The increasing complexities of newly discovered reservoirs coupled with the increasing cost of field development mandate significantly improved and timely work flows for reservoir evaluation. Traditional modeling workflows are typically time consuming and require well-organized cross-disciplinary integration between geoscientists. Such models and processes are not well suited to be used and updated during formation-evaluation acquisition phases of field development. In this paper, a more accessible approach is proposed and demonstrated. The existing fluids model is combined with the current geologic model to construct an accurate representation of key features of the reservoir. This model is then used to predict data for a wireline formation sampling and testing tool (WFT), with emphasis on downhole fluid analysis (DFA). In this process, current reservoir understanding is tested by direct measurement in real time. If differences are uncovered between predicted and measured log data, the WFT tool is in the well, and measurements can be made to uncover the source of the error. In this paper a workflow is demonstrated in which WFT DFA and pressure/volume/temperature (PVT) lab reports were used to build a fluid model after the first exploration well data was acquired. This model was then used to predict fluid properties and WFT DFA logs for a subsequent well intersecting nominally the same compartment. These DFA predictions presumed fluid equilibrium and flow connectivity. Real-time comparisons were made of predicted and measured pressures, fluid gradients, contacts and DFA data obtained from the WFT logging run. Agreement of predicted and measured log data indicates that fluid properties and reservoir connectivities used for the modeling are correct. If predictions disagree with measurements, the acquisition program can be altered in real time to ensure sufficient data are acquired to understand the reservoir model inaccuracies. During the WFT logging job, this predictive model enabled validation of critical WFT data. This process also allowed testing of the reservoir connectivity. It was discovered that either compartmentalization or lateral disequilibrium of the fluids in the reservoir exists. Interpretation of the DFA data suggested that a subtle lateral disequilibrium exists, and the assumption of reservoir connectivity is supported.
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. 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.
It has long been recognised that during and after drilling through certain formations, the rock moves inward and begins to close off the well. Normally this phenomenon is considered undesirable since it can cause problems for drilling and casing running. It can however be put to good use as the mechanism to create an annular barrier behind casing. In order to extend the life of a number of North Sea brown fields many well slots on production platforms and sub-sea templates are being re-used. This process involves permanent plug and abandonment of the old well track prior to sidetrack drilling into a fresh area of the reservoir. Norwegian Continental Shelf (NCS) regulatory requirements dictate that compliant procedures for well abandonment require the establishment of double barriers to avoid leakage from the reservoir. With a shortage of sufficient traditional cement barriers these wells often need costly remedial work in order to meet abandonment requirements. Traditional sonic and ultrasonic azimuthal bond logging provides information on the material immediately behind the casing. Many such bond logs show solid material behind the casing far above the theoretical cement top. Clear correlation of this bonding pattern to shales, known to cause problems during drilling, indicates that the shale has sealed off the annular region and that it is the presence of such formation material that results in a good bond log response Logging and pressure testing sealed off zones in a number of wells allowed the bond log response to be qualified for a certain formation without further pressure testing. In this manner logs can provide a clear answer of whether shale successfully seals off certain zones and consequently provides a natural annular barrier. This technique has been employed successfully on over 40 wells, proving non-destructively that high quality natural annular barriers had formed, resulting in elimination of complex remedial work and substantial cost savings.
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.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.