EOR: Recovery Time

But with field’s depletion rates fast-increasing and some of the crude trapped in difficult-to-reach reserves, the region’s main players are increasingly looking at enhanced oil recovery to help achieve its targets.

One type of EOR technique that is growing in popularity is polymer water flooding. The first EOR pilot was run as far back as the 1980s with the country of choice being Oman.

The Sultanate has one of the most challenging terrains in the Middle East, limiting oil extraction to as little as 10%. But after a pilot was launched on Oman’s Marmul field, the recovery rate was projected to reach upwards of 30%.

In 2012, Marmul produced the once unimaginable figure of 75,000 barrels of oil per day. Since then, thanks to enhanced oil recovery, Oman has managed to add billions of barrels of oil to its production from previously thought unrecoverable reserves.

The Sultanate not only managed to reverse one of its worst production declines since 2007, but has recently outlined plans to add a further 600,000 barrels per day (bpd) to its exisiting production by 2019 using enhanced oil recovery methods.

According to a recent report by Manaarco consultancy, polymer water flood holds a promising potential for oil and gas operators, and while its effectiveness can vary according to the formation characteristics, it can help achieve a recovery rate of up to 50%.

It was with this ambitious figure in mind that Wintershall and its parent company BASF decided to develop a special kind of polymer that can not only significantly improve recovery but is designed to do so in a completely harmless way for the environment.

When work on the technology first began, Wintershall said it decided to ‘copy nature’, as nature is where answers to technical challenges can often be found. Then it came up with the idea of a revolutionary type of biopolymer based on a simple fungus that holds the secret to its enhanced extraction properties.

“Schizophyllum commune, the split gill fungus, is one of the world’s most widespread fungi (its scientific name). It grows on softwood and hardwood. Schizophyllan, the biopolymer that can be extracted from the fungus, exhibits – even in low concentrations – a strong thickening effect that remains stable at up to 140 degrees celsius and in high salt concentrations,” said Wintershall’s Martin Bremeier, technology manager for the Middle East.

When injected inside the well, the gelatine-like substance thickens the water of the deposit to increase output. The water then forces more oil out of the deposit and to the surface because it no longer flows past the valuable raw material as much or as easily as before.

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“The thickening effect in injection water effectuates a higher viscosity of the displacing fluid, which can be close or equal to the viscosity of the oil. The more favourable oil displacement process results in higher oil recoveries.

“High temperatures and high salinity brines are the two specific challenges of fields in the Middle East. Schizophyllan is specifically being used to address these challenges,” says Bremeier.

He adds that both polymer flooding and steam flooding, a thermal EOR method based on steam injection, rather than water injection, have been successfully applied in the region, with the Abu Dhabi National Oil Company being the first company in the Middle East to run tests on Wintershall’s EOR technology.

“The studies are ongoing and will be followed by decisions on pilot field tests,” Bremeier says.

However, while polymer water flooding is believed to hold immense potential for this region, its tight carbonate formations make it very difficult to implement, accoridng to Adriano Gentilucci, commercial director for India, Middle East and Africa at Dow Oil, Gas & Mining.

“Reservoir conditions – such as natural fractures in the reservoir rock or resistance from heavier or more viscous oils – can cause traditional water flooding to be less effective in injection operations,” said Gentilucci.

“High temperature inside the reservoir can lead to the degradation of many traditional chemicals used in EOR, while high connate water salt concentration causes to issues of compatibility with EOR chemicals, he added.
Bremeier concedes that the structure of carbon formations can often be the main obstacle to EOR projects in the region.

“Rock surfaces of carbonates have a tendency to prefer the contact to oil in the wetting phase whereas rock surfaces of sandstone reservoirs prefer contact to water. This makes EOR applications more difficult and requires advanced physical and chemical research to enhance the oil recovery process,” he said.

In addition, EOR programmes almost always require a displacement fluid – most often water but also supercritical carbon dioxide. However, much of the region suffers from scarcity of fresh water and projects are required to incorporate water treatment for injection and produced water treatment, making the idea of EOR even less appealing.

Adding to the challenges of EOR in the region is the lower oil price environment. With the oil price showing no signs to recover any time soon, companies have been forced to cut down their spending, particularly on projects that don’t have an immediate return on investment, which is the very category enhanced oil recovery falls into.

“The greatest challenge facing the enhanced oil recovery market is the drop in oil prices. EOR investments are becoming less commercially attractive in comparison to other low-risk investments that can generate positive cash flow – more quickly.

“Today, oil and gas companies are becoming more and more cash constrained. EOR economics have traditionally suffered from high costs associated with energy, carbon dioxide, and chemicals supply.

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“This, in turn, has meant that EOR investments have broadly reflected oil price trends. We have observed that in the USA, EOR projects more than halved from the late 1980s to the mid-1990s when oil prices dropped. Our expectation is that, over the next year, the technology will see a decline in new EOR investment,” said Shelly Trench, principal at Boston Consultancy Group.

Across the globe, there are several issues impacting the development of EOR technologies, according to Trench.
“EOR technologies are relatively young, while the EOR cycle is long and investors typically realise financial returns after six to ten years,” she explained.

“From lab tests to full field application, EOR operations can take between seven and ten years; and this timeframe often involves several redesigns and testing phases intended to ease the implementation process. As part of this process, pilot testing can take between two and four years. In addition, to see a visible impact on production, it can take another three to four years,” Trench explained.

“The reality is, despite all this time and investment, EOR projects are uncertain until testing and piloting projects have been successfully completed. That is why it is difficult to estimate potential returns until later.”

Therefore, it should come as no surprise if some operators put EOR investment on hold. However, experts are warning that in doing so producers are risking not being abe to meet demand once it starts to climb back up.

“In the context of the current pricing environment, it makes economic sense to extend the life of existing assets when looking at a per barrel basis. The fact is, large up-front investments pose a major hurdle to project execution – which ultimately impacts the NPV of assets,” said Trench.

To succeed in the long run, EOR will have to undergo a fundamental shift and make significant changes to its business and operating model. Speaking at a special EOR workshop in Ravenna, Italy, Shell’s Diederik van Batenburg made an excellent point.

He said that rather that treating EOR as a seperate business stream, companies should make it an integrated capability, linked to existing facilities but also in-house research, laboratories and leveraging the business’ various geographic operations to share experience and learnings.

Similarly, Trench suggest that the ideal operating model might be one that provides research and development and operations teams with freedom from the constraints of traditional exploration and production models.

“Successful EOR projects require excellence across multiple domains. This typically demands deep collaboration between R&D, operational teams, service companies, and other stakeholders during pilot projects,” she said.

“The USA’s unconventional oil and gas sector is a perfect example of this. It is a situation where they have shifted away from the normal E&P business model and now implement active change management strategies.

In order to avoid these high up-front costs in the future, operators should incorporate EOR technologies during the early stages of an asset’s lifecycle, explains Trench, giving BP as a leading example. The IOC has pioneered EOR in the North Sea with its LoSal technology and now plans to incorporate similar technology elsewhere before substantial depletion occurs.

Agreeing with Trench, Gentilucci said: “In some cases it makes economic sense to implement these schemes earlier in the asset lifecycle, in others – particularly offshore – it allows the operator to plan for future investment and make prudent decisions on critical items like platform space. With less than 30% of the original oil in place, recovered through primary production methods, we agree that up-front development of secondary and tertiary schemes during the production planning process is necessary.”

“The GCC has a unique opportunity to implement such schemes due to the longer term nature of strategy development that the National Oil Companies consistently show,” he added.