As maximising production and recovery become an even greater priority in the North and Norwegian Seas, regulators are pushing technology adoption even harder. The Norwegian Petroleum Directorate (NPD) now hopes to encourage more operators to use enhanced oil recovery (EOR) techniques at new-build projects as well as fields nearing the end of their productive lifespan, Reuters reported on June 15.
More than that, firms could even be ordered to do so as part of their plans for development and operations (PDOs), an approach which would echo NPD efforts to encourage joint infrastructure programmes between upstream projects.
It is understood that Statoil’s Johan Sverdrup could trial EOR technology when it launches in late-2019, piloting an injection scheme which would mix injected water with polymers to bolster recovery. Statoil had touted a lower break-even cost for Johan Sverdrup of US$25 per barrel, after last year reducing its full project budget estimate by as much as 23%, to around 140-170 billion kroner (US$16.4-19.9 billion). But whether operators will welcome such interventions remains uncertain.
Declining production Norwegian oil production plummeted from a peak of roughly 3.11 million bpd to 1.62 million bpd in 2016, though last year’s figure was itself an improvement on the 1.57 million bpd reported for 2015. Meanwhile, the crash in crude prices has forced Norwegian operators to make savings at their development projects to maintain profitability. According to the Norwegian Oil & Gas Association, upstream spends could slide by 7% this year to 143 billion kroner (US$16.7 billion), before falling further to 131 billion kroner (US$15.46 billion) in 2018. The upshot of this has left the NPD searching for ways to ensure that operators squeeze the most efficiency out of each NCS project, both on expenditure and in terms of reserves.
In mid-June, the NPD said that fully utilising EOR technologies could lift the NCS’ recovery factor by around 7% of in-place oil reserves. On the basis of Norway’s 27 largest oilfields, the directorate estimates that an additional 3.7 billion barrels could be unlocked with EOR. It goes so far as to argue that failing to invest in EOR would result in half of Norway’s oil resource being left below ground.
“The NPD believes that it is worthwhile to investigate whether some of this technical potential can be realised. Full scale pilots are needed to quantify the resource potentials of EOR,” the directorate told Newsbase Intelligence (NBI).
Already, EOR has prolonged the lifespan of major Norwegian producing fields by 12 years on average when compared with the original PDOs. But the NPD wants to extend this further, by encouraging operators to implement EOR techniques at the beginning of each lifecycle. Some believe this would allow EOR to improve recovery rates of the so-called “easy oil” at fresh developments, rather than focusing on the more challenging task of lifting recovery volumes at the end of life, which are more challenging for displacing agents to shift.
Weighing the options On the one hand, the NPD’s emphasis on early-stage EOR investment makes sense given the planning needed to make recovery upgrades efficient. The NPD said: “There are reasons to believe that early commitments to infrastructure, weight and spare capacity could open up future EOR projects.” In an economic assessment of EOR published in 2015, senior advisors from Petoro estimated that retrofitting Norwegian fields with a 15,000 cubic metre low salinity water injection (LSWI) plant could cost US$300 million. Further hurdles arise when considering that injection wells must be adequately sited into the aquifer, Petoro said, which could open a wide gap between injection and production wells. This could prolong the time required to gather testing results, which would in turn reduce net present value (NPV) projects for EOR investments at existing reservoirs. Petoro suggested these challenges might be bypassed by using EOR in undeveloped sectors instead. Yet the NPD was less clear on how it proposes to convince operators to bear EOR investments at the beginning of NCS projects. While it could certainly make it a licensing requirement to do so, investors may be displeased with racking up additional short-run costs at a time when slashing capital expenditure has been a priority. The NPD said: “[Our] role is to make sure that all economic resources are produced from the reservoirs. NPD encourages the companies to investigate and pursue all possibilities to achieve this, including EOR technologies.”
Choices, choices Then there is the question of which technology would be most cost-effective in Norwegian waters. EOR is typically more expensive when deployed at offshore fields, where all of Norway’s producing fields are currently situated. According to a University of Aberdeen paper published in November 2014, it would have cost GBP338 million (US$430 million) at 2014 prices to develop EOR for 42 million barrels of oil reserves in the UK Continental Shelf (UKCS). Lifecycle operating costs were estimated at another GBP100 million (US$127 million). This largely remains the case regardless of whether operators choose polymer or gas injection strategies for their EOR projects. Polymer flooding programmes were judged to require a high initial investment, much of which would be spent modifying the FPSO or platform to accept polymer throughput.
The cost of purchasing polymers was said to account for 80-90% of total opex projections, and there is also the risk that polymer will degrade in the choke of the reservoir. However, polymer EOR schemes are believed to bolster extraction at “modest” levels for a “very long time”, which could make it more suited for Johan Sverdrup at the beginning of its lifecycle.
Moreover, it may be easier for the NPD to convince investors to roll out polymer injection prior to the FID stage, before any key design decisions have been taken and approved.
Gas injection may also involve “very large” operating costs because of the gas volumes needed over an EOR project’s lifecycle, according to the University of Aberdeen. At 2014 prices, the paper estimated using gas injection to extract 53.3 million boe would cost GBP503.5 million (US$641 million) to develop, plus GBP 1.492 billion (US$1.9 billion) for gas supplies.
But gas injection may bring other advantages for developers on the NCS, particularly given the supply glut which sent prices crashing in 2015. Statoil is already preparing to utilise water alternating gas (WAG) injection at its Snorre Expansion Project in the Norwegian North Sea from January 2021. WAG interchanges between the injection of water and gas to increase the volume of the reservoir brushed by injected fluids.
Statoil will spend around 22-25 billion kroner (US$2-5.3 billion) on the upgrades between 2018 and 2024, to extract an additional 190 million barrels of oil reserves.
The so-called “Increased Oil Recovery (IOR)” programme will comprise six templates, each of which can hold up to four wells connected to the Snorre A platform. At present, Statoil proposes completing 11 production wells and 11 WAG wells for the expansion project, of which four should be pre-drilled before launch in 2021.
Its concept would see up to 2,000 cubic metres of gas per day received from Gullfaks A, as pressure support between 2022 and 2036, but Statoil has said this could change depending on market prices for gas.
What next? In NBI’s view, the NPD is likely to select a handful of Norwegian development stage projects to trial earlier EOR installations in a bid to improve yields. Now seems an apt time to begin negotiations with operators, given the fact that development costs as a whole have plummeted because of the industry depression. At first glance, it would seem Norwegian firms are more likely to opt for gas injection technology to realise synergies with other upstream projects. The NPD estimates that gas injection could unlock an additional 320-360 million cubic metres of oil equivalent (2-2.6 billion barrels) of reserves over its 27-field sample.
But that could change should gas prices recover, driving up the costs of supplying feedstock for gas injection projects.
Polymer appears more suited for realising sustained gains over a prolonged period, which might be ideal for newly launched projects. This would explain the NPD’s request for a polymer trial at Johan Sverdrup, as it would provide a sturdy testing ground to consult at other new-build projects. In any case, NPD’s willingness to push EOR – however gently or firmly – is good news for technology developers, equipment providers and chemical suppliers, who should watch development carefully.