bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Fluorosurfactant Performance with Super-Critical CO2 Flooding for High Salinity Carbonate Reservoirs
Authors: Jangda Z. Z. , Sultan A. S. , Gajbhiye R. N. , Abu-khamsin S. A. , Arshad A. 
Published: June 2014

Abstract
Super-Critical CO2 flooding combined with surfactants is one of the latest methods being used for Enhanced Oil Recovery. This overcomes the shortcomings associated with CO2 gas injection like gravity override and viscous fingering to an appreciable extent. It restricts the mobility of the injected fluid leading to higher contact with the resident crude resulting in better sweep efficiency. A number of surfactants have been tested with CO2 to appraise performance in different scenarios. However there have been problems of surfactant instability at real reservoir conditions i.e. at high temperature and high salinity. Adsorption of surfactants on the rock surface is another issue that usually decreases the effectiveness of the system.
In the core-flood experiments performed in this work, an amine oxide-based amphoteric fluorosurfactant has been injected with super critical CO2 for the first time on foot long carbonate cores saturated with high saline formation water (Total Dissolved Solids &gt; 200,000 ppm). High temperature (90°C) and pressure (2500 psi) were applied coupled with 5 days of aging time with reservoir crude to recreate actual reservoir environment. Different injection strategies were studied including co-injection of super-critical CO2 and surfactant solution, and alternating injection of super-critical CO2 and surfactant solution in different ratios, and then compared to find out the optimum injection strategy.
Results from the study exhibit a significant increase in the oil recovery due to this CO2-surfactant system as well as foam generation in high saline environment for the co-injection scheme.
This research provides a new and viable option for CO2-Surfactant flooding especially for high salinity carbonate reservoirs. It displays the usefulness of the surfactant even at very low concentrations, thus mitigating the high cost of this type of surfactants. Furthermore, this surfactant does not contain environment harmful substances making it a greener substitute to conventional hydrocarbon surfactants.
The Novel Use of Deep Eutectic Solvents for Enhancing Heavy Oil Recovery
Authors: Mohsenzadeh A. , Al-Wahaibi Y. , Jibril B. , Al-Hajri R. 
Published: June 2014

Abstract
The World has abundant deposits of heavy crude oils. In the past, production of such heavy oil was disfavored due to discouraging economic feasibility and availability of lighter oils. Increasing demand and dwindling supply of crude oil have spurred efforts towards enhancing heavy oil recovery. Recently, applications of ionic liquids (ILs) for heavy oil recovery and catalytic upgrading have been reported. However, ILs are generally considered too expensive for industrial applications. Moreover, certain types of ILs are non-biodegradable and toxic. An alternative class of ILs called Deep Eutectic Solvents (DESs) have recently been discovered and investigated upon. A DES generally composed of two or more components that are capable of self-association, to form eutectic mixture with a melting point lower than that of each individual component. DESs are non-toxic, biodegradable, recyclable, nonflammable, environmentally friendly and cheap. Therefore, DESs have found application in fields like extraction/separation, solvent development/reaction medium, hydrometallurgy, etc. In this study, and for the first time to our knowledge, the effectiveness of two different types of DESs, Choline Chloride:Glycerol(1:2) and Choline Chloride:Urea(1:2), in enhancing heavy oil recovery is thoroughly investigated. Effect of the two DESs diluted with water on emulsification, altering wettability, spontaneous imbibitions, surface and interfacial tensions and tertiary residual heavy oil saturation reduction are studied experimentally at different temperatures. Heavy oil with 16 °API and formation brine from one of the Omani heavy oil fields was used. The core flood experiments were conducted at reservoir condition and using Berea sandstone core plugs.
The results showed that the two DESs did not make emulsion with the heavy oil. They increased the IFT of oil-brine system. Moreover, the two DESs altered the wettability of the sandstone rock surfaces from strongly oil-wet to neutral-wet conditions. The core flooding runs at different temperatures showed high potential of using these DESs for enhancing heavy oil recovery; where 14-30% of water flooded residual heavy oil was recovered after injecting the DES solvents as tertiary recovery stage.
Oil Production From Heated Core Plugs: Experimental Results and Thermal Simulation
Authors: van Heel A. P. , Oedai S. , van Wunnik J. N. 
Published: June 2014

Abstract
Recovering medium to heavy oil from fractured carbonate reservoirs, which typically have a low matrix permeability, is challenging. Steam-injection is a promising EOR application for such reservoirs, as it initiates beneficial processes like thermal expansion and viscosity reduction of the oil, leading to an increased rate of gas-oil gravity drainage, resulting in accelerated recovery. In addition thermal solution-gas drive and distillation of lighter components can be activated upon heating.
We present experimental results and thermal simulation results of oil production from carbonate core-plugs during heating, which were designed to determine the contribution of the various thermal recovery mechanisms. Two carbonate core-plugs were cleaned, aged with formation brine and live-crude to restore original wettability, and were subsequently heated from 50 C to 235 C at a constant pressure of 31 bara, in a dedicated set-up.
The liquids and gas expelled from the core-plugs were continuously collected in a separate collection vessel, also at 31 bara.
The recovered oil volumes were substantial. We simulated the experimental results by thermal k-value simulation and obtained good agreement with experimental results. Progressive heating activates several recovery mechanisms: thermal expansion, thermal solution-gas drive and distillation. The temperature ranges where each of these recovery mechanisms are dominant are clearly distinguished in the experimental and simulation results.
The results provide quantitative estimates for the contribution of the various thermal recovery mechanisms in carbonate reservoirs subject to steam-injection.
CEOR Facilities: Onshore Concept as an Alternative to Offshore
Authors: Mahbob Izwan Nizam , Abd Satar Fairudul Azhar , Mohamad Othman Khairul Anwar , Amirrudin Farahnajwa , Yaacob Aisha A'shikin , Halim Nor Hadhirah , Zainal Suzalina 
Published: June 2014

Abstract
PETRONAS is currently embarking on a project to implement Chemical Enhanced Oil Recovery (CEOR) by injecting 160,000 BWPD of chemically enhanced water consisting of Alkaline and Surfactant (AS) for a period of four (4) years. The oil field is located in the South China Sea and has been in operations for thirteen (13) years.
Initially in terms of facilities development, the base case identified for the project was a floating vessel (ship) concept which was preferred to other options considered at the time such as having a new standalone platform or a bridge link platform to house the water treatment and chemical mixing and injection facilities. Short duration of CEOR injection, opportunity to redeploy the floater to reduce lease costs as well as the ability to store large volumes of treated water and chemicals were key factors in selecting the floater to be the base case. Further studies using the floater concept i.e. Basic Engineering Design (BED) and Front End Engineering Design (FEED) were carried out in 2011 and 2012 to mature the development concept.
High project cost and chemical logistics challenges learnt from these engineering works resulted in a decision to explore other alternative facilities development concept which could meet the project requirements but at a lower cost and risks. One of the options identified is to build the CEOR Plant at onshore and deliver the chemical mixture by using a pipeline. The opportunity to consider this option was made possible with the availability of an existing oil pipeline that connects the CEOR Field and an existing Onshore Crude Oil Terminal belonging to PETRONAS. A feasibility study was immediately carried out to assess this option which included evaluation of the compatibility of the cocktail with the pipeline internal walls as well as its effectiveness after travelling the whole length of the pipeline at varying seawater temperatures. In parallel, potential locations to construct the plant were surveyed, a preliminary layout of the plant was drafted and numerous seawater intake options evaluated including the potential of using river water as alternative to seawater to produce the designer water required.
Results from the feasibility study were encouraging and high level cost estimates indicated significant savings could be achieved by pursuing the onshore plant option. More importantly logistics challenges associated with transportation of huge amount of chemicals to offshore and other operational constraints would be eliminated via this option. This new alternative concept has given a new lease of life for the project to be realized.
Polymer Flood at Adverse Mobility Ratio in 2D Flow by X-ray Visualization
Authors: Skauge Tormod , Vik Bartek Florczyk , Ormehaug Per Arne , Jatten Berit K. , Kippe Vegard , Skjevrak Ingun , Standnes Dag Chun , Uleberg Knut , Skauge Arne 
Published: June 2014

Abstract
Polymer flooding is a mature EOR technology, but several pore scale phenomena with possible large influence on the reservoir scale are poorly understood. This paper describes and analyses oil mobilization experiments of heavy oils by imaging instable displacement at adverse mobility ratio water and polymer floods. Two-dimensional flood experiments have been performed using Bentheimer outcrop slabs. X-ray imaging is utilized to visualize displacements and to determine the underlying flow mechanisms. Viscous fingering, water channel formation and oil displacement are described for a series of mobility ratios.
Mechanistic understanding of development and propagation of viscous fingers at adverse mobility ratio may be used to improve reservoir simulations. Description of oil mobilization for various mobility ratios may give guidelines for choice of polymer concentration and slug size for polymer floods.
Bentheimer slabs were drained using oils with 4 viscosities (5 − 616 mPa∙s). X-ray imaging revealed differences in water-finger formation, and width and growth of fingers with increasing mobility ratio. Lower mobility ratios showed formation of wide fingers or water channels. Oil recovery was dominated by propagation of these channels, but still showed poor sweep efficiency (water breakthrough 0.3 – 0.5 PV). At high mobility ratio, water breakthrough occurred very early at 0.08 – 0.15 PV. Here, the oil recovery mechanism was totally different. Oil was mobilized by polymer injection through cross-flow into the water channels. Polymer flood showed rapid change in oil cut and high total oil recovery efficiency. Through analysis of 2D x-ray images, mechanisms for fingering initiation and propagation and for oil mobilization by polymer is visualized and discussed as a function of mobility ratio.
The results presented here may impact polymer flood design, in particular the choice of polymer injection strategy for heavy oil reservoirs. Data show that relatively low polymer concentrations are sufficient for mobilizing heavy oil.
Overview and Analysis of a Thermal Trial in a Deep Ultra-Heavy Oil Field in South of Oman
Authors: Al-Hinai Rashid , Al-Bahlani Al Mutasim , Al-Maharbi Abdulaziz , Al-Qassabi Dawood , Abdullah Jahdamy , Nasser Omairy , Musallam Mandhari , Al-Hinai Nasser 
Published: June 2014

Abstract
A thermal steam trial is applied in a multi-billion barrel STOIIP oilfield with very complex reservoir and oil properties. With low permeability, and saturation, deep thinly laminated formation and ultra heavy oil viscosity (100,000 cp at reservoir temperature of 65o C), the field introduces extreme challenges for conventional thermal development. This requires innovative solutions to stretch the thermal development boundaries to achieve technical and commercial success. In order to accommodate such subsurface challenges, unique surface facilities were acquired which made it possible to inject heat at high pressures.
Despite all these challenges, Phase 1 of the trial successfully conducted 4 cyclic steam stimulation cycles where over 13,000 tons Cold Water Equivalent (CWE) were injected into the formation at high pressure (21,000 Kpa) and high temperature (360o C) environment. With such extreme conditions, the project team managed to perform 11 PLT runs during injection, soaking and free-flow periods, making such success an industry-first in the region.
Previous paper (Stretching the EOR Boundaries: Thermal Trial in one of Petroleum Development Oman's Deep Reservoirs containing Heavy Oil, M. Mandhari et al) provided an overview of the early stages of the development of the trial. This paper will provide a thorough overview of the surveillance data during Phase 1 of the trial. "It will also provide an extensive representation of the analysis done on the gathered data which led to the design of Phase 2 of the trial and the methods selected to achieve higher latent heat injection into the formation."
Construction, Operations and Performance of the First Enclosed Trough Solar Steam Generation Pilot for EOR Applications
Authors: Palmer Daniel , O'Donnell John 
Published: June 2014

Abstract
This paper presents performance, results and learnings from the first solar enhanced oil recovery (EOR) project in the MENA region.
The following areas are covered in the paper: the motivation for solar EOR in Oman, description of the enclosed trough design employed in the Amal field, operations and performance data in the Oman desert environment, integration with oilfield operations and an update on results at the time of publication.
According to industry forecasts, the GCC region faces a significant shortfall of gas supply. In Oman today, over 22% of gas consumed is used for oil production including power generation, gas injection and steam generation for EOR.
The pilot project deployed in Amal West field was of a new enclosed trough design in which solar radiation is concentrated using parabolic trough mirrors that are enclosed to protect them from dust and wind loading. The "once-through" design allows the use of standard OTSG feed-water to produce 80% quality steam at 100 bar, matching typical EOR specifications.
The key objective for the pilot was to prove that the system is able to be deployed practically and economically at scale in the region. To do this several key elements had to be field proven. First, it was important to prove that the steam output could be modeled and predicted with certainty. The paper will discuss performance verses model and the enhancements implemented during the year to improve steam production and quality. Second, the oilfields of Oman lie in a region with about fifteen times higher dust or "soiling rate" than locations where concentrating solar power (CSP) is typically deployed. The performance of the system in extreme weather was tested. In conclusion, the data will point towards the feasibility of full field deployment of solar EOR in the region and explore some of the challenges that lie ahead in its adoption.
Study of the Hydraulic Performance of Drill Bits Using a Computational Particle-Tracking Method
Authors: Moslemi Ali , Ahmadi Goodarz 
Published: June 2014

Summary
The hydraulic performance of fixed-cutter drill bits was studied with the ANSYS-FLUENT code (ANSYS 2012). Cuttings were modeled as spherical particles that were injected from the bottom of the hole, and discrete particle modeling (DPM) was used to track the cuttings in which particle/particle interaction is ignored. The ratio of average particle velocity to average annulus fluid velocity, referred to as the cuttings-transport ratio (Ct), was then evaluated to study the hydraulic performance of drill bits under different conditions.
The simulation results show that Ct increases as nozzle-jet velocity and HSI (hydraulic horsepower per square inch of bit) increase. Comparing Ct with rate-of-penetration (ROP) data available in the literature revealed that the rate of Ct change is less than that of ROP as HSI changes. Ct decreased slightly in a bit with seven nozzles when compared with the same bit with five nozzles with the same total flow area (TFA) of nozzles and inlet flow rate. Also, Ct was found to be insensitive to the nozzle-size arrangement and bit-waterway profile in the studied bit size. Overall, the current method (with the assumption of negligible particle/particle interaction) is more appropriate for predicting drill-bit hydraulic performance when drilling hard and nonreactive formations.
Digital Energy Assessment: The First Step Towards Operational Excellence
Authors: Arcot Senthil , Lochmann Mark 
Published: June 2014

Abstract
Digital Energy (DE) describes broad initiatives to improve asset performance and boost corporate value through operational excellence and engineering design. It has been described in many papers presented at SPE meetings such as Digital Energy in Houston and Intelligent Energy in Europe and the Middle East. Digital energy introduces new principles and information technology (IT) tools, frequently requiring new work processes, workforce adoption, and changes in behavior. One description of digital energy (Davidson and Lochmann 2011) includes:
Fully-integrated, multi-disciplinary operations Task and process automation Digitally-enabled technology Business or operational intelligence Innovative, efficient methods to maximize performance
The move from ‘good enough’ practices to operational excellence is a transformational change (evolving from one ‘look’ to another or one culture to another)and poses challenges and opportunities for organizations. Applying DE principles to promote operational excellence inevitably leads to new ways of working and unfortunately, organizational stress. Some of the challenges include aligning people, technology, and the organization to the new vision.
The first step in the digital energy process, regardless of a project’s size, should bean assessment of an organization’s current state including its level of understanding of DE, readiness to change, and what a digital energy initiative may contain. An assessment is a way to look into the world of DE and identify the functionality that may be best suited for a company’s operating environment and assess its impact on performance. Assessments have proven essential for success when organizations undertook major projects to improve asset performance and increase corporate value. Assessments often uncover unexpected paths to better performance.
The objective of an assessment is to identify and articulate the organization’s operational vision (different than broad IT or engineering objectives) and follow a structured approach to uncover and identify how DE initiatives can support and solidify the organization’s strategic objectives. During an assessment, information is gathered to identify and understand business drivers and goals while analyzing business priorities and developing value propositions. Through the evaluation and analysis of this information, a working solution roadmap is produced.
Because E&P organizations are largely unfamiliar with the practical aspects of DE, the assessment step is often undervalued and, in some cases, skipped altogether. This means suboptimal results, increased project risk, and diminished returns.
Economic Implications Of The Current Geopolitical Forces Vis-à-vis Hydrocarbons On Global Energy Markets
Authors: Michael Andreas 
Published: June 2014

Abstract
Energy, coming in its great majority from oil and gas has become a strategic factor in global geopolitics. It is key to national power and a major requirement for economic growth. Energy consumption has become the most palpable national characteristic that separates rich from poor countries. The United States, the richest nation in the "room" is also the most intense user of energy per capita.
There is a substantial imbalance in the location of energy producers and consumers, an imbalance that has precipitated world conflicts and one that will likely cause future upheavals. There is huge activity by China buying energy resources all around the world. Russia's recent ascendancy in the energy world has been an important counterbalance to the power of OPEC. However, recent events surrounding Russia's energy industry have exposed fissures within the economic and political makeup of the country.
The United States Shale Revolution has, and will, bring market distortions throughout the entire nation and to many others such as the energy-starving, Southeast Asia markets of China and Japan. The recent removal of restrictions on LNG exports by the American government means that new forces will be implemented on both demand and supply of those markets. I believe that the globalization of gas trade will make prices of natural gas to converge and thus we will witness a more "unified" price regime in the not-too-distant future. Predictions of the future supply of petroleum have typically been far less accurate than predictions of demand. Flawed predictions have caused public bewilderment, distrust and, more importantly, government inaction or poorly conceived reactions. The cause of every energy crisis, like oil climbing to $150 per barrel in 2008 before dropping to $40, is above the ground geopolitics and never behind the valve issues.
This paper applies basic economic principles to assess the effects of present-day geopolitical forces on energy markets, particularly those of natural gas, around the globe arriving on a number of interesting conclusions. Topics touched include Chinese urbanization, United States LNG exports, Keystone XL Pipeline, Russian nationalization over its energy industry and its relationship with former Soviet Union countries.
An Integrated Life-Time Artificial Lift Selection Approach for Tight/Shale Oil Production
Authors: Khan N. , Ganzer L. , Elichev V. , Ali N. 
Published: June 2014

The application of horizontal drilling coupled with hydraulic fracturing technology has enabled tight oil economic production from tight oil reservoirs (well known as "shale play"). In North America, tight oil production has emerged as a reliable crude oil source. The contribution from tight oil resources is expected to grow further and could share a significant amount of future energy demand. However, the challenge is to produce difficult reservoirs economically, and key enablers are identification of "sweet spots" and well placement optimization, improving drilling efficiency, optimizing stimulation treatment and decline rates/OPEX reduction.
The main challenge for long economical production is high decline rate –normally production rates could drop to 70 percent of initial rates after the first year. There are basically three reasons of such reservoir behavior: transient inflow effect, no pressure maintained and fractures deterioration. Handling of high variety of production rates with high efficiency is a significant challenge to artificial lift technique.
This paper presents an integrated life-time artificial lift selection approach to optimize bottom-hole pressure and production lifting efficiency and therefore minimize production OPEX. The methodology incorporates integrated fit-for-purpose modelling approach, with taking into account the most important factors like transient reservoir behavior, lifting efficiency, equipment reliability and economics. The procedure is based on production optimization by determination of artificial lift method change necessity over well life and optimal switching point finding. The main criterion for the technique selection is a generation of maximization of value (like NPV) with minimal risks over well-life within given production constrains.