Reservoir Formation Damage Episode 3 Part 10 ppsx

When asked "Is it more cost effective toprevent formation damage or bypass it?" JPT, ©1994 SPE; reprinted bypermission of the Society of Petroleum Engineers, some experts repliedas follo

cases, such as open hole completions (Bennion, 1999) Because formationdamage is usually nonreversible, it is better to avoid formation damagerather than deal with it later on using expensive and complicated pro-cedures (Porter, 1989; Mungan, 1986) In many cases, remedial treatmentsmay also cause other types of damages, while the intent is to cure thepresent damage problems When asked "Is it more cost effective toprevent formation damage or bypass it?" (JPT, ©1994 SPE; reprinted bypermission of the Society of Petroleum Engineers), some experts replied

as following:

McLeod: "There is no universal answer for this question Often theformation quality determines whether it is more cost effective toprevent damage or to remove it or bypass it later by acidizing orhydraulic fracturing Generally, damage prevention is more costeffective than removing or bypassing damage later."

Peden: "Prevention of damage must be cost effective but it requires

a greater understanding of the physics of the processes, as well as

an improvement both in our predictive and operational techniques.Bypassing damage can never be an attractive alternative to damageminimization."

Penberthy: "If it is more cost effective to prevent damage, then that

is probably the best solution If an effective, inexpensive acid job or aminifrac treatment is less expensive than the cost of the completionfluid, the post-treatment approach probably should be selected."

Some of the other comments of the experts are quoted in the followingfrom JPT (1994):

Burnett: "If there is existing formation damage in a well, there are threechoices: live with it; fracture or perforate past it; or use some means

of removing it The choice depends upon economics and technology.The key to formation damage cleanup is understanding what hascaused the damage The damage may be caused by tenacious filtercakes, particle invasion into the rock, and/or fluid-filtrate chemicaldamage Many of us believe that particulate damage extends only

a few tenths of a foot into a zone On the other hand, chemicaldamage (clay reactions, formation fines movement, rock/fluid incom-patibility, and precipitation) can exist tens of feet into the pay zone.Near-well damage can be reduced (but not eliminated) with acids,oxidizers, and solvents If you have deep damage, then sidetracking

is nearly always the best option."

Peden: "The further we get away from the borehole, the less control

we have over our ability to clean up or remove impairment However, formation damage is largely characterized by a lack ofunderstanding of the potential of the processes and the mechanismsinvolved Greater understanding, training, and technology transfer

is required between the service and operating-company sectors."Penberthy: "One of the main causes for formation damage is usingtechniques, procedures, and fluid systems that are known to causeproblems and risking the chance that somehow the operator will beable to "get by with it."

Whether a particular fluid is nondamaging depends on the ticular site-specific application and formation in which the well iscompleted; i.e., there may be no such thing as a universal non-damaging completion fluid Suggestions are to use clear brines thatare compatible with the reservoir rock

par-I will specify the guidelines for selecting an ideal fluid While itmay be rare that all properties can be achieved, compromisingbetween fluid properties and characteristics should identify com-pletion fluids that will provide acceptable results

An ideal completion fluid should be compatible with the reservoirrock (nondamaging) and have low fluid loss, acceptable suspensionand transport properties, thin filter cake, and low friction loss Thedensity should be easily controlled The fluid should also be readilyavailable, inexpensive, easily mixed and handled, and nontoxic."Ali: "All brine systems are potentially formation damaging at hightemperatures In addition, unfavorable fluid/rock interaction atrelatively low temperature can produce mobile fines with the addedpotential for the precipitation of carbonate, sulfide, sulfate, andsodium-chlorite scales The need for thoroughly evaluating thecompatibility of completion fluids with formation brine, formationmineralogy, and produced fluids cannot be overly stressed."Burnett: "In fields we have studied, we've found that formationdamage from water-based fluids was no worse than correspondingoil-based or synthetic fluids The key is ensuring that the fluid,whatever it may be, is compatible with the formation fluids and therock matrix."

McLeod: "In high-permeability formations, polymers and otherfluid-loss control materials can cause severe damage if not mixedproperly Sometimes that damage may be removed by appropriate

acidizing If fluid-loss pills are not used, sometimes fluid losses are

so high that they pick up contaminants still attached to tubing andcasing surfaces after incomplete cleaning of mud, rust, and otherparticles Those particles are carried into the formation, where theyare filtered out and reduce permeability

Good filtration of compatible brines and shearing and filtering ofpolymers used for fluid-loss control are key to preventing or reduc-ing damage Even with good hydration techniques, microgels inpolymer solutions can plug formations unless the microgels arereduced or removed by shearing and filtration before their placement

in the well."

Peden: "To establish fluid-selection procedures, realize that tion damage is a result of either a solid/solid interaction betweenthe drilling-mud particulates and the formation or a fluid/fluid interaction resulting from the base fluid interacting with thereservoir fluid Or alternately, it is an interaction between the basefluid of the drilling mud and the rock constituents To select appro-priate fluids, devise testing programs that address those issues."Ali: "By conducting core displacement tests with various drillingfluids on representative reservoir samples, the least damag-ing drilling fluid can be selected In addition, fluid rheology,solids content and size distribution, overbalance pressure, formationpermeability, and other parameters can be considered for selectingwell-specific fluid systems."

forma-Burnett: "We recommend that our clients obtain certain basicinformation about the formation and about the fluids that con-tact the formation Information such as mineral content, porosity,permeability, and formation pore-size distribution can be used toscreen completion fluids."

Formation damage control and remediation is both a science and anart There are no universally proven technologies that are panesia forall problems Creative approaches, supported by science and laboratoryand field tests yield the best solution An examination of the reportedstudies reveals that numerous recipes and/or recommended procedureshave been developed However, their applicability and/or effectivenesshave been validated for certain specific rock and fluid systems and,therefore generalization of these approaches is questionable In thischapter, some of the more common treatment methods are reviewed.However, their applicability in specific fields should be investigated and

adapted by laboratory core testing Here, they are only provided forinstructional purposes, as our learning curve is still evolving, judging bythe new techniques that are being introduced in the literature.

Selection of Treatment Fluids

As expressed by Thomas et al (1998),*

The type and location of the damage must be determined to selectthe proper treating fluids Additionally, precautions should betaken to avoid further damage Damage can be from emulsions,wettability changes, a water block, scale, organic deposits (paraffinand asphaltenes), mix deposits (a mixture of scale and organicmaterial), silt and clay, and bacterial deposits In most cases, thetype or types of damage cannot be precisely identified with 100%accuracy However, the most probable type or types can be deter-mined; therefore, most matrix treatments incorporate treating fluids

to remove more than one type of damage

The selection of the treatment fluids depends on the specific tions and purposes The treatment fluid volumes are usually determined

applica-by means of laboratory core tests and mathematical models Treatmentfluids should contain various additives for various purposes Thomas et

al (1998) explain the issue of additives as following:

Although proper fluid selection is critical to the success of a matrixtreatment, the treatment may be a failure if the proper additives arenot used The major treating fluid is designed to remove the damageeffectively Additives are used to prevent excessive corrosion, sludg-ing and emulsions, provide uniform fluid distribution, improvecleanup, and prevent precipitation of reaction products Additionally,additives are used in preflushes and overflushes to stabilize clays,disperse paraffins and asphaltenes and inhibit scale and organicdeposition Additive selection is primarily dependent upon thetreating fluid, the type of well, bottom-hole conditions, the type oftubulars, and the placement technique Diverters are essential

to obtain uniform fluid distribution in a horizontal well

The volume of each additive used is dependent on the specificproblem addressed For example, surfactants are commonly used at 0.2

to 0.5% to lower surface and interfacial tension and provide waterwetting As a rule, the minimum amount of additive should be used.Normally, the recommended concentration is determined in the labora-tory and is based on testing (i.e., nonemulsifiers, anti-sludge agents)

* Reproduced by permission of the Society of Petroleum Engineers, ©1998 SPE

Clay Stabilization

When clays are exposed to low salinity solutions, two mechanismscause formation damage (Himes et al., 1991) Swelling clays imbibe waterinto their crystalline structure and enlarge in size and plug the pore space.Mobilization, migration, and deposition of clays can plug the pore throats.Himes et al (1991) describe the desirable features of effective claystabilizers, especially for applications in tight formation as following:

1 The product should have a low, uniform molecular weight toprevent bridging and plugging of pore channels

2 The chemical should be nonwetting on sandstone surfaces toreduce water saturation

3 It should have a strong affinity for silica (clay) surfaces tocompete favorably with the gel polymers for adsorption siteswhen placed from gelled solutions and to resist wash-off byflowing hydrocarbons and brines

4 The molecule must have a suitable cationic charge to neutralizethe surface anionic charges of the clay effectively

Inorganic Cations (1C)

Clay stabilization can be maintained by the aqueous solution salinityabove that of the connate water (Himes et al., 1991) Figure 23-1 byHimes et al (1991) shows the clay stabilizing effectiveness of variousbrines The basal spacing versus the salt concentrations are shown as anindication of clay swelling, measured by x-ray diffraction (XRD) The

clay will disperse when the basal spacing is greater than 21A (Himes et

al., 1991) In this respect, Figure 23-1 indicates that the clays are stable

even at very low concentrations of K+ and NHj cations; whereas, a sufficiently high concentration of Na+ cation is necessary to maintain clay stability Therefore, K+ and NHj are natural clay stabilizers, but are not permanent because they can be exchanged with Na + (Himes et al., 1991).Figure 23-1 shows that calcium ion can maintain clay stability, but it isnot preferred as a clay stabilizing agent because it may react withformation brines and chemical additives (Himes et al., 1991) Cesiumcation (Cs+) is also very effective at low concentrations, but it is veryrare and expensive (Khilar and Fogler, 1985; Himes et al., 1991) Damageresulting from clay swelling and mobilization, migration, and redepositioncan be prevented by adding certain ions to stabilize the clays in workoverand injection fluids (Keelan and Koepf, 1977) Five percent solutions of

CaCl 2 and KCl, and hydroxy-aluminum (OH-Af) may be effective (Keelan

and Koepf, 1977)

Figure 23-1 Basal spacing of smectite clay vs concentration of various

brines (after Himes et al., ©1991 SPE; reprinted by permission of the Society

of Petroleum Engineers)

Cationic Inorganic Polymers (CIP)

In order to provide somewhat permanent clay stabilization, cationicinorganic polymers (CIP) such as hydroxyl aluminum and zirconiumoxychloride, have been introduced (Reed, 1974; Valey and Coulter, 1968;Coppell et al., 1973; Himes et al., 1991) These agents provide resistance

to cation exchange, but they are applicable for clay stabilization in carbonate containing sandstones and the formation should be retreatedafter acidizing (Himes et al., 1991)

non-Cationic Organic Polymers (COP)

Quaternary cationic organic polymers (COP) are used for effective andpermanent stabilization of clays (especially smectite clays), and control-ling fines and sand in sandstone as well as carbonate formations (Himes

et al., 1991) They are applicable in acidizing and fracturing treatments

They provide permanent protection because of the availability of multiplecationic sites of attachment However, their applicability in tight forma-tions is limited to low concentrations (Himes et al., 1991) They can causepermeability damage by pore plugging because these high molecularweight and long-chain polymers have molecular sizes comparable withthe some pore size fractions in porous rock They can also increase theirreducible water content of porous rock because they are hydrophobicand water-wetting Their effectiveness is substantially lower in gelled-water solutions used for hydraulic fracturing and gravel-packing asindicated by Table 23-1 by Himes et al (1991) because of gel competitionfor adsorption on clay surfaces.

Oligomers

Oligomers are low-molecular-weight, cationic, organic molecules

having an average of 0.017 \lm length (Penny et al., 1983; Himes et al.,

1991) Oligomers offer many potential advantages over the cationicorganic polymers for clay stabilization (Himes et al., 1991) Availability

of many repeating sites and high affinity for clay surfaces enables bettercompetition of oligomers with gels in water used for hydraulic fracturingand gravel-packing Because of their smaller size compared to pore size,the treatment-imposed permeability damage is significantly reduced.Because they are only slightly water-wetting (contact angle is 72°), theirreducible water content is also reduced Zaitoun and Berton (1996)examined the effectiveness of cationic polyacrylamides (CPAM) andnonionic polyacrylamides (PAM) for stabilization of montmorilloniteclay by means of the critical salinity concentration method (CSC) Asschematically depicted in Figure 23-2 by Zaitoun and Berton (1996), thepolymers prevent fines migration by coating over the pore surface and

Table 23-1 Basal Spacing of Smectite Clay Exposed to Various Brines

Spacing—Dry Solution (A)

Figure 23-2 Polymer coating of pore surface for clay migration prevention

(after Zaitoun and Berton, ©1996 SPE; reprinted by permission of the Society

of Petroleum Engineers)

blocking the clay particles They determined that low-molecular-weightpolymers have comparable stabilizing capability to high-molecular-weightpolymers and are more advantageous because they cause less treatment-induced permeability damage

Kalfayan and Watkins (1990) used organosilane compounds as additives

to acid systems to prevent the weakening of the rock by acid dissolution.This additive undergoes a hydrolysis reaction to form silanols, which tie

to the silanol sites present on siliceous mineral surfaces and forms apolysiloxane coating to bind clay and siliceous fines in place

/>#-Buffer Solutions

Buffering is an effective means of pH control by maintaining the

hydrogen ion activity constant in spite of the changing conditions Buffer

capacity expresses the sensitivity of pH of an aqueous solution to adding

a strong base (Gustafsson et al., 1995) Hayatdavoudi (1998) hypothesizesthat alteration of kaolinite to dickite, nacrite, and halloysite, throughchemical oxidation according to the following reactions, may be respons-

ible for fines generation, at high pH in the presence of alkali hydroxides.

2Na + O-> NaO 2 2

Na 2 O 2 + 2H 2 O -> 2NaOH + H 2 O 2

Therefore, Hayatdavoudi (1998) recommends buffering the pH of brines

to 8 or below and avoid aeration of injected fluids to prevent kaolinitecomminution-induced formation damage Hayatdavoudi (1998) also recom-mends adding ammonium chloride and/or ammonium sulfate buffers to

prevent silicate dissolution at high pH environments.

Clay and Silt Fines

The fluid selection studies conducted by Thomas et al (1998) haveindicated that:

1 The sandstone formation damage can be treated by fluids that candissolve the materials causing the damage

2 The carbonate (limestone) formations are very reactive with acidand, therefore, the damage can be alleviated by dissolving orcreating wormholes to bypass the damaged zone If there is a silt

or clay damage, HCl should be used to bypass the damage The damage by calcium fluoride precipitation cannot be treated by HCl

or HF acid treatment.

Formation damaged by silt and clay fines introduced by drilling,completion or production operations require different acid treat-ment recipes that vary by the formation type, location of damage andtemperature (Thomas et al., 1998) Recipes recommended for acidizing

of carbonate (limestone) formations are outlined in Figure 23-3 byThomas et al (1998)

Motta and Santos (1999) proposed that certain blends of fluosilicic acid

(H 2 SiF 6 ) with hydrochloric acid (HCl) or an organic acid, such as acedic

acid (//Ac) can dissolve clays and feldspars without reacting with thequartz These systems remove deep clay damage in sandstone formations,without the usual adverse effects of the secondary precipitation reaction

encountered in conventional acidizing by HF or H 2 SiF 6 alone Motta andSantos (1999) have determined that properly designed acid blends cansubstantially reduce the skin in the field Gdanski and Shuchart (1996)have shown that the equilibrium condition between fluosilicic acid and

Treating Fluid Selection for Damaged Carbonates

Damage in Fissures and/or Matrix

10% Acetic Acid with mud/silt dispersants

Figure 23-3 Fluid selection for carbonate acidizing (after Thomas et al.,

©1998 SPE; reprinted by permission of the Society of Petroleum Engineers).

hydrochloric acid controls the extent of the primary and secondaryreactions of hydrofluoric acid with the aluminum silicates

Fluobaric acid (//BF4) is a retarded acid, which reacts with the aluminalayers of clays to form a borosilicate film The borosilicate film preventsthe migration of in-situ clay and silt fines at high shear-rates of flowbecause the borosilicate film stabilizes the fine particles in petroleum-bearing formations (Thomas and Crowe, 1978; Colmenares et al., 1997).The fluoboric acid can be effective for applications extending 3 to 5 feetfrom the wellbore (Ezeukwu et al., 1998)

Bacterial Damage

Bacteria growth in injection wells can cause many problems includingplugging of the near-wellbore formation Johnson et al (1999) recommendthe use of 10-wt% anthrahydroquinone disodium salt in caustic to con-trol the growth of sulfate-reducing bacteria (SRB) combined with thetraditional biocide treatment for control of other types of bacteria Forexample, bacteria-induced formation damage in injection wells can be

treated using a highly alkaline hypochlorite solution, followed by a HCl

overflush for neutralization of the system (Thomas et al., 1998)

Inorganic Scales

Scales can be removed by various methods Carbonate scales can

be dissolved by HCl, organic acids, and dihydrogen ethylenediamine tetraacetic acid Iron scales can be dissolved using HCl and an iron stabilizer When FeS is present, iron reducing and chelating (or sequester-

ing) agents should be added to the treatment fluid to avoid any cipitation (Thomas et al., 1998) Chelating agents chemically bind thehydrated metal ions and change the reactivity of these ions and, therefore,

pre-prevent precipitation of iron (III) hydroxide at pH > 2.5 (Brezinski, 1999).

The reaction of ferric ion with hydrogen sulfide causes sulfur

pre-cipitation Reaction of ferrous iron with H2 S above pH =1.9 causes FeS

precipitation Scale inhibitors may also interfere with the crystallizationphenomena by blocking the sites available for crystal growth and preventthe adhesion of scales to metal surfaces (Meyers et al., 1985) Brezinski(1999) has demonstrated that some of the frequently used chelating agents,such as ethylenediaminetetra acedic acid (EDTA) and nitrilotriacedic acid(NTA), may not be effective in downhole temperature conditions becausethey may decompose at temperatures at or above 250°F Therefore,

Brezinski (1999) recommends removing H2 S using a hydrogen sulfide scavenger as the only method of preventing FeS production.

Scale inhibitor squeeze method is resorted to prevent the precipitation

of inorganic salts, including barium/strontium/calcium sulfates, calcium/barium/magnesium carbonates, and calcium fluoride The effectiveness ofthe scale inhibitors is severely reduced at high temperature and pressureenvironments prevailing at most wellbore conditions because of thermaldecomposition In fact, the thermal stability studies with several inhibitors,such as penta and hexa-phosphonates, phosphino polycarboxylate (PPC),polyvinyl sulfonate (PVS), and sulfonated polyacrylate copolymer (SPC),conducted by Graham et al (1997), indicate that they are stable up to

175°C Hydroxide scales can be dissolved by HCl and organic acids, sulfate scales can be dissolved gradually by EDTA, chloride scales can

be dissolved by aqueous solutions of weak HCl or brine, and silica scales

can be dissolved using mud acids (Thomas et al., 1998)

Organic Deposits

Organic deposits, such as paraffins and asphaltenes, can be dissolvedwith aromatic solvents, mutual solvents, blends of aromatic and mutualsolvents or their dispersion in water (Thomas et al., 1998)

Asphaltine flocculatization and deposition can be prevented by addingresins and aromatics (Leontaritis et al., 1992) Samuelson (1992) has

demonstrated that combined non-aromatic solvents yield the best solventperformance Barker et al (1999) tested solvent treatment for removal

of the paraffin deposits and applied crystal modifier squeezing to preventparaffin crystallization

Mixed Organic/Inorganic Deposits

Mixed organic/inorganic deposits can be dissolved using acid dispersed

in an organic solvent (Thomas et al., 1998)

Formation Damage Induced by Completion-Fluids and Crude-Oil Emulsions

Foxenberg et al (1998) tested some blends of solvents and surfactants anddemonstrated that certain blends are effective in providing compatibilitybetween completion-fluids and crude-oils for gravel-packing applications.Polymer-specific damage associated with drilling, completion, stimula-tion, and workover operations can be treated by breaking long-chainmolecules to short-chain molecules by means of suitable enzymaticdegradation reactions

Filter-cake forming agents can be typically used to prevent the invasion

of fines and filtrates of drilling muds and hydraulic fracturing fluids into thereservoir formation by forming an impermeable filter cake over the sand face.Zhang et al (1998) propose the use of alpha- and beta-methyl glucosides

(MEG) These are chemical derivatives of glucose produced from corn

starch and, therefore, are environmentally acceptable These low interfacialtension pore-bridging substances can form low-permeability filter cakes overthe sand face of low- and high-permeability formations

Wettability Alteration and Emulsion and Water Blocks

Wettability change, converting the formation toward oil-wet condition,can be reversed using mutual solvent, blends of mutual solvent andsurfactant, and surfactants (Thomas et al., 1998)

Water external emulsions can be decomposed by aqueous solutions ofmutual solvents, blends of solvents and surfactants, and alcohol andmutual solvent mixtures (Thomas et al., 1998) Oil external emulsionscan be decomposed by means of the blends of aromatic and mutualsolvents, such as toluene and xylene (Thomas et al., 1998)

Water blocks can be removed using mutual solvents, blends of aromaticand mutual solvents, blends of alcohol and mutual solvents, and non-aqueous acedic acid containing 10% glacial acedic acid in diesel (Thomas

et al., 1998)