Formation damage can be defined as the reduction in the original permeability of the reservoir rock close to the wellbore. The potential of the near wellbore formation permeability being reduced (damaged) exits from the minutes the drilling bits enters the formation until the wells is abandoned. 

From the time the drilling bit enters the pay zone until the well is put on production, the zone is presented to drilling fluids that could be detrimental to the future productivity of the well. At the point when drilling through the zone, the nature of the drilling liquid and the pressure differential are basic. 

Generally oil and gas well reservoirs are penetrated using water based drilling fluids. The presentation of both the mud solids and polymers into the formation influences the liquid saturation in the pore space. The response between the formation fines and/or contradictory reservoir brine with moved mud fines and filtrates brings about a decrease of the formation original permeability. Oil wells that are completed in an open opening system, even generally shallow attack close to the wellbore might considerably hinder the stream in light of the fact that reservoir fluids must go through the damaged zones before production. 

The formation can be damaged in distinctive ways. Physically, the formation can be damaged by: 

(a) The attacked mud solids obstructing the pore channels 

(b) The narrowing of vessels because of adsorption of attacked polymers furthermore 

(c) Water block, emulsion block and gas block. 

Synthetically, the formation can be damaged by the response between the filtrate and pore substance and/or network materials. Swelling and scattering of muds and precipitation by the response between mud filtrate and pore content and additionally arrangement of salt and minerals from the network are the primary elements. 

Bacterially, the formation can be damaged by the settlement of microscopic organisms and their hastened items, obstructing the pore channels. 

In this manner with a specific end goal to augment the economic benefits of oil wells, it is important to know the attributes of damage accounted during drilling and to create strategies to minimize the degrees of damage brought on by drilling fluids. 

Van Everdingen and Hurst presentation the ideas of skin component to the petroleum business. They perceived that for a given flow rate, the measured bottom hole flowing pressure was not as much as that computed hypothetically. This demonstrated that there was an extra pressure drop over that figured hypothetically and is free of time. They ascribed this pressure drop to a little zone of changed or decreased permeability around the wellbore and called this "attacked/damaged/skin" zone. They suspected that attacked zone is because of reservoir pollution by mud and stopping of some pore spaces around the wellbore. Numerically, skin drop is exhibited by,


The concept of thin skin in the above equation works very well in damaged wells. But because of mathematical and physical difficulties when the well is stimulated i.e negative skin, it has to be generalized.

Hawkins modified the above equation by introducing the concept of thin skin. He defined skin factor for a damaged zone of radius rs with permeability ks in a formation with permeability k and wellbore radius rw 9see figure 1.2 & 2.2) as:

Image ..................1.2

Theoretically, the skin factor for a damaged well can vary from zero to Image and for simulated well, the skin can vary from zero to a value as low as -6.

1.1 skin Damage & Formation Permeability 

Skin damage is brought about by drilling liquid attack, which decreases the permeability around the wellbore. A high permeability reservoir exhibits a high attacked zone than a low permeability reservoir. However the rate loss in permeability in a high permeability zone is smaller than that in a low permeability zone. This is on the grounds that those high permeability formations have extensive pore throat sizes, which are not totally obstructed by solids in drilling fluids. 

Though pore throats or low permeability formations are little, mud solids and filtrates presumably obstruct those throats bringing about huge decrease in permeability. Comparison 1.2 demonstrates that change in permeability is more essential than thickness of the attacked zone.


FIGURE 1.1: A Schematic Of A Well With Damaged Zone (Skin Damage)



Pwf1 > pwf  > pwf2

FIGURE 1.2: Effect Of Skin Factor On Well Flow Pressure.


The objective of this project is 

⦁ To recognize, diagnose the causes of formation damage.

⦁ To analyze the effect of the damage to the wells.

⦁ To evaluate the economic effects of formation damage.

⦁ To make recommendation of formation damage removal base on evaluation and analysis of data.


The study is concerned with the causes, effect on the wells and the economic effects of this damage on the wells as well as solutions of formation damage in oil wells. 


This well was drilled as a deviated appraisal well in 2003. It was also completed in 2004 as a TSM.  It came on stream in June 2004 and was rapidly beamed up to potential. Production picked in January 2005 at 3702 BOPD on 44/46”. Interval started cutting water in November 2006, thereafter, production started to decline. Further beam-ups failed to increase production or arrest decline. An abnormal decline in FTHP occurred in June 2007 following a beam up to 52/64”. Since then THP has been fairly low. The production fell to 1250 barrels per day. A stimulation program was carried out in June 2008 when the production rate decreased to 975 BOPD.


This method adopted in writing this research project is through abstracts obtained from journals, textbooks, SPE technical papers and presentations. The research project also involved the receiving of past project of similar subject matters and obtaining relevant information. 


The initial sign that will occur to show that a formation is damaged is that the well will not produce as expected on initial production or after a work over operation, or that an extensive pressure buildup develops in injection wells.

Sometimes it is unimaginable that a well that has been producing at about 2000 barrels of oil per day suddenly reduces to 200 barrels per day without production test giving us the impression that the well has been depleted.


Formation damage is defined as any type of process which involves in a reduction of the flow capacity of an oil, water or gas bearing formation. Formation damage has long been recognized as a source of serious productivity reductions in many oil and gas reservoirs and as a cause of water injectivity problems in many water flooding projects.


Formation damage can occur whenever non-equilibrium or solid bearing fluid enters a reservoir, or when equilibrium fluids are displaced at extreme velocities. Thus, many processes used to drill, complete or stimulate reservoirs have the potential to cause formation damage. Some of the operations are:

1.8.1 Drilling

Mud Solid And Particle Invasion

⦁ Pore throat plugging 

⦁ Particle movement

Mud Filtrate Invasion

⦁ Clay swelling, flocculation, dispersion and migration

⦁ Fines movement and plugging of pore throats.

⦁ Adverse fluid-fluid interaction resulting in either emulsion/water block, or organic scaling

⦁ Alteration of pore structure near wellbore through drill bit action

1.8.2 Casing & Cementing

⦁ Blockage of pore channels by cement or mud solids pushed ahead of the cement.

⦁ Adverse interaction between chemicals (spacers) pumped ahead of cement and reservoir mineral fluid.

⦁ Cement filtrate invasion with resulting scaling, clay slaking, fines migration and silica dissolution.

1.8.3 Completion

⦁ Excessive hydrostatic pressure can force both solids and fluids into a formation.

⦁ Incompatibility between circulation fluids and the formation with resultant pore plugging.

⦁ Invasion of perforating fluid solids and explosives debris into the formation with resultant pore plugging.

⦁ Crushing and compaction of near wellbore formation by explosives during perforation.

⦁ Plugging of perforation of extraneous debris (mill scale, thread dope, and dirt).

⦁ Wettability alteration from completion fluid additives.

1.8.4 Well Servicing

⦁ Problems similar to those that can occur during completion.

⦁ Formation plugging by solids in unfiltered fluids well killing.

⦁ Adverse fluid-fluid and fluid-rock interaction between invading fluid and reservoir minerals.

⦁ Damage to days from dumping of packer fluids.

1.8.5 Well Stimulation

⦁ Potential plugging of perforations, formation pores, and fractures from solids in the well kill fluid.

⦁ Invasion of circulation fluid filtrates into the formation with resultant adverse interaction.

⦁ Precipitation of hydrofluoric acid reaction by-products during acidizing.

⦁ Potential release of fines and collapse of the formation during acidizing.

⦁ Precipitation of iron reaction products.

⦁ Plugging of pores and fractures by dirty fracture liquids.

⦁ Inadequate breakers for high viscosity fracture fluids may cause blockage of propped fracture.

⦁ Fluid loss or adverting agents may cause plugging of the perforation pores, or propped fracture.

⦁ Crushed propants may behave like migratory fines to plug the fracture.

1.8.6 Production

⦁ Initiation of fines movement during initial DST by using excessive drawdown pressures.

⦁ Inorganic/organic scaling through abrupt shift in thermodynamic conditions.

⦁ Sand production in unconsolidated formations triggered by water encroachment into producing zones.

1.8.7 Secondary Recovery Operations

⦁ Formation wettability alteration from surface active contaminants in the injection water.

⦁ Impairment of infectivity due to suspended solids (clays, scale, oil and bacteria) in the injection water.

⦁ Formation plugging by iron corrosion products.

⦁ Inorganic scaling due to incompatibility of injected and formation waters.

⦁ In pressure scaling due to incompatibility of injection, formation may be plugged by compressor lubricants that may also alter wettability

⦁ Reduced well injectivity from injected corrosion inhibitors in gas zones.

1.8.8 Enhanced Oil Recovery

⦁ Fines migration, clay swelling and silica dissolution initiated by contact of high pH steam generator effluents (condensates) with the formation rock during thermal recovery.

⦁ Dissolution of gravel packs and increased sanding during thermal recovery.

⦁ Inorganic scaling due to change in thermodynamic conditions during steam injection.

⦁ Plugging due to carbonates deposition during CO2 injection.

⦁ Deposition of asphaltenes when CO2 contacts asphaltic crude oils.

⦁ Potential emulsion formation during CO2 wags process.

⦁ Fines movement due to hydrodynamic conditions of velocity and viscosity during chemical EOR process with surfactant and polymers.


Formation damage poses a serious problem to the oil and gas industry. Before the drill bit penetrates the reservoir region, the reservoir rock and its constituent minerals and resident fluids are essentially in a state of thermodynamic equilibrium. This equation is disturbed during the drilling process when extraneous mud solids/fines are introduced into the wellbore giving rise to pressures in excess of the reservoir pore pressure. The resultant differential pressure usually referred to as overbalance pressure, promotes the invasion of the colloidal materials and filtrates into the near wellbore region of the formation where they reduce the intrinsic permeability.

The impact of formation damage on reservoir productivity can be evaluated by computing the annual revenue loss per well (FD$L) at given oil price p:

Image ............1.3

Advances in causes and control of formation damage..

Ameafule and Kersey “international publication of core Laboratories, Division of Western Atlas International. Inc (January, 1990)


q= Undamaged flow rate STB/D

P= Oil price, $/bbl

DR= Damage ration-fractional loss in production rate

FD$L= Annual revenue loss per well, $U.S



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