Formation Damage Examples

7/30/2019 Formation Damage Examples

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Formation Damage

Examples

Scale

Emulsions

Paraffin

3/14/2009 1George E. King EngineeringGEKEngineering.com


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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 asdamage.



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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 youidentify the difference?



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Identification of Damage.

How good are you at deductive reasoning?

Identifying the cause and source of damage isdetective 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 wells production.



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The Effect of Damage on Production

Rate = (P x k x h) / (141.2 o o s)

Where:

P = differential pressure (drawdown due to skin)k = reservoir permeability, md

h = height of zone, ft

o = viscosity, cpo = reservoir vol factors = skin factor



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What changeable factors control

production rate?

Pressure drop need maximum drawdownand 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 ourstimulation design.



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Formation Damage

Impact

Causes

Diagnosis

Removal/Prevention?

Basically, the severity of damage on productiondepends on the location, extent and type of the

damage. A well can have significant deposits, filland 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 o f Damage, m

%o

foriginalFlow

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

TheoriesZone of Invasion - Homogeneous Case



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i l ll i


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Horizontal Well Formation Damage

TheoriesZone of Invasion - Heterogeneous Case


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


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


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Narrow (


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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 onlypractical approach to prevent excessive damage.


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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


One common and severe problem is the creation of a


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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 oilbased 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 amutual 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 to12 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 directlywith 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 thedarker brown and the cuttings that

have dropped out are at the bottom of

the cylinder.


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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 (pressurereduction)

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

flood front breakthrough that cool the oil (wateror CO2 expansion) or by dry gas stripping thatremoves 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


C32 158F melting point C42 181F 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.

Dont expect to get heat deep in a well by circulating hot fluids itsa shell-and-tube heat exchanger.

Solvents good but need heat at the reaction site to be about130oF (54oC) and add jetting or agitation to speed the removalprocess.

Dispersants water based with additives designed to disperseparaffin and hold it in suspension works only where lab and fieldtesting are coordinated to develop the best product and approach.

Scraping a short term fix - turns loose a lot of debris and leavesparaffin 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 ofcontact 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)Hydrocarbon Number

Field As phaltene Re s in Aro matic Saturated Total of

(Wt %) (Wt %) (Wt %) (Wt %) (Wt %) Samples

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

Peace River 48.7 23.2 20.5 7.6 28.1 3

Cold Lake 20.6 28 30.5 20.9 51.4 7

E. Vene zue la 12.6 32.4 36.4 18.6 55 5

Average on 22.9 30.6 30.4 16.1 46.5 4646 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 nventio nal 14.2 28.6 57.2 85.8 517Normal 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 66.2 153/14/2009 41George E. King Engineering

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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 inthe middle of the micelle

Dispersed platelets are not usually a problemalthough 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


Calcium carbonate scale, note the layers.


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An unusual form of calcite scale in the


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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).


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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 inbicarbonate ion and calcium.


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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 polymerformed and

separated to the

top of the tank. If

this layer were

drawn into the

pump as the tanklevel dropped, the

polymer mass could

be displaced into

the perfs and would

be a significant

barrier toproduction for

years. Acid has

little effect on this

type of deposit.

Even pre-mixed polymer has un-hydrated gels or fish-eyes after mixing

ith t Sh i d filt i th l th h i t i ht


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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


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Particles in the Fluid

Solids from tanks, lines and fluids

Severe problem, but often ignored


h f h d b


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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 inyour well.

Will the same


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truck be used

to haul mix

water to yournext job?


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Cartridge filters before use.


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Afterwards


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Downhole camera


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picture of a perforation

completely filled with

debris after displacing a

few loads of dirty fluids.What is the cost in

production?


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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 ondeposit configuration.


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Many chemical

reactions are

surface areadependant. 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


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Illite is actually low

reactivity in most cases

but serves as a trap for

migrating fines.


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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 (


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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 trapand hold water.

May explain non recovery or slow recovery ofload fluids

May explain errors in log calculations involvinghigh Sw prediction and subsequent dryhydrocarbon flows.


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In some forms,

particularly the Chl i i llKaolinite (left) and Chlorite (right) are


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particularly the

weathered and loosely

attached forms,

kaolinite has been

known to migrate, butvery 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. Itdoes contain ferrous

iron, but tests have

shown only slow

reactivity with the

concentrations and

volumes of acid thatare 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.

two common clays found in pore

throats. Reactivity is low, but some

caution is needed.


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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 claytype, form, location and presence of reactivefluids.

In hundreds of sensitivity tests, most corescontaining clays are not highly sensitive (>30%permeability reduction) to changes in fluidsalinity.

The question is how representative the clays inthe core being tested are to the higherpermeability sections of the reservoir.

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Preventing Clay Damage

Unless the clays in the higher permeabilitysections of the rock are sensitive to the fluids thatwill actually contact them, any type of claycontrol treatment will likely be unnecessary and

potentially damaging.

When clay damage is possible, test for the bestfluid and monitor performance in the field.

In practice, fluids with 2% to 3% KCl are common.These may be effective, unnecessary orineffective 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 tobypass the damage.

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

Flow


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Increasing internal fraction of the emulsion

52% 74% 96%

Viscosity

WidelyDispersed

Contact

Deformation

Inverted

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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bl


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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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B i l P bl


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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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B t i l P l ti


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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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B t i l S


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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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B t i l C t l


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Bacterial Control

Acids - kills free floating, little effect on sessilecolonies

Bactericides - (same as acid) kills free floating, little

effect on sessile colonies Bleaches and Chlorine - (3% to 8%) strips slime layer,

dissolves cell wall, cant remove biomass. Watch

corrosion!

Bleach, followed by acid - good removal history.

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Relative Permeability Damage


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y g

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


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g y

Mechanisms

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

Wetting can modify by cleaning, but thenatural surfactants ultimately will define thewetting of the rock.

Condensate drop-out increase the flow area

by fracturing to negate the effects of lowingthe permeability of the formation.

Documents

Formation Damage Examples