A new tubular design offers an alternative to drilling strings in deepwater applications.

Concurrent with seismic innovations that have significantly increased the exploration and production industry's ability to find deep oil and gas reservoirs during the past 10 years, oilfield manufacturing and service companies have aggressively developed new drilling, completion and production technologies to economically access and exploit those reservoirs. Landing strings - tubulars with rotary shoulder connections and tube wall thicknesses that exceed standard API drill pipe specifications - are one of those technological innovations. These high-performance tubulars enable and expedite lifting of the extremely long, heavy casing strings used in deepwater wells.
Background
The continuous extension of the deepwater drilling frontier has increased the need for heavy-wall drill pipe landing strings. Initial expectations for landing strings were that they would be used for drilling as well as running casing. However, most drilling contractors have chosen to maintain separate, dedicated landing and drilling strings due to conflicting design parameters despite the additional rig space required for landing string storage
Design considerations
Deeper offshore wells not only increase the load and tensile capacity requirements on downhole tubulars, but they also introduce additional design and operating considerations such as connection selection, elevator and hoisting capacity, potential tube body slip crushing and rig space use.
The tensile requirement for standard API drill pipe tube body is generally less than that of the attached rotary shoulder connection, although the tube's torsional strength typically exceeds the connection's. However, because landing strings generally dictate nonstandard ratings, the performance characteristics of the tube and the connection must be considered independently and as a single unit.
Tube grade. The majority of the 40-plus landing strings - 300,000 ft (915,000 m) of pipe - in use meet API's S-135 specification (135-ksi minimum yield strength). However, the tube material's yield strength is not limited to standard API grades. Several Z-140 and V-150 grade strings have been manufactured, and a few have been ordered specifying lower yield-strength materials tested by the National Association of Corrosion Engineers (NACE). Because increasing the tube body's yield strength lowers the impact properties of the material and increases susceptibility to sulfide stress cracking and other types of corrosion, offshore and sour well environments may dictate use of NACE-tested 105-ksi or 95-ksi yield-strength material.
Tube body. The API 5D Specification for Drill Pipe defines the lifting capacity of the tube as the product of its yield strength and the area of the tube body's cross-section. Cross-section improvements are greater when the tube's outside diameter is increased than when its inside diameter is decreased. Additionally, for a given required cross-section, a larger inside diameter improves hydraulics for cementing and circulating. Due to the combination of these two factors, more 6 5/8-in. landing strings have been purchased than any other size.
However, optimal tube body configuration involves tradeoffs between tension capacity, hydraulics and handling efficiencies. Matching the tube outside diameters and connection types of the landing and drilling strings expedites changeover time between the two and mitigates the need for multiple sets of differently sized slips, elevators, crossovers and other types of handling equipment on the rig. Recognition of these efficiencies is demonstrated by the practice of matching 5-in., 5-in. FH and 5-in. HT55 drilling and landing strings and more recently in the demand for matching 5 7/8-in. XT57 deepwater drillstrings and similarly sized landing strings.
Tube wall thickness. By definition, landing strings are tubulars with rotary shoulder connections and tube wall thicknesses that exceed standard API drill pipe specifications.
Connection selection. Casing load requirements necessitate that rotary shoulder connections be capable of lifting equal or greater tension than the tube body and that the weld or attachment of the tool joint exceed the string's lifting capacity. Tool joint connections can place load limitations on the landing string, including its torque capacity, elevator and hoisting capacity and the connection's own tensile capacity if the tool joint type and dimensions are not properly selected.
In most applications, torque requirements are not a design consideration because the landing string is not rotated. In other applications, however, rotating the landing string prior to setting the casing is desirable to reduce the drilling mud's gel strength and to improve casing cementation integrity. High side loads, along with high friction and high torque, are generated when a heavy casing string is turned in the wellbore, so connection torque is a consideration when designing a rotating landing string.
A rotary shoulder connection's torque limitation is its makeup torque (MUT), not its torsional strength. If the torque applied to the connection downhole does not exceed the connection's MUT, the connection will not tighten up downhole beyond its MUT limit. Downhole connection makeup is largely uncontrollable and should be avoided at all costs given the potentially catastrophic risk of connection torsion failure. Standard API-type connections provide adequate torque and tension for landing strings that will not be subject to rotation. However, if the landing string will be rotated, proprietary high-performance connections may be required. Torque and drag simulators are used to predict torque loads throughout a string and identify the torque loading at each connection. Casing connections and their MUTs vs. predicted torque loads also should be evaluated to mitigate possible casing string connection makeup downhole.
Pin-neck tensile capacity. Once the connection type is selected, the connection outside diameter and inside diameter must be defined with the understanding that the inside diameter determines the connection's tensile capacity. When selecting a landing string connection of the same type used in the drillstring, a much smaller pin inside diameter typically is needed to ensure that the cross-sectional area of the pin will support the landing string's tensile load demands. Selection of the connection pin inside diameter should yield a connection tensile capacity at least equal to the tube's tensile capacity at new nominal 100% wall thickness.
A common design practice applies the same connection MUT methodology to the landing string as is used to define the drillstring's MUTs with an equivalent connection. However, for landing strings that will not be rotated, this practice results in greater MUT than may be needed. Elevated MUTs prestretch the connection pin neck and may de-rate the connection's tensile capacity. In most landing string applications, a MUT adequate to ensure that the connection's shoulders will not separate due to tension, pressure and bending loads is sufficient to successfully run the casing string. Tool joint manufacturers' technical service personnel can provide designers with MUT values matched to a given connection's tensile capacity under prescribed operating conditions.
Elevator and hoisting capacity. Elevator and hoisting capacity is a particularly important design consideration because elevator capacity determines the rig's ability to hoist and support the landing string during the casing run. Elevator capacity is based on the maximum contact-bearing stress between the elevator shoulder and the 18° taper on the box-end tool joint. Larger tool joint outside diameters provide more contact area on the 18° taper, thereby increasing the landing string's hoisting capacity. In deep drilling applications, the contact-bearing stress exceeds 65%, sometimes even approaching 100%, of the elevator's specified minimum yield strength. The elevator capacity must therefore exceed or closely approximate the landing string tube's tensile capacity at 100% of new nominal wall thickness.
Properly sized tool joint outside diameters prevent running speed impairment, suboptimal hydraulic performance and unnecessary expenses in purchasing and running the landing string. Although tool joint outside diameter wear in nonrotating landing string connections is less critical than tool joint wear in drilling strings, leading landing string manufacturers offer double-diameter tool joints. A double-diameter connection has a larger outside diameter near the 18° taper, increasing elevator capacity, along with a smaller tool joint outside diameter near the box face to facilitate fishing of the string should it be used in open- or cased-hole situations. The smaller tool joint outside diameter has the additional advantage of reducing the connection's MUT requirement.
Finally, if the landing string's elevator capacity limits the string's lifting capacity, the designer needs to determine at what load a different handling system will be required. Square (90°) elevator shoulders are an alternative to 18° shoulders if repeated high loads are anticipated. Although the square shoulder design does not increase the connection's lifting capacity, it does reduce lateral loads on the elevator, thereby minimizing tool joint wear and damage.
Slip crushing. As water and well depths continue to increase and landing strings become even heavier, slip crushing of the tube becomes a limiting factor. The maximum rated slip capacity is 1.5 million lb, so landing strings will have to be modified to increase the tube's cross-section area in the interest of preventing crushing as casing loads increase. Another option involves handling subs with walls thicker than the landing string's tube body to provide a stronger area for slip placement. Elevator capacity also may become a limiting constraint and may require the use of specially designed high-capacity elevator handling equipment.
Although landing string technology is so new that it is not been addressed in any industry standard, more than 40 application-specific landing strings have enabled and expedited the drilling and completion of wells in deepwater projects worldwide. Landing string design involves different design considerations than are considered in conventional drillstring design. Innovations such as double-diameter tool joints, slip-proof tube sections and specialized running and handling equipment have extended the reach of extremely heavy casing runs, and future refinements may make landing strings an important tool for many more deepwater drilling projects.

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