TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA new generation of sampling technology is introduced which allows a Wireline Formation Tester to sample reservoir fluids in open-hole with levels of filtrate contamination that are below measurable limits, in many cases. Furthermore, the time required on station to cleanup before sampling is significantly reduced compared to conventional sampling methods.Formation fluid sampling has always been adversely affected by mud filtrate contamination, which introduces errors into the laboratory analysis and requires analytical methods to backcalculate the measured properties to the uncontaminated reservoir fluid. The ability to secure a totally clean sample of formation fluid at reservoir conditions is a significant advance, that replaces the need for sampling during Drill Stem Tests and provides accurate fluid information for characterization of the reservoir, flow assurance, facility design, production strategies, and defining reserves.The application of this new focused sampling technology is presented using four case studies from wells drilled on the Norwegian Continental Shelf. A wide range of formation fluids and permeabilities are examined, in both oil-based and water-based drilling fluids. Results from focused sampling are compared directly with conventional sampling in the same reservoir zones. This study also gives insight into the cleanup dynamics of invaded filtrate, and explores the different factors that affect performance of the focused sampling technique.An important consequence of negligible contamination is the ability to accurately measure fluid properties in-situ. And reduced cleanup time allows for multiple zones to be scanned efficiently. Downhole Fluid Analysis (DFA) can thus be utilized to reveal reservoir architecture that is unable to be determined by traditional wireline logs.

Reservoir fluids often show complex compositional behaviors in single columns in equilibrium due to combinations of gravity, capillary and chemical forces. Frequently non equilibrium or non stationary state conditions are also encountered, for instance due to thermal forces acting. Recognizing these behaviors downhole is a complex process that requires a greater number of data points, fluid samples and associated laboratory analysis. Pressure gradients with wireline formation testers are traditionally used to evaluate fluid density, fluid contacts, and layer connectivity in exploration settings. This information is today supplemented by downhole fluid analysis (DFA) measurements to reveal possible reservoir fluid heterogeneities. Although these fluid complexities have been largely recognized, conventional pressure-depth plot and pressure gradient analysis are still performed with traditional straight line regression schemes. This process may however be misleading as fluid compositional changes and compartmentalization give distortions in the pressure gradients, which lead to erroneous interpretations of fluid contacts or pressure seals. Hence the models imposed on the pressure data to calculate pressure gradients need to incorporate a rigorous mathematical approach to respect all data available, so as to follow an objective assessment of reserves and reservoir architectures. This paper presents a method to use combined repeated pressure and in-situ fluid measurements to provide a simple model of vertical fluid distributions, looks at the different regression schemes that can be imposed on pressure data to calculate fluid gradients with their associated uncertainties and concludes on an optimal fit approach. This data integration then allows making assessments and quality control of the different measurements and conclusions about the relevant reservoir heterogeneities. The method is illustrated with a published case study [1] from a North Sea appraisal well, where a large compositional gradient has been observed with in-situ fluid measurements. An equation of state is elaborated from a sample and its PVT experimental results, and a compositional gradient is parametized using the DFA observations at the different depths. A polynomial fit is then given to the distributed pressure measurements and the obtained fluid density variations are compared to the fluid model ones. Introduction Recently developed wireline technologies involving downhole fluid analysis measurements through optical spectroscopy, refractometry and fluorescence, have shown how to reveal non homogeneous fluid distributions in reservoirs [1], [2]. Light and near critical reservoir fluids often exhibit significant continuous variation of hydrocarbon components with depth. This has been illustrated in the literature [3], [4], [5]. With increased drilling in HPHT (high pressure, high temperature) and deep offshore settings, more and more fluids with complex phase behavior are met. Crossing the phase envelope of a hydrocarbon fluid mixture, although often unpredictable in the reservoir, is common: saturated oils are accompanied with a phase transition and a gas cap in the reservoir. Interestingly also, pressure and temperature ranges of 350–400 bars and 80–100C are close to critical temperature of mixtures of hydrocarbons in several settings. Near critical fluids are then encountered and their description and volumetric behavior is complex. When a critical transition exists in the reservoir, the fluid column then changes from a bubble point fluid to a dew point fluid without encountering a fluid meniscus or contact. Further anomalies may arise also because these reservoirs may possibly not be in thermodynamic equilibrium, but still undergoing for instance a flux from the source rock, where the lighest components, such as methane, tend to diffuse faster. This has been shown by Montel et al. [3]

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA new generation of sampling technology is introduced which allows a Wireline Formation Tester to sample reservoir fluids in open-hole with levels of filtrate contamination that are below measurable limits, in many cases. Furthermore, the time required on station to cleanup before sampling is significantly reduced compared to conventional sampling methods.Formation fluid sampling has always been adversely affected by mud filtrate contamination, which introduces errors into the laboratory analysis and requires analytical methods to backcalculate the measured properties to the uncontaminated reservoir fluid. The ability to secure a totally clean sample of formation fluid at reservoir conditions is a significant advance, that replaces the need for sampling during Drill Stem Tests and provides accurate fluid information for characterization of the reservoir, flow assurance, facility design, production strategies, and defining reserves.The application of this new focused sampling technology is presented using four case studies from wells drilled on the Norwegian Continental Shelf. A wide range of formation fluids and permeabilities are examined, in both oil-based and water-based drilling fluids. Results from focused sampling are compared directly with conventional sampling in the same reservoir zones. This study also gives insight into the cleanup dynamics of invaded filtrate, and explores the different factors that affect performance of the focused sampling technique.An important consequence of negligible contamination is the ability to accurately measure fluid properties in-situ. And reduced cleanup time allows for multiple zones to be scanned efficiently. Downhole Fluid Analysis (DFA) can thus be utilized to reveal reservoir architecture that is unable to be determined by traditional wireline logs.