109 research outputs found
Calculating Equivalent Fracture Network Permeability of Multi-Layer-Complex Naturally Fractured Reservoirs
No full textAbstract
Modeling naturally fractured reservoirs (NFRs) requires an accurate representation of fracture network permeability. Conventionally, logs, cores, seismic, and pressure transient tests are used as data base for this. Our previous attempts showed that a strong correlation exits between the fractal parameters of 2-D fracture networks and their permeability (Jafari and Babadagli, 2008, 2009a). We also showed that 1-D well (cores-logs) and 3-D reservoir data (well test) may not be sufficient in fracture network permeability (FNP) mapping and 2-D (outcrop) characteristics are needed (Jafari and Babadagli, 2009b). This paper is an extension of these studies where only 2-D (single layer, uniform fracture characteristics in z-direction) representations were used.
In this paper, we considered a more complex and realistic 3-D network system. 2-D random fractures with known fractal and statistical characteristics were distributed in the x-, and y-directions. Variation of fracture network characteristics in the z-direction was presented by a multi layer system representing three different facieses with different fracture properties. Wells were placed in different locations of the model to collect 1-D fracture density and pressure transient data. In addition, five different fractal and statistical properties of the network of each layer were measured.
The equivalent fracture network permeability (FNP) was calculated using a commercial software package as the base case. Using available 1-D, 2-D, and 3-D data, multivariable regression analyses were performed to obtain equivalent FNP correlations for many different fracture network realizations. The derived equations were validated against a new set of synthetic fracture networks and conditions at which 1-D, 2-D and 3-D are sufficient to map fracture network permeability were determined. The importance of the inclusion of each data type i.e. 1-D, 2-D and 3-D, in the correlations was discussed.</jats:p
Field Scale Modeling of Tracer Injection in Naturally Fractured Reservoirs using the Random-Walk Simulation
No full textAbstractModeling complex transport processes in naturally fractured reservoirs (NFRs) using classical continuum models may not be practically possible, because using classical algorithms for the detailed structure of fracture-matrix system requires unreasonable computational time. Also, fractured reservoirs are highly heterogeneous, and finite-difference calculations for such models often cause convergence problems. In addition to these, an exact representation of a complex fracture network in classical continuum modeling algorithms is highly difficult. An alternative is to use a non-classical technique known as the Random Walk Particle Tracking (RWPT) algorithm.We showed earlier (Stalgorova and Babadagli, 2009) that the random walk (RW) technique can be adapted to model miscible flooding in a fractured porous medium at the lab scale. The unknown parameters used to match the model results were only diffusion coefficients for oil and solvent, as the diffusive/dispersive transport (effective if fracture and matrix) was coupled with viscous (effective in fracture) and gravity (effective in fracture and matrix) displacement. Advantages of this method over classical simulation are: (1) shorter computational time, which allows avoidance of simplifications, and (2) the ability to model the matrix-fracture diffusion process without any transfer function.In the present paper, we modified this lab scale RW model for field scale applications. For validation, a series of tracer test results from the Midale field in Canada was used. Fracture network model was constructed based on geological data, and then we used the RWPT model to calibrate the fracture network against tracer test results.We performed a sensitivity analysis to identify the importance of different parameters for the simulation results. The new model and observations can be used to validate and calibrate stochastically generated fracture network models and to estimate the EOR performance of NFRs.</jats:p
Generating 3D Permeability Map of Fracture Networks Using Well, Outcrop, and Pressure-Transient Data
No full textSummary
Well-log and core information, seismic surveys, outcrop studies, and pressure-transient tests are usually insufficient to generate representative 3D fracture-network maps individually. Any combination of these sources of data could potentially be used for accurate preparation of static models.
Our previous attempts showed that there exists a strong correlation between the statistical and fractal parameters of 2D fracture networks and their permeability (Jafari and Babadagli 2009). We extend this work to fracture-network permeability estimation using the statistical and fractal properties data conditioned to well-test information. For this purpose, 3D fracture models of 19 natural-fracture patterns with all known fracture-network parameters were generated initially. It is assumed that 2D fracture traces on the top of these models and 1D data from imaginary wells that penetrated the whole thickness of the cubic models were available, as well as pressure-transient tests of different kinds. The 1D and 2D data include statistical parameters and fractal characteristics of different features of the fracture system. Next, the permeability of each 3D fracture-network model was measured and then converted to a grid-based permeability map for drawdown well-test simulations using commercial software packages.
Finally, an extensive multivariable-regression analysis (MRA) using the statistical and fractal properties and well-test permeability as independent variables was performed to obtain a correlation for equivalent fracture-network permeability. The equations were derived using different natural-fracture-network patterns. The cases requiring well (logs and cores) and reservoir (pressure-transient tests) data were identified. It was found that an equation honoring all types of data [i.e., outcrop (2D), wellbore data (1D), and welltest analysis (3D)] can accurately predict the actual permeability of the fracture system. For certain fracture-network types, reliable correlations can be obtained without 2D data, which are relatively difficult to obtain. These types of patterns were identified.</jats:p
Recovery Improvement by Chemical Additives to Steam Injection: Identifying Underlying Mechanisms Through Core and Visual Experiments
No full textAbstract
Steam injection of any kind (flooding, cyclic, or gravity drainage) is a proven heavy-oil recovery method; however, it also involves excessive costs due energy and water needed for steam generation. Any effort in reducing this cost or improving oil recovery is essential for sustainable production, especially in times of low oil prices. Chemical additives to steam were suggested a few decades ago to improve two major mechanisms, namely heat transfer and interfacial phenomena, but research in that area discontinued due to the cost and thermal stability problem of the additive chemicals. With recent advancements in nano-technologies, new generation chemicals showed potential to reconsider chemical additives to improve the efficiency of steam injection. This, however, requires extensive research especially for mechanism identification. The objective of this paper is to identify the flow characteristics and the mechanisms involved in recovery enhancement by chemical additives through core and visual tests.
To mimic the gravity assisted drainage and flooding type steam displacement tests we performed previously (Bruns and Babadagli 2017) on cores saturated with 27,000 heavy-crude-oil, a visual Hele-Shaw model was designed to simulate the same process and identify the physical characteristics of the steam-condensate-oil interface and the role played by added chemicals. Majority of the chemicals/chemical blends showed either improvement in the rate or ultimate recoveries in the coreflooding tests and, based on this data, the best performing and the most thermally stable chemicals were selected for the visual tests. These chemicals include ionic liquids, internal olefin sulfonate, biodiesel (thermally stable surface active agents) and solvents (heptane), and nano-fluids (silicon oxide). The chemical solution was injected at constant rate and pressure after being vaporized in an oven along with steam and the whole process was recorded with a camera.
The contribution to recovery improvement through these phenomena in flooding and gravity controlled cases were identified. Foaming, emulsification, and IFT reduction yielding reduced drag forces between two phases at the interface were observed to be the main reason for positive contribution of chemicals. Biodiesel (Surfactant 1) exhibited a diffusion-like behavior near the injection port where no residual oil was noticed. The solvent (heptane), simulating ES-SAGD, stabilized the flow of steam in the late stage of the experiment due to the viscosity reduction. Improved oil + condensate drainage was assumed to be the contributing mechanism because of the change in surface properties during the injection of the ionic liquid. Nanoparticle, silicon oxide, and the internal olefin sulfonate (Surfactant 2) showed similar improvements in tip-splitting of the displacing fingers. It was concluded that the interfacial tension (IFT) reduction resulted in a wider occupation of the Hele-Shaw cell (better lateral sweep).</jats:p
Mechanics and Up-Scaling of Heavy Oil Bitumen Recovery by Steam-Over-Solvent Injection in Fractured Reservoirs (SOS-FR) Method
No full textAbstract
Recently, the steam-over-solvent injection in fractured reservoirs (SOS-FR) method was proposed as a potential solution for efficient heavy-oil/bitumen recovery in oil-wet naturally fractured reservoirs. The method is based on initial injection steam (Phase-1), followed by solvent (Phase-2). In the third cycle (Phase-3), steam is injected again to recover more oil and retrieve the solvent. Solvent retrieval during the third cycle was observed to be very fast if the temperature is around the boiling point of the solvent. This process is controlled by efficient matrix recovery and the mechanics of the process needs to be clarified to further determine the efficient application conditions for the given matrix and oil characteristics.
Single matrix behavior during the process was numerically modeled for static conditions and the results were matched with the experimental observations. The physics of the recovery mechanism was analyzed through visual inspection of saturation and concentration profiles in each cycle. The major observation was the substantial effect of gravity in oil recovery when the matrix was exposed to solvent. Special attention was given to the solvent retrieval rate and amount in Phase-3 and the permeability reduction due to asphaltene precipitation in Phase-2. This phenomenon was modeled using a permeability function changing with spatial coordinates and time, i.e. k=f(x, y, z, t). It was observed that permeability reduction due to asphaltene precipitation is significant and needs to be taken into account in modeling the process.
After showing the effect of the matrix size on the oil recovery and solvent retrieval, an up-scaling analysis was performed. The log-log relationship between the time value to reach ultimate recovery and the matrix size yielded a straight line relationship with a non-integer exponent less than two for all three phases of the process. The observed straight line relationship (and the exponent values obtained) is highly encouraging to extend the study to obtain a universal scaling relationship.</jats:p
Selection of Proper EOR Method for Efficient Matrix Recovery in Naturally Fractured Reservoirs
No full textScaling of Co-Current and Counter-Current Capillary Imbibition for Surfactant and Polymer Injection in Naturally Fractured Reservoirs
No full textOPTIMIZATION OF CO2 INJECTION FOR SEQUESTRATION / ENHANCED OIL RECOVERY AND CURRENT STATUS IN CANADA
No full textEffect of fractal permeability correlations on waterflooding performance in carbonate reservoirs
No full textScaling of Capillary Imbibition Under Static Thermal and Dynamic Fracture Flow Conditions
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