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Collaborating Authors
Kamp, A. M.
Abstract Smart water injection or low-salinity water flooding is an enhanced oil recovery technique for fractured reservoirs. The mechanism of low-salinity water flooding is performed by altering the wettability of rock towards water-wetness. This study presents an evaluation of low-salinity water flooding based on a brown field fractured reservoir properties by using explicit simulation of spontaneous imbibition at a fine scale (single and multiple matrix block level), and assessing the validity of dual-medium simulation models, which will be further used to perform modelling at the full field scale. Some reservoir parameters were varied within plausible range to quantify their impact on the recovery mechanism. To mitigate the biases of dual-medium models, upscaling and pseudoisation techniques were applied to match the behaviour of explicit fine-scale single-porosity model. A particular emphasis on the modelling of salt diffusion is made through one-dimension model. It was found that, whereas pressure diffusion is rather well represented by the usual matrix-fracture exchange coefficient formalism, the underlying assumption of pseudo-steady state seems to be inappropriate for salt diffusion phenomenon. When salt diffusion is the main driver for low salinity water imbibition, for example at the early times of a switch from high salinity to low salinity, it appears that the salt diffusion process occurs in a transient regime that cannot be properly represented by the pseudo-steady state regime assumption. This has an impact on the modelled incremental recovery and consequently on the low salinity flooding efficiency evaluation.
- North America > United States > Texas (0.54)
- Europe > United Kingdom > North Sea (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.61)
Abstract In fractured reservoir, the use of the so-called cubic law represents a method to describe fluid flow through fractures and to estimate effective fracture porosity from effective fracture permeability and matrix block size. The method supposes perfect fracture connectivity. In practice, however, it often underestimates field fracture porosity. This paper explores the relation between fracture porosity, fracture permeability and matrix block size using field, and in particular well test, data. We used field data coming from four naturally fractured sand-stone reservoirs in foothills. Values of storativity ratio (ω) and inter-porosity flow coefficient (λ) coming from thirty-three pressure buildup derivatives interpretations are listed and used to estimate fracture porosity and matrix block size. The effective permeability associated to each well test, which is obtained from the stabilization of the pressure derivative, was also recorded. A non-linear regression was put in place in order to correlate fracture porosity, matrix block size and effective permeability. Obtained fracture porosities and block sizes are similar to values from other sources, such as thin section analysis and image log data. The most significant finding is that field data can be correlated by introducing in the cubic law a correction parameter that increases fracture porosity by about two orders of magnitude. The reason for deviation from the theoretical cubic law can be threefold: first, the cubic law considers the entire hydraulic aperture of the fracture as contributing to the fluid flow, while in reality the flow may be hindered by presence of cement in-filling the fracture (thin section data supports this assumption); secondly, the cubic law assumes a perfectly connected fracture network, while in real cases some fractures may die out without intersecting any other fracture; thirdly, transient flow effects and distribution of block sizes may lead to a less well pronounced dip in the derivative, which may be interpreted as a larger fracture porosity when using a pseudo steady-state model for analysis. The correction parameter is likely not universal, and will depend on the degree of fracture in-fill and connectivity in a given field. The work presented in this paper provides fracture permeability, fracture porosity, and block size estimates for the given type of environment. It issues a strong warning with respect to the application of the cubic law to estimate fracture porosity, and proposes a corrected cubic law expression that gives more accurate results. The methodology is useful for characterizing fracture porosity, a parameter that is notoriously difficult to measure.
Abstract Reservoir models for fractured reservoirs are mainly dual-porosity models, and assume a unique equivalent fracture scale. However, fractured reservoirs are generally characterized by a multitude of fracture scales, ranging from small-scale diffuse fractures to large-scale seismic faults. This paper presents a methodology to extend single-fracture-scale dual-porosity models to situations with more scales, and investigates the optimal number of fracture scales. We focus on what happens at local level (zero-dimensional system of one cell) in case of a singlephase sequential flow through different fracture levels with some fracture pattern assumptions. Different options to turn a continuous fracture distribution into a given number of discrete levels are investigated. Eventually, based on dimensionless coefficients, an optimal number of fracture scales is determined by lumping levels with similar behaviour. Rate-limiting transfer occurs between these lumped levels. The dimensionless parameters that are defined are similar to the dimensionless parameter lambda used in dual porosity well test interpretation. They are a dimensionless representation of transfer rates. Each rate is also characterized by a dimensionless time, which is the reciprocal of the dimensionless transfer coefficient. The lumping of scales is thus done in between groups that are separated by low dimensionless transfer coefficients (slow transfer). Examples are shown of cases in which a 5-scale representation can be lumped to two scales (dual porosity) or three scales (triple porosity fracture- fracture-matrix). This study is a first step towards a reservoir modelling representing more than one single fracture scale, and sets a general methodology for lumping scales in a single-phase context. However for practical application the multiscale issue is even more relevant for multi-phase flow, and must be addressed. Such extension will be part of future work, which will also include implementing multiple scale models in 3D reservoir simulation.
- South America (0.28)
- Europe > Austria (0.28)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
Abstract By solving a 1-D heat equation for single phase flow, Butler et al. (1981, 1985) derived their classical SAGD equation, which has excellent predictive capability at experimental scales but performs poorly at field scales. Several authors have tried to remedy this by accounting for multiphase flow at the steam-bitumen boundary and their efforts have resulted in modified expressions for the oil rate incorporating rate multipliers. The practice of applying rate multipliers, however results in models that seem to vary for each reservoir or experiment. Recently, by making the prior assumption that fluid saturations ahead of the steam chamber vary linearly with temperature, Sharma and Gates (2010) derived a SAGD equation that accounts for multiphase flow ahead of the steam chamber, which performs excellently at field scales but poorly at experimental scales. In this work, we couple the multiphase mass conservation equations with the energy equation and show that the multi-scale, multiphase flow phenomenon associated with SAGD is the classical Marangoni (thermo-capillary) effect which can be characterized by the Marangoni number. At low Marangoni numbers (typical of experimental scales) we get the Butler solution while at high Marangoni numbers (typical of field scales), we approximate the Sharma & Gates solution. We present results from our model in dimensionless space so they can be used as a fast SAGD predictive model within a proxy-based history matching process.
- Information Technology > Data Science > Data Mining (0.54)
- Information Technology > Modeling & Simulation (0.34)
Abstract Some hydrocarbon recovery processes are characterized by the existence of sharp saturation and/or concentration fronts. Examples of such processes are VAPEX, in situ combustion, or water flooding of heavy oil reservoirs in presence of viscous fingering. In order to simulate correctly what happens around the fronts, small grid sizes need to be used. If however the whole reservoir is gridded very finely, computational time becomes prohibitive. In order to circumvent this problem, dynamic gridding, also callled, automatic mesh refinement may be used. During the computation, the computational grid is adapted to the dynamics of the flow. This requires the use of an estimator in order to decide where to refine or to coarsen the grid. In this work we studied dynamic gridding for a water flooding problem. We implemented this problem using the mixed hybrid finite element method in 2-D on a triangular grid. The resulting code was validated by comparison to a commercial reservoir simulator. From literature, we adapted an a posteriori estimator that had been derived for incompressible flow, and we used this to refine our grid on each time step. We show that the grid refinement criterion captures relatively well the sharp saturation front. Heterogeneities are also well captured. The code is able to reproduce some tendencies of viscous fingering, although more time is required to avoid definitely the numerical disperion and dynamic gridding influence. This work is a preamble for a second work considering simulation of the VAPEX process using dynamic gridding. For this we decided to switch to the finite volume method, for which a second code was developed which is shortly mentionned in the perspectives. We think that dynamic gridding may be a solution that will allow the simulation of processes such as VAPEX and in situ combustion at reservoir scale, using effective grid refinement in the region of the front.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.41)
The Influence of Salt Concentration in Injected Water on Low Frequency Electrical-Heating Assisted Bitumen Recovery
Bogdanov, I. I. (CHLOE, University of Pau, France) | Torres, J. A. (CHLOE, University of Pau, France) | Akhlaghi, H. A. (CHLOE, University of Pau, France) | Kamp, A. M. (CHLOE, University of Pau, France)
Abstract Steam injection is often not a good alternative for oil recovery from shallow bitumen reservoirs; for instance, the thin cap-rock creates the danger of steam breakthrough. For deeper reservoirs the heat losses from injection well may be prohibitive. A technology that may be better suited is oil recovery aided by electrical low frequency heating of the reservoir. This technology, well known for environmental remedial applications, has been recently field-tried, yielding promising results. The process uses electrical conductivity of connate water to propagate an alternating current between electrodes, inducing the Joule heating of the reservoir. An associated problem is the appearance of hot spots around the electrodes that may be relieved by water circulation. However, the water circulation may have a significant effect on the heating process because the electrical conductivity of the circulated water depends on its salt content. In order to find out the influence of salt concentration on process efficiency we have studied the process of salt water recirculation around an electrode using numerical simulation. The physical properties and operational data for Athabasca bitumen have been collected from the literature. The model built with CMG STARS™ simulator and tested first with available analytical solutions, has been validated and the proper choice of the underlying grid and numerical tuning parameters has been verified. The process was also studied at field scale for a common pattern of electrodes and production wells. The salt turned out to penetrate into the reservoir, far beyond the major water circulation zone around the electrodes. This process increases the electrical conductivity in a large region between electrodes, which improves the heating of the reservoir. The single-electrode simulation studies using the different tools yielded similar results for a simple problem. More complex (and more realistic) field-scale simulations show that adding salt enhances finally the oil production. In practice an upper concentration limit is given by corrosion problems at the electrodes. The reservoir simulation of bitumen recovery assisted by low-frequency heating is a challenging multiphysics problem. The understanding of the influence of salt concentration on the circulated water provided by this work is an important key in process design considerations.