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Matrix Treatment Design
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PRESENTATION SUMMARY
EP Matrix Treatment Design
Preamble
Matrix design methodology
Candidate selection
Nature and location of damage
Fluid and additives
Placement strategy
Practical considerations
Equipments expected onlocation
Assess profitability
Evaluation of the job
Matrix treatment design keypoints
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PreambleFormation damage
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Definition
DEFINITION
Formation damageis any impairmentof reservoir permeabilityaround the wellbore
It is a consequence of the
drilling, completion, workover, production, injection orstimulation operations
Productivity or Injectivity are
adversely affected
ONLY TWO TYPES!!!
Although there are a numberof damage mechanisms,
there are only two ways in
which near wellbore
permeability can be reduced:
1)Physical reduction in
pore/pore throat size
2)Relative permeability
reduction
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Typesofdamages
EP Matrix Treatment Design
Invasion of Fluids and/or Solids Drilling Mud
Cement, frac fluids, acid treatments
Plugged Perforations Perforation Compaction
Fines Migration
Deposits Scales: organic, inorganic
Corrosion Bacterial slime
Unfiltered solids (injection wells)
Fluid Problems Emulsions
Water Production Clay swelling Wettability changes
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Originsofformationdamage
EP Matrix Treatment Design
PROCESS TYPE PHYSICAL PORE SIZE
REDUCTION
RELATIVE PERMEABILITY
REDUCTION
FLUID-ROCK
INTERACTION
Fines migration
Clay swelling Solids
invasion
Adsorption / precipitation of
large molecules (polymers)
Wettability change due to
surfactant adsorption
FLUID-FLUID
INTERACTION
Scale
Emulsion
mud(sludge)
Fluid saturation change
Fluid blocking
(water block, gas block)
PRESSURE /TEMPERATURE
REDUCTION
Gas breakthrough
Condensate banking
Water coningMECHANICAL PROCESS
(stress induced)Permeability reduction
Perforation plugging
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Types of Mineral SCALES
Scale:
Adhering mass of solid formed on a surface incontact with waterhard and impermeable.Carbonate scale: CaCO3, FeCO3 / Sulfate scale:CaSO4, BaSO4, SrSO4 /Chloride scale: NaCl,...
Sludge:
Mass of loose precipitated solids that can form in alocation and settle downstream where the flowvelocity is less.
Production Tubing Scale
Reservoir Scale
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Darcys lawoil wellvertical
S Q = Oil flow rate, stb/d
K= Permeability, md
H = Reservoir thickness, ft
Pe = Reservoir pressure, psi
Pwf = Bottom hole flowing pressure, psi
o = Oil viscosity, cp
Bo = Formation volume factor, resbbls/stb
K H Pe P
rwr ln
e
o
wf
B
Q
141 .2 0
ksDamaged
Zone
EP Matrix Treatment Design
kf
Bulk
Formation
H
rw
re
rS
re = Reservoir drainage radius, ft
rw = Wellbore radius, ft
rs = Damaged zone radius
S = Skin factor
k d f
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Skindefinition
EP Matrix Treatment Design
S total skin is a dimensionless term To take into account the additional pressure drop in the
wellbore area
Result from formation damage and other factors
Skin effect is positive if an additional pressure drop is present
Skin effect is negative if the actual Pwf is higher than the idealPwf
Ski d i bili d i
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Skindamageequation:permeabilityreduction
Skin effect is intended to describe
alterations in the near wellbore zone
Nature of radial flow is that pressure
difference increases with logarithm of
distance: the same pressure is consumed
within the 1st foot as within the next ten
,hundred,thereforeconceivable that largest
portion of total pressure gradient may be
consumed within the near well bore zone.
Ideal:
Q=Kf*H*(PsPwfideal)/141.2*B**ln(rs/rw)
If damaged:
Q=Ks*H*(PsPwreal)/141.2*B**ln(rs/rw)
PwfidealPwfreal=Q*B**S/(2*pi*H*K)
re
EP Matrix Treatment Design
rs
rw
kf
ks
Ski d ti bilit d ti
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Skindamageequation:permeabilityreduction
re
rs
rw
kf
ks For Rs = 4 ftR = 6 inches (0.5 ft)wKf = 100 md
If Ks = 10 md
S = ?
S =Kf Ks
Ks
EP Matrix Treatment Design
X (ln (rs/rw)
Ski d ti bilit i t
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ksDamaged
Zone
kf
Bulk
Formation
h
rw
re
rS
Skindamageequation:permeabilityimprovement
For Rs = 4 ftRw = 6 inches (0.5 ft)
Kf = 100 md
If Ks = 1000 md
S = ?
S =Kf Ks
Ks
EP Matrix Treatment Design
X (ln (rs/rw)
Skin effect on vertical wells
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Skineffectonverticalwells
+ 100%
50%
PI S 0
PIwith skinEfficiencyCompletion
CE = ln(re/rw) / (ln(re/rw) + S). As ln(re/rw) often ranges between 7 and 9.
EP Matrix Treatment Design
Skin
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Skin
EP Matrix Treatment Design
The total Skin (ST) is the combination of formation damage and pseudoskins. It isthe total skin value that is obtained directly from a welltest analysis.
Formation Damage:
S > 0
S = 0
Mathematically defined as an infinitely thin zone that creates a steadystate
pressure drop at the sand face.
Damaged Formation
Neither damaged nor stimulated
S < 0 Stimulated formation
Pseudo Skin:
Includes situations such as fractures, partial penetration, turbulence, andfissures.
The Formation Damage is the only type that can be removed by stimulation.
Near well bore damage
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Near well bore damage has
the greatest impact
Severe but shallow damagecan have the same effect aslesser deeper damage
How can we tell which type ofdamage we have if theresultant production loss is thesame ?
We can not, we can only lookat the well records andhypothesis
Nearwellboredamage
001
09
08
07
wolfla 0n 6igiro 0f 5otne 0cr 4eP
03
02
01
0
1 2 3 4 5 6 7 8 9 10
Ke = 50mdRe = 1000ftRw = 0.354ft (8 1/2'' OH)
With :
Radial extent of damaged zone (ft)
100%
80%
40%
60%
20%
Retained permeability
30%
50%
Comple
tionefficiency
20%
10%
Ks/Kf =
0.50
K /K =s f0.30
Ks/K
f=
0.20Ks/Kf =
EP Matrix Treatment Design
0.10
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Skin in horizontal well
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Skininhorizontalwell
125%
100%
200%
- 4 0 5 10 15 20Skin
Horizontal well
Vertical well
Stimulation has generally more impacton vertical wells
Completion
Efficiency
EP Matrix Treatment Design
Areas of damage
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Areasofdamage
Scales
Organic deposits
Silicates, Aluminosilicates
Emulsion
Water block
Wettability change
Tubing Gravel Pack Perforations Formation
no
no no no
no no no
Formation
EP Matrix Treatment Design
PerforationsGravel Pack
Tubing
Sources of formation damage
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Sourcesofformationdamage
EP Matrix Treatment Design
Drilling & Completion
Cementing Perforating
Stimulation
Gravel packing
Workover
Production
Injection operations
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IMATRIX DESIGN METHODOLY
EP Matrix Treatment Design
Matrix treatment design methodology
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A typical design for a stimulation job should involve the following major
steps
Candidate Selection
Establish Nature and Location of Damage
Treating fluid / Additive Selection
Determine Pressure / Injection Rate
Establish Fluid Volume
Determine Placement strategy
Define Shutin / Cleanup Stages
Assess Profitability through Productivity Improvement4EP Matrix Treatment Design
Matrixtreatmentdesignmethodology
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IICANDIDATE SELECTION
EP Matrix Treatment Design
Candidateselection
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Why stimulate
the well ?Other
issues
Improve
Production
What caused
the problem ?
Drill mud
invasion
Cement
losses
Perforation
damage
Formationcollapse
Bad
stimulation
fluids
Incompatible
completionfluid
Scales
EP Matrix Treatment Design
Candidateselection
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EP Matrix Treatment Design
Other times it may not be very obvious such as when:
Water cut has increased
The formation pressure has declined to the point the reservoir cannotsustain production
the tubular size is inappropriate
Main possible damage causes to check:
on a new well due to mud losses or cement losses
From perforating debris on a new or existing well
in an old well possibly due to fluid incompatibility and scale formation
Large pressure draw downs that might have caused formation collapse(sand control)
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IIINATURE AND LOCATION
OF DAMAGE
EP Matrix Treatment Design
Matrixtreatmentdesignmethodology
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DIAGNOSIS to establish Nature and Location of damage
KEY POINTS
well data/history
laboratory test
EP Matrix Treatment Design
Tubing Gravel
pack
Perforations Formation
Scales possible possible possible possible
Organic
deposits
possible possible possible possible
Silicates
Aluminosili
cates
possible possible possible
Emulsion possible posible possible
Waterblock possible
Wettability
change
possible
WellCandidateSelectionProcess
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Matrix acidcandidate?
Frac acidcandidate?
K>10md
oil well
K>1md
gas well
K
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IVFLUID AND ADDITIVES
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Matrixtreatmentdesignmethodology
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Calcite
Limestone
Establish fluid volume and acid (HCl) strength
EP Matrix Treatment Design
Depend on the selectedtreatment and not on theformation characteristics
Acid Wash: 10 20 gal/ft
Stimulation: 5070 gal/ft (1 1.5m/ perforated meter (HCl)
Acid strength: 15% in all cases
exceptLow temperature ...
Matrixtreatmentdesignmethodology
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Treating fluid / Additive Selection
1.Inhibitors
2.Surfactants
3.Diverters
4.Mutual solvents
5.Iron control
6.Clay control
7.Non emulsifying
8.Antisludge agents9.Scale control
agents
Select the proper
formulation of treating fluid
that will remove the damage
without damaging the rock through
formation of secondary precipitates,sludge...
This may require laboratory tests.
3EP Matrix Treatment Design
Matrixtreatmentdesignmethodology
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A chemical added to acid to reducethe corrosion of tubulars
A corrosion inhibitor forms a barrierat a cathodic or anodic surface whichinterferes with electrochemicalreactions
Inhibitor effectiveness is a functionof its ability to form and maintain afilm on the steel surface.
Acceptable metal loss: 0.02lb/ft with t up to 250F
0.05lb/ft with t up to 250F
Inhibitor Effectiveness
Temperature and Pressure
Flow Velocity
Volume/Area Ratio
Concentration and Type of otherAdditives
Concentration of inhibitor
Concentration and Type of acid
Metal type
Laboratory evaluations
Corrosion Inhibitor
5EP Matrix Treatment Design
Matrixtreatmentdesignmethodology
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M+
X-
(pH)
-
+
+
-
Hydrophilic Hydrophobic (Lipophillic)
Anionic
Cationic
Non-Ionic
Amphoteric
Chemicals containing both an oil soluble and water solublegroups with the ability to alter liquidliquid or gasliquid interfacialproperties. They thus make it possible to solubilize two immiscible
phases.
water wet oil wet
3EP Matrix Treatment Design
Anionic types tend to waterwetsand.
Cationic types tend to oilwet sand.
Anionic types tend to oilwet carbonate.
Cationic types tend to waterwet carb.
Anionic types tend to emulsify oilinwater
and break waterinoil emulsions
Cationic types tend to emulsify waterinoiland break oilinwater emulsions.
Anionic types tend to disperse clays inwater.
Cationic types tend to flocculate clays inwater and disperse them in oil.
Anionic and cationic types are notcompatible with each other.
Surfactant
The wrong type of surfactant or the wrong
concentration , may cause formation
damage.
Matrixtreatmentdesignmethodology
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Train
Mutual solvent
This term means the chemical issoluble in both oil and water
Type EGMBE (Ethylene Glycol MonoButyl Ether)
Use mainly in oil bearing sands
Reduces pore water saturation
Reduces interfacial tension
Solubilises or removes oil and oilwetting chemicals from mineral surfacesthat tend to be naturally water wet
Enhances the action of water wettingchemicals
Reduces the absorption of chemicalsand oil on mineral surfaces
Emulsion preventing
Allows more rapid cleanup
3EP Matrix Treatment Design
Matrixtreatmentdesignmethodology
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Train
Must always be used in acid
Iron control
Chemical which prevents ironhydroxide precipitate
Avoid emulsions with oil(asphaltenes)..
Avoid very strong precipitates
Iron(Fe) dissolved during an acidizing
treatment can exist in either the Fe3+ or
Fe2+ oxidation state. Upon spending of
the acid, Fe3+ will start to precipitate at a
Ph of 2.2. At 3.2 all the dissolved Fe3+ will
be precipitated. Fe2+ hydroxide will not
precipitate below a Ph value of of 7.7
3EP Matrix Treatment Design
Matrixtreatmentdesignmethodology
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Train
Iron control
3EP Matrix Treatment Design
Matrixtreatmentdesignmethodology
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Clay control agent
Formation damage can result fromthe dispersion , migration or swelling
of clay particles.
Clays stabilizers eliminate thisproblem in most cores.
Laboratory test
Foaming agent
Used as a mechanism to divert
Boost the flow back
Improved matrix leak off control
(return production of spent acid by
reducing fluid gravity and surface
tension of the fluids injected)
3EP Matrix Treatment Design
Matrixtreatmentdesignmethodology
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Nonemulsifying anti sludge agents
Avoid emulsion problems betweenacid, used acid and oil in place
Emulsifying agents include:
Asphaltenes
Formation fines
Laboratory test
Use to lower the friction pressure ofungelled fluids in high rate job
Used during matrix acidizing through CT
Suppress turbulence of the fluid
Increasing flow rate
Friction reducerAction of friction reducers
(at a given flow rate)
3EP Matrix Treatment Design
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VPLACEMENT STRATEGY
6EP Matrix Treatment Design
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Matrixtreatmentdesignmethodology
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Define shutin/cleanup stage
a bad cleanup can increase the damage near the
wellbore
precipitatesemulsion
scales
fines
4EP Matrix Treatment Design
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VIPRACTICAL CONSIDERATIONS
4EP Matrix Treatment Design
Matrixtreatmentdesignmethodology
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Determine pumping hydraulic parameters
Maximum Injection Rate
4.917x106 khFGxd dPs p
Rs
RwB Ln
Q max
S
q = injection rate (bpm)
k = undamaged permeability (md)
h = net height of the formation (ft)
= viscosity of the injected fluid (cp)
p = pore pressure (psi)
Rs = drainage radius (ft)
Rw = wellbore radius (ft)
B = formation volume factor
dPs = safety pressure (200 500 psi)
D:DEPTH VERTICAL FT
KEY POINTS
Qmax should not be exceeded
during the treatment.
4EP Matrix Treatment Design
Whatistheexpectedrate?
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Injectivity index can be calculated based on Darcy sLaw Rule of thumb Skin prior acid : + 20
Skin after acid : 4 Pressure of the treatment depends on Friction in the tubing / on Frac
pressure / on reservoir pressure
Rate will be maximised if possible.max 4 .917x10 khFGxd dPs p
Rs
RwB Ln
6
S
Q
4EP Matrix Treatment Design
Matrixtreatmentdesignmethodology
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Determine pumping hydraulic parameters below frac
pressure
Maximum Surface Pressure
Ps = FG x d Ph + Pf dPs
Ps = surface pressure (psi)
FG = fracturing gradient (psi/ft)
d = vertical depth (ft)
Ph = hydrostatic Pressure (psi)
Pf = friction pressure (psi)
dPs= safety pressure (200500psi)
If the frac gradient is not known,
it can be estimated by adding 0.25psi/ft
4EP Matrix Treatment Design
to the BHSP gradient.
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Expectedequipmentonlocation
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CT required to spot the acid ?
4EP Matrix Treatment Design
Pretreatmentchecklist...
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7EP Matrix Treatment Design
What should you do on location prior a treatment
Safety issues (Escape line, shower, PPE, fire hose)
Contengency plan ready (what if there is a leak ?)
Review of treatment parameters
Review of equipment calibration
QAQC of fluid mixed on location Review of pumping program
RequiredEquipment
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Pumps: 8 x HT 400, 4800 HP
Storage: 76,000 gal
Pressure: Maxi 5000psi (Wellhead)
Blending: Max Rate @ 60 bpm
Monitoring
BHP w: Down Hole Gauge, real time
Pumping Rate
4EP Matrix Treatment Design
ExpectedEquipmentonlocation
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4EP Matrix Treatment Design
RequiredRigup
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T ubin g pres su re 1 a nd 2
3" w he el v alve2" or 1 " b all va lve
C hec k v alve
Cem en t Un it
Ac id L ineRig P u m p s
An nu lu s M o n ito ring
Rig P u m p s
F low line
E m erge n cy B lee d O ff line.
O n ly to b e u sed if a cid in th e
lin e
P1
Flow line
Ac id L ine
Swab valve
W ing V a lve / E S D / F low Line V alve
K ill Lin e V alve / Inlet W in g V alve
Ma ste r V alve
P2
P1
C h ristm as tree o n p la te fo rm
5EP Matrix Treatment Design
to M V 220
S D P 3 plate form
1 5
6
7
8
2
3
4
To c em ent un it/R ig
pum p
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VIIIASSESS PROFITABILITY
5EP Matrix Treatment Design
Matrixtreatmentdesignmethodology
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Assess profitability of treatment by estimating
increases in productivity or injectivity vs.the cost of the treatment itself.
$$$
5EP Matrix Treatment Design
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IX EVALUATION OF THE JOB
5EP Matrix Treatment Design
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InjectivityindexAnalysis
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0
40500
20
1000
1500
0 500 1000 1500 2000
Cumu lative Job V olum e (bbls)
2500 3000 3500
2500
160
1402000
120
3000
Pressure
(psi)
0
60
80
100
180
200
BPM-
InjectivityIndex(bbl/d/psi)
Tubing Pres sure (at W H)
Pum ping Rate
Stages at perf
Injectivity Index
8EP Matrix Treatment Design
II (b/d/psi) = Q (bpm) x 24 x 60 / (BHP Pres)
Guidelinesforselection /Evaluation
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Keep a
riti
l eye
on recordings
1500
1700
19:12 19:26 19:40 19:55 20:09 20:24
Time (8th Dec 2001)
0
2
From surface
readings, Job
appears to be a
school case !
Looking at BHP only250psi are lost in
2800bbls...
=> check for possible
other causes
(density, leak)
Data: WHP / BHP versus time and BPM
1900
2100
2300
2500
2700
4
6
8
10
12
14
16
18
20
22
250psi
BHP(gauge)
WHP
(real time)
5EP Matrix Treatment Design
Treatmentdataanalysis
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Perform the analysis ondownhole data if possible
Calculate the variation of theInjectivity Index during thetreatment
II(bpd/psi)= Qinject x 24 x 60 /(BHP Pi)
0
500
1000
1500
2000
2500
3000
0 500 1000 1500 2000
Cumulative Job Volume (bbls)
2500 3000 3500
Pressure(psi)
0
20
40
60
80
100
120
140
160
180
200
BPM-InjectivityIndex(b
bl/d/psi)
5EP Matrix Treatment Design
Tubing Pressure (at W H)
Pum ping Rate
Stages at perf
Injectivity Index
Onsitequalitycontrol
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Check on site the quality of the fluids to be pumped
Stability of fluids
Efficiency of diverters
Compatibilities
Good
ad
20
pH
5EP Matrix Treatment Design
2 4
1000
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XMATRIX TREATMENT DESIGN
KEY POINTS
6EP Matrix Treatment Design
Matrixtreatmentdesign:KeyPoints
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6EP Matrix Treatment Design
Candidate selection
Good estimation of the damage (nature and origin)
Selection of the fluids (additives, lab tests)
Fluids placement and entire zonal coverage
Choice of the appropriate equipments
Assess profitability
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