Results

In order to improve the oil recovery factor, many oil companies employ surfactant in injected water. On one hand, the injection of surfactant influences the interfacial tension and to a lesser extent, the mobility reduction factor. On the other hand, the efficiency of the surfactant depends strongly on the salinity and temperature conditions. In order to optimize the surfactant injection procedure, the salinity and temperature effects are commonly studied through series of laboratory experiments. However, these types of experiments are often long and expensive. Therefore, engineers use numerical simulations. The present study addresses a numerical model, which allows to take into account the modifications of the interfacial tension (IFT) and the mobility reduction factor due to the salinity and temperature variations during the surfactant injection.

In this work, we propose a coupled numerical model based on five equations: i) two transport equations of water and oil phases modelized by the Darcy's law, ii) two transport equations for the surfactant and the salinity (the surfactant and the salinity are transported only in the water phase) iii) one energy conservation equation to take into account the thermal effect on surfactant flooding. The system of equations includes the salinity and the temperature impacts on the surfactant adsorption and thermal degradation, as well as the interfacial tension. Thus, this model allows improving the analysis of thermal corefloods or reservoir operations resulting from the surfactant injection.

The coupled model is used to reproduce laboratory experiments based on corefloods. We analyze the interaction phenomena between the surfactant, salinity and temperature. Then, we demonstrate a competition between two phenomena: the thermal effect on the viscosity of water on one hand, and the effect of surfactant on the mobility of water on the other hand. This study highlights the efficiency of numerical simulations for the analysis and choice of the surfactant applied to the given reservoir and well conditions.

Obviously, the knowledge of IFT and its dependence on surfactant concentration, salinity and temperature is not sufficient to understand all the physical mechanisms involved in a coreflood study. The phenomena are in fact extremely coupled, and the reservoir simulator coupling all these effects is found to be very helpful for engineers in order to take a good decision about the surfactant species to be used.

Summary

It has been demonstrated in both laboratory measurements and field applications that tertiary polymer flooding can enhance oil recovery from heterogeneous reservoirs, primarily through macroscopic sweep (conformance). This study quantifies the effect of layering on tertiary polymer flooding as a function of layer-permeability contrast, the timing of polymer flooding, the oil/water-viscosity ratio, and the oil/polymer-viscosity ratio. This is achieved by analyzing the results from fine-grid numerical simulations of waterflooding and tertiary polymer flooding in simple layered models.

We find that there is a permeability contrast between the layers of the reservoir at which maximum incremental oil recovery is obtained, and this permeability contrast depends on the oil/water-viscosity ratio, polymer/water-viscosity ratio, and onset time for the polymer flood. Building on an earlier formulation that describes whether a displacement is understable or overstable, we present a linear correlation to estimate this permeability contrast. The accuracy of the newly proposed formulation is demonstrated by reproducing and predicting the permeability contrast from existing flow simulations and further flow simulations that have not been used to formulate the correlation.

This correlation will enable reservoir engineers to estimate the combination of permeability contrast, water/oil-viscosity ratio, and polymer/water-viscosity ratio that will give the maximum incremental oil recovery from tertiary polymer flooding in layered reservoirs regardless of the timing of the start of polymer flooding. This could be a useful screening tool to use before starting a full-scale simulation study of polymer flooding in each reservoir.

Summary

The PG Reservoir in Jidong Oil Field is at a depth of approximately 4500 m with an extremely high temperature of approximately 150°C. The average water cut has reached nearly 80%, but the oil recovery is less than 10% after only 2 years of waterflooding process. It is of great importance to develop a high-temperature-resistant plugging system to improve the reservoir conformance and control water production. An in-situ polymer-gel system formed by the terpolymer and a new crosslinker system was developed, and its properties were systematically studied under the condition of extremely high temperature (150°C). Suitable gelation time and favorable gel strength were obtained by adjusting the concentration of the terpolymer (0.4 to 1.0%) and the crosslinker system (0.4 to 0.7%). An increase of polymer and crosslinker concentration would decrease the gelation time and increase the gel strength. The gelant could form continuous 3D network structures and thus have an excellent long-term thermal stability. The syneresis of this gel system was minor, even after being heated for 5 months at the temperature of 150°C. The gel system could maintain most of the initial viscosity and viscoelasticity, even after experiencing the mechanical shear or the porous-media shear. Core-flow experiments showed that the gel system could have great potential to improve the conformance in Jidong Oil Field.

In hydrocarbon reservoirs, we typically encounter a brine phase and at least one hydrocarbon phase. Because of their dissimilarities, the flow of hydrocarbon phases is hindered by the presence of brine. The interfacial tension between brine and oil is typically high (50 mN/m for some systems), which results in unfavorable relative permeabilities and high residual oil saturation. The oil and gas industry has been fascinated by surfactants since their understanding began to emerge in the early 1950s. Surfactants are compounds that display a dual nature, with affinity to both brine and hydrocarbon phases.

The exploration and development of super-low permeability reservoirs have become a global focus in recent years. However, conventional flooding systems commonly face problems of high injection pressure and poor displacement efficiency in super-low permeability reservoirs. Thus, it is imperative to find new flooding agents that tackle such problems.

In this study, a novel ultra-low interfacial tension (IFT) nanofluid was formulated, consisting of surfactants to achieve ultra-low IFT and silica nanoparticles to reduce injection pressure. The compatibility test between the surfactants and silica nanoparticles in 10,000 mg/L NaCl solution at 90 °C was conducted to ensure their adaption to harsh reservoir conditions. Also, the effects of silica nanoparticles on the IFT and emulsion stability of the surfactant solution as well as wettability of reservoir rock were evaluated to determine the optimum concentration of nanoparticles. Finally, oil displacement efficiency of the nanofluid was assessed and compared from respective nanofluid flooding, surfactant flooding and surfactant-free nanofluid flooding.

The compatibility results showed that the ultra-low IFT surfactant solution with silica nanoparticles remained clear and stable at 90 °C for one month. The surfactant solution can effectively emulsify oil, and the stability of the oil emulsion could be further improved in the presence of silica nanoparticles. In addition, the solution could achieve lower IFT at both low and high temperature with the addition of 0.01% silica nanoparticles. The silica nanoparticles could effectively alter the wettability of the rock, making it become more water-wet with increasing silica nanoparticle concentration. The displacement experiments through 0.2–0.3 mD tight cores indicated that the enhanced oil recovery could reach 21.12%OOIP by the nanofluid flooding after water flooding, higher than that of surfactant flooding (18.84% OOIP), and much higher than that of surfactant-free nanofluid flooding (3.48% OOIP). Moreover, the injection pressure difference was able to decrease nearly 50% after nanofluid injection in comparison with the occurrence of an increase in pressure along the surfactant solution injection. Thus, the combined surfactant and nanoparticles behaved excellent synergistic effect.

The newly formulated surfactant based silica nanofluids can efficiently enhance oil recovery in comparison with water flooding, and significantly lower the injection pressure compared with the surfactant flooding. This work lays the foundation for the application of ultralow IFT nanofluid flooding technology in super-low permeability reservoirs.

Recent laboratory studies have shown fines migration induced decrease in rock permeability during CO₂ injection. Fines migration is a pore scale phenomenon, yet previous laboratory studies did not conduct comprehensive pore scale characterization. This study utilizes integrated pore scale characterization techniques to study the phenomenon.

We present CO₂ injection experiments performed on two Berea sandstone samples. The core samples are characterized using nitrogen permeability, X-ray micro-computed tomography (micro-CT), Scanning Electronic Microscopy with Energy Dispersive X-ray Spectroscopy (SEM-EDS) and Itrax X-ray Fluoresence (XRF) scanning. The core samples were flooded with freshwater, then CO₂-saturated water, and finally water-saturated supercritical CO₂ (scCO₂). To calculate permeability, the pressure difference across the core samples was monitored during these fluid injections. The produced water samples were analysed using Inductively Coupled Plasma-Optical Emission Spectrometry (ICPOES). After the flooding experiment, nitrogen permeability, micro-CT, SEM-EDS and Itrax-XRF scanning was repeated to characterize pore scale damage. Micro-CT image based computations were run to estimate permeability decrease along the core sample length after injection.

Results show dissolution of dolomite and other high density minerals. Mineral dissolution dislodges fines particles which migrate during scCO₂ injection. Berea 1 and Berea 2 showed respectively 29% and 13% increase in permeability during CO₂-saturated water injection. But after water-saturated scCO₂ injection, both Berea 1 and Berea 2 showed 60% decrease in permeability. The permeability damage of the sample can be explained by fines migration and subsequent blockage. SEM-EDS images also show some examples of pore blockage.

The high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-mD formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions.

The low-IFT foam process was investigated through core flooding experiments in homogenous and fractured oil-wet cores with sub-10-mD matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer (AOS C14-16) were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the core flooding experiments.

Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-mD matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-mD matrix permeability achieved 64% incremental oil recovery compared to water flooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluids flow in it. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids, such as mineral dissolution and the exchange of Calcium and Magnesium, were found to increase the Ca²⁺ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca²⁺ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It therefore may cause injectivity and phase trapping issues especially in the homogenous limestone.

Results in this work demonstrated that despite the challenges associated with limestone dissolution, a low-IFT foam process can remarkably extend chemical EOR in fractured oil-wet tight reservoirs with matrix permeability as low as 5 mD.

Summary

This paper examines oil displacement as a function of polymer-solution viscosity during laboratory studies in support of a polymer flood in Canada’s Cactus Lake Reservoir. When displacing 1,610-cp crude oil from field cores (at 27°C and 1 ft/D), oil-recovery efficiency increased with polymer-solution viscosity up to 25 cp (7.3 seconds^-1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of this paper explores why this result occurred. Floods in field cores examined relative permeability for different saturation histories, including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1,000 cp. In field cores, relative permeability to water (k_rw) remained low, less than 0.03 for most corefloods. After extended polymer flooding to water saturations up to 0.865, k_rw values were less than 0.04 for six of seven corefloods. Relative permeability to oil remained reasonably high (greater than 0.05) for most of the flooding process. These observations help explain why 25-cp polymer solutions were effective in recovering 1,610-cp oil. The low relative permeability to water allowed a 25-cp polymer solution to provide a nearly favorable mobility ratio. At a given water saturation, k_rw values for 1,000-cp crude oil were approximately 10 times lower than for 1,000-cp refined oil. In contrast to results found for the Daqing polymer flood (Wang et al. 2000, 2011), no evidence was found in our application that high-molecular-weight (MW) hydrolyzed polyacrylamide (HPAM) solutions mobilized trapped residual oil. The results are discussed in light of ideas expressed in recent publications. The relevance of the results to field applications is also examined. Although 25-cp polymer solutions were effective in displacing oil during our corefloods, the choice of polymer viscosity for a field application must consider reservoir heterogeneity and the risk of channeling in a reservoir.

This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system.

This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.

Upscaling the simulation of unstable displacement of heavy oil is challenging because accurately modeling the development and propagation of viscous instabilities within a simulation grid-block is next to impossible. Various models have been developed that are capable of history matching oil recovery results, however, there is little lab data to allow for validated scale-up of these viscous fingering model. We present experimental results from different geometries, i.e. cylindrical corefloods, 2D slabs and 3D blocks, where a viscous oil is displaced by water and polymer solutions, under pressure-constrained injection.

Waterflood and polymer flood oil recovery experiments were performed in ‘2-Dimensional’ (2D) sandstone slabs (12" by 12" by 1") and ‘3-Dimensional’ (3D) blocks (12" by 12" by 4") of sandstone and compared with oil recovery experiments through linear ‘1-Dimensional’ (1D) cylindrical cores. Experiments were performed with a high viscosity (540 cP) mineral oil at room temperature. UTCHEM (a software product from The University of Texas at Austin) with viscous fingering model was used to model the experiments and identify parameters for scaling the process to a field scale.

As expected, water breakthrough was accelerated as we moved from cylindrical cores to 2D slabs to 3D blocks. For the experiments conducted, gravity instability had a minimal effect compared to viscosity instability, even for the 3D blocks. Pseudo relative permeability curves based on the modified viscous fingering model were developed to match the 1D experiment. The same pseudo parameters showed excellent scalability across the varying experimental geometries (1D, 2D and 3D). These results indicated that the effective finger width did not vary for the different geometries.