Challenging drilling operations in the Vaca Muerta unconventional shale gas play have prompted operators to implement innovative drilling techniques to improve drillability and operational efficiency. Significant benefits have been reported by utilizing Managed Pressure Drilling (MPD), Underbalanced Drilling (UBD), and/or drilling with casing; however, challenges still exist, due to a variety of reasons. The heterogeneity found from field to field and within fields has resulted in wells with significant events, some resulting in loss of the well, even on the same pad where a previous well has been drilled uneventfully. Arguably, the most successful non-conventional drilling technique being incrementally used in the area is MPD, often combined with UBD, particularly in gas wells. As with any new technology implementation, there is a learning curve which can be accelerated by translating learnings from successful experiences. Three key components for a successful implementation on MPD are still building a collective experience in the Vaca Muerta play. Firstly, the equipment and associated technology is the key enabler for physically perform the operations safely and efficiently. The second component is a ‘soft’ framework consisting of a robust layered approach including overarching standard policies, the MPD strategy for implementation in the specific project, conceptual and detailed procedures, and specific work instructions. Lastly, the human component is a group of competent personnel, whom, at their specific responsibility level, understand the ‘soft’ framework, and knows how to operate the hardware to implement the technology so that objectives are met. The potential of the technology is limited to the weakest of these three components. A strong combination of any two of them, not complemented by the third one, will most likely result in a partial success at best, if not a complete failure at worst. The operator had recently three major events in wells being drilled with MPD, which resulted in the loss of the wells. After implementing a training program on MPD/UBD, which emphasized the human factor and understanding of the equipment, the ‘soft’ framework of strategy, procedures and project management, the safety and efficiency during operations has increased significantly. This resulted in a better handling of events related to bottom hole pressure control without a single well loss event to the date of writing this document, approximately nine months of continuous operations. The other mainstay of this process has been the flexibility to adapt the application of the methodology based on the well challenges encountered.

Technology integration is not complete without ownership. In light of the numerous challenges associated with deepwater plays all over the world, the most recent generation of ultra-deepwater drillships have more thoroughly considered the integration of managed pressure drilling (MPD) technology into the rigs. In the interest of accelerating technology integration of MPD in deepwater environments, essential equipment that enables the technique and its associated methodologies was recently offered for ownership by service companies to drilling contractors. Two (2) state-of-the-art dynamically positioned (DP3) drillships have successfully integrated MPD via ownership into their rig systems. This paper focuses on the process that was undertaken to realize rig integration for these drilling rigs, as well as on the challenges that were faced and the solutions developed to surmount them. More importantly, it discusses the outcome of the pioneering MPD rig integration projects and the lessons that were learned along the way, so that future projects are able to build on them. Lastly, it covers the substantial advantages and benefits that MPD equipment ownership, instead of traditional equipment rental, brings to the service companies, drilling contractors and operators.

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 barrels The implementation of managed pressure stripping procedures that resulted in increased tripping speeds The 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.

Managed Pressure Drilling (MPD) dynamic influx control techniques offer substantial advantages over conventional well control, including reduced influx size, and the ability to control and circulate an allowable influx without requiring conventional methods. With careful planning and execution, MPD dynamic influx control can yield considerable increases in safety and efficiency. Many issues with conventional well control, particularly in deepwater operations, can be mitigated or even eliminated using dynamic influx control. Notably, conventional methods passively rely on the influx to increase wellbore pressure sufficiently to balance reservoir pressure, resulting in needlessly large influx volumes. In contrast, MPD methods quickly detect and actively apply pressure to control an influx in a fraction of the volume. Furthermore, conventional influx removal methods are typically slow, leading to drawn out well control events with high likelihood of further complication, such as stuck pipe and secondary influxes. Conversely, using dynamic influx control, an allowable influx may be controlled and removed from the wellbore in a few hours, not days. In this work, methods that address concerns with current well control practices through application of dynamic influx control are outlined. In addition, transient, multiphase simulation is used to demonstrate comparison between dynamic influx control and conventional well control, clearly quantifying potential benefits of adopting these new methods.

Based on experiences with the Controlled Mud Level (CML) system ECD-Management (ECD-M) in the Gulf of Mexico (GoM) in 2014 and 2015, this paper outlines how the reduced riser level was applied to improve kick detection and to reduce drilling risks associated with downhole pressure constraints. CML is a Managed Pressure Drilling (MPD) technology, but it is not only about Constant Bottom Hole Pressure (CBHP). The paper will cover the authors' learning curve from the first to the 4 th well. The main focus during the first well was to make everything work and to train the personnel on the rig. The riser level was only reduced by about 150 feet and the ECD-M system was mainly used for improved kick detection by using the riser as a trip tank. Several kick drills were performed with good results showing how the drill crew was able to detect influxes even earlier with the new CML parameters. The use in the second well was extended by mitigating salt creep in the salt section, CBHP during salt exit and reducing hydrostatic head during a cement operation. Further experiences were gained during the last two wells, even though one major new component failed during commissioning. Other potential applications will also be described. The paper will describe the planning of riser levels and controller modes together with the usual drilling parameters mud weight, flow rate, ROP, etc. using hydraulic simulations and pore and fracture gradients taking the different constraints and risk into consideration.

A pressure determination system (PDS) was field tested to progress Managed Pressure Drilling (MPD) from a reactive system to one that prevents well control events from initiating. Physical testing performed on an offshore drilling operation successfully demonstrated the capability of the PDS to detect a simulated, unsafe change in fracture margin without incurring significant losses in August 2014. The test methods and results will be discussed in detail this report. The PDS is designed to oscillate the position size of a dedicated pressure control valve (PCV) in a repeatable and gradual fashion and analyze the resultant behavior of Applied Surface Back Pressure (ASBP), Bottom Hole Pressure (BHP), and Flow Out indicators over time. In the event that average BHP begins to near a margin, the behavior of the above indicators at the crest or trough of a wave cycle will momentarily deform indicating a pending well control event. Since, average BHP has continuously remained within drilling margins during this process, any resultant gain or loss is negligible. Once the threat of a well control event is detected, a dedicated MPD PCV will adjust average wellbore pressure to a safer value to prevent the occurrence of a well control event. During field testing, the PDS concept was verified with two assessments, signal transmission reliability and simulated fracture detection. The signal transmission reliability test validated that the PDS can oscillate PCV position in a controlled and consistent fashion as well as create highly repeatable behaviors in ASBP, BHP, and flow rate waves over time. The simulated fracture margin test demonstrated that the PDS has the sensitivity to detect a fracture margin at 20 psi above the driller's intended wellbore pressure with a negligible volume of losses while the PDS PCV oscillated wellbore pressure as described above. Both tests were performed in an open hole section of a medium depth well with a rotating and reciprocating drill string. Prior to field testing, a SIT (System Integrity Test) was performed on the PDS equipment installed on MPO's MPD Pressure Control Manifold (PCM) to ensure the system was prepared for concept testing. The SIT was performed with the MPD PCM isolated from well bore riser returns in August 2014. The field tests described above were previously performed as an initial test, at the MPO Dubai Training Center Flow Loop where the PDS concept was also successfully validated in a laboratory environment. During those tests, the sensitivity of the PDS system was also demonstrated by validating that a 4 inch Coriolis Coriolis meter in a small, closed loop system was able to detect less than a 1 gallon difference in flow.

This paper presents the development, qualification, and first use of ECD-Management (ECD-M); a new managed pressure drilling system developed to solve major challenges when drilling in deep waters. ECD-M combines EC-Drill from Enhanced Drilling (EDR), a Controlled Mud Level technology where a subsea pump module is installed mid riser, with the Delta Seal Riser Module (DSRM) from Managed Pressure Operations (MPO) having a Quick Closing Annular (QCA) installed just above the subsea pump. This enables extending the operating envelope of the technology to a point where loss of circulating capability could otherwise cause an underbalance in the well. The first ECD-M well was partially drilled with a reduced riser level, but without the Delta Seal Riser Module. The paper describes the rig modifications, interfaces between vendors, rig contractor and service companies, training, process with BSEE, qualification, success criteria and finally the results and experiences from first use.

Downhole incidents such as kick, lost circulation, pack-off, and hole cleaning issues are important contributors to downtime in drilling. In managed pressure drilling (MPD), operations margins are typically narrow, implying a risk of more frequent incidents and more severe consequences than during conventional drilling. Detection and handling of symptoms of downhole drilling contingencies at an early stage are therefore crucial for the reliability and safety of MPD operations. This paper describes a method for early detection and localization of incidents, based on a fit-for-purpose model of the downhole pressure hydraulics, distributed pressure measurements from wired pipe, and statistical change detection methods. Using statistical change detection methods, it is possible to detect the incidents and their location at a very early stage when small changes in process data are covered in measurement noise, which may be very hard to observe for a human operator. The method has successfully been tested on experimental data from a medium-scale horizontal flow loop in Stavanger, Norway. The flow loop represents a 700 m borehole with emulation of the following downhole contingencies: drillstring washout, drill bit nozzle plugging, gas influx and fluid loss. In the tests, these incidents were successfully detected at an early stage. The developed detection and localization method could be included as a diagnosis tool in a drilling system with MPD or conventional drilling.

Well control has been a major obstacle for introducing dual gradient systems for deep water drilling, involving both new and more complex procedures and equipment. Here test results using a new dual gradient drilling (DGD) system to control simulated well control events are presented. After successfully drilling a Statoil well with Enhanced Drilling's dual gradient solution (EC-Drill) at the Troll ( Kjøsnes et al. 2014 ) field on the Norwegian continental shelf, the well was plugged and made ready for 48 hours of controlled testing. Several tests were run, each designed to determine the functionality of the system; to detect and handle liquid loss, gas and liquid influx, gas migration in the riser, and circulation of gas through the subsea pump module. The detection tests were carried out with a reduced riser level and an open annular, to quantify the capability of the system to detect volume imbalances while drilling. Three circulation tests with increasing amount of gas injected through the drillstring were performed. After the influx was detected, the annular was closed, and the flow was routed from the well through a bypass line to the subsea pump module. A topside choke in the mud return line was actively used to apply backpressure with the objective to control bottom-hole pressure, while circulating the gas from the well. In the last test gas was allowed to migrate into the marine drilling riser with a reduced riser level and open annular. The paper will present the planning and preparations as well as the results.

Detection and control of gas kicks in OBM/SBM while drilling through narrow pore - fracture windows has always been a challenge due to gas solubility and mud compressibility. Continuous closed loop monitoring of the well and automated early kick detection and control helps to keep the influx volume at a minimum before it reaches the "well control" threshold margin in the kick tolerance matrix. This paper presents a case study and detailed analysis of the event through advanced simulations to examine the benefits of automated influx detection and control using MPD system in comparison to conventional well control method. In the case study, an automated MPD system successfully detected and controlled a gas influx in OBM while drilling onshore Western Canada. The analysis employed dynamic well control simulations to regenerate the event and a close match with the field data was achieved. A sensitivity analysis was then conducted to study the effect of total response time on pressures at the surface and at the casing shoe during the application of conventional Driller’s method of well control. The findings from the study demonstrate how automated early kick detection and control minimizes influx volume and increases operational safety. The implementation of MPD system with such capabilities significantly reduces NPT by enabling influx circulation at full rate and eliminating the need for flow-check, BOP closure and operational delays inherent in conventional well control.

Managed Pressure Drilling (MPD) has gained industry-wide acceptance as a technology that enables drilling into the challenging zones. Narrow pore pressure – fracture pressure window, depleted reservoir zones, highly fractured reservoirs and deep-water wells are few examples of such challenges. Weatherford’s MPD system has proved its effective application in drilling challenging wells. Its unique early kick and loss detection capability helps to identify such event in very early stage, take corrective action and hence to minimize the nonproductive time. Early detection of a kick / loss event helps in minimizing the potential risk posed by the event and ensure safety during the operations. Weatherford’s advanced gas extraction and analysis system uses an innovative membrane technology and high speed gas chromatograph to improve surface gas detection and analysis in real time. This capability was utilized in conjunction with accurate flow metering capability of MPD system. Various tests were carried out to validate the advanced gas detection system’s capability to detect and analyses gas in mud. During circulation of the influx, data from gas detection system helped to plan the strategy gas on the surface. The test data was validated by the data from real wells. Feedback from the advanced gas detection system also helped to control the break out of the dissolved gas from oil based mud by varying surface back pressure through automated chokes. This is very critical to ensure that gases containing hydrocarbons are handled safely on the surface. It also provided quantitative analysis of the lighter and hence volatile hydrocarbon components. Circulation rates and surface back pressure can be used to mitigate potential hazards. Use of advanced gas extraction system in combination with MPD system added significant HSE value by making well control operations more efficient and safer.

Closing the wellbore at the top with a Rotating Control Device (RCD) for some kind of Managed Pressure Drilling (MPD) operations raises a number of issues with regards to well control and kick detection. The wellbore is closed and the standard flow check of looking into the well is no longer possible. The use of a rotating control device provides drillers with an additional level of comfort because it is a pressure management device, but it doesn’t eliminate the need to have well control as a primary objective. In recent MPD operations, it was observed that well control procedures were relaxed as a result of managed pressure drilling. The installation of an MPD system provides the sense that well control is now taken care of by the MPD provider. This raises the question "Is Managed Pressure Drilling the same as primary well control?", and how do we deal with kicks in Managed Pressure Drilling operations? At what point in a well control process do we change the well from Managed Pressure Drilling to well control and who is responsible? This paper will present some of the issues that need to be considered when planning and conducting MPD operations. arly kick detection and annular pressure control are promoted as an essential part of managed pressure drilling operations, but there can be confusion as to where the responsibility for well control lies. Does this remain with the drilling contractor and Operator or is this now shifted to the provider of the MPD services. The paper provides some case stu ies where MPD and well control conflicted, causing a number of issues that in some cases led to the loss of the well.

An industry-supported research project has investigated well control methods for managed pressure drilling (MPD) using the constant bottom hole pressure (CBHP) method. This paper proposes a method for pre-selecting the best initial response to be taken when a kick occurs during CBHP MPD based on conclusions from the research. That research ( Davoudi et al 2010 ) concluded that the three most widely applicable initial responses to kicks during MPD were increasing casing pressure until flow out equals flow in, shutting the well in, and using an adaptation of a MPD pump shut down schedule to detect and shut in a low rate kick. Increasing pump rate until flow out equals flow in was concluded to have limited, but potentially still important applications. The proposed method uses a decision tree to pre-select the best response to be used if an influx of formation fluid is detected. This selection is based on the desired tolerance to kicks, equipment being used, well geometry and conclusiveness of the kick warning signs. The equations necessary to calculate decision parameters, example calculations for an application of the decision tree and comparison of simulation results to application of the decision tree are included. The decision tree indicates the response that maximizes kick tolerance within the well design, gives a basis for revising equipment or well design to maximize kick tolerance, and supports calculation of the expected kick tolerance advantage of the increasing casing pressure response versus a shut in response.

Conventional methods of identifying a kick as well as the shut-in procedure can take a significant amount of time and therefore result in additional influx volumes. Coriolis flow meters have been used for more than 15 years for delta flow kick detection and have been very effective in most cases in identifying or confirming kicks much faster than conventional means. In Managed Pressure Drilling operations, Coriolis meters are frequently used for delta flow kick detection purposes since the system is in a closed loop and it is not possible to perform a conventional flow check. Unfortunately, Coriolis flow meters are sensitive to gas entrainment and also need to be properly maintained to ensure they are always in good working order. The constant bottomhole pressure (BHP) calculation and control system of the Dynamic Annular Pressure Control (DAPC) system has been modified to provide an effective means of accurately detecting an influx without a Coriolis flow meter and then controlling the unplanned event, which significantly reduces influx volume and shut-in time, as well as eliminating the cost and complexity of using a Coriolis flow meter. Mud losses during drilling can also be confirmed. The modified DAPC system has been adapted to shut-in the well whenever the rig pumps are turned off. By observing the choke position it is possible to determine if the well is unexpectedly flowing and at what rate. If the well is shut-in, the system can monitor the choke position and identify additional flow out. In addition, the system can be configured to account for normal back flow to reduce the occurrence of false alarms and, in the event the well is flowing and the system’s warning is overlooked, the system can be programmed to automatically increase shut-in pressure to stop the influx. Recent tests performed at the Louisiana State University PERTT facility proved the system’s ability to reliably identify unplanned flow events. The system has also been field tested. Test results will be shown and ways in which the system can easily be installed on a rig will be discussed.

Abstract Managed Pressure Drilling (MPD) is an enabling technology that is highly sought after in the drilling industry in recent years. MPD is generally associated with narrow pressure windows, i.e., staying between either pore pressure (Pp) or formation stability and fracture pressure (Fp). However, operators are starting to realize MPD has a broader range of application, beyond navigating narrow pressure windows and other traditional applications such as Dual Gradient Drilling and Pressurized MudCap Drilling. Over the past couple of years, MPD's range of application has increased, as can be seen from the examples presented in this paper. New offshore and onshore MPD projects in the Gulf of Mexico (GoM), North Sea, North America, South America, Africa and Europe are being designed for objectives like improving Rate of Penetration (ROP), reducing formation invasion, validation of pore pressure data, reducing incidents of stuck pipe and mitigating the effects of differential sticking, reducing ballooning or hole breathing and minimizing Non-Productive Time (NPT). MPD is not a universal solution or panacea and improper application of the technique may ultimately cost more than conventional drilling methods. However, with comprehensive planning and execution by experienced engineers, MPD can help actualize project objectives that otherwise might be impossible with conventional techniques. Introduction MPD is a name for a collection of old, modified, and new technologies, referred to as VARIATIONS or METHODS of MPD. MPD can help in achieving specific purposes (such as eliminating a casing string or avoiding formation damage in a particular section of hole), or in solving particular drilling problems (such as drilling through narrow pressure windows or lost circulation zones), or in meeting definite project constraints, such as quality, time or safety (Nauduri, Medley, 2008). Although the MPD acronym was coined recently (Hannegan, Wanzer, 2003; Hannegan, 2005) in 2003, and the IADC UBD committee gave an official definition in 2004, many techniques associated with MPD have been in existence well before the turn of the Twentieth Century. There are accounts of such techniques being used even in the late 18th century and early 19th century. MPD in part evolved from its precursor, Underbalanced Drilling (UBD), in that both drilling methods typically incorporate much of the same drilling equipment and pressure management equipment. Similar equipment is used to drill both UBD and MPD wells and the benefits of the techniques are, in many cases, identical. However, since there is no continuous flow of fluids to the surface, MPD wells are often perceived to be safer than UBD. Until recently based on the applications, four major classifications or "Variations" of MPD have been recognized - Constant Bottomhole Pressure (CBHP), Dual Gradient Drilling (DGD), Pressurized Mudcap Drilling (PMCD) and Zero Discharge or Health Safety and Environmental (HSE). Some of these variations are achieved by using more than one different technique or method of MPD together (Medley, Reynolds, 2006). There are other applications of MPD, however, that do not fit into these broad categories of MPD.