bluuebunny/crossref_metadata_2025_split huggingface dataset:
Low Salinity Oil Recovery–Increasing Understanding of the Underlying Mechanisms
Authors: Lee S. Y. , Webb K. J. , Collins I. R. , Lager A. , Clarke S. M. , O'Sullivan M. , Routh A. F. , Wang X. 
Published: July 2010

Abstract
Water injection has been used to increase oil recovery since the late 19th century. For over 100 years, the mechanisms behind this incremental oil recovery have been thought of as physical, i.e. the injection of water maintains reservoir pressure and sweeps the mobilised oil to the producing well. In the last decade this premise has been questioned and through the development of BP's LoSal™ EOR technology, it is now recognised that oil recovery through waterflooding also involves chemical processes and that modifying the brine chemistry of the injection water can significantly impact the observed recovery.
Several hypotheses regarding the mechanism involved with low salinity waterflooding have been discussed in the literature. In 2006, BP published a proposed mechanism for this phenomenon based upon multicomponent ion exchange (MIE) triggered by expansion of the electric double layer at the mineral surfaces that bind the oil.
This paper describes on going research studies focused on advancing the understanding of these mechanisms using sophisticated physical chemistry techniques such as Small Angle Scattering using neutrons from the ILL facility in Grenoble, France and the ISIS facility at the Rutherford Appleton laboratory, UK and X-rays at the DIAMOND Light source, Oxon. These techniques are capable of measuring the thickness of any water layer at the mineral surface down to the Angstrom level.
Results to date provide some support for the BP published mechanism. They have shown the presence of a thin water layer and its variation with changes in the salinity of the water medium at model silica and clay-like surfaces, with attached (model) polar oil components, suspended in oils. Furthermore, the impact of cation-type on the water-layer thickness has also been demonstrated.
Swelling/Extraction Test of a Small Sample Size for Phase Behavior Study
Authors: Tsau J. S. , Bui L. H. , Willhite G. P. 
Published: July 2010

Abstract
Swelling/extraction tests are single-contact phase-behavior experiments to measure the solubility of CO2 dissolved in crude oil and the amount of hydrocarbon that CO2 can extract or vaporize from crude oil. The tests are commonly conducted in a visual PVT cell with a large sample size (40–100cc). In this paper, an easy operated apparatus capable of determining phase behavior with a significantly smaller sample size (3 to 14 cc) is described. The apparatus consists of a high-pressure view cell, high-pressure and precision syringe pump filled with CO2, a water bath, and accessories to measure the temperature and pressure. The device is capable of determining vapor-liquid, liquid-liquid and vapor-liquid-liquid equilibrium commonly observed in a high pressure CO2 enhanced oil recovery process. The solubility of CO2 in oil, the expansion volume of oil due to the dissolution of CO2 as well as the phase transition during the test were quantified with excellent reproducibility. The molar volume of oil saturated with CO2 correlated linearly with the mole fraction of dissolved CO2 suggesting ideal mixing in the liquid phase. The phase behavior between CO2 and crude oil samples with different composition, temperature and pressure is discussed.
Numerical Coupling of Geomechanics and Fluid Flow During Steam Injection in SAGD
Authors: Zandi S. , Renard G. , Nauroy J. F. , Guy N. , Tijani M. 
Published: July 2010

Abstract
The Steam Assisted Gravity Drainage (SAGD) process is a thermal enhanced oil recovery (EOR) method that appears tremendously successful, especially for bitumen.
SAGD process results in a complex interaction of geomechanics and multiphase flow in cohesionless porous media. In this process, continuous steam injection changes reservoir pore pressure and temperature, which can increase or decrease the effective stress in the reservoir. Quantification of the state of deformation and stress in the reservoir is essential for the correct prediction of reservoir productivity, seal integrity, hydro fracturing and well failure. In SAGD process, the analysis of reservoir geomechanics is concerned with the simultaneous study of fluid flow and mechanical response of the reservoir.
The objective of this paper is to show the importance of taking into account the role of geomechanics in SAGD numerical modeling and to provide a better description of the rock contribution to fluid flow in the SAGD process. Therefore, we introduce a geomechanics-reservoir partially coupled approach, which allows a better predictive description of the SAGD process to be performed.
The results of numerical simulations show that the classical treatment of deformation of reservoir through the rock compressibility in the conventional reservoir theory is not a rigorous framework to represent the evolution of high porous rock strains that play a significant role in the performance of SAGD.
MEOR Success in Southern California
Authors: Zahner Bob , Sheehy Alan , Govreau Brad 
Published: July 2010

Abstract
A Microbial Enhanced Oil Recovery (MEOR) process was successfully applied to a mature waterflood in Southern California, using indigenous microbes that normally remain dormant during the producing life. Certain indigenous microbial species can be activated in waterflood reservoirs by introducing the correct blend of nutrients. Once activated, the microbes multiply when the nutrients deplete, then migrate to immobile oil in search of a food source. The microbes break up this residual oil saturation into smaller micro-droplets that can flow through pore throats and be swept to producers, yielding an increase in oil recovery. The application on a producing well led to an increase in well tests from 20 to over 80 BOPD. Following this encouraging test, the nutrients were applied in three batch treatments on each of the waterflood injectors. At peak response a thirty percent oil rate increase was seen in the offset producers. Because this process uses indigenous microbes, there are no compatibility issues with reservoir fluids or concerns about survival in a foreign environment. The results from this field application demonstrate that managing a reservoir's indigenous microbes can yield significant incremental oil production in a mature waterflood with a minimal investment.
Improved Oil Recovery using Thermally and Chemically Protected Compositions Based on co- and ter-polymers Containing Acrylamide
Authors: Gaillard N. , Giovannetti B. , Favero C. 
Published: July 2010

Abstract
The change in properties of several anionic polyacrylamides that were used in various EOR projects around the world is discussed. Due to mechanical, radical and/or thermal degradations reported, the molecular weight, anionicity and viscosity of polymer change from the time it is injected until breakthrough when it is produced. Strategies for optimizing the long term stability of EOR polymers have been developed for various polymer types combined with protective additives. Polymers investigated are acrylamide (AMD) based co- and ter-polymers functionalized with monomers such as sodium acrylate (AA), sodium acrylamido-tertiary-butyl sulfonate (ATBS) or N-vinyl pyrrolidone (NVP). The additives belong to five families: free radical absorber, oxygen scavenger, metal precipitant, chelating chemicals, and sacrificial agent. The additives have been selected in addition to their chemical properties for their physical and toxicological characteristics to allow to be formulated as one single formulation under the ready-to-use powder or inverse emulsion form. Chemical and thermal stability for polymer solutions containing 50 to 500 ppb of oxygen have been evaluated using a new test apparatus that allows precise control of the oxygen level. The "as is" stabilized polymer compositions can be used for polymer, surfactant polymer and alkaline surfactant polymer floods. With this technology, polymer viscosity is stable while it propagates through the reservoir and a favorable mobility ratio is maintained from injectors to producers. This enables better sweep efficiency and more efficient oil recovery. Laboratory data shows that new acrylamide based polymer compositions maintain viscosity in the presence of oxygen and iron at high temperature and salinity. ATBS, NVP containing polyacrylamides with protective additives are shown to have the best resistance to radical and thermal degradation. The viscosity of polymer solutions aged up to 120°C can typically reach 60 - 110 % of initial viscosity after a few months compared to 10-40% of previous systems. The polymer and additive combination must be optimized in order to achieve long term thermal and chemical stability at specific reservoir conditions. Results show that polymer flooding can be successful in reservoirs with relatively high temperature and poor water quality. Improved polymer compositions stability leads to increased oil recovery from chemical floods used in EOR.
In-Situ Phase Identification and Saturation Determination in Carbon Dioxide Flooding of Water Flooded Chalk Using X-Ray Computed Tomography
Authors: Niu Ben , Yan Wei , Shapiro Alexander A. , Stenby Erling H. 
Published: July 2010

AbstractAs an effective method to enhance oil recovery and to reduce green gas emission, injection of carbon dioxide (CO2) into water flooded petroleum reservoirs has obtained increasing attention. In the laboratory study of such a process, in-situ identification of different phases and determination of their saturations by use of X-ray computed tomography (CT) is the key to visualize flow and get insight into the mechanisms of the multiphase flows in porous media.Although the flooding process is essentially three-phase, and involves interaction between oil, water and CO2 (mutual solubility, change of acidity, swelling of the oil etc.), there are few studies on identifying all the three phases and measuring their saturations, especially on chalk core under high pressure and temperature conditions. The purpose of our study is to experimentally identify different phases and to quantify their saturations during CO2 flooding. Laboratory experiments on injection of CO2 into chalk cores form the Danish North Sea, saturated with the doped live oil and the doped distilled water, have been carried out under high pressure and high temperature. Dopants were used to increase the accuracy in phase saturation determination, especially the in-situ CO2 saturation under three-phase flow conditions. The experiments utilized CT imaging to visualize the displacement patterns, in-situ fluid saturations dynamically during the flooding. Different image processing software have been used to ensure the validity of image analysis.During the experiment, in-situ saturation of CO2 in the tertiary gas flooding has been determined quantitatively and the visualization of injection process was constructed dynamically. At the same time, production of various fluids was recorded dynamically during CO2 flooding, and based on those data, detailed analysis was conducted. The key factors and the preferential parameters needed for the successful application of the X-ray computed tomography to the multiphase flows in a chalk rock were also discussed.
Application of Internal Olefin Sulfonates and Other Surfactants to EOR. Part 1: Structure - Performance Relationships for Selection at Different Reservoir Conditions
Authors: Barnes Julian R. , Dirkzwager Henk , Smit Jasper R. , Smit Johan P. , On An , Navarrete Reinaldo C. , Ellison Bob H. , Buijse Marten A. 
Published: July 2010

Abstract
The development of structure – property relationships are described for new commercial grade internal olefin sulfonates (marketed as the ENORDET™ O series) and laboratory scale alcohol-alkoxy-sulfate surfactants for use in chemical flooding. Surfactant structure was characterised by an in-house developed liquid chromatography mass spectrometry (LC-MS) technique and properties focused on oil/water microemulsion phase behaviour. Such relationships are important to match the surfactant formulation to particular reservoir conditions (temperature, salinity and crude oil). The relationship between IOS structure (by LC-MS) and optimal salinity (by phase tests) has been modeled by the empirical HLB number and by a semi-empirical molecular model. An IOS 24-28 based surfactant system gave excellent microemulsion performance with several, regionally different crude oils and an initial correlation of performance with the composition crude oils has been made. The IOS surfactants described have been produced on a pilot scale and with consistent quality. This commercially available family, and the commercially available alcohol-alkoxy-sulfate family, cover most of the salinity and temperature reservoir conditions expected, though for high temperature and high salinity reservoirs, alcohol based sulfonates will most likely be required. Finally, the chemistry of production of the IOS surfactants and their handling properties are summarised. Part 2 of this paper (SPE-129769-PP) describes work to formulate an IOS mixture that was subsequently used in a successful ASP field test.
Application of Internal Olefin Sulfonates and Other Surfactants to EOR. Part 2: The Design and Execution of an ASP Field Test
Authors: Buijse Marten A. , Prelicz Ruth M. , Barnes Julian R. , Cosmo Claudio 
Published: July 2010

Abstract
This paper discusses the design and application of an alkaline-surfactant-polymer (ASP) system for the West Salym field in West Siberia. The discussion in the paper focuses on surfactant selection, and less on polymer selection. The optimum surfactant system for the West Salym crude is a combination of IOS 24-28 (internal olefin sulfonate with a tail length of 24-28 C-atoms) and IOS 15-18 and also includes an alcohol as co-solvent. The IOS surfactants are manufactured commercially by Shell Chemicals as the ENORDET™ O series. In an accompanying paper1 the properties of the IOS family of surfactants are discussed in more detail.
For optimum performance, the surfactant needs to be tailored to the crude oil. Although the oil is not too heavy (API density is 30), and has a near-zero TAN, it contains a significant fraction of heavier components such as asphaltenes and resins, which are surface active and can interfere with the surfactant in the oil-brine interfacial layer. It is discussed in the paper how the crude oil composition affects the surfactant selection process. From test results and theoretical considerations, it was concluded that these types of crude require a surfactant with a long alkyl tail, such as an IOS 24-28. Further optimisation of the surfactant formulation was based on phase behaviour, surfactant solubility and core flow tests. To adjust optimal salinity, and to improve solubilisation, a co-surfactant (IOS 15-18) and an alcohol (2-butanol) were also added.
Polymer tests were performed as part of the ASP design program. The purpose was to optimise the ASP/oil mobility ratio. Based on filtration and rheology tests, a hydrolysed poly-acrylamide polymer with a molecular weight in the range 5-8 million was selected.
The optimised ASP system was tested in the field in a single well chemical tracer (SWCT) test. The test design, execution and result will be discussed in the paper. The goal of the SWCT test was to measure -under field conditions- the ability of the ASP system to reduce the residual oil saturation. A tracer test was performed, to measure remaining oil saturation (ROS), before and after ASP injection. The test was executed successfully. Analysis of tracer response indicated that 90% of the ROS after waterflood was mobilized by the ASP flood.
Analytical Upgridding of Geocellular Model to Preserve Dynamic Flow Behavior in the Presence of Gravity Dominated Displacement
Authors: Rittirong Ake , Kelkar Mohan 
Published: July 2010

Abstract
In simulating enhanced oil recovery processes, it is critical that all the flow behaviors are properly accounted for in the simulation. Due to computation limitations, long calculation time, and complexity of physics, geological models cannot be directly used for field wide simulations. Upgridding reduces the number of grid blocks in the simulation model and hence make the simulation more efficient. An appropriate upgridding process needs to preserve the dynamic behavior of fine scale model.
We propose such a methodology. Previous methodologies were based on preservation of variability in the fine scale models. However, those methodologies do not necessarily account for the dynamic flow behavior. Instead, our new methodology is based on preserving the fractional flow character. In upgridding the fine scale model, we have developed a criterion by which the sequence in which the fine scale layers are combined is proposed such that fractional flow characteristics based on fine scale model are honored. Using this methodology, we can not only determine the sequence in which layers are combined, but also, to what extent we can upgrid the fine scale model.
The proposed methodology is developed for two-phase, two-dimensional flow under the effect of gravity segregated displacement. However, it is also tested for three-phase, three-dimensional flow in gravity dominated displacement with moderate effect of viscous and capillary forces. The proposed solution is analytical; therefore, computationally efficient. We have validated the methodology using both synthetic and field examples and demonstrate that the proposed methodology is superior to variance based methodologies.
The Study on Mechanism of Steel Pipeline Corrosion in Dagang Oilfield
Authors: Feng Qing-xian , Zhang Zhong-zhi , Shao Ding-bo , Ren Bao-sheng , Shi Ming-yi , He Feng 
Published: July 2010

Abstract
The differences of temperature and formation water characteristics among each reservoir were significant in Dagang oilfield. Although many measures have been taken in an attempt to control steel pipeline corrosion, the corrosion rate in the south block of oilfield was several times higher than that of the middle and north blocks. Further studies, therefore, were needed to clarify the case.
The ion and microorganism concentrations of the water in nine central stations were analyzed by sampling of aberration-free point. Under nonsterile and aseptic conditions, the relations among corrosion rate, salinity and SRB numbers were studied by static and dynamic methods. The results showed that, the salinity of formation water in the south block was the high (35g/L), and its SO42- content ranged from 50 to 150mg/L. In the south block of oilfield, the SRB number was less than 102cell/ml, but the corrosion rate was 71 percent higher than standard value. The case in the middle and north block of oilfield was inverse: the corrosion rate was 73 percent higher than that of the aseptic condition; production water was fit for microbial growth; the change law of pH and Eh was different. In the south block of oilfield, electrochemical corrosion was the main factor due to the higher salinity. In addition, microbiologically influenced corrosion was significant. The electron microscope analysis showed that, corrosion products were mainly iron and sulfur compounds, and calcium carbonate.
The influence of SRB on corrosion was obtained by experiment between SRB numbers and corrosion rates. A preliminary strategy was proposed to control and reduce SRB numbers, as well as to reduce corrosion.
A Proposed Pore-Scale Mechanism for How Low Salinity Waterflooding Works
Authors: Sorbie K. S. , Collins I. R. 
Published: July 2010

Abstract
In this paper, we propose a detailed, semi-quantitative, theory of how the low salinity waterflooding effect works based upon pore-scale theoretical considerations. This theory follows on from detailed core flooding work performed in our laboratories demonstrating the importance of multicomponent ion exchange (MIE) as the underlying mechanism of low salinity waterflooding (Lager et al, 2006). Whilst this earlier work highlighted the importance of MIE, it did not explain the precise consequences of the theory in terms of quantifying the incremental oil recovery nor the precise impact on pore-scale physics. For example, with MIE occurring, the changes in the divalent cation concentrations (Ca2+ and Mg2+) leads to the development of a "self freshening" zone within the waterflooded region within which certain changes in the surface chemistry of the pore walls may occur. Such effects include expansion of the electrical double layers, changes in the adsorption of polar organic species, and resulting changes in wetting. The theory presented here attempts to show the consequences of these changes which are supported by some plausible pore-scale model calculations. These calculations i) indicate the pore-scale origins of the low salinity oil recovery mechanism, ii) show the magnitude of the effect semi-quantitatively, and iii) allow some clear predictions to be made which can be tested experimentally. This work also follows Lager et al (2006) in further explaining why both crude oil and clay-bearing reservoir rock are required for the low salinity effect to occur, and why the effect is not seen in strongly water-wet, clay-free porous media with mineral oils. Thus, this proposed pore-scale physical model of the low salinity waterflooding effect both complements and extends previous mechanistic explanations based upon multicomponent ion exchange (MIE). Although this proposed mechanism is consistent with all the available observations, further experimental studies are required to definitively confirm it.
Application of Gas for Mobility Control in Chemical EOR in Problematic Carbonate Reservoirs
Authors: Srivastava Mayank , Nguyen Quoc P. 
Published: July 2010

Abstract
The use of gas for mobility control in chemical enhanced oil recovery is an attractive option to substitute polymer in conditions where its application is not feasible. Especially in carbonate reservoirs, which generally have low permeability and contains vugs and fractures, the use of polymer may result in the loss of permeability and benefits of chemical conformance control. In such conditions, gas is a good alternative. The direct dependence of dispersed gas mobility on rock permeability reduces the likelihood of gas plugging oil-rich low permeable rock matrix in carbonate reservoirs. The mobility of both gas and liquid phases in fractures can be controlled by changing fractional gas and liquid rates in such a manner that the two phases retains their flow characteristics.
A series of high performance surfactant-gas corefloods were performed on different core samples having very low to medium permeability values. In each experiment, foamed chemical slug was chased by foamed drive. The main objective of the research work was to determine mobility control characteristic of dispersed flow by evaluating pressure response and oil recovery data obtained from corefloods.
All corefloods resulted in oil recoveries above 75% of residual oil to waterflood. No early surfactant and gas breakthrough was observed, indicating absence of viscous fingering and presence of effective mobility control. The scaled pressure gradients remained within the practical limits observed in field EOR applications. Particularly, low pressure gradients observed at relatively high fluid rates indicates a degree of in-situ foaming for favorable injectivity, thus highlighting the potential use of gas in low permeability reservoirs. The beneficial effect of trapped surfactant mobilization on foaming, with the decrease in salinity, was observed in the form of increased foam strength during the drive injection phase.
The experimental study provides an insight into the effective application of gas in chemical floods in problematic carbonate formations. Substituting polymer with gas increases the applicability of chemical EOR methods in different types of reservoirs.