New correlations for density of methane-free sodium chloride brine and solubility of methane in sodium chloride brines, valid over wide ranges of pressure, temperature, and salinity, are presented. Both correlations agree with the best available measurements within experimental error over most of the range of validity. These new correlations are combined with published correlations for methane partial molar volume to provide accurate and internally consistent estimates of brine density, specific volume, formation volume factor, and coefficient of isothermal compressibility at pressures above or below the bubble point pressure. The brine density correlation is valid for temperatures from 0 to 275 ° C (32 to 527 ° F), pressures from 0.1 to 200 MPa (14.5 to 29,000 psi), and sodium chloride content from 0 to 6 moles/kg H2O (0 to 26﹪ by weight). The methane solubility correlation is valid for temperatures from 20 to 360 ° C (68 to 680 ° F), pressures from 0.9 to 200 MPa (130 to 29,000 psi), and sodium chloride content from 0 to 6 moles/kg H2O (0 to 26﹪ by weight). A modification of an existing correlation for brine viscosity is also presented, extending its range of applicability to temperatures between 20 and 300 ° C (68 to 572 ° F), pressures between 0.1 and 200 MPa, and salinity between 0 and 5.4 moles NaCl/kgH2O (0 to 25﹪ NaCl by weight). Introduction Oil companies today produce in excess of 33 million cubic metres of water per day (210 MMbbl/day). The associated cost of handling this water production is estimated to exceed $40 billion per year(1). Understanding and dealing with these costs requires accurate knowledge of the water properties. Properties such as density, viscosity, and solubility affect the volume and movement of water through the reservoir, in the well bore, and at the surface facilities. As water production continues to increase, so does the importance of our understanding of the properties of the produced water. Many experimental studies of the behaviour of systems comprising water, sodium chloride, and methane have been reported in the physical chemistry literature during the last 25 years. By and large, the results of these studies have not been widely disseminated within the petroleum engineering community. In this paper, we present new correlations based on the published data for estimating those properties of primary interest to the petroleum engineer, namely the density, specific volume, methane solubility, formation volume factor, coefficient of isothermal compressibility, and viscosity. The next two sections of the paper discuss the development of the new brine density and methane solubility correlations. The third section shows how the brine density and methane solubility correlations may be combined with previous work to calculate internally consistent values for reservoir brine density, specific volume, coefficient of isothermal compressibility, and solution gas-water ratio at pressures above or below the bubble point pressure. The final section presents a modification of a published brine viscosity correlation, extending its range of applicability to temperatures of 300 ° C (572 ° F) and pressures of 200 MPa (29,000 psi).
Summary. This paper presents correlations to determine reservoir-fluidproperties from field data. The best available correlations wereselected by comparison with a data base of hundreds of reservoir-fluid studies of samples representing all areas of the free world involvedin active petroleum exploitation from 1980 to 1986. Also, correlationsof 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 touse 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. Thegeographical and geological origins of the reservoir samples hadbeen carefully removed from the data but the samples were knownto represent all areas of the free world in which petroleumexploitation was active during the first 6 years of the 1980's. All reservoir-fluid property correlations available in thepetroleum engineering literature were compared with this data base. Thispaper gives the best correlations. Identification of Reservoir-Fluid Type Surprisingly accurate "rules of thumb" are available to identifyreservoir-fluid type from field data. When the initial producing GORis less than 3,300 scf/STB, the fluid is a liquid at reservoir conditions. Possible exceptions occur if the stock-tank liquid is colorless orhas a gravity higher than about 50 degrees API. Reservoir liquids are either black oils or volatile oils; thegeneral material-balance equations work only for black oils. Thebehavior of volatile oils does not fit the assumptions inherent in thederivation of the material-balance equations. Black oils areidentified as having initial producing GOR's below 2,000 scf/STB anddeeply 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 areidentified as having deeply colored stock-tank liquids with gravities lessthan 40 degrees API. Retrograde behavior occurs for gases with initialproducing GOR's of 150,000 scf/STB or higher;however, as a practicalmatter, gases with initial producing GOR's > 50,000 scf/STB canbe treated as wet gases. The term wet gas is used for a gas that does not releasecondensate in the reservoir but does form hydrocarbon liquid at thesurface. The term dry gas is used for a gas that does not form any hydrocarbonliquid at the surface. In this context, the terms "wet"and "dry" do not refer to water or water vapor, which is alwayspresent 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 studynot discussed here. Solution GOR at Bubblepoint, Rsb. The initial producing GORprovides a good estimate of solution GOR for use at pressures equalto and above. bubblepoint pressure. Ms wig not be true if free gasfrom a gas cap or another formation is produced with the oil. Fielddata often exhibit a great deal of scatter; however, a trend ofconstant GOR usually can be discerned before reservoir pressure dropsbelow the bubblepoint. Often the reported values of producing GOR do not includestocktank vent gas. In this case, the use of initial producing GOR forsolution GOR results in values that are low by 10% or more. Thestock-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 separatortemperature is >140 degrees F. Addition of the estimate of stock-tank GOR from Eq. 1 to theseparator GOR results in an estimate of solution GOR accurate towithin 3 %. Bubblepoint Pressure, Pb. The bubblepoint pressure of the oil atreservoir conditions can be estimated with Pb = 18.2(Cpb − 1.4),...................................... (2) where Cpb =(Rs/ g)0.83 × 10(0.00091T-0.0125 API)..............(3) to an accuracy of 15%. The specific gravity of the separator gascan be used for g; however, Rs should include stock-tank ventgas. 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 pressureand producing GOR vs. cumulative production. For a volumetricsolution-gas-drive reservoir, pressure will decline rapidlyinitially, then flatten when reservoir pressure drops below the oilbubblepoint pressure (the pressure at which the line changes slope). The producing GOR will begin to increase shortly after bubblepointpressure is reached. Solution GOR, Rs. Eqs. 2 and 3 can be used to estimate solution GOR for pressures below the bubblepoint. Enter any pressurebelow bubblepoint in place Of Pb in Eq. 2 and calculate thecorresponding value of solution GOR with Eq. 3. The results shouldbe within 15% of measured values. If a field-derived bubblepoint pressure has been obtained frompressure measurements as described above. the accuracy of theestimates of solution GOR can be improved. Start by creating atable of pressures and solution GOR'S. Subtract the field-derivedbubblepoint pressure from the bubblepoint pressure calculated with Eqs. 2 and 3 to obtain a "delta pressure." Subtract this "deltapressure" from all pressures in the Rs vs. p table. This procedure works very well for pressures near the bubblepoint. It is lessaccurate at low pressures. Oil FVF, Bo. The oil FVF for use at pressures equal to or belowbubblepoint 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 thebubblepoint by inserting the corresponding value of solution GORestimated as discussed above. The resulting FVF value will be within5% 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 unknowncombination of the 15% accuracy of Eqs. 2 and 3 and the 5%accuracy of Eqs. 4 and 5. Do not use at temperatures above 352degrees F. SPERE P. 266^
The Eagle Ford Shale is one of the most active U.S. shale plays; it produces oil, gas condensate, and dry gas. To better understand the regional and vertical variations of reservoir properties and their effects on fluid types and well performance, we conducted an integrated, regional study using production and well log data. Maps of the average gas-oil ratio (GOR) of the first three production months identified four fluid regions, including black oil, volatile oil, gas condensate, and dry gas regions. Maximum oil production occurs in Karnes County, where first-month oil production of most wells exceeds 5,000 barrels (bbl). The most productive gas region is between the Stuart City and Sligo Shelf Margins, where first-month gas production of most wells exceeds 60 million cubic feet (MMcf). Eagle Ford Shale petrophysical properties were analyzed in individual wells and were mapped to clarify the regionally variations of Eagle Ford Shale reservoir properties and their controls on fluid types and well performance. In comparison to the upper Eagle Ford, the lower Eagle Ford Shale has high gamma ray, high resistivity, low density, and long transit time values; we infer that the lower Eagle Ford shale has higher total organic carbon and lower carbonate content than the upper Eagle Ford Shale. Integration of production and geological data shows that thermal maturity and structural setting of the Eagle Ford Shale strongly influence fluid types and production rates. Plots of GOR vs. time for individual wells were constant in different reservoir fluids. Results of this study clarify causes of vertical and lateral heterogeneity in the Eagle Ford shale and the regional extents of fluid types. Understanding of the reservoir property differences between upper and lower Eagle Ford Shale should assist with optimizing completion design and stimulation strategies. The results may be applicable to similar developing shale plays.
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