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One of the final goals of any reservoir characterization study is to deliver reliable production forecasts. This is definitely a challenging task as the fluid flow dynamics is governed by non-linear equations: a small perturbation in the reservoir model inputs might have a large impact on the modelling outputs, thus the forecasts. Also, depending on the maturity of a project, engineers have various amounts and types of data to deal with and to history match through an optimization process.
Considering the case of a mature asset, for which massive datasets of various types are available, the standard history matching process is based on the minimization of a single objective function (history matching criteria), computed through weighted least squares formulation. The difficulty is then to (user) define properly the weight of each data set before the summation itself into the single objective function is performed.
To avoid this difficulty, two currently available but yet prospective – in geosciences application - optimization techniques are considered. The former is based on the definition of multiple objective functions (based on data types and/or location on the field) coupled to an optimization process. If all the objective functions minimize trends together, the user has still the flexibility to assess one by one the individual objective functions minimization. On the contrary, if the objective functions are minimizing/maximizing trends in competition (e.g. because of noisy data), then the derived Pareto front (in 2D case) would identify the location of optimal compromises. The latter is a sequential optimization approach based on single-objective constrained optimizations: optimize each objective at a time with constraints on the other objectives. The thresholds defined for the constraints on the objectives are derived from the results of the previous optimization results. This pragmatic approach allows to prioritize the objectives and tunes the expected accuracy on each data type.
Both approaches are applied to a real field gas storage asset with more than 40 years of exploitation history and various data types e.g. pressures, saturations as well as gas breakthrough of control wells, leading to the definition of multiple (possibly more than 2) objective functions. Both show promising results in terms of history matching quality and in terms of flexibility as the user might be able to consider, define and update dynamically alternative history matching strategies. These approaches might be considered as alternatives to the standard one for the history matching process, preliminary to the production forecasts computation, even if the associated challenges and complexity are growing accordingly to the number of objective functions.
Enhanced-Oil-Recovery processes for Naturally-Fractured Reservoirs usually require fluids mobility control in the fractures, which can be ensured by foam-based processes. The latters have to demonstrate stability over very long distance as their efficiency rely on the pressure increase in the fractures network. Despite their potential, the ability of foams to propagate and regenerate in fractures, but also the most adapted design of foaming-surfactant formulations, are poorly documented. These issues are addressed in this experimental paper.
The propagation of foams over long-distance fractures (from 100 to 1000 meters) is modelled at the lab-scale by a flow of pre-formed foams in long vertical and horizontal tubings (from 0.01m to 10 meters). The visualization of the flowing foam and the measurement of pressure allow identifying the physical phenomena which account for foam evolution in horizontal and vertical configurations. Comparison of performances is also conducted for several formulations differing by their foam performances in sandpack and by their wettability alteration properties.
A preliminary test shows that co-injection of gas and liquid in a representative oil-wet fracture generates very poor foams, unlike classical porous media (sandpacks, rock core samples). This poor rejuvenation of foam evidences that foam flow in fracture strongly differs from observations in porous matrix and highlights the need for long-term foam stability. In long tubings, characterization of different formulations first shows that the most efficient foams do not correspond to the best formulations identified for porous media. Criteria to optimize a foam formulation for fracture network seem specific. Second, the evolution of flowing foams highly differs from static foams and highlights the difference of performances brought by the flow. The local foam flow structure is different from one formulation to another. These results suggest that the ability to create a high pressure gradient depends on wettability properties of formulation, due the strong interaction of foam lamellae with walls along the flow.
To ensure an efficient foam-based process in a fractured reservoir, long-term stability is crucial yet not predicted by classical criteria based on porous media experiments. Besides, the best foaming-surfactant formulation for fractured systems corresponds to new criteria, likely related to wettability instead of apparent viscosity. This work has important implications on the design of foam injections in naturally fractured reservoirs regarding the calculation of liquid volumes, injection strategy to ensure foam propagation over long-distance.
Carbonate Brazilian pre-salt fields have a large number of faults detected by seismic and well data. Nevertheless, because of limitations in seismic resolution, all existent faults cannot be identified. That is one of the main challenges for understanding related heterogeneities (vugs, karst) and the flow behavior. This paper deals with a fault analysis and modeling using an original approach and fault data of three pre-salt reservoirs.
One possible approach for characterizing and modeling the fault network (
The results presented on this article lead us to discuss the importance of how to choose the samples for modeling sub-seismic faults based on the ensemble of seismic faults available. This article answers the question about which available seismic faults we should use for estimating fractal dimension, should we use all available seismic faults near of the reservoir area or use only the faults inside the reservoir contour. After this short discussion on the fractal dimension choice from a spatial distribution point of view, the impact of this choice on flow was illustrated. The sub-seismic fault models were modeled using different fractal dimension. Subsequently, an upscaling step using analytical upscaling (
Characterizing sub-seismic faults has a major impact on the overall flow behavior of the field. The chosen methodology has been applied only on synthetic cases but never published using real data. This work will interest a practicing engineer. The fault network of these neighbor reservoirs allows us to illustrate the importance on the choice of fractal dimension for characterizing the fault network and its impact on the subseismic models and fluid displacement, consequently on production.
Unconventional shale-gas and tight oil reservoirs are commonly naturally fractured, and developing these kinds of reservoirs requires stimulation by means of hydraulic fracturing to create conductive fluid-flow paths through open-fracture networks for practical exploitation. The presence of the multiscale-fracture network, including hydraulic fractures, stimulated and nonstimulated natural fractures, and microfractures, increases the complexity of the reservoir simulation. The matrix-block sizes are not uniform and can vary in a very wide range, from several tens of centimeters to meters. In such a reservoir, the matrix provides most of the pore volume for storage but makes only a small contribution to the global flow; the fracture supplies the flow, but with negligible contributions to reservoir porosity. The hydrocarbon is mainly produced from matrix/fracture interaction. So, it is essential to accurately model the matrix/fracture transfers with a reservoir simulator.
For the fluid-flow simulation in shale-gas and tight oil reservoirs, dual-porosity models are widely used. In a commonly used dual-porosity-reservoir simulator, fractures are homogenized from a discrete-fracture network, and a shape factor based on the homogenized-matrix-block size is applied to model the matrix/fracture transfer. Even for the embedded discrete-fracture model (EDFM), the matrix/fracture interaction is also commonly modeled using the dual-porosity concept with a constant shape factor (or matrix/fracture transmissibility). However, in real cases, the discrete-fracture networks are very complex and nonuniformly distributed. It is difficult to determine an equivalent shape factor to compute matrix/fracture transfer in a multiple-block system. So, a dual-porosity approach might not be accurate for the simulation of shale-gas and tight oil reservoirs because of the presence of complex multiscale-fracture networks.
In this paper, we study the multiple-interacting-continua (MINC) method for flow modeling in fractured reservoirs. MINC is commonly considered as an improvement of the dual-porosity model. However, a standard MINC approach, using transmissibilities derived from the MINC proximity function, cannot always correctly handle the matrix/fracture transfers when the matrix-block sizes are not uniformly distributed. To overcome this insufficiency, some new approaches for the MINC subdivision and the transmissibility computations are presented in this paper. Several examples are presented to show that using the new approaches significantly improves the dual-porosity model and the standard MINC method for nonuniform-block-size distributions.
Relative permeabilities are a first-order parameter to consider when describing multiphase flows in porous media. Among many other parameters, the core wettability controls the fluids repartition in the porous media at pore scale, strongly affecting how the fluids can be displaced (i.e., their relative permeabilities). As the initial wettability of cores sampling a reservoir is rarely preserved, classical SCAL measurements (such as relative permeabilities) may not reflect the rock properties at reservoir conditions. This original core wettability may be restored in a process referred as ‘core aging’. It is generally done by injecting the core with the reservoir fluids (brine and crude-oil) to equilibrate the rock surface with respect to the oil and brine components. Here, we investigated the effect of two aging protocols (static and dynamic) on wettability restoration, and characterize the aging using oil/water relative permeabilities measured on the core after aging. The two aging protocols were applied on a set of initially strongly water-wet outcrop sandstone samples (Bentheimer). The relative permeabilities were measured using the steady-state method and a state-of-the-art experimental setup (CAL-X) based on X-ray radiographies. The setup is equipped with an X-ray radiography facility, enabling monitoring of 2D local saturations in real time and thus giving access to fluid flow paths during the flooding. The relative permeability curves of aged samples show clear differences when compared to water-wet relative permeabilities, hence. suggesting that the wettability has been effectively altered. However, the two aging protocols were unable to produce the same results. The dynamic aging has led to an inversion of the original relative permeability curves asymmetry, suggesting a strongly oilwet system, whereas the static aging protocol has altered the wettability to a lesser extent. The differences can be explained by analyzing 2D saturation maps. In the case of dynamic aging we observed a homogeneous distribution of fluid saturation during fractional flow. In contrast, the static protocol results in heterogeneous flow paths, confirming that this protocol did not uniformly alter the wettability of the sample and generates a patchier mixed-wettability system.
In naturally fractured carbonate reservoirs, Gas Oil Gravity Drainage processes (GOGD) are successfully implemented but oil recovery is limited by a slow kinetics. However a gas EOR process represents a promising alternative to boost this oil production rate. Nevertheless the design of this process should address several technical challenges: the typically unfavorable wettability of the matrix (intermediate to strongly oil-wet), the densely connected fracture network and the high contrast of fracture-to-matrix permeability.
We propose here the injection of a advanced EOR foam with reduced interfacial tension. The foam flow in the fracture creates an important viscous drive leading to a pressure gradient, which increases the oil recovery dynamics compared to GOGD. Besides, the reduced interfacial tension (IFT) between crude oil and aqueous phase allows the aqueous phase to enter the matrix despite the unfavorable wettability.
In this paper, we demonstrate that a balance exist between IFT and foam strength performances to optimize the process. Three foam formulations are optimized with very different profiles in terms of IFT and foam performances. For their design, priority is given either to ultra-low IFT values (10-3mN/m) or to a strong foam with larger IFT (0.35mN/m) or to a balance between the two first formulations (0.03mN/m). Foams are evidenced as intrinsically less stable in ultra-low IFT conditions: apparent viscosity (in porous media) in contact with oil is respectively enhanced by a factor 40 when IFT rises from 10−3 to 10−1mN/m. Based on sandpack and coreflood experiments, we recommend an IFT in the order of 10−1 mN/mas a balance between the viscous drive in fracture and an efficient aqueous phase imbibition in the oil-wet matrix. Simulation work supports this experimental conclusion: the common target of IFT in the order of 10−3 mN/m determined by capillary desaturation curves in SP flooding can be adjusted to a higher IFT value, which can be deduced from the wettability of the reservoir.
To ensure an accelerated oil recovery in naturally fractured carbonate reservoirs, we recommend the design of a low-IFT foam formulation with revised IFT performances compared to a classical Surfactant-Polymer process targeting residual oil. Indeed, the final process is likely more efficient if the target of IFT is defined by wettability requirements rather than residual oil desaturation. This article gives the target formulation parameters which arise from the mechanisms at play (viscous drive and imbibition in oil-wet matrix), and are realistically achieved with industrial surfactants.
Unconventional tight-oil and shale-gas reservoirs are usually naturally fractured, and developing this kind of reservoirs requires stimulation via hydraulic fracturing to create conductive fluid flow paths via open fracture networks for practical exploitation. The presence of the multi-scale fracture network, including hydraulic fractures, stimulated and non-stimulated natural fractures, and micro-fractures, increases the complexity of the reservoir simulation. The matrix block sizes are not uniform, and they can vary in a very wide range, from several tens of centimeters to several tens of meters. In such a reservoir, the matrix provides most of the pore volume for storage, but makes few contributions to the global flow, while the fracture supplies the flow, however, with negligible contributions to reservoir porosity. The hydrocarbon is mainly produced from matrix-fracture interaction. So, it is essential to model accurately the matrix-fracture transfers with a reservoir simulator.
For the fluid flow simulation in tight-oil and shale-gas reservoirs, dual-porosity models are widely used. In a dual-porosity model, fractures are homogenized, and a shape factor, based on the homogenized matrix block size, is applied to model the matrix-fracture transfer. However, in real cases, the discrete fracture networks are very complex and non-uniformly distributed. One cannot determine an equivalent matrix block to compute the shape factor. So, a dual-porosity model is not accurate for the simulation of tight-oil and shale-gas reservoirs due to the presence of complex multi-scale fracture networks.
In this paper, we will study the MINC (Multiple Interacting Continua) method for the flow modeling in fractured reservoirs. MINC is usually considered as an improvement of the dual-porosity model. However, a standard MINC approach, using transmissibilities derived from the MINC proximity function, cannot always handle correctly the matrix-fracture transfers when the matrix block sizes are not uniformly distributed. To overcome this insufficiency, we present some new approaches for the MINC subdivision and the transmissibility computations. Several examples are presented to show that using the new approaches improves significantly the dual-porosity model and the standard MINC method for non-uniform block size distributions.
Ding, Didier Y. (IFP Energies Nouvelles) | Farah, Nicolas (IFP Energies Nouvelles) | Bourbiaux, Bernard (IFP Energies Nouvelles) | Wu, Yu-Shu (Colorado School of Mines) | Mestiri, Imen (IFP Energies Nouvelles)
Unconventional reservoirs, such as shale-gas or tight oil reservoirs, are generally highly fractured (including hydraulic fractures and stimulated and nonstimulated natural fractures of various sizes) and embedded in low-permeability formations. One of the main production mechanisms in unconventional reservoirs is the flow exchange between matrix and fracture media. However, because of extremely low matrix permeability, the matrix/fracture exchange is very slow and the transient flow may last several years to tens of years, or almost the entire production life. The commonly used dual-porosity (DP) modeling approach involves a computation of pseudosteady-state matrix/fracture transfers with homogenized fluid and flow properties within the matrix medium. This kind of model clearly fails to handle the long-lasting matrix/fracture interaction in very-low-permeability reservoirs, especially for multiphase flow with phase-change problems. Moreover, a DP model is not adapted for the simulation of matrix/fracture exchange when fractures are described by a discrete-fracture network (DFN). This paper presents an embedded discrete-fracture model (EDFM) dependent on the multiple-interacting-continua (MINC) proximity function to overcome this insufficiency of the conventional DP model.
Hosseini-Nasab, S. M. (Amirkabir University of Technology) | Douarche, F. (IFP Energies Nouvelles) | Nabzar, L. (IFP Energies Nouvelles) | Simjoo, M. (Sahand University of Technology) | Bourbiaux, B. (IFP Energies Nouvelles) | Roggero, F. (IFP Energies Nouvelles)
This paper presents an novel integrated approach for numerical simulation of foam core-flood experiments in the absence and presence of oil. The experiments consisted of the co-injection of gas and Alpha-Olefin Sulfonate (AOS) surfactant solution into Bentheimer sandstone samples initially saturated with the surfactant solution [see (Simjoo & Zitha, 2013)]. The foam model implemented is based on a local equilibrium and describes dependency of foam mobility reduction factor using several independent functions, such as liquid saturation, foam velocity, oil saturation and capillary number. First, a series of numerical simulation was conducted to investigate the effect of surfactant concentration on pressure drop across the core for the foam flooding in the absence of oil. To this end, the dry-out and gas velocity functions in the foam model were determined from the experimental data obtained at low and high-quality regimes of foam flow at a constant injection velocity. Next, pressure drop profiles of foam flooding at two different surfactant concentrations were modelled to determine the parameters of the surfactant-dependent function in the foam model. The simulation results fit the experimental data of pressure drops very well. Then, the numerical simulations investigated the oil displacement, by foam where the main goal was to determine the foam model parameters dedicated to the oil saturation-dependent function. The pressure drop across the core, oil-cut, and oil recovery factor were modelled, and an excellent match was obtained between the pressure profile and the oil recovery obtained numerically compared with those obtained from the corresponding core-flood experiments.
Summary A key challenge in polymer-flood forecasting is the prediction of polymer stability far from the injector. Degradation may result from various mechanical-degradation events in surface facilities and at the wellbore interface, as well as possible oxidative degradation caused by the presence of oxygen and reduced transition metals. All these steps must be closely examined to minimize degradation and ensure propagation of a viscous polymer solution. In this paper, polymer solutions are pushed toward degradation rates that would be unacceptable for enhanced-oil-recovery applications to better understand the underlying physics. Multistep degradation events are induced in various geometries, such as capillaries, blenders, and porous media. For the geometries and range of polymer and salt concentrations investigated, degradation (as defined here) approaches an asymptotic value as the number of degrading events increases. An empirical normalization method is proposed, allowing superimposition of curves of viscosity loss vs. time across multiple possible geometries. The normalization procedure is applied to predict the extent of degradation during a field injection in which near-wellbore degradation occurs after degradation in surface facilities. We predict that degradation in the porous medium reaches a stable value after passing through approximately 6 mm of rock. Finally, degradation is proposed as a tool to probe the molecular-weight distribution and to narrow the polydispersity of polymers, which can be used for maximizing both viscosifying power and injectivity simultaneously. Introduction Compared with biopolymers such as xanthan, hydrolyzed polyacrylamides (HPAMs) are more prone to mechanical degradation (Seright et al. 2009; Zaitoun et al. 2011). This behavior is attributed to the conformation of the macromolecules. Xanthan is structured in solution as a double-strand helix and can be considered to behave as a rigid rod in solution and will align in the direction of the flow. HPAM, on the other hand, is a flexible chain with a coiled conformation that can be stretched by flow, leading to the macroscopic observation of viscoelasticity associated with chain extension and rupture (Chauveteau 1981; Magueur et al. 1985). When injecting HPAM for mobility-control application, the level of degradation experienced in surface facilities, wellbore, and reservoir must be known to accurately predict the increased oil recovery caused by improved mobility control. This degradation will result from oxidative and mechanical degradation in surface facilities along with mechanical degradation near the wellbore where the strain rates experienced are highest.