RTA Workflow: A Critical Review

Abstract

Abstract Rate Transient Analysis (RTA) software encapsulates the standard approach used to extract useful completion and reservoir parameter estimates from shale reservoir production data (rate and pressure versus time). The standard well/reservoir model used in analysis software assumes that flow from the reservoir pore volume outside of the fracture tips can be ignored and, hence, the model exhibits two main flow regimes in the well response. The first of these is the formation linear flow regime which can be analyzed using a ‘linear flow analysis’ plot to obtain an estimate of A*k1/2. Here, A is the effective total fracture area and k is formation permeability. If k can be estimated then A can be used to back calculate an estimate of effective fracture half-length, xf. The second of these flow regimes is the SRV- Boundary dominated flow regime which theoretically begins at the point when the linear flow regime ends. In practice, the data in this flow regime is analyzed on a ‘flowing material balance analysis’ plot to obtain an estimate of the amount of gas originally in the SRV volume, i.e. SRV OGIP. In general, industry standard RTA software couples the two analysis plots to obtain an estimate of xf first and then an estimate of k. The SRV OGIP is used to backcalculate an estimate of effective xf with user defined well length, rock and fluid properties. With xf fixed, a value of A can be calculated with user defined input for the number of fractures intercepting the well, N. The value of permeability can then be obtained from the results of the linear flow analysis plot. The coupling of these plots to obtain a complete analysis of the production data (estimates of k, xf and SRV OGIP) introduces some difficulties since the choice of the time to the end of linear flow on the ‘linear flow analysis’ plot impacts the shape of the data on the ‘flowing material balance analysis’ plot. The purpose of this study is to examine critically this approach and develop some understanding of when it can be expected to be successful. To that end, a systematic study was designed to obtain representative simulations of production data responses from the three main types of shale reservoirs that dominate the BP unconventional shale reservoir portfolio. These types are dry gas with and without associated free water production (Haynesville type), volatile oil with associated free water production (Permian type) and gas condensate with associated free water production (Eagle Ford type). In addition to these fluid property and reservoir flow types, three fracture geometry configuration have been considered. The first configuration reflects the standard model used in RTA software. In this configuration all the fractures are sysmmetric bi-wing fractures with uniform spacing along the well. Each fracture has the same fracture half-length, xf. The second configuration is similar to the first except fracture half-length varies from one fracture to the next. The third configuration is the most general. In this configurations, fracture half-length varies from fracture to fracture, spacing between the fractures varies and the fractures are not sysmmetric bi-wing completions. In all of the cases studied, flow contribution from beyond the fracture tips, i.e. fluid influx from pore volume outside the SRV, is included. The CMG β (black oil) model has been used throughout as the chosen simulation tool for the Permian type well responses (oil/water). The dry gas and gas condensate simualtions were done using CMG GEM. Analysis of the various production data simulations have been done in Harmony RTA focusing on evaluating the effectiveness of the standard work flow, establishing what can actually be extracted from the analyses and improving on the analyses, where possible. The major conclusions justified by the work documented here are: Formation linear flow (FLF) analysis can be done accurately on data from single phase gas producing wells and for data from wells producing hydrocarbon and water if well pressure is above fluid saturation pressure. The new equations required for successful FLF analysis when the data comes from wells producing hydrocarbon and water above fluid saturation pressure are derived and presented.Picking the end of the FLF regime consistent with the well/reservoir configuration simulated cannot be done accurately if flow from beyond the frature tips is included. This yields the observation that the flowing material plot does not generally give a good estimate of SRV volume.