A development campaign offshore Australia, with a total of 15 laterals in a challenging geological environment, has been successfully completed by Quadrant Energy. The main objectives were to geosteer and place the well path at an optimum standoff from the oil/water contact (OWC), while drilling at the interface of the gas/oil contact (GOC), when present, and at 1-1.5m TVD from the reservoir top when not.
The field is characterized by a series of transverse and longitudinal seismic and sub-seismic faults that bisect hydrocarbon-bearing sands which represent the greatest challenges in this development campaign. Evidence from exploration wells showed a thin column of heavy oil and a gas cap in the fault-bonded reservoir. A new multi-disciplinary methodology not only enabled Quadrant Energy to achieve its development objectives, but to develop a full subsurface picture of the Coniston field reservoir.
The use of the Reservoir Mapping-While-Drilling (RMWD) combined with Bed Boundary Mapping Tool (BBMT) and Multi-Function LWD services enabled the laterals to be placed at 1-2m TVD below the reservoir top or gas cap, when present, even in highly faulted sections. In addition to this precise placement the extreme depth of investigation of the RMWD service, in conjunction with the real-time multilayer inversion capability, constantly mapped the OWC at a distance up to 19m TVD below the wellbore. While drilling, different qualities of reservoir sands were identified and enabled the extensions of the wells’ TDs based on reservoir properties. The distance to boundary information, provided in real-time by the RMWD service, was used in real-time by the Quadrant Energy geology and geophysics team to update and validate the seismic model that provided increased confidence in the reservoir model and a more precise planning for future development wells.
This paper will illustrate the use of the latest LWD RMWD technology in a challenging geological environment. The paper will explore the close collaboration, teamwork, and integration necessary to drive innovation and demonstrate the outcomes of this successful campaign which have not only exceeded the development goals, but have also generated a full 3D view of the reservoir.
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.
Horton, Phillip John (Shell Development (Australia) Pty. ) | Harrison, Paul (Shell Development (Australia) Pty.) | MacDonald, Shona (Shell Development (Australia) Pty.) | Partington, Mark (Shell Development (Australia) Pty.)
This reference is for an abstract only. A full paper was not submitted for this conference.
The Upper Swan sandstones represent a key exploration target in the Caswell Sub-basin and are the main reservoir units for the large Ichthys-Prelude gas-condensate field. The sandstones are present west of the Yampi Shelf margin from Leveque-1 in the southwest to Maret-1 in the northeast, and in the central portion of the Caswell Sub-basin extend to the northwest as far as Caswell-2.
Within the Caswell Sub-basin the Upper Swan sandstones are best understood in the Ichthys-Prelude gas-condensate field where twelve wells have been drilled to date. Interpretation of nearly 600m of conventional core, wireline logs, image logs and 3D seismic surveys have contributed significantly to the understanding of the depositional environment.
The Upper Swan sandstones is a lithostratigraphic term for sandstones that range in age from Latest Jurassic (Tithonian) to early Cretaceous (Berriasian) and are calibrated to the P. iehiense, K. wisemaniae and C. delicata Biozones. These sandstones are sourced from the Yampi Shelf and typically onlap and overstep Tithonian-aged mudstones. The sandstones are quartz rich, dominantly fine - medium grained with occasional very fine to coarse grained units present. Individual sandstone units range in thickness from centimetre scale up to several metres and are typically relatively featureless, homogeneous beds with occasional dewatering structures. Thin claystones typically centimetre to tens of centimetres thick, but up to 15m thick locally, are interbedded with the sandstones.
Core data suggests they were deposited as a series of stacked sand-rich gravity flows comprising repeated massive suspension (S3) and thin traction flows (T1 and T2) (dense flows of Lowe, 1982) in a shallowing Outer to Middle shelf characterised by vertically shallowing ichnofossil associations of Chondrites, Phycosiphon/Chondrites to Zoophycus/Phycospihon.
In the Prelude Field, the Tithonian and Berriasian-aged sandstones are mineralogically similar, with a complex diagenetic history consisting of compaction, quartz cementation, framework grain dissolution, precipitation of kaolinite/dickite, and the formation of authigenic illite. Authigenic clays appear to be of the greatest importance in the Upper Swan Sandstone in terms of reservoir quality with the data indicating the older sandstones tend to have higher total clay content and these are typically tight.