The Lower Barmer Hill (LBH) Member of Barmer Hill Formation is the major regional source rock in Barmer basin of Rajasthan and has sourced nearly all the discovered fields. Our previous studies helped to identify the geochemical potential of the LBH as a shale play. Its considerable thickness (50m-800m), high organic richness (6-14 wt.%) and optimum thermal maturity as indicated by vitrinite reflectance (VRo up to 1.7%) makes it a potential unconventional shale play. However, many other questions need to be answered before exploration wells can be drilled. In this paper, we have addressed those important questions and the associated workflow for answering them, with an emphasis upon 1) delineating the prospective areas, 2) estimating prospective resource volumes in these areas, and 3) estimating the chance of commerciality. We have adopted a play-based approach to identify prospective areas in the northern part of the basin. The LBH shale was divided into two play types (oil and gas) based on thermal maturity ranges of 0.7-1.1% VR o and 1.1-2% VR o respectively. The less prospective areas were eliminated by applying global cut-offs for thickness (>30m) and TOC (>3 wt.%). Finally, the fault segments and the gross depositional environment (GDE) map guided the subdivision of each play type into play segments. A total of 8 play segments (five oil and three gas play segments) were delineated for further exploration. We then estimated the hydrocarbons-in-place and prospective resources of each play segment. Each play segment was subdivided into sub-play segment polygons based on five different thermal maturity windows corresponding to different hydrocarbon phases. The probability distribution of in-place volumes and technically recoverable resources (TRR) for individual sub-play segment polygon was generated using a reservoir hydrocarbon pore volume and recovery factor approach. Next, we compute the minimum breakeven estimated ultimate recovery (EUR) on a single well basis assuming an economic hurdle of zero NPV 10 and production type curves from North American analog shale plays. The chance of meeting or exceeding this EUR for the average well (economic chance of success or ECOS) was then computed for each sub play segment. The 1U, 2U, and 3U Prospective Resources for the play segment were estimated by probabilistically aggregating the TRR distribution of its’ constituent sub-play polygons incorporating risk dependencies. The aggregated Prospective Resources numbers and the chance of success, along with other strategic parameters, help to rank the 8 play segments to high-grade projects for exploration drilling.

Abstract The objectives of this paper are to summarize effective Reserves estimation methods for use in unconventional reservoirs, and to propose systematic procedures for classification of Resources other than Reserves (ROTR) volumes. We propose optimal timing for application of decline curve analysis (DCA), rate transient analysis (RTA), and reservoir simulation. Using these techniques, we provide results for one well from a 38-well database in the Permian Basin wells (TX USA). We then describe how the volumes are classified and categorized and how those volumes move between Reserves and ROTR as more information becomes available. We begin with the analysis of well performance, where we specify the information that is necessary for each estimation method. We then suggest procedures to identify the flow regimes using diagnostic plots, provide guidance on the application of multi-segment DCA models, and finally suggest procedures for the application of RTA and reservoir simulation. We continue with progress toward Reserves classification, starting with suggested procedures to reclassify Prospective Resources as Contingent Resources (upon discovery). We provide post-discovery guidance on development and commerciality for the project maturity sub-classes (within the Contingent Resources classification). We explain that “established technologies” must be technically and economically viable before they can be used for development decisions. And finally, we examine requirements to remove contingencies so that the volumes can be reclassified properly as Reserves. Our major suggestions for well performance analysis are, first, that the multi-segment DCA approach is most effective in unconventional reservoirs when specifically relevant models are used for transient flow and boundary-dominated flow. Furthermore, we suggest that RTA using analytical models expands possibilities of forecasting for changes in well conditions and for well spacing studies. Though time and computationally time consuming, compositional simulation is required for confident analysis of near-critical reservoir fluids. For movement of resources toward Reserves, we suggest that there is no linear path to define the movement from Prospective to Contingent Resources, though there are certain criteria which must be met for a given project. Certain contingencies, such as price of oil and available technologies, dominate the classification of resource volumes. This paper provides a visual representation of when to use each Reserves estimation method depending on available data. We present a thorough analysis of best practices for each Reserves estimation method. We provide graphical representation of the movement between Prospective to Contingent Resources categories, the progression in chance of development and commerciality within project maturity sub-classes for Contingent Resources, and the contingencies that must be resolved to move from Contingent Resources to Reserves. Finally, we present an explanation of the criteria that must be met before volumes can be reclassified and/or recategorized from undiscovered to discovered.

Abstract The Kidson Sub-basin lies within latitudes 20°S and 24°S and longitude 123°E and 128°E and is one of the depocentres formed during the development of the Canning Superbasin in the Early Paleozoic in Western Australia. Hydrocarbon discoveries have been made over the years in some parts of the Canning Superbasin but none in the Kidson Sub-basin. This report evaluates the prospectivity of Kidson Sub-basin for unconventional hydrocarbon resources. The Kidson Sub-basin has a sedimentary section thickness reaching up to over 7000m, mainly of Paleozoic age. Using the available well data three unconventional shale gas plays within the Goldwyer, Bongabinni and Noonkanbah shales are interpreted to meet all the necessary requirements for hosting shale gas accumulations. A pseudo-well modelled near the centre of the Kidson Sub-basin shows that the organically-rich Noonkanbah Formation is mature enough to generate gas and 1-D modelling of the Kidson-1 well indicates that both the Bongabinni and Goldwyer Formations are also presently in the gas window. The prospective resources of the unconventional shale plays are estimated using geochemical approach. The Goldwyer Shale is estimated to contain potential gas in-place (GIIP) of about 13.4TCF over the most prospective area of Kidson Sub-basin estimated to be around 567 km2. The Bongabinni Shale is organically-rich and about 324 km2 is estimated to be prospective in the Kidson Sub-basin. About 205 km2 is estimated to be prospective in the centre of Kidson Sub-basin where Noonkanbah Shale is deeply buried to a depth up to 1600m. The three shale plays have mid range gross prospective resources of 31.0 TCF of gas. The current skilled labour shortage in Australia may pose a big challenge in shale gas production as this will lead to higher drilling costs compared to those of United States. In addition, Kidson Sub-basin is a desert and water scarcity will be another challenge for shale gas production since water is required for fraccing.