Well Test Analysis in Tight Gas Reservoirs

Abstract

Abstract The increasing global energy demand, rising energy prices and declining conventional gas reserves all call for increasing exploitation of gas reserves from unconventional sources, most notably gas trapped in tight formations. This study describes an investigation of some of the key issues related to well test interpretation in tight gas condensate formations, which are often overlooked or ignored. A single-well radial model was constructed with measured rock and fluid properties using ECLIPSE300. This compositional simulator was used to generate synthetic pressure transient data which were subsequently interpreted in PanSystem welltesting package. The impact of test duration (drawdown, buildup), phases present (gas, condensate), type of fluid system (lean, rich) and reservoir heterogeneity (homogeneous, layered) were investigated. The results indicate that in the absence of wellbore storage effects, a short drawdown period ensures that a short buildup is sufficient to compute reservoir parameters from radial flow regime. For long drawdown periods, the subsequent buildup period can take months to reach infinite-acting radial flow. The time needed to dissipate layering effects (such as a high-perm streak) is frequently excessively long in tight reservoirs. Also, a number of simulations with and without rate-dependent relative permeability curves were performed to investigate the positive impact of velocity (coupling effect) on two-phase skin due to condensate banking. The results reveal that the conventional two-phase pseudo-pressure function results in more difficult interpretations for obtaining reservoir parameters and is also unable to capture the positive coupling, which is more pronounced than negative inertia especially for richer fluid systems. Finally, the application of the probe radius concept yielded remarkably accurate reservoir pressure profiles versus distance as compared to those obtained by compositional simulations. This data could be used to calculate reasonably accurate rate-dependent relative permeability curves, thus improving long-term well deliverability predictions. Introduction Worldwide increasing energy demand, raising of energy prices and declining hydrocarbon reserves in conventional natural gas reservoirs all point to the increasing exploitation of gas reserves from unconventional sources, most notably gas trapped in tight (low permeability) formations, which is made technically viable by present day drilling and completion technology. Onshore conventional natural gas production is decreasing as opposed to a solid incremental production coming from unconventional resources; the forecast for unconventional gas production in 2030 is some 9.5 Tcf (EIA 2008). Tight gas is the term commonly used to refer to formations with a permeability of about 0.1 md or less but it should be emphasized that in reality there is no such thing as a "typical" tight gas reservoir (in terms of a specific permeability value) since the flow performance depends not only on permeability but also on other reservoir characteristics such as thickness and initial pressure. Despite lacking a formal definition, in the context of this study a tight gas reservoir will be considered to have a permeability of the order of 0.1 md.