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Collaborating Authors
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)
Rapid Simulation of Unconventional Reservoirs by Multidomain Multiresolution Modeling Based on the Diffusive Time of Flight
Chen, Hongquan (Texas A&M University (Corresponding author)) | Li, Ao (Texas A&M University) | Terada, Kazuyuki (Texas A&M University) | Datta-Gupta, Akhil (Texas A&M University)
Summary The fast marching method (FMM)-based rapid flow simulation has been shown to accelerate simulation efficiency by orders of magnitude by transforming 3D simulation to equivalent 1D simulation using the concept of the “diffusive time of flight” (DTOF). However, the 1D transformation does not directly apply to multiwell problems. In this paper, we propose a novel DTOF-based multidomain multiresolution discretization scheme to accelerate multiwell simulation of unconventional reservoirs. Our method formulates multiwell simulation problems based on the DTOF which displays the pressure front propagation in unconventional reservoirs. The DTOF contours are used to partition the reservoir into local and shared domains. A local domain is where the flow is dominated by a single well, and the shared domain is where the fluid flow is influenced by multiple wells. The DTOF contours expand independently in local domains and interfere in the shared domain. After the partitioning, each domain is discretized using a multiresolution scheme whereby the original 3D fine mesh is preserved near the wells to account for detailed physics including gravity, and the rest of the domain is discretized into 1D mesh based on the DTOF contours to alleviate the simulation workload. The power and efficacy of our approach are demonstrated using synthetic and field-scale simulation models with different degrees of geologic and well-completion complexity. The simulation results, number of active cells, and computation time for the proposed discretization scheme are compared with the original high-fidelity 3D model for each case. The results show that the proposed method is suitable for multiwell simulation problems in unconventional reservoirs and can accelerate flow simulations by orders of magnitude with minimal loss of accuracy. The novelty of this work is the creation of DTOF-derived multiresolution discretization with local and shared domains to simplify and accelerate the calculation of subsurface flow problems, especially in unconventional reservoirs. Our workflow can be easily interfaced with commercial simulators, making it suitable for large-scale field applications.
- North America > United States > Texas (1.00)
- Europe (0.93)
- Asia (0.93)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- 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 > Formation Evaluation & Management > Drillstem/well testing (0.95)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (0.93)
Abstract In the development of shale plays, significant emphasis has been laid on forecasting well performance based on rates and finding the expected ultimate recoveries. Specifically, forecasting producing gas-oil-ratio (GOR) over the long term has been problematic, given the complexities and uncertainties in modeling a muti-stage fractured horizontal well in the unconventional reservoir. In this work, we propose a hybrid model which is capable of accurately forecasting multiphase flow rates. The proposed hybrid forecasting modeling is an amalgamation of data-centric methodology blended with physics-based principles, using easily available inputs such as production rates, flowing pressure, and fluid properties. The proposed method is a two-step procedure – (1) detect the inflection point up to which the gas produced is only the solution gas using an automated trajectory detection procedure, imposing physics-based constraints (2), apply the material balance to calculate dynamic drainage volume, average reservoir pressure, and productivity index that are used to forecast well performance in the future. The proposed approach also handles changing artificial lift strategies and hence changing bottom hole pressure conditions, which is a practical consideration since most unconventional wells experience operational changes throughout their lifecycle. The automated trajectory detection procedure consistently captures the inflection point for all wells and is robust to scale for all well types. The history-matched multiphase flow model parameters are blind-tested to validate the model. The proposed technique extrapolates reservoir pressure depletion based on established trends to forecast GOR trends with reasonable accuracy at an extremely low computational cost. The proposed hybrid model overcomes (1) deficiencies of pure data-driven approaches, where changes in operating conditions are not properly represented and the forecasts are not physically consistent, (2) limitations of analytical models, where the assumptions are too many/strict to represent the real-life performance of a multifracture horizontal well, and (3) complexities of numerical simulation models, which are expensive, time-consuming and requires too many inputs for initialization. Additionally, the proposed hybrid model provides a robust and scalable method to identify future GOR trends to support the pace of operations and data-driven decision-making.
- Europe (1.00)
- Africa (0.68)
- North America > United States > Texas (0.47)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (4 more...)
The paper presents an adjusted mathematical model of two-phase filtration processes in fractured porous media. Traditionally, the equations of two-phase filtration in a medium of dual porosity are based on the laws of conservation of oil and water phases in fractured and matrix (block) rock spaces. These equations are interconnected by some functions that describe phases flow between fractures and blocks, and these functions are taken proportional to the pressure difference between the phases in the rocks matrix and fractures. With the exception of transient processes, characterized by a sharp change in reservoir pressure, as occurs, for example, during hydrodynamic studies in wells, the indicated difference in hydrodynamic pressures in long-term waterflooding of productive formations is due only to capillary forces. For this reason, it is traditionally assumed that the displacement of oil from hydrophilic rocks matrix is due precisely to the processes of capillary impregnation of these blocks. At the same time, as shown in the article, mass transfer between rock matrix and fractures is also determined by the processes of mixing of two-phase fluid flows in the fractured space of the rock, and comparable in intensity to capillary impregnation, which also leads to a decrease in oil saturation of matrix and, accordingly, an increase in oil saturation of the fractured space. The proposed mathematical model, which takes into account both the processes of capillary impregnation of matrix and the mass transfer due to mixing of fluid flows in fractures, will allow a more adequate description of the processes of two-phase filtration in fractured-porous reservoirs.
- Europe > Norway > Norwegian Sea (0.24)
- Europe > Russia (0.16)
Abstract In hydrocarbon reservoirs, reservoir heterogeneity and fluid production/injection result in unique reservoir energy signature (waves/pulses) and determine its shape and propagation. Reservoir engineers uses this propagation of the pressure waves or pules to determine many key reservoir properties (e.g., drainage volumes, reservoir energy, rock properties, decline analysis, etc.) to help in evaluating different field development strategies. The objective of this paper is to illustrate applications of Fast Marching Method (FMM) in assessing reservoir performance, identifying reservoir patterns and anomalies from production/injection data, and predicting the reservoir response when considering modeling uncertainty for model calibration. The proposed hybrid approach in this work is a physics-constrained data-driven approach. It uses the diffusive time-of-flight (DTOF), this represents the propagation time of pressure disturbance/wave from a source or a sink, from which the drainage volumes can be obtained as it is the case in traditional well testing. The DTOF is calculated from the 3D diffusivity equation after the transformation to a 1D equation. The high frequency diffusivity solution can be casted in the form of the Eikonal equation to allow for an analytical computation of the DTOF, which is solved via the FMM. Using the DTOF calculated production and injection rates will help us inferring faults existence and their transmissibility, fracture networks (existence, location, orientation and direction, faults’ transmissibility, fractures’ conductivity, and inter-well connectivity network.). The fundamental concept is to formulate a solution of the diffusivity equation that describes the transient flow. In this work, several synthetic models were used to benchmark. The work demonstrates how the DTOF was used to: generate pressure maps for reservoir monitoring, predicts the operational constraints (e.g., bottom-hole pressure) drainage volumes, and predict new wells’ performance. FMM results approximately matches in terms of well performance compared to simulation results; the DTOF gives a great insight about the pressure drop in the reservoir during the early- and mid-stages of the simulation. For a relatively short time intervals, FMM proved to be computationally efficient with a much shorter turnaround time to solve the problem, and closely matching the results obtained from numerical reservoir simulation. The physics-constrained data-driven using the DTOF was able to identify the pressure drop for the whole reservoir and to predict the bottom-hole pressure for the wells. Using the DTOF, it is possible to infer major geological features such as faults, fracture networks and regional heterogeneity. Fast Marching Method is an efficient method for solving the diffusivity equation for the DTOF to quickly give engineers an insight into the reservoir pressure (energy) and contacted reservoir volumes in order to maintain evergreen reservoir models.
- Asia > Middle East (0.46)
- North America > United States (0.28)
- Geology > Geological Subdiscipline > Geomechanics (0.35)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.34)