Total Oil Marine Sees More Alwyn Area Potential

Aug. 17, 1998
Block 3/14a Dunbar platform is a wellhead installation from which all output is exported to the North Alwyn complex via a multiphase pipeline for processing. Photo courtesy of Total. [9,137 bytes] Dunbar-Alwyn Area [58,535 bytes] Total Oil Marine plc (TOM) began oil and gas production from its U.K. North Sea Alwyn North field in 1987 and has since made its two platforms the focus of a number of satellite developments.
Exports from Total's Alwyn North A and B platforms, on U.K. North Sea Block 3/9a, will be rerouted to the Cormorant A platform. Photo courtesy of Total.
Total Oil Marine plc (TOM) began oil and gas production from its U.K. North Sea Alwyn North field in 1987 and has since made its two platforms the focus of a number of satellite developments.

Alwyn North field output now represents only one third of the total production passing through the Alwyn platform facilities, and the operator is working on a number of projects for the field's mature phase.

Over the last 12 months total oil production from Alwyn North, Dunbar, and Ellon fields has averaged 82,000 b/d, while gas production has averaged 390 MMcfd.

Arnaud Breuillac, Alwyn area commercial manager at TOM, said Alwyn North was sanctioned in the mid-1980s with oil and gas reserves of less than 400 million bbl of oil equivalent.

Alwyn is operated by TOM, which has a 33.33% interest, while license partner Elf Exploration U.K. plc has a 66.66% interest. Today Alwyn area reserves, comprising Alwyn North, Dunbar, Ellon, and Grant, amount to 1.1 billion bbl of oil equivalent, of which just more than 500 million bbl has been produced. Remaining reserves are about 65% gas and 35% oil.

"The upside potential prospects," said Breuillac, "are mainly on Alwyn North Triassic and on a southern extension of Dunbar."

Since most of the upside potential is for gas, TOM is looking to debottleneck gas treatment facilities on Alwyn North. Original throughput capacity was 9 million cu m/day, but this has been raised to 11.5 million cu m/day.

Breuillac said studies are under way to raise capacity to 15 million cu m/day to enable TOM to unlock a number of small developments, including in the longer term four nearby discoveries.

Breuillac said TOM and Elf aim to spend more than £120 million/year ($192 million/year) on Alwyn area projects in 1998, 1999, and 2000 covering miscible gas injection, Dunbar multiphase pumping, development drilling in Dunbar, Alwyn Triassic, and debottlenecking of the Alwyn gas plant.


Philippe Persillon, engineering and projects manager, said TOM has a number of projects lined up to maintain Alwyn area production.

The largest will be installation of multiphase pumps on the nearby Dunbar satellite platform, with work starting in February 1998 and due for completion by the end of 1999.

Jean-Francois Renault, project manager for Dunbar multiphase pumping, explained that Dunbar is a wellhead platform treated as a satellite of the twin-platform drilling, processing, and utilities complex of the Alywn North field situated 21 km to the northeast (OGJ, Aug. 15, 1994, p. 68).

Renault said: "The challenge facing operators today is to recover their reserves in a cost-effective and efficient way. TOM is pushing forward the limits of technology by installing the biggest ever multiphase pumps on Dunbar."

The output from the Dunbar wells (oil, water, and gas together) is flowing directly into a 16-in. interfield export pipeline. In order to free-flow into this pipeline, a minimum wellhead flowing pressure (WHFP) of around 126 bar is required to enter the Alwyn North high pressure system at 71 bar.

As reserves are produced, the WHFPs will decline, particularly following water breakthrough. There will come a point when some Dunbar wells are no longer able to retain sufficient pressure to maintain flow rate to the 16-in. multiphase line. The installation of a gas and oil pumping capacity is required to provide energy to such wells.

Initially, said Renault, TOM planned to deal with falling well pressures by installing separation equipment on the Dunbar wellhead platform. Then, a new pipeline would be installed to take oil to Alwyn North's low pressure process plant (30 bar), while gas would be sent to the Alwyn high pressure system.

"During initial development," said Renault, "we thought we would need to lay the new pipeline in 2000 to enable production to continue, but during Dunbar production we have experienced two unexpected things.

"First, we found that to maintain stable operating conditions in multiphase flow, we needed to achieve a certain minimum flow rate at a certain minimum pressure, and to operate a multiphase pipeline below these parameters might induce flow instability.

"Secondly, the 30 bar receiving process facilities on Alwyn are today fully loaded. To modify these to receive low pressure production from Dunbar would require a major investment."

So, instead of building a new low pressure pipeline, TOM decided to boost Dunbar production. Renault said a feasibility study 3 years ago proposed the following scheme:

Low pressure (less than around 126 bar) wellhead fluids would flow to one of two independent multiphase pump packages via a segregated scheme. High pressure fluids would continue to flow directly to the Dunbar export pipeline. If required, a third multiphase pump package could be installed later.

Each multiphase pump package would have a dedicated production manifold to optimize the energy requirement.

Downstream of the pumps, production would be commingled into the Dunbar export pipeline for onward transportation to Alwyn North, as at present.

Renault said that rather than have three 50 bar streams in parallel for boosting to 126 bar, it is better to segregate the well streams into three different bands-90 bar plus, 70-90 bar, and 50-70 bar.

The advantage of segregation is that as much reservoir energy as possible can still be used, which means the segregated approach requires less power to drive the pumps.

"We selected a segregated system because it offers flexibility to the reservoir," said Renault. "We don't know when and how many wells will be 70 bar, how many will be 50 bar, and so on.

"Dunbar platform has 24 well slots. Most of these are drilled, and the number of producing boreholes is expected to be increased with drilling of sidetracks to turn existing wells into multilaterals."

The study showed that there was enough room on Dunbar to install the new plant and also that multiphase pumping on Dunbar platform would require 30% less capital and 30% less equipment in terms of weight than a conventional solution.

Renault added that while multiphase pumping is an emerging technology, the Dunbar team convinced management and Elf that it involved a manageable risk. One reason they were successful was TOM's experience of multiphase transportation.

"Total is involved in various multiphase research programs," said Renault. "We have applied this experience to Dunbar and have since continued multiphase pumping research and development."

Total was a partner in the Poseidon project, together with Institut Francais des Petroles and Statoil AS. The project has developed a multiphase hydraulics code and granted a license to build to Sulzer Pumps AS, Winterthur, Switzerland, and Framo Engineering AS, Bergen, Norway.

Total has also experienced the pros and cons of helico-axial and twin-screw pumps for multiphase pumping and claims to be a leader in multiphase technology, with a mature technical team.

Renault said Total has opted for helico-axial hydraulics for Dunbar as they could be easily optimized depending on reservoir behavior. Furthermore, the associated pumps are mechanically simpler than twin-screw pumps. They can run pure gas without damage, and they are equally efficient, which minimizes the operating risk in unstable flow conditions.

Sulzer-one of the licensees for Poseidon pump technology-has developed an 80 bar multiphase pump, which will be used in Dunbar. Dunbar platform's electric power comes through two 20 kv cables from Alwyn North. Three multiphase pumps (rated to 4.5 MW), could be deployed without requiring an increase in Alwyn's power-generating capacity. Renault said two multiphase pumps will be installed by the end of 2000 to cover multiphase pumping requirements to 2004. Provision will be made for installation of a third pump as required.

Design of a pumps module has been completed by Brown & Root Energy Services, Aberdeen. The pumps will be built by Sulzer, and a module fabrication contract is to be awarded this summer.

The two-pump module, with space for a third pump, will be attached to the side of the platform as a cantilever module on a support frame, which is currently being designed by Kvaerner AS, Oslo.

Alwyn projects

Last year, TOM began work on a miscible gas injection scheme to enhance oil recovery in Alwyn field and expects to complete the work by the end of April 1999.

Persillon said the project involves installing a small compressor on one of Alwyn's two platforms to inject up to 4 million cu m/day of gas at a pressure of 390 bar.

TOM has also built a 12-in. oil export pipeline from Alwyn North to the Cormorant A platform operated by Shell U.K. Exploration & Production. This will replace an existing export route via the Ninian platform. Persillon said the contract for export of Alwyn area crudes via Ninian to Sullom Voe runs out this year.

"The main reason for the changeover," said Persillon, "is that the Cormorant/Brent system has the same life expectancy as the Alwyn area. In addition, there is a significant reduction in transportation costs which made this project quite attractive."

The new line was installed in readiness for a planned shutdown and transfer of exports in July. The pipeline was laid in October 1997, with connection to Alwyn being made this March and to Cormorant in April.

TOM waited until the summer platform shutdown to switch to the Cormorant route. Alwyn area production typically amounts to 80,000 b/d of oil, said Persillon, while the new export line has capacity to carry 95,000 b/d. This capacity can be increased if necessary by injection of drag-reducing agents.

Development work for an extended well test and early production scheme in the Grant gas field was completed in July. A well was drilled from February to May.

For the test, the well will be tied back 250 m by a 6-in. pipeline and umbilicals to the Ellon field subsea manifold. Production from Grant will be exported via Ellon to Dunbar and on to Alwyn North.

"We want to see the production results from this well," said Persillon, "before we decide how to develop Grant further. We are likely to make the decision after 6 months of production."

Future work planned for the Alwyn area includes development of a Triassic gas and condensate reservoir 5,000 m below the Alwyn platforms. So far, TOM has drilled three wells from the Alwyn North A platform.

Persillon said these three wells are in production today. The Triassic reservoir is likely to be developed further with up to six platform wells and three subsea tiebacks up to 10 km away.

A further subsea development south of Dunbar field is also being considered after TOM drilled an appraisal well last year of a discovery made in 1972.

The find has now been called Dunbar South. Last year's well suggested the find is not viable, but a further appraisal well in a different part of the accumulation is being considered with a view to a two or three-well subsea satellite development.

In the southern half of Quadrant 3 between Alwyn and the Frigg field, TOM is operator of a group of four gas finds called Nuggets (Northern Underwater Gas Gathering Export and Treatment System), which were discovered between 1973 and 1991 and which have combined estimated reserves of approximately 500 bcf of gas.

Persillon said Total has no development plan for the Nuggets fields in place but may look to develop them in the future. Gas prices make development marginal, he said, but the potential for development using Alwyn infrastructure is seen as highest.

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