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Reservoir engineering

Reservoir engineering answers the questions of how much hydrocarbon can be recovered, at what rate and with what energy.

The sections run from reservoir conditions and fluid properties to rock properties and the laws of flow, and then to material balance, aquifers and displacement.

48 / 48 topicsWhere to start: Reservoir engineering: tasks across the life of a field

Reservoir conditions and development tasks

  1. 01Reservoir engineering: tasks across the life of a fieldA road map of field development: the three main questions — how much oil there is, what share of it can be recovered and how fast — the tasks of the reservoir engineer in exploration and appraisal, planning, production and the late stage, the data and uncertainty of each stage, project documents in Kazakhstan, why every reservoir is unique and how development is tied to geology, drilling, production and economics; where oil is left after waterflooding and how a production decline curve is extrapolated. Basic
  2. 02Systems of units: SI, oilfield and metric oilfieldSI, US oilfield and metric oilfield units; conversion factors derived from the exact definitions of the foot, pound, gallon, atmosphere and darcy, and how many digits to keep; absolute and gauge pressure, temperature scales; standard and normal conditions (20 °C, 15 °C, 60 °F, 0 °C) and why a gas volume is always quoted with its conditions; density, API gravity and barrels per tonne; deriving the constants in formulas and checking dimensions. Basic
  3. 03Reservoir pressure and temperatureNormal hydrostatic and abnormal pressure in an accumulation, pressure gradients of water, oil and gas, contacts and the pressure at the top of the reservoir from measurements, ways of measuring pressure and referring it to a datum, reservoir temperature and the geothermal gradient. Basic

Fluid composition and phase behaviour

  1. 04Composition of reservoir fluidsThe classes of hydrocarbons, non-hydrocarbon components — nitrogen, carbon dioxide, hydrogen sulfide — mole and mass fractions, the C7+ fraction and pseudo-components, oil density in API gravity. Basic
  2. 05Phase behaviour: pure substances and binary mixturesThe phase diagram of a pure substance, vapour pressure, the critical point, bubble and dew points of a mixture, the cricondenbar, the cricondentherm and retrograde condensation. Intermediate
  3. 06Types of reservoir fluidsBlack oil and volatile oil, gas condensate, wet gas and dry gas: the position of reservoir temperature relative to the phase envelope, field indicators (producing gas–oil ratio, °API, C7+), sample recombination, gas cycling, accumulations with a gas cap. Intermediate

Gas properties

  1. 07Ideal and real gas: the gas deviation factor (Z)The ideal gas equation of state and standard conditions, why a real gas departs from the ideal, the law of corresponding states, pseudo-critical properties from composition and from specific gravity, the correction for hydrogen sulfide and carbon dioxide, and calculation of the gas deviation factor Z. Basic
  2. 08Gas formation volume factor, compressibility and viscosityThe gas formation volume factor and expansion factor in metric and oilfield units, gas density at reservoir conditions, isothermal compressibility, gas viscosity and its dependence on pressure and temperature, pseudo-pressure. Intermediate
  3. 09Cubic equations of stateThe van der Waals, Soave–Redlich–Kwong and Peng–Robinson equations: parameters from critical constants and the acentric factor, roots for gas and liquid, mixing rules and binary interaction coefficients, fugacity, volume translation, accuracy and tuning. Advanced

Reservoir oil properties

  1. 10Black oil model: solution gas–oil ratio and formation volume factorsSolution gas–oil ratio and the formation volume factors of oil and gas above and below the bubble point pressure, the total formation volume factor, converting volumes and rates between reservoir and surface conditions, the limits of the model. Intermediate
  2. 11Density and compressibility of reservoir oilStock-tank oil density, specific gravity and API gravity referred to standard temperature; reservoir oil density from a mass balance with the formation volume factor and solution gas–oil ratio, and its minimum at the bubble point pressure; the pressure gradient in the oil zone and the formation volume factor derived from it; isothermal compressibility above the bubble point pressure — instantaneous and average, from experiment and from the Vasquez–Beggs correlation; apparent compressibility below the bubble point pressure and the thermal expansion of oil. Intermediate
  3. 12PVT correlations for oil and gas condensateCorrelations for bubble point pressure, solution gas–oil ratio and oil formation volume factor — Standing, Lasater, Vasquez–Beggs, Glasø, Al-Marhoun, Petrosky–Farshad — and the oils on which they were built; input data in oilfield units, error estimation against laboratory data, tuning to a single sample, limits of applicability, the formation volume factor of gas condensate. Intermediate
  4. 13Oil viscosity and interfacial tensionDynamic and kinematic viscosity and their units; the viscosity of dead (stock-tank) oil as a function of temperature and density, and of oil with dissolved gas below and above the bubble point pressure — the Beggs–Robinson, Vasquez–Beggs and other correlations against laboratory data; heavy oils; oil–gas interfacial tension by the parachor method and oil–water interfacial tension, its role in capillary pressure and the capillary number. Intermediate

Phase equilibrium and PVT studies

  1. 14Vapour–liquid equilibriumEquilibrium ratios of ideal and real mixtures, flash calculation with the Rachford–Rice equation, bubble point and dew point pressures, the stability test and the equation-of-state equilibrium calculation loop. Advanced
  2. 15Separator calculations and optimum separator pressureMultistage separation as a chain of flash calculations: mole balance by stage, the gas–oil ratio of each stage, solution gas–oil ratio and formation volume factor from composition with a mass-balance check, the optimum pressure of the first stage, the effect of temperature and of the number of stages. Advanced
  3. 16Equilibrium ratios: correlations and equations of stateWhere equilibrium ratios come from: the Hoffman plot and the Standing correlation for separators, convergence pressure and the Whitson–Torp equation, the K-values of the C7+ fraction and its characterisation, calculation with an equation of state, the requirements for compositional data and how the choice of method changes the flash calculation. Advanced
  4. 17Reservoir fluid samplingA representative sample and well conditioning, bottomhole and single-phase samplers, formation-tester samples and contamination by oil-based mud filtrate, separator samples and recombination at the corrected gas–oil ratio, gas condensates, checking samples at the well site, documentation and transport. Intermediate
  5. 18Laboratory PVT testsThe PVT cell and the tests on an oil sample: constant-composition expansion (bubble point pressure, relative volume, Y-function, compressibility), differential liberation, separator tests and the role of the separation stages, converting differential data to separator conditions, viscosity measurement; for gas condensate, constant volume depletion and the two-phase gas deviation factor. Intermediate
  6. 19How to read a PVT reportWhat an oil or gas-condensate report contains and on what basis each number is given — absolute or gauge pressure, standard conditions for gas, residual or stock-tank oil, m³/t; whether the sample is fit for use — duplicates, the history of the sample, the margin above bubble point pressure at sampling and reservoir pressure; consistency of the tables — mass balance of the liberation and separator test, the Y-function, the total formation volume factor calculated two ways; the black oil property table and the check for positive apparent compressibility; the gas-condensate report — dew point against reservoir pressure and the p/Z line of the constant volume depletion test. Intermediate
  7. 20Retrograde condensation, wax, asphaltenes and high-pressure fluidsRetrograde condensation near wells and condensate banking — the three flow regions, the relative-permeability ratio from the constant-composition experiment and the loss of rate; wax — wax appearance temperature and pour point, deposits and cooling of the reservoir by cold water, the oils of Mangyshlak; asphaltenes — onset pressure, the de Boer screening plot and the colloidal instability index; hydrates; near-critical and high-pressure, high-temperature fluids; variation of composition with depth. Advanced

Rock properties

  1. 21PorosityThe fraction of void space in a rock: total, effective and isolated porosity, primary and secondary, measurement on core and from logs, averaging and its link to hydrocarbons in place. Basic
  2. 22Fluid saturationThe fractions of pore volume occupied by water, oil and gas: irreducible water and residual oil, the saturation profile and the transition zone, determination from core and logs, movable oil and the displacement efficiency. Basic
  3. 23Core analysisThe path of core from the well to the results: coring and preservation, scanning and depth matching, cleaning and drying of samples, routine and special core analysis, converting laboratory values to reservoir conditions and comparing them with logs and well tests. Basic
  4. 24Rock permeabilityThe ability of a rock to transmit fluid under a pressure difference: Darcy's law, units (darcy, millidarcy, m²), measurements, radial flow, anisotropy and averaging across layers. Basic
  5. 25Rock compressibility and the effect of stress on core propertiesEffective stress and its increase during depletion; compressibility of grains, rock and pore volume; measurements under confining stress and conversion of laboratory compressibility to reservoir conditions; the dependence of porosity and permeability on load, compaction of the reservoir and surface subsidence. Intermediate
  6. 26Wettability and interfacial phenomenaInterfacial tension, contact angle and Young's equation, water-wet, oil-wet and mixed-wettability rocks, the Amott and USBM methods, and the effect of wettability on capillary pressure, relative permeability and waterflooding. Intermediate
  7. 27Capillary pressure and the transition zoneCapillary pressure in pores, drainage and imbibition curves and their hysteresis, laboratory methods and conversion to reservoir conditions, the Leverett J-function, the free water level, the oil–water contact and the transition zone in a homogeneous and a layered reservoir. Intermediate
  8. 28Relative permeabilityHow permeability is shared between the phases when oil, gas and water flow together: effective and relative permeability, relative permeability curves and end points, the Corey model, fractional flow of water and water cut, the effects of wettability and hysteresis, laboratory measurements. Intermediate
  9. 29Reservoir heterogeneity and permeability averagingReservoir heterogeneity at different scales; average permeabilities of layers for linear and radial flow and of concentric zones around a well; random mosaics and averages of log-normal permeability; the ratio of vertical to horizontal permeability and communication between layers; the Dykstra–Parsons and Lorenz coefficients, their relationship and accuracy; correlation length and the choice of reservoir model. Intermediate

Flow in porous media and transient inflow

  1. 30Flow regimesSteady-state, pseudo-steady-state and transient regimes: how pressure changes in time and in space, the roles of compressibility and hydraulic diffusivity, how long each regime lasts, how to recognise it from the bottomhole flowing pressure, flow geometries and the choice of calculation model. Intermediate
  2. 31Diffusivity equationHow the equation of transient flow in porous media follows from mass balance, Darcy's law and compressibility: the derivation for radial flow, the assumptions and accuracy of linearisation, the general form with the permeability tensor and gravity, initial and boundary conditions, dimensionless variables in metric and oilfield units. Advanced
  3. 32Line-source solution and the pressure functionPressure around a well producing at a constant rate in an infinite reservoir: the line-source solution through the exponential integral, the logarithmic approximation and the conditions for its use, the well pressure function and its limits, the response in a neighbouring well, production at constant bottomhole pressure. Advanced
  4. 33Superposition principleAdding solutions of the diffusivity equation: several wells and interference testing, a rate change or shut-in treated as the start of another well, skin in superposition, the superposition time function for a multi-rate record, image wells in place of reservoir boundaries, and the cases where addition ceases to be exact. Advanced

Drive mechanisms and material balance

  1. 34Reservoir drive mechanismsSources of reservoir energy and the natural drive mechanisms — elastic (compressibility) drive, solution gas drive, gas cap drive, water drive, gravity drainage and compaction drive: how each shows itself in pressure, producing gas–oil ratio and water cut, typical oil recovery, sensitivity to the rate of withdrawal and combination drives. Intermediate
  2. 35Material balance for gas reservoirsThe balance of a closed gas reservoir and the p/Z line: gas in place from pressure and production data, why plain pressure cannot be plotted against production, pressure forecasting and gas recovery at abandonment pressure; water influx, apparent gas in place and trapped gas under water drive; the gas equivalent of condensate, assumptions and typical errors. Intermediate
  3. 36General material balance equation for oil reservoirsThe balance between underground withdrawal and the sources of reservoir energy: derivation of the general equation term by term, special cases above and below the bubble point pressure, estimating oil in place and water influx from production and pressure history, drive indices, assumptions, input data and the limitations of the method. Intermediate
  4. 37Straight-line material balance (Havlena–Odeh method)The material balance equation as a straight line: the compact notation F, Eo, Eg, Efw, plots for a reservoir with no gas cap, with a gas cap and with an aquifer, what the shape of the plot means, why oil in place and gas cap size are hard to separate, joint determination of oil in place and water influx from history, drive indices. Advanced
  5. 38Performance prediction for solution gas drive reservoirsWhy material balance alone is not enough below the bubble point pressure: the instantaneous gas–oil ratio from Darcy's law and how it differs from the cumulative one, average saturation from the balance, the step of Tarner's method, Tracy's formulation and the Muskat equation, checking relative permeabilities against the gas–oil ratio history, averaging pressure over drainage areas and moving to a forecast in time through well productivity. Advanced

Aquifer influx

  1. 39Aquifer models: water influxWhere the energy of an aquifer comes from and why influx lags behind the pressure decline; the elastic capacity of the aquifer, the pot (small) aquifer model and the steady-state model with calculation of the productivity index and of influx from pressure history; the ideas behind the pseudo-steady-state and unsteady-state models, the response time of the aquifer and the choice of model. Advanced
  2. 40Unsteady-state water influx: the van Everdingen–Hurst methodThe exact solution for a radial aquifer under a constant pressure drop at the contact: the aquifer constant, dimensionless time and the dimensionless influx of infinite and closed aquifers; superposition of pressure steps with drops based on the average pressures of the intervals, and its error; influx from pressure history, a check against material balance and pressure prediction by trial and error. Advanced
  3. 41History matching of aquifer parametersFitting an aquifer model to pressure and production history: what is adjusted and what it is compared with, the apparent aquifer constant, the Havlena–Odeh line with an unsteady-state influx function, matching on pressure and the measure of fit, non-uniqueness and a check on withheld data, geological limits on the parameters, the effective parameters of the Fetkovich and Carter–Tracy methods. Advanced
  4. 42Simplified water influx models: Fetkovich and Carter–TracyStep-by-step water influx models that avoid superposition over the whole history: the Fetkovich method (the aquifer as a tank behind a resistance, maximum encroachable water, productivity index, the recursive formula) and the Carter–Tracy method (the influence function and its derivative); comparison with the exact solution on one pressure history, model error and step error, small and large aquifers, choice of method. Advanced

Oil displacement

  1. 43Why water is injected: pressure maintenance and oil displacementThe two purposes of water injection — maintaining reservoir pressure and displacing oil; the recovery factor as the product of displacement efficiency and areal and vertical sweep; the mobility ratio; voidage replacement by injection and the balance at reservoir conditions; when to start injection; injection well patterns. Basic
  2. 44Fractional flow function and mobility ratioThe fractional flow equation from two-phase Darcy's law with gravity and capillary pressure; the shape of the curve and the mobility ratio; the effects of oil viscosity, wettability, reservoir dip and injection rate; the gravity number and capillary length; the curve as a working tool — water cut, saturation at the well, comparison of options. Intermediate
  3. 45Buckley–Leverett theory and the Welge methodOne-dimensional displacement of oil by water: the saturation advance equation, the saturation jump at the front and the Welge tangent, average saturation behind the front, water breakthrough time, oil production up to and after breakthrough, the effect of oil viscosity; calculation for a line-drive pattern element, the displacement efficiency of the reservoir over time, the assumptions of the theory and checking the models. Advanced
  4. 46Segregated flow and gravity displacementDisplacement with a sharp interface between the phases in a dipping reservoir under vertical equilibrium: when the phases have time to segregate across the thickness, the condition for a stable interface and the critical rate for water and gas up-dip and down-dip, the tilt of the interface below the critical rate, thickness-averaged relative permeabilities and calculation of breakthrough and production, the limiting rate of gravity drainage. Advanced
  5. 47Displacement in heterogeneous reservoirsWaterflooding a layered reservoir: vertical sweep, layers without crossflow — the Stiles and Dykstra–Parsons methods, sweep as a function of the volume injected and the mobility ratio; crossflow and vertical equilibrium, pseudo-functions for the cross-section; gravity, the ratio of vertical to horizontal permeability and the order of the layers; comparison of the methods with field water cut and the fractional flow curve of the reservoir from production history. Advanced
  6. 48Displacement of oil by gasImmiscible displacement of oil by gas: gas fractional flow and the Buckley–Leverett solution, the unfavourable mobility ratio, early breakthrough and the rise in gas–oil ratio, gravity stabilisation with crestal injection and gas cap expansion, gas injection for pressure maintenance and make-up gas, residual oil to gas, the idea of miscibility; gas reinjection at Tengiz and Karachaganak. Advanced

This section is growing: new topics are published after a technical review.