Permeability log is the main input required to deliver 3D reservoir property which alongside other properties are used for reservoir simulation to estimate recovery factor, reservoir connectivity, flow units, barriers, baffles and production profiles. This underscores the importance of this parameter which can be obtained mainly from core analysis, nuclear magnetic resonance (NMR), stoneley (sonic), well testing (DST), wireline formation tester, petrophysical evaluation of rock properties and mineralogy. Amongst these approaches, log based permeability estimation has over the years received consistent embrace due to robust measurements that provide permeability information at relatively small sample rates, which account for minor heterogeneities unlike conventional approach of large scale core based approximations. However, the need to ensure accuracy of log based measurements have drawn wide attention and many analysts have taken steps to validate log based permeability results with core data, formation tester and well test analysis results. Permeability characterization for two reservoirs in the Lower Congo Basin offshore Angola was done using log based measurements from basic triple combo and LWD spectroscopy measurements, mobility estimation from sonic alongside formation tester samples, SCAL analysis and well testing results. This paper presents the workflow for evaluation, integration and comparison of permeability from various sources, highlighting challenges and sources of error in the approach.
Deep-water offshore exploration has revealed increasing discovery of unconsolidated and under-compacted reservoirs characterized by high porosity and permeability. Formation evaluation becomes challenging since conventional drilling practices adapted for this environment often results in near-wellbore alteration which can reach deeper into the formation due to relatively low competency of the rock. This characteristic is observed for almost all the deep-water Miocene-Oligocene turbiditic sands across the globe. The concept of near-wellbore damage is a well-known topic, however, its implication in deep-water exploration and production is being studied now in great detail. Measurements of properties like mobility and formation-fluid attributes have been jeopardized by fines migration, damage and alteration. The effect of near wellbore deformation causes development of skin and stiffness change that has a strong impact on formation fluid sampling and pressure acquisition. Multi-pole multi-array sonic acquisition has shown that damage causes variation of sonic-velocity in the radial direction that could be identified and quantified with the current technology. Innovations in Nuclear Magnetic Resonance (NMR) with greater depth-of-investigation (DOI) and radial-imaging and interpretation techniques indicates that the concept of fines migration causes considerable effect on formation permeability and porosity estimation and has a critical impact on reserve estimation. The current work focuses mainly on two aspects of wellbore alteration on measured logs. First, effect of alteration has been identified by using multi-DOI NMR and sonic measurements in an integrated manner. Secondly, and subsequently, quantification of the damage was measured along with its impact on other measurements like formation-tester. This integrated technique can significantly and efficiently reduce formation sampling duration by locating damaged-zones and effectively reduces acquisition cost in a complex deepwater operation. The implication of identifying the damaged zone has a great value in designing optimum completion and sand management and exclusion technique at the subsequent stages of development.
Characterization of complex Cretaceous reservoirs of offshore Angola, Lower Congo basin, poses similar uncertainties of evaluating carbonates in other parts of the world. The formation is a mixture of clastics, with carbonates at varying fraction that changes with depositional environment. With horizons of complete carbonates and fraction of dolomite and anhydrite, it poses a real challenge to any Petrophysicist engaged in evaluation of these oil bearing formations. The primary evaluation problem becomes even more complicated with porosity related issues since the primary oil reservoirs in general fall in the carbonate sections with moderate porosity and with varying secondary porosity like vugs and occurrences of fractures at different intervals. There is often a significant difference in permeability between testing results and those estimated from formation evaluation results or computed from formation tester data. These observations have also been verified with core results. A need for integrated evaluation could therefore be easily reckoned, with proper matrix evaluation to generate a better estimation of intergranular porosity and a complementary method for accurate estimation of secondary porosity from vugs, and then incorporating the results to generate a more realistic permeability. Apart from evaluation challenges with conventional logs, the drilling mud system and logging dynamics generates some environment effect on the acquired data which impedes the efficient use of the data. Photoelectric factor is an important measurement in complex lithology, but its accuracy is very sensitive to mud systems and to borehole rugosity. The method of estimation of carbonates based on elemental yields from the new generation elemental logging devices has evolved significantly and in recent years magnesium can be separated out of the concentrations to provide a major input for estimating dolomitic fraction out of total carbonate in the formation. The remaining issue of porosity partitioning has been developed since 1995 with the incorporation of nuclear magnetic resonance (NMR) data. For carbonates, the porosity systems were assumed in a completely different way to accommodate the larger vugular fraction in the evaluation schemes. This new approach has been generated based on the knowledge and experience acquired in evaluating carbonates throughout the world. The approach in estimating permeability therefore takes advantage of the computation of vugular pore fraction from NMR. The recent technique provides significant accuracy while correlating with other answers from testing and core results. Improvement of the results depends on the data acquisition and uncertainty can be reduced by proper planning. The acquisition for the current case was forced to a limit since the drilling was carried out with very saline mud. Although, higher salinity for mud and formation water is always environmentally challenging to logging, a proper approach in cancelling the effect of borehole chlorine can generate very reasonable log quality. In the current analysis for Pinda carbonates, the authors utilize the carbonate-dedicated workflow comprising of elemental spectroscopy and nuclear magnetic resonance data acquired in an offshore well. Integrating all data and information with a proper workflow, realistic estimation of permeability was possible with a rock typing framework based on calibrated porosity partitioning.
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%
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