bluuebunny/crossref_metadata_2025_split huggingface dataset:
Low-Adhesion Coatings as a Novel Gas Hydrate Mitigation Strategy
Authors: Brown Erika , Hu Sijia , Wang Shenglong , Wells Jon , Nakatsuka Matthew , Veedu Vinod , Koh Carolyn 
Published: April 2017

Abstract
Gas hydrates typically form at high pressure and low temperature conditions where water and small gas molecules exist in sufficient concentrations. When these thermodynamic (temperature, pressure, composition) conditions are fulfilled in oil and gas production flowlines, gas hydrate plugs can form and greatly restrict flow, which can lead to severe safety, economic, and environmental consequences. One potential strategy towards hydrate management involves allowing hydrates to form, but mitigating their tendency to deposit on the flowline walls by deploying a low adhesion, protective surface coating on the interior of the flowline. Without deposition (and agglomeration), the hydrate slurry can be transported until it exits the thermodynamically stable region without impeding production.
In this study, two coatings were produced and evaluated to determine their effect on hydrate adhesion onto carbon steel surfaces. The coatings used in this study were a super-hydrophobic, anti-icing coating and an omniphobic and corrosion resistant coating. The coatings were applied to substrates in both pristine (no corrosion) and pre-corroded conditions, where the coupon was exposed to a 5 wt.% salt solution prior to coating. Hydrate/surface interactions were studied using micromechanical adhesion force measurements in both liquid and gas bulk phases. A model sII cyclopentane hydrate (forming the same hydrate structure that is typically formed in subsea flowlines) was utilized at atmospheric pressure for the liquid phase measurements, while the high pressure measurements were performed using methane/ethane mixed gas hydrate (also sII). Rocking cell tests were also conducted to evaluate the coatings at high pressure under dynamic conditions using methane/ethane mixed gas hydrates and a liquid loading of 70 vol.% (water + oil).
It was observed that applying the coating to a surface was effective at reducing the adhesive forces between hydrate particles and steel surfaces, especially in the presence of corrosion. This held for both the low and high pressure micromechanical force adhesion tests. Rocking cell tests additionally revealed a significant reduction in time to hydrate deposition at low water content under dynamic conditions. The initial results from these three apparatuses suggest that utilizing these coatings may be an effective hydrate mitigation strategy at low water content, and in flowlines which have undergone significant internal corrosion, but more research is necessary to characterize the hydrate/surface interaction when a higher water content is present.
A Review of Hydrate Formation for Partially Dispersed Systems in Multiphase Flow Conditions and the Detection of Hydrate Deposits
Authors: Majid Ahmad A. A. , Grasso Giovanny , Creek Jefferson L. , Qin Hao , Charlton Thomas , Estanga Douglas , Rivero Mayela , Bbosa Ben , Waturuocha Amaka , Volk Mike , Koh Carolyn A. 
Published: April 2017

Abstract
The formation of gas hydrates in subsea oil and gas flowlines is a major concern since this can cause production interruptions, and environmental and safety problems. Under gas hydrate formation conditions, hydrates can create flow restrictions, that may then lead to plugging of the flowline. The risks associated with hydrate formation in subsea flowlines increases significantly as the reservoir matures and the amount of produced water increases. The oil and gas industry recognizes the need for the investigation, development and implementation of better hydrate management strategies covering the gaps in current practices.
In helping to develop better hydrate management strategies, hydrate formation in partially dispersed multiphase flow conditions were previously investigated using a high pressure industrial-scale flowloop (Vijayamohan et al. 2016). In our recent tests using the same flowloop, the effect of hydrate volume percent on the pressure drop of the system was evaluated. The amount of hydrate formed in the system was limited by systematically controlling system temperature and gas available for hydrate formation.
In recent flowloop tests, it was also hypothesized that hydrate deposition on the pipe surface can contribute significantly to a rapid increase in the pressure drop (Grasso 2015). As such, an investigation into hydrate deposition mechanisms and their detection was performed. Deposition mechanisms were investigated using a high pressure lab-scale flowloop (Grasso 2015). In this part of the work, hydrate deposition mechanisms were evaluated by varying parameters such as liquid loading, water cut, subcooling, and liquid/gas phase velocity. The results from these laboratory-scale investigations show that both liquid and gas phase velocities have a high impact on the amount of hydrate formed in this system.
The results from the investigations presented in this paper provide new insights into hydrate formation and deposition mechanisms. It is anticipated that such investigations can lead to new possibilities for more advanced hydrate management strategies for the flow assurance community.
Gas Hydrate Formation in High Water Content Systems Containing Anti-Agglomerat and Salt
Authors: A Majid Ahmad A , Braniff Martin , Creek Jefferson , Koh Carolyn A , Kusinski Greg , Gomes Joseph 
Published: April 2017

Abstract
In this work, the effects of an anti-agglomerant (AA) and salt (sodium chloride, NaCl) on water-in-oil (w/o) emulsion stability with and without the presence of gas hydrates is presented. The characteristics of gas hydrate formation and the hydrate slurry transportability were determined using a high pressure autoclave cell, with continuous mixing. The stability of the emulsions was independently measured by performing bottle tests, where the stability of the emulsion was determined by observing any evidence phase coalescence for a period of one week after emulsification. In addition, the stability of the emulsion with hydrate formation and dissociation was tested using high pressure differential scanning calorimetry (DSC). From high pressure autoclave studies, it was observed that the formation of a stable emulsion was shown to with the subject oils led to transportable hydrate slurries. Note however, it was observed that for this specific oil at 75 vol.% water cut and the addition of both AA and salt, a highly viscous mousse with viscosity of ~100 000 cP formed when the emulsion was saturated with methane gas at 950 psia and 20 °C. Even without the presence of hydrate, the formation of a highly viscous mousse may not be desirable in the field production system since it could render the system inoperable (effectively plugged).
Interestingly, it was observed that the highly viscous mousse produced dispersed slurry of hydrates upon hydrate formation. Based on the autoclave studies, the absolute motor current (which indicates the relative viscosity of the system) at maximum amount of hydrate is 2 times lower of its original viscosity.
Performance Comparison of Sand Jet Perforating to Explosive Perforating for Multistage Hydraulic Fracturing of Coal Bed Methane Wells
Authors: Dotson Thomas , Gupta Tanya , Sharma Anshit , Marwah Devashish 
Published: April 2017

AbstractMulti-stage hydraulic fracturing of coal bed methane wells using coiled tubing in Raniganj Coal Bed fields in the eastern part of India has been steadily increasing over the last several years. The completion process of these wells involves various kinds of explosive perforating and sand jet perforating (SJP) prior to the hydraulic fracturing process. Communication with the reservoir is vitally important to the success of the hydraulic fracture. Sand jet perforating is a process that uses high pressure fluid slurry to perforate the casing and cement of an oil or gas well, and extend a cavity into the reservoir. This paper examines the performance of traditional explosive perforating versus sand jet perforating through an examination of case history using both technologies in the same zones. Different operating parameters of sand jet perforating are evaluated. Performance evaluation includes the production of the well.The paper describes various methods for hydraulic fracturing of coal bed methane formations using a bottom hole assembly with perforator on coiled tubing. The generalized stimulation method for perforating employs the following steps: Run the bottom hole assembly (BHA) to the zone to be treated.Perforate the zone.Perform the hydraulic fracturing of the zone.Isolate the zone.Pull up to the next zone and begin again.The procedures and process of each completion method will be discussed in detail.Case history is used from a coal bed methane well in the Raniganji Coal Bed Methane Field, to compare the different parameters of the hydraulic fracturing process in coal beds for traditional explosive perforating versus sand jet perforating. The effectiveness of the treatment process as it relates to production and cost of the treatment is compared.New techniques for sand jet perforating were employed in the subject wells to improve the communication between the wellbore and the formation. Variations in pressure, and flow through the bottom hole assembly, sand concentration, and total sand delivered are compared and conclusions will be made for optimizing the treatment process.
Degradable Thermoset Polymer Composite for Intervention-Less Downhole Tools
Authors: Khatiwada Suman , Duan Ping , Garza Ramon , Sadana Anil K. 
Published: April 2017

Abstract
Commercially available polymeric frac balls and other downhole tools made with polyglycolic acid (PGA), a thermoplastic, have severe application limitations owing to their low Tg of approximately 104°F as well as high cost. A thermoset polymer composite made from cyanate ester resin has been developed that exhibits hot-water degradability as well as excellent mechanical properties. This polymer composite demonstrates excellent potential for use in structural components of downhole tools for intervention-less operations. A degradable composite with cyanate ester resin with a glass transition temperature (Tg) of 536°F was prepared by adding inorganic fillers and glass fibers. A new process was developed to prepare a bulk molding compound from this composite that enabled fabrication of parts via compression molding. Molded parts were tested for their mechanical properties and for their degradability in water and brines. The composite with one quarter inch chopped glass fiber has a compressive strength of 41.88 ksi, tensile strength of 15.83 ksi, tensile modulus of 3.62 Msi and an elongation-at-break of 0.48%. Composite degradation occurs at 200°F and above, with a higher rate of degradation observed as the temperature increases.
Optimizing Proppant Surface Properties to Improve Formation Flow in Offshore Frac-Packs
Authors: Bestaoui-Spurr Naima , Stanley David , Williams Vanessa , Usie Marty , Nguyen Hanh , Hoffpauir Erik 
Published: April 2017

Abstract
The objective of this study is to introduce a new neutral wettability proppant that improves flow and cleanup of the proppant pack. It is known that the proppant pack permeability is the primary factor that affects the productivity of a fractured well. In such operations, fracturing fluid (cross-linked or linear) is used to deposit the proppant. In order to transport proppant within the fracture, fracturing fluid rheological properties must be attained based on fracture type, job design metrics, formation characteristics, proppant properties and proppant loading. These fluid properties are typically adjusted by using gelling agents and other chemical additives to ensure transport capability. The types and concentration of gelling agents, cross-linkers, and breakers, are known to affect the permeability of the pack. If these fluids are not removed, they build up in the proppant pack. This fluid retention leads to decreased permeability and reduced effective half-length of the fracture. In this paper a neutral wettability proppant that is neither oil wet nor water wet was used to (1) eliminate capillary pressure within the proppant pack and (2) alter the interaction between aqueous/organic (hydrocarbons) and the proppant surfaces by decreasing the intra-molecular interactions between the fluids and the proppant surfaces thus resulting in improved flow compared to native surfaces.
Light weight ceramic proppant was permanently surface modified to a neutral wettability state. This new proppant was evaluated in the laboratory and in the field for compatibility with the fracturing fluid, clean-up properties through the proppant pack and recorded flow back of treatment fluids after a frac-pack operation.
Results indicated that the new proppant surfaces not only reduced water saturation but also improved oil mobility. These observations showed the promises of permanently modifying surfaces as next-generation products for improved flow and decreasing the risk of formation damage due to the fracturing fluids left behind after treatment. When this proppant was applied in a frac-pack completion, flow back was efficient with rapid recovery of all pumped fluids. In this case the surface of the proppant reduced the intra-molecular forces between the proppant and the fracturing fluid, eliminating capillary pressure within the frac-pack and leading to a more efficient and quicker fracturing fluid flow back compared to using proppant in its native state. First oil breakthrough was earlier than other wells in the same area.
Characterization of Wet Gas Flows
Authors: Subramani Hariprasad J. , Sambath Krishnaraj , Rhyne Lee D. , Nadge Pankaj , Vedapuri Damodaran 
Published: April 2017

Abstract
Presently, several large deep water natural gas fields are designed to produce over 1000 MMSCFD of gas with low liquid content &lt;20 BBL/MMSCF. Such deep water facilities are typically comprised of ~8-10" diameter well manifolds and 30-40" in diameter 100 mile long flow lines that are operated at high pressure and temperature conditions. Key CAPEX and OPEX decisions for deep water gas facilities include: wellbore tubing and subsea flow line sizing, subsea flow line routing, pigging frequency, pipeline materials, range of allowable operating rates and large production rate variations, and subsea asset integrity management. Key design decisions require knowledge of variations in flow regime over field life, liquid hold-up in the flow lines, liquid entrainment and sand in the fluids in the subsea facilities that may result in erosion at the high operating limit and sand deposition concerns at low operating limit. Given the scarcity of data at conditions similar to wet gas field conditions, current industry-standard multiphase flow simulators predict flow behaviors with a high degree of uncertainty and hence, are known to have been inadequately validated. This paper presents a unique set of high quality wet gas multiphase flow data in a 16" diameter flow loop operated at ambient conditions including several salient measurements such as pressure drop, liquid hold-up, liquid film velocity as a function of liquid film depth, average liquid film velocity, etc. using state-of-the-art instrumentation.
Study of Anti-Agglomerant Low Dosage Hydrate Inhibitor Performance
Authors: Salmin Davi Costa , Majid Ahmad A. A. , Wells Jonathan , Sloan E. Dendy , Estanga Douglas , Kusinski Greg , Rivero Mayela , Gomes Joseph , Wu David T. , Zerpa Luis E. , Koh Carolyn A. 
Published: April 2017

Gas hydrates can form in subsea oil and gas flowlines, where the depths of seawater and ocean conditions provide the thermodynamic environment for hydrate stability. Hydrates present a major flow assurance problem due to the relatively fast timescales at which they can form, grow/agglomerate, and plug a flowline. The common strategy for preventing hydrate formation uses thermodynamic inhibitors (THIs). However, THIs can be cost prohibitive or impractical as the water content in the flowline and its seawater depth increases. Therefore, there is growing interest in the use of alternative hydrate management strategies, such as the injection of low dosage hydrate inhibitors (LDHIs), which are active at considerably lower concentrations than THIs (e.g. 2 vol.% of LDHI versus 50 vol.% of THI). Anti-agglomerants (AAs) are a type of LDHI that prevent agglomeration and allow hydrates to flow as a slurry in oil and gas subsea flowlines. Before field deployment, AAs are screened and selected using laboratory set-ups, mimicking field conditions, in order to evaluate their performance and determine the effective dosage. Current hydrate agglomeration characterization methods implemented in the industry are non-uniform and qualitative, which can lead to conservative recommendations.
In this work, the possibility of quantifying hydrate agglomeration in the presence of AAs is investigated, along with studies of the mechanisms via which AAs may operate. One mineral oil and two crude oils were used with a commercial AA in a high pressure stirred autoclave, equipped with particle imaging probes. Motor current input at a fixed RPM was monitored throughout the experiments and serves as an indicator of relative viscosity of the hydrate slurry. This investigation enabled the development of a comprehensive AA performance evaluation. Hydrate agglomeration was detected and quantified by simultaneous increases in the relative motor current and chord length distribution.
Framework for Prediction of NPT causes using Unstructured Reports
Authors: Priyadarshy Satyam , Taylor Aimee , Dev Ashwani , Venugopal Suresh , Nair Geetha Gopakumar 
Published: April 2017

Abstract
Drilling capital expenditure represents significant portion of any oil and gas project. Drilling investment accounts to about 40% of the cost of the well. Therefore monitoring the health of equipments and processess associated with rigs are critical in bringing down both the cost of the well and the Non Productive Time (NPT). At the moment there are several Key Performance Indicators (KPIs) to monitor NPT but they are reactive in nature. Proactive measures can be taken to avoid NPT and reduce Invisible Lost Time (ILT) by exploiting the power of big data. The scope of this work is to create a framework to predict NPT and ILT causes from massive degree of unstructured data collected during the drilling operations. KPIs and performance values come from numerical metrics. In addition, the industry has also gathered an enormous amount of unstructured data from drilling and other reports. In many industries, Natural Language Processing (NLP) has been used to create value from unstructured data. Upstream reports are not exactly natural language ready reports. Our approach on generating value from these reports has two major steps (1) transforming NLP challenge to Technology language processing (TLP) in drilling context, and (2) classification of NPT causes.
The two-step approach mentioned above results in a framework for mining unstructured reports to detect anomalies like symptoms, events, and actions. A modified NLP, referred here as TLP in the drilling context is used to achieve the first set of data extraction. Furthermore, a predictive model for classification of NPT and ILT causes is performed on the extracted data. The accuracy of these predictive models is an on-going effort, as it is dependent upon the transformation and detection of complex technical language that is inconsistent due to multiple reasons. However, this framework provides a foundation for predicting NPT / ILT during different phases of drilling operations. Use cases that predict attributes related to hole packoff or equipment failure shows the accuracy in the range of 50% to 70% due to a limited amount of extracted technical terms that are relevant. The framework calls for continual improvement of employing deep learning algorithm based on enhanced recovery of correlated technical terms across unstructured reports.
While there are many attempts in using NLP for mining data in E&P sector, in this paper we present a framework for mining unstructured reports that leverage contextual Technology Language processing a step ahead NLP. Our framework incorporates the use of various machine learning algorithms to detect multiple attributes necessary to calculate NPT and ILT, and guides on how to enhance the predictive model.
DeepStar® Global Offshore Technology Development Program 12505 Analysis of Current Technology and Capabilities for Shearing
Authors: Gomes J. , Kusinski G. , Freitas F. 
Published: April 2017

This work shares some of the impactful collaborative efforts completed within DeepStar® Global Deepwater Technology Development Program as part of Phase XII projects in X500 Drilling & Completions committees. It will lead to gap identification and provide a current baseline of shearing technologies.
The goal of this research was to survey the BOP industry and gather information about the current state-of-the-art of shearing systems as well as future shearing technologies. The work includes: development of a survey form/table, data collection, and reporting.
A survey table has been developed as part of the present project. The survey table includes: equipment specification (description/type, rated pressure, rams type, etc.), equipment capabilities (water depth rating, compatibility with H2S environment, working temperature range, etc.), equipment options to improve performance (customizable options to enhance shearing performance ram capabilities and/or options for specific applications such as sour service), and testing (repeatability of shearing and durability performance, tested pipe sizes, wall thicknesses, material grades, evidence of testing, etc.).
The desired outcome of the present work includes DeepStar® operators members being allowed access to performance information regarding current state-of-the-art shearing systems summarized in one report. The report will facilitate discussion about the available shearing capabilities as well as future technologies. This document can also be helpful in selecting BOP providers (and/or future technology providers that will be able to operate in 20 ksi pressure conditions).