Current trends in drilling require a proven and comprehensive approach to assessing and managing the risks of wellbore collisions. This paper outlines the scope and nature of the challenges in collision risk management, and provides an overview of a systematic, field-tested approach to identifying, evaluating, eliminating and/or mitigating those risks. Key aspects of the process are explained in detail and a recent field application on a large platform offshore Indonesia is discussed to illustrate the key values of the risk management process. These include maximizing resource recovery by permitting the safe, precise placement of wellbores, and minimizing the financial and human cost of losses from incidents avoided or mitigated.

Field data have proven that, when drilling extended laterals in the Midland Basin, the rate of penetration (ROP) will significantly decline after the rig's surface torque limit is reached. A high-specification drilling system was introduced to combat drilling torque issues which, in turn, produced record-setting performance. The approach is to identify which factors have the highest impact on drilling torque when using a motor-driven RSS (rotary steerable system) to drill a lateral longer than 10,000 ft. The field dataset analyzed included trajectory design, simulated torque and drag (T&D) versus actual values, hole cleaning effect, mid-lateral cleanup cycle effect, drilling parameters, target formation, and drilling fluids. The outcomes of torque reduction methods are explained in detail, and the final solution is verified with field results. Furthermore, an improvement plan to double the record lateral drilling speed in the Midland basin while staying within rig's capacity, is also discussed. When drilling laterals longer than 10,000 ft, a motor-driven RSS can produce an ROP of 300 to 400 ft/hr until the mid-lateral point where surface torque reaches 28,000 to 30,000 ft.lbf. This is also close to the torque limit of 5-in. drillpipe. Comparisons between on-bottom and off-bottom torque suggest an oil-based mud (OBM) system yields lower off-bottom torque and friction than a water-based mud (WBM). Simulated and actual T&D data were studied to find that wellbores with tangent profile in the intermediate section, commonly seen in pad well design for anti-collision, contribute to higher bottomhole assembly (BHA) side forces and friction after the wells drill into lateral section. Drilling parameters also plays a significant role in torque induction since they affect interactions between bit and rock. On the formation side, stringers such as limestone reduce torque. Analysis also concluded that mid-lateral cleanup cycles have minimal impact on torque reduction, and OBM is necessary to extend drilling performance in long lateral wells. An RSS powered by a high-specification motor drilled a 7,000-ft lateral in just 21 hours to set a new high mark in the Permian Basin.

Extended Abstract Today, oil and gas industries have been continuously drilling into deeper reservoirs and into high temperature formations. Drilling high temperature wells poses new challenges with current available drilling tools because the operating temperatures can closely reach and at times, surpass downhole tools' temperature specifications. The temperature will affect electronics, elastomer or rubber components in tools, sensors, or even could reduce the mechanical strength of the steel collar and cause twist-off. The development of downhole tool technology continues to strengthen and increase the tool temperature rating to withstand those challenges. Utilizing high temperature rated downhole tools can be significantly expensive compared to standard temperature rating tools (150oC). Other technological developments for high temperature wells rely on mud properties and mud surface cooling system. Despite that, one of the key factors to successful drilling operations in high temperature wells still lies on the capability to simulate downhole conditions taking account various technologies and parameters involved, understand the potential challenge and risks, and predict down-hole circulating temperatures that tools will be exposed to.

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Extended Abstract Present day, oil and gas industries continue to drill more complex, extended reach, deeper and higher dogleg severity wells. Due to this, drillstring elements are subjected to higher loads and several kinds of cyclic stresses. The success of drilling operations rely on keeping the integrity of BHA and the drillstring. One of the most common and catastrophic events related with BHA integrity is twist-off where the BHA component parted downhole. Twist off can be caused by many reasons, such as the load exceeding collar strength, high shock and vibration, corrosion, etc., but the primary cause of twist-offs is due to fatigue failure. Despite the stress is below the material strength specification, the drillstring would fail downhole. This is caused by fatigue accumulated over time. According to some reports fatigue failure contributes to over 60% of total dirllstring failures. Fatigue failure can occur under a wide range of conditions and environments, however there is always a higher risk of fatigue failure when rotating drill collars and tools through high doglegs interval during the drilling process. With high rig operating costs, the increasing BHA complexity, and wellbore complexity, there is an increased focus to avoid twist-off related expenses such as: