OilVoice

It's because somebody knows something about it that we can't talk about physics.
It's the things that nobody knows anything about we can discuss.
Richard Feynman
US educator & physicist (1918 - 1988)

Heavy Oil is an important global resource and worldwide reserves may be comparable to those of conventional oil. In the UK, it’s less significant currently - UKCS Heavy Oil production only amounts to 150,000 barrels per day, or 10% of total UK oil production - but could become more so over the next couple of decades.

At the 2006 DEVEX Conference in Aberdeen, the UK’s DTI offered the view that the UKCS had some 7-10 billion barrels of Heavy Oil in place, corresponding to reserves of 0.25-1 billion barrels (see http://heavyoil.senergyltd.com/events.asp?page=devex_2006 for a conference summary and a full set of downloads).
In this article, I examine what UKCS Heavy Oil might be all about and, equally importantly, what it is not.

What is Heavy Oil?

The USGS defines Heavy Oil as a type of crude oil characterized by its asphaltic, dense, viscous nature and its asphaltene content. It also contains impurities such as waxes and carbon residue that must be removed before refining.

The American Petroleum Institute’s “API gravity” is a standard measure of the ‘heaviness’ of oils and this together with the viscosity (normally measured in centipoise, cP) provides definitions of four categories of crude oil:

1. Light Oil: is also known as “conventional oil”, with an API gravity of at least 22O and a viscosity less than 100cP.
2. Heavy Oil: described as above, the upper API gravity limit being set at 22O and a viscosity of less than 100cP.
3. Extra-Heavy Oil: like Heavy Oil but with an API gravity of less than 10O.
4. Natural Bitumen: also known as “oil sands”, is like Heavy Oil but even more dense and viscous with a viscosity greater than say 10,000cP.

Light or “conventional oils” flow naturally and can be pumped without being heated or diluted.
Heavy Oils typically do not offer significant natural recovery through a well by ordinary production methods but require usually some form of heating and/or dilution before they will flow into a well bore or through a pipeline.
Natural Bitumens – or “oil sands” – are not producible by conventional oil field methods. Shell, for example, is investing more than $20bn in its Canadian “oil sands” operations but as a Times article (www.thetimesonline.co.uk; July 27th, 2007) pointed out, Shell regard it as a mining and refining operation. Likewise, Marathon Oil has agreed to acquire Canada’s Western Oil Sands Inc. for $5.56bn (plus assumed debt) to access the Athabasca Oil Sands Project, an essentially mining operation (http://realtimenews.slb.com/news/story.cfm?storyid=643477).

The DTI’s working definition for UKCS Heavy Oil is oil with API gravity < 220 and reservoir viscosity > 5 cP. Exhibit 1 shows the various fields and discoveries that they have identified. Before considering the Heavy Oil fields that have been in production in the North Sea, for example Gannet E, Captain and Grane (in the NOCS), it’s worth considering how Heavy Oil is produced elsewhere in the world, especially in North America where the history is long and informative.

Heavy Oil Production in North America

Over 35 billion barrels of Heavy Oil are defined as technically recoverable in North America, with the USGS estimating almost 8 billion barrels available in the L48 (dominated by onshore California) and at least 7 billion barrels on the North Slope of Alaska.

The most common approach to producing Heavy Oil has been to heat the reservoir, usually by injecting steam, generated from banks of nearby steam-drives (each the size of a house), into very closely spaced wells (a few hundred metres apart at most). Such thermal recovery is at once very costly and very energy inefficient, as considerable energy is required to generate the steam in the first place.

A technological advance has been achieved with a new thermal technique known as steam-assisted gravity drainage in which pairs of horizontal wells are drilled into the producing zone, one about five metres above the other. When steam is introduced into the upper well and heats the reservoir and its fluid, gravity pushes the warm oil towards the lower, producing, well.

A completely different technique (in use in Alaska) is to inject into the reservoir slugs of water alternating with gas (known as WAG). The gas acts as a solvent to reduce viscosity and the water helps to drive the less viscous oil towards the producing wells. Elsewhere, a variety of other solvents, including lighter crude, have been used, not especially successfully.

In addition, these various recovery processes require careful monitoring and control, and a variety of down-hole surveillance and control equipment is now available to help optimize production and improve reliability. Again, this is expensive.

Heavy Oil is somewhat difficult to transport and refine and thus tends to sell at a discount to conventional light oil. One way of thinking about it is as being rather similar to a natural gas deposit that is a long way from infrastructure and that therefore the producers must think about the whole value chain, including processing the Heavy Oil into a product that the market actually wants. Thus a financial characteristic is of relatively heavy capital investment up front and long pay back times.

That said, in the relatively benign surroundings of Kern County, California, there has been Heavy Oil production for more than 100 years and four large fields have produced more than 1 billion barrels. Flying over say Aera Energy’s properties in California, one can see the very close well spacing and small “villages” of equipment that have produced such successes.

In an erudite review of Heavy Oil recovery in Alaskan Arctic Fields (www.WorldOil.com; August 2006), Perry Fischer highlighted:

1. The cooperation in the North Slope Viscous Team, between ConocoPhillips and BP, with some ExxonMobil participation
2. The key role of extended reach, multilateral and tri-lateral wells yielding production rates of 2000-3000 bopd, up to 10 times that of vertical wells – see Exhibit 2.
3. That the reservoir sands are typically unconsolidated and so sand production was and is a major issue, with a new sand management plan now in action involving extra facilities and extra costs for recovering, moving, processing and disposing the produced sands.
4. The use of ESPs to produce the Heavy Oil to the surface, alternatively gas-lift.
5. The various recovery enhancement methods, such as low salinity waterflooding; gas or WAG flooding. There is considerable optimism about WAG, especially as steam-floods are impractical and inappropriate on the North Slope.
6. This cooperative combination offers the possibility of recovering up to 4 billion additional barrels in the North Slope: even then, the heaviest of the oils must wait for new, as yet undeveloped technologies, to come along.

Thus imaginative engineers and innovative technologies are beginning to offer the possibility of recovery factors up to 30% for onshore Heavy Oil fields. What does this imply for the North Sea?

Heavy Oil Production in the North Sea

There is existing, reasonably well documented, Heavy Oil production in the North Sea from Captain (Chevron), Gannet East (Shell) and Grane (Hydro). What lessons can be learned from the experiences of these three companies?

Gannet East was discovered in 1982 and was deemed uneconomical at the time. In response to the higher oil prices of the mid 1990’s, development planning began in 1996 and first production was in January 1998. The key ‘breakthrough’ was the use of ESPs. The field’s main features are:
• Heavy Oil in the Forties Formation, a consolidated reservoir: 144 million barrels in place.
• Strong aquifer, so natural drive only – no injection or pressure support of any kind.
• One initial well, horizontal and producing 17,000 bopd; water breakthrough by July 1998.
• Two additional horizontal wells drilled in 2000 and 2001.
• Surveillance, using both 4D seismic and PLTs, and fluid sampling, using PVTs, has been a major focus.
• Depending on future developments, recovery factors are envisaged to be 29-35%.

Captain is a rather different beast that went on production in early March 1997. The field’s main features are:
• Heavy Oil and some gas in 4 formations, with probably just less than 1 billion barrels in place.
• Significant sand production.
• Insignificant natural drive: major water injection, envisaged at up to 400,000 bwpd.
• Many complex wells, with extensive use of both ESPs and HSPs.
• Surveillance a key, with PLTs to the fore.
• Production circa 70,000 bopd: just less than 150 million barrels produced by the end of 2004.

Grane is an especially useful North Sea example to look at, as Hydro have been very open about their approach to the field and going onto production as late as 2003, it has benefited from much new technology. The field’s main features are:
• Heavy Oil in the Heimdal Formation, a consolidated reservoir: probably just over 1.5 billion barrels in place.
• No natural drive: gas imported for immiscible gas injection to provide the pressure to move the Heavy Oil.
• Horizontal wells envisaged from the outset; nowadays, horizontal wells with multilaterals.
• Surveillance is a key; a major focus on seismic, both 4D and permanent monitoring from the seabed.
• Peak production (March 2006) of 243,000 bopd: a recovery factor of 55% is foreseen compared to a maximum of 35-40% that could be anticipated from a waterflood (see above).
Hydro’s experiences with the Troll and Oseberg fields, admittedly not Heavy Oil fields themselves, have nonetheless been key to their learning how to deploy modern technology.

Other North Sea Heavy Oil fields with significant production history include Alba (developed by Chevron) and Harding (developed by BP): experiences with them are similar to aspects of the above three fields.

Future North Sea Heavy Oil Developments

So what can we learn from the history of Heavy Oil production in California, Alaska and the North Sea? Key aspects seem to be:

1. Thermally-aided recovery mechanisms such as conventional steamfloods or steam assisted gravity drainage seem unlikely. They demand significant surface facilities, unlikely to be available offshore, and are relatively energy inefficient and expensive.
2. Waterfloods are possible but tend to lead to lower recovery factors than some of the gas-aided alternatives.
3. Immiscible gas injection or WAG schemes offer a boost to recovery factors and have already been tested in the North Sea – see Grane above and note also that BP introduced a WAG scheme in the Ula field (conventional Light Oil) as long ago as the end of the 1990’s.
4. The tight patterns of vertical wells deployed in for example onshore California will be impractical, inefficient and far too expensive for the offshore environment, just as they are on the North Slope of Alaska. Extended reach, horizontal, multilateral and tri-lateral wells will be the norm.
5. ESPs and HSPs, with which there is plenty of experience in the North Sea, will also be normal.
6. Sand management will be critical when dealing with unconsolidated reservoirs; again, there is plenty of experience elsewhere in the North Sea.
7. Surveillance is critical – especially 4D seismic and/or permanent sea-bed monitoring, PLTs and PVTs.
8. The experience, the “Know How”, from having done this elsewhere, will be crucial.

So, this all feels very “do-able” for the bigger, experienced companies and one could argue that the DTI’s estimate of 0.25-1 billion barrels reserves from 7-10 billion barrels in place could be quite conservative – why wouldn’t say 2 billion barrels be expected? The cornucopia of skills and technologies identified above may well be expensive to deploy but surely at $50+ per barrel oil prices, North Sea Heavy Oil’s “day” has come!

And yet!

One of the next, logical, developments in the North Sea would be that of the Mariner discovery, drilled as early as 1981, located on the East Shetland Platform, north of the Viking Graben, in Block 9/11a – operated by Chevron. Since 1981 several 3D surveys have been acquired, and 9 vertical, and 6 high angle horizontal, wells have been drilled – see Exhibit 3.
The vertical wells produced 1000-1595 bopd. In 1997 an extended well test (EWT) produced 662,000 barrels of 14.5O API oil over 63 days at a maximum rate of 14991 bopd.
The main reservoir is the Tertiary Maureen Sandstone which has a gross thickness up to 122m and excellent reservoir characteristics. The trap is both structural and stratigraphic, and is estimated to contain 375 million barrels (2P) oil in place with 82 million (2P) recoverable.
A shallower reservoir, the Heimdal Sandstone Member, could contain around 500+ million barrels oil in place. This has flowed up to 1800 bopd on a vertical test.

For most of 2006, there were press releases to the effect that Chevron were drawing on their experiences of Captain (see above) and conducting extensive engineering studies (FEED; also on the somewhat heavier oil in the Bressay discovery) with a view to finally submitting a development plan and bringing Mariner onto production.

But about six months ago, the following could be found at:
http://host.businessweek.com/businessweek/research/stocks/snapshot/snapshot.asp?symbol=CVX
Chevron Mulls Sale Of Operating Stake In Stalled UK Oilfield Project
06/8/2007
Chevron Corp. plans to divest its operating stake in Mariner heavy-oil field in UK waters, putting paid to plans to move the project into front-end engineering and design this year. A Chevron spokesman confirmed that it plans to sell its equity stakes in Production Licenses 335 and 726, which contain the Mariner and Mariner East discoveries. "The company has made an intensive effort over the past several years to bring Mariner to economic development," said the spokesman. "We have now reached a decision that, although it is an attractive project, it is not competitive in our global portfolio and may offer better value to others." Chevron holds a 44.44% interest in the Mariner complex. Informed sources said Chevron's decision means the project has been delayed "indefinitely" because "its economics didn't match up" to the operator's expectations.

Without detailed knowledge of Chevron’s work and thinking, one can only surmise as to the economic rationale behind their decision. My guess is that the following would be the key components:

1. A successful development will require the drilling, completion and management of many extended reach horizontal wells, with multilateral and tri-lateral access to the reservoirs. Relative to a conventional Light Oil development, this will lead to a very high number of rig days and hence very high costs in these days when rig rates have ‘caught up’ with oil price rises – see Exhibit 4.
2. The need to go beyond normal Light Oil export facilities, such as a pipeline or an FPSO, and include the processing of the Heavy Oil into a product that the market is willing to accept, in power stations or upgraded refineries for example.
3. The uncertainty as to whether, at the end of all this, the products will still have to be sold at a substantial discount to prevailing Light Oil prices.

The decision to participate in offshore Heavy Oil is essentially a strategic one and is made against a background of the fit of such projects into a company’s total portfolio: in the case of Chevron, they may well prefer to spend their development $s on, for example, Deep Water Light Oil developments in the Gulf of Mexico or Angola.

Who then might take North Sea Heavy Oil forward? I suggest the candidate companies might have the following characteristics:

a) Firstly, a prime requirement is that the management team has considerable experience of the many commercial and economic skills connected with the lifting, marketing and sale of Heavy Oil and its by-products.
b) Secondly, Heavy Oil will need to offer a good strategic fit in the company’s portfolio, probably because there has been a lack of success in exploring for conventional oil or gas.
c) Thirdly, the technical team must be big enough and have the necessary skills and experience to manage the cornucopia of technologies needed to develop and manage a Heavy Oil field. A key lever will be innovation, especially the ability to drive down the costs of completing and managing the well suite.
d) Fourthly, the company will need deep enough pockets to invest significant upfront capital and be tolerant of the relatively long pay back times.

It was therefore no surprise, I believe, that the newly formed StatoilHydro stepped in and acquired Chevron’s interests in the Mariner discovery and some other Heavy Oil assets. In addition to their success with the Grane Field in the NOCs, mentioned above, they have aggressively pursued reserves in for example the Peregrino Heavy Oil discovery, offshore Brasil.

The arrival of such an operator for the Mariner discovery should be one component of transforming the fortunes of Nautical Petroleum who have ~27% equity. At least as important, however, will be the recent, successful, operated Kraken appraisal well where reserves now seem to be ahead of previous expectations (perhaps as much as 100 million barrels?), with potentially better quality oil and reservoir than previously encountered.
A key lever for Nautical will be the timing of 1st Oil from both Mariner and Kraken: can the company influence StatoilHydro to bring the Mariner 1st Oil date forward from a mooted 2013/14 and can it, as operator, deliver 1st Oil from Kraken in, say, two years time?

There is a final issue though. It is a myth that Heavy Oil becomes unfailingly attractive at the level of oil prices we are seeing today. Given a level playing field, it will still be relatively less attractive than conventional “light oil” projects, assuming a company has some of these in its portfolio. The UK Government has the fiscal power to tilt the playing field in favour of Heavy Oil, for example by significant tax breaks, but has not done so (the April 2006 Budget was unhelpful to all UKCS Developments).

Author: David Bamford

Monday, February 25, 2008 19:46