Equations of state for basin geofluids: algorithm review and intercomparison for brines

Physical properties of formation waters in sedimentary basins can vary by more than 25% for density and by one order of magnitude for viscosity. Density differences may enhance or retard flow driven by other mechanisms and can initiate buoyancy-driven flow. For a given driving force, the flow rate and injectivity depend on viscosity and permeability. Thus, variations in the density and viscosity of formation waters may have or had a significant effect on the flow pattern in a sedimentary basin, with consequences for various basin processes. Therefore, it is critical to correctly estimate water properties at formation conditions for proper representation and interpretation of present flow systems, and for numerical simulations of basin evolution, hydrocarbon migration, ore genesis, and fate of injected fluids in sedimentary basins. Algorithms published over the years to calculate water density and viscosity as a function of temperature, pressure and salinity are based on empirical fitting of laboratory-measured properties of predominantly NaCl solutions, but also field brines. A review and comparison of various algorithms are presented here, both in terms of applicability range and estimates of density and viscosity. The paucity of measured formation-water properties at in situ conditions hinders a definitive conclusion regarding the validity of any of these algorithms. However, the comparison indicates the versatility of the various algorithms in various ranges of conditions found in sedimentary basins. The applicability of these algorithms to the density of formation waters in the Alberta Basin is also examined using a high-quality database of 4854 water analyses. Consideration is also given to the percentage of cations that are heavier than Na in the waters.

[1]  R. Mckibbin,et al.  A Model for Deep Geothermal Brines, II: Thermodynamic Properties – Density , 1998 .

[2]  Craig M. Bethke,et al.  A Numerical Model of Compaction-Driven Groundwater Flow and Heat Transfer and Its Application to the Paleohydrology of Intracratonic Sedimentary Basins , 1985 .

[3]  G. Garven.  A hydrogeologic model for the formation of the giant oil sands deposits of the Western Canada sedimentary basin , 1989 .

[4]  R. Mckibbin,et al.  A Model for Deep Geothermal Brines,III: Thermodynamic Properties – Enthalpy and Viscosity , 1998 .

[5]  Grant Garven,et al.  The role of regional fluid flow in the genesis of the Pine Point Deposit, Western Canada sedimentary basin , 1985 .

[6]  Allen M. Rowe,et al.  Pressure-volume-temperature-concentration relation of aqueous sodium chloride solutions , 1970 .

[7]  R. Potter,et al.  Volumetric properties of aqueous sodium chloride solutions from 0/sup 0/ to 500/sup 0/C at pressures up to 2000 bars based on a regression of available data in the literature , 1977 .

[8]  B. Hitchon,et al.  Culling criteria for “standard” formation water analyses , 1994 .

[9]  K. Michael,et al.  Flow of variable-density formation water in deep sloping aquifers: minimizing the error in representation and analysis when using hydraulic-head distributions , 2002 .

[10]  T. Isono.  Density, viscosity, and electrolytic conductivity of concentrated aqueous electrolyte solutions at several temperatures. Alkaline-earth chlorides, LaCl3, Na2SO4, NaNO3, NaBr, KNO3, KBr, and Cd(NO3)2 , 1984 .

[11]  S. L. Phillips,et al.  A Technical Databook for Geothermal Energy Utilization , 1981 .

[12]  V. Vand.  Viscosity of solutions and suspensions; experimental determination of the viscosity-concentration function of spherical suspensions. , 1948, The Journal of physical and colloid chemistry.

[13]  Zhijing Wang,et al.  Seismic properties of pore fluids , 1992 .

[14]  I. G. Donaldson,et al.  A Galerkin‐finite element analysis of the hydrothermal system at Wairakei, New Zealand , 1975 .

[15]  R. Mckibbin,et al.  A Model for Deep Geothermal Brines, I: T-p-X State-Space Description , 1998 .

[16]  R. J. Correia,et al.  Viscosity and density of aqueous Na/sub 2/SO/sub 4/ and K/sub 2/SO/sub 4/ solutions in the temperature range 20 to 90/sup 0/C and the pressure range 0 to 30 MPa , 1980 .

[17]  T. Patzek,et al.  MODELING OF MULTIPHASE TRANSPORT OF MULTICOMPONENT ORGANIC CONTAMINANTS AND HEAT IN THE SUBSURFACE : NUMERICAL MODEL FORMULATION , 1993 .

[18]  H. Ezzat Khalifa,et al.  Tables of the Dynamic and Kinematic Viscosity of Aqueous KCl Solutions in the Temperature Range 25-150 C and the Pressure Range 0.1-35 MPa, , 1981 .

[19]  J. Sengers,et al.  An Improved Representative Equation for the Dynamic Viscosity of Water Substance , 1980 .

[20]  Yoshiyuki Abe,et al.  Effect of pressure on the viscosity of aqueous sodium chloride solutions in the temperature range 20-150.degree.C , 1978 .

[21]  K. Pruess,et al.  The simulator TOUGH2/EWASG for modelling geothermal reservoirs with brines and non-condensible gas , 1997 .

[22]  Grant Garven,et al.  A sensitivity study of the driving forces on fluid flow during continental-rift basin evolution , 1994 .

[23]  W. McCain.  Reservoir-fluid property correlations; State of the art , 1991 .

[24]  J. Gates,et al.  Densities of aqueous solutions of sodium chloride, magnesium chloride, potassium chloride, sodium bromide, lithium chloride, and calcium chloride from 0.05 to 5.0 mol kg-1 and 0.1013 to 40 MPa at 298.15 K , 1985 .

[25]  S. Bachu.  Flow of variable-density formation water in deep sloping aquifers: review of methods of representation with case studies , 1995 .

[26]  J. Hanor.  Origin of saline fluids in sedimentary basins , 1994, Geological Society, London, Special Publications.

[27]  M. Hubbert,et al.  Entrapment of Petroleum Under Hydrodynamic Conditions , 1953 .

[28]  C. Bethke.  Hydrologic constraints on the genesis of the Upper Mississippi Valley mineral district from Illinois Basin brines , 1986 .