Production Operator's Handbook

PRODUCTION TECHNOLOGIESProduction Operator’s Handbook

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To avoid harm to, or loss of: • Personnel • Environment • Process equipment • Production

Examples:• Foaming can result in reduced production • Corrosion can cause problems in process equipment,

unnecessary expense, and injury to personnel and tothe environment

• Scale precipitation will cause reduced production • Emulsions can result

in bad water quality,danger to theenvironment andhigh water contentin the produced oil

• Wax can cause reducedoil production

• Bacteria can causecorrosion and theproduction of toxicgases such as H2S

Why use chemicals?

Chemicals are one of the tools that can beused on an oil-production or oil-treatinginstallation to solve a problem, increasethe production, create better water qualityor enhance the quality of the oil or gas.Chemicals have uses in many processsystems, including:

• Water injection

• Oil and gas production

• Gas separating and dehydrating

• Utilities

There is almost always a large stock ofvarious chemicals on these installations,each dedicated to a particular purpose.Therefore specialized knowledge isnecessary to ensure that they are used:

• Optimally

• Safely

• Economically

This handbook describes the chemicaltreatment of all types of process systemsand gives a short description of the typical properties for each chemical.

About this handbook

2 3

Where do problems occur in oil production?

5

The oil can contain wax, asphaltenes and other solids.

Water can produce corrosion in process equipment andpipelines, precipitation of salts, and emulsion with oil.

Gas can cause foaming as well as corrosion due to CO2 or H2S.

These problems can be solved with the correct design of processequipment, active management and optimization of the process,and the use of chemicals.

Why are chemicals needed in the production of oil, gas and water?

4

Topside processEmulsions,foam,scale,corrosion,asphaltenes

Water injectionScale, corrosion, foam, bacteria growth

Perforated zone andproduction tubingScale, wax, corrosion, asphaltenes

Water to sea and produced waterScale, corrosion,oil content, chemicals

Oil and gasexportWax,corrosion,water

UtilityScale,corrosion,foam,dirt and grime

Normally, two types of scale-inhibitor chemistry are used:phosphonates and/or polymers. These products are water-soluble , and have a pH in the range of 2 to 7. The “scale squeeze”is an operation where long-term protection against mineral-scale precipitation from the perforations is provided throughthe topside process. Due to injection-water breakthrough or ahigh content of calcium and bicarbonate in the formation water,increased scale formation may be experienced at some point inthe operation of a field.

In the scale squeeze, a calculated volume of scale inhibitor isdisplaced directly into the formation. The scale inhibitor adsorbsto the formation surface and then de-adsorbs as it returns, dis-solved in the produced water. This will protect the perforatingzone, the production tubing and the topside against scale precip-itation. The lifetime for a scale squeeze is normally 180 days,but it depends on the water production rate.

Scale inhibitors for scale squeeze Well and flowline

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Chemical Purpose/applicationScale inhibitor Scale squeeze of wellsScale dissolver Removing scaleMethanol, glycols and LDI Hydrate inhibitingSolvents Removing wax and/or asphaltenesWax inhibitor Wax inhibitionAsphaltene dispersant Asphaltene control Corrosion inhibitor Batch or continuous application

Scale is normally a buildup of salts of calcium, barium orstrontium as calcium carbonate, barium sulfate and strontiumsulfate. Carbonate scale is caused by the presence of calciumand bicarbonate ions in the formation water. When pressuresare decreased or temperatures are increased, the bicarbonatewill begin to decompose, resulting in pH increases and calcium-carbonate precipitation in the form of scale.

Barium and strontium sulfates form in wells that producewaters naturally saturated with barium or strontium sulfates,or when produced water containing barium or strontium iscontaminated with a sulfate-bearing water. When seawaterinjection is employed, the seawater contains sulfate, and theformation water may contain barium and/or strontium whichwill then form barium and/or strontium sulfate when the twowaters commingle.

The solubility of barium sulfate is verylow, which means that it will precipi-tate even at very low concentrations.

Scale in production equipment can have dramatic, negative consequences.

Well and flowline

6

Metal surface

Starting at the metal surface, scaleforms in various layers, dependingon the chemical composition ofthe water, pressure, temperatureand total dissolved solids. Inwellbores, layers are typicallymixtures of barium and strontiumsulfates and then calcium sulfate.Following pressure drops, such asthose that occur at wellheads andchokes, calcium carbonate forms.

Pipe metal surface

In most cases, methanol is used to avoid hydrates in pipelines, orwhen starting or closing a well. Methanol is toxic and flammableand must be handled with care. Read the safety data sheet anduse suitable protective equipment. Methanol is soluble in water,and can cause emulsion problems in the separators and treatingvessels. Low-Dose Hydrate Inhibitors (LDHI), both kinetic andanti-agglomerate, are now replacing methanol in subsea linesand pipelines.

Removing wax and/or asphaltenes In production tubing and topside equipment, wax andasphaltenes can precipitate. Wax normally precipitates due to reduced temperature, while asphaltenes precipitate due to decreased solubility atgas breakthrough. The mosteffective chemicals for removingasphaltenes contain dispersantsformulated with xylene or otheraromatic solvents. The sametypes of formulations are alsoeffective for removing waxdeposits. Xylene is flammableand is harmful to health. Readthe safety data sheet carefully.

Hydrate inhibition Well and flowline

9

In production tubing/flowlines, acids are normally used toremove calcium carbonate. For barium sulfate, sequestrants(scale dissolvers) must be used.

AcidsDepending on the steel characteristics, choose the acid thateffectively removes the calcium carbonate while exhibitingacceptable corrosivity against the steel. The reaction is exothermicand releases CO2. Examples are: hydrochloric acid, phosphoricacid, nitric acid and citric acid. These are corrosive products and safety infor mation sheets must be read carefully before any acid is used.

SequestrantsSequestrants are normally used to remove/dissolve sulfate scale.The chemicals are often based on EDTA or its homologs. They do not release gas or give a noticeable exothermic reaction.

The chemicals have a high pH of 10 to 12. Safety data sheets must be read carefullybefore use.

Well and flowline

Scale dissolvers

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Natural gas is described as a “clean” fuel, and its production nor-mally gives few chemical problems. Whether produced from gasfields or associated with oil production, the gas will normally beprocessed in the following way:

1. It is separated from liquids at the separator.2. NGL and water are removed using the combined effects of

compression and cooling.3. Residual water is removed in a glycol contractor tower.

Triethylene glycol is normally used, due to its good adsorptionand regeneration qualities.

Water connected with gas production may contain salt from thereservoir or it may be condensed water from the cooling andexpansion processes.

Topside process: Gas

11

There are several methods used to apply a corrosion inhibitordownhole to control either sweet or sour corrosion. These meth-ods fall into two categories, named for the mode of application:batch or continuous.

Batch methods • Regular tubing “fill and soak” • Corrosion inhibitor squeeze • Periodic “brush” application on well tubing • Encapsulated for slow release from the rathole• Weighted

Batch treatments lay down a relatively thick protective film onthe metal surface which is slowly eroded by the shear and flowin the system until the next treatment cycle is due.

Continuous methods • Injection through the annulus either as a liquid or with the lift

gas via a mandrel valve• Injection via a macaroni string • Injection with the power fluid in a hydraulic lift pump

Continuous treatments lay down, and then continuouslymaintain, a thin but complete film of inhibitor molecules which covers and protects the metal surface.

Well and flowline

Corrosion control

10

Topside Process Train First-stage compressors

Second-stage compressor

Liquids-knockoutvesselLiquids-knockout

vessels

Exportcrudeoil

Flotationcell

Degasser

Heat exchanger

Hydrocyclones

Three-phase,second-stageproductionseparator

Producedfluids

Three-phase, first-stageproductionseparator

Mainoil-linepumps

One definition of sour conditions is when the partial pressureof H2S is over 0.3 kPa/0.05 psi or more typically 500 ppm H2S @100 psi (6.9 bar). On the other hand, most pipelines in the NorthSea have a limit of 2 to 3 ppm H2S in the gas. H2S is normallyremoved by adsorption in an amine process, or by the use of non-regenerated H2S scavengers. Examples are glyoxal and triazines.

Gas hydrates Hydrates are snow-like crystals that are composed of methaneand water. This “hydrocarbon ice” can plug pipelines and destroyprocess equipment. Hydrates start forming even at moderatepressure and at temperatures below 50° F (10° C). They are alsovery concentrated and therefore verydangerous; one m3 of hydrate contains150 m3 of methane. Hydrates can beavoided by the injection of methanolor glycol, and the same chemicals canbe used to dissolve hydrate plugs. LDHIare also used to control hydrates.

Generally:• Methanol is very toxic and flammable, with a flash point of

3.2° F (–16° C), so safe handling procedures must be impressedupon the customer

• Amines and alkanolamines are often irritating to the skin andhave a sharp smell

Sour gas Topside process: Gas

13

Wet gas is produced or transported in subsea flowlines,pipelines, between fields or in export pipelines and can causeseveral problems:• Emulsion • Hydrates • Corrosion — When gases come in contact with water, there is

always a risk of corrosion. The gas can simultaneously containCO2 and H2S, both of which will reduce the pH in the associatedwater and create the potential for corrosion.

The corrosion rate is dependent on:• Salt content of the formation water • Presence and concentration of acidic gases• Pressure • Temperature • Flow velocity

The corrosion can be controlled by:• Pressure • Construction materials • Dehydration of the gas • Chemical neutralization

Corrosion inhibitors. Continuous injection of corrosioninhibitors will effectively protect the system, but corrosioninhibitors can also cause problems such as emulsions, foamingand poor quality of the disposal water.


Wet gas

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This section describes the chemicals that are frequently used onan installation in the following process systems:• Flowlines and pipelines • Topside process, oil/water

All products that are used in these systems are solutions, whichcan be divided into two groups:• Water-base chemicals. These are products which use water as

the primary solvent. • Solvent-base chemicals. These products are oil-soluble, and the

solvents are hydrocarbon-base, e.g. aromatics and aliphatichydrocarbons, alcohols and esters.

Topside process: Oil and produced water

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Associated gas in oil production is a valuable resource, but cancause problems when produced together with the oil. Theseproblems can be listed as:• Foaming • Enhanced corrosion

Foaming Foaming occurs when gas is separated from oil or condensatethrough pressure release. In most cases, foaming will increase

as the Gas/Oil Ratio (GOR) increases.Foaming can be eliminated by theuse of defoamer/antifoam. They areusually made of silicones or fluoro -silicones, and they work by reducingthe surface tension on the gas bub-bles and therefore allowing easy sep-aration. They normally work at verylow dosage rates. The injection pointshould be as close to the problemas possible.


Associated gas

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Gas

Oil

Gas

Gas

Oil

Gas

Defoamers/antifoam

Broken

Crude oil is a complex substance formed under high pressureand temperature from vegetable and/or animal organic materi-als. A broad spectrum of organic chemical components exist inlight, paraffinic and heavy oils. These include wax up to C60,esters, organic acids, asphaltenes and napthalenes. Dependingon the makeup of these components, the crude oil will have itsown characteristics, including specific gravity, wax content, pourpoint, color, etc.

Crude oil can cause a series of problems:• Wax deposition • Viscous gels at low temperatures (from heavy oils)• Deposition of asphaltenes


17

Production chemicals are used when the process equipment isnot functioning properly or when there are problems such asscale, corrosion, foaming or emulsions.

Again, these chemicals are divided into water-soluble and oil-soluble , depending upon the phase in which they are to be used.

All chemicals that are supplied and used shall have approvedsafety data sheets and complete environmental documentation.

Typically, topside process chemicals may include:• Defoamers/antifoams• Emulsion breakers/demulsifiers• Reverse emulsion breakers/deoilers • Scale inhibitors • Corrosion inhibitors • Wax inhibitors • Asphaltene dispersants • Pour-point depressants • Microbiocides


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North Sea oil Texas oil Utah oil

Wax inhibitors modify the structure on the growing wax crystal,either by co-crystallization or by absorption to the surface of thecrystal. Further growth will then be stopped.

Wax inhibitors Topside process: Oil and produced water

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Wax is present in most crude oils, usually in quantities of lessthan 5%, but even this much can still cause problems. Wax can bedetected by normal analytical methods (IP) and usually rep resentsthat fraction of the oil with a carbon number higher than 18.Wax is formed when the oil is cooled as a result of being producedfrom the well. • Subsea pipelines • Heat exchange • Joule effect • Gas lift (change in solubility)

The wax crystals are formed at a specific temperature (waxappearance point), and then they become so big that theydeposit on the surface and block the pipes or process equipment.

Methods for avoiding wax precipitation: • Heat • Solvents (e.g. xylene) • Blending of

hydrocarbon streams • Wax inhibitors

and dispersants • Mechanical equipment


Wax

18

Number of Melting pointcarbon atoms °F (°C)

16 64 (18)17 72 (22)18 82 (28)19 95 (35)20 99 (37)23 122 (50)25 129 (54)

Depositions

H3C–(CH2)N–CH3

Higher alkanes (n, iso, cyklo-) depositand form thick, firm layers of wax

at specific conditions.

Modifying of wax crystals

Wax crystal Treatment withwax inhibitors

Inhibits further3D growth

Wax particles

Treatment with dispersantsor surfactants

Keeps the wax particles dispersed in the oil phase

Asphaltenes are present in most oil, and they are mainly respon-sible for its black color. Chemically, asphaltenes can be describedas very complex hydrocarbons with a ring structure. They arecharged molecules, and therefore they can agglomerate due toelectrochemical binding mechanisms. Asphaltenes are definedas the hydrocarbons that are not soluble in pentane (C5); hexaneand heptane can also be used in such tests.

Asphaltene depositions can exist already in the reservoir andmigrate out with the oil during production. Asphaltenes can alsodeposit during production after the following process changes:• Physical effects as pressure drop • Gas stripping loss of light ends • Mixing of oil from several wells/formations• Gas lift

Typical moleculestructure of an

asphaltene molecule.

Asphaltenes Topside process: Oil and produced water

21

Mode of operation Change the crystal structure in sucha way that further growth is notpossible. Some of the wax inhibitorsare defined as dispersant-typechemicals that keep the waxcrystals in solution and preventthem from depositing.

Typical injection point(s) For well and production tubing: downhole injection

For topside process: production manifold

For export lines: upstream of the oil coolers

Typical dosage rate It depends on the wax content ofthe oil, but normally 20 to 200 ppm

Typical physical properties Flash point: <145° F (<63° C)(depends on the solvent)

Viscosity: 20 to 100 cP Health: Irritating, depending

on the solvent (see MSDS)

Compatibility Depends upon the solvent inthe product, but in general notcompatible with water or otherwater-soluble chemicals. Usewhite spirit or naphtha fordilution. Compatible withmost types of steel.


Wax inhibitors

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There are several factors that influence the breaking of a water-in-oil emulsion: • Stability. Generally very stable emulsions form if there are

emulsifiers in the oil or if the system has high levels of shear. • Temperature. Emulsions are dissolved faster at high temper -

atures, slower at low temperatures. This is often the reasonsubsea wells have emulsion problems.

• Time. You need time to completely break an emulsion,sometimes hours. This is often the main limitation for oilproduction.

• Fluid dynamics. Turbulent flow will produce a higher risk foremulsification or re-emulsification than laminar flow.

When the process does notmanage to break the emulsion,emulsion breakers are necessary.Most systems require chemicalinjection because the oil pro -duction is often over the designcapacity, has a high water cut, orhas oil that contains asphal tenes,wax or particles of clay/sand.Emulsion breakers are developedby trained personnel and areformulated specifically forthe oil and/or system. Emulsionbreakers are developed with the help of bottle tests on actual field emulsion samples, followed by a field test.

Emulsions Topside process: Oil and produced water

23

Emulsions are defined as one phase dispersed in another. Theyare dynamic, and they change with changing conditions. Thekey is always to try to force the emulsion into instability, so that it separates quickly. In oil production there are two types of emulsions: • Water-In-Oil (WIO) emulsions • Oil-In-Water (OIW) emulsions, or reverse emulsions

Oil will easily emulsify with water, when the following condi-tions are present: • Energy — normally pressure drop over the choke or valve and

mixing in a high-shear pump• Emulsifier — normally a chemical component in the oil, or

other substances such as wax, solids, etc.

Separators are designed for separation of oil, gas and water, butif an emulsion is formed, then the separators will have problemsto separate the phases. To help the separation process, we canuse the following physical or chemical tools:

• Heat • Electrical field • Increased flow rate in the separator • Chemicals (emulsion breakers) • Chemicals (flocculants/deoilers)

Typical example of the breaking of an emulsion.


Emulsions

22

Typical test kit for emulsion-breaker testing.

Mode of operation An emulsion breaker/demulsifierreduces the surface tension on thewater micro-droplets that are sus-pended in the oil. These will thencoagulate to form larger waterdroplets and fall out of the oil. Theresult of this separation is a sharp,clear interface.

Typical injection point(s) Normally they are injected into thesystem as early as possible, other-wise an increased dosage rate mayhave to compensate for injectionlater in the process.

Typical dosage rate Normal dosage rate for emulsionbreakers is in the area of 5 to 25 ppm, based on the total flowrate of oil + water. Some heavycrudes require much higher doses.

Typical physical properties Flash point: >145° F (>63° C)Viscosity: 20 to 100 cP, depending

on the temperature and solventHealth: Irritating, depending

on the solvent (see MSDS)

Compatibility The solvent in the product deter-mines compatibility, but in generalthese are not compatible withwater or other water-solublechemicals. Use white spirit ornaphtha for dilution. Compatiblewith most types of steel.

Emulsion breaker/demulsifierTopside process: Oil and produced water

25

These chemicals are used when the natural separation ofoil/water is not satisfactory.

Emulsion breakers are specially formulated for each process,but because the process changes from time to time (caused bynew wells, increased water cut, etc.), the emulsion-breaker for-mulation must be reassessed from time to time. Breakers usuallyconsist of three to four active components, such as polymers,esters, polyols, block polymers and other surface-active polymers,suspended in a solvent system such as white spirit (solvent),naphtha and higher alcohols.


Emulsion breakers

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Demulsifier

Treatment

Water-in-oil emulsion

Surface-active polymer

Separation of oil and water

The water clarifiers work by reducing or neutralizing the charge onthe oil droplets in such a way that the droplets begin to agglomer-ate into larger drops, and will separate from the water due to thedifference in specific gravity.

Water clarifiersTopside process: Oil and produced water

27

Oil-in-water emulsions are also known as “oily water” or some -times “reverse emulsions” and are a daily problem for mostinstallations because there is usually a statutory limitation on the amount of oil allowed in the waste water. Oil in water is caused by the same mechanisms as for oil emulsions, themain ones being:• Bad separation• Mixing effect over valves and pumps• Treatment with surface-active chemicals such as corrosion

inhibitors, surfactants, etc.• The wrong emulsion breaker or dosage rate

There are several mechanical ways to remove the oil from the produced water, the most important being: • Flotation tanks — Induced Gas Flotation (IGF), Dissolved

Air Flotation (DAF), etc. • Skimtanks — plate-type or API• Centrifugal equipment — Hydrocyclones, centrifuges, etc.

In most cases, this equipment is not enough to solve the problemon its own because: • The stabilizing components are too strong• The droplet size is too small (generally <20 μm)

This requires the use of chemicals.


Water clarifiers

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Treatment

Oil droplets are negatively charged

Positively charged polymer (cationic)

Flocculation

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Treatment

Positively charged ion(e.g., calcium) canchange the charge on the oil droplet

Negatively chargedpolymer (anionic)

Flocculation

Mode of operation Reduces the surface tension on thegas bubbles so they can burst andrelease the gas from the oil.

Typical injection point(s) Normally they are injected into thesystem as early as possible, other-wise an increased dosage rate mayhave to compensate for injectionlater in the process.

Typical dosage rate Normal dosage rate for defoamers/antifoams are 1 to 3 ppm based onthe total flow rate of oil + water forfluorosilicones and 4 to 10 ppm forPolydimethylsiloxanes (PDMS).

Typical physical properties Flash point: >145° F (>63° C)Viscosity: 20 to 100 cP,

depending on solvent and active content

Health: Irritating, depending on the solvent (see MSDS)

Compatibility This depends upon the solvent in the product, but generally thefollowing will apply: Other chemicals: Not compatible

with water or water-solublechemicals

Dilution: White spirit or diesel can be used

Steel: Normally compatible with all types

Seals and hoses: Normally compatible with all types

Defoamers/antifoamsTopside process: Oil and produced water

29

These chemicals, usually comprised of silicon-base molecules,work by reducing the surface tension on the gas bubbles,causing the bubbles to burst.

There are two principles for this depending on the system andtype of defoamer/antifoam.


Defoamers/antifoams

28

Situation 1: Foam on the surface

Situation 2: Gas bubbles in the oil

Gas bubbles

Defoamer/antifoaminjection

Gas bubblescoagulate

Release of gas and oil

Foam Defoamer/antifoaminjection

Foam collapse

Release of gas and oil

Oil phase

There are many types of filter systems, but they all have some-thing in common. They need chemicals to achieve the requiredeffect. Some common filter types are:• Sand filter • Cartridge filter — normally polypropylene-fiber • Multibed filter — normally anthracite and sand in layers • Precoat filter — uses a precoat of diatomaceous earth

Seawater contains approx. 0.5 to 2 mg/L dry particles with sizesranging from 1 to 20 microns.

Water injection: Filtration

31

Water injection gives pressure support in the reservoir in con -nection with oil and gas production. The water is pumped intothe reservoir. Normally seawater is used offshore, but in lateryears, produced water, or water from separate water zones canalso be used.

Before the water is pumped down into the formation, thefollowing processes are normally carried out:• Remove foreign particles through filtration• Add biocides to avoid microbiological growth • Remove O2, CO2 or H2S • Reduce the potential for precipitation of salts • Increase the injectivity

Water injection

30

Lift pumps

Coarsefilter Fine filters

Biocide

Defoamer/antifoamChlorination

Scale inhibitor Polyelectrolyte

Deaeration/degassing Oxygen

scavenger

Injection wells

Injectionpumps

Scale inhibitor Pressure-boosterpumps

Heatexchanger

Typical water-injection system with normal chemical types and injection points.

Water is an excellent medium for microbiological growth, so it isnecessary to treat injection water to reduce the microbiologicalgrowth. The problem is often connected with the growth ofGeneral Aerobe Bacteria (GAB) and anaerobic Sulfate-ReducingBacteria (SRB). GAB growth can result in slime and can be thefirst step to the growth of SRB. Sulfate-reducing bacteria produceH2S which is both toxic and corrosive.

To avoid these problems, biocides are added to the water, oftenthrough an injection of hypochlorite, either as liquid product orby producing it with an electrochlorinator.

Primary treatment involves hypochlorite being injecteddownstream of the seawater intake pumps, at a dosage rateof 0.5 ppm residual chlorine in the seawater. The hypochloritewill remove 99% of the bacteria, but will be removed later inthe system through the deaeration process and by the oxygenscavengers (see next page). A secondary batch treatment withbiocides is therefore necessary.Caution: Hypochlorite isextremely corrosive.

Secondary treatment is normally abatch treatment with aldehyde- oramine-base biocide formulations,usually at a dosage rate of 200 to1,000 ppm for 1 to 4 hrs, 1 to 2times per week.

Water injection: Bacteria

33

Polyelectrolyte Mode of operation These are polymers with either a

cationic (+) or anionic (–) charge.They bond with the fine particlesto form larger aggregates whichare easily removed in the filter.

Typical injection point(s) Upstream of the filter units.

Typical dosage rate 0.2 to 2 ppm as product. Can be diluted with freshwater.

Typical physical properties Flash point: Not exhibited Viscosity: Low Freeze point: +41° to –14° F

(+5° to –10° C)Health: See MSDS

Compatibility Normally compatible with otherchemicals. They will react withparticles in water. Polyelectrolytesare normally compatible with stain-less steel and plastic but can becorrosive to carbon steel and brass.

Water injection: Solids

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Treatment

Particles in water arecharged negatively

Positively charged polymer (cationic)

Particles agglomerate and are collected by the filter

Shapes of bacteria

Coccus (sphere)

Bacillus (rod)

Curve

Spiral

Stalked bacterium

Oxygen scavenger Mode of operation Chemical reaction with

oxygen in seawater.

Typical injection point(s) Between back-flow and pressure-increase pumps.

Typical dosage rate Normally 10 to 15 ppm. Note: 6.5 ppm of scavenger is required to remove 1 ppm of oxygen.

Typical physical properties Flash point: Not exhibited Viscosity: Low Freeze point: +41° to –14° F

(+5° to –10° C)Health: See MSDS

Compatibility Oxygen scavengers are not com -patible with acids due to releaseof SO2 which is toxic. They are cor-rosive to steel but are compatiblewith most gasket materials.

Water injection

35

Seawater contains 6 to 8 ppm (6,000 to 8,000 lb/billion) of oxy-gen, is highly corrosive to carbon steel and must be removed. Thebulk of the dissolved oxygen is normally removed by mechanicalmeans such as vacuum or gas stripping. Scavenging chemicalsare used to remove the residual dissolved oxygen. The main typeof chemicals normally used have a bisulfite base: either sodiumbisulfite or ammonium bisulfite. These oxygen scavengers canbe catalyzed to increase the efficiency and rate of reaction.

The reaction with oxygen is complex, but several factors can be controlled: • Increase the temperature • Change the pH • Use a catalyst such as cobalt or iron• Increase the dosage rate

Reaction mechanism for removal of oxygen:

2NaHSO3 + O2 ➞ Na2SO4 + H2SO4

Water injection: Oxygen removal

34

Questions? Call the M-I SWACO office nearest you.

©2004 M-I L.L.C. All rights reserved. *Mark of M-I L.L.C. PMC.1302.0710.R1 (E) 3M Litho in U.S.A.

P.O. Box 42842Houston, Texas 77242-2842

www.miswaco.comE-mail: [email protected]

Technology Centers:

HOUSTON, TEXASTel: 281·561·1300 · Fax: 281·561·1441

STAVANGER, NORWAYTel: 47·51·577300 · Fax: 47·51·576503

Technical Service Centers:

NISKU, ALBERTA, CANADATel: 780·955·3388 · Fax: 780·955·2064

ABERDEEN, SCOTLANDTel: 44·1224·285500 · Fax: 44·1224·890904

BERGEN, NORWAYTel: 47·55·173850 · Fax: 47·55·173851

DUBAI, U.A.E.Tel: 971·4·8833100 · Fax: 971·4·8837197

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Documents

Production Operator's Handbook