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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 - 20 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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