Scale Deposition

8/18/2019 Scale Deposition

1/18

Scale deposition

Scale problems in production

Wells producing water are likely to develop deposits of inorganic scales. Scales can

and do coat perforations, casing, production tubulars, valves, pumps, and downhole

completion equipment, such as safety equipment and gas lift mandrels. If allowed to

proceed, this scaling will limit production, eventually requiring abandonment of the

well.

Scale deposits usually form as a result of crystallization and precipitation of minerals

from water.

Scales: crystallisation of salts from fluids

Occurrence: Scale is deposited in formation matrix and fractures, wellbore,

downhole pumps, tubing, casing, flowlines, heater treaters, tanks, and salt water

disposal and water flood systems.

Causes: Primary factors affecting scale precipitation, deposition, and crystal growth

are:

Mingling of two unlike waters having incompatible compounds in

solution; change of temperature

Supersaturation- Supersaturation is the most important reason behind mineral

precipitation. A supersaturated is the primary cause of scale formation and

occurs when a solution contains dissolved materials which are at higher

concentrations than their equilibrium concentration. The degree of

supersaturation, also known as the scaling index, is the driving force for the

precipitation reaction and a high supersaturation, therefore, implies high

possibilities for salt precipitation.

Effect of temperature –

calcium sulfate is less solubleat higher temperatures.

Change of pressure on

solution- The sulfates of calcium, barium and strontium are more soluble at

higher pressures. Consequently, formation water will often precipitate a

sulfate scale when pressure is reduced during production. The scale may


2/18

deposit round the wellbore, at the perforations, or in the downhole pump (if

used).

Evaporation (affects concentration)

Agitation

Long exposure time (crystal growth)

Change of pH-The amount of CO2present in the water affects the pH of the

water and the solubility of calcium carbonate. However it really does not matter

what causes the acidity or alkalinity of the water. The lower the pH, the less likely

is CaCO3

precipitation. Conversely, the higher pH, the more likely that

precipitation will occur

Source of Oil Field Scale: The chief source of oilfield scale is mixing of

incompatible waters. Two waters are called incompatible if they interact chemically

and precipitate minerals when mixed. A typical example of incompatible waters are

sea water with high concentration of SO4

-2and low concentrations of Ca

+2, Ba

+2/Sr

+2,

and formation waters with very low concentrations of SO4

-2but high concentrations of

Ca+2

, Ba+2

and Sr +2

. Mixing of these waters, therefore, causes precipitation of

CaSO4, BaSO

4, and/or SrSO

4. Field produced water (disposal water) can also be

incompatible with seawater. In cases where disposal water is mixed with seawater

for re-injection, scale deposition is possible. During the production, the water is

drained to the surface and suffers from significant pressure drop and temperature

variations. The successive pressure drops lead to release of the carbon dioxide with an

increase in pH value of the produced water and precipitation of calcium carbonate.

Zinc sulfide scale is more likely when zinc ion source mixes with the hydrogen sulfide-

rich source within the near wellbore or the production tubing during fluid extraction. Lead

and zinc sulfide scales have recently become a concern in a number oil and gas fields.

These deposits have occurred within the production tubing and topside process facilities

Composition: The composition of scales is as variable as the nature of the watersthat produce them. The most common oil field scale deposits are calcium carbonate

(CaC03), gypsum (CaS04 • 2HP), barium sulfate (BaS04) and sodium chloride

(NaCl). Calcium sulfate (CaS04) or anhydrite does not usually deposit downhole but

may be deposited in boilers and heater treaters. A less common deposit is strontium

sulfate ( SrSO 4) .

Nature: Scale deposited very rapidly may have gas channels, by very porous, and

be easy to remove with acid. Scale deposited slowly may be very hard and dense,


3/18

and may be difficult to remove with acid or other chemicals.

Mechanism of scaling

1. Supersaturation: Behind every chemical process, there must be athermodynamic driving force. For precipitation, this is given by the difference

between the chemical potential of a given substance in the stable and

metastable/labile region. To represent this driving force, the term

supersaturation is often used. At

point A, the solution is not

supersaturated, there is no

thermodynamic driving force and

therefore no precipitation. By

changing either the temperature

or the concentration e.g. by

evaporation some solute) one

can exceed the solubility

concentration (point B and D)

and cross into the

supersaturated regime. Now, a

thermodynamic driving force forprecipitation is established and

formation of solids may take place.

2. Nucleation sites: Although a driving force is established, a solution can besupersaturated without solid formation occurring. The short explanation to this is

that the supersaturation has tobe sufficiently high; we have to be in the labileregime of figure 1. In the metastable region of figure 1, the driving force is not


4/18

large enough to overcome the energy amount required to form a surface; a solidparticle. Spontaneous precipitation will therefore not take place. However, when

a surface is present, already existing defects at the surface can act asnucleation sites. By this, the surface free energy required is lowered, allowing

solid particles to form and grow even in the metastable regime.

3. Precipitation – nucleation is followed by precipitation and adherence.

Oilfield Scale Types

The most common scales encountered in oilfield operations are sulfates such ascalcium sulfate (anhydrite, gypsum), barium sulfate (barite), and Strontium sulfate

(celestite) and calcium carbonate. Other less common scales have also been

reported such as iron oxides, iron sulfides and iron carbonate. Lead and zinc sulfide

scale has recently become a concern in a number of North Sea oil and gas fields(Collins and Jordan, 2001). There follows a brief description of each scale.

1. Carbonates -Calcium carbonate or calcite scale has the greatest stability in

oilfield circumstances, so it is the most common form of calcium carbonate

encountered in oilfield production operation.

Carbonate scales frequently appear in the wellbore, especially near the

wellhead where, because of pressure drop, dissolved CO2

escaped from

produced water and caused water pH as well as the saturation index of

carbonate minerals to increase.

Carbonate scale formation occurs when connate water or aquifer water passes

through the bubble point and carbon dioxide is evolved.

First, carbon dioxide reacts with water to produce carbonic acid as seen by

reaction

CO2 (g) + H2O(l ) H2CO3 (aq) (3)

This carbonic acid will continue to dissociate hydrogen, creating new deprotonatedspecies of carbonic acid, as seen in reaction 4 and 5.

H2CO3 (aq) + H2O(l) H3O+ (aq) + HCO−3 (aq) (4)HCO−3 (aq) + H2O(l) H3O+ (aq) + CO2− 3 (aq) (5)

In the water mixture there will be a mixture of the species H2CO3, HCO−3 and CO2− 3 .

Finally, in the presence of calcium and carbonic acid, calcium carbonate willprecipitate out as seen by reaction 6.

CO2− 3 (aq) + Ca2+(aq) CaCO3 (s) (6)Since produced water usually contains a carbonic acid and calcium ions, arecombination of these reactions will give a better representation of the situation, as

seen by reaction 7.Ca (HCO3)2 (aq) CO2 (g) + H2O(l) + CaCO3 (s) (7)

Calcium and carbonic acid together in liquid form will be in equilibrium with water,solid calcium carbonate and CO2 gas.


5/18

Most behaviour of the calcium carbonate equilibrium can be predicted from LeChâtelier’s equilibrium principle. This principle states that a chemical system at

equilibrium will always try to counteract any imposed change in pressure,temperature, volume and composition.

Pressure dependence: When pressure is decreased in a chemical system, theequilibrium will try compensate by increasing the pressure. Because CO2 is the only

gaseous specie, the only way to increase pressure is by shifting the equilibrium

towards producing more CO2. A decrease in pressure will then result in more

precipitation of calcium carbonate.

Concentration dependence: If the concentration of calcium or carbonic acid is

increased or the partial pressure of CO2 is decreased, then there would be an

equilibrium shift towards the right and more precipitation of calcium carbonate.

Temperature dependence: The

solubility of calcium carbonate willdecrease as the temperature

increases. This is an interesting

phenomena because most

solubilities increase with increasing

temperature and therefor one gets

less precipitation. One of the

reasons for this behaviour is the fact

that the precipitation of calcium

carbonate require energy

(endothermic). This can be writteninto the equilibrium equation as

follows:

energy + Ca (HCO3)2 (aq) CO2 (g) + H2O(l) + CaCO3 (s) (8)

When the temperature increases, the energy also increases, and the equilibrium will

try to counteract this by consuming energy. The equilibrium is then shifted towards

right, favouring precipitation of calcium carbonate.

Scaling will increase with increased temperature

Scaling increases with an increase in pH

Scaling increases and becomes harder with increased contact time.

Scaling decreases as total salt content (not counting Ca ions) of water increases

to a concentration of 1 20g N aCl/ 1 000g of water. Further increases in NaCI

concentration decrease CaC03 solubility and scaling increases

Scaling increases with increase in turbulence


6/18

Stiff Davis Method (SI) - Calcium Carbonate - Methods of Predicting Scale

SI=H-K- – AK where H=actualH of water

= - log (moles of Ca++/litre)

AK= - log (equivalents of total alkalinity/litre)

Total alkalinity= CO3-2 + HCO3-2

K=a constant which is a function of

salinity composition and water temperature

SI0 Scale Formation Is Likely

2. Sulfates

i) CaS04.2H2O or anhydrite or hemihydrate - Calcium sulfate can

crystallize from aqueous solution in three forms: gypsum (CaSO4.2H

2O),

hemihydrate (CaSO4.1/2H

2O) and anhydrate (CaSO

4).

Gypsum, the most common scale occurs at relatively low temperature. At

higher temperature (above 100 ºC), the stable phase predicted is anhydrite

(CaSO4). Many parameters are affecting this problem. Temperature,

pressure, fluid concentration, ratio of brine to hydrogen, fluid dynamic andtype of porous media are among these parameters.

Causes

Mixing of two waters, one containing calcium ions and the other

containing sulfate ions, often causes gyp scaling, particularly in

water flooding.

Pressure reduction : A reduction in pressure

decreases solubility and causes scaling.

Pressure drop from 2 ,000 psi to atmosphericpressure may precipitate as much as 900 ppm

(0. 3 Ib/bbl of water) calcium sulfate.

Casing leaks or poor cement jobs are frequent

causes of scaling due to downhole mixing of

water from the producing zone with water from

other porous zones.

Casing leaks or poor cement jobs are frequent

causes of scaling due to downhole mixing of

water from the producing zone with waterfromother porous zones.


7/18

Agitation increases scaling tendency

An increase of magnesium ions in the range of 24 ,400-36,600

mg/liter may increase the solubility of CaS04 up to several times the

solubility of CaS04 in distilled water and thereby decrease scaling.

Within the pH range of 6 to 8, p H has very little effect on solubility

and scaling.

Evaporation of water due to evolution of free gas near or in the

wellbore may cause supersaturation and gyp scaling. Hydrates in

gas wells frequently become

supersaturated due to evaporation,

with resultant scaling

The effect of temperature on

solubility of gyp scale and anhydriteis illustrated in Figure 9-4. A

change in temperature will change

the solubility of calcium sulfate or

gyp and the tendency to

precipitate.

ii) BaS04 and SrS04 - Both BaS04 and SrS04 scales are usually caused

by mingling of two unlike waters, one containing soluble salts of barium or

strontium and the other containing sulfate ions. Barium sulfate is often

precipitated in gas wells as hydrates are evaporated.

For a given NaCl concentration, BaS04 scaling increases with

decreases in temperature as a result of decreasing BaSO4

solubility

Pressure drop may decrease the solubility of BaS04 in a given NaCl

solution and cause scaling

Solubility of BaS04 is noted in Table 9-

2 with changes in percent NaCI andtemperature. Solubility of BaS04 in

many of the high salinity oil-field brines

may average 85 to 1 00 mg/liter.

Presence of radioactive strontium in

scales is a major safety and

environmental issue.


8/18

3. NaCl

Precipitation of sodium chloride is normally caused by supersaturation-

usually due to evaporation or decreases

in temperature. For example, from Table

9-3, it may be noted that 4,000 mg/ l ofNaCI will be precipitated from saturated

salt water if temperature drops from

140°F to 86°F.

Salt precipitation may be quite severe

near bottom of the tubing or in the well bore in gas wells or high GOR

oil wells producing very little or no water at the surface.

Precipitation may result from both drop in temperature and drop in

pressure through perforations and into the tubing. Dry gas will

evaporate water, leaving the salt as a precipitate. Table 9-4 shows the

great difference in solubility of NaCI, Gypsum, CaC03, and BaS04 in

distilled water.

4. Iron salts- iron salts are precipitated during simulation if pyrite, siderite, iron

rich in clays are present in rocks. Scales do not consist of one salt but mixtures

of barium, strontium, calcium and iron salts along with wax if present in oil.

Iron sulfide scale is present in oil and gas producing wells, sour wells and

water injectors where the injected water has high sulfate content.

The disposal water contains dissolved H2S, whereas the aquifer water

contains dissolved iron. When these two waters are mixed together, H2S

reacts with the iron ions and precipitates iron sulfide species, as shown in

Equation (2.7).

Iron scales are frequently the result of corrosion products such as various

iron oxides and iron sulfide. Sulfate-reducing bacteria can be a source of

hydrogen sulfide , which then reacts with iron in solution or with steelsurfaces to form iron sulfide . If oxygen is introduced to a system , it can


9/18

react with iron to form a precipitate and with steel surfaces to form an

oxide coating.

5. Silica – silica and silicate chemistry(SiO2) is quite complicated and highly

varied in rocks and reservoir brined. Silicates scale is rarely a problem in low

temperature reservoirs.

6. Dolomite [CaMg(CO3)2] -there is no way to precipitate dolomite in lab. It forms

in 1000 to 10^6 years in field.

Prediction of Scaling Tendencies

A. Field -rapid decline in production, formation damage, perforation choking,

tubing choking B. Analysis of water properties immediately after sampling is the best approach to

predict the scale formation tendency.C. Analysis of water flood water provides a reliable basis for estimating scaling in

injection lines and down hole in injection wells.D. Analysis of produced brine predicts the scaling in the surface facilities. It may

provide the basis to estimate the scaling in the down hole equipment in producingwells because of possible prior deposition of scales due to release of CO2 formBi-carbonate ions in water as pressure declines.

E. If bottom hole pressure is near original, bottom hole sample brought undersubsurface condition may provide reliable information on both down hole and

surface scaling tendencies under original reservoir condition.F. To determine Calcium carbonate super saturation, take a well head sample of

water and run test on water at the time of sampling. If the calcium carbonate supersaturation is more than 10% of bi-carbonate alkalinity content, then the water willusually have a scaling tendency.

IDENTIFICATION OF SCALES

The first step is to determine which scales are forming and where they are forming.

The simplest method of physically detecting scale in the wellbore is to runcalipers down the wellbore and measure decreases in the tubing inner

diameter Gamma ray log interpretation has been used to indicate barium sulfate scale

because naturally radioactive radium (Ra226) precipitates as an insoluble

sulfate with this scale.

Wells with intelligent completions and permanent monitoring systems are beingdesigned to contain scale sensors. The function of the scale sensor is double

duty— not only to provide early warning about the initiation of productionimpairment by scale generation but also to provide information about possible

impairment of the smartwell sensors and valves by films of scale. X-ray diffraction is the most used method for the scale identification. This

involves directing a beam of X-ray on to a powdered sample of scale crystal.Each chemical compound in the scale diffracts x-rays in a characteristics


10/18

manner which permits its identification. It is the fastest method and requires

least amount of sample.

Chemical analysis may also be used for scale identification. Samples of scales

are decomposed and then dissolved in chemical solution. Scale compounds

are then analysed by standard techniques of titration or precipitation.

Scale compounds will usually not be identified unless the analysis is made foreach specific chemical compound, By comparison, all chemical compound can

readily be identified form an x-ray analysis. (1) After adding HCI to the scale

sample, effervescence usuallyindicates CaC03, especially if thesample does not contain iron

sulfide or iron carbonate. The odourof H2S will indicate the presence of

sulphide scale. Table 9-5 is asummary of easily run laboratory or

field tests to determine type of scale

(2) Analysis of field brine can show scaling tendencies. Table 9-6 shows an

example of BaS04 scale caused by mixing of Bartlesville and Arbucklebrines from wells in the Boston Pool, Oklahoma .


11/18

(3) Table 9-7 shows anexample of predictable

CaC03 precipitation due topressure drop and release

of CO2 from HC03 – 1,inthe Grayburg formation,Hobbs field, New Mexico

SCALE REMOVAL

Scale remediation techniques must be quick and nondamaging to the wellbore,tubing, and the reservoir. If the scale is in the wellbore, it can be removed

mechanically or dissolved chemically. Selecting the best scale removal technique fora particular well depends on knowing the type and quantity of scale, its physical

composition, and its texture. Mechanical methods are among the most successful

methods of scale removal in tubulars. When pulling costs are low (e.g., readily

accessible and shallow land locations), the least expensive approach to scaling is

often to pull the tubing and drill out the scale deposit.

Chemically inert scales are not soluble in chemicals. Chemically reactive scales may

be classified as water soluble, acid soluble and soluble in chemicals other than wateror acids.

1. Mechanical methods

I. Wireline chipping- time consuming, not a cost effective method

II. Milling- Scales are generally brittle. One of the earliest methods

used to break off the thin brittle scale from pipes was explosives: a

strand or two of detonation cord (“string shot”) placed wi th an

electronic detonation cap at the appropriate location in the wellbore,

most effectively at the perforations. Thicker scales require more

stringent means. Impact bits and milling technologies have been

developed to run on coiled tubing inside tubulars using a variety of

chipping bits and milling configurations. Such scale removal rates

are generally in the range of 5 to 30 linear ft/hr of milling.

III. Impact techniques-works much like a jack hammer, hammering

the scales until they break. These impact techniques work best for

brittle scales.

IV. Jetting-Tools can be used with chemical washes to attack soluble

deposits where placement is critical. Water jetting can be effective

on soft scale, such as halite, but is less effective on some forms of


12/18

medium to hard scales such as calcite and barite. The use of

abrasive slurries greatly improves the ability of jets to cut through

scale but can damage the steel tubulars and valves.

“Sterling beads” is an alternative abrasive material for scale removal

by jetting. This material matches the erosive performance of sandon hard, brittle scales, while being 20 times less erosive of steel.

Sterling beads do not damage the well if prolonged jetting occurs in

one spot. The beads are soluble in acid and have no known toxicity,

simplifying use and cleanup. Hard scales, such as barite, are

removed at rates > 100 ft/hr. This tool is capable of descaling

configurations other than wellbore tubing (e.g., removing hard barite

scale deposits on two gas lift valves in a multiplemandrel gas lift

completion).

For perforated casing, reperforating is a most effective method of

bypassing perforations sealed with scale.

Mechanical methods such as string shot, sonic tools, drilling , or

reaming have been used to remove both soluble and insoluble

scales from tubing, casing, or open hole.

Internally plastics coated tubulars -not a cost effective solution

old wells but feasible in new wells

2. Magnetic method- a permanent or induced magnet is placed to prevent

nucleation and precipitation. It has to be planned and installed in the mechanical

completions. It is being practiced in USSR.

3. Chemical methods -most effective, cost feasible

Chemical treatment design

Objectives-to treat the pores, perforations and downhole

equipment with scale dissolver in order to remove/prevent scale

deposition

Data check list-

I. Field

II. No. of wells

III. Well production(production/Status)

IV. Perforated interval

V. Petro-physics

VI. Tubing id and od

VII. Wireline observation

VIII. Types of scales


13/18

IX. Produced/injected water analysis

X. Previous history and treatment

Treatment procedure

Carry out production test, build up if well is not in conformity withreservoir engineer prediction

Prepare the well for injection

Demulsifier spearhead: inject a slug containing 0.1% solution of

demusifier in deoxygenated seawater along with scale inhibitor (70-100 gal/ft.) of perforation +wellbore volume below packer

Inject a spacer containing (4-6 %) EDTA/Erythorbic acid in

deoxygenated seawater with 2%KCl -(70-100 gal /ft. of perforation)

Inject a more concentrate on scale dissolver solution 20-25% w/w in

deoxygenated seawater +2%KCl

Calculate the injection volume to perforate 4ft. around wellbore andbottom of tubing. Add foaming agent if gas lift is not available.

Scale dissolver over flush solution- depending upon reservoir

pressure inject tubing volume of diesel or liquid nitrogen or seawaterwith foaming agent.

Scale dissolver shut in for 24 hr. – to assist the scale dissolver, agitate

after 4 to 1 hr. 4 ft. involves flowing of 5 bbl of fluid out of well (in mostcases) so that unreacted solution is moved to the scale surface.

A three stage treatment may be planned. Each may be separatedafter chemical analysis of produced fluid and well performance.

Water-Soluble Scale-The most common water-soluble scale is sodium chloride

which can be readily dissolved with relatively fresh water. Acid should not be used to

remove NaCI scale. If gyp scale is newly formed and porous, it may be dissolved by

circulating water containing about 55,000 mg/liter NaCl past the scale. At 100 deg. F,

55,000 mg/liter NaCl will dissolve three times as much gypsum as fresh water.

Acid-Soluble Scale-

i. The most prevalent of all scale compounds, Calcium carbonate (CaCO3), is

acid soluble. HCl or Acetic acid can be used to remove calcium carbonate.Formic acid and sulphonic acids have been used effectively to remove such

scales.ii. Acetic acid has special application down the hole in pumping wells when it

is desired to leave chrome plated or alloy pumps in a well during acid

treatment. Acetic acid will not damage chrome plated surfaces attemperature below 200 deg. F, However HCl may severely damage the

chrome plated surfaces.iii. Acid soluble scales also include iron carbonate (FeCO3), iron sulphide

(FeS), and iron oxide (Fe2O3).

iv. HCl plus a sequestering agent is normally used to remove iron scale. Thesequestering agents holds iron in solution until it can be produced from the

well. A sequestered Fe acid, such as HCl + .75% Acetic acid + .55% citricacid may provide over 15 days of sequestering time.


14/18

v. Normally 15% sequestered HCl is used but 20% may be necessary becauseof slow reaction with iron compounds.

vi. A 10% solution of Acetic acid may be used to remove iron scales without anadditional sequestering agent. However Acetic acid is much slower than

HCl.

------------------------------------------------------------------------------------------------Type of acid soluble scale Gallons of 15% HCl/Cu ft of scale

-----------------------------------------------------------------------------------------------CaCO3 95

Fe2O3 318FeS 180-----------------------------------------------------------------------------------------------

ACID INSOLUBLE SCALES:

i. The only acid insoluble scale which is chemically reactive is Calcium

Sulphate or gypsum. Calcium sulphate though not reactive in acid, can betreated with chemical solutions which can convert calcium sulphate to an

acid soluble cmpounds like Calcium carbonate or calcium Hydroxide CaCO3 or Ca(OH)2 which can be removed with acid.

---------------------------------------------------------------------------------------------

Type of solution % of gypsum dissolved

24 hours 72 hours-----------------------------------------------------------------------------------

------------NH4HCO3 87.891.0

Na2CO3 83.885.5

Na2CO3 – NaOH 71.285.5KOH 67.6

71.5--------------------------------------------------------------------------------

---------------

ii. most of the chemical shown above convert gypsum to CaCO3 . KOH

converts gypsum to Ca(OH)2 , which is soluble in water or a weak acid;however only 68 – 72% is converted to gypsum leaving an undissolved

scale in matrix.iii. After converting gypsum the residual fluid is circulated out. CaCO3 can be

removed with either HCl or Acetic acid.

SCALE REMOVAL IF WAXES, IRON CARBONATE AND GYPSUM ARE

PRESENT:

i. Degrease with a solvent such as Kerosene or Carbon Di-sulphide plus asurfactant.

ii. Remove iron scales with a sequestered acid.

iii. Convert gypsum scales to CaCO3 or Ca(OH)2.


15/18

iv. Remove converted CaCO3 scale with HCl or Acetic acid. Dissolve Ca(OH)2 with water or weak acid.

v. Compounds such as EDTA (Ethylene di-amine Tetra-acetic acid) and DTPA(Di-ethylene Tri-amine Penta-acetic acid) can dissolve gypsum without the

necessity of conversion to CaCO3 or Ca(OH)2. But EDTA or DTPA are not

used because of high cost.

CHEMICALLY INERT SCALES:

The most common chemically inert scales are Barium Sulphate (BaSO4) and

Strontium Sulphate SrSO4. Barium Sulphate scales on the formation face or in theperforation may be removed by mechanical methods such as string shots, drilling outor under reaming or by-passing by re-perforating. The best approach is to prevent the

scale deposition.SCALE PREVENTION

Scale prevention

Inhibition of Scale Precipitation by Inorganic Polyphosphates

Inhibiting scale with a few parts per million of molecularly dehydrated

polyphosphates is called a " threshold treatment. " When a crystal nucleus is

formed, polyphosphate is adsorbed on the surface and slows further crystal

growth.

For about 25 years, sand-grain size polyphosphate particles have been

injected as a part of regular fracturing treatments. Also, wells have been

fractured specifically to inject the phosphate particles. The polyphosphate

slowly dissolves in produced water and prevents scale precipitation.

Reversion to Orthophosphate-When placed in solution all polyphosphates tend tohydrolyze into orthophosphates. In the presence of calcium ions, insoluble calcium

precipitates may be formed. Polyphosphates will also revert to orthophosphates in

the presence of acid.

Rate of reversion to orthophosphates depends on temperature, acidity, mineral

content, phosphate content, and nature of polyphosphates. Reversion does not start

until polyphosphate goes into solution.

Sodium-calcium phosphates are normally used in well treatment because of their

slow dissolving rate. This property assures a near constant phosphate concentration

in the water over a long period of time. The objective is for the phosphate-containing

water to be produced from the well before reversion can occur.

Inhibition of Scale with Polyorganic Acid- During the late 1960 ' s, a very stable

polyorganic acid, LP-55 , was field-proven by Halliburton. This liquid polymer inhibits

scale formation through "threshold treatment" approach. It has no temperature limit

and does not precipitate solids.

Placement during fracturing-

If placed during a conventional frac treatment, the LP-55 liquid should

precede the introduction of sand. If injected during a minifrac, carried out onlyto place the chemical, the well is fraced and then LP-55 is pumped in the well


16/18

at rates of 0. 25 to 1.0 bbl/minute to permit rapid leakoff. The feedback rate is

controlled by pressure drop when the well is produced from formation

capillaries or from minute fractures.

It may be combined with a corrosion inhibitor if desired; however, lab tests of

compatibility should be made before injecting both a corrosion inhibitor andscale inhibitor into a well.

The polyorganic acid is placed on the basis of 10 gals of chemical per 1,000

gals of water or alcohol. The polyorganic acid can also be injected in a water

solution down the annulus to reduce scale deposition in the casing, tubing,

pump, and surface equipment.

It can also be used in the power oil of hydraulic lift type of downhole pumps

Inhibition of Scale with Organic Phosphates and Phosphonates

Various organic phosphates are now offered to inhibit against calcium sulfate,barium sulfate, and to a lesser degree, against calcium carbonate scale. Many of

these water soluble liquid organic phosphates are suitable for squeeze treatments

into the formation

Exxon Inhibitors-

Exxon Chemical Company offers several organic phosphate inhibitors, two of

which are COREXIT 7605 and SURFLO H-372.

Exxon Chemical's COREXIT 7605 has replaced their COREXIT 7640 to inhibit

against calcium and barium sulfate scale deposition.

Exxon Chemical 's SURFLO H-372 replaces COREXIT 7641 to inhibit against

most scales including CaC03, CaS04, and BaS04 • SURFLO H-372

wasformerly sold by NL Chemicals.

COREXIT 7640 treating procedure for downhole squeeze:

Preflush with 30 bbl of freshwater

Squeeze 165 gallons COREXIT 7640 dissolved in 30 bbl of freshwater

Overflush with 100 bbl of freshwater

Shut in well for 24 hr.

Return to production.

COREXIT 7641 is a water soluble organic phosphates, especially designed to

prevent deposition of CaCO3, CaSO4, BaSO4. It may be applied by continuousinjector or formation squeeze technique.


17/18

Exxon Production Research Compan/4 reported average effective inhibiting of nine

months against very severe gyp scaling in one West Texas field, with retreatment

being considered when the inhibitor in the produced water decreases to about 7

ppm. With this approach, some wells have been relatively scale free with

retreatments every 15 months depending on water production.

Visco Inhibitors-Visco Division of Nalco Chemical Co. offers a number of

phosphate, phosphonate, and polyacrolate scale inhibitors

I. VISCO 950 inhibits against deposition of BaSO4, CaS04, and CaC03. VISCO

950 may be added to surface water systems or may be used for continuous

feed into down the casing-tubing annulus. As an effective formation squeeze

treatment scale inhibitor, Visco 950 is best used with a 1 :9 ratio of produced

water, with 200-500 barrels of overflush into the formation.

II. Visco 953 controls CaC03, CaS04, and BaS04 scales at very low dosages in

oil and gas wells, water injection systems, and salt water disposal systems.

For water injection systems, continuous treatment is best; for downhole usage

, batch treatment or semicontinuous treatment is most effective. Visco 953

also is used as a formation squeeze treatment scale inhibitor, mixed at a 1 :9

ratio with overflush into the formation. However, the most effective treatment

is to mix a 1-3% solution of Visco 953 with produced water, displacing the

solution into the formation.

III. VISCO 959 is designed for formation squeeze jobs to inhibit CaC03 and

sulphate deposits in oil and gas wells and producing equipment. Typicaltreatment is to preflush with 5 to 1 0 bbl of produced water, pump in VISCO

959 mixed with formation water at a ratio of one to ten, overflush with 50 to

250 bbl of formation water, depending on daily water production. Usual

treatment is about 1 65 gal of VISCO 959.

Inhibiting Scale with Polymers

ARCOHIB S-223, a salt of polyacrylic acid, developed by Atlantic Richfield is

marketed by major service companies.

Procedure for use in prevention of BaSO4, CaSO4, CaCO3 is as follows:

Pump in 100-150 gal. HCl spearhead to ensure CaCO3 scale clean up. Pump

in the slug consisting of 45 bbl of produced water, 100 gal of 15% HCl and

100 gal AACROHIB polymer.

Follow up with enough CaCl2 to raise the CaCl2 content in the 45 bbl slug of

water to 10,000 ppm. This raises the pH from 1.2 to about 4.5 and causes the

polymer to crosslink and precipitate as a gel in the formation.

The crosslink polymer is then pushed into the formation and dispersed with100-200 bbl of produced water.


18/18

CaC03 Scale Prevention by Pressure Maintenance-If calcium carbonate scale can

be predicted as a result of drop in reservoir pressure, pressure maintenance should

be considered as a means of reducing scaling.

Case study

Details: semoga field is an oil field in the rimau block, which is located south

Sumatra Indonesia. There is also a nearby oil field in this block

These fields have experienced reservoir souring when H2S is being generated from

the reservoir and entering the system. To reduce the H2S concentration in the

facilities H2S scavenger to injected in the system.

Problem: there was a separation system problem at Free Water Knock Out (FWKO)

semoga station. FWKO outlet was dismantled for the injection purposes. It was

found that oil outlet down at the downstream valve LCV ---- 0.5 ’’ only

Reason:

X-ray diffraction and x-ray fluroscence analysis confirm that the deposit is

CaCO3 scale.

There is H2S scavenger brand X injection at the downstream of the LCV in

the FWKO with a conc of 11,030 ppm.

The scale dosage was 9-10 ppm only. Lab test shows H2S scavenger brand

X injection reduced scale inhibition % from 97.2 to 35.3% with a 9 ppm of

scale inhibitor.

No deposits found in oil outlet line at downstream of LCV at kaji station which

has same H2S scavenger point and dosage. Dosage was 17.3

Date post:	07-Jul-2018
Category:	Documents
Upload:	nitesh-kumar
View:	217 times
Download:	0 times

Scale Deposition

Documents