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.
Summary Modern wireline formation testers (WFTs) are able to collect a massive amount of data at multiple depths, thus helping to quantify changes in rock and fluid properties along the wellbore, to define hydraulic flow units, and to understand the reservoir architecture. They are being used routinely in a wide range of applications spanning pressure and mobility profiling vs. depth, fluid sampling, downhole fluid analysis (DFA), interval pressure-transient testing (IPTT), and microfracturing. Because of the complex tool strings and the elaborate operational aspects involved in wireline formation testing, success requires detailed upfront planning and procedural design as well as real-time operational and interpretational support. It is becoming increasingly critical for operating and service company experts to remotely monitor and interpret WFT surveys in real time through Web-based systems. The importance of meeting all rock and fluid data-acquisition objectives cannot be overstated, given the high cost of offshore operations and the implications of obtaining false or misleading information. The main objective of real-time monitoring remains to assure that the planned data are acquired according to pre-established procedures and contingency plans. However, even in developed reservoirs, unexpected circumstances arise, requiring immediate response and modifications to the preplanned job procedures. Unexpectedly low or high mobilities, probe plugging, unanticipated fluid types, the presence of multiple phases, and excessive fluid contamination are but a few examples of such circumstances that would require real-time decision making and procedural modifications. Real-time decisions may include acquiring more pressure data points, extending sampling depths to several zones, extending or shortening sampling times, and repeating microhydraulic fracture reopening/closure cycles, as well as real-time permeability, composition, or anisotropy interpretation to determine optimum transient durations. This paper describes several examples of formation tester surveys that have been remotely monitored in real time to ensure that all WFT evaluation objectives are met. The power of real-time monitoring and interpretation will be illustrated through these case studies. Introduction WFT has become a standard part of the evaluation program of most newly drilled wells, but the objectives vary from offshore deepwater exploration and appraisal wells to old cased-hole and development wells later in the life of a field. Given the wide range of applications and combinations, each WFT evaluation program is unique. Some may include only a pressure-gradient survey for reservoir depletion and communication information, whereas others may seek information on the precise nature of the hydrocarbon fluids and water in terms of chemical and physical properties, phase behavior, and commingling tendencies. Cased-hole surveys might look for bypassed hydrocarbon zones or have objectives that could not be achieved during the openhole phase. Regardless of the type of survey performed, understanding the exploration and appraisal or field-development objectives and translating these into acquisition objectives is essential for success. Figs. 1 and 2 schematically illustrate the real-time monitoring concept. Real-time data are viewable by authorized personnel anywhere around the world, thus allowing virtual collaboration between field staff and off-site service- and operating-company experts throughout the operation. This paper includes several examples of WFT surveys that were monitored and supervised in real time. The cases presented span the entire spectrum of WFT applications including pressures, gradients, sampling, downhole fluid analysis (DFA), IPTT, and microfracturing. The power of real time monitoring and interpretation is clearly illustrated by these examples.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractCarbon dioxide (CO 2 ) occurrence in hydrocarbon bearing formations presents a challenge to the valuation and subsequent prospect development of the hydrocarbons. Corrosion is a major concern effecting capital and operational expenditures since the presence of CO 2 can cause corrosion failures. Carbon dioxide also denotes an issue for health, safety and the environment (HSE) and is readily absorbed by elastomer seals, weakening the resistance of those seals and compromising the integrity of the fluid samples and the safety of equipment and personnel. The conventional procedure to evaluate the CO 2 content in a hydrocarbon bearing formation is to take fluid samples downhole or on surface during a well test and send the fluids to the laboratory for analysis. Both methods are compromised by the reactive nature of CO 2 , whose concentration can change significantly by reaction with formation waters, mud filtrates, etc. before reaching an analysis facility. Optimizing the fluid sample acquisition program to match existing fluid complexities is impossible without real-time analysis. Recently, NIR (near-infrared) spectroscopy has enabled the real time analysis of the CO 2 content in downhole fluid samples. This paper describes a new method for using DFA * (Downhole Fluid Analysis) in the real-time determination of the CO 2 amount in the MDT * (Modular Dynamic Formation Tester) flow line. Extensive laboratory data from a research grade spectrometer and shop data with the downhole tool support the new methodology. Multiple interpretation algorithms have been developed for CO 2 quantification and verified in the laboratory. Several log examples are given * Mark of Schlumberger demonstrating successful CO 2 detection and subsequent confirmation of the measured concentrations by the laboratory data.
The subject of the case study is a recently discovered oil and gas accumulation characterized by laminated, shaly sandstones with high apparent water saturation. Conventional openhole log data was inconclusive in identifying hydrocarbon type and net hydrocarbon pay zones. Moreover, reservoir complexity, low mobility, and inadequate differentiation of oil versus gas pay made it unlikely that a conventional production testing program would be successful and cost effective. However, reservoir fluid identification and pressure measurements were critical for resolving key uncertainties and guiding decision making for future appraisal and development. Cased-hole wireline formation testing was used to better determine reservoir fluid type and productivity in selected intervals so as to differentiate oil pay from gas pay and net pay limits. A total of 30 dual packer stations were conducted in cased hole. The test results were used to choose the intervals, methodology, and equipment for subsequent production tests, which successfully proved the existence of three separate oil reservoirs and demonstrated commercial production rates.
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