Eni Australia is operating the Blacktip gas field offshore Australia and Kitan oil field offshore East Timor. The main challenge was to manage these green fields remotely, with lean resources and strict deadlines covering tasks like data capture and acquisition, data validation, application integration and field analysis efficiently. The implications of the decisions made during the development of a green field are imperative to the optimization of reservoir production. Therefore, an integrated production decision support system was required for performance monitoring of asset health and optimizing production to meet the targets. This paper describes how these challenges were overcome at Eni Australia by centralizing the operations of both fields into a standardized production platform, providing a seamless data transfer from offshore assets to the onshore technical office and establishing the foundation towards a digital oilfield. The platform framework automates the process of acquisition, transfer, conditioning, aggregation and storage of production and operations data into a secure centralized data repository with an auditable amendment history. The production platform provides improved operational and reservoir visibility, which forms the basis for all subsequent analysis and underpins the engineering justification to support operational decisions.The current solution framework provides a multifunctioning system that can be expanded for future assets and fields as they come online by leveraging the investment in the existing system. All the domain experts, from production operations to reservoir engineering, will have the required information at their fingertips for collaborative decision making. Thus, a centralized production platform provides engineers with an improved field visibility for remote field management, proactive decision making and help them to strategically develop fields by optimizing production. Introduction:

As the oil and gas industry moves towards new ventures and remote locations, possibly in more challenging reservoirs and in high-cost, high-risk environments, a cost-effective formation testing method is fundamental to assess new findings and proper decision making. Despite its ability to provide precise pressure profiles and multiple samples obtained along reservoir sections, wireline formation testing is generally seen as complementary to extensive well test operations. Determination of reservoir viability with wireline testers is often considered only indicative of reservoir productivity, while testing techniques through straddle packers are perceived as not totally risk free. Information obtained from a well test often depends on the reservoir type. If most of the heterogeneous carbonate reservoir warrants comprehensive testing to evaluate productivity through natural fractures, evaluation of homogeneous sandstone is generally an assessment of matrix permeability. An advanced formation testing technique was used for the first time in a 12.25-inch bore hole in the Asia Pacific region. An effective mini-DST was carried out by delivering an inflow performance relationship (IPR) consistent with the known production behaviour of the Laminaria Formation in the Kitan oil field in a cost-effective manner compared to the traditional straddle packer technique. In addition, this case study points out that under certain circumstances, mini-DST results from a specific interval of the reservoir can be scaled up to the whole reservoir under investigation, making this technique potentially an alternative to a full well-testing program, when rig costs or environmental constraints often make such a procedure prohibitive.

This paper describes the work flow adopted by Eni Australia to support Blacktip daily production operations. The Blacktip gas field is located offshore in the southern Bonaparte Basin, Australia. Eni Australia is the operator for the Blacktip gas field and holds 100 per cent (%) working interest. Production from the Blacktip gas field started in September 2009 and has been the primary source of gas for Darwin, Northern Territory. The Blacktip gas project consists of a normally unmanned Wellhead Platform (WHP) at a water depth of 50 meters (m), a 110 kilometer (km) offshore Gas Export Pipeline (GEP) and the onshore Yelcherr Gas Plant (YGP). Two deviated production wells were drilled and completed on the WHP in September 2009. Well intervention was carried out on the WHP to shut off a lower production zone and perforate the main production zone in June 2013. Untreated gas from the wells is directly sent to the YGP via the GEP, without offshore processing. The gas is treated at the YGP to meet the customer's specifications and it is sent to Darwin via an onshore gas transmission pipeline operated by a third party. Condensate is processed and stored at the YGP, and offloaded via a 10 km offshore offloading line. Multiphase flow numerical transient simulation (dynamic simulation) techniques have been used to establish the work flow to support daily production operations. Three fit for purpose models have been constructed in order to fulfill this task in a timely manner. They are the well(s) model, the GEP model and the offloading line model. History matching of the GEP model has been routinely conducted to monitor pipeline performance and to provide the operations team with relevant information such as liquid volume in the GEP, slug prediction, etc. The condensate offloading line model was used to develop operational guidelines for the first offloading operations conducted in July 2010. In due course, dynamic simulations were applied to support well operations using well models. Regular history matching has been conducted to validate the models and monitor well performance. The well model was also used to establish a sound and safe operations plan for the well intervention campaign, to change the production zone. The application of dynamic simulation is now an integral part of daily production operations for the Blacktip gas field.

The Kitan oil field is located in the northern Bonaparte Basin in the Joint Petroleum Development Area, an area jointly administered by Timor-Leste and Australia. The Kitan structure is a Jurassic east-west trending tilted fault block. The Kitan–1 exploration well was drilled and successfully tested in early 2008. Kitan–2 appraisal well was drilled immediately after Kitan–1 and intersected the reservoir up-dip from Kitan–1 and confirmed the extension of the oil accumulation. The main oil-bearing section is in the shallow marine sandstone of the Middle Jurassic Laminaria Formation. It is divided into two reservoir zones: a blocky channelised sandstone (Unit–2) overlain by a dominantly finer-grained succession composed of coarsening-upwards para-sequences (Unit–1). Kitan oil field was declared a commercial discovery in April 2008 and a field development plan was submitted in May 2009 and approved in April 2010. Four development wells were drilled of which three were completed as producers, each employing an intelligent completion design to enable independent control and monitoring of the two reservoirunits. The three wells were tied back subsea via flexible flowlines and risers to the Glas Dowr FPSO. Oil production from the Kitan started in October 2011, about 3.5 years after the discovery of the field. The fast-track development of Kitan was achieved due to accelerated appraisal, prompt completion of studies, early commitment to long lead items, and excellent support from joint-venture partners and government.