A new automated method of detecting an influx or losses using standpipe pressure (SPP) and annular discharge pressure (ADP) has been tested while drilling a tight gas well in Canada with approximately 200 hours of operational time being logged. While tight gas reservoirs may seemingly pose a low well control risk, they are typically drilled underbalanced to increase the rate of penetration and to eliminate a casing string which is required when using a higher mud density in order to protect upper formations due to low kick margin tolerance. The operator's experience was that previous kicks went undetected until a significant volume had been produced due to the closed loop system having fluid retention without accurate flow measurement, resulting in slower pit volume measurement, extended well control time and requiring the casing to be set deep enough to protect the weaker formations from high shut-in pressures. Delta flow using flow meters has been in use for over 15 years for early kick detection (Haeusler et al 1995), however for tight gas drilling this method has not proven suitable due to cost, complexity and measurement disruption due to high gas fractions in the drilling fluid. A comparison of using a high resolution flow meter and pressure sensors prior to the field test will be discussed in addition to the field trial results. Benefits of using this new system, what was learned during the trial and improvements to the system will also be discussed along with how the system can be applied to Managed Pressure Drilling applications where the system is augmented using choke position and with conventional drilling applications.

Manual choke control has been the staple of many Managed Pressure Drilling (MPD) operations. To be successful manual choke control requires close communication and cooperation with between the driller and the choke operator. Responding to contingency scenarios, such as rig pump failure, is highly dependent upon the situational awareness of the choke operator and the speed at which they can respond. The consistency and repeatability of manual methods is therefore only as good as the choke operator's skill, experience and how well the choke operator and driller work together. Automated choke control increases the consistency and repeatability of control, as well as the ability to respond to contingency scenarios with little or no operator intervention. However, automation tends to increase the complexity of the equipment needed and changes the competencies required from personnel. Achieving a fit for purpose degree of automation that balances the delivery required to successfully drill the well without adding any more complexity than is absolutely necessary is therefore a challenge. This paper describes a new automated MPD system that was developed with the goal of providing increased performance while minimizing any additional complexity. The new system had to be capable of providing pressure trapping, to be able to manage multi-step pressure/flow pump ramp schedules, and yet had to have a similar physical footprint to and work with existing equipment. The technology was evaluated in terms of ability to control, setup time, ease of use, and ability to perform the scope of work required. The system represents a step change in performance compared to manual MPD and yet maintains a streamline equipment footprint.

Objectives/Scope This case history paper describes the well integrity challenges Spirit Energy was faced with for executing the drilling operations on the Scarecrow wildcat well in the Barents Sea. The expected reservoir depth on Scarecrow was the shallowest reservoir ever drilled in the Barents Sea being only 188 m below mudline with a water depth of 454 m MSL. Several mitigating actions were implemented to improve robustness of the well integrity such as: The focus in this paper is to describe the qualification of a new automated pressure control method (Autochoke system) used on the Scarecrow wildcat well in the Barents Sea for circulating out an influx. Simulations and return of experience indicated that manual conventional well control practices would not provide sufficient pressure control precision to maintain bottomhole pressure within the +/- 4 bar (58 psi) operational window required to circulate out an influx. A new automated pressure control method based on a commercial managed pressure drilling (MPD) control system was developed, tested, and DNV approved to achieve the required pressure control precision for both single- and multi-phase scenarios, and permit safe operations. Methods, Procedures, Process A pressure control method was developed to automate control of well control chokes to maintain a constant standpipe pressure, as required during circulating using Driller's Method. The methodology used is comparable to commercial MPD pressure control systems, in which pressure transducer (PT) measurements are input to a control loop which actuates chokes to attain the pressure demand while minimizing overshoot. Unlike a typical MPD installation, in which PTs are typically located upstream of a choke manifold, this installation utilized PTs installed on the rig standpipe, with chokes installed in the well control manifold. The choke control system was improved to automatically compute and account for pressure wave propagation lag due to the distance between the chokes and the control PTs. Results, Observations, Conclusions The system was tested at a test rig in Norway that permitted the injection of air into the standpipe to simulate a gas kick. In multiple test cases, various quantities of air were injected into the standpipe, circulated into the annulus, and finally circulated out of the wellbore with automated chokes operating to maintain a constant standpipe pressure as the air was circulated out of the wellbore and through the chokes. Testing was repeated with varying quantities of injected air and varying standpipe pressure setpoints to validate the process across a range of operating conditions. The control system demonstrated standpipe pressure control precision of +/- 1 bar (14.5 psi) during all test phases, achieving the required precision. Testing under additional operating conditions was conducted to approximate a real-world well control scenario, in which constant casing pressure is maintained while ramping the pumps, and constant standpipe pressure is maintained while circulating out the kick (i.e. first circulation of driller's method of well control). The maximum observed deviation from the control value was 2 bar (29 psi), again meeting the required control precision. Novel/Additive Information These tests were observed, validated, and approved by DNV. The technology was introduced to the field in July 2018.