MR0176-2012, Metallic Materials for Sucker-Rod Pumps for Corrosive Oilfield Environments

NACE Standard MR0176-2012 Item No. 21303

Standard Material Requirements Metallic Materials for Sucker-Rod Pumps for Corrosive Oilfield Environments This NACE International standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude 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 or otherwise, 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 standard represents minimum requirements and should in no way be interpreted as a restriction on the use of better procedures or materials. Neither is this standard intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this standard in specific instances. NACE assumes no responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE interpretations issued by NACE in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers. Users 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 its use. This NACE standard may not necessarily address all potential health and safety problems or environmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this standard. Users of this NACE standard are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this standard. CAUTIONARY NOTICE: NACE standards are subject to periodic review, and may be revised or withdrawn at any time in accordance with NACE technical committee procedures. NACE requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication and subsequently from the date of each reaffirmation or revision. The user is cautioned to obtain the latest edition. Purchasers of NACE standards may receive current information on all standards and other NACE publications by contacting the NACE FirstService Department, 1440 South Creek Dr., Houston, TX 77084-4906 (telephone +1 281-228-6200). Reaffirmed 2012-06-05 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 © 2012, NACE International

MR0176-2012

_________________________________________________________________________ Foreword This standard specifies metallic material requirements for the construction of sucker-rod pumps for (1(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 T1F-15 on Sucker-Rod Pumps for Corrosive Environments, a component of Unit Committee T-1F, “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, “Oil and Gas Production—Metallurgy;” and in 2012 by STG 32. 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. The terms shall and must are used to state a requirement, and are considered mandatory. The term should is used to state something good and is recommended, but is not considered mandatory. The term is used to state something considered optional.

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(1)

American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005-4070.

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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 ......................................................................................................................................14 Appendix A: Economic Benefits (Nonmandatory) ............................................................................14 Appendix B: Case-Hardening Processes for Steel Pump Barrels for a Corrosive Environment (Nonmandatory).........................................................................................................................15 TABLES: (A) Table 1: Classification of Metal-Loss Corrosion for Sucker-Rod Pumps ........................................4 Table 2: Recommended Materials for Mild Metal-Loss Corrosion Environments...............................5 Table 3: Recommended Materials for Moderate Metal-Loss Corrosion Environments ......................6 Table 4: Recommended Materials for Severe Metal-Loss Corrosion Environments ..........................7 Table 5: Typical Mechanical Properties of Pump Barrel Materials .....................................................8 Table 6: Typical Mechanical Properties of Plunger Materials ..........................................................11 Table 6.1: Typical Chemical Composition of Spray Metal ................................................................12 Table 7: Typical Materials for Cages ...............................................................................................12 Table 8: Typical Materials for Pull Tube, Valve Rod, and Fittings ....................................................13 Table 9: Typical Composition and Hardness of Cast Cobalt Alloys Used for Valve Parts ...............13 Table 10: Typical Composition and Hardness of Sintered Carbides Used for Valve Parts ..............13

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_________________________________________________________________________ Section 1: General 1.1 An adequate chemical treatment program using a selection of proper corrosion inhibitors and application techniques is necessary for optimum performance of sucker-rod pumping equipment in a corrosive environment. However, control of direct attack on pump materials may be accomplished by materials selection alone or by materials selection in combination with chemical treatment. 1.2 The recommended materials in this standard are presented in tables and listed in order of preferred usage in six different environments with varying degrees of corrosiveness and with and without possible abrasion. The listed materials have performed satisfactorily when used in the specified environments. These material recommendations are based on field experience. 1.3 This standard is not intended to preclude the development and testing of new materials that might improve sucker-rod pump performance. It is the responsibility of the user to fully evaluate the performance of any new material prior to its use. 1.4 The designations and mechanical properties of the materials covered by this standard are listed in selected tables.

_________________________________________________________________________ Section 2: Description of Tables 2.1 The specific quantities of water, hydrogen sulfide (H2S), and carbon dioxide (CO2) that are used to classify the corrosiveness of a fluid as mild, moderate, or severe are detailed in Table 1. 2.1.1 Explanations of the mild, moderate, and severe metal-loss corrosion classifications provided in Table 1 are intended to be a guide for the user. Currently, there is no clear consensus on which combination of produced fluids constitutes mild, moderate, or severe corrosive environments for subsurface pumps. There can be amounts of H2S, CO2, and water that do not clearly fall into one of the three combinations. The user’s operating experiences coupled with analysis of failures should be used to develop the appropriate classification. 2.1.2 The three corrosion classifications are identified by amounts of water, H2S, and CO2 in the produced fluids. There are other constituents in the fluid that can influence corrosion. General comments on these constituents follow: 2.1.2.1 Oxygen—Oxygen can be very destructive to the system. If oxygen is discovered, every attempt should be made to free the system of oxygen, or at least bring it to below 50 ppb dissolved oxygen. Severe corrosion can be expected above 50 ppb dissolved oxygen. 2.1.2.2 Chlorides—High chlorides can lead to pitting corrosion. High-chloride service conditions should be assumed to exist when the total dissolved solids exceed 10,000 mg/L and/or total chlorides exceed 6,000 mg/L. 2.1.2.3 H2S (Sour Service)—Sour service conditions should be assumed to exist when H2S is present in the system at partial pressures equal to or greater than 0.35 kPa absolute (0.050 psia). When operating in sour service, the material for subsurface pump fittings (connectors, bushings, etc.) should conform to the requirements of NACE MR0175/ISO 4 15156. 2.1.2.4 Water Content—Generally, if the water content is greater than 20%, the fluid exists as a water phase with oil droplets. If the water content is less than 20%, an oil phase with water droplets can exist. Inhibitors should be used if the water content is greater than 20%. 2.1.2.5 Temperature—The higher the temperature, the greater the rate of corrosion. Temperature below the crystallization point of paraffin results in deposition of a film of paraffin that may act as a corrosion barrier. 2.1.2.6 pH—The pH at bottomhole conditions is frequently lower (more acidic) than that measured at the surface. After acidizing, the pH should be monitored to ensure that the fluid does not attack chrome plate if chrome plate is used in the pump.

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MR0176-2012 2.1.2.7 Pressure—Pressure does not have a direct influence on the general corrosion rate. However, the system pressure influences the partial pressures of H2S and CO2, which have an effect on the corrosive nature of the fluids. 2.1.2.8 Velocity—Generally, the higher the velocity of produced fluids through the pump, the greater the metal loss because of erosion-corrosion. 2.1.2.9 Abrasion—Abrasion results not only from produced fluids but also from corrosion byproducts (e.g., iron sulfide). If the fluids contain greater than 100 ppm solids, conditions are considered abrasive. 2.2 General definitions of mild, moderate, or severe corrosive environments follow: 2.2.1 Mild metal-loss corrosive environment: Corrosion attack on downhole equipment, rods, and tubing is evident but equipment may last several years (more than three years) either with or without inhibitor treatment before corrosion-related failures occur. 2.2.2 Moderate metal-loss corrosive environment: Corrosion rates and time-to-failure are between mild and severe. 2.2.3 Severe metal-loss corrosive environment: Corrosion rates are high and corrosion failures occur in less than one year unless effective inhibitor treatment is applied. 2.3 Recommended materials for sucker-rod pumps to be used in mild, moderate, and severe metal-loss corrosive environments are listed in Tables 2, 3, and 4, respectively. The tables are each divided into two degrees of abrasion (i.e., “no abrasion” and “abrasion”) for each of the three corrosive environments. 2.4 A determination of the correct environmental classification for the selection of the materials to be used in a particular well should be made by an experienced corrosion or materials specialist. 2.5 The recommended pump barrels and compatible plungers are the first items shown under each environment. A plunger can be used with more than one barrel, but this could alter the preferred order of usage. 2.6 The tables showing barrel/plunger combinations also show the recommended material selections for valves, cages, pull tubes, valve rods, and fittings. 2.7 Materials for all parts are listed in preferred order based on optimum operating costs as determined by field experience rather than expected pump life or initial cost. In some instances, performance of these recommended materials can be similar. The total costs of pump repairs and proper material selection are discussed in Appendix A: Economic Benefits (Nonmandatory).

_________________________________________________________________________ Section 3: Barrel Selection 3.1 Mechanical properties of the various pump barrel base materials and available surface-conditioning requirements of barrels are given in Table 5. 3.2 There is no significant difference in corrosion performance between the D1 and D4 non-hardened steel barrels. 3.3 Generally, the corrosion performance of the four different case-hardened barrels is comparable. Case-hardening processes recommended for steel pump barrels to be used in H2S environments are discussed in Appendix B: Case-Hardening Processes for Steel Pump Barrels for a Corrosive Environment (Nonmandatory). ________________________________________________________________________________

Section 4: Pump Selection 4.1 Interrelated factors, other than the corrosive and abrasive natures of the produced fluids, that shall be considered when selecting materials for a sucker-rod pump include: 4.1.1 Type of pump;

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MR0176-2012 4.1.2 Barrel length and diameter; and 4.1.3 Seating depth and required material strength. 4.2 For a given pump size and seating depth, the strength requirement for a barrel in a top hold-down pump is greater than that for a barrel of a bottom hold-down pump. This is the result of a top hold-down pump having a greater pressure differential across the barrel. 4.3 Materials should be selected from Tables 2 through 10 to meet the strength and hardness requirements dictated by the type of pump and anticipated operating conditions. 4.4 Tables 5 through 8 list many of the materials by specific alloy number. 4.4.1 When selecting pumps, the purchaser should be aware that common names, brass for example, are often used to describe alloys of significantly different compositions and properties. 4.4.2 Specific alloys should be designated as shown in the tables to prevent substitution of trade name materials with different composition, which has resulted in repetitive failures in the past.

_________________________________________________________________________ Section 5: Maintenance Record System 5.1 A maintenance record system should be initiated to assist in reducing expenses related to sucker-rod pump failures. API 11BR details a sucker-rod pump repair/new pump log that can initiate a database for pump performance and aid in establishing a maintenance record system that should include the following factors: 5.1.1 A cross-reference file that lists the well number and pump number; 5.1.2 All of the pertinent information on the pump, including pump type and description and the complete metallurgy of the individual parts; 5.1.3 Pumping conditions; 5.1.4 Length of run; 5.1.5 Volume of fluid lifted during the run; 5.1.6 Cost, description, frequency, and type of repairs, including the type of material used in the manufacture of the replaced part or parts; and 5.1.7 A method of determining the point at which replacement of the pump becomes more economically desirable than continued repair. 5.2 Effectiveness of the maintenance record system is dependent on cooperation from the pump repair facility. A study of repair records should identify the principal causes of repeated failures and also indicate the corrective measures required to solve these problems. 5.3 Recordkeeping should be used for tracking pump part materials and comparing the cost of repetitive failures and the cost of upgrading with more expensive materials and parts. However, because many factors other than corrosion and abrasion can cause pump failures, upgrading the metallurgy of the entire pump assembly is seldom required.

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MR0176-2012 Table 1: (A) Classification of Metal-Loss Corrosion for Sucker-Rod Pumps (B)

Water H2S CO2

Mild Metal-Loss Corrosion cuts are less than 25% is less than 10 ppm is less than 250 ppm. (B)

Water and/or H2S and/or CO2

Moderate Metal-Loss Corrosion cuts are between 25% and 75% is between 10 and 100 ppm (C) is between 250 and 1,500 ppm. (B)

Water and/or H2S and/or CO2

Severe Metal-Loss Corrosion cuts are more than 75% is greater than 100 ppm (C) 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). 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). (B)

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Table 2 : Recommended Materials for Mild Metal-Loss Corrosion Environments No Abrasion Barrel

Abrasion Plunger

1. Nonhardened steel

Barrel

1. Chrome plate on steel

1. Case hardened steel

2. Spray metal on steel

2. Chrome plate on steel

1. Chrome plate on steel

(C)

Valves

(A)

Plunger

Valves (B)

1. Ball: UNS S44002 Seat: UNS S44004

1. Cobalt alloy

1. Spray metal on steel

2. Cobalt alloy

2. Cobalt alloy ball, sintered carbide seat

2. Cobalt alloy ball, sintered carbide seat

Cages

1. Steel Pull Tube, Valve Rod, and Fittings 1. Steel

Cages

1. Steel Pull Tube, Valve Rod, and Fittings 1. Steel

(A)

Metals and Alloys in the Unified Numbering System (latest revision), a joint publication of ASTM International (ASTM) and the American Society 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 differential across the valve.

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Table 3 Recommended Materials for Moderate Metal-Loss Corrosion Environments No Abrasion Barrel

1. Brass, nonhardened

Abrasion Plunger

1. Spray metal with nickelcopper alloy pin ends

Barrel

1.Chrome plate on brass

2. Spray metal with electroless nickel pin ends

2. UNS N04400

1. Spray metal with nickelcopper alloy pin ends 2. Spray metal with electroless nickel pin ends

3. Heavy chrome plate on steel

2. Heavy chrome plate on steel

Same plungers as above

Same plungers as above

3. Chrome plate on steel

Same plungers as above

(A)

(A)

Valves 1. Cobalt alloy

Plunger

Valves

1. Sintered carbides 2. Cobalt alloy (A)

(A)

Cages

Cages

1. Nickel-copper alloy

1. Nickel-copper alloy, insert or lined

2. Brass

2. Stainless steel, insert or lined

3. Stainless steel

3. Brass, insert

Pull Tube, Valve Rod, and (B) Fittings

Pull Tube, Valve Rod, and (B) Fittings

1. Steel

1. Steel

2. Stainless steel

2. Stainless steel

3. 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 differential across the valve. (B) See Table 8 for materials within each component.

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Table 4 Recommended Materials for Severe Metal-Loss Corrosion Environments No Abrasion

Abrasion

Barrel 1. Nickel-copper alloy

Plunger

Barrel

Plunger

1. Spray metal with nickelcopper alloy pin ends

1. Chrome plate on nickelcopper alloy

1. Spray metal with nickelcopper alloy pin ends

2. Spray metal with electroless nickel pin ends

2. Spray metal with electroless nickel pin ends

2. Brass, nonhardened

Same plungers as above

2. Chrome plated on brass

Same plungers as above

3. Electroless nickel coating on steel

Same plungers as above

3. Electroless nickel coating on brass

Same plungers as above

(A)

(A)

Valves

Valves

1. Cobalt alloy

1. Sintered carbides (A)

(A)

Cages

Cages

1. Nickel-copper alloy

1. Nickel-copper alloy, insert or lined

2. Brass

2. Stainless steel, insert or lined

3. Stainless steel

3. Brass, insert (A)

Pull Tube, Valve Rod, and Fittings

(B)

Pull Tube, Valve Rod, and Fittings

1. Nickel-copper alloy

1. Nickel-copper alloy

2. Stainless steel

2. Stainless steel

3. 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 differential across the valve. (B) See Table 8 for materials within each component.

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Table 5 Typical Mechanical Properties of Pump Barrel Materials Identification Symbol

(A)

Product Description

Surface Condition

Base Core (B) Hardness

Base Material

Typical Yield Strength, MPa (1,000 psi)

A1

Chrome plate on steel

0.08 mm (0.003 in) min. plate thickness. Chrome plate hardness 67 to 71 HRC

Base material hardness 95 HRB to 23 HRC

Low-carbon steel. Ex: UNS G10200

410 (60)

A2

Chrome plate on brass

0.08 mm (0.003 in) min. plate thickness. Chrome plate hardness 67 to 71 HRC

Base material hardness 83 HRB to 23 HRC

Inhibited admiralty brass. Ex: UNS C44300

380 (55)

A3

Chrome plate on red brass

0.08 mm (0.003 in) min. plate thickness. Chrome plate hardness 67 to 71 HRC

Base material hardness 83 HRB to 23 HRC

UNS C23000 (Red brass)

240 (35)

A4

Chrome plate on 5% chromium steel

0.08 mm (0.003 in) min. plate thickness. Chrome plate hardness 67 to 71 HRC

Base material hardness 94 HRB to 23 HRC

UNS S50100 (5% chromium steel)

480 (70)

A5

Chrome plate on nickelcopper alloy

0.08 mm (0.003 in) min. plate thickness. Chrome plate hardness 67 to 71 HRC

Base material hardness 85 HRB to 20 HRC

UNS N04400 (Nickelcopper)

380 (55)

A6

Chrome plate on low-alloy steel

0.08 mm (0.003 in) min. plate thickness. Chrome plate hardness 67 to 71 HRC

Base material hardness 82 HRB to 23 HRC

Low-alloy steel. Ex: UNS G41300

550 (80)

A7

Heavy chrome on steel

0.15 mm (0.0060 in) min. plate thickness. Chrome plate hardness 67 to 71 HRC

Base material hardness 95 HRB to 23 HRC

Low-carbon steel. Ex: UNS G10200

410 (60)

A8

Electroless nickel coating on steel

0.033 mm (0.0013 in) min. plate thickness. Plate hardness 45 to 70 HRC

Base material hardness 95 HRB to 23 HRC

Low-carbon steel. Ex: UNS G10200

410 (60)

A9

Electroless nickel coating on lowalloy steel

0.033 mm (0.0013 in) min. plate thickness. Plate hardness 45 to 70 HRC

Base material hardness 83 HRB to 23 HRC

Low-alloy steel. Ex: UNS G41300

550 (80)

A10

Electroless nickel coating on brass

0.033 mm (0.0013 in) min. plate thickness. Plate

Base material hardness 83 HRB to

Inhibited admiralty brass

280 (40)

Plating

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Identification Symbol

Product Description

(A)

Surface Condition

Base Core (B) Hardness

Base Material

hardness 45 to 70 HRC

23 HRC

Ex: UNS C44300

Typical Yield Strength, MPa (1,000 psi)

Case Hardening

B1

Carbonitrided

0.25 mm (0.010 in) min. carburized case with 45 HRC min. hardness 0.25 mm (0.010 in) from the surface. Surface hardness 58 HRC min., 63 HRC max.

95 HRB to 23 HRC

Low-carbon steel. Ex.: UNS G10200

450 (65)

B2

Carburized

0.25 mm (0.010 in) min. carburized case with 45 HRC min. hardness 0.25 mm (0.010 in) from the surface. Surface hardness 58 HRC min., 63 HRC max.

95 HRB to 23 HRC

Low-carbon steel. Ex.: UNS G10200

450 (65)

B3

Carbonitrided 5% chromium steel

0.25 mm (0.010 in) min. carburized case with 45 HRC min. hardness 0.25 mm (0.010 in) from the surface. Surface hardness 58 HRC min., 63 HRC max.

98 HRB to 27 HRC

UNS S50100 (5% chromium steel)

480 (70)

B4

Nitrided 4130

0.13 mm (0.0050 in) min. nitrided case with 45 HRC min. hardness 0.13 mm (0.0050 in). Surface hardness 58 HRC min., 63 HRC max.

82 HRB to 23 HRC

UNS G41300

550 (80)

D1

Nonhardened steel

Surface is treated with a nonmetallic-type phosphate coating or other equally effective antigalling treatment.

Base material hardness 95 HRB to 23 HRC

Low-carbon steel. Ex.: UNS G10200

410 (60)

D2

Nonhardened brass

Surface is oiled.

Base material hardness 83 HRB to 23 HRC

Inhibited admiralty brass. Ex: UNS C44300

280 (40)

D3

Nickel-copper alloy

Surface is oiled.

Base material hardness 85 HRB to 20 HRC

Nickel-copper alloy. Ex: UNS N04400

380 (55)

(C)

Nonhardened

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(A)

Identification Symbol

Product Description

Surface Condition

Base Core (B) Hardness

Base Material

Typical Yield Strength, MPa (1,000 psi)

D4

Nonhardened steel

Surface is treated with a nonmetallic-type phosphate coating or other equally effective antigalling treatment

Base material hardness 82 HRB to 23 HRC

Low-alloy steel. Ex.: UNS G41300

550 (80)

(A)

Hardness readings are converted from Rockwell superficial hardness readings. 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. (B)

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MR0176-2012 Table 6 Typical Mechanical Properties of Plunger Materials Identification Symbol

Product Description

Surface Condition

Thread Base Material (A) Hardness

Base Material

Typical Yield Strength, MPa (1,000 psi)

A1

Chrome plate

0.15 mm (0.0060 in) min. plate thickness. Chrome plate hardness 67 to 71 (B) HRC

Hardness 95 HRB to 23 HRC

Carbon steel. Ex. UNS G10200

410 (60)

A2

Chrome plate

0.30 mm (0.012 in) min. plate thickness. Chrome plate hardness 67 to 71 (B) HRC

Hardness 95 HRB to 23 HRC

Carbon steel. Ex.: UNS G10250/G10350/ G10450

410 (60)

(C)

0.25 mm (0.010 in) min. coating thickness. Hardness 78.5 HRA (55 HRC) min.

Hardness 85 HRB to 23 HRC

Carbon steel. Ex.: UNS G10260

410 (60)

(C)

0.25 mm (0.010 in) min. coating thickness. Hardness 78.5 HRA (55 HRC min.

Hardness 93 HRB to 23 HRC

Carbon steel. Ex.: UNS G10260

410 (60)

(C)

0.25 mm (0.010 in) min. coating thickness. Hardness 78.5 HRA (55 HRC) min.

Nickel-copper alloy pin ends. Hardness 84 HRB to 23 HRC

Carbon steel. Ex.: UNS G10260/G10450

410 (60)

(C)

0.25 mm (0.010 in) min. coating thickness. Hardness 78.5 HRA (55 HRC) min.

Electroless nickel coating 0.033 mm (0.0013 in) on the pin ends. Base material hardness 85 HRB to 23 HRC

Carbon steel. Ex.: UNS G10260

410 (60)

(C)

0.25 mm (0.010 in) min. coating thickness. Hardness 78.5 HRA (55 HRC) min.

Electroless nickel coating 0.033 mm (0.0013 in) on the pin ends. Base material hardness 85 HRB to 23 HRC

Carbon steel. Ex.: UNS G10450

480 (70)

(C)

0.25 mm (0.010 in) min. coating thickness. Hardness 78.5 HRA (55 HRC) min.

Hardness 82 to 23 HRC

Low-alloy steel. Ex.: UNS G41300

550 (80)

Chrome Plate

Spray Metal

B1

Spray metal

B2

Spray metal

B3

Spray metal with nickel-copper alloy pin ends

B4

Spray metal with electroless nickel pin ends

B5

Spray metal with electroless nickel pin ends

B6

Spray metal

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Identification Symbol

Product Description

Surface Condition

Thread Base Material (A) Hardness

Base Material

Typical Yield Strength, MPa (1,000 psi)

B7

Spray metal

0.25 mm (0.010 in) min. coating thickness. Hardness 78.5 HRA (55 HRC) min.

Electroless nickel coating 0.033 mm (0.0013 in) on the pin ends. Base material hardness 82 HRB to 23 HRC

Low-alloy steel. Ex.: UNS G41300

550 (80)

Nonhardened

Surface is not hardened or plated.

Hardness 95 HRB to 23 HRC

Carbon steel. 23 HRC. Ex.: UNS G10260/G10350/ G10450

410 (60)

(C)

Nonhardened

C1

(A) (B) (C)

Critical strength component or plunger. Converted from Knoop or Vickers microhardness. See Table 6.1 for typical chemical composition of spray metal.

Table 6.1 Typical Chemical Composition of Spray Metal

Carbon (C) Silicon (Si) Phosphorus (P) Sulfur (S) Chromium (Cr) Boron (B) Iron (Fe) Cobalt (Co) Titanium (Ti) Aluminum (Al) Zirconium (Zr) Nickel (Ni)

wt% Min.

wt% Max.

0.50 3.50 ------------12.00 2.50 3.00 -------------------------

1.00 5.50 0.02 0.02 18.00 4.50 5.50 0.10 0.05 0.05 0.05 Remainder

Table 7 Typical Materials for Cages Steel

Nickel-Copper Alloy

UNS N04400

Brass

UNS C46400

Stainless Steel

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Carbon Steels UNS G10200 through G10450 Low-Alloy Steels UNS G41300 through G41450 UNS G86200 through G86450

UNS S30400, UNS S31600

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MR0176-2012 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% Ball

wt% Seat

Co Cr Tungsten (W) C Other

45.2 32.0 18.0 2.3 2.5

57.9 24.5 12.0 2.1 3.5

HRC

58-63

51-55

Table 10 Typical Composition and Hardness of Sintered Carbides Used for Valve Parts wt% Balls and Seats

(A)

Tungsten Carbide Co

87 13

HRA

88

wt% Balls (A)

Titanium Carbide Nickel/Cobalt Trace Elements HRA

60 14 1 90

The lighter-weight titanium carbide ball reduces the impact of the ball in the valve. Titanium carbide is used in heavy pumping wells or gassy wells to reduce the effects of impact.

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MR0176-2012 _________________________________________________________________________ References 1.

API Spec 11AX (latest revision), “Specification for Subsurface Sucker Rod Pumps and Fittings” (Washington, DC: API).

2.

API RP 11AR (latest revision), “Recommended Practice for Care and Use of Subsurface Pumps” (Washington, DC: API).

3.

API RP 11BR (latest revision), “Recommended Practice for Care and Handling of Sucker Rods” (Washington, DC: API).

4. NACE MR0175/ISO 15156 (latest revision), “Petroleum and Natural Gas Industries—Materials for use in H2S-containing Environments in Oil and Gas Production” (Houston, TX: NACE). 5.

D.S. Clark, W.R. Varney, Physical Metallurgy for Engineers, 2nd ed. (Princeton, NJ: Van Nostrand Reinhold, 1969).

6. “Heat Treatment of Steel,” Republic Alloy Steels Handbook, Booklet Adv. 1009 (Cleveland, OH: Republic Steel Corporation, 1961). 7. E.A. Avallone, T. Baumeister, Mark’s Standard Handbook for Mechanical Engineers, 11th ed. (New York, NY: McGraw-Hill, 2006). 8. “Subsurface Pumps—Selection and Application,” United States Steel Corporation (Oilwell Supply Division), Pittsburgh, PA, 1967. 9.

J. Zaba, Modern Oil-Well Pumping (Tulsa, OK: Petroleum Publishing Co., 1962).

10. T.C. Frick, ed., Petroleum Production Handbook (New York, NY: McGraw-Hill, 1962). 11. B.R. Bruton, “Selection of Metallic Materials for Subsurface Pumps for Various Corrosive Environments,” University of Oklahoma Short Course, September 14-16, 1970.

_________________________________________________________________________ Appendix A Economic Benefits (Nonmandatory) This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein. A1 The selection of the proper materials for use in subsurface pumps is paramount in establishing low costs per barrel of fluid lifted. The differential cost of selecting a premium material over a common material can be relatively insignificant when the total costs for a single pump failure are evaluated. The total costs for repairing a subsurface pump include: A1.1 Pump pulling cost a.

Rig travel cost

b.

Rig operating cost

c.

Rig waiting cost

A1.2 Pump repair cost A1.3 Administrative cost (direct overhead cost) A1.4 Electrical cost resulting from decreased volumetric efficiency A1.5 Rod and tubular replacement cost

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MR0176-2012 A1.6 Lost production cost A2 The pump pulling, pump repair, electrical, and lost production costs are self-explanatory. Administrative costs are direct overhead costs that can be attributed directly to the failure. For example, for each failure there is generally verification, a data bank entry, establishment of failure cause, and development of a solution to prevent further failure. A3 Rod and tubular replacement costs are those costs associated with rods and tubing that are damaged because of the failure. The more frequently rods and tubing are handled or the connections broken and remade, the more opportunity there is for error and subsequent failures. A4 The average pump repair was 31% of the total of the pump repair cost and the well-pulling cost. It is difficult, however, to assign a dollar value to the other costs because these vary from well to well. From a conservative standpoint, the percentage of total costs contributed by pump pulling and repair can easily drop to 20% of the total repair cost. A5 The key to low cost per barrel of fluid lifted is generally associated with long pump life and keeping the pump in the well. Proper material selection, along with pump design, is a key factor in achieving this goal.

_________________________________________________________________________ Appendix B Case-Hardening Processes for Steel Pump Barrels for a Corrosive Environment (Nonmandatory) This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein.

. General B1 Pump barrels intended for service in an abrasive, corrosive environment must have a wear-resistant surface and body strength capable of resisting sulfide stress cracking (SSC). This combination can be achieved in steel barrels by either plating or case-hardening the wear surface. B2 The inside diameter (ID) surfaces of steel pump barrels are commonly hardened by five case-hardening processes used individually or in combination: flame hardening, induction hardening, carburizing, carbonitriding, and nitriding. Although lowcarbon steels can be properly cased by induction hardening, the carburizing, carbonitriding, and nitriding processes are preferred for service in an H2S environment. Barrels through-hardened by flame hardening or induction hardening are not recommended for H2S environments because of their susceptibility to SSC. Steel barrels that have been cold worked are not recommended because of residual stresses. B3 The surface hardness, obtained by carburizing and carbonitriding, depends on heat treatment after the composition of the case has been altered. Nitriding alters the composition of the case in such a way that hard compounds are formed without further heat treating. 5-8

B4 A brief description of each of the three preferred case-hardening processes follows. B4.1 Carburizing

In this process, the carbon content of the surface of low carbon steel (0.15 to 0.25% carbon) is increased. There are two carburizing processes used to case harden pump barrels. The characteristics of the case produced by both methods are somewhat similar. Hardness values as high as HRC 62 can be obtained with both methods. B4.1.1 In gas carburizing, carbon is absorbed into the barrel surface by heating in an atmosphere of methane. Carbon is dissolved and subsequently precipitated as iron carbide. B4.1.2. Liquid carburizing uses a fused bath of sodium cyanide and alkaline earth salt. The salt reacts with the cyanide to form a cyanide of the alkaline earth metal that then reacts with iron to form iron carbide. A small amount of nitrogen is liberated and absorbed. Nitrogen increases the hardenability of steel and increases the solubility of carbon. Barrels treated by this process are hardened on both the outside diameter (OD) and ID.

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MR0176-2012 B4.1.3 The final characteristics of a carburized barrel depend on the heat treatments in general use. One method is a direct quench from the carburizing temperature into a suitable quenching medium. A second treatment is to cool slowly from the carburizing temperature, reheat to above the critical temperature of the case, and quench. B4.2 Carbonitriding This is a modification of the gas carburizing process. Low carbon steel is normally used. Anhydrous ammonia is added to the furnace atmosphere so that both carbon and nitrogen are absorbed by the steel surface. Carbonitriding is conducted at lower temperatures than gas carburizing to increase the absorption of nitrogen. Nitrogen increases the hardenability of steel and the solubility of carbon. At higher temperatures, the process approaches gas carburizing with a minimum transfer of nitrogen. The final properties are dependent primarily on the rate of cooling following the carbonitriding process. The increased hardenability made possible by the alloying effect of nitrogen permits the oil quenching of carbonitrided low-carbon steels. Otherwise, this process requires drastic water quenching to develop effective hardening. Hardness values as high as HRC 62 can be obtained by carbonitriding. B4.3 Nitriding When using this process, the surface hardness of certain alloy steels may be increased by heating, in contact with ammonia, without the necessity of quenching. The process involves the formation of hard, wear-resistant nitrogen compounds on the surface of the steel by absorption of nascent nitrogen. Most of the steels that are commonly used for nitriding contain combinations of Al, Cr, molybdenum (Mo), vanadium (V), and in some instances, Ni. Steels in the UNS S40000 series also respond well to nitriding but do not develop as hard a surface. Hardenable stainless steels may also be nitrided, but their corrosion resistance is greatly reduced by nitriding.

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ISBN 1-57590-099-8 NACE International