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Applied annular pressure, for both managed pressure and underbalanced drilling, was born on land decades ago. In fact, the first Rotating Control Device (RCD), the critical component, dates as far back as the 1930's. Simply closing the annulus around the drillstring, and "bottling up" the well, introduced new techniques that enabled wellbore pressures to be managed to drill a better well. In some cases, this was the only way to drill the well. Typical of the drilling business, innovation is generally derived from repurposing or repackaging technology to address new challenges. Applied annular pressure fits squarely into this arena. The shale boom in North America has pushed all technical limits, striving to squeeze every ounce of lost efficiency out of the program. The lighter your fluid, the more you can pump, the better your rate of penetration, the better you can clean the hole, and the less damage to drilling equipment… efficiencies compound. Lighter fluid introduces more pressure dynamics with the well, however, and these require managing. This is where Managed Pressure Drilling (MPD) came to life as unconventional drilling expanded. As a result, more than 75% of drilling rigs are making hole with RCDs in North America Land today. Early success of applied annular pressure drilling allowed for migration offshore also. The nature of equipment required to execute limits how easily it can deploy, however. So historically, it has been reserved for the most demanding "undrillable" wells. MPD was typically a technology of last resort, requiring equipment uniquely designed for offshore applications, along with space not commonly available on offshore installations. These barriers eroded over time, however, and MPD is now common on several offshore projects. Moving into deepwater, the step-change to overcome barriers becomes another significant technology shift. The RCD needs to fit into the drilling riser, and an additional annular is required to manage any gas buildup above the sub-surface BOP. These challenges are dissolving and MPD is picking up pace in deepwater. The motivation remains "undrillable" challenges. However, in order to justify the effort and cost, cracking the "efficiency" drivers that have pushed the shale revolution need to be harvested. What happens when the efficiency drivers applied in the shale factory start heading to deeper and deeper water? Surprising, the opportunities to harvest efficiency with MPD are even greater, with less effort, in deeper water. The challenge is getting the equipment there. This paper will explore two parallel universes, showing cases of the technical efficiency gains from real wells. In both arenas, the financial impacts of cost and savings will be normalized. Further opportunities to expand the "efficiency-verse" will also be explored, shining clear light on money well spent.
Applied annular pressure, for both managed pressure and underbalanced drilling, was born on land decades ago. In fact, the first Rotating Control Device (RCD), the critical component, dates as far back as the 1930's. Simply closing the annulus around the drillstring, and "bottling up" the well, introduced new techniques that enabled wellbore pressures to be managed to drill a better well. In some cases, this was the only way to drill the well. Typical of the drilling business, innovation is generally derived from repurposing or repackaging technology to address new challenges. Applied annular pressure fits squarely into this arena. The shale boom in North America has pushed all technical limits, striving to squeeze every ounce of lost efficiency out of the program. The lighter your fluid, the more you can pump, the better your rate of penetration, the better you can clean the hole, and the less damage to drilling equipment… efficiencies compound. Lighter fluid introduces more pressure dynamics with the well, however, and these require managing. This is where Managed Pressure Drilling (MPD) came to life as unconventional drilling expanded. As a result, more than 75% of drilling rigs are making hole with RCDs in North America Land today. Early success of applied annular pressure drilling allowed for migration offshore also. The nature of equipment required to execute limits how easily it can deploy, however. So historically, it has been reserved for the most demanding "undrillable" wells. MPD was typically a technology of last resort, requiring equipment uniquely designed for offshore applications, along with space not commonly available on offshore installations. These barriers eroded over time, however, and MPD is now common on several offshore projects. Moving into deepwater, the step-change to overcome barriers becomes another significant technology shift. The RCD needs to fit into the drilling riser, and an additional annular is required to manage any gas buildup above the sub-surface BOP. These challenges are dissolving and MPD is picking up pace in deepwater. The motivation remains "undrillable" challenges. However, in order to justify the effort and cost, cracking the "efficiency" drivers that have pushed the shale revolution need to be harvested. What happens when the efficiency drivers applied in the shale factory start heading to deeper and deeper water? Surprising, the opportunities to harvest efficiency with MPD are even greater, with less effort, in deeper water. The challenge is getting the equipment there. This paper will explore two parallel universes, showing cases of the technical efficiency gains from real wells. In both arenas, the financial impacts of cost and savings will be normalized. Further opportunities to expand the "efficiency-verse" will also be explored, shining clear light on money well spent.
Subsurface uncertainty, inadequate offset wells correlation, and high investment cost are some of the biggest drilling challenges in any frontier environment or wild cat exploration wells. These challenges comes with inherent risk on people, environment, assets, and reputation. Mitigating these risks through contingency in the detailed well planning phase as well maximizing operational uptime and efficiency during the well delivery phase, greatly impact the outcome of the well. Digital tools and automation have been a cornerstone in the industry's latest tools to reduce personnel on the rig, as well as minimize downtime and inefficiency. A collaboration of experts between an Operator and Service company was formed during the well planning phase to evaluate the feasibility of an automation platform for a holistic drilling advisory platform that facilitates real time decision making based on downhole and surface data. An offset well study in the area showed that nearby wells experienced recurrence incidents of wellbore instability and downhole pore pressure uncertainty. Modeling iterations for dynamic and static drilling were simulated during pre-planning phase and optimized in real time based on actual downhole and surface data information. Real time models were compared against dynamic models such as Torque and Drag, Hole Cleaning, Pore pressure, ECD (Equivalent Circulating Density), ESD (Equivalent Static Density), and tripping speed (Swab, Surge, etc.). An automated directional drilling tool was run and compared to decisions made by the directional driller to improve the tool's decision-making process for predictive well trajectory parameters. Based on the resultant models, proactive advice was given to the rig in real-time to optimize the input parameters and reduce negative impact to well operation. For example, the practical, real-time visualization helped quickly identify a decreasing pore pressure trend and avoided resultant high overbalance while drilling the 17.5 in. × 22 in. section. The early warning alert allowed swift real time reaction sent to the rig, with mud weight subsequently decreased to 9.2 ppg, avoiding a potential risk of differential sticking stuck pipe incident due to high mud overbalance. Torque and Drag monitoring throughout the well accurately identified few instances of deviation from the trend and models, which detected an early sign of deteriorating wellbore condition which eventually led to a temporary stuck pipe event. Nevertheless, the pipe was freed, which demonstrate that the real time advisory helps in minimizing and avoiding the severe impact of the stuck pipe on the drilling operation. Automated advisory effectively delivered alerts on tight spots while drilling and casing running resulting in a faster 9-5/8 in. liner running in the deviated section. Tripping advisory mode and Real-time modelling of the swab-surge limits successfully allowed the team to avoid critical areas or swabbing events, which increased tripping speed where an opportunity was available and reduced tripping speed when risk of swab/surge was high avoiding well control/well loss events. The automated directional drilling tool increases in accuracy as the dogleg increased. The intelligent advice from the model got closest to the decisions taken by the directional driller, the closer the well got to the planned trajectory. These resulted in improvement and feedback for the pre-planning model such as target radius allowance, formation properties, and optimum drilling parameters. This work takes the first steps towards drilling automation and digital integration of insights and operation. The collaboration between operator and service company resulted in a successful deployment of an automation platform as a solution to manage and mitigate risks as well as optimize drilling operations in exploration wells.
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