formation evaluation by 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 (2.510-6 to 510-6 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 (AB) 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 (BC) 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 (CD).The pistons in Figure 2.1 demonstrate the changes in fluid phase schematically. It is worthnoting that the process ABCD 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 DCBA.



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, gAPI,oAPI

- 65.0 48.5 36.7 23.6

C7+ SpecificGravity, go

- 0.750 0.816 0.864 0.920

Note: Fundamental specific gravity go 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 gravitygAPI is defined as; gAPI = (141.5/go) - 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 60C, 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:

f = = =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 mm) 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 (birds-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 100mm, and for some recent sediments porosities up to 0.8 have been measured. As grain sizeincreases past 100 mm, 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 r is known, then thedifference in weight is r 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 Boyles 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.. BoylesLaw 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

Formation Evaluation MSc Course Notes

formation evaluation by paul glover

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