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Copyright 2006, Society of Petroleum Engineers
This paper was prepared for presentation at the 2006 SPE Gas
Technology Symposium heldin Calgary, Alberta, Canada, 1517 May
2006.
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AbstractGas production and transportation pose challenges for
operators. Unprocessed gas streams in production and flowlines
containing brine and hydrogen sulfide are particularlycorrosive and
susceptible to forming hydrates and scaledeposits. Methanol is
often added to such streams for hydrate
prevention; however, methanol increases the corrosiontendencies
of pipes and equipment because it can deactivatesome Corrosion
Inhibitors (CI) and adds oxygen to the system.As a result, if
hydrates are controlled with methanol, thesystem requires extra
amounts of properly selected corrosioninhibitors to counteract the
oxygen induced acceleratedcorrosion.
Corrosion rates of tubular steel exposed to sweet and sour
brines were investigated. The sweet conditions containedcarbon
dioxide saturated brine, methanol, corrosion and gashydrate
inhibitors. Hydrogen sulfide was added to the systemto create a
sour environment. Methanol and hydrogen sulfide
present in wet gas streams create an environment difficult for
corrosion control; they accelerate corrosion rates to the pointof
rendering some commercial corrosion inhibitors unsuitablefor
corrosion protection. It was discovered that some gashydrate
inhibitors offer both, hydrates and corrosion
protection. In addition it was found that the
corrosioninhibiting properties of these gas hydrate inhibitors
wereenhanced in the presence of hydrogen sulfide.
The dual action of the Low Dosage Hydrate Inhibitor (LDHI)
described here can limit or even eliminate CorrosionInhibitors in
highly corrosive methanol containing sour gas/water streams; thus,
LDHI application improves
production and transportation economy by replacing highvolumes
of methanol with less costly volumes of LDHI and
providing additional operational savings on CI.
IntroductionGas hydrates form when water molecules crystallize
aroundguest molecules. The water/guest crystallization process
has
been recognized since i ts discovery by Sir Humphrey Davy in1810
it is well characterized and occurs with sufficientcombination of
pressure and temperature. 1 Lighthydrocarbons, methane-to-heptanes,
nitrogen, carbon dioxideand hydrogen sulfide are the guest
molecules of interest to thenatural gas industry. Depending on the
pressure and gascomposition, gas hydrates may build up at any place
wherewater coexists with natural gas at temperatures as high as30C
(~85F).
Formation of undesired gas hydrates can be eliminated or
hindered by several methods. The thermodynamic preventionmethods
control or eliminate elements necessary for hydrateformation: the
presence of hydrate forming gas, the presenceof water, high
pressure and low temperature. The eliminationof any one of these
four elements from the system would
preclude the formation of hydrates. Heating and
insulatingtransmission lines is a common mechanical solution to
thehydrate problem often encountered in long subsea pipelines.Gas
dehydration is another method of removing a hydratecomponent.
However, in a practical oil and gas operation,water can be
economically removed to a certain minimumvapor pressure only and
residual water vapors are always
present in a dry gas. Hydrate plugs in "dry" gas lines have been
reported in the past. 2
Tubular failures due to corrosion and pipelines pluggingwith
solid hydrates are major concerns for gas production andtransport
operators. Hydrate plugs can form in a short time,often within a
few hours at hydrate formation pressure andtemperature (p/T)
conditions. Corrosion is a significantlyslower process taking
months or years to manifest itself withhardware failing.
Nevertheless, both processes can result in
catastrophic consequences if left unchecked.The addition of
chemicals to the gas/water streams is the
most common method of preventing corrosion and hydrateformation.
Small amounts of commercial corrosion inhibitingcompounds are
applied to mitigate corrosion. Large amountsof alcohols, glycols
and salts are being utilized to controlhydrates. These additives
(THI) thermodynamicallydestabilize hydrates and effectively lower
the temperature of hydrate formation. They function by bonding to
water molecules through hydrogen bonds or solvation.Unfortunately,
oxygen carried with hydrate preventing solventaddition has strong
negative impact on corrosion rates.Replacing thermodynamic
inhibitors with hydrate growth
SPE 100474
Corrosion Mitigation W ith Gas -Hydrate InhibitorsR . Hoppe, R .
L. Martin, SPE, M . K. Pakulski, SPE, and T . D. Schaffer, SPE, BJ
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2 SPE 100474
inhibitors that are ten to several hundred times more
efficient,offers a significant cost reduction to gas producers
and
pipeline operators.The non-thermodynamic hydrate inhibitors
called Low
Dosage Hydrate Inhibitors (LDHI) are further categorized
intoAnti-agglomerants (AA) and hydrate growth inhibitors. Thelatest
are subdivided into Kinetic Hydrate Inhibitors (KHI)
and Threshold Hydrate Inhibitors (ThKI).Incidentally, the most
corrosive environment in the
oilfield, oxygen contaminated sour brine and gas is the
mostsusceptible to hydrates formation due to hydrate promoting
properties of hydrogen sulfide (H 2S). Figure 1 illustrates
adramatic hydrate equilibrium shift toward lower pressure andhigher
temperature with increased concentration of hydrogensulfide in
methane. The difference in hydrate formationtemperature T is 14 C
(25 F) between 100% methane gasand 20% H 2S in methane at
intermediate pressure 10,000 kPa(1,450 psi).
100
1000
10000
100000
-10 -5 0 5 10 15 20 25 30Temp. deg C
P r e s s u r e , k
P a
Methane 100%
5% H2S in Methane
10% H2S in Methane
20% H2S in Methane
Fig. 1: Comparison of hydrate formation in CH 4/H2S
mixtures. Hydrate equilibrium curves simulated with software
package Hydrate 5.2, DBR, Edmonton, Canada.
Hydrate prevention with methanol and glycols can be
quiteexpensive due to the high effective dosages required, 20%
to50% of the water phase. Ethylene glycol is usually
recovereddownstream and recycled. Methanol is not usually
recoveredand poses an environmental problem. Methanol partitions
tothe oil or condensate phase and is carried to refining
facilitieswhere it has to be washed out. It greatly increases
oxygendemand of any water effluent resulting in the possibility of
discharge permit violations and/or additional expenses for
wastewater treatment. Methanol accelerates equipment and
tubular corrosion due to acidic impurities and dissolvedoxygen,
and aggravates potential scale problems by loweringscaling salts
solubility in water and precipitating most knownscale inhibitors.
3
Some work has been done in the past to quantify the effectof
methanol on steel corrosion in sour systems. Siegmund eall 4
concluded that dissolved oxygen in technical grade
methanol is the major factor accelerating corrosion rates.Martin
5 suggested corrosion inhibitors that function in
brine/methanol sour-environments while Thieu and
Frostmanreported field experience with hydrate suppression in
sour-systems. They did not report any laboratory data concerningCI
and LDHI effectiveness. Dahlmann and Fenstel 7 attemptedto design
molecules displaying both LDHI and CI properties.This approach
requires the inhibitor to bind to a metal surfaceand hydrate
crystals. The task is achievable by designingmolecules having two
different ends, hydratephillic andmetallophillic. It is not clear
how much each property iscompromised by having them both. This new
technology isnot being applied in the oilfield at this time.
A certain class of KHI displays amine functionality8
Being amine derivatives these compounds are potentialcorrosion
inhibitors. Standard corrosion testing procedureswere applied to
these LDHI in various conditions to measuretheir impact on
corrosion rates and how they interfere withcommercial CI.
Results and DiscussionAmbient Pressure Corrosion TestingWheel
Corr osion Test . The test, NACE ID182 measuresweight loss of 1018
steel coupons submerged in NACE brine(7.33% NaCl, 0.7539% CaCl 2
and 0.1% MgCl 2) saturated withCO 2 and sealed. Bottles containing
tested samples aremounted on a wheel turning continuously for 24
hours at 65C(150 F). Weight loss of coupons exposed to inhibited
anduninhibited (blank) brines is compared and inhibitor
efficiencyis calculated.
Two known gas hydrate inhibitors were tested,
polyvinylpyrrolidone (PVP) and oligomeric (LDHI).
Table 1Laboratory Corrosion Results
Wheel Corrosion Test
Hydrate Inhibitor Concentration
% Corrosion Inhibition
PVP ---0.01% None0.1% 8%0.3% 12%LDHI ---
0.01% None0.1% 12%0.3% 83%
Minimal anti-corrosion properties of the PVP compoundwere
observed in this test while LDHI oligomer displayedreasonable
anti-corrosion activity at typical kinetic hydrateinhibitor
concentrations.
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SPE 100474 3
Copper Strip Cor rosion. Condensate, a liquid mixture of light
hydrocarbons, is usually associated with natural gas
production. This valuable light-end petroleum fraction can be
blended directly into gasoline without any processing if itdisplays
no copper corrosion. Traces of sulfur compounds incondensate are
responsible for the copper corrosion.
Two solutions of LDHI one 10% in water and another one
10% in kerosene were prepared for testing. For a reference,
aclear condensate (200 mL) from central Texas, USA wasadded to
equal volume of tap water in a separatory funnel andvigorously
shaken for two minutes. Water was allowed toseparate and drained.
The top condensate layer was collectedand submitted for the copper
strip corrosion test (ASTMD1838). The same procedures were repeated
with addition of 20 mL LDHI kerosene solution to test #2 and 20 mL
LDHIwater solution to test #3. In the test, freshly polished copper
strips are exposed to the fuel for three hours at 50C (122F).
Next, the strip color is compared to standards and the
resultsare graded accordingly to visible coloration. Freshly
polishedcopper coupon receives grade 1a; the next best ones are 1b,
2a,
2b, 2c... Results in Table 2 indicate relatively minor copper
corrosion.
Table 2Laboratory Test ResultsCopper Strip Corrosion
No Description Results1 Blank 2c2 LDHI / Kerosene 1b3 LDHI /
Water 1b
Rating 1b obtained for condensate treated with LDHIchemical is
practically the best result one can expect to get.This rating is
significantly better than the 2c for the untreatedcondensate. The
results indicate that the LDHI that is solublein the hydrocarbon
phase, but would preferentially partitioninto the water phase is
capable of mitigating the effect of corrosive sulfur compounds
dissolved in the condensate.
Ambient Pressure Linear Polarization Resistance Testing.Series
of Linear Polarization Resistance tests were performedat ambient
temperature in 2000 mL glass resin kettles.Corrosion rates were
monitored using a linear polarizationresistance instrument with 3
electrode probes. Tests were 24-hour exposures of AISI 1018 (UNS
G10180) steel electrodesto stirred solutions at laboratory
temperature. In all CO 2 tests
(called sweet conditions), the brines (3% NaCl, 0.3% CaCl 2
x2H2O) were CO 2 sparged for the duration of the tes t. For sour
condition tests, the brines were also saturated with CO 2 , 1 g/Lof
Na 2Sx9H 2O) was added, then the kettle was sealed for the
balance of the tes t.Corrosion rates were sometimes determined
by weight loss
of the reference electrode. Electrodes were cylindrical with
asurface area of 9 cm 2. Tests were performed using mixtures of 75%
brine and 25% technical grade MeOH except test #1,which was
performed with 100% brine. Methanol was aerated
prior to adding it to the brine in test #2. It was determined
before that various grades of methanol i.e. reagent quality or
solvent obtained from the field display identical
performance.Measured corrosion rates are collected in Table 3.
Observations It is not surprising that regardless of conditions,
sweet or sour systems displayed extremely highcorrosion rates
without any corrosion inhibitor, particularlywhen methanol was
saturated with air prior to the testing (exp.
#1-3, 13). LDHI did not offer much corrosion protection inthe
sweet environment and can even cancel the protectiveeffect of a
wrongly selected CI (exp. #4-7). Several corrosioninhibitors are
effective in sweet mixtures of brine, methanol,and LDHI (exp.
#8-12). The same LDHI becomes aneffective CI in sour systems (exp.
#13-15). Quaternization of LDHI leads to a surfactant type molecule
with enhancedaffinity to the metal surface. The derivative has
improvedcorrosion inhibition properties in both, sweet and sour
systems(exp. #16, 17).
Table 3Corrosion Rates in H 2O/MeOH System
With Various Corrosion Inhibitors
Exp.# LDHI CI Gas Av. mpy
1 - - CO 2 73
2 - - CO 2 1123 - - CO 2 444 0.3% - CO 2 355 1% - CO 2 526 - A1
CO 2 2.17 0.3% A1 CO 2 338 0.3% B1 CO 2 0.99 0.3% C1 CO 2 2.2
10 0.3% D1 CO 2 1.411 0.3% E1 CO 2 0.812 0.3% H1 CO 2 1.513 - -
H 2S/CO 2 4014 0.3% - H 2S/CO 2 1.715 1% - H 2S/CO 2 0.916 0.15%* -
CO 2 1417 0.15%* - H 2S/CO 2 2.2
*Quaternized LDHI (converted to AA, see reference 8a) wasused in
the last two experiments.
High Pressure Corrosion TestingL PR Resul ts in Sour Gas
Systems. Originally the testing of
LDHI was for a sour gas gathering system to assure there is
noincompatibility between the hydrate inhibitor and
incumbentcommercial corrosion inhibitor, CI-A. The corrosion
inhibitor was evaluated at a concentration 200 ppm alone, as well
as inthe presence of 10% methanol/LDHI and against 10%inhibited
methanol normally used in the system.
Test conditions: 50C (122 F), ~ 125 rpmPressure: 550 psi (3800
kPa)Gas composition, Mol%: CO 2 10%, H 2S 22%, CH 4 68%Brine:
Central Alberta ~ 3% TDSTest duration: 94 hours
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Detail ed Test Protocol . Brine was charcoal filtered and then
purged with CO 2 for two hours. The pH was then adjusted to5.0 with
hydrochloric acid. The autoclave cell is constructedof Hastelloy
C-276 and has a capacity 300 mL. The tests werecarried out with 200
mL of brine or approximately two-thirdfull. A three-electrode
assembly was suspended from the lidof the autoclave, keeping the
bottom clear for a teflon-coated
magnetic stir-bar. The configuration of the electrodes was
aclosely spaced equilateral triangle, with each
cylindricalelectrode having a 9.5 mm x 12.5 mm geometry.
Thereference electrodes were made from Hastelloy C-276 whilethe
working and counter electrodes were 1018 carbon steel.The
electrodes were cleaned and weighted. The quotedsurface area of
4.55 cm 2 has been used for the corrosion ratecalculations. A
thermistor probe held at the center of the cell
by a Hastelloy sleeve sensed the temperature of the fluid in
theautoclave. Purging and changing the headspace of theautoclave
was done by means of an offset Hastel loy tube fittedwith a
pressure gage and sour-service needle valve. LPR measurements were
obtained at 30 minutes intervals by
connecting the cell to a PC4-300 potentiostat and controller,via
Gamry ECM8 multiplexer. Data acquisition was done bymeans of Gamry
PC105 software package.
Autoclave Fi ll in g and Pressur in g Procedure. For all
threetests, purged brine (200 mL test #1, 180 mL for tests #2
and#3) was placed into an autoclave cell, followed by an
injectionof 200 ppm (40 L) of the corrosion inhibitor, CI-A. For
experiment #2, 20 mL of methanol (purged with CO 2 for 10minutes to
remove oxygen) was added making a 10%methanol solution in brine.
For experiment #3, 20 mL of methanol and hydrate inhibitor were
added to 180 mL brine inthe autoclave.
After sealing and purging, each cell was pressurized withacid
gas composed of 28% CO 2 , 72% H 2S to 175 psi (1200kPa) and the
pressure was increased to 550 psi (3800 kPa)with methane. The final
initial headspace gas compositionwas 10% CO 2, 22% H 2S and 68% CH
4 (all gas concentrationsare expressed in Mol%). Carbon dioxide and
hydrogen sulfidehave greater solubility in water than methane;
hence, the endheadspace gas composition was methane enhanced. Each
testcell was placed inside a heating mantle and brought to
50C(122F) via proportional temperature controllers (5-10 min).At
this point, the Gamry instrument started collecting LPR data for a
period of 94 hours.
Observations. Figure 2 depicts the LPR data collected from
all three autoclave experiments. The data indicate a quitelarge
corrosion rate in the CI-A/MeOH system. Apparently,the inhibitor
CI-A was deactivated with 10% methanol presentin the solution. This
CI-A deactivation cannot be attributed toa presence of oxygen in
the cell because the solvent was
purged with CO 2 to remove any dissolved oxygen from
thesolution.
Figure 3 shows the same data on an expanded Y-scale, sothat some
differentiation can be made between experiments #2and #3. One notes
two short periods of activity on the CI-A/MeOH/LDHI cell. These may
reflect a protective film
breakdown and reformation. One cannot be sure whether thiswould
stabilize over a longer period test. However, the
perturbation is quite minor when the scale of the Y-axis istaken
into the account.
0
2
4
6
8
10
12
14
16
18
0 10 20 30 40 50 60 70 80 90Time, hours
C o r r o s
i o n
R a
t e , m
p y
CI-A,MeOH LDHI,MeOH,CI-A CI-A
Fig. 2: LPR data collected from cells 1-3 (full Y-scale).
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
0 10 20 30 40 50 60 70 80 90Time, hours
C o r r o s
i o n
R a
t e , m
p y
LDHI,MeOH,CI-A CI-A
Fig. 3: LPR data collected from cells 2-3 (expanded
Y-axisscale).
Figure 4 shows the corrosion potential of each cell as afunction
of time. Using a Hastelloy C reference electrode, onecan determine
the rest or corrosion potential of each cell. Insome systems, the
less negative the value of Ecorr, the more
passive the cell. However, in the sour environment, this set
of
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SPE 100474 5
data has only a limited value because the system is not
passivated.
-25
-20
-15
-10
-5
0 0 1 2 3 4 5 6 7 8 9
Time, hours
C o r r o s
i o n p o
t e n
t i a
l , m
V
CI-A,MeOH LDHI,MeOH,CI-A CI-A
Fig. 4: Corrosion Potential Data from cells 1-3.
The gravimetric and visual inspection results obtainedfrom each
cell are provided in Table 4.
Table 4Gravimetric and Visual Inspection Results
of Corroded Electrodes
Cell Fluid Corrosion mpy Visual
CI-A blank 0.4 Minor pittingCI-A/ MeOH 5.0 Severe pitting
CI-A/ MeOH / LDHI 0.3 Minor pitting
The results indicate a standard commercial corrosioninhibitor
doesnt perform in the presence of methanol, leadingto a significant
damage of tubular iron and equipment.Addition of LDHI can
compensate for an inferior CI in the
presence of methanol.
Autoclave Corrosion Testin g at Sour Conditi ons. Machinemilled,
single sided C1018 steel disks were submerged in anautoclave
containing the test solution and pressurized withCO 2 and H 2S
mixtures. The disks were pre-corroded for 12hours in the test
solution without the sour gases.
Test conditions: 35C (95 F), stirring at 120 rpmPressure: 241
psi (1660 kPa)Gas composition: 16 mol% CO 2, 84 mol% H 2SBrine: DI
water, purged with N 2 for 1h
Test duration: 12 hours pre-corrosion + 6 days
After completion of each test, the weight loss and pittingof the
disks was calculated in mm/yr. Results are presented inthe table
below.
Table 5
Corrosion Rates of Steel Disks inSour Solution and Various
Additives
ExperimentNumber Composition
Corrosionmm/year
Pittingmm/year
1 DI Water only 0.442 02 66% MeOH 0.324 11.7
3 66% MeOH, 0.25%CI-B* 0.091 2
4 40% MeOH,+ LDHI 0.193 0
5 40% MeOH, 0.25%CI-B + LDHI *
0.208 0
6 10% MeOH, + LDHI 0.21 0
7 10% MeOH, 0.25%CI-B* + LDHI, 0.191 0
*CI-B commercial corrosion inhibitor different than CI-A
The testing purpose was to investigate the effect of a partial
replacement of methanol with LDHI. Largeconcentrations of MeOH
result in severe pitting of steel unacceptable in the field
environment. Even a large dosage of commercial corrosion inhibitor
lowered the overall corrosionrate but did not prevent pitting (exp.
#2, #3). Replacing some
methanol with a significantly less volume of LDHIdramatically
lowered corrosion rates and eliminated pitting. Notice that the
corrosion rates with or without the inhibitor CI-B are almost the
same. CI-B can be eliminated withoutaffecting iron corrosion
(compare exp. #4 and #5 with #6 and#7).
ConclusionPreventing hydrates formation with methanol is
morecomplicated than simply adding sufficient amounts of thesolvent
to gas/water streams. Methanol increases corrosionrates and
deactivates some corrosion inhibitors. The testedLDHI displays CI
properties in some environments. The CI
properties are enhanced at sour conditions. Converting LDHIto a
quaternary ammonium compound further improves its CIactivity.
However, the required LDHI effective concentrationis usually
significantly higher than the typical loadings of acommercial
corrosion inhibitor.
When planning a corrosion and hydrates protection program for
any field operation one has to consider severalfactors: sweet or
sour stream methanol, LDHI or both chemicals for hydrates
prevention select CI compatible with hydrate inhibitors assure
LDHI is not deactivated by CI
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It is highly recommended to test new CI and LDHI prior tofield
application to avoid unpleasant surprises. Methanol isoften
replaced with LDHI as a less expensive solution to gashydrate
problems. If selected CI and LDHI are compatible, itis possible to
achieve further savings by using less CI in the
presence of LDHI.
AcknowledgementsAuthors thank the management of BJ Chemical
Services for approving the publication of this work and Dr.
WilliamClements for helpful review comments.
NomenclatureLDHI Low Dosage Hydrate Inhibitor including Kinetic
and
anti-agglomerant inhibitor CI Corrosion Inhibitor KHI Kinetic
Hydrate Inhibitor THI Thermodynamic Hydrate Inhibitor
AA Anti-agglomerant Hydrate Inhibitor PVP
PolyvinylpyrrolidoneTDS Total Dissolved SolidsMpy mils per year
corrosion rate, 1 mpy=0.0254 mm/yr.ThKI Threshold Kinetic Inhibitor
LPR Linear Polarization Resistance
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