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IOR 2017 - 19th European Symposium on Improved Oil Recovery
- Conference date: April 24-27, 2017
- Location: Stavanger, Norway
- Published: 24 April 2017
1 - 100 of 139 results
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Bayesian Inversion of Time-lapse Seismic Waveform Data Using an Integral Equation Method
Authors K. S. Eikrem, M. Jakobsen and G. NævdalIn the last couple of decades, we have witnessed an increased use of time-lapse seismic data. Interpretation of time-lapse seismic data can give a better understanding of the oil saturation in the reservoir, leading to identification of the water-flooded areas and pockets of remaining oil, and an improved understanding of compartmentalization of the reservoir. Within the context of dynamic reservoir characterization or seismic history matching, where one performs a quantitative integration of time-lapse seismic and production data, the covariance matrix (quantifying the uncertainty) of the seismic data needs to be specified. Usually, this is done in a very ad-hoc manner, for example by using a diagonal covariance matrix where the uncertainty is given in percentage of the measurement values. Eikrem et al. (2016) has recently demonstrated that a more accurate and complete dynamic reservoir characterization can be obtained if one performs a Bayesian seismic waveform inversion for the seismic parameters and use the full covariance matrix when updating permeability and porosity. In that paper a simple linear Born inversion was used, and it is of interest to investigate whether similar results hold for a more advanced seimic inversion method. The present work will focus on Bayesian nonlinear full waveform inversion (FWI) to get an estimate of the uncertainty in the seismic inversion. In contrast with the main stream of researchers within the FWI community, we develop a direct iterative nonlinear Bayesian inversion method based on an explicit representation of the data sensitivity function in terms of Green functions, rather than the indirect optimization approach based on the adjoint state method. Our method is based on the T-matrix approach by Jakobsen and Ursin (2015).
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Integrated Approach to CO2 EOR and Storage Potential Evaluation in an Abandoned Oil Field in Czech Republic
Authors R. Berenblyum, A. Khrulenko, L. Kollbotn, A. Nermoen, A. Shchipanov, H.J. Skadsem, J. Zuta and V. HladikThe paper presents the results of the experimental and simulation activities of the Czech-Norwegian CO2 Pilot Preparation project (REPP-CO2) carried out under Norway Grants. A relatively small hydrocarbon field located in Vienna basin was selected as a candidate for the CO2-EOR and storage (CCUS) pilot. The field produced in 1950-1970’s, the available reservoir data is somewhat limited and uncertain as typical for old abandoned fields. Nevertheless, based on available geological knowledge, core material and fluid samples (sometimes from the neighboring analog fields) a geological model was build and an integrated approach to evaluation of CO2-EOR and storage (CCUS) potential was suggested. As a first approximation to the CCUS potential, a material balance model was established to evaluate aquifer size and connectivity, as well as potential CO2 storage capacity. The material balance study was based on available production history. Laboratory investigations of available core material and fluid samples allowed to identify and reduce the uncertainties related to fluid properties, geochemistry and geomechanics. An approach was suggested to link core scale geomechanical experiments to the field scale, while addressing the uncertainty in geomechanical parameters in a systematic way. Material balance studies, geological modelling and interpretation of experimental data enabled us to create a simulation model matched to available production and pressure data, therefore laying out a good basis for evaluation of CO2-EOR and storage (CCUS) potential. Simulations taking into account advantages in drilling, monitoring and reservoir technology over four decades since the field abandonment indicated a potential to recover approximately as much oil as was produced from the virgin reservoir. The CO2-EOR is also believed to create a business case suitable for paving the way for the storage project where estimated capacity is up to 1 million tons depending on technical and economic conditions.
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Nickel Decorated Carbon Nanocomposites as Catalysts for the Upgrading of Heavy Crude Oil
More LessSummaryNickel (Ni) nanoparticles (NPs) supported onto different carbon nanomaterials, including ketjenblack carbon, carbon nanotubes and graphene nanoplatelets, and zeolite are prepared via the wet chemical method and employed as catalysts for the viscosity reduction of heavy crude oil. X-ray powder diffraction and transmission electron microscopy confirm the formation and uniform dispersion of Ni NPs with an average particle size of ca. 9 nm on the surface of supports. Thermogravimetric analysis is used to determine the content of Ni NPs in the nanocomposites. The specific surface area and pore volume are studied by the N2 adsorption–desorption surface area analyzer. Furthermore, catalytic aquathermolysis is conducted in a batch reactor containing HCO, hydrogen donor and the as-prepared nanocomposites under conditions of temperatures of 200–300 °C and pressures of 2–5 MPa. Parameters, such as temperature, hydrogen donor, catalyst dosage and reaction time, are further investigated to improve the catalytic activity. It is discovered that with the nanocomposite catalysts, high viscosity reduction ratio of 97% is achieved and undesirable viscosity regression is not observed. These results suggest that carbon supported Ni nanocomposites can serve as a promising candidate catalyst for the future implementation in the in-situ upgrading and recovery of HCO.
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Characterization of Viscous Unstable Flow in Porous Media at Pilot Scale - Application to Heavy Oil Polymer Flooding
Authors S. Bouquet, S. Leray, F. Douarche and F. RoggeroSummaryThe hydrodynamic stability of polymer flooding is studied in a heavy oil context.
The consistency of mobility ratio as a criterion to refer and predict the flow stability/instability is studied through numerical high resolution simulations, on a 2D pilot-scale porous medium, for different viscosity ratios between the injected fluid and fluid-in-place. Several definitions of mobility ratio are calculated, and the predictive shock mobility ratio is inferior to 1 for observed stable flow behavior and vice-versa. Whenever the flow is unstable, fingers develop, grow and tend to merge linearly with respect to the injected pore volume. Additional scenarii are studied with polymer adsorption or degradation. The unstable behavior is also analyzed when coupling flow instability and heterogeneities. The linear fingers behavior, occurring in homogeneous medium, changes with heterogeneity: fingers in-situ dynamical behavior is non-linear when channeling occurs. The less the mobility reduction is (i.e. less stable flow), the more the flow behavior is sensitive to the heterogeneities. The polymer flooding remains more efficient than waterflooding even when strong channeling occurs. Eventually, we show the consequences on water and polymer breakthrough and draw some insights about the flow behavior of a polymer injection pilot in practical cases.
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Oil Recovery Potential for a Heavy Oil in Unconsolidated Sands Under Polymer Flood in the UKCS
Authors S. Law, E.J. MacKay and E. CastilloSummaryHeavy oil production on the United Kingdom Continental Shelf (UKCS) is set to increase with the new developments expected to come on-stream within ten years. It is estimated that 9 billion barrels of heavy oil resources are in-place. The next generation of fields have lower API in the range of 10–18°, with viscosities as high as 1,500cP, presenting significant technical challenges. Shallow Eocene sand reservoirs, such as Bressay and Bentley, are often unconsolidated, which results in significant potential for compaction if the reservoir voidage is not maintained. Initial work matched the Li et al. (2014) model performance and the main controls on reservoir compaction were identified as rock stiffness and rate of withdrawal with constant aquifer properties. The results suggest that without inclusion of the geomechanics model in both aquifer and polymer assisted recovery the oil recovery is underestimated for low values of reservoir stiffness. The overburden compacts the reservoir while oil is produced and the polymer decreases the mobility of water, thereby allowing the recovery of more oil. Therefore, we conclude that managed compaction should be actively used as a reservoir management tool for Eocene reservoirs in the UKCS in addition to the application of EOR technologies.
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Study of Nanoparticle Retention in Porous Media - A Perfect Sink Model
Authors E.R. Abdelfatah, K. Kang, M. Pournik, B. Shiau and J. HarwellSummaryPhysicochemical interaction between the nanoparticles and the pore walls can cause significant retention of nanoparticles. The objective of this paper is to study nanoparticles retention when there is no energy barrier between the nanoparticles and rock surface. In this case, the double layer repulsion doesn’t exist, that nanoparticles retention depends on the diffusion coefficient of the nanoparticles and the thickness of the DLVO layer that mainly contributed by van der Waals attractive force. Perfect sink model is adjusted to calculate the rate of deposition of nanoparticles. Deposited nanoparticles could be released from the surface by physical perturbations. The kinetics of mobilization was analyzed by torque balance applied on a nanoparticle adhered to a flat surface in a moving fluid. Surface roughness is an important parameter in initiating particle to release from rock surface by affecting the length of the torque arms. The critical velocity for release acting at the center of nanoparticle can be identified. Numerical model was used to compare the theoretically calculated rates to experimental data. The model can be used to determine the fate of nanoparticles in porous media under different conditions of temperature, ionic strength, concentration, and pH that suppress the double layer repulsion.
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Experimental Investigation of EOR by Injecting SiO2 Nanoparticles as Water Additive with Application to the Hebron Field
Authors H. Kim, D.J. Sivira, L.A. James and Y. ZhangSummaryThe use of silicon dioxide (SiO2) nanoparticles for enhanced oil recovery is novel, and is attractive because of the cost effectiveness, considering low concentrations required for enhanced oil recovery technique, and its surface-active properties for both interfacial tension reduction, and possible wettability alterations. Previous laboratory scale investigations have demonstrated a potential of SiO2 nanoparticles as water additive for enhanced oil recovery (EOR). In this study, the potential of injecting SiO2 nanoparticles as water additive is experimentally investigated for EOR application in Ben Nevis Formation from Hebron Field, offshore Newfoundland and Labrador, Canada. Only 30% of its crude oil in Ben Nevis Formation from Hebron Field is projected to be recoverable. Therefore, the investigation of EOR method requires attention now, since first oil is expected in 2017.
The experiments for this study are designed to be as realistic as possible. Unique from the previous laboratory investigations that used deionized water or simple synthetic brine as a medium to disperse nanoparticles, the SiO2 nanoparticles are dispersed in seawater obtained from Grand Banks, offshore Newfoundland, of which nanoparticles will be added to in the Hebron field. Interfacial tension, contact angle, and coreflooding experiments are conducted at Hebron field temperature and pressure (62 °C and 19.00 MPa). The results showed that the SiO2 nanofluids decrease interfacial tension and contact angle, indicating positive impact on the oil recovery. Preliminary coreflooding experiments are conducted using 0.01 and 0.03 wt% SiO2 nanofluid, with Berea standard cores, consisting of similar mineralogical composition as the lower facies of Ben Nevis Formation. The results show that 0.01 and 0.03 wt% SiO2 nanoflooding both increased additional recovery by 3.3% and 9.3%, respectively.
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Dynamic Screening for Microbial Enhanced Oil Recovery (MEOR)
Authors F. Kögler, N. Dopffel, E. Mahler and H. AlkanSummaryMicrobial Enhanced Oil Recovery (MEOR) is a cost-effective and environmentally friendly method for mature reservoirs, exploiting indigenous microorganisms that can be stimulated in the reservoir. As MEOR relies of the combination of various mechanisms a very well designed screening procedure is necessary for a successful field application.
In a MEOR project started 2011 by Wintershall and BASF, we established dynamic sandpacks to investigate microorganisms sampled from Wintershall fields. Requirement for the setups are strictly anaerobic and sterile conditions. Original fluids including oil, injection water and reservoir microbes are used together with different materials to create the porous media consisting of either glass beads, quartz sand or crushed reservoir rock in order to produce sandpacks with permeabilities ranging from 1 to 13 D. Analytics included petrophysical aspects(permeability, pososity, fluid saturations) as well as microbial methods (e.g. 16S sequencing). In more than 20 dynamic MEOR experiments we observed that the choice of the porous medium is crucial for dynamic screenings and affects both microbial growth as well as oil recovery. Our study contributes to the improvement of MEOR screening methods by conducting reliable dynamic experiments, which will help having more accurate predictions for MEOR field applications in the future.
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Nanoemulsion Enhanced Oil Recovery - From Theoretical Aspects to Coreflooding Simulation
Authors O. Uchenna, A. Amendola, G. Maddinelli, E. Braccalenti, A. Belloni, P. Albonico and M. BartosekSummaryThis work presents a theoretical discussion on nanoscale physico-chemical parameters affecting nanoemulsion flow in porous media and a bulk approach for modeling nanoemulsion enhanced oil recovery in coreflood experiments. Nanoemulsions are kinetically stable emulsions stabilized by surfactants with droplet sizes ranging from 20 to 500 nm and have the potential to deliver chemical agents depending on their application. For enhanced oil recovery (EOR), nanoemulsions have the potential to be more effective than the often used microemulsion because of their inherent ability to impart several theorized chemical EOR mechanisms. In particular, microemulsions differ from nanoemulsions since microemulsions are usually thermodynamically stable, while nanoemulsions are not: this implies that nanoemulsions should be quite indifferent to local physical (i.e., temperature) or chemical (i.e., composition) modifications. In addition, nanoemulsions are theoretically to be preferred to microemulsion due to their high surface area per unit volume and a general behavior that can be described through some feasible mechanisms. The first mechanism is the reduction of interfacial tension with the crude oil phase and rock, which facilitates mobilization of residual oil in the reservoir rocks. The second mechanism is the viscosity reduction of the crude oil phase due to the transport of nanoemulsion solvent into the crude oil phase. The third is the increased viscosity of the nanoemulsion fluid that improves the sweep efficiency of the nanoemulsion flood. Since current reservoir simulation software does not address nanoemulsion EOR modeling, the objective of this work is to theoretically show a way to incorporate the proposed mechanisms of nanoemulsion EOR into a robust reservoir model that can be used to history match nanoemulsion coreflooding results. Results show reasonable agreement with nanoemulsion core flood experiments. Although the approach is macro in nature, results indicate that it approximately models the transport of nanoemulsions in porous media for enhanced oil recovery. Modeling nanoemulsion EOR provides a framework to quantify recoverable oil. Quantifying these reserves is essential in the reservoir management of fields that are good candidates for nanoemulsion EOR.
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Polymer Injection Start-up in a Brown Field - Injection Performance Analysis and Subsurface Polymer Behavior Evaluation
Authors M. Spagnuolo, M. Sambiase, F. Masserano, V. Parasiliti Parracello, A. Lamberti and A. TianiSummaryA robust analysis of a polymer flooding inter-well pilot start-up in a brown oil field was performed. The objective was to analyze the polymer injection performance to verify the in-situ preservation of the injected viscosity, key condition for the expected EOR effect.
The adopted workflow focused on the integration of different analyses. Indeed, several phenomena may occur during polymer injection, such as complex injectivity behavior due to polymer non-Newtonian rheological nature, formation damage caused by particles adsorption, fractures opening, and mechanical degradation of the solute. Our injection performance analysis considered the following aspects: literature studies, polymer laboratory tests, shear stress through perforation evaluation, diagnostic plots, injectivity test interpretation, well test analysis, and fracturing investigation. Eventually, numerical simulations allowed us to integrate the different disciplines, thoroughly capturing the subsurface polymer behavior. Main conclusion is that injection under fracturing conditions occurred during pilot start-up. These small-scale fractures are localized in the near-wellbore zone and lead to a satisfactory well injectivity.
Furthermore, no evidence of mechanical degradation was detected.
The evaluation of the subsurface polymer behavior during an inter-well pilot is crucial to verify the correct polymer injection process. Robust reservoir monitoring is ongoing and preliminary promising effects are now being shown.
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Field Testing the Polysaccharide Schizophyllan - Single Well Test Design and Current Results
Authors D. Prasad, B. Ernst, G. Incera, B. Leonhardt, S. Reimann, E. Mahler and M. ZarflSummaryA bio-polymer pilot flood is ongoing in Bockstedt, a mature oilfield in northern Germany.
Bockstedt is a highly saline, moderately viscous, moderate temperature and darcy sandstone reservoir and is on waterflood since 1959.
Previous results of Schizophyllan properties in lab and field have been published by Leonhardt et. al. (SPE 169032) and Ogezi et. al. (SPE 169158). The polymer has shown very good injectivity and even though positive response was observed in a producer, no breakthrough of polymer has been observed so far in the producer. To understand this fact, multiple single well tests (SWT) have been conducted in the field by injecting, incubating and back-producing, to check the biopolymer performance especially in terms of mechanical/biological/chemical stability.
Single well tests were designed considering several factors. Based on ability to produce/inject from/into the well, representative condition like temperature, shear, microbes and ability to acquire production/injection log data, an injector well in the pilot block was selected. Additionally injection rates, biocide concentration/type were varied to check the mechanical/microbial stability. The injected and produced volume were designed in a way to minimize dilution and mechanical stressing of biopolymer. Progressive cavity pump was used to avoid shear in the wellbore during back-production.
A very extensive lab surveillance plan was set up to understand dilution of samples from wellbore/reservoir, mechanical and microbial degradation. Viscosity, microbial growth, chemical analyses and structural analyses of biopolymer conformation were performed on baseline injection samples and back produced samples at different times. Chemical tracers assisted in quantifying dilution of the injected polymer slug while back-producing. Special sampling procedures (e.g. anaerobic, sterile, high pressure sampling) were developed to ensure representative reservoir sample and its preservation in order to avoid incorrect conclusion.
This paper presents the lab and field initial test design, important learnings during testing and the main outcome of the multiple single well tests.
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Optimum Polymer-injection Strategy for the Polymer-flood-expansion Area of the Tambaredjo Field
Authors H. Salimi, R. Paidin, K. Moe Soe Let and K. BhoendieSummaryThe main objective of this study was to determine the optimum polymer-injection strategy for the Polymer-Flood Expansion area in the Sarah Maria South Area of the Tambaredjo Field through reservoir simulation. The performance of the performance of the polymer-flood pilot was used as a sanity check for the obtained optimum polymer-injection strategy.
The performance of the existing polymer-flood pilot area was examined. Polymer related properties were obtained using the polymer-flood pilot data.
The key points (well-pattern design and combination of oil strata) of polymer-flood designs for the polymer-flood expansion area of the Tambaredjo Field were discussed. A large number (> 400) of polymer-injection scenarios in terms of different polymer-injection concentrations, downhole injection pressures, numbers of new wells, and injection sequences (tapered, flared, and uniform injection) were performed using the previously obtained history-matched dynamic model. The simulation runs of these scenarios were elucidated in detail.
The review of the polymer-flood-pilot performance reveals that polymer injection increased the developed reserve by 17%. In the Tambaredjo field, the permeability, the temperature, the salinity, and the reservoir type (sandstone) are favorable for polymer injection. However, the oil viscosity and reservoir heterogeneity are not favorable for polymer injection.
It turned out that the ratio of sweep to injectivity plays a key role in determining the optimum polymer-injection strategy. The optimum well pattern turned out to be driven by the remaining oil, existing wells, and connectivity. For all the polymer-injection scenarios, there is no value (no incremental oil) to go above downhole pressure 850 psi to inject polymer. Flared scenarios for a given cumulative polymer injection, are better than the tapered and constant-injection-concentration scenarios in terms of incremental oil and displacement efficiency. From a technical point of view, the flared scenarios with low average polymer-injection concentrations and shorter time intervals are optimum.
No further activity forecasts an oil recovery of 18% until year 2034. For full-field implementation (i.e., 102 injection wells), water injection as a base line to the performance of polymer injection can lead to a recovery factor of 21.5% until year 2034. Finally, full-field polymer injection (102 injection wells, flared injection sequence with polymer-injection ranges from 0 to 3,000 ppm and one-year time interval and injection pressures of about 800 psi) can lead to a recovery factor of 25%. Therefore, the optimum polymer-injection strategy can potentially increase the developed reserve by 39%.
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CO2 Foam EOR Field Pilot - Pilot Design, Geologic and Reservoir Modeling, and Laboratory Investigations
Authors Z.P. Alcorn, S.B. Fredriksen, M. Sharma, M.A. Fernø and A. GraueSummaryA CO2 foam field pilot research program has been initiated to test and advance the technology of CO2 foam systems with mobility control to optimize CO2 integrated EOR and CO2 storage. Previous CO2 foam pilot tests have analyzed field scale displacement mechanisms, foam’s effects on gas mobility, reservoir injectivity, and overall recovery. Past tests have shown variable amounts of success, establishing the need for a more integrated methodology for advancing CO2 foam technology for EOR.
This work describes initial design, generation of geologic and dynamic reservoir models, laboratory investigations, and the application of a reservoir management workflow for a CO2 foam field pilot in the Permian Basin of west Texas, USA. Application of a reservoir management workflow guides a systematic approach from data gathering, model generation, and decision making to final implementation and analysis of the CO2 foam field pilots. Initial pilot design begins with an improved reservoir characterization, field pilot selection criteria, and laboratory studies. Laboratory work investigating foam’s behavior at variable pressures found that increased reservoir pressure will result in more favorable CO2 foam behavior as it will recover oil more effectively, considering the economic limits on CO2 and surfactant usage.
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Polymer Injectivity De-risking for West Salym ASP Pilot
Authors D. Wever, V. Karpan, G. Glasbergen, I. Koltsov, M. Shuster, Y. Volokitin, N. Gaillard and F. DaguerreSummaryIn the West Salym field, a mature waterflood is ongoing with increasing water cuts and declining oil production. To counter the decline a tertiary oil recovery technique called Alkaline-Surfactant-Polymer (ASP) flooding was selected. According to earlier studies the potential incremental oil recovery factor due to ASP injection is 15–20% of the ASP-targeted field STOIIP. An injection/production pilot to demonstrate the oil recovery potential of ASP technology and to obtain information for decisions on the subsequent commercial ASP projects was started in February 2016. ASP injection started in July 2016. The pilot area was developed with a 5-spot well pattern: 4 injectors connect to a single producer through the 15–20 m thick sandstone formation with permeabilities varying from 10 to 100 mD. Because of the short inter-well distance matrix conditions were required for the injection. This requirement in combination with the relatively low permeability of the reservoir rock resulted in the recognition that loss of injectivity is a major risk for the project.
This paper focuses on de-risking polymer injectivity for both the ASP and polymer chase injection. We discuss the selection of the polymer type, molecular weight and concentration, specification of the water quality and chemical preparation procedures that are all important to minimize the risk of injectivity decline. Additional experimental work that was performed to qualify filtration of the polymer solution using a very small filter sizes is described. During long term injection experiments in both representative outcrop and reservoir material continuous pressure increase indicating permeability loss was initially observed. In investigating possible causes and feasible mitigations for the loss of injectivity different scenarios were tested. Both pre-shearing the polymer, pre-filtering the solution and different ways of preparing were tried and resulted in better results. A step change was made when dissolving the polymer in higher pH solution resulting in filtration ratios close to 1 and good injectivity in representative core material. Furthermore, in close collaboration with the polymer vendor, ways were found to improve the polymer quality in the manufacturing process in order to meet our strict specifications. Finally the laboratory results and field observations during ASP and subsequent polymer chase injection will be presented.
The results of this work could be used to define the polymer specifications for ASP and polymer flooding in the reservoir with permeability range (from 10 to 100 mD) that is considered at the border of the typical screening criteria for the polymer application. Due to large amount of such reservoirs a successful mitigation for polymer injectivity could have significant impact on the application of polymer flood in the oil industry.
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Grimbeek -120 cp Oil in a Multilayer Heterogeneous Fluvial Reservoir. First Successful Application Polymer Flooding at YPF
Authors J.E. Juri, A. Ruiz, G. Pedersen, P. Pagliero, A. Limeres, C. Bernhardt, P. Vazquez, V. Eguia, F. Schein, V. Serrano, G. Villarroel, A. Tosi and S. KaminszczikSummaryVery low water effective permeability could explain the success of water flooding and polymer flooding into friable formation with viscous oil. This challenges the common assumption of poor performance because very adverse mobility ration. In this type of reservoirs, high permeability zones (above 8–10 Darcy) are not well characterised because they are often lost during coring or they are not suitable for coreflooding experiments. Then, the target resistance factor could be underestimated and polymer injection might not perform as expected. Multilayer fluvial reservoirs hinder vertical conformance and affect the efficiency of polymer flooding. Here we report the results of the ongoing polymer pilot. After injecting 0.3 pore volumes of polymer solution we recovered 10% ooip incremental oil above water flooding from the central pattern and 5% of the ooip from offset producers in contacted zone. The water cut reduced from 90% to 45% in the confined producer and from 87% to 67% in the offset producers. We calculated water flow velocities in the reservoir using three history matched simulation models constructed at different scales (full field, sector model coarse and fine) and we found that more than 90% of water velocities across the complete field are below 1ft/day [normally assumed reservoir water velocity for calculating the resistance factor in laboratory experiments]. We increased polymer concentration in 10 to 30% to ensure good mobility ration in the high permeability streaks possibly located in the channel bars. Simulation based analyses of the flows in the pilot zone strongly suggest that one of the key success factors was pattern confinement. There was no out flow of the central pattern. The very good performance in terms of low utility factor obtained so far [0.31 kg per incremental barrel of oil above water flooding] supports the hypothesis of the good confinement. This allows us to design a pattern rolling strategy for the polymer expansion that makes this technology economic for this low oil price context.
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Injectivity Experiences and its Surveillance in the West Salym ASP Pilot
SummaryASP or polymer flooding in reservoirs with permeabilities below 100 mD has not been often applied due to the perceived and/or potential issues related to the injection of viscous polymer solution under those conditions. Poor injectivities become an even bigger issue if injection under matrix conditions is required. This is usually the case for pilot projects with relatively short inter-well distances to optimize response time, project costs and pilot duration. One of the major problems that could lead to injectivity deterioration is plugging of the formation in the near wellbore due to trapping of polymer molecules in smaller pores and polymer adsorption. The higher injected fluid viscosity due to polymer also leads to higher injection pressures. The injection pressure should, however, not exceed the formation breakdown pressure if matrix conditions are required. A proper flood design should achieve the compromise between polymer molecular weight, its concentration, viscosity of injected solution and injection pressure, and should include appropriate plans to mitigate injectivity loss.
The paper describes the injectivity challenges experienced during water, ASP and subsequent polymer injection in the West Salym ASP pilot. The project is implemented in a sandstone reservoir with permeabilities in the range from 10 mD to 100 mD. Conventional waterflooding in West Salym is performed under fracturing conditions, hence it was recognized from the beginning that the injection of ASP and polymer solutions under matrix conditions in the pilot would be challenging. The paper provides the injectivity history for the pilot wells, describes the surveillance methods used, and provides details on the steps taken to improve the injectivity. New analysis approaches to effectively extract information contained in the real-time data that were developed for this project are also discussed.
Overall, this paper will provide the reader with hands-on experience in injection of ASP and polymer solutions in reservoirs with permeabilities below 100 mD.
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First Surfactant-Polymer EOR Injectivity Test in the Algyő Field, Hungary
SummaryIn the past decades, the primary efforts of R&D activity aimed at developing an efficient EOR method to increase the recovery factor at oil fields depleted with extensive water flooding. Surveying the potential options, a final decision was made to concentrate on chemical EOR using combined surfactant/polymer flooding at the largest Hungarian oil field. The target formation of the stacked multilayer hydrocarbon occurrence was a sandstone reservoir with 70 mD permeability on average and bearing low viscosity oil (0.64 cP at 98 °C and 190 bar).
This paper summarizes the workflow and set of experiments that were performed to allow a field injectivity test performed in 2013. The injected chemical solution contained a surfactant mixture developed by MOL and its Hungarian university partners and a sulfonated copolymer. The test started with the injection of 100 m3 of water followed by the chemical cocktail containing 15,000 ppm of surfactant and 1,000 ppm of polymer driven into the reservoir by an additional water volume of 100 m3. The project was precisely monitored measuring the well head pressure, flow rate and viscosity of injected fluids. Although the main criterion of successful job was obtaining good injectivity, other important factors like thermal stability of the surfactant-polymer solution under reservoir conditions was also evaluated by back-flow test. Among others, various laboratory measurements were performed to determine the polymer and surfactant concentration as well as the rheological and interfacial properties of back-flushed solutions in order also to calculate the possible loss of chemicals. In addition, the success of the pilot was also proved by the decreased water-cut and the change of quality of oil in the produced samples, which clearly indicated that the chemical solution mobilized the entrapped oil remaining after water flooding. The current plans and next steps will also be discussed at the end of the paper.
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Shift to Hydrogen - 100% Recovery from Depleted and Abandoned Gas Fields
Authors L. Surguchev, R. Berenblyum and M. SurguchevSummaryThe gas remaining in depleted and abandoned fields typically account to 20–30% of the initial volume in place. The proposed in situ hydrogen generation technology will allow converting the remaining methane reserves to hydrogen directly in situ. The reservoir is therefore converted into a ready to produce high pressure hydrogen storage cell.
Reservoir conditions experimental and numerical modelling was performed to validate in situ hydrogen generation process. Hydrogen can be produced from hydrocarbons in situ from a combination of steam reforming and enthodermic methane catalytic cracking reactions. State of the art thermal simulation tools were used to model the process at reservoir conditions.
A hydrogen generation process implemented at a medium size abandoned gas field will allow generating significant volume of hydrogen. In principal, converting just a few fields should cover annual world demand of hydrogen currently amounting to about 100 million tons per year.
Hydrocarbon processing and transportation stages on the surface are therefore abated.
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A New Method of Bidirectional Displacement to Enhance Oil Recovery in Fault-block Reservoirs at High Water Cut Stage
Authors K. Ma, H.Q. Jiang, J.J. Li, Y.H. Chang, L. Zhao, H.X. Yang and Q. YanSummaryThis paper focuses on the research of a new method to enhance oil recovery in fault-block reservoirs at high water cut stage. Through three-dimensional water flooding experimental analysis and Nuclear Magnetic Resonance (NMR) analysis, the distribution of remaining oil at high water cut stage in fault block reservoir is clarified from macro and micro aspect. Although the development of reservoirs has stepped into the ultra-high water cut stage, there still has a great potential for development with two kinds of remaining oil. One is located on the top of tectonic structures which is hardly swept by water flooding and the fault barrier increases the recovery difficulty of this kind. The other is the highly dispersive residual oil between wells.
The paper investigates the whole vertical structural position and presents a new development mode named bidirectional displacement to extract those two kinds of remaining oil: the top structure is for gas injection while the bottom is for water injection, thereby bidirectionally (upper and lower) compensating formation energy for oil displacement in the middle of the structure.
In the higher position, we adjust working system by injecting gas from old wells and then force the gas to migrate to the top to displace oil. During this process, a newly formed artificial gas cap is matched with reservoir scale and displaces oil by gas cap expansion energy when the reservoir pressure declines. At the bottom, we convert oil wells with high water cut into water injection wells with wide well spacing and large displacement to form the artificial edge water flood that can re-aggregate the dispersed remaining oil, achieving efficient development of remaining oil in fault-block reservoirs with bidirectional displacement.
In this paper, a typical geological model of fault-block reservoirs is built by numerical simulation, and the factors that influence the development effect are discussed by orthogonal experimental design. We obtain the influence of various development and geological factors on bidirectional displacement, optimize the working system at different developmental stages, establish a corresponding matching relationship between production and injection wells for stable development and form the screening criteria for bidirectional displacement.
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Application of Nanoparticles in Chemical EOR
Authors A.A. Ivanova, A.N. Cheremisin and M.Y. SpasennykhSummaryMore than 50% of origin oil in place are still trapped in reservoir after primary and secondary oil recovery. Thus, there is a need in tertiary recovery or enhancing oil recovery (EOR) methods, which include chemical flooding, steam injections etc. It is well known that chemical flooding is one of the most perspective and widely used method for enhancing oil recover. However, chemical species such as surfactants or polymers are very sensitive to high temperature, salinity and pH. Indeed, injecting alkaline solutions into wellbore aid in increase of brine solution salinity and pH, that may cause polymer destruction. This fact makes their use in oil recovery difficult. Replacing an alkaline solution with nanoparticles is a promising way of getting more stable surfactant and polymer solutions in typical reservoir conditions.
In the present work, we investigated the influence of adding nanoparticles to surfactant solutions for improving their properties. Due to amphiphilic properties, surfactants are using as lowering interfacial tension (IFT) agents between brine solution and oil. The problem with surfactants injection is the high adsorption of surfactant molecules on the rock surface. Usually, to avoid high adsorption, alkaline solutions are added, but in sandstone formations alkali may cause polymer destruction and in carbonate formations - precipitation of several unfavorable inorganic scales.
First, in this work, was shown that the addition of a low nanoparticles concentration to anionic (sodium alpha-olefine sulfonate) and cationic (erucyl bis(hydroxyethyl)methylammonium chloride) surfactants results in the decrease of IFT between solutions and oil. Then, the adsorption measurements were performed on brine solutions in a presents of different nanoparticles concentrations. The amount of adsorbed surfactants molecules decreases upon addition of nanoparticles, which is due to hydrophobic interaction between nanoparticles and molecules parts. Such reduction is almost the same with alkaline solution injection. However, a higher concertation of alkali is necessary to prevent a high adsorption on rock surface.
Thus, the addition of nanoparticles to surfactant solutions retains their responsibilities to reduce IFT and, in addition, decreases adsorbed amount of surfactant molecules. As a result, less surfactant and polymer will be needed to reach low IFT and high viscosity of brine solution.
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Supramolecular Assemblies as Displacement Fluids in EOR
SummaryThe concept is that the viscosity of injected supramolecular system will be maintained at initially low values for easy injection and pumping, and then increased by means of an external pH stimulus just before or upon contacting oil. Our promising lab-scale preliminary studies have indicated that such supramolecular systems possess not only reversible pH-responsive properties but also very tolerant against high salinities and temperatures.
Supramolecular solutions can adapt to the confining environment. For instance, when a height molecular weight polymer macromolecules are forced to flow into narrow channels and pores, molecular scission processes may take place.
Supramolecular solutions can have significant impact on the cases where thermal methods cannot be used for some viscous oils due to thin zones, permafrost conditions and environmental constraints. This project is primarily aimed at developing novel supramolecular assemblies with adjustable viscosity and interfacial properties that have robust tolerance against high temperatures and salinities. Such supramolecular assemblies will be used to significantly improve the feasibility and cost-effectiveness of displacement fluids used in EOR. Overall, there is a significant potential for application of supramolecular solutions in the US and throughout the world.
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Nanoemulsion Flooding - The Journey to Field Begins
Authors E. Braccalenti, L. Del Gaudio, P. Albonico, A. Belloni, M. Bartosek and E. RadaelliThe continuous and growing request of energy worldwide, together with the depletion of the oil and gas resources, lead to an increasing interest to develop and apply EOR techniques in order to improve the production of already exploited reservoirs. In this scenario, current chemical EOR technologies are not yet widely applied, mainly for the high costs associated and high volumes required. “New” technologies and renovated chemical approaches must be implemented in order to make the chemical EOR processes extensively used. Among them, Nanotechnology seems to have an extraordinary potential to change production processes.
Taking into account encouraging results recently achieved at laboratory scale using Nanoemulsions and aspiring to the field, the aim of this study was dual: on one hand render nanoemulsions cost effective and attractive for field applications, on the other hand, have a deeper understanding and knowledge of nanoemulsions mechanism of action and effect of on porous media.
The two goals have been pursued with an intense formulative work based on a particular “low energy” proprietary method and using both bulk fluid characterizations and core floodings. Particular attention has been reserved to effluents observation and characterization in order to reveal criticalities associated to the application of this technology.
A possible key role of the coexistence, in nanoemulsions, of small droplets size, surfactants mixture and solvent has been highlighted. In fact, these actors can favorably impact, in a synergic way, some critical parameters associated to oil recovery such as oil/water interfacial tension, wettability and oil viscosity. Surfactant adsorption/retention as well as rock/nanoemulsion interactions have been also evaluated.
The future applicability of nanoemulsion strongly depends on its costs that can be reduced decreasing the amount of surfactants and solvent present in the formulation. This surely has an impact on nanoemulsion intrinsic structure (i.e. average droplet size, surface area) but not necessarily on the efficiency of mobilization of residual oil in porous media. Furthermore, alternative injection approaches can induce additional savings.
The next phase foresees studies on injection strategies, the design of an up-scaled nanoemulsion production and nanoemulsion tuning on the basis of specific field parameters in order to render the technology suitable for a SWCTT.
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A Novel Optimization of SAGD to Enhance Oil Recovery - The Effects of Pressure Difference
More LessSummarySteam-Assisted Gravity Drainage (SAGD) provides many advantages compared to alternate thermal recovery methods for bitumen recovery. Nowadays, most of researchers believe that the gravity mechanism is the main drive in SAGD recovery, ignoring the injector-producer pressure difference, which makes the field prediction deviate from reality. To tackle this problem, this paper makes further investigation on the injector-producer pressure difference. A series of 2D numerical simulations are conducted on the basis of Mackay River reservoir in Canada to investigate on influence of injector-producer pressure difference. Meanwhile, a new mathematical model considering injector-producer pressure difference is established. The results indicate that when the injector-producer pressure difference exists, SAGD usually has better recovery. Pressure difference can effectively improve SAGD operating performance to achieve a high economic efficiency. More pressure difference doesn’t necessarily lead to better recovery, for when the pressure difference increases to some certain degrees, it will cause steam breakthrough. Pressure difference usually plays an important role at the beginning of SAGD recovery, therefore it is better for us to increase pressure difference at the steam rising stage and decrease pressure difference at the steam chamber expansion to avoid steam breakthrough, and finally to achieve a high economic efficiency.
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Laboratory Testing of Thermo-chemical Schemes for Carbonate Heavy Oil Reservoirs
Authors S. Ursegov and E. TaraskinSummaryThe objective of this work is the Permian - Carboniferous reservoir of the Usinsk field located in the Timan-Pechora province of Northwest European Russia. The oil-producing rocks are the naturally fractured limestones and dolomites. The live oil viscosity is equal to 1240 mPa*s. In the reservoir, there is a steam injection at ~300°C and ~10 MPa. The current oil recovery numbers are estimated between 8 – 10 %. These oil recovery efficiencies could be improved with the injection of suitable chemicals to increase the water wettability of the reservoir matrix. In order to justify a package of measures aimed to increase the reservoir oil recovery factor, special laboratory studies were carried out with the help of hot water and steam injection thrown the stacked models of full-sized and standard-sized core samples. In addition, the experiments of heavy oil extraction by hot water in combination with surfactants were conducted. This work summarizes the results obtained during the laboratory tests. The combined use of hot water and the NOP surfactant increases the oil recovery factor up to 38 %. However, the oil-wet characteristic of the reservoir rocks did not modified even upon their heating up to the temperatures of 100 – 2500C.
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Overcome Viscous Fingering Effect in Heavy Oil Reservoirs by an Optimized Smart Water Injection Scheme Part II
Authors T. Kadeethum, H.K. Sarma, B.B. Maini and C. JaruwattanasakulSummaryViscous fingering is a major obstacle to successful waterflooding in heavy oil reservoirs, as it results in premature water breakthrough resulting in bypassed oil and an underdeveloped oil bank ahead. To reduce viscous fingering, the composition of injected fluid needs to be tailored to create a favorable mobility ratio with the oil to be displaced. Smart waterflooding often entails wettability alteration in the reservoir, and it can also lead to a change in mobility ratio, which depending on the value, may have either a negative or positive impact on oil recovery.
This study is an extended study from Kadeethum et al. (2017a) because in that paper only one static realization was analyzed. This practice may lead to a bias and unreliable result because we did not include the uncertainties into the system. Therefore, a statistical analysis is used to reveal the smart waterflooding true potential. In this study, smart waterflooding outperforms conventional waterflooding regarding oil recovery, with incremental recovery reaching as high as five percent. Moreover, smart waterflooding also significantly decelerates the water cut (WCUT) trend by subduing the effect of viscous fingering and decreasing the water relative permeability.
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Sedimentary Characteristics and Architecture of Fan Delta Front Reservoir Based on Dense Well Pattern in Oilfield, China
More LessSummaryThe study focus on a Paleogene sandstone reservoir in the northeastern China deposited on a fan delta front, which started to produce since 1986. Through long term of steam huff-puff, the average reservoir pressure declines from 9.75Mpa to 2Mpa, the water cut increases to 90%. Therefore, a steam driving pilot with 417 wells is built, and the detailed sedimentary analysis and reservoir architecture characterization is urgently needed to better understand the distribution and connectivity of reservoir. The study is based on the analysis of 6 core data, 417 well logging data and several surveillance data, such as injection profile and tracer. The reservoir architecture in single well, plane and profile of main producing layers is depicted, the architecture modes is established with the analysis of connectivity and forming environment, the scale of different architecture elements is summarized, and the effect of architecture on reservoir performance is analyzed by using surveillance data for further development adjustment proposal.
There are 14 lithofacies identified in the study area, which can be classified into five architecture elements: underwater distributary channel, mouth bar, underwater distributary inter-channel sand, underwater distributary inter-channel mud and sheet sand. Three types of lateral architecture modes, five types of vertical architecture modes, and three types of plane combination modes of architecture elements are established, with detailed discussion of pattern, cross section, plane distribution, genetic mechanism and connectivity. The scale of distributary channel and mouth bar in different architecture modes is summarized and compared. Finally, further development adjustment plan is proposed according to the effect of architecture on reservoir performance, such as the producing layer with isolated banding distributary channels is suggested to perform stratified gas injection, the injection and producing well should be placed in layers with good connectivity, like sheet-shaped distributary channels etc.
The study provides a comprehensive case study for geologists and engineers to better understand the sedimentary characteristics and architecture of fan delta front reservoir, which help to provide fine-scaled geological model and adjust development plan for improving recovery.
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A Non-standard Model for Microbial Enhanced Oil Recovery Including the Oil-water Interfacial Area
Authors D. Landa-Marbán, F.A. Radu and J.M. NordbottenSummaryIn this work we present a non-standard model for microbial enhanced oil recovery including the oil-water interfacial area. Including the interfacial area in the model, we eliminate the hysteresis in the capillary pressure relationship. One of the characteristics that a surfactant should have, it is biological production at the oil-water interface. Therefore, we consider the production rate of surfactants not only as a function of the nutrient concentration, but also the interfacial area. To solve the model equations, we use an efficient and robust linearization scheme that considers a linear approximation of the capillary pressure gradient. A comprehensive, 1D implementation based on two-point flux approximation of the model is achieved. We consider different parameterizations for the interfacial tension and residual oil saturation reduction.
Illustrative numerical simulations are presented, where we study the spatial distribution and evolution in time of the average pressure, water saturation, interfacial area, capillary pressure, residual oil saturation and bacterial, nutrient and surfactant concentrations. Inclusion of the interfacial area in the model leads to different predictions of oil recovery. The model can also be used to design new experiments contributing to a better understanding and optimization of MEOR.
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EOR Screening and Potential Applications on the Norwegian Continental Shelf (NCS)
Authors J. Zuta and A. StavlandSummaryEnhanced oil recovery (EOR) projects have moved down the industry’s priority list given the present oversupply of world crude oil and resulting low oil prices. However, this is the right time for the industry to evaluate options for injecting new life into some of the brown fields on the Norwegian continental shelf (NCS). Inspite of the current market challenges, EOR application in offshore oil fields remains a promising option for increasing the oil production on the NCS. The size of the targeted offshore oil fields is generally large and their proven original oil in place (OOIP) can be sufficiently large to overcome the high cost required for re-development. This means that a large amount of oil remaining on the NCS could potentially be recovered using EOR processes.
In this work, the main objective was to screen some selected oil fields on NCS for possible EOR processes based on present-day reservoir data. The work was carried out in the National IOR Center based on published reservoir data on the selected fields. As a result, available reservoir information for the selected fields were limited. In addition, there were significant differences in the quality of field data supporting the viability of the various EOR processes considered. However, a fast evaluation of various EOR processes based on a simulation screening tool, SWORD proved to be very useful and assisted in providing an assessment of recovery strategies and EOR methods applicable for the selected fields.
The EOR processes screened included hydrocarbon gas, CO2, surfactant, polymer and a combined surfactant/polymer process. The screening criteria for the EOR processes were based on six quantitative reservoir data namely density and viscosity of reservoir oil, and properties such as depth, temperature, porosity and permeability of the formations. The applicability of the different EOR methods and recovery strategies at different reservoir properties and conditions were evaluated based on existing information published on the selected fields and knowledge collected from a suite of successful EOR projects around the world.
Results based on simulations indicate that the estimates of potential EOR incremental oil recovery compared to water flooding for the screened fields can be quite significant. However, key project development including realistic laboratory experiments and reservoir simulations needs to be performed to evaluate the EOR processes in detail. In addition, implementation and environmental issues, and additional cost elements must be weighed equally with oil recovery forecasts in any EOR ranking process.
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Bugs and Electric Fields - Underexplored IOR?
By J.N. RavnåsSummaryElectric and magnetic fields can influence microbial activity and could be used to control and improve the efficiency of microbial enhanced oil recovery. In addition, large electric and magnetic fields could be useful in improving operational efficiency by preventing undesired microbial processes in the petroleum industry. This paper reviews the literature from outside this industry to demonstrate that electric and magnetic fields can alter microbial activity. As expected very high fields deactivate or kill microbes but, perhaps unexpectedly, modest fields can actually increase their activity and also help to direct their movement.
Microbes may be affected by electric and magnetic fields in three ways: 1) Membrane permeabilization that can induce either inactivity or activity, 2) Cell orientation alteration, 3) Cell velocity changes.
Ways in which pulsed electric fields can be modified to influence microbial behaviour include: change field intensity, number of pulses, pulse width and pulse shape. The critical field when membrane permeabilization occurs seems to depend on cell size, orientation and type of cell wall.
This paper gives background material that, through research, may lead to future oil industry applications using electrical and magnetic fields to control microbial behaviour.
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Evaluation of Three Large Scale ASP Flooding Field Test
More LessSummaryScaling, emulsion breaking and high cost prevent ASP flooding going laboratory to field. When anti-scaling and produced fluid disposal challenges has been gradually solved in China after years of hard work, the sharp drop oil price makes prospect of ASP flooding dim again. However, ASP flooding is still very promising and has entered into commercial application in 2014 in Daqing. In 2015, the whole crude production from ASP flooding in Daqing was 3.509 million ton, 9.14% of the total production of Daqing oilfield (38.386 million ton). In 2016, there are more than 22 ASP flooding field projects active in Daqing, and the total ASP flooding oil production is 4.06 million ton, 11.11% of total oil production in Daqing. One of the three evaluated ASP flooding tests, ASP 1,2,3, is weak alkali (Na2CO3) based, the other two are both strong alkali (NaOH) based. These three tests shared four slug formulation, which is current standard practice in Daqing. Surfactants and polymers are all domestic. The total cost consists of construction investment, injected chemical fees (polymer, surfactant and alkali), operation fees including maintenance and repair fees, and water disposal fees. These costs are actual spending during ASP flooding tests. Though the ASP 1 and ASP 2 have the similar incremental oil recovery (30%) and both successful, the economic performances of weak alkali ASP flooding is much better for lower commuted total cost. Total cost of ASP 1 and ASP 2 is 28.2 $/bbl and 36.3 $/bbl respectively. The reservoir formation of ASP 1 and ASP 2 has many similarity, thus the difference can reflect alkali effects. ASP 3 has incremental oil recovery of 20.5% upon waterflooding, while it has much higher cost (49.5 $/bbl) than ASP 1 and ASP 2. This is attributed to the much higher polymer molecular and concentration injected, but less oil production. Though higher viscosity helps to overcome the severer heterogeneity as expected, it actually blocked the relative lower permeability formation. This tests shows that formation contamination is important issue to be considered. In high oil price era, the incremental oil recover can be regarded as core parameter since the cost increase can always be compensated by benefits of more oil, while in ultra-low oil price era, the balance between input and output is vital. Previous large scale ASP flooding field tests and current ASP flooding in practice shows that ASP flooding is still very promising even under such low oil price.
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Comparison of Scaling in Strong Alkali and Weak Alkali ASP Flooding Pilot Tests
Authors H. Guo, Y. Q. Li, Y. Zhu, F. Y. Wang, D. B. Kong and R. C. MaSummaryScaling was proven great challenge to prevent ASP flooding going from laboratory to field especially in low oil price era. Both strong alkali ASP flooding (SASP) and weak alkali ASP flooding(WASP) tests were compared from perspective of scaling to help understand ASP technique. ASP field tests in Daqing indicated that scaling(Na2CO3) due to strong alkali(NaOH)was much more severe than weak alkali, which reflected by more pump stuck, higher pump checking rate and short pump checking time.Scaling type in WASP was different from SASP and the percentage of silicate scale difference distinguished WASP from SASP scale. WASP scaling samples composition was mainly carbonate scale, while a majority of scale from SASP composition was carbonate and silicate, and the proportion of silicate varied with injection stages. Different from WASP, SASP scaling included scaling and formation damage, thus it had greater influence on oil production in SASP than WASP. Scaling mechanism was different between WASP and SASP. Compared with SASP, WASP supersaturation was much lower and this made it uneasy to form new mineral particle. PH value was crucial to scale type. Different ASP blocks proved similar scale type at the same PH value, and as PH value increased, silicate scale content decreased.
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Efficient Brownfield Optimization of a Reservoir in West Siberia
Authors O. Ushmaev, V. Babin, N. Glavnov, R.R. Yaubatyrov, D. Echeverria Ciaurri, M. Golitsyna, A. Pozdneev and A. SemenikhinSummaryIn this work we present a methodology for optimal management of brownfields that is illustrated on a real field. The approach does not depend on the particular reservoir flow simulator used although streamline-derived information is leveraged to accelerate the optimization. The method allows one to include (nonlinear) constraints (e.g., recovery factor larger than a given baseline value), which are very often challenging to address with optimization tools.
We rely on robust (derivative-free) optimization combined with the filter method for nonlinear constraints. It should be noted that the approach yields not only a feasible optimized solution but also a set of alternative infeasible solutions that could be considered in case the constraints can be relaxed. The whole procedure is accelerated using streamline-derived information. Performance in terms of wall-clock time can be improved further if distributed-computing resources are available (the method is amenable to parallel implementation).
The methodology is showcased using a real field in West Siberia where net present value (NPV) is maximized subject to a constraint for the recovery factor (RF). The optimization variables represent a discrete time series for well bottomhole pressure over a fraction of the production time frame. An increase in NPV of 7.9% is obtained with respect to an existing baseline. The optimization methods studied include local optimization algorithms (e.g., Generalized Pattern Search) and global search procedures (e.g., Particle Swarm Optimization). We provide solutions with different levels of approximation and computational efficiency. Without the acceleration achieved through streamline-derived information, the method, while effective, could be prohibitive in many practical scenarios. It is worthwhile noting that part of the solution determined in this work has been tested out on the real field.
Optimal management of brownfields is typically addressed using bottomhole pressure values or rates as well control variables. Well controls given as bottomhole pressure values, although not directly implementable in the real field, are often much easier to put into practice than if they are given as rates. However, optimization algorithms that deal with well rates as control variables can be in many cases computationally faster than methods based on bottomhole pressure values. In this work we combine the two aforementioned desirable features for the optimal management of mature fields: well controls are given as bottomhole pressure values for a more practical implementation, and these values are also determined efficiently using concepts borrowed from optimization via well rates.
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Integration of IOR Research Projects through Generic Case Studies
SummaryThe research project portfolio of The National IOR Centre of Norway includes core scale, mineral-fluid reactions at micron-/nano-scale, pore scale, upscaling and environmental impact, tracer technology, reservoir simulation tools and field scale evaluation and history matching. The complexity of each subtopic and the fact that a multitude of data, scales and disciplines is involved may be an obstacle in proper integration of the research results. For the same reasons, exploiting synergies between the various IOR research projects may be a difficult task. At the same time, a collaborative setup like The National IOR Centre of Norway should enable integrated case studies across scales and disciplines.
In this paper, we investigate the relationships between the different IOR research projects within The National IOR Centre of Norway. An important objective of the presented work is to facilitate integration and motivate research that falls between the typical disciplines and projects involved in an IOR case study. To make the relationships between projects more evident, the projects are described in terms of input and output related to testing, measuring, simulating, monitoring, predicting, and optimizing fluid flow in a reservoir. The ultimate goal of the integrated IOR research is to provide a framework for monitoring, evaluating and understanding the effects of an IOR method tested in a field pilot. The presented work links simulation and history matching of fluid flow, geomechanics and geochemical effects to lab measurements, pore scale and core scale modeling, tracer characteristics, production data and 4D seismic.
As part of the process, two generic case studies are defined, one for a chalk reservoir and one for a sandstone reservoir. The reservoir characteristics are chosen to be representative for fields on the Norwegian Continental Shelf. Two selected IOR methods are discussed; smart water injection and polymer injection.
The paper is a result of a collaborative effort involving researchers from both academia, research institutions and the oil industry.
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Economic Analysis of Profitability Index and Development Cost Based on Improved Oil Recovery (IOR) Projects in Indonesia
SummaryIn early 2016, the oil price has fallen to its lowest level (31.68 US$/bbl) over the last 11 years. Since then, Improved Oil Recovery (IOR) Projects are no longer quite interesting economically for contractors due to the high cost of development.
Until August 2016, there were 407 Field Development Plans approved by the Government of Indonesia and 26 of them are already using IOR methods (waterflood and steamflood). In Indonesia, these methods have been applied in Sumatera and Kalimantan. Currently, the biggest oil recovery is employing the steamflood of the IOR methods, which is operated by Chevron Pacific Indonesia in Sumatera Island since 1981 and it has contributed approximately 40% of the total oil production in Indonesia.
In countries that adopt Production Sharing Contract Fiscal Regime such as Indonesia, there are a number of terms and conditions specifically intended for IOR Projects. To attract and help contractors, they will be given an investment credit and/or interest of cost recovery so that the IOR projects can be developed more economically. Moreover, there are some tools which these contractors may use to improve the economical nature of their projects, such as DMO Holiday, Depreciation Acceleration, Shared First Tranche Petroleum, Split Changes, and many more.
For the purpose of this paper, the geographical areas of Indonesia were divided into 3 different IOR areas (North Sumatera, South Sumatera, Kalimantan). Then, collect the data of the 26 IOR Projects and afterwards the Profitabilty Index and Development Cost were calculated and distributed to those aforementioned areas.
Based on analysis, the results shows that the lowest profitability index is equal to 1.04 while the highest one is 2.28 equal to, meaning that these projects generate positive revenue to the contractors (PI value by > 1). The average development cost of IOR projects in Indonesia is equal to 34.64 US$/bbl, which remain lower than the current oil price. Based on the obtained Profitablity Index and Development Cost above, it can be concluded that the Indonesian IOR Projects are economically acceptable.
Finally, it is expected that this paper will provide contractors with a quick look at the growth of IOR Projects in Indonesia, especially in terms of the analyses of the economical nature required in Indonesia. Moreover, this paper is expected to provide an insight into the flexibility of PSC fiscal regime that can be used to support the economical nature of the IOR projects executed by contractors.
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Wettability Alteration and Interactions between Silicon Dioxide (SiO2) Nanoparticles and Reservoir Minerals in Standard Cores Mimicking Hebron Field Conditions for Enhanced Oil Recovery
Authors D. Sivira Ortega, H. Kim and L. JamesSummaryEconomically suitable innovative techniques are becoming a main objective in the oil and gas industry. SiO2 nanoparticle as a water additive for enhanced oil recovery (EOR) has been gaining grounds during the last few years because of its favourable results at laboratory scale; however, application at field is still unknown. A goal of injecting nanofluids is to promote fluid-rock interaction; therefore, determining the level of interaction between the two is a key factor. This research aimed to study interaction between the 0.01, 0.03, and 0.05 wt% SiO2 nanofluids and standard cores through contact angle experiments; scanning electron microscopy (SEM); mineral liberation analysis (MLA); and inductively coupled plasma optical emission spectroscopy (ICP-OES), to predict EOR mechanisms using SiO2 nanofluids in Hebron field. Hebron field is one of the major developments in offshore Newfoundland and Labrador, Canada, with an estimation of 2620 million barrels of oil in place, and an objective to achieve first oil in 2017. Berea and Bandera standard cores were selected to represent the mineralogical compositions of Ben Nevis Formation, which is the most important reservoir with approximately 80% of the Hebron’s crude oil. The SiO2 nanoparticles were dispersed in seawater from offshore Newfoundland, and the oil used was from offshore Newfoundland. The contact angle measurements at Hebron Field temperature and pressure (62 °C and 19.00 MPa) showed that the maximum decrease occurred after 6 hours of aging the core plug in nanofluids at 62 °C. Berea core presented a decrease from 51.4° to 30.2°, and in the case of Bandera rock was from 76.7° to 29.6°. SEM images and MLA revealed the higher the SiO2 nanoparticle concentration, the more nanoparticle adsorption on the rock surfaces after aging in nanofluids. These results are complemented by ICP-OES analysis on the nanofluids, since SiO2 nanoparticle concentrations in the nanofluids decreased after aging. The wettability alteration observed may be caused by the nanoparticles adsorption and interaction of the nanoparticle with the rock surface.
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Cost-effective Seawater Pre-treatment for EOR Development
Authors B. Dørum and A.A. MuminovaSummaryEOR requires specifically treated seawater adjusted with suitable ionic composition for the injection into the reservoir. Field experience shows that pretreatment constitutes cause significant concern at high volume rates during injection. High algae and silt concentrations in feed seawater cause rapid fouling of membranes. Seawater prefiltration imposes challenge due to heavy weight and expensive maintenance. The present study covers historical observations of ocean warming and important mechanisms of membrane fouling due to algal blooming. A modeling data is extracted with Marine Research Institute of Norway. Ecological and hydrodynamic models of Intergovernmental Panel on Climate Change (IPCC) scenario were used to investigate the effects of climate change on the marine ecosystem of the North Sea. Results indicate increasing phytoplankton and temperature trends.
The solution to remove particles and algae is to install parallel pretreatment system, switching between such units to allow frequent cleaning of some while the parallel units are active. This research includes an estimation of acceptable cost and weight values for the pre-filtration system.
Complex knowledge about phytoplankton and silt concentrations fluctuations must be applied towards development of technically and economically efficient solution for seawater filtration in large volumes.
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Enhance Microscopic Sweep Efficiency by Smart Water in Tight and Very Tight Oil Reservoirs Part II
Authors T. Kadeethum, H.K. Sarma, B.B. Maini and C. JaruwattanasakulSummaryImprovement of oil recovery in smart water injection schemes has been shown to be affected by wettability alteration. This process reduces residual oil saturation, which in turn affects the microscopic sweep efficiency and leads to subsequent enhancement of overall waterflood performance ( Willhite, 1986 ). Tight oil reservoirs are often associated with high clay content and significant cation exchange capacity (CEC) values ( Breeuwsma et al., 1986 ). CEC directly influences smart waterflood behavior as it controls ion exchangeability between the solid and aqueous phases, which in turn, regulates the double layer thickness and the wettability of the system ( Nasralla and Nasr-El-Din, 2014 ).
This paper is an extended study from Kadeethum et al. (2017a) in which only one static realization was analyzed. This practice may lead to a bias and unreliable result because we did not include the uncertainties into the system. Therefore, statistical analysis is used to reveal the smart waterflooding’s true potential. Furthermore, an “estimated effect” method is utilized to identify heterogeneity and CEC value effect. Smart waterflooding outperforms conventional waterflooding in both tight and very tight oil reservoirs in terms of oil recovery. Moreover, smart waterflooding also significantly decelerates the water cut (WCUT) trend by subduing the water relative permeability.
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Impact of Salinity and Water Ions on Surface Charge Alteration in Arab D Reservoir Cores at Elevated Temperatures
Authors S.C. Ayirala, S.H. Saleh, S.M. Enezi and A.A. YousefSummarySmartWater flooding through tailoring of injection water salinity and ionic composition is becoming an attractive proposition for improved oil recovery in carbonate reservoirs. Most of the recent studies suggest that surface charge change induced by lower salinity and certain water ions on carbonate surfaces is the main mechanism responsible for favorable wettability alteration, and consequently, higher oil recovery in SmartWater flooding. Unfortunately, these studies determined surface charges based on the electrophoretic mobility (EPM) measurement technique using powdered crushed core samples, which may not reflect the natural conditions existing in the subsurface reservoirs. In this study we used a state-of-the-art experimental technique based on streaming potential measurements to determine surface charge in intact Arab-D reservoir core samples saturated with different brine salinities and individual ion compositions. We also believe that this is the first time such a measurement technique has been used to measure surface charges in reservoir cores at elevated temperatures.
The results indicated a favorable effect of sulfate ions in Arab-D rocks to alter the surface charge to more negative and the reactivity of these ions increased significantly by almost one order of magnitude at higher temperatures. Such a surface charge alteration to an extreme negative obtained upon exposure to injection waters containing sulfates would release the oil droplets from the carbonate surface. Among the positive ions, calcium showed the highest reactivity to shift the surface charge to slightly positive. Both magnesium and sodium ions showed almost similar behavior to change the surface charge toward less negative. In addition, only minor to moderate changes in surface charge were observed with the positive ions when the temperature is increased. The dynamic time-dependent effects on surface charge measured during the displacement of seawater by SmartWater (10 times diluted seawater) in reservoir cores showed an immediate shift in the surface charge from positive to negative. This instantaneous change observed in the surface charge confirms the beneficial effect of SmartWater on wettability alteration. All of these novel findings from this study will provide several major fundamental insights to better understand the dynamic role of surface charge alteration mechanism on oil recovery in SmartWater flooding.
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Laboratory Investigation of Low Salinity Waterflooding using Carbonate Reservoir Rock Samples
Authors T. Uetani, K. Takabayashi, H. Kaido and H. YonebayashiSummaryA laboratory study was performed to evaluate the possibility of performing a low salinity waterflood in an offshore carbonate reservoir using its rock and fluid samples. A series of spontaneous imbibition and core flood tests were conducted and both tests confirmed the incremental oil recoveries when the composition of the injection brine was diluted and modified.
During the core preparation stage, three uncertainties were identified; the core cleaning procedure, the aging time and the reservoir heterogeneity. First, a core is conventionally cleaned with polar solvents. However, a new core cleaning procedure called the “mild cleaning” has been proposed by Austad, which recommends the use of non-polar solvents. In our laboratory studies, the similar core samples were cleaned by the two different techniques and subsequently the spontaneous imbibition test results were compared. It was found that the low salinity effect was confirmed regardless of the core cleaning procedure. Second, the wettability distribution is not clear in this field. To account for this, the core aging time was varied from eight weeks (more oil-wet) to no-aging (more water-wet). The similar cores were aged for different time and subsequently the spontaneous imbibition test results were compared. It was found that the low salinity effect was confirmed regardless of the aging time, although the core samples with longer aging time showed lower oil recoveries. And third, since the reservoir is heterogeneous, the above sensitivity investigations covered a wide range of rock types within the production intervals. It was found that all rock types showed the low salinity effect.
In addition to the above investigations, a number of water recipes were tested. It was found that the sea water performed better than the formation water, while the diluted sea water performed better than the sea water. The effect of sulfate ions was also investigated. Some core plugs showed the low salinity effect when the concentration of the sulfate ion was spiked, while other core plugs did not respond. The effect of sulfate ions therefore, needs to be further investigated in this field.
Based on the results from the zeta-potential and the contact angle measurements, the low salinity effect in this reservoir was considered to be due to a change in the surface-charge and the wettability, which is consistent with the mechanism proposed by Austad. The conclusion of this laboratory study highlighted the possibility of applying the low salinity waterflood in this field.
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Streaming Potential Measurement to Quantify Wetting State of Rocks for Water Based EOR, In-house Novel Setup Experience
Authors M. Rahbar, A. Jafarlou, M. Nejadali, S. Esmaeili, H. Pahlavanzadeh and S. AyatollahiSummaryThe wetting condition of the reservoir rock is the key to the success of any EOR technique and the ultimate oil recovery. Wettability is dictated by the surface chemistry related to the interactions between the fluids and the rock surface which determines the stability of the water film between the rock and the oil phase. Streaming potential measurement is one of the electrokinetic techniques used to determine the average zeta potential of porous rock which can provide reliable information on fluid-rock interaction and wettability state of the rock surface. Streaming potential measurement has recently been introduced in the oil reservoirs applications and there are still significant uncertainties during the measurements and interpretation of streaming potential results. The primary purpose of this work was to establish a setup to measure the streaming potential of porous media and evaluate voltage measurements that could be used at different conditions. Moreover, according to significant differences of reported zeta potential (depending on measurement methods, measurement conditions and nature of minerals), comprehensive investigations were performed on zeta potential measurements of carbonate samples adjacent to the potential determining ions-PDI by streaming potential technique. Streaming potential coupling coefficients have been measured for 60 samples of calcite and quartz sandpack in adjacent to the fluid with different concentration of PDI and in the pH range of 1.5 to 11. The next step was to develop an understanding of the behavior of coupling coefficient under condition of brine salinity and pH to determine the rock fluid interactions and wettability alteration mechanism. To achieve this goal, the measured streaming potential and zeta potential of each test was compared to the results of adhesion test as experimental measurement of wettability and analysis of equilibrium solution. The experimental setup proposed in this study permits accurate measurements of streaming potential without any effect of polarization. The paired-stabilization and the pressure-ramping methods validate the voltage measurements obtained from the setup. The results showed that the wettability is directly and quantitatively affected by streaming potential measurements and the electrical properties interpreted from these measurements can predict wettability alteration mechanisms such as double layer expansion and ion exchange for various fluids. In addition, an accurate empirical expression is proposed for the measured coupling coefficients which predict streaming potential coupling coefficients and zeta potential of quartz sample in the salinity range from 0.0001 M to 5.5 M of NaCl.
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The Influence of Crude Oil Flooding and Ageing on Carbonate Core Wettability During Core Restoration
Authors P.A. Hopkins, K. Walrond, I. Omland, S. Strand, T. Puntervold and T. AustadSummaryInjection of a Smart Water, with a modified and optimized ionic composition, is an environmentally friendly and cheap EOR method. To be able to optimize the ionic composition to cause wettability alteration in the reservoir, one must understand the initial wetting of the reservoir. Experimental studies have confirmed that acidic material in the crude oil, especially negatively charged carboxylates, R-COO-, are the most important wetting parameters towards positively charged carbonate surfaces that dictate the rock wettability. The carboxylate molecules bond strongly to the carbonate surface and these crude oil anchor molecules can only be removed from the calcite surface by chemical reactions. Generating representative core wettability during core restoration in the laboratory is important for doing realistic oil recovery studies, capillary pressure and relative permeability measurements.
Very water-wet outcrop chalk cores showing good reproducibility were used to study adsorption of carboxylic material onto chalk. Crude oil with a known acid number (AN) was flooded through water-wet chalk cores with 10 % water saturation. The AN of the eluted oil was measured and the amount of adsorbed acidic organic material was determined. It is a general assumption that aging of a core is a requirement to generate a mixed-wet core. Therefore the wettabilities of aged and non-aged cores were determined and compared by spontaneous imbibition and chromatographic wettability tests. The results of this study first and foremost showed that both the aged and non-aged core behaved mixed-wet, thus aging is not a requirement to generate a mixed-wet core. The two parallel cores adsorbed similar amounts of acidic material, and the chromatographic wettability test results showed similar water-wet surface area in both the aged and non-aged cores. However, since spontaneous imbibition is very sensitive to the location of the oil-wet surface, a difference in capillary forces between the aged and non-aged cores was observed. The non-aged core behaved mixed-wet in a spontaneous imbibition test, while the aged core behaved slightly less water-wet than the non-aged core. It seems that during the aging process the oil components were distributed in such a way to influence the capillary forces to some degree. To conclude, aging is not necessary to change the wettability of an initially water-wet core that has been flooded with crude oil. The acidic polar oil components attach to the carbonate surface immediately upon contact, resulting in a mixed-wet system.
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Interaction of Ionic Species with Calcite and Oil Components in Waterflooding - Theoretical Study
Authors A. O. Alghamdi, M.B. Alotaibi and A.A. YousefSummaryDensity functional theory (DFT) trends in Gibbs free energies and enthalpies were thoroughly studied in calcite. Different coordination was applied for ionic species that exist in seawater and smartwater as well as for carboxylic acids presented in crude oil at distinct two primary hydration sites: >CO3H, >CaOH. The studied hydration sites were proposed based on electro-kinetics besides surface titration experimental studies.17, 18 Interfacial energy runs using the Gaussian 09 suits of program21, with Becke’s three parameter exchange and Lee Yang Parr corrected correlation functional (B3LYP) and 3-21G basis set, based on previous surface sites were performed to account for stability, reactivity and wettability alteration. The calculations predict the most stable complexes for calcite are, CO3H, CaO-, CO3Ca, CO3Mg , CaCO3-, CaHCO , CaH2O+ and CaSO4-. We also demonstrate that free ion species are having a higher free energy in seawater than in case of a complex and thus indicates a more reactivity of complex species to interact with rock sites. Furthermore, corresponding values of free energy and enthalpy change of ions association with calcite surface provided insights about complexes that are most favorable at the surface. This study proposes a mathematical correlation between thermochemistry profiles and wettability alteration, which expresses to us how the surface affinity for a certain organic compound compares with its affinity for water. The calculations agrees with previous experiment findings especially in case of Ca+2, Mg+2, SO4-2,MgOH+1 ,OH-1, and NaCl. Some reversed trend can be explained by the smaller size of the basis set used in the calculations. The results of this insights help in understating the interaction mechanism of this unique systems in order to modify reactivity for enhancing oil recovery (EOR) purposes, and to use the outcomes of this study to pose questions and directions for continuing theoretical efforts destined at linking macroscopic reactivity in case of altering wettability with molecular-level understanding.
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Impact of Anhydrite on the Low Salinity EOR Effect in Sandstone Material with High Clay Content
Authors I. Piñerez Torrijos, M. Risanger, T. Puntervold, S. Strand and T. AustadSummaryAt low oil price, using expensive chemicals in EOR methods is not economically feasible. Injecting water of a tailored composition, i. e. Smart Water, is thus a better option. It has previously been shown that injecting a brine of low salinity (LS), very often results in an increased oil production. In laboratory experiments it has been found that an “in situ” induced pH increase is a key parameter to experiencing a LS EOR effect in sandstones. In a field situation, e.g. Endicott, this pH increase is rarely observed, due to pH buffering by fluids, minerals and sour gases. When a LS injection brine is introduced into a core containing crude oil and high salinity (HS) formation water, desorption of cations from the mineral surface, and a subsequent adsorption of protons, H+, leaves OH−, which increases pH. At high OH− concentrations, the acidic and basic polar organic molecules attached to the mineral surface transform into species of lower affinity to the mineral surface, and are released, leading to increased oil recovery. However, the different minerals present in sandstone can influence the induced pH increase. A pH screening test has been developed to investigate the minerals’ influence on pH. Clays are the main wetting materials in sandstone rocks, and they are also known to be cation exchangers, which can influence pH in the system. Feldspars have also been shown to influence pH in both a positive and a negative way, the latter responsible for the poor LS effect in the Snorre field on the NCS.
A mineral often present in reservoir rock, but usually ignored, is anhydrite, CaSO4. In this paper the LS EOR potential in reservoir sandstone containing anhydrite and significant clay content was tested. Because of the amount of clays, this reservoir should be a good candidate for LS injection. The LS EOR potential was investigated using the pH screening test, oil recovery tests and chemical analyses.
The main results from this study showed that reservoir core material containing anhydrite experienced poor LS EOR effects. When LS brine is injected into a reservoir containing anhydrite, some of the anhydrite dissolves and prevents parts of the cation desorption from the clay surface, thereby lowering the pH increase needed to observe increased oil recovery. Based on this study, other minerals than clays, such as anhydrite, can have a serious influence on the reservoir LS EOR potential, and should not be overlooked.
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Application of Low Salinity Water to Improve Oil Recovery from A Fractured Tight Carbonate Reservoir - A Case Study
Authors A. Emadi, J. Guitián, T. Worku, C. Cornwall, B. Shubber and E. EscobarSummaryCarbonate reservoirs are estimated to contain around half of the total oil and gas reserves in the world. Exploitation of these reservoirs is specifically challenging and their recovery factor is generally lower than clastic reservoirs, due to their structural complexity, local heterogeneities, fracture porosity and the oil-wet-nature of the carbonate rocks.
The principle objective of this study was to investigate through laboratory experimentation, the feasibility of improving oil recovery from a fractured tight carbonate reservoir by spontaneous and forced imbibition of a compatible low salinity water (LSW), with and without a surfactant. To facilitate this objective, core material and reservoir crude oil from an active field were combined with reservoir temperature and wettability restoration, in a series of complementary tests, supported by compelling photographic images. Wettability screening of the restored core samples confirmed an oil-wet system with small tendency for water imbibition, which is typical behavior of such low permeability carbonates. In spontaneous imbibition tests, the samples were exposed to resident formation brine, followed by a LSW (2253ppm), with and without surfactant. The start point for the two-stage imbibition sequence was a residual oil saturation (~ 32%PV), which was representative of the target reservoir, established by centrifuge displacement. Exposure to the formation brine resulted in no additional recovery. In contrast the LSW prompted a reduction in the residual oil saturation of 20.47% (9%OOIP). With the addition of a surfactant to the LSW, there was an apparent improvement in the effectiveness of the displacement process, which lowered the residual oil saturation by 27.02% (13.14%OOIP).
To assess the benefits of forced imbibition of the LSW, a combined “soak-and-drive” sequence was deployed. For a core sample with a restored wettability and an established residual oil saturation of ~ 32% PV, the sequencing almost doubled the additional oil production when compared with spontaneous imbibition tests using the same fluid.
Wettability modification has often been cited as a possible mechanism for the success of LSW, particularly in clastic lithologies. An alternative mechanism for improving oil production has recently been introduced in the technical literature, described as an osmosis like phenomenon. This paper explores the possibility of this type of oil displacement in the context of a carbonate reservoir, with the movement of the LSW from the fracture network into the matrix blocks. The data generated by the experimentation, coupled with the progressive series of photographic images, are presented to give credence to the suggested mechanism.
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Pore-scale Visualization of Oil Recovery by Viscoelastic Flow Instabilities during Polymer EOR
Authors A. Rock, R.E. Hincapie, J. Wegner, H. Födisch and L. GanzerSummaryThis paper provides a new understanding of pore-scale polymer displacement processes, namely an additional oil recovery due to elastic turbulence. Using the potential of state-of-the-art GSG micromodels enables to conduct high-quality streamline visualization which is the key to an improved polymer EOR screening. Thereby enables to understand which properties of viscoelastic solutions contribute to oil mobilization. Moreover, this analysis can be used to optimized subsequently the fluid characteristics in order to achieve a higher recovery.
Single and two-phase polymer EOR experiments were conducted in Glass-Silicon-Glass (GSG) micromodels that resemble porous media. The objective of this work is to investigate the additional oil mobilization associated to viscoelastic flow instabilities encountered during polymer flooding at pore-scale. To set a benchmark for non-viscoelastic flooding processes, polystyrene oxide experiments are presented as well.
Experimental workflow consists of three steps: 1) Saturation of micromodel with a synthetic oil (10% silicon oil / 90% decane) with a viscosity of 25 mPas, 2) Displacement of synthetic oil by an aqueous polystyrene oxide solutions and 3) Displacement of remaining oil by a viscoelastic polymer solutions. All aqueous solutions are dissolved in a 4 g/l TDS brine. Additionally, viscosity of the polymer and polystyrene oxide solution are approximately matched. Furthermore, tracer particles are attached to the aqueous phase to enable high-quality streamline visualization using a high-speed camera mounted on an epi-fluorescence microscope.
Here we show that viscoelastic flow instabilities are highly caused and influenced by fluid properties. It is also shown flow instabilities dependence on pore space geometry and Darcy’s velocity. Streamlines and pressure differential evaluations revealed a dependency of elastic turbulence on solutions’ mechanical degradation/pre-shearing conditions, polymer concentration and solvent salinity. Furthermore, two-phase flood experiments in complex pore-scale geometries have preliminary confirmed that elastic induced flow inconsistency provides a mechanism capable of increasing oil phase recovery by the viscoelastic aqueous phase. Thereby, a polymer flood under elastic turbulence caused 20% additional oil recovery, whereas a polymer flood under laminar flow conditions enhances the recovery by only 5%. Due to high-resolution particle tracing in the micromodels, the main causes of enhanced recovery can be described as: (1) vortices, (2) crossing streamlines, especially near grain surfaces and (3) steadily changing flow directions of streamlines. Thus by adding viscoelastic additives to injection fluids and considering a sufficient shear rate, even a low reynold numbers are able to further enhance the displacement process in porous media by its elastic instabilities.
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Modelling of normal net stress effect on two-phase relative permeability and capillary pressure of rough-walled fracture
Authors A.Y. Rozhko, O.P. Wennberg and S. JonoudSummaryFluid-flow in fractured reservoirs is highly sensitive to the change of effective stress during fluid injection or production. Permeability, capillary pressure and relative permeability of rock fractures to oil and water directly impact the amount of hydrocarbons that can be ultimately recovered; however, these parameters are difficult to measure in the lab as a function of effective stress. This stimulates development of computational algorithms to predict the impact of stress changes on two-phase fluid-flow properties of fractures at depth.
In this work, we developed a numerical approach for determining relationships between normal effective stress, elastic rock properties, fracture aperture distribution, aspect ratio scaling, oil/water interfacial tension, contact angle and two-phase fluid-flow characteristics of rough-walled fractures. We extended a well-established approach developed for modeling of single-phase fluid-flow in rough-walled fractures. According to this approach, the aperture distribution is replaced by a network of elliptical cavities forming connected pathway from the inlet to the outlet. The extension towards two-phase flow is based on our previous analytical model, in which a two-phase fluid-flow is calculated in a deformable elliptical cavity.
The numerical algorithm developed in this work allows quick computation of the impact of the stress-change on two-phase fluid-flow properties of fractured rock. Relative permeabilities of fractures are shown to be non-linear functions of water saturation dependent on the effective normal stress. The capillary pressure-saturation curve for rough-walled fracture is shown to be a function of the effective normal stress. The dependency of fracture permeability, fracture porosity and surface area of open/closed fracture on the effective normal stress is also predicted by the model, which can be used as input parameters for reservoir simulators.
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Associative Polymers as Enhanced Oil Recovery Agents in Oil-wet Formations - A Laboratory Approach
Authors R. Askarinezhad, D.G. Hatzignatiou and A. StavlandSummaryAssociative polymers recently tested for their EOR potential in water-wet systems displayed a good potential for reducing residual oil saturation in polymer-flooded cores. In this work, an oil-wet porous medium was used to investigate these observations. A low molecular weight associative polymer was tested as a displacing agent and its ability to increase oil recovery on chemically treated oil-wet Berea cores was evaluated. Linear coreflood experiments were performed using filtered associative polymer solution as the EOR agent at standard pressure and 60°C temperature.
Results from the polymer floods conducted at an established waterflood residual oil saturation (Sorw) yielded increased oil recoveries, i.e., reduced residual oil saturations, Sor, in the formation. The observed incremental oil production was a function of the injected associative polymer treatment volume; Sor decreased with increased injected associative polymer volume. It should be noted that at laboratory conditions it is often hard to establish and also distinguish a 100% water-cut; in other words, true residual oil saturation, Sorw, is often difficult to be established during water injection.
Oil production profile can be discussed based on fractional flow theory, which defines the true Sorw at 100% water-cut. Whenever the produced water-cut is not precisely 100%, oil saturation in the formation is higher than the true Sorw; polymer injection with an improved mobility ratio compared to the water injection one results in an additional oil production, which could be misinterpreted as a reduction in the residual oil saturation, i.e., enhance oil production. Although this accelerated oil production is an attractive possibility (mobility control), it is not an EOR process. Our results are in agreement with previously reported observations in water-wet media related to the EOR nature of the injected associative polymer as opposed to the traditional mobility control of other, either synthetic or organic, polymers. The same results showed that the polymer mobility reduction is highly affected by the injected polymer velocity at the lower spectrum of velocity values and a correlation for the velocity dependent mobility reduction was developed.
Finally, during the injection of the associative polymer, a column of oil-polymer emulsion was formed gradually in the separator which caused some difficulties and introduced uncertainties in the separator’s fluids level readings, and thus eventually in the fluids saturation evaluation. Resistivity data obtained in real time were used to correct for the overestimated values of oil production during polymer injection attributed to the formation of the oil/water emulsion.
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Investigation of CO2 Application for Enhanced Oil Recovery in a North African Field - A New Approach to EOS Development
Authors R. Khabibullin, A. Emadi, Z. Abu Grin, R. Oskui, H. Alkan, M. Grivet and K. ElgridiSummaryMiscible displacement of oil by CO2 injection is one of the most successful enhanced oil recovery (EOR) processes and has been widely implemented in fields around the world since the early 1980s. The advantage of CO2 compared to the other gases is its high extraction power and dissolution rate. As a result, CO2 can develop the miscibility front in the light and medium gravity crude oils at relatively low pressures.
A comprehensive set of experimental studies were conducted using bottomhole oil samples (BHS) and stock tank oil to investigate the viability of miscible CO2 flood in a North African field. The objectives of the study were:
- To measure physical and thermodynamic properties of the oil and CO2 mixtures
- To investigate minimum miscibility pressure and minimum miscibility concentration.
This paper explains the technical approach that was followed to combine laboratory experiments and simulation studies in order to improve quality of the data and tuning of the equation of state. The study started with standard PVT tests (constant composition expansion, differential vaporization, separator tests and viscosity tests) to measure the physical and thermodynamic properties of the reservoir oil. To characterize CO2/oil interaction the study continued with swelling tests. Miscibility of oil and CO2 at reservoir conditions was investigated by visual techniques and the results were verified by slim-tube analysis.
The data from PVT analysis were used to develop three equations of state (EOS) for the reservoir oil from very early stages of the study. The EOS model was then used to design the CO2/oil interaction experiments and was updated once tests were completed.
Simulation of the slim-tube tests were done in order to: (1) verify that simulated FC and MC MMP lies in the range of measured values in laboratory; (2) select the best EOS for conceptual simulation model; (3) calibrate conceptual model for slim-tube test; and (4) understand combined condensing/vaporizing mechanism for a given oil and estimate thermodynamic residual oil at different pressures. Detailed explanations of vaporizing and condensing drives were given in order to allocate them in combined drive along slim-tube.
For conceptual model preparation special attention was given to establish reference interfacial tension and immiscible base case. Further improvements for experimental set up were suggested based on the simulation.
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Novel Application of Micro-CT and Interpretive Geological Analysis to Assess Asphaltene Deposition by CO2 Injection
Authors A. Emadi, R. Khabibullin, I. Patey, Z. Abu Grin, M. Grivet and K. ElgridiSummaryThe asphaltene related issues are known to cause operational problems during well drilling, completion and production life of oil reservoirs. In many cases, this has a significant impact on the development of marginal fields due to the cost associated with inhibition and/or remediation treatment. Therefore, the understanding of asphaltene properties and deposition potential is an important consideration in the reservoir development and design of the EOR/IOR processes.
This paper introduces a new approach that tries to enhance our understanding of asphaltene deposition by adding petrography analysis and Micro-CT studies to conventional PVT type asphaltene analysis and coreflood tests. The application of this approach for a CO2 injection process is presented as a case study which shows how the addition of interpretive geological analysis can assist our understanding of asphaltene deposition and the mitigation solutions.
The main objective of this study was to investigate asphaltene deposition and permeability impairment during CO2/Hydrocarbon flow in the reservoir rock. Asphaltene onset pressure (AOP) and CO2 titration tests were performed using SDS and filtration techniques to characterize asphaltene phase behaviour. Based on the results of the characterization tests, coreflood tests were designed and carried out using reservoir oil and CO2 with CO2 injection ratios increasing from 0.25 to 1.00. Effective permeability measurements were undertaken before and after test to determine the level of permeability alteration due to asphaltene deposition and fluid rock interactions. Comparison of the permeability data before and after the tests shows average permeability reductions of 31% and 13% for two samples with initial permeability of 23.42 and 251.80 mD, respectively. The inverse relationship between permeability loss and original permeability is believed to be due to the smaller size of pore throats in the low permeability sample which boost effect of damaging mechanisms on the permeability.
The interpretive geological analysis (micro-CT, thin section analysis and dry SEM) showed the permeability loss can be attributed to (1) Fluid-Fluid interactions between CO2 and reservoir oil which results in deposition of asphaltene and, (2) Rock-Fluid interactions between CO2 and reservoir rock which results in clay fines redistribution and removal. The results show that the effect of asphaltene deposition in porosity change is significantly higher than the effect of clay fine redistribution. The micro-CT analysis also show asphaltene deposition takes place soon after mixing between crude oil and CO2.
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What Are the Differences between CO2 Injection Offshore and Onshore?
Authors S. Ghanbari, E.J. Mackay and G.E. PickupSummaryCO2-EOR offshore, has the benefit of CO2 storage in addition to EOR. CO2 flooding in the offshore groups of reservoirs, will be different from the past experience of CO2 flooding onshore. Offshore developments are characterised by fewer wells, larger well spacing and higher rates per well. In this study, different aspects of CO2 flooding in these two groups of reservoirs are identified and compared, and possible opportunities for CO2 flooding offshore are identified.
To evaluate potential differences, CO2 flooding in a geological model was simulated under two different development scenarios (offshore vs onshore). Results show that both models are similarly affected by gravity. Offshore, because of larger inter well spacing, a greater degree of heterogeneity can be identified between well pairs. This makes the flow pattern more stable offshore which means that flow correcting mechanisms will be required to a lesser extent offshore.
The requirement for compression is also greater offshore. There are positive consequences for CO2 flooding offshore. The microscopic sweep efficiency increases due to higher miscibility development; the density difference between CO2 and other reservoir fluids decreases and net CO2 utilisation efficiency will be higher. This makes offshore reservoirs better candidates for coupled EOR and CCS CO2 flooding.
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New Methodology for Numerical Simulation of Water-Alternating-Gas (WAG) Injection
Authors H.A. Alzayer, A. Jahanbakhsh and M. SohrabiSummaryA new methodology is presented to simulate WAG injection scenarios. In addition to properly model three-phase flow, the concept of directional and cyclic hysteresis is modelled to capture the underlying physics. Laboratory measured data is used to validate the proposed methodology.
The approach in this paper is based on updating parameters of WAG hysteresis model during the course of cyclic injection to adequately model the key physical mechanisms in WAG injection tests. For this study, we used ‘Modified Stone 1’ model for calculating three-phase relative permeability (kr) data from measured two-phase kr. We used Land’s parameter (C) and the reduction exponent (alpha) for gas secondary drainage relative permeability as the variable parameters in WAG hysteresis model for matching the coreflood production and pressure data.
Results of this study showed that, by applying the proposed methodology for simulating WAG coreflood experiments at different wettability conditions, better match to the experimental data can be achieved. In this paper, we highlight the shortcomings of the current capability of numerical simulators for simulating WAG injection. Some areas of improvement to the current WAG hysteresis model is introduced and a new methodology is proposed to improve the performance of current simulation procedures for WAG injection scenarios.
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Field Pilot of Gel Barriers Placement for In-depth Fluid Diversion of Horizontal Wells in Jidong Oilfield
More LessSummaryMost of the old oilfields in eastern China have already entered into an ultrahigh water cut period, but their annual oil production and remaining recoverable reserves still occupy a pivotal position. Due to severe edge-bottom water coning, the main horizontal production well G104-5P70 of Gao104–5 block in Jidong oilfield has seen an early water breakthrough while a large amount of remaining oil is still stuck in the high structural region. An innovative in-depth fluid diversion technique, gel barrier placement (GBP), proves to be a promising approach to tap the potential of remaining oil in the period of ultrahigh water cut, which involves injecting gel into the horizontal well at the toe end to form ‘gel barriers’, then the edge-bottom water will bypass these barriers and be diverted into the upper zones where the remaining oil is relatively enriched.
In this present work, sensitivity analysis was carried out to study the influence of plugging location, plugging size and plugging strength on the in-depth fluid diversion effect, and optimization design of the plugging system was then conducted with regard to the agent dosage and slug combination. Simulation results indicate that: (1) the main plugging location should be the upper two layers while the appropriate angle between gel barrier and horizontal wellbore is 45°; (2) an obvious water plugging effect is observed for gel barriers with radial slug length of 80m, horizontal probing thickness of 10m and vertical plugging ratio of 0.6; (3) with the permeability reduction factor around 0.05, gel barrier placement will ensure a comparatively high enhanced oil recovery; (4) three-round injection mode is designed to apply on 1500m3 compound plugging agent for the gel barrier placement. Field application shows that the designed GBP is valid for two years with increased oil amount of 1670t and enhanced oil recovery of 6.4%. Compared with traditional profile control techniques, gel barrier placement has prolonged the water control period, improved the plugging accuracy and reduced the plugging agent dosage. It will provide an effective reference for similar edge-bottom water reservoirs in ultrahigh water cut period to further enhance oil recovery.
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Application of Self-Conforming Well Stimulation Technology in Oil and Gas Fields - Fundamentals and Case Histories
Authors I.J. Lakatos, J. Lakatos-Szabó, G. Szentes, A. Jobbik and Á. VágóSummaryThe primary aim of the research project was to develop an efficient technology to control excessive water production in gas and oil wells. As a novelty, water sensitive petroleum-based solutions were developed, which spontaneously form extremely high viscosity barrier under reservoir conditions when contacting with water. Thus, application of that reservoir conformance control technique in fields becomes independent of placement methods even in case of bullhead treatments. After detailed fundamental and applied studies the technology was deemed matured to test under field conditions. Until now, more than 16 well treatments had been carried out including both oil and gas producers. The project is still running in a gas capped oil reservoirs of the largest stacked hydrocarbon field Algyő, Hungary.
The detrimental (higher than 100 m3/d) water production was the primary factor selecting the target wells to be treated. Evaluating the field results, it was concluded that the treatments prove a multifunctional mechanism. The water production in some wells dropped significantly (from 120 m3/d to less than 30 m3/d); meanwhile the gas production remained unchained. In case of some wells, the water production remained unchained, however, the gas production tripled. Surprisingly, all treated gas producers operating in gas capped oil fields, which never produced liquid hydrocarbons started to produce substantial amount of oil (between 10% and 75% oil in net fluid rate). These positive results can be attributed to three different reasons: effective barrier formation against water influx, reducing skin factor caused by formation damage, and opening new flow paths from entrapped oil bodies existing below the gas cap. Thus, the treatment technology was qualified as a “multifunctional well stimulation” contrast to the original term of “water shutoff” method. Based on the encouraging field results the technology became one of the strategic projects of the company in the coming years until 2020.
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Silicate Gel for In-depth Placement - Gelation Kinetics and Pre-flush Design
Authors A. Omekeh, A. Hiorth, A. Stavland and A. LohneSummarySodium silicate gel has historically been used in the oil industry for near wellbore water shut-off. Relatively recent application of Sodium silicate gel for in-depth water diversion have generated some interest. Its main advantage is that its mobility is water-like before it gels. For in-depth diversion purposes, the gelation kinetics need to be appropriately modeled for better prediction of gel placement. This paper makes a review of different gel kinetics models found in the literature. To our knowledge, the models presented in the literature are fit-for-purpose, i.e. they are based on correlations that are fitted to the lab data. Although they describe the lab data well, it is challenging to use them to predict field scale operations, where there are significant temperature, pH, and salinity gradients throughout the reservoir. In this paper, we present an improved silicate gel model. Our model takes into account two important rate step in the formation of silica gel from a sodium silicate solution: the nucleation rate of monosilisic acid to form critical nucleus of nanosized colloids and an aggregation rate of the nano-colloids to form a pore blocking gel. It is important to allow for nano sized colloids as these are small enough to be transported a significant distance from the well before they aggregate into larger clusters that can block the pores. The model explains well the experimental observations where the gelation time is sensitive to pH, temperature, silicate concentration and brine composition. We also investigate the preflush volume and concentration that is needed to minimize the indirect rock-brine interaction that can alter the designed gelation time. Results from this simulation shows that the Cation Exchange Capacity (CEC), Mineral distribution and Temperature profile are critical design criteria for the preflush volume and concentration.
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Simulation of Sodium Silicate Water Diversion Using lORSim
More LessSummaryWe demonstrate that it is possible to predict the impact of a sodium silicate injection on oil recovery by using a coupled approach where an industry standard reservoir model, Eclipse, interacts with a simulator for species transport and reaction, IORSim, using file based communication. The main motivation for our approach is that it makes it possible to take advantage of history matched industry standard reservoir models and use these models together with new models for ion transport and geochemical reactions.
In IORSim a block sorting technique is used to speed up the computation of species transport and chemical interactions. IORSim also has a thermal model which can be used if the temperature option is not used in the reservoir simulator.
The validity of our approach has been checked by comparing with analytical solution and by comparing with an in-house reservoir simulator. Our in-house version solves the multiphase sodium silicate system implicitly. We demonstrate that it is possible to get the very similar results with the sequential IORSim-ECLIPSE coupling and our in-house reservoir simulator by choosing reasonable reporting steps in ECLIPSE. The numerical scheme is improved by using an adaptive implicit numerical scheme and a Cranc-Nicolson method for solving the geochemical reactions.
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Snorre In-depth Water Diversion Using Sodium Silicate - Evaluation of Interwell Field Pilot
Authors V.R. Stenerud, K. Håland, K. Skrettingland, Ø. Fevang and D.C. StandnesSummaryDeclining oil production and increasing water cut in mature fields indicate the need for improved conformance control. In this paper we report on the numerical modeling performed to evaluate the in-depth water diversion pilot performed for the Snorre field, offshore Norway. For this pilot 240 000 m3 of a sodium silicate solution was injected in the period July to October 2013. The goal of the pilot was to form an in-depth flow restriction for improving the sweep. The setup, execution and measured data from response monitoring for the pilot have been presented in previous papers. As discussed therein, the operation clearly resulted in a strong in-depth flow restriction resulting in delayed tracer responses and decrease in the water cut. However, the monitoring was only limited to well observations, so to understand the spatial and temporal forming of the flow restrictions we had to rely on numerical simulation and modeling. In short, we calibrated simulation models to the observed well responses by introducing flow restrictions; i.e. using history matching techniques.
Through the reservoir modeling work we reproduce the pilot response well by introducing sound flow restrictions. This gives us clear indications on the location, timing, strength and corresponding uncertainties of the introduced flow restriction. Moreover, the modeling work supports interpretations from the response monitoring program. Finally, in addition to help evaluating the performed pilot, the learnings from the modeling work will hopefully give more accurate evaluation of potential future water diversion candidates.
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Temperature-switchable Polymer for Enhanced Oil Recovery
Authors R. Reichenbach-Klinke, A. Stavland, T. Zimmermann, D. Strand, H. Berland and C. BittnerSummaryA new copolymer based on hydrophobically modified Polyacrylamide was characterized by its rheological behavior. Viscosities were measured at various temperatures and salinities in comparison to a regular acrylamide/sodium acrylate copolymer (HPAM). It is proven that the viscosity of this new associative polymers increases with temperature, while the viscosity of HPAM is decreasing.
This effect was further explored in porous media studies. Polymer solution was injected into a Bentheimer sandstone with a permeability of around 2 Darcy at 20°C and the pressure drop was measured along the core. From the pressure drop the resistance factor, RF, was derived, which is a measure of the in-situ viscosity in the porous medium.
Next, the temperature was increased to 45°C. This resulted in an increase of the RF from 15 to 94. At 60°C a RF of even 152 was observed. By reducing the flow rate from 0.5 ml/min to 0.1 ml/min the RF could be further increased to 562. Finally the flow rate and the temperature were set to the initial values and a RF of 21 was measured, which shows that the thermothickening behavior of the novel polymer is reversible. Monitoring the effluent viscosity indicated that the increase of the RF / in-situ viscosity is due to polymer being retained in the porous media. This retained polymer lowers the permeability of the rock pores and thereby increases RF. By lowering the temperature the properties are switched back to the original state and the polymer is released from the rock matrix.
The thermothickening behavior of the discussed copolymer can be quite beneficial for polymer flooding applications. During injection at surface temperature the viscosity of the fluid is low and therefore it can be injected at high rates. Once the polymer solution migrates deeper into the reservoir formation, the temperature of the fluid will rise gradually; in-situ viscosity will increase and simultaneously the flow rate will decrease. Both effects will help to improve sweep efficiency.
In general, the magnitude of the RF can be adjusted by modifying the polymer structure and hence the copolymer can be optimized for specific field conditions.
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Design, Characterization and Implementation of Emulsion-based Polyacrylamides for Chemical Enhanced Oil Recovery
Authors A. Thomas, O. Braun, J. Dutilleul, F. Gathier, N. Gaillard, T. Leblanc and C. FavéroSummaryPolymer flooding is a widely used chemical technique used to enhance or speed up oil recovery from brown or green fields. Polyacrylamides used in chemical enhanced oil recovery processes can be supplied either in powder or inverse emulsion forms. The latter has several benefits for offshore deployment including smaller equipment footprint for dissolution and easier transportation to the site compared to the products in solid form. However, the emulsion is a multi-component system that requires much more attention during the formulation and the implementation than the polymer in powder form; the surfactant package must be adapted to the brine used for inversion (temperature and salinity) in order to allow a perfect release of the macromolecules and a good dispersion of the oil droplets to avoid injectivity issues. Moreover, depending on the field conditions and the dosages that are used, the interactions between the components of the emulsion and the crude has to be studied. This paper reviews the basics of emulsion formulation and design along with the best practices for evaluation in the laboratory. Basic inversion procedures for rheological evaluations, filtration tests and oil droplet size analysis are described. An attempt is made to list relevant tests that can quickly allow to discard bad formulations. A quick review is presented on the propagation of emulsions in porous media along with the possible interactions between the components of the emulsion and the reservoir. This is illustrated with several core floods performed using Bentheimer cores where pressure profiles, resistance factors and residual resistance factors as well as mitigation techniques are carefully studied in various injection conditions (low and high temperature, with or without crude oil) and compiled with other laboratory tests such as droplet size measurement to isolate the contribution of each component. The discussion is concluded with engineering and logistic aspects to discuss the proper implementation of such product in the field.
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Enhanced Polymer Flooding - Reservoir Triggering Improves Injectivity and Eliminates Shear Degradation
Authors W.J. Andrews, S.E. Bradley, P. Reed, M. Salehi and D. ChappellSummaryThis paper describes a successful program of lab and pilot-scale studies qualifying a new shear-resistant, high-injectivity, reservoir-triggered polymer (Polymer) for field trial. The Polymer mitigates two of the major operational and economic challenges facing polymer flooding applications for mobility control, namely, shear degradation during injection and reduced fluid injectivity.
Shear degradation of conventional HPAM polymers through injection facilities can result in dramatic losses of up to 70% of viscosity yield. However, this can be eliminated using the new Polymer. This is particularly important in an offshore environment where highly-shearing subsea chokes are required for flow distribution control.
The Polymer formulation uses a novel yet inexpensive chemical approach enabling it to inject with near-water viscosity in a shear-resistant form. The Polymer has been engineered such that it does not viscosify the injection fluid until it is triggered in the reservoir away from the near wellbore region. Higher injection rates and viscosities can therefore be attained than would otherwise be possible with a conventional polymer flood.
Methods:
The Polymer’s triggering performance in porous media under both static and dynamic conditions has been demonstrated. The un-triggered Polymer has been subjected to extremes of shear at both lab and pilot-scale to test shear resistance. Injectivity of the Polymer has been assessed through an extensive suite of sand pack and coreflood experiments. Tests have also been conducted to verify the Polymer’s suitability for field deployment including surface storage, inversion, and long-term reservoir stability.
Results:
The Polymer is completely shear-resistant during injection, demonstrated by flowing through a scaled choke with pressure drops exceeding those expected during deployment. The viscosity of the un-triggered Polymer solution has been shown to be almost independent of the Polymer concentration, injecting with a viscosity close to that of sea water and giving excellent injectivity into sand packs and cores. In addition, the Polymer has been demonstrated to inject, propagate and trigger to deliver a pre-determined viscosity in a temperature-controlled 40ft sand pack experiment. The Polymer solution is easily and reliably prepared, out-performing a conventional HPAM in a pilot-scale inversion study, and demonstrates storage characteristics above the industry standard. A 15 month-long stability test performed at reservoir temperature with reservoir fluids showed minimal loss of viscosity.
Testing will now proceed to field trial. If successful, this new technology offers a route to overcoming some of the key obstacles to large scale polymer EOR deployment, particularly in the offshore environment.
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Qualifying an “Emulsion” Polymer for Field Use - Lab-scale Assessments on Adsorption and Injectivity
Authors K. Sandengen, M.T. Tweheyo, C.M. Crescente, A. Mouret, I. Henaut and D. RousseauSummaryPolymers prepared as concentrated inverse emulsions (“emulsion” polymers) appear valuable for offshore EOR as they involve simple dilution procedures. However, recent studies have shown that these polymers could entail permeability reduction effects which question their injectivity.
Initial screening tests, for a specific high temperature and high salinity field case, showed no sign of plugging. Adsorption was, however, reported to be extremely high and a more elaborate work package was therefore initiated.
An “emulsion” polymer and its “dry” equivalent (from which oil and most surfactant were removed) were put through coreflood tests focused on injectivity (including plugs with intermediate pressure taps) and adsorption (evaluated from measurements of the irreversible retention). Injection in porous media, at reservoir type rates, revealed increases of the resistance factors, RF, in two successive fronts: a “quick” front with RF values consistent with the polymer viscosity and a “slow” front with much higher RF. The quick front corresponds to the propagation of the viscous polymer, as is it associated to the polymer breakthrough. The slow front is attributed to the deposition of oil droplets coming from the synthesis process of the polymer. Similar behavior has been observed from tests carried out in monophasic conditions, in presence of residual oil and at different injection velocities, but not with solutions of the “dry” polymer sample. As oil droplets impact the polymer inaccessible pore volume and hence the volumes at breakthrough, a specific procedure had to be developed to determine polymer adsorption. With this procedure the “emulsion” and the “dry” polymer samples yielded comparable results. Following this work package adsorption was consequently no longer a concern, while injectivity again proved questionable. Finally a new version of the “emulsion” polymer, with an improved surfactant formulation package, was injected through porous media with no sign of plugging/pressure build-up.
In conclusion we do not foresee problems associated with the chosen “emulsion” product. In the laboratory we have, however, not mapped all rate regimes nor with actual mineralogy. Hence sufficient emulsion propagation cannot be guaranteed (in particular as the permeability damage could propagate in-depth). Injectivity therefore still remains as one major factor to be investigated in the coming field trial.
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Experimental Investigation of Inorganic Scale Deposition during Smart Water Injection - A Formation Damage Point of View
Authors J. Ghasemian, R. Mokhtari, S. Ayatollahi, S. Riahi and E. MalekzadeSummarySmart water injection is determined as an effective EOR process to change the wettability and interfacial tension for better micro/macro sweep efficiencies. This water contains reactive ions such as Mg ^(2+), Ca ^(2+) and SO _4 ^(2-)which can act as potential determining ions and change the surface charge of calcite rocks. One of the major concerns in the execution of an effective waterflood, especially in tight carbonate reservoirs, is the incompatibility between the formation brine and the injecting water. This research work aims to investigate the most important challenge of waterflooding process related to the possible formation damage because of inorganic scale deposition during experimental smart water injection. At the first stage, sea water as the basis for smart water were prepared to examine the impact of determining ion such as Mg ^(2+), Ca ^(2+), and SO _4 ^(2-)and the salinity of the injected brine on total amount of CaSO _4 precipitation. The tests were performed to find the effects of each ion at static and dynamic conditions. According to the obtained results, as the concentration of SO _4 ^(2-) in the injecting water increases from 1/4 to 1 times of its concentration in ordinary sea water, the CaSO _4 deposition increases smoothly, which was accelerated beyond that. Hence, as the increasing of the sulfate concentration improved the wettability alteration ability of the smart water, however calcium sulfate deposition was noticed which make permanent formation damage. Besides, the test results showed that CaSO _4 deposition increases smoothly as the concentration of Ca ^(2+) in the sea water increases. On the contrary, the presence of Mg ^(2+) ion in the sea water, increases the solubility of CaSO _4 and subsequently, lower scale formation was noticed by increasing the concentration of magnesium. This study also showed that, there is an optimum salinity (5 times dilution in sea water salinity) in which the minimum amount of CaSO _4 is deposited. The findings would enable us to optimize the ion contents of smart water for both, better oil sweep efficiency and lower risk of formation damage.
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A New Frontier Technique for Nano-analysis on Flooded Chalk - TERS (Tip Enhanced Raman Spectroscopy)
Authors L. Borromeo, M. Minde, C. Toccafondi, U. Zimmermann, S. Andò and R. OssikovskiSummaryUnderstanding the chalk-fluid interactions at the sub-micron scale is one of the most challenging goals in Enhanced Oil Recovery. The grain size of newly grown minerals far below 1 micron asks for a high performing imaging: we present a new methodology using the TERS (Tip Enhanced Raman Spectroscopy), a new frontier technique that combines Raman Spectroscopy with Atomic Force Microscopy, allowing impressively high-resolution chemical analyses down to an outstanding spatial resolution (~ 20 nm). TERS permits the recognition of minerals thanks to the vibrational mode peaks that are diagnostic of composition and structure. Carbonate-group minerals are easily identified by Raman spectroscopy. First analyses allow us to state that magnesite and calcite could be identified in, respectively, ultra-long-term flooding experiments of chalk at reservoir conditions and in unflooded samples; no dolomite or high Mg-calcite have been found. Few microns squared areas have been imaged by AFM using ultra polished thin sections with a 50 nanometers step.
Transmission electron microscopy has been employed to confirm the results of TERS and add dark and bright field grain-imaging to the investigations.
This confirms the need for high-resolution methodology such as TERS and TEM to fully understand EOR effects at sub-micron scale.
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Water-blocking Solution Based on Emulsion with SiO2 Nanoparticles Content for Reservoir Stimulation Technologies
Authors V.V. Sergeev, Y.V. Zeigman and F.S. KinzyabaevSummaryA significant part of existing oilfields are in late stage of development,it’s leading to problems with high water cut and reduction in hydrocarbon production. One of the main reason is water break-through from high permeability reservoir intervals. In this regard,one of the most important object of IOR methods is to enhance efficiency of water-blocking solutions. Into the object the main task is developing high effective solutions for selective blocking high-permeability water-bearing intervals and involvement low permeability oil-saturated intervals into production.
Results of wells operation monitoring are presented in article. The technology based on application of emulsion for selective blocking water-bearing intervals into reservoir. On the results of 6 months wells monitoring data analysis,treated due oilfield tests were determined that the technology allowed to decrease water-cut on 10% and increase oil production twice.
On the results of carried out by lab research it was proposed to improve provided technology by applying emulsion with SiO2 nanoparticles content. Physicochemical properties of new emulsion solution better in rheology and stability in compare with standard emulsions and its might increment the time of technological efficiency. The lab research showed that the addition of SiO2 nanoparticles allows reach better physicochemical properties both hydrophilic and hydrophobic type of emulsions.
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Gravity Override and Vertical Sweep Efficiency in Dipping Reservoirs
Authors G.Y. Yu, M.N. Namani, J.K. Kleppe and W.R. RossenSummaryThe model of Stone (1982) and Jenkins (1984) predicts the extent of gravity override at steady state during gas-liquid co-injection in an enhanced oil recovery (EOR) process. The model is accurate for WAG injection if the slug sizes are sufficiently small. The model is exact for homogeneous reservoirs if the standard assumptions of fractional-flow theory apply ( Rossen and Van Duijn, 2004 ). Stone and Jenkins relate the distance to complete gravity segregation to total mobility in the mixed zone and the thickness of the override zone beyond this point to mobilities in the override and underride zones.
Namani et al. (2012) and Jamshidnezhad (2009) have proposed extensions to Stone and Jenkins’ model for dipping reservoirs. The accuracy of these correlations were tested in this study for a wide range of conditions and angle of reservoir dip using 2D computer simulations. Both correlations are approximately correct, but deviate from observed behaviour at large dip angle. Specifically, gravity override occurs at shorter distances than predicted by Namani et al. for up-dip injection, but longer distances for down-dip injection at moderate dip angles. Jamshidnezhad’s correlation works reasonably well for down-dip injection except at large dip angles, for which segregation occurs at much shorter distances than predicted. Much of the sweep of gas occurs not at steady-state, however, but during the transient period before steady state is attained. During the period of three-phase flow, mobilities are lower; as suggested by Stone’s approach, this temporarily extends the mixed zone beyond that at steady state. In up-dip injection, the override zone is extended much deeper into the reservoir during the period when gas first enters than at steady state. The oil swept during this period can greatly exceed that represented in the mixed zone in any of these models: even though the mixed zone is reduced, overall sweep can be greatly increased by this effect. This extension of the override zone during transient flow follows the logic of Jenkins’ derivation of the thickness of the override zone based on mobilities.
Unfortunately, there is no single exact equation for gravity segregation in dipping reservoirs as for horizontal reservoirs, even at steady state. Therefore behaviour varies somewhat from case to case.
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Uncertainties - Extension of Smart Waterflooding from Core to Field Scale
Authors T. Kadeethum, H.K. Sarma, B.B. Maini and C. JaruwattanasakulSummarySmart waterflooding has emerged as an EOR process of much interest in recent years. Much research is being reported, along with a few successful field applications, notably clastics. In most cases, there are undeniable inconsistencies in results between lab and field cases. This leads to unpredictable outcomes and misleading profit prediction of smart waterflooding projects. The objective of this work is to evaluate uncertainties in smart waterflooding from core- to field-scale.
Kozaki (2012) experiment is mimicked by 1-D numerical model that couples with geochemical reactions. Validation results show that there are many combinations of matching parameters that can describe coreflooding results. Each realization may lead to different results when extended to 3-D heterogeneity model. Hence, to cover ranges of uncertainties, many realizations should be tested before summarizing smart waterflooding performance.
Full-field heterogeneity model also shows that smart waterflooding is sensitive to grid size and heterogeneity. With different grid volume settings, results vary dramatically. This may contribute towards smart waterflooding misinterpretation. Furthermore, heterogeneity alters smart waterflooding within a particular range by affecting cation exchange capacity, and subsequently interpolant value, which is used to represent system wettability. Therefore, these parameters should be accounted in field-scale simulation to obtain smart waterflooding true potential.
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Water Ion Interactions at Crude Oil-water Interface - Is there a Correlation between IFT and Interfacial Rheology?
Authors S.C. Ayirala, S.H. Saleh, A.A. Yousef, Z. Li and Z. XuSummarySmartWater flooding (SWF) through the injection of optimized chemistry waters is getting good attention in recent years for improved oil recovery (IOR) and enhanced oil recovery (EOR) in carbonate reservoirs. Consequently, much of the research conducted so far in this emerging area has been limited to studying salinity and water ion interactions at carbonate rock-crude oil-water interfaces. Favorable wettability alteration has been seen to play a major role on oil recovery based on measurements such as contact angle and zeta potential; however, the other important aspect of characterizing water ion interactions at crude oil-water interface has received little attention. In this study we performed interfacial shear rheology measurements to study water ion interactions at crude oil-water interface and compared these results with the previously reported IFT data. The major objectives are to determine the impact of different water ions on the viscoelastic properties of crude oil-water interface as well as to explore the correlation between IFT and interfacial rheology. Several low salinity SmartWater recipes with varying individual ion compositions were used in these experiments.
The data indicated noticeably higher IFT values for SmartWater recipes containing sulfate ions, while IFT was the lowest for SmartWater composed of magnesium ions. In contrast, SmartWater with only sodium or calcium ions displayed almost similar IFT values. Interfacial shear rheology results showed significantly higher viscous and elastic modulus for SmartWater recipes comprising of sulfate ions. The SmartWater recipes with sodium-only, calcium-only or magnesium-only ions showed comparable interfacial rheology. The transition times for the interface to become elastic-dominant from a viscous-dominant regime are found to be the lowest for sulfates-only brine followed by the sodium-only and calcium-only brines, and the highest being with magnesium-only brine. The much quicker transition times to elastic regime observed with sulfates-only brine indicates rigid skin at the interface that could potentially delay the destabilization of the interfacial film and hinder the coalescence between oil droplets. The longer transition times to elastic regime observed with magnesium-only brine shows the presence of less rigid films at the interface to promote the coalescence between oil droplets. A good correlation between IFT and the interfacial film transition times from viscous to elastic-dominant region was observed for all the brines, which confirms that similar sensitivity of water ions is reflected in both the parameters. These novel findings on the microscopic scale interactions of different water ions at crude oil-water interface pointed out the importance of magnesium and calcium ions in the SmartWater to enhance the coalescence between released oil droplets to quickly form oil bank in the reservoir for faster recovery.
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Produced Water Treatment with Membranes for Enhanced Oil Recovery in Carbonate and Sandstone Reservoirs
Authors R. Nair, E. Protasova, S. Strand and T. BilstadSummaryThe research is focused on determining the technical performance of membranes for treating and reinjecting produced water (PW). Ionic composition of pre-treated PW containing 90,000 ppm total dissolved solids (TDS) is manipulated by membrane separation and reinjected as smart water in carbonate and sandstone reservoirs. Nanofiltration (NF) membranes coupled with reverse osmosis (RO) membranes are tested in this research. TDS of less than 5,000 ppm with negligible divalent ions is defined as Smart Water for sandstone reservoirs. High divalent ion concentrations with TDS typically above 10,000 ppm compose Smart Water for carbonate reservoirs.
The performance of NF membranes at different pH of PW is evaluated at various pressures. An economic analysis is performed for different combinations of membranes with TDS of 90,000 ppm as reference. A combination of two NF membranes are used to produce Smart Water for carbonate reservoirs. The power consumption is calculated at 0.37 kWh/m3. PW reinjection in sandstones with TDS of 5,000 ppm require either the use of permeate from RO or supplying fresh water by other means for diluting permeate from NF. A power consumption of 14.8 kWh/m3 is calculated for the combination of two NF membranes and RO for Smart Water production for sandstones.
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Effects of Potassium Ion on Low Salinity Waterflooding in Sandstone Formation
Authors F. Srisuriyachai, S. Meekangwal, C. Charoentanaworakun and Y. VathanapanichSummaryMulti-Component Ion Exchange (MIE) is a mechanism that has been proven to take place during low salinity waterflooding. In sandstone surface, oil containing organic acid may be attached onto rock surface through an aid of divalent ion binding. Substitution of monovalent ion onto the linking divalent ion site results in liberation of oil. Minimum quantity of divalent ion such as Calcium ion and Magnesium ion together with presence of monovalent ion in injected brine would be therefore favorable conditions for the MIE mechanism.
In this study, spontaneous imbibition test is performed to observe ability in replacement of monovalent ion by excluding effect from injection rate. Formation brine is prepared to have total salinity of 100,000 ppm, using an average ion proportion from sandstone oilfields around the globe. Effects of Potassium ion which is much smaller in quantity in brine and seawater compared to Sodium ion, is investigated. From the experiment, Potassium Chloride solution at 35,000 ppm can imbibe into rock sample with total increment of water saturation of 0.42, whereas Sodium Chloride solution at the same salinity can only increase water saturation of about 0.27. Potassium ion is usually accompanied by 1–4 molecules of water, whereas Sodium ion is surrounded by 5–11 molecules. This causes hydrated Potassium to be smaller in size and more active in replacing divalent ion compared to hydrated Sodium. Lowering concentration of Potassium Chloride to 5,000 ppm shows an adverse effect on imbibition ability. As number of active monovalent ion is reduced, replacement of divalent ion occurs slowly. As a result, only 0.24 of water saturation is increased from initial water saturation. Comparing to seawater at the same total salinity which contains Potassium ion only 369 ppm, seawater imbibes at higher degree compared to solely Potassium Chloride which is about 0.47 of water saturation. This can be explained that, adequate total salinity could favor Potassium ion to approach the surface. Moreover, presence of Calcium ion would help induce liberation of oil through formation of Calcium Carboxylate complex. Last, seawater without Potassium ion is prepared to confirm effect of Potassium ion and it is observed that 0.40 of water saturation is increased during the test.
In summary, Potassium ion is more potential in replacing divalent ion compared to Sodium ion. A presence of only small quantity of Potassium ion is adequate for spontaneous imbibition as this can be offset by presence of other potential ions.
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Effect of Mud Invasion on the Determined Low Salinity Water Flooding Potential
By I. FjeldeSummaryLaboratory experiments with reservoir rock samples should give input to estimation of the potentials of recovery methods. The potential for low salinity water flooding (LSWF) of sandstone oil reservoirs has been reported to depend on the amount of clay and their surface properties. The objective for the reported study was to investigate the effect of KCl water-based mud invasion on the determined LSWF-potential. The wettability of minerals and a sandstone reservoir rock was characterized by flotation tests using two brines (formation water (FW) and mud brine) and two stock tank oils (STOs). During preparation of sandstone reservoir core plugs, effluent samples were analyzed for element compositions to determine whether they were contaminated with KCl mud. Unsteady-state flooding experiments with sea water (SW) and low salinity water (LSW) were carried out in these core plugs. Core plugs were analyzed by scanning electron microscopy (SEM) both after cleaning with solvents and after water flooding experiments. Bentonite consists mainly of montmorillonite clay and is added to water-based muds for rheology and filtration control. In the flotation tests, this clay was found to be less water-wet than the dominating minerals in the original reservoir rock. Rock samples with bentonite invasion can therefore become more oil-wet than the original rock. The mud brine was also in the flotation tests found to give more water-wet reservoir rock than the FW. High permeable sandstone reservoir core plugs were during preparation found to be contaminated by the KCl mud brine. Chemical analyses confirmed that this brine was removed during cleaning of the core plugs. In some cases, production of emulsions was observed during LSWF. These emulsions may have been stabilized by bentonite contamination. The water flooded core plugs were by SEM-analysis found to contain clusters of barite and clay and also polymer. This means that all mud components were not removed by using the standard core cleaning procedure. It was not possible to conclude anything about the LSWF-potential for the studied reservoir rock, because the core plugs were contaminated by mud components that may have affected the determined LSWF-potential.
Mud contamination of the reservoir rock can affect the permeability and the established wettability conditions. Invasion of bentonite clay will increase the cation exchange capacity, and this can affect the determined LSWF-potential. It should therefore be confirmed that mud components that can affect the established flow conditions, are removed during core preparation.
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A Novel Characterization of Effective Permeability of Tight Reservoir - Based on the Flow Experiments in Microtubes
More LessSummaryIn tight reservoirs, as throat radius decreases to micro-nano scale, pore structure becomes more complex. The effect of interaction between seepage fluids and rocks increases, which changes flow characteristics in micro scale. In order to realize efficient development of tight reservoirs, the throat distribution and permeability needs new understanding.
In this paper, a device was established to measure water flow rate in microtubes, under different pressure gradient. The water was de-ionized and tubes were made of fused silica with radius of 1, 2.5, 5, 7.5, 10 and 15μm. The pressure gradient was set mainly 0.02~0.6MPa/m, close to that in oilfield, while previous published experiments focused on 1~80MPa/m. The results showed that experimental flow rate was lower than theoretical value calculated by Poiseuille equation. A stable boundary layer was formed near the solid wall, blocking the flow. Its thickness was calculated, ranging 29.6nm~ 1.08μm. As pressure gradient increased, the boundary layer declined and its effect vanished. This change led to nonlinear flow characteristics in micro scale. The thickness increased with throat radius increasing and reached a constant value when tube radius were larger than 15μm.
Based on experimental results, a boundary layer thickness function was regressed. The independent variables were pressure gradient, throat radius and viscosity. Considering boundary layer, the effective throat radius distribution was characterized, taking normal distribution as the original distribution. The results showed that the range of effective throat distribution was narrower than the original one and the peak value was higher. The sensitivity of the function was analyzed.
Based on the characterization of effective throat distribution, the formulas of Klinkenberg permeability and effective permeability were derived. The effective permeability formula was validated using data from Shiwu and Bohai oil reservoir. The deviation is lower than 6%.
The effective permeability of tight reservoir under different conditions was calculated and investigated. The larger the median radius and the range of the throat distribution, the higher the effective permeability. The effective permeability of a core is not determined only by its pore structure. It is also effected by pressure gradient and the properties of the fluids. When the pressure gradient increases, the effective permeability increases as the boundary layer declines. When the fluid viscosity increases, the effective permeability decreases.
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Petrological, Mineralogical and Geochemical Constraints on Hydrocarbon Bearing North Sea Reservoir Chalk
Authors E.I. Kallesten, U. Zimmermann, M.V. Madland and M.W. MindeSummaryA study of the geochemistry and petrology characterizing the North Sea reservoir chalk is central in the efforts of refining or developing new Increased Oil Recovery (IOR) methods, as it provides an insight in the chemical composition, mineral structures and textures of the reservoir rock and the grounds for a pilot test within the National IOR Centre of Norway. The study is based on cores collected over a decimeter-scale, under different flooding status, from unflooded to waterflooded at lower or higher temperatures, swept and unswept regions from the Tor and Ekofisk formations directly sampled from the Ekofisk field. Optical petrography shows a very fine, micritic carbonate matrix, with various microfossils such as calcispheres, foraminifers, or sponge spicules. SEM micrographs reveal post-depositional calcite precipitation inside the calcispheres, sometimes entirely cementing their cavities. The amount of clay minerals observed with SEM varies and there is a clear decrease in porosity stratigraphically downwards, along with more cementation and compaction. X-ray diffraction confirms calcite as most abundant in the whole-rock composition, with quartz and few other non-carbonate minerals like smectite, illite and kaolinite present. The silica content varies highly from <2 wt% in the shallower cores to 6 – 8 wt% in areas close to tight zones and up to 11 wt% in the deeper cores. δ13C and δ18O are lower than the secular global isotopic values for this period. Since similar disturbed stable isotope values are seen in other hydrocarbon-rich samples unexposed to any fluid for IOR purposes, the disturbance is assigned to a post-depositional diagenetic overprint, or to the influence of a secondary fluid of unknown origin, rather than the effect of the cores’ flooding status.
Given the compositional variety of the Ekofisk reservoir rocks, selecting a single on-shore exposure as a standard equivalent for the Ekofisk chalk would be problematic. The complexity of the reservoir chalk and consideration of many other IOR influencing parameters, compel caution when transferring results from the onshore chalk modeling to the reservoir chalk (e.g. Hjuler and Fabricius, 2009 ). Beside the mineralogical composition of chalk strongly influencing compaction, the palaeo-environmental conditions at the time of deposition, the diagenetic history, calcite recrystallization and fossil preservation may affect the strength of the rock. Hence, a further thorough geological study on the reservoir chalk is necessary to verify the prospect of comparisons based on geological grounds.
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Physical Modeling of Rheological Properties of Polymer Solutions for Enhanced Oil Recovery
Authors D. Shogin, P.A. Amundsen, A. Hiorth and M.V. MadlandSummaryWe review the FENE-P dumbbell model of diluted polymer solutions, based on molecular dynamics. Although simplified, this model has proven to be a useful tool for qualitative and quantitative studies of non-Newtonian fluids.
It is demonstrated that under reasonable assumptions, the equations of fluid dynamics with the FENE-P constitutive equations can be solved analytically for some simple flows. In this report, we obtain and investigate the analytical solutions for laminar flows of FENE-P fluids in straight circular tubes and slits of constant width. This includes the expressions for the velocity and shear rate profiles, volume flow rates, pressure gradients, stress tensor components, and viscometric functions. The results are formulated in a manner allowing their direct practical use. A connection to several relations utilized by petroleum engineers is established.
The solutions are generalized to describe the flow through capillary bundles and grids consisting of multiple slits --- these can be thought as a simplified model of porous media. We explain why the behaviour of polymeric fluids in such media is essentially different from that in a single tube or slit, and demonstrate how this difference can be accounted for, if the pore size distribution is known.
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Scale Risk Management during CO2 WAG in Carbonate Formations
Authors A.S. Ribeiro, E.J. Mackay, L.J.N. Guimarães, M. Jordan and S. FellowsSummaryIn this work we have used commercial software to perform reactive transport simulations of CO2 WAG injection in an oil reservoir, with the objective of assessing the scaling risk associated with CO2 EOR in carbonate formations. Higher WAG ratio promotes faster mineral reactions and severe scale deposition at earlier times. Injection of cooler fluids also enhances calcite and CO2 dissolution in water near the injector wellbore. Finally, the mass of calcite around the producer wellbore changes due to three different mechanisms: (a) brief dissolution caused by arrival of the CO2-rich front, (b) re-precipitation caused by mixing between high HCO3 injected water with high Ca formation water and (c) continuous precipitation caused by evolution of CO2 along the flow path, which occurs continuously after CO2 breakthrough. The results of these calculations allow the critical location where scale damage could occur within a production system to be identified, and a mitigation strategy developed to control its formation, for example via continual injection of scale inhibitor down to the production packer in early field life, reducing the need for batch inhibitor (squeeze) treatments into the reservoir in later field life, thereby significantly reducing OPEX.
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Improved Modeling of Gravity-Aided Spontaneous Imbibition Using Momentum-Equation-Based Relative Permeabilities
Authors P.Ø. Andersen, Y. Qiao, S. Evje and D.C. StandnesSummaryIt is well known that relative permeabilities (RPs) can vary depending on the flow configuration and are lower during counter-current flow as compared to co-current flow.
In this paper we use a novel two-phase momentum-equation approach to generate effective RPs where this dependence (and others) is well captured whereby the fluids transfer momentum due to fluid-rock interaction and fluid-fluid interaction.
During co-current flow the faster moving fluid accelerates the slow fluid, but is itself decelerated, while for counter-current flow they are both decelerated.
We investigate recovery of oil from a matrix block surrounded by water due to a combination of gravity drainage (GD) and spontaneous imbibition (SI), relevant for fractured reservoirs.
In capillary-dominated systems the flow is counter-current and viscous coupling can result in increased time scale of the recovery process.
During gravity-dominated flow it is more co-current and applying co-currently measured relative permeabilities from the lab becomes a better assumption.
Using one set of parameters the momentum-equation approach is thus able to model the behavior of blocks of different operating at different Bond numbers in the reservoir.
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An Analytical Model for Analysis of Centrifuge Capillary Pressure Experiments
Authors P.∅. Andersen, S.M. Skjæveland and D.C. StandnesSummaryPrimary drainage with centrifuge is considered where a core fully saturated with a dense wetting phase is rotated at a given rotational speed and a less dense, non-wetting phase enters. The displacement is hindered by a positive drainage capillary pressure and equilibrium is approached with time. We present general partial differential equations describing the setup and consider a multi-speed drainage sequence from one equilibrium state (at a given rotational speed) to the next.
By appropriate simplifications we derive that the process is driven by the distance from equilibrium state as described by the capillary pressure at the inner radius and position of the threshold pressure (transition from two to one-phase) from their equilibrium values.
Further, an exponential solution can describe the transient production phase.
Using representative input saturation functions and system parameters we solve the general equations using a commercial software (Sendra v2016.1) and compare with the predicted exponential solutions. It is seen that the match is excellent and that variations in time scale are well captured.
The rate is slightly underestimated at early times and overestimated at late times, which can be related to changes in total mobility during the cycles for the given input.
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Reflection of Processes of Non-equilibrium Plastic or Two-phase Filtration in Oil-saturated Hierarchic Medium
Authors O.A. Hachay, O.Y. Khachay and A.Y. KhachaySummaryA comparison is provided of non-equilibrium effects of the influence of independent hydrodynamic and electromagnetic induction on an oil layer and the medium which it surrounds. Using the earlier developed 3-D method of induction electromagnetic frequency geometric monitoring, we showed the possibility of defining the physical and structural features of a hierarchic oil layer structure. For description of these effects it is needed to consider the wave process in the hierarchic blocked medium. Some algorithms were constructed for 2-D modeling of sound diffraction on a porous fluid-saturated intrusion of a hierarchic structure located in the layer number J of an N-layered elastic medium, for 2-D modeling of sound diffraction and propagations of transversal wave in the layer number J of an N-layered elastic medium with plastic inclusion. These algorithms present the strong mathematical theory for modeling and interpretation of acoustic wave propagation using a model more adequate to the real medium with oil and gas. It can be used as a base for constructing new methods of seismic monitoring for receiving results of choosing better places for oil recovering. Some analogues ideas are fulfilled in the electromagnetic case by recovering rocks in the rock shock mines.
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Induced Shear Failure by Temperature Reduction at Uni-axial Strain Conditions
Authors T. Voake, A. Nermoen, R.I. Korsnes and I.L. FabriciusSummaryThis study improvises uniaxial strain condition during cooling by keeping constant overburden, and adjusting radial stress at cooler temperatures in order to re-establish the same radial dimensions prior to cooling. The amount of radial stress reduction by thermal contraction could be sufficient to trigger shear failure. Experiments are performed on Mons chalk and Kansas chalk so the role of induration can be assessed. Calcite thermal expansion is highly anisotropic. Weakening caused by temperature fluctuation could give insight to what gives chalk its strength, cementation, or repulsive electrostatic forces. For each chalk type, shear failure line is determined. The samples are heated to 90oC and loaded to 70% of the axial stress required to induce shear failure. Then the temperature is reduced by 60°C. The change in confining pressure necessary to restore zero radial strain is estimated. The two chalks show different behaviour. Mons demonstrates this cooling would induce shear failure, but has no significant effect on its strength. Kansas, is able to restore uniaxial strain conditions without shear failure. The strength of the Kansas sample was unaffected, however the change in confining pressure needed to restore the uniaxial strain condition decreased with each additional cycle, indicating changing elastic properties.
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Elastic and Plastic Behavior of Chalks at Deviatoric Stress Condition: Experiments Performed with Four Different Brines
Authors J.S. Sachdeva, A. Nermoen, M.V. Madland and R.I. KorsnesSummaryThis paper deals with exploring elastic (bulk modulus and Young’s modulus) and plastic parameters (yield stress, creep and rebound) during deviatoric loading and time-dependent deformation. A series of experiments were carried out at Ekofisk reservoir temperature (130°C) to study the effect of four different fluids, viz., distilled water (DW), NaCl-brine, MgCl2-brine and seawater (SSW), on Mons outcrop chalk. The cores were deviatorically loaded and left to creep at a constant value of 69–73% of the axial yield stress obtained from reference tests with the same brine. Variations in the bulk modulus and Young’s modulus were observed as function of saturation fluid, although the significance of these observations require more data. SSW had the lowest yield stress followed by NaCl and MgCl2, and highest for DW, which conforms the results from earlier studies. The final creep strain was highest for SSW and was 1.3–1.5 times higher than for other brines. The core initially saturated by SSW showed the highest plastic component of the total strain inferring that the ions in SSW does play an important role in inducing permanent damage.
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Comparative Studies of Mineralogical Alterations of Three Ultra-long-term Tests of Onshore Chalk at Reservoir Conditions
Authors M.W. Minde, S. Haser, R.I. Korsnes, U. Zimmermann and M.V. MadlandSummaryTo understand the alterations in geomechanical and mineralogical properties of reservoir chalk injected with seawater, countless experiments have been carried out through decades of research at UiS. Several parameters are varied to understand how these parameters impact fluid-flow, rock-fluid interaction and compaction, which is an important drive mechanism for Enhanced Oil Recovery (EOR). Identification of mineralogical alterations is crucial input to modelling and simulation of EOR methods.
We present the results from flow through experiments on Liège chalk from three ultra-long-term tests. The core were flooded with MgCl2 at reservoir temperature (130°C) and hydrostatic stresses above yield (9.5, 10.4 and 12.6 MPa), with one core was flooded for a short period with a mixture of MgCl2 and CaCl2, and with MgCl2 brines at different pH, ~2.7, ~5.7 and ~9.
The studies based on Mineral Liberation Analyzer and Transmission Electron Microscopy show two fronts moving through the cores at different velocities. The first alterations are partial dissolution of calcite with precipitation of secondary minerals like high-magnesium carbonate and clays, followed by fronts of complete transformation to the Mg-rich mineral. Random calcium impurities (<4wt%) are present in all analysed magnesite crystals. In addition, precipitation of Si-Mg-bearing clays is observed throughout all flooded cores.
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Wettability Characterization Using the Flotation Technique Coupled with Geochemical Simulation
Authors S. Erzuah, I. Fjelde and A.V. OmekehSummaryWettability controls the distribution of fluid phases and flow properties in oil reservoirs. Wettability characterization can be accomplished using standard techniques such as Amott-Harvey and USBM. Nevertheless, these experiments are time consuming and limited numbers are carried out for each oil reservoir. The objective is to evaluate the possibility to use the flotation technique combined with geochemical simulations for fast wettability characterization.
The flotation technique relies on the affinity of the minerals to either the brine or the oil, and was used to characterize the wettability of minerals. The amounts of oil-wet particles is determined for the mineral-brine-oil mixtures after aging the mineral in brine and oil respectively. Two formation water compositions and two stock tank oils were selected for the flotation experiments. As an introduction to this study, the wettability of six (6) minerals found in sandstone reservoir rocks were investigated by flotation test. The mineral-brine interactions such as solubility and surface complexation of minerals were modelled with the geochemical simulator PHREEQ-C, and the results were compared with their experimental counterpart. The flotation tests showed that the crude oils altered the wettability of some of the water-wet minerals to oil-wet. It was inferred that the clay minerals were less water-wet. Calcite with cationic surfaces, became more oil-wet by aging with crude oil, and this indicated direct adsorption of carboxylic acids.
Surface Complexation Modelling (SCM) results reveal that the surface charges of both quartz-brines and STOs-brine are mostly negatively charged and hence electrostatic repulsion exist between the two interfaces leading to lack of oil adhesion. Unlike quartz, the calcite-brine and the STOs-brine interfaces were positively and negatively charged respectively. Hence, direct adhesion of the polar oil components onto the calcite surface is the reason for the high oil-wet nature of calcite. This was also consistent with the total bond product which expresses the tendency of oil adhesion onto minerals surfaces. The total bond product for calcite (0.95 – 1.06) was greater than quartz (0.01 – 0.07) and hence confirming that more oil was adsorbed on the calcite surface unlike quartz. Both the SCM and the flotation test results reaveal that the calcite is strongly oil-wet while quartz is strongly water-wet.
The flotation technique combined with geochemical simulation is a promising and cheap approach of characterizing the wettability. In the flotation tests only small rock samples are required. This approach has the potential to provide fast estimation of the wettability of reservoir rocks.
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Quantification of Mineralogical Changes in Flooded Carbonate under Reservoir Conditions
Authors N. Egeland, M.W. Minde, K. Kobayashi, T. Ota, E. Nakamura, U. Zimmermann, M.W. Madland and R.I. KorsnesSummaryInjection of seawater-like brines is one of the most successful EOR methods on the Norwegian Continental Shelf. Aqueous chemistry affects the mechanical strength of chalk. The injected seawater might trigger several mechanisms simultaneously and the importance of each mechanism is not fully understood. The aim of this study is to obtain an improved understanding of EOR mechanisms at pore scale by studying new mineral phases when flooding chalk with MgCl2 at reservoir conditions (130°C, 1 PV/day, 11.3 MPa effective stress). Two chalk cores were investigated, one artificial and one outcrop chalk. FE-SEM, STEM, and EDS-analyses show newly formed magnesite growing on calcite surfaces after 27 days. The Mg/Ca interphase is sharp, no diffusion of elements is observed on Ångström scale, and flooding experiments change the crystallography of phases. Whole-rock geochemistry of the Liége outcrop chalk flooded with MgCl2 for 3 years reveals a MgO content of c. 42 wt.%, but still c. 4 wt.% CaO. STEM mapping shows that CaO impurities are present in MgO dominated phases. These experiments confirm that magnesite grows as a new mineral phase even after short term flooding and that calcium is still present as impurities in the magnesite after long term flooding.
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SmartWater Flooding in a Carbonate Asphaltenic Fractured Oil Reservoir - Comprehensive Fluid-fluid-rock Mechanistic Study
Authors M. Fattahi Mehraban, S. Afzali, Z. Ahmadi, R. Mokhtari, S. Ayatollahi, M. Sharifi, A. Kazemi, M. Nasiri and S. FathollahiSummaryWaterflooding has been regarded as an efficient method for pressure maintenance of oil reservoirs. x Improved techniques such as Smart Water flooding as a new EOR/IOR process has gained more momentum based on the recent research activities in this field and the reduction of oil price. Despite many efforts on achieving the governing mechanisms of Smart Water flooding in many individual fields, most of data are sparse and more possible mechanisms which explains all the interactions yet to be introduced. This experimental study used a systematic laboratory framework which is based on seawater treatments at fixed ionic strength to eliminate the ionic strength effects, NaCl considered as the adjusting salt, as the injecting water. An oil-wet carbonate asphaltenic and fractured reservoir is the subject of this study. In order to investigate the impact of divalent ions in Smart Water and determining the governing mechanisms, both fluid-fluid and rock-fluid interactions are carefully studied through contact angle, IFT and pH measurements. The best Smart Water recipes from these experiments are chosen for Amott cell imbibition tests to combine all of the rock-fluid and fluid-fluid interactions of species during Smart Water injection in fractured rocks. According to the obtained results, sulfate ion has the most impact on IFT reduction for the crude oil and various Smart Water recipes and also causes the most reduction in contact angle tests. The imbibition experiments confirm these results, since the lowest recovery was obtained by removing sulfate in seawater while increasing this ion up to 4 times in seawater causes more than 8% of the ultimate recovery efficiency. The results indicated that sulfate is the most efficient divalent ion in seawater to improve the wettability alteration process for carbonate rocks during Smart Water flooding due to the expansion of electrical double layer mechanism. It is also believed that the acceleration of wettability alteration process would be mostly through rock dissolution mechanism. In addition, in the condition of high concentrations of sulfate ions, increased amount of Ca2+ and Mg 2+ concentrations and the absence of monovalent ions in the injecting water, result in significant enhancements in wettability alteration which lead to 17.5% increase in ultimate oil recovery efficiency.
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Interfacial Rheology at the Crude Oil/brine Interface - A Microscopic Insight of SmartWater Flood
Authors A. Gmira, S.M. Al Enezi and A.A. YousefSummarySmartWater flooding (SWF) has been proven as an effective and successful recovery method for carbonates, in which the injected water alters the carbonate rock wettability to produce incremental oil. Core-scale displacement experiments have demonstrated significant incremental recoveries of SmartWater in both secondary and tertiary modes and single-well chemical tracer tests have demonstrated this potential in the field at a larger scale. Still, the underlying mechanisms responsible for SmartWater wettability alteration of carbonates are not well understood. In this study, we are investigating the effect of salinity and ionic composition on a crude oil monolayer using Langmuir trough technique. Solely ions brines were used (CaCl2, MgCl2, Na2SO4, NaCl) in addition to seawater dilutions. Results confirmed the sensitivity of the interfacial monolayer to brine composition: a salinity decrease increases interfacial compressibility while sulfate and magnesium ions have shown interfaces with higher compressibility compared to sodium and calcium ions. The ultimate goal of this study is to enhance our understanding of carbonate wettability alteration by integrating interfacial rheological properties and its dependency on various parameters. These efforts will ultimately lead to additional oil recovery trough optimization of the fluid/fluid interactions involved in oil/brine/rock systems during SmartWater flooding.
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Introducing a Novel Enhanced Oil Recovery Technology
Authors C. Parsons, A. Chernetsky, D. Eikmans, P. te Riele, D. Boersma, I. Sersic and R. BroosSummaryIn this paper we present a novel Chemical EOR technique in which dimethyl ether (DME), a widely-used industrial compound is utilised as a miscible solvent in conjunction with conventional waterflooding. The end effect of the solvent’s application is an increase in oil recovery significantly greater than that typically achieved by waterflood alone.
The method of application is straightforward, taking advantage of DME’s solubility in both water and hydrocarbons: water is used as a carrier for DME during injection and upon contact with reservoir fluids, DME preferentially partitions into the hydrocarbon phase thereby swelling and mobilising the oil phase. This is followed by a DME-free water chase to recover the remaining mobile oil and DME. Residual oil saturation after sweep is reduced, significantly below that typically achieved by waterflood alone. Furthermore, the DME can be extracted from the produced wellstream fluids by distillation and/or absorption processes, and re-used for injection.
The DME Enhanced Waterflooding (DEW) technique takes advantage of the unique solubility properties of dimethyl ether to improve oil mobility and reduce residual oil saturations. Significant research into the pressure-volume-temperature (PVT) behaviour of DME and DME/crude oil mixtures has been carried out in recent years; in particular the partitioning behaviour of the solvent and mixing rules for the various mass transfer properties affecting mobility. The PVT-driven behaviour and the overall displacement efficiency of the DEW technique have been observed in core flood experiments using both carbonate and clastic core plugs.
The DEW technique can be deployed in reservoirs with different geologies, fluid properties and conditions (pressure, temperature and salinity), making its application envelope much larger than that of any of the currently available EOR technologies.
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Nanoparticle-stabilized Emulsions for Improved Mobility Control for Adverse-mobility Waterflooding
Authors I. Kim, A.J. Worthen, M. Lotfollahi, K.P. Johnston, D.A. DiCarlo and C. HuhSummaryThe immense nanotechnology advances in other industries provided opportunities to rapidly develop various applications of nanoparticles in the oil and gas industry. In particular, nanoparticle has shown its capability to improve the emulsion stability by generating so-called Pickering emulsion, which is expected to improve EOR processes with better conformance control. Recent studies showed a significant synergy between nanoparticles and very low concentration of surfactant, in generating highly stable emulsions. This study’s focus is to exploit the synergy’s benefit in employing such emulsions for improved mobility control, especially under high-salinity conditions.
Hydrophilic silica nanoparticles were employed to quantify the synergy of nanoparticle and surfactant in oil-in-brine emulsion formation. The nanoparticle and/or the selected surfactant in aqueous phase and decane were co-injected into a sandpack column to generate oil-in-brine emulsions. Four different surfactants (cationic, nonionic, zwitterionic, and anionic) were examined, and the emulsion stability was analyzed using microscope and rheometer.
Strong and stable emulsions were successfully generated in the combinations of either cationic or nonionic surfactant with nanoparticles, while the nanoparticles and the surfactant by themselves were unable to generate stable emulsions. The synergy was most significant with the cationic surfactant, while the anionic surfactant was least effective, indicating the electrostatic interactions with surfactant and liquid/liquid interface as a decisive factor. With the zwitterionic surfactant, the synergy effect was not as great as the cationic surfactant. The synergy was greater with the nonionic surfactant than the zwitterionic surfactant, implying that the surfactant adsorption at oil-brine interface can be increased by hydrogen bonding between surfactant and nanoparticle when the electrostatic repulsion is no longer effective.
In generating highly stable emulsions for improved control for adverse-mobility waterflooding in harsh-condition reservoirs, we show a procedure to find the optimum choice of surfactant and its concentration to effectively and efficiently generate the nanoparticle-stabilized emulsion exploiting their synergy. The findings in this study propose a way to maximize the beneficial use of nanoparticle-stabilized emulsions for EOR at minimum cost for nanoparticle and surfactant.
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Evaluation of Innovative Associative Polymers for Low Concentration Polymer Flooding
Authors D. Alexis, D. Varadarajan, D.H. Kim, G. Winslow and T. MalikSummaryPerformance of current synthetic EOR polymers is primarily constrained by salinity, temperature and shear which restrict their application to low to moderate salinity, low to moderate temperature and relatively high permeability reservoirs. The primary goal of the current work is to qualify recently developed associative polymers (AP) for EOR applications as well as to study their behavior in porous media. We also compare their performance with conventional non-associative polymers. In this work, we present the evaluation of several associative polymers. Two broad types of associative polymers were tested, one with a partially hydrolyzed poly acrylamide (HPAM) backbone and the other with a sulfonated HPAM backbone. The concentrations of the tested polymer vary between 75 ppm and 1000 ppm. We demonstrate the applicability of these innovative AP’s through the carefully controlled lab experiments: (1) Corefloods in sandpacks to compare the sweep behaviors with conventional HPAM’s. (2) Single phase flooding experiments are carried out in consolidated outcrop rocks to identify optimal polymer concentrations to achieve the desired in-situ resistance. (3) One dimensional displacement experiments with 8 cP and 90 cP oil are carried out in both unconsolidated and consolidated rocks at different temperatures to validate improved oil recovery. Results generally indicate that associative polymers require lower polymer concentration to generate high resistance factors in porous media and have stable long term injectivity behavior in high permeability rocks (>1D). Associative polymers with HPAM backbone have better filterability and injectivity in comparison to those with HPAM sulfonated backbone in low permeability (<300mD) rocks. Improved oil recovery in high permeability rocks compare well with conventional HPAM and sulfonated HPAM polymers. Based on the laboratory results, we are able to establish the selection baseline for associative polymers in different permeability rocks, salinities and temperatures. Such information can be used to select and screen the appropriate associative polymers, resulting in extending their applicability envelope in EOR.
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How Much Polymer Should Be Injected during a Polymer Flood? Review of Previous and Current Practices
By R.S. SerightSummaryThis paper provides an extensive review of the polymer concentrations, viscosities, and bank sizes used during existing and previous polymer floods. On average, these values have been substantially greater during the past 25 years than during the first 30 years of polymer flooding field activity. Reasons for the changes are discussed. Even with current floods, a broad range of polymer viscosities are injected—with substantial variations from a base-case design procedure. Extensive discussions with operators and designers of current polymer floods revealed substantial differences of opinion for the optimum design of polymer floods. This paper examines the validity of arguments that are commonly given to justify deviations from the base-case design. For applications involving viscous oils (e.g., 1000 cp), the designed polymer viscosities have sometimes been underestimated because of (1) insufficient water injection while determining relative permeabilities, (2) reliance on mobility ratios at a calculated shock front, and (3) over-estimation of polymer resistance factors and residual resistance factors. In homogeneous reservoirs, the ratio of produced oil value to injected fluid cost is fairly insensitive to injected polymer viscosity (up to the viscosity predicted by the base-case method), especially at low oil prices. However, reservoir heterogeneity and economics of scale associated with the polymer dissolution equipment favor high polymer viscosities over low polymer viscosities, if injectivity is not limiting.
Injection above the formation parting pressure and fracture extension are crucial to achieving acceptable injectivity for many polymer floods—especially those using vertical injectors. Under the proper circumstances, this process can increase fluid injectivity, oil productivity, and reservoir sweep efficiency, and also reduce the risk of mechanical degradation for polyacrylamide solutions. The key is to understand the degree of fracture extension for a given set of injection conditions so that fractures do not extend out of the target zone or cause severe channeling. Many field cases exist with no evidence that fractures caused severe polymer channeling or breaching the reservoir seals, in spite of injection above the formation parting pressure.
Although at least one case exists (Daqing) where injection of very viscous polymer solutions (i.e., more viscous than the base-case design) reduced Sor below that for waterflooding, our understanding of when and how this occurs is in its infancy. At this point, use of polymers to reduce Sor must be investigated experimentally on a case-by-case basis.
A “one-size-fits-all” formula cannot be expected for the optimum bank size. However, experience and technical considerations favor using the largest practical polymer bank. Although graded banks are commonly used or planned in field applications, more work is needed to demonstrate their utility and to identify the most appropriate design procedure.
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Application of New Tracer Technologies for Surveillance of EOR and IOR
Authors O.K. Huseby, S.K. Hartvig, K. Jevanord and Ø. DugstadSummaryRecent advances of tracer technology have induced a step-change in surveillance opportunities for EOR and IOR projects. Two particularly interesting methodologies, both targeting assessment of how remaining oil saturation can be minimized, are the partitioning inter-well tracer test (PITT) and the single-well chemical tracer test (SWCTT). Upon completion of a SWCTT or a PITT, the remaining oil saturation (ROS) can be estimated from this time-lag and the partitioning coefficient, through a simple relation. Regarding PITTs, new and stable, oil-water partitioning tracers were developed and has now matured into a well-established methodology applicable for a wide range of reservoir conditions. For SWCTTs, new and significantly improved tracers were recently applied in the field and pilot testing demonstrated that required tracer amounts are reduced from tonnes to grams. The reduction in required tracer amounts solves several operational and logistical issues. It also allow for injection of several tracers simultaneously, without compromising the chemical composition of the reservoir fluids. The tracers can be designed to span a wide range of partitioning coefficients. By analysis of interpretation of the production curves from the individual partitioning tracers, an in-situ assessment of fractional flow and how EOR chemicals can affect this fractional flow, can be made.
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Improved Method for Inter-well Partitioning Tracer Response Interpretation
Authors S.P. Busch, D.W. van Batenburg and C.P.J.W. van KruijsdijkSummaryThe partitioning inter-well tracer test (PITT) is a method to determine average oil saturation between an injector-producer pair. Tracer tests can be used to quantify incremental oil recovery in enhanced oil recovery (EOR) pilots and for reservoir surveillance purposes. Various interpretation methods can be applied: peak arrival time comparison, Residence Time Distribution Analysis (RTDA), extrapolation methods and projection methods. Various sensitivities influence the outcome, accuracy and consistency of these methods. First and foremost, reservoir geometry and heterogeneity have significant impact on the shape of the tracer response curve, and on the accuracy of the subsequent oil saturation estimation. The presence of multiple flow paths can be clearly identified from tracer responses and oil saturation of each flow path can be determined individually by use of extrapolation and projection methods. Thus, potential permeability baffles or barriers can be identified and static reservoir models can be improved by evaluating tracer response data. Further key sensitivities are sampling duration, sampling frequency and measurement errors. An incomplete tracer response can lead to significant loss of accuracy of oil saturation determination by RTDA. A low sampling frequency has severe impact on the accuracy of oil saturation estimation, especially if large measurement errors are present. For timely execution of an EOR project, an early estimation of oil saturation is desirable. In this study, a new and robust analytical projection method is proposed that enables early time estimation of oil saturation based on limited data. The projection method is based on a translation of the non-partitioning tracer response curve to the partitioning tracer curve using a time and amplitude scalar. Robustness of this method is achieved by performing a least squares optimization that takes into account all available data in order to find optimal fitting time and amplitude scalars for tracer data translation. This projection method provides accurate early time oil saturation estimations based on limited partitioning tracer data. Especially if responses are incomplete, contain multiple peaks caused by reservoir heterogeneities, have a low sampling frequency and contain large measurement errors, the least squares projection method provides a more accurate oil saturation estimate than the other methods.
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New Fluorescent Tracers for SWCTT
Authors T.B. Brichart, M.O.M. Ould Metidji, L.F. Ferrando-Climent and T.B. BjørnstadSummaryTracer technology is a tool mostly uses to monitor mass flow in various systems. In the context of reservoir monitoring, and when used during a Single Well Chemical Tracer Test (SWCTT), tracers can provide information on residual oil saturation (SOR) in the near-well zone.
Although effective, today’s single-well tracers suffer from important drawbacks. Current technology consists of simple esters such as ethyl acetate which need to be used in large quantities to be detected properly by highly qualified workers.
With its ease of use, luminescence seems to be a promising substitute to current technics. Although the oil intrinsic luminescence may be looked upon as a difficulty, time-resolved spectroscopy offers a way to circumvent it, without generating too much drawbacks.
Lanthanide chelates have gained a lot of traction over the last decade in several fields including tracers (e. g. in medicine). They are versatile and it is possible to adapt, modify and customize so that they conform to specified requirements in term of interactions and stability. In this manner, it is possible to produce potential replacement candidates for today’s SWCTT tracers.
This study explores luminescent tracers currently being designed for SWCTT, their possibilities, future developments and applications for SOR measurements.
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Integration of Analytical and Simulation Techniques to Estimate Uncertainty in Incremental Oil Recovery from SWCTTs
Authors D.J. Robbins and G.R. JerauldSummarySingle well chemical tracer tests (SWCTTs) are the first measure of potential enhanced oil recovery (EOR) response in a reservoir. This paper presents a workflow of integrating classical tracer analysis techniques with reservoir simulation modelling for understanding of the impact of pertinent non-ideal physical effects on the estimated incremental oil saturation. In particular, we introduce an extension of the direct shift method to quantitatively estimate co-injected product alcohol and the extent of gas stripping of the ester and a new type curve method for matching raw tracer data. As the reservoir simulation model of the SWCTT is under-constrained, a Monte Carlo iterator is employed to determine the distribution of oil saturation values that adequately describe the observed tracer data with unbiased sampling of the variable space. It is observed that the distribution of oil saturations derived from simulation models is not necessarily Gaussian. We show an example of a pair of SWCTTs performed in an onshore US field to determine the response of the field to a low salinity water treatment. The observed P50 estimate of incremental oil saturation is 5 saturation units, with a positively-skewed distribution biased towards larger values of incremental oil saturation.
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Robust Dynamic Modelling of the Impact of Chemical Flood Implementation Time on Ultimate Recovery and Net Present Value
Authors A.J. Alshehri, M. A. Algeer and A.M. AlkhatibSummaryChemical EOR (CEOR) methods such as polymer-surfactant flooding are used to reduce oil trapping and mobilize remaining oil. This trapping is mainly a resultant of capillary trapping associated with waterflooding. Hence, it is believed that earlier implementation of CEOR post water-flooding will result in higher oil recovery, as the impact of capillary trapping will be less prominent in this case.
One of the main challenges associated with CEOR flooding is the high implementation cost. Earlier implementation results in higher cost, hence defining the optimum implementation time necessities evaluating both ultimate recovery and Net Present Value (NPV). This study investigates the effect of post-waterflood implementation time of surfactant-polymer flooding on ultimate recovery and (NPV) - given this capillary trapping – in order to determine the optimal implementation time while maximizing the dual objectives of NPV and ultimate recovery.
CEOR has been identified as an effective EOR method which is usually implemented in tertiary mode, where field development has reached a mature level. At this stage, the efficiency of waterflooding in terms of mobilizing remaining oil declines due to capillary trapping. Although this EOR process have been implemented in tertiary mode, experimental results of earlier implementation have shown more desirable effect on recovery because capillary trapping is less prominent.
This study investigates impact of post-waterflood implementation time of surfactant-polymer flooding on ultimate recovery and (NPV) given this capillary trapping. A series of numerical experiments were conducted to test this effect while accounting for operating expenses associated with both flooding options. Capillary pressure curves for the waterflood case and the chemical flood case were added to incorporate capillary trapping effects. Then, the chemical-flood implementation time was varied to evaluate its impact on the ultimate oil recovery and NPV These experiments were performed on 2 stylized reservoir models: the PUNQ-S3 and SPE10 reservoir models.
In a previous work, we have only covered the static properties. A pronounced impact was seen on the NPV however no drastic changes were recorded on the ultimate recovery. In this study, we implement a robust model accounting for all dynamic properties associated with varying the implementation time of CEOR flooding including effects on the relative permeability.
In general, the sooner chemical EOR is implemented the higher the ultimate recovery of the process. Also, results show that the optimum implementation time – based on NPV values - is function of reservoir heterogeneity, as the more heterogeneous model has earlier optimum implementation time.
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Modeling Waterflood Sweep Improvement at Prudhoe Bay and Determining Key Controls on Incremental Oil Recovery
Authors P.K. Singh, G.R. Jerauld, D.R. Thrasher, J.S. Isby, D. Nottingham, D.H. Ohms, B. Stechauner, G. Stechauner and H. FramptonSummaryWe present a model of how a Thermally Activated Particle (TAP) system works and model the incremental response of a pattern in Prudhoe Bay, Alaska. The model has also been applied on a range of descriptions to determine the major controls on incremental oil recovery and the best circumstances to apply TAP.
Polymeric “kernel” particles expand as a result of breaking labile cross-links through a hydrolysis reaction under the influence of temperature and time. The expanded particles adsorb and provide Residual Resistance Factor to water. The model builds on conventional reservoir simulation of cold water injection and polymer flooding by including reaction kinetics of the particles and the dependence of reaction rate and other polymer properties on temperature as well as the extent of reaction. To address the uncertainty in the mechanisms, the model considers both mechanical entrapment and physical adsorption, linking the amount and impact of the entrapment to the ratio of the particle size to the estimated pore-throat size.
Previously reported slim tube data and recent coreflood studies on Prudhoe Bay core indicate physical adsorption to be the dominant mechanism. The application of the model to the treated pattern captures the timing and magnitude of the incremental response. The overall size and the resistance of the in-situ block are comparable to that interpreted from the Pressure Fall-Off analysis.
Realistic type pattern models and idealized descriptions have been used to model TAP performance for a range of slug sizes and waterflood maturities. The primary controls on incremental oil recovery are the slug size, pattern maturity, mobility ratio and heterogeneity. Traditional measures of heterogeneity do not correlate well with incremental recovery. Instead, the best correlations appear to be with the ratio of the swept volume, at breakthrough, to the total pore-volume and the slope of cumulative water-oil ratio to the instantaneous water-oil ratio, with larger slopes indicating better candidates.
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Capital Rationing by Metrics - Implications for IOR/EOR-projects
More LessSummary(1) Overview
The recent fall in the oil price has given rise to a renewed focus on other parameters for project selection that the net present value (NPV). A regime with capital constraints is introduced, implemented by key metrics like the Internal Rate of Return (IRR), the Net Present Value Index (NPVI) and the Break Even Price (BEP). The paper describes metrics used by the oil companies to ration capital, and analyse implications for IOR/EOR projects.
(2)Method
We examine the different investment metrics of a portfolio of oil projects and check how they affect ranking of projects. Particular attention is paid to IOR/EOR-projects. After the increased volatility of the oil price, more emphasis has been placed on the breakeven price. We analyse how IOR/EOR-projects are affected in their ranking - towards other types of projects - of this decision criteria. We also address how the current Norwegian petroleum tax system affects the possibility to sanction marginal IOR/EOR-projects.
(3)Results
The project metrics analysis shows that the overall grouping of the projects is the same with the three metrics for capital rationing. The highest ranked projects are the same for the l3 first projects with individual order ranking the same. This is also the same for the 6 worst projects. Projects 14 to 21 are the same for the three metric rankings but their individual ranking differ somewhat. The company focus on robustness related to oil price gives particular attention to break-even price and cost optimisation. Capital rationing may severely affect marginal IOR/EOR-project, but the choice of rationing metric is not significant. The Norwegian petroleum tax system is not well designed to secure implementation of marginal IOR/EOR-projects.
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Optimization of Alkaline-Surfactant-Polymer (ASP) Flooding Minimizing Risk of Scale Deposition
Authors O. Vazquez, I. Fursov, A. Beteta and E. MackaySummaryAlkaline-Surfactant-Polymer (ASP) flooding, which is classified as chemical EOR (Enhanced Oil Recovery) technique, has a great potential to recover an additional 10–25% of the oil in place, as demonstrated during various field pilot tests. A typical ASP flooding comprises of three stages: main ASP slug, polymer post slug and finally a water slug. The surfactant reduces the interfacial-tension between the displacing fluid and oil, the alkaline reduces the surfactant adsorption and creates in-situ natural surfactant, and the polymer decreases the water to oil mobility ratio. However, the deposition of inorganic scales directly attributed to geochemical processes during ASP flooding can significantly impact the viability of ASP floods.
ASP flooding has economic limitations due to the large volumes of chemicals injected. Therefore, technical and economical feasibility of ASP flooding depends on the effective use of the injected chemicals and slug formulation. The main purpose of this paper is to describe the automatic optimisation of ASP flooding designs using an optimization algorithm, in particular, PSO (Particle Swarm Optimization). The algorithm identifies the most efficient optimum ASP design for a given set of criteria, specifically minimizing the total chemical expense and the scaling risk, and maximizing the oil revenue and NPV (Net Present Value).
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Joint Optimization of Field Development and Water-alternating-gas Recovery Strategies
Authors T. Feng, O. Leeuwenburgh, C. Hewson and R.G. HaneaSummaryAlternating injection of water and gas (WAG) has been widely applied as an oil recovery strategy since the late 1950s. The expected benefits are improved macroscopic sweep, with the water and gas sweeping lower and upper zones of the reservoir respectively, and improved microscopic sweep due to various effects leading to lowering of the residual oil saturation. Benefits on the microscopic scale are expected especially if the injected gas is miscible with the oil. WAG has been applied to various North Sea assets such as Snorre, Statfjord and Gullfaks.
WAG strategies are typically designed using trial simulations of different scenarios. For fields with many wells it is not generally possible to design an optimal strategy without the use of approaches to systematically explore alternative strategies. Mathematical optimization theory provides such methods. Previously, we have applied such methods to determine optimal drilling sequences for new field developments for a number of Norwegian assets under uncertainty. Here we apply similar concepts to additionally optimize the optimal injection and production strategies for drilled wells.
The development period may take a number of years if many wells are to be drilled, leading to time-varying capacity to (re-)inject gas that is difficult to take into account when the order in which injectors become available is not a priori fixed. Therefore we investigate alternative approaches to characterize WAG strategies during the field development stage, namely switching time controls and injection type controls, also in combination with injection rate controls.
We present a number of examples of numerical experiments for a representative test model. Multiple geological realizations of the model are used to represent the uncertainty. Results indicate that significant improvements in economic returns can be obtained through optimization relative to reasonable base strategies, also if the WAG strategy is optimized for a fixed drilling sequence. We show that not only the expected value can be increased, but that also the value for the worst performing realizations can be improved, thereby reducing risk. Finally, we provide physical interpretations of the optimal strategies in support of decision maturation.
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Value of Information from History Matching - How Much Information is Enough?
Authors A.J. Hong and R.B. BratvoldSummaryWith the rapid increase in computing power over the past several decades, automatic or semi-automatic approaches to history matching (HM) have become viable replacements for the traditional manual HM approach. HM approaches now include robust and efficient numerical algorithms with the ability to account for geological and petrophysical uncertainties. Downhole rate and pressure data are commonly collected for the purpose of uncertainty reduction through the HM process. Although the cost required to collect such data, and conduct the HM, is significant, few companies conduct an a priori analysis of the information value from the data.
Although some studies have demonstrated the post-hoc value of HM data, few have demonstrated its a priori value; i.e., the assessment required to determine whether it is worthwhile investing in gathering the data and conducting the HM. In this paper, we illustrate and discuss an a priori analysis on information valuation, known as the Value-of-Information (VOI) analysis. The VOI from HM is assessed for future production data with the goal of informing the decision-maker of the potential value of investing in downhole measuring devices and HM procedures. We present the scientific basis for VOI analysis followed by an example of its implementation for an improved-oil-recovery (IOR) case. In the example, we use our proposed workflow of assessing VOI from HM to calculate the VOI from different types of production data and compare their values to distinguish between constructive and wasteful information gathering.
The contributions of this paper are three-fold. Firstly, we provide a consistent definition of VOI from production data and HM, and discuss the details of the calculations. Secondly, we propose a workflow of assessing VOI from HM. Thirdly, we present an IOR example using our proposed workflow involving the use of Ensemble Kalman Filter (EnKF) combined with Robust Optimization (RO) to calculate the VOI. Finally, we identify and discuss the possible causes for the limited use of VOI methods in HM contexts and suggest ways to increase the use of this powerful analysis tool.
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Polymer
Authors K. Sandengen, K. Melhuus and A. KristoffersenSummaryThere exist several mentions of HPAM polymers leading to reduced end point saturation; commonly referred to as “viscoelastic effect”. Huh and Pope(2008) proposed that polymers act as to maintain oil phase continuity, meaning that an impact can only be induced before oil breaks up into discontinuous ganglia. Hence, if their proposed mechanism is correct, common tertiary mode investigations would be misleading and cannot capture the full potential effect.
The present work was therefore initiated with the aim of testing the hypothesis of Huh and Pope. A reservoir rate core flood study was performed in a “micro-CT” imaging system enabling pore scale (≈ 7 μ m) resolution of fluids. Tertiary polymer injection, did not change oil saturation, which was in agreement with the hypothesis. Thereafter oil was injected into the porous medium, which already contained polymer, to increase oil saturation. Subsequent polymer injection led to higher SOR, which was in complete contradiction to the hypothesized lowering of SOR.
The results reported herein, did consequently not fit with the expectations from the hypothesis at question. On a general basis the results do therefore not support claims that polymer flooding, due to the viscoelastic nature of the fluid, should lead to a lower SOR.
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An Original SEC Method to Assess Simultaneously Concentration and Hydrolysis of HPAM for EOR
Authors M.L. Loriau, A.B. Boufar, T.K. Ky and N.P.B. Passade-BoupatSummaryAn original SEC method to assess simultaneously concentration and hydrolysis of HPAM for EOR.
In the current condition of hydrocarbon production, future developments of chemical EOR (cEOR) productions require a specific attention to the monitoring of chemical additives. Polymer flooding or Surfactant Polymer flooding are among the most promising cEOR technologies: the polymer is used to viscosify the injection water in order to get a better mobility control within the reservoir. For those technologies, it would be very beneficial to be able to monitor easily the polymer along the process, from the injection to the back-production. There are different water soluble classes of polymers which are able to increase the viscosity, but the most common polymer used in these technologies is partially hydrolyzed polyacrylamide (HPAM). The most specific and accurate analytical methods to quantify the HPAM polymer content are based on specific amide group dosage. As a consequence, knowing the hydrolysis degree of the polymer chains is an important parameter to determine before doing the quantification. It is also a very important parameter in itself to determine the history of the polymer chains along the process. The amide group hydrolysis can occur in the reservoir, in the wells, in the surface process, depending of physical parameters, as pressure or temperature, and also of the residence time of the polymer. In addition, the hydrolysis rate depends strongly on the water pH of the geological formation. We have developed a new methodology for polymer concentration measurements by size exclusion chromatography coupled to an Ultraviolet (UV) and a Refractive Index (RI) detector. The simultaneous use of these two detectors allows evaluating the hydrolysis rate of the HPAM. As a consequence, it is possible by only one short time analyze to obtain a real HPAM concentration, considering the real amide chemical function remaining in the polymer.
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