fax 01-972-952-9435. AbstractDownhole fluid analysis (DFA) has emerged as a key technique for characterizing the distribution of reservoir fluid properties and determining zonal connectivity across the reservoir. Information from profiling the reservoir fluids enables sealing barriers to be proven and compositional grading to be quantified; this information cannot be obtained from conventional wireline logs. The DFA technique has been based largely on optical spectroscopy, which can provide estimates of filtrate contamination, gas/oil ratio (GOR), pH of formation water, and a hydrocarbon composition in four groups: methane (C1), ethane to pentane (C2-5), hexane and heavier hydrocarbons (C6+), and carbon dioxide (CO 2 ). For single-phase assurance it is possible to detect gas liberation (bubble point) or liquid dropout (dew point) while pumping reservoir fluid to the wellbore, before filling a sample bottle.In this paper, a new DFA tool is introduced which greatly increases the accuracy of these measurements. The tool uses a grating spectrometer in combination with a filter-array spectrometer. The range of compositional information is extended from four groups to five groups: methane (C1), ethane (C2), propane to pentane (C3-5), C6+, and CO 2 . These spectrometers, together with improved compositional algorithms, now make possible a quantitative analysis of reservoir fluid with much greater accuracy and repeatability. This accuracy enables comparison of fluid properties between wells for the first time, thus extending the application of fluid profiling from a single well to multi-well. Field-based fluid characterization is now possible.In addition a new measurement is introduced -in-situ density of reservoir fluid. Measuring this property downhole at reservoir conditions of pressure and temperature provides important advantages over surface measurements. The density sensor is combined in a package that includes the optical spectrometers, fluid resistivity, pressure, temperature, and fluorescence measurements that all play a vital role in determining the exact nature of the reservoir fluid.Extensive tests at a pressure/volume/temperature (PVT) laboratory are presented to illustrate sensor response in a large number of live fluid samples. These tests of known fluid compositions were conducted under pressurized and heated conditions to emulate reservoir conditions. In addition several field examples are presented to illustrate applicability in different environments.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIdentifying compartmentalization, quantifying connectivity, and assessing the presence of compositional grading are critically important to reservoir management, particularly in deepwater projects where uncertainties are large and mistakes are costly. Compositional grading has been known for over 50 years, but the topic received little attention until the 1980's when sufficiently advanced analytical methods became available to assess the phenomenon. Individually, geochemistry, downhole fluid, and mud gas analyses have provided valuable insights into compositional grading, but each analytical method relies on different fluid traits and has different implications. When these analytic methods are systematically combined and consistently applied, the synergy delivers a much more accurate and robust picture of the reservoir and the fluids therein.In this paper, we review two case studies in which we have combined multiple techniques for the assessment of compositional grading in different settings. We demonstrate that new technologies combined with real-time monitoring and control and a more integrated evaluation approach produce a more robust interpretation of the fluids and yield insights into reservoir architecture.
Summary Downhole fluid analysis (DFA) has emerged as a key technique for characterizing the distribution of reservoir-fluid properties and determining zonal connectivity across the reservoir. Information from profiling the reservoir fluids enables sealing barriers to be proved and compositional grading to be quantified; this information cannot be obtained from conventional wireline logs. The DFA technique has been based largely on optical spectroscopy, which can provide estimates of filtrate contamination, gas/oil ratio (GOR), pH of formation water, and a hydrocarbon composition in four groups: methane (C1), ethane to pentane (C2-5), hexane and heavier hydrocarbons (C6+), and carbon dioxide (CO2). For single-phase assurance, it is possible to detect gas liberation (bubblepoint) or liquid dropout (dewpoint) while pumping reservoir fluid to the wellbore, before filling a sample bottle. In this paper, a new DFA tool is introduced that substantially increases the accuracy of these measurements. The tool uses a grating spectrometer in combination with a filter-array spectrometer. The range of compositional information is extended from four groups to five groups: C1, ethane (C2), propane to pentane (C3-5), C6+, and CO2. These spectrometers, together with improved compositional algorithms, now make possible a quantitative analysis of reservoir fluid with greater accuracy and repeatability. This accuracy enables comparison of fluid properties between wells for the first time, thus extending the application of fluid profiling from a single-well to a multiwall basis. Field-based fluid characterization is now possible. In addition, a new measurement is introduced--in-situ density of reservoir fluid. Measuring this property downhole at reservoir conditions of pressure and temperature provides important advantages over surface measurements. The density sensor is combined in a package that includes the optical spectrometers and measurements of fluid resistivity, pressure, temperature, and fluorescence that all play a vital role in determining the exact nature of the reservoir fluid. Extensive tests at a pressure/volume/temperature (PVT) laboratory are presented to illustrate sensor response in a large number of live-fluid samples. These tests of known fluid compositions were conducted under pressurized and heated conditions to simulate reservoir conditions. In addition, several field examples are presented to illustrate applicability in different environments. Introduction Reservoir-fluid samples collected at the early stage of exploration and development provide vital information for reservoir evaluation and management. Reservoir-fluid properties, such as hydrocarbon composition, GOR, CO2 content, pH, density, viscosity, and PVT behavior are key inputs for surface-facility design and optimization of production strategies. Formation-tester tools have proved to be an effective way to obtain reservoir-fluid samples for PVT analysis. Conventional reservoir-fluid analysis is conducted in a PVT laboratory, and it usually takes a long time (months) before the results become available. Also, miscible contamination of a fluid sample by drilling-mud filtrate reduces the utility of the sample for subsequent fluid analyses. However, the amount of filtrate contamination can be reduced substantially by use of focused-sampling cleanup introduced recently in the next-generation wireline formation testers (O'Keefe et al. 2008). DFA tools provide results in real time and at reservoir conditions. Current DFA techniques use absorption spectroscopy of reservoir fluids in the visible-to-near-infrared (NIR) range. The formation-fluid spectra are obtained in real time, and fluid composition is derived from the spectra on the basis of C1, C2-5, C6+, and CO2; then, GOR of the fluid is estimated from the derived composition (Betancourt et al. 2004; Fujisawa et al. 2002; Dong et al. 2006; Elshahawi et al. 2004; Fujisawa et al. 2008; Mullins et al. 2001; Smits et al. 1995). Additionally, from the differences in absorption spectrum between reservoir fluid and filtrate of oil-based mud (OBM) or water-based mud (WBM), fluid-sample contamination from the drilling fluid is estimated (Mullins et al. 2000; Fadnes et al. 2001). With the DFA technique, reservoir-fluid samples are analyzed before they are taken, and the quality of fluid samples is improved substantially. The sampling process is optimized in terms of where and when to sample and how many samples to take. Reservoir-fluid characterization from fluid-profiling methods often reveals fluid compositional grading in different zones, and it also helps to identify reservoir compartmentalization (Venkataramanan et al. 2008). A next-generation tool has been developed to improve the DFA technique. This DFA tool includes new hardware that provides more-accurate and -detailed spectra, compared to the current DFA tools, and includes new methods of deriving fluid composition and GOR from optical spectroscopy. Furthermore, the new DFA tool includes a vibrating sensor for direct measurement of fluid density and, in certain environments, viscosity. The new DFA tool provides reservoir-fluid characterization that is significantly more accurate and comprehensive compared to the current DFA technology.
Identifying compartmentalization, quantifying connectivity, and assessing the presence of compositional grading are critically important to reservoir management, particularly in deepwater projects where uncertainties are large and mistakes are costly. Compositional grading has been known for over 50 years, but the topic received little attention until the 1980's when sufficiently advanced analytical methods became available to assess the phenomenon. Individually, geochemistry, downhole fluid, and mud gas analyses have provided valuable insights into compositional grading, but each analytical method relies on different fluid traits and has different implications. When these analytic methods are systematically combined and consistently applied, the synergy delivers a much more accurate and robust picture of the reservoir and the fluids therein. In this paper, we review two case studies in which we have combined multiple techniques for the assessment of compositional grading in different settings. We demonstrate that new technologies combined with real-time monitoring and control and a more integrated evaluation approach produce a more robust interpretation of the fluids and yield insights into reservoir architecture. Introduction Sage and Lacey (1938) define compositional grading as "variations in the composition of the liquid phase of natural reservoirs, which are continuous through significant ranges in elevation". Therefore, the requirements for compositional grading are that the reservoir is interconnected and that fluid properties such as gas/oil ratio (GOR), saturation pressure, API, Saturation/Aromatics ratio, gas mole fraction, etc. vary with elevation. The magnitude in grading of these properties can vary greatly, depending on the geological and geochemical history of the reservoirs. One must distinguish compositional grading from the fluid property changes commonly observed in vertically stacked reservoirs. For instance, the fill/spill mechanism at work in many stacked reservoirs results in each reservoir filling up by petroleum spiraling up from deeper reservoirs via faults and other pathways, by hydraulic leakage from the crest of the underlying reservoir, or by capillary leakage. As the source matures with time, later petroleum charges become less dense, and each reservoir fills downward from the top due to buoyancy and displaces the earlier heavier charge. As such, there is a tendency for the average API gravity, GOR and bubble point to increase in successively deeper reservoirs. If, on the other hand, the charge entering the trap is denser than the existing hydrocarbon column, filling will occur at the oil/water contact and may not readily mix with the rest of the column. The range of API gravity in a trap initially reflects the maturity of the source rock kitchen during trap filling, constrained by the capacity of the trap while the range of GOR and the bubble point of oil in a trap reflect the pressure and temperature history of the trap (Stainforth, 2004). Compositional grading can be caused by a variety of factors and often indicates a state of non-equilibrium, but it can also be observed in equilibrated systems when chemical potential gradients are balanced by gravitational potential gradients. Temperature gradients can also contribute to concentration variation. In light oils with gravity greater than 35 degrees API, strong compositional grading will often occur where the reservoir fluid is near its critical point. In heavier oils, compositional grading can be due to a number of causes or a combination thereof. These include water washing, evaporative fractionation, incompetent sealing shales, dynamic charge of differing fluids, and segregation of asphaltenes. We will detail two case studies in which we have employed multiple techniques for the assessment of compositional grading. At the end, it will be apparent how an integrated approach yields a more robust interpretation of the fluid grading and a better understanding of reservoir architecture.
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