| Harding oilfield | |
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| Country | Scotland, United Kingdom |
| Region | North Sea |
| Block(s) | 9/23B |
| Coordinates | |
| Operator(s) | BP |
| Field history | |
| Discovery | 1987 |
| Production | |
| Current production of oil | 17,000 barrels per day (~8.5×105 t/a) |
| Current production of gas | 9 million cubic feet per day (250×103 m3/d) |
| Producing formations | Eocene formation |
The Harding oilfield is a small oil field operated by BP, in the North Sea block 9/23b, approximately 200 miles (320 km) North-East of Aberdeen and in 110 metres (360 ft) of water.[1]
Contents |
The field was discovered in 1987, when oil was found in Eocene at a depth of 1,850 metres (6,070 ft). The abundance of napthalmic acid in the oil however made the development unattractive at the time. The crude is heavy and naphthenic and is generally of a lower value compared to other North Sea oils. Consequently the decision was made to export it by tanker rather than co-mingle it in a pipeline. The oil from the Harding field therefore requires to be stored offshore. The selected development solution was a heavy-duty steel jack-up production unit based on a proprietary design by Technip Geoproduction resting on a concrete gravity base which had storage for 550,000 barrels (87,000 m3) of oil.[2]
The Harding field is in fact composed of five separate reservoirs. The largest is the central field, hosting most of the wells as well as the site of the gas re-injection. There is also smaller fields to the North, North-East, South and South-East, all named as such. This has led to a unique well naming system in addition to the traditional use of DTI well numbers and slot numbers, which identifies a well by the particular field in which it has been drilled and its purpose.
The formations are unconsolidated, making the wells likely to produce sand. In order to prevent this, traditional cased hole completions are not used on any of the Harding wells. Instead, all wells used sandscreens.
Harding presently produces around 17 thousand barrels per day (2.7×103 m3/d) of oil, from 15 wells, and 9 million cubic feet per day (250×103 m3/d) of gas, most of which is re-injected. All production wells are gas lifted. The central reservoir is supported by two water injection wells and a gas injector. The south and north fields have the support of one water injector each, though the injector in the north field is currently suspended.
All produced water is reinjected. In addition there are two aquifer wells to provide extra injection water, if required.
Without a pipeline, the bulk of the produced gas has been reinjected into the cap of the central reservoir, sequestering it for production after 2009, when the platform is converted to a gas producer after decline of oil production.
The Harding reservoir also contains gas, which BP hopes to develop at some future stage. BP announced plans in 2006 to develop the gas resources via the Harding Area Gas Project. A combination of factors has made this original development concept uncompetitive; particularly low gas prices and increased development costs. The project is being recycled and BP is in discussion with its partner, Maersk Oil, to investigate alternative development options for the gas resources in the area.