Chilingarian G.V. et al. Surface Operations in Petroleum Production, II
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175
Corrosion
inhibitors
In acid corrosion, metallic iron goes into solution at anodic sites and electrons
are liberated at cathodic sites, reducing hydrogen ions to form gaseous hydrogen
(Williams et al., 1979, p. 92). A corrosion inhibitor reduces the acid reaction rate at
the cathodic site, anodic site, or both. An anodic type inhibitor functions by sharing
electrons of its molecules with anodic sites on the metal surface. This makes the
surfaces more noble. In the case of cathodic type
of
inhibitor, a protective film
forms on the metal surface by attachment
of
the cationic inhibitor to the cathodic
area through electrostatic attraction. The effectiveness of inhibitors is a function of
their ability to form and maintain
a
film on the iron surface. As pointed out by
Williams et al. (1979, p. 92), an important factor limiting the effectiveness is
hgh
temperature, because at higher temperatures the acid corrosion rate increases,
whereas the ability of the inhibitor to adsorb on the metal surface decreases. In
general, at temperatures above 250
OF,
effective inhibitors for strong acids are very
expensive and hard
to
formulate.
As pointed out by Harp and Dobbs (1967, p. 7), hydrochloric acid
is
the most
corrosive (on ferrous metals) of all commonly used acids for stimulation of oilwells.
With increasing temperature and/or concentration of acid, the acid reaction on the
metal becomes more rapid. Some organic corrosion inhibitors can protect tubular
d
E!
1000
I
I
CONDITIONS
ACID
15%
HCI
METAL TYPE
N-80
EXPOSURE
TIME 24
HOURS
AG
IT
AT
I0
N
130
RPM
-
INHIBITOR
CONC.
0.1
VOL.
%
10
1
I
100
150
200
TEMPERATURE
-
"F
Fig.
5-4.
Relationship between the temperature and corrosion rate. (After McDougall,
1969,
fig.
4,
p.
32;
courtesy of the Materials Protection.)
176
goods for up to 24 hrs at
300
OF
using 15% HC1. In the case of 28% HC1 at 210
”
F,
protection cannot be provided for more than
six
hours. New inhibitors for use with
strong acids and capable of long-term metallic protection must be developed for
deep or high-temperature wells. Hydrochloric acid usually etches in a “pitting” or a
“roughmg” pattern on tubular goods (Harp and Dobbs, 1967, p. 7).
Williams et al. (1979, p. 95) stated that the selection of an inhibitor type and its
concentration can be done only after the following facts concerning treating and
well conditions have been established: (1) type of tubular goods, (2) duration of
acid-pipe contact,
(3)
maximum pipe temperature, and (4) type and concentration
of acid. It is assumed that a loss of 0.02 lb/sq-ft of metallic area can be tolerated if
there is no pitting. Arsenic inhibitors, which historically have been used for
high-temperature wells have the following disadvantages: (1) arsenic is a dangerous
poison, (2) arsenic compounds are relatively ineffective
if
HC1 concentration is
above 17%,
(3)
arsenic compounds are ineffective in the presence of hydrogen
sulfide, and (4) arsenic can poison catalysts used in the refineries. Figure
5-4
shows
the effect of temperature on the effectiveness of an inhibitor. While not as effective
as arsenic, some organic inhibitors can be used at temperatures up to 250°F.
Expensive systems such as combined organic-inorganic inhbitor systems can be
designed for temperatures up to 400
OF.
For
example, inhibition extender potassium
iodide is effective.
Mutual solvents
Materials that have appreciable solubility in both oil and water are called mutual
solvents. They include alcohols, aldehydes, ketones, and ethers. In oilfield applica-
tions, ethylene glycol monobutyl ether (EGMBE) is frequently used in sandstone
acidizing as a mutual solvent. It also reduces interfacial tension between oil and
water and acts as a solvent to solubilize oil in water. Sutton and Lasater (1972)
found that the use of a mutual solvent reduces the adsorption of surface-active
materials on the formation solids. Hall (1975) found that the addition of a mutual
solvent increased the depth of penetration of the surfactant in laboratory tests (sand
packs). Dunlap (1966) described the use of EGMBE (preflushing before HC1
injection) in a carbonate reservoir. The EGMBE improves the effectiveness of the
acid treatment acting as a formation cleaner and oil remover. (See Williams et al.,
1979, for a detailed treatment
of
the subject.)
Surfactants
Williams et al. (1979, p. 95) pointed out that surface-active agents are used in
oilwell acid treatments to (1) reduce interfacial tension, (2) demulsify acid-oil
emulsions,
(3)
alter formation wettability, (4) prevent sludge formation in the case
of concentrated acids (28% HC1 or higher), and/or
(5)
speed cleanup. Cationic
surfactants (organic amines and salts of quaternary amines) and nonionic surfac-
tants (polyoxyethylated alkylphenols) are often added as a demulsifying agent to
117
minimize the development of formation fluid blocks by acid-spent acid-crude oil
emulsions. Alkyl aryl sulfonate (anionic) or ethoxylated alkylphenol (nonionic)
surfactants in concentrations of 0.1-0.5% by volume can be used to reduce the
interfacial tension between acid or spent acid and oil phase
(LST
acid, i.e.,
low-surface-tension acid). In theory, the reduced surface tension aids in increasing
the acid’s spreading ability on the surfaces of oil- or water-wet rocks. In addition,
the lower surface tension facilitates the commingling of live or spent acid with the
formation waters resulting in more efficient removal of fluids (Halliburton,
1965).
Hall
(1975)
noted that adsorption of the surfactants on rocks near the wellbore
limits their effectiveness in the field. In California (U.S.A.), the Rocky Mountain
States (U.S.A.), Canada, and other areas, anti-sludge agents are required during
acidizing formations with heavy oils, containing high concentrations of asphaltic
materials. Surface active agents such as fatty acids, alkylphenols, and certain
oil-soluble surfactants are sometimes effective. It is strongly recommended to
determine the type of asphaltine present in the crude oil and actually test the
effectiveness of the surfactant in the laboratory using the field crude oil.
Friction
reducers
Normally, friction reducers are polymers that convert the Newtonian fluid
possessing constant viscosity at all shear rates, to a non-Newtonian fluid, with
I0
FLOW RATE,
BBL
PER
MIN
Fig.
5-5.
Relationship between the flow rate and friction pressure
drop
through a 2-7/8-in. tubing using
various
concentrations
of
polymer. (After Williams et
al.,
1979, p. 96, fig.
11.8;
courtesy
of
the Society
of
Petroleum Engineers
of
AIME.)
178
TABLE
5-IV
Friction reducers (After Williams et al., 1979, p. 97, table
11.1;
courtesy
of
the
Society of Petroleum
Engineers
of
AIME)
Fluid type Generic
Water-based pad Guar
classification
of
additive
Polyacrylamide
Cellulose
Oil-based pad Polyisobutylene
Fatty acids
Crosslinked organic polymers
Acid Guar
Gum karaya
Polyacrylamide
Cellulose
viscosity varying with shear rate. Addition
of
polymer to the acid mixture will
reduce the fluid’s frictional pressure drop through well tubing. Ths drop in
pressure, in turn, reduces the horsepower required to pump the acid mixture at a
specified rate or to pump the acid at the maximum allowable rate as the surface
pressure is maintained below a fixed limit. Figure
5-5
shows a typical relationship
between the friction pressure and flow rate through a Z7/,-in. tubing with various
concentrations of polymer. With increasing polymer content, the friction pressure is
decreased. The concentration of polymers used varies from
1
to
20
lb/1000 gal of
fluid (Williams et al., 1979, p. 97). Table
5-IV
lists many of the common additives
used for friction reduction.
Acid .fluid-loss additives
Fluid-loss reduction additives are added to reduce the rate of fluid loss from the
acid mixture in the induced fracture to the formation. Longer and wider fractures
result on reducing the rate of fluid loss from the acid mixture while generating
hydraulically induced fractures. Generally, fluid-loss reduction additives are com-
posed of two agents: (1) inert, solid particles that can enter the formation pores,
bridging near the fracture surface (Fig. 5-6.a), and (2) gelatinous material that plugs
the formation pores (Fig. 5-6.b; Williams et al., 1979, p. 98). Commonly used
fluid-loss additives are listed in Table
5-V.
Crowe (1971) listed the following limitations associated with fluid-loss additives:
(1)
The fluid-loss additive deposited from the fluid pad is effective only for a short
time once it is contacted by an acid that does not contain an effective fluid-loss
additive.
(2)
It is difficult to attain the same degree of fluid-loss control with an acid
179
A. SOLID PARTICLES ENTER AND BRIDGE IN PORES
FRACTURE
SURFACE
3-
PORES
3-r-p
FOR MATlON
6. SOLID ADDITIVE GELATINOUS MATERIAL PLUGS PORES IN
Fig.
5-6.
Behavior of typical fluid-loss additives. (After Williams et al., 1979, p. 97, fig.
11.9;
courtesy of
the Society of Petroleum Engineers
of
AIME.)
as with an inert fluid, because acid (reaction) destroys the matrix on which the filter
cake is being deposited.
(3)
Acid reacts with all the polymeric additives used to
control fluid loss, particularly at high temperatures.
(4)
Most fluid-loss additives
cannot effectively seal formation fractures or
vugs
that may be intersected by the
hydraulically induced fracture.
TABLE
5-V
Commonly used fluid-loss additives (After Williams et al., 1979, p. 98, table 11.2; courtesy of the Society
of
Petroleum Engmeers of AIME)
Hydrocarbon pad
Acid
Fluid type
Solid additives
Gelatinous additives
Aqueous pad Silica flour
Guar
Calcium carbonate Cellulose
Organic polymer Polyacrylamide
Inert solid coated with
guar-type material
Inert solid coated with
organic sulfonate
Acid-swellable solid
Organic resin
Silica
flour
Organic polymers
Guar
Karaya
Cellulose
Polyacrylamide
Polyvinyl alcohol
180
Diverting agents
A
diverting agent is used to obtain maximum stimulation in a wellbore by
diverting the injected fluids from a lower-pressure interval to a higher-pressure one
by temporarily plugging the lower-pressure interval. When used in matrix acidizing,
diverting agents are designed to bridge at the wellbore formation face by plugging
off the pores of the lower-pressure intervals first, followed by the plugging of
sequentially higher-pressure intervals as they begin to take fluid. Diverting agents
used for matrix acidizing include solid organic acids, finely divided inert organic
resins, deformable solids, acid-swellable polymers, mixtures of waxes and oil-soluble
polymers, and mixtures of water-soluble polymers (gum guar, gum karaya, cellulose,
polyacrylamide, etc.) and inert solids (silica flour, calcium carbonate, rock salt, and
oil-soluble resins; Williams et al.,
1979,
p.
99).
These diverting agents often can be
used to divert acid flow from intervals of higher permeability to those
of
lower
permeability without damaging the formation. The ideal quantity of agent to use
would be that which just reduces the flow into the higher-permeability zone
so
that
NO DIVERTING AGENT
WELLNO.
1
2
3
463 12 32
12
(19)(8l
\
/
\
1
-
FIELD
A
B
C
Fig.
5-7.
Comparative field results of fracturing with wax-polymer and other diverting agents. (After
Gallus and Pye,
1969,
p.
503,
fig.
10;
courtesy
of
the Society
of
Petroleum Engineers
of
AIME.)
181
it is equal to the
flow
into the lower-permeability interval. As pointed out by
Williams (1979,
p.
99), use of the excessive amount of additive will drastically
reduce injectivity into all zones.
An effective diverting agent in acid fracturing must bridge either at the perfora-
tions or immediately upon entering the fracture (Williams et al., 1979). The bridge
formed in this fashion must have a low permeability and be strong enough to stand
up under a differential pressure of several hundred psi. Upon completion of the
TABLE 5-VI
Comparison of various iron-sequestering agents (After Williams et al., 1979, p.
102,
table 11.3; adapted
from Smith et al., 1968; courtesy
of
the Society of Petroleum Engineers of AIME)
Sequestering agent Advantages Disadvantages Amount
a
(lb)
Citric acid
Citric acid-acetic
acid mixture
Lactic acid
Acetic acid
Gluconic acid
Tetrasodium salt
of
ethylene di-
amine tetracetic
acid (EDTA)
Trisodium salt of
nitrilo triacetic
acid (NTA)
Effective at temperatures of
up to
200
F
Very effective at lower tem-
peratures
Little chance of calcium
lactate precipitation if ex-
cessive quantities are used
No
problem from possible
precipitation as calcium
acetate
Little chance
of
calcium
gluconate precipitation
Large quantities may be
used without precipitation
of calcium salt. Effective at
temperatures up
to
at least
200
F
May be used in consider-
able excess without precipi-
tation as calcium salt. Ef-
fective up to at least
200
F
Will precipitate as calcium
citrate when excess quanti-
ties are used
When indicated amount
is
used, calcium citrate will
precipitate unless at least
2000
ppm Fe3+ is present
in spent acid. Efficiency de-
creases rapidly at temper-
atures above 150
F
Not very effective above
100
F
Effective only to about
160
F
Effective
only
up
to
about
150OF.
Expensive on a
cost-performance basis
More expensive
to
use than
many other agents
Less expensive than EDTA,
but still more expensive
than citric acid.
175
50 (citric acid)
87 (acetic acid)
190 (at
75
F)
435
350
296
250
a
Amount required in
100
gal
of
15% HCl acid
to
sequester
5000
ppm Fe3+ for a minimum of 2 days at
150
F.
182
treatment, the diverting agent must be easily removed from the fracture or perfora-
tions when the well is returned to production. Data are presented in Fig.
5-7
comparing the performance of several proppants. Additional information on acid
fracturing and proppants is presented in Chapter
4.
Complexing agents
The complexing agent is used to tie-up ions such as Fe3+ before they can
precipitate. When appreciable quantities of iron in the ferric ionization state (Fe3+),
as opposed to the more typical ferrous state (Fe2'), are dissolved by the acid, iron
precipitates in the flow channels and permeability reduction can occur when the pH
returns to 7. Sources
of
iron include (1) corrosion products found on the walls
of
casing and other tubular goods,
(2)
pipe scale, and
(3)
iron in a mineralized form
found in the formation (Williams et al.,
1979).
The precipitation
of
ferric hydroxide
can be prevented by adding certain complexing or sequestering agents
to
the acid.
Several organic acids (citric, lactic, acetic, and gluconic) and derivatives [ethylene
diamine tetracetic acid (EDTA) and nitrilo triacetic acid (NTA)] were reviewed by
Smith et al. (1968). Table 5-VI has been adapted from the studies by Smith et al.
(1968) by Williams et al. (1979). Each agent has its own advantages and limitations
with cost and performance widely varying.
Cleanup additives
In low-pressure reservoirs where a problem is anticipated in removing the spent
acid, the addition of gaseous nitrogen, alcohols, or surfactants can be considered
(Foshee and Hurst, 1965; Howard and Fast, 1970). Nitrogen can be added
so
that
when the wellbore pressure is reduced after the acid treatment, the nitrogen will
expand and help to push the spent acid out of the flow channels along with the
production. Alcohols are sometimes added to help to lower the interfacial tension
between the spent acid and formation fluids (McLeod and Coulter, 1966). Adding
alcohol
to
acid is most useful in very low-permeability, shally gas reservoirs, where it
is
difficult to remove water from the formation (Williams et al., 1979).
OILFIELD ACID TREATMENT DESIGN
Matrix acidizing
In matrix acidizing, natural permeability is restored around the wellbore by a
reactive acid flowing through the pores of the rock matrix, with injected acid
pressure being lower than that of the formation fracturing gradient. If the acid
penetrates the pores uniformly, the permeability will increase as a result
of
the pore
enlargement. If fractures are opened,
the entire interval may not be treated.
According to Halliburton (1971, personal communication), a large percentage of
183
PERCENT HCI
Fig.
5-8.
Effect
of
concentration
of
hydrochloric acid on reaction and spending rates. Reactivity reaches a
maximum
at a concentration
of
24-25%.
(Courtesy
of
A.R. Hendrickson
of
the Dowel1 Division of the
Dow Chemical Co.)
matrix acid treatments are conducted at injection rates which are too high. The rate
of injection is dependent upon the thckness and permeability of the formation
treated.
As
a general rule, the maximum injection rate should not exceed
0.1
bbl/min/ft of treated interval. Low injection rates must be used in order to
concentrate the acid reaction in the damaged zone around the wellbore. The
productivity increases as a result of removal
of
wellbore damage. Usually, low initial
injection rates are recommended, and the core tests with acid must be conducted
prior to field tests to determine the optimum rates. Generally, the volume
of
acid is
limited to less than
100-200
gal/ft of treating interval. If there is a good distribu-
tion of acid and damage is shallow, only 10-25 gal/ft may be required (Hendrick-
son,
1972,
p. 325).
Spending time of the acid determines the depth of acid penetration into the
formation. The acid reaction rate decreases as the acid is spent. The radius of
penetration of unspent acid is a function
of
the acid velocity in the formation and
the spending time of acid. The latter depends on the volume and strength of the acid
(Fig. 5-8), specific surface area of the formation, porosity, pressure, and tempera-
ture. If the injection rate remains constant and the spending time does not change
from one increment of the acid to the next, additional injected acid entering the
flow channels will not penetrate much deeper than the first acid increment. Instead,
it will enlarge the existing flow channels. The acid velocity in the formation
184
decreases as a result. Enlargement of pores also results in the reduction of the
surface/volume ratio. These two effects are opposite in significance.
The following assumptions are made in evaluating a matrix acid treatment (Craft
et al., 1962, p.
538):
(1)
the pores are of uniform size, (2) the formation is
homogeneous,
(3)
the acid penetration is uniform and radial,
(4)
uniform decline in
reaction rate with decreasing acid concentration, and
(5)
uniform decrease in the
weight of formation dissolved per increment of distance penetrated until the acid is
completely spent. The volume of acid injected is equal to the pore volume invaded
(see Craft et al., 1962, p.
538):
qit
=
T@h(
r,’
-
r:’)
(5-15)
where
qi
=
acid injection rate, bbl/min,
t
=
spending time of acid, sec,
r,
=
radial
distance of penetration until acid is spent,
ft,
@
=
fractional porosity,
r,
=
wellbore
radius,
ft,
h
=
formation thickness,
ft.
In order to acheve greater penetration during matrix acidizing, it is necessary to
decrease the reaction rate (increase the spending time) and/or increase the rate of
injection. Solving for
r,:
r,
=
[
(0.0936
qit/T@h)
+
r:]1’2
(5-16)
The spending time for several different acids is presented in Table 5-VII. Hendrick-
son et al. (1960) found that for most acids the spending time is less than 15 sec,
because of large specific surface area of reservoir rocks. Table 5-VIII shows various
required injection rates computed by Hendrickson et al. (1960) for a carbonate
formation. Craft et al. (1962, p.
540)
pointed out that inasmuch as spending time is
affected by many variables, it should be determined by laboratory tests for each
particular formation to be treated. In tight formations, acidizing at pressures lower
than fracturing pressures will result in an increase in permeability only in the
vicinity of the wellbore. Consequently, matrix acidizing is applicable for overcoming
formation damage only.
The most important variable, which must be determined prior to acidizing, is the
volume of acid to be used in a particular stimulation job. In most cases, however,
the optimum volume of acid required cannot be determined accurately. This is
critical because insufficient volumes of acid may cause damage to a sandstone
formation, for example. In the case of excessive volumes of acid, cementing
materials in the sandstones can be dissolved, resulting in damage through the
collapse of pore structure and thus, incurring additional costs. Acid volumes
required for optimum treatment are determined by the following variables:
(1)
porosity, (2) specific surface area of rock,
(3)
chemical composition of the forma-
tion,
(4)
thickness of the formation interval to be treated,
(5)
mineralogy and the
minerals distribution within the rock, (6) rock strength,
(7)
extent and type of
wellbore damage,
(8)
acid type, (9) acid strength,
(10)
treatment rate, (11) pressure,
and (12) formation temperature. Direct laboratory tests must be made to determine