fax 01-972-952-9435. AbstractIn recent years, new technology has significantly improved the economics in high-cost drilling environments worldwide. In a western Siberian case, two service providers recently combined their technologies and operating procedures to yield reduced drilling costs and overall improved project economics. The service companies cooperated to produce the best results for the project and the customer. This paper describes a project in western Siberia, a welldeveloped, low-cost environment. Drilling performance had to be measurable and repeatable. The major challenge was to design a polycrystalline diamond compact (PDC) drillbit/mud-motor combination for use on Russian-made rigs to achieve performance improvement. Issues included tool face control, initial cost of PDC drill bits, and in-country rigs incapable of delivering adequate torque and hydraulic horsepower to the PDC bit.Applied technology included a new PDC bit designed for steerable motors in projects in which tool face control was a primary concern. The PDC bit was optimized for formation characteristics and motor capabilities by use of depth-of-cut control (DOCC) technology. This optimization reduced torque fluctuations that, in turn, increased tool face control while sliding and increased the rate of penetration (ROP) in rotary mode. Maximizing the benefit of the bit, a special motor was used that was capable of delivering high torque to allow consistently high ROP while maintaining trajectory control. This combination resulted in successful high-performance drilling.The objective was to complete intervals normally requiring several bits with a single bit run at higher average ROP. The results were indeed rewarding. There were 66% fewer trips per 8½-in. section, on average, compared to offset wells, in conjunction with a 37% reduction in drilling hours, equating to an ROP improvement of 27%. In spite of the additional cost of the PDC and high-torque motor, the system delivered the lowest cost per foot vs. the best offsets from three drilling pads examined. An important feature of the application was that the bit/motor combination was run on a risk/reward incentive program.

Many forms of "beat-the-curve" incentive contracts are in use in the drilling industry to reduce cost and improve project performance. A successful variation involved drilling conventional deviated wells from pads in less than two-thirds of the budgeted time for a lump-sum fee. Modulators, included in the contract to account for nonproductive times (NPT), were subsequently used to adjust the lump-sum fee, depending on the party responsible for the NPT. Historically, the deviated hole sections were drilled with turbines and local tricone bits requiring multiple trips for bit changes, turbine bent-housing setting changes, and directional surveys. The new plan included the use of a telemetry system, positive displacement motors, and polycrystalline diamond compact (PDC) drill bits. One run per section was targeted, and results were achieved after a few wells by experimenting with several bottomhole assembly (BHA) configurations and PDC design combinations. The wells were drilled in 22 to 26 days instead of the originally planned 40 days. These results are attributable to a concerted effort by the operator, drilling contractor, and the service companies to identify and eliminate "invisible" NPT by applying fit-for-purpose technology and better planning. Several time-saving practices were also adopted. A main contributor to the success was that the local drilling contractor adopted the mind-set change for all the contractor rigs, including those not associated with the project. Cooperation developed the means to overcome the limitations of the drilling equipment belonging to the drilling contractor: first, an external audit identified critical areas needing immediate improvement, and then these areas were subsequently remedied jointly without creating a heavy financial burden on the drilling contractor. Introduction Historically in Russia, all boreholes were S-shaped until the introduction of horizontal drilling1 with western technology several years ago. The S-shaped wells were drilled from pads constructed in swampy fields that were actually frozen for 8 or 9 months of the year but were extremely soft other times. Owing to the nature of this environment, it was desirable to drill as many possible wells from the same pad to minimize location cost. In some cases, this meant drilling to large-displacement downhole targets up to 2 km from the pad location. Russian manufactured rigs have successfully been used to drill these wells in conjunction with Russian technology and equipment (turbines, telemetry system, aluminum drillpipe, and drill bits). However, inherent problems with the technology in use included the following:inability to rotate with aluminum drill pipefrequent bit trips owing to short bearing lifefrequent trips for bent-housing setting adjustment to correct inclination and azimuthold, time-consuming surveying method. These problems not only caused invisible lost time but also created tortuosity in the wellbore, making subsequent operations rather difficult and requiring extensive hole reaming where corrections were made. As a result, it was standard practice to make frequent reaming trips and a final checktrip with a nearly full-size stabilizer to increase the chance of running casing to the bottom. This phenomenon was in contrast to observations in analogous sections while drilling horizontal wells with pilot holes; therefore, the operator was approached to consider using similar western technology to reduce drilling times dramatically. It was hence the beginning of the targettime based performance contract. This paper describes the processes and methodologies applied which brought about the results.

fax 01-972-952-9435. AbstractThe history of integrated services is a decade old, yet the concept has found new application. A new contract model whereby certain services were contracted to drill horizontal wells on a lump-sum fee basis enhanced the existing relationship between operator and service company. The workscope covered provision of downhole drilling services, tools, and equipment to a maximum total measured depth. Conventional and slim design well options were considered, and equipment specifications were decided to provide flexibility, depending on ongoing reservoir modeling results and production forecasts.A joint project team consisting of the operator and three principal contractors (namely integrated drilling services, drilling fluids, and rig) spudded the first well in January 2003 with a heavy land rig in the arctic drilling environment. Drilling of the first well with a conventional well design (8 1/2-in. horizontal drain) took longer than initially planned, partly because of high nonproductive time (NPT) that was related to harsh winter conditions, and partly because of workscope changes. However, the second well was finished as the fastest horizontal well drilled to date by the operator, in two-thirds of the scheduled time. Slim-well design, fit-forpurpose equipment and technology selection, improved mud system for intermediate hole sections, and close operational coordination among four participating companies were among the factors resulting in the benchmark performance.Another key component of the success has been setting of project objectives and targets for quality, health, safety, and environment (QHSE) issues, which were also reviewed by an experienced project startup audit. The review identified critical areas for improvement and thereby facilitated the project's success. The remedial work plan based on the review contributed to the performance improvement in a short time.