TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAn efficient, safety-conscious wellbore drilling method features highly accurate wellbore placement, reduced drilling time, and improved safe drilling practices. Rotary steerable system (RSS) technology provided a cost-efficient solution in a high-volume environment for a US-based oil and gas exploration company drilling 80 to 100 wells per year in South Texas, USA.Although vertical drilling has been in practice since the birth of the industry, maintaining verticality is still challenging and requires alternative drilling strategies. Traditionally, downhole positive displacement motors (PDMs) have been used to control the wellbore vertically in this drilling environment. This drive system typically requires one or two additional bit runs to achieve the target objectives. A reduction of the weight on bit (WOB), or feathering, was also required to maintain a vertical wellbore. The combination of this drive system coupled with the lower-than-optimum WOB leads to a dramatic reduction in rate of penetration (ROP) when steering is required, which is neither cost-efficient nor desirable. The introduction of RSS technology has addressed both of these concerns by allowing the application of higher WOBs for faster ROP while maintaining high levels of wellbore placement accuracy.RSS technology in this environment increased the number of drillsites available as the surface location can be right on the "hard-line" of 467 ft from the lease-line required by the Texas Railroad Commission. Previously, fewer lease-line wells were drilled owing to the problems of keeping the accumulated displacement inside the lease dimensions.This paper presents field studies from 2004 to 2006 demonstrating RSS success in maintaining verticality where the bit tends to walk related to highly faulted, fractured, and dipping formations. The RSS system provided real-time response and a vertical wellbore. Instantaneous wellbore corrections reduced drilling time in some cases more than 40%. In both the vertical and deviated wellbores studied, total depth (TD) was reached ahead of schedule with reduced costs.

A rank exploration well drilled in Southwest Louisiana recently with Managed Pressure Drilling (MPD) techniques reached new operating levels for depth, pressure, and temperature. The exploration well reached a total depth of 29,426 ft at a maximum bottomhole pressure (BHP) and temperature of ~30,000 psi and ~500° F, respectively. Below 15,000 feet, the increased solubility of gas posed a particularly difficult risk for kick detection. The need for precise kick detection was magnified further by the uncertain magnitude of the pore pressure, the reduced kick tolerance, and well conditions conducive to swabbing during tripping operations. Managed pressure drilling techniques were employed to mitigate these risks. This paper will describe the processes that were used to identify the functional requirements and limitations of the MPD equipment that was selected to achieve the well objectives. The MPD process flow paths were designed early in the planning phase of the project to minimize any potential misapplication of MPD techniques during the execution phase. The paper will also include a description of the substructure vertical space limits that are created when installing MPD equipment. These designs were also completed in the early planning phase because the stack-height design defines the substructure spacing requirements, which can have a significant impact on rig selection and substructure requirement. The case history presented in this paper will document: The successful early detection of influxes of less than 3 barrelsThe implementation of managed pressure stripping procedures that resulted in increased tripping speedsThe application of MPD techniques that reduced the time spent circulating and managing gas at surface The above actions saved ample amounts of rig time in each of these areas. Additional MPD techniques were utilized to perform dynamic leak off and in-flow tests which yielded accurate data that will be used to refine earth models for possible future well applications. Key improvement opportunities were identified during the execution phase through daily communication meetings with the service provider, which were used to improve MPD plans, procedures, and reliability.

The Permian basin has been one of the main drivers leading the recovery of recent drilling activity on U.S. land. It has been a focus for drilling activity that has targeted conventional reservoirs since the first well was drilled in 1925. Through the depletion of conventional reservoirs, fracture pressure in these zones has decreased due to the reduction in pore pressure. Some of these previously drilled reservoirs throughout the Permian Basin have been selected for the reinjection of produced water which has caused abnormal pore pressures to occur. The combination of having both loss and injection zones exposed in the same drilling interval has resulted in challenges for operators as they have to navigate the resulting mud weight windows of highly developed fields of the Midland and Delaware Basins. As development throughout the Permian basin continues, these mud weight windows will only become more difficult to manage. In one of Chevron's highly developed Midland Basin fields, managing the exposed injection and loss zones in the intermediate hole section proved to be challenging. This hole section had routinely experienced severe to complete losses upon entering the Upper Spraberry formation as a result of trying to manage higher pressures inflicted by the San Andres formation, a shallower injection zone. The mud weight could not be reduced to mitigate these losses without inducing an influx from the San Andres. Circulation could often not be reestablished upon entering the Spraberry formations which resulted in mud cap or blind drilling in order to reach section total depth (TD). These losses and overall wellbore conditions introduced higher risk and consequences in the form of well control events, wellbore instability, and mechanically or differentially sticking 9-5/8" casing prior to reaching planned set point. The immediate solution to isolate the wellbore problems was to implement a contingency liner, which comes at a premium and decreases drilling and completions efficiencies of the production hole section. Managed pressure drilling techniques were identified as a solution to simultaneously navigate a shallow injection zone and a deeper loss zone within the same hole section. The necessary equivalent mud weight profile was established through the reduction of MW and the addition of surface back pressure. This enabled a higher equivalent mud weight to be held at the shallow injection zone and a lower equivalent mud weight to be held across the loss zones. Additionally, managed pressure cementing techniques were used to achieve a similar pressure profile during cementing operations in order to increase the likelihood of maintaining returns while placing cement across the loss zones. Managed pressure drilling and cementing techniques implemented in this field contributed to the elimination of contingency liners and significant non-productive time in hole sections where both injection zones and loss zones were exposed. As laterals are extending beyond 10,000’ across the Permian Basin, the team has collectively proven the concept that the MPD system is part of an equipment package that can eliminate contingency liners and deliver the preferred sizes of production hole and production casing that is crucial to successfully reaching TD and efficiently placing hydraulic fracturing jobs at optimal rates.

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.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAn efficient, safety-conscious wellbore drilling method features highly accurate wellbore placement, reduced drilling time, and improved safe drilling practices. Rotary steerable system (RSS) technology provided a cost-efficient solution in a high-volume environment for a US-based oil and gas exploration company drilling 80 to 100 wells per year in South Texas, USA.Although vertical drilling has been in practice since the birth of the industry, maintaining verticality is still challenging and requires alternative drilling strategies. Traditionally, downhole positive displacement motors (PDMs) have been used to control the wellbore vertically in this drilling environment. This drive system typically requires one or two additional bit runs to achieve the target objectives. A reduction of the weight on bit (WOB), or feathering, was also required to maintain a vertical wellbore. The combination of this drive system coupled with the lower-than-optimum WOB leads to a dramatic reduction in rate of penetration (ROP) when steering is required, which is neither cost-efficient nor desirable. The introduction of RSS technology has addressed both of these concerns by allowing the application of higher WOBs for faster ROP while maintaining high levels of wellbore placement accuracy.RSS technology in this environment increased the number of drillsites available as the surface location can be right on the "hard-line" of 467 ft from the lease-line required by the Texas Railroad Commission. Previously, fewer lease-line wells were drilled owing to the problems of keeping the accumulated displacement inside the lease dimensions.This paper presents field studies from 2004 to 2006 demonstrating RSS success in maintaining verticality where the bit tends to walk related to highly faulted, fractured, and dipping formations. The RSS system provided real-time response and a vertical wellbore. Instantaneous wellbore corrections reduced drilling time in some cases more than 40%. In both the vertical and deviated wellbores studied, total depth (TD) was reached ahead of schedule with reduced costs.