microporosity recovery will be 0%.

## Recovery factors for different drive types

The table below shows recovery factor percentages for different drive mechanisms for oil vs. gas reservoirs.

Reservoir drive mechanism Percent ultimate recovery
Gas Oil
Strong water 30–40 45–60
Partial water 40–50 30–45
Gas expansion 50–70 20–30
Solution gas N/A 15–25
Rock 60–80 10–60
Gravity drainage N/A 50–70