kuliah 4 fluida komplesi ah

8/16/2019 Kuliah 4 Fluida Komplesi AH

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u au a - -

(2 SKS)

. ,Universitas Trisakti - Jakarta


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Objective/ Objective/SasaranSasaran

Memahami konsep-konsep fluida yang

di unakan untuk Kom lesi sumur dan ker a

ulang sumur Memahami enis- enis fluida en elesaian sumur

Memahami penerapannya di dunia Perminyakan


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Daftar Daftar PustakaPustaka

Allen S.O. and Robert A.P. ”Production Operation”, Vol. I Oil andGas Consultant International Inc.

” “ , ,

2004

Peter E. Clark,”Well Completions : Stimulation and Work Over”.

Pertamina Hulu,” Teknik Produksi”, Jakarta, 2003

H.K. Van Poolen,”Well Completion and Stimulations Program”.

Peter E. Clark ”Well Com letions : Stimulation and Work Over”.

Jonathan Billary,”Well Completions Design”, PetroleumElsevier,2009

Semua buku erihal Kom lesi dan u i Sumur

Semua Jurnal tentang Komplesi dan uji Sumur


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Com letion Fluids


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Completion Fluids: Description & ScopeCompletion Fluids: Description & Scope

Description:

This section of the completions training course coverstopics related to completion fluids and their applications.Important properties of clear completion brines and oil-

ase u s are scusse , as we as ssues re a e oformation damage control and safety and the environment.

Participants will become familiar with the compositions,characteristics and uses of a variety of completion fluid

systems.


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Completion Fluids: ObjectivesCompletion Fluids: Objectives

At the end of this section, you should have areasonable understandin of:

• The composition, properties and uses of completion fluids

completion fluids

• Methods of calculating completion fluid densities undervar ous con t ons

• Special considerations when using completion fluids indeepwater applications

• How to work more effectively with vendors in the selectionand utilization of completion fluids


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Completion Fluids: AgendaCompletion Fluids: Agenda

During the next few hours, we will cover the following:

• Fluid Types and Selection Criteria ..…………………. 35 minutes• Crystallization Point and Other Brine Properties …. 45 minutes

• Wellbore Displacement ………..………………..……... 35 minutes

• Fluid Filtration ……….………………………………….. 40 minutes• Fluid Loss Control …….………………………………… 35 minutes

• Formation Damage & Acidizing ………..…………….. 35 minutes

• Safety and Environmental Concerns ………………... 15 minutes

• Total ……………………………………………………….. 4 hours


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Completion Fluids: PracticesCompletion Fluids: Practices

We will describe preferred practices for:

• Completion fluid selection

• completion fluids

• Methods of filtration and maintenance of fluid quality

• Effective control of completion fluid leak-off

• Formation damage control when completing wells and


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Completion Fluids: Key LearningsCompletion Fluids: Key Learnings

We will describe key learnings and best practices for selecting andusin com letion fluids. Im rovements will be made in our:

• Awareness of the strengths and limitations of variouscompletion fluids

• Knowledge of the important characteristics of completion

fluids under a variety of well conditions• Ability to select completion fluids in a cost-effective manner

• Knowledge of methods to improve the properties of heavy,clear brines

• Knowledge of several practical aspects of handling andmodifying completion fluids


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Completion Fluids: ProblemsCompletion Fluids: Problems

We will work through problems to ensure that you understandthe fundamentals of this technolo area includin :

• Evaluation of factors affecting fluid density

• Calculation of fluid properties required for well control

• Determination of filtration requirements for removing


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Fluid Types and Selection CriteriaFluid Types and Selection Criteria


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Completion Fluids & Their Functions

A completion fluid is any fluid pumped downhole

to conduct post-drilling well operations.

Primary Functions

• Effective control of reservoir pressure while performing well work

• Prevention of permanent formation damage

during completion and workover operations


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The Completion Fluids Family

• –

• Drill-in Fluids – for drilling and completing fluid- sensitive a intervals

• Packer Fluids – for filling annular volume above a

production packer

• Workover Fluids – for remedial operations

• –fluid loss to the formation


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Completion Fluid Types (& Examples)

• Clear BrinesKCl, NaBr, CaCl 2 , CaCl 2 /CaBr 2

ZnBr 2 /CaCl 2 /CaBr 2

• Solids-Laden Fluids

Sized CaCO 3 in NaCl

Organosoluble Resin in KCl

• Brine-in-Oil Emulsions

CaCl 2 Brine in Diesel

• Weighted “All-Oil” Fluids

Hi h Densit Or anics in Diesel


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Important Completion Fluid CharacteristicsImportant Completion Fluid Characteristics

• Easil wei hted or diluted for well control

• Non-damaging to the reservoir and wellbore

• a e a sur ace an own o e con ons

• Easily viscosified for solids transport • Safe to handle and environmentally friendly

• Readil available economical and otentiall

recyclable


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Physical and Chemical Propertiesof Completion & Workover Fluids

• Density

• Viscosity

• Thermal Stability

• Chemical Composition

• Corrosiveness• Additive Compatibility

• Formation Compatibility

• Solids Transport Capability

• Environmental Compatibility


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Uses of Clear Brine Completion Fluids

•

• Perforating

• e ng

• Wellbore Washing • Fishing

• Gravel Packing

• Packer Fluids


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Clear Brine Completion FluidsClear Brine Completion Fluids

Brine Type Common Density Range (ppg) Fluid Cost ($USD/bbl)

NaCl (sodium chloride) 8.4 – 10.0 3.00 – 9.00

KCl (potassium chloride) 8.4 – 9.7 3.00 – 31.00

NH4Cl (ammonium chloride) 8.4 – 8.9 10.00 – 19.00

NaBr (sodium bromide) 10.0 – 12.7 67.00 – 180.00

NaCl/NaBr 10.0 – 12.5 10.00 – 170.00

NaHCO2 (sodium formate) 9.0 – 11.1 35.00 – 165.00

KHCO2 (potassium formate) 10.8 – 13.3 335.00 – 356.00

NaHCO2 / KHCO2 8.4 – 13.1 157.00 – 338.00

CsHCO2 (cesium formate) 13.0 – 19.2 Obtain Quote

CaCl 2 (calcium chloride) 9.0 – 11.8 4.00 – 25.00

CaBr 2 (Calcium bromide) 12.0 – 14.2 30.00 – 191.00

CaCl 2 / CaBr 2 11.7 – 15.1 22.00 – 160.00

ZnBr 2 (zinc bromide) 19.2 – 21.0 538.00 – 671.00

ZnBr 2 / CaBr 2 14.2 – 19.2 30.00 - 538.00

ZnBr 2 / CaBr 2 / CaCl 2 14.2 – 19.2 30.00 – 538.00


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Periodic Table of the Elements

• •

• Alkali metal carbonates and sulfates are soluble

• Alkaline earth metal carbonates are insoluble; calcium sulfate has limited solubility


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Brine Density Ranges

Sodium Formate

Sodium ChloridePotassium Chloride

Potassium Formate

Sodium Bromide

Calcium Chloride

Zinc Bromide

Cesium Formate

Calcium Bromide

8.4 9.4 10.4 11.4 12.4 13.4 14.4 15.4 16.4 17.4 18.4 19.4

Maximum Density (ppg)


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Maximum Solubility of Salt in Water (RT)Maximum Solubility of Salt in Water (RT)

Salt Sol Maximum

Density

Specific

Gravity

lbs/bbl

(ppg)

Sodium Chloride 26 10.0 1.200 109 311

. .

Sodium Bromide 46 12.7 1.525 245 288

Calcium Chloride 40 11.8 1.417 198 298

Calcium Bromide 57 15.3 1.837 366 277

Zinc Bromide 78 21.0 2.521 688 194

Sodium Formate 50 11.1 1.333 231 235

Potassium Formate 78 13.3 1.597 434 125


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Practical Aspects of Common Brines

Brine/Salt Properties & Precautions

•

Potassium

Based

, ,

conditions

• Dissolving dry KCl or KBr in water affords noticeable cooling

(endothermic)

• ,

crystalline salts behind

Calcium and

Zinc Based

• Anhydrous chloride and bromide salts are hygroscopic (will

absorb water from air

• Dissolving bromide and chloride salts in water gives off heat

(exothermic)

• Salts wi ll not crystallize from solution under normal conditions

• Solutions will absorb moisture from the air

• Brines are slippery and cannot be “ wiped” up; spills must beflushed with water

• pH elevation may cause precipitation reactions

• Avoid contact with skin or e es as severe irritation can occur


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Completion Brines and pH

Typical completion brine pH values:

• KCl, NaBr, CaCl 2 (pH = 6 to 8)• ZnBr 2 (19.2 ppg, pH = 1 to 1.5)

• ZnBr 2 /CaBr 2 (17.2 ppg, pH = 3.5)

• Formates (NaHCO 2 , KHCO 2 ), pH >9.5

• pH is a measure of the chemical activity of the H + in solution.

• H = -lo H + or H + = 10 -pH H ran es from 0 to 14

• Due to the ionic strength of high-density completion brines, pHmeasurements provide only an indication of the acidity (orbasicity) of the fluid.


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Brine Availability

• Stock fluids manufactured as clear liquids

- =. .

- 12.5 ppg (SG = 1.50) [45%] NaBr - 14.2 ppg (SG = 1.70) [52%] CaBr 2

- 13.1 ppg (SG = 1.57) [78%] KHCO 2

- 19.2 ppg (SG =2.30) [53%/23%] ZnBr 2 / CaBr 2

• Dr stock salts

- NaCl, NaBr, KCl, NH4Cl, CaCl2, NaHCO2, KHCO2

• Fluids prepared from dry salts

- 3-8% NaCl - 3-8% KCl

- 3-8% NH4Cl


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Important Clear Brine Properties

• Density

• pH

• True crystallization temperature (TCT)• Pressure crystallization temperature (PCT)

• Eutectic point (lowest crystallization temp)

• Brine / formation water compatibility • Brine / crude oil emulsion potential

• Brine / formation mineral compatibility

• Chemical compatibility • Availability

• os s


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Completion Brine Selection GuideCompletion Brine Selection Guide

• Assure Compatibility with Formation Brine

- vo seawa er n orma ons w g a , r or a eve s

- Avoid Ca2+ in formations with high HCO 3- or SO 42- levels- Conduct fluid-fluid compatibility testing in the laboratory

• Assure Compatibility with Formation Minerals

- Protective brines for sandstones typically include- ≥ 1% CaCl2; ≥ 2% KCl; ≥ 3% NH4Cl

- Unocal’s “go-to” fluid remains 6% KCl (8.65 ppg)

- Maintain salinities ≥ that of the formation brine

- High clay formations generally require higher salinities- Review formation mineralogy (XRD, SEM & Thin Section Data)

- Conduct core flow studies for sensitive formations


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Completion Type Log for UIC’s Attaka Field


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Completion Type Log for UIC’s Santan Field


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Completion Type Log for UTL’s Surat Field


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Compatibility Flow ChartCompatibility Flow Chart – – MI SwacoMI Swaco

Spacers v. Mud

Spacers v. Brine

Formation

Crude v. Brine

Formation Water FP/GP Gel v.

FLC Pills v.

Brine

FLC Pills v.Formation

Brine v. Control

Lines

Hydraulic Fluid

Displacem

ent

Perforation FP/GP Remove

Tools

Run

Tubing S acers v. Cement

.

Brine v. Mud & Formation v.

Fluids

FLC Pills v.

.

Inhibitor v.

Brine v. Mud

Mud Filtrate

Brine v.Formation Clays

Pre-Pack Acid

Formation v.FP/GP Gel

Formation

FLC Pills v.Sand Control

Hardware

Tubulars

Brine v.Tubulars

Brine v. ChargeFluids

Brine v.Elastomers

Insulating Fluidv. Tubulars


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Advantages of Formate Brines Advantages of Formate Brines

M +O

O

CH - M + = Na+, K +, Cs+

• Practical alternative to intermediate-density divalent brines

•

• Highest densities among all monovalent brines (up to 13.3 ppg for

potassium formate; 19.2 ppg for cesium formate)• When viscosified with XC polymer, transition temperatures are

retained (i.e., viscosities are maintained at higher temperatures)

•

• Above 8.7 ppg, bacterial growth is inhibited; upon dilution,formates biodegrade


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Completion Brine Additives

• Biocides – to control bacteria, especially sulfate-reducing bacteria

• H Buffers – to maintain o timum H ran e for s ecific fluidsystem

• Sulfide Scavengers – to minimize time effects of sulfide

• Oxygen Scavengers – to retard oxidation

• Corrosion Inhibitors – to protect pipe from chlorides

• Surfactants – to prevent secondary emulsions, improve wellrecovery after workover, minimize fluid retention, etc.

–

the completion fluid

• Polymeric Clay Stabilizers – to further protect against clay

s ur ances


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Oil Based Fluids - Advantages

Oil External Emulsions and “All-Oil” Fluids

• Inhibitive to shales and clays

• Excellent lubricity

•

• Wide range of densities possible

• ompa e w many o -pro uc ng orma ons


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Oil Based Fluids - Limitations

• Disposal. Oil based fluids present significant disposalchallenges; toxic halogenated densifiers in “all-oil” fluidsfurther complicate after-use handling.

• Halogenated Organics. Halogenated densifiers in “all-oil”

high temperatures; halogens can also poison refinerycatalysts.

• ur actants an mu s ons. mu s ers n r ne- n-oemulsions may afford wettability changes and emulsification offormation water; emulsions may block pore throats.

• Low Baseline Density. Oil based fluids require significantamounts of weighting agent to build density from a baselinedensit of 6.5 .


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Packer Fluids

Packer fluids represent a special class ofcompletion fluids designed to provide:

• Weight and pressure on production packers andseals

• Pressure support for the production tubing

• Pressure support for the casing -- to offset formation

forces

• Thermal conduction or insulation for the productiontubing flowing fluids

• n on aga ns corros on an po en a ac c gasseepage from production hardware

• Ease of re-entry and hardware recovery in workoveroperations

Baro

id


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Additional Packer Fluid Issues

• In addition to providing the necessary properties cited previously, packer fluids should be simple to formulate

and economical.

temperature range (e.g., deepwater applications) and fora prolonged period of time.

• Must accommodate a range of additives without showingsigns of incompatibility.

• during a workover operation.


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Packer Fluid Components

Packer Fluid System Typical Additives / Adjustments

-

(Not Recommended)

. .

Sulfide inhibitor

Biocide

Oxygen scavenger

Fresh Water / Salt Water

(including gelled fluids)

Sulfide inhibitor

Biocide

Oxygen scavenger

Oil

(including gelled fluids)

Corrosion inhibitor

Biocide

Oil Based Mud Surfactant stabil izer

(Not Recommended) Biocide

Heavy Brine (CaCl2, CaBr 2, ZnBr 2,

or combinations thereof)

Corrosion inhibitor

Oxygen Scavenger Baro

id


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Other Brine Properties


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Crystallization Point

The Cr stallization Point is the tem erature atwhich crystals begin to fall out of solution, givensufficient time and proper nucleating * conditions.

* Nucleation is the process by which insoluble

crystals can form. Dust, silty particles, andsuspended fines are potential nucleating agents.


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TCT v. PCT

TCT = True Crystallization Temperature

PCT = Pressure Crystallization Temperature

Effects of Crystallization

• Brine densit chan es

• Flow line restrictions can develop

• May cause difficulties in re-establishing desired density

• Physical properties will change (viscosity, etc.)


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Idealized Crystallization Point Curve

FCTA – First-Cr stal-to-A ear u oncooling of completion fluid

TCT – True Crystallization Temperature

LCTD – Last-Crystal-to-Disappearupon re-heating fluid

Cool Heat

r a t u r e

TCT LCTD T e m p

FCTA

Time


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Ocean TemperatureOcean Temperature -- Depth ProfileDepth Profile

(www.windows.ucar.edu)


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Clear Brines – The Eutectic Point

The Eutectic Point is thelowest freezing point of a solution.

• The addition of fresh water to a brine whose density is abovethe Eutectic Point lowers the density and lowers the TCT.

• The addition of fresh water to a brine whose density is belowthe Eutectic Point lowers the density and elevates the TCT.

Eutectic Point


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TCT Curves for Various BrinesTCT Curves for Various Brines

Sodiumchloride

Potassiumchloride

Calcium

Density


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Crystallization Temperature CurveCrystallization Temperature Curve

Pressure Increases

PCT Region

Crystallization

TemperaturePressure DecreasesCrystallization

Hydrate Region

Ice and Brine Salt and Brine

Density


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Effects of Pressure on TCT

• In High Pressure, Low Temperature (HPLT) conditions(e.g., deepwater), higher pressure can elevate TCT.

• Based on SPE 58729 (Freeman, et. al.), PCT (Pressure*

= . ,

* Relationship applies to a variety of calcium chloride,, .


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Clear Brines and Gas Hydrates

What are Gas Hydrates?

• Gas hydrates are solid assemblages of cage

complexes composed of water molecules surroundingsmall hydrocarbon molecules or other light gases.The t icall form when li uid water coexists withnatural gas under high pressures and lowtemperatures (HPLT).

• Gas hydrate formation is a special concern for deep“ ” .may completely block fluid flow.

• Variations in P, T, salinity, free water content and gascomposition present operational challenges forcontrolling and removing gas hydrates.

• Take care to prevent gas hydrate formation in the first place (work with flow assurance specialists and the

http://geology.usgs.g ov/.../

. _ e.htm


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Hydrate Inhibition with CaCl 2 at 40° F

Hydrate Region

9%MEG

Hydrate Free Region

MEG


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Gas Hydrate Curves (CaCl 2 /CaBr 2 )

0.725

10.4 ppg CaCl 2

12.0 ppg CaBr 2

Hydrate Region

Hydrate Free Region

B i D i


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Brine Density

Brine density varies with temperature and pressure:

• As temperature increases, density decreases

• s pressure ncreases, ens y ncreases

Deepwater Gulf of Mexico

Water Depth = 7,100’

Mudline Temp = 38 deg F

MD = 14,000’

SBHP = 6,550 psi

=

Completion Fluid

200 psi Ubal = 9.24 ppg

Th T D it f Cl B i


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The True Density of a Clear Brine

• Temperature Expansion Factor

• Pressure Compression Factor

• Compensated Column Density @ TVD

C id ti f D W t W ll


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Considerations for Deep Water Wells

• Riser Compensated Column Density(inverse function of temperature gradient –surface to mud line)

• Sub-Sea Compensated Column Density

Mud Line

Fluid Cooling Down

Fluid Heating Up

St t C l l t th A Fl id D it


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Steps to Calculate the Average Fluid Density

1. Calculate the average well temperature.

2. Calculate the average temperature increase overthe API standard measurement temperature.

3. Calculate the density loss due to temperature.

4. Calculate the avera e h drostatic ressure.

5. Calculate the density gain due to pressure.

. .

Example Problem:


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Example Problem:

A 12.0 ppg NaBr brine (70 o F) is to be

used as a completion fluid for a wellw per ora ons a , - , . eBHT is 230 o F. What will be the average

wellbore density of the NaBr brine at the perforations?

Solution to Example


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Solution to Example

The following steps are necessary to calculate

1. Calculate the average well temperature (AT).

. a cu a e e average empera ure ncrease overthe API standard measurement temperature (ATI).

. .

4. Calculate the average hydrostatic pressure (AH).

5. Calculate the density gain due to pressure (DG).6. Calculate the average wellbore density (AD).

Solution to Example Step #1


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Solution to Example – Step #1

AT = (BHT + ST)/2

BHT = Bottom Hole Temperature, o F

ST = Surface Tem erature of Fluid, o F

AT = (230 + 70)/2 = 150 ° F



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. API standard measurement temperature (ATI):

ATI = AT – 70 F

= ° - ° = °



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3. Calculate the density loss due to temperature (DL):

DL = ATI x Cf

ATI = Average temperature increase over the API standard, ° F

= ° ,

Table 1

Temperature Correction Factors (ppg/o F)

NaCl or KCl 0.0024

CaCl2 0.0027

DL = ATI x Cft

DL = (80 ° F x 0.0033) = 0.264 ppg .

CaBr 2 or CaBr 2 / CaCl2 0.0033

ZnBr 2/ CaBr 2/ CaBr 2 ( . .



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4. Calculate the average hydrostatic pressure (AH):

AH = (SD – DL) x 0.052 x TVD

SD = Surface density at 70 ° F, ppg

DL = Density Loss due to Temperature, ppg

0.052 = Constant = 12 in/ft x 7.48 gal/ft 3 x1 ft 3 /1728 in3, in gal/in2 -ft

TVD = Well depth to mid-perf, ft

AH = (12.0 – 0.264) x 0.052 x 10,000 = 6,102 psi



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5. Calculate the density gain due to Pressure (DG):

= x p

AH = Average hydrostatic pressure, psi

Cf = Pressure correction factor / si

Table 2

Pressure Correction Factors

NaCl or KCl 0.000019

CaCl2 0.000017

DG = AH x Cfp = (6,102 x 0.000021)

= .

CaBr 2 or CaBr 2 / CaCl2 0.000022

ZnBr 2/ CaBr 2/ CaBr 2 (

. .



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6. Calculate the average wellbore density (AD):

AD = SD – DL + DG

AD = (12.0 – 0.264 + 0.128) = 11.864 ppg

So, the NaBr brine with a surface density (SD) of 12.0would have an avera e wellbore densit of 11.864

ppg at 10,000 ft (BHT = 230 o F)

JENIS FLUIDA C/WO JENIS FLUIDA C/WO


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--

SolidsSolids--Laden FluidsLaden Fluids

•• Dri ing F ui sDri ing F ui s•• Lease Water or SeawaterLease Water or Seawater

SolidsSolids--Free Brine SystemsFree Brine Systems


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==maupun tinggi)maupun tinggi)

Hi h densit brines meru akan fluida C WO anHi h densit brines meru akan fluida C WO an paling aman (tidak mengakibatkan banyakpaling aman (tidak mengakibatkan banyakkerusakan formasi)kerusakan formasi)



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--

Terdapat dua jenis brines: monovalent dan divalentTerdapat dua jenis brines: monovalent dan divalent

-- Monovalent : NaCl, KCl, NaBrMonovalent : NaCl, KCl, NaBr

-- Divalent : CaClDivalent : CaCl22, CaBr, CaBr22



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Walaupun ZnClWalaupun ZnCl22 dan ZnBrdan ZnBr22 keduanya secara tekniskeduanya secara teknis--

salt brine akan tetapi tidak praktis dan tidaksalt brine akan tetapi tidak praktis dan tidakekonomisekonomis

ZnClZnCl22 dikenal sangat korosif sedangkan ZnBrdikenal sangat korosif sedangkan ZnBr22 sulitsulitditangani karena sangat hygroscopic.ditangani karena sangat hygroscopic.



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NaCl dan KCl brines biasanya dibuat denganme arut an r sta garam er ng engan a r arena

densitas maximum yang dapat dicapai relatif rendah;bila dijual dalam bentuk larutan biaya angkutanmenja i ma a arena a anya tam a an erat air.

NaBr biasanya dibuat dari garam kering atau tersedia

dari su lier dalam bentuk larutan ekat den an densitas sesuai dengan kebutuhan.



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Jika diperlukan, concentrated NaBr diencerkan dilokasi dengan manambah air untuk menurunkan

densitas. Pengenceran pada umumnya dilakukan



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CaCl2 dan CaBr2 brines tersedia dalam bentuklarutan. Pembuatan brines di lapangan dari garam

- bubuk CaCl2 dan CaBr2 merupakan,

- pelarutan bersifat eksotermik dan

atas titik didih air sehingga

dianggap hazardous operation



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Garam kering CaCl2 dan CaBr2 biasanya digunakan

hanya untuk mengatur harga densitas (density.



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Multiple salt brines:

Dibuat dari aram monovalent aram divalent atau campuran dari keduanya

Formulasi yang umum digunakan adalah CaCl2 /CaBr2,CaBr2 /ZnBr2, dan CaCl2 /CaBr2 /ZnBr2

Multiple salt brines dari garam mono-valent secara

,karena tidak ekonomis



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Keuntungan multiple salt brines: dapatormu as an un u memenu persyara an ens y

dan temperatur kristalisasi.



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Pengujian kualitas brines

relatif atau sering disebut nephelometric turbidity.nephelometric turbidity.

Diukur dengan nephelometernephelometer (alat yang mengukurntens tas ca aya yang e o an o o e a anyapadatan dalam suatu larutan). Makin besar intensitasyang dibelokkan berarti fluida makin keruh.



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Pengujian kualitas brines (lanjutan)

voltage dalam suatu photocell dan diberi satuan yangdisebut nephelometric turbidity unit (NTU).

Spesifikasi kejernihan single-salt brines berkisar antara3 – 10 NTU

Nephelometry juga digunakan untuk menentukanefektifitas wellbore clean up dan filtrasi fluida

Formate Formate Brines Brines


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Mulai diperkenalkan di awal 90-an dalam upayamencari high-density brines yang environmentallyfriendly.

Jenis dan SG maximumnya:

NaCOOH (SG 1,33), KCOOH (SG 1,60) dan CeCOOH(SG 2,37).

- maupun low-solids C/WO fluid.



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Kelebihan formate brines:

Non-hazardous dan biodegradable

Dapat melindungi viscosifyer dan polymer dari degradasi

termal hingga 150oC.

Korosivitas lebih rendah dibandingkan alkali metal halides(klorida dan bromida).

ion sulfat maupun carbonate (mengurangi kemungkinanpresipitasi).



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Kelebihan formate dari segi teknis dan HSE sangatterasa pada aplikasi sumur dalam yang memerlukandensitas tinggi. Saat ini untuk kasus yang demikian

digunakan C/WO fluid yang mengandung ZnBr2. Namun

korosif dan toxic. Untuk mengatasi hal ini dapatdigunakan caesium formate (SG 2,3) yang non-

2

Solids Solids- -Free Brine Systems Free Brine Systems


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SifatSifat--sifat brinessifat brines

DensitasDensitas

Viskositas Viskositas

Densitas Densitas Brines Brines


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Densitas Standard Brines

CaBr2/ZnBr2

ZnBr2

NaBr

CaBr2

a a r

NaCl

CaCl2

KBr

KCl

8 10 12 14 16 18 20 22 24

Density, ppg

DENSITAS SINGLE DENSITAS SINGLE--SALT BRINES SALT BRINES


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Densitas, ppg Densitas, ppg

• Larutan KCl 8.4 - 9.7

• Larutan NaCl 8.4 - 9.8

• Larutan KBr 8.4 - 11.5

2 . - .• Larutan NaBr 8.4 - 12.4

• Larutan CaBr 2 14.2 - 15.5 • Larutan ZnBr 15.0 - 21.5

DENSITAS MULTIPLE DENSITAS MULTIPLE--SALT BRINES SALT BRINES


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Densitas Densitas, , ppg ppg

• KCl/KBr 9.8 - 11.5

• NaCl/CaCl 2 10.1 - 11.1

• NaCl/NaBr 10.1 - 12.5

• CaCl 2 /CaBr

2 11.7 - 15.1

• CaCl 2 /ZnBr 2 /CaBr 2 15.1 - 19.2

• NaBr/ZnBr 12.5 - 20.5

• CaBr 2 /ZnBr2/NaBr 12.5 - 22.5

Efek Efek TT dan dan PP Pada Pada Densitas Densitas


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n s i t a s

60F

1 F14,7 psi

100F10.000

psi

D

V o l u m

14,7

psi

60F

10.000 psi

Perhitungan Perhitungan Densitas Densitas


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⎤⎡ n

⎦⎣

−−

=i

m

1))()(())()(( Dg A Dg B T pi ∆−∆=∆ ρ

= average wellbore density,ppg

m =surface fluid density, ppg

i =incremental density change n = number of intervals



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))()(())()(( Dg A Dg B T pi ∆−∆=∆ ρ

A = thermal expansion coefficient, ppg/oFB = pressure compressibility coeff., ppg/psi∆D =(Di-1- Di) =length of interval, ft

= - =, - ,gT =(Tbh-Tsurf )/D=temperature gradient, oF/ftD=total vertical depth (TVD), ft

A dan B di eroleh dari tabel

ExpansibilityExpansibility dan dan Compressibility Compressibility


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A BBrine ppg

NaCl 9.42 0.24 0.019. . .

NaBr 12.48 0.33 0.021

. . .ZnBr2/CaBr2/CaCl2 16.01 0.36 0.022

. . .

A: from 76 to 198 F at 12000 psi



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Aproksimasi dilakukan berdasarkan hargam po n , m sa nya pa a . apa

digunakan densitas rata-rata yang dihitunger asar an an pa a . .

Men in at efek P tidak be itu besar makaseringkali koreksi dilakukan hanya untuk efek tem eratur.



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• Dasar perhitungan: P hidrostatik

• Operasi dilakukan dengan overbalance:>

terhadap T dan P).

reservoir minyak dan 300 psi untuk

.



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Tentukan P hidrostatik berikut overbalance-nya,misaln a P si ada kedalaman D ft.

Tentukan density, ppg = P/(0.052 D)

Tentukan temperatur rata-rata sumur:= dasar sumur+ permukaan

Koreksi densitas brines berdasarkan temperatur rata-rata

tersebut Konversikan densitas tersebut ke kondisi 60oF (brines

biasanya dijual berdasarkan standar temperatur = 60oF)

Contoh Contoh

S b i t h


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•Sebagai contoh,kalau perlu 10ppg engan s s m

CaCl2 pada 130o

F,

dan ikut garismiring untuk

men apa andensitas pada60oF dida at 10.2

Gb.4.Densitas vs.T ppg.

Untuk Sistim CaCl 2

Gb. 5. Densitas vs. T untuk Sistim CaBr Gb. 5. Densitas vs. T untuk Sistim CaBr 2 2


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Gb.6. Densitas vs. T sistim CaCl Gb.6. Densitas vs. T sistim CaCl 2 2 /CaBr /CaBr 2 2


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Gb. 7. Densitas vs. T Sistim CaCl Gb. 7. Densitas vs. T Sistim CaCl 2 2 /Zn/CaBr /Zn/CaBr 2 2


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Pembuatan Pembuatan C/WO BrinesC/WO Brines di di Lapangan Lapangan


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Dilakukan dengan cara:

Mencampurkan serbuk garam dengan air

MencampurkanMencampurkan larutanlarutan garamgaram dengandengan airair

MencampurkanMencampurkan serbuk serbuk garamgaram dengandengan larutanlarutan garamgaramlainlain

MencampurkanMencampurkan suatusuatu larutanlarutan garamgaram dengandengan larutanlarutangaramgaram lainlain

Pembuatan Pembuatan Lar Lar.. NaBr NaBr dari dari Serbuk Serbuk NaBr NaBr + Air + Air


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Pembuatan Pembuatan Lar Lar. CaCl2/CaBr2. CaCl2/CaBr2 dari dari Serbuk Serbuk CaCl2CaCl2 dan dan CaBr2 + Air CaBr2 + Air


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Pembuatan Pembuatan Lar Lar.. NaBr NaBr dari dari NaBr NaBr 12,512,5 ppg ppg + Air + Air


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Pembuatan Pembuatan Lar Lar. ZnBr2/CaBr2. ZnBr2/CaBr2 dari dari Lar Lar. ZnBr2 19,2. ZnBr2 19,2 ppg ppg dan dan Lar Lar. CaBr2 14,2. CaBr2 14,2 ppg ppg


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Pembuatan Pembuatan Lar Lar. CaCl2/CaBr2/ZnBr2. CaCl2/CaBr2/ZnBr2 dari dari Serbuk Serbuk CaCl2CaCl2 dengan dengan Lar Lar..CaBr2 14,2CaBr2 14,2 ppg ppg dan dan Lar Lar. ZnBr2/CaBr2 19,2. ZnBr2/CaBr2 19,2 ppg ppg


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19.2 ppg ZnBr2/CaBr2

14.2 ppg CaBr2

97% CaCl2 krist

QUESTIONS ? QUESTIONS ?


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44


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1. Sebutkan jenis –jenis fluida komplesi

2. Apa keuntungan dan kerugian fluida komplesi

kuliah 4 fluida komplesi ah

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