Solid expandable tubulars have been used to assist in the success and slimming of deepwater wellbores over the past two years. The expandable openhole liner system expands and seals the outside diameter of an expandable casing against the inside diameter of a string of conventionally set casing, thus slimming the wellbore compared to conventionally cased wellbores. Further slimming of wellbores was realized with the capability of expanding and sealing sequentially installed expandable casing strings, or "nested" expandable liners. This procedure decreases reduction of a typical hole size by approximately 50%. Nesting was the next step in the evolution of creating a monodiameter system, that is, a wellbore that has the same inside diameter from surface to total depth (TD). The first nesting of two expanded casings in a well was successfully completed in a drilling application in the Summer of 2001, a milestone toward creation of the monodiameter wellbore. Using nested expandable systems facilitates the employment of smaller, more economical drilling vessels to drill deepwater wells (wells drilled in water depths of 1,500 to 10,000 ft). The monodiameter system is created when the junctions of the nested expanded casing liners are "over-expanded, resulting in a single internal diameter (ID) wellbore. This type of well exhibits the ultimate diametric efficiencies" a constant ID from the top of the well to its TD. The first monodiameter "over-expanded" sealed liner overlap was produced in the lab in late 2000, opening the door for the creation of the monodiameter drill liner, followed by the production-quality monodiameter liner system. This paper reviews the evolutionary steps taken to date toward the realization of true monodiameter technology and discusses the installations that have served as milestones. This paper also discusses the potential savings realized when wellbores are slimmed using expandable systems, combined with more economic drilling vessels and the associated reduced spread-rates. Technical Evolution Solid expandable tubular technology essentially changes how to install the main load-carrying member around which all well designs are built, namely, the casing. The monodiameter system became a feasible idea with the advent of successfully expanding solid tubulars. This revolutionary concept was proven with the successful expansion of solid tubulars (initially automotive steel) by forcing an expansion cone through the tubular with hydraulic pressure and expanding it ?20%. After demonstrating conceptual proof, attention turned to refining the existing materials to address specific downhole conditions. These developments consisted of replicating desired automotive steel properties in Oil Country Tubular Goods (OCTG), changing the cone material makeup from a combination of ceramic and steel to one of all steel, and replacing welded connections with specially threaded, expandable connections. L-80 casing was developed with exceptional fracture toughness in order to achieve consistent success of expansion without pipe body failure.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractMaximizing hole conservation while optimizing well economics in both conventional and deepwater wells is a continual challenge. Addressing these challenges with new technology has provided some significant solutions, but the uncertainty when utilizing new technology with no proven track record must be risk-weighted.Solid Expandable Tubulars (SETs) have been installed in both openhole and cased-hole wellbores from November of 1999, in a variety of environments in wells on land, offshore and in deepwater to solve a range of drilling and completion challenges.This paper will discuss the drilling case histories in depth including:• Descriptions of drilling challenges surrounding the use of SETs and their next best alternatives

Maximizing hole conservation while optimizing well economics in both conventional and deepwater wells is a continual challenge. Addressing these challenges with new technology has provided some significant solutions, but the uncertainty when utilizing new technology with no proven track record must be risk-weighted. Solid Expandable Tubulars (SETs) have been installed in both openhole and cased-hole wellbores from November of 1999, in a variety of environments in wells on land, offshore and in deepwater to solve a range of drilling and completion challenges. This paper will discuss the drilling case histories in depth including:Descriptions of drilling challenges surrounding the use of SETs and their next best alternativesRisk analysis leading to the use of SETsDiscussion of the advantages and disadvantages of using SETsOperational lessons learned during installations of SETs Technology Overview Previously published papers and articles have discussed the concepts of Solid Expandable Tubular technology1 and the effect of the expansion process on the system's tubulars2,3 and connectors4. In this paper, the basics of SET technology will be briefly reviewed, emphasizing how the early products of this new technology have been applied in the drilling environment. Presentation of several case histories will demonstrate that Solid Expandable Tubular products can provide additional tools for the drilling "tool box", ultimately cutting drilling costs and bringing more dollars to the bottom line. As of this writing, 15 jobs have been performed, of which three were unsuccessful. Since learnings often are the results of problems, heavy emphasis will be placed on problems and the lessons learned. The Expansion System. The underlying concept of expandable casing is cold-working steel tubulars to the required size downhole - a process that, by its nature, is very unstable mechanically. Thus, there are many technical and operational hurdles to overcome when using cold-drawing processes in a downhole environment. An expansion cone, or mandrel, is used to permanently mechanically deform the pipe (Fig. 1). The cone is moved, or propagated, through the tubular by a differential hydraulic pressure across the cone itself and/or by a direct mechanical pull or push force. The differential pressure is pumped through an inner-string connected to the cone, and the mechanical force is applied by either raising or lowering the inner-string (Fig. 2). The progress of the cone through the tubular deforms the steel beyond its elastic limit into the plastic region, while keeping stresses below ultimate yield (Fig. 3). Expansions greater than 20 percent, based on the inside diameter of the pipe, have been accomplished. However, most applications using 4–1/4 inch to 13–3/8 inch tubulars have required expansions less than 20 percent.

This paper presents the requirements for a drilling rig to drill in up to 10,000 ft of water using a pressured riser. An analysis of deepwater wells drilled was carried out to determine what characteristics (Water depth, drilled depth, number of casing strings etc..) these wells had. A "look forward" portfolio of wells was constructed as the target for the design of the rig. A full QRA was conducted to examine the impact of emerging technologies such as Expandables and Dual Gradient and to determine which choices for rig components were appropriate. The paper includes an outline rig design for deepwater for West Africa and one for GOM operations. An outline specification for the well systems (BOP, riser configuration) is also included. A comparison is made of the impact of drilling deepwater wells with this "new" approach versus using the "conventional subsea BOP" arrangement. The paper also includes details of how the "new" approach may be applied to existing rig types and how it may be applied to a new-build. The cost implications of this step change are examined. Fully risked well cost comparisons ("new" vs "conventional") are provided along with some comment on the risks and consequences of the available choices. The paper concludes that the "new" rig specifications detailed will allow for deepwater drilling in up to 10,000 ft water depth and that in some cases there will be significant overall well cost savings. Conclusions It is possible to configure a surface BOP, slender riser and seabed shut-off device (SSOD) to successfully drill many wells in ultra deepwater. This allows use of a rig smaller than the "conventional" 5th generation rig/ship. The optimum configuration of rig/well equipment will vary depending on water depth, well type etc.. This configuration is best arrived at using a QRA approach to compare the alternatives. Significant cost savings are possible in comparison to well costs that would result from using a conventional marine riser/subsea BOP and the resultant large rig. The savings that result are dependent on the well. The work carried out (and as described in this paper) allows for a totally objective analysis of the deepwater drilling process and (once refined properly) will allow for rational decisions to be taken about rig selection and deployment. The paper sets out a description of the work process rather than detailed results of the process - presentation of detailed results would require back-up that is beyond the scope of a paper. The work that has been carried out shows how operations can be carried out in the most efficient manner possible. This has implications for both exploration and development drilling. Well Characteristics The characteristics of wells that have been drilled or are likely to be drilled were examined in order to identify the requirements for a drilling rig. The major characteristics of these wells are:Water depthMeasured depthFormation/Fracture pressure window (Number of casing strings)Metocean environment

Kinetic Pressure Control has developed the 18 ¾" 15000 psi blowout stopper (KBOS) system for applications on all subsea well activities. The 18 ¾" 15000 psi systems builds upon the successful development of the 5-1/8" 15000 psi KBOS system for surface BOP applications[5]. The system can be configured within the existing subsea BOP, by replacing a casing shear ram or blind shear ram, or can be configured as a shut-in device below the BOP. The KBOS system provides a significant improvement over existing shear ram technology, providing the ability to shear/seal any items in the wellbore, which reduces the likelihood of a blowout, resulting in an improved risk profile. The KBOS is a proprietary design which uses a pyro-technical, electrically initiated process the actuate the shearing process. The system has been designed and tested to actuate and shear/seal in milliseconds, under full wellbore flowing conditions and meets NACE/ISO sour service requirements without exemptions. The control system includes real-time monitoring and function testing capabilities, and requires minimal in-service maintenance, as the working components are isolated from the wellbore fluids. A computational predictive model has been developed, with a test regime conducted to validate the model results. A full qualification program, with 3rd party certification, has been completed to industry standards. Shearing tests have been conducted for a large range of tubulars which have been challenging to shear with existing technology. These include: 9 ½" drill collars, combinations of large OD casing and inner strings, high strength drill pipe and tool joints, wireline, and production tubing. A subsea test of the system was successfully performed in 2019 to shear large OD casing and inner string. The KBOS system utilizes technology from other industries (ballistics, military, automotive) to provide improved shearing and sealing capabilities for all well activities (drilling, completion, intervention). The improved shearing/sealing capacity and reduced time enable a reduced likelihood of a blowout and improved risk profile