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IOR 2019 – 20th European Symposium on Improved Oil Recovery
- Conference date: April 8-11, 2019
- Location: Pau, France
- Published: 08 April 2019
41 - 60 of 122 results
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Successful Time Lapse Seismic Pilot on Al Shaheen field (Offshore Qatar): Analysis and Practical Applications in Reservoir Monitoring
Authors G. Berthereau, R. Sanchez and M. EmangSummaryThe Al Shaheen field, offshore Qatar, is one of the world's oil largest carbonate fields currently at a production plateau of 300 000bopd with more than 300 active wells. It comprises a stacked sequence of thin layered Lower Cretaceous reservoirs. The objective of the paper is to illustrate the applicability and demonstrate the economic impact of 4D information by revisiting data acquisition, work overs, appraisal wells around monitor acquisition time.
Time lapse seismic survey (4D seismic) is a geophysical technique consisting in acquiring 3D seismic over the same area at different times. Following a conclusive 4D feasibility study, a pilot monitor survey was shot in 2015 to be compared to a base survey shot in 2007 (first oil in 1994). Aside from seismic acquisition repeatability and processing, successful 4D analysis was highly dependent on extracting meaningful 4D attribute, integration and collaboration of different geoscience disciplines.
4D analysis led to the following conclusions:
- 4D seismic response is broadly consistent between Al Shaheen carbonate reservoirs
- 4D signal associated with gas saturation changes is easily observable in a very reduced time frame:
- Sg increase associated with gas exsolution (due to unsupported production) or gas injection (WAG)
- Sg decrease associated with gas production / re-dissolution due to unsupported production before base monitor and support between base and monitor.
- 4D signal associated with water saturation increase is mostly limited to non-uniform sweep such as early water breakthrough issue.
- 4D signal associated with pressure decrease is not directly observed as quickly associated with gas exsolution whereas 4D signal associated with pressure increase is limited to producers in depletion mode converted around base monitor time into water injectors.
Current applications in reservoir management include:
- Identification of undrained / poorly supported areas based on non-uniform 4D signal associated with gas saturation changes
- Identification of early water breakthrough issue location along water injector
- reservoir surveillance plan strategy
- influencing workover strategy
- optimizing appraisal well location in order to sample sweep efficiency or investigate inter reservoir communication.
Despite 4D has been proven a successful technique in clastic environment, its applicability to carbonates fields is more challenging and depends first on rock physics and also seismic quality. Nevertheless, the 2015 seismic pilot results proved the 4D value particularly in reservoir management and consequently validated a full field 4D OBN monitoring strategy with first survey to be executed in 2019.
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A New Mechanism for Enhanced Oil Recovery by CO2 in Shale Oil Reservoirs
Authors P. Mahzari, T. Mitchell, A. Jones and E. OelkersSummaryDuring the past decade, enhanced oil recovery (EOR) by CO2 in shale oils has received substantial attention. In shale oil reservoirs, CO2 diffusion into the resident oil has been considered to be the dominant interaction between the CO2 in fractures and the oil in the matrices. CO2 diffusion will lead to oil swelling and improvement in oil viscosity. However, despite two-way mass transfer during CO2 EOR in conventional oil reservoirs, one-way mass transfer into shale oils saturated with live oils is controlled by an additional transport mechanism, which is the liberation of light oil components in the form of a gaseous new-phase. This in-situ gas formation could generate considerable swelling, which could improve the oil recovery significantly. This mechanism has been largely overlooked in the past. This study is aimed to better understand the role of this evolving gas phase in improving hydrocarbon recovery.
Taking account of Bakken shale oil reservoir data, numerical simulations were performed to identify efficiencies of EOR by CO2 at the laboratory and field scales. Equation-of-state parameters between CO2 and oil components were adjusted to optimize the calculations and a sensitivity analysis was performed to identify the role of the parameters on gas formation and consequent EOR efficiencies. At the laboratory scale, in-situ gas formation can increase oil recovery by 20% depending on the amount of gas saturation. Also, the CO2 storage capacity of the shale matrix can be enhanced by 25%, due to CO2 trapping in the gas phase. At the field scale, an additional oil recovery of 9.3% could be attained, which is notably higher than previous studies where this gas evolution mechanism was ignored. The results suggest that a 6 weeks huff period would be sufficient to achieve substantial EOR if this new mechanism is incorporated. Furthermore, the produced fluid in the early period was primarily composed of CO2, which would make it available for subsequent cycles. The produced gas of the well under CO2 EOR was used in an adjacent well, which resulted in similar additional oil recovery and hence, 10% impurities in CO2 injection stream would not undermine efficiency of this EOR method. The results of this study, therefore, could potentially be used to substantially improve the evaluations of CO2 EOR in shale oil reservoirs.
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An Approach to Miscible Injection in the Oil Rim Reservoir
Authors N. Glavnov, A. Penigin, M. Vershinina, I. Mukhametzyanov and P.L. McGuireSummaryAcross PJSC «Gazprom Neft» portfolio of technological projects an especial place is reserved for gas technologies and miscible flooding is one of them. It allows to increase production and recovery factor but also helps utilize rich gas components which otherwise would be flamed/sold without extra value. This paper discusses development options of miscible injection in oil rim reservoir.
To evaluate gas processing options multiple models in Aspen HYSYS were designed in order to increase extraction of C2–C4 fraction that is mixed with lean gas to achieve miscible displacement in the reservoir, since otherwise the only option to get rid of C2–C4 is to mix in with lean gas and sell as pipeline gas. At the beginning PVT model was designed and MME was evaluated. Having results from actual lab experiments and compositional modeling software available optimal composition of injection fluids and pressure regimes were investigated. Current and planned patterns of oilfields were studied for best injector location using 3D compositional simulator. Integrated models were built to monitor and predict produced and injected gas compositions and volumes. In addition they allowed watching for bottle-necks in production network, cryogenic plant, gas facilities and calculation of recycling volume.
Main idea was to ensure maximum economically possible extraction of C2–C4 fraction from produced gas thus obtaining fluid for miscible injection. During iterative process decision was to be made between -55 and -80O C after turbo-expander and the last one was more prominent, since it increased extraction by 35%. According to MME test, average pressure, regimes of production and available volume of gas optimal composition of miscible gas is 65% methane and is achieved by mixing C2–C4 with lean gas for a pipeline and gas cap injection. Gas utilization achieves maximum for patterns with higher OIP, number of wells and their density. WAG is considered to perform better in terms of gas utilization that in its turn leads to increased incremental oil. By choosing most efficient patterns in terms it became possible to increase recovery in these regions by 10–15%.
The paper describes the approach used to design development strategy of miscible flooding option for the oil rim reservoir. Technical details shown describe cryogenic plant design considerations, selection process of optimal injected gas composition, evolution of development strategy for the reservoir. The approach shows a way to incorporate all available data into one decision-making space in order to achieve maximum value from available resources.
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Low Salinity Evaluation in Low Permeable Sandstone Reservoirs with Intermediate Clay Content
Authors E. Hoffmann, R.E. Hincapie and L. GanzerSummaryWithin this work, we evaluate the Low Salinity Waterflooding (LSWF) effects in the German Wealden Sandstone (intermediate clay-content). Therefore, we present a comprehensive workflow that combines different experimental approaches to determine LSWF effects in oil mobilization. Experiments included fluid optimization-characterization, spontaneous imbibition and coreflooding evaluations.
The workflow comprises the following steps: 1) Detailed fluid optimization/characterization based on typical German reservoir characteristics (including oil samples, brine composition and polymer solutions)-for mobility control-, 2) Routine core analysis (such as porosity, permeability, contact-angle and pore-size distribution), 3) Spontaneous imbibition evaluations for selected fluids -to assess wettability changes-, 4) Investigation of LSWF combined with polymer in coreflooding experiments (monitoring pressure response and mobilized oil vs PV injected), 5) Assessment of Streaming-Potential response for selected cores, to link with the LWSF effects and 6) Cross-checking the acquired data by performing a quantitative and qualitative analysis.
Results of this work allowed to validate three main mechanisms out of those reported in literature: 1) Wettability Alteration (contact angle and spontaneous imbibition), 2) Fine Migration (pressure responses along with fine production), and 3) Multi-ion exchange (Streaming-Potential decline). Half of the experiments in secondary-mode depicted a higher Recovery Factor. The less saline brine LSW2 (50-times diluted FW), injected after LSW1 (10-times diluted), did not recover any additional oil. This suggested that a higher reduction in salinity should be aimed for in future investigations. Tertiary-flooding with solely LSWF, showed a lower recovery than tertiary LSWF-PF flooding. This observation confirms the potential of polymer-combined LSWF in sandstones. Streaming-Potential measurements enabled the verification of the multi-ion exchange inside the rock pores during flooding. Results have shown a declining trend in voltage response, indicating the exchange of dissolved ions with the rock surface. Moreover, results of the Spontaneous Imbibition tests refuted the Low Salinity Effect (LSE) in aged cores. On one hand, the immersion in formation water has yielded 3.2% more oil compared to LSW1. On the other hand, in the case of non-aged cores the low saline brine released additional oil.
To the best knowledge of the authors, Low Salinity Water Flooding has yet not been investigated in the German Cretaceous Wealden Formation. This investigation provided excellent insights on recovery factor in secondary and tertiary-mode. Tertiary-mode flooding experiments provided clear evidence of the advantages of LSWF-PF. This could yield that the processes -when applied in tandem- become a leading EOR strategy. Moreover, fellow researchers can benefit with the presented data and workflows.
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Importance and Inclusion of Gas Diffusion in CO2 Emulsion Population-balance Model
Authors H. Luo, G. Ren, K. Ma, K. Mateen, V. Neillo, C. Blondeau, G. Bourdarot and D. MorelSummaryUnlike conventional foams made of nitrogen or methane, CO2 emulsion exhibits more complex behaviors in porous media. For instance, CO2 emulsions are relatively weak and do not exhibit sudden loss of apparent viscosity at very high foam quality. Compared to conventional foams in porous media that capillary suction is the main mechanism of bubble coalescence, gas diffusion is significantly enhanced in CO2 emulsion, but the relative contribution of the two emulsion destruction mechanisms and how to account for gas diffusion are rarely seen in the literature. To better understand the key underlying mechanisms, a comprehensive investigation of the CO2 emulsion stability is carried out and bubble coalescence due to gas diffusion is introduced in a population-balance model. First, analytical models are set-up to evaluate the characteristic times of capillary suction and gas diffusion under the same conditions. The analytical solutions suggest that the characteristic time of gas diffusion is comparable to that of capillary suction for CO2 emulsion, while it is one to two orders longer in case of N2 foam. Based on these analyses, a foam/emulsion model is developed through incorporating an additional gas diffusion term as a function of gas solubility, diffusivity, capillary pressure, temperature and several other variables. The new foam/emulsion model is used to fit a set of experiments of CO2 and N2 foams ranging among different foam qualities in the same core. The fittings were carried out using three different selections of the coalescence terms, i.e., the capillary suction term only, the gas diffusion term only, and both terms, for N2 foam and CO2 foam. The results reveal that using the original coalescence model (only capillary suction) can fit the N2 foam data but leads to mismatch with the CO2 data, while using the gas diffusion term only leads to mismatch with the N2 foam data but better match with the CO2 foam data. Using both terms was found optimum for the CO2 emulsion model. In addition, having the gas diffusion term enables to capture the gradual change of the foam strength with foam quality for CO2 foam instead of the abrupt change of foam strength for N2 foam near the limiting capillary pressure. Our research on this subject has unveiled the fact that gas diffusion is important for CO2 emulsion instability. This methodology is a key to evaluate the feasibility of improving CO2 EOR through foaming and to optimize such a process.
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Foam to Optimize Gas Injection Development Scheme: Labs Evidence and Simulation Forecast of Gas Control Efficiency
Authors C. Topini, M. De Simoni, L. Dovera, F. Rotelli, M. Bartosek, A. Abrar, D. Renna and E. BraccalentiSummaryThe present work aims to assess the potentialities of foam in mitigating the gas injection issues foreseen during water alternating gas injection (WAG) scheme, such as premature gas breakthrough at producers and gas cycling. Main objective is to demonstrate foam efficiency for an offshore oil field by integrating extensive dedicated laboratory testing, accurate reservoir modeling and preliminary facilities feasibility, key steps for field EOR application.
The adopted workflow focused on the close integration of different analyses allowing the characterization of the different phenomena and criticalities that may arise during foam injection application.
Lab tests started with an accurate in bulk surfactants screening to identify the best performer for the candidate reservoir.
Eleven foamers were tested and the best one was selected for the following core flood tests.
Core flood tests were performed at reservoir pressure and temperature conditions. Berea cores were first flooded under WAG scheme and then adding also a buffer of the optimized foamer solution (FAWAG scheme). Core flood results showed that injection of foam decreases gas and fluid mobility. The reduction of foamer performance in presence of oil was also evaluated.
Core floods results were matched and main foam parameters were obtained to perform field scale foam injection simulations. Two sets of parameters matching the available lab data were defined. Both of them were applied providing an optimistic and a pessimistic scenario. Field scale simulations highlighted that foam injection provided a positive effect on field oil production and GOR reduction; the best scenario highlights additional reserves of about 3% after 15 years of production associated with a 30% GOR reduction.
The pre-feasibility study identified the most suitable injection scheme and it assessed no major show stoppers from flow assurance. The preliminary cost estimate per incremental barrel associated to the implementation of the technology was also done.
Main conclusion of the study was that laboratory tests, numerical simulations and preliminary facilities assessment confirm the potentialities of foam injection for the candidate reservoir.
An integrated and comprehensive workflow was set-up to estimate the efficiency and benefits of foam injection. The presented workflow is currently being applied to assess foam injection potentiality for other fields within the company's portfolio.
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Parameter Estimation of a Population-balance Foam Model Using Two-step Multi-variable Search
Authors K. Ma, K. Mateen, G. Ren, H. Luo, V. Neillo, C. Blondeau, G. Bourdarot, D. Morel, O. M'barki and Q. NguyenSummaryEvaluation of modeling techniques for foam flow through porous media requires reliable laboratory measurements. Previously, a set of experimental data points have been collected in steady-state foam flood. Significant efforts have been made to mitigate foam hysteresis and to ensure experimental repeatability in each run by properly restoring the system.
In this work, we have investigated the steady-state behavior of the Chen et al population-balance foam model in porous media. The classic Nelder-Mead search algorithm is used to estimate the foam-model parameters from the abovementioned experimental data with a variety of total fluid velocities and foam qualities. Our results show that this foam model does not correctly model the high-quality foam regime as the limiting capillary pressure is not reached. Further analysis reveals that, depending on the initial guesses, two different steady-state saturations at the same foam quality can be obtained. We have identified that the quadratic formula in the foam coalescence equation is the source of the issue, with which the same foam coalescence rate results in two saturation values. Therefore, we have resolved the problem with significantly reduced bubble density when the capillary pressure exceeds the limiting value. The improvement in this model results in physically meaningful fit to the steady-state data with a unique solution. Additionally, sensitivity studies of the parameters indicate that the trapped gas function could be combined with other parameters in the model based on our steady-state data fit.
During this investigation we have discovered that the lack of proper initial guesses frequently causes convergence issues of the Nelder-Mead search algorithm. A new two-step approach is therefore developed with a combination of direct calculation and Nelder-Mead search to estimate the foam-model parameters. The new approach greatly reduces the parameter space explored in the algorithm, thus it significantly improves the computational efficiency and the convenience of probing a suitable set of initial guesses to mitigate convergence issues.
For the first time, we have provided methodology with improved multi-variable parameter search and evaluation of hysteresis-free steady-state foam data with a population-balance foam model. The improvement in the model makes it not only correctly simulate the effect of the limiting capillary pressure but also potentially more stable in reservoir simulation practices due to the elimination of non-physical solutions.
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Screening and Uncertainty Assessment of Foam-Assisted Water-Alternate Gas Injection
Authors H. Groot, J. Groenenboom, N.I. Kechut, N.M. Rahayu Razali, S. Vincent-Bonnieu and A. Mar-OrSummaryIn a Foam-Assisted Water-Alternate Gas injection (FAWAG) process, surfactant is used to reduce the mobility of the gas by creating foam in the reservoir. This process potentially improves the performance of a Water-Alternate Gas injection (WAG) process. The effective dynamic behaviour of FAWAG can be highly complex and often stands in contrast to the behaviour of WAG. This paper presents insights in the effective dynamic behaviour of FAWAG and a comparative study of its sensitivity to uncertainties, reservoir conditions, field design and modelling assumptions, which is important for risk mitigation, opportunity realisation and process optimisation. In this paper the FAWAG process is modelled from the assumption of local equilibrium of foam creation and coalescence using an Implicit Texture model. Sensitivities to uncertainties, pattern design and reservoir screening parameters are studied to identify and analyse the key parameters impacting the FAWAG process as opposed to a WAG process and quantify the reliability of production forecasts with FAWAG. A box reservoir model is used for the study that represents a line drive pattern and can mimic a wide range of different reservoir conditions, injection strategies and pattern designs. A ranking is made of the sensitivity parameters according to their ultimate impact on oil recovery. The results are compared with the literature.
From the sensitivity study it is concluded that FAWAG is mostly sensitive to permeability and well-spacing because of the relatively low throughput rate, while in contrast WAG is mostly sensitive to reservoir heterogeneity and oil viscosity as the process requires high displacement stability. In addition, FAWAG requires high throughput rate or project duration to overcome high heterogeneity and oil viscosity in the long run. It shows that the optimal conditions for a successful FAWAG are high permeability, small well-spacing, high layer connectivity and favourable conditions for injectivity. Furthermore, FAWAG can still be expected to perform well in a reservoir with high heterogeneity and reasonably high oil viscosity, which could turn out to be detrimental conditions for iWAG. Finally, a successful FAWAG project requires optimal conditions for foam generation in the reservoir, which means foam strong enough to improve mobility control, yet not too strong to impair injectivity. However, the optimal conditions for foam at field scale often prove to be highly uncertain in practice and should be determined from field pilots or injectivity tests.
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Injectivity of Multiple Gas and Liquid Slugs in SAG Foam EOR: A CT Scan Study
SummarySurfactant-alternating-gas (SAG) is often the injection method for foam enhanced oil recovery (EOR) in order to improve injectivity. However, liquid injectivity can be very poor once foam is created in the near-wellbore region. In a previous study, we reported core-flood experiments on liquid injectivity after foam flooding and liquid injectivity after a period of gas injection following foam. Results showed the importance of the gas slug to subsequent liquid injectivity. However, the effects of multiple gas and liquid slugs were not explored.
In this paper, we present a coreflood study of injectivities of multiple gas and liquid slugs in a SAG process. We inject nitrogen foam, gas and surfactant solution into a sandstone core sample. The experiments are conducted at a temperature of 90°C with 40-bar back pressure. Pressure differences are measured to quantify the injectivity and supplemented with CT scans to relate water saturation to mobility.
We find that during prolonged gas injection in the first gas slug following foam, a collapsed-foam region forms near the inlet due to the interplay of evaporation, capillary pressure and pressure-driven flow. This region slowly propagates downstream. During subsequent liquid injection, liquid mobility is much greater in the collapsed-foam region than downstream, and liquid sweeps the entire core cross section there rather than a single finger. In the region beyond the collapsed-foam region, liquid fingers through foam. Liquid flow converges from the entire cross section to the finger through the region of trapped gas.
During injection of the second gas slug, the liquid finger disappears quickly as gas flows in, and strong foam forms from the very beginning. A collapsed-foam region then forms near the inlet and slowly propagates downstream with a propagation velocity and mobility similar to that in the first gas slug. Behavior of the second liquid slug is likewise similar to that of the first liquid slug.
Our results suggest that, in radial flow, the small region of foam collapse very near the well is crucial to injectivity because of its high mobility. The subsequent gas and liquid slugs behave like the first slugs. The behavior of the first gas slug and subsequent liquid slug is thus representative of near-well behavior in a SAG process.
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Foam Propagation at Low Superficial Velocity: Implications for Long-Distance Foam Propagation
Authors G. Yu, S. Vincent-Bonnieu and W. RossenSummarySince the 1980s experimental and field studies have found anomalously slow propagation of foam that cannot be explained by surfactant adsorption. Friedmann et al. (1994) conducted foam-propagation experiments in a cone-shaped sandpack and concluded that foam, once formed in the narrow inlet, was unable to propagate at all at lower superficial velocities towards the wider outlet. They hence concluded that long-distance foam propagation in radial flow from an injection well is in doubt.
Ashoori et al. (2012) provide a theoretical explanation for slower or non-propagation of foam at decreasing superficial velocity. Their explanation connects foam propagation to the minimum velocity or pressure gradient required for foam generation in homogeneous porous media ( Gauglitz et al., 2002 ). The conditions for propagation of foam are less demanding than those for creation of new foam. However, there still can be a minimum superficial velocity necessary for propagation of foam, except that it could be significantly smaller than the minimum velocity for foam generation from an initial state of no-foam. At even lower superficial velocity, theory ( Kam and Rossen, 2003 ) predicts a collapse of foam.
In this study, we extend the experimental approach of Friedmann et al. in the context of the theory of Ashoori et al. We use a cylindrical core with stepwise increasing diameters such that the superficial velocity in the outlet section is 1/16 of that in the inlet. N2 foam is created and stabilized by an alpha olefin sulfonate surfactant. Previously ( Yu et al., 2019 ), we mapped the conditions for foam generation in a Bentheimer sandstone core as a function of total superficial velocity, surfactant concentration and injected gas fraction (foam quality). In this study, we extend the map to include the conditions for propagation of foam, after its creation in the narrow inlet section at greater superficial velocity. Thereafter, by reducing superficial velocity, we map the conditions for foam collapse.
Our results suggest that the minimum superficial velocities for foam generation, propagation and maintenance increase with increasing foam quality and decreasing surfactant concentration, in agreement with theory. The minimum velocity for propagation of foam is much less than that for foam generation, and that for foam maintenance is less than that for propagation. The implications of our lab results for field application of foam are discussed.
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Coreflood Study of Non-Monotonic Fractional-Flow Behavior with Foam: Implications for Surfactant-Alternating-Gas Foam EOR
Authors R.O. Salazar Castillo and W. RossenSummaryFoam is able to increase gas's sweep efficiency in Enhanced-Oil-Recovery applications. A surfactant-alternating-gas, or SAG, process is usually preferred for placing foam in the reservoir. During a SAG process, foam is generated away from the wellbore, offering both good injectivity and good mobility control at the leading edge of the foam bank.
Scale-up of laboratory data for SAG to field applications remains a challenge. Direct scale-up of dynamic SAG coreflood results is unreliable because of the dominance of core-scale artifacts. Steady-state coreflood data can be scaled up using fractional-flow theory ( Kibodeaux and Rossen, 1997 ; Rossen and Boeije, 2015). However, about half the published laboratory studies of foam fractional-flow curves report non-monotonic behavior, where at some point liquid saturation Sw increases with decreasing liquid fractional flow fw. Rossen and Bruining (2007) warn that such behavior would result in foam collapse during injection of the gas slug in a SAG process at the field scale. Here we report and analyse a series of steady-state and dynamic coreflood experiments to investigate the occurrence of non-monotonic fractional-flow behavior. These corefloods vary surfactant concentration, injected gas fraction (foam quality) and total superficial velocity and are supported by CT measurements. The CT data confirm that in these cases, as foam weakens with decreasing fw, liquid saturation increases, confirming the non-monotonic fw(Sw) behaviour.
In our results, every case of non-monotonic fractional-flow behavior begins with propagation of foam from the inlet, followed by eruption of a much-stronger foam at the outlet of the core and backwards propagation of the stronger foam state to the inlet, similar to behavior reported by Apaydin and Kovscek (2001) and Simjoo et al. (2013) . This suggests that there may be more than one stable local-equilibrium (LE) foam state. The initial creation of the stronger foam near the outlet is at least in part due to the capillary end effect. It is thus not clear which LE foam state controls behaviour in a SAG process in the field.
In our results, the subsequent transition from a stronger- to a weaker-foam state, leading to non-monotonic fw(Sw) behavior, coincides with conditions for weaker foam (lower surfactant concentration, lower fw) and less-vigorous foam generation (lower superficial velocity); this agrees with the theory of foam propagation of Ashoori et al. (2012) . We discuss the implications of these findings, if confirmed to apply generally, for design of SAG foam processes.
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Isolation and Characterization of Endogenous Crude Oil Surface Active Species and their Implication in the Formulation of Surfactants for EOR
Authors V. Molinier, A. Klimenko, M. Loriau, L. Ligiero, M. Bourrel and N. Passade-BoupatSummaryIn SP (Surfactant Polymer) and ASP (Alkali Surfactant Polymer) EOR processes, the surfactant role is to reduce the oil/water interfacial tension down to extreme values (10-3 mN/m and lower). The surfactant blend has to be adapted to the specific conditions of each reservoir, i.e. to the temperature, water in place salinity and crude oil nature, through rigorous phase behavior studies. If the effects of temperature and salinity on surfactants phase behavior are well established, the impact of crude oil, and particularly of its endogenous surface active species, is much less understood.
Naphthenic acids and asphaltenes are the two crude oil components families that are usually described as having interfacial activity. Their implication in physical-chemical problems linked to surface activities, as emulsion and foam formation in separators, is well documented. However, their role in the presence of surfactants for EOR applications has been much less studied, even if ASP processes take advantage of the global contribution of naphthenic acids salts to the reduction of oil/water interfacial tension. Gaining insights on the interfacial activity of these endogenous surfactants in the presence of synthetic detergents could help select and eventually design the most efficient EOR surfactants.
In this work, several techniques have been used to isolate the surface active species of a medium-density oil: naphthenic acids have been isolated by liquid-liquid extraction, asphaltenes have been precipitated with n-heptane and global interfacial materials have been extracted by emulsification and by using the wet-silica method. These natural surfactants have been characterized from a physical-chemical (tensiometry, phase behavior in model systems) and from an analytical (mass spectrometry) point of view. The phase behavior of EOR surfactants with the crude oil cleared from these components has also been studied, with and without alkali. All these experiments allowed confirming the surface activity of these crude oil extracts. Moreover, their contributions to the interfacial activity in the presence of EOR surfactants have been evaluated and compared, which gives some insights on the role of these species in surfactant formulation optimization.
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Modeling Alkali-Polymer Corefloods in Viscous Oil
Authors A. Perez-Perez, C. Romero, A. Klimenko, E. Santanach, G. Bourdarot and I. BogdanovSummaryThe injection of alkali in acidic viscous oils is known to promote the in-situ formation of emulsions during chemical oil recovery. Naphthenic acid components react with the alkali to form in-situ surfactants, which support oil emulsification at the water-oil interface. Experimental observations confirm that emulsification and transport of the dispersed oil in presence of polymer can improve oil recovery significantly.
In this work a new mechanistic non-equilibrium model is proposed to simulate Alkali-Polymer processes (AP) for viscous oil. The model takes into account emulsion generation kinetics, polymer and emulsion non Newtonian viscosity through a straightforward modelling strategy. In this model, the emulsified oil is treated as a dispersed component in water phase, while water mobility is represented by an apparent water viscosity containing dispersed oil and polymer. Shear rate effects were considered for both polymer and emulsion viscosities and viscous fingering was included using the effective fingering model developed recently at the University of Texas to retrieve the initial condition after secondary water flood/polymer flood process.
Seven Alkali-Polymer (AP) corefloods were successfully history-matched using this new approach to interpret AP corefloods mainly as a tertiary recovery process. Different alkali types were evaluated at different concentrations and slug sizes. In all cases, a high molecular weight partially hydrolyzed polyacrylamide (HPAM) was used as polymer. Oil viscosity was between 2000–3500 cP @ 50°C.
Numerical results show that the proposed model is capable of appropriately matching oil production, total pressure drop and oil cut, when the oil bank formed at emulsion breakthrough is composed by non-emulsified oil and dispersed oil. Kinetics obtained by history match indicate that emulsions can be generated at different rates depending on the choice of the alkali and that emulsion properties will also change depending on the alkali type. This development provides to our knowledge, one of the first alkali-polymer models to take into account the unstable displacement framework and modified water phase non Newtonian viscosity including emulsion and polymer.
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Evaluation and Prediction of Emulsion Formation in Produced Fluids during an ASP Flood Applied to a Carbonate Reservoir in Kuwait
Authors A. Qubian, S. Adkins, H. Al-Enezi and M. DelshadSummaryThis work is concerned with the nature of produced fluids resulting from ASP injection in a carbonate reservoir in Kuwait. The main objective is to examine and identify the nature of produced emulsions at conditions and chemical concentrations that are predicted by numerical simulation studies of the ASP pilot. The laboratory element of the work provides emulsion handling insight before the pilot begins, to reduce potential downtime and production costs.
Laboratory tests and numerical simulations were used to identify the nature of the produced fluids. The simulations used a pilot-scale model to determine realistic ranges of chemical concentrations. The laboratory study used these pre-determined concentration ranges to form, observe, and characterize the emulsions. Key variables that increase emulsion formation and stability are determined. Variables studied include total surfactant concentration, surfactant ratio, polymer, effects of crushed core, temperature, pH, salinity, and viscosity.
O/W and W/O emulsions were formed with a typical emulsion stability pattern of sedimentation followed by coalescence. The emulsion stability varied with conditions. The conditions leading to the most-stable and problematic emulsions included high surfactant, high polymer concentrations, low temperatures, and high salinity. Dense, creamy emulsions were the most stable. When surfactant concentration was increased, interfacial tension decreased, stability increased, and water and oil qualities decreased. A low interfacial tension allowed smaller (more stable) droplets to form, slowed sedimentation, and if low enough stabilized drops against coalescence. As polymer concentration increased, the aqueous viscosity increased and slowed sedimentation, water quality increased, and oil quality decreased. Shearing the polymer (reducing the viscosity) increased sedimentation. Emulsion stability decreased markedly when the temperature was increased. Sedimentation and coalescence were faster, giving an improved oil quality. Lower oil/water viscosities and densities, plus higher thermal energy destabilize the emulsions.
Pilot recommendations: At low surfactant concentration, adequate residence time in the separator is needed, where the phases exiting will be easier to break. For higher surfactant concentrations, in-field bottle-testing of stable, dense emulsions is needed to select a chemical demulsifier and neutralize the surfactant. The success of chemical EOR pilots can be jeopardized due to the formation and stability of produced emulsions. Increased downtime and unplanned mitigation costs may ruin a pilot. Limited ASP emulsion handling resources are available in industry due to the limited ASP pilots made public worldwide. This work provides additional produced emulsion resources and investigations before the pilot begins and also addresses new challenges in a carbonate reservoir ASP flood.
AbstractThis work is concerned with the nature of produced fluids resulting from ASP injection in a carbonate reservoir in Kuwait. The main objective is to examine and identify the nature of produced emulsions at conditions and chemical concentrations that are predicted by numerical simulation studies of the ASP pilot. The laboratory element of the work provides emulsion handling insight before the pilot begins, to reduce potential downtime and production costs.
Laboratory tests and numerical simulations were used to identify the nature of the produced fluids. The simulations used a pilot-scale model to determine realistic ranges of chemical concentrations. The laboratory study used these pre-determined concentration ranges to form, observe, and characterize the emulsions. Key variables that increase emulsion formation and stability are determined. Variables studied include total surfactant concentration, surfactant ratio, polymer, effects of crushed core, temperature, pH, salinity, and viscosity.
O/W and W/O emulsions were formed with a typical emulsion stability pattern of sedimentation followed by coalescence. The emulsion stability varied with conditions. The conditions leading to the most-stable and problematic emulsions included high surfactant, high polymer concentrations, low temperatures, and high salinity. Dense, creamy emulsions were the most stable. When surfactant concentration was increased, interfacial tension decreased, stability increased, and water and oil qualities decreased. A low interfacial tension allowed smaller (more stable) droplets to form, slowed sedimentation, and if low enough stabilized drops against coalescence. As polymer concentration increased, the aqueous viscosity increased and slowed sedimentation, water quality increased, and oil quality decreased. Shearing the polymer (reducing the viscosity) increased sedimentation. Emulsion stability decreased markedly when the temperature was increased. Sedimentation and coalescence were faster, giving an improved oil quality. Lower oil/water viscosities and densities, plus higher thermal energy destabilize the emulsions.
Pilot recommendations: At low surfactant concentration, adequate residence time in the separator is needed, where the phases exiting will be easier to break. For higher surfactant concentrations, in-field bottle-testing of stable, dense emulsions is needed to select a chemical demulsifier and neutralize the surfactant. The success of chemical EOR pilots can be jeopardized due to the formation and stability of produced emulsions. Increased downtime and unplanned mitigation costs may ruin a pilot. Limited ASP emulsion handling resources are available in industry due to the limited ASP pilots made public worldwide. This work provides additional produced emulsion resources and investigations before the pilot begins and also addresses new challenges in a carbonate reservoir ASP flood.
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Why is it so Difficult to Predict Polymer Injectivity in Chemical Oil Recovery Processes?
Authors A. Thomas, M.A. Giddins and R. WiltonSummaryPolymer injection to improve and/or accelerate oil recovery is a widespread technique with numerous ongoing and successful projects. In recent years, many field cases have been reported with injected polymer viscosity ranging from 5 to 160cP, producing large incremental oil volumes, without major injectivity issues. These field results often contradict pessimistic predictions of injectivity from prior studies. Despite abundant publications on the subject, there is no standard explanation of the reasons for discrepancies between forecast and actual behavior, and many questions are not yet fully answered. Will it be possible to inject the polymer solution at target viscosity? How much to inject? How fast? Will high pressures lead to fracturing or polymer degradation? Should the polymer solution be pre-treated, pre-sheared? What should be done if planned injection rates are not achievable? Will injectivity decline over time? These questions are very topical when it comes to building a business case for EOR, using 3D reservoir simulation models for forecasting production and calculating the economics of the project. In this paper, we present a critical review of selected field cases from the literature, analyzing reservoir characteristics and development history as well as properties of the injected solution. We discuss the mechanisms which can affect injectivity, including polymer solution rheology, near-well flow regimes, reservoir heterogeneity and geomechanical effects, and how these mechanisms can be represented in reservoir simulation models. Based on this investigation, we propose appropriate methodologies for dynamic modeling of polymer injection, considering the impact on predicted flow behavior of assumptions about polymer physics, selection of key parameters for sensitivity studies and the issues of upscaling from core experiments to the field. We suggest guidelines for using laboratory measurements and field observations, and for implementing forecasting workflows. Finally, we make recommendations on designing a practical field injection and monitoring program, to obtain data for calibrating models and improving future predictions.
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Analysis and Simulation of Polymer Injectivity
Authors J.G. Jacobsen, M. Alzaabi, S. Tormod, K. Sorbie and A. SkaugeSummaryPolymer flooding is one of the most successful and mature chemical EOR methods. Qualification programs, which often include injectivity and/or performance pilots, are a prerequisite to reduce risk in further implementation. The former being typically pressure fall-off tests and the latter single well tracer tests (SWTT). However, limited work has been conducted on assessing interpretability and uncertainty associated with these tests. This is something of a paradox since investments to perform these pilots are large and implications of successful versus failed pilots are enormous.
In field tests, only injection bottom-hole pressure (BHP) and volumetric injection rate are the available parameters to determine polymer in-situ rheology. In addition, analysis of pressure fall-off tests for polymer injections are far more complex compared to water and gas due to the non-Newtonian behavior of the polymer. The following question remains: what rheological information is actually obtainable based solely on BHP? Moreover, how sensitive is polymer rheology estimation to uncertainties in pressure measurements? Can high uncertainties in pressure data completely distort the rheological information obtained? Lastly, is pressure response from the near wellbore region sufficient to obtain accurate estimations of polymer injectivity in porous media?
The aforementioned issues are investigated herein by modelling pressure fall-off tests using the STARS simulation tool (CMG). Generic field data were used to design a near-well sector and a high molecular weight partially hydrolyzed polyacrylamide (HPAM) was used as polymer reference. Here, the influence of different polymer rheological behaviors on BHP and BHP-transient was analyzed and identified.
Influence of pressure measurement noise on polymer rheology was evaluated using the automated history-matching tool CMOST (CMG) for lab scale simulations. A recently developed history match method, based on pressure measurements from internal pressure taps distributed between injector and producer, was used. Even though results showed deviations from a generic (base case) rheology curve for individual rates, the arithmetic average of these curves displayed negligible deviation from its generic behavior below a threshold noise level. Moreover, simulations show that polymer injectivity is solely dependent on polymer behavior in the near wellbore region. Finally, two different flood experiments using the same HPAM polymer were history matched and results confirm the conclusions suggested in the simulation study.
This paper provides additional interpretational anchoring for pressure fall-off test for polymer injectivity assessments. Additional methods and insights developed in this paper should both improve experimental design and reduce implementation risk for polymer flood projects.
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A Scientific Approach for Generating a Rheology Model to Simulate Polymer Injectivity
Authors D.C. Raharja, D. Prasad and C. MittelbachSummaryModelling polymer injection at near-wellbore conditions is challenging, as it is strongly affected by Non-Newtonian polymer rheology among other parameters. During polymer injection, viscosities vary significantly near the wellbore where flow velocities and therefore shear rates are high. Current commercial reservoir simulators have limited capabilities in capturing this behaviour. Modification of properties on each grid around the injector including reducing fluid viscosity, increasing permeability along with building extremely fine grid is often performed in the simulation. However, this results in limited prediction capability and will be inefficient for full field simulation where multiple injectors with different properties and rates must be considered. This paper presents both; a workflow to generate an appropriate rheology model using viscometer and core flood data, and polymer injectivity simulation.
Viscosity vs. shear rate and viscosity vs. velocity data has been generated from rheometer and core floods at different velocities respectively. Data is then plotted together after converting core flood velocities into shear rate. A correction factor is established by matching viscosity at high shear rate regimes. Based on this, a rheology model for highly shear thinning biopolymer Schizophyllan was generated using Carreau-Yasuda correlation. The rheology model was then used to simulate and match the bottomhole pressure (BHP) response of a recently conducted single well test in 2017 using conceptual radial and actual Cartesian grid model. The matching was achieved with and without grid refinement for the Cartesian model while correcting the skin factor for the grid size (Behr et al.). Matching exercise required numerical tuning due to highly shear thinning behaviour. Additionally, the same rheology model was validated by matching the multi-well pilot injector BHP for a longer period without any near wellbore modification. In contrast, earlier matching attempts had required multiple modifications in either viscosity or permeability at different time periods with progressing flood.
The newly generated rheology model accounts for both viscometer and core flood data and represents the polymer behaviour much closer to reservoir performance. The results from the single- and multi-well polymer injection simulation showed a decent history match without any near wellbore grid property modification.
The workflow to generate a rheology model and deriving a shear correction factor is relatively novel for this biopolymer. The advantage of such a rheology model becomes more distinct for the simulation and history matching of a full field scale polymer injection with multiple injectors, as the overall process can be simplified.
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Modeling of Associative Polymer Flow in Porous Medium
Authors A. Lohne, A. Stavland and R. Reichenbach-KlinkeSummaryPrevious core flood investigation of acrylamide-based polymers with associative thickening properties indicated in-situ flow resistance factors (RF) significantly higher than experienced with non-associative polymers having similar bulk rheological properties. Here we propose a novel model for associative polymers which handles the formation of an in-situ polymer network and captures its properties in different flow regimes and at various polymer concentrations. The model is implemented in an in-house black-oil simulator and will allow more robust core-to-field scaling of laboratory results.
The modeling is validated by simulating a set of core experiments conducted with the same polymer but with different concentrations.
In the experimental study the polymer was injected at variable flow rates into dual serial mounted cores with 100 % water saturation. The results are compared with results obtained with a non-associative polymer with similar bulk rheological properties. The increased flow resistance due to injected polymer was observed to propagate as two fronts. The first front had flow resistance consistent with measured bulk viscosity and a velocity typical for non-associative polymer, while the second front had up to two order of magnitude higher RF and the velocity was lower and dependent on the injected polymer concentration. Another characteristic observed for these types of polymer is the moderate sensitivity of the steady-state pressure drop to changes in the flow rate.
In the proposed model, the associative polymer is treated as a mixed polymer system consisting of a smaller fraction rich in hydrophobic groups and a larger fraction with properties like a regular synthetic polymer. For both fractions, we include typical rheological behavior observed for regular synthetic polymers in flow regimes; shear thinning, shear thickening (elongational flow) and mechanical degradation when going from low to high shear rate. The formation of a pore filling network is modelled as a shear rate dependent retention of the smaller hydrophobic fraction and its additional flow resistance is obtained using a Carman-Kozeny approach.
Simulations of the experiments conducted with 100 % Sw demonstrate that the model can reproduce observed effects like pressure front velocities at different polymer concentrations and responses in RF to rate variations. The model was also applied to two-phase experiments. Effect of water saturation was included in appropriate terms and the RF in presence of oil is captured. Finally, we demonstrate how temperature dependent associative behavior can be utilized at the field scale in a simple large-scale model.
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Flexible Coiled Polymer Dynamics in a Single Pore Throat with Effects of Flow Resistance and Normal Stresses
Authors E. Eguagie, S. Berg, J. Crawshaw, S. De and P. LuckhamSummaryWe investigate the challenges involved in the use of polymer flooding as a chemical enhanced oil recovery (cEOR) technique for improving mobility ratio and enhancing macroscopic sweep efficiency. Flexible coiled polymers in porous media undergo stretching in a spatially heterogeneous structure. Due to the viscoelasticity of these polymers, they stretch continuously depending on their previous deformation until their elastic limit is reached and relaxation occurs. Previous research has proposed that at a certain critical flow rate, the relaxation of polymers cause an increase in viscosity and in turn a better mobility for enhancing microscopic sweep in porous media. However, others have reported that the increased viscosity in porous media is not so much related to the elasticity but more on the normal stresses that occur when polymers are sheared in porous media flow. One similar fact is that as increased viscosity is observed an enhanced pressured drop occurs and the flow becomes highly unstable even at laminar flow regime. This unstable flow is termed the elastic instability or turbulence but the details of this kind of turbulence, its consequences and applicability on the impact of oil recovery is not understood. In this work, we experimentally investigate the flow behaviors of flexible coiled polymers of hydrolyzed polyacrylamide (HPAM) based on a single pore throat geometry using a microfluidic device. The aim is to adequately parameterize the effects of the normal stress difference in shear and extension as a function of the geometry and intrinsic characteristics of the polymer solutions at different Deborah (De) numbers. Hence, we carry out pressure drop and particle image velocimetry experiments and results showed a critical De at which polymer viscosity increases as well as the normal stress difference. It was also observed that the flow resistance might be a function of both the elasticity and the normal stresses in shear flow, however, extensional stresses cannot be neglected.
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Novel Insights on the Transport of HPAM Solutions in Low Permeability Porous Media: Impacts of Brine and Reservoir Properties
Authors I. Guetni, C. Marlière, D. Rousseau, I. Bihannic, M. Pelletier and F. VilliérasSummaryChemical EOR is now considered as an attractive option for low permeability reservoirs, in particular where lack of gas supply does not allow gas injection processes. However, its application can be challenging for permeabilities below 100 mD as poor injectivity and high chemical retention are frequently observed. This work aimed at investigating the impact of both chemical and mineralogical parameters on the transport of polymer solutions in well-controlled low permeability porous media.
Selected polyacrylamide (HPAM) solubilized in brines of variable strengths and hardnesses were injected in granular sand and clays packs having similar petrophysical characteristics (permeability around 60–80 mD) but variable and well controlled mineralogical compositions. The granular packs were characterized in terms of structure (SEM) and specific surface area (BET) before and after polymer injections. The main observables of the coreflood tests were the resistance and residual resistance factors generated by the polymer, the polymer inaccessible pore volume and its irreversible retention.
Viscometric analysis showed that the HPAM solutions intrinsic viscosity decreased with increasing total salinity, as expected from charge screening, with a sharp decrease in presence of divalent cations, even at low ionic strength, which was less expected. Coreflood experiments revealed that polymer retention, resistance factor and irreversible resistance factor increased significantly: (a) with increasing ionic strength and hardness for porous media of a given mineralogical composition (this appeared consistent with the outcomes of the viscometric study and confirmed the major impact of hardness); (b) in presence of clays, even at low ionic strength and hardness. The polymer inaccessible pore volume was significantly impacted by the presence of clays, but not by the brine composition.
Assuming that polymer retention originated in polymer adsorption, irreversible resistance factors were translated into adsorbed layer thicknesses according to a simple capillary bundle model. This allowed discussing the results in terms of adsorbed layer density, which was showed to increase if brine hardness was increased and to be lower in presence of illite than kaolinite and pure quartz. These findings indicate that complex polymer adsorption/retention mechanisms occur depending on the clay type (layer charge and expandability).
This systematic study allowed dissociating the impacts of salinity, hardness and clay contents/types on the transport properties of polymer solutions in low permeability porous media. Its results should be of interest to the chemical EOR industry as they provide guides to help tuning the injection brine composition and polymer concentration to the reservoir properties.
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