A Drilling Guide to Shales and Related Borehole Problems

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A Drilling Guide to Shales andRelated Borehole Problems

Document Information

Status: Issued

Document Number: DCB/46/93

Issue Number: -

Issue Date: 1993

Custodian: Drilling Fluids Group, BP Sunbury

Prepared By: Mark Aston/Paul Reid

A Drilling Guide to Shales andRelated Borehole Problems

CONTENTS

Preface

1 INTRODUCTION

2 SHALE TYPES & ASSOCIATED DRILLING PROBLEMS

3 SHALE-WATER INTERACTIONS

3.1 How Does Water Get into Shale?

3.2 What Does Water Do?

4 HOW DIFFERENT MUD COMPONENTS WORK

4.1 Water Based Muds

4.2 Oil Based Muds

5 MUD SELECTION AND PLANNING


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5.1 Define the objectives of the well

5.2 Collect and Analyse Offset Data

5.3 Obtain and Characterise Shale Samples

5.4 Laboratory Inhibition Tests

5.5 Optimise Drilling Practices

5.6 Communicating Potential Problems and Remedial Actions

5.7 Establish a Review Mechanism

6 SHALE PROBLEMS AT THE RIGSITE

6.1 Tight Hole

6.2 Soft Cuttings, Cuttings Dispersion and Gumbo

6.3 Cavings and Hole Fill

6.4 Changes in Mud Properties

6.5 Rigsite Inhibition Tests

7 FUTURE TECHNOLOGY NEEDS

7.1 Shale/Salt Interactions

7.2 Linking Chemical & Mechanical Behaviour

7.3 Glycols

7.4 Brittle Shales

7.5 Fractured Shales

7.6 Fluid Loss Control in Shales

7.7 Mud and Shale Monitoring at the Rigsite

8 REFERENCES

Preface

This document provides an overview of shale types and associated drilling

problems, and is aimed at improving our understanding of the causes ofborehole instability in shales.


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The topics addressed are as follows:

common shale types, their classification and associated drilling problems

reactions which occur when water based muds come into contact with shales

how water based mud chemicals are used to minimise shale problems

issues, including mud selection, which must be considered when planning awell which will encounter reactive shales

remedial actions which should be taken when shale instability is encountered

whilst drilling

future technology needs

With regard to muds, no attempt is made to compare and contrast the widerange of commercial systems available - such a comparison would in anycasesoon be out of date. Instead, only the main generic mud types and additivesare discussed. Emphasis is placed on how they work, and the procedureswhich will lead to optimum mud selection.

Considerable detail is given on the mechanisms of shale-fluid interactions,much of this arising from the work carried out at Sunbury over the past 2-3years. This represents valuable information which is not available elsewhere.It is recognised there may also be a need for a 'user-friendly' abridged versionwhich uses a flow-chart format, and focusses on the planning, mud selectionand trouble-shooting procedures; feedback on this would be welcomed.

1 INTRODUCTION

On average, shales constitute more than 75% of rocks drilled during oil and

gas exploration. These clay-rich sedimentary rocks are the major source ofwellbore instability problems and as such are responsible for more lost timeand additional costs than any other drilling problem: Shell have estimated thatshale-related problems account for approximately 50% of their lost drillingtime and cost the industry around $500-600 million per year (1).Although encountering shales makes for potential drilling problems, theirpresence - or at least proximity - is vital because they are the source rocks formost oil and gas deposits and frequently form the seals which traphydrocarbon accumulations.Most shales have the potential to cause drilling problems. Some forms ofinstability are caused by ground stresses or excess pore pressures: these are

regarded as having a purely mechanical failure mode. Other problems arecaused by the chemical reactions which occur when the formations areexposed to drilling mud. Often what begins as a chemical reaction results inchanges in the mechanical properties of the shale and this causes failure ofthe rock. Chemical effects are therefore often firmly linked to the mechanics ofwellbore instability.The preferred solution to the large majority of shale problems is to use aproperly engineered oil based mud (OBM) at the correct mud weight. Thisapproach has been adopted in many operational areas - for example theNorth Sea - and has been estimated to reduce drilling costs on vertical wellsby around 15%. Savings on deviated wells are often much greater.While OBM solves many problems, it is not a universal solution:


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In the North Sea, although OBM is the preferred technical option, the

discharge of mud and oily cuttings is becoming increasingly restricted by

environmental legislation. While the continued use of OBM may be possible

by using cuttings cleaning or re-injection technology, several companies are,

with varying degrees of success, replacing OBM with inhibitive water based

muds (WBM). The rationale behind these moves is that effective use of WBMallows the OBM issue to be dealt with at its source and does away with the

need to install additional hardware to deal with the consequences of OBM use.

Some companies also argue that the use of WBM is justified on the grounds of

the improved working conditions for rig crews and the reduction in the impact

of (and liability for) any accidental spillages and discharges of mud.

In frontier exploration areas the use of OBM can be difficult because of supply

problems and lack of logistical support. In these situations, WBM is often the

only practical option.

While these arguments can support the increased use of WBM it is clear that,

even with recent developments, nothing can yet match the inhibition obtainedwith OBM. If WBM is to be used for drilling shale, it is therefore critical thatefforts are made to understand how the rocks are likely to react and to usethis information in adopting both the most appropriate mud system and thebest engineering practices. For maximum impact, this all-round approachmust be used on the planning and execution stages of the well.

2 SHALE TYPES & ASSOCIATED DRILLINGPROBLEMS

The term shale, as applied to drilling, is a misnomer: Shales form a subgroupof MUDROCKS, the generic group of fine-grained, clay-rich sedimentaryrocks encountered by the drill bit. For ease, this report will continue to refer tothe whole mudrock family as "shales", although strictly speaking shales areonly those mudrocks which show a preferred cleavage direction (other typesinclude mudstones, claystones and slate). The clay minerals commonly foundin these rocks are given in Table 1.

Table 1 TABLE 1

Mineral TypicalSurface

Area(m2/gm

ParticleSize

(microns)

ParticleShape

Swellsin

Water?

Dispersesin water?

Smectite(Montmorillonite)

350-800 0.05 - 2 Thin plates Yes Yes

Kaolinite 15-30 0.05 - 8 Plates/Books No Yes

Illite 10-150 0.5 - 15+ Plates/Shards No Yes

Chlorite 30-150 0.1 - 5 Plates No No

Illite/Smectite(Mixed Layer)

10-600 0.2 - 5+ Plates Yes Yes

Attempts have been made to classify shales to reflect the way they behaveduring drilling (Table 2 and references 2, 4 and 5). None of these


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classifications are perfect since there are too may variables to allow anunambiguous description of behaviour. Many schemes draw on localexperiences (such as in the Gulf of Mexico or onshore USA) and makeinterpretations which indicate a poor understanding of shale reactions andmud chemistry.

Although it is impossible - and dangerous - to force shales into a particulargroup and then expect them to behave in a way identical to a "classic"member of that group, the use of a system (however limited) forms a goodstarting point in the early stages of well planning and mud selection. Adetailed study using shale samples, offset well data and focused laboratorywork will then provide the detail to make the necessary refinements. The bestmud type and drilling practices will be strongly influenced by theexpected type (or types ) of shale.A classification of mudrock types, modified from that suggested by Mondshine(2), is given in Table 2. Note that this scheme uses shale hardness as themain classification criterion: this is a convenient approach since it also offers

some correlation with burial depth and compaction (there are severalexceptions) and swelling clay contents. Equally valid schemes could usemineralogy, age, drilling behaviour etc as the principle variable.

Table 2 TABLE 2

Class Texture MBT*(meq/100gm)

WaterContent(weight %)

Clays# Wt%Clay

Density(g/cc)

A Soft 20-40 25-70 Smectite +Illite

20-30 1.2-1.5

B Firm 10-20 15-25 Illite +MixedLayer

20-30 1.5-2.2

C Firm-Hard

10-20 2-10 Illite +MixedLayer

20-30 2.3-2.7

D Hard 3-10 5-15 Illite + possSmect.

20-30 2.2-2.5

E Brittle 0-3 2-5 Illite,Kaolinite,Chlorite

5-30 2.5-2.7

NOTES1. * MBT (methylene blue test) is a measure of cation exchange capacity ofthe clay minerals. High MBT values equate to smectite-rich shales.2. # See Table 1 for details of clay mineral types.It is important to realise that shales can vary in a number of ways:

i. The grain size can range from very fine (claystones) to gritty (siltstones). Thecoarse material in siltstones is generally quartz with some mica, feldspar,

chlorite and kaolin. Swelling clays are invariably fine grained.

ii. The mineral grains can be well cemented (indurated), weakly cemented oruncemented. Calcium carbonate (calcite) and secondary quartz are common

cements.


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iii. The mineralogy can vary from a high swelling clay content to the completeabsence of swelling clays.

iv. The moisture content of the shale - which typically reduces with consolidation& depth of burial - can vary from over 25% to less than 5%.

v. The salinity and chemical composition of the pore fluids can vary widely:

Most shales are deposited by rivers flowing into sedimentary basinswhere the water salinity can range from freshwater through brackish toseawater. Other reactive "shales", such as the North Sea BalderFormation, are formed from airborne deposits such as volcanic ashfalls.

Freshwater shales are comparatively rare. Brackish shales are typicalof lagoonal areas and some inland seas (the present day Caspian Seais a good example). Seawater shales are common (for example manyof the North Sea Tertiary shales).

As the clay-rich sediments are compacted, water is squeezed out and,because ions are held close to the clay layers, the expelled water is oflower salinity than the bulk pore fluid. The end result is that, in acompacted shale, the residual pore fluid will be more saline than thewater in which the original sediment was deposited. In general, themore the shale has been dewatered the greater will be the salinitycontrast. This has implications for the design of the invading filtrate(see Section 3).

vi. The pore pressure can range from naturally pressured to highly over-pressured.

All of these variables can have a major influence on shale reactivity and theoptimum mud engineering approach. Some examples of reactivity controls aregiven in a BP Report by I.J. Evans and P.I. Reid (3) which attempts to explainthe geological controls on drilling problems in UKCS Central North SeaTertiary shales. In this study several points were noted which are goodexamples of how shales can very both vertically and laterally:

"Gumbo" problems (soft, high water content shales which can disperse,

deform into the hole and/or form mud rings) were rate in sediments belowabout 1600 metres. The occurrence of gumbo was not related to the

mineralogical composition of the shale but depended on the degree of

consolidation and hence the water content of the shale: as the shales become

more compacted and lose water, problems with gumbo diminish. (Gumbo can

occur at greater depths if a poorly inhibitive mud allows firm shales to take up

large amounts of water).

As is common with most sedimentary basins, there is a general fining of

sediments towards the centre of the basin. Because montmorillonite is a very

fine mineral, this means that the swelling clay content of the shale tends to

increase with distance from the shore line. Also, there is a tendency for these

distal deposits to be thicker. Although there is no hard and fast rule, thereactivity of the shales - and hence the frequency and severity of drilling


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problems related to WBM/shale interactions - tends to increase towards the

centre of the basin.

Overlying variable (ii) is the effect of sand and silt bodies originating from

submarine slope fan facies (identified from sand body maps of the area). A

careful study showed that the most severe and frequent shale problems came

from silty muds, muddy silts and interbedded sands and shales - rather thanfrom the more homogeneous shales. The control here seems to be the higher

permeability of the silty formations which allows more filtrate invasion and

hence increases the severity and extent of any reactions. This effect appears to

outweigh straight forward mineralogical controls such as the amount of

swelling clay present in the shale.

Using the Table 2 classification scheme, some statements can be made aboutlikely wellbore problems in each shale type and the implications for design ofthe drilling mud programmes:CLASS A SHALES: Soft, high water content, high clay content, low

densityThese shales are typically young, rapidly deposited and not deeply buried.Examples include many of the Tertiary shales of the North Sea and Gulf ofMexico. Contrary to Mondshine's classification these shales do not alwayscontain high amounts of swelling clay and those which are present can besmectites and/or mixed layer illite/smectites. Some deeper, older Class Ashales do exist; for example plastic kaolinite-rich Carboniferous fireclaysencountered in the East Midlands oilfields in the UK.Because of the variable clay mineralogy, these shales can range from highlyswelling to non-swelling. The clay composition will be that which wastransported into the sedimentary basin (detrial minerals) since burialtemperatures will rarely be high enough to promote mineral transformation(diagenesis). Because of the rapid deposition of many of these sediments, theformations may be poorly sorted and therefore will be appreciably silty, givingpermeabilities significantly higher than usually expected in shales.Drilling problems which can occur in Class A Shales are:

Hole closure

Frequent and often lengthy sections of tight hole are encountered whentripping out of the hole and when making connections. Significant time

can be spent working and reaming the string, which can becomemechanically stuck if care is not taken. Pumping out of the hole willgenerally make trips easier.

Hole enlargement

Because these shales are soft and easily eroded, large washouts candevelop which can make hole cleaning, directional control and effectivecement jobs difficult. If the washouts become severe, hole collapse ispossible and if the shale is dispersive, cuttings will break down in themud causing an increase in viscosity. Excessive dispersion will

increase mud maintenance costs.


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If more competent formations are interbedded with the shales, ledgesmay form to give problems while tripping, logging and running casing.

Sticky cuttings

The wet, often plastic nature of these shales give them the potential tocause problems such as bit balling, poor hole cleaning, mud rings andblocked flow lines.

CLASS B SHALES: Firm, moderate/high water content, high claycontentThese are often just deeper-buried versions of the Class A shales but theirdifferent behaviour merits placing them in a different group. As burial depthincreases, water is squeezed out to form a more consolidated material.Temperature also increases with depth and as it reaches 60 - 100C(corresponding to depths of 2-3 km at normal geothermal gradients) smectites

gradually transform into non-swelling illites: however, since this transition isnot abrupt, it is common to find an appreciable amount of swellable mixedlayered illite/smectite at depths to (and exceeding) 3 km. Therefore withdepth, the Class A shales are gradually transformed into the firmer Class Bformations and, if smectite was present in the original sediment, this is slowlyconverted to mixed layer clays and ultimately illite.There do, however, appear to be a number of exceptions to the smectite-to-illite transformation rule which means that the occurrence of more of less puresmectite at depths greater than 2 km should not be ruled out. A typicalexample is the smectite-rich Balder Clay formation, found extensively in theNorth Sea at depths in excess of 2.5 km.Drilling problems which can occur in Class B shales are:

Hole closure

Problems will be similar to Class A except that the increased hardnessof the formation makes the shale less prone to plastic flow.

Hole enlargement

Reaction with WBM can soften the shale to the extent where it is easily

washed out, although this can be limited by use of the correct mudformulation. The shales may also be competent enough to swell andstress the wellbore to the extent where cavings will be produced (ratherthan stress relief occurring by plastic flow into the wellbore as withClass A shales). With the wrong mud system, instability can beobserved even in shales with low (


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influence (6): calcium shales seem much more prone to balling thansodium-rich varieties.

CLASS C SHALES: Firm-hard, low/medium water content, high claycontent

The hardness of these shales combined with an appreciable swelling claycontent make them prone to caving although hole closure (swelling withoutcaving) is not unknown.Drilling problems which can occur in Class C shales are:

Hole closure

Problems are unlikely to be as severe as in Class A and B shales.Aggressive reaming and high tripping speeds through tight regions maydestabilise the wellbore and initiate caving.

Cavings

Characteristic thin fragments with curved faces can be produced.These may generally remain hard and so can be easily recognised atthe shale shakers. Excessive cavings can make hole cleaning difficultand can, in the extreme, result in the hole packing off. The subsequenthole enlargment can add to hole cleaning problems as well as makinglogging, running casing and cementing difficult.

Cavings (and cuttings) from some Class C shales can soften andpartially disperse in the mud en route to the surface, producing adegree of rounding which can make caving events difficult to detect atthe shakers.

Dispersion

As already noted, some shale may disperse into the mud as cuttingssoften although problems are unlikely to be severe. Similarly, mudrings will be rare in these shales. Bit balling may occur but becomesless likely than with Classes A and B.

CLASS D SHALES: Hard, moderate water content, high clay content.Shales in this category tend to contain predominantly illite or mixedillite/smectite - for example the Jurassic Kimmeridge Clay in the North Seaand Cretaceous Pierre Shale from Utah, USA. Drilling problems will dependboth on physical factors (stress, pore pressure) and compositional variationssuch as the presence and concentration of smectite or swelling mixed layerphases. With these more compacted - and usually older - shales, the fabric(arrangement of minerals within the structure of the shale), and thedevelopment of cementitious minerals (carbonates, quartz overgrowths,authigenic clay minerals) can exert a much greater influence on reactivity thanin Class A and B shales.

The high salinity of pore fluids within these rocks may contrast sharply withthat of the mud filtrate: many workers have argued that a high salinity contrast


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will cause the formation to take up water by osmotic processes and that thiscan be a major cause of wellbore instability. (See Section 3).Drilling problems which can occur in Class D shale are:

Cavings

These shales will produce characteristically hard, dry curved cavingswhich are only slightly-to-moderately dispersive in any water basedmud. Drilling problems include the formation of cuttings beds with theassociated risk of packing off and the production of large amounts ofhole fill on trips. Hole enlargement which results from extensive cavingcan make hole cleaning, directional control and cementing difficult.

CLASS E SHALES: Brittle, low water content, low-to-high clay contentClass E shales are often extremely hard and compacted. They arecharacteristic of deep, old shales or those which have been subjected to

extensive tectonic activity; the Colombian shales are good examples of thelatter. An example of the former case may be the Jurassic shales which areinterbedded with the reservoir sands in Statoil's Sleipner field.The shales tend to be illitic and contain no, or very little, swelling clays. Theyare rarely dispersive and fail by caving and heaving into the wellbore, oftenseveral days after they have been drilled. It may be appropriate to subdividethe brittle shales into those which contain communicating microfractures(either natural or induced while drilling) and unfractured shales: the reason formaking this subdivision is that the failure mechanisms of the 2 types will bedifferent and the preventative approaches adopted in engineering the mud willbe different.Possible mechanisms which explain failure of brittle shales are discussed inSection 3.Drilling problems which can occur in Class E shales are:

Hole collapse

Small cavings similar to those seen in Class D shales can occur but themode of failure in these shales is more typically a sudden and oftencatastrophic collapse which produces large blocky or angular shalepieces. These events will generally occur without warning some time

(hours or days) after the unstable zone has been drilled and canquickly pack off the drillpipe. Hole cleaning, efficient cementing andlogging and casing problems will be common.

3 SHALE-WATER INTERACTIONS

Some wellbore failures in shales can be put down to purely mechanicalorigins such as high tectonic stresses or overpressured formations. Ifgeological and drilling conditions allow, these situations can be managed byusing an appropriately high mud weight. The BP Wellbore Stability Guidelinesof Addis, McLean and Roberts (7) discuss the mechanical aspects of shaleinstability.


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Where there are chemical (or linked chemical-mechanical) processes involvedit is often not possible to give a simple, clear reaction mechanism whichexplains the processes which take place in the wellbore. There is stillconsiderable debate on how shales react (particularly with water based muds)and no definitive, unifying theory has been produced. What follows is a

detailed discussion of the fundamental chemistry, based on BP Sunbury'scurrent understanding of the processed involved. A more general overview ofhow different mud components function is given in Section 4.

3.1 How Does Water Get into Shale?

The simple and very obvious first step in the reaction between shales andWBM is that water penetrates the rock once it is exposed during drilling.Although well sorted and compacted shales have very low permeabilities,water is able to invade an promote the reactions which cause swelling, stressbuild-up and/or softening.The classical argument for explaining how water moves from the mud into theshale is that osmosis occurs. (Osmosis is the spontaneous movement ofwater from a low concentration salt solution to a more concentrated onethrough a semi-permeable membrane). This requires that the shale acts as amembrane through which water can pass but not anions or cations. If the saltconcentrations (or more correctly the water activities) of the mud aqueousphase and formation fluids differ, water molecules will move from the lowconcentration regime to that with the higher concentration until the wateractivities are balanced. Since shale pore fluids are often more saline than thedrilling fluid, water is therefore drawn into the shale and this can cause

instability.The concept of osmosis has, for many years, given rise to the suggested useof balanced activity muds (ie where the activities of the mud aqueous phaseand formation fluids are matched) which will prevent these reactions takingplace.It is still generally agreed that osmosis is a key mechanism in OBM, wherelaboratory experiments have shown that shale can be made to swell or shrinksimply by changing the activity of the emulsified brine phase. Figure 1 showslaboratory data obtained at Sunbury for Oxford Clay. With this clay, the porefluid has a low salinity so quite low concentrations of salt in the OBM aresufficient to cause clay shrinkage. Balanced activity is between 5 and 10 ppb

calcium chloride in Figure 1; OBM's are discussed more fully in Section 4.2.Figure 1 Shale Swelling in Oil Based Muds of Varying Salinity


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In WBM's it is now a widely-held view, however, that osmosis does notoccur, for the following reasons:

Low salinity shales (such as Oxford Clay above) do not shrink even when

contacted with highly saline fluids, eg swellings still occur in 30 ppb NaCI or

KCI(8). Studies of water transport in shales carried out by AEA Technology in Dorset

showed that diffusion rates are not affected by salinity (9). This work also

showed that anions and cations diffuse through the shale at similar rates to

water molecules. If osmosis was occurring, these ions should be excluded

from the shale and water diffusion rates should be affected by salinity

changes.

Water diffusion and fluid penetration studies by Shell (10) support the AEA

work.

If osmosis was important in WBM's mud containing low concentrations of

KCI should be more effective than high concentrations for drilling shallow

Tertiary shales (which tend to have low pore water salinity). Furthermore, toohigh a KCI level should cause these shales to shrink and hence possibly

destabilise. No well documented evidence exists to support this and, in fact,

widespread industry experience shows that muds with salinities much higher

than those of the pore fluids are generally the more successful.

If osmosis is not a valid mechanism for WBM, how do shales hydrate in thesecases?At least 3 processes can operate:DiffusionWater will diffuse between the shale and the mud and gradual mixing of thetwo fluids will therefore take place. If the chemical composition and/orconcentration of the two fluids is significantly different, shale reactions canoccur, resulting in a change in the physical properties of the rock. Diffusionrates for water in shales will depend on the permeability. Rates andpermeabilities for several shales have been measured by AEA Technology(9):

Shale Type Porosity(%)

DiffusionRate (Water)x10-10m 2s-1

ConvectionRate (Water,300psi) x10-10m2s-1

Permeability(nanoDarcies)

London Clay 46.0 1.70 - -

Oxford Clay 35.0 1.90 10.0 500

CarboniferousShale

14.0 0.23 1.9 70

N. Sea Tertiary(core, 8182')

29.0 1.25 3.4 99

N. Sea Tertiary(core, 5709')

56.0 1.90 - 6000

Kimmeridge 7.9 0.176 0.24 12

* Convection (Differential Pressure)


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For reasons of safety and wellbore stability, shales are drilled with a mudoverbalance and this positive differential pressure will force fluid into theshale. Increasing the mud overbalance will increase the rate of fluidinvasion. The rate at which fluid invades is also governed by the shalepermeability. Because of the very low permeability of the shale, invasion will

be slow, eg compared with materials such as sandstones. Therefore, it isunlikely that any significant mud filter cake will form, and any that does will bemore permeable than the shale itself and so will not reduce the rate of fluidloss.With OBM's, the oil phase will not invade water-wet shale because of capillaryforces/wetting effects, and hence the oil will not cause instability: this is usedby Bol to explain the fundamental difference in performance between OBMand WBM. He has calculated that an overbalance of at least 4000 psi wouldbe needed to force oil into water wet shale."Suction" and Expulsion of Fluid by Changes in Rock StressAs shales are drilled, the radial stress is reduced in the rock close to the

wellbore (in cuttings the stress is removed completely). This can cause shaleto expand (dilate), making the rock undersaturated with respect to the porefluid. In response to this, the shale sucks water from the mud to reach its newequilibrium moisture content: if the composition of the water drawn into theshale differs from that of the pore fluid, reactions can occur.This effect can be very variable and will depend on the stress state of therock: for instance in shallow, soft uncemented shales which have a highmoisture content, where the weight of the overlying sediments is themaximum stress, the rock may compact (the Poisson effect) rather than dilate.In this instance, pore fluid will be expelled and/or the shale will plasticallydeform into the wellbore.

3.2 What Does Water Do?

Once within the shale matrix, the invading mud filtrate may cause reactionswhich make the shale swell, soften and/or disperse. The exact nature of thereactions and their severity depends on the characteristics of the shale(Section 2), the drilling conditions, and the chemical composition of the fluid.The consequences of fluid invasion can be conveniently separated intomechanical and chemical effects:The purely mechanical effect can be dealt with in a straightforward way and

has been described by Bol (10) in terms of a "pore pressure penetration"model: Any invading fluid, driven by a positive differential pressure (mudoverbalance) will increase the pore pressure within the matrix, even if nochemical reaction takes place between the rock and the filtrate. The result is areduction in the effective stress on the shale which can, if sufficient, lead tofailure. A more detailed discussion of this effect is beyond the scope of theseguidelines. Further information can be found in standard soil and rockmechanics texts.The chemical and surface chemical processes that can take place are lesswell documented and need further discussion. The reactions which occur willbe very dependent upon the composition of the invading fluid. It was seen

above that ions such as potassium and chloride can readily diffuse into theshale, but many of the larger species present (such as shale inhibiting


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polymers, fluid loss additives and viscosifers) are likely to be too large toinvade. A known exception is the recent class of glycol additives, which havea relatively low molecular weight, are non- ionic, and as such can readily enterthe shale (see Section 4.1.4 for more detail on glycols).In general, though, theinvading fluid will mainly consist of water plus simple dissolved ions, so that

the reactions will be dominated by ion composition effects (salinity). Theimplications of this are discussed in some detail below. Firstly, it is helpful togive two definitions:The Electrical Double LayerThese are diffuse layers of electrical charge which surround clay particles inan aqueous suspension. The layers consist of counterions (cations) which areattracted to the negatively charged clay surface. When two clay particlesapproach one another close enough, the layers on each begin to interact anda repulsive force is set up. The final separation distance of the particles isdetermined by a balance between this electrical double layer repulsive forceand the attractive forces which operate, namely the Van der Waals attraction.

When the suspending fluid has low salinity (for example distilled water), theelectrical double layers extend a considerable distance from the clay surfaceforcing the particles further apart. As the salinity increases, the layers"collapse" bringing the particles closer together.Cation ExchangeMost clay minerals (and in particular the swelling clays and micas) incorporateion substitutions within the clay structure (eg magnesium for aluminium oraluminium for silicon) which gives a permanent negative charge to the clayminerals. This charge is balanced by cations which are adsorbed by the claybut which can readily be exchanged for others which are present in anaqueous solution in contact with the clay. For example, a sodium smectite canbe converted to the potassium form by contacting the clay with a strong KCIsolution. The ion exchange form of the clay will strongly influence its swellingand dispersion behaviour.

3.2.1 Salinity and Specific Ion Effects

In an undisturbed shale, all colloidal forces should be equilibrium. Theaverage distance between clay particles will be such that the electrical doublelayer repulsion (see above) is exactly balanced by the attractive forcesbetween the particles: hence, there is no built-in swelling pressure. If the

shale is invaded by a fluid of the same salinity (assuming the ion compositionand fluid pressure is the same as that of the pore fluid) there will be nochange in this energy balance and the shale will remain stable. If, however,the invading fluid has a lower salinity (higher water activity) than the pore fluid,the pore fluid will be diluted, the electrical double layers around the clays willtry to expand and a swelling pressure will build up in the rock. If the swellingpressure is sufficient the shale will fail, by plastic flow, dispersion or caving.If the invading fluid is more saline than the pore fluid, there is the potential forshale to shrink, although in reality this shrinkage will be small in saline shalesand may only give rise to hole problems if the salinity contrast is large: forexample if a "freshwater shale" is drilled with a seawater mud containing

substantial amounts of KCI. (No clear-cut documented evidence exists for thistype of failure).


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As well as being compressed by non-specific high salinity, the electric doublelayers around clays are strongly influenced by the valency (charge) of theadded cations: The Shultz-Hardy rule (11) states that divalent cations (egcalcium and magnesium) are 4 times more effective at collapsing doublelayers than monovalent ions such as sodium or potassium and that trivalent

ions (eg aluminium) are 9 times as effective. Put another way, equivalenteffects are obtained from 0.1 molar (5.8 grams/litre) sodium chloride, 0.025molar (2.8 grams/litre) calcium chloride and 0.011 molar (1.5 grams/litre)aluminium chloride (aluminium salts are used as flocculants in watertreatment processes for this reason). This may explain why gypsum muds areeffective at preventing dispersion of some shales, particularly those with a lowswelling clay content.The above view, although supported by many workers, is somewhatsimplisticUnless both the activity and the chemical composition of the invading filtrateexactly matches that of the pore fluid, ion exchange reactions will take place

and the composition of the incoming fluid will alter as cations adsorb on, anddesorb from the mineral surfaces.Since different ions influence swelling to different degrees, swelling orshrinkage can occur if cation exchange takes place - even when the salinities(or activities) of the fluids are matched. Extensive laboratory work on cationexchange reactions with smectites shows that preferred uptake of thecommon cations are in the following order (12):Na < K < Cs < Mg < Ca < Al cation uptake for smectitesThis means that if a predominantly sodium shale is drilled with a mudcontaining calcium ions, calcium will displace many of the sodium ionswhereas if a calcium shale is drilled with a fluid containing sodium,displacement of the calcium ions will not be so marked. (Again, this argumentis too simplistic: If a high concentration of sodium is present in the mud thereis, in effect, an infinite supply of these ions and displacement of much of theadsorbed calcium will occur simply because Na ions greatly outnumber Ca.)These exchange reactions are much more important in shales which containswelling clays than in those where they are absent: in the latter case, the useof salinity alone is generally sufficient to give reasonable control There issome field evidence that suggests that the above order of cation exchangeselectivity changes for mixed layer illite/smectites which, being closer to micasin structure, have a stronger preference for potassium. The order appears to

become:Na< Mg < Ca < K cation uptake for illite/smectitesThese two exchange series show that ion exchange will occur unless thecomposition of the invading fluid exactly matches that of the pore fluid. Thisconcept of matching fluids gives rise to "balanced activity" muds which aregood in principle but impractical: it is difficult to measure the real pore fluidcomposition which, in any case, can vary from shale to shale within awellbore.With regard to the swelling process itself, the actual swelling behaviour ofmost clays tends to follow the cation exchange series of the mixed layeredclays:

Na > Ca > Mg > K > Cs > Al clay swelling sequence


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This series suggests that, if it is not possible to match the composition of thepore fluid precisely, the next best approach is to ensure that any reaction thatdoes occur converts the shale into a lower reactivity form: The swelling seriesindicates that potassium, caesium, and aluminium ions will all reduce theswelling potential of clays compared with the native Ca, Mg and Na states.

The incorporation of these ions into muds will therefore provide good levels ofswelling inhibition.In reality, the choice is at present restricted to potassium since caesium isunavailable in a cost-effective form and the aqueous chemistry of aluminiumions is complex and difficult to control in a drilling fluid.To add further difficulty to mud design it should also be appreciated that thecomposition of the invading fluid will change as the invasion front moves intothe shale. As an example, take a freshwater/KCI fluid moving into a shalecontaining sodium smectite:At the wellbore wall, very effective exchange of K for Na will take place andthe reactivity of the rock will be lowered substantially. However as it moves

through the rock, the invading fluid becomes progressively depleted inpotassium and enriched in sodium such that the exchange reaction becomesless complete further into the shale (and hence the reactivity of the shaleremains higher). Since the invading front advances in plug flow, shale furtherfrom the wellbore first sees this "depleted" filtrate rather than a "clean" KCIfluid: hence swelling can occur. Ultimately, as bulk filtrate rich in potassiumgets to the reacted zone, it may be possible that potassium exchange may"undo" some of the damage (although laboratory experiments suggest this isnot usually the case) but by that time the shale structure may already besufficiently weakened to cause mechanical failure. This effect may explainthe time-delayed failure seen in some shales.There is little that can be done about this depletion other than to recognise itsexistence and that it will be most acute in smectite-rich rock. The onlypractical solutions are to:

i. Begin with a mud which has a high effective concentration of potassium (egby running a freshwater rather than seawater mud and/or by raising the level

of potassium chloride). In this way, depletion of potassium below an effective

concentration may be delayed long enough that the section can be cased off

before the onset of problems

ii. Avoid excessive mud weights - and hence reduce the rate of filtrate invasion.

In summary, both the salinity and ion composition of the mud aqueousphase must be considered when selecting an inhibitive WBM.

4 HOW DIFFERENT MUD COMPONENTSWORK

4.1 Water Based Muds

The current view is that the inhibition provided by water based muds will

always fall short of that achievable with oil based systems, simply because itdoes not appear possible to totally prevent the ingress of water, using current


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technology. Nonetheless, steps can be taken to maximise inhibition levels inWBM's. As already discussed, the salinity of the mud plays an important role,but, in addition, materials such as polymers can be added to minimise filtrateinvasion and/or to act as encapsulants to physically hold or 'glue' the shaletogether. The function of different inhibiting chemicals and the rationale

behind their use is discussed below:

4.1.1 Salts

SalinityAs shown in the previous section, the addition of a sufficient amount of anysalt to WBM will cause compression of the electric double layers surroundingclay particles and will therefore reduce shale swelling and dispersion.In non-swelling clays, where cation exchange is not a strong driving force, theuse of a suitably saline fluid should be sufficient to give reasonable shaleinhibition. When swelling clays are present, it will be necessary to add cations

which will undergo selective ion exchange and thereby suppress swelling.Several ions, including ammonium, potassium, caesium,. calcium andaluminium, are effective. Potassium is the most frequently used cationbecause of its effectiveness, low cost, availability and compatibility with othermud additives.PotassiumPotassium will contribute to inhibition (like any salt) because of the salinity itprovides, but there are specific ion effects (benefits) as discussed in Section3.2.1. The potassium ion is particularly effective at reducing both the swellingand dispersion of shales. The precise way in which it functions is still not fullyunderstood. One theory relates to the size of the hydrated ion. Potassium mayfit snugly into 'holes' in the clay structure, thereby reducing the effectivesurface charge, whereas most other ions are too large to do this. Indeed, acorrelation appears to exist between ion size and inhibition, which wouldaccount for the effectiveness of other small ions such as ammonium andcaesium which have a similar size to potassium. Other less well establishedtheories focus more on hydration energies, and the effects of ion type onwater structure within the clay matrix (13-16).

4.1.2 Polymers

Partially hydrolysed polyacrylamide (PHPA)PHPA is a common additive in inhibitive polymer mud systems. The mostfrequently used PHPA's have molecular weights in the range 7 to 14 millionand have approximately 30% of the acrylamide groups hydrolysed to acrylicacid (Figure 2). These properties are viewed as optimum following severallaboratory evaluations of different materials (17). The molecules are thereforelarge (if the polymer chain is fully extended it can be of the order of 10microns long) and anionic (negatively charged).In distilled water or dilute salt solutions the PHPA chains will be extendedbecause the anionic groups in the molecule will repel one another. A solutionof 1 ppb of the polymer under these conditions will be viscous and will often

exhibit a characteristic "stringiness".


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As the salinity is raised, say by adding 30 ppb KCI, the charges on the anionicgroups are screened from one another and the mutual repulsions arereduced. In this situation the polymer forms loose coils and gives a much lessviscous solution.PHPA inhibits shales by adsorbing strongly on clay surfaces and edges.

Because the polymer is large in relation to the dimensions of most clayparticles, it can bridge between several mineral grains and reduce dispersionand erosion of the shale. Several studies have been carried out to understandthe inhibition mechanism (18): The consensus is that adsorption of PHPA isincreased in the presence of salt and that adsorption occurs both on theedges and flat faces of clay minerals. The presence of trace amounts ofcalcium may enhance adsorption by forming "bridges" between the polymerand the clay surface: this has not been proven conclusively and does notappear to be critical for the PHPA to provide inhibition.Figure 2 Partially Hydrolysed Polyacrylamide (PHPA)

Because the pore diameters in most shales are small (often considerablybelow 1 micron), PHPA will not penetrate into the bulk but will only adsorb onthe surfaces of cuttings and the wellbore. Several laboratory studies (19 and20) have shown that PHPA does not reduce swelling or softening of shales,presumably because the loosely packed coils on the surface do not form aneffective barrier against the migration of filtrate. The role of PHPA as aninhibitor therefore appears to be to form a slick surface coating that reducesdispersion of cuttings and the erosion of the wellbore wall. This process isoften referred to as shale encapsulation.Xanthan Gum

Xanthan gum is added to many polymer muds to give the necessary shear-thinning rheology, and provide hole cleaning. The molecules will adsorb onshale minerals but are not held as strongly as PHPA and their rigid rod-likeshape means that they are not very effective encapsulators. Xanthan will notreduce water uptake but appears to make a positive, if small contribution toreducing dispersion.Cellulose DerivativesPAC and CMC are sometimes claimed to be shale inhibitors although theirmain functions are to provide fluid loss control and/or viscosity (the viscositycontribution depends on the molecular weight of the polymer). Like the otherpolymers discussed here, they will adsorb on shales and will make a small

contribution to reducing dispersion (these polymers would be expected to beslightly more inhibitive than Xanthan Gum but significantly less inhibitive than


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PHPA). Again, there is no evidence to suggest that PAC or CMC will slow theabsorption of water by the shale.On a cautionary note, low viscosity CMC can be a mild clay dispersant(thinner), particularly in low salinity systems when used in concentrationsabove about 4 ppb. There may, therefore, be the potential for high levels of

CMC to cause some instability in some shales although no definitive studiesappear to have been carried out in this area.StarchStarch forms a colloidal dispersion of microscopic particles in a mud ratherthan "dissolving" in the aqueous phase like CMC, PAC etc It is used for fluidloss control which it gives by blocking pores in permeable formations and filtercakes. Starch gives no shale inhibition.While Xanthan Gum, CMC, PAC and starch do not provide significant levelsof inhibition in microporous shales, they become very important in shales thatare either naturally fractured or fracture during the drilling process. In theserocks the polymers are able to enter and seal off any microfractures, thereby

limiting water ingress and (presumably) preventing extensive propagation ofthe fractures. These additives will also be needed to give fluid loss control inany adjacent sand or silt formations. With these points in mind, conventionalfluid loss additives should always be maintained at useful levels when drillingshale.ThinnersThinners (for example, lignosulphonates, polyacrylates, styrene polymers,vinyl polymers etc) are used to reduce the viscosity of muds by deflocculatingdrill solids. While the use of thinners is important in controlling mud propertiesand minimising volumes, the possible impact of their use on shale inhibitionmust be bourn in mind: if thinners can deflocculate clay drill solids, they alsohave the potential to disperse the shales which make up the wellbore. Thesematerials should only be added to inhibitive muds when absolutely necessary(and then only after pilot testing) and alternative approaches, such as wholemud dilution, should be considered in preference.

4.1.3 Particulate Additives

GypsumGypsum (calcium sulphate) is slightly soluble and provides a lowconcentration of calcium ions in a cheap, easily usable form. Gypsum

dissolves quickly to give a saturated solution (500 - 1000ppm calcium) andacts as a good "store" of calcium ions: as calcium is taken up by the shale,more gypsum dissolves to maintain the concentration in solution. This lowconcentration of calcium will provide a small amount of inhibition by keepingthe clay minerals in the shale flocculated and hence dispersion is reduced.Because of the flocculating power of gypsum it improves the solids toleranceof muds and increases the efficiency of secondary solids removal processes.This helps to reduce mud volumes when drilling dispersive shales. For thisapplication gypsum can be run as the sole "inhibiting" additive or inconjunction with KCI, seawater etc.Lime

Lime muds have been used extensively, and with some success, in areassuch as the Gulf of Mexico but have generally performed poorly elsewhere.


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The muds have a characteristic high pH (due to the lime) and are commonlyused in conjunction with lignite derivatives. The level of inhibition attainablewith these muds is, at best, only moderate and the inhibition mechanism is notclear, although two possibilities have been suggested:

the high pH (about 12) of these systems will tend to inhibit clay dispersion. the lime may undergo a cementing reaction with the shale, particularly at

temperatures above about 200F. It is reasonable to suppose that this reaction

will strengthen the shale.

Gilsonite, asphalts and derivativesGilsonites and asphalts are used as fine powders which disperse into themud. Some derivatives, such as Soltex, also contain soluble components.These additives are assumed to provide inhibition by softening at downholetemperatures, and plastering the wellbore wall to form a competent, water-impermeable layer. Their inhibitive qualities are the subject of debate and the

field performance of the products is variable. Because of their particulatenature and the fact that they are deformable, it is likely that these materialswill be most effective in fractured shales where they should effectively sealmicrofractures. They would not be expected to contribute greatly to inhibitionin young, plastic shales such as the Tertiary North Sea formations.BentoniteBentonite clay (gel) is still added to some so-called inhibitive mud systems forrheology and fluid loss control. This material will not inhibit shales (indeed it isthe most active component of many reactive shales) and it should be usedsparingly - or preferably not at all. Any bentonite in the mud will react withinhibitors such as PHPA, potassium, glycol or cationic polymer: this willreduce the amount of these additives available for true shale inhibition andmay change mud properties significantly.

4.1.4 New Mud Additives

The new mud developments have been recently reviewed in BP Sunburyreports (19 and 21) which should be referenced for detailed information. Thereports identified two major new mud types: glycol muds and cationic muds.These are discussed below and their laboratory performance compared withconventional WBM is shown in Figure 3.

Figure 3 Shale Inhibition of Different Mud Systems


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i. Glycols and glycerols

The use of glycols and glycerol WBM additives has had somecredibility since about 1990. There are several glycol and glycerolspecies which give good shale inhibition when added to WBM at levelsof 10% or less. Typical chemical structures of these compounds aregiven in Figure 4.

Glycols can be added to many conventional mud types to increaseinhibition. They are most commonly added to KCI/polymer mudsalthough sodium chloride/glycol and gypsum/glycol muds have alsobeen used successfully. Gel/glycol combinations have been lesseffective and in general should be avoided.

Not all glycols give equally good shale inhibition and at present theindustry is concentrating on ethylene glycol/propylene glycol (EO/PO)copolymers and glycol ethers. Compounds which contain a highpercentage of propylene oxide are not as inhibitive although theyappear to be effective lubricants, anti bit balling additives and (possibly)pipe release agents. An earlier product (Hydrafluids HF100) based ona mixture of glycerols has also been used to good effect but sufferscertain disadvantages including cost effectiveness, product variabilityand its effect on other mud properties.

Figure 4 Typical Glycol Structures


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The shale inhibiting mechanisms of glycols are still not fully understoodbut the following points are known:

o At the levels used (3 to 10% by volume of the mud liquid phase),glycols will not reduce the chemical activity of the water phase to a

level that can explain their performance in terms of osmosis

(laboratory work shows that, in common with other WBM, osmosis is

not a credible mechanism for glycol muds).

o The molecules are small - typically molecular weights are a few

hundred to a few thousand - compared with PHPA which has a weight

of the order of millions. The molecular dimensions are therefore too

small to suggest the glycols act as bridging polymers.

o Their small size suggests that many of these molecules will be able to

enter shale pores along with water and salts. They therefore have the

potential to form hydrogen bonds with clay surfaces (adsorptionstudies and entropy considerations suggest they will do it in preference

to water) and may therefore interfere with normal shale hydration

processes.

Shale hardening is observed with some glycols as evidenced from laboratory

tests in Sunbury (see also Figure 5, P35); this hardening effect correlates with

the high inhibition levels achievable and perhaps suggests exchange of some

of the water in the shale for glycol. However, the exact reason for hardening

has not yet been established.

The actual mode of action may vary with the type of glycol:

EO/PO Copolymers

This group is typified by a BP Chemicals product known as DCP 101.Similar materials can be sourced from other manufacturers (eg ICI,Dow Chemicals, BASF, Shell Chemicals and Rhone Poulenc). Mostmud service companies have a preferred supplier but many of theproducts are interchangeable from a technical standpoint. Many of theEO/PO products have molecular weights in the range 500 - 5000 and

EO/PO ratios between 25/75 and 75/25.


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EO/PO compounds show cloud point behaviour in aqueous solution;this means they are soluble at low temperature but form an insolubleemulsion above a critical temperature (the cloud point). The cloud pointis affected by molecular weight (increasing the weight decreases cloudpoint), the proportion of PO in the polymer (increasing the PO content

decreases the cloud point) and salinity (high salinity decreases thecloud point). DCP 101 has a cloud point of 35C (95F) in aseawater/25ppb KCI solution.

EO/PO materials have been run effectively in KCI, KCI/PHPA andgypsum WBM (the latter by Statiol). Typical additive levels are 3 to 5%by volume at which the muds give excellent wellbore stability, hardcuttings, good lubricity and low HTHP fluid loss. Solids tolerance isgood and therefore mud volumes are minimised. Examples of BPExploration wells drilled with these copolymers are:

Forties Delta 3.2

Forties Bravo 4.2

Hides-C (PNG)

UKCS 204/24

Observations on the laboratory and field performance of the muds are:

o Shale recoveries are increased in the presence of KCI, although

reasonable inhibition is obtained without.

o 101 can reduce, but will not eliminate, shale swelling. Control of

swelling is greater in some shales than others.

o Depletion rates are low compared with additives such as PHPA. An

apparently conflicting observation is that glycol is preferentially

adsorbed on clays and will not displace water, even in aqueous

solutions containing as little as 3% glycol.

o There is no clear evidence that inhibition depends on whether the

glycol is dissolved or dispersed (ie below or above its cloud point).

The above observations do not offer a clear inhibiting mechanism and furtherwork is needed in this area. One suggestion is that, in the localised high cation

concentrations found adjacent to clay layers there is always sufficient

"salinity" to cause the glycol to cloud out. If this is the case it will displace

water from the surface and stabilise the shale. Because of the plugging effect

of the glycol droplets, a form of fluid loss control could be achieved which

prevents deep penetration of filtrate or glycol into the bulk of the shale: this

would help to explain its effectiveness, the low depletion rate and the apparent

unimportance of cloud point.

Glycol Ethers


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At present, the only commercially available, technically acceptable,non-toxic glycol ether is the BP Chemicals product DCP208. AlthoughDCP208 does show cloud point behaviour, the critical temperature ismuch higher than with DCP101 and the glycol remains soluble over thefull temperature and salt concentration ranges normally experienced by

polymer WBM.

Although laboratory tests show 101 to be a better inhibitor than 208,field performance to date makes it hard to differentiate between the twoglycols. BP wells drilled with 208 muds include:

UKCS 15/28 (2 wells)

UKCS 13/28

UKCS 204/24

NCS 7/12 (Ula)

Laboratory and field observations are similar to 101 except that:

o Good inhibition is only obtained when 208 is used in conjunction with

KCI (cf. 101). A typical formulation would use 25ppb KCI and 3 - 5%

208.

o Shale invasion studies suggest that 208 is carried through the shale

with the invading filtrate. (no parallel studies with 101 have been

carried out to see if at least a portion of the EO/PO polymer also

invades the formation).

The inhibition process with 208 is currently no better understood than that of

101 and it may be that a common mechanism holds for both materials.

However, the greater dependence of KCI and the greater mobility of this lower

molecular weight material are sufficient to suggest subtly different behaviour

of the two classes of compounds.

Glycerols

The only commercially available glycerol-based shale inhibitor isHydrafluids HF100, a complex mixture of glycerols, propylene glycolsand salts. The product is a modified waste stream from a glycerinmanufacturing process.

To provide inhibition equivalent to that obtained with 3 - 5% EO/PO orglycol ether normally requires around 10% HF100, presumablybecause the active concentration of the glycerols is reduced by thepresence of salts and water (which sometimes make up 40 - 50% ofthe fluid).

HF100 has been used extensively by several companies throughoutthe world and at this time (summer 1993) is the "glycol" offered by


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International Drilling Fluids. The material is effective but can havedisadvantages:

o It is a highly alkaline material, often necessitating the use of a second

additive (such as citric acid) to maintain mud pH within specified

limits.o Addition of 10% by volume of a liquid additive can cause supply,

storage and handling difficulties, particularly in remote locations.

o Addition of 10% HF100 can make subsequent hydration of polymers

difficult and hence mud properties difficult to control.

o HF100 must be run in the presence of KCI. Without KCI the additive

can promote rather than inhibit shale dispersion.

o On occasion, high concentrations of the additive have been found to

promote bit and stabiliser balling.

With the exception of the preferred use with KCI, these disadvantages are not

observed with the EO/PO copolymers or glycol ethers.

No investigation of the inhibiting mechanism of HF100 has beenpublished.

Muds containing HF100 have been used in several wells by BP,including Wytch Farm (L10) and UKCS 16/28.

ii. Cationic Polymers

The use of cationic (positively charged) polymers in drilling andcompletion fluids has been discussed since the early 1970's but theirdevelopment into workable inhibitive mud systems did not occur untilabout 1990. The principle behind the use of cationic polymers is simpleand sound:

The edges and faces of clay minerals carry negative charges at the pHvalues found in drilling muds. Under these conditions, cationic specieswill be much more strongly adsorbed and held on the surface thananionics: therefore if adsorption of polymers promotes inhibition,cationic should be much more effective than anionics. Early attempts to

formulate cationic muds used surfactant molecules.

The resulting muds were not particularly inhibitive, tended to foam and,in general had an unacceptably high environmental impact. Laterdevelopments - involving the use of low molecular weight polyamines,DADMAC or cationic polyacrylamides - gave more effective mudsystems (eg see Figure 3, P20):

Polyamines

These are small (molecular weights 5,000 - 500,000), water soluble

molecules which carry a high permanent positive charge provided byquarternised amine groups. In laboratory and field use (eg Anchor


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Drilling Fluids' "Ancoquat" mud system) these are found to be verygood shale inhibitors, reducing swelling and dispersion. Thepolyamines are compatible with amy common anionic mud additivesprovided the salinity of the mud is kept high (in excess of seawater +20ppb KCI is recommended). Although technically successful, these

muds become expensive to run in regions of very reactive shalesbecause of the very high depletion rates of the polyamines. Thisdepletion is unavoidable since it is a consequence of the inhibitingmechanism: the polyamine molecules adsorb very strongly on shaleminerals by displacing the exchangeable cations on the clays and theyare therefore particularly reactive towards smectites and illite/smectiteswhich have the highest cation exchange capacities.

Once exchanged onto the clays, the polyamine cannot be displacedand will bind adjacent layers together. This explains the high depletionrates, the good control of swelling and the "permanent" inhibition which

is retained even if the cationic mud is subsequently replaced byfreshwater.

Because of their high charge, polyamines are very effective flocculantsbut the molecules are too small to act as bridging polymers in the sameway as PHPA. Polyamine muds therefore tend to have excellent solidstolerance.

The high cost of these systems - compared with the glycols which givebetter inhibition - and concerns over the environmental impact of muddischarge has meant that these muds have not become widely used.

BP has used polyamine mud systems in UKCS 14/15 and NCS 7/12.

DADMAC

DiAllyl DiMethylAmmonium Chloride is used as the cationic inhibitor inBaroid's cationic mud system (Cat-1) (22). The product has someadvantages over the polyamines - most notably lower depletion ratesand lower aquatic toxicity - but it is not such a good shale inhibitor. Theinhibition mechanism is similar to that of polyamines although the

DADMAC cation is less strongly bound to clays.

Cationic PHPA

Cationic polyacrylamindes have been added to some mud systemseither as a direct replacement for the usual anionic variety or incombination with polyamine (eg M_I's M-Cat system). The cationicPHPAs have a similarly high molecular weight as their conventionalcounterparts and are therefore not thought to penetrate shale pores.Because of their positively charged functional groups they arepresumed to adsorb more strongly on the wellbore and cuttings than

anionic PHPA and therefore to be better encapsulators. In practice,there appears to be little advantage in using the cationic polymer.


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Like the other cationic polymers, PHPA is compatible with mostcommon mud additives provided the aqueous phase salinity is kepthigh.

4.2 Oil Based Muds

OBM is widely recognised as the most inhibitive mud type and if run correctly,chemical instability can be prevented (but mechanical problems due toincorrect mud weight or tectonic stress can still occur).Inhibition by OBM is probably provided as follows:A semipermeable surfactant membrane will form at the emulsion droplet/oilinterface - this is the adsorbed layer of surfactant (emulsifier) which preventsdroplet coaslescence and confers stability to the emulsion. Work at Sunburyhas shown that a semipermeable membrane also forms on the shale surfaceitself, and this is again believed to consist of adsorbed surfactant. Thesemembranes allow the movement of water (but not ions) between the dropletsand the shale; ie osmosis can occur. The direction of flow is determined bythe salinity balance, with water flowing from the low to the high saltenvironment in an attempt to equalise the salinities. In effect, water will onlyenter the shale if the salinity of the OBM brine phase is lower than that of thepore fluid in the shale. Therefore, provided the calcium chloride content of theemulsified brine is kept high enough in field muds, shales will remain stable.Soft cuttings will indicate that the brine concentration should be increased (orpossibly that more surfactant is needed to improve the membrane quality).It is, in theory, possible to destabilise shales by having the brine phase tooconcentrated and hence cause dehydration of the formation. As in many

wellbore problems, anecdotal field evidence of this problem exists but thereare no well documented examples.As noted in Section 3.1, the osmotic effect can be demonstrated with OBM inthe laboratory where shales can be made to expand when the brine phasehas a low salt content and shrink when the concentration is increased (seeFigure 1). These effects are likely to be influenced by mud overbalance, andby shale permeability and degree of consolidation. As yet, these aspects arenot well understood.In addition to the osmotic effects which give such good shale stability, the oilphase itself prevents ingress of fluid into the shale as discussed in Section3.2.

One further point to note is the role of osmosis when oil based muds havingdiffering salinities are mixed. Water transport will occur between the dropletsto equalise the salinities. This is a desirable effect as it leads to ahomogeneous system, but it will tend to make the more saline droplets largerand the less saline ones smaller. Extreme differences in salinity could lead tocatastrophic destabilisation of the emulsion, and re-shearing (re-emulsification) of the mud would be required.

5 MUD SELECTION AND PLANNING

The preceding sections of these guidelines have discussed reactions betweenshales and water based muds by considering how mud filtrates interact with


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different clays and how different mud components can influence thesereactions. Attempts were also made earlier to loosely categorise shale typesin terms of how they are likely to react and the nature of the drilling problemsthat will be caused by these reactions.This Section brings these issues together to consider the implications for

planning a well where reactive shales are known, or expected, to be present.Emphasis is on the procedures which should be followed, including theexperimental methods used to screen mud systems. It is not the intention tocompare and contrast the wide range of commercial muds available - thedatabase is continuously evolving and it is through regular contact with theservice companies that an up-to-date view of available systems ismaintained.Steps In The Planning ProcessThe steps which can be taken when planning a well which will encounterreactive shales are given below. Attempts have been made to put theactivities in a logical sequence, although not all the steps may be needed: this

will depend on the severity of anticipated shale problems and the level ofexperience and confidence (both within BP and with the contractors) whichexists, perhaps due to offset well information.

5.1 Define the objectives of the well

The objectives may have a strong influence on the quality of the shale controlneeded. For example:

A certain amount of wellbore instability may be acceptable in vertical

exploration or appraisal wells, provided the respective sections can be drilledreasonably quickly and cased successfully.

Highly deviated wells will, in general, present greater challenges because of

the tendency for these wellbores to be less mechanically stable (this will

require a higher mud weight which may, in itself, promote chemical shale

problems (see Section 3) and the fact that a longer shale section will be

exposed for a greater length of time than in a corresponding vertical well.

Severe tight hole will cause delays which are costly and which increase thechange of further problems occurring.Efficient hole cleaning is more difficult in high angle holes and extensive

cavings can quickly lead to packing off.Hole enlargement - whether from cavings or shale dispersion - can makeaccurate directional control difficult and, particularly if ledges of hardermaterial remain, can cause logging and casing problems. Hole enlargementwill also add to any existing hole cleaning difficulties and may also result inpoor cement jobs which will have long term implications in production wells ifzonal isolation is compromised.

Down-sized and slimhole wells

It is important to control shale stability in these wells where annular

clearances may be reduced, and hence where any hole closure or collapsemay have more immediate and/or extreme consequences.


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An additional concern may be the lack of contingency strings in the event ofsevere hole problems which necessitate casing to be set early.

5.2 Collect and Analyse Offset Data

This is potentially the most valuable information. Written records such asdrilling recaps and mud reports are a good source of information providedthey are factually accurate; often important events are reported only in acursory way or not at all. Discussions with people actively involved with offsetwells - even if the information is sometimes anecdotal - are extremelyvaluable: impression can be of more use than bland statements made in adaily report: these discussions need to take place with company employees,contractors and other oil companies if possible. Important data include:

Muds used in previous wells.

The shale-related drilling problems.

Any clear reasons why the problems occurred (eg mud weight, composition

etc). Any problems unrelated to mud formulation (eg poor tripping practices,

poor hole cleaning).

Any corrective actions which were attempted. This should include successful

and unsuccessful actions.

Actions which, with hindsight,. should have been taken but were not?

5.3 Obtain and Characterise Shale Samples

A good characterisation of the problem shale horizons may have been

obtained as part of 5.2. If not, and samples from offset wells are available, thiswill provide additional valuable information and will be an aid in mudselection.Cuttings or side wall core (SWC) can be used for X-ray diffraction analysis(XRD) to give an indication of the mineralogy of the shale (although XRD isonly a semi-quantitive technique and therefore can only be a guide to shalecomposition). This information can be used in conjunction with offset drillingdata to classify the shale type.Cuttings and SWC should be used in laboratory inhibition tests only if theyare well preserved and not altered by exposure to mud:

Samples which have dried out or become very mushy will appear morereactive in laboratory tests than the corresponding native shale.

Samples obtained from OBM will be permanently stabilised and will appear

less reactive than in the native state.

Samples taken from an inhibitive WBM are likely to have changed from their

native reactivity.

If cuttings samples are to be saved for XRD analysis they should be rinsedfree of most of the adhering mud using fresh water or brine (for WBM) or baseoil (for OBM). If intended only for XRD analysis, the samples should then beoven dried, bagged and labelled with the well number, depth, date and time.

If the cuttings are to be used for inhibition testing (for mud selection), theyshould be rinsed as above, blotted dry with absorbent paper and stored in


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airtight bags or cans. All possible precautions - such as completely filling thecontainers, storing in a cool place and returning them to shore as soon aspossible - should be taken to avoid the cuttings drying out.If there is any doubt about the quality of well site samples, these should beused only for mineralogical analysis. It is often possible to obtain well

preserved samples of outcrop shales which have similar mineralogy andthese should then be used in inhibition tests in place of the cuttings.

5.4 Laboratory Inhibition Tests

Testing to various levels of sophistication can be carried out to assess shalereactivity and select an appropriate mud system. Many tests are availablefrom service companies as well as in-house. Common methods are:Cold roll dispersion testThese rudimentary dispersion tests are carried out in glass bottles at ambienttemperature and pressure. A weighted amount of cuttings are placed in abottle with a fixed volume of test fluid, rolled for a predetermined time and thenondispersed residue recovered on a screen, dried and weighted. The resultis expressed in terms of the percentage of the original weight of cuttingsrecovered at the end of the test. A high recovery indicates that the cuttingsare of low reactivity, that the test fluid is inhibitive or a combination of both.The test is best limited to low viscosity additives such as salts, polyamines,glycols and small polymers. High viscosity fluids (eg those containing PHPAor Xanthan gum) will give an artificially high recovery because the thick fluidreduces the tumbling motion of the cuttings.This test gives a rapid first assessment of shale reactivity and screening of

potential inhibitors.Hot roll dispersion testThis is a standard oil field test. Weighed cuttings are placed in a steel orInconel bomb with the test mud. The bomb is sealed, pressurised, rolled in anoven at temperature and the cuttings recovered, dried and weighed. As withthe cold roll test, high recoveries indicate an inhibitive mud and/or shale of lowreactivity.Since, in general, temperature and pressure do not influence shale recoverygreatly - and this test is relatively complicated and time consuming - there arefew advantages in using it in place of the cold roll method. Probably the onlytimes when the hot roll test gives additional information are when temperature

thins the mud significantly (this test is sensitive to viscosity) or when inhibitorsare degraded by temperature.Capillary suction time (CST)This test uses the filtration time of a shale dispersion as a measure ofreactivity. The assumption is that the more reactive the shale, the finer will bethe dispersion formed in water and hence the longer the filtration time in thetest. The results can be useful but are very sensitive to the way in which theclay suspensions are prepared. The method can be used to assess salts asinhibitors but cannot be used for polymers: it is therefore a limited andpotentially misleading method of assessing mud formulations.Slake Dispersion Test (SDT)


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The slake dispersion test - sometimes called the "hamster cage" test - is anaggressive cuttings dispersion test developed by BP and now widely used inthe industry.An advantage of the test compared with the hot roll test is that it more clearlydifferentiates between the performance of different inhibitive mud types and

hence allows the best mud to be selected with more confidence.A disadvantage is that approximately 100 gm of cuttings is required for eachtest (this amount of cuttings is not available routinely as rigsite samples andspecific sampling instructions will be needed).Swelling testDispersion tests will indicate how effectively muds will prevent the breakdownof cuttings as they are carried out of the well and will also give an estimate oflikely washout problems but they provide no indication of the swelling potentialof shales. Swelling is a critical parameter because it gives a measure of thestress that can build up in the wellbore and which can result in collapse orsoftening. It also gives some measure of the extent of ingress of fluid into the

shale.There are several swelling tests, some of which use preserved core, somecompacted cuttings and some dried and reconstituted shale. BP's preferredmethod uses preserved core in an unconfined test with a circulating mudsystem. This test has been chosen because of its ease of use, speed andflexibility. The results appear to correlate well with the observed fieldbehaviour of several muds.Penetrometer (hardness) testA penetrometer will detect any softening of shale which is caused byexposure to different muds and hence can be used as a measure of inhibition.The test is of limited value when used in isolation and is best used inconjunction with swelling and dispersion data. This tests requires sampleswhich have a well defined geometry and cannot be used directly on cuttings.Extrusion (hardness) testthis new test, developed at Sunbury, measures changes in the bulk hardnessof cuttings after exposure to mud by determining the force needed to extrudecuttings though small holes drilled in a metal plate. The method appears torelate well to other measures of shale inhibition (particularly dispersion) and ispotentially a useful, robust and simple rigsite test. An example of dataobtained with that test is shown in Figure 5, P35."Downhole" tests

Several large scale testers exist which can study shale inhibition underdownhole conditions. The most recognised "public" facility is operated byO'Brien, Goins and Simpson (OGS) in Houston. BP also has access to ashale tester at Baker Hughes, Inteq (Milpark) in Houston as a result ofcollaborative work over the last 3 years. In principle, because the testing iscarried out under downhole conditions of temperature, pressure and annularvelocity, muds which give good results in these tests should also give goodfield performance. In reality, the non-availability of good, undamaged coremakes much of this testing suspect. The tests are also very time consumingand expensive. Published studies generally rank muds in the same order asobtained with the simpler tests outlined above.

5.5 Optimise Drilling Practices


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Good mud selection is critical to the success of drilling problem shales but it isstill only one part of the larger planning process. Several other factors mustalso be considered:Pore PressuresThe predicted pore pressures (and those observed in offset wells) will

determine the minimum mud weights needed for well control and for goodmechanical wellbore stability. Given the arguments used in Section 3 thelowest acceptable mud weight should be used to minimise the invasion offiltrate into the shale.Casing pointsCasing points may be controlled by the pore pressure plot or the occurrenceof suitably competent formations. However, where possible the casingprogramme should be designed to minimise the length of time reactive shalesare exposed to the mud.Bit selectionSelection of the bit type and nozzle sizes which give the optimum combination

of ROP and bit life is still an imprecise science since it depends strongly onformation mineralogy, hardness and chemistry as well as mud formulation.Offset well information will be a good initial guide and this data should besupplemented as necessary with guidance from bit manufacturers and in-house specialists.Tripping proceduresEven with the new types of highly inhibitive WBM, it is still recommended thatfrequent wiper trips are made. As a minimum, newly drilled hole should bewiped every 300 metres or more frequently as hole conditions dictate. Beforetripping, ensure sufficient mud circulation has taken place to clean the hole(see BP's Hole Cleaning Guideline (23)).Tight sections should be worked through carefully, if possible while circulatingthe mud.Trip speeds - both in and out of the hole - must be controlled to avoidswab/surge pressures destabilising any weakened shales.

5.6 Communicating Potential Problems and Remedial Actions

The planning process will identify preferred procedures and potentialproblems and should suggest some remedial actions (see Section 7). It is vitalthat these issues are communicated to rigsite personnel - most importantly,

the contractors - who should understand the objectives of the well, whycertain procedures are proposed and what remedial actions are suggested.The rigsite "team" should be involved at a level consistent with the expectedseverity of the problems: for high risk wells it is recommended that thecontractors are involved early in the planning process and become "partners"in achieving the objectives.

5.7 Establish a Review Mechanism

A final aspect of the planning process is to decide on the data required fromthe coming well and how it will be collected and recorded. Quality information

- whether accessed from written reports or databases such as DEAP - will be


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the basis of the learning process for future wells and proper dissemination ofthe information will help the Company learn more quickly on a global basis.

6 SHALE PROBLEMS AT THE RIGSITE

When a well is planned the likely shale problems should have been identifiedand the most suitable mud system selected. Unless OBM has been chosen, itis possible (even with the most advanced inhibitive WBM) that some wellboreproblems will be experienced. the impact of these problems will be minimisedif they are recognised early, the appropriate remedial action taken and theeffect monitored.Although many shale problems are easily recognised, their cause(s) can beambiguous and so any treatment may or may not be effective: this underlinesthe importance of monitoring the effect of any treatment and - if unsuccessful -to try an alternative approach. Typical problems and possible solutions are

discussed below:

6.1 Tight Hole

Tight hole during trips or on making connections is indicative of an obstructionor constriction in the wellbore. This can be due to:

A build up of cuttings beds in deviated holes which should be remedied by

improving hole cleaning. This can be achieved by increasing circulating rates,

increasing circulating times, decreasing ROP or changing the mud rheology as

appropriate. Full details of hole cleaning considerations are given in BP's Hole

Cleaning Guidelines (23).

Hole cleaning will be made more difficult in reactive shales if thecuttings become sticky enough to aggregate into a coherent mass.

Gumbo rings and sticky cuttings can also be a problem in verticalholes. In general this should be solved by increasing the inhibitivenature of the mud by increasing the salt content or the concentration oflow molecular weight additives such as glycols (or polyamines). If theproblem occurs in a PHPA mud, addition of more encapsulatingpolymer is unlikely to be beneficial.

Shale cavings or pieces of cement can fall into the wellbore. Approaches

outlined below should be used to prevent cavings. Blocky material can be

removed from the wellbore by circulating the mud and gently working the

string. Viscous pills will help remove particularly large or dense material.

Shale - particularly those in Classes A and B (see Section 2) - can soften and

deform into the wellbore by swelling an/or plastic flow. Increasing mud

weight will help hold the wellbore open but may cause longer term problems

because the higher differential pressure increases the rate at which mud filtrate

is lost to the formation. This could result in further problems some hours or

days later.


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The preferred approach is to increase the mud weight only my theminimum necessary to ease the tight hole problem and at the sametime reduce the mud fluid loss to below a corrected value of 5mls (APItest) by the addition of starch, PAC or CMC (this will control fluid loss insilty horizons but will have less impact in tight mudstones). The

situation should be monitored carefully and further increases in mudweight only made when hole conditions dictate.

Many times when drilling with WBM the first trip through newly drilled hole willbe tight but subsequent trips will be clean. It is recommended that, if possible,the hole is wiped on this first trip without increasing mud weight; the mudweight should only be raised if later trips through the same section remaintight.As well as the mud weigh/fluid loss approach, other changes to the mudformulation may be appropriate. If the shale contains swelling clays thenincreasing the KCI concentration (and glycol if this is used) should be

considered. Increases of the order of 10ppb KCI would be expected to providesome benefit.If the mud already contains PHPA, increasing the concentration above 0.5ppbis unlikely to give any incremental improvement. In fact, it could be that highlevels of PHPA could contribute to the formation and stabilisation of a soft,sticky layer of shale at the wellbore wall and thus contribute to tight hole. Oneapproach used by some operators is to decrease the PHPA concentration insevere tight hole situations which allows some erosion of the wellbore andgives a slightly overgauge hole. If this approa

A Drilling Guide to Shales and Related Borehole Problems

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