Reservoir engineering and stimulation

Stock tank volume of oil initially in place by the volumetric method, in million barrels.

Free gas initially in place by the volumetric method, in million standard cubic feet.

Gas dissolved in oil initially in place by the volumetric method, in million standard cubic feet.

Initial oil in place by the volumetric formula of Russian and Kazakh reserves reports (GKZ): oil-bearing area, net oil pay, porosity and oil saturation, shrinkage factor and oil density. The result is in thousand tonnes and thousand cubic metres of stock-tank oil, with the dissolved gas in place.

The recovery factor as the product of the displacement, sweep and flooding efficiencies; the displacement efficiency comes from the initial and residual oil saturations of core floods. Recoverable reserves are that share of the oil in place.

Liquid flow rate in linear flow by Darcy's law, in barrels per day.

Well flow rate for radial liquid flow by Darcy's law, in barrels per day.

Well flow rate for radial flow by Darcy's law, corrected by the oil formation volume factor, in cubic metres per day.

Theoretical productivity index of a vertical well in a bounded drainage area (circle, square, rectangle) from permeability, thickness, fluid properties and skin, and the same without skin. The drainage radius comes from the area per well.

Steady-state productivity index of a horizontal well by Joshi's equation with permeability anisotropy, compared with a vertical well in the same drainage area.

Viscosity of degassed oil at standard conditions from its density, for oil with a density of 0.845 to 0.924 g/cm³, in mPa·s.

Viscosity of degassed oil at standard conditions from its density, for oil with a density of 0.78 to 0.845 g/cm³, in mPa·s.

Viscosity of degassed oil at a given temperature from its laboratory viscosity and the coefficient a, in mPa·s. The coefficient c is chosen from the viscosity: 10 for μ > 1000, 100 for 10 ≤ μ ≤ 1000, 1000 for μ < 10.

Coefficient a for converting the viscosity of degassed oil to another temperature. The coefficients b and c are chosen from the viscosity: b = 0.00252 and c = 10 for μ > 1000; b = 0.00144 and c = 100 for 10 ≤ μ ≤ 1000; b = 0.00076 and c = 1000 for μ < 10.

Viscosity of gas-saturated oil at reservoir conditions from the degassed oil viscosity and the correlation coefficients A and B, in mPa·s.

Coefficients A and B for the viscosity of gas-saturated oil, from the gas-oil ratio at 15 °C and atmospheric pressure.

Converts the gas content of oil from standard conditions to 15 °C and atmospheric pressure, in m³/m³.

Thermal expansion coefficient of degassed oil from its relative density.

Oil formation volume factor from the gas-oil ratio, for gas-oil ratios up to 400 m³/m³.

Oil formation volume factor from the gas-oil ratio, for gas-oil ratios above 400 m³/m³.

Molecular weight of gas from its composition (in %), and the gas density at normal (0 °C) and standard (20 °C) conditions.

Converts the saturation (bubble-point) pressure of oil from reservoir temperature to another temperature, in MPa.

Converts the gas content of reservoir oil from m³/m³ to m³ per tonne at normal conditions (0 °C).

Density of gas-saturated oil from the oil and gas densities, the gas-oil ratio and the oil formation volume factor, in kg/m³.

Total compressibility of the rock and its fluids from the saturations and the oil, water, gas and pore compressibilities, and the storativity φ·c_t: inputs to well test interpretation, radius of investigation and diffusivity.

Formation fracture pressure by Eaton's method: the minimum horizontal stress from the overburden and pore pressures through Poisson's ratio. The gradient is given in kPa/m or as an equivalent density.

Expected surface pressure while pumping: the bottomhole treating pressure minus the hydrostatic head plus the friction in the pipe and through the perforations, and the hydraulic power of the pump fleet.

Pressure drop across the perforations: for limited-entry fracturing and for estimating the number of open perforations from a step-down test.

Proppant mass and slurry volume and density for a frac stage from the clean fluid volume and the proppant concentration in kilograms per cubic metre of fluid (in ppa, pounds added per gallon).

Dimensionless fracture conductivity F_CD, the equivalent skin and effective wellbore radius after fracturing from the Cinco-Ley and Samaniego chart, and the fold increase in productivity in pseudo-steady-state flow.

How much calcite or dolomite a cubic metre of acid dissolves: the gravimetric (β) and volumetric (X) dissolving power from the reaction stoichiometry, the mass of rock dissolved and the CO₂ released.

Volume of acid to fill the pores and dissolve the carbonate minerals in a ring around the well out to a given radius: in total and per metre of pay. The typical case is the hydrochloric acid preflush ahead of a mud acid treatment of a sandstone.

Current voidage replacement at reservoir conditions: the injected water against the produced oil, water and free gas, and the injection needed for 100 % replacement.

The water-oil mobility ratio from the end-point relative permeabilities, and the water fractional flow at a given water saturation with Corey curves: the stability of the displacement front and the water cut.