A report from Norway’s Auditor General criticizes several aspects of the way health, safety, and the environment in the Norwegian oil and gas industry is followed up by the Petroleum Safety Authority Norway. Norway has invited companies to submit bids to use subsea reservoirs to store carbon dioxide near the country’s largest oil and gas field, Troll. Statoil To Become Equinor, Dropping'Oil' To Attract Young Talent Shareholders in Norway’s largest company, Statoil, approve the board’s proposal to drop “oil” from its name as its seeks to diversify its business and attract young talent concerned about fossil fuels’ impact on climate change. But serious personal injuries are growing, while feedback on the working environment, the HSE climate and perceived risk is moving in the wrong direction. Norwegian suppliers Framo, Maritime Partner, Norbit Aptomar, and NorLense have come together to create the Oil Spill Recovery Vessel Group to offer a complete oil-spill-response solution.
The SPE Norway One Day Seminar is the key annual forum for discussion points, industry developments and technical challenges facing upstream oil and gas in the Norwegian Continental Shelf and wider E&P industry. Its highly respected technical content represents a diverse range of oil and gas disciplines and provides an excellent learning experience.
Thank you for attending the SPE Seminar. Thank you for attending the SPE Seminar. The SPE One Day Seminar is the key annual forum for discussion points, industry developments and technical challenges facing upstream oil and gas not only in the Norwegian Continental Shelf, but also the wider E&P industry. The conference's highly respected technical content represents a diverse range of oil and gas disciplines and provides an excellent learning experience. The seminar will provide scope for networking with industry colleagues, as well as an exhibition that will showcase leading organisations active within the sector.
The digital transformation of the oil and gas industry is happening right now. This session looks at how digitalisation and data sharing philosophies can change business models, as well as enable optimised operations and efficiency gains through better insight, faster decisions and optimised work processes. The progress of drilling technology is exposed widely in this section. Scientists and engineers from academia, oil companies and service companies are working together to develop new methodology and experiences. The session includes Depletion and Re-Pressurizationin the Valhall Field, Reconstruction of Pipe Movement, Optimized Trajectory and Efficient Slot Recovery, Model Parameters on Frictional Pressure Loss Uncertainty and Accuracy of Combining Overlapping Wellbore Surveys.
The SPE Board of Directors meeting was recently held in Cairo. My intent is to share important information with our members after each meeting. As SPE, and the industry, emerge from the downturn, one of the Board’s most important topics of discussion was financial. The New SPE International App allows you access to SPE anytime, anywhere. It has many great benefits: access to our widely used OnePetro® and PetroWiki® platforms, the latest content from SPE magazines and publications which you can tailor to your preferences, and global networking opportunities through SPE Connect.
In recent years, the oil and gas industry has gained greater operational efficiencies and productivity by deploying advanced technologies, such as smart sensors, data analytics, artificial intelligence and machine learning — all linked via Internet of Things connectivity. This transformation is profound, but just starting. Leading offshore E&P operators envision using such applications to help drive their production costs to as low as $7 per barrel or less. A large North Sea operator among them successfully deployed a low-manned platform in the Ivar Aasen field in December 2016, operating it via redundant control rooms — one on the platform, the other onshore 1,000 kilometers away in Trondheim, Norway. In January 2019, the offshore control room operators handed over the platform's control to the onshore operators, and it is now managed exclusively from the onshore one. One particular application — remote condition monitoring of equipment — supports a proactive, more predictive condition-based maintenance program, which is helping to ensure equipment availability, maximize utilization, and find ways to improve performance. This paper will explain the use case in greater detail, including insights into how artificial intelligence and machine learning are incorporated into this operational model. Also described will be the application of a closed-loop lifecycle platform management model, using the concepts of digital twins from pre-FEED and FEED phases through construction, commissioning, and an expected lifecycle spanning 20 years of operations. It is derived from an update to a paper presented at the 2018 SPE Offshore Technology Conference (OTC) that introduced the use case in its 2017-18 operating model, but that was before the debut of the platform's exclusive monitoring of its operations by its onshore control room.
CML (Controlled Mud Level) is a dual gradient type of Managed Pressure Drilling (MPD). The CML system was developed and implemented on the Troll field to allow for reducing the annular pressures acting on the wellbore during drilling, thus allowing drilling areas weakened by faults and fractures and longer horizontal sections in the depleted normal pressured reservoirs. This paper will present a short introduction to the Troll field, a description of the system utilized, a summary of the rig integration, operations and experiences with the CML system on Troll.
The oil and gas industry faces three key questions with regard to sustainability. Can we transform oil and gas into a cleaner, efficient source of energy with minimum or zero-net CO2 emissions? The New SPE International App allows you access to SPE anytime, anywhere. It has many great benefits: access to our widely used OnePetro® and PetroWiki® platforms, the latest content from SPE magazines and publications which you can tailor to your preferences, and global networking opportunities through SPE Connect. Watch the video to find out what our members are saying about the benefits of being an SPE member.
The most important contributer to Improved Oil Recovery (IOR) on mature fields is drilling of infill wells. Managed Pressure Drilling (MPD) and Continuous Circulation System (CCS) techniques can be used for improved control of bottomhole pressure when drilling wells in depleted fields with narrow pressure windows, but rig heave is a challenge when drilling from floating drilling units. Rig heave, caused by sea waves, induces pressure oscillations downhole that may exceed the operational pressure window. These oscillations are called "surge & swab" and occur both during tripping in and out of hole as well as during drill pipe connections, when the topside heave compensation system used during drilling is disabled because the drill pipe is put in slips. Downhole choking was introduced as a method to reduce downhole pressure oscillations induced by the rig heave and the concept was tested in laboratory scale and using computer simulations (
This paper gives an overview of the surge & swab simulator, describing its capabilities and limitations. Data from drilling of a North Sea well is then used to validate the simulations made using the software. The well, used as example in this paper, was drilled conventionally from a floating rig. The downhole pressure variations recorded during three different drill pipe connections are compared with simulated downhole pressure. The simulations are based on the recorded rig heave as well as the actual drilling fluid, well design and drill pipe data. Results show that there is a good correlation between simulated and actual measured downhole pressure. The surge & swab simulation software is then used to simulate the same drilling pipe connections using three different techniques and combinations of techniques utilized for improved downhole pressure control: (1) Managed Pressure Drilling (MPD) (2) Managed Pressure Drilling combined with Continuous Circulation System (CCS) and (3) MPD combined with CCS and a downhole choke. Results show that rig heave-induced downhole pressure variations are reduced to a level which is considered acceptable for drilling a well with narrow pressure window for the last two cases, while utilization of backpressure MPD alone is not sufficient. The combination of MPD and CCS reduced surge & swab for two out of three connections. For the third and deepest connection, the surge & swab increased. The largest reduction in significant downhole pressure variations (43-68 % vs. conventional drilling for the three connections) occurs when MPD and CCS are combined with downhole choking.
Future work will consist of further developing the surge & swab simulator so that it will be possible to utilize it in well planning and as real-time decision support during drilling operations. The simulator will also be developed to include possibility of simulating various well completion operations such as running casings and liners. A prototype of the downhole choke is currently being tested at the mud loop of the Ullrigg test rig facility in Stavanger, Norway, and the next development phase consists of designing and building a complete downhole tool for testing in a well.
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:
Seismic While Drilling in the pilot hole down to planned depth of the 13 3/8" shoe to reduce reservoir depth uncertainty
Minimum acceptable LOT value at the 13 3/8" casing shoe for allowing drilling into the reservoir
Unknown reservoir fluid; gas gradient used in design
If actual LOT value lower than minimum accepted; P&A well
Well Control training with the crews onshore at Maersk Training Center
Installation of low flow pump to improve control of actual LOT value
Installation of Autochoke system on the rig
Kick drills on the rig focusing on kick detections and optimizing sequence for closing in the BOP
Well control training using the Autochoke system on the rig as part of qualifying the system for use
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.
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.
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.
These tests were observed, validated, and approved by DNV. The technology was introduced to the field in July 2018.