Matrix Treatment Design FINAL VERSION.pdf

8/10/2019 Matrix Treatment Design FINAL VERSION.pdf

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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


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


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


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


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


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


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


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.


Skin


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Skin


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 =


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


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


PerforationsGravel Pack

Tubing

Sources of formation damage


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Sourcesofformationdamage


Drilling & Completion

Cementing Perforating

Stimulation

Gravel packing

Workover

Production

Injection operations


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IMATRIX DESIGN METHODOLY


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


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


Candidateselection


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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




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DIAGNOSIS to establish Nature and Location of damage

KEY POINTS

well data/history

laboratory test


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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Calcite

Limestone

Establish fluid volume and acid (HCl) strength


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 ...



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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



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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




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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


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.



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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




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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




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Train

Iron control




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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)




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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)



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VPLACEMENT STRATEGY



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Define shutin/cleanup stage

a bad cleanup can increase the damage near the

wellbore

precipitatesemulsion

scales

fines



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VIPRACTICAL CONSIDERATIONS




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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.


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




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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


to the BHSP gradient.


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Expectedequipmentonlocation


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CT required to spot the acid ?


Pretreatmentchecklist...


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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


ExpectedEquipmentonlocation


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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


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




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Assess profitability of treatment by estimating

increases in productivity or injectivity vs.the cost of the treatment itself.

$$$



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IX EVALUATION OF THE JOB



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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


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)


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)


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


2 4

1000


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XMATRIX TREATMENT DESIGN

KEY POINTS


Matrixtreatmentdesign:KeyPoints


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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

Documents

Matrix Treatment Design FINAL VERSION.pdf