formation damage

Formation Damage

• Examples

– Scale

– Emulsions

– Paraffin

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Damage – What is it?

• Divide the well into three parts: – Inflow: area from reservoir to the wellbore

– Completion potential: flow to surface

– Surface restrictions: chokes, lines, separators.

• Basically, anything that causes a restriction in the flow path decreases the rate and acts as “damage.”


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The first step…..

• For the purposes of this work, consider the flow connection between the reservoir and the wellbore as the primary but not the only area of damage.

• Now, is it “formation damage” or something else that causes the restriction?


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Some sources of the “damage” in the reservoir-wellbore “connection”

• Wetting phases (from injected or “lost” fluids)

• Debris plugging the pores of the rock

• Polymer waste from frac and drilling fluids

• Compacted particles from perforating

• Limited entry (too few perforations)

• Converging radial flow – wellbore too small

• Reservoir clay interactions with injected fluids

• Precipitation deposits (scale, paraffins, asphaltenes, salt, etc)

Note that not all are really formation damage – How do you identify the difference?


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Identification of Damage.

• How good are you at deductive reasoning? – Identifying the cause and source of damage is

detective work. • Look at the well performance before the problem

• Look at the flow path for potential restrictions

• Look to the players: – Flow path ways

– Fluids

– Pressures

– Flow rate


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Completion Efficiency

• What is it? – a measure of the effectiveness of a completion as measured against an ideal completion with no pressure drops.

• Pressure drops? – these are the restrictions, “damage”, heads, back-pressures, etc. that restrict the well’s production.


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The Effect of Damage on Production

Rate = (DP x k x h) / (141.2 mo bo s)

Where:

DP = differential pressure (drawdown due to skin)

k = reservoir permeability, md

h = height of zone, ft

mo = viscosity, cp

bo = reservoir vol factor

s = skin factor


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What changeable factors control production rate?

• Pressure drop – need maximum drawdown and minimum backpressures.

• Permeability - enhance or restore k? - yes

• Viscosity – can it be changed? – yes

• Skin – can it be made negative?

• These factors are where we start our stimulation design.


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Formation Damage

• Impact

• Causes

• Diagnosis

• Removal/Prevention?

• Basically, the severity of damage on production depends on the location, extent and type of the damage. A well can have significant deposits, fill and other problems that do not affect production.


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Impact of Damage on Production

• Look at Effect of Damage

• Type of Damage

• Severity of Plugging

• Depth of Damage

• Ability to Prevent/Remove/By-Pass


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Observations on Damage

• Shallow damage is the most common and makes the biggest impact on production.

• It takes a lot of damage to create large drops in production


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Effect of Depth and Extent of Damage on

Production

0

10

20

30

40

50

60

70

80

90

100

0 1 2 3

Radial Extent of Damage, m

% o

f o

rig

ina

l F

low

80% Damage

90% Damage

95% Damage


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Productivity and Skin Factor

• Q1/Qo = 7/(7+s)

Where:

Q1 = productivity of zone w/ skin, bpd

Qo = initial productivity of zone, bpd

s = skin factor, dimensionless


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Example

• Productivity for skins of -1, 5, 10 and 50 in a well with a undamaged (s=0) production capacity of 1000 bpd

• s = -1, Q1 = 1166 bpd

• s = 5, Q1 = 583 bpd

• s = 10, Q1 = 412 bpd

• s = 50, Q1 = 123 bpd


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Improvements

• For s = -1 (1166), -2 (1400), -3 (1750), and -4 (2333) …..

• Why have we seen better results in field?

– Fracturing past damage!


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Damage By-Pass

• For 1 well producing 1500 bpd with a skin of 50, what would frac with s=-2 yield?

• Qo = 12,214 bpd to get to s = 0

• Qimproved = 17,100 bpd at s = -2


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Causes

• “Pseudo” damage - very real effect, but no visible obstructions

• “Structural” damage


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“Pseudo” Damage

• Turbulence – high rate wells

– gas zones most affected

• Affected areas: – perfs (too few, too small)

– fracture (conductivity too low)

– tubing (tubing too small, too rough)

– surface (debottle necking needed)


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“Structural” Damage

• Tubular Deposits

– scale

– paraffin

– asphaltenes

– salt

– solids (fill)

– corrosion products


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Perforation Damage

• debris from perforating

• sand in perf tunnel - mixing?

• mud particles

• particles in injected fluids

• pressure drop induced deposits – scales

– asphaltenes

– paraffins


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Near Well Damage

• in-depth plugging by injected particles

• migrating fines

• water swellable clays

• water blocks, water sat. re-establishment

• polymer damage

• wetting by surfactants

• relative permeability problems

• matrix structure collapse


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Deeper Damage

• water blocks

• formation matrix structure collapse

• natural fracture closing


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Horizontal Well Formation Damage Theories

Zone of Invasion - Homogeneous Case

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Horizontal Well Formation Damage Theories

Zone of Invasion - Heterogeneous Case

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Clay like smectite may have a major effect on damage in some cases, none in others.

Narrow (<0.1” wide) natural fracture in dolomite formation


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Natural fractures, like this one from a downhole camera, dominate the permeability and ability to produce fluids from a formation.


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Wide, often cavernous fractures are present in some rocks, particularly limestones. These types of fractures can take whole mud, making cleanout and effective restoration of permeability nearly impossible. Air drilling is often the only practical approach to prevent excessive damage.

Mud Damage

• Common problems

– fines in the mud - physical plugging

– wetting of formation by mud surfactants

– Emulsions from formation fluids and both oil based mud (OBM) and water based mud (WBM)

– reactions with the formation fluids

– reaction with the formation clays


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One common and severe problem is the creation of a rigid sludge (extremely viscous emulsion) from mixing the heavier ranges of oil based muds (typically over 12 lb/gal) with some brines and most acids and/or spent acids. The emulsion is stabilized and its viscosity significantly increased by the cuttings in the oil based mud. The result is a nearly solid sludge when the oil based mud emulsifiers react with the low pH acid or high chloride brines. Testing with laboratory samples of OBM and acid will not predict this problem – it usually only occurs with field samples of the OBM (containing the cuttings) and the field samples of acid and spent acid, which contain iron. To prevent the problem, overflush OBM in the well with xylene or a suitable safe substitute and backflow before acidizing. Jetting the solvent assists in OBM removal. Apply the solvent before acidizing and use a mutual solvent in the acid To clean up a sludge, a strong OBM solvent (xylene is usually the best) is soaked for several hours before flowing back and then acidizing with acid and a suitable mutual solvent. Test on field samples.


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50/50 mixtures of a field sample of 14.5 lb/gal OBM and acid produced this solid sludge. The sample was stable for months. The well it was from was expected to come in a 12 mmscf/d but the flow was too small to measure after the well was perforated and acidized with straight 12%/3% HCl/HF. The well was treated with high quality xylene (soaked for 12 hours), before circulating the solvent and mud out of the well. After acidizing with HCL and a mutual solvent, the rate increased to 12 mmscf/d within 24 hours.


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Another sample of OBM that was treated with acid. In the sample on the left, a field sample of OBM was mixed directly with acid. The sample was stable for three months until discarded. In the sample in the left, the OBM was mixed with xylene and allowed to soak. The water in the OBM is the darker brown and the cuttings that have dropped out are at the bottom of the cylinder.

Deposits

• Paraffin - precipitated by: – loss of temperature in the tubing

– loss of light ends of the liquids such as ethanes, propanees and butanes by venting (pressure reduction)

– mixing with cool fluids (acids, frac, kill, etc) that reduce the oil temperature below the cloud point.

– flood front breakthrough that cool the oil (water or CO2 expansion) or by dry gas stripping that removes the light ends.


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Paraffin Location

• Deposit first appears at or near the surface

• Location moves downhole as field is produced and pressure drops reduce the light end concentrations)


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Paraffin Composition

• C18 to C60+ straight chain hydrocarbons

– C18 82F melting point





Paraffin deposits are never pure (pure paraffin is white).


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Deposition Location

• Top 5 joints of tubing

• Downstream of pressure drop

• Sea floor flow lines, wellheads, risers

• Gas breakout points

• On old paraffin deposits


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Paraffin Removal Methods • Hot Oiling – better for surface lines and the very top tubing joints.

Don’t expect to get heat deep in a well by circulating hot fluids – it’s a shell-and-tube heat exchanger.

• Solvents – good but need heat at the reaction site to be about 130oF (54oC) and add jetting or agitation to speed the removal process.

• Dispersants – water based with additives designed to disperse paraffin and hold it in suspension – works only where lab and field testing are coordinated to develop the best product and approach.

• Scraping – a short term fix - turns loose a lot of debris and leaves paraffin on the tubing, which serves as a growth site for more paraffin.

• Heating cables – good but often expensive to install and operate.

• Plastic rod guides – can be effective in rod pumped wells, if area of contact overlaps other guides.

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Paraffin Prevention Methods

• Crystal modifiers that prevent wax deposition. Need by careful selection and a consistent method of application.

• Heating cables – expensive?

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Asphaltene Sources

• Dispersions - kept suspended by micelles

• Soluble in oil (very limited)

• Additives to muds (gilsonites)


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World Wide Crude Oil Chemical Compositions (SARA)Hydroc arbon Numbe r

Field Asphaltene Re s in Aro matic Saturated Total of

(Wt %) (Wt %) (Wt %) (Wt %) (Wt %) Sample s

Athabas ca 23.3 28.6 32.1 15.9 48.1 15

Wabas ca 21.6 30.6 32.1 15.6 47.7 7

Peac e Rive r 48.7 23.2 20.5 7.6 28.1 3

Cold Lake 20.6 28 30.5 20.9 51.4 7

E. Ve ne zue la 12.6 32.4 36.4 18.6 55 5

Average on 22.9 30.6 30.4 16.1 46.5 46

46 Heavy Oils

PB HOT (EOA) 14.13 13.37 28.1 44.4 72.5

PB HOT (WOA) 10.38 20.42 28.23 40.97 69.2

W. Ven. (ne ar 13.2 12.9 38 35.9 73.9

HOT)

Co nve ntio nal 14.2 28.6 57.2 85.8 517

Normal Oils

PBU Normal 16.52 1.9 31.93 49.67 81.6

Oil 18.42

Schrader Bluff 4.9 29.0 24.7 41.5 66.2 158/25/2015 41


Asphaltenes

• precipitated by:

– CO2

– acid

– pH

– turbulence

– chemical shift that upsets micelle


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Asphaltene Stability

• Maltenes and resins form the micelle

• Asphaltene is the small platelet (35A) held in the middle of the micelle

• Dispersed platelets are not usually a problem although the oil may have a high viscosity

• When micelles are upset and broken, the platelets coagulate and form a mass.


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Scales

• calcium carbonate - upset driven

• calcium sulfate - mixing waters, upset, CO2

• barium sulfate - mixing waters, upset

• iron scales - corrosion, H2S, low pH, O2

• rarer scales - heavy brines


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Calcium carbonate scale, note the layers.


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An unusual form of calcite scale in the form of 1 to 2 mm diameter pellets where the calcite layers formed around a grain of silt and grew until the were too heavy to be suspended in a well with very strong water drive (E. Texas – circa 1975).

Scale Location

• at pressure drops - perfs, profiles

• water mixing points - leaks, flood breakthru

• outgassing points - hydrostatic sensitive

• shear points - pumps, perfs, chokes,

• gravel pack - formation interface


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In one case, scale was forming at the interface of a gravel pack and formation sand in an extremely fine and poorly sorted sand. The formation water was high in bicarbonate ion and calcium.

Scale Prediction

• Chemical models - require water analysis and well conditions

• Predictions are usually a “worst case” - this is where the “upset” factor comes in.

– added shear - increased drawdown, choke changes, etc.

– acidizing

– venting pressure


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Polymer Damage

• From: muds, pills, frac, carriers

• Stable? - for years

• location - depends on form polymer was in

– dispersed properly - surface to deep in formation

– in pills and mass - right in perfs


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Using dry polymer mixed into cold water, a crust of un-hydrated polymer formed and separated to the top of the tank. If this layer were drawn into the pump as the tank level dropped, the polymer mass could be displaced into the perfs and would be a significant barrier to production for years. Acid has little effect on this type of deposit.


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Even pre-mixed polymer has un-hydrated gels or “fish-eyes” after mixing with water. Shearing and filtering the gel through a six to eight gauge screen is the fastest way to remove the plugging debris. Incidentally – the sales representative said this would never happen with their product.

BP

Particles in the Fluid

• Solids from tanks, lines and fluids

• Severe problem, but often ignored


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Much of the debris that is pumped down a well comes from debris left in the water and mix tanks. If you think tank cleaning is too time consuming, you will live with the production decrease in your well.


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Will the same truck be used to haul mix water to your next job?


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Cartridge filters before use.


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Afterwards


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Downhole camera picture of a perforation completely filled with debris after displacing a few loads of dirty fluids. What is the cost in production?

Migrating Fines

• Sources

– kaolinite - not really that likely!

– Smectite - very likely, but clay is rare

– zeolites - common in younger sands, GOM area

– weathered feldspar - older sands

– micas, silts, drilling additives


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Area of Clays

Sand Grain 0.000015 m2/g

Kaolinite 22

Smectite 82

Illite 113

Chlorite 60

The areas for clay are highly variable and depends on deposit configuration.


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Many chemical reactions are surface area dependant. The more area, the faster the reaction.


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The surface area of clay compared to the volume of reactive fluid in contact drives the reaction.


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Fibrous or spider web Illite is actually low reactivity in most cases but serves as a trap for migrating fines.

Migrating Clay Catalysts

• water salinity changes

• surfactants and mutual solvents

• overburden increases

• wettability changes


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Other “Migrators”

• The following are dwarfs compared to the problems with smectite.

– Zeolites - (common in young marine sands) - clintoptolite

– “Weathered” or altered feldspars

– one very rare form of chlorite

– a few loosely attached kaolinite bundles

– broken illites (and mixed layers)

– silt and other grains (<5 microns)


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Is Clay a Problem?

• Usually not.

• Very few formations are water sensitive to a degree that will affect production.

• Clay is a problem when it is in contact with a reactive fluid and the effects or the reaction significantly lower permeability (30% or more?).


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Microporosity

• Refers to the very small (non flowable?) volume between clay platelets that can trap and hold water.

• May explain non recovery or slow recovery of load fluids

• May explain errors in log calculations involving high Sw prediction and subsequent dry hydrocarbon flows.


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In some forms, particularly the weathered and loosely attached forms, kaolinite has been known to migrate, but very little reactivity has been seen in most instances that have been investigated by flow.

Chlorite is usually strongly attached and most forms of the mineral are non reactive with water. It does contain ferrous iron, but tests have shown only slow reactivity with the concentrations and volumes of acid that are likely to come in contact with Chlorite in the pores of a rock. Rare examples are known of free standing chlorite rims – these are unstable and can break during flow.

Kaolinite (left) and Chlorite (right) are two common clays found in pore throats. Reactivity is low, but some caution is needed.

Migrating???

• Because fines are there means nothing

• What turns the fines loose? – Velocity - unlikely

– salinity change in fluids - very common

– wetting change

– cleaning agents

– solvents (and mutual solvents)

– shock loads (perforating for example)


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Damage from clays?

• The potential for clay damage depends on clay type, form, location and presence of reactive fluids.

• In hundreds of sensitivity tests, most cores containing clays are not highly sensitive (>30% permeability reduction) to changes in fluid salinity.

• The question is how representative the clays in the core being tested are to the higher permeability sections of the reservoir.



Preventing Clay Damage

• Unless the clays in the higher permeability sections of the rock are sensitive to the fluids that will actually contact them, any type of clay control treatment will likely be unnecessary and potentially damaging.

• When clay damage is possible, test for the best fluid and monitor performance in the field.

• In practice, fluids with 2% to 3% KCl are common. These may be effective, unnecessary or ineffective – depending on the clay.

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Removing Clay Damage

• Shallow – (to a depth of about 6 inches or 15 cm), 1%HF and 9%HF may be effective in some cases.

• Deeper damage usually requires fracturing to bypass the damage.



Emulsions

• Multiple phases that do not separate quickly.

• Creating an emulsion generally requires an energy source.

• If oil and water do not separate quickly, then look for the stabilizing mechanism – Surfactant – either added or natural

– Silt from the formation or from drilling

– Viscosity – high viscosity emulsions often require thinning to break.

– Charge – even weak electric charges can be stabilizers but are more common in water-in-gas emulsions (clouds).


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Increasing internal fraction of the “emulsion”

52% 74% 96%

Viscosity

Widely Dispersed Contact

Deformation

Inverted

Changes in Fluid Viscosity with Change in Internal Phase of Dispersed or Emulsified Flow


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Energy Sources

• lift system

• gas breakout

• shear at any point in the well

• choke

• gas expansion


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Common Stabilizers in Oil Production

• surfactant (film stiffeners)

• solids (silt, rust, wax, scale, cuttings)

• emulsion or component viscosity (prevents particle or droplet contact)


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Iron Problems

• Precipitates - usually with acid spending - not typically a problem

• Sludges - more of a problem than we realize - can be controlled with iron reducer and anti-sludge

• Solid particles - multiple problems


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Bacterial Problems

• Aerobic - lives only w/ oxygen

• Anerobic - lives w/o oxygen

• Facultative - w/ or w/o, but better one way

• Problems Caused – eats polymer

– causes formation damage and corrosion

– SRBs may sour reservoir


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Bacterial Populations

• Free Floating - easy to kill, not that plentiful

• Sessile (attached colonies)

– 100,000 x free floating populations,

– very difficult to kill,

– live in densly matter layers

– protected by slime layer

– highly accelerated corrosion underneath


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Bacterial Sources

• Some small populations dormant in reservoir? Probably.

• drinking water < 1000 cells/ml

• sea water - high populations of SRBs

• brackish waters - very high populations

• river/pond - moderate to high populations

• concentrated brines - very low concentrations

• acids - very low to almost none


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Bacterial Control

• Acids - kills free floating, little effect on sessile colonies

• Bactericides - (same as acid) kills free floating, little effect on sessile colonies

• Bleaches and Chlorine - (3% to 8%) strips slime layer, dissolves cell wall, can’t remove biomass. Watch corrosion!

• Bleach, followed by acid - good removal history.


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Relative Permeability Damage Mechanisms

• Wetting – surface wetting

• Water blocks – trapping water – some effects of capillary pressure in small pores in wells with low differential pressures.

• Condensate banking and retrograde condensate – a phase drop-out that decreases perm to a single fluid.

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Controlling Relative Permeability Mechanisms

• Water blocks – reduce the interfacial and surface tension of the intruding fluid and re-establish the connate fluid saturation.

• Wetting – can modify by cleaning, but the natural surfactants ultimately will define the wetting of the rock.

• Condensate drop-out – increase the flow area by fracturing to negate the effects of lowing the permeability of the formation.



formation damage

Documents

damage shallow damage

impact of damage

severity of damage

area of damage

source of damage

identification of damage

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production rate