Realizing the potential benefits automation brings, many operators have turned to managed pressure drilling (MPD) techniques as a technical and cost-reward solution to hard-to-reach assets, an approach which not only saves time but also enhances the safety capabilities of the operation. The evolving industry shift toward MPD-ready rigs demonstrates the significant need for a reliable software system to interact with the equipment and simultaneously deliver enhanced models able to precisely control annular pressure in geological complexities where drilling windows are narrow. Several studies have demonstrated the operational benefits of MPD through the application of the constant bottom hole pressure (CBHP) method, imbedded automated kick detection, and control capabilities. MPD technology relies substantially on applying surface back pressure (SBP) using automated chokes to precisely control the annular pressure profile in a closed loop circulation system. During drilling, CBHP connections, mud displacements and fluid anomaly incidents, the SBP is dynamically adjusted in response to operational changes that yield annular pressure changes; such as circulation rate, top drive speed, and rate of penetration to name a few. The integrated MPD drilling software platform is used in combination with interactive models and surface and downhole data measurement in a unified computing system to enhance real-time analysis of drilling performance. By employing real-time models such as hydraulics, well control, pore and fracture pressure estimation, surge and swab, and drilling optimization torque and drag, the system quantifies the boundaries and aid in understanding the real operational limits. Additional software platform applications deliver the common integration baseline that enables both operations within the pre-drilling, while drilling and post analysis. The current automated MPD software has been successfully used in several onshore and offshore wells with narrow drilling windows. This paper discusses the applications and the newest developments in the MPD integrated software to automatically and precisely manage wellbore pressure. The results to be presented include the summary of planning, while drilling analysis, and post drilling analysis of an offshore case study where a detailed parametric analysis of measured and estimated data are compared.
Pore pressure (PP) is one of the most critical parameters in geomechanical analyses of wellbore stability along with well planning. Several empirical methods aim to estimate the pore pressure using seismic and logging while drilling data, and drilling parameters. Considerable number of studies addressed the uncertainty in the PP estimate using these methods due to noise and fluctuation in the received data as well as under compaction effect in over-pressured formations. It is common practice to calibrate these methods with data from Repeat Formation Tester (RFT) or Drill Stem Test (DST). Managed pressure drilling (MPD) allows precise measurement of the PP with dynamic pore pressure testing (DPPT), reducing the non-productive time inherit in RFT and DST without compromising operational safety. This paper presents methodology to calibrate the available pore pressure prediction methods using dynamic PPT data. Presented methodology involves comparison of several correlations and selection of the one with the best fit to the dynamic PPT data, and determination of the formation-specific correlation coefficients using regression analysis. The work includes validation of the method on case study example. The technique implemented in a new MPD control software platform for real time analysis of the dynamic PPT data to forecast the pore pressure of the following formations while drilling.
The deep basin of British Columbia, Canada contains the Montney and Doig plays, which are categorized as tight gas sands. Both are considered major unconventional gas plays containing vast quantities of gas in the west and oil in the coarser eastern facies. The formations have high initial formation pressure which promotes production, however during drilling causing drilling challenges. It is especially difficult when drilling through the abnormally pressured Doig transit zone. This is further complicated when a trip is required for the bit as the swabbing effect, if not properly managed, can easily escalade into a well control event. Due to the overpressured and geologically fractured formations, it is very difficult to trip the drill string out of the well safely without using specialized techniques. MPT is one such method that can be utilized in these scenarios. Managed Pressure Tripping allows the driller to control bottomhole pressure (BHP) in different types of abnormally pressured zones, and simultaneously eliminating the swabbing effects by holding surface back pressure (SBP) with the managed pressure drilling (MPD) system. Applying MPT techniques on subnormal and overpressured formations results in safe and cost effective drilling operations. This paper presents a case study where advanced Managed Pressure Tripping (MPT) technology was successfully applied in the Altares field in British Columbia, Canada, to mitigate well control challenges associated with swabbing. The study elaborates on recommended operational procedures, engineering calculations, equipment set up and process flow diagrams along with the analyzed graphical data.
Since the latest downturn of the Oil and Gas (O&G) sector, productivity growth has become the priority, which led to the adoption of new key technologies for better performance and lower cost. As part of the 4th Industrial Revolution, these technologies are taking the O&G by storm, forcing hardware manufactures to innovate quickly and create devices with more capabilities. What was impossible a few short years ago is reality today. Managed pressure drilling (MPD) systems are taking advantage of this development by implementing advanced data analytics and hydraulic modeling in programable automation controllers. This approach has several benefits, reliability and full real-time deterministic operation being the major ones. Previously, controlling bottomhole pressure (BHP), the required modeling and analysis were executed in a networked computer at a different physical location. Now it is executed locally in a fully deterministic control system. This includes data acquisition (DAQ), signal conditioning, well bore modeling, analytics and data visualization. This approach mitigates the risk of connectivity issues and makes the system more robust in case of network failure. Furthermore, it simplifies the deployment of the system, as all critical functions are at a single physical location. Another major benefit is an increased resolution of the model in areas of specific interest. For example, a zoom in on the openhole section and a lower resolution in the cased hole section. The flexibility of this approach manifests itself on the deployment side. This system can be installed in several different scenarios, for example as a full system with controls and manifolds, or as a control system only, and integrated into existing rig MPD manifolds and drilling controls. This level of integration creates robust and flexible systems while reducing downtime during operations. This new approach includes the integration of cyber secure communications, an upcoming standard in the O&G industry. The system communicates via the open platform communications unified architecture (OPC UA) protocol – recommended by the Cyber Security community. This new platform integrates advanced data analytics and hydraulic modeling in real-time, coupled with cyber security features via OPC UA protocol directed to automation controllers for managed pressure drilling applications.
MPD enables drillers to navigate through narrow drilling windows to reach designed target depths. After a hole section is drilled, pressure management is still required to pull drill strings out and run and cement liners. Conventional cementing programs and procedures may not be practical for a challenging hole section that has been drilled by MPD. Elaborate wellbore pressure management is required to ensure safe and efficient cementing operations. The same closed loop circulation system utilized for drilling is used to manage the wellbore pressure during cement operations. The technique of pressure management during liner cement jobs was utilized repeatedly by a major client in one of the most challenging HPHT campaigns in the North Sea. This paper provides an insight into the technique as well as information on the procedures, challenges and lessons learned pertinent to these operations. Various cases studies describing the setup, planning and execution of operations, simulation vs measured data will be compared. Drilling wells in complex environments with century-old technology is difficult at best and unsafe at worst. From drilling through narrow pore-pressure/fracture-pressure gradient windows to mitigating kicks and differential sticking, managed pressure drilling (MPD) succeeds when conventional techniques are likely to fail. MPD entails the use of specialized equipment to control wellbore pressure profiles more precisely than is possible with conventional drilling methods. MPD enables drillers to navigate through narrow drilling windows to reach designed target depths. After a hole section is drilled, pressure management is still required to pull drill strings out and run and cement liners. Conventional cementing programs and procedures may not be practical for a challenging hole section that has been drilled by MPD. Elaborate wellbore pressure management is required to ensure safe and efficient cementing operations. The same closed loop circulation system utilized for drilling is used to manage the wellbore pressure during cement operations. A case study describing the setup, planning and execution of operations, and simulation is presented in this paper.
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