Reservoir-Fluid Property Correlations-State of the Art (includes associated papers 23583 and 23594 )

Summary. This paper presents correlations to determine reservoir-fluid properties from field data. The best available correlations were selected by comparison with a data base of hundreds of reservoir-fluid studies of samples representing all areas of the free world involved in active petroleum exploitation from 1980 to 1986. Also, correlations of formation-water properties are given.

Introduction

Values of reservoir liquid and gas properties are often needed when laboratory PVT data are not available. This paper shows how to use normally available field data to estimate fluid properties.

While at Texas A and M U., I had access to a data base of hundreds of reservoir-fluid studies provided by Core Laboratories Inc. The geographical and geological origins of the reservoir samples had been carefully removed from the data but the samples were known to represent all areas of the free world in which petroleum exploitation was active during the first 6 years of the 1980's.

All reservoir-fluid property correlations available in the petroleum engineering literature were compared with this data base. This paper gives the best correlations.

Identification of Reservoir-Fluid Type

Surprisingly accurate "rules of thumb" are available to identify reservoir-fluid type from field data. When the initial producing GOR is less than 3,300 scf/STB, the fluid is a liquid at reservoir conditions. Possible exceptions occur if the stock-tank liquid is colorless or has a gravity higher than about 50 degrees API.

Reservoir liquids are either black oils or volatile oils; the general material-balance equations work only for black oils. The behavior of volatile oils does not fit the assumptions inherent in the derivation of the material-balance equations. Black oils are identified as having initial producing GOR's below 2,000 scf/STB and deeply colored stock-tank oil with gravities below 45 degrees API.

Reservoir gases are classified as retrograde gases (often called condensate gases or gas condensate), wet gases, and dry gases. Retrograde gases have initial producing GOR's >3,300 scf/STB. The few exceptions of oils that have ratios higher than this are identified as having deeply colored stock-tank liquids with gravities less than 40 degrees API. Retrograde behavior occurs for gases with initial producing GOR's of 150,000 scf/STB or higher;however, as a practical matter, gases with initial producing GOR's > 50,000 scf/STB can be treated as wet gases.

The term wet gas is used for a gas that does not release condensate in the reservoir but does form hydrocarbon liquid at the surface. The term dry gas is used for a gas that does not form any hydrocarbon liquid at the surface. In this context, the terms "wet" and "dry" do not refer to water or water vapor, which is always present to some extent.

Properties of Reservoir Liquids

The physical properties discussed next apply only to black oils. Engineering a volatile-oil reservoir requires a special laboratory study not discussed here.

Solution GOR at Bubblepoint, Rsb. The initial producing GOR provides a good estimate of solution GOR for use at pressures equal to and above. bubblepoint pressure. Ms wig not be true if free gas from a gas cap or another formation is produced with the oil. Field data often exhibit a great deal of scatter; however, a trend of constant GOR usually can be discerned before reservoir pressure drops below the bubblepoint.

Often the reported values of producing GOR do not include stocktank vent gas. In this case, the use of initial producing GOR for solution GOR results in values that are low by 10% or more. The stock-tank GOR can be estimated with

log RST =A1+A2 log o +As log gSP+A4 log PSP

+a5 log Tsp,............................................ (1)

where A1=0.3818, A2=-5.506, A3=2.902, A4=1.327, and A5=-0.7355. Eq. 1 should not be used if the separator temperature is >140 degrees F.

Addition of the estimate of stock-tank GOR from Eq. 1 to the separator GOR results in an estimate of solution GOR accurate to within 3 %.

Bubblepoint Pressure, Pb. The bubblepoint pressure of the oil at reservoir conditions can be estimated with

Pb = 18.2(Cpb - 1.4),...................................... (2)

where Cpb =(Rs/ g)0.83 x 10(0.00091T-0.0125 API)..............(3)

to an accuracy of 15%. The specific gravity of the separator gas can be used for g; however, Rs should include stock-tank vent gas. The equations are valid to 325 degrees F.

A more accurate estimate of bubblepoint pressure can be obtained if reservoir pressure is measured regularly. Plot reservoir pressure and producing GOR vs. cumulative production. For a volumetric solution-gas-drive reservoir, pressure will decline rapidly initially, then flatten when reservoir pressure drops below the oil bubblepoint pressure (the pressure at which the line changes slope). The producing GOR will begin to increase shortly after bubblepoint pressure is reached.

Solution GOR, Rs. Eqs. 2 and 3 can be used to estimate solution GOR for pressures below the bubblepoint. Enter any pressure below bubblepoint in place Of Pb in Eq. 2 and calculate the corresponding value of solution GOR with Eq. 3. The results should be within 15% of measured values.

If a field-derived bubblepoint pressure has been obtained from pressure measurements as described above. the accuracy of the estimates of solution GOR can be improved. Start by creating a table of pressures and solution GOR'S. Subtract the field-derived bubblepoint pressure from the bubblepoint pressure calculated with Eqs. 2 and 3 to obtain a "delta pressure." Subtract this "delta pressure" from all pressures in the Rs vs. p table. This procedure works very well for pressures near the bubblepoint. It is less accurate at low pressures.

Oil FVF, Bo. The oil FVF for use at pressures equal to or below bubblepoint can be estimated with

Bob =0.9759+12(10 -5)C Bob 1.2,......................... (4)

where C Bob=Rs( g/ o)0.5+1.25T..............................(5)

The equations can be used for any pressure equal to or below the bubblepoint by inserting the corresponding value of solution GOR estimated as discussed above. The resulting FVF value will be within 5% of laboratory-measured values if accurate values of solution GOR are used. If solution GOR's are obtained with Eqs. 2 and 3. the accuracy of the resulting FVF values will be some unknown combination of the 15% accuracy of Eqs. 2 and 3 and the 5% accuracy of Eqs. 4 and 5. Do not use at temperatures above 352 degrees F.

SPERE

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