Flow Assurance and Production Chemistry Corecloud1.activelearner.com/contentcloud/portals/hosted3/PetroAcademy/...Production Chemistry Core Why This Module Is Important Understand

Introduction

Flow Assurance and Production Chemistry Core

Why This Module Is Important

Understand and identify system conditions and problems

Apply production chemistry principles

Optimum Flow Rates

Flow Assurance and Production Chemistry Core ═══════════════════════════════════════════════════════════════════════════════════

©PetroSkills, LLC. All Rights Reserved. _________________________________________________________________________________________________________

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• Paraffins• Scales• Asphaltenes• Hydrates• Emulsions• Clay migration• Fluid retention• Corrosion• Upset rock wettability

conditions• Other typical oilfield

challenges

• Mechanical • Chemical

Possible Impediments Remediation Methods


Oilfield Chemistry Applications

Problem Prevention

RemediationMethods

Fix Ignored Problems



2

Examples

OutcomePlanPrevention Method

1

2

Regular chemical treating process

Identification of wellbore and in-plant scales

Compatibility of both wellbore and plant treatment methods and chemicals

Selection of chemical treatment of emulsion conditions

Identification of “true formation damage” conditions

Deny high fluid viscosity condition to limit or even possibly curtail production

Examples


1

2

Regular chemical treating process

Identification of wellbore and in-plant scales

Compatibility of both wellbore and plant treatment methods and chemicals

Selection of chemical treatment of emulsion conditions

Identification of “true formation damage” conditions

Deny high fluid viscosity condition to limit or even possibly curtail production

Save now? Or later?



3

Examples


3Identification of conditions wherein capillary pressure principles “trap” fluid treatment volumes from being produced back after a treatment job, thus maintaining “kill fluid” volume effects in the reservoir

Application of solvent and surfactant chemistry to break the capillary effects, thus free up trapped fluids

Increased production from a treated well



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Paraffins and Asphaltenes


Learning Objectives

This section will cover the following learning objectives:

Identify characteristics of both paraffin waxes and asphaltenes

Identify the primary causes of paraffin wax and asphaltenedeposition

Outline the mechanical and chemical treatment methodsavailable to minimize costs and maximize production whendealing with organic scale problems

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Different Crude Oil Samples

SOURAKHANY

Caucasus – Azerbaijan

Clear / Light / Sweet

Used as Medicine

ARABIAN LIGHT

Middle East

Reference

Medium

Sulfur

Barrow Island

AUSTRALIA

Light Crude

Very Few

“Heavies”

BRENTNorth SeaLow Sulfur

Medium oAPI

PARENTISFranceLight

Sweet

Heavier Molecular Weight = Darker Crudes


ARABIAN HEAVY

Low oAPI

High Sulfur

PENNSYLVANIA

Very Pure

Lubricant

without

Refining

SANTA BARBARA

Offshore Calif

High Sulfur

Medium oAPI

BOSCAN

Venezuela

Very Heavy

High Grade

Asphalts

ALTAMOUNT UTAH

Highly

PARAFFINIC

Solid at

Std Conditions

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ARABIAN HEAVY

Low oAPI

High Sulfur

PENNSYLVANIA

Very Pure

Lubricant

without

Refining

SANTA BARBARA

Offshore Calif

High Sulfur

Medium oAPI

BOSCAN

Venezuela

Very Heavy

High Grade

Asphalts

ALTAMOUNT UTAH

Highly

PARAFFINIC

Solid at

Std Conditions

Refineries have specific limits in the amount of sulfurpermitted in crude oil.

The limits are regulated by crude sampling analyseswhere different crude properties are determined,such as molecular weight of the crude and APIgravities.

Mainly straight chain paraffins (C15 to C100)

Approximately C15 to C40 form crystalline wax

Approximately C40 to C100 form microcrystalline wax

Wax/paraffins are very useful for refineries – high qualityfeedstock

What is Wax ?

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Normal Pentane

PARAFFIN SERIES

Alkane

Differences: Asphaltene and Paraffins

Asphaltene• Melts slowly, gradually

softening to a thickviscous liquid

• Burns with a smokyflame

– Leaves a thin ash orcarbonaceous ball

Paraffin• Melts over a narrow

temperature range• Hot liquid has low

viscosity• Burns rapidly with less

smoke than asphaltene– Leaves little residue

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Paraffins

Paraffins

Natural Constituent of Most Crudes• Alkanes of high molecular weight:

C18 [melts at 82F (28°C))] – C70 [melts at 120°F (49°C)]

• Liquid at reservoir conditions form as wax if temperature is less thancloud point or gas/light hydrocarbons flash: Solubility decreases

• Deposited as: Mushy liquid/firm hard wax (solid)

• Waxy coating may also contain silts sand, corrosion products, oil,water, chemicals, and asphaltenes

• Usually melts between 100°F (38°C) and 180F (82°C)

• Hardest waxes (highest molecular weight/highest melting point)deposited first

• High flow rate selectively removes softer waxes (leaves hard wax)

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Example of Paraffin Build-up in Flowline

Typical Paraffin Problems

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What are the issues for production?

When crude cools, wax comes out of solution• Cloud Point (CP) = Temp at which wax crystals starts forming• Wax can deposit on cold metal surfaces

Temperature below which crude flow ceases• Pour Point (PP) = At low enough temperature, a crude oil becomes

highly viscous/becomes a gel – Does not pour• Minimum and maximum pour points exist

Temperature above which solidified wax must be heated to allowflow = Inversion Temperature

Flow Assurance issues:• For temperatures in between CP and PP – Wax deposition• For temperatures below PP – Flow line blockage and restart issues

Wax/Paraffins Viscosity

Temp.

Lo

g V

isco

sity

WAT = Wax Appearance Temp

CP = 35°C

PPmax = 30°C

Tres = 51°C

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Cloud Point Determination

(23°C)

(71°C)(49°C)(27°C)(4°C)

(0.00005 m2/s)

(0.00001 m2/s)

(0.000005 m2/s)

(0.000001 m2/s)

Vis

co

sit

y C

en

tis

tok

es

Temperature - °F (°C)

(m2 /

s)

CP - 73°F

Cloud Point Determination

(23°C)

(17 °C)

(82°C)(49°C)(27°C)(4°C)

Vis

co

sit

y –

Ce

nti

sto

ke

s (

m2/s

)

(0.00005 m2/s)

(0.00001 m2/s)

(0.000005 m2/s)

(0.000001 m2/s)

(°C)

CP - 73°F

CP - 62°F

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The lowest temperature at which a crude oil will flow in the absence of shear

The temperature at which the first crystals appear in a crude

ASTM D 2500-66 (But Not Applied / Used in Field)

Analysis of Paraffins

ASTM D 97-66…Changed to D97-09

To determine Cloud Point

To determine Pour Point

Paraffins BELOW Cloud Point

NOT VISIBLE in Transmitted Light

VISIBLE in Polarized Light

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What Does Paraffin Look Like?

Wax deposition in pipeline

Wax crystals under the microscope

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Paraffin Deposition

Wax deposits because of loss of solubility of higher molecular weight paraffins (C-18 to C-70) in the crude

Paraffin is not BS&W; it is a sales product

Heat to keep paraffin in solution; API says heat to 140°F (60°C) but a higher temperature may be necessary to keep wax in the solution

BS&W =Bottom

Sediment inWater

Paraffin Problems

Paraffin problems vary among wells in the same reservoir due to:

Crude oil composition

Pressure drop

Producing procedures

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Paraffin Induced Production Problems

Deposition in pore system

Deposition in perforations

Plugging in artificial lift equipment

Coating on rods, tubing or surface flowlines

Deposition in flow lines

Deposition in separators

Plugging of filters

Plugging of mist extractors

………More…….

COOLING: The Primary Cause of Deposition

Gas expansion• Due to pressure drop as

oil moves through thewellbore towards thesurface

• Due to pressure dropthrough perforations,chokes and otherrestrictions

Dissolved gas getting freefrom solution

Reduction of productionflowrate

Expansion in vessels,valves, diameter change

Expansion in transfer lines

Cooling in exchangers

Top of separators andstabilization units

In Wells: In Surface Operations

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Conditions Favoring Deposition in Wells and Surface Units

Intermittent well production

Contact of pipe with cold aquifer

Rough pipe surface

Effects of formation fines

Higher Production rates

Increase in Gas/Liquid Ratio (GLR)

Use of Cooling Units

Use of Chemicals

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Remedial Treatment for Paraffin

Scraping wells

Reheating fluids – Hot oil,steam, hot water

Pigging of flow lines

Use chemicals• Solvents, water base

solutionsUndoped

Doped

Hot Oil Truck for Well Applications

Heater on truck heats oil to 150°F (66°C) – 300°F (149°C) for wellplacement

Objective is to heat oil above paraffin melting point

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Hot Oil Treatment

Treatment

(93°C) (93°C) (93°C) (93°C)

Keep HOT OIL off the formation to avoid paraffin

dropping out and causing damage

Use of Heat for Paraffin to Go Into Solution

Hot oil dissolves and melts paraffin

Formation damage occurs if wax in solution in the hot treating oil contacts formation

Steam is used to melt paraffin or asphalt in flowlines, wells and formations

Hot water is often used in low temp wells

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Limit Hot Oiling Problems

Use best oil available

Use top oil (lightest available oil)

Treat oil before using

Change to another fluid if necessary

Insights into Good Oiling Practices*

Paraffin treatment design should be specific to each well

Frequency of treatment should be minimized

Good quality fluid should be used

Injection should be down the annulus

Tubing should be full and producing oil, not gas alone

BTUs / hour injected should be maximized

The volume injected should be limited

Thermodynamics alone should not be the deciding factor inchoosing between hot oil and hot water

* SPE 25484

SPE‐25484COPYRIGHT



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Criteria for Alternate Fluid

Contain no paraffinic or asphaltenic materials

Accept and transfer heat effectively

Not lead to damage of the formation pore system, with orwithout chemical aids

Be readily available and not costly

Have attributes that chemically clean well system

Chosen Treating Fluid should:

Selecting Solvent for Wax Solubility/Modification

Immerse a small amount of wax in solvent in clear glass containers

Side by side comparison will allow solvent selection in minutes

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Methods for Minimizing Paraffin Deposition

Solvents

Dispersants

Plastic Pipe or Coating

Surfactants

Crystal Modifiers

Adopt Adequate Production Techniques

Typical Crystal Modifiers

Polyethylene (a polymer)

Polyalkylmethacrylate(a polymer)

Ethylene/Vinyl Acetate (a co-polymer)

Maleic Anhydride/Alpha (a co-polymer)

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Wax Treatment with Dispersants

Use water soluble dispersants

Dispersant system is usually 90% to 98% water

Heating of solution usually aids in wax removal

4‐hour soak aids in removal of very hard paraffin

Solvents for Paraffin Deposit Removals

Condensate

Kerosene

Diesel

Benzene

Toluene

Xylene

Non-Toxic, Biodegradable Solvents

Only if asphaltenecontent is low

Not recommended!

Newer, more costly

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Solvents for Paraffin Deposit Removals

• Is not miscible with water

Xylene

• Getting xylene across the perforations where wax is present isdifficult due to its low density (about 7 pounds/gallon (1.85 kg/l))

• Therefore, it tends to float

• Displacing xylene with water enhances the tendency of xyleneto float

• As a result, large volumes of xylene must often be pumped tooffset the above

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Asphaltenes

Ring Chain – Single Bonds

HH

H

H

H

H

H

H H

H

C

C

C

C

C

Asphaltene Series

CycloPentane(C5H10)

CycloAlkanes

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Differences: Asphaltene and Paraffins

Melts slowly, gradually softening to a thick viscous liquid

Burns with a smoky flame

• Leaves a thin ash or carbonaceous ball

Melts over a narrow temperature range

Hot liquid has low viscosity

Burns rapidly with less smoke than asphalt

• Leaves little residue

Asphaltene Paraffin

Asphaltenes Characteristics

Natural Constituents of Many Crudes• Black PolyCyclic Aromatic (CycloAlkenes) are complex• Spherical (30–65 Å) (MW 10,000–100,000): Surrounded by Resins

and Aromatics H-C • Liquid or Colloidal Suspension• Deposited at lower T and P based on Composition• Destabilized by Acid, CO2, Injection

– Shear (Turbulent Flow), Crude Mixing, Iron Ions, Heavy Metals

• Attaches to Clay / Sand: Makes Oil – Wet• Insoluble in Distillates: Kerosene, Diesel• May Also Contain Oxygen / Nitrogen / Sulfur Molecules

– If so, may be Electrically Charged

• Stabilize Emulsions• Asphaltenes do not Melt, but do Decompose

– At Temperatures > 302 F (150 C )

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Asphaltenes

Crude Oil from Belmont Offshore

Deep Zone Field, Well #10

API Gravity - 26.7 at 60°F (16°C)

Asphaltene Obtained

From the Crude Oil

34% by Volume

If it is greenish color, it does not contain

asphaltenes.

If an oil sample is black, it contains asphaltenes.

Asphaltenes

Broad Softening Point: Melts Slowly to Viscous Fluid

• Decompose at T > 302F (150C)

Typical Compositions• 9 API crude: 82%

Asphaltenes

• 41 API crude: 3.4% Asphaltenes

– Asphaltene content does NOT predict problem

Venezuela Boscan Crude

Hassi Messaoud Crude (Algeria)

• 0.1% Asphaltenes –Big problems

17% Asphaltenes

No problems

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Asphaltenes

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Asphaltene Deposition

May separate from asphaltenic crude and deposit in formation, usually near wellbore

Deposition will reduce the relative permeability to oil by oil-wetting the sand

Physical pore plugging can occur

Asphaltenes are a more severe problem than paraffins

Asphaltene Deposition

Temperature and Pressure Changes, Asphaltene Depositional Envelope – ADE

Change in surface electrical charge of asphaltene due to streaming potential, as oil flows through the pore system

Contact of crude oil with acid used in stimulation treatment

Change in asphaltene / maltene resin equilibrium when contacted by straight chain hydrocarbon

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Asphaltene Deposition Envelope (ADE)

Temperature

Pre

ssu

re

Pres

ADE =

AsphalteneDepositional

Envelope

Asphaltenes and Paraffins

Asphaltenes VISIBLE

Paraffins not VISIBLE

Asphaltenes VISIBLE

Paraffins VISIBLE

TRANSMITTED LIGHT POLARIZED LIGHT



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Solubility of Asphaltenes

Asphaltenes are Soluble in:

Benzene

Toluene

Xylene*

Carbon Tetrachloride

Carbon Disulfide

* The only solventrecommended for welltreatments

Asphaltenes are Insolublein:

Distillates

Kerosene

Diesel Oil

Propane

Butane

Sludge is a Precipitate

Often caused by:• Contact with acid and enhanced by Fe in solution

When attempting to recover treating fluids, do not pumpmethanol into formations containing asphaltenes (to avoidprecipitation)

Oilfield sludge often consists of:

Asphaltenes

Other high weight hydrocarbons

Resins

When pumping alcohols down hole, any asphaltene in the

wellbore region crude will likely come out of solution.

Methanol is often used to reduce surface tension, interfacial tension, and

capillary pressure.



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Prevent flocculation of colloidal particles

Anti-Sludging Surfactants

Solubilize sludge, and

Anionic or Non-anionic blends

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What are the Options for Both Paraffins and Asphaltenes

What are the Treatment Options / Solutions?

Mechanical• Heat retention – Insulation, heat tracing• Physical removal of wax – Pigging• Heat via hot oil, hot water or steam

Chemical• Wax Inhibitors – “Inhibit”/reduce wax deposition• Pour Point Depressants – Improve flow properties

– Wax crystal modifier

Either Mechanical or Chemical

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What are the Options/Solutions?

Mechanical:

Heat Retention (insulation, heat tracing)• Scrapers and cutters• Pigging lines

Solvents: Condensate, Kerosene, Diesel (Paraffins)

Aromatics: Benzene, Toluene, Xylene (Asphaltenes / Paraffins)• May Add Solvent Accelerators

9:1 Xylene : AsphaltenesRatio by Weight

Removal: Mechanical or Chemical

What are the Options/Solutions?

Chemical:

Heat: Hot Oil• Take from top of tank• Add Xylene, Diesel (25%)• Add dispersant• Hot water produced or 2% KCI steam

Dispersants: Crystal Modifiers – Very effective, proprietary• Wax Inhibitors – “Inhibit”/reduce wax deposition• Pour Point Depressants – Improve flow properties

– Wax crystal modifier• T > 120F (49°C) helps• Removes 50+ its Volume of Asphaltenes

Micro-Organisms: Best if 90F (32°C) < T < 150F (66°C)

Removal: Mechanical or Chemical

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Program Design for Wax Removal

Determine cloud point, pour point and asphaltenecontent of crude oil (to aid planning)

Select artificial lift systems carefully (to minimize waxdeposition)

Downhole hookup should permit injection of inhibitor,solvents or heated fluid

Heat tracing may be required to prevent gelling of highpour point crude

Mechanical Methods for Paraffin Removal

Paraffin scraper guides installed on rod string rods

Weatherford Type “H” paraffin knife

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Bi-Di Pigs: Gauging and Cleaning

Paraffin Recovered During Pigging a Flowline

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Historical Treatment of Paraffin Chemically

Solvent Treatment Down Annulus

Typical Paraffin Chemical Treatment

Wellhead mechanicalchemical pump and solventstorage tank for injectioninto well

Surface chemical pump andsolvent storage tanks forinjection into surfaceflowlines

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Microorganisms do not eat oil / paraffin

A food source must be supplied to the “bugs”

Other Potential Methods for Paraffin Control

Bugs (microbial)

The bugs secrete enzymes which put waxes back into solution

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Learning Objectives

This section has covered the following learning objectives:

Identify characteristics of both paraffin waxes and asphaltenes

Identify the primary causes of paraffin wax and asphaltenedeposition

Outline the mechanical and chemical treatment methods availableto minimize costs and maximize production when dealing withorganic scale problems

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Oilfield Inorganic Scales


Learning Objectives


Identify the most accurate scale identification technology

Recognize specific scaling tendency conditions for severalcommon oilfield scales

Identify the water soluble, acid soluble, and insoluble oilfieldscales

Outline various continuous and batch chemical scale inhibitionoptions

Describe various chemical and mechanical scale inhibitiontreatments for scale removal

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Scale can significantly restrict tubing and flow lines as theseillustrations demonstrate

Typical Scale Problems

Downhole Video View of Scale Formation

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What is Scale?

• Mineralcompounds

• Corrosionproducts

• Congealed oil• Formation fines• Paraffin• Asphaltenes

1. a solid depositof mineralswhich haveprecipitatedbased on lossof solubilityconditions

noun | \'skāl\

Usually a mixture which may include:

Definition of scale

Scale

Why Scale is Deposited

Change in Temperature

Pressure Decrease

Mixing of Incompatible Waters

Evaporation of Water

Long Exposure Time (Crystal Growth)

Agitation (Nucleation)

Change of pH (Solubility Change)

Oxidation

Corrosion

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Symptoms of Scale Problems

Abnormal Decline of Production Flowrate

Change in Brine Composition

Failure of Downhole Pumps

Scale on Downhole Equipment

Scale in Surface Equipment

Various Oilfield Scale Facts

Hard deposit formed inequipment in presence ofwater

Insoluble corrosion products• Iron sulfide Fe S• Iron carbonate Fe CO3

• Iron oxides Fe2 O3 (Rust)

Mineral scales (precipitateddirectly from water)

• Calcium sulfate Ca SO4

• Strontium sulfate Sr SO4

• Calcium carbonate Ca CO3

• Calcium sulfate CaSO4(Gypsum) (Anhydrite)

• Barium sulfate Ba SO4

Co-deposits• Bacterial matter• Heavy oil (solids)• Formation fines

To determine make-up• Test multiple portions of

total deposit thickness(layered)

• Test representativesection of scaled pipe orequipment

NORM Scales

NORM =

Occurring RadioactiveMaterials

Naturally

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Oilfield Scale Deposits

HCl Acid Soluble Scale

Chemical Formula

Mineral Name

Calcium Carbonate CaCO3 Calcite

Iron Carbonate FeCO3 Siderite

Iron Sulfide FeS Trolite

Iron Oxide Fe3O4 Magnetite

Iron Oxide Fe2O3 Hematite

Magnesium Hydroxide Mg(OH)2 Brucite

H2O Soluble Scale Chemical Formula

Mineral Name

Sodium Chloride NaCl Halite

Oilfield Scale Deposits

Acid Insoluble Scale

Chemical Formula

Mineral Name

Calcium Sulfate CaSO4 Anhydrite

Calcium Sulfate CaSO4 H2O Gypsum

Barium Sulfate BaSO4 Barite

Strontium Sulfate SrSO4 Celestite

Barium Strontium Sulfate BaSr(SO4)2 - - -

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Barium Sulfate Scale at a Gas Lift Operating Valve

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Scaling Tendencies Vary by Scale

All scales have a scaling tendency, varying on conditions uponwhich scale will begin to form

Changes in pressure, temperature, pH, or flow rate

Impurities from formation

Additives by oil workers

Fluid expansion / evaporation

Mixing of incompatible waters

Some form QUICKLY (Calcium Carbonate)

Some form SLOWLY (Barium Sulfate)

Calcium Carbonate Scaling Tendency

Caused by pressure dropreleasing CO2 from HCO3

• With carbon dioxidereleased, pH increasesand dissolved carbonatesolubility decreases

• Increased temperature• Increased pH• Increased contact time means

the scale is also harder• Increase in turbulence• Increased Ca++ (common ion

effect)

• Increased salt (not Ca++)content

Incr

ease

s w

ith

:

Decreases w

ith:

Solubility is key

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Gypsum or Anhydrite Scaling Tendency

Reduction in pressure decreases solubility• 3000 psi (20684 kPa) to 0 psi (0 kPa) precipitates 0.3 lb/bbl (0.86 kg/m3)

(W. Texas)

Mixing waters with Ca++ and SO4-

Casing leaks causing water mixing

Agitation increases scaling

Evaporation from gas evolution may cause scale

Temperature change

Water flow through anhydrite may precipitate gypsum

Mg++ increases solubility

Barium and Strontium Sulfate Scaling Tendency

Caused by mingling waters with SO42- and Ba++, Sr++

BaSO4 scaling decreases with increases in NaCl

BaSO4 scaling increases with decreased temperaturein NaCl solutions and pressure drop

BaSO4 forms when gas hydrates evaporateCOPYRIGHT



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Barium Sulphate and Coal Dust from Mine Water Trough

Prediction of Scaling Tendencies

Formation water analysis• Representative samples (bottom hole)• Analyzing aged samples

– Different pH from that at time of sample gathering– Different HCO3 (bicarbonate) and CO2 than sampled

Produced brine analysis

Well head samples analysis (CaCO3 saturated)

Prediction of temperatures and pressures

Waterflood or commingled waters analysis

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Effect of Temperature Change on the Solubility of Gypsum and Anhydrite in Fresh Water

(0°C) (20°C) (40°C) (60°C)

Temperature, °F (°C)

(80°C) (100°C) (120°C) (140°C) (160°C) (180°C)

Cal

ciu

m c

arb

on

ate,

pp

m (

mg/

kg)

Effect of Temperature on Solubility of CaCO3

(-18°C) (4°C) (27°C) (49°C) (71°C) (93°C) (116°C) (138°C) (160°C) (182°C)

Cal

ciu

m c

arb

on

ate,

pp

m (

mg/

kg)

(°C)

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Sodium Chloride (Salt) Scaling

Caused by supersaturated brines• From evaporation, or,• From cooling*

Can be severe in gas or high GOR wells

* Note: Cooling Saturated NaCl Salt Solution from 140°F (60°C) to80°F (27°C) precipitates 4000 mg/l (4 kg/m3) NaCl

Downhole Video View of Salt Deposition

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Scale Identification

Scale Removal

Scale Prevention

Oilfield Scales


Laboratory X-ray Diffraction• Fast• Only small sample required• By far the most accurate method

Laboratory Chemical Reactions• Less accurate• Large sample needed• Time consuming

Field Tests Chemical Reactions• Quick and only approximate

Scale forms in layers

Composition varies by layer

Obtain sample of ALL layers

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HCl Reactivity on Various Acid Soluble Scales

Laboratory or Field Test for Scale

ScaleAdditive for

TestResults

Calcium Carbonate HCI Bubbles vigorously

Iron Carbonate HCI Bubbles – solution yellow

Iron Sulfide HCI Bubbles – H2S gas

Iron Oxide HCI Dissolves – solution yellow

Magnesium Hydroxide HCI Dissolves – solution clear

HCl Reactivity on Various Acid Insoluble Scales

Laboratory or Field Test for Scale

Scale Additive for Test Results

Calcium Sulfate 1. Soak overnight inbaking soda(NaHCO3)

2. Treat with HCl(Hydrochloric Acid) Bubbles vigorously

Barium Sulfate Not soluble

Strontium Sulfate Not soluble

Sodium Chloride Fresh Water Dissolves

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Oilfield Scales

Chemical Methods

Mechanical Methods


Scale Removal

Scale Prevention

Scale Removal

Chemical Methods

Solvents

Converters

Disintegrators

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EthyleneDiamineTetraAcetate

GYP CaSO4 Solvents

Both expensive

Only used as a last resort

EDTA

NTA

NitriloTriAcetate

Bicarbonate

Caustic

Inorganic Converters

CaSO4 + HCO3-

(Acid Insoluble)

CaCO3 + SO4- -

(Acid Soluble)

CaSO4 + 2OH-

(Acid Insoluble)

Ca(OH)2 + SO4- -

(Acid Soluble)

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Potassium Acetate + CaSO4

Sodium Citrate + CaSO4

Potassium Glycolate + CaSO4

Organic Converters

Calcium Glycolate

Calcium Citrate

K2Ca(SO4)2 8H2O

Chemical Methods of Scale Removal

Scales are generally oil-coatedor mixed with organic deposits

Surfactants allow penetrationof oil film for faster conversionor solution

When surface cannot becontacted by acid, rate of scaledissolution is reduced

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Mechanical Methods

Jetting

Drilling / Reaming

Pigging

Scale Removal

Re‐Perforating

Jetting nozzle run on coiled tubing to

mechanically remove scale

Jetting Nozzle

Check Valve

Fitting

Fluid SeparationShear Plug

Mechanical Scale Removal Using CTU Jetting

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Oilfield Scales


Scale Removal

Scale Prevention Most favored approach

Less expensive

Scale Prevention is Achieved Through Inhibition

pH Control

Chelation• Chemical method of

binding molecules• Prevent scales from

forming

Threshold Effect• Polyphosphate

adsorption on nucleus• Crystal surface to slow

further crystal growth• Low concentration

required

Inhibition programsreduce or prevent scaleformation

Maintenance effort isongoing

• Recurring costs• Treatments repeated

periodically

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Cardinal Rule: Scale Prevention is Less Costly

Scale Prevention

Normally, the Simplest and Most Economical

Part of the Overall Scale Program

Types of Scale Inhibitors

Inorganic Polyphosphates

Polyorganic Acids

Organic Phosphonates

Organic Phosphate Esters

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Batch Chemical Treatment for Scale Inhibition

Batch Chemical Treatment for Scale Inhibition

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Inhibitor Treatment

Continuous• Surface injection• Downhole injection

Batch• Periodic volumes

pumped

Squeeze• Diluted volume:

Inject volume of produced water

Pump chemical + demulsified (protect water sensitive clays)

Formation

Inhibitor chemical pumped into annulus, or down ¼ in. (6.35 mm) s.s. tubing

How Scale Inhibitors Work

Sequestering – Chelating

Isolates or Captures Ionsthat Precipitate

• (e.g., Calcium, Barium)

Requires 1:1 Ratio ofInhibitor to Scale Ions

Costly – Not CommonlyUsed

Threshold Inhibition

Interacts with Scale Surface (Microscopic)

Alters Crystal Structure as Formed• Inhibitor Attracted to Charges on Scale Crystals• Stops Crystals from Growing• As Crystals Dissolve, Inhibitor Released

Effectiveness Depends on Nature and Chemistry of Scale

Economical

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Scale Inhibitors

Amino Phosphonates

Phosphate Esters

Amino AlcoholsNot for use as long life squeeze at Temp > 175F / 80C

Sodium Polyacrylates

Polymers

Threshold Inhibition

Interacts with Scale Surface (Microscopic)

Alters Crystal Structure as Formed• Inhibitor Attracted to Charges on Scale Crystals• Stops Crystals from Growing• As Crystals Dissolve, Inhibitor Released

Effectiveness Depends on Nature and Chemistry of Scale

Economical

Sequestering – Chelating

Isolates or Captures Ions that Precipitate• (e.g., Calcium, Barium)

Requires 1:1 Ratio of Inhibitor to Scale Ions

Costly – Not Commonly Used

Sand Grain Sized Polyphosphate Particles

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Sand Grain Sized Polyphosphate ParticlesInjected into Fracture

Summary

Oilfield scale problems are universal

Identify scale and reason for deposition

Remove scale deposits chemically or mechanically

Bypassing/re-perforating may be best option

Inhibit against future deposition

Accurate analysis of sampled waters allows engineers tocorrectly define the scale problem in order to choose the mostappropriate treatment and removal methods

Carefully analyze and design produced water treatment optionsto minimize handling costs

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Learning Objectives


Identify the most accurate scale identification technology

Recognize specific scaling tendency conditions for severalcommon oilfield scales

Identify the water soluble, acid soluble, and insoluble oilfieldscales

Outline various continuous and batch chemical scale inhibitionoptions

Describe various chemical and mechanical scale inhibitiontreatments for scale removal

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Oilfield Corrosion


Learning Objectives


Recognize data which illustrate the statistical dominance ofcorrosion as the key concern in minimizing oilfield failures

Identify the corrosion cell and its components

Differentiate between internal and external corrosion

Recognize the broad list of options to control but not completelyeliminate oilfield corrosion

Outline the principles of cathodic protection

Identify continuous and batch treatment design for chemicalinhibition to control corrosion

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Oilfield Corrosion Control

Recognition of Corrosion

Causes of Corrosion

Corrosion Prevention

Failure Types

Oil & Gas Industry Data

Analysis of Selected Number of Failures in Petroleum Related Industries

Type of failureFrequency

(%)

Corrosion (all types) 33

Fatigue 18

Mechanical damage/overload 14

Brittle fracture 9

Fabrication defects (excluding welding defects) 9

Welding Defects 7

Others 10

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Corrosion Recognition

Abrasion (rod wear on tubing, etc.)

Failures have many causes and appearances

Erosion (solids, droplets, mists) wear

Chemical (oxidizing, acids, acid gas, chlorides, etc.)

Galvanic coupling (electromotive series)

Chemical

Metal alteration

Physical

Primary Forms of Corrosion

• Metal Pitting

• Metal Cracking

• Metal Wall Thinning

Usual Production Operations Corrosion Types

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What caused tubing failure?

Clues are found in the well environment and the history surrounding the break.

Catastrophic Tubing Failure

Split in 5-1/2 in.(0.14 m) casing

unknown cause:Mechanical damage?

Suspected wear?

Catastrophic Casing Failure

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Basic Corrosion Cell

Loss of metal at the anode

Electrons flow from anode to cathode

• Requires dissimilar metals or dissimilar surfaces on the same metal

Battery principle

• Requires electrolyte

Corrosion Reactions

Oxidation – loss of electronsReduction – consumption or

gain of electrons

(Oxygen may or may not be involved)

Fe°=> Fe++ + 2e- metal loss occurs at the anode

e- + metal => reduced metaCOPYRIGHT



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From: Schlumberger O.F.R

Corrosion Cell Theory

Conductor

e-

Metal ions (M+)

Ano

de

Cat

hode

Electrolyte

Steel Loss at the Anode- weight loss and pitting

Corrosion Cell on Steel Surface

Corrosion on a steel surface. At anodic sites, iron readily goes into solution as iron ions, Fe++, which combine with oxygen, O2, hydrogen sulfide, H2S, r carbon dioxide, CO2, depending on the constituents of the electrolyte fluid. These form corrosion products or scales as rust‐iron oxide [Fe2O3.H2Ox], iron sulfides [FeSx] or iron carbonate [Fe2CO3]. While this is happening, the electrons migrate to the cathode. At the cathode surface, they reduce oxygen generated water to produce hydroxyl ions [OH] or reduce hydrogen ions to produce hydrogen gas [H2].

Anode

Cathode

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Corrosion Mechanism

Corrosion can be considered as a natural result of energy stored in the metal when it was refined and fabricated

Energy release by corrosion

Iron ore(Oxides)Corrosionproducts

Energy added by refining “Pure”

metal oralloy

After Fe+2 is formed by oxidation (note that Fe+2 is soluble in water when pH<7), the Fe+2 ion must be carried away from the anode for the reaction to continue

Oxygen, H2S and CO2 will all combine with iron in water to form precipitates

Reaction By-Products

• Fe+2 + O2 => Fe2O3, Fe3O4, etc.

• Fe+2 + H2S => FeS

• Fe+2 + CO2 => Fe2CO3

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Galvanic Series in Sea Water

1. Magnesium

2. Zinc

3. Soft Aluminum

4. Cadmium

5. Hard Aluminum

6. Steel

7. Stainless Steel (300 series)

8. Lead

9. Brass and bronze

10. Inconel

11. Hastelloy C 276

Corrode when coupled with steel; i.e. zinc anodes

Any metal on the list will

corrode when coupled with a

metal listed below it

Zinc anodes

Zinc Anodes on Offshore Platform

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Chemical Corrosion

H2S • Very corrosive, especially at low pressure• Weak acid, source of H+

• Different regions of corrosion with temperature

CO2

• Weak acid (must hydrate to become acid)• Leads to pitting damage

Strong acids • HCl, HCl/HF, Acetic, Formic

Brines • Chlorides and zinc are the most damaging

Tubular Selection Criteria

Chloride stress cracking• Corrosion begins at defect and travels along grain boundary• Accelerated by high chloride concentration and low pH

Embrittlement• Hydrogen

Weight Loss Corrosion• H2S / CO2 / H2O / NaCl systems• CO2 / H2O / NaCl systems

Localized Corrosion

Galvanic

Strength

Cost and availability

Acidizing

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Pitting



May Be

Anodes can form on a single piece of metal that has small crystals of slightly different composition

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Increasing Rate of Penetration with Pit Development

Large anodic area, rate of metal loss and pit penetration is slow.

Anodic area decreases, cathodic area extends down side of pit. Rate of

penetration increases.

Anodic area confined to bottom of pit. Rapid rate of metal loss and wall

penetration.

Electrolyte

Current Flow

Anode Cathode

Metal I: Electronegative Metal II: Electropositive

Increasing Rate of Penetration with Pit Development

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Anode Material

Electrolyte Environment

Anodic Reaction Cathodic Reaction

Anodic & Cathodic Reactions Occurring at a Metal Surface

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Corrosion Failure

Hot Spot: Screen Erosion by Sand Opposite Perforation

From: World Oil Magazine & George Suman

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Severe Corrosion in a Surface LineDownstream of a Flanged Connection

Consequences of Turbulent Flow, Erosion, and Corrosion

Screen Corrosion Failure

Screen failure

Screen pieces from well completion failures in Teak Field –TrinidadCOPYRIG

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General chart

Effect of Water Cut vs. Corrosion Rate

Co

rro

sio

n R

ate

Water Cut, % Water

I

II

III

Corrosion – Water in Sweet Gas

Water (bbl/mmcf)

Chlorides (ppm) (mg/kg)

Iron (ppm) (mg/kg)

Corrosion Potential

+/- 2 0–250 50 No

+/- 2 0–250 50–100 Possible

+/- 2 0–250 >150 Possible

2-5 250–500 50 Possible

2-5 250–500 50–150 Probable

2-5 250–500 >150 Yes

>5 >500 >150 Yes

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Oxidation Corrosion

Source of constant corrosion

Spray and mist area corrosion most severe

where T = water system temperature, °F (°C)

Oxygen Saturation Guideline Estimate

Concentration

ppm O2 =

Oxygen in Surface Waters

10 – 0.055 (T – 30)°F (-1.1°C)

@ 32°F (0°C) – 10 ppm (mg/kg) (saturation)

@ 210°F (100°C) – 0 ppm (mg/kg)

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CO2 (Sweet) Corrosion

H2S (Sour) Corrosion• Additional Hazard: FeS Coating is Cathode to Steel / Iron Pipe

Anode (Galvanic Corrosion)

Non-Corrosive

CO2 & H2S (Acid Gases) Corrosion

PRESSURE

Solubility TEMPERATURE

API SPEC 12GDU states, “Carbon dioxide partial pressures in the gas phase below 3 psia (20.7 kPa) typically do not require corrosion control. Between 3 and 30 psia (20.7 kPa and 207 kPa), some form of corrosion control may be required, such as pH control or inhibitor injection. Corrosion resistant metals may also be needed. For carbon dioxide (CO2) partial pressures above 30 psia (207 kPa), design/operational corrosion control measures will be required.

Possibly Corrosive

Corrosive

Partial Pressure of CO2 Pressure x Mole Fraction CO2=

30+ (207)

7–30 (48–207)

0 – 7 (48)Partial Pressure (psia) (kPa) Corrosiveness

25oC

Corrosion Rate vs. CO2 Partial Pressure

(kPa)(68.95) (689.48) (689.48)

Co

rro

sio

n r

ate

(mm

/y)

Partial pressure of CO2(Mpa)Temperature : 25°C (77°F)

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Corrosion Rate vs. CO2 Partial Pressure

80oC(kPa)

(68.95) (689.48) (689.48)

Partial pressure of CO2 (Mpa)Temperature : 80°C (176°F)

Co

rro

sio

n r

ate

(mm

/y)

pH vs. H2S Partial Pressure

So

luti

on

pH

Hydrogen Sulfide Partial Pressure (bar)

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H2S and pH

Rel

ativ

e C

orr

osi

on

Rat

e

Sulfides as H2S, ppm (mg/m3)

(0.5) (1.0) (1.5) (2.0) (2.5) (3.0)

Hostile Environment Tubing Metallurgy Applications

Typical Duplex Alloy (22/25% Cr) Environments

Location Depth, ft(m)

Bottomholetemperature, °F (°C)

Bottomhole pressure, psi (kPa)

CO2 CIꞏ,ppm

(mg/kg)

H2S,ppm

(mg/kg)

Mississippi 15,000 (4,572)

325 (163) 10,500 (72394.95 kPa) 5 110,000 < 1

Louisiana 15,000(4,572)

330 (165) 14,700 (101352.93 kPa) 7 High < 1

Louisiana 15,000(4,572)

325 (165) 10,500 (72394.952 kPa) 3 100,000 < 1

Nickel‐Base Alloy Usage

Location Depth, ft(m)

Bottomholetemperature, °F (°C)

Bottomhole pressure, psi (kPa)

CO2 CIꞏ,ppm

(mg/kg)

H2S,ppm

(mg/kg)

Oklahoma (Huntoon) 22,800(6,949)

285 (141) 15,000 (103,421.36 kPa) 3 < 2,000 225

Big Excambia Creek 15,500(4,724)

280 (138) 3,500 (24,131.65 kPa) 40 < 190,000 21%

La Barge, Wyo. 15,000(4,572)

285 (141) 4,000 (27,579.03 kPa) 65 150-200,000

220

Big Horn, Wyo. 24,500(7,467)

425 (218) 9,500 (65,500.19 kPa) 19 6,870 11%

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N‐80 410‐Stainless(24) (46) (68) (91)

1(38) (66) (82)

1

Acid Corrosion Rates on Different Alloys

Co

rro

sio

n r

ate,

mp

y

Co

rro

sio

n r

ate,

mp

y

Temperature, °F (°C) Temperature, °F (°C)

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Abrasion Increases Corrosion / Erosion

Constantly clean surface, no oxide protective films

Corrosion / Erosion and Velocity

Corrosion increases steadily with velocity for all liquid systems (82°C)

(49°C)

(16°C)

(0.6) (1.2) (1.8) (2.4) (3.0)

Rel

ativ

e C

orr

osi

on

Rat

e

Velocity in ft/sec (m/s)

In a fluid stream, corrosion jumps sharply with solids or liquid droplets

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sand free conditions

To keep pipe clean C = 15 to 24 (minimum flow)Swing check valves C = 35 – 50 (maximum flow)Piston check valves C = 40 – 140 (maximum flow)

Sand free conditions

Corrosion / Erosion and Velocity

(kg/m3)Mixture density, lb/cu ft

(320)(481)

(641)(801)

(961)(1121)

(1602)(1281)(1442)(160)

(m/s

)(43)

(37)

(30)

(24)

(18)

(12)

(6)

C = 250C = 200C = 150C = 100C = 50

e

COther "C" Values for V =

ρmρm

Valves and Pipe Fittings• When fluid flows through a pipe at high velocities erosion can occur

• High rate gas velocity at 60 to 70 ft/sec (18.3 to 21.3 m/s) often incurs erosion of pipe

• The presence of sand can dramatically increase the tendency for erosion to occur

• The velocity at which erosion occurs has been related to the density of the fluid

• With C set at 100 and using the gas equation of state to express gas density, then the equation becomes

or, gas flow rate at standard conditions

Erosional Velocity in Tubing

0.5e

C

0.5

100

29e

gp

ZRT

where e = erosion velocity, ft/sec = fluid density, lbm/ft3 = L L + g (1–L)C value ranges from 75 to 150

0.5

51.86 10eg

pq A

ZT

where qe = erosional flow rate, MscfdA = area of pipe, ft2

p = lowest pressure in the pipe, psiaT = temperature at point where p is determined, RZ = gas compressibility factor at p, Tg = gas gravity

API 14E Specificationminimal sand concentration

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Erosional Velocity (with Sand Production)

Alternative to API 14E Erosional Velocity Limits for Sand-Laden Fluids

The current practice for eliminating erosional problems in piping systems is to limit the flow velocity (Ve) to that established by the recommended practice API RP 14E based on an empirical constant (C-factor) and the fluid mixture density (rhom) as follows: Ve = C / rho0.5

The API criteria is specified for clean service (non-corrosive and sand-free), and it is noted that the C-factor should be reduced if sand or corrosive conditions are present. The validity of the equation has limits on the basis that the API RP 14E C-factor (a) can be very conservative for clean service and (b) is not applicable for conditions when corrosion or sand are present.

Extensive effort has been devoted to develop an alternative approach for establishing erosional velocity limits for sand-laden fluids. Unfortunately, none of these proposals have been adopted as a standard practice because of their complexity. Results of various studies propose an alternative and simple equation to the API 14E equation.

This alternative equation has the following form: Ve = SD rho0.5 / W0.5

The S-factor depends on the pipe geometry (i.e., bend, tee, contraction, expansion, etc.). Using the units for mixture flow velocity (Ve) in m/s, fluid mixture density (rhom) in kg/m3, pipe diameter (D) in mm and sand production (W) in kg/day, the value of the S-factor is 0.05 for pipe bends.

The accuracy of the proposed equation for predicting erosion in pipe bends for fluids containing sand is demonstrated by a comparison with several multi-phase flow loop tests that cover a broad range of liquid-gas ratios and sand concentrations.

(30)

(18)

(27)

(7)

(21)

(24)

(3)

(9)

(12)

(15)

(160) (320) (481) (641) (801) (961)(1121)(1281)

Tubing Design Velocities

(m/s

)

(Kilograms per cubic meter)

Gas@ 1000 psi

Clean-Single Phase Fluids

Gas@ 5000 psi

Oil-45API

FreshWater

Produced WaterCorrosive

Wet-GasNon-Corrosive

Corrosive and/orAbrasive Fluids

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Biological Corrosion

SRBs Sour conditions in the well / reservoir

Iron Fixers Slime and sludge

Slime Formers Formation damage

Anaerobic

SRB =

Reducing Bacteria

Sulfate

Sulfate-Reducing Bacteria

• Create numerous SRB colony growths • Low pH exists below SRB colony

SRBs are anaerobic bacteria

Generate H2S concentration in small area

Worst where velocity < 3.5 ft/s (1.07 m/s)

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Sulfide Stress Corrosion

Occurs when metal is under tension and exposed to H2S and H2O

Generates atomic hydrogen

• Hydrogen encroaches into metal atomic network

• Metal ductility is reduced

Chloride Stress Cracking

Chloride stress cracking process accelerated by:

Starts at a pit, scratch or notch

Crack proceeds primarily along grain boundary

• Chloride ions

• Low pHCOPYRIGHT



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Velocity Range

Minimum – Prevent bacterial growth and solids dropout

Maximum – Prevent erosion

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Corrosion Control Methods

Maintain high pH

Control gas breakout

Use passive metals

Remove oxygen from system

Control velocities

Lower chlorides

Control bacteria

Acid / brine alternatives

Remove liquids

Inhibitor injection

Coatings

Cathodic protection

Corrosion and pH

pH 7 or higher – significant corrosion unlikelypH 7 to 6.5 – minor corrosionpH 6.5 to 6 – moderate corrosion, possible pittingpH 6 or less – significant corrosion, probable pitting

Corrosion-ErosionVelocity

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Corrosion Coupon Access to Flowlines

Corrosion probe monitoring of a water injection trunk line using a smaller diameter side

stream piping run to accommodate the oxygen

probe equipment

Oxygen Probe Access to Flowline

Side stream oxygen

monitoring line

Oxygen probe

Injection trunk line

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Surface Chemical Storage for Downhole Injection of Emulsion and Corrosion Control Chemicals

Corrosion Monitoring: Pipeline Pig Launcher

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Corrosion Monitoring: Pipeline “Intelligent Pig” Launcher

<‐‐‐‐‐‐‐‐‐ To launch a pig

To receive a pig ‐‐‐‐‐‐‐>

Corrosion Monitoring: Pipeline Pigging

Pig Launcher and Receiver

CLOSED CLOSED

CLOSED

OPEN

END VIEW

TO DRAIN TANK

OPEN

CLOSED

CLOSED

OPEN

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Corrosion Monitoring: Pipeline Pigging

Asphaltenes

Paraffins

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• Electrolyte Properties• Resistivity

• Chlorides

• pH…

• Temperature• Pressure• Check CO2 content• Check H2S content• Check O2 content• Check for presence of bacteria and type

Always determine:


Conditioning of the metal

Conditioning of the corrosion

Conditioning of the Corrosion Environment

Use of Corrosion Inhibitors

Measurement of Corrosion Rates

Use of Cathodic Protection

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Corrosion Inspection

Continuous Chemical Treatment for Internal Corrosion Control

Chemical storage tank and surface pump

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From: Baker Petrolite

Chemical Treatment for Internal Corrosion Control

Dispersion of OIL soluble corrosion inhibitor in saturated brine for downhole treatment

Dispersion of WATER soluble corrosion inhibitor in saturated brine for downhole treatment

System Inhibitor Metal Conc.

Sulfuric Acid Phenylacridine Fe 0.5%

Cooling Water Sodium Chromate Fe, Zn, Cu 0.1%

Oilfield Brines Sodium Chromate Fe 0.01%

Seawater Calcium Bicarbonate All f(pH)

HCI Ethylaniline Fe 0.5%

Glycol/Water Borax All 1–1.5%

Corrosion Inhibitors

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Inhibitor Treatment

ContinuousINHIBITOR MIXTURE RESERVOIR

PUMP

• Result of film may be reduced corrosion

Films may form a beneficial tight barrier

Corrosion Films

Films are first by-products of corrosion

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Pipeline Coating to Control Corrosion

Electrochemical Corrosion

• Extraneous AC or DC current in earth• Point of arrival is cathode• Point of departure point is anode

Galvanic Corrosion

Stray Current Corrosion

Crevice Corrosion

• Localized, forced penetration, O2 and Cl– are major factors

• Two dissimilar metals– Found in couplings, centralizers, pumps, packers, profilesCOPYRIG

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Cathodic Protection Rectifier for Well Casing External Corrosion Control

Cathodic Protection Sacrificial Anodes for Well Casing External Corrosion Control

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Summary

Corrosion exists throughout oil and gas systems

Corrosion may be internal or external

Corrosion prevention is less costly than repair

Corrosion control methods are varied

Corrosion monitoring is essential

Corrosion cause identification is essential

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Learning Objectives


Recognize data which illustrate the statistical dominance of corrosion as the key concern in minimizing oilfield failures

Identify the corrosion cell and its components

Differentiate between internal and external corrosion

Recognize the broad list of options to control but not completely eliminate oilfield corrosion

Outline the principles of cathodic protection

Identify continuous and batch treatment design for chemical inhibition to control corrosion

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Gas Hydrates

Flow Assurance and Production Chemistry

Learning Objectives


Outline the conditions required for the formation of gas hydrates

Recognize how ice crystals and methane in pipelines can lead tosevere plugging of lines if not prevented from occurring orregularly removed by pigging operations

Describe the methods employed to treat gas hydrates in pipelinesCOPYRIG

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Gas Hydrates

A hydrocarbon accumulation where molecules of natural gas, typically methane, are trapped in ice crystal structures.

1 m3 (35.3 ft3) of hydrate disassociate at atmospheric pressure and temperature to form 164 m3 (5,791.6 ft3) of natural gas + 0.8 m3 (28.3 ft3) of water.

(Kvenvolden, 1993)

Applies in two cases:1. Within a subsea pipeline where temperatures drop due to the

cold sea2. At depths in the ocean where the ambient temperature is cold

and the pressure is high

Hydrate Potential

Gas saturated with water in reservoir• For example at 120°F (49°C) and 4000 psia (27.6 MPa) =

60 pounds / MMSCF (961.1 mg/m3)

As gas cools, water and light hydrocarbons drop out

Hydrates

• Are solid crystals formed by physical bonding between water andlight hydrocarbons

• Hydrates look like ice crystals or snow• Hydrate specific gravity ~ 0.98 floats in water, sinks in oil• Components: 10% hydrocarbon / 90% water

– Also formed by N2, CO2, H2S

• Formation temperature depends on composition and pressure• Forms more readily at higher pressures• Accelerated by agitation, pressure pulsation, scale/solids

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Gas Hydrate Prediction Plot

(50) (68) (86)

(14.5)

(145)

(1,450)

(14,504)P

ress

ure

(b

ar)(

psi)

Temperature (°C)(°F)

Hydrate

No Hydrate

Pressure-Temperature Curves for Predicting Gas Hydrate Formation

(-1.1) (4.4) (10) (15.6) (21.1) (26.7) (32.2)

(41,369)

(276)

(414)

(552)

(689)

(1,034)

(27,579)

(20,684)

(10,342)

(6,895)

(5,516)

(4,137)

(2,758)

(2,068)

(1,379)

Pre

ssu

re f

or

hyd

rate

fo

rmat

ion

, psi

a(k

Pa)

Temperature, °F (°C)

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Gas Hydrate Problems in a Pipeline Pig Catcher

Hydrate Prevention

Inhibitors

Heat

Dehydration (reduce water to 7 pounds / MMCF (112.1 mg/m3))

• Glycol• Methanol

• Prevents gas hydrate formation• Reduces pipeline corrosion• Maintains pipeline capacity (avoids hydrate plugging)

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From: US Geological Survey

Known Worldwide Gas Hydrate Locations

Naturally Occurring Gas Hydrates

Slow seepage of thermogenic methane from below

What gas hydrates look like in lab

research projects

Learning Objectives


Outline the conditions required for the formation of gas hydrates

Recognize how ice crystals and methane in pipelines can lead to severe plugging of lines if not prevented from occurring or regularly removed by pigging operations

Describe the methods employed to treat gas hydrates in pipelinesCOPYRIG

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PetroAcademyTM Production Operations

Production Principles Core Well Performance and Nodal Analysis Fundamentals Onshore Conventional Well Completion Core Onshore Unconventional Well Completion Core Primary and Remedial Cementing Core Perforating Core Rod, PCP, Jet Pump and Plunger Lift Core Reciprocating Rod Pump Fundamentals Gas Lift and ESP Pump Core Gas Lift Fundamentals ESP Fundamentals Formation Damage and Matrix Stimulation Core Formation Damage and Matrix Acidizing Fundamentals Flow Assurance and Production Chemistry Core Sand Control Core Sand Control Fundamentals Hydraulic Fracturing Core Production Problem Diagnosis Core Production Logging Core Production Logging Fundamentals

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Documents

Flow Assurance and Production Chemistry Corecloud1.activelearner.com/contentcloud/portals/hosted3/PetroAcademy/...Production Chemistry Core Why This Module Is Important Understand