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IOR 2021
- Conference date: April 19-22, 2021
- Location: Online
- Published: 19 April 2021
41 - 60 of 77 results
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Estimating two-phase reactive flow model parameters from single- and two-phase modified-salinity core flooding data
Authors H.M. Ciriaco, H.M. Nick and A.A. EftekhariSummaryDue to the complexity of underlying physics of the modified salinity water flooding, mechanistic models are often utilized to better understand and predict its behaviour in the field scale. The mechanistic models are a combination of several submodels of different nature, each with several adjustable parameters. Adjusting these parameters by fitting the model to a limited number of recovery factors obtained from core flooding experiments is not a viable solution, often estimating highly uncertain values for the model parameters. We address this challenge by providing a framework for fitting a mechanistic two-phase reactive-transport model to a combination of low-cost single- and two-phase flow experimental data.
The effectiveness of modified-salinity water flooding is often tested in (qualitative) spontaneous and (quantitative) forced imbibition tests in the lab. Several mechanisms that are suggested for explaining the observed improved oil recovery cannot be distinguished in those traditional imbibition tests. Mechanistic models with adjustable physically-meaningful parameters exist for these mechanisms, e.g. carbonate dissolution, surface charge (and force) alteration, fines migration, water weakening, etc. However, obtaining these adjustable parameters by fitting “a mechanistic model that incorporates all these mechanisms” is not a good strategy. Our mechanistic models are a combination of chemical equilibrium and kinetics models that describe the chemical reactions between the ionic species in the aqueous phase (electrolyte model with known parameters), chalk and oil surface complexation reactions (CD-MUSIC, diffuse layer models with unknown parameters), and an empirical parameter linking the surface reactions to the relative permeability and capillary pressure model parameters. When fitting the model to the core flooding data, the optimization algorithms are more sensitive to the relative permeability parameters. Moreover, the number of parameters are often too many and can result in a largely underdetermined system of equations, for which the optimization algorithm is very sensitive to the initial estimates.
Our novel numerical framework optimizes the model parameters by simultaneously fitting the parameters to a set of core flooding, spontaneous imbibition, and single-phase chromatographic tests (i.e. injecting MSW to a core saturate with formation water and measuring effluent ionic concentrations with time). We obtain the initial estimates of the surface complexation model parameters by fitting the model to the zeta potential measurements performed on powdered carbonate suspensions. We finally demonstrate the capabilities of our framework by optimizing model parameters for a set of inhouse experiments performed on chalk cores from the North Sea reservoirs.
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Laboratory Study to Investigate Cyclic Hysteresis in Miscible and Immiscible WAG Experiments in Carbonate Reservoir
Authors S. Masalmeh, A. Al-Mesmari, A. Farzaneh and M. SohrabiSummaryIn this paper, we present the results of a detailed experimental study aimed at understanding three-phase hysteresis in miscible and immiscible WAG injection processes. It has been reported in literature that the two-phase hysteresis models will generally not be able to describe relative permeability obtained in three-phase core floods. The main shortcoming of two-phase hysteresis models is that after imbibition cycle, the relative permeability is reversible. In three-phase flow, a cycle dependent hysteresis was reported which could significantly impact the gas mobility in the different cycles and improves sweep efficiency.
In this study, a number of immiscible and miscible gas and WAG injection experiments were performed using limestone reservoir core samples from a carbonate reservoir. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by ageing the core in crude oil for several weeks under reservoir conditions. Methane (C1) was used as the immiscible injectant and CO2 was used as the miscible injectant.
The main conclusions of this study are: 1- Cyclic hysteresis in gas relative permeability was observed when comparing the first and second gas cycle, however, no further hysteresis was observed in the subsequent cycles, 2- The gas mobility at similar gas saturation for experiments starting with gas is better than that for experiments starting with water, 3- Gas and water relative permeability end points are not dependent on their own saturation alone as assumed in three-phase relative permeability models, significant variation in the relative permeability end points was measured at almost the same saturation, and 4- The water mobility of the experiments starting with water cycle is better than the water mobility of the experiments starting with gas cycle at the same water saturation. This shows the presence of gas before the first water cycle reduces the water mobility.
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Rheology, Stability, and Adsorption of an Amphoteric Foaming Agent for CO2 Mobility Control Applications under Reservoir Conditions
Authors Z. AlYousef, A. Gizzatov, M. Almajid and A. AlabdulwahabSummaryFoam injection is one of the most promising techniques to overcome gas mobility challenges during gas injection processes. Foam reduces gas mobility by increasing the gas apparent viscosity and reducing its relative permeability and, consequently, improving the gas sweep efficiency. The stabilization of foam at reservoir conditions, together with reducing surfactant adsorption on the rock minerals are the major challenges facing this technique. The objective of this study is to extensively evaluate the effectiveness of a potential surfactant on generating stable foams using sc-CO2 at high temperature and salinity conditions.
In this study, bulk and dynamic foam tests were conducted to evaluate the effectiveness of an amphoteric surfactant, Amphosol LB, on stabilizing foams at harsh reservoir conditions (more than 2000 psi, 100 oC and 57,000 ppm of brine salinity). For bulk foam tests, the stability of surfactant solutions as well as the foam rheological properties using foam rheometer apparatus were analyzed and quantified. For dynamic foam tests, the CO2 mobility reduction factor as a result of foam generation using the surfactant was measured using two different systems: microfluidic device (chip with physical rock network) and coreflooding apparatus (actual rock samples). Also, the adsorption of the surfactant on carbonate rock minerals was quantified using the coreflooding apparatus.
The experimental results demonstrated that the surfactant solution is chemically stable and able to generate foams at different reservoir conditions. The Amphosol LB surfactant solution produced foam with relatively high apparent viscosity when compared to those used for foam applications. The results also demonstrated that the foam viscosity increased as the foam quality decreased. For retention test, the results revealed that 86.56% of the injected surfactant solution was recovered. The amount of surfactant adsorbed by rock is about 0.257 mg/g rock. In the microfluidic chip and actual rock sample, the results also demonstrated that Amphosol LB surfactant solution showed higher resistance to gas flow and, accordingly, higher mobility reduction factor of sc-CO2 at 70% foam quality when compared to the other tested foam qualities. High apparent viscosity, small adsorption to the rock, and an acceptable CO2 mobility reduction factor are indicative of strong and more stable foam for reservoir applications.
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Microfluidic Device for Fast Pre-Screening of EOR Chemicals at Close to Reservoir Conditions
Authors A. Gizzatov, W. Wang, S. Chang, G. Thomas, A. Mashat and A. Abdel-FattahSummaryMicrofluidic devices allow manipulations with the flow of fluids at sub-millimeter scales. The advantages of this technology include a significantly reduced volume of fluids required for certain physical and chemical characterizations; reproducible and enhanced mixing of flowing phases; better control over the heat exchange; access to imaging of the pore-scale flow phenomena; reduced cost of characterization methods when compared to some conventionally used methods and devices; and more. This work reports on an innovative approach to study the recovery of crude oil from microfluidic devices. This approach was designed to closely mimic the environment within pores of carbonate rocks.
Commonly used techniques to study the recovery of crude from saturated core plug samples are coreflooding and imbibition experiments using an Amott cell. Coreflooding is labor intensive, does not provide pore-scale imaging, takes close to a week or longer to operate, uses liters of solvents, and is also cost intensive. Imbibition experiments also do not provide a visual understanding of the oil recovery process at the pore scale. To address some of these challenges, transparent microfluidic devices made of glass that are capable of operating at close to reservoir conditions were developed to improve and complement conventionally used devices. These devices contain patterned channels representing carbonate pore networks. The interior surface of the channels are fully coated by growing a thin layer of calcite nanocrystals, which closely represent a carbonate reservoir’s rock chemistry. The surface is then treated by crude oil aging to generate appropriate wettability resembling the natural reservoir carbonates. The fabricated device was used to study the recovery of oil from porous networks and to successfully prescreen candidate surfactants for enhanced oil recovery (EOR) applications.
The microfluidic devices developed here allowed us to effectively differentiate between three in-house developed surfactant formulations. Data obtained by image analysis of the oil recovery process from within the porous microfluidic channels using various surfactants provided quantitative oil recovery for each chemical and served as a useful benchmark to differentiate the best candidate formulations. Results also were used to compare efficiency of surfactants based on interfacial tension and potential effects related to wettability alteration. The high-temperature microfluidics platform allows us to rapidly prescreen a large number of formulations for applications in EOR, visualize mobilization of the oil from porous structure at close to carbonate reservoir conditions, and allow cost savings by facilitating processes in developing best EOR formulations.
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Investigation on the Effect of Micro-structure Difference between Hydrophobic Associated Polymer and Salt-resistant Polymer on Enhance Oil Recovery
More LessSummaryHydrophobic association polymers and salt-resistant polymers are functional polymers with stronger viscosifying properties than common polymers such as hydrolyzed polyacrylamide (HPAM). And both of them can furtherly expand sweep volume to improve oil recovery efficiency. However, the current researches on the two types of polymers are mainly focused on the EOR effect, and there is no in-depth investigation on the differences in their microstructure. In this paper, hydrophobic association polymer HSP and salt-resistant polymer SRP were selected to evaluate, and the differences in microstructure, hydrodynamic characteristic size, migration capacity and enhanced oil recovery were compared. The results show that the HSP has a complex spatial network structure, while the SRP has a rigid coarse-straight chain structure. The HSP has stronger spatial aggregation structure corresponding to larger hydrodynamic characteristic size. Compared with HPAM, both HSP and SRP have higher adsorption retardation rate, causing the resistance coefficient and residual resistance coefficient are larger. The higher flow resistance of spatial network leads to better EOR effect of HSP. Compared with the SRP, the EOR of HSP flooding can be increased by 2.98%.
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A Deep Investigation of EOR/EGR and Stimulation Enhancement Methods in Unconventional Reservoirs
Authors C. Temizel, C. Canbaz, H. Aydin and Z. WijayaSummaryProduction from Unconventional structures is being expected to be the future trend of oil and gas industry. Although the primary recovery values range between 5 to 8%, liquid-rich shale structures has great amount of hydrocarbon in place and it can be produced by EOR applications such as cyclic gas injection that can boost the production up to 1.7 times. This reference study gives a deep review of EOR mechanisms and the stimulation techniques for unconventionals.
A comprehensive investigation about the historical development of the concept, the technologies utilized as well as transferred from other industries, adaptness and impetus of the methods in both conventional and unconventional structures is described with the escalating efficacies that these methods ensured for different reservoir structures. The concepts are exemplified with existing worldwide field case studies and applications by implying the advantages, challenges and drawbacks belong to each story. All parameters are discussed and summarized that lead to conclusions on the criteria of application of enhanced technologies.
The concept of EOR and Stimulation is a proven area of application which demonstrated itself with its great number of worldwide applications in conventional structures. Key factor of success for an EOR application is to evaluate each case individually to take the suitable actions of technical and economic concerns. This study underlines the theory, key parameters, methodology, challenges and advantages of a successful EOR application for the wells that include intelligent or standard completions in unconventional structures. It aims to serve as a unique reference study which combines of all the aspects of the employed techniques and their usability in specific cases.
There are dozens of publications which includes certain examples of Enhanced Oil and Gas technologies, but a detailed study that includes all the aspects of EOR methods suitable to apply in unconventional reservoirs is missing. This study aims to be a reference study by giving all the details from design to result of a successful EOR application in unconventional reservoirs.
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Huff’n Puff EOR Optimization by using Different Cyclic Gases in Unconventional Shales
Authors C. Temizel, C. Canbaz, H. Aydin, V. Kudrashou, J. Wu, F. Haeri, Y. Unal and N. NurlybayevSummaryIncreasing global trend of unconventional production impelled the oil and gas companies to adapt the EOR mothods to unconventionals to increase the recovery. In this study, a deep review of cyclic gas (Natural Gas, CO2, N2) injection processes and the methodology to apply in unconventional shale reservoirs is described by investigating all the geological, petrophysical, production and reservoir engineering aspects. The significance of each uncertainty and control variable throughout the process is outlined.
A full-physics commercial simulator is used to identify the significance of control variables, and also the level of uncertainty which are directly affecting the production and recovery functions. The challenges encountered during implementation of cyclic gas injection processes are outlined in order to provide a comprehensiveand practical implementation perspective rather than only theoretical or a simulation work. Besides, the theory, advantages, drawbacks, benefits are given in details. Results of real cases are being compared and matched with the simulation results.
The study indicates the incremental advantages of appliying huff`n puff process in unconventional shale reservoirs by comparing the primary production performance with the performances of cyclic injection cases that uses various gases. Key factors that directly affect the reservoir, completion and operational attitudes are circumstantially given to technically handle a successful project in a feasible way. In the model, the objective function is built by considering the economic parameters to help NPV maximization in a realistic perspective. S-curves and tornado charts is used to visualize the results and illustrate the significance of parameters and ranges of the developed probabilistic economic model. The effect of huff`n puff method and how a successful cyclic injection gives better recovery and feasibility results is clearly shown.
Petroleum literature includes several studies related to cyclic gas injection. However, these works are either only focus on the simulation/theoretical parts or only includes a case study that focuses reservoir/production analysis. This comprehensive study closes the gap aims to be a reference by including a deep look into details of the theory and combines it with real field cases and solutions by clearly describing the candidate selection, modeling, physical parameters/key factors, economics, and success stories.
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Evaluation of First-Ever Foam Assisted Conformance Control for a Middle Eastern Carbonate Reservoir Offshore Qatar
Authors M. Taha, A. Kumar, P. Patil, M. Pal and Q.P. NguyenSummaryGas injection has been evaluated and implemented in a middle-eastern oil field as water alternating gas or WAG. It has been seen that WAG is economically viable and a robust EOR method for areas of the field which are homogenous and do not pose conformance issues. However, the application of WAG in heterogeneous parts of the field has not been widely attempted due to issues like an early gas breakthrough and unfavorable sweep efficiency that are typically associated with WAG in heterogeneous reservoirs. Hence it was decided to design a foam assisted WAG system that can provide the required conformance control to mitigate those issues and expand the use of WAG to the entirety of the field.
There are numerous references in literature to ‘aqueous foam’ as an attractive option to reduce the conformance issue of injected gases like hydrocarbon gas or carbon dioxide. There have been many field implementations of foam assisted WAG in CO2 flooded reservoirs in the United States. There is one example of foam-assisted hydrocarbon gas injection in the Snorre field. However, Foam as an EOR or IOR method remains untested and unproven in middle eastern reservoirs. In this study, we have carried out a comprehensive experimental program to design an effective foam system, that evaluates foam performance under specifically field conditions.
A complete laboratory program has been carried out to screen the best foaming surfactant formulation that resulted in selection of Alkyl Polyglucoside surfactant. The criteria’s used in selection of surfactant involves having low adsorption on rock, good aqueous stability at reservoir conditions, and strong foam stability in presence of oil. The surfactant screening also involved foamability tests in porous media under oil-wet and water-wet conditions. The selected surfactant showed good foam strength under both oil-wet and water-wet conditions. The impact of mobile oil was also observed by co-injecting oil during the linear core flood experiments which clearly showed that good foam strength can be achieved in lower flow fraction of mobile oil with foam. Additionally, it was shown that altering wettability using another non-ionic surfactant along with APG resulted in a higher foam strength. The evaluation of surfactant formulation for boosting of foam strength using Lauryl Betaine surfactant was also performed. All the experimental results generated in this detailed evaluation of foam in the lab will be used in a foam modeling during next phase of the project to design a field injection strategy.
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Successful Wettability Alteration Pilot in Offshore Reservoir: Pilot Planning, Execution, Monitoring and Interpretation
Authors M. Pal, P. Saxena, N. Rohilla, A. Katiyar, P. Rozowski and T. KnightSummarySurfactant injection as an EOR method is considered for a giant middle-eastern carbonate oilfield in offshore setting. The field is characterized by thin oil column, low permeability, and large lateral variations in fluid properties. Even after an extensive water-flood program, there are substantial amounts of oil left behind in the reservoir due to the mixed-wet to oil-wet nature of the Reservoir. An extensive surfactant-based wettability alteration EOR screening process was conducted to select the best surfactant for improving the oil recovery. After successful short surfactant injection trials, a long-term surfactant injection pilot was planned and executed. The pilot was supported by a comprehensive monitoring program. The pilot was conducted in an offshore environment involving very long horizontal well, which is unique in the industry and is first of its kind. A robust and comprehensive monitoring program is key to successfully evaluate the pilot performance and qualify the incremental oil production from the trial. A detailed monitoring program was prepared in advance before the pilot start-up, which involved internal and external parties. Monitoring plan consisted of high frequency monitoring of delivered surfactant quality, constant monitoring of surfactant injection concentration and injection rates. Plan involves high-frequency collection and monitoring of production samples with the aim of highlighting any changes compared to the base line measurement. External labs were also involved for precision monitoring of any surfactant breakthrough for pro-actively mitigating effects of any upset due to pre-mature surfactant breakthrough. For monitoring a dashboard has been created for identifying correlation between various processes. The pilot monitoring is still on-going and will continue for another 6 months. The comprehensive monitoring program has contributed to the successful conclusions from the pilot. The data gathered during the monitoring program will enable scale up of trial to other wells, qualification of incremental oil production, and to improve efficiency of the future implementation of surfactant injection on a greater number of wells.
The paper presents the results planning of trial form lab to field, implementation of monitoring plan and results of the monitoring plan, which support the trial conclusions. The pilot and the monitoring program are unique in themselves as the scale of operations and number of stakeholders involved are large. The pilot demonstrates that it’s possible to implement an EOR project in a highly complex offshore carbonate field. The pilot was conducted in an offshore environment involving very long horizontal well and is first of its kind.
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Hybrid Nanoparticle-Surfactant Stabilized Foams for CO2 Mobility Control at Elevated Salinities
Authors A. Soyke, B. Benali, T. Føyen and Z.P. AlcornSummaryA major problem during CO2 enhanced oil recovery (EOR) and CO2 storage is reservoir heterogeneity and the high mobility of CO2 relative to reservoir fluids. Surfactant-stabilized CO2 foams are a viable method for mitigating the impacts of reservoir heterogeneity and reducing CO2 mobility. However, surfactant-stabilized foams can breakdown at harsh reservoir conditions with elevated temperatures, salinities and pH. The addition of silica nanoparticles to the surfactant-stabilized CO2 foam has gained attention for increasing the foam strength and stability at harsh conditions. Therefore, this work includes nanoparticles in the surfactant-based CO2 foam to evaluate their ability to increase foam stability at harsh conditions. The primary objective was to systematically determine the effect of salinity on hybrid nanoparticle-surfactant, surfactant-, and nanoparticle-based foam generation and stability. We implement a multi-scale approach that spans from pore- to core-scale to investigate foam generation and stability with low and high salinity brines at reservoir conditions.
At the pore- and core-scale, unsteady-state CO2 injections were performed in porous media pre-saturated with the hybrid-, surfactant-, or nanoparticle-based foaming solution at low and high salinity. High-pressure silicon wafer micromodels enabled direct pore-level visualization of fluid dynamics and foam morphology with different the foaming solutions. Bubble density and size (foam texture) were compared and the results were used to corroborate core-scale measurements. Pore-scale results showed an increase in the number of bubbles by 20 to 27% for the hybrid solution, compared to the surfactant solution, indicating stronger foam. At the core-scale the hybrid foaming solution generated a weak foam of 5 cP whereas the surfactant-based solution generated a foam of nearly 20 cP. Increasing the salinity from 3.5 to 15 wt.% NaCl increased the number of bubbles by more than a 100% at pore-scale for both the surfactant and hybrid solutions. At the core-scale, apparent viscosity increased from 5 to 18 cP using surfactant solution. The generation of CO2 foam with and without nanoparticles delayed gas breakthrough by approximately 65% and improved water displacement which is advantageous for combined CO2 EOR and CO2 storage operations.
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Adsorption/Retention of HPAM Polymer in Polymer Flooding Process: Effect of Molecular Weight, Concentration and Wettability
More LessSummaryOne of the major issues of polymer flooding in EOR is the loss of polymer material during injection due to retention/adsorption and even the formation damage because of other mechanical phenomena. So, operating companies usually look for minimizing this polymer loss.
To understand the retention of polymers in reservoir rocks, we carried out several core flood experimental studies by investigating the influence of rock nature and permeability (high and intermediate permeability considering Bentheimer and Berea sandstones), polymer molecular weight (low and high), and concentration of polymer solutions (from dilute to semi-dilute).
Under monophasic conditions and high permeability, we show that the polymer retention if corrected for inaccessible pore volume (IPV) depends on polymer concentration regime: retention increases rapidly with polymer concentration (Cp), in the dilute regime and increases then very weakly in the semi-dilute regime. Moreover, the use of low polymer weight results in a high material loss, and in case of high molecular weight and low permeability, plugging is evidenced.
Besides, diphasic tertiary experiments were performed under water-wet and intermediate wet conditions. The first set of experiments was performed on the native water-wet Bentehimer porous medium. The second set of experiments was performed by altering first the wettability of the same porous media, by submitting them to ageing in presence of crude oil.
Our results mainly show that the polymer retention decreases when the oil is present in the porous system due to additional inaccessible pore volume as the added volume is now occupied by residual oil. However, the retention is even smaller in intermediate wet porous media because the pore surface is partially filled by oil. A phenomenological explanation is proposed that supports such observed behaviors.
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Polymer Screening to Enhance Oil Recovery at High Salinity/High Temperature Conditions; Rheology and Static Adsorption Studies
Authors M.S. Mousapour, M. Simjoo and M. ChahardowliSummaryThis paper aims to investigate the polymer screening for a clayey sandstone reservoir with a temperature of 80ºC having a high salinity formation brine. Ordinary HPAM does not tolerate this condition, and thus we considered three modified HPAM based polymers in our study, i.e., Polymer-A, polymer-B and polymer-C. Polymer solutions are prepared in a brine that was considered representative for see water. The rheology of the solutions was measured by a Paar rheometer. Moreover, the static adsorption tests for polymer solutions prepared in the makeup water were performed using reservoir rock sample through the bleach method. According to the rheology results, the viscosity of the solutions was a function of the polymer molecular weight (i.e. B>A>C). In addition, the viscosity of 2000 ppm polymer solutions at different temperatures ranging from subsea to reservoir condition (4º to 80ºC) was measured. At a shear rate of 10 1/s, the viscosity reduction due to the increase in temperature from 4º to 80º C was 35% for polymer C, while it was 48% for polymer B. Polymer C has the lowest molecular weight, and exhibited the lowest adsorption on the reservoir rock, e.g. 51% lower than polymer B (the highest adsorption value).
Results shows that the studied polymers could be considered proper candidates for core flooding studies, among the studied polymers, polymer-C can be considered the most proper one. However, it is necessary to investigate its long-term stability.
The results of this paper provide useful insight for other polymer flooding studies at HS/HT conditions.
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Experimental Design and Evaluation of Surfactant Polymer for a Heavy Oil Field in Sultanate of Oman
Authors R. Al-Jabri, R. Farajzadeh, A. Alkindi, R. Al-Mjeni, D. Rousseau, S. Renard, V. Miralles and E. DelamaideSummaryHeavy oil reservoirs remain challenging for surfactant-based EOR, particularly in selecting fine-tuned chemical formulations which exhibit high performances and are cost-effective. This paper reports a core-scale laboratory feasibility study, aiming at designing a surfactant-polymer pilot for a heavy oil field with an oil viscosity of ∼500cP in the South of Sultanate of Oman, where polymer flooding has already been successfully trialed. A major driver was to design a simple chemical EOR method, to minimize the risk of operational issues (e.g. scaling) and ensure smooth logistics on the field. To that end, a dedicated alkaline-free and solvent-free surfactant polymer (SP) formulation has been designed, with its sole three components, polymer, surfactant and co-surfactant, being readily available industrial chemicals. This part of the work has been reported in a previous paper. A comprehensive set of oil recovery coreflood tests has then been carried out with two objectives: validate the intrinsic performances of the SP formulation in terms of residual oil mobilization and establish an optimal injection strategy to maximize oil recovery with minimal surfactant dosage.
The coreflood tests performed involved various rock mineralogies and structures: Bentheimer sandstone as model analogues ; artificial sand and clays granular packs with representative mineralogical composition ; native reservoir rock plugs, to validate the injection strategy in fully representative conditions.
Under injection of “infinite” slugs of the SP formulation, all tests have led to tertiary recoveries of more than 88% of the remaining oil after waterflood with final oil saturations of less than 5%. When short slugs of SP formulation were injected, tertiary recoveries were larger than 70% ROIP with final oil saturations less than 10%. The final optimized test on a reservoir rock plug, which was selected after an extensive review of the petrophysical and mineralogical properties of the available reservoir cores, led to a tertiary recovery of 90% ROIP with a final oil saturation of 2%, after injection of 0.35 PV of SP formulation at 6 g/L total surfactant concentration, with surfactant losses of 0.14 mg-surfactant/g(rock). Further optimization will allow accelerating oil bank arrival and reducing the large PV of chase polymer needed to mobilize the liberated oil.
These outcomes validate, at lab scale, the feasibility of a surfactant polymer process for the heavy oil field investigated. As there has been no published field test of SP injection in heavy oil, this work may also open the way to a new range of field applications.
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Experimental Investigation on the Formation, Stability and Emulsification Mechanism of Polymeric Surfactants Emulsion in Porous Media
More LessSummaryPolymeric surfactants display brilliant capabilities in expanding sweep volume and improving oil displacement efficiency as compared with that of traditional displacing agents attributing to the co-existence of hydrophilic and hydrophobic groups in molecular chains. The displacement effect of emulsification and the difficulty of demulsification are the key factors affecting the application of polymeric surfactants. In order to study the formation, stability, and oil displacement ability of the polymeric surfactants emulsion in porous media, we took the newly synthesized anti high temperature and high salt polymeric surfactants as the research object to study the influence of different concentrations, different oil-polymer ratios, and different migration distances on the stability of polymeric surfactants emulsion. The generative mechanism of emulsified oil droplets with the polymeric surfactants and its relationship with EOR were then elucidated by comparing core flooding experiments with different injection rates, different saturated oil types, and different polymeric surfactants concentrations. The results showed that the main reasons for the formation of polymeric surfactant emulsions are a certain shearing action, the snapping action of hydrophobic microdomains on residual oil droplets and assisted effect of colloidal asphaltene. The longer the migration distance of polymeric surfactants in porous media, the larger the size of the emulsion and the weaker the stability. Contrary to the migration distance, the higher the ratio of oil to water and the concentration, the easier it is to produce the emulsion, and the smaller the particle size of the emulsion, the better the stability. The combination of dimensionless pressure gradient and capillary number as the characterization parameters of polymeric surfactants emulsion can effectively determine whether emulsification can occur during the polymeric surfactants displacement process. The results of this paper can provide some theoretical guidance for formulating the production plan of polymeric surfactants in offshore oil fields.
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Successful Wettability Alteration Pilot in an Offshore Reservoir: Laboratory Analysis to Support Planning, Implementation and Interpretation
Authors N. Rohilla, A. Katiyar, P. Saxena, M. Pal, P. Rozowski and A. GentilucciSummaryWettability Alteration from oil-wet to water-wet condition is a very promising EOR technique for producing significant incremental oil recovery from oil-wet carbonate reservoirs. A thorough lab program led to the development of the wettability altering surfactant formulation for a giant offshore carbonate reservoir. The field implementation was done in a systematic step wise manner to mitigate the risk in implementing such a technology field wide. A long term surfactant injection pilot was then conducted to evaluate efficacy of developed solution at field scale. Post surfactant injection, a rigorous Monitoring and Surveillance program was put in place to carefully monitor production data and quantify incremental oil gains.
Surfactant injection was done in a continuous mode at 4,000 ppm active concentration in sea water for 7 months followed by sea water injection. Surfactant injection didn’t result in any injectivity loss or formation of any viscous emulsions in the reservoir. An injector where surfactant was injected (Injector-01) gained 8% yearly injectivity as a result of the surfactant injection. Incremental oil response was observed for both producer wells for the pattern. There was no surfactant breakthrough observed from produced water analysis till now.
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Approximating Irreversible Asphaltene Adsorption to Screen IOR Candidates
Authors S. Hassan, S. Kamireddy, M. Yutkin, C. Radke and T. PatzekSummaryAfter drainage of brine-filled rock pores with an asphaltenic crude oil, the wettability state of a sandstone or limestone subjected to a high capillary pressure eventually changes from strongly water-wet to mixed-wet. A partial reversal of this mostly irreversible change of reservoir rock wettability is the condition necessary to increasing field-scale recovery of asphaltenic crudes.
In this work, we propose asphaltene molecule proxies that possess many asphaltene properties and satisfy reservoir adsorption conditions. We quantify the irreversible adsorption of these analogs with carboxylic, amino, or sulfate groups onto the silica using a quartz crystal microbalance with dissipation (QCM-D). We explore conditions for desorption of the irreversibly adsorbed analogs.
We use aqueous-soluble functionalized dextran polymers of variable chain length as asphaltene analogs. Adsorption was studied in brines with varying salts and pH. QCM-D results reveal that positively charged ammonia-functionalized poly-dextrans adsorb on silica irreversibly regardless of chain length and brine composition. However, sufficiently long chains and the presence of calcium ions are required for negatively charged sulfate- and carboxylate-modified poly-dextrans to adsorb irreversibly onto silica surface. Such a phenomenon is explained by calcium ion bridging of two negatively charged moieties. Experiment duration is found to be important for irreversible adsorption as well.
After the polymers have irreversibly adsorbed to silica, we attempt to desorb them by changing the brine composition. Desorption tests included combinations of 10, 100 and 300 mM of NaCl, KCl and CsCl. Preliminary results suggest that dextran polymers adsorbed via the bridging mechanism (i.e., sulfate- and carboxylate-modified) desorb using salt solutions with monovalent cations of potassium and cesium in obedience to the Hofmeister series. A similar result, but to a lesser extent, applies to ammonia-functionalized poly-dextrans yielding far less desorption.
In summary, positively charged amines adsorb irreversibly on the negatively charged silica surface. However, three factors are important to achieve irreversible adsorption of carboxylates and sulfates: a sufficient chain length, presence of calcium ions, and time. For monovalent cations, desorption efficiency seems to follow the Hofmeister series but to different extents depending on the adsorption mechanism.
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Detailed Surfactant Model Construction Elucidates Benefits of Cross-Flow in Fluvial Heterogenous Surfactant-Polymer Pilot in Grimbeek
Authors V.S. Scordo Paes De Lima, G.F. Villarroel, V. Lara, F. Schein, A. Therisod, P. Guillen, V. Serrano, A. Ruiz, A. Lucero and J. JuriSummaryAfter an 18%STOOIP incremental oil polymer pilot we have developed the surfactant-polymer(SP) formulation to recover the residual oil. The SP formulation has a viscosity more than 1.5 times greater than oil viscosity. The Grimbeek reservoir is a heterogeneous multilayer fluvial system with many surfaces of contact between high permeability and low permeability.
Increasing oil recovery because of induced flow from low permeability to high permeability driven by a high viscosity slug has been around for more than 30 years. This phenomenon occurs when there is higher pressure drop across a viscous slug.
Does the cross-flow mechanism (Sorbie2019) that increased the polymer flow recovery benefit the surfactant-polymer flooding? How is this mechanism affected by factors such, removal of residual oil, surfactant concentration, slug size, salinity changed, retention and injection strategy? To answer these questions, we construct a detailed surfactant model in a compositional simulator that captures the multiscale nature of the multiple surfaces of contact created by the fluvial depositional environment. This realistic representation of the subsurface poses challenges to the numerical methods in the compositional simulator.
Through modelling the fluvial geometry in a compositional simulator, our simulation reveals that the viscosity overdesigned of the surfactant-polymer formulation favours accessing to more residual oil. Starting from a black oil model, the work was divided into four main tasks. First, converting the BlackOil PVT Model to a compositional model, followed by creating trajectories and perforations in an unstructured grid that brings complexities to the typical well-tracking task to place wells in corner point grids. Third, the compilation of the historical production of oil and gas as well as the water injected and polymer. We automate the input deck using visual basic and Python scripts that now are useful for any source file. Based on them, we can propose the most suitable injection strategy.
This result indicates that when the geological setting is heterogeneous is better to increase formulation viscosity (it depends on the formulation, but this usually means to increase surfactant concentration) and avoid the typical EOR workflow of formulation optimization to reduces surfactant concentration.
Our simulation elucidates the efficacy of increasing the formulation concentration to reduce the slug size. And It improves our understanding of the interplay between viscosity and capillary forces. Also, we developed different scripts that allow us to easily obtain the dataset for our compositional simulator.
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Development of a Thermogel for the Treatment of Fractured Reservoir
Authors L. Hernando, N. Martin, A. Zaitoun, E. Read and O. BraunSummaryMany fields worldwide suffer of excessive water production and poor sweep efficiency because of conformance problems due to the existence of reservoir heterogeneities and preferential pathways for water flow. When heterogeneity contrasts are high, a permeability barrier has to be placed in water thief zones. In this paper, a new Conformance technology using thermo-associative polymers (TAPs) is presented. TAPs are polymers containing temperature-sensitive chemical moieties, called “LCST moieties” (“LCST” for “Lower Critical Solubility Temperature”). These moieties are totally hydrophilic at low temperatures and becomes hydrophobic above a threshold temperature. They can thus interact with each other, forming a three-dimensional network through hydrophobic associations. This process is thermo-reversible. By adjusting the amount of LCST moieties and the molecular weight of the polymer, strong viscosity contrasts may be obtained between low and high temperature (up to several decades). This strategy was used to develop a new family of conformance products called “thermogel” where a transition from a low viscous solution to a strong gel may be obtained upon heating. The paper presents the work performed to develop a Thermogel for a North Sea fractured chalk application. Since chalk matrix has a very low permeability (K∼1.5mD), strategy of production is to fracture and acid stimulate the formation along the well with water injection support. In this specific field case, one isolated fracture connects injection well to production well inducing a short cut between the wells. The aim of the pilot is to inject a Thermogel treatment to reduce water intake from the fracture. The paper describes the development of the product through laboratory experiments. The evaluation of the properties of different thermogels in bulk rheology and in coreflooding experiments are discussed in view of the pilot application. The main results can be listed as follows:
- – The new thermogel has a threshold temperature of around 40°C, that enables gelation far from the injection well, deep in the reservoir.
- – Coreflooding experiments in carbonate pack that mimic fracture permeability (K∼250D) have been performed. A minimum Thermogel concentration of 60 000ppm is necessary to form a gel with high blocking efficiency.
- – Injectivity in coreflooding experiments depends on Thermogel chemistry and on elasticity properties.
- – Strong face plugging when Thermogels are injected in pure matrix conditions (K=2mD) ensures that the product cannot propagate inside the matrix and will flow in fracture only.
From those laboratory results, two products have been qualified for further field applications.
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Model for the Diffusion of N-alkane Confined in Nanopores: Effect of the Fluid/Pore-Wall Interaction
More LessSummaryAs one of the most important parameters describing the dynamic behavior of fluid, diffusion coefficient can be used to evaluate the mobility and viscosity. Under nanoconfinement, the diffusion behavior is quite different from that in bulk space because of the strengthened fluid/pore-wall interaction. In this work, the ‘extra energy barrier’ induced by fluid/wall interaction is emphasized, and the main factors affecting the diffusion behavior, including pore size, temperature, and pore geometry, are discussed. We find that the ‘extra energy barrier’ is significant at the first molecule layer and decreases rapidly within two layers, and when the distance from the wall is greater than 2.5 nm, the ‘extra energy barrier’ can be ignored. However, the temperature almost has no effect on the ‘extra energy barrier’. In addition, the diffusivity of shorter chain n-alkanes is higher than that of the longer ones due to the weaker fluid/wall interaction.
Besides, geometry of nanopores also has a great impact on the apparent diffusion, and it is easier for n-alkane molecules to transport in a slit nanopore than in a circular nanopore because of the curvature effect of the later ones. N-alkane molecules seem to stick to the wall when pore size reduces to 0.5 nm in a slit and 5nm in a circular pore. And when the size of slit and circular pore exceeds 500 nm and 5000 nm, respectively, the existence of the ‘extra energy barrier’ can be ignored and the apparent diffusion is quite similar to that of the macropores.
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Pore Scale Observations of Wetting Alteration During Low Salinity Water Flooding Using X-Ray Micro-CT
Authors E. Andrews, A. Muggeridge, A. Jones and S. KrevorSummaryThis paper describes the first pore scale in-situ observations of wetting alteration on clays during tertiary low salinity flooding. Observations in the laboratory over a range of scales show that reducing the salinity of injected water can alter the wetting state of a rock, making it more water-wet. However, there remains a poor understanding of how this alteration impacts the distribution of fluids over the pore and pore network scale and how it leads to additional oil recovery. In this work, X-ray micro-CT scanning is used to image an unsteady state experiment of tertiary low salinity water flooding in a Berea sandstone core with an altered wettability due to exposure to crude oil. Oil was trapped heterogeneously, at a saturation of 0.62, after flooding with high salinity brine. Subsequent flooding with low salinity brine led to an oil production of three percentage points. To understand the mechanisms for this additional recovery, we characterise the wetting state of the sample using imagery of fluid-solid fractional wetting and fluid pore occupancy analysis. Pore occupancy analysis shows that there is a redistribution of oil from large pores to small pores during low salinity flooding. We observe a decrease in the solid surface area covered by the oil after low salinity flooding, consistent with a change to a less oil-wetting state. Pore by pore analysis of the mineral surface area covered by the oil shows that the wetting alteration during low salinity flooding is more significant on clays which likely control the behaviour. Whilst there was only three percentage points of additional recovery during low salinity flooding, the wetting alteration led to the redistribution of 22% of oil within the rock. The success of low salinity water flooding depends on a wetting alteration and oil mobilisation as well as a pore structure which can facilitate the production of the mobilised oil.
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