CATEGORIZED | 2010, May/June

Development of 2.5 million-lb landing string stretches limits of manufacturing capabilities

Posted on 30 April 2010

By James N Brock, David Chin, NOV Grant Prideco; Leianne W Sanclemente, Workstrings

Figure 1: Although design compromises had to be made, a safe and functional 2.5 million-lb landing string, with its components detailed above, was successfully developed.

Figure 1: Although design compromises had to be made, a safe and functional 2.5 million-lb landing string, with its components detailed above, was successfully developed.

Deepwater and ultra-deepwater well designs continue to drive the requirement for higher tension-capacity landing strings. Water depth and total depth are increasing, and step-outs are being extended. This, combined with the often narrow margin between pore pressure, mud weight and fracture gradient, is causing well designers to set more intermediate casing strings. In turn, that is pushing large-diameter, heavy casing strings to deeper setting depths to maintain hole size and reach the intended hydrocarbon targets.

Initially, casing, liners and offshore casing strings set in subsea wellheads were simply run on the drill pipe that was used to drill the well. The axial tension loads encountered created no significant concerns and were well within the capabilities of the standard drill pipe and pipe-handling tools used to drill the well.

As setting loads increased, more specialized systems were required to run these longer and heavier casing strings in increasing water depths. Initially, it was sufficient to simply increase wall thicknesses, increase slip segment lengths, increase material strengths and enlarge cross-sectional areas; however, unique fit-for-purpose designs would be required.


Initial fit-for-purpose solutions were developed with increased load capacities targeted toward anticipated running loads for specific areas or projects.  Lessons learned during this period led to the development of more standardized products suitable for a wide range of critical projects.

As ultra-high capacity landing strings were developed, slip-crushing was identified as a major obstacle. With the current slips available, the slip-crushing resistance for the pipe body is less than its axial tensile capacity. To address this issue, a special thick wall section was provided in the slip-gripping area.  Dual-diameter tool joints were utilized to increase elevator capacity.

Figure 2 (left): FEA of standard bevel diameter at 80,000 ft-lbs makeup torque. Figure 3 (right): FEA of landing string bevel diameter at 80,000 ft-lbs makeup torque.

Figure 2 (left): FEA of standard bevel diameter at 80,000 ft-lbs makeup torque. Figure 3 (right): FEA of landing string bevel diameter at 80,000 ft-lbs makeup torque.

A 2 million-lb slip-based landing string incorporating the above features was manufactured in 2004. Specially engineered elevators and slips completed this ultra-high capacity landing string system.

This system has now been deployed multiple times and has successfully set casing with loads approaching 1.75 million lbs. The development of the 2 million-lb landing string led to the development of the first published design criteria for landing strings.

Wells that are more difficult, higher-capacity rigs, top drives and associated drilling equipment have now created a demand for a landing string of even higher capacity. Operators are setting larger diameters and heavier casings to ever-increasing depths, requiring landing strings with increased setting capacity.  Drilling rigs, top drives and associated equipment with capacity of 1,250 tons are in use.

The past several years have seen well designs pushing the 13 5/8-in.

casing point to below 20,000 ft. Current and future designs are pushing the 16-in. casing point below 20,000 ft. Final well depths are at 34,000 ftand going deeper. Production liners and tiebacks at these depths have increased in size, wall thickness and weight and are approaching the setting loads of the intermediate casing strings. These intermediate and production casing strings are being designed with setting loads exceeding 1.75 million lbs.

At these loads, well designers include a minimum of 200,000 lbs of additional slip-crushing capacity and overpull to account for the dynamics of rig movement and setting the slips. Some case histories have already reached the 2 million-lb hookload limit, including required overpull, while landing these types of strings.

Current limitations on the components of the rig equipment include derrick rating, top drive rating and/or drill line rating. Contractors have begun to install some 1,250-ton equipment, but for the deepwater rig class, it is not yet common for all equipment on the rig to have a 1,250-ton rating. Higher rig capacities will be required to run casing strings from 2 million lbs to 2.5 million lbs and prevent limiting the well design.

Landing strings with 2.5 million-lb capacity will be required, and the industry is in the process of qualifying 1,250-ton elevators and slips to run this 2.5 million-lb landing string to full capacity.


The landing string design criteria referenced above was developed over several years and was refined with design and manufacturing of several purpose-built landing strings. As the criteria was applied to the design of a landing string with a 2.5 million-lb capacity, several challenges had to be met.

Pipe body

The weakest component of previously manufactured 2 million-lb landing string design was the 150,000-psi yield strength tube.

Utilizing the 165,000-psi yield strength tube provided the additional tensile capacity needed to achieve a 2.5 million-lb tensile capacity rating. The higher yield material significantly increased the slip-crushing capacity of the tube body to 2 million lbs. This is desirable in case of an unexpected situation requiring setting the slips on the tube, such as a loss of power or loss of control or to facilitate space-out.

These situations have occurred during deployments of the 2 million-lb landing string. For 6 5/8-in. diameter V-150 grade pipe, 1.125-in. wall thickness is required for the pipe body tensile rating at 90% remaining body wall (RBW) to meet the 2.5 million-lb rating.

By utilizing a 165,000-psi SMYS pipe, the wall thickness can be reduced to 1.000-in. resulting in a 5% decrease in string weight.

Although 6 5/8-in., 1.000-in. wall thickness, range 3 pipe was the preferred choice for the 2.5 million-lb landing string, 6 5/8-in. 0.938-in. wall thickness range 2 pipe was used due to supply chain logistics. The landing string was manufactured to a 95% RBW requirement. Landing strings with this high-load capacity are generally ordered at a minimum of 95% RBW and experience minimum rotation during landing and cementing operations. These industry practices justified increasing the design criteria from 90% to 92% RBW to achieve the tensile capacity on this extreme design.

An ongoing inspection requirement of 92% RBW will be required for the landing string to maintain a 2.5 million-lb rating.

A drill pipe grade with a minimum yield strength of 165 ksi was developed to meet the needs of not only high-capacity landing strings but also for high-capacity drillstrings required for drilling ultra-deep wells, and high strength-to-weight drillstrings required to reduce tensile and drag load in ultra-extended reach wells. The UD-165 grade is a refined Cr-Mo-Ni similar to the alloy used for high-toughness (NS-1) S-135T, Z-140 and V-150 grades but with the addition of micro-alloying constituents.  Developmental testing included small sample fracture and fatigue test, impact test, and full-size field trials.

Heavy-wall slip section

Slip-crushing capacity is a primary design concern for landing strings because, for a given tube, it is less than the tube tensile capacity. For high-capacity landing strings, the use of a heavy-wall slip section (HWSS) is required. As landing string capacity approaches 2.5 million lbs, obtaining adequate slip-crushing resistance, even with the HWSS, can prove difficult due to dimensional and manufacturing restrictions.

The HWSS OD must equal the pipe body upset diameter, DTE, in order to use standard elevator bushings. The HWSS ID is limited by maximum area of the friction welds that join the HWSS to the pipe upset and to the tool joint. For 6 5/8 -in. pipe, DTE equals 6.906 in., and the minimum ID of the HWSS is 3.500 in.

Material with a SMYS of 155,000 psi is required for the slip-crushing capacity of the HWSS to equal or exceed the tensile capacity of the pipe body. Due to the 48-in. length limitation of the friction welder, the HWSS is made from two parts. One section is plain ended, and one section is integral with the box tool joint.

Since the impact of the higher-strength material on the fatigue resistance of the RSC was not known, only the plain-end section of the HWSS was made from the 155,000-psi SMYS material, and the integral HWSS-box tool joint section was made of 135,000-psi SMYS material.

Tool joint

For landing string applications, tool joint design is concerned with two issues:

• Tensile capacity of the rotary-shouldered connection (RSC).

• Elevator capacity.

RSC tensile capacity is easily obtained by using 135,000-psi SYMS tool joint material. Normally, standard tool joints for API RSC are made from 120,000-psi SYMS material. However, use of high yield strength material is a proven technology for proprietary RSCs. Due to manufacturing requirements, the ID of the RSC must equal the ID of the HWSS, 3.500 in., as noted above.

A more difficult challenge is obtaining the necessary elevator capacity.  Elevator capacity is calculated from the projected area of the tool joint in contact with the elevator bushing and the compressive yield strength of the elevator bushing.

As mentioned, a dual-diameter tool joint is used to provide a balanced connection and adequate elevator capacity. A tool-joint diameter of 8.688 in. was selected for tool-joint OD over the connection. This provides a balanced connection with an AB/AP ratio of 1.06. The standard elevator bushing compressive strength value is 110,100 psi. This would require the tool-joint diameter adjacent to the taper to be equal to 9.125 in. for the elevator capacity to equal the tensile rating of 6 5/8-in., 1.000-in. wall thickness, UD-165 pipe.

Again, the physical limits of the friction welder come into play. The ID of the friction welder spindle is 9 in. Therefore, the maximum tool-joint diameter is limited to 8.875 in.

Although, this does not meet the preferred design criteria, fortunately this does provide elevator capacity in excess of the 2.5 million-lb rating. The taper of the elevator shoulder was increased from the standard 18° to 45° to accommodate the high-capacity elevator bushing.

Weld strength

The weld strength is limited by the alloy composition of the two mated components. For the 2.5 million-lb landing string, the expected weld yield strength would be 125,000 psi or higher. As mentioned, the weld area is defined by the dimensions of the HWSS, or 6.906-in. OD by 3.500-in. ID. The required weld yield strength calculates to 122,657 psi, which is below the 125,000-psi minimum and therefore acceptable.

Rotary-shouldered connection

Normally, API RSC are selected for landing strings, as the higher torque and slimmer profiles of proprietary RSCs are not required. The 6 5/8-in. FH connection on a properly sized tool joint provides adequate tensile strength. However, there are issues in regards to yielding the connection upon makeup and connection shoulder separation.

The tool joint material is 135,000 psi SMYS with tool-joint OD of 8.688 in. and ID of 3.500 in. With this material yield strength and dimensions, the recommended makeup torque is 80,000 ft-lbs, and the minimum makeup torque is 78,000 ft-lbs. At these makeup torques, the bearing stress at the primary shoulder exceeds the minimum yield strength of the material.

This extreme bearing stress would lead to galling of the primary shoulder and deformation of the counterbore area.  The yielded area, highlighted in red in Figure 2, shows the yielding to occur at about a 45° plane perpendicular to the primary shoulder and extends into the first two threads of the connection. This extent of yielding is unacceptable in any rotary-shoulder connection.

To eliminate the yielding, one solution is to decrease the makeup torque in order to reduce the bearing stress at the primary shoulder. The connection required a 135,000-psi SMYS to overcome tensile capacity requirements for the connection; but for torsional strength, the high yield strength was not needed. By using 120,000-psi SMYS instead to calculate torsional yield, the recommended makeup torque is reduced to 71,000 ft-lbs and the minimum makeup torque is reduced to 69,500 ft-lbs.

At these reduced makeup torques, bearing stress is on the edge of being acceptable, but another problem arises. If the 2.5 million-lb load were applied with the reduced makeup torque, shoulder separation would occur.

In the analysis, the increased load in combination with a reduced makeup torque posed a problem for the 6 5/8-in. FH connection – shoulder separation would occur at 2.3 million lbs. The easiest way to combat shoulder separation is to increase makeup torque, but that would lead to increased bearing stress as described. To alleviate high bearing stress, the makeup torque had to be reduced, but that would lead to shoulder separation. The limits of the 6 5/8-in. FH connection became apparent, and a new solution was needed.

The goal was to have enough contact area to distribute the bearing stress over a broader area and to maintain sufficient makeup torque to prevent shoulder separation. A solution was implemented by increasing the bevel diameter to 8.078 in., the same bevel diameter used for drill collars. This resolved the high contact stress in the primary shoulder. With the increased makeup torque, the connection shoulder remains intact at a 2.5 million-lb load.

A FEA was conducted to analyze the contact stress at the primary shoulder and the contact pressure at a 2.5 million -lb tensile load. The end result is a modified 6 5/8-in. FH with an increased bevel diameter of 8.078 in, a recommended makeup torque of 80,000 ft-lbs, a minimum makeup torque of 78,000 ft-lbs, and 135,000 psi SMYS tool joints (Figure 3).

At a 2.5 million-lb tensile load, the contact pressures at the primary shoulder are 2,155 psi and 1,006 psi for recommended and minimum makeup torque respectively. By altering the bevel diameter to 8.078 in., interchangeability will be an issue when making up to a standard 6 5/8-in. FH drill pipe connection. A crossover sub would be required to go from the standard bevel diameter to the landing string bevel diameter.


A 2.5 million-lb landing string was manufactured, although compromises had to be made in the original design criteria.

The preferred choice for the 6-5/8 inch OD UD-165 pipe was range 3 with 1.000 in. wall thickness. Due to green tube delivery, range 2 pipe with a 0.938 in. wall thickness was used. This will require the pipe body to be in rated at 92% RBW instead of 90% RBW per the design criteria. The pipe must be periodically inspected to a 92% RBW requirement to maintain a 2.5 million-lb rating.

Once the pipe body tube is established, it is preferable to design the remaining components assuring that the pipe body is the weakest component, so in case of overload, the pipe body would yield instead of the connection or weld. Due to the 9-in. ID limit of the friction welder spindle, the maximum allowable finished tool-joint OD is 8.875 in. This results in an elevator capacity of 2,510,400 lbs, which exceeds the 2.5 million-lb rating but falls short of the design criterion of 2,765,200 lbs, equal to or greater than the tensile capacity of the pipe body in new condition.

Design of a safe and functional 2.5 million-lb landing string was accomplished, although it taxed the limits of manufacturing capabilities. Pipe with SMYS of 165 ksi was developed, tested, field-trialed and incorporated into the design. HWSS was successfully made from material with 155 ksi SMYS for the first time. The sealing limits of standard API RCS was extended by redesign of the connection bevel diameter.

This article is based on a presentation at the IADC International Deepwater Drilling Conference & Exhibition, 2-3 March 2010 in Rio de Janeiro, Brazil.

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