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Dr. Paul W.J. Glover
MSc Petroleum
Geology
Department of Geology
and Petroleum Geology
University of Aberdeen
UK
Contents
Contents
1.
Introduction
1
2.
Reservoir Fluids
6
3.
Reservoir Drives
19
4.
Coring, Preservation and Handling
33
5.
Porosity
43
6.
Single Phase Permeability
54
7.
Wettability
76
8.
Capillary Pressure
84
9.
Electrical Properties
95
10.
Relative Permeability
104
11.
Commissioning Studies
131
Abbreviations
References
Chapter 1: Introduction
1.1
Introduction
This course aims to provide an understanding of the behaviour of fluids in reservoirs, and the use of core analysis in the evaluation of reservoir potential. It is intended to give the end user of special core analysis data an insight into the experimental techniques used to generate such data and an indication of its validity when applied to reservoir assessment. It has been written from the standpoint of a major oil industry operational support group, and is based upon the substantial experience of working in such an environment.
1.2
Core Analysis and other Reservoir Engineering Data
Special core analysis (SCAL) is one of the main sources of data available to guide the reservoir engineer in assessing the economic potential of a hydrocarbon accumulation. The data sources can be divided into field and laboratory measurements as shown in Figure 1.1.
Laboratory data are used to support field measurements which can be subject to certain limitations, e.g.: (i) Fluid saturations may be
uncertain where actual formation brine composition and resistivity are not available.
(ii) Permeability derived from well test data may be reduced by localised formation damage (skin effects) and increased by fractures.
Sedimentological data can be used to predict areal and vertical trends in rock properties and as an aid in the correct choice of core for laboratory measurements.
For core analysis to provide meaningful data, due regard must be given to the ways in which rock properties can change both during the coring procedure (downhole), core preservation, and subsequent laboratory treatment.
This report is intended as a guide to the reliability and usefulness of the various RCAL and SCAL techniques generally available, and the ways which these techniques have, and will continue to be, refined in the light of current research. Maximum benefit will only be obtained from core analysis by full consultation between the reservoir engineer and the laboratory core analyst; taking all available data into account.
1.3
Reservoir Fluids and Drives
Hydrocarbon reservoirs may contain any or all of three fluid phases. These are;
• Aqueous fluids (brines),
• Oils, and
• Gases (hydrocarbon and non-hydrocarbon).
The distribution of these in a reservoir depends upon the reservoir conditions, the fluid properties, and the rock properties. The fluid properties are of fundamental importance, and will be studied in the first part of this course.
The natural energy of a reservoir can be used to facilitate the production of hydrocarbon and non-hydrocarbon fluids from reservoirs. These sources of energy are called natural drive mechanisms. However, there may still be producible oil in a reservoir when natural drive mechanisms are exhausted. There exist artificial drive mechanisms that can then be used to produce some of the remaining oil. The type of drive currently operating in a reservoir has a strong control on the evaluation and management of the reservoir. Consequently, drive mechanisms will also be reviewed as part of the course.
1.4
Routine Core Analysis (RCAL)
Routine core analysis attempts to give only the very basic properties of unpreserved core. These are basic rock dimensions, core porosity, grain density, gas permeability, and water saturation. Taken in context routine data can provide a useful guide to well and reservoir performance, provided its limitations are appreciated. These limitations arise because routine porosity and permeability measurements are always made with gases on cleaned, dried core at room conditions. Such conditions are distinctly different from the actual reservoir situation. Thus routine data should be applied to the reservoir state with caution. This is especially true for permeability measurements. Routine core analysis data is cheap, and often form the great majority of the dataset representing reservoir core data. A schematic diagram of common RCAL measurements is given as Figure 1.2.
Routine porosity data are generally reliable, being little affected by interactions between minerals and reservoir fluids. Correction for overburden loading is usually all that is required. Routine permeability results can misrepresent the reservoir situation as reservoir fluids often interact with the minerals forming the pore walls. This is frequently the case because these interactions cannot be allowed for in routine measurements. Correction can be only made for the compressibility of gases used. Thus the Klinkenberg correction converts gas permeability to ‘equivalent liquid permeability’ (KL) but still assumes no fluid-rock interaction. An actual
present in the reservoir, drying can destroy them and KL may be one or two orders of
magnitude greater than an actual brine permeability measured on preserved, undried, core. An example of this effect is seen in the Magnus field and was demonstrated by Heaviside, Langley and Pallatt [1]. Permeability is affected by overburden loading to a greater extent than porosity. This must be allowed for when applying routine data to the reservoir situation.
Each of the RCAL measurements made is discussed in detail, covering; the theory, test methods, and limitations of alternative methods. The topics covered will include:
Chapter 4. Unpreserved core cleaning and water analysis.
Chapter 5. Sample dimension, porosity and grain density measurements. Chapter 6. Gas permeability.
1.5
Special Core Analysis (SCAL)
Special Core Analysis attempts to extend the data provided by routine measurements to situations more representative of reservoir conditions. SCAL data is used to support log and well test data in gaining an understanding of individual well and overall reservoir performance. However, SCAL measurements are more expensive, and are commonly only done on a small selected group of samples, or if a difficult strategic reservoir management decision has to be made (e.g. to gasflood, or not to gasflood).
Tests are carried out to measure fluid distribution, electrical properties and fluid flow characteristics in the two and occasionally three phase situation, and are made on preserved core. A schematic diagram of common SCAL measurements is given as Figure 1.3.
Porosity and single phase gas or liquid permeabilities are measured at overburden loadings so that the room condition data can be corrected.
Wettability and capillary pressure data are generated by controlled displacement of a wetting phase by a non wetting phase e.g., brine by air, brine by oil or air by mercury. These systems usually have known interfacial tension (IFT) and wetting (contact) angle properties.
Conversion to the required reservoir values of IFT and contact angle can then be attempted to give data for predicting saturation at a given height within a reservoir. Electrical properties are measured at formation brine saturations of unity and less than unity, to obtain the cementation exponent, resistivity index, and excess conductivity of samples. These are used to provide data for interpretation of down-hole logs.
Relative permeability attempts to provide data on the relative flow rates of phases present (e.g. oil and water or gas and water). Fluid flow is strongly influenced by fluid viscosities, and wetting characteristics. Care has to be taken that measurements are made under appropriate conditions, which allow some understanding of the wetting characteristics. The data generated allows relative flow rates and recovery efficiency to be assessed.
Each of the SCAL measurements made is discussed in detail in the relevant chapter, covering the theory, test methods, and limitations of alternative methods. The topics covered will include:
Chapter 4. Preserved core; methods of preservation and requirement for preserved core.
Chapter 5. Porosity at overburden pressures.
Chapter 6. Gas and liquid single phase permeabilities at overburden conditions. Chapter 7. Wettability determinations; techniques available and limitations of
data obtained.
Chapter 8. Capillary pressure measurements; techniques available and limitations of data obtained.
Chapter 9. Electrical measurements; resistivity index and saturation exponent, formation factor at room and overburden pressure, and cementation exponent.
Chapter 10. Relative Permeability; Theory, Techniques available, limitations and application of data.
Chapter 11. Typical SCAL programmes.
1.6
Arrangement of the Text
Effective assessment of reservoirs begins with an understanding of the properties of reservoir fluids, which is covered in Chapter 2. Chapter 3 discusses the various reservoir drives encountered in reservoir management. Chapter 4 discusses coring, core preservation and handling, which is of relevance mainly to SCAL studies. Chapters 5 and 6 cover RCAL porosity and permeability measurements, together with extensions to overburden pressure for SCAL studies. Chapters 7 to 10 cover various wettability, capillary pressure, electrical, and relative permeability measurements commonly practised in SCAL studies. Chapter 11 briefly examines typical SCAL work programmes.
Chapter 2:
Reservoir Fluids
2.1 Introduction
Reservoir fluids fall into three broad categories; (i) aqueous solutions with dissolved salts, (ii) liquid hydrocarbons, and (iii) gases (hydrocarbon and non-hydrocarbon). In all cases their compositions depend upon their source, history, and present thermodynamic conditions. Their distribution within a given reservoir depends upon the thermodynamic conditions of the reservoir as well as the petrophysical properties of the rocks and the physical and chemical properties of the fluids themselves. This chapter briefly examines these reservoir fluid properties.
2.2 Fluid Distribution
The distribution of a particular set of reservoir fluids depends not only on the characteristics of the rock-fluid system now, but also the history of the fluids, and ultimately their source. A list of factors affecting fluid distribution would be manifold. However, the most important are:
Depth The difference in the density of the fluids results in their separation over time due to
gravity (differential buoyancy).
Fluid Composition The composition of the reservoir fluid has an extremely important
control on its pressure-volume-temperature properties, which define the relative volumes of each fluid in a reservoir. This subject is a major theme of this chapter. It also affects distribution through the wettability of the reservoir rocks (Chapter 7).
Reservoir Temperature Exerts a major control on the relative volumes of each fluid in a
reservoir.
Fluid Pressure Exerts a major control on the relative volumes of each fluid in a reservoir. Fluid Migration Different fluids migrate in different ways depending on their density,
viscosity, and the wettability of the rock. The mode of migration helps define the distribution of the fluids in the reservoir.
Trap-Type Clearly, the effectiveness of the hydrocarbon trap also has a control on fluid
distribution (e.g., cap rocks may be permeable to gas but not to oil).
Rock structure The microstructure of the rock can preferentially accept some fluids and not
others through the operation of wettability contrasts and capillary pressure. In addition, the common heterogeneity of rock properties results in preferential fluid distributions throughout the reservoir in all three spatial dimensions.
The fundamental forces that drive, stabilise, or limit fluid movement are:
• Gravity (e.g. causing separation of gas, oil and water in the reservoir column)
• Capillary (e.g. responsible for the retention of water in micro-porosity)
• Molecular diffusion (e.g. small scale flow acting to homogenise fluid compositions within a given phase)
• Thermal convection (convective movement of all mobile fluids, especially gases)
Although each of these forces and factors vary from reservoir to reservoir, and between lithologies within a reservoir, certain forces are of seminal importance. For example, it is gravity that ensures, that when all three basic fluids types are present in an uncompartmentalised reservoir, the order of fluids with increasing depth is
GAS:OIL:WATER, in exact analogy to a bottle of french dressing that has been left to settle.
2.3 Aqueous Fluids
Accumulations of hydrocarbons are invariably associated with aqueous fluids (formation waters), which may occur as extensive aquifers underlying or interdigitated with hydrocarbon bearing layers, but always occur within the hydrocarbon bearing layers as connate water. These fluids are commonly saline, with a wide range of compositions and concentrations; Table 2.1 shows an example of a reservoir brine. Usually the most common dissolved salt is NaCl, but many others occur in varying smaller quantities. The specific gravity of pure water is defined as unity, and the specific gravity of formation waters increases with salinity at a rate of about 0.075 per 100 parts per thousand of dissolved solids. When SCAL measurements are made with brine, it is usual to make up a simulated formation brine to a recipe such as that given in Table 2.1, and then deaerate it prior to use.
Table 2.1 Composition of Draugen 6407/9-4 Formation Water Component Concentration, g dm-3
Pure water Solvent
NaCl 34.70 CaCl2.6H2O 4.90 MgCl2.6H2O 2.70 KCl 0.40 NaHCO3 0.40 SrCl2.6H2O 0.12 BaCl2.6H2O 0.06 Final pH = 7
Why a connate water phase is invariably present in hydrocarbon bearing reservoir rock is easily explained. The reservoir rocks were initially fully or partially saturated with aqueous fluids before the migration of the oil from source rocks below them. The oil migrates upwards from the source rocks, driven by the differential buoyancy of the oil and the water. In this process most of the water swaps places with the oil since no fluids can escape from the cap rock above the reservoir. However, the water is not completely displaced as the initial reservoir rock is invariably water-wet, leaving the water-wet grains covered in a thin layer of water, with the remainder of the pore space full of oil. Water also remains in the micro-porosity where gravity segregation forces are insufficient to overcome the water-rock capillary forces.
The aqueous fluids, whether as connate water or in aquifers, commonly contain dissolved gases at reservoir temperatures and pressures. Different gases dissolve in aqueous fluids to different extents, and this gas solubility also varies with temperature and pressure. Table 2.2 shows a selection of gases. If gas saturated water at reservoir pressure is subjected to lower
pressures, the gas will be liberated, in exactly the same way that a lemonade bottle fizzes when opened. In reservoirs the dissolved gas is mainly methane (from 10 SCF/STB at 1000 psi to 35 SCF/STB at 10 000 psi for gas-water systems, and slightly less for water-oil systems). Higher salinity formation waters tend to contain less dissolved gas.
Table 2.2 Dissolution of Gases in Water (dissolved mole fraction) at 1 bar Gas 104× Xgas @ 1 bar
25oC 55oC Helium 0.06983 0.07179 Argon 0.2516 0.1760 Radon 1.675 0.8911 Hydrogen 0.1413 0.1313 Nitrogen 0.1173 0.08991 Oxygen 0.2298 0.0164 Carbon dioxide 6.111 3.235 Methane 0.2507 0.1684 Ethane 0.3345 0.01896 Ammonium 1876 1066
Xgas = mole fraction of gas dissolved at 1 bar pressure, i.e.=1/Hgas.
Aqueous fluids are relatively incompressible compared to oils, and extremely so compared to gases (2.5×10-6 to 5×10-6 per psi decreasing with increasing salinity). Consequently, if a unit volume of formation water with no dissolved gases at reservoir pressure conditions is transported to surface pressure condition, it will expand only slightly compared to the same initial volume of oil or gas. It should be noted that formation waters containing a significant proportion of dissolved gases are more compressible than those that are not gas saturated. These waters expand slightly more on being brought to the surface. However the reduction in temperature on being brought to the surface causes the formation water to shrink and there is also a certain shrinkage associated with the release of gas as pressure is lowered. The overall result is that brines experience a slight shrinkage (< 5%) on being brought from reservoir conditions to the surface.
Formation waters generally have densities that are greater than those of oils, and dynamic viscosities that are a little lower (Table 2.3). The viscosity at high reservoir temperatures (>250oC) can be as low as 0.3 cP, rises to above 1 cP at ambient conditions, and increases with increasing salinity.
Table 2.3 Densities and Viscosities for a Typical Formation Water and a Refined Oil Brine Component Composition, g/l
Pure water Solvent
NaCl 150.16
CaCl2.6H2O 101.32
MgCl2.6H2O 13.97
Na2SO4 0.55
NaHCO3 0.21
Fluid Temperature, oC Density, g/cm3 Dynamic Viscosity, cP
Brine 20 1.1250 1.509 Brine 25 1.1237 1.347 Brine 30 1.1208 1.219 Kerosene 20 0.7957 1.830 Kerosene 25 0.7923 1.661 Kerosene 30 0.7886 1.514
2.4 Phase Behaviour of Hydrocarbon Systems
Figure 2.1 shows the pressure versus volume per mole weight (specific volume) characteristics of a typical pure hydrocarbon (e.g. propane). Imagine in the following discussion that all changes occur isothermally (with no heat flowing either into or out of the fluid) and at the same temperature. Initially the component is in the liquid phase at 1000 psia, and has a volume of about 2 ft3/lb.mol. (point A). Expansion of the system (A→B) results in large drops in pressure with small increases in specific volume, due to the small compressibility of liquids (liquid hydrocarbons as well as liquid formation waters have small compressibilities that are almost independent of pressure for the range of pressures encountered in hydrocarbon reservoirs). On further expansion, a pressure will be attained where the first tiny bubble of gas appears (point B). This is the bubble point or saturation pressure for a given temperature. Further expansion (B→C) now occurs at constant pressure with more and more of the liquid turning into the gas phase until no more fluid remains. The constant pressure at which this occurs is called the vapour pressure of the fluid at a given temperature. Point C represents the situation where the last tiny drop of liquid turns into gas, and is called the dew point. Further expansion now takes place in the vapour phase (C→D). The pistons in Figure 2.1 demonstrate the changes in fluid phase schematically. It is worth noting that the process A→B→C→D described above during expansion (reducing the pressure on the piston) is perfectly reversible. If a system is in state D, then application of pressure to the fluid by applying pressure to the pistons will result in changes following the curve D→C→B→A.
We can examine the curve in Figure 2.1 for a range of fluid temperatures. If this is done, the pressure-volume relationships obtained can be plotted on a pressure-volume diagram with the bubble point and dew point locus also included (Figure 2.2). Note that the bubble point and dew point curves join together at a point (shown by a dot in Figure 2.2). This is the critical point. The region under the bubble point/dew point envelope is the region where the vapour phase and liquid phase can coexist, and hence have an interface (the surface of a liquid drop or of a vapour bubble). The region above this envelope represents the region where the
vapour phase and liquid phase do not coexist. Thus at any given constant low fluid pressure, reduction of fluid volume will involve the vapour condensing to a liquid via the two phase region, where both liquid and vapour coexist. But at a given constant high fluid pressure (higher than the critical point), a reduction of fluid volume will involve the vapour phase turning into a liquid phase without any fluid interface being generated (i.e. the vapour becomes denser and denser until it can be considered as a light liquid). Thus the critical point can also be viewed as the point at which the properties of the liquid and the gas become indistinguishable (i.e. the gas is so dense that it looks like a low density liquid and vice versa). Suppose that we find the bubble points and dew points for a range of different temperatures, and plot the data on a graph of pressure against temperature. Figure 2.3 shows such a plot. Note that the dew point and bubble points are always the same for a pure component, so they plot as a single line until the peak of Figure 2.2 is reached, which is the critical point.
The behaviour of a hydrocarbon fluid made up of many different hydrocarbon components shows slightly different behaviour (Figure 2.4). The initial expansion of the liquid is similar to that for the single component case. Once the bubble point is reached, further expansion does
not occur at constant pressure but is accompanied by a decrease in pressure (vapour pressure) due to changes in the relative fractional amounts of liquid to gas for each hydrocarbon in the vaporising mixture. In this case the bubble points and dew points differ, and the resulting pressure-temperature plot is no longer a straight line but a phase envelope composed of the bubble point and dew point curves, which now meet at the critical point (Figure 2.5). There are also two other points on this diagram that are of interest. The cricondenbar, which defines the pressure above which the two phases cannot exist together whatever the temperature, and the cricondentherm, which defines the temperature above which the two phases cannot exist together whatever the pressure. A fluid that exists above the bubble point curve is classified as undersaturated as it contains no free gas, while a fluid at the bubble point curve or below it is classified as saturated, and contains free gas.
Figure 2.6 shows the PT diagram for a reservoir fluid, together with a production path from the pressure and temperature existing in the reservoir to that existing in the separator at the
surface. Note that the original fluid was an undersaturated liquid at reservoir conditions. On production the fluid pressure drops fast with some temperature reduction occurring as the fluid travels up the borehole. All reservoirs are predominantly isothermal because of their large thermal inertia. This results in the production path of all hydrocarbons initially undergoing a fluid pressure reduction. Figure 2.6 shows that the ratio of vapour to liquid at separator conditions is approximately 55:45. If we analyse the PT characteristics of the separator gas and separator fluid separately then we would find that the separator pressure-temperature point representing the separator conditions falls on the dew point line of the separator gas PT diagram, and on the bubble point line of the separator oil PT diagram. This indicates that the shape of the PT diagram for various mixtures of hydrocarbon gases and liquids varies greatly. Clearly, therefore it is extremely important to understand the PT phase envelope as it can be used to classify and understand major hydrocarbon reservoirs.
2.5 PVT Properties of Hydrocarbon Fluids
2.5.1 Cronquist Classification
Hydrocarbon reservoirs are usually classified into the following five main types, after Cronquist, 1979: • Dry gas • Wet gas • Gas condensate • Volatile oil • Black oil
Each of these reservoirs can be understood in terms of its phase envelope. The typical components of production from each of these reservoirs is shown in Table 2.4, and a schematic diagram of their PT phase envelopes is shown in Figure 2.7.
Table 2.4 Typical Mol% Compositions of Fluids Produced from Cronquist Reservoir Types
Component or Property
Dry Gas Wet Gas Gas Condensate
Volatile Oil Black Oil
CO2 0.10 1.41 2.37 1.82 0.02 N2 2.07 0.25 0.31 0.24 0.34 C1 86.12 92.46 73.19 57.60 34.62 C2 5.91 3.18 7.80 7.35 4.11 C3 3.58 1.01 3.55 4.21 1.01 iC4 1.72 0.28 0.71 0.74 0.76 nC4 - 0.24 1.45 2.07 0.49 iC5 0.50 0.13 0.64 0.53 0.43 nC5 - 0.08 0.68 0.95 0.21 C6s - 0.14 1.09 1.92 1.16 C7+ - 0.82 8.21 22.57 56.40 GOR (SCF/STB) ∞ 69000 5965 1465 320 OGR (STB/MMSCF) 0 15 165 680 3125 API Specific Gravity, γAPI ,oAPI - 65.0 48.5 36.7 23.6 C7+ Specific Gravity, γo - 0.750 0.816 0.864 0.920
Note: Fundamental specific gravity γo is equal to the density of the fluid divided by the
density of pure water, and that for C7+ is for the bulked C7+ fraction. The API specific gravity γAPI is defined as; γAPI = (141.5/γo) - 131.5.
2.5.2 Dry Gas Reservoirs
A typical dry gas reservoir is shown in Figure 2.8. The reservoir temperature is well above the cricondentherm. During production the fluids are reduced in temperature and pressure. The temperature-pressure path followed during production does not penetrate the phase envelope, resulting in the production of gas at the surface with no associated liquid phase. Clearly, it would be possible to produce some liquids if the pressure is maintained at a higher level. In practice, the stock tank pressures are usually high enough for some liquids to be produced (Figure 2.9). Note the lack of C5+ components, and the predominance of methane in
the dry gas in Table 2.4.
2.5.3 Wet Gas Reservoirs
A typical wet gas reservoir is shown in Figure 2.9. The reservoir temperature is just above the cricondentherm. During production the fluids are reduced in temperature and pressure. The temperature-pressure path followed during production just penetrates the phase envelope, resulting in the production of gas at the surface with a small associated liquid phase. Note the presence of small amounts of C5+ components, and the continuing predominance of methane
in the wet gas in Table 2.4. The GOR (gas-oil ratio) has fallen as some liquid is being produced. However, this liquid usually amounts to less than about 15 STB/MMSCF. Note also the small specific gravity for C7+ components (0.750), indicating that the majority of the
2.5.4 Gas Condensate Reservoirs
A typical gas condensate reservoir is shown in Figure 2.10. The reservoir temperature is such that it falls between the temperature of the critical point and the cricondentherm. The production path then has a complex history. Initially, the fluids are in an indeterminate vapour phase, and the vapour expands as the pressure and temperature drop. This occurs until the dewpoint line is reached, whereupon increasing amounts of liquids are condensed from the vapour phase. If the pressures and temperatures reduce further, the condensed liquid may re-evaporate, although sufficiently low pressures and temperatures may not be available for this to happen. If this occurs, the process is called isothermal retrograde condensation. Isobaric retrograde condensation also exists as a scientific phenomenon, but does not occur in the predominantly isothermal conditions of hydrocarbon reservoirs. Thus, in gas condensate reservoirs, the oil produced at the surface results from a vapour existing in the reservoir. Note the increase in the C7+
components and the continued importance of methane in Table 2.4. The GOR has decreased significantly, the OGR has increased, and the specific gravity of the C7+
components is increasing, indicating that greater fractions of denser hydrocarbons are present in the C7+ fraction.
2.5.5 Volatile Oil Reservoirs
A typical volatile oil reservoir is shown in Figure 2.11. The reservoir PT conditions place it inside the phase envelope, with a liquid oil phase existing in equilibrium with a vapour phase having gas condensate compositions. The production path results in small amounts of further condensation, and re-evaporation can occur again, but should be avoided as much as possible by keeping the stock tank pressure as high as possible. Reference to Table 2.4 shows that the fraction of gases is reduced, and the fraction of denser liquid hydrocarbon liquids is increased, compared with the previously discussed reservoir types. Changes in the GOR, OGR and specific gravities are in agreement with the general trend.
2.5.6 Black Oil Reservoirs
A typical gas condensate reservoir is shown in Figure 2.12. The reservoir temperature is much lower than the temperature of the critical point of the system, and at pressures above the cricondenbar. Thus, the hydrocarbon in the reservoir exists as a liquid at depth. The production path first involves a reduction in pressure with only small amounts of expansion in the liquid phase. Once the bubble point line is reached, gas begins to come out of solution and continues to do so until the stock tank is reached. The composition of this gas changes very little along the production path, is relatively lean, and is not usually of economic importance when produced. Table 2.4 shows a produced hydrocarbon fluid that is now dominated by heavy hydrocarbon liquids, with most of the produced gas present as methane. The GOR, OGR and specific gravities mirror the fluid composition.
Chapter 3: Reservoir Drives
3.1 Introduction
Recovery of hydrocarbons from an oil reservoir is commonly recognised to occur in several recovery stages. These are:
(i) Primary recovery (ii) Secondary recovery
(iii) Tertiary recovery (Enhanced Oil Recovery, EOR) (iv) Infill recovery
Primary recovery This is the recovery of hydrocarbons from the reservoir using the natural
energy of the reservoir as a drive.
Secondary recovery This is recovery aided or driven by the injection of water or gas from
the surface.
Tertiary recovery (EOR) There are a range of techniques broadly labelled ‘Enhanced Oil
Recovery’ that are applied to reservoirs in order to improve flagging production.
Infill recovery Is carried out when recovery from the previous three phases have been
completed. It involves drilling cheap production holes between existing boreholes to ensure that the whole reservoir has been fully depleted of its oil.
This chapter discusses primary, secondary and EOR drive mechanisms and techniques.
3.2 Primary Recovery Drive Mechanisms
During primary recovery the natural energy of the reservoir is used to transport hydrocarbons towards and out of the production wells. There are several different energy sources, and each gives rise to a drive mechanism. Early in the history of a reservoir the drive mechanism will not be known. It is determined by analysis of production data (reservoir pressure and fluid production ratios). The earliest possible determination of the drive mechanism is a primary goal in the early life of the reservoir, as its knowledge can greatly improve the management and recovery of reserves from the reservoir in its middle and later life.
There are five important drive mechanisms (or combinations). These are: (i) Solution gas drive
(ii) Gas cap drive (iii) Water drive (iv) Gravity drainage
(v) Combination or mixed drive
Table 3.1 Recovery ranges for each drive mechanism
Drive Mechanism Energy Source Recovery, % OOIP
Solution gas drive Evolved solution gas and expansion 20-30
Evolved gas 18-25
Gas expansion 2-5
Gas cap drive Gas cap expansion 20-40
Water drive Aquifer expansion 20-60
Bottom 20-40
Edge 35-60
Gravity drainage Gravity 50-70
A combination or mixed drive occurs when any of the first three drives operate together, or when any of the first three drives operate with the aid of gravity drainage.
The reservoir pressure and GOR trends for each of the main (first) three drive mechanisms is shown as Figures 3.1 and 3.2. Note particularly that water drive maintains the reservoir pressure much higher than the gas drives, and has a uniformly low GOR.
3.2.1 Solution Gas Drive
This drive mechanism requires the reservoir rock to be completely surrounded by impermeable barriers. As production occurs the reservoir pressure drops, and the exsolution and expansion of the dissolved gases in the oil and water provide most of the reservoirs drive energy. Small amounts of additional energy are also derived from the expansion of the rock and water, and gas exsolving and
expanding from the water phase. The process is shown schematically in Figure 3.3.
A solution gas drive reservoir is initially either considered to be undersaturated or saturated depending on its pressure:
• Undersaturated: Reservoir pressure > bubble point of oil.
• Saturated: Reservoir pressure ≤ bubble point of oil.
For an undersaturated reservoir no free gas exists until the reservoir pressure falls below the bubblepoint. In this regime reservoir drive energy is provided only by the bulk expansion of the reservoir rock and liquids (water and oil).
For a saturated reservoir, any oil production results in a drop in reservoir pressure that causes bubbles of gas to exsolve and expand. When the gas comes out of solution the oil (and water) shrink slightly. However, the volume of the exsolved gas, and its subsequent expansion more than makes up for this. Thus gas expansion is the primary reservoir drive for reservoirs below the bubble point.
Solution gas drive reservoirs show a particular characteristic pressure, GOR and fluid production history. If the reservoir is initially undersaturated, the reservoir pressure can drop by a great deal (several hundred psi over a few months), see Figures 3.1 and 3.2.
This is because of the small compressibilities of the rock water and oil, compared to that of gas. In this undersaturated phase, gas is only exsolved from the fluids in the well bore, and consequently the GOR is low and constant. When the reservoir reaches the bubble point pressure, the pressure declines less quickly due to the formation of gas bubbles in the reservoir that expand taking up the volume exited by produced oil and hence protecting against pressure drops. When this happens, the GOR rises dramatically (up to 10 times). Further fall in
reservoir pressure, as production continues, can, however, lead to a decrease in GOR again when reservoir pressures are such that the gas expands less in the borehole. When the GOR initially rises, the oil production falls and artificial lift systems are then instituted.
Oil recovery from this type of reservoir is typically between 20% and 30% of original oil in place (i.e. low). Of this only 0% to 5% of oil is recovered above the bubblepoint. There is usually no production of water during oil recovery unless the reservoir pressure drops sufficiently for the connate water to expand sufficiently to be mobile. Even in this scenario little water is produced.
3.2.2 Gas Cap Drive
A gas cap drive reservoir usually benefits to some extent from solution gas drive, but derives its main source of reservoir energy from the expansion of the gas cap already existing above the reservoir.
The presence of the expanding gas cap limits the pressure decrease experienced by the reservoir during production. The actual rate of pressure decrease is related to the size of the gas cap.
The GOR rises only slowly in the early stages of production from such a reservoir because the pressure of the gas cap prevents gas from coming out of solution in the oil and water. As production continues, the gas cap expands pushing the gas-oil contact (GOC) downwards (Figure 3.4). Eventually the GOC will reach the production wells and the GOR will increase by large amounts (Figures 3.1 and 3.2). The slower reduction in pressure experienced by gas cap reservoirs compared to solution drive reservoirs results in the oil production rates being much higher throughout the life of the reservoir, and needing artificial lift much later than for solution drive reservoirs.
Gas cap reservoirs produce very little or no water.
The recovery of gas cap reservoirs is better than for solution drive reservoirs (20% to 40% OOIP). The recovery efficiency depends on the size of the gas cap, which is a measure of how much latent energy there is available to drive production, and how the reservoir is managed, i.e. how the energy resource is used bearing in mind the geometric characteristics of the reservoir, economics and equity considerations. Points of importance to bear in mind when managing a gas cap reservoir are:
• Steeply dipping reservoir oil columns are best.
• Thick oil columns are best, and are perforated at the base, as far away from the gas cap as possible. This is to maximise the time before gas breaks through in the well.
• Wells with increasing GOR (gas cap breakthrough) can be shut in to reduce field wide GOR.
• Produced gas can be separated and immediately injected back into the gas cap to maintain gas cap pressure.
3.2.3 Water Drive
The drive energy is provided by an aquifer that interfaces with the oil in the reservoir at the oil-water contact (OWC). As production continues, and oil is extracted from the reservoir, the aquifer expands into the reservoir displacing the oil. Clearly, for most reservoirs, solution gas drive will also be taking place, and there may also be a gas cap contributing to the primary recovery. Two types of water drive are commonly recognised:
• Bottom water drive (Figure 3.5)
• Edge water drive (Figure 3.5)
The pressure history of a water driven reservoir depends critically upon: (i) The size of the aquifer.
(ii) The permeability of the aquifer. (iii) The reservoir production rate.
If the production rate is low, and the size and permeability of the aquifer is high, then the reservoir pressure will remain high because all produced oil is replaced efficiently with water. If the production rate is too high then the extracted oil may not be able to be replaced by water in the same timescale, especially if the aquifer is small or low permeability. In this case the reservoir pressure will fall (Figure 3.1).
The GOR remains very constant in a strongly water driven reservoir (Figure 3.2), as the pressure decrease is small and constant, whereas if the pressure decrease is higher (weakly water driven reservoir) the GOR increases due to gas exsolving from the oil and water in the reservoir. Likewise the oil production from a strongly water driven reservoir remains fairly constant until water breakthrough occurs.
Using analogous arguments to the gas cap drive, it can be seen that thick oil columns are again an advantage, but the wells are perforated high in the oil zone to delay the water breakthrough. When water breakthrough does occur the well can either be shut-down, or assisted using gas lift. Reinjection of water into the aquifer is seldom done because the injected water usually just disappears into the aquifer with no effect on aquifer pressure. The recovery from water driven reservoirs is usually good (20-60% OOIP, Table 3.1), although the exact figure depends on the strength of the aquifer and the efficiency with which the water displaces the oil in the reservoir, which depends on reservoir structure, production well placing, oil viscosity, and production rate. If the ratio of water to oil viscosity is large, or the production rate is high then fingering can occur which leaves oil behind in the reservoir (Figure 3.6).
3.2.4 Gravity Drainage
The density differences between oil and gas and water result in their natural segregation in the reservoir. This process can be used as a drive mechanism, but is relatively weak, and in practice is only used in combination with other drive mechanisms. Figure 3.7 shows production by gravity drainage.
The best conditions for gravity drainage are:
• Thick oil zones.
• High vertical permeabilities.
The rate of production engendered by gravity drainage is very low compared with the other drive mechanisms examined so far. However, it is extremely efficient over long periods and can give rise to extremely high recoveries (50-70% OOIP, Table 3.1). Consequently, it is often used in addition to the other drive mechanisms.
3.2.5 Combination or Mixed Drive
In practice a reservoir usually incorporates at least two main drive mechanisms. For example, in the case shown in Figure 3.8. We have seen that the management of the reservoir for
different drive mechanisms can be diametrically opposed (e.g. low perforation for gas cap reservoirs compared with high perforation for water drive reservoirs). If both occur as in Figure 3.8, a compromise must be sought, and this compromise must take into account the strength of each drive present, the size of the gas cap, and the size/permeability of the aquifer. It is the job of the reservoir manager to identify the strengths of the drives as early as possible in the life of the reservoir to optimise the reservoir performance.
3.3 Secondary Recovery
Secondary recovery is the result of human intervention in the reservoir to improve recovery when the natural drives have diminished to unreasonably low efficiencies. Two techniques are commonly used:
(i) Waterflooding (ii) Gasflooding
3.3.1 Waterflooding
This method involves the injection of water at the base of a reservoir to; (i) Maintain the reservoir pressure, and
(ii) Displace oil (usually with gas and water) towards production wells.
The detailed treatment of waterflood recovery estimation, mathematical modelling, and design are beyond the scope of these notes. However, it should be noted that the successful outcome of a waterflood process depends on designs based on accurate relative permeability data in both horizontal directions, on the choice of a good injector/producer array, and with full account taken of the local crustal stress directions in the reservoir.
3.3.2 Gas Injection
This method is similar to waterflooding in principal, and is used to maintain gas cap pressure even if oil displacement is not required. Again accurate relperms are needed in the design, as well as injector/producer array geometry and crustal stresses. There is an additional complication in that re-injected lean gas may strip light hydrocarbons from the liquid oil phase. At first sight this may not seem a problem, as recombination in the stock tank or afterwards may be carried out. However, equity agreements often give different percentages of gas and oil to different companies. Then the decision whether to gasflood is not trivial (e.g. Prudhoe Bay, Alaska).
3.4 Tertiary Recovery (Enhanced Oil Recovery)
Primary and secondary recovery methods usually only extract about 35% of the original oil in place. Clearly it is extremely important to increase this figure. Many enhanced oil recovery methods have been designed to do this, and a few will be reviewed here. They fall into three broad categories; (i) thermal, (ii) chemical, and (iii) miscible gas. All are extremely expensive, are only used when economical, and are implemented after extensive SCAL studies have isolated the reservoir rock characteristics that are causing oil to remain unproduced by conventional methods.
3.4.1 Thermal EOR
These processes use heat to improve oil recovery by reducing the viscosity of heavy oils and vaporising lighter oils, and hence improving their mobility. The techniques include:
(i) Steam injection (Figure 3.9).
(ii) In situ combustion (injection of a hot gas that combusts with the oil in place, Figure 3.10).
(iii) Microwave heating downhole (3.11). (iv) Hot water injection.
It is worth noting that the generation of large amounts of heat and the treatment of evolved gas has large environmental implications for these methods. However, thermal EOR is probably the most efficient EOR approach.
3.4.2 Chemical EOR
These processes use chemicals added to water in the injected fluid of a waterflood to alter the flood efficiency in such a way as to improve oil recovery. This can be done in many ways, examples are listed below:
(i) Increasing water viscosity (polymer floods)
(ii) Decreasing the relative permeability to water (cross-linked polymer floods) (iii) Increasing the relative permeability to oil (micellar and alkaline floods)
(iv) Decreasing Sor (micellar and alkaline floods)
(v) Decreasing the interfacial tension between the oil and water phases (micellar and alkaline floods)
Chemical flood additives, especially surfactants designed to reduce surface or interfacial tension, are extremely expensive. Thus the whole chemical EOR flood is designed to minimise the amount of surfactants needed, and to ensure that the EOR process is economically successful as well as technically. Chemical flooding is therefore not a simple single stage process. Initially the reservoir is subjected to a preflush of chemicals designed to improve the stability of the interface between the in-situ fluids and the chemical flood itself. Then the chemical surfactant EOR flood is carried out. Commonly polymers are injected into the reservoir after the chemical flood to ensure that a favourable mobility ratio is maintained. A buffer to maintain polymer stability follows, then a driving fluid, which is usually water, is injected. Figure 3.13 shows a typical flood sequence. Note that the mobilised oil bank moves ahead of the surfactant flood, and how the total process has reduced the amount of the surfactant fluid used.
3.4.3 Miscible Gas Flooding
This method uses a fluid that is miscible with the oil. Such a fluid has a zero interfacial tension with the oil and can in principal flush out all of the oil remaining in place. In practice a gas is used since gases have high mobilities and can easily enter all the pores in the rock providing the gas is miscible in the oil. Three types of gas are commonly used:
(i) CO2
(ii) N2
All of these are relatively cheap to obtain either from the atmosphere or from evolved reservoir gases. The high mobility of gases can cause a problem in the reservoir flooding process, since gas breakthrough may be early due to fingering, leading to low sweep efficiencies. Effort is then concentrated on trying to improve the sweep efficiency. One such approach is called a miscible WAG (water alternating gas). In this approach water slugs and CO2 slugs are alternately injected into the reservoir; the idea being that the water slugs will
lower the mobility of the CO2 and lead to a more piston-like displacement with higher flood
efficiencies. An additional important advantage of miscible gasflooding is that the gas dissolves in the oil, and this process reduces the oil viscosity, giving it higher mobilities and easier recovery. A WAG flood is shown in Figure 3.14.
3.5 Infill Recovery
Towards the end of the reservoir life (after primary, secondary and enhanced oil recovery), the only thing that can be done to improve the production rate is to carry out infill drilling, directly accessing oil that may have been left unproduced by all the previous natural and artificial drive mechanisms. Infill drilling can involve very significant drilling costs, while the resulting additional production may not be great.
Chapter 4: Coring, Preservation and Handling
4.1 Introduction
Large financial resources are invested in RCAL and SCAL core analysis programmes, and a wide range of accurate experimental determinations can be carried out. However, cores are expensive to obtain and represent a very dilute sampling of the reservoir rock. It is clear that the samples used in such studies should be as representative as possible of the reservoir rock at depth if the final data is to be credible, and an efficient use of the financial resources devoted to them. Samples of the reservoir rock and the fluids they contain can be, and are commonly, altered by the process of obtaining them (coring, recovery, wellsite handling, shipment, storage, and preparation for experimentation). This chapter gives an overview of the alteration processes that may be at work, together with some of the techniques available to reduce alteration, and preserve the rock and fluid properties. The choice of core preparation techniques is increasingly being made by using pre-screening information on the preserved core. This approach is highly recommended.
4.2 The Coring Process
Reservoir rock undergoes changes during the coring process and on storage before reaching the laboratory. The changes which occur are shown in Figure 4.1. Some of the changes are reversible whilst others are irreversible but preventable. In most cases it is possible to leave all or part of the core in a usable state. It is essential to use preserved core for certain SCAL tests and for meaningful assessment of routine data.
Drilling of the core is invariably carried out at very high bottom hole pressure differentials, thus the core is effectively water-flooded with mud filtrate, and the original contents partly displaced. The outer surface of the core will be invaded by mud particles; the depth of invasion being dependent upon permeability. This zone should be avoided when sampling. The rest of the core will have had its original hydrocarbon content, and formation water displaced by mud filtrate; the extent depending upon the core permeability and original fluid saturations. These changes are not always harmful as the core can usually be restored in the laboratory. More important changes can occur if the rock contains minerals sensitive to water salinity. For example, contact with low salinity water can mobilise poorly adhered clay particles, giving a small possibility that core can arrive in the laboratory with mobilised fines, which are not significantly mobile in the reservoir. In a similar fashion the wetting characteristics of the rock may be altered by surfactant mud additives. These changes are usually unavoidable but if formations are known to be particularly sensitive, it may be possible to modify mud composition and reduce overpressure to minimise damage. For complete preservation of wettability on cores above the transition zone, coring with lease crude is necessary. Water saturation may then also be retained intact, allowing better estimation of initial reservoir oil saturation. For transition and water zone a bland mud formulation will do the least harm to original rock properties.
Drying can be the worst that can happen to core after removal from the barrel. If interface sensitive clays, e.g., fibrous illite are present they can be irreparably damaged by drying (Figure 4.2) and any permeability measurements made on such core will be valueless. Thus it
is necessary to preserve some core in the state that it leaves the barrel either by immersion in simulated formation brine or by wrapping in foil and wax. The latter technique is the minimum required for samples intended for wettability measurements, but for straightforward assessment of water zone permeabilities immersion in brine is adequate. The necessity for preserved core will be more fully covered under relevant sections below.
4.3 Plug Sampling and Cleaning (Unpreserved Core)
Standard techniques are applied unless the core is very heterogeneous or likely to be damaged by routine cleaning methods.
One or one and a half inch diameter sample plugs are drilled and trimmed to between two and three inches long with simulated formation brine as lubricant. If the composition of formation brine is unknown, a five percent sodium chloride brine is used. Plugs are taken at regular intervals (often every 25 cm), parallel to bedding planes for horizontal permeability (see Figure 4.3a). Further plugs normal to the bedding plane are taken if required for vertical permeability. The sampling interval can either, be increased, if the core is from a formation known to be homogeneous; or varied if the core contains thin shaly bands making it difficult to produce intact plugs. Thin shaly bands are avoided unless frequent and representative. Figure 4.3b analyses the suitability of core plugs for homogeneous, thickly bedded and thinly bedded whole core.
Tests may also be carried out on full diameter core samples. This is necessary if plug sized samples do not contain a representative pore size spectrum. Fractures, vugs (very large pores) and stylolytes are typical structural features which necessitate measurement on full diameter (whole core) samples. The measurements made are the same as for plug samples, but a special core holder is necessary if horizontal permeabilities are required.
Plugs are cleaned by alternate extraction with hot toluene and methanol in Soxhlet extractors (Figure 4.4a and 4.4b) until no further discolouration of solvent occurs. This may take from a few, to several hundred hours depending upon permeability. Low permeability plugs are seldom completely free of residual brine and oil at this stage. Complete removal of residual fluids can only be achieved by prolonged Soxhlet extraction. Cores can also be cleaned by
flushing the core with alternate miscible solvents (e.g. toluene (for the oil phase) and methanol (for the water phase)) done hot or cold in a Hassler coreholder (Figure 4.4a; also see section 4.5). Both the aqueous (methanol) and oleic (toluene) cleaning phases exiting the rock can be bulked and submitted for analysis of the amount of water and individual hydrocarbons present.
Plugs are then dried to constant weight in a humidity controlled oven at 60°C, 40% relative humidity. Humidity controlled drying assists in restoring clays to nearer their reservoir state, and may assist in preventing any further damage. However, the Klinkenberg corrected equivalent liquid permeability from this type of drying process may still be larger than the actual brine permeability due to the destruction of the clay texture.
If samples of plugs containing clays that are sensitive to drying are required for SEM analysis (e.g. Figure 4.2), then a sample of the core with the original fluid contents must be critical point dried. Ordinary drying destroys fine clay minerals because the interfacial forces associated with the retreating liquid-vapour interface are high enough to mash the clay structure. Critical point drying involves keeping a small sample of the core at pressure and temperature conditions of the critical point of the fluids. The fluids will then be evaporated from the sample without a liquid-vapour interface, which avoids destroying the fine clay structure. This is an expensive operation because it can take many days to perform on even the smallest sample chip. Consequently, it is almost never carried out for core plugs.
4.4 Core and Plug Preservation (SCAL Techniques)
Preserved core is almost always required for one or more of the following reasons: (i) Wettability determinations.
(ii) Prevention of drying of interface sensitive clays. (iii) Maintenance of fluid saturations as received at surface. (iv) Other SCAL where drying is not desirable.
(v) Unconsolidated or relatively uncompacted samples that exhibit strong porosity and permeability reductions with overburden stress.
Several methods of preservation are currently available and a choice can be made if the requirement for preserved core is specified. The methods are:
Under simulated formation brine or kerosene, for water and oil zone cores respectively.
Cores are either kept under simulated formation brine in polymer containers with an airtight seal at ambient pressure (certain types of spaghetti jars are good for this); see Figure 4.5.
Wax coated, for all SCAL purposes and especially wettability and residual oil saturations. This technique, also called ‘seal-peel’, is widely used, and involves wrapping the
core in layers of plastic and aluminium foil before being dipped in wax. Cores preserved in this way at the well site can be safely stored for moderately long periods and then be used for almost all SCAL purposes (Figure 4.5).
In deoxygenated formation brine or kerosene, for wettability measurements.
Samples are kept in anaerobic jars which can be pressurised to 30 psi (Figure 4.5). The freshly cut core pieces are placed in the jars under deaerated simulated formation brine or kerosene, and the jars are then sealed. The remaining air is then purged with nitrogen, which is then raised to 30 psi pressure. The samples are then preserved under reservoir fluid and a blanket of inert gas. Providing that the pressure is maintained, the samples may be stored in this state for long periods.
Wrapped in cling film and frozen in solid CO2 for fluid
saturation measurements.
core. The samples are cooled using liquid nitrogen and are loaded into special containers. The containers can be transported packed in solid CO2, and stored in special freezers. Plugs can be
cut from the core using liquid nitrogen as the cutting fluid, and the plugs are then immediately loaded into special coreholders again, and stored frozen. The sample is thawed out and tested without being removed from the special coreholders in which they were initially loaded.
4.5 Cleaning and Treatment of Preserved Core
Treatment of preserved core for the tests mentioned above will be reviewed with the appropriate tests; but in general, sample plugs are drilled and trimmed using deoxygenated formation brine and stored under deoxygenated, depolarised kerosene or brine before testing. There are several methods of cleaning core. The actual method used will depend upon the properties of the core. Usually the optimum method will be clear from pre-screening information on the core. Pre-screening measurements include:
• Core description
• Core lithology
• Assessment of consolidation
• SEM analysis of mineralogy and pore structure
• Petrographic analysis of mineralogy and pore structure
• XRD/XRF analysis for bulk and clay mineralogies
This information is designed to identify possible problems with; (i) unconsolidated core, (ii) clay sensitivity, (iii) stress sensitivity, (iv) core mineralogical hetereogeneity, (v) core structural heterogeneity (e.g. fractures, vugs, fossils, and cross-bedding).
The commoner specialist cleaning methods include: (i) Critical point drying
(ii) Cold miscible solvent flushing (iii) Hot miscible solvent flushing
(iv) Direct fluid replacement (oil for oil and brine for brine)
Core cleaning, where appropriate, is most often carried out using miscible solvent flushing techniques. The core if confined in a Hassler holder (Figure 4.4a) and cold solvent flowed through it. Cleaning is usually complete after flowing three 200 ml alternating portions each of methanol and toluene. Under certain circumstances only one portion of each solvent will be used, although it is commoner to use at least three portions of each. This is applied to cores known to contain mobile fines or where it is necessary to retain wettability modifying crude oil components in their existing state. In some circumstances the evolved solvents need to be quantitatively tested using chemical techniques for the water content, and the oil content and composition. In this case special dry methanol is used, and the toluene is replaced with a more efficient solvent such as CS2 (very dangerous) or dichloromethane.
4.6 Unconsolidated Core
Unconsolidated core gives rise to particular problems in coring, storage, handling and plugging. Its extremely friable nature means that any rough handling damages the pore structure irreversibly, and samples can turn into a pile of mud in your hand. The most common method of handling, shipping, storage, and plugging this type of core is in a frozen state. The core is frozen with liquid nitrogen or dry ice as soon as it emerges from the coring barrel. It is then placed in a special core holder for the relevant experiment to be carried out. Thawing inside the coreholder, prior to the experiment is only carried out after the sample has been fully supported with the relevant applied confining pressures (see above).
4.7 Water Analysis
It is possible to obtain the initial water saturation and water composition from preserved whole core and core plugs by extracting the water. This is done by the Dean and Stark method. Figure 4.7 shows the Dean and Stark apparatus. The preserved sample is placed in a paper thimble in the large glass container and fluxed with hot solvent. The water evaporates, is carried by the solvent vapours into the long straight condenser in the top of the apparatus, cools, condenses and is trapped in the graduated part of the apparatus. The water saturation can be calculated by using the volume of the evolved water and a measurement of the porosity of the rock sample after the extraction process. The composition of the evolved fluids can also be analysed chemically, however, the water compositions more commonly used in SCAL applications derive from wireline formation testing.
Chapter 5: Porosity
5.1 Introduction and Definition
Total porosity is defined as the fraction of the bulk rock volume V that is not occupied by solid matter. If the volume of solids is denoted by Vs, and the pore volume as Vp = V - Vs, we
can write the porosity as:
φ
=
V - V
=
=
V
V
V
Pore Volume
Total Bulk Volume
s
p
(5.1)
The porosity can be expressed either as a fraction or as a percentage. Two out of the three terms are required to calculate porosity.
It should be noted that the porosity does not give any information concerning pore sizes, their distribution, and their degree of connectivity. Thus, rocks of the same porosity can have widely different physical properties. An example of this might be a carbonate rock and a sandstone. Each could have a porosity of 0.2, but carbonate pores are often very unconnected resulting in its permeability being much lower than that of the sandstone.
A range of differently defined porosities are recognised and used within the hydrocarbon industry. For rocks these are:
(i) Total porosity Defined above.
(ii) Connected porosity The ratio of the connected pore volume to the total volume. (iii) Effective porosity The same as the connected porosity.
(iv) Primary porosity The porosity of the rock resulting from its original depositional structure.
(v) Secondary porosity The porosity resulting from diagenesis.
(vi) Microporosity The porosity resident in small pores (< 2 µm) commonly associated with detrital and authigenic clays.
(vii) Intergranular porosity The porosity due to pore volume between the rock grains. (viii) Intragranular porosity The porosity due to voids within the rock grains.
(ix) Dissolution porosity The porosity resulting from dissolution of rock grains. (x) Fracture porosity The porosity resulting from fractures in the rock at all scales. (xi) Intercrystal porosity Microporosity existing along intercrystalline boundaries usually
in carbonate rocks.
(xii) Moldic porosity A type of dissolution porosity in carbonate rocks resulting in molds of original grains or fossil remains.
(xiii) Fenestral porosity A holey (‘bird’s-eye’) porosity in carbonate rocks usually associated with algal mats.
(xiv) Vug porosity Porosity associated with vugs, commonly in carbonate rocks. It should be noted that if the bulk volume and dry weight, or the bulk volume, saturated weight and porosity of a rock sample is known, then the grain density can be calculated. This parameter is commonly calculated from the data to compare the results with the known grain
densities of minerals as a QA check. For example the density of quartz is 2.65 g cm-3, and a clean sandstone should have a mean grain density close to this value.
5.2 Controls on Porosity
The initial (pre-diagenesis) porosity is affected by three major microstructural parameters. These are grain size, grain packing, particle shape, and the distribution of grain sizes. However, the initial porosity is rarely that found in real rocks, as these have subsequently been affected by secondary controls on porosity such as compaction and geochemical diagenetic processes. This section briefly reviews these controls.
5.2.1 Grain Size
The equilibrium porosity of a porous material composed of a random packing of spherical grains is dependent upon the stability given to the rock by frictional and cohesive forces operating between individual grains. These forces are proportional to the exposed surface area of the grains. The specific surface area (exposed grain surface area per unit solid volume) is inversely proportional to grain size. This indicates that, when all other factors are equal, a given weight of coarse grains will be stabilised at a lower porosity than the same weight of finer grains. For a sedimentary rock composed of a given single grain size this general rule is borne out in Figure 5.1 (to the left). It can be seen that the increase in porosity only becomes significant at grain sizes lower than 100
µm, and for some recent sediments porosities up to 0.8 have been measured. As grain size increases past 100 µm, the frictional forces decrease and the porosity decreases until a limit is reached that represents random frictionless packing, which occurs at 0.399 porosity, and is independent of grain size. No further loss of porosity is possible for randomly packed spheres, unless the grains undergo irreversible deformation due to dissolution-recrystallisation, fracture, or plastic flow, and all such decreases in porosity are termed compaction.
5.2.2
Grain Packing
The theoretical porosities for various grain packing arrangements can be calculated. The theoretical maximum porosity for a cubic packed rock made of spherical grains of a uniform
size is 0.476, and is independent of grain size. The maximum porosity of other packing arrangements is shown in Table 5.1 and Figure 5.2.
Table 5.1 Maximum porosity for different packing arrangements
Packing Maximum Porosity (fractional)
Random ≥0.399 (dependent on grain size)
Cubic 0.476
Orthorhombic 0.395
Rhombohedral 0.260
Tetragonal 0.302
Figure 5.2 The porosities of standard packing arrangements.
5.2.3
Grain Shape
This parameter is not widely understood. Several studies have been carried out on random packings of non-spherical grains, and in all cases the resulting porosities are larger than those for spheres. Table 5.2 shows data for various shapes, where the porosity is for the frictionless limit. Figure 5.1 shows data comparing rounded and angular grains, again showing that the porosity for more angular grains is larger than those that are sub-spherical.
Table 5.2 The effect of grain shape on porosity
Grain Shape Maximum Porosity (fractional)
Sphere ≥0.399 (dependent on grain size)
Cube 0.425
Cylinder 0.429
5.2.4
Grain Size Distribution
Real rocks contain a distribution of grain sizes, and often the grain size distribution is multi-modal. The best way of understanding the effect is to consider the variable admixture of grains of two sizes (Figure 5.3).
Figure 5.3 The behaviour of mixing grain sizes. Note that a mixture of two sizes has
porosities less than either pure phase.
The porosity of the mixture of grain sizes is reduced below that for 100% of each size. There are two mechanisms at work here. First imagine a rock with two grain sizes, one of which has 1/100th the diameter of the other. The first mechanism applies when there are sufficient of the larger grains to make up the broad skeleton of the rock matrix. Here, the addition of the smaller particles reduces the porosity of the rock because they can fit into the interstices between the larger particles. The second mechanism is valid when the broad skeleton of the rock matrix is composed of the smaller grains. There small grains will have a pore space between them. Clearly, if some volume of these grains are removed and replaced with a single solid larger grain, the porosity will be reduced because both the small grains and their associated porosity have been replaced with solid material. The solid lines GR and RF or RM in Figure 5.3 represent the theoretical curves for both processes. Note that as the disparity between the grain sizes increases from 6:3 to 50:5 the actual porosity approaches the theoretical lines. Note also that the position of the minimum porosity is not sensitive to the grain diameter ratio. This minimum occurs at approximately 20 to 30% of the smaller particle diameter. In real rocks we have a continuous spectrum of grain sizes, and these can give rise to a complex scenario, where fractal concepts become useful.
5.2.5 Secondary Controls on Porosity
Porosity is also controlled by a huge range of secondary processes that result in compaction and dilatation. These can be categorised into (i) mechanical processes, such as stress
