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Results
New Downhole-Fluid-Analysis Tool for Improved Reservoir Characterization
Dong, Chengli (Schlumberger) | O'Keefe, Michael D. (Schlumberger) | Elshahawi, Hani (Shell) | Hashem, Mohamed (Shell) | Williams, Stephen M. (StatoilHydro) | Stensland, Dag (ENI Norge) | Hegeman, Peter S. (Schlumberger) | Vasques, Ricardo R. (Schlumberger) | Terabayashi, Toru (Schlumberger) | Mullins, Oliver C. (Schlumberger) | Donzier, Eric (Schlumberger)
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.
- North America > United States (1.00)
- Asia (1.00)
- Europe > Norway (0.94)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Egypt Field (0.89)
- Asia > Philippines (0.89)
New Downhole Fluid Analyzer Tool for Improved Reservoir Characterization
Dong, Chengli (Schlumberger) | O'Keefe, Michael David (Schlumberger) | Elshahawi, Hani (Shell) | Hashem, Mohamed (Shell) | Williams, Stephen Mark (Hydro) | Stensland, Dag | Hegeman, Peter S. (Schlumberger) | Vasques, Ricardo Reves (Schlumberger) | Terabayashi, Toru (Schlumberger) | Mullins, Oliver C. (Schlumberger) | Donzier, Eric (Schlumberger)
Abstract 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 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 (C2โ5), hexane and heavier hydrocarbons (C6+), and carbon dioxide (CO2). 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 (C3โ5), C6+, and CO2. 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 โ 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. 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 proven to be an effective way to obtain reservoir fluid samples for PVT analysis. Conventional reservoir fluid analysis is done in a PVT lab, and the analysis usually takes a long time (months) before the results become available. Additionally, 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 substantially reduced by using focused-sampling cleanup recently introduced in the next-generation wireline formation testers. Downhole fluid analyzer 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 is obtained in real time and fluid composition is derived from the spectrum on the basis of C1, C2โ5, C6+, and CO2; then GOR of the fluid is estimated from the derived composition. Additionally, from the differences in absorption spectrum between reservoir fluid and filtrate of oil-base mud (OBM) or water-base mud (WBM), fluid sample contamination from the drilling fluid is estimated.
- Europe (0.94)
- North America > United States > Texas (0.89)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Compartment Identification by Downhole Fluid Analysis
Mullins, Oliver C. (Schlumberger) | Fujisawa, Go (Schlumberger) | Dong, Chengli (Schlumberger) | Betancourt, Soraya (Schlumberger) | Terabayashi, Toru (Schlumberger) | Hashem, Mohamed (Shell International E&P) | Elshahawi, Hani (Shell International E&P)
ABSTRACT In the development of deepwater and expensive prospects, it is essential to understand the precise nature of the hydrocarbon fluids in terms of chemical and physical properties, all phase transitions and commingling incompatibilities. The best assurance for accuracy is to perform hydrocarbon analysis at the point of sample acquisition during openhole wireline logging - these agenda are embodied in Downhole Fluid Analysis (DFA. In addition, DFA provides the ability to identify fluid compositional variation and compartmentalization. The DFA logging program can be expanded in real time without logistical constraint, commensurate with discovered fluid and formation complexities. Testing the dynamic response of the fluids during the sample acquisition process provides confirmation of hydrocarbon fluid type and character as well as insight into formation characteristics. Here, we describe new methods of in-situ hydrocarbon compositional analysis (or DFA by near-infrared spectroscopy. In particular, we establish that known large hydrocarbon fluid density inversions for large vertical intervals, i.e. deep dry gas versus shallow heavy oil, project into subtle density inversions over vertical intervals as small as six feet. Consequently, this paper establishes a new and cost effective method to find compartments - hunting for fluid density inversions by DFA In addition, we describe how two DFA tools at different locations in the sampling tool string coupled with (effective tool separator volumes can be used to ascertain detailed fluid properties. DFA, coupled with wellsite and laboratory analysis, provides the best, most robust hydrocarbon sampling and analysis process.
- North America > United States (1.00)
- Asia (0.93)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (0.66)
Hydrocarbon Compositional Analysis In-Situ In Openhole Wireline Logging
Mullins, Oliver C. (Schlumberger-Doll Research) | Hashem, Mohamed (Shell International Exploration and Production Inc.) | Elshahawi, Hani (Shell International Exploration and Production Inc.) | Fujisawa, Go (Schlumberger-Doll Research) | Dong, Chengli (Schlumberger Product Center) | Betancourt, Soraya (Schlumberger-Doll Research) | Terabayashi, Toru (Schlumberger)
ABSTRACT In the development of deepwater and other expensive prospects, it is essential to understand the precise nature of the hydrocarbon fluids in terms of chemical and physical properties, all phase transitions, and commingling incompatibilities. Hydrocarbon sample acquisition and analysis, if performed improperly, can yield invalid results leading to costly corrective measures. The best assurance for accuracy is to perform hydrocarbon analysis at the point of sample acquisition during openhole wireline logging ? this agenda is now embodied in Downhole Fluid Analysis (DFA). In particular, understanding compartmentalization, fluid compositional grading and flow assurance requires DFA in order to improve efficiencies. Testing the dynamic response of the fluids during the sample acquisition process provides confirmation of hydrocarbon fluid type and character as well as insight into formation characteristics. Here, we describe new methods of in-situ hydrocarbon compositional analysis or DFA by near-infrared spectroscopy (NIR). Using this method, sample analysis and acquisition can be independently optimized thereby allowing improved operational performance. In addition, we describe how two fluid analyzers at different locations in the sampling tool string coupled with (effective) tool-separator volumes can be used to ascertain detailed fluid properties. In the development of deepwater and other expensive prospects, it is essential to understand the precise nature of the hydrocarbon fluids in terms of chemical and physical properties, all phase transitions, and commingling incompatibilities. Hydrocarbon sample acquisition and analysis, if performed improperly, can yield invalid results leading to costly corrective measures. The best assurance for accuracy is to perform hydrocarbon analysis at the point of sample acquisition during openhole wireline logging ? this agenda is now embodied in Downhole Fluid Analysis (DFA). In particular, understanding compartmentalization, fluid compositional grading and flow assurance requires DFA in order to improve efficiencies. Testing the dynamic response of the fluids during the sample acquisition process provides confirmation of hydrocarbon fluid type and character as well as insight into formation characteristics. Here, we describe new methods of in-situ hydrocarbon compositional analysis or DFA by near-infrared spectroscopy (NIR). Using this method, sample analysis and acquisition can be independently optimized thereby allowing improved operational performance. In addition, we describe how two fluid analyzers at different locations in the sampling tool string coupled with (effective) tool-separator volumes can be used to ascertain detailed fluid properties.
- North America > United States (1.00)
- Asia (1.00)