By RUSSELL STEVENS &
SCOTT MALONE
Norris
K
eeping with the theme presented in the
previous three parts of this series, the rod
string is a vital link between the surface
equipment and the subsurface equipment in a rod
pumped well. To optimize the service life of the rod
string, it must be properly designed (based upon
experience), physically handled and made-up in
accordance with the recommendations of the manufacturer, and operated within acceptable design
parameters with an effective corrosion control
program. An effective corrosion control program that
is properly designed, implemented and optimized
using accepted monitoring techniques, is a critical
constituent that helps extend the economical service
life of the rod string. Since most failures can usually
be categorized as either man-made or well induced,
Part 1 (Well Servicing July/August 2005), Part 2 (Well
Servicing September/October 2005), and Part 3 (Well
Servicing November/December 2005) of this series
dealt with preventing man-made failures and
recognizing acceptable design parameters. Now in
Part 4, we will attempt to explore some of the more
commonly recognized design, implementation and
monitoring techniques for an effective downhole
corrosion control program.
Corrosion defined
Corrosion is defined by NACE International as
“… the deterioration of a substance (usually a metal)
or its properties because of a reaction with its
environment.” For the steel components in the rod
string, corrosion is the electrochemical reaction
between the steel and the corrosiveness of the
produced fluids. This electrochemical reaction will
turn your investment, in the rod string, into a worthless solution of corrosion byproducts (i.e., iron oxide,
iron sulfide, iron carbonate, etc.). Some form and
concentration of water (H2O) is present in all wells
considered corrosive and most contain considerable
48 Well Servicing January/February 2006
quantities of dissolved impurities and gases. For
instance, carbon dioxide (CO2) and hydrogen sulfide
(H2S) acid gases, commonly found in most wells, are
high soluble and readily dissolve in H2O –– which
lowers its potential of hydrogen (pH). The corrosivity
of the produced fluid is then a function of the amount
of these two acid gases that remain in solution, the
pH of the fluid, wellbore temperature and pressure.
Regardless of the steel grade or type, effective
corrosion inhibition is necessary in any well
considered corrosive. Some steel grades or types
may offer enhanced performance in certain aqueous
environments, but effective inhibitor programs must
be maintained to adequately protect the steel from
corrosion. In order to be effective and provide a
protective barrier against corrosion, the inhibitor
must be allowed to contact the surface of the steel it
is to protect. The preceding statement acknowledges
that, for effective corrosion inhibition, it is best to
start out with clean equipment. Another aspect of
corrosion is the steel and its potential to corrode.
New steel introduced into an corrosive environment
typically has a higher potential to corrode –– thus
steel components in the rod string must be
adequately protected from corrosion. NACE Task
Group T-1D-3 has prepared recommendations for the
corrosion control of steel sucker rods and these
recommendations are published in the API
Recommended Practice 11BR. These recommendations set forth standard guidelines for application
methods, inhibitor selection and treatment program
evaluation.
Type and method of treatment
Fluid compatibility, fluid volumes, completion
methods and reservoir compatibility determine the
type and method of treatment that is available for
each well. Fluid analysis is critical to the evaluation of
treating chemicals for compatibility with the fluid
produced by the well. Selection criterion includes
using chemicals that do not create stable emulsions.
Selection criterion also includes using treating
chemicals that are not so tenacious as to develop
undesirable precipitates or “gunk” when injected
downhole. Prior to their application, chemical
companies should test their chemicals with
produced well fluid in order to prevent operational
problems related to the chemical treatment program.
An effective corrosion inhibitor will create a
protective barrier between the steel rod string and
the corrosive well fluids, but will not create additional
problems with operating the well. Improper selection
of a corrosion inhibitor may result in increased
subsurface pump failures, rod failures and problems
with surface production facilities.
Batch treating
Batch treating down the casing/tubing annulus is a
common method of applying corrosion inhibitors.
Batch treating involves “pre-flush” water to wet the
casing/tubing, a high concentration of corrosion
inhibitor, and “flush” water, of a determined volume,
that helps disperse the chemical treatment downhole. A calculated quantity of corrosion inhibitor is
added to the casing/tubing annulus at regular
intervals to help promote the continued repair of the
protective inhibitor film until the next treatment
cycle. A basic rule-of-thumb for corrosion inhibitor
concentration is to start at 25 ppm (parts per million),
based on the total fluid production volume between
treatments, and to increase the concentration as
deemed necessary by results obtained from acceptable monitoring techniques. (Use a minimum volume
of 2 quarts corrosion inhibitor per 1,000' of well
depth). Flush volumes will be determined by the well
depth and the dynamic fluid level in the casing/
tubing annulus.
Batch treatments are sometimes re-circulated for
several hours. A relatively large volume of corrosion
inhibitor is deliberately re-circulated from the
casing/tubing annulus to the production stream and
back again. Batch and circulate treatments help
ensure all downhole production equipment surfaces
in the well make contact with the corrosion inhibitor
more than once.
concentration as deemed necessary by results
obtained from acceptable monitoring techniques.
Squeeze treatments
Although not a common practice, corrosion
inhibitor squeeze treatments can be effective and
long-lasting. Squeeze treatments involve pumping
large volumes of corrosion inhibitor, diluted with
solvent, into the producing formations under high
pressure. The inhibitor in the formation desorbs over
time to help maintain the inhibitor film on the downhole production equipment. A basic rule-of-thumb for
corrosion inhibitor concentration is to start with 50
to 75 ppm (parts per million), based on the total fluid
production for the expected treatment life. Because
inhibitor compatibility with the formation fluids and
the formation rock is a concern, squeeze treatments
are generally not used when other treatment
methods are possible.
Program performance
Once a corrosion inhibition program is designed
and effectively applied, it is important to monitor the
performance of the program and optimize the
inhibitor type or concentration level before failures
occur. An effective chemical inhibition program is
fairly expensive and may be subject to cutbacks if
justification for this huge expense cannot be made.
Continuous treatment
Continuous treatment is another method commonly
used to apply corrosion inhibitors. Continuous treatment involves a chemical-feed pump used to inject
corrosion inhibitor at the surface or below the subsurface pump via a capillary string. A small volume of
produced fluid is continuously circulated to help
flush the inhibitor down the casing/tubing annulus.
Prior to putting the well on continuous injection, a
pre-treatment application, typically consisting of five
to 10 gallons of concentrated corrosion inhibitor, is
injected into the casing/tubing annulus. The basic
rule-of-thumb for corrosion inhibitor concentration is
to start at 25 ppm (parts per million), based on total
fluid production, and to increase the level of
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Well Servicing January/February 2006 49
no means all inclusive on the subject of corrosion
induced failures. Chemical companies that specialize
in the design and treatment of corrosion inhibition
programs are the best source for up-to-date information about programs recommended for your
particular application.
Figure 1
Figure 2
Types of corrosion
Acid corrosion is a uniform thinning of the metal
surface, leaving the component with the appearance
of sharp, feathery, or web-like residual metal nodules.
Corrosion deposits will not be formed in the pits or
on the surface of the component (Figure 1).
Acid producing bacteria (APB) has the same basic
pit shape characteristics of CO2 acid gas corrosion
except for the cavernous appearing pit-wall and the
striated or grainy appearing pit-base. The pit will not
contain scale deposits (Figure 2).
Carbon dioxide (CO2) acid gas corrosion forms
round-based pits with steep walls and sharp pitedges. These pits are usually interconnected in long
lines but can occasionally be singular and isolated.
The pit base will be filled with iron carbonate scale ––
a corrosion byproduct of CO2 acid gas corrosion
(Figure 3).
Non-effective corrosion inhibition programs allow
the system to become contaminated and may require
extensive cleaning in order to re-establish an
effective maintenance film. By reducing an effective
inhibition program, it will become difficult to
continue operating the well economically due to the
potential damage incurred by the downhole
production equipment. In the long run, most wells
will be more economical to operate with effective
corrosion inhibition programs versus those without.
Monitoring techniques
NACE International recommends using several
monitoring techniques simultaneously, if possible ––
and recommends never relying on any single method
for monitoring corrosion! Some of the tools typically
used to measure the effectiveness of chemical
inhibition programs include: (1) water and gas analysis;
(2) weight loss coupons; (3) pH measurements;
(4) H2S content; (5) C02 content; (6) O2 content;
(7) chloride content; (8) iron count measurements;
(9) copper ion displacement (CID); (10) corrosion
inhibitor residuals; (11) linear polarization; (12)
bacterium cultures; (13) bottomhole temperature
measurements; (14) bottomhole pressure measurements; (15) fluid level measurements; and (16) visual
water quality.
Designing and implementing an effective corrosion
inhibition program is a complex subject that is
difficult to cover due to the numerous combinations
of corrodent concentration levels, temperatures,
pressures, compatibility issues, production volumes,
and completion methods –– to name a few. Proper
selection of the corrosion inhibitor type and
concentration level, application method and
monitoring techniques should help prevent most
corrosion related failures. However, this article is by
50 Well Servicing January/February 2006
Figure 3
Figure 4
Chlorides contribute to the likelihood of an
increase in corrosion related failures in wells with
small amounts of CO2 and/or H2S acid gas corrosion.
Plain carbon steel tends to pit in produced waters
containing high chlorides. The pitting is usually
spread over the entire surface of the component with
flat-bottomed, shallow, irregular shaped pits that
exhibit steep walls and sharp pit-edges.
Dissimilar metals corrosion may be apparent
when the less noble metal has a tapered or leeched
appearance toward the more noble metal.
Figure 5
Hydrogen blistering is the formation of blisters on
or near the metal surface from the absorption of
hydrogen into the metal lattice creating excessive
internal pressure in the steel (Figure 4).
Hydrogen embrittlement usually leaves the fracture
surface halves with a brittle, granular appearance
due to the immediate shear tear that occurs as a
result of the absorption of hydrogen into the metal
lattice and the loss of ductility in the steel (Figure 5).
Hydrogen sulfide (H2S) acid gas corrosion pits are
round-based with beveled walls and pit-edges. Pits
are usually random and scattered over the entire
surface of the component. Both the surface of the
metal and the pit-base will be covered with iron
sulfide scale –– a corrosion byproduct of H2S acid gas
corrosion (Figure 6).
Figure 7
Figure 8
Figure 6
Oxygen (O2) enhanced corrosion pits are broadbased, smooth-bottomed with the tendency for one
pit to combine with another. Pit shape characteristics
may include steep pit-walls and sharp pit-edges with
CO2 acid gas corrosion or beveled pit-walls and
pit-edges with H2S acid gas corrosion (Figure 7).
Stray current corrosion generally leaves deep,
irregular shaped pits with smooth sides and sharp
pit-edges.
Sulfate Reducing Bacteria (SRB) has the same basic
pit shape characteristics of H2S acid gas corrosion,
often with multiple transverse cracks in the pit-base,
tunneling around the pit-edges (aka pits-within-pits),
pit clustering, and/or unusual anomalies (i.e. shiny
splotches) on the surface of the component
(Figure 8).
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Well Servicing January/February 2006 51