Offshore Europe 2019, Day 4: A new era of innovative thinking
ABERDEEN - The industry’s efforts to cut costs, reduce working times and improve efficiency have paid off handsomely over the last five years, making previously uneconomic fields viable and boosting the life and output of existing fields. The wealth of real-life case studies outlined at SPE Offshore Europe have highlighted that this work continues apace.
Read the full SPE Offshore Europe Day 4 Show Daily here.
Wednesday’s sessions on Smarter and More Effective Field Development were a case in point, covering themes as varied as subsea operating envelope review, marginal field hydrate formation, field redevelopment planning and dynamic wellbore modelling.
The North Sea industry has benefitted greatly from innovative analytical approaches to field life extension, a good example of which is Bridge Petroleum’s proposed Galapagos field redevelopment of the abandoned North West Hutton field and the adjacent Darwin discovery, some 130 km northeast of the Shetland Islands.
The development could hold around 900 MMbbl of oil in place, of which the company hopes to recover around 40%. Drawing up the redevelopment plan involved several multi-disciplinary teams, whose work included analysis of 20 years of production data from 52 wells, to identify production behavior and confirm the target providing the basis selecting the development concept. This involved using gas-lifted production wells, with pressure maintenance through water injection.
A reference case of an FPSO with four subsea drill centers and horizontal wells completed with in-flow control devices and gas lift was used to devise an initial techno-economic model. The initial idea was for an FPSO capable of handling 90,000 bpd. However, improved understanding of the reservoir and flow control valve (FCV) behavior through extensive modelling and testing revealed that the project was only likely to require one with about half the capacity.
As Jeb Tyrie, Head of Technical at Bridge told the session: “We realized we were going to need a smaller boat!” The intensive optimization of this development built on FCV, resulted in increased oil recovery, and drastically reduced both water injection and production with the net result that the required facilities could be shrunk.
Cutting completion times. Step changes have also been made in reducing the time needed for well completions. Typically, offshore completions are carried out over two or three trips which routinely take 8–10 days or more to deploy. Faced with costly day rates for high-specification rigs capable of drilling in deep water, Shell wanted to look at how completion times could be cut on its Bonga field, 120 km off the Nigerian coast in up to 1,500 m of water. Weatherford worked with Shell Nigeria Exploration & Production Company to come up with a single-trip, interventionless, sand control completion system and successfully install it. This involved the first full-system approach to the application of radio frequency identification (RFID) enabled tools in such a project, Bruce Robertson, Weatherford’s Geozone Technical Sales Manager, explained that the system was tested and evolved through a number of iterations in an onshore trial well environment leading to its first successful deployment in 2018.
That resulted in an average completion installation time of five days, compared to the average of 10 days for deploying multi-trip completions at Bonga. He said this single trip set-up was not applicable in all scenarios, notably at shallower depths, and it costs more than the conventional approach, but that this would be outweighed by the savings on rig hire through a shorter deployment.
Democratizing data. Making complex data more accessible through easy-to use visualization tools has been a major theme at Offshore Europe, reflecting recent advances in know-how and computing power.
At another African project, Total E&P’s Kaombo field in Angola’s prolific deepwater Block 32, the wide range of often-complex reservoir conditions and the large subsea production system—with flowline lengths up to 25 km—called for an innovative approach to handling and interpreting large amounts of data. Total’s Julien Rolland told delegates how an in-house team went about developing a visual decision-making tool for the operator to handle normal and unplanned operations of the subsea system.
The team developed operating maps and envelopes that enabled a wide pool of users to analyze flow assurance more easily than standard studies, he said. The method is specifically adapted to complex economical and technical environments, with a focus on tightly defining the design margins of subsea assets. The tool helped efforts to broaden access to data across disciplines at the Kaombo project, as well as bridging the gap between project/development phase and operations.
“The data is accessible to everyone. Not only the specialists can talk about these sometimes-difficult topics, but everybody can use the tool—management, decision-makers, offshore people can check wherever they operate,” Rolland said.
