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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
101 - 120 of 139 results
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Flow of polymer solutions through porous media-Prediction of mobility reduction from ex-situ measurements of elasticity
Authors S. Jouenne and G. HeurteuxSummaryWhen injected at high flow rates in porous medium, polymer solutions exhibit a resistance to flow which is a signature of chain conformation and size. For biopolymers, which exist in solution as rigid rods, mobility reduction follows the shear thinning behavior measured in shear flow on a rheometer. For flexible coils, such as hydrolyzed polyacrylamide, flow thickening is observed in porous medium whereas bulk viscosity presents a shear thinning behavior. These differences are the result of the complex flow experienced in the porous medium combined with the visco-elastic properties at large strains of the solutions.
In this study, we investigate the effect of physical chemistry parameters such as salinity, polymer concentration, molecular weight and degradation state on the mobility reduction in porous medium at high flow rates. We show that parameters describing the mobility reduction curve (flow rates corresponding to the onset and to the maximum of the mobility reduction curves, value of the maximum mobility reduction) are not correlated with bulk viscosity but rather with screen factor. This old and rough measurement, widely used in the EOR community to evaluate “solution elasticity”, is an indirect measurement of the extensional viscosity of polymer solutions. The pertinence and the physical meaning of this measurement is assessed through comparison with measurements performed on a newly developed extensional viscometer, which consists in measuring the pressure drop when the fluid is injected through a hyperbolic contraction (in which strain rate is constant at the centerline). A correlation “Screen factor” vs. “Extensional Viscosity” is obtained. Hence, from the knowledge of the mobility reduction curve in one porous medium in one set of conditions, it is possible to predict the mobility reduction in any other set of conditions from ex-situ measurements of screen factor or extensional viscosity. At last, the inadequacy of traditional small strain visco-elastic measurements to characterize the elastic behavior of polymer solutions at large strain is discussed.
These results give some insight on the behavior of polymer solutions in injectivity conditions along with the way to characterize their elastic properties from bulk measurements.
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Analysis of Viscous Crossflow in Polymer Flooding
Authors M. H. Alshawaf, S. Krevor and A. MuggeridgeSummaryPolymer flooding improves oil recovery by improving flood front conformance compared with waterflooding as well as, in some cases, extracting more oil from lower permeability zones in the reservoir by viscous cross-flow. However viscous cross-flow of water from the low permeability zone may also adversely affect the polymer flood by causing the polymer slug to be diluted and possibly to lose its integrity. The extent to which viscous cross-flow improves or reduces recovery depends upon the permeability contrast between the low and high permeability zones, the viscosity ratios of the fluids (oil, water and polymer solution) and the geometry of the layers. This paper uses inspectional analysis to derive the minimum set of 6 dimensionless numbers that can be used to characterise a polymer flood in a two layered model. A series of finely gridded numerical simulations are then performed to determine the contribution of viscous crossflow to oil recovery from secondary and tertiary polymer flooding in this system. We show that viscous cross-flow will only make a positive impact on oil recovery from secondary polymer flooding when the viscosity ratio values of oil to polymer solution is less than 1 and permeability ratio between the layers is less than 50. Furthermore, we show that there is an inverse relationship between the permeability ratio between layers and the amount of degradation the polymer slug experiences due to viscous crossflow in the high permeability layer. As the permeability contrast between layers increases, the slug degradation decreases. Also, the results show that the desired positive impact from viscous crossflow is higher in secondary polymer foods when compared to tertiary polymer floods. Finally, the results can be used to make initial estimates of the contribution of both viscous cross-flow and mobility control in polymer flooding applications without the need to perform extensive and time consuming numerical simulations.
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Reduced Residual Oil Saturation for Secondary and Early Tertiary Polymer Floods Obtained in the Laboratory
Authors M.J. Bourgeois, C. Cottin, D. Morel, J. Hy-Billiot, S. Hourcq, S. Lassalle and M. N’guyenSummaryThis paper reviews twenty-two polymer core flooding experiments performed in the laboratory on highly permeable (0.5 to 20 D) aged unconsolidated sandstone reservoir cores. Experiments were carried out at reservoir temperature, with oil viscosities ranging from 5 to 100 cP.
Polymer solutions were injected at different maturity levels: secondary (polymer injection at irreducible water saturation), early tertiary (after 0.5 to 1 PV of water injected), or late tertiary (after 20–80 pore volumes of water injected before polymer injection).
Final oil recovery results were analyzed as a function of maturity of the flood, but other parameters like permeability, wettability and polymer viscosity were also considered. For each experiment, history matching of oil and water production with differential pressure data including rate-bumps, constrained on in-situ saturation profiles enabled us to obtain robust relative permeability curves, and to differentiate ROS (remaining oil saturation at the end of experiment) and Sor (residual oil saturation, at kro=0).
Both the ROS vs. capillary number plot and the KR curves were more favorable for secondary or early tertiary polymerfloods than for late tertiary polymerfloods or waterfloods, especially at high water saturation. Residual oil saturations were lower when polymer was injected early.
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Advanced Selection of Polymers for EOR Considering Shear and Hardness Tolerance Properties
Authors N. Gaillard, A. Thomas, S. Bataille, G. Dupuis, F. Daguerre and C. FavéroSummaryPolymer flooding has proven to be an effective technique to improve oil recovery from mature reservoirs. The selection of polymer, focusing mainly on its temperature tolerance properties and its ability to propagate in porous media, is key to achieve a successful EOR job. This selection also depends on brine injection compositions that covers a large range of salinities and hardness worldwide. A screening of viscosity behavior with different polymers in different brine conditions is obviously helpful in order to select the most cost effective chemistry.
The impact of different acrylamide based polymer chemistries is evaluated through viscosity measurement over a wide range of salinities and hardness. A parameter called R+, corresponding to the molar ratio of divalent cations divided by the total mole number of cations in the brine is introduced. Salt tolerance and hardness tolerance of polymers in solutions are evaluated for brine considering either constant Total Dissolved Salt (TDS) with different R+ either the impact of different total salinities for constant R+. This parameter is as well considered to compare shear stability of the different polymers. At least, the impact of the type of divalent cations on viscosity is reported.
Polymers from the study are all anionic and acrylamide based. The introduction of different amounts of sulfonated monomer (ATBS) was performed and its impact on hardness and shear tolerance was assessed. For all the polymers, a threshold beyond which viscosity remains constant is reached for R+> 0,5. Interestingly, this threshold is obtained for lower value of R+ for polymers containing ATBS since they provide better calcium tolerance. Calcium provides a higher impact on viscosity compared to magnesium for all the polymers studied. Increasing the amount of ATBS leads to higher tolerance to divalent cations. It also provides better stability to shear degradation. A minimum amount of sulfonated monomer is required to improve stability.
The objective of this paper is to complete guidelines in the selection of industrial polymers considering a wide range of salinities and hardness. The screening of brine and polymers selected for this study is wide enough to represent worldwide injection brine conditions and helps selecting the most appropriate chemistry for each reservoir condition.
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Spontaneous Imbibition as Indicator of Wettability Change During Polymer Flooding
Authors J.L. Juarez-Morejon, H. Bertin, A. Omari, G. Hamon, C. Cottin, G. Bourdarot and D. MorelSummaryThe presence of polymer molecules in an altered wettability core and its possible interactions with the solid phase is the subject of this study.
Experiments were carried out in Bentheimer sandstone which wettability is altered by an ageing process.
The wettability index after ageing (WI = 0.075) shows an intermediate wettability.
After ageing we carried out spontaneous imbibition tests by putting in contact the core with brine or polymer solution (HPAM, C = 2500ppm) or in a sequence (first with brine and then with the polymer solution)
For each experiment we measure the volume of oil recovered by spontaneous imbibition, this oil volume gives us an evaluation of the core wettability, the higher the recovered oil volume, the more water wet is the core. The experimental data show that final oil production by spontaneous imbibition is higher when the core was kept for a long time in contact with polymer solution rather than with brine. Moreover if the core is put in contact with polymer after having been immerged in brine, we notice a significant increment of produced oil. All these results confirm that the polymer has an interaction with the solid phase and makes the core more water wet.
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Mechanical Degradation of Polymers at the Field Scale - A Simulation Study
Authors O.M. Nodland, A. Lohne and A. HiorthSummaryPolymer flooding is a chemical EOR method which aims to improve the oil recovery by making the water phase more viscous, and hence to increase the macroscopic sweep efficiency of a waterflood. However, the polymers considered for EOR applications are very susceptible to mechanical degradation in regions of high shear, such as in the injection facilities and in near well regions. If the applied flow rate is too high, an injected polymer solution may lose more or less all its viscosifying ability before properly entering the formation. This can be especially difficult to avoid if polymer is injected directly into a heterogeneous reservoir region where high molecular weight polymer species will have to travel through successive contractions and expansions inside small pores.
At EAGE-ECMOR XV we presented a new simulation model that is capable of modeling all the commonly observed flow regimes in porous media, such as Newtonian, shear thinning and shear thickening flow, as well as polymer mechanical degradation. Based on simple pore scale models, we derived expressions for the in-situ polymer rheology that can account for spatial variations in important reservoir parameters such as permeability, temperature, and salinity. This allowed us to match the different experiments with most of the input parameters kept fixed. The model captured very well how HPAM polymers of different molecular weights were mechanically degraded when injected into cores and series of cores with an order of magnitude variation in permeability.
In this paper we use the model with parameters that was history matched to lab data to study the polymer behaviour in a typical field operation. We investigate how the model scales from the lab to the field. In particular, we simulate flow of polymer near an injector in order to estimate the amount and extent of mechanical degradation as a function of injection rate and reservoir heterogeneity near the injection well. Preliminary results indicate that there will always be some degradation, but that this can to some extent be minimized using reasonable injection rates. In cases of open fractures near the injection well, the risk of degrading the polymer will be greatly reduced.
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Characterizing Foam Flow in Fractures for Enhanced Oil Recovery
Authors B.I. AlQuaimi and W.R. RossenSummaryGas is very efficient in displacing oil for enhanced-oil-recovery projects because of its high microscopic-displacement efficiency. However, the process at the reservoir scale suffers from poor sweep efficiency due to density and viscosity differences compared to in-situ fluids. Foam substantially reduces the viscosity of injected gas and hence improves the sweep. Foam rheology in 3D geological porous media has been characterized both theoretically and experimentally. In contrast, the knowledge of foam flow in fractured porous media is far less complete.
We study foam rheology in a fully characterized model fracture. This investigation is conducted by varying superficial velocities of gas and surfactant solution. We find in this model fracture the same two foam-flow regimes central to the understanding of foam in 3D porous media: a low-quality regime where pressure gradient is independent of liquid velocity and a high-quality regime where pressure gradient is independent of gas velocity. The transition between regimes is less abrupt than in 3D porous media. Direct observation of bubble size, bubble trapping and mobilization, and foam stability as functions of superficial velocities allows comparison with our understanding of the mechanisms behind the two flow regimes in 3D porous media. Additionally, foam is shear-thinning in both regimes. But in other important respects the mechanisms thought to be behind the two flow regimes in 3D media do not appear in our model fracture. Foam is not at the limit of stability in the high-quality regime. Mobility in the high-quality regime instead reflects reduced and fluctuating foam generation at high foam quality.
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SAG Foam Flooding in Carbonate Rocks
Authors C.S. Boeije and W.R. RossenSummaryFoam is used in gas-injection EOR processes to reduce the mobility of gas, resulting in greater volumetric sweep. SAG (Surfactant Alternating Gas) is a preferred method of injection as it results in greater injectivity in the field, but designing a successful process requires knowledge of foaming performance at very high foam qualities (gas fractional flows).
Here the use of foam in low-permeability (~1 mD) Indiana Limestone cores for SAG foam applications is studied. Coreflood experiments were performed for a range of foam qualities at high pressure (100 bar), elevated temperature (55°C), high salinity (200,000 ppm) and in the presence of crude oil. The effectiveness of the foam was studied by differential pressure measurements along the core. Foam was still able to form under these stringent conditions, but it was a relatively weak foam (i.e. its ability to reduce gas mobility is modest).
For one surfactant formulation, further analysis of the experimental results show that the foam would be able to maintain mobility control over the displaced phase, thus providing a stable displacement front, and that it can be used in a SAG foam process in these formations. For a second formulation the non-monotonic nature of the fractionalflow data require further investigation before scale-up to the field.
In addition, further coreflood experiments were carried out using heterogeneous, vuggy Edwards White cores with even lower permeability (~0.5 mD). These experiments were performed to determine whether foaming is possible in heterogeneous media and especially to investigate the effects of disconnected vugs on the foaming performance. CT scans were taken during the period of foam injection to determine saturation profiles within the core. Foam was able to form inside these cores, but inside the vugs foam segregation was observed with liquid pockets visible in the bottom of the vugs and gas in the remainder. This segregation was only a local effect though, confined to the vug itself, and foam was able to persist in the rest of the core.
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The Effect of Trapped Gas on Foam Flow in a Model Porous Medium
Authors S.A. Jones, N. Getrouw and S. Vincent-BonnieuSummaryFoams for enhanced oil recovery can increase sweep efficiency, as they decrease the gas relative permeability, mainly due to gas trapping. However, gas trapping mechanisms are poorly understood. Some studies have been performed during corefloods, but little work has been carried out to describe the bubble trapping behaviour at the pore scale.
Microfluidic experiments are a useful tool for studying the foam flow behavior at the pore scale. We have carried out foam flow tests in a model porous media glass micromodel. Image analysis of the foam flow allowed local velocities to be obtained. The quantity of trapped gas was measured both by considering the fraction of bubbles that were trapped (via velocity thresholding) and by measuring the area fraction containing immobile gas (via image analysis). A decrease in the trapped gas fraction was observed both for increasing total velocity and for increasing foam quality.
Calculations of the gas relative permeability were made with the Brooks Corey equation, using the measured trapped gas saturations. The results showed a decrease in gas relative permeabilities for increasing fractions of trapped gas. It is suggested that the shear thinning behaviour of foam could be coupled to the saturation of trapped gas.
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Numerical Modelling Study for Designing CO2-Foam Field Pilot
Authors M. Sharma, Z.P. Alcorn, S. Fredriksen, M. Fernø and A. GraueSummaryCarbon dioxide has been successfully used in fields as EOR agent; and because of technical, commercial and environmental reasons, it has received considerable attention in recent years over other solvents. Based on experience with CO2 flooding worldwide, it is well understood that despite its high local displacement efficiency, the process suffers from poor sweep efficiency due to reservoir heterogeneity, viscous instability and gravity override. Application of foam has been found to mitigate these limitations at laboratory scale, however understanding of CO2-Foam flow behaviour at a larger scale is limited industrywide. Some of the previous pilots have shown technical success especially near wellbore, but there exist a need to establish an integrated methodology to scale-up the CO2-Foam technology efficiently and effectively.
As part of an ongoing research program, we have identified a field with heterogeneous carbonate reservoir onshore in west Texas, USA to run CO2-Foam field trial. The research emphasizes on implementing a modelling, monitoring and verification approach as part of the roadmap. Static model created by integrating petrophysical logs and core data in-line with geologic framework, and dynamic model created based on analysis of reservoir engineering data including RCA, SCAL, PVT, pressure data and coreflood experiments forms the basis for reservoir simulation study for the pilot area. In this paper, we provide an overview of different elements of numerical model and demonstrate application of a probabilistic framework to incorporate the uncertainties associated with model inputs. The success will be validated via appropriate monitoring plan in the ongoing pilot research program.
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An Automated Sandpack as a New Intermediate Test for EOR Foam Formulation Design
Authors E Chevallier, N. Demazy, M. Chabert, A. Cuenca and G. BatôtSummaryFoams are now a well-accepted method for conformance control in a wide range of EOR gas floods, from produced gas re-injection in the North Sea to CO2 EOR applications in the US. To maximize the chances of success of a foam process, both the composition of the aqueous foaming solution (salinity, surfactants, polymers…) and the process parameters (foam gas fraction, injection flow rates, …) must be optimized. This is generally done by combining bulk foam experiments and heavy petrophysics application tests, which limits the number of experiments carried out for the process optimization.
We present here a new experimental approach based on an automated porous media set-up with in-situ flow visualization. This sandpack design allows changing automatically the injection velocity and gas fraction and thus speeding-up an extensive mapping of performances of numerous formulations. This helps selecting the most adapted formulation. In addition to automation, the direct flow visualization through thick rectangular glass windows allows to characterize the transport of the colored aqueous and oil phases by a proper selection of dyes. The possibilities of in-situ velocities measurement thus brings new insight on foam flow in porous media with and without oil. Moreover, this tool, through the generated set of data, helps clarifying the relation between the bulk foam properties such as foamability, foam stability and the performances in porous media such as relative mobility reduction and conditions for efficient foam generation. Stability of bulk foam but also the ability for a formulation to create foam lamellae are evidenced as key parameters to control the apparent viscosity in porous media.
Overall, this study presents both a new high-throughput tool as an intermediate test between bulk foam and petrophysics measurements, and a set of data generated with this sandpack which brings new insights on foam flows in EOR processes.
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Multilateral Technology - Riding the Uncertainty Wave
Authors G.L. Liland, S.C. Cappiello, C.B. Benson and C.G. GrahamSummaryThe oil and gas Industry is currently suffering its deepest downturn since the 1990s. Under challenging conditions, the industry has had to drastically adjust its business infrastructure, resulting in lower budgets, personnel reduction, and projects postponed or cancelled. Oil companies have reviewed their approach to drilling and completion solutions, including the use of multilateral technology (MLT). This paper presents a study on how MLT use has been influenced by the recent downturn and demonstrates how multilateral wells have improved well and field economics during a period of low oil prices.
MLT has provided significant economic and operational benefits over the years in very different environments. A study was conducted from 2010 to 2016 analyzing both predownturn (2010 to 2013) and downturn (2014 to 2016) periods. This study reviews how MLT use has been impacted by low oil prices and what challenges have been encountered from both service company and operator perspectives. Additionally, global installations are reviewed and compared to previous years to help demonstrate how the overall economics and personnel reductions have impacted service quality (SQ).
Global data was studied with the primary focus on the largest existing multilateral markets, including the North Sea, Saudi Arabia, and the Asia Pacific region. The results demonstrate that multilateral wells can help improve well and field economics during low oil price periods, for example, as 2015 was one of the strongest years for total installations and market size in MLT history. Market growth can also be measured by operator interest in the technology. There has been an increase in requests for feasibility reviews for multilateral field developments, both in near and long-term projects.
The study and paper demonstrate that the overall development and production benefits of implementing MLT have resulted in continuous use of the technology by operators that adapted to the technology before the downturn. The paper also demonstrates the MLT well construction technique helps improve the economics and can be used during periods of low oil prices. This paper provides operators additional reference data regarding the resilience of MLT and how its use can be facilitated to improve well and field development economics during periods of both volatile and stable oil prices.
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Effect of Oil on Gravity Segregation in SAG Foam Flooding
Authors A.A.A. Hussain, A. Amin, S. Vincent-Bonnieu, R. Farajzadeh, A. Andrianov, P. Abdul Hamid and W.R. RossenSummaryWe report a simulation study of surfactant-alternating-gas (SAG) foam injection into a waterflooded oil reservoir. We show the effects of oil, and of SAG cycle size and number on sweep efficiency, and the long-term impact of a single surfactant slug on the areal sweep efficiency of a gas-flood.
Shan and Rossen (2004) show that a single-cycle SAG flood with fixed injection pressure can effectively overcome gravity override in a homogeneous reservoir with a uniform residual oil saturation. A single cycle works better than multiple cycles. We show that the presence of mobile oil can invalidate this model, but not simply because oil weakens or destroys foam. If foam is weakened by oil, moderately but uniformly, vertical sweep efficiency can still be good. Of course if oil kills foam nearly completely, gravity override occurs.
In our simulations, foam collapses where oil saturation is above a certain threshold value greater than waterflood residual. Oil mobilized by the foam bank flows downward. This can lead to an oil bank at the bottom of the reservoir, and in single-cycle SAG this oil bank is not displaced by foam if its oil saturation is sufficient to destroy foam. Meanwhile, gas flows upward and the low-mobility front advances rapidly across the top of the reservoir, leading to an override zone. It is the non-uniformity of the resulting oil saturation and gas mobility that invalidates Shan and Rossen’s model in this case. Instead there is an oil-rich zone at the bottom of the reservoir, foam above the oil-rich zone, and a foam-free override zone above the foam. In this case, if foam is injected in several relatively small slugs, oil production can be better than that with fewer relatively large slugs.
We also illustrate the impact of injecting a single surfactant slug on the areal sweep efficiency of a long-term gas-flood. By injecting a surfactant slug prior to the gas slug, stronger foam can form in parts of the reservoir with a lower oil saturation. Foam then diverts gas flow to oil-rich areas in the reservoir, in our case the bottom of the reservoir. In a conventional gas flood gas flows primarily across the top of the reservoir with poor sweep efficiency. By injecting a single surfactant slug ahead of gas, higher oil recovery can be achieved at the same injected PV of gas.
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Application of Low Concentration Surfactant Enhanced Water-Alternating-Gas Flooding
Authors I. Sagbana, P. Diaz, M. Eneotu, M. Centeno, F. Vajihi and A. FarhadiSummaryLarge amounts of oil left in the petroleum reservoir after primary and secondary enhanced oil recovery methods have brought about the implementation of several tertiary means of oil recovery. Increment of oil recovery can support the world’s oil supply. Water alternating gas injection has been a very popular method of gas injection to improving volumetric sweep efficiency. Although water alternating as injection has been shown to improve oil recovery, this process suffers inherent challenges such as water blocking, mobility control in high viscosity oil and gravity segregation. To combat these problems associated with water alternating gas flooding, the use of surfactant has been employed in water alternating gas injection. Due to the high operational cost arising from chemical cost in surfactant alternating gas injection, a new technique which involves the injection of low concentration surfactant before water alternating as flooding has been proposed. This work investigates experimental and numerical oil recovery potential of surfactant enhanced water alternating gas flooding. The distinctive feature of this technique is that instead of injecting surfactant slugs alternatively with gas, which will result to using a greater amount of surfactant, a low concentration surfactant is injected into the reservoir before water alternating gas flooding. The aim is to evaluate the performance of this technique as a low cost and effective means of chemically enhanced oil recovery by combining both mechanisms of surfactant reduction of water-oil interfacial tension and creation of foam with gas. This study begins with surfactant evaluation to characterise surfactants compatibility with reservoir brine and oil. Then followed by series core flooding experiments which include waterflooding, gas flooding, water alternating gas flooding and surfactant-enhanced water alternating gas flooding. Core flood data was history matched for water alternating as flooding and surfactant-enhanced water alternating as flooding via commercial simulator by inputting relative permeability curves, rock, fluid properties and interfacial tension. The results showed that experimentally, surfactant enhanced water alternating as flooding had the highest oil recovery when compared to conventional enhanced oil recovery methods. History matching of core flood experiment predicted similar increment in oil recovery during surfactant enhanced WAG. The effectiveness of this technique is based on the injection pattern after the initial surfactant injection and oil recovery potential is similar to that of surfactant alternating gas flooding.
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Improvement in Foamability/stability Test Rigs for CO2 Foam EOR Screening Evaluation
Authors H. Yonebayashi and Y. MiyagawaSummaryTo screen effective foaming agents for CO2 Foam EOR, foamability/stability test is performed as visual evaluation and/or slimtube apparatus under high pressure and high temperature (HPHT) condition in reservoir. There are several ways for generating foams: i.e. bubbling, stirring, and mixing through porous media (ex. sandpack, glassbeads, etc.). The bubbling method is usually applicable in the open system at ambient pressure condition. The mixing through porous media is applicable in HPHT condition, but mainly used in flooding tests in which mixing efficiency might be minimal because of just one time chance for injectants (CO2 and foaming agent) to create foam. The stirring can be applied into closed/ pressurized system such as PVT apparatus that provides visual observation through glass cell/window. In this paper, stirring and mixing-through-porous-media were used in the foamability test rig and the slimtube apparatus, respectively.
The existing rigs in our laboratory were modified for evaluating CO2 foam. In general, magnetic stirring system is equipped in PVT apparatus to equilibrate fluid samples, however; the iron magnets could not be resistant to our experimental condition. Then, polytetrafluoroethylene (PTFE)-encapsulated magnetic stirrer was used as alternative material. The PTFE stirrer was wheel shape with 4 blades on both surfaces of upper and lower for more stirring power. From material aspects, PTFE is universal chemical/corrosion resistance under existence of oil and hydrocarbon gas mixture, however; our experimental environment (mixing of CO2 + formation water) rapidly becomes severer as pressure/temperature increase. The stirrer was expanded and chipped due to CO2 corrosion, and stuck in cylinder-shape metal device location at the bottom of glass cell, although it was originally set with small clearance to rotate freely. This expansion resulted insufficient stirring power to create foams. In the slimtube flooding test to evaluate apparent viscosity increase by CO2 foam, a visual cell was equipped at the downstream location of the sandpack to check ideal foam creation. However, our first trial was failed and required modification.
This paper demonstrates how we improved the foam creation sufficiently under the reservoir condition for appropriate evaluation.
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The Effect of Oil on Steady-state Foam Flow Regimes in Porous Media
Authors J. Tang, S. Vincent Bonnieu and W.R. RossenSummaryFoam flow in porous media without oil shows two regimes, depending on foam quality (gas fractional flow). Complexity and limited data on foam-oil interactions in porous media greatly restrict understanding of foam in contact with oil. Distinguishing which regimes are affected by oil is key to modelling the effect of oil on foam. We report steady-state corefloods to investigate the effect of oil on foam through its effect on the two flow regimes. We fit parameters of the widely used STARS foam model to data for foam-oil concurrent flow. This research provides a practical approach and initial data for simulating foam EOR in the presence of oil.
To ensure steady state, oil is co-injected with foam at a fixed ratio of oil (Uo) to water (Uw) superficial velocities in a Bentheimer sandstone core. Model oils used here consist of two components: hexadecane, which is benign to foam stability, and oleic acid, which can destroy foam. Varying the concentration of oleic acid in the model oil allows one to examine the effect of oil composition on steady-state foam flow. Experimental results show that oil impacts both high- and low-quality regimes, with the high-quality regime more vulnerable to oil. In particular, oil increases the limiting water saturation (Sw*) in the high-quality regime and also lessens gas mobility reduction in the low-quality regime. The high-quality regime is strongly shear-thinning in the presence of oil. Pressure gradient ( p) in the low-quality regime, in some cases, decreases with increasing Uw at fixed gas superficial velocity (Ug), either with or without oil. This may reflect either an effect of oil, if oil is present, or easier flow of bubbles under wetter conditions. Increasing oleic acid concentration extends the high-quality regime to lower foam qualities, indicating more difficulty in stabilizing foam. Thus oil composition plays as significant a role as oil saturation.
A model fit assuming a fixed Sw* and including shear-thinning in the low-quality regime doesn’t represent each regime when the oil effect is strong enough. In such cases, fitting Sw* to each p contour and excluding shear-thinning in the low-quality regime yields a better match to data. The dependency of Sw* on oil saturation is not yet clear owing to absence of oil-saturation data in this study. Furthermore, none of the current foam simulation models can capture the upward-tilting p contours in the low-quality regime.
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Experimental Study of Hysteresis Behavior of Foam in Porous Media
Authors S. Kahrobaei, S. Vincent Bonnieu and R. FarajzadehSummaryFoam EOR improves the sweep efficiency by reducing gas mobility and creating a stable displacement front. In the field application, the surfactant concentration and flow rate vary in the reservoir, influencing dramatically the foam mobility. However, the variations of surfactant concentration and flow rate do not relate monotonously to the foam properties. In some cases, the foam properties depends on the history of the flow, i.e., a hysteresis effect. But hysteresis in foam flood has not been well characterized and understood.
This study aims to understand hysteresis behavior of foam in porous media. To this end two series of experiments have been conducted:
1) Hysteresis behavior due to flow rate variations and 2) Hysteresis behavior due to surfactant concentration variations. In the flow rate experiments, several shear-thinning experiments at different volume fractions of gas (foam quality) are conducted in order to understand the effect of gas fraction and total velocity on foam generation mechanisms. In the surfactant concentration experiment, experiments have been performed at different surfactant concentrations and at different volume fractions of gas (foam quality).
Results showed that a transition from weak to strong foam is more pronounced in high-quality regimes (gas fractional flow above 90%) than low-quality regimes (gas fractional flow below 80%). Remarkably, no hysteresis behavior has been observed in low-quality regimes, while hysteresis behavior occurred in high quality regimes. Furthermore, the effect of surfactant concentration on hysteresis behavior has been also investigated at high- and low-quality regimes. Contrary to some previous works, hysteresis behavior does not occur for surfactant variation. Remarkably, the apparent viscosity remains almost constant in low-quality regime for different surfactant concentrations.
These results have important implications of the injection strategy and the economics of foam EOR. The surfactant concentration could be decreased and less gas could be injected, and in the same time, the foam performance could be maintained.
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Chemical EOR - High Potential beyond ASP
Authors B. Jakobs-Sauter, R. Rommerskirchen and P. NijssenSummaryChemical enhanced oil recovery methods like alkali-surfactant-polymer (ASP) flooding can yield high additional recoveries at the right conditions. But chemical floods are often cost intensive, and are limited to certain reservoir temperatures, water salinities, and so on. These restrictions reduce the number of reservoirs where chemical floods can be applied with highest performance.
Surfactants are defined and well-known by their ability to lower the interfacial tension (IFT) between oil and water to ultra-low values and thereby mobilize the trapped oil. It is less known that due to their intrinsic properties surfactants and related chemicals can also be used to improve oil recovery via most other EOR techniques. They have the ability to decrease heavy oil viscosity, change reservoir wettability, reduce injection pressure, create stable foams, and increase miscibility. Hence, involving those materials in steam injection, gas/(sc)CO2 injection, solvent flooding, wettability alteration, or foam assisted procedures is an easy way to increase the economics of oil recovery processes even more if the injection facilities are already in place.
This paper describes the physical principles of different EOR techniques and presents examples on how to select the best surfactant for each of the above applications by considering the varying requirements and limitations.
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Comparative Study of Polyacrylamide Co-polymers for EOR at High Salinity Conditions “Laboratory and Simulation
Authors M.A. Centeno, P. Diaz and A. BredaSummaryThe success of polymer flooding as a method of oil recovery has been attributed to a profile control mechanism of the displacing fluid (polymer solutions) related to the displaced fluid (crude oil), depending on properties such as polymer viscosity and its dependence with reservoir and flow conditions. The viscosity of polymer flow depends not only on the size of the molecules or molecular weight but it is further affected by salinity and divalent content on the brine used for the preparation of the polymer slug. The effect of salinity on polymer viscosity is more critical in presence of divalent ions Ca2+ and Mg2+ and high salinity conditions, which limits the use high salinity produced water for re-injection in polymer flooding processes where high salinity is involved. A series of salinity resistant polymers have been developed by incorporating co-monomers including hydrophilic and hydrophobic groups or combination of them along the chain of polyacrylamide which has made the viscosity behavior more complex and affected by ionic interactions both intra-molecular and inter-molecular. Therefore, an extensively screening process that includes evaluation of variables such as: stability of polymer solutions under salinity and ion composition, flow conditions and sensitivity analysis using simulation according to specific applications, is required for the selection of any specific system.
A systematic comparative study of the screening of commercial partial hydrolysed polyacrylamide (PHPA), and co-polymers of acrylamide and hydrophobic modified Comb-polymers (HMPAM) under high salinity conditions is investigated. Synthetic high salinity and multi-component (with divalent ions) produced water from a North Sea reservoir was used on Bernheimer sandstone core samples using a crude oil from the North Sea with specific gravity 21 °API. Results from core flooding and rheology were matched to obtain required mathematical correlations to simulate core flooding experiments numerically and compare the efficiency of the different polymers.
While polymers PHPA and co-polymers AM-AMPS and AM-nVP showed typical Newtonian behavior at low shear rates and non- Newtonian at high shear rates, HMPAM polymers have shear thinning behavior. Newtonian behavior on PHPA-3 seems to support its higher recovery factor comparing with PHPA-6 (higher MW). Viscosity of HMPAM solutions is more sensitive to changes of the polymer concentration and more sensible to flow conditions. Additionally, ionic interactions and steric effects in the co-polymers contribute the efficiency of the oil recovery at high salinity. Therefore, their viscosity behavior needs to be evaluated.
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Surfactant-steam-noncondensible Gas-foam Modeling for SAGD Process in the Heavy Oil Recovery
Authors Z.Y.G Zhou and L.S. ChengSummarySAGD(steam assisted gravity drainage) is a mature technology to recover the heavy oil and oil sands in the Alberta. Owning to the reservoir heterogeneity and fluid properties differences, nonuniform steam chamber formed along the horizontal well leading to lower recovery
Foam is dispersion of gas in a continuous water phase with thin films (lamella), acting as a separator. surfactant mobilizes the high viscous oil by emulsification and reduction of interfacial tension.Adding surfactants also lowers the interfacial tension at the water-oil interface and further produces water in oil or oil in water emulsion. In situ emulsion generation is thus another active mechanism that is involved as a result of surfactants presence. Noncondensible gas could enhance the steam foam by reducing the affection of liquid phases condensation and evaporization.
Due to the above properties, gravity override is consequently limited.The existence of noncondensible gas contributes to foam stability. The phase behavior for emulsification regulates different relative permeability regimes into the oil flow. We find that adding surfactant,condensable gas and foam contributes to higher production and leads to less steam consumed.
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