inspection of drill stem component_rus-eng

: : - __________________________ . _________________________ .

Standard INSPECTION OF DRILL STEM COMPONENTS Introduction Drill pipes shall be checked independently of all other equipment. Inspection of hoisting equipment and all other load baring equipment is to be man-aged via the preventative maintenance system (PMS) under the existing inspection criteria current set by each company and chief mechanics depart-ment. This standard shall set the minimum requirements applied across TNK-BP to inspection of drill stem components. This standard shall not supersede the mandatory requirements defined by the Russian authorities. If the requirements set herein are higher than those defined by the Russian authori-ties, the former shall prevail. Most failures of drill pipe result from some form of metal fa-tigue. A fatigue failure is one which originates as a result of repeated or fluctuating stresses having maximum values less than the tensile strength of the material. Fatigue fractures are progressive, beginning as minute cracks that grow under the action of the fluctuating stress. The rate of propagation is re-lated to the applied cyclic loads and under certain conditions may be extremely rapid. The failure does not normally exhibit extensive plastic deformation and is therefore difficult to detect until such time as considerable damage has occurred. There is no accepted means of inspecting to determine the amount of accumulated fatigue damage or the remaining life in the pipe at a given stress level. Presently accepted means of inspection are limited to location of cracks, pits, and other surface marks; measure-ment of remaining wall thickness; measurement of outside diameter; and calculation of remaining cross sectional area. Recent industry statistics confirm that a major percentage of tube body in-service failures occur near the upset runout or

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1 of 24 Prepared by: BBenedict

within the slip area. Special attention to these critical failure areas should be performed during inspection to facilitate crack detection in drill strings which have been subjected to abnor-mally high bending stresses. Drill pipe which has just been inspected and found free of cracks may develop cracks after very short additional service through the addition of damage to previously accumulated fatigue damage. Content

1. Drill String Cracks 2. Measurement of Pipe Wall 3. Determination of Cross Sectional Area (optional) 4. Procedure 5. Tool Joints 5.1. Required inspections 5.2. Optional Inspections 5.3. General 6. Drill Collar inspection procedure 7. Drill Collar handling System 8. Kellys 9. Setting the Inspection Program 10. Inspection Methods 11. Inspection Program 11.1. Recommended beginning Inspection Frequency 11.2. Recommended Inspection Programs for Drill

Pipe 11.3. Recommended Inspection programs Drill Collars

and HWDP 12. Suggested Field Inspection of Aluminum Tubes /

Steel Tool Joints 13. Recommended inspection for hard banding (Tool

Joints) 13.1. Wear Resistant Overlays 13.1.1. Transverse Cracks 13.1.2. Circumferential Cracks and flaking/spalling 13.1.3. Interbead Troughs 13.2. Tungsten Carbide overlays 14. Recommended inspection or drill pipe bores with in-

ternal plastic lining

1. Drill String Cracks A crack is a single line rupture of the pipe surface. The rupture shall: a) be of sufficient length to be shown by magnetic iron parti-cles used in magnetic particle inspection or b) be identifiable by visual inspection of the outside of the tube and/or optical or ultrasonic shear-wave inspection of the inside of the tube. Drill pipe tubes / , tool joints, and drill collars found to contain cracks should be considered unfit for further drilling service. Shop repair of some tool joints and drill collars, con-taining cracks, may be possible if the unaffected area of the tool joint body or drill collar permits.

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2. Measurement of Pipe Wall Tube body conditions will be classified on the basis of the lowest wall thickness measurement obtained and the re-maining wall requirements. The only acceptable wall thickness measurements are those made with pipe-wall micrometers, ultrasonic instruments, or gamma-ray devices that the opera-tor can demonstrate to be within 2 percent accuracy by use of the test blocks sized to approximate pipe wall thickness. When using a highly sensitive ultrasonic instrument, care must be taken to ensure that detection of an inclusion or lamination is not interpreted as a wall thickness measurement. 3. Determination of Cross Sectional Area (optional) Determine cross sectional area by use of a direct indicating instrument that the operator can demonstrate to be within 2 percent accuracy by use of a pipe section approxi-mately the same as the pipe being inspected. In the absence of such an instrument, integrate wall thickness measurements taken at 1-inch intervals around the tube. 4. Procedure Used drill pipe should be classified according to the API Recommended Practice (RP) 7G table 24 (for pipes manufactured in accordance with API standards or in accor-dance with GOST requirements). Hook loads at minimum yield strength for New, Premium and Class 2 drill pipe, values rec-ommended for minimum OD and make-up torque of weld-on tool joint used with the New, Premium and Class 2 drill pipe and maximum allowable hook loads for New, Premium and Class 2 tubing work strings are listed in tables of API RP 7G or in the reference literature for Russian made pipes. 5. TOOL JOINTS

5.1. Required inspections

Following are required inspections:

a) Outside diameter measurements measure tool joint outside diameter at a distance of 1 inch from the shoulder and determine classification from data in Classification table for Used Tool Joints (API RP 7G). Minimum shoulder width should be used when tool joints are worn eccentrically. The GOST pipes data are presented in Attachment 1.

b) Condition of the shoulders check the tool joint shoulders for wear marks, scratches, burrs and other

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damage that could influence the condition of the shoulders or their ability to hold pressure. The GOST pipes data are presented in Attachment 1.

) Visual thread inspection the thread profile is checked to detect over-torque, lapped threads, and stretching. Threads are visually inspected to detect handling damage, corrosion damage and galling. In addition, threads are checked for wear resulting from make-up. Minimum gaps between the tool joints bearing faces prior to make-up are shown in Attachment 1.

5.2. Optional Inspections (dependent on selected inspec-tion Programme see section 11 for further details)

Following are optional inspections:

a) Shoulder width using data in Classification table for Used Tool Joints (API RP 7G), determine minimum shoulder width acceptable for tool joint in class as governed by the outside diameter.

b) Box swell and/or pin stretch these are indications of

over-torquing and their presence greatly affects the future performance of the tool joint. The lead gauge is the only standard method for measuring pin stretch. On used tool joints, it is recommended that pins hav-ing stretch which exceeds 0.006 inch in 2 inches should be recut. All pins which have been stretched should be inspected for cracks.

c) Magnetic particle inspection if evidence of pin stretching is found, magnetic particle inspection should be made of the entire pin threaded area, es-pecially the last engaged thread area, to determine if transverse cracks are present. In highly stress drilling environments or if evidence of damage, such as cracking is noted, magnetic particle inspection should be made of the entire box threaded area, especially the last engaged thread area, to de-termine if transverse cracks are present. Longitudal or irregular orientation of cracking may oc-cur as a result of friction heat checking. In that case magnetic particle inspection of both box and pin tool joint surfaces, excluding any hardband area, should be performed, with an emphasis on detection of longi-tudinal cracks. For crack detection, the wet fluorescent magnetic par-ticle method is preferred for tool joint inspections. Tool joints found to contain cracks in the threaded ar-eas or within the tool joint body, excluding any hard-band area, should be considered unfit for further drill-ing service. Shop repair of some cracked tool joints maybe possible if the unaffected area of the tool joint

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body permits.

d) Minimum tong space. The criteria for determining the minimum tong space for tool joints on used drill pipe should be based on safe and efficient tonging opera-tions on the rig floor, primarily when manual tongs are in use. In this regard, there should be sufficient tong space to allow full engagement of the tong dies, plus an adequate amount of tong space remaining to allow the driller and/or assistant driller to visually ver-ify that the mating shoulders of the connection are unencumbered to allow proper make-up or break-out of the connection without damage. It is also recommended that any hard banded sur-faces of the pin or box tool joint tong space be ex-cluded from the area of tong die engagement as stated above when minimum tong space is deter-mined. This practice will ensure that optimum gripping of the tongs is achieved and that damage to tong dies is minimized. In the case where tool joint diameters have been worn to the extent that the original hard banding has been substantially removed, the user may include this area in determining the minimum tong space.

5.3. General

a) gauging thread wear, plastic deformation, mechani-cal damage and lack of cleanliness may all contribute to erroneous figures when plug and ring gauges are applied to used connections. Therefore, ring and plug standoffs should not be used to determine rejection or continued use of rotary shouldered connections.

b) repair of damaged shoulders when refacing a dam-aged tool joint shoulder, a minimum of material should be removed. It is a good practice to remove not more than 1/32-inch from a box or pin shoulder at any one refacing and not more than 1/16-inch cumu-latively.

It is suggested that a benchmark be provided for the determination of the amount of material which may be removed from the tool joint makeup shoulder. This benchmark should be applied to new or recut tool joints after facing to gauge. The form of the bench-mark should be applied to new or recut tool joints af-ter facing to gauge. The form of the benchmark may be a 3/16-inch di-ameter circle with a bar tangent to the circle parallel to the makeup shoulder, as shown in next figure. The distance from shoulder to the bar should be 1/8-inch. Variations of this benchmark or other type bench-marks may be available from tool joint manufacturers or machine shops.

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Coverage Identification of Lengths Covered by Inspection Stan-dards

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6. DRILL COLLAR INSPECTION PROCEDURE The following inspection procedure for used drill col-

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lars is recommended: a) Visually inspect full length to determine obvious

damage and overall condition b) Measure OD and ID of both ends c) Thoroughly clean box and pin threads. Follow imme-

diately with wet fluorescent magnetic particle inspec-tion for detection of cracks. A magnifying mirror may be used in crack detection of the box threads. Drill collars found to contain cracks should be considered unfit for further drilling service. Shop repair of cracked drill collars is typically possible if the unaffected area of the drill collar permits.

d) Use a profile gauge to check thread form and to check for stretched pins

e) Check box bore back diameter for swelling. In addi-

tion, use a straight edge on the crests of the threads in the box checking for rocking due to swelling of the box. Some machine shops may cut box bore back larger than API standards, therefore, a check of the diameter of the bore back may give a misleading re-sult.

f) Check box and pin shoulders for damage. All field re-pairable damage shall be reapired by refacing and beveling. Excessive damage to shoulders should be repaired in reputable machine shops with API stan-dard gauges.

7. DRILL COLLAR HANDLING SYSTEM When the elevator shoulder on drill collar is new it is square and has sufficient area in contact with the elevator. As the collar is used for drilling, however, it wears as shown in Figure below.

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Elevator contact area is decreased by collar OD wear and


elevator load is increased by angle and radius buildup on the collar and corresponding wear on the elevator seat. Elevator capacity is drastically reduced by spreading action as most all drill collar elevators are intended for use with square shoulders only. As an example, with 1/16 inch wear on the collar OD, 1/32 inc radius worn on the corner, and a 5-degree angle on the shoul-der, elevator capacity can be reduced by as much as 40 to 60 percent, depending on collar size and elevator design. Before this danger point is reached, the collar and elevator should be shopped and the shoulder brought back to a square condition. Ensure the elevator shoulder radius on the drill collar is cold worked when shoulder is reworked. 8. KELLYS The following inspection procedure is recommended for used kellys:

a) Examine junction between upsets and drive section for cracks. (A saver sub shall be removed from the Kelly prior to the examination).

b) Kelly straightness can be checked either of two ways:

1. By watching for excessive swing of the swivel and traveling block while drilling, or 2. By placing square kellys on level supports (on at each end of drive section), stretching a heavy cord from one end of a vertical face of the square to the other, measuring deflection, rolling Kelly 90 de-grees, an repeating procedure. A too long kelly can sag because of its own weight. Therefore if all kelly sides are of equal non-straightness (in turning mode), its geometry shall be considered satisfactory. 3. Visual thread inspection the thread profile is checked to detect over-torque, lapped threads, and stretching. Threads are visually inspected to detect handling damage, corrosion damage and galling. In addition, threads are checked for wear resulting from make-up. Minimum gaps between the tool joints bearing faces prior to make-up are shown in At-tachment 1.

9. SETTING THE INSPECTION PROGRAM This section recommends standard procedures for specifying and conducting inspection programs for used drill stem com-ponents - drill pipe, heavy-weight drill pipe, drill collars, and end connections on all drill stem components.

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The inspection program defines:

a) Which inspection methods will be applied to each drill stem component

b) How each inspection method must be conducted in

step-by-step procedure c) What acceptance criteria will be in effect during in-

spection

Many inspection errors occur because the operator does not know or does not spell out his exact requirements. Operators may require (API) Inspection without understand-ing what this includes and more importantly, what it omits. 10. Inspection Methods The following table lists fifteen widely available inspection methods that make up the great majority of drill stem inspec-tions today. All these methods are generic and are available from multiple sources, though each may employ slightly differ-ent equipment.

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WHAT IS DONE / WHAT IS BEING EVALUATED /

NAME OF METHOD /

APPLIED TO / - INSPECTION APPARATUS /

Full length visual examination of the inside and outside surfaces of used tubes / Straightness, mechanical or corrosion damage, debris such as scale or drilling mud / , , ,

1. Visual Tube / -

Drill pipe tubes /

Paint marker, pit depth gage, and a light capable of illuminating the full length internal surface of the pipe are required / , - , Full length mechanical gauging of the outside diameter of used Drill pipe tubes / Diameter variations caused by excessive wear or mechanical damage, expan-sions caused by string shot, reduction caused by overpull / - , -

2. OD Gauge Tube / -

Drill pipe tubes /

Direct reading or Go-No-Go type gages may be used. Gages must be capable of measuring the smallest and largest permissible tube outside diameter / - - - . - , . Measurement of the wall thickness around one circumference of the drillpipe tube using an ultrasonic thickness gage / - - Tube wall thickness below the specified acceptance limits, minimum cross-sectional area of the tube / - ,

3. UT Wall Thickness (ultrasonic) / - - -

Drill pipe tubes /

The ultrasonic instrument shall be the pulse-echo type with digital or analog display. The transducer shall have separate transmit and receive elements. /


- . . Full length scanning (excluding upsets) of drill pipe tube using the longitudinal field buggy type unit / ( ) Transverse flaws such as fatigue cracks, corrosion pits, cuts, gouges, and other damage that exceed the specified acceptance limits / - , , -, , , -

4. Electromagnetic 1 / 1

Drill pipe tubes /

Flux leakage detection equipment (unit) used for transverse flow detection shall utilize a DC coil. The unit shall be designed to allow active inspection of the tube surface from upset-to-upset. / - , - . , - . Full length scanning (excluding upsets) using a unit with both longitudinal EMI and gamma ray wall thickness capabilities / ( ) , . Flaws such as fatigue cracks, corrosion pits, cuts, gouges, and other damage that exceed the specified acceptance limits, full length tube wall thickness / , , - , , , - , .

5. Electromagnetic 2 / 2

Drill pipe tubes /

a) EMI unit (flux leakage detection unit) / - ( ). b) Gamma ray unit shall employ a configuration capable of detecting eccentric-ity. The double average wall method shall be used only in conjunction with backscatter or single wall method. / - . - . Examination of external surface of DP and HWDP upsets and slip areas using the active-field AC yoke dry visible magnetic particle technique / - , -, . Flows such as a fatigue cracks, corrosion pits, cuts, gouges, exceed the speci-fied acceptance limits / , , , , -, .

6. MPI Slip/Upset (magnetic particle in-spection) /

Drill pipe or HWDP slip and upset ar-eas / T

Longitudinal magnetization shall be accomplished with a handheld AC yoke / , . Examination of DP and HWDP upsets and slip areas using shear wave ultra-sonic equipment / - Flows such as a fatigue cracks, corrosion pits, cuts, gouges, and exceed the specified acceptance limits / , - , , , -, .

7. UT Slip/Upset (ultrasonic) / - -

Drill pipe or HWDP slip and upset ar-eas /

The ultrasonic instruments for both scanning and prove-up shall be the pulse-echo type with A-scan presentation and gain control increments no greater than 2 db. The units shall have both audible and visible alarms. / , - - - 2 . , .

8. Elevator Groove / Drill collar elevator Measurement of elevator groove dimensions such as collar OD, groove length,


groove depth, and visual inspection of groove shoulder / - , , ,

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grooves /

Out of tolerance dimensions which could result in inadequate gripping of the collar, or rounded shoulders which could overstress the elevators / - , - , , Visual examination of connections, shoulders, and tool joint and profile check of threads, measurement of box swell / , ,

9. Visual Connection / - -

Handling damage, indications of torsional damage, galling, washout fins, visibly non-flat shoulders, corrosion, weight/grade markings on tool joint and pin flat / , , , -, , , - , /

Drill pipe tool joints HWDP tool joints BHA connections / - ,

A metal rule, a metal straight edge, a hardened and ground profile gage, OD calipers, a lead gage, and a lead setting standard shall be available / - , , , , Measurement or Go-No-Go gaging of box OD, pin ID, shoulder width, tong space, box bore back/ , - , , -

10. Dimensional 1 / 1

Drill pipe tool joints / - -

A steel rule, a metal straightedge, and ID and OD calipers are required / - , -

Dimensional 1 requirements plus measurement or Go-No-Go gaging of pin lead, counterbore depth, pin flat length, bevel diameter, seal width, and shoul-der flatness / - 1 , , , - , , - . Same as dimensional 1, plus evidence of torsional damage, potential box thread engagement with pin flat, excessive shoulder width, sufficient seal area to avoid galling, non-flat shoulders / , 1 , -, , - , - , .


Drill pipe tool joints / - -

A metal rule, a metal straight edge, a hardened and ground profile gage, a lead gage, and a lead setting standard, and ID and OD calipers are required / - , , - , , .


HWDP tool joint & upsets BHA connections / - - -

Measurement or Go-No-Go gaging of box OD, pin ID, pin lead, bevel diameter, pin stress relief groove diameter and width, boreback cylinder diameter and thread length and HWDP center upset diameter / - , , , , -, ,


Torsional capacity of HWDP pin and box, drill collar BSR, evidence of torsional damage, excessive shoulder width, proper dimensions on stress relief features to reduce connection, wear on HWDP center upset / , , , , , , .

A metal rule, a metal straight edge, a hardened and ground profile gage, a lead gage, and a lead setting standard, and ID and OD calipers are required / - , , - , , . Fluorescent wet magnetic particle inspection using active DC current / - , . - .

The existence of fatigue cracks /

13. Blacklight Con-nection / -

Drill pipe tool joints HWDP tool joints BHA connections (magnetic only) / - , ( -)

1. Particle Bath Medium/ 2. Blacklight Equipment / 3. Coil (a DC coil) / ( ) 4. Magnetic particle field indicator / 5. A mirror to examine box thread roots / - Compression wave pulse-echo ultrasonic inspection of connections / - -

The existence of fatigue cracks/

14. UT Connection (ultrasonic) / -

HWDP tool joints BHA connections (all) / , - ()

The ultrasonic instrument shall be the pulse-echo type with with and A-scan presentation / - - With liquid penetrant inspection of connections / -

15. Liquid Penetrant Connection/ - -

Non-magnetic BHA connections / - -

The existence of fatigue cracks/

11. Inspection Program

A typical inspection program consists of selecting one or more of the methods from above table and applying them to the drill stem components, using step-by-step procedures.

The drill stem inspection program will vary with the

severity of drilling conditions and the safety, environmental and economic risks associated with a possible failure. More several conditions with higher associated risks demand more inspections and tighter acceptance criteria. For operators wishing to tailor the inspection programs for various drilling conditions and risks, DS-1 standard establishes five service categories:

1. Service Category 1: very shallow, very rou-tine wells in well-developed areas. When drill stem failures occur, failure costs are so minimal that the cost of extensive inspection would not have been justified (OFS Defini-tion = Vertical and Direction wells from 0 m to 1500 m measured depth)

2. Service category 2: Routine drilling condi-

tions where the established practice is to perform minimal inspection and failure ex-perience is low. (OFS Definition = Verticial and Directional wells 1500 m to 2500 m

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measured depth with a maximum deviation of 50 deg)

3. Service Category 3: Mid range drilling condi-tions where a standard inspection program is justified. If a failure occurs, the risk of sig-nificant fishing cost or losing part of the hole is slight. (OFS Definition = all wells vertical , directional, S shaped horizontal from 2500 m to 4000 m. When horizontal section does not exceed 600 meters measured depth.

4. Service Category 4: Drilling conditions more

difficult than Cat.3. Significant fishing costs or losing part of the hole are likely in the event of a drill stem failure. OFS Definition = same as Cat 3 but where Horizontal sec-tion is greater then 600 800 meters meas-ured depth.

5. Service category 5: Severe drilling condi-tions. Several factors combine to make the cost of a possible failure very high. (OFS Definition = All wells greater then 4000 me-ters measured depth or wells with highly complicated zones of loss circulation, HTHP, well bore stability and H2S, where horizontal section is greater than 800 meters.

11.1 Recommended inspection frequency

1500 2500 - 50 ).

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4. 4: -, 3. - - ( - 3, 600 800 ) .

5. 5: . - ( 4000 , -, , - , - 800 .

11.1

Service Category / Component /

1 2 3 -4 5

When picked up / -

When picked up/ -

Before each well / -

Drill Pipe and Kellys / -

After each 1500 rotating hours / 1500 -

After each 1500 rotating hours / 1500 -

Aluminum Drill pipe/ After 2500 hours rotating and non rotating/ 2500 -

After 2500 hours rotating and non rotating/ 2500 -

After 2500 hours rotating and non rotating/ 2500 -

When picked up/ -

When picked up/ -

When picked up/

HWDP & Drill Collars all down hole subs and cross overs below drill pipe / , -

After each 600 rotating hours (+/- 10%) / 600 -

After each 600 rotating hours (+/- 10%) / 600 -

After each 600 rotating hours (+/- 10%)/ 600

Surface subs between Swivel and Kelly/ - -

After each 2500 actual ro-tating hours/ 2500

After each 2500 actual ro-tating hours/ 2500

After each 2500 actual rotat-ing hours/ 2500

Subs between Kelly and first joint of drill pipe./ - -

After 500 make up and brake outs/ 500 -

After 500 make up and brake outs (shall be speci-fied in the subs passport)/ 500 - ( )

After 500 make up and brake outs/ 500 -


11.2 Recommended Inspection Programs for Drill

Pipe

11.2

(less severe) Inspection Program for Drilling Service Category (more severe)

( ) ( )

Component / -

1 2 3 4 5

Tool Joint / -

Visual con-nection / -

Visual con-nection / - - Dimensional 1 / -1

Visual connection / - - Dimensional 2 / 2

Visual connection / Dimensional 2 / - 2

Visual connection / Dimensional 2 / - 2 Blacklight connec-tion / -

Drill Pipe Tube /

Visual Tube / -

Visual Tube / - - OD Gage / - UT-wall thick-ness / - -

Visual Tube / - OD Gage / UT-wall thickness / Electromagnetic1 / 1

Visual Tube / - OD Gage / UT-wall thickness / - Electromagnetic1 / 1 MPI Upsets /

Visual Tube / - OD Gage / UT-wall thickness / - Electromagnetic1 / 1 MPI Upsets/ UT Upsets / -

Acceptance Crite-ria / (See Table 24 API RP 7G for classifica-tion requirements for API pipe/ . 24 7 - - - - )

Class 2 / 2-

Class 2 or Premium Class (de-pending on loads to be applied) / 2- ( - )

Premium Class /

Premium Class /

Premium Class /

11.3 Recommended Inspection programs Drill Collars

and HWDP

11.3

Service Category / Component / 1 2 3-5 Connection / -

Visual connection /

Visual connection / - - - Blacklight connection /

Visual connection / - - Blacklight connection / -


Dimensional 3 / 3

DC elevator groove (if present) / ( )

Elevator groove / -

Elevator groove / - -

Elevator groove / -

HWDP tube / Visual tube / -

Visual tube /

Visual tube / MPI upsets / -

An unscheduled drill stem inspection should be performed when well remediation work is done involving tensile, torsional loads or drill string failures (due to impact loads or parting).

, - ( ) - -.

After defining Service categories 1 5, the operator deter-mines the drill stem inspection program in a given well or area using a three-step process: Step 1: Choose a Service Category for the Well Being Consid-ered Step 2: Specify the Inspection Program Step 3: Specify the Acceptance Criteria (which acceptance criteria the inspector will use to accept or reject the material) Acceptance criteria are selected based on the anticipated loads, equipment availability and failure history. The choices will usually consist of picking a drill pipe class and then select-ing a BSR (Bending Strength Ratio) range for BHA connec-tions. 12. SUGGESTED FIELD INSPECTION OF ALUMINUM

TUBES / STEEL TOOL JOINTS 1) Tubes and tool joints should be CLEAN & DRY to al-low inspection. 2) Check make/break shoulders of boxes and pins for handling damage, distortion and eccentric wear.

3) Check pin threads for stretch using a lead gauge. (A profile gauge is a poor substitute.) 4) Examine box threads for damage and measure box counterbore for distortion. 5) Examine aluminum near steel tool joint for cathodic corrosion. This is both outside and inside. Pit depths should not exceed 1/8 or 0.125. 6) Measure tubes at mid-point with a pi-tape. If remain-ing wall is less than 80% of nominal, tubes are below pre-mium class.

7) Examine connection between tool joint members and tube. Any obvious movement is cause for rejection.

8) Measure box outside diameter within 1 of box make/break shoulder. Excess wear can make this member the limiting factor with regards to torsional strength. (Be guided by API RP7G.)

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9) Pressure test all drill string assemblies to pressure, needed for used drill string. 10) Inspect all members visually as they are being han-dled. Reject bent tubes and tubes and tool joints that exhibit eccentric wear. 11) Watch tubes for exfoliation. Exposure to salt water causes some aluminum alloys to peel in hand-sized layers.

12) Reject tubes with excess slip marks. 360-degree deep slip grooves are stress raisers, generally brought about by careless handling.

13. Recommended Inspection for Hard Banding The hardbanded area, heat affected zone (HAZ) from the welding/hardbanding process, and the adjacent parent mate-rial region for a minimum of 25mm (1 inch) either side shall be inspected at the same time as the drill pipe. The hardbanded region shall be examined for cracks by visual inspection. The adjacent HAZ and surrounding parent material shall be exam-ined for cracks by visual inspection together with dye pene-trant (e.g. in accordance with ASME V, Article 6) and/or mag-netic particle inspection, (e.g. in accordance with ASME V, Article 7) as appropriate (Note: ASME = American Society of Mechanical Engineers) In addition, visual by the rig floor crew of the hardbanding dur-ing tripping operations is required. This section gives information on what features to look for dur-ing this inspection. 13.1 Wear Resistant Overlays On wear resistant alloys it is normal to find cracks in the trans-verse or diagonal direction. Typically, these cracks may run straight across the weld bead or at an angle of between 30 and 45 Occasionally the cracks will interconnect. This is ac-ceptable providing the cracks are less than 1.6mm (1/16) wide with, in the case of cracks which extend across the full width of the hard banded region, a minimum spacing or 12.5mm (). If the cracks exceed these criteria then the pipe should not be run in the well. The reason for this is that spalling may result, possibly leading to severe casing wear. If for any reason cracks extend into the HAZ (Heat Affected Zone), parent metal or main body of the component, then the joint should be taken out of service. 13.1.1 Transverse Cracks

9) -

, .

10) - . , , - .

11) . - -.

12) . (3600) -. .

13. - , () / 25 (1 ) - . . - (. 6 V), ( 7 V) (: --) , - - . , -. 13.1 - . 30-45. . , - 1,6 (1/16) , -, , - 12,5 (1/2 ). , . , - - . - - , , . 13.1.1.


The above figure illustrates an acceptable configuration of transverse cracks. Crack are less than 1/16 (1.6mm) wide and cracks extending the full width of the hard band deposit are greater than *(12.5mm) apart. 13.1.2 Circumferential Cracks and flaking/spalling If there is any single continuous circumferentially running cracks greater than 76mm (3) long, these are unacceptable as they can result in premature fatigue failure. In such circum-stances, lay out the bad joint. If there is any evidence of the hardbanded deposit spalling, flaking or chipping off, this is not acceptable as this can result in premature casing wear. The pipe should not be run in the well.

The above figure illustrates unacceptable circumferential cracking and flaking/spalling and acceptable circumferential cracking. Cracks into the HAZ and parent metal are not al-lowed and pipes exhibiting such cracks should not be run into the well. These pipes should be removed and sent for repair and require the cracks to be complete removed in accordance with a repair and re-hardbanding procedures to be approved by TNK-BP. 13.1.3 Inter-bead troughs

Cracks into HAZ or par-ent metal are not allowed

>1/2

Small troughs between individual weld beads are acceptable providing they are no more than (3.2mm) wide or 1/16 (1.6mm) deep. 13.1.4 Wear tolerance/weld overlay defects For flush overlays the tool joint should be re-hardbanded as soon as the tool joint wear exceeds the thickness of the weld overlay, i.e. either when local areas are found where there is no hardfacing material remaining or when the tool joint diame-ter has reduced by more than 4.8mm (3/16) For proud overlays, the tool joint should be re-hardbanded as soon as the hardbanded area is flush with the tool joint. If there are surface breaking non-linear defects such as poros-ity on the hard band weld beads greater than 3.2mm () or 1.6mm (1/16) deep, these may be filled by using semi-automatic GMAW or SMAW. This type of repair must be performed with a consumable matching the composition of the hardband material and will require a TNK-BP approved weld procedure for application. 13.2 Tungsten Carbide overlays The presence of cracks visible with the naked eye on the welded or ground surface of tungsten carbide hardfacing is unacceptable. If there is any evidence of the hardbanded deposit spalling, flaking or chipping off, the pipe should not be run in the well. 14. Recommended Inspection for drill pipe bores with In-ternal Plastic Lining a. The pipe to be inspected shall be cleaned internally, pref-

erably with high pressure water jetting equipment. Removal of drilling mud, chemical residues, dust and dirt and other visible contaminants is required. NOTE: The water blast should not exceed 5000psi (~ 340 atm). It is also recommended to use a 360 nozzle. Do not use a pencil point nozzle

b. The pipe internal diameters to be dried with compressed air

to remove residual water prior to visual inspection

, 1/3 (3,2 ) 1/16 (1,6 ). 13.1.4. / - , , .. , - - 4,8 (3/16). - , - . , 3,2 (1/3) 1,6 (1/16), - - . - , , . - - - . 13.2 - - . - -, , . 14. -

-

a. , - . - , -, , , .

:

5000 /. (~340 .). . .

. ,


c. To help determine fitness for purpose, Classes 1, 2, 3 & 4

have been established to provide guidelines for evaluating the condition of the coating

d. Photographs showing the varying conditions of the Classifi-

cations are recommended for training purposes (e.g. in-spectors) and can be used to assist in decision making.

e. The benefits of a comprehensive used drill pipe coating

inspection program are ultimately to extend the useful life of the pipe and to prevent premature failures caused by pitting type corrosion in the critical transition area (weld line and internal upset area)

Drift requirements Each length of external upset drill pipe shall be tested throughout the length of the pipe with a cylindrical drift mandrel having a diameter 3,2 mm smaller than the inside diameter of the drill pipe and a length 10 times the inside diameter. CLASSIFICATIONS:

. . 1,2,3,4 , - .

. (. ) - , - , - .

. - - - ( )

- - 3,2 , 10 - . :

CLASS 1 Status: Re-use 1 : Description: :

The internal diameter coating contains minor abra-sion and scrapes down the tube and in the critical transition area

- .

No corrosion products (rust or scale) are present in

the tube or transition area

The internal diameter coating is not blistering or de-laminating (coming off)

( ) ,

-

.

Damage to the coating in the tool joints is normal and acceptable

- .

In Tool Joint


In Upset Run Out

In Tube Body

CLASS 2 Status: Re-use

2 :

Description: :

The internal diameter of the tube coating contains limited wire line cuts and tool damage

Presence of corrosion (rust) is visible. However, there is no serious underfilm (undercreep) corrosion pre-sent.

(). - .

Coating loss is 5% or less in the tube

5%

Limited cuts and scrapes are present, but there is

minimal coating loss in the transition area. , -

.

Internal diameter coating is not blistering or delamina-ting (coming off).

Damage to the coating in the tool joints is normal and acceptable

- .


In Tool Joint

In Upset Run Out

In Tube Body

CLASS 3 Status: Re-use 3 : Description:

:


The internal diameter of the tube contains multiple

wireline cuts and tool damage -

. , The underfilm corrosion is present but not severe 15% Coating loss is 15% or less in the tube

Damage to the transition area observed but coating loss is less than 15% and the onset of pitting type corrosion has not occurred.

Internal diameter coating is not blistering of delamina-ting (coming off).

Damage or the coating in the tool joints is normal and acceptable

Note: Re-use of this pipe is normal drilling operations is ac-

ceptable. However, the coating should be re-inspected after each use.

Note: Re-use of this pipe in deep, high temperature gas wells with significant amounts of CO2 and or H2S is not rec-ommended

Note: Water blast limitations

, 15%, - .

. -

.

: . .

: - -

: CLASS 4 STATUS: Re-coat Description:

4 : :

Moderate to severe coating damage in the tube and

transition area with severe underfilm corrosion.

Coating loss in the tube is 25% or more with the on-set of pitting corrosion

- -.

25%

Coating loss in the transition area is 25% or more

with the onset of pitting corrosion 25% -

Internal diameter coating is not blistering or delamina-ting (coming off)

Tool joint damage is normal

In Tool Joint


In Upset Run Out

In Tube Body

Developed by: Brandon Benedict (OFS) Valery Kolotilin (OFS)

: () ()

Roy Richardson (SCM) Andre Georgiesh (NvBN)

() ()

Vladimir Ryigalov (OBN) Alexander Nikulin (NvBN)

() ()

Ivan Perepeliatnik (NPRS 1) (-1)

Bernard Perrot (OFS)

()


1 ( , ) Attachment 1 (drill pipes manufactured according to GOST) . Tool joint wear limits , , Minimum OD, mm

Nominal size, mm

uneven wear

even wear 80 75 77 95 89 92

108 102 105 172 164 168 178 167 172.5 203 191 197 155 148 151.5

. Drill pipe body wear limits

, , , , Nominal pipe diameter, mm

Worn OD, mm Nominal pipe diameter

Worn OD, mm

60 57 127 124 73 69 147 144 89 85 93 90 102 98

(, ). Allowable wear for tool joint threads (tubes, subs)

, ( -)

, Thread designa-

tion Tool joint nominal di-ameter, mm

Distance between pin bearing face and box when stabbing, mm (minimum)

80 -66 14 86 -73 21 95 -76 14

105 -83 29 108 -88 21 140 -117 14 155 -133 21

172/178 -147 26 197 -152 26


inspection of drill stem component_rus-eng

Documents

inspection methods

drill string cracks

drill strings

failures of drill pipe

drill collar handling

minute cracks

location of cracks

circumferential cracks