bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mesh Learning: A Cloud and Edge–based Computing Network Providing Data–Driven Solutions to the Oil and Gas Industry
Authors: Wen Tailai , Dobson Ellie , Hvaara Roy 
Published: November 2020

Abstract
Over the past decade, the application of machine learning has become one of the most studied topics in the oil and gas industry. The recent success of some small-scale pilot projects has resulted in more attention being paid to deploying machine learning models at scale for operations. While cloud-based deployment (data backhauled for analysis in the cloud) and edge-based deployment (data being analyzed locally at a remote site without persistent Internet connection) are the two major approaches, each strategy has specific advantages and drawbacks. In this paper, we proposed "mesh learning", a new approach that optimally balances cloud computing and edge computing for deploying machine learning solutions in an industrial internet of things (IIoT) environment. We present how the system enables some new strategies to manage machine learning model lifecycles and how it helps with relevant use cases for the oil and gas industry.
Drilling Geomechanics Successfully Applied in a High-Temperature High-Pressure Offshore Well, South China Sea
Authors: Wang Shiyue , Liu Peng , Guo Shusheng , Gao Yongde , Chen Ming , Du Chao 
Published: November 2020

Abstract
Drilling in Yinggehai basin of South China Sea is challenging due to high pressure gradient (2.20-2.30 g/cm3) and high temperature (186-196 0C). Several wells did not reach target and were abandoned due to severe wellbore instability of gas kick and mud loss. In order to drill safely, drilling geomechanics techniques were applied in well LD-6, including: 1) real-time monitored pore pressure and fracture pressure with logging while drilling (LWD) technique; 2) predicted over-pressured reservoir depth and formation pressure ahead of bit with borehole vertical seismic profile (VSP); 3) wellbore stability analysis to reveal the mechanism of mud loss in Huangliu formation.
With drilling geomechanics techniques, well LD-6 was successfully drilled and completed. The achievements were:1) formation pore pressure and fracture pressure were accurately monitored while drilling. The predicted reservoir pore pressure gradient was 2.27g/cm3 and actual measurement was 2.28 g/cm3; 2) The top depth of over-pressured reservoir, S1 Sand, was predicted within 3 meters versus actual depth. The 9-5/8" casing successfully set in shale formation above S1 Sand, which enabled a manageable pressure window for drilling 8-3/8" reservoir section; 3) the wellbore stability analysis with borehole resistivity image revealed that mud loss only occurred in sand and mainly caused by drilling-induced tensile fractures. Stresses computation results indicated that horizontal stress anisotropy in sand is larger than shale; and breakdown pressure in sand is smaller than that in shale. With this finding, drilling parameters was adjusted accordingly and managed downhole pressure within the narrow safe mud weight window.
The drilling experiences in well LD-6 has proved the advantages of drilling geomechanics techniques, especially in HTHP area. It can predict and mitigate drilling risks, optimize mud weight and completion diagram, improve operational safety and reduce costs.
A Systematic Characterization of a Novel Diamond-Like Coating to Reduce Solids Deposition in Production Systems
Authors: Heydrich Marcus , Choudhary Suresh , Hammami Ahmed , Ratulowski John , Bukuaghangin Ogbemi , Charpentier Thibaut , Neville Anne 
Published: November 2020

Abstract
Deposition of inorganic and organic solids in production systems impacts throughput and can cause other operational and safety issues. Once formed, remediation of deposits is costly, often resulting in lost production. Solids management strategies involve a combination of chemical injection, thermal management and periodic chemical or mechanical remediation operations specific for each depositing species. A novel diamond-like carbon (DLC) coating, which exhibits extreme hydrophobicity in oil water systems, has been developed to control deposition of most common solids including asphaltenes, inorganic scale, wax and potentially hydrates under flowing conditions in production tubing and flowlines. This molecularly bonded, multifunctional coating may simplify solids management strategies and lower field development costs by reducing chemical injection, eliminating chemical injection systems, reducing insulation and eliminating the need for active heating. In this paper, we build on previous published data further refining the performance envelopes of the coating for inorganic scales.
Previously published work has shown that this coating is effective in managing wax and asphaltene depositions. Over forty tests in a 2-inch flow loop were used to define an operating envelop as a function of wall shear and δT in which little or no wax deposition occurs. This envelop covers much of the operational range of typical production systems. A Couettte shear cell, Organic Solids Deposition and Control (OSDC) [Zougari et al, 2006], was used to test the deposition tendency of asphaltene on the coated surface at wall shears representative of field conditions. Both live oil and dead oil tests showed a significant reduction of deposits on the coated surface for the two oils tested.
Initial testing for calcite deposition tendency was performed using a benchtop Rotating Cylinder Electrode (RCE) device. Also, small scale flow loop tests were done to determine the impact of the coating on halite and barite deposition. The coating resulted in a reduction of deposition rate for both calcite and halite. For barite, there was a significant reduction in adhesion force between the scale and the coated tubing resulting in an easily remediated deposit. In this paper, we further refine the performance envelopes for calcite and barite with a systematic study investigating the impact of brine composition, wall shear rate and the presence of oil on both deposition tendency and adhesion force.
Based on the positive results of the performance testing, a commercial-scale application facility has been designed and constructed. Plans are underway to deploy the coating, where conditions are applicable, throughout the industry.
Tracking Mercury Contaminant in the Subsurface
Authors: Bourdet Julien F. , Stalker Linda , Hortle Allison L. , Ryan Chris G. 
Published: November 2020

Abstract
In 2019, Australia led all Liquified Natural Gas (LNG) exporters in incremental growth (IGU World LNG report, 2019), supported by the start-up of the Wheatstone and Ichthys LNG projects. Production and economic recovery of gas are affected by the association of chemical compounds naturally present at low to trace levels within natural gas such as carbon dioxide, hydrogen sulphide and mercury. These contaminants generate a cascade of costly treatments and waste recovery efforts. If the level of mercury in a produced gas stream is higher than expected, the treatment process in the LNG plant rapidly reaches capacity and may cause shut-down of the facility or rejection of gas supply resulting in significant profitability impacts. There may also be long term consequences that could impact on the decommissioning of industrial infrastructures in the future.
High mercury levels in produced gas have been reported in South East Asia and Australia (Chalkidis et al., 2020; Black and Saunders, 2018; Zeeshan and Manikandan, 2017). However, currently there are no standard method to accurately quantify the presence of mercury in gas in the reservoir. The highly absorbent and multi-speciated nature of mercury makes reliable gas sampling difficult and generally leads to gross under-predictions of quantity. The spatial distribution of mercury within the reservoir means mercury may not appear in the initial production phase and its presence in fluids may vary over the lifetime of the field.
Understanding the source, the transport mechanism and the distribution of naturally present contaminants in the subsurface is critical for lowering their impact in industrial activity through avoidance. High mercury levels of about 1000 microgram per cubic meter (µg/Sm3) were reported in reservoir gas samples from a sand unit of the Gorgon gas field in the Northern Carnarvon Basin, Australia (Chevron Australia, 2014). Other gas samples from different depth intervals in the same well delivered readings below 20 µg/Sm3. The closest exploration well to GOR-1D (about 2.5 km), North Gorgon-1, has provided abundant core materials that were investigated to detect and understand the distribution of mercury in the rocks. Our research seeks to address some of the significant but remaining geoscientific knowledge gaps on the generation and distribution mechanisms of mercury in rocks, from source to accumulation in the subsurface. In this paper, we provide an assessment of the workflow by examining preliminary analytical results on the detection and quantification of mercury in rocks.
Generator in Situ Inspection
Authors: Kutbi Jehad Fawzi , Alkharboush Abdullah Abdulelah , Georgiou Ioannis 
Published: November 2020

Abstract
Assessing power generators condition utilizing periodic inspection programs has been an established practise in power plants with proven reliability and availability results. However, the continuous efforts to reduce maintenance costs while minimizing the outage periods opened the path towards the development of alternative inspection tools and services that facilitate rapid offline assessment of equipment inspection. The conventional technique of pulling out a generator rotor in order to have an access over the stator is time consuming and requires extensive logistic preparation in addition to high exposure risks. Moreover, utilizing an advanced technology tool for online measurements such as robotic devices for In-Situ inspection provide an economical, fast and low risk alternative solutions. Ras Tanura Producing Department (RTPD) from Saudi Aramco has successfully implemented In-Situ inspections for two power generators at one of its plants. This paper compares the conventional rotor out inspection with In-situ technology techniques that allow inspection and testing while the rotor is still installed whereas will highlight a case study in which In-Situ technology was implemented on RTPD generators.
Petrographic Characterization of Black Shales From Belata Formation, Peninsular Malaysia: Implication for Fracability
Authors: Boateng Esther Owusu , Tsegab Haylay , Borecho Cornelius Bavoh 
Published: November 2020

AbstractSuccessful fracturing processes in shale, during shale gas drilling and production, is an effective way to reduce environmentally and cost risks. Fracability of rocks is highly affected by the rock’s quartz, carbonate and/or clay content. Thus, a fair understanding of shale quartz, carbonate and/or clay content is critical in achieving an effective fracturing process. The objective of this paper is to qualitatively and semi-quantitatively characterise the quartz and clay minerals within the black shales of the Belata Formation. Twenty-two samples were analysed using Scanning electron microscopy (SEM) fitted with energy dispersive x-ray spectroscopy (EDS) and X-ray diffraction (XRD). The result showed slight variations in the concentrations of quartz, which are not too highly deviated from the recorded average. Chlorite and kaolinite are the dominant clay minerals within the black shales. However, the chlorite and kaolinite in Belata black shale show little effect on the fracability of the shales. The estimated brittle index indicated a high quartz/silica composition in the Belata black shales compared to clay minerals. The brittle index further suggested a high fracability with quartz concentration of about 86 %. The range of fracability using the brittle index method is between 0.91 to 0.64, with an average of 0.79, which is considered very high. Thus, these shales could be fractured at various locations through hydraulic fracturing in order to improve their permeability for any flued within the shale. This finding provides new insight into the fracability of the Paleozoic shales in the Peninsular.
Sand Production Management While Increasing Oil Production of a Gravel Packed Well Equipped with RCP Autonomous Inflow Control Devices in a Thin Heavy Oil Reservoir in Offshore China
Authors: Xiong Shuquan , Li Fan , Wei Congda , Luo Donghong , Moradi Mojtaba 
Published: November 2020

Abstract
In the 2018 infill development campaign, improved production was targeted by the operator through the installation of Autonomous Inflow Control Devices (AICDs) in a horizontal well at Offshore China. However, as the well requires gravel packing to manage the sand, the integration of AICD and gravel pack was an issue. The well was expected to intersect heterogeneous formations with varying properties resulting in an uneven reservoir influx toward the wellbore. In addition, water mobility in the reservoir is at least 150 times bigger than oil mobility and a strong aquifer is located near the well. Therefore, similar to the analogue wells completed with gravel packs, oil production from this well was expected to suffer severely from an early water breakthrough in a couple of weeks. These challenges can be mitigated by deploying AICDs that can manage the reservoir fluid influx toward the wellbore and therefore optimise the well performance. AICD, an active flow control device, delivers a variable flow restriction in response to the properties of the fluid and the rate of flow passing through.
An integrated workflow was followed to deliver successfully the AICD application for CNOOC in an offshore heavy oil reservoir with huge uncertainties in remaining oil thickness and water-oil contacts. The well with the horizontal length of 440m was drilled in a thin formation with the oil column of 4.5m on average. The well intersected three different geological layers with different rock properties. The lower well completions comprised gravel pack, sand screens and RCP AICD valves were connected to an ESP pump lifting the fluids to the surface. The well was segmented in 4 compartments and a tailored AICD completions based on the real-time log data from the well was designed to properly restrict the production of unwanted fluid. Through teamwork between the companies, the well was successfully completed with AICD and gravel pack.
The final modelling was performed just in the time span between reaching target depth and running the completion. Over a period of 12 months production, the offset well with no AICD devices encountered water production in the first two weeks and water cut has kept increasing to 88%. However, the AICD well not only has no problem in terms of sand production and has limited water cut to less than 15% but also has successfully delivered 200% increase in total oil production compared to the offset well.
This well is an example that demonstrates the possibility of a successful combination of AICD and gravel packs. AICD completions ensured a balanced contribution from all reservoir sections and limited water production significantly while gravel pack kept the valves safe from impacts of sands.
Impact of Petrophysical and Geomechanical Modelling on Brittleness Index
Authors: Iqbal Omer , Padmanabhan Eswaran 
Published: November 2020

Abstract
Rock fabric and physical properties are known indicator of the fracturing potential of unconventional reservoirs under hydraulic fracturing stimulation. However, very limited study is documented on reservoir cut offs to find fracturing potential. Therfore, systematic workflow adopted to estimate reservoir properties and their relationship with brittleness index. For this purpose, the One-Dimensional Mechanical Earth Model (MEM) and multi-mineral petrophysical models is developed to estimate reservoir properties based on laboratory experiments and well logs. Rock brittleness (BI_T) is estimated using petrophysical properties and elastic properties. The reservoir cut offs determined to classify reservoir into brittle and ductile zones. The correlations indicated that higher concentration of minerals quartz and siderite, and young's modulus (YM_Cali) enhance brittle nature of rock, while higher concentration of organic richness (TOC), porosity (φT), clay contents, and Poisson's ratio enhance ductile nature of rock. The gamma ray log indicated a decreasing trend with an increase in brittleness index. However, there is no significant relationship observed between BI_T, pore pressure and strength/failure parameters except few zones, where BI_T decrease with an increase in pore pressure that is attributed to higher clay minerals in such zones. There is significant decrease in BI_T observed with an increase in fracturing pressure. It implies that brittle rock requires less fracturing pressure to induce hydraulic fractures or open natural fractures. Both shale formations had an organic richness of 3% to 5%, total porosity, φT, of 5% to 20%, and a BI_T of 0.15 to 0.7. It is observed that calibrated values lied between static and dynamic geomechanical properties, which is considered actual reservoir properties. The stress regime is strike slip due to higher magnitude of maximum horizontal stress (σH). Furthermore, the several correlations could be used to classify reservoir into brittle and ductile zones, which would enable the better selection of intervals for fracturing. The model indicated that the Roseneath shale was potentially better than the Murteree shale for stimulation purposes because of its high BI_T, and favourable stress concentration, which is attributed to its high content of quartz and siderite, and relatively less organic matter. However, generally, both shale formations fall in the region of "less brittle". It is recommended that reservoir properties could be computed from top to bottom of interval by integrating core and well logs data due to good agreement between core and well logs which could be used to assess fracturing potential of reservoir. The reservoir cut offs can be used as a proxy to find fracturing potential in unconvemntional reservoirs.
Challenges in Managing Top of Line Corrosion TLC in Multiphase Wet Gas Pipelines
Authors: Ong Hock Guan , Faziana Sagara , Leow Chun Ho , Lim Gek Joo, 
Published: November 2020

Abstract
Top of Line corrosion (TLC) has becoming a growing concern for the oil and gas industry over the past recent decades especially on the offshore subsea high temperature and high pressure (HTHP) pipelines. This paper will present the challenges in managing TLC in multiphase wet gas pipelines. It will also cover the design, execution, appropriate inspection and corrosion monitoring to ensure pipeline integrity meeting the intended design life. There are many corrosions prediction modelling softwares available in the open market. However, once TLC is predicted in a pipeline, there are only few mitigation options which are by material selection, chemical injection, routine operation pigging, batch inhibition, etc. New projects are often considering material selection to mitigate TLC. This approach is rather straight-forward, however, high CAPEX is required. As for existing pipelines in operation with TLC, it must depend on effective chemical control (corrosion inhibitor) that could protect both TLC and BLC (bottom of line corrosion) coupled with continuous corrosion monitoring tools. Routine pigging during operation and more frequent inspection could be required too. To date, there is no common standard in testing the effectiveness of volatile corrosion inhibitor (VCI) in mitigating TLC.
Uncertainty in Reservoir Fluid Fill Prediction and Its Implications on the Business – Case Studies from South East Asia
Authors: Ali Arfan , Jofri Azimah , Mohd Yakup Mohamad Azwan , Zamikhan Norshah , Chung Shao-Jung 
Published: November 2020

Abstract
LWD logs are becoming increasingly reliable for the primary (and often the only) source of downhole log data. The standard and advanced mud logs in conjunction with LWD logs are used to conclude on the reservoir fluid typing (gas, oil, water) in real time. However, there are examples where the mentioned logs can equally misguide the log interpreter.
An incorrect fluid interpretation can result in huge financial implications. There could be decisions associated with laying new pipelines, upgrading surface facilities (separators, compressors) and/or installing new platforms. In addition, the fluid fill would have a direct impact on the company reserves and reporting.
Historically, a number of exploration and development wells were drilled in the SE Asia region where minimal LWD log data was acquired. This data is often considered sufficient for evaluation of reservoir properties. However, for fluid fill, the data was insufficient for various valid reasons and the initial interpretation from the LWD logs could have led one astray. This paper highlights examples where an integrated effort from the subsurface disciplines provided insights into the misbehaviour of the LWD logs and mud log data.
The examples shown in this paper demonstrate that similar looking reservoir log responses could lead to an uncertain fluid fill. In such circumstances, the requirement for additional log data needs to be highlighted at an early stage of the project and should also be reflected in the well and field economics. The uncertainties in the reservoir fluid fill needs to be reflected in the project risk register and in the field development plan (FDP).
This paper provides alarming signals to the log interpreters that extra caution needs to be taken in log data acquisition, processing and interpretation stages. The paper also highlights the importance of integration between subsurface disciplines and the criticality for the log interpreters to be familiar with the depositional environments. It has also been demonstrated that a limited set of log data could equally mean having no information unless additional evidence is available to address the uncertainties.
Well Integrity Analysis and Risk Assessment for Injection Wells in CO2 Flooding
Authors: Zhang Shaohui , Wang Shuai , Lv Yongke , Pan Ruosheng , Geng Xiaoran , Liu Yang , Bai Mingxing 
Published: November 2020

Abstract
Well integrity risk assessment is of great importance to the safe production in CO2 flooding. In this study, the well integrity of injection well in CO2 flooding is analyzed firstly, and the assessment criteria of injection well integrity are put forward. Secondly, the injection well integrity failure risks are analyzed, and the Bow-tie model of well integrity failure is established. By transforming the Bow-tie model into a hierarchical structure, the weights of well integrity influencing factors are obtained with the use of analytic hierarchy process (AHP). Next, the probability and consequences of each single well integrity risk are assessed by using risk matrix method. Finally, the well integrity risk assessment model of injection wells in CO2 flooding is established, and the well integrity risk value and risk level are calculated.
The injection well integrity assessment of CO2 flooding can be divided into three assessment units: wellhead, pipe string and wellbore. The well integrity influencing factors and assessment criteria involve the following fifteen aspects: christmas tree, wellhead seal, tubing, safety valve, packer, casing, cementing, etc. The probability of well integrity risk and the consequence caused by the risk are both considered in the well integrity risk assessment. Based on the risk assessment results, the injection well integrity risk can be divided into four levels: critical risk, high risk, medium risk and low risk. With the use of the above method, the well integrity of certain CO2 injection well in Jilin oilfield of China has been assessed, and the main risk influencing factors and the risk level of well integrity have been determined.
The well integrity analysis and risk assessment of injection wells in this study provide a reliable basis for safety risk decision making and management, and are helpful to reduce the risk of safety accidents in CO2 flooding.