1) Sistemas de Producción 5- Skin Damage

8/11/2019 1) Sistemas de Produccin 5- Skin Damage

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Formation Damage

Types of Damages and Origins, Skin Factor and

Productivity Index, Flow Efficiency


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2

Origin of Formation Damage

Formation damage Types Origin Location

Diagnosis

Removal and Prevention Methods Chemistry


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3

Formation Damage Characterization

Fines Migration

Swelling Clays

Scale Deposits

Organic Deposits Paraffins Asphaltenes

Mixed Deposits

Bacteria

Induced Particles Solids LCM/Kill Fluids

PrecipitatesOil Based Mud

Emulsion Block

Wettability Changes

Water Block


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Swelling Clays: Smectite


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5

Migrating Clays: Kaolinite


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FINES MIGRATION MECHANISM

fineswetting phase

non wetting phase

non wetting phase

non wetting phase


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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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Scale

Inorganic mineral deposits.

Formed due to supersaturation at wellbore conditions orcommingling of incompatible fluids.

Form in the plumbing system of the well, in theperforations/near wellbore formation.


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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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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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Scales Prediction

Chemical models -require water analysis andwell conditions

Predictions are usually a worst case-this iswhere the upset factor comes in. added shear -increased drawdown, choke

changes, etc. acidizing venting pressure

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Drilling Fluid Damage

Mud filtrateinvasion


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RDF (STARDRILL) Filter Cake

Filter cake Formation

Drilling Damage

Filter cake should prevent extensivedamage to formation during drilling

Low permeability (~ 0.001md) filter cakemay be damaging during production

formation permeability may be impaired potential plugging of screen/ gravel pack

Openhole completions do not haveperforations or fractures to bypass anydamage

Filter cake removal maybe a necessity!


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Drilling Damage

Drilling Mud Solids Particle Size vs. Pore

Size/Fissures Filtration - 3 inches

Poor Mud Cake Overbalance

Drilling Mud Filtrate Formation Sensitivity (pH,

salinity, scale) High Penetration Capillarity Fines Dispersion Additive Residues Cooling

Oil Based Muds High Solids Oil Invasion/Relative Permeability Cationic Emulsifiers


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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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Perforations

Debris

Compacted Zone

R a

d i a l D

i s t a n c e

( m m

)


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Completion Fluids Damage

Suspended Solids Polymer Residue

Fluid Loss Control Formation Sensitivity Clays Wettability Scales

A (2.5 ppm)

C (94 ppm)

D (436 ppm)

P e r m e a

b i l i t y

( m d )

Volume Injected (gal/perf)

500

100

50

100 0.02 0.04 0.06 0.08 0.10

(A) Bay Water FilteredThrough 2um Cotton Filer

(B) Bay Water

Through 5um Cotton Filter

(C) Produced Water Untreated

(D) Bay Water Untreated

B (26 ppm)


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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 withlow differential pressures.

Condensate banking and retrogradecondensate a phase drop-out that decreasesperm to a single fluid.

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Water Block Damage

A reduction in effective orrelative permeability to oil due toincreased water saturation inthe near wellbore region.

Favored by pore-lining clayminerals (Illite)

Treatment Reduction ofinterfacial tension usingsurfactants/alcohol's in acidcarrier

1 1

Kro Krw

0

0 1Swc 1-S or Sw

Water Wet

Oil Wet

KroKrw


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Controlling Relative Permeability Mechanisms

Water blocks reduce the interfacial and surfacetension of the intruding fluid and re-establish theconnate fluid saturation.

Wetting can modify by cleaning, but the naturalsurfactants ultimately will define the wetting of therock.

Condensate drop-out increase the flow area byfracturing to negate the effects of lowing thepermeability of the formation.

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Damage due to Production

In an oil reservoir, pressure nearwell may be below bubblepoint,allowing free gas which reduceseffective permeability to oil nearwellbore.

In a retrograde gas condensatereservoir, pressure near well maybe below dewpoint, allowing animmobile condensate ring to buildup, which reduces effectivepermeability to gas near wellbore.

p < p bp > p b

The main Production damage is due to Fines Migration


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Damage Quantification

The Damage is quantified by the Skin Factor and theProductivity Index


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Reservoir Model of Skin Effect

Bulkformation

h

r w

ka

r a

Alteredzone


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Reservoir Pressure Profile

Distance from center of wellbore, ft

500

1000

1500

2000

1 10 100 1000 10000

P r e s s u r e ,

p s

i

p s


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Skin and Pressure Drawdown

k = Permeability, md

h = Height, ftq = Production, STB/DB = Oil Volume Factor, bbl/STBDps = Pressure drawdown, psi

= Oil Viscosity, cp


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Radial Production and Skin

q = Production, STB/Dk = Permeability, milidarcyh = Height, ftP

r = Reservoir Pressure, psi

Pwf = Bottomhole FlowingPressure, psi

= Oil Viscosity, cpBO = Oil Volume Factor, bbl/STBln = natural logaritmr e = drainage radius, ftr w = wellbore radius, fts = skin factor

(Darcys Law)

s

r r

lnB141.2

PPhk q

w

eO

wf r


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Example

27

K 200mdPr 3200psiPwf 1500psih 20ftUo 2cpBo 1,18re 1000ft

rw 0,5ft

Determine the productivity for skins of -1, 5, 10 and 50 in a well with aundamaged (s=0).


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Skin Factor and Properties of the Altered Zone

If ka < k (damage), skin ispositive.

If ka > k (stimulation), skin is

negative.If ka = k, skin is 0.


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Effective Wellbore Radius


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Example

Calculate the skin factor resulting from the invasion of the drillinfluid to a radius of 2 feet. The permeability of the skin zone iestimated at 20 md as compared with the unaffected formationpermeability of 60 md. The wellbore radius is 0.25 ft.

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Geometric Skin Converging Flow toPerforations

When a cased wellbore is perforated, the fluid must converge to theperforations to enter the wellbore. If the shot spacing is too large, thisconverging flow results in a positive apparent skin factor. This effectincreases as the vertical permeability decreases, and decreases as the

shot density increases.


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Geometric Skin - Partial Penetration

When a well is completed through only a portion of the net pay interval,the fluid must converge to flow through a smaller completed interval. Thisconverging flow also results in a positive apparent skin factor. This effectincreases as the vertical permeability decreases and decreases as theperforated interval as a fraction of the total interval increases.

h

hp


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33

Partial Penetration

hp

h t

h 1

Sd = Skin due to formation damage

Sp = Geometric Skin due to perforations


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Geometric Skin - Deviated Wellbore

sech

h

S < 0


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Geometric Skin - Well With Hydraulic Fracture

r w

rw

sww er r '

For example,

r w = 0.4 fts = -3

r w = 8 ft


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Completion Skin

r dp

Lp

kR

kdp

kd

r p

r d

r w

After McLeod, JPT (Jan. 1983) p. 32.

s p- geometric skin due to converging flow toperforations

s d - skin due to formation damages dp - perforation damage skinkd - permeability of damaged zone around wellbore,

mdkdp - permeability of damaged zone around

perforation tunnels, md

kR - reservoir permeability, mdLp - length of perforation tunnel, ftn - number of perforationsh - formation thickness, ftr d - radius of damaged zone around wellbore, ftr dp - radius of damaged zone around perforation

tunnel, ftr p - radius of perforation tunnel, ftr w - wellbore radius, ft


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Gravel Pack Skin

Lg

Cement

Gravel

s gp - skin factor due to Darcy flow through gravelpackh - net pay thicknesskgp - permeability of gravel pack gravel, mdkR - reservoir permeability, mdLg - length of flow path through gravel pack, ftn - number of perforations openr p - radius of perforation tunnel, ft

Does not include effects of non-Darcyflow (high-rate gas wells)


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Productivity Index

The productivity index is often used to predict how changesin average pressure or flowing bottomhole pressure pwf willaffect the flow rate q.

The productivity index is affected by Reservoir quality (permeability) Skin factor

l ff


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Flow Efficiency

We can express the degree of damage on stimulation with theflow efficiency.For a well with neither damage nor stimulation, Eff = 1.For a damaged well, Eff < 1For a stimulated well, Eff > 1

wf

swf

ideal

actualff pp

pppJJ

E

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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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 almostnone

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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, cant remove biomass. Watch corrosion!

Bleach, followed by acid -good removal history.

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1) Sistemas de Producción 5- Skin Damage