SCALE
What is it? Why does it form?
Types of scales:
1) Calcium/Magnesium carbonates - CaCO3 & MgCO3 - formed from the
following occurrences:
a) Change in formation or system temperatures and/or
pressures: As the temperature increases, carbonate scaling
tendencies increase. As pressure decreases, carbonate scaling
tendencies increase.
b) Decrease in solubility due to mixing incompatible waters: If one
mixes two or more waters with a Total Dissolved Solids (TDS)
difference of more than 20%, carbonate scale can occur.
2) Calcium sulfate - CaSO4 - formed from the following occurrences:
a) Change in formation or system temperatures and/or pressures: As the
temperature increases, Calcium sulfate scaling tendencies decrease up
to —118 degrees F then increase from --118 to —136 degrees
F. As pressure decreases, Calcium sulfate scaling tendencies
increase.
b) Decrease in solubility due to mixing incompatible waters: If one
mixes two or more waters with a Total Dissolved Solids (TDS)
difference of more than 20%, Calcium sulfate scale can occur.
3) Barium and Strontium sulfates - BaSO4 and SrSO4 respectively are
formed from the following occurrences:
a) Barium sulfate will generally occur whenever two or more waters
are mixed with one of the water(s) containing greater than 2.0
milligrams per liter (mg/1) Barium and the other water(s) containing
greater than 150-300 mg/I soluble sulfate.
b) Strontium sulfate scales will generally occur based upon either an
increase in water temperature and/or a decrease in water pressure
as well as oversaturation when two different TDS waters are mixed.
SCALE
What is it? Why does it form?
Types of scales:
1) Calcium/Magnesium carbonates - CaCO3 & MgCO3 - formed from the
following occurrences:
a) Change in formation or system temperatures and/or
pressures: As the temperature increases, carbonate scaling
tendencies increase. As pressure decreases, carbonate scaling
tendencies increase.
b) Decrease in solubility due to mixing incompatible waters: If one
mixes two or more waters with a Total Dissolved Solids (TDS)
difference of more than 20%, carbonate scale can occur.
2) Calcium sulfate - CaSO4 - formed from the following occurrences:
a) Change in formation or system temperatures and/or pressures:
As the temperature increases, Calcium sulfate scaling tendencies
decrease up to —118 degrees F then increase from --118 to —136
degrees F. As pressure decreases, Calcium sulfate scaling tendencies
increase.
b) Decrease in solubility due to mixing incompatible waters: If one
mixes two or more waters with a Total Dissolved Solids (TDS)
difference of more than 20%, Calcium sulfate scale can occur.
3) Barium and Strontium sulfates - BaSO4 and SrSO4 respectively are
formed from the following occurrences:
a) Barium sulfate will generally occur whenever two or more waters
are mixed with one of the water(s) containing greater than 2.0
milligrams per liter (mg/1) Barium and the other water(s) containing
greater than 150-300 mg/I soluble sulfate.
b) Strontium sulfate scales will generally occur based upon either an
increase in water temperature and/or a decrease in water pressure
as well as oversaturation when two different TDS waters are mixed.
" THE KIT "
CONTENTS:
1) XYLENE
2) 15% HYDROCHLORIC ACID
3) BAR MAGNET
4) MAGNIFYING GLASS
5) LEAD ACETATE STRIPS
6) 10% COPPER SULFATE SOLUTION IN 89% DISTILLED WATER + 1% # 2
7) POCKET KNIFE
8) BUTANE LIGHTER
9) POCKET THERMOMETER
10) PLASTIC BAGS
11) DIXIE CUPS
12) SURGICAL SAFETY GLOVES
These tests must always be performed at a safe
location---completely removed from any oil and gas
location/pipeline. Follow the directions and safety
precautions for each test.
USES:
1) XYLENE- Take a small portion of the solids sample and add to a Dixie cup. Pour a small
amount of xylene onto the sample and gently stir. If sample begins to dissolve turning the
xylene from clear to brown or black, the solids have Hydrocarbons in them. One can then
take a separate sample onto the knife blade and gently heat it with the butane lighter. If the
solids sample begins to melt the solids are most probably a form of paraffin.
* Safety note- Do not use the open flame butane lighter near the flammable xylene or any
oil or gas location. Xylene fumes are hazardous and narcotic and should not be inhaled.
2) 15% HYDROCHLORIC ACID- Take a small portion of the solids sample and add to a
Dixie cup. Pour a small amount of 15% Hydrochloric acid onto the sample and gently stir.
If the sample begins to bubble gas and dissolve observe the color of the liquid acid in the
cup. If the acid remains clear, the sample contains Calcium or Magnesium carbonate. If the
liquid acid turns yellow or green, wet with water one end of a lead acetate strip and hold it
above but not into the liquid in the Dixie cup. If the lead acetate strip turns brown/black or
if a metallic shean is seen on the strip, Hydrogen sulfide is present.
This indicates that the sample contains Iron sulfide. If the acid turns yellow and the lead
acetate paper remains white take the bar magnet and touch it to the original dry sample, if
the sample is magnetic, the solids contain Iron oxide, Mill scale and/or processed metal . If
the acid turns yellow, the lead acetate paper remains white and the original dry sample is
not magnetic, the solids contain Iron carbonate. *Safety note- 15% HCL acid gives off
dangerous fumes and should not be inhaled. Any exposed skin or pipe surface should
immediately be washed with lots of water and soap.
3) BAR MAGNET- When applied to a sample of Iron oxide, Mill scale and/or processed
metal (steel) will show their magnetic properties.
4) MAGNIFYING GLASS- When used to look closely at a solids sample can easily
identify irregular sand grains, pieces of man-made materials such as "0" rings and cotton
gloves and/or hexagonal (six sided) Calcium sulfate crystals.
5) LEAD ACETATE STRIPS- When moistened are used to identify the presence of
Hydrogen sulfide gas. Can be used for identification of Iron sulfide solids and other safety
related issues. *Safety note- Lead acetate strips contain Lead and should not be placed in
one's mouth. Lead is a hazardous metal and the strips should be disposed properly. Do not
use and throw down on the ground.
6) 10% COPPER SULFATE SOLUTION- When applied to a corrosion coupon or
any metal surface will immediately detect visually the absence of a coating and/or
corrosion inhibitor. Turns unprotected metal bright copper color on contact.
7) POCKET KNIFE- If left in " The Kit " can be very useful for performing these tests
and scrapping out a sample of solids from many locations. * Safety note- The knife
provided in " The Kit " is sharp and can cause injury if improperly used. Do not use any
metal object including the knife provided in " The Kit " in a manner that can cause a spark
in or around any oil and gas location and/or pipeline.
8) BUTANE LIGHTER- Is used in testing solids samples for melting or burning
tendencies. The butane lighter produces an open flame. Care should be excercised when
using this instrument on any solids sample or around any flammable liquid and/or gas.
9) POCKET THERMOMETER- Can test the relative temperature of practically anything.
10) PLASTIC BAGS- Can contain solids samples for transport.
11) DIXIE CUPS- Nice, disposable test vessels for solids testing.
12) SURGICAL GLOVES- Used to protect users of " The Kit " from the
hazardous chemicals contained and used therein.
13) COMMON SENSE- Not supplied in " The Kit " but necessary for use of same.
Scale Coupons
Most scale coupons sent to this Lab will be of mild steel. The dimensions
are x 3", each containing three holes, in addition to the top hole which
is used to secure the coupon to the coupon chuck when it is installed in
a system.
Upon receipt of a scale coupon it will be coated with oil, CaCO3, Iron Oxide,
Iron Sulfide and various other materials. In order to determine which materials
are present and in what amounts, the following steps should be followed:
Scale Coupon Analysis
Equipment needed:
1. Analytical balance
2. Beaker (150 ml or 250 ml)
3. Hot plate
4. Drying oven @-160 degrees F.
5. Desiccator
6. Brillo pads
Reagents Needed:
1.
2.
3.
4.
5.
6.
Toluene
Distilled H2O
Acetic acid diluted 1:4 with distilled H2O
HC1 diluted 1:1 with distilled H2O
Acid Inhibitor
IPA
Procedure:
1.
2.
3.
4.
5.
6.
7.
Weigh beaker on balance and record weight.
Place coupon in beaker and weigh together. Record Weight.
Fill beaker with Toluene until coupon is completely submersed and heat
gently on hot plate to a slow boil. Continue heating until all
hydrocarbon materials are disolved in the Toluene. Decant liquid and
repeat until Toluene remains light in color.
Dry beaker and coupon in drying oven. Cool to room temperature in
Desiccator and re-weigh and record weight. The weight difference are
organic deposits.
Fill beaker with 1:4 acetic acid. Heat gently on the hot plate to
a slow boil. Continue heating until sample stops effervescencing,
decant liquid, repeat if necessary.
Dry beaker and coupon in drying oven. Cool to room temperature in
Desiccator and re-weigh and record weight. The weight difference are
Carbonate deposits.
Fill beaker with 1:1 HC1 and acid inhibitor solution: (5-10% inhibitor in
1:1 HC1) to remove the iron compounds present. Heat gently on hot plate to a
slow boil, decant liquid, repeat until acid solution remains light in color.
Scale Analysis
i Continued
Page 2.
To Determine if iron sulfide (FeS) is present place a damp strip of
lead acetate paper over beaker when 1:1 HC1 solution is added. If
the paper turns dark FeS is present, report as positive or negative.
8.
Dry beaker and coupon in drying oven. Cool to room temperature in
desiccator and re-weigh and record weight. The weight differences
are iron compound deposits.
9.
Remove coupon from beaker and scrub clean using brillo pad and
water, rinse coupon in distilled water and damp dry. Place coupon in
beaker of Isopropyl alcohol to remove any water remaining. Dry coupon
and re-weigh, record weight.
Calculations:
1.
Weight of coupon with scale equals weight of beaker and coupon minus
weight of beaker.
2.
Total weight of scale equals weight of coupon with scale minus final
weight of cleaned coupon.
3.
mg/sq. in = mg scale
factor
4.
g/sq. in./year = (mg/sq. in) (10-3) (365)
days in system
5.
mpy = (weight loss of coupon) (factor)
days in system
6.
Composition of scale: Use the same calculations as are given
in the scale analysis procedure.
NACE Standard T1A0374-90
Item No. 53023
National Association of Corrosion Engineers
Standard
Test Method
Laboratory Screening Tests to Determine the
Ability of Scale Inhibitors to Prevent the Precipitation of
Calcium Sulfate and Calcium Carbonate From Solution
(For Oil and Gas Production Systems)
The National Association of Corrosion Engineers (MACE) issues this standard in conformance
with the best current technology regarding the specific subject. This standard represents a
consensus of those individual members who have reviewed this document, its scope and
provisions. It Is Intended to aid the manufacturer, the consumer, and the general public. Its
acceptance does not In any respect preclude anyone, whether he has adopted the standard or
not, from manufacturing, marketing, purchasing, or using products, processes or procedures
not In conformance with this standard. Nothing contained in this NACE standard is to be
construed as granting any right, by implication or otherwise, to manufacture, sell or use In
connection with any method, apparatus, or product covered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This standard
represents minimum requirements and should in no way be interpreted as a restriction on the
use of better procedures or materials. Neither is this standard intended to apply in all cases
relating to the subject Unpredictable circumstances may negate the usefulness of this
standard in specific instances. NACE assumes no responsibility for the Interpretation or use of
this standard by other parties and accepts responsibility for only those official NACE
interpretations Issued by NACE In accordance with its governing procedures and policies
which preclude the issuance of Interpretations by Individual volunteers.
Users of this standard are responsible for reviewing appropriate health, safety, and regulatory
documents and for determining their applicability in relation to this standard prior to its use. This
NACE standard may not necessarily address aN safety problems and hazards associated with the
use of materials, operations, and/or equipment detailed or referred to within this document.
CAUTIONARY NOTICE: NACE standards are subject to periodic review, and may be revised or
withdrawn at any time without prior notice. NACE requires that action be taken to reaffirm, revise,
or withdraw this standard no later than two years from the date of Initial publication. The user is
cautioned to obtain the latest edition. Purchasers of MACE standards may receive current
Information on all standards and other NACE publications by contacting the NACE Publication
Orders Department, P.O. Box 218340, Houston, Texas 77218 (telephone 713/492-0535).
Approved November 1974
Revised January 1990
National Association of Corrosion Engineers
P.O. Box 218340
Houston, Texas 7 218
713/492-0535
Copyright 1990, National Association of Corrosion Engineers
T111011144110
Foreword
Scale can be defined as an adherent deptatit of inorganic compounds
precipitated from water onto surfaces. Meet oilfield waters are brines
containing large amounts of calcium saes. When calcium is deposited
as calcium carbonate or calcium sulfate. a lose of production and
increased maintenance expenses can result; therefore, scale inhibition is of primary importance to the of producer.
Scats inhibitors can be used in many circumstances to control
scats formation, thereby reducing production difficulties. Inhibitors
are commercially available and are widely used in of and gas
production systems. T'he test methods in this standard are designed
to provide a relative and quantitative measure of the abilities of
inhibitors to prevent the precipitation of solids, a necessary and
critical stage in the formation of scale deposits. The laboratory
screening tests descridid in this standard cannot and do not allow for
the wide variation in water chemistry and system properties seen in
field operations. As such they must only be regarded as a starting
point in the evaluation of scale inhibition products. The existence and
use of these methods allow for a uniform mode of collection of
screening test results and facilitates discussion of the results by
interested parties.
This standard, issued by NACE Group Committee T-1 on
Corrosion Control in Petroleum Production. was originally prepared
by Task Group T-10-9 and was revised by Task Group T-1D-31, a
component of Unit Committee T-1D on Control of Meld Conosion by
Chemical Treatment. The members of Task Group T-1D-31 are
consumers and producers of scale inhibitors and other interested
parties, who use NACE Standard TM0374 (latest revision) or a
modification of this standard on a regular basis.
The test methods in this standard have been selected by Unit
Committee T-10 as a means of comparing, under the specified
laboratory conditions, the effectiveness of inhibitors in preverang
precipitation of calcium sulfate and calcium carbonate from solution.
As the prices of such products change with time and may be
unkritem to the tester, no attempt has been made to dilute the
inhibitor to a common cost base.
Section 1: General
1.1 The test methods described in this standard are static laboratory
screening tests designed to give a measure of the ability of inhibitors
to prevent the precipitation of calcium carbonate and calcium sulfate
from solution at 160°F (71°C).
deemed to be outside the scope of this standard. However, field
conditions. field brine composition and other variables noted
above should be considered at some point in inhibitor evaluation
prior to final inhibitor selection for field use.
1.2 These test methods we recommended only for ranking the
performance of different chemicals under laboratory conditions set by
these methods. They we not intended to provide actual field treating
rates.
1.4 Tests should be conducted at various inhibitor concerti*** in
order to obtain a better comparison of inhibitors under labor elory
conditions set by these methods. The inhibitor concentration mauled
for a field applications fa* to be different than That debar-tithed
under these laboratory conditions.
1.3 Many factors, such as reaction kinetics, fluid velocity and
composition. variable temperatures and pressures, scale adherence
and solids dispersion can significantly affect actual scale deposition
under field conditions. Detailed consideration of these parameters is
1.5 This standard lists the necessary apparatuses, reagents. and
procedures for conducting screening tests.
Section 2: Calcium Sulfate Precipitation Test
2.1 This section lists the apparatus and procedure for conducting the
calcium sulfate precipitation screening test.
2.2 Apparatuses and solutions
2.2.1 Constant temperature water bath or forced draft oven
with the capability of maintaining the specified temperature
within `2°F (1°C).
2.2.2 Clean and dust-free glass test cells (4 oz [approximately
125 mL) bottles with a positive sea).
2.2.3 Synthetic brine prepared with distilled or deionized
water, as follows:
2.2.3.1 Calcium-containing brine: 7.50 g/L. NaCI (ACS
(American Chemical Society, Washington, D.C.] Reagent grade); 11.10 g/L CaCl2 - 2H20 (ACS Reagent
grade).
2.2.3.2 Sulfate-containing brine: 7.50 g/L NaCI (ACS
Reagent grade): 10.66 g/L Na2S0, (ACS Reagent grade).
NACE
2.2.3.3 Note: Insoluble materials in very small quantities
will remain after the specified reagents have ccinOstaty
dissolved. For corsislency of results, solutions shout/lbw
filtered through a 0.45 micron filter.
2.2.4 Apparatus for reproducibly delivering 50 -Lt 0.5 mi., e.g.,
graduated cylinders or volumetric pipets.
2.2.5 One percent (wt) deionized water solutions of nhltribes ter
be tested: 0.1% (wt) inhibitor solutions in deienized water *aid
be used for tests where inhibitor loadings are to be betel* 10
mg/l....
2.2.6 Graduated measuring pipets in the following sizes: 0.1. 0.5
and 1.0 mL.
2.2.7 Standard reagents and apparatus for determination of
calcium concentration as per ASTM D 511-88 or D 1126-86, (1)
API RP 45,(2) "Standard Methods for the Examination of Water
and Wastewater (Part 300)," 3) and other accepted test meth
ods.
4
TM0374-90
2.3 Test Procedure
2.3.9 Determine the calcium ion concentration by procedures
given in ASTM D 511-88 or D 1126-88, API RP 45, "Standard
Methods for the Examination of Water and Wastewater (Part
300)," or another accepted test method. NOTE: Calcium ion
concentration values for duplicate test samples often differ by
two percent or more. Some analysts consider a five percent
difference to be unacceptable and to be cause for rerunning the
test
2.3.1 All tests are conducted on the inhibitor on an as-received
basis; 1% and 0.1% dilutions are made from the as-received
inhibitor.
2.3.2 Using the 1% and 0.1% dilutions, pipet the desired amount
of inhibitor into each test cell. Duplicates should be run of each
concentration.
2.3.10 Report the average of the duplicate calcium ion concentration values as mg/L calcium sulfate retained in solution for
each inhibitor test concentration and both blank concentrations.
2.3.3 Duplicate blanks should be prepared as follows:
2.3.11 Representative data from the evaluation of three
inhibitors are given in Table 1. These figures are examples
only and do not reflect experimental precision. For a
percent inhibition calculation, see Section 4.
2.3.3.1 Two samples of the calcium-containing brine (50
mt. each) are set aside. The blanks before precipitation
are determined by measuring the calcium ion concentrations (Paragraph 2.3.9) and dividing each value by 2.
"ASTM. 1916 Race St., Philadelphia, PA 19103-1187.
American Petroleum Institute (API), 1220 L St., N.W., Washington.
DC 20005.
(3)
American Public Health Association. 1015 15th St.. KW., Washington. DC 20005.
(
2.3.3.2 The blanks after precipitation are prepared
and handled as in Paragraphs 2.3.4 through 2.3.9 but
do not contain a scale inhibitor.
121
2.3.4 Add 50 mL of sulfate-containing brine to the test cell and
mix well. Add 50 mt. of calcium-containing brine to the test cell.
TABLE 1 — Calcium Sulfate
Retained in Solution (as
Calcium Sulfate, mg/L)
2.3.5 Immediately cap the test cell and agitate to mix the
brines and the inhibitor thoroughly.
Scale
2.3.6 Place all test cells and blanks in a forced draft oven or
immerse to 3/4 of their lengths in a water bath at 160°F
(71°C) for 24 hours.
2.3.7 Remove the test cells after the 24-hour exposure and
avoid agitation. Allow the test cells to cool to 77°F (25°C) s
9°F (5°C) for a time not to exceed two hours.
2.3.8 Pipet 1 ml of the test brine to a suitable vessel, avoiding
the transfer of calcium sulfate crystals. and dilute with distilled
water, deionized water, or as otherwise specified in the calcium
determination method to be used.
Inhibitor
A
B
C
1 ppm
3 ppm
5 ppm
10 ppm
20 ppm
5140
4080
4896
5140
4352
5103
5140
4896
5140
5140
5068
5140
5140
5140
5140
Blank (after precipitation) 3808
Blank (before precipitation) 5140
These data indicate that inhibitor A is best. Note: Costs of the
inhibitors have not been considered.
Section 3: Calcium Carbonate Precipitation Test
3.1 This section lists the apparatus and procedure for conducting
the calcium carbonate precipitation screening test.
3.2.4 Fritted-glass gas dispersion tube(s) (medium or
coarse porosity rating).
3.2 Apparatus and solutions
3.2.5 Synthetic brines prepared with distilled or deionized
water. as follows:
3.2.1 A regulated source of carbon dioxide (CO 2). All recognized grades of CO2 are suitable for this test
3.2.2 Constant temperature water bath or forced draft oven
with the capability of maintaining the specified temperature
within _t 2"F (1°C).
3.2.3 Clean and dust-free glass test cells (4 oz [approximately
125 mL) bottles with a positive seal). Caution: The amount of
vapor space above the test solutions in Paragraph 3.3.6 will
affect the test results. To maximize the validity and reproducibility of test results, choose test cells that vary in capacity
(volume) when sealed by 5% or less; that is, V, = V i; 0.025 V,
where V, equals the desired range of test cell capacities and V
equals the mean test capacity.
2
3.2.5.1 Calciuni-containing brine: 12.15 gIL CaCt2 21120 (ACS Reagent grade); 3.68 g/L MgCl 2 - 6H20
(ACS Reagent grade); 33.0 9.11 NaCI (ACS Reagent
grade).
3.2.5.2 Bicarbonate-containing brine: 7.36 g/L
NaHCO3 (ACS Reagent grade); 33.0 g/L NaCI (ACS
Reagent grade).
3.2.5.3 Note: Insoluble materials in very small quantities
will remain after the specified reagents have completely
dissolved. For consistency of results, the solutions
should be filtered through a 0.45 micron filter.
NACE
•
TPA0374-90
3.2.8 Apparatus for reproducibly delivering 50 ± 0.5 mL, e.g.,
graduated cylinders or volumetric pipets.
3.2.7 One percent (wt) deionized water solutions of inhibitors to
be tested: 0.1% (wt) inhibitor solutions in deionized water should
be used for tests with loadings below 10 ppm where inhibitor
loadings are to be below 10 mg/L.
3.2.8 Graduated measuring pipets in the following sizes: 0.1,
0.5. and 1.0 mL.
3.2.9 Standard reagents and apparatus for determination of
calcium concentration as per ASTM D 511-88 or D 1126-86,
API RP 45. "Standard Methods for the Examination of Water
and Wastewater (Part 300)." and other accepted test methods.
3.3 Test Procedure
3.3.1 All tests are conducted on the inhibitor on an asreceived basis; 1% and 0.1% dilutions are made from the asreceived inhibitor.
3.3.2 Using the 1% and 0.1% dilutions, pipet the desired amount
of inhibitor into each test cell. Duplicates should be run of each
concentration.
3.3.3 Duplicate blanks should be prepared as follows:
3.3.3.1 Two samples of the calcium-containing brine (50
mL each) are set aside. The blanks before precipitation
are determined by measuring the calcium ion concentrations and dividing each value obtained by 2.
3.3.3.2 The blanks after precipitation are prepared and
handled as in Paragraphs 3.3.4 through 3.3.10, but do
not contain a scale inhibitor.
3.3.4 Both the calcium- and bicarbonate-containing brines
should be saturated with CO2 immediately before using. Saturation should be accomplished at room temperature by
bubbling CO2 through a bitted-glass gas dispersion tube
immersed to the bottom of the container. A rate of 250
rritimin. of CO2 for 30 minutes will be sufficient to saturate up to
1 L of each brine simuttaneously. A tee may be used to spirt
the gas flow for this purpose.
3.3.5 Add 50 mL of bicarbonate-containing trine to the test cell
and mix well. Add 50 mL of calcium-containing brine to the test
cell.
3.3.6 Immediately cap the test cell and agitate to mix brines and
inhibitor thoroughly. The cells must be capped tightly to avoid
loss of CO2. Note: Pressure will build in the test cells as the CO2saturated test brine approaches and reaches 160°F (71°C).
Rupture of the test cells has not been reported, yet it is a
potential danger associated with this test procedure. Note also
that an improperly sealed test cell may lead to pressure
release, a resulting test brine compositional change. and an
invalid test result.
3.3.7 Place all test cells and blanks in a forced draft oven or
immerse to 3/4 their lengths in a water bath at 160°F (71°C)
for 24 hours.
3.3.8 Remove the test cells after the 24-hour exposure and
avoid agitation. Allow the test cells to cool to 77°F (25°C) ± 9°F
(5°C) for a time not to exceed two hours.
3.3.9 Pipet 1 mt. of the test brine to a suitable vessel, avoiding
the transfer of calcium carbonate crystals, and dilute with
distilled water, deionized water, or as otherwise specified in
calcium determination method to be used.
3.3.10 Determine the calcium ion concentration by procedures
given in ASTM D 511-88 or D 1126-86, API RP 45, "Standard
Methods for the Examination of Water and Wastewater (Part
300)," or another accepted test method. NOTE: Calcium ion
concentration values for duplicate test samples often differ by
2% or more. Some analysts consider a 5% difference to be
unacceptable and to be cause for rerunning the test.
3.3.11 Report the average of the duplicate calcium concentration values as mg/L calcium carbonate retained in solution for
each inhibitor test concentration and both blank concentrations.
3.3.12 Representative data from the evaluation of three inhibitors are given in Table 2. These figures are examples only and do
not reflect experimental precision. For a percent inhibition
calculation, see Section 4.
TABLE 2 — Calcium Carbonate
Retained in Solution
(as Calcium Carbonate, mg/L)
Scale
Inhibitor
A
B
C
1 ppm
3 ppm
5 ppm
10 ppm
20 ppm
3000
3500
3600
3400
4000
4140
3800
4100
4140
4000
4100
4140
4100
4140
4140
Blank (after precipitation) 2600
Blank (before precipitation) 4140
These data indicate that inhibitor C is best. Note: Costs of
the inhibitors have not been considered.
Section 4: Percent Inhibition Calculation
4.1 Caution: The percent inhibition calculation is for comparative
purposes only. It is not intended to reflect the ability of a particular
inhibitor to prevent scaling in a field application.
4.2 Percent inhibition values may be calculated as follows:
Inhibition (I) = C• Cb x 100
C, - Cb
Where:
C, = Ca2' concentration in the treated sample after precipitation
Cb = Ca2* concentration in the blank after precipitation C, = Ca2
+ concentration in the blank before precipitation
SPE
SPE 15457
SocietkorPetrolesznEncsneere
Use of Inhibitors for Scale Control in Brine-Producing Gas and Oil
Wells
by M.B. Tomson, Rice U.; L.A. Rogers,' Gas Research lnsL; K. Varughese, Aiquatani Pipe
Coating Terminal; S.M. Prestwich, U.S. DOE; G.G. Waggett, South Texas College of Law: and
M.H. Salimi, Rice U.
'SPE Members
This paper was prepared tor presentation at the blot Annual Technical Conference and Exhibition or the Swells, of Petroleum Engineers held
in New Orleans. LA October 5-8. 1916.
This paper was selected tor presentation by an SPE Program Committee following review of information contained in an abstract submitted by the autrorls).
Contents of the paper, as presented. have not been renewed by ihe Society of Petroleum Engineers and an Strisiect io correction by the autlyorni. The
material. as presented, ODDS not necessary reflect any position of the Society d PIIIIONWTIEngtners, ns officers. or members Pipers presented at SPE
meetings are subject to publication review by Echtonai Committees at the Society of Petroleum Engineers. Permission to Copy n restricted to an abstract of
not more than 300 words Illustrabons may not be copied. The abstract should contain =his:victims aCknowndgment of where and by whom the paper is
presented. Write Publications Manager. SPE. P O. Boa 933836. Richardson. TX 750113-3836. Telex. 730999 SPEDAL.
ABSTRACT
IMTRODUCTIOM
Field and laboratory work sponsored by the Gas
Research Institute (CAI) and the Department of
Energy (DOS) have shown that calcium -carbonate
scale formation in waters produced with natural
gas and oil can be prevented by injection of
phosphonate inhibitor into the formation, even if
the formation is sandstone without calcite binding
material. Inhibitor squeeze jobs have been carried
out on DOS's geopressuced -geothermal Gladys
McCall brine-gas well and GAI's co-production
wells in the Hitchcock field. Following the
inhibitor squeeze on Gladys McCall, the well
produced over five million barrels of water at •
rate of approximately 30,000 BPD without
calcium-carbonate scaling. Before the inhibitor
squeeze, the well could not be produced above
15,000 BPD without significant scale formation. In
the Gil brine-gas co-production field tests,
inhibitor squeezes have been used to
successfully prevent scaling.
Progress has been made toward controlling scale
formation from brines often associated with
geopressured energy production, co-production
wells, and oil wells which make large amounts of
water. As brine flows out of the formation and up
the well, the pressure drops. This pressure drop
causes dissolved carbon dioxide, CO2 to go out of
solution, which incr eases the solution pH. The pH
rise causes aqueous bicarbonate, HCOm to be
converted to carbonate. COm, which tends to
initiate calcium carbonate, CaC0s, precipitation
Laboratory work has been conducted to determine
what types of oil field waters are subject to scaling.
This research has led to the development of a
saturation index and accompanying nomograph*
3.
Core samples from both fields were used in
laboratory studies and analytical methods to
analyze inhibitors in brine at a low levels were
extended. A complete history of field
developments and the laboratory backup
experiments is inciuded in this paper.
The first option, reduced production, generally
entails an unacceptable loss in revenue. Injection
of inhibitors into the surface equipment, option
2, does not protect the production tubing, and
installation of a downhole treat string, option 3,
is often prohibitively expensive. The last option,
an inhibitor squeeze, can protect the near well
bore formation, the production tubing, and the
surface equipment. Successful inhibitor squeeze
jobs have been
which allow prediction of when scale will develop
into a problem in brine production.
References and illustrations at end of paper.
either in the formation pore throats near the
well bore, on the production tubing walls or in
surface handling equipment. Four scale control
options include:
1.
2.
4.
Limiting production so that the drop in
pressure is not sufficient to induce
precipitation (see below for details).
Injection of trace concentration of
inhibitors in the surface equipment.
Injection of trace concentrations of
inhibitors downhole via a small diameter
treat string or down the annulus; and
squeezing inhibitor into the formation in
such a manner that the inhibitor will be
slowly released when production commences.
Use
2
Inhibitors for Scale Control in Brine-Producing Cas and Oil Hells
carried out on DOt's geopressured -geothermal
Gladys McCall brine-gas well near Grand Chanier,
La, and =I's co-production wells in the Hitchcock
field near Galveston, Tx, and will be presented.
The producing formation of the Gladys McCall well
was secondary quartz cemented and contained no
calcite, which made a successful inhibitor squeeze
design considerably more complicated. Previous
laboratory work has led to the development of a
method to predict when scale will begin to form
and how little inhibitor might be needed to
prevent stale.
In this paper we will first discuss the field
applications and results of phosphonate inhibitor
squeezes to prevent formation of CaCOs scale.
This will be followed by a description of
laboratory experiments and theoretical considerations that led to the development of the
inhibitor squeeze techniques employed.
FIELD EXPERIMENTS GLADYS MCCALL
The first attempts at phosphonate inhibitor
squeezes at Gladys McCall were unsuccessful since
the inhibitor could not be pumped into the
formation. There appeared to be two possible
causes for this: (1) Poor surface water quality
with high iron and calcium content and (2)
Interaction of the phosphonate with formation
brine which contained 4000 PPM Ca ion (Table 1).
The first of these problems could be handled by
using good quality water which had passed through
an ion exchange and a good filtering unit to
remove any iron hydroxide. The second problem
could be handled by using a brine spacer ahead of
the inhibitor to force the calcium containing
formation water away from the well bore. Based on
these conclusions, the inhibitor pill was designed
to be injected as follows:
1.
2.
3.
4.
5.
6.
300 B of 15% NaC1 spacer
100 D of 3% inhibitor in 15% ■aC1 (the
inhibitor was nitrilotri(methylene
phospbonic) acid from Champion Chemical
Co., Houston, Tx
100 D of 15% MaCI spacer
100 B of 101 CaCla overflush
500 B of 15% BaCI into the formation
as a pusher
The well was to be shut in for 24 hrs. to
allow reaction
In fact, 6% inhibitor was used (step 2).
Everything went well with the treatment at first.
Pumping rate was held at 2 IPS with only a slight
pressure increase over original shut in wellhead
pressure. When the 100 D of inhibitor hit the
formation, the pressure built up rapidly and the
pump rate was reduced to 1 DPW to keep from
exceeding fracturing pressure. The 100 D of
inhibitor and 100 D of NeC1 spacer was squeezed
away at 1 DPW.
When the CaCls overflush hit the formation, the
pressure built up rapidly to the pre-set limit.
Pump rats was reduced to 0.2 BPW and the 100 B
of CaCla solution was slowly pumped away. This
was followed by approximately 25 II of 15% NaC1
solution to clear the tubing. Then the well was
SPE 15457
shut in since all of the inhibitor was in the
formation and had been exposed both to calcium
from the formation brine and the CaC12 overflush
as evidenced by the pressure increases.
After 24 hours, the well was allowed to flow
back at 100 BPH. Brine samples were taken
every 10 barrels during the flow back of the
pill and periodically thereafter. These
samples were analyzed for numerous elements,
in addition to the inhibitor itself (Figure
1). It was found that magnesium was the most
distinctive tracer for the formation brine
although the early buildup (around 600 barrels
of returns) could be due to impurities in the
15% MAC' and some interaction with the
phosphonate. By the time 1200 barrels of brine
had been produced, Mg, Ca, Na and X had
stabilized to their original concentrations in
formation brine. About 70% of the inhibitor
flowed back with the first few thousand
barrels of brine production. The remaining
inhibitor was slowly released over the next
six months. The concentration of the inhibitor
dropped to about 0.1 to 0.2 mg/1 within a few
weeks and remained there until the well was
shut in for repair and resqueeze in January,
1986. This corresponded to about 701, of the
inhibitor remaining in the formation. In order
to measure such low inhibitor concentrations
in field brine it was necessary to modify
standard colormetric phosphonate procedures
which will be published elsewhere. Prior to
the inhibitor squeeze, production was limited
to about 15,000 BPD in order to avoid scale
formation. This severely curtailed gas
production. After the squeeze it was possible
to increase the production rate to about
30,000 BPD, still without scale formation in
the production tubing. During this period
about 25 SCF of natural gas was separated and
sold per barrel of brine produced. At about
four months into production, a light scale was
observed in the final filters before the
disposal well. This was eliminated by addition
of 0.25 mg/1 of inhibitor downstream of the
choke. After six months of production no
indication of scale formation in the
production tubing was found, and when the well
was shut in, the high pressure side of the
choke was observed to be scale free. Thus, the
phosphonate inhibitor squeeze had protected
the tubing for the production of over five
million barrels of brine.
Upon analysis of the breakthrough data of the
flowback curves from the first squeeze job, it was
concluded that the calcium in the formation brine
could be used to fors the calcium phosphonato in
situ if sufficient mixing could be obtained in a
large pill which was pumped a considerable distance
from the well bore. This would avoid the pressure
increase observed when the calcium of the CaCla
overflush hit the formation containing the pill and
would greatly simplify the overall operation of the
pill application.
Based on the observations from the behavior of the
first successful phosphonate inhibitor squeeze, a
simplified pill procedure was designed as follows:
1. Pump a 100 barrels preflush of 10% illaC1 to
push most of the Calcium ion in the reservoir
brine away from well bore.
SPE 15457
2.
3.
4.
5.
M. 8. Towson, ec al.
Use 100 barrels of pH neutral 3% (N1(4)
phosphonate inhibitor salt in 10% lad
solution which will react with calcium from
formation water.
Overflush with 900 barrels of 10% MaC1
followed by 300 barrels of oil field brine
to clean the tubing.
Shut in for 36 hours and bring back slowly at
100 barrels per hour.
After 2 days resume flow of 30,000 barrels
brine per day.
Since these fluids had approximately the same
density as the formation brine and viscosities
were low, the injection rate after preflush was
chosen as 6 barrels per minute.
An oxygen scavenger (MH4)HS0a and an iron
chelating agent (EDTA) was added to all of the
brine to prevent formation of iron hydroxide and a
2-1/2 micron filter was used just upstream of the
pump suction. In addition. 100 millicuries of I
131 was mixed with the phosphonate pill as •
tracer. The pressure curve for the injection is
given in Figure 2. No problem was encountered
which forced slowing the pumping rate. Maximum
pressure rise was approximately 400 to 500 PSI as
the pill was pumped into the formation.
The well was brought back on stream after 36 hours
and produced at the rate of 100 barrels per hour
for two days. Flow rate was then increased to
approximately 30,000 barrels and has remained
there for over six months except for a slow rate
decrease that is a function of the reservoir flow
properties.
Samples were taken on a regular basis during
early flowback and once a day thereafter. Figure
3 shows the 1-131 scintillation count data vs.
barrels of brine produced. A well defined curve
with a maximum at around 1450-1500 barrels of
brine flow results.
Samples of the brine were also used for
determination of the phosphonate concentrations in
solution. These are included in Table 2. In this
squeeze treatment there was never the tremendous
backflow of the calcium phosphonate that had been
observed in the earlier squeeze job. This is
probably because the phosphonate pill was pushed
far enough back into the reservoir to smear it out
over a large volume of the sand grains. After 8
days of production at 30,000 BPD the inhibitor
concentration dropped to about 0.15 ng/1 and has
remained at that level for over six months (Table
2).
The successful application of the phosphonate pill
has allowed the Gladys McCall well to be produced
at the maximum rate available from the reservoir.
Over five million barrels of brine have already
been produced using this second pill with
apparently no reduction in protection from CaCOs
deposition.
LABORATORY STUDIES AID THEORETICAL CONSIDERATIONS
In order to prepare for the field work numerous
laboratory experiments were conducted. Core
material from the producing formation at the
Gladys McCall well was analyzed by x-ray
diffraction and by scanning electron microscopy
and microprobe analyses. Results are in Table 3.
From the information in Table 3 it can be
concluded that the producing formation is
sandstone cemented by secondary quartz with a
small amount of clay. The porosity was found to
be about 20%, similar to Brea sandstone. This
core material was used in all laboratory column
studies of the Gladys McCall well.
Column Studies
Column studies were conducted using both ground
core samples and intact core plugs. Packed columns
using ground core material were quick and easy to
prepare and allowed numerous variables to be
examined.
For the experiments using ground core material 14 g
portions of core material were gently crushed with
a porcelain mortar and pestle and packed into 10 ml
plastic pipets fitted for use as chromatography
columns. These columns were saturated with
synthetic brine (1 M l•Cl and 0.125
CaCla) and then flushed to remove all traces of
drilling fluids. These columns had 40% porosity.
After preliminary experiments were run to
determine appropriate concentration ranges, the
following test of the effect of CaCla overflush
was performed by injecting the following into a
set of columns:
1.
2.
3.
4.
2.0 al 15% lad as a lead spacer
0.5 al 3% active Gyptron T-132 (pH neutral
fora of Dequest 2000 from Champion Chas.
Houston, Tx.)
0.5 al 15% lad as tail spacer
2.0 al 15% Wel as overflush
These columns were shut in for 8 hrs at 85•C
(185•F) and than slowly backflushed with 40 al
of synthetic brine at 85•C. Columns were then
cut into 10 sections and each was analysed for
remaining inhibitor. Next, the 2 ml of 15% NaCl
overflush (4. above) was replaced by 2 al of 15%
CaCla. All experiments were run in duplicate, at
least. The overall mass balance of inhibitor in
these experiments was generally 901, or better.
A fourfold enhanced inhibitor retention is shown
in Figure 4 as a consequence of using a CaCla
overflush. This corresponded to about 40% of the
inhibitor which was loaded. For this reason a
CaCla overflush planned to be used is the
inhibitor squeeze at the Gladys McCall well.
Similar column experiments were conducted using
core material from the Delee No. 1 well in the
Hitchcock Field. These core materials were
calcite cemented. Little difference was observed
between the Nadi and CaCla overflush regimes.
Columns of intact Gladys McCall core metrial were
also prepared. Rectangular pieces of core material
1 cm x 1 cm x S ca were cut and embedded in Epoxy
in a 1 in OD steel pipe. The end cap pieces and
reducers on the pipe were all filled with Epoxy
end later drilled to allow 1/I" 00 high pressure
Teflon tubing to contact both ends of the
3
4
Cs. of Inhibitors for Scale Control in Brine-Producing Cas and Oil liens
core material (Figure 5). This system was used to
evaluate the adsorption and desorption of
inhibitors. Columns were first saturated with
synthetic brine (1 M Nadi, 0.125 M CaCla, pH .
4.1) and then flushed at 95'C until all traces of
drilling fluid were removed. A pill dosage of 0.95
ml of Ti inhibitor in 0.125 M CaCla and 1 M NaC1
was injected into the core. The intact core column
was shut in for 24 hrs at 95*C.
Desorption of inhibitor into flowing synthetic
brine at 95'C was monitored for about 10.000 pore
volumes, or sixteen liters. The result is plotted
in Figure 6. After 300 pore volumes the inhibitor
concentration dropped to about 1 mg/1 (as
phosphonic acid) and remained approximately
content for another 7000 pore volumes. After
about 7000 pore volumes the concentration of
inhibitor in the brine rapidly dropped to below
detection limit.
(31)
fora scale
(1)
-: brie. tubseturated, scale may istssohnt
where (Ca14) and (C0:-) represent
molar concentrations of calcium and carbonate,
respectively, and Kip is the conditional
solubility product of CaCO2.1 The solubility
product in Equation 1 is a function of temperature
T. pressure P, and ionic strength IS, or total
dissolved solids TDS. At the pH values normally
encountered in sec-pressured brines, the ionic
calcium concentration in Equation 1 can be
replaced by the total calcium, Tca, which is easily
measured. The divalent ionic carbonate
concentration, (C01-). in Equation 1 can be
expressed in terms of bicarbonate (MC0a) and pH
using the second ionization constant of carbonic
acid. Below about 8.3 pH, bicarbonate is
essentially the same as alkalinity (Alk), which is
also readily measured. Finally, by appropriate
algebraic substitution the pH can be expressed in
terms of Henry's law constant, the alkalinity, and
the gas phase partial pressure of carbon dixoide.
Oddo and Towson (1962)1 have determined least
squared curves for the various equilibrium
constants as a function of T, P, and TOE. The SI
for most gas and oil well brines has been shown to
be:1
SI • lea(Tc. 4)10/71,,,) • SAII • 1.S0410'8 T
- 4.21,00*
T'
- 7.44:10* r - 2.556 Is% • 0.920 IS
(2)
where Tca(molar) (mg/1 Ca)/40.000; /ilk (solar)
. (mg/1 HCO4)/61.000; IS (molar) . conductance
(vmho/cm)/66,667 m (mg/1 TD6)/56,500; end ICOa
volume or mole fraction of COs in gas phase,
with pressure, P, in.psia end temperature, T,
in 'F.
 similar equation for pH was derived.' All of
the variables of Equation 2 are readily
SI - S I ,

The driving force for CaCOa precipitation under
any solution conditions can be represented by the
saturation index, SI, defined by:
brim? sup.maturatimil, soy
0: mullibrium
measureable. A simple kit to measure Ca, Alk, and
TIM on site is available from LaMotte Chemical Co.
(Chestertown, Maryland) and the gas phase percent
carbon dioxide can be easily measured by e.g.
Dreier tubes or gas chromatography. The T and P
are generally available at the sample point. To
facilitate the use of Equation 2 a monograph was
constructed2 and a slide rule is available from
Shell Canada (Calgary, Alta, Canada). At initial
shut in conditions the downhole SI in Equation 2
is theoretically zero for any formation which is
calcite cemented. Therefore, a change in
saturation index, ASI, was defined as the sum of
the changes resulting from P, T. Ca, Alk, PCO,,
and TDS, independently:2
ASI •
Saturation Index
'co
SPE 15457
sSIP • ASI,
aSIA,, • 15110. • &Sins
(31))
During production in the absence of scale
formation the only variables which change from
bottom hole to well head are T and P. Homographs
to calculate ASI were also developed.2 A semiquantitative correlation of scale formation
process vs SI was developed from field and
laboratory studies. For ASI values between zero
and 1.1 to 1.4 scale will probably not start to
form in equipment free of scale. For AS! values
between about 1.4 to 2.3 scale can generally be
controlled by trace concentrations of inhibitors.
Above ASI of about 2.3 it may not be possible to
prevent scale with inhibitors (see below). Below
ASI • 0 scale will not form, but corrosion will
likely be the prima concern, especially if AU is
less than - 1.0.
Inhibitors
Rosenstein in 1935 found that extremely low
concentrations of metaphosphates could be used to
prevent scale formation.3 Today several classes of
compounds are used for this substoihiometric
(threshold) scale inhibition, e.g.: 1. inorganic
polyphosphates; 2. polyphosphate esters; 3.
phophonates; and 4. low molecular weight
polyacrylates; and polymaleates.4
Most of these threshold inhibitors are surface
active. They probably prevent nucleation of a new
scale phase by interacting with the forming
nuclei and preventing formation of a stable solid
phase.5 They prevent further growth of an already
existing phase by adsorbing onto active growth
sites on the surface and preventing incorporation
of more lattice ions.' For brines supersaturated
with respect to calcite it has been proposed that
the lowest concentration of threshold inhibitor
needed would be approximately the molar
concentration of divalent carbonate.
specifically:5
2(CO:
-)/Iz(InS
-) < 1.0
(4)
where parenthesis represent molar concentrations
and z is the average charge on the inhibitor or
inhibitor unit used to express concentration. The
summation sign in Equation 4 suggests strict
SPE 15457
5
M. I. Tomos st
additivity of mixed inhibitors. In laboratory tests
compounds and various combinations of compounds
from several chemical classes have been shown to
prevent nucleation at concentrations similar to
those predicted by Equation 4. Yet, no examples
have been found of inhibition of calcite nucleation
below the limit suggested by Equation 4.
of the iodine has returned by the time 3000 barrel
of fluid have been produced.
Also, there is an upper limit at which an
inhibitor might work. This upper limit is
controlled by the solubility of the inhibitor.
Inhibitors of precipitation generally form
insoluble salts of one of the lattice ions of
the phase being inhibited. All of the classes of
inhibitors listed above are anions and form
insoluble calcium salts. If the concentration of
inhibitor is two large a calcium-inhibitor salt
(pseudoscale) precipitates. For some of the
field systems investigated by the authors this
upper limit of inhibitor concentration has been
found to be only a few mg/1 or less.
concentration found in laboratory tests.1'4 As
noted before, with each inhibitor squeeze scale
began to form in.the low pressure side of the
surface equipment at 4 to 5 - mos. This occurred
as the &SI increased above 2.3 to 2.5 (Equation
3),1,2 but an additional 0.25 mg/1 of inhibitor
was sufficient to prevent scale in the low
pressure region of the surface equipment. When
greater than 1 mg/1 of inhibitor was injected in
the surface equipment calcium-inhibitor
pseudoscale formed in the filter units.
DISCUSSION
At flowing wellhead conditions the
concentration inhibitor, 0.73 sg/1 (1.7 x 10-'
N), is only 15% greater than that predicted by
Equation 4.1.3 This agreement may be
fortuitous, but is similar to the lowest
CONCLUSIONS
1.
The development of • successful squeeze method to
inhibit calcium carbonate depositions from produced
brines has been tested. This method has been shown
effective in sandstone reservoirs where there is
Phosphonate inhibitor squeeze can be used to
successfully prevent formation of CaCOs
scale in the tubing and surface equipment
of brine wells which would normally have
scaling problems. Inhibitor concentrations of
only 0.15 mg/1 have effectively prevented
scale formation in the production tubing.
no calcite in the cementing material. The key
ingredient in a successful application appears
to be that the calcium phosphonate needs to be
formed in the reservoir at some distance awe), from
2.
the well bore. This can be done by carefully
selecting the amounts of preflush to move the brine
which contains calcium ion away from the well bore
and pumping in excess afterflush to force the
Treatments can be successfully carried out
in reservoirs where the sand grains are not
cemented with calcite.
3.
Extreme care should be taken to form the
insoluble calcium phosphonste in the
reservoir so that it won't block the well
bore.
4.
The use of a calcium chloride overflush can be
phosphonate into the reservoir where it
interacts with calcium from the formation water to
form the insoluble calcium phosphonste.
There is considerable room for improvement in the
development of the inhibitor squeeze technique.
For example, we are not sure that the 10% RaC1
preflush and afterflush couldn't be done with
regularly available oil field brine. Precautions
would need to be taken however to see that the Ca
and Fe levels in the brine were low. Also, the
use of a small pore size filter (preferably 2
microns or less) is a most to prevent blocking of
the well bore from any particles in the oil field
brine.
The mixing data available from the first
successful squeeze job at Gladys McCall is quite
interesting. The sodium concentration (Figure 1)
rises more sharply than expected and than doesn't
appear to remain at the high concentration as long
as it should. In fact, the sodium concentration
has returned almost to its normal formation brine
level by the time 900 barrels of brine have been
produced, whereas we'd expect high values to cover
at least a five hundred barrel spread. Its
apparent peak at the same point as the phosphonate
peak also is unexpected.
avoided by using the natural dispersion
properties of the reservoir to induce the
mixing of the injected inhibitor with
calcium in the formation brine. This greatly
simplifies an inhibitor squeeze.
Acisgtommigt
This work was supported by the Gas Research
Institute under contract No. 5084-212-0890, but in
on way does this constitute an endorsement by CRI of
any products or views contained herein. Manuscript
preparation by Leticia Villafranco and artwork by
Peggy O'Day are gratefully acknowledged.
Egnigang
1.
1583-1590.
2.
In the second squeeze inhibitor test the iodine
peaks around 1500 barrels (Figure 3) which is
about 300 barrels later than would be expected.
It is interesting to note however, that if you
integrate the area under the iodine curve over 90%
Oddo, J. S. and Tomson, M. S.: "Simplified
Calculation of CaCOs Saturation at Nigh
Temperatures and Pressures in Brine
Solutions," J. Pet. Tech.
(1982) pp.
Tomson, N. B., Natty, J., Durrett, L. R. and
Rogers, L.: Saturation Index Predicts Brine's
Scale-Forming Tendency," cal salgag L.
ga (1985) pp. 97-108.
3.
Cowan, J. C. and Weintritt, D. J. Water
CONTINUOUS INJECTION OF SCALE INHIBITORS
Continuous injection is the preferred method for all scale inhibition
since it ensures the presence of proper levels of inhibitor at all times. In
this method, the chemical is applied with or without flush by a gasoperated, beam-operated or electric chemical proportioning pump. For proper
addition, the scale inhibitors should always be injected into a stream of
fluid where adequate turbulence exists to ensure thorough mixing of the
inhibitor and to prevent stagnant precipitation of scale inhibitors.
Normally continuous feed of scale inhibitors in oil production is required
because the systems are once-through.
For continuous injection systems, the following are the inhibitor criteria:
the inhibitor must be completely soluble in the waters processed at usage
concentrations; unlike squeezing, precipitation in continuous injection should be
avoided. The solids add to the suspended solids and decrease water quality, as
well as promote scale deposition and underdeposit corrosion. The chemical should
not be corrosive to pumping equipment or to the system. The scale inhibitor must
be thermally and hydrolytically stable. They must be compatible with treating
chemicals in the production, processing and water systems; these include:
demulsifiers, paraffin compounds, microbiocides, corrosion inhibitors, surfactants
and other chemicals. The scale inhibitors do react with many amines, as the scale
inhibitors are highly anionic while the other compounds are cationic. Chlorine and
reducing microbiocides are also affected by (and affect) scale inhibitors and
subsequent performance.
Continuous injection scale inhibitors must not be pumped into static
brines due to precipitation potential. They should not be pumped directly
into water tanks, heater treaters or other vessels. Do not inject ahead of an
intermittent operating dump valve. Do not inject into annuli without adequate
flush. Do not allow faulty check valves to leak produced water into a scale
inhibitor line and do not pump scale inhibitors into lines containing neat
corrosion inhibitor. Do not drip feed scale inhibitors. Do maintain chemical
pump operation as it is critical to effective scale inhibition.
Scale inhibitors generally are injected at 5 to 100 ppm (typically 10 to
25 ppm) in scaling water to effect scale control. They must be injected as
far upstream of a scaling point as is feasible. The following are some of the
main points where scale inhibitors are applied by continuous injection in the
oil field: injection water systems, disposal systems, source wells, producing
wells, gas lift wells, flowing wells, hydraulic pumping systems, heater
treaters and other vessels. Start treatments high and reduce dosages as
possible.
The following are some of the generalized recommended continuous
injection programs:
1.
Source wells-inject chemical down the annulus with slipstream flush
at 10-25 ppm.
2.
Gas lift wells-inject scale inhibitor highly diluted with fresh water
into the lift gas at 10-25 ppm.
3.
Producing wells with open annuli-inject the chemical with slipstream
flush down the annulus at 15-100 ppm. Problems may occur with high
gas production or heading up and unloading out the annulus. A
macaroni string should be used for these problems.
Continuous Injection of Scale Inhibitors
Page 2.
4.
Flowlines and laterals-inject the inhibitor at the head of the
line at 10 to 100 ppm.
5.
Heater treaters-inject the scale inhibitor into the moving
fluid stream at the header or other point well upstream of
the vessel at 20-100 ppm.
6.
Waterfloods and disposal systems-for scale problems downstream of the
station, inject the scale inhibitor in the pump suction at 10-25 ppm.
Where incompatible waters are involved, add the scale inhibitor to
the cation-containing water upstream of the comingling point.
7.
Power oil or power water systems-continuously inject the scale inhibitor
into the power fluid at 10-25 ppm based upon water production volume
rather than power fluid circulation volume.
Special note: Do not attempt to add additional scale inhibitor (30-50 ppm)
at the injection station or injection wells to protect the
producing wells when brakthrough occurs as the scale inhibitor
would be adsorbed out within the formation. Unsuccessful
attempts have been made to to this.
SCALE INHIBITOR SQUEEZES
Principles of Squeeze Treatments:
1.
Scale inhibition, especially scale inhibition by squeeze
treatments, is an art not a science. It involves a certain amount of
trial and error and field experience in the development of viable
squeeze programs because of the imcompletely understood mechanisms of
scale inhibition, the interactions between the chemicals and the
water involved and the complexities and unknowns in the formation.
2.
For squeeze application of a scale inhibitor to perform for a desired
long-term life, the inhibitor must be retained in the formation by one
or more retention mechanisms: adsorption, and/or precipitation.
Adsorption-a physical interaction between an ionized solution and a solid
surface in which molecular forces promote a molecular film by
charge attractions between the ions and the solid surfaces.
Precipitation-the formation of an insoluble salt from solution by reaction
between anion (scale inhibitor) and a cation (divalent metal
salt, usually Calcium).
3.
The inhibitor retained in the formation must be capable of desorption
from the formation surface at a slow enough rate to allow long-term '
inhibition.
4.
Adsorption-desorption is the preferred mechanism in scale inhibition in
a formation since precipitation involves the development of potentiallyplugging precipitates which could cause long-term or permanent formation
damage.
5.
In essence, the application of a scale inhibitor squeeze is a batch treatment; however, the performance of the squeeze is a continuous treatment.
Requirements of Squeeze Application Inhibitors:
1.
The inhibitor utilized must be effective against the scale(d)
involved at a low dosage.
2.
The inhibitor must have adequate adsorption-desorption characteristics to
allow a long-term continuous inhibitor return.
3.
The inhibitor must be thermally and hydrolytically stable for long
terms under formation conditions.
4.
The inhibitor must be compatible with the produced fluids, the formation
lithology and other chemicals utilized in squeeze, well treatment and
production processing.
5.
6.
The inhibitor must not promote or create emulsification.
The inhibitor in return fluids must be monitorable at low typical
usage concentrations.
Scale Inhibitor Squeezes
Page 2.
7. Other desirable properties could include solids dispersion
capabilities and water-wetting (oil dispersion).
Mechanics of Scale Inhibitor Squeezes:
1. A formation squeeze is the placement of a chemical or chemicals into
a formation at pressures and rates which are less than fracture
pressure for a given formation.
2. Scale inhibitor squeezes are determined arbitrarily, or they have
been established by trial and error in field applications.
3. The amount of inhibitor required, the volume of overf lush, and the
use of diverting agents or other additives will depend upon:
a: Well completion data.
b.
Amount and flow rates of produced fluids.
c.
Field experience.
4. Because of the complexity of environments and array of production
conditions, there are a number of methods utilized for inhibitor
placement in the formation:
a.
Adsorption squeeze.
b.
Precipitation squeeze.
c.
Forced precipitation squeeze.
d.
Fracturing placement.
e.
Mixed adsorption-precipitation squeeze (most scale squeezes are
probably of this type. Actually, a combination of A &
5. In order for a squeeze treatment to provide maximum benefit, existing
scale (and paraffin) deposits must be removed.
6. Potential problems resulting form scale squeeze:
a.
Formation of a "pseudoscale" due to interaction of improperly applied
inhibitor with divalent metal cations in formation brine (Me", Ca++,
Ea++, Sr44). Results are scaling, plugging solids and loss of scale
inhibitor.
b.
Emulsions created by surfactancy of some scale inhibitors, especially
phosphate esters. Results are decreased productivity following squeeze,
presence of chemical emulsion in production and increased demulsifier
and heat requirements for oil treating.
c.
Emulsion blocks are possible anytime foreign fluids are placed into
a formation. In addition to, and in relation to, emulsion blocks are
the development of zones of water saturation. The result is a loss
of production following treatment.
Scale Inhibitor Squeezes
Page 3.
7. Basic Operation of a scale squeeze:
a.
Mixing of inhibitor and diluent at a suitable ratio and pumping
down tubing or annullus.
b.
Displacement of the inhibitor to perforations or open hole face.
c.
Overdisplacement of the inhibitor into the formation several
feet from wellbore.
d.
Shut in period to allow maximum adsorption of the inhibitor
and migration of the balance into pores, vugs, fractures
and other traps.
e.
Monitoring of produced brine for inhibitor
return. Designing Scale Squeeze Treatments:
1.
Scale inhibitor squeeze treatments must be designed for specific conditions
on a well-by-well basis. There is no such thing as a standardized squeeze.
2.
Only a properly designed scale squeeze will be effective. Application of an
optimum inhibitor by improper procedure will result in poor performance or
squeeze failure.
3.
Scale inhibitor squeezes can be designed for any formation compositionlimestone, dolomite, sandstone, or shale. Returns from sandstone may be
75% or more of the inhibitor during the effective life, 50% or more in
limestones and as low as 25% from dolomites. Returns usually improve
significantly with future squeezes.
4.
The following are the design features of each type of squeeze application.
(a)
Adsorption Squeeze-preferred squeeze mechanism in which an inhibitor
is placed into the formation and the chemical is
adsorbed to the formation matrix. Effective in all
formation types.
(b)
Precipitation squeeze-a squeeze in which the acid form of a scale inhibitor
is placed in the formation or basic form is mixed with
15% acid and placed in the formation. The acidic scale
inhibitor or the HC1 acid reacts with calcium carbonate
in the rocks to produce a high level of calcium ion in
the solution to promote precipitation of a calcium
phosphonate salt which will slowly solubilize as an
effective inhibitor. Effective only in limestones,
dolomites or calcareous sandstones and calcareous shale.
(c)
Forced precipitation squeeze-a modified precipitation squeeze which utilizes
a calcium chloride solution pumped in the treatment to
precipitate the phosphonate salt. Used in non-calcareous
sandstones and shales.
Scale Inhibitor Squeezes
Page 4.
(d) Fracturing fluid placement- a scale inhibitor determined compatible with
the frac fluids is placed into the formation, pumped at
frac pressure and adsorbed or precipitated in the newly
developed porosity or fractures. Serves as an initial
squeeze.
SPECIFIC SCALE INHIBITOR SQUEEZE DESIGNS
I. Inhibitor Volume:
The first step in developing a scale inhibitor squeeze treatment is to
determine how much of the selected scale inhibitor is required. The following
calculations allow determination of approximate inhibitor dosages. Normally a
minimum of 55 gallons is recommended.
A. Radius of Desired Protection (most accurate and preferred procedure)*
SI = (Rp 2 - Rw 2 ) xlrx8x TXC
or SI = 0.785 (Rp2 -Rw2) x 8 x T
where SI = scale inhibitor volume in gallons
Rp = radius of desired protection (feet)
Rw = radius of wellbore, casing 0.D., or openhole in feet.
?r= 3.14
8 = porosity of formation expressed as a drcimal.
T = thickness (length) of pay zone in feet.
C = constant; 0.25 based upon experiment results and squeeze case histories.
* Use this equation for high volume wells or wells with considerable pay zone.
B.
Estimated Life Based on Production
SI = VwxDxC
where SI = scale inhibitor volume in gallons
Vw = water production, bwpd
D = estimated or desired squeeze life, days
C = constant; 0.006 based upon experimental results and
squeeze case histories
C. Rule of Thumb for Inhibitor Volume
0.62 to 0.7Z of daily water production; 12 in lower volume wells
Use no less than 55 gallons per squeeze.
BPD x .008 = drums of chemical (12 of H2O prod.)
BPD x .006 = drums of chemical (0.72 of H20"prod.)
BPD x .005 = drums of chemical (0.62 of H2O Prod.)
42
(based upon 55 = 0.8; 1% = 0.008)
II. Displacement Volume:
Use the tubing or annular displacement tables in a Halliburton, Dowell
or B J-Hughes cementing manual. Use produced water or 2% KC1. Be sure
to include 0.1-0.52
suncrwr
Specific Scale Inhibitor Squeeze Designs
Page 6.
•
III. Overdisplacement Volume:
As a general rule, the amount used is equal to one (1) full days water
production, with a 100 barrel minimum (at least 6 foot radial penetration). Do
not use more than 250 to 300 barrels except under specific recommendation.
Produced water or 2% KC1 brine should always be used. Be sure to include 0.1
to 0.5% SURFAcIRAPT.
Radial Penetration (ft.)
Over Displacement (BBLS)
1
2
3
23
5
66
6
7
100
130
9
215
IV Inhibitor Dilution Volume
Normally, Acci,r...v.recommends 10% in fresh water; some companies
recommend 2.5% for phosphate esters and 5% for phosphates in fresh
water or produced water.
b. If produced water must be used, the proper dilution ratio must be
determined with the scale inhibitor added to the water to determine
solubility range. Check 1%, 5%, 10% and 20% until a ratio with a
clear solution is achieved. Produced water is normally used only
when no fresh water is available or due to the presence of watersensitive clays or shale; ACc1;/"41-prefers the use of 2% KC1 brine
in these situations rather than produced water.
V.
Shut-in Time
Based upon proven field performance, the shut in time to allow maximum
adsorption and migration of the inhibitor should be 24 hours. Some
companies may recommend 48 hours, but field experience by several
companies have shown excessive time provides no discernible benefit. No
less than 12 hours shut-in should be recommended; 24 hours is preferred.
VI. Typical Adsorption Squeeze Procedure (no packer)
1.
Collect acidized water sample for baseline in residual monitoring.
2.
Conduct recommended well clean-out.
3.
Close the offside casing and flowline valves and pressure the tubing
to 250 psi by pumping 2 to 3 strokes to fill the tubing.
4.
Shut the unit in on downstroke.
Specific Scale Inhibitor Squeeze Designs
Page 7.
5.
Pump 10 to 30 barrels of clean produced water or 2% KC1 brine
containing 0.5% suRFAc-r4/47-
down the annulus.
6.
Mix the recommended scale inhibitor volume in fresh water
at a 10% ratio of chemical and pump the mixture down the
annulus at a rate below frac pressure.
7.
Displace the inhibitor-diluent mixture to the perforations or
open-hole face with the required volume of produced water (or 2%
KC1) containing 0.5% b.v. SURFACT4A)-7-;
8.
Overdisplace the inhibitor-diluent mixture into the formation with
produced water (or 2% KC1) containing 0.5% b.v. SURFAcro4Afir.
Volume should be 100 to 300 barrels depending on the daily
water production.
9.
Shut the well in for 24 hours and remove treating equipment.
10.
Return the well to production and begin monitoring program.
Note: For wells producing under packer, the treatment must be down the tubing.
As a result, the pump must be unseated in a rod-pumped well to allow
passage of treating solution. Displacement volume will change.
VII. Staged Inhibitor Squeeze (for wells with large open hole area):
1.
Collect acidized water sample for baseline in monitoring.
2.
Conduct recommended well cleanout.
3.
4.
5.
Premix the recommended scale inhibitor at a 10% ratio in fresh water
or 2% KC1 brine and pump 50% of this mixture down the annulus.
Pump a 50 barrel pad of water down the annulus.
Pump 10 to 20 barrels of diverting agent (typically SO to 100#) down
the annulus. The volume necessary will raise the pressure about 150 psi.
6.
Pump the remaining scale inhibitor mixture down the annulus.
7.
Displace to the perforations with produced water or 2% KC1
containing 0.5% b.v. SURFAc7rAr,11-;
8.
Overdisplace the mixture and diverter into the formation with 100
barrels of produced water or 2% KC1 containing 0.5% b.v. SURFA°CrAttn:
9.
Shut the well in for 24 hours.
10.
Return the well to production and begin monitoring program.
Specific Scale Inhibitor Squeeze Designs
Page 8.
VIII. Typical Precipitation Squeeze:
1.
Collect acidized water sample for baseline in monitoring.
2.
Conduct the recommended well clean-out.
3.
Shut the offside casing and flowline valves.
4.
Pressure up on the tubing to seat the pump and prevent leak-by.
5.
Mix the recommended dosage of phosphonic acid in fresh
water or 2% KC1. Add acid retarder, if needed, at 1% of
scale inhibitor volume.
6.
Pump the scale inhibitor/diluent mixture down the annulus at
adequate pump rate below frac pressure to ensure maximum
penetratin of the formation.
7.
Displace the inhibitor to the perforations or open hole face
with required volume of produced water or 2% KC1 containing
0.5% b.v. P. FACTRArr.
8.
Overdisplace the inhibitor into the formation with 100 to 250 barrels
of produced water or 2% KC1 containing 0.5% b.v. SURFAC74e1:
9.
Shut the well in for 24 hours to allow maximum acid neutralization
and precipitation.
10.
Return the well to production and initiate the monitoring program.
IX. Typical Forced Precipitation Squeeze
1. Collect acidized water sample for baseline in monitoring.
2. Close in offside casing and flowline valves.
3. Pressure up on the tubing.
4. Premix the phosphonic acid with 2% KC1 brine or fresh water at 5%
to 10% (optimum) ratio.
5. Pump the mixture down the annulus.
6. Displace the scale inhibitor-diluent mixture with a 1% CaC12
brine (4 lb./barrel).
7. Overflush the scale inhibitor-diluent with 2% KC1 brine or fresh
water containing 0.5% b.v. PAR Vitt.c-rott4T to the recommended radial
penetration.
Specific Scala Inhibitor Squeeze Designs
Page 9.
Shut the well in for 24 hours (optimum).
9.
Put the well back on production and initiate monitoring
program.
Monitoring
Monitoring of the organic phosphate scale inhibitors (phosphate esters,
phosphonic acidized phosphonates) can be done by collecting an acidized
water sample on at least a monthly basis. Analysis should be ppm of
proprietary compound although some chemical companies run total phosphate
(no distinction between ortho- and metaphosphate). Polymer residuals are
run by specialized procedures (carbonate adsorption bed or dialysis
methods), and should not be acidized. Results should be reported on a
running report form or graph showing squeeze dates.
TYPICAL RETURN CURVE
Inhibitor Return
X.
8.
Time in Days or Months --->
TABLE
COMPARISON OF ADVANTAGES AND DISADVANTAGES OF
INHIBITOR SQUEEZES AND DOWN HOLE TREAT STRINGS
flmarroR sauEgiE
Disadvantages
Achraniacuti
1. Treat near wel bore formation to
prevent plugging during draw down.
1. A squeeze generally must be repeated
from every two weeks to two years.
2. All staid surfaces at the well bottom are
protected from scale.
2. The rule-of-thumb is that only about
one-third of the added inhibitor is
actually effective: one-third generally
flows back with the first production
and about one-third is never returned,
although these ratio may improve
upon repeated squeezes.
3. A squeeze can be done on old
wells without puling tubing.
3. There is virtually no control on the
concentration of inhibitor which flows
back with the brine.
4. During routine production, tittle
maintenance Is required and no
on-site power is needed.
4. Performance on a new system
is highly unpredictable.
5. Generaiy, a squeeze is a
simple procedure for most
service comparies.
5. Once a squeeze is started, It is not
possible to change the concentration
or the chemical, as it is with a treat
string.
6. The potential lifetime of a squeeze is
virtually unlimited, in theory.
6. There is a real potential for
formation damage.
7. Only periodic (about weekly) brine
analysis is necessary to detect when
to resqueeze.
7. It is difficult and expensive to treat
corrosion due the different chemical
nature of corrosion inhtitors and the
higher concentrations often needed.
8. It is difficult to analyze for most
scale inhibitors at the concentrations
typically needed.
DCMIWQLEIBEALSIERISI
Achlaff1808s
Disadvantages
1. Chemical type and concentration can
be changed as needed.
1. The treat string tubing, generally onefourth in. 00 stainless steel or high
alloy steel, etc., is expensive, $0.50 to
$5.00 per foot per tube and generally
two or more tubes are used per well.
2. Deivery concentration is
relabie and can be
as the
production rate charges. This greatly
reduces the need for inhibitor
analyst&
2. With old weft installation of a treat
string requires a work over.
3. Down Axle pressure can be monitored
either directly or by Inference.
3. Operation requires reliable on-site
power. Loss of power for a single
day may permit serious wale
problems to begin.
4. Treat string If °time is potentially
unirnited. This yields predictable
capital and maintenance costs.
4. It is difficult 13 instal treat strings in
slanted brines.
5. Either the same or an additional treat
sift can be used to control additional
chemical problems, such as corrosion
and enaisilicadon.
5. The presence of tubing dips, may
complicate some maintenance
operations.
6. If any downhole component fails,
it is generally necessary to pull the
tubing out of the well.
IMILL1
The Conditional Sokibilties and Stoichlometdo Coeffidents
for Ca - Dlethylenetdaminepenta(Methylene Phosphonate)
in 2.0 M Brines at 70° C
pH
Stoichiornetric
Coefficient
4.7
5.0
6.0
7.0
8.0
9.0
0.50
0.48
0.41
0.30
0.31
0.29
Conditional
Solublity (K1
4.27 x 104
3.02 x 104
1.92 x 104
1.78 x 104
1.23 x 104
1.20 x 104
SOLUTIONS ARE CHEMICALLY ACTIVE AND EITHER
SCALE OR CORROSION DOMINATES
BrALLIAMEDIAIEPHOLEM
CORROSION: LONGER TO DEVELOP
—SOIL
G AS
01L
X ___________BRINE
SCALING TINCENCY NCR. DRAMATICALLY AFTER CHOKE
TEMPERAURE ESSENTIALLY CONSTANT
PRESSURE DECREASING
SCAUNG TENDENCY INCREASNG
CORROSION TENDENCY DECREASIVG
SC DS CAN PLUG
DISPOSAL RESEVOIR
i N:stszsA:sr
s
;;,
CORROSION GENERALLY
A PROBLEM DOWNHOLE
t t Si t 1 i t ft t it'~ti
CONVENTIONAL CURES
PARAMETER
SCALE CORROSION
TaFERATURE
DEC.
DEC.
PRESSURE DEREAS1NG
PRESSURE
INC.
DEC.
N RESEVOIR
PH
DEC.
INC.
SATURATION INDEX DEC.
INC
DISSOLVED SALTS INC.
DEC.
CHEMICAL ADDITIVES
MALE
Ca180614N
PHOSPHONATES AMINES
POLYACRYLATES THIO-AMINES
POLYMALEATES FATTY ACIDS TO 1 000mg/1
AT 1-10 mg/1
ZINC CHROMATES
PROTECTIVE SCALE
FIGURE 1. SCHEMATIC DIAGRAM OF A PRODUCTION SYSTEM
•
THRESHOLD MOTORS MAY NOT WORK ABOVE SI 2.3
RANGE WHERE SCALE CAN PROBABLY BE
2.0
CONTROLLED MTH CHFJAICAL
INHIBITORS
TRANSMON RANGE FROM NON-SCALING
TO SCALING
1.0
RANGE
SCALE
WHERE
FREE
INHIBITORS ARE PROBABLY NOT NEEDED IN A
SYSTEM
EQUILIBRIUM
0.0
SCALE WILL NOT FORM
BELOW SI 0.0
SCALE WILL DISSOLVE
1 .0
-1.0
AND BRINE MAY BE VERY CORROSIVE BELOW SI
FIGURE 2. DEPICTION OF SI VALUES AND
CORRESPONDING SCALE-RELATED PHENOMENA FOR
CALCIUM CARBONATE, SCALE FORMING BRINES
Polyetnylaneglyco4nnonOnnto
Patiel110401011/.00,0W,PHH
wo AT
ester PE-22
0
Cipost 2000
--- OH
14+0/44HTeM1004nr1.1-410004014:4440/12
HEM
Ostn.Ht2ow
HO 014 OH
I 8
1
HO— P—C — • — OH
0
a
tiszed phosphonairearboxylate
I
VITC-08
CH. 0
44041.04.
044441'1444041.1.40ents\
04044410n4 200soitax Pe:01
)1 04.04. 24 CHICHI .4,..
I
4404,044
CHI
CH.P0s14
0401141120110
PO•14.
N
101.10110eCa.°4"W
2144:1444300
Ptanotorals00,044,
WTC-11
1
COON
CHNC,00.1
I
CH,
6,24.
;'0,14
HO —C—COOH
CH/000H
A
01—,04).-14-404).
1
C.
\CH*P03HP4a
Cnrle PC/0
VITC-10
-Om
AHsPO,Ns,
14000C(CH24— N
FIGURE 3. SOME COMMON THRESHOLD SCALE INHIBITORS
ais
csoPosmil
CHEMICAL
RESERVOIR
CHEMICAL
INJECTION
POW
VALVE 0
FILTER
VALVE
TREAT
STRING
RUPTURE DISK
CHECK VALVE [
FIGURE 4. SCHEMATIC DIAGRAM OF BASIC
INHIBITOR TREAT STRING APPARATUS
CALCIUM SULFATE (GYP) SCALE REMOVAL CHEMICALS
Scale type deposits have probably been occurring in well bores and surface equipment since the beginning of the industry. The literature shows investigations on paraffinprOblems as early as 1923. (1) And there is a reference for
acid being used in wells for, "... dissolving out limestone that has been
deposited from the waters...", in Oklahoma in 1928. (2) Generally the inorganic scales were assumed to be calcium carbonate. Where these scales formed
they were considered more of a nuisance than a serious problem. The standard
solution was acidization of the well and equipment.
With the advent of waterflooding and particularly in dolomitic reservoirs, it soon
became apparent that, in addition to carbonates, sulfate scales were formed. The
principal scale was calcium sulfate with barium and strontium types being
occasionally encountered. Since these scales were essentially insoluble in acid
the usual treating procedures were no longer effective. It further became apparent
in the sixties, that when these scales formed on the reservoir face and in
perforations, the productivity of wells would be markedly reduced. As the
seriousness of the calcium sulfate problem was recognized there was a concerted
effort by both producers and service companies to develop treating chemicals and
procedures to solve the problem.
EARLY FIELD EXPERIENCE
With the damaging effect of scale formation on well productivity fully recognized a
major sales effort was directed to this problem by chemical suppliers. In a survey
conducted in 1962, twenty-two chemical suppliers were marketing 93 commercial
formulations for the prevention or removal of scales. These ranged from well known,
low priced materials to complex blends of organics with alleged esoteric actions.
Many of the early well treatments failed and by the mid-sixties it was estimated
that only 50% of the programs for removal of sulfate scales were even partially
effective. A survey conducted in the late sixties listed 35 chemicals being
furnished by fifteen suppliers for. the removal of well deposits of sulfate scales.
It was obvious from field results that either many of the chemicals were not
effective or well treating procedures were inadequate.
The extent to which calcium sulfate deposits can impair production of a well
is shown by Figure 1, for the period 1961 to 1967. Also it will be noted in
2
Figure 1 there is wide variations in the effectiveness of the clean out procedures, further emphasizing either chemical or treating method inadequacy. In
view of frequent treating failures and erratic results,in depth studies of the
problem were required.
LABORATORY STUDIES ON CALCIUM SULFATE REMOVAL CHEMICALS
In the late sixties the laboratory of a major producer began an evaluation
of the effectiveness of chemicals being sold for gyp scale removal.
Fifteen suppliers furnished 30 chemicals for the tests.
The initial program was a screening type to determine which of the chemicals
exhibited sufficient activity to warrant additional evaluation. The criteria
for passing this test were arbitrarily selected as:
A - Effective with a dilution rate of 1:1 with water.
B - Compounds formed must be either water or acid soluble.
C - Reaction independent of pressure (no CO2 evolution).
D.- Effectively convert 75% of scale to a soluble form.
The screening tests were on 1/2 inch cubes cut from gypsum rock consisting of
fine needle like gyp crystals andarorphous CaSO4 powder. While it was recognized the rock was not comparable to the frequently encountered crystal form,
it had many advantages for a screening test. The samples were of a uniform
composition and test blocks could be precisely sized. The high porosity and
permeability furnished a maximum of surface area for reaction.
The bottle results shown in Figure 2 are typical of the performance of many of
the chemicals. By visual observation only, the treated sample indicates the
reaction has been extensive. But as shown by the test results in the third
bottle the rate of conversion has been quite low. As shown in the Table at the
bottom of the Figure only four of the chemicals evaluated met the specifications that had been established for acceptability.
In view of the inadequacy of most of the chemicals the suppliers were informed
of results on their materials and comments requested, permission was also granted to submit additional chemicals for screening. Some suppliers objected to the
type of rock used in the testing and it was agreed to conduct future tests on
other forms of calcium sulfate.
In the second test program 31 chemicals were submitted for evaluation. The testing
method was identical to that described for the first program, illustrated in
Figure 2. However to assure the form of the calcium sulfate was not influencing
the results three variations were used. The rock type used previously, thin clear
bladed crystals from a pipe in West Texas carrying Hendricks Reef water, and crystals deposited in tubing in a New Mexico well. The latter were of a variety of
shapes and sizes. In the tests they were broken and graded to approximately the
size of pea gravel.
The test procedure was identical to that presented in Figure 1, except the
chemical was used at a 100% concentration. Of the 35 chemicals tested 23 met
the requirement for 75% effectiveness.
3
The second screening test was to determine the dilution effect. In most wells
the area to be treated will be filled with produced water. Also in many treatments, where a long producing interval is to be covered, it is desirable to dilute the chemical. The criteria for acceptance was that 75% of the scale must
be converted to a form soluble in water and/or acid at a 1:1 concentration of
the chemical. Figure 3 illustrates typical results on the chemicals meeting
this specification and outlines the test procedure followed.
This test eliminated 12 of the 23 chemicals. The 11 chemicals meeting the
specification all gave results in the 95 to 100 percent efficiency range.
The type and speed of reaction indicated all these chemicals to be of the
same generic family and of the same approximate concentration. Also the
results were so markedly superior to the other 12 chemicals in the program
that no further testing was warranted on the other products. The 11 satisfactory products were from nine major chemical supply companies. This assured the availability of a suitable product in all major producing areas.
This program established the effectiveness of chemicals and eliminated this
as a potential source of treating failures.
FACTORS CONTROLLING SCALE DEPOSITS (3 , 4)
Once it became recognized that calcium sulfate scales could be plugging the
formation there was a tendency to over react. Many operators, without adequate
study assumed any abnormal production rate decline was caused by scale
deposits. While the ineffectiveness of many of the chemicals resulted in
failures, unfortunately many wells were also treated where scale was not the
problem. However as the factors governing the precipitation of calcium sulfate
scales became more generally known the treating of wells where scale was not
the problem markedly decreased. The following discusses the principal items to
be reviewed in evaluating the scaling possibilities in a well or field.
RESERVOIR ROCK CHARACTERISTICS: It would be assumed that the water, both in the
interstices and formation outside the reservoir, would be saturated with the
soluble salts contained in the producing interval. The usual mineral sources of
the calcium and sulfate ions are anhydrite, gypsum and hemihydrate. If any of
these minerals are present it would be assumed the waters contained in the
reservoir are saturated with calcium and sulfate ions for the pressure and
temperature conditions of the reservoir. It should further be assumed, in flood
projects, regardless of the injection water composition, it will become
saturated with calcium and sulfate ions, where the above minerals are present,
as it moves from injection to producing wells.
When calcium sulfate containing minerals, are present in the reservoir, scale
deposits should be anticipated during the producing life of the field. However
the deposits may be in the producing equipment rather than the well bore. Also
the time period over which scales occur will vary with water composition and
pressure and temperature conditions in the flow stream,- --
TEMPERATURE EFFECT: The curves on Figure 4 show the solubilities in distilled
water of the three mineralized forms of calcium sulfate at various temperatures.
While the form and relative position of the curves would be expected to remain
the same, the solubility values will change with pressure and other dissolved
salts. The relationship between the gypsum and anhydrite illustrates why both
types of scales will be encountered in production operations. For the conditions
of the curve, at temperatures less than approximately 100°F., gyp crystal
4
scales will develop. Above this temperature the anhydrite should be expected.
Since in most wells the temperature drop between reservoir and well bore would
be insignificant, this factor is not considered important in most well bore
deposits. But as will be noted the solubility of gypsum drops significantly
below 100° F. This probably accounts for the heavy crystal deposits in some
systems where the surface temperatures in pipelines are below the produced
water temperature.
PRESSURE EFFECT: Figure 5 illustrates how pressure drop increases the tendency
of scale to form from saturated solutions. The pressure drop effect, coupled
with the decreasing solubility of gypsum at temperatures below + 100° F. accounts for many of the crystal type scaling problems encountered in shallow,
low temperature reservoirs. Also the crystal scale development frequently encountered where pressure drop occurs in surface operations.
As shown by Figure 5 the rate of scaling increases with increasing pressure
drop. Once scaling has begun the fluid passages will plug rapidly. There have
been many instances where calcium sulfate scales have completely plugged
fluid passages. As shown in Figure 1, where such deposits occur in perforations or on the formation face the production will be markedly reduced.
DISSOLVED SALTS EFFECT: The solubility of calcium sulfate increases as the content of most of the soluble salts normally found in oil field waters increase.
Sodium chloride is usually the predominant salt and Figure 6 illustrates how
the solubility of calcium sulfate is markedly increased up to a salt concentration of 150 gms. per liter.
The variation in calcium sulfate solubility with salt content, when coupled with
the pressure effect can be a frequent cause of formation plugging in flood projects. When relatively fresh flood waters contact highly saline formation waters,
both of which are saturated with calcium sulfate, the salt concentration in the
mixture will be reduced. Under these conditions the solubility of calcium sulfate
will be exceeded and scale precipitation occurs. In most of the reservoir this
will not significantly reduce the permeability. But when it occurs in the well
bore zone or perforations and particularly when coupled with the pressure drop
effect, plugging can occur.
FACTORS EFFECTING WELL TREATING PROCEDURES (4)
Calcium scale removal treatments, being of the chemical conversion type, are time
dependent and there are a number of well bore conditions that will markedly
influence their effectiveness. The following factors should be evaluated where
the conventional "spot and wait" treatments are planned.
TREATING TIME: The conversion reaction whereby the calcium sulfate is changed to
a water or acid soluble compound is a surface active phenomena. This requires
maintaining intimate contact between the scale and the treating compound for a
significant period of time. Figure 7 illustrates that for optimum laboratory
conditions. With pea sized gravel crystals, a minimum of 6 hours is required for
100% conversion. In this test the total surface areas of the crystals were exposed to 100% concentration of the treating compound. In well treatments the scale
would be attached to reservoir face or perforations and the reaction would be
occurring only over the exposed surface of the scale. Under these conditions the
time for conversion would be greatly increased. Field experience indicates that
in developing a procedure for a specific area or field, initial treatments
should be at least for a 24-hour period and preferably longer.
THIEF ZONES: In low pressure wells, where some strata are essentially depleted,
thief zones can markedly reduce treating effectiveness. Should the hydrostatic
head used in spotting the treatment be too high, most of the treating chemical
may enter the depleted strata. Where thief zones are known to exist a preflush
for partially filling the thief zone may be desirable. Also in the spotting of
the treatment every effort should be made to minimize the hydrostatic head.
WELL BORE WATER: As noted in Figure 3 concentration of the treating chemical is
of major importance, with a minimum concentration of 50% being considered necessary. In most wells the producing zone will be filled with water and this may
extend up the hole. Also, if the scale is removed first from a high water producing zone, there may be an inflow of water during the treatment. In determining
the concentration of the chemical the possibility of these extraneous waters
diluting the treatment must be considered. With open annulus spotting procedures
dual treatments may be required to obtain good results.
LOW PRESSURE ZONES: Where a highly depleted zone is plugged by scaling, once the
scale has been removed,there is the possibility of this acting as a thief zone.
FIELD TEST DATA: While field experience during the sixties had often been disappointing, with the elimination of inadequate chemicals and the developing of
treating procedures the success ratio increased. The experiences in one West
Texas field for the period 1970 - 75 are shown in Table I (5). It is obvious
from this data, that where calcium sulfate scales are impairing production,
successful treatments are possible.
AN OPTIMUM WELL TREATING PROCEDURE (5)
As the problems associated with scale removal treatments discussed in the previous sections were discovered, procedures were developed to circumvent the difficulties. The method described below, controls the hydrostatic head minimizing
the thief zone problem. In addition by isolating the zone to be treated, the
possibility of serious dilution of the chemical is prevented. Also by the use of
a controlled overflush, that squeezes treatment into the producing interval any
skin damage effect, due to scale, will be more directly treated.
The technique requires the use of packers and accessories. Careful control is
required with regard to-chemical volume and injection procedure. A programmed
well clean up is also required to assure maximum treating effectiveness. Obviously the method is far more expensive than the usual spotting method applied
in most treatments of this type. Prior to application well performance and
reservoir conditions should be reviewed. It is essential that the well have the
potential to produce significantly larger volumes of oil, to warrant the
additional cost of the treatment.
The increases in production that can be obtained with this type of treatment
are listed in Table II. These wells in a West Texas field were known to have
heavy gyp scale build-ups and with the increases shown, the additional expense
and time required for the optimum treatment was certainly justified.
TREATING EQUIPMENT AND PROCEDURE: The well equipment is illustrated in Figure 8.
It consists of a hook wall packer with a fluid spotting control valve, coupled to
the packer by a tail pipe, to position the valve close to the bottom of the zone
to be treated. The spring in the control valve is adjusted to the wells hydrostatic head, under closed in conditions. When the assembly has been run and the
slips set the treatment is pumped into the well. The recommended volume is 1-1/2
to 2 times that required to cover the zone to be treated. The chemical mixture is
displaced into the well with the volume of oil required to spot the treatment
over the zone to be treated. The packer is then set and the remaining volume of
chemical in the tubing is displaced into the formation.
The well is closed in for 24 hours, but preferably longer on initial treatments.
The well is returned to production, by swabbing the tubing dry, and dropping a
bar to shear the pin in the valve and open the block out sleeve. The swabbing
should be continued for two to four hours. This is to recover the residue of the
reaction and prevent any unconverted small crystals from being forced back into
the formation and acting as a nuclei for scale growth. The well should be
acidized for a final clean-up and stimulation.
CONCLUSIONS
1.
Laboratory and field test programs have proved the calcium sulfate scales
can be successfully removed from the well bore face and perforations.
2.
Marked increases in oil production can be obtained from reservoirs having
the potential for increased production.
3.
Where large increases in production are possible the additional expenses
of optimum treatments are warranted.
4.
Successful scale removal treatment should be followed by scale
inhibitor squeeze type treatments to minimize further scaling.
REFERENCES
(1) Mills R. : Van A. : The Paraffin Problems in Oil Wells, U.S. Bur.
Mines R. I. 2550 (1923)
(2) History of Petroleum Engineering, Pg. 598, American Petroleum Institute.
(3) NGSMA Handbook
(4) Richard S. Fulford, Effects of Brine Concentration and Pressure Drop
on Gypsum Scaling in Oil Wells, AIME SPE-1803, 1967
(5) Jerry N. Crane, An Engineered Approach For Successful Removal of
CaSO4 Scale Deposition; Petroleum Engineer, July 1972
FIGURE CAPTIONS
Fig. 1. - Calcium Sulfate Scale Plugging And Clean Out
Results In A West Texas Well
Fig. 2. - Results With Gyp Scale Removal Chemicals
Fig. 3. - Average Effect Of Dilution On Gyp
Scale Removal Chemicals
Fig. 4. - Solubility Of Calcium Sulfate Scales In Water
Fig. 5. - Pressure Effect On Scaling Tendency Of
Calcium Sulfate
Fig. 6. - Effect Of Salt Concentration On Solubility Of
Calcium Sulfate
Fig. 7. - Rate Of Gyp Crystals Conversion Versus
Time Fig. 8. - Optimum Treating Procedure
Table I. - Gyp Scale Removal Treatdents In a West Texas Field
Table II.- Results With Optimum Well Treating Procedure
inhibitor
senleeze
4000 --
0 ZL - TIAPPY.L.C/1101MI
1
3000
2000 _
I
1000 -1
1- CLEAN OUT PROGRAMS -i
62
I
63
I 64
1 65
_ r ___
1
66
1 67

.
"•"."."'"."••••,-4,.••
0
Li «C id,
Vb
4
a
E ". U a
0
" C•4
0 a . . 0 a t V •I•.• ••
tu
-.1 alat; "o
W S
i n
8.tua
IL
Val
•••• t" *
la •IP
0
-1.1 .0
•
0
14 : ...In 31
2 c t:t %....
V 0 E 7:
WEIGHT OF SAMPLE — 16.16
0.
SAMPLE LOSS-4.71 gr
E :E
o
to
0
*0
TREATING EFFICIENCY —29%
0
g
GYP SCALE REMOVAL CHEMICALS
C
FiVIURP1 - 2
p
ab i
.r■
.
WEIGHT OF SAMPLE-11.45 grs.
TESTRESULTS
TREATED SAMPLE
11.":4■••■'"
'•••"7"."
.., .0 4.0 k....2 — 3 0_ a c ;-,
r... E
"v t I a a
-- 0 a ...
.1
AVERAGE EFFECT OF DILUTION ON
GYP SCALE REMOVAL CHEMICALS
GYP SCALE CRYSTALS CONVERTED -%
Hot Water
100
80
iii
15°/0HCI
11 11
—
Nr-
60
40
20
0
10
100
50
25
CHEMICAL CONCENTRATION —%
FInURT: - 4
S OLUB I LI TY OF SCALES IN WATER
ZOW
I
AtMI 1401YDRATE
(C460-.11/420)
2400
2200
2000
,GYPSUM
(CaS0.2H20)
1100
,
1600
i
1400
1200
100
1111
Ilk
ANwroarr
a
(Ca604
33 IS 104 140 171 212 240 214 120 36$
0 am
TEMPERATURE-'F
SCALE PRECIPITATED
700
(6000 ppm in solution @ 100'F. & 100 gm/1 P4sCI)
z 600
2 see
2
0
7
3116
lo
o
/
/tut
io
c
a
0 2
10
12
14
PRESSURE DROP in nein 100
111
SOLUBILITY OF CALCIUM VS SALT CONCENTRATION
4000
z
0
n 5000
3
a
♦000 a
3000
2000
0
50
100
150
Gill Conaminition—ipme.11 IOW R
PERCENT CRYSTALS CONVERTED
GYP CRYSTALS CONVERSION
PERCENT VS TIME
(optimum for laboratory tests)
PACKER AND SPOTTING CONTROL VALVE
(unknown fluid level)
SLIPS SET
PACKER OPEN
PACKER CLOSED
OPEN
BY-PASS
CLOSED
SPOTTING CHEMICAL
CHEMICAL ISOLATED
TAILPIPE
SPOTTING VALVE
OPEN
CLOSED
TABLE I
GYP SCALE REMOVAL TREATMENTS IN A
WEST TEXAS FIELD
YEAR
10
91
V
•
73TAL
WELLS
17
42
31
50
33
17
rya
BEFORE
OIL WATER
17
10
29
20
36
29
45
81
46
100
23
110
36
59
AFTER
OIL
60
50
64
61
62
35
56
WATER
69
81
113
142
146
175
121
INCREASE
OIL
43
21
28
18
16
12
20
WATER
59
61
84
61
46
65
62
-
1 1
TREATING RESULTS
Well No.
1
2
3
4
5
6
7
8
9
10
Total
Prior Production
Water
12
0
7
3
21
8
8
21
17
13
44
0
35
9
61
5
8
13
37
16
88
250
Oil
Oil
Production After
Water
197
46
37
 37
120
102
31
393
61
56
89
97
81
68
96
31
72
104
35
96
880
969