Surfactin is an anionic surfactant generated by bacteria. Although it has high ability to decrease interfacial tension (IFT) between oil and water, it binds with bivalent cations and forms precipitation. Because the precipitation causes the significant reduction of reservoir permeability, surfactin cannot be applied to EOR in oil reservoir whose bivalent cations concentration is more than 100 ppm. This study investigated methods for applying surfactin to reservoir containing bivalent cations with high concentration.
Screening of an effective binding inhibitor was carried out by measuring turbidity of the solution containing 0.3 wt% of surfactin, 900 ppm of calcium ion, and inhibitor candidates such as alcohols, chelating agents, cationic surfactants, and ion capturing substances. Influence of the inhibitors on surfactin capacity for decreasing IFT was also evaluated by measuring IFT between the solution and oil. The best inhibitor was finally selected through the injectivity tests using Berea sandstone core which was saturated with calcium solution. EOR potential of the solution containing the inhibitor was evaluated by the core flooding experiments.
Citric acid and trisodium citrate inhibited binding of surfactin with calcium ion with lower concentration such as 0.6 wt%, they were selected as potential inhibitors and subjected to the IFT measurements. Both of them had strong potential as co-surfactants of the surfactin because IFT was greatly decreased to less than 0.1 mN/m which was less than a tenth as compared with IFT between the pure surfactin solution and oil. Trisodium citrate however caused significant permeability reduction on the injectivity tests whereas citric acid could be injected into the core without permeability reduction. The high pH value of trisodium citrate solution might cause the dissolution of ferrum and aluminum in the core and the colloids of ferrous hydroxide and aluminum hydroxide were formed in the core, which brought the significant permeability reduction. Citric acid was selected as the best inhibitor and subjected to the core flooding experiments. 25 % of oil remaining after primary recovery was recovered by injecting the solution containing 0.3 wt% of surfactin, 0.6 wt% of citric acid and 900 ppm of calcium ion. Rise in the differential pressure was not found during the injection of the solution, which suggested that citric acid was effective for inhibiting the precipitation in oil reservoir. Moreover, 25 % of recovery factor was 5 % higher than the recovery factor obtained by injecting pure surfactin solution. Citric acid is also effective for enhancing the surfactin capacity for increasing the recovery factor.
Citric acid has dual role as the binding inhibitor and co-surfactant. Because citric acid is environmentally friendly and cheap chemical, it can be promising additive which increase the applicable reservoir and potential of surfactant EOR.
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.
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.
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.
Partially hydrolyzed polyacrylamide (HPAM) is one of the most widely reported polymers for chemical enhanced recovery (EOR) since most of the previous work deals with low-temperature and low-salinity reservoirs. As most of the remaining oil is in the deeper and hotter reservoirs, application of HPAM is limited because it is not suitable for high-temperature and high-salinity (HTHS) conditions. HPAM suffer a huge viscosity loss due to charge shielding effect and hydrolysis of the amide group. In presence of divalent cations, hydrolyzed product may also precipitate. In this work, we propose a novel thermo-sensitive water soluble polymer for HTHS conditions. Due to the presence of thermo-sensitive monomer, as the temperature exceeds lower critical solution temperature (LCST), the formation of physical network takes place. This formation of physical network results in the viscosity enhancement. The rheological behavior of the polymer was investigated using Discovery Hybrid Rheometer (DHR-3) at different polymer concentrations, temperatures, and in presence of different ions. Two different regions were observed in the viscosity-temperature plot. At lower temperatures (T< LCST), thermothinning behavior was observed i.e. viscosity decreased with temperature. At higher temperatures (T> LCST), the thermo-thickening behavior was observed i.e. the viscosity increased with temperature. This thermo-thickening also depends on the salinity of the solution. By increasing the salinity of the solution, the LCST shifted at low temperatures. In deionized water, no thermo-thickening was observed and only thermo-thinning behavior was noted. Such type of viscosity behavior is highly desirable for EOR operation as low viscosity at low temperatures ease the pumping operation. As the liquid move down the reservoir, the solution viscosity increases due to the formation of network structure.
Oil is recovered from a reservoir in three different stages termed as primary, secondary, and tertiary oil recovery. In primary oil recovery, oil is recovered using the natural pressure of reservoir, while in secondary recovery; some external fluids such as water or gas are injected to recover additional oil. However, only one-third of the oil present in a reservoir can be recovered in the primary and secondary stage using water flooding (Alagorni, Yaacob, and Nour 2015). To recover the remaining oil present in a reservoir, enhanced oil recovery (EOR) methods are used at the tertiary stage. Thermal EOR, gas injection and chemical EOR are most important tertiary oil recovery methods (Olajire 2014, Kamal 2016, Xu, Saeedi, and Liu 2017).
AbstractThe era of easy oil recovery is over. One of the ways to economically improve oil production is through Enhanced Oil Recovery (EOR) implementation especially in mature field development. Alkaline-Surfactant-Polymer (ASP) flooding is considered to be the most promising EOR choice between the chemical flooding options due to its great effectiveness as result of synergy between Alkaline, Surfactant and Polymer. The main objective of this work is to analyse the pH evolution of different alkali species (NaOH, Na2CO3 and NH3) that should be used in ASP flooding application by using PHREEQC thermodynamic database software.The work will divide the simulation into static and dynamic test. The static test will give result of pH evolution in terms of increasing alkali concentration in the brine to measure initial performance of each alkali species. The dynamic test will be used to simulate each alkali species performance in field application and involve of building a 1D reactive model that describe flow path of communication between injector and producer well in a reservoir and measures the pH evolution at the production well. This work will also use different reservoir brine and injection water composition for each test that will represent the onshore and offshore environment due to different amount of Total Dissolved Solids (TDS) of each case.Through the result of this work it is found out that in onshore NaOH will be preferred based on its performance and cost, and as for the offshore environment case, NH3 will be more preferred based on its performance and storage size. One issue to be notice for the implementation of ASP flooding in offshore that it requires the injection water to be in low salinity and that the water treatment approach is more preferred compared to pipeline construction to provide the required injection water as it is more economical.
Anand, A. (Shell Development Oman) | van Batenburg, D. (Shell Global Solutions International B.V.) | Parker, A. (Shell Global Solutions International B.V.) | Eikmans, D. (Shell Global Solutions International B.V.) | Boersma, D. (Shell Global Solutions International B.V.)
Predicting Alkaline Surfactant Polymer flood performance at fullfield scale is an interestingly vast subject. Typically, this would comprise of detailed modelling exercises at different dimensions and resolutions to calibrate the model for observed physical and geo-chemical behavior during the fluid flow. Modelling of different physical and chemical phenomena active during the ASP flood offers different complexities. To name a few, the phenomena active during the ASP flood in a reservoir are changing salinity, changing interfacial tension, changing capillary pressure and relative permeability, viscosity modification, chemical transport and retention, residual resistance factor, shear effects and so on. Nonetheless, the degree of areal and vertical heterogeneity in the field has a significant imprint on the ASP flood as an effective recovery process and poses another hurdle in the flood optimization. Also, due to large number of variables associated with the ASP process itself, the number of uncertainty and design parameters increase tremendously in comparison to any conventional recovery technique. The large list of sensitivity variables with increased computational time to model ASP active processes, makes it further restrictive to carry-out a holistic sensitivity analysis.
This paper investigates and addresses the aspects of a field scale development of an ASP flood with the help of full-fledged ASP modelling for our example field. The paper will cover the entire spectrum of the ASP feasibility study from illustrating the approach adopted to simulate the ASP active phenomena to the demonstration of the flood optimization techniques for the field. We will illustrate how the degree of areal and vertical heterogeneity in the field can cause inefficient utilization of chemicals, which in our case was found to have the most limiting effect on ASP field performance. We will discuss some of the ways to optimize the ASP flood in such a heterogeneous reservoir system. The selection of the uncertainty and design parameters and their ranges will be shown and the outcomes of the sensitivity analysis will be presented, including creaming curve analysis. We will also highlight the fullfield 3D effects on some of the conventionally established ASP parameters, for instance slug size.
Hosseini-Nasab, S. M. (Delft University of Technology) | Padalkar, C. (Delft University of Technology) | Battistutta, E. (Delft University of Technology) | Zitha, P. L. (Delft University of Technology)
Alkaline-Surfactant-Polymer (ASP) flooding is potentially the most efficient chemical EOR methods. It yields extremely high incremental recovery factors in excess of 95% of residual oil for water flooding. The current opinion is that such extremely high recoveries can only be achieved at optimum salinity conditions, i.e. for the Winsor type III micro-emulsion phase characterized by an ultra-low interfacial tension (IFT). This represents a serious limitation since several factors including alkali-rock interaction, initial state of reservoir water and salinity of injected water may shift the ASP flood design to either under or over optimum conditions.
A recent experimental study of ASP floods, based on a single internal olefin sulfonate (IOS), in natural sandstone cores varying salinity from under-optimum to optimum conditions indicated that indeed high recovery factors can be obtained also at under-optimum salinity conditions (see parent paper in this conference by Battistutta et al (2015).
In this paper a mechanistic model is developed to explore the causes behind the observed phenomena.
The numerical simulations were done using the UTCHEM research simulator (University of Texas at Austin) together with the geochemical module EQBATCH. UTCHEM combines multiphase multicomponent simulator with a robust phase behaviour modelling. An excellent match of the numerical simulations with the experiments was obtained for oil cut, cumulative oil recovery, pH profile, surfactant, and carbonate concentration at effluents. The simulations gave additional insight into the propagation of alkali consumption, salinity, surfactant and polymer profiles within the core. The study showed that the initial condition of the core is important in designing an ASP flood. Due to the uncertainties in the various chemical reactions taking place in the formation, an accurate geochemical model is essential for operating the ASP flood at a particular salinity region. Moreover, simulation results demonstrate for the crude oil with considerably low acid number, the ultralow IFT and low surfactant adsorption can be achieved over a wide range of salinities less than optimal salinity. The results provide a basis to perform better modelling of the under-optimum series of experiments and optimizing the design of ASP floods methods for the fields scale with more complicated geochemical condition.
Chemical Enhanced Oil Recovery (EOR) has seen numerous applications worldwide onshore but very few offshore. The reasons for that are mostly related to the technical and logistical challenges that need to be overcome for the successful implementation of chemical EOR: transporting various chemicals to the platforms, the need for space for the mixing skids and storing chemicals on the platforms, the need to use sea water as the injection fluid among others. As primary and secondary recovery reach their technical and economical limits in offshore fields, the operators are faced with the dilemma of abandoning the field and the platforms or resorting to EOR to increase recovery and extend the life of the field. Non chemical EOR techniques face their own challenges such as the need for large gas supply for gas injection so chemical methods cannot be ruled out so easily. However new approaches need to be defined to make chemical EOR a realistic method for offshore reservoirs. A large part of these issues arise from the mindset which associates chemical EOR with Alkali-Surfactant-Polymer injection. The approach proposed is to use only surfactant in cases where polymer is not absolutely required and to eliminate alkali altogether. This will eliminate various obstacles such as deck space limitations and the need to soften the injection water. This approach opens new doors for chemical Enhanced Recovery offshore. Such an approach is possible thanks to the progress in surfactant formulation and the development of adsorption inhibitors which allow dealing with seawater as an injection fluid. The novelty is not the technology but the way the standard approach is discarded to the benefit of a simpler solution.
Alkali-surfactant-polymer (ASP) flooding is a commercially viable enhanced oil recovery method. The complexity of chemical interactions, multi-phase flow, emulsification, capillary number changes and upscaling issues, especially in highly heterogeneous reservoir, make field designs difficult to extrapolate from coreflood measurements. In this work, two representaions of low interfacial tension conditions in chemical flooding were evaluated to determine the impact of model formulation on scaling-up from lab data to field situations. The first one is a mechanistic model based on interpolation of relative permeability curves parametrized with respect to the local capillary number. The second model requires tracking a thermodynamically stable phase known to exist at water-oil ultralow interfacial tension, namely a microemulsion. To perform this analysis, two sets of chemical coreflooding results were history matched and then the tuned models were utilized for field-scale predictions. For ASP flooding, a sensitivity analysis was implemented to show the importance of microemulsion phase on ASP upscaled (field scale) forecast. In this study, coreflooding experiments were performed using three different crude oils, case I: heavy oil with high acid number, case II: medium oil with high acid number and finally, case III: light oil with very low acid number. Predictions between the two modeling approaches are shown to diverge from each other upon upscaling of core-scale history matched models. This discrepancy is mostly attributed to the need to track a microemulsion phase behavior as well as its properties. Effects are more pronounced for heavier oil with high acid number. The results of this analysis should be useful to constrain field projections of any field design of surfactant-assisted EOR projects. Additionally, this study provides guidelines to understand existing uncertainties in current chemical flooding simulation regarding our ability to accurately predict the results of such a chemical flood design.