bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Autonomous Underwater Vehicle with Remote Piloting Using 4G Technology
Authors: Newell Todd , Gayathry Hema 
Published: November 2020

Abstract
Conventional remotely operated vehicles (ROVs) are tethered with umbilical cable and are distantly controlled by a vehicle operator. The ROV control system requires constant monitoring due to complexities caused by unknown nonlinear hydrodynamic effects, parameter uncertainties, and system inflexibilities (conventional ROV systems cannot be preprogrammed and can only be operated at a limited distance due to tether length limitations). Conventional operators are unable to dynamically compensate existing vehicles for operations that need further efficiency, flexibility in movement, and a non-disruptive data transfer.
To solve these challenges, Oceaneering introduced its next-generation resident ROV, which provides a new level of flexibility and efficiency while performing common ROV tasks, such as surveys, inspections, valve and torque tool operations, and manipulator-related activities. The next-generation resident ROV is sustained by a docking station at seabed, and its design features hybrid functionality that enables it to operate in two modes: remotely piloted via tether to provide real-time control or by battery power, operating autonomously and without a tether.
Using a next-generation resident ROV decreases the number of vessel days required to complete operations, reduces carbon footprint, and minimizes mobilizations. It enables operators to expedite subsea interventions in strategic locations and overcome challenges associated with weather windows. The next-generation resident ROV also improves operational versatility by offering tethered and autonomous operating modes and significantly improved depth ratings that enable it to access difficult-to-reach locations. Vehicle operations are supported by our remote piloting and automated control technology (RPACT) and Onshore Control Center. By delivering a single-source solution, users are able to streamline operations, adopt standardization across projects, and reduce both cost and risk. The operational flexibility of the next-generation resident ROV is driven by proprietary supervisory control software. Whether the vehicle is operating with or without a tether, this software provides complete vehicle control, autonomy, payload and sensor control, topside mission planning, and situational awareness. Oceaneering's proprietary supervisory control software provides key vehicle piloting improvements, including an unprecedented level of awareness in crowded subsea fields.
The next-generation resident ROV can also be programmed to make piloting decisions without the need for human pilot control, such as for avoiding obstacles or responding to changing plans. By taking advantage of the known subsea environment, proprietary software enables pilots commanding the next-generation resident ROV to be available for other tasks. This combined software and vehicle configuration makes it possible to perform more tasks, faster and more safely than ever before.
Twelve Years Field Applications of Offshore Heavy Oil Polymer Flooding from Continuous Injection to Alternate Injection of Polymer-Water
Authors: Pan Guangming , Zhang Lei , Huang Jianting , Li Hao , Qu Jifeng 
Published: November 2020

Abstract
South part of NN reservoir, located at Bohai Bay of China, has reservoir characteristics of complex oil-water contact system, thin single pay zones of 6~8 m and heavy oil viscosity with 413~741mPa·s. At initial natural energy production stage, daily oil of horizontal well reached 21~ 35m3/d. Due to complex oil-water relationship and high formation oil viscosity, oil production rate of whole reservoir decreased from 0.6% to 0.3% after one year.
Considering increasing viscosity of injected fluid and reducing the difference of water-oil mobility ratio, polymer flooding with continuous injection mode was carried out since 2008, and its initial good application effect demonstrated polymer flooding was suitable for the thin heavy oil reservoir. However, the problem of gradual decreasing injection ability and oil increment occurred after eight years of continuous injection.
A series of physical experiments indicated that profile inversion was inevitable for long PV continuous injection, which results from the difference in the variation of resistance coefficients in high and low permeability zones. The phenomenon of profile inversion was also found in field application by water profile test data over the years. It became critical to inhibit profile inversion for the following injection stage. Two kind of modes including continuous and polymer-water alternate after long PV continuous injection were considered by double tube contrast experiments. Results showed that alternating injection performance was better than continuous injection, low permeability tube had higher oil recovery and larger flow fraction in alternating injection, which demonstrated profile inversion was inhibited in alternating injection mode and more fluid flew in the low permeability tube. After alternate injection was carried out in target reservoir in 2016, the injection rate was increased by 20% because of lower phase viscosity. The average resistance coefficient of alternating mode reached as high as 1.74, which was similar to continuous injection process (2.06). Around the three injection wells, there are nine wells increasing the oil production, and incremental oil production for single well has reached 0.45×104m3~2.12×104m3. The total daily oil production was enhanced by 30%, and the water cut was decreased by 8%. During alternating injection process, polymer agent dosage was reduced by 50%, and operation cost of barrel oil was reduced by 85%, which showed good economic benefit.
Polymer flooding has been considered a suitable method for reservoirs with viscosities up to 150 mPa·s. Our practice confirmed again such alternating injection of polymer-water development techniques were also effective and economical for heavy oil fields, even in the offshore oil fields. Polymer flooding pilot of initial continuous and then alternate can provide certain technical reference for similar reservoirs.
Revealing Deeper Plays, Offshore Kutch, India: A Success Story of Sub-Basalt Imaging
Authors: Biswal S. K , Naidu N. N. , Basu S. , Kole J. , Sengupta S. , Goswami S. K , Menzel-Jones G. , Chowdhury B. , Sazykin A. , Aly O. , Afia M. , Mukherjee A. , Mallick A. 
Published: November 2020

Abstract
Novel System for Mitigating Sand Production Using Surface Modified Nanoparticle
Authors: Kalgaonkar Rajendra Arunkumar , Chang Fakuen 
Published: November 2020

Abstract
Sanding in hydrocarbon producing and water injection wells has been a severe problem in unconsolidated formations. Many technical solutions have been evaluated by the industry. These solutions encompass mechanical sand exclusion methods such as screen, gravel packing, and frac and pack. Various production and completion practices such as controlling the production rate and following specific well completion guidelines to minimize sand production have failed to provide satisfactory returns. Several limitations such as screen plugging and high costs associated with deploying expandable screens make the current mechanical sand control practices more expensive. With both cost and treatment effectiveness in mind, chemical sand consolidation could present the most cost effective remediation and prevention opportunity. Additionally this would also allow the wellbore to be free of tools, screens and pack sands.
In this paper we describe the development of a unique chemistry for mitigating sand production in unconsolidated formations. This chemistry involves using cationically-modified nanoparticles that can self-assemble over loose formation sand to form a layer of consolidating material thus preventing any unwanted sand production. The new consolidation treatment material consists of colloidal nanoparticles modified using a cationic modifier and oligomeric activator that is initially low viscosity fluid. The fluid has high affinity to the solid surface therefore less prone to build up in the pore space. Once cured at reservoir temperature it forms a thin layer of hard gel around the surface of the sand particles, thus cementing the sand grains together at the same time maintaining open porosity to ensure easy flow of hydrocarbons and injected water.
The ability of the new fluid to consolidate loose sand and at the same time maintain good permeability was investigated. Various oligomeric activators were studied with particular focus on effect of concentration temperature and shear. The ability of the cationic modified nanoparticles to self-assemble around unconsolidated sand and eventually cure to form a consolidated sand pack was investigated. Regain permeability studies showed excellent regain permeability of the consolidated sand pack. It was also shown that the new sand control fluid system provides a controllable curing time, thus avoiding any premature setting of the nanoparticles in the wellbore.
The novelty of the newly developed sand consolidation system is its ability to self-assemble around unconsolidated sand and eventually cure to form a consolidated sand pack while maintaining good permeability.
Application of Compressive Seismic Imaging Technology for Multi Component Ocean Bottom Nodes Seismic Survey Acquisition in K Field, Sabah Offshore and Reconstruction of Multi Component Data
Authors: Abdul Rahim Abdul Aziz , Zainal Nur Fitri , Li Chengbo , Mosher Chuck C. , Janiszewski Frank D. 
Published: November 2020

Abstract
An illumination forward modelling feasibility study conducted in year 2017 over K-field, Offshore Sabah has demonstrated multi-component Ocean Bottom Node (OBN) seismic as a viable method in achieving the subsurface objectives particularly utilising mode-converted shear waves (Ps) that will not be affected by the gas overburden; thus, allowing imaging the structure and characterizing the reservoir underneath it. The seismic survey design was optimized further through Compressive Seismic Imaging (CSI) where seismic sampling is unregularized to improve imaging based on the increase in fold, trace density and bandwidth while optimizing cost through reduced sail line kilometers. The acquired data was then reconstructed to enables denser sampling and higher unaliased bandwith.
Integration of Casing Wear Simulation in Well Design and Casing Stress Analysis for Lateral Wells
Authors: Rosland Habil Akram , Tengku Majid Tengku Khairi , Rosli Azlesham 
Published: November 2020

Abstract
A casing wear assessment was implemented as part of the workflow and methodologies for an operator well design process to better anticipate the critical failure mode of a tubular string. Because the reduction in tubular string wall thickness as a result of drilling and workover operations has been an ongoing concern within oil and gas field development, casing wear modeling with a workflow to accurately predict wear and minimize uncertainties is vital to maintaining well integrity throughout its lifespan with minimal or zero intervention. Because of multiple high-angle lateral branches drilled in lateral wells, the wear factor should be understood while managing casing wear. Wellbore and drillstring geometry can incur high lateral loads on tool strings and production casing, causing possible excessive casing wear. This wear reduces both burst and collapse ratings of the casing and can wear through the casing, resulting in costly remedial intervention measures for mitigation.
This paper provides an integral insight for production casing wear focusing on a lateral well simulations study of the underlying wear factors ranging from the base case to the worst case. This enables a proper assessment in the well design by means of casing integrity, particularly for multilaterals and deep and/or long horizontal wells. A simulation and detailed workflow on how to incorporate its results into a multilateral/highly deviated casing design and stress analysis are discussed, thus providing an integration process resulting in improved anticipation of the critical failure mode for the investigated tubular string for this type of well.
Artificial Intelligence Assisted Production Forecasting and Well Surveillance
Authors: Masini Shashipal Reddy , Goswami Shubham , Kumar Aditya , Chennakrishnan Balaji , Baghele Abhishek 
Published: November 2020

Abstract
In oil and gas, Production forecasting is the most vital process required for all the operational and investment decisions. The basis for any project-based resource estimation is a good production forecast. The objective of this paper is to demonstrate assisted production forecasting from the real-time data using AI (Artificial Intelligence) Techniques.
Decline curve analysis is one of the most used production forecasting methodology. Conventional Production Forecasting involves anomaly removal and applying best method for DCA (decline curve analysis). These processes are combined and automated Using Big data and AI techniques, in this method. The algorithm used clustering techniques like isolation forest and density-based clustering to automatically remove the anomalies and later uses neural network / conventional curve fitting (depending upon data frequency) for production forecasting. It also used LSTM (Long Short-term memory cells algorithm) neural network to predict the flowing bottom-hole pressure with the rates forecasted using automated production forecasting. This in-turn was used along with VFP (Vertical Flow Performance) curves of the well to assess the well ceasure date under existing condition. The algorithm also has a module to recommend the decline rates of workover wells based on the similar past events by using unsupervised clustering techniques.
The algorithm removed the anomalies data and perform production forecasting in a scalable manner. The actual and calculated EURs were matching very closely (very less root mean square error and a maximum deviation of 8%).
This approach is useful to debottleneck the processes involved in production forecasting like identifying the rate changes, production forecasting and FBHP prediction. This information can be coupled with an interactive dashboard to support quick diagnostics, easy interpretations and prompt business decisions.
First Successful Utilisation of High Density Micronised Ilmenite in South East Asia
Authors: A Razak M Solehuddin , Ezani Farah Shakina 
Published: November 2020

Abstract
The objective of this paper is to share the Operator's first experience in utilizing ilmenite in an offshore HPHT well as part of a low cost well initiative and the value obtained by utilization of such a weighting agent in particular towards lowering ECD. After extensive testing micronized ilmenite was used as the weighting agent for the synthetic based drilling fluid (SBM) for the B1 well. This well was classified as high complexity with a narrow margin window and with predicted maximum bottom hole pressure of 12,013 psi at 3,990 m TVDDF.
Extensive laboratory testing was conducted to determine the optimum formulation for a 16 ppg SBM. Part of the methodology in the testing was conducting rheology comparisons between various weighting agents, manganese tetraoxide, barite and micronized ilmenite. The subsequent results were then run through hydraulics simulations to determine the best formulation for optimized hydraulics. Additional testing was conducted to determine the overall stability of the system including conducting static sag tests with a similar duration to the planned wireline logging operation.
The primary drivers for using this fluid were to reduce ECD in a narrow margin environment and facilitate the taking of good wireline logs by providing optimum hole conditions without any sag. The micronized ilmenite system successfully achieved a similar rheology to manganese tetraoxide with low PV's of less than 50 cP at 17 ppg and a sag index of less than 0.52. These properties were at an OWR of 80:20. This led to both the successful drilling of the well and completing the required wireline logging with no fluids related NPT or issues related to sag. During logging, the mud was static for 5 days without problems. The mud weight of 17 ppg was the highest density, at that time, at which the micronized ilmenite system had been used.
Pulsed–Neutron Log Design for Uncertain Water Salinity Reservoirs in an Oil Producer Offshore
Authors: Tao Bin , Zhou Jiheng , Wu Ke , Zhang Zhongqing 
Published: November 2020

Abstract
When an offshore oilfield enters its secondary development stage, the formation residual oil saturation is the crucial information for development planning. Pulsed-neutron logs can accomplish the task of residual oil saturation investigation in cased hole. Building on the various types of nuclear reactions between neutrons and formation, multiple pulse neutron logging modes were developed and are applied in different logging environment. How to choose the most appropriate log mode to improve work efficiency is particularly important for offshore operations.
The capture cross-section log (SIGMA) is the best choice in high water salinity reservoirs. It can be recorded with relatively faster speed and need single pass only, saving lots of operation time. But sometimes the formation behind casing may be polluted by the low-salinity water injected during the past oilfield development, the uncertainties of the water salinity always act an important role effecting the accuracy of interpretation results. The carbon/ oxygen ratio log (C/O) can overcome the water salinity problem, because it is salinity-independent log. However, due to the measurement physics, a C/O log usually requires multiple passes with lower logging speeds, cost significant amounts of operation time.
This paper introduces a novel pulsed-neutron log design that was successfully practiced in North Asia, where it took the advantages from both Sigma and C/O log modes to efficiently overcome the challenges of residual oil investigation in an injection polluted formation. The core method of this log design is "C/O calibrated Sigma". We use C/O log results to calibrate the formation sigma water, then apply it to calculate the water saturation of full interval. Field engineer log a short interval in C/O mode with multiple passes. Then log only a single pass with full target formation in SIGMA mode. Once the geoscientist received the data, firstly process C/O data to work out the water saturation of that short interval. Secondly, use the saturation result of C/O along with SIGMA log data to inverse-calculate the formation water sigma. Finally, apply the water sigma to calculate the water saturation of full interval.
By applying this methodology, the calibrated formation water salinity was calculated and proved to be lower than the original formation water. The full scope formation water saturation was successfully determined within an acceptable operating time (6 hours), compared with conducting the C/O log across the full interval which required more than 18 hours, increased the offshore operations efficiency as well as minimized the interpretation result uncertainties.
A Truly Multi Cycle, Remotely Activated Barrier Valve Boosts Reliability in Subsea Applications
Authors: Croucamp Leandre , Munro Christopher Robert , Murdoch Euan Martin 
Published: November 2020

Abstract
The reliability of subsurface barrier valves has long been an industry problem. This can lead to costly interventions, especially apparent in deep-water subsea markets. This paper describes the world's first deployment of multicycle barrier valves in 2 subsea wells in Australia that uses innovative methods of both remote activation and triggering, that have been previously unavailable on the market, and attain a step change in reliability.
The remote activated barrier valves were deployed as part of a subsea gravel pack system. They were initially run in hole (RIH) open as part of the lower completion, then closed mechanically. The valve was subsequently opened via Radio Frequency Identification (RFID) tags and then closed again mechanically to allow the running of the upper completion. Frequency modulated pressure cycles were applied to the well to open the valve and allow the well to flow.
The valve functioned exactly as planned, and it was demonstrated that it could be closed multiple times on a semi-sub vessel. The valve was then opened via RFID tags conveyed on wash pipe. This is a much more reliable method when in high debris environments. The valve was opened for the final time via frequency modulated pressure cycles. These are better able to be transmitted through debris and are not affected by other hydraulic events in the well.
The hydraulic pump that is used to actuate the tool provides a constant force directly to the ball valve mechanism and is not subject to failures over time like existing gas charges, ratchet mechanisms or springs. The RFID, Mechanical or pressure cycles used to trigger the valve offer a huge increase in operational flexibility that have never been able to be realized with existing technologies.
Application of Intelligent Sliding Sleeves to Improve Reservoir Management, Operation Efficiency and Well Economics
Authors: Wei Ping , Zeng Fanqian , Wang Kai 
Published: November 2020

Abstract
The sliding sleeve has been widely used in upper completions as a useful flow management device to enable selective communications between the production tubing and the annulus. Traditional sliding sleeves are mechanically operated by standard wireline method, which not only results in non-productive time and potential operational risks but also restricts sliding sleeve applicable in vertical wellbores only.
To overcome the limitations, this paper introduced an innovative Hydraulic Controlled Sliding Sleeve (HCSS), which eliminates interventions with conventional wireline shifting tools. HCSS offers instant open/close operation by surface controlled hydraulic pressure through a single control line. HCSS features unique advantages over mechanical sliding sleeves, by its operational simplicity, independence on wireline units, and applicability in deviated wells and horizontal wells. The application of HCSS could save non-productive time, reduce operational risks and improve operational efficiency and economics.
This paper will give a comprehensive demonstration of HCSS and illustrate the working principle in detail. Unique features and capabilities over traditional sleeves will be discussed explicitly. HCSS will be opened by applying hydraulic pressure from the surface control unit to activate the movement of the inner sleeve, and it will be closed simply by releasing the pressure, which will allow the inner sleeve to return to its original position. In the case of hydraulic control failure, HCSS also equipped with a secondary open/close mechanism by the special shift tools operated by coiled tubing. The authors conducted two representative case studies of HCSS application in offshore upper completion in Bohai bay in China to further highlight the improvement of operational efficiency and well economics.