Spring 1997 3

Otto HouwenHemant LadvaGerry MeetenPaul ReidCambridge, England

Don Wi l l i a m s o nMontrouge, Fra n c e

One of the golden rules for vertical wells isthat formation damage caused by drillingshould, if possible, be eliminated in ther e s e r vo i r. Genera l l y, this concept has alsobeen extrapolated to horizontal wells andhas led to the adoption of aggressive tech-niques to clean up formation damage. How-e ve r, in some cases these complicated treat-ments increase rather than decrease risk tothe wellbore. Quantifying the effects of mudsystems and available cleanup tech n i q u e smakes possible an informed choice, specificto the reservoir and well being drilled.

The clear objective for any well is that itshould perform to the full potential of the for-mation it penetrates and remain stablethroughout its lifetime. This goal is besta ch i e ved by avoiding formation damage inthe first place, but in most cases this is notpossible. How e ve r, if damage is unavo i d a b l e ,a correlation can be drawn by looking at fra c-turing treatments in vertical wells. Duringf racturing jobs, wells may sustain near- w e l l-bore damage similar to drilling-induced dam-age. But this damage may be largely ignoredbecause induced fractures extend thousandsof feet into the formation, exposing more ofthe reservoir to a conductive flow path andsignificantly improving productiv i t y.

Horizontal wells penetrate up to 6000 ft[2000 m]—even more than most inducedf ractures—into a reservo i r, exposing thewellbore to an area of producing formationat least an order of magnitude greater thanwould be ach i e ved with a vertical well. Th i sopens up two opposing factors that drivehorizontal well productiv i t y.

Because of their huge flow area, horizon-tal wells can withstand higher levels ofdamage than vertical wells and still delive rhigher production rates. Conve r s e l y, drillingtimes for horizontal sections are genera l l ym u ch longer than for vertical wells in thesame formation, giving drilling mud moretime to enter the formation and potentiallycausing more severe formation damage.Also, lower draw d own pressures in horizon-tal wells may reduce cleanup efficiency.1

Therefore, some reduction in permeabilitym ay be permissible in horizontal wells, aslong as the wellbore extends far enough intothe formation to ensure sufficient flow area.At the same time, other aspects of thedrilling fluid, like its effect on well drillabil-i t y, may be brought to the fore. The trick isk n owing wh i ch drilling fluids to select tomaximize drilling rate while minimizing riskto the formation.

For too long, decisions about drilling fluidsh ave been made in isolation. Now, theindustry is developing a strategy that bringstogether the domains of the reservo i r,petroleum and drilling engineer with that ofthe fluids engineer. At the heart of this wo r kis the development of a real understandingof how drilling fluid damage affects produc-t iv i t y, with the goal of developing a reservo i rengineering tool for drilling fluid design.

“ Z e ro damage—good; permeability reduction—bad,” long a motto of drilling engineers, is accurate

for most vertical wells. Horizontal wells, however, with more exposure to producing formations,

a re diff e rent. Laboratory work and re s e rvoir simulation are helping write a more equivocal phrase:

“ Z e ro damage—preferable; permeability reduction—better to avoid, but often allowable.”

A New Slogan for Drilling Fluids Engineers

For help in preparation of this article, we would like tothank Sarah Browne, Michael Burnham and Dan Rya n ,BP Exploration Operating Company Limited, A b e r d e e n ,Scotland; Lindsay Fra s e r, Dowell, Houston, Texas, USA;and Paul Way, Schlumberger Cambridge Research ,Cambridge, England.VISPLEX is a mark of Sch l u m b e r g e r.

1. Renard G and Dupuy JG: “Influence of Fo r m a t i o nDamage on the Flow Efficiency of Horizontal We l l s ,”paper SPE 19414, presented at the 9th SPE Fo r m a t i o nDamage Control Symposium, Lafayette, Louisiana,USA, February 22-23, 1990.B r owne SV and Smith PS: “Mudcake Cleanup toEnhance Productivity of High Angle We l l s ,” paper SPE27350, presented at the SPE International Symposiumon Formation Damage Control, Lafayette, Louisiana,USA, February 7-10, 1994.Beatty T, Hebner B, Hiscock R and Bennion DB: “CoreTests Help Prevent Formation Damage in HorizontalWells,“ Oil & Gas Journal 91, no. 31 (August 2, 1993):6 4 - 7 0 .

4 Oilfield Review

F o rmation Damage—Invasion of the Production SnatcherFrom a mud standpoint, a well may bed ivided into two sections. In the first—fromthe surface to top of the reservoir—the twokey drivers are health, safety and env i r o n-mental (HSE) constraints, and drilling cost.In the second section—the reservo i r — H S Econcerns remain of central importance, butthe cost factor is usually ove r s h a d owed by aneed to minimize formation damage. Ofcourse, a prerequisite in both sections is thatthe well be drillable with the mud of ch o i c e .

Formation damage is considered to bea nything that impairs the permeability ofr e s e r voir formations, reducing injectivity orhydrocarbon production. Damage canoccur during all stages of well construction,during remedial treatments and during pro-d u c t i o n .2 This article concentrates on therelationship between drilling fluids and for-mation damage.

In reality, all reservoirs are damaged tosome extent by drilling fluid. The importantissue is whether this damage significantlyaffects well productiv i t y. One way of quanti-fying formation damage is to use the dam-age skin factor (r i g h t). Ty p i c a l l y, a poorlyconstructed damaged well will have a posi-t ive skin of 20 to 500; a good unstimulatedwell will have a skin of plus five to minusunity; and a well that has been fracture stim-ulated will have a large negative skin.

To d ay, most vertical wells are completedusing a cemented liner that is then perfo-rated. This is not the case for horizontal wellsthat are most often completed barefoot—thatis open hole—or using prepacked sand con-trol screens, slotted liners or predrilled linerswhere drilling mud may have a greaterimpact on the productivity of a well. Th e r eare at least two reasons for this effect.

First, oil and gas must be producedthrough the filter cake and mud filtra t e -induced formation damage because thereare no perforations that reach beyond thedamaged zone. Second, sand control com-pletions such as prepacked screens may alsobe plugged by the mud (see “How DrillingFluid Reduces Producibility in an OpenholeHorizontal We l l ,” page 6) .

Drilling fluid selection for reservoir drillingin horizontal and high-angle wells is a com-plex process. Obv i o u s l y, the choice of mudshould ensure that the well is drillable, anda wide range of well and formation factorsinfluence this selection. The effect ofdrilling fluid systems on factors such as holecleaning, torque and drag, wellbore stabil-i t y, and stuck pipe is central to success orfailure (see “Stickance Tester: Predicting aM u d ’s Pe r f o r m a n c e ,” page 10) .

The next and increasingly important factorinfluencing selection is the HSE aspect of adrilling fluid. Some fluids may not be usablein certain situations because of company orregulatory policy. Then come the cost andimpact of the drilling fluid on productiv i t y.This article focuses on the interplay of thesefinal two factors.

Understanding the Real Eff e c t sof a Drilling FluidWhile there appears to be a broad consen-sus on the mechanisms of formation dam-age, there is growing divergence over how itm ay be combated or avoided. The need tocost effectively eliminate or at least mini-mize formation damage, so that productiv i t yis maximized, has spawned a specializedarea of fluid design for reservoir drilling andushered in a host of what are called “drill-inf l u i d s .” Most drilling fluid companies haved e veloped drill-in fluids to allow effectivecleanup following reservoir drilling.

One development has been the introduc-tion of mud systems with a solid phase,wh i ch makes up the filter cake, that maysubsequently be removed by washes orbreaker fluids circulated into the well beforecompletion to dissolve or partially break thefilter cake. Th e o r e t i c a l l y, these treatmentsreduce the pressure required by formationfluid to break through the filter cake once awell is put on production, ensuring an eve nf l ow across the productive part of the hori-zontal interval. In practice, their action isn e ver uniform across the wellbore and suchtreatments substantially increase drillingcosts and complicate field opera t i o n s .

■Damage skin surrounding a wellbore. The skin factor may bere p resented as a dimensionless pre s s u re drop. The magnitude ofthis factor depends on the ratio of the undamaged and damagedp e rmeabilities in the formation, and on the depth of damage,which is related both to the depth of invasion and fluid loss.

Spring 1997 5

S a t u rated salt muds with salt crystals sizedto bridge across the formation and form a sig-nificant part of the filter cake are a typicalexample. After drilling, this cake is wa s h e dwith an undersaturated brine that dissolve sthe salt, promoting filter-cake cleanup. A l t e r-n a t ive l y, calcium carbonate may be used asthe weighting and bridging agent in bothwa t e r-base and oil-base muds. In this case,the filter cake may then be treated with amild acid to dissolve the carbonate. Also, cel-

lulosic products that are frequently used forfluid-loss control or as bridging agents maybe dissolved—although often only partially—using dilute acids or oxidizing agents such assodium hy p o ch l o r i t e .

Enzyme breakers have been developed forsome wa t e r-base muds (WBM). Th e s eenzymes are designed to attack polymersand may be used alone or with one of the

a b ove treatments. For example, sized-saltsystems incorporate magnesium peroxidethat when exposed to acid releases hy d r o-gen peroxide, wh i ch degrades polymers. Avariety of solvent and surfactant fluids isavailable to treat oil-base mud (OBM) filtercakes, breaking down the oil-wetting ch a r-acter of the cake and allowing it to dispersein the aqueous, or mixed-phase wash fluid.As with polymer breakers, this treatmentm ay also be used in combination witha d d i t ives that dissolve the cake.

These treatments are not without problems.Washes may cause significant losses of treat-ment fluid to the formation. These inva d i n gfluids, and the resulting filter-cake residues,m ay cause significant additional formationdamage—the opposite of what is intended. Ifthe losses are severe, it will be necessary touse expensive and time-consuming lost-cir-culation treatments that may themselve scause damage. Also, severe losses coulde ventually lead to well-control incidents.Treatment of some OBM filter cakes pro-duces viscous sludges that cause formationdamage. Polymer sludges may also resultfrom treatment of WBM filter cakes. A c i dbreakers may cause corrosion problems.

An alternative is to do away with wa s h e sand breakers altogether and back - p r o d u c ethe drilling fluid through the completionh a r dwa r e (see “Bringing in Wells Without aC l e a n u p ,” page 16). Another approach is tominimize particulate invasion of the forma-tion in the first place by creating a filter cakethat may be more easily “lifted” by forma-tion fluid during flow b a ck. An example ofs u ch a system is a bentonite/mixed-metal-hydroxide (MMH)/sized-carbonate system.MMH fluids are highly thixotropic, and lab-o ratory tests show that they have a lowpotential for formation damage, lay i n gd own a predominantly external filter cakeand thereby avoiding the need for deep-p e n e t rating washes (a b ove left) .3

■Minimizing particu-late invasion. VISPLEXfilter cake (A) on thee x t e rnal surface of ac o re ( t o p ). Betweenrock grains (B),unblocked pore s — o nthe order of 30 micro n s(µ) wide—may be seenimmediately below fil-ter cake (C). At highermagnification, a film-like bridge of bentoniteand mixed-metalh y d roxide (D) over thep o re throat is high-lighted ( c e n t e r ). Aftere x p o s u re to KCl-poly-mer mud, internal filtercake (E) is appare n tbetween the ro c kgrains ( b o t t o m ) . T h eunusual behavior ofthe VISPLEX fluid mayexplain the low levelof permeability impair-ment seen in labora-tory and field evalua-tions of this system.

2. Krueger RF: “An Overview of Formation Damage andWell Productivity in Oilfield Opera t i o n s ,” Journal ofPe t roleum Te c h n o l o g y 39, no. 2 (February 1986):1 3 1 - 1 5 2 .

3. Fraser LJ, Williamson D, Enriquez F Jr and Reid P:“ M e chanistic Investigation of the Formation Damag-ing Characteristics of Mixed Metal Hydroxide Drill-InFluids and Comparison With Po l y m e r-Base Fluids,”paper SPE 30501, presented at the 70th SPE A n n u a lTe chnical Conference and Exhibition, Dallas, Te x a s ,USA, October 22-25, 1995.

(continued on page 8)

6 Oilfield Review

T h e re are at least four dif f e rent mechanisms for

drilling fluid to damage horizontal well pr o d u c i b i l -

ity both inside the formation and in the wellbor e .

Mud-solids invasion and internal filter cake—

Drilling fluid solids will invade a short distance

into the formation—on the order of a few millime-

ters—bridging across or plugging pore thr o a t s

(next page, top left).1 An internal cake will r e s t r i c t

flow unless it is removed by treatment or flushed

out during production. The damage potential of

mud solids depends on the size of particles r e l a -

tive to the size of the pore throats in the for m a t i o n

being drilled. Shape, flexibility and degree of dis-

persion of particles are also important. Possible

exceptions are highly flexible particles like ben-

tonitic clays that can deform suf f i c i e n t l y , allowing

them to penetrate pores smaller than the diameter

of the clay sheets. As a guideline, par t i c l e s

between one-sixth and one-third of the diameter of

a pore throat may invade a significant distance

into the rock before bridging pore throats; par t i c l e s

less than one-sixth of the por e - t h roat diameter

generally do not bridge.

Mud-filtrate invasion—Mud filtrate may interact

chemically and physically with the for m a t i o n

causing significant damage—for example, mobi-

lizing formation fines or changing formation wet-

tability due to adsorption of mud surfactants onto

the par t i c l e s .

F o rmation-fines mobilization—When water-

base mud invades a rock containing oil, fines

mobilization following filtrate invasion may be

t r i g g e red by a salinity change, by a chemical

deflocculant in the filtrate, or by high fluid-flow

velocities in the pore space. Migrating fines may

cause extensive damage by blocking pore thr o a t s .

In most formations, mobile particles ranging fr o m

1 to 100 microns (µ) a re believed to be most dam-

aging, since particles smaller than 1 micron are

n o rmally strongly held to the surfaces of lar g e r

mineral grains by Van der Waals forces and are

d i fficult to dislodge. Particles above 100 micr o n s

a re larger than most por e - t h roat diameters and so

cannot migrate any great distance. It is usually dif-

ficult to carry out successful remedial tr e a t m e n t s

to remove damage caused by formation fines.

Sometimes even these treatments can cause fines

to become mobilized—by dissolving inter g r a n u l a r

cements—or can leave reaction products that are

themselves damaging (next page, top center).

Changes in wettability—When oil-base mud fil-

trate invades a water-wet formation, surfactants or

c e rtain types of polymer in mud filtrate may change

the wettability of the rock. Displaced for m a t i o n

water forms droplets in the pore spaces and thus

a ffects hydrocarbon production. In fact, oil-wetting

agents are specifically designed to make weighting

agents and drilled solids particles hydrophobic, so

it is inevitable that, if free surfactant enters the

rock in the mud filtrate, the rock is also likely to

become oil-wet. Permeability damage caused by

wettability change is generally assumed to be per-

manent. However, because of the low fluid-loss

rates of oil muds, the depth of damage will often be

small. Wettability change generally has a gr e a t e r

influence on production in tight rocks that contain

small-diameter pores (next page, top right).

Undisplaced whole drilling fluid— L a rg e - s c a l e

flow loop tests have shown that when screens are

uncentralized, mudcake and debris are left on the

low side of the hole even after aggressive cleanup.

Whole fluid left behind in the annulus can pack off

on the completion har d w a re during pro d u c t i o n .

Also, for wells with low drawdown, the high gel

s t rength of drilling mud could prevent or r e s t r i c t

flow from part of the horizontal section (next page,

bottom right).

Drilling fluid damage to completion hard w a re—

As sand control completion har d w a re is run into

the well, it fills with the fluid in the well. Mud will

flow or filter through the screen as a result of

s u rge pre s s u res created while running into the

well. During this process, solids in the mud may

p a rtially or completely plug the screen. Suscepti-

bility to mud damage will vary widely, depending

on completion type—prepacked screens are par-

ticularly vulnerable due to internal plugging ( n e x t

page, bottom left).

Damage profile from a polymer mud—A polymer

mud may damage formation permeability in several

ways. For example, mud solids may invade and

c reate an internal filter cake; fines can be mobilized

and block pores inside the formation; and cer t a i n

polymers carried inside the rock may adsorb onto

the rock and change the wettability, while lar g e r

polymers can also block pore spaces. Each of these

p rocesses invades to a dif f e rent depth, cr e a t i n g

m o re or less damage. A damage profile is more

useful than a simple average because it helps

explain the consequences and mechanisms of inva-

sion (next page, bottom center). In this case, the dam-

age profile decreases in severity away from the

w e l l b o r e. If a formation is not susceptible to fines

damage, then this graph will be dif f e rent.

How Drilling Fluid Reduces Producibilityin an Openhole Horizontal Well

1. Francis PA, Eigner MRP, Patey ITM and Spark ISC: “Vi s u a l i-sation of Drilling-Induced Formation Damage MechanismsUsing Reservoir Conditions Core Flood Testing,” paper SPE30088, presented at the SPE European Formation DamageC o n f e rence, The Hague, The Netherlands, May 15-16, 1995.

Spring 1997 7

8 Oilfield Review

The continuing debate on the pros andcons of washing versus back-production offilter cake in openhole completions has, atleast in part, been driven by the philoso-phies of individual companies. How e ve r,new studies into cake properties and dam-age mechanisms are now providing betterinformation for decisions.

For example, a joint industry study of mudcleanup in horizontal wells fully examinedthe role of common washes and breakers.4Small-scale core experiments tested six mudsystems and various breakers. Surprisingly,more of the breakers increased the back f l owpressure required to break through the filtercake than reduced it (t o p). In no case wa s

all filter cake removed. In displacement flowtests, effectiveness of washes on the lowside of horizontal wellbores also proved tobe limited because of the presence of stag-nant whole mud, and large amounts ofresidual mudcake and debris.

Another role of breakers is to removemud-induced damage from the near- w e l l-bore region. In this case, performance va r-ied for different mud systems—significantlyreducing near-wellbore damage for somemuds and increasing damage in others(a b ove). For some mud systems there was a

correlation between treatments that inducehigh losses and high levels of damage withthe wash fluids carrying damaging materials u ch as fines or partially degraded polymerdeep into the formation.

The high cost of specialized drill-in fluidsmeans that attempts to drill a well with zeroskin may take up a significant proportion ofwell budgets. How e ve r, any savings in themud cost have to be weighed against therisk of reducing productivity rather than pre-serving it. There is much to be gained bydefining the optimum amount of formationdamage that may be tolerated for a give nwell in a given situation.

But what is the optimum skin factor for awell? The answer is not simple. In some set-tings a considerable skin factor may have lit-tle effect on flow. The joint-industry studyreferred to above confirms that some hori-zontal wells can tolerate a significant leve lof mud damage before productivity is signif-icantly impaired. In others, only low skinfactors may be tolerated, but these condi-tions cannot be ach i e ved economicallyusing available mud systems. Reservo i rch a racteristics, well profile, completiondesign and economics all dictate the opti-mum skin factor.

A further determinant is the future role ofthe well. In an exploration well, where theo b j e c t ive is to find rather than producehydrocarbons, a moderate skin may beacceptable. How e ve r, in a marginal deve l-opment with a limited number of wells andtight margins, low skin may be ofp a ramount importance. Many high-anglewells are targeted to intersect multiple sandbodies. For these wells, the main objectiveis ensuring that all potentially productivesections of the well may flow so thatr e s e r ves access is maximized. Other wellsare drilled truly horizontal to maintain aconstant standoff with gas or wa t e r. Th emain driver in these wells is an even draw-d own to minimize coning.

Therefore, distribution of the damage isalso important. As part of an extensive study,BP confirmed that the percentage of thei n t e r val flowing, and distribution of thef l owing intervals over the length of a hori-zontal well may have a larger impact on

■The effects of washes on permeability damage. A joint industrystudy showed that, in some cases, washes significantly re d u c edamage levels; in others, washes increase damage.

■The effects of washes on bre a k t h rough pre s s u re. Data collectedby a joint industry study reveal a wide variation between thee ffectiveness of diff e rent mud systems when washes are used toremove or destabilize a filter cake. However, contrary to expecta-tions, more breakers were found to increase bre a k t h rough pre s-s u re than reduce it.

Spring 1997 9

p r o d u c t ivity than the reduction in perme-ability around the well (l e f t) .5 This wo r k ,carried out in Sunbury, England, pro-duced three key findings:• If a given percentage of filter cake is

r e m oved to allow a well to flow, it isbetter for this percentage to be dis-tributed over a large number of smalleri n t e r vals, instead of having all the flowc o n c e n t rated in a single, large interva l .

• The cleanup need not be complete.Rather than remove the filter cake,increasing its permeability to at least0.1 md is sufficient—filter-cake perme-abilities are typically 10- 2 to 10- 6 m d ,depending on fluid type, differentialpressure and solids content.6

• Damage by deep invasion of filtra t e —on the order of feet—causes only asmall reduction in productivity as longas the reduction in permeability is nottoo great ( b e l ow left).Studies such as this one by BP illustra t e

a central truth. There is no single bestt e chnique for the cleanup of unce-mented horizontal wells. The comple-tions engineer has a range of options thatmust be assessed for each field and eachwell stra t e g y. The only way of know i n gwh i ch is best is to understand the drillingfluid and its interaction with the forma-tion and completion hardware. Pra c t i c a loptions will vary depending on issuess u ch as environmental legislation, opera-tional risk or logistics—for example, acomplicated wash strategy may not bepossible if there is insufficient stora g ecapacity on the rig. There is also, quitec l e a r l y, no guarantee of success.

Thus, although the objective of anydrilling fluid design should be to delive ra well with no formation damage,drilling and production pra c t i c e sinevitably lead to some damage that maynot be removable. But if the well stillproduces to its full potential, this damagecould be termed “affordable.” As yet, thisconcept of affordability is not widelyreflected in industry pra c t i c e s .

■How distribution offlow affects flow eff i-ciency. The first wellschematic ( t o p ) i l l u s-trates 50% of the for-mation flowing fro ma single interval inthe heel of the well.The second wellschematic ( m i d d l e ),also shows only 50%of the well flowing.H o w e v e r, this time,flow is divided intosix evenly spacedflow intervals acro s sthe length of thewell. The graph ( b o t-t o m ), based on datag a t h e red by BP,shows how incre a s-ing the number offlowing intervalsi n c reases the flowe fficiency of a welleven though thetotal percentage ofthe well contributingto the flow re m a i n sc o n s t a n t .

■The impact ofn e a r- w e l l b o re per-meability re d u c t i o non flow efficiency. Asmall reduction inthe near- w e l l b o rep e rm e a b i l i t y — i nthis case up toabout 30%—has lit-tle effect on flowe fficiency and thed i ff e rences in depthof damage are notsignificant. How-e v e r, when perm e-ability re d u c t i o nreaches 60% and upto about 80%, thee ffect on flow eff i-ciency becomes pro-found and the diff e r-ences in depth ofdamage becomem o re marked.

4. R yan DF, Browne SV and Burnham MP: “MudCleanup in Horizontal Wells: A Major Joint IndustryS t u dy,” paper SPE 30528, presented at the 70th SPEAnnual Te chnical Conference and Exhibition, Dallas,Texas, USA, October 22-25, 1995.The work was undertaken as a joint industry projectby Amoco, BP, Chevron, Norsk Hydro, Saga, Shell,Statoil and TBC Brinadd.

5. Early work in this field is reported in:Goode PA and Wilkinson DJ: “Inflow Performance ofPartially Open Horizontal We l l s ,” paper SPE 19341,presented at the SPE Eastern Regional Meeting, Mor-g a n t own, West Virginia, USA, October 24-27, 1989.

6. For example, in a typical wellbore, a cake of 0.1-mdpermeability and thickness of 3 mm gives a skin of 5;a cake of 0.01 md gives a skin of 56.

(continued on page 11)

10 Oilfield Review

Stuck pipe during drilling operations is a major

n o n p roductive cost to the industry. 1 S t u c k - p i p e

incidents are generally divided into two main cate-

gories: mechanical and dif f e rential sticking. Which

of these problems is more dominant depends on

w h e re drilling is taking place. In the North Sea,

mechanical sticking is the main problem; in the

Gulf of Mexico, it is dif f e rential sticking.

Mechanical sticking includes a large number of

mechanisms, including hole collapse and key

seating. Dif f e rential sticking is the most common

single mechanism and occurs when part of the

drillstring becomes embedded in the mud filter

cake and is then held there by hydrostatic pr e s-

s u re, which exceeds the formation pr e s s u re. As

such, it can occur only where a filter cake has

been established—across permeable for m a t i o n s .

The pipe usually becomes stuck when it is station-

a ry adjacent to a permeable zone and there is a

significant mud overbalance. The likelihood of dif-

f e rential sticking increases with the length of per-

meable section being drilled—making extended-

reach and horizontal wells particularly vulnerable.

When it comes to preventing dif f e rential sticking,

the nature of the rock cannot be changed. High over-

balance pr e s s u res may also be needed to maintain

well control or wellbore stability. However, it is pos-

sible to modify mud composition and pr o p e rt i e s .

R e c e n t l y , a better understanding of dif f e re n t i a l

sticking led to the development of a new labora-

t o ry test tool to help design mud systems that

avoid dif f e rential sticking. Work carried out by

re s e a r chers at Schlumberger Cambridge

R e s e a r ch, Cambridge, England has concentrated

on the nature of mud filter cake—in par t i c u l a r

thickness, lubricity and str e n g t h . 2

A true measure of filter-cake pr o p e rties is not

c u rrently included in the suite of standard Ameri-

can Petroleum Institute (API) measurements r o u-

tinely carried out on drilling fluids. Although addi-

tional tests do exist, SCR r e s e a r chers have devel-

oped a new technique to measure filter-cake pr o p-

e rties that can be related to a fluid’s propensity to

encourage dif f e rential sticking. The technique is

designed as a low-cost, simple test that may be

c a rried out at wellsites.

A high-temperature, high-pr e s s u re (HTHP) fil-

tration cell was converted to create a stickance

tester ( a b o v e ). In this test, a filter cake is built up

a round a polished steel ball inside the cell. The

f o rce needed to rotate the ball is used to quantify

the nature of a filter cake.

Stickance Tester: Predicting a Mud’s Performance

■Stickance tester. The body of the device is a double-ended, high-temperature, high-pressure (HTHP) mudfiltration cell. The top end cap has been modified to allow the entry of a spring-steel wire through an o-ringseal set in the center of the cap. A new entry port has been drilled to allow the cell to be pressurized. Insidethe cell, the steel wire is connected to a 1.5-in. [3.8-cm] polished steel ball that rests on the filter medium atthe bottom of the cell. The end of the wire protruding from the cell is attached to an electronic torque gauge.

Spring 1997 11

Quantifying Aff o rdable DamageTo make sense of the notion of affordability,it is necessary to understand the conse-quences of damage. Although new produc-tion logging techniques are being deve l-oped, it is still difficult to extract fromhorizontal well tests all the informationneeded to make the required judgements.7Therefore, the productivity effects of forma-tion damage caused by drilling fluid inva-sion—or indeed the magnitude of the dam-age itself—are usually unquantified.

The need to close this knowledge gap hasbeen addressed in work carried out byr e s e a rchers at Schlumberger CambridgeR e s e a rch (SCR), Cambridge, England. Usingcore-flood experiments, they are determin-ing the formation-damage effects of drillingfluid invasion. Data from these experimentsare then used in accurate reservoir simula-tions that model the effects of this damageon productivity (see “How Core-Flood Te s t sAre Carried Out,” n ext page) .

New analytical expressions have beend e veloped that relate damage to the produc-tion potential of the formation. From themud, all information on filtration, inva s i o nand cleanup is channelled into the calcula-tions through the skin factor. Fo r m a t i o ndamage expresses itself through large posi-t ive skin values and hence lower productiv-ity index (PI) values and lower flow efficien-cies—that also take account of wellg e o m e t r y, formation thickness, permeabilitya n i s o t r o py, reservoir location, length of thewellbore and proximity of other wells.8

To help determine the return, in terms ofPI, from an incremental improvement in theperformance of a mud, numerical simula-tions using data generated by these analyti-cal expressions model the effects of damageon well producibility. These simulationsassess the implication of damage on reser-voir producibility, the implications ofincomplete penetration of the damage if awell is to be perforated (having assessed thedepth of damage from cores), and effects ofincomplete filter cake removal if a well isnot perfora t e d .

A test is carried out by placing the filter medium

re p resenting a permeable formation in the cell.

The filter medium is usually filter paper, although

c o res, sand packs and simulated fractured for m a-

tions may also be used in future versions of the

device. The cell is filled with drilling fluid, the top

end cap is installed and the ball and torque gauge

a re set in position. The cell is then placed in a

s t a n d a rd HTHP heating jacket. The mud is heated

to the desired temperature and then pressurized as

if a normal HTHP fluid-loss measurement were

being made—typically a dif f e rential pr e s s u re of

500 psi [3445 kPa] is used.

As filtration proceeds, a filter cake is built up on

the filter medium and around the steel ball. At pre-

cisely noted intervals—about every 5 minutes—

the torque gauge is rotated and the force needed to

f ree the ball from the filter cake is measured. This

m e a s u res both adhesion of the ball to the cake and

the force needed to break this bond. T o rque data

a re plotted as a function of the thr e e - q u a r ter power

■Typical plot in whichthe stickance is given bythe slope. Good repro-ducibility has beenachieved as long as con-sistent operating prac-tices are employed.

1. Bailey L, Jones T, Belaskie J, Orban J, Sheppard M, HouwenO, Jardine S and McCann D: “Stuck Pipe: Causes, Detectionand Prevention,” Oilfield Review 3, no. 4 (October 1991):1 3 - 2 6 .

2. Reid PI, Meeten GH, Way PW, Clark P, Chambers BD andGilmour A: “Mechanisms of Diff e rential Sticking and a Simple Well Site Test for Monitoring and OptimizingDrilling Mud Pro p e rties,” paper IADC/SPE 35100, p resented at the 1996 IADC/SPE Drilling Conference, New Orleans, Louisiana, USA, March 12-15, 1996.

7. Bamforth S, Besson C, Stephenson K, Whittaker C,B r own G, Catala G, Rouault G, Théron B, Conort G,Lenn C and Roscoe B: “Revitalizing Production Log-g i n g ,” Oilfield Rev i ew 8, no. 4 (Winter 1996): 44-61.

8. F l ow efficiency is defined as the flow rate with skind ivided by the flow rate without skin, at the samed raw d own pressure.

of time (t 3⁄4) to account for the buildup of filter cake

a round a spherical object. This plot usually gives a

straight line, the slope of which is the dif f e re n t i a l

sticking tendency—stickance ( a b o v e ).

Using this apparatus, SCR r e s e a r chers have

established mud formulation and engineering

guidelines to reduce the risk of dif f e rential stick-

ing. Fur t h e r, treatment options for field muds have

been investigated to help avoid sticking. The stick-

ance tester is now being pr e p a red for deployment

in field laboratories so that these services may

become generally available.

(continued on page 14)

12 Oilfield Review

Over the years, various core-flood experiments

have been per f o rmed to assess formation damage

by using equipment that measures per m e a b i l i t y

changes in rock cores before and after exposure to

drilling fluid. Researchers at Schlumberger Cam-

bridge Research (SCR), Cambridge, England have

c a rried out extensive tests, building up a wide

range of data. The experimental pr o c e d u re may be

divided into three stages:

Stage One: Sample Preparation and Initial Per-

meability Measure m e n t . The equipment at SCR

tests rock cores that are 25 mm in diameter and up

to 32 mm long. Cores are placed under vacuum to

remove entrapped air and then saturated in brine

or simulated formation water—this may be unnec-

e s s a ry if well-pr e s e rved re s e rvoir core is used.

Once pre p a red, the core sample is fir m l y

mounted in the sample holder so that there is a

seal between the rubber sleeve and the core. The

c o re holder is fitted into a standard high-tempera-

t u re, high-pr e s s u re (HTHP) fluid-loss cell body

How Core-Flood Tests Are Carried Out

■Core-flood equipmentfor initial permeabilitymeasurements. Detail ofthe core holder showshow the rock sample islocked into place.

Spring 1997 13

that is then filled with the test fluid to be used for

the permeability measur e m e n t — g e n e r a l l y

k e rosene, crude oil or brine. Finally, a standard

HTHP end cap is secured in place.

The valve stem at the top of the cell is then con-

nected to a 2.5-liter [0.7-gal] r e s e r voir of test fluid

that may be pressurized. The fluid passing thr o u g h

the rock is collected and its volume logged as a

function of time ( p revious page).

P e rmeability measurements are made by open-

ing the valve stem at the top of the cell to pr e s s u r-

ize the fluid inside. The valve stem at the base is

opened to start flow through the sample, and the

data logging is star t e d .

Test fluid is allowed to flow through the sample

at a fixed pr e s s u re. The volume of fluid collected

versus time is logged until a constant flow rate is

reached, indicating that the core has r e a c h e d

residual water saturation. Experience has shown

that for most rocks this constant rate is r e a c h e d

when approximately 100 pore volumes have

passed through the core.

At the end of the measurement, flow is stopped

by opening up the regulator and locking off the

valve stem at the base of the cell. After the fluid

re s e r voir and cell are depressurized, the top end

cap is removed and the cell is emptied of fluid in

p reparation for the mud-filtration phase.

Data may now be combined with fluid viscosity

and core size to calculate sample per m e a b i l i t y :

P e rmeability =

flow rate x fluid viscosity x sample length .c ross-sectional area x pre s s u re

Stage Two: Core Exposure to Test Fluid in a

Static or Dynamic Filtration Environment. F i l t r a -

tion—establishing a filter cake—may be per-

f o rmed under either static or dynamic mud flow.

The filtration phase may be set for a specified

period of time or until a pr e d e t e r mined volume of

filtrate is collected and may be per f o rmed at tem-

p e r a t u res up to 150°C [302°F] and pr e s s u res to

550 psi [3790 kPa].

To perf o rm filtration under static conditions, the

cell is filled with 200 mL mud, the standard end

cap is refitted and a pr e d e t e r mined pre s s u re dif-

f e rential is applied from a gas source. As with the

p e rmeability measurement, the volume of fluid

collected is logged as a function of time. Test con-

ditions are varied to mimic r e s e rvoir temperature

and expected mud overbalance pr e s s u re .

To perf o rm a dynamic filtration test, a paddle

s t i rrer is installed in the cell a fixed height above

the core after the mud has been poured into the

cell. The cell is then made up and placed back into

the HTHP heating jacket and the paddle is r o t a t e d .

F i n a l l y , filtration is r e s t a r ted. Once again, filtrate

volume is r e c o rded as a function of time ( r i g h t ).

This stirrer generates a range of flow conditions

f rom turbulent, where little or no external filter

cake forms, to laminar, which leaves filter cakes

similar to those formed under static conditions. At

the end of the filtration phase, the cell is depr e s-

surized before rotation of the paddle is stopped to

e n s u re that no filtration occurs under dif f e re n t

operating conditions.

■Schematic of equipment for initial permeabilitymeasurements with the stirrer installed for dynamicfiltration tests.

14 Oilfield Review

To understand how much damage is toler-able, the undamaged PI of a well must bek n own. Herein lies a major snag. Th eundamaged PI in horizontal wells is oftenu n k n own because it is difficult in horizontalwell tests to acquire reliable data for thep r o d u c t ive length of the well and the dam-age skin factor. This difficulty is due to well-bore stora g e — where fluid compressibilitymasks pressure changes—and the shortd u ration of early-time radial flow fromwh i ch skin is calculated (n ext page, t o p) .

Although a sensible baseline for well pro-d u c t ivity simulations should ideally bed rawn using existing horizontal wells in thesame field, the data uncertainty outlineda b ove renders this sort of reference informa-tion unreliable. Therefore, since understand-ing the PI of vertical wells is more stra i g h t-f o r ward, SCR researchers use a vertical wellin the same formation as a reference.9

Starting from the influence of formationt h i ckness and anisotropy on the skin factor,r e s e a rchers derived relationships that com-pare the flow efficiency of a horizontal wellwith that of a vertical well fully penetra t i n gthe same producing formation.1 0 A nove lexpression has been derived that calculatesthe length of horizontal section required tocreate a well with the same skin factor asthe vertical reference well. The expressioncombines all the geometric, reservo i r, andformation damage information necessary toassess effects on flow efficiency of the hori-zontal well.

The degree to wh i ch an increase in skinaffects productivity of a horizontal welldepends on its drainage area, wh i ch intro-duces the concept of “neutral skin.” At neu-t ral skin, production from both the horizon-tal well and its vertical reference is equallyimpaired. With a skin value below neutra l ,production from the vertical well is dispro-portionately reduced compared to its hori-zontal “sister” well. With skin greater thanthe neutral value, the horizontal well suffersa larger proportional production decrease.

Altering the horizontal well—for examplemaking it longer or increasing the dra i n a g era d i u s — m ay mitigate this effect, and adva n-tages of a horizontal well over a ve r t i c a le q u ivalent may be enhanced (n ext page,b o t t o m). This knowledge helps establish theminimum length or drainage area requiredfor a horizontal well. For a given geometry,s e n s i t ivity of a horizontal well to skin can beassessed and thus the level of affordabledamage inferred.

9. Renard G and Dupuy JG, reference 1.10. E ven if a vertical well has not been drilled, an

approximation of its PI may be estimated using available reservoir information.

Stage Three: Return - P e rmeability Measure-

m e n t . Following filtration, another measure of

c o re permeability is made to determine the level

of formation damage caused by the mud. The stir-

rer is removed and any remaining mud is pour e d

a w a y. The cell is then filled with test fluid, and the

end cap is fitted and sealed with a valve stem. The

cell is inverted and replaced in the stand, r e v e r s -

■Flow before and afterfiltration. Typically theinitial flow (blue) quicklyreaches a constant, whilethe re t u rn flow (red) maytake a significant time tostabilize as damagecaused by the drillingfluid may be cleaned upto some degree before asteady state is re a c h e d .

■Simulating produced fluids flowing through a damaged reservoir.

ing the direction of test fluid flow through the

c o re—the equivalent of producing the for m a t i o n

( t o p ). The same pr e s s u re is used as in the initial

p e rmeability measurement, although there is often

a significant time delay before a steady flow rate

is reached ( a b o v e ). The change in per m e a b i l i t y

b e f o re and after filtration may then be calculated.

Spring 1997 15

■Ratio of lost production from horizontal and vertical wells as a result ofdamage skin factors plotted for three similar wells with diff e rent drainagea rea radii: 1000, 2000 and 4000 ft. For a given well, the neutral skin value isfound at the intersection of the curve describing (qH/ qV)l o s t as a function ofskin with the horizontal line (qH/ qV)l o s t =1. Below this line, the incre m e n t a le ffect on flow rate of increasing skin will be greater for the vertical re f e re n c ewell than for the horizontal well. Above the line the opposite is true andi n c reasing skin will have a more deleterious effect on the horizontal wellthan on the vertical well. This effect is mitigated by increasing the drainageradius of the well, as can be seen from the graph, where a well withdrainage of 4000 ft remains below neutral for greater skin factors than doequivalent wells with smaller drainage radii. There f o re, placing many hori-zontal wells together in close spacing—thus reducing the horizontal drainager a t i o — i n c reases the susceptibility of individual wells to formation damage.

• Early-time radial flow is the first radial flow period (in the verti-cal plane), which ends when the effect of the top or bottomboundary is felt. For horizontal wells, this regime is short and diff i-cult to identify because of wellbore storage effects. This is unfortu-nate as it is the only regime in which formation skin damage maybe deduced directly from a well test.

• Intermediate-time linear flow develops if the well is sufficientlylong compared with reservoir thickness—where the spread offlow beyond the ends of the well is negligible compared to itslength. If the well is not long, there will be a long transitionbetween early-time radial flow and the next regime, bypassingthis one.

• Late-time radial flow is the second radial flow period (in the hori-zontal plane) that develops if the reservoir is sufficiently large andwide compared to the length of the well. The well behaves like apoint source in the middle of the form a t i o n .

• Late-time linear flow—the second linear flow period—beginswhen the pre s s u re transient has reached all lateral extre m i t i e s .

■Consecutive flow regimes observed for horizontal wells.

16 Oilfield Review

Bringing in Wells Without a CleanupThree possible options exist when dealingwith the drilling fluid prior to completing ahorizontal well with an uncemented liner ors c r e e n :• displace mud with a low-solids or solids-

free, clear fluid• displace mud with a breaker system• design the mud already in the well to flow

harmlessly through completion equipmentand bring the well into production with-out cleanup.For its part, BP has begun to use comple-

tions programs that, where pra c t i c a l ,e m p l oy the latter option—back - p r o d u c i n gdrilling fluid through prepacked screens.1 1

I n t e g ral to this strategy is a desire to elimi-nate the complications and expenses associ-ated with the other two strategies, wh i l eavoiding any chance that a breaker mightactually decrease rather than increase per-m e a b i l i t y. By opting for simplicity, the com-p a ny reasons it is cutting risk.

H ow e ve r, BP is reducing risk only if thedrilling fluid system can effectively flowthrough the prepacked screens without leav-ing permanent damage. Also, the well mustf l ow, lifting sufficient filter cake to enable fullp r o d u c t iv i t y. Critical to both of these objec-t ives is quality control of the drilling fluid inthe field—ensuring that it meets specifica-tions established by laboratory work.

From this, BP has drawn up a series ofguidelines. For example, solids loading mustbe below a critical level to avoid any log-jam effect that could occur as the fluidpasses through the screen; particle size dis-tribution must be carefully controlled as justa few percent of large particles bridging inthe screen may allow the many smaller par-ticles to form an impermeable cake; andparticle cohesiveness must be limited ase ven fine particles—such as weightinga g e n t s — m ay agglomerate into much largerparticles. The total volume of mud that willbe flowing per unit area of screen should becalculated and an excess used in the labora-tory tests; the field mud actually used to drillthe horizontal section should also be testedon the screens (a b ove) .

At the same time, the drilling fluid must notdamage well productivity by either com-pletely stopping flow from any reservoir sec-tion or significantly increasing near- w e l l b o r epressure drop and thus reducing well PI. Fo rthis reason, the effects of mud filtrate on theformation and the back f l ow pressurerequired to break through the mud filtra t eand establish production must also be tested.

For BP, tests like these now form an inte-g ral part of developing the ove rall well com-pletion plan. In essence there are threecomponents in a design loop: mud systemoptimization to fit the reservoir; cleanups t rategy to ensure selection of the simplestt e chnique that leaves no significant mud-related productivity impairment; and sandcontrol screen specification to best accom-modate anticipated downhole needs.

Completing the PictureM a ny of the steps described above are notn ovel. What is new is a much clearer accep-tance that drilling fluid design is one part ofa much bigger process. To understand howa reservoir will perform implies deep know l-edge of the number and type of wellsneeded; their length, angle and completiontype; and how they will perform—includinganticipated pressure draw d own and wa t e rconing. Drilling fluid design is an integra lpart of all of these.

There is a wide range of available fluids. Toselect the right one means that the mud anddrilling engineers must talk to many others p e c i a l i s t s — r e s e r voir geologists, productionchemists, drillers, completions engineers andlogging engineers—to establish their objec-t ives. The task then is to choose a drillingfluid that, in addition to meeting HSE needsand achieving the primary objective of ensur-ing the well can be drilled, helps ach i e vethese shared objectives. In the end, thismeans delivering a well that has sustained nomore than an acceptable level of damage.

The key is knowing what this acceptablel e vel is and how a given mud will affect ag iven formation in a given drilling situation.This need for understanding has been driv i n gr e s e a rch at BP Sunbury, SCR and elsewh e r e .The final piece needed to complete the pic-ture is an assessment of actual results ove rthe lifetime of wells. This process is only justbeginning, but when complete, drilling engi-neers will know that although zero damageis preferable for horizontal wells, permeabil-ity reduction is sometimes allowa b l e .

— C F

■Reducing the impact of an oil-base mud. Core-flood testing, carried out by BP withreservoir core under downhole conditions, showed a 99% permeability impairment. Laboratory work revealed an incompatibility between the synthetic-base oil and theemulsifier that caused precipitation in the rock pore throats. Changing the emulsifier and then reducing its concentration cut permeability impairment to 70% and 36%,respectively. In fact, the field sample showed only a 12% reduction in perm e a b i l i t y ,which had a negligible effect on well pro d u c t i v i t y .

11. B r owne SV, Ryan DF, Chambers BD, Gilchrist JMand Bamforth SA: “Simple A p p r o a ch to the Cleanupof Horizontal Wells with Prepacked Screen Comple-t i o n s ,” paper SPE 30116, presented at the SPE Euro-pean Formation Damage Conference, The Hague,The Netherlands, May 15-16, 1995.