bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fractal Description of Pore Structures of Low Permeability Oil Reservoirs and its Relationship with Gemini Surfactant Flooding
Authors: Wei Heng , Liu Junhan , Wei Guoqi , Liu Xiangui , Liu Weidong 
Published: February 2011

Abstract
Gemini surfactant flooding is a promising technique to enhance oil recovery from medium-high permeability oil reservoirs. The screening of the gemini surfactants are mainly based on their capability of lowering the surface tension between oil and water. However, gemini surfactants with high capability of lowering the surface tension do not necessarily enhance oil recovery from low permeability oil reservoirs. Based on fractal method and the mercury injection curve data, the fractal dimensions of the pore structures of low permeability oil reservoirs are different from those of medium-high permeability oil reservoirs. Based on the fractal dimensions of molecular fragments, the fractal dimensions of gemini surfactants are in relation to the fractal dimensions of the pore structures of low permeability oil reservoirs.
Based on the fractal dimensions of the pore structures of low permeability oil reservoir Z and molecular fragments, gemini surfactant D is designed and applied in developing the reservoir. Gemini surfactant D enhanced oil recovery 5% more than conventional gemini surfactants.
The fractal dimensions of the pore structures of medium-high permeability oil reservoirs range from 2 to 3. The fractal dimensions of the pore structures of low permeability oil reservoir Z are less than 2. The fractal dimension of the spacer group should match with fractal dimensions of the pore structures. The gemini surfactants are absorbed more onto the rock surface as the spacer groups of the gemini surfactants are less complicated than the rock surface.
Fractal dimension is supplementary to the parameters (permeability and porosity) that are used to estimate low permeability oil reservoirs. Low permeability oil reservoirs which were not able to be developed are able to be developed. This helps more and more low quality reserves be turned into producing reserves.
Best Practices & Innovations for Improved ESP Performance; Mature Field Case History; TNK-BP Company, Russian Federation
Authors: Borling Daniel C. , Sviderskiy Sergey V. , Gorlanov Sergey F. 
Published: February 2011

Abstract
Leadership, teamwork and technical ingenuity were critical strategy elements that resulted in an 82% run life improvement for Electric Submersible Pump (ESP) systems in the TNK-BP Company. During the past four years, the 12-month rolling Mean Time Between Failure (MTBF) steadily improved from 295 days during January 2006 to the current 541 days in July 2010. This 246 day improvement was achieved across more than 14,250 ESP’s and achieved $307 million value to date.
This case history paper contains insights, best practices and technical innovations used by TNK-BP to safely improve relatively low ESP run life. As of July 2010, TNK-BP had 15,700 active producing wells and approximately 98% used some form of artificial lift. Average production was 200,000 tonnes of oil per day (1.5 million barrels per day) from more than 200 mature fields across Western Siberia and Orenburg region.
The most significant insight during the past four years was the amount of effort it took to change the way the Company viewed ESP run life.
TNK-BP improved ESP equipment reliability with specific technical protocols and innovations. Benefits from longer run time resulted in less deferred oil, reduced equipment repairs, fewer new replacement equipment purchases and better deployment of rigs to perform other production enhancing wellwork. An important technical learning early in the program was reduced early-time failures. A TNK-BP best practice was its ESP MTBF Sector Team for unified communication of strategy, work plans and learnings across 14 regional businesses.
Understanding true root causes for ESP failures had a profound effect for improved run time. TNK-BP participated in the Joint Industry Project called ESP- RIFTS (Reliability Information and Failure Tracking System) and developed its own “state-of-the-art” failure analysis methodology to better classify failures across the Company.
Reservoir Management of Inflow Control Devices in an Undersaturated Reservoir: A Case Study in the De Ruyter Field, Netherlands
Authors: Leung E. , Samosir H. , Fong K. , McKellar D. , Westerhof D. 
Published: February 2011

Abstract
Passive inflow control devices (ICD) are being rapidly adopted in horizontal production wells particularly when there is a high probability of produced water or gas in a heterogeneous reservoir in the early life of a well. The justification, application, installation and the flow physics of ICDs available to the industry are well documented in the literature [1–3]. However, there are limited case studies that discuss the production and reservoir performance, to investigate their longer term impact supported with actual production data. The De Ruyter Field, which started production in September 2006, has been completed with passive ICDs in combination with zonal isolation in two horizontal wells in the undersaturated western fault block. This paper will describe how ICDs increased recovery compared to stand alone screens, by controlling water production and promoting inflow from lower productivity zones thus extending the life of the De Ruyter Field . This paper will also discuss the use of actual production and PLT data to history match a dynamic simulation model. The ICDs allowed the operator to commercialize an offshore development by delaying and controlling water production in a heterogeneous reservoir, thereby increasing recovery and extending the field production life.
Use of Gyro-MWD Technology Offshore, A Step Change in Drilling Performance in Saudi Aramco
Authors: Alidi Bashaar A. , Al-Sarrani Hasan F. , Stewart Jeff , Sarkar Abhijeet , Smith Geoff 
Published: February 2011

Abstract
Over the past few years, Saudi Aramco has had major efficiency improvements while drilling and completing smaller diameter hole sections. Such improvements provided significant reductions in rig time, and consequently reduced the overall operational cost. Less attention was paid to the upper hole sections due to less exposure to third party rental tools used in them. Offshore oil wells in Saudi Aramco have recently gone through major savings in the 28"/22" hole section after the successful utilization of the new Gyro measurement while drilling (MWD) technology coupled with powerful, performance drilling mud motors.
The normal process was to drill the 22" hole section, 1,050 ft +/−, running Gyro single-shot surveys every 50 ft - 100 ft drilled, until the well is drilled in a safe path away from other wells within its vicinity. After adopting the Gyro-MWD system, along with a modified 22" bit and 111/4" performance mud motor, the rate of penetration (ROP) increased by 82%; Thus, reducing CPF respectively.
The increase in the ROP resulted in average savings of 0.9 days per well (6 to 12 wells per platform) at this stage of the well. In addition, the reliability of the gyro tool face from vertical, even when inside the casing, provided confidence in drilling operations, which facilitated the increase of weight on bit (WOB), leading to faster drilling, thereby improving the overall ROP. Furthermore, eliminating the use of wireline to run surveys increased the safety of the operation.
The success of these 22" hole sections was substantial across the board, since it was one of the challenging areas where major improvements had not taken place before for years.
This paper will evaluate the new drilling practice in more detail. It will also cover the conventional drilling and operational practices, and the thorough planning stages that resulted in these fruitful savings.
An EoS Model for a Middle East Reservoir Fluid with an Extensive EOR PVT Data Material
Authors: Negahban Shahin , Pedersen Karen Schou , Baisoni Mahmoud Ali , Sah Pashupati , Malaysia Calsep , Azeem Jawad 
Published: February 2011

Abstract
The paper presents compositional data and PVT data for a Middle East reservoir fluid with a reservoir temperature of 394 K and reservoir pressure of 287 bar. The PVT data was selected and designed to provide the best possible starting point for developing an EOS model that would accurately reproduce the phase behavior of a reservoir fluid subject to injection of either CO2 or a hydrocarbon gas.
To eliminate the uncertainty from use of default molecular weights and densities for the C7+ hydrocarbon fractions the reservoir fluid composition was analyzed using a True Boiling Point (TBP) analysis. PVT experiments, both routine and gas injection (EOR) experiments, were carried out including solubility swelling, equilibrium and multi contact experiments and slim tube tests. With both injection gases the reservoir fluid shows a combined vaporizing/condensing drive mechanism.
A 9-component EOS model was developed for the volume corrected Peng-Robinson equation of state, which shows a good match of all available data. Two methods were used to predict the vaporizing/condensing MMP; (a) a multi-component tie-line MMP algorithm and (b) a compositional 1D simulator. The CO2 MMP is considerably lower than the reservoir pressure while the MMP seen with the hydrocarbon gas is close to the reservoir pressure.
Case History of a Successful Progressing Cavity Pump Application in an Extremely Low Pressure Environment
Authors: Lewis Blain , Daves Dusty , Skelton Gregg 
Published: February 2011

Abstract
This paper summarizes the production history, wellbore configuration, reservoir parameters and mechanical design parameters of a progressing cavity pump application in a high productivity, extremely underpressured, partial water drive reservoir. The current reservoir pressure of approximately 50 psi has presented a unique challenge to optimizing the productivity and operating costs of the well. It was operated for many years on conventional rod pump with a history of downhole equipment failures and restricted production capability. An effort to produce the well with an electric submersible pump system was unsuccessful because of the low reservoir pressure and the limited vertical space to install equipment. A progressing cavity pumping system has been in operation for fifteen months. After seven subsurface failures in six months, several changes to the system were made that optimized the production rate and minimized downhole failures. Among these changes were installing plastic coated sucker rods, an oversized carburized rotor, and a tubing anchor and stabilizing the wellhead from vibration. The oil production rate on progressing cavity pump has increased 35 BOPD, almost 300%.
How Smart Completion Can Maximize Oil Production and Recovery Factor in Stacked-Marginal Reservoir
Authors: Naroso Gangsar , Hofland John 
Published: February 2011

Abstract
This paper will address how reservoir depletion using Smart Well completions in stacked-marginal reservoirs will gain large benefits. Different scenarios will be used to illustrate this point.
Utilizing On-Off ICV’s combined with Permanent Down Hole Gauges, will achieve an optimized off take from each zone, thus creating efficient reservoir depletion as well as maintaining sustainable oil production. A cycling production approach from different zones will optimize well production; optimizing reservoir drainage and improve recovery factor.
Marginal reserves are hydrocarbon accumulations too small or too difficult to recover economically by themselves under prevailing fiscal terms. Stacked reservoirs containing marginal reserves are often passed over in favor of more prolific zones containing economic volumes. The opportunity to develop the marginal reserves in conjunction with other marginal reserves or with larger reserves by commingling (and by doing so make them economic) is sometimes overlooked by operators due to government regulations prohibiting commingling.
Shanayel field has stacked-marginal reservoirs that will benefit from the smart well approach. As part of Shanayel field development plan and reservoir characterization study, an observer well will be worked over and will be completed in 5 (five) zones. The smart completion configuration include 5 ea of 7 inch Feed through Hydraulic set - Retrievable packer, 3.5 inch Hydraulic ON-OFF ICV, 4 ea of 3.5 inch Single Gauge Carrier with P & T reading ported to annulus, 1 ea of 3.5 inch Dual Gauge Carrier with P& T reading ported to annulus - tubing, 3-1/2 inch - 9.2 ppf CRA tubing and 7 inch - 5 Penetrations Wellhead.
An automated Digital Infrastructure system is planned to operate the Smart Well completion, which enables to manipulate ICV’s remotely and monitor PDHG by providing connectivity to the existing field control system.
Deployment of the smart completion will provide proactive approach to manage oil production at every zone in the well, thus form efficient reservoir depletion as well as maintaining sustainable oil production. Pressure monitoring in every zone provides sufficient data to determine the depletion strategy, which in turn will maximize production and increase recovery factor. The well will also provide operational experience, as it will demonstrate if this is a viable completion technique for small and stacked hydrocarbon accumulations. Lastly, the initiative fits into ADCO’s 2020 vision.
High and Low Frequency Vibrations in Flare, Piping Systems: Causes, Consequences, and Avoidance Screening Methodology
Authors: Moustafa Ihab Fikry 
Published: February 2011

Abstract
Designing a new flare system or evaluating the integrity of an existing one has become a more complicated practice in the last few years. The original design of the flare system was probably based on a simple static analysis and code compliance, and didn’t consider the different types of vibration sources that will affect the integrity of the flare system in the short or the long term, these was not obvious to the designer, especially as most piping design codes don’t address vibration in a meaningful way.
Recently, incidents have occurred world wide where piping failure was related to unexpected piping vibration, this typically occurred due to increased fluid flow as a result of de-bottlenecking and the relaxation of erosion velocity limits. There also was a tendency by designers to use thin walled pipe for economic reasons and to allow increased flexibility in the piping system. This is very common on lower pressure designed relief and flare systems.
This paper will consolidate the guideline, techniques, definitions and equations related to High and Low Frequency Vibrations in Flare Piping System to get better understanding of the nature of these vibrations, I will also describe how to build a screening tool and provide examples from two Egyptian gas plants to see practically how the screening assessment was completed.
Improving Progressing Cavity Pump Performance Through Automation and Surveillance
Authors: Woolsey K. A. 
Published: February 2011

Abstract
To extend the run life of the pump while producing all available fluid is the goal of all PCP operators. The primary challenge is to do so without starving the pump and causing damage to the stator. The petroleum industry has been searching for years to find a reliable way to control progressing cavity pumps for pump-off. Several methods have been used, from monitoring torque to manual fluid levels. To date, none of these have been commercially successful. A method for controlling these wells has been developed combining wedge meter flow technology and microprocessor control of both electric motors using variable frequency drives and hydraulic motors using proportional control valves. This method has proven to be accurate and reliable, extending the run life while producing all available fluids.
Combining this automated technology at the well with a web based system that feeds back real time data to a dedicated SCADA host allows PCP technical experts to diagnose problems, and operators to respond quickly to changing well conditions.
This presentation discusses the advances in automation and optimization of progressing cavity pumps. The method will be explained and data will be presented of field study results showing actual well tests.
Integration of Montney Microseismic Information Into a Reservoir Simulator to Analyze a Horizontal Wellbore With Multiple Fracture Stages
Authors: Quirk D. J. , Cui A. 
Published: February 2011

Abstract
In order to get a clear picture of the effectiveness of a multi-stage stimulation treatment pumped into the horizontal wellbore of a tight gas reservoir, one must integrate data from a number of different sources. This will provide a more complete forecast of the reservoir's development.
The Montney formation straddles the British Columbia / Alberta border in the Western Canadian Sedimentary Basin. There is significant variability in the formation's properties across its area, but even so, we have seen a multitude of horizontal wellbores lined up within the formation in recent years. Many involved have questions about fracture spacing along a horizontal wellbore, and ultimately, the spacing of the horizontal wells in a field. The answers to these questions can lead to improved recovery factors and better economics for the resource play.
In this case study, seven stages of Basal Doig / Upper Montney microseismic data are integrated with fracture pumping information, and finally incorporated into a reservoir simulator. Two years of production history from the Montney horizontal is matched to "calibrate" the four layer reservoir model and make it a predictive tool. This provides the basis for understanding of drainage radiuses around the fractures, and for recommendations on fracture spacing in order to optimize completions in subsequent wells.
The calibrated reservoir model is then used as a predictive tool to understand drainage radius and productivity differences when the number of fracture stages in the wellbore is increased to reduce fracture spacing. Predictably, the cumulative production from the tight gas well with more stages is greater than the same well with fewer stages. Ultimately, there is an economic trade-off between completing the well with more stages and increased well productivity, and an optimal combination that differs from one region to the next.
An Innovative PCP Logging Technique for the Separated Layer Production Wells
Authors: He Liu , Fengshan Wang , Guochen Shi , Gang Cao , Tao Jiang , Tianli Zhang 
Published: February 2011

Abstract
In the past 50 years, the oil production of Daqing Oilfield has maintained 50 million tons (near 350 million bbls) per year for 27 years. To date, Daqing Oilfield is still the largest continental oilfield in China. Separated layer development technology is one of the key techniques contributed to this great achievement. In order to monitor dynamic performance of separated layer production, it was necessary to implement logging technique periodically in a large number of selected injectors and producers. Due to the limit of annulus size is too small for sensor to be run into down hole of progressing cavity pump (PCP) wells, traditional PCP system design couldn’t meet the requirement of well logging for separated layer production.
Since separate layer development technology is more and more popular in oilfield development, PCP logging technique has become a bottleneck issue which limited PCP application in larger scale. This paper presented an innovative design for logging technique in PCP wells. In this design, a unique drive head design was developed as well as several special downhole tools which applied the path for sensor and wire to be run into the appointed place.
Till the end of 2009, this technique has been applied in more than 200 PCP wells in Daqing Oilfield. The operation was simple and safety, the successful ratio was 95%. This technique could also be applied in other conditions which has a brilliant future.
Analysis and Flow Modeling of Single Well MicroPilot to Evaluate the Performance of Chemical EOR Agents
Authors: Cherukupalli Pradeep , Horstman Dirk , Arora Shyam , Ayan Cosan , Cig Koksal , Kristensen Morten , Ramamoorthy Raghu , Zaggas John , Edwards John 
Published: February 2011

Abstract
Many Enhanced Oil Recovery (EOR) applications involve injection of fluids into oil reservoirs to displace and recover as much of the remaining oil as possible. Typical maturation of (chemical) EOR involves phase and compatibility testing in the laboratory, displacement experiments in cores before single or multi-well pilot trials in the field, leading eventually to full field implementation. Recently, a new technique referred to as MicroPilot* has been introduced as an intermediate step to take laboratory results into the field, providing valuable data for pilot design and implementation.
The MicroPilot* is a log-inject-log method executed under in-situ conditions downhole in a matter of hours. A suite of wireline openhole logs are utilized to determine the initial saturations. The test then continues with a formation tester string which can drill into open hole, cleanup and inject an EOR agent into the formation. Following injection, the suite of open hole logs are run again to evaluate the effectiveness of the flood by measuring the change in oil saturation and the dimensions of the flood.
The world’s first successful test has been run in a medium heavy-oil field in the Sultanate of Oman with Alkaline Surfactant Polymer (ASP) solution as the EOR agent. Post-injection formation image logs clearly show the swept zone and an oil bank.
In this paper we take the analysis of the test a step further and present dynamic simulation modeling results using the acquired data as benchmark parameters for the history match. Grid verification using single-phase pressure transient analysis is discussed. Each phase of the test is modeled and history-matched to the acquired data. The electrical borehole image log response is matched together with the vertical saturation profile seen on the post injection NMR log. During the history match, formation parameters are fine tuned and some parameters describing the EOR displacement process in the simulator are studied in more detail. The history matching effort not only provided a consistency check for the field observed data but can also help determine a few key modeling parameters prior to possible field pilot planning.
The Role of Corrosion Prediction and Real-Time Corrosion Measurement Technologies in Corrosion Management – Theory and Applications
Authors: Kelleher Andrew 
Published: February 2011

Abstract
The methods and tools used to mitigate risks associated with corrosion damage have continuously evolved in response to an increasingly competitive marketplace and the realities of ageing plants. The development trend is clear: systematic approaches supported by both traditional and new technologies. Bayer Technology Services GmbH has recognized the need for a multi-disciplined team to assist companies to establish a robust Corrosion Management System (CMS) and to leverage new technologies in the management of corrosion risks.
Corrosion prediction and real-time corrosion measurement technologies are inherently suitable for application within the CMS. The high quality corrosion information provided by these technologies facilitates an increased level of understanding (and hence control) of the corrosion system. In contrast to traditional technologies, the corrosion prediction and real-time corrosion measurement technologies promote and support continual improvement in Corrosion Management.