DRILL PIPE MANAGEMENT EXTENDS DRILLSTRING LIFE

Oct. 28, 1991
Jeff S. Shepard Global Marine Drilling Co. Houston Better handling procedures and frequent drill pipe inspections prolong the life of a drillstring. Crews taught to make quick visual inspections during rig moves and tripping can spot problem pipe early, thus preventing downtime or extensive repairs. Because of escalating costs of drillstring repair and replacement, Global Marine Drilling Co. organized a task force in March 1989 to define problem areas and establish new handling and maintenance
Jeff S. Shepard
Global Marine Drilling Co.
Houston

Better handling procedures and frequent drill pipe inspections prolong the life of a drillstring.

Crews taught to make quick visual inspections during rig moves and tripping can spot problem pipe early, thus preventing downtime or extensive repairs.

Because of escalating costs of drillstring repair and replacement, Global Marine Drilling Co. organized a task force in March 1989 to define problem areas and establish new handling and maintenance procedures.

The task force estimated that one 20,000-ft drillstring costs about $600,000 and has a 7-year life span. Assuming the average rig life is 21 years, each rig will wear out three strings, totaling $1.8 million.

The addition of $30,000/year for full rack inspections, repairs, and downhole loss brings the total to approximately $2.4 million/rig over the 21 years.

A contractor with a fleet of 25 rigs could expend $60 million on drill pipe-the construction cost of a well-equipped, 300-ft jack up rig.

The task force identified four basic causes of drill pipe failures:

  • Tool joint and tube OD wear

  • Internal corrosion

  • Fatigue cracking in the slip and internal upset areas

  • Physical damage to the tool joint threads and shoulders, and to the tube.

DRILL PIPE MANUFACTURE

The Global Marine drill pipe task force identified 20 steps in the tube and tool joint manufacturing process, involving numerous vendors from steel making to pipe protection.

The American Petroleum Institute (API), however, recognizes the manufacturer as the company that heat treats and joins the tube to the tool joint.

Two factors affect drillstring reliability in the design and manufacturing phases:

  • The number of manufacturers and the variance in mill and processor capabilities

  • Excessive or unspecified tolerances allowed by API standards, specifically in wall thickness deviations, control of the length and shape of the internal upset (Miu), and the ability of the tool joint thread and shoulder design to withstand stress.

From further analysis, the drill pipe management team recommends a decrease in the wall thickness deviation (currently 121/2%). A reduction in deviation would allow for some corrosion and abrasion which demote drill pipe from premium to Class 2 status. Unfortunately, most modern steel mills cannot attain the ideal zero tolerance level. However, some mills can produce drill pipe with lower tolerances of 5-6%, doubling the amount of wall thickness that can be lost prior to reaching Class 2 condition.

The task force found that controlled formation of the length and shape of the Miu, in the upsetting process is one of the most critical steps in drill pipe manufacturing.

Several studies confirmed that washouts occurred near the end of the Miu, closest to the tube body-the most highly stressed area of the drill pipe during drilling and the most prone to fatigue failure (Fig. 1).

RIG FLOOR HANDLING

Although the drilling contractor usually does not control the drilling program, the contractor can maximize drilling operations with good quality control on the rig floor.

Frequently, crews eager to minimize tripping time, in fact, reduce productive drilling time by inadvertently damaging the drill pipe. The task force led to the development of a training team to teach Global Marine employees and operator personnel the proper care in rig floor handling to reduce drill pipe damage and unnecessary risk to the well. The following are some of the more important points:

  • Crews should not set the slips too hard. This causes slip dies to make deep, sharp notches that form cracks in the drill pipe and eventually result in a washout.

  • Crews can prevent drill pipe damage from overused and worn slips, dies, and bushings with more frequent and thorough inspections and maintenance.

  • After a missed stab, crews should pick up the pipe to stab again, rather than kick the pin into the box. If the pin gets hung up on the shoulder, it may score the shoulder faces or damage threads. This can cause a false torque reading, undertorqued connections, connection failures, and possibly a fishing job.

  • Crews should always use two tongs to break out connections. The use of only one tong increases the risk of damage because of unpredictable breakout torque. The one-tong approach can bend pipe in the slips under extreme high breakout situations, resulting in bent pipe, coating failure, and fatigue failure.

  • Rig-based policies for consistent redoping and the use of approved thread lubricants ensure proper thread lubrication. A dope stand averts contamination and makes it easier to apply thread compounds.

  • The Kelly spinner should never be used to "shotgun" connections.

  • Close monitoring of torque gauge accuracy ensures proper torque application.

  • tong maintenance and correct placement on the pipe facilitate proper makeup and breakout operations.

  • Recommendations for zinc-based and lead-based thread lubricant compounds must be followed to attain the correct amount of connection preload. High temperature conditions require special thread compounds.

  • A large supply of thread protectors reduces the frequency and cost of tool joint recutting and the subsequent loss of tool joint length.

  • Only mallets with soft lead or brass heads should be used to tap on the pipe because dents from steel hammers create stress risers and, eventually, cracks.

  • Careful thread cleaning and fresh lubrication help prevent improper makeup torque, thread/shoulder damage, and washouts.

  • Well-planned stand rotation during tripping avoids stressing the same part of the string repeatedly and spreads out the fatigue of the string over time.

  • If drill pipe is to be laid down, regardless of how short the period, thread protectors must be used.

  • Rotating breaks in stands while tripping prevents overtorquing the unbroken tool joint connections, provides greater opportunity to inspect more connections during trip inspections, and allows proper doping of connections.

  • Although no API specifications exist for lift sub manufacture, the lift subs must be inspected with every drill collar inspection.

  • Acidizing through drill pipe should only be allowed if the customer agrees to comply with preventive measures and to pay for inspection, repair, or replacement of drill pipe subject to damage. This policy appropriately distributes damage costs and protects the next customer.

  • Serial marking of individual joints permits tracking of downhole wear or loss and culling of joints from a string. A good marking system prevents mixing of pipe during handling for inspections or maintenance by third parties.

TOP DRIVE EFFECTS

Top drive systems allow drilling of higher risk, highly deviated wells, but these wells dramatically increase drill pipe wear and tear downhole. Top drives engage the elevators around the drill pipe while drilling, This extra wear at the slip area reduces fatigue life.

Backreaming and circulating out of the hole increase rotating hours and increase drillstring tension. Thus, more outer diameter wear can occur in deviated wells than in comparable vertical wells. Additionally, a higher chance exists for mud contamination of the boxes in stands set back without proper cleaning and redoping, unless done when running back in the hole.

Other negative features of top drives include connection damage from missed stabs and inaccessibility to the saver sub for inspection and redoping. Because of the tendency to use the same stands while drilling with a top drive, stand rotation in the string and service breaks become very important.

DOWNHOLE WEAR

The study found that adverse drilling conditions, such as drilling in compression, drilling at critical speeds, and drilling in highly deviated holes, caused more than 80% of the drill pipe damage.

Drilling in compression can result in bent pipe or excessive wear on one side of the pipe. Proper bottom hole assembly (BHA) design can remedy most compression problems, but highly deviated holes may need extra attention if drilling in compression is unavoidable. A change in mud properties or the addition of heavy-weight drill pipe above the BHA often helps lessen drill pipe wear.

Aside from damage to drill pipe, drilling in compression can damage casing. Thus, operators and contractors mutually benefit by minimizing drilling in compression.

Rotating equipment has a critical speed which varies with changes in the location of the center of gravity, mass, alignment between the axis of rotation and gravitational force, and rotational speed.

Experienced drillers should recognize when critical speeds, or harmonics, are encountered by detecting any unusual vibrations. These vibrations occur in a variety of ways, depending on the size, type, and layout of the rig and its floor equipment. Critical speed problems include bent pipe, BHA connection failures, fatigue failure of the crossover sub, washouts, and severe outer diameter wear of tool joints and tube sections.

Several factors help prevent drilling at critical speeds: the addition of heavy-weight drill pipe above the BHA, redesign of the BHA, adjustment of the weight on bit (WOB), or a change in the rotational speed.

In deviated wells, the pipe contacts more of the formation than in vertical wells. The rate of deviation, or hole curvature, has more impact on drill pipe wear than the total amount of deviation, especially if sharp doglegs exist. The increase in the lateral force of the tool joint against the formation causes high bending stresses and fatigue damage, despite the flexibility of drill pipe (Fig. 2).

To reduce the effects of high deviation, Global Marine's task force recommends the following:

  • Maintain hole curvatures below 2.5/100 ft.

  • Replace worn drill collars that may have low bending strength ratios.

  • Use proper thread compounds.

  • Check for proper torque on all connections.

  • Minimize backreaming and string rotation off bottom.

  • Use mud motors whenever possible.

CORROSION AND FATIGUE

Corrosion and fatigue augment one another to accelerate drill pipe failure. The combination of corrosion and fatigue failure is the most common and most difficult to avoid.

A properly maintained internal plastic coating can help combat corrosion. The task force recommends the use of oil-based mud whenever possible. If water-based mud is used, the high rate of corrosion can be slowed with a higher mud pH.

The task force also recommends injection of oxygenscavenging chemicals into the mud pump suction lines to reduce the amount of oxygen in the mud downhole. This method can cost-effectively reduce the corrosive damage of oxygen with the least amount of chemicals if other anticorrosion methods are inappropriate.

The drill pipe's fatigue life depends primarily on the shape of the internal upset (Miu,), the degree of hole deviation (bending stresses), corrosion (metal loss) of critical high stress areas in the drill pipe, and mechanical damage to the tube upset areas.

Mechanical damage in the upset areas results from slip cuts, hammer marks, formation cuts, etc.

More severe bending stresses concentrate at notches formed by the internal upset of the drill pipe (Fig.3). The more severe the notch effect is, the fewer bending cycles allowed before failure. This demonstrates the importance of a smooth, long upset taper.

As a result of these findings, Global Marine developed its own specifications and carefully selected pipe manufacturers capable of producing pipe of superior design, metallurgy, and upset configuration. These, along with specifications for inspection, maintenance, repair, and handling, combine to maximize the fatigue life of the drill pipe.

CHEMICAL CORROSION

H2S and CO2 can cause catastrophic failure of drill pipe. Hydrogen embrittlement, or sulfide stress cracking, occurs when hydrogen gas molecules form under high pressure within the steel grain structure. Hydrogen embrittlement can result in failure under load.

Failure usually occurs at the most highly stressed areas, such as the last engaged thread of the pin. CO2 in water-based mud combines with water to form carbonic acid which immediately reacts with exposed iron surfaces, causing severe pitting.

Oil-based mud is one of the best preventive measures to avoid the rapid corrosive damage from H2S and CO2- If oil-based mud cannot be used, the water-based mud pH should be kept at a minimum of 10.5 to neutralize acids and stop the reactions.

DOWNHOLE TROUBLESHOOTING

Effective troubleshooting is the key to preventing excessive downhole wear. For example, upon discovering bent pipe, the crew should note the area in which the bend occurs, the severity and type of the bend, and the drilling conditions. This information can help determine a change in the BHA design, the use of a higher grade of pipe, the addition of more heavyweight above the BHA, or a change in drilling parameters.

If the pipe bends because of high breakout torque, the crews should use the E-Z torque with a backup tong and place the pipe in the slips as low as possible (Fig. 4).

Additionally, the crews should know the factors that cause excessive outer diameter wear, primarily seen on tool joints. The symptoms of abnormal wear include shiny tool joints, eccentric wear on only one side of the tool joint, shiny tubes in the middle third section, and loss of bevel on tool joint shoulders. This abnormal wear can result from drilling with bent pipe, drilling in highly deviated wells, excessive backreaming in deep wells, rotating off bottom, drilling abrasive formations, operating at critical or high rotary speeds, and drilling in compression.

Following detection of the causes, the drill pipe should be monitored, repaired, or replaced.

If abrasive formations abnormally wear the pipe's surface, the friction can be reduced by:

  • Reducing lateral force between the pipe and formation by minimizing backreaming or rotating off bottom, using drill pipe rubbers, or using mud motors

  • Changing mud properties to allow for better lubricity

  • Hardbanding tool joints (those exposed to open hole).

Split or belled boxes have various causes: a reduction in outer diameter below minimum dimensions, high-torque drilling exceeding recommended makeup torque, heat checking, or hydrogen embrittlement. Thus, the remedies vary from spotting mineral oil to changing BHA design and drilling parameters.

Troubleshooting washouts depends on the location: at a connection shoulder, in the slip area, or at the internal upsets near the box or pin end.

Dry or muddy connections in the setback often indicate damage at the shoulder. Better pipe handling, proper refacing, use of thread protectors, proper makeup torque, and proper matching of bevel diameters can lessen shoulder damage. Mismatched bevels can damage other shoulders if connected to their once-appropriate mates.

Slip area washouts occur from fatigue cracks that form within a slip die mark on the outer diameter. The cracks grow inward until mud pressure washes them out. Proper high breakout procedures and maintenance of slips, bowls, and bushings help prevent slip area washouts.

Internal upset area washouts, the most serious type of washout, indicate corrosion and fatigue failure (Fig. 5). The entire drillstring may be approaching its fatigue life. The worst joints should be removed from the string and the extent of the damage noted. Continued monitoring of the string ensures removal of other bad joints before they pose a threat to the well.

DRILL PIPE INSPECTIONS

The increasing cost of third-party inspections prompted Global Marine's task force to implement two new inspection-related programs. Third-party inspectors and rig supervisors receive a stringent set of guidelines and specifications for proper inspections. In addition, rig floor personnel conduct intermediary inspections while tripping pipe and between wells.

Tripping operation inspections include visual checks for:

  • Shiny tool joints

  • High breakout torque

  • Belled or split boxes

  • Galled shoulders or threads

  • Dry or muddy connections

  • Bent pipe

  • Washouts

  • Other connection damage.

Although third-party inspections are necessary, trip inspections become more important as drilling conditions become more severe.

Drill pipe inspections on the rig between wells are more detailed than trip inspections. Thus, they can reveal defects or wear otherwise overlooked. This early detection permits lower cost repairs before extensive damage occurs. By keeping full records of these inspections, the contractor also reduces the cost of later third-party inspections.

For the inspections between wells, the crews should at a minimum:

  • Evaluate the shoulder and thread condition of the pin end and cull joints requiring refacing or recutting.

  • Check the straightness of the tube section and measure the outer diameter of the middle of each joint (for example, 4.85-in. minimum for 5-in. OD, standard weight drill pipe).

  • Inspect the internal plastic coating for wire line cuts, blisters, and extent of corrosion, with special attention to coating failure at the internal upsets because this indicates the potential for corrosion and fatigue failure.

  • Remove for recoating any joints with only 60-70% of the plastic coating remaining (Fig. 6).

  • Examine tool joints for overall and eccentric wear and note any diameter variance of more than 1/8 in.

For third-party full rack inspections, a drilling contractor representative should arrive on site before the drill pipe. The pipe must be thoroughly cleaned before it leaves the rig. The supervisor notes the inspection company's handling of the pipe and reviews the qualifications of the inspector and the condition and calibration of the inspection equipment prior to use.

The on site supervisor works with the inspector to establish an efficient route of rejection. Older drill pipe is inspected for corrosion, minimum OD, and length of tool joints. Younger pipe is assessed for tool joint damage. Pipe between the ages of 3 and 7 years takes up most of the inspection time because of the wide variation in severity and type of damage. The supervisor and the inspector determine the type of repair or maintenance required for each joint.

The primary reason for junking drill pipe is poor condition of the tube section, which cannot be rebuilt or replaced if damaged. API guidelines allow for only a 20% loss of wall thickness of any part of the tube section to maintain premium class.

Two methods assess tube section condition: a go/no-go gauge and electromagnetic inspection (EMI). A go/no-go gauge is a set caliper for quickly checking the outer diameter. EMI, also called flux leakage detection or a "buggy run," detects local damage to the tube section.

Recently, shear wave ultrasonic end area inspection tools have been developed. These can detect pits and cracks in the internal upset areas more reliably than flux leakage detection.

Scale buildup on the inspected steel surfaces influences the reliability of these methods. Often, neither the time nor the equipment is available to clean these areas adequately. Nevertheless, end area inspections are essential to cull joints.

At the end of the internal upset taper, the most likely area for a washout to occur, the wall thickness is measured with an ultrasonic thickness gauge. A baroscope determines the location of the heaviest pitting so numerous ultrasonic readings can be located and compared.

Optional inspection techniques include wet or dry magnetic particle inspections or dye-penetrant inspections. Unfortunately, there is no method to detect fatigue. Fatigue failure can still occur immediately after an inspection if the fatigue life of the drill pipe has been reached.

Although seemingly straightforward, mere visual checks of tool joints by the on site supervisor prevent costly and unnecessary repairs. The tool joint inspection examines the tool joint OD and length, shoulder and thread condition, pin stretch, and box swelling. Guidelines for transportation, handling, and storage complement the preventive maintenance and inspection techniques.

All inspections, as well as drill pipe activities, are recorded on detailed logs to track the condition of the pipe and the effects of the drill pipe management program.

Copyright 1991 Oil & Gas Journal. All Rights Reserved.