api sucker rods

Recommended Practice for the Care and Handling of Sucker Rods

API RECOMMENDED PRACTICE 11BR NINTH EDITION, AUGUST 2008

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Recommended Practice for the Care and Handling of Sucker Rods

Upstream Segment

API RECOMMENDED PRACTICE 11BR NINTH EDITION, AUGUST 2008

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Special Notes

API publications necessarily address problems of a general nature. With respect to particular circumstances, local, state, and federal laws and regulations should be reviewed.

Neither API nor any of API's employees, subcontractors, consultants, committees, or other assignees make any warranty or representation, either express or implied, with respect to the accuracy, completeness, or usefulness of the information contained herein, or assume any liability or responsibility for any use, or the results of such use, of any information or process disclosed in this publication. Neither API nor any of API's employees, subcontractors, consultants, or other assignees represent that use of this publication would not infringe upon privately owned rights.

Classified areas may vary depending on the location, conditions, equipment, and substances involved in any given situation. Users of this recommended practice should consult with the appropriate authorities having jurisdiction.

Users of this recommended practice should not rely exclusively on the information contained ín this document. Sound business, scientific, engineering, and safety judgment should be used in employing the information contained herein.

API publications may be used by anyone desiring to do so. Every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them; however, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use or for the violation of any authorities having jurisdiction with which this publication may conflict.

API publications are published to facilitate the broad availability of proven, sound engineering and operating practices. These publications are not intended to obviate the need for applying sound engineering judgment rcgarding when and where these publications should be utilizad. The formulation and publication of API publications is not intended in any way to inhibit anyone from using any other practices.

Any manufacturer marking equipment or materials in conformance with the marking requirements of an API standard is solely responsible for complying with all the applicable requirements of that standard. API does not represent, warrant, or guarantee that such products do in fact conform to the applicable API standard.

All rights reserved. No part of this work may be reproduced, stored in a retrieval system, or transmitted by any means, electronic, mechanical, photocopying, recording, or otherwise, without prior written permission from the publisher. Contact the Publisher, API

Publishing Services, 1220 L Street, N.W., Washington, D.C. 20005.

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F o rewo rd

Thís recommended practice is under the jurisdiction of the API Executive Commíttee on Standardization.

Detailed requirements applying to sucker rods are given in API Specification 11B, Specification for Sucker Rods,

which also is under the jurisdiction of the API Executive Committee on Standardization.

Nothing contained in any API publication is to be construed as granting any right, by implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters patent. Neither should anything contained in the publication be construed as insuring anyone against liability for infringement of letters patent.

This document was produced under API standardization procedures that ensure appropriate notification and participation in the developmental process and is designated as an API standard. Questions concerning the interpretation of the content of this publication or comments and questions concerning the procedures under which this publication was developed should be directed in writing to the Director of Standards, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005. Requests for permission to reproduce or translate all or any part of the material published herein should also be addressed to the director.

Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years. A one-time extension of up to two years may be added to this review cycle. Status of the publication can be ascertained from the API Standards Department, telephone (202) 682-8000. A catalog of API publications and materials is published annually by API, 1220 L Street, N.W., Washington, D.C. 20005.

Suggested revisions are invited and should be submitted to the Standards Department, API, 1220 L Street, NW, Washington, D.C. 20005, [email protected].


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Contents

Page

1 Scope 1

2 References 1

3 Selection of API Steel Sucker Rods 1

3.1 General 1

3.2 Stress Effects 1

3.3 Environmental Effects 1

3.4 Sucker Rod and Coupling Grade Selection 2

4 Allowable Sucker Rod Stress Determination Utilizing Range of Stress 3

4.1 General 3

4.2 Stress Diagrams 3

4.3 U.S. Customary (USC) Example 3

4.4 Metric Example 4

5 Slim Hole Sucker Rod Coupling Derating 4

5.1 Derating Factor History 4

5.2 Modified Derating Factor 4

6 Sucker Rod Joint Makeup Utilizing Circumferential Displacement 5

6.1 General 5

6.2 Circumferential Displacement Values 6

6.3 General Recommendations, Power Tongs 7

6.4 Calibration of Power Tongs 7

6.5 Use of Rod Wrenches for Manual Makeup 8

7 Installation of Polished Rod Clamp on Polished Rod 8

8 Inspection of Used Sucker Rods and Couplings 9

8.1 General 9

8.2 Visual Inspections 9

8.3 Electromagnetic Inspections 11

8.4 Pin End Inspections 12

8.5 Coupling Inspection 13

8.6 Acceptance Criteria 13

8.7 Completion of Inspection i3

9 Corrosion Control 14

10 Transportation and Handling, Storage, Running and Pulling 14

10.1 General 14

10.2 Handling 15

10.3 Transportation 15

10.4 Storage 15

10.5 Running and Pulling 16

11 Bibliography 17

Annex A NACE International SP0195, Corrosion Control of Sucker Rods by Chemical Treatment 19

Figures 1 Modified Goodman Diagram for Allowable Stress and Range of Stress for Sucker Rods in

Non-corrosive Service 3

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Hand-tight Joint 6 3 Made-up Joint 6

Tal-ales 1 Chemical Composition of Steel Sucker Rods 2 2 Mechanical Strength Properties of Steel Sucker Rods 2 3 Recommended Slim-hole Coupling Derating Factors, Fd 5 4 Sucker Rod Joint Circumferential Displacement Value Measurements 5 5 Color Coding 14


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Recommended Practice for Care and Handling of Sucker Rods

1 Scope

This rocommended practico (RP) covers the tare and handling cf steel sucker rods, including guidelines on selection, allowable stress, proper joint makeup, corrosion control and used rod inspection.

2 Referentes

This specification includes by reference, either in total or in part, the most recent editions of the following API, industry, and government standards, unless a specific edition is listed:

API Specification 11B, Specification for Sucker Rods

API Technical Report 11L, Design Calculations for Sucker Rod Pumping Systems (Conventional Units)

ASNT SNT-TC-1A 1, Recommended Practice, Personnel Qualification and Certification in Nondestructive Testing

NACE MR0174 2, Selecting lnhibitors for Use as Sucker-Rod Thread Lubricants

NACE SP0195, Corrosion Control of Sucker Rods by Chemical Treatment

3 Selection of API Steel Sucker Rods

3.1 General

The selection of API grade sucker rods for a beam pump installation depends on a variety of factors, including stress effects, environmental effects and rod grade.

3.2 Stress Effects

Sucker rods need to be selected based on applied stresses. API 11L, Design Calculations for Sucker Rod Pumping Systems provides a procedure for calculating the applied loads or stress on a sucker rod string design.

Sucker rod strength is limited by the fatigue performance of the rod's metal. This useful strength is dependent on the metal's tensile strength as shown by Goodman (Goodman, "Mechanics Applied to Engineering" and Kommers, "Effect of Range of Stress and Kind of Stress on Fatigue Life"). This relationship is the basis for Section 4 of this document. According to the Goodman diagram shown in Figure 1, sucker rods operating in a non-corrosive environment and in the proper stress ranga will theoretically exceed 10 million load reversals. However, the fatigue life can be dramatically decreased by improper installation, design, handling or operation even without corrosion.

3.3 Environmental Effects

Sucker rods will eventually fail, even if not stressed, when placed in a corrosiva environment. There is a reduction in sucker rod and coupling life if placed in a corrosiva environment. However, the life of the sucker rod can be extended by the use of an effective corrosion inhibition program. In that case the expected life of a sucker rod can potentially be the same as a rod in a non-corrosiva environment.

1 American National Standards Institute, 25 West 43rd Street, 4th (loor, New York, New York 10036, www.ansi.org. 2 NACE International (formerly the National Association of Corrosion Engineers), 1440 South Creek Drive, Houston, Texas

77218-8340, www.nace.org.

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API i<LCOMMENDEU 1-1-tACI ICE 1 iBR

Another environmental concern is the use of the sucker rods in a production environment which contains hydrogen sulfide. A sucker rod placed in this environment can rapidly fail oven though the corrosion effects are not readily apparent. NACE MR0175 has defined a hydrogen sulfide environment as "sour" when the hydrogen sulfide padal pressure is greater than 0.05 psi or 0.0034 atm (0.345 kPa). Materials placed in sour environments with hydrogen sulfide partial pressures equal to or greater than this value can fail prematurely due to hydrogen embrittlement unless the materials are sulfide stress cracking resistant or unless are effective corrosion inhibition program 13 maintaincd.

3.4 Sucker Rod and Coupling Grade Selection

3.4.1 General

Tables 1 and 2 identify the chemical composition and mechanical strength properties of steel sucker rods. For non-sour (sweet) environments, the applied stresses determine which grade of sucker rod is selected. However, a corrosion inhibition program may be required to combat the damaging effects of corrosion and its associated life reduction.

3.4.2 Grades

Materials which are not susceptible to sulfide stress cracking usually possess a Rockwell C scale hardness of less than 23. Thus, a Grade C sucker rod is the optimum sucker rod to be used if the applied stresses are within its capabilities and a sour environment exists.

If the applied stresses require Grade D sucker rods and a sour environment exists, then an effective corrosion inhibition program is required.

The Grade K rod is available for use when the other sucker rod grades have not performed satisfactorily in a corrosive environment.

The chemical composition of steel sucker roads and steel pony rods shall be any composition of AISI series steel, or international equivalent, listed in Table 1 which can be effectively heat treated to the mechanical property requirements of API Grades K, C, and D rods as shown in Table 2.

Table 1—Chemical Composition of Steel Sucker Rods

API Grade Chemical Composition

K AISI 46XX Series Steel a

C AISI 10)0( Series Steel a AISI 15XX Series Steel a

D Carbon AISI 10XX Series Steel a AISI 15XX Series Steel a

D Alloy AISI 41XX Series Steel a

D Special Special--Special alloy shall be any chemical composition that contains a combination of nickel, chromium and molybdenum that total a minimum of 1.15% alloying content.

a Or an equivalent international series number steel.

Table 2—Mechanical Strength Properties of Steel Sucker Rods

API Grade Minimum Yield 0.2% Offset psi (Mpa)

Minimum Tensile psi (Mpa)

Maximum Tensile psi (Mpa)

K 60,000 (414) 90,000 (620) 115,000 (793)

C 60,000 (414) 90,000 (620) 115,000 (793)

D 85,000 (586) 115,000 (793) 140,000 (965)

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Minimum Tensile Stren

Sa = (1,711 + M S,-„1) SF 1 Sa = (0.25T+ 0.5625 Sr.i„) SF 2

AS. = S.— Sr.,. 3

where Sa = maximum available stress, psi (N/mm2)

AS. = maximum allowable range of stress, psi (N/mm2) M = slope of Sa curve = 0.5625

= minimum stress, psi (N/mm2)(calculated or measured) SF = service factor T = minimum tensile strength, psi (N/mm2)

RECOMMENDED PRACTICE FOR (.ARE AND HANDLING OF SUCKER RODS 3

4 Allowable Sucker Rod Stress Determination Utilizing Range of Stress

4.1 General

In determining the allowable rango of stress and allowable sucker rod stress for a string of sucker rods, it is recommended that the modified Goodman stress dianram shown in Figure 1 he used This gives the basic or fundamental rating which can be used where corrosion is not a factor. Since all well fluids are corrosive to some degree, if not inhibited 100%, and since the corrosivity of well fluids varíes greatly, it is of extreme importance that the stress values determined from this diagram be adjusted by an appropriate service factor, based on the severity of the corrosion. This service factor should be selected by each user as his experience indicates. It could be greater than one, although normally it will be less than one, varying inversely with severity of corrosion.

4.2 Stress Diagrams

In applying this information from Figure 1, separate diagrams can be prepared for each minimum tensile strength value. Separate diagrams showing load in pounds (KN) rather than stress can also be prepared for each grade and rod size. Alternately, the desire value can be obtained by using one of the equations shown in Figure 1.

Figure 1—Modified Goodman Diagram for Allowable Stress and Range of Stress for Sucker Rods in Non-corrosive Service

4.3 U.S. Customary (USC) Example

Assume a string of API Grade C rods with a minimum tensile strength of 90,000 psi (620 N/mm2) is being used and

that a minimum downstroke stress of 15,000 psi (103 N/mm2) has been either measured or calculated. At what peak polished rod stress may we operate this string in non-corrosive service?

Refer to Figure 1, Equation (2).

Sa = (0.25T+ 0.5625 Smin)

= (0.25 x 90,000 + 15,000 x 0.5625)

= 30,938 psi (non-corrosive)

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4 API RECOMMENDED PRACTICE 11BR

Converting to load for different size top rods, this would be:

5/8 in. 30,938 /0.307 9,498 lb

/c:

3/4 in 30,938 x 0.442 = 13,675 lb

7/s in. 30,938 x 0.601 = 18,594 lb

1 in. 30,938 x 0.758 = 24,286 lb

4.4 Metric Example

Sa = (0.25T+ 05625 Smm)

= 0.25 x 620 1- 0.5625 x 103

= 213 N/mm2

Converting to load for different size top rods, this would be:

15.9 mm 213 x 1979 = 42.2 KN

19.0 mm 213 x 285.0 = 60.9 KN

22.2 mm 213 x 387.9 = 82.6 KN

25.4 mm 213 x 506.7 = 107.9 KN

The aboye values should then be adjusted by an appropriate service factor.

5 Slim Hole Sucker Rod Coupling Derating

5.1 Derating Factor History

The concept for reducing the allowable rod string stress when slim-hole couplings were used was originally published by Gipson et al., (Gipson, F.W and H.W. Swaim, "Beam Pump Fundamentals").

It was discussed that the actual derating factor was not known. Original derating factors were developed based on the relationship between the slim-hole coupling cross sectional area divided by the cross sectional area of the corresponding sucker rod. However, it was known, based on field performance, that slim-hole couplings for 1-in. rods did not have a record of excessive failures. Thus, the derating factors were normalized based on the slim-hole area divided by the rod area for 1-in. rods. Derating factors were presented for the different slim-hole coupling sizes for use on all grades of sucker rods.

5.2 Modified Derating Factor

A more rigorous analysis of the cross sectional area relationships, stress concentration factor effects of the rod connection threads, and the use of the API Modified Goodman Diagram included here as Figure 1 was published by D.E. Hermanson (Hermanson, D.E., Petroleum Engineering Handbook).

These derating factors include the influence of the different állowable stress capabilities for the different rod and corresponding coupling size and API grade. These factors are presented in Table 9.8 of the aboye referenced handbook and are identified in Table 3 of this RP.

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RECOMMENDED PRAC I ICE FOR CP■RE ANO HANDLING OF SUCKER Reos 5

Table 3-Recommended Slim-hole Coupling Derating Factors, F(f

API Rod Size (in.)

API Rod Grade

K C D

5/8 - 0.97 0.77

3/4 - - 0.86

7/8 0.93 0.88 0.69

1 - - 0.89

These derating factors should be considered as a conservative allowable load or stress reduction to account for the "weakest link" design approach for sucker rod strings. Field experience may allow for modifications in these factors to either increase or decrease the amount of derating based on the individual well conditions. However, the use of a derating factor should be considered in the string design similar to that of rod stress determination.

6 Sucker Rod Joint Makeup Utilizing Circumferential Displacement

6.1 General

For optimum performance, it is imperative that all of the joints in the string of rods be made up to a given preload stress leve) in order to prevent separation between the pin shoulder and the coupling face during the pumping cycle.

Both test data and theoretical calculations show that circumferential displacement beyond hand-tight makeup of coupling and pin provides an accurate and repeatable means with which to measure and define the preload stress in a sucker rod joint.

Table 4-Sucker Rod Joint Circumferential DIsplacement Value Measurements all dimensions in inches (followed by equivalent in mm)

1 2 3

Running New Grade D

Rerunning Grades C, D and K Displacement Valves

Displacement Values

Rod Size Minimum Maximum Minimum Maximum

5/8 (15.9) 8/32 (6.3) 9/32 (7.1) 6/32 (4.8) 8/32 (6.3)

3/4 (19.1) 9/32 (7.1) 11/32 (8.7) 7/32 (5.6) 17/64 (6.7)

7/8 (22.2) 11/32 (8.7) 12/32 (9.5) 9/32 (7.1) 23/64 (9.1)

1 (25.4) 14/32 (11.1) 16/32 (12.7) 12/32 (9.5) 14/32 (11.1)

1 1/8 (28.6) 18/32 (14.3) 21/32 (16.7) 16/32 (12.7) 19/32 (15.1)

NOTE: Aboye displacement values were established through calculations and strain gauge tests.

There are many inherent variables which affect joint makeup. Among these are the differences in materials, the smoothness of surface finishes, selection of an acceptable thread lubricant, and the lubricity of lubricants, as well as the operating characteristics and mechanical condition of the power tong equipment. As a result, applied torque has not proven to be the most accurate, nor the most practica! means of measuring the preload stress level in a sucker rod joint.

NOTE NACE MR0174 has developed a tested procedure for possible thread lubricants that requires a single application of the thread lubricant to a pin, complete makeup and break-out using the appropriate makeup displacement for the rod size and grade and repeated for 10 complete cycles. After this procedure, the pin and coupling threads should be cleaned and inspected. An acceptable pin lubricant is one which results in no visible damage or galling of either thread forms.

In view of the foregoing, this RP provides, for field use, a comprehensive set of circumferential displacement values and procedures covering their use, including a method for the calibration of power tongs.


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6 API RECOMMENIDED PRACTICE 11BR

6.2 Circumferential Displacement Values

Circumferential displacement as used herein is the distance measured, after makeup, between the displaced parts of a vertical line scríbed across the externa! surfaces of the box and pin when they are in a shouldered hand-tight relationship prior to makeup. See Figure 2 and Figure 3.

Scribed vertical line

Figure 2—Hand-tight Joint

Measured circumferential display

Figure 3—Made-up Joint

The circumferential displacement values shown in Table 4 are the necessary and recommended displacements required to achieve an optimum preload stress. Values for a combination of materials and their application are listed in the column headings. Choose the correct column.

Because the interface sur-faces of the joint are burnished or smoothed out on initial makeup, the displacement values on initial makeup are greater than those on subsequent makeup. While this difference in displacement occurs in varying degrees with all rod grades, it is observed to be consistent only in the Grade D rod.

NOTE The tabulated values for use when rerunning Grade D rods are smaller than those for the initial makeup of new Grade D rods.

It is impractical to establish displacement values for the initial makeup of Grade C and K rods because of the inconsistency of observed test data with these materials. It is therefore recommended that new Grade C and K rod joints be made up and broken, in the field, prior to final makeup on initial installation.

When new couplings are installed on previously used rods regardless of their grade, the displacement values listed in Table 4, Column 2 should be used.

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RECOMfv1ENDEO Pt A TiC c F J CAFIE r riü i ;AivüLiNG OF GUGKER RODS 7

6.3 General Recommendations, Power Tongs

The use of a hydraulic power tong is recommended to assure best makeup results for all sizes of sucker rods. However, it is imperative the power tongs be maíntained in accordance with the manufacturer's recommendations. It is recommended the hydraulic power oil system be circulated until a normal operating temperature is reached and that this temperature be inaintained within a reasonable leve! ti iiough calibration and installation of rods.

6.4 Calibration of Power Tongs

6.4.1 General

Power tongs must be calibrated to produce recommended circumferential displacement makeup values shown by Table 4. Alter initial calibration, it is recommended the power tong calibration be checked each 1000 ft (300 m) and be calibrated for each change in rod sizes.

There are three different methods employed in calibrating power tongs for various API Grade rods and field conditions. It is imperative to select the recommended method to suit your field conditions.

6.4.2 Calibration Process for Power Tongs for New API Grade D Rods

The following process should be used for calibration of power tongs for new API Grade D rods.

a) Check condition outlined under 6.1.

b) Set the tongs operating pressure on the low side of the estimated value required to produce prescribed circumferential displacement value shown by Table 4.

c) Screw the first joint together hand-tight; scribe a fine vertical line across the pin and coupling shoulder to establish hand-tight reference as shown by Figure 2.

d) Loosen coupling to the normal running position then make up the joint with power tong operating with the tong throttle depressed to the fully open position. Do not hit the throttle a second time after joint shoulder and tongs have stalled.

e) Remove the tongs and measure the circumferential displacement between the scribed hand-tight vertical line as shown by Figure 3.

f) Increase or decrease the tong operating pressure to achieve the selected prescribed circumferential displacement as shown by Table 4.

g) Repeat Steps d) through f) until proper displacement is achieved. Check the calibration of tongs a minimum of four joints and for each 1000 ft thereafter, and at each change in rod sizes.

6.4.3 Calibration Process for Power Tongs for API Grade C and Grade K Rods

The following process should be used for calibration of power tongs for API Grade C and Grade K rods.

a) For the initial run of API Grade C and Grade K ruds, d constant correction factor cannot be recommended because of inherent variables involved. Therefore, it is imperative to make up and break the connection prior to calibration and power tongs if proper preload is to be assured.

b) Once the joint is made up and broken follow the same procedure as outlined in 6.4.2, Steps a) through g), using the appropriate circumferential displacement values in Table 4, Column 3.


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6.4.4 Calibration Process for Power Tongs for Rerunning of all Grades of API Rods and New Couplings

Employ values shown in Table 4, Column 3 and follow same procedure as outlined in 6.4.2, Steps a) through g).

6.5 Use of Rod Wrenches for Manual Makeup

6.5.1 General

The use of rod wrenches is not recommended for rod sizes larger than 3/4 in. Application of rod wrenches to achieve the desired preload is as follows.

6.5.2 Manual Makeup of New API Grade D Rod Strings

The following process should be used for manual makeup of new API Grade D rod strings:

a) screw rod and coupling to a shouldered hand-tight position;

b) scribe a fine vertical line across the pin and coupling to establish a hand-tight reference as shown by Figure 2;

c) apply necessary mechanical force to achieve recommended displacement values as shown in Table 4, Column 2.

6.5.3 Mechanical Makeup of API Grade C and Grade K Rods

The following process should be used for mechanical makeup of API Grade C and Grade K rods:

a) apply mechanical force and make up joint once. Loosen and retighten to hand-tight position;

b) scribe a fine vertical line across the pin and coupling shoulder to establish a hand-tight reference as shown by Figure 2;

c) apply necessary mechanical force to achieve recommended displacement values as shown in Table 4, Column 3.

6.5.4 Mechanical Makeup of Used Rods and New Couplings

The following process should be used for mechanical makeup of use rods and new couplings:

a) bring coupling and rod pin to a hand-tight position;

b) acribe a fine vertical line across the pin and coupling shoulder to establish a hand-tight reference as shown by Figure 2;

c) apply mechanical force sufficient to achieve circumferential displacement as shown in Table 4, Column 3.

NOTE The hand-tight position as used in Section 6 is attained when full shouldered adjustment is made.

7 Installation of Polished Rod Clamp on Polished Rod

Installation of a polished rod clamp on a polished rod is as iollows.

a) Instan the polished rod clamp per manufacturer's instruction tag (see API 11B).

b) The polished rod must be void of dirt and grease where the clamp is located.

c) The polished rod clamp must be void of dirt and grease in the gripping area.


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RECOMMENDED PRAL 1 IGE FOR GARL ANU HANDLING UF SUCKLH RUUS 9

d) The hanger bar must be perpendicular to the wellhead in line with the well bore and void of dirt and Brease.

e) Place the polished rod clamp in a clean area on polished rod and tighten nut (or nuts) to hand tight. Do not install on any sprayed metal part of the rod.

1) For proper torque, rolluw rnanufacturer's instruction lay attoul tu the clamp (see 1111D).

g) If a friction type polished rod clamp is used with a metal sprayed polish rod, the user should be aware that the O.D. has a +0.005, -0.040 tolerance between the pin end and start of metal spray (see API 11B).

8 Inspection of Used Sucker Rods and Couplings

8.1 General

8.1.1 Inspection Methods

Sucker rods and couplings should be inspected by using visual, electromagnetic, magnetic particle and dye penetrant testing methods and various dimensional gauging tools (Stuart and Lloyds). Any of the aboye methods or combinations of them can result in an adequate inspection as selected and defined by the user. API 11B has a listing of definitions for defects and details on measurement procedures to verify workmanship and finish.

All inspection and NDT equipment used by the methods stipulated in this RP should be calibrated in accordance with 8.1.3.

8.1.2 Personnel Qualification

Inspection personnel should be minimally Level 1 quifi-d according to ASNIT SNT-TC-1A (Recommended Practice, Personnel Qualification and Certification in Nondestructive Testing).

8.1.3 Calibration Frequency

Inspection equipment calibration frequency should be adequate to assure accuracy of the equipment's measurements. The calibration status shall be recorded on the gauge and in a log book (or similar tracking method) with the date of the calibration and the initials of the person who performed the calibration. AII calibration activities shall be traceable to NIST or equivalent.

8.1.4 Calibration Referentes

Working gauges, API P6 and P8 "no-go" and "go" ring gauges used to inspect sucker rod pins and API B2 and B6 "go" and "no-go" box plug gauges for sucker rod couplings, shall be checked against Master Reference Gauges according to gauge certification specifications described in API 11B. Working master gauges P8 and P6 shall be checked against setting gauges P7 and P5, respectively, prior to running any rod orden

8.1.5 Feeler Gauges

The working area(s) of the feeler gauges shall be checked at the beginning of each shift with a calibrated micrometer. Feeler gauges shall be trimmed or replaced if they do not measure within -0.0002 in. of the actual value.

8.2 Visual Inspections

8.2.1 Preparations for Inspections

The rod body should be visually inspected for signs of damage, corrosion or wear by a qualified person. Rod guides should be removed before rods are inspected. This will enable visual inspection of the rods and improve cleaning to

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10

API RECOMMENDED PRACTICE 11BR

bare metal during shot cleaning. The area of the rod body near the location of the guides should be carefully inspected for obvious corrosion pitting or erosion.

Used rods should be shot-cleaned to remove surface deposits which may interfere with the inspection. The shot weight, size, shape and velocity should be such as to not shot-peen the rods, per the manufacturer's specifications. Thread protectors should be used to protect the pins from the shot-cleaning.

Rod length shall be measured to determine if the rod is within manufacturing tolerances of ±2 in. Measurements outside this tolerance are cause for rejection in all classes.

Couplings should be removed prior to visually inspecting rods. Rods visually rejected prior to coupling removal may be discarded as a single unit.

8.2.2 Bend Evaluations

Rods should be visually inspected for bends by rolling. Those with an apparent bend should be further checked folloWing the procedure in API 11B. Severely bent or kinked rods (those exceeding the limits identified below) should be rejected without further inspection.

For:rod bodies, the maximum allowable bend when using a 12 in. straight edge is 0.065 in. for all rod diameters. If a total indicated run-out (TIR) gauge is used, the maximum allowable TIR value is 0.130 in. The TIR methodology would be good to be detailed as variability of the process could cause differing results.

Rods with bends between 0.150 in. and 0.300 in. measured with a TIR can be cold straightened if the rods are downgraded to Class II. Rods with bends greater than 0.300 in. TIR can be cold straightened if desired by the customer. These rods should be downgraded to Class III.

Rod ends should not have more than 0.150 in. TIR when the rod body is supported 18 in. from the rod pin shoulder.

8.2.3 Mechanical Damage and Wear

Mechanical damage, such as hammer or wrench marks, is cause for rejection in alI classes.

Signs of mechanical damage or rounding of wrench flats that cannot be repaired and meet API 11B dimensions are cause for rejection or downgrading as directed by the user.

Wear measuring up to 20% of the cross-sectional area or a pit between 0.020 in. and 0.040 in. are criteria to downgrade the rod to Class II. Wear between 20% and 30% reduction in cross-sectional area or corrosion pits of 0.040 in. to 0.060 in. shall be cause for rejection or downgrading to Class III.

8.2.4 Couplings

Couplings should be removed by a method that will not cause damage to either the rod or the coupling during the removal process. Couplings may be removed from rejected rods if the couplings pass a visual inspection for wear, corrosion or damage by a qualified person.

8.2.5 Threads

Pin threads should be visually inspected by a qualified person for thread damage and evidence of pulling. Evidence of pulled threads is cause for rejection in all classes.

Damage on the first three threads from the undercut end is cause for rejection. Minor damage on threads beyond the first three from the undercut end may not be cause for rejection if the damage can be repaired during the thread gauging process in 8.4.4.

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8.3 Electromagnetic Inspections

8.3.1 Eddy Current Inspection

An Eddy Current Reference Standard should be used to ensure that the system is capable of detecting gross material variations

lndicated wear that exceeds allowable diameter dimensional tolerances but is less than 20% of the rod cross-sectional area shall be downgraded to Class II or rejected. Indicated wear that exceeds 20% of the rod cross-sectional area but is less than 30% of the rod cross-sectional area shall be downgraded to Class III or rejected.

Gross material variation indications within individual rods that are detected by eddy current inspection require follow-up visual inspection before being rejected or downgraded.

NOTE Other methods may be used to identify changes in diameter as long as they have the demonstrated capability to identify the diameter variations described aboye.

8.3.2 Electromagnetic Flux Leakage Inspection

Calibrate the inspection equipment with a reference standard of the same diameter as the rods to be inspected. Run the reference standard at the start and end of each day, at any change in rod size, after any breakdown, after breaks and lunch and after every 100 rods. An electromagnetic flux leakage reference standard should be used to ensure that the system is capable of detecting the following artificial discontinuities.

a) A 1/32 in. drilled hole, 0.020 in. deep.

b) Proof of system linearity shall be demonstrated by a series of 1/16 in. diameter drilled holes with depths ef 0.015 in., 0.020 in., 0.030 in., 0.040 in.and 0.050 in. The bottoms of the holes may have up to a 30° angle from the longitudinal axis of the rod.

c) Proof of system sensitivity shall be demonstrated by detection of transverse notches of 0.010 in. width with depths of 0.005 in., 0.010 in. and 0.020 in. The notches should be detectable using a minimum signal-to-noise ratio of 2:1. Notches should be machined with square sides.

d) All artificial discontinuities should be spaced a minimum of 18 in. apart and at least 2 ft from the end of the rod. All dimensions shall have a tolerance of —0.001 in. to +0.002 in.

A dynamic calibration shall be performed by inspecting the reference standard in four quadrants at line speed. The artificial discontinuities should produce linear indications on a strip chart or computer display.

In the event that calibration verification is found to differ by more than 15% from the previous calibration, all rods inspected since the previous calibration shall be reinspected.

During inspection, all indications exceeding the defect threshold as noted during calibration shall be cause for further examination by visual and/or magnetic particle methods.

a) All cracks shall be cause for rejection in all classes.

b) Mechanical damage that leaves sharp indications on the rod body shall be cause for rejection in all classes.

c) Loss of cross-sectional area due to corrosion, wear, defects, etc. greater than 0.020 in. shall be cause for downgrading to Class II or for rejection.

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12


d) Wear hetween 20% and 30% reduction in cross-sectional area or corrosion pits of 0.040 in. to 0.060 in. shall be cause for rejection or downgrading to Class III.

e) After electromagnetic flux leakage inspection is completed, rods should be demagnetized to less than 30 gauss as measured with a Hall-effect electronic gauss meter. Measurements made with alternate instruments, such as a mechanical magnetometer, should be capable of making readings ot equivalent accuracy.

8.4 Pin End Inspections

8.4.1 Preparation

Rod pin threads and shoulders shall be cleaned to bright metal.

8.4.2 Inspection Methods

The segment of the sucker rod pin end, upset area and rod body, not inspected by the electromagnetic system, should be inspected by fluorescent magnetic particle inspection, using a longitudinal magnetic field or other similar techniques mentioned in 8.1.1.

8.4.3 Pit Gauge

The depth of stampings, makeup marks, etc., should be confirmed with a pit gauge prior to rejection:

a) any corrosion found in the thread relief area with a depth greater than 0.005 in. shall be cause for rejection or downgrading as directed by the user;

b) wear measuring greater than 0.020 in. on the pin shoulder shall be cause for rejection or downgrading as directed by the user;

c) mechanical damage or wear on the upset areas of a rod shall be cause for rejection for all rods except for Class III rods.

8.4.4 Thread Gauging

Sucker rod pin threads should be checked with API P6 and P8 "go" and "no-go" ring gauges to verify that the threads are properly manufactured and a feeler gauge should be used to confirm the pin shoulder is in compliance with API 11B.

A coupling that has been verified on each shift with API B2 and B6 working gauges may be used to gauge pin threads of used sucker rods for complete make up. If shake is noted with the verified coupling, an API P6 working gauge shall be used to check for proper thread height.

At the end of each shift, the coupling used to gauge pin threads shall be reverified using API B2 and B6 working gauges. If the coupling is out of tolerance, all used sucker rod pin ends inspected since the previous coupling verification shall be reinspected to ensure proper pin make up dimensions.

Thread damage on the first three threads from the undercut end shall be cause for rejection except for Class III rods.

There can be no more than three threads in a plane with minor damage that can be repaired usíng a thread chaser or other similar implement. At no time are files to be used to dress thread areas.


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RECOMMENDED PRACrICE Furt CARE AND riANuLiNu ur SOCKER RC.)DS 13

8.5 Coupling Inspection

8.5.1 General

Sucker rod couplings should be visually examined for wear and/or corrosion. Wear that reduces the outside diameter of a T-type coupling to —0.010 in. of nominal OD ()I` the outside dig,meter of the rod pin shoulder or wear through the spray metal coating of an SM coupling is cause for rejection.

8.5.2 Inspection Method

Sucker rod couplings should be magnetic particle inspected using a circular field or inspected using demonstratively comparable techniques. Any relevant magnetic particle indication is cause for rejection.

8.5.3 Gauges

API B2 and B6 "go" and "no-go" box plug gauges should be used to check coupling threads and parallelism in accordance with API 11B.

A rod pin end that is verified each shift using API P8 and P6 working gauges may be used to gauge coupling connections for complete makeup when inspecting used couplings.

At the end of each shift, the pin end used to gauge coupling connections shall be reverified using API P8 and P6 working gauges. If the pin is out of tolerante, all used sucker rod couplings inspected since the previous pin verification shall be reinspected to ensure proper coupling make up dimensions.

8.6 Acceptance Criteria

8.6.1 New Rods

New rods shall meet all requirements of API 11B. New rods may be inspected using the procedures in this section but rods failing the inspection process must be checked with inspection equipment that meets the requirements listed in API 11B before they can be rejected.

8.6.2 Used Rods

Used rods can be either downgraded or rejected by the inspection processes listed in this section. Downgraded rods can be used in less severe operating conditions at the discretion of the user.

8.7 Completion of Inspection

8.7.1 General

If there is a possible claim after the inspection company has finished inspecting rods and/or couplings, the user representative, together with the manufacturer's representative and the inspection company's personnel should examine all rejected sucker rods and/or couplings to confirm they do not meet test specifications. The user representative will then decide what action to take on the rejected sucker rods and/or couplings.

8.7.2 Rod Rejection

Rejected rods shall be segregated from acceptable rods and either bundled and tagged accordingly or marked within 18 in. of either pin shoulder with easily identifiable red paint.

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14 API RECOMMENDED 1"RACTICE 11 BR

8.7.3 Lubrication

The pin ends of good rods shall be lubricated with an anti-galling thread compound prior to the installation of pin protectors.

8.7.4 Corrosion Inhibitor

Rods that pass inspection shall be completely coated with an atmospheric corrosion inhibitor and allowed to dry.

8.7.5 Color Coding

Rods that pass inspection shall be color coded with paint within 18 in. of the pin shoulder to designate the rod grade and class:

a) for Class I rods, a single band shall be used;

b) class II rods shall have two bands;

c) class III rods shall have three bands;

d) for rods manufactured to API standards, color coding shall be consistent with API 11B as shown in Table 5;

e) a color coding scheme should be selected to uniquely identify the type and manufacturer of rods that are not manufactured to API 11B.

Table 5—Color Coding

Chemical Composition Color

API Grade C White

API Grade K Blue

API Grade D a—Carbon Steel (AISI 10XX or 15XX) Brown

API Grade D a—Chrome-Moly (AISI 41XX) Yellow

API Grade D a—Special Alloy Orange

a See 3.4.5 for chemical and mechanical properties.

9 Corrosion Control

See Annex A for NACE SP0195-2007, Corrosion Control of Sucker Rods by Chemical Treatment.

10 Transportation and Handling, Storage, Running and Pulling

10.1 General

Rods should be inspected (see Section 8) on delivery and thereafter as necessary to ensure that damaged rods are not placed in regular storage or in service.

In all handling operations, care should be exercised to prevent sucker rods or rod ends from contacts which might cause nicks or bends, or injury to the threads by jamming of the thread protectors. Further, the sucker rods should never be handled in such a manner as to cause damage. Kinked, bent, or nicked rods are permanently damaged and require reinspection to determine their serviceability.

Packaged rods should be handled and stored as a packaged unit, until the rods are to be run in the well. When removing the rods from the package, care should be exercised to use proper tools to prevent damage, especially by nicking.


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Sucker rods delivered from the manufacturen are provided with thread protectors on both the pin and coupling ends. Whenever observed to be without such protection, the sucker rod should be inspected and if undarnaged, the protectors replaced. Protectors should not be removed, except for inspection purposes, until the rods are hung in the derrick or mast in preparation of running.

Thread protectors, couplings, upsets, and wrench squares should never be harnmered for any rcason. One harnmer blow can so damage any part of a rod or coupling as to result in premature failure.

10.2 Handling

Care should be taken to avoid damaging the sucker rods when removing bulkheads and tie-downs used to secure the rods during shipment and transport. Cross supports, spacers and blocks contacting the sucker rods should be of material that is non-abrasive to the rods.

Sucker rods in packages should always be lifted and laid down with a handling device so designed as to support the package without damage to the rods.

Unpackaged sucker rods should be handled individually. They should never be thrown nor flipped from or onto a railway car truck or stack. During all handling operations, the sucker rods should be supported at least at two points to prevent excessive sagging and/or damaging contacts of any nature. Skids should be made of material not abrasive to the rod.

When rods are unloaded at the well, they should it is recommended they be placed on a transportable service rack. They should be located in such position they will not be damaged by a vehicles nor where heavy equipment may be set or dropped on the rods. Particular care should be taken to ensure the rods are not walked on by personnel.

10.3 Transportation

Transportation handling of packaged sucker rods should provide blockage directly under the crosswise supports of the package to ensure that the rods do not contact the blockage. Sucker rod packages should be stacked so that the bottom supports rest squarely on the top supports of the next lower package. Tie-down chains, straps, or cables should pass over the crosswise supports without contacting the rods.

Transportation handling of unpackaged sucker rods should provide cross supports near the rod ends and at least two other equally spaced intermediate positions. When flat beds are used, the supports should be of such thickness as to prevent the rod ends or couplings from resting directly on the bed. The spacers should be long enough to extend a few inches beyond the stack on both sides. If the spacers are not notched, the outside rods in each layer should be chocked with blocks to prevent the rods from rolling off the spacer. Tie-down chains, cables, or straps should pass over the ends of the spacers and should be prevented from contacting the sucker rods.

When sucker rods are loaded for transport for field distribution, the same precautions apply in loading, transporting, and unloading as for placing new rods in storage.

10.4 Storage

Rods should be stored separately according to grade and size. They should be stored in such locations and in such manner as to minimize deterioration from exposure to acid or other corrosive atmospheres. They should be stacked off the ground on racks or sills made of or surfaced with a material not abrasive to the rods.

For packaged rods, a rack or sill should be provided Linde( ecit..11 support of the package. The packages should be stacked so that the supports are in vertical alignment. See API 11B for packaging requirements.

For unpackaged rods, at least four rack or sill supports should be provided and the end supports should be located approximately one foot from the rod ends. The rod layers should be separated by spacers placed directly aboye the rack or sill. The spacers should be thick enough to prevent the rods from contacting those in adjacent layers. If the

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16


spacers are not notched, the outside rods in each layer should be chocked with blocks to prevent the rods from rolling off the spacers.

Stored rods should be inspected at regular intervals. Any rust should be removed with a wire brush and a suitable rust preventative which will not become fluid at less than 125°F (52°C) applied.

Sucker rods returned to storage after use should be cleaned, lubricated, and covered with clean, undamaged thread protectors. The sucker rod surfaces, including threads, should be covered with a rust preventative which will not become fluid at less than 125°F (52°C).

NOTE It is good practice to perform an inspection of sucker rods and couplings after use and before storage, see Section 10 for guidelines on this processing.

10.5 Running and Pulling

Alter removal of the thread protectors, inspect rods for damage and clean as necessary. If rods are being rerun the rod pin thread and face and, the coupling threads and faces should be thoroughly cleaned. Make certain that wire brushes are not used. Threads and faces of couplings and pins should be inspected for damage.

Running and pulling tools should be suitable for the job, in good condition and clean. These include but are not limited to: rod elevators, hooks and wrenches. They should be inspected regularly for wear and other damage, and be repaired or replaced when their use may result in damage to the rods. Special attention should be given to elevators and hooks to avoid dropping the rod string.

Single rods should be tailed into the mast. Special care should be taken to ensure they do not touch the ground, other rods, or any part of the mast. Also during tailing do not allow the rods to be raised with elevator latches. For maximum efficiency and to minimize the risk of damage to the rods, it is recommended suitable hangers be provided in the mast.

To help avoid cross threading, care should be taken that the handling equipment is positioned so that the rods, when hanging straight and free (without slack) in the rod elevators, are centered directly over the well bore. Should cross threading occur, the connection should be broken, a die run over the pin and a tap into the coupling; after which the threads should be cleaned, inspected and lubricated prior to storage or transport.

To obtain satisfactory results in makeup of rod connections, the joint must be clean, undamaged, properly lubricated and have a free-running fit to shoulder contact if applied circumferential displacement is to sufficiently preload the joint to prevent shoulder face separation during pumping. During makeup, the joint should be observed to determine that the coupling face makes proper contact with the shoulder face. When proper contact is not made, the joint should be broken, cleaned, inspected and re-lubricated.

In breaking the joints, care should be exercised that the threads and contact faces are not damaged. When breaking out connections, particularly with hand wrenches, the joint should never be hammered, and the proper coupling and rod wrenches, with the assist of cheater bars, should be used if a joint is unbreakable by ordinary procedure. Any hammered or over-torqued couplings should be discarded since hammering and over-torquing damages the coupling, faces, threads, and may result in premature failure.

Whenever rods are pulled, they should be carefully inspected for damage before being rerun. Kinked, bent, or nicked rods are permanently damaged and should be discarded. (See Section 8 and API 11B.) If a rod hanger is not provided, the rods should be pulled and laid down in singles. The same care should be exercised in handling and stacking the pulled rods as herein recommended for new rods.


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RECOMMENDED PRACUIGE l'UF< CiArce ANL/ i iAIJULING r SUCKER RODS

17

11 Bibliography

[1] Gipson, F.W and H.W. Swairn, "Beam Pump Fundamentals," Southwestern Petroleum Short Course, Texas Technological College, Lubbock, Texas, April 17 — 19, 1969

[2] Goodman J. "Mcchanics Applied to Engineering," lst cd. London, Longmans, Orcen and Co., 1899

[3] Kommers, J.B., "Effect of Range of Stress and Kind of Stress on Fatigue Life," Proceeding ASTM Vol. 20, 1930, Philadelphia, p. 272

[4] NACE MR0175, Sulfide Stress Corrosion Cracking Resistant Metallic Materials for Oil Field Equipment, Houston, 1980

[5] Hermanson, D.E., Petroleum Engineering Handbook, H.B. Bradley, Editor, Society of Petroleum Engineers, Richardson, Texas, 1987, pp. 9-5, 9-8

[6] NIST, National Institute of Standards and Technology, 100 Bureau Drive, Gaithersburg, Maryland 20899-1070

[7] Stuart and Lloyds, Limited, A Guide to Non-Destructing of Tubes, JSB48



Annex A

NACE International SP0195, Corrosion Control of Sucker Rods by Chemical Treatment 3

NACE International NACE Standard SP0195-2007

Standard Practice Corrosion Control of Sucker Rods by Chemícal Treatment

This NACE International standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. lts acceptance does not in any respect preclude anyone, whether he 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 International 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 International assumes no responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE International interpretations issued by NACE International in accordance with its governing procedures and policies which preclude the issuance of interpretatíons by individual volunteers.

Users of this NACE International standard are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determíning their applicability in relatíon to this standard prior to its use. This NACE International 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 International 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 International standards are subject to periodic review, and may be revised or withdrawn at any time without prior notice. NACE International requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication. The user is cautioned to obtain the latest edition. Purchasers of NACE International standards may receive current information on all standards and other NACE International publications by contacting the NACE International First Service Department, 1440 South Creek Dr., Houston, Texas 77084-4906 (telephone: +1 281/228-6200).

Reaffirmed 2007-03-11 Reaffirmed 2001-03-15 Approved March 1995

NACE International 1440 South Creek Drive

Houston, Texas 77084-4906 +1 (281) 228-6200

ISBN 1-57590-121-8 © 2007, NACE International

3 Reprinted with permission from NACE International (formerly the National Association of Corrosion Engineers), 1440 South

Creek Drive, Houston, Texas 77218-8340, www.nace.org.

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NACE Standard SP0195 Foreword

This standard practice presents corrosion inhibition, wear reduction, and corrosion prevention techniques for use from the manufacturing of bare steel sucker rods and couplings through installation and service in the well. Although aluminum, fiberglass, coated sucker rods, and high-alloy sucker rods are not specifically addressed in this standard,

many recommendations contained herein may be applieo to such sucker rods, as appropríate, at the users

discretion. Throughout this standard the words "sucker rod" or "rod" will be used in the above-described context.

This standard was originally prepared as NACE Publication 1D167 by NACE Task Group T-1D-3 for inclusion in API RP 11BR. Beginning in 1988 it was updated for the revision of API RP 11BR by NACE Task Group T-1D-35, a component of Unit Committee T-1D on Corrosion Monitoring and Control of Corrosion Environments in Petroleum Production Operations, for conversion to a standard practice, and this standard was originally issued in 1995. This standard was also balloted to and approved by API for inclusion in API RP 11BR. lt was reaffirmed in 2001 and 2007 by Specific Technology Group (STG) 31 on Oil and Gas Production — Corrosion and Scale Inhibition and is issued by

NACE International under the auspices of STG 31.

This standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. lts acceptance does not in any respect preclude anyone, whether he has adopted the standard or not, from manufacturing, marketing, purchasing, or using products, processes or procedures not in conformance with this statement. Nothing contained in this NACE International 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.

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. Should is used to state something considered good and is recommended but not mandatory. May is

used to state something considered optional.

NACE International Standard Practice

Corrosion Control of Sucker Rods By Chemical Treatment

Contents

1) General

2) Atmospheric Corrosion Control During Transportation and Storage

3) Well Servicing

4) Downhole Corrosion Inhibition

5) Inhibitor Selection

6) Evaluation of Inhibitor Programs

References

Bibliography

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RECOMMENDED PRACTICE FOR CARE AND HANDLING OF SUCKER RODS

21

A.1 General

Corrosion can lead to serious multiple failures of oil well sucker-rod strings and other equipment. The use of chemical corrosion inhibitors has proved to be a cost-effective approach to minimize corrosion damage and to extend the life of the downhole equipment. This standard addresses corrosion control for atmospheric conditions and downhole environments, treatment procedures, inhibitor selection, arid cva uatian cf corrosion inhibitor programs. Other factors to control failure of sucker-rod strings are addressed in API 11BR.

Corrosion inhibitors fall into many chemical classes that may be physical or health hazards. The handling precautions recommended by the manufacturer in the material safety data sheet (MSDS) shall be followed. In all cases, protection of the environment shall be considered.

In all operations discussed in this standard, corrosion inhibition is enhanced when sucker rod and coupling surfaces are free of scales and deposits.

Care should be taken to prevent air entry into the well to avoid oxygen-accelerated corrosion. Air entry can occur if casing vents are left open to the atmosphere or if the wellhead seals do not hold a vacuum.

A.2 Atmospheric Corrosion Control During Transportation and Storage

Hydrocarbon-renovable coatings (HRC) 4 such as atmospheric corrosion inhibitors or temporary protective coatings should be used to prevent corrosion damage to sucker rods before they are placed in service. These coatings should be applied before transportation of the sucker rods and should be maintained during storage. HRC can also be used to minimize atmospheric corrosion during field service of the sucker rods.

The manufacturer should provide sucker rods and couplings free of mill scale and with a suitable HRC applied to all exposed surfaces. The HRC should be adequate to provide protection against corrosion for a minimum of one year under humid atmospheric conditions at the storage site 5. Acceptable HRCs shall be readily removable using hydrocarbon solvents. HRCs that do not obscure manufacturer markings are preferred.

The vendor, supplier, or agent shall inspect shipments and warehouse stocks of sucker rods and couplings for visible signs of physical damage and corrosive attack. The vendor also shall take necessary action to clean rust spots and repair damage in the HRC.

The purchaser should inspect sucker rods and couplings upon receipt for physical damage and corrosion attack. The purchaser should also make periodic inspections of the sucker rods and couplings and maintain the HRC integrity during storage.

Used sucker rods that are stored for future service should be cleaned and coated for protection against atmospheric corrosion. Corrosion protection for less than one year can be obtained by dipping or spraying the rods and couplings with a suitable HRC atmospheric corrosion inhibitor. However, storage for more than one year requires the use of HRC similar to those recommended aboye.

A.3 Well Servicing

A.3.1 General

Sucker rods should be protected alter removal fron vvell well-servicing operations. This is especially important in areas where hydrogen sulfide (H2S) and/or carbon dioxide (CO2) is produced. However, the corrosion damage may frequently be caused by atmospheric oxidation. In some cases, protection from atmospheric oxidation can be achieved

4 For the purposes of this standard, HRC refers to materials that are removed from the sucker-rod surface because they are soluble in produced hydrocarbon. The materials are not necessarily formulated in a hydrocarbon solvent.

5 Performance assessment methods are available from standards-writing organizations such as the American Society for Testing and Materials (ASTM) International, 100 Barr Harbor Drive, West Conshohocken, PA 19428-2959.

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22 API kECOMMENDED HRACTICE 11 tsR

by pumping oil with a high concentration of corrosion inhibitor into the tubing immediately before the rods are pulled. Alternatively, the rods may be coated with a mixture of oil and corrosion inhibitor after the rods are laid clown.

k3.2 Corrosion Inhibitor

Failures in threaded connections because of impr'epel nlakeup or corrosion fatigue can occur vvell fluids ente.- the couplings during pumping. Corrosion inhibitor should be applied during sucker-rod connection makeup to minimize corrosion inside the coupling. The couplings and pin ends can be dipped, brushed, or sprayed with a mixture of oil-soluble, film-forming corrosion inhibitor in refined oil or with inhibited grease. Sealants, such as thread dope, which contain a high level of solids, are not recommended for sucker-rod threads. The procedure for selecting an inhibitor can be found in NACE Standard MR0174, Selecting lnhibitors for Use as Sucker-Rod Thread Lubricants. The sucker-rod manufacturer may be consulted for assistance in selecting commercial lubricants. Use of too much inhibitor-oil mix in the coupling cavity interferes with proper makeup. The procedure for proper makeup of sucker-rods is found in API 11BR. Proper circumferential displacement develops sufficient sealing force at the shoulders, which tends to exclude well fluids from the threads.

A.3.3 Pulling and Running

When new rod string is run or each time the rods are pulled and rerun, the corrosion inhibitor film should be established (or reestablished) on downhole equipment. The rods should be examined for physical and corrosion damage each time they are run.

To provide initial protection to rods during and following installation, one approach is to add an oil-soluble corrosion inhibitor mixture [19 to 38 L (5 to 10 gal U.S.) of chemical in diesel or lease crude] to the tubing before running the rods (or to the casing before running tubing and rods). As the rods pass through this inhibitor mixture, a protective film is applied. If there is no packer, additional benefit may be obtained from the inhibitor by circulating one tubing volume óf fluid into the annulus before the well is returned to production.

An alternate initial treating practice is to add 19 to 38 L (5 to 10 gal U.S.) of inhibitor to the casing/tubing annulus and eirculate the well to displace the annular volume before beginning production to the battery.

A.3.4 Program Resumption

Áfter the well is placed back on production, the selected treatment program should be resumed.

A.4 Downhole Corrosion Inhibition

A.4.1 General

There are many corrosion-inhibiting products and application techniques that are effective in protecting downhole production equipment. Selection of a particular method should be based on the specific application and the economics of the treatment program. These economic evaluations should consider the effectiveness of the treatment program as it relates to equipment replacement frequency and lost production.

A.4.2 Batch-and-flush Treatment

The batch-and-flush treatment is most widely used for rod-pumped wells. Normally in this technique, an oil-soluble, water-dispersible corrosion inhibitor is injected into the well annulus and flushed down to the fluid level. The flush fluids may be chemically oxygen-scavenged produced brine, chemically oxygen-scavenged fresh water, crude oil from a treater truck, or produced fluids bypassed from the well's flowline. Water-soluble inhibitors are generally less film-persistent than oil-soluble inhibitors, and therefore are normally not recommended for the batch-and-flush treatment.




Not for Resale, 09/18/2013 09A9:14 MDT

RECOMENDE° PRACTICE FOR CARE AND HANDLING OF SUCKER RODS 23

Specific design of a treating program (i.e. inhibitor selection, inhibitor dosage, treating frequency) should include considerations such as oil/water ratio, fluid corrosiveness, fluid leve) aboye the pump, rod loading, etc. Inhibitor selection is covered in A.5. Typical inhibitor dosage and frequency are as follows.

a) One common practice for selecting inhibitor dosage for the initial program is to use an inhibitor concentration that is equal to 25 ppmv 6 based on the total fluid production between treatments. A minimum inhibitor volume of 4 L (1 gal U.S.) per treatment is recommended. For example, a well producing 64 m3/d [400 barreis of fluid per day

(BFPD)] would require about 11 L (3 gal U.S.) of inhibitor per week.

b) Treatment frequency usually varíes with the well production rate. Typical treating frequencies are every other week for wells producing less than 16 m3/d (100 BFPD), weekly for wells producing 16 to 48 m3/d (100 to 300 BFPD),

and twice weekly for wells producing 48 to 80 M3/d (300 to 500 BFPD). When the total produced fluid is more than

80 M3/d (500 BFPD), some operators consider continuous treatments.

c) Adjustments in dosage and frequency to optimize treatment effectiveness should be based on corrosion-monitoring results (see A.6 on Evaluation of Inhibitor Programs).

Flush volumes are often calculated based on well depth and annular pumping fluid level. For example, in low-fluid-level wells [less than 150 m (500 ft) aboye the pump], typical flush volumes are 80 to 160 L (0.5 to 1.0 bbl) of flush (produced water or oil) per 300 m (1000 ft) of well depth. Wells with more than 150 m (500 ft) of fluid aboye the pump;

may require more overflush. The goal is to displace chemical to the pump intake. The flush can be supplied by pump truck or the well can be circulated into the annulus (through a chemical pot if one is used) for a time to achieve the desired volume. Care should be taken not to introduce air into the well during the flush process. It may be necessary

.' to chemically remove oxygen from the flush fluid when a pump truck is used. If this is done, sufficient time should be allowed for the oxygen-removal process to take place before the well is treated.

1 he casing and tubing annulus should be preflushed with the tlush fluids before the inhibitor is introduced to ensure that the inhibitor reaches the fluid level.

If the well is pumped high (i.e., pump set well aboye the production zone) a tailpipe should be attached below the pump to ensure that the lower portion of the casing is exposed to the inhibitor treatment. However, this can significantly reduce the pump's volumetric efficiency if the liquids entering the tailpipe contain solution gas.

A.4.3 Batch-and-circulate Treatment

The batch-and-circulate treatment procedure is generally used to treat problem wells in which batch-and-flush treatments are not effective. This treatment procedure is the same as batch-and-flush treatment except that, rather than flushing after treatment, a Iarge portion or al! of the produced fluids are diverted from the flowline to the tubing/ casing annulus for a specific circulation period. Production is delayed during the circulation period.

Although there are many variations of the batch-and-circulate treatment, the most common procedure is to circulate the well until the injected inhibitor slug reaches the surface and is returned to the annulus. The well is then placed on production.

The inhibitor volume required for this treatment varíes according to the fluid volume in the annulus and the well depth. A basic goal is to contact well surfaces with an inhibitor concentration of more than 1000 ppmv for one hour or longer. The literature contains descriptions of other methods for determining inhibitor dosages and circulation times [Cameron, et. al]. Inhibitor concentration and treatment frequency are similar to those for the batch-and-flush treatment method described in A.4.2. Treatment dosage and frequency should be optimized to increase the effectiveness on each well.

6 ppmv = parts per million by volume; 1 ppmv = 0.001 L/m2 or 0.0042 gal U.S./100 bbl.


Licensee=Occidental Oil & Gas/5910419104 Not for Resale, 09/18/2013 0149:14 MDT

14

API RECOMMENDED PRACfICE '11BR

Possible disadvantages of the batch-and-circulate treatment are the manpower required to circulate the well and the delayed production. The batch-and-circulate treatment may not be practica! for wells in which a long circulation time is required and/or a large delayed production volume results. Also, some wells build excessive pressure during circulation and are generally not treated using this method. In these cases, continuous treatment as described in A.4.5 should be considered.

A.4.4 Automated Treatment (Semi-batch)

Equipment is available for automatic injection of a preselected amount of inhibitor into the annulus, followed by produced fluid circulation for a preselected time. These devices permit treatment as often as desired. An economic analysis should be done to determine cost effectiveness.

A.4.5 Continuous Treatment with Bypass Flush

Typically, continuous flush is applied to wells with production exceeding 15 M3/d (100 BFPD). In this procedure, a chemical feed pump is used to continuously inject inhibitor into a small volume of produced fluid continuously bypassed into the casing annulus. The inhibitor feed rate is typically 25 ppmv to 50 ppmv based on total produced fluid volume. Subsequent corrosion-monitoring results should be used to optimize the inhibitor dosage. The volume of produced fluid is not critica!, as long as a positive flow is maintained down the annulus. Initial treatment in wells that do not pump off should include a large batch treatment [e.g., 19 L to 38 L (5 gal to 10 gal U.S.)] to ensure that the annulus is loaded with treated fluid.

A.4.6 Squeeze Treatment

Although it is not a common practice, effective and long-lasting treatments can sometimes be achieved by squeezing corrosion inhibitor mixtures into producing formations. A large volume of inhibitor mixed with crude or diesel is displaced into the formation. A portion of the inhibitor absorbs on the reservoir rock and subsequently desorbs over time to maintain the protective film. Normally, an oil-soluble inhibitor is used. Prior to any squeeze treatment, inhibitor compatibility with reservoir fluids and, more importantly with the formation, should be investigated to minimize formation damage and avoid a decrease in production. Core testing is one method used to assess the effect of the candidate squeeze inhibitor on the formation. Because of concerns such as inhibitor compatibility with formation rock and formation fluids, squeeze treatments are generally used when other treatment methods are not possible or practical. For example, squeeze treatments may be useful when tubing is set on a packer.

A.4.7 Continuous Downhole Injection

Continuous downhole injection utilizes a small-diameter tubing, generally a 6 mm to 13 mm (0.25 in. to 0.50 in.) OD, attached to the outside of the production tubing and connected to a downhole chemical injection mandrel and a chemical injection pump at the surface. This configuration allows a large amount of chemical to be injected in a short period of time to batch treat the production string. Thereafter, the dosage rate can be reduced to a maintenance treatment, typically 25 ppmv based on total fluid.

Adjustments in treatment rates to obtain optimum treatment effectiveness should be based on corrosion-monitoring results.

The inhibitor can be readily changed by flushing the old chemical from the tube ID with a suitable solvent followed by injecting the new chemical at a selected rate.



RECOMMENDED PRACT ICE i-OR CAKE AiNu HANDLINu Ofr SuCKER ROuS 25

A.5 Inhibitor Selection

A.5.1 Types

Most inhibitors used in producing operations are polar organic compounds available in many different formulations. The inhibitor may either he oil-soluble, water-soluble or water/oil dispersible Reggrdless of the type, the inhibitor must:

a) match the application technique; i.e., the solubility and dispersibility must allow the inhibitor to reach the steel surface to form a protective film, and film persistency must be adequate for the selected treatment interval,

b) be compatible with other treating chemicals used,

c) not create an emulsion that is difficult to break, and

d) not exceed target levels for all carryover into injection water.

Thus, care must be taken in selecting the inhibitor.

A.5.2 Testing

Before using an inhibitor in a given field, laboratory and field tests for corrosion-mitigation effectiveness, compatibility with other chemicals, emulsion tendency, and water quality are generally a cost-effective investment. When dilution solvents are used, the tests should be performed using the actual chemical/solvent mixture.

A.6 Evaluation of Inhibitor Programs

The cost effectiveness of treating with the properly selected and applied inhibitor is normally high, with treatments providing excellent insurance against equipment failure and lost production. Proper corrosion control requires the following steps:

a) properly design and operate the beam pump lift system;

b) keep the rod string free of atmospheric corrosion before use;

c) protect the rod string immediately upon installation;

d) use a properly selected and applied corrosion inhibitioil rnethod based on the well's corrosiveness;

e) continue treatment, monitor results (as described below), and adjust the corrosion control program as needed.

Various methods can be used to evaluate inhibitor programs. Well-failure history, visual inspection, changes in production characteristics, pump repair reports, and other equipment service records can be used to evaluate current program effectiveness. Often such records may indicate corrosion problems before the first rod failure occurs.

Other monitoring methods include the use of weight-loss 7 corrosion coupons, evaluation of weight loss of pony rods used as corrosion coupons, iron content analysis of produced fluids, copper-ion displacement tests, hydrogen sensors, galvanic probes, electrical resistance probes, and linear polarization probes.

The efficiency of the treating program should be evaluated by comparing monitoring data with actual well-failure history. It should be noted that surface-installed corrosion-monitoring tools only report corrosion rates for the condition

7 In common terminology, "weight loss" is used to refer to a loss in mass.

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26 API RECOMMENDEID PRACTICE. 11BR

at their point of installation. Often the development of a correlation between surface monitoring results and downhole

corrosion is needed.

Assistance in evaluating inhibitor treatment programs can be obtained by consultation or study. Direct help can be obtained by consultation with recognized corrosion engineers, corrosion consultants, and chemical company service

engineers.

A data and analysis system must be maintained to ensure the successful optimization of the corrosion control

program.

A.7 References

1) NACE Publication 1D167 (withdrawn), Recommendations for Corrosion Control of Sucker Rods by Chemical

Treatment (Houston, TX: NACE International, 1967).

2) API RP 11BR, Recommended Practice for Care and Handling of Sucker Rods (Washington, D.C.: API).

3) M. Winfield, "Sucker Rod Lubricants," Materials Performance 29, 9 (1990): p. 37.

4) NACE Standard MR0174 (latest revision), Recommendations for Selecting Inhibitors for Use as Sucker Rod

Thread Lubricants.

5) W.J. Frank, "Here's How to Deal With Corrosion Problems in Rod-Pumped Wells," Oil and Gas Journal 74, 22

(May 31, 1976): p. 63.

6) G.R. Cameron, G.S. McNab, L.S. Lam, R.D. Myers, "Optimizing Downhole Corrosion lnhibition Treatments: A

Well Circulation Equation Based on Field Tracer Studies," Corrosionl88, paper no. 100 (Houston, TX: NACE,

1988).

7) J. Knox, R. Stout, "Simple Screening Test for Determination of Inhibitor Film Persistence," Corrosion 16, 10

(1969): p. 5541.

8) E. D. Junkin Jr., D.R. Fincher, "Oil Field Corrosion Inhibitors Evaluated by Film Persistency Test," Materials

Protection 2, 8 (1963): p. 18.

9) L.S. Shehorn, "Corrosion Monitoring on Rod-Pumped Wells Using Linear Polarization Probes," 1980 SPE Conference, paper no. SPE 9363 (Dallas, TX: Society of Petroleum Engineers (SPE) 8 of American Institute of

Mining, Metallurgical, and Petroleum Engineers (AIME) 9, 1980).

10) R. Wieland, J.R. Bruce, "Corrosion Inhibitor Screening Test for Oil Wells," Materials Protection 1, 8 (1962): p. 24.

11) NACE Standard RP0775 (latest revision), Preparation and Installation of Corrosion Coupons and

Interpretation of Test Data in Oilfield Operations (Houston, TX: NACE).

12) J.M. Kilpatrick, "Measure Corrosion Rate Now," Oil and Gas Journal 62, 11 (March 15, 1964): p. 155.

13) Corrosion of Oil and Gas Well Equipment (Houston, TX: NACE Washington, D.C.: API, 1968).

14) H.E. Waldrip, "Petroleum Production Corrosion," Materials Protection 5, 6 (1956): p. 8.

8 Society of Petroleum Engineers, P.O. Box 833836, Richardson, Texas 75083. 9 American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME), 345 E. 47th St., New York, NY 10017.


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RECOMMENDED PRACTICE FOR CARE AND HANDLING OF SUCKER KODS 2/

15) D.T. Moore, H.G. Byars, "Oilfield Corrosion—Measurement Records Vital for Effective Programs" (Parí 1), Oil and Gas Journal 88, 22 (July 1990): p. 97, and "Oilfield Corrosion—Econornic Importance in Selecting Monitoring Techniques" (Part 2), Oil and Gas Journal 88, 32 (August 1990), p.68.

A.8 Bibliography

Barrett, J.P. "Oil and Gas Well Corrosion lnhibitors," Materials Protection 5,7 (1966): p. 43.

Billings, W.E., D. Morris. "Effect of Acid Volume and Inhibitor Quantity on Corrosion of Steel Oilfield Tubing in Hydrochloric Acid," Corrosion 17, 5 (1961): p. 208t.

Bush, H.E., J.C. Cowan. "Characterization and Performance Studies: Corrosion lnhibitors in Oilfield Fluids," Materials Protection 3, 9 (1966): p. 28.

"Cooperative Evaluation of Inhibitor Film Persistency Test," Report of NACE Unit Committee T-1D on Control of 011field Equipment Corrosion by Chemical Treatment. Materials Protection 8, 10 (1966): p. 69.

Evans, S., C.R. Doran. "Batch Treatment Controls Corrosion in Pumping Wells," World Oil (February 1, 1984): p. 55.

Fincher, D.R. "Special Techniques Cut Corrosion Costs," Petroleum Engineer 33, 2 (1961): p. B-30.

Gordon, B.E., P.J. Raifsnider, D.L. Lilly, "Corrosion Monitoring in Oil Wells with a Radioactive Specimen." Materials Protection 6, 11 (1966): p.21.

Kerver, J.K., H.R. Hanson, "Corrosion Inhibitor Squeeze Technique—Field Evaluation of Engineered Squeezes," Journal Petroleum Technology 17, 1 (1965): p. 80.

Kerver, J.K., F.A. Morgan III. "Corrosion Inhibitor Squeeze Technique: Laboratory Adsorption-Desorption Studies," Máterials Protection 4, 7 (1965): p. 69.

Larrison, K.L. "Oil Well Corrosion Treatment—Polarization Testing for Field Testing Inhibitors," Materials Protection 6, 4 (1967): p. 61.

Maradudia, A.P. "Dril) Pipe, Casing, Tubing, Sucker Rods: Corrosion Failures and Methods of Combatting Corrosion," Materials Protection 4, 12 (1965): p. 45.

Martin, R.L. "Inhibition of Corrosion Fatigue of Oil Well Sucker Rod Strings," Corrosion/79, paper no. 15. Houston, TX: NACE 1979.

Mehdizadeh, P., R.L. McGlasson, J.E. Landers. "Effect of Organic Corrosion lnhibitors on Corrosion Fatigue," Corrosion 23, 4(1967): p. 53.

Mehdizadeh, P., R.L. McGlasson, J.E. Landers. "Corrosion Fatigue Performance of a Carbon Steel in Brine Containing Air, Hydrogen Sulfide, and Carbon Dioxide," Corrosion 22, 12 (1966): p. 325.

Moore, K.H. "Stop Sucker Rod Failures to Save Money," Petroleum Engineer 7 (1961).

NACE Publication 1C184. Monitoring Infernal Corrosion in Oil and Gas Production Operations with Hydrogen Probes. Houston TX: NACE, 1984. Also Materials Performance 23, 6 (1964): p. 49.

Nestle, A.C. "Organic Inhibition of Oil and Gas Wells." Materials Protection 7, 1 (1968): p. 31.

"Protective Coatings in Petroleum Production," Report of NACE Committee T-6E on Protective Coatings in Petroleum Production. Corrosion 17, (1961): p. 261t.


licensee=Occidental Oil & Gas/5910419104 Not for Resale, 09/18/2013 09:49:14 MDT

28


Raifsnider, P.J., V.P. Guin, C.L. Barr, D.L. Lilly, "Radioactive Tracer Studies on Squeeze Inhibition of Oil Wells." Materials Protection 4, 7 (1965): p. 18.

Steward, W.B., "Sucker Rod Failure." Oil and Gas Journal 71, 15 (April 9, 1973).

Sucker Rod Symposium. Petroleum Equipment and Services 23 (July/August 1965): pp. 19 — 30.

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Used Sucker Rods

Equipment Required: 1. Standard personal protective equipment 2. Wire brush capable of cleaning external and internal threads 3. Full body thread gauge for pin and box and profile thread gauges. New rods may

be checked by API P8 Go gauge. Used rods may be checked with the same gauge or a API P6 Not Go gauge. Vendors may also have acceptable gauges.

4. A feeler gauge with 0.05mm (0.002") accuracy 5. Micrometers if inside and outside box diameter is to be checked. 6. Measuring tape or strap longer than longest rod length. 7. Permanent marking pen or paint device. 8. Forms for recording data on the rods.

Checks: 1. Record metallurgy if available. 2. Reject rods that are bent, have damage from impacts, or are worn more than 5%

of body or coupling thickness. 3. Clean pin connection surfaces of debris.

a. Reject the rod if there is corrosion or pitting in the threads. b. Minor mechanical damage may be repaired by chasing the treats with a

properly sized thread die. c. Insert an external thread gauge onto the pin end until the shoulder is

engaged or the gauge is hand tight. Check for tightness of fit (can it be shaken or moved side-to-side or back and forth?). Downgrade the rod or reject if excessive looseness is found in the connection.

d. Use a feeler gauge to measure standoff from the connection shoulder to the face of the thread gauge. Any clearance of 0.05 mm or more is cause for rejection if the joint will not be repaired.

4. Clean box connection a. Reject the rod if there is corrosion or pitting in the threads. b. Repeat procedure in #3 with a internal gauge.

5. Examine connection and at least the first 50 cm of rod body from the wrench flats. Reject rod if the following defects are found: body cracks or splits; severe wrench, tong or slip marks more than 2 mm deep; corrosion pitting more than 1 mm deep;

6.

For Corrosion: MR0176-2000 Metallic Materials for Sucker-Rod Pumps for Corrosive Oilfield Environments

Again, for pipe, we have certainly 'logged' used pipe in the past (i.e. put through ultrasonic inspection for wall thickness, defects/cracking, etc.) and I am sure something could be generated. However, again I am not aware of any written procedures that are available.

Tubing - API 5C1 New Rods - API 11B Used Rods - API 11BR

0% - 15% Wall Loss - Yellow Band (Used for downhole operations and some line pipe applications) 16% - 30% Wall Loss - Blue Band (Shallow downhole operations and line pipe applications) 31% - 45% Wall Loss - Green Band (Low pressure fine pipe applications)

We only inspect to #1 grade of rod inspection which is less than .020" body defect.

Of course with the aboye inspections, there are special end arca and coupling inspections.

If you would like anything more detailed on tubular/rod inspection, please let me know. The aboye data is general information concerning our inspection.

SPE SPE-134975-PP

Sucker-Rod Pumping Failures Diagnostic System G. V. L. Moisés, SPE, and S. F. A. Andrade, Petrobras; A. C. Bicharra, UFF; and Y. S. Ferreira, Schulumberger

Copyright 2010, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibitbn heid in Fbrence, Italy, 19-22 September 2010.

This paper was selected for presentatbn by an SPE program commlttee following revlew of informatbn contained In an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Englneers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this papar without the wrilten consent of the Society of Petroleum Engineers le prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; Illustrations may not be copied. The abstract must contaln conspicuous acknowledgment of SPE copyright.

Abstract A decision support system was developed based on Failure Root Cause Analysis aiming to reduce the mean time between failures (MTBF) of sucker rod pumping wells. It collects, organizes and integrates data about pulling service, failures, diagnosis, and technical observations and uses a combination of Failures Modes and Effects (FMEA) and Fault tree (FTA) analysis techniques to generate diagnosis. The system is based on an ontology that describes the domain, including: equipments, failures modes and causes. The diagnosis is inferred by a specialist system based on production rules and identifies well severity level based on data aggregation algorithms, in particular, k-means, which clusters the behavior of similar wells given the subsurface reservoir and equipment characteristics, type of material installed and the failures characteristics. The sucker rod pumping failures diagnostic system is currently being implemented at Petrobras. Initial results are promising: even during pilot tests, analysts were able to detect problems with manufactures and a lack of synchronicity between component changes.

Introduction Sucker-Rod pumping system is the major artificial lift method in number of well applied in oil fields all over the world. To reduce mean time between failures (MTBF) of sucker rod pumping wells and improve its processes, a decision support system was developed based on Failure Root Cause Analysis. A Sucker-rod pumping ontology that describes the domain, including: equipments, failures modes and causes was developed to support the failures diagnostic system. It collects, organizes and integrates data about pulling service, failures, diagnosis, and technical observations and uses a combination of Failures Modes and Effects (FMEA) and Fault tree (FTA) analysis techniques to generate diagnosis. The diagnosis is inferred by a specialist system based on production rules and identifies well severity level based on data aggregation algorithms, in particular, k-means, which clusters the behavior of similar wells given the subsurface reservoir and equipment characteristics, type of material installed and the failures characteristics. For Electrical Submersible pumping (ESP) sytems, a standardized failure analysis was proposed by Alhanati et al (2001). The sucker-rod pumping failures diagnostic system is currently being implemented at Petrobras. Initial results are promising: even during pilot tests, analysts were able to detect problems with manufactures and a lack of synchronicity between component changes.

Sucker-Rod Pumping Ontology An ontology is a description of a domain developed by a group to support the accomplishment of specific tasks (Gruber 1993; Garcia et al, 2006). Building an ontology involves negotiating meanings of concepts and specifications within a community of practice that share norms and standards, but that may diverge on the way to interpret them. The ontology establishes the common ground knowledge.

Sucker-rod pumping (SRP) ontology was built by a group of artificial lift engineers that works for the same company for more than 10 years, but in different business units. Although they work for the same company, they have never worked together. They had monthly meetings during a period of 8 month to develop the ontology. Their discussion went over the analysis of previous interventions on company's wells in the light of international standards.

The goal of building an ontology was to provide basis for the development of an expert system to assist sucker rod pumping failure diagnosis and wells degradation severity level classification. Figure 1 illustrates the SRP ontology. Nodes represent the main concepts and the links represent the relation between concepts.

Is-an-atbibute-of

Is-the-oblect-of-the-inteivention

[ Agent

Causa Part-of

Oil production

Is-a Part-of

ROd

Dehne, Oile neviicrop inomitaet inotn

Constrains

Is-assembled-1

Part-o Part-of

Part-of

Sucker - Rod pumping system

ls-a

Is-an-attribute-of

Is-an-attribute-o

Part-of

Is a

Equipament

List of equipament of replacement

( List of removed equipament Part-of

(Rod components) diasgnosis

• Tubing componente

diagnosis

Pump componente

diagnosis

• ID • Manufacturer • Type • Material • Dimension

P rt- f

[Equip ment component inspection

List of inserted equipament

2 SPE SPE-134975-PP

Figure 1: Sucker-Rod Pumping Failures Diagnostic Ontology.

Damage severity level

Part-of

Failure mode 1 descriptor

SPE SPE-134975-PP 3

As Figure 1 shows, a well intervention occurs whenever a reason for pulí is identified. In the case of a suspected failure of subsurface system, the reason for pulí is the primary symptom pointing towards a downhole equipment failure. It is usually related to an abnormal operating condition as detected by the operator or installation monitoring system, or by inadequate performance on a well test (Alhanati et al, 2001).

In case of production down time, there will be a preliminary diagnosis based on the visual observation and operation tests on site. The dynamometric cards and pressure tests are the basic inputs to define the reason for pulí.

The rod sucker pumping system is disassembled and its parts, such as the pump, rod and tubing strings, are sent to specific maintenance services to collect evidences that will complete the failure data sheet. Pumps, rods and tubing are further decomposed in components as described in Annex A, which contain the full equipment taxonomy.

It is important to notice that whenever a well intervention occurs, all equipments removed from the well will be inspected, tested and diagnosed for further repair or simply usage classification and storage. The intervention causes equipment replacement: equipments are removed and equipments are inserted based on the artificial lift engineer design. The replaced equipments have a usage status that should be adequate to the level of degradation severity of the well. The degradation severity can be inferred observing the lifetime of different classified equipment in the well.

In each specific maintenance service, inspection procedures and tests will be performed in the equipment component to identify the failure characteristics. Based on international standard ISO 14224 and the experts' experience on sucker rod pumping failures diagnostic process, the followed concepts were considered:

• failure data: data characterizing the occurrence of a failure event; • failure descriptor: evidence of equipment component failure; • failure mechanism: physical, chemical or other process that leads to a failure; • failure mode: effect by which a failure is observed on the failed item • failure root cause: circumstances associated with design, manufacture, installation, use and maintenance that have led

to a failure; • failure agent: actor responsible for the failure cause.

The failure descriptor, mechanism and mode form evidences to classify the equipment usage status and to eventually determine the failure root causes and the underlying root cause agent. Depending on the equipment component, there will be a set of feasible agents and expected possible causes as described in Annex B.

The system diagnosis is a combination of equipment usage description ruled by Modes and Effects (FMEA) and Fault tree (FTA) techniques. From the reason for pulí, an Up-down analysis is developed connecting the equipment usage description with logical connector (AND/OR).

For instance, if a production downtime (reason for pulí) was related to the equipment usage description Broken (failure description) Rod (equipment) by corrosion (failure mechanism) leading to Power/signal transmission failure (failure mode), the system diagnosis can be described as illustrated in Figure 2.a.

A more complex example can be represented if a production loss (reason for pulí) related to two equipment usage descriptions: Hole (failure description) in a Tubing (equipment) by corrosion (failure mechanism) leading to External leakage —process medium (failure mode) and eroded (failure description) traveling valve ball (equipment component) by erosion (failure mechanism) leading to External leakage —process medium (failure mode). The system diagnostic process can be described as illustrated in Figure 2.b.

Production downtime - mode

e Root cause

Legenda

I I Anomaly

I I Know fact

Well

Well

Production loss - mode

Rod string

Power transmission failure - mode

Column string

External leakage - mode

Pump


Broken Rod by corrosion

Hole in a Tubing

Eroded traveling valve ball

Power transmission failure - mode

Failure description and external leakage - mode


1

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Figure 2: Reasoning samples for achieving a diagnostic.

C(Roo

esign related cause

Physical

(Root cause)

1

C(Ro

Artificialcial lift designer

Human

(Root cause)

Expected

wear and tear

Manufacturing problem

Physical

(Root cause)

Physical

(Root cause)

Fabricant

Human

(Root cause)

2.a 2.b The diagnosis of each equipment component can be classified as:

• normal: equipment component without failure, • critical failure: failure of an equipment unit that causes an immediate cessation of the ability to perform a required

function; • degraded failure: failure that does not cease the fundamental function(s), but compromises one or several functions; • incipient failure: imperfection in the state or condition of an item so that a degraded or critical failure might (or might

not) eventually be the expected result if corrective actions are not taken.

Root cause analysis When all detection methods (test and inspection) were applied, a group of equipment usage description is associated to a

specific well service. The analyst or the specialist system based on the registers defines the root cause analysis that defines: 1. Define reason for pull: motive for the downhole equipments pull. A reason for pull shall be defined once the operator

has determined that the downhole equipments installed must be removed from the well because of a system failure or other circumstances (CFER);

2. Gather all the equipment usage description based on test and inspection of the equipments pulled from the well; 3. Classify the equipment usage descriptions related to the specific well service: normal, critical, incipient and degraded

failure; 4. Complete failure data if necessary; 5. Define the fault tree based on Failure modes and effect: logical correlation between the registers; 6. define Root cause and its agent;

The SRP ontology was used as basis for building the SRP expert system to support sucker rod pumping failures diagnostic as described in the next section.

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Expert System for Sucker Rod Pumping Failures Diagnostic

Expert systems technique Expert systems are computer programs that encode human expertise to solve problems in a specific domain (Feigenbaum

1977). They are the most popular and mature artificial intelligence technique with a well-known adequacy for diagnostic tasks, in domains for which there is available human expertise to drive knowledge from.

Traditionally, problem-solving programs can also contain knowledge in their source code. However, knowledge and inference mechanism are mixed. Updates in the knowledge base imply updates in the system as a whole.

Expert systems are composed of a knowledge base, generally represented as a set of IF-Then rules, an inference engine to process the knowledge base, and a working memory that contains the facts known at the beginning of a process and facts deduced during a system run.

From a set of known facts that represent the initial scenario, the inference engine selects inference rules that can be fired from there initial facts. After firing rules, other facts are deduced and added to the working memory. The inference engine keeps selecting, firing rules and adding deduced facts to the working memory. The process remains until no more rules can be selected from the knowledge base.

Any inference can be explained as a chain of rules triggered by parts of the initial data that configured the initial scenario of a case.An expert system is evaluated by the precision of its knowledge base. A set of known cases should be reserved to evaluate the expert system. In addition to reaching the expected result, evaluation should also comprise the line of reasoning that led to the result.

SRP expert system to failures diagnostic SRP system is an expert system implemented in JAVA, in which the knowledge was represented using Drools (Java Rule

Engine) (Drools). The previous section described the vocabulary and the domain information for BM. This section explains BM expert system, as illustrated in Figure 2, composed of an inference engine and BM knowledge base.

SRP inference engine follows the following algorithm: 1. Gather data from user conceming well intervention initial scenario.

a. Reason for pull, b. preliminary diagnosis (pressure tests and dynamometric card analysis), c. equipments' replacements descriptions

2. Collect data from the different equipment component inpections and tests. 3. For each equipment component PUT in working memory equipment component failure data:

a. Failure mechanism b. Failure mode c. Failure descriptor

4. While there are rules in the KB that matches working memory a. Fire rules b. Add new facts on working memory

5. For each removed equipment, present users with the final diagnosis: a. Failure status b. Failure root causes c. Failure root cause agents

6. Present explanation to users for the results 7. After user's result validation (Ratification or Rectification), Update SRP knowledge base

Case

Knowledge Base

Case

Cases

1' Rock sucker

pump intervention

data

KNN Clustering method •

Failure + Explanation

Graphical user interface

Inference englne

•

Well intervention

Rock sucker pump symptoms

Well damage severity leve)

Prodution rules

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Figure 3: BM expert system architecture.

BM knowledge base is composed of 157 inference rules described in terms of XML Condition-Action rules. The rules compose the knowledge base on equipment failure root cause diagnosis, such as:

<rule name="Operational Root Cause"> <pump_unit status:condition> <Pump_Unit:inlet_power failure_mechanism="corrosion"> <Pump_Unit:status failure mode=="internal leakage"> </pump_unit:status>

</Pump_Unit:inlet_power> </pump_unit status:condition> <pump_unit_status:actions> < pump_unitstatus Failure_status="critical failure">

</pump_unit status•actions> </rule>

In addition to providing a diagnostic, SRP system helps collecting and organizing data about sucker rod pump systems' interventions, as well as to provide a standard for reaching diagnostic solutions. The interface guides users to reach a diagnostic for a case. There are four main interfaces:

• Case data entry interface that helps users to describe the well intervention; • Inspection/test data interface that helps users to input data concerning each equipment component test; • Diagnosis interface that presents the final results concerning equipment diagnosis and failure root causes; • Production analyses interface that diagnosis the well concerning its level of damage severity to assist users to choose

equipment material that adequately fits the well environment. Well level of damage severity is defined by clustering methods as described next.

The K-means clustering technique Clustering has always been used in statistics and science as a traditional multivariate statistical estimation process (Scott 1992).

The process of clustering is the process of dividing data into groups containing similar elements. Each cluster contains similar objects different from objects of other clusters. Consequently, clustering involves abstracting a set of objects into few representative ones. In this process, specificity is lost in the name of simplification. The ultimate goal of clustering is to assign points to a finite system of k subsets, clusters. Usually subsets do not intersect with possible outliers.

Traditionally clustering techniques are broadly divided in hierarchical and partitioning. While hierarchical algorithms build clusters gradually (as crystals are grown), partitioning algorithms learn clusters directly for instance trying to discover clusters by iteratively relocating points between subsets, as illustrated in Figure 4.

K-means partitioning algorithm (Hartigan et al, 1979) is by far the most popular clustering method used in scientific and industrial applications. The name comes from representing each of k clusters Cj by the mean (or weighted average) el of its points, the so-called centroid.

I+ One point assignment

is changed.

1 0 01

01 o

01

03 03

03 03

3 03 3

03 03

1

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Figure 4: Iterative Optimization with centroid re-computation, from Bradley et al (1998)

Consider a dataset X composed of data points xi = (x11, xi2,...xiN) E A in attribute space A, where i=1:N, and each component is a numerical or a nominal categorical attribute that characterizes an element in the domain. This data format conceptually

corresponds to a matrix N x d, in which N is the number of attributes and d is the average size of domain attribute values. An important step in any clustering is to define the distance metric, which will determine similarity degree of two elements

described in terms of its attribute xi. This will influence the shape of the clusters, as some elements may be close to one another according to one distance and farther away according to another. The distance

Partitioning methods aim optimization the cost criteria, defined as a function of the distance between the training set instances and the clustering centers, for which d(x(t),w;), in most cases, is the Euclidean distance and the weight matriz (w) is defined by the relative weight of the attributes. Distance based methods are affected by the different scales of the attributes measures. So is wise attributes normalizing the interval values of all attributes.

K-means algorithm starts with a random distribution of the domain elements in k clusters. For each cluster, the method calculates the centroid considering the relative distance among the elements. The centroids represent the clusters. All elements are free from the original cluster. Each element will jump to the cluster represented by the nearest centroid. Alter the rearrangement, centroíds are re-calculated and the process goes all over again until centroids stop changing. The challenge is to configure the distance metric. It is a simple algorithm described as:

K-Means Algorithm: 1. Choose a value for K, the total number of clusters. 2. Randomly choose K points as cluster centers. 3. Assign the remaining instances to their closest cluster center. 4. Calculate a new cluster center for each cluster. 5. Repeat steps 3-5 until the cluster centers do not change.

K-means applied to well level of damage severity classification There is already a standard indication of the best equipment material description according to the level of damage severity of

an oil field. The quest is to identify the field level of severity. Field tests are expensive and they need to be repeated from time to time since the oil reservoir characteristics changes during the well lifetime.

On the other hand, well intervention history may provide hints to deduce well level of damage severity. For instance, frequent interventions caused by ceasing oil production may denote inadequate material selection or lack of the adequate material in the stock.

Well interventions are recorded by a set of data that describes the removed equipment status, the inserted equipment status and the intervention data. Rod replacement data, collected during well interventions, are composed of:

• Well ID • Intervention Data • Removed Rod Description

o Rod Specification (type, diameter and gradel) o Rod Usage Status (class)

• Inserted Rod Description o Rod Specification (type, diameter and grade) o Rod Usage Status (class)

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The usage description for rods is defined by Recommended Practice for the Care and Handling of Sucker Rods (API RP 11BR). The used rods removed from well are inspected and classified as Class I, II, III and IV. For new rods installed class O will be considered.

Considered the rod replacement data, for specific well history:

Installed date Rod specification

(type, diameter and Grade)

Installed Equipment Removed Equipment Period in the well (days)

Quantity usage status (Class) Quantity usage status

(class)

Sucker rod, 1" and KD 15 I 5 II

10 III Sinker bar, 13/4" and

24/02/2009 D 5 I 5 II 100

Sucker rod, 7/8" and II 7

KD 61 I 53 III 1 IV 32 II

Sucker rod, 1" and KD 41 II 8 III 04/06/2009 1 IV 87

Sucker rod, 7/8" and KD 40 I 40 II

Sucker rod, 1" and KD 47 II 47 II 30/08/2009 Sucker rod, 7/8" and

34 II 25 II 93 KD 9 III

specific weel and t=type, d=diameter and g=grade. K-means was applied to cluster wells that present similar equipment lifetime considering equipment specification, especially

material specification. The idea is to look for the best equipment material fit considering the tradeoff between frequent interventions and material costs.

SRP system was deployed in a Brazilian oil company to assist employees to diagnose sucker rod pump system failures and to classify the level of damage severity of the company's oil wells. Next we present the data collected from using the system.

Conclusion This paper presented BM, an expert system for failures in rod sucker pumping failures diagnostic system and well level of damage severity prediction. The system was developed after a thorough knowledge acquisition process that took around six month of work reviewing written material, collecting evidences and interviewing experts.

SRP expert system was modeled, implemented and it is currently under deployment at Petrobras. All power/signal transmission failure and leakage modes are correctly identified by the system for single tree branch analysis, it represents more than 80 % of the cases. To identify correctly complex diagnosis, it is necessary to populate the database and interpretate new fire rules. The system helps to automate the process for multiples wells (more than 6000). If the system could interpretate the failure data, and the artificial lift engineer agrees with the diagnostic, a confirmation acceptance is the only requirement. If not, the engineer will generate the fault tree and record his analysis to improve the fire rules. Users evaluations were very positive after an initial resistance to accept the new technology.

The wells are being classified in groups due to damage severity classification, but the algorithm applied needs to be evoluted, because only few clusters are being detected and sometimes not are the characteristic are compatible in a cluster. It provides similar MTTF but the mean periods of class transition are not totally correlated.

During the pilots tests, even with control samples of intervention, it was possible to identified manufacture problem with sucker rod pumps from a specific manufacture. After a laboratory tests, it was detected a high porosity in the chrome layer. It shows the importance of identify failure root cause and elimínate it.

The system is creating an integrated knowledge base on equipment performance that will assist better maintenance planning. However, definitely the best benefit is expected concerning amplifying production periods to avoid well intervention. Since equipment is frequently used, it is necessary to understand the consequences of inserting equipment with a certain degree of usage in a well with high severity level of damage. Frequent interventions on the same well are indications of a poor planning that can be avoided if we understand about the wells.

Taqbl

The table aboye allows the MTTF calculation and a correlation between time and class modification as a function of rod specification (type, diameter and grade).

Well severity classification of well can be described as a function of rod specification and status usage change during the time period in the well. So, xi = (xi I=MTTFi, xi2=Time04(t, d, g,), xi3=Timeo_dt, d, g) ...xiN = Timerv_w(t, d, g)), where i represents a

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References BRADLEY, P., FAYYAD, U., and REINA, C. 1998. Scaling clustering algorithms to large databases. In Proceedings of the 4th ACM SIGKDD,

9-15, New York, NY. Drools, http://legacy.drools.codehaus.org/. Feigenbaum, E. A. The art of artificial intelligence: Themes and case studies in lcnowledge engineering. In Proceedings of the Fifth International

Joint Conference on Artificial Intelligence. Pittsburgh, PA: Computer Science Department, Camegie-Mellon University, 1977. (FMEA). Procedure for performing a failure mode effect and criticality analysis, November 9, 1949, United States Military Procedure, MIL-P-

1629. (FTA). Fault Tree Analysis. Electronic Reliability Design Handbook. B. U.S. Department of Defense. 1998. http://www.everyspec.com/MIL-

HDBK/MIL-HDBK+(0300+-+0499)/download.php?spec=MIL-HDBK-338B.015041.pdf. GARCIA, A. C. B.; FERRAZ, I. N.; PINTO, F. The Role of domain ontology in text mining applications: The ADDMiner project. In: The 2006

IEEE International Conference on Data Mining (ICDM), 2006, Hong Kong. IEEE Computer Society, 2006. T. R. Gruber. A translation approach to portable ontologies. Knowledge Acquisition, 5(2):199-220, 1993 ISO- 14224. Petroleum, petrochemical and natural gas industries — Collection and exchange of reliability and maintenance data for equipment,

second cdition, 2006. API RP 11BR, Recommended Practice for the Care and Handling of Sucker Rods HARTIGAN, J. and WONG, M. 1979. Algorithm AS136: A k-means clustering algorithm. Applicd Statistics, 28, 100-108. SCOTT, D.W. 1992. Multivariate Density Estimation. Wiley, New York, NY. Alhanati, F.J.S., Solanki, S.C. and Zahacy, T.A. 2001. ESP Failures: Can we Talk the Same Language? Presented at the SPE ESP Workshop,

Houston, Texas, April 25-27.

Annex A — Equipment

To apply ISO 14224 to sucker-rod pumping systems, in the well-completion equipment section (A.2.7.) a few consideration were needed:

1. The string items category was divided in two: a. Tubing string items: defined as items that are integral parts of the conduit ("string") used for production or

injection of well effluents. The string is built by screwing together a variety of equipments items; b. Rod string items: defined as items that are integral parts of the transmission ("string") used to transfer

mechanical energy to downhole pumps. The string is built by screwing together a variety of equipments items;

2. Alternative Pump was added to the accessories category due to its complexity;

Sucker rod pumps

Table A.1 – Type classification – Subsurface pumps Equipment class – Level 6 Equipment type Description Code Description Code

Subsurface pumps SP Centrifugal CR Reciprocating RE Progressive cavity PC

Figure A.1 – Boundary definition – Sucker rod pumps

Mechanical Power

Rod Figure A.2 — Boundary definition — Element of rod string

Mcchanical power

Power transnnssion

Power transmission

boundary

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Inlet connector

Pump Una

Power transmission

Outlet connector

}ir

boundary Mechanical powcr

Tabela A.2 — Equipment subdivision — Sucker Rod oumps Equipment unit Rod Sucker Pumps

Subunit Barre! Standing valve Plunger Power transmission Maintainable items lower

Extension Hold-down seal assembly

Valve rod Plunger connector

Upper Extension

Ball Traveling valve

Extension nipples

Seat Rod

Cage Puller

Table A.3 — Rod classification Item category Data-collection format Predefined item name Rod string Rod Polished rod

Sinker bar Sucker rod Pony rod

Tabela A.4 — Equipment subdivision — Rod

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Equipment unit Rod Subunit Body Power transmission Miscellaneous

Maintainable items Rod Coupling rod Rod centralizer On-off connector

Tubing Figure A.3 — Boundary definition — Tubing

Inlct connector

Tub ng

Outlet connector

boundary

Tabela A.5 — Equipment subdivision — Tubing

Equipment unit Tubing Subunit Body Connection Miscellaneous

Maintainable items Tubing Coupling rod Tubinq centralizer Seating nipple

Intake section Figure A.4 — Boundary definition — Intake section

Inlet connector

Intake section

Outlet connector

boundary

Tabela A.6 — Equipment subdivision — Intake section Equipment unit Intake section

Subunit Solid control Gas control Miscellaneous Maintainable items Filter Gas anchor centralizer

Gas handler

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Annex B — Notation of failure parameters All the ISO 14224 generic and subdivisions codes for failure mechanism, mode and cause were respected.

Table B.1 - Reasons for Pull of subsurface system (Alha Reason for Pull: General Reason for pull: Specific Description

Abnormal Operating Condition No flow to surface (downtime) Symptom/evidence of possible failure, as detected by abnormal operating conditions.

Low flow to surface (production loss) Other abnormal Operating Condition Detected

Well Optimization or recompletion Change artificial Lift System method System pulled to optimize the Artificial Lift system or recomplete the well

Convert well Resize Artificial Lift System Change/modify Producing zone Stimulate Well New technology application Other

Other Economics Log Well Well test Other

Unknown Unknwon

Table B.2 - ISO 44224 failure modes applied for sucker rod pumping equipments.

Equipment class Failure modes Pump Tubing Rod Filter Valves Separator Description Examples Code

X X X Breakdown Serious damage (seizure, breakage)

BRD

X X X X X External leakage — process medium

Oil, gas, condensate,water ELP

X X X X X Internal leakage Leakage internally of process or utility fluids

INL

X Leakage in closed position

Leak through valve in closed position

LCP

X Power/signal transmission failure

Power/signal transmission failure

PTF

X X X Vibration Abnormal vibration VIB X X X Overheating Machine parts, exhacooling

water OHE

X X Noise Abnormal noise NOI X X X X X Plugged/choked Flow restriction(s); Partial

or full flow restriction; PLU

X Parameter deviation

Monitored parameter exceeding limits, e.g.high/low alarm

PDE

X Abnormal instrument reading

False alarm, faulty instrument indication

AIR

X X X X X X Structural deficiency

Material damages (cracks, wear, fracture, corrosion)

STD

X X X X X X Minor in-service problems

Loose items, discoloration, dirt

SER

X X X X X X No immediate effect

No effect on function NON

X X X X X X Other Failure modes not covered aboye

OTH

X Unknown Too little information to define a failure mode

UNK

Table B.3 — Failure descriptor applied to sucker rod pumping failures system.

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Notation Subdivision of the failure descriptor Specific failure descriptor 1-Mechanical failure 1.0-General

1.1-Leakage 1.1.0-General 1.1.1-Hole

1.2-Vibration 1.3-Clearance/alignment failures 1.4-Deformation 1.4.0-General

1.4.1-Twisted 1.4.2-Bent 1.4.3-Dented 1.4.4-Swollen

1.5-Looseness 1.6-Stuck

2-Material failure 2.0-General 2.1-Cavitated 2.2-Corroded 2.3-Eroded 2.4-Wear 2.4.0-General

2.4.1-Worn 2.5-Breakage 2.5.0-General

2.5.1-Broken 2.5.2-Sheared 2.5.3-Torn 2.5.4- Parted

2.7-Overheating 2.7.0-General 2.7.1-Burn 2.7.2-Melted

2.8-Burst 2.8.0-General 2.8.1-Ruptured 2.8.2-Collapsed

5-External influence 5.0-General 5.1-Blockage/plugged 5.1.0-General

5.1.1-Paraffin 5.1.2- Scale 5.1.3- Hydrate 5.1.4- Asphaltene

5.2-Contamination 5.3-Miscellaneous external influences

6-Miscellaneous 6.0-General 6.1-No cause found 6.2-Combined causes 6.3-Other 6.4-Unknown

api sucker rods

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