bluuebunny/crossref_metadata_2025 huggingface dataset:
Cyclic p-y Curves in Clays for Offshore Structures
Authors: Zhang Youhu , Andersen Knut H , Jeanjean Philippe
Published: April 2019

Pile foundations supporting offshore structures are typically subjected to lateral cyclic loading. In design, the pile response under peak design load is generally estimated using a beam-column model where soil-structure interaction is simulated with a series of uncoupled non-linearly force-displacement springs (p-y curves) along the depth of the pile. In clay, the current state-of-practice uses p-y springs derived from some limited field pile tests carried out in the 1950s at Sabine River site, where only one soil type was tested and the cyclic load history applied in the tests was intended to provide a lower bound estimate of soil reaction under cyclic loading. In this study, comprehensive analyses are carried out to investigate the pile responses under two representative storm load histories (Gulf of Mexico (GoM) hurricannes and North Sea winter storms), in three different soil conditions (Gulf of Mexico clays, North Sea soft clays and North Sea stiff clays) for two types of structures (jackets and spars). The analyses use a numerical procedure that was developed in recent years and is fundamentally based on soil response measured at element level. From the parametric analyses, cyclic p-y curves are recommended for the design of jackets under GoM and North Sea metocean and soil conditions, and for spar anchors in GoM conditions.
Digitalization and Data Democratization in Offshore Drilling
Authors: Yoder Randy Thomas
Published: April 2019

Digitalization involves the use of digital technologies to improve, or create new, business processes that drive operational efficiencies. Moreover, the concept of data democratization allows the fruition of digitalization; the data sources, data processes, and content, to be leveraged and scaled enterprise wide.

Visualization and self-service analytics platforms allow all levels of business more autonomous ability to analyze and communicate data driven solutions to decision makers and those responsible for implementation.

Driving toward digital transformation, modern digitalization strategies include aspects of data democratization. Data content is shared across the enterprise. Entire organizations have access to the raw data sources and data processes in addition to the produced report or visualization itself. This data democratization is the key to reducing replicated work, removing silos, and developing a social network for leveraging the hard data efforts of one business entity for efficient use in another.

Results, observations, and conclusions, as well as solution specifics, will be presented with a series of use cases within the offshore drilling industry.

These use cases are:

Digitalization of Rig Activity Performance KPIs using data enablement platforms to build the first version of an interactive Performance Dashboard. Democratized results of this exercise allowed user defined performance measures to be developed specific to proposed customer well specs. These performance measures were quickly analyzed and presented in contract tenders. Digitalizing downtime events and maintenance history reports using data enabling visualization and self-service analytics platforms for flexible and efficient analysis identifying Reliability Improvement Initiatives and Maintenance Optimization opportunities in support of a company's Failure Reporting, Analysis, and Corrective Action System processes. Digitalizing the Cost of Quality KPIs for use in Vendor Scorecards using easily filterable reports and automated distribution of daily updates.
Single Independent Riser: A Cost Efficient Ultra-Deep Water Riser
Authors: Lirola François , Revault Eric , Lunven Jean-François
Published: April 2019

Hydrocarbon fields discovered in ever deeper waters and uncertainties regarding oil prices are driving the need for cost efficient riser concepts tailored for ultra-deep waters. The Single Independent Riser (SIR) is an innovative hybrid riser configuration optimized for Ultra-Deep water field development. This paper will provide a general overview of the SIR with a specific focus on its installation method and the associated tools that were developed.

The SIR is based on a hybrid solution composed, from bottom-up, of a rigid part vertically tensioned by means of distributed or continuous buoyancy and a flexible jumper. This configuration features improved dynamic behavior for the rigid riser section under fatigue and extreme environmental conditions thanks to its compliant shape. The configuration of the flexible jumper ensures displacements of the rigid riser section are significantly decreased compared to that of an SHR. In addition, its design makes it adapted to any water depth beyond 1000 m. The SIR is also inherently safer as it is less sensitive to buoyancy loss than a riser tensioned by mean of a buoyancy tank. This design is highly versatile and can easily be staggered to comply with design constraints, congested lay out and installation scheme.

The relevancy of the SIR has been assessed on the basis of several case studies derived from actual projects as well as on-coming prospects. The considered cases include a wide range of environments such as West of Africa, East of Africa, Brazil and riser types, both for pipe in pipe and single pipe arrangements, in order to confirm the suitability of the design. Extreme, wave fatigue, VIV fatigue, interference analyses were conducted through these assessments. In parallel, a dedicated installation method was developed to address the specificities of the design and to cover both dry and wet flexible jumper connections. In the frame of this study, specific installation tools were designed to reduce the need for offshore assets during installation.

This paper will first provide a general overview of the SIR, illustrating the arrangement of the various components and providing outcomes of engineering studies confirming the relevancy of the design. A second part will focus on its installation method and the associated tools that were developed.
Innovation and Practice of Geological Modeling Techniques in Complex Clastic Reservoir of Bohai Bay Offshore Oilfield
Authors: Ye Xiaoming , Huo Chunliang , Wang Pengfei , Gao Zhennan , Xu Jing , Mao Yue , Shi Xinlei
Published: April 2019

Bohai oilfield located at Bohai Bay of China mainly consists of complex clastic reservoirs. Reservoir prediction is difficult especially in the deep depth oilfields because of low seismic resolution. In addition, how to quantitatively characterize the risk of new oilfield development and how to build a more elaborate model in the late period of oilfield development are particularly challenging. This paper developed an innovative workflow for complex clastic reservoir characterization of offshore oilfield.

A modeling method based on sedimentary evolution simulation, which can provide modeling constraints, is proposed for deep depth oilfields. Through sedimentary evolution modeling and other information, reservoir and structure uncertainty are analyzed, then reserves scale and reservoir connectivity are evaluated through experimental design, geological modeling and streamline simulation; 3p models are selected lastly. A new method is proposed for building an elaborate model of old oilfield with less grid amounts. The fluid seepage effect caused by some small scale configuration units is characterized by a parameter similar to fault transmissibility multiplier data in numerical simulation model, for there is no actual modeling of the configuration units, so the operation efficiency is greatly improved.

BZ3 oilfield is a deep depth delta oilfield. A geological model was established for exploration evaluation well placement, reserves evaluation and development plan research based on sedimentary evolution simulation and quantitative uncertainty evaluation, the reservoir prediction accuracy is greatly improved that is confirmed by new drilled wells. Through quantitative uncertainty evaluation, reliable geological basis was provided for engineering investment, which can avoid the investment waste caused by geological uncertainty.

Q32 oilfield is a fluvial oilfield that has come into high watercut (86.7%). How to characterize the lateral accretion interlayer (often less than 1 meter) in model for fine remaining oil distribution prediction is difficult, thus the method mentioned above for old oilfield was used. Firstly, a conventional geological model was established, then the lateral accretion interlayer was extracted as interface from it based on configuration results, then the interface was used to extract the parameter named transmissibility multiplier data in the numerical simulation model; a software has been compiled to perform the whole process. Based on the method, more than 100 adjusting wells were disposed and better production results were obtained.

These geological modeling techniques have been widely applied in Bohai Bay offshore oilfields in different periods of oilfield development, including BZ2, JZ2, KL10, CFD6, SZ3, and JZ9. This ensures that these oilfield developed with high quality and efficiency.
Deep Neural Network Based Prediction of Leak-Off Pressure in Offshore Norway
Authors: Choi Jung Chan , Skurtveit Elin , Grande Lars
Published: April 2019

Leak-off pressure (LOP) is an important parameter to determine a weight of drilling mud and in-situ horizontal stresses. When the well pressure become higher than the LOP, it can cause a wellbore instability during drilling, such as a mud loss. Thus, accurate prediction of LOP is important for safe and economical drilling for the oil and gas industry. In this study, we present a novel prediction model for the leak-off pressure (LOP) offshore Norway. The model uses a deep neural network (DNN) applied on a public wellbore database provided by the Norwegian Petroleum Directorate (NPD).

We used a Python-based web scrapping tool to collect data from more than 6400 wells (1800 exploration wells and 4600 development wells) from the NPD factpages. Then, we analyzed the collected data to investigate impacts of spatial and regional factors on the collected LOPs. The DNN model was structured to predict the leak off pressure offshore Norway using open source libraries Keras and Tensor Flow. The model tests have various hidden layers (i.e. 3, 5, and 10 layers). In order to avoid overfitting, we specified an early-stop algorithm. In our study, we took 80% of the data as the training set keeping the remaining 20% to test the model. In total, the database consists of around 3000 leak-off pressure data from about 1800 exploration wells, and grouped in geographical area (North Sea, Norwegian Sea, Barents Sea groups).

The LOPs of the North Sea and the Norwegian Sea show a bi-linear trend with depth. The LOPs that are measured from deeper than 2-3 km below sea level show clear a deviation in trend, with a steeper increase compared to the shallower section. The steeper part of the bi-linear trend at greated sub-surface depths can be related to a coupling with tectonic stresses from base rocks. The data from the Barents Sea shows more scattered LOP compared to the other regions offshore Norway. The scattered data seem to relate to the complex geological history on the Barents sea. In general, the accuracy of the prediction increases with the number of hidden layers. However, when the number of the hidden layer exceed 5, there was no significant improvement in the accuracy of prediction. The validation test shows relatively good prediction of LOP with an MAE (Mean Absolute Error) of less than 0.07 even for areas experiencing complex geological history such as the deep subsurface of the Norwegian Sea and the shallow subsurface of the Barents sea.

This study clearly demonstrates how a data-driven approach combined with machine learning algorithms can provide hidden patterns of not only LOP itself but also the additional information about the lithology, the stress history and the geographical frequency of exploration.
Leveraging Online Analytical Processing Cubes in the World's Largest Offshore and Land Drilling Record System
Authors: Kuwertz Luke , Neill James , Santana Roberta , Skoff Gregory Michael , Steinke Stephen Claude , Williams John , Wolfram Preston , Fink Dave
Published: April 2019

The purpose of this paper is to demonstrate the power and business benefits of leveraging online analytical processing (OLAP) cubes in the utilization of high-level data analytics and data dashboards from an established drilling record system (DRS). The DRS contains over 1.4 million wells, including 75,000 offshore wells drilled worldwide since 1980 with nearly 5 million total bottomhole assembly (BHA) runs from over 100 countries. Since 2009, over 1.5 million BHA runs drilling 2.6 billion feet of formation have been captured. Being able to visualize and understand the drilling data allows for increased efficiencies, reducing the days on wells for operators from deepwater to inland barge and land drilling worldwide.

The development of the OLAP cubes required a multidisciplinary team consisting of software developers, business managers, domain champions, field-based engineers, and data scientists. The OLAP cubes consist of multidimensional databases built from relational and algorithmic interpretations of DRS transaction data. These algorithms are generated and developed by an iterative cycle of continuous improvement, development, and utilization of the OLAP cubes in parallel to improve the functionality and business impact for performance analysis, sales, product development, product reliability, and marketing. The data can be analyzed and visualized in the Microsoft Office suite by directly querying the DRS OLAP cubes. This also allows for dashboards to be updated in real time as data are added to DRS.

OLAP cubes have been developed to analyze the performance of drill bits, motors, reamers, rotary steerable tools, and many more downhole tools. The DRS cubes assist in identifying failure causes on bits to identify high-risk intervals to better target products and parameters to reduce costly nonproductive time. Fit-for-purpose OLAP cubes have been developed to understand drilling efficiencies and strategies in multibit versus single-bit sections using variable trip speeds and field performance. Traditional business reports were made more efficient and auto-updated and dashboards were built to identify major business trends to equip business managers.

This OLAP cube development has allowed for increased usage of the world's largest drilling record database and has made it easier to access and analyze the data. Ultimately, the techniques and development described in this paper help answer business questions to make better business decisions through data-driven analytics.
Case Study: Subsea Field Development Using Innovate Jumper Mounted Flow Access Technology and Standardized Hardware.
Authors: Donald Ian , McDonald Craig George , Hudson Adam Dudley Lawrence , Bryce Tom Gerard
Published: April 2019

This paper presents various case studies of projects in Gulf of Mexico and West Africa, which demonstrate how innovative jumper mounted flow access technology was successfully adopted to provide a differentiated field development strategy based on standard subsea hardware while still accommodating production enhancing technologies across multiple subsea field developments.

The paper also will explain how the technology supports fast track, cost effective subsea tiebacks, by promoting standard equipment and allowing concurrent hardware deliveries to deliver first oil faster.

The paper will share client considerations regarding standardization of the main subsea hardware elements, subsea system flexibility and the existing solutions for measurement and intervention packages, such as multiphase flow meters.

Project critical paths typically dictate that technologies such as flow meters must be available to synchronize with XT, manifold and jumper manufacture, testing and installation. Thereafter, any retrofit or rework requires significant operational downtime to recover and replace that element of the subsea system.

Integrating the retrievable flow access module (FAM) technology into subsea architecture within the jumper envelope addresses these concerns. Promoting standardized XT and manifolds on a field or regional basis, while the FAM technology provides the flexibility to address the individual well production requirements.

Further explanation will be provided as to how operators can use the technology to maximize ultimate recovery by accessing a suite of technologies throughout the life of field for both new greenfield and existing brownfield applications. Technologies such as, flow measurement and control, well and flowline hydraulic intervention and remediation, well production pumping and compression, pre-commissioning and secondary well control.

Finally, the paper considers the strategic benefits of adopting the flow access technology for subsea field development, promoting subsea system standardization, Capex, schedule and risk reduction compared to the more typical alternatives.
Beatrice Offshore Wind Project, Wind Turbine Generator Foundation Design
Authors: MacLeay Alan John , Hodgson Trevor
Published: April 2019

Objectives/Scope

The Beatrice Offshore Wind project comprises the development of 84 number 7MW turbines located in the Moray Firth in the North of Scotland. It is one of the most northerly and exposed sites globally and also the deepest site for fixed foundations for offshore wind. The paper describes the design challenges and how they were addressed. The solutions are likely to be of interest to anyone else developing a deep water offshore wind project, especially with variable soil conditions and a significant water depth range.

Methods, Procedures, Process

The Beatrice WTG foundations were completed as an EPCI project with close integration between the EPCI contractor, designer, fabrication and installation teams. Across the site water depths ranged from 35-68m, however, this range was reduced when a small number of outliers were discounted. The final range was 38-55m. There was also a significant variation in soil conditions across the site and this created significant challenges when attempting to standardise the design.

Global analysis of the selected structures under wind and wave conditions was performed using Sequential Coupled Analysis (SCA) with BHawC and ANSYS ASAS software packages. The analysis was performed by passing information between the turbine supplier and the substructure designer to produce coupled wind and wave loading on the integrated jacket, WTG and tower system.

Results, Observations, and Conclusions

The jackets are the largest ever designed and installed for offshore wind. The solution developed was a 4 legged pre-piled jacket. The design was split up in to 5 clusters to address the water depth range. Associated with this a pile stick up range of 2-6m was adopted. No scour protection was used.

The top half of the jacket, transition piece and much of the secondary steelwork was standardised across the site. The base dimension for the jacket and pile diameter was also standardised across the site to allow for re-use of a pre-piling template.

The final foundations were installed in 2018.

Novel/Additive Information

The grouted connection between the jacket and the pre-piles includes the first application offshore of Masterflow 9800 grout.

Control of early age cycling was a key consideration in design of the jacket to pile interface.

Piles were designed in accordance with the Imperial College Pile ‘ICP’ effective-stress pile design approaches for offshore foundations.
Elimination of False Positives in VIV Identification Using Machine Learning
Authors: Agarwal Puneet , Bhalla Kenneth , Campbell Robert Brad
Published: April 2019

Vortex-induced-vibration (VIV) is an important consideration while drilling at sites with moderate to high current speeds. Planning for drilling operations often includes determination of limits on maximum drilling riser motion amplitude using model simulations. These limits can then be used to raise alarms in the field by comparing motions measured in the field using one or more motion sensors. The determination of such alarm limits is challenging as VIV is a highly nonlinear process, and small changes in the speed or shape of current profile can result in quite different VIV fatigue results for drilling risers, especially in deep water depths.

We use feed-forward neural network, which is a powerful machine learning algorithm, to develop a classifier for distinguishing damaging and non-damaging VIV events. The neural network uses acceleration and angular rate data from only three motions sensors located on the upper flex joint, the lower flex joint and the BOP stack. To train the neural network, riser motions and fatigue damage data are generated from SHEAR7 runs on the model of the drilling riser. Thousands of current profiles measured from a current mooring at a deepwater site (water depth > 6,000 ft) are used as inputs to SHEAR7 model in order to capture full variability in VIV response from the actual field environment.

Results show that the neural network classifier almost always predicts damaging and non-damaging VIV correctly. The precision, recall, and F1 score (a combination of precision and recall) for the neural network classifier are all close to 100%. A high precision, recall, and F1 score for a classifier implies that it has no false positives and no false negatives. Here, a false negative is defined as the situation when damaging VIV occurred but was identified as a non-damaging VIV event and an alarm is not raised. False positive is the situation when an alarm is raised for damaging VIV when the event was actually not so damaging.

On the other hand, the baseline "constant" classifier of conservatively chosen limits (from the same data) for upper and lower flex joint angles results in very low precision and F1 scores, implying too many false positives. While the baseline classifier does not predict any false negatives, it is very expensive because of too many false positives. Furthermore, it carries the risk of being ignored by users due to too many false alarms.

This work demonstrates that machine learning techniques can accurately predict damaging VIV events in the field using minimal number of sensors. Such accurate predictions were not possible using traditional methods.
Reliability Study on the Life Extension of Subsea Umbilical Systems
Authors: Melo Joao , Silva Murilo
Published: April 2019

Subsea umbilicals are a critical element on most subsea oil & gas production systems. They can include hydraulic conduits and electrical and/or optical cables that serve as a critical lifeline, connecting topside facilities and equipment to subsea architecture, distributing multiple elements including power, chemicals, and communication functions throughout the deepest and harshest of environments.

Globally, thousands of subsea umbilical systems are approaching or have reached the end of their design lives after 15-25 years of operation. In many cases, operators would have a need to continue using such umbilical systems for longer, but they are unsure whether that can be done or if they need to invest in new replacement umbilicals. To make the right decision, operators need a well-defined process for evaluating the risks of continuing to produce using the existing umbilical systems.

This paper presents a simple methodology for assessing risks related to extending the life of subsea umbilical systems. This method helps operators identify the most critical areas of the system and their associated risks, and helps estimate the reliability of the system in its current and future states.

Upon review of available literature and current practices, it was determined that there were no industry standards for extending the life of umbilicals. The method described here is in line with the guidelines and recommendations of API RP 17N [Ref. 1]. The approach includes a review of the available information related to the life of the asset along with risk identification, risk assessment and recommendations for risk mitigation. Reliability models using field data and available literature are used to quantify the system reliability under different conditions, including life-extension scenarios. The proposed method is demonstrated using an actual business case from the North Sea, where risks associated with the life extension of a given umbilical system were identified and reviewed, and where the work has supported the operator's decision-making process.
Kaikias Phased Appraisal and Development Strategy
Authors: Hyder Scott C , Baird John I
Published: April 2019

Kaikias is an oil discovery of four stacked miocene reservoirs in the Deepwater Gulf of Mexico in the Greater Mars/Ursa Area. During exploration, only the lowest reservoir objective (Lambda) was penetrated, discovering oil pay to base. A follow-up appraisal well was drilled penetrating the upper three reservoir objectives (Beta, Zeta, and Kappa) discovering oil pay to base in all reservoirs, as well as penetrating the lowest reservoir objective (Lambda) and again discovering oil pay to base. Following the exploration and appraisal program, there remained considerable resource uncertainty given the lack of definitive oil water contacts in any of the reservoirs and poor seismic imaging (impacting the ability to determine the reservoir extent and thickness). Rather than continue to de-risk the field with further exploration and appraisal activities (potentially eroding lifecycle value and delaying first oil), a small, robust Phase 1 project was matured to accelerate first oil and to de-risk the subsurface through production data. The Phase 1 project was highly competitive attributable to the re-use of two existing exploration and appraisal wellbores and a minimal subsea scope. The Phase 1 project was sanctioned by Shell (80%) and MOEX NA (20%) in January 2017.

During execution of Phase 1, a Phase 2 project was proposed to further appraise the three reservoirs developed by Phase 1 (Beta, Kappa, and Lambda) as well as to produce unique volumes from the fourth reservoir (Zeta). The Phase 2 appraisal program was a great success, proving upside in all three Phase 1 reservoirs and justifying expansion of the two lowest reservoirs (Kappa and Lambda). Following the successful Phase 2 appraisal and subsequent side track to the Zeta reservoir, a Phase 3 project was proposed to add a second production well to each of the two lowest reservoirs, accelerating and capturing unique volumes from each. The Phase 3 project also provided an opportunity to calibrate seismic imaging for further exploration in the area and to provide a better understanding of fluid gradients. This phased appraisal and development approach resulted in a highly a competitive investment for Shell (80%) and MOEX NA (20%) and allowed co-owners to optimize the lifecycle value of the project without overspending on exploration and appraisal activities. Further, the phased appraisal and development approach reduced the overall downside risk for the project.
Subsea Water Treatment Pilot Testing at the Ekofisk Field in the North Sea
Authors: Dirdal Eirik
Published: April 2019

A new subsea water treatment system for injection water has been developed and has undergone several phases of testing. A full-scale water treatment module has been built and is currently being tested at the Ekofisk field offshore Norway to determine its viability under North Sea field conditions.

A hybrid configuration approach is used, as the test is based on utilizing existing infrastructure to minimize project cost. The subsea water treatment system was therefore installed next to a fixed platform and connected to topsides through a flexible hose for water supply and an umbilical for power and communication of the subsea water treatment module. The disinfected water is lifted to the platform deck through a retrieveable lift pump, and the treated water is then analyzed before injection into the reservoir through a high-pressure pump and converted production well.

The primary objective with the test is to replicate the results from a similar full-scale version that was tested in sheltered environments in a fjord on the Norwegian west coast, which would verify the water treatment module's performance and reliability through seasonal variations and thereby demonstrate its ability to deliver injection water of a quality in real offshore conditions.

The secondary objective is related to Ekofisk requirements and reservoir related impacts of injecting water treated by this new submerged water treatment technology. The results from this test will not become available until second half of 2019.

The commissioning phase has been completed, and the results achieved so far are within expectations, with high disinfection capabilities and equipment regularity. The particle content in the water was generally higher than previous inshore testing, which was not a surprise due to the harsh environment and relatively shallow water (∼70m) in the Ekofisk Area.

The project has recently moved into the longterm testing phase. The results from this phase will become available second half of 2019.
Optimizing Seawater Treatment Operations with Condition Monitoring Software
Authors: Wilcox Austin , Mikkelsen Rene , Lian Pei Ling Esther
Published: April 2019

In an effort to maximize the value of the Enhanced Oil Recovery(EOR) process, a condition monitoring software program aims to optimize Seawater Treatment system performance and maintenance efforts. By collecting digital inputs from sensors, instruments and controllers on the platform or vessel, you can monitor system behavior and use application expertise and data science to characterize the operational conditions which enable operators to reduce their operating costs and maximize production.

Combining unparalleled process expertise with data science and software development team, a system-wide view of the Seawater Treatment (SWT) process is produced. Using current and historical data from SWT operations, ingesting into an IOT platform and, utilizing custom software program, provide full visualization of the system performance and condition monitoring of critical components within the system. One example is monitoring the sulphate removal unit (SRU) and predicting fouling types of the membranes. With this enhanced view of performance and predictive analysis, you can reduce the need for offshore supervision and troubleshooting efforts and can prevent repeat failures and unplanned downtime.

Using the SRU as an example, the Seawater Treatment software program enables early stage detection of membrane fouling which allows the operator to proactively implement a fouling mitigation program. By detecting the fouling early, the operator can optimize the cleaning in place (CIP) sequences, perform timely CIP and chemical dosing to extend the life of the membranes and prevent unnecessary downtime and prevent permanent membrane damage. It has been observed through historical data that operators can save a significant amount of money per year on membrane life, downtime reduction and production penalty prevention. There are additional potential savings by using an optimized chemical injection program to manage and prevent biogrowth/scale formation in the system.

To address the operator's need of optimizing Seawater Treatment and other topside process equipment, a suite of process specific software applications can be fully integrated into a digital platform, providing a framework that easily can be tailored to customer's needs to include additional features if required. Combining a comprehensive selection of wellstream processing technologies with deep understanding of fluids behavior and proven track record of digitalization, operational issues can now be uncovered and solved. This is different from typical remote monitoring initiatives in that it applies proven machine learning and predictive analytics frameworks to detect patterns and traces from the captured data to provide the earliest possible detection of future issues and provide proactive recommendations to prevent disruption to operations.
Impacts of Fiscal Systems on Oil Projects Valuation
Authors: Dambros Lucchesi Rodrigo
Published: April 2019

Despite increasing demand for cleaner energy around the world, oil is still the main global energy source and this scenario will not change in the short term. Together with natural gas, they supply 57% of world primary energy demand (BP, 2018). Therefore, if a country wants to benefit from having its hydrocarbon reserves developed to generate wealth, it is crucial to enable economic conditions for such. This study aims to show the impact that distinct fiscal systems adopted by each country can have on the valuation of an oil field and its commercial feasibility, from an international oil company perspective. Fiscal terms define, among other things, how revenue from oil production is shared between operators and the host country. To investigate such topic, a deepwater offshore oil development project was valuated using discounted cash flow method. Sixteen scenarios were created, considering a combination of four distinct field sizes under four fiscal systems, selected from some of the world's top oil producing countries. For each scenario, internal rate of return (IRR), which indicates the project's economic return for the operator, and government take (GT), which indicates how much of the oil revenue is directed for the host country, were calculated. Findings show very distinct results in each scenario, with IRR for operators ranging between 8 and 21% and government take between 57% and 84%. Considering that project returns should always be higher than a company's capital cost, in some scenarios the discovery would not be declared commercial. Results also show that, in general, large oil development projects in countries with tax/royalty system present a higher return for the operators, while production-sharing contracts tend to generate a higher government take. This shows that the same oil field, under same geological conditions, can offer very different economic returns to the operators and host governments, depending on the fiscal system in place. In some cases, the fiscal system has such an impact on the economic feasibility of the project, that it may even prevent the discovery to be declared as commercial and, therefore, not be developed and booked as proven reserves. The main takeaway of this study is that understanding fiscal systems is an essential tool for operators to properly evaluate its projects and one of the most important features governments can adjust to attract private investment to their oil industries.
Operational Adoption Challenges to USV/ROV Services
Authors: Moles Peter , Ladreux Mathieu , Karl Larry
Published: April 2019

A fully unmanned surface vessel/remotely operated vehicle (USV/ROV) system—controlled remotely from shore and providing inspection and light intervention services—could deliver many benefits during offshore operations including increased safety, cost effectiveness, and data quality. Development of an unmanned solution also faces many challenges in ensuring the system's fitness for purpose. System developers must address a range of inter-related issues including system reliability; operational risks and mitigations; monitoring and analyzing performance of key hardware system; safety policies; determination of required level of control for the many activities and failsafe functionalities; potential regulatory requirements; and a path to adoption that satisfies all stakeholders.

Solutions to the challenges of unmanned operations must consider the operational philosophies, governance policies and risk tolerance of the many stakeholders because acceptance of such solutions are not always straightforward. Many of the component technologies of the unmanned system are available and proven, but new solutions also need to be developed. ROVs piloted from onshore control centers and operations by unmanned surface vessels are not uncommon today. With no personnel on board to resolve problems, reliability must be increased from current levels, failsafe autonomy and increased ROV/USV functionality must be included in the USV/ROV system. The system's design also must provide for safe transfer of people from a manned vessel to the USV in the event that troubleshooting and more extensive maintenance are required.

This paper reviews these challenges based on performing a series of traditional analyses: concept of operation reviews defined key operational functions; hazard analyses identified potential failure modes and their respective mitigation; reliability assessments to understand the current level of reliability for USV and ROV systems and requirements for multi-day missions; current and pending regulations were reviewed to identify their impact on technical specifications and operational procedures.
Riser Gas Equilibrium for Oil Based Muds with MPD Considerations
Authors: Nwaka Nnamdi , Chen Yuanhang , Williams Wesley
Published: April 2019

The offshore drilling industry has been seeking to more realistically simulate gas-in-riser events, to optimize mitigation methods and justify the adoption of new pressure control equipment. This paper presents an improved model to describe gas in riser events with direct application to oil-based muds (OBM), with which most of the gas-in-riser events take place.

A mathematical model is developed and used to describe the behavior of gas influx migrating or being circulated out in a marine riser in an OBM. The release of dissolved gas in OBM is thus factored in and assumed instantaneous. Bubbly flow is assumed for the contaminated mud and simulations are performed for different choke openings as in Managed Pressure Drilling (MPD) applications and with different booster pump circulation rates. The contaminated mud section is discretized both in time and space to ensure that pressure and pressure dependent parameters are accurately quantified.

Results clearly show that the severity of the rapid unloading process can be overestimated when a water-based mud scenario is assumed. The severity of rapid unloading and the depth of the riser equilibrium point during the circulation of the influx out of the riser are seen to be of little dependence on the time at which the backpressure is initiated but with very high dependence on the magnitude of the backpressure and the circulation rates. Severity of rapid unloading increases with the circulation rate. If the gas is allowed to migrate without circulation, backpressure application would have a much greater effect on the unloading results.

The concept of riser equilibrium has been thus far developed in the context of water-based muds. This paper considers only OBMs where most of the events take place.
Dynamic properties of offshore sands
Authors: Zuccarino Lorenzo , Morandi Daniela Ausilia , Ottonello Luca
Published: April 2019

This paper examines shear modulus degradation and damping for offshore sands. The work is based on an extensive database of dynamic soil properties for undisturbed and reconstituted granular samples from offshore sites worldwide. The data set consists of direct measurements obtained from advanced laboratory tests (resonant columns). Data considered in this paper includes a wide range of granular marine sediments. The effects of soil properties such as confining pressure and fines content on the dynamic parameters are described and guidance on interpretation and applicability is provided.

A new calibrated model is proposed to evaluate normalized shear modulus reduction and damping ratio curves as a function of shear strain of marine sands. The proposed relationship can be used for a wide range of granular soil conditions for direct use in routine offshore dynamic engineering analyses and, in particular, in non-linear site response analysis.
Submerged Archaeological Resources: Sound, Software and Three Inch Pipes - A Recipe for Finding Submerged Prehistoric Archaeological Sites?
Authors: Ervan Garrison G
Published: April 2019

Objectives/Scope

1. Review the effectiveness of existing technology for identifying and characterizing submerged and buried prehistoric archaeological sites.2. Critique and suggest changes to existing technology to improve the effectiveness for the identification and characterization of submerged prehistoric archaeological sites.3. Examine the "why" this is important to offshore technology regulation and management.

Methods, Procedures, Process

The process can easily be paraphrased as "sound, software, and three inch pipes" - the sound being the pulse from sonar or sub-bottom instruments, the software being the methods by which those pulses are processed and display, and the three-inch pipes, of course, denoting the coring tubes used to sample targets identified in using sound and software. In fairness to the methods discussed herein, their application has been, at best, uneven. The use of the first two technologies - sound/acoustic and post-processing software programs have been in regular use by geophysical contractors. The latter technology - sediment coring - has been utilized far less.

Results, Observations, Conclusions

How effective has this methodology proven to be over the past thirty years? That is open to some debate and this paper will examine some reasons why this is so and suggest some possible alternatives. The overarching goal of this paper is to push beyond this methodology to potentially more effective technologies or at least improved usage of the current technology.

Novel/Additive Information

Submerged prehistoric archaeological sites are "hard problems" in terms of their discovery and characterization. Compared to submerged historic archaeological sites - primarily shipwrecks - those are "easy." This comparison of the use and effectiveness of technology is novel and additive.
Synthesis of Disruptive Technologies Leads to Design of Flowable Sensors for Reservoir Monitoring, Passively Retrievable Through Carrier Buoyancy
Authors: Chen Ting , Shenoy Ram , Roy Indranil , Zhou Jing
Published: April 2019

Technology gaps in measuring wellbore parameters and providing the results at surface without using wireline (Production Logging) or slick-line, without using mud-pulse, electromagnetic or acoustic telemetry, or pre-installed or permanently installed downhole sensors remain an area to be bridged.

Our ability to engineer light-weight, high-strength, highly-reactive (dissolvable) or corrosion-resistant, nanostructured-alloys and intelligent micro-electromechanical system (MEMS) devices have enabled design of buoyant sensors having thin (millimetric) wall, capable of withstanding 20,000 psi or more differential pressure. These sensors measure and record a complete set of the client’s required wellbore parameters (e.g., Pressure, Temperature, Depth, Casing collars, Flow-rate across perforations or in wellbore, Water cut, Dissolved O2, etc.). These devices are deployed, either nested in an outer shell of salinity independent water reactive alloy to abet pump down to depth or weighed down by a sinker of dissolvable alloy. These devices are free-flowing within a wellbore so that they can be placed downhole to required depth for a specific time, after which the outer shell dissolves or the sinker weight falls, releasing the inner gauge. The now buoyant device flows back to surface with produced fluids where they make their presence known by sonic or inductive signaling.

Our company was founded to take advantage of these disruptive innovations in materials science and sensors and synthesis of these technologies to provide superior performance products for both deep-water domains and the multistage stimulation (MSS) market.

In this article we address two of our key inventions. First, the development of miniature, self-contained, battery powered, free-flowing sensor devices for reservoir monitoring, passively retrievable through carrier buoyancy. A subset of this game changing approach, to economize operations is, "Measuring in- situ pressure, temperature, and subsequent production during MSS". Second, we present a mechanism to assess susceptibility of oilfield alloys, especially in live reservoir fluids at the production zone. This encompasses a retrievable sensor device to assess environmental effects on materials at target zone in wellbore during production or shut in, can be deployed anywhere from production zone to bubble point, to surface separator. It facilitates testing not in a simulated autoclave environment at surface, but downhole, at the zone of interest.
From Watt-Scale to Megawatt-Scale: Advances in Wave Energy Technologies for Offshore Applications
Authors: Lamb Bradford Storrs , Lesemann Arvid Reenstjerna
Published: April 2019

Potential applications for wave energy cover the spectrum from powering watt-scale maritime sensors to generating electricity at megawatt-scale. These applications include energy generation for: ocean observation, communications, autonomous underwater vehicles recharging, isolated community grids, aquaculture, underwater data centers, seawater desalination, ocean mining, disaster relief and recovery, and utility grids. Much of the focus to date has been on utility-scale systems for grid-connected applications. However, despite the effort to develop viable technologies and the attractiveness of the resource, wave energy has yet to achieve status as a mainstream renewable resource.

According to REN21, 150 GW of wind and solar was installed last year, but in spite of this growth, wind and solar do not present a universal solution to our renewable energy needs. Without significant amounts of cost-effective storage to smooth and shift energy supplies, the intermittency of wind and solar leave gaps that must be filled with other, new renewable resources that are widespread, energy dense and close to the load. These issues are exacerbated in a maritime environment where wind and solar are not technically viable in many cases.

Energy from marine hydrokinetic sources—mainly ocean waves, currents, and tides—will help fill the gap that wind and solar can’’t. Our oceans are the largest battery of stored energy on the planet; capable of providing 200% of our current global electricity supply & 30% of US demand (load). Wave energy, in particular, possesses the desirable characteristics of a new mainstream renewable, with nearly 7x the amount of tidal resource available globally. However, all marine energy resources present inhospitable operating environments, with a need to balance the competing interests of affordability on a local basis, acceptability of the system by the various stakeholders, and availability of the generation system on a consistent and reliable basis. While federally-funded wave energy research and development has been underway for over a decade, recent advances in wave energy technology present the opportunity to breakthrough these constraints and provide dependable, cost-effective energy.

These advances also bring forward several potential market applications of interest to the maritime community, specifically low-power autonomous systems for maritime sensing, monitoring and communications payloads and utility-scale systems for provision of megawatt-scale energy. Potential customers of these systems—such as defense and security agencies, and oil&gas, industrial, aquaculture and telecommunications companies—need consistent and reliable energy storage and generation that reduces their cost of ownership for their current battery, solar or liquid fuel energy sources and/or enables operating capabilities and location persistence that is not currently available.