bluuebunny/crossref_metadata_2025_split huggingface dataset:
Efficient Experimental Data Acquisition for Miscible CO2 WAG Injection Corefloods in Carbonate
Authors: Duchenne Sebastien , Puyou Gilles , Cordelier Philippe , Hy-Billiot Joelle , Hamon Gerald 
Published: June 2014

Abstract
Understanding the physics behind which CO2 and water displaces oil in the porous medium is of the utmost importance for the success of any miscible CO2 water-alternating-gas (WAG) injection project. Coreflood experiments have to be designed efficiently to provide relevant information about complex three-phase flow mechanisms and ensure precise measurements of key reservoir parameters such as trapped gas saturation, CO2 relative permeability curves and hysteresis effects.
This paper presents an experimental study to investigate the effect of miscible cyclic CO2 injection on three phase relative permeability by performing a series of coreflood experiments in horizontal carbonate cores with light oil from a Middle East field. These experiments are designed using innovative data acquisition techniques to ensure data quality and allow accurate determination of reservoir microscopic properties. Produced volumes are monitored to provide material balance of each phase at both reservoir and laboratory conditions with a clear separation of flashed oil, condensate and gas. A full compositional analysis is then conducted, using gas chromatography and liquid analysis of flashed oil and condensate, providing essential information for recovery calculation. Differential pressure across the core is also monitored for relative permeability estimation. Finally, in situ saturation profiles are acquired in real time during experiments, using a dual energy X-Ray scanner for three-phase calculations. Redundancy in measurements, along with rigorous accounting of measurement uncertainties, allows a successful cross-check of all acquired data.
Methods of saturation estimation are discussed. Results show that for miscible corefloods, recovery strongly depends on how swelling and stripping mechanisms are accounted for.
Study of Particle Structure and Hydrophobicity Effects on the Flow Behavior of Nanoparticle-Stabilized CO2 Foam in Porous Media
Authors: Yu Jianjia , Wang Sai , Liu Ning , Lee Robert 
Published: June 2014

Abstract
Studies of supercritical CO2 foam stabilized with amorphous and crystalline silica nanoparticles at reservoir conditions were carried out for the CO2 foam enhanced oil recovery (EOR) application. In this paper, three types of silica nanoparticles, consisting of crystalline and amorphous structures, as well as different wettabilities, were employed to study the effects of particle structure and wettability on supercritical CO2 foam generation. The effects of silica nanoparticle structure and hydrophobicity on supercritical CO2 foam behaviors such as foam morphology, foam resistance factor and mobility were investigated under the conditions of a wide range of phase ratios and total flow rates. Our results showed that CO2 foams stabilized by crystalline silica and amorphous silica exhibit similar flow behaviors. The hydrophobicity of nanosilica plays the most important role for CO2 foam generation; the CO2 bubble size decreased significantly with the increase in hydrophobicity of silica nanoparticles. The silica nanoparticle with the highest hydrophobicity shows the greatest reduction of foam mobility under the conditions of wide-ranged phase ratios and total flow rates.
Integration of Reservoir Simulation and Time-Lapse Seismic in Delhi Field: A Continuous CO2 Injection EOR Project
Authors: Chen T. , Kazemi H. , Davis T. L. 
Published: June 2014

Abstract
In assessing the effectiveness of any CO2 enhanced oil recovery projects, it is essential to track the flow path of injected CO2 and determine the bypassed oil pockets. The objective of this research was to construct a high definition, dynamic reservoir model that can support reservoir management activity. Time lapse seismic is an effective tool for monitoring CO2 movement and deciphering flow channels in the reservoir. Reservoir engineers use mathematical simulation, which is constrained by production-injection data, to determine displacement efficiency and dynamic changes in pressure and saturation in the reservoir. Reservoir simulation also serves as a prediction tool to evaluate the economics of the CO2 projects. Both time-lapse seismic analysis and reservoir simulation can complement each other to increase the resolution of CO2 flow path and CO2 – effectiveness.
The paper presents integration of geology, geophysics and engineering for assessing a continuous CO2 injection EOR project in Delhi Field, Louisiana. The CO2-targeted formations are Tuscaloosa and Paluxy sandstones. The production and injection activities in Delhi Field result in changes in fluid saturations and pore pressure. These changes affect properties of the reservoir rock and fluids, which can be detected by time-lapse seismic analysis as P-wave anomalies. A geologic model was built using well logs, petrophysical measurements and seismic inversion for the Reservoir Characterization Project (RCP) area. We built two reservoir simulation models, including black oil and an eleven-component compositional model, based on the reservoir geologic model as the first step in the integrated research effort. We obtained production history matches for the primary, secondary and tertiary phases of the field operation.
The simulated flow paths of the injected CO2 agree well with the time-lapse seismic interpretations. This agreement validates the effectiveness of integrating geologic modeling, reservoir simulation, and time-lapse seismic analysis in assisting field operations and maximizing oil recovery efficiency.
Survelliance of Secondary and Tertiary Floods: Application of Koval's Theory to Isothermal Enhanced Oil Recovery Displacements
Authors: Jain Lokendra , Lake Larry W 
Published: June 2014

Abstract
Fluids injected during secondary and tertiary floods often leave parts of the reservoir unswept mostly because of large heterogeneity and mobility ratio. Several applications require an analytical scheme that could predict production with as few parameters possible. We develop such an analytical model of volumetric sweep that aims to apply an extension of Koval's theory (Jain and Lake, 2013) where flow is assumed to be segregated under vertical equilibrium conditions for secondary and tertiary displacements. The original Koval factor is applicable for upscaling secondary miscible floods. The new analytical model for secondary and tertiary floods is applied to provide quick estimates of oil recovery of miscible as well as immiscible displacements, which is then calibrated against field data. The model parameters: Koval factor, sweep efficiency and pore volume, estimated after history matching could be used to make reservoir management decisions. The model is very simple; history matching can be done in a spreadsheet. Single-front, gravity-free, displacements can be modeled using Koval factors. Two-front, gravity-free, displacements can also be modeled using Koval-type factors for both the fronts. These Koval-type factors, coupled with laboratory scale relative permeabilities, allows for scaling the displacement to a larger reservoir system. The new method incorporates by-passed pore volume as a parameter, a difference between this work and that of Molleai (2012), along with Koval factors and local front velocities. For two front displacements, it also accounts for the interaction between the fronts which honors correct mass conservation, another difference with the work of Molleai (2012). The results from new models for secondary and tertiary displacements were verified by comparing them against numerical simulations. The application is also demonstrated on actual field examples. Current techniques for reservoir surveillance rely on numerical models. The parameters on which these numerical models depend on are very large in number, introducing large uncertainty. This technique provides a way to predict performance without the use of computationally expensive fine scale simulation models, which could be used for reservoir management while reducing the uncertainty.
Ammonia as Alkali for ASP Floods – Comparison to Sodium Carbonate
Authors: Southwick Jeffrey G. , van den Pol Esther , van Rijn Carl H. , van Batenburg Diederik W. , Boersma Diederik M. , Svec Yi , Mastan Ahmad Anis , Shahin Gordon T. , Raney Kirk 
Published: June 2014

Abstract
Ammonia is logistically preferred over sodium carbonate for alkaline-surfactant-polymer enhanced oil recovery projects (ASP) due to its low molar mass and the possibility for it to be delivered as a liquid. On an offshore platform space and weight savings can be the determining factor in deciding whether an ASP project is feasible. Logistics may also be critical in determining the economic feasibility of projects in remote locations.
Ammonia functions as an effective alkali together with a surfactant blend of alkyl propoxy sulfate – internal olefin sulfonate (APS/IOS). Surfactant adsorption is low and oil recovery in core floods is high. Static adsorption tests show that low surfactant adsorption is attained at pH &gt; 9, a condition that ammonia satisfies at low solution concentration.
It is expected that ammonia has a performance deficiency relative to sodium carbonate in that it does not precipitate calcium from solution. Calcium accumulation in the ammonia ASP solution will occur due to ion exchange from clays. The high oil recovery for ammonia and the calcium accumulation in ASP and SP core floods with APS-IOS blends shows that this surfactant system is effective and calcium-tolerant. Also, phase behavior and IFT measurements suggest that APS/IOS blends remain effective in the presence of calcium. EO/PO sulfates (such as the employed APS) are well known commercially available, calcium-tolerant surfactants. However, due to hydrolysis sulfate-type surfactants such as APS are suitable for use only in lower temperature reservoirs.
Very different behavior was noticed for phase behavior measurements with calcium intolerant surfactants such as alkyl benzene sulfonates (ABS) and internal olefin sulfonates (IOS). In this case calcium addition results in a very high IFT and complete separation of oil and brine. Presumably this will result in low oil recovery. A preferred approach for ASP offshore with divalent ion intolerant surfactants may be the use of a hybrid alkali system combining the attributes of sodium carbonate and ammonia. The concept is to supply the bulk of the alkalinity for an ASP flood by ammonia with all the inherent logistical advantages. A minor quantity of sodium carbonate is added to the formulation to specifically precipitate calcium ions.
The Effectiveness of MEOR Permeability Modification Beyond the Well Bore
Authors: Jackson Scott , Fisher John , Fallon Bob , Norvell Joe , Hendrickson Ed 
Published: June 2014

Abstract
Biofilms produced from microbes have been shown to reduce the permeability of high perm streaks which can result in improved sweep efficiency. The rate of permeability modification is very reproducible but can vary depending on the specific treatments used. Our approach has been to inoculate the reservoir with a microbe that under the optimal nutrient conditions will express a biopolymer as a film, reduce the size of pore throats and reduce the apparent permeability. The microbe and the nutrients are tailored to the conditions of each reservoir thus giving MEOR the greatest chance for success. This paper presents data that shows modification of permeability can be accomplished away from the injector well bore by microbial production of a biofilm using a proprietary feed protocol (8). These lab scale experiments show that it is possible to do MEOR without affecting the near well bore region of an injector well. A unique set of slim tube experiments are described and an outline of the experimental procedure is provided. This work is a continuation of tests described in earlier papers (SPE129657, SPE146483 and SPE159128 – references 4, 5 and 6).
The zone of permeability modification was measured in a specially designed hydraulically constrained and segmented slim tube. The permeability was modified in later segments of the slim tube using a proprietary protocol. This demonstrates the ability to modify the permeability and control its placement well beyond the injector well bore where it can have a greater effect and avoid near well bore formation damage. In other tests, this permeability modification was shown to change composite slim tubes with high permeability contrast to a system of slim tubes that showed no permeability contrast.
A Survey of Polymer Flooding in Western Canada
Authors: Renouf G. 
Published: June 2014

Abstract
Polymer flooding is becoming increasingly more common and more successful in western Canada. In the year 2011, western Canada produced over 1,600,000 m3 of oil using polymer flooding. In the statistical study reported here, production, injection, reservoir, and operating data were gathered from 32 polymer floods of heavy and medium oil in western Canada. Success was highly variable. Incremental recovery ranged from 0.5 to 14% of the original oil in place over periods lasting between 1 and 9 years. Half of the polymer floods in the project showed a decline in water cut. Oils of very high viscosity and low gravity—as high as 5,000 mPa-s for dead oil and as low as 15°API gravity — were successfully flooded using a polymer solution.
Operational factors that were most significant to flooding success were injection volumes and rates; inclusion of horizontal wells, in particular injection wells; and water quality. Water quality was a major issue, suggesting that the success of many projects comes down to handling operational issues rather than project concept or design. Polymer integrity and injectivity led to many of the operational difficulties.
ASP Process for Anhydrite-Containing Oil Reservoirs
Authors: Sharma Himanshu , Dufour Sophie , Pinnawala Arachchilage Gayani W. , Weerasooriya Upali , Pope Gary A. , Mohanty Kishore 
Published: June 2014

Abstract
The presence of gypsum or anhydrite in oil reservoirs limits the application of alkali-surfactant-polymer (ASP) flooding using conventional alkalis such as sodium carbonate (Na2CO3) because these alkalis precipitate in the presence of gypsum leading to high alkalinity loss and permeability damage. Sodium metaborate (NaBO2) and ammonium hydroxide (NH4OH) were investigated as possible alternatives to Na2CO3. Batch mixing experiments were performed with these alkalis in the presence of excess gypsum, single phase brine-alkali transport experiments were perfomed in sandstone and carbonate cores containing gypsum, and ASP corefloods were performed in outcrop and reservoirs cores (containing gypsum). Effluent pH and ion concentrations including boron, calcium and sulfate were measured using an ion chromatograph (IC) and inductively coupled plasma (ICP). The residence times in injection experiments were increased up to 15 days to study the effect of reaction kinetics. NaBO2 and NH4OH were found to maintain and propagate a high pH of more than 10 in the batch and transport experiments without significant permeability changes. High oil recoveries were obtained in the ASP corefloods along with low surfactant retention due to the high pH propagation.
Influence of Chemical EOR on Topside Produced Water Management
Authors: Argillier J-F. , Henaut I. , Noik C. , Viera R. , Roca Leon F. , Aanesen B. 
Published: June 2014

Abstract
As a result of the recent increases in crude oil prices, a number of chemically-based enhanced recovery methods are being reconsidered by companies around the globe. But one important aspect that is generally neglected in chemically-based enhanced recovery technology concerns the impact of the EOR chemicals on the produced water cycle. This includes the compatibility of EOR chemicals with the additives used to pre-treat the injected water and to process the produced oil/water mixture after EOR chemical breakthrough. Some chemicals themselves, like surfactants and mechanically degraded polymers, may as well produce stable W/O or O/W emulsions and induce strong impact of produced water treatments, that ask for specific additives and equipment in order to keep the topside processing efficient. All these problems may seriously impact the forecast economical performance of EOR projects.
In this paper we will describe in more detail some specific constraints in terms of water management linked to chemical EOR and what are the challenges associated with backproduced chemicals (polymers & surfactants) on topside surface processes. Results will be described using a specific laboratory methodology designed to study the impact of ASP-type chemicals on water treatment efficiency, mimiking actual surface processes, that includes bottle test, gas flotation using an induced gas flotation lab column and membrane filtration. Influence of back produced polymer and surfactants is evaluated by monitoring the turbidity of the water and concentration of oil in water as a function of time.
As the present trend is to increase the use of enhanced recovery methods, among them the chemically-based ones, the industry urges for viable solutions to implement those methods while accomplishing the strict process and environmental constraints that nowadays exist. Water management is an important challenge for chemical EOR that needs an integrated approach and should be studied upfront.
Compositional Modeling of EOR Process in Stimulated Shale Oil Reservoirs by Cyclic Gas Injection
Authors: Wan Tao , Meng Xingbang , Sheng James J. , Watson Marshall 
Published: June 2014

Abstract
Cyclic gas injection is considered as an effective and quick responding recovery process that has been widely used in the worldwide. Studies showed that cyclic gas injection combined with modern technologies such as horizontal well drilling and hydraulic fracturing has achieved promising results in low permeability formation. Cyclic gas injection technique was introduced in our earlier publication for improving oil recovery in stimulated fractured shale oil reservoirs. In this paper, we focus on the effect of injected gas composition and fracture properties on oil recovery. Different injection gas scenarios such as lean gas, rich gas and CO2 were included in the simulation in order to analyze the EOR mechanisms of vaporizing, condensing or a combined condensing/vaporizing process.
Our simulation results indicate that the stimulated natural fractures are critical to enhancing oil recovery and well productivity performance in shale oil reservoirs. Since the interaction of the induced hydraulic fractures with pre-existing natural fractures and fissures makes the hydraulically fractured reservoir modeling very challenging in shale oil/gas reservoirs, we can use a dual-continuum model by making changes to the fracture permeability and intensity to attain a better characterization of the natural fractures. We conclude that cyclic gas injection in shale oil reservoirs employing hydraulically stimulated fractures is feasible to improve substantial amounts of oil production than primary production.
A Novel Low Tension Foam Flooding for Improving Post-Chemical-Flood in Shuanghe Oilfield
Authors: Tang Shanfa , Tian Lei , Lu Jun , Wang Zhengxin , Xie Yunlong , Yang Xiaopei , Lei Xiaoyang 
Published: June 2014

Abstract
Shuanghe oil field is a sandstone reservoir characterized by high water cut, poor sweep efficiency, and high heterogeneity with a long history of water flooding. The field has completed polymer flooding and is now under SP flooding. Although the SP flood is close to the end, the residual oil saturation is estimated to still be about 46~50% OOIP. Therefore, it is desired for future development of such reservoir to find an efficient method to recover residual oil. In this paper, we presented a new high-temperature resistant nitrogen foam system that gives a low oil/water interfacial tension and improves the sweep efficiency after SP flood.
A novel high activity foam agent was prepared with unique surfactants and a high-temperature resistant foam stabilizer. This foam formulation is also able to lower the oil-water interfacial tension to the order of 10-2mN/m and create stable foam at high reservoir temperature. Firstly, the concentration of the foam agent was determined by interfacial tension and foam property. Then, the molecular weight and concentration of foam stabilizer was optimized by Ross-Miles method. Next, the properties of foam formulation were measured by Ross-Miles method at different temperatures, salinities, contents of Ca2+/Mg2+, aging time. The final optimal foam formulation is 0.35 wt% foam agent and 0.1 wt% foam stabilizer, which has a low IFT (5.31×10-2mN/m) and high foam stability index (&gt;10000mLmin). Operating parameters such as foam injection modes, gas liquid ratio, injecting slug size were investigated at reservoirs conditions. The results reveal that, co-injection of gas and solution is a better option than alternating injection; the optimum gas-solution ratio is 1.5:1 by co-injection; the optimum foam injecting size is 0.5 pore volumes; and the injection rate was optimized as well.
The foam flood performance was validated by comparing with other three EOR processes in a series of four oil displacement experiments. The four individual core floods are foam, polymer, gel and SP floods, and they were all injected after water flood. Among these four core floods, foam flood showed the best performance and highest oil recovery. An additional core flood was also done to mimic the field processes. The core was first water-flooded, polymer-flooded and SP-flooded, and then the foam was injected. The results showed the foam flood can effectively recover residual oil after the previous chemical processes. All the experimental results indicate this low-tension foam flooding could be a potential application in Shuanghe oil field.