Oil & Gas - Maximising Recovery Programme (formerly SHARP) IOR Views

Picture for UKCS Heavy Oil (Colin Cranfield, Energy Resources Development Unit, DTI)

There are various definitions for heavy oil. As far as the UKCS is concerned, it is any oil whose viscosity causes production difficulties either sub-surface or at surface. Colin defined heavy oil for the UKCS as being between 10º and 22º API and viscosity greater than 5 cp.

The UKCS had 2.2 billion barrels STOOIP on production, 4.3 billion barrels undeveloped with another 2 to 3 billion barrels yet to find; giving a grand total of about 10 billion barrels.  The corresponding reserves would be of the order 250 million to 1 billion barrels. This represents just a few per cent of the total UKCS reserves, but was still considered significant and could equate to 100,000 to 200,000 b/d over a 10-15 year period.

The heavy oil characteristics were due to biodegradation either during migration or in situ. This reduced the proportion of light ends, leaving a higher concentration of heavy ends, asphaltenes and up-concentrated metals. The oil is typically found in shallow, unconsolidated, high permeability reservoirs. It had generally high acid numbers but relatively low sulphur.

All the oil that has been developed to date on UKCS was less than 200 cp, while most that remains has viscosity in the range greater than 200 cp but less than about 2000 cp. There was relatively little discovered heavy oil with viscosity greater than 2000 cp.

Figure 1: Geological Setting of Quad 9, Northern North Sea – Location of Many UKCS Heavy Oil Fields

There was little worldwide experience of developing heavy oil in any significant offshore water depth, but the North Sea industry had successfully progressed the development of increasingly heavy oil reservoirs during the 1990s. It was noted that the Captain Field has been referred to elsewhere as the industry benchmark for offshore heavy oil development.

Colin referred to a number of the challenges involved in heavy oil production offshore, particularly the difficulties in obtaining oil samples. Conventional DSTs had often been unsuccessful; drilling mud had a cooling effect while downhole emulsions would have sometimes hampered flow. Nitrogen-lift had often induced sand production. In view of resulting uncertainties on oil viscosity in particular, it was challenging to move from appraisal to development. Closer-spaced wells and lower rates would mitigate some of those uncertainties.

Some of the DTI and industry activities aimed at encouraging development were:

• Promote licences
• Marketing studies
• Sub-surface evaluations
• Seminars
• Provision of a heavy oil website (http://heavyoil.senergyltd.com)
• Participation in an Upgrader evaluation. This had delivered the conclusion that heavy oils could be converted into diesel, a more marketable product.

Various possible techniques for sub-surface recovery were briefly discussed. It was concluded that water flooding was the likely approach for oils with less than 200 cp. Waterflooding might also be the most appropriate technique up to viscosities approaching 1000 cp., but hot water injection would tend to be more applicable at these higher viscosities. Studies had indicated that hot water injection could double recovery and improve project economics, although this was dependent on the specific viscosity and reservoir characteristics. Work was nevertheless still needed to improve the underlying base development economics.

The way forward would likely involve novel well solutions to give effective high well density, viscosity reduction at producers for instance via heated downhole pump drive fluid or recycled diluents where appropriate, more flexible process export facilities, and novel commercial solutions.

Marketing solutions to avoid a significant discount on price against lighter oil would be an Upgrader, possibly phased with a hydro-cracker installed in a second phase, or a proposed “MSAR” process to produce a “clean” fuel for power generation.

He concluded that innovative, integrated solutions were required, with the long-term aim to develop 10º to 15º API fields.

For further information from DTI, the following contacts were given:

• Upstream - Colin Cranfield (colin.cranfield@dti.gsi.gov.uk) or Malcolm Pye (malcolm.pye@dti.gsi.gov.uk)
• Downstream- Peter Christie (peter.christie@dti.gsi.gov.uk)

In answer to a question he thought that emissions would not be a show-stopper but would require further study.

Heavy Oil - an Upstream/Downstream Solution (Steve Jenkins, Nautical Petroleum)

Steve said that many of the discovered heavy oil fields had complex structures, viscosity variation within the reservoir, and often thin oil columns. There is a high level of uncertainty caused by the data  issues which causes consequent uncertainty in how the fields would produce in development which in turn affect development decisions. He gave various examples of the viscosity and thickness in different heavy oil discoveries.

Development solutions need to be positive and innovative to deal with the problems. As an example, his company had found that new information on reservoir definition could be obtained from reprocessing seismic. He also said there were opportunities to glean additional information from 2D site survey seismic which gave good resolution at shallow depths, was cheap to acquire and was again useful for helping to define reservoir architecture although obviously not the quality of 3D seismic.

For development, Steve considered that wells would need to be drilled one at a time and tested extensively to establish performance. Development should start in a sweet spot and move out in order to mitigate risk. Surprises should be expected and these are likely to alter the future development.  Horizontal wells would be needed, drilled from a semi-sub. Process facilities would need to handle high watercuts and be designed for easy installation on a semi-sub.

Turning to marketing issues, Steve noted that typical North Sea oil heavy oil was 9-15º API, with 2-9 TAN which is bad news since it significantly affects the marketability. But there was some good news in that the sulphur content is relatively low.  There was currently limited refinery capacity which would handle this type of oil. In essence there was more heavy oil than the refinery capacity for it. It would probably need to be sold as fuel oil with a discount of $3-20bbl on its value. He referred to Upgrader technology which Steve said would cost of the order of $800 million for 100,000 bopd capacity and had a long  lead time such that it could not be ready before 2009. Relying on that would give little incentive to seek new heavy oil reserves.

Steve then discussed an alternative such that the oil would first be split into heavier and lighter components. An example oil had about 70 per cent which could be split out fairly readily as a lighter component which could be sold into existing markets. The 30 per cent remaining residue could then be processed into power plant feedstock by the “MSAR” technique.  This process involves grinding and mixing with water and surfactant to create an emulsion which can be used as a fuel for power generation. The process uses existing technology, has a small footprint and makes a fuel which is environmentally better than coal. A unit for 12,000 bopd could be built for $10 million with 9 months delivery.

In summary, Steve concluded that better reservoir definition was required, phased development, and promotion of the MSAR technology.

There was some debate with Howard Simons of M W Kellogg about the feasibility of this approach for marketing UKCS heavy oil. The debate was largely about whether the acids would be eliminated from the lighter ends split prior to the MSAR process. Time restricted this discussion although there was further discussion on the marketing question in the panel session following the presentations.

Captain: Heavy Oil Challenges (Gert de Jonge, Chevron)

Gert went over the history of Captain starting with its discovery in 1977, followed by an extensive appraisal programme between 1989 and 1995. Appraisal had included 20 appraisal wells. There was also a 90 day EWT to prove up the development concept which is entirely with pumped horizontal wells.

The field is more complex than originally thought. The oil viscosity also varies, from about 40 cp to about 150 cp.  Cumulative recovery is about 150 mmbbls after 8 years production from a STOOIP of 900-950 mmbbls. The field is still on plateau at about 75 mbopd.

However, there have been historical and ongoing challenges to achieving this.  Challenges have included:

• Extending submersible pump life. Early expected ESP life had been about 3 years, but this had now been shown to be 5 years on a P50 basis. Experience with HSPs used in Area B was considered generally very satisfactory.
• The reliability of facilities, including separation efficiency.
• Achieving water injection targets. The policy was for voidage replacement. While this was now largely being achieved on a field basis, the areal distribution still needed attention.
• Dealing with the increasing water production and its disposal.
• The reservoir complexity. Pilot wells have been used to help define the geology and to place the final well trajectories. Production logging was also important.
• Well trajectories have been increasingly complex, first in achieving long lengths, but more recently with complex paths with severe doglegs - for instance draining beneath the platform. Avoiding collision with other wells was also an issue.
• Sand production, where there had been problems with early pre-packed screens. Gravel packs have been implemented successfully, but other approaches were now being reviewed to reduce costs while at the same time achieving reliability in sand control.
• Making the well design cheaper. Originally the intention had been for wells to last as long as the field, but it was thought cheaper wells could be better even if they had a shorter life as this provided an option to have more sidetracks, which in turn increased the overall field recovery factor.
• Environmental issues of flaring and chemicals disposal.

Gert concluded that there are also brown field issues on heavy oil fields in addition to the problems associated with initial development. These posed ongoing challenges.

Panel Session (Howard Simons, M W Kellogg, Peter Blom, Mare Corp, Wayne Strachan, Ingen-Ideas)

There were various questions and comments made about the projected Upgraders referred to earlier.

Howard Simons firmly predicted they would be built in the coming years. Howard presented the view that the price differential between light and heavy acidic oil would increase as oil prices become greater and the demand for light crude increases. This would increase the incentive for Upgraders. They are demanded by market-pull with the increasing use of diesel in Europe.  Upgraders are however very expensive. Various figures were suggested ranging from $800 million to in excess of $4 billion. It was, however, stated that although they are expensive, the economics become attractive at oil prices above $23 per barrel.

Peter Christie of DTI, commenting from the audience, noted that the world refining capacity would likely fall below demand in the foreseeable future. Additionally there would be increasing pressure on lighter oil crude supplies over the next 10 to 20 years. There was therefore a need for new refining investment which should cater for heavy acidic oil.

Howard Simons projected that an Upgrader would be built by 2009 depending upon circumstances, or late 2010 at the latest. In fact, there could be three such Upgraders of perhaps 50,000 to 100,000 barrels per day capacity each.

Colin Cranfied advised that at present there was only one heavy oil field, Skipper, with an imminent development proposal, although there were nine other Promote licensees who should be actively developing plans. Nonetheless, there was nothing firm about North Sea heavy oil development.

However, it was considered the Upgraders would not be dependent on decisions about the North Sea because of the market pull. Other world oil supplies could provide the feedstock. Supply was not considered an issue. But the Upgraders would be beneficial to North Sea heavy oil.

It was noted that building the Upgraders would take time. Another issue noted by several speakers was the availability of skilled people to build them, with potential competition from naval and other construction. The question of skilled labour was being addressed and it was thought would be solved, but it was far from trivial.

There was also some discussion about shorter-term solutions. There was further discussion on the MSAR process discussed earlier by Steve Jenkins. There was agreement that it would be preferable to have smaller units such as MSAR in the shorter term, but there remained some questions about how well such alternative approaches would work. Wayne Strachan advised that Ingen had several alternative potential marketing arrangements for their Skipper field.

One other question about heavy oil was about the disposal of sulphur. The pharmaceutical industry use sulphur, but the market for sulphur was probably limited. Disposal may involve landfill, possibly abandoned coalmines.

There was also a brief discussion on the sub-surface side.

One question asked was whether the same level of appraisal as had occurred on Captain would be appropriate in the future. Gert de Jonge noted that Captain had been developed some time ago when there was even less experience about offshore development of such fields. There were issues with long horizontal wells instead of the large number of vertical wells traditionally used for heavy oil fields onshore, questions on the down hole pumping of oil and many other questions about the feasibility. He felt that today there would probably be much less appraisal, but did note that early development decisions were extremely important and these decisions were data dependent.

There was also a brief discussion about hot water flooding. Studies by RML on behalf of the DTI had indicated there could be a very substantial improvement in recovery with more viscous oil and other suitable reservoir characteristics, but the cost of heating the water was very high. Nonetheless it could still improve project economics in some cases, but the fundamental problem was the base development cost. The general view was that hot water flooding was far from a no-brainer either way. It would require further analysis in specific cases.