bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact of Gas-Assisted Gravity Drainage on Operating Pressure in a Miscible CO2 Flood
Authors: Adel Imad A. , Zhang Fan , Bhatnagar Nicole , Schechter David S. 
Published: March 2018

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.
ASP Experiments in Indiana Limestone using NaOH to Reduce Surfactant Retention
Authors: Maubert M. , Jith Liyanage P. , Pope G. , Upamali N. , Chang L. , Ren G. , Mateen K. , Ma K. , Bourdarot G. , Morel D. 
Published: March 2018

Abstract
Alkaline-surfactant-polymer (ASP) coreflood experiments using Indiana limestone were conducted to test the effectiveness of sodium hydroxide in reducing surfactant retention on limestones. Low concentrations of sodium hydroxide of only about 0.3 wt% increase the pH to about 12.6. The high pH reduces the adsorption of anionic surfactants by changing the surface charge of the limestone from positive to negative as well as having other favorable geochemical effects. Sodium carbonate could not be used in these experiments to increase the pH because the Indiana Limestone rock contained gypsum, which causes calcium carbonate to precipitate when it dissolves. Another advantage of sodium hydroxide is that much lower concentrations are needed compared to sodium carbonate because of its lower molecular weight. No adverse reactions between the sodium hydroxide and limestone were observed and the propagation of the pH in the corefloods was observed to be extremely favorable. The tertiary oil recovery was high and the surfactant retention using sodium hydroxide was low compared to experiments without alkali and compared to typical retention values reported in the literature for carbonates.
Extension of HLD-NAC Flash Calculation Algorithm to Multicomponent Mixtures of Microemulsion and Excess Phases
Authors: Khorsandi Saeid , Johns Russell T. 
Published: March 2018

Abstract
Current HLD-NAC theory and most simulators represent multicomponent mixtures with three lumped components, where the excess phases are also assumed pure. This can cause significant errors, and discontinuities in chemical flooding simulation for surfactant mixtures. We coupled the HLD-NAC and pseudo-phase models to develop an EOS for microemulsions where surfactant, polymer, alcohol, alkali and monovalent/divalent ions can partition differently into the excess phases and microemulsion phase as temperature and pressure are changed.
We develop a pseudo-phase model to calculate partitioning of components between lumped components or namely pseudo-phases. The pseudo-phase model is based on a transformed composition space. The partitioning model is based on different mechanisms such as cation exchange like reactions for ions and surfactant hydration properties. Next, the three-pseudo-component HLD-NAC EOS is used to calculate curvature of the interface and microemulsion phase composition based on pseudo-phases. That is, the microemulsion phase consists of a curved ruled surface between water and oil pseudo-phases. Polymer partitioning is updated based on micelle radius. Finally, the phase compositions are converted back from pseudo-phase space to the original composition space.
This model is the first comprehensive and mechanistic flash calculation algorithm based on HLD-NAC and pseudo-phase theory to calculate microemulsion properties for mixtures without the assumption of pure excess phases. This algorithm allows for modeling of the chromatographic separation of surfactant, soap, alcohol, alkali and polymer components in chemical flooding processes. Current microemulsion models usually ignore the differing partitioning of components between excess and microemulsion phases, generating discontinuities that slow computational time and adversely impact accuracy.
Nanoparticle-Enhanced Surfactant Floods to Unlock Heavy Oil
Authors: Arab Danial , Kantzas Apostolos , Bryant Steven L. 
Published: March 2018

Abstract
Thermal and solvent-based EOR methods are not applicable in many of thin post-CHOPS heavy oil reservoirs in Western Canada. Alkaline-surfactant flooding has been suggested as an alternative to develop these reservoirs. The main mechanism behind these processes has been attributed to emulsion-assisted conformance control due to the effect of synthetic and/or natural surfactants. Because nanoparticles (NPs) offer some advantages in emulsion stabilization, here we combine surface-modified silica NPs and anionic surfactants to enhance the efficiency of heavy oil chemical floods.
Based on the results of bulk fluid screening experiments, in the absence of surface-modified silica NP surfactant concentration should be tuned at the CMC (between 1 and 1.5 wt. %) to achieve the highest amount of emulsion. These emulsions are much less viscous than the originating heavy oil. However, at surfactant concentrations far from the CMC, complete phase separation occurs 24 hours after preparation. In the presence of surface-modified silica NP this emulsification was achieved at much lower surfactant concentration. The mixture of 0.1 wt. % anionic surfactant and 2 wt. % surface-modified silica NP produce a homogeneous emulsion of heavy oil in an aqueous phase. This observation was not observed when aqueous phase contains only either 0.1 wt. % anionic surfactant or 2 wt. % silica NP.
Preliminary tertiary chemical floods with water containing 0.1 wt. % surfactant and 2 wt. % surface-modified silica NP yielded an incremental oil recovery of 48 % OOIP, which is remarkably higher than that of either surfactant or NP floods with incremental recoveries of 16 and 36 % OOIP, respectively. Tertiary recovery efficiency, defined as ratio of incremental recovery factor to maximum pressure gradient during the tertiary flood, is six times greater for the surfactant/NP mixture than for the surfactant-only flood. This enhancement in recovery efficiency is of great interest for field applications where high EOR and large injectivity are desired.
A Multi-Well ASP Pilot in San Francisco: Design, Results and Challenges
Authors: Dueñas D. , Jimenez J. A. , Zapata J. F. , Bertel C. , Leon J. M. 
Published: March 2018

Abstract
A tertiary alkaline/surfactant/polymer (ASP) multi-well pilot flood was carried out in the San Francisco field, Colombia. The pilot had mixed results, as the positive subsurface response was counterbalanced by serious operational issues, that in the end did not allowed the pilot to realize its full potential. The complexity of the flow paths in a multi-sand reservoir with irregular well spacing lead to large quantities of chemicals being recirculated, which trigger the operational issues, becoming a complex loop where these issues led to closing wells, which led to changing the flow paths and generating more operational issues. The paper presents the design of the pilot, the extensive work that was carried out to understand and improve the flow in the pilot area, the response of the pilot, the challenges that were faced during its operation, and the analysis and lessons learned from this pilot.
Conditioning Polymer Solutions for Injection into Tight Reservoir Rocks
Authors: Driver Jonathan W. , Britton Chris , Hernandez Richard , Glushko Danylo , Pope Gary A. , Delshad Mojdeh 
Published: March 2018

Abstract
Water soluble polymers have been used for decades as mobility control agents for tertiary recovery processes. Viscosity is conferred by the large hydrated size of the individual high molecular weight polymer molecules; their single-molecule hydrated size is so large that it can rival the diameters of the pore throats conducting the fluid, and it is widely understood that there are permeability limits below which solutions of such polymers cannot transport well. Delineating exactly where these limits are remains challenging, and operators are left to use whatever anecdotal evidence is available to decide whether to inject polymer, and, if so, what type and molecular weight to use. A rule of thumb is that when the permeability of a rock falls below 100 millidarcys, transport can be problematic.
We have developed processing techniques for laboratory tests to condition polymer solutions for injection into reservoir carbonate cores with permeabilities below 10 millidarcys and median pore radii below one micron. Shearing and tight filtration were used to reduce the maximum size of polymers in solution while retaining as much viscosity as possible. Subsequent filtration was used to quantitatively assess the plugging behavior of the product solution across a range of pore sizes smaller than those which conduct in the rock sample. Coreflood injectivity tests revealed the onset of face plugging as a function of average polymer size. Co-solvent was shown to dramatically improve the transport of sulfonated polyacrylamides when face plugging did not occur, and those improvements were mirrored in benchtop filtration data. This improvement came despite equal-or-better viscosity in the polymer solution, demonstrating that the co-solvent did not reduce the polymer's hydrated size and therefore most likely weakens inter-molecular associations in solution. In sum, the data indicate that permeability loss occurred by two mechanisms: simple mechanical plugging and progressive adsorption, likely mediated by inter-molecular entanglements. These two permeability reduction mechanisms should be rectified by different means.
Alkaline Surfactant Polymer ASP Process for Shaley Formation with Pyrite
Authors: Ding L. , Zhai X. , Puerto M. C. , Miller C. A. , Hirasaki G. J. 
Published: March 2018

Abstract
The ASP process may still be promising for surfactant flooding of shaley formations that have high surfactant adsorption with conventional surfactant-polymer flooding. Positive sites on clays are sites where anionic surfactant adsorption occurs in conventional surfactant flooding. High pH of alkali converts positive clay sites to negative sites. In addition, sodium carbonate sequesters calcium ions due to the small solubility product of calcium carbonate. If the formation has pyrite or siderite present, the core material in the laboratory environment will likely have a coating of ferric oxide that contributes to the anionic surfactant adsorption sites. Thus the test core should be restored to reducing conditions to better represent in situ conditions.
The ASP process has two sources of surface active materials. One is injected synthetic surfactant and the other is soap generated in-situ by reaction of alkali with naphthenic acids in crude oil. However, this adds to the complexity of the process because the optimal salinity becomes a function of both the concentration of injected surfactant and in-situ generated soap. Water soluble active soap number (WSASN) is used instead of total acid number (TAN) to estimate the optimal salinity. When WSASN rather than TAN is used to estimate the soap content, the logarithm of the optimal salinity is a linear function of the soap fraction. In this presentation, we demonstrate the technology to estimate the optimal salinity of soap/surfactant mixtures and use it to develop formulations with great potential to recover oil for a weakly consolidated sandstone reservoir.
The potential of incremental oil recovery by the ASP formulation is evaluated by ASP flooding tests on both quartz sand packs and formation material. The ASP formulation recovered more than 95% of the water flooded residual oil using a 0.5 PV slug of either 0.3% or 0.5% NI blend surfactant. The sodium carbonate concentration was 1.0% and the polymer concentration was 0.3%. Moreover, it is found from simulation results that the development of soap/surfactant gradient in ASP flooding ensures the process passing through the optimal condition, where minimum IFT and low residual oil saturation will be attained.
Effect of Nano-Scale Pore Size Distribution on Fluid Phase Behavior of Gas IOR in Shale Reservoirs
Authors: Luo Sheng , Lutkenhaus Jodie L. , Nasrabadi Hadi 
Published: March 2018

Abstract
The improved oil recovery of unconventional shale reservoirs has attracted much interest in recent years. Gas injection, such as CO2 and natural gas, is one of the most considered techniques for its sweep efficiency and effectiveness in low permeability reservoirs. However, the uncertainties of fluid phase behavior in shale reservoirs pose a great challenge in evaluating the performance of gas injection operation. Shale reservoirs are featured with macro-scale to nano-scale pore size distribution in the porous space. In fractures and macropores, the fluid shows bulk behavior, but in nanopores the phase behavior is significantly altered by the confinement effect. The integrated behavior of reservoir fluids in this complex environment remains uncertain.
In this study, we investigate the nano-scale pore size distribution effect on the phase behavior of reservoir fluids in gas injection for shale reservoirs using a multi-scale equation of state modeling. A case of Anadarko Basin shale oil is used. The pore size distribution is discretized as a multi-scale system with pores of specific diameters. The phase equilibria of methane injection into the multi-scale system are calculated. The constant composition expansions are simulated for oil mixed with various fractions of injected gas. Bubble point, swelling factor, criticality and fluid volumetrics are studied in comparison to the behavior of the bulk fluid. It is found that fluid in nanopores becomes supercritical with injected gas, but lowering the pressure below bubble point will turn it into the subcritical state. The swelling factor is slightly higher with nanopores, and bubble point is lower than the bulk. The degree of deviation depends on the amount of injected gas.
A Systematic Study of the Effect of Plugging on Polymer Flooding in W Offshore Oilfield of Bohai Bay
Authors: Li Baozhen , Kang Xiaodong , Zhang Jian , Tang Engao , Wei Zhijie , Yu Wei 
Published: March 2018

Abstract
Polymer flooding, as the most effective chemical EOR technique, was widely and used in onshore oilfields in the world. Also, it has been successfully applied in China offshore oilfields as a major EOR technology. In general, compared with water flooding, the production rate in polymer flooding drops by less than 30% according to observations of onshore field application. However, the production rate dropped much more severely in mid to late stage of polymer flooding for plugging problems in W offshore oilfield, which is over 50% in some producers and leads to poor flooding performance and less incremental oil. In this study, we perform a systematic analysis through integrating production dynamic analysis, well testing and reservoir simulation for the mechanisms and impacts of the plugging during the polymer flooding based on actual field data. First, a typical 1-injector & 1 producer polymer flooding reservoir model was established. Through simulation with the detailed description of reservoir and polymer properties, the impacts of key parameters affecting the production rate of producers in different stages of polymer flooding were analyzed. In addition, the dynamic characteristics of well performance under the condition of different plugging location were examined. After that, the local grid radial refinement technology was utilized to calculate the plugging degree and pollution radius of the target wells. Finally, a full-field corner grid system numerical model with local grid radial refinement near the wellbore was built in W fileld. We performed history matching with target injectors and producers and determined the plugging degree of pollution radius near above wells.
Through this field case study, the relationship between production rates and different stages of polymer flooding was identified. In addition, a diagnostic plot for characterizing the impact of plugging location on dynamic well performance was generated. Furthermore, the degree of plugging and pollution radius of all target wells was determined accurately. This study provides critical insights for understanding the polymer plugging mechanism and its effect on polymer flooding effectiveness in the offshore oil field. It also delivers a good reference for plugging removal design and optimization of polymer flooding strategy to maximize oil recovery.
Viscous Fingering in Reservoirs With Long Aspect Ratios
Authors: Hamid S. A. , Muggeridge A. 
Published: March 2018

Abstract
This paper investigates the impact of aspect ratio on the growth rate of viscous fingers using high resolution numerical simulation in reservoirs with aspect ratios of up to 30:1. The behaviour of fingers in porous media with such high aspect ratios has been overlooked previously in many previous simulation studies due to limited computational power.
Viscous fingering is likely to adversely affect the sweep obtained from any miscible gas injection project. It can also occur during polymer flooding when using chase water following the injection of a polymer slug. It depends upon the viscosity ratio, physical diffusion and dispersion, the geometry of the system and the permeability heterogeneity. It occurs because the interface between a lower viscosity displacing fluid and a higher viscosity displaced fluid is intrinsically unstable. This means that any small perturbation to the interface will cause fingers to grow. It is therefore almost impossible to predict the exact fingering pattern in any given displacement although many previous researchers have shown that it is possible predict average behaviour (such as gas breakthrough time and oil recovery) provided a very refined grid is used such that physical diffusion dominates over numerical diffusion. It is impossible to use such fine grids in field scale simulations. Instead engineers will tend to use standard empirical models such as the Todd and Longstaff or Koval models, calibrated to detailed simulations, to estimate field scale performance.
At late times in high aspect ratio systems, we find that one finger dominates the displacement and that this finger grows with the square root of time, rather than linearly. We also observe that this single finger tends to split, during which time the solvent oil interface length grows linearly with time before one finger again dominates and grows with the square root of time. This cycle can repeat several times. We also find that industry standard empirical models cannot properly capture the average behavior of the fingering in these cases because they assume linear growth as a function of time. We show that a modified Peclet number can be used to estimate when these empirical models are no longer valid.
Pilot Scale CO2 EOR at Wellington Filed in South Central Kansas
Authors: Holubnyak Yevhen , Watney Willard , Hollenbach Jennifer , Rush Jason , Fazelalavi Mina , Bidgoli Tandis , Wreath Dana 
Published: March 2018

Abstract
Baseline geologic characterization, geologic model development, studies of oil composition and properties, miscibility pressure estimations, geochemical characterization, reservoir modelling were performed. In March of 2015 the injection well (class II) KGS 2-32 was drilled, cored, and logged through an entire anticipated injection interval. Whole core samples were obtained and tested for porosity and permeability, relative permeability, and capillary pressure. The Drill Stem Test (DST) was also conducted to estimate injection interval permeability and pore-pressure. After the injection well KGS 2-32 was acidized, Step Rate (SRT) and Interference (IT) tests were conducted and analysed for permeability, well pattern communication, and fracture closing pressure.
Approximately 20,000 metric tons of CO2 was injected in the upper part of the Mississippian reservoir to verify CO2 EOR viability in carbonate reservoirs and evaluate a potential of transitioning to geologic CO2 storage through EOR. Total of 1,101 truckloads, 19,803 metric tons, average of 120 tonnes per day were delivered over the course of injection that lasted from January 9 to June 21, 2016. After cessation of CO2 injection, KGS 2-32 well was converted to water injector and is currently continues to operate. CO2 EOR progression in the field was monitored weekly with fluid level, temperature, and production recording, and formation fluid composition sampling.
As a result of CO2 injection observed incremental average oil production increase is ~68% with only ~18% of injected CO2 produced back. Simple but robust monitoring technologies proved to be very efficient in detection and locating of CO2. High CO2 reservoir retentions with low yields within actively producing field could help to estimate real-world risks of CO2 geological storage.
Wellington filed CO2 EOR was executed in a controlled environment with high efficiency. This case study proves that CO2 EOR could be successfully applied in Kansas carbonate reservoirs if CO2 sources and associated infrastructure is available.