bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mathematical modeling of fines fixation in the sandstone cores soaked by MgO nanofluid
Authors: Habibi Ali , Ahmadi Milad , Bastami Alireza , Pourafshari Peyman , Ayatollahi Shahab 
Published: May 2016

Abstract
Formation damage in oil reservoirs as a result of fines migration is a major reason for productivity decline. Fines loosely attached to the pore surface are in the equilibrium with the pore fluids. These particles start to flow when the equilibrium state is disturbed which, may end up in permeability reduction in porous media. Different solutions have been suggested to prevent detachment of fines from surface such as acidizing, ionic clay stabilizer, polymers and etc.
Nanofluids containing metal oxide nanoparticles show specific properties. They have various applications including catalysis, waste remediation, additives in refractory and paint products. Our previous published works showed that MgO nanoparticle could be used as the best adsorbent of the fines in s synthetic porous media. In this work, Unit Bed Element (UBE) model and material balance were proposed to describe the effect of nanoparticles presence on fines fixation. UBE model relates dimensionless parameters of surface forces to fines removal efficiency of porous media. Material balance modeling provides an estimation of effluent fines concentration based on the injected fluid flow rate. Also the main mechanism for this fixation has been studied by surface forces analysis.
Results show that soaking the core for 24 hours with 0.1% wt MgO nanofluid and water injection with 800 cc /hour could fix the fines which could used in particles release rate calculation in porous media. UBE and material balance modeling showed that the experimental results are trustable.

Introduction
Fines migration is a challenging problem in the production from oil reservoirs. Fines are feeble particles present in the porous media, which can detach and move easily due to fluid flow. Flow of suspension causes formation damage because of filtering at pore-level in the porous media (Muecke, 1979; Vaidya, et al, 1990; Civan, et al, 2007). Colloidal and hydrodynamic forces are found to be responsible for the fines detachment and their release from the pore surfaces. London Van der Waals attraction, double layer and Born repulsion and hydrodynamic forces are the dominant forces in the detachment of fines from porous media (Khilar, et al, 1998; Schramm, et al, 1996; Ahmadi et al, 2011). Hibbeler et al, (2003) provide an excellent review on the practical recipes to reduce fines migration.
The Practice and Evolution of Torque and Drag Reduction: Theory and Field Results
Authors: McCormick John Edward , Evans Chad D. , Le Joe , Chiu TzuFang 
Published: May 2016

Introduction
In the past two decades, drilling extended reach wells (ERWs) has become commonplace in the petroleum industry as companies seek to drill deeper and further to optimize the oil and gas production in the target field. ERWs are defined as wells that have two times more horizontal stepout than true vertical depth. Drilling longer horizontal sections allows more area of the reservoir to be exposed as well as less surface area disruption. As a result, with the global trend moving toward drilling ERWs, engineers can no longer ignore the high torque and drag forces expected in the well. There are numerous methods and tools engineers have developed to lower torque and drag forces and ultimately allow the drill string to drill to total depth (TD). However, only a few have proven to be a worthwhile investment.
An early high-visibility, large scale ERW drilled was the Wytch Farm project conducted by BP Exploration Operating Co. Ltd in 1993. The company originally considered creating an artificial offshore island; however, it was neither economical nor environmentally friendly. Instead, they drilled 10.1 km or 33,136 ft horizontally from an onshore platform to the target of interest. The well was known as the longest ERW drilled at the time. It is notable that back then, without knowing as much about torque and drag as we do today, they were able to control the torque and drag within the limitations of the drilling components. The mechanisms they used that allowed them to drill such a hole included a combination of hole cleaning improvements and mechanical friction reduction. This paper focuses on the different torque and drag reduction methods utilized in the past and how individual methods have proven to be worthwhile for engineers to use. The methods that are discussed in this paper include wellpath design, light weight string components, lubricants, hole cleaning, co-polymer beads, and mechanical friction reduction tools.

History Of Torque & Drag
In the past, engineers rarely encountered torque and drag problems simply because the wells drilled were not as challenging as the wells drilled today. As "easy to drill" conventional oil and gas wells have diminished, engineers are drilling wells and sidetracks that are more complicated and deeper than ever before. This results in higher torque and drag forces during downhole operations. Since the Wytch Farm well was successfully drilled in 1993, operating companies have challenged the limitations of the tubulars, the rigs, and the personnel in hopes of discovering reserves that were not accessible in the past. This use of onshore extended reach drilling (ERD) to avoid the creation of offshore islands has been repeated many times, including well known wells in Sakhalin Island.
Potential Unconventional Oil and Gas Resource Accumulations, Onshore Thailand
Authors: Schenk Christopher J. 
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
The U.S. Geological Survey has assessed undiscovered, technically recoverable shale gas, shale oil, tight gas, and coalbed gas resources in more than 140 unconventional hydrocarbon accumulations in the United States. The geologic and engineering attributes of these U.S. unconventional plays are used in the present study as geologic analogs to define potential resource plays in onshore Thailand basins. Tight gas and shale gas accumulations might exist in Triassic sandstones and mudstones of the Khorat Plateau Province, and shale oil and possibly shale gas might occur in the extensional structures in the Thai Cenozoic Basins Province. Coalbed gas does not appear to be a viable resource in northern Thailand at present.

Introduction
A goal of the Energy Program of the U.S. Geological Survey (USGS) is to assess the potential for undiscovered, technically recoverable oil and gas resources in both conventional and unconventional accumulations in the United States and in priority basins worldwide. As part of this process, the undiscovered conventional oil and gas resources in Thailand were assessed recently (Schenk and others, 2010). This report summarizes the geologic definition of potential unconventional oil and gas resources in two onshore geologic provinces in Thailand—Khorat Plateau Province and Thai Cenozoic Basins Province (fig. 1). Unconventional resources are identified for onshore rather than offshore areas given the marginal economics associated with many of these oil and gas accumulations.
Integrated Approach to Quantify L80 Tubing Corrosion for High-rate Sour Gas Wells
Authors: Sun Wei , Ling Shiun , Reddy Ramani V. , Pacheco Jorge , Asmann Marcus , Nor Nazri M. , Kersey Michael Scott , Morshidi Leozarin Bin , Nisbet Robert Smith 
Published: May 2016

Abstract
The ability to optimise the use of carbon steel in sour service presents many economic advantages, including minimizing the use of expensive corrosion resistant alloys, enabling optimised large bore completions, and eliminating additional offshore facilities. An integrated approach to corrosion modeling and testing has been developed to reliably extend the application of carbon steel. Key elements of this integrated approach include:rigorously establish tubular environmental conditions,accurately simulate environmental conditions (acid gas concentrations (CO2/H2S), water cut, and water composition) in the laboratory,mathematically extrapolate laboratory weight loss and pitting to predict tubing life, andvalidate tubing life predictions with field caliper data.
This paper describes the application of the integrated approach to evaluate L80 tubular corrosion and predict tubing life for a range of acid gas (CO2/H2S) concentrations. The paper also discusses the corrosion mechanisms and validation of predicted corrosion with field caliper data.
Using Research-vetted, Actionable Leading Indicators to DRIVE Safety Performance and Operational Excellence
Authors: Stough Joseph , Wichienrut Watana 
Published: May 2016

Abstract
This paper will review the leading indicator research findings drawn from analyzing a large Energy industry data set. The source of research includes QHSEmanagement system practices and data spanning over 100 countries involving some global industry leading companies such as ExxonMobil, ConocoPhillips, Shell, Chevron, OMV, and multiple others.
From the analytical research and careful review with industry QHSE executives and Subject Matter Experts, the factors that were found to best predict the Safety outcome performance of an organization included measurements of (a) proactive event reporting (Reporting Culture), (b) the discipline and consistency in execution of QHSE processes, (c) the timeliness in closure of important corrective / preventive actions, and finally (d) the responsiveness of supervisors and line managers.
In each of these key areas, solid performance can be attributed to the tone set by leadership and the influential day-to-day behavior of field supervision and line management. So, throughout this paper we will emphasize how engaging these leaders is imperative to improving the above factors and driving QHSE outcome performance.
This paper will also review some actionable leading metrics which can be calculated to measure the factors that have been found to be uniquely strong in organizations who continue to sustain top-level Safety lagging performance. We will review some creative solutions to reach out to front-line workers and leaders to engage them directly in the process of continuously improving these factors.
And finally, we will outline a sample process for implementing practical, "actionable" leading metrics in each key area to drive line manager / leadership behavior and ultimately improve QHSE performance outcomes.

Background: Researching world-wide Energy data set to find Safety leading indicators
The companies involved in the research project provided their data on a scale that spans thousands of operating facilities in over 100 countries. Engaged in this initiative are world-wide operations from multiple Energy companies which have world-class QHSE performance… as well as leading companies in Oil Field Services, Chemicals, Manufacturing, and other industries where managing operational risks is a material concern.
Although most of the companies referenced in this study deploy unique company-specific programs for managing QHSE performance, they share one thing in common. Each of them is applying a common technology solution to collect and analyze data from a myriad of "risk reduction" events such as incident investigations, near miss reports, management system audits, risk assessments, assurance reviews, behavioral observations, field-level inspection programs, hazard analysis, and many other processes. As depicted in the below diagram, the intended scope of this database is to be the organization's collection of all events that result in risk reduction actions.
Rejuvenating Field Production through Horizontal Wells in Unfavourable Mobility and Strong Aquifer Environment - A Case History
Authors: Junchang Dong , Mohammed Ahmed Abdalla , Tewari Raj Deo , Fenghan Bai , Saeed Ismail 
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
Maximization of recovery from multilayered, viscous and highly heterogeneous oil fields is a challenging task for operators. Heglig oil field is located in Muglad basin of Sudan wherein oil accumulation is found in multiple layers of late cretaceous deposits. The formations are heterogeneous, unconsolidated with higher viscosity and strong aquifer support. Some formations are tighter too. Field was initially developed with commingly completed vertical wells with a wider well spacing. ESP and PCP are in application for lifting the oil. Current development & production strategies and concepts implemented in the field resulted into exponential rise of water cut which reached to 90% within 10 years of production. This behavior is resulting into sharp decline of oil production and causing significant bypassed oil.
This paper discusses about the midcourse correction and modification of the exploitation strategy of the field by changing the completion strategy and targeting the bypassed oil by placing the horizontal wells of optimal drainhole lengths. Accordingly, reservoir re-development plan adopted drilling of horizontal wells with suitable artificial lift techniques as one of the IOR option for maximizing well productivity in this viscous oil field.
Updated static and dynamic models generated for diagnosing the bypassing of oil and saturation distribution for identifying the suitability of the locations. More than a dozen horizontal wells were drilled during rejuvenation phase which contributed remarkably in oil production, generally 2–3 folds compared to current vertical wells production. Controlled well production limiting to 1000 bopd/well by optimizing the drawdown and pump off take resulted into sustained production from the wells and controlling water cut below 40% after a year of production. The paper also illustrates how integration of different disciplines with focused efforts led to successful rejuvenation of the viscous oil field with proper well placement and sand & water control.
Deepwater Infrastructure Integrity Assurance - State of the Art
Authors: Lee Young-woong , Gerretsen Jan Hendrik , Figueroa Humberto , Raghu Damodaran 
Published: May 2016

Abstract
This paper provides an overview of the Deepwater Integrity Assurance program being developed by Shell for ensuring integrity and reliability of deepwater facilities at minimum technical and commercial risks through a prognostic and holistic suite of tools and techniques. The strategy and workflow processes for design and implementation of the program are described with focus on four major areas shown in Figure 1:
1) Riser Integrity Assurance (RIA) - developing a toolkit to inspect and monitor critical components of risers during the operations phase and ultimately recommending the operational strategies to assure the riser system integrity is maintained cost effectively, operationally safe and reliably,
2) Floating Structure Integrity Assurance (FSIA) - developing intelligent prognostic health management systems to accurately predict deterioration levels and estimate remaining useful life of floating structures,
3) Ultralight Material Application (UMA) - facilitating deepwater development by utilizing and identifying right integrity management technology with high fidelity for lightweight materials, such as high strength steel and composite. A fundamental understanding is required for these 'materials of the future' to ensure appropriate design guidelines and a lifecycle integrity assurance,
4) Subsea System Integrity Assurance (SSIA) - developing a non-intrusive screening tool to enable continuous monitoring of wall thickness of subsea pipelines.
A long term outlook for the above main areas is maturation of the core technologies (see Figure 2) to achieve and maintain excellence in asset integrity through a systematic approach focusing on realizing 'Our assets are safe and we know it' and supporting extended life assessments for ageing facilities, whilst enabling less manning of offshore structures in the future. This will allow operators to assess the real time condition of their integrated deepwater production system and determine cost effective methods to maximize systems integrity.
The principles and experiences outlined in this paper will be of direct interest to professionals interested and engaged in improving both the safety and the performance of deepwater facilities for oil and gas production.
Advanced Seismic Characterization As A Direct Input For Reservoir Modeling
Authors: Anquelle Lorette 
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
With the increasing quality of seismic data, especially in deep-offshore turbiditic environments, seismic attributes are now systematically used to identify reservoirs and characterize their heterogeneities. From pre-stack inversion and training on well data, supervised classification techniques provide volume attributes which attempt to quantitatively reproduce petrophysical properties or geological facies variations within the reservoirs. However the effective integration of those results in the geomodel building is not fully achieved. This is partly due to technical challenges inherent to seismic data themselves, such as limited vertical resolution, noise, and ambiguous discrimination between fluid and reservoir properties…. But lack of time, experience and specific methodology are also key issues.
Through the past years and progressive learning from operational field case studies, we have developed workflows which allow the use of in-house attributes such as Pseudo-Vclay and litho-fluid facies as a 3D constraint for facies modeling, after upscaling within the reservoir grid. Because some facies are difficult to discriminate between each-other from seismic data alone, specific rules are built taking into account different constraints such as the location in the environment of deposition, an adequate combination of different seismic attributes, some cut-off values on attributes, etc.
The resulting workflows always require specific data analysis, intermediate controls and computations, and, above all, a high level of integration with the geological understanding. The final result provides a more robust geomodel in-filling between and beyond the calibration wells and offers a more solid base for 4D seismic information valorization.
Through illustrations on real cases in deep-offshore West Africa and in different operational contexts (pre-development and producing field), we will point out that there is no way for press button methods ; the success of the approach is highly depending on the degree of integration between advanced seismic techniques and geological input.
A New Generation Associative Polymer Extends Temperature Stability Of Deepwater Drilling Fluid
Authors: Schlemmer Robert P. , Phoon Gary 
Published: May 2016

Abstract
Specialty drilling fluids, described by mud companies as rheologically flat, constant, or continuous, were introduced for drilling in deepwater less than 10 years ago. As used, the terms describe a rheological profile which is relatively flat or continuous only when compared to that of a conventional non-aqueous fluid. These specialty fluids have been shown to reduce plastic viscosity by 50–70% at seabed temperature and provide more consistent yield point, 6, and 3 rpm rheological values across a broad range of temperature. The properties are maintained primarily by use of temperature sensitive associative polymers.
First generation associative polymers are efficient but have limited temperature stability. Controlled 16 hour dynamic exposure shows that the temperature stability of the highest quality associative polymer in use by most mud companies is less than 210°F. This modest temperature stability and resulting thermal degradation of the polymer and mud properties has begun to limit application in hot wells. It has been claimed that early generation polymers can be used when bottom hole temperature exceeds 250°F However, it has been necessary in some cases, before logging or completing a well, to spot 50–100 barrels of drilling fluid supplemented with organoclay as a "pill" in the open hole. This is needed if thermal damage and loss of rheological properties are expected to occur due to extended exposure to bottom hole temperature beyond the thermal stability of the associative polymer selected.
When a deeper higher angle well with bottom hole temperature of 250–350°F is considered, the probability for rapid thermal degradation increases and a more stable polymer chemistry is preferred. In 2010 a second generation associative polymer with claimed temperature stability of 350°F was introduced for use in the field.
Laboratory tests confirm significantly improved temperature performance by the novel second generation associative polymer. Field experience has shown that the new polymer is essentially interchangeable with an earlier version without significant change in rheological properties at lower temperature. A detailed study and discussion documents how the new second generation polymer compares to the original polymer in terms of indicative cost, performance, and potential for application in hotter environments.
Reservoir in Fractured Granite Basement (Fgb): Unconventional or Conventional?
Authors: Giao Pham Huy , Trung Bui Duc , Minh Nguyen Hai 
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
Reservoirs in fractured basement are few in number and so far have contributed only a small percentage to the world production of oil and gas. Those from the fractured granite basement (FGRB) are even much fewer, and many of them were incidentally found by an unplanned exploration work. Therefore, it is not unusual to consider them as some unconventional reservoirs. But in Vietnam, where 90% of the national oil production comes from the fractured granite basement one would rather consider them as a conventional reservoir. In any case characterization of fractured granite reservoir is more difficult than that of clastic reservoirs. On top of that, experiences and literatures on this type of reservoir are not so much published and available.
In this poster a review of reservoirs in fractured granite basement is presented. The main information, including the occurrence depth, geographic locations, production, geological age etc. are summarized and tabulated. A distribution map of the studied reservoirs was digitally constructed. In particular, a more detailed description of the Fractured Granite Basment (FGB) reservoirs in Vietnam including the White Tiger field is presented.
There is no doubt that fractured granite basement reservoirs will play a more and more important role in future E&P in the region and all over the world. The paper is expected to bring a useful review that is of interest for those will be or are dealing with exploration and production of reservoirs in fractured granite basement.