220 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION
(NaHSO
3
), ammonium bisulfi te, (NH
4
)
2
HSO
3
, and
sulfur dixoxide (SO
2
) are some of the oxygen scaven-
gers that are used for this purpose. Filming corrosion
inhibitors are seldom used, because the large volumes
of water involved mean that oxygen stripping and scav-
enging is more economical.
This discussion has concentrated on the use of surface
waters for injection purposes. The handling of formation
water prior to reinjection emphasizes maintaining posi-
tive pressures on all piping and vessels to minimize air
entry. Oxygen scavengers are then added prior to
reinjection.
Because injection water oxygen control is the primary
means of corrosion control, it is necessary to monitor
the oxygen levels at various stages in treatment and
transport. This is done with online electronic oxygen
sensors as well as galvanic probes and other means of
corrosion monitoring. Galvanic corrosion probes that
will respond quickly to changes in oxygen content are
often the fi rst indication that oxygen control has been
compromised.
52
Reservoir souring due to inadequate injection water
treatment is a serious concern. This often happens
several years after water injection has started and is
usually due to inadequate water treatment to include
the use of biocides that are effective on anaerobic bac-
teria. Seawater treatment must include some means of
removing the natural sulfates present in seawater.
53
Tubing, Casing, and Capillary Tubing
Most corrosion problems in oil and gas production are
associated with tubing and casing. The reason for this is
the large volume of these components used per well.
While it is common to use CRAs for wellhead equip-
ment, pumps, packers, and so on, economic incentives
and availability drive the trends for continued use of
carbon steel and low - alloy tubing and casing. Concerns
with eventual souring of fi elds have convinced most
operators that all downhole equipment, to include
tubing and casing, should meet the recommendations of
NACE MR0175/ISO 15156.
16,34,35,54
Tubing Corrosion Most well designs use tubing strings
for upward production of produced fl uids. Formation
temperatures do not change during the lifetime of pro-
duction, but production rates decrease as fi elds age. The
resulting changes in temperature and pressure as fl uids
move up production tubing strings alter locations of gas
breakout in oil wells and condensation formation in gas
wells, and these altered locations are where most corro-
sion problems are likely to occur. Injection water break-
through can also alter the corrosivity of both oil and gas
wells. The cost of tubing replacement can be upward of
preferred method of corrosion control. For deep, hot gas
wells operating at temperatures where organic inhibi-
tors break down, the use of CRAs is necessary.
While a number of software systems have been
developed for the purpose of modeling gas well corro-
sion, they differ in their predicted corrosion rate outputs,
and they are not at the stage of development where they
can reliably predict corrosion rates prior to the start of
production.
26,27,32,33,47
SOCRATES, a proprietary soft-
ware package, is gaining wide use for selecting alloys for
downhole applications,
48
and other software is under
development . Nyborg reviewed the software available
in 2009 and reported diffi culties with all of the corrosion
rate prediction models.
32
Most of the currently available
models are not intended for use in the presence of H
2
S
or organic acids.
Injection Wells Injection fl uids are usually water or
steam but sometimes gas, for example, natural gas, CO
2
or H
2
S, injected into reservoirs to either avoid pollution
(disposal wells) or to maintain pressure. Enhanced oil
recovery is also important using water fl ooding, steam
injection and, in recent decades, miscible fl ooding with
CO
2
which may be pipelined long distances to maintain
production after less expensive means have neared or
reached their limits.
Because injection water chemistry can be controlled,
it is common to use carbon steel or 1% Cr for many
injection wells, although fi ber - reinforced plastic (FRP),
and lined pipe are also used. If bottomhole conditions
lead to corrosive water accumulation, the tubing and
equipment at the bottom of the hole may have CRAs,
usually 13Cr.
NACE RP0475 recommends metallic materials for
injection water handling. It recommends carbon steels
for use in non - aerated injection waters (less than 10 ppb
oxygen) with CO
2
partial pressures below 20 kPa (3 psi)
and without H
2
S. Tables of alloys for other service are
provided, including recommendations for various com-
ponents on injection pumps, valves, fi lters, oxygen, and
H
2
S strippers, and miscellaneous equipment to include
storage tanks, gathering and injection lines, and down-
hole tubing.
49
Most corrosion control of injection water is by gas
stripping to remove dissolved oxygen. This method is
used for seawater and surface waters intended for injec-
tion wells, because it is normally more cost - effective
than vacuum deaeration. It can achieve part per billion
levels of residual oxygen, but the lower limit depends
on the quality of the stripping gas. Natural gas, exhaust
gas from engines, or nitrogen are the normal stripping
gases used for this purpose.
20,50,51
Oxygen scavengers are
then added to the water bringing dissolved oxygen
levels down to approximately 5 – 10 ppb. Sodium bisulfi te
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