Gerald Hamon

Computational Permeability Determination from Pore-Scale Imaging: Sample Size, Mesh and Method Sensitivities

In this work, a complete work flow from pore-scale imaging to absolute permeability determination is described and discussed. Two specific points are tackled, concerning (1) the mesh refinement for a fixed image resolution and (2) the impact of the determination method used. A key point for this kind of approach is to work on enough large samples to check the representativity of the obtained evaluations, which requires efficient parallel capabilities. Image acquisition and processing are realized using a commercial micro-tomograph. The pore-scale flows are then evaluated using the finite volume method implemented in the open-source platform OpenFOAM®. For this numerical method, the influence of the different aspects mentioned above are studied. Moreover, the parallel efficiency is also tested and discussed. We observe that the level of mesh refinement has a non-negligible impact on permeability tensor. Moreover, increasing the refinement level tends to reduce the gap between the methods of computational measurements. The increase in computation time with the mesh is balanced with the good parallel efficiency of the platform.

Pore-Scale Modelling of the Effect of Viscous Pressure Gradients During Heavy Oil Depletion Experiments

In this work, we implement a dynamic gas/oil interface tracking algorithm for the mobilization of bubbles under intense pressure gradients in order to improve the simulation of solution gas drive for heavy oil in the framework of a pre-existing pore-scale network simulator. The model is used to characterize both the stationary capillary controlled growth of bubbles characteristic of slow depletion rates (far-wellbore region) and the flow phenomena in the near-wellbore region: in this case, it is shown how viscous forces lead to an increased persistence of small bubbles for a longer time, creating an effect similar to what described as foamy oil. The study has identified three different regimes of bubble growth, depending upon capillary number and depletion rate, and these regimes appear to cover the entire range of phenomena observed experimentally. These three regimes are (a) the conventional capillary-controlled growth pattern at low capillary numbers, (b) viscous biased growth at intermediate capillary numbers, and (c) bubble mobilization and breakup leading to foamy behaviour at the highest capillary numbers and depletion rates. A predictive methodology for the associated continuum-scale constitutive relationships, such as relative permeabilities, is also proposed for each of the three depressurization regimes.

Finger Thickening during Extra-Heavy Oil Waterflooding: Simulation and Interpretation Using Pore-Scale Modelling.

Although thermal methods have been popular and successfully applied in heavy oil recovery, they are often found to be uneconomic or impractical. Therefore, alternative production protocols are being actively pursued and interesting options include water injection and polymer flooding. Indeed, such techniques have been successfully tested in recent laboratory investigations, where X-ray scans performed on homogeneous rock slabs during water flooding experiments have shown evidence of an interesting new phenomenon–post-breakthrough, highly dendritic water fingers have been observed to thicken and coalesce, forming braided water channels that improve sweep efficiency. However, these experimental studies involve displacement mechanisms that are still poorly understood, and so the optimization of this process for eventual field application is still somewhat problematic. Ideally, a combination of two-phase flow experiments and simulations should be put in place to help understand this process more fully. To this end, a fully dynamic network model is described and used to investigate finger thickening during water flooding of extra-heavy oils. The displacement physics has been implemented at the pore scale and this is followed by a successful benchmarking exercise of the numerical simulations against the groundbreaking micromodel experiments reported by Lenormand and co-workers in the 1980s. A range of slab-scale simulations has also been carried out and compared with the corresponding experimental observations. We show that the model is able to replicate finger architectures similar to those observed in the experiments and go on to reproduce and interpret, for the first time to our knowledge, finger thickening following water breakthrough. We note that this phenomenon has been observed here in homogeneous (i.e. un-fractured) media: the presence of fractures could be expected to exacerbate such fingering still further. Finally, we examine the impact of several system parameters, including core length, wettability and injection rate, on the extent and efficiency of the finger swelling phenomenon.

A Pore-Scale Investigation of Low-Salinity Waterflooding in Porous Media: Uniformly Wetted Systems

The potential of low-salinity (LS) water injection as an oil recovery technique has been the source of much recent debate within the petroleum industry. Evidence from both laboratory and field-level studies has indicated significant benefits compared to conventional high-salinity (HS) waterflooding, but many conflicting results have also been reported and, to date, the underlying mechanisms remain poorly understood. In this paper, we aim to address this uncertainty by developing a novel, steady-state pore network model in which LS brine displaces oil from a HS-bearing network. The model allows systematic investigation of the crude oil/brine/rock parameter space, with the goal of identifying features that may be critical to the production of incremental oil following LS brine injection. By coupling the displacement model to a salinity-tracking tracer algorithm, and assuming that a reduction of water salinity within the pore network leads to localised wettability alteration, substantial perturbations to standard pore filling sequences are predicted. The results clearly point to two principal effects of dynamic contact angle modification at the pore scale: a “pore sequence” effect, characterised by an alteration to the distribution of displaced pore sizes, and a “sweep efficiency” effect, demonstrated by a change in the overall fraction of pores invaded. Our study indicates that any LS effect will depend on the relative (scenario-dependent) influence of each mechanism, where factors such as the initial wettability state of the system and the pore size distribution of the underlying network are found to play crucial roles. In addition, we highlight the important role played by end-point capillary pressure in determining LS efficacy.

Secondary and Tertiary Polymer Flooding in Extra-Heavy Oil: Reservoir Conditions Measurements - Performance Comparison

In the challenging context of heavy to extra heavy oil production, polymer flood technology appears to be a promising solution to enhance ultimate recovery of reservoirs. Several field applications have already shown the efficiency of such technologies, although the final incremental recovery and mechanisms involved are still poorly understood. Indeed, the characteristics of the viscous fingering effects that certainly play a role are rarely captured at the field scale or at the core scale. This work aims at comparing the results of two core experiments with polymer flood in secondary and tertiary mode, in reservoir conditions, in term of recovery as well as in terms of relative permeabilities. In both cases, experiments were carried out on reconstituted reservoir cores, with restored wettability, initially saturated with live oil partially degassed in a PVT cell to the expected pressure and viscosity at the start of the field test. Saturation profiles were measured with X-Ray scans; effluents were collected in test-tubes and analyzed by UV measurements. Additional follow-up with tracers was tested in order to better assess the breakthrough of different fluids as well as the polymer adsorption during the experiment. Although the viscosity ratio was still highly unfavorable, with a polymer bulk viscosity around 70 cP at 10s-1 and an oil viscosity estimated at 5500 cP, polymer floods exhibit an excellent recovery factor.

An Experimental Investigation of the oil Recovery in the Transition Zone of Carbonate Reservoirs Taking Into Account Wettability Change

Abstract It is estimated that 60% of the world’s remaining oil is held in carbonate reservoirs. Due to its moderate permeability, the transition zone can extend over a hundred meters and therefore contain a significant amount of STOIIP. The water-oil displacements behavior is not always well understood, especially when it occurs in the transition zone where capillary effects are dominant and both phases are mobile. The oil trapping and the rock wettability in this zone appear to be two key features to deal with. They must be studied as a function of parameters such as initial oil saturation, oil characteristics, rock properties etc. There is very little experimental data available in the literature that describes these features. This study focuses on relative permeability and residual oil saturations during drainage and imbibition in carbonate reservoirs. Steady-state core floods were performed with crude reservoir oil on outcrop limestone cores, some with moldic porosity, over a very large range of initial oil saturations. Cores were aged with crude oil before the imbibition process to allow wettability change at the initial oil saturations. Two main types of limestone have been studied: with unimodal or bimodal pore size distributions. The two types of limestone cores exhibit very different responses to wettability alteration for the same oil/brine system while almost identical mineralogy. We attributed these differences to the vuggy structure of the Estaillade limestones, which might promote oil-wettability. The inspection of the water relative permeability curves show that water wettability decreases as Soi increases, i.e. as the elevation above the contact increases, for the two types of limestones. Therefore it is not correct to derive imbibition scanning Kr curves from the bounding Kr curve at high Soi, while assuming that wettability is constant. Hysteresis is observed for both the oil and water relative permeability curves as a function of saturation Non monotonic evolution of Sorw as a function of Soi has been observed for the limestone with bimodal pore size distribution. This behavior is ascribed to the combined effect of increasing fraction of micro porosity being filled by oil initially as well as wettability variation as Soi increases. On the other hand, Sorw increases monotonically as Soi increases, for the limestone with unimodal pore size distribution. The comparison between the experimental relative permeability curves and the ones derived from simple hysteresis models show that neglecting the variation of wettability along the transition zone leads to erroneous values in oil saturations thus on oil recovery.

Pore-scale simulation of hysteresis effects during repressurisation of gas-oil systems

Repressurisation of a hydrocarbon reservoir may occur either as a natural response to subsurface phenomena (for example, aquifer encroachment or fault re-activation) or as a consequence of a particular production strategy. In this paper we examine, for the first time to our knowledge, the pore scale mechanisms underlying the repressurisation of a gas-oil reservoir that has previously been exploited by solution gas drive. Our investigation, triggered by experimental observations in both glass micromodels and cores, utilizes a pore-scale network model: a modelling approach that is nowadays sufficiently mature to facilitate virtual experiments that are rapid, cheap and physically realistic. The new physics implemented here captures a wide range of phenomena related to multiphase repressurisation, including gas re-dissolution in oil by diffusion, bubble retraction, fragmentation and re-stabilisation under gravitational forces, and oil reimbibition. It is found that repressurisation is not simply the reverse of primary depletion, as the previously developed gas phase does not simply retract from the latest pores invaded during depressurization: rather, the process exhibits a large degree of hysteresis in both local supersaturation and gas phase distribution. We have studied the effects of several combinations of depressurization and repressurisation rates upon phase distribution and recovery, as the system is first depleted below bubble point and subsequently repressurised back to the starting pressure. Crucially, we find that a highly dispersed gas phase can persist once the original bubble point of the oil has been reached at the end of repressurisation. It is clearly shown that the repressurisation of an unequilibrated system essentially generates a high bubble density: this could theoretically be exploited by a secondary depletion to obtain improved recovery, as it is well known that the generation of large numbers of bubbles (generated by nucleation or, as we suggest here, induced by repressurisation) is highly beneficial for solution gas drive performance.