Over the past few years a new generation of heavy crude oils has been produced from the North Sea, posing a number of operational and marketing challenges to operators. At a recent SPE panel session in London, representatives from three companies outlined how they have overcome these challenges and, indeed, turned them into opportunities.

Gryphon was the first heavy oil field to come onto production in the North Sea in 1993. Mike Mansell of field operator Kerr-McGee explained that a number of things had to be done differently to make the development economically viable and to facilitate early production.

The field has been developed using a floating production, storage and offloading system (FPSO) connected to a subsea wellhead cluster located some 1.5 km away. Shuttle tankers offload the oil for export to international markets.

The Gryphon FPSO was also the first to be moored permanently on location ñ made possible by the ship being designed and constructed to weathervane around the moored turret to maintain its heading into the prevailing weather.

The development concept called for hori-zontal wells to minimise gas and water breakthrough and enhance long-term oil production rates. The fewer wells required would also ultimately result in better oil recovery.

Added Mike: The production profile is typical for heavy oil fields, with early peak production but more water than oil produced over the life of field.

Reservoir modelling showed the optimum position for the horizontal section of the wells to be 45 ft below the gas/oil contact, although Mike noted that gas production has turned out to be higher than predicted. Later wells were therefore completed 65 ft below the gas/oil contact.

The Gryphon development was the first in the world to use a subsea spool tree system - the innovative design of which allows drilling and completion operations to follow tree installation. Mike said that the spool tree allows substantial time savings and increased safety during well completions and workovers compared to conventional subsea trees.

The main processing plant - which is located on a support frame across the main deck of the ship ñ consists of a single process train with two stages of three-phase separation, followed by an electrostatic coalescer. Heat required for separation is provided by a closed-loop heating medium system from waste heat recovery units installed in the exhaust system of the two turbine alternators. Demulsifiers are used to assist the separation process. Furthermore, the alignment of the separators lengthways along the ship ensures minimal roll since the ship always faces into the weather.

Offshore loading means that pure Gryphon crude is delivered to refineries which has turned out to be quite an advantage, according to Mike. Before production started, we had established a market with niche refiners and those wishing to use heavier crudes as a blend in their crude slates. Gryphon crude has the added advantages of a low sulphur content (0.45 % weight) and low concentrations of heavy metals such as nickel and vanadium, he said.

Other crude characteristics include an API gravity of 21.5°, a total acid number of 4.4 mg KOH/g, and a low pour point of -27°C. No waxing or asphaltene problems have been encountered.

The characteristics of Alba crude have certainly been a major factor in shaping the different aspects of the development: from its oil production wells to the design of equipment on the Alba Northern platform where the crude is processed before being held aboard the North Sea's first purpose-built floating storage unit (FSU) ready for export by shuttle tanker.

Dave Dawson of Chevron spoke briefly about the Alba field. He explained that devel-opment complexities include relatively heavy oil (20° API), unconsolidated formation, exclusive use of horizontal producers, bottom water, water injection, complex completion procedures, scaling, difficult top of sand seismic resolution, electric submersible pumps (ESPs), and seismically unresolvable shales in the main sand body along the planned well paths.

Field development was originally approved with a phased approach. The first phase consists of a minimum facilities platform - Alba Northern - and a floating storage unit with a capacity of 825,000 barrels. The crude is offloaded to a dedicated shuttle tanker. First production was in January 1994.

The southern section of the reservoir will be developed with extended reach wells from Alba Northern and possibly a bridge-linked support platform and subsea wells depending on the outcome of studies currently in progress. Dispensing with the need for a second major platform has helped reduce development costs considerably.

The lack of pressure support in the reservoir has necessitated water injec-tion from production start-up. 'Water-flooding has worked well,' Dave noted. 'We have successfully maintained reservoir pressure above the bubble point of 2300 psia and inject-ivities of up to 70,000 barrels a day of water are being achieved in some wells.'

Artificial lift techniques were also identified as essential from the outset and it was decided to install ESPs in the initial completions. However, they have not been installed in some of the more recent wells due to high reservoir pressures, low water cuts and excess well deliverability.

As was the case for Gryphon, Dave pointed out that the design of the topsides process facilities was the key area impacted by the heavy, viscous (20 cp at 70°C) nature of Alba crude.

The two first-stage separators, measuring an enormous 26m in length and 4.3m in diameter, became the major consideration in setting the size, weight, and consequently the cost of the topsides design. Each separator spans the entire width of the platform's processing deck.

The oil has to be heated to lower its viscosity and enhance the separation process in what is one of the biggest heat transfer operations in the North Sea. A third coalescer/degasser module has recently been added to the Alba Northern platform, marking the beginning of the phase two development and allowing oil production to increase to 100,000 barrels a day.

Electrostatic coalescers further reduce the water content of the crude to the low level required for export, while the oily sand produced is cleaned thoroughly by passing it through innovative ceramic hydrocyclones.

The Alba development presented a number of new challenges for a North Sea project and valuable lessons have been learned for the future. So, with hindsight, what might have been done differently? Dave suggested a range of issues associated with the separation process - for instance, increasing the heat at the first stage, installing the separators in a series with interstage heating rather than as separate trains, injecting demulsifier as far upstream as possible to allow maximum 'break out' time, and taking steps to minimise internal flow disturbances in the very long separators.

Harding crude is a more recent entrant to the market, having come on stream earlier this year. Adrian Pearce of BP explained that the main Central and South pools were first discovered in 1988, with project sanction and development approval given by the government in 1993.

Harding is another heavy North Sea crude ñ 19.5-21.0° API, viscosity of 5-10 centipoise, and total acid number of 2.8 mg KOH/g ñ and its early commercial viability was cast further in doubt by the shallow and complex nature of the reservoir. However, advances in extended reach and horizontal well technology led to a development proposal based on:

• a single heavy-duty triangular jack-up drilling and production unit placed between the two main oil accumulations;

• an 84,000-tonne concrete gravity base, capable of storing 580,000 barrels of oil;

• a two-kilometre pipeline to a tanker loading system.
  

The reservoir quality of Harding is excellent by North Sea standards - very homogenous with a porosity of 35 per cent and permeability of up to ten Darcies. A total of 16 wells have been planned, nine of which will be horizontal production wells. Two wells will be water producers (Harding formation water is incompatible with sea water) and the remaining five will be used for water and gas injection to maintain pressure, minimise flaring and maximise recovery. The horizontal sections in the first wells drilled were positioned some 75 ft below the gas cap to maximise the early production rate; later ones will be drilled shallower to improve ultimate oil recovery.

Field life is expected to be some 20 years with peak oil production of around 70,000 barrels per day. Associated gas will initially be re-injected into the reservoir with exports not commencing until oil production is in decline.

The facilities design on the platform allows for the high water production expected later in field life. As with Gryphon and Alba, the separators are large and a main challenge, according to Adrian, is to heat the crude sufficiently to reduce its viscosity and facilitate gas/oil separation.

Unlike many heavy crudes, Harding oil has no wax or asphaltene problems and is also low in sulphur.

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