03 Oilfield Water

SITP Corrosion

Onyekpe, B.O of 1 ©Univation

3 OILFIELD WATER

THE WATER CYCLE

There is a constant body of water on the planet, which is, largely undergoing a

process of continuous recycle:

The Figure shows that:

• water is precipitated

as rain, hail, snow

• some becomes surface water

in streams, rivers, lakes and oceans

• some is sub-surface

forming sub-surface streams and lakes

• the water returns for further precipitation by:

evaporation of surface water

transpiration from vegetation

condensation into clouds

PURE WATER

SITP Corrosion


Chemically water is dihydrogen oxide (H2O). In practice, it dissociates a little to yield

hydrogen ions (H+) and hydroxyl ions (OH-):

H20 ⇔ H+ + OH-

The concentration of hydrogen and hydroxyl tons is extremely small at 24°C:

H+ 10-7 g ions/I ≡ 10-7 g/l

OH- 10-7 g ions/l ≡1.7 X 10-6 g/l

H,0 ≅1000 g/I

pH =log [H+]

It will be seen that the pH of pure water is 7 at 24°C.

If the measured pH of a water sample is <7 it follows that the water contains

dissolved substances (e.g. CO2) that render it acid. Similarly, if the pH is >7 the

water contains dissolved substances (e.g. bicarbonates) that render it alkaline.

Note: distilled water is not pure water; it contains dissolved CO2 and is acid.

WATER COMPOSITION

Water is an extremely effective solvent.

In the water cycle it comes into contact with:

• atmospheric gases

• soils, rock

• organic matter

• industrial processes- effluent etc

As a result. natural water is:

• not pure water

• contains both dissolved and suspended solids

Natural water compositions mill vary according to the sources

SITP Corrosion


Significance of constituents in oilfield brines

CATIONS

Calcium

• major constituent of oilfield brines (up to 30000 pprn)

• readily combines with HCO3- CO3

- and SO42- to give precipitates, scales and

suspended solids

Magnesium

• present at lower concentration than Ca2+ (<< 0.1 x Ca2+ concentration)

• may town scale (MgCO3) with carbonate ions (relatively unlikely because

MgCO3 is very much more soluble than CaCO3)

• more likely to be incorporated in CaCO3 scale

SITP Corrosion


Sodium

• usually present at high concentration (thousands of ppm)

• does not produce deposits, scales or suspended matter

• like other ions, increases the conductivity

Barium

• produces extremely insoluble compound with SO42- (BaSO4)

• BaSO4 scales arc extremely difficult to remove

• waters containing high SO42- usually contain low Ba2+ and vice-versa

Strontium

• like Ba2+, combines with SO42+ to give insoluble scale (SrS04)

• SrS04 is more soluble than BaSO4 ; it is usually found incorporated in BaS04

scales

• sulphate scales containing SrS04 remain difficult to remove

Iron

• may derive from the formation or be due to corrosion (of tubulars, for

example)

• may be present as ferric (Fe") or ferrous (Fe') ion or as a suspended solid

(iron 'oxides')

• iron 'oxides' deposited on metal surfaces can often provide an ideal

environment for microbial activity

ANIONS

chloride

• major constituent of oilfield waters; often exceeding 100000 ppm

• forms soluble salts so does not provoke deposition

• whilst not corrosive in itself it:

o increases water conductivity

SITP Corrosion


o may provoke pitting, crevice and deposit corrosion, also chloride stress

corrosion cracking of certain passive metals

carbonate/bicarbonate

• waters usually contain only HCO3- , but a small increase in pH can produce CO3

2-

• capable of forming insoluble salts with Ca2+

• carbonate scales are usually easy to remove by acid or mechanical means

sulphate

• readilv forms insoluble salts with Ca2+ , Ba2+, Sr2+

• these salts difficult to remove chemically; not easy to remove mechanically

• SO42- is involved in metabolism of sulphate reducing bacteria; may favour

microbially assisted corrosion.

Other constituents that may be present

oxygen

• formation water is usually anaerobic (oxygen free)

• oxygen ingress significantly increases the corrosivity of a water to non-passive metals

• if dissolved iron is present it will often precipitate in presence of O2 (ferric

salts are more insoluble than ferrous)

• great care needed to remove O2 from injected water

carbon dioxide

• dissolves to give a more acid solution

• may encourage scaling in high Ca2+ water

• may reduce pH sufficiently to prevent scaling and increase corrosivity

hydrogen sulphide

• dissolves to give a more acid solution

SITP Corrosion


• since metal sulphides are insoluble, H2S may encourage protective films

• if protective filets formed, may encourage pitting attack

• a progressive increase in H2S content of water may indicate microbial

activity

• sulphide deposits may plug waterways

pH

• most oilfield water have a pH in the range 4 to 8

• the more alkaline a water, the greater the chance of depositing Ca2+ and

Fe2+ /Fe3+ salts

o deposition may favour some protection, but may also:

§ plug waterways

§ encourage anaerobic microbial activity

§ interfere with heat transfer

• the more acid the water, the smaller the chance of deposition

o this may result in an increase in corrosivity

Checking a water analysis

• check the total dissolved solids (TDS):

o the sum of all the cations and anions (in ppm) should equal the IDS

(also in ppm)

o the agreement should be close, but may not be exact

o do not add he twice by including dissolved iron and total iron

• check the equivalence of anions and cations:

o since anions and cations have opposite charge and water is electrically

neutral, the total positive charge present must equal the total negative

charge

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o since ions have different mass and different charge, the mass of

cations should not equal the mass of anions

o we need to compare equivalent amounts

o if we divide the concentration (in g/1) of an ion by the ionic weight, we

get a measure of the number of each ion present in the water (g

ions/l)

o if we then multiply by the charge on the ion, we obtain a measure of the

total charge due to each ion in the water (equivalents/I)

o the sum of the cationic equivalents/I should equal the sum of the

anionic equivalents/I (see example below)

• check the conductivity or resistivity:

o it should reflect the IDS

• check the pH:

o is it consistent with the reported composition, e.g. bicarbonate content?

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This analysis seems sound:

• the analysed TDS closely relates to the sum of all the ion concentrations

• the equivalent concentrations of cations and anions coincide

WATER CORROSIVITY

• water corrosivity depends on a variety of factors including:

o pH - more acid, more aggressive

o O2 content - more oxygen, more corrosion of non-passive metals

o metabolizing bacteria

o suspended solids - tend to promote deposit and microbially assisted

corrosion

SITP Corrosion


• a major factor is whether the water is likely to deposit insoluble and protective

scales

scaling

• the most common source of scale is CaCO3

• when CO. dissolves in water it produces carbonic acid (HCO3), bicarbonate

and carbonate ions:

CO2 + H2O ⇔ H2CO3

H2C03 ⇔ HC03- + H+

HCO3- ⇔ C03

2- + H+

• if Ca2+ is present, calcium bicarbonate (Ca(HCO3)2) and calcium carbonate

may be formed:

Ca2+ + 2HC03- → Ca (HC03)2 soluble

Ca2+ + CO32- → CaC03 insoluble

• natural water usually contains HCO3- and very little CO3

2-; the primary Ca2+

salt produced is Ca(HCO3)2

• if CO, is lost from the water Ca(HCO3)2 can decompose to CaCO3:

Ca(HCO3)2 → CaCO3 + CO2 + H2O

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CaCO3 is more insoluble and likely to precipitate

• CO2 may be lost by heating or following a sudden pressure drop: the former

can occur in heat exchangers, the latter in well screens, pumps, valves,

vessels, etc.

• note that if the pH is increased, CO32- forms preferentially to H2CO3 and

HCO3 this favours CaC03 deposition

• at cathodically protected surfaces- or at cathodes in galvanic cells, the pH

increases locally, favouring local CaCO3 deposition

Predicting CaC03 scaling

• a water saturated with CaCO, tends to precipitate scale which may protect

against corrosion, it may also produce encrustation in water and injection

wells

• the degree of CaCO, saturation has been used as an indicator of water

corrosiv ity and scaling/encrustation tendency

Langelier Index

• the Langelier Index (LSI) compares the actual pH of a water (pHa) with the

pH it would have if it was saturated with CaCO3 (pHs)

LSI = pHa - pHs

Strictly, it applies to fresh waters of low TDS and pH 6.5 to 9.5. i.e. not oilfield brines

• pHs can be calculated:

pHs = (pK12 – pK1

S ) + pca + pAlk

pK12 and pK1

S are constants depending on temperature etc.

pca is the negative log. of the calcium concentration (in mg/I)

pAlk is the so-called bicarbonate (or VI) alkalinity expressed as mg/I

equation for pH, therefore, reduces to:

pHs = constant (C) + pca + pAlk

SITP Corrosion


• a nomogram exists that allows easy calculation of pHd (see below)

• if LSI is:

positive - the water has scale forming tendency and is likely to be

relatively non-corrosive

negative - the water has no scaling tendency and is likely to be

corrosive

To determine:

pca; locate mg/I value for calcium hardness (expressed as CaCO3) on the mg/I

scale. Proceed vertically to the upper diagonal line, then across to the

pCa scale.

PAlk. locate mg/l value for M alkalinity (expressed as CaCO3 ) on the mg/l scale.

Proceed vertically to the lower diagonal line, then across to the pAlk scale.

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C: locate mg/l value for TDS on the mg/l scale. Proceed vertically to the

appropriate temperature line, then across to the C scale.

Ryznar index

• whilst the LSI derives from theoretical considerations, the Ryznar Index (RSI)

is empirical:

RSI = 2pHs - pHa

• if RSI is:

<6.0 -indicates scale forming tendency

>6.5 - indicates no scale foaming tendency

In practice, the following, based on experience, helps interpretation of the data:

Note:

• calculated LSI and RSI values do not always lead to the same interpretation;

a judgement must be made

• the calculation must be modified for very concentrated waters

Stiff and Davis Saturation Index

• this index applies to oilfield brines where the TDS is >5000 ppm

• pH, is calculated using the equation

pHs = pca + pAlk + K

Thus, the Stiff and Davis index (SDI) is given by:

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SDI = pHa -Pca - PAlk -K

The value of the constant, K, takes into account the influence of the higher overall

concentration of ions in the water.

• steps in the calculation:

o convert concentrations of major ions (in mg/l) to ionic strengths using

the following factors

Note ionic strength = 1/2 CZ2

where C = concentration of ion in moles/l

Z = charge on ion

• calculate total ionic strength by summing individual ionic strengths

• determine value of K from Figure taking account of temperature

• determine Pca and pAlk from monogram on p 10

• calculate Stiff & Dads index from pHa , and values determined above

SITP Corrosion


• If SDI is:

positive - the water has a scaling, tendency and is likely to be relatively

non-corrosive

negative - the eater has no scaling tendency and is likely to he corrosive

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WATER IN THE OILFIELD

• water is produced in increasing quantity with the produced oil as a held

depletes

• this water will always have a high TDS

• it must be cleaned up (hydrocarbon and acid gas removal) prior to disposal

• secondary oil recovery may require water injection of water from:

o produced water clean up

o water wells

o seawater, where available

• these will be blended in varying proportion depending on the rate of

produced water production and the injection requirements

• blended water may also be used for some domestic uses and in desalting

• well water may undergo secondary treatment to produce utilities water (e.g.

boiler feed) and potable water

potential water problems

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• it will be necessary to infect treatment chemicals into the produced fluid:

o corrosion inhibitor

o scale inhibitor

o demulsifer

o antifoam

o hydrate suppressant

these must be mutually compatible and not be deleterious to any subsequent

blended water quality

• the drop in pressure downhole as water is drawn from a water well may

lead to scale deposition in the well screens and gravel packs; a heavily

scaling water would normally be unsuitable for blending

• in the blending plant the treatment chemicals must remain compatible and

the two waters being blended must also remain compatible: mixing waters

can change the scaling tendency (needs scaling calculations)

• injection water must be compatible with the formation water on breakthrough

to prevent pore plugging (needs scaling calculation) and must be treated to

remove solids and oxygen, destroy bacteria and to avoid corrosion and

deposition

• water treatment of well water is required to alter the composition of the water

to render it potable and/or suitable for hailer food

Injection Water

• wherever possible, injection water is handled in a closed system, this

prevents ingress of oxygen

• the water should be non-scaling and compatible with formation water

• oil must be removed (floatation cell)

• suspended solids must he removed (filtration)

SITP Corrosion


• oxygen scavenger must be added (ammonium or sodium sulphite, or

hydrazine)

• biocides must be added (see Table)

• corrosion inhibitor may be required

• sampling points must be installed throughout the water conditioning train

Bacteria can become resistant to a biocide. It may be necessary to:

• change the biocide at intervals

• inject two biocides (one intermittent /one continuous or both intermittent)

• change the time schedule (more frequent/ less frequent) of intermittent

treatment with changes in biocide concentration

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Water treatment fur steam raising:

• most boilers in the oilfield used for steam raising are classed as low (Q00

psi) or intermediate (200-500 psi) boilers

• boiler feedwater treatment is intended to:

o prevent scale or deposit accumulation

o prevent boiler corrosion and in the steam system

o maintain steam purity (avoid droplet carryover and transfer of silica (SiO2) in steam)

• a good quality water source reduces the extent and cost of feedwater

treatment

• boiler feedwater should have the lowest hardness, alkalinity, SiO2, TDS

and suspended solids economically possible (maximum limits for boiler in

Table below: feedwater limits must be lower depending on % blowdown)

RECOMMENDED UPPER CONCENTRATION LIMITS IN BOILER

WATER

• silica content ensures <0.03 ppm SiO2 in steam

• values follow those of American Boiler Manufacturers Association

• these levels to be achieved by blowdown:

100max

XTDSTDS

B f=

B = blowdown rate as % of feed rate

TDSf =TDS in feedwater (ppm)

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TDSmax = maximum permitted TDS in boiler (ppm)

• if the source water does not meet these requirements it must undergo:

o suspended solids removal (filtration)

o sobering (by precipitation of CaCO3 or ion exchange)

• the water in a boiler concentrates as steam is produced; scale formation

must be prevented and corrosion controlled

• this requires both scale and corrosion control within the boiler

• scale control aims to precipitate insoluble salts within a boiler and to ensure

that the precipitated particles are dispersed and do not adhere to heat

transfer surfaces

o this is usually achieved by adding a sodium phosphate and some alkali

(to pH 9.5) which precipitates calcium phosphate, magnesium

hydroxide and magnesium silicate

o sludge dispersants (e.g. polvacrylates) are also added to disperse the

precipitates

o failure of dispersement can, at best, reduce the thermal efficiency of a

boiler and, at worst, produce overheating of a tube and failure by metal

creep. Magnesium silicate scales are often associated with a failure by

overheating

• corrosion control is achieved by:

o maintaining a very low oxygen content; adding sodium sulphite or

hydrazine depending on boiler pressure

o maintaining an adequate pH (~9.5)

o addition of volatile amine (morpholine) to protect the steam system

o remember volatile treatment renders condensed water not potable

• foam control is essential to avoid carryover of water droplets; this is

achieved by:

o effective boiler water level control

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o restricting dissolved solids content (phosphate treatment and

blowdown)

o restricting suspended solids content (blowdown, periodic chemical

cleaning)

o antifoam agents are sometimes used

Water treatment for potable water

• water can be obtained for drinking purposes by:

o distillation

o reverse osmosis

of non-potable water

• all potable water must be treated to destroy bacteria (e.g. UV treatment or

chlorine dosing)

• if distilled water is to be used as potable water, chemicals that carryover in

the steam from the boiler (e.g. morphline or ammonia) are debarred

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• distilled water will usually require some post-distillation mineral addition to

render it palatable and also to reduce the risk of 'red water'

Materials Selection

• the general principles for materials selection for oilfield waters follow those

outlined in the materials selection module

• a NACE Standard exists that deals with materials selection:

o RP0475, 'Selection of Metallic Materials to he Used in All Phases of Water

Handling for Injection into Oil-Bearing Formations'

• the RP covers both water and CO2 injection

• the following equipment is considered:

o pumps (downhole motor driven, deepwell shaft driven, centrifugal

(mufti-stage volute, single stage horizontal injection pumps)

o valves (gate and throttle)

o filters

o oxygen strippers

o H2S strippers

o well equipment

o miscellaneous equipment

o meters

03 Oilfield Water

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