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Collaborating Authors
Results
Heterogeneity Modeling and Heterogeneity-Based Upscaling for Reservoir Characterization and Simulation
Madalimov, M. (North Caspian Operating Company) | Li, D. (North Caspian Operating Company) | Haynes, B. (North Caspian Operating Company) | Yergaliyeva, B. (North Caspian Operating Company) | Dair, Y. (North Caspian Operating Company) | Ehighebolo, I. T. (North Caspian Operating Company) | Ionescu, C. L. (North Caspian Operating Company)
Abstract Reservoir heterogeneity is a key factor in modelling reservoir performance. Heterogeneity measures can be calculated for a given permeability field, but not straight forward to reverse the process. Detailed heterogeneity can be built into a fine-scale model but can be lost during upscaling to a coarse-scale, no matter which method is chosen from simple averaging to flow-based. This paper proposes a method of heterogeneity modeling and heterogeneity-based upscaling with the aim of solving these problems. Unlike the traditional geostatistical method used to generate a permeability field that is not directly linked to a desired heterogeneity coefficient, the proposed method creates a heterogenous permeability field directly using LCC (Lorenz coefficient and curve). Using a given LCC as input, the expected heterogenous permeability field can be generated via the proposed steps and equations. Using the proposed heterogeneity-based upscaling method, the LCC defined from the fine-scale model can be preserved exactly during upscaling such that gas-oil-ratio and water-cut can be matched between the fine- and coarse-scale models without using pseudo functions. The proposed method has been successfully applied in modelling a giant carbonate oil field in the Caspian Sea consisting of a matrix dominated platform and a fracture/karst dominated rim. Due to the field's complex geology and high H2S content, a dual porosity, dual permeability compositional model has been created to model compositional flow within/between matrix and fracture/karst initialized with an abnormally high reservoir pressure. The field surveillance data shows that reservoir heterogeneity (LCC) is a key component for the field reservoir characterization and simulation. The LCCs can be estimated from the cores and logs, but the challenge is how to preserve the characteristics of the LCCs during modeling, upscaling, HM, and Uncertainty Analysis (UA). Application of the new method has demonstrated its ability to overcome this challenge and has significantly improved the quality of the field's reservoir modeling, upscaling, HM, and UA. The fine-scale model LCCs were directly applied to calculate the coarse-scale permeability. The range of the LCCs estimated from cores and logs were used to generate a range of heterogeneous permeability fields for UA. Regional LCCs were adjusted based on the mismatches of GOR and/or water-cut and new heterogeneous permeability fields were generated to improve the HM quality.
- Asia (0.93)
- North America > United States > Texas (0.68)
- Europe (0.68)
- Geology > Geological Subdiscipline (0.68)
- Geology > Rock Type > Sedimentary Rock (0.54)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
Managing New Development Uncertainty with Scenarios and Multiscale Modelling: An Integrated Study of the Fogelberg Discovery
Mullins, James R. (Rock Flow Dynamics, Aberdeen, UK) | Mendez, Maria (Rock Flow Dynamics, Aberdeen, UK) | Bajan, Luka (Lime Petroleum AS, Oslo, Norway) | Rocher, Dimitri (Lime Petroleum AS, Oslo, Norway) | Spitzmรผller, Adam (Lime Petroleum AS, Oslo, Norway) | Marsh, Tom (Rock Flow Dynamics, Aberdeen, UK) | Berntsen, Bjรธrn A. (Lime Petroleum AS, Oslo, Norway)
Recent hydrocarbon developments are generally characterised by high complexity and uncertainty with lower margins for error in an unpredictable financial market. This is further compounded by new oil and gas discoveries being typically smaller today, than in the past; highlighting the need for robust and fit-for-purpose reservoir models that accurately capture key uncertainties to inform management decisions and to help avoid substantial financial losses. To make an informed decision on either field development or relinquishment of the Fogelberg production license on the Norwegian Continental Shelf (NCS), an alternative full field reservoir model was commissioned by one of the License partners of a complex stacked tidal bar system in the Norwegian Sea. The model includes an accurate representation of the underlying heterogeneities observed in a drill stem test (DST) performed in 2018, incorporating the spatial evolution of the tidal bar system including the placement of low permeability inter-bars to stylolitisation at core-plug scale. Furthermore, the model is robust enough to permit future forecasting and well planning required to enable a management decision. A scenario-based modelling approach (after Bentley and Smith, 2008) based on three discrete concepts was undertaken, accounting for uncertainty in the spatial geometry of the tidal bar complexes. This approach was combined with a hierarchical modelling strategy to honour the depositional concept model and to provide modelling flexibility. Sub-cell resolution heterogeneity in the form of stylolites that were prevalent in cored intervals were incorporated using a multi-scale approach in the form of a representative elementary volume (REV). A full uncertainty ensemble was generated for each of the three modelling scenarios. The model produced a robust match to the bottom hole pressure (BHP) reported during the DST and was used to generate production potential and optimize lower completion strategy, including a side-by-side comparison of recovery of horizontal wells with fishbone stimulation, hydraulic fracturing stimulation and unstimulated slotted liner completions. Based on new static and dynamic understanding of the reservoir, the license will be re-applied for with a view to future development. This paper highlights the importance of managing uncertainty through the use of scenarios, their flexibility with ensembles and the use of a multi-scale approach to accurately represent the respective lengths at which heterogeneities occur to build a better knowledge of the subsurface. The work undertaken for this petroleum system is both highly relevant and transferable for the future transition of safe and permanent storage of carbon, hydrogen and nuclear storage.
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.66)
- Geology > Structural Geology > Tectonics > Extensional Tectonics (0.46)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL S86 > Melke Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 199 > Block 6506/11 > Kristin Field > Tofte Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 199 > Block 6506/11 > Kristin Field > Ile Formation (0.99)
- (13 more...)
Abstract In a homogeneous non-faulted reservoir where oil production has been ongoing long enough for a pseudo steady-state pressure regime to exist, the time-lapse shut-in pressures for all wells are expected to be similar in magnitude and trend. This gives a cluster of similar lines on a plot of shut-in bottom hole pressure over time. By contrast, heterogeneous non-faulted reservoirs can exhibit variations in these trends. Traditionally, mapping a reservoir's heterogeneity requires the use of seismic or facies data. This study aims to investigate whether the differences in pressure trends observed in heterogeneous reservoirs can be used to map reservoir heterogeneities. Numerical experiments are performed using hypothetical models to study the impact that stepwise and continuous permeability variations, the permeability ratio, duration of shut-in, and flowrate all have on the time-lapse pressure trends of wells located within regions of similar and different permeability magnitudes. The time-lapse shut-in bottom-hole pressures for all wells are plotted on the same axis to assess cluster differentiation. Closed polygons are drawn around the wells within each differentiated cluster. The simulation results indicate that pressure cluster differentiation typically implies heterogeneity, whereas time-lapse pressure clustering does not necessarily imply homogeneity. Therefore, in a reservoir where time-lapse pressure cluster differentiation is observed, mapping the spatial locations of wells within each pressure cluster would result in a reservoir heterogeneity map comparable to what is obtained traditionally from facies and seismic maps as part of geological modeling. A key contribution of this study is the development of an alternative spatial heterogeneity map, based on dynamic data (pressure), that can be used as a trend map for guiding 3D model property distributions. The application of the alternative spatial heterogeneity map for 3D geo-model property distributions ensures that important geo-model connectivity patterns are represented, facilitating subsequent history-matching efforts.
- Asia > Middle East (0.68)
- North America > United States > Texas > Terry County (0.40)
- North America > United States > Texas > Gaines County (0.40)
- Europe > United Kingdom > North Sea > Southern North Sea (0.40)
- Well Drilling > Drilling Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
However, spatially regular distribution of the fluids may not always give an adequate representation of the real distribution. In particular, as we have seen in Chapter 3, random and periodic 1D heterogeneity may produce very different attenuation/dispersion pairs. Although 1D alternating fluid distributions may not be realistic, this result gives an additional motivation to study wave propagation in porous media with random spatial fluid distributions. First, we review models for partial fluid saturation that utilize regular spatial fluid patterns, followed by models of random fluid distribution. This analysis is largely based on the generic models of heterogeneous porous media described in Chapter 3. In addition, Section 4.10 describes the effect of interfacial tension between the two fluids, the phenomenon specific to the case of partial saturation.
- Research Report > Experimental Study (0.67)
- Research Report > New Finding (0.46)
- Geology > Rock Type (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.46)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (2 more...)
The front matter contains the title page, copyright page, contents, about the authors, preface, and basic notation.
- Europe (0.93)
- Asia (0.68)
- Oceania > Australia (0.28)
- North America > United States (0.28)
- Geophysics > Borehole Geophysics (0.68)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.68)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- (5 more...)
Summary A multiscale sequential fully implicit (MS SFI) reservoir simulation method implemented in a commercial simulator is applied to a set of reservoir engineering problems to understand its potential. Our assessment highlights workflows where the approach brings substantial performance advantages and insight generation. The understanding gained during commercialization on approximately 40 real-world models is illustrated through simpler but representative data sets, available in the public domain. The main characteristics of the method and key features of the implementation are briefly discussed. The robust fully implicit (FI) simulation method is used as a benchmark. The implementation of the MS SFI method is found to faithfully reproduce FI results for black-oil problems. We provide evidence and analysis of why the MS SFI approach can achieve high levels of performance and fidelity. The method supports the solution of unique problems that would benefit from incorporating multiscale geology and multiscale flow physics. The MS SFI implementation was used to successfully simulate a typical sector model used for field pilots at extremely high โwhole coreโ scale resolution within a practical time frame leveraging high-performance computing (HPC). This could not be achieved with the FI approach. A combination of MS SFI and HPC offers immense potential to simulate geological models using grids to capture mesoscopic or laminar scale geology. The method, by design, demands fewer computing resources than FI, making it far more cost-effective to use for such high-resolution models. We conclude that the MS SFI method has a distinct capability to enhance reservoir engineering practice in the areas of high-resolution simulation-driven workflows in context of subsurface uncertainty quantification, field development planning, and reservoir performance optimization. NOTE: This paper is also published as part of the 2021 SPE Reservoir Simulation Conference Special Issue.
- North America > United States > Texas (0.68)
- Asia > Middle East (0.67)
- Europe > United Kingdom > England (0.46)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Overview (0.46)
- Collection (0.34)
- Geology > Sedimentary Geology (0.67)
- Geology > Geological Subdiscipline (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Evaluation of uncertainties (1.00)
- (7 more...)
Summary A multiscale sequential fully implicit (MS SFI) reservoir simulation method implemented in a commercial simulator is applied to a set of reservoir engineering problems to understand its potential. Our assessment highlights workflows where the approach brings substantial performance advantages and insight generation. The understanding gained during commercialization on approximately 40 real-world models is illustrated through simpler but representative data sets, available in the public domain. The main characteristics of the method and key features of the implementation are briefly discussed. The robust fully implicit (FI) simulation method is used as a benchmark. The implementation of the MS SFI method is found to faithfully reproduce FI results for black-oil problems. We provide evidence and analysis of why the MS SFI approach can achieve high levels of performance and fidelity. The method supports the solution of unique problems that would benefit from incorporating multiscale geology and multiscale flow physics. The MS SFI implementation was used to successfully simulate a typical sector model used for field pilots at extremely high โwhole coreโ scale resolution within a practical time frame leveraging high-performance computing (HPC). This could not be achieved with the FI approach. A combination of MS SFI and HPC offers immense potential to simulate geological models using grids to capture mesoscopic or laminar scale geology. The method, by design, demands fewer computing resources than FI, making it far more cost-effective to use for such high-resolution models. We conclude that the MS SFI method has a distinct capability to enhance reservoir engineering practice in the areas of high-resolutionsimulation-driven workflows in context of subsurface uncertainty quantification, field development planning, and reservoir performance optimization. NOTE: This paper is published as part of the 2021 SPE Reservoir Simulation Conference Special Issue.
- North America > United States > Texas (0.68)
- Asia > Middle East (0.67)
- Europe > United Kingdom > England (0.46)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Overview (0.46)
- Collection (0.34)
- Geology > Sedimentary Geology (0.67)
- Geology > Geological Subdiscipline (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Evaluation of uncertainties (1.00)
- (7 more...)
Abstract A new implementation of a multiscale sequential fully implicit (MS SFI) reservoir simulation method is applied to a set of reservoir engineering problems to understand its utility. An assessment is made to highlight areas where the approach brings substantial advantage in performance as well as address problems not successfully resolved by existing methods. This work makes use of the first ever implementation of the multiscale sequential fully implicit method in a commercial reservoir simulator. The key features of the method and implementation are briefly discussed. The learnings gained during field testing and commercialization on about forty real world models is illustrated through simpler, but representative data sets, available in the public domain. The workhorse robust fully implicit (FI) method is used as a reference for benchmarking. The MS SFI method can faithfully reproduce FI results for black oil problems. We conclude that the MS SFI method has the capability to support reservoir engineering decision making especially in the areas of subsurface uncertainty quantification, representative model selection, model calibration and optimization. The MS SFI method shows immense potential for handling prominent levels of reservoir heterogeneity. The challenge of including fine-scale heterogeneity, which is often overlooked, when scaling up EOR processes from laboratory to field, appears to have found a practical solution with a combination of MS SFI and high-performance computing (HPC).
- Europe (0.68)
- Asia > Middle East (0.67)
- North America > United States > Texas (0.28)
- Geology > Sedimentary Geology (0.46)
- Geology > Geological Subdiscipline (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
Abstract Building reliable subsurface models requires detailed knowledge of both the rock and fluids involved. One critical petrophysical property determining the viability of a development is the hydrocarbon saturation. In 3D geological models, the saturation is populated via Saturation height models and free fluid levels. In populating a 3D model with meaningful properties, measurements at various scales are integrated. Core measurements acquired at resolution far superior to that used in the 3D models require a change of scale-upscaling step. The process of accurately predicting water saturation in the upscaled model is not trivial. Here we follow this process by employing a saturation height model (SHM) at different scales in relationship to various permeability realizations. Multiple choices available as inputs into the SHM in various ranges of sensitivity with respect to the free water level position as well as different rock quality are looked at. Various degrees of heterogeneity are studied by using synthetic data, the saturation prediction accuracy based on upscaled input rock properties (like arithmetic/geometric and harmonic upscaled permeability) is investigated. For homogeneous rocks a workflow is detailed with the purpose of detecting the upscaling limits highlighting the possible errors that might appear in the upscaling process. A counterintuitive result is that in the transition zone (the focus of this work) permeable rocks are more prone to errors than the less permeable ones. We also conclude that no alteration of the SHM is necessary in the upscaling process. Given the fact that rock quality enters the SHM and that permeability upscaling follows a route that ultimately attempts to honor well performance, a natural question is what the relevance of such a permeability model as input for the SHM is. Our results highlight the best choices for an upscaled SHM input (upscaled) permeability- not necessarily the upscaled permeability used in history matching. Smallest errors are shown to be resulting from using geometrical or 1/3 power law upscaled permeability.
- North America > United States (0.46)
- Europe > Netherlands (0.28)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
Summary Seawater injection is widely used to maintain offshore-oil-reservoir pressure and improve oil recovery. However, injecting seawater into reservoirs can cause many issues, such as reservoir souring and scaling, which are strongly related to the seawater-breakthrough percentage. Accurately calculating the seawater-breakthrough percentage is important for estimating the severity of those problems and further developing effective strategies to mitigate those issues. The validation of using natural-ion boron as a tracer to calculate seawater-breakthrough percentage was investigated. Boron can interact with clays, which can influence the accuracy in seawater-breakthrough calculation. Therefore, the interaction between boron and different clays at various conditions was first studied, and the Freundlich adsorption equation was used to describe the boron-adsorption isotherms. Then, the boron-adsorption isotherms were coupled into the reservoir simulator to investigate the boron transport in porous media, and the results in turn were further analyzed to calculate the accurate seawater-breakthrough percentage. Results indicated that boron adsorption by different clays varied. pH value of solution can significantly influence the amount of boron adsorbed. As a result, the boron-concentration profile was delayed in coreflood tests. The accuracy of the new model was verified by convergence rate tests and comparison with analytical results. Furthermore, model results fit well with experimental data. On the basis of the reservoir-simulation results, the boron-concentration profile in produced water can be used to calculate the seawater-breakthrough percentage by considering the clay-content distribution. However, the seawater-breakthrough point cannot be determined by boron because the boron concentration is still at the formation level after seawater breakthrough due to boron desorption.
- Europe (1.00)
- North America > United States > Texas (0.93)
- Research Report > New Finding (0.64)
- Research Report > Experimental Study (0.50)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (4 more...)