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CORROSION MANAGEMENT |
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Based on a workshop sponsored by PTTC's Southwest Region on June 25, 2002 in Farmington, New Mexico
Corrosion can be uniform, or of a pitting nature where penetration rates can be very high. Corrosion severity is influenced by temperature, pressure, pH, velocity, and wear/abrasion, among other factors. Corrosion inhibitors, which are typically organic amine-based compounds, function by establishing a film that protects metal from corrosive fluids. In production wells, a target goal might be below 1 mpy (mils per year). In water systems, a 2 mpy rate might be tolerated. Many monitoring techniques, including brine analyses, corrosion coupons, and visual inspection, are used to monitor treatment effectiveness. Chemical treating programs often address scale prevention as well as corrosion inhibition. Organic deposits, paraffin and asphaltene, may also be part of a treating program. Field experience indicates that a systematic, integrated process will, over time, reduce failure rates, effectively lowering lifting costs.
Corrosion is a fact of life in operations. Unmanaged, corrosion can cause premature equipment failures leading to unnecessarily high operating costs and environmental/safety problems. Independents typically rely heavily on vendor recommendations for corrosion/chemical treating. This approach can be effective, but operators who understand corrosion basics are better able to assess recommended treating programs and program effectiveness.
Brine Sampling, Corrosion Inhibition, Failure Reduction, Paraffins & Asphaltenes, Wellbore Management
Field Water Analysis and Corrosion Management
Mike Cloud, Champion Chemicals
Corrosion Problems in Petroleum Production
Rich Martin, BJ Unichem
Paraffin and Asphaltene Formation Damage
Ken Barker, Baker Petrolite
The Producing Well Improvement Process
Kent Gantz, Schlumberger IPM
For corrosion to occur, there must be: (1) an anode, (2) a cathode, (3) conducting metal between anode and cathode, and (4) a conductive fluid. The anode is where metal dissolution occurs. Corrosion rate is typically expressed in mpy (mils or thousandths of an inch per year). CO2, H2S, oxygen, and microbes can all contribute to corrosion. Corrosion can be general where metal loss occurs uniformly, or of a pitting nature. Pitting corrosion rates can be orders of magnitude higher than uniform corrosion rates. Under-deposit corrosion (bacterial, solids, etc.) is a common problem. Metallurgy and stress points within a metal from manufacturing or damage influence where corrosion starts. Oilfield steels are also susceptible to hydrogen damage (hydrogen cracking of high strength steels in tension, stepwise/blister cracking on non-stressed, medium strength steels), and corrosion fatigue, alternating tensile stress.
Corrosion severity is influenced by: (1) pH, (2) temperature, (3) pressure, (4) velocity, (5) wear/abrasion (wear-accelerated corrosion), (6) galvanic, (7) microbial activity, and (8) oxygen. Temperature is not a major factor below 110° F. Pressure affects solubility of CO2 and H2S in brine, which in turn affects corrosivity. Velocity can have a major effect on corrosion. For corrosive water in steel pipe, the limiting velocity is in the 6-12 ft/sec range. With crude oil, that limiting velocity is higher, in the 20-25 ft/sec range. Velocities in the 3.5-5.0 ft/sec range are usually required to keep BS&W entrained.
Velocity effects are more pronounced in sweet systems. Galvanic corrosion occurs in some combinations of dissimilar metals. Microbial activity can aggravate corrosion. Microbes can be aerobic, anaerobic, acid producing or sulfate reducing. Although requiring some oxygen, aerobic slimers can reproduce with as little as 0.5 ppm oxygen. Hydrogen sulfide in otherwise sweet systems can be related to activity of sulfate-reducing bacteria (SRB). Corrosion can occur under biomass or sulfide deposits. Oxygen is extremely corrosive, and typical oilfield corrosion inhibitors do not adequately control it. Common sources of oxygen include hydrotest fluids, leaks, improper vessel purging after closing, unblanketed tanks, and methanol injection.
Corrosion increases as pH decreases below 7. Lower pHs can be caused by carbonic acid (increasing CO2 levels), sulfuric acid (increasing H2S levels), and organic acids. Uninhibited corrosion rate in mild steel systems can be estimated from the following:
Corrosion Rate (mpy) of mild steel = ((ppm CO2+ppmH2S/2) + 0.2 (ppm
HCO3- + 1/2ppmH2S))/K
Where K = 50 in fresh water, K = 25 in oil well brine. Pits typically grow 10-50 times this rate.
Corrosion can never be completely eliminated. In production wells, a target goal might be below 1 mpy. In water systems, a 2 mpy rate might be tolerated.
Typical oilfield corrosion inhibitors function by creating a film or protective barrier between metals and the corrosive fluids. They can be applied by continuous injection, batch treatment or squeeze treatments. Most inhibitors are organic, cationic, nitrogen-based chemistries. Linear or cyclic amines, fatty acids, or quarternary amine chemistries are common. Carrier fluids can be water, alcohol or hydrocarbons. Many formulations have a surfactant component. Corrosion inhibitors are formulated to exhibit myriad combinations of oil and water solubility (from soluble to dispersible to insoluble in either phase). In selecting products, one must consider solubility, emulsion tendencies, foaming tendencies, gunking tendencies and partitioning. Common laboratory tests for screening inhibitors include wheel tests, rotating cylinder electrode, autoclave and corrosion loops.
A rough formula for calculating inhibitor requirements is:
Vol (gal of inhibitor) = (M x D x L)/(60 x A) where
M= desired film thickness, mils
D = pipe size, in
L = length, ft
A = inhibitor activity, %
Initial treatments should strive for 3-5 mil films to initially coat the pipe. Less inhibitor can be used in subsequent treatments, 0.5 to 1.5 mil, since only damaged films need to be repaired. Treating frequency depends to some extent on velocity and the severity of corrosion.
Common monitoring methods include: (1) failure records & visual inspection (but failures have already occurred by then), (2) weight loss coupons (gives only average rate), (3) spools, subs (more costly to install and recover), (4) brine analyses, (5) deposit analyses, (6) PAIR instruments (reads instant corrosion rates but must have conductive media over probe), (7) electronic resistance instruments (fairly quick, but can give false readings with pits or deposits), (8) different types of hydrogen patches/probes (indirect measurement), (9) inhibitor residual analysis, and (10) caliper surveys for tubing (disrupts production, which adds to cost). Other tools that can be used, but usually aren't, include A/C Impedance and electrochemical noise instruments. Copper ion displacement tests work only in certain areas.
Key questions to ask when sampling are: Why am I sampling (to evaluate or discover)? Where do I sample (representative of conditions)? How do I sample (flush lines, rinse bottle 2-3 times)? Certain parameters, such as dissolved oxygen, alkalinity, temperature, pH, CO2, and H2S will change, so they must be measured in the field. Alkalinity is related to the stability of waters for mineral precipitation. In the field, use a pH meter or paper. CO2 analysis is a color endpoint (phenolphthalein indicator) with NaOH titre. H2S analysis is a color endpoint (starch indicator) with KIO3 (potassium iodide) titre. Alkalinity is a color endpoint (methyl purple indicator) with H2SO4 titre.
For laboratory measurements, a 1-2 quart sample is generally sufficient. Acidify the sample when first collected with nitric acid to keep metals in solution. Iron concentration can be a measure of metal lost. Manganese concentration can be a meaningful indicator since manganese is rarely present naturally in quantities greater than 1 mg/l. The sooner the better for analyzing laboratory samples, remembering that total preservation is a practical impossibility. Chloride content is determined by titration with silver nitrate. Total hardness/calcium/magnesium are determined by titration with EDTA. Sulfate is determined by turbidmetry.
Knowing what to look for is important during visual inspection. The following illustrations, provided by Rich Martin with BJ Unichem and used with permission, illustrate how corrosion from different mechanisms looks.
Scaling occurs when conditions change—temperature, pressure and brine capacity. For example, when a pressure drop occurs, CO2 migrates from the liquid to the gas phase. Less CO2 in water increases pH, which lowers calcium carbonate solubility. Brine becomes supersaturated, nuclei form and CaCO3 scale crystals can begin to grow. Scaling tendencies can be assessed in terms of saturation index. A saturation index of 0 is in equilibrium, whereas a saturation index of 1.0 represents 10 times equilibrium concentration. There are equations for each major type of scale.
On the surface, continuous injection is most often used for scale inhibition. Downhole, scales can be treated by squeeze treatment or continuously (treating string, gas lift, side stream flush). For squeeze treatments, the overflush volume can be calculated as follows:
Vol (bbls) = 0.1781 x pi x r**2 x t x (porosity as a fraction) where
R = radial displacement into formation (4-8 ft recommended)
t = pay zone, ft
Common chemistries for scale inhibitors include: (1) phosphonates, (2) polymers, and (3) phosphate esters. Phosphate esters are good up to 160° F, phosphonates to 350+° F, and polymers to 400+° F. It is common to measure residual inhibitor concentrations in brine to monitor a scale inhibitor treating program. Scale coupons can also be used.
Paraffin and asphaltene are both organic deposits that can cause similar production problems, such as formation plugging, tank bottoms, filter plugging and coated solids—but they are different. Paraffins are N-alkanes with long chains to greater than C100 that form crystalline structures. Melting points can be greater than 240° F. Asphaltenes have a benzene ring structure with a charged, high density molecule. They form amorphous, usually brittle solids. Paraffins melt, while asphaltenes decompose. Deposits of both float on water and are soluble in xylene. Paraffin is soluble in crude oil, while asphaltenes are not. Paraffin is soluble in heptane, while asphaltenes are not.
Paraffin problems can be naturally occurring (from gas expansion cooling, geothermal gradient, high production levels) or from operational practices (cold completion/frac fluids, water/CO2 floods, hot oiling). Asphaltene deposits can occur when incompatible liquids destabilize micelles, such as in acid jobs, condensate treatments, or huff & puff treatments. They often occur when high gas/liquid ratios, as might be experienced in a CO2 flood, exist. Charged surfaces, which can occur with high flow rates, can also cause asphaltene wetting (and deposition).
Common hot oil treatments for paraffin removal don't solve the problem. They just move the deposits from one location to another. Water with chemicals (surfactant with or without dispersants) works better for removing paraffin deposits. The geothermal temperature gradient, typically 1° F per 100 ft, can even warm up cold water sufficiently to remove deposits. Re-circulating hot oil will actually deposit paraffins, leading to formation damage. Hot oil temperature (220° F in tubing and 260° F in annulus application) is above the wax melting point. Hot oil will carry wax in solution or dissolve any near surface deposit. Whereas downhole, as the treatment oil cools down to the formation temperature, it becomes over-saturated and dissolved waxes will redeposit.
Schlumberger Integrated Project Management (IPM) applied its Producing Well Improvement Process (PWIP) in an 80,000 acre, 1,200 active well (900 producers) mature (producing since 1925) project in the Permian Basin. In 1991, before the effort, well failures exceeded 150 per month. Upon implementing PWIP, well failures were reduced to about 50 per month within the first two years, followed by a further steady decline to the current (2000) level of 18 per month. This equates to a failure rate of 0.25 failures per well per year. More than half of the current failures are tubing failures (includes injectors and wells with submersible pumps). Remaining failures are split evenly between rod and pump failures. Lease operating costs, over $0.70 per barrel of liquid lifted in 1994, have been holding steady at around $0.40 per barrel of liquid lifted since then.
The PWIP is a systematic, holistic process by which well production optimization and wellbore equipment repair procedures are implemented and improved over time. Decisions are based upon data, not just opinions, using economic parameters consistent with business plans. Pre-planned well service procedures, trained well service and support crews, post-job review and analysis, and automatic operation and continued surveillance are key elements of the process. Pre-planning well service procedures means that there is a written package presenting the data and diagnosis, well information, well servicing procedure, cost estimate and economics, and the appropriate authorization. Forcing a thorough analysis eliminates surprises.
Given a good well servicing plan, well-trained service and support crews execute the job in the field. No job is complete without post-job review and analysis. Well service records must be complete and accurate, failure examinations made, mistakes identified and process improvements discussed. On a post-job basis, pump-off controllers and continued surveillance by the lease operator extend equipment run life. Experience indicates that taking the lowest bid is often not the best option, there is no excuse for repeated failures of the same kind, and repeated failures of different kinds reveal that the initial process was not thorough enough. Tracking failures by lease operator beat allows problem severity and human factors to be assessed.
Philosophies which have proven to be cost effective include: (1) clean older rods while pulling for visual inspection, (2) scan tubing and remove red (> 50% wall loss) and green (31-50% wall loss) band joints, (3) treat rods and tubing with corrosion inhibitor going in hole, (4) run rods with tongs checking coupling displacement, (5) collect samples for analysis when cleaning wellbore, (6) install the smallest pump with the slowest polish rod velocity possible, (7) keep rod loads in the 80% range, (8) always use sinker bars with lift subs between sinker bars, (9) avoid fluid pound by leaving a little production above the pump, and (10) use premium quality pumps with Ni-carb coated brass barrels, 316 SS fittings and silicon nitride valve balls. Depending on well environment, rod strings are case hardened steel, API C, and fiberglass using the lightest effective weight possible. Tubing is seamless J-55 using a 316 SS pup joint above the seating nipple.
Corrosion protection is critical, since about 40% of the failures are due to wear and wear with corrosion, plus another 20% due to corrosion alone. Scale and sand cause 20% of the failures, while human error causes 20%. For corrosion protection, wells should be treated at least weekly with the minimum treatment being one gallon of inhibitor. Allow one gallon of inhibitor for every 100 bfpd produced. Wells producing above 300 bfpd should be treated continuously with 35-50 ppm of inhibitor. Consider how sour wells are when developing a treating schedule. Application is more important than the specific product.
Mike Cloud
Champion Chemicals
2060 South 1500 East
Vernal, UT 84078
Phone: 435-789-4327 Fax: 435-789-4315
Email: CLOUDMW@aol.com
Richard Martin
B J Unichem Chemical Services
Tomball Technology Center
11211 FM 2920
Tomball, TX 77375
Phone: 281-357-2608 Fax: 281-357-2701
Email: RMartin@bjservices.com
Ken Barker
Baker Petrolite
5032 Darfield Ct
Saint Louis, MO 63128
Phone: 314-968-6001 Fax: 314-968-6013
Email: Kenneth.Barker@bakerpetrolite.com
Kent Gantz
Schlumberger IPM
P.O. Box 1859
Pennwell, TX 79776
Phone: 915-580-4359
Email: kgantz@pennwell.ipm.slb.com
For information on PTTC's Southwest Region and it's activities contact:
Robert Lee, Director, Petroleum Recovery Research Center
801 Leroy Place, Socorro, NM 87801
Phone: 505-835-5408 Fax 505-835-6031 Email lee@prrc.nmt.edu
Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.
The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.
Petroleum Technology Transfer Council, 2916 West T. C. Jester, Suite 103, Houston, TX 77018
Toll-free 1-888-THE-PTTC; Fax 713-688-0935; E-mail hq@pttc.org;
web www.pttc.org
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