1、1Item No. 24016NACE International Publication 1G286 (2002 Revision)This Technical Committee Report has been preparedby NACE International Task Group 086* on Oilfield CorrosionInhibitors and Their Effects on Elastomeric SealsOilfield Corrosion Inhibitors and TheirEffects on Elastomeric Seals April 20
2、02, NACE InternationalThis NACE International technical committee report represents a consensus of those individual memberswho have reviewed this document, its scope, and provisions. Its acceptance does not in any respect precludeanyone from manufacturing, marketing, purchasing, or using products, p
3、rocesses, or procedures not included inthis report. Nothing contained in this NACE International report is to be construed as granting any right, byimplication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, or productcovered by Letters Patent, or as indemnifying
4、 or protecting anyone against liability for infringement of LettersPatent. This report should in no way be interpreted as a restriction on the use of better procedures or materialsnot discussed herein. Neither is this report intended to apply in all cases relating to the subject. Unpredictablecircum
5、stances may negate the usefulness of this report in specific instances. NACE International assumes noresponsibility for the interpretation or use of this report by other parties.Users of this NACE International report are responsible for reviewing appropriate health, safety,environmental, and regula
6、tory documents and for determining their applicability in relation to this report prior toits use. This NACE International report may not necessarily address all potential health and safety problems orenvironmental hazards associated with the use of materials, equipment, and/or operations detailed o
7、r referredto within this report. Users of this NACE International report are also responsible for establishing appropriatehealth, safety, and environmental protection practices, in consultation with appropriate regulatory authorities ifnecessary, to achieve compliance with any existing applicable re
8、gulatory requirements prior to the use of thisreport.CAUTIONARY NOTICE: The user is cautioned to obtain the latest edition of this report. NACEInternational reports are subject to periodic review, and may be revised or withdrawn at any time without priornotice. NACE reports are automatically withdra
9、wn if more than 10 years old. Purchasers of NACE Internationalreports may receive current information on all NACE International publications by contacting the NACEInternational Membership Services Department, 1440 South Creek Dr., Houston, Texas 77084-4906 (telephone+1281228-6200).ForewordThis techn
10、ical committee report addresses the issue ofcorrosion inhibitor/elastomer interactions and defines thescope of the current problem.In the production of oil and gas, corrosive agents such aswater or brine, hydrogen sulfide (H2S), carbon dioxide(CO2), and low-molecular-weight organic acids can befound
11、 in the produced fluid or gas streams. Withoutproper controls, these corrosive agents can cause severedeterioration of production tubulars and other metal wellcomponents. In efforts to control this corrosion damage,film-forming corrosion inhibitors are being usedincreasingly in oilfield production o
12、perations. PreviousNACE publications1, 2have addressed the use of corrosioninhibitors in oilfield applications. While corrosion inhibitorscan be highly effective in protecting the metalcomponents, many types of inhibitor compounds used canalso attack and degrade the types of elastomers typicallyused
13、 in oilfield seal designs. This report includes datafrom various industry sources.This report was originally prepared in 1986 by NACE WorkGroup T-1G-17d, a component of Task Group T-1G-17and Unit Committee T-1G on Protective Coatings,Elastomers, and Other Nonmetallic Materials for Oilfield_*Chairman
14、 Donald R. Petrash, ABB Vetco Gray, Inc., Houston, TX.NACE International2Use. It was revised by Task Group 086 on Elastomersand Other Nonmetallics for Oilfield Sealing Service(formerly T-1G-17) in 2002 and is issued by NACE underthe auspices of Specific Technology Group (STG) 33 onOil and Gas Produc
15、tionNonmetallics and Wear Coatings(Metallic).IntroductionCorrosion inhibitors are complex blends of many differentcompounds, only a portion of which are nitrogen-containing materials. Other chemicals such assurfactants, emulsifiers, and biocides can also be present.Solvent and carrier systems can in
16、clude high-boiling-pointaromatics, xylene, various alcohols, saturatedhydrocarbons, and water. These other chemicals can bejust as damaging to particular elastomers as the nitrogen-containing compounds. Furthermore, they can also havesynergistic effects that make elastomer degradation muchworse than
17、 would be observed otherwise.To understand the interaction between corrosion inhibitorsand elastomers used in well equipment, an understandingof the ways inhibitors are used is necessary. Thetreatment method can be as important as the inhibitor orelastomer type in this interaction because differentt
18、reatment methods expose the elastomers to a variety ofinhibitor concentrations for varying time periods.Oilfield corrosion inhibitors can generally be divided intotwo broad classifications based on the carrier system usedin the field. Water-soluble inhibitor systems utilize wateras the carrier, whil
19、e hydrocarbon-soluble inhibitors usediesel fuel, kerosene, condensate, or other liquidhydrocarbon as the carrier. In selecting appropriateelastomer systems, it is also important to know thelocation of the inhibitor system, i.e., in the tubing orannular space.Common Treatment Methods and Their Effect
20、sTo protect well tubulars, corrosion inhibitors are introducedinto the well in a way that establishes good contactbetween the inhibitor and the metal surfaces to beprotected. Several schemes have been devised toprovide this contact and filming. The methods can bearranged in three categories: (1) tho
21、se that provide a high-concentration contact for a short period of time, (2) thosethat provide a low-concentration contact for a long periodof time, and (3) squeeze treatments that involve bothexposures.High-Concentration/Short-Period ExposuresThis category includes methods referred to as batchtreat
22、ment, tubing displacement, and swab treatment.Casing batch treatment is used when there is contactbetween the tubing and annulus, i.e., no packer is installedin the well. The inhibitor solution is pumped into thetubing-to-casing annulus and allowed to fall, or it isdisplaced with produced fluids or
23、solvent to the bottom ofthe well. There, the solution (often referred to as a slug)ispicked up by the well fluids and carried up the tubing, thuscovering the metal with film. Sometimes this treated slugis circulated several times down the annulus and back upthe tubing to ensure complete coverage of
24、all surfaces.Tubing displacement is a form of batch treatment in whichthe inhibitor solution is pumped into the tubing directly withthe well shut-in. It is allowed to fall to the bottom of thewell or is displaced to the bottom with produced fluids,solvent, or gas. The well is then returned to produc
25、tion,and the inhibitor solution is carried back up the tubing bywell fluids.Swab treatment is similar to tubing displacement exceptthat the inhibitor solution is displaced between brushesthat have been inserted into the tubing. The brushes arethen lowered using a wireline unit. This method usuallyen
26、sures complete contact of the inhibitor with the welltubing.Inhibitors used with these methods are normally dilutedwith suitable solvents. Concentrations can range from 1 to2% up to 50% inhibitor. Typically, concentrations are 5 to10%. Typical diluents for hydrocarbon-soluble inhibitorsare diesel, p
27、roduced oil, or produced condensate.Although these treatment methods are not widely usedwith water-soluble inhibitors, water-diluted solutions havebeen used in some cases.With these methods, all elastomers that normally see theproduced fluids are exposed to the inhibitor solution.Primary areas of co
28、ncern are wellhead and valve packingseals, subsurface safety valve seals, and to some extent,tubing and packer seals. Casing batch treatment alsoexposes any materials used in the annulus, e.g., controlline protectors, pump power cables, and tubing hangerseals, to inhibitor solution. Exposure times a
29、re generallyshort, i.e., less than 24 hours. However, equipment withcomplicated geometry such as safety valves can trapthese high-concentration inhibitor solutions for some timebefore they are diluted by normal produced fluids. Indeed,if production is primarily gas, these may not be diluted atall.Tr
30、eatment frequency depends on the corrosiveness of thewell fluids and inhibitor effectiveness. Typical intervalsbetween treatments can be anywhere from a few days toseveral months.Low Concentration/Long Period ExposuresThe primary example for this category is continuoustreatment. Special cases such a
31、s packer fluids andinhibitor atomization into lift gas produce similar results.NACE International3Continuous treatment can be accomplished by applyingsolution through dual tubing strings, small-diameter (0.375in. 1.00 cm or less) injection strings, tubing injectionvalves, packer bypass assemblies, o
32、r directly into an openannulus. Continuous treatment usually involves the use ofa diluted inhibitor solution, typically 1 to 10%. The inhibitoris normally added to the wellstream at the bottom, but itcan be injected uphole depending on the location of thecorrosion problems. Resultant inhibitor conce
33、ntration inthe produced fluids generally ranges from 10 to 20 ppm to1 to 2 vol% depending on inhibitor type and wellconditions. Depending on the injection method, someareas of the well can be exposed to high concentrations ofinhibitor. For example, if a packer bypass system ordownhole chemical injec
34、tion valve is used, the tubing-to-casing annulus is loaded with an inhibitor solution that canhave a concentration as high as 10 vol%. Packerelements, tubing-to-packer seals, control line protectors,tubing hanger seals, or any other elastomers external tothe tubing can see long-term exposure to high
35、 inhibitorconcentration. On the other hand, the use of a small-diameter injection string isolates the inhibitor from annulusseals and limits exposure to seals in the produced fluidsstream.Packer fluids constitute a special case of continuousinhibition. These fluids are solutions that are used to fil
36、lthe tubing-to-casing annulus above a packer. Theyusually consist of a salt solution of sufficient density tobalance downhole pressures. They are treated withwater-soluble inhibitors to prevent corrosion of the casingID and the tubing OD. Inhibitor concentration is usuallyless than 1 vol%, with 0.1
37、vol% being typical. Affectedelastomers are normally confined to tubing seals, packerelements, and control line protectors.Treatment via gas lift injection usually results in a lowconcentration of inhibitors. The inhibitor is injected intothe lift gas at the surface, and the entrained inhibitor iscar
38、ried through the gas lift valves in the tubing. Exposureis normally only from the bottom valve upward, so packerand seal assemblies are rarely affected. The resultantinhibitor concentration in the well fluid stream is similar tothat used in continuous treatment.Squeeze TreatmentSqueeze treatment is
39、similar to tubing displacementexcept that the inhibitor solution is displaced from thetubing and into the producing formation. During thedisplacement phase, the seals on the production side areexposed to high concentrations of inhibitor. Once the wellis returned to production, the inhibitor concentr
40、ationinitially remains high in the produced fluids, but slowlydrops with time as the inhibitor is washed from theformation. This involves a transition to a longer, low-concentration exposure. Squeeze treatment is usuallydone on a monthly or semiannual basis.Chemical Considerations for Corrosion Inhi
41、bitor FormulationsIn many formulations used in oilfield operations, theprincipal corrosion-inhibiting ingredients are long-chain,nitrogen-containing compounds. These compounds arefilm-forming in nature and can provide effective corrosioninhibition in oilfield environments.Reference Inhibitor Formula
42、tionsIn the course of designing laboratory test procedures toevaluate the performance of elastomers in simulatedoilfield environments, two reference inhibitor formulationshave been developed. These are a water-solubleformulation (Table 1) and a hydrocarbon-solubleformulation (Table 2). The compositi
43、ons in these tableshave been used by various laboratories to screen thesensitivity of selected elastomers to oilfield corrosioninhibitors. In particular, they have been used extensivelyby Task Group T-1G-17,3as well as by elastomermanufacturers4-9in the evaluation of seal materials.NACE Internationa
44、l4TABLE 1Elastomer Test Inhibitor A(A)(Water-Soluble)13.3 wt% Acetic acid31.1 wt% n-coco 1,3 propylene diamine22.2 wt% Isopropyl alcohol33.4 wt% Water(A)Formulated by NACE TG 086 (formerly T-1G-17).TABLE 2Elastomer Test Inhibitor B(A)(Hydrocarbon-Soluble)23.1 wt% Vegetable residue acid described as
45、a dimer-trimerwith an acid number approximately 150.11.1 wt% n-tallow, 1, 3 propylene diamine4.1 wt% Nonylphenol condensed with 9.5 to 10.0 moles ofethylene oxide.61.7 wt% Solvent described as heavy aromatic solvent, 90%of which will distill below 500F (260C) atatmospheric pressure.(A)This reference
46、 inhibitor, formulated by NACE TG 086 (formerly T-1G-17), has a hydrocarbon-solubility number of greater than 50and is poorly dispersible in brine.Available DataUntil recently, published data concerning the performanceof elastomeric seals in environments containing corrosioninhibitors have been virt
47、ually nonexistent. A number ofpapers3-11that summarize the results of laboratoryinhibitor exposure studies have been published. Data forthe various elastomer types have been arranged toprovide an overview of these results, as well as data fromunpublished sources. The data are summarized below.The da
48、ta in these tables do not differentiate betweeneffects caused by corrosion inhibitor compounds andcarrier systems or other components.The data in this report do not differentiate betweenreversible chemical effects (solubility) and irreversible,permanent reactions. The effects of corrosion inhibitorf
49、ormulations on elastomers may be due only to simpleswelling, sometimes caused by the diluent and not theactive components of the inhibitor. In other cases, theinhibitor may alter the polymer structure by inducingfurther crosslinking, a more severe problem in terms ofcompatibility. Therefore, the data have been scrutinizedwith the knowledge that similar values for propertychanges between different elastomers can be caused bycompletely different mechanisms.In selecting an elastomer compound for an applicationwith corrosion inhibitors, the acceptance of the compoun
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