Brief Formation Damage

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Formation Damage Mechanism & Treatment Strategy

The productivity / injectivity of the reservoir may decrease due to many different reasons. Out

of those causes, the formation damage is the most important one. There are many

mechanisms, which occur separately or simultaneously to generate formation damage. The

understanding of those probable mechanisms are very important in order to take steps toprevent the occurrence or to remove the damage.

The different formation damage mechanisms and their treatment strategy are as follows:

a) Fines Migration: Movement of detached particles along with produced fluid in the porous

reservoir may reduce the effective permeability of the reservoir. The particles can bridge

across the pore throats in the near- wellbore region causing formation damage and

reduce the well productivity. When the damaging particles come from the reservoir rock,

they are usually referred to as fines. Migrating fines can be a variety of different

materials, including clays (typical size less than 4 µm) and silts (silicates or alumino

silicates with sizes ranging from 4 to 64 µm). Kaolinite clays are considered to be

some of the more common migratory clays. Damage from fines is located in the near-

wellbore area, within a 3- to 5-ft radius. Damage can also occur in a gravel pack.

The low strength formation or loosely cemented grain can be controlled with help of bridging

effect and presence of high conductivity path which will reduce the drag velocity on the

grains. In these conditions the gravel pack or the fracturing with TSO (tip screen out)

properties may be helpful. In the sandstones, blocking due to migrated fines can be treated

with acidizing with the deep penetrating acid which can dissolve the fines. The conventional

mud acid (HF + HCl) and hydrofluoric acid etc. are generally used as the treatment fluid. In

limestone or carbonate reservoirs the HCl is mostly used to remove the fines and clear the

near wellbore damage zone. Because the fines are not dissolved, but are dispersed in

natural fractures or the wormholes that are created, N2 is usually recommended to aid fines

removal when the well has a low bottomhole pressure.

b) Swelling clay : The salinity of the fluid in contact with the clay plays a major role. Some

clays are swelling in nature with change in the salinity of the fluid. Clays may change volume

as the salinity of the fluid flowing through the formation changes. The most common swelling

clays are smectite and smectite mixtures. Smectite swells by taking water into its structure.

It can increase its volume up to 600%, significantly reducing permeability. Clays or other

solids from drilling, completion or workover fluids can invade the formation when these

particles are smaller than the pore throat openings. Any subsequent increase in flow rate

through the invaded zone will force a high concentration of particles into the rock matrix,

which may prove damaging to the reservoir if there is any sudden change in the fluid salinity

later on.



The presence of the Smectite and Montmorillonite clay in the formation rock, necessitates

the precaution against the clay swelling. The salinity of the external or internal water which

may come in contact with the clay surface is very important as lower salinity value than

required may cause the swelling of these clay particles. Therefore the salinity of the

external injected water or liquid should be kept high enough to prevent the swelling.

The removal of smectite is usually accomplished with HF or fluoboric acid, depending on thedepth of penetration. The fluoboric acid is suitable for deeper penetration. In the event of

very deep clay-swelling problems (more than 2 ft), the best treatment is usually a fracture

to bypass the damage, as the matrix treatments will not be able to remove the damage to

that deep penetration.

c) Induced Particle Plugging: In addition to naturally occurring migrating particles such as

clays and fines, many foreign particles are introduced into the formation during normal

well operations. Drilling, completion, workover, stimulation, and secondary or tertiaryproduction operations can cause the injection of extraneous particles into the formation.

These foreign or external particles may plug the pore spaces, which creates obstruction to

the fluid flow and thereby decreases the productivity or injectivity. Particle damage from

injected fluids happens in the near-wellbore area, plugging formation pore throats. Problems

include bridging of the pores, packing of perforations and the loss of large amounts of high

solids fluid into natural fractures or propped fracture systems.

“Prevention is better than Cure”

The generation of the induced particle plugging should be avoided as much as possible by

using treated and clear fluid, which is to injected in the formation. The brine filtration

systems may be useful to get the cleaner fluid without any external impurities which can

plug the pore spaces. The other objective should be to prevent or improve the job procedure

or activity which may induce particle plugging. Removal of the mud cakes especially in the

open hole horizontal wells are very important. As, it may not allow the whole horizontal

section to contribute to production.

Generally in the vertical wells the mud cakes may be removed by pressure drawdown. But in

horizontal wells the necessary drawdown is very difficult to achieve on any section other than

heel. In these conditions the treatment of the whole section with help of Coiled Tubing may

be beneficial. In case the formation is damaged by the induced particle, then the

studies should be carried out to find out the nature of the particle which has plugged the

formation pores and accordingly proper treating fluid should be injected which can dissolve

those particles. Hydraulic fracturing may also be helpful to bypass the near wellbore damagearea.

d) Asphaltene and Sludge deposition : Organic skin damage in oil producing wells is a

major factor in the loss of productivity. Asphaltene deposition in the formation creates a



barrier for the transportation of the crude oil to the tubing. Organic damage may occur

naturally or through various intervention practices used in the wells. Asphaltenes are

heterocyclic unsaturated macromolecules consisting primarily of carbon, hydrogen, and

minor components such as sulfur, oxygen, nitrogen and various heavy metals. These higher

molecular weight components of crude oil are in equilibrium at “normal” reservoir condition.

As crude oil is produced this equilibrium is upset by a number of factors such as,

temperature decline, pressure reduction, addition of miscible gases and liquids, acidizing,

hot oiling and other oilfield operations. Flocculation of asphaltene in paraffinic crude oils is

known to be irreversible. This is the major cause of irreparable arterial blockage damage to

the flow of petroleum fluids. Due to their large size and their adsorption affinity to solid

surfaces flocculated asphaltenes can cause irreversible deposition. The two primary

mechanisms for asphaltene flocculation and deposition are depressurizing the oil and mixing

of solvents with reservoir oil during enhanced oil recovery (EOR). Acid treatments are

frequently accompanied by the appearance of organic sludge that, if not controlled, plug

perforations and reduce production. It is commonly accepted that this organic sludge results

from the incompatibility of “asphaltenes” with acid.

Removal treatments for asphaltenes use aromatic solvents such as Xylene and toluene or

solvents containing high percentages of aromatics. Solvent soak time, heat and agitation are

important considerations for treatment. The compatibility of the acid with the crude oil should

be checked in order to minimize the chances of occurrence of sludge formation. Proper anti-

sludge material is required to be added to prevent its occurrence.

e) mulsion: A crude oil emulsion is a dispersion of water droplets in oil. Produced oil-field

emulsions can be classified into three broad groups:

• Water-in-oil (W/O)

• Oil-in-water (O/W)

• Multiple or complex emulsions

The water-in-oil emulsions consist of water droplets in a continuous oil phase and the

oil-in-water emulsions consist of oil droplets in a water-continuous phase. In the oil

industry water-in-oil emulsions are more common (most produced oilfield emulsions are of

this kind) and therefore the oil-in water emulsions are sometimes referred to as "reverse"

emulsions. Multiple emulsions are more complex and consist of tiny droplets suspended in

bigger droplets which are suspended in a continuous phase. For example, a water- in-oil-in-

water (W/O/W) emulsion consists of water droplets suspended in larger oil droplets which in

turn are suspended in a continuous water phase.



In-situ emulsification has been experienced in some of wells and is causing formation

damage in the porous media. Emulsification Is believed to be initiated by the presence

of natural emulsifying agents which are present In the oil. Naturally occurring emulsifiers in

the crude oil include the higher boiling fractions, like asphaltenes and resins, organic acids

and bases. These agents are slightly soluble In the oil phase and are attracted to the

water phase causing reductions in interface tension between the water and the oil. This

results in a film forming about the dispersed water particle causing the particle to remain

isolated and inhibits coalescence into larger particles which would more readily separateand destabilize the emulsion. Viscosity of emulsions can be substantially higher than the

viscosity of either the oil or the water. This high viscosity causes the blocking of the pore

spaces by creation of immobile fluid and decreases the formation permeability. In the high

water cut wells and cyclic steam injection wells the chances of emulsion formation in much

more.

Demulsification is the breaking of a crude oil emulsion into oil and water phases. The

in-situ demulsification can be obtained by injection of chemical demulsifier in the

formation or by increasing temperature with presence of low shear.

Figure: SEMmicrographsof the porousrock takennear to the core inlet (a)imageon the grain scale , (b) zoomedimage

!) Scale: Scale is a solid mineral deposit usually formed from produced salt water. Because

water constantly dissolves and deposits solids, scale is an endless problem in the petroleum

industry. Scale occurs in primary production wells, secondary wells, injection wells, disposal

wells, and pipelines that connect wells to tank batteries. Wherever water production occurs,a potential for scale formation exists. Mixing of incompatible waters causes the minerals in

solution to form an insoluble precipitate. Some scale, such as calcium carbonate, develops

quickly but is relatively easy to treat. Barium sulfate is typically slower to form, but it is more



difficult to treat. The effect these scales have on a well depends largely on their location and

the amount deposited in the system. Scales can restrict and completely choke production in

the tubing, in the flowlines, at the sandface, or in the perforations. Scales can deposit in

fractures and formations that are distant from the wellbore.

Chemical scale inhibitors control the deposition of scale by either interacting with the

microscopic scale surface and altering the crystal structure as it is forming or by sequesteringthe ions (calcium and barium) that precipitate as scale. Numerous chemical additives are

effective at preventing scale precipitation such as Polyphosphates and phosphate esters,

Slowly soluble polyphosphates, Phosphonates, Polyacrylic acid and other carboxylic acid-

containing polymers, etc. Different solvents are used for dissolving the various kinds of scales

depending on their generating source. Most used solvents are HCl and EDTA (ethylene

diamene tetra acetic acid). These scale inhibitors and dissolvers are used by different means

such as Placement during a stimulation treatment, Squeeze treatments/Chemical Placement

Technique (CPT) or Continuous injection.

g) "acteria: The effects of indigenous and introduced microbes and their role in oilfield

formation damage is less well understood compared to the other mechanisms. Bacteria can

grow in many different environments and conditions: temperatures ranging from 12°F to



greater than 250°F [ –11° to >120°C], pH values ranging from 1 to 11, salinities to 30% and

pressures to 25,000 psi. Bacteria are classified as follows:

• Aerobic bacteria are bacteria that require oxygen.

•Anaerobic bacteria do not need oxygen (in fact, their growth is inhibited by oxygen).

•Facultative bacteria can grow either with or without oxygen because their metabolism

changes to suit the environment. They usually grow about 5 times faster in the presence of

oxygen.

The combination of the various microbial populations often result in the precipitation of

insoluble metal sulphides, biopolymer and/or hydrogen sulphide production, with loss in

production or injection rates. The bacteria most troublesome in the oilfield are sulfate-

reducing bacteria, slime formers, iron-oxidizing bacteria and bacteria that attack polymers

in fracturing fluids and secondary recovery fluids.

Figure: Different kinds of bacteria on the rock samples

Formation damage due to bacteria is more dominant in the wells with waterflood. Bacterial

growth may take place either on the injection well sandface or in the formation itself, and the

pore plugging mechanism maybe caused either by the larger cell population or by the by-

products of bacterial metabolism. Temperature is one of the major controls on the growth of

bacteria and their by-products. The greatest risk of microbial formation damage within the

reservoir would occur in those areas at 30 0C. The type of mineral present has a significant

effect on plugging characteristics of the rock formation due to bacteria. Bacteria have affinity

with a negative charge toward any particular mineral and their subsequent accumulation

around that mineral in the pore space. Bacteria uses negative charge for attachment to

nutrient source, i.e., magnesium, calcium, and iron thereby reducing the permeability in



nearby areas of these minerals.

Bactericides are also used commonly to control these bacteria. Iron- oxidizing bacteria are

aerobic and convert iron from the ferrous (Fe2+) to the ferric (Fe3+) state. To alleviate some

of the damaging effects of bacterial colonies, the main objective is to either control the

nutrients or eliminate the oxygen. EDTA is mostly used to control the metal nutrients by

chelating them that will be released by ionization into the porous media. Elimination of oxygen

from the injected fluid entering the porous media is very important. Aeration sources like leaky

pumps must be eliminated completely by introducing oxygen excavenger, repair of air leaks,

and avoiding unnecessary agitation of fluid. All nutrients, such as sugar rings, starches,

cellulose, etc., as a source of nutrient for bacterial growth should be eliminated. Some amount

of bactericide in proper doses with due care and consideration should be used to the toxicity

of such agents. Aldehyde-based compounds could prove useful in this regard.

h) #ater "loc$: Poor gas flow performance following well operations such as drilling,

completions and workovers was recently observed in some wells in a gas field. Loss of

aqueous fluids during these operations causes a ring of high water saturation around the

wellbore. This can potentially reduce gas flow into the well, and this phenomenon is called

"Waterblocking." Water blocking is a problem where the in situ water saturation is

significantly less than "irreducible" water saturation. Water blocking is a transient

phenomenon. The duration depends on reservoir properties, amount and type of fluid lost,

gas flow rate, and the pressure drawdown in the reservoir.

Figure: Water Blocks :



Increasing the water saturation from 20% to 35% decreases the relative oil permeability from

90% to 30%, respectively

Lower permeability reservoirs will have more significant water-block problems. This is due to

the smaller volumes of gas flow, leading to longer times for the water-block to clean up. Poor

gas production from tight rock following a water- base fracture treatment is often attributed to

water block. In water-wet rock, capillary \ forces resist brine displacement from the matrix

into the fracture. Water block occurs if the drawdown pressure gradient in the formation near

the fracture face does not exceed the rock capillary pressure sufficiently for gas to flow.

These \damage conditions usually occur when: (1) the pore throats are very small, (2) the

injected water in the pores of the rock was untreated (to reduce surface tension), and (3)

the bottom hole pressure is low.

Clean up of water block occurs as gas flows past this high liquid saturated region and

removes liquid by displacement and mass transfer. Any loss in gas well deliverability

recovers in two phases. The first phase corresponds to fluid displacement ("flowback

period") and lasts for a few days at most. The second phase is slower and can last several

months. Removal of water from gas wells has often been handled with acid and alcohol

solutions or acid and mutual solvent solutions. These systems attempt to reduce the

surface tension of the injected water which is trapped in the pores of the rock. In some

cases, treatment of the well to reestablish gas saturation and provide energy can be

accomplished by injecting either gaseous nitrogen or liquid carbon dioxide. Removal of a

water block can be accomplished using a surfactant or alcohol applied as a preflush to

reduce surface tension, followed by a post flush of N2 or CO2 to remove the water from the

near-wellbore area and reestablish gas saturation. Once the water has been mixed with the

surface-tension-lowering materials, removal is easier.

i) #ettability Alteration: Wettability is preferential sticking of the liquid on the solid surface. If

a drop of a liquid is placed on the surface of another Immiscible liquid or on the surface of

a solid that it cannot dissolve, it may spread out into a thin film or it may remain in the form

of a drop or a thick lens (Hausler,1978). If the drop of liquid spreads, it wets the surface; if

the drop of liquid does not spread, it does not wet the surface. The surface free energy of the

two phases and the interfacial tension between them determine whether the liquid spreads

or remains in a deformed drop. Formation plugging can be caused by liquid (or gas)

changing the relative permeability of the formation rock. Relative permeability can reduce

the effective permeability of a formation to a particular fluid by as much as 80% to 90%. The

wettability and related relative permeability of a formation are determined by the

flowing- phase quantity and by coatings of natural and injected surfactants and oils.

Most of the formation rocks are water wet and the alteration of the wettability leads to oil wet.

When a surface of a pore passage is oil-wet, more of the passage is occupied by the bound

oil (thicker monomolecular layer), and less of the pore is open to flow than in a water-wet

pore.



Wettability alteration damage is removed by injecting (mutual) solvents to remove the oil-

wetting hydrocarbon phase and then injecting strongly water wetting surfactants. Again, a

surfactant by itself will not work. The oil phase, which is usually precipitated asphaltenes or

paraffins, must first be removed with a solvent. (The same applies to an adsorbed oleophilic

surfactant.) Then, a strongly water-wetting surfactant can be injected and adsorbed onto the

rock minerals. This reduces the tendency for new hydrocarbon precipitates to stick to the

mineral surfaces and oil-wet them again. For retrograde condensation problems, the most

appropriate treatment technique is the injection of neat natural gas in a periodic “huff and

puff” operation. Condensate is picked up by the gas and transported into the reservoir.

Reprecipitation requires the retrograde of the process after several months of production.

6. Origins of Formation Damage & Remedial Measures

Formation rock gets damaged during its life by various known / unknown activities and

controllable / uncontrollable reasons. In order to reduce the chances of occurrence of the

formation damage, it is very essential to analyze each activity carried out in the well

during different period of well life. The analysis of these various activities will allow

understanding of the conditions and causes, which may lead to damage. This will help to

improve the activities so as to minimize the chances of occurrence of formation

damage. The understanding the formation damage origin is very critical to allow the

formation to produce to its maximum capacity.

a) Formation damage during drilling: Drilling is the first well operation, which brings

formation in contact with foreign material. This is also the first instance, in the life of a well,of formation damage. The formation is exposed to drill bit and drilling mud. To over come

inflow of formation fluids and to lay down a thin, low permeability filter cake on the walls of

the hole, the pressure of the drilling mud column must exceed the pore pressure by atleast

200 psi. The horizontal drilling requires more concern for formation damage, as it makes the

formation to be exposed to mud for longer period requiring more time drilling within the

targeted productive formation than do vertical wells. Under pressured reservoirs are also

significantly more susceptible to formation damage.

Filter cake

FracturePlugging



Well bore cross section Pore Plugging

Shallow matrix damage

Fig.: Drilling damage

Formation damage during drilling activity can be characterized by mainly twoProcesses:

– Invasion of Mud solids: Mud solids play a major role in the successful and safelycompletion of the drilling of the well. There objectives are to balance the reservoir

pressure thereby preventing the chances of Blow out and to create filter cake at the

formation face thereby reducing the filtrate losses in the formation. But these mud solids

can progressively fill the porosity of the reservoir rock if forced into the pay zone.

Subsequent attempts to start production or injection at moderate or high flow rates

may cause these materials to bridge and severely decrease the permeability of the

near-wellbore area. Such damaging processes are usually limited to the first few inches

around the wellbore (an average value of 3 in. is commonly used), but the resultantpermeability reduction can be as high as 90%.

– Invasion of Mud filtrate: Sometimes higher values of filtrate invasion may result from the

deliberate choice of high penetration rates. The liquid phase of a drilling fluid also

contains many potentially damaging compounds. Because filtrate invasion can be

deep drilling filtrate damage can be one of the most important causes of production

impairment. The severity of this damage depends on the sensitivity of the formation to the

filtrate. High-permeability clean sandstones undergo more invasion than lowpermeability reservoirs but are more likely to be less affected when their connate

water is chemically compatible with the filtrate.



Fig.: Formationdamagecausedby differentzonesof mudinvasion

There are several mechanisms by which mud solids or filtrate may reduce wellproductivity. These are summarized as follows:

i) Water Block: Invasion of large volume of mud filtrate can generate waterblock near

wellbore region. The capillary pressure plays important role in the generation of waterblock.

Water block may be avoided by the use of oil muds, provided no water is in their filtrates

under bottom hole conditions. As use of oil based mud (OBM) is not applicable in all type

of reservoir and in some cases it may be damaging, therefore during water base drilling

fluid the objective should be to minimize the filtrate loss to the pay zone. This can be

achieved only by effective filter cake at the formation face.

ii) Swelling and dispersion of indigenous reservoir clays by the mud filtrate: Nearly all

sands and sandstones contain clays that are either detrital or digenetic or both which

profoundly influence the permeability of the rock. The action of aqueous filtrates on

indigenous clays can severely reduce the permeability of the rock, but only if the clays

are located in the pores. The decrease in permeability at low salinities is caused by the

displacement and dispersion of the clay or other fines from the pore walls by the invading

fluid and by subsequent trapping at the pore exits. Swelling of the clay can be controlled

by maintenance of compatible salinity. The salinity of the injected fluid should be more

than the formation fluid. At salinities less than 20 g/l the clays become “unstable” (i.e.

dispersed). ate of reduction of salinity should be gradual to minimize the formation damage

due to salinity change.

iii) Penetration of the formation and plugging of its pores, by particles from the mud:

Mud particles can only penetrate the formation during the mud spurt period, before the filter

cake is established. Once the filter cake is fully formed, it filters out the finest colloids

because of its structure and very low permeability (around 10 – 3md). The permeability may

continue to decrease, but the decrease will be caused not by particles passing through the

cake, but by transport and re-arrangement of particles already carried in by the mud spurt.

a



b

Fig.: Structureof external (a) and internal (b) mudcakes

Most of the impairment caused by particle invasion is concentrated in the first fewmillimeters of the rock. The way to control mud particle damage is to minimize the mud spurt by

ensuring that enough bridging particles of the right size are present in the mud.

Fig. Effect of mudcake

To be effective, the primary bridging particles must be not greater than the size of the

pore openings and not less than 1/3 that size, and there must be a range of successively

smaller particles down to the size of the largest particles in the colloidal fraction. The

greater the amount of bridging particles, and the lower the permeability of the rock the

quicker the particles will bridge, and the smaller will be the mud spurt. Particle penetration of

2 to 5 cm is observed. The invasion of mud solids can be avoided using underbalance

drilling. Underbalance drilling in horizontal wells and in under pressure wells are very useful in

avoiding chances of formation damage. The need is felt to get clean brine in which thepresence of unwanted solids should be less. To achieve it the brine filtration system may be

proved useful

iv) Polymer invasion: During the drilling process many additives are added to the

drilling fluid for different purposes. Some of these additives are polymers and they may cause

damage in adverse condition if proper care is not taken during selection of the additives and

their composition.

The damage during drilling process is mainly of shallow depth only. The near wellboredamage is mainly choking of pores with fines or indissoluble mud cake. To remove this kind

of damage the acidizing is the most useful technique. Any one of the different kinds of

acidization technique such as matrix acidizing , acid washing, acid spotting ,etc. should be

used according to the formation rock and degree of damage. In sandstone the mud



flow effectively. Once cement is lost into the fracture system, hydraulic fracturing or

sidetracking and redrilling the well are the best alternatives. In some carbonate

formations, acid fracturing may be beneficial.

The differentdamagemechanismsin cementingoperationsare as follows:-

i) Fines migration from the cementslurry into the formation : The fines present in the cement

slurry may migrate into the formation during the cementing operation, if sufficient mud

cake is not present. These fines can block the pores and can lead to formation damage.

ii) Precipitationof solids from the cementwithin the formation : Cementing operations produce two

distinct generation of aggressive alkaline fluids which can permeate into and react with

the formation adjacent to the cement rock interface. They are, invasion filtrates which are

forced from the liquid cement into formation during cement pumping and setting shut-in

and cement leachates evolve & diffuse /advect away from the well bore as the set cement

equilibrate with aqueous formation pore fluids. These invading cement filtrate and leachates

are the potential source of formation damage. Ca(OH) 2 present in the filtrate may allow the

precipitation of calcium silicate. Because the cement slurry always contain additive ,they

also play a role in the formation of precipitate particles during cement filtration.

iii) Differential dissolution of reservoir minerals leading to fines migration : The cement has a very

high pH (>12) and a high concentration of divalent ions. The high pH tends to cause clay

and fines to be released and to migrate into pore threats, where they cause damage. The

cement filtrate may cause growth of large calcium carbonate crystal in a pore opening

and additional loose fines on the pore wall, indicating a potential pore plugging problem.

Some SBR latex cement slurries, commonly used for gas control, may cause severe

formation damage due to latex deposition in the formation. Because of the limited solubility

of SBR latex, the damage could be permanent.

Though the chance of damage during cementing operation is very slight, it should be

given proper care. To prevent the possible formation damage during cementing operation,

the presence of sufficient and proper mud cake is essential. The mud cake helps to keep

the cement filtrates away from the formation, which are the major culprit for formation

damage. Fluid loss from spacers and cement slurries is reduced when a competent drilling

mud filter cake is present on the formation face. The addition of KCl to spacers or

cement slurries will help to reduce or eliminate formation damage. A non damaging, fluid

loss additive, such as PVA or HEC, is used to minimize filtrate leakoff from the cement slurry.

The proper selection of the additives is necessary, as they play major part in further

reactions. The use of seawater should be given care.

The chances of damage during the cementing operations are very less, as normally the

presence of mud cake during drilling prevents further damage but lack of care may

damage the formation. Normally it is also damaging in shallow depth only.

Damage mechanism %emedial measures



Perforating process initiates the flow of formation fluid to the wellbore. Perforations are the

entry point from the formation to the wellbore, and all flow in a cased, perforated completion

must pass through these tunnels. Generally the perforating process if treated as a good sign,

as it starts the production. But the negligence during perforation may lead to formation

damage and thereby reduce the productivity. Perforating mildly overbalance always forcesformation and gun debris into perforation walls and decreases the permeability near the

perforations. The overbalance / under balance, perforation diameter, perforation

penetration, perforation density, etc all should be adequately given proper attention. The

formation around the perforation get crushed and compacted by perforating process.

Perforations may be plugged with shaped charge debris and solids from perforation fluids.

These pulverized, compacted rock and charge debris may block the natural pore spaces in

the formation. The extreme overbalance perforation generates more chances of damage as

the invasion of perforation fluid! it"s filtrate and solid particles can cause problem such asclay swelling, solid plugging and water blocks, etc.

Fig.: Damageduringperforationdue to overbalance

The workover process makes the wellbore condition more or less like the drilling condition.

Definitely the contact area between the formation face and the wellbore fluid is less, but then

also the chances and mechanism of formation damage are as same as during drilling

process. The loss of filtrate and the fluid particle invasion may lean to formation

damage and therefore care should be paid during workover operation to avoid the damage.

During the performance of such operations, many conditions exist that can cause the

formation damage of one or more of the forms. The different mechanisms are as follows:

i) Hydration and swelling of clay minerals : During workover/completion jobs the fluid

filtrate enters in the formation and if the percentage of clay (mainly montmorillonite) is

more then selling of clay minerals may occur. Due to less salinity of the fluid also the

swelling or hydration becomes severe. The hydrated and swelled clay minerals choke the



pore spaces.

ii) Movementand pluggingby clay size particlesin the formation : The solid particles in form of

invaded fines from filtrate or insitu formation fines may be generated during the job and

can choke the pore spaces. Due to inefficient cake formation and extreme overbalance

condition, the fines present in the fluid may enter in the formation and thereby causing

damage. Due to change in chemical environment of the fluid inside the formation there may

be generation of the fines inside the formation.

iii) Emulsion and water blocksdue to lost wellborefluid : If the fluid loss during the job

is not controlled then large amount of the fluid loss can be accumulated near wellbore

in the formation. This accumulation of large volume of water and filtrate may lead to

formation of water block. The presence of filtrate may form emulsion if the favorable

conditions for emulsion formation exist.

iv) Relativepermeabilityeffects : The presence of large volume of water or filtrate, due to lack

of sufficient cake formation, the relative permeability of oil changes and the wells doesn"t

produce even after perforation and wor#over job.

v) Precipitationof scales : There are many additives added in the fluid for different purposes.

In adverse conditions the precipitation of scale may be generated, which causes damage to

the formation. The presence ofasphaltene, wax and resin may the condition sever and

increase the chances of scale formation. The chemical incompatibility of the fluid with

formation rock and formation fluid also tends to form scales and lead to formation damage.

To save the formation against damage during workover and completion job many

precautions are necessary. The care on every job detail during the execution of the

job is necessary. Depending on the job objectivity and the type of fluid used, well productivity

damage during workover and completion can be minimized by:

i)

ii)

Using chemically compatible fluid,

Cleaning the fluids by filtration on the surface,

iii) Providing adequate fluid-loss control with agents that bridge on the

surface of the formation and that easily dislodge or dissolve when the well is put on

production,

iv) Minimizing fluid loss by establishing a small pressure differential between the

wellbore and the formation,

v) Cleaning the injection string of pipe with acid/solvent mixtures and mechanical

Scraper



vi) Using bottom hole filters (if necessary, in conjunction with surface filters).

vii) Perforating at efficient overbalance condition or in Underbalance condition.

Its normally seen that after per foration the well doesn"t produce. The most likely culprit is

formation damage. The different remedial measures depending upon cause of damage and

degree of damage are as follows:

Damage mechanism %emedial measures

Hydration and swelling of clay minerals Matrix acidization, Hydraulicfracturing, Clay stabilization

Movement and plugging by clay sizeparticles in the formation

Matrix acidization ,Clay stabilization

Plugging by invading materials fromthe wellbore fluids

Matrix acidization

Emulsion and water blocks due to lostwellbore fluid

Surfactant treatment, Matrixacidization

Relative permeability effects Surfactant treatmentPrecipitation of scales AcidizationPlugged perforations due to improperperforating conditions

Acidization, Perforation

d) Formation Damage During Sand ontrol operations: Most high permeability unconsolidated and

loosely consolidated sandstone formations require sand control measures. The most widely used

sand control technique is gravel pack completions. The gravel packed completions are designed to

allow the soft formations to produce sand free and the productivity of the well is also maintained.

However many gravel packed wells produce sand free hydrocarbon but suffer reducedproductivity as a result of formation damage induced by current gravel pack completion practices.

Gravel packing slightly damaged formation or damaged caused during gravel packing operations

can result in long term detrimental effects on production. Major sources of damage in gravel packs

are:

Improper placement of the gravel pack (perforations remain empty or the annulus between

casing and screen is incompletely filled), allowing perforation filling by formation sand, pack

fluidization and subsequent intermixing of sand and gravel in the case of pressure surges

Damage by unbroken gels or formation particles during placement as a result of incompleteperforation cleaning

Invasion by loss-control materials (LCM)

Thread dope, paint, rust and polymer residues forced between formation sand and the gravel

pack during placement

Inadequate gravel size, leading to gravel-pack invasion by formation fines during production

Screens with slots too large (do not retain gravel) or with slots too narrow that become plugged

and reduces production.

The mechanismsof formationdamageduringsandcontrol are as follows:

i) Pore plugging by solids: Gravel size selection is most important in gravel packing procedure of

sand control. Inefficient gravel size may lead to pore plugging or perforation plugging. In gravel

packing, plugging of the pack may occur from formation and well bore. The gravel pack can also



gradually fill the formation sand. Mud solids deposited by the under reaming fluid can also

decrease the permeability. If the properties related to filtrate and bridging agent of the gravel

packing fluids is not analyzed carefully, they can be proved harmful also, similar to the drilling

fluid during drilling process. Poor quality gravel and dirty packing fluids may prove as source of

plugging.

ii) Perforation plugging: In gravel pack operation all the perforations are filled with gravels. The

migrated fines and smaller sand particle may plug these perforations in proper bridging effect is not

generated in the gravel pack around wellbore.

iii) Polymer invasion: Failure to properly prepare gravel pack carrier fluids is a major contributor to

formation damage. The two primary areas of concern are microgel plugging and breaker

performance. Proper diffusion of microgels will result in an increased viscosity and ease of

filtration. It is important to remember that polymers are suspended solids. Therefore, too high a

level of filtration or utilization of multiple filtration cycles will remove polymer, which could result in

poor performance. Inadequate breaker performance is a major cause of formation damage.

In order to minimize the chances of the formation damage during sand control operation following

important points should be carefully analyzed:

i) Gravel size selection is the most important part of success of any gravel pack operation. Proper

size of the gravel provides better bridging effect and controls the sand and fines migration.

ii) Pickling the work string prior to gravel packing is the most efficient method for eliminating pipe

dope deposition as a potential formation damage mechanism.

iii) Prior to gravel packing, the perforations must be completely open in order to effectively place,

gravel in the perforation tunnels. Both washing and surging techniques are adequate for removing

bulk formation damage existing in perforations.

iv) The fluid composition used during the job execution should be compatible with the

formation rock and should be capable of handling fluid leakoff property.

The main cause of damage during sand control are plugging due to solids.The remedial measures are as follows:

Damage mechanism %emedial measuresFines migration Acidization, Clay stabilization , Frac &

Pack , Acidization with foam based fluidsPerforation plugging AcidizationPolymer invasion Surfactant treatment, Matrix acidization

e) Formation Damage During Production: In production phase, though the formation does not

come in contact with any external agent, it may be damaged due to intrinsic changes only.

Major constituent of production are formation rock and formation fluid. Their mechanical and

chemical properties are very important for optimum production without any problem. Any adverseproperty can lead to formation damage and may reduce the productivity of the well. Major causes

of formation damage during production phase can be generated by the movement of the

formation fines / sands and changes in formation fluid properties. Formations that are capable

of releasing parts of the matrix during production or after stimulation pose special treating



problems. Although these situations are commonly thought of as sand-control problems rather than

formation damage, the effect of mobile sand and the pressure drop caused by collapsed

formation tunnels closely resemble the effect of formation damage. Some reservoirs cannot be

produced at high flow rates or large drawdowns without being affected adversely. Permanent

damage, which cannot be removed simply by the reducing production rate, may be created. A

major problem is the movement of fines in the formation in response to either flow velocity or

changes in the salinity of the flowing fluid. Native silts and clays loosely attached to pore walls can

be put into motion by high flow rates, especially when two or more immiscible fluids are produced

at the same time. Depending on their particle size, they can either block pore throats in the

vicinity of their initial location or migrate toward the wellbore. Reduction in the pore pressure

during production and sometimes cooling resulting from gas expansion, results in the

precipitation of organic or inorganic materials. Generally, these deposits affect only the production

string and surface equipment. However, they can reduce formation permeability. Seeds, such

as high-surface-area clays, promote the deposition of organic materials (especially

asphaltenes) or the precipitation of supersaturated salt solutions. Common scales are calcium

carbonate and calcium sulfate. Problems associated with the deposition of elemental sulfur,

sodium chloride and barium sulfate have also been experienced. Commingled precipitation of

asphaltene and calcium carbonate is common. Retrograde condensation and bubble point

problems are relative permeability blocking problems. Retrograde condensation is the

condensation of a liquid from gas. When this happens, the relative permeability to gas can be

reduced substantially. In oil reservoirs produced below the bubble point pressure, free gas is

formed, which reduces the relative permeability to oil.

The followingmechanismsare responsiblefor damageduringproduction :

i) Fines migration : The production rate and rock matrix strength are important factors in the

fine generation during production. The increased production rate, crossing the critical

velocity of formation fines generation, may generate the formation fines and cause pore

blocking. Presence of Kaolinite or fibrous illite clay or some feldspars (nonclays) enhances the

chances of fines generation and their movement inside the formation. Brine changes may

trigger fines movement. To minimize chances of fines generation, the production rate or flow

rate should be controlled and should not be allowed to cross the critical velocity of formation

fines generation. If the formation matrix strength is too low and the formation is weak then

proper sand control technique may be used for controlling the fines movement and their

generation.

ii) Scale deposition : The scale deposition in the formation may cause pore space reduction.

Calcium carbonate scale may form at any pressure drop, either in the formation or tubulars. It

may form quickly and can sharply limit production, especially at gravel-pack interfaces or near

perforations in wells with high drawdown across the perforations. These are more common in

earlier stages in some fields when the pressure drop is more severe. Effective and proper inhibitors

in sufficient amount should be used in the well to prevent the scale deposition. Scale inhibitor

should be used in the wells according to the type of scale expected.

iii) Paraffin, Wax& Asphalteneformation: Paraffin and Wax deposition in producing string is common

problem, but skin damage from their deposition may also occur. If Cloud point of oil is near the



reservoir temperature, then the chances of formation damage sue to them increases. Pressure

drop may also trigger paraffin drop out. It may disappear if well is shut in for several days. The

precipitation of asphaltene may be triggered by destabilization of maltene resins caused by acid

contact, out gassing, shear in pumps, electrically charged metal surfaces, temperature reduction

and CO2. The asphaltenes are adsorbed on the formation rock surface. Generation of paraffin can

be prevented with help of inhibitor squeeze. Treatment with downhole heat- generating processes

also helps if the well is a good producer. The solvent soaks may also be used. The reservoir

pressure maintenance helps wax and asphaltene generation. As their generation is controlled by

many different mechanism and therefore its prevention is not so easy. But, treatment with aromatic

(cyclic ring) solvents such as xylene or toluene and some surfactants are useful for dispersion of

the asphaltic mass.

iv) Wettability alteration : The absorbed asphaltene layer induce wettability alteration of the oil

bearing formation. The injection of incompatible surfactants can also alter the wettability of the

formation rock. These can be prevented by using the surfactants only after compatibility studies.

v) Condensate banking: In gas reservoirs with significant condensate yield and relatively high dew

point pressure, the condensate baking may occur. It will reduce relative permeability to gas thereby

reducing the production of the gas. This kind of problem arises with age of the well due to

decrease in pressure of the reservoir. It can be controlled using minimum production

drawdown and effective pressure control of the reservoir.

vi) Gas breakout: Gas breakout may occur in the wells having downward coning of preexisting

gas cap and increased near wellbore gas saturation. This increase in gas saturation near the

wellbore does not allow the oil to produce at its previous rate. This problem arises with drop

in reservoir pressure when pressure decreases below the oil bubble point pressure. It can be

controlled using minimum production drawdown and effective pressure control of the reservoir.

vii) Emulsion generation: The in-situ emulsion may be generated with presence of injected

emulsifying agents (incompatible surfactants) or natural emulsifying agents if other conditions

such high shear rate, water, etc. are already present. This emulsion will have higher viscosity

compared to both crude oil and water, which will decrease the productivity of the well. Emulsion

formation can be minimized with control on the causes of emulsion formation, i.e. formation fines /

silts and surfactant which resides at the interface.

The remedial measures for the damage occurred during production process are as follows:

Damage mechanism %emedial measuresFines migration Deep penetrating acid treatment, Clay

stabilizationScale deposition AcidizationParaffin, Wax & Asphaltene formation Surfactant treatment, Solvent treatmentWettability alteration Surfactant treatment, Solvent treatment

Liquid block Surfactant treatmentCondensate banking Hydraulic fracturingEmulsion generation Solvent / Demulsifier treatment

!) Formation Damage During #ater In ection And Di!!erent (% Methods :Success of a water injection scheme and other Enhanced Oil recovery (EOR) methods



depends on being able to inject sufficient quantity of injection water into zone of interest and

successful implementation of job. The injection well may not produce the desired result due to

lack of injectivity caused by formation damage. The other EOR methods such as steam

injection, polymer injection, insitu combustion, carbon dioxide flooding ,etc may also not give

expected result due to formation damage caused by these processes itself if proper care is not

taken in the selection of method and execution and implementation of the job. The different

mechanisms ,which can affect the result of the water injection and different EOR methods by

damaging the formation are as follows:

i) Solid invasion : If gradual reduction in injectivity is observed it may be attributed to

plugging of formation face by suspended solids in injection water. These solids can be

formation fines and clays, suspended solids, silt or carbonates fines from injection water

source, bacteria, corrosion products from surface or injection equipment or generation of

insitu solids by adverse chemical reactions between blended injection fluid or chemical

decomposition or degradation of injection water.

ii) Fines migration : Sandstone formations which may contain high percentage of

loosely attached and mobile clays exhibit critical interstitial velocity at which insitu

fines may occur. The dislodging of fines in the fluid stream by high water injection

velocities may plug the formation.

iii) Clay swelling: If swelling clays are present in the formation i.e. smectite clay then the

absence of proper salinity can result in clay swelling.

iv) Clay deflocculating: Clay deflocculating can also be the cause of injectivity

impairment in formations with no swelling clays, which is due to abrupt contact of with

fresh water or sudden salinity changes or shocks or sudden increase in pH level.

v) Formationdissolution: Target zones may include water soluble materials such as

highly hydratable clays, anhydrites, halites etc. Partial or complete dissolution or softening

of these constituents by sustained aqueous contact may lead to migration or release of

insoluble fines which were previously immobilized in an encapsulated state. These

materials carried by injection water into the formation may cause plugging thereby

impairing injectivity.

vi Skim oil entrainment : Oil entrapped in injection water is a major source of potential

impaired injectivity, which is due to high saturation of hydrocarbon liquid entrapped

in the porous media around an injector to ensure that a continuous oil phase with finite

relative permeability and mobility is obtained.

vii) Biologically Induced Impairment : Injection water, whatever the source, contains

bacterial agents. Bacterial problems associated with water injection can be associated

with the growth of both aerobic ( oxygen requiring) and anaerobic (non O 2 requiring)

bacteria in surface facilities, pumps, tubing, downhole equipment as well as within the

formation itself.

viii) Sand influx : It is observed that sand in injection wells remains stable till injection

continues. The moment injection is stopped due to disruption in power supply or some

other reason, there is sudden decline in the pressure in the tubing because of which



sand has the tendency to flow back into the wellbore. Presence of suspended

solids/oil in such situation brings the injectivity down.

ix) Chemical adsorption/ Wettability alterations : The injection water contains chemical

additives such as de-emulsifiers and surfactants used to inhibit emulsion formation or

allow the separation of the produced crude oil from the total fluid stream. In addition it

may include corrosion inhibitors, scale inhibitors, etc. These chemicals are highly polar

and may have a tendency for physical adsorption on both sandstones and carbonates.

The adsorption of these chemicals may cause :

Reductions in permeability.

Alterations in wettability (generally to a more oil-wet state).

x) Formation of insoluble scales and Emulsification: Carbonate and sulphate based scales

are commonly encountered in water injection operations. Emulsion formation is caused

by simultaneous formation of oil and water in porous media.

xi) Precipitate formation : Injection water may react adversely with formation water and form

insoluble carbonate, sulphates or iron based precipitate which can plug the target zone.



The important properties, which should be given, care to prevent the damage to the

formation during water injection are as follows:

I Total dissolve solids (Salinity and type of ions)

Ii pH and state of oxidation of brine

Iii Presence of Bacteria

iv) Additives,

Lack of proper preventive measures causes formation to be damaged by the job and

then the effectiveness of the job decreases very much. To restore the potential of the

water injection potential the efficient remedial measures are necessary. The remedial

measures for the damages done during water injection according to the different

damage mechanisms are as follows

Damage mechanism %emedial measuresSolid invasion Acidization, Hydraulic fracturingFines migration Acidization ,Clay stabilization treatment

Clay swelling High saline fluidClay deflocculating Surfactant treatment, Clay stabilization

treatmentFormation dissolution Acidization, Hydraulic fracturingSkim oil entrainment Surfactant treatmentBiologically Induced Impairment Biocide treatmentSand influx Sand consolidation treatmentChemical adsorption/ Wettabilityalterations

Surfactant treatment

Formation of insoluble scales andEmulsification

Surfactant treatment, Solvent treatment

Precipitate formation Acidization

g) Formation Damage During Stimulation Treatment: The objective of well stimulation is to

improve existing well productivity. If the well problem is accurately diagnosed and the

treatment is well designed and executed, the net effect will be improved productivity and

satisfactory economic payout. If the damage aspects dominate, however, the treatment may

result in no change in productivity or even a decline. Sometimes lack of proper care leads to

further damage after job also. Acids have been widely used for increasing or restoring the

permeability of formations Acid reactions can produce several side effects that can decrease

formation permeability if the acid composition is not properly analyzed /designed. During

acid treatment following mechanisms are responsible for formation damage:

i)External particle intrusion : If the wellbore is not cleaned properly before the acid job, i.e. in

absence of tubing pickling, the external damaging particles may enter into the formation

thereby creating much more problem. If the tubing rust or iron enters with acid in the

formation then it may lead to generation of sludge, which can increase the value of skin. Dirty



tubing strings can also be a source of damaging materials.

ii)Finesmigration : The excess and high concentration of acid may dissolve matrix and matrix

cement. Therefore, mineral grains may be liberated and can migrate to plug pores. It may also

lead to collapse of the formation.

iii)Reaction and precipitation: The acid reaction with the formation rock minerals are very

complex and the secondary & tertiary reaction and byproducts may generate formation

damage in place of stimulation.

iv)Sludge formation: Precipitation of colloidal materials from asphaltic crude oils may form

during acidizing and can plug the formations. These sludges, which form in presence of

asphaltenes, resins, paraffin waxes, and other high molecular weight hydrocarbons, when pH of

the crude oil is reduced by acid contact.

v) Emulsion formation: The additives / surfactant present in the acid formulation may result

in formation of emulsion. The presence of formation fluid, acid composition and generated

formation fines may enhance the chances of emulsion formation.

vi)Wettability alteration: The surfactants present in the acid composition, especially corrosion

inhibitor may change the wettability of the formation to oil wet.

vii)Water Block: Excess injection of the acid volume in the formation fluid during acid

treatment may lead to formation of water block near wellbore and cause formation damage.

vii)Iron ion precipitation: Formation damage from ferric hydroxide precipitation is a potential

problem in any acidizing treatment. Acid readily dissolves iron scales in pipe and attacks

iron containing minerals in the formation under treatment.

The proper laboratory studies while selecting the acid composition are essential so as to

control the occurrence of these mechanisms. Along with acid composition the job execution

also plays major role in the success of the stimulation job.

The different remedial measures for different kind of damage mechanismscausing damage

duringacid treatmentare as follows:

Damage mechanism %emedial measuresFines migration Clay stabilization, Hydraulic fracturingReaction and precipitation Hydraulic fracturing, Acidization

Sludge formation Solvent treatmentEmulsion formation Surfactant treatment, Solvent treatment

*+ Formation damage Diagnosis

To understand the nature and cause of formation damage, the correct diagnosis of the

problem is necessary. It helps to design proper effective treatment to solve the problem.

Diagnosis of the formation damage can be done with help of many different procedures and

available data.Well performance curves or production history of specific well can provide clues to help define

the problem. Comparing the actual well performance with the expected normal production

performance for that type of operative reservoir drive mechanism can be very helpful to

figure out the cause of production decline. The production trend and the information about



activities done on the well gives information, whether production decline is normal

reservoir pressure depletion or it is due to formation damage or to mechanical problems in the

well bore such as sand production or in effective artificial lift.

The well completion reports or workover reports may also give many helpful information.

S,I-: The value of skin is mostly used measure to quantify the extent and severity of the

formation damage. The higher positive value of the skin indicates the higher level offormation damage.

Fig.: Effect of Skin on production

F.(# FFI I - / : Flow efficiency can be also used to describe wellbore damage. It is the

ratio of the theoretical pressure drop if no skin had been present to the actual pressure drop

measured during the test. FE= ∆P (zero skin) / ∆P (actual)

P% SS0% T%A-SI -T A-A./SIS

Transient pressure testing has been used for many years to define various reservoir

characteristics. Several ways to identify, and quantify, formation damage in producing wells are

available from analysis of this type of test. The value of skin or extent of formation damage may

be measured with help of pressure transient analyses. There are many tests, which can beutilized. The choice of test depends upon the practical limitation and suitability. The different

kinds of tests are as follows:-

i) Drawdown test : In a drawdown test, a well that is static, stable and shut in is opened to

flow. But getting initial stable pressure and later const. Flow rate is difficult.



ii) "uild up test : In a build up test, a well which is already flowing (ideally at constant rate) is

shut in, and the downhole pressure measured as the pressure build up. The difficulty is to

get const. Rate production prior to the shut in and the production is lost while well is shut in. the

practical advantage is that the const. Flow rate condition, in the second half, is more easily achieved

(since the flow rate is zero).

iii) In ection test: An injection test is conceptually identical to a drawdown test, except that flow is into

the well rather than out of it. It is easier to control the injection rate than production rate. But, the

properties of the injected fluid play a major role if it is different from original reservoir fluid.

iv) Fall o!! test : - A fall off test measures the pressure decline subsequent to the closure of an injection.

It is conceptually identical to a buildup. Similar to injection test, in it also the earlier injected fluid plays a

major role.



-odal Analysis

Nodal analysis is another tool, which can be used to identify the presence of formation damage and

quantify the effect of the damage on the production rate as well. By definition, nodal analysis is a

systematic approach to the optimization of oil and gas wells by thoroughly evaluating the complete

Producing system. Each component of the producing system, including the reservoir, wellbore, and

surface facilities, is considered. Once a well"s optimum producing rate is determined! problem wells!

producing below this rate can be recognized. This reduced productivity can be a result of many factors,

but nodal analysis allows for evaluation of each component of the producing system separately ad

therefore can isolate the source of the problem.

Production logging

The production logging proves to be helpful in further defining the cause of formation damage.

The production logs, such as flow meter and grandiomanometer are normally used to determine the

flow profile of the perforated zone. By analyzing the flow profile, intervals that are contributing little

or no fluid can be identified.

.aboratory StudiesLaboratory studies in view of formation damage are done to understand the factors responsible for

damage, identification of damage mechanisms and remedial measures. The studies about the rock

mineralogy, formation fluid and their compatibility with other fluids and additives help to diagnose

the damage and to identify a suitable remedial measure.

The different laboratory studies which can be used to identify the nature of the damage, damage

mechanisms and factors responsible for damage are as follows:

X-Ray Diffraction Analysis

(b ecti'e-Qualitative and semi-quantitative analysis of rock and clay mineralogy

Applications

-The knowledge of composition of rock and clay mineralogy helps to

understand the probable causes of formation damage.

-The clay mineralogy can give information about the effect of different

fluids, which come in contact with rock.

-It helps to decide the acid formulation.

Scanning Electron Microscope Analysis(b ecti'e

-To get a view of framework grains, cements, matrix and porosity.

-To get view of distribution of clay particles and other fines within the

pore spaces.



Applications

-To understand the cause of damage

-Treatment design

Solubility Test

(b ecti'e

-To study solubility of rock formation in different acid formulations

-Filterate analysis for Iron content

Applications-To decide acid formulation & acid additives

-Treatment design

Core Wettability Test

(b ecti'e

study Wettability of core samples

Application

-It helps to decide acid additives.

Immersion Test (b ecti'e

-Study Effect of 2% KCl Kerosene, 15% HCl on formation chips

Application

-Treatment design

-Acid additives

Sludge Test

(b ecti'e

-Study for sludge forming tendency of crude oil with treatment acidformulation

-Solubility of sludge with different solvents

Application

-Treatment design

-Acid additives

lus! Test "it! #ndamaged Core $lug

(b ecti'e

-Develop Acid Response CurveApplication

-Treatment design

Damage E%posure

(b ecti'e

-Exposing restored core plug to specified drilling / completion fluid.

-Determine damage permeability

Application

-Treatment design

Brief Formation Damage

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