bluuebunny/crossref_metadata_2025_split huggingface dataset:
Asphaltene Deposition in Capillary Flow
Authors: Seifried Christine Maria , Al Lawati Sadiqa , Crawshaw John P , Boek Edo S 
Published: June 2014

Abstract
Asphaltene precipitation and deposition may cause severe problems during production, transportation and processing of crude oil, hence affecting efficiency and cost of production in both upstream and downstream operations. During crude oil production they can deposit in rock reservoir pores, thus leading to possible blocking and formation damage. Despite significant research asphaltene deposition under flowing conditions remains barely understood. Here, capillary flow experiments were conducted to study asphaltene deposition by examining the pressure drop across the capillary as a function of different factors. Asphaltenes were precipitated with n-heptane from a crude oil/toluene mixture. Increasing the precipitant fraction led to greater precipitation which results in a faster deposition rate. A higher total volumetric flow rate also led to a higher deposition rate and a higher mass of deposited asphaltenes with more asphaltenes deposited at the entrance of the capillary. This was confirmed by images taken with a confocal laser-scanning microscope. Diffusive boundary layer theory was considered to explain the results which predict that the effective diffusive boundary layer thickness grows with the mean velocity ūs1/3, whereas our results showed a dependence on ū.
Hydraulic Fracture Design Flaws-Proppant Selection
Authors: Yang Mei , Economides Michael J. , Wei Chenji , Gao Chao 
Published: June 2014

Abstract
This work presents the statistical use of important elements of fracture technology in a number of major locations, primarily in Texas. The geographic analysis appears to be consistent and valuable: similar reservoirs in a basin call for similar treatments. The research will particularly focus on proppant selection, as one of the most important elements in both the physical success of a hydraulic fracture and its economic optimization. The paper also incorporates logistical costs such as proppant shipping to well site.
Completion data are summarized, specifically on fracturing treatments in the Eagle Ford, Marcellus and Barnett Shales and the Permian Basin. Production data from hydraulically fractured wells in the Permian Basin, Texas are included in the study. One of the observations from the production data is that cumulative production from natural proppants is superior to the production from treatments using synthetic proppant in the same fields. This is an interesting finding because with the higher conductivity of synthetic proppants, a higher production rate is often expected. The paper discusses the hydraulic fracture design flaw that causes the discrepancy.
Another conclusion is that in the reservoirs currently under exploitation, natural sand proppants are appropriate and the net present values of the treatments are superior to those of any synthetic proppant. This conclusion is not only because of the shallower depths (and therefore less crashing) but also because of the low-reservoir permeability, allowing for lower proppant-pack permeability.
With the theory guidance of the Unified Fracture Design approach and massive completion and production data analysis, this study can help the industry considerably to implement hydraulic fracture designs more effectively.
Improving EH&S Practices during Turnarounds in Facilities and Plants: A Process of Knowledge Capture and Transfer Worth Implementing
Authors: Daher Elie , Dowd Darrell 
Published: June 2014

Abstract
A well-executed maintenance shutdown or turnaround in processing facilities or plants can represent a source of competitive advantage for an organization. It can drive commercial performance, boost morale and bring recognition to high performing teams keeping everyone safe.
Maintenance shutdowns or turnarounds represent an increasingly significant challenge and an increasingly significant opportunity. Understanding the various EH&S issues facing previous turnarounds and most importantly how they were addressed is essential for the success of subsequent activities.
This paper discusses how to ensure the capture and dissemination of the wealth of knowledge generated and how to make proper use in order to impact the efficiency and effectiveness of these projects while keeping everyone safe.
There are three places or situations that a project can and should gather learnings; the planning phase, execution phase and completion phase. To ensure the maximum benefit from knowledge capture and transfer, two best practices have been developed - Needs Assessment and the Stewardship Report.
The Needs Assessment is a process used to review the work with key management stakeholders. While systems and processes are designed to maximize the efficiency in the delivery of safety resources for planned tasks during the turnaround, the Needs Assessment proactively identifies areas that are likely to generate unplanned work. This enables the creation of readiness plans that let you effect change quickly, before unplanned work becomes an issue or a source for delay and extra cost.
The Stewardship Report is a document that is used at the conclusion of a project to examine and evaluate how the contractors and company personnel performed during the project. It is an unbiased, objective recap of everything that worked and what didn't work as well. This long term comprehensive strategy for information flow and technology innovation driven by customer feedback ensures that lessons are learnt, mistakes avoided and successes repeated. Corrective actions and solutions are proposed, discussed and documented for implementation prior to the next project.
This paper studies these two tools, Needs Assessment and Stewardship Report in detail and provides practical examples and tips on how they can ensure knowledge capture and transfer in their organization.
Development and Field Testing of Advanced Ceramic Proppants
Authors: Mack Mark G. , Coker Chris E. 
Published: June 2014

Abstract
A unique family of advanced ceramic proppants has been developed based on formulated mixed-metal oxides. In contrast to conventional top-down ceramic proppant manufacturing, a bottom-up process is used to coat ceramic cores with highly-engineered layers of mixed-metal oxide. This process yields a very strong, light proppant with well-controlled porosity, and a narrow size distribution.
Laboratory results show that individual advanced ceramic proppant beads are much stronger than conventional ceramic proppant grains, and that the strength distribution is also much tighter than conventional ceramic proppants. The strength profile of the engineered beads bears a close relationship to the generation of conductivity-damaging crush fines. As a result, the conductivity measured in industry-standard tests is as much as 40% higher than that of conventional ceramic proppants, and this improvement is maintained over a wide range of closure stresses and multiple stress cycles. There is thus a critical link between individual proppant bead behavior and overall proppant pack performance.
Proppant transport in slickwater is a result of three major mechanisms: gravity settling (Stokes Law), sedimentation (dune formation), and saltation. The low density of advanced ceramic proppants reduces the settling rate, and the low coefficient of friction reduces the height of dunes, resulting in proppant transport further into the fracture.
An important new property related to proppant transport in slickwater has been identified, i.e., the coefficient of restitution. A high coefficient of restitution reduces clustered settling, and results in more active saltation. A new laboratory test to compare the coefficient of restitution of different proppants has been developed. In this test, advanced ceramic proppant beads typically move approximately 40% further than conventional ceramic particles, and twice as far as sand.
A comprehensive field test of Advanced Ceramic Proppants was performed in the Permian Basin. Ten pairs of wells were selected and the new material was pumped into one member of each pair, while conventional ceramic proppant was used in the other. Advanced Ceramic Proppant increased cumulative 12-month oil production by 20% compared to the offset wells. The statistical techniques which demonstrate this improvement also identified some key variables which impacted production, including stimulation treatment execution and interference effects.
The use of Advanced Ceramic Proppant increased the NPV of the wells by 25% relative to conventional ceramic proppant, and the incremental cost of the treatment was paid back in 3 to 4 months.
Feasibility and Challenge of Quantitative Cement Evaluation with LWD Sonic
Authors: Kinoshita Toshihiro , Izuhara Wataru , Valero Henri-Pierre , Blyth Matthew 
Published: June 2014

Abstract
Cementing is an essential part of well construction as it supports the casing and provides hydraulic sealing. Quantitative cement evaluation is becoming increasingly important in the industry to verify well integrity and zonal isolation. Such information has historically been obtained with a wireline tool, acquiring data at ultrasonic or sonic frequencies. The most common log providing information on cement bond quality is the cement bond log (CBL), which relies on the amplitude of the casing arrival to determine the quality of cement bonding to the casing and in some applications to the formation.
Although logging while drilling (LWD) sonic technology has progressed rapidly in recent years the established service from an LWD sonic tool that provides cement information is only top of cement (TOC), and it indicates only the presence or absence of cement behind the casing. Since the major structural part of the tool is a rigid steel collar, there is significant acoustic propagation along the collar. It is technically difficult to separate the casing signal from the one traveling in the collar as these two propagations have similar speed and frequency content. When the cement is poorly bonded to the casing, the casing amplitude can be far larger than the collar arrival. However, if the cement is well-bonded, most of the casing signal energy is dissipated into the cement, and the casing amplitude at a receiver a certain distance from the transmitter tends to be similar or even smaller than the collar arrival. In such cases, the measured signal loses sensitivity to cement bonding. However, it is challenging to establish a relationship between the respective amplitudes of the collar and casing as it depends upon many factors such as the acoustic impedance of the cement and the casing size.
We explore the feasibility of quantitative cement evaluation with a conventional LWD sonic tool. Finite-difference method (FDM) modeling over a wide range of conditions was conducted to quantify the relationship between casing amplitude and collar arrival. Results indicate that quantitative cement evaluation is feasible with existing LWD sonic tools, depending upon the bonding value. This study also provided information for comparisons between conventional wireline cement evaluation methods and LWD-derived CBL.
Smart Collaboration for Decision Making in Drilling
Authors: Fjellheim R.. 
Published: June 2014

Abstract
In spite of impressive advances in drilling technology, the cost of drilling is soaring and represents a significant and increasing part of oil recovery investments. Data is available in abundance, but drilling teams are struggling to make sense and good use of the data in daily operations and decision making. By embedding analytics and decision making tools in "smart collaboration" solutions, we can make better use of scarce human expertise, help improve operational performance, and ensure compliance to safety standards.
We describe an implementation of smart collaboration for drilling. The solution supports decision making in a decentralized and multi-disciplinary team of engineers drilling complex wells in a large and mature offshore field. The system aids the team in carrying out challenging coordination and decision tasks in drilling, and is based on social media technology, mathematical decision models, and data visualization. Probabilistic decision models have been developed for a range of typical drilling problems, e.g. change bit, set casing, gas influx, etc.
Social media similar to the blogging and chatting tools we use in our private lives help team members to quickly obtain expert support, achieve a common situation understanding, and rapidly converge on a sound decision in complex drilling situations. Our solution combines high-level visualization of drilling status, risk and progress with problem-specific decision tools, all based on a common social collaboration platform integrated with the existing industry standard IT infrastructure of the operator company.
Automated Workflows to Monitor, Diagnose, Optimize, and Perform Multi-Scenario Forecasts of Waterflooding in Low-Permeability Carbonate Reservoirs (a KwIDF Project)
Authors: Ranjan P.. , Carvajal G. A. , Khan H.. , Vellanki R.. , Saputelli L.. , Md Adan F.. , Villamizar M.. , Knabe S.. , Rodriguez J.. , Al-Jasmi A.. , Nasr H.. , Al-Saad B.. , Pattak A.. 
Published: June 2014

AbstractSurveillance and optimization of waterfloods in low-permeability carbonate reservoirs pose many challenges. Updating reservoir models is tedious and time-consuming, involving multiple data sources, model updates, and simulations. Technological challenges include large simulation models, waterflood complexities, and limited real-time data. Human challenges must be addressed as well, since waterflooding decisions affect multiple disciplines: reservoir engineers, production engineers, facilities engineers, IT, Operations, and asset managers. The ‘languages’ and interests of these disciplines are quite different; necessitating a workflow that satisfies the needs of all disciplines and integrates people, processes, and technology.This paper presents an innovative automated workflow to enable monitoring, diagnostics, forecasting, and optimization of waterflooding processes in days instead of weeks. This workflow seamlessly captures historical and monthly real-time data, updates simulation history, creates simulation restart prediction points, runs numerical simulations with optimization scenarios, selects the global optimum solution by scenario, and compares results so that multi-disciplinary teams can make reactive or proactive decisions to maximize short-term oil rates and long-term oil recovery, while honoring constraints on voidage replacement ratios, reservoir pressure, sweep efficiencies, production, and injection.The workflow automatically updates real-time production data in the simulator each month. A base case is run to recalculate waterflooding indicators. The process then starts a 24-month production forecast, running hundreds of scenarios under constrained optimization to achieve global optimization points. The optimizer changes control variables such as injection volumes, tubing head pressure, bottomhole pressure, and production allowable. The workflow ranks potential well decisions with important impacts on oil rate and water cut.The workflow uses an intuitive user interface incorporating the needs of multiple engineering and operations disciplines, and facilitates one common language while evaluating and optimizing waterfloods. This workflow has been implemented for a waterflood in a Middle East carbonate reservoir to help engineers evaluate the waterflood and make better, faster decisions.
Inflow Control Devices Improve Production in Heavy Oil Wells
Authors: Least Brandon , Greci Stephen , Konopczynski Mike , Thornton Kim 
Published: June 2014

Abstract
In order to maximize oil production, it is desirable to have a balanced influx of oil from the entire completion. Non-uniform production rates from each zone along the completion may not be evident early in the well’s production life, but they can become problematic when water and gas break through. If water and gas break through in select zones, they will produce at higher rates than the oil, which in turn will impede oil production rates from the remaining zones.
Formation permeability variations or toe-to-heel friction loss can cause flow rate differences between zones, and in a heavy-oil well, these variations may be even greater. Viscous fluids experience larger frictional losses both in the formation and the wellbore flow conduit; thus, when low viscosity water or gas breaks through, the flow from a high water or gas cut zone can quickly dominate the flow from the well. Inflow Control Devices (ICDs) have been developed to balance the influx of oil by creating additional back-pressure in the zones that produce at higher rates. Using ICDs can delay water or gas breakthrough, but once unwanted fluids break through, conventional passive ICDs are not able to maintain the balanced flow.
This paper discusses a new ICD, an autonomous inflow control device (AICD), which performs similar to a passive ICD during oil production and can be used to balance reservoir influx. Unlike passive ICDs, when unwanted fluids (water, gas) flow through the AICD, they take a different path than oil, and a much higher pressure drop is created. This behavior can be used to restrict the flow of unwanted fluids when they break through in a zone, allowing the oil production from other zones in a well to continue at the maximum rate.
Simulations are presented that will compare a stand-alone screen completion to a completion with passive ICDs, to a completion with an autonomous ICD. The simulation results will show a clear distinction in each type of completion, and it will highlight the benefits that are provided with the ICD and the even greater benefits derived from use of the AICD, both onshore and offshore.
Real Time Data: Interactive Monitoring of Data Flow for Continuous and Reliable Data Transmission
Authors: Al-Amer Abdulrahman A. , Al-Gosayir Muhammad , Al-Naser Naser , Al-Towaileb Hussain 
Published: June 2014

Abstract
The dependency on well-head and field real time data has significantly increased in the past few years in the oil and gas industry. The data is used to maximize oil and gas recovery, increase revenue and improve health and safety. This new mode of operation mandates the availability of reliable real time information sent by the different well and field digital equipment for optimum right-time decision making. The challenge is in the fact that intelligent field components include many different layers and nodes that increase the complexity of such assurance. Therefore, the health and the data transmitted from these components, such as digital gauges (e.g., multi-phase flow meters and permanent downhole monitoring systems) and the communication network must be continuously monitored and well maintained.
This paper will highlight a newly developed comprehensive and interactive monitoring and key performance indices reporting solution to quantify, assess and visualize the health of the different intelligent field components. The new system is using advance technologies, such as GIS maps to locate fields, equipment, real-time data historian servers, and networks to highlight their availability and reliability status. This solution provides real time alerting and alarming in case of transmission failure, well data integrity situation or inaccurate data detected using an automated diagnostic engine, thereby maximizing safety and increasing accuracy and data reliability.
Profit and Loss at the Wellhead; Producing from the Wells that are Profitable and Shutting-in the Loss-makers
Authors: Forrester Dean , Trescott Jenna M. , Nell Johan , Landgren Ken 
Published: June 2014

Abstract
In traditional Digital Oilfield programs, it is assumed that increasing production from any given well has a positive impact on the operator’s bottom-line. In fact, optimum profitability for a field is dependent not just on production volume, but also on the individual contribution of each well to the overall profitability of the organization.
Understanding the contribution of each well, and operating based on this knowledge, can provide significant benefits over and above traditional production optimization techniques. Specifically, it can allow the field operations team to prioritize highest profitability wells – rather than just highest flow wells – and can even allow the identification of seemingly ‘productive’ wells which actually have an overall negative contribution to the organizations bottom line.
To calculate well –by-well profitability, operators must not only be able to accurately measure/allocate production volume, but must also consider other factors such as water handling cost, ongoing maintenance cost, production sharing agreement impact, short and long-term pricing contracts, etc. These and many other factors all contribute to the financial benefits accrued from a given well.
Understanding the contribution of any well or group of to the profitability of an operator is therefore more complex than simply calculating the production flow for the day and multiplying by the prevailing price for WTI or Brent.
The data necessary to calculate well-by-well contribution is spread across many siloed systems, including production, maintenance and financial applications. At best, operators review production volumes monthly to produce revenue figures when some sort of contribution figure may be possible to calculate. However it rare for any operator to manage cost information at the resolution necessary to calculate P&L accurately, so there has not been the ability to manage daily operations based on well-by-well profitability. Instead, operators have typically calculated a broad ‘field lifting cost’ and applied this across wells.
Clearly, with the high-well counts and heterogeneous production fields that are increasingly common, the potential value to manage wells on a full fiscal calculation rather than just cost can offer significant benefits.
This paper discusses the main contributing factors to well profitability, the potential business value from operating on well- P&L versus traditional volume-based approaches and describes solutions to achieve this capability.