The DW Turbidite field in Deepwater Nigeria has limited SCAL data on drainage capillary pressure curves used, traditionally, in building saturation-height functions for application in 3D static and dynamic models. An alternative approach to derive capillary pressure curves from Nuclear Magnetic Resonance (NMR) T2 distributions, developed by Volokitin et al, has been tested in one of the key reservoirs in the DW Turbidite North field and compared to mercury injected capillary pressure (MICP) data from a full-bore core across the reservoir. The alternative approach relies on an underlying assumption that a relationship exists between porebody radius (as represented by the NMR T2 distribution) and pore-throat radius (which drives capillary behavior). An algorithm has been applied that uses a T2 cutoff such that the sum of the bound and moveable fluid spectra amplitudes matches the water porosity to correct for the presence of hydrocarbons. The hypothesis is the resulting relationship (between the NMR T2 distribution and pore-throat distribution) embedded within a proportionality parameter, κ. The hypothesis was tested on the three key facies (CSA - Channel Storey Axis, CSM - Channel Storey Margin & ICTB - Inter-Channel Thin Beds) identified in the reservoir. Field-specific proportionality parameters were determined from which NMR T2 capillary pressure curves have been derived. Comparison between the derived capillary pressure curves and the SCAL (MICP) data provide confidence that this technique can be applied in the absence of SCAL data.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractConventional resistivity analysis has been used for evaluation of hydrocarbon saturation in both exploratory and development wells. Resistivity logs are however not sufficient for performance of a fluid characterization because resistivity cannot detect variation in hydrocarbon densities. As a result, additional logs such as nuclear, sonic and nuclear magnetic resonance logs are required to perform a satisfactory evaluation of hydrocarbon fluid typing and saturation computation. This paper focuses on recommended best practices for combination of behind casing resistivity measurements and complementary logs in matured fields for evaluation of hydrocarbon/water contacts, detection of by-passed reserves and fluid typing.An example from the eastern Niger Delta shows where cased hole formation resistivity results were optimized with pulsed neutron spectroscopy measurements in performing a successful workover program and improving production rates by over 80%
XY is a deepwater turbidite field with potential untapped volume opportunity estimated at~100MMbbls residing in Inter-Channel Thin Beds (ICTB) facies. Quantitative interpretation of Production Logging Tool (PLT) data was performed using commercial production log interpretation software to accurately quantify contributions to total flow and flow potential of the ICTB facies. The PLT data was acquired pre-production across two ICTB dominated "A" and "B" reservoirs in the XY-P well during a production test at flow rates of 5,000 and 12,000 bbls/day. The PLT evaluation result was calibrated using production test data. This paper demonstrates the application of a simple workflow to estimate the flow potential of ICTBs from conventional PLT data. The results suggest ICTBs have significant potential to flow at economic rates. The interpretation also demonstrates producibility of ICTB at relatively high Productivity Index (PI) at flow rate above 12,000bbls/day. Intuitively, one can infer that though the flow potential of ICTB is lower than Channel Storey Margin (CSM) facies, ICTBs could become potential producers in the XY Field if produced standalone at relatively high drawdown.
The success of any green as well as mature field development planning and execution lies in the ability to recreate the environment of deposition with the appropriate spatial and temporal facies interdependencies. This, when done with proper application of the varied suite of geotechnical software/knowhow, often leads to the creation of a finite number of high resolution and equiprobable reservoir models within a macro and micro sedimentological framework, that readily lends itself to optimized risk and uncertainty management. This becomes even more critical in deepwater turbidite systems where the impact of geologic uncertainties can significantly reduce project value and does often prevent marginal field developments in the absence of a low cost tie-in option.This paper presents the novel application of one such technique; the QuantiMin methodology approach improves aspects of reservoir characterization and facilitates various aspects of well and reservoir management in the waterflood development of a Miocene deepwater turbidite system in the Gulf of Guinea.The QuantiMin technique is a sequential quadratic program that solves non-linear problems by series of quadratic programming steps. When applied in this context, it assesses the mineral and fluid content around the near wellbore area, based on their unique well log responses, and returns with a finite volume distribution of mineral and fluid distribution around the wellbore, using the mineral and fluid distribution input from appraisal well cores as the calibration or control variable.The results from QuantiMin analysis have been used in this field to: • Evaluate the potential impact of mineralogy on the performance of water injection wells. • Apply understanding of mineral types around the wellbore to the design of acid stimulation recipes. • Develop a framework for understanding the field scale distribution of heterogeneities by establishing the interdependencies between log-scale QuantiMin and microscopic core petrography data, and hence facilitate high resolution reservoir characterization. • Establish realistic flow potentials for development wells.
The Ajanla field is a deepwater turbidite field located offshore Nigeria. PLT data acquired across two turbidite "A" and "B" reservoirs in the Ajanla-P well before production commenced in the field demonstrated flow potential of the reservoirs at a proportion of 85% | 15% and 100% | 0% drainage contribution at flowrates of 12,000 bbls/day and 5,000 bbls/day respectively. New infill drilling results and 4D seismic data acquired several years after production commenced have provided significant insight in the sweep pattern in the reservoirs. The 4D seismic data has indicated strongly channelized sweep in reservoir "A" but negligible pressureand saturation changes in reservoir "B". This interpretation was further verified by the results of the in-fill wells which showed low remaining hydrocarbon saturations in "A" but near virgin saturations in "B" after five years of commingled production from both reservoirs through Ajanla-P. This paper investigates the interplay of several factors such as well completions integrity and water injection constraints critical to effective development of turbidite reservoirs and also discusses how the various data sources were integrated to improve understanding of the dynamics between reservoirs "A" and "B" and their possible impact on the future development of the reservoirs.
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