Completion_Reservoir Drill in Fluids

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Global Research & Technology Centre/ GRTC

Training Department

Completion & Completion & Reservoir Reservoir Drill Drill ––In In

FluidsFluids

Completion & Completion & Reservoir Reservoir Drill Drill ––In In

FluidsFluids

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Definition - Completion Fluid

A Completion Fluid may be defined as any fluid that is

used during the completion operation…after the well has

been drilled and before any oil and/or gas has been

produced from the formation.

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Definition - Workover Fluid

A Workover Fluid may be defined as a fluid that is used during remedial or workover operations after a well has produced oil and/or gas.

It can be the same fluid as the

completion fluid.

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Why Use Brines

MINIMIZEFORMATION DAMAGE!!

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Performance Criteria

• control formation pressures

• circulate and transport solids

• protect the productive zone

• stable at surface and downhole

• safely handled

• environmentally friendly

• readily available

• cost effective

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TYPES OFCOMPLETIONANDWORKOVER FLUIDS

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COMMON DENSITIES

SINGLE SALT SOLUTIONS

• AMMONIUM CHLORIDE 8.4 - 8.9 PPG

• POTASSIUM CHLORIDE 8.4 - 9.7 PPG

• SODIUM CHLORIDE 8.4 - 10.0 PPG

• CALCIUM CHLORIDE 8.4 - 11.6 PPG

• SODIUM FORMATE 8.4 - 11.1 PPG

• SODIUM BROMIDE 8.4 - 12.5 PPG

• POTASSIUM FORMATE 8.4 - 13.1 PPG

• CALCIUM BROMIDE 8.4 - 14.2 PPG

• ZINC BROMIDE 19.3 - 21.0 PPG

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COMMON DENSITIES

MULTIPLE SALT SOLUTIONS

• NaCl/NaBr 10.1 - 12.4 PPG

• NaHCO2/KHCO2 11.2 - 13.1 PPG

• CaCl2/CaBr2 11.7 - 15.1 PPG

• CaBr2/ZnBr2 19.2 PPG

• CaCl2/CaBr2/ZnBr2 15.2 - 19.1 PPG

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“SPIKE” FLUIDS

CALCIUM BASED

• 11.6 PPG CaCl2

• 14.2 PPG CaBr2

• 15.1 PPG CaCl2/CaBr2

• 19.2 PPG CaBr2/ZnBr2

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“SPIKE” FLUIDS

SODIUM BASED

• 10.0 PPG NaCl

• 12.5 PPG NaBr

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COMPLETION AND WORKOVER FLUIDSPROPERTIES AND TESTING

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Properties

• Density � determined by a hydrometer.

• TCT �True Crystallization Temperature.

• pH � pH paper is OK...a meter is better.

• Solids Content �� determined by centrifuging.

• Turbidity �� determined by an NTU meter.

• Viscosity � Marsh funnel.

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Density

To check for brine density use:

Hydrometer

Note: If you do not know the approximate density of thefluid you are weighing…use a mud balance to get you inthe ballpark.

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Density

Can be adjusted by adding

• water

• “Spike” Fluids

• Dry salts

NOTE: adjusting the density usually adjusts the TCT of the fluid…unless the salt concentrations are balanced as a part of the density adjustment.

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Crystallization Temperature

• Each salt has a maximum solubility in water before it willprecipitate out of solution. This maximum solubility is afunction of the temperature of the water.

• The crystallization temperature of the a brine is definedas the temperature at which a solid will form andprecipitate out of solution.

• Operations utilizing completion fluids must account for the crystallization temperature by recognizing the coolest temperature to which the bulk of the brine will be exposed for any significant period of time.

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Crystallization Temperature

For example:• A completion fluid standing

static in the riser of a deepwaterwell may reach the thermalequilibrium with the water at thesea floor or mud line. Thissituation must be taken intoaccount to avoid crystallizedfluid in the riser even thoughthe surface conditions may besunny and warm and the BHT ishigh.

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Solids ContentSolids Content

Solids Content

Determined by

Centrifuging

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pH

• Salt Typical pH

• 11.6 ppg Calcium Chloride 6.5 to 7.5

• 14.2 ppg Calcium Bromide 6.5 to 7.5

• 15.0 ppg CaCl2/CaBr2 6.0 to 7.0

• 16.0 ppg CaCl2/CaBr2/ZnBr2 4.5 to 5.0

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pH

• Salt Typical pH




• 19.2 ppg CaBr2/ZnBr2 <1.5

• The more Zinc Bromide that you have in a fluid,

the lower the pH will be.

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Turbidity

• Turbidity is a function of the cleanliness of the fluid. If thefluid contains drilling mud solids, undissolved salt, pipe scale,air etc., the turbidity will be high.

• The NTU value is lowered by cleaning the fluid. This isaccomplished by allowing the solids to settle out or float,filtering the fluid through cartridges, through a DE filterpress, or all of the above.

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Turbidity Meter (NTU Readings)

Sample Bottle

Calibration Sample

NTUMeter

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Density Control

INCREASE THE DENSITY OF A SINGLE SALT FLUID

• Do = density of original, ppg

• Df = density of final, ppg

• Wo = water of original, bbl/bbl brine

• Wf = water of final, bbl/bbl brine

• So = salt of original, lb

• Sf = salt of final, lb

• Vo = original volume of brine, bbl

• Vf = Final volume of brine, bbl

WoSf

Salt Required (lbs) = Vo --------- - So

Wf

VoWoFinal Volume (bbl) = -------------

Wf

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Density Control

CoWf

Wa = Water added = Vo --------- - Wo

Cf

CoBf

Ba = Bromide Salt added = Vo --------- - Bo

Cf

VoCo

Vf = Final Volume = ---------Cf

• INCREASE DENSITY OF A TWO SALT FLUID WITH DRY

CALCIUM BROMIDE.

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Buy-Back

• The typical “Buyback” for completion fluids with a densityabove 11.6 ppg is 80% of the selling price, less the cost ofreclamation.

• A fluid that sold for $125.00/bbl initially and had a reclamationcost of $7.00/bbl would have an ending value of $93.00/bbl.We would give the customer credit for $93.00/bbl of reclaimedfluid.

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Mass Balance

• Fluids are said to be “Mass Balanced” when two or more fluidsare blended together and the combined volume and combineddensity becomes the new volume and density.

• TCT’s are not a function of Mass Balancing.

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Salt Table

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Mass Balance – The Easy Way

• HEAVY FLUID 15.1

• DESIRED FLUID 13.0

• LIGHT FLUID 12.5

2.6 2.6

EXAMPLE:

RAISE DENSITY OF 12.5 PPG FLUID TO 13.0 PPG, USING 15.1 PPG

SPIKE FLUID. FINISH WITH 600 BARRELS OF VOLUME

DIVIDE DIFFERENCES BY TOTAL DIFFERENCE AND INVERT THEVALUES. THE FRACTION OF 15.1 PPG IS .192 BBLS AND THEFRACTION 0F 12.5 PPG IS .808 BBLS. MULTIPLY THE FRACTIONTIMES THE DESIRED VOLUME TO FIND THE AMOUNT OF EACHFLUID.

2.1 0.5/2.6 = .192

0.5 2.1/2.6 = .808

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Typical Wellsite Filtration System Setup

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Filtration Unit

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Displacement & Wellbore Displacement & Wellbore CleanClean--UpUp

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Displacement Method

Forward Reverse Indirect

Displace with

water

Drilling mud

Displacement

spacers

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WELL CLEAN-UP DESIGN

Suggested Standard Procedure.

It would be good practice to follow the program of clean-up pillsas listed below, if the rig pit system allows:

A Viscosified Surfactant Spacer.This is designed to act as a piston displacing the existingwellbore fluid efficiently out of the hole. It is best pumped inlaminar flow to push the wellbore fluid up the annulus. A YieldPoint of 40 – 50 lbs/100 ft2 is recommended.

A Solvent Wash.This is used to dissolve any mud residue, pipe dope or minorscale on metal surfaces. This non-viscosified pill is best pumpedin turbulent flow.

A Surfactant Spacer.This pill is NOT viscosified to ensure turbulent flow and isdesigned to prevent channeling and lift residual solids from thehole.

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DISPLACEMENT & HYDRAULICS SOFTWARE

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Hydraulics Software

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Clean-Up Tool

• Scrapers

• Brushes

• Magnets

• Debris Management Tools

• Jetting Subs

• Circulating Tools

• Pipe Rotation

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Xanthan vs. HEC

• Xanthan has superior suspension and transport

properties

• Xanthan slips at the wall, HEC grabs

• Xanthan used in brine < 10.5 lb/gal CaCl2 HEC used

in all brines and densities

• XC and HEC can be used in combination in up to 11.4

lb/gal CaCl2 brine

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Suspension in HEC and XC

XANTHAN-GUM

2 lbs/bblHEC

4 lbs/bbl

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Velocity Profiles

HEC Xanthan

Area of high friction drag

Slip area

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Cleaning Spacer Design

After 5 Minutes Rating 2 After 8 Minutes Rating 1 Aft er 10 Minutes Rating 1

11.6 ppg 3% Safe Solv OM 5% Safe Surf O 0% Contami nation and 13.2ppg Nova Plus @100rpm/ 42fpm

Clean Dry Sleeve Sleeve Coated with 13.2 ppg SBM Afte r 3 Minutes Rating 2

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Displacement Evaluation

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WELL CLEAN-UP DESIGN

Well name : Angsi C-11

Well Geometry :9 5/8" Csg Shoe 3797 m 9 5/8" section Length 3797 m DP in 9 5/8" csg 5.5 in

9 5/8" Csg ID 8.681 in 5.5" DP ID 4.778 in7" Casing Shoe 6527 m 7" section length 2730 m DP in 7" csg 3.5 in

7" Csg ID 6.366 in 3.5" DP ID 2.6 in

Pill Volume

Type ( bbl ) 9-5/8" 7" 9-5/8" 7" 9-5/8" 7"

Casing Casing Casing Casing Casing Casing (gpm) ( bpm )

Surfactant Pill Flowzan 2ppb Flowzan 3

(viscosified) RinseAid 30% Rinse Aid 14

Solvent Pill 120 Super Pickle 50%

Super Pickle 31 835 1332 15 15 Turbulent Turbulent 336 8

Surfactant Pill 80 RinseAid 30% Rinse Aid 14 556 888 10 10 Turbulent Turbulent 336 8

Sea water > 1127 > 8

Brine (filtered) 1127 Brine > 8

880

Casing Clean-Up

Flow Rate

336

Contact Length ( m ) Flow Regime

556 888 10

Product Usage (sack, drum)

Product Concentration

(ppb, % v/v)

Laminar Turbulent

Contact Time (min)

10

XXX

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CLEAN-UP DESIGN

Visc. Un. Visc. Visc. Un. Visc.

bpm gpm Surfactant Surfactant Surfactant Surfactant

3.7 157 Lam. Lam. Lam. Lam. Lam. Lam.

6 255 Lam. Lam. Lam. Lam. Turb. Turb.

8 336 Lam. Turb. Turb. Lam. Turb. Turb. RECOMMENDED

10 420 Lam. Turb. Turb. Lam. Turb. Turb.

12 504 Lam. Turb. Turb. Turb. Turb. Turb.

14 588 Lam. Turb. Turb. Turb. Turb. Turb.

20.3 854 Turb. Turb. Turb. Turb. Turb. Turb.

FLOW RATEREMARKS

Solvent Solvent

9 5/8" Annulus 7" Annulus

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NTU vs TIME CHART

NTU vs Time

0

30

60

90

0:30

1:00

1:30

2:00

2:30

3:00

3:30

4:00

4:30

5:00

5:30

6:00

Time (24 hrs)

NTU

Unfiltered Seawater out

Displace to 8.9 ppg Filtered NaCl + 3% KCl Brine

Filtered NaCl + 3% KCl Brine at surface

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NTU vs CIRC. CYCLE - CHART

NTU vs Number of Surface to Surface

0

30

60

90

1.25 1.75 2.25 2.75 3.25 3.75

Number of Surface to Surface

NT

U

Unfiltered Seawater out

Displace to 8.9 ppg Filtered NaCl + 3% KCl Brine

Filtered NaCl + 3% KCl Brine at surface

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Reservoir DrillReservoir Drill--In In FLuidsFLuids

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The DifferenceThe Difference

● Typically used to drill only the producing formation

● Non-damaging

● Low solids

● Does not contain clay (gel) and/or dispersants

● Compatible with formation

● Additives are soluble in typical chemical treatments e.g. acid, enzymes, chelants, oxidizers

● Inhibitive to formation clays

● Compatible with the completion

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The DifferenceThe Difference

Property Drilling Mud RDIF

Density Barite Base fluid

Viscosity Gel Bio-polymer

Fluid Loss gel/polymer Starch

Bridging Barite Calcium carbonate,

Sized salt

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Why use Reservoir DrillWhy use Reservoir Drill--In Fluids?In Fluids?

To maximize production by minimizing damage to the formation and completion assembly!

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Solids PluggingSolids Plugging● filtrate invasion / solids contamination● fines migration● Inadequate displacement

Chemical IncompatibilityChemical Incompatibility● clay / shale swelling● inducing fines migration● fluid-fluid interactions

● emulsions, precipitation (scaling)● wettability reversal

How do we damage the formation How do we damage the formation and/or Completion Assembly?and/or Completion Assembly?

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Reservoir Drilling Fluid Design Criteria

Drilling Issues

� Density for Well Control / Wellbore Stability

� Rheology for Hole Cleaning & Suspension

� Minimum ECD

� Lubricity

� Low Fluid Loss

� Formation Inhibition

� Environmental restrictions

� Thermal Stability

� Contaminant Stability

� Availability

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Completion Issues

Type of completion planned e.g. open hole, cased hole, screen completion, gravel pack etc.

Efficient removal of RDF residues/filter cake

● Clean-up without treatment? (flowback)

● Chemical breakers

● Displacement to completion fluid

Compatible with procedures and equipment

● Completion tool restrictions


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Reservoir Issues

● Compatibility with formations drilled

● Fluid Compatibility

● Expected Fluid Production (Type & Volume)

● Pore Size

● Pore Interconnectivity


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1) Typically used to drill only the producing formation

2) Engineered to maintain drill solids below target

3) Relatively low amount of Bridging Solids

4) Typically does not contain inert solids or gel

5) Bridging solids are acid/chelant soluble

6) Inhibitive to formation Clays

7) Compatible with Formation Fluids

8) Compatible with the completion screens

9) Compatible with Sand Control Screen

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ViscosifiersViscosifiers

● High yielding xanthan gum or biopolymer

● Clarified / Dispersible

● Provides LSRV

● High thermal stability.

● Not affected by acids/alkalis over a wide pH range (2.5 to 10)

Usually 0.75 ppb to 2.0 ppb

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Fluid Loss Control AgentsFluid Loss Control Agents

● Hydroxypropyl, X-linked, starch

● High Thermal Stability

● Synergy with xanthan and scleroglucan

Usually 4 ppb to 7.5 ppb

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Pre-Planning

RDF Questionnaire - location, BHT, BHP, wellbore geometry, etc

Mineralogical Information -permeability, porosity, clay content, etc

Completion Information -completion assembly type, tools, etc

Rig Information - solids control availability, volumes, etc

Interview Engineers - determine primary objective and concerns,etc

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Required InformationRequired Information

● Completed Questionnaire

● Well Diagram

● Completion Design

● Core sample or formation data e.g. thin section, core flood

results, XRD

● Established metrics/objectives

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Fluid Optimization

● Test and Evaluate Properties -Fluid Loss (modified HTHP or PPA), Rheological Profile (LSRV), Hot Roll & Static Age, Swellmeter, Shale Dispersion test, Emulsion Tests, etc.

● Test a variety of products and compositions.

● Use SOFTWARE for determining blend of bridging particles.

● Use Brookfield Rheometer to determine optimum LSRV

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RDF Lab TestsRDF Lab Tests

● Density

● Static age and hot roll

● Viscosity Profile

● Fluid loss data (dynamic and static), PPT/HTHP

● Compatibility tests

● Cleanup treatment

● Compatibility with Completion assembly

● Return permeability

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RDF SystemsRDF Systems

• The primary mechanism for minimizing the invasion of solids/liquids on all RDF systems is creating a thin, impermeable filter cake.

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Bridging Agents Objectives

• Thinner filter cake

• Reduced chance of wellbore problems

• Minimize invasion of solids and fluid

• Less formation damage

• More efficient cleanup

• Better productivity

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Bridging Theories - Choosing PSDChoosing PSD

Abrahm’s rule • “The median particle size ofthe bridging material shouldbe equal to or slightly greaterthan 1/3 the median pore sizeof the formation.”

• The concentration of bridgingparticles must be at least 5%by volume of these solids inthe fluid

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Ideal Packing Theory

● “Ideal packing occurs when the percent of cumulative volume versus the D 1/2 forms a straight line relationship” - SPE 58793

● Provides the optimum PSD for bridging the opening created by the bridging solids

● In un-weighted fluids 2-3% by volume is sufficient to form an optimum seal

● In weighted fluids or high solids laden fluids the guidelines are more flexible

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Pore Opening Size

D1/2

Abrahm’s rule

133 microns

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Particle Size Distribution/PSD

Closest Mixture Utilizing CaCO3 for a 133 Micron Op ening

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 5 10 15 20 25

Square Root (Microns) D 1/2

Cum

lutiv

e %

Bel

ow

Target Line

CaCO, 2

CaCO3 10

CaCO3 40

CaCO3 250

Closest Mix W/CaCO3

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HyPR-BRIDGE

Scomi Software

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RDF Design Tools

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+-

+-

+-

CORE

Piston

Piston

ISCO PUMP

BPR

OVERBURDEN PUMP

Drill-InFluid

BPR

BPR

OVEN

ValidyneDelta PressureTransducersViscosity Coil

Hassler Cell

HIGH PRESSURE , HIGH TEMPERATURE - RETURN PERMEABILITY APPRATUS

ISCO

PR

Return Gas Cylinders

Mud CoilsBrine Coils

Humidifier

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Cleanup Design

Test to determine Return

Permeability - Return

Permeameter, modified HTHP or

PPA, Production Screen Tester,

etc. Test various methods of

cleanup including flow back only,

single step or two step chemical

cleanup treatments using acids,

enzymes and/or oxidizers.

Air-D rivenPump

BPR

O VERBURDEN PUM P

ISC O

CO NTINO US F LO WP UMP

BP R

BPRCompletionScreen

S creen G ate

Core S ample

Air Dr iven Cylinder

F luid Chamber

FORM ATION EVALUATIONCOMPLETIO N SIMULATOR

PressureTransducers

WASTE

STEMULATION

DRILLING

HAS TELLOYTRAN SFER VES SELS

HY DRAULIC DISPLA CEM ENTCYLIND ER

COMPLETION

Before After

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Chemical Breakers

Filter Cake Oxidizer: SpottyBreaks in Cake

Acid: “Wormholes”

Enzyme/Chelant: Cake Removal

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Common Breakers

Oxidizers

• Lithium Hypochlorite

• Sodium Hypochlorite

• Calcium Hypochlorite

• Internal Breakers

Enzymes

• Starch specific

• Cellulose specific

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Breaker Options

• Multi

•Oxidizer/Acid

•Acid/Acid

• Single

• Acid

• Oxidizer

• Enzyme(s)

• Enzyme/Chelant

• No Clean-up

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Chemical Cleanup Options

Chemical Options

� Acids – Attack polymers above 120oF and calcium

carbonate in WB, water wet reversible invert emulsion fluid

� Oxidizers – Attack polymers above 80oF in WB fluids

� Enzymes – Attack specific polymers above 40oF (usually

starch) in WB fluids

� Chelants – Dissolve calcium carbonate in WB fluids.

Performance may be enhanced with enzymes or oxidizers

� No Treatment – Flowback through completion assembly

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Breaker Selection

Factors that effect Breaker Selection

• BHT

• Length of open hole

• Fluid Density

• RDF formulation

• Completion assembly

• Condition of RDF

• Completion design

What to use, when to use it & how do you get it What to use, when to use it & how do you get it there?there?

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Field Testing and Evaluation

Monitor fluid properties with :

• Modified HTHP or PPA

• Production Screen Tester

• Brookfield Rheometer

• Solids Determination Test

• etc.

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Production Screen Tester (PST)Production Screen Tester (PST)

• Manufactured in Stainless Steel

• Many parts standard OFI fittings

• Cell capacity - 1200 ml

• Weight - 10.5 kg

• Max. Pressure - 100 psi

• Robust Construction

• Quick and Simple to Use

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Production Screen Tester (PST)Production Screen Tester (PST)

• The RDF is designed utilizing properly sized bridging/ weighting agents.

• The PSD of the bridging/weighting agents meet the required PSD in order not to plug the completion assembly.

ProductionScreen

ReceivingCup

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Example of Screen Plugging

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Example of Screen Plugging

Shale and mud plugging screensShale and mud plugging screensShale and mud plugging screens

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Brookfield Brookfield RheometerRheometer

• Maintaining the Low Shear Rate Viscosity (LSRV) with a Brookfield Rheometer is critical to proper hole cleaning and suspension.

• An LSRV of 40,000 cp at 0.063sec-1 is typical.

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Completion ProcedureCompletion Procedure

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Displacement Of Horizontal Section Prior To Running the Completion Assembly

RDIF RDIF SystemSystemSolids Free pillSolids Free pill

Displace the used RDIF system with a Solids Free pill in the open hole and +500’ inside of the casing

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Displacement of the Casing Above the Displacement of the Casing Above the Horizontal SectionHorizontal Section

Completion brineCompletion brine

Solids Free pillSolids Free pill

Pull hole opener +300 inside casingDisplace the used RDIF system with spacers and completion brinePull out of the hole to pick up screens

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Completion Assembly In Horizontal Section

Completion fluidCompletion fluid


ScreensScreens

Run screens to bottom, set and test packer

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Displace out the Solids Free pill with the completion fluid



Displacement Clean-up procedure

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Displacement Clean-Up Sequence


Breaker solutionBreaker solution

Spot the breaker solution in the open hole and soak for the specified amount of time

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Displacement Clean-Up Sequence


Breaker solutionBreaker solution

After the soak period has elapsed, displace the breaker solution out of hole with completion fluid

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DRILLING WITH

RESERVOIR DRILL-IN FLUIDS

CASE HISTORY

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OPTA-FLO Sized Salt – A Reservoir Drill – In FluidsBackground:

November 2006 : The well Sumandak A-01 was drilled with waterbased mud system HYDRO-FOIL GEN 2- KCL/PHPA to TD at depth1645m MD/ 1330m TVD with 40.7 deg angle and 160 oF BHST. Thewell was drilled with 13 3/8” casing set at 843m MD, 9 5/8” casing at1488m MD with 9.5 ppg. The 8 ½” hole was planned to be open holecompleted where 7” production WWS screen planned to be set at1645m MD through the U1.1 and U1.2 sands. Scomi Oiltools has beenrequested to propose drill-in fluid system for this particular 8 ½”section that has characteristic of non-formation damage and easyclean-up after the production sand screen set.

Scomi Oiltools Solution:

Scomi Oiltools had proposed the OPTA-FLO Sized Salt RDIF whichwas formulated and tailored to the given well data. The productswere carefully chosen and tested in the lab. Final formulation asfollows i.e. saturated NaCl with 3% w/w KCL in brine, MagnesiumOxide 1.0 ppb as pH buffer, clarified starch OPTA STAR PLUS 4.0ppb, High clarity viscosifier OPTA ZAN ( premium grade) 1.5 ppb,with sized salt 5E ( 5µm) 15 ppb and 20E ( 20µm) 31 ppb as bridgingagent. The HyPR-SIZER software program was used to optimize theconcentration and particle size distribution of the bridging agent toensure solids are deposited across the pore throats. OPTA ZYME S,the enzyme breaker was chosen and tested successfully in the lab at3% vol/vol to clean up the mud cake at the well bore.

Operator : Petronas Carigali Sdn.Bhd.

Well Name : Sumandak A-01

Location : Offshore Sarawak, Malaysia

Scomi OiltoolsScomi Oiltools

CASE HISTORYCASE HISTORY

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.

Results:

The well was displaced and drilled with 10.2 ppg OPTA-FLO Sized Salt RDIF from 1488m to 1645m. At TD the holewas then displaced with solids free OPTA-FLO Sized SaltRDIF before running in the WWS screen which was set at1645m as well ( The solid free OPTA-FLO RDIF was earliertested with PST unit to determine the ability of the fluidpassing through the sand screen). The under saturated

brine at 9.0 ppg with enzyme breaker OPTA ZYME S at

3% v/v was pumped inside and at screen annulus todestroy the mud cake and dissolve the salts. The wholeoperation while drilling and completing the well with OPTAFLO sized salt RDIF was without any problem.

Benefits:

Fluids are non damaging to the production reservoir .

The bridging agent that produce external cake are easilyremovable with under saturated brine wash couple with 3%

OPTA ZYME S enzyme breaker.

Improved productivity for U 1.1 and U 1.2 sands fromestimated at 1000 bbls/day to 1800bbls/day ( as informedby PCSB Production Technologist)

For Additional Information, Contact:For Additional Information, Contact:

[email protected]

Operator : Petronas Carigali Sdn.Bhd.

Well Name : Sumandak A-01

Location : Offshore Sarawak, Malaysia

Mud Weight, ppg 10.2

Funnel Viscosity, sec 57-61

PV, cPs 18-19

YP, lb/100ft2 17-18

Gel Strength, lb/100ft2 4-6 / 5-7

6 rpm 6-7

3 rpm 5-6

API Flitrate, ml/30 min 3.8

Chlorides, mg/l 200,000

pH 8.7 - 9.0

LGS, % 2.0 - 2.7

MUD PROPERTIES

OPTA-FLO Sized Salt – A Reservoir Drill – In Fluids

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CASE HISTORYCASE HISTORY

Completion_Reservoir Drill in Fluids

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Transcript of Completion_Reservoir Drill in Fluids