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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 - 50 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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