bluuebunny/crossref_metadata_2025_split huggingface dataset:
Foam-Oil Interaction in Porous Media: Implications for Foam Assisted Enhanced Oil Recovery
Authors: Farajzadeh R. , Andrianov A. , Krastev R. , Hirasaki G. J. , Rossen W. R. 
Published: April 2012

Abstract
The problems associated with many gas injection projects are the inefficient gas utilization, poor sweep efficiency and low incremental oil recovery due to viscous instabilities (channeling or fingering) and gravity segregation. These are caused by rock heterogeneity as well as the low density and viscosity of the injected gas. To mitigate these drawbacks foam can be injected into the oil reservoir by co-injection of surfactant solution and gas, or by surfactant-alternating-gas (SAG) mode. When the foam films are created in-situ, the flow of gas is hindered and gas can sweep the pores that would not be reached in the absence of foam – better vertical and areal sweep. The efficiency of the displacement process in foam-assisted gas flood depends largely on the longevity of the created foam films, and ratio of film destabilization and re-generation rates. Experimental studies have demonstrated the detrimental impact of oil on foam stability. This paper reviews the mechanisms and theories (disjoining pressure, coalescence and drainage, entering and spreading of oil, oil emulsification, pinch-off, etc) suggested in the literature to explain the impact of oil on foam stability in the bulk and porous media. Moreover, we describe the existing approaches for foam modeling in porous media and the ways these models use to describe the oil effect on foam propagation in porous media.
Further, we present various ideas on an improvement of foam stability and longevity in the presence of oil. The outstanding questions regarding foam-oil interactions are pointed out.
Biosurfactant Producing Microorganisms and Its Application to Enhance Oil Recovery at Lab Scale
Authors: Gudiña E. J. , Rodrigues L. R. , Teixeira J. A. , Pereira J. F. , Coutinho J. A. , Soares L. P. 
Published: April 2012

Abstract
Microbial Enhanced Oil Recovery (MEOR) is a tertiary oil recovery process where microorganisms and their metabolites are used to retrieve unrecoverable oil from mature reservoirs. Stimulation of biosurfactant production by indigenous microorganisms can reduce the capillary forces that retain the oil into the reservoir. The studied reservoir is characterized by alternated oil and water sand layers, with an average porosity of 25% and a permeability of 50 mD. It's a flat structure at 450 m depth, with an initial pressure of 32.4 bars and a temperature of 42.5°C. The oil is paraffinic, with low viscosity, high pour point and a gravity of 25° API, with no gas dissolved. Due to these properties, the wells can't flow naturally and the production has to be lifted, making this reservoir a good candidate for MEOR application. This work addresses the isolation and identification of microorganisms capable of producing biosurfactants and degrading heavy oil fractions at the oil reservoir conditions. Five Bacillus subtilis strains isolated from oil samples were able to grow and produce extracellular biosurfactants at 40°C under anaerobic conditions in medium supplemented with hydrocarbons. In addition, some of the isolates displayed a capacity to degrade, both in aerobic and anaerobic conditions, the large alkyl chains, and reduce the viscosity of hydrocarbon mixtures. A sand-pack column model was designed to simulate the oil recovery operations and evaluate the mobilization of residual oil by microorganisms. Additional oil recovery using B. subtilis isolates ranged from 19.8 to 35.0%, suggesting that stimulation of biosurfactant production by these strains in situ can contribute to mobilize entrapped oil. The novelty of this technique, compared to the conventional EOR methods, is the application of indigenous microorganisms to increase the oil recovery.
Polymer Trial Using Horizontal Wells: Conceptual Well Completion Design and Surveillance Planning Aspects
Authors: Mukmin Mukmin , Al-Azri N. , Al-Mjeni R. , Morshidi A. , Douma S. 
Published: April 2012

Abstract
This paper describes key aspects related to conceptual well completion design and surveillance planning for an evolving polymer field trial in the South of Oman. An existing field was developed with mostly horizontal production wells drilled at the top of the oil column to deliver high oil production rates. The production of this medium-heavy oil is supported by a strong bottom drive. However, many wells have observed premature water breakthrough resulting in high water cuts and large volume of unswept oil. Polymer flooding using a horizontal well approach is proposed to improve sweep efficiency. If successful, this alternative approach has the potential to significantly improve oil recovery in the subject field.
Because of the significant investment required and novelty of the process (i.e. heavy oil, strong bottom water drive combined with the use of horizontal wells), a field trial is planned to address some of the development risks. Key subsurface risks and uncertainties include: possible polymer losses to the underlying aquifer, loss of effective matrix polymer injectivity, lack of polymer injection conformance along the horizontals and poor sweep efficiency. A number of activities were performed to help design the field trial and reduce some key risks and uncertainties i.e. laboratory coreflood, subsurface study, injectivity test and field visit to analogue field.
The study concluded horizontal polymer injectors placed between the existing producers and slightly deeper than the centre of the oil column is optimum to recover the unswept oil. Polymer injector with Smart completion is proposed to mitigate the lack of conformance along the horizontals. A detailed surveillance plan is critical to identify the required tools and technologies to facilitate data gathering and well intervention activities during the field trial. Proposed surveillance technologies are DTS, Multi Pressure Sensors (MPS) and saturation logging. Observation wells with glass reinforced epoxy (GRE) pipe are planned to get a higher accuracy and deeper investigation of the formation saturation. These activities will be supported by calibrated subsurface simulation models as new data is available to address the trial performance, as well as, better predict full-field performance.
Polymer Flooding in a Large Field in South Oman - Initial Results and Future Plans
Authors: Al-Saadi Faisal Salim , Amri Badr Ali , Nofli Sami , Van Wunnik John , Jaspers Henri F , Harthi Said , Shuaili Khalfan , Cherukupalli Pradeep Kumar , Chakravarthi Ravula 
Published: April 2012

Abstract
In heavy oil reservoirs, water flooding leaves behind unswept hydrocarbon volumes due to unfavourable mobility ratios resulting in low ultimate recoveries. Increasing the viscosity of the injected water using polymer improves the water-oil mobility ratio resulting in improved recovery factors. This paper discusses for a large field in South Oman the successful implementation of a polymer flood project, the early results of Phase I and the planned expansions to Phase II and Phase III. Following a number of field trials and a series of laboratory studies, a full-field polymer project was implemented in the field in 2010. One of the key risks identified prior to starting the project was poor polymer injectivity. However, initial field results showed better injectivity than expected. Surveillance efforts are in progress to understand the better injectivity. The data analysis so far indicate that wellbore clean up due to polymer injection, improved as a result of improved mobility ratio and small scale induced fractures in some injectors are contributing to the improved injectivity. These factors enabled injection of more volumes of polymer than planned resulting in improved volumetric sweep efficiency and producer response. Results to date are encouraging, as after over a year of polymer injection, the oil gain due to the polymer flood is higher than expectation. Based on the initial results of Phase I, expansion phases II and III are being planned. Phase II is based on utilizing the available ullage in the system to accelerate the oil gain from polymer; it requires a relatively small upgrade of the existing infrastructure and surface facilities. Phase III is a full-field polymer flooding expansion combined with an intense infill drilling. Currently, a study is in progress to optimize the development concept for the infill wells and polymer flooding of Phase III.
New Frontiers In EOR Methodologies By Application Of Enzymes
Authors: Jain Tarang , Sharma Akash 
Published: April 2012

Abstract
Enhancement of the amount of oil recovered from existing reservoirs is slowly becoming a standard procedure during the operational life of an oil well. The need for a cost effective and efficient method led to EEOR or Enzyme Enhanced Oil Recovery, a process based on the application of enzymes. It is basically a subset of Microbial EOR in which co-injected micro organisms or nutrients are used for reduction of oil viscosity.
EEOR offers a wide array of applications due to efficient surfactant mechanism and utility in both oil-wet and water-wet systems. Moreover its cost effectiveness has led to applications in marginal oil fields, for example in the Mann Field in Myanmar this led to an increase in production from 10 bopd and 109 bwpd to 17 bopd and approximately 1636 barrels of incremental oil was produced from one of the wells within 9 months of enzymatic treatment.
Use of engineered enzymes not only counter the risk of using nutrients over a long period of time but also enhance the recovery process by accelerating desired biochemical reactions between a substrate, water medium and formation. Enzymes tend to reduce viscosity and inter facial tension to a remarkable extent. Moreover they are not consumed during the reaction and act even in low concentrations. Certain strands of enzymes like Acinetobacter sp.6A2 have the ability to degrade alkanes with a chain length ranging from C10 to C40 and reduce paraffin content.
The present paper effectively summarizes the utility of EEOR through its various advantages. Enzymes are the key to the future which eradicates the long term use of microbes. Moreover its utility in marginal fields and paraffin reduction abilities make it highly suitable for countries like India which greatly suffer from such issues.
Improve Oil Recovery for Heavy Oil by Chemical Treatment Implementation as an Alternative, Cast Study Bentayan Field
Authors: Mucharam Leksono , Nugroho Wisnu , Wibisono Kunto 
Published: April 2012

Abstract
The Bantayan field, located on the northeast flank of the South Sumatra basin, was delineated by surface geological studies in the late 1920s as a narrow northwest trending anticlinal structure bisected by numerous northeast trending transbasinal normal faults. In 1932, a discovery well encountered productive upper Talang Akar sandstones which yielded 800 BOPD of paraffinic based crude with a pore point of 115 degrees F. Until year of 1982, only 12 delineation wells were drilled, from which 12 potentially productive sandstone units were obtained within a structural area of 27 sq km. Further evaluation from other new 8-well, it was found that this reservoir system is considered a complex system.
In the Bentayan Field, the hydrocarbon oil is deposited in the Talang Akar depositional complex, with the best overall reservoir quality which is relatively thick and well-connected, fine-to coarse-grained, and cross-bedded fluvial sandstones3).
Oil properties of this reservoir currently have oil gravity of 17° API and viscosity of 82.2 cp1) at the reservoir temperature. Based on the above oil properties, Bentayan field is considered as a heavy oil reservoir, and so far only 14% of Bentayan oil reserve has been produced. Since 80 years of the discovery, reservoir pressure of Bentayan field has declined from 1696 psi to about 1035 psi, and oil production has also declined significantly. In order improve the oil production, water injection has been implementing to several wells throughout the field, however the oil production is still declining.
To reduce viscosity of the oil in the reservoir, application of steam huff n puff could not work very well for improving oil production in this field. This could be caused by high reservoir pressure and also by depth of the reservoir. Since this field is considered as a mature field where all production wells have been producing with high water cut, all conventional efforts to improve oil production would be difficult to success. Implementing chemical EOR, in this case, is the best way to increase oil production. However, the selected chemical must be able to lower the oil viscosity, lower IFT and alter the oil wettability. In this case, a special chemical treatment (SEMAR) had been implemented in this field using huff n puff technique. Since, the reservoir is under strong water drive, the injection of SEMAR can also improve oil production of other surrounding wells nearby. These phenomena are very interesting to be evaluated for further steps in fullfield chemical EOR implementation.
Improved Oil Recovery by Chemical Flood from High Salinity Reservoirs-Single-Well Surfactant Injection Test
Authors: Hsu Tzu-Ping , Prapas Lohateeraparp , Roberts Bruce L. , Wan Wei , Lin Zhixun , Wang Xiaoguang , Budhathoki Mahesh , Ben Shiau B. J. , Harwell Jeffrey H. 
Published: April 2012

Abstract
Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca2+and Mg2+, the presence of iron in the brine can be a challenging issue. Different surfactant formulations incorporating cosurfactants and co-solvents are studied. These formulations minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations are further studied in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at 42°C. Using similar injection protocols, 0.5 PVs surfactant/polymer, oil recoveries ranging from 50 % to 70% of the residual oil (Sor) after waterflooding are observed. The level of surfactant loading is less than 0.6 wt%. A single-well test is conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 165,000 mg/L total dissolved solids (TDS). The test is considered to be a technical success and confirms the effectiveness of a high-salinity surfactant-polymer formulation composed of 0.23 wt% of surfactant and 1,800 ppm of polymer loading. Approximately 87% of the residual oil was mobilized.
Laboratory Investigation of the Injectivity of Sulfonated Polymer Solutions into Carbonate Reservoir Rocks
Authors: Han Ming , Zhou Xianmin , Alhasan Fuseni B. , Zahrani Badr , AlSofi Abdulkareem M. 
Published: April 2012

Abstract
The injectivity of sulfonated polymer solutions in carbonate reservoir rocks was investigated to evaluate the performance and feasibility of the polymer in the porous media under reservoir conditions. A sulfonated polyacrylamide with a sulfonation degree of 25 mole% was selected for this study. Polymer solutions at 0.1 wt% and 0.2 wt% in seawater were injected into carbonate core plugs with a permeability ranging from 100~600 mD at reservoir temperature and pressure. Two critical parameters, the resistance factor and residual resistance factor, were obtained in the tests. The resistance factor represents a quantitative measure of the mobility reduction during the propagation of the polymer solution in the porous media, while residual resistance factor is a measure of permeability reduction after the polymer treatment. The resistance factor is 5 ~ 8 at a flow rate of 0.5cc/min for 0.1 wt% polymer solution. The residual resistance factor is 1.24 ~ 1.34 for seawater injection after the polymer injection. Meanwhile, the resistance factor is 50~65 at a flow rate of 0.5cc/min for 0.2 wt% polymer solution. The residual resistance factor is 1.48~2.17. It is found that resistance factor increases significantly with flow rate, while residual resistance factor decreases with flow rate. The investigation of adsorbed polymer layer based on the permeability reduction provides insights into the performance of the selected polymer in the carbonate cores.
Evaluation of Long-Term Gas-Hydrate-Production Testing Locations on the Alaska North Slope
Authors: Collett T.S.. S. , Boswell R.. , Lee M.W.. W. , Anderson B.J.. J. , Rose K.. , Lewis K.A.. A. 
Published: April 2012

Summary
The results of short-duration formation tests in northern Alaska and Canada have further documented the energy-resource potential of gas hydrates and have justified the need for long-term gas-hydrate-production testing. Additional data acquisition and long-term production testing could improve the understanding of the response of naturally occurring gas hydrate to depressurization-induced or thermal-, chemical-, or mechanical-stimulated dissociation of gas hydrate into producible gas. The Eileen gashydrate accumulation located in the Greater Prudhoe Bay area in northern Alaska has become a focal point for gas-hydrate geologic and production studies. BP Exploration (Alaska) Incorporated and ConocoPhillips have each established research partnerships with the US Department of Energy to assess the production potential of gas hydrates in northern Alaska. A critical goal of these efforts is to identify the most suitable site for production testing. A total of seven potential locations in the Prudhoe Bay, Kuparuk River, and Milne Point production units were identified and assessed relative to their suitability as a long-term gas-hydrate-production test sites. The test-site-assessment criteria included the analysis of the geologic risk associated with encountering reservoirs for gas-hydrate testing. The site-selection process also dealt with the assessment of the operational/logistical risk associated with each of the potential test sites. From this review, a site in the Prudhoe Bay production unit was determined to be the best location for extended gas-hydrate-production testing. The work presented in this report identifies the key features of the potential test site in the Greater Prudhoe Bay area and provides new information on the nature of gas-hydrate occurrence and the potential impact of production testing on existing infrastructure at the most favorable sites. These data were obtained from well-log analysis, geological correlation and mapping, and numerical simulation.
Design of SWTT at High Salinity and High Temperature: Where are the Limits?
Authors: Mechergui Aymen , Romero Carolina , Ganzo Alejandro 
Published: April 2012

Abstract
The single well tracer test SWTT is a well established method to measure Residual Oil Saturation (ROS) in-situ. The large radius of investigation makes the SWTT a well suited method to evaluate ROS reliably compared with other techniques such as coring and logging.
The partitioning tracer is chosen depending on three basic parameters: reservoir temperature, reservoir salinity and live oil partitioning behavior. These properties control the extent of the hydrolysis reaction that takes place during the shut-in time period to generate the secondary non-partitioning tracer. At high temperature and high salinity (HT/HS), the partitioning coefficient Kd and hydrolysis reaction rate Kh can be significantly high, therefore risking complete reaction of the partitioning tracer and loss of test results reliability.
This paper presents a simulation study carried out to evaluate the feasibility of performing SWTT at HT/HS and help the selection of tracers at these conditions. Using experimental design, a series of SWTT numerical simulations were performed to assess the impact of high Kd and Kh on ROS measurement and interpretability of tracer profile.
Results indicate that conventional rules used for SWTT design would need to be modified or adapted in order to have an interpretable signal from the test. The paper presents also the impact of modified shut-in time and drift on the quality of test.
Crude Oil, Brine Salinity and Sandstone Interaction - Nanoscale Resolution
Authors: Al-Aulaqi Talal , Fisher Quentin 
Published: April 2012

Abstract
Many laboratory experiments and field tests have shown improved oil recovery by manipulating wettability of reservoir rocks. Until recently, most of what is known about crude oil/brine/rock (COBR) interactions has been inferred from contact angle measurements, which are considered to be macro physical parameters. Advancement of surface analytical tools enables us to characterize structures of crude oil deposition as a function of brine salinity, temperature and asphaltene content at nano-scale resolution.
The non contact mode of vertical scanning interferometry (VSI) is utilised as a tool to study COBR interaction for the first time. A borosilicate glass surface used as a substrate for crude oil deposition as a function of brine salinity, temperature and asphaltene content. The main results it provides the first direct evidence of thickness of adsorption oil is largely minimised as NaCl brine salinity diluted. Furthermore the temperature shows to enhance the accumulation of oil adsorption. Three dimensional view of crude oil morphology indicate the absence of asphaltene content generate wider valleys features than the asphaltenic oil morphology. The oil solvency generates a dendritic crude oil adsorption when crude oil is mixed with heptane whereas a very thin layer when crude oil is mixed with toluene. A detail analysis of surface profile is conducted using two and three dimensional parameters.