A downhole density-viscosity (D-V) sensor is introduced that provides a real time direct measurement of in-situ density and viscosity at reservoir conditions using a wireline formation tester (WFT). The new fluid measurements are obtained during open-hole sampling of reservoir fluids, or alternatively through fluid profiling where downhole fluid analysis (DFA) is performed at a number of depths to characterize the reservoir fluid properties at a vertical resolution much higher than traditional sampling methods. The utilization of these new measurements are outlined, to illustrate the emerging importance of quantifying fluid variations in real time. This leads to more complete reservoir understanding, resulting in better decisions regarding field modelling, facilities planning and production strategy. An overview of the D-V sensor is presented together with specifications, and extensive laboratory testing is discussed to show validity of the measurements. Five case studies from around the world are examined to show different applications of this measurement in a wide range of environments. Fluid density and viscosity have long been primary objectives of formation evaluation, as they bear significant impact on field production and economics. The ability to measure true fluid density and viscosity of formation fluids in-situ at reservoir conditions, is a major advancement for reservoir fluid characterization. Introduction Accurate fluid information is important for characterization of the reservoir, flow assurance, facility design, production strategies, and defining reserves. The recent introduction of focused sampling to significantly reduce contamination from drilling mud filtrate (in many cases below measurable limits) has proven that WFT are able to obtain pure, representative formation fluid samples 1. DFA in real time can now be performed with accurate results, due to the negligible effect of contamination on the reservoir fluid. The capabilities of fluid analyzers utilizing optical spectroscopy have been extended to measure gas-oil ratio (GOR) and a more advanced hydrocarbon composition in five groups: methane (C1), ethane (C2), propane to pentane (C3-C5), hexane and heavier hydrocarbons (C6+), and carbon dioxide (CO2). Other sensors measure downhole fluorescence for single phase assurance, pH and resistivity of formation water, pressure and temperature 2, 3. The introduction of in-situ density and viscosity to this DFA portfolio provides important advantages over surface measurement techniques. Pressure gradients have been the traditional method used to evaluate fluid density, fluid contacts, and layer connectivity in exploration or appraisal settings. However gradient accuracy is very dependent on the number and location of pressure points for a given formation thickness, with well qualified uncertainties due to accuracy tolerances on depth and pressure4. Real time measurement of in-situ density yields the value of the pressure gradient directly, which significantly decreases the uncertainty on interpreted pretest gradients, thus giving a more accurate estimate of fluid contacts. This application is especially important in evaluation of thin beds, such as stacked sand sequences deposited in a turbiditic environment, where establishing a gradient is very challenging without this direct measurement of fluid density. Reservoir fluids often show complex compositional behavior in single columns in equilibrium due to gravity, capillarity, or chemical forces. Frequently non equilibrium or non static conditions are also encountered, for instance due to acting thermal forces 5, 6. Fluid profiling of reservoir fluid using DFA at multiple depths enhances pressure gradient interpretation to reveal inhomogeneous fluid distributions in the reservoir, beyond the conventional sampling resolution of a few depths. The D-V sensor can quantify the variation of fluid density and viscosity versus depth for appropriate fluid modeling rather than assuming a straight-line fit. Zonal compartmentalization can be determined through abrupt changes in fluid properties, which provides evidence that a suspected barrier is hydraulically sealing 7. The high accuracy of these measurements permits comparison of fluid properties between different wells, extending the technique of fluid profiling from single well to field wide characterization.

The Vankor field development in Russia's Eastern Siberia involves the exploitation of moderately viscous oil from medium to low permeability reservoirs. The field is on production from two different layers, both of which have active aquifers and are supported by water injection. Conventional petrophysics in the field can be difficult and fluid typing is often ambiguous. Downhole fluid analysis with wireline formation testers (WFT) is frequently used to assist in the clarification of petrophysical challenges.However, formation tester operations are not straightforward. Lower permeability and higher oil viscosity means that the WFT probe does not allow sufficient area for fluid to flow. Inflatable dual packer devices are therefore required. The inflatable packer, however, brings its own challenges. With a larger volume of reservoir being investigated longer pump times are required to evacuate invaded filtrate. Additionally, issues associated with the relative permeability of water and heavier oil frequently mean that hundreds of litres of fluid often must be pumped before the fluid typing questions are resolved. In this paper we discuss the implementation of a modified formation tester tool that uses an inflatable packer arrangement configured with dual intake ports. Each of the intake ports is supported by an independent pump and fluid analysis section. Such a configuration offers two benefits. Firstly, the simultaneous operation of two pumps allows the evacuation of larger amounts of fluid in a given time. Secondly, and more importantly, the positioning of the intake ports within the dual packer module allows the tool to take advantage of the density segregation occurring in the packed off interval and to arrive at a clean oil flow much more quickly than a standard configuration. Field examples and lessons learned are provided.

No abstract

The Piltun-Astokhskoye field is located off the east coast of Sakhalin Island and has been on production since 1999. Several layers of the reservoir rocks feature high water saturations in the range of 40 to 90%, particularly within the ‘deep layers’. A key uncertainty for the development is the productivity of these layers: how much of which fluid will flow and at what saturation level? This paper looks at the various options for reducing this uncertainty. Ultimately, a wireline formation tester option was chosen, and we cover the execution of the job and the interpretation of the acquired data.

One of the most important objectives of fluid sampling using wireline formation testers (WFT) is to ensure that representative samples of the different fluids encountered in the formation are obtained. Usually the wireline or LWD petrophysical logs will guide the sample acquisition program. This typically means that resistivity and nuclear logs are used to infer basic fluid types, caliper log is used to verify that the borehole is suitable for sampling, and NMR logs are used to gauge if permeability is sufficient for a sample to be taken. However these logs are not able to capture variations in the hydrocarbon column to allow the operator to ensure that all representative fluids are sampled. The most important information, a continuous fluids type and property log, is still not widely used in the industry.Modern NMR logging tools can deliver -in addition to conventional porosity and permeability information -a continuous fluid log of oil, gas, water and OBM filtrate (OBMF) at multiple depths of investigation. The radial fluid profiling allows discrimination of OBMF versus native oil. Additionally, within the hydrocarbon column the NMR measurements can be used to provide continuous logs of oil viscosity and gas-oil ratio (GOR). With this information acquired before the sampling operation, it is easier to ensure that a full suite of representative samples are acquired and that we do not indulge in needless over sampling. When NMR data is acquired after the sampling operation, the continuous logs of viscosity and GOR can be calibrated with WFT data to provide fluid information in places where WFT did not sample.