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Results
Abstract Polymer flood improves the sweep efficiency of viscous oil recovery over water flood. The low-tension polymer (LTP) flood has the potential to improve the displacement efficiency due to low interfacial tension without sacrificing sweep efficiency. The objective of this research is to evaluate the performance of LTP floods as a function of IFT for a viscous oil in a 2D sand pack. Over 20 non-ionic surfactants/co-solvents were tested. A series of sandpack flooding experiments were conducted in a custom-designed 2D visualization cell. The results show that short-hydrophobic surfactants 2EH-xPO-yEO can reduce the IFT to as low as 0.05 dynes/cm. Flooding experiments were performed in sandpacks with and without connate water saturation. For the experiments with connate water saturation, the sandpack was water-wet/intermediate-wet. A base-case polymer flood (without any surfactant) with a viscosity ratio of 10 showed a stable displacement and 82% OOIP oil recovery at the first pore volume injected (PVI).LTP flood with an IFT of 0.1 dynes/cm also showed stable displacement front, but ahigher oil recovery at 1 PVI (90% OOIP).Further reduction in IFT to 0.05 dynes/cm resulted in an unstable displacement and a lower recovery of 65% OOIP. For the experiments without connate water saturation, sandpack was oil-wet, the base-case polymer flood at a viscosity ratio of 10 showed severe fingering and a low oil recovery at 1 PVI (58% OOIP). Adding the nonionic surfactants did not improve displacement efficiency nor oil recovery in oil-wet sandpacks.
- North America > Canada > Alberta (0.46)
- North America > United States > Texas (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (0.66)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Mooney Field > Bluesky Formation (0.99)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
Experimental and Simulation Based Interpretation of Characteristic Behavior During Forced and Spontaneous Imbibition in Strongly Water-Wet Sandstones
Andersen, Pål Østebø (Department of Energy Resources, University of Stavanger, 4021 Stavanger, Norway) | Salomonsen, Liva (Department of Energy Resources, University of Stavanger, 4021 Stavanger, Norway) | Sleveland, Dagfinn (Department of Energy and Petroleum Engineering, University of Stavanger, 4021 Stavanger, Norway)
Abstract In this work we investigate forced and spontaneous imbibition of water to displace oil from strongly water-wet Gray Berea (~130 mD) and Bentheimer (~1900 mD) sandstone core plugs. Two nonpolar, nonvolatile oils (n-heptane and Marcol-82) and their mixtures were used as non-wetting phase, giving oil viscosities between 0.4 and 31 cP between experiments. Brine (1 M NaCl) was used as wetting phase with viscosity 1.1 cP. Recovery was measured for both imbibition modes, and pressure drop was also measured during forced imbibition. Forced imbibition (five tests) was conducted with same viscosities at low and high injection rate using two different viscosities. 17 spontaneous imbibition experiments were performed at four different oil viscosities, and on the two rock types, including tests at same conditions. By varying the oil viscosity, injection rate and imbibition modes we measured the system's response to displacing oil by water under different conditions where both capillary and advective forces were allowed to dominate. Our hypothesis is that such a combination of experiments allows us to determine some characteristics of water-wet systems. Transient analytical solutions were derived accounting for low water mobility and inlet end effects, allowing theoretical predictions consistent with the observations. Full numerical simulations were also run to consistently match all the experimental observations. We find that, consistent with the literature, water has low mobility associated with its relative permeability. Thus, complete oil recovery was achieved at water breakthrough during the forced imbibition both at low and high oil viscosity tests. For the same reason, increasing oil viscosity by a factor of almost 100 did not increase the spontaneous imbibition time scale by more than 5 compared to the lowest oil viscosity. This was consistently matched by our models. Theoretical analysis indicates that pressure drop increases linearly with time until water breakthrough if capillary pressure is negligible and that the initial pressure drop correspond to the oil relative permeability end point. Positive capillary forces assist water in entering the core, and the pressure drop is reduced and possibly nonlinear with time. Using a high injection rate we could a linear trend more clear than at low rate, consistent with our predictions.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
X-Ray CT Investigation of Displacement Mechanisms for Heavy Oil Recovery by Low Concentration HPAM Polymers
Skauge, Arne (University of Bergen) | Shaker Shiran, Behruz (NORCE Energy) | Ormehaug, Per Arne (NORCE Energy) | Santanach Carreras, Enric (TOTAL E&P) | Klimenko, Alexandra (TOTAL E&P) | Levitt, David (TOTAL E&P)
Abstract Polymer flooding has proved to be a successful EOR method in very heavy oil reservoirs, despite failure to achieve a favorable mobility ratio even with polymer, which was originally imagined to be a necessary criterion for success based upon fractional flow theory. In a previous study (Levitt et al. 2013), we demonstrated a surprisingly high oil recovery with low concentration (and viscosity) partially hydrolyzed polyacrylamide (HPAM) polymer solutions of only 3 cP displacing a 2000 cP oil. Additional experiments with more viscous as well as non-elastic viscosifying agents demonstrated that recovery is not sensitive to viscosity, and thus cannot be understood through fractional flow theory. The scope of this paper is to understand where additional recovery comes from through visualization using CT imaging, in order to allow operative driving mechanisms to be optimized. Two long core (30 cm) flooding experiments have been performed to understand oil recovery at adverse mobility ratio. The first experiment started with waterflooding followed with polymer flooding (3 cP), while the second experiment started with polymer flooding directly. In-situ saturations were obtained by a medical CT scanner operated at high energy level, and used two X-ray sources and two array detectors simultaneously. The procedure was to perform the waterflood or polymer flood direct in the CT scanner. That will give us the finger development from early stage until a well-established channel is developed. The frontal velocity was about 1 ft/day. The displacements were further analyzed through simulations and dynamic pore scale model to understand the changes in fluid flow. CT imaging demonstrated that increased oil recovery with low-concentration HPAM solutions is correlated with an increase in finger width, rather than for instance an increase in finger density. This is in agreement with observed behavior of unstable displacements involving viscoelastic fluids in Hele-Shaw cells (Bonn et al., 1995). These results suggest that elasticity may be more significant than viscosity in optimizing oil recovery under highly unstable conditions, for example with oils of ~1000 cP or higher. Presence of fingering under both water and polymer flood was also confirmed, with dominant finger diameter on the order of 1 mm (under waterflood) to 2 mm (under polymer flood). Fingers grow in thickness and length, and near the inlet they start quickly to overlap. Fingers are formed mostly in the middle of the core and fewer fingers appear near the wall of the core. CT shows that the waterflood is dominated by viscous fingering. Experimental CT data together with simulations and pore scale modelling have demonstrated that increased oil recovery with low-concentration HPAM solutions is correlated with an increase in finger width, rather than for instance an increase in finger density or stabilization of the displacement front. Among other things, these results demonstrate that the assumption of capillary equilibrium is inappropriate under these conditions, and thus that fractional flow theory is poorly suited to predicting or optimizing recovery.
- Europe (1.00)
- Asia (0.94)
- North America > United States > Oklahoma (0.28)
- (2 more...)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
Use of Dynamic Pore Network Modeling to Improve Our Understanding of Experimental Observations in Viscous Oil Displacement by Polymers
Salmo, Iselin Cecilie (University of Bergen) | Zamani, Nematollah (Norce) | Skauge, Tormod (Energy research Norway) | Sorbie, Ken (Energy research Norway, Heriot Watt University) | Skauge, Arne (Energy research Norway, University of Bergen, Norce)
Abstract Any aqueous solution viscosified by a polymer (or glycerol) should improve the recovery of a very viscous oil to some degree, but it has long been thought that the detailed rheology of the solution would not play a major role. However, recent heavy oil displacement experiments have shown that there are clear differences in incremental oil recovery between aqueous polymeric or Newtonian solutions viscosified to the same effective viscosity. For example, synthetic polymers (such as HPAM) recover more oil than biopolymers (such as xanthan) at the same effective viscosity. In this paper, we use dynamic pore scale network modeling to model and explain these experimental results. A previously published dynamic pore scale network model (DPNM) which can model imbibition, has been extended to include polymer displacements, where the polymer may have any desired rheological properties. Using this model, we compare viscous oil displacement by water (Newtonian) with polymer injection where the "polymer" may be Newtonian (e.g. glycerol solution), or purely shear-thinning (e.g. xanthan) or it may show combined shear thinning and thickening behaviour (e.g. HPAM). In the original experiments, the polymer concentrations were adjusted such that the in situ viscosities of each solution were comparable at the expected in situ average shear rates (see Vik et al, 2018). The rheological properties of the injected "polymer" solutions in the dynamic pore network model (DPNM), were also chosen such that they had the same effective viscosity at a given injection rate, in single phase aqueous flow in the network model. Secondary mode injections of HPAM, xanthan and glycerol (Newtonian) showed significant differences in recovery efficiency and displacement, both experimentally and numerically. All polymers increased the oil production compared to water injection. However, the more complex shear thinning/thickening polymer (HPAM) recovered most oil, while the shear-thinning xanthan produced the lowest oil recovery, and the recovery by glycerol (Newtonian) was in the middle. In accordance with experimental results, at adverse mobility ratio, the DPNM results also showed that the combined shear- thinning/thickening (HPAM) polymer improves oil recovery the most, and the shear-thinning polymer (xanthan) shows the least incremental oil recovery with the Newtonian polymer (glycerol) recovery being in the middle; i.e. excellent qualitative agreement with the experimental observations was found. The DPNM simulations for the shear-thinning/thickening polymer show that in this case there is better front stability and increased oil mobilization at the pore level, thus leaving less oil behind. Simulations for the shear-thinning polymer show that in faster flowing bonds the average viscosity is greatly reduced and this causes enhanced water fingering compared with the Newtonian polymer (glycerol) case. The DPNM also allows us to explore phenomena such as piston-like displacements, snap-off and film flow, which at the pore level may have impact on the overall efficiency of the various fluid injection schemes. The DPNM models the effect of polymer rheology which changes the balance between the viscous/capillary forces that allows fluid microscopic diversion, and hence improved incremental recovery, to emerge.
- Europe (0.93)
- North America > United States (0.46)
- Asia > China (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.48)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract This paper gives a critical review of miscibility measurement techniques published in the open literature along with recommendations and lessons learned. Many of these suggested methods violate the assumptions for multicontact miscibility (MCM). The confusion often arises from a failure to distinguish between the first-contact miscibility (FCM), in which two fluids can be mixed in all proportions without forming two phases, and MCM, in which fluid compositions that arise during the flow of two phases in a porous medium approach a specific critical point within the constraints of the MCM definition. There are many analytical, numerical, correlational, and experimental methods available to estimate the minimum miscibility pressure (MMP) for MCM flow. The numerous available methods, some of which are quite inexpensive, have caused significant confusion in the literature and in practice regarding their ability to estimate MMP. Our experience has shown that the best methods are those that honor the multi-contact process (MCM), in which flow interacts with phase behavior in a prescribed way. Good methods that achieve this are slim-tube experiments, detailed slim-tube smulations, multiple mixing cell calculation methods, and the method-of-characteristics (MOC). Techniques such as the rising bubble apparatus (RBA) and vanishing interfacial tension (VIT) experiments are subject to significant uncertainties, though they may still provide quite useful information. Numerous MMP correlations have been developed. They should be used with caution for systems similarto those used to develop the correlation. Use for other systems can lead to significant errors. We discuss the advantages and disadvantages of most current methods and show that various combinations of methods can reduce uncertainty.
- North America > United States > Texas (1.00)
- Asia (0.92)
- North America > United States > Texas > Permian Basin > Levelland Field > Wichita-Albany Formation (0.99)
- North America > United States > Texas > Permian Basin > Levelland Field > Strawn Formation (0.99)
- North America > United States > Texas > Permian Basin > Levelland Field > Abo Formation (0.99)
- (5 more...)
Abstract For very viscous oils (>500cp), a stable polymer flood is not economical due to low processing rates. In such cases, a partially stable (mobility ratio >1) polymer flood must be designed. Depending on the magnitude of viscosity ratio, these displacements will be influenced by viscous fingering. Typically, viscous fingers cannot be accurately captured with the grid sizes used in full-field simulations. To optimize and design a partially-stable polymer or water flood, it is critical to correctly upscale the laboratory-generated relative permeability curves for reservoir simulation. In recent years, such models have been published in SPE literature. Unfortunately, most of these models require multiple fitting parameters (3+). In this work, we present a simplified technique that requires systematic change in only one parameter to generate upscaled relative permeability curve for a given viscosity ratio. Using fine-grid simulations, we show that due to small-scale random heterogeneities, the flow at high viscosity ratio is channelized even in a core perceived to be homogeneous at laboratory scale. Upscaling averages these fine variations in heterogeneities, causing the grids to be over-swept, and thus the recovery is over-predicted. To compensate for this over-prediction, relative permeability curves need to be upscaled.
Gravity-Stable Processes for Dipping or Thick Reservoirs
Doorwar, Shashvat (Chevron Energy Technology Company) | Lee, Vincent (Chevron Energy Technology Company) | Davidson, Andrew (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Abstract Traditionally, all surfactant processes require viscous polymer to mobilize the oil bank. Recent literature shows that for highly dipping reservoirs, a continuous surfactant injection process can be stabilized with gravity alone, by slowing down the processing rate. We extend the gravity stable approach for surfactant slug processes and demonstrate the importance of maintaining gravity stability between slug and chase in addition to gravity stability between microemulsion and slug. Four sandpack experiments were conducted and pictures of the sandpack were taken at regular intervals to provide visual evidence of stable or unstable interfaces. Different color dyes were used to aid visualization of clear fluids. Gravity-stabilized surfactant-only processes eliminate the need of polymer and other facilities associated with surfactant polymer or alkali-surfactant-polymer processes. The slug process described in this paper is a significant improvement on the continuous surfactant injection gravity stable process published earlier.
Abstract Alkaline-Surfactant-Foam flooding is a novel enhanced oil recovery process which increases oil recovery over water flooding by combining lowering of the oil-water interfacial tension by two to three orders of magnitude and foaming. We report an experimental study of the formation of the oil bank and its displacement by foam drives of varying qualities. Experiments include: (a) bulk phase behaviour and foam testing studies using n-hexadecane and a single internal olefin sulfonate surfactant which was found to lower the oil-water interfacial tension by at least two orders of magnitude and (b) series of CT scanned core-floods using Bentheimer sandstone cores. A major goal of this study was to investigate the effect of drive foam quality on oil bank displacement. Core-flood results, performed at under-optimum salinity conditions yielding an oil-water interfacial tension in the order of 10 mN/m, showed similar ultimate oil recovery factors for the range of drive foam qualities studied. Although the total oil recovery is not affected by drive foam quality, results indicate a more frontal oil bank displacement at lower foam qualities. The findings in this study suggest that a) a lower drive foam quality favours oil bank displacement and b) the amount of clean oil produced by the oil bank is not effected by drive foam quality.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Polymer Oil Recovery Experiments in Different Geometries for Improved Upscaling of Viscous Oil Reservoirs
Lee, Vincent (Chevron Corporation) | Doorwar, Shashvat (Chevron Corporation) | Dwarakanath, Varadarajan (Chevron Corporation) | Isbell, J. Taylor (Chevron Corporation) | Malik, Taimur (Chevron Corporation) | Slaughter, Will (Chevron Corporation)
Abstract Upscaling the simulation of unstable displacement of heavy oil is challenging because accurately modeling the development and propagation of viscous instabilities within a simulation grid-block is next to impossible. Various models have been developed that are capable of history matching oil recovery results, however, there is little lab data to allow for validated scale-up of these viscous fingering model. We present experimental results from different geometries, i.e. cylindrical corefloods, 2D slabs and 3D blocks, where a viscous oil is displaced by water and polymer solutions, under pressure-constrained injection. Waterflood and polymer flood oil recovery experiments were performed in ‘2-Dimensional’ (2D) sandstone slabs (12" by 12" by 1") and ‘3-Dimensional’ (3D) blocks (12" by 12" by 4") of sandstone and compared with oil recovery experiments through linear ‘1-Dimensional’ (1D) cylindrical cores. Experiments were performed with a high viscosity (540 cP) mineral oil at room temperature. UTCHEM (a software product from The University of Texas at Austin) with viscous fingering model was used to model the experiments and identify parameters for scaling the process to a field scale. As expected, water breakthrough was accelerated as we moved from cylindrical cores to 2D slabs to 3D blocks. For the experiments conducted, gravity instability had a minimal effect compared to viscosity instability, even for the 3D blocks. Pseudo relative permeability curves based on the modified viscous fingering model were developed to match the 1D experiment. The same pseudo parameters showed excellent scalability across the varying experimental geometries (1D, 2D and 3D). These results indicated that the effective finger width did not vary for the different geometries.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.45)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.40)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.36)
Abstract We investigated the combined contributions of gravity drainage and miscibility as recovery mechanisms during CO2 flooding. The effects of gravity stable and unstable CO2 fronts under immiscible, near miscible and miscible displacements of crude oil by CO2 are presented. We contrast our results in porous media, with slim tube experiments, core floods, and bead packed tubes. Standard slim-tube, vertically and horizontally oriented bead packed tubes, as well as vertical and horizontal reservoir core flood experiments, were used to investigate the role of the gravitational forces in improving oil recovery under different conditions regarding the crude oil – CO2 miscibility. Three crude oils with different minimum miscibility pressure (MMP) values were used in this study. Our results show the gravity drainage mechanism has a much greater significance than previously thought when compared to the effects of phase behavior or the miscibility alone. Not surprisingly, vertically stable, downward displacement resulted in better performance compared to horizontal displacement in all cores and bead packed tubes in our experiments. Recovery is only slightly higher in the gravity stable floods when miscibility is achieved. However, in immiscible and near miscible displacements, recovery is significantly higher in the gravity stable floods, reaching up to 90% RF at 250 psi below the MMP value, compared to only 33% in horizontal floods. Our results suggest that achieving miscibility is not necessary to obtain high recovery efficiency during a gravity-stable displacement. Breakthrough is reached faster in horizontal floods as a consequence of fingering and gravity override. This work challenges the paradigm that miscibility is required to achieve high recovery factors during CO2 flooding, and highlights the overlooked role of gravity drainage as a displacement mechanism. This finding has an essential impact on field operations as it allows for lower operating pressures in CO2 flooding processes under stable gravity displacement that will result in positive impact on economics. The relevance of our results is exacerbated by the current low crude oil price environment.