bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Combination Technology of Profile Control and Mini-type Surfactant Flooding: Laboratory Evaluation and Field Application
Authors: Zhao Huating , Yang Huanwen , Wu Xuguang , Zhao Puchun , Xiao Liping 
Published: December 2007

Abstract
Wenmingzai (WMZ) is a mature water-flooded Oilfield, which is characterized by high temperature (80°F), high salinity (8°104mg/L) and high heterogeneity. After long time of waterflooding, the heterogeneity is getting worse and worse. Many injection wells were treated by injecting water-plugging agents, but the treatment results are fading with treatment times. To improve treatment results, a combination technology of profile control and mini-type surfactant flooding has been applied since 1998. This paper has introduced the laboratory experiment evaluation and field application results of the combination technology. Based on the salinity, hardness and temperature of this oilfield, a new non-ion surfactant has been developed. Effects of temperature, surfactant concentration, salinity and formation water hardness on surface tension between the surfactant and reservoir oil have been studied. Results show the tension has a magnitude of 10−3 mN/N at 65° and 10−2 mN/N at 80° under reservoir brine conditions, and it can resist 5°104mg/L of brine and 1500mg/L of Ca2+ and Mg2+. Adsorption of the surfactant onto reservoir cores has been studied by static and dynamic experiments. Results show that the dynamic adsorption density is less than 0.5g/g. Core flooding experiments were carried out to prove that the surfactant could improve recovery by more than 10%. Two application examples were analyzed to show how to choose candidate wells and how to operate the injection procedures. This combination technology can be widely used to improve oil recovery for mature oilfields.
Real-Time Reservoir Model Updating Using Ensemble Kalman Filter
Authors: Wen X. -H. , Chen W. H. 
Published: December 2007

Abstract
Ensemble Kalman Filter (EnKF) has been reported to be very efficient for real-time updating of reservoir model to match the most current production data. Using EnKF, an ensemble of reservoir models assimilating the most current observations of production data are always available. Thus the estimations of reservoir model parameters, and their associated uncertainty, as well as the forecasts are always up-to-date.
In this paper, we apply the EnKF for continuously updating an ensemble of permeability models to match real-time multiphase production data. We improve the previously EnKF by resolving the flow equations after Kalman filter updating so that the updated static and dynamic parameters are always consistent. By doing so, we show that the production data are also better matched for some cases. We investigate the sensitivity of using different number of realizations in the EnKF. Our results show that a relatively large number of realizations are needed to obtain stable results, particularly for the reliable assessment of uncertainty. The sensitivity of using different covariance functions is also investigated.
The efficiency and robustness of EnKF is clearly demonstrated using an example. By assimilating more production data, new features of heterogeneity in reservoir model can be revealed with reduced uncertainty, resulting in more accurate predictions.
The Relative Effects of Acid Number and Temperature on Chalk Wettability
Authors: Zhang P. , Austad T. 
Published: December 2007

Abstract
Contrary to sandstone reservoirs, 90% of carbonate oil reservoirs are characterized as neutral to preferential oil-wet. It is documented that the water wetting nature increases as the temperature increases, which is opposite to the behavior of sandstone reservoirs. The content of carboxylic acid groups in the crude oil, i.e. the acid number, AN, appeared to be a crucial wetting parameter, which very often dictates the wetting nature of the reservoir: the water wetness decreases as the AN increases. It is, however, well known from organic geochemistry that the AN of a crude oil is linked to the reservoir temperature because decarboxylation takes place as the temperature increases. Therefore, the temperature and the AN are not independent wetting parameters for carbonates. In the present experimental investigation, we have decoupled the connection between temperature and AN and studied the individual effects of these two wetting parameters towards chalk. The porous media used are outcrop chalk from Stevns Klint with a very high porosity, about 45-50%, and low permeability, about 2 mD. A number of tests were performed using oils with different AN (0.17-2.07 mgKOH/g). The cores, which contained initial brine saturation of about 25-39%, were aged for 30 days in the corresponding crude oils at different temperatures (40, 80 and 120 C). A recently developed new wettability test method was used to quantify the wetting index. This is a very important technique, because the well known Amott test is not very sensitive close to neutral conditions. The conclusion from the work was that the AN was the most important wetting parameter, and the aging temperature only played a very minor role in determining the wetting conditions. Also a correlation between the new wetting index and Amott water index was established.
Seawater as IOR Fluid in Fractured Chalk
Authors: Austad T. , Strand S. , Høgnesen E. J. , Zhang P. 
Published: December 2007

Abstract
The wetting nature of a carbonate reservoir determines the potential of improved oil recovery by water injection, especially if the formation is highly fractured, which often is the case for chalk formations. The initial wetting state is mostly governed by the properties of the crude oil, where the acid number, AN, appeared to be a crucial parameter. The reservoir temperature plays, however, a minor role as a wetting parameter. Improved oil recovery by water injection decreases as the water-wetness decreases due to decrease in spontaneous imbibition. The relative high specific surface area of chalk, about 2-3 m2/g, indicates that compositional properties of injected fluid could influence the wetting properties of the formation somewhat during the production phase. The exceptional good response of seawater injection into the Ekofisk formation is an indication of a special rockwater interaction, which improves the spontaneous displacement of oil. In the present paper, we will summarize the results from ongoing research to improve spontaneous imbibition of water into oil-containing chalk samples at various wetting states and temperatures. The chemical composition of the imbibing fluid is discussed in relation to the composition of initial brine and changes in the rock-fluid (water and oil) equilibrium conditions. Major observations are: (1) The presence of sulfate in seawater improved spontaneous imbibition at all wetting conditions tested. (2) Sulfate is a potential determinig ion towards chalk, which has impact on the wetting state in a positive way. (3) The adsorption of sulfate onto chalk increases as the temperature increases, which implies that the efficiency of sulfate as an active wettability modifier is improved as the temperature increases. (4) The relative increase in sulfate adsorption onto chalk increases at temperatures above 100°C. (5) Injection of produced water with a high Ca2+/SO4 2- ratio is recommended to be used only as pressure support and not as an oil displacing fluid.
Effects of Organism Size and Weight on the Synthetic-Based Mud Sediment Toxicity Bioassay Using Leptocheirus Plumulosus
Authors: MacGregor R. 
Published: December 2007

Proposal
The key objective of this study was to identify controllable test parameters that might reduce test variability for the 4-day sediment toxicity bioassay of synthetic-based drilling muds (SBM) required for offshore drill cuttings discharge into the Gulf of Mexico. The factors that produce an effect on the performance of the SBM-sediment toxicity bioassays include quality of mixing procedures, sediment composition, test organism health, size and weight. This study was designed to determine how different sieve sizes might affect the size and weight variability of selected Leptocheirus plumulosus and how this selection affected the LC50 test results of the SBMsediment bioassays. The design focused on organisms collected after passing through a 1000-micron sieve and retained on either 850-micron or 710-micron sieves. Weights of sieve-selected organisms were measured before each bioassay. The data from these bioassays was used to illustrate the relationships between organism sieve size, organism weight, variability of weights within sieve size, LC50 responses to SBMs and the variability of LC50 responses. These test parameters were evaluated for their degree of effect on the SBM-sediment toxicity bioassay test result variability.
Atomic Force Microscopy Study of Wettability Alteration
Authors: Kumar K. , Dao E. K. , Mohanty K. K. 
Published: December 2007

Abstract
Waterflooding recovers little oil from fractured carbonate reservoirs, if they are oil-wet or mixed-wet. Surfactant-aided gravity drainage has the potential to achieve significant oil recovery by wettability alteration and interfacial tension (IFT) reduction. The goal of this work is to investigate the mechanisms of wettability alteration by crude oil components and surfactants. Contact angles are measured on mineral plates treated with crude oils, crude oil components, and surfactants. Mineral surfaces are also studied by atomic force microscopy (AFM). Surfactant solution imbibition into parallel plates filled with a crude oil is investigated. Wettability of the plates is studied before and after imbibition. Results show that wettability is controlled by the adsorption of asphaltenes. Anionic surfactants can remove these adsorbed components from the mineral surface and induce preferential water wettability. Anionic surfactants studied can imbibe water into initially oil-wet parallel plate assemblies faster than the cationic surfactant studied.
The Discovery of High-Molecular-Weight Naphthenic Acids (ARN Acid) Responsible for Calcium Naphthenate Deposits
Authors: Baugh T. D. , Grande K. V. , Mediaas H. , Vinstad J. E. , Wolf N. O. 
Published: December 2007

Abstract
Calcium naphthenate deposition is among the most challenging obstacles to high production regularity for oilfields where acidic crude oils are produced. Until now it has generally been acknowledged that the deposit is made up of calcium soaps of the naphthenic acids in the crude oil, though with a slight overrepresentation of the lighter acids. In this paper, however, we demonstrate that this is not the case. Through a combination of several analytical techniques – the most important being Potentiometric Titration, LC/MS, NMR, and VPO – the ARN acid has been identified as the dominating constituent of these deposits. The ARN acid is a family of 4-protic carboxylic acids containing 4 - 8 unsaturated sites (rings) in the hydrocarbon skeleton with mole weights in the range 1227 – 1235 g/mol. The mole weight of the homologous ARN acids series are 1227, 1229, 1231, 1233, 1235 (basic structures) + n×14 (n = number of additional CH2-groups in hydrocarbon skeleton). The ARN acid with mole weight 1231 has C80H142O8 as empirical formula.
The present paper describes the different analytical methods leading to the ARN acid discovery. Furthermore it discusses possible ARN structures and methods for quantitative ARN detection in crude oils. The ARN acid has proved to be the main component in naphthenate deposit from oilfields offshore Norway, Great Britain, China and West Africa. The implications of the discovery to current calcium naphthenate treating strategies will be briefly discussed.
Experimental Study on Asphaltene-Induced Formation Damage
Authors: Nabzar L. , Aguilera M. E. , Rajoub Y. 
Published: December 2007

Abstract
Application of many EOR technologies provokes productivity decline due to asphaltene deposition leading to wellbore plugging and flow restriction in tubing, flow lines and production facilities. The present study aims at investigating the kinetics of asphaltene deposition using both model system and actual crude oil. Experiments were performed by injecting asphaltenic fluids into capillaries and outcrop sandstones. The effect of flow rate, presence of resins and asphaltene aggregation were investigated.
It was experimentally evidenced that asphaltene deposition is a continuous process that results in multilayer deposition. It was demonstrated that asphaltene deposition takes place according to the well-known scaling law of Diffusion Limited Deposition (DLD) regime. The results demonstrated that multilayer deposition might be hindered by shear rate. It was shown that, above a first critical shear rate (lower critical shear rate) that depends on asphaltene aggregation state, the multilayer deposition kinetic is slowed down upon increasing injection flow rate. The flow rate dependence switches from−2/3 to −5/3 power law. This latter exponent is thought to encompass the classical −2/3 dependence of the DLD regime and the effect of asphaltene detachment that, therefore, varies as the flow rate to the power −1. The results put into evidence the existence of an upper critical shear rate value beyond which multilayer deposition is totally hindered. The value of this critical shear rate depends on resin content and varies exponentially with solvent quality.
In conclusion, the experimental results showed that the "colloidal approach" is a valuable route for asphaltene deposition modeling that can be used to develop a more realistic asphaltene near-wellbore damage model that takes into account the actual physics of the process.
New Technique for Evaluating Antiagglomerate Gas-Hydrate Inhibitors in Oilfield Applications
Authors: Oskarsson H. , Lund A. , Hjarbo K. W. , Uneback I. , Navarrete R. C. , Hellsten M. 
Published: December 2007

Abstract
Gas hydrate inhibitors have been evaluated using different techniques in the past.In particular, anti-agglomerates have been evaluated in Rocking Cells, Stirred Autoclaves, different types of pipe flow devices such as the rotating wheel device, and regular pipe rheology.In this paper the development of new anti-agglomerate chemistry is illustrated using a new technique where miniature autoclaves, that allow for the simultaneous testing of up to 47 samples in an affordable way, are used.Temperature and turbidity are measured directly, whereas the viscosity of the mixture is indirectly measured via a unique rotating stirring device.
Theoretical Modeling of Tertiary Structure of Paraffin Inhibitors
Authors: Lindeman O. E. , Allenson S. J. 
Published: December 2007

Summary
Theoretical molecular-mechanical modeling of conventional paraffin inhibitors was performed to determine a correlation between the tertiary structure of paraffin inhibitor polymers and their melting and glass transition temperatures, crystallinity, viscosity, and performance. The results allowed implementation of targeted syntheses of new advanced paraffin inhibitors. The physical properties and performance of these new paraffin inhibitors were successfully predicted by the molecular-mechanical modeling.
Salinity, pH, and Surfactant Concentration Effects on CO2-Foam
Authors: Liu Yi , Grigg Reid B. , Bai Baojun 
Published: December 2007

Abstract
The influence of a number of parameters on CO2-foam stability and surfactant adsorption at reservoir conditions are determined. In this work changes of pH from 1 to 12, salinity from 0 to 25 wt%, and surfactant concentration from 0 to 1 wt % were tested for foam stability in a bubble chamber and for adsorption in a static adsorption apparatus using pure kaolinite powder. The mechanisms by which pH and salinity influence CO2-foam behavior are also discussed in the paper.
Stability of CO2-foam is surfactant concentration-dependent. The foam was stable under all tested pH and salinities at concentrations both below and above the critical micelle concentration (CMC) except at the lowest concentration tested (0.005 wt%). The adsorption of surfactant onto kaolinite increased with salinity for both NaCl and CaCl2 with the divalent salt system inducing a higher adsorption onto the kaolinite.
General Stability Criteria for Compositional and Black-Oil Models
Authors: Wan J. , Sarma P. , Usadi A. K. , Beckner B. L. 
Published: December 2007

Proposal
A numerical scheme is unstable when the result, during the solution procedure, becomes unbounded. Explicit schemes, such as IMPES, are limited by stability conditions. Robust stability criteria can help in understanding the numerical scheme's behavior and can also be used as switching criteria for adaptive implicit models. In this paper, general stability criteria are derived for black-oil and compositional models with various levels of implicitness, including pressure implicit, pressure and saturation implicit and fully implicit.
Unlike the existing stability analyses for reservoir simulation models, we start with the most general multiphase multicomponent model framework and derive stability criteria using Fourier stability analysis on the equations to which explicit schemes are applied. Our approach takes into account all of the major mechanisms governing fluid flow, i.e., convection, diffusion, capillary forces, gravity, fluid and rock compressibility, vapor-liquid equilibrium in compositional models and solubility in black-oil models. The derived criteria can provide a reasonable measure in the most general models. Black-oil models are treated as special cases of compositional models.
Our approach is compared to existing approaches; its application within ExxonMobil's reservoir simulator, EMpower, is discussed.
Sorption of Surfactant Used in CO2 Flooding onto Five Minerals and Three Porous Media
Authors: Grigg R. B. , Bai B. 
Published: December 2007

Abstract
This paper documents results of adsorption and desorption tests performed onto five powdered minerals and three rock types using a carbon dioxide - aqueous phase foaming agent, surfactant Chaser International CD1045™ (CD). This work was performed in order to better understand surfactant adsorption behaviors and transport mechanisms through three different porous media. Batch experiments were run to determine the kinetics of the surfactant adsorption onto five powdered minerals common to the selected three porous media. Dynamic experiments were performed to determine the kinetics and equilibria of surfactant adsorption onto three porous media. Characterizations of the three porous media were performed by SEM (Scanning Electron Microscopy) to aid in discerning the mechanisms controlling the retention and release reaction rates of the surfactant through the three different rock types.
Results show that CD adsorption and desorption onto powdered minerals can be established in one hour. The decreasing order of the surfactant adsorption density onto the five minerals is: montmorillonite, dolomite, kaolinite, silica and calcite. Surfactant adsorption onto the three core systems took at least an order of magnitude longer than that onto the five powdered minerals, and the surfactant adsorption onto Berea sandstone required a longer time than either Indiana limestone or Lockport dolomite. Desorption of the surfactant from the three porous media follows exponent decline equations.
The Successful Use of Both Kinetic Hydrate and Paraffin Inhibitors Together in a Deepwater Pipeline with a High Water Cut in the Gulf of Mexico
Authors: Swanson T. A. , Petrie M. , Sifferman T. R. 
Published: December 2007

Abstract
Under deepwater operating conditions, hydrates and wax can often form blockages in a pipeline. The resultant costs to remediate the situation include not only those for removing the blockage, but also for lost production.
Potential hydrate preventative measures include Low Dosage Hydrate Inhibitors (LDHIs) which are limited by hydrate formation potential (known as subcooling that is measured in F degrees) and both fluid compositions and ratios. The subcooling for this application is very challenging, since it is between 15 F degrees under normal operating conditions and 27 F degrees under shut-in conditions.
This field application was conducted on a pipeline for a newly re-completed well which was predicted to have water cuts in the 20% range. Actual water-cuts have typically been about 35% but have also increased to above 60% at times.
The continuing evaluation of different chemistries and consequently different mechanisms for preventing hydrate and wax problems in a sub-sea pipeline is reviewed. A kinetic hydrate inhibitor (KHI) was injected after the production rates had stabilized. A wax inhibitor was also used because of previous concerns about possible wax blockage.
The kinetic hydrate inhibitor was chosen based on data from lab testing and computer modeling. Not only is steady state operation often an issue, but shut-down and, more importantly, start-up are often the major concerns. KHIs are classified as LDHIs since only low concentrations (generally below 3%) are used.
The KHI provided lower operating costs plus better environmental conditions than methanol, which had been used before the well was re-completed.
The advantages and disadvantages of this KHI product are reviewed. Some of the advantages of KHIs (compared to methanol) include reduced logistics, removal of the undesirable methanol from the crude, plus no oil/water quality issues.
This continuous injection application in the deepwater Gulf of Mexico is special since KHIs have generally not been used there. Most previous continuous injection case histories have been from the North Sea. Also, wax control additives were used in conjunction with the LDHIs.
Enhancing Chemical Efficiency Using Slow-Release Corrosion Inhibitors
Authors: Weghorn S. J. , Stegmann D. W. 
Published: December 2007

Abstract
The proper application of corrosion inhibitors within oil and gas producing wells is critical so that a timely delivery of chemical occurs throughout the system. In conventional batch treatment, the performance of the chemical and the retreatment interval depend almost entirely upon the film persistency of the product. In continuous treatment, the chemical performance depends on the concentration of inhibitor in the brine phase. By using the new slow release (mass-transfer controlled) encapsulated corrosion inhibitor described in this paper the chemical performance is based both upon the inhibitor concentration in the system and its film persistency. The novel slow-release treatment of encapsulated corrosion inhibitors approximates continuous inhibitor application while providing the film persistency characteristics best attained using a batch chemical application. This results in a chemical treatment that provides highly effective corrosion treatment in wells, especially those that present treatment challenges due to climatic conditions or for those located in remote areas.