Hurricane Energy has proven commercial oil can flow from its fractured basement oil reservoirs West of Shetland – it’s next job is finding an economical solution to get it to market. Elaine Maslin reports.
Artist's illustration showing a minimal facilities DP production vessels. Images from Hurricane Energy.
Imagine there is proven oil in the ground, but not enough cash to fund the initial preferred development option, which would capture long-term production data from a number of wells to optimize the full field concept.
What do you do? This was Hurricane Energy’s conundrum for its Lancaster fractured basement reservoir development West of Shetland, until it successfully drilled and tested a 1km horizontal well on the Lancaster field in 2014.
The results of the well test enabled Hurricane to completely review its first phase of development on the field.
The firm, which had been considering a multi-well, floating production, storage and offloading (FPSO) concept, is now looking at a simple, one-well, first phase early production system (EPS), using a DP FPSO with a disconnectable turret and minimal subsea and process infrastructure.
Hurricane hopes that, ultimately, this concept will lead to an enhanced full field development, potentially stimulating a new hub in what has been up to now an area with limited infrastructure.
Existing pipeline infrastructure and fields West of Shetland.
Hurricane Energy was formed in 2004, to focus on naturally fractured basement West of Shetland. It was awarded its first license, P1368, containing the Lancaster field, in 2005. It now has three licenses, with the second two containing the Typhoon and Tempest prospects. The area sits on the Rona Ridge, in about 150m deep water, with Typhoon and Tempest in slightly deeper water, at about 490m.
The EPS reference case.
Lancaster has had four wells drilled on it, the first by Shell in 1974 and then three by Hurricane, in 2009-2014, proving up 207 MMbbl of 2C contingent resource. A further 200 MMbbl has been found on the nearby Whirlwind field, plus 400 MMbbl P50 prospective resources across its other assets, Neil Platt, Hurricane’s chief operations officer, told the Devex conference in Aberdeen earlier this year.
But, development options for the field and neighboring Whirlwind and Lincoln discoveries, have not been obvious. “The location and environment are a challenge, as is the lack of infrastructure” Platt says. “However, not a challenge that Hurricane believes cannot be overcome with the right mindset.”
Hurricane worked with EPC Offshore, now part of Costain Upstream, on a series of conceptual reviews from 2012-2013. More than 45 concepts were assessed, based on 4-5 fundamental principles, with 10 short-listed for further evaluation.
“The main considerations were; platform versus FPSO, phased versus pre-invested ‘all in one go,’ hub versus third-party host and different options for oil export etc.,” Platt says. One solution was broadly favored, a two-phase project based on an FPSO, which would be designed to either have the facility to be upgraded at a future time or be replaced by a larger vessel.
The first phase of this concept is constrained by Hurricane’s primary objectives of better understanding the reservoir performance as well as providing an economic return on the capital expended.
The EPS capex lite option.
“From our analysis of our 2014 well test results, we don’t believe we can learn much more from drilling further wells, rather we need to put the field on a long-term production test, which we refer to as an early production system, to really understand the performance of the reservoir, whilst at the same time delivering an economic return on the capital invested,” Platt says. “As the reservoir is also near bubble point and there remains uncertainty over the effective aquifer pressure, the prolonged period of production will also be designed to monitor these variables to assist with and augment long-term planning.”
Within the company’s latest Competent Persons Report (CPR) dated 2013, the reservoir evaluation phase, or phase 1 would involve a leased FPSO, capped at 37,500 b/d, from six wells; using the 2010 suspended appraisal well, the 2014 horizontal well, a further three horizontal wells and a crestal surveillance well. The project would run for 2-5 years, with two years to provide production data, followed by a further approximate three years while the optimum full field facilities are installed for the commencement of production from phase 2.
With the nearest oil export line from West of Shetland c.85km away at the BP-operated Clair field, Hurricane went for oil offtake by shuttle tanker.
For phase 2, a further five wells would be added, increasing capacity to a total 80,000 b/d with the concept designed to handle both upside Lancaster volumes and potentially other nearby assets. The CPR states that Lancaster upside volumes could be in excess of 400 MMbbl in the 3C case.
Flow assurance and artificial lift methods – electrical submersible pumps (ESPs) vs. gas lift – were considerations for both phases, as were the implications of future produced water on flowline design, (heated or not) and chemical injection requirements.
Price changes everything
What a Greater Lancaster Area and Whirlwind development might look like.
At the time of the CPR, oil was trading at a steady US$100/bbl. The phase 1 development was estimated to cost about $1 billion, with a letter of assurance required for the leased FPSO of c.$750,000. Total project cost, including phase 2, was closing in on $3 billion. With the declining oil price, Hurricane needed to look at alternative solutions to achieve phase 1’s primary objectives.
It came up with a DP2/3 EPS, which it called the EPS reference case. This would involve turning the existing horizontal well 205/21a-6 into a producer, and adding a new horizontal well at the same drill center, with both tied back to a small leased FPSO, about 3km away. The 4Z well would remain suspended initially with the option to either tie back or run gauges for reservoir performance analysis at some time post first oil depending on field requirements and the constraints on the vessel.
The reduced level of subsea infrastructure meant a smaller FPSO and therefore lower capex and potentially a faster route to first oil. The vessel could also then be used as a facilitator for EPSs on the company’s other assets as Lancaster moved into phase 2.
Well test changes all that
Then, last year, Hurricane flowed better than expected commercial rates of oil from Lancaster, at 9800 b/d, with an ESP down the well, constrained by surface equipment. “This enabled us to further optimize our thinking on how to progress and accelerate the Lancaster hub and how we can move forward with a phased development,” Platt says.
The company’s original phase 1 development was based on its CPR, which predicted 2km-long horizontals would be needed to achieve a starting well rate of 10,000 b/d. “Last year, we achieved nearly 10,000 b/d from just 1km,” Platt says.
Hurricane reviewed its EPS reference case plans – and came up with “EPS Capex Lite” based on a single well at first oil. “This is a step change, which has enabled us to also critically look at its subsea infrastructure work scopes and costs,” Platt says. “We believe the outcome will still deliver the full evaluation and optimization data we need, but it now has the potential to allow us to drill the second well, funded from cash flow, at a timing of our choice during the initial five years and to place it optimally, based on the first few years’ production from the single well.”
The relatively simple DP FPSO would be 300m from the well, on a disconnectable buoy, using flexible flowlines, effectively tied to a small riser-based structure adjacent to the well. It would have a 20,000 b/d gross fluid handling name plate capacity, 10,000 b/d produced water capacity, and one separation train. The infrastructure would have the ability to “daisy chain” a second well using the umbilical and flowlines that go down to the riser based structure from the FPSO post-first oil.
“Normal oil offtake would be via shuttle tankers, but, in bad weather, the FPSO could disconnect and sail away to discharge the oil cargo itself,” Platt says. Because of the shorter umbilical length, initial investigations suggest flowline heating would not be required and chemical injection would suffice. Instead of gas lift, ESPs, or potential hydraulic submersible pumps, would be used to minimize flaring through maximizing the use of produced gas for power generation and in marine systems.
“Process-wise; it’s a turret and a buoy, with a simple oil processing and water clean-up system,” Platt says. Hurricane hopes to be able to discharge any produced water over the side.
“Hurricane has also started discussions with a number of FPSO providers for a financial solution, which would not rely on traditional bank financing routes to help solve its conundrum of having to collateralize a letter of assurance to the FPSO provider,” Platt says.
Phase 2, “Post-EPS Capex Lite”
What the new phase 2 would look like is still undecided. “It could be that Hurricane goes direct from the “EPS Capex Lite” to a full field development in one go, or via the CPR concept of phase 1 through to a full field development,” Platt says.
Hurricane also has more than the Lancaster field to consider. The nearby Lincoln field has a P50 prospective resource of 150 MMbbl, which could pave the way for a Greater Lancaster Area (GLA) hub development.
There is also Whirlwind, with a 200 MMbbl 2C contingent resource in the oil case. However, Whirlwind might require a platform-based solution to host compression supported by the GLA hub FPSO, as analysis of the Whirlwind discovery well suggests the hydrocarbon type may be either a light condensate or volatile oil.
Then, there is also Strathmore, Typhoon and Tempest. As OE went to press, Hurricane announced it had been awarded two further blocks in the area, 204/30b and 205/26d, which contain a new basement prospect provisionally named Warwick, considered to be analogous to the Lancaster discovery. Lincoln is also thought to extend into 204/30b.
“There’s significant potential West of Shetland, not just for us, but for everyone,” says Platt, who is keen to emphasize the opportunities for collaboration and shared facilities in this area.