Jeremy Beckman
Editor, Europe
Some of the UK's largest remaining untapped resources are the high pressure, high temperature (HPHT) gas-condensate fields in the central North Sea. These extend from the Conoco Phillips-operated J-block in Quadrant 30 northwest to the Britannia satellites in Quadrant 15.
New development projects in the HPHT category are under way on Chevron's Alder and Ithaca Energy's Greater Stella Area. However, the producing fields with the most extreme reservoir conditions remain Shell's Shearwater and Total's nearby Elgin/Franklin, all of which were developed concurrently in the early 2000s. Total's latest add-on, due onstream later this year, is the 85MM-boe Franklin West, which will be connected by two 6-km (3.7-mi) pipelines to the Elgin complex. Here the reservoir pressure of 1,100 bar (15,954 psi) and temperature of 190°C (374°F) are thought to be the UK's most extreme combination to date.
However, there are other discoveries in the corridor with even harsher conditions which are proving difficult to drill, let alone develop. Technologies are emerging that can take these projects forward, but at a cost. Additionally, evidence from HP/HT fields in production for some time suggests that the shelf life of some wells may be shorter than anticipated due to migration of gas in the reservoir over time and the impact of the gas' chemical content on production facilities. This may necessitate costly re-drills.
UK offshore production is in irreversible decline and the government has introduced a series of tax allowances to encourage development of problematic or marginal fields. In March's annual Budget speech, Chancellor George Osborne announced proposals for a new allowance for ultra high pressure, high temperature (uHPHT) field clusters – the latter were among the key recommendations in Sir Ian Wood's review of the UK's long-term needs as a hydrocarbons-producing province, published earlier this year. Sir Ian called for different sets of offshore license holders to collaborate to establish new area-wide production hubs to ensure development of clusters of otherwise stranded fields.
The government published its uHPHT allowance consultation last month, to be followed by a period of engagement between interested parties and relevant UK government officials that ends on September 30, with the final level to be announced along with the final policy design later in the fall.
As things stand, the proposed cluster area allowance would operate similarly to existing UK field allowances by exempting a portion of a company's profits from the supplementary charge, reducing the effective ax rate on that portion from 62% to 30%. The amount of profits exempt from the supplementary charge would be based on a proportion of the capital expenditure a company incurs in relation to a cluster. This would include exploration and appraisal costs, but would exclude decommissioning costs.
The government proposes that a cluster area:
- contains an undeveloped ultra HPHT discovery
- could extend into unlicensed acreage
- would be defined as a 3D volume (i.e. with a top and/or bottom). Non-ultra HPHT fields above a new cluster area would likely be excluded from this 3D volume
- may contain undeveloped potential not expected to be ultra HPHT
- may contain more than one discrete field
- a cluster area is not a hub taking in several geographically separate discoveries.
Companies would start to generate and hold the allowance as soon as they incurred qualifying capital expenditure in relation to a cluster. They could also opt to transfer generated allowance between their projects in the same cluster. This would mean that allowance generated by spending on unsuccessful exploration or appraisal, for example, could be activated by production income from a successful project within the cluster (but only after a period of three years from when the expenditure was incurred).
To help reach agreement on a viable plan, each cluster area should have the following:
- commercial alignment among licensees in a cluster area – any differences in equity interests should not adversely affect exploration, appraisal and development work
- unified mapping and no equity drilling (e.g. sole-risking)
- full data sharing between all licensees in a cluster area
- one agreed operator per cluster area where possible
- shared, agreed exploration and production concepts, plans and timings
Culzean complex
Two of the central North Sea operators with most to gain from the new proposals are Maersk Oil UK and BG Group. Both have large (by UK standards) discoveries with hostile reservoir conditions that they have been trying for some time to commercialize. In May, Maersk announced that in partnership with JX Nippon Exploration and Production (UK) and Britoil (BP) it had selected a new standalone platform complex to develop its Culzean field which the company discovered in 2009 in 88 m (289 ft) of water in block 22/25. The well was complex and took a long time to drill: the reservoir is around 4,300 m (14,107 ft) below sea level. Plans call for a 12-slot wellhead platform (WHP) bridge-linked to a central processing facility and utilities/living quarters.
Maersk said the total investment would likely exceed $4.7 billion, adding that the project was set to benefit from the new uHPHT allowance (a final investment decision is due next year). First gas could flow in 2019, and within two years the field could be supplying around 5% of the UK's annual gas consumption, the company added, peaking at 500 MMcf/d. Among the main contracts awarded so far, KBR is working on front end engineering design of the facilities, Ramboll Group is performing detailed design of the WHP jacket, and Hercules Offshore's newbuild heavy duty jackup will start development rilling in 2016.
At Oil & Gas UK's uHPHT conference in Aberdeen in June, Martin Rune Pedersen, managing director, Maersk Oil UK, said the new allowance "has the potential to reduce dead weight on projects as it is targeted and scalable for individual projects…It also takes into account pre- and post-field development plan expenditure, so theoretically, it can be extended to exploration and appraisal.
"So why is an allowance needed? This is because uHPHT is very different to conventional field developments in terms of the risk and capital investment, and also the pre-commitments required in order to drill within the windows of opportunity due to the nature of these projects. The allowance should be enough to get the project across the line in terms of commercial viability for all the partners. It provides incentives, compared to the fixed allowances the industry has been used to, making it easier to call on capital and to determine future proofing of these concepts as we go forward."
From the UK government's perspective, he added, there would be a further benefit from the newly-installed offshore infrastructure. "Looking at future opportunities, the additional pipelines will drive less focus on a sole-field development and more on an area-wide cluster development. This is a significant change."
Pedersen then posed the question, why does a cluster development matter? The answer, he said, is that "clusters do matter because they enable maximized recovery from the area so that we end up focusing on the license terms and the individual development. It could mean rolling up the entire license commitments for an area and driving the respective partners to collaborate for much earlier alignment in terms of exploration prospects and ownership of the emerging hubs."
During planning for the Culzean development, Maersk examined the potential for a hub for the area able to accommodate other wellhead platforms and production add-ons from other projects at later stages. "However, if the hub/cluster model is to be replicated elsewhere in the basin," Pedersen said, "operator behavior will have to change…we need to devise far easier alignment in the area and strive for early agreement on how to develop work plans for wider [field] clusters.
Jackdaw extremes
Much of BG's UK offshore production of 110,000 boed/ comes from the central North Sea, where the company operates the Armada, Everest, and Lomond hubs, and is a partner in Buzzard and the HP/HT Jade development, operated by ConocoPhillips.
The company's main undeveloped resource is the Jackdaw gas-condensate field, containing reserves estimated currently in the range 125 to 250 MMboe. The region around Jackdaw holds total discovered resources of around 2 Bbboe, according to Andy Samuel, BG's managing director for Europe E&P, another speaker at the uHPHT conference.
BG drilled the Jackdaw discovery well in 2005 followed later by three appraisal wells: most of the company's activity to date has focused on the northern part of the field. It was an extensive and costly appraisal program, Samuel explained, "owing to the very substantial pressures and temperatures". Pressure at the base of the Jackdaw reservoir is 17,250 psi (1,189 bar), possibly the highest for any UK offshore discovery to date, and the temperature around the base is 385°C (725°F).
"To date we've penetrated three of the fault blocks: it's a very permeable, high-quality Jurassic reservoir, and we can take some learning from [Total's] experiences at Elgin/Franklin, which is a similar type of reservoir. Unfortunately, Jackdaw has quite a lean gas condensate, so we won't have the economic benefit of the substantial oil that is produced from Elgin/Franklin."
In 2012 BG conducted a successful drillstem test on Jackdaw using equipment specially qualified for the harsh conditions, following collaboration with the UK supply chain. "It is critical to get an understanding of the reservoir fluids and the challenges they may pose down the line," Samuel said. "Exploration and appraisal is expensive – anything that would allow us to drill these wells cheaper, and safer, would help hugely."
Jackdaw spans three licenses; BG and five other partners in the licenses are working to put in place a pre-unit agreement ahead of a development. "We're currently going through a concept select phase: the base concept is similar to Culzean, with three platforms. But there are challenges unique to uHPHT. From the safety viewpoint, we want the maximum pressure brake to occur at the wellhead platform, and we will do this through a high integrity pressure protection system." The numerous ball valves on the platform providing protection by reducing the pressure will weigh over 10 t each, he said, using this as an instance of the high development costs that lie ahead. "The capex is high, the drilling costs are high, and you may have to factor in infill well drilling down the line. Plus, there is a degree of risk."
Nevertheless, BG sees Jackdaw and the new allowance as a good test case for the uHPHT corridor as a whole, Samuel said. "We will provide data openly, and we need to creatively explore broader solutions to kick-start developments such as this and unlock these resources." One way is through collaboration: "As part of the base case development for Jackdaw, our team approached all operators of acreage within a 25-km (15.5-mi) radius of our proposed project to explore possibilities for a joint development or a subsequent tie-in [to the new facilities]. There are a lot of stranded discoveries nearby, mainly operated by Maersk and Gaz de France E&P UK, with exciting exploration potential."
Jackdaw's future proofing scenario takes into account tie-ins, with some deck space on the platforms to add further modules. "But to maximize value we are exploring whether to go for a joint development from day 1."
To the south-east of Jackdaw BG operates the Invincible prospect. "We expect to find the same Joanne Triassic sandstone reservoir that is so productive in the J Area. To the north and south there is high-quality Jurassic rich clay. There is a range of resources with all these structures but the mid-case potential appears to be 60MMboe. However, right now these prospects are not economic to drill, even though there are enough to potentially make a difference. Our challenge is to find a way to make them economic, get them to be part of a base development and accelerate exploration. In this area we think that putting in new infrastructure is the way forward – this area could supply up to 10% of the UK's gas, and these fields tend to have a long life."
