TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractHeterogeneous formations present challenging performance issues for PDC bits, specifically in terms of ROP and durability. With current PDC bit technology, the bit runs are usually short and slow 1 , even when BHA design and drilling processes are optimized.

Kra Al-Maru 3 (KM-3) is a deep vertical exploration well originally drilled to investigate the hydrocarbon potential of the Jurassic formations. Investigation of the open hole logs/cores indicated that there was limited porosity development in the Marrat zones of interest. Therefore an operational opportunity became available to deepen the well to explore the deeper Triassic horizons which had gas bearing potential. The main challenges of this well were to design an extended casing program within the constraints of the present wellbore to allow for drilling/testing of the well with a wellhead rating of 20,000 psi whilst assuring the collection of maximum amount of useable data (cores, logs, rates, pressures and samples). In order to meet these challenges a special casing design was employed, based on the experiences of other deep wells. Special HPHT cement additives were specified for the cementing of the deep liner strings. Application of turbine and slim hole motor technology was tried and a HPHT well test operation was planned including the use of a state of the art 20,000 psi surface test package. During the well re-entry major complications were encountered due to high pressure profile, high mud weights, severe losses and well control situations. During the initial short term test the well produced gas, condensate/light oil along with highly saline water which caused salt plugging of tubing and surface lines. Plans are in hand to re-enter the well for long term test after solving the problem of salt plugging. This paper will present a case history of the well including the planning, design process, implementation and lessons learned from the drilling and testing operations. These conclusions will then provide the basis for future optimization in the design of these types of wells. Introduction The search for commercial quantities of non associated gas from the Lower Mesozoic and Paleozoic horizons has been an important part of the exploration strategy of Kuwait Oil Company (KOC) over a number of years. Four deep wells were drilled down to the Pre-Khuff formation in the existing oilfield areas of Burgan, Umm Gudair and Sabriyah, before gas shows were recorded from the Sudair formation in the fifth well, KM-1, in the Kra Al-Maru area (Figure 1). Following this result, further evidence of gas shows were recorded from the Unayzah formation in North West Raudhatain-1 and strong indications of a free gas potential were seen during the drilling phase on Mutriba 10, where high pressure influxes were encountered while drilling the Sudair formation. This potential was borne out in the subsequent Mutriba well, MU-12, which tested the first measurable quantities of non-associated gas in Kuwait from the Sudair in 2004. Following the success in MU-12, and the indications of gas in KM-1, it was decided to return to the Kra Al-Maru area for the re-entry and deepening of KM-3. The well KM-3 was located near the crest of the Kra Al-Maru structure some 450 meters away from KM-1. Although the original drilling and evaluation of KM-3 had indicated some hydrocarbon potential in the Najmah / Sargelu, logs and cores suggested that there was only limited porosity development in the primary targeted Marrat zones. The well was therefore suspended without running the liner across the open hole with a future possible decision to deepen the well depending on engineering feasibility as well as the test results from MU-12, which had not been completed at the time of KM-3 suspension.

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Simulating the mechanical response of PDC drill bits contains a lot of uncertainties. Rock and fluid properties are generally poorly known, complex interactions occur downhole and physical models can hardly capture the full complexity of downhole phenomena. This paper presents a statistical approach that improves the reliability of the PDC bit design optimization process by ensuring that the expected directional behavior of the drill bit is robust over a well-defined range of drilling parameters. It is first examined how uncertainty propagates through an accurate bit/rock interaction model which simulates numerically the interaction between a given PDC drill bit geometry and a given rock formation, both represented as 3D meshed surfaces. Series of simulations have been launched with simulation parameters defined as probability density functions. The focus has been set on directional drilling simulations where the drill bit is subjected to significant variations in contact loads on gage pads along its trajectory. A global sensitivity analysis has also been performed to identify the key parameters which control drilling performance. Directional system parameters are critical in terms of steerability and tool face control, particularly in high dogleg severity applications. Based on these simulations, a statistical optimization strategy has then been implemented to ensure that the directional performance of the drill bit remains effective under a given uncertain drilling environment. Statistical analysis combined with drilling simulations indicated that ROP improvements could even be achieved without compromising steerability. A balanced bit design was selected and manufactured in an 8 1/2-in. model to drill a 714 ft section of a Kuwait field. The bit was run on a high dogleg rotary steerable system and directional assembly. The bit achieved the high steerability goals required by the application while showing a good compatibility with the directional tool. Moreover, ROP was increased by approximately 27% compared to offset wells, setting a record rate of penetration in the field. Whereas statistical analyses are commonly conducted in the field of geosciences, it has rarely been applied in the field of drilling applications. The statistical bit design optimization strategy deployed in this work has allowed to improve both the drilling performance of the drill bit and its reliability.

Drilling deep exploratory wells in Kuwait presents a number of distinctive challenges.The 16" hole section is particularly demanding because it must be drilled through hard interbedded formations including the Zubair sandstone, Ratawi shale, Ratawi limestone, Minagish limestone/dolomitic limestone, Makhul limestone/shale and Hith anhydrite.[1] Historically, 16" roller cone bits were used to drill the float equipment and several hundred feet of Zubair in order to get the stabilizers out of the casing.Several such wells have been drilled in North Kuwait with the best case requiring three PDC bits to complete the section subsequent to the roller cone run.The main challenge has been the highly abrasive Zubair formation with UCS in the 12,000–15,000 psi range. Traditionally, drilling abrasive formations with PDC has been challenging even in smaller hole sizes (8–1/2" etc).[2]However, as hole size increases torque response is magnified increasing vibration issues.In this application, vibration is further amplified by variations in formation hardness.These factors make efficiently drilling the Zubair with PDC a serious challenge.The operator required new PDC bit and cutter technology. A team was assembled that analyzed PDC technology using numerical models, laboratory and field tests.Engineers focused on the bit frame/cutting structure, and cutter design. Cutters diamond table properties were evaluated in an effort to increase durability and wear resistance.The result is a tougher, more abrasion-resistant cutter capable of maintaining an efficient edge in the hard/abrasive Zubair sand. Patented depth-of-cut control (DOCC) technology provided smoother, more stable drilling through the interbedded formations.By limiting the unnecessary depth-of-cut of PDC cutters, the amount of torque generated can be effectively controlled.Penetration is managed by adjusting cutter exposure from the bit body and providing a load-bearing surface.Laboratory testing proved how DOCC technology maintains bit aggressiveness needed and limits reactive torque as more weight is applied or as softer formations are encountered.The threshold for bearing engagement is precisely adjusted for each application.This minimized vibration when transitioning between formations while optimizing the ROP advantage of a PDC bit. Utilizing the new bit design, the operator drilled the entireZubair 16" interval in a single run for the first time and was able to cut drilling costs by eliminating several trips for new bits and the up-front expense of the extra downhole tools.The authors will discuss how the new technology cut costs and increased drilling efficiencies. Introduction In Minagish field of western Kuwait, exploratory wells are typically drilled to a depth of 14,500 ft to 16,500 ft and completed in the Marrat formation through 5–1/2" liner.In northern Kuwait's Sabriya field, well typically are drilled to a depth of 15,500 ft to 16,800 ft.The completion in Sabriya field is mainly in the Marrat formation but sometimes the drilling continues further in to Minjur formation. This requires the 16" section to start relatively deep at approximately 7,800 ft in Minagish field and 9,200 ft in Sabriya field in Zubair formation and generally ending in Hith formation at 11,430 ft in Minagish and 13,170 ft in Sabriya.