Novel Simulation Techniques Used in a Gas Reservoir With a Thin Oil Zone: Troll Field

Henriquez, Adolfo; Apeland, Odd J.; Lie, Øystein; Cheshire, I.M.

doi:10.2118/21181-pa

Cited by 8 publications

(3 citation statements)

References 4 publications

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“…Several techniques have been used to avoid these problems. The most common technique in use is the application of Local Grid Refinements around horizontal wells, or across the entire oil column [3] . Although LGRs improve the general flow dynamics along the layers, the application will be constrained by the maximum allowed refinement in order to achieve acceptable CPU times.…”

Section: Grid Selectionmentioning

confidence: 99%

A New Approach to Thin Oil Zone Modeling in High-Dipping Multilayered Reservoirs

Tolstukhin

Olivier

2010

SPE EUROPEC/EAGE Annual Conference and Exhibition

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This paper focuses on maximizing oil recovery from thin oil rim in a high-dipping, multilayered reservoir in the North Sea. Oil output from thin oil zones between a gas cap and an aquifer is limited to uneconomical rates caused by water coning and gas cresting. Horizontal wells are widely used in thin oil rim development due to the limited pressure drawdown applied to the formation. The horizontal wells should be optimally positioned within the oil zone to avoid premature gas and water breakthrough. Critical issues for thin oil zone reservoir modeling are correct grid representation of internal heterogeneities, fluid saturation distribution, fluid contacts, horizontal well trajectories and flow displacement properties. In a stratigraphic grid, the lack of resolution affects the fluid contacts movement within the high-dipping reservoir layers. Similarly for a horizontal grid, thin reservoir intervals are truncated due to a 'stair-casing' effect, which leads to loss of communication within the layers. A hybrid grid was constructed to combine the benefits of the horizontal grid in the oil zone together with the stratigraphic grid in the water and gas zones. Such a grid framework provides the best modeling approach for representing the transition zone and fluid contact movements. In the study, the prediction of oil, gas and water production in the transition zone was difficult because the crude oil altered formation wettability after hydrocarbon migration and reservoir structure tilting. Multiphase flow was modeled by integrating the key dynamic reservoir controls, translated into end-point correlations above the free water level based on multivariate SCAL data analyses. Comparative analyses of alternative modeling techniques exhibited clear differences in the response for coning development and optimal well placements.

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Section: Grid Selectionmentioning

confidence: 99%

A New Approach to Thin Oil Zone Modeling in High-Dipping Multilayered Reservoirs

Tolstukhin

Olivier

2010

SPE EUROPEC/EAGE Annual Conference and Exhibition

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“…In a series of papers [59,49,46,38,2], modern VE methods for CO 2 sequestration were reinterpreted in the classical formulations developed during the early period of reservoir simulation [40,14,41,13], when time-step robustness and mass-conservation aspects using a limited computational budget was the primary focus. Similar formulations were also introduced in the commercial Eclipse simulator to model thin layers of oil in the Troll field [29]. The resulting formulation is an extension of the traditional pseudo-relative permeability and capillary pressure [32,34,60,8], which unifies the 3D and VE discretizations in a generalized model of multiphase flow with more complex functional dependencies than in traditional models.…”

Section: Introductionmentioning

confidence: 99%

Multiresolution coupled vertical equilibrium model for fast flexible simulation of CO2 storage

Møyner

Nilsen

2018

Comput Geosci

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CO 2 capture and storage is an important technology for mitigating climate change. Design of efficient strategies for safe, long-term storage requires the capability to efficiently simulate processes taking place on very different temporal and spatial scales. The physical laws describing CO 2 storage are the same as for hydrocarbon recovery, but the characteristic spatial and temporal scales are quite different. Petroleum reservoirs seldom extend more than tens of kilometers and have operational horizons spanning decades. Injected CO 2 needs to be safely contained for hundreds or thousands of years, during which it can migrate hundreds or thousands of kilometers. Because of the vast scales involved, conventional 3D reservoir simulation quickly becomes computationally unfeasible. Large density difference between injected CO 2 and resident brine means that vertical segregation will take place relatively quickly, and depth-integrated models assuming vertical equilibrium (VE) often represents a better strategy to simulate longterm migration of CO 2 in large-scale aquifer systems. VE models have primarily been formulated for relatively simple rock formations and have not been coupled to 3D simulation in a uniform way. In particular, known VE simulations have not been applied to models of realistic geology in which many flow compartments may exist in-between impermeable layers. In this paper, we generalize the concept of VE models, formulated in terms of well-proven reservoir simulation technology, to complex aquifer systems with multiple layers and regions. We also introduce novel formulations for multi-layered VE models by use of both direct spill and diffuse leakage between individual layers. This new layered 3D model is then coupled to a state-of-the-art, 3D black-oil type model. The formulation of the full model is simple and exploits the fact that both models can be written in terms of generalized multiphase flow equations with particular choices of the relative permeabilities and capillary pressure functions. The resulting simulation framework is very versatile and can be used to simulate CO 2 storage for (almost) any combination of 3D and VE-descriptions, thereby enabling the governing equations to be tailored to the local structure. We demonstrate the simplicity of the model formulation by extending the standard flow-solvers from the open-source Matlab Reservoir Simulation Toolbox (MRST), allowing immediate access to upscaling tools, complex well modeling, and visualization features. We demonstrate this capability on both conceptual and industry-grade models from a proposed storage formation in the North Sea. While the examples are taken specifically from CO 2 storage applications, the framework itself is general and can be applied to many problems in which parts of the domain is dominated by gravity segregation. Such applications include gas storage and hydrocarbon recovery from gas reservoirs with local layering structure. arXiv:1710.08735v1 [physics.comp-ph] 24 Oct 2017 simulation tools play a vital role to...

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“…A high-resolution grid is needed to capture fluid movement in the vicinity of the producing wells, while the size of the field prohibits such a grid field-wise. One successful compromise was presented by Henriquez, Apeland, Lie, and Cheshire [5], where they used local grid refinement (LGR) surrounding the wells and vertical equilibrium (VE) outside the LGR areas. Although good results were achieved there was (and still is) some uncertainty tied to the accuracy of the VE-to-LGR flow.…”

Section: Introductionmentioning

confidence: 99%

Horizontal simulation grids as alternative to structure-based grids for thin oil-zone problems: a comparison study on a Troll segment

Pettersen¹

2011

Comput Geosci

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The layering in reservoir simulation grids is often based on the geology, e.g., structure tops. In this paper we investigate the alternative of using horizontal layers, where the link to the geology model is by the representation of the petrophysics alone. The obvious drawback is the failure to honor the structure in the grid geometry. On the other hand, a horizontal grid will honor the initial fluid contacts perfectly, and horizontal wells can also be accurately represented. Both these issues are vital in thin oil-zone problems, where horizontal grids may hence be a viable alternative. To investigate this question, a number of equivalent simulation models were built for a segment of the Troll Field, both geology-based and horizontal, and various combinations of these. In the paper, it is demonstrated that the horizontal grid was able to capture the essentials of fluid flow with the same degree of accuracy as the geology-based grid, and near-well flow was considerably more accurate. For grids of comparable resolution, more reliable results were obtained by a horizontal grid than a geo-grid. A geo-grid with local grid refinement and a horizontal grid produced almost identical results, but the ratio of computing times was almost 20 in favor of the horizontal grid. In the one-phase regions of the reservoir, relatively coarse cells can be used without significant loss of accuracy.

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Novel Simulation Techniques Used in a Gas Reservoir With a Thin Oil Zone: Troll Field

Cited by 8 publications

References 4 publications

A New Approach to Thin Oil Zone Modeling in High-Dipping Multilayered Reservoirs

A New Approach to Thin Oil Zone Modeling in High-Dipping Multilayered Reservoirs

Multiresolution coupled vertical equilibrium model for fast flexible simulation of CO2 storage

Horizontal simulation grids as alternative to structure-based grids for thin oil-zone problems: a comparison study on a Troll segment

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