Reservoir Fluids: Oil and Gas

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Summary

Reservoir engineering covers fluids in a gas or oil-bearing reservoir, movement of those or injected fluids, and evalua­tion of the factors governing the recovery of oil or gas. The objectives of a reservoir engineer are to maximize production and recovery at the lowest cost in time and money.

Basic Principles, Definitions, and Data

Reservoir Fluids Oil and gas

Reservoir oil may be saturated with gas with the degree dependent upon reservoir pressure and temperature. When it is totally saturated, the excess gas becomes a free gas cap. Oil is either undersaturated, saturated or saturated with a free gas cap. The point of saturation is called bubble-point pressure, and the gas begins coming out of a saturated solution as soon as the reservoir pressure begins to decrease. In the case of under-saturated oil, the gas does not start coming out of solution until the reservoir pressure drops to the level of saturation pressure.

As the gas comes out of solution the viscosity of oil increases and its gravity decreases, making it difficult for the oil to flow through the reservoir toward the wellbore. On produced oil, as the gas comes out of solution the oil shrinks so that the liquid oil at surface conditions will occupy less volume than the gas-saturated oil occupied in the reservoir. The number of barrels of reservoir oil at reservoir pressure and temperature which will yield one barrel of stock tank oil at 60^◦F and atmospheric pressure is the formation volume factor or reservoir volume factor. The solution gas–oil ratio is the number of standard cubic feet of gas per barrel of stock tank oil.

Physical properties of reservoir fluids are determined in the laboratory, either from bottomhole samples or from recombined surface separator samples, or charts are used, based present bubble-point pressures, formation volume factors of bubble-point liquids, formation volume factors of gas plus liquid phases, and, density of a bubble-point liquid as empirical functions of gas-oil ratio, gas gravity, oil gravity, pressure, and temperature.

With the development of programmable calculators, graphical data are being replaced by mathematical expres­sions suitable for computer use. In a later section, the use of such programs for estimating PVT properties will be pre­sented. In the initial sections, the presentation of graphical data will be instructive to gaining a better understanding of the effect of certain variables.

Water

Interstitial or connate water is present in the reservoir in pores held by capillary forces, in amounts usually inversely proportional to the permeability of the reservoir, and ranges10% to 40% of saturation. Consideration of interstitial water content is of particular importance in reservoir studies, in estimates of crude oil reserves and in interpretation of electrical logs.

Fluid Viscosities

Gas Viscosity

Viscosities of natural gases are affected bypressure, temper­ature, and composition, and can be measured in the laboratory, but common prac­tice is to use available empirical data charts. The viscosity of a gas at low pressures increases as the temperature is raised. At high pressures, gas viscosity decreases as the temperature is raised. At intermediate pressure, gas viscosity may decrease as tem­perature is raised and then increase with further increase in temperature.

Oil Viscosity

The viscosity of crude oil is affected by pressure, tempera­ture, and most importantly, by the amount of gas in solution. Below the bubble-point, viscosity decreaseswith increas­ing pressure because of the thinning effect of gas going into solution. Above the bubble-point, viscosity increases with increasing pressure because of liquid compression. Undersaturated oil viscosity will decrease slightly as the reservoir pressure decreases. A minimum viscosity will occur at the saturation pressure. At pressures below the bubble-point, evolution of gas from solution will increase the density and viscosity of the crude oil as the reservoir pressure is decreased further. Viscosities of hydrocarbon liquids decrease with increas­ing temperature. One can measure viscosity of the dead oil with a viscometer at reservoir temperature.

With the dead oil viscosity at atmospheric pressure and reservoir temperature (either measured or obtained from Figure 5.1.9), the effect of solution gas can be estimated with the aid of charts.

Water Viscosity

In 1952, the National Bureau of Standards conducted tests which determined that the absolute viscosity of pure water was 1.0019 cp as compared with the value of 1.005 cp that had been accepted for many years, which is used to calibrate viscometers and standard oil samples. Water viscosity decreases as temperature is increased. Although the predominate effect on water viscosity is temperature, increased assalinity increases viscosity. Potassium chloride is an exception. For temperatures higher than 60 degrees the effect is slight.

Formation Volume Factors

These factors are used for converting the volume of fluids at the prevailing reservoir conditions of temperature and pressuretostandard surface conditionsof 14.7 psia and 60^◦F.

Gas Formation Volume Factor

The behavior of gas can be predicted from:

pV = znRT

where:

• p = absolute pressure
• V = volume of gas
• T = absolute temperature
• n = number of moles of gas
• R = gas constant
• z = factor to correct for nonideal gas behavior

To obtain the z factor, reduced pressure, pr , and reduced temperature, Tr , are calculated:

• pr = p
• pc (where pc is the critical pressure).

And:

• Tr = T
• Tc (where Tc is the critical temperature).

The critical pressure and temperature represent conditions above which the liquid and vapor phase are indistinguishable. Gas formation volume factors can be estimated by determining the gas deviation factor or compressibility factor, and can be expressed in so many different ways that care must be taken to make certain that all terminology matches. The critical pressure and temperature represent conditions above which the liquid and vapor phase are indistinguishable. Compressibility factor and gas formation volume factor can be more conveniently estimated by the use of programs available for hand-held calculators.

Oil Formation Volume Factor

The volume of hydrocarbon liquids produced and measured at surface conditions will be less than the volume at reservoir conditions. The primary cause is the evolution of gas from the liquids as pressure is decreased from the reservoir to the surface. When there is a substantial amount of dissolved gas, a large decrease in liquid volume occurs. Other factors that influence the volume of liquids include changes in tem­perature (a decrease in temperature will cause the liquid to shrink) and pressure (a decrease in pressure will cause some liquids to expand). All of these factors are included in the oil formation volume factor, B_o, which is the volume of oil in reservoir barrels, at the prevailing reservoir conditions of pressure and temperature, occupied by a stock tank barrel of oil at standard conditions. The withdrawal of reservoir fluids can be related to surface production volumes by obtaining laboratory PVT data with reservoir fluids. Such data include B_g (the gas formation volume factor), B_o (the oil formation volume factor), and R_s (the solution gas-oil ratio which is the volume of gas in standard ft³ that will dissolve in one stock tank barrel of oil at reservoir conditions).

The formation volume factor is used to express the changes in liquid volume accompanied by changes in pressure. As the initial reservoir pressure decreases, the all-liquid system expands and the formation volume factor increases until the bubble-point pressure is reached. As pressure decreases below the bubblepoint, gas comes out of solutions, the volume of oil is reduced, and B_o decreases. For a saturated solution above the bubblepoint,R_si equalsR_s,and the single-phaseand 2-phase formation volume factors are identical. At pressures below the bubblepoint, the 2-phase factor increases as pressure is decreased because of the gas coming out of solution and the expansion of the gas evolved. For a system above the bubblepoint pressure, B_o is lower than the formation volume factor at saturation pressure because of contraction of the oil at higher pressure. The customary procedure is to adjust the oil formation volume factor at bubble-point pressure and reservoir temperature by a factor that accounts for the isothermal coefficient of compressibility.

The basic PVT properties (Bo, Rs, and Bg) of crude oil are determined in the laboratory with a high-pressure PVT cell. When the pressure of a sample of crude oil is reduced, the quantity of gas evolved depends on the conditions of liberation. In the flash liberation process, the gas evolved during any pressure reduction remains in contact with the oil. In the differential liberation process, the gas evolved during any pressure reduction is continuously removed from contact with the oil. As a result, the flash liberation is a constant-composition, variable-volume process and the differential liberation is a variable-composition, constant-volume process.

For heavy crudes (low volatility, low API gravity oils) with dissolved gases consisting primarily of methane and ethane, both liberation processes yield similar quantities and compositions of evolved gas as well as similar resulting oil volumes. However, for lighter, highly volatile crude oils containing a relatively high proportion of intermediate hydrocarbons (such as propane, butane, and pentane), the method of gas liberation can have an effect on the PVT properties that are obtained.

For reservoir fluids at the bubblepoint when a well is put on production, the gas evolved from the oil as the pressure declines does not flow to the well until the critical gas saturation is exceeded. Since the greatest pressure drop occurs near the wellbore, the critical gas saturation occurs first near the well, especially if the pressure drop is large.

Several correlations are available for estimating formation volume factors. Empirical equations have been developed from Standing’s graphical data.

Water Formation Volume Factor

The factors discussed that affected B_o also affect the water formation volume factor, B_w. However, gas is only slightly soluble in water so evolution of gas from water has a negligible effect on B_w. Expansion and contraction of water due to reduction of pressure and temperature are slight and offsetting.

Fluid Compressibilities

Gas Compressibility

The compressibility of a gas, which is the coefficient of expansion at constant temperature, should not be confused with the compressibility factor, z, which refers to the deviation from ideal gas behavior.

For perfect gases (z = 1 and dz/dp = 0), c_g is inversely proportional to pressure. For example, an ideal gas at 1,000 psia has a compressibility of 1/1,000 or 1, 000 × 10-⁶ psi^-1. However, natural hydrocarbon gases are not ideal gases and the compressibility factor, z, is a function of pressure. At low pressures, z decreases as pressure increases and dz/dp is negative; thus, c_g is higher than that of an ideal gas. At high pressures, dz/dp is positive since z increases, and c_g is less than that of a perfect gas.

Compared to other fluids or to reservoir rock, the compressibility of natural gas is large; c_g ranges from about 1,000 × 10-⁶ psi^-1 at 1,000 psi to about 100 × 10-⁶ psi^-1 at 5,000 psi Compressibility of natural gases can be obtained from laboratory PVT data or estimated from the correlations given by Trube , who defined the pseudo-reduced compressibility of a gas, c_pr, as a function of pseudo-reduced temperature and pressure.

Pseudo-critical pressures and temperatures can be calculated from the mole fraction of each component present in hydrocarbon gas mixture.

Oil Compressibility

The compressibility of oil, c_o, can be obtained in the laboratory from PVT data. In the absence of laboratory data, Trube’s correlation for compressibility of an undersat-urated oil can be used in a similar fashion as previously discussed for c_g. Pseudo-critical temperature and pressure can be estimated.For conditions below the bubblepoint, dissolved gas must be taken into account. There are several types of petroleum-engineering software equipped with the so-called “PVT data” generator code. Engineers only need fill in the known fluid properties or pressure-temperature data. By choosing the suitable correlation, the software will provide all pertinent PVT data.

Although the best approach is to obtain water compressibilities from laboratory PVT tests, this is seldom done Much of the data in the literature have been transmitted to empirical equations suitable for use with programmable calculators or personal computers. In some cases, improved empirical data have been presented recently.

Water Compressibility

This section provides a number of the expressions available for computer use and also provides references for recent books devoted to programs for hand-held calculators. References to some of the software available for personal computers will be given. The correlation should only be used as an estimate and applies for pressures less than 10,000 psi, salinity less than 26% NaCI, and in a temperature range of 60° to 400° F. Most of the equations for the updated Standing’s classic work were developed by simple curve fitting procedures.

Gas viscosity can be estimated from the correlations of Carr, Kobayashi, and Burrows; first the atmospheric value of gas gravity at reservoir temperature, estimated from gravity and non-hydrocarbon content:

m1 = (m1 uncorrected) + (N2 correction) + (CO2 correction) + (H2S correction)

where:

• (m1 uncorrected) = [1.709(10−5) − 2.062(10−6)gg]
• × T + 8.188(10−3) − 6.15(10−3) log gg
• (N2 correction) = yN2
• [8.48(10−3) log gg + 9.59(10−3)]
• (CO2 correction) = yCO2
• [9.08(10−3) log gg + 6.24(10−3)]
• (H2S correction) = yH2S[8.49(10−3) log gg + 3.73(10−3)]

is adjusted to reservoir conditions by a factor based on reduced temperature and pressure:

• ln __mg mi _(Tpr )_ = a0 + a1ppr + a2p2 pr + a3p3
• pr + Tpr (a4 + a5ppr + a6p2 pr + a7p3
• pr ) + T2 pr (a8 + a9ppr + a10p2 pr + a11p3
• pr ) + T3 pr (a12 + a13ppr + a14p2 pr + a15p3 pr ))

where:

• a0 = −2.462 118 20E − 00 a8 = −7.933 856 84E − 01
• a1 = 2.970 547 14E − 00 a9 = 1.396 433 06E − 00
• a2 = −2.862 640 54E − 01 a10 = −1.491 449 25E − 01
• a3 = 8.054 205 22E − 03 a11 = 4.410 155 12E − 03
• a4 = 2.808 609 49E − 00 a12 = 8.393 871 78E − 02
• a5 = −3.498 033 05E − 00 a13 = −1.864 088 48E − 01
• a6 = 3.603 703 20E − 01 a14 = 2.033 678 81E − 02
• a7 = −1.044 324 13E − 02 a15 = −6.095 792 63E − 04 (= 0.00 060 957 9263).

A reasonable fit to Beal’s correlation is given by Standing. The dead oil viscosity can then be adjusted for dissolved gas with the correlation by Chew and Connally for saturated oil. Standing also presents equation for; density correc­tion for compressibility of liquids; density correction for thermal expansion of liquids; apparent liquid densities of natural gases; effect of condensate volume on the ratio of surface gas gravity to well fluid gravity; pseudo-critical constants of gases and condensate fluids; pseudo-liquid density of systems containing methane and ethane; and pseudo-critical temperatures and pressures for heptane and heavier. In the first book specifically for hand-held calculators, Hollo and Fifadara presented programs for estimating gas deviation factor (based on data of Standing and Katz).

In 1980 Vazquez and Beggs published improved empirical correlations for some of the commonly required crude oil PVT properties. Their study utilized a much larger database than was used in previous work so the results are applicable to a wider range of oil properties. The empirical correlations, presented as a function of gas specific grav­ity, oil API gravity, reservoir temperature, and pressure, are particularly convenient to use with hand-held calculators. Gas gravity was found to be a strong correlating parameter. Since gas gravity depends on gas-oil separation conditions, Vazquez and Beggs chose 100 psig as a reference pressure, which resulted in a minimum oil shrinkage for the separator tests available. Thus, gas gravity must first be corrected to the value that would result from separation at 100 psig. For both dissolved gas and oil formation volume factor, improved correlations were obtained when the measured data were divided into two groups, with the division made at an oil gravity of 30°API. Vazquez and Beggs also presented an equation for viscos­ity of undersaturated crude oils that used the correlations of Beggs and Robinson. The improved correlations of Vazquez and Beggs were incorporated by Meehan in the development of programs for hand-held calculators. These programs were presented in a series of articles in the Oil and Gas Journal.

Properties of Fluid-Containing Rocks

Porosity

The porosity, (]>, is equal to the void volume of the rock divided by the bulk volume and is expressed as a percent or fraction of the total bulk volume of the rock. Oil-bearing sandstones

have porosities which often range from 15% to 30%. Porosities of limestones and dolomites are usually lower. Differentiation must be made between absolute and effective porosity. Absolute porosity is defined as the ratio of the total pore volume of the rock to the total bulk volume of the rock whereas effective porosity is defined as the ratio of the interconnected pore volume of the rock to the total bulk volume of the rock.

Factors affecting porosity are compactness, character and amount of cementation, shape and arrangement of grains, and uniformity of grain size or distribution. In problems involving porosity calculations it is convenient to remember that a porosity of one percent is equivalent to the presence of 77.6 barrels of pore space in a total volume of one acre-foot of sand.

Pore Volume

The pore volume of a reservoir is the volume of the void space, that is, the porosity fraction times the bulk volume. In conventional units, the pore volume, V_p, in reservoir barrels is:

V_p= 7758 V_b(|> = 7,758Ah(]>

where Vb is the bulk volume in ac-ft. A is the area in ft², h is the reservoir thickness in ft. and (]> is the porosity expressed as a fraction.

Permeability

The permeability of a rock is a measure of the ease with which fluids flow through the rock. It is denoted by the sym­bol k and commonly expressed in units of darcies. Typical sandstones in the United States have permeabilities rang­ing from 0.001 to a darcy or more, and for convenience the practical unit of permeability is the millidarcy which equals 0.001 darcy.

Absolute Permeability

If a porous system is completely saturated with a single fluid, the permeability is a rock property and not a property of the flowing fluid (with the exception of gases at low pres­sure). This permeability at 100% saturation of a single fluid is termed the absolute permeability.

Darcy Equation

The Darcy equation relates the apparent velocity, v, of a homogeneous fluid in a porous medium to the fluid viscosity. This equation states that the fluid velocity is propor­tional to the pressure gradient and inversely proportional to fluid viscosity. A negative sign indicates that pressure decreases in the L direction when the flow is taken to be positive. The flow rate, q, is understood to be positive dur­ing production and negative during injection.

Linear Flow

A rock has permeability of one darcy if it permits the flow of one cc per second of a one-phase fluid having viscosity of one centipoise under the pressure gradient of one atmosphere per gradient of one atmosphere per centimeter.

Radial Flow

Production from or injection into a reservoir can be viewed as flow for a cylindrical region around the wellbore.

Capacity

Flow capacity is the product of permeability and reservoir thickness expressed in md ft. Since the rate of flow is propor­tional to capacity, a 10-ft thick formation with a permeability of 100 md should have the same production as a 100-ft thick formation of 10md, if all other conditions are equal.

Transmissibility

Transmissibility is flow capacity divided by viscosity or kh/m with units of md ft/cp. An increase in either reservoir per­meability or thickness or a decrease in fluid viscosity will improve transmissibility of the fluid in the porous system.

Resistivity and Electrical Conductivity

Electrical conductivity, the electrical analog of permeability, is the ability of a material to conduct an electrical current. With the exception of certain clay minerals, reservoir rocks are nonconductors of electricity. Crude oil and gas are also nonconductors. Water in clay materials or ions in clay materials or shale act as a conductor of electrical current and are referred to as conductive solids. Water is a conductor if dissolved salts are present so the conduction of an electric current in reservoir rocks is due to the movement of dissolved ions in the brine that occupies the pore space. Conductivity varies directly with the ion concentration of the brine. Thus, the electrical properties of a reservoir rock depend on the fluids occupying the

Formation Resistivity Factor

The formation resistivity factor, FR, is the ratio of the resis­tivity of a porous medium that is completely saturated with an ionic brine solution divided by the resistivity of the brine. Results of a logging study in the Brown Dolomite forma­tion, in which the resistivity of the mud filtrate was the same as the connate water, were used by Owen to establish a relationship between the true formation factor and porosity. In the absence of laboratory data, different opinions have existed regarding the appropriate empirical relationship. Other variables that affect resistivity of natural reservoir rocks include overburden pressure and temperature during measurement. To summarize the general relationship between forma­tion resistivity factor and porosity and the normal range for the geometric term, a, is 0.6 to 1.4, and the range for the cementation exponent, m, is 1.7 to 2.5 for most consolidated reservoir rocks. Since the exact val­ues depend on pore geometry and composition of the rock, formation factors should be determined with samples of the reservoir rock of interest, under the reservoir conditions of temperature and overburden pressure. Based on core analyses of 793 sandstone and 188 carbonate samples, Carothers observed different permeabilities and formation factors for samples from the same core even though porosity was identical. Furthermore, permeability generally decreased as formation factor increased.

The effective rock com­pressibility is considered a positive quantity that is additive to fluid compressibility; therefore, pore volume decreases as fluid pressure decreases. Since overburden pres­sure of a reservoir is essentially constant, the differential pressure between the overburden pressure and the pore pressure will increase as the reservoir is depleted. For different reservoirs, porosities tend to decrease as over­burden pressure (or depth) increases. Therefore, porosity under reservoir conditions may differ from values deter­mined in the laboratory. There are different opinions on the correlation among the different attributes and porosity and its effects.

Properties of Rocks Containing Multiple Fluids

Total Reservoir Compressibility

The total compressibility of oil- or gas-bearing reservoirs represents the combined compressibilities of oil, gas, water, and reservoir rock in terms of volumetric weighting of the phase saturations. Oil compressibility increases as a function of increasing API gravity, quantity of solution gas, or temperature. As pointed out by Ramey [26], when the magnitude of water compressibility is important, the effect of solution gas in the water will be more important.

Resistivity Index

Since crude oil and natural gas are nonconductors of electricity, their presence in reservoir rock increases resistivity. When using equations to categorize the resistivity index, their accuracy will not be as good in formations with vugs or fractures.

Surface and Interfacial Tensions

The term interface indicates a boundary or dividing line between two immiscible phases. Types of interfaces include: liquid-gas, liquid-liquid, liquid-solid, solid-gas, and solidsolid.

For fluids, molecular interactions at the interface result in a measurable tension which, if constant, is equal to the surface free energy required to forma unit area of interface.

For the case of a liquid which is in contact with air or the vapor of that liquid, the force per unit length required to create a unit surface area is usually referred to as the surface tension. Interfacial tension is used to describe this quantity for two liquids or for a liquid and a solid. Interfacial tension between two immiscible liquids is normally less than the surface tension of the liquid with the higher tension, and often is intermediate between the individual surface tensions of the two liquids of interest.

At a given temperature, surface tension of hydrocarbons in equilibrium with the atmosphere or their own vapor increases with increasing molecular weight. For a given hydrocarbon, surface tension decreases with increasing temperature. At 70◦F, surface tensions of crude oils often range from 24 to 38 dyne/cm. The presence of dissolved gases greatly reduces the surface tension of crude oil. Under reservoir conditions, the interfacial interaction between gas and oil involves the surface tension of the oil in equilibrium with the gas. Similarly, the interaction between oil and water determines the interfacial tension between the crude and brine.

In studies with a crude oil containing large amounts of resins and asphaltenes, different effects of temperature on interfacial tension were observed when measurements made at aerobic conditions were compared to anaerobic tests. Interfacial tension between the crude and reservoir brine showed a decrease with an increase in temperature under aerobic conditions, whereas at anaerobic conditions, interfacial tension increased with increasing temperatures. This difference in behavior was attributed to oxidation of the stock tank oil in the aerobic tests. At conditions of reservoir temperature and pressure, interfacial tension of the live reservoir oil was higher than the stock tank oil. The study concluded that live reservoir crude should be used in measurements of interfacial properties and that if stock tank oil is used, at least the temperature should correspond to reservoir conditions.

Wettability and Contact Angle

The contact angle, existing between two fluids in contact with a solid and measured through the more dense phase, is a measure of the relative wetting or spreading by a fluid on a solid. A contact angle of zero indicates complete wetting by the more dense phase, an angle of 180◦ indicates complete wetting of the less dense phase, and an angle of 90◦ means that neither fluid preferentially wets the solid. The importance of wettability on crude oil recovery has been recognized for many years. Tests confirming oil wettability over water are considered flawed, since they were contaminated by the extraction processes. Oil wetness is reputed to promote oil flow. Mud additives, such as dispersants, weighting agents, lost circulation materials, thinners or colloids, that possess surface-active properties may drastically change core wettability. Surface active agents should be avoided so that the core samples have the same wettability as the reservoir rock.

Results suggest that from a wettability standpoint, the best coring fluid is water (preferably formation brine); if bentonite is used, mud pH should be neutral or slightly acidic. If appreciable hydrogen sulfide is suspected in the interval being cored, it may be undesirable to lower pH. In fact, a very alkaline mud (pH 10–12) may be used to keep the sulfide in the ionized state for safety and corrosion considerations. Preventing wettability changes in core material, after it

has been recovered at the surface, is equally important so that subsequent laboratory measurements are representative of reservoir conditions. Most often these changes are cause by oxidation of the crude oil, evaporation of volatile components, or decreases in temperature or pressure which cause the deposition of polar compounds, asphaltenes, or heavy hydrocarbon compounds. Protection of the core samples so that the wettability is not contaminates or changes can be done by immersing them in a brine solution or sealing them with saran wrap, foil, plastic or wax. Mostly exposure to air should be minimized. All tests should be done in as close to reservoir conditions for temperature, pressure etc. as possible.

Capillary Pressure

Curvature at an interface between wetting and nonwetting phases causes a pressure difference that is called capillary pressure. This pressure can be viewed as a force per unit area that results from the interaction of surface forces and the geometry of the system. Capillary pressure depends on pore geometry, interfacial tension between the fluids, wettability of the system, and the saturation history in the medium, and it affects oil flow. A very valuable use of capillary pressure data is to indicate pore size distribution. Since the interfacial tension and contact angle remain constant, pore sizes can be obtained from capillary pressures. For rocks with more uniform pore sizes, capillary pressure curves will be close to horizontal. The slope of the capillary pressure curve will generally increase with broader pore-size distribution, If laboratory capillary pressure data are corrected to reservoir conditions, the results can be used for determining fluid saturations and for qualitative assessment of transition zones within the reservoir.

Effective Permeability

100% saturation of a fluid (other than gases at low pressure) is a characteristic of the rock and not a function of the flowing fluid. Of course, this implies that there is no interaction between the fluid and the rock Klinkenberg found that by extrapolating all data to infinite mean pressure, the points converged at an equivalent liquid permeability (k_), which was the same as the permeability of the porous medium to a nonreactive single-phase liquid. Permeability affects wettability and flow. The lower the saturation of a certain liquid, as compared to other liquids, the lower the permeability to that liquid. This type of permeability is termed effective permeability and is defined as permeability of the rock to one liquid under conditions of saturation when more than one liquid is present.

Relative Permeability

For gas-oil two phase relative permeabilities, the base permeability is often the equivalent liquid permeability. If a clean, dry core is completely saturated with water, the permeability at 100% Sw should be similar to the equivalent liquid permeability obtained from gas flow measurements at 100% Sg. Exceptions to this generality include some low-permeability systems and other cores that contain clays or minerals that interact with the water used. If a clean core is used, it will probably be strongly water-wet when saturated with brine. As crude oil is injected into the core, the relative permeability to water decreases during the drainage cycle (decreases in wetting phase) while the relative permeability to oil increases. Some water that resides in the nooks and crannies of the pore space cannot be displaced by the oil, regardless of the throughput volume.

Effect of Wettability on Fluid-Rock Properties

Oil Recovery and Fluid Saturations

Since a reservoir rock is usually composed of different minerals with many shapes and sizes, the influence of wettability in such systems is difficult to assess fully. Oil recovery at water breakthrough in water-wet cores is much higher than in oil-wet cores.

Relative Permeability Characteristics

For a system having a strong wetting preference for either oil or water, relative permeability of the wetting phase is a function of fluid saturation only.

Capillary Pressure Curves

By convention, oil-water capillary pressure, Pc, is defined as the pressure in the oil phase, po, minus the pressure in the water phase. Depending on wettability and history of displacement, capillary pressure can be positive or negative.

Resistivity Factors and Saturation Exponents

Because of the scarcity of data and the difficulty of altering wettability without affecting other properties, the effect of wettability on formation resistivity remains unclear.

Formation Evaluation

Formation evaluation, as applied to petroleum reservoirs, consists of the quantitative and qualitative interpretation of formation cores, geophysical well logs, mud logs, flow tests, pressure tests, and samples of reservoir fluids. The goal of the interpretation is to provide information concerning reservoir lithology, fluid content, storage capacity, and producibility of oil or gas reservoirs. The final analysis includes an economic evaluation of whether to complete an oil or gas well and, once completed, an ongoing analysis of how to produce the well most effectively. These interpretations and analyses are affected by geological complexity of the reservoir, rock quality, reservoir heterogeneity, and, from a logistical standpoint, the areal extent and location of the project of interest. In the early stages of development, the purpose of formation evaluation is to define reservoir thickness and areal extent, reservoir quality, reservoir fluid properties, and ranges of rock properties. The key rock properties are porosity, permeability, oil, gas, and water saturations. Because of space limitations and the importance of these properties, methods of measuring porosity, permeability, and fluid saturations will be emphasized.

Coring and Core Analysis

Routine or conventional core analyses refer to common procedures that provide information on porosity, permeability, resident fluids, lithology, and texture of petroleum reservoirs. Routine core analyses can be performed on whole cores or on small plugs that are cut from a larger core. With the exception of petrographic analyses (thin sections, x-ray; scanning electron microscopy, etc.), special core analyses are normally done with core plugs.

Coring

Well coring refers to the process of obtaining representative samples of the productive formation in order to conduct a variety of laboratory testing. Various techniques are used to obtain core samples: conventional diamond-bit coring, rubbersleeve coring, pressure coring, sidewall coring, and recovery of cuttings generated from the drilling operation.

Core Preservation

As discussed earlier, core preservation is essential. Cores taken with a pressure core barrel are often frozen at the well-site for transportation to the laboratory.

Core Preparation

Depending on the type of core testing to be done, core samples may be tested as received in the laboratory or they may be cleaned to remove resident fluids prior to analysis.

Core Analysis

Core analysis is discussed in the first section.

Porosity

A number of methods [13] are suitable for measuring porosity of core samples. In almost all the methods, the sample is cleaned by solvent extraction and dried to remove liquid. Porosity can be determined by saturating the dry core with brine and measuring the weight increase after saturation.

Permeability

The permeability of core plugs is determined by flowing a fluid (air gas, or water) through a core sample of known dimensions. If the absolute permeability is to be determined, the core plug is cleaned so that permeability is measured at 100% of the saturating fluid.

Fluid Saturations

Coring procedures usually alter the fluid content of the reservoir rock during the coring process. Drilling fluid is jetted against the formation rock ahead of the coring bit and the core surface as it enters the core barrel; as a result of this flushing action by the drilling mud filtrate, most free gas and a portion of the liquid are displaced from the core.

Factors Affecting Oil Displaced During Coring

During the coring operation, it is important to avoid extreme flushing conditions that could cause mobilization of residual oil. Some of the variables that control the amount of oil flushed from a core by mud filtrate are: borehole-to formation differential pressure (overbalance), coring penetration rate, core diameter, type of drill bit, drilling mud composition (including particle size distribution), depth of invasion of mud particles into the core, rate of filtrate production (both spurt loss and total fluid loss), interfacial tension of mud filtrate, permeability of the formation (both horizontal and vertical), and nature of the reservoir (uniformity, texture, etc.).

Factors Affecting Oil Saturation Changes During Recovery of Cores

Surface oil saturations should be adjusted to compensate for shrinkage and bleedings. Shrinkage is the term applied to the oil volume decrease caused by a temperature change or by a drop in pressure which causes dissolved gases to escape from solution. Shrinkage of reservoir fluids is measured in the laboratory by differentially liberating the samples at reservoir temperature.

Measurement of Fluid Saturations

There are two primary methods of determining fluid content of cores; these methods are discussed in part 1.

Grain Density and Core Description

Grain density and lithologic descriptions are often provided in data for routine care analysis.

Special Core Analysis Tests

Special core analysis testing is done when specifically required.

Drill Stem Tests

A drill stem test (DST) is some form of temporary completion of a well that is designed to determine the productivity and fluid properties prior to completion of the well.

Logging

Introduction

This section deals with the part of formation evaluation known as well logging. Well logs are a record versus depth of some physical parameter of the formation. Parameters such as electrical resistance, naturally occurring radioactivity, or hydrogen content may be measured so that important producing characteristics such as porosity, water saturation, pay thickness, and lithology may be determined.

Parameters that Can Be Calculated or Estimated from Logs

Porosity

Porosity is defined as the ratio of volume of pores to the total volume of the rock.

Water Saturation

Connate water saturation (Sw) and flushed zone water saturation (Sxo) can be calculated from information supplied by well logs.

Pay Thickness

The thickness of a hydrocarbon-bearing formation (hpay) is easily determined from well logs.

Lithology

It is often necessary to know the rock type in order to properly design downhole assemblies, casing programs, and completion techniques. Data from well logs can provide the geologist or engineer with an estimate of the lithologic makeup of any formation.

Permeability

Permeability is one of the essential properties used in evaluation of a potentially producing formation. Unfortunately there are no logging devices that read permeability. This is because permeability is a dynamic property. Most logging tools spend only a few seconds in front of any one point of a formation, therefore it is impossible to measure any time-dependent parameter. There are methods to estimate permeability from well logs, but they are based on general assumptions.

Influences on Logs

The purpose of well logging is to determine what fluids are in the formation and in what quantity. Unfortunately the drilling process alters the fluid saturations by flushing the pores near the borehole and filling them with the fluid fraction of the drilling mud (mud filtrate). To correct for these influences, the invasion profile must be identified.

Mud Relationships

Since the borehole is filled with mud and the adjacent portion of the formation is invaded with mud filtrate, mud properties must be accurately known so they can be taken into account. Mud has a minor influence on most porosity tools; however, it can have a large effect on the resistivity tools.

Temperature Relationships

Mud resistivity is a function of temperature and ion concentration. Since temperature increases with depth due to geothermal gradient, the mud resistivity is lower at the bottom of the hole than at the surface (pits).

Openhole Logs and Interpretation

The SP log is a record of the naturally occurring electrical currents created in the borehole. These currents or circuits usually occur at bed boundaries and are created by the interaction between fresh drilling mud and salty formation water.

Theory

The total potential (Et) can be separated into two components: the electrochemical (Ec) and the electrokinetic (Ek).

Interpretation

The total electrochemical component of the total potential is what the SP records. The shape and amplitude of the SP are affected by:

1. 1. Thickness and resistivity of the permeable bed (Rt ).
2. 2. Diameter of invasion and resistivity of flushed zone (Rxo)
3. 3. Resistivity of the adjacent shales (Rs).
4. 4. Resistivity of the mud (Rm).
5. 5. Borehole diameter (dh)

Resistivity Tools

The purpose of resistivity tools is to determine the electrical resistance of the formation (rock and fluid). Since most formation waters contain dissolved salts, they generally have low resistivities. Hydrocarbons do not conduct electricity, therefore rocks that contain oil and/or gas show high resistivity. This is the way hydrocarbon-bearing zones are differentiated from water zones. Resistivity tools are divided into three types based on the way measurements are made:

1. non-focused (normal) tools,
2. induction tools,
3. ocused resistivity tools.

Theory Nonfocused (Normal Tools)

The first tools to be used were nonfocused tools.

Inductions Tools

Since a slightly conductive mud is necessary for the normal tools, they cannot be used in very fresh muds or in oil-base muds. The induction tool overcomes these problems by inducing a current into the formation instead of passing it through the mud-filled borehole.

Phasor Induction Tools

Since the early 1960’s, induction logging tools have become the principal logging device for fresh, slightly conductive to non-conductive (oil-base) muds, but they are vulnerable to outside influence.

Theory

It is known that gamma rays affect reservoir contents, though much more study is needed to predict exact effects, ratios, factors and results.

Interpretation

The interpretation of a total gamma ray curve is based on the assumption that shales have abundant potassium-40 in their composition. The open lattice structure and weak bonds in clays encourage incorporation of impurities.

Sonic (Acoustic) Log

The sonic (acoustic or velocity) total measures the time it takes for a compressional wave to travel through one vertical foot of formation. It can be used to determine porosity (if the lithology is known) and to determine seismic velocities for geophysical surveys when combined with a density log. The sonic log also has numerous cased hole applications.

Density Log

The formation density tool measures the bulk electron densityof the formation and relates it to porosity. It is a pad device with a caliper arm. The tool is usually run in combination with a neutron log, but it can be run alone.

Neutron Log

Neutron tools measure the amount of hydrogen in the formation and relate it to porosity. High hydrogen content indicates water (H2O) or liquid hydrocarbons (CxHz) in the pore space. Except for shale, sedimentary rocks do not contain hydrogen in their compositions.

Nuclear Magnetic Resonance (NMR)

This log examines the nucleus of certain atoms in the formation. Of particular interest are hydrogen nuclei (protons) since these particles behave like magnets rotating around each other [23]. Hydrogen is examined because it occurs in both water and hydrocarbons.

Dielectric Measurement Tools

Dielectric measurement tools examine the formation with high frequency electromagnetic waves (microwaves) rather than high-frequency sound waves (as in the sonic or acoustic logging tools). The way the electromagnetic wave passes through a given formation depends on the dielectric constants (e) of the minerals and fluids contained in the rock. The profiles can be read like a biological ultrasound.

Focused Resistivity Tools (Laterologs)

The Laterologs are the primary salt-mud resistivity tools. Salt mud presents a problem in that the path of least resistance is within the borehole. Therefore the current must be forced into the formation which has higher resistance.

Corrections

As previously mentioned, resistivity tools are affected by the borehole, bed thickness, and invaded (flushed) zone.

Interpretation

When two or more resistivity logs with different depths of investigation are combined, permeable zones can be identified. In a permeable zone, the area closest to the borehole

will be flushed of its original fluids; mud filtrate fills the pores. If the mud filtrate has a different resistivity than the original formation fluids (connate water), the shallowest-reading resistivity tool will have a different value than the deepest reading tool.

Microresistivity Tools

Microresistivity tools are used to measure the resistivity of the flushed zone. This measurement is necessary to calculate flushed zone saturation and correct deep-reading resistivity tools for invasion.

Theory

The microlog makes two shallow nonfocused resistivity measurements, each at different depths.

Interpretation

The saturation of the flushed zone must be at formation temperature.

Gamma Ray Logs

The gamma ray log came into commercial use in the late 1940s. It was designed to replace the SP in salt muds and in air-filled holes where the SP does not work. The gamma ray tool measures the amount of naturally occurring radioactivity in the formation. These logs need to be calibrated before use.

Cased-Hole Completion Tools

These tools examine cement bond and casing quality. They assure that no leakage or intercommunication will occur between producing horizons, or between water-bearing horizons and producing horizons. The most common completion tools include:

• Cement bond logs (CBL). This is a sonic tool used to check cement bond quality behind the casing and to estimate compressive strength of the cement. It can also be used to locate channeling in the cement or eccentered pipe and to check for microannulus.

• Multifingered caliper logs. These logs incorporate up to 64 feelers or scratchers to examine pipe conditions inside the casing. Specifically, they can be combined with other logs to check.

Casing collar locations

1. Corroded sections of pipe.
2. Casing wear.
3. Casing cracks or burstings.
4. Collapsed or crushed casing.
5. Perforations.
6. Miscellaneous breaks.

The number of feelers is a function of pipe diameter; smaller diameter pipe requires fewer feelers on the tool.

Electromagnetic inspection logs

This device induces a magnetic field into the casing and measures the returning magnetic flux. In general any disturbance in the flux from readings in normal pipe can be used to find:

1. Casing collars.
2. Areas of corroded pipe.
3. Perforations.
4. Breaks or cracks in the pipe.

This tool only records if corrosion has occurred on the pipe, not whether it is currently taking place. It does give an indication of casing quality and integrity without removing the pipe from the hole. The principle behind this tool is the same as the magna flux device used to detect flaws in metals in a machine shop.

Electrical potential logs

This tool measures the potential gradient of a DC current circulating through a string of casing. It can identify corrosion.

Borehole televiewers

This tool incorporates an array of transmitters and receivers to scan the inside of the casing. The signals are sent to the surface where they are analyzed and recorded in a format

that gives a picture of the inside of the casing. Any irregularities or cracks in the pipe are clearly visible on the log presentation. This allows engineers to fully scan older pipe and get an idea of the kind and extent of damage that might not otherwise be readable from multifinger caliper, electromagnetic inspection, or electrical potential logs. The main drawback to this device is that it must be run in a liquid-filled hole to be effective.

Production Logs

Production logs are those devices used to measure the nature and behavior of fluids in a well during production or injection. A Schlumberger manual summarizes the potential benefits of this information: early evaluation and detection, detailed and positive monitoring, positive evaluation and guidance for remediation.

The types of logs run include

A thermometer is used to log temperature anomalies produced by the flow or fluid inside the casing or in the casing anulus.

Manometer and gradiomanometer

Manometers are pressure-sensitive devices used to measure changes in pressure that result from:

• Leaks in tubing or casing.
• Fluid inflow through perforations.
• Gradient measurements in a static mud column.

The pressure difference is converted to a density for interpreting two wave flow.

Flow meters

Flowmeters are designed to measure fluid flow in the casing.This measurement is then related to volume of fluid being produced. Three types of flowmeters are available:

1. Fullbore-spinner flowmeter.
2. Continuous flowmeter.
3. Packer flowmeter.

These can be used singly or combined.

Radioactive Tracers

Radioactive tracers are combined with cased hole gammaray logs to monitor:

1. Fluid velocities in monophase fluid flow situations where flow velocity is at or near the threshold for spinner flowmeters.
2. Fluid movement behind the casing or to locate channeling in the cement.

Different equations are use to evaluate initial gas and oil in place.

Pressure Transient Testing of Oil and Gas Wells

Production rates depend on the effectiveness of the well completion (skin effect), the reservoir permeability, the reservoir pressure, and the drainage area. Pressure transient analysis is a powerful tool for determining the reservoir characteristics required to forecast production rates. Transient pressure data are generated by changing the producing rate and observing the change in pressure with time. The transient period should not exceed 10% of the previous flow or shut-in period. There are a number of methods to generate the transient data available to the reservoir engineer. Several excellent references on well test analyses are available, and a good discussion of difficulties in interpretation of data is available in a recent text.

Transient Region

In the transient region, the reservoir is infinite-acting, and the flowing bottomhole pressure is amenable to analysis by transient methods.

Late-Transient Region

At the end of the transient region and prior to the semisteadystate period, there is a transitional period called the late-transient region. It may be very small or practically nonexistent.

Semisteady-State Region

If there is no flow across the drainage boundary and compressibility is small and constant, a semisteady- or pseudosteady-state region is observed in which the pressure declines linearly with time. Pressures in the drainage area decrease by the same amount in a given time, and the difference between reservoir pressure and wellbore pressure remains constant during this period.

Steady-State Flow

At a constant flow rate for steady-state flow, the pressure at every point in the reservoir will remain constant with time.

Buildup Tests

Pressure buildup tests are conducted by:

• producing an oil or gas well at a constant rate for sufficient time to establish a stabilized pressure distribution,
• ceasing production by shutting in the well,
• recording the resulting increase in pressure. In most cases, the well is shut in at the surface and the pressure is recorded downhole. The pressure buildup curve is analyzed for wellbore conditions such as damage or stimulation and for reservoir properties such as formation permeability, pressure in the drainage area, reservoir limits or boundaries and reservoir heterogeneities.

Drawdown Tests

Pressure drawdown tests are conducted by:

• having an oil or gas well shut in for sufficient time to establish a stabilized pressure distribution,
• putting the well on production at a constant rate,
• recording the resulting decrease in bottomhole pressure. A long, constant flow rate is required.

Falloff Tests

Pressure falloff tests are conducted in injection wells and are analogous to the pressure buildup tests in producers. A falloff test consists of:

• injecting fluid at a constant rate,
• shutting in the well,
• recording the decrease in pressure.

Multiple-Rate Tests

Multiple-rate tests maybe conducted at variable flowrates or a series of constant rates, and are applicable to buildup or drawdown tests in producers or falloff tests in injectors. If accurate flow rate and pressure data are obtained, information on permeability, skin, and reservoir pressure can be deduced.

Interference Tests

Interference tests are conducted by producing from or injecting into at least one well and observing the pressure response in at least one shut-in observation well. A change in rate (pressure) at the active producer or injector will cause a pressure interference at the observation well. A special form of multiple-rate testing is the pulse test in which the pressure caused by alternating periods of production (or injection) and shut-in periods is monitored at one or more observation wells. Multiple-rate tests are used to determine if wells share the same reservoir as well as to provide estimates of formation permeability and the product of porosity and total compressibility.

MDH Method

The MDH method is a plot of bottomhole pressure versus log time on semilog paper.

Horner Plot

The Horner method should be applied only to infinite-acting reservoirs; for radial flow, the Horner plot will be a straight line. Several conditions such as boundaries or changes in fluids or fluid properties, can cause the Horner plot to deviate from a straight line.

Skin Factor

The skin effect is altered permeability near a wellbore as a result of drilling, completion, or stimulation which is positive for damage and negative for improvement. Skin factor can range from about −5 for a hydraulically fractured well to a theoretical limit of infinity for a severely damaged or plugged well.

Wellbore Storage

Wellbore storage, also referred to as after flow, wellbore loading or unloading, after production, and after injection, will affect short-time transient pressure behavior, and can be especially important in low permeability formations or in gas wells. During a buildup test, a well is closed in at the surface, but fluid may continue to flow into the wellbore for some time which causes a lag in the buildup at early times. Storage can obscure the transient period thus negating the value of a semi log plot. Hydraulically stimulated wells in tight formations (<0.01 md) with long finite conductivity) fractures never exhibit the proper straight line during a conventional transient test time period.

A problem in determining the initial pressure frequently arises when pressure buildup data from pumping wells are analyzed. A Cartesian plot of the early-time bottomhole pressure versus shut-in time should result in a straight line with the proper initial pressure at the intercept.

Type-Curves

Curve-matching techniques have recently received more widespread use. In some cases where conventional analyses fail such as when wellbore storage distorts most or all of the data, type-curves may be the only means of interpretation of the pressure data.

Mechanisms & Recovery of Hydrocarbons by Natural Means

Petroleum Reservoir Definitions

A reservoir is the portion of the trap that contains the oil and/or gas in a hydraulically connected system of accumulations of oil and gas occur in underground traps, formed by structural and/or stratigraphic features. Many reservoirs are hydraulically connected to water-bearing rocks or aquifers that provide a source of natural energy to aid in hydrocarbon recovery. Oil and gas may be recovered by: fluid expansion, fluid displacement, gravitational drainage, and/or capillary

expulsion. A volumetric reservoir, one with no aquifer, hydrocarbon recovery occurs primarily by fluid expansion, which may be aided by gravity drainage. If there is water influx or encroachment from the aquifer, recovery occurs mainly by the fluid displacement mechanism aided by gravity drainage or capillary expulsion. In many instances, recovery of hydrocarbon occurs by more than one mechanism.

The single phase of fluids in a reservoir may be a gas phase or a liquid phase in which all of the gas present is dissolved in the oil. When there are hydrocarbons vaporized in the gas phase which are recoverable as liquids at the surface, the reservoir is called gas-condensate, and the produced liquids are referred to as condensates or distillates. For two-phase accumulations, the vapor phase is termed the gas cap and the underlying liquid phase is called the oil zone, and includes the free gas in the gas cap, evolving from dissolved gas, recoverable liquid from the gas cap, and crude oil from the oil zone. A transition zone in which the water saturation can vary as a function of vertical depth and formation permeability. Water that exists in the oil- or gas-bearing portion of the reservoir above the transition zone is called connate or interstitial water.

Natural Gas Reservoirs

For reservoirs where the fluid at all pressures in the reservoir or on the surface is a single gaseous phase, estimates of reserves and recoveries are relatively simple. However, many gas reservoirs produce some hydrocarbon liquid or condensate for which the single-phase case can be modified to include the condensate if the reservoir fluid remains in a single phase at all pressures encountered. However, if the hydrocarbon liquid phase develops in the reservoir, additional methods are necessary to handle these retrograde, gas-condensate reservoirs.

Primary Recovery of Crude Oil

Initial crude oil production works by the expansion of fluids which were trapped under pressure in the rock. The expanding fluids may be gas from the oil, an expanding gas cap, a bottom- or edge-water drive, or a combination. When the reservoir falls to a low value, the oil no longer flows to the wellbore, and pumps lift the crude oil to the surface, called primary production. These are classified as: solution-gas or depletion drive, gas cap drive, natural water drive, gravity drainage, and compaction drive. Production may use one or more of the mechanisms, referred to as a combination drive.

Statistical Analysis of Primary Oil Recovery

Most of the producing mechanisms are sensitive to the rate of oil production; only the solution gas drive mechanism is truly rate-insensitive. Primary recoveries are usually reported to be less than 25% of the original oil in place by solution gas drive, 30% to 50% for water drive, and can exceed 75% for gravity drainage in thick reservoirs with high vertical permeabilities. For water drive reservoirs, primary recovery efficiency can be low if the initial water saturation is more than 50%, if permeability is low, or if the reservoir is oil-wet. The differences in recovery mechanisms are important if an engineer is to avoid misapplication of methods.

Empirical Estimates of Primary Oil Recovery

Several attempts have been made to correlate primary oil recovery with reservoir parameters. A second study found that for reservoirs separated by lithology, geographical province, and producing mechanism, the only reasonable correlations that could be developed were between recoverable oil and original oil in place.

In view of the lack of suitable correlations, primary oil recovery for an individual reservoir must be estimated by:

• material balance equations in conjunction with equations for gas-oil ratio and fluid saturations,
• volumetric equations if residual oil saturation and oil formation volume factor at abandonment are known or estimated,
• decline curve analysis, if production history is available.

Primary Recovery Factors in Solution-Gas-Drive Reservoirs

Primary recovery from solution-gas-drive reservoirs depends on: type of geologic structure, reservoir pressure, gas solubility, fluid gravity, fluid viscosity, relative permeabilities, presence of connate water, rate of withdrwal, and pressure drawdown.

To use Wahl’s figures the following is required: oil viscosity at reservoir conditions, interstitial water saturation, bubble-point pressure, solution gas-oil ratio at the bubble-point pressure, and formation volume factor.

Graphical Form of Material Balance

For volumetric gas reservoirs in which there is no water influx and negligible water production, the definition of gas formation volume factor can be substituted and the resulting equation can be rearranged to give where all terms are as defined previously. This equation indicates that for a volumetric gas reservoir a plot of cumulative gas production (Gp) in standard cubic feet versus the ratio p/z is a straight line. The straight line can be extrapolated to zero pressure to find the initial gas in place, or can be extrapolated to predict the cumulative production at any future average reservoir pressure. A plot of pressure versus cumulative production is not a straight line because the produced gas is not a perfect gas.

Material Balance Equations in Oil or Combination Reservoirs

A reservoir may contain oil, gas and water that can be intermingled or segregated into zones. As described earlier, recovery may be caused by solution gas drive, water drive, gas cap drive, or a combination of these mechanisms. A general material balance equation should be capable of handling any type of fluid distribution and any drive mechanism. Because of the complications they would introduce in already complex equations, water and formation compressibilities are generally neglected, except in undersaturated reservoirs producing above the bubble point. One general material balance equation, the Schilthuis equation, is a volumetric balance stating that the sum of the volume changes in oil, gas, and water must be zero because the reservoir volume is constant.

Material Balance for Solution-Gas Drive Reservoirs

A schematic representation of material balance equations for solution-gas reservoirs, when the change in pore volume is negligible. When these reservoirs are producing above the bubble point or saturation pressure, no gas is liberated and production occurs by expansion of liquids in the reservoir. When reservoir pressure drops below the bubble point, gas is liberated in the reservoir and will be produced with the oil.

Liquid Expansion

For some very large reservoirs (often with limited permeability), production may occur for extended periods by expansion of liquids in the reservoir.

Gas Liberation

When reservoir pressure declines below the bubble-point pressure, the original gas in solution has either been produced as Gp, is still in solution in the oil, or exists as free gas.

Predicting Primary Recovery in Solution-Gas Drive Reservoirs

Several methods for predicting performance of solution-gas behavior have appeared in the literature relating to pressure decline to gas-oil ratio and oil recovery. Because neither water influx nor gravity segregation is considered, time is not a factor with solution-gas reservoirs, and time must be inferred from the oil in place and production rate. The following assumptions are generally made: uniformity of the reservoir at all times regarding porosity, fluid saturations, and relative permeabilities; uniform pressure throughout the reservoir in both the gas and oil zones (which means the gas and oil volume factors, the gas and oil viscosities, and the solution gas will be the same throughout the reservoir); negligible gravity segregation forces; equilibrium at all times between the gas and the oil phases; a gas liberation mechanism which is the same as that used to determine the fluid properties, and no water encroachment and negligible water production.

The Schilthuis Method

For solution-gas drive reservoirs where the reservoir pressure is about equal to the saturation pressure and for gas cap drive reservoirs. In order to predict the cumulative oil production at any stage of depletion, the original oil and gas in place and the initial reservoir pressure must be known.

The Tarner Method

This is a trial-and-error procedure based on the simultaneous solution of the material balance equation and the instantaneous gas-oil ratio equation.

The Muskat Method

The Schilthuis and Tarner forms of material balance have been expressed in integral form. An approach presented by Muskat expresses the material balance in terms of finite pressure differences in small increments. The changes in variables that affect production are evaluated at any stage of depletion or pressure. The assumption is made that values of the variables will hold for a small drop in pressure, and the incremental recovery can be calculated for the small pressure drop.

Predicting Primary Recovery in Water-Drive Reservoirs

In the prediction of performance caused by water influx, predictions of water encroachment are made independent of material balance. The extent of water encroachment depends on the characteristics of the aquifer and is a function of the pressure history and time.

Recovery of Oil

Methods and equations are different for different situations, such as Solution-Gas or Depletion Drive, Water-Drive Reservoir, Gravity Drainage, or Gas-Cap Drive.

Decline Curve Analysis

The conventional analysis of production decline curves for oil or gas production consists of plotting the log of flow rate versus time on semilog paper. In cases for a decline in rate of production, the data are extrapolated into the future to provide an estimate of expected production and reserves. If time is in days, flow rate in this equation is expressed in terms of stock tank barrels per day in the case of oil and scf per day for gas.

Exponential Decline

For the exponential or constant percentage decline, the nominal or instantaneous decline rate is calculated by a set of equations.

Hyperbolic Decline

This uses a different set of equations.

Harmonic Decline

For a harmonic decline, the time-rate relationship is calculated.

Production Type-Curves

Semilog Plots

The complexity of the analysis of hyperbolic decline-curves led to the development of curve-matching techniques. One of the simpler techniques was proposed by Slider with the development of an overlay method to analyze rate-time data.

Log-log (Fetkovich) Type-Curves

Conventional decline-curve analysis should be used only when mechanical conditions and reservoir drainage remain constant and the well is producing at capacity. An advanced approach for decline-curve analysis, which is applicable for changes in pressure or drainage, has been presented by Fetkovich.

Reserve Estimates

Definition and Classification of Reserves

Crude Oil

This is defined technically as a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface facilities.

Natural Gas

This is a mixture of hydrocarbons and varying quantities of nonhydrocarbons that exist either in the gaseous phase or in solution with crude oil in natural underground reservoirs.

Natural gas may be subclassified as ssociated gas, commonly known as gascap, and nonassociated gas that is in reservoirs that do not contain significant quantities of crude oil.

Natural Gas Liquids (NGLs)

There are those portions of reservoir gas that are liquefied at the surface in lease separators, field facilities, or gas processing plants including but not limited to ethane, propane, butanes, pentanes, natural gasoline, and condensate.

A reservoir is a porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (oil and/or gas) which is

confined by impermeable rock and/or water barriers and is characterized by a single natural pressure system, classified as oil reservoirs or as gas reservoirs by a regulatory agency.

Improved Recovery

This includes all methods for supplementing natural reservoir forces and energy, or otherwise increasing ultimate recovery from a reservoir. Such recovery techniques include:

• pressure maintenance,
• cycling,
• secondary recovery in its original sense.

Improved recovery also includes the enhanced recovery methods of thermal, chemical flooding, and the use of miscible and immiscible displacement fluids.

Reserves do not include volumes of crude oil, condensate, or natural gas liquids being held in Inventory whose estimates are based on interpretation of geologic and/or engineering data available at the time. Existing economic conditions are prices, costs, and markets prevailing at the time of the estimate.

Marketable means that facilities to process and transport reserves to market are operational at the time of the estimate, or that there is a commitment to install such facilities in the near future, and there is a readily definable market or sales contract.

Natural gas reserves are those volumes which are expected to be produced and that may have been reduced by onsite usage, by removal of nonhydrocarbon gases, condensate or natural gas liquids. Reserves may be attributed to either natural reservoir or improved recovery methods. Improved recovery includes all methods for supplementing natural reservoir energy to increase ultimate recovery from a reservoir. Such methods include:

• pressure maintenance,
• cycling,
• waterflooding,
• thermal methods,
• chemical flooding,
• the use of miscible and immiscible displacement fluids.

The relative degree of uncertainty for reserve estimates may be conveyed by placing reserves in one of two classifications, either proved or unproved.

Classification of Reserves

Proved Reserves can be estimated with reasonable certainty. The area of a reservoir considered proved includes:

• the area delineated by drilling and defined by fluid contacts, if any,
• the undrilled areas that can be reasonably judged as commercially productive on the basis of available geological and engineering data.

In general, proved undeveloped reserves are assigned to undrilled locations that satisfy the following conditions:

• the locations are direct offsets to wells that have indicated commercial production in the objective formation,
• it is reasonably certain that the locations are within the known proved productive limits of the objective formation,
• the locations conform to existing well spacing regulation, if any,
• it is reasonably certain that the locations will be developed.

Unproved Reserves are based on geologic and/or engineering data similar to that used in estimates of proved reserves, but technical, contractual, or regulatory uncertainties preclude such reserves being classified as proved. Unproved reserves may be divided into probable and possible.

Probable Reserves are attributed to known accumulations and are less certain to be recovered than proved reserves. Possible Reserves are associated with known accumulations and are less certain to be recovered than probable reserves.

Reservoir Engineering

An improved recovery program that is not in operation and that is in a field in which formation, fluid, or reservoir characteristics are such that a reasonable doubt exists to its success.

Reserve Status Categories define the development and producing status of wells and/or reservoirs.

Developed Reserves are expected to be recovered from existing wells (including reserves behind pipe). Improved recovery reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Developed reserves may be

producing or nonproducing. Producing Reserves are expected to be recovered from completion intervals open at the time of the estimate and producing to market. Nonproducing Reserves include shut-in and behind-pipe reserves. Undeveloped Reserves are expected to be recovered:

• from new wells on undrilled acreage,
• from deepening existing wells to a different reservoir,
• where a relatively large expenditure is required to recomplete an existing well or install production or transportation facilities for primary or improved recovery projects.

Methods of Estimating Reserves

Method of determining reserves progress from analogy, before a well is drilled, to history after it is plugged and abandoned. The accuracy with which reserves can be estimated progresses along the same path from speculation to history.

Analogy

The decision to drill a well is based upon the potential reserves that it will recover. This means that an engineer must be able to predict reserves before a well is drilled. Analogy is the only method which can be used without specific well information such as porosity, reservoir thickness, and water saturation.

Volumetric

If a well is drilled after reserves are determined by analogy, factual information becomes available and reserves can then be determined volumetrically. When enough wells have been drilled to delineate the field, a subsurface geological contour map showing the subsea sand top and bottom depth, oil-water contact, and gas-oil contact can be prepared. The engineer must determine from core data and/or electric logs the percentage of the gross sand volume that is productive and must then reduce the total acre-feet by that percentage. If there is no subsurface contour map available or if the reservoir is very heterogeneous, an isopach or an isovol map should be constructed by contouring net sand thickness. This kind of map works well when the reservoir is uniformand when porosity and water saturation are relatively constant. When the water saturation and porosity vary widely from well to well, an isovol map that indicates hydrocarbon thickness is useful.

Material Balance

If a field development program has been well planned and executed, enough information should be available to calculate reserves by the material balance equation.

Model Studies

Predicting reservoir performance with the Tarner or the Muskat method is a long and tedious process and, even with a programmable calculator, the process takes several hours. Fortunately, computers have cut the required time to a few minutes.

Production Decline Curves

The most widely used method of estimating reserves is the production rate decline-curve. This method involves extrapolation of the trend in performance. If a continuously changing continuous function is plotted as the dependent variable against an independent variable, a mathematical or graphical trend, using one of three major types of decline curves: constant percentage or exponential, hyperbolic, and harmonic.

Quality of Reserve Estimates

If reserve estimates contained no risk, no dry holes would be drilled. Unfortunately, risk is inversely proportional to knowledge and the least is known before a well is drilled.

Secondary Recovery

Secondary and Tertiary Recovery

Primary recovery, as already discussed, refers to the recovery of oil and/or gas that is recovered by either natural flow or artificial lift through a single wellbore.

Pressure Maintenance

Pressure maintenance is a secondary recovery process that is implemented early during the primary producing phase before reservoir energy has been depleted.

Gas Injection

Historically, both natural gas and air have been used in gas injection projects, and in some cases nitrogen and flue gases have been injected.

Water Injection

Water injection processes may be designed to: (1) dispose of brine water, (2) conduct a pressure maintenance project to maintain reservoir pressure when expansion of an aquifer or gas cap is insufficient to maintain pressure, or (3) implement a water drive or waterflood of oil after primary recovery.

Spacing of Wells and Well Patterns

Spacing of Wells

One section (one sq mile or 5,280 ft by 5,280 ft) is 640 acres.

Injection Well Placement

Wells may be spaced evenly or unevenly from each other based on surface topology, lease boundaries, regulations, or other factors. Many older fields were developed on irregular

spacing. In more recent times, more uniform drilling patterns and well spacing have been used.

Peripheral or Central Flooding

In peripheral flooding, the injectors are located around the periphery so that the flood progresses toward the center. When the first row of producers flood out, they are converted to injection status.

Pattern Flooding

In pattern flooding, the injectors are distributed among the producers in some repeating fashion.

Fluid Movement in Waterflooded Reservoirs

Many of the principles discussed in this section also apply to immiscible gas injection, primary recovery by gravity drainage, and natural bottom-water drive.

Displacement Mechanisms

Under ideal conditions, water would displace oil from pores in a rock in a piston-like manner. However, because of various wetting conditions, relative permeabilities of water and oil are important in determining where flow of each fluid occurs, and the manner in which oil is displaced by water.

Buckley–Leverett Frontal Advance

By combining the Darcy equations for the flow of oil and water with the expression for capillary pressure, Leverett provided an equation for the fractional flow of water at any point in the flow stream.

Welge Graphical Technique

A more simplified graphical technique was proposed by Welge which involves integrating the saturation distribution from the injection point to the front.

Viscous Fingering

A problem often encountered in the displacement of oil by water is the viscosity contrast between the two fluids. The adverse mobility ratios that result promote fingering of water through the more viscous crude oil and can reduce the oil recovery efficiency.

Recovery Efficiency

Recovery efficiency is the fraction of oil in place that can be economically recovered with a given process, and it varies widely among recovery processes used.

Displacement Sweep Efficiency (ED)

Factors affecting the displacement efficiency for any oil recovery process are pore geometry, wettability (waterwet, oil-wet, or intermediate), distribution of fluids in the reservoir, and the history of how the saturation occurred.

Volumetric Sweep Efficiency (EV)

Macroscopic or volumetric sweep takes into account that fluid (i.e., water) is injected at one point in a reservoir and that other fluids (i.e., oil, water) are produced from another point.

Areal or Pattern Sweep Efficiency (EP)

Areal sweep efficiency of an oil recovery process depends primarily on two factors: the flooding pattern and the mobilities of the fluids in the reservoir. These are widely discussed by different theoretical engineers.

Vertical or Invasion Sweep Efficiency (EI)

For well-ordered sandstone reservoirs, the permeability measured parallel to the bedding planes of stratified rocks is generally larger than the vertical permeability. For carbonate reservoirs, permeability (and porosity) may have developed after the deposition and consolidation of the formation; thus the concept of a stratified reservoir may not be valid.

Permeability Variation

Two methods of quantitatively defining the variation in vertical permeabilities in reservoirs are commonly used. The extent of permeability stratification is sometimes described with the Lorenz coefficient and is often described with the Dykstra–Parsons coefficient of permeability variation.

Lorenz Coefficient

Schmalz and Rahme suggested arranging the vertical distribution of permeabilities from highest to lowest, and plotting the fraction of total flow capacity (kh) versus the fraction of total volume (hf).

Dykstra–Parsons Coefficient of Permeability Variation

The coefficient of permeability variation described by Dykstra and Parsons [19] is also referred to as the permeability variation or permeability variance. This method assumes that vertical permeabilities in a reservoir will have a lognormal distribution.

Crossflow

In the usual cases where there is vertical communication between the different layers of varying permeabilities, the effect of vertical crossflow must be considered.

Estimation of Waterflood Recovery by Material Balance

The volumetric sweep efficiency can be estimated from one of the correlations given previously or can be obtained from an analogy from similar water-flood projects.

Prediction Methods

An extensive survey on prediction of waterflood performance was provided by Craig with the three appeared most promising being: (1) the Higgins-Leighton streamtube model, (2) the Craig, Geffen, and Morse model and the Prats et al. method.

Performance Evaluation

Monitoring waterflood performance is crucial to the success of the flood. From a reservoir engineering standpoint, the primary concerns are water injectivity and oil productivity.

Injectivity and Injectivity Index

Some engineers express injectivity in terms of qsc/piwf so that when injectivity is given, the reader is cautioned to understand what base pressure was intended.

Injectivities for Various Flood Patterns

Analytical expressions for liquid-filled patterns were given by Muskat and Deppe for a mobility ratio of one.

Monitoring Injectivity

Injection well performance can be analyzed and monitored by several means. During and after a period of injection, the pressure transient methods discussed earlier can be used. Additionally, several bookkeeping methods of monitoring injection rates and pressures are quite useful.

Production Curves

Plots of waterflood injection and production performance can be presented in a number of ways. For the history of the project, water injection rate, oil production rate, and water-oil ratio or water cut can be plotted vs. time (usually months). The actual water injection and oil production rates can be compared to the predicted rates on a time basis.

Waterflood Parameters

Important parameters in waterflood operations are the water residual oil saturation, Sor , and the relative permeability to water, krw. A statistical study of these parameters, as well as peak oil rates, was provided by Felsenthal.

Estimation of Waterflood Residual Oil Saturation

It is recognized throughout the industry that there is no single generally accepted method of measuring residual oil.

Material Balance

Material balance was one of the first and is the most widely used technique employed in estimating oil reserves and depletion. Overall estimates of the amount of in-place and recoverable oil are based mainly on material balance.

Production Data

When the producing oil and water flow rates, formation volume factors, and viscosities are known, relative permeability ratios can be determined. Provided core analysis data are available, this method is easy and rapid.

Transient Tests

Whereas the producing well production data can only provide a relative permeability ratio, transient well testing can provide estimates of reservoir permeabilities to both oil and water (and free gas, if present).

Applicability

Because of the rigid requirements of the assumptions made, and the problems with interpreting the field data, oil saturations obtained from well test analyses are considered rough estimates. The saturation estimate is an overall average for the region of the reservoir influenced by the test.

Coring and Core Testing

Well Coring

Well coring is the process of obtaining representative samples of the productive formation. The choice of depth at which to begin coring can often be a problem. Cores from the regions of interest may not be obtained because of unexpected changes in stratigraphy. There is also the possibility that the region cored will be a nonproductive region which did not contain significant hydrocarbon content initially.

Flushing During Coring

For a condition where the in-place oil saturation is at its waterflood residual value, no more oil can be produced at normal flow rates.

Overbalance Pressure

Unintentional displacement of residual oil may occur in coring operations when large pressure gradients exist near the core bit. In this region when fluid velocities are high, the resulting viscous forces may become sufficient to overcome the capillary forces that hold the residual oil in place.

Drilling Mud Properties

At bottomhole conditions, API filter loss for water-base muds is often in the range of 5 to 10 cc for 30 minutes, which is sufficient to drive most 3-in. to 4-in. diameter cores to the equivalent of the waterflood residual oil saturation if the region being cored is not already at this condition.

Higher mud water loss or smaller core diameters can lead to displacement of some of this residual oil.

Shrinkage and Bleeding

In reservoirs which have been depleted to low pressures and waterflooded to high water-oil ratios, changes in residual saturation in bringing the core to the surface should be fairly minimized. However, in most cases, as the core is raised, gases will come out of solution and can cause residual oil to bleed from the core. The loss of gas causes the oil to shrink. Shrinkage of residual oil can be estimated from laboratory measurements of shrinkage when the pressure of bottomhole oil samples is lowered. Reduction of temperature will also contribute to shrinkage. Considerable development work has gone into developing a core barrel that will bring cores to the surface without major reduction in reservoir pressure, and thus prevent shrinkage and bleeding. A recent modification to a conventional core barrel is the incorporation of a porous sponge to collect oil that bleeds from the core. The oil saturation measured by conventional techniques is corrected for the bleeding of oil as measured in the sponge.

Core Testing

Laboratory tests to estimate reservoir residual oil can be performed on cores that have been preserved at the well site or cores which are extracted with solvent and subsequently restored to reservoir conditions.

Core Handling

Conventional Cores

The precautions taken in handling cores once they have been recovered depends mainly on the measurements and tests that are to be performed on them. If the measurements are routine and can be run within a day or two, it is generally considered sufficient to wipe the cores, wrap them in plastic and protect them from exposure to the sun.

Pressure Cores

Special handling is needed for cores obtained using the pressure core barrel. This is normally carried out by the trained crew which assembled the barrel prior to testing.

Measurement of Residual Oil in Recovered Cores

Various techniques are available for determining the oil content of cores.

Residual Oil from Laboratory Core Floods

Most cores are subjected to cleaning before measurement of permeability and porosity.

Tracer Tests for Determining Residual Oil

How Tracer Tests Work

The tracer test was conceived by applying principles of chromatographic separation to fluid movement in the reservoir. The outstanding advantage of the tracer test is its ability to investigate a relatively large volume of the formation.

Test Procedure

The method involves injection of a bank of water containing an alkyl ester as the tracer. The selection of the ester will depend on temperature of the reservoir.

Interpretation

Computer simulation is used to model the injection, reaction, partitioning, production of the tracers and to correct for overall drift of fluids past the wellbore.

Reservoir Heterogeneity

Although the tracer test samples a relatively large pore volume, results will be weighted towards the higher permeability zones. However, this may not be a disadvantage because these zones will normally be swept preferentially by tertiary processes.

Loss of Tracer

When the chemical tracer is injected into zones that do not subsequently produce fluids, tracer will be lost to the reservoir.

Accuracy

Success in application of the tracer test depends to a considerable extent on the skill and experience of those conducting the test.

Field Application

Logistic considerations require adequate preplanning which means it may be difficult to schedule tests on quick notice. As compared to well logging techniques, considerable time is required to obtain and interpret the data.

Geophysical Well Logging Techniques

Geophysical well logging has the advantage of being an insitu measurement and is able to give a continuous estimate of residual oil saturation versus depth. These features allow the calibration of the measurements in known water saturated formations. A more detailed discussion of well logging is given earlier. An evaluation of logging techniques for measurement of Sor was provided by Fertl.

Logging Devices

Five measurements that have potential application are:

1. Electrical resistivity. Many devices of different depths of investigation are available. These devices cannot be used in cased holes unless one uses some nonconducting casing.
2. Pulsed neutron capture. This name (PNC) covers logs commercially available such as the Dresser Atlas Neutron Lifetime Log (NLL) and the Schlumberger Thermal Decay Time (TDT). The PNC has the virtue of being useful in cased holes.
3. Carbon-oxygen. This measurement has the virtues of being directly sensitive to carbon and of working in cased holes.Nuclear magnetism.
4. This service is not routinely used but has the unique virtue of being sensitive only to formation fluids.
5. Dielectric constant. This service is now routine but is limited to open holes. Its main advantage over resistivity measurements is that water salinity need not be known.

Electrical Resistivity

Resistivity measurements provide a great range of choice as to the volume of formation to be sampled, ranging from a few cubic inches to many cubic feet.

Pulsed-Neutron-Capture

The device used for this measurement periodically emits brief bursts of high energy neutrons. Between bursts these neutrons are rapidly reduced in energy and then more slowly absorbed by formation nuclei. It is the rate of this relatively slow absorption that is measured.

Carbon-Oxygen

The oil industry has long sought a logging method that directly measures oil saturation. The carbon-oxygen (C/O)log is the most recent method in this continuing effort.

Nuclear Magnetism

The technique involves a polarization of the hydrogen magnetic moments via a large coil (3 ft long and 312 in. in diameter) carrying a large direct current. The idea is to align the hydrogen magnetic moments along the field created by the coil. This field ideally is at right angles to the earth’s magnetic field.

Dielectric Constant

The dielectric constants of rock and oil are distinctly different from that of water. The dielectric constant of bulk water is about 80 while those of oil and rock are 4 or less. Due to polarization effects on heterogeneous media, this difference in dielectric properties is masked unless very high frequencies are employed in the measurement.

Accuracy of Logging Methods

The estimated uncertainty in residual oil saturations from electric logs is 5% to 10% under optimum conditions and could easily exceed 10% under less favorable conditions.

Summary of Methods for Estimating Residual Oil

Economics of primary and secondary recovery processes are usually sufficiently attractive to permit considerable error in the estimation of recoverable reserves. However, for tertiary recovery the amount of oil remaining in a reservoir and its distribution must be known with reasonable confidence.

Recommended Methods for Assessing Residual Oil

In determining residual oil saturation, at least two reliable methods should be compared. In most cases, a tracer test combined with injectivity profiles should be run in all situations unless there are clear reasons, such as excessive drift, why the tracer test would fail. The second method selected should provide information on vertical distribution of residual oil. The situations of old and new holes will be considered separately.

Existing Wells

Considerable cost can be saved if first measurements can be made on existing, preferably watered-out, producing wells.

New Wells

When drilling new wells for residual oil determination, special attention should be given to using a bland drilling mud that contains no additives likely to alter interfacial tension or wetting properties. If full-diameter cores are obtained (which is desirable if economics permit), the sponge coring technique should be used with precautions being taken to ensure that flushing is minimal during coring.

Enhanced Oil Recovery Methods

Definition

The more common techniques that are currently being investigated include:

Enhanced Oil Recovery

• Chemical Oil Recovery or Chemical Flooding oil recovery methods include polymer, surfactant/polymer (variations are called micellar-polymer, microemulsion, or low tension waterflooding), and alkaline (or caustic) flooding.
• Polymer-augmented waterflooding: high mobility ratios cause poor displacement and sweep efficiencies, and result in early breakthrough of injected water. By reducing the mobility of water, water breakthrough can be delayed by improving the displacement, areal, and vertical sweep efficiencies; therefore more oil can be recovered at any given water cut. In-Situ Polymerization, in which acrylamide monomer is injected and polymerized in the reservoir. Both injection wells and producing wells have been treated.
• Alkaline or caustic flooding consists of injecting aqueous solutions of sodium hydroxide, sodium carbonate, sodium silicate or potassium hydroxide.
• Surfactant flooding for oil recovery is not a recent development. Patents in the late 1920s and early 1930s proposed the use of low concentrations of detergents to reduce the interfacial tension between water and oil. A recent development uses a combination of chemicals to lower process costs by lowering injection cost and reducing surfactant adsorption. These mixtures, termed lkaline/surfactant/polymer (ASP), permit the injection of larger slugs of injectant because of the lower cost.

Low tension waterflooding

• Micellar/polymer (microemulsion) flooding.
• Hydrocarbon or Gas Injection Methods, including Hydrocarbon Miscible Flooding, Gas injection is certainly one of the oldest methods utilized by engineers to improve recovery, and its use has increased recently, although most of the new expansion has been coming from the nonhydrocarbon gases.
• Miscible solvent (LPG or propane).
• Enriched gas drive.
• High-pressure gas drive.
• Carbon dioxide flooding: CO2 is effective for recovery of oil for a number of reasons: it is very soluble in crude oils at reservoir pressures; therefore, it swells the net volume of oil and reduces its viscosity even before miscibility is achieved by the vaporizing gas drive mechanism.
• Flue gas: previously mentioned, nitrogen and flue gas (about 87% N2 and 12% CO2) are sometimes used in place of hydrocarbon gases because of economics.
• Inert gas (nitrogen).
• Thermal Recovery.
• Steamflooding is the only process routinely used on a commercial basis.
• In-situ combustion or fireflooding is covered comprehensively in the recent SPE monograph on thermal recovery by Prats.

Technical Screening Guides

In some instances, only one type of enhanced recovery technique is applicable for a specific field condition but, in many instances, more then one technique is possible. The selection of the most appropriate process is facilitated by matching reservoir and fluid properties to the requirements necessary for the individual EOR techniques. The mechanisms and limitations of all of these need to be studies and observed.

Criteria for Chemical Methods

For surfactant/polymer methods, oil viscosities of less than 30 cp are desired so that adequate mobility control can be achieved. Good mobility control is essential for this method to make maximum utilization of the expensive chemicals.

Criteria for Thermal Methods

For screening purposes, steamflooding and fireflooding are often considered together. In general, combustion should be the choice when heat losses from steamflooding would be too great.

Laboratory Design for Enhanced Recovery

Preliminary Tests

Water Analysis

A complete water analysis is important to determine the effects of dissolved ions on the EOR processes (especially the chemical methods) or to ascertain any potential water problems such as scale or corrosion that may result when EOR processes are implemented. Water viscosity and density are also measured.

Oil Analysis

Oil viscosity and density are measured as well. A carbon number distribution of the crude may be obtained, especially if CO2 flooding is being considered.

Core Testing

Routine core analyses, such as porosity, permeability, relative permeabilities, capillary pressure, and waterflood susceptibility tests are normally done by service companies that specialize in these types of tests.

Polymer Testing

The desirability of adding polymers is determined by evaluating all available data to assess the performance of normal waterflooding. Any problems such as adverse viscosity ratios or large permeability variations should be identified. If the results of this study indicate that mobility control of the waterflood is warranted, the following laboratory tests are undertaken.

Viscosity Testing

Based on the permeability of the reservoir, relative permeability data, and the desired level of mobility control, polymers of certain molecular weights are selected for testing.

Polymer Retention

Retention of polymer in a reservoir can result from adsorption, entrapment, or, with improper application, physical plugging. Polymer retention tests are usually performed after a standard waterflood (at residual oil saturation) or during a polymer flood oil recovery test.

Surfactant and Alkali Testing

Laboratory tests consist of measuring the interfacial tension (IFT) between the crude oil and the injected solution (alkaline or surfactant additive). This is usually done with a spinning drop interfacial tensiometer.

CO2 Flooding

For the gas injection projects, the trend in this country is toward the use of carbon dioxide although the full impact of CO2 flooding will be felt in several years since construction of CO2 pipelines into the west Texas area was completed in the 1980s. Carbon dioxide flooding is not a truly miscible process; that is, it does not dissolve in all proportions with crude oil.

Thermal Recovery

Viscosities of very viscous crude oils can be reduced by the use of thermal recovery methods. Fireflooding or insitu combustion involves starting a fire in the reservoir and injecting air to sustain the burning of some of the crude oil. Heat that is generated lowers the viscosity of the crude oil and results in improved recovery. With the steam drive or steamflooding process, steam is generated on the surface and injected into the injection wells. For steamflooding, the most important laboratory tests are, of course, viscosity of the crude oil and permeability

of the reservoir core material. To be economically viable, steamfloods must be conducted in thick, very permeable, shallow reservoirs that contain very viscous crude.

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