The Coniston and Novara Development in Western Australia - Offshore Challenges Met With Solutions

Sankoff, Roumen Dimitrov (Apache Energy Ltd.) | Di Martino, Gianluca (Apache Energy Ltd.) | MacDonald, Shona (Apache Energy Ltd.) | Marshall, Craig Scott (Apache Energy Ltd.) | Smith, Anthony (Apache Energy Ltd.)



The development of heavy oil accumulations presents difficult engineering, technological and geological challenges that need to be overcome to produce economically viable projects. Even a large oil accumulation can be deemed unattractive for development in cases that combine a high cost environment with complex geological setting and unfavorable fluid dynamics. This paper highlights the challenges and presents the subsurface solutions that unlocked the value of an offshore heavy oil accumulation, 32 years after it was first discovered. Within the context of the overall development plan, the paper describes:

1. The design of the offshore well test that delivered 11,244 bbl/d 15.7oAPI oil and proved the production capacity of the reservoir and the conceptual well design.

2. Workflow for confirming the existence of a compositional gradient and characterization of a biodegraded oil column.

3. A novel approach to evaluation of inflow control devices (ICD) and its implementation in the well design.

4. An ICD modelling tool developed specifically for direct comparison of different ICD geometries.

The paper also presents the field history to date - from the early failures in recovering hydrocarbons using conventional methods, through to the enabling technologies that made Coniston and Novara a viable project.


Coniston and Novara reservoirs are located in permit WA-35-L, offshore Western Australia (Figure 1). Apache holds 52.5% working interest and operates the permit on behalf of a joint venture with INPEX which holds 47.5%. The joint venture acquired the permit in 2009, 27 years after the field was discovered with the drilling of Novara-1 in 1982. The fields are 45 km from the coast of Western Australia (Figure 1) in 380 m water depth and will produce 14-16oAPI oil from the Barrow Group formation.

The reservoir contains a thin oil column between a small gas cap and strong bottom-drive aquifer. The oil will be produced via subsea tie-in to an existing production system and a floating production, storage and offloading facility (FPSO), the Ningaloo Vision (NV), located approximately 10 km away.

The project was challenged by (1) unproven well and reservoir capacity to deliver production at commercial rates, (2) heavily compartmentalized low relief reservoir structure, (3) water and gas coning affecting recovery from a thin oil column, (4) a strong bottom-drive aquifer impacting the wells’ drainage area and (5) flow assurance and operability issues due to long distance subsea tie-back.

Production at commercial rates from each reservoir was demonstrated in the early phase of the appraisal campaign. The flow tests met all objectives, and set a record for the region with the Coniston-2H well testing at 11,244 bbl/d of 15.7oAPI oil. The successful production tests were followed up with further appraisal wells to delineate the structure. The results from the appraisal drilling revealed: a low-relief structure, complex fault network, lateral variation in the fluid contacts.