21-Matrix Treatment and Fracturing

7/30/2019 21-Matrix Treatment and Fracturing

1/75

Matrix Stimulationand Hydraulic Fracturing


2/75

Well Stimulation

Matrix stimulation (remove near wellbore formation damage)

Reactive (acidizing)

Non reactive (solvents/surfactants)

Acid fracturing (low k carbonates or remove damage in high

k sandstones)

Hydraulic fracturing (low k sandstones)

Group of well treatments which objective is to remove the formationdamage and, depending on each case, to restore the natural productioncapacity (matrix stimulation), or bring it above this value (HydraulicFracturing or Acid Frac).


3/75

Matrix Stimulation

e

w

eo

iP

kh

srrl nBq1.142

P

The treating fluid is pumped into the well at a bottom holeinjection pressure which value does not exceed the mechanicalresistance of the rock.

Pi is the bottom hole injection pressure Pe the reservoirpressure.

Knowing the fracture pressure is required to stablish the limitof Pi.


4/75

.

PUMPING RATE, BPM

PRESSUR

E,

Mpsi FRACTURE PRESSURE

0

0,5

1

1,5

2

2,5

3

3,5

4

4,5

0 1 2 3 4 5 6 7 8 9 10

Matrix Stimulation


5/75

SOURCE OF DAMAGE TYPE OF DAMAGE MATRIXTREATMENT___________

DRILLING, COMPLETION AND CHANGE IN WETTABILITY SOLVENT/SURFACTANTSTIMULATION FLUIDS

EMULSIONS SOLVENT/ SURFACTANT

INORGANIC DEPOSITS ACID / /INHIBITOR /MECHANIC

WATER BLOCKAGE SURFACTANT / SOLVENT

FINES MIGRATION ACIDIZING

CLAY MIGRATION / SWELLING ACIDIZING

INORGANIC DEPOSITS ACID / /INHIBITOR /MECHANIC

ORGANIC DEPOSITS SOLVENT / THERMAL /MECHANIC

PLUGGING BY SOLIDS ACIDIZING

PRODUCTION

INVASION OF SOLIDS FROMDRILLLING MUD, COMPLETIONFLUIDS OR STIMULATION FLUIDS

SELECTION OF TYPE OF CHEMICAL TREATMENT

Matrix Stimulation


6/75

Non Reactive Treatments

Combination of aromatic solvents, mutual solvents and surfactantsto remove damage due to asphaltene or paraffine deposition

Sequential treatments with oxidants and Na(OH) to eliminateplugging by bacterias in water injection wells.

Specific treatments with surfactants for special damages, such asthose produced by inverted muds (emulsions and changes in rockwettability)

Mixture of acetic acid, mutual solvents and aromatic solvents,

specially for gravel pack clean out.

Matrix Stimulation


7/75

Reactive Treatments (Acid/Rock Interactions):

1.- Fundamentals

Hydrochloric acid, HCl (Carbonates)

Hydrofluoric acid , HF (Silicate minerals: Clays and Feldspars)

Acetic acid, CH3- COOH (carbonates dissolution at high temperatures)

Formic acid HCOOH (carbonates dissolution at very high temperatures)

2.- Special combinations and formulations

Mud-Acid: Mixture of HCl y HF (Clays)

Sequential Mud Acid: Alternative stages of HCl and NH4F (Clay-Sol) (in situ HF Generation)

Alcoholic acids (water block in gas wells) (Lower surface tension)

Mud acid retarded with aluminium chloride (excessive clay content)

Dispersed Acids (in aromatic hydrocarbons to remove organic deposits in the minerals andallow contact of acid with rockhigher penetration).

Acid to remove debris from perforations during shooting.

Fluoboric acid (Clay Acid: alternative to mud acid (slow generation of HF), stabiizes clayfines, specially Kaolinite)

Matrix Stimulation


8/75

Basics mechanisms of Interaction

between acid and rock minerals

Reactive Stimulations

STOICHIOMETRY: Amount of rock dissolvedfor a given amount of acid expended.

REACTION KINETICS: Rates at which acids

react with various minerals.

DIFFUSION RATES: How rapidly acid istransported to the rock surfaces.


9/75


STOICHIOMETRY

2HCl + CaCO3 CaCl2 + CO2 + H2O

Reaction between HCl and Calcite

DISSOLVING POWER FACTOR ( ) FOR DIFFERENT HClSOLUTIONS (ft3 CaCO3/ ft

3 HCl)

HCl Concentration (%)

5 0.02610 0.05315 0.08230 0.175


10/75


STOICHIOMETRY

4HF + SiO2 SiF4 + 2 H2O

Reaction between HF and Silicate Minerals

DISSOLVING POWER FACTOR ( ) FOR DIFFERENT HFSOLUTIONS (ft3 SiO2/ ft

3 HF)

HF Concentration (%)

2 0.0063 0.0104 0.0186 0.0198 0.025

SiF4 +2HF SiF4 + 2 H2O


11/75

Precipitation of acid reaction products


2HF + CaCO3 CaF2 + CO2 + H2O (fast)

In sandstone acidizing:

Colloidal Silica Si(OH)4 (slow)

Ferric Hydroxide Fe(OH)3 (present in iron bearing mineralsor dissolution of rust tubing)

Asphaltene sludges (contact of acid with some crude oils)


12/75

Acid modifications by additives

Indispensable Additives

Corrosion inhibitor (Prevent damage to casing and tubing) Iron stabilizer (Prevent Fe(OH)3 deposition )

Surfactant (Prevent emulsions and sludge)

Any other additive is optional and the necessity to use it, must bedemonstrated by doing compatibility tests with formation fluids.

DO NOT EVER USE UNNECESSARY ADDITIVES



13/75

Formation Treatment Response

Prediction of the reaction of the rock and saturating fluids with the aliveand wasted acid.

(The idea is to remove damage, not to build in additional damage).

It is important to know the rock mineralogy in order to know:

1.Which volume of formation will be dissolved by the acid (solubility tests)

2.Which volumen of formation will be dissoved in HCl-HF.

3.Which products will precipitate as a consequence of these reactions.



14/75

Components of an acid treatment

1 Preflush

Avoid contact of the acid with the crude oil

Avoid contact of the hydrofluoric acid with sodium, potassium or calcium

(CaF2 precipitation)

2 Treatment

Mixture of acid designed to remove damage.

3 Over displacement

Push the acid to the limit of critical area.

Solutions of NH4Cl (non reactive), gasoil with mutual solvent, mutual

solvent with surfactant, nitrogen



15/75

Properties of Formation Favourable for using hydrofluoric acid

Less than 15% of solubility in HCl

Difference between solubility in HCl and HCl-HF greater than 10%

Contain Montmorillonite or Kaolinite

Wells with a thick mud cake (from caliper)

Wells drilled with poor solids control

Wells with moderate low water cut

Fines migration problem identified (Abrupt decrease of production)

Wells producing sediments and mud

Wells with loss of circulation in the producing zone

Zones with low resistivity, low water production , high clay content



16/75

Injection Pressure and RateOptimum Conditions:

Maximum rate and maximum pressure without fracturing the formation.

A previous injectivity test must be done or the fracture gradients of the area must

be taken.

For safety reasons, Pi must be 500 psi lower than the fracture pressure

Design of a Chemical Matrix Treatment

e

w

e

o

iP

kh

sr

rl nBq1.142

P


17/75

Design of the treatment stages

Possible separator of ammonium chloride to displaceincompatible water formation.

Preflush of solvents and surfactants (avoid emulsions)

Preflush of acetic acid for carbonates if the formation contains alot of iron (avoid Fe(OH)3 precipitate)

Preflush of HCL.

Treatment with variation of HF.

Overdisplacement with NH4Cl, weak HCl, Gasoil withsurfactants, Nitrogen.



18/75

ACID SELECTION

STANDARD TREATMENTS

Carbonates: 15%WT HCl

Sandstones: 3%HF, 12% HCl, preceededby 15% HCl (preflush)


19/75

Sandstone Acidizing (Guidelines from extensive field experience)

HCl solubility >20% Use HCl only

High Permeability (100 mD plus)

High quartz (80%), low clay (20%) 13.5%HCl 1.5%HF (a)

High clay (>10%) 6.5%HCl 1%HF (b)

High iron chlorite clay 3%HCl 0.5%HF (b)

Low Permeability(10 mD or less)

Low Clay(


20/75

Carbonate Acidizing

Perforating Fluid 5% acetic acid

Damaged Perforations 9% formic acid

10% acetic acid

15% HCl

Deep Wellbore damage 15% HCl

28% HCl

Emulsified HCl

ACID SELECTION


21/75

PENETRATION RADIUS (FEET)

0

50

100

150

200250

300

350

400

00,511,522,533,544,555,566,577,58

0

50

100

150

200250

300

350

400F 5%

F 10%

F 15%

F 20%

F 25%

V= r2h, for h= 1


Re

quiredVolumes

(gallons/ft)


22/75

FLOW RATE, Q

BOTTOMOLE

FLOWINGPRESSU

RE,

PwfPr

00 PRODUCTION INCREASE

1

2

2**

2*

WELL WITH

SKIN EFFECT

S=12

WELL WITHOUT SKIN EFFECTS=0


NODAL ANALYSIS


23/75

TIME, MONTHS

050

100

150

200

250300

350

400

450

0 5 10 15 20 25 30

S=12

S=0

Impact of Damage on Cumulative Production


CUMULA

TIVEOILPRODU

CTION,

MBbls


24/75

+0-

Pay out time

tU D tD

TIMEProductionExploration Evaluation Development


S=12

S=0

Impact of formation damage on cash flow and payout time


25/75

Placement Techniques and Vertical Distribution

Dependent on:

Permeability Thickness Reservoir Pressure Multiple Zones

Chemical Distribution Tecnique:

Resins dispersable in water, benzoic acid

Mechanical Distribution Techniques:

Packers, Cups, Coiled Tubing, Sealing Balls

Fluids Viscosifier

Foam

Maximum rate and pressure (Paccaloni)



26/75

Additional Design Considerations

A minimum injectivity of 0.25 BPM is required at the end of thetreatment

Low formation pressure requires using foamy fluids.

Safety: H2S, high pressures, handling of fluids to be pumped,contingency plan

Different procedures for new and old wells

Casing and cement integrity



27/75

Execution and Evaluation of the Acid Job

Supervisin and quality control before the job

Well preparation: Cleaning, platform o location conditioning,wellhead.

Possible circulation of acid to clean out the tubing

Tanks and lines cleaning

Wellhead Testing

Equipment Availability

Tanks circulation

Samples of all mixed fluids

Laying of lines and valves

Meeting with personnel

Hidrostatic Test


28/75

Supervision and quality control during the job

Know the capacity of the tubing to know when each fluid is reachingthe perforations.

Take samples of each fluid

Observe the pressure response when each fluid reach the formation

If the pressure increases, damage is increasing. Stop and flowthe well

If the pressure decreases, keep the pressure increasing the rate,without fracturing.



29/75

Supervision and quality control after the job

Put the well on production as soon as possible to give no chance ofsecondary reactions.

Take samples of the returning fluids, analyze type and size ofsolids, returning acid concentration, iron content, emulsions,

Test the well



30/75

1.- Paccaloni Method

Pi = Surface pumping pressure, psi

Pe= reservoir pressure, psi

Ph= Hidrostatic pressure, psiPfr= Friction losses, psiQ= Injection rate, b/d= Fluid viscosity, cpK= Effective permeability of the injected fluid, mdh= Formation thickness, feetrb= Radius of the ijected fluid bank, feet

rw= Well radius, feets= Skin factor, dimensionless

Based on this equation, a plot of injection pressure versus rate isprepared, taking S as the parameters of the curves

Real Time Monitoring and Evaluation of an AcidStimulation

P P P P QK h

rri e h fr

b

w-S

= ( - + ) + . * **

1417

ln


31/75

Real Time Monitoring and Evaluation of an AcidStimulation

PRESION DE

FRACTURA

S=10 S=5 S=2 S=0

S=-2

S=-3

PERDIDAS POR FRICCION

PaccaloniINJECTION RATE (bpm)

01000

2000

3000

4000

5000

6000

7000

8000

900010000

0 1 2 3 4 5

S

URFACEPRE

SSURE,

PSI

PACCALONI METHOD

Friction losses

Surface Frac pressure


32/75

EXERCISE

A well is draining oil from a reservoir which matrix contains 10% Vol CaCO3

and no other HCl-soluble mineral and has an initial porosity of 20 %.Wellbore radius=0.5 ft

Calculate the volume (gal) of 15% wt HCl needed to dissolve all carbonates

to a distance of 2.5 ft (rs=3.0ft) from the wellbore (Preflush). Reservoir

thickness = 60 ft.

1 ft3=7,48 gal; dissolving power factor of HCl 15%=0,082 ft3CaCO3/ft3HCl

H d li F t i


33/75

Hydraulic Fracturing

The pumping pressure exceeds the mechanical resistanceof the rock

A high conductivity channel is created in manner where:

The damaged area around the wellbore is by passed.

The channel extends in the reservoir to increase theproductivity.

The channel changes the flow pattern in the reservoir.


34/75


How?

Pump at high pressure Breakdown the formation

Open up & propagate the

fracture

Fill the fracture up with

proppant

FractureGrowth

Direction

Fracfluid

injection smin


35/75

Benefits of fracturing

By pass of the formation damage

Reduction of draw-down

Control of the disaggregation of the porous medium

Reduction of fines migration and asphaltene deposition

Reduction of water

Increase of the productivity index

Improvement of the connection reservoir-well


36/75

RADIAL FLOW

WELL

Pwf

Pe

r

qp

r

Kh

Benefits of fracturing

Flow Pattern without Fracturing


37/75

Linear Flow in the fracture

Bi-linear Flow

Linear flow in the reservoir

Eliptic or Transitional flow

Pseudoradial flow

Alteration of flow pattern

100ft


38/75

ELIPTIC FLOW

DIST. PARALLEL TO THE FRACTURE

WELL

Pwf

Pe

Pressure drop in the fracture


39/75

f

f

fDkx

wk

C

2 xf

w

CONDUCTIVITY CONTRAST

kf: Permeability of the fracturek: Reservoir permeability

1.0


40/75

Productivity Index

fx

r.B

kh

r

xsx

r.B

khJ

f

e

w

f

f

f

e 4720ln

2

ln4720

ln

2

PRODUCTIVITY INDEX WITH FRACTURE

(Cinco Ley and Samaniego)


41/75

Cinco-Ley and Samaniego

0

1

2

3

4

0.1 1 10 100 1000CfD

f

fD

fD

Cu

u.+u.u+.+

u.u+.-.Cf

lnwhere

005006401801

11603280651)(

32

2

f = ln(2) para CfD > 1000


42/75

EXERCISE

WELL DATA

Depth: 8000 ftTbg ID: 3 Kr=5 mDPr=2085 psi

h =50 ftrw=6re=2500 ft

Calculate the production increase when a fracture ofL=100 ft and width= 1 is created by a hydraulicfracturing job


43/75

STAGE 1

STAGE 2A

STAGE 2B

Kp/Skin Factor S

Thickness h

Barriers Bd

Hole conditions Wd

MatrixStimulation

Fracture

Stimulation

DamageMechanism

Temperature

Solubility HClHomogeneityGeomechanicNatural fracturesFines Stabilization

Matrix Acidization

Solvents

Other ChemicalTreatments

Mechanical Removal

Thermal Methods

Acid Frac


STAGE 1A

Selection of the stimulation

STAGE 1B


44/75

A FRACTURE TREATMENT MUST BE JUSTIFIED BASED ON:

INCREASE OF THE PRODUCTION RATE

INCREASE OF THE PRODUCTIVITY INDEX

ACCELERATED RESERVES RECOVERY

INCREMENT OF THE RESERVES

INCREASE OF THE PRODUCTIVE LIFE OF THE WELL

THE FLOW RATE AND THE RECOVERY ARE CONTROLLED BY:

DRAINAGE AREA

RESERVES

FORMATION PERMEABILITY

FRACTURE LENGTH

FRACTURE CONDUCTIVITY



45/75

LOW PERMEABILITY

Log q

TIME

STIMULATED

NOT STIMULATED

TIME

Np

STIMULATED


NOT STIMULATED

Increasing Reserves


46/75

HIGH PERMEABILITY

Log q

time

economic Limit

stimulated

not stimulated

time

Np

final recoverystimulated

not stimulated


Acelerating Reserves


47/75

5 mD - 7000 mD.FT

5mD - 3000 mD.FT

1 mD - 7000 mD.FT

1 mD - 3000 mD.FT

1000

4000

2500

3500

3000

2000

1500

FRACTURE LENGTH, FT (Xf)

NPV M$

0 200 400 600 800 1000 1200


k kf x w

S l ti f th ti l ti


48/75

FINAL RECOVERY

IN HIGH PERMEABILITY RESERVOIRS THERE IS NO ADDITIOINALRECOVERY, BUT ACCELERATION OF THE RESERVES.

IN LOW PERMEABILITY RESERVOIRS THE RECOVERABLE RESERVESARE INCREASED.

THE RESERVES ARE FUNCTION OF PERMEABILITY, FRACTURE

LENGTH, DIMENSIONS AND SHAPE OF THE DRAINAGE AREA.


S l ti f th ti l ti


49/75

FRACTURE OPTIMIZATION

WELLS SPACING AND FRACTURE LENGTH MUST BE KNOWN TO

OPTMIZE THE INTERNAL RATE OF RETURN AND THE NET PRESENTVALUE.

IN GENERAL, LOW PERMEABILITY RESERVOIRS REQUIRE LONGFRACTURES.

HIGH PERMEABILITY RESERVOIRS REQUIRE SHORT AND VERYCONDUCTIVE FRACTURES.


S l ti f th ti l ti


50/75

RESERVOIRSIMULATOR

Np

t

Xf=3000

Xf=1000

Xf=500

$ INC.

$ COST.

$ ENT.- $COSTO

FRACTURE LENGTH

FRACTURE LENGTH

FRACTURE LENGTHFRACTURE LENGTH

FRACTURESIMULATOR

TREAT.VOLUME


HYDRAULIC FRACTURING DESIGN


51/75

PSEUDO-TRIDIMENSIONAL MODELS

HOLDITCH, TRIFRAC

STIMPLAN, NSI, INC.

ENERFRAC, SHELL

2.- PARAMETRIZATION OF FRACTURE GEOMETRY FRACPRO, RESOURCES ENGINEERING CO.

MFRAC II, MEYER & ASSOCIATED

FRACCade, Schlumberger

1.- PLANAR

PLANAR 3D TERRA-FRAC, TERRA-TEK

HYFRAC 3D, ADVANI, LEIGH UNIVERSITY

CHING YEW, TEXAS UNIVERSITY




52/75

STRESS CONCENTRATION

TORTUOUSITY CONCEPT

CONVECTIVE DISTRIBUTION CONCEPT

PERFORATING DESIGN FOR CONVENTIONAL FRACTURING PERFORATING DESIGN FOR HIGH PERMEABILITY

FRACTURES

PERFORATING DESIGN FOR FRAC-PACK

SCREENLESS FRAC-PACK

MAIN GOAL OF ANY TYPE OF FRACTURE




53/75

1

2

3

4

5

6

7

89

10

11

Depending on the porosity, permeability andsand quality, the fracture may be initiated in

the layers 6 and /or 2, and may be verticallypropagated upward or downward dependingon the contrast of stresses between this twolayers and the adjacent layers. It is moreprobable the upward growth of the fracture.

Shales are barriers when their effective

thickness is greater than 50 feet.

The vertical growth can be stopped by a highpermeability sand, due to the excess of fluidleakoff..

Layer 10 exhibits an oil-water contact which

can make water to break through in the well ifthis layer is fractured.

.

To control the starting point of the fracture, thecement has to be perfect


OTHER PARAMETERS


54/75

OTHER PARAMETERS

FLUID SELECTION

PROPPANT SELECTION

FRACTURE HEIGHT

REAL TIME MONITORING MINIFRAC ANALYSIS

WELL PRODUCTION TEST

BULID UP TEST

POST-FRACTURE DAMAGE

PRODUCTIVITY INDEX VARIATION

CRITICAL FACTORS IN HYDRAULIC FRACTURING


55/75

CONVECTIVE REDISTRIBUTION OF THE FLUID STAGES OF DIFFERENT DENSITY,DUE TO THE PROPPANT CONCENTRATION.

TORTUOUSITY IN THE NEAR WELLBORE WHICH LIMITS PLACEMENT OF THE

PROPPANT.

HIGH PRESSURE INSIDE THE FRACTURE DUE TO THE NON LINEAL EXPANSION

OF THE ROCK, WHICH IN CONSEQUENCE REDUCE THE EFFECTIVENESS OF

THE CONTENTION BARRIERS OF THE FRACTURE.

THE REOLOGY AND THE INJECTION HAVE VERY LITTLE INFLUENCE IN THEFRACTURE DIMENSIONS, BUT THEY CONTRIBUTE TO ELIMINATE THE

TUORTUOUSITY.

THE FRACTURE GROWTH IS MAINLY DOMINATED BY THE VARIATIONS IN

PERMEABILITY.

CRITICAL FACTORS IN HYDRAULIC FRACTURING

ADDITIONAL BENEFITS


56/75

D= 7

L= 1000 PIES

AREA= D L2 4 = 250 FT2Q DEPENDS ON

K

KV

H

LF= 300 FT

AREA= APPROX 4x300x100= 120000 FT2

AND Q ONLY DEPENDS ON KH AND THE FRACTURECONDUCTIVITY

HF= 100 FT

ADDITIONAL BENEFITS

ADDITIONAL BENEFITS


57/75

1.- DECREASES THE FLUID VELOCITY IN THE FACE OF THE ROCK MATRIX

2.- INCREASES THE EFFECTIVE DRAINAGE AREA OF THE WELL.

3.- DECREASES THE REQUIRED NUMBER OF WELLS TO DRAIN A CERTAIN AREA.

4.- REDUCE THE NECESSITY TO DRILL HORIZONTAL WELLS.

5.- DECREASES THE PRESSURE DROP IN THE MATRIX BY CHANGING THE FLOW PATTERN. L

6.- CONTROLS SAND PRODUCTION AND ASPHALTENES, PARAFFIN AND SCALE DEPOSITION.

7.- RETARDS THE EFFECT OF WATER CONING, BY DECREASING THE PRESSURE DROP.

ADDITIONAL BENEFITS

UNIFIED FRACTURING DESIGN


58/75

UNIFIED FRACTURING DESIGN

Exist an unique optimum combination

of fracture width and length for a given

volume of proppant to get a maximumproductivity index for that set ofconditions


59/75

Anomalies Identification and Formation

Damage Diagnosis

Anomalies Identification and FormationD Di i


60/75

Damage Diagnosis

Anomalies

Low Productivity Index

High Declinatioin Rate

Is the well damaged?



61/75

Factors to be discounted before diagnosing

formation damage

Insufficient number of shots per foot

Partial Penetration

Diameter and penetratiion of the guns

Bad Cementation

Tubular Designs

Artificial Lift Design

Surface Facilities Restriction

After this analysis, a diagnosis of the true

formation damage can be done

Damage Diagnosis



62/75

Determination of type of damage

Analysis of group of wells from the same reservoir (OFM)

Reservoir quality analysis around the wellbore

Nodal Analysis to identify restrictions

Buld up test analysisWell production history review

History of drilling, completion and workover operations

Fluids/solids samples analysis

Production log analysis

Lab Analysis

Damage Diagnosis

Analysis of group of wells from thei


63/75

same reservoir

Je ideal

Wells with NormalPerformance

Wells with Low

Performance

oo

o

idealB

KJ h

Reservoir quality analysis around thewellbore


64/75

wellbore

Reserves Porosity

Cumulative Production

Remaining Reserves

Permeability

Fluids Saturation

Clay index

Log Analysis

NODAL ANALYSIS


65/75

NODAL ANALYSIS

Pr

00

1

2

GAS LIFT

Pb

PRODUCTION INCREASE

WELL WITH AVERY STONG

SKIN EFFECT

3

IPR IMPROVED BYREPERFORATION +STIMULATION JOB

ZERO GAS INTHE PUMPPwf > Pb

ELECTRICAL SUBMERSIBLEPUMP (ESP)

FLOW RATE, Q

BOTTOMHOLEFLOWINGPR

ESSURE,

Pwf

BUBBLE PRESSURE

Build up Tests


66/75

Build up Tests

23.3log151.1s 2w

wfhr1

cr

km

PP

Production History Review


67/75

Historia de produccin

1

10

100

1000

0 5 10 15 20

tiempo, meses

Produccin

B/

DAcidizing Job

% water cut

PRODUCTION HISTORY

TIME, months

PRODUC

TIONSTB/day



68/75



69/75

TIME, DAYS

ST

B/DAY

OIL FLOW RATE

WATER FLOW RATE

WARNING!!

History of drilling, completionand workover operations


70/75

and workover operations

Overbalance during drilling/workovers

Chemical additives and their effect

Surfactants

pH stabilizers

Corrosion inhibitor

Dispersants

Hidrocarbons

Type and size distribution of solids in the drlling and

workoiver fluids

Type of acid and additives used during cemical stimulation

Types of fluids and additives used in hydrauliuc fracturingjobs

Produced Fluids Analysis


71/75

y

Solids analysis

Fluids Composition (cromatography, water characterization)

PVT analysis

Fluids Compatibility

Asphaltenes, Paraffins

Emulsions stability

Organic/inorganic Precipitates

Production logs


72/75

1. ZONES CONTRIBUTION IN COMMINGLED PRODUCTION

2. CHANGES IN PROFILE DUE TO STIMULATION TREATMENT

3. LOCATION OF WATER ZONES

4. VERTICAL FLOW DISTRIBUTION IN INJECTION WELLS

5. MECHANICAL CONDITIONS OF THE WELL(TUBING/CASING/PACKER LEAKS, CORROSION, CEMENT)

6. FLOW BEHIND THE CASING

7. CROSS FLOIW

CORE FLOW TESTS


73/75

CORE FLOW TESTS

Evaluacin del potencial de dao de un fluido de trabajo

10

100

1000

0 100 200 300 400

Volmenes porosos inyectados

Permeabilidad

,mD

Water

50% original K

EVALUATION THE DAMAGING POTENCIAL OF A WORKING FLUID

INJECTED PORE VOLUMES

Permeability

Acid response curve


74/75

Acid response curve

0

20

40

60

80

100

120

0 5 10 15 20 25 30

FORMATION

WATER

HCL MUD ACID (12% HCL- 3% HF)

VOLUMENES POROSOS INYECTADOSINJECTED PORE VOLUMES

Permeability

OTHER LAB TESTS


75/75

OTHER LAB TESTS

-ACID SOLUBILITY ANALYSIS-MICROSCOPY OBSERVATIONS (PETROGRAPHY)

-PRODUCED SOLIDS SOLUBILITY ANALYSIS-ROCK COMPOSITION-ASPHALTENE SOLUBILITY ANALYSIS

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21-Matrix Treatment and Fracturing

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