Formation Damage

CM 12

COMPLETION FORMATION DAMAGE of 36

MANUAL Issue 1PROPRIETARY INFORMATION -For Authorised Company Use Only January 1998

DRILLING DEPARTMENTPETRONAS CARIGALI SDN BHD

CHAPTER 12

FORMATION DAMAGE

TABLE OF CONTENTS

12.1 INTRODUCTION ……………….…...……………....………….….….…..….… 3

12.1.112.1.212.1.312.1.412.1.512.1.6

Chapter Goals ……………………………………………………….Poor Productivity …………………………………………………...Formation Damage …………………………………………………Wellbore Deposits ………………………………………………….Ineffective Perforating ……………………………………………...Treating Approaches ……………………………………………….

3 3 3 4 5 5

12.2 EFFECT OF DAMAGE …………………………………………………………. 6

12.2.112.2.212.2.312.2.412.2.512.2.612.2.712.2.812.2.9

Radial Flow …………………………………………………………Darcy’s Law ………………………………………………………...Radial Reservoir Flow ……………………………………………...Productivity Index ………………………………………………….Inflow Performance ………………………………………………...Effect Of Damage Zone Thickness …………………………………Effect Of Damage Location ………………………………………..Matrix Treating Benefits……………………………………………Matrix Treating Undamaged Wells ………………………………...

6 6 7 10 10 12 14 15 15

12.3 INDICATORS OF DAMAGE ……………………………………………...……. 17

12.3.112.3.212.3.312.3.412.3.512.3.6

Introduction …………………………………………………………Offset Production …………………………………………………...Production History ………………………………………………….Reservoir Predictions ……………………………………………….Darcy’s Law Calculations …………………………………………..Well Testing ………………………………………………………..

17 17 17 18 18 18

CM 12




12.4 CAUSES OF FORMATION DAMAGE …………………....…...……………… 21

12.4.112.4.212.4.312.4.412.4.512.4.612.4.712.4.812.4.912.4.1012.4.1112.4.1212.4.13

Introduction …………………………………………………………Clay Disturbance …………………………………………………...Clay Swelling ………………………………………………………Clay Dispersion And Migration ……………………………………Low Salinity Clay Dispersion ……………………………………...Flow Induced Fines Migration ……………………………………..Effect Of Mobile Water …………………………………………….Scale Deposition ……………………………………………………Asphalt And Paraffin Deposition …………………………………..Emulsions …………………………………………………………..Water Blocking …………………………………………………….Wettability Changes ………………………………………………..Acid Precipitates ……………………………………………………

21 22 23 23 23 24 24 26 27 27 29 30 30

12.5 DAMAGE REMOVAL ………………………………………………………...… 31

12.5.112.5.212.5.312.5.412.5.512.5.6

Introduction …………………………………………………………Matrix Treatments ………………………………………………….Acidizing ……………………………………………………………Solvents And Surfactants …………………………………………..Hydraulic Fracturing ………………………………………………..Tubing Treatments ………………………………………………….

31 31 31 31 32 32

12.6 DAMAGE PREVENTION ….....…………………………………………………. 33

12.6.112.6.212.6.312.6.412.6.512.6.612.6.712.6.812.6.9

Drilling Fluid Selection …………………………………………….Workover Fluid Salinity ……………………………………………Brines To Stabilize Clays …………………………………………..Clay Stabilizers ……………………………………………………..Avoid Incompatible Brines …………………………………………Surfactant Selection ………………………………………………...Drawdown …………………………………………………………..Fluid Loss Control ………………………………………………….Injection Water Quality …………………………………………….

33 33 34 35 35 36 36 36 36

12.1 INTRODUCTION

CM 12




12.1.1 Chapter Goals

The purpose of this chapter is to introduce the engineer to the common causes of poorproductivity which can be remedied by workover treatments. Special emphasis is given topoor productivity attributable to permeability reduction of the formation near the wellbore,commonly referred to as damage. Upon completing this section, the engineer should beable to recognize well productivity impairment, review information to identify its likelysource, and avoid causing formation damage when possible.

The radial flow theory necessary to understand the effects of damage and estimateunimpaired production is presented first. This is followed by a discussion of indicators ofdamage, causes of damage and damage prevention. Finally, a brief introduction to damagetreatments serves to bridge the gap between this and subsequent sections.

12.1.2 Poor Productivity

There are two major categories of poor productivity : (1) poor productivity attributable toreservoir characteristics, and (2) poor productivity caused by alterations in the formationnear the wellbore or deposits in the production tubulars. Reservoir factors such as lowpressure, low permeability, and high viscosity may be overcome through methods involvingflooding, thermal methods and large hydraulic fracturing treatments. These approacheshave in common that they are designed to affect large reservoir areas. However, for thepurpose of this section, we are interested in causes of poor productivity that can beremedied by workover treatments localized to a particular well. Included in this categoryare formation damage and well deposits.

12.1.3 Formation Damage

Poor productivity caused by flow restrictions in the reservoir rock is called formationdamage. Formation damage is usually caused by disturbances to the formation or its nativefluids during drilling, workover, and producing operations. Formation damage is generallylimited to the reservoir rock lying within a couple of radial feet of the wellbore asillustrated in Figure 1.

CM 12




Figure 1. Damaged Zone Around A Wellbore Restricts Production

In contrast to reservoir limitations, formation damage can often be removed with relativelysmall treatments designed to treat the wellbore or penetrate only a limited distance into theformation.

12.1.4 Wellbore Deposits

Material deposited in the production tubing and casing also is a common cause ofproductivity declines. Such deposits can consist of organic material such as paraffin, ormineral material such as calcite and barite, known as scale. These and similar solids oftenprecipitate from produced fluids as they re-equilibrate with wellbore conditions. Removingwellbore deposits often involves a different approach than removing formation damage.

12.1.5 Ineffective Perforating

CM 12




Optimal flow rate from a particular well is also dependent upon establishing goodcommunication between the wellbore and the reservoir. This is the goal of perforating. Forvarious reasons however, perforations may not provide the necessary good communication.Charges may fail to ignite, or ignite below their design force, or the cement sheath may bethicker than the limited penetration depth of the gun. These limitations are associated withgun capabilities and may require re-perforation to achieve satisfactory flow.

The perforating technique is also important for attaining perforating objectives.Specifically, it is widely recognized that perforations shot underbalanced in a clear fluidperform better than those shot overbalanced in mud. Overbalancing causes perforationdebris and mud to become compacted in the tunnels, often necessitating an acid job toattain maximum deliverability. These are but a few examples of how the perforatingprocess can effect well performance. For a more complete discussion refer to the sectionon Perforating.

12.1.6 Treating Approaches

The type of treatment chosen is determined by the cause of the productivity impairment.Formation damage is often treated with acids and solvents which are injected into the rockmatrix, so that flow restrictions will be dissolved. Material deposited in the wellbore mayalso be remove with solvents, usually with less volume than required for matrix treatment.In some cases, mechanical methods may be necessary to remove wellbore restrictions.

Hydraulically fracturing a formation will often be successful at by passing a zone ofdamage. While such treatments are frequently designed to stimulate reservoirs byovercoming naturally low permeability, added benefit often is realized from by passingdamage. In fact, smaller volume fracturing treatments are often designed only to penetratea damage zone immediately around the wellbore. However, fracturing treatments in generaltend to be more involved and costly, and there are added risks. Therefore, it is usuallydesirable to remove damage with matrix treatments whenever possible.

12.2 EFFECT OF DAMAGE

CM 12




12.2.1 Radial Flow

The severity of formation damage is a consequence of the radial flow pattern of reservoirfluids. Flow in an unfractured reservoir proceeds via radial geometry, in which fluidstraverse progressively smaller volumes of rock as they approach the wellbore.Consequently, the greatest pressure drop occurs in the formation adjacent to the wellbore,making overall production very sensitive to permeability reductions there.

12.2.2 Darcy’s Law

Henry D’Arcy, while studying the operation of sand filters for municipal water treatment inFrance during the mid-1800’s, deduced the basic law for the flow of a single liquid througha porous medium. Darcy (his name has long since been Anglicized) observed that thevelocity of flow is directly proportional to the pressure gradient, dp/ds, and inverselyproportional to fluid viscosity, µ. This proportionality is expressed in the followingequation;

v = - k dp µ ds (1)

where k, the constant of proportionality is a characteristic of the porous medium called thepermeability. The velocity referred to in this equation is the apparent velocity and is equalto volumetric flow rate divided by the area through which this flow occurs, i.e., v = q/A. Incgs units, v is expressed in centimeters per second, viscosity in centipoise and pressuregradient in atmospheres per centimeter. Similarly, volumetric flow rate is expressed incubic centimeters per second and area in square centimeters. In these units theproportionality constant, k, is expressed in darcies.

Darcy’s Law applies to the laminar flow region only. Turbulent flow may occur in porousmedia provided that flow rate is high enough, fluid viscosity low enough, or thecharacteristic pore dimension large enough. In non-Darcy flow the pressure gradientincreases at a rate greater than flow rate. However, non-Darcy flow seldom occurs withliquids flowing through porous media except in the case where very high injection orproduction rates are encountered, and then only in the region nearest the wellbore. For gaswells, however, non-Darcy flow is by no means uncommon. Calculations based on Darcy’sLaw on gas wells producing at high rates can be seriously in error.

12.2.3 Radial Reservoir Flow

Although flow very near the wellbore probably occurs via a complex combination ofgeometries, most near-wellbore flow problems are analyzed by assuming a radial flow

CM 12




model throughout the reservoir. Radial flow actually occurs only in an open holecompletion from a formation of uniform permeability, as idealized in Figure 2.

Figure 2. Radial Flow

As a practical matter, however, flow from densely perforated completions can besuccessfully analyzed by employing the radial flow model. When Darcy’s equation ismodified for radial geometry and converted from cgs units to customary field engineeringunits of psi, barrels per day, millidarcies and centipoise, the final equation relates surfaceproduction rate to pressure drop, formation permeability and fluid viscosity :

Q = 7.08 x 10-3kh (Pe Pw) re µ Bo ln rw (2)

Q = flow rate, stock tank barrels/day

k = average formation permeability, millidarcies

h = interval thickness, feet

CM 12




Pe = formation pressure at external drainage radius, psi

Pw = flowing wellbore pressure at perforations, psi

µ = oil viscosity at formation temperature, centipoise

Bo =

re = drainage radius of well, feet

rw = wellbore radius, feet

Notice that the factor Bo appears in the equation. This factor is used to account for thevolume change of crude oil from the time it flows into the wellbore to the time it ismeasured in a stock tank. This factor is determined from an analysis of a crude sampletaken at a particular point in a well’s production history. This equation can be used toestimate an oil well’s flowing potential, if the required reservoir and wellbore factors areknown or can be estimated.

A slightly different equation exists for gas wells, and includes terms to account for gascompressibility. This equation takes the form

Q(MScf/D) = 7.03 x 10-4kh (P2e P

2w)

re µ T z ln rw (3)

where the additional term T is Rankine temperature, and z is a dimensionless factoraccounting for gas deviation from ideality.

The drainage radius is inferred from well spacing. For example, the drainage radius for awell spacing of 40 acres is 660 feet. This can be verified by noting that a circle with radiusof 660 ft can be inscribed within a square 40-acre unit. Similarly, for 160 acre spacing, thedrainage radius is 1320 ft, and for 640 acre spacing, the drainage radius is 2640 feet. Thus,quadrupling the spacing doubles the drainage radius.Common well spacings and corresponding drainage radii are summarized in Table 1 :

TABLE 1

reservoir fluid volume factor, stock tank barrelsreservoir barrels

CM 12




Well SpacingAcres

Drainage RadiusFt

10 20 40 80160320640

330 467 660 933132018672640

While the concept of a drainage radius and wellbore radius is precise, neither quantity isknown with great precision. In the case of the wellbore radius, for example, this radius isclearly not the inside radius of the casing, nor even the outside radius of the casing, butrather the radius of permeable formation beyond the cement sheath at the cement-formationinterface. This radius is not always precisely definable because of hole enlargement orfilter cake deposition. Additionally, flow is through a perforation at this point and hence,departs markedly from radial flow in the immediate vicinity of the perforation.Nonetheless, these imprecisions on the determination of rw have less effect than might beanticipated because of the logarithmic term in which re and rw appear. For example, in an8” diameter wellbore (rw = 4 in or 333 ft) for a well on 40-acre spacing (re = 660 ft) the ratioof re over rw is 1980 and the logarithm of 1980 is 7.59. An increase in the internal radiusfrom 4 in to 6 in, i.e., 50 percent increase in the value of rw yields a value of 7.18 for thelogarithmic term which is a decrease of less than 6 percent in the value of this quantity.Thus, the effect of the uncertainty is greatly reduced in the final calculation.

In the practical application of this equation Pw is generally determined by measurementswith a bottomhole pressure bomb positioned adjacent to the sand face near the middle ofthe perforated interval during the period when the well is flowing. Pe’ the pressure at thedrainage radius is generally estimated from a shut-in pressure buildup test. For relativelypermeable formations, this can be determined within a reasonably short shut-in period (say24 hours) provided bottomhole pressures have substantially stabilized during this period.More involved methods, however, must be employed on formations of low permeability toobtain a suitable Pe.

The viscosity of the crude at reservoir temperature can be obtained from a hydrocarbonreport if available, or estimated from correlations of oil gravity and viscosity. Viscosity ismeasured in centipoise, and can be compared to water at 1 cp.

Using the above equation, the average permeability of the formation may be estimated from

CM 12




a given flow rate at known pressure drawdown (Pe - Pw). This calculated permeability willrepresent an average, which will include the effects of any damage zone that is present. Asdiscussed further in the text, comparing this average permeability with independentlymeasured formation permeability from core data or a buildup test often serves as anindicator of well damage. Alternatively, this equation can be used to estimate flow ratefrom a knowledge of formation permeability. In this case, permeability may be inferredfrom buildup test data or core permeability measurements, when available.

12.2.4 Productivity Index

For field applications in which comparisons among wells in the same formation are oftenrelied upon as an indicator of damage, many of the terms in Darcy’s equation will cancelout to give a simplified, convenient measure of productive capacity, called productivityindex, J :

J = (4)

The productivity index can be used to compare well performance within a given formation,where formation properties are constant. The Specific Productivity Index, J per foot ofinterval, is a way of accounting for differences in formation thickness from one well to thenext.

12.2.5 Inflow Performance

The productivity index is a limited concept in that it assumes that there is no relativepermeability during production; i.e., no other reservoir fluids are being produced with theprimary production fluid. Since the production rate is directly proportional to the pressuredrawdown, both will decrease proportionally as the well is depleted, and the productivityindex should remain relatively constant. The only reservoir characteristic that will alter theproductivity index is the presence of relative permeability.

In particular, the productivity index will decline in a well with a solution-gas drive reservoirwhen the reservoir pressure falls below the bubble point of the formation’s crude oil. Thebubble point is the pressure at which gas begins to evolve from the crude. As gas isreleased from the oil, it begins to fill the pore spaces, making it more difficult for oil toflow. An inflow performance curve which is more applicable to a well producing below itsbubble point is shown in Figure 3. This curve demonstrates that a greater drawdown is

Pe - Pw

q

CM 12




required to obtain a given production rate as reservoir pressure declines below the bubblepoint (when the straight-line relationship does not hold). When producing at reservoirpressures below the bubble point, the productivity index will decline with time.

Figure 3. Typical Inflow Performance Relationship for Solution Gas Drive Reservoirs

When evaluating the productivity of a well by comparing its specific productivity index tothat of other wells, it will be necessary to first determine if a given well is producing aboveor below its bubble point pressure. If the specific productivity index of a well is lower thanthe specific productivity index of offset wells, it may not be damaged but simply producingbelow its bubble point. The bubble point for various crudes will differ from one field toanother, depending on the fluid properties and temperatures of a given formation.

CM 12




re

rw

J/Jo = re

rw

12.2.6 Effect Of Damage Zone Thickness

As a natural consequence of radial flow, formation damage that is located closest to thewellbore exerts the greatest adverse influence on production. Of course, the thicker ordeeper the damage zone is, the greater the reduction of productivity. However, oncedamage to the near wellbore region occurs, deepening of the damage adds a progressivelysmaller contribution to production loss. This is mathematically shown by manipulatingDarcy’s equation to include a zone of damaged permeability, kd, of thickness rd. Theresulting equation relates the productivity index of the damaged formation to the nativeformation (J/Jo) and the depth and magnitude of damage :

(5) log + αlog

where α is the ratio of damage zone permeability to virgin permeability. These dimensionsare illustrated in Figure 4 for an idealized damage zone. Plotting the above equation forvarious amounts of damage, α, as a function of depth of damage radius shows that thegreatest effect of damage is within the first two inches of the wellbore (Figure 4), withdiminishing influence as depth of damage invasion increases.

re

rwαlog

CM 12




Figure 5. Effect of Moving a Zone of Damage of Constant Thickness Outward from the Wellbore

CM 12




12.2.7 Effect Of Damage Location

The fact that damage is most harmful near the well also implies that a damage removaltreatment will be effective even though it may not penetrate deeply enough to remove alldamage. This is also mathematically founded in Darcy’s equation, which, when rearrangedto describe a residual zone of damage around the wellbore gives :

re

rw

(6)

Figure 5. Effect of Moving a Zone of Damage of Constant Thickness Outward from the Wellbore

As shown in Figure 5, a hypothetical zone of damage 6 inches thick exerts less influencesas it is placed further from the wellbore. This demonstrates that, although deep damageremoval may be desirable for complete recovery in some cases, it is not essential. Benefitscan be derived from removing damage near the wellbore even if the deeper portion can’t beremoved.

rd

ru

ko

kd

re

rw

ln

ln ln− 1+J/Jo =

CM 12




12.2.8 Matrix Treating Benefits

Removing damage with solvents can result in productivity many times the damagedproductivity, depending on the extent of initial damage. For example, Figure 4 indicatesthat a well which contains a 90% reduction in permeability in the first foot around thewellbore has a flow efficiency near 35%. Therefore, a properly designed damage-removaltreatment has the potential to increase the production rate by a factor of three. Suchdamage removal benefits are estimated on the assumption of uniform, radial removal ofdamage from within the matrix of the rock, hence such treatments are often referred to asmatrix treatments. Hydraulic fracturing, as discussed later, can also yield these benefits, bya mechanism which causes the damage to be bypassed. However, a fracture treatment mustbe intentionally designed in order to be effective. Fracturing a treatment intended formatrix injection will generally yield disappointing results.

12.2.9 Matrix Treating Undamaged Wells

Matrix treating only offers the potential for significant productivity improvement indamaged wells. Little benefit can be expected if no damage is present. The negligiblebenefits of undamaged well treating can be dramatized with the aid of Equation 5, this timeby approaching the limit of α = ∞ for the hypothetical case of a treatment which infinitelyincreases near wellbore permeability of a 6-in. well completed on 40 acre spacing.Physically, this would require underreaming the formation with a drill bit, therebyremoving all rock.

As shown in Figure 6, very little benefit can be expected from even such an extremeoperation as removing all rock radially out to 10 feet. A productivity index increase of twofold is about the best to expect. In reality, such permeability increases are not possible withmatrix treatments, and production increases would be negligible. Furthermore, somedamage removal treatments may create damage if not performed properly. For thesereasons, there should be evidence of formation damage before a matrix treatment isimplemented.

CM 12




Figure 6. Stimulation of an Undamaged Well

12.3 INDICATORS OF DAMAGE

CM 12




12.3.1 Introduction

There is a large incentive for being able to identify the presence of treatable formationdamage, since the economic return of a field often depends on maintaining maximumproductivity from each well. Treatments performed on undamaged wells are wasted at best,and may actually lead to increased damage. We can avoid many problems associated withincorrect diagnosis by exploiting the evaluation tools available, including productivitycomparisons, calculated production estimates, and well testing.

12.3.2 Offset Production

A common indicator of well damage is low productivity relative to offset wells in the sameformation. The specific productivity index, J/ft of interval, provides a means forquantifying this comparison. A substantially lower specific productivity index relative toother wells in the field suggests that damage is present. However, although this is a usefulapproach for initial screening, this concept is limited by the heterogeneous makeup of manyformations. Therefore, additional diagnostics and data should be gathered prior to decidinga course of remedial action.

12.3.3 Production History

Comparison of present production with past production history is a good indicator ofproblem wells, providing that normal reservoir decline is accounted for. Productivityindex, J, is especially useful for comparing production from the same well at differenttimes, since formation factors are likely to remain constant.

After an abnormally high production decline has been verified, the well’s history can giveimportant clues as to the type of damage present. Low productivity may be traceable to aspecific completion, workover or production practice. For example, formation damage isoften common after well killing operations, especially if drilling mud is used as a workoverfluid. Injection of unfiltered brines into disposal or injection wells is a common cause ofreduced injectivity. Instances such as these should be looked for in well files when damageis suspected.

12.3.4 Reservoir Predictions

CM 12




Reservoir engineering calculations which predict production history are important guides toa well’s potential, against which actual performance can be measured. A decline inproductivity which is inconsistent with reservoir predictions is reason to suspect damage.

12.3.5 Darcy’s Law Calculations

The previous subject detailed the use of the radial flow equation to estimate production, andthe use of this approach is an important part of diagnosing possible problems. If rockpermeability and hydrocarbon properties are known, a rough estimate of productivity indexcan be calculated using Darcy’s equation and compared to the actual value. Althoughlimitations on our knowledge of the true rock permeability will make accurate predictionsdifficult, large discrepancies imply formation damage.

12.3.6 Well Testing

Well testing is generally understood to encompass flow testing and pressure buildup testing.Flow testing can provide productivity index, fluid ratios, and a measure of averagepermeability. Changes in flow rate or relative fluid production from one test period toanother are often signs that the well is damaged.

Pressure buildup testing is a relatively sophisticated approach to measuring reservoirpermeability and obtaining an indication of formation damage. A buildup test involvesflowing the well at constant rate buildup of pressure in the formation is monitored. Therate at which this pressure re-establishes itself after being drawn down is a measure of thenative formation permeability, and the presence of a damage zone.

The ideal system is a single well in an infinite, homogeneous reservoir containing a fluidwith constant properties but with no altered zone around the well. If this well is shut in atthe sand face after producing at a rate q for Horner time, th, the sandface pressure at time ∆tafter shut-in given by :

Pw - Pi = 162.6 qµ Bo log kh (7)

This equation suggests that a plot of Pw vs log (th + ∆t/∆t) will be a straight line forcircumstances adequately described by the ideal reservoir model. Bulk formationpermeability can be obtained from the slope, m, of this straight line by :

K = 162.6 qµBo

mh (8)

th + ∆t ∆t

CM 12




Original reservoir pressure, Pj, is obtained by extrapolating the straight line to infinite shut-in time; i.e., where (th + ∆t)/∆t = 1 (See Figure 7).

In actual buildup or fall of test, it is rare for straight line to be observed over all shut-intimes. Instead, field curves have various shapes, which can be explained with the depth-of-investigation concept. Field curves can logically be divided into three regions, as shown inFigure 8. At early times, the depth of investigation is near the wellbore. Accordingly,conditions in the altered zone (such as formation damage) determine the character of thecurve. In addition, continued production into the well (afterflow) because of surface shut-ininfluences the curve in this region. “Afterflow” occurs because the compressibility of fluidin the wellbore will permit residual feed in, even after shut in. This effect, which interfereswith early time data analysis, can be eliminated or reduced by using bottomhole shut-inequipment.

Formation damage is often indicated by the shape of the curve in region I. A steeply risingslope suggests a high pressure drop caused by formation damage. A numerical estimate ofdamage, called the skin factor, “s”, is obtainable from this region. Although its calculationis beyond the scope of this text, it is worthwile to gain an appreciation of typical skin factormagnitude. A skin factor of 0 indicates that no damage is present, while positive skinfactors are typical of damaged formations. Typically, a skin factor of 5 - 10 may indicatemoderate levels of damage, while factors above 10 indicate severe damage. Very high skinfactors, say 30 and above, may sometimes be attributable to ineffective perforationpenetration or incomplete perforation of an entire interval. These possibilities should beinvestigated in cases of high skin factors. Negative skin factors often are indicative ofstimulated wells.

In the middle time region, the depth of investigation has moved beyond the region ofinfluence of the altered zone and is not yet affected by conditions at the drainage boundary.Bulk formation properties are the dominant influence. A straight line with slope m usuallyoccurs, from which bulk-formation permeability can be obtained just as if the reservoirwere infinite. Permeability can be obtained from the slope of the MTR using equation 8.

The flow rate q, is the maintained prior to the shut-in period. If they are not accuratelyknown from hydrocarbon analyses, the viscosity and formation volume factors can beestimated from correlations using API gravity and gas/oil ratio obtained at the wellsite.

The buildup measurement of kh gives us a value to compare with average kh obtained fromproduction testing. If kh (buildup) is significantly greater than kh (flow), formation damageis indicated.At late times, the depth of investigation has reached the well’s drainage boundaries.Pressure behavior is accordingly influenced by conditions at these boundaries

CM 12




Figure 7. Ideal Build-up

Figure 8. Actual Build-up

12.4 CAUSES OF FORMATION DAMAGE

CM 12




12.4.1 Introduction

Formation damage implies that hydrocarbon flow through reservoir rock has been impaired.Solids plugging probably is the major cause of damage problems. As a category, solidsinclude native clays and fines, materials precipitated from reservoir fluids (mineral scale,asphalt, paraffin) and solids introduced by drilling mud (barite, bentonite, drilled rock).They can range in size from sub-micron clay particles to perforation and wellbore-fillingscale deposits. Some clay solids are illustrated in Figure 9.

Figure 9 Examples of Native Formation Clays

CM 12




Figure 10. Osmotic Swelling of Clays

Other established causes of damage are emulsion blocking, water blocking, and wettabilitychanges. These conditions adversely affect production through different mechanisms butnevertheless the end result can be as harmful as solids damage. A more recently recognizedform of damage occurs as a result of reprecipitation of dissolved material during sandstoneacidizing.

12.4.2 Clay Disturbance

Clays are probably the fine particles most often responsible for damage. They can impairpermeability several ways. First, all clays are prone to dispersion and migration whendisturbed.

Foreign fluid invasion and fluid flow forces are common disturbance which are oftenblamed for causing clay migration subsequent plugging. The second widely accepteddamage mechanism involves swelling. There is a variety of clay known as smectite(montmorillonite) which can expand to several times its size upon water absorption. Thisexpansion is believed capable of causing blocking of pore spaces, especially if the clays arelocated at critical pore throats. These clays are also more prone to disperse and migratewhen they expand. Consequently, they can restrict pores by a dual mechanism ofexpansion and migration if disturbed. A scanning electron microscope photo of smectite isincluded in Figure 9.In actuality, attributing damage to either of these mechanisms exclusively is overlysimplistic. Clay damage probably proceeds via a combination of these and othermechanisms in most cases.

CM 12




12.4.3 Clay Swelling

Swelling is believed to occur because of an osmotic pressure difference between the bulkfluid and the interlayer region of the clay particle. This theory explains the sensitivity ofclays towards brines with salinity sharply lower than the connate brine. Water moleculesfrom a less-saline brine will enter a clay structure containing higher salinity brine. Thisoccurs because osmotic forces tend to equilibrate the lower bulk salinity with the highersalinity in the vicinity of the clay layers, as conceptualized in Figure 10.

Divalent cations such as Ca ++ and Mg ++ limit clay swelling by holding the clay layerstogether more tightly. This is also true of K + and NH4

+, monovalent cations which areeffective at reducing swelling because they fit well into the clay structure. Regardless ofwhich cation is responsible for stabilizing clays, the effect is reversible. Stabilizing cationscan be replaced by re-exposure of clays to sodium, after which the clays are prone to lowsalinity damage.

12.4.4 Clay Dispersion and Migration

Clays also reduce permeability by dispersing and migrating. In this case, they can lodge inpore throats, causing blockage. Although this pore blockage occurs on a microscopic scale,the result is a reduction of the bulk rock permeability. Migration can be caused by salinityincompatibility with introduced brine and mechanical forces on particles during fluid flow.Either or both of these causes may be operative at the same time.

12.4.5 Low Salinity Clay Dispersion

Abrupt salinity reductions of the clay environment will often cause clay particles to detachfrom each other and the sand grain surfaces, as shown in Figure 11. Clays in this detachedstate are free to migrate until they bridge at pore constrictions and reduce fluid flow.

The charge characteristics of clays explain their tendency to disperse upon exposure to lowsalinity brines. Clays are characterized by a negative surface charge which attracts adiffuse layer of cations such as Na+ and Ca++. This layer of cations experiences twoopposing forces which counteract each other. A diffusional force away from the claysurface. The tendency for diffusion increases if the salinity is reduced, causing the layer ofions to expand and exert repulsive forces on nearby particles, as shown in Figure 11.This mechanism believed to be responsible for dispersing clays, especially if salinityreduction is abrupt. However, evidence has shown that reduction in salinity sometimes willbe completely non-damaging if introduced gradually. This suggests that the repulsiveforces causing dispersion can be rendered less damaging if they are taken in a stepwise

CM 12




fashion. This observation has important practical implications for workover fluids. If lowsalinity brine must be used, severe damage can be avoided by exposing the formation toprogressively lower salinity brine until the desired strength is attained.

Figure 11. Low Salinity Causes Clay Dispersion

12.4.6 Flow Induced Fines Migration

The foregoing discussion suggests that dispersion damage can be avoided by the properchoice of fluids introduced to the formation. This is true, up to a point. Clays, as well asother fine particles, can be mobilized by fluid forces exerted by fluid flow, and this problemis more difficult to avoid. As shown in Figure 12, fluid flow velocities increasedramatically towards the near wellbore region, and it is possible to entrain particles from afew feet into the reservoir, particularly in a high rate well.

12.4.7 Effect of Mobile Water

Entrainment of fines by fluid flow has been shown to be related to the mobility of the waterphase. Clays and silica fines, being generally water-wet will experience greater fluid forcesif the water phase flows. This concept is illustrated in Figure 13, which portrays physicallaboratory observations made under a microscope.

Field observations tend to support this concept, since it is generally true that the onset ofwater production marks the onset of sand production in poorly consolidated fields. Coning,flood breakthrough, and workover fluid leakoff are a few mechanisms by which anirreducible water phase, and hence fines, may become mobilized.

CM 12




Figure 12. High Fluid Velocity near Wellbore Can Cause Fines Migration

Figure 13.

12.4.8 Scale Deposition

Scale deposition occurs because produced fluids seek to regain equilibrium with the newenvironment in the wellbore. As a result, solid mineral material, called scale, is oftendeposited if solubility limits are exceeded under well conditions. Common scales includeCaCO3 (calcite), CaSO4 • 2H2O (gypsum). and BaSO4 (barite).

CM 12




Calcite scales are generally deposited as a result of pressure drop and CO2 gas evaluationfrom produced brine, according to the equation :

Ca++ + 2HCO3 ➙ CO2 (gas) + CaCO3 + H2O

Deposition may occur in the perforations or tubing, depending on flow conditions. Figure14 shows a scale buildup in a laboratory perforation which was exposed to downhole flowconditions. The above equation also implies that calcite scale can form if a natural brinerich in HCO3 is exposed to a Ca++ brine. This is also an established damage mechanism.Calcite scales are very soluble in ordinary acids, so their removal is generallystraightforward.

Scales such as CaSO4 and BaSO4 are deposited as a result of temperature and pressuredrops which the produced fluids experience. Although these scales can be deposited in theperforations or tubing, they usually occur in the tubing. Both of these scales are insolublein acids although there are treating chemicals available which will convert CaSO4 into anacid soluble form. There is no solvent for BaSO4, therefore this scale is often mechanicallyremoved.

Figure 14. Scale Buildup in Simulated Perforation

12.4.9 Asphalt and Paraffin Depostion

Asphalt and paraffin are organic species which precipitate from produced hydrocarbons.Temperature and pressure changes can be responsible for inducing their appearance whenthey are present in the oil. Although reductions in temperature will cause reducedsolubility, reductions in pressure have a more complicated effect. Pressure reductions mayactually increase asphalt solubility by allowing methane and CO2 to escape. Both of these

CM 12




gases are known to reduce asphalt solubility. However, paraffin is less soluble in theabsence of methane, so its solubility decreases as pressure decreases below the bubblepoint.

12.4.10 Emulsions

An emulsion is a dispersion of one immiscible phase in another (Figure 15). Emulsions canexhibit varying degrees of stability, some having lifetimes of only seconds, others beingindefinitely stable. Much of the world’s oil is produced in the form of emulsions, oneestimate being as high as 70%. These emulsions are usually produced by fluid shear in thetubing, and therefore do not affect formation productivity. However, the formation ofemulsions within the pore spaces of rock does occasionally occur, and in these casesproductivity suffers.

Figure 15. An Emulsion is a Dispersion of One Phase in Another

The viscosity of an emulsion is generally mush higher than the viscosities of either of theindividual phases, and may approach several thousand centipoise (compare to room-temperature water at 1 cp). Because of their high viscosities, emulsions will inhibit flow ifthey occur within pore spaces, as predicted by Darcy’s Law. An illustration of themagnitude of this effect is given in Figure 16, which shows the productivity reductionspossible for various emulsion viscosities as a function of depth of emulsion.

CM 12




Figure 16. Production Rate Decrease Resulting from High-Viscosity Emulsions and Increasing Radius of Blocked Formation

Emulsions can be generated by mixing of oil and aqueous fluids within the reservoir or inthe wellbore. For example, mixtures of acid and some produced crudes can create thickstable emulsions which result in high injection pressures during acid jobs. Also, the misuseof surfactants in acidizing and workover fluids has been suspected of stabilizing emulsionsin formation rock. Although surfactants are often added to prevent emulsions, and underincompletely understood downhole conditions their behavior is often unpredictable.

Emulsions can be induced to form by fluid shear and agitation. Although such forces maybe present in the formation during routine well production, current experience suggests thatformation damage from this mechanism is not a common occurrence. Instead,incompatibility of workover or acidizing fluids with crudes is a more established source ofemulsion problems.

12.4.11 Water Blocking

Water blocking refers to the condition in which a high water saturation impedes the flow ofhydrocarbons within pore spaces. Water blocking is a relative permeability effect, and canbe explained with the aid of Figure 17, which describes the effect of the presence of twoimmiscible fluids on each other’s permeability. On each vertical axis is the permeability ofeach phase in the absence of the other. For fluids which don’t interact with the formation,these permeabilities are the same for both phases. The relative permeability curve alsoshows how the presence of a second phase will reduce the permeabilty of the first.

CM 12




Increasing water saturation has the effect of progressively reducing oil permeability.

Figure 17. Example of Relative Permeability

Water blocks may occur as a result of coning or fingering of water from another zone, ortemporary loss of workover fluid. Acid jobs tend to leave small temporary water blocks,which explains why restoring production often involves a short cleanup period duringwhich spent acid is recovered.

Water blockage from coning or fingering illustrated in Figure 18 is more of a problem,since it will not clean up as a temporary block will. Increasing drawdown will generallyhave the effect of bringing in more water, thus aggravating the problem. In such cases, re-completion of the well may be necessary.

CM 12




Figure 18.

12.4.12 Wettability Changes

In an oil well, water usually is the wetting phase, meaning that it coats the grain surfacesand is more tightly held in the smaller pore spaces. This situation is desirable, since itallows the oil phase to flow through the larger, more permeable pores. Refer back to Figure17, which summarizes the basics of relative permeability effects. From this figure, it isobvious that the presence of two immiscible phases reduces the permeability of each one,and this was termed water blocking. It is also shown that the permeability to the phasewhich wets the rock, in this case water, is more severely affected by the presence of theother phase. In other words, when two fluids compete for flow in the same permeablemedium, the wetting phase will be constrained to the smaller, less permeable pore spaces.

Wettability changes may occur through the use of surfactants which are incompatible withthe formation. For example, some surfactants with net positive charges have been known toadsorb on sandstone surfaces which are negatively charged. The other part of the surfactantmolecule may then have enough hydrocarbon character to cause oil to be attracted to thesurface, causing oil wetting.

Oil wetting may also occur following acidizing if a clean silica surface is exposed to crudeoil with strong natural surfactants. These and other causes of wettability changes are morethoroughly discussed in the chapter on Solvents and Surfactants.

12.4.13 Acid Precipitates

A relatively recently recognized mechanism for damage involves the precipitates which canform during sandstone acidizing treatments. As discussed in the section on sandstoneacidizing, several precipitates including silica gel may appear during acid spending.Improper treatment may allow these to reduce job success or actually increase damage.

12.5 DAMAGE REMOVAL

12.5.1 Introduction

Damage removal is the general term given to treatments designed to remove the effectstreatments remove the damage while others overcome its effects without actually removingit. There are many techniques available for restoring productivity to a damaged well,depending upon the type of formation and the type of damage. Most treatments fall into thegeneral categories of matrix treatments, hydraulic fracturing treatments, and wellbore

CM 12




treatments.

12.5.2 Matrix Treatments

Matrix treatments are designed to more-or-loss uniformly permeate the fabric of the rock inorder to dissolve damaging particles or deposits. This requires that the injection pressurebe kept below fracturing pressure, and that treating fluids contact all parts of the intervalintended to be treated. This latter requirement can be accomplished by various divertingtechniques, the subject of a later chapter. The various types of matrix treatments are brieflyintroduced in the following paragraphs. A detailed discussion of each appears in theirrespective chapters.

12.5.3 Acidizing

Acidizing is perhaps one of the earliest applications of matrix treating. Most reservoirs fallunder the categories of sandstone or carbonate, and each calls for a different type of acidmatrix treatment. Sandstones are most effectively treated with combinations of hydraulic(HF) and hydrochloric acid (HCI). Hydrofluoric acid is the component which activelydissolves damaging clays. On the other hand, carbonate formations are most often acidizedwith HCI because this acid reacts very quickly with carbonate rock. The acid etches outchannels in the rock which are able to bypass the damage.

12.5.4 Solvents and Surfactants

Damage attributable to emulsions, water blocks, wettability changes, and organic depositsis usually treated with surfactants and organic solvents. Surfactants are surface-activemolecules which can break emulsions, reduce water blocks and restore wettability ifproperly chosen and applied. Organic solvents are used to dissolve asphalt and paraffindeposits. Some special organic solvents can also break emulsions.

12.5.5 Hydraulic Fracturing

Hydraulic fracturing is another category of well treating. Hydraulic fracturing involvesgenerating a fracture within hydrocarbon formations and rendering the crack conductive,either by propping it open with sand or by etching it with acid, if it is in a carbonate. Thesetreatments usually are done to effect reservoir stimulation by partially overcoming naturallylow permeability. However, fracturing is occasionally used to bypass formation damage asshown in Figure 19. Usually, fracturing to overcome damage will involve smaller job sizes.

CM 12




Figure 19. Bypassing Damage by Fracturing

12.5.6 Tubing Treatments

Low productivity which is caused by mineral or organic scale deposits in tubing is removedby treating the wellbore. In the case of soluble scale, acid circulated down to theobstruction is frequently sufficient to restore production. Organic deposits, such as asphaltand paraffin, can be removed with organic solvents or heated-oil treatments. Suchprocedures are generally referred to as tubing or casing washes.

12.6 DAMAGE PREVENTION

12.6.1 Drilling Fluid Selection

Although drilling fluids are generally selected for their drilling properties, a considerationof formation damage sensitivity should also guide mud selection. For example, formationsknown to be sensitive to low salinity brine can be drilled with a NaCI brine mud or KCI-polymer mud. Experience has shown that these muds can be less damaging to formationswith sensitive clays, leading to easier production testing and well completion.

Although approach to minimizing mud damage involves maintaining low fluid lossproperties in the mud, thereby confining the invaded zone close to the wellbore. Lowfiltration characteristics require careful monitoring of the mud system, with the addition of

CM 12




additive and deflocculants as necessary. Maintaining the clays in a deflocculated stateincreases their effectiveness at building thin, impermeable filter cakes. If this can beaccomplished, routine perforating may be sufficient to penetrate the shallow damage zone.

12.6.2 Workover Fluid Salinity

Formation damage from clay swelling and migration can be avoided during workovers byexploiting some established properties of clays. Clays will tend to resist changing fromtheir native geologic equilibrium state, providing that external disturbances are not toosevere. This applies to both swelling and dispersing, where it has been shown in core teststhat gradual reductions in salinity are less damaging than abruptly imposed decreases (seeFigure 20). General experience suggests that clays which formed in high salinity connatebrines (50,000 ppm +) can withstand decreases in salinity of 50% or more, and even greaterfinal reductions can be tolerated if taken stepwise. However, general experience alsosuggests that some clay disturbance will result in high salinity formations exposed to NaCIbrines lower than about 4000 ppm in salinity regardless of how slowly salinity is lowered.

Factors such as maximum tolerable salinity drop per step and damage threshold salinity arecertainly dependent upon the rock and the formation brine. Nevertheless, they provide uswith general guidelines for field application. For example, based on the above observationsit is recommended that workover fluid salinity not be sharply different from salinity. Thisguideline permits us some leeway, in the sense that 50% reductions are often tolerable,whereas a 95% reduction is usually too drastic. Fresher water formations, characterized by5000 ppm salinity or lower, generally are not even sensitive to fresh water.

CM 12




Figure 20. Effect of Gradual Salinity Reduction on Permeability

12.6.3 Brines To Stabilize Clays

Clays can be stabilized against low salinity swelling by exposure to calcium brine. Corematerial pretreated with calcium brines is typically insensitive to fresh water damage.Other ions such as NH4

+ and K+ may also be somewhat effective at preventing fresh waterdamage, but this has not been conclusively demonstrated.

Damage from dispersion of non-swelling clays by fresh water can also be prevented bytreating these clays with calcium brine. As in the case of swelling, there is evidence thatNH4

+ and K+ also help to inhibit dispersion.

Although there are a variety of theories and observations concerning clay sensitivity, itseems clear that most damage can be avoided by preventing drastic decreases in salinity. Itis also well established that calcium brines will desensitize clays against swelling anddispersal damage. These observations are the basis for establishing field guidelinesgoverning compatibility of workover fluids with formation clays.

12.6.4 Clay Stabilizers

Clay stabilizers are chemicals designed to eliminate the tendency of clays to swell anddisperse when exposed to low-salinity brine. These molecules function by adsorbingtightly onto the clays, thus preventing the expansion of the ionic layer upon introduction offresh water.

Experiments confirm that some clay stabilizers are effective at preventing low-salinitydamage. However, experiments also show that currently available clay stabilizers are noteffective at preventing fines migration caused by fluid flow. Figure 21 shows the effect ofa clay stabilizer on a laboratory core under two flow rate conditions for the case of freshwater exposure.

At the lower velocity, the clay stabilizer prevented clay damage and the core retained 100%of its permeability, even after exposure to fresh water. However, above a critical flowvelocity, the permeability declined in spite of the presence of stabilizers. Thus, clay

CM 12




stabilizers should only be used where formations will unavoidably be exposed to freshwater.

Figure 21. Pretreatment with a Clay Stabilizer Prevents Only Fresh Water Damage

12.6.5 Avoid Incompatible Brines

As discussed earlier, some combinations of calcium workover fluid and formation brine canlead to scale damage in the formation. Where possible, a water analysis should be obtainedto determine this tendency. Specifically, there are methods to predict whether the HCO3

content of a reservoir brine will scale if exposed to calcium workover fluid.12.6.6 Surfactant Selection

The use of surfactants which will not cause adverse wettability changes is also important.Specifically, sandstone formations, which normally are negatively charged, should not beexposed to positively charged cationic surfactants. Carbonate formations are positivelycharged and therefore should not be treated with negatively charged anionic surfactants.

12.6.7 Drawdown

The drawdown, or pressure differential from the formation into the wellbore, can beresponsible for causing mechanical fines migration, especially in poorly consolidatedformations. This type of fines and clay migration cannot be prevented through the uses ofclay stabilizers. It may be necessary to limit drawdown and fluid production if fines-migration damage and sand production is a severe problem.

CM 12




12.6.8 Fluid Loss Control

The ideal approach to workover fluid quality is to maintain well filtered fluids to preventdamage from fines introduction into the formation. However, under realistic fieldconditions, it is not often possible to achieve a high level of fluid cleanliness. This problemis compounded if permeable zones are being exposed to the fluid. An approach to thisproblem is to intentionally add acid-soluble fluid loss control particles to the fluid tominimize leakoff and damage. These particles can then easily be removed with acid. Thisprocedure will be discussed in more detail in the workover fluids section.

12.6.9 Injection Water Quality

Formation damage in injection wells is often characterized by recurring injectivity declinesrequiring periodic treatment. This is usually attributable to solid particle or oil injection,which ultimately leads to plugged perforations and/or creation of a near wellbore oilsaturation. Although it is not practically possible to remove all solids and oil from injectionwater, maximizing water quality within economic constraints will significantly reduce thefrequency of cleanout and damage removal operations. The cost of frequent treatmentsmust therefore be balanced against the cost of improved facilities.

Formation Damage

Documents

Transcript of Formation Damage