TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWith water depths increasing to over 10,000 feet, offshore well depths exceeding 34,000 feet and extended reach targets pushing out over 35,000 feet; operators are deepening the setting depths of larger diameter and heavier casing strings. These offshore designs require landing strings with hoisting capacity approaching 2-million pounds. These requirements have exceeded the limits of previous tubular manufacturing and handling capabilities. This paper documents the design, development, manufacture and deployment of a 2-million pound landing string system to meet these requirements. The system incorporates three components: pipe, elevators and slips. The 6 5/8-inch, heavy wall, 150-ksi yield strength pipe incorporates an innovative thick-walled section in the slip contact area for resistance to slip crushing loads and a uniquely designed dual-diameter tool joint to increase elevator capacity. Slips were specially engineered to equalize radial and axial loads, increase the slip-to-pipe contact area, and optimize the contact angle to minimize the crushing loads on the pipe body. Combined with 1,000-ton elevators, the system utilizes conventional rig-up and operating procedures. The design criteria developed for landing string applications and the solutions to the unique manufacturing challenges associated with the heavy wall, high strength pipe are presented. In addition, laboratory and case studies are presented for landing operations, some with axial tension loads approaching 1.75-million pounds.SI to Metric Conversion feet ('): ft. = 3.048 E -01 m inches ("): in. = 2.54 E 00 cm 1,000-pounds per square inch: ksi = 6.894757 E 03 kPa pounds: lb. = 4.448222 E 00 N pounds per foot: ppf = 1.4594 E 01 N/m pounds per square inch: psi = 6.894757 E 00 kPa

This paper presents the results of a two-year comprehensive effort to design, test, and qualify third-generation rotary-shouldered connections (RSC) for 20,000 psi internal and 10,000 psi external pressure service. ISO13679 testing methodologies for casing and tubing were modified to evaluate the RSC pressure capability. Results from comprehensive finite element modeling and extensive laboratory testing designed to reproduce the harsh, aggressive loading modes and high pressures encountered in field use are presented. The result of this program is a RSC that incorporates a double-start thread form to reduce the number of revolutions to assemble the connection by 50 percent reducing trip time. The thread form also provides a unique dual-radius thread root that offers a step change improvement in fatigue resistance. A metal-to-metal seal provides pressure integrity. In addition to providing a 20,000 psi internal and 10,000 psi external pressure rating, the new connections provide increased mechanical and hydraulic performance compared to second generation high torque connections while also providing fatigue performance greater than standard API connections. Introduction New developments in drilling tubulars are rapidly evolving and represent enabling technologies for the industry's continued advancement of drilling deeper, further and more cost-effective wells. Much focus has been made toward the advancement of RSC technology to permit high torque drilling of extended reach, directional and horizontal wells. In response to this need, the development of third generation, ultra-high torque connections was recently announced providing reduced tripping times and the mechanical and hydraulic load requirements for drilling today's deepwater, extended reach and ultra-deep wells. The next step in the evolution of RSCs has now occurred with the development of a third-generation, gas-tight, pressure rated connection providing enabling technology for high-pressure completion and workover, drill-stem testing, UBD and intervention riser applications. Although drill pipe, drill pipe connections and drill stem materials represent mature technologies, innovations are being developed in these areas. This third generation gas-tight, double-shoulder connection presented here represents several advancements that address some of the challenges ahead. Double-Shoulder Connection Design Development First generation double-shoulder connections (1st Gen. DSC), see Figure 1, were introduced in the early 1980's.4 1st Gen. DSC's were basically API rotary-shoulder connections (primarily NC or FH) with a second torque shoulder added inside the box member at the pin nose interface.1,3 These 1st Gen. DSC's incorporated the same basic design features in terms of thread form, taper, lead, pitch diameters, etc. as the API connection on which they were based. These connections yielded a simple, straight forward solution that increased the connection torsional strength by approximately 40 percent over the corresponding API connection.

Shale drilling for both natural gas and hydrocarbon liquids has increased dramatically in North America over the last several years. Shale oil and gas deposits are known to exist all over the globe including Australia and the rest of the Asia Pacific. This paper discusses the requirements for drillpipe in shale drilling applications along with a review of some of the challenges and problems associated with the drillstring in these critical applications. Most wells are horizontal with long departures. Typical wells in the Balkan Shale are 17,000 ft MD, 11,000 ft TVD with a 6,000 ft horizontal reach. Drilling these wells puts huge demands on the drillpipe and rotary shoulder connections and pushes the drilling equipment and rig crews beyond the requirements of typical onshore well construction projects. Many, if not most, of the shale wells require advanced design, double shoulder connections (DSC) on the drillstring to provide the enhanced torsional strength and streamlined connection dimensions required to effectively drill these prospects. The paper presents connection design solutions along with considerations for safe and efficient running procedures. Although, the advanced DSCs are designed to be transparent to normal drilling operations, compared to standard API connections, some problems have been encountered. The paper addresses these running and handling issues and provides guidelines to mitigate these problems. Excessive tool joint and drillpipe body wear have also been encountered in several shale plays. This is discussed, along with recommendations to limit wear. Stick-slip has created drillstring problems on several wells. Stick-slip can cause damage to the drillpipe and, in the extreme, downhole connection back-offs have occurred. The paper looks at aspects of case histories to illustrate these issues and provides lessons learned to improve shale drilling operations in North America, the Asia Pacific and other regions of the world.

Summary The effect of downhole axial compression forces on casing string designs and connectors is a major concern to engineers designing high-temperature, high-pressure, extended reach, and horizontal wells. Widespread concern regarding the significance of compression loads on casing string design is relatively recent. For decades engineers were either not aware that high-compression loads may occur or were not concerned about the effect of compression on the casing. This paper discusses the sources of axial compression forces in straight and directional wells. Methods to analyze casing subjected to compression and bending loading are presented including the effect of compression and bending on the von Mises equivalent stress state of the pipe. Connector selection for casing applications where high axial compression loads are anticipated is critical. Compression ratings for API casing connectors have never been addressed in API standards. The paper offers methods to evaluate API connectors for applications with significant compression loading. Compression ratings for premium casing connectors are generally available, but the justification for these ratings varies substantially from one manufacturer to another and the basis for the compression ratings may not be well documented. The paper discusses compression rating methods for various premium connector configurations including threaded and coupled, flush and near flush. Desirable and undesirable premium connector features that relate to compression capacity are reviewed. Results from compression testing of premium connectors are also presented. The paper benefits engineers involved in the design of casing strings for applications with high compression and bending loading. Background Conventional casing string design analysis has traditionally been based on calculating minimum design factors for internal pressure (burst), collapse, and axial tension. Axial tension design factors are often calculated based on the string weight in air. If the effect of buoyancy is accounted for, the adjusted weight per foot of the pipe in the drilling fluid is generally used to determine string weight. Axial compression forces acting on the casing are generally not considered. The trend in more high-temperature, high-pressure (HTHP), extended reach and horizontal wells combined with the availability of sophisticated casing design models has increased awareness that casing can experience severe axial compression loads and that these compression forces have a significant impact on the overall safety of the string design and the well. High temperatures, high pressures, and borehole friction can result in substantial axial compression forces acting on the casing. Downhole Causes of Axial Compression Understanding the impact of compression forces on casing and casing connectors starts with recognizing the sources of compression forces in the well. Several downhole factors cause axial compression loading of casing strings: buoyancy, Poisson's effect or (reverse) ballooning, thermal expansion, borehole friction or drag in directional wells, and slack-off. Buoyancy. Buoyancy from the drilling fluid results in axial compression forces at the bottom of the casing string and at crossovers in the string (Fig. 1). In conventional casing design, buoyancy is accounted for by using an adjusted weight per foot for the casing in fluid to determine the tension force at the top of the string. This approach yields the correct tension force at the top of a string suspended in fluid, but has several inaccuracies and shortcomings if applied to detailed evaluation of casing string designs. The correct method to account for buoyancy is the pressure/area method.1 The actual fluid pressure at the bottom of the string is multiplied by the cross-sectional area of the pipe to arrive at the buoyancy force. This is a compressive force acting on the bottom of the string. The axial load on the casing is the hanging weight of the pipe (in air) minus the buoyancy force acting on the string. The equation for buoyancy force for open casing is as follows: F B = − P o A p b . ( 1 ) For casing with a plugged end (float valve holding): F B = p i A i − p o A o . ( 2 ) Throughout this paper tension forces and stresses are positive and compressive forces and stresses are negative. Fig. 2 shows plots of axial force vs. depth for a 12,000 ft, 9 5/8-in. 53.5-lbf/ft (0.545-in. wall) casing string suspended in 16-lbm/gal fluid based on the adjusted weight method and the pressure/area method. Note, the adjusted weight method yields the correct value at the top of the string, but this is the only place where the force profile is correct and no indication that axial compression is effecting the lower portion of the casing is shown. The compression force due to buoyancy at the bottom of the string is equal to 155,000 lbf. Once the casing string is cemented the buoyancy force is "locked in" below the cement top and effects all subsequent load conditions. Poisson's Effect of (Reverse) Ballooning. After the casing string is cemented changes in internal or external pressure effect the axial force profile in the casing. Pipe that is free to move (not fixed) shortens when internal pressure increases or external pressure decreases. This is often called ballooning or Poisson's effect. Conversely, decreases in internal pressure or increases in external pressure cause pipe that is free to move to get longer (reverse ballooning). Since casing is generally cemented and cannot move, changes in pressure cause a change in axial force (Fig. 3). Net increases in external pressure and net decreases in internal pressure generate axial compression forces. The force due to ballooning or Poisson's effect is calculated with the following formula: F P = 0.6 [ Δ p i A i − Δ p o A o ] . ( 3 ) Partial or complete evacuation load conditions can generate high axial compression forces in the casing. For example, a lost circulation condition inside of 9 5/8-in. 53.5-lbf/ft casing that results in a net reduction in average internal pressure of 7,000 psi generates an axial compression load of 240,000 lbf in the casing.

In 2010, Chevron Thailand successfully conducted a unique comparative field test involving two strings of drill pipe, one featuring a new 3rd generation double shoulder connection (3rd Gen DSC) against another with the previous generation connection (2nd Gen DSC). Both strings were used to drill off the same offshore platform with all parameters being equal besides the drill pipe connection selection. This test was required to gauge a possible solution to the operator's need for higher drilling torque in the challenging fast rotary drilling of the slimhole production interval. The evaluated 3rd Gen DSC was originally developed and introduced to allow drilling always more challenging wells. It was designed to achieve a set of performances, which exceed the capability of the successful 2nd Gen DSC for torque and hydraulics with an enhanced fatigue resistance. One of the particular design priorities was to allow for fast makeup and breakout through the use of a new feature to drill pipe; a double start thread. Results of this field trial were gathered in a previous paper that shows actual time saving in running speed, which is of interest to Chevron, initial trend seen in the lower number of connection needing repairs and evaluation of the cost saving for adopting the new technology on all rigs drilling for the operator. Based on this initial set of data, Chevron decided to switch to the 3rd Gen DSC for the 4 in. drill pipe used in slimhole drilling. This new paper will briefly summarize the result of previously presented material but will focus on the actual field experience with the new technology deployed on three drilling rigs for more than six months now. Special emphasis will be put on evaluating the connection ruggedness through results found in the inspection of the equipment, which was hard to evaluate on the initial short time trial.