As the exploration for hydrocarbon resources continues to move into nontraditional areas, geologists are targeting reservoir rocks not usually associated with typical sedimentary-basin settings. One such group of rocks are volcanic rocks. In drilling 10 wells in the Deccan volcanic province in the Ingoli field in the Cambay basin, all wells encountered thick sections of Deccan basalt with intermittent fine-grained intratrappeans. However, only three of the wells produced hydrocarbon. In this formation, conventional resistivity was unable to distinguish fluid saturations, so defining the hydrocarbon-bearing zones was not possible. A nonconventional and integrated approach successfully characterized the formation and the reservoir. Using image logs, together with mud logs, we defined the facies that could be productive in this basalt formation. All the geological information was used in material balance analysis to estimate possible ranges of original oil in place (OOIP). Well data, particularly borehole images, seismic attribute interpretation, geomechanical analysis, and reservoir and production data were used to understand the reservoir system, characterize the facies, and provide guidelines to delineate the reservoir. Significant uncertainties had to be addressed to ensure successful exploitation of significant remaining oil in place. A number of multibean productivity tests and pressure buildup tests were acquired. Pressure transient analysis of these well test data, when incorporated with borehole image interpretation, provided important insights in understanding the productive reservoir facies. A conceptual geological model for the Ingoli basement reservoir is developed by integrating all the boreholederived geological information with seismic and reservoir analysis. The conceptual geological model forms a basis to consider the next steps of effectively exploiting the Ingoli field. Introduction Exploration and exploitation of hydrocarbon from unconventional reservoirs pose new challenges to subsurface geologists where conventional technology and proceses may not all be applicable. Worldwide basement rocks have indicated significant oil resources, but only a small percentage (Byeonggoo Choi, et. al., 2008) have been exploited. The Deccan basement of the Ingoli field of the Cambay basin has been identified as hydrocarbon bearing volcanic reservoir. Gujarat State Petroleum Corporation (GSPC) drilled ten wells through the Deccan volcanic in the period 2003-2004 in the north-south trending ridge, called the PK high (See details in Geophysics Section), in the Cambay basin (Fig. 1). All the wells encountered thick siliciclastic sequence underlying Deccan basalt with intermittent fine-grained intratrappeans. The prime target here is fractured and weathered basaltic rock. The general stratigraphy (Fig. 2) outlines the source, reservoir, and caprock present in this part of the basin. The uplifted older basement block proved to be a potential reservoir against younger Cambay shale, which is a major source rock. The structural framework in this region is characterized by three fault trends, namely, Dharwarian, the oldest, trending north-northwest to south-southeast; Aravalli, trending northeast to southwest; and Satpura, the youngest, trending east-northeast to west-southwest. These trends define the fault system of the study area. The Dharwarian fault system is believed to be the conduit for hydrocarbon migration from source to the reservoir.
Oil India Limited's (OIL) operational areas, in Upper Assam-Arakan Basin, are located in a seismically active thrust fault zone (Bora et al., 2010). Multiple stacked layers, highly faulted anticlines and large number of compartments make the structural setting of these fields very complex. In terms of lithology, some of these reservoirs are low resistivity pays, leading to ambiguities in interpretation due to fresh water environment and complexities in evaluation of hydrocarbon-bearing and water-bearing sands (Koithara et al., 1973, Borah et al., 1998). Greater Nahorkatiya and Greater Jorajan, since the inception of commercial production in the 1950s, have been intensively studied to find prospective sweet spots, perforation intervals for new well locations and potential workover candidates. These forecasts, guided only by dynamic numerical model results, have had mixed results when implemented in the field. A validation of the dynamic model forecasts with near-wellbore saturation logs, can help to reduce uncertainty. This paper describes the success stories in field implementation of workovers, guided by dynamic reservoir model results and cross-validated with Pulse Neutron Tool (Roscoe et al., 1991, Schnorr, 1996) log recordings. The intricacy of delivering a precise dynamic reservoir model was managed by state-of-the-art seismic-to-simulation workflows, an integrated approach to improve the quality of the geological model and specific analytical techniques to fill in the data gaps. The calibrated model was analyzed for workover opportunities of zone transfer. In zones with high confidence, (i.e. high Hydrocarbon Pore Volume (HCPV), high porosity, permeability, etc., perforation intervals were recommended for hydrocarbon saturation monitoring to confirm the near-wellbore saturation predicted by the model. This workflow was followed in 8 wells which added immense value both technically and economically. The validation of model predictions with near-wellbore saturation was carried out in old wells which helped in making informed decision about tapping bypassed hydrocarbon pockets. It helped to avoid non-hydrocarbon bearing zones, which were removed from the existing workover plan. Moreover, it introduced confidence in the dynamic model which will be used in future for more aggressive economic development of the fields. This approach resulted in better understanding of the reservoir characteristics which led to identification of some potential reserves which could be characterized as "Reserve Growth".
This paper presents techniques for interpretation of Mini-Drill Stem Test (MiniDST) for establishing commingled Absolute Openhole Flow Potential (AOFP) in deep water exploration wells in India. These gas bearing reservoirs are vertically heterogeneous with high permeability. MiniDST's are conducted using the inflatable straddle packer system of wireline formation tester. A MiniDST transient sequence consists of a single or multiple flow periods, induced using a downhole pump, followed by a pressure buildup. The objectives of a MiniDST are sampling, estimation of reservoir properties such as permeability (k), skin(s), radial extrapolated pressure (p*) and estimating AOFP. AOFP is an important gas well flow parameter and is used to determine the commerciality of discovered prospects. We use a two step approach in establishing commingled AOFP of gas wells. First, we conduct a multiple station MiniDST run and interpret the data to estimate reservoir parameters (k, s, and p*). We also compute non-Darcy flow coefficient (D) using Swift & Kiel expression and then use an analytical pseudo-steady state equation to establish single point AOFP for each of the tested zones. Second, we extend routine forward modeling and incorporate features such as scaled permeability data, rock types and hydraulic flow units through interpretation of Nuclear Magnetic Resonance (NMR) and wireline petrophysics, into a model. The model is built in two different ways. One is based on numerical simulator and another based on cumulative permeability-thickness product for the gas bearing zones, using average reservoir pressure and temperature for the whole zone of interest. The success of single well simulation has given us the capability to forecast total AOFP for multiple zones using commingled approach. Furthermore, we also included production tubular and choke in our simulation model for well deliverability estimation. Our technique has resulted in immense saving in rig time and cost since the workflow allowed delivering answers which enabled us to determine AOFP without resorting to conventional four points deliverability testing. Introduction Deliverability testing of gas wells is based on theory of transient and pseudosteady flow of gases (Lee, 1982). Traditionally, different testing procedures like flow-after-flow, isochronal and modified isochronal are used to estimate parameters required to provide deliverability estimates. The turbulent or non-Darcy flow effects close to the wellbore, which appear as rate-dependent or non-Darcy skin, requires gas wells to be tested at a number of rates with the above mentioned tests so as to be able to estimate the non-Darcy flow coefficient by separating the mechanical skin component from the total skin factor (st). All these multirate methods of interpretation require well tests of quite long durations (Horne and Kuchuk, 1988). Kabir (2006) suggested a two step approach based on multirate transient drawdown tests, followed or preceded by a buildup. Firstly, he estimates reservoir parameters (k, s, D and p*) with transient data, rather than doing the traditional deliverability calculation with four points. Then he uses these parameters to predict future deliverability by forward simulations with an analytic tool.
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