Wang, Shuoshi (University of Oklahoma) | Yuan, Qingwang (University of Regina) | Kadhum, Mohannad (Cargill, Incorporated) | Chen, Changlong (University of Oklahoma) | Yuan, Na (University of Oklahoma) | Shiau, Bor-Jier (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
While injection of CO2 has great potential for increasing oil production, this potential is limited by site conditions and operational constraints such as lack of proper infrastructure, limited cheap CO2 sources, viscous fingering, gravity override at the targeted zones, and so forth. To mitigate some of these common limitations, we explore alternative methodologies which can successfully deliver CO2 through gas generation in situ, with superior IOR performance, while offering reasonable chemical cost.
While dissolved easily in reservoir brine, urea is thermally hydrolyzed to CO2 and NH3 after equilibration under reservoir conditions. Therefore, given its exceptional compatibility with reservoir fluids, its CO2 producing capacity and reasonable cost benefit, urea appears to be a promising candidate for delivering CO2 to increase oil recovery. The in-situ gas generation requires single chemical slug, which can minimize the complexity of the injection system.
One-dimensional sand pack tests and core flooding experiments were operated at pre-set conditions: different API gravity oils were used, varying from 27 to 57.3. In addition, the reaction rates of the urea hydrolysis and urea solution PVT property were tested separately under reservoir conditions.
Most importantly, results of injecting urea solution (as low as 10 % solution) showed superior tertiary recovery performance (as high as 37.97%) are realized as compared to the most recent efforts at our group (29.5%) as well as similar in situ CO2 generation EOR (2.4% to 18.8%) approaches proposed by others.
The economic feasibility and operational advantages of this newly developed method were demonstrated in this work. In brief, results of this work served further as a proof of concept for designing in situ CO2 generation formulations for tertiary oil recovery at both onshore and offshore fields under proper conditions.
In-situ upgrading (IU) is a promising method of improved viscous and heavy oil recovery. The IU process implies a reservoir heating up and exposition to temperature higher than 300°C for long enough time to promote a series of chemical reactions. The pyrolysis reactions produce lighter oleic and gaseous components while a solid residue remains underground. In this work, we developed a numerical model of IU based on lab experiences (kinetics measurements and core experiments) and validated results applying our model to an IU test published it the literature. Finally, we studied different operational conditions searching for energy-efficient configurations.
In this work, two types of IU experimental data are used from two vertical-tube experiments with Canadian bitumen cores (0.15 m and 0.69 m). A general IU numerical model for the different experimental setups has been developed and compared to experimental data, using a commercial reservoir simulator framework. This model is capable to represent the phase distribution of pseudo-components, the thermal decomposition reactions of bitumen fractions and the generation of gases and residue (solid) under the cracking conditions.
Simulation results for the cores submitted to 370°C and production pressure of 15 bar, have shown that oil production (per pseudo-component) and oil sample quality were well-predicted by the model. Some differences in gas production and total solid residue were observed with respect to laboratory measurements. Computer-assisted history matching was performed using an uncertainty analysis tool on the base of the most important model parameters. In order to better understand IU field-scale test results, the Shell’s Viking pilot (Peace River) was modeled and analyzed with proposed IU model. The appropriated grid-block size was determined and calculation time was reduced using the adaptive mesh refinement technique. The quality of products, the recovery efficiency and the energy expenses obtained with our model were in good agreement with the field test results. Also the conversion results (upgraded oil, gas and solid residue) from the experiments were compared to those obtained in the field test. Additional analysis was performed to identify energy efficient configurations and to understand the role of some key variables, e.g. heating period and rate, the production pressure, in the global IU upgrading performance. We discuss these results which illustrate and quantify the interplay between energy efficiency and productivity indicators.
Performance predictions of In-Situ Combustion (ISC) process is a challenge as it involves complicated chemical reactions, fluids movement, phase changes, and heat and mass transfer. This study investigates how the aquathermolysis reactions and their chemical products can affect the ISC performance through combination of combustion tube and Thermogravimetric Analysis and Differential Scanning Calorimetry (TGA/DSC) experiments.
Combustion tube experiments were conducted with two different crude oil without water (Swi=0%) and with the presence of water (Swi=34%). Experimental conditions were kept constant (3 L/min air injection rate and 100 psig pack pressure) for all four experiments conducted with two different oil samples. To determine the chemical reactions occurred during combustion tube experiments, the initial crude oil samples and their Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractions were subjected to TGA/DSC experiments under air injection at two constant heating rates with and without water addition. Because during combustion tube experiments, two heating rates were observed, 5°C/min was used to represent the slow heating region (Steam Plateau and Evaporation & Visbreaking) and 20°C/min was used to mimic the rapid heating region (Cracking Region and Combustion Zone). To better understand the complicated mutual interactions of functional groups in crude oil, TGA/DSC experiments were repeated on normal-decane (an alkane), decanal (an aldehyde), decanone (a ketone), and decanol (an alcohol) which may represent the low temperature oxidation (LTO) products. Note that these chemicals have constant carbon number (C10).
The combustion tube experiments showed that Oil1 was able to burn for both conditions (with and without water), while Oil2 could only sustain combustion with water. To study the reason for this difference in burning behavior, the burning behavior of the crude oils and their individual SARA fractions with and without water addition was studied through TGA/DSC experiments. At high heating rate (20°C/min), heat generation does not vary for both crude oil. However, in low heating rates (5°C/min), Oil1 generates higher amount of energy at high temperature oxidation (HTO) zone. We have observed similarities between the decanone (a ketone) burning behaviors with aromatics fractions for Oil1 which may indicate that aromatics fraction may contain ketone functional groups as LTO products Because upon burning, ketones generate higher energy than any LTO products, Oil1 may have functional groups in its structure more like ketones which promotes its combustion more than Oil2. While presence of water does not change the burning behavior of Oil1, we observed that aromatics fraction of Oil2 in the presence of water generates components similar to decanol (an alcohols) burning behavior. Note that alcohols generate more heat than aldehydes upon burning which explains the enhancement of Oil2 burning behavior in the presence of water, however, produced less energy than ketones, hence, combustion performance of Oil2 was poorer than Oil1. Our results suggest that the chemical structure of aromatics fraction is critical for the success of ISC. Water and aromatics fraction interaction at elevated temperature favors ISC reactions.
One major concern for Alkaline Surfactant Polymer (ASP) flooding is the possibility of inorganic scale formation near the wellbore and in the production facility. In this process, the precipitation reactions of multivalent hardness ions present in the carbonate reservoirs with alkalis in high pH brines might damage the formation, production facilities, and cause severe flow assurance issues. Therefore, it is crucial to understand the geochemical reactions and possibility of scale formation and its associated problems to develop mitigation plans. In this paper, we performed geochemical simulations to investigate the likelihood of inorganic scale formation during ASP flooding in a 5-spot pilot project in one of the largest carbonate reservoirs in the Middle East.
We used a coupled chemical flooding simulator and geochemical (IPhreeqc) framework for this study. First, we incorporated published laboratory data in a geomodel realization of the pilot area. Second, we used the pilot model to investigate the possibility of scale formation during ASP flooding considering a comprehensive system of reactions. Using IPhreeqc, we were able to include thermodynamic databases with various geochemical reactions and capabilities such as saturation index calculation, reversible and irreversible reactions, kinetic reaction, and impacts of temperature and pressure on reaction constants and solubility products. Thus, we were able to show how and where the scales may form.
Our results indicated that the mixing of very hard formation water or water from the subzones near the production wellbore with the injected alkaline water causes scale deposition. We observed calcite dissolutions with slight increase in pH near the injection wellbores after soft seawater preflush. As the ASP solution was injected and high pH brine propagated, carbonate scale and to a lesser extent hydroxide scale formed near the producer. Moreover, although some carbonate and magnesium hydroxide deposits in the formation, but there was negligible effect on reservoir properties. Furthermore, according to our simulation results, most of the scales deposited near the production wellbore, which increases the chance of reducing wellbore productivity and production system damage. These results can help in developing mitigation strategies i.e. preflood the reservoir with soft brine before introducing the ASP slug and optimize the soft brine injection time.
To the best of our knowledge, this is the first study that a comprehensive chemical flood reactive transport simulator is used to assess scale formation during ASP flooding in a carbonate reservoir. Our approach can be used to identify and mitigate challenges and associated design problems for field-scale ASP scenarios.
Previously proposed models of wettability change have not been tied to the chemistry that controls wettability but instead were driven by simplistic criteria such as salinity level or concentration of an adsorbed species. Such models do not adequately predict the impact of brine compositional change and therefore cannot be used to optimize brine composition. In this work, after testing proposed models in the literature on sandstones and carbonates, we propose a mechanistic surface-complexation-based model that quantitatively describes observations for ionically treated waterfloods. To the best of our knowledge this is the first surface-complexation-based model that fully describes ionic compositional dependence observed in ionically treated waterfloods in both sandstones and carbonates.
We model wettability change by directly linking wettability to brine chemistry using detailed colloidal science. Brine has charged ions that interact with polar acidic/basic components at the oil-water interface and rock surface and therefore oil/brine and rock/brine interfaces are charged and exert both Van der Waals and electrostatic forces on each other. If the net result of the forces is repulsive, the thin water film between the two interfaces is stable (i.e., the rock is water-wet) otherwise, the thin water film is unstable and the rock becomes oil-wet. Based on
We implemented the improved wettability change model in a comprehensive coupled reservoir simulator, UTCOMP-IPhreeqc, in which oil/brine and rock/brine zeta potentials are modeled using the IPhreeqc surface complexation module. We take into the account total acid number (TAN) and total base number (TBN) for the oil/brine interface and we use rock surface reactions for brine/rock surface potential modeling. Surface potentials obtained from the geochemical model are used to calculate the dimensionless group controlling wettability change, which is dynamically modeled in the transport simulator. The model is validated in sandstones and carbonates by simulating an inter-well test, and several corefloods and imbibition tests reported in the literature. For sandstones, we model
It is now common knowledge among EOR practitioners that the combination of ferrous iron (Fe2+) and oxygen causes severe oxidative degradation to EOR polymers, resulting in a lowering of molecular weight and hence a loss of viscosity. During the design of polymer flooding projects, an important question is thus the acceptable levels of Fe2+ and dissolved oxygen that can be tolerated in injection water specifications. Furthermore, we would like to be able to predict the extent of degradation in the case of excess Fe2+ or oxygen ingress.
However, despite over fifty years of research and a general understanding of the degradation mechanism involved, quantitative prediction of the extent of degradation has proven elusive and dependent on the measurement protocol. This is likely due to the fastidious experimental protocols required to work under anaerobic or limited-oxygen conditions.
We examine existing protocols and demonstrate that experiments in which either Fe2+ or oxygen are the limiting reagent yield equivalent results when the stoechiometry of the Fe2+ oxidation reaction with oxygen is taken into account. Based upon these findings, a novel, easy approach is proposed to quantify polymer oxidative degradation as a function of either dissolved oxygen or Fe2+ content.
The limits of 225 ppb Fe2+ and 32 ppb dissolved oxygen are fixed for Flopaam 3630S in 6 g/l brine in the concentration range 500-1500ppm in order to ensure degradation of low-shear plateau viscosity does not exceed 10%. Higher levels will lead to severe polymer degradation. The influence of polymer concentration, temperature and salinity is also investigated. At last, evolution of redox potential and pH during Fe2+ oxidation are discussed.
There is a direct practical application of these finding for the design of surface facilities for polymer dissolution and transport and for the prediction of degradation in case of oxygen ingress. Moreover, a simple and easily performed protocol is proposed for the evaluation of polymer oxidative degradation.
Scaling up from lab to pilot is one of the challenges to meet in any ASP project to accomplish the requirements at full implementation. Tailored EOR surfactants developed and manufactured in the laboratory, to achieve the lowest interfacial tension (IFT) between oil and water at the reservoir conditions, have to be viable and robust in the manufacture, capable in performance and compatible in the formulation, not only at laboratory scale, but also at industrial scale.
It is described in this poster the route map in the development and manufacture of alkyl aryl sulfonates surfactants for the Cepsa ASP pilot project in the Caracara Sur field, Los Llanos basin (Colombia) from a continuous feed-back of the laboratory tests. The surfactant employed for the project was selected from other surfactants from several suppliers and dyalkylbenzene sodium sulfonate was the one achieving the lowest interfacial tension for Caracara field conditions. The dyalkylbenzene sodium sulfonate was accompanied by a co-surfactant improving the solubility and performance properties.
Pilot ASP injection started in May 2015 and some conclusions were obtained during the production of the surfactants in several manufacture batches: Composition, molecular weight even isomerism of alkylbenzenes may impact strongly on the interfacial activity of alkyl aryl sulfonates surfactants. Sulfonation and neutralization of alkylbenzenes are critical processes to comply the requirements of alkyl aryl surfactants for any cEOR project. Finally, the laboratory in the field for quality assurance and quality control (QA/QC) of surfactants is completely necessary. Periodical sampling and on-site analyses are scheduled but also samples delivery to research center for more sophisticated analyses. These data are essential for the final performance evaluation and the project success.
Composition, molecular weight even isomerism of alkylbenzenes may impact strongly on the interfacial activity of alkyl aryl sulfonates surfactants.
Sulfonation and neutralization of alkylbenzenes are critical processes to comply the requirements of alkyl aryl surfactants for any cEOR project.
Finally, the laboratory in the field for quality assurance and quality control (QA/QC) of surfactants is completely necessary. Periodical sampling and on-site analyses are scheduled but also samples delivery to research center for more sophisticated analyses. These data are essential for the final performance evaluation and the project success.
Polymer flooding is a proven technology to improve sweep efficiency, while being one of the most economical enhanced oil recovery (EOR) processes. Partially hydrolyzed polyacrylamide (HPAM) has been widely used for polymer flooding. As the HPAM usage for EOR increases, the challenge of produced water management is also raised because residual HPAM in produced water could increase total chemical oxygen demand and unwanted viscosity in discharging or re-injecting the water. As the environmental standards and regulations get more stringent, it is difficult for the conventional methods to meet the requirement for discharging. Use of magnetic nanoparticles (MNPs) to remove contaminants from produced water is a promising way to treat produced water in an environmentally green way with minimal use of chemicals. The main attraction for MNPs is their quick response to move in a desired direction with application of external magnetic field. Another attraction of MNPs is versatile and efficient surface modification through suitable polymer coating, depending on the characteristics of target contaminants. In this study, we investigate the feasibility of polymer removal using surface-modified MNPs and regeneration of spent MNPs for multiple re-use.
The electrostatic attraction between negatively charged HPAM polymer and positively charged MNPs controls the attachment of MNPs to HPAM molecular chain; and the subsequent aggregation of the now neutralized MNP-attached HPAM plays a critical role for accelerated and efficient magnetic separation.
Although geochemical reactions are the fundamental basis of the alkaline/surfactant/polymer (ASP) flooding, their importance is commonly overlooked and not fully assessed. Common assumptions made when modeling geochemical reactions in ASP floods include: 1) ideal solution (i.e., using molalities rather than ion activities) for the water and aqueous geochemical species 2) limiting the number of reactions (i.e., oil/alkali and alkali consumptions) rather than including the entire thermodynamically-equilibrated system 3) ignoring the effect of temperature and pressure on reactions 4) local equilibrium ignoring the kinetics. To the best of our knowledge, the significance of these assumptions has never been discussed in the literature. In this paper we investigate the importance of geochemical reactions during alkaline/surfactant/polymer floods using a comprehensive tool in the sense of surfactant/soap phase behavior as well as geochemistry.
We coupled the United States Geological Survey (USGS) state-of-the-art geochemical tool, with 3D flow and transport chemical flooding module of UTCHEM. This geochemical module includes several thermodynamic databases with various geochemical reactions, such as ion speciation by applying several ion-association aqueous models, mineral, solid-solution, surface-complexation, and ion-exchange reaction. It has capabilities of saturation index calculation, reversible and irreversible reactions, kinetic reaction, mixing solutions, inverse modeling and includes impacts of temperature and pressure on reaction constants and solubility products. The chemical flood simulator has a three phase (water, oil, microemulsion) phase behavior package for the mixture of surfactant/soap, oil, and water as a function of surfactant/soap, salinity, temperature, and co-solvent concentration. Hence, the coupled software package provides a comprehensive tool to assess the significance of geochemical assumptions typically imposed in modeling ASP floods. Moreover, this integrated tool enables modeling of variations in mineralogy present in reservoir rocks. We parallelized the geochemistry module of this coupled simulator for large-scale reservoir simulations.
Our simulation results show that the assumption of ideal solution overestimates ASP oil recovery. Assuming only a subset of reactions for a coupled system is not recommended, particularly when a large number of geochemical species is involved, as is the case in realistic applications of ASP. Reservoir pressure has a negligible effect but temperature has a significant impact on geochemical calculations. Although mineral reaction kinetics is largely a function of the temperature and in-situ water composition, some general conclusions can be drawn as follows: to a good approximation, minerals with slow rate kinetic reaction (e.g., quartz) can be excluded when modeling ASP laboratory floods. However, minerals with fast rate kinetic reactions (e.g., calcite) must be included when modeling lab results. On the other hand, in modeling field-scale applications, local equilibrium assumption (LEA) can be applied for fast rate kinetic minerals, whereas kinetics should be used for slow rate kinetic minerals.
Polymer flooding can significantly improve sweep and delay breakthrough of injected water, thereby increasing oil recovery. Polymer viscosity degrades in reservoirs with high salinity brines, so it is advantageous to inject low salinity water as a preflush. Low salinity water flooding (LSW) can also improve local displacement efficiency by changing the wettability of the reservoir rock from oil wet to more water wet. The mechanism for wettability alteration for low salinity waterflooding in sandstones is not very well understood, however experiments and field studies strongly support that cation exchange (CE) reactions are the key element in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport has not been explained to date.
This paper presents the first analytical solutions for the coupled synergistic behavior of low salinity waterflooding and polymer flooding considering cation exchange reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the cation exchange of Ca2+, Mg2+ and Na+ is used to model the wettability alteration. The aqueous phase viscosity is a function of polymer and salt concentrations. Then, the coupled multiphase flow and reactive transport model is decoupled into three simpler sub-problems, one where cation exchange reactions are solved, the second where a variable polymer concentration can be added to the reaction path and the third where fractional flows can be mapped onto the fixed cation and polymer concentration paths. The solutions are used to develop a front tracking algorithm, which can solve the slug injection problem where low salinity water is injected as a preflush followed by polymer. The results are verified with experimental data and PennSim, a general purpose compositional simulator.
The analytical solutions show that decoupling allows for estimation of key modeling parameters from experimental data, without considering the chemical reactions. Recovery can be significantly enhanced by a low salinity pre-flush prior to polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned LSP flood can be as much as 10% OOIP greater than with considering polymer alone. The results show the structure of the solutions, and in particular the velocity of multiple shocks that develop. These shocks can interact, changing recovery. For example, poor recoveries obtained in core floods for small low salinity slug sizes are explained with intersection of shocks without considering mixing. The solutions can also be used to benchmark numerical solutions and for experimental design. We demonstrate the potential of LSP as a cheaper and more effective way for performing polymer flooding when the reservoir wettability can be altered using chemically-tuned low salinity brine.