bluuebunny/crossref_metadata_2025_split huggingface dataset:
Low Salinity Waterflooding in Low Permeability Sandstone: Coreflood Experiments and Interpretation by Thermodynamics and Simulation
Authors: Xie Quan , Ma Desheng , Wu Jiazhong , Liu Qingjie , Jia Ninghong , Luo Manli 
Published: August 2015

AbstractIn recent years, low salinity waterflooding (LSWF) has been a promising technique to recover oil in sandstone reservoirs. In view of research results for the last decade, it is acknowledged that substantial oil recovery beyond conventional waterflooding from sandstone is wettability alteration. However, the major contributor to wettability alteration is still uncertain. Therefore, this paper investigates this major mechanism and shows how it is involved in the process of IOR.Rock and oil surface chemistry were tested to explain the influence of zeta potential on the disjoining pressure. Coreflood experiments with permeability less than 1mD were carried out and the impact of different wettabilities ranging from strong water-wet to slight water-wet on LSWF recovery was investigated with combination of thermodynamic theory. Relative permeability curves were obtained by history matching the corefloods experiments for both slight water-wet and strong water-wet cores with consideration of salinity effect. Thermodynamics of wettability by low salinity waterflooding was analyzed to characterize the surface forces between the surfaces of oil/water and water/rock.Zeta potential results showed that decreasing divalent cations and salinity makes the electrical charges at both oil/brine and brine/rock interfaces become strongly negative, which results in elevation of the repulsive forces between oil and rock, and as a result the rock turns more water-wet, which was confirmed by thermodynamics characterization. Corefloods experiments showed that a high potential in slight water-wet reservoirs can be achieved by low salinity waterflooding due to the double layer expansion. The relative permeability curves obtained by history matching showed that LSW improves oil recovery by accelerating oil production (relative perm changes) and reducing residual oil saturation in slight water-wet rock but not in strong water-wet rock. Thermodynamics of wettability analysis indicated that the mechanism of low salinity waterflooding might be interpreted by disjoining pressure calculation.In conclusion, double layer expansion caused by highly negative zeta potential as a result of lower salinity and divalent cation plays a major role in recovering additional oil. The low salinity waterflooding EOR-Effect might be interpreted by disjoining pressure calculation. These findings can help in composition design of low salinity water to maintain higher potential to recover oil in oil field.
Effects of Crude Oil Components on the Interfacial Tension Between Oil and Surfactant Solutions
Authors: Zhu Youyi , Lei Ming 
Published: August 2015

Abstract
The oil/water interfacial tension (IFT) is a key index of the properties of chemical enhanced oil recovery (EOR) displacement systems with surfactant. The studies showed that different oil and water often required different surfactant formulations to reduce IFT. The crude oil compositions in different oilfields differ with each other. Therefore, it requires different surfactant formulations to fit oil properties. It is necessary to reveal what kinds of components in crude oil have crucial influence on IFT reducing ability of surfactants, so as to optimize surfactant formulations for certain crude oil being performed efficiently.
Daqing Oilfield crude oil was cut into five oil fractions with different boiling range by true boiling point distillation method. Group compositions (saturates, aromatics, resins, wax and asphaltene) of high boiling fraction and vacuum residuum were further separated by column chromatography and solvent extraction method. Five oil fractions and seven group compositions of crude oil were obtained. The effects of these fractions and chemical compositions on the performances of surfactants in reducing IFT were investigated.
The IFT for the crude oil fractions and group components separated were tested using sodium alkylbenzene sulfonate (ABS) surfactants with different structures. The results indicated that oil fractions and group components have different impact on surfactants in reducing IFT. Low IFT value could be obtained for 200–350 °C and 350–400 °C oil fractions by ABS with carbon chain length of C16-C18 or C16 alkyl methyl benzene sulfonate. The unfavorable interfacial activity for oil fractions were low and high boiling point fractions. The effect degree order of IFT reducing ability for group components by ABS surfactants was: resins &gt; aromatics &gt; saturates &gt; wax. High boiling point fractions and heavy components of resins and aromatics significantly influence on the performance of ABS surfactants in reducing IFT. Based on these results, an industrial product HABS was developed which could reach ultralow IFT between crude oil and surfactant solutions.
Understanding the effect of crude oil components on the performances of surfactants in reducing oil/water IFT will help us to screen and optimize surfactant oil displacement formulations targeted according to the different properties of crude oils.
Enhanced Foam Stability By Adding Dispersed Particle Gel: A New 3-Phase Foam Study
Authors: zhao Guang , Fang Jichao , Dai Caili , Yan Yuan , Yan Zhihu , You Qing 
Published: August 2015

Abstract
Foam has been successfully used for profile control in mature reservoirs for the advantages of easy preparation, selectively plugging capacity, effective profile control and displacement efficiency capacity. However, the stability of foam is a serious problem for scale applications in oilfields. Due to viscoelasticity, strong shearing stability, high temperature and salinity resistance of micron dispersed particle gel (DPG), it was prepared to stabilize foam.
The micron DPG particles were prepared using bulk gel by high shearing method in our lab (C.L. Dai, et al., 2012). A new three phase foam system was successfully prepared by adding micron DPG particles through a modification of Ross-Mile method. The foaming capacity, stability and morphology were systemically investigated. The plugging capacity and enhanced oil recovery capacity of new three phase foam have been also investigated by sand-pack flowing tests.
The effects of surfactant concentration, DPG particle concentration, salinity, oil concentration and gas-liquid ratio on the foaming capacity of three phase foam are systematically investigated. Increasing in surfactant concentration, DPG particles concentration and gas-liquid ratio can improve the foam volume and decay half-life of three phase foam, whereas increasing in salinity and oil concentration decrease the foam volume and decay half-life. By increasing in solution viscosity, adsorption at gas-liquid interface and non-adsorption in solution, the DPG particles can effectively stabilize new three phase foam. Morphology results show that the formed new three phase foam is compact and uniform. Sand-pack experimental results show that the new three phase foam has a better plugging capacity and enhanced oil recovery capacity than traditional aqueous phase foam. The new three phase foam may have a great potential for profile control in mature reservoirs.
Composition Characteristic and Miscibility Behavior of Continental Deposit Reservoir Oil
Authors: Ke Zhang , Li Shi , Ma Desheng , Chen Xinglong 
Published: August 2015

Abstract
One of the key factors in the design of gas injection project is the minimum miscibility pressure (MMP) because local sweep efficiency from gas injection is mainly dependent on the MMP. Slim tube displacement, vanishing interfacial tension, and rising bubble method are three main tests to determine MMP. However these tests are both expensive and time consuming. Our study aims to find a quick and accurate mathematical methodology to determine gas–oil MMP. This study was conducted using 30 wells data sets which have experimental CO2-MMP values. These data sets were corresponding to gas/oil compositional information of 25 blocks. In order to understand miscibility mechanism between CO2 and oil, mass transfer phenomenon between them was firstly displayed in a visible pressure-volume-temperature (PVT) cell apparatus. Different hydrocarbon compositions range effecting on miscibility were presented and reservoir oil components are classified into three pseudo-components for modeling process, which are C2-C15, C1+N2+C16+ and colloid-bitumen. Finally, CO2 density under reservoir temperature, composition coefficient (Xf) and colloid-bitumen content (mass percent) were used to predict pure CO2 MMP, a model with 3 variables was developed. The results of proposed model agree well with experimental data, which indicates that the model was reliable and predictive. This study shows great possibility for future enriched CO2 miscible injection to improve miscibility and enhance oil recovery.
Discerning In-Situ Performance of an EOR Agent In the Midst of Geological Uncertainty: II. Fluvial-Deposit Reservoir
Authors: Fatemi S. A. , Jansen J. D. , Rossen W. R. 
Published: August 2015

AbstractAn enhanced-oil-recovery (EOR) pilot test has multiple goals, among them to make money (if possible), demonstrate oil recovery, verify the properties of the EOR agent in situ, and provide the information needed for scale-up to an economic process. Given the complexity of EOR processes and the inherent uncertainty in the reservoir description, it is a challenge to discern the properties of the EOR agent in situ in the midst of geological uncertainty. We propose the “modified Egg Model” case study to illustrate this challenge: a polymer EOR process designed for a 3D fluvial-deposit water-oil reservoir. The polymer is designed to have a viscosity of 20 cp in situ. We start with 100 realizations of this 3D reservoir to reflect the range of possible geological structures honoring the statistics of the initial geological uncertainties. For a population of reservoirs representing reduced geological uncertainty after five years of waterflooding, we select three groups of 10 cases out of 100 with similar water breakthrough dates at the four production wells. We then simulate five years of polymer injection. We allow that the polymer process might fail in situ and viscosity could be half that intended. We test whether the signals of this difference at injection and production wells would be statistically significant in the midst of the geological uncertainty. Specifically, we compare the deviation caused by loss of polymer viscosity to the scatter caused by the geological uncertainty at the 95% confidence level. Among the signals considered, polymer breakthrough time, minimum oil cut and rate of rise in injection pressure with polymer injection give the most reliable indications of whether a polymer viscosity was maintained in situ. Unfortunately, given the likelihood of an unknown extent of fracturing of the injection well, injection pressure may be an unreliable indicator of in situ polymer viscosity.
Characterization of Ultra-High Molecular Weight Oilfield Polyacrylamides Under Different pH Environments Using Asymmetrical Flow FFF and Multi-Angle Light Scattering Detector
Authors: Dalsania Yogesh , Doda Ankit , Trivedi Japan 
Published: August 2015

Abstract
Various types of ultrahigh molar mass polyacrylamides (PAMs) or HPAMs and their co- and ter-polymers used not only in enhanced oil recovery, but also in drilling, fracturing, water treatment and tailing applications require an accurate description of polymer molar mass (Mw) and hydrodynamic size for their optimal design. The range of Mw for various types of available HPAMs is between 4 and 30 million g/mol and is typically determined using intrinsic viscosity measurement.
Molecular weight distribution (MWD or PDI) cannot be determined since neither standards with low PDI nor GPC/SEC techniques exist today for such ultrahigh molar mass polymers. Moreover, the solution environment in underground reservoirs, characterized by high temperatures, pH and the presence of monovalent and divalent ions, may often lead to changes in polymer macromolecular conformation. Current techniques, such as light scattering or microscopy, SEC, ultraviolet visible measurements and liquid chromatography, are not capable of accurately investigating these macromolecular complex structures for various reasons. In this paper the Asymmetrical Flow Field Flow Fractionation system was utilized to fractionate four different ultrahigh molecular weight HPAM samples, varying in molar mass and commercially used for oilfield applications, in different carrier pH values ranging from 12 to 3 (pH 12, pH 7.4 and pH 3). The system uses field flow fractionation a family of analytical techniques developed specifically for separating and characterizing macromolecules, colloids and particles. Other advantages over conventional GPC/SEC include minimum shear degradation, mild operating conditions and no sample loss due to adsorption. The flow system was equipped with a multiangle light scattering and refractive index detectors to measure molar mass and radius of gyration.
The results show that the samples molecular weights increased substantially as the pH (or the ionic strength) of the carrier solution decreased from 12 to 3, especially for higher molar mass polymers. The samples radius of gyrations showed the opposite trend decreasing as the pH of the carrier solution changed from basic to acidic. For ultrahigh molecular HPAM at high pH, a narrower molar mass and radius distribution was observed with disaggregated molar mass and increased branching or swelling (therefore higher hydrodynamic radius). Use of this direct separation and measurement technique can improve understanding of polymer macromolecular structure and respective changes in the reservoir environments to enable optimal chemical dosage in oilfield applications.
Estimation of Polymer Retention from Extended Injectivity Test
Authors: Juri J. E. , Ruiz A. M. , Hernandez M. I. , Kaminszczik S.. 
Published: August 2015

Abstract
The aim of this study was to reduce risk in polymer flooding projects. Specifically, this study investigates polymer retention and viscosity losses. The study reservoir is a fluvial type reservoir with friable/unconsolidated sandstone units that are saturated with viscous oil. The reservoir is located in the south of Argentina. Retention and viscosity losses are the key parameters in designing a polymer flooding. They slow down the polymer velocity and deplete the polymer slug leading to a significant impact in the oil banking formation and therefore in the oil response. In friable/unconsolidated reservoir rock samples the usual laboratory procedure for retention estimation is fraught with complications and errors and may lead to unreliable results.
We used a 20 month single-well injection/back-production test. And we monitored the sweep efficiency with time-lapse formation resistivity logging. The well schedule included, 5 months of water injection, three months of polymer injection and 12 months of back-production. We used an innovative inline viscometer to measure viscosity in the backflow stream at anaerobic conditions. This procedure avoided the problems of chemical degradation due Fenton chemistry with the oxygen scavenger. We measured the concentration with two methods, COD (Chemical Oxygen Demand) and bleach method.
The back-produced polymer solution showed relatively low viscosity losses as compared to that of the injected solution. The interpretation of the polymer concentration measurements with a detailed simulation model led to retention bounds between 35 to 260 micro-grams of polymer per gram of rock with heterogeneous retention depending on the facies.
This is sevenfold the value estimated from packs of crushed reservoir core material and threefold the value from coreflood studies in reservoir samples. This study has allowed us to adjust the forward planning and understand the retention behaviors in distributed clay fluvial formations.
This methodology can provide low cost reliable estimations of polymer retention at a larger scale than corefloods.
Foam Simulation From Coreflood to Field Scale
Authors: Masoudi Rahim , Ann Giddins Marie , Karkooti Hooman , Jalan Shlok , Valero Gil Adelis Alfonzo 
Published: August 2015

Abstract
Although there is a wealth of literature on experimental studies and theories of foam behavior, industry experience of foam enhanced oil recovery is still limited, and it remains a challenge to move from laboratory studies to field scale predictive simulations. This work describes a reservoir simulation study of foam enhanced oil recovery (EOR) processes, starting from a matched coreflood experiment, and extending the model to investigate foam behavior at a larger scale and over longer times.
A core-scale compositional simulation model is constructed, including chemical reactions to represent foam generation, adsorption and decay over time, with a functional representation of gas mobility reduction due to foam behavior. The simulation parameters are tuned to match production and pressure for a laboratory coreflood consisting of water, gas, surfactant and Surfactant-Alternating-Gas (SAG) injection phases. The core is modeled with 2D and 3D grids at coarse and fine scales and the results are extended to field scale sector models. Sensitivity runs are performed to determine the impact of key parameters on foam behavior for different model resolutions, sizes and timescales.
The impact of gravity override, heterogeneity, adsorption and decay can be observed even in core-sized models, and visualization of the simulated results over time shows the effect of grid design in capturing foam behavior in the core. At the field scale, simulations demonstrate qualitatively how foam improves oil recovery by reducing gas mobility and delaying breakthrough. However, upscaling and numerical dispersion effects can be significant when modeling chemical reactions and foam physics. The complexity and uncertainties of foam processes mean that additional measured data from experiments and pilot projects are needed, to develop confidence in predictions of field performance.
In this work, we aim to fill some of the knowledge gaps in simulation of foam EOR, by describing practical approaches for modeling and understanding foam processes at different scales. We focus on important parameters for upscaling from experimental results and make recommendations for further studies to assist with de-risking foam EOR projects.
Insights for Air Injection EOR from Static Oxidization Behaviours of Crude Oil
Authors: Wei Xiaofang , Yang Siyu , Wang Bojun , Yang Yongzhi , Song Wenfeng , Xu Ying , Zhou Minghui , Liu Keyu 
Published: August 2015

Abstract
Laboratory simulation experiments of air injection with low temperature (65°C, 17 MPa) for a low permeability (4.5 mD) reservoir was conducted by using crude oil from the Dagang Oilfield, Northern China. The initial oil density and viscosity are 12 API and 74.5 mPa.s, respectively. The physical properties of the crude oil such as viscosity, density in the oxidation zone before and after air injection were measured. Changes of both the saturated hydrocarbons and aromatic fractions were analyzed using GC X GC-FID. The changes of resin, asphaltene and oxygenated products were analyzed using a Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS).
The results indicate that the produced CO, CO2 and the gasified low molecular weight hydrocarbons drive the oil out from the tight reservoir core with an oil recovery of 45 %. The viscosity of the produced oil is reduced slightly by 2.6 %. The in situ viscosity, although not measured directly, should have been reduced significantly due to the thermal effect. The physical properties of the oil in the oxidation zone are deteriorated significantly, with the viscosity being increased by 30 % and the content of Oxygen by 7 %.The oxidization pathways from molecular alterations based the static oxidization of light oil at low temperature are also explored in accordance with the molecular heterogeneities.
Development of Thermo-Gels for in Depth Conformance Control
Authors: Al-Maamari R. S. , Al-Hashami A. R. , Al-Sharji H. H. , Dupuis G.. , Bouillot J.. , Templier A.. , Zaitoun A.. 
Published: August 2015

Abstract
A novel technology has been developed for in-depth profile control based on thermo-gelling polymers (refers as THR). This technology differs from the ones currently used through different aspects. Thermo-gels polymers spontaneously gel when they reach a threshold temperature. Below this temperature, the product behaves as low-viscosity fluid, with good injectivity in reservoir rock. The system is single-component, and does not require any additive, contrary to classical gel systems which need to mix a polymer with a cross-linker (and often additives) to control gelation time. It is thus of easy control and does not face the drawbacks of two- or multi-component gel systems. Moreover this family of products is bio-sourced, thus environmentally friendly (some are CEFAS approved). Different THRs have been developed whose gel temperature varies between 25 and 85°C.
The present work details laboratory evaluation of different THRs, including rheological properties, gel kinetics, gel strength, long-term stability and coreflood experiments.
Main results are as follows: i) gel temperature can be optimized by varying brine salinity and THR type and/or concentration; ii) gel kinetics is very rapid once the gel temperature is reached, iii) THRs remain stable over period of time superior to one year in reservoir conditions; iv) coreflooding experiments in sandstone rocks show moderate adsorption (around 50 μg/g), good injectivity below gel temperature and strong pressure build-up once gel temperature is reached. Gel strength can be as high as 35 bar/m.
Minimizing Formation Damage for Preformed Particle Gels in Mature Reservoirs
Authors: Elsharafi Mahmoud , Bai Baojun 
Published: August 2015

Abstract
In oilfild operations, it is important to decrease water production and increase the efficiency of oil sweep. A gel treatment is using preformed particle gels (PPGs) to reduce water flow through high-permeability formation in mature reservoirs. The success of PPGs treatment primarily depends on whether or not PPGs can reduce the high permeability zones to the anticipate level. This work sought to find methods that minimized the damage caused by PPGs on unswept, low-permeable zones/areas, thus improving PPG treatment efficiency. These results can help to identify of the best PPG types, particle sizes, and brine concentrations for specific reservoir condition. Both a static filtration test model and load pressure model were used to evaluate the damage caused by various PPGs on sandstone core samples with various degrees of permeability. Two types of particle gels, a strong Daqing gel (DQ) and a weak LiquiblockTM 40k gel (40K), were used for various experiments, each with a different strength. The particle sizes ranged from 30 to 120 meshes. Sodium chloride (NaCl) was used to prepare all brines. Various brine concentrations at room temperature were selected to prepare the swollen PPGs. The effect of particle size, core permeability, and brine concentration on core damage was investigated. Results of these experiments yielded information useful for promoting the best PPG treatment for conformance control in mature reservoirs. These results can be used to optimize PPG's design and, thus, prevent damage to the unswept, low-permeable zones/areas.