Reservoir-Fluid Characterization From Tests on Tight Formations

Abstract

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164887, ’Reservoir-Fluid Characterization From Tests on Tight Formations,’ by Brian Moffatt, Michael Fawcett, Jaimar Maurera, and Anna Bruzco, Petrophase, prepared for the 2013 European Association of Geoscientists and Engineers Annual Conference and Exhibition incorporating SPE Europec, London, 10-13 June. The paper has not been peer reviewed. Drillstem testing of low-permeability reservoirs is challenging because high-pressure drawdown around the wellbore lowers fluids below saturation pressure and creates two-phase flow into the wellbore. The fluids produced at surface no longer represent the original reservoir fluid. This paper shows the benefits of a careful methodology of data selection and equation-of-state (EOS) modeling to validate data used to characterize the reservoir fluid. Introduction There are significant technical difficulties in capturing representative fluid samples from tight formations. Attempts to flow to surface from tight formations induce a fall in pressure around the well-bore that may take the reservoir oil or gas below its saturation pressure. Two-phase flow in the wellbore can cause significant errors for sampling downhole, although surface sampling can be less prone to error. However, because the gas within the formation is more mobile than liquid, the surface gas/oil ratios (GORs) are higher than those of the native fluid. This can lead to erroneous assumptions about the reservoir fluid if the separator samples are recombined to the prevailing GOR without reference to what is happening in the reservoir. Two case studies are presented that resolve apparently conflicting data and use a wider range of well-test data than single data points to define reservoir fluids. Neither study had the benefit of downhole pressure/depth gradients to corroborate reservoir-fluid properties. Characteristic Test Results for Tight-Formation Drillstem Tests (DSTs) DSTs performed where the flowing bottomhole pressure (FBHP) stays above saturation pressures are ideal for surface sampling or for taking bottomhole flowing samples. However, the low deliverability of tight-formation wells often makes it difficult to establish stable flowing conditions. The FBHP, flowing well-head pressure, and separator conditions may all be unstable, causing difficulties in establishing the correct GOR even when the total wellbore composition is constant. A further complication can arise if the gas rates are too low to lift liquids to the surface. GORs for bottomhole samples (BHSs) are measured in the laboratory by flashing the sample to specified conditions. The same wellstream composition sampled at the surface will normally have a lower GOR because separator conditions favor an increase in stable liquid volume. Surface and bottomhole GORs will match only under identical flashing conditions. Typical GOR characteristics for BHSs and surface samples for a tight formation containing oil are shown in Fig. 1.