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Collaborating Authors
Achourov, Vladislav
Enigmatic Reservoir Properties Deciphered Using Petroleum System Modeling and Reservoir Fluid Geodynamics
Pierpont, Rob (OMV) | Birkeland, Kristoffer (OMV) | Cely, Alexandra (Equinor) | Yang, Tao (Equinor) | Chen, Li (SLB) | Achourov, Vladislav (SLB) | Betancourt, Soraya S. (SLB) | Canas, Jesus A. (SLB) | Forsythe, Julia C. (SLB) | Pomerantz, Andrew E. (SLB) | Yang, Jing (SLB) | Datir, Harish (SLB) | Mullins, Oliver C. (SLB)
Abstract Two adjacent reservoirs in offshore oil fields have been evaluated using extensive data acquisition across multiple disciplines; several surprising observations were made. Differing levels of biodegradation were measured in the nearly adjacent reservoirs, yet related standard geochemical markers are contradictory. Unexpectedly, the more biodegraded oil had less asphaltene content, and this reservoir had some heavy end deposition in the core but upstructure, not at the oil-water contact (OWC) as would be expected, especially with biodegradation. Wax appears to be an issue in the nonbiodegraded oil. These many puzzling observations, along with unclear connectivity, gave rise to uncertainties about field development planning. Combined petroleum systems and reservoir fluid geodynamic considerations resolved the observations into a single, self-consistent geo-scenario, the co-evolution of reservoir rock and fluids in geologic time. A spillfill sequence of trap filling with biodegradation helps explain differences in biodegradation and wax content. A subsequent, recent charge of condensate, stacked in one fault block and mixed in the target oil reservoir in the second fault block, explains conflicting metrics of biodegradation between C7 vs. C16 indices. Asphaltene instability and deposition at the upstructure contact between the condensate and black oil, and the motion of this contact during condensate charge, explain heavy end deposition in core. Moreover, this process accounts for asphaltene dilution and depletion in the corresponding oil. Downhole fluid analysis (DFA) asphaltene gradients and variations in geochemical markers with seismic imaging clarify likely connectivity in these reservoirs. The geo-scenario provides a benchmark of comparison for all types of reservoir data and readily projects into production concerns. The initial apparent puzzles of this oil field have been resolved with a robust understanding of the corresponding reservoirs and development strategies.
- Europe > Norway (1.00)
- North America > United States > Texas (0.94)
- Asia (0.94)
- (2 more...)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (4 more...)
In Situ Bubblepoint Measurement
Gisolf, Adriaan (Schlumberger) | Dubost, Francois X. (Schlumberger) | Dumont, Hadrien (Schlumberger) | Achourov, Vladislav (Schlumberger) | Daniele, Nicola (Eni SpA) | Anselmino, Alessia (Eni SpA) | Crottini, Ada (Eni SpA) | Aarseth, Nils Andre (Aker BP ASA) | Fjeld, Per Henrik (Aker BP ASA) | Molla, Shahnawaz (Schlumberger)
Abstract Representative fluid properties are required for a wide range of field life aspects such as initial sizing of reservoir hydrocarbon reserves and production planning. Fluid properties are routinely obtained from laboratory sample analysis, but some fluid properties can also be measured in situ with formation testers. A new downhole bubblepoint technique has been developed to supplement traditional downhole fluid analysis measurements. Bubble-initiation pressure is measured on reservoir fluids enabling early estimations and sample representativity. The method outlined consists of two parts: bubble generation and bubblepoint-pressure detection. After isolation of a volume of contamination-free fluid in the fluid analyzer module of a formation tester, a downhole pump is used to reduce flowline pressure at a low and precise flow rate. Bubble initiation is detected using optical spectroscopy measurements made at a 64-ms data sampling rate. Even very small bubbles scatter visible and near-infrared light directed through the flowline, ensuring that the initiation of bubbles is detected. Flowline decompression experiments are performed in minutes, at any time, and on a wide range of downhole fluids. Downhole bubblepoint pressure measurements were made on four different fluids, all from different reservoirs and regions. The gas-oil ratio of the tested fluids ranged from 500 to 1,500 scf/bbl. In each case, the downhole bubblepoint obtained from the flowline decompression experiment matched the saturation determined by constant composition expansion in the laboratory to within 50 psi. We observed that bubble initiation is first detected using near-infrared spectroscopy. As pressure drops, gas bubbles coming out of solution will increase in size, and the bubble presence becomes identifiable on other downhole sensors such as the live fluid density and fluorescence, where it manifests as signal scattering. For each of the investigated fluids, pressure and density measurements acquired while the flowline pressure is above saturation pressure are also used to compute compressibility as a function of pressure. This downhole bubblepoint pressure measurement allows optimizing real-time sampling operations, enables fluid grading and compartmentalization studies, and can be used for an early elaboration of a fluid equation of state model. The technique is well-suited for black oils and volatile oils. For heavy oil with very low gas content, the accuracy of this technique may be reduced due to the energy required to overcome the nucleation barrier. Prior documented techniques often inferred downhole bubblepoints from analysis of the rate of change of flowline pressure. Direct precise detection of the onset of gas bubble appearance without the need to divert fluid flow is shown for the first time on a wide range of fluids. The measurement accuracy is enabled by the combination of 64-ms optical spectroscopy with low and accurate decompression rates.
- Europe (0.69)
- North America > United States > Texas (0.28)
- Reservoir Description and Dynamics > Formation Evaluation & Management (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)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
Analysis of Lateral Fluid Gradients From DFA Measurements and Simulation of Reservoir Fluid Mixing Processes Over Geologic Time
Chen, Qing (Schlumberger) | Kristensen, Morten (Schlumberger) | Johansen, Yngve Bolstad (Aker BP) | Achourov, Vladislav (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Downhole fluid analysis (DFA) is one pillar of reservoir fluid geodynamics (RFG). DFA measurements provide both vertical and lateral fluid gradient data. These gradients, especially the asphaltene gradient derived from accurate optical density (OD) measurements, are critical in thermodynamic analysis to assess equilibration level and identify RFG processes. Recently, an RFG study was conducted using DFA and laboratory data from an oil field in the Norwegian North Sea. Fluid OD gradients show equilibrated asphaltenes in most of the reservoir, with a lateral variation of 20%. This indicates connectivity, which is confirmed by three years of production data. Two outliers are off the asphaltene equilibrium curve implying isolated sections, one each on the extreme east and west flank. Their asphaltene fraction varies by a factor of six. Such a difference reveals that different charge fluids entered the reservoir, and the equilibrated asphaltenes are the result of an after-charge mixing process. Meanwhile, different gas-oil contacts (GOCs) exist in the reservoir, indicating a lateral solution-gas gradient. Geochemistry analysis shows the same level of mild biodegradation in all the fluid samples, including those from two isolated sections. This means that biodegraded oil spills into the whole reservoir with little or no in-reservoir biodegradation. Furthermore, lateral asphaltene gradients at different times after charge have been preserved; it was a factor of six in asphaltenes content initially and is now 20% in the present day. This unique data set provides a valuable constraint to simulate reservoir fluid after-charge mixing processes to present day, aiming to investigate the factors impacting the evolution of lateral composition gradients in geologic time in a connected reservoir. Numerical simulations were performed over geologic time in reservoirs filled by oil with a lateral density gradient, which imitates the lateral compositional gradients in the gas-oil ratio (GOR) and asphaltenes measured in the above oil field. Simulations show that this lateral gradient creates lateral differential pressures and causes a countercurrent fluid flow forming a convection cell. In reservoirs with realistic vertical-to-horizontal aspect ratios, such fluid flows are not rapid, and lateral gradients can be partially retained in moderate geologic times. Additionally, diffusion was included in the simulation. The reservoir model was initialized with two GOCs producing subtle lateral GOR and density gradients. The simulated mixing process transports gas from higher GOR regions to lower GOR regions and reduces the GOC difference. However, the flux of solution gas transport is small. Consequently, we conclude that lateral GOR and asphaltene gradients can persist for moderate geologic time, which is consistent with observation from the field.
- Europe > Norway > North Sea (0.87)
- North America > United States > Texas > Harris County > Houston (0.28)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 457 > Block 16/1 > Ivar Aasen Field > Sleipner Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 457 > Block 16/1 > Ivar Aasen Field > Skagerrak Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 457 > Block 16/1 > Ivar Aasen Field > Rotliegend Formation (0.99)
- (12 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (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)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Reservoir Implications of Measured Thermodynamic Equilibrium of Crude Oil Components: Gases, Liquids, the Solid Asphaltenes, and Biomarkers
Mullins, Oliver C. (Schlumberger) | Johansen, Yngve Bolstad (AkerBP) | Achourov, Vladislav (Schlumberger) | Chen, Qing (Schlumberger) | Cañas, Jesus Albert (Schlumberger) | Chen, Li (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Forsythe, Julia C. (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Bayestehparvin, Bita (Schlumberger)
Abstract The process of compositional equilibration of reservoir crude oil requires excellent reservoir connectivity. For example, the measured of asphaltene gradients for indications of connectivity is now commonplace. In addition, equilibrated fluids imply various other important fluid and reservoir properties. However, some measurements of distinguishing equilibration from disequilibrium have been ambiguous. Here, we provide measurement protocols which provide robust determination of equilibrium within a framework of reservoir fluid geodynamics. Thermodynamic modeling of measured asphaltene gradients vertically and laterally with considerations of solution gas provides a robust determination of equilibrium. In addition, two-dimensional gas chromatography with its high-resolution compositional evaluation especially within a geochemical context can corroborate conclusions from asphaltene gradient analysis. Outlier locations in the reservoir can often be found and aid considerably in delineating the important reservoir fluid geodynamic processes operative in the reservoir and validating the assessments regarding equilibrium. The evolution of lateral equilibration is shown in a reservoir with known initial (at time of charge) and present-day lateral gradients. Modeling clarifies the convection which has occurred over geologic time to minimize these lateral gradients. Different processes of mass transport in reservoirs are compared. Equilibration processes and corresponding asphaltene gradient measurements are analyzed for differing geologic times including a very young (Pleistocene and Pliocene) and very old (Cretaceous) reservoir charges in different reservoirs. The important role of convection is shown, with its critical requirement of a density inversion.
- North America > United States (1.00)
- Europe > Norway > North Sea > Central North Sea (0.68)
- Asia (0.67)
- Phanerozoic > Cenozoic > Quaternary > Pleistocene (0.35)
- Phanerozoic > Cenozoic > Neogene > Pliocene (0.34)
- Geology > Structural Geology (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.94)
- Geology > Rock Type > Sedimentary Rock (0.93)
- South America > Colombia > Llanos Basin (0.99)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 457 > Block 16/1 > Ivar Aasen Field > Sleipner Formation (0.98)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 457 > Block 16/1 > Ivar Aasen Field > Skagerrak Formation (0.98)
- (49 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Analysis of Lateral Fluid Gradients From DFA Measurements and Simulation of Reservoir Fluid Mixing Processes Over Geologic Time
Chen, Qing (Schlumberger) | Kristensen, Morten (Schlumberger) | Johansen, Yngve Bolstad (Aker BP) | Achourov, Vladislav (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Mullins, Oliver C. (Schlumberger)
ABSTRACT Downhole Fluid Analysis (DFA) is one pillar of Reservoir Fluid Geodynamics (RFG). DFA measurements at varying depths and multiple wells provide both vertical and lateral fluid gradient data. These gradients, especially the asphaltene gradient derived from accurate optical density (OD) measurements, are critical in thermodynamic analysis to assess the degree of equilibration and identify RFG processes. Recently, an RFG study was conducted using both DFA and laboratory data from seven wells in an oilfield in the Norwegian North Sea. Fluid OD gradients show that most of the reservoir has equilibrated asphaltenes with a lateral variation of 20%. This indicates connectivity in the large portion of the reservoir, which is confirmed by three years of production data from the field. There are two outliers off the asphaltene equilibrium curve implying isolated sections: one is located on the extreme east flank of the field and the other on the extreme west flank. The asphaltene fraction varies by a factor of six between these two sections. Such difference reveals that different charge fluids entered the reservoir, and the equilibrated asphaltenes are the result of an after-charge mixing process. In addition, although GOR and fluid composition demonstrate apparent equilibration, different gas-oil contacts (GOCs) exist in the reservoir indicating a lateral solution gas gradient. Geochemistry analysis shows same level of mild biodegradation in all the fluid samples, including those from the two isolated sections. This leads to the conclusion that biodegraded oil spills into the whole reservoir with little or no in-reservoir biodegradation. Furthermore, lateral asphaltene gradients at different times after charge have been preserved, the initial lateral gradient after charge is measured to be a factor of 6 in asphaltene content and, in present day, is now 20%. This unique dataset provides a valuable opportunity to constrain a simulation of reservoir fluid mixing processes after charge to present day. The purpose of the simulation is to investigate the factors which impact the evolution of lateral composition gradients in geologic time in a connected reservoir. Numerical simulations were performed over geologic time in 2D isothermal reservoir models filled by oil with a lateral density gradient. This density gradient imitates the lateral compositional gradient in GOR and asphaltenes measured in the North Sea field. Simulations show that this lateral gradient creates lateral differential pressures and causes a countercurrent fluid flow forming a convection cell. However, in reservoirs with realistic vertical to horizontal aspect ratios, such fluid flows are not rapid, and some degree of lateral gradients can be retained in moderate geologic times. Additionally, diffusion was included in the simulation of the mixing process. The reservoir model was initialized with two different GOCs producing subtle lateral GOR and density gradients. Simulated mixing process transports gas from regions of higher GOR to regions of lower GOR and reduces the difference between the GOCs. However the flux of solution gas transport is very small. Consequently, we conclude that lateral GOR and asphaltene gradients can persist for moderate geologic time, which is consistent with the observation from the field.
- Europe > Norway > North Sea (1.00)
- North America > United States > Texas > Harris County > Houston (0.28)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 457 > Block 16/1 > Ivar Aasen Field > Sleipner Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 457 > Block 16/1 > Ivar Aasen Field > Skagerrak Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 457 > Block 16/1 > Ivar Aasen Field > Rotliegend Formation (0.99)
- (12 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (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)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Diverse Fluid Gradients Associated with Biodegradation of Crude Oil
Mullins, Oliver C. (Schlumberger) | Johansen, Yngve Bolstad (AkerBP) | Rinna, Joachim (AkerBP) | Meyer, John (Kosmos) | Kenyon-Roberts, Steve (Premier) | Chen, Li (Schlumberger) | Forsythe, Julia C. (Schlumberger) | Achourov, Vladislav (Schlumberger) | Jackson, Richard (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Canas, Jesus A. (Schlumberger)
ABSTRACT Severe biodegradation of crude oil is widely known to increase viscosity quite significantly. Water washing is known contribute to this increase under some circumstances. What has been less understood is the spatial variation of viscosity in reservoirs that is caused by biodegradation. Biodegradation-induced gradients are expected because the microbes live in water and consume oil at the oil-water contact (OWC), thus biodegradation is far from uniform in the oil column. Case studies reviewed here show that reservoirs with biodegraded crude oil can have large viscosity gradients at/near the oil-water contact (OWC) or have no variation of viscosity or have variations of viscosity at the top of the oil column. These entirely different outcomes depend on reservoir fluid geodynamic (RFG) processes that occur in conjunction with biodegradation. The combination of downhole fluid analysis and geochemical analysis is shown to delineate the particular RFG processes that control viscosity variations associated with biodegradation. The extent of spill-fill and the evolution of biodegradation is of particular concern. In addition, diffusive mixing can minimize viscosity gradients from biodegradation and depends strongly on overall distance from the OWC, thus depends on tilt angle of the reservoir. In addition, reservoir temperature is important in that biodegradation ceases above 80°C. The different case studies presented herein account for the dominant viscosity profiles associated with biodegradation and provide guidance for optimal reservoir evaluations and inputs to development decisions INTRODUCTION Biodegradation can significantly modify oil properties and increase viscosity which impacts economic potential, well production rates and downstream handling: important considerations for optimal field development planning. In going from no biodegradation to severe biodegradation, microbes can typically consume ∼2/3 of the oil (Head et al, 2003). The microbes consume at most negligible quantities of the asphaltenes; consequently, severe biodegradation can result in a tripling of the asphaltene concentration. The viscosity of crude oil depends essentially exponentially on asphaltene content. In addition, the microbes consume many lower viscosity components of the crude oil such as light alkanes. Even moderate biodegradation can negatively affect crude oil viscosity.
- Asia (1.00)
- Europe > Norway (0.69)
- Africa (0.68)
- (2 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- South America > Colombia > Llanos Basin (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 28/9a > Catcher Field > Tay Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 28/9a > Catcher Field > Cromarty Formation (0.99)
- (7 more...)
Asphaltene Gradient Analysis by DFA Coupled with Geochemical Analysis by GC and GCxGC Indicate Connectivity in Agreement with One Year of Production in a Norwegian Oilfield
Johansen, Yngve Bolstad (AkerBP) | Rinna, Joachim (AkerBP) | Betancourt, Soraya S. (Schlumberger) | Forsythe, Julia C. (Schlumberger) | Achourov, Vladislav (Schlumberger) | Canas, Jesus A. (Schlumberger) | Chen, Li (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Abstract Asphaltene gradient analysis in many wells in a large field match the Flory-Huggins-Zuo Equation of State (FHZ EoS) indicating equilibrated asphaltenes, thus reservoir connectivity. This analysis is consistent with data from over one year of production to date. Reservoir fluid samples were acquired with use of focused sampling techniques providing contamination free samples. Pressure measurements and many fluid properties are used to validate fluid equilibrium, including GOR and composition analyzed by the Cubic EoS, and a variety of markers in the condensate range, black oil range and the biomarker region. All analyses indicate equilibrium with the exception that the only two outliers in the asphaltene gradient curve are shown to be of different thermal maturity by utilizing the preferred biomarkers, the hopanes Ts and Tm. Moreover, the asphaltene abumdance in differently charged fluids varies by a factor of 6 while the maturity ratio Ts/(Ts+Tm) varies by 6% showing the sensitivity of asphaltene gradients for connectivity analysis. The modest levels of biodegradation (Peters- Moldovan rank=1) are used to constrain the petroleum system context of this reservoir considering that current reservoir temperatures significantly exceed biodegradation thresholds. There is evidence both that mildly biodegraded oil spilled into this reservoir and that some further biodegradation occurred in reservoir. Different gas-oil contacts in the field are associated with charge direction and show the limits of Cubic EoS for connectivity analysis in contrast to the good capability of the asphaltene gradients and FHZ EoS for this purpose. Moreover, the FHZ EoS analysis indicates that the asphaltenes are dispersed as a true molecular solution for this light oil in accord with the Yen-Mullins model of asphaltenes. Results from detailed whole-core and petrophysical analyses supports connectivity analysis. Core analysis shows the lack of any asphaltene deposition in the reservoir as expected from the fluid and asphaltene evaluations.
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.49)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 457 > Block 16/1 > Ivar Aasen Field > Sleipner Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 457 > Block 16/1 > Ivar Aasen Field > Skagerrak Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 457 > Block 16/1 > Ivar Aasen Field > Rotliegend Formation (0.99)
- (14 more...)
ABSTRACT The Jurassic and Triassic conglomerate reservoirs encountered in the central part of the North Sea are mineralogically complex and highly heterogeneous across the field. In addition, fluid complexities associated with heavy oil and tar formation from specific reservoir fluid geodynamics processes have also been identified in these reservoirs and have significant impact on development strategies. An integrated approach is applied in which advanced petrophysical evaluation delineates the likely mobile fluids versus viscous oil or tar, and the results can subsequently be validated by downhole fluid analysis and core analysis. Petrophysical methods discussed herein accurately describe and quantify the fluid volumes and types, which are needed to anticipate the fluid movability in the near-wellbore region of the oil column. The work described in this paper shows the sequential refinements of individual, and collective, petrophysical interpretation with the use of advanced log measurements, leading to an enhanced understanding of an atypical reservoir. Nuclear spectroscopy helps resolve an accurate porosity and matrix permittivity, enabling dielectric to solve accurately the shallow zone saturation (SXO), rock textural parameter (MN), salinity, and shallow zone resistivity. The combined dielectric and spectroscopy results are directly used to resolve the undisturbed zone saturation (SWT) on formation resistivity. This sequential integration constrains fluid dynamics descriptions of immovable fluids by analyzing the shallow versus undisturbed zone saturations. In hydrocarbon-bearing formations with water-based muds used here, if the saturation profiles indicate SXO=SWT, there is no invasion and the hydrocarbons are immobile, whereas if SXO>SWT, then the hydrocarbons are mobile. Additionally, nuclear magnetic resonance (NMR) data mark zones of immobile fluids showing missing porosity, thereby indicating the presence of heavy oil or asphaltene/tar. Even if the zones have some mobile hydrocarbon yet still have missing porosity from NMR, this could also indicate some asphaltene/tar in the formation. The petrophysical interpretation guides downhole fluid analysis (DFA) investigation of the reservoir to validate reservoir fluid geodynamics (RFG) scenarios that yield tar deposition; here, gas charge into oil. Core analysis is then targeted to confirm these RFG scenarios. This powerful combination of petrophysics, DFA, and core analysis (even of uncleaned cores) clarifies the importance of immobile hydrocarbons on well placement and aquifer sweep in field development planning.
- Asia > Middle East (0.94)
- North America > United States > Texas (0.47)
- Europe > Norway > North Sea (0.34)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.69)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.48)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 359 > Block 16/4 > Solveig Field > Luno II North Field (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.94)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.94)
The Critical Role of Asphaltene Gradients and Data Integration in Reservoir Fluid Geodynamics Analysis
Mullins, Oliver C. (Schlumberger) | Dumont, Hadrien (Schlumberger) | Mishra, Vinay K. (Schlumberger) | Gomez, Alexandra (Chevron) | Wilkinson, Tim (Talos) | Winkelman, Ben (Talos) | Primio, Rolando Di (Lundin) | Uchytil, Steven (Hess) | Nagarajan, Nagi (Hess) | Strauss, Steve (Hess) | O'Donnell, Martin (Premier) | Seifert, Douglas J. (Saudi Aramco) | Elshahawi, Hani (Shell) | Chen, Li (Schlumberger) | Pfeiffer, Thomas (Schlumberger) | Achourov, Vladislav (Schlumberger) | Zeybek, Murat (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Forsythe, Jerimiah (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Andrews, A. Ballard (Schlumberger) | Pomerantz, Andrew E. (Schlumberger)
Abstract Reservoir fluid geodynamics (RFG) has recently been launched as a formal technical arena that accounts for fluid redistributions and tar formation in reservoirs largely after trap filling. Elements of RFG, such as analysis of biodegradation, have long been in place; nevertheless, RFG is now strongly enabled by recent developments: 1) downhole fluid analysis (DFA) allows routine elucidation of reservoir fluid gradients, 2) the development of the first equation of state for asphaltene gradients allows identification of equilibrium vs. geodynamic processes of reservoir fluids and 3) RFG analyses of 35 oilfields systematize a multitude of RFG processes and show their direct impact on wide-ranging production concerns. Thermodynamic analyses identifying reservoir fluid geodynamic processes rely heavily on measurement of fluid gradients to avoid ambiguous interpretations. The unique role of asphaltene gradients and their integration with other data streams are the focus herein. RFG oilfield studies have repeatedly shown that analyses of asphaltene gradients are critical to proper evaluation of RFG processes. Naturally, any reservoir concern that directly involves asphaltenes such as heavy oil, viscosity gradients, asphaltene onset pressure, bitumen deposition, tar mat formation, and indirectly, GOR gradients are strongly dependent on asphaltene gradients. Moreover, as shown in numerous case studies herein, asphaltene gradients can be measured with accuracy and the corresponding thermodynamic analyses allow explicit identification of RFG processes not traditionally associated with asphaltenes, such as analysis of connectivity, fault block migration, baffling, spill-fill mechanisms and many others discussed below. In turn, these processes imply other corroborative reservoir and fluid properties that can then be confirmed. Crude oil chemical compositional data, such as ultrahigh resolution two-dimensional gas chromatography, combined with geochemical interpretation, is highly desirable for understanding RFG processes. Nevertheless, biomarkers and other fluid properties often exhibit small gradients relative to standard deviations (except with biodegradation) but often can still corroborate specific RFG processes. In general, integration of fluid gradient analysis with other data streams including petrophysics, core analysis, stratigraphy, geology and geophysics is critical; nevertheless, which integration is most needed depends on particular reservoir attributes and RFG processes that are in question. Examples of data integration are shown for ten reservoirs undergoing various fluid geodynamic processes. Asphaltene gradient analysis is relatively new, yet it is essential for characterization of RFG processes.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia > Middle East (1.00)
- Asia > India (0.68)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.69)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
Advances in Quantification of Miscible Contamination in Hydrocarbon and Water Samples From Downhole to Surface Laboratories
Zuo, Julian (Schlumberger) | Gisolf, Adriaan (Schlumberger) | Pfeiffer, Thomas (Schlumberger) | Achourov, Vladislav (Schlumberger) | Chen, Li (Schlumberger) | Mullins, Oliver C. (Schlumberger) | Edmundson, Simon (Schlumberger) | Partouche, Ashers (Schlumberger)
ABSTRACT Formation fluid properties are critical inputs for field development planning. Acquisition of representative, low-contamination, formation fluid samples is key to obtaining accurate fluid properties from laboratory analysis. Quantification of oil-based mud (OBM) or water-based mud (WBM) filtrate contamination of hydrocarbon or water samples is still one of the biggest challenges, both during real-time formation-tester sampling operations and with surface laboratory techniques. Laboratory sample analysis uses either the skimming or the subtraction method to quantify OBM filtrate contamination of hydrocarbon samples whereas tracers are typically required to quantify WBM filtrate contamination of water samples. Recently, a new real-time workflow has been developed to quantify OBM or WBM filtrate contamination of hydrocarbon or water samples with downhole multisensor formation-tester measurements. When discrepancies are observed between laboratory-derived and real-time contamination quantification, it can be challenging to uncover the source of the difference or to identify the most accurate method. This paper evaluates the applicability of different methods. Surface laboratory methods to quantify OBM filtrate contamination crucially assume that the mole fraction of components in the C8+ portion of uncontaminated reservoir fluids and the corresponding molecular weights (or carbon numbers) follow an exponential relation. When actual fluid compositions deviate from the assumed behavior, a large error in OBM filtrate contamination quantification can occur. In this paper, more than 20 laboratory-created mixtures of formation fluid and mud filtrate are analyzed to validate the laboratory methods. Errors of 2 to 3 wt% in OBM filtrate contamination quantification were observed for virgin reservoir fluids that follow the assumed behavior. However, much larger errors may be observed for biodegraded oil, oils with multiple charges from different sources, or oil with similarly wide ranges of compositions to OBM filtrate. A new workflow allows quantification of OBM or WBM contamination using multiple downhole sensors, for real-time measurement, with unfocused and focused sampling tools for water, oil, and gas condensate. The new workflow comprises five steps:data preprocessing; endpoint determination for a pure native formation fluid using flow regime identification; endpoint determination for pure mud filtrate and quality control of all endpoints using linear relations between measured fluid properties; contamination determination in vol% and wt% on the basis of live fluids and stock-tank liquids; and decontamination of the fluid properties including gas/ oil ratio, density, optical density, formation volume factor, resistivity, and compositions. The new workflow has been applied to a large number of field cases, with very good results. For most of the cases, the downhole analysis is consistent with the surface laboratory results. When discrepancies between methods are observed, a thorough understanding of the limitations of each technique, as described in this paper, will help to determine which data to bring forward and what to discard.
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