bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Study for Optimizing Injected Surfactant Volume in a Miscible Carbon Dioxide Flood
Authors: Afonja Gbolahan , Hughes Richard G. , Shetty Shrinidhi 
Published: April 2012

Abstract
One major drawback in the implementation of CO2/surfactant enhanced oil recovery is the high cost of the surfactant volume needed and the extrapolated amount of surfactant required for use in the field. Therefore, there exists a need for a methodology to evaluate the most economic surfactant volume that will lead to optimum oil production.
This paper presents the results of laboratory experiments that were designed to study the performance of foam injection and to obtain information on the parameters that will be utilized in a future modeling study to determine the minimum but most effective volume of surfactant needed for optimum foam generation and hence oil recovery in a porous medium. The effect of reservoir pressure and surfactant concentration is studied.
Carbon dioxide and surfactant solution were co-injected into Berea sandstone core that was saturated with brine and oil after a waterflood process. Some of the values of parameters utilized in the experiments include surfactant concentrations of 0.1 wt % and 0.5 wt %, average back pressure of 2350 psi and total flowrate of 0.4 cm3/min, with CO2 injected at 0.3 cm3/min and surfactant concentration at 0.1 cm3/min, which results in a volumetric flow ratio of 3:1 and foam quality of 75%.
Results show that at a higher surfactant concentration, more oil was recovered, and a steady increase in pressure difference was observed. This indicates that foam was formed, which was also seen at the production end of the system. The foam created during the experiments with the 0.1 wt % surfactant concentration, on visual inspection, appeared to be weaker than that formed in the case of the 0.5 wt % concentration.
Upgrading Crude Oil by a Deasphalting Technology Under Non Severe Operating Conditions
Authors: Álvarez M. , Chirinos M. , Silva F. , Zabala A. , Perdomo L. 
Published: April 2012

Abstract
Because of very large reserves of heavy and extra heavy oil, mainly located in Venezuela, the development of technologies for recovering and treating these hydrocarbons becomes a key factor in the strategic valorization of those resources. In accordance with these needs, has been developed since 2005 a technology named INT-MECS®. INT-MECS® technology is a heavy and extra heavy oil deasphalting process for streams coming from waste pits and different production areas; it is based on a liquid - liquid extraction unit, using low molecular weight paraffin solvents under not severe operating conditions (temperature and pressure).
INT-MECS® technology has been evaluated at laboratory scale under a batch scheme and finally, using a 250BOPD pilot plant facility, located in Jobo field (Morichal, Venezuela); generating encouraging results with high crude conversion and an improvement in the physicochemical properties of the original fluids coming from PETROMONAGAS upgrader and Morichal's production unit: reduction of viscosities, increase in API gravity (14 – 21 °API deasphalted oils from heavy and extra heavy oils), asphaltene content reduction, desulfurization and demetallization, getting better results in transportation and refining processes.
After having passed the stages of laboratory scale and pilot scale tests, this technological solution is currently entering in a visualization study for field deployment in existing upgrading facilities schemes in the Venezuelan oil industry.
Methodology of the Juxtaposition Analysis for Fault Structural Traps
Authors: Carrasco J. 
Published: April 2012

Abstract
The new challenges of the oil exploration focused to the location in closed traps against faults in deep waters. The methodology has been developed for the juxtaposition studies by faults in structural traps that it analyzes the sealed surface, which is like an evaluation technique that quantifies of efficient way, the exploratory risk related with the sealed and the hierarchy of the prospective objectives in an opportune way speeding up the answer capacity for the taking of decisions that imply a high consumption of time and money. This summary synthesizes the method for the construction of the Allan's diagrams of juxtaposition. It consist of using computational tools that optimize the times of elaboration. The work flow has been directed in the realization of the juxtaposition (2D/3D) diagrams that it allows to evaluate the efficiency of the lateral sealed in traps against fault segment and obtaining of hydrocarbon new wells. To determine the capacity of sealed for the faults the seismic interpretation it is needed in depth of the roof-ceiling horizons, as well as the behavior of the segments of faults. Later on, it is carried out the seismic mapping of each geologic element to analyze. The principal stage of the methodology is the obtaining by means of an operation vector subtraction of the intersections of the objective horizon so much of the roof block and the ceiling block on the fault surface in the setting. Once certain, the vertical component of the fault jump for each one of the exploratory objectives. It proceeds to elaborate Allan's (2D) diagram in a profile made up of the integration of the intersections of all the objectives for each contour of fault surface. Finally, It spreads in perspective the geometry 3D of each fault plan with their intersections type and their impact in juxtaposition. This method has been proven with success in the hydrocarbon locations on deep waters of area the Region Marina from Gulf of Mexico.
Colloidal-suspension Flow in Rocks: A New Mathematical Model, Laboratory Study, IOR
Authors: Aji K. , McLindin C. , Saha A. , Le K. , You Z. , Badalyan A. , Bedrikovetsky P. 
Published: April 2012

Abstract
A new analytical model for deep bed filtration of colloidal/suspension transport under size exclusion particle capture is developed and validated. The laboratory tests on suspension flow in engineered porous media, which simulate the injection of colloidal and particle suspensions in rocks, have been carried out. The model was successfully matched with the laboratory coreflood results, predicting particle breakthrough and stabilised concentration. Compared to the previous population balance model, the present one provides a better prediction of the normalised particle concentration versus jamming ratio. The sensitivity analysis shows that among the three parameters: the mean pore radius, the standard deviation and the inter-chamber distance, the first one has the largest effect on the outlet concentration.
A Comprehensive Approach on Determining Correlations between Sonic- and Density-Log Measurements from the Gulf of Mexico and North Sea Fields for Improved Reservoir Descriptions
Authors: Bai M. , Li G. 
Published: April 2012

Abstract
In the past, numerous relations between sonic velocity (i.e., an inverse of sonic travel time, DT) and rock density were developed that were suitable for certain fields or certain rocks only. In this paper, the correlations between sonic- and density-log measurements were investigated again using the data information from multiple fields in the Gulf of Mexico (GoM) and North Sea (NS). For sandstone-shale sequences, the dominant linear relationships between travel time (DT) and formation density (RHOB) were observed and compared with the popular Gardner's method (Gardner et al. 1974) along with other known methods. The implications of data clusters distinguished by formation lithologies and rock mechanical strengths were revealed from a cross-plot analysis. The probabilities and uncertainties of the developed correlations were determined using the actual histograms from the collected data of the GoM and NS fields coupled with Monte Carlo simulations.
An Analytical Equation to Predict Gas-Water Relative Permeability Curves in Fractures
Authors: Chima A. , Geiger S. 
Published: April 2012

Abstract
Naturally fractured reservoirs (e.g., carbonates) and hydraulically fractured reservoirs (e.g., shale gas) contain a major part of the world's remaining hydrocarbon reserves yet suffer from low recovery. The accurate perdiction of multi-phase flow in fractures is hence highly important. In 1966, E. S. Romm proposed an equation to calculate oil-water relative permeability curves in fractures based on experimental results using kerosene and water. He suggested that relative permeability is a linear function of saturation (krw = Sw, krnw = Snw). However, it is not clear if linear relative permeability curves can be used for gas-water flow in fractures because there is mounting experimental evidence that in this case relative permeability curves in fractures are non-linear function of saturation. Despite this fact, Romm's equations continue to be widely used in most reservoir simulators to calculate relative permeability curves in fractures for gas recovery processes, which may lead to significant errors when predicting gas recovery from fractured reservoirs, particularly unconventional reservoirs such as shale gas.
In this work, we hence use the concept of shell momentum balance, Newton's law of viscosity and the cubic law for flow in fractures to derive a new analytical equation to calculate relative permeability curves in fractured systems for gas-water two-phase flow. This derivation shows that the relative peremeability curves should be non-linear functions of not only saturation but also viscosity. Our proposed equations, which can be implemented straightforwardly in commercial reservoir simulators, are validated with laboratory data measurements and show much better agreement compared to Romm's equation. We further demonstrate the impact of Romm's and our relative permeability models on gas recovery and time to water breakthrough: Romm's equation will overestimate gas recovery and time to water breakthrough by a factor of two, which is significant considering the low recovery typically encountered in naturally and hydraulically fractured reservoirs.
Cementing Unconsolidated Sandstone Formations with Coexisting Oil and Water
Authors: Robles J. , Sapag F. , Sanchez L. , Morris W. , Peacock H. , Bravo J. 
Published: April 2012

Abstract
Oil wells with unconsolidated formations where oil and water coexist require special attention during drilling, well completion and production stages. This is the case of a heavy oilfield located in the Neuquina Basin, Argentina, where for many years, periodic cement squeeze jobs were needed to avoid near-wellbore water channeling. In addition to formation unconsolidation, this reservoir has high porosity and permeability as well as poor lithologycal barriers.
When the top of the oil producing zone is perforated and evaluated by swabbing, viscous oil carrying formation sand is initially produced. After a short period of time (days), water cut rises to values close to 100 % promoted by the high mobility ratio. This response impedes a profitable production of these oil wells.
After analyzing open and cased-hole logs, as well as production history data, the hypothesis for the short term water invasion was identified as near-wellbore channeling caused by sand production. This process was aided by formation weakening due to its interaction with drilling and completion fluids.
The solution to this problem was based on a primary cementing procedure that included specially designed slurries containing polymeric admixtures. Effective formation isolation, bonding and near-wellbore consolidation was achieved by allowing these additives to leak-off into the unconsolidated formation. This paper presents the experimental tests performed to develop the procedure and the field results obtained after five successful cementing jobs. Sand production was significantly diminished and no cement repairs were needed after the first six months of production.
Transient Pressure Behavior for Dual Porosity Low Permeability Reservoir Based on Modified Darcy's Equation
Authors: Xu J. , Jiang R. , Xie L. , Yang M. , Wang G. , Liu J. 
Published: April 2012

Abstract
With further progress of oilfields' development in China, more and more low permeability reservoirs are being put in production. However, fluid flow in low permeability porous media no longer obeys Darcy's law, so traditional well testing interpretation methods may cause error in estimation of the reservoir parameters.
This paper describes problems encountered when analyzing transient pressure tests in low permeability reservoir. The equation to describe the non-Darcy flow was given according to experimental method and two factors were introduced into the equation to improve the Darcy's law. Based on the modified model, the theoretical well test model for dual-porosity media in low permeability reservoirs with complex fractures was derived which allows for the influence analysis of non-Darcy effect. The model was solved by numerical method and the log-log curves for the pressure responses were plotted. Sensitivity analysis shows that the pressure responses for both Darcy flow and non-Darcy flow conditions are the same for the following parameters: wellbore storage, skin factor, ratio of storativity, and interporosity flow coefficient. Non-Darcy flow mainly affects the transition section between the pure wellbore storage and radial flow region, and the pressure derivative curves exhibit a gentle transition region compared with the Darcy's flow. These type curves give a better interpretation of well testing pressure response in low permeability reservoirs.
Non-Petrochemical Surfactant for Enhanced Oil Recovery
Authors: Majidaie S. , Mushtaq M. , Tan I. M , Demiral B. , Lee S. Y. 
Published: April 2012

Abstract
A new sulfonate surfactant from non-edible vegetable oils is developed. The sulfonate surfactant was synthesized from C16-18 fatty acid and evaluated for stability, Interfacial Tension (IFT) and core flooding experiments for its capability to enhance oil recovery. The feedstock is composed mostly of unsaturated fatty acid derived from jatropha curcas oil which can be converted to fatty acid methyl ester. The methyl ester is epoxidized and hydrolyzed to hydroxyl groups, which subsequently were sulfonated to form a product named Methyl Ester Sulfonates (MES).
The performance of the synthesized surfactant was studied for its stability, IFT and core flooding experiments. The stability shows that surfactant solution in produced water is clear and free of precipitation. Based on IFT experiments optimum surfactant concentration is 1 wt% which resulted in a lowest possible IFT of 0.19 mN/m in the presence of Na2CO3 as alkali.
By conducting a displacement test, an improvement in oil recovery is observed. Surfactant floods perform to test how effectively a surfactant formulation can recover oil on tertiary oil recovery. The results confirmed that there is a possibility of developing new surfactants from vegetable oils. It can obviate the need for using petrochemicals substances in synthesizing surfactants.
Utilization of Charged Particles as an Efficient Way to Improve Rheological Properties of Heavy Asphaltic Petroleum Fluids
Authors: Alfi Masoud , Da Silva Paulo F. , Barrufet Maria A. , Moreira Rosana G. 
Published: April 2012

Abstract
High energy electron particles were utilized to improve the rheological properties of heavy asphaltic petroleum fluids and upgrade them into lighter, and more utilizable, fluids. Heavy oil reserves, as one of the most abundant sources of energy, have attracted considerable attention during the last decades. However, high viscosity of such fluids always poses problems during production and transportation operations. Complex hydrocarbon molecules in heavy petroleum fluids can be affordable sources of energy if we can find a way to convert them into components of simpler structure in a cost-efficient process. While high energy demand of conventional thermal and thermo-catalytic process casts doubts on the application of such methods, emerging electron beam upgrading technology appears to provide promising achievements as a novel hydrocarbon treatment process. Radiation thermal cracking was observed to reduce the viscosity of highly asphaltic petroleum samples more than the conventional thermal cracking method. Simulated distillation analysis showed higher concentrations of lighter components in radiolyzed samples, which indicated the intensified cracking as a result of electron irradiation. Stability of the products with time is one of the main concerns because samples with altering properties may cause difficulties after the upgrading process. The viscosity of thermally cracked samples showed a substantial increase with time, while aging investigations on radiation thermal cracking products demonstrated stable properties.
Facilitating Treatment of Produced Water from Offshore Platforms by an Oxidation/Coagulation/Flocculation Approach
Authors: Cardoso C. , Filho F. , Mahmoudkhani A. , De Caprio A. , Costa M. , Nair M. 
Published: April 2012

Abstract
On average, 3 barrels of water is produced for every barrel of oil in offshore platforms. The water must be treated for reuse or discharge. Oilfield produced water contains a diverse mixture of compounds that varies from formation to formation. Of particular importance are the organic compounds classified as "Oil and Grease" (O&G) by the Clean Water Act. These compounds must be removed to meet environmental, political and operational goals. Excessive O&G in re-injected water can foul the equipment or the formation. Discharged water must meet legal or contractual standards often less than 30 mg/L per day. Governmental restrictions are put on the quality of water-discharge to sea, but the self-imposed corporate guidelines provided by the oil-companies are often more stringent. As a result a water treatment facility running smoothly is important, and a fitting control structure provided a good tuning strategy is essential in reaching this goal. When selecting produced water treatment technologies, one should focus on reducing the major contributors to the total environmental impact. These are dispersed oil and semi-soluble hydrocarbons, alkylated phenols, and added chemicals. Experiments with several samples of produced water from South America offshore platforms have been performed. These experiments were designed to find efficacy of treatment strategies using a combination of oxidation, coagulation and flocculation methods. Experiments were conducted at various pH values (6 – 9) with samples containing TOG of 17 – 198 mg/L and TSS of 100 – 1000 mg/L. With optimal and low dosage of coagulant/flocculant, oxidation process and treatment sequence, TOGs can be easily reduced to below discharge limit. Results from our studies indicate the viability of this approach for water management in offshore platforms with no need for capital equipment.
Environmentally Friendly Dispersants for High Temperature Invert-Emulsion Drilling Fluids Weighted by Manganese Tetraoxide
Authors: Rehman Abdul , Moajil Abdullah M. , Nasr-El-Din Hisham A. , Al-Bagoury Mohamed , Steele Christopher D. 
Published: April 2012

Abstract
This paper evaluates different environmentally friendly dispersants in invert-emulsion drilling fluids that can be used to drill HP/HT wells. The drilling fluid is weighted by manganese tetraoxide (Mn3O4) particles, which have a specific gravity of 4.8 and a mean particle diameter of 1 µm. Manganese tetraoxide has different wetting properties and surface chemistry than other weighting agents. Hence, there is a need to find dispersants for manganese tetraoxide that give reduced sag, reduced rheological properties, and low fluid-loss at HP/HT conditions. This is particularly important for deep wells with narrow operating windows between pore-pressure and fracture pressure gradients.
The stricter global environmental regulations mandate the dispersants to be environmentally friendly, e.g. within OCNS group D or E.
First, oil compatibility tests and particle settling time experiments were conducted on several dispersants. From the experiments, we identified 3 oil-compatible dispersants that gave the longest settling time in base oil and belonged to OCNS group D. We investigated the effectiveness of the selected chemicals in dispersing manganese tetraoxide at HP/HT conditions. Samples of 1.9 and 2.4 SG drilling fluids were prepared and tested. Drilling fluid samples were statically aged at 400°F and 500 psi for 16 hours. Sag and rheological measurements were taken before and after aging to determine the effect of HP/HT conditions on fluid properties. Sag tendency was measured by viscometer sag shoe test (VSST). Then, HP/HT dynamic filtration tests were done at 500 psi differential pressure and 300°F to determine HP/HT dynamic fluid-loss.
We have found that one of the dispersants (nonionic) with a concentration of 8 and 16 g/l for 1.9 and 2.4 SG, respectively, gives low rheological properties and reduced sag before and after static aging. It also gives the lowest fluid-loss of the selected dispersants. For 2.4 SG fluid, 10-minute gel strength was reduced from 50 to 32 lb/100ft2, plastic viscosity from 37 to 25 cp, sag from 0.249 to 0.135 lbm/gal, and the fluid-loss at 300°F was reduced from 44.4 to 39.6 cm3, with the addition of the dispersant. This dispersant prevents agglomeration of particles, thereby reducing fluid rheological properties, sag, and fluid-loss.
State of the Art and Future Trend of Drilling Fluid: An Experimental Study
Authors: Apaleke Adeleye Sanmi , Al-Majed Abdulaziz , Hossain M. Enamul 
Published: April 2012

Abstract
In its endeavor to provide a sustainable flow of hydrocarbon energy, the Petroleum industry has been recognized by the general public as an industry that has negatively impacted the environment as a result of using either harmful materials or risky practices. This leads the industry to continuously invest in R&D to develop environmentally friendly technologies and products. For any new technology or product, the current R&D trend is toward the development of sustainable practices and expertise. Drilling fluids are necessary for drilling oil and gas wells. Unfortunately drilling fluids have become increasingly more complex in order to satisfy the various operational demands and challenges. The materials used in the process to improve the quality and functions of the drilling fluids, contaminates the subsurface and underground systems, landfills, and surrounding environment. Due to the increasing environmental awareness and pressure from environmental agencies throughout the world it is very important to look back to the drilling fluid technology to reassess its progress. To sustain its position as an environment friendly industry, the petroleum industry should make forward steps to improve its practices. This article outlines the state-of-the-art of drilling fluids. The major types of drilling fluids, their strengths, limitations, and remedies to limitations are discussed. It also presents the current trend and the future challenges of this technology. An experiment was conducted to develop an environment friendly drilling fluid which is found more convenient and user friendly based on sustainability concept. The results of the experiment show that 90/10 oil water ratio formulation has higher probability to consider as a sustainable drilling mud. In addition, future research guidelines are presented focusing on the development of environmentally friendly drilling fluids with zero impact on the environment. The paper concludes that future trend leads toward the development of sustainable drilling fluids.