Cooper Basin reservoirs commonly contain low-permeability reservoirs that require stimulation to flow. However, conventional multi-layer stimulation techniques has been shown to leave some sands untreated and not contributing, leaving potential to further increase flow rate and reserves through the use of new technology. Pinpoint fracturing technology allows multiple precisely-targeted fracs to be economically treated, which can increase flow rates and reserves, reduce incremental per-frac costs and significantly shorten cycle time compared to multi-stage conventional treatments Eight wells in the Cooper Basin of Australia have been Pin-Point stimulated using coiled tubing producing a 30% increase in well productivity compared with AFE expectations. Production logs run over the fractured zones show markedly improved completion efficiency with production from the majority of Pin-Point fractured zones. Introduction. The Cooper Basin extends over 130,000 sq kms in the north eastern corner of South Australia and the south western corner of Queensland.The basin is Australia's largest onshore producing area, currently producing 600 MMscf/day from 700 gas wells and 12 Mbbl/day from 400 oil wells.Hydraulic fracturing has been a critical technology in the basin for over 40 years.To date, over 600 individual treatments have been pumped with up to three stages per well.The fracturing environment throughout the basin is very challenging from a number of perspectives.The producing zones for fractured wells are typically between 7500 ft to 10000 ft depth with temperatures ranging from 250 to 400 °F.Multiple reservoir intervals are found interbedded with shales and coals. Fracture gradients are between 0.9 and 1.25 psi/ft with near wellbore pressure losses between 500 and 2500 psi.The basin is normally pressured with only a few isolated cases of overpressure being recorded.A typical well could have up to 1500 ft of gross interval with multiple fracture targets.Traditionally, this has been accomplished by blanket fracturing multiple zones in one treatment with up to 3 treatments in a wellbore isolated by sand plugs. Analyzing the effectiveness of this blanket fracturing technique with production logging suggests that significant pay has been bypassed by grouping multiple sands together in one treatment.For blanket treatments targeting multiple zones, production logging showed only one zone flowing.With the increasing differential depletion seen across fields within the Cooper Basin, grouping more than one sand package in a fracture treatment has become ineffective.Pin-Point fracturing was introduced to effectively stimulate more than three zones in a wellbore quickly and economically. This paper discusses the details of the fracturing process and operational methods plus presents two case histories with treatment examples, analysis and results.Pre-frac diagnostic injection tests were performed on all treatments using downhole pressures obtained through the use of the coiled tubing as a dead-string.Post-frac production logs show the additional production and reserve contribution from the fracture treatments, with observable production from almost every fractured interval. Well Selection Criteria. Initially, a trial group of four wells was targeted to trial the Pin-Point technique.The wells were selected based on reservoir, mechanical and logistical constraints.The wells required a minimum of at least three individual targets.New drill wells with 4 ½" 15.1 lb/ft P110 casing were selected due to the size restrictions on the mechanical packer and downhole equipment.This configuration limited the maximum pumprate to 15 bpm due to erosional velocity constraints in the wellhead and coil BHA.After the first four wells, the Pin-Point technique was changed from isolation by packer to isolation by sand plugs and another four wells were targeted to further refine the technique.A summary of the well parameters is given in Table 1 with the two case study wells highlighted.

Field development planning based on integrated studies, including construction of a 3D geo-model, is an accepted standard for development of larger assets. The need to keep field development plans ‘evergreen’ is well recognized, but often difficult to realize in practice. This paper will focus on the results of a drilling campaign that followed an integrated study previously described in SPE paper 62901(Herweijer et al., 2000). As with many drilling campaigns, the results covered a range from very positive to negative outcomes. This paper will show how the result of the campaign, which was an overall success, was affected by:The modeling process, which assumed a base case with perturbations. It became anchored on a specific, optimistic, fluid contact scenario, rather than including a realistically wide range.The process of multi-disciplinary work, which, although rigorous, did not in itself guarantee that a realistic range of scenarios had been covered.Changes in team membership prior to execution of the infill campaign. This lead to a partial lack of ownership, resulting in the missing of signposts that could have lead to re-tuning the campaign by accounting for more downside scenarios.The relatively elaborate study and modeling process, which discouraged updating and hence lead to poor integration of some early negative drilling results into the model. The conclusion of the paper is that the whole study became somewhat ‘model-centric’. The model served as an unbeatable ‘truth’: trusted more than pre-model mapping, not fully connected to post-model ‘mass production’ infill drilling results, and used on problems to which it was not suited. As a result of the lessons learned we have been able to assess the real value of knowledge continuity and model ‘ever-greening’ from early stages of development through to later ‘harvest’ drilling. Introduction With the upsurge of 3D modeling as de-facto standard for integrated subsurface studies, there is much scope to address managerial issues that directly impact value delivered by development following such studies. We present a case regarding management of such a study and lessons learned for future modeling-driven development activity, and present how improvement of study management can directly impact value. This paper is a follow-up of paper SPE 62901 (Herweijer et al., 2000), which presented the results of a 3D model study of the onshore Moomba North gas field in Australia. This study was part of a larger effort of several integrated studies that were conducted in parallel at a relatively fast pace to underpin further development of a suite of gas field assets in the Cooper Basin in South Australia (Bard et al., 2000). We note that in the current high activity setting of the oil and gas industry, this fast pace parallel study approach is often practiced. The original field development plan (FDP) for Moomba North, called for 20–30 development wells, some of them clearly crestal infill wells, with others extending a fairly dense well pattern towards the flank of the field (Herweijer et al., 2000). During 2000 and 2001, a total of 32 wells were drilled in two campaigns. From the start it was recognized that drilling outcomes would be variable, and that in the end the total campaign results would be the economic benchmark.