Chap 3 Core Damage

8/12/2019 Chap 3 Core Damage

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Chap 3 Core Damage.DOC Special Core Analysis

CONTENTS : CHAPTER 3

1. INTRODUCTION 1

2. FLUID SATURATION ALTERATION 2

2.1 During Coring 2

2.2 During Core Retrieval 3

2.3 At the Wellsite/Laboratory 4

3. ROCK TEXTURAL PROPERTY DAMAGE 8

3.1 Stress Damage 8

3.2 Unconsolidated Core 9

4. WETTABILITY ALTERATION 13

4.1 Wettability Definition 13

4.2 Native Wettability and Controls 14

4.3Wettability Alteration 154.3.1 Contact With Drilling Mud 164.3.2 Pressure and Temperature Loss on Core Recovery 164.3.3 Oil Oxidation 174.3.4 Core Cleaning 174.3.5 Core Testing 184.3.6 In Situ Wettability Estimation 184.3.7 Laboratory Measurements 18

5. CLAYS AND CLAY DAMAGE MECHANISMS 22

5.1 Clay Structures 22

5.2 Clay Morphology and Rock Property Controls 245.2.1 Rock Property Alteration 24

6. REFERENCES 28


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Chap 3 Core Damage.DOC Special Core Analysis

FIGURES CHAPTER 3

Figure 2-1: Saturation Alteration WBM in Oil Reservoir ..................................................... 5

Figure 2-2: Saturation Alteration WBM in Gas Reservoir .................................................... 5

Figure 2-3: Saturation Alteration OBM in Oil Reservoir ...................................................... 6

Figure 2-4: Conventional Core Bit............................................................................................ 6

Figure 2-5: Low Invasion Core Bit ...........................................................................................7

Figure 3-1: Foam Stabilisation of Unconsolidated Core (Courtesy Kirk Petrophysics)......... 10

Figure 3-2: Liquid Nitrogen Plugging.....................................................................................11

Figure 3-3: Example Unconsolidated Plug Assembly ............................................................ 12

Figure 4-1: Wettability Concepts ............................................................................................ 19

Figure 4-2: Cryogenic SEM Photomicrograph ....................................................................... 19

Figure 4-3: Effects of Oil-Based Mud on Spontaneous Imbibition (Bobek13) ........................ 20

Figure 4-4: Effects of Oil-Based Mud on Spontaneous Imbibition (Stiles14

).......................... 20

Figure 4-5: Core Preservation Cylinder (Corex)..................................................................... 21

Figure 4-6: Idealised Free Water Level Contact Relationships ...........................................21

Figure 5-1: SEM Photomicrograph - Illite .............................................................................. 25

Figure 5-2: SEM Photomicrograph Kaolinite ...................................................................... 25

Figure 5-3: SEM Photomicrographs - Chlorite ....................................................................... 26

Figure 5-4: Neashams Categories of Authigenic Clays.........................................................26

Figure 5-5: Typical Poroperm Relationships (from Neasham)............................................... 27

Figure 5-6: Typical Capillary Pressure Relationships (from Neasham) ................................. 27


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Chap 3 Core Damage.DOC Special Core Analysis Page 2

2. Fluid Saturation Alteration

2.1 During Coring

In an oil or gas reservoir, the fluid distribution (water and oil or gas) saturation will be

controlled by capillary pressure. During coring with either an oil-based mud (OBM) or

water-based mud (WBM) system, mud filtrate will enter the pore system of the rock as it is

being cored, altering the initial volumetric and spatial fluid distribution. The degree of mud

filtrate invasion will depend upon coring bit design, drilling rate, the rheological properties of

the mud, and the rock properties such as porosity, capillary pressure, wettability, and both the

absolute and relative permeability. Figure 2-1,Figure 2-2,andFigure 2-3provide schematic

representations of the changes in saturation that occur during coring for both oil and gasreservoirs.

For example, when drilling with a WBM in the irreducible water zone (oil leg), the relative

permeability to WBM filtrate at high oil or gas saturations will be low and so the amount of

fluid flushing might be small. However as the overbalance increases, filtrate enters the core

and the water saturation increases, so it is easier for WBM to invade deeper into the core as

the relative permeability to water increases. This will result in oil being flushed from the

core towards residual oil saturation. On core recovery, gas in the oil expands and drives off

both oil and invaded WBM filtrate. So the oil and water may be reduced towards residual

saturation. WBM flushing in the water leg may result in partial or complete replacement of

the connate water with filtrate. There is always a limited amount of gas dissolved in theformation water, which will expand and drive off some water on core recovery. If the core is

oil wet, WBM invasion may be restricted, especially in low permeability formations.

In gas reservoirs, drilled with WBM, similar processes apply. WBM filtrate will flush the

core towards residual gas saturation. Gas expands on core recovery, displacing the WBM

filtrate towards residual water saturation.

When drilling with an OBM in the irreducible water zone of a water-wet gas or oil reservoir

rock, the relative permeability to OBM filtrate will be high so that OBM may be able to

thoroughly flush the core. However, since the water is at immobile saturation, the water

saturation should remain unaltered unless surfactants in the mud system lower the interfacial

tension between oil and water and result in mobilisation of irreducible water, or the core isallowed to dry out. In the absence of IFT effects, the irreducible water saturation in the core,

measured at surface, will be the same as that in the reservoir before coring. In the water leg

and towards the base of the transition zone, OBM filtrate is expected to drive the water

towards residual saturation. Gas expansion on core recovery will also drive off OBM filtrate

and mobile water. The result is that core saturation measurements at surface conditions will

show little difference between oil leg and water leg samples.

In the transition zone through the water zone, the relative permeability to oil will be low, so

OBM filtrate invasion will be restricted. However, if the mud pressure is sufficiently high

(overbalance drilling) filtrate will be forced into the pore system.


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The coring penetration rate also controls the degree of invasion. The faster the core enters

the barrel, the less invasion it undergoes, apparently regardless of mud system type.

When drilling with conventional core bits (e.g. Figure 2-4)filtrate invasion occurs ahead of

the bit (filtrate bank), in the throat of the bit and in the core barrel (static invasion) duringcoring and core recovery. The bit cutters cut into the external and internal filter cakes

thereby exposing the formation to rapid filtrate intrusion which can result in a complete

flushing of the core with filtrate. OBM filtrate also damages the native wettability.

To minimise filtrate invasion, low invasion core bits are often used (Figure 2-5). These cut

as fast as possible without breaking the formation apart and direct the flow discharge away

from the core, rather than towards it. The cutters are designed to produce a deep cut that

removes the initial filtrate spurt. The faster penetration rate reduces the core exposure time,

and the core head is designed to sweep mud away from the core.

The amount of invasion within the core can be established by doping the coring fluid with

tracers such as deuterium oxide 1, tritium, or potassium bromide. The latter is also used to

dope mud to determine mud invasion in RFT/MDT samples and can also be conveniently

used to determine mud invasion in core. Subsequent fluid extraction measurements on

recovered core samples (e.g. Dean-Stark for a WBM system) can determine the amount of

tracer per unit volume of fluid in the core and so quantify the amount of invasion and

potential fluid and rock property alteration.

As discussed in the previous chapter, the use of an encapsulated gel coring system cal also

help to reduce invasion.

2.2 During Core Retrieval

As the core is brought to the surface, the hydrocarbon fluid will expand and, in an oil

reservoir, gas will be liberated when the oil is brought below the bubble point. Gas liberation

or expansion provides a force which will cause displacement of both the native fluids and the

invaded mud filtrate. Subsequent extraction saturation measurements of water and/or oil

saturation in an oil reservoir core will therefore indicate a gas saturation, even although there

may be no gas cap in the reservoir. Depending upon the magnitude of driving force and the

formation wettability, water, for example, can be driven back towards irreducible saturations,

so that subsequent water saturation measurements may be close to the reservoir value.

If an OBM has been used, hydrocarbon expansion will not affect the water saturation in the

irreducible water zone, since no amount of pressure should be able to mobilise the water.However, if the OBM had a high surfactant concentration, this can reduce the interfacial

tension between oil and water, so that the irreducible water might now be mobilised, reducing

the water saturation.

Gas evolution can cause mechanical damage to cores from loosely consolidated formations,

but this can be minimised by pulling the last few hundred feet of the core barrel string very

slowly.

The use of pressurised core barrels and sponge coring provides a means to prevent loss of oil

from the core on hydrocarbon expansion on core recovery or to retain the moveable oil

normally lost to the mud system on coring and core recovery.


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Both sponge core and pressurised core barrels are often used to determine oil-in-place in

depleted zones prior to improved oil recovery project evaluation.

2.3 At the Wellsite/Laboratory

At the surface at the wellsite, or back in the laboratory, unprotected core is exposed to air.

Consequently the saturation in the core can be altered through evaporation. Preserving the

core provides an opportunity to prevent further fluid loss as well as other forms of core

damage. The use of liners can aid in preventing fluid loss as well as other forms of

mechanical and physio-chemical core damage.

End caps are placed over the each section of liner, so that exposure of the core to air and fluid

loss are minimised during wellsite operations and transportation to the laboratory.

If the rock is competent, the core can usually be easily pushed out of aluminium or fibreglass

liners. However if the rock is weak, extracting the core will result in unacceptabledisturbance, so in this case, plug samples are often taken through the liner prior to removing

the core, and the liners must be carefully cut open to reveal the core.


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Water

30%

Oil

75% 25%

Oil Gas

15%

Water Oil Water

Gas Water

75-90 %

Water Water

Reservoir

Water Zone Filtrate Invasion Core RecoverySurface

Oil Shrinks

Gas Expands

Figure 2-1: Saturation Alteration WBM in Oil Reservoir

Gas

70% 30%

Gas Water

30%

Water Gas Water

Gas Water

70-95 %

Water Water

Reservoir


Gas Expands

Figure 2-2: Saturation Alteration WBM in Gas Reservoir


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Oil

75% 25%

Oil Gas Swi

25%25%

Swi Oil Swi

Gas Water

30%

Water Water

Reservoir


Oil Shrinks

Gas Expands

25%

Oil

35 %

Oil

30%

Figure 2-3: Saturation Alteration OBM in Oil Reservoir

Figure 2-4: Conventional Core Bit


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Figure 2-5: Low Invasion Core Bit


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3. Rock Textural Property Damage

Rock texture is defined as those properties that are concerned with grain to grain

relationships. The major textural properties that are of concern in core analysis include:

Grain size

Grain sorting

Grain shape/roundness

Grain orientation/packing

Diagenesis

These textural properties not only have an impact on the basic rock properties such as

porosity and permeability, but influence core electrical properties, pore size distribution and

capillary pressure data, rock compressibility, fluid distribution and fluid flow behaviour. By

virtue of their structure and location within the rock pore network, clays can be easily

damaged and the rock properties readily altered.

3.1 Stress Damage

During coring, at some distance below the coring bit, the vertical stress starts to reduce as the

bit is approaching from above, with little or no change in the horizontal stress. When the bit

comes closer, and as the core is drilled free from the surrounding rock, the horizontal stress isalso released. Depending upon the shape of the core bit, there will be a zone of compression

underneath the teeth of the bit and a zone of vertical tension around the external side of the

core, just above the bit.

Stress release causes the grains to relax increasing both the pore volume and bulk volume

leading to an increase in porosity. As the pore space increases on stress release so the

permeability increases. This porosity and permeability measurements on core plugs

recovered at surface will be higher than those at reservoir conditions under reservoir

appropriate stress.

In addition and depending upon the rock strength characteristics, tensile failure can also

occur as the stress is released. This leads to the formation of microcracks, and these crackswill be oriented in the direction perpendicular to the maximum in situ stress. If the stress

situation at some point exceeds the failure strength for the core, the rock may fail

macroscopically, often with a disced appearance2. If the stresses exceed the yield envelope

of the rock, permanent mechanical damage can occur, without necessarily causing visible

mechanical damage. Since it looks intact, the core will be used for petrophysical property

measurements but the results of these analyses may be invalid.

In low permeability rocks, the pore pressure is released more slowly than the lithostatic

stress. This implies that tensile failure may occur within the core as it is recovered. This is a

problem with high viscosity oils (slow fluid drainage) and in low permeability reservoirs (e.g.

chalk).


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sleeves at wellsite. It cannot be effectively used where the core has been retained by liners,

and would not be effective if the core has been damaged during coring or on handling of the

barrel at wellsite.

Foam or gypsum stabilisation techniques generally involve drilling holes (Figure 3-1)in theliner to allow for injection of the foam/gypsum and to permit expulsion of any remaining

drilling mud, which is pushed out ahead of the foam. Foam expands into the voids and down

the annulus encapsulating the core in a cushion of foam. The foam sets quickly and is non-

invasive and non-absorbent.

Figure 3-1: Foam Stabilisation of Unconsolidated Core (Courtesy Kirk Petrophysics)


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Care is also required when taking plug samples from unconsolidated core if sample

disturbance is to be avoided. There are two principal techniques used to plug unconsolidated

core:

liquid nitrogen drilling; and,

plunge cutting

Liquid nitrogen drilling is used where the core is too weak to survive conventional plugging.

Conventional drill press and core plug bit equipment are used but liquid nitrogen is used as

the coolant (Figure 3-2).

Figure 3-2: Liquid Nitrogen Plugging

The cores are then stored in specially designed coreholders under a nominal confiningpressure and allowed to thaw. Normally the plugs are cleaned in the coreholders by cold

solvent flushing. This eliminates one handling stage. If the technique is used in unfrozen

cores, contact with liquid nitrogen might cause damage to the plug material as a result of ice

formation.

Plunge cutting involves forcing a special core bit with a chisel edge into the rock then

extracting the sample by carefully twisting the bit. Provided the cutting edge of the plunge

cutting bit is designed to deflect the most of the force of penetration to the sides, away from

the downward direction, the force on the part of the core which will form the plug is

minimised. Plunge cutting is more successful in very poorly consolidated cores than in better

consolidated material which can fracture more easily.

Worthington et al7contend that plunge cutting avoids damage from frozen nitrogen which

causes grain rearrangement. Unalmiser8 and La Torraca

9 recommend that plugs should be

taken with a plunge cutter with the core sections chilled (not frozen) using liquid nitrogen.

Lamb and Ruth10

recommend rotary drilling with liquid nitrogen on cores frozen in the field.

The plug samples from unconsolidated cores must be protected against further disturbance

during core testing. Laboratory measurements are best made in a single loading operation.

Ideally, if liquid nitrogen plugging has been used, the measurements should be made on plugs

in the coreholders used for core thawing. Alternative protection includes mounting the plugs

in aluminium foil or thin tin (similar to the material used in toothpaste tubes) or nickel

sleeves. Foil tends to conform better to the plug surface than PTFE which can deteriorate


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during subsequent plug cleaning and testing. Metal sleeves cannot be used if the plugs are

scheduled for electrical properties testing.

A typical unconsolidated plug mount is shown in Figure 3-3. The plug sample is wrapped in

PTFE tape then inserted into a sheath of PTFE heatshrink tubing. Fine (100 mesh) thencoarse )16 mesh) steel gauzes or screens are placed at each end of the plug inside the PTFE

heatshrink. These protect the end faces and prevent grain loss on subsequent handling. The

assembly is then exposed to heat using a heat gun. This causes the heatshrink to contract and

bind the assembly together, protecting the plug. Excess heat shrink in then trimmed off.

Both the weight and volume of PTFE tape, heatshrink and gauze must be accounted for in

subsequent porosity measurements. These normally assume a density of PTFE of 2.20 g/cc

and 7.93 for steel. All trimmed materials must also be carefully weighed.

e.g. 38 mme.g. 38 mm

Ensure fits coreholderEnsure fits coreholder

TeflonTeflonHeatshrinkHeatshrinkjacketjacket

Plug SamplePlug Sample

Fine ScreenFine Screen

Figure 3-3: Example Unconsolidated Plug Assembly


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4. Wettabili ty Alteration

Wettability is a fundamental rock property that controls fluid distributions within porous

media. It is the result of a complex interaction of forces which are related to both the fluid

system type and the rock type, and has a major impact on capillary behaviour, core electrical

measurements, relative permeability tests and residual saturations. These will be

demonstrated ad nauseumthroughout the remainder of the SCAL course.

It is important to maintain the appropriate reservoir wettability conditions if core analysis

tests are to provide reliable results. Despite many studies on the effects of wettability on rock

properties measured in core analysis experiments, appropriate wettability conditioning is

frequently still ignored. Laboratories are quite happy to offer to carry out tests on fresh-

state or hot soxhlet cleaned cores knowing that the results of the tests may be whollyinappropriate.

4.1 Wettability Definition

Wettability is defined as "the tendency for one fluid to spread or adhere to a solid surface in

the presence of a second fluid". When a drop of water is placed on a glass slide immersed in

oil, it will form a contact angle, , with the slide of somewhere between 0 and 180 . By

convention, this contact angle is measured through the denser phase. If the slide has a

preference for water compared to oil, the water droplet will tend to spread (Figure 4-1) so

that the contact angle is low. This system is said to be preferentially water-wet. The

adhesion force (or tension, At) is a function of the interfacial tension (IFT) between the oil

and water system and the contact angle. i.e.:

coswot

A

=

where:

o-w: IFT (dyne/cm or mN/m)

: contact angle

Suppose the glass slide is made to be non water-wet by some form of treatment. Now, oil

tries to contact the glass slide but water gets in the way. Consequently since water has no

tendency to spread, the water droplet forms a ball and the contact angle exceeds 90 . In thiscase water is said to be non-wetting.

In a rock/oil brine system many wetting states are thought to occur. Some of these are:-

Water-wet: Where water coats the grains and may fully occupy the smaller

pores. Oil would occupy only the centre of the larger pores.

Oil-wet: Where the reverse of the above is the case and oil coats the grains

and occupies the smaller pore spaces.

Neutrally-wet: Where the system has a uniform non-preference for oil or water


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Fractional wettability: Where certain areas of the rock (minerals) have a strong preference

in one direction, while other areas (minerals) have a strong

opposite preference (e.g. calcite-cemented quartz sandstone)

Mixed wettability: A special case of fractional wettability in which oil-wet surfacesform a continuous path through the larger pores although water

continues to occupy the smaller pores. This wetting state is

probably unproven but does allow very low residual oil

saturations, and some unusual relative permeability behaviour to

be explained.

In the reservoir condition, wettability can also be visualised through the use of cryogenic

SEM in which a specimen of rock at reservoir appropriate saturation is mounted onto a brass

SEM stub then rapidly plunged into nitrogen slush under a low vacuum in a sealed chamber.

The sample is cryogenically frozen and examined in the SEM chamber which is equipped

with a cryogenic stage. Figure 4-2 provides an example of a cryogenic SEMphotomicrograph which shows droplets of brine (surrounded by oil) adhering to quartz

grains. The contact angles vary though most are between 30 to 80 indicating a weakly

water-wet rock, possibly mixed wettability rock.

4.2 Native Wettability and Controls

It must be accepted that the process of obtaining the core, and subsequent core processing

and handling, will alter the rock wettability so that it is almost impossible to be certain of the

true reservoir wettability state.

Before oil migrates into the reservoir, the rock can only be water-wet, by definition. It mightalso be expected that, in a virgin reservoir, depending upon the rock mineralogy and reservoir

fluids, wettability might grade towards a less strongly water-wet state through the transition

zone, possibly becoming non water-wet in the irreducible water zone. A number of studies

have been carried out which indicate that most reservoirs are not strongly water wet.

Treiber et al11studied rock wettabilities from 50 reservoirs. They classed wettability on the

basis of contact angles, and the results were.


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Contact

Angle

Silicate

Reservoirs

Carbonate

Reservoirs

Total

Reservoirs

Water wet 0 - 75 13 2 15

Inter wet 75 - 105 2 1 3

Oil wet 105 - 180 15 22 37

Chilingar and Yen12studied the wettabilities of carbonate formations. Their results were:

Contact

Angle

% of

Reservoirs

Water wet 0 - 80 8

Inter wet 80 - 100 12

Oil wet 100 - 160 65

Strongly oil wet 160 - 180 15

The results may be biased however. Tests on fresh-state core (especially drilled with OBM)

or on unpreserved core may indicate an oil-wetting tendency. Very few sandstone reservoirs

are truly oil-wet.

The original wettability of reservoir rock is controlled by a number of factors including:

Oil type. Adsorption of polar compounds and surfactants, and deposition of organicmatter from the crude oil can induce strong oil-wetting tendencies;

Brine chemistry. High brine pH, or a high concentration of divalent cations in theformation brine, can promote surfactant adsorption on the rock surfaces, resulting in an

oil-wetting tendency.

Grain type. Carbonates tend to be more oil wet than silicate grain surfaces. This isrelated to the surface charge of the minerals and the nature of the oil and brine surrounding

them. Generally, under similar fluid conditions, adsorption of asphaltenes on silica

surfaces (which can lead to oil-wetting) are an order of magnitude less than adsorption of

asphaltenes on carbonates. Recent evidence points to many clays (e.g. Kaolinite) being

oil-wet.

4.3 Wettability Alteration

Native reservoir wettability estimates from reservoir core samples can be further complicated

as a result of interactions between the rock and fluids during coring, core recovery, core

handling and testing, including:

contact with drilling mud;

pressure and temperature losses on core recovery;


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oxidation of the oil through lack of appropriate core preservation;

core cleaning;

temperature and pressure during core testing.

All can alter the native wettability to different degrees.

4.3.1 Contact With Drill ing Mud

There is a long-standing concern that components of drilling muds can alter the wettability of

portions of the formation with which they come into contact. Wettability alteration is severe

for oil-based mud fluids because of the oil-wetting surfactants commonly used. For example,

in the Southern North Sea gas basin, OBM contact induces an extremely strong oil-wetting

tendency that can be difficult to remove, even by harsh cleaning. Core analysis tests on

fresh-state core drilled with an OBM will be unrepresentative - the wettability will be

altered from its native condition. The only drilling fluid ever recommended for use wherewettability preservation is the goal of the coring programme is to use unoxidised reservoir

crude, but it is seldom used due to safety and environmental concerns.

In work reported by Bobek et al13, water-wet plug samples were flushed with a variety of

mud filtrates and additives and the subsequent effect on brine imbibition rates was examined.

The low imbibition rates following treatment with oil mud filtrate indicate little affinity for

brine indicating that the samples have become oil wet (Figure 4-3)

Stiles14carried out a similar study on the Brent field and found a marked reduction in brine

imbibition rates for samples treated with an oil based mud filtrate (Figure 4-4).

Jia et al15

provide a useful summary of several workers results. This showed (with somediscrepancies) that:

strongly water-wet rocks were unaffected by water-based whole muds, filtrates and mudcomponents, with the exception of lignosulphonate which reduced the water wetness.

not strongly water-wet rocks were made more water wet by contact with individual water-based mud components.

all oil based muds, filtrates and components increase oil wettability or reduced waterwettability

In their own work, Jia et al tested seven water-based mud formulations made up from a range

of chemical additives, and aged samples in the mud filtrates in the laboratory. Solutions ofindividual additives were also tested. All seven chemical additives individually lowered the

water wetness and raised the oil wetness of strongly water wet samples. The wettability

alteration due to exposure to mud filtrates is less than with solutions of individual additives.

Filtrates from a KCl/FCLS/CMC/Drispac mud rendered the minimum wettability alteration.

4.3.2 Pressure and Temperature Loss on Core Recovery

Water-wet rock can be made more oil-wet during core retrieval as the core is brought to the

surface. Pressure reduction results in the liberation of gas as the core pressure is reduced

below the bubble point of the crude oil. This increases the relative concentration of heavier

end components (increases surfactant concentration) in the oil which can be adsorbed on the


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rock surfaces. Temperature reduction reduces the solubility of the surfactants of the oil and

increases the potential for adsorption.

4.3.3 Oil Oxidation

Oxidation of the crude oil, through exposure of the core to air during handling at wellsite and

in the laboratory, causes an increase in the asphaltene component and provides an

opportunity to increase the oil-wettability. Correct core preservation, designed to eliminate

or minimise core exposure to air, will prevent this form of wettability damage.

Core preservation methods are either wet or dry. Dry methods encapsulate the core in a

material intended to keep formation fluids from evaporating and which should prevent

exposure to air during handling and storage. The most widely used method is to enclose the

core section in plastic film wrap, then in aluminium foil, then dipping the core in paraffin

wax to form the seal. Tests have shown16

that with the right sealant, water loss can be

reduced to practically zero with this method. Another method is to use plastic-aluminiumlaminate to seal the core sections. The core section is wrapped firstly in plastic film then

placed in the laminate, which is then evacuated (in some applications) then sealed with a heat

gun. The laminate is less permeable to gases and fluids than the combination of

film/foil/wax. The main problem with this method is the fragility of the laminate - they can

be subject to pinholes and cracks, and some operators have found them to be too delicate for

field use.

Many operators now use wet methods in which the core section is placed in a foot long steel,

glass or PVC container filled with deoxygenated brine or depolarised kerosene or other

mineral oil17

(Figure 4-5). A bactericide is added to the fluid, which is then evacuated or

purged with helium or nitrogen to remove air, then the containers are sealed. PVC containersare not optimal because they permit diffusion of water and oxygen. Glass containers are

preferred because they are inert, but experience has shown that they can be easily damaged in

transport such that the preservation fluid is lost.

4.3.4 Core Cleaning

Core cleaning methods are designed to remove oil and water (plus other drilling mud

contaminants) from a plug sample. Invariably therefore, core cleaning tends to increase the

water wetness. In fact, core cleaning as part of wettability restoration is designed to induce a

strong wetting state in the test samples, and the cleaning methods and solvents are selected

primarily on this basis. Anderson 18 provides an excellent description of the methods andtechniques used. Depending upon the oil and rock types, extremely harsh cleaning methods

and solvents may be required.

Recent (mostly unpublished) evidence shows that hot soxhlet extraction in toluene and

methanol often fails to remove oil-wetting contaminants so that the cleaned core is not

wholly water-wet. Hot soxhlet extraction in toluene removes both water surrounding the

grains and the non-polar fraction of the crude oil, thus permitting the heavier (polar) oil

fraction (which contain surfactants and asphaltenes) to come in contact directly with mineral

surfaces and alter wettability. The phenomenon may be exacerbated by low initial water

saturation.


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4.3.5 Core Testing

If crude oil is used during core testing, then the core wettability can be altered by temperature

and pressure. If the tests are run at higher temperatures and pressures, the core can become

more water wet. An increase in temperature and pressure will increase the solubility ofwettability altering compounds. The interfacial tension (IFT) of the fluid phases and the

oil/water contact angle on the solid grain surfaces will decrease as temperature increases.

4.3.6 In Situ Wettabil ity Estimation

Since the act of taking the core and bringing back to the surface is likely to alter the native

wettability, it must be considered that core tests on fresh or cleaned-state samples can

never provide an accurate representation of the in-situ wettability. Unfortunately, there is no

convenient tool with which to quantitatively characterise wettability under downhole

conditions, although the nuclear magnetic resonance tool holds promise. However native

wettability can be inferred from analysis of core, log and formation pressure tester (RFT)data.

For example, Figure 4-6 (from Rajan and Delaney19), shows typical free water level (FWL),

oil-water contact (OWC), capillary pressure and saturation relationships for water-wet,

neutral-wet and oil-wet reservoirs. For the water-wet case, it takes a certain amount of entry

pressure in the oil column before the oil enters the formation. This means that the OWC will

be above the FWL (level of zero capillary pressure). The OWC can be estimated from log

and core measurements and the FWL from the intersection of the oil and water RFT

gradients. The smaller the pore radii , the larger the entry pressure and the higher the OWC

will be above the FWL. In an oil-wet reservoir, the reverse is true: the OWC will lie below

the FWL. Wettability forces will force the non-wetting phase (water) below the level of zerocapillary pressure since the capillary pressure (Po-Pw) is negative between the OWC and the

FWL. The reservoir saturation at the FWL would be at or above irreducible values.

For a neutral-wet reservoir, surface forces exhibit no preference for oil or water, and the FWL

and OWC are nearly the same, with little entry effect. The curve looks similar to the water-

wet case, discounted for the entry pressure effect. In high permeability formations, where

there is little or no transition zone, the FWL and OWC may well be coincident, so wettability

may not be able to be inferred with any degree of confidence.

4.3.7 Laboratory Measurements

Lab wettability measurement methods and interpretation are discussed in a later Chapter.


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Water

OilOil

water-glass Glass SlideGlass Slide

oil-wateroil-waterWATER WETWATER WET

Glass SlideGlass Slidewater-glass

oil-glassoil-glass

OilOil

Water

oil-wateroil-water

OIL WETOIL WET

Figure 4-1: Wettability Concepts

Figure 4-2: Cryogenic SEM Photomicrograph


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Figure 4-3: Effects of Oil-Based Mud on Spontaneous Imbibition (Bobek)

Figure 4-4: Effects of Oil-Based Mud on Spontaneous Imbibition (Stiles )


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Figure 4-5: Core Preservation Cylinder (Corex)

Water-Wet

Oil-Wet

Neutral-Wet

Figure 4-6: Idealised Free Water Level Contact Relationships


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5. Clays and Clay Damage Mechanisms

Authigenic clay minerals grow in the pore spaces of a sediment after deposition and during

cementation, and their presence usually reduces permeability. Further, they are in contactwith the pore fluids in the reservoir, and can react with these, as well as drilling and

production fluids, as they flow through the formation. They have an effect on the saturation

distributions and production characteristics of the reservoir which far outweighs the

percentage distribution which they occupy in the reservoir pore system.

5.1 Clay Structures

Clay minerals are composed of silicon, magnesium and aluminium and a quantity of other

metals. The basic building blocks are the silica tetrahedral sheet and the alumina octahedra

sheet. Substitution of Si4+

by Al3+

in the tetrahedron sheet and replacement of Al3+

with Mg2+

or Fe3+ in the octahedral sheet produce a net negative charge on the clay. This negative

charge is balanced by cations attracted to the surface of each flat platelet. The cations on the

clay surface are termed exchangeable since they can be readily removed by other cations in

their environment. The exchange layers are associated with layers of water molecules which,

to varying degrees, are bound to the negative sites on the clay platelet surface.

The number and location of these bound layers of water molecules, which are considered to

be an integral part of the clay mineral and not free pore water, depend on the mineralogy

and nature of the clay present.

The major clay groups of concern are:-

Kaolinite

Montmorillonite

Illite

Chlorite

These clays are classified according to their molecular structure and comprise relatively

simple "building blocks" arranged in a variety of different ways.

Montmorillionite (Smectite) group minerals, are composed of two silica tetrahedral sheets

with a central alumina octahedral sheet. Some 80% of exchange cations (commonly Na+or

Ca2+

) occur between the silicate layers, with the remainder associated with the externalsurfaces of the particle.

Cation exchange capacity is high and this clay conductivity has a considerable impact on core

electrical measurements. Special care is required when montmorillonite is present

Illite group (mica) minerals comprise a layer composed of two silica tetrahedral sheets with a

central octahedral sheet. The structure is similar to smectite, with the exception that the

charge deficiency at the interlayer exchange is balanced by potassium cations, which are

stable and not easily replaced. This clay usually occurs in a pore lining or pore bridging

morphology. Its low CEC value produces no clay conductivity problems but one of its

textural forms - filamentous or hairy illite - can have a very significant effect on measured

electrical properties and is easily damaged during core preparation. Figure 5-1provides anSEM photomicrograph of fibrous illite in its pore bridging habit.


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Kaolinite minerals are composed of a single silica tetrahedral sheet and an alumina

octahedral sheet combined in a unit such that the tips of the silica tetrahedrons and one of the

layers of the octahedral sheet form a common layer. Electrical charges within the structural

unit are balanced and there is very little substitution within the lattice. Kaolinite commonlyoccurs as pseudo-hexagonal "booklets" which are loosely attached to the host grains

frequently in discrete patches (Figure 5-2). This loose attachment may result in mobilisation

during production and core flow testing and result in pore blockage. It has a low cation

exchange capacity and its main effect on rock properties is simple pore volume reduction.

Chlorite group minerals consists of alternate mica-like and brucite-like layers. The mica

layer is unbalanced by substitution of Al3+

for Si4+

and the charge deficiency is balanced by

an excess charge in the brucite layer, as a consequence of substitution of Al3+

for Mg2+

.

Chlorite can be very stable in its well crystallised form but is easily degraded by acids to an

unstable form. It typically occurs with a "cornflake" texture as clay coatings (e.g. Figure

5-3).

The ability of clay materials to sorb certain anions and cations and retain them in an

exchangeable state is one of their most important properties. The ions are exchangeable for

other anions or cations by treatment with such ions in a water solution. In smectites, some

80% of the exchangeable cations occur on the base of plane surfaces with the remainder on

the edges. In illite and chlorite most of the cations are on the edges, between crystals. With

kaolinite, the exchangeable cations occur only on the base of the silica tetrahedral units, and

the cation exchange capacity depends on the thickness of the kaolinite particles.

Thus, in general, kaolinite has the lowest cation exchange capacity (CEC), increasing through

illite and chlorite, to smecite, which has a CEC about 20 to 30 times that of kaolinite. The

exchange cations in these clays are associated with an integral number of water layers. Insmecite two layers of water molecules occur between the silicate layers. Interlayer water

molecules are co-ordinated around the exchange cations constituting an inner primary

hydration cell referred to as Type I water. Type II water forms an outer secondary co-

ordination sphere, being indirectly linked to the cations and the inner Type I layer via weak

ion-dipole bonds, and is more mobile than Type 1 water. Exchange reactions in kaolinite,

illite and chlorite generally occur as the result of broken bonds at the edges of the crystal

lattices and consequently, exchange sites occur at interparticle (that is, between crystals)

rather than at interlayer (within crystals) sites. In these minerals the excess negative charge

is balanced by exchange cations. Polar water molecules are attracted to both the clay

surfaces and to the cations, and results in the formation of a diffuse double layer of bound

water molecules, the first layer immediately adjacent to the clay surface, and the second heldby the hydrated cations. If the delicate chemical equilibrium at the exchange sites is

disturbed, for example by exposure to lower salinity brine or fresh water, the existing cations

on the clays will hydrate. Hydration forces will depend upon the original cation at the

exchange sites. Sodium cations are the most readily exchangeable, and can promote

adsorption of up to 32 layers of water molecules in smectite interlayers, causing clay volume

expansion. Hydration of Na+cations in the interparticle sites of kaolinite, illite and chlorite

generates sufficient osmotic pressure to cause separation of individual clay platelets which,

under the influence of flowing liquid, are dispersed into the pore network. Clay swelling and

dispersion can cause plugging or bridging of pore throats, leading to severe permeability

damage.


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5.2 Clay Morphology and Rock Property Controls

Neasham20describes 3 categories of dispersed clay which are illustrated in Figure 5-4.

Dispersed particles - typically kaolinite

Pore lining - typically chlorite and smectite

Pore bridging - typically illite and smectite

Neasham examined the impact of these different morphologies on porosity/permeability

relationships (Figure 5-5)and capillary pressure curves for a number of broadly similar sands

(Figure 5-6).

The discrete clays, kaolinite, appear to have a minimal effect on porosity and permeability

and good reservoir quality is maintained (though both porosity and permeability are reduced

to some extent).

The data set for the pore bridging clays still shows good porosity but the permeability is

reduced by one or two orders of magnitude. This perhaps indicates that pore throat channels

become significantly reduced by a relatively small amount of pore lining clays.

This pattern of permeability reduction is continued further with the intergrown pore bridging

clays, e.g. hairy illites, where the permeability is reduced by a further two orders of

magnitude.

Neasham described the effect of different clay morphologies on the shape of mercury

injection curves. The discrete clay samples show relatively low threshold pressures,

indicating fairly large pore and pore throat sizes. The curve then trends horizontally or sub-

horizontally indicating a very uniform pore size distribution. Pore lining and bridging claysprogressively increase the threshold pressure since the larger pore throat sizes are reduced

and effectively create a very wide range of pore sizes.

Though these results are entirely predictable and indicate just two ways in which

petrophysical data is controlled by clays, they clearly show that if we alter the clay

morphology in any way then the impact on the derived core petrophysical data may be very

significant.

5.2.1 Rock Property Alteration

Clay damage can occur during coring, if a relatively fresh water-based mud is used, in which

case montmorillonite clays can swell or kaolinite and illite clays detach and cause poreblockage if there is fluid movement.

The prime cause of clay damage however is during cleaning and drying in the laboratory.

This is discussed in detail in a later Chapter.


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The progressively higher magnification images (A-B-C-D) show chlorite forming pore fills in a poorlysorted sandstone.

Figure 5-3: SEM Photomicrographs - Chlorite

Figure 5-4: Neashams Categories of Authigenic Clays


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Figure 5-5: Typical Poroperm Relationships (from Neasham)

Figure 5-6: Typical Capillary Pressure Relationships (from Neasham)


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6. References

1Fjerstad, P.A, Thereby, H., Pallatt, N, and Stockden, I. : Application of Deuterium Tracer in Estimating

Native Water Saturation in the Gyda Field, SPE 25376, SPE Asia Pacific Oil and Gas Conference and

Exhibition, Singapore, Feb., 1993

2Maury, et al: Core Discing: a Review in Proc. SANGORM Symp. Of Rock Mechanics in Africa, 1988

3Everett et al: Faja Case Study Results on a Single Well, SPE Formation Evaluation, Volume 2, 1987.

4Torsaeter and Beldring: The Effect of Freezing on Slightly Unconsolidated Cores, SPE paper 14300, 60th

Ann SPE Tech Conf. And Exhibition, 1985.5Worthington et al: Reservoir Petrophysics of Poorly Consolidated Cores, I, Wellsite Procedures and

laboratory Methods, Log Analyst, No. 28, Vol. 2, (March-April), 1987.

6Sincock et al: Major Advance in Sampling and Preserving Unconsolidated Core, Proceedings of 1st Society

of Core Analysts European Symposium, London, 21-23 May, 1990.

7Worthington et al, ibid

8Unalmiser, S.: Handling Unconsolidated Cores to Preserve Wettability and Pore Structure, Society of Core

Analysts Paper SCA 8803, 1988

9LaTorraca: Combined Resistivity, Porosity, Brine Saturation, and Capillary Pressure Measurements on

Poorly Consolidated Samples, Society of Core Analysts Paper SCA 8904, 1989

10Lamb., C.F., and Ruth, D.W.: Laboratory Program Design for Unconsolidated Heavy Oil Reservoirs,Society of Core Analysts Paper SCA 9104, 1991

11Treiber et al: A laboratory Evaluation of the Wettability of Fifty Oil Producing Reservoirs, SPEJ, Dec.,

1972

12Chilingar and Yen: Some Notes on Wettability and Relative Permeability of Carbonate Reservoir Rocks,

Energy Sources, Vol. 7, 1983.

13Bobek et al: Reservoir Rock Wettability - Its Evaluation and Significance, Trans AIME, 1958

14Stiles, J., and Hulfitz, J.M.: The Use of Routine and Special Core Analysis in Characterising Brent Group

Reservoirs, UK North Sea, SPE 18386

15Jia, Buckley and Morrow: Alteration of Wettability by Drilling Mud Filtrates, Paper SCA 9408, SCA

Symposium, Stavanger, 1994.16

Auman, J.B.: A laboratory Evaluation of Core Preservation Materials, SPE 15381, Oct., 1986

17Cornwall, C.K.: Core Preservation - An Alternative Approach, Proceedings of 1st Society of Core Analysts

European Symposium, London, 21-23 May, 1990.

18Anderson, W.G: Wettability Literature Survey - Part 1: Rock/Oil/Brine Interactions and the Effects of Core

Handling on Wettability, JPT, Oct,. 1986

19Rajan, R.R., and Delaney, P.: Capillary Pressure Based Water Saturation in the Fateh Thamma Reservoir,

Dubai paper submitted for presentation at 32nd Soc. Of Professional Well Log Analysts Annual Logging

Symposium, Midland, Texas, June 16-19, 1991.

20Neasham, J.W.: The Morphology of Dispersed Clay in Sandstone Reservoirs and Its Effects on Sandstone

Shaliness, Pore Space, and Fluid Flow Properties, SPE 6858, Oct., 1977

Documents

Chap 3 Core Damage