Mechanisms of Formation Damage

Solids Plugging

Fig 1 Illite

Clay Swelling Formation damage that occurs when water-based filtrates from drilling completion workover

or stimulation fluids enter the formation altering the ionic environment of clays via ion exchanges changes in

pH andor changes in salinity thus leading to a reduction in porosity and permeability Figures 1A-1E show

SEM photographs of several different clays

Figure 2 Smectite

Fig 3 Kaolinite

Fig 4 Chlorite

Fig 5 Smectite-Illite

Smectite for example possesses negative charges on the faces of the clay crystal while the edges are positively

charged The density of negative charges on the clay structure is determined in terms of the cation exchange

capacity (CEC) which is the amount of positively charged ions (cations) that the clay structure can

accommodate on its negatively charged exterior Thus CEC values are a measure of the clays propensity to

swell under aqueous conditions Table 1 CEC ranges of several clays

Clay Type CEC Range (Meq100g)

Smectite 80 - 150

Kaolinite 3 - 15

Illite 10 - 40

Chlorite 10 - 40

Table 1 Cation Exchange Capacity Ranges of Several Clays1

A common laboratory method for measuring CEC is through multiple salinity tests a technique used for the

determination of the electrical properties of shale containing core samples In this test the sample is flushed

with brines of different salinities and the conductivity determined after each flush A plot of the conductivity of

the sample versus the conductivity of the brine gives the excess conductivity caused by clays and other surface

Fig 3 Kaolinite

Fig 4 Chlorite

Fig 5 Smectite-Illite

Smectite for example possesses negative charges on the faces of the clay crystal while the edges are positively

charged The density of negative charges on the clay structure is determined in terms of the cation exchange

capacity (CEC) which is the amount of positively charged ions (cations) that the clay structure can

accommodate on its negatively charged exterior Thus CEC values are a measure of the clays propensity to

swell under aqueous conditions Table 1 CEC ranges of several clays

Clay Type CEC Range (Meq100g)

Smectite 80 - 150

Kaolinite 3 - 15

Illite 10 - 40

Chlorite 10 - 40

Table 1 Cation Exchange Capacity Ranges of Several Clays1

A common laboratory method for measuring CEC is through multiple salinity tests a technique used for the

determination of the electrical properties of shale containing core samples In this test the sample is flushed

with brines of different salinities and the conductivity determined after each flush A plot of the conductivity of

the sample versus the conductivity of the brine gives the excess conductivity caused by clays and other surface

Fig 5 Smectite-Illite

Smectite for example possesses negative charges on the faces of the clay crystal while the edges are positively

charged The density of negative charges on the clay structure is determined in terms of the cation exchange

capacity (CEC) which is the amount of positively charged ions (cations) that the clay structure can

accommodate on its negatively charged exterior Thus CEC values are a measure of the clays propensity to

swell under aqueous conditions Table 1 CEC ranges of several clays

Clay Type CEC Range (Meq100g)

Smectite 80 - 150

Kaolinite 3 - 15

Illite 10 - 40

Chlorite 10 - 40

Table 1 Cation Exchange Capacity Ranges of Several Clays1

A common laboratory method for measuring CEC is through multiple salinity tests a technique used for the

determination of the electrical properties of shale containing core samples In this test the sample is flushed

with brines of different salinities and the conductivity determined after each flush A plot of the conductivity of

the sample versus the conductivity of the brine gives the excess conductivity caused by clays and other surface

conductors Then using a suitable model (eg Waxman-Smits dual water SGS) it is possible to determine the

intrinsic formation factor and porosity exponent and the cation-exchange capacity2 Another source of clay

disturbance is usually associated with changes to the wetting phase (often native formation water) In the case of

smectite and mixed-layer clays (primarily smectite-illite) a change in size due to swelling or water retention

enhances their probability of getting dislodged and migrate with the mobile wetting phase This phenomenon is

referred to as swelling-induced clay migration3

Fines Migration Formation damage which arises when the drawdown forces during flowback or production

exceed the cohesive forces between fines and the rock fabric This in turn causes particles suspended in the

produced fluid to bridge the pore throats near the wellbore reducing well productivity Fines can include

different materials such as clays (phyllosilicates smaller than 4 microns) and silts (silicates or aluminosilicates

with sizes ranging from 4 to 64 microns)4 Fines migration can be exacerbated by the use of incompatible fluid

treatments Commercial products have been developed to minimize the potential for fines migration (eg resin

consolidation tackifiers and covalent bonding of polymers)

Ultra-thin tackifying agents (UTTA) like Halliburtons SandTrapreg have been developed to stabilize fines in

high-rate producing or injection wells These systems can be applied during initial fracturing or gravel-packing

operations as a remedial treatment or as a follow up to fracturing or acidizing treatments Schlumbergers K300

is an example of technology based on the polymerization of resin All of the developed products address the

issue of fines migration and have similar solutions They all involve the application of some form of coating to

adhere fines to the mineral surfaces Advantages of resin consolidation are that it is suitable for through-tubing

applications applicable in small diameter casing and that it can be applied in abnormal pressure well5

Problems arise because resin consolidation involves multistage processes in which several fluids must be

uniformly applied sequentially into a perforated interval and frequently are highly toxic and relatively

expensive Moreover resin consolidation can significantly reduce the permeability to oil by changing the

wettability of the rock and by occluding the pore space with resin

Sand Production Formation damage that results from the production of sand and its subsequent movement

into pore throats and frasl or proppant-packs causing plugging and productivity impairment Key factors

influencing sand production are

Degree of formation consolidation which depends on cementation of sand grains around the perforation

tunnel the geological age and depositional environment

Reduction in pore pressure throughout the life of the well which results in an increasing amount of stress

on the formation sand causing it to break loose from the matrix and get crushed thus creating movable

fines that are produced along with the wellbore fluids

Production rate of reservoir fluids which creates a pressure gradient and frictional drag forces that

exceed the formation strength Thus there is a critical flow rate below which these forces will not

exceed the formation strength

Reservoir fluid viscosity which plays a vital role in the case of heavy oil reservoirs with low-gravity

high-viscosity oils even at low production rates

Increase in water-cut influences sand production twofold On one hand it decreases the relative

permeability of oil over the time after production thus increasing the pressure differential and induced

stresses required to produce the well at the same rate yielding sand production On the other hand it

increases the likelihood of water-wet particles to move along with the aqueous (wetting) phase

Sand production is detrimental to productivity over the life of the well Some of the issues seen with sand

production are

Plugging of perforations reducing production efficiency

Erosion in surface and downhole equipment when the velocity of sand is high increasing the need for

workover treatments

Collapse of formation may take place due to void formation around perforation tunnel over the time as

sand is being produced decreasing permeability and increasing pressure drop

Sand control can be achieved through various means including reducing drag forces (ie lower production

rates) mechanically bridging sand (eg gravel packs) and resin consolidation An example of resin

consolidation is the silanol resin consolidation system This sand control technology is a resin system consisting

of aromatic polyester amide and tri-alkoxy organosilane The tri-alkoxy organosilane acts as a coupling agent

between the reservoir sand grains and aromatic polyesteramide which acts as the load bearing resin due to the

pore pressure gradient and overburden stresses It is applicable at high pressures and temperatures from about

50degF to 450degF When in contact with formation water the chemicals react to hydrolyze it at the specific sites to

form silanol glue which bonds the sand grains together forming a strong bond Additional information can be

found in SPE paper 120472

Perforating Charge Debris Formation damage caused by perforating is one of the highest risks in well

completions As shown in Figure 26 (Published by Schlumberger Used courtesy of Schlumberger

Permission obtained Sept 9 2009) common types of damage that can occur inside the perforation tunnel are

fractured and compacted zones perforation gun debris and the reaction of perforating charge liner materials

(eg zinc) with high density brines upon detonation seen in Figure 3

When sprayed into clear completion brines at a high detonation temperature high surface area particles become

activated and then react with the aqueous phase to form metal oxides metal hydroxides and hydrogen gas For

instance when calcium chloride completion brines are used along with perforating charge cases containing zinc

alloy materials a number of chemical reactions may take place resulting in the formation of cementing

materials that can significantly block pore throats (SPE paper 58758) Equations 1A-1D demonstrates the

sequence of chemical reactions leading to the formation of cement type materials Moreover the chemical

nature of the reaction products suggests that typical scale inhibitors might function to reduce interparticle

associations and minimize the cementing or agglomeration process7

Zndeg + H2O rarr H2(g) + ZnO(ppt)

Equation 1A Zinc Oxide Precipitate Formation Reaction

Zndeg + 2H2O rarr H2(g) + Zn(OH)2(ppt)

Equation 1B Zinc Hydroxide Precipitate Formation Reaction

Zndeg + CaCl2 + 2H2O rarr ZnCl2 + Ca (OH) 2(ppt) + H2 (g)

Equation 1C Zinc Chloride amp Calcium Hydroxide Precipitate Reaction

xZn (OH)2 + yZnCl2 + zH2O rarr 2Zn(x+y)(OH)xCly(H20)z(ppt)

Equation 1D Complex Zinc Hydroxy Chloride Precipitate Formation Reaction

High-temperature frasl high pressure (HTHP) wells are particularly susceptible to this source of damage A post

perforating acid treatment can be performed in order to revert some of the damage however as formation

temperatures increase metal corrosion and acid sensitivity of the formation become problematic At higher

temperatures organic acids are frequently used but many of them do not have the acid strength or the capability

to dissolve zinc or zinc salts The long-chained organic acid HTO has been shown to dissolve zinc and

perforating gun debris The solubilities of zinc metal and gun debris at 250deg F (121deg C) are shown in table 2 It

is estimated that typical weights of debris can range from 02 lbft (14 kgm) in low debris carriers to 14 lbfraslft

(13 kgfraslm) in steel carriers at a 12 shotfraslft density At the higher temperatures above 250deg F (121deg C) a savings

of up to 20 on acid volume can be realized based on the increased dissolving power of a long chained organic

acid (eg HTO) Table 2 shows the solubilities of zinc and gun debris in different acids at different

temperatures

10 Formic Acid 10 Acetic Acid 10 HTO Acid

Zn metal 21deg C 010 lbfraslgal 002 lbfraslgal 009 lbfraslgal

Zn metal 121deg C 028 lbfraslgal 024 lbfraslgal 034 lbfraslgal

Gun Debris 21deg C 023 lbfraslgal 027 lbfraslgal 017 lbfraslgal

Gun Debris 121deg C 028 lbfraslgal 027 lbfraslgal 028 lbfraslgal

Table 2 Zinc amp Gun Debris Solubilities in Various Acids8

Particle Precipitation Formation damage caused by the formation of an insoluble material in a fluid Particle

precipitates can be classified as organic inorganic or organometallic

Inorganic

Calcite Calcium carbonate (CaCO3) scale the most common inorganic scale precipitates as pressure is

reduced and CO2 is given off from the formation water and calcium scale is deposited The production of scale

produces a further drop in reservoir pressure causing more scale to be formed The deposition takes place

through the following reaction (Equation 2)

Ca2+

+ 2HCO3 rarr CaCO3 (s) + CO2 (g) + H2O

Equation 2 Calcium Carbonate Scale Formation Reaction

Induced scaling also occurs by mixing of formation brine with extraneous incompatible fluids invading the

reservoir during drilling cementing completion and workover operations For the example above any increase

of the dissolved calcium (Ca2+

) cation concentration caused by these operations is compensated by calcium

carbonate (CaCO3) precipitation9 Effective calcium carbonate scale removal can often be achieved through

acid treatments as CaCO3 is highly soluble in acid However spent acid can contain high concentrations of

scale producing ions often leading to short lived stimulation treatments as the calcium carbonate re-precipitates

around the near wellbore region Also effective are chelating agents but they can be expensive Chelating

agents work by preventing the chelated Ca2+

cations from re-precipitating after treatment In order to prevent

calcium carbonate scaling inhibitors squeezes have been used These treatments work by either adsorbing onto

the formation material providing a prolonged treatment through desorption into production fluids or through a

precipitation mechanism The precipitation mechanism functions by precipitating a calcium salt into the pores

which dissolve over time during production providing inhibition This method might increase treatment life

but also presents the possibility of inducing damage into the producing formation10

Barite Scale Barium sulfate (BaSO4) scale formation occurs when the concentration of barium sulfate exceeds

the saturation point causing the excess BaSO4 to precipitate The saturation point of an aqueous solution

dependent upon temperature pressure and solvent composition Solubility of barium sulfate increases with

temperature pressure and salt content of the brine Factors that commonly induce BaSO4 are lower

temperatures brine dilution pressure drops and mixing of incompatible waters The deposition takes place

through the following reaction (Equation3)

Ba2+

(aq) + SO42-

(aq) rarr BaSO4

Equation 3 Barium Sulfate Formation Reaction

Barium sulfate scale is especially difficult to remove through acid treatments due to the high cost of treatments

However EDTA and nitrilotriacetic acid (NTA) are two chemicals that can be used for removal Mechanical

removal and coiled tubing operation are the only effective methods of BaSO4 scale removal Laboratory test

should be performed to determine the inhibitor concentration needed to prevent barium sulfate scale formation

and to evaluate the effectiveness of the inhibitor as changes in temperature pH and salinity Inhibitors

commonly used are phosphonates phosphate esters polyphosphonates and polymeric species Additional

treatments can include squeeze treatments continuous injection (upstream of known risk points capillary

string injection) precipitation squeezes (where scale inhibitor precipitates and dissolves slowly over time into

the brine) solid inhibitors (placed in the rat hole associated with proppant) scale inhibitors included in

hydraulic fluids or gas lift deployed inhibitors11

Anhydrite Scale Calcium sulfate (CaSO4) scale deposition is largely dependent upon pressure changes The

deposition takes place through the following reaction (Equation 4)

Ca2+

(aq) + SO42-

(aq) rarr CaSO4(s)

Equation 4 Calcium Sulfate Scale Formation Reaction

Temperature is also a factor with higher temperatures lowering the anhydrite solubility and increasing scaling

tendency In seawater injections scale such as anhydrite will become more significant as seawater breakthrough

occurs There are 3 available methods for chemical removal of anhydrite scales1213

Inorganic converters which modifies the scale into an acid soluble byproduct This method will also

remove other acid soluble materials present

Organic converters which converts the scale into a dispersionsludge that is able to flow This method

can include an acid treatment or not The acid treatment will effectively remove the reaction products

because they are soluble in acid

Chelants which work by complexing the Ca2+

ions This method effectively reduces the ions capacity to

re-precipitate Inhibition of anhydrite scale could involve polyphosphonates or polyorganic acid salt

compounds

Halite Scale Salt scale that can be formed during production of high salinity (gt200000 ppm) formation brine

as seen in Figure 8 Halite formation may also occur during the evaporation of water into the gas phase

Halite scale is normally easily removed with periodic fresh or low salinity water flushes Removal can also be

achieved with continuous dilution of the fluid stream with water upstream of where deposition occurs14

Depending on the rate of the salt deposition and the availability of fresh water such flushes could become an

expensive removal method An example of a salt inhibitor used is potassium hexacyanoferrate (HCF) HCF is a

well-known species which has been applied as an anti-caking agent in cooking and as a drilling-fluid additive

for drilling through salt layers where it both limits hole wash-out (because it also reduces the rate of salt

dissolution) and prevents salt from crystallizing from the returned fluid as it cools and becomes supersaturated

in salt15

Iron Sulfide Scale that can occur whenever sources of both iron and hydrogen sulfide are present H2S can

result from the presence of sulfate reducing bacteria thermal sulfate decomposition or introduction to a well

through gas lift operations Iron sulfides are able to enhance the corrosion process decrease productivity and

negatively affect oil-water separation activities Iron sulfide exists in numerous crystalline forms with numerous

acid solubilities The FeS species responds well to HCl treatment but the longer the contact time between FeS

and H2S the more likely that the scale will become richer in sulfur While FeS may be effectively removed with

acid FeS2 is not Since iron sulfide is normally oil-wet scale removal is impeded To correct this adding

surfactants and water-wetting agents is important Acid treatments should also have a corrosion inhibitor an

iron control agent and a hydrogen sulfide scavenger Toxic H2S is produced by the following reaction

(Equation 5) between FeS and HCl

FeS(s) + 2HCl (aq) rarr FeCl2 (aq) + H2S (g)

Equation 5 Hydrogen Sulfide Gas Formation Reaction

FeS will also precipitate as H2S continues to react with any ferrous iron present at pH gt 19 If ferric ion is

present elemental sulfur can precipitate which is insoluble in HCl and needs expensive organic solvents to

remove16

Understanding the source of iron and sulfide is key to preventing iron sulfide scaling Iron can be

present in the formation water or supplied by tubing corrosion If the iron is supplied by tubing corrosion

protecting the metallurgy could reduce the potential for iron sulfide scale If the iron is present in the formation

water the course of action should be to limit the amount of H2S through biocides injection water sulfate ion

minimization or injection of nitrates One chemical treatment option is tetrakis hydroxymethyl phosphonium

(THPS) used to dissolve or chelate iron sulfide once it is formed17

Organometallic

Naphthenates Formation damage caused by fluctuations in the reservoir water pH resulting in the formation

of organic scales carbonate deposits and the stabilization of emulsions Reservoir water is naturally saturated

with CO2 in equilibrium with bicarbonate anion (HCO3-) as shown in the following reaction (Equation 6)

CO2 + 2H2O rarr HCO3- + H3O

+

Equation 6 Reservoir Water Equilibrium

Fluids injected into the well for various procedures can alter the temperature pressure and composition of the

fluids in the near wellbore region Precipitation can occur during production by a chemical reaction of two or

more ions in solution or by changing the temperaturefraslpressure of a saturated solution which causes a drop in

solubility Scale can also precipitate due to the mixing of two incompatible fluids and with the release of CO2

brought on by a pressure reduction

These pressure drops are accompanied by an increase in pH and oftentimes the formation of mixed carbonate

and naphthenate deposits inside tubing or surface installations as well as the creation of stable emulsions due to

the surface-active naphthenate group RCOO- Naphthenic acids R-COOH are often present in crude oils and the

hydrophilic nature of the carboxylic acid group means that they congregate at the oil-water surface18

Examples of their structures

can be seen in Figure 11 Oil and formation water composition is very important in the formation of naphthenates These variables

are naphthenic acid concentration and composition formation water cations bicarbonates and pH Crude oils that present the biggest

complications are ones with high total acid number TAN and high concentrations of naphthenic acid

Naphthenate problems can be exacerbated by the presence of solids such as formation sand and fines waxes and other types of scale

The stability of emulsions containing naphthenic acids has been shown to be a function of pH asphaltenefraslresin ratios naphthenic acid

types and cation content of the aqueous phase Sodium rich emulsions lead to less separated water volume over time showing the

stability of the oil-water emulsion Calcium rich solutions lead to less stable emulsions possibly due to excess ionic strength in

solution Sarac and Civan19

determined through experimentation that the critical minimum initial brine pH required for the onset of

naphthenate precipitation to be 591 As pressure drops occur during production degassing of CO2 takes place raising the pH of the

formation brine and promoting the dissociation of naphthenic acids as shown in Equation 7

R-COOH + OH- rarr R-COO

- + H2O

Equation 7 Naphthenic Acid Dissociation

The naphthenate ion is very reactive and tends to complex with Na+ and Ca

2+ cations to form sodium and

calcium naphthenate scales as shown in Equation 8 and Equation 9 Naphthenate deposits normally collect in oil

frasl water separators but can deposit in tubing and pipelines as well

2R-COO- + Ca

2+ rarr (R-COO)2Ca

Equation 8 Calcium Naphthenate Formation

R-COO- + Na

+ rarr R-COONa

Equation 9 Sodium Naphthenate Formation

Due to its high molecular weight calcium naphthenate is less soluble than sodium naphthenate in water This is

important because when calcium carbonate and calcium naphthenate form together the carbonate will decrease

the formation of naphthenate This is due to the reduction in available calcium cations for reactions with the

naphthenate anions When evaluating the stability of emulsion and the amount of naphthenate deposits during

processing of acidic crude it is important to take into account the following criteria

1 Water pH value at process conditions as well as the level of bicarbonate and calcium content at reservoir

conditions

2 Total Acid Number (TAN) of crude oil20

TAN is the amount of any acid contained in an oil sample

While the test is unable to determine specific types of acids it is useful in determining if a sample of oil

will be corrosive or not The threshold for corrosive oils is 05 mg KOHfraslg oil Acidizing with HCl and frasl

or acetic acid is often used to remove naphthenate deposits An example of naphthenate deposits can be

seen in Figure 12 Additional information on naphthenate formation prevention and mitigation can be

found in SPE papers 93407 80395 112434 and 68307

Organic

Asphaltenes amp Parrafins Formation damage resulting from organic deposit which hamper the production of

crude oil Paraffins are alkanes of relatively high MW (C18 to C70) which can be either straight-chained or

branched They have specific solubilities and melting points Because these hydrocarbons have satisfied valence

electron configurations they are almost completely inert to chemical reactions and as a result immune to

attack by bases and acids

Paraffin waxes are soluble in most liquid petroleum fractions and their solubility normally decreases as MW

increases Hence they are soluble in both straight-chain and aromatic petroleum derivatives They are deposited

as solids when the temperature drops below the cloud point for the particular crude oil SARA analysis can be

performed to determine the different constituents present in oil SARA is a method for characterization of oils

based on fractionation whereby a heavy oil sample is separated into smaller quantities or fractions with each

fraction having a different composition

Fractionation is based on the solubility of hydrocarbon components in various solvents used in the test Each

fraction consists of a solubility class containing a range of different molecular-weight species In this method

the oil is fractionated to four solubility classes referred to collectively as SARA Saturates-Aromatics- Resins-

Asphaltenes

Saturates are generally paraffins while aromatics resins and asphaltenes form a continuum of molecules with

increasing molecular weight aromaticity and heteroatom contents Products like Halliburtons Parachekreg 160

a polymeric paraffin inhibitor alter the paraffin structure decreasing its tendency to precipitate21

Common

solvents used for paraffin removal include condensate kerosene and diesel (straight-chain hydrocarbons)

Asphaltenes on the other hand are black polycyclic aromatic complex compounds seen in Figure 5

Published by Experimental Soft Condensed Matter Group ( Harvard) Permission to use obtained Aug 3

2009 Generally they are spherical 30Aring to 65Aring in diameter with MW of 10000 to 100000

These molecules are held in suspension by surrounding asphaltic resins (maltenes) Asphaltenes polar

properties result from the presence of oxygen sulfur nitrogen and various metals in their structures Figure 7

shows the blockage that can occur resulting in severe damage Published by London Center for

Nanotechnology Permission to use obtained Sept 9 2009 Deposition occurs not only by temperature frasl

pressure reductions but also by destabilizing factors which act on the resins such as contact with acid CO2 or

aliphatic solvents that act on the micellar colloidal suspension to strip away the maltene and resin from the

micelles Removal is possible but selecting the appropriate method is crucial and can be accomplished by field

tests

While condensate kerosene and diesel are commonly used to dissolve paraffin they should not be used when

attempting to remove asphaltenes These non-aromatic hydrocarbons if used can cause further precipitation of

the asphaltenes as the maltene stabilizers are disturbed Instead aromatic chemicals such as xylene can be used

Their power can be enhanced by almost ten times with the addition of approximately 5 by volume of a

specific primary or secondary amine such as Halliburtons highly polar organic Targonreg II22

Closely

monitored due to low flash points moderate heating will hasten the removal process New solvents that are

non-toxic biodegradable and work similarly are available such as Dowell Schlumbergers PARAN ECOreg

Another asphaltene solvent is Tretolites Paridreg PD-72 which is a mixture of toluene and a surfactant While

continuous or batch pumping methods are employed the batch method is recommended with the solvent left in

contact with the asphaltenes for up to 24 hours Common methods for organics scale removal are mechanical

solvents heat and dispersants

Hydrates Hydrates are solid white crystalline substances with cellular structures formed as a result of water

vapors and gaseous hydrocarbons interaction in the presence of water and under high pressure and low

temperature conditions (T gt 32deg F) as shown in Figure 9 There are three common types of gas hydrate

inhibitors thermodynamic kinetic and crystal size modifiers Thermodynamic inhibitors (eg inorganic and

organic salts glycerol or low molecular weight glycol combination of salt and glycol) work upon injection by

preventing the formation of hydrogen bonds or destroying them Kinetic inhibitors (eg polymers and

surfactants) work as a slow reaction to delay nucleation or slow the crystal growth rate Crystal size modifiers

also known as crystal habit modifiers do not prevent hydrate formation Instead they act as anti-agglomerates

to ensure that hydrates form a pumpable slush so that fluid flow is maintained

Bacterial Growth

Formation damage that is caused by the introduction of bacteria while aqueous phase fluids are utilized and

improper bacteriological control is maintained Bacterially induced formation damage is a particularly insidious

type of formation damage in that the apparent harmful effects of the introduction of the bacterial agents are

usually not noticed until well construction materials fail catastrophically Bacteria which cause formation

damage can be classified into two types aerobic and anaerobic Aerobic bacteria require a constant source of

oxygen to survive and are mainly problematic with long term water injection operations Anaerobic bacteria do

not require oxygen and tend to be more widespread and problematic Both types present issues with plugging

corrosion and toxicity23

Corrosion is caused by anaerobic bacteria sulfate reducers which digest sulfate in

water to produce corrosive hydrogen sulfide The resulting iron sulfide corrosion product particularly in

combination with small amounts of oil can significantly plug water treatment and injection facilities Slug

treatments with bactericide are usually effective in controlling the anaerobic sulfate reducers24

Other

alternatives (still in early development stages) rely on the use of phage cocktails to target specific bacteria

within the reservoir andor in pipe lines25

Polymer Plugging

Formation damage caused by the addition of polymers typically used to provide clay stability and frasl or control

fluid losses during drill-in and completion operations Chemical fluid loss control (FLC) materials can be

grouped into two categories solids laden and solids free Sized salts calcium carbonate and organosoluble

resins are three types of solids typically used as FLC materials Solids free FLC pills on the other hand may

consist of linear gels (eg Liqui-Visreg and Bromi-Visreg) crosslinked gels as seen in Figure 13 (eg K-

Maxtrade Max Sealtrade TekPlugtrade and Protectozonetrade) and the more recently developed viscoelastic surfactant

gels (eg ClearFractrade)

Solids Laden FLC The most widely used solids laden FLC materials consist of sized CaCO3 particles

suspended in a polymer matrix Computer software is used to determine the optimum CaCO3 loading

and particle size distribution to form a seal against the formation rock and minimize fluid losses The pill

can be either bullheaded or spotted with a coil tubing unit The pill is usually removed with an acid

treatment (eg HCl or HClfraslacetic) Other clean-up alternatives include breaker systems (internal or

external) based on polymer-specific enzymes and frasl or chelating agents An alternative to the calcium

carbonatefraslpolymer system particularly for injector wells is the saltfraslpolymer system which consists of

ground sodium chloride in saturated NaCl brine frasl polymer matrix Since sodium chloride is readily

soluble in water produced water or unsaturated brine treatments will afford removal of residual salt

solids Depending on the polymer uploading in the FLC pill an acid treatment may also be required

Santrols Collagen or synthetic polymer balls are also readily dissolved in the presence of unsaturated

brines and thus constitute another alternative for water-soluble FLC materials particularly for injector

wells26

Oil soluble resins such as benzoic flakes may be used as FLC materials in low to moderate

temperature producer wells Resins are typically added to completion brines and delivered to the

formation where they plate out onto rock surfaces After the completion operation is finished produced

oil or condensate flowing over the resin gradually dissolves it As with the introduction of any foreign

fluid into the formation there are advantages and disadvantages to be evaluated before using a FLC

material Table 3 highlights the strengths limitations and costs of the three general types of bridging

solids used for FLC

Particulate Strengths Limitations Cost

CaCO3 frasl

Polymer

Inexpensive

Relatively easy to mix

Good for bridging on gravel and

frac packs

Used when lower densities are

required

Can plug perforation tunnels

Highly damaging if particles are not sized

properly

Polymer damage may require remedial

treatments

May cause tools to stick

Degradation depends upon contact with

acid for removal

Relatively

low

NaCl frasl

Polymer

Relatively easy to mix

Good for bridging on gravel and

frac packs

Water soluble particles

Can plug perforation tunnels

Highly damaging if particles are not sized

properly

Polymer damage may require remedial

treatments

May cause tools to stick

Low

Oil Soluble

Resin

Easy to mix

Good for bridging on gravel and

frac packs

Water soluble particles

May not stop losses completely

Not useful above melting point

Only recommended in oil wells

Relatively

low

Table 3 Bridging Particulate Systems Strengths Limitations amp Costs

Solids Free FLC Linear gels can be prepared from a range of polymer systems most typically natural

polymers or natural polymers that have been modified to achieve the necessary purity and solution properties

The chemical structure of common polymers used as FLC materials and viscosifiers are shown in figures 14A-

14F Cellulose Figure 14A is a natural structural component of wood and in cotton it exists in nearly pure

form However cellulose is insoluble in water and brines To make this polymer soluble it is usually

derivatized to hydroxyethyl cellulose (HEC) Figure 14B which is relatively easy to disperse and hydrate in

most brine solutions Xanthan polymer Figure 14C is a more complex system with excellent solids

transport and suspending characteristics particularly at low shear rates Note that xanthan has pendant carboxyl

groups which can bind to contaminant ions to produce difficult-to-break gels Additionally xanthan polymer

systems are incompatible with many biocides and clay stabilizers Linear polymer gels are useful in operations

involving low overbalance low temperature low permeability and short interval length More recently

viscoelastic surfactants (VES) have been developed as an alternative to polymer-based FLC materials VES

impart viscosity to the fluid by forming a 3D network of rod-like micellar structures show in Figure 14E

The advantage of viscoelastic surfactants is that they need no added breakers to reduce viscosity after use

Viscosity is degraded when contact is made with oil whereby the micelles are disrupted and the viscosifying

network is destroyed Another benefit of the particles is the formation of a pseudo filter cake of viscous VES

fluid that greatly decreases fluid loss rates and improves overall efficiency of the fluid Table 4 lists the

strengths limitations and cost of some available linear gel systems and VES New technology has led to the

introduction of nanometer-scale particles which interact with VES micelles through chemisorptions and

surface charge attraction to form a worm-like micellular structure as seen in Figure 14F (Published by

Schlumberger - Used courtesy of Schlumberger Permission obtained September 9 2009) Such interactions

stabilize fluid viscosity at high temperatures As internal breakers are activated to break the micelles the fluid

drastically loses its viscosity and the pseudo filter cake dissolves into nanometer-sized particles Since these

particles are so small they are easily carried back to the surface thus minimizing formation damage potential

SPE paper 107728 provides more information on the new VES system

Polymer Strengths Limitations Cost

Hydroxyethyl Cellulose

(HEC)

Relatively easy to mix

Readily available

Non-toxic non-corrosive

Acid soluble

Internally or externally

broken

Highly damaging if not pumped

correctly

Does not stop losses completely

Requires multiple treatments

Requires shearing and filtering

Relatively

inexpensive

Xanthan (XC) Relatively easy to mix

Readily available

Non-toxic non-corrosive

Good low-shear viscosity

Highly damaging if not pumped

correctly

Does not stop losses completely

Requires multiple treatments

Requires filtering

Not readily removed with acid

Relatively

inexpensive

Succinoglycan Easy to mix

Non-toxic non-corrosive

Good low-shear viscosity

Does not stop losses completely

Requires multiple treatments

Requires filtering

Temperature limitations

Moderately

expensive

Viscoelastic Surfactant

(VES)

Easy to mix

No solids

Good low-shear viscosity

Requires hydrocarbon contact to

break

Temperature limitations

Relatively

expensive

Table 4 Linear Gel Systems (Polymers) Strengths Limitations amp Cost

Figure 15 shows a comparison of rheological properties of HEC and xanthan (XC) polymer As seen in this

figure XC polymer displays a higher low shear rate viscosity (LSRV) compared to HEC which translates in

better solids carrying capacity at low flow rates and under static (no flow) conditions On the other hand HEC

is easier to remove via the use of internal breakers and frasl or remedial acid treatments To achieve higher

viscosities crosslinked polymer systems are typically employed Crosslinked gels are typically compromised of

derivatized HEC and are useful at temperatures up to 300deg F They are available as pre-blended products or can

be prepared on the rig Crosslinking agents for HEC include zirconium and lanthanide salts Crosslinked gel

particulates in the form of premanufactured slurries are oftentimes useful when more complete fluid loss

control is needed Max Sealtrade slurries for example can effectively plug off formations under relatively high

overbalanced pressures It is comprised of crosslinked HEC gel which has been chopped up to form

inhomogeneous lumpy flowing slurry Table 5 lists some crosslinked gel systems along with their strengths

limitations and relative cost

Crosslinked Strengths Limitations Cost

Crosslinkable HEC Stops losses completely

Easily removed with breakers

Can withstand high overbalanced

pressures

Can run tools through it

Internal breakers used for le

48 hrs

(fluid begins to degrade with

time)

Must be mixed on location

Moderately expensive

Pre-Prepared

Crosslinked

Gel Particles

Stops losses completely

No on-site mixing required

Can withstand high overbalanced

pressures

Can run tools through it

No internal breakers can be

added

(must be broken externally)

Bulky to ship and store

Moderately expensive

to high

Zinc Bromide

Crosslinked Gel Stops losses completely

Only pumpable system available

for ZnBr2

Must be mixed on site

Must be broken externally

High

Table 5 Cross linked Gel Systems (Polymers) Strengths Limitations amp Cost

Another potential source of formation damage from polymer plugging is that related to clay stabilization via the

use of polymers The polymers include cationic inorganic polymers (CIP) and cationic organic polymers (COP)

CIP such as hydroxyl aluminum and zirconium oxychloride provide marginally permanent clay stabilization

They offer resistance to cation exchange but their application is limited to noncarbonate-containing sandstones

Cationic organic polymers are effective in providing permanent stabilization to clays especially smectite and

for controlling fines and sand in sandstone and carbonates formations Permanent protection is provided by the

availability of multiple cationic sites of attachment but their application is limited to low concentrations COP

are applicable in acidizing and fracturing but their effectiveness is lowered in gelled-water solutions used for

hydraulic fracturing and gravel-packing due to gel competition for adsorption on clay surfaces27

They are often

the cause of formation damage via polymer plugging because of their high molecular weight and long chains

that have molecular sizes similar to pore throats in porous rock Figure 16 shows a scanning electron

micrograph detailing solids and polymer plugging of pore throats

Altered Wettability

Formation damage in which the formation wettability is modified generating a change in relative permeability

to oil gas and frasl or water that eventually affects well productivity In particular surfactants and other additives in

drilling fluids especially oil-base mud can change a naturally water-wet formation to an oil-wet formation with

consequent production impairment caused by reduction of relative permeability to oil andor gas Brine salinity

and pH are another important factor related to wettability because they strongly affect the surface charge density

on the formation rock and fluid interfaces which in turn can affect surfactants adsorption Figure 17 shows

an SEM of water droplets on both kaolinite and quartz illustrating the contrasting wetting characteristics of

different mineral surfaces Published by University of the West of Scotland No further reproduction please

use for this project webpage only Permission to use obtained Aug 5 2009 Relative permeability modifiers

such as Halliburtons WaterWebreg and BJ Services AquaContrade are hydrophilic polymers designed to reduce

the effective permeability to water while increasing (or maintaining) the relative permeability to gas and frasl or

oil They do not typically require special placement techniques

Water Block

Formation damage that occurs when large quantities of water andor brine are lost to the formation thus

increasing water saturation and decreasing the relative permeability to oil andor gas Partially pressure-depleted

reservoirs are particularly sensitive to this type of damage Water blocking can be prevented frasl minimized by

adding surface tension reducing agents (eg surfactants alcohols or microemulsions) to wellbore fluids to not

only lower surface and interfacial tension but also to water-wet the formation and prevent emulsions28

Emulsions

Formation damage that is a mixture of two or more immiscible liquids in which the liquids are stabilized by

one or more emulsifying agents If an emulsion block exists well permeability as determined through injectivity

test will be much greater than permeability determined through production tests Oilfield emulsion types consist

of water in oil (regular emulsions) oil in water (reverse emulsions) and complex emulsions Most emulsions

break easily when the source of the mixing energy is removed However some natural and artificial stabilizing

agents such as surfactants and small particle solids keep fluids emulsified Natural surfactants created by

bacteria or during the oil generation process can be found in many waters and crude oils while artificial

surfactants are part of many drilling completion or stimulation fluids Among the most common solids that

stabilize emulsions are iron sulfide paraffin sand silt clay asphalt scale and corrosion products29

More

information regarding emulsions can be found in SPE papers 105858 100430 and 97886

References

1Allen Thomas O and Roberts Alan P Production Operations 2 OGCI Tulsa Oklahoma 2000

2Allen Thomas O and Roberts Alan P Production Operations 2 OGCI Tulsa Oklahoma 2000

3Allen Thomas O and Roberts Alan P Production Operations 2 OGCI Tulsa Oklahoma 2000

4Schlumberger Oilfield Glossary

5Allen Thomas O and Roberts Alan P Production Operations 2 OGCI Tulsa Oklahoma 2000

6Schlumberger Perforation Damage

7Javora PH Ali SA and Miller R Controlled Debris Perforating Systems Prevention of an Unexpected Source of Formation Damage SPE 58758

2000

8 McElfresh PM Gabrysch AD Van Sickle E Myers Jr B and Huang T A Novel Method of Preventing Perforation Damage in High-Temperature

Offshore Wells SPE 86521 2004

9Civan Faruk Reservoir Formation Damage 2nd Ed Elsevier Inc Oxford UK 2007

10Thane CG SMAD-Mafumeira Drilling Completions and Production Formation Damage Review and Recommendations Block 0 Angola TM 2008-27

2008

11Jordan MM Collins IR Gyani A and GM Graham Coreflood Studies Examine New Technologies That Minimized Intervention Throughout Well Life

Cycle SPE 74666 2006

12Jewell RJ and BR Lasater New Products to Solve Scale Problems SPE 3550 1971

13OJ Vetter Oilfield Scale ndash Can We Handle It SPE 5879 1976

14Frigo DM Jackson LA Doran SM and RA Trompert Chemical Inhibition of Halite Scaling in Topsides Equipment SPE 60191 2001

15Earl SL Use of Chemical Salt Precipitation Inhibitors to Maintain Supersaturated Salt Muds for Drilling Salt Formations SPE 10097 1981

16Nasr-El-Din HA and AA Al-Taq Water Quality Requirement and Restoring the Injectivity of Waste Water Disposal Wells SPE 68315 1998

17Nasr-El-Din HA Roser HR and Al-Jawfi M Formation Damage Resulting from BiocidefraslCorrosion Squeeze Treatments SPE 58803 2000

18Dyer SJ Graham GM and Arnott C Naphthenate Scale Formation ndash Examination of Molecular Controls in Idealised Systems SPE 80395 2003

19Sarac S and Civan F Mechanisms Parameters and Modeling of Naphthenate Soap-Induced Formation Damage SPE 112434 2008

20Rousseau G Zhou H and Hurtevent C Calcium Carbonate and Naphthenate Mixed Scale in Deep-Offshore Fields SPE 68307 2001

21Parachekreg 160 Paraffin Inhibitor Chemical Compliance 08 Jan 2008 Halliburton 29 May 2009

22Targonreg II Asphaltene Solvent Chemical Compliance 08 Jan 2008 Halliburton 29 May 2009

23Bennio DB et al Mechanisms of Formation Damage and Permeability Impairment Associated with the Drilling Completion and Production of Low API

Gravity Oil Reservoirs SPE 30320 1995

24Allen Thomas O and Roberts Alan P Production Operations 2 OGCI Tulsa Oklahoma 2000

25Phage Biocontrol Inc

26Santrol Oil amp Gas Stimulation Products

27Civan Faruk Reservoir Formation Damage 2nd Ed Elsevier Inc Oxford UK 2007

28Allen Thomas O and Roberts Alan P Production Operations 2 OGCI Tulsa Oklahoma 2000

29Schlumberger Oilfield Glossary

Last Update 21 September 2009