Case Study - Hovea Oil Field (Onshore, Western Australia)
Transformed Oil Recovery & Company

Situation

Arc Energy (Operator, 50%) made an oil discovery with its Hovea-1 well in 2001 and drilled an appraisal well, Hovea-3, in a crestal location in mid-2002. Both wells were vertical and had tested 42° API oil with a GOR of 200 scf/stb. The estimated STOIIP was 10-15 MMstb.

Arc’s Asset Manager called an Advance member in early September 2002. He was asked to review Arc’s development plan for the Hovea field that was being finalised for submission to the regulator ahead of the imminent start-up of an early production system (EPS) from the 2 wells. A short data gathering exercise followed later that week. The Arc plan was to put both wells on production via the EPS, ahead of installing a permanent production facility in 2003. 

Solution

An evaluation of the data revealed that Hovea-1 had encountered the Dongara reservoir 8 m above the OWC, and that Hovea-3 was located close to the crest of the structure with a 25 m oil leg. The Dongara sandstone at Hovea was ±50 m thick with a net:gross of ±90% and an average permeability of ±600 mD, which is large. The oil viscosity in the reservoir was 1.2 cp, so the mobility ratio (M) was <1, meaning that a waterflood would provide efficient, piston-like displacement of oil by water, and hence a recovery factor of up to 50% could be envisaged. Moreover, many years of production from the depleted Dongara gas field ±5 km to the north had left the Hovea field depleted from the original reservoir pressure by ±750 psi.

Arc was presented with an 8-page fax report by the end of that same weekend by the Advance team member, recommending that the Hovea-1 well be converted into a water injector for pressure maintenance, and ultimately re-pressuring of the reservoir. In addition, it was recommended that a series of horizontal oil development wells be drilled along the crest of the Hovea structure. 

As a result, the submission to the regulator for the EPS was rewritten based on the recommendations provided. The EPS came on production soon after with 1 producer and 1 water injector. During the following 12 months the Advance team member, along with the Arc team, worked through the implementation of the full suite of development recommendations summarised in that initial 8-page fax, including drilling horizontal producers along the crest of the field.

Result

The Hovea field achieved peak production of >10 Mstb/d with a prolonged plateau at low watercut, as a result of the implemented development plan. The field produced 7.3 MMstb in the 4 years from late 2002 to 2006 before being closed-in. The recovery factor was >50% as a result of the change in development plan that itself took place over only a matter of days in September 2002.

Arc had only very limited cashflow from a small volume of gas production at the time that the Hovea field came on production. Arc’s first year’s net revenue of $US 65 MM from the reconfigured Hovea development plan completely transformed the company, allowing it to proceed to discover and develop other nearby oil fields. The net revenue generated by the Hovea field for Arc in just 4 years was ±$US 150 MM, and was instrumental in AWE taking over Arc for $480 MM in 2008.