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Collaborating Authors
Results
Acid Fracturing Experience In Naturally Fractured – Heavy Oil Reservoir, Bati Raman Field
Gozel, Mustafa Erkin (Turkish Petroleum Corporation) | Uysal, Serkan (Turkish Petroleum Corporation) | Ayan, Cosan (Turkish Petroleum Corporation) | Yuce, Ugur (Turkish Petroleum Corporation) | Ozturk, Egemen (Turkish Petroleum Corporation) | Gune, Huseyin Kerem (Turkish Petroleum Corporation) | Yilmaz, Ismail Sahin (Turkish Petroleum Corporation) | Oymael, Mustafa (Turkish Petroleum Corporation) | Eswein, Edmund (Schlumberger)
Abstract Bati Raman field, with an original oil in place of 1.85 billion barrels, is a naturally fractured carbonate reservoir containing 9-13 °API extra heavy oil with viscosities varying from 300 to 600 cp. Not only a wide range of pilot EOR schemes including gas, thermal and chemical methods, but also novel IOR applications have been tried in the field. CO2 injection was a game changer for this reservoir which has been the main drive mechanism since 1987. Since then, various techniques are applied to further improve the production performance of the field. This study focuses on the design and outcome of the pilot acid fracturing treatments in selected three wells in the tighter and less fractured southeastern part of the reservoir. State of the art planning included full evaluation of well integrity, cement bond and open hole logs, geomechanics studies augmented with rock mechanics laboratory tests. Laboratory tests were also conducted focusing on sludge/emulsion forming tendencies and acid reaction rates. Using these results, expected fracture dimensions were predicted along with production forecasts. In all wells, pre-frac calibration tests were conducted to assess stress conditions and fracturing parameter optimization. The treatments were then executed, improving the procedure between each well for acid fracturing. Injections schemes were operationally efficient and various diversion techniques were used to mitigate the presence of naturally fractured zones. Pre and post-job temperature logs helped to evaluate each treatment. The results from the wells were very positive; total production rate increased about fivefold, observed within one month after the treatments. No considerable change in water or CO2 production in the wells was observed which had been one of the most important objectives during the candidate selection process. One well was suspended, which turned out to be one of the producers of the field after acid fracturing treatment. Each well had a different post-frac production performance because of its geological characteristics and flow dynamics, making the study more valuable for better understanding of the process. The wells are still on critical observation to assess the nature of the created fractures and their longevity in the long run. Even after twelve to fifteen months of production, which is the breaking point period for fracture closure, the overall production level of the wells was double compared to pre-frac rates. One well still has a fracture dominated production while other two changed back into its pre-frac rates. Based on these results, acid fracturing campaign was extended in the area which is currently under evaluation.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Asia > Middle East > Turkey > Bati Raman Field (0.99)
- North America > United States > Texas > East Texas Salt Basin > Fallon Field (0.94)
A New Environmentally Friendly Technique to Extend the Limits of Transient Pressure Testing and Sampling Using Pipe Conveyed Open Hole Wireline Formation Testing Tools
Ayan, Cosan (Schlumberger) | Mishra, Vinay (Schlumberger) | Eriksen, Kåre-Otto (Statoil) | Van der Hoek, Jeroen (Statoil) | Thorne, Tyson (Statoil)
Abstract Transient well testing is one of the most critical components of reservoir evaluation due to its impact on a project's key economic parameters such as reserves and producibility. A conventional cased hole well test involves casing off the well, installing process equipment, completing the well perforating, flowing the well to surface and flaring the produced fluids. While the data acquired from conventional well tests is very useful; a large number of wells are not tested due to time, cost and regulatory constraints. In such situations with no well test, operators are obliged to take important decisions from a relatively small amount of reservoir information and hence take risks associated with subsurface uncertainties. To help reduce the development risks, a new pipe conveyed testing tool referred as Formation Testing While Tripping (FTWT) was developed. The new testing tool integrates a number of innovations allowing pumping large fluid volumes at higher rates with extended testing time and improved well noise control. This is done by circulating the produced fluids out of the wellbore during pumping out formation fluids. The new hardware can be combined with wireline sampling and downhole fluid analysis modules allowing to achieve overall well testing objectives; including collecting pressure transient data, real time fluid typing and capturing cleaner and larger volume fluid samples, while increasing the radius of investigation for better characterization of any reservoir heterogeneities compared to conventional wireline formation testing techniques. In this paper, we introduce the new testing technique, which has recently been utilized in the Norwegian sector of the North Sea and offshore Canada. In one well, following the FTWT surveys, Drill Stem Tests (DST) were also conducted for comparison. The field examples and comparison with DST's indicated that the new method can provide valuable reservoir information while also showing its current limitations.
- North America > United States > Texas (0.28)
- Europe > United Kingdom > North Sea (0.24)
- Europe > Norway > North Sea (0.24)
- (2 more...)
- North America > Canada (0.89)
- Europe > United Kingdom > North Sea (0.89)
- Europe > Norway > North Sea (0.89)
- (2 more...)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Understanding Reservoir Fluid Dynamic Processes by Using Diffusive Models
Zuo, Julian Y. (Schlumberger) | Mullins, Oliver C. (Schlumberger) | Jackson, Richard (Schlumberger) | Agarwal, Ankit (Schlumberger) | Ayan, Cosan (Schlumberger) | Wang, Kang (Schlumberger) | Chen, Yi (Schlumberger) | Pan, Shu (Schlumberger) | Elshahawi, Hani (Shell) | Dong, Chengli (Shell) | Herold, Bernd (Cairn) | Kumar, Sanjay (Cairn)
Abstract Downhole fluid analysis (DFA) has successfully been used to delineate reservoir connectivity and fluid properties and to understand the origins of many complexities in oil reservoirs with the Flory-Huggins-Zuo equation of state (FHZ EOS). Equilibrium asphaltene gradients strongly imply reservoir connectivity, with fluid equilibration often taking tens of millions of years. However, reservoir fluids often demonstrate complicated compositional gradients from undergoing dynamic processes such active late gas charges, biodegradation, and water washing. In this paper, a simple 1D two-component diffusive model with analytical solutions is developed for taking into account dynamic processes in oil reservoirs. Two field applications of the developed diffusive model are active gas charging and biodegradation to better understand these dynamic processes. In the first field application, an active late gas charge results in huge nonequilibrium gradients in several fluid properties including API gravity, gas/oil ratio (GOR), saturation pressures, and asphaltene content (color optical density) measured by DFA and surface laboratory analysis. Because the reservoir is not in equilibrium, these fluid property gradients cannot be modeled by the equilibrium EOS model. Thus, a diffusive model is needed to account for the large GOR gradient. The diffusive model predicts the large variations of GOR gradients successfully. The asphaltene gradient is evidently under control of convective currents induced by the gas charge. The exact nature of this process is currently under investigation. The asphaltene gradient is consistent with the predictions by the FHZ EOS with the assumption of asphaltenes locally in equilibrium with the local fluids described by the diffusive model. The second field application is biodegradation occurring at oil/water contact (OWC). Compared to the predictions of the FHZ EOS, it is observed that the upper half of the oil column follows an equilibrium asphaltene distribution well. However, a much larger asphaltene gradient is found in the lower half of the reservoir, which gives rise to a huge (8×) viscosity variation and affects production. The measured asphaltene distribution in the whole oil column can be described nicely by the diffusive model along with the FHZ EOS. The diffusion of alkanes to the OWC (where they are rapidly consumed) is a control step. The consumption of alkanes at the OWC reduces the oil volume and increases asphaltene content and viscosity. Petroleum system modeling predicts initiation of reservoir charging in the Eocene matching the diffusive times required in the FHZ EOS modeling.
- Asia (1.00)
- Europe (0.68)
- North America > United States > Colorado (0.28)
- North America > United States > Texas (0.28)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Inversion of Wireline Formation Tester Data to Estimate In-Situ Relative Permeability and Capillary Pressure
Cig, Koksal (Schlumberger) | Ayan, Cosan (Schlumberger) | Kristensen, Morten (Schlumberger) | Liang, Lin (Schlumberger) | El Battawy, Ahmed (Schlumberger) | Elshahawi, Hani (Shell) | Ramaswami, Shyam (Shell) | Mackay, Eric (Heriot-Watt University)
Abstract Relative permeability and capillary pressure curves are crucial inputs for a reservoir description. However, measuring these quantities on core samples in the laboratory is an extensive and time-consuming process. Wireline Formation Tester (WFT) logging is routinely applied in field operations for reservoir evaluation purposes. Often a historical record of WFT data exists for a field which can be re-interpreted, and since this interpretation takes days, rather than months to years in the case of core analysis, we propose in this paper to revisit the acquired WFT data with the purpose of estimating multiphase flow properties. WFT logging is generally conducted in an open hole environment. By the time of logging, the near-wellbore region has been exposed to mud filtrate invasion. In the case of immiscible mud filtrate and formation fluid the invasion resembles a small scale water-flood process. During WFT sampling the mud filtrate is first cleaned and formation fluid subsequently sampled in a multiphase flow environment while measuring bottom-hole pressures and water-cuts. As shown in previous papers (Cig et al., 2014, 2015), the measured WFT data can be utilized in an inversion workflow to estimate relative permeabilities by combining a forward model of the cleanup process with an optimization engine. The proposed methodology starts with an open hole log interpretation which provides reservoir properties including a saturation distribution. The filtrate invasion is represented as accurate as possible from the open hole logs and drilling reports. WFT tool geometry and its internal tool storage and fluid segregation effects are incorporated into the modeling. A numerical forward model is then simulated within an optimization workflow where relative permeabilities, capillary pressures, damage skin, and depth of mud filtrate invasion are estimated by minimizing a misfit function between measured and modeled bottom-hole pressures and water-cuts. Industry accepted parameterization techniques are used for the relative permeability and capillary pressure curves. Initial parameter estimates are provided from the interpretations of the open hole logs, such as resistivity, dielectric, nuclear magnetic resonance, as well as from pressure transient analysis. Previously we have studied WFT data from a 3D radial probe (3DRP) and a dual packer (DP) (Cig et al., 2014, 2015). The proposed methodology was also validated with synthetic datasets in the same papers. In this paper we extend the methodology to a single probe (SP) inlet and to joint inversion of both capillary pressure and relative permeability curves. We demonstrate the methodology using field data from a Central Asian clastic reservoir. Interpretation of multiphase flow properties from WFT data represents a valuable complement to core measurements and will help to condition reservoir models for more reliable forecasting.
- Asia (0.94)
- Europe (0.93)
- North America > United States > Texas (0.68)
Abstract Measuring relative permeabilities and capillary pressures on core samples in the laboratory is both a lengthy and costly process. Wireline formation testers (WFT) are routinely used in the field to measure pressures and collect fluid samples. Commonly available data from WFT operations carry information about the multiphase flow properties of the formation. By utilizing in-situ WFT measurements together with a flow model and an optimization engine, we propose in this paper a new methodology for estimation of relative permeability and capillary pressure (PC). The proposed methodology consists of a numerical forward model describing the mud filtrate invasion and fluid sampling processes while accurately accounting for WFT tool geometry and internal tool storage and fluid segregation effects. The forward model is embedded in an optimization workflow where relative permeabilities, capillary pressures, damage skin, and depth of mud filtrate invasion are estimated by minimizing a misfit function between measured and modeled pressures and water-cuts. The relative permeability and PC curves are parameterized using industry accepted models. The optimization workflow uses a distribution function of response parameters where the entire parameter range is included in the numerical runs, thus ensuring that a global optimum is found. Initial parameter estimates are determined from open-hole logs, such as resistivity, dielectric, nuclear magnetic resonance, as well as from pressure transient analysis. The methodology developed in this paper is validated by application to a synthetic dataset with a known solution, and it is subsequently demonstrated on actual field data from a WFT sampling operation. The results of this paper demonstrate that it is possible to reliably estimate multiphase flow properties from WFT sampling data. The key contributions of this study are to show the capability of estimating a variety of multiphase flow properties from in-situ WFT cleanup measurements and to establish an automated approach, including a novel inversion methodology, to reduce the turnaround time.
- Europe (0.93)
- North America > United States (0.28)
A Novel Methodology for Estimation of In-Situ Relative Permeabilities from Wireline Formation Tester Data in an Abu Dhabi Carbonate Reservoir
Cig, Koksal (Schlumberger) | Kristensen, Morten (Schlumberger) | Thum, Sebastian (Schlumberger) | Ayan, Cosan (Schlumberger) | Mackay, Eric (Heriot-Watt University) | Elbekshi, Amer (ADCO) | Naial, Radwan (ADCO)
Abstract A multilayer carbonate reservoir, having medium to low permeabilities with distinctive oil-water contacts, is in an appraisal stage. Large data gathering including rigorous coring is underway in the field. It is identified that the slowest part of the data evaluation is generally SCAL analyses due to its laborious workflow. A new approach is proposed by introducing a wireline formation tester (WFT) multiphase flow analysis to obtain relative permeabilities. The WFT tool is commonly used in this field to measure pressures and collect samples. In this paper we present a novel methodology for estimating in-situ relative permeability curves with the help of available WFT multiphase flow data and its numerical optimization. During drilling of a well the formation is exposed to mud filtrate invasion. The invasion displaces oil in the vicinity of the wellbore, much like a small water flooding experiment in the case of immiscible mud filtrate and formation fluid. A WFT sampling operation in a multiphase flow environment provides an opportunity for determining related properties by utilizing bottom-hole pressure and water-cut data. A numerical model replicates the mud filtrate invasion and sampling with reservoir properties and WFT tool geometry. The numerical simulation model consists of a proper definition of reservoir properties as well as WFT tool geometry, including size and shape of flow inlets, along with tool storage and fluid segregation effects. The model is embedded in an optimization workflow and relative permeability curves, damage skin and depth of mud filtrate invasion are then estimated by minimizing a misfit function between measured and modeled pressures and water-cuts. The relative permeability curves are parameterized using industry accepted models. The optimization workflow uses a distribution function of response parameters where the entire parameter range is included in the numerical runs, thus ensuring that a global optimum is found. Initial parameter estimates are determined from open hole logs, such as resistivity, dielectric, magnetic nuclear resonance and from pressure transient analysis. The methodology developed in this paper is validated by application to a synthetic dataset with a known solution, and it is subsequently demonstrated on actual field data from a WFT sampling operation. The results of this paper demonstrate that it is possible to reliably estimate multiphase flow properties from WFT sampling data. The key contributions of this study are to show the capability of estimating a variety of multiphase flow properties from routine WFT cleanup data and to establish an automated approach, including a novel inversion methodology, to reduce the turnaround time.
- North America > United States (1.00)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.50)
Mapping and Modeling Large Viscosity and Asphaltene Variations in a Reservoir Undergoing Active Biodegradation
Jackson, Richard R. (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Agarwal, Ankit (Schlumberger) | Herold, Bernd (Cairn India Ltd) | Kumar, Sanjay (Cairn India Ltd) | Santo, Ilaria De (Schlumberger) | Dumont, Hadrien (Schlumberger) | Ayan, Cosan (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Abstract Viscosity is one of the key reservoir fluid properties. It plays a central role in well productivity and displacement efficiency and has a significant impact on completion strategies. Accurately assessing areal and vertical variations of viscosity will lead to more realistic reservoir simulation and optimal field development planning. Downhole fluid analysis (DFA) has successfully been used to measure the properties of reservoir fluids downhole in real time. DFA has excellent accuracy in measuring fluid gradients which in turn enable accurate thermodynamic modeling. Integration of DFA measurements with the thermodynamic modeling has increasingly been employed for evaluating important reservoir properties such as connectivity, fluid compositional and property gradients. The thermodynamic model is the only one that has been shown to treat gradients of heavy ends in all types of crude oils and at equilibrium and disequilibrium conditions. In addition, fluid viscosity depends on concentration of heavy ends that are associated with optical density measured by DFA. Therefore, mapping viscosity and optical density (heavy end content) is a new important application of DFA technology for use as assessment of reservoir architectures and a mutual consistency check of DFA measurements. In this case study, a very large monotonic variation of heavy end content and viscosity is measured. Several different stacked sands exhibit the same profiles. The crude oil at the top of the column exhibits an equilibrium distribution of heavy ends, SARA and viscosity, while the oil at the base of the oil column exhibits a gradient that is far larger than expected for equilibrium. The fluid properties including SARA contents, viscosity and optical density vary sharply with depth towards the base of the column. The origin of this variation is shown to be due to biodegradation. GC-chromatographs of the crude oils towards the top of the column appear to be rather unaltered, while the crude oils at the base of the column are missing all n-alkanes. A new model is developed that accounts for these observations that assumes biodegradation at the oil-water contact (OWC) coupled with diffusion of alkanes to the OWC. Diffusion is a slow process in a geologic time sense accounting for the lack of impact of biodegradation at the top of the column. An overall understanding of charging timing into this reservoir and expected rates of biodegradation are consistent with this model. The overall objective or providing a 1st-principles viscosity map in these stacked sand reservoirs is achieved by this modeling. Linking DFA with thermodynamic modeling along with precepts from petroleum systems modeling provides a compelling understanding of the reservoir.
- Asia > India (0.30)
- North America > Canada (0.28)
- Europe > United Kingdom (0.28)
- Europe > Netherlands (0.28)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.87)
- Geology > Geological Subdiscipline > Geochemistry (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.48)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Fatehgarh Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract During drilling of a well, the formation is exposed to mud filtrate invasion. The invasion displaces oil in the vicinity of the wellbore, much like a small water flooding experiment in the case of immiscible mud filtrate and formation fluid. Pressure transient or flow test of a wireline formation tester (WFT) commonly provides reservoir properties under the assumption of single-phase flow. However, a WFT sampling operation in a multiphase flow environment gives an opportunity for determining related properties in an inversion workflow by utilizing recorded bottom-hole pressure and water-cut data. In this paper, we present a novel methodology to estimate multiphase flow properties with the help of numerical simulation and optimization. The numerical simulation model for mud filtrate invasion and cleanup consists of a proper definition of reservoir properties as well as WFT tool geometry, including size and shape of flow inlets, along with tool storage and fluid segregation effects. The model is embedded in an optimization workflow and relative permeability curves, damage skin and depth of mud filtrate invasion are then estimated by minimizing a misfit function between measured and modeled pressures and water-cuts. The relative permeability curves are parameterized using industry accepted models. The optimization workflow uses a distribution function of response parameters where the entire parameter range is included in the numerical runs, thus ensuring that a global optimum is found. Initial parameter estimates for the optimization process are determined from open hole logs, such as resistivity, and from pressure transient analyses. The methodology developed in this paper is validated by application to a synthetic dataset with a known solution, and it is subsequently demonstrated on actual field data from a sampling job in an oil-water transition zone. The results of this paper demonstrate that it is possible to reliably estimate multiphase flow properties with defined confidence intervals from WFT sampling data. The key contributions of this study are to show the capability of estimating a variety of multiphase flow properties from routine WFT cleanup data and to establish an automated approach, including a novel inversion methodology, to reduce the turnaround time.
- Asia (0.68)
- North America > United States > Texas (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Flow Modeling and Comparative Analysis for a New Generation of Wireline Formation Tester Modules
Kristensen, Morten (Schlumberger) | Ayan, Cosan (Schlumberger) | Chang, Yong (Schlumberger) | Lee, Ryan (Schlumberger) | Gisolf, Adriaan (Schlumberger) | Leonard, Jonathan (Schlumberger) | Corre, Piere-Yves (Schlumberger) | Dumont, Hadrien (Schlumberger)
Abstract Wireline formation testing (WFT) is an integral part of reservoir evaluation strategy in both exploration and production settings worldwide. Application examples include fluid gradient determination, downhole sampling, fluid scanning in transition zones, as well as interval pressure transient tests (IPTTs). Until recently, however, formation testing was still challenging and prone to failure when testing in low-mobility, unconsolidated, or heavy-oil-bearing formations, especially with single-probe type tools. A new-generation WFT module with a 3D radial probe expands the operating envelope. By using multiple fluid drains spaced circumferentially around the tool, the new module can sample in tighter formations and sustain higher pressure differentials while providing mechanical support to the borehole wall. We performed a detailed flow modeling-based analysis of the contamination cleanup behavior during fluid sampling with the new module. Using both miscible (sampling oil in oil-based mud) and immiscible (sampling oil in water-based mud) contamination models we studied the cleanup behavior over a wide range of formation properties and operating conditions. Comparison of the cleanup performance of the new module with the performance of conventional single-probe tools demonstrates that the new module is 10 to 20 times faster than the single-probe tools when sampling in tight formations. Finally, we also compared the new module against the sampling performance of dual packers and a focused probe. This work is directly relevant to the planning and fundamental understanding of wireline fluid sampling. The key contributions are miscible and immiscible contamination cleanup models that include the effect of tool storage, a comprehensive analysis of contamination cleanup behavior for the new-generation WFT module with comparisons against conventional single-probe, focused probe, and dual-packer tools, and a characterization of fluid sampling conditions versus the preferred type of sampling tool.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- (2 more...)
Downhole Viscosity Measurement: Revealing Reservoir Fluid Complexities and Architecture
Mishra, Vinay K. (Schlumberger) | Barbosa, Beatriz E. (Schlumberger) | LeCompte, Brian (Murphy Oil) | Morikami, Yoko (Schlumberger) | Harrison, Christopher (Schlumberger) | Fujii, Kasumi (Schlumberger) | Ayan, Cosan (Schlumberger) | Chen, Li (Schlumberger) | Dumont, Hadrien (Schlumberger) | Diaz, David F. (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Abstract Knowledge of formation fluid viscosity and its vertical and lateral variations are important for reservoir management and determining field commerciality. Productivity and fluid displacement efficiency are directly related to fluid mobility, which, in turn, is greatly influenced by fluid viscosity. Therefore, viscosity is a critical parameter for estimating the economic value of a hydrocarbon reservoir and also for analyzing compositional gradients and vertical and horizontal reservoir connectivity. The conventional methods for obtaining formation fluid viscosity are laboratory analysis at surface and pressure/volume/temperature (PVT) correlations. However, deducing viscosity from correlations introduces uncertainties owing to the inherent assumptions. Surface viscosity measurement may be affected by irreversible alteration of the sampled fluid through pressure and temperature changes, as well as related effects of long-term sample storage. A new downhole sensor for a wireline formation tester tool has been introduced to measure the viscosity of hydrocarbons. The new viscosity sensor uses a vibrating-wire (VW) measurement method with well-established analytical equations for interpretation. Downhole field testing of an experimental prototype has been conducted, with extensive laboratory tests to validate the sensor performance in viscosities ranging from light to heavy oil and at a wide range of well environments. The vibrating wire viscometer sensor meets requirements not only for measurement performance, but also for operations in downhole applications, and possesses the following properties:
- Asia > Middle East (0.93)
- North America > United States > Texas (0.68)
- Africa (0.68)
- South America > Atlantic Basin (0.89)
- North America > Atlantic Basin (0.89)
- Europe > Atlantic Basin (0.89)
- Africa > Atlantic Basin (0.89)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (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)
- (3 more...)