Fluid Profiling for Reservoir Evaluation: Norwegian Case Studies

Abstract

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166204, ’Fluid Profiling for Reservoir Evaluation: Two Norwegian Case Studies,’ by Thomas Pfeiffer, Schlumberger; Vincent Kretz, BG Norge; Daniel Opsen, Wintershall Norge; and Vlad Achourov and Oliver C. Mullins, Schlumberger, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. Recent advances in sensor technology and petroleum science allow using downhole-fluid-analysis (DFA) data to improve confidence in reservoir architecture. New independent work flows are especially valuable when used in concert with pressure/volume/temperature (PVT) reports, well-test data, static-pressure gradients and other common techniques used to assess reservoir architecture. This paper presents two real-field case studies from the Norwegian continental shelf that use available DFA data to support the assumptions made from other data on reservoir architecture between wells. Introduction A valuable plan to manage subsurface uncertainty assesses the effect of fluid properties on the project execution. Understanding the fluid properties and their vertical and lateral distribution will elucidate quality and continuity of the discovery during the exploration-and-appraisal phase and extend into deciding on development options. The fluid distribution in the reservoir is a function of source-rock material, migration path, charge history, charge mechanisms, processes working toward fluid equilibration and disequilibrium, geologic setting, burial history, reservoir architecture, and timing. Therefore, an interdisciplinary approach is necessary to make use of the information contained in the fluid distribution to constrain the understanding of processes that affect production. The level of confidence rises with the data quality and data availability. Acquiring high-quality data to map spatial variations of fluid properties across the field is an integral part of this methodology. Stratigraphy and structure analysis, static-formation-pressure surveys, mud-gas analysis, isotope analysis, oil geochemistry, and solution-gas geochemistry are routinely used to assess compartmentalization. However, in spite of this array of methods, unrecognized compartmentalization remains one of the leading causes of production underperformance in the industry. A successful new method to address this issue is to assess if reservoirs fluids are equilibrated; if so, then reservoir connectivity is indicated. In particular, fluid compositional equilibrium is orders of magnitude more stringent than pressure equilibration in revealing reservoir connectivity. Moreover, it is now possible to determine independently whether gas/oil-ratio (GOR) gradients and asphaltene gradients are equilibrated. Specifically, the application of new asphaltene science in new wireline work flows allows the assessment of fluid equilibrium on the basis of the suspended solids in the oil: the asphaltenes. This new approach is based on different physics than is the industry standard of assessing the solution gases in oil. Frequently, it is the asphaltenes that provide the best method of analysis of reservoir connectivity. The case studies in this paper show the application of this new methodology in real-field examples. For a discussion of the theoretical work behind the new work flows using DFA data to assess asphaltene gradients, please see the complete paper. Case One The operator drilled a discovery well and an appraisal well on the Norwegian continental shelf within a distance of approximately 2 km of each other. Fig. 1 shows a model of the reservoir setting. One sample and DFA station were acquired per sand, giving three data points in two wells. Oil-based mud-filtrate contamination varies from 3 to 6 vol%. The discovery well encountered oil-down-to in the upper sand. The lower sand was water bearing under a slightly higher aquifer pressure compared with the appraisal well. The appraisal well encountered oildown- to in the upper sand and an oil/ water contact in the lower sand. Static formation pressure found the upper sand in the appraisal well to be 1.2 bar lower than the upper sand in the discovery well. The aquifer pressure in the lower sand south seems to be slightly elevated. The 1.2-bar difference between the top two sands is unlikely to reflect DST-related depletion. Subseismic faults are suspected to be the reason that the drillstem test (DST) indicates boundaries close to the well.