The Moomba field was first discovered in 1966 in the Cooper Basin, South Australia with first production commencing in 1969. From inception, the gas wells were drilled conventionally overbalanced with the majority of wells fracture stimulated to optimise production from the tight inter-bedded gas sands. Today the reservoir is highly depleted and conventional methods of accessing reserves are no longer viable over most areas of the field. Santos Ltd. investigated the application of new technology to accelerate the remaining reserves while avoiding formation damage and optimising potential production rates. Coiled Tubing Underbalanced Drilling was identified as a potential enabling technology for this application and 3 sidetracks from existing depleted wells and 2 new wells were drilled in the field in early 2007. This paper will discuss the planning, implementation and post drilling analysis of the campaign. The paper will also discuss the technical challenges encountered due to the high pressure depletion, complex geology of the reservoir, hostile drilling environment and remote location. Of the five wells drilled, four produced with increased rates when compared to modelling with a physically recorded zero skin on all wells. One of the two new wells achieved production rates not seen in the field for over 20 years. Overall, the campaign showed it was technically viable to drill wells in a geologically complex, depleted, tight gas field without damaging the reservoir. The paper concludes with a detailed discussion of how the degree of success achieved is reliant upon the selection of the right technology with a comprehensive understanding of the reservoir and its physical properties. In addition candidate selection is illustrated to be a critical element in achieving projects goals. Introduction The Moomba field has a history of high productivity since first production in 1969, Many of these wells are now into their production 'tails' and producing at low rates or have ceased production. The field is highly depleted with reservoir pressures in the range of 600 psia from an initial pressure of 3400psia. Field wide static gradient and Pressure Build-Up surveys (PBUs) were performed and revealed that the pressure depletion was widely varied and many wells were subject to high near wellbore skin damage. Typically, wells were drilled conventionally and fracture stimulated in earlier field development phases. However, with the field now severely depleted and the reservoir showing characteristic interbedded sands, shales and coals, the ability to effectively apply fracture stimulation technology is particularly challenging. Coiled Tubing Underbalanced Drilling (CTUBD) was identified as the technology with the best potential for accelerating reserves capture. The aim of the project was to achieve a zero skin wellbore through the two gas bearing intervals in the Moomba area and therefore, lower the abandonment pressure. This will accelerate reserves from long production 'tails' and potentially add incremental reserves by accessing previously undrained sands. Well Candidate Selection Candidate Selection is a key element when applying new technology such as CTUBD (M. Brown et al1). The following criteria were applied in order to rank possible candidates within the existing wells in the Moomba field as re-entry candidates.
As production from the Gippsland Basin in Bass Strait Australia passes the 30 year mark, the need to find innovative techniques to maximise production from this world class maturing basin is a principle priority for the operator. To address this issue, Esso Australia, on behalf of the 50: 50 joint venture with BHP, recently embarked on a concentrated program to trial and evaluate several new technologies being developed by industry. This paper discusses several technologies that were employed to increase production, enhance reservoir recovery and improve well integrity. Varying degrees of success were achieved during these trials and the successes, failures and lessons learned will be outlined. The technologies discussed include:Scab liners with inflatable packers set through tubing in horizontal wells to isolate water/gas production;Gas and water shut off techniques utilising polymer technology;Wellhead leak sealing technology using differential pressure-set coagulating polymers;Wirelineless completions using expendable plugs and perforating gun hanger systems on space limited platforms (during infill drilling operations);Through-tubing deep penetration perforating charges used to stimulate production from wells with extensive near wellbore damage; andMini-fracturing gas stimulation technology used on poor performing reservoirs. The high level of mechanical success combined with encouraging reservoir success in some instances is promoting a continued search for further production enhancing techniques. Introduction Esso/BHPP's operations in Bass Strait, South Eastern Australia, include 16 production platforms, five sub-sea completions and two single mono-towers (Fig. 1). From these facilities there are 364 wells, the majority being oil and/or gas producers with the remainder injecting for reservoir management. Since production commenced from the Gippsland Basin in 1969 with the installation of the Barracouta platform, significant ongoing drilling and workover activities have enhanced and maintained production levels. Until the mid to late 1990s, traditional tubing pull, mechanical isolation and cement squeeze techniques have yielded high levels of mechanical and reservoir success with strong workover economics. An ever declining list of high quality opportunities, as evaluated using traditional techniques, made it necessary to embark on a search for technologies that would continue to achieve mechanical and reservoir objectives while at the same time reducing workover costs. After implementation of each new technology, an evaluation based on both mechanical and reservoir factors was performed. Mechanical success was defined as the completion of the required scope of work with appropriate testing successfully completed. Reservoir success was defined by long and short term reservoir performance compared against pre-job expectations. This paper concentrates on the mechanical aspects of each technology, however reservoir performance has also been discussed where appropriate. Each of the new technologies trialed are discussed in the following sections; Scab Liners with Inflatable Packers A number of horizontal wells in Bass Strait were identified as potentially producing either gas or water preferentially from the heel of the horizontal section. The cost of traditionally used methods for water or gas shut-off such as tubing pull re-completions for installation of mechanical isolation equipment or cement squeezes made them uneconomic.
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