Formation damage evaluation

FORMATION DAMAGE
Formation damage mechanism:
 Physical mechanism
 Chemical Mechanism
 Bacterial Mechanism
The caking process:
 Formation of filter cake
Formulation of drilling mud:
 Fluid loss control chemicals
 Compatible mud filtrate

SOURCES OF FORMATION DAMAGE
Formation damage may occur during:
• Drilling operation
• Completion operation
• Workover operation
• Stimulation operation
• Production operation
• Injection operation
• IOR / EOR operation

Origins of formation damage & Remedies
Formation damage during drilling:
Damage mechanism
1. Particle invasion/ Filter cake
2. Swelling and dispersion of indigenous
reservoir clays by the mud filtrate
3. Mutual precipitation of soluble salts
in the filtrate and formation water
4. Slumping of unconsolidated sands
5. Water block / Emulsion block
Remedial measures
1. Matrix acidization,
Perforation, H.fracturing
2. Matrix acidization
4. Sand consolidation
techniques, Frac and Pack
5. Surfactant treatment,
Matrix acidization

Formation damage during cementing:
Damage mechanism
1. Fines migration from the
cement slurry into the
formation
2. Precipitation of solids from
the cement within the
formation
3. Precipitation of expansive
secondary minerals following
reservoir mineral dissolution
Remedial measures
Perforation, Hydraulic
fracturing
Perforation
3. Acidization

During well completion & workover
Damage mechanism
1. Hydration and swelling of clay
minerals
2. Movement and plugging by clay
size particles in the formation
3. Plugging by invading materials
from the wellbore fluids
4. Emulsion and water blocks due to
lost wellbore fluid
5. Relative permeability effects
6. Precipitation of scales
7. Plugged perforations due to
improper perforating conditions
Remedial measures
1. Matrix acidization ,Clay
stabilization
2. Matrix acidization ,Clay
stabilization
4. Surfactant treatment,
Matrix acidization
5. Surfactant treatment
6. Acidization
7. Acidization, Perforation

During sand control
Damage mechanism
• Fines migration
• Perforation plugging
• Polymer invasion
Remedial measures
• Acidization, Clay stabilization , Frac
& Pack , Acidization with foam
based fluids
• Acidization
• Surfactant treatment, Matrix
acidization

During Production
Damage mechanism
• Fines migration
• Scale deposition
• Paraffin, Wax &
Asphaltene formation
• Wettability alteration
• Liquid block
• Condensate banking
• Emulsion generation
Remedial measures
• Deep penetrating acid treatment,
Clay stabilization
• Acidization
• Surfactant treatment, Solvent
treatment
treatment
• Surfactant treatment
• Hydraulic fracturing
• Solvent / Demulsifier treatment

During W/I and Various EOR methods
Damage mechanism
• Solid invasion
• Fines migration
• Clay swelling
• Clay de-flocculation
• Formation dissolution
• Skim oil entrainment
• Sand influx
• Formation of insoluble
scales and Emulsification
• Precipitate formation
Remedial measures
• Acidization, Hydraulic fracturing
• Acidization ,Clay stabilization
treatment
• High saline fluid
• Surfactant treatment, Clay
stabilization treatment
• Acidization, Hydraulic fracturing
• Surfactant treatment
• Sand consolidation treatment
treatment
• Acidization

FORMATION DAMAGE
 All wells are susceptible to formation damage to some degree from
relatively minor loss of productivity to complete plugging of specific zones.
 Flow surveys invariably show that a high percentage of the zone is open to
the well-bore is not contributing to total flow.
 Critical area is always, a few feet away from the well bore.
 Contact with foreign fluid is the basic cause of formation damage. This
foreign fluid may be drilling muds, workover fluid, stimulation fluid, or
even the reservoir fluid itself if the original characteristics are altered.
 Fluid consists of two: liquid and solids. Either can cause significant
damage to formation through one or several possible mechanisms.

FORMATION DAMAGE (continued)
 Formation damage is usually caused by the invasion of mud solids & mud
filtrate in to the formation well drilling, completion, workover, water
injection operations.
 Formation damage chacterized by low porosity and low permeability with
significant presence of swelling and migrating clays.
Plugging associated with solids:
• Weighing materials, Viscosity builders, Drilled solids, Cement particles,
Lost circulation materials, Pipe dope, Precipitated scales,
• Clays, Fluid loss control materials, Perforating charge debris, Rust and mill
scale, Un-dissolved salt, Fines, Asphaltenes.

Physical mechanism:
Physical mechanism where formation can be damaged when pores
and pore channels become blocked by invading mud solids , fines
migration water blocks, emulsion block or gas block phenomenon.
Chemical mechanism:
Chemical mechanism caused by filtrate-pore fluid and filtrate ,
rock incompatibility, mud additives adsorption, / wettability
alteration of the matrix.
Bacterial mechanism:
o Bacterial growth where bacteria can cause permeability
impairment when produce wastes in the form of precipitates thus
blocking pores and pore channels.
o Formation damage problems can be mitigated by the use of a
properly designed mud system that forms a filter cake with low
porosity and low permeability near the well bore region which is
capable of minimizing the mud solids invasion and filtrate loss in
to formation.

Use of Alcohols and Mutual solvents in oil & gas wells
 Alcohols and Mutual solvents when used with workover fluids can remove or
prevent water or condensate blocks that restrict production.
 Alcohols normally mixed with surfactants to reduce surface tension are
effective at removing these blocks , while mutual solvents act as carriers to
minimize their adsorption on to formation.
 Water blocks and or condensate blocks are frequently encountered in gas and
retrograde gas wells. These blocks can be carried by a number of operations:
 Pressure drawdown in a retrograde well.
 Clean filtered brine kill fluids.
 Stimulation fluids.
 Shut-in where fluid is allowed to fall back on the perforations.
 Normal reservoir pressure decline.
 Cross flow
 Water coning.

 After a gas well has produced for a period of time, the formation around the
perforation become very dehydrated. This can result from the rapid expansion
of gas and the flash distillation of liquids in this area of maximum pressure drop.
 This mechanism can result in formation of salt deposits around the perforations.
When the dehydrated formation is contacted by fluid, formation minerals
especially clays and salts act like a sponge to strongly imbibe water.
 A block can then result when the maximum differential pressure that can be
achieved across the perforations is not sufficient to overcome capillary forces in
the pore channels.
Equation for calculation of differential pressure in capillaries is :
ΔP = Ω 2 cos θ/r
ΔP = Differential pressure dynes/cm2, Ω = Surface tension in dynes/cm2. (ST)
θ = Contact angle, r = Capillary radius.
o As ST of a fluid increases, contact angle is decreased or capillary radius is
decreased, the differential pr required to flow down a pore channel will increase.
o To minimize the fluid blocks, ST should be minimized and contact angle
maximized for that fluid in the formation.
o Alcohols have often been used to remove the fluid blocks. Physical properties of
two alcohols have been shown below.

Paraffin & asphaltenes
 Paraffin & asphaltenes are constituents of crude oils. Deposits of asphaltene and
wax in surface & down hole equipment are a major problem in production operations
 Severity depends upon crude oil production, well depth, formation temp, Pr
drop, and producing procedures.
 Any organic deposit associated with crude production is called paraffin or wax.
Paraffin compounds are major components of these deposits, they are frequently
a mixture of wax and asphaltenes.
Significant reasons for wax paraffin deposition:
• Cooling produced by the gas in expanding through an orifice or restriction.
• Cooling produced as a result of gas expansion forcing the oil ….
• Cooling produced by radiation of heat from the oil and gas to the surrounding
formations as it flows from the bottom of the well to the surface,.
• Cooling produced by dissolved gas being liberated from the system. Change in
temperature produced by water intrusion.
• Evaporation of the lighter constituents when there is increase in temp.
• Paraffin characteristics & asphaltenes vary significantly from reservoir to reservoir.
• Cross-flow.

 Paraffin & asphaltenes differ significantly in chemical structure.
 Paraffins are normal (straight chain) or branched alkalines of relatively
high molecular weight and represented by Cn H2n+2
 This type of hydrocarbons, inert to chemical reaction and therefore
resistant to attack by acids or bases.
 Paraffin deposit also contain asphaltenes, resins, gums, crude oils and
inorganic matter such as fine sand, silt, clays, salt, scales and water.
 Asphaltenes are black components present in the crude oil. Molecular
weight is relatively high. They are normally polar chemicals because of the
presence of sulfur, oxygen, nitrogen and various metals in their
molecular structure.
 Asphaltenes consist of polycyclic, condensed, aromatic ring compounds.
They are soluble in aromatic solvents such as benzene, toluene, xylene,
Carbon tetrachloride and carbon disulfide but they are not soluble in
distillates such as kerosene and diesel oil. They are also insoluble in other
low molecular weight hydrocarbons such as propane, butane.
 Cloud point is to be measured during early stages of crude oil production.

Asphaltenes
1. Melts slowly gradually softening
to a thick viscous fluid.
2. High viscosity fluids.
3. Burns with a smokey flame and
leaves thin ash or carbonaceous
ball
Paraffins
1. Melts over a narrow temperature
range
2. Hot Liquid has a low Viscosity.
3. Burns rapidly with less smoke
than asphaltene and leaves little
residue
Removal of wax deposits:
Mechanical
Solvents
Heat
Dispersants

Mechanical Removal of wax deposits:
• Scrapers and cutters are extensively used to remove paraffin from tubing.
• These are relatively economical and usually result in less damage to the
formation.
Removal of wax with Solvents:
• Use of solvents most common for removing wax. CCl4 is excellent solvent but
adverse effect on refinery catalysts. Carbon disulfide is also excellent solvent,
but very expensive. Extremely flammable.
• Condensate, kerosene and diesel are commonly used to dissolve paraffin in
wells where asphaltene content of the deposit is very low.
• Asphaltenes are not soluble in straight chain hydrocarbons such as kerosene,
diesel oil and most condensates. However some condensates contain aromatic
components enables them to dissolve asphaltic deposits.
• Aromatic chemicals such as toluene and xylene are excellent solvents for
asphaltene and paraffin deposits.
• Solvent application must be adopted to suit well conditions. Soaking of the
solvent over a period of time will usually dissolve the solvent.
• Severe paraffin build up in the tubing of rod pumping wells often makes rod
removal very difficult. Pumping a solvent down the tubing soften paraffin and
facilitates rod pulling.

Use of Heat for Removal of Wax:
 Hot oiling is one of the most popular methods of paraffin removal.
 Paraffin is dissolved and melted by the hot oil. Crude or other oil is
heated to a temp significantly greater than that of the formation. Hot
oil is normally pumped down the casing and up the tubing.
 Hot oiling can cause the plugging of the formation in wells having a
reservoir temperature of less than 1600 F (710 C). The formation will
cool the hot oil causing paraffin to be deposited in pores of the rock.
 Paraffin deposits frequently contain scales and formation fines that
are released when paraffin is dissolved or melted. Well productivity
can be reduced if these solids are forced into formation.
 Steam has also been used to melt paraffin or asphaltene in the flow
lines, tubing, casing, well bore or formation.
 Any application of heat to remove paraffin should be carried out
before large deposits have accumulated. The use of hot oil at regular
interval has proved to be effective.

Removal Wax Using Dispersants:
 Water soluble dispersants can be used to remove paraffin
deposits. Chemical concentrations (2-10%) water soluble
dispersant are generally used to remove paraffin removal.
 It does not remove paraffin but disperses paraffin particles, to
be circulated from the well.
 In low pressure wells, the dispersant solution may be injected
down the annulus and then pumped with oil production.
 When paraffin is very hard and dense , soaking period of 3-4
hours is suggested prior to returning the well to production.
 Surface lines can also be cleaned by circulating dispersant
through the system.
Pour point Depressors: (PPD)
 PPD is generally used on the surface for flow assurance from the
process station till oil reaches to refinery.

Surfactants for well Treatments
 Surfactants are chemicals that can favorably or un-favorably affect the
flow of fluids near the well bore .
 Chemically a surfactant has an affinity for both water and oil. The
surfactant molecule is partially soluble both in water and oil.
 Surfactants can bring the following changes of reservoir fluids reservoir:
 Raise or lower surface and interfacial tension
 Make, break, weaken or strengthen an emulsion.
 Change the wettability of reservoir rocks and casing, tubing.
 Disperse or flocculate clays and other fines.
 Surfactants can also reduce interfacial tension between two immiscible
liquids by adsorbing.

 Wettability is a descriptive term used to indicate whether a rock or
metal surface has the capacity to be preferentially coated with a film
of oil or a film of water.
 Surfactants may adsorb at the interface between the liquid and rock
or metal surface and may change the electrical charge on the rock or
metal there by altering the wettability.
 Sand and clays are water wet and have a negative surface charge.
Lime stone and dolomite are water wet and have a positive surface
charge in the pH range of 0-8
 Non ionic surfactants are the most versatile of the surfactants, used to
lower the surface tension, prevent damage and stimulate the well.
Non ionic surfactants do not carry a charge and therefore compatible
with most other chemicals being used in production operations.
 Non ionic surfactants are more soluble at lower temperature,
however they are more prone to come out of solution at an elevated
temperatures forming insoluble miscelles visible as a cloud point

Types of damage that are prevented, alleviated or aggravated by surfactant
o Oil wetting of formation rock
o Water blocks
o Viscous emulsion blocks
o Interfacial film or membrane blocks
o Particle blocks caused by dispersion , flocculation or movement of clays.
o Flow restriction caused by high surface or interfacial tension of liquid.
Oil wetting of formation rock: Sources of oil wetting in oil & gas wells:
• Surfactant in drilling mud filtrates, workover or well stimulation fluids
may oil wet the formation.
• Corrosion inhibitors and bactericides are usually cationic surfactants
which will oil wet sand stone and clay.
• Stock tank or heater treater emulsion breakers are cationics which will
oil wet sand and clay.
• Oil base mud containing blown asphalt will oil wet sand stone. Filtrates
from oil emulsion muds usually contain considerable cationic surfactants
which will oil wet sand stone and clays.

Water Blocks:
 When large quantities of water are lost to a partially oil–wet
formation, the return of original oil or gas productivity may be very
slow especially in partially depleted reservoirs.
 It is caused by temporary reduction of relative permeability near the
well bore to oil or gas.
 Water blocking can be prevented by adding about 0.1to 0.2 % by
volume of surfactant selected to lower surface and interfacial
tension, water wet the formation and prevent emulsions.
 Clean up of a water blocked well can be accelerated by injecting in to
the formation solution of 1% to 3% by volume of selected surfactant
in clean compatible water or oil.
 The surfactant should lower the surface and interfacial tension and
leave the formation in a water wet condition.
 It requires many times the volume of surfactant to prevent or remove
the formation damage.

Interfacial Films or Membranes:
 Film forming material including surfactants can be adsorbed at the
oil- water interface and cause formation plugging.
 Interfacial films are related to oil wetting and emulsion properties of
crude. Fines, clays and asphaltenes increase film strength.
 An increase in percent salt in a solution increase film strength. Oil
exposed to air may form tough films. Specific surfactant may also
increase film strength in a particular oil-water system.
 The use of solvent as a carrier for surfactant is usually beneficial in
removing tough films.

Emulsion Block:
 Various emulsions of oil and water in the formation near well bore can
drastically reduce the productivity of oil and gas wells.
 Emulsions in the formation can be broken by injecting demulsifying
surfactants into the formation provided intimate contact is made
between the surfactant and each emulsion droplet.
 Breaking emulsion in the formation usually require injection of 2-3% by
volume of demulsifying surfactant in clean compatible water or clean
oil.
Diagnosis of Emulsion block:
 If the calculated average well permeability as determined by the
injectivity tests is more than the average permeability determined from
the production tests, then it can be attributed to emulsion blocks.
 It is frequently called check valve effect.
 If an emulsion blocked well is producing water, increasing or decreasing
rates will not appreciably change the water percentage.

Particle Block:
 It is desirable to maintain formation clays in the original condition in the
reservoir, but an oil or gas formation may be blocked by transmission of
clays into the formation in water or oil or mud filtrate.
 Dispersing flocculating, breaking loose or moving clays causes more
damage to wells than the swelling of clays.
Dispersion of clays: Diagnosis of emulsion block:
• Clay dispersion is a frequent cause of formation damage. A non-ionic
surfactants will disperse clays in acid solution. High pH fluids tends to
disperse clays.
• High concentrations of same surfactants may damage the formation by
dispersing clays in to formation.
Flocculation of clays:
o Clay flocculation may sometimes reduce or increase formation damage.
o Specific non ionic surfactants may be used to flocculate clays.
o Acid and other low pH fluids tend to flocculate clays.

Change of Particle Size:
• Oil wetting clays with cationic surfactants increase the size of clay
particles and there by increase the severity of clay blocking.
• Cationic surfactants are difficult to remove from clays and sand; use of
cationic surfactants should be avoided in sandstone reservoirs.
• A mutual solvent preflush may prevent cationic adsorption on clays, sands
• Anionic surfactant should always be used when acidizing sandstone with
HCl to prevent clay flocculation as well as to prevent emulsions and to
increase water wettability of the formation.
• Lowering surface and interfacial tension will aid in preventing emulsion
and water blocks and will accelerate well cleanup.
• Proper use of surfactant during well completion can prevent many types
of damage and result in increased productivity.
• A correct surfactant which is designed for specific well conditions can
lower surface and interfacial tension, favorably change wettability, break
or prevent emulsions, prevent or remove water blocks, cause clays to
disperse, flocculate or remain in place as desired

Susceptibility to surfactant related damage:
 Organic corrosion inhibitors and bactericides are cationic
surfactants. Before squeezing any cationic corrosion inhibitor into
sandstone, lab testes should be run on cores to determine the effect
of specific corrosion inhibitor on formation permeability.
 Caution must be exercised in using salt water or oil from treaters or
field stock tanks treated with cationic surfactant emulsion breakers.
 The damage effects of cationic surfactant may be overcome by
adding selected surfactants or mutual solvents.
 Crude containing more than 1% asphaltene are prone to formation
damage that is amenable to surfactant and solvent stimulation.
 Low API gr crude usually contains a high asphaltenes. Sandstone
wells producing low gr crudes are more susceptible to formation
damage from oil wetting, emulsion blocking, and water blocking.
 24-72 hour solvent surfactant soak followed by HF acid treatment is
usually best treatment for wells.

Formation damage evaluation

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