bluuebunny/crossref_metadata_2025_split huggingface dataset:
Machine Learning for Improved Directional Drilling
Authors: Pollock Jacob , Stoecker-Sylvia Zachary , Veedu Vinod , Panchal Neil , Elshahawi Hani 
Published: April 2018

Abstract
Directional drilling is a complex process involving the remote control of tool alignment and force application to a very long drill string subject to variable external forces. Controlling bit tool face orientation while ensuring adequate rate of penetration (ROP) is quite challenging, with aspects that have been described as more art than science. Improving this control helps preserve proper well trajectory and eliminate deviations that require corrective measures and add to well costs.
An artificial intelligence system was developed to learn from the actions of expert directional drillers and the mechanics of drilling simulations. Machine learning algorithms were employed to improve the efficiency of directional drilling: optimized ROP, less tortuous borehole, less personnel on board (POB), and consistency across operations. The system ingests historical and simulation data corresponding to the information used and actions taken by expert directional drillers and uses that data to generate decisions that result in efficient slide drilling.
To create a system for controlling tool face angle and guiding drill bit sliding during directional drilling, relevant historical data from directional drilling operations was gathered. Much of this data was recorded in the drilling logs, which the drilling operator traditionally uses to control drilling parameters. The collected data was then filtered and used to structure and train artificial neural networks and select appropriate hyperparameters. Reinforcement learning methods were used to refine the neural networks trained on historical data. A computational model for drill string physics was used to simulate the mechanics of directional drilling. A successfully trained network was considered one that minimized deviation from planned wellbore trajectory, minimized tortuosity, and maximized ROP.
The neural network developed could replicate the decisions of expert directional drillers within a small error (&lt;3%). Reinforcement learning was then successfully used to improve network performance, particularly for conditions not previously considered.
Since the algorithm has demonstrated competence in the historical and simulated realms, it will be further tested as a real-time advisory system for control of directional drilling operations. The system will be tested in simulation with an expert directional driller before use in a field drilling operation. Ultimately, the algorithm can be directly integrated into drilling operations, enabling fully automated directional drilling.
Digital Transformation and IIoT for Oil and Gas Production
Authors: Berge Jonas 
Published: April 2018

Abstract
Oil and gas producers are challenged with addressing long-term business needs such as: improving health, safety, and environment; extending life of production equipment; increasing reliability to reduce maintenance cost; reducing losses; improving operability to reduce personnel cost; improving productivity; increasing production; and improving governance and regulatory compliance.
To meet these business needs, operating companies are once again investing, now in digital transformation of how their sites are run and maintained. Personnel are digitally enabled. For safety this includes digital distress calls, digital safety checks for situational awareness, digital mustering and geolocating. For reliability, new ways of working include digital inspection and predictive maintenance of more of the equipment, digital collaboration with experts, digital documents on-the-go, and digital integrity management. For operations, new best practices include digital operator rounds including on EOR injection wells and digital logbooks. Also, instead of having people at site; some personnel instead work from a city office or equipment monitoring is outsourced to a service provider as Industrial Internet of Things (IIoT) -based connected services.
This digital transformation is made possible with new technologies such as wireless sensor networks, analytics software, and cloud computing making condition monitoring for a broader scope of process equipment practical, and enable new business models without capital outlay. Wireless, non-intrusive sensors along with readymade software apps enable easy and rapid deployment of these solutions at low cost.
Digital transformation with IIoT and advanced software does not require costly and time-consuming custom programming, but can be accomplished through purpose-built, readymade apps with embedded subject matter expert knowledge. Using platform-agnostic apps, operating companies can use their existing middleware instead of replacing it, and without adding another expensive platform layer, thus protecting existing investment.
Results from digital transformation include: extended life of production equipment to ensure continued service of facilities and operations, maintenance cost reduction, operations cost reduction, improved productivity, and increased production. Further, all departments benefit from the same digital infrastructure, which also enhances integration across disciplines.
Verification and Validation of Computational Modeling in Energy Systems
Authors: Sharma Vinod , Freitas Christopher J. , Kim Minsu , Bell Jennifer 
Published: April 2018

AbstractThis paper presents the latest initiative by ASME's Codes and Standards Verification and Validation (V & V) Committee. A new subcommittee for the Verification and Validation of Computational Modeling in Energy Systems, ASME V&V60 was formed in 2017. The V&V 60 subcommittee's stated mission is to develop guidance to assist end users of computational methods and simulations with assessing the inherent limitations introduced by methodologies and assumptions used during verification and validation, and uncertainty quantification.To achieve this goal, the subcommittee seeks to better understand and examine gaps in existing industry guidance related to the verification and validation of computational models and simulation-based solutions. This paper highlights potential gaps in modeling and simulations of High Pressure High Temperature (HPHT) systems and presents opportunities for meeting the challenges of practices and procedures surrounding the assessments and quantification of the accuracy and credibility of such computational models and simulations. The results from this paper suggest that the benefits of insight developed by the existing groups as well as a common generalized framework increase the level of transparency in communication regarding verification and validation and uncertainty quantification and will prove useful to HPHT system users and practitioners.
Asphaltene Inhibitor Testing: Comparison Between a High Pressure Live-Fluid Deposition and Ambient Pressure Dead-Oil Asphaltene Stability Method
Authors: Jennings David W. , Chao Kung-Po , Kim Jihye 
Published: April 2018

AbstractThe goal of this study was to provide in-sight regarding use of laboratory asphaltene inhibitor testing to help guide expectations for inhibitor field performance. Specifically, this paper compares results from asphaltene inhibitor testing using two laboratory methods: (1) dead-oil analytical centrifuge stability analysis for asphaltenes method and (2) high-pressure live-fluid test that includes deposition evaluation. The analytical centrifuge method was developed as a simple laboratory test with test conditions pushed closer to field conditions than previous stability methods. As live-fluids are often not available, if data from the analytical centrifuge method can be used to help form better, more reliable field expectations, it would benefit operators in making field development plans and optimizing field operations.The high-pressure testing in this study was performed with a Solids Detection System (SDS) apparatus designed to measure asphaltene onset pressures (AOPs) of live-crude oils through monitoring near infrared laser transmittance but also run with an augmented procedure to quantify the amount of asphaltenes deposited during depressurization. Although not replicating the exact higher shear flow environment in many wells, the live-fluid SDS testing represented the closest test possible to field conditions available with our current laboratory capabilities. As such, in the absence of complete field data, it represented our next best alternative to mimic field data for use in comparison against the analytical centrifuge method.Included in this paper are results with four different asphaltene inhibitors. The high-pressure test results show the inhibitors shifting measured AOPs and reducing asphaltene deposit weights. The analytical centrifuge test results are shown over a range of crude oil to destabilizing solvent ratios at different temperatures. One example comparing analytical centrifuge testing to a field data set is also presented. Results from the study indicated that the dead-oil analytical centrifuge stability testing should be performed at equivalent temperatures and with relatively high crude oil to destabilizing solvent ratios (~30 % crude oil or greater) to achieve similar results to high-pressure live-fluid testing. When performing dead-oil testing at lower temperatures and lower crude oil to destabilizing solvent ratios, the ability of the inhibitors to increase asphaltene stability were generally significantly greater than that achieved for reducing asphaltene deposition within the SDS apparatus. Testing at lower temperatures and lower crude oil to destabilizing solvent ratios, however, did indicate trends for determining relative asphaltene inhibitor performance.
Understanding Slope Instability on the East Nile Delta – A Case Study
Authors: Harrison D. P. , Smith C. A. , Brown J. , Thomas S. 
Published: April 2018

Abstract
Various field operators and developers in the Eastern Mediterranean are reliant on the development of export pipeline routes that ascend the eastern portion of the Nile submarine delta. Evidence of numerous complex slope instability events and other geohazard processes across the submarine delta front mean that risk mitigation in this region needs careful considerationprior to installation.
This paper focuses on integrated site characterisation including detailed sedimentological logging and two-dimensional (2D) geomechanical modelling of slope stability for a recent project on the eastern portion of the Nile submarine delta, with focus on four distinct palaeolandslide features on the delta slope region.
Based on the review and integration of geophysical, geological and geotechnical datasets, all four palaeolandslides appear to have failed in a translational manner along a shear surface at approximately 6 m below seafloor. The shear surface coincides with the presence of a strong impedance reflector mapped in sub-bottom profiler data. This reflectorcorrelates well with a sampled occurrence of an approximately 1 m-thick silty sand bed (sedimentological FaciesN2), bounded above and below by extremely low to very low strength organic clay sediments (Facies N1).
Eleven radiocarbon tests were performed in the palaeolandslide evacuation surfaces and the resultant mass transport deposits. These test resultsindicate that the four events occurred between approximately 500 years and 1600 years before present, with a best estimate age of 800 years before present (i.e. 12th century AD). The 1068 AD Gulf of Aqaba earthquake or the 1202 AD Lebanon earthquake are possible triggers for the palaeolandslides and relict seafloor morphology.
Deterministic 2D slope stability analyses were performed along four slope profiles to output values for factor of safety (FOS) against slope failure. The analyses modelled present-day slope stability, and a reconstructed (pre-failure) seafloor to further understand the characteristics of the four observed palaeolandslides. The modelling showed that the slopes are stable under presentday conditions, even under abnormal level event (ALE) seismic loading. The modelling also showed how faulting plays a key part in overall slope stability: some faults buttress upslope sediments and thus increase the slope FOS, whereas in other casesthe faults steepen the overall slope and result in a lower slope FOS.
The key uncertainty in the slope stability modelling is the poorly understood lateral geotechnical variability of Facies N2, which variesfrom silty fine sand to sandy silt, and the complex and currently uncharacterised behaviour of Facies N2 under cyclic seismic loading. It is possible that the variable fines content governs whether Facies N2 behaves in a drained or undrained mannerduring seismic loading, and how much strength degradation (i.e. liquefaction) may occur. All these factors could contribute to the stability of the slope during earthquake loading.
Integrated Design Computational Model Applied to O&G Offshore Field Development
Authors: Basilio Leandro , Noronha Celso , Passos Matheus , Calaza Débora , da Nova Anderson L. , Daly Roland 
Published: April 2018

The development of Offshore Oil and Gas Production Systems demands a multi-disciplinary team to investigate a multitude of design uncertainties extending from the reservoir to the production facilities, and commodity product sales. The generation of concept options usually follows a linear and technically oriented process, where each specialized discipline determines the technical requirements and boundary conditions to the next discipline. The process may be repeated as new information becomes available, and some design uncertainties are progressively reduced, as most of key design parameters are stochastic and non-deterministic. This methodology may vary between Oil Companies regarding the logical sequence, accuracy range and concept coverage, but is strongly driven by the Company's culture and by industrial capacity available in each region.
Due to limitations of time and availability of costly multi-disciplinary specialized resources, the generation of field development concept options is often focused primarily on generating concepts considering the highest technological maturity and the lowest Capital Expenditure (CAPEX). Following this approach, the generation of ranked concept options with a focus on the Net Present Value (NPV) is usually performed on a limited workable number of options. The NPV check is a project finance tool to assess and rank the concepts generated at the end of the engineering process. Further design phase iterations tend towards these same options, resulting in either slow and incremental improvement, or worse through propagation of the initial uncertainties, inadequate facilities design and reduced project reward.
On a process digitization perspective, an integrated and automated design computational model enables specialized disciplines to probe and visualize the concept search space, including lower maturity concepts with potentially higher NPV reward. Automation accelerates the design process, allowing the necessary time to focus efforts either on maturing concepts from an earlier phase, or on minimizing uncertainty in propagation, by reconsidering full concept search space in subsequent design phase iterations, ensuring more adequate facilities design.
The objective of this paper is to present the results of an integrated design approach applying a computationally developed model, focusing on automating the process of offshore full field concept generation and ranking during early project phases to fetch optimized designs. Based on the use of the computational model, a case study was developed, highlighting the sensitivity analysis of CAPEX, OPEX (Operational Expenditures) and NPV, by varying specific parameters in typical subsea production system architectures. The hypothetical scenario is representative of the ultra-deepwater environment in the Brazilian Pre-Salt.
Completion Fluids-Induced Formation Damage in High Temperature Gas Wells: Causes and Mitigation
Authors: Hamzaoui Bilel , Moajil Abdullah M. Al , Yami Ibrahim , Hazzazi Hassan 
Published: April 2018

Abstract
The use of high-density brines has been always considered as afactor in minimizing formation damage during completion operations. However, these brines can be potentially damaging if it is not well designed. Under high temperature conditions, precipitations may occurcausing a rapid loss innear wellbore permeability. A laboratory study was directed to evaluate the potential of formation damage from high-density brines at high temperature and pressure conditions.Corefloodtests were conducted to assess unfavorable fluid/rock interactions between completion fluidsand Barea sandstone core. The effects of salt precipitation on the completion fluid compositionwas evaluated. Effluent ion analysis was conducted to determine the factors responsible for the observed permeability impairment. Examination of the mineralogy of the sandstone core plugs and the precipitated solids was performed using XRD, ESEM and EDS analysis. The obtained results confirmed that halite and calcium carbonateprecipitated at 300°F. The potential of formation damage caused by high-density brine increases at high pH. Reduction of permeability of 12 to 21%were observed during the injectionof completion fluids with pH&gt;11.
Experience with Interface Shear Box Testing for Axial Pipe-Soil Interaction Assessment on Soft Clay
Authors: Westgate Z. J. , White D. J. , Savazzi M. 
Published: April 2018

AbstractThis paper presents experience and best practice for a new geotechnical laboratory test protocol – the low stress interface shear box (ISB) test – for determining soil properties relevant to pipeline-seabed friction. The paper is underpinned by a major database (&gt;200 tests) that demonstrates the protocol and shows general variations in the key parameters that may be useful for early design purposes. By accurately quantifying shear resistance along the pipe-soil interface under low normal stresses imposed by subsea pipelines, ISB tests allow design ranges in axial friction to be narrowed and tailored to specific pipeline conditions. These improved geotechnical inputs to pipe-soil interaction can alleviate unnecessary axial expansion, walking or buckling mitigation, unlocking cost savings otherwise unavailable without accurate geotechnical parameter characterization.A large database is presented of recent industry experience with low normal stress interface shear testing using a modified direct shear box device. This device, while still considered novel, is emerging as the new industry standard for axial pipe-soil interaction testing, gaining wider adoption than the tilt table and torsional shear devices. The test database comprises several soft clays from various deep water hydrocarbon-producing geographical regions, and several types of pipeline coatings.The database populates a theoretical framework for axial pipe-soil interaction with new data, illustrating general trends for key parameters such as shearing duration, normal stress, interface roughness, and changing pipeline weight, each of which is shown to vary the axial resistance by a factor of two or more. The shear resistance can also change by a factor of two or more due to consolidation or swelling during and between individual cycles of movement, associated with pipeline operations. This database and the populated theoretical framework can guide pipeline and geotechnical engineering by providing a basis for initial estimates of axial friction, and an approach for improving these estimates via focused site-specific testing.The new approach has been applied through &gt;200 ISB tests for &gt;12 oil and gas projects conducted in the laboratories of Fugro and the University of Western Australia, to deliver better pipe-soil interaction data than is available via other means. This paper shares this experience to support new projects in two ways: Firstly, the large high quality database provides a significantly improved basis for estimates of geotechnical soil properties for subsea pipeline design where site-specific data is not yet available. Secondly, we provide guidance on the planning, execution and interpretation of low stress interface shear tests, to allow best practices to be adopted more widely across industry.
Bridging the Gap between Benchtop Testing and Field Conditions in Flow Assurance Studies
Authors: Sum A. K. , Melchuna A. , Sa J. , Zhang X. , Morales R. , Machado A. , Herri J. M. , Cameirao A. 
Published: April 2018

Objectives/Scope: The goal for any flow assurance study is to capture the thermo-hydraulic conditions in flowlines without having large scale flow facilities that closely represent the field. As such, benchtop testing must as best as possible reproduce the shear and dispersion of the phases encountered in flowlines. With the increasing need of laboratory testing for solid precipitation and production chemicals, coupled with reduced CAPEX and OPEX, it is critically important to have a robust benchtop testing system that give reliable and transferable data that can be used for field applications.
Methods, Procedures, Process: While many benchtop tools are widespread (e.g., autoclave cells, rocking cells, cold fingers) and are used extensively by industry, there is still a significant gap in bridging the results from these lab scale devices to field conditions. One of the major concerns with the current testing rigs is the inability to reproduce the shear AND phases dispersion that are present in pipe flow and are a consequence of the multiphase flow conditions. To bridge the gap between benchtop testing and filed conditions, we demonstrate how an innovative testing rig, called rock-flow cell, can be used to capture flow assurance issues (e.g., hydrate, wax, asphaltene, scale, corrosion, sand transport) under pseudo-flow conditions.
Results, Observations, Conclusions: This system is superior to existing testing systems due to its ability to reproduce flow conditions that are typically found in actual production flowlines, such as, stratified flow, stratified wavy flow, and slug flow. In addition, the system is compact and inexpensive to build and operate, unlike flow loop systems, which are currently the only reliable testing rig with proper flow conditions.
Novel/Additive Information: The rock-flow cell can be easily used for testing of chemicals (e.g., anti-agglomerants and kinetic inhibitors) for hydrate management, for assessing wax deposition of crude oils, for testing of scale precipitation, and for testing of sand transport; each of these flow assurance issues can be tested separated or combined as desired. Moreover, the rock-flow cell is also a suitable setup for testing of steady-state and transient (shut-in/restart) conditions typically encountered in flow assurance with proper account of liquid loading, water cut, and GOR.