Sticky business

Elaine Maslin

May 1, 2017

Offshore enhanced oil recovery pilots in the North Sea are paving the way towards helping to get more heavy oil out of the ground. Elaine Maslin reports.

Biopolymer containers on Heidrun’s deck. Photo from Statoil. 

Using polymerized water to flood fields and increase recovery rates is an established technology onshore. But, to date, polymer use for enhanced oil recovery (EOR) offshore has been limited to a handful of projects.

Since 2003, CNOOC has been using polymer from platforms on its heavy oil fields in Bohai Bay, offshore China. France’s Total was first to take polymers on a floating production, storage and offloading (FPSO) vessel deep offshore with its polymer EOR pilot on the Camelia field offshore Angola in 2010-11, with a skid-mounted injection pilot on the deck of the Dalia FPSO.

Since 2010, Chevron has been trialing polymer EOR on its Captain heavy oil field and, more recently, Statoil has been putting the technology to test on its Heidrun field, with plans for further pilots on other fields in coming years.

UPDATE: 20 October 2017, Chevron made FID on a polymer EOR project at Captain. Read more here.

While there are challenges associated with the technology, there’s a large prize in getting it right, particularly for heavy or viscous oil.

Ruben Schulkes, project manager for polymer flooding technology development, Statoil, says that the Norwegian major has one of the largest portfolios of offshore heavy oil, including the Peregrino field offshore Brazil, the Mariner field in the UK (first oil due in 2018), and Grane, offshore Norway.

Heavy oil production recovery rates are often low (less than 20% is not unusual), compared to the average 50% or up to 70% on Norway’s more usual lighter oil fields, Schulkes says. A breakthrough in increasing the recovery rate of this treacly stuff could be significant. Statoil’s Mariner field, for example, is estimated to contain 250 MMbbl – a 5% increase in recovery would be significant.

Currently, waterflood is used to sweep heavy oil fields, but alone it isn’t hugely effective because of a fingering effect caused by the water finding paths of least resistance through the reservoir and then sticking to them. This creates “water motorways,” leaving behind swathes of unswept reservoir. This happens because of the difference in viscosity between the oil and the water. For example, in the Mariner field the oil viscosity ranges between 67-506 centipoise (cP) oil, while water is 0.5-1cP (500cP is typical for syrup). Adding polymer to the water increases the water’s viscosity enabling it to more effectively sweep the reservoir.

But, what also makes polymer EOR interesting is that in combination with increasing recovery rates, it reduces water cut, Schulkes says. Statoil has clear ambitions to reduce the amount of CO2/bbl of oil produced and reducing the amount of produced water is a step towards reaching this ambition, he says.

Offshore challenges

Statoil’s Heidrun field. Photo from Statoil, by Øyvind Hagen. 

Using this technology offshore isn’t so easy. To get the polymer into the water, it has to be water soluble, Schulkes says. There are two types of water soluble polymer, biological and synthetic. The latter is already easily available in the large volumes needed, but, in Norway, synthetic polymer is classified a red chemical since the biodegradability is slower than acceptance criteria require. In the UK, it’s classed as yellow chemical, due to different rules. The classification as a red chemical in Norway implies that produced water containing even tiny traces of synthetic polymer cannot be release into the sea and has to be reinjected.

Biological polymer, meanwhile, is made by fungi and meets all the criteria to be a green chemical, including in Norway. It’s also more resistant to shear, meaning that a polymer molecule will not be drawn to pieces while entering the reservoir. A reduction in the length of the polymer reduces the viscosity of the polymer/water mixture and, therefore, the effectiveness. But, it’s not widely available in large quantities. And, because it’s biological, it can get eaten by bacteria in the reservoir, also reducing its viscosity. Closer well spacing onshore also makes polymer flood easier – it can be sent where it is needed faster, so less of it and lower injection rates are needed. Offshore, the well spacing is larger, which means that a larger reservoir volume has to be dealt with. This, in turn, requires higher pump rates, to get the polymer where it’s needed, leading to the shear degradation mentioned above. In addition, in an offshore setting, the polymers will be in the reservoir for a longer time, implying that thermal degradation of the polymer may become an issue that will also reduce its viscosity, Schulkes says.

There’s also a logistical question – to ship the polymer as powder and mix it onboard or to ship as an emulsion. “No one has done this full field offshore before,” Schulkes says. “There is uncertainty at what point it is worthwhile to start polymer flooding. In principle, it would be beneficial to start polymer from the start, to stop the water motorways occurring. But it’s not a mature technology. So, it is going to be a brownfield technology.”

Chevron’s Captain WPP.  Photo from Chevron.


Chevron’s Captain EOR project in the UK North Sea is the most advanced polymerized water injection project in the basin. It has been and is still a long-term project, but its full implementation could see significant volumes recovered from the field and subsequently others.

Chevron has been working on the project for 10 years. Earlier this year, it started its fourth pilot project on the field to further refine its future polymer EOR plans for Captain. The plan looks likely to be a staged roll-out, starting with up to six long-reach horizontal injection well, using synthetic polymer, followed by full-field expansion.

Discovered in 1977, in Block 13/22a, the billion-barrel Captain field achieved first production in March 1997 thanks to technology developments in horizontal drilling and downhole pumps. Production peaked at 100,000 b/d and is now around 26,500 b/d.

For many years, the field has been under waterflood, which means a lot of effort is put into water production and treatment (some 300,000 b/d of water are produced). However, there is still a lot of bypassed oil, because of the way waterflood results in a “coning” effect in the reservoir.

Its reservoir conditions – pressure, temperature, type of rock and oil properties – make it an attractive candidate for polymerized water injection.

“If we can introduce polymerized water, we can exploit the mobility ratios between the oil and the polymer,” says Richard Hinkley, general manager of Projects and Future Growth at Chevron Upstream Europe. “Instead of coning, we are bull heading a bank [of polymerized water] towards the producing wells.” This will also help reduce the water cut produced and, rather than extending field life, it could mean recovery is maximized earlier instead.

The timing is important, Hinkley says. “There is a tradeoff between not leaving it too late or not going too early when you still have an effective waterflood,” he says. “We are producing around 26,500 b/d. Now is the time to focus on optimizing recovery and implementing EOR.”

To assess the potential for polymer EOR and develop its approach, Chevron started with a screening process, then lab trials, before going on to complete three pilot projects. Each pilot has targeted specific uncertainties, Hinkley says. The first, an injector-producer pair, in 2010, ran for 30 months and was to see if the polymer enhanced recovery process worked at Captain.

The second, an injector producing to four wells, drilled in 2013, and running for 18 months, was to see if polymer worked on a typical producer-injector configuration for what the asset needed. The third pilot, started in 2016, and running for six months, was back to an injector-producer pair, and was to enhance understanding of the logistics and supply chain requirements involved in polymer EOR. Building upon this, in Q1 2017, Chevron started injection on a fourth well, which is ongoing and will further expand the learnings from earlier pilots. “As we are going, we are fine-tuning the polymer and learning. Each pilot informs the next phase and helps us progress,” Hinkley says.

Designer polymer

A cavitron mixer (a mixing unit for polymer and water). Photo from Statoil. 

Crucial to the work has been designing a polymer for the specific conditions at Captain. As well as developing the right polymer, Chevron is also keen to develop a strong supply chain for polymer.

“One of the key lessons is that it takes a lot longer than you think,” Hinkley says. “There are no short-cuts. We have been 10 years from initial screening and as a result we are on pilot number four. We have demonstrated the polymer works. We have had to fine tune the polymer for the specific reservoir conditions at Captain. Now we are at the point where we are looking at long-term staging the development, going from a pilot to six wells in the platform area [Area A] of the field. We are looking to make a decision to go with that this year. If that is a success, we would like to go to full field expansion.”

Polymer injection facilities were installed as part of the original development, but some brownfield work will be needed to accommodate the six-well project. This will include bulk provision of the polymer and modification work on the Captain wellhead protector platform (WPP), including new polymer mixing equipment to expand processing capacity.

A full field expansion would require a bridge-linked platform. Chevron had issued an invitation to tender for a new facility to hold the polymer injection equipment, but this was then put aside in favor of the staged approach.

Chevron’s learnings from the project to date, along with lessons learned from others, are to be included in a project led by the Oil and Gas Authority to create a “starter-pack” for those looking to try polymer EOR. “This will help others understand if EOR is suitable for their reservoirs and what expectation they can have towards implementation,” Hinkley says, adding that Chevron’s experience and lessons learned will also be incorporated.

Up for the challenge

Meanwhile, Statoil has also been putting polymers to the test – synthetic and biopolymers – through a series of pilots.

Statoil ran its first pilot polymer EOR project, using biopolymer supplied by partner Wintershall, part of Germany’s BASF, on the Heidrun field, in the Norwegian Sea, offshore Norway in Q3 2016. The field has been producing since 1995, from a floating tension leg platform with a concrete hull. A single well was used, for injection and back production.

Several EOR tests have been performed over the past years (single well tests of synthetic polymer and low saline water injection). The single well test of biopolymer consisted of injecting biopolymer, biocide and water tracer and producing this back after 39 days shut-in.

“From analysis of samples taken during injection and back production, we were able to conclude on degradation of the biopolymer, the injectivity development and on the impact polymerized water has on topside water treatment facility,” Schulkes says.

One of the main aims at Heidrun was to test if there would be no biodegradation – due to bacteria eating the biopolymer – in the near well area and to see how much biocide would have to be injected to achieve this. It was also set up to test if there was shear degradation in the injection phase and to see what impact back production of the polymer would have on the production system, particularly the water processing system.

“We found there was no biodegradation of the polymer in the near well zone,” Schulkes says. “That was a significant result and means the amount of biocide injected was sufficient to protect the polymer. The test also verified we didn’t get a significant amount of shear degradation during injection and the results also showed we had good injectivity into the reservoir.”

The sampling work helped understand what type of bacteria are in the reservoir, which would be important for future projects, as this determines what biocide is used. But, this would be something that would need managing over time, as bacteria can adapt to their environment, which could mean having to change out biocides periodically, Schulkes suggests.

The project was also a useful exercise in terms of experience for Statoil in handling polymer, i.e. the logistics involved, Schulkes says. Nevertheless, Statoil isn’t looking to carry out more polymer injection on Heidrun. Instead, it is planning another pilot on the Peregrino heavy oil field in the Campos Basin offshore Brazil.

Polymerizing Peregrino

Peregrino, 85km offshore Rio de Janerio, contains some 300-600 MMbo recoverable. Production started in 2011, via two fixed platforms and a floating production vessel. At 14° API gravity, it is the second heaviest oil to be produced in Brazil.

Statoil is planning to test synthetic polymer on Peregrino, with a two-well – injector-producer – pilot. “The business case for this field is more obvious,” Schulkes says. The pilot is due to start later this year and is expected to run for a year. The aim here is to prove polymer can be injected and sustain sufficient viscosity when it is injected. “Synthetic polymer is more easily shear degraded than biopolymer,” Schulkes says. “We will use the pilot to prove that the technology works for polymer flooding in viscous reservoirs.”

The biggest issue is the number of uncertainties around using this technology, which Statoil hopes the Peregrino pilot will help to reduce. “With successful results from Peregrino, we will re-evaluate the business case for polymer flooding on Peregrino and we will also be able to be more certain about the upside for Mariner (in the UK North Sea),” he says. A pilot on Mariner could start around 2021. It very much depends on the Peregrino pilot and the oil price as this is not a cheap technology, Schulkes says.

A polymer EOR trial is also being considered for Johan Sverdrup, in the Norwegian North Sea, although it’s a less obvious candidate for this technology because it has a lighter oil. Despite this, a two-well pilot within three years of production start-up was included in the agreed plan for development and operation for the field. “One of the challenges at Johan Sverdrup is the recovery rate is already estimated at 70%, without polymer flooding, because the oil has a relatively low viscosity and the reservoir properties are good,” Schulkes says.

“Each pilot gives you a more robust business case, but given that each reservoir is different we would still be taking a step-by-step approach,” he adds.

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