Extended Well Tests (EWTs) – A Personal View
In the 1990s there was a whole spate of extended well tests mostly involving a drilling rig linked up to a tanker, to win and save the oil. Nowadays EWTs are comparatively rare which begs the question: “Should EWTs be conducted on any of the fields currently under appraisal?” Malcolm Pye (Malcolm.Pye@dti.gsi.gov.uk) of the DTI Oil and Gas office in Aberdeen presents a personal view.
1990s
Amongst the EWTs in the 1990s were ones conducted on the heavy oil fields, Captain and Mariner, on the diapir fields, Mungo and Pierce and on the West of Shetland fields, Foinaven, Schiehallion and Clair. The tests lasted 2-3 months and the volumes produced were usually between 0.5 to 1 million barrels (one or two tanker cargoes). Operators reported that the EWTs were marginally profitable as the sale of the oil covered the rig and tanker rental costs.
The main reasons for the EWTs were:
- To confirm that there was sufficient connected oil volume to reduce the risk of an uneconomic development.
- To obtain reservoir and performance data for facility design.
Why was there this spate of EWTs in the 1990s?
Partially it was to do with new kinds of fields being developed such as the diapir fields, the heavy oil fields and the West of Shetland fields. In the diapir fields the reservoirs are steeply dipping against the salt diapir and the reservoir often looks to be compartmentalised by radial faults. In the heavy oil fields the unfavourable mobility ratio between the heavy oil and water, meant early water breakthrough from water coning was likely. In the West of Shetland fields with Palaeocene reservoirs the oil API was in the 20s and the water depths were greater than anything produced in the North Sea. In Clair the fractured Devonian reservoir was the challenge. All of these fields were too remote from existing infrastructure to lay a flow-line and start a phased development as Mobil were able to do very successfully with Nevis.
In addition new well designs were being tried out. The exploration and appraisal of these fields had mainly been carried out with vertical wells but the development was to be with long horizontal wells. Could these wells be drilled and completed from a semi-submersible drilling rig? Could the wells be successfully cleaned up? How productive would the horizontal wells be? Many of the reservoirs required some form of sand control such as screens or slotted liners. The EWT well gave the opportunity to test out the well and completion designs.
The EWTs were also of great comfort to management. They provided tangible proof that there was oil there capable of being produced. Something that all the seismic and well log displays in the world cannot actually provide.
The EWT tests of the 90s achieved their objectives and with one exception (Mariner), field development went ahead. In the main the EWT wells subsequently proved to be fairly typical in terms of performance as the other wells drilled in the field. The exception was Schiehallion where the EWT well was drilled along the axis of a turbidite channel and is by far, the best producer in the field. As BP has pointed out, drilling an exceptional EWT well can lead to over-optimistic expectations of well performance.
Present
So which fields under appraisal at present might benefit from EWTs?
Later diapir and WoS fields can now look to existing fields as analogues but amongst heavy oil fields the heaviest so far developed is Captain at 19 degree API. Are heavier oil fields developable or are the oils too viscous?
There are a number of heavy oil discoveries in Quadrant 9 where an EWT would provide an indication of the sustainability of production. At present the only test data from these fields is short duration drill stem tests which were often curtailed by sand production. An EWT probably adds a year to the development timetable but that would be preferable to a failed development.