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. A summarized overview of the test method, conclusions, and results will be discussed as well. The PDS Pressure Control Valve (PCV) is designed to oscillate its position size in a repeatable and gradual fashion and analyze the 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 drilling margin, the behavior of the above indicators at the crest or trough of a wave cycle will momentarily deform indicating an unsafe change in a drilling margin trend that will eventually lead to a recordable well control event if wellbore pressure is not proactively adjusted. 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, the MPD PCV will adjust 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. Both tests were performed in open hole of a medium depth well with a rotating and reciprocating drill string and the mud pumps running. 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. 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 performed offshore, 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 meter in a small, closed loop system was able to detect less than a 1 gallon difference in flow.

Deepwater drilling projects are inherently more challenging to execute due to the increased risks and complexity associated with narrow and unpredictable drilling formation pressure margins. With regards to well control, small gas influxes that are initially dissolved in the drilling mud can remain in solution and be circulated above the SS BOP undetected before finally breaking out in the riser; resulting an overboard diversion of oil based fluids, or worst case unloading the riser through the rotary table. In terms of drilling operations, the narrow and unpredictable nature of formation pressure margins experienced in offshore operations often require solutions that can dynamically control and adjust wellbore pressure to complete a hole section safely and efficiently. Finally, the lack of ability to respond quickly to an influx can result in kick sizes that cause significant safety concerns as well as Non Productive Time (NPT) and higher drilling costs.Managed Pressure Operations (MPO) has designed a new Riser Safety System (RSS) to allow the effective implementation of contingency Riser Gas Handling (RGH) and Managed Pressure Drilling (MPD) operations. The RSS system is intended to reduce the environmental risks associated with diverting an uncontrolled flow of gas and drilling fluid overboard with a conventional rig diverter system. With regards to MPD, the RSS is able to support constant bottomhole pressure control and mud cap drilling to facilitate reaching total depth safely, and effectively and with minimized NPT. The RSS also offers the technology to rapidly respond to well control events by dynamically and rapidly adjusting wellbore pressure in MPD mode. The RSS consists of an API 16RCD rated Riser Drilling Device (RDD) for sealing the riser closing on the drill string during MPD, and an API 16A rapid closing riser gas handling annular. Beneath both sealing devices a flow spool is used to divert riser returns from subsea to a pressure control manifold and high flow rate MGS on the rig via 2 ϫ 5.5" ID API 17K return hoses, with a third API 17K, 5.5" hose for over pressure relief.The RSS subsea equipment is also designed to reduce the operational risk and deployment time associated with moon pool installation operations. As such, the RDD, RGH annular and flowspool are designed to drift through the rotary table like a joint of riser. Once suspended in the rotary table by the spider slips, the remainder of the deployment consists includes a control umbilical connection and return hose gooseneck connection of three 5.5" mud hoses. The hose gooseneck latch connection system consists of an adjustable padeye system, hydraulic latching mechanism, and clearance for a reasonable range of rotational offset during the connection process allowing for rig crews to quickly and safely rig up the RSS system.This paper provides a detailed overview of the subsea equipment associated with the RSS system and how it is integrated with the rig's drilling riser. The RSS equipment conforms to the industry codes, i.e. API 6A, API...

The AFGlobal Corporation has developed a mid-riser pump system targeted toward managed pressure drilling (MPD) wells that maintains a full riser fluid column and statically overbalanced well at all times while excluding the need for rig and riser modifications or multiple interconnected manifolds at topside. The optimized configuration of this system is envisioned to permit rapid deployment on any deepwater floating drilling vessel to serve as one method of controlling equivalent circulating density. Ultimately, the PRS will serve as a stepping stone to full dual gradient drilling. Wellbore pressure is controlled by utilizing a subsea pump system to reduce the amount of riser annulus pressure exerted on the formation. The subsea pump system is operated in conjunction with an MPD wellbore seal permitting a configuration where the pump system can take suction from the riser below the MPD wellbore seal and discharge back into the riser above the MPD wellbore seal. As such, all riser flow is returned to the rig via the main flow line which also permits the option for conventional or advanced kick detection techniques. Since there is no independent mud return line out of the riser, the riser is always full of drilling mud. The topside footprint consists of a combined hydraulic power unit and pump controller skid and umbilical reel permitting 1-2 weeks of rig up time. The pump system and MPD wellbore seal are packaged as single unit which can be deployed through the rotary table in the same manner as a conventional joint of riser. By utilizing a positive displacement pump, the power requirement is low enough for installation across a broad range of drilling vessels.

One of the many benefits of a managed pressure drilling (MPD) system is the reduction in the non productive time associated with kick and loss events. While such an approach has merit, a pressure determination system (PDS)1–6 has been developed to progress MPD from a reactive system to one which anticipates changing formation pore and fracture pressure regimes as the well depth increases. Ultimately the objective of the PDS is to prevent a recordable well control event from occurring over the duration of the drilling process. The PDS is deployed in conjunction with an MPD Pressure Control Valve (PCV), a rotating or non-rotating annular sealing device, and a flow metering sensor system. The PDS is based on the premise that a small ID PCV, positioned in parallel with a larger ID MPD PCV, oscillates with a programmed open-close cycling speed to generate a pressure pulse in the drilling returns annulus. The programmed PDS PCV thus produces the annular "pulse" with amplitude parameters specified by the operator within the PDS control system that oscillates the annular pressure within a predetermined narrow pressure band while keeping the overall average annular pressure constant. As the cyclic annular pressure changes occur, the models and algorithms within the PDS analyze the relationship between the return flow rate measured by the flow meter sensor and the surface PCV pressure to determine if either pore or fracture pressure margins have been breached. The PDS then readjusts the target bottom-hole pressure (BHP) using the MPD PCV such that the BHP continues to remain within the new drilling window. Please note that at no point is average BHP expected to fall out of drilling margins. Wellbore compressibility of fluids, solids, and gas, wellbore storage effects, and the efficacy of the pulse transmission are key factors to facilitate the analysis3. Since the PDS PCV is rapidly oscillating its orifice size, a degree of influx or loss is potentially expected to occur in the presence of changing pore or fractures downhole as drilling progresses further. The preset amplitude of the generated pulse either begins to increase beyond the fracture pressure (in the case of an unexpected decrease in the fracture pressure) or decrease below the pore pressure (in the case of an unexpected increase in the pore pressure). The result is that for a brief moment in time drilling fluid is lost to the formation or formation fluid enters the wellbore. What is critical to note is that the resultant loss or gain volumes are negligible and occur instantaneously with the associated peak amplitude of the pressure pulse as it dips below the pore pressure or above the fracture pressure. The flow meter sensor data analyzed by the alogirthms of the PDS detect these miniscule volumetric changes in the annulus and make adjustments before a recordable well control event can occur. Once the average BHP has neared any changes in the geo-margin limit detected and calculated by the pressure pulse analysis of the PDS, the MPD PCV can be manipulated to change the average BHP to continuously remain within the drilling window. Therefore, a recordable well control event is prevented. The PDS will proactively "ascertain the downhole pressure environment limits" as stated in the IADC definition of MPD. This paper will discuss the engineering concepts, practical implementation, and a preliminary field testing program for the PDS system.

Objectives/Scope This paper introduces an active wellbore sealing system for use in Managed Pressure Drilling (MPD) incorporating a wellbore seal condition monitoring system. The paper will discuss how finite element analysis which has previously been validated with full scale testing can be expanded to develop the condition monitoring system. Methods, Procedures, Process In contrast to a passive rotating control device, an active MPD wellbore sealing system requires hydraulic pressure to engage a sealing element and form a wellbore seal. The paper will investigate the relationship between wellbore sealing pressure and hydraulic fluid parameters using the results of finite element analysis on a sealing technology which has been previously operated offshore in addition to extensive full-scale testing in a lab environment. Results, Observations, Conclusions The paper will show how the required hydraulic fluid requirements to form a wellbore seal change over time due to sealing element wear. The information can be used to predict the remaining life of the existing sealing element as well as proactively alarm the driller of the need to replace a seal sleeve due to a sudden deviation from expected behavior. The implementation of a real-time, condition monitoring system for the MPD wellbore seal is intended to increase the rig's confidence toward using MPD for challenging hole sections as well as circulating out small influxes from the well without closing the SSBOP, further reducing the risk of stuck pipe events. Novel/Additive Information The active MPD wellbore sealing system is a non-rotating, offshore wellbore annular sealing device which is integrated into the riser. It contains a seal of elastomeric composition which seals against drill pipe during all tripping and drilling operations. As the seal wears, the hydraulic closing fluid requirement to maintain an annular seal changes, which indicates the amount of seal material remaining.