NACE 1D177-2009 Monitoring Techniques and Corrosion Control for Drill Pipe Casing and Other Steel Components in Contact with Drilling Fluids《与钻井液接触的钻管 衬里和其他钢制部件的监测技术和腐蚀控制 项目编号24006.pdf

《NACE 1D177-2009 Monitoring Techniques and Corrosion Control for Drill Pipe Casing and Other Steel Components in Contact with Drilling Fluids《与钻井液接触的钻管 衬里和其他钢制部件的监测技术和腐蚀控制 项目编号24006.pdf》由会员分享，可在线阅读，更多相关《NACE 1D177-2009 Monitoring Techniques and Corrosion Control for Drill Pipe Casing and Other Steel Components in Contact with Drilling Fluids《与钻井液接触的钻管 衬里和其他钢制部件的监测技术和腐蚀控制 项目编号24006.pdf（7页珍藏版）》请在麦多课文档分享上搜索。

1、Item No. 24006 NACE International Publication 1D177 (2009 Edition) This Technical Committee Report has been prepared by NACE International Task Group 376,* “Monitoring Techniques for the Control of Corrosion of Drill Pipe, Casing, and Other Steel Components in Contact with Drilling Fluids” Monitorin

2、g Techniques and Corrosion Control for Drill Pipe, Casing, and Other Steel Components in Contact with Drilling Fluids January 2009, NACE International This NACE International (NACE) technical committee report represents a consensus of those individual members who have reviewed this document, its sco

3、pe, and provisions. Its acceptance does not in any respect preclude anyone from manufacturing, marketing, purchasing, or using products, processes, or procedures not included in this report. Nothing contained in this NACE report is to be construed as granting any right, by implication or otherwise,

4、to manufacture, sell, or use in connection with any method, apparatus, or product covered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This report should in no way be interpreted as a restriction on the use of better procedures or m

5、aterials not discussed herein. Neither is this report intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this report in specific instances. NACE assumes no responsibility for the interpretation or use of this report by other parties. User

6、s of this NACE report are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determining their applicability in relation to this report prior to its use. This NACE report may not necessarily address all potential health and safety problems or enviro

7、nmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this report. Users of this NACE report are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulato

8、ry authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this report. CAUTIONARY NOTICE: The user is cautioned to obtain the latest edition of this report. NACE reports are subject to periodic review, and may be revised or withdrawn

9、at any time without prior notice. NACE reports are automatically withdrawn if more than 10 years old. Purchasers of NACE reports may receive current information on all NACE publications by contacting the NACE FirstService Department, 1440 South Creek Drive, Houston, Texas 77084-4906 (telephone +1 28

10、1-228-6200). Foreword This NACE state-of-the-art report includes descriptions of monitoring techniques and corrosion control programs that have been used on drilling rigs in many different regions of the world. Field information from tests evaluating corrosion control of drill pipe, casing, and stee

11、l components in contact with various drilling fluids is incorporated and presented. Corrosion inhibition programs have provided increased life for equipment ranging from the fluid ends of mud pumps to the steel drill pipe and casing. Workover operation personnel have become more aware of the need to

12、 treat completion and workover fluids to mitigate corrosion. These treatments have resulted in fewer metal failures and have provided safer operations for drilling and completion of wells. This report does not cover air and gas drilling techniques or thermal recovery projects. _ * Chair Michael S. W

13、infield, Oxy Permian Ltd., Abernathy, TX. NACE International 2 The intended audience for this report is drilling, workover, and completion operations. This technical committee report was originally prepared in 1977 by Task Group T-1D-17, a component of Unit Committee T-1D, “Corrosion Monitoring and

14、Control of Corrosion Environments in Petroleum Production Operations.” It was reaffirmed in 1995 by T-1D and was revised in 2009 by Task Group (TG) 376, “Monitoring Techniques for the Control of Corrosion of Drill Pipe, Casing, and Other Steel Components in Contact with Drilling Fluids.” TG 376 is a

15、dministered by Specific Technology Group (STG) 31, “Oil and Gas ProductionCorrosion and Scale Inhibition” and is sponsored by STG 62, “Corrosion Monitoring and Measurement: Science and Engineering Applications.” This report is issued by NACE International under the auspices of STG 31. NACE technical

16、 committee reports are intended to convey technical information or state-of-the-art knowledge regarding corrosion. In many cases, they discuss specific applications of corrosion mitigation technology, whether considered successful or not. Statements used to convey this information are factual and ar

17、e provided to the reader as input and guidance for consideration when applying this technology in the future. However, these statements are not intended to be recommendations for general application of this technology, and must not be construed as such. Drilling Fluids A drilling fluid is a liquid t

18、hat is first circulated from a surface holding tank system into a high-pressure rig pump. From this pump suction, the fluid passes through the pump and surface piping (stand pipe) into the drill pipe. It then passes through the internal bore of the drill pipe and flows through the drillbit nozzles,

19、in which prevailing high temperatures and high pressures are encountered. The drilling fluid then returns to the surface from outside the drill pipe and inside the open hole or cased section. It reaches the flowline and, at this point, is usually passed over a shaker screen apparatus, thus removing

20、cuttings and returning to prevailing atmospheric pressure conditions. Before being recirculated downhole, the fluid is processed by means of special solids handling equipment or chemically treated. The density can be maintained or changed as desired. There are many types of drilling fluid or mud. Th

21、ey usually are named according to the continuous phase and the type of chemical added for certain desired performance characteristics, as shown in Table 1. Table 1 Corrosion Rates in Untreated Drilling Fluids Corrosion Rate Type of Drilling Fluid kg/m2y lb/ft2y Fresh Water 1473 315 Low Solids Nondis

22、persed 1473 315 Seawater 73 15 Potassium Chloride (KCl) Polymer 73 15 Saturated Salt (NaCl) 1024 25 Oil Muds 10 2 Drilling systems are large-volume, high-temperature and high-pressure, dynamic systems. The circulating system of the drilling rig can encounter many types of contaminants while drilling

23、 downhole without the contractor or operator being aware of their presence. A drilling fluid can be composed of fresh water, salt water, synthetic fluid, or oil as the continuous phase (e.g., an oil mud). The density ranges from approximately 1.0 kg/L (8.3 lb/gal) to greater than 2.4 kg/L (20 lb/gal

24、) in certain cases. The pH of water-based muds may range from a low of 6 to greater than 13. The chloride ion content may range from less than 100 mg/L to saturation at approximately 190,000 mg/L. Soluble calcium and magnesium ions NACE International 3 may be present, from a trace to approximately 5

25、0,000 mg/L in some special cases. Sulfates and bicarbonates are present in many systems. Sulfides may be present during a drilling operation. They can be derived from several sources, including make-up water or drilling into a formation containing sour gas. Carbon dioxide (CO2) may be encountered al

26、one or in combination with hydrogen sulfide (H2S). Oxygen is a contaminant of primary significance in corrosion. Oxygen contamination results from air that can be dissolved, entrained, or entrapped in a drilling fluid system in various ways. The rig mixing facilities (e.g., hopper, high-pressure mud

27、 gun, pit mixer, shale shaker) and leaks in the pump suction or connections all may contribute to saturating the fluid with oxygen before circulating the mud downhole. Monitoring Techniques and Chemical Treating Rates One of the most important aspects of a corrosion inhibition program involves the c

28、orrosion monitoring before, during, and after chemical treatment. Typical techniques for monitoring corrosion during drilling operations include the following: Galvanic ProbeBrass/Steel It was common practice to install a galvanic probe on the high-pressure side of the rig pump in the stand pipe. Th

29、e probe output in microamperes (A) was usually measured by a meter and recorded on a 30-day strip-chart recorder. A reading of less than 20 A on a 4,600-ohm modified meter has generally indicated some control of corrosion. See NACE Publication 1C187.1 Drill Pipe Circular Ring Coupons Common practice

30、 involves placing a circular ring coupon in the tool joint box of the first joint above the drill collars. The ring coupons are usually exposed for more than 40 hours. Normal exposure time is approximately 100 hours. The total number of hours from placement to removal is generally considered when th

31、e coupons are evaluated. See the discussion below in the paragraph titled “Corrosion Rates of Various Systems.” The procedure for use of drill pipe circular ring coupons is set forth in API(1)RP 13B-1.2API RP 13B-1 also includes additional H2S and drilling fluid test procedures for sulfite content.

32、Sulfite content (residual) in water-based drilling fluids is usually measured when sulfite is intentionally added as an oxygen scavenger. Many operators desire a minimum of 100 mg/L sulfite content, and 600 mg/L sulfite can be maintained in seawater and in the 3% KCl drilling fluids. Phosphate Conte

33、nt Analysis When organic phosphate corrosion inhibitors or scale inhibitors are used, the phosphate content (residual) usually can be measured. An excess of phosphate is normally maintained to retard scaling and lower corrosion rate as noted from coupons. Bacteria Certain fluids (e.g., long-term pac

34、ker fluids) are susceptible to damage. Current practices for treatment of bacteria are available from drilling fluid service companies. (1)American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005-4070. NACE International 4 pH Analysis The pH is usually measured with pH paper, or more

35、accurately with a pH meter. For steel drill pipe, acid (low) pH usually increases corrosion while alkaline (high) pH usually reduces corrosion to a degree. The control of pH alone has not always solved corrosion problems. Controlling pH to greater than 10.5 to 11 has been helpful when compatible wit

36、h the drilling fluid. Failure Records Several organizations maintain failure records along with serially numbered tubulars. Each joint of drill pipe with identification numbers may aid in following troublesome drilling situations. This method has generally led to successful drill pipe life determina

37、tion. The following monitoring techniques have been used on specially selected test wells in the past. 1. Linear polarization resistance (LPR) corrosion rate probes. These are used on the pressure side of the rig mud pumps, usually located in the stand pipe. They do not measure bottom hole condition

38、s. 2. Membrane-type oxygen sensors located in mud pit and flowline measurement stations. If possible, exit samples are usually taken before the mud reaches the flowline and becomes aerated for the most accurate annulus readings from bottom hole conditions. Corrosion Rates of Various Systems The corr

39、osion rates that have been generally noted for steel exposed to various untreated drilling fluids are given in Table 1. Any type of drilling fluid can have a higher or lower corrosion rate under various circumstances. A steel corrosion rate of less than 10 kg/m2y (2 lb/ft2y) (approximately 1.3 mm/y

40、50 mpy) with no pitting is considered by many operators to be acceptable, but some require control to less than 2.4 kg/m2y (0.50 lb/ft2y) (approximately 0.3 mm/y 12 mpy) for their operations. These low corrosion rates have usually been attained by a properly designed and maintained chemical treating

41、 program. Conversion factors for steel corrosion rate are given in Table 2. Table 2 Conversion Factors for Steel Corrosion Rate(A)mpy = 24.6 x lb/ft2y mpy = 5.03 x kg/m2y lb/ft2y = 0.0406 x mpy lb/ft2y = 0.204 x kg/m2y kg/m2y = 0.199 x mpy kg/m2y = 4.90 x lb/ft2y (A)Conversion factors based on speci

42、fic gravity of steel = 7.86. Common Contaminants and Chemical Treating Methods When dissolved in drilling fluids, oxygen, CO2, and H2S are primary contaminants that can create corrosion problems. The presence of oxygen is the major cause of corrosion in drilling fluids. Measures taken to mitigate dr

43、illing fluid corrosion by the various contaminants are discussed individually below. Oxygen It is common practice to treat continuously with an oxygen scavenger or an organic phosphate corrosion inhibitor or both. The oxygen scavenger generally is pumped into the chemical injection port located on t

44、he suction side of the mud pump. Both liquid sulfite (i.e., an aqueous sulfite solution) and powdered chemicals are available for removing NACE International 5 oxygen; however, the powdered chemicals are usually dissolved in water before being added to the mud. The treating chemical generally is pum

45、ped directly from the drum or from a closed injection tank with a proportioning chemical pump. The organic phosphate corrosion inhibitors generally do not need the chemical pump for addition. It is done by manual addition. Organic phosphate corrosion inhibitors are added to the mud system manually t

46、hrough the mud mixing hopper or ranger tank, which feeds directly to the suction of the mud pump that discharges down hole and readily mixes with the mud system. Carbon Dioxide It is common practice to neutralize the acidic effect of CO2with caustic soda (NaOH) or lime (CaOH2). Many contractors batc

47、h treat the drill pipe with a film-persistent type of corrosion inhibitor. Many contractors have also added an organic scale inhibitor continuously to minimize carbonate scale buildup. This is in addition to sulfite treatments and corrosion inhibitors. Hydrogen Sulfide Chemical treatment generally i

48、s used with proper mud-handling techniques. The pH is usually adjusted to greater than 11 with NaOH as a pretreatment. It is common practice to batch treat with a film-persistent corrosion inhibitor. Many operators and contractors precipitate residual sulfides with compatible heavy metal compounds s

49、uch as zinc oxide (ZnO) or iron-based scavengers. Oil muds have been used successfully in drilling under severe conditions of extreme temperature and pressure. These fluids are composed of an oil external phase or oil continuous phase with some water emulsified as the internal phase. Oil muds are normally electrically nonconductive and associated corrosion is usually not a problem if the properties of the oil muds are properly maintained. They can stand much higher temperatures and pressures than water-based fluids. When H2S is