Drilling operators continually experience increasing pressure to achieve all objectives safely and at the lowest cost. Powered rotary steerable systems (RSS), applied within the correct drilling environment, can improve rate of penetration (ROP), lower risks, and reduce non-productive time (NPT), which can decrease drilling costs. Using through motor telemetry (TMT) technology, a wired motor with a hollow rotor and flex shaft, allows a connection between rotary steerable systems (RSS) and logging while drilling (LWD) downhole tools. A conductor passes power and communication through the motor to operate and steer the RSS. The wired power section uses a uniform wall thickness stator design that reduces heat production and retention. It also delivers higher rev/min and torque directly to the RSS and bit. Using the TMT powered RSS not only has improved ROP, but has also mitigated stick-slip vibration and reduced NPT. The NPT improvements have been identified in areas, such as slip-stick vibration, drill string failures, drill string torque variations, casing wear, and rig equipment failures. Early planning and risk assessment have also been key. Experience across the globe, both on and offshore, are presented to show the benefits of integrating advanced drilling technologies, such as TMT powered RSS and real-time downhole measurements with effective planning, to reap tangible benefits from drilling optimization. With improved performance as a result of increased torque capacity and bit speed, and reduction of the stick-slip mechanism, this new motor-driven rotary steerable technology has delivered superior performance and improved ROP in challenging medium and hard formations. After more than 10,000 drilling hours and nearly half a million feet drilled, TMT powered RSS technology is setting new records and exceeding benchmarks by bringing greater horsepower to the rock destruction process with longer runs and higher ROPs.
The precise placement of well pairs is one of the most crucial factors in the successful execution of a steam assisted gravity drainage (SAGD) drilling program. A SAGD drilling program includes placing the producer well relative to the reservoir boundaries, as well as accurately twinning the producer with the injector well. Delivering on these high expectations in unconsolidated formations, such as the McMurray oil sands, requires a strong focus on technological innovation.A common practice in drilling SAGD wells in northeast Alberta is to drill lateral SAGD pairs with conventional steerable mud motors and logging-while-drilling (LWD) resistivity measurements. Although this combination has delivered success, certain limitations exist in terms of wellbore quality and placement. At the Statoil Leismer Demonstration Project, several industry firsts were successfully implemented, including a combination of the newest and most cutting-edge directional, measurement, and LWD technology.The keystone of these industry firsts was the application of a soft formation modified, point-the-bit rotary steerable system (RSS), used on 20 horizontal wells. Combined with an ultra deep azimuthal resistivity sensor, the RSS provided precise geosteering along the bottom bed boundary in the producer wells, resulting in improved reservoir capture and reservoir characterization. More on-bottom time enabled more efficient drilling and significantly reduced well costs. Smooth, almost effortless liner runs reflected the lack of tortuosity in the wellbore, made possible by the rotary bottom hole assembly (BHA). Improved directional control made uniform well separation possible between lateral pairs, thereby reducing the risk of hot spots and short-circuiting during SAGD operations. The use of an even-walled power section above the RSS increased the bit RPM for improved BHA responsiveness while minimizing casing and pipe wear. Overall, the results and lessons learned from the demonstration of these new techniques provide a clear indication of the progressive future of directional drilling in SAGD. September 2008 and December 2009. The LDP is the first of eight proposed major SAGD projects for Statoil's Kai Kos Dehseh (Dene for "Red Willow River", also known as the Christina River) asset. Kai Kos Dehseh (KKD) is located approximately 20 km west of Conklin, Alberta, in the heart of the Athabasca oil sands region. Spanning over 1100 km 2 , KKD's bitumen resources are expected to produce approximately 2.2 billion barrels of oil over approximately 35 years with a peak production of 220,000 bbl/day. Statoil chose to take a stepwise approach to their operations at KKD in order to maximize knowledge transfer and continuously improve operations. Experience gained from drilling and producing LDP will be implemented in future expansions at Leismer as well as at the future commercial development phases at KKD.Reservoir Profile and Well Design. Bitumen reserves at Leismer and the entire KKD asset lie within the McMurray formation. Key reservoir properties ...
Drilling operations performed through the shoe-track are generally considered duplicated effort by many operators. Nonetheless, shoe-track drillout is an operation that must be performed on all surface or intermediate casing strings or liners. Slow penetration rates are often experienced, even when drilling through so-called drillable casing equipment. Today's costly drilling operations force operators to attempt to reduce nonproductive operations whenever possible. Therefore, improved shoe-track drillout performance can improve operators' overall drilling cost and schedule. Thus, a better understanding of downhole dynamics is necessary to develop improved drilling procedures. A review of jobs from the North Sea database of cement jobs and shoe-track drillouts revealed that, of the more than 1,200 data points available to the authors, 83% of the drillout times were less than three hours; 70% of the drillout times were less than two hours; and 50% of the drillout times were less than one and one-half hours, with the overall average being 93 minutes. When a single type of cementing casing equipment was drilled in some wells in 30 minutes and other wells in three hours, questions were raised as to what major contributing factors determine actual drillout time. Two case histories are presented with close attention paid to drilling parameters that adversely affect actual weight applied by the bit to the target being drilled. A better understanding of weight on bit (WOB) and weight on target (WOT) is needed to best determine drilling procedures to be used for any given drillout. This paper documents lessons learned from successful drillouts performed with conventional and rotary-steerable drilling assemblies. Software-driven recommendations are provided for improved interpretation of downhole forces applied to the target being drilled. Introduction During the past several years, much progress has been made in fixed-cutter bit designs. Improved technology and manufacturing processes have improved bit performance and reliability to the extent that polycrystalline diamond compact (PDC) bits are successfully encroaching into hard-rock drilling applications. Formations that once were reserved for roller cone bits are successfully being drilled with PDC bits. Additionally, it is becoming more common for PDC bits to be used to drill out cementing plugs and float equipment. These achievements reflect recent improvements in technology and the innovation involved in bit design and manufacture. The aggressive cutting nature of many fixed-cutter bits is designed to maximize bit performance when drilling formations. However, this aggressive nature can cause large debris to be created when drilling through cementing plugs or other cementing casing equipment (Fig. 1). Specifically, the elastomer and phenolic materials commonly used in the construction of cementing plugs and floating equipment tend to tear or fragment into large pieces rather than the typical shearing that occurs when drilling formations. The cuttings created when drilling cementing casing equipment are more significant than cuttings created when drilling formation. In some situations, such debris can become lodged in the junk slot area of the fixed-cutter bit. Therefore, special consideration should be made when determining procedures to be followed when drilling out shoe tracks.
Reliable toolface calculation is essential for achieving robust automatic steering control with rotary steerable systems (RSS). For RSS with fully rotating sensor packages, this task becomes particularly challenging under extreme conditions, where signal-to-noise ratio (SNR) of measurements from one or more sensors reduce significantly (e.g., while drilling near-vertical wells, along dip, towards magnetic north, in the vicinity of casing and/or under severe vibration and stick-slip). To ensure robust toolface control for fully rotating RSS under these conditions, this paper proposes a novel dynamic toolface calculation method. The proposed dynamic toolface calculation method of the new-generation fully rotating RSS overcomes the challenge of achieving robust toolface control despite extreme drilling conditions, by bringing together real-time health monitoring, online sensor calibration and novel sensor fusion techniques. Considering that robust toolface control is the heart of any drilling automation architecture with RSS, this technology is key to enable advanced drilling control strategies in the future.
Summary The precise placement of well pairs is one of the most-crucial factors in the successful execution of a steam-assisted-gravity-drainage (SAGD) drilling program. A SAGD drilling program includes placing the producer well relative to the reservoir boundaries and twinning the producer with the injector well accurately. Delivering on these high expectations in unconsolidated formations (e.g., the McMurray oil sands in Canada) requires a strong focus on technological innovation. A common practice in drilling SAGD wells in northeast Alberta is to drill lateral SAGD pairs with conventional, steerable mud motors and logging-while-drilling (LWD) resistivity measurements. Although this combination has delivered success, certain limitations exist in terms of wellbore quality and placement. At a demonstration project by a major oil company, several industry firsts were implemented successfully, including a combination of the newest and most-cutting-edge directional, measurement, and LWD technology. The keystone of these industry firsts was the application of a soft-formation-modified, point-the-bit rotary-steerable system (RSS) used on 20 horizontal wells. Combined with an ultradeep azimuthal resistivity sensor, the RSS provided precise geosteering along the bottombed boundary in the producer wells, resulting in improved reservoir capture and characterization. More on-bottom time enabled more-efficient drilling and reduced well costs significantly. Highly smooth liner runs reflected the lack of tortuosity in the wellbore, made possible by the rotary bottomhole assembly (BHA). Improved directional control made uniform well separation possible between lateral pairs, thereby reducing the risk of hot spots and short circuiting during SAGD operations. The use of an even-walled power section above the RSS increased the bit rev/min for improved BHA responsiveness while minimizing casing and pipe wear. Overall, the results and lessons learned from the demonstration of these new techniques provide a clear indication of the progressive future of directional drilling in SAGD.
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