Statoil takes on challenge of offshore heavy oil

May 1, 2011
Statoil is demonstrating its readiness to tackle the challenges posed by heavy oil fields, with the Peregrino project offshore Brazil due to come onstream soon, and Mariner and Bressay in UK waters at an earlier stage of development.
Grane experience provides base for future developments

Nick Terdre
Contributing Editor

Statoil is demonstrating its readiness to tackle the challenges posed by heavy oil fields, with the Peregrino project offshore Brazil due to come onstream soon, and Mariner and Bressay in UK waters at an earlier stage of development.

However, recent proposals in the UK government’s budget to increase petroleum taxes have for the time being stalled planning for Mariner and Bressay. Statoil said at the time it would “pause and reflect”, and asked for a meeting with the UK Treasury. The two fields were in a phase of concept selection, with Mariner expected to come onstream in 2016/17 and Bressay following a year or two behind. They are believed to have combined recoverable reserves of around 600 MMbbl, and each would require an investment of £3 billion ($4.88 billion) or more.

Field layout at Peregrino, a heavy oil field off Brazil which Statoil is about to bring on stream.

Whatever happens, the turn of events is a dramatic illustration of the essentially marginal nature of many heavy oil fields – although they may have substantial reserves, getting the crude out at a viable rate does not come easy.

But the time for developing heavy oil expertise has arrived, according to Karl Johnny Hersvik, senior VP for Research and Development in Statoil’s Technology, Projects and Drilling business area. Easy oil has largely been developed, but energy demand continues to grow, and among unconventional sources heavy oil represents an attractive alternative, with many such fields to be found around the world, he points out.

By developing a competitive edge in this area, Statoil can gain access to more such fields. The company has a strong culture of technology development, and Hersvik is confident it can meet the challenges. Another advantage for Statoil is that immersing itself in heavy oil helps strengthen its activities in the international arena, another of the company’s long-term aims, given its limited opportunities for growth on the Norwegian continental shelf.

As a rule of thumb, crude with a density of 20º API or less counts as heavy. As its name suggests, heavy oil is viscous and flows to the well less readily than lighter crude. In some cases heavy oil reservoirs are the result of biodegradation, where the lighter components of the original hydrocarbons have been consumed by bacteria. This is the case, for example, with some of the accumulations in Statoil’s Heidrun field in the Norwegian Sea.

It can also be found in younger formations such as the Tertiary, and therefore in shallower reservoirs – the Peregrino reservoir, for example, is only 2,300 m (7,546 ft) beneath the seabed. But according to Halvor Kjørholt and Lars Høier, who as chief researchers in Statoil’s research center in Trondheim are engaged in heavy oil research, this kind of crude is to be found in a variety of geological settings. Reservoir temperatures and pressures may vary from low to medium, though they are unlikely to be high. Gas content is low due to the absence of lighter components, but a heavy oil accumulation may also be found in combination with an overlying gas cap.

In addition to the viscosity of the oil, another key feature is the permeability of the reservoir rock, though again heavy oil is not associated with any particular degree of permeability. On the basis of these two properties a mobility ratio can be calculated. The worst case is the combination of high viscosity and low permeability, in which case the flow of the oil towards the wells will be so sluggish that natural depletion on its own will not yield viable productivity. In such reservoirs measures to aid the flow are likely to be required from day one.

Grane base case

Statoil cut its teeth in terms of heavy oil on the Grane field in the Norwegian sector – or rather Norsk Hydro, whose oil and gas division merged with Statoil in 2007. Grane, which contains recoverable reserves of around 700 MMbbl of crude with a density of 19º API, was brought onstream in 2003. It now produces 200,000 b/d through a PDQ platform. There are 27 production wells with horizontal reservoir sections.

Recovery has also been assisted with water and gas injected through separate wells, though gas injection – supplies were imported through a 50-km (31-mi) pipeline from the Heimdal Gas Center – came to an end last December. Oil production is expected to continue for some 25 years, and eventually the gas will also be produced and sold.

Statoil’s patented autonomous inflow control device (AICD), which is being piloted for use in heavy oil developments.

Post-Grane, the work on developing heavy oil technology has intensified, with a lot of money and man-hours being invested, says Hersvik. It has enabled the company to make $5-6/bbl more on its heavy oil than would otherwise have been the case, providing a good return on the investment.

Grane represented the first step on the ladder leading to ever more complex fields, Hersvik says. Peregrino, with 14º API crude, is the next step. Though the future for Mariner and Bressay is for the time being unclear, these were to follow: Mariner crude is around 14.5º API while parts of Bressay are as low as 11º API.

Improved oil recovery (IOR) is a key priority for Statoil, and many of the known measures are applicable to heavy oil fields, such as water and gas injection. In addition to IOR measures in the reservoir and well, Statoil has focused on processing issues, such as chemistry, sulfur numbers, and how to use other oils for blending.

Maintaining reservoir pressure through water injection, a well-understood and widely- used technology, is widely applied in heavy oil reservoirs. Offshore Norway gas injection may also be deployed, as on Grane. Gas, being miscible with oil, can provide a more efficient sweep of the reservoir, says Høier, while water, which is not, tends to leave more residual oil behind. Research is under way into additives to the injection water which will provide an even more effective sweep.

Another piece of technology which holds out substantial promise in heavy oil production is the autonomous inflow control device (AICD), which is installed as part of the well completion. Statoil has developed and patented its own version, but similar devices have also been produced by other companies.

The AICD, which works on a purely mechanical principle, reacts to viscosity by varying the size of its nozzle opening – the lower the viscosity of the fluid at the nozzle, the more the nozzle closes. So it facilitates the passing of high-viscosity heavy oil but chokes back in the presence of low-viscosity water and gas. The net effect is to boost the crude production while restricting that of water and gas. The device is currently undergoing pilot testing on the Norwegian continental shelf – its large-scale production effect needs to be studied and optimized for each case, Kjørholt says.

Drilling technologies are also relevant to heavy oil development. Horizontal drilling exposes a greater area of the reservoir to the well, while multilateral drilling enables two or more bores to be placed in the reservoir at a much reduced cost compared with single-bore wells. Here again Statoil can draw on an extensive experience including the pioneering use of multilateral wells with horizontal sections to produce the thin oil layers of Troll oil field in the Norwegian sector.

Within the well, downhole electric submersible pumps (ESPs) can be used to boost the upward flow of the wellstream – if the crude is extremely heavy, it may not even flow up the well without such assistance. Such pumps provide the additional benefit of drawing more crude from the reservoir into the well.

There is scope for improving the performance of ESPs, says Kjørholt, and in particular in prolonging the mean time to failure. Sooner or later such pumps are almost bound to fail. The problem can be mitigated by installing dual pumps, and bringing the second into operation when the first fails. But when both have gone, a time-consuming intervention exercise is called for, which involves pulling the tubing below which the pumps are installed. This is an especially costly operation in the case of subsea wells.


Statoil has been able to transfer its experience from Grane to Peregrino, an asset inherited through the merger with Hydro. After acquiring Anadarko’s 50% interest and becoming the operator in 2008, Statoil used this competence to increase the volume of recoverable reserves and the value of the asset, Hersvik says. In 2010, the company sold a 40% holding to the Chinese company Sinochem, which brought its own relevant experience in chemical extraction methods.

The heavy oil flow loop recently installed at Statoil’s Porsgrunn facility will become an important research tool.

Peregrino contains reserves of 300-600MMbbl. Reservoir temperature and pressure are relatively low at -78° C (-108° F) and 234 bar (3,394 psi) respectively. The gas-to-oil ratio is also low, at 13 cu m/cu m.

The field lies in water depths of 100-120 m (328-393 ft) in the Campos basin, 85 km (53 mi) from Rio de Janeiro. It has been developed with two wellhead platforms several kilometers apart delivering their output to an FPSO located about midway between them for processing and export. A total of 37 wells are planned, comprising 30 horizontal producers and seven water injectors. These are being drilled by rigs installed on each of the wellhead platforms. Peak production of 100,000 b/d will be maintained for seven-eight years.

The producers are fitted with ESPs. Produced water will be reinjected into the reservoir – a substantial volume of water is required to move the crude to the wells. Water-continuous transport will be required to get the crude to flow from the wellhead platform to the FPSO, Hersvik says. Separation will be facilitated by heating the liquids.

Statoil has drawn up a program for increased oil recovery with which it aims to raise recovery from 20% to 30%. It has identified a number of measures to be studied in this program, including polymer flooding, AICDs, multilateral drilling, and ESP improvements.

Dedicated facility

Statoil’s intent in developing heavy oil expertise is evident in its decision to set up a dedicated facility at its Porsgrunn research center in southern Norway. Currently being commissioned, this consists of a complex heavy oil flow loop, partly 2-in. (5-cm) and partly 3-in.(7.6-cm), which can handle a three-phase high-pressure fluid. At its heart is a three-phase separator packed with state-of-the-art separation technology such that the flow loop can be fed with “clean” water, oil, and gas, including live fluids from actual fields. The intention is to simulate the process whereby heavy oil is transported from upstream of the ESPs, through wellhead platforms, production manifolds, multiphase pipelines and a three-stage separation process.

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