Although the Palaeocene-Eocene reservoirs of the Assam shelf have been prolific producers of oil and gas, the production profiles of various fields have caused concerns because of their departure from the geological model originally envisaged. An attempt is made to understand the temporal and spatial reservoir heterogeneity within a broader depositional model framework using microresistivity image and open hole log data from four fields in the assam Shelf; Baghjan, Katahloni, Bhogpara and Nahorkatia. Using image data, whole cores, dip patterns, openhole logs, image derived neural network facies and image derived textural facies, the key reservoir facies associations are identified. Facies associations in different wells are made use of to reconstruct depositional sequences, which enable to conceive a broader depositional model for the sedimentation of major Plaeocene to Eocene formations, namely Langpar, Lakadong, Narpuh, Prang and Kopili.This study infers marginal marine to coastal plain channelized sedimentation for the Langpar formation with reservoirs likely to be oriented in a NW-SE to E-W direction. These basal clastics are overlain by lagoon-barrier island to coastal plain channel environment of the Lakadong formation with reservoir orientation along E-W to NW-SE direction. Beach-strand plain to chenier plain depositional environment is encountered in the Narpuh formation with the reservoir appearing to have an extension along N-S to NW-SE direction. Overlying Prang and Kopili formations are inferred as restricted marginal marine deposits. The Prang shows occurrences of carbonate facies whereas the Kopili shows feeder channels facies of thick argillaceous sequence. Overall, the Eocene-Oligocene petroleum system seems to have been deposited in a marginal marine depositional setting. Analysis of depositional units in a sequence stratigraphic context suggests that the overall sequence has evolved in a transgressive system. Using a sequence stratigraphic framework allowed us to better define reservoir distribution patterns of the Assam Shelf, and these facies associations may prove useful in future reservoir modeling studies. SPE 128668 Conclusions1. Beacuse the seismic resolution is coarse in these deep seated formations, depostional sequences were reconstructed using microresitivity imaging tool which in turn helped to understand likely reservoir facies distribution in the field. Coastal plain channel sand of Langpar formation likely to have reservoir extension in E-W to NW-SE direction.Langpar sand is moderately sorted, capped with coastal plane shale which are highly calcretized in Bhogapra and Kathaloni field. 3. Lakadong sands evolved through lagoon-barrier island time tarnsgressive sedimentation. Lagoon-barrier island sand facies of the Lakadong seem to extend along shoreline strike in the E-W to NW-SE direction. However, few ebb-tidal flood channel may be oriented oblique to this. The Lakadong member appears to contain a complete petroleum system (lagoon shale as source and seal whereas Barrier Island ...
In this era of cutting-edge technology where stochastic and geostatistical modelling is the order of the day, conventional layer-cake modelling for highly heterogeneous reservoirs in two fields have yielded very good results. The performance predictions of reservoir simulation studies based on the conventional geological model of these fields are in close conformance with the actual production behaviour thus substantiating the efficacy of such type of modelling. The results of these studies recommended that additional wells be drilled for augmenting production and recovery. Mapping of advancing edge-water front from simulation based on the 3D seismic derived geological model helped in optimal positioning of the development well locations. Although the role and accuracy of geostatistical and stochastic modelling can not be denied, conventional layer-cake modelling, within certain limitations, is a fairly reliable and cost-effective reservoir characterization tool. Introduction The two fields under study viz. Dikom-Madarkhat and Kathaloni-Bachmatia, discovered in 1990–91, are prolific producers and have their hydrocarbonaccumulations in thin, layered reservoirs inter-bedded with shale/mudstone of Eocene sandstones in Assam-Arakan geological province of North-East India. The production from these two fields presently account for around 25% of the total production (8400 tonnes/day) of the company. The basic objective of these studies was to build dynamic models to chalkout optimum field development plans and assess alternative exploitation schemes subject to their financial feasibility. Due to the heterogeneous nature of the reservoirs, sand-to-sand correlation was a major challenge and the problem was aggravated by sparseness of conventional cores, PVT and pressure transient survey results. However, the best possible correlation using 3D-seismic data, well logs, pressure-production and available well test analysis data was established for constructing the geological models which were eventually subjected to fluid flow simulation. This paper deals with these two case studies where conventional geological modelling for reservoir characterization was resorted to and satisfactory results were obtained thereof. Dikom-Madarkhat Field — Field Overview The Dikom-Madarkhat-Kuhiarbari oilfield established commercial oil production for the first time from the Lower Eocene formation in Upper Assam in April 1990 with the drilling of well N-438. Madarkhat, a satellite structure of the Dikom main structure and located in its south-west vicinity, was identifiedon the basis of close-grid 2D seismic data acquired during 1991–93 and commercial oil was discovered in well M-1 drilled in 1996. A review of close-grid 2D seismic data in Dikom-Madarkhat area revealed that Madarkhat structure is connected to the Dikom structure by a narrow north-south trendingridge. As seen from Figure 1, Kuhiarbari is another satellite structure developed to the east of Madarkhat structure with a minor intervening saddle.The first well Kuhiarbari 1 was drilled during October-November 2000 and produced clean oil on testing. A pressure transient survey carried out in December 2000 in this well indicated pressure level similar to that of D-15(360–365 ksc). The initial pressure in this well was of the order of the pressure of N-438 Block thus indicating communication with the main Dikom-Madarkhat structure. Till date, a total of 22 wells have been drilled in the Dikom-Madarkhat-Kuhiarbari field of which 18 wells have been completed as producers. Wells D-4 and 11 did not encounter any commercial hydrocarbon prospects whereas D-1and D-5 could not be completed as oil producers due to blowout and casing related downhole problems respectively. The remaining 16wells are currently producing at a total rate of around 1380 m3/daywith about 40% water cut.
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".
High angle S-shaped and high displacement L-shaped well profiles are preferred now-a-days in Balimara field located in the northeast region of India. Main targets are the deep Clastic reservoirs of Oligocene age. Major events reported are while drilling against dipping formations with differential stuck pipe situations with variety of drilling complications in the unstable formations owing to shales in Tipam sandstone and thin sections of coal and shale alteration in oil bearing Barail sandstone formation. The substantial risk of wellbore instability in accessing the reservoirs with lateral variation in pore pressure threatened the commercial success of the project. This paper elaborates how geomechanical information along with BHA design and chemicals was integrated into the decision-making process during well design and drilling operations to avoid wellbore instability issues. Wellbore stability analysis through Mechanical Earth Model was conducted using estimated state of stress and mechanical properties of the overburden and reservoirs. The model incorporated data from several sources including geophysical logs, leak-off tests, advanced sonic far field profile and drilling records collected from the earlier wells. Examination of the deviated well bore profiles suggested occurrence of ledges due to lower mud weight and improper drilling parameters while drilling alternate layers of sand, shale and coal in Barail formation. Horizontal stress contrast increases in Barail formation supporting the need of higher mud weight with increased well deviation towards specific azimuth. The integrated geomechanical analysis provided key information: The 9 5/8" casing shoe should be set at shale layer of Tipam Bottom to isolate upper differential sticking prone sandstone layers with Barail Argillaceous sequence. This will help to drill 12.25-inch hole with 9.6 ppg-9.8 ppg only. Shale layers at Tipam bottom require 10.0-10.5 ppg, while Barail shale requires 10.5 ppg-11.0 ppg for vertical well. When the well deviation increases up to 30deg, mud weight requirement rises to 11.2 ppg-11.8 ppg. Based on analysis, the mud weight at the start of 8.5inch section was raised sufficiently to 10.5 ppg to avoid the hole collapse experienced in the earlier lower angle wells. Later, continuous review of torque and drag along with cutting analysis helped to raise mud weight up to 11.0 ppg till well TD. As a result, lower UCS shale and coal layers are drilled with minimal shear failure and improved hole condition. However, changes to the mud system were needed to limit fluid loss and avoid differential sticking across the sandstone. For deviated section, rotary BHA has been used to improve hole trajectory vs. planned with lesser ledges. Downhole hydraulics has been maintained with proper flow rate and rpm to main hole cleaning. The new well engineered with the integrated geomechanics information has been drilled from surface to extended TD while saving 15 rig days.
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