formation evaluation msc course notes paul glover

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Dr. Paul W.J. Glover

MSc PetroleumGeology

Department of Geologyand Petroleum Geology

University of AberdeenUK

Contents

Copyright

Formation Evaluation MSc Course Notes

Dr. Paul Glover Page i

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

Formation Evaluation MSc Course Notes Introduction

Dr. Paul Glover Page 1

Chapter 1: Introduction

1.1 Introduction

This course aims to provide an understanding of the behaviour of fluids in reservoirs, and theuse of core analysis in the evaluation of reservoir potential. It is intended to give the end userof special core analysis data an insight into the experimental techniques used to generate suchdata and an indication of its validity when applied to reservoir assessment. It has been writtenfrom the standpoint of a major oil industry operational support group, and is based upon thesubstantial 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 thereservoir engineer in assessing the economic potential of a hydrocarbon accumulation. Thedata sources can be divided into field and laboratory measurements as shown in Figure 1.1.

Laboratory data are used to supportfield measurements which can besubject to certain limitations, e.g.:

(i) Fluid saturations may beuncertain where actual formationbrine composition and resistivityare not available.

(ii) Permeability derived from welltest data may be reduced bylocalised formation damage(skin effects) and increased byfractures.

Sedimentological data can be used topredict areal and vertical trends inrock properties and as an aid in thecorrect choice of core for laboratorymeasurements.

For core analysis to providemeaningful data, due regard must begiven to the ways in which rockproperties can change both during thecoring procedure (downhole), corepreservation, and subsequentlaboratory treatment.



This report is intended as a guide to the reliability and usefulness of the various RCAL andSCAL techniques generally available, and the ways which these techniques have, and willcontinue to be, refined in the light of current research. Maximum benefit will only beobtained from core analysis by full consultation between the reservoir engineer and thelaboratory 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 fluidproperties, and the rock properties. The fluid properties are of fundamental importance, andwill be studied in the first part of this course.

The natural energy of a reservoir can be used to facilitate the production of hydrocarbon andnon-hydrocarbon fluids from reservoirs. These sources of energy are called natural drivemechanisms. However, there may still be producible oil in a reservoir when natural drivemechanisms are exhausted. There exist artificial drive mechanisms that can then be used toproduce some of the remaining oil. The type of drive currently operating in a reservoir has astrong control on the evaluation and management of the reservoir. Consequently, drivemechanisms 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 watersaturation. Taken in context routine data can provide a useful guide to well and reservoirperformance, provided its limitations are appreciated. These limitations arise because routineporosity and permeability measurements are always made with gases on cleaned, dried core atroom 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 truefor permeability measurements. Routine core analysis data is cheap, and often form the greatmajority of the dataset representing reservoir core data. A schematic diagram of commonRCAL measurements is given as Figure 1.2.

Routine porosity data are generally reliable, being little affected by interactions betweenminerals and reservoir fluids. Correction for overburden loading is usually all that is required.

Routine permeability results can misrepresent the reservoir situation as reservoir fluids ofteninteract with the minerals forming the pore walls. This is frequently the case because theseinteractions cannot be allowed for in routine measurements. Correction can be only made forthe compressibility of gases used. Thus the Klinkenberg correction converts gas permeabilityto ‘equivalent liquid permeability’ (KL) but still assumes no fluid-rock interaction. An actualliquid, brine or oil, usually gives a lower permeability than KL. If interface sensitive clays are



present in the reservoir, drying can destroy them and KL may be one or two orders ofmagnitude 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 thanporosity. 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, testmethods, 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 tosituations more representative of reservoir conditions. SCAL data is used to support log andwell test data in gaining an understanding of individual well and overall reservoirperformance. However, SCAL measurements are more expensive, and are commonly onlydone on a small selected group of samples, or if a difficult strategic reservoir managementdecision has to be made (e.g. to gasflood, or not to gasflood).

Tests are carried out to measure fluid distribution, electrical properties and fluid flowcharacteristics in the two and occasionally three phase situation, and are made on preservedcore. 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 sothat the room condition data can be corrected.

Wettability and capillary pressure data are generated by controlled displacement of a wettingphase by a non wetting phase e.g., brine by air, brine by oil or air by mercury. These systemsusually 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 togive data for predicting saturation at a given height within a reservoir. Electrical properties aremeasured at formation brine saturations of unity and less than unity, to obtain the cementationexponent, resistivity index, and excess conductivity of samples. These are used to providedata 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, andwetting characteristics. Care has to be taken that measurements are made under appropriateconditions, which allow some understanding of the wetting characteristics. The datagenerated allows relative flow rates and recovery efficiency to be assessed.

Each of the SCAL measurements made is discussed in detail in the relevant chapter, coveringthe theory, test methods, and limitations of alternative methods. The topics covered willinclude:



Chapter 4. Preserved core; methods of preservation and requirement forpreserved 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 cementationexponent.

Chapter 10. Relative Permeability; Theory, Techniques available, limitationsand 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 reservoirfluids, which is covered in Chapter 2. Chapter 3 discusses the various reservoir drivesencountered in reservoir management. Chapter 4 discusses coring, core preservation andhandling, which is of relevance mainly to SCAL studies. Chapters 5 and 6 cover RCALporosity and permeability measurements, together with extensions to overburden pressure forSCAL studies. Chapters 7 to 10 cover various wettability, capillary pressure, electrical, andrelative permeability measurements commonly practised in SCAL studies. Chapter 11 brieflyexamines typical SCAL work programmes.

Formation Evaluation MSc Course Notes Reservoir Fluids


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 theircompositions depend upon their source, history, and present thermodynamic conditions. Theirdistribution within a given reservoir depends upon the thermodynamic conditions of thereservoir as well as the petrophysical properties of the rocks and the physical and chemicalproperties of the fluids themselves. This chapter briefly examines these reservoir fluidproperties.

2.2 Fluid Distribution

The distribution of a particular set of reservoir fluids depends not only on the characteristicsof the rock-fluid system now, but also the history of the fluids, and ultimately their source. Alist of factors affecting fluid distribution would be manifold. However, the most importantare:

Depth The difference in the density of the fluids results in their separation over time due togravity (differential buoyancy).

Fluid Composition The composition of the reservoir fluid has an extremely importantcontrol on its pressure-volume-temperature properties, which define the relative volumes ofeach fluid in a reservoir. This subject is a major theme of this chapter. It also affectsdistribution through the wettability of the reservoir rocks (Chapter 7).

Reservoir Temperature Exerts a major control on the relative volumes of each fluid in areservoir.

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 distributionof the fluids in the reservoir.

Trap-Type Clearly, the effectiveness of the hydrocarbon trap also has a control on fluiddistribution (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 notothers through the operation of wettability contrasts and capillary pressure. In addition, thecommon heterogeneity of rock properties results in preferential fluid distributions throughoutthe 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)• Fluid pressure gradients (the major force operating during primary production)



Although each of these forces and factors vary from reservoir to reservoir, and betweenlithologies within a reservoir, certain forces are of seminal importance. For example, it isgravity that ensures, that when all three basic fluids types are present in anuncompartmentalised reservoir, the order of fluids with increasing depth isGAS: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 (formationwaters), which may occur as extensive aquifers underlying or interdigitated with hydrocarbonbearing 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 isNaCl, but many others occur in varying smaller quantities. The specific gravity of pure wateris defined as unity, and the specific gravity of formation waters increases with salinity at a rateof about 0.075 per 100 parts per thousand of dissolved solids. When SCAL measurements aremade with brine, it is usual to make up a simulated formation brine to a recipe such as thatgiven 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 SolventNaCl 34.70

CaCl2.6H2O 4.90MgCl2.6H2O 2.70

KCl 0.40NaHCO3 0.40

SrCl2.6H2O 0.12BaCl2.6H2O 0.06

Final pH = 7

Why a connate water phase is invariably present in hydrocarbon bearing reservoir rock iseasily explained. The reservoir rocks were initially fully or partially saturated with aqueousfluids before the migration of the oil from source rocks below them. The oil migratesupwards from the source rocks, driven by the differential buoyancy of the oil and the water. Inthis process most of the water swaps places with the oil since no fluids can escape from thecap rock above the reservoir. However, the water is not completely displaced as the initialreservoir rock is invariably water-wet, leaving the water-wet grains covered in a thin layer ofwater, 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 capillaryforces.

The aqueous fluids, whether as connate water or in aquifers, commonly contain dissolvedgases at reservoir temperatures and pressures. Different gases dissolve in aqueous fluids todifferent extents, and this gas solubility also varies with temperature and pressure. Table 2.2shows 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 fizzeswhen opened. In reservoirs the dissolved gas is mainly methane (from 10 SCF/STB at 1000psi to 35 SCF/STB at 10 000 psi for gas-water systems, and slightly less for water-oilsystems). 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 bar25oC 55oC

Helium 0.06983 0.07179Argon 0.2516 0.1760Radon 1.675 0.8911

Hydrogen 0.1413 0.1313Nitrogen 0.1173 0.08991Oxygen 0.2298 0.0164

Carbon dioxide 6.111 3.235Methane 0.2507 0.1684Ethane 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 togases (2.5×10-6 to 5×10-6 per psi decreasing with increasing salinity). Consequently, if a unitvolume of formation water with no dissolved gases at reservoir pressure conditions istransported to surface pressure condition, it will expand only slightly compared to the sameinitial volume of oil or gas. It should be noted that formation waters containing a significantproportion 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 intemperature on being brought to the surface causes the formation water to shrink and there isalso a certain shrinkage associated with the release of gas as pressure is lowered. The overallresult is that brines experience a slight shrinkage (< 5%) on being brought from reservoirconditions to the surface.

Formation waters generally have densities that are greater than those of oils, and dynamicviscosities 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 increaseswith increasing salinity.



Table 2.3 Densities and Viscosities for a Typical Formation Water and a Refined Oil

Brine Component Composition, g/l

Pure water SolventNaCl 150.16

CaCl2.6H2O 101.32MgCl2.6H2O 13.97

Na2SO4 0.55NaHCO3 0.21

Fluid Temperature, oC Density, g/cm3 Dynamic Viscosity, cP

Brine 20 1.1250 1.509Brine 25 1.1237 1.347Brine 30 1.1208 1.219

Kerosene 20 0.7957 1.830Kerosene 25 0.7923 1.661Kerosene 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 followingdiscussion that all changes occur isothermally (with no heat flowing either into or out of thefluid) 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 inlarge drops in pressure with small increases in specific volume, due to the smallcompressibility of liquids (liquid hydrocarbons as well as liquid formation waters have smallcompressibilities that are almost independent of pressure for the range of pressuresencountered in hydrocarbon reservoirs). On further expansion, a pressure will be attainedwhere the first tiny bubble of gas appears (point B). This is the bubble point or saturationpressure for a given temperature. Further expansion (B→C) now occurs at constant pressurewith more and more of the liquid turning into the gas phase until no more fluid remains. Theconstant pressure at which this occurs is called the vapour pressure of the fluid at a giventemperature. 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 worthnoting that the process A→B→C→D described above during expansion (reducing thepressure on the piston) is perfectly reversible. If a system is in state D, then application ofpressure to the fluid by applying pressure to the pistons will result in changes following thecurve D→C→B→A.



We can examine the curve in Figure 2.1 for a range of fluid temperatures. If this is done, thepressure-volume relationships obtained can be plotted on a pressure-volume diagram with thebubble point and dew point locus also included (Figure 2.2). Note that the bubble point anddew point curves join together at a point (shown by a dot in Figure 2.2). This is the criticalpoint. The region under the bubble point/dew point envelope is the region where the vapourphase and liquid phase can coexist, and hence have an interface (the surface of a liquid drop orof 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 phaseregion, 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 phaseturning into a liquid phase without any fluid interface being generated (i.e. the vapourbecomes denser and denser until it can be considered as a light liquid). Thus the critical pointcan also be viewed as the point at which the properties of the liquid and the gas becomeindistinguishable (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 theyplot 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 componentsshows slightly different behaviour (Figure 2.4). The initial expansion of the liquid is similar tothat 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 thevaporising mixture. In this case the bubble points and dew points differ, and the resultingpressure-temperature plot is no longer a straight line but a phase envelope composed of thebubble point and dew point curves, which now meet at the critical point (Figure 2.5). Thereare also two other points on this diagram that are of interest. The cricondenbar, which definesthe pressure above which the two phases cannot exist together whatever the temperature, andthe cricondentherm, which defines the temperature above which the two phases cannot existtogether whatever the pressure. A fluid that exists above the bubble point curve is classifiedas undersaturated as it contains no free gas, while a fluid at the bubble point curve or below itis classified as saturated, and contains free gas.

Figure 2.6 shows the PT diagram for a reservoir fluid, together with a production path fromthe 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. Onproduction the fluid pressure drops fast with some temperature reduction occurring as thefluid travels up the borehole. All reservoirs are predominantly isothermal because of theirlarge thermal inertia. This results in the production path of all hydrocarbons initiallyundergoing a fluid pressure reduction. Figure 2.6 shows that the ratio of vapour to liquid atseparator conditions is approximately 55:45. If we analyse the PT characteristics of theseparator 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 theseparator gas PT diagram, and on the bubble point line of the separator oil PT diagram. Thisindicates that the shape of the PT diagram for various mixtures of hydrocarbon gases andliquids varies greatly. Clearly, therefore it is extremely important to understand the PT phaseenvelope 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, afterCronquist, 1979:

• Dry gas• Wet gas• Gas condensate• Volatile oil• Black oil



Each of thesereservoirs can beunderstood interms of its phaseenvelope. Thetypicalcomponents ofproduction fromeach of thesereservoirs is shownin Table 2.4, and aschematic diagramof their PT phaseenvelopes isshown in Figure2.7.

Table 2.4 Typical Mol% Compositions of Fluids Produced from Cronquist ReservoirTypes

Component orProperty

Dry Gas Wet Gas GasCondensate

Volatile Oil Black Oil

CO2 0.10 1.41 2.37 1.82 0.02N2 2.07 0.25 0.31 0.24 0.34C1 86.12 92.46 73.19 57.60 34.62C2 5.91 3.18 7.80 7.35 4.11C3 3.58 1.01 3.55 4.21 1.01iC4 1.72 0.28 0.71 0.74 0.76nC4 - 0.24 1.45 2.07 0.49iC5 0.50 0.13 0.64 0.53 0.43nC5 - 0.08 0.68 0.95 0.21C6s - 0.14 1.09 1.92 1.16C7+ - 0.82 8.21 22.57 56.40

GOR (SCF/STB) ∞ 69000 5965 1465 320OGR(STB/MMSCF)

0 15 165 680 3125

API SpecificGravity, γAPI

,oAPI

- 65.0 48.5 36.7 23.6

C7+ SpecificGravity, γo

- 0.750 0.816 0.864 0.920

Note: Fundamental specific gravity γo is equal to the density of the fluid divided by thedensity of pure water, and that for C7+ is for the bulked C7+ fraction. The API specific gravityγAPI 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 abovethe cricondentherm. During production the fluids are reduced in temperature and pressure.The temperature-pressure path followed during production does not penetrate the phaseenvelope, 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 higherlevel. In practice, the stock tank pressures are usually high enough for some liquids to beproduced (Figure 2.9). Note the lack of C5+ components, and the predominance of methane inthe 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 thecricondentherm. During production the fluids are reduced in temperature and pressure. Thetemperature-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 thepresence of small amounts of C5+ components, and the continuing predominance of methanein the wet gas in Table 2.4. The GOR (gas-oil ratio) has fallen as some liquid is beingproduced. However, this liquid usually amounts to less than about 15 STB/MMSCF. Notealso the small specific gravity for C7+ components (0.750), indicating that the majority of theC7+ fraction is made up of the lighter C7+ hydrocarbons.



2.5.4 Gas Condensate Reservoirs

A typical gas condensate reservoir is shown in Figure 2.10. The reservoir temperature is suchthat it falls between the temperature of the critical point and the cricondentherm. Theproduction path then has a complex history. Initially, the fluids are in an indeterminate vapourphase, and the vapour expands as the pressure and temperature drop. This occurs until thedewpoint line is reached, whereupon increasing amounts of liquids are condensed from thevapour 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, theprocess is called isothermalretrograde condensation.Isobaric retrogradecondensation also exists as ascientific phenomenon, butdoes not occur in thepredominantly isothermalconditions of hydrocarbonreservoirs. Thus, in gascondensate reservoirs, theoil produced at the surfaceresults from a vapourexisting in the reservoir.Note the increase in the C7+

components and thecontinued importance ofmethane in Table 2.4. TheGOR has decreasedsignificantly, the OGR hasincreased, and the specificgravity of the C7+

components is increasing,indicating that greaterfractions of denserhydrocarbons are present inthe C7+ fraction.

2.5.5 Volatile Oil Reservoirs

A typical volatile oil reservoir is shown in Figure 2.11. The reservoir PT conditions place itinside the phase envelope, with a liquid oil phase existing in equilibrium with a vapour phasehaving gas condensate compositions. The production path results in small amounts of furthercondensation, and re-evaporation can occur again, but should be avoided as much as possibleby keeping the stock tank pressure as high as possible. Reference to Table 2.4 shows that thefraction 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 andspecific 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 ismuch lower than the temperature of the critical point of the system, and at pressures above thecricondenbar. Thus, the hydrocarbon in the reservoir exists as a liquid at depth. Theproduction path first involves a reduction in pressure with only small amounts of expansion inthe liquid phase. Once the bubble point line is reached, gas begins to come out of solution andcontinues to do so until the stock tank is reached. The composition of this gas changes verylittle along the production path, is relatively lean, and is not usually of economic importancewhen produced. Table 2.4 shows a produced hydrocarbon fluid that is now dominated byheavy hydrocarbon liquids, with most of the produced gas present as methane. The GOR,OGR and specific gravities mirror the fluid composition.

Formation Evaluation MSc Course Notes Reservoir Drives


Chapter 3: Reservoir Drives

3.1 Introduction

Recovery of hydrocarbons from an oil reservoir is commonly recognised to occur in severalrecovery 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 naturalenergy of the reservoir as a drive.

Secondary recovery This is recovery aided or driven by the injection of water or gas fromthe surface.

Tertiary recovery (EOR) There are a range of techniques broadly labelled ‘Enhanced OilRecovery’ that are applied to reservoirs in order to improve flagging production.

Infill recovery Is carried out when recovery from the previous three phases have beencompleted. It involves drilling cheap production holes between existing boreholes to ensurethat 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 hydrocarbonstowards and out of the production wells. There are several different energy sources, and eachgives rise to a drive mechanism. Early in the history of a reservoir the drive mechanism willnot be known. It is determined by analysis of production data (reservoir pressure and fluidproduction ratios). The earliest possible determination of the drive mechanism is a primarygoal in the early life of the reservoir, as its knowledge can greatly improve the managementand 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 shows the recovery ranges for each individual drive mechanism.



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 driveoccurs when any of the firstthree drives operate together,or when any of the first threedrives operate with the aid ofgravity drainage.

The reservoir pressure andGOR trends for each of themain (first) three drivemechanisms is shown asFigures 3.1 and 3.2. Noteparticularly that water drivemaintains the reservoirpressure much higher than thegas drives, and has a uniformlylow GOR.

3.2.1 Solution Gas Drive

This drive mechanism requiresthe reservoir rock to becompletely surrounded byimpermeable barriers. Asproduction occurs the reservoirpressure drops, and theexsolution and expansion ofthe dissolved gases in the oiland water provide most of thereservoirs drive energy. Smallamounts of additional energyare also derived from theexpansion of the rock andwater, 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 saturateddepending 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 thebubblepoint. In this regime reservoir drive energy is provided only by the bulk expansion ofthe reservoir rock and liquids (water and oil).

For a saturated reservoir,any oil production results ina drop in reservoir pressurethat causes bubbles of gasto exsolve and expand.When the gas comes out ofsolution the oil (and water)shrink slightly. However,the volume of the exsolvedgas, and its subsequentexpansion more than makesup for this. Thus gasexpansion is the primaryreservoir drive forreservoirs below the bubblepoint.Solution gas drivereservoirs show a particularcharacteristic pressure,GOR and fluid productionhistory. If the reservoir isinitially undersaturated, thereservoir pressure can dropby a great deal (severalhundred psi over a fewmonths), see Figures 3.1and 3.2.

This is because of the smallcompressibilities of therock water and oil,compared to that of gas. In

this undersaturated phase, gas is only exsolved from the fluids in the well bore, andconsequently the GOR is low and constant. When the reservoir reaches the bubble pointpressure, the pressure declines less quickly due to the formation of gas bubbles in the reservoirthat expand taking up the volume exited by produced oil and hence protecting against pressuredrops. 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 againwhen reservoir pressures are such that the gas expands less in the borehole. When the GORinitially 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 inplace (i.e. low). Of this only 0% to 5% of oil is recovered above the bubblepoint. There isusually no production of water during oil recovery unless the reservoir pressure dropssufficiently for the connate water to expand sufficiently to be mobile. Even in this scenariolittle water is produced.

3.2.2 Gas Cap Drive

A gas cap drive reservoir usually benefits to some extent from solution gas drive, but derivesits main source of reservoir energy from the expansion of the gas cap already existing abovethe reservoir.

The presence of theexpanding gas cap limits thepressure decrease experiencedby the reservoir duringproduction. The actual rate ofpressure decrease is related tothe size of the gas cap.

The GOR rises only slowly inthe early stages of productionfrom such a reservoir becausethe pressure of the gas capprevents gas from coming outof solution in the oil andwater. As productioncontinues, the gas capexpands pushing the gas-oilcontact (GOC) downwards(Figure 3.4). Eventually theGOC will reach theproduction wells and theGOR will increase by largeamounts (Figures 3.1 and3.2). The slower reduction inpressure experienced by gascap reservoirs compared tosolution drive reservoirsresults in the oil productionrates being much higherthroughout the life of thereservoir, and needingartificial lift much later thanfor 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 ofhow much latent energy there is available to drive production, and how the reservoir ismanaged, i.e. how the energy resource is used bearing in mind the geometric characteristics ofthe reservoir, economics and equity considerations. Points of importance to bear in mindwhen 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 theoil-water contact (OWC). As production continues, and oil is extracted from the reservoir, theaquifer expands into the reservoir displacing the oil. Clearly, for most reservoirs, solution gasdrive will also be taking place, and there may also be a gas cap contributing to the primaryrecovery. 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 thereservoir 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 waterin the same timescale, especially if the aquifer is small or low permeability. In this case thereservoir pressure will fall (Figure 3.1).

The GOR remains very constant in a strongly water driven reservoir (Figure 3.2), as thepressure decrease is small and constant, whereas if the pressure decrease is higher (weaklywater driven reservoir) the GOR increases due to gas exsolving from the oil and water in thereservoir. Likewise the oil production from a strongly water driven reservoir remains fairlyconstant until water breakthrough occurs.



Using analogous arguments tothe gas cap drive, it can be seenthat thick oil columns are againan advantage, but the wells areperforated high in the oil zoneto delay the waterbreakthrough. When waterbreakthrough does occur thewell can either be shut-down,or assisted using gas lift.Reinjection of water into theaquifer is seldom done becausethe injected water usually justdisappears into the aquifer withno effect on aquifer pressure.

The recovery from waterdriven reservoirs is usuallygood (20-60% OOIP, Table3.1), although the exact figuredepends on the strength of theaquifer and the efficiency withwhich the water displaces theoil in the reservoir, whichdepends on reservoir structure,production well placing, oilviscosity, and production rate.If the ratio of water to oilviscosity is large, or theproduction rate is high thenfingering can occur whichleaves oil behind in thereservoir (Figure 3.6).



3.2.4 Gravity Drainage

The density differences between oil and gas and water result in their natural segregation in thereservoir. This process can be used as a drive mechanism, but is relatively weak, and inpractice is only used in combination with other drive mechanisms. Figure 3.7 showsproduction 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 otherdrive mechanisms examined so far. However, it is extremely efficient over long periods andcan give rise to extremely high recoveries (50-70% OOIP, Table 3.1). Consequently, it isoften 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 mechanismscan be diametrically opposed(e.g. low perforation for gascap reservoirs compared withhigh perforation for waterdrive reservoirs). If bothoccur as in Figure 3.8, acompromise must be sought,and this compromise musttake into account the strengthof each drive present, thesize of the gas cap, and thesize/permeability of theaquifer. It is the job of thereservoir manager to identifythe strengths of the drives asearly as possible in the life ofthe reservoir to optimise thereservoir performance.

3.3 Secondary Recovery

Secondary recovery is the result of human intervention in the reservoir to improve recoverywhen the natural drives have diminished to unreasonably low efficiencies. Two techniquesare 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 designare beyond the scope of these notes. However, it should be noted that the successful outcomeof a waterflood process depends on designs based on accurate relative permeability data inboth horizontal directions, on the choice of a good injector/producer array, and with fullaccount 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 pressureeven if oil displacement is not required. Again accurate relperms are needed in the design, aswell as injector/producer array geometry and crustal stresses. There is an additionalcomplication in that re-injected lean gas may strip light hydrocarbons from the liquid oilphase. At first sight this may not seem a problem, as recombination in the stock tank orafterwards may be carried out. However, equity agreements often give different percentagesof 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 inplace. Clearly it is extremely important to increase this figure. Many enhanced oil recoverymethods have been designed to do this, and a few will be reviewed here. They fall into threebroad categories; (i) thermal, (ii) chemical, and (iii) miscible gas. All are extremelyexpensive, are only used when economical, and are implemented after extensive SCALstudies have isolated the reservoir rock characteristics that are causing oil to remainunproduced by conventional methods.

3.4.1 Thermal EOR

These processes use heat to improve oil recovery by reducing the viscosity of heavy oils andvaporising 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 gashas large environmental implications for these methods. However, thermal EOR is probablythe 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 theflood 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)

An example of chemical EOR is shown in Figure 3.12.



Chemical flood additives, especially surfactants designed to reduce surface or interfacialtension, are extremely expensive. Thus the whole chemical EOR flood is designed tominimise the amount of surfactants needed, and to ensure that the EOR process iseconomically successful as well as technically. Chemical flooding is therefore not a simplesingle stage process. Initially the reservoir is subjected to a preflush of chemicals designed toimprove 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 intothe 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, isinjected. Figure 3.13 shows a typical flood sequence. Note that the mobilised oil bank movesahead of the surfactant flood, and how the total process has reduced the amount of thesurfactant 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 interfacialtension with the oil and can in principal flush out all of the oil remaining in place. In practicea gas is used since gases have high mobilities and can easily enter all the pores in the rockproviding the gas is miscible in the oil. Three types of gas are commonly used:

(i) CO2

(ii) N2

(iii) Hydrocarbon gases.



All of these are relatively cheap to obtain either from the atmosphere or from evolvedreservoir gases. The high mobility of gases can cause a problem in the reservoir floodingprocess, since gas breakthrough may be early due to fingering, leading to low sweepefficiencies. Effort is then concentrated on trying to improve the sweep efficiency. One suchapproach is called a miscible WAG (water alternating gas). In this approach water slugs andCO2 slugs are alternately injected into the reservoir; the idea being that the water slugs willlower the mobility of the CO2 and lead to a more piston-like displacement with higher floodefficiencies. An additional important advantage of miscible gasflooding is that the gasdissolves in the oil, and this process reduces the oil viscosity, giving it higher mobilities andeasier 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), theonly 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 andartificial drive mechanisms. Infill drilling can involve very significant drilling costs, while theresulting additional production may not be great.

Formation Evaluation MSc Course Notes Coring, Preservation and Handling


Chapter 4: Coring, Preservation and Handling

4.1 Introduction

Large financial resources are invested in RCAL and SCAL core analysis programmes, and awide range of accurate experimental determinations can be carried out. However, cores areexpensive to obtain and represent a very dilute sampling of the reservoir rock. It is clear thatthe samples used in such studies should be as representative as possible of the reservoir rockat depth if the final data is to be credible, and an efficient use of the financial resourcesdevoted to them. Samples of the reservoir rock and the fluids they contain can be, and arecommonly, altered by the process of obtaining them (coring, recovery, wellsite handling,shipment, storage, and preparation for experimentation). This chapter gives an overview of thealteration processes that may be at work, together with some of the techniques available toreduce alteration, and preserve the rock and fluid properties. The choice of core preparationtechniques is increasingly being made by using pre-screening information on the preservedcore. This approach is highly recommended.

4.2 The Coring Process

Reservoir rock undergoes changes during the coring process and on storage before reachingthe laboratory. The changes which occur are shown in Figure 4.1. Some of the changes arereversible whilst others are irreversible but preventable. In most cases it is possible to leaveall or part of the core in a usable state. It is essential to use preserved core for certain SCALtests 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 partlydisplaced. The outer surface of the core will be invaded by mud particles; the depth ofinvasion 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 waterdisplaced by mud filtrate; the extent depending upon the core permeability and original fluidsaturations. These changes are not always harmful as the core can usually be restored in thelaboratory. More important changes can occur if the rock contains minerals sensitive to watersalinity. For example, contact with low salinity water can mobilise poorly adhered clayparticles, 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 wettingcharacteristics of the rock may be altered by surfactant mud additives. These changes areusually unavoidable but if formations are known to be particularly sensitive, it may bepossible to modify mud composition and reduce overpressure to minimise damage. Forcomplete preservation of wettability on cores above the transition zone, coring with leasecrude is necessary. Water saturation may then also be retained intact, allowing betterestimation of initial reservoir oil saturation. For transition and water zone a bland mudformulation 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 interfacesensitive 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 insimulated formation brine or by wrapping in foil and wax. The latter technique is theminimum required for samples intended for wettability measurements, but for straightforwardassessment of water zone permeabilities immersion in brine is adequate. The necessity forpreserved 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 damagedby routine cleaning methods.

One or one and a half inch diametersample plugs are drilled andtrimmed to between two and threeinches long with simulatedformation brine as lubricant. If thecomposition of formation brine isunknown, a five percent sodiumchloride brine is used. Plugs aretaken at regular intervals (oftenevery 25 cm), parallel to beddingplanes for horizontal permeability(see Figure 4.3a). Further plugsnormal to the bedding plane aretaken if required for verticalpermeability. The samplinginterval can either, be increased, ifthe core is from a formation knownto be homogeneous; or varied if thecore contains thin shaly bandsmaking it difficult to produce intactplugs. Thin shaly bands areavoided unless frequent andrepresentative. Figure 4.3b analysesthe suitability of core plugs forhomogeneous, thickly bedded andthinly bedded whole core.

Tests may also be carried out on full diameter core samples. This is necessary if plug sizedsamples 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 aspecial 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 afew, to several hundred hours depending upon permeability. Low permeability plugs areseldom completely free of residual brine and oil at this stage. Complete removal of residualfluids 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) andmethanol (for the water phase)) done hot or cold in a Hassler coreholder (Figure 4.4a; also seesection 4.5). Both the aqueous (methanol) and oleic (toluene) cleaning phases exiting the rockcan be bulked and submitted for analysis of the amount of water and individual hydrocarbonspresent.



Plugs are then dried to constant weight in a humidity controlled oven at 60°C, 40% relativehumidity. Humidity controlled drying assists in restoring clays to nearer their reservoir state,and may assist in preventing any further damage. However, the Klinkenberg correctedequivalent liquid permeability from this type of drying process may still be larger than theactual 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 criticalpoint dried. Ordinary drying destroys fine clay minerals because the interfacial forcesassociated with the retreating liquid-vapour interface are high enough to mash the claystructure. Critical point drying involves keeping a small sample of the core at pressure andtemperature conditions of the critical point of the fluids. The fluids will then be evaporatedfrom the sample without a liquid-vapour interface, which avoids destroying the fine claystructure. This is an expensive operation because it can take many days to perform on even thesmallest 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 therequirement 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 airtightseal 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 oilsaturations. This technique, also called ‘seal-peel’, is widely used, and involves wrapping thecore in layers of plastic and aluminium foil before being dipped in wax. Cores preserved inthis way at the well site can be safely stored for moderately long periods and then be used foralmost all SCAL purposes (Figure 4.5).

In deoxygenated formationbrine or kerosene, forwettability measurements.Samples are kept in anaerobicjars which can be pressurisedto 30 psi (Figure 4.5). Thefreshly cut core pieces areplaced in the jars underdeaerated simulated formationbrine or kerosene, and the jarsare then sealed. The remainingair is then purged withnitrogen, which is then raisedto 30 psi pressure. The samplesare then preserved underreservoir fluid and a blanket ofinert gas. Providing that thepressure is maintained, thesamples may be stored in thisstate for long periods.

Wrapped in cling film andfrozen in solid CO2 for fluidsaturation measurements.This is used for unconsolidated



core. The samples are cooled using liquid nitrogen and are loaded into special containers. Thecontainers can be transported packed in solid CO2, and stored in special freezers. Plugs can becut from the core using liquid nitrogen as the cutting fluid, and the plugs are then immediatelyloaded into special coreholders again, and stored frozen. The sample is thawed out and testedwithout 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 theappropriate tests; but in general, sample plugs are drilled and trimmed using deoxygenatedformation 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 theproperties of the core. Usually the optimum method will be clear from pre-screeninginformation 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• CT scanning to assess core heterogeneities, Figure 4.6 (cross-bedding, and fractures)



This information is designed to identify possible problems with; (i) unconsolidated core, (ii)clay sensitivity, (iii) stress sensitivity, (iv) core mineralogical hetereogeneity, (v) corestructural 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 flushingtechniques. The core if confined in a Hassler holder (Figure 4.4a) and cold solvent flowedthrough it. Cleaning is usually complete after flowing three 200 ml alternating portions eachof methanol and toluene. Under certain circumstances only one portion of each solvent willbe used, although it is commoner to use at least three portions of each. This is applied tocores known to contain mobile fines or where it is necessary to retain wettability modifyingcrude oil components in their existing state. In some circumstances the evolved solvents needto be quantitatively tested using chemical techniques for the water content, and the oil contentand composition. In this case special dry methanol is used, and the toluene is replaced with amore efficient solvent such as CS2 (very dangerous) or dichloromethane.

4.6 Unconsolidated Core

Unconsolidated core gives rise to particular problems in coring, storage, handling andplugging. Its extremely friable nature means that any rough handling damages the porestructure irreversibly, and samples can turn into a pile of mud in your hand. The mostcommon method of handling, shipping, storage, and plugging this type of core is in a frozenstate. The core is frozen with liquid nitrogen or dry ice as soon as it emerges from the coringbarrel. 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 hasbeen 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 preservedwhole core and core plugs by extracting the water. This is done by the Dean and Starkmethod. Figure 4.7 shows the Dean and Stark apparatus. The preserved sample is placed in apaper 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 saturationcan be calculated by using the volume of the evolved water and a measurement of the porosityof the rock sample after the extraction process. The composition of the evolved fluids can alsobe analysed chemically, however, the water compositions more commonly used in SCALapplications derive from wireline formation testing.

Formation Evaluation MSc Course Notes Porosity


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 bysolid matter. If the volume of solids is denoted by Vs, and the pore volume as Vp = V - Vs, wecan write the porosity as:

φ = = =V - V

V

V

V

Pore Volume

Total Bulk Volumes p

(5.1)

The porosity can be expressed either as a fraction or as a percentage. Two out of the threeterms are required to calculate porosity.

It should be noted that the porosity does not give any information concerning pore sizes, theirdistribution, and their degree of connectivity. Thus, rocks of the same porosity can havewidely different physical properties. An example of this might be a carbonate rock and asandstone. Each could have a porosity of 0.2, but carbonate pores are often very unconnectedresulting in its permeability being much lower than that of the sandstone.

A range of differently defined porosities are recognised and used within the hydrocarbonindustry. 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, saturatedweight and porosity of a rock sample is known, then the grain density can be calculated. Thisparameter 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 aclean 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 beenaffected by secondary controls on porosity such as compaction and geochemical diageneticprocesses. This section briefly reviews these controls.

5.2.1 Grain Size

The equilibrium porosity of aporous material composed of arandom packing of sphericalgrains is dependent upon thestability given to the rock byfrictional and cohesive forcesoperating between individualgrains. These forces areproportional to the exposedsurface area of the grains. Thespecific surface area (exposedgrain surface area per unit solidvolume) is inversely proportionalto grain size. This indicates that,when all other factors are equal, agiven weight of coarse grains willbe stabilised at a lower porositythan the same weight of finergrains. For a sedimentary rockcomposed of a given single grainsize this general rule is borne outin Figure 5.1 (to the left). It can

be seen that the increase in porosity only becomes significant at grain sizes lower than 100µm, and for some recent sediments porosities up to 0.8 have been measured. As grain sizeincreases past 100 µm, the frictional forces decrease and the porosity decreases until a limit isreached that represents random frictionless packing, which occurs at 0.399 porosity, and isindependent 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. Thetheoretical 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 packingarrangements 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 0.476Orthorhombic 0.395Rhombohedral 0.260Tetragonal 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 randompackings of non-spherical grains, and in all cases the resulting porosities are larger than thosefor spheres. Table 5.2 shows data for various shapes, where the porosity is for the frictionlesslimit. Figure 5.1 shows data comparing rounded and angular grains, again showing that theporosity 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 0.425Cylinder 0.429Disk 0.453



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 ofgrains of two sizes (Figure 5.3).

Figure 5.3 The behaviour of mixing grain sizes. Note that a mixture of two sizes hasporosities less than either pure phase.

The porosity of the mixture of grain sizes is reduced below that for 100% of each size. Thereare two mechanisms at work here. First imagine a rock with two grain sizes, one of which has1/100th the diameter of the other. The first mechanism applies when there are sufficient of thelarger grains to make up the broad skeleton of the rock matrix. Here, the addition of thesmaller particles reduces the porosity of the rock because they can fit into the intersticesbetween the larger particles. The second mechanism is valid when the broad skeleton of therock matrix is composed of the smaller grains. There small grains will have a pore spacebetween them. Clearly, if some volume of these grains are removed and replaced with a singlesolid larger grain, the porosity will be reduced because both the small grains and theirassociated porosity have been replaced with solid material. The solid lines GR and RF or RMin Figure 5.3 represent the theoretical curves for both processes. Note that as the disparitybetween the grain sizes increases from 6:3 to 50:5 the actual porosity approaches thetheoretical lines. Note also that the position of the minimum porosity is not sensitive to thegrain diameter ratio. This minimum occurs at approximately 20 to 30% of the smaller particlediameter. In real rocks we have a continuous spectrum of grain sizes, and these can give riseto 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 compactionand dilatation. These can be categorised into (i) mechanical processes, such as stress



compaction, plastic deformation, brittle deformation, fracture evolution etc., and (ii)geochemical processes, such as dissolution, repreciptation, volume reductions concomitantupon mineralogical changes etc. The effect of stress mediated compaction on porosity will bediscussed in section 5.4. The effect of chemical diagenesis is more complex, and is betterassessed for any given rock by examination of SEM or optical photomicrographs.

5.3 Laboratory Determinations

There are many methods for measuring porosity, a few of which will be discussed below.Several standard techniques are used. In themselves these are basic physical measurements ofweight, length, and pressures. The precision with which these can be made on plugs isaffected by the nature (particularly surface texture) of the plugs.

5.3.1 Direct Measurement

Here the two volumes V and Vs are determined directly and used in Eq. (1). This methodmeasures the total porosity, but is rarely used on rocks because Vs can only be measured ifthe rock is totally disaggregated, and cannot, therefore, be used in any further petrophysicalstudies. This measurement is the closest laboratory measurement to density log derivedporosities.

5.3.2 Imbibition Method

The rock sample is immersed in a wetting fluid until it is fully saturated. The sample isweighed before and after the imbibition, and if the density of the fluid ρ is known, then thedifference in weight is ρ Vp , and the pore volume Vp can be calculated. The bulk volume Vis measured using either vernier callipers and assuming that the sample is perfectly cylindrical,or by Archimedes Method (discussed later), or by fluid displacement using the saturatedsample. Vp and V can then be used to calculate the connected porosity. This is an accuratemethod, that leaves the sample fully saturated and ready for further petrophysical tests. Thetime required for saturation depends upon the rock permeability.

5.3.3 Mercury Injection

The rock is evacuated, and then immersed in mercury. At laboratory pressures mercury willnot enter the pores of most rocks. The displacement of the mercury can therefore be used tocalculate the bulk volume of the rock. The pressure on the mercury is then raised in a stepwisefashion, forcing the mercury into the pores of the rock (Figure 5.4). If the pressure issufficiently high, the mercury will invade all the pores. A measurement of the amount ofmercury lost into the rock provides the pore volume directly. The porosity can then becalculated from the bulk volume and the pore volume. Clearly this method also measures theconnected porosity. In practice there is always a small pore volume that is not accessed by themercury even at the highest pressures. This is pore volume that is in the form of the minutestpores. So the mercury injection method will give a lower porosity than the two methodsdescribed above. This is a moderately accurate method that has the advantage that it can bedone on small irregular samples of rock, and the disadvantage that the sample must bedisposed of safely after the test.



The mercury method also has the advantage that the grain size and pore throat sizedistribution of the rock can be calculated from the mercury intrusion pressure and mercuryintrusion volume data. This will be discussed at further length in the section on capillarypressure.



5.3.4 Gas Expansion

This method relies on the ideal gas law, or rather Boyle’s law. The rock is sealed in acontainer of known volume V1 at atmospheric pressure P1 (Figure 5.5). This container isattached by a valve to another container of known volume, V2, containing gas at a knownpressure, P2. When the valve that connects the two volumes is opened slowly so that thesystem remains isothermal, the gas pressure in the two volume equalises to P3. The value ofthe equilibrium pressure can be used to calculate the volume of grains in the rock Vs.. Boyle’sLaw states that the pressure times the volume for a system is constant. Thus we ca write thePV for the system before the valve is opened (left hand side of Eq. (5.2)) and set it equal to thePV for the equilibrated system (right hand side of Eq. (5.2)):

( ) ( )P V V P V P V V V1 1 s 2 2 3 1 2 s− + = + − (5.2)

The grain volume can be calculated:

( )( )

V =P V P V P V V

P Ps1 1 2 2 3 1 2

1 2

+ − −−

(5.3)

In practice P1, P2 and P3 aremeasured, with V1 and V2known in advance bycalibrating the system withmetal pellets of known volume.

The bulk volume of the rock isdetermined before theexperiment by using eithervernier callipers and assumingthat the sample is perfectlycylindrical, or after theexperiment and subsequentsaturation by ArchimedesMethod (discussed later), or byfluid displacement using thesaturated sample. The bulkvolume and grain volume canthen be used to calculate theconnected porosity of the rock.

Any gas can be used, but thecommonest is helium. Thesmall size of the heliummolecule means that it canpenetrate even the smallestpores. Consequently this



method gives higher porosities than either the imbibition or mercury injection methods. Themethod itself is very accurate, insensitive to mineralogy, and leaves the sample available forfurther petrophysical tests. It is also a rapid technique and can be used on irregularly shapedsamples. Inaccuracies can arise with samples with very low. Low permeability samples canrequire long equilibration times in the helium porosimeter to allow diffusion of helium intothe narrow pore structures. Failure to allow adequate time will result in excessively high grainvolumes and low porosities.

5.3.5 Density Methods

If the rock is monomineralic, and the density of the mineral it is composed of is known, thenthe pore volume and porosity can be calculated directly from the mineral density and the dryweight of the sample. This method gives the total porosity of the rock, but is of no practicaluse in petrophysics.

5.3.6 Petrographic Methods

This method is used to calculate the two dimensional porosity of a sample, either by pointcounting under an optical microscope or SEM, or image analysis of the images produced fromthese microscopes. Commonly a high contrast medium is injected into the pores to improvethe contract between pores and solid grains. This method can provide the total porosity, but iswildly inaccurate in all rocks except those that have an extremely isotropic pore structure.However, it has the advantage that pore types and the microtextural properties of the rock canbe determined during the process.

5.3.7 Other Techniques

Other techniques include porosity by (i) analysing all evolved fluids (gas+water+oil) andassuming that their volume is equal to that of the pore space, (ii) CT scanning, and (iii) NMRtechniques.

5.3.8 Bulk Volume Measurement

Most of the methods reviewed above require the knowledge of the bulk volume of the rocksample. Three ways are commonly used. These are (i) by using callipers, (ii) using fluiddisplacement, and (iii) using Archimedes’ method.

Vernier Callipers If the rock is a perfect right cylinder with smooth surfaces, then callipermeasurements of length and diameter can give quite an accurate bulk volume. In this caseseveral measurements (approx. 10) are made of the length and the diameter, and the arithmeticmean of each is used. Repeatability and accuracy then depend mainly upon surface texture ofthe sample. Repeat helium expansion determinations of porosity on samples with smoothsurface textures where the calliper bulk volume is used should fall within ±0.3 porositypercent regardless of actual porosity. Inaccuracies can arise with samples with very highpermeability. High permeability sandstone samples are frequently friable, have large grain andpore sizes, and do not produce smooth surfaced right cylinders when plugs are drilled andaccurate bulk volume determination becomes difficult. Straightforward measurement with



vernier callipers is not possible and Archimedes method or other liquid displacement methodshave to be used.

Fluid Displacement This method notes the displacement of fluid on a graduated scale whenthe rock sample is placed in a container containing the fluid. If the fluid automatically entersthe pores errors will result. The method is commonly carried out with a non-wetting fluid suchas mercury, or with other fluids with a sample that has already been saturated. Mercurydisplacement is carried out in a pyknometer fitted with a calibrated pump (Kobe method -Figure 5.4). The sample is immersed in mercury during this test and will give erroneousresults where mercury enters samples with very large pores. There is also a tendency to givehigh bulk volumes if air is trapped where the sample touches the top of the chamber. TheKobe method is used as the first part of the mercury injection method (Section 5.3.3).

Archimedes Method The sample is weighed dry, fully saturated with formation brine whosedensity is accurately known. The saturated sample is then weighed suspended under a balancein air, and again while suspended in the fluid in which it is saturated. The various weightreadings, and the density of the fluid allow the bulk volume of any irregular sample to befound accurately. The difference in the weight between the saturated sample suspended in airand that when suspended in the fluid is equal to Vsρf, where ρf is the density of the fluid.There are few sources of significant error in this method, provided no fluid drains from theplug whilst it is weighed in air. The most difficult part is judging how much excess fluid toremove from the surface of the plug. Vuggy limestones present particular problems whichmay only be overcome by whole core measurements. The contents of vugs exposed on theplug surface may have been disturbed during drilling. Internal vugs may be partially filledwith solids from the drilling fluid during the coring process. If exposed vugs are genuinelypart of the pore volume, then bulk volume must be obtained by calipering since these will notbe taken account of by liquid immersion techniques.



It should be noted that these are all laboratory methods. Well logging utilises several otherdifferent techniques, which all have larger errors associated with them. These are based onacoustic, electromagnetic, NMR, and radioactive processes.

5.4 Influence of Stress

SCAL porosity measurements have to be done at overburden pressure if they are to becorrelated with downhole measurements. These measurements are made using the overburdencell (Figure 5.6) attached to a helium expansion porosimeter. Pore volume changes can alsobe observed whilst measuring formation factor at overburden pressures. It is not possible torepeat determinations without allowing time for stresses in the core to be relieved. It isconceivable that permanent damage could result when applying overburden to poorlycemented cores, thus if a plug has to be used for a number of tests, overburden measurementsshould form the later stages of the test sequence. As with routine poroperms, whole coremeasurements may be necessary if samples are vuggy, fractured or contain stylolytes. Theprecision of the data obtained is similar to that of routine poroperms. Care has to be takenthat samples are given sufficient time to allow compaction to occur at each overburdenpressure. The resulting porosity data is usually displayed as a fraction of that at ambientpressure as function of overburden pressure (Figure 5.7), or as pore volume compressibility(pore volume/pore volume/psi), as shown in Figure 5.8.

Formation Evaluation MSc Course Notes Single Phase Permeability


Chapter 6: Single Phase Permeability


Permeability is a property of a porous medium that characterises the ease which fluids flowthough it in response to an applied fluid pressure gradient.

The primary objective for permeability measurements applied to the hydrocarbon industry isthat they should be fit for purpose. In this case the purpose is to provide data that can be usedin accurate and effective reservoir modelling. If the reservoir model is to be used to help theunderstanding of a dry gas reservoir at ambient conditions, then horizontal air permeabilitymeasurements at ambient conditions will be fine. However, the reservoirs that are of interestare rarely so simple, and it should be our aim to build multi-phase models capable ofmodelling oil reservoirs at in situ conditions. Fluid permeabilities measured at or corrected torelevant reservoir conditions using relevant fluids are essential inputs if such models are to berepresentative of the reservoir. The fluid saturation and number of mobile fluids have a greateffect on permeability, reducing it below that for a dry rock containing a single fluid. Thissection will deal with single phase fluid permeabilities. In particular the gas and Klinkenbergpermeability measurements that are made as part of RCAL, and the single phase liquidpermeabilities that are part of the more complex relative permeability SCAL tests, but whichare sometimes carried out on their own as part of RCAL.

6.1.1 Basic Definitions

Feynmann once said that, for a scientific measurement to be successful, the scientist orengineer must know exactly what he or she is measuring. This comment has manyimplications for the scientist. For the reservoir engineer/petrophysicist it requires that themeaning of permeability is understood. So back to basics; permeability characterises the easewith which fluids flows through a medium in response to a fluid pressure gradient. However,permeability is not measured directly, but calculated from other physical measurements withvarious theoretical and empirical relationships. The dependence on these relationships has theimplication that the resulting permeabilities are dependent on various assumptions andboundary conditions. The relationship used in the hydrocarbon industry is the empiricallyderived Darcy’s Law in 1856, derived using the apparatus shown in Figure 6.1.

q K Ah

LK A

(P P

Lin out= =

−∆ )(6.1)

where: q = water flow rateA = cross-sectional area of sand packL = length of sand pack∆h = difference between the water heights in the manometers in Figure 6.1 (h1-h2)K = A constant of proportionality characteristic of the sand pack (permeability)Pin-Pout = fluid pressure gradient.



The units of permeability used in the oil industry are the ‘darcy’, D, and the ‘millidarcy’, mD.It is worth noting that the S.I. unit of permeability is in per metres squared (m-2), and showsthat there is an implicit spatial scaling of permeability in the measurement itself. This fact isoften overlooked when we use core measurements made at core plug scale (core volumeapproximately 40 cm3), and then happily (and naively) compare it directly with loggingmeasurements, whose scale volume (volume of sensitivity) is 15000 cm3, and model reservoirwide processes, whose scale volume may be approximately 1015 cm3! A permeability of 1 Dallows the flow of 1 cm3 per second of water with 1 centipoise, cP, viscosity, through a cross-sectional area of 1 cm2, when a pressure gradient of 1 atmosphere pressure per centimetre isapplied. (1 D ~ 10-12 m-2.)

It should be understood that Darcy’s law, Eq. (6.1), was derived for unconsolidated sandpacks, assumes unreactive aqueous fluids with constant properties, and requires correction forthe different viscosity of different fluids, and correction for gas slippage (Klinkenberg effect)



and inertial effects (Forchheimer effect) if used with gaseous fluids. In practice it is applied toall rocks even though it is not clear that this is a valid extrapolation. One should, therefore,always question the accuracy of a core permeability measurement. The law, Eq. (6.1), hasbeen extended for practical use in the following ways:

• Inclusion of a fluid dynamic viscosity so that unreactive fluids other than brines can beused.

• Rewriting the ∆h term in terms of absolute pressures.• Writing the flow rate, q, as volume flow per time (q=V/t).• Inclusion of a constant to take account of the units commonly used in measurement.

Thus the working equation for measuring single phase liquid permeabilities in thehydrocarbon industry is:

( ) ( )K mD

L

A

V

t

1

P P1 2

=−

1000 µ (6.2)

If gas is used we must take account of the compressibility of the gas giving the workingequation for measuring single phase gas permeability in hydrocarbon industry RCAL:

( ) ( )K mD 2000

L

A

V

t

P

P P

atm

12

22

=−

µ (6.3)

where:K = permeability, (millidarcies, mD)µ = viscosity, (centipoise, cP)L = plug length (cm)A = plug cross section (cm2)V = volume of fluid passed in t seconds (cm3)t = time (seconds)q = Flow rate, q=V/t, cm3s-1

P1 = inlet pressure (atmospheres absolute)P2 = outlet pressure (atmospheres absolute)

Patm = atmospheric pressure (atmospheres absolute)

Gas permeability measurements are the most common RCAL permeability measurements.These measurements suffer from two problems that are not encountered with liquidpermeabilities. These are the Klinkenberg and Forchheimer effects.

6.1.2 The Klinkenberg Effect

Darcy’s modified law for gases Eq. (6.3) is not applicable at low gas pressures (gas densities).This is because, at such low pressures, the mean free path of the gas molecules become largerthan the pore dimensions. When this happens, the gas cannot be considered to be a continuousmedium and fluid mechanics cannot be used reliably. In practice the effect causes measuredpermeabilities to be overestimated at low pressures (Figure 6.2a). In the low density (gaspressure) limit the permeability is expressed as:



K K 1Papp L= +

α(6.4)

Here the apparent or measured permeability Kapp is dependent on the so-called Klinkenbergpermeability KL, the gas pressure P and a constant known as the slip factor, α. The standardsolution to the problem involves the following steps:

• Repeating the measurement of gas permeability, Kapp, at four or five different gas inletpressures, P1 and gas outlet pressures, P2.

• Calculating the mean gas pressure in the core for each determination; Pmean = (P1 + P2)/2.• Plotting Kapp against 1/Pm.



The resulting plot is a straight line with a positive gradient (Figure 6.2b). The intersection ofthe curve with the x-axis at 1/Pm = 0 gives KL . The Klinkenberg permeability is independentof gas pressure, and is effectively the permeability of the gas as P→∞, i.e. the permeability fora near perfect liquid (an infinitely compressed near perfect gas). The values of apparentpermeability depend on the type of gas used even though their different viscosities are takeninto account in the calculation of apparent permeability. However, the Klinkenbergpermeability is independent on the type of gas used as all gases have the same properties inthe P→∞ limit (Figure 6.2c). This makes the Klinkenberg permeability very useful, for it canbe compared for different samples that had their gas permeabilities measured with differentgases at different gas pressures. The Klinkenberg permeability should be approximately thesame as the permeability of the rock when 100% saturated with a single phase reservoir liquidsuch as water or oil. The gradient of the Klinkenberg plot gives the slip factor, which can beused to characterise the rock microstructure.

The Klinkenberg correction should be applied to all core analysis measurements without fail.



6.1.3 The Forchheimer Effect

At high gas flow rates (high differential pressures P1-P2), the gas accelerates through porethroats and decelerates in pore bodies sufficiently for the gas inertia to cause turbulence.Darcy’s law is an approximation of Navier-Stokes law, both of which require flow to belaminar. Thus when the flow rate is fast enough for the flow to be turbulent, neither work. Inpractice such high flow rates are avoided in all core analysis measurements. If they areencountered they show up as underestimates in gas permeability measurements that arerecognised as an increase in the gradient of the K versus 1/Pm curve at low values of 1/Pm.

6.1.4 Averaging Permeabilities

It has been shown that the most probable permeability behaviour of a heterogeneous porousmedium made up of n randomly distributed regions of differing uniform permeabilities, K1 toKn, is described by the geometric mean of the individual permeabilities, which corresponds tothe mode of a log-normal distribution:

K K K K Kg 1 2 3 nn= ⋅ ⋅ ⋅ ⋅ ⋅ (6.5)

The analysis is extremely complex. However, it is possible to analyse two simple systems ofdifferent permeabilities that occur within core analysis and reservoir systems. These are (i)flow through linear beds in series, and (ii) flow through linear beds in parallel.

Linear Beds in Series. The system is shown in Figure 6.3a. The beds have a cross-sectionalarea A that is constant. Each bed has a thickness, Ti , and a uniform permeability Ki. Thepressures at the contact between each of the beds, Pi. can be analysed thus:

(P P ) (P P ) (P P ) (P P1 4 1 2 2 3 3 4− = − + − + − ) (6.6)

Now using Eq. (6.1) with ∆h replaced by the pressure difference, and noting that the thicknessof the total unit T is equal to the sum of the individual beds T1 etc., we get:

q T

K A

q T

K A

q T

K A

q T

K A1

1

2

2

3

3= + + (6.7)

Rearranging we find that the mean permeability is the harmonic average of the individualpermeabilities:

{ }K

T

T Kh

i ii 1

n=

=∑

(6.8)

For example analysing Figure 6.3b, where three layers of equal thickness T=1 m havepermeabilities 1000 mD, 200 mD, and 1 mD, we get the mean permeability equals 2.98 mD!



Clearly the permeability is controlled by the smallest permeability because all the fluids thatpass easily through the higher permeability layers are held up by the low permeability layer.

Linear Beds in Parallel. The system is shown in Figure 6.3c. The beds have a thickness Tthat is constant. Each bed has a cross-sectional area to flow, Ai , and a uniform permeability,Ki. The pressures at the inlet P1 and outlet P2 of the complete unit will be the same for alllayers, but each layer will transport a different fraction qi of the total flow rate qt thus:

q q q qt 1 2 3= + + (6.9)

Now using Eq. (6.1), with ∆h replaced by the pressure difference and noting that the total areaA = A1+A2+A3, we get:

( ) ( )

( ) ( )

K A P P

T

K A P P

T

K A P P

T

K A P P

T

in out 1 1 in out

2 2 in out 3 3 in out

−=

−+

−+

−(6.10)

Rearranging we find that the mean permeability is the arithmetic average of the individualpermeabilities:

K

K A

Aa

i ii=1

n

=∑

(6.11)

For example, analysing Figure 6.3d, where three layers of equal area A = 1 m2 havepermeabilities 1000 mD, 200 mD, and 1 mD, we get the mean permeability equals 400 mD!The mean permeability falls much more into the mid range because the fluids partition forflow into each of the layers depending on its permeability. In this case, the layer with thehighest permeability conducts 83.3% of the flow.

For comparison, the geometric mean of equal volumes of 1000 mD, 200 mD, and 1 mD is10.6 mD, which falls between the two extreme cases analysed above, and represents randomarrangement of equal volumes of material with these three permeabilities.

6.1.5 Notes on RCAL Permeabilities

Gas permeabilities corrected for the Klinkenberg effect are commonly used, however thismeasurement provides the most optimistic values of permeability mainly due to themeasurement being done for; (i) single phase gas fluids that are not representative of the truereservoir fluids, (ii) low overburden pressures and temperatures that are not representative ofthe in situ reservoir conditions, and (iii) cleaned dry rocks. Other measurement methodsaccount for these problems, but are more expensive, and often we are asked to useKlinkenberg permeabilities where better measurements are unavailable. It is thereforeimportant for us to understand the factors affecting the determination of permeability



measurements, such that the quality and relevance to the problem of any permeability datasetcan be assessed.

The factors affecting core permeability measurements fall into three broad categories; (i)planning errors, (ii) sample errors, (iii) measurement errors, and (iv) analysis errors. Planningerrors are the fault of the person who commissions the permeability study. It is very temptingto order a standard routine core analysis study. However, resources and time can be saved bythe commissioning manager thinking carefully about the purpose that the data is required for.Klinkenberg permeabilities should not be used to estimate the efficiency of a waterflood, yetsome companies do so by correcting them to effective relative permeabilities using rules ofthumb that do not take account of the fluids and reservoir wettability adequately. Sampleerrors are associated with; (i) sampling frequency, location, orientation, type and size; all ofwhich affect how representative the 40 cm3 sample is of the properties of the 1015 cm3 sizedreservoir, (ii) the type of drilling fluids, and (iii) the state of preservation and the process ofcleaning and drying, which can affect permeability greatly in shaly sandstones. Measurementproblems are related to the accurate measurement of pressure and flow, and are dependentboth on the initial experimental rig design as well as the permeameter operator. Finally,Analysis problems involve the relevant use of the derived data and close the circle to theplanning stage. The indiscriminate lumping together of permeability data from differentmeasurement techniques, bad poroperm cross-plot analysis, and inefficient core-logcorrelation of poroperm data, all contribute to inaccurate analysis, and almost always are theresult of either ignorance of the meaning and limitations of permeability data, or an effort to‘make do’ with irrelevant data resulting from poor permeability study planning.

6.2 Controls on Permeability

6.2.1 Porosity

There have been several attempts to derive a general relationship between porosity andpermeability. In many ways, however, all attempts are bound to fail at a fundamental levelsince porosity is a scalar measurement and permeability is a vector measurement. Clearlythough it is reasonable to assume that permeability should increase with porosity inunfractured reservoirs without significant diagenetic. One of the most well known modelslinking porosity and permeability is known as the Kozeny-Carman model that considers theporous media to be made up of bundles of capillary tubes. The basic equation is:

( )K

c d

1KC

2 3

2=

−

φ

φ(6.12)

where:KKC = Kozeny-Carman predicted permeability, mDc = A constantd = Median grain size diameter, micronsφ = Effective porosity

Despite the obvious invalid capillary tube assumptions, this model remains one of the bestpredictors of permeability, and is often used in the hydrocarbon industry.



Another commonly used empirical model is that of Berg:

K dB2 5.1= φ (6.13)

where KB is the predicted permeability. Although this empirical model has been concoctedfrom a range of rocks and it is clear that the equation may not work on samples from otherlocations.

Recently, a new model has been proposed by Revil, Glover, Pezard and Zamora (RGPZ). Thisis a non-empirical model that is derived from the fundamental understanding of the electro-kinetic properties of rocks, and hold the potential for improved permeability prediction forrocks of different porosities, grain sizes, and pore tortuosities. It is expressed as:

Kd

4 a mRGPZ

2 3m

2=

φ(6.14)

where:KRGPZ = RGPZ predicted permeability, Dm = The cementation exponentd = Median grain size diameter, micronsa = Grain packing indexφ = Effective porosity



Note that all of these models use a grain size diameter to scale the predicted permeability tothe size of rock microstructure, and to ensure that the models are dimensionally correct.Figure 6.4 compares the three models described above for a range of clean sandstone, shalysandstone, and carbonate samples. Lines are placed at 1 mD in Figure 6.4; rocks withpermeabilities less than this value are considered to be non-reservoir rock (i.e. unproducibleeconomically).

6.2.2 Bedding

Permeability is a vector property, and as such, is greatly affected by directional heterogeneitywithin core samples. The commonest cause of such heterogeneities is bedding. It is a generalrule that the vertical permeability within a reservoir (i.e. that perpendicular to the bedding) islower than that in the bedding plane (horizontal permeability). In fact the vertical permeabilityis often about a third of that in the horizontal direction. It should also be noted that some ofthe difference between the vertical and horizontal permeabilities results from differences inthe way the local stress fields in the vertical and horizontal directions compact pores and closemicrocracks.

6.2.3 Pore Geometry

Permeability is highly dependent on the tortuosity of the pore fluid flow paths. Tortuosity canbe affected by many rock characteristics, including:

• Grain size and its distribution• Grain shape• Sorting• Grain orientation• Packing arrangement• Degree and type of cementation• Amount, orientation and connectivity of micro-fractures• Clay content• Bedding• Diagenesis

The detailed relationships are known only qualitatively, and the relative importance of eachvary from rock type to rock type. For example, the permeability of carbonates is primarilycontrolled by; (i) dissolution porosity, (ii) dolomitization, and (iii) fractures.

6.2.4 The Stress Conditions

Permeability is very sensitive to stresses that compact the rock. This compaction can occur inany direction not just vertically. However, vertical compaction is usually the most important.Indeed the local stress state may be such that dilatancy occurs (formation of fractures)increasing the permeability of the rock. In all cases it is poorly consolidated rocks that areaffected to the greatest extent. Figure 6.5a and b show the effect of increasing the hydrostaticconfining pressure on the permeability of a rock. Figure 6.5c compares the effect ofoverburden stress on permeability compared to the effect upon porosity. It can be seen thatoverburden stress affects permeability much more than porosity. This is because permeability



is very sensitive to the tortuosity of fluid flow paths through the rock, and such changes areassociated with very small changes to the rock porosity Overburden stress compacts the rockpressing the grains together. The size of the pores reduces little, but the pore throats thatcontrol the passage of gas between the pores undergo much greater closure, effecting thepermeability to a greater extent.

The large decreasesobserved indicate that itis very important toapply corrections topermeabilities measuredat low confiningpressures before they areconsidered to berepresentative of thereservoir, or measure thepermeability at reservoirstress conditions in thefirst place (SCAL). Itshould also be noted thatfracturing (bothmacroscopic and micro-fractures), that increasesthe permeability of therock samples whenmeasured in thelaboratory, can becaused by drilling andconcomitant upon thesudden reduction instress experienced by therock upon extraction ofthe core from the well.These fractures can beclosed again bymeasuring the rock atreservoir conditions, butit is very difficult toknow how to correct lowpressure Klinkenbergpermeabilitydeterminations for suchfracturing.



6.3 Laboratory Determinations

6.3.1 Steady State Gas Permeability Determinations

Routine permeability measurements are made by confining plugs in Hassler core holders,Figure 6.6, applying nitrogen pressure to one end and measuring flow rate and pressuredifferential. Figure 6.7 shows a steady state gas permeability rig that is equipped to measure alarge range of permeabilities (i.e. gas flow rates). Standard hydrocarbon industry rigs looksimilar, but have fewer options for measuring upstream pressure and flow rate.



For plugs having moderate permeabilities, 5-500 mD, repeat determinations at givenconfining, inlet and outlet pressures should fall within a few percent. Normally four or fiveconsecutive measurements are made at various mean pressures (Pm) to enable a Klinkenbergplot (Figure 6.2b) of permeability vs. 1/Pm to be made. Extrapolation to infinite meanpressure gives the equivalent liquid permeability, KL. Permeabilities above about 500 mDbecome less precise as the measured pressure differential falls leading to higher experimentalerrors. High permeabilities also imply large pores, large grains and rough surface texture.



Very rough surfaces may need wrapping in soft PTFE tape or repair with epoxy to ensureproper sealing by the Hassler sleeve. The sleeve pressure used will depend upon plug surfacetexture and the hardness of the rubber sleeve. Low permeabilities (less than 5 mD) do notnormally present any problems; but for normal reservoir applications, a cut off value of 0.01mD is applied. Values below this are simply reported as less than 0.01 mD, and are notinteresting as a reservoir. In practice rocks with permeabilities less than 1 mD are consideredto be non-reservoir rock (i.e. unproducible economically). If cap rocks are being investigated,the actual permeability values will be reported, whatever their permeability. Caution is neededin the handling of friable, poorly cemented samples. Gradual compaction can occur even withsleeve pressures as low as 400 psi. Consequently long equilibration times may be necessaryfor this type of sample. The first indication of this type of behaviour occurs when carrying outthe normal repeat timings of gas flow, when steadily decreasing flow rates are observed.

6.3.2 Unsteady State Gas Permeability Determinations

This is not as standard as the steady state method. It applied a volume of gas at a high initialpressure to one end of the sample and then measures the decay of the pressure as the gas leaksaway through the core. One advantage of this method is that it can be used to determine thepermeability of very low permeability rocks. It has therefore been used to measure thepermeability of cap rocks. It must be said, however, that leakage through cap rocks is nowrecognised to depend primarily on fractures through the cap rock rather than the permeabilityof the bulk rock itself, and so these measurements are being done less and less.

6.3.3 Steady State Liquid Permeability Determinations

Permeabilities to oil and water at 100% saturation of each fluid, or of oil in the presence of Swi

can also be easily carried out. The saturated samples are placed in a core holder. The requiredfluid is flowed through the sample, while measuring the steady state volume flow and pressuredifferential (see Figure 6.8 for a schematic diagram of a typical permeameter set-up). Allfluids used should be degassed prior to use. The permeability is calculated from Eq. (6.2).There is no need to institute a Klinkenberg correction, but the data is carefully examined toensure that the flow is laminar by carrying the test out at various flow rates and checkingwhether they all give approximately the same permeability. Those high flow rates that aresuspected to contain turbulent (Forchheimer) effects are discarded.



The values of permeability Kw at Sw=1 or Ko at So=1 should be approximately the same as theKlinkenberg permeability, KL. Ko at Sw=Swi and So=1-Sw will be less that that at So=1.

6.4 Data Handling

The correlation of core and logging data enable reservoirs to be assessed for productionpotential. The full description of this process is outwith the scope of this course. However, wewill briefly examine some of the issues related to the correlation of core measurements withlogs, and the use of permeability measurements in poroperm cross-plots.

6.4.1 Core-Log Comparison

The comparison of porosity and permeability data from core measurements and log methods isimportant to ensure that there is good agreement between them, allowing the measurements tobe used in reservoir modelling with confidence. The process should compare the log and coredata on the same log-type display (Figure 6.9). It is usually clear whether one of the curvesneeds to be depth shifted relative to the other. If a shift is necessary it is usually implementedfor the core data, as uncertainties in core depth occur when there is not 100% core recovery



form the hole. Corrections of 10 to 20 m are not uncommon. When comparing the depthcorrected core and log data it is usually clear whether there is a good match between the two.The degree of match is an average determination made by eye as the two measurements willrarely be in very close agreement. This is because the measurements are made by widelyvarying techniques, with varying scales of measurement. For example, a standard core plugwill have a volume of investigation of about 40 cm3, compared to approximately 15000 cm3

for a wireline tool. Additionally, the various methods measure different properties. Forexample core porosities are usually measurements of effective porosities (with non-connectedporosity and clay bound water excluded, and usually avoiding fractures), whereas log derivedporosities are generally measurements of total porosity. This results in the log porosities beinggenerally a little higher than the log-derived porosities.

6.4.2 Poroperm Cross-plots

Permeability is of incredible interest to the hydrocarbon industry as it describes how profitablefluids can be extracted from reservoirs. Clearly, any way of predicting permeability is of greatinterest too. One of the fundamental processes that is applied to permeability data is to plot iton a log-lin permeability-porosity diagram (Figure 6.10). Often there is a relationship within agiven rock unit, and differences between rock units can be useful in the analysis of thereservoir. The main aims are:



• To estimate permeability where only porosity data is available (e.g. In Figure 6.10, aconglomerate with a porosity of 13.3% has a permeability of 100 mD).

• To establish a porosity cut-off below which the reservoir is unproductive (e.g. thedata in Figure 6.10 has porosity cut-offs of 5.3% in the conglomerate and 10.7% in thesandstone, corresponding to a permeability of 1 mD..

This method is very powerful if used in an homogeneous formation, but can produceremarkably erroneous results if carried out badly. There are a few points to bear in mind whenusing cross-plots:

• Some positive correlation between porosity and permeability exists for non-fractured, non-vuggy rocks with the same degree of diagenesis (Figure 6.11).

• The estimation method is based on a mathematical correlation that only takes account ofporosity and permeability.

• No other factors are taken account of (e.g. diagenesis, fractures, vugs).• The log permeability scale can generate large permeability errors.• The cross-plot should be done for each individual rock unit if the relationship is to be

valid. Doing a cross-plot for the whole reservoir is a waste of time. Individual cross-plotsfor each mineralogy/lithology and/or based upon grain and pore size information frommercury porosimetry. Individual permeability zones can also be delineated by plotting thedistribution of permeabilities on a lin-log plot. This results in a log-normal distribution forwell controlled permeability data (see section 6.1.4). If the distribution is unimodal(Figure 6.12a) then a cross-plot for all the data will be valid. If the distribution is multi-modal (Figure 6.12b) then a cross-plot must be done for the data belonging to each of the



unimodal populations making up the multi-modal dataset (3 in the case of Figure 6.12b).There are statistical tests that can distinguish which population a sample belongs to, e.g.the Kolmogorov-Smirnoff test.

• Some rocks do not produce a clear relationship (e.g. commonly carbonates).• There is no physical basis for this type of plot. In fact reference to Eqs. (6.12) to (6.13)

indicates that a log-log plot would be more appropriate, and Eq. (6.14) indicates that a lin-lin plot of permeability against φ3m/m2 would provide the best results.

There are two other important points to bear in mind. First, for the cross-plot to be the mostvalid, it should be done with permeabilities and porosities that are representative of thereservoir. This means that the permeabilities should be Klinkenberg corrected, and bothpermeabilities and porosities should be corrected to reservoir stress conditions. Any derivedpermeabilities are then the permeabilities for complete saturation of the rock with the testfluid, and will need to be reduced to relative permeabilities if required. If drill stem testpermeabilities are used, then these will have been made in the presence of multi-phase fluids,and it is important to know more about the fractions of each fluid present and the wettabilityof the rock before valid deductions can be made. The second point is that the porosities fromcore measurements are effective porosities, whereas those from log measurements arecommonly total porosities. If data from both sets are to be used, then they must be reconciled



before use. Figure 6.13 shows the typical ranges of poroperm relationships for variouslithologies and rock microstructure.

Formation Evaluation MSc Course Notes Wettability


Chapter 7: Wettability


There exists a surface tension between a fluid and a solid, in the same way that a surfacetension exists between an interface between two immiscible fluids (cf. the surface tension onwater under air that is sufficient to support the weight of a needle.). When two fluids are incontact with a solid surface, the equilibrium configuration of the two fluid phases (say air andwater) depends on the relative values of the surface tension between each pair of the threephases (Figure 7.1). Let us denote surface tension as γ, and solid, liquid and gas as s, l, and grespectively. Each surface tension acts upon its respective interface, and define the angle θ atwhich the liquid contacts the surface. This is known as the wetting (or dihedral) angle of theliquid to the solid in the presence of the gas. Equilibrium considerations allow us to calculatethe wetting angle from the surface tensions:

γ θ γ γlg sg slcos = − (7.1)

This is known as Young’s equation (1805). Table 7.1 shows some contact angles and surfacetensions for common fluids in the hydrocarbon industry.

Table 7.1 Contact angles and interfacial tension for common fluid-fluid interfaces

Interface Contact Angle, θ,degrees

cos θ Interfacial Tension,dynes/cm

Air-Water 0 1.0 72Oil-Water 30 0.866 48Air-Oil 0 1.0 24Air-Mercury 140 -0.765 480



Note that:

• If γsg > γsl , then cosθ > 0 and θ <90o.• If γsg < γsl , then cosθ < 0 and θ >90o.

For a stable contact | cosθ | ≤ 1, or equivalently | γsg - γsl | ≤ γgl . This inequality is notsatisfied when γlg + γsl < γsg, when liquid covers the whole solid surface. Alternatively, whenγlg + γsg < γsl, the gas displaces the liquid away from the surface completely. Figure 7.2 showsa range of different wetting conditions.

When one fluid preferentially covers the surface, it is called the wetting fluid, and the otherfluid is called the non-wetting fluid. The origin of these surface tensions arises in the differentstrengths of molecular level interactions taking place between the pairs of fluids. For examplea quartz sandstone grain generally develops greater molecular forces between itself and waterthan between itself and oils. Clean sandstones are therefore commonly water wet. However,should that same grain have been baked at high temperatures in the presence of oil at depth,then (i) its surface chemical structure can be altered, or (ii) the surface itself can becomecoated, in such a way that results in the grain having greater molecular interaction with oilsthan water, and hence become oil wet. IMPORTANT NOTE Properly measured wettabilitieson well preserved core and core plugs should form the initial step in choosing relativepermeability test methods.



7.2 Laboratory Determination

There are several methods for determining wettability of a rock to various fluids. The mainones are:

(i) Microscopic observation This involves the direct observation and measurement ofwetting angles on small rock samples. Either a petrographic microscope or SEM fitted with anenvironmental stage is used. The measurements are extremely difficult, and good data reliesmore on luck than judgement.

(ii) Amott wettability measurements This is a macroscopic mean wettability of a rock togiven fluids. It involves the measurement of the amount of fluids spontaneously and forciblyimbibed by a rock sample. It has no validity as an absolute measurement, but is industrystandard for comparing the wettability of various core plugs.

(iii) USBM (U.S. Bureau of Mines) method. This is a macroscopic mean wettability of arock to given fluids. It is similar to the Amott method but considers the work required to do aforced fluid displacement. As with the Amott method, it has no validity as an absolutemeasurement, but is industry standard for comparing the wettability of various core plugs.

(iv) NMR longitudinal relaxation and other wettability methods. These are brieflysummarised in Table 7.2.

Table 7.2 Summary of Wettability Measurement Techniques

Measurement Technique Physical Observation

Amott and Amott-Harvey Amounts of oil and water imbibed by asample spontaneously and by force.

U.S. Bureau of Mines (USBM) Work required to imbibe oil and water.Microscopic examination Microscopic examination of the interaction

between the fluids and the rock matrix.Nuclear Magnetic Resonance Changes in longitudinal relaxation time.Flotation method The distribution of grains at water/oil or

air/water interfaces.Glass slide method Displacement of the non-wetting fluid from a

glass slide.Relative permeability method Shape and magnitudes of Kro and Krw curves.Reservoir logs Resistivity logs before and after injection of a

reverse wetting agent.Dye adsorption Adsorption of a dye in an aqueous solvent.

The first two methods are the commonest within the oil industry and are described in greaterdetail in the next two sections.



7.2.1 Amott Wettability Measurements

Wettability measurements by the Amott method give a guide to the relative oil or brinewetting tendencies of reservoir rocks. This can be crucial in the selection of relativepermeability test methods to generate data relevant to the reservoir situation. It is not alwayspossible to reproduce reservoir wettabilities in room condition relative permeability tests.However, an appreciation of the difference between reservoir and laboratory wettabilities canassist in interpretation of laboratory waterfloods.

The Amott method (Figure 7.3) involves four basic measurements. Figure 7.4 shows the dataproduced with the water wetting index given by AB/AC and the oil wetting index by CD/CA.

(i) The amount of water or brine spontaneously imbibed, AB.(ii) The amount of water or brine forcibly imbibed, BC.(iii) The amount of oil spontaneously imbibed, CD(iv) The amount of oil forcibly imbibed, DA

Figure 7.4 shows the initial conditions of the sample (point X) to be oil saturated at Swi. Thespontaneous measurements are carried out by placing the sample in a container containing aknown volume of the fluid to be imbibed such that it is completely submerged (steps 1 and 3in Figure 7.3 for water and oil respectively), and measuring the volume of the fluid displacedby the imbibing fluid (e.g. oil in step 1 of Figure 7.3). The forced measurements are carriedout by flowing the ‘imbibing’ fluid through the rock sample and measuring the amount of thedisplaced fluid (steps 2 and 4 in Figure 7.3), or by the use of a centrifuge. The importantmeasurements are the spontaneous imbibitions of oil and water, and the total (spontaneousand forced) imbibitions of oil and water. Water-wet samples only spontaneously imbibe water,



oil-wet samples only spontaneously imbibe oil, and those that spontaneously imbibe neitherare called neutrally-wet. The wettability ratios for oil (AB/AC) or water (CD/CA) are theratios of the spontaneous imbibition to the total imbibition of the each fluid.



In general use the samples to be measured are centrifuged or flooded with brine, and thenflooding or centrifuging in oil to obtain Swi. The standard Amott method is then followed. Atthe end of the experiment the so called Amott-Harvey wettability index is calculated:

CACD

ACAB

ImbibitionOilTotalImbibitionOilsSpontaneou

ImbibitionWaterTotalImbibitionWatersSpontaneou

Index

−=

−=(7.2)

Wettability indices are usually quoted to the nearest 0.1 and are often further reduced toweakly, moderately or strongly wetting. The closer to unity the stronger the tendency.

7.2.2 USBM Wettability Measurements

This method is very similar to the Amott method, but measures the work required to do theimbibitions. It is usually done by centrifuge, and the wettability index W is calculated fromthe areas under the capillary pressure curves A1 and A2:

A2A1

logW= (7.3)

where, A1 and A2 are defined in Figure 7.5. Note that in this case the initial conditions of therock are Sw=100%, and an initial flood down to Swi is required (shown as step 1 in Figure 7.5),although either case may be necessary for either the Amott or USBM methods. Figure 7.6shows typical USBM test curves for water wet, oil wet and neutrally wet cores.

7.2.3 USBM and Amott Technique Comparison

Warning. While both methods are common within the oil industry, they show remarkabledifferences especially near the neutral wettability region. In general, the Amott method isprobably the most reliable and accurate especially in the neutral wettability region. Acomparison of the two methods, together with contact angles, is given in Table 7.3.

Table 7.3 Comparison of the Amott and USBM Wettability Methods

Oil Wet Neutral Wet Water Wet

Amott wettability index water ratio 0 0 >0Amott wettability index oil ratio >0 0 0Amott-Harvey wettability index -1.0 to -0.3 -0.3 to 0.3 0.3 to 1.0USBM wettability index about -1 about 0 about 1Minimum contact angle 105o to 120o 60o to 75o 0o

Maximum contact angle 180o 105o to 120o 60o to 75o



7.3 Sample Preservation and the Effect on Wettability

Sample preservation, preparation, storage and test conditions are important since wettability issensitive to oxidation of crude oil and to temperature. Preservation of samples at the well-siteis generally by wrapping in foil and wax coating. The process should be carried out as soonas possible after removal of the core from the barrel. Samples are drilled and trimmed withdeaerated, simulated depolarised kerosene prior to testing. Tests carried out to assessreservoir wettability must be made on preserved core at a temperature high enough to ensurethat any wax present in the residual core remains in solution. If the wax precipitates, it willtend to increase the oil wetting tendency of the core. Room condition wettabilities may onlyapply to reservoirs containing wax free crude or cleaned cores from laboratory tests.

Formation Evaluation MSc Course Notes Capillary Pressure


Chapter 8: Capillary Pressure

8.1 Introduction and Theory

Capillary pressure data are required for three main purposes:

• The prediction of reservoir initial fluid saturations.• Cap-rock seal capacity (displacement pressures).• As ancillary data for assessment of relative permeability data.

Capillary pressures are generated where interfaces between two immiscible fluids exist in thepores (capillaries) of the reservoir rock. It is usual to consider one phase as a wetting phaseand the other as a non-wetting phase. However, intermediate cases occur which can greatlycomplicate the picture. The drainage case, i.e. a non-wetting phase displacing a wetting phaseapplies to hydrocarbon migrating into a previously brine saturated rock. Imbibition data is theopposite to drainage, i.e. the displacement of a non-wetting phase by a wetting phase. Thus,the drainage data can usually be used to predict non-wetting fluid saturation at various pointsin a reservoir, and the imbibition data can be useful in assessing the relative contributions ofcapillary and viscous forces in dynamic systems.

The basic relationship (Figure 8.1) between capillary pressure, interfacial tension, contactangle and pore radius is given by

Ccos

aAp =

2 γ θ. (8.1)

where;

Cp = capillary pressure (psi)γ = interfacial tension (dynes/cm)θ = contact angle (degrees)a = pore radius (microns)A = 145 x 10-3 (constant to convert to psi)

Applying this to a water wet rock having a broad spectrum of pore entrance radii, oilmigrating into water filled pores under a given pressure differential will only enter poreslarger than those indicated by ‘a’ in Equation (8.1). Thus for oil introduced at 2 psi into asystem having γ = 40 dynes/cm and θ = 0 (water wet), oil will only enter pores larger than

22 40 1

145 10 3= −x x

ax x (8.2)

giving a = 5.8 µm.

If capillary pressure data are available for a given system, it should be possible to convert toanother system of known θ and γ. This is expanded in Section 8.2.



8.2 Mercury Injection

These tests can only be carried out on cleaned, dried test plugs. They are initially immersed inmercury at <10-3 mm Hg vacuum within the apparatus sketched in Figure 8.2. The pressure inthe system, effectively the differential across the mercury/vacuum interface, is raised in stages.The volume of mercury which has entered the pores at each pressure is determined fromvolumetric readings, and the proportion of the pore space filled can be calculated. This givesthe curve shown in Figure 8.3. Further readings can be taken as the pressure is lowered toprovide data for the imbibition case from Swi to Cp = 0 at point A in Figure 8.3.

The volume of mercury injected into the pores at a given pressure is usually expressed as aproportion of the total pore space, and is presented as a pore size distribution (Figure 8.4) orconverted to oil or gas-brine data using appropriate contact angles and interfacial tensions.Typical conversions are given below:-

C (gas - brine) = C (Air - Hg)72 cos 0

cos 130p p

o

o480(8.3)

= 0 233. C (Air - Hg)p



C oil - brine) = C (Air - Hg)25 cos 30

480 cos 130p p(

o

o(8.4)

= 0.070 C (Air - Hg) p

Further conversion to height above oil, or gas-water contact is possible from

C = hg ( - p oρ ρw ) (8.5)

Displacement pressures for the assessment of cap rock seal capacity can be assessed from thecapillary pressure curves. Care has to be used and allowance made for the effect of surfaceirregularities. This is especially true of samples with small total pore volumes, i.e. less than 1ml that are typically the case with cap rock samples.

Approximate permeabilities can also be calculated from pore size distribution data; but carehas to be taken to exclude the contribution of surface irregularities, since a small number oflarge pores disproportionately increases the calculated permeability. The data presented inFigure 8.4 shows the effect of surface irregularities at pore throat diameters greater than 10microns.



Mercury injection has the following disadvantages:

(i) It is a destructive test.(ii) It is carried out on dried core which allows for no fluid-surface interactions.(iii) It can cause collapse of accumulations of grain surface coating minerals.

The latter two effects lead to low implied connate water saturations. The data obtained applyto a system containing a fully wetting phase and a fully non-wetting phase. The capillarypressure data obtained will not necessarily apply to pores containing fluids showing partialwetting preferences.

The advantages of the technique are that it is rapid (about three hours per sample) andirregular samples can be used. A drainage capillary pressure curve can be produced in amatter of hours and in certain circumstances drill cuttings can provide useful data.



8.3 Porous Plate Method

8.3.1 Gas-Brine Systems

This technique is generally applied in the drainage mode to air-brine systems starting with testplugs which are initially brine saturated. The capillary pressure is applied across the test plugand a brine saturated porous plate. The high displacement pressure of the porous plate allowsbrine from the plug to pass through, but prevents flow of the displacing fluid (normally air).The apparatus is shown in Figure 8.5. Plugs are removed at intervals and weighed untilweight (and therefore fluid) equilibrium is attained. The pressure applied is then increasedand the process repeated until a full curve of about six points is obtained.

In this method care has to be taken to maintain good capillary contact between the test plugand the porous plate. This is assisted by using a paste of filter-aid and brine between the plateand a filter paper. The test plug is positioned on the paper and a lead weight placed on theplug to keep it solidly in place. There is also the danger that the water in the sample will be



evaporated by the gas pressure. To avoid this the input gas can be saturated with water bybubbling it through a reservoir of water prior to use, and keeping a beaker of water inside theporous plate pressure vessel.

The resulting data is presented as (i) air-brine capillary pressure versus brine saturation(Figure 8.6), (ii) converted to oil-brine data (Figure 8.7), or (iii) as saturation versus heightabove oil (or gas) - water contact.



The disadvantages of the porous plate method are that it is time consuming, needing up totwenty days for equilibration at each pressure. Also, capillary contact with the porous platemay be lost at high pressures. This causes erroneously high connate water saturations to beimplied. Imbibition measurements are not generally attempted.

The advantage of the method is that the test plug has at least one representative fluid in place,i.e. the brine. This ensures that brine mineral interactions e.g. clay swelling, which affect poresize and surface states, are taken account of. This is a large advantage over the mercurymethod, which cannot take account of clay-water interactions.

8.3.2 Oil Brine Systems

It is more difficult to make oil-brine measurements than air-brine. For a fully water-wetsystem, oil-brine drainage capillary pressure data can be inferred from air-brine data. Actualoil-brine drainage capillary pressure can be measured using a Hassler cell fitted with a brinesaturated disc (see Figure 8.8). An initially brine saturated test plug is subjected to an oilpressure at the inlet face, and the volume of brine produced (oil taken up) observed at theoutlet. Once equilibrium is achieved (this may take 1-3 weeks), the pressure is increased andthe process repeated until a full curve is obtained. Care has to be taken that the displacementpressure of the disc is not exceeded, leading to brine displacement from the disc as well as thetest plug. This can only be checked and allowed for by weighing the disc before and duringthe course of the experiments.

The disadvantages of the method are basically the same as for the gas-brine case, but withadded complications if test plug wetting characteristics differ from those of the reservoir. Themethod is limited to approximately 50 to 100 psi depending upon disc characteristics.Imbibition measurements are extremely difficult and are limited to about 25 psi.



The advantages of the method are that, if the wetting characteristics are as in the reservoir,then representative data should be obtained for both mixed and oil wet systems.

8.3.3 Other Methods

There are several other more advanced methods of measuring capillary pressure that arecurrently being investigated by the hydrocarbon industry. All use a core in a Hassler or similarcoreholder under confining pressure. The major ones are:

(i) The Dynamic Method This involves injecting the two fluids into a rock coresimultaneously, and producing one behind a semi-permeable membrane.

(ii) The Semi-Dynamic Method This involves injecting a single fluid, while a membraneat the far end of the rock is washed with the other fluid. This method can be used to measurethe complete drainage and imbibition parts of the capillary pressure curve.

(iii) The Transient Method This method is technologically complex, and involves themeasurement of saturation and pore fluid pressures simultaneously during fluid injection intothe sample.



8.4 Centrifuge Method

The centrifuge method is widely advocated by US companies. It relies upon increasing the g-term in the equation;

C = h g ( - ) ,p ρ ρw o (8.6)

by spinning the core plug at a known radius and rpm. The average capillary pressure is thengiven by:

C psi 7.9x10p ( ) ( ) ( )= − −−81 2

2 2 2ρ ρ R r rb t (8.7)

where ρ1 and ρ2 are the densities of the two phases present and rb and rt are the radii ofrotation of the bottom and top of the core respectively.

For the oil-brine drainage cycle, brine saturated test plugs are immersed in oil in speciallydesigned holders. Starting at a low rpm setting, the amount of brine expelled from the plug isnoted for a given rate of rotation. The volumes are measured in the following manner. Acalibrated glass vial is attached to the end of the sample. The volume of fluid being depositedin this vial can be read while the centrifuge is spinning fast using a stroboscope. The rate isthen increased in stages and produced brine volumes are recorded for each rotation speed togive the drainage curve. The imbibition curve can then be followed by stopping the centrifugeallowing spontaneous imbibition to occur to point A at Cp = 0 (Figure 8.3). The fluid in theimbibition cell is then changed from brine to oil, and the portion of the curve from A (Cp) = 0to Sor (Figure 8.3) can then be followed by recording the volume of oil produced at severalincreasing rates of rotation.

The main disadvantage of the centrifuge method is that a capillary pressure gradient is appliedwhich must inevitably give rise to a saturation gradient. This will be more exaggerated at lowpressures.

The advantages of the centrifuge method are that it is rapid, a full drainage and imbibitioncycle being complete in a matter of days, and that oil-brine data can be obtained, hopefully,under representative wetting conditions. Centrifuges can also be operated at elevatedtemperatures (up to 150°).

Differences in wetting characteristics should be taken into account when applying laboratorydata to the field. Thus air-brine and mercury-air data obtained on cleaned core will represent afully water wet system for the drainage case. They may not adequately describe a mixed or oilwet system. The closest one can get to this situation, on a routine basis, is with an actual oil-brine system when one would expect to find lower Swi values than a water wet system.



8.5 Applications of Methods

The applications of the various major methods described above are given in Table 8.1.

Table 8.1 Parameters associated with various capillary pressure measurement methods.

Range Method

Mercury Porous Plate CentrifugeHg - Air Air - Brine Oil - Brine Air - Brine Oil - Brine

Drainage Sw = 1 to Swi

Imbibition Swi to Cp=0 Swi to Cp=0,Cp=0 to Sor

Cp=0 to Sor Cp=0 to Sor

Sample wettingstate

Water wet As sample

Sw precision tends low tends high tends high not known not knownPressure limit, psi 1150 70-100 70-100 1000-2000Elapsed time 1-2 days 3 months 3 months 1-3 days 1-3 days

8.6 Capillary Pressure Prediction (Leverett Method)

The Leverett ‘J’ function is an attempt to correlate capillary pressure with pore structure(defined in terms of porosity and permeability). The basic capillary model predicts that todisplace a wetting phase with a non-wetting phase then:

C =2 Cos

apγ θ

. (8.8)

For a simple capillary model, the mean hydraulic radius, a, is given by:

aK

=

2 21 2

εθ

(8.9)

Combining Eq. (8.8) and (8.9) we get;

CK

p θγ θ ε

=

1 2

1

2cos(8.10)

from which the Leverett ‘J’ function is defined:



JC

Kp

=

θ

γ θ

1 2

cos(8.11)

or;

J 0.217 CK

p=

θ

1 2(8.12)

where Cp is in psi, γ is in dynes/cm, and K is in mD.

Given a typical J curve, the capillary pressure curve for a material of similar pore structure canbe calculated for a given value of θ and K.

Formation Evaluation MSc Course Notes Electrical Properties


Chapter 9: Electrical Properties

9.1 Introduction

Laboratory measurements of electrical properties (formation factor and resistivity index) areintended to complement those made during down hole logging operations. The data are usedto refine values of n, a and m in Eq. (9.1) and (9.2) below:

F = R

R

ao

wm=

φ(9.1)

where;

F = Formation factorRo = Resistivity of brine saturated rockRw = Resistivity of brinea = Constantφ = Porositym = Cementation exponent

and,

IR

R St

o wn

= =1

(9.2)

where;

I = Resistivity indexRt = Resistivity of rock at Sw < 100%n = Saturation exponent

Without prior laboratory data, n is generally assumed to have a value of 2. Typically,laboratory derived data gives values between 1.7 and 2.4 (Figure 9.1).

Equations (9.1) and (9.2) are empirical in nature. They are generally adhered to by ‘clean’samples, but where clays (usually described as shales in this context) are present largedeviations can occur. Empirical corrections for shale effects, i.e. for m to m* and n to n* arepossible but the best procedures are in doubt. The shale effect, which is primarily due toenhanced surface conduction in the high surface area clays, can now also be corrected forusing fundamental theory, but the governing equations for the physical processes involved arecomplex.

As with other SCAL tests, samples should be prepared and brought to the initial brinesaturated state without drying. The displacing phase used in resistivity index measurements isair, thus these tests are carried out in conjunction with air-brine capillary pressuremeasurement, most commonly using the porous plate method.



9.2 Formation Factor

Formation factor is a function of porosity and pore geometry and is defined above in Eq. (9.1).Laboratory measurements are made at room conditions or at overburden conditions, theapparatus is sketched in Figures 9.2 and 9.3 respectively. Normally plugs require 2 weeks forequilibration with formation brine. For room condition tests, measurements are made atintervals of a few days until constant values are obtained. In the case of overburdenmeasurements, it is possible to flow brine through the plug in the cell and equilibrium isachieved more rapidly.

Overburden resistance measurements are made at increasing pressures, but time has to beallowed for equilibrium to be achieved. This is generally due to varying rates of compactionunder overburden pressures and, in the case of low permeability samples, it can take manyhours for brine to be fully expelled. Rates for compaction vary according to material, 24 hoursoften being required for full equilibration. Repeat determinations cannot be made withoutallowing plugs sufficient time to relax back to the unconfined state. This can take many weeksand in some cases, where the pore structure is irreversibly damaged, the rock never returns toits initial state. Once a rock has been used for resistance measurements at high overburdenpressures, it should never be used for further study for this reason. Overburden formationfactor measurements are generally combined with pore volume compressibilitydeterminations.



The actual electrical measurements of resistance in themselves are very precise (better than0.1%), but care has to be exercised in setting up the plug for the measurements. The mostimportant thing is that the electrodes at each end of the sample do not have any electricalconnection except through the rock. This may seem obvious and trivial to arrange, but this oneproviso causes the greatest difficulty when setting up a plug to be measured either at highoverburden pressures, during rare triaxial deformation experiments, or using high electricalfrequencies. The first and second of these situations arises from the need to electrically isolatethe electrodes at each end of the sample from each other and the pressure vessel. Insulation isshown schematically in Figure 9.3, but in reality it is not always easy to arrange a robustelectrically insulating and pressure-proof leadthrough. In the last situation, it is thecapacitance of the leadthroughs and the pressure vessel itself that causes the problems. Eventhough there is no direct conductive connection, high frequency current can leak from oneelectrode to the other through the body of the pressure vessel by charge induction, eventhough there is an insulator in between.



High quality in-phase and out-of-phase resistance (conduction, and permittivity)measurements can be made anywhere in the frequency range from DC to 10 MHz usingimpedance analysers. The whole range of frequencies is generally used in academic rockphysics, where the technique is called impedance spectroscopy. In the oil industry, only onefrequency is used. This is usually 1 kHz, or near it, and is usually taken as the frequency atwhich the out-of-phase component of the resistance is minimised, i.e. the frequency at whichthe conduction is most ohmic. Note that this frequency avoids the highest frequencies wherecurrent leakage can be a problem. It also avoids the low frequencies, where electrodepolarisation can be a problem.

The electrodes are commonly made of platinum gauze, upon which a fine dendritic structureof amorphous black platinum has been electro-deposited. This increases the surface area of theelectrodes by several orders of magnitude, helping to reduce electrode polarisation effects tonegligible values. Often a pad of filter paper soaked in the pore fluid is inserted between therock and the platinum electrode to (i) homogenise the current flow, (ii) improve the electricalconnection, and (iii) avoid conductive minerals channelling current into the rock.

For room condition tests, care has to be taken to remove excess surface moisture from theplug (so that the conduction along the plug surface is not measured) and to ensure that justsufficient brine is contained in the electrode ends to give good contact. Contact problems are



less pronounced in the overburden cell as brine is flowed through the system beforemeasurements are taken, and good electrical contact is assisted by the hydrostatic load on theend pieces. Plug surface conduction is removed by placing the plug in a rubber sleeve, whichis squeezed tightly onto the plug by the confining pressure.

The main measurement is sample resistance, r. This is clearly dependent upon the length, L,and the cross sectional area, A, of the sample. In order to compare samples, the resistance,length and cross sectional area of the sample are used to calculate the resistance per unitlength and per unit cross sectional area of the sample rock; this is called the resistivity, R:

R = rAL

(9.3)

Note from Eq. (9.1) that the resistivity of the pore fluid is also required. This can be done in astandard dip cell, but this method is prone to large systematic errors. More commonly aspecially designed fluid cell is used (Figure 9.4). This cell is connected to the same impedanceanalyser as used for the main measurements, and at the same frequencies. The fluid resistanceobtained in this way is converted to a fluid resistivity by multiplication by a cell constant, thatvaries from cell to cell, and with temperature and pressure. The cell constant is obtained bycalibrating the cell with fluids of accurately known composition and resistivity.

The precision of measurement is dependent upon operator skills and sample permeability. Forlower permeability samples (with small pores) repeat determinations should fall within a fewpercent. For friable, high permeability samples repeatability is poorer, and in extreme casesroom condition tests may be impossible due to too rapid drainage of fluid from the sample.



Cementation exponent, m, for a particular sample can be calculated directly from Eq. (9.1) ifit is assumed that a=1. More commonly, cementation exponent for a group of samples iscalculated graphically using a minimum of 10 samples covering a wide a permeability rangeas possible. A typical data set is shown in Figure 9.5. Equation (9.1) can be rewritten as:

log F = log a - mlog φ (9.4)

A log-log plot of formation factor against porosity gives a straight line, with a gradient equalto the negation of the cementation exponent, and with a y-intercept at φ=1 equal to log (a). Itis common to see cementation data from a best fit through the data giving both m and a, butmost commonly the linear regression is forced through (φ=1, F=1) corresponding to a=1.

Some typical overburden measurements are shown in Figure 9.6.



9.3 Resistivity Index

This involves similar measurements to formation factor except that resistance is measured atvalues of Sw less than 100%. Plots of resistivity index and Sw give n, the saturation exponent(Figure 9.7). The methods of desaturation include porous plate and centrifuge, thus resistivityindex measurements are conveniently combined with air/brine capillary pressuremeasurements.

Note that Eq. (9.2) can be written as:

log I = 1 - nlog Sw (9.5)

So the saturation exponent, n, is the negation of the gradient of the log I versus log Sw plot(Figure 9.7 shows typical data), and that the line should always pass through (Sw=1, I=1).

The practical considerations for these electrical measurements are similar to those forformation factor, except that the tendency for brine to drain from the plug is essentiallyremoved because of the lower saturations. The electrical measurements can be performed tobetter than 0.1% and saturation changes determined to ± 0.5 Sw%.

Care has to be taken to avoid evaporation losses during desaturation and measurement ofresistance. Plugs are stored in closed weighing bottles and only removed for the minimumpossible period.



9.4 Shale Effects

Very little data is available on the reproducibility of m and n. Repeat determinations of n by askilled operator should result in good agreement, probably within a few percent.

Plots of Sw versus resistivity index often give very good straight lines, but this is not alwaysthe case. Some scatter is likely at high values of Sw (above 80%) and at low values (below20%).

The reasons for this are not well understood. Scatter at high values of Sw is difficult toaccount for; but at low values of Sw it could be due to genuine clay effects, i.e. ‘excess’conductivity of clays, or to water vapour loss and concentration of brine in the test plug.

Correction of m and n to m* and n* is still under general discussion within the industry.These are generally corrected from cation exchange capacity (CEC), which can be obtainedfrom laboratory measurements on crushed rock. Unfortunately, the values obtained for CECcan depend upon the amount of crushing the core has been subjected to, and the method used.It is possible that measurement of formation factor at various salinities can give a better guideto correction of m and n. A plot of core conductivity against brine conductivity (Figure 9.8)can give a value for BQV/F*, which has then at least been obtained from direct electricalmeasurements on intact core with the fluids of interest in place.



This topic requires deeper discussion than can be covered here, but it should be borne in mindthat the relationships between electrical properties and saturations are empirical; linearrelationships cannot always be expected.

A more comprehensive discussion on the accuracy of electrical measurements are given in

references [2] and [3].

Formation Evaluation MSc Course Notes Relative Permeability


Chapter 10: Relative Permeability


Routine permeability measurements are made with a single fluid filling the pore space. Thisis seldom the case in the reservoir situation except in water zones. Generally, two andsometimes three phases are present, i.e. oil, water, and occasionally gas as well.

Here one would expect the permeability to either fluid to be lower than that for the single fluidsince it occupies only part of the pore space and may also be affected by interaction with otherphases. The concept used to address this situation is called relative permeability. The relativepermeability to oil, Kro, is defined as:

KK

K

effective oil permeability

base permeabilityroeo= = (10.1)

Similarly we can define:

KK

K

effective water permeability

base permeabilityrwew= = (10.2)

KK

K

effective gas permeability

base permeabilityrgeg= = (10.3)

The choice of base permeability is not, in itself, critical provided it is consistently applied.Conversion from one base to another is a matter of simple arithmetic. However,experimentally, the base permeability is usually chosen as that measured at the beginning ofan experiment. For example, an experiment may start by measuring the permeability to oil inthe presence of an irreducible water saturation in the core. Water is then injected into the core,and the oil permeability and water permeabilities measured as water replaces oil within thecore. The base permeability chosen here, would most commonly be the initial permeability tooil at Swi.

Laboratory measurements are made by displacing one phase with another (unsteady state testssee Figure 10.1) or simultaneous flow of two phases (steady state tests Figure 10.2). Theeffective permeabilities thus measured over a range of fluid saturations enable relativepermeability curves to be constructed. Figure 10.3 shows an example of such a curve from anunsteady state waterflood experiment. At the beginning of the experiment, the core issaturated with 80% oil, and there is an irreducible water saturation of 20% due to the waterwet nature of this particular example. Point A represents the permeability of oil under theseconditions. Note that it is equal to unity, because this measurement has been taken as the basepermeability. Point B represents the beginning water permeability. Note that it is equal to zerobecause irreducible water is, by definition, immobile. Water is then injected into the core atone end at a constant rate. The volume of the emerging fluids (oil and water) are measured at



the other end of the core, and the differential pressure across the core is also measured. Duringthis process the permeability to oil reduces to zero along the curve ACD, and the permeabilityto water increases along the curve BCE. Note that there is no further production of oil fromthe sample after Kro=0 at point D, and so point D occurs at the irreducible oil saturation, Sor.Note also that Kro + Krw ≤ 1 always.



It must be stressed, however, that these curves are not a unique function of saturation, but arealso dependent upon fluid distribution. Thus the data obtained can be influenced by saturationhistory and flow rate. The choice of test method should be made with due regard for reservoirsaturation history, rock and fluid properties. The wetting characteristics are particularlyimportant. Test plugs should either, be of similar wetting characteristics to the reservoir state,or their wetting characteristics be known so that data can be assessed properly.

Rigs for relperm measurement are often varied in design depending upon the exactcircumstances. Figure 10.4 shows an example of a typical rig piping diagram. The fluid flowlines would be nylon or PTFE tube for ambient condition measurements (fluid pressures up toa few hundred psi, and confining pressures up to 1500 psi), and stainless steel for reservoircondition measurements (fluid pressures of thousands of psi, confining pressures up to 10,000psi, and temperatures up to 200oC). These latter experiments are extremely complex, time-consuming, and expensive especially if live fluids are to be used. The mean saturation in thecore is measured by collecting and measuring the volume of time-spaced aliquots of theevolving fluids. However, there are various successful methods of monitoring the saturationof the various fluids inside the core during the experiments. These are:



(i) GASM (Gamma Attenuation Saturation Monitoring). Commonly used by BP, this usesdoped oil or water phases to attenuate the energy of gamma rays that travel through the coreperpendicular to the flood front. Each gamma source/detector pair measures the instantaneouswater and oil, or gas and oil saturation averaged over a thin cross section of the core. Up to 8pairs are used to track the fluid saturations in the core during an experiment, giving a limitedresolution. Modern techniques use a single automated motorised source/detector pair.

(ii) X-Radiometry. Commonly used by US companies. It is similar to GASM, but uses x-rays instead of gamma rays.

(iii) CT Scanning. Uses x-rays and tomographic techniques to give a full 3D image of thefluid saturations in the core during an experiment. The spatial resolution is about 0.5 mm, butis extremely expensive, and measurements can be made only every 5 minutes or so.

(iv) NMR Scanning. A very new application that is similar to the CT scanning. It has anincreased resolution, but is even more expensive.

The first two methods are commonly used, whereas the last two are rarely used due to theircost.

10.2 Oil-brine relative Permeability Theory

Three cases will be considered:

(i) Water-wet systems(ii) Oil-wet systems, and(iii) The intermediate wettability case.

It should be remembered that in water-wet systems capillary forces assist water to enterpores, whereas in the oil wet case they tend to prevent water entering pores.

Many reservoir systems fall between the two extremes, which does nothing to make laboratorywater-flood data easier to interpret. However, a knowledge of the two extreme cases allowsmisinterpretation of intermediate data to be minimised.

Consideration must be given to flow rates. Close to the well bore, advance rates will be high,further away, rates can be very low. This can be modelled in laboratory tests; but in the caseof oil wet systems, there is a tendency for low recoveries to be predicted due to end effects,i.e. retention of wetting phase at test plug outlet face.

10.2.1 Water Wet Systems

Consider a water-wet pore system at Swi (generally 15 to 30%) some distance from well boresuch that flow rates are low, typically advancing at 1 ft/day. This is equivalent to about 4cc/hr in a typical laboratory waterflood. The following sequence occurs as water migrates intothe rock:



(i) Figure 10.5. Initially at Swi, water is the wetting phase and will not flow. Kro = 1 andKrw = 0.

(ii) Figure 10.6. Water migrates in a piston like fashion, tending to displace most of the oilahead of it.

(iii) Figure 10.7. As water saturation increases oil flow tends to cease abruptly, and Sor isreached.

(iv) Figure 10.8. Dramatically increasing the water flow rate (bump) has very little effect onoil production or Krw. This is because capillary forces provide most of the energyrequired for displacement of the oil.

If floods are carried out at too high a flow rate on water-wet cores the trapping mechanismspresent in the reservoir are not allowed to occur. Instead of entering small pores preferentiallyby capillary forces, the water flows at a relatively higher velocity through larger pores, thustending to bypass ‘groups’ of smaller pores containing oil. The Sor value obtained may thendiffer from the true reservoir situation.



Water wet systems are usually adequately described by low rate floods, and do not exhibit endeffects to any significant extent. Water wet data are characterised by:

(i) Limited oil production after water breakthrough.(ii) Generally good recoveries.(iii) Low Krw values at Sor.

Some typical data are presented in Figures 10.9 and 10.10. Points to take note of are thelimited amount of incremental data obtained (although this may be extended by using viscousoils). This is caused by the rapid rise in water cut and the very short period of two phase flowtypical of water wet systems.

10.2.2 Oil Wet Systems

Consider water entering an oil-wet pore system containing (typically) very low watersaturations. The sequence of events from Swi is illustrated by Figures 10.11 to 10.14 asfollows:



(i) Figure 10.11. Capillary pressure considerations indicate that an applied pressuredifferential will be required before water will enter the largest pore. The actual pressuredifferential required is dictated by Eq. (8.1).

(ii) Figure 10.12. Water flows through the largest flow channels first, Kro falls and Krw risesrapidly.

(iii) Figure 10.13. After large volumes of water have flowed through the system, Sor isreached. This equilibrium is attained slowly giving the characteristic prolonged slowproduction of oil after early water breakthrough.

If waterfloods on oil wet core are carried out at too low a flow rate there may be inappropriateretention of oil at the outlet face of the test plug. This is illustrated in Figure 10.14. At theend of a low rate flood, Krw and the amount of oil produced are relatively low. If the flow rate(and hence the pressure differential) are increased at this stage, substantial further oilproduction occurs and Krw increases significantly. This situation does not model processesoccurring in the reservoir and should be avoided by appropriate choice of waterflood rate atthe beginning of the experiment.

Typical high rate valid oil wet data are shown in Figure 10.15 and 10.16.



10.2.3 Intermediate Systems

Data from intermediate wetting rock-fluid systems can be difficult to assess, especially if asingle test mode has been used to obtain data. It is usually necessary to carry out a variety offlood modes to fully assess end effects and rate dependence. A low rate flood followed by ahigh rate bump flood will usually give an indication of the extent of end effects. Flowreversal may indicate whether low recoveries are due to pore scale end effects evenlydistributed within the test plug. Steady state tests may be necessary to fully define the shapeof the relperm curves.

Typical intermediate wettability relperm data are shown in Figures 10.17 and 10.18. Theshape of the relperm curves is significantly different for the high and low rate floods.However, the volume of oil produced is similar.

Figure 10.19 shows steady state data obtained from a core containing mobile kaolinite fines.These were mobilised during the prolonged simultaneous flow of oil and brine during thesteady state test sequence. They have caused the water relative permeability to be suppressed.Figures 10.17, 10.18 and 10.19 contain data obtained on the same test plug and illustrate theneed for more than one test made in obtaining valid relative permeability data. Note also that



the data points are more reasonably spaced and are less scattered for the steady state test, butthere are fewer of them. The steady state test is more controlled because it takes much longerto carry out, but the length of time required to come to equilibrium at each flow rate ratio (atleast a few days compared to less than one day for a whole unsteady state test) results in fewerdata points being taken.



10.2.4 Relative Permeability Calculations

This section includes:

(i) Calculation of relative permeability from laboratory waterflood data and the basicequations from Johnson Bossler & Nauman (JBN).

(ii) Prediction of fractional flow from relperm curves and capillary pressure data.(iii) Fractional flow from transition zones.(iv) Variation of fractional flow with viscosity ratio.

I. Calculation of Relative Permeability from Waterflood Experiments: JBN Analysis.

The experimental data generally recorded includes:

Qi = Quantity of displacing phase injected∆p = Pressure differential∆pi = Pressure differential at initial conditionsQo = Volume of oil producedQw = Volume of water produced



These data are analysed by the technique described by Johnson, Bossler and Nauman (seereference list [4]), which is summarised below. Three calculation stages are involved:

(a) The ratio Kro/Krw.

(b) The values of Kro and hence Krw.

(c) The value of Sw.

The method is aimed at giving the required values at the outlet face of the core which isessentially where volumetric flow observations are made.

(a) Kro/KrW The average water saturation (Swav)is plotted against Qi:

It can be shown that the fractional flow of oil, at the core outlet is given by:

fd S

d Qoutwav

i= (10.4)

Together with:

fK

K

outrw o

ro w

=+

1

1µµ

(10.5)

(b) Kro A plot of ∆p/∆pi against Qi is used to obtain the injectivity ratio IR:



Ip

p

1

QRi

i=

∆∆

(10.6)

Kro is obtained by plotting 1/QiIR versus 1/Qi;



and using the relationship;

( )( )

K f1

d 1/ Q I

d 1/ Q

ro outi R

i

= (10.7)

Knowing Kro/Krw from (a) above, then Krw can be calculated.

(c) Using Welges correction to convert average saturations to outlet face saturations(Swout);

S S f Qwout wav out i= − (10.8)

Thus Kro and Krw can be plotted against Swout to give the normal relative permeability curves.

II. Prediction of Fractional Flow

Fractional flow can be predicted from capillary pressure data and relperm curves. Capillarypressure data gives the saturations expected, and the relperm curves provide the values for Krw

and Kro at that saturation. Water cut can then be calculated.

Water and oil cuts are defined as follows:

Water Cut%Water productionTotal production

x 100%= (10.9)

and

OilCut%Oil production

Total productionx 100%= (10.10)

Using the radial flow equations;

QK H P

lnR

R

oeo t d

oe

w

=

2π

µ(10.11)

and;



QK H P

lnR

R

wew t d

we

w

=

2π

µ(10.12)

where; Ht = Thickness of the producing zone being considered.Pd = Drawdown pressure.

But from equations 10.1 and 10.2;

K K Keo ro= (10.13)

and

K K Kew rw= (10.14)

Thus, since the fractional water cut, fw, is defined as;

fQ

Q Qww

o w=

+(10.15)

we can say:

f1

1K

K

ww

o

ro

rw

=+

µµ

(10.16)

III. Fractional Flow from Transition Zones

Transition zones or zones with Sw at some value greater than Swi may present problems withunsteady state tests. It may not be possible to perform an unsteady state waterflood starting atSw values greater than Swi, i.e. where the initial oil saturation is lower than the irreduciblesaturation attained at ‘infinite’ capillary pressure. The steady state test may be moreapplicable in such cases. This situation frequently exists in transition zones before productionis started. When production commences the oil/water flow ratio should correlate with steadystate water drainage test data, i.e. carried out with Sw increasing. This is the most probabledirection in which saturation last changed to place the reservoir in its discovery state.

IV. Variation of Fractional Flow with Viscosity Ratio

For cases where capillary forces are negligible, it can be shown that the fractional flow ofwater increases as the viscosity of water decreases relative to the oil viscosity. Using the termmobility, defined as:

M for oilphase K /ro ro o= µ (10.17)



M for water phase K /rw rw w= µ (10.18)

the Mobility Ratio M / Mro rwλ = (10.19)

Eq. (10.16) is then expressed as:

fw =+1

1 λ(10.20)

Thus fw decreases as µw is increased or as µo is decreased. The effect is shown in Figure 10.20.



10.3 Laboratory Tests Available

There are at least ten usual variations of room condition tests, and each can also be done atfull reservoir conditions of confining pressure, fluid pressure, and temperature with live fluids(Table 10.1).

Table 10.1 Common Laboratory Relperm Tests

Type Mode Sw So Sg

Oil/brine imbibition Steady state Increasing Decreasing Sg=0Oil/brine drainage Steady state Decreasing Increasing Sg=0Oil/brine imbibition Unsteady state Increasing Decreasing Sg=0Oil/brine drainage Unsteady state Decreasing Increasing Sg=0Gas/brine drainage Unsteady state Decreasing So=0 IncreasingGas/brine imbibition Unsteady state Increasing So=0 DecreasingGas/oil drainage Unsteady state Sw=0 Decreasing IncreasingGas/oil imbibition Unsteady state Sw=0 Increasing DecreasingGas/oil drainage Unsteady state Sw=Swi Decreasing IncreasingGas/oil imbibition Unsteady state Sw=Swi Increasing Decreasing

The most representative and costly test is the reservoir condition waterflood. This is carriedout on core which has been restored to full reservoir conditions of temperature, overburdenloading, fluid contents (live crude) and wettability. Limited numbers of these tests areperformed to assess more economical room condition waterflood data.

In view of the large number of possibilities, detailed discussion here will be limited to thosemost frequently studied, i.e. water-floods, steady and unsteady state, gas/brine drainage andimbibition, and gas/oil drainage and imbibition.

10.3.1 Oil-Brine Relative Permeability

This is the most frequently requested relative permeability test. It attempts to simulate thedisplacement of oil by a rising oil-water contact or a waterflood. The choices of test modeavailable are unsteady state or steady state, and each has its limitations and advantages. Ingeneral terms unsteady state tests are less time consuming than steady state tests, but cansuffer from uneven saturation distributions (end effects). Displacement rates can be modifiedto accommodate wettability characteristics to some extent, and to model reservoir flow rates.Steady state tests can be set up to avoid end effects but are more time consuming, requiringtime to reach equilibrium at each chosen oil/brine flow ratio.

10.3.2 Oil-Brine Unsteady State Test Procedure

Cleaned cores at Swi are confined in a Hassler or other type of core holder fitted with abreakthrough detector and subjected to a constant brine flow. Data recorded are incrementaloil and brine production (in calibrated vials), the pressure differential across the core, and thebrine breakthrough point. The data are used to calculate the relative permeabilitycharacteristics by using the Johnson, Bossler and Naumans technique.



The normal full test sequence is as follows:

(i) Miscibly clean core by flushing alternately with toluene and methanol; measure weightsaturated with methanol.

(ii) Saturate with formation brine without drying; measure weight saturated with brine.(iii) Measure Kew at Sw=1.(iv) Flood down to Swi at a suitable differential pressure.(v) Measure Keo at Swi.(vi) Carry out waterflood, recording pressure differential, incremental oil and water

production, etc. (data required for JBN analysis).(vii) Use JBN analysis to calculate Keo, Kew, Kro, and Krw for various Swout and Swav.(viii) Measure Kew , and calculate Krw at Sor before and after bump.(ix) Clean, dry, measure KL and φ.

Flooding down to Swi is carried out in a Hassler or other type of core holder fitted with acapillary pressure disc. This process may take several weeks, but has the advantage overcentrifuge techniques that even saturation distributions are obtained. Oil wet and intermediatesystems tend to flood to typically low values of Swi more rapidly, and at lower pressuredifferentials than water wet systems. Figures 10.9, 10.15 and 10.17 show example data forwater-, oil- and intermediate wet cores.

10.3.3 Oil-Brine Steady State Test Procedure

These differ from the unsteady state tests in that oil and brine are flowed simultaneouslythrough the test plug at a fixed ratio until equilibrium is attained, Figure 10.2 (constantpressure differential). The saturations were traditionally determined by demounting the plugand weighing, but are now done using one of the methods discussed at the end of section 10.1.The process is repeated with various oil/brine ratios, changing to suit the expected reservoirhistory, to build up complete relative permeability curves (e.g., Figure 10.19). The effectivepermeabilities are simply calculated using Darcy’s Law.

The disadvantages of steady state tests are that they are more time consuming both in man-hours and elapsed time than unsteady state floods. It usually takes at least 24 hours for eachflow ratio to equilibrate, but this can extend to 72 hours for low permeability samples orsamples made from several core plugs abutted to each other to form a long test sample.Estimation of saturation can be difficult for friable samples if grain loss occurs each time theplug is removed for weighing. The methods of measuring fluid saturations in situ overcomethis problem.

Steady state tests have the advantage that end effects (which can affect certain unsteady statetests) are eliminated. The test core is mounted between mixer heads made from adjacent corematerial. These have similar wetting characteristics to the test plug and allow the correct flowregime to fully establish itself before the test plug is entered. End effects then occur in theoutlet end piece instead of the test plug.



10.3.4 Gas-Brine Relative Permeability Tests

Unsteady state tests are most common due to difficulties handling injection of gas over longperiods in steady state tests. Consequently, this section will only deal with unsteady state gas-brine relperm tests. The drainage cycle, i.e. gas displacing brine, models gas injection into abrine saturated zone. Full relative permeability curves are generated and more importantly,gas permeability at irreducible brine saturation. The imbibition cycle models movement of agas/water contact into the gas zone. Imbibition tests cannot be set up to give the full relativepermeability curves, but do give brine permeability at trapped gas saturation and the actualtrapped gas saturation itself. Typical gas-brine drainage and imbibition data are shown inFigures 10.21 and 10.22.

The drainage test is performed by flowing gas (saturated with water vapour to ensure that thegas does not evaporate the brine) into a brine saturated plug. Incremental gas and brineproduction and pressure differential are recorded. Relative permeability curves can then becalculated using JBN analysis.



Figure 10.22 Gas/Brine Relative Permeability Data

PlugCode

KL,mD

Drainage Imbibition

Kew atSw=100% mD

Keo atSwi,mD

Kro atSwi,mD

Sw atEnd of

Test

Sg atend ofTest

Kew atSgi, mD

Krw atSgi, mD

Sg at endof test

Sw atend of

test

3 12.8 4.3 5.2 1.21 0.38 0.62 0.21 0.05 0.53 0.475 411 165 87 0.53 0.42 0.58 1.48 0.01 0.19 0.81

12 103 50 44 0.88 0.21 0.79 1.05 0.02 0.48 0.52

Imbibition data are obtained by recording the pressure differential across the core as brine isflowed into the test plug initially at S=Swi+Sg. As the initially dominant gas phase is replacedby more viscous water, the pressure differential rapidly increases to a maximum. It then fallsslowly as gas dissolves in the flowing brine. This dissolution is unavoidable to some extent,but can be reduced by equilibrating the injected brine with the gas at pressure prior toinjection. It should be noted that the injected brine will not completely displace the gas, and atrapped gas saturation will always remain. The maximum pressure differential is recorded andused to calculate Krw at residual (trapped) gas saturation. Krw at trapped gas saturation can besurprisingly low, values of 0.02 to 0.1 being frequently recorded.

It is interesting to consider the reservoir situation which is slightly, but significantly, differentfrom the laboratory technique. In the reservoir water migrates into the gas zone as pressuredeclines, but unlike the core test, the gas saturation does not necessary decline. It tends toremain high or increase slightly, since the trapped gas expands as pressure falls. Thismaintenance or even increase in Sg tends to keep Krw low or reduce it even further. Thisscenario operates in many reservoirs even if some of the gas migrates onwards and upwards.

10.3.5 Gas-Oil Relative Permeability Tests

Unsteady state tests can be performed in both drainage and imbibition modes. The drainagemode (gas displacing oil) models gas advance into an oil zone, and usually yields full relpermcurves. The imbibition cycle provides data for an oil zone advancing into a gas cap but onlyend point permeability and trapped gas saturation are obtained. It is worth considering themechanism occurring as an oil reservoir is depleted to a pressure below its bubble point. Theprocess which occurs is represented in Figures 10.23, 10.24 & 10.25.

(i) Referring to Figure 10.23. Initially gas forms in discrete, immobile bubbles, whichreduces Kro very significantly.

(ii) Figure 10.24. As pressure falls further, the gas saturation increases. The bubbleseventually become connected and give rise to a significant gas permeability. Thesaturation at which gas becomes mobile is termed the critical gas saturation. Krg rapidlyincreases and Kro further declines. The relative flow rate of oil is further reduced by thelower viscosity and higher mobility of the gas.

(iii) Figure 10.25. Eventually the oil droplets become discontinuous and only gas isproduced.



Laboratory gas-oil relative permeability tests are performed in a similar manner to the gas-brine tests. If required, the tests can be performed with connate water present, but thisrequires that brine saturated cores be flooded to Swi with oil prior to gas flooding. The relativemerits of tests with and without connate water have not yet been fully investigated. It can beargued that the connate water will be immobile and this has been found to be true in someexperiments. However, where connate water is present we have noticed that Krg tends toshow a more concave upwards curve than when it is absent. The situation is very complex,but could possibly be affected by the wetting characteristics of the rock. The effect is shownin Figures 10.26 & 10.27.

10.3.6 Relative Permeability Data Treatment

Interpretation and use of relative permeability data to predict individual well or reservoirperformance can be complicated by lateral variations in rock properties. Thus, although thelaboratory tests can adequately describe the behaviour of a particular test plug, modelling of awell or reservoir performance may require modified relative permeability data. Correlationsof overall curve shape, cross-over points, recovery at a given produced volume, brinepermeability at residual oil saturation etc., must all be made with reference to lithology,permeability, and initial fluid saturations.

Choice of test method will be governed by application of data, i.e. high flow rate for near thewell bore, and low flow rates away from the well bore. As stressed previously, no one testmethod can fully describe a system and choice of data will be influenced by laboratory scalelimitations; in particular, end effects in oil wet cores and problems sometimes caused bywettability alterations and mobile fines.

Good petroleum engineering reports should highlight any experimental difficultiesencountered and indicate the most reliable data. However, it is often impossible to assessservice company data since flow rates are seldom constant and ∆p/∆pi versus Qi curves are notreported. If you are ever in a position to commission this type of work, ensure that provisionof this information is part of the contract.

Formation Evaluation MSc Course Notes Commissioning Studies


Chapter 11: Commissioning Studies

11.1 Introduction

It is not easy to specify RCAL and SCAL programmes on a general basis. Each reservoir (orwell) has to be considered on its own merits. The numbers of each particular test requiredwill depend on the permeability/porosity distribution. The range of tests required will dependon previous experience with the particular reservoir rock/fluid combination under study.Where previous experience is available and there is good agreement between routine coreanalysis, log and well performance data, the numbers of tests and possibly scope can bereduced. Where anomalies exist it will be advantageous to increase coverage of someparameters and possibly introduce special test sequences to assess the more unusual core andfluid interactions connected with formation damage.

The more common reservoir situations encountered are summarised below. In each case it isthe SCAL that has been concentrated upon. Routine core analysis commissioning is usuallydone by internal protocol. For example, plugging every foot wherever the strength of the corefabric allows it, basic chemical cleaning, and then He porosity and gas permeability on thecore plugs. Sometimes Hg porisimetry, CT scanning and petrographic analyses are alsocarried out on a small number of plugs.

When commissioning a SCAL study the FIRST step is to review ALL the RCAL data thathas already been obtained. The RCAL information effectively provides a pre-study that willhelp identify possible problems in carrying out the SCAL work. These problems may include(i) swelling clays, (ii) friable and unconsolidated core, (iii) drilling fluid contamination, (iv)mobile fines, etc.

Also, it is important to seek the technical advice and expertise of:

v Anyone with experience of the rock properties for the field in question.v The technical staff and managers carrying out the work.v Any other individual or source that may provide data that could help save expensive

mistakes.

Remember time is money, but if corners are cut such that the real requirements are not welldefined, or data that you already have is not used, or possible problems with the rocks are notrecognised, then more money will be wasted. SCAL data is very expensive to collect. Hence,ask yourself the following points during SCAL commissioning:

1. What data do you have already from RCAL?2. What other knowledge is there that you can draw upon?3. What is the type of field, drive and hydrocarbon?4. What do you want to do with the SCAL data?5. Will your projected SCAL campaign provide sufficient data for the purpose it was

designed - Is it fit for purpose?6. Is there any information that would be missing? If it is required, commission it!7. Is there a specified test that will not tell you any further information concerning the field?

If there is drop it!



8. Have you commissioned sufficient cores of each type of test to provide a reliable andrepresentative coverage of the well section of interest? If you do not know how to judgethis, get advice!

9. Does the data you have flag any possible problems with the particular rock to be analysed?If there are problems you must talk to the people carrying out the tests. They should bewarned of problems, and in most cases will be able to advise you on the best technicalapproach to either overcome, avoid or minimise the problem.

10. Does the service company know your needs sufficiently well to provide good andinformed service? Good communications leads to better data!

11. Have you asked the service company managers and technical staff for their expert advice?12. Do you know the timescale for the scheduled work, and is it fixed? If not fix it – SCAL

tests are of known duration and can be scheduled well.13. Have you specified the errors that are acceptable on the measurements? To do this you

will need to communicate with the service company. Ensure that measurement errors,which always occur, are sufficiently small or manageable that the data is fit for purpose.

14. Have you specified the data to be provided in a format that will the of best use to you, i.e.,on CD-ROM in Excel format as well as a written report?

A little time spent planning can save an enormous amount of money.

11.2 Dry Gas Reservoirs

These represent the simplest case but the relative importance of the suggested tests (Figure11.1) will depend upon the nature of the reservoir. Particular care should be taken with highlyfractured reservoirs where gas/brine contacts move rapidly. Measurement of trapped gassaturation is particularly important here. With sandstone reservoirs brine permeability in thewater zone may be significantly lower than indicated by routine measurements. This can bereadily assessed from a relatively small number of tests on preserved water zone cores.



Figure 11.1 Basic SCAL Programme for a Dry Gas Reservoir 100’Thick with a Single Facies Type

Test Sequence Number ofTests

Proposed

TypicalCharge perTest (Man-

hours)

1 Drill, trim and clean by flushing as many plugs as areobtainable from preserved core (up to 60)

As required -

2 Capillary pressure (air-brine)Resistivity indexSaturation exponentFormation factorCementation factor

10-20 15

3 Formation factor at overburden pressurePore volume compressibility at overburden pressureBrine permeability at overburden pressure

10-20 12

4 Ambient condition relative permeability gas floodsDrainage and imbibition cycles

10 30

5 Water zone permeabilitiesBrine permeabilities of preserved core - plug samples

5 6

6 Clean by routine methodsRoutine porosity (He method)KL gas permeability

As required -

7 Plug description, thin section, and SEM studies to linkSCAL properties with sedimentological characteristics

As required -

Typical cost 700-1000 man-hours(approximately £800,000)

11.3 Oil Reservoir without Gas Cap

The situation with oil reservoirs becomes more complex than a dry gas reservoir as:

(i) Transition zones are usually from a more significant portion of the reservoir.(ii) Flow characteristics and relative permeabilities are strongly influenced by wettability.

The static tests, i.e. capillary pressure, resistivity index, formation factors etc., are basicallystraightforward, (Figure 11.2). However, dynamic tests, i.e. relative permeability, are morecomplicated, and choice of type and test mode depends upon wettability. Wettabilitymeasurements should be considered as an essential preliminary to choice of relativepermeability test. If waterflooding is envisaged then wettability is extremely important, aswill be water zone brine permeabilities on preserved core.



Figure 11.2 Basic SCAL Programme for an Oil Reservoir 100’ Thickwith a Single Facies Type

Test Sequence Number ofTests

Proposed

TypicalCharge perTest (Man-

hours)

1 Drill, trim and clean by flushing as many plugs as areobtainable from preserved core (up to 60)

As required -

2 Capillary pressure (air-brine)Resistivity indexSaturation exponentFormation factorCementation factor

10-20 15

3 Formation factor at overburden pressurePore volume compressibility at overburden pressureBrine permeability at overburden pressure

10-20 12

4 Wettability tests on preserved and cleaned core 6 155 Ambient condition relative permeability tests

(mode chosen depending on wettability measurements)10-15 30

6 Reservoir condition waterfloods. Possibly in preferenceto (5 above) depending on the characteristics of thecore

Up to 6 120

7 Water zone permeabilitiesPore throat size distribution measurements by mercuryinjection

5 10

8 Clean by routine methodsRoutine porosity (He method)KL gas permeability

As required -

9 Plug description, thin section, and SEM studies to linkSCAL properties with sedimentological characteristics

As required -

Typical cost 700-1700 man-hours(approximately £1,400,000)

11.4 Oil Reservoir with Gas Cap

The static tests are basically the same as for 11.2 above. Choice of dynamic relativepermeability tests will depend upon the expected movement of oil/water and gas/oil contacts.If expansion of the gas cap into the oil zone is envisaged, gas-oil relative permeability atconnate water tests are desirable. Similarly if the reservoir is being waterflooded for pressuremaintenance or to reduce gas cap size; the imbibition gas/oil test will provide valuable data onoil permeability at trapped gas saturation and the trapped gas saturation itself.



11.5 Gas-Condensate

The flow regimes and saturation changes which occur in condensate reservoirs are among themost difficult to model in the laboratory, and are extremely rare.

11.6 Formation Damage

The term formation damage generally describes permeability reduction brought about by:

(i) Movement of fines.(ii) Introduction of particulate matter.(iii) Introduction of incompatible fluids.(iv) Introduction of fluids upsetting desired relative permeability behaviour.

It is especially difficult to specify a general scheme of formation damage tests. The particularreservoir fluids, minerals, saturation change directions, and introduced fluid compositionsshould be considered when defining a programme. Two situations will therefore be brieflycovered which illustrate the means of damage detection and the applicability of single and twophase tests. The cases considered here are poor and declining injectivity in a water injectionwell, and formation damage caused by drilling muds.

11.6.1 Poor and Declining Injectivity

The possibilities here are:

(i) Particulate matter in injection water.(ii) Mobile fines within reservoir rock.(iii) Incompatible waters causing clay swelling.

These processes can be tested for by the following methods:

(i) The problem of particulate matter in injection water should be taken care of by properfiltration but could be tested for with on site core tests. The tests however tend to bepessimistic and indicate greater permeability decline rates than are encountereddownhole.

(ii) The presence of mobile fines can be detected fairly readily in the laboratory.Permeability to liquids (brines) are observed and plotted against throughput. Changesoccur with throughput and flow direction when fines move to block pore throats, Figure11.3.

(iii) The sensitivity of a formation to brine composition can be assessed by core throughputtests with changing brine compositions, Figure 11.3. Simple clay swelling effects areobserved as reversible permeability changes. However, it is possible that some particlesbecome dislodged during the tests and then behave as mobile fines.



10.6.2 Drilling Mud Formation Damage

A recent study indicated that single phase (liquid) permeability tests cannot necessarily berelied upon to predict formation damage for a two phase situation. Single phase testsindicated that oil based mud filtrate permeability was greater than for water based mud filtrate,implying permeability damage by the water based mud. However, when the mud filtrateswere displaced with gas, the effective gas permeabilities were the same in both instances. Thiscase has been simplified, as other factors, such as relative permeability, fluid saturations andvolume throughput required to achieve recovery of gas permeability; also need to beconsidered when interpreting the permeability data.

Formation Evaluation MSc Course Notes Abbreviations

Dr. Paul Glover Page i

Abbreviations

A Cross sectional areaB Specific Counterion Activity (Waxman-Smits)Cp Capillary PressureFF,F Formation factorE Tortuosity factorHt Producing zone thicknessKbrine Brine permeabilityKg Gas permeabilityKL Equivalent liquid permeability (Klinkenberg corrected gas permeability)Ko Oil permeabilityKeo Effective oil permeabilityKr Relative permeabilityKro Relative permeability to oilKrw Relative permeability brineKSFW Permeability to simulated formation waterKw Brine/water permeabilityKew Effective brine/water permeabilityl , L Lengthm Cementation factorm* Cementation factor (corrected)Mr Mobilityn Saturation exponentn* Saturation exponent (corrected)P, p PressurePc Capillary pressure (psi)Pd Drawdown pressurePm Mean flowing pressureQo Volume oil producedQi Volume water injectedQv Cation exchange capacity meq/mlQw Volume water producedRe Effective reservoir radiusRCAL Routine core analysisRelperm Relative PermeabilityRo Core resistivityRw Brine resistivity (or wellbore diameter)Rt Core resistivity at reduced Sw

SCAL Special Core AnalysisSo Oil saturationSor Residual oil saturationSgt Residual trapped gas saturationSw Brine saturationSwi Initial brine saturationt Time (secs)

Formation Evaluation MSc Course Notes Abbreviations

Dr. Paul Glover Page ii

Abbreviations continued

V, v Volumeγ Interfacial tensionλ Mobility ratioθ Contact angleφ Porosityρο Oil densityρω Brine densityµο Oil viscosityµω Water (brine) viscosity

Formation Evaluation MSc Course Notes Selected References

Dr. Paul Glover Page iii

Selected References

[1] Permeability Characteristics of Magnus Reservoir Rock. Heaviside, Langley and Pallatt, 8th FormationEvaluation Symposium Trans. Mar. 1983. London.

[2] Errors in Laboratory Measurements of Formation Resistivity Factor”, by A.E. Worthington. S.P.W.L.A.16th Annual Logging Symposium 4-7 June 1975.

[3] Comments on obtaining Accurate Electrical Properties of Cores, by Hoyer, S Spann. S.P.W.L.A. 16thAnnual Logging Symposium 4-7, June 1975.

[4] Calculation of Relative Permeability from Displacement Experiments, Johnson, Bossler and Nauman, Pet.Trans. AIME (1959), 216, p.370.

[5] EHRLICH, R., CRABTREE, S.J., HORKOWITZ, K.O. & HORKOWITZ, J.P. 1991. Petrography andreservoir physics 1: objective classification of reservoir porosity. The American Association of PetroleumGeologists Bulletin, 75, 1547-1562.

Abstract: Porosity observed in thin section can be objectively classified using a combination of digitalacquisition procedures and pattern recognition algorithms. Pore types are derived from the frequencydistributions of sizes and shapes of patches of porosity exposed in thin section. Each pore type isrepresented by a characteristic distribution of sizes and shapes found in thin section. Most sandstonereservoirs contain fewer than six pore types. Much of the variability in reservoir physics is associated withchanges in pore type abundance. The advantages of this approach to porosity classification are (1) thecriteria for classification are objectively defined, (2) classification procedure is rapid, accurate, andprecise, (3) pore types are understood easily in terms of conventional genetic classification schemes, and(4) pore type data are related strongly to petrophysical properties.

[6] MCCREESH, C.A., EHRLICH, R. & CRABTREE, S.J. 1991. Petrography and reservoir physics 2:relating thin section porosity to capillary pressure, the association between pore types and throat size. TheAmerican Association of Petroleum Geologists Bulletin, 75, 1563-1578.

Abstract: Porosity in reservoir rocks is configured into a few types of pores whose size and shape arecontrolled by depositional fabric and processes. The size, shape, and abundance of each pore type can beobjectively determined from thin section using image analysis and pattern recognition procedures. Eachpore type tends to be associated with a limited range of throat sizes. The association between pore typeand throat size can be determined using regression procedures linking pore type data obtained from thinsection with capillary pressure data. To do so, a set of samples is required wherein the association betweenpore type and throat size is fixed, but where pore type proportions vary between samples. This conditionis met by a sample suite representing reservoir facies from a single core or, in many cases, from a singlefield. The relationship between pore type and throat size is an effective means to relate reservoirs in termsof the efficiency of the porous to multiphase flow. Parameters derived from the relationship can be used toconstruct accurate physical models that subdivide physical response in terms of the contributions of eachpore type.

[7] EHRLICH, R., ETRIS, E.L., BRUMFIELD, D., YUAN, L.P. & CRABTREE, S.J. 1991. Petrographyand reservoir physics 3: physical models for permeability and formation factor. The AmericanAssociation of Petroleum Geologists Bulletin, 75, 1579-1592.

Abstract: Permeability and formation factor are physical properties of porous rocks useful for assessingreservoirs. Neither property varies consistently as porosity varies. The relationship of both properties toporosity is complex, being sensitive to the structure of the porous microstructure, i.e., the sizes of porethroats, the numbers and sizes of pores, and the relationships between pores and throats. Physical modelsto account for these factors require parameters that describe physically relevant properties of themicrostructure. A partial characterization of the relationship between pores and throats is embodied in therelationship between pore type and throat size. This relationship is derived by combining data obtainedfrom thin sections, from which pore types are derived via image analysis, and mercury injectionporosimetry, which quantifies throat size information. Parameters derived from such a combination are


Dr. Paul Glover Page iv

sufficient to construct simple physical models for permeability and electrical conductivity (inverseformation factor). These models assume a porous medium that has large numbers of flow paths parallel tothe potential gradient, such that flow has little tortuosity (i.e., flow parallel to bedding). The contributionsof each pore type to permeability and electrical conductivity are computed. Calculated values are close tomeasurement values. A constant of proportionality is the same for all samples from a reservoir, but canvary between reservoirs, is required, and must have values ranging (for sandstones) from about 2.5 to 3.5for permeability and 5.0 to 7.0 for conductivity. These values are consistent for an efficiently packedfabric. One result of such modeling is a physical model of Archie's cementation exponent m as the ratio ofthe logarithms of the cross sectional throat area to pore area (per unit area).

[8] WARDLAW, N.C. & TAYLOR, R.P. 1976. Mercury capillary pressure curves and the interpretation ofpore structure and capillary behaviour in reservoir rocks. Bulletin of Canadian Petroleum Geology, 24,225-262.

Notes: A classic on this subject. Explains the reasons behind various aspects of injection and withdrawalcurves, by looking at SEM of rocks studied.

[9] VAVRA, C.L., KALDI, J.G. & SNEIDER, R.M. 1992. Geological applications of capillary pressure: areview. The American Association of Petroleum Geologists Bulletin, 76, 840-850.

Notes: Important discussion of interpreting mercury injection porosimetry results.

[10] PITTMAN, E.D. 1992. Relationship of porosity and permeability to various parameters derived frommercury injection-capillary pressure curves for sandstones. The American Association of PetroleumGeologists Bulletin, 76, 191-198.

Notes: As mercury injection tests are expensive and not abundant, derives relationships using multipleregression on large database of samples. Empirical equations make it possible to construct pore apertureradius distribution curves from core analysis porosity and permeability.

[11] BLIEFNICK, D.M. & KALDI, J.G. 1996. Pore geometry: control on reservoir properties, Walker Field,Columbia and Lafayette counties, Arkansas. The American Association of Petroleum Geologists Bulletin,80, 1027-1044.

Notes: An oolite carbonates sequence. Useful discussion on interpreting mercury injection porosimeteryresults.

[12] RINGROSE, P.S., SORBIE, K.S., FEGHI, F., PICKUP, G.E. & JENSEN, J.L. 1993. Relevant reservoircharacterisation: recovery process, geometry and scale. In Situ, 17, 55-82.

Notes: With miscible-gas flood, large-scale geometry may be more important than the internal small-scalestructure. With waterflood, small-scale structure likely to be dominant. Emphasises must think not onlyabout the rock but also the fluids and the recovery process.

[13] CORBETT, P.W. & JENSEN, J.L. 1993. Quantification of variability in laminated sediments: a role forthe probe permeameter in improved reservoir characterization. In: NORTH, C.P. & PROSSER, D.J. (eds)Characterization of fluvial and aeolian reservoirs. Geological Society special publication 73, London,433-442.

[14] HUANG, Y., RINGROSE, P.S. & SORBIE, K.S. 1995. Capillary trapping mechanisms in water-wetlaminated rocks. SPE Reservoir Engineering, 10, 287-292.

Abstract: Most floods in sandstone cores are performed either in almost homogeneous samples or else incore samples of uncertain heterogeneity. As a result, the interaction of small-scale sedimentaryheterogeneity with the fluid mechanics of water-oil displacement cannot be adequately understood orquantified. The results are reported from low-rate, drainage-imbibition floods in a 20 x 10 x 1 cm slab orcross-laminated heterogeneous sandstone. The laminated aeolian sandstone was characterized by detailed


Dr. Paul Glover Page v

probe permeameter mapping prior to setting it in a resin cast. The distribution of porosity, permeability,irreducible water, and residual oil saturation were subsequently monitored using CT scanning techniques.The low-rate imbibition floods show that between 30 and 55% of original oil may be trapped in isolatedhigh permeability lamina. This work shows the importance of recognizing the role of core-scaleheterogeneity in the laboratory measurement of waterflood behavior, i.e., the interaction of capillaryforces with rock structure. The practice of performing high-rate floods on rock samples assumed to beheterogeneous is unwise and can lead to erroneous conclusions. The work has major implications for (1)2-phase petrophysical measurements, (2) the assessment of residual/remaining oil, and (3) multiphase flowscaleup.

[15] MCDOUGALL, S.R. & SORBIE, K.S. 1992. Network simulations of flow processes in strongly wettingand mixed-wet porous media. In: CHRISTIE, M.A., DA SILVA, F.V., FARMER, C.L., GUILLON, O.,HEINEMANN, Z.E., LEMONNIER, P., REGTIEN, J.M.M. & VAN SPRONSEN, E. (eds) ECMOR III:Proceedings of the third European conference on the mathematics of oil recovery. Delft University Press,Delft, Netherlands, 169-181.

Notes: Deriving 2-phase flow parameters such as relative permeability and capillary pressure frommicroscopic considerations.

[16] MCDOUGALL, S.R. & SORBIE, K.S. 1995. The impact of wettability on waterflooding: pore-scalesimulation. SPE Reservoir Engineering, 10, 208-213.

[17] PICKUP, G.E., RINGROSE, P.S., JENSEN, J.L. & SORBIE, K.S. 1994. Permeability tensors forsedimentary structures. Mathematical Geology, 26, 227-250.

Abstract: Accurate modeling of fluid flow through sedimentary units is of great importance in assessingthe performance of both hydrocarbon reservoirs and aquifers. Most sedimentary rocks display structurefrom the millimeter or centimeter scale upward. Flow simulation should therefore begin with grid blocksof this size in order to calculate effective permeabilities for larger structures. Several flow models forsandstones are investigated, and their impact on the calculation of effective permeability for single phaseflow is examined. Crossflow arises in some structures, in which case it may be necessary to use a tensorrepresentation of the effective permeability. Conditions are established under which tensors are required,e.g., in crossbedded structures with a high bedding angle, high permeability contrast, and laminae ofcomparable thickness. Cases where the off-diagonal terms can be neglected, such as in symmetricalsystems, are also illustrated. The method of calculating tensor permeabilities may be extended to modelmultiphase flow in sedimentary structures.