bluuebunny/crossref_metadata_2025 huggingface dataset:
Machine Learning for Improved Directional Drilling
Authors: Pollock Jacob , Stoecker-Sylvia Zachary , Veedu Vinod , Panchal Neil , Elshahawi Hani
Published: April 2018

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 (<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

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

This 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

The 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

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

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>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

This 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 (>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 >200 ISB tests for >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.
Generalized Framework to Simulate Gravel Packing in Wellbore Completions
Authors: Mimouna A. , Verma A. , Guddati M. N.
Published: April 2018

A generalized numerical framework to simulate gravel packing in typical wellbore completions is proposed. Given the well, downhole tool string configuration, fluid and gravel properties, and pump schedule, the simulator predicts the time evolution of the pressure, fluid and gravel fluxes and concentrations along the wellbore. The time evolution of the gravel concentration provides the packing pattern and the end of job pack state. This is achieved by solving the one dimensional (1D), mass and momentum conservation equations for the fluid and gravel in a staggered manner. A 1D, piecewise linear, finite element method is used to discretize the governing equations along the wellbore. The architecture of the framework is general enough to handle typical wellbore completions and gravel packing tool string configurations. This is achieved by modeling wellbore components as generalized forms of nodes, linear elements (with or without cross flow), and sources/sinks. This description allows different gravel packing completion configurations to be modeled generally without resorting to a separate and explicit model of each type of tool. At each time step, the whole system is assembled, and the nonlinear system is solved using robust and performant non-linear and sparse linear solvers. The software heavily leverages object-oriented design and high-performance computing practices. Finally, the simulator is used to show the efficacy of the Alternate path technology shunt tubes in achieving complete gravel pack in a long horizontal well. This is shown by simulating cases where significant leak-off would result in a premature bridge in the absence of the shunt tubes. This generalized approach should allow for a flexible extension to simulating gravel packing using other wellbore completions such as washpipe diverter valves, screens with inflow control devices.
Comparing Levelized Cost of Energy for a 200 MW Floating Wind Farm using Vertical and Horizontal Axis Turbines in the Northeast U.S.A.
Authors: Shelley Steffen. A. , Boo S. Y. , Kim D. , Luyties William H.
Published: April 2018

The technology to engineer, fabricate and install offshore floating wind turbine exists and is feasible for all components. Applying lessons learned from offshore oil and gas projects with respect to engineering execution options, competitive supply and reduction in life cycle costs makes offshore floating wind a commercially viable energy supply in regions with relatively high electricity prices or in regions that have other geographical or resource constraints to bringing additional energy supply on-line.

However, while horizontal wind turbine (HAWT) technology is developing rapidly and driving down cost, it may be possible to further drive down offshore floating wind costs by choosing a vertical axis wind turbine (VAWT) technology. VL Offshore has developed a cost effective 5 MW floating foundation, Y-Wind semi for HAWT. In this study, the LCoE (Levelized Cost of Energy) of the Y-Wind semi with 5 MW HAWT is compared against the same foundation type with a 5 MW VAWT. For the present work, a 200 MW wind farm, located about 10km off shore the Northeast U.S. at a water depth of 100m is selected. This water depth exceeds the current commercial limits for fixed foundations for offshore wind. LCoE is estimated using the tool developed by NREL, considering all the cost parameters of foundation and mooring CAPEX, installation, operation and maintenances, in-field and export power cables, capacity factors, turbine layouts, substation, discount rate, cost escalation rate, current electricity price and design life. The LCoE results indicate that a 5 MW VAWT foundation will be more commercially viable than a comparable 5 MW HAWT foundation. The LCoE values compare favorably to the LCoE values for most electricity prices in the Northeast states.
Offshore Wind Sediment Stability Evaluation Framework
Authors: Jones Craig , McWilliams Sam , Engelmann Georg , Thurlow Aimee , Roberts Jesse
Published: April 2018

Developing sound methods to evaluate risk of seabed mobility and alteration of sediment transport patterns in the near-shore coastal regions due to the presence of Offshore Wind (OW) infrastructure is critical to project planning, permitting, and operations. OW systems may include seafloor foundations, cabling, floating structures with gravity anchors, or a combination of several of these systems. Installation of these structures may affect the integrity of the sediment bed, thus affecting seabed dynamics and stability. It is therefore necessary to evaluate hydrodynamics and seabed dynamics and the effects of OW subsea foundations and cables on sediment transport.

A methodology is presented here to map a site's sediment (seabed) stability and can in turn support the evaluation of the potential for these processes to affect OW deployments and the local ecology. Sediment stability risk maps are developed for a site offshore of Central Oregon. A combination of geophysical site characterization, metocean analysis, and numerical modeling is used to develop a quantitative assessment of local scour and overall seabed stability. The findings generally show the presence of structures reduces the sediment transport in the lee area of the array by altering current and wave fields. The results illustrate how the overall regional patterns of currents and waves influence local scour near pilings and cables.
Cold Finger Benchmarking Study for Paraffin Inhibitor Selection
Authors: Peng Yun , Golchha Abhishek , Broze George
Published: April 2018

Selection of effective paraffin inhibitors is critical for managing wax deposition risks in existing assets and for enabling potential CAPEX savings in new developments. Cold finger (CF) testing is a common method used for screening paraffin inhibitors (PI), but there are various kinds of in-house-developed and commercial CF equipment used throughout the industry. Additionally, there is no standard PI testing protocol. In some cases, there are inconsistent results between laboratories when evaluating PI performance.

To better understand the root causes of PI testing discrepancies and investigate the impact of key parameters on test results, a benchmarking study using both in-house and commercial CF equipment was conducted. Additionally, Shell (the Company) and BHGE (the Vendor) conducted a detailed joint exercise to understand and benchmark the commercial CF equipment used in both of their laboratories. Finally, the laboratory results were compared against field performance through a case study for a Gulf of Mexico operating asset.

PI performance was found to depend upon the particular oil as well as testing conditions, test procedures, and equipment. Good agreement in PI performance was observed between the two laboratories using the same testing conditions with the same CF equipment and equipment specifications, under similar procedures for a given crude oil. In this study, it was observed that shear and CF roughness can play a significant role on PI test results. Rougher CFs tend to make certain PIs less effective under low shear conditions. Hence, a PI chosen based on a specific set of conditions, equipment, and procedures might appreciably differ in its performance if any of the above parameters are changed. Therefore, selecting appropriate testing parameters is important to identify and qualify an effective PI suitable for a specific field application.

This work makes it possible to improve standardization between laboratories and helps to better understand the limitations, uncertainties, and suitability of CF tests for predicting PI performance in the field. It also provides insights on how to design tests and equipment to better represent PI field performance.
Looking Deep Beyond the Wellbore: Mid-Field Hydraulic Fracture Diagnostic
Authors: Stolyarov Sergey , Cazeneuve Eduardo , Sabaa Karim , Kotov Sergey
Published: April 2018

Understanding the stimulated reservoir volume and mapping hydraulic fractures away from the wellbore remains one of the biggest challenges in unconventional plays development. Currently available production logging and tracer technologies have shallow depths of investigation—only a few inches beyond the wellbore. Far-field microseismic mapping offers an image of micro-earthquakes that are caused by shear slippage during a hydraulic fracture treatment. Although the location of the associated microseismic events enables spatial mapping of the stimulated rock volume, particularly its orientation and growth characteristics, the microseismic deformation does not provide direct information about hydraulic fracture effectiveness.

The latest improvement in deep shear wave imaging processing (DSWI) provides a visual representation of geological features up to 100 feet from the wellbore. DSWI nicely fills the resolution space between conventional near-wellbore diagnostic technology and far-field microseismic mapping. The shear wave azimuthal sensitivity enables estimation of the hydraulic fracture geometry away from the wellbore. It also provides direct visualization of the actual reservoir volume that has been stimulated in the mid-field region with the extension of hundreds feet from the wellbore.

This paper presents a case study of the post-hydraulic fracture diagnostic in a shale reservoir using deep shear wave imaging technology. The information derived from the pre- and post-hydraulic fracture imaging enables a better understanding of the stimulation treatment effectiveness and fracture propagation away from the wellbore. This imaging can also be used for the completion optimization of the new drilled wells, as well as for the identification of previously unstimulated zones for re-fracturing.

The accuracy and credibility of the DSWI hydraulic fracture diagnostic was confirmed by running a cross-dipole acoustic log in a well with high water cut. Radioactive material present in the produced water caused up to 150 API increase in the gamma ray activity due to precipitation associated with the pressure drop in a hydraulic fracture. The study showed that the lateral intervals with a substantial increase in gamma ray activity matched the hydraulic fracture locations identified by the DSWI process.

These case histories highlight the value of the information obtained from the DSWI to enhance the fracture optimization, to improve ultimate recovery, and to reduce overall operational cost.
Quick Estimating Pipeline Walking Anchor Force - It is Much Less Than the Full-Length Mobilization
Authors: Carneiro Daniel
Published: April 2018

An analytical methodology for estimating walking anchor force is presented. Currently, anchor force calculation requires substantial FEA which is not compatible with early phase design schedules. At such stage, anchor force is typically assumed to correspond to full pipeline length mobilization. This is very conservative, in many cases by an order of magnitude, and can hence mislead important early design decisions.

The force on a walking anchor increases with cycles of pipeline operation, eventually approaching an asymptotic limit value, often of the order of 1 MN. Robustly identifying this limit requires extensive FEA, incorporating detailed bathymetry, simulating tens to hundreds of operational cycles, and covering numerous sensitivities to input parameters, which often yield counterintuitive results. The proposed analytical method does not require repetitive calculations. It derives the limit value straightforwardly, based on fundamental principles, and has been implemented in a spreadsheet.

Providing immediate results, it permits quick assessment of the effects of many parameters such as soil resistance, operating loads, as well as the number and location of global buckles, on the system's ultimate response. Results are shown to agree very well with extensive FEA results, and yield required anchor loads which are much lower than the full-length mobilization approach. Having such results early in design allows better informed decisions, for example making end anchors viable, and thus avoiding much more complicated mid-line ones. Pipeline ends can be anchored by either adopting piled foundations or by connecting them to a separate anchor pile. Mid-line anchors mobilize lower loads, however in most cases require additional attachments or structures, which bring additional concerns in terms of through-life integrity, and installation cost, safety and schedule risks.

The proposed tool permits proper estimation of anchor loads at early design stages, and can make otherwise too expensive concepts viable. Its capability of quickly assessing multiple sensitivity cases also allows early identification of the relevant aspects to be tackled later in the project, in a value engineering approach.
Insight into Pipeline On-bottom Stability, DNV RP F109 and DNVGL RP 114
Authors: Thusyanthan N. I. , Jegandan S.
Published: April 2018

On-bottom stability of pipeline is a one of the key factors that affects the design and installation methodology of subsea pipelines. With ever increasing demand for energy, the need for new pipelines in harsher seabed conditions is on the rise and hence accurate on-bottom stability assessment of pipelines plays a vital role in cost effective pipeline design and ensures the long-term integrity pipelines. The recommended guideline DNV RP F109, "On-bottom stability of assessment of submarine pipelines" and American Gas Association/Pipeline Research Council International (AGA/PRCI) stability methodology are the most commonly followed guidelines in the industry for the on-bottom stability assessment. This paper provides insight into on bottom stability assessment, effect of soil classification system on on-bottom stability assessments and compares results from DNV RP F109 and AGA/PRCI methods. It is often assumed that the seabed is stable while undertaking pipeline on-bottom stability of pipelines. However, this may not be case due to seabed mobility and wave induced liquefaction, especially in sandy seabeds. Therefore, insight into how to evaluate the seabed mobility and wave induced seabed liquefaction is provided in this paper. Results from parametric study of on-bottom stability of a typical pipeline are presented to highlight the key influence of seabed classification on the on-bottom stability assessment results. Seabed mobility and wave induced liquefactioin results are presented in graphical form such that they can be assessed quickly for Front End Engineering Designs (FEED). Comparison of soil models from newly released DNVGL RP F114 with that in DNV RP F109 is also presented and discussed. The results presented in this paper are a vital source of information for all pipeline design engineers.
Optimized Mixed Refrigerant System Using Advanced Vessel Economizer
Authors: Kim Taeyun , Park Hyunki , Kim Chulwoo , Oh Youngseok , Lee Donghun , Kim Seunghyuk , Min Joonho
Published: April 2018

The purpose of this paper is to demonstrate the following features of the Advanced Vessel Economizer, derived from the principle of the Advanced Vessel Economizer and comparison with the Conventional Vessel Economizer. Equipment which needs a host refrigerant process.Maintains the characteristics of the host process.Improves efficiency of host process.Is able to be applied not only to marine, onshore and offshore, but also to industrial refrigerant processes and household appliances.Is able to be applied not only to the plant to be built in the future, but also to the plant that is currently being operated thanks to the simple configuration of this technology.

Two case studies were conducted for this purpose:

The first case study is a comparison of the newly developed process with the commercialized process. Since the Advanced Vessel Economizer is not a process but equipment, it requires a process to be a host therefore the one of commercialized SMR process [3] has been selected and the Advanced Vessel Economizer is applied for optimization. As a result of this, the newly developed process shows that it not only improves the performance of the host process [3] by about 7.4%, but also maintains the properties of the host process.

The second case study demonstrates efficiency of the newly developed process by comparing the commercialized BOG reliquefaction processes and the offshore liquefaction processes (see table below) to show the possibility of commercialization.

It is concluded that the BOG SMR process [2] was the most efficient among BOG reliquefaction processes and LNG SMR-II process [3] was the most efficient in offshore liquefaction processes. However, the newly developed process showed about 7% higher efficiency than these two processes. Also, thanks to the small number of equipment which is similar to LNG SMR process [3] and BOG SMR process [2], a low capital cost, a compact configuration in terms of layout and simple operating and control can be expected. That is, the newly developed refrigerant system using Advanced Vessel Economizer can be commercially attractive.

Through two case studies, the features of the Advanced Vessel Economizer described above are demonstrated as well as the performance of the newly developed process using the Advanced Vessel Economizer.
Mooring Chain Wear Experiments and Findings
Authors: Jayasinghe Kanishka , Potts Andrew , Kilner Andrew , Melchers Rob
Published: April 2018

Whilst mooring chain design practice has traditionally considered wear and corrosion together under a single allowance for material loss, the two phenomena are influenced by different factors whereby they may act synergistically to accelerate degradation rates or act completely independently. As chain wear has been attributed to both the acceleration of corrosion-related degradation and the cause of chain failures and early mooring repairs by itself, it was investigated as part of the SCORCH JIP.

An extensive literature review and meta-analysis of wear research was carried out in order to determine a framework for assessing the wear of mooring chains. The literature review found that the phenomenon of wear in general and mooring chain wear in particularly was not well understood, with little agreement as to a general analytical model for wear prediction. The particular wear regimes under which mooring chain wear occurs was identified and a critical analysis of available data on mooring chain wear was carried out where it was determined that experimental conditions were likely to have been outside of the bounds of validity for what would be experienced in the field. A generic formulation for chain wear was presented, where the amount of wear is proportional to the work done at the interlink contact due to the relative sliding of the chain links.

Supplementary to the literature review, a series of wear tests of full-scale mooring chain links were carried out under varying load conditions for different grades of chain. These tests were used to determine empirical coefficients for the prediction of chain wear. A model for wear prediction was presented based on the position of the chain in the mooring line, the tension in the line and the relative motion of the chain links.

The evolution of the contact surface between chain links was modelled using 3D geometries of idealized chain links in order to determine a relationship between the volume of worn metallic area and the depth of wear, which can be more easily measured in-service.
Repeat AUV MBES Surveys for Deepwater Seafloor Change Detection
Authors: Haneberg William C.
Published: April 2018

Repeated multibeam echosounder (MBES) surveys conducted using autonomous underwater vehicles (AUVs) have the potential to document the magnitude and areal extent of seafloor changes associated with both human and natural causes, including seafloor subsidence, fault or slope movements, fluid expulsion, volcanism, and biological activity. If AUV survey design does not consider the practical limits to change detection and include best practices to minimize noise, however, the results may be ambiguous or even useless. Using a series of simulations combining real bathymetric digital elevation models (DEMs) with idealized perturbations representing seafloor subsidence and faulting, this paper examines limits to seafloor change detection using repeat MBES surveys in terms of the standard deviation of the noise in the surveys. In general, the magnitude of vertical change between surveys should be greater than the standard deviation of the noise (also known as uncertainty or error) in each of the surveys compared in order reliably recognize seafloor change. Filtering can suppress noise and recover the real seafloor change, possibly even if the magnitude of the change is less than the standard deviation of the noise. Based upon the simulations in this paper, filtering is more effective for broad features like subsidence bowls than localized features like faults even if the amount of vertical change is identical. A probabilistic threshold based upon the standard deviation of the noise appears to be less useful than filtering in the simulations undertaken for this paper.
A New Practical Water Injection System in Offshore Fields
Authors: Martinez V. , Ascencio F.
Published: April 2018

This work proposes a new system to perform the water injection for pressure maintenance in offshore fields without the need of installing additional facilities for water treatment. The main objective is to directly communicate an active aquifer with the depleted reservoir through existing vertical or deviated wells, of which trajectories enable the completion in both formations. It takes advantage of the pressure support from the aquifer, thus, avoiding the requirement of additional infrastructure. It is an artificial crossflow between two formations, where the water-injection rates will basically depend on two parameters: the formations flow capacity and the pressure difference between the aquifer and the reservoir. The injectivity indexes of the communicating wells can be determined using a combination of pressure drop equations. Finally, an example of possible application in an offshore field is presented; the analysis indicates that its implementation would carry many benefits in a short period of time.
Field Life Extension and Integrity Management in Campos Basin
Authors: Müller D. T. , Nogueira D. C. , Gonzalez E. C. , Nicolosi E R. , Dutra E. S. S. , Campello G. C. , Muniz T. J. C. , Capella M. M.
Published: April 2018

The integrity management of Campos Basin platforms, subsea systems and wells and its risks control due to ageing process are key priorities for HSE. With this awareness, Petrobras is implementing initiatives to improve the production viability of mature fields and to extend the life of current facilities.

This paper will describe some of these initiatives, which include: carrying out platforms maintenance campaigns using UMS (Units for Maintenance and Safety); subsea facilities and platforms life extension studies; well integrity evaluations; compliance with the new regulatory aspects of ANP (Brazilian National Petroleum, Gas and Biofuels Agency); development of business decision-making methodology based on break-even point; implementation of decommissioning projects of non-operating structures that have reached their technical and economic limit. As an example, it will be presented the extension of the concession contracts for the Marlim and Voador fields until 2052, which were originally due to expire in 2025.