bluuebunny/crossref_metadata_2025_split huggingface dataset:
Novel Surfactants that Attain Ultra-Low Interfacial Tension between Oil and High Salinity Formation Water without adding Alkali, Salts, Co-Surfactants, Alcohols and Solvents
Authors: Wang D. , Liu C. , Wu W. , Wang G. 
Published: July 2010

Abstract
ASP (alkali, surfactant, polymer) flooding has obtained good results in the field. However, it has serious “scale” and “emulsion” and “chromatographic separation” problems, and because of the reaction of alkali with the formation, it cannot be used at high temperature conditions. A relatively pure surfactant that attains ultra-low Interfacial Tension (IFT) between crude oil and formation water without adding alkali into the system needs to be developed.
A mechanism (or condition) for surfactants to form ultra-low IFT at low concentrations is put forward. According to this mechanism, the chemical structure of 5 series of surfactants is designed, more than 30 specific surfactants were synthesized, all the above surfactants types and most of the specific surfactants attained ultra-low IFT (less than 9X10−3mN/m) with the crude oil and formation water systems. In the above surfactants, a series of “Betaine Amphoteric Surfactants” (a relatively pure surfactant with only one or two effective molecular structures) are the most promising. The surfactant was comprehensively evaluated. Besides the make-up water, it does not require additional “alkali”, “salts”, “co-surfactants”, “alcohols” or “solvents” into the system; the IFT between the driving fluid and crude oil of many reservoirs can reach an ultra-low IFT value at concentrations of only 10 ∼ 3000ppm; it is tolerant to salinities up to 229,000ppm, divalent ions 21,000ppm, temperatures 98°C. Test on cores shows that the recoveries of flooding by SP (surfactant, polymer) systems using this surfactant are higher than that by ASP systems using alkyl-benzene-sulphonates as the surfactant and NaOH as the alkali, its total recovery can reach above 70% OOIP. Micro-visual oil displacement experiments show that this surfactant can also change the pore surface wettability and further increase the recovery.
The above results show that this is a very promising surfactant for chemical flooding, it can be used in very challenging reservoir conditions (very few reservoirs have conditions harsher than those listed above); the mechanism to achieve ultra-low IFT, which is put forward, is useful to the development of new surfactants for EOR and to chemical EOR itself; Surfactants that do not require alkali, co-surfactants, alcohols, salts and solvents in the system to attain ultra-low IFT should promote better understanding of the function of surfactants in chemical flooding.
The Influence of Visco-Elasticity on Micro Forces and Displacement Efficiency in Pores, Cores and in the Field
Authors: Wang D. , Xia H. , Yang S. , Wang G. 
Published: July 2010

Abstract
Normally, when analyzing Driving Forces to determine the Displacement Efficiency (ED) during flooding, only Viscous Forces (vμ), which are proportional to the Macro Pressure Gradient (dp/dl), are considered. Micro Forces in pores are not considered. The micro forces considered in this paper are: First, the Normal Force caused by the change in shape of the flow lines in pores; second, the kinetic force caused by the change in momentum, which is due to the change in flow lines in pores also. Both these two micro forces are caused by the change in flow lines, the larger the change in flow lines, the larger the two micro forces.
Analysis, calculations and experiments show that the Flow Lines in pores are different between Visco-Elastic Fluids and Newtonian Fluids. Flow lines in pores of visco-elastic fluids, compared to Newtonian fluids, look more like and “expanding” and “contracting” Piston Flow. The change in flow lines changes the micro Forces, these Micro forces act on locations that caused the flow lines to change, mainly the Protruding Portions of residual “oil blobs”. This enhanced Micro force causes the protruding portions of the “oil blobs’ to change shape and mobilize. The results of the calculated magnitude of the enhanced micro forces are shown in this paper. For visco-elastic fluids, micro forces in pores are much larger that that for Newtonian fluids and must be considered when analyzing the “Displacement Efficiency”.
Results on “Visualization Core Models” confirm the above calculations and analysis. The affect of ED by core flooding using visco-elastic fluids is shown. Due to this mechanism, “Very High Concentration Polymer Flooding” is being implemented in the field, the incremental recovery is nearly twice that of conventional polymer flooding.
Tests show that only the “First Normal Force Differential” (N1) and its corresponding “Weisenberg Number” (We) affect the shape of the flow lines, other elastic properties and the viscosity of the driving fluid do not affect flow lines, therefore they do not affect the ED either.
The above analysis of the affect of visco-elasticity on flow lines, micro forces and ED is new in the study of flow of fluids in porous media and in Reservoir engineering; It is of significant value to further understand the mechanism of increasing ED in porous media; Useful in designing, screening, developing and evaluating better chemical products, chemical floods and methods to further increase oil recovery; “High Concentration Polymer Flooding” that utilizes the high visco-elasticity of the driving fluid to increase ED is field trailed in a large scale (4 large field tests) and shows a very much higher incremental recovery over water flood and conventional polymer flood, this is a “New Flooding Method” that has high potentials.
The above also shows that this is a new mechanism for displacement by flooding in porous media with multiple phases in its pores.
Methodology for Oil Production-Loss Control in a Digital Oilfield Implementation
Authors: García Alejandro , Machado Leonardo , Singh Gagan , Martins Diego , de Sousa Paulo Sérgio , Herdeiro Marco 
Published: July 2010

Abstract
Measuring daily production losses requires that operators be aware of different events that may affect well performance. Operators normally have the responsibility of closing the gap between the platform-measured production and theoretical-production potential. Common actions to close this gap include transforming events into production downtime, distributing plant process inefficiencies among all wells, and identifying and allocating losses to underperforming wells. This process presents challenges related to accurately identifying the wells manifesting production loss events and in calculating and distributing the production losses among identified wells. These challenges normally cause misinterpretation and misallocation of production losses, consequently impacting the final analysis of operations. This paper presents the methodology and technology deployed in a production-loss control module of an intelligent-asset implementation.
The production-loss control module is implemented as a workflow that allows for the identification of events, loss calculation, and classification of results for analysis. Using graphical analysis of well-by-well plots of production and potential data, the operators are able to identify individual well or platform process anomalies, allowing them to clearly identify events that produce a gap between production and well potential. An algorithm to minimize effects of errors in production measurement and well potential variations is implemented. The workflow is concluded by classifying production-loss events based on the identification of the root cause and remedial actions.
The technology implements a process for the proper quantification and qualification of production losses and provides a reliable platform for analysis of historical results. This process supports remedial actions to be taken to minimize the recurrence of production losses, positively impacting the operational efficiency of the asset. This solution represents a good example to the industry in the integration of people, processes, and technology for an intelligent-asset implementation.
First Installation of 5 ESPs Offshore Romania - A Case Study and Lessons Learned
Authors: Camilleri L. A. , Banciu T , Ditoiu G , Petrom S. A. 
Published: July 2010

Abstract
Petrom operates offshore oil and gas fields on the continental shelf in the Black Sea in Romania. These mature fields were discovered in the late 1970s and early 1980s in sandstone reservoirs with average well depths of 5500ft to 7200 ft (1700m to 2200m). Until recently, production has been with both free flow and gas lift. Over the past three years, ESPs have been installed in five wells resulting in production increases. The paper reviews the ESP completion designs and focuses on the impact of real-time data on the run lives and uptimes achieved over the past 3 years. To analyze the well performance, a new technique based on the ESP torque equilibrium equation between the pump and motor was utilized to reconstruct a continuous rate versus time profile using real-time data. This provided greater resolution in rate measurement than that provided by traditional surface well testing, which proved instrumental in understanding the ESP behavior in these wells which exhibited low flowrates (typically less than 100 Sm3/d, i.e., 600 bbl/d) and high GORs. The authors explain how the technique is valid in both transient and steady state conditions and therefore calculates the instantaneous flowrate at any time when real-time data are available. This continuous "rate log" as opposed to episodic rate data from well testing enabled superposition technique to be used to monitor drainage area average reservoir pressure, to confirm the relationship between motor temperature and well rate, and to observe the effect of high GVF (Gas Void Fraction) through the ESP. In the future this methodology can be used for back allocation and a reduction in surface well testing. In addition to the interpretation of rate data, there are important lessons learnt on how to achieve high ESP uptimes in excess of 98% using real-time data alarms.
Recent Progress and Evaluation of ASP Flooding for EOR in Daqing Oil Field
Authors: Shutang Gao , Qiang Gao 
Published: July 2010

Abstract
Many ASP flooding method have been tested in Daqing oil field. After the success of polymer flooding in Daqing oil field, four alkaline- surfactant-polymer flooding pilot tests have been conducted in order to: increase oil recovery further and provide technical and practical experience for expanding the ASP pilot. From four ASP pilot test, the following conclusions can be made: ASP flooding pilot can form oil banks, greatly lower water cut, increase the oil production as well as the oil recovery. The incremental oil recovery was about 20% over water flooding.
To further confirm the effect of large well spacing on EOR, three ASP field test with a large well spacing (200 to 250 m) have been tested in Daqing oil field. The commercial pilot tests result shows that the ASP flooding can increase recovery 20% more than water flooding.
The paper collected 12 pilot test date of industrial surfactant flooding in China, It Has been evaluated that each pilot test successful or not cleanly. Also discussed problem. Emphasize indicated that design project of combination flood, surfactant kind, structure, slag design and size and a scale of production were developed key. Decreased cost were also important task. Alkaline-Surfactant-Polymer (ASP) flood processes have been increasingly applied in the oil fields due to their high ultimate oil recovery. However, a major technical challenge is how to significantly reduce the amount and the cost of chemicals used such that ASP floods can become cost-effective as well. Field applications show that the concentrations of alkali, surfactant and polymer remain relatively high in the produced fluids of ASP floods. Thus, successful reuse of these chemicals can substantially reduce the capital cost and the environmental impact. Also re-injection of the produced chemicals is conducted for further enhancing oil recovery.
This paper have discuss problems of ASP flooding:
Emulsions occurred in some producers of the larger well spacing field test, the test shows that by using a specific kind of de-emulsifier commonly used in the field, the emulsions in the produced fluid are not to be broken because adding hard alkali.
This paper provides practice basis for the enlarging of ASP flooding..At present, most of ASP flooding are successful, But alkaline/com-oil carboxylates/polymer and foam/alkaline/surfactant/polymer flooding are not successful to be used to Daqing oilfield. The cost of chemicals (alkaline/surfactant/polymer) per barrel incremental oil is $11 to $15.The total cost of per barrel incremental oil is $15 to $30. The incremental recovery is 20% OOIP over water flooding.
Real Time Integration of ECD, Temperature, Well Stability and Geo/Pore Pressure Simulations during Drilling a Challenging HPHT Well
Authors: Rommetveit Rolv , Ødegård Inge , Nordstrand Christine , Bjørkevoll Knut S. , Cerasi Pierre , Helset Hans Martin , Borge Hans , Li Liming , Fjeldheim Mikkel , Håvardstein Stein T. 
Published: July 2010

Abstract
A very challenging HPHT well has been drilled utilizing an advanced ECD & Temperature, Well Stability and Geo Pressure Management System including real time simulations, early diagnosis of upcoming problems and real time simulations using state-of-the art models. The System uses all available real time drilling data (surface and downhole) in combination with real time modelling to monitor and optimize the drilling process. This information is used to visualize the wellbore as well as simulation results in 3D in real time. It has been implemented in Total E&P Norge TASC (Total Activities Support and Collaboration) Center in Norway. Among the System elements are:
An advanced and fast Integrated Drilling Simulator which is capable to model the different drilling sub-processes dynamically, and also the interaction between these sub-processes in real time. The Integrated Drilling Simulator is used for automatic forward-looking during drilling, and can be used for what-if evaluations as well. The transient flow & thermal wellbore model is coupled to the well stability model in real time, so that the updated well pressures and temperatures and drilling mud properties are used by the well stability model for RT predictions. A multi-purpose geo-pressure modelling tool which includes all significant processes relevant to pressure generation and dissipation is coupled to the integrated drilling simulator and can give updated pore pressure predictions during drilling. Methodology for diagnosis of the drilling state and conditions. This is obtained from comparing model predictions with measured data. Advisory technology for more optimal drilling. A Virtual Wellbore, with advanced visualization of the downhole process. A new generation visualization system designed to integrate all participants involved, will enable enhanced collaboration of all drilling and well activities in a global environment. Data flow and computer infrastructure
Among the challenges during planning and drilling of this well have been
Very small window between pore and fracture pressure. RT ECD simulations was performed with an advanced hydraulic and thermal wellbore model Increased probability for instabilities in the tight window. Was mitigated by RT stability modeling during drilling Uncertainties in pore pressure predictions. Was mitigated by updating predictions during drilling.
Experiences from the drilling as well as use of the decision support System will be summarized and presented.
Development and Adoption of Remote Assisted Operations Capabilities in the Gulf of Mexico
Authors: Chevis Marc , Weiss Christopher 
Published: July 2010

Abstract
The journey from concept to adoption of remote operations capabilities in the Gulf of Mexico (GoM) has undergone significant evolution over the years. The effort to date has resulted in the full adoption of three Remote Control Rooms (RCRs) in New Orleans for remote assistance to their associated assets: the Brutus Tension Leg Platform (TLP), Ursa TLP and Perdido SPAR. A fourth RCR is slated to be operational in mid-2010 supporting the Auger TLP. A brief look back shows that factors such as broad stakeholder engagement and support, along with a dedicated project staff working to integrate technology, operations processes and people considerations contributed immensely to the project’s success. Furthermore, development of an operating model encompassing principles, policies, performance management, IT support and activity roles/responsibilities has been essential in adoption of the RCRs. At present, plans are under way to extend current RCR capabilities including bringing additional control and monitoring capabilities into the RCR, deferment reduction during hurricane events, and moving additional activities from the asset to a shore-based environment.
Figure 1 Perdido Remote Control Room in New Orleans
Remote Real Time Well Testing—Experience in the Grove Gas Field in the North Sea
Authors: Sikandar S. , Badr A. , Shumakov Y. , Theuveny B. , McMillon M. , Sarac S. , Fuentes A. 
Published: July 2010

Abstract
Accurate well test data acquired throughout an appropriately designed test program is critical to confidently characterize a reservoir. Achieving this requires the right DST string selection or completion and stimulation designs, surface test set up / facilities, and the ability to rapidly handle dynamic changes in flow regimes. Well testing is inherently complex due to the interaction between these various elements. "Successful failures" in well testing is unfortunately not uncommon and results from each element of a test performing as per standards, but losing focus on achieving the ultimate objectives. The remote participation in operations of expertise that designed the test is becoming increasingly important in achieving test objectives, in particular in geologically complex structures, low-deliverability formations, reservoirs with high flow rate wells, or environmentally challenging conditions.
Technological developments have enabled improved monitoring and controlling of advanced well testing equipment often now with multiple data acquisition systems. For increased accuracy in highly dynamic test environments, well tests are also performed using multiphase flow metering alongside separators specifically designed to increase handling and separation efficiencies with separate acquisition systems. Remotely located experts are now able to validate and evaluate data in real-time, 24/7, with flexibility to change acquisition and test programs to ensure that objectives are achieved.
Real-time access and remote connectivity were provided during gas condensate testing of three North Sea wells in the Grove field. This paper describes the value of real-time services where the test program required continuous data quality assurance and rapid real-time evaluation onshore. This paper also demonstrates how real-time collaboration of personnel at multiple sites was crucial in carrying out a successful pressure transient analysis and a complete interpretation, both of which helped achieve the test program objectives within the planned test duration.
Delivering Value by Continuous and Automated Production Monitoring and Optimization
Authors: Vilanova Jordi , Alvarez Cheo 
Published: July 2010

Abstract
The promise of an "Intelligent Energy" initiative is premised both on the availability of real-time data, and on improving real-time communications between the field and the office. However, acquiring, organizing, and making sense of real-time data for field production management poses a number of challenges for any individual surveillance engineer. For an asset team working collaboratively, the challenge of efficient and effective data monitoring and the performance of optimization workflows can be even more demanding. Many production workflows require an engineer to coordinate data flows between numerous, diverse, and frequently siloed systems and applications. Studies have shown that approximately 50-70% of an engineer’s time is spent finding, gathering, and managing data for use in these different applications1. This non-productive time can be drastically reduced by defining standard production workflows, by implementing an automated system to execute these prescribed workflows, and by ensuring that the data sources are well defined and accessible.
A well-designed, thoughtfully implemented, and automated workflow ensures that all the relevant data is available "at the fingertips" of each member of the asset team, reduces the likehood of input errors, and removes the burden of data management from engineering personnel. These automated workflows allow knowledge workers to focus on value-added engineering tasks. In addition, the design and implementation of automated and configurable workflows creates a transparency and consistency in work processes that can be customized to the unique needs of each asset.
This paper presents an asset-based collaborative project that includes:
Initial needs assessment Design of well data required for advanced surveillance Workflow design Implementation methodology Value realization review
The core enabling technology that allows these automated workflows is a vendor-neutral integration platform that dynamically links diverse data sources and software applications currently in use for production monitoring and optimization.
Case History – Steam Injection Monitoring with Optical–Fiber–Distributed Temperature Sensing
Authors: Batocchio Marcelo A. , Triques Adriana L. , Pereira Pinto Hardy L. , de Lima Luis A. , Souza Carlos F. , Izetti Ronaldo G. 
Published: July 2010

Abstract
This paper describes a project initiated by Petrobras to map the steam-front progress in a heavy-oil, steam-assisted field. A new Distributed Temperature Sensing system (DTS) that was provided by a major service/engineering company to monitor the distributed temperature along the well has been deployed in a pilot program in a 4-well field that has three producers and one continuous steam-injection well. The project goals were to obtain:
Proof of the performance capabilities of optical-fiber DTS in continuous injection wells for temperatures of approximately 300°C Mapping of the steam front in the reservoir to better understand the steam propagation so that injection efficiency can be increased Prediction and prevention of steam breakthrough.
The pilot forecasts selective injection in two zones using packers for isolation. Since there were no commercial packers available with feedthrough capabilities for deployment of hydraulic lines or optical fiber cables for steam injection, a new solution had to be devised to permit fiber installation at the injector.
Aspects considered for this project included the well selection for the pilot development, the performance capabilities of the system, and the solutions for fiber installation.