Summary A growing number of operators are looking at monobore and slim-holecompletion techniques as possible solutions to economic and operational problems. Each technique can enhance the completion, and because the advantages of each concept affect a different phase of well technology, a broad spectrum of operational advantages could be generated if these techniques were merged into a single completion approach. Each philosophy, however, requires specialized equipment to provide its benefits, and attempts to unite the two strategies have created unique challenges for equipment designers. In many cases, these challenges are not really fully understood. This paper overviews several new equipment designs that are ideally suited for monobore completions in slim-hole wells. Also discussed are new servicing methods and how using these options and the newly designed equipment can overcome the difficulties challenging the design of completion equipment for the combined technologies. Introduction The oil and gas industry is focusing on operational efficiency and cost reduction more heavily than ever before, and any technique that can offer possibilities for improvement in these areas is worth investigating. This explains the recent resurgence of interest in the monobore and slim-hole concepts. Monobore completions offer operators a highly desirable degree of flexibility for maintenance operations. By design, the tubing imposes no restriction on any tool that may be deployed in the liner. Because use of special tools is eliminated for these wells, service costs are lower. Unfortunately, these operational savings typically are not realized until later in the life of the well. Because cost savings from use of the monobore concept are anticipated rather than immediate, it is difficult to justify the additional expense during the completion phase, which plays an important role in making decisions on the complexity of the downhole components. In contrast to the cost savings generated by monobore completions, those generated with the slim-hole concept are usually realized during the drilling phase because slim-hole drilling techniques offer a reduction in the cost of the cement, fluids, tubulars, etc. The timing of the cost savings explains why operators are more inclined to try slim-hole procedures. Background Slim-hole completions were noted in the oil field as early as 1942, having developed in response to increased demand for oil during World War II. Most of the wells were drilled to the top of the formation with small-diameter drillpipe; then a drill was placed on the end of a tubing string, and the tubing was used to continue drilling into the formation. After the tubing string was cemented into place, the well was perforated and placed on production. This technique greatly reduced drilling time and, subsequently, expense. The mid-1950's saw a resurfacing of the concept as a viable means of drilling in soft rock formations. At that time, technology had advanced to the point that a 4 3/4-in. bit could achieve penetration rates similar to those of an 8 3/4-in. bit, and the cost savings for slim-hole drilling came in the form of reduced horsepower requirements for the rig. However, the hazard from the reduced mud volume and the limitations on the other downhole services resulting from the small hole imposed obstacles that were insurmountable with the technology available at that time. Today, the savings from the cement, mud, and tubular components tends to be a dominant factor in well economics, and the hazard potential reported in the1950's has been addressed with more sophisticated mud-monitoring systems. The one remaining obstacle to slim-hole completions concerned the downsizing of the technologies required for efficient operational techniques. Now, however, this problem has also been addressed. A full suite of logging tools is currently available for holes smaller than 5 1/2 in., and with the combination of monobore completions in slim-hole wells, these tools help achieve the flexibility that operators have been seeking. Completion Equipment Fig. 1 shows a monobore completion system for a gas-lift installation. As stated earlier, monobore completions for slim-hole wells pose a unique challenge to the designers of the downhole components because traditional design philosophies cannot be applied to determine monobore completion design criteria. For example, because of reduced diametrical clearance, these completions will not accommodate traditional designs of subsurface flow-control devices. Also, typical lock-mandrel/nipple systems rely on interference-engagable packing to achieve a seal for plugs and chokes. In amonobore well, the restriction that the conventional nipple seal bores introduce may affect the capability to perform other downhole services, such as those required by production logging. It is clear, therefore, that design criteria used in the planning of current completion equipment must be discarded, and a different design approach must be taken. Lock-Mandrel/Landing-Nipple Systems. To address restriction problems, one significant change has occurred in landing-nipple/lock-mandrel system configurations (Fig. 2). The change has resulted in a nipple that does not pose a restriction to the tubing ID. This incongruity, a "nonnipple," is easily accepted when the improvement in the seal mechanism of the lock is considered. Instead of an interference type of seal, this lock uses an expandable seal. The nipple profile (that portion into which the mating lock keys engage) is similar to the existing nipple, but the polished-bore section of the nipple is tubing-drift ID. This provides a fixed point in the tubing that is positively locatable for installing a plug or other flow-control device. Table 1 lists specifications for this system. An additional benefit provided by this system is that current well design parameters are still applicable because only the nipple/lock systems have been modified. Another approach to addressing the requirement of eliminating a restriction for monobore wells is to eliminate the nipple completely. Nipple less Lock System. Previous designs of nipple less locks were used in the early days of the industry and were called slip-type locks. They were used primarily for downhole plug applications. These low-pressure devices normally held pressure from only one direction. The new requirement, a high-pressure lock that can withstand pressure reversals, represents a much more complex challenge. Such a device has been designed and recently installed in a number of North Sea wells (Fig. 3). This lock has been designed to set anywhere in the tubing and is both settable and retrievable with standard slick line operations. The benefit that this lock provides is that there are no limitations concerning where the lock must be set. This flexibility is an important part of the monobore concept. Table 2 gives lock specifications. P. 794^