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  • 1. NACE Standard MR0176-2006 Item No. 21303 Standard Material Requirements Metallic Materials for Sucker-Rod Pumps for Corrosive Oilfield EnvironmentsThis NACE International (NACE) standard represents a consensus of those individual members whohave reviewed this document, its scope, and provisions. Its acceptance does not in any respectpreclude anyone, whether he or she has adopted the standard or not, from manufacturing, marketing,purchasing, or using products, processes, or procedures not in conformance with this standard.Nothing contained in this NACE standard is to be construed as granting any right, by implication orotherwise, to manufacture, sell, or use in connection with any method, apparatus, or product coveredby Letters Patent, or as indemnifying or protecting anyone against liability for infringement of LettersPatent. This standard represents minimum requirements and should in no way be interpreted as arestriction on the use of better procedures or materials. Neither is this standard intended to apply inall cases relating to the subject. Unpredictable circumstances may negate the usefulness of thisstandard in specific instances. NACE assumes no responsibility for the interpretation or use of thisstandard by other parties and accepts responsibility for only those official NACE interpretations issuedby NACE in accordance with its governing procedures and policies which preclude the issuance ofinterpretations by individual volunteersUsers of this NACE standard are responsible for reviewing appropriate health, safety, environmental,and regulatory documents and for determining their applicability in relation to this standard prior to itsuse. This NACE standard may not necessarily address all potential health and safety problems orenvironmental hazards associated with the use of materials, equipment, and/or operations detailed orreferred to within this standard. Users of this NACE standard are also responsible for establishingappropriate health, safety, and environmental protection practices, in consultation with appropriateregulatory authorities if necessary, to achieve compliance with any existing applicable regulatoryrequirements prior to the use of this standard.CAUTIONARY NOTICE: NACE standards are subject to periodic review, and may be revised orwithdrawn at any time without prior notice. NACE requires that action be taken to reaffirm, revise, orwithdraw this standard no later than five years from the date of initial publication. The user iscautioned to obtain the latest edition. Purchasers of NACE standards may receive current informationon all standards and other NACE publications by contacting the NACE International FirstServiceDepartment, 1440 South Creek Drive, Houston, Texas 77048-4906 (telephone +1 281/228-6200). Reaffirmed 2006-03-11 Reaffirmed 2000-03-28 Revised October 1994 Approved January 1976 NACE International 1440 South Creek Drive Houston, TX 77084-4906 +1 281/228-6200 ISBN 1-57590-099-8 © 2006, NACE International
  • 2. MR0176-2006 ________________________________________________________________________ Foreword This standard specifies metallic material requirements for the construction of sucker-rod pumps for (1) 1 service in corrosive oilfield environments. American Petroleum Institute (API) Spec 11AX provides dimension requirements that ensure the interchangeability of component parts. However, that document does not provide material specifications or guidelines for the proper application of 2 various API pumps. API RP 11AR does list the general advantages and disadvantages of the 3 various pump types and lists the acceptable materials for barrels and plungers; and API RP 11BR supplements API Spec 11AX by providing corrosion control methods using chemical treatment. This NACE standard is intended for end users (e.g., production engineers) and equipment manufacturers to supplement the use of the aforementioned API publications. This standard was originally published in 1976 and was revised in 1994 by NACE Task Group T- 1F-15 on Sucker-Rod Pumps for Corrosive Environments, a component of Unit Committee T-1F on Metallurgy of Oilfield Equipment. It was reviewed by Task Group T-1F-28 and reaffirmed by T-1F in 2000, and was reaffirmed in 2006 by Specific Technology Group (STG) 32 on Oil and Gas Production—Metallurgy. This standard is issued by NACE International under the auspices of STG 32. In NACE standards, the terms shall, must, should, and may are used in accordance with the definitions of these terms in the NACE Publications Style Manual, 4th ed., Paragraph 7.4.1.9. Shall and must are used to state mandatory requirements. The term should is used to state something considered good and is recommended but is not mandatory. The term may is used to state something considered optional. _________________ (1) American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005. ________________________________________________________________________NACE International i
  • 3. MR0176-2006 ________________________________________________________________________ NACE International Standard Material Requirements Metallic Materials for Sucker-Rod Pumps for Corrosive Oilfield Environments Contents 1. General ......................................................................................................................... 1 2. Description of Tables .................................................................................................... 1 3. Barrel Selection............................................................................................................. 2 4. Pump Selection ............................................................................................................. 2 5. Maintenance Record System........................................................................................ 3 References........................................................................................................................ 12 Appendix A, Economic Benefits........................................................................................ 12 Appendix B, Case-Hardening Processes for Steel Pump Barrels for a Corrosive Environment ................................................................................................................ 13 Appendix C, Selection of Optimum-Type Pump ............................................................... 14 TABLES: Table 1: Classification of Metal-Loss Corrosion for Sucker-Rod Pumps........................... 3 Table 2: Recommended Materials for Mild Metal-Loss Corrosion Environments ............. 4 Table 3: Recommended Materials for Moderate Metal-Loss Corrosion Environments..... 5 Table 4: Recommended Materials for Severe Metal-Loss Corrosion Environments ........ 6 Table 5: Typical Mechanical Properties of Pump Barrel Materials.................................... 7 Table 6: Typical Properties of Plunger Materials............................................................... 9 Table 6.1: Typical Chemical Composition of Spray Metal ........................................... 10 Table 7: Typical Materials for Cages ............................................................................... 11 Table 8: Typical Materials for Pull Tube, Valve Rod, and Fittings................................... 11 Table 9: Typical Composition and Hardness of Cast Cobalt Alloys Used for Valve Parts ............................................................................................................... 11 Table 10: Typical Composition and Hardness of Sintered Carbides Used for Valve Parts ............................................................................................................... 12 ________________________________________________________________________ii NACE International
  • 4. MR0176-2006 ________________________________________________________________________ Section 1: General1.1 An adequate chemical treatment program utilizing the specified environments. These materialselection of proper corrosion inhibitors and application recommendations are based on field experience.techniques is necessary for optimum performance ofsucker-rod pumping equipment in a corrosive environment. 1.3 This standard is not intended to preclude theHowever, control of direct attack on pump materials may be development and testing of new materials that mightaccomplished by materials selection alone or by materials improve sucker-rod pump performance. It is theselection in combination with chemical treatment. responsibility of the user to fully evaluate the performance of any new material prior to its use.1.2 The recommended materials in this standard arepresented in tables and listed in order of preferred usage in 1.4 The designations and mechanical properties of thesix different environments with varying degrees of materials covered by this standard are listed in selectedcorrosiveness and with and without possible abrasion. The tables.listed materials have performed satisfactorily when used in ________________________________________________________________________ Section 2: Description of Tables2.1 The specific quantities of water, hydrogen sulfide (H2S), present in the system at partial pressures equal toand carbon dioxide (CO2) that are used to classify the or greater than 0.35 kPa absolute (0.050 psia).corrosiveness of a fluid as mild, moderate, or severe are When operating in sour service, the material fordetailed in Table 1. subsurface pump fittings (connectors, bushings, etc.) should conform to the requirements of NACE 4 2.1.1 Explanations of the mild, moderate, and severe Standard MR0175/ISO 15156. metal-loss corrosion classifications given in Table 1 are intended to be a guide for the user. Currently, there is 2.1.2.4 Water Content—Generally, if the water no clear consensus on which combination of produced content is greater than 20%, the fluid exists as a fluids constitutes mild, moderate, or severe corrosive water phase with oil droplets. If the water content environments for subsurface pumps. There can be is less than 20%, an oil phase with water droplets amounts of H2S, CO2, and water that do not clearly fall can exist. Inhibitors should be used if the water into one of the three combinations. The user’s content is greater than 20%. operating experiences coupled with analysis of failures should be used to develop the appropriate 2.1.2.5 Temperature—The higher the classification. temperature, the greater the rate of corrosion. Temperature below the crystallization point of 2.1.2 The three corrosion classifications are identified paraffin results in deposition of a film of paraffin by amounts of water, H2S, and CO2 in the produced that may act as a corrosion barrier. fluids. There are other constituents in the fluid that can influence corrosion. General comments on these 2.1.2.6 pH—The pH at bottomhole conditions is constituents follow: frequently lower (more acidic) than that measured at the surface. After acidizing, the pH should be 2.1.2.1 Oxygen—Oxygen can be very destructive monitored to ensure that the fluid does not attack to the system. If oxygen is discovered, every chrome plate if chrome plate is used in the pump. attempt should be made to free the system of oxygen, or at least bring it to below 50 ppb 2.1.2.7 Pressure—Pressure does not have a dissolved oxygen. Severe corrosion can be direct influence on the general corrosion rate. expected above 50 ppb dissolved oxygen. However, the system pressure influences the partial pressures of H2S and CO2, which have an 2.1.2.2 Chlorides—High chlorides can lead to effect on the corrosive nature of the fluids. pitting corrosion. High-chloride service conditions should be assumed to exist when the total 2.1.2.8 Velocity—Generally, the higher the dissolved solids exceed 10,000 mg/L and/or total velocity of produced fluids through the pump, the chlorides exceed 6,000 mg/L. greater the metal loss because of erosion- corrosion. 2.1.2.3 H2S (Sour Service)—Sour service conditions should be assumed to exist when H2S isNACE International 1
  • 5. MR0176-2006 2.1.2.9 Abrasion—Abrasion results not only from environments are listed in Tables 2, 3, and 4, respectively. produced fluids but also from corrosion The tables are each divided into two degrees of abrasion byproducts, e.g., iron sulfide. If the fluids contain (i.e., “no abrasion” and “abrasion”) for each of the three greater than 100 ppm solids, conditions are corrosive environments. considered abrasive. 2.4 A determination of the correct environmental2.2 General definitions of mild, moderate, or severe classification for the selection of the materials to be used incorrosive environments follow: a particular well should be made by an experienced corrosion or materials specialist. 2.2.1 Mild metal-loss corrosive environment: Corrosion attack on downhole equipment, rods, and 2.5 The recommended pump barrels and compatible tubing is evident but equipment may last several years plungers are the first items shown under each environment. (more than three years) either with or without inhibitor A plunger can be used with more than one barrel, but this treatment before corrosion-related failures occur. could alter the preferred order of usage. 2.2.2 Moderate metal-loss corrosive environment: 2.6 The tables showing barrel/plunger combinations also Corrosion rates and time-to-failure are between mild show the recommended material selections for valves, and severe. cages, pull tubes, valve rods, and fittings. 2.2.3 Severe metal-loss corrosive environment: 2.7 Materials for all parts are listed in preferred order based Corrosion rates are high and corrosion failures occur in on optimum operating costs as determined by field less than one year unless effective inhibitor treatment is experience rather than expected pump life or initial cost. In applied. some instances, performance of these recommended materials can be similar. The total costs of pump repairs2.3 Recommended materials for sucker-rod pumps to be and proper material selection are discussed in Appendix A:used in mild, moderate, and severe metal-loss corrosive Economic Benefits. ________________________________________________________________________ Section 3: Barrel Selection3.1 Mechanical properties of the various pump barrel base 3.3 Generally, the corrosion performance of the fourmaterials and available surface-conditioning requirements different case-hardened barrels is comparable. Case-of barrels are given in Table 5. hardening processes recommended for steel pump barrels to be used in H2S environments are discussed in Appendix3.2 There is no significant difference in corrosion B.performance between the D1 and D4 nonhardened steelbarrels. ________________________________________________________________________ Section 4: Pump Selection4.1 Interrelated factors, other than the corrosive and 4.3 Standards concerning the most practical pumpabrasive natures of the produced fluids, that shall be assembly for various operating conditions are unavailable;considered when selecting materials for a sucker-rod pump however, guidelines for selecting the most suitable pump forinclude: a particular application are given in Appendix C. 4.1.1 Type of pump; 4.4 Materials should be selected from Tables 2 through 10 to meet the strength and hardness requirements dictated by 4.1.2 Barrel length and diameter; and the type of pump and anticipated operating conditions. 4.1.3 Seating depth and required material strength. 4.5 Information shown in Tables 5 through 8 lists many of the materials by specific alloy number.4.2 For a given pump size and seating depth, the strengthrequirement for a barrel in a top holddown pump is greater 4.5.1 When selecting pumps, the purchaser should bethan that for a barrel of a bottom holddown pump. This is aware that common names, e.g., brass, are often usedthe result of a top holddown pump having a greater to describe alloys of significantly different compositionspressure differential across the barrel. and properties.2 NACE International
  • 6. MR0176-2006 4.5.2 Specific alloys should be designated as shown in materials with different composition, which has resulted the tables to prevent substitution of trade name in repetitive failures in the past. ________________________________________________________________________ Section 5: Maintenance Record System5.1 A maintenance record system should be initiated to 5.1.6 Cost, description, frequency, and type of repairs,assist in reducing expenses related to sucker-rod pump including the type of material used in the manufacturefailures. API 11BR details a sucker-rod pump repair/new of the replaced part or parts; andpump log that can initiate a database for pump performanceand aid in establishing a maintenance record system that 5.1.7 A method of determining the point at whichshould include the following factors: replacement of the pump becomes more economically desirable than continued repair. 5.1.1 A cross-reference file that lists the well number and pump number; 5.2 Effectiveness of the maintenance record system is dependent on cooperation from the pump repair facility. A 5.1.2 All of the pertinent information on the pump, study of repair records should identify the principal causes including pump type and description and the complete of repeated failures and also indicate the corrective metallurgy of the individual parts; measures required to solve these problems. 5.1.3 Pumping conditions; 5.3 Recordkeeping should be used for tracking pump part materials and comparing the cost of repetitive failures and 5.1.4 Length of run; the cost of upgrading with more expensive materials and parts. However, because many factors other than corrosion 5.1.5 Volume of fluid lifted during the run; and abrasion can cause pump failures, upgrading the metallurgy of the entire pump assembly is seldom required. TABLE 1: CLASSIFICATION OF METAL-LOSS (A) CORROSION FOR SUCKER-ROD PUMPS (B) Mild Metal-Loss Corrosion Water cuts are less than 25% H2S is less than 10 ppm CO2 is less than 250 ppm. (B) Moderate Metal-Loss Corrosion Water cuts are between 25% and 75% and/or H2S is between 10 and 100 ppm (C) and/or CO2 is between 250 and 1,500 ppm. (B) Severe Metal-Loss Corrosion Water cuts are more than 75% and/or H2S is greater than 100 ppm (C) and/or CO2 is greater than 1,500 ppm.(A) The classification of metal-loss corrosion is intended only as a guide for the user of subsurface pumps (see Paragraph 2.1.1).(B) For all three classifications, the higher number of the three constituents should be the guide.(C) High concentrations of CO2 at low pressures are not corrosive, i.e., in shallow-depth wells less than 300 m (1,000 ft).NACE International 3
  • 7. MR0176-2006 TABLE 2 : RECOMMENDED MATERIALS FOR MILD METAL-LOSS CORROSION ENVIRONMENTS NO ABRASION ABRASION BARREL PLUNGER BARREL PLUNGER1. Nonhardened steel 1. Chrome plate on steel 1. Case hardened steel 1. Chrome plate on steel 2. Spray metal on steel 2. Chrome plate on steel (C) VALVES VALVES (A) (B)1. Ball: UNS S44002 1. Cobalt alloy 1. Spray metal on steelSeat: UNS S440042. Cobalt alloy 2. Cobalt alloy ball, 2. Cobalt alloy ball, sintered carbide seat sintered carbide seat CAGES CAGES 1. Steel 1. Steel PULL TUBE, VALVE ROD, AND FITTINGS PULL TUBE, VALVE ROD, AND FITTINGS 1. Steel 1. Steel(A) Metals and Alloys in the Unified Numbering System (latest revision), a joint publication of ASTM International (ASTM) and the AmericanSociety of Automotive Engineers Inc. (SAE), 400 Commonwealth Dr., Warrendale, PA 15096.(B) Pits in the presence of chlorides.(C) The type of valve and cage is also dependent on how hard the well is being pumped, the amount of free gas, and the pressure differentialacross the valve.4 NACE International
  • 8. MR0176-2006 TABLE 3: RECOMMENDED MATERIALS FOR MODERATE METAL-LOSS CORROSION ENVIRONMENTS NO ABRASION ABRASION BARREL PLUNGER BARREL PLUNGER1. Brass, nonhardened 1. Spray metal with nickel- 1. Chrome plate on brass 1. Spray metal with nickel- copper alloy pin ends copper alloy pin ends 2. Spray metal with 2. Spray metal with electroless nickel pin ends electroless nickel pin ends 3. Heavy chrome plate on 2. Heavy chrome plate on Same plungers as above steel steel2. UNS N04400 Same plungers as above 3. Chrome plate on steel Same plungers as above (A) (A) VALVES VALVES1. Cobalt alloy 1. Sintered carbides 2. Cobalt alloy (A) (A) CAGES CAGES1. Nickel-copper alloy 1. Nickel-copper alloy, insert or lined2. Brass 2. Stainless steel, insert or lined3. Stainless steel 3. Brass, insert PULL TUBE, VALVE ROD, PULL TUBE, VALVE ROD, (B) (B) AND FITTINGS AND FITTINGS1. Steel 1. Steel2. Stainless steel 2. Stainless steel3. Brass 3. Brass(A) The type of valve and cage is also dependent on how hard the well is being pumped, the amount of free gas, and the pressure differentialacross the valve.(B) See Table 8 for materials within each component.NACE International 5
  • 9. MR0176-2006 TABLE 4: RECOMMENDED MATERIALS FOR SEVERE METAL-LOSS CORROSION ENVIRONMENTS NO ABRASION ABRASION BARREL PLUNGER BARREL PLUNGER1. Nickel-copper alloy 1. Spray metal with nickel- 1. Chrome plate on nickel- 1. Spray metal with nickel- copper alloy pin ends copper alloy copper alloy pin ends 2. Spray metal with 2. Spray metal with electroless nickel pin ends electroless nickel pin ends2. Brass, nonhardened Same plungers as above 2. Chrome plated on brass Same plungers as above3. Electroless nickel coating Same plungers as above 3. Electroless nickel coating Same plungers as aboveon steel on brass (A) (A) VALVES VALVES1. Cobalt alloy 1. Sintered carbides (A) (A) CAGES CAGES1. Nickel-copper alloy 1. Nickel-copper alloy, insert or lined2. Brass 2. Stainless steel, insert or lined3. Stainless steel 3. Brass, insert PULL TUBE, VALVE PULL TUBE, VALVE (A) (B) ROD, AND FITTINGS ROD, AND FITTINGS1. Nickel-copper alloy 1. Nickel-copper alloy2. Stainless steel 2. Stainless steel3. Brass 3. Brass(A) The type of valve and cage is also dependent on how hard the well is being pumped, the amount of free gas, and the pressure differentialacross the valve.(B) See Table 8 for materials within each component.6 NACE International
  • 10. MR0176-2006 TABLE 5: TYPICAL MECHANICAL PROPERTIES OF PUMP BARREL MATERIALS (A) Identification Product Description Surface Condition Base Core Base Material Typical Symbol Hardness Yield Strength, MPa (1,000 psi)PLATINGA1 Chrome plate on 0.08 mm (0.003 in.) Base material Low-carbon 410 (60) steel min. plate thickness. hardness 95 steel. Ex: Chrome plate hardness HRB to 23 HRC UNS 67 to 71 HRC G10200A2 Chrome plate on 0.08 mm (0.003 in.) Base material Inhibited 380 (55) brass min. plate thickness. hardness 83 admiralty Chrome plate hardness HRB to 23 HRC brass. Ex: UNS 67 to 71 HRC C44300A3 Chrome plate on 0.08 mm (0.003 in.) Base material UNS C23000 240 (35) (Red brass) red brass min. plate thickness. hardness 83 Chrome plate hardness HRB to 23 HRC 67 to 71 HRCA4 Chrome plate on 0.08 mm (0.003 in.) Base material UNS S50100 480 (70) (5% 5% chromium min. plate thickness. hardness 94 chromium steel Chrome plate hardness HRB to 23 HRC steel) 67 to 71 HRCA5 Chrome plate on 0.08 mm (0.003 in.) Base material UNS N04400 380 (55) (Nickel- nickel-copper min. plate thickness. hardness 85 copper) alloy Chrome plate hardness HRB to 20 HRC 67 to 71 HRCA6 Chrome plate on 0.08 mm (0.003 in.) Base material Low-alloy 550 (80) low-alloy steel min. plate thickness. hardness 82 steel. Ex: Chrome plate hardness HRB to 23 HRC UNS 67 to 71 HRC G41300A7 Heavy chrome 0.15 mm (0.0060 in.) Base material Low-carbon 410 (60) on steel min. plate thickness. hardness 95 steel. Ex: Chrome plate hardness HRB to 23 HRC UNS 67 to 71 HRC G10200A8 Electroless nickel 0.033 mm (0.0013 in.) Base material Low-carbon 410 (60) coating on steel min. plate thickness. hardness 95 steel. Ex: Plate hardness 45 to HRB to 23 HRC UNS 70 HRC G10200A9 Electroless nickel 0.033 mm (0.0013 in.) Base material Low-alloy 550 (80) coating on low- min. plate thickness. hardness 83 steel. Ex: alloy steel Plate hardness 45 to HRB to 23 HRC UNS 70 HRC G41300 NACE International 7
  • 11. MR0176-2006 (A) Identification Product Description Surface Condition Base Core Base Material Typical Symbol Hardness Yield Strength, MPa (1,000 psi)A10 Electroless nickel 0.033 mm (0.0013 in.) min. Base material Inhibited 280 (40) coating on brass plate thickness. Plate hardness 83 HRB to admiralty brass hardness 45 to 70 HRC 23 HRC Ex: UNS C44300CASE HARDENINGB1 Carbonitrided 0.25 mm (0.010 in.) min. 95 HRB to 23 HRC Low-carbon 450 (65) carburized case with 45 steel. Ex.: UNS HRC min. hardness 0.25 G10200 mm (0.010 in.) from the surface. Surface hardness 58 HRC min., 63 HRC max.B2 Carburized 0.25 mm (0.010 in.) min. 95 HRB to 23 HRC Low-carbon 450 (65) carburized case with 45 steel. Ex.: UNS HRC min. hardness 0.25 G10200 mm (0.010 in.) from the surface. Surface hardness 58 HRC min., 63 HRC max. (C)B3 Carbonitrided 5% 0.25 mm (0.010 in.) min. 98 HRB to 27 HRC UNS S50100 480 (70) chromium steel carburized case with 45 (5% chromium HRC min. hardness 0.25 steel) mm (0.010 in.) from the surface. Surface hardness 58 HRC min., 63 HRC max.B4 Nitrided 4130 0.13 mm (0.0050 in.) min. 82 HRB to 23 HRC UNS G41300 550 (80) nitrided case with 45 HRC min. hardness 0.13 mm (0.0050 in.). Surface hardness 58 HRC min., 63 HRC max.NONHARDENEDD1 Nonhardened steel Surface is treated with a Base material Low-carbon 410 (60) nonmetallic-type phosphate hardness 95 HRB to steel. Ex.: coating or other equally 23 HRC UNS G10200 effective antigalling treatment.D2 Nonhardened brass Surface is oiled. Base material Inhibited 280 (40) hardness 83 HRB to admiralty 23 HRC brass. Ex: UNS C44300D3 Nickel-copper alloy Surface is oiled. Base material Nickel-copper 380 (55) 8 NACE International
  • 12. MR0176-2006 (A) Identification Product Description Surface Condition Base Core Base Material Typical Symbol Hardness Yield Strength, MPa (1,000 psi) hardness 85 HRB to alloy. Ex: UNS 20 HRC N04400D4 Nonhardened steel Surface is treated with a Base material Low-alloy steel. 550 (80) nonmetallic-type phosphate hardness 82 HRB to Ex.: UNS coating or other equally 23 HRC G41300 effective antigalling treatment (A) Hardness readings are converted from Rockwell superficial hardness readings. (B) Regarding the thread base material condition, the hardness is the same as the core hardness. (C) 98 HRB to 29 HRC thread base material condition. TABLE 6: TYPICAL MECHANICAL PROPERTIES OF PLUNGER MATERIALSIdentification Product Surface Condition Thread Base Base Material Typical YieldSymbol Description Material Strength, MPa (C) Hardness (1,000 psi)A1 Chrome plate 0.15 mm (0.0060 in.) min. Hardness 95 Carbon steel. Ex. 410 (60) plate thickness. Chrome HRB to 23 HRC UNS G10200 plate hardness 67 to 71 (A) HRCA2 Chrome plate 0.30 mm (0.012 in.) min. Hardness 95 HRB Carbon steel. Ex.: 410 (60) plate thickness. Chrome to 23 HRC UNS plate hardness 67 to 71 G10250/G10350/G1 (A) HRC 0450SPRAY METAL (B)B1 Spray metal 0.25 mm (0.010 in.) min. Hardness 85 HRB Carbon steel. Ex.: 410 (60) coating thickness. to 23 HRC UNS G10260 Hardness 78.5 HRA (55 HRC) min. (B)B2 Spray metal 0.25 mm (0.010 in.) min. Hardness 93 HRB Carbon steel. Ex.: 410 (60) coating thickness. to 23 HRC UNS G10260 Hardness 78.5 HRA (55 HRC min. (B)B3 Spray metal with 0.25 mm (0.010 in.) min. Nickel-copper alloy Carbon steel. Ex.: 410 (60) nickel-copper alloy coating thickness. pin ends. Hardness UNS pin ends Hardness 78.5 HRA (55 84 HRB to 23 HRC G10260/G10450 HRC) min. (B)B4 Spray metal with 0.25 mm (0.010 in.) min. Electroless nickel Carbon steel. Ex.: 410 (60) electroless nickel coating thickness. coating 0.033 mm UNS G10260 NACE International 9
  • 13. MR0176-2006Identification Product Surface Condition Thread Base Base Material Typical YieldSymbol Description Material Strength, MPa (C) Hardness (1,000 psi) pin ends Hardness 78.5 HRA (55 (0.0013 in.) on the HRC) min. pin ends. Base material hardness 85 HRB to 23 HRC (B)B5 Spray metal with 0.25 mm (0.010 in.) min. Electroless nickel Carbon steel. Ex.: 480 (70) electroless nickel coating thickness. coating 0.033 mm UNS G10450 pin ends Hardness 78.5 HRA (55 (0.0013 in.) on the HRC) min. pin ends. Base material hardness 85 HRB to 23 HRC (B)B6 Spray metal 0.25 mm (0.010 in.) min. Hardness 82 to 23 Low-alloy steel. Ex.: 550 (80) coating thickness. HRC UNS G41300 Hardness 78.5 HRA (55 HRC) min. (B)B7 Spray metal 0.25 mm (0.010 in.) min. Electroless nickel Low-alloy steel. Ex.: 550 (80) coating thickness. coating 0.033 mm UNS G41300 Hardness 78.5 HRA (55 (0.0013 in.) on the HRC) min. pin ends. Base material hardness 82 HRB to 23 HRCNONHARDENEDC1 Nonhardened Surface is not hardened Hardness 95 HRB Carbon steel. 23 410 (60) or plated. to 23 HRC HRC. Ex.: UNS G10260/G10350/ G10450 (A) Converted from Knoop or Vickers microhardness. (B) See Table 6.1 for typical chemical composition of spray metal. (C) Critical strength component or plunger. TABLE 6.1: TYPICAL CHEMICAL COMPOSITION OF SPRAY METAL wt% wt% Min. Max. Carbon (C) 0.50 1.00 Silicon (Si) 3.50 5.50 Phosphorus (P) ------- 0.02 Sulfur (S) ------- 0.02 Chromium (Cr) 12.00 18.00 Boron (B) 2.50 4.50 Iron (Fe) 3.00 5.50 Cobalt (Co) ------- 0.10 Titanium (Ti) ------- 0.05 Aluminum (Al) ------- 0.05 Zirconium (Zr) ------- 0.05 Nickel (Ni) Remainder 10 NACE International
  • 14. MR0176-2006 TABLE 7: TYPICAL MATERIALS FOR CAGES Steel Carbon Steels UNS G10200 through G10450 Low-Alloy Steels UNS G41300 through G41450 UNS G86200 through G86450 Nickel-Copper Alloy UNS N04400 Brass UNS C46400 Stainless Steel UNS S30400, UNS S31600 TABLE 8: TYPICAL MATERIALS FOR PULL TUBE, VALVE ROD, AND FITTINGS Pull Tube Steels—UNS G10200 through G10450 Stainless Steels—UNS S30400, UNS S31600 Brass—UNS C46400 Nickel-Copper Alloy—UNS N04400 Valve Rod Steels—G10200 through G10450 Stainless Steels—UNS S30400, UNS S31600 Nickel-Copper Alloy—UNS N04400 Fittings Steel Carbon Steels—UNS G10200 through G10450 Low-Alloy Steels—UNS G41300 through G41450 Stainless Steel—UNS S30400, UNS S31600 Nickel-Copper Alloy—UNS N04400 TABLE 9: TYPICAL COMPOSITION AND HARDNESS OF CAST COBALT ALLOYS USED FOR VALVE PARTS wt% wt% Ball Seat Co 45.2 57.9 Cr 32.0 24.5 Tungsten (W) 18.0 12.0 C 2.3 2.1 Other 2.5 3.5 HRC 58-63 51-55NACE International 11
  • 15. MR0176-2006 TABLE 10: TYPICAL COMPOSITION AND HARDNESS OF SINTERED CARBIDES USED FOR VALVE PARTS wt% wt% Balls and Seats Balls (A) Tungsten Carbide 87 Titanium Carbide 60 Co 13 Nickel/Cobalt 14 Trace Elements 1 HRA 88 HRA 90(A) The lighter-weight titanium carbide ball reduces the impact of the ball in the valve. Titanium carbide is used in heavy pumping wells orgassy wells to reduce the effects of impact. ________________________________________________________________________ References1. API Spec 11AX (latest revision), “Specification for 7. “Heat Treatment of Steels,” Republic Alloy SteelsSubsurface Sucker Rod Pumps and Fittings” (Washington, Handbook, Republic Steel Corporation, Cleveland, OH,DC: API). 1961.2. API RP 11AR (latest revision), “Recommended 8. E.A. Avallone, T. Baumeister, Mark’s StandardPractice for Care and Use of Subsurface Pumps” Handbook for Mechanical Engineers, 10th ed. (New York,(Washington, DC: API). NY: McGraw-Hill).3. API RP 11BR (latest revision), “Recommended 9. J. Zaba, Modern Oil-Well Pumping (Tulsa, OK:Practice for Care and Handling of Sucker Rods” Petroleum Publishing Co., 1962).(Washington, DC: API). 10. T.C. Frick, ed., Petroleum Production Handbook (New4. NACE Standard MR0175/ISO 15156 (latest revision), York, NY: McGraw-Hill, 1962).“Petroleum and natural gas industries—Materials for use inH2S-containing environments in oil and gas production” 11. B.R. Bruton, “Selection of Metallic Materials forHouston, TX: NACE International). Subsurface Pumps for Various Corrosive Environments,” presented at University of Oklahoma Short Course,5. “A Data-Gathering System to Optimize Production September 14-16, 1970.Operations: A 14-Year Overview,” Journal of PetroleumTechnology 39, 4 (1987): pp. 457-462. 12. “Subsurface Pumps—Selection and Application,” United States Steel Corporation (Oilwell Supply Division),6. D.S. Clark, Physical Metallurgy for Engineers, 2nd ed. Pittsburgh, PA, 1967.(Princeton, NJ: Van Nostrand, 1966). ________________________________________________________________________ Appendix A Economic BenefitsThe selection of the proper materials for use in subsurface - Rig Waiting Costpumps is paramount in establishing low costs per barrel offluid lifted. The differential cost of selecting a premium Pump Repair Costmaterial over a common material can be relatively Administrative Cost (Direct Overhead Cost)insignificant when the total costs for a single pump failure Electrical Cost Resulting from Decreasedare evaluated. The total costs for repairing a subsurface Volumetric Efficiencypump include: Rod and Tubular Replacement Cost Lost Production CostPump Pulling Cost The pump pulling, pump repair, electrical, and lost - Rig Travel Cost production costs are self-explanatory. Administrative costs - Rig Operating Cost are direct overhead costs that can be attributed directly to12 NACE International
  • 16. MR0176-2006the failure. For example, for each failure there is generally a run it or another pump back in the well, was $1,620. Theverification, data bank entry, establishment of failure cause, average pump repair was 31% of the total of the pumpand development of a solution to prevent further failure. repair cost and the well-pulling cost. It is difficult, however, to assign a dollar value to the other costs because theseRod and tubular replacement costs are those costs vary from well to well. From a conservative standpoint, theassociated with rods and tubing that are damaged because percentage of total costs contributed by pump pulling andof the failure. The more frequently rods and tubing are repair can easily drop to 20% of the total repair cost.handled or the connections broken and remade, the moreopportunity there is for error and subsequent failures. The key to low cost per barrel of fluid lifted is generally associated with long pump life and keeping the pump in theOne company reported an average pump repair cost of well. Proper material selection, along with pump design, is 5$720. The average well-pulling cost, to pull the pump and a key factor in achieving this goal. ________________________________________________________________________ Appendix B Case-Hardening Processes for Steel Pump Barrels for a Corrosive EnvironmentGENERAL Carbon is dissolved and subsequently precipitated as iron carbide.Pump barrels intended for service in an abrasive, corrosiveenvironment must have a wear-resistant surface and body 2. Liquid carburizing utilizes a fused bath of sodiumstrength capable of resisting sulfide stress cracking (SSC). cyanide and alkaline earth salt. The salt reacts with theThis combination can be achieved in steel barrels by either cyanide to form a cyanide of the alkaline earth metalplating or case-hardening the wear surface. that then reacts with iron to form iron carbide. A small amount of nitrogen is liberated and absorbed. NitrogenThe inside diameter (ID) surfaces of steel pump barrels are increases the hardenability of steel and increases thecommonly hardened by five case-hardening processes solubility of carbon. Barrels treated by this process areused individually or in combination: flame hardening, hardened on both the outside diameter (OD) and ID.induction hardening, carburizing, carbonitriding, andnitriding. Although low-carbon steels can be properly cased The final characteristics of a carburized barrel depend onby induction hardening, the carburizing, carbonitriding, and the heat treatments in general use. One method is a directnitriding processes are preferred for service in an H2S quench from the carburizing temperature into a suitableenvironment. Barrels through-hardened by flame hardening quenching medium. A second treatment is to cool slowlyor induction hardening are not recommended for H2S from the carburizing temperature, reheat to above theenvironments because of their susceptibility to SSC. Steel critical temperature of the case, and quench.barrels that have been cold worked are not recommendedbecause of residual stresses. CARBONITRIDINGThe surface hardness, obtained by carburizing and This is a modification of the gas carburizing process. A low-carbonitriding, depends on heat treatment after the carbon steel is normally used. Anhydrous ammonia iscomposition of the case has been altered. Nitriding alters added to the furnace atmosphere so that both carbon andthe composition of the case in such a way that hard nitrogen are absorbed by the steel surface. Carbonitridingcompounds are formed without further heat treating. is conducted at lower temperatures than gas carburizing to increase the absorption of nitrogen. Nitrogen increases theA brief description of each of the three preferred case- 6,7,8,12 hardenability of steel and the solubility of carbon. At higherhardening processes follows. temperatures, the process approaches gas carburizing withCARBURIZING a minimum transfer of nitrogen. The final properties are dependent primarily on the rate of cooling following the carbonitriding process. The increased hardenability madeIn this process, the carbon content of the surface of a low- possible by the alloying effect of nitrogen permits the oilcarbon steel (0.15 to 0.25% carbon) is increased. There quenching of carbonitrided low-carbon steels. Otherwise,are two carburizing processes used to case harden pump this process requires drastic water quenching to developbarrels. The characteristics of the case produced by both effective hardening. Hardness values as high as HRC 62methods are somewhat similar. Hardness values as high can be obtained by carbonitriding.as HRC 62 can be obtained with both methods. 1. In gas carburizing, carbon is absorbed into the NITRIDING barrel surface by heating in an atmosphere of methane. When using this process, the surface hardness of certain alloy steels may be increased by heating, in contact withNACE International 13
  • 17. MR0176-2006ammonia, without the necessity of quenching. The process vanadium (V), and in some instances, Ni. Steels in theinvolves the formation of hard, wear-resistant nitrogen UNS S40000 series also respond well to nitriding but do notcompounds on the surface of the steel by absorption of develop as hard a surface. Hardenable stainless steelsnascent nitrogen. may also be nitrided but their corrosion resistance is greatlyMost of the steels that are commonly used for nitriding reduced by nitriding.contain combinations of Al, Cr, molybdenum (Mo), ________________________________________________________________________ Appendix C Selection of Optimum-Type PumpIn selecting materials for a sucker-rod pump, the pump type, Stationary Barrel with Bottom Holddown. This is bettersize, seating depth, and required material strength must be suited for deep-well pumping because both sides of theconsidered. There are several methods for determining the barrel are exposed to the pressure of the column of fluid. 9,10size of pump required. Differing opinions concerning the However, a long pump should not be used because it is notproper application of various API pumps exist. However, anchored at the top, and the action of the sucker-rod stringthere are some generally accepted recommendations that tends to weave it back and forth, which may cause 9,10,11,12are outlined below as a guide. premature failure. This pump is not suited for handling fluid- containing sand, because sand tends to settle between theTUBING PUMP barrel and the tubing, causing the pump to stick. The outside of the barrel tube of this type of pump is susceptibleThis pump is suitable for severe service. It is adaptable for to corrosion because it is surrounded by stagnant fluid. Toproducing viscous fluids because of the large flow areas. A prevent this, a partial bottom discharge can be utilized totubing pump has fewer working parts and is often lower in force approximately 25% of the pumped fluid through thecost than a rod pump of corresponding size. However, pump-tubing annulus. Methods that permit sealing the topthese savings can be offset by repair costs because the of the pump are available. This prevents settlement of sandtubing must be pulled to repair the barrel of a tubing pump. in the pump-tubing annulus and corrosion of the barrel.Tubing pumps are generally used when it is necessary to lift This represents the ideal technique for deep wellslarge volumes of fluid and a pump of high displacement is producing sand with the well fluids and it is also acceptablerequired. The greater volume can result in a heavier fluid when a long pump is needed for a deep well.load on the sucker-rod string. A portion of the capacityadvantage may be lost in excessive rod and tubing stretch. Traveling Barrel Pump. The bottom-seated traveling barrel pump is well suited for handling fluid with sand because the turbulence caused by the action of the barrelINSERT PUMPS prevents the sand from settling. Also, the construction of this type of pump is such that sand cannot settle into theStationary Barrel with Top Holddown. A top holddown pump barrel when the pump is shut down, because thepump is designed for low-fluid-level wells because the large traveling valve acts as a built-in sand check valve.standing valve can be submerged in the well fluids. This However, in intermittent pumping, it is possible for sand topump is also capable of handling low-gravity crudes and is settle below the barrel, between the barrel and theideally suited for fluids carrying sand. The top holddown holddown, and prevent full travel of the barrel on theprovides a seal just below the point where fluid is downstroke. This type of pump can be used to pump deepdischarged to the tubing; sand cannot settle around the wells because both sides of the barrel are exposed to thebarrel and cause the pump to stick in the tubing. full fluid column pressure. However, long traveling barrelIntermittent pumping may allow sedimentation between the pumps are seldom used to pump deep wells because theplunger and barrel; this can be prevented by sealing off the compressive load on the standing valve tends to buckle thepump body at the top with a sand-check guide and drop. pull tube. This pump is not suited for pumping largeThe barrel in this type of pump is subject to tensile stresses volumes of heavy, viscous oil. Because of the long fluidthat can lead to premature failure in a sulfide environment. passage, the smaller standing valve, and the comparativelyThis pump is not suitable for deep pumping because of the smaller compression ratio, this pump is not suited forpressure differential across the wall of the barrel. The pumping wells that tend to gas lock.inside of the barrel is exposed to pressure of the full columnof fluid and the outside only to the pressure of Special Pumps. In addition to the standard API pumps,submergence. The resulting breathing of the barrel during specialty sucker-rod pumps have been designed to handlethe pumping cycle tends to increase the clearance between unusual downhole conditions. These include such pumpsthe plunger and the barrel, thereby increasing the slippage as casing pumps, double-displacement pumps, three-tubeof fluid past the plunger. In extreme cases, the barrel can pumps, and pumps having two compression chambers.burst. Detailed discussion of these pumps is beyond the scope of this standard.14 NACE International