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
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.
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.
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.
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.
Al-Aulaqi, Talal (Petroleum Development Oman L.L.C.) | Dindoruk, Birol (Shell Technology Houston) | Zhang, Etuan (Shell Technology Houston) | Ward, David (Shell Technology Houston) | Al-Azri, Nasser (Petroleum Development Oman L.L.C.)
Thermal EOR has been applied in different reservoirs in Oman to maximize the production from heavy oil prospects. PDO consider the highest HSE standard in their field operation to protect people and the integrity of the assets. In thermal EOR one of the highest HSE and risk integrity is the drastic increase of acid gas production mainly (H2S and CO2).
Historically, the quantification of the acid gas development in thermal EOR developments has been challenging, either leading to underestimation of the acid gas levels or overdesigning the material type with huge cost associated which impact the commerciality of the project especially at the current low oil price. Thus, improvement of the thermal souring prediction capabilities is required for the risk assessment and fit for purpose material selection rather than exotic option.
This work shows the results from an integrated subsurface and surface engineering collaboration to define the geochemical sources of souring in the thermal projects
The shortage and high cost of CO2 and/or HC gases makes chemical EOR a practical option for tertiary oil recovery in carbonate reservoirs. ASP formulations continue to evolve to withstand challenges in relation to reservoir heterogeneity, complex mineralogy, high temperature and high formation water salinity. This paper sheds light on the application of chemical EOR in carbonate reservoirs. The performance of chemical EOR in a Kuwaiti carbonate reservoir was evaluated through an ASP coreflood experiment using a composite core. This paper presents the modeling steps of this ASP flood, as well as the workflow to calibrate it with the resulted experimental data.
The carbonate composite core was first seawater flooded until residual oil saturation, Sorw, was achieved. The ASP coreflood started with low rate pre-flushing using softened seawater. The flood continued with the ASP slug, and ended by injecting multiple pore volumes of polymer solution for mobility control. This resulted in a 90% reduction in Sorw. A 1-D compositional model was developed to model the linear ASP coreflood using, CMG-GEM™ simulator. The study is composed of two parts, modeling the ASP chemical EOR process, and calibration of the model to the experimental results of the coreflood.
The modeling part of this paper captured the vital mechanisms involved in the ASP chemical EOR process. The modeling workflow captured the micro-emulsion phase behavior, surfactant solubility ratios and resulting IFT measurements, soap generation by naphthenic acids of the crude oil reacting with the injected alkali. Additionally, the workflow considered the effect of geochemistry, salinity gradient, surfactant and polymer adsorption on the process as well as the rheological behavior of polymer solutions.
The calibration part of this study followed a stepwise procedure to calibrate the model by first matching the water flood results followed by matching the ASP flood results. The paper discuss the required changes made on waterflood relative permeability curves to match Sorw and pressure differential resulted from the water flood stage. The paper also presents the changes on surfactant adsorption, micro-emulsion viscosity; the capillary number based relative permeability interpolation process, and the wettability modifications criteria to match the ASP flood results. The matched results included the flood oil recovery, oil cut, average oil saturation of the composite core, flow pressure differential, and the concentration of chemical effluents traced during the experiment.
This paper deals with coreflooding and modeling of ASP flooding in the difficult environment of carbonate reservoirs. The profile of ASP oil recovery in this carbonate composite core is more gradual, and it is different from those experienced in sandstone corefloods. This is accounted for by additional changes made to relative permeability curves moving from oil wet to water wet conditions.
A procedure to model the impact of reservoir CO2 on chemical EOR (polymer/ASP) flood performance has been developed. The work which was initially developed for polymer flood modelling has been further extended and a simple approach has been presented to model the impact of reservoir CO2 on ASP flood performance.
Fatehgarh reservoirs in Aishwariya field, located in Barmer Basin of Rajasthan India, have very high CO2 content in reservoir fluid. The oil is moderately viscous and aqueous based chemical EOR techniques like polymer/ ASP flooding are being considered for production enhancement. The presence of high CO2 may impact aqueous based flooding processes planned in Aishwariya field. Three unconventional mechanisms occur in the reservoir: i). With injection of water, CO2 is stripped out of oil over time, this leads to increase in oil viscosity. ii). Since CO2 decreases pH of the system, polymer in-situ viscosity is decreased. iii). CO2 reacts with sodium carbonate (alkali) in aqueous medium leading to reduction in pH which may have an impact on ASP performance.
An advanced processes simulator was used initially to model the impact of CO2 on polymer flood performance. For simplicity, solution gas was assumed to be entirely composed of CO2. Waterflood followed by polymer injection was simulated in the model. CO2 was defined as an aqueous component instead of conventional oleic component allowing for modelling polymer viscosity dependence on CO2 concentration.
In order to model the impact of CO2 on ASP performance, reaction of CO2 with alkali was included in the model. The ASP simulation run could now capture all three unconventional mechanisms occurring in the reservoir due to presence of CO2: increase in oil viscosity, reduction in polymer viscosity and consumption of alkali due to reaction with CO2. Different simulation runs were then carried out both with and without the reaction of CO2 with alkali and the results were compared. Impact of grid refinement on the flood performance was also studied.
The developed approach could mechanistically capture the impact of CO2 on ASP performance in Aishwariya field. It was also observed that grid refinement has a major impact on the results; fine grid simulation is required to properly evaluate the impact of CO2 on ASP performance as it can appropriately capture impact of dilution and reaction based on CO2 concentration (moles) available.
The paper presents a step by step approach of modelling the impact of in-situ CO2 on ASP flood performance. The suggested approach helped in evaluating the impact of CO2 on polymer/ASP flood performance and adjusting the injection slug design appropriately.
In order to design and analyse Alkaline Surfactant Polymer (ASP) pilots and generate reliable field forecasts, a robust scalable modeling workflow for the ASP process is required. Accurate modeling of an ASP flood requires detailed representation of the geochemistry and the saponification process, if natural acids are present. The objective of this study is to extend the existing models of ion exchange and surfactant partitioning between phases to improve the quality of the model.
Geochemistry and saponification affect the propagation of the injected chemicals. This in turn determine the chemical phase behaviour and hence the effectiveness of the ASP process. A starting point of such a workflow is to carry out ASP coreflood tests and history matching (HM) using numerical models. This allows validation of the models and generates a set of chemical flood parameters that can be used for forecasts. The next step is upscaling from lab to field. The presence of (geo)-chemistry in ASP model improves significantly the quality of core HM especially for produced chemicals, breakthrough time and their profiles shape.
The addition of surfactant partitioning between the oleic and the aqueous phases based on salinity of the system as well as propagated distance (time) improves understanding of the required surfactant concentration. The partitioning of surfactant is important for coreflood matching of native cores as they tend to have more clays and minerals that affect ASP phase behaviour. The upscaling of the HM coreflood was conducted in two steps. First step the coreflood was scaled up with the distance between injector–producer pair as the scaling parameter. Second step was the application of the scaled up injection rates, residual saturations, etc. to the full field model. Sensitivity study for parameters such as grid size, well distance, ASP slug size, and rate of surfactant partitioning was performed. It was found that grid size of 50ft was optimum for ASP modeling. The higher rate of surfactant partitioning resulted to lower recovery. The optimal well distance was determined as 700ft for optimization of oil recovery. The reduction of ASP slug size from 0.5PV to 0.3PV leads to the reduction in oil recovery by 2-3%.
Usually chemical reactions accompanied ASP process are left out of the model due to increase in complexity as well as longer computational time. However, their addition as well as presence of surfactant partitioning between the oleic and the aqueous phases makes ASP models more realistic and it results in significant improvement to coreflood HM quality and prediction of ASP process.
Zakwan, M. (Petroliam Nasional Berhad, PETRONAS) | Sahak, M. (Petroliam Nasional Berhad, PETRONAS) | Aris, M. Shiraz (Petroliam Nasional Berhad, PETRONAS) | Ariff, Idzham F. M. (Petroliam Nasional Berhad, PETRONAS) | Saadon, Shazleen (Petroliam Nasional Berhad, PETRONAS) | Muhammad, M. Fadhli (Petroliam Nasional Berhad, PETRONAS) | Radi, N. M. (Petroliam Nasional Berhad, PETRONAS) | Daud, N. M. (Petroliam Nasional Berhad, PETRONAS)
The injection of chemicals in a chemical enhanced oil recovery (CEOR) program is expected to impose technical and economic challenges in produced water management especially for offshore installations. The breakthrough of injection chemicals into the surface facilities process lineup, through the water phase, have been tested to be toxic and the typical overboard discharge option will have to be substituted with a much more complex and expensive reinjection scheme if a solution to treat the discharge water is not found. A study to find a chemical treatment solution capable of degrading the toxic components in CEOR produced water was carried out and upscaled towards a pilot implementation for an offshore Malaysian field. The advanced oxidation process (AOP) technique was evaluated as it showed promising capabilities for the intended application. The governing degradation mechanism in the AOP stems from the release of hydroxyl radicals from hydrogen peroxide (H2O2), with the aid of UV radiation, which oxidizes organic components in the injected chemicals to detoxify the outlet stream of the surface facilities process. The results from the experiments showed promising degradation potential where complete degradation of the toxic chemicals was achieved. Specific degradation rates of the chemicals at fixed rates of UV radiation were obtained in this study and used with the electrical energy per order (EE/O) upscaling correlation to size a treatment system for the intended pilot implementation. Compared to other established chemical degradation applications, the upscaling EEO value of 17.9 kWh/1000 USgal/order can be considered to be within reasonable range.