bluuebunny/crossref_metadata_2025 huggingface dataset:
Nozzle Check Valve for Subsea Application
Authors: Gupta Abhineet , G V Praveen , Shirras Holly , Kaars-Sijpesteijn Nicholas , Kamdar Prashant
Published: April 2022

Check valves are critical to the safe and efficient operation of many facilities. By using field data and various analysis techniques, check valve designs can be optimized to provide maintenance-free operation in addition to low-pressure loss and fast-dynamic performance.

Success in onshore applications provided an opportunity to repurpose highly reliable check valve technology for offshore use. The design was modified by scaling to suit the application, reducing the number of components, reducing sources of component wear, using iterative analysis techniques, such as Finite Element Analysis (FEA) and Computational Fluid Dynamics (CFD) to reduce the pressure loss, and focusing on proper sizing to ensure optimal performance during operation, such as providing an accurate evaluation of opening/closing forces.

Common field issues such as worsening seat leakage rates and inconsistent performance are generally caused by the constant movement of components within a check valve during normal operation, which causes wear and ultimately failure. It is critical to have accurate fluid flow information and size the check valve accordingly. To avoid these common field issues, check valve designs should be selected to ensure no unnecessary movement of internal components during normal operation. With proper attention to detail, check valves can be designed to eliminate field issues while also providing lower pressure loss characteristics and fast-dynamic response.

This paper presents field data from existing applications of the technology, performance data from the analytical methods, and field data from the temporary application in the offshore/subsea industry. This paper also discusses a reliable alternative to ball check valves, which are commonly used in the subsea industry. It provides a better understanding of the check valve design and how specific design details influence performance and reliability.
Forward Simulation and Backward Calibration on Fracture Morphology in Shale Formation Based on Finite Element Method and Ensemble Method
Authors: Zhang Ruxin , Shan Qinglin
Published: April 2022

In this paper, a workflow is proposed to investigate fracture morphology in shale formations, integrating two parts: forward simulation and backward calibration. Uncertainty in the forward simulation should be quantified by backward calibration, in order to get the efficient simulation results.

The workflow is based on the combination of finite element method and ensemble method. Finite element method is used to establish a forward simulation to study fracture initiation and propagation under the effect of natural fracture. Ensemble method is adopted in the backward calibration process, in order to quantify the uncertain parameters, such as Young's modulus, Poisson's ratio, damage factor of cracks, and horizontal stress contrast, based on injection treatment pressure. Moreover, before the backward calibration, sensitivity analysis is conducted for each type of data misfit to find the most influential parameters.

The simulation results indicate that induced hydraulic fractures prefer to propagate along the maximum horizontal stress, forming a bi-wing fracture. Under the effect of natural fractures, two different propagation behaviors, diversion and cross, could be observed, resulting in a tortuous fracture geometry in the shale formation. Sensitivity analysis claims that Young's modulus, Poisson's ratio, and damage factor of cracks are the three main influential parameters for the forward simulation. A set of ensemble models are established based on above three parameters as initial state for the data assimilation algorithm. The injection treatment pressure are matched well after model calibration by ensemble method.

The highlights of this workflow: 1) the interaction between induced fractures and natural fractures is involved, resulting in a torturous fracture morphology; 2) model calibration is conducted to reduce and quantify uncertainty; 3) The calibrated fracture model could be used to do production prediction. This workflow provides the theoretical basis for fracture initiation and propagation, but also generates the more reliable fracture morphology for further research.
Zero Base Budgeting Applied to Oilwell Construction
Authors: Petersen Flávia Cristina , Ramos Junior Antonio Carlos , Marques Marcello , Da Silva Hugo Alves , Dalvi Dos Santos Priscilla Regina , Rodrigues Lorrainy Toledo , Rodrigues dos Anjos Jorel Lopes , Russo Renato Márcio Dias , Ferreira Filho Virgílio Martins
Published: April 2022

The development of digital transformation tools has significantly increased the amount of available data in recent years. As in all sectors of the economy, the oil industry, with a focus on well construction, was not left out of the process. Numerous data are monitored and stored in real time and several studies are carried out to increase operational performance. However, little has evolved in relation to the knowledge that these data can generate in decision-making processes, such as in the definition of targets that serve as a reference for the planning of interventions. Thus, this article explains a new methodology for defining targets, based on the knowledge of specialists, the concept of zero-based budgeting and risk analysis, with the integration of teams of well designers, reservoirs, and budgeting. The methodology was used in 19 fields’ studies and directly applied to the planning of 5 new projects.
Economic Analysis of Gas to Power Project in Nigeria
Authors: Ihejirika Vivian Chinenye , Iledare Omowumi , Adeogun Bimpe
Published: April 2022

This research work is based on the economic analysis of Gas to Power in Nigeria. Gas is progressively substituting the time of crude which substituted Coal. Nigeria is positioned as the 9th country in Africa with 192tcf estimated gas reserve in the world and 1st in Africa. The power sector has been underdeveloped over the years. The current initiative by the Federal Government of Nigeria to reach a target of 20GW capacity of electricity by year 2020 has identified the choice of Gas-to-Power as a major key-driver in attaining such a goal. This research work considered the economic analysis of converting Gas-to-Power under the prevailing petroleum fiscal system, through a critical review of a number of literatures. Model assumptions were made based on an offshore field for the analysis of associated Gas sales and an average of 20,000kW of power generated every year for 20years. Government Net Present Value (NPV) was gotten to be $181.12 MM and contractor NPV $337.04 MM for sales of the Gas and $20.07B, $10.78B for the government and contractor NPV respectively for power generation, Internal rate of return (IRR) for the contractor was recovered as 15% and 19% for gas sales and power generation respectively and the Profitability Index (PI) was calculated to be 3.88 for Gas and 3.2 for Power at the end of 20 years field life. The effect of CAPEX, OPEX, product price, production rate and discount rate on NPV, IRR and PI at 15% discount rate was investigated to know the range of profitability of Gas-to-Power using @Risk software to perform risk and sensitivity analysis. Discount rate and Price were seen to have the most impact on the output variables. Generally, the results were favorable for converting Gas-to-Power. The economic model has proved that Gas to Power technology is profitable in Nigeria and can also lead to industry growth which will invariably lead to revenue generation, therefore bettering the Nigerian economy and increasing social and human development.
Novel Marine Energy Environmental Compliance Reporting Application Summarizes Disparate Content by Tags and Location
Authors: Barr Zach W. , Best Ben , Peplinski William J. , Jones Craig , Chang Grace , Roberts Jesse D. , Kramer Sharon
Published: April 2022

Objectives/Scope

Marine renewable energy (ME) projects in the United States must complete a wide range of environmental permitting activities focused on evaluating the potential interactions between the technology and the environment (endangered species, habitats and human uses) (Kramer et. al. 2020). For those interactions where there is high uncertainty, studies are likely to be required, with outcomes addressed through adaptive management, which can increase expense and time needed to work through the permitting process. We developed the publically available marine energy toolkit (http://https://marineenergy.app) to provide multiple sources of information to support permitting ME projects.
Casing String Fatigue: No More
Authors: Noshi Christine Ikram , Amani Mahmood
Published: April 2022

Casing strings are an indispensable component in the design of any well and serve numerous purposes in oil and gas wells, constituting 20-30% of the total well cost. An alarming rate of failures, up to 50%, have been observed yet hushed under the rug, due to reputation, company profile, and privacy. In this work, The designed workflow follows 6 acceptance criteria, namely, (1) identification of potential risk factors amongst different exposures, (2) evaluation of the type and magnitude of the impact for each risk factor, (3) identification of the levels within each potential risk factor that impose the highest risk on casing failure, (4) acknowledgement of the depths most susceptible to casing failure, (5) prediction of the overall probability of casing failure given the information for pre-defined risk factors, and finally (6) have a scheme for mitigating casing failure.

Case-control study design was adopted to test the association between the different exposures and the occurrence of casing failure. Impact type and magnitude of identified risk factors were determined through various statistical association measurements. Non-parametric survival analysis techniques were used for identification of the levels within each potential risk factor that impose the highest risk on casing failure and the depths most susceptible to casing failure.

The scheme provided quantifiable numeric percentage increase/decrease for significant risk factors at lower, intermediate, and higher depth of casing. One importance of such conclusions is that although the conclusions coincide with already proven theories, unlike physics-based models, we did not need to acquire any domain knowledge to reach to those outputs. Moreover, in addition to exploring the significance of subcategories with respect to imposed risk, we managed to quantify those impacts which would be of great value when calibrating malpractices later using the proposed "correction-prediction" procedure.
Accelerate Digital Transformation in the Oil and Gas Industry
Authors: Ziadat Dr. Wael M. , Kirkham Dr. Richard W.
Published: April 2022

It has been recognized that Digitalization in the oil and gas industry, as emerging information communication and technology, can improve collaboration to different extents. However, because of the fast progress of Digitalization adoption both on the scope and in-depth, there is a knowledge gap between industry and academia that lacks systematic analysis on critical success factors (CSFs) of implementing Digitalization for collaboration in the oil and gas industry. This study develops a digitalization framework for collaboration from technical, organizational, process, and legal scopes. It identifies the CSFs of Digitalization in each scope based on the latest publications. From a system analysis perspective, the pair-relationship matrix is established to reveal the hidden effect between CSFs. The CSFs in the specific Digitalization application areas are identified based on the matrix.

The Innovative Digital Race is based on the evolution of the operational backbone of the engineering domain, driven by advancements in Artificial Intelligence, Machine Learning, Deep Learning, Automation, energy technologies, and data-driven prediction and analytics.

Organizations are constantly buffeted by unexpected events, from the COVID-19 pandemic to climate change to political unrest. In contrast, the promise of digital transformation to prosper and outperform the challenges during disturbances stays apparent as digital is responsible for supporting digital enterprise technology. As a result, enterprises can embrace innovations to accelerate growth and strategically drive the enterprise forward through gaining trusted digital connections, solutions to disruptive scale digital creativity, and innovative capacities to post business growth and resilience.
Influence of Residual Stress on Casing Collapse Performance under External Pressure
Authors: Lin Bisen , Coe David , Harris Richard
Published: April 2022

Collapse performance of a casing string subjected to external hydraulic pressure is one of the most important parameters in the deep water well casing design. It often becomes one of the governing factors in a casing design program. This paper investigates the quantitative effect of inherent circumferential residual stress (RS) on casing collapse resistane to external pressure through parametric Finite Element Analysis (FEA).

Nonlinear elastic-plastic FEA study on casing collapse calculations have been performed. Different magnitudes and orientations of the initial circumferential residual stress were considered. Modified Riks method was used to predict the casing onsite collapse pressure as well as the post-collapse response. Parameters considered in the analysis include: (i) two material grades (L80 and Grade 135); (ii) for each material grade, ratio of outside diameter to wall thickness (i.e. D/t) ranging from 10 to 50; (iii) for each D/t ratio, initial circumferential residual stress at casing inner diameter (ID) ranging from -40% to +50% of the material yield strength (YS).

Analysis results indicate that there is a highly nonlinear, parabolic-like dependence of collapse strength on the initial circumferential residual stress. Comparison of the FEA results to the predictions by Klever-Tamano Ultimate Limit-State (KT ULS) equation indicates that the KT ULS equation in the current API Technical Report 5C3 (API TR 5C3) does not capture this nonlinear relationship. This is probably due to the limitation of the API historical collapse test data upon which the KT ULS equation was calibrated to. The majority of the API historical collapse tests had the compressive residual stress at the casing ID. Moreover, the relationship between casing collapse strength and residual stress may be used as a guideline for potentially developing new high collapse casing by full-length residual stress control in mill production.
Alternatives to Conventional Offshore Fixed Wind Installation
Authors: Robinson Roy , Furtado Ivan
Published: April 2022

This paper presents alternatives to the conventional offshore fixed wind construction and installation methods. Of particular interest are methods that avoid the need for the heavy lift vessels. The Jones Act in the USA precludes the efficient use of these vessels, and this curtails the rate at which offshore renewable energy can be constructed. The primary areas of focus are:

Platform designs that allow for in-port assembly of the structure. Alternatives to the current wind turbines and the heavy lifts they require Alternative offshore methods of assembling current systems.

The conventional installation method of stick building offshore wind turbines one at time using specialized, and costly, vessels has become limit on rapid low-cost deployment. This paper is intended make the audience aware that there are practical and more cost-effective alternatives that could challenge the established method.

Offshore fixed wind breaks the golden rule of offshore development: never do in port what you can do onshore, and never do offshore what you can do in port. If it costs $1 onshore, its $2 in port, and $10 offshore. For the industry to thrive this needs to change. The paper describes first how offshore fixed wind is installed, then proceeds to address the shortcomings of the current methods by drawing from a data base of more than 2000 companies and technologies to illustrate there are viable alternatives to the conventional construction methods.

Practical methods for in-port integration, robotic assembly, and alternatives to conventional turbines are presented. If applied these systems would resolve Jones Act issues limiting rapid development of US based offshore wind, reduce the cost and risk of offshore wind developments generally, and increase the value of current offshore wind leases.
High Performance Heated Pipe-in-Pipes: Comparative Constructability Study for Remote Subsea Tiebacks
Authors: D’Huart Pierre Emmanuel , Jardin Antoine
Published: April 2022

The High Performance DEH-PiP is a new technology for electrical heating of subsea tie-back flowlines, that minimizes disturbances to the construction and installation process wrt. to standard PiP avoiding the use of internal heating cable, while reaching the same electrical efficiency as e.g. Electrical Heat-Traced (EHT) pipe-in-pipes. The aim of this paper is to present a comparative study that has been made on the cost, delivery schedules, and local content of various heated pipelines technologies for subsea tiebacks, with specific application targets, notably in West Africa.

A complete engineering study has been made (flow assurance, pipeline design, electrical engineering, installation engineering) based on real cases. Full EPCI costs have been evaluated, and local content for fabrication quantified. Two construction techniques have been compared: J-Lay comparatively to Reel-Lay, as the DEH-PiP is a product well adapted to all types of construction vessels. The study concludes that High Performance DEH PiP, while being comparable in terms of electrical efficiency to ETH, brings a 20% saving in total EPCI costs and a very significant increase in manhours of local fabrication (+100k mhrs)

This paper introduces a new DEH-PiP design, reaching significantly higher electrical efficiency, in the range of 90%-95%, and installable with a very versatile fleet. Hence constructability studies in J-Lay are completely novel.
Dynamic Operations for Wax Removal, a Challenge on Pre-Salt Oil Wells
Authors: Veiga Helena Maria Borja , German Carole
Published: April 2022

Pre-salt oil wells represent huge Flow Assurance challenges for operators both in terms of the complex oil compositions and deep-water conditions. In this paper a field case will be presented with the description of novel wax deposition removal techniques developed case by case to mitigate fouling on production pipelines where a service network is not available. The efficiency of cleaning operations brings not only more stable production but also higher operational efficiency and reduction of emissions per barrel produced. The added challenge of the lack of service network was a constraint specially in terms of keeping acceptable integrity parameters during operations.

The methods described on the present article are dynamic operations developed case by case, with the available means, to efficiently clean the production networks. The methods are the so-called diesel soaking, effluent soaking, and gas top-up. All the methods use the shear effect caused by the presence of a viscous fluid and a high velocity gas flow.

The production lines cleaning effectiveness was compared in terms of oil gain, fouling factors reduction, flaring events duration during cleaning operations and improvement of energy efficiency of the plant. The savings with OPEX were also mentioned. Differently from what has been suggested before, it seems that the presence of a high velocity flow is the most important parameters when speaking of cleaning by dynamic methods.

This article proposes an improvement on previous works proposing dynamic methods to clean wax deposits. Here suggesting methods that can be used for cases where a service network is not available for cleaning, yet, obtaining the same gains.
Fixed AI-Powered Imaging for Automated Leak Detection on Offshore Production Platforms
Authors: McKay Mike , Bansal Gurjeet , Ahmed Tariq
Published: April 2022

At the request of a major offshore producer in Thailand, an analytic edge-based leak detection vision technology was developed and implemented. The solution was the result of modifications made to an onshore system that was engineered in collaboration with a midstream operator and has been proven in various aboveground facilities and other industrial monitoring applications. One of the key changes involved making the product explosion-proof (Ex).

The modified AI vision system addresses 1) the unique challenges of offshore platform environments (remoteness, harsh climate, network limitations, and high safety risks), and 2) customer coverage requirements: continuous, autonomous monitoring of distributed assets with automated detection and alarming on early-stage leaks and/or leaks of a particular size. Aside from leak detection, the system can also be implemented for exhaust vents monitoring prior to well pad remote start up, fire detection and other applications.

It is anticipated that the solution will deliver the benefits and advantages intended by design as well as those that were gained by onshore operators with the use of the original AI leak detection vision system. These include higher operational efficiency, improved event detection and alarm validation capabilities, enhanced automation (e.g.: remote shutdown), up to 90% workload reduction as a direct result of significantly lowered false alarms along with 50% decrease in monitoring related costs and site visits.

The success of the first installation in 2019 was followed by system deployment at additional well pads, with continued expansion planned. The growing demand and the positive experience with the technology together demonstrates the viability, value and potential of artificial intelligence powered cameras for remote monitoring of offshore platform assets and processes.
From Laboratory to Field Applications: A Safer Gas Hydrate Dissolver to Replace Methanol
Authors: Sayed Mohammed , Saini Rajesh , AlAli Eyad , Kalgaonkar Rajendra , Arnous Ahmed
Published: April 2022

Low-molecular-weight hydrocarbon gases, such as methane and ethane, along with other low-molecular-weight species, such as CO2 and H2S, exist within the gas stream flowing through the pipelines used to transport natural gas and crude oils. Under certain conditions of low temperature and high pressure, and in the presence of free water molecules, gas-hydrate crystals will start to form. These gas hydrate crystals may accumulate and cause partial or complete plugging of the pipeline in the vertical or horizontal sections of the pipe. Methanol was previously found to be the only effective chemical able to clear gas hydrate plugs in many cases. The low flashpoint of methanol makes it unsafe to be pumped or stored in large volumes in hot regions such as in the Middle East. The main objective of the current work is to develop a safer chemical treatment with a higher flashpoint for the dissolution/mitigation of in-place gas hydrate plugs in pipelines.

The parameters that make methanol an effective hydrate dissolver were investigated before development of the new hydrate dissolver. Methanol has a very low freezing point (-90°C) and is completely miscible with water. Solvent-based and aqueous-based formulations were chosen while considering parameters such as miscibility with water, freezing point, viscosity, and availability. The performance of these formulations was evaluated using a see-through gas hydrate cell. Pressure and temperature were modified to allow the formation of hydrates at simulated field conditions. Representative gas and water compositions were used in the experiments to form gas hydrate inside the gas hydrate cell. Hydrate formation can be detected either by detecting the change in torque on the stirring shaft or by visual inspection of the cell. The performance of these formulations was evaluated and compared to methanol.

Two solvent-based formulations and two aqueous-based treatments met the flashpoint requirement and were effective in dissolving hydrate plugs at similar dosage when compared to methanol. These formulations proved to dissolve gas hydrate plugs in similar or less time than methanol. Two field trials were conducted to test one of the aqueous-based treatments and the outcome showed that the hydrate plug was dissolved in less than 17 minutes from the moment the aqueous solution was injected.

The tested formulations have been shown to not only work as a dissolver, but also as an inhibitor to prevent the fresh formation of hydrate downstream. In addition to improving the performance of dissolving gas hydrate plugs in the pipelines, the use of these treatments has enabled safer operations in the field.
Integrated Active Heating and Subsea Boosting Technologies to Unlock Long Tie-Back Reservoirs with Flow Assurance Challenges
Authors: Jez Radoslaw , Eretveit Ragnar , Lazarczyk Michal , Ejma-Multanski Jakub , Vivet Romain , Liszka Michal
Published: April 2022

Subsea oil and gas production can utilize a number of technical solutions to ensure efficient and cost- effective operation. There are two main technologies applied to address flow assurance challenges in case of particularly long tieback reservoirs: subsea active heating and subsea boosting. The production from distant reservoirs with challenging flow assurance conditions may require application of both mentioned systems. In such case, one challenge relies on the selection of a power supply infrastructure for both systems, considering all possible optimization aspects.

In the conventional approach, the implementation of both systems is realized independently. Subsea active heating system and subsea boosting system are supplied and monitored from topside by the separate power strings. However, the development of subsea technologies allows to review the approach and consider integration of both systems, enabling reduction of topside infrastructure for general cost savings.

The purpose of this article is to present the integrated system composed of Electrically Trace Heated Pipe in Pipe (ETH-PIP) and subsea boosting pumps where Variable Speed Drive (VSD) is required. The role of both system is shortly presented. Next, a proposal of an integrated power system for subsea heating and boosting is illustrated and discussed on a case study example. The analysed field layout is characterized by a long tie-back to a production facility where both subsea boosting and active heating systems are necessary operating in the relevant power modes. The results of analysis allow to conclude that the presented solution can be valuable alternative to traditional approach of complex subsea system topologies.
Floating Wind Power Cable Installation with Lazy Wave Configuration Both Ends Set Up
Authors: Patrick Belenfant , Julien Boucard
Published: April 2022

The floating wind industry requires dynamic 66kV inter array cable to be installed and hooked up to the floating structure on both ends. While first end lazy wave initiation is a common practice, the scope focus on 2nd end lazy wave installation to obtain the final configuration according to max design excursion of the floater and temporary measure to be taken.

The inter array cables are preset cable length with end termination which are either design for short term subsea or long term subsea storage. For the floating wind turbine, the 2nd end cable requires to be inserted into I-tube with specific arrival angle and a lazy wave configuration compatible with extreme design excursion of the floater (circa 30m). The Windlfoat Atlantic 2nd end required cross haul to the I tube while keeping sag bend well above seabed, with no uncontrolled contact. Temporary buoyancy module was connected to lazy wave to achieve this transient configuration, maintaining the operating radius of the power cable, with correct I-tube entry angle. For Windfloat floater design, the I.tube are disconnectable from the floater and is self standing in case of disconnection of floater.
Project Execution of Industry First 20,000-psi Subsea Production System
Authors: Pollak Joshua Brian , Pathak Parth Dilip , Weaver Clint David , Gaydos Stephen Erek , Stevens James Edward , Katsounas Nicholas Paul , Penuela Diego Alejandro , Baptista Alessandro , Kaleemullah Hunnain , Watne Karl Johan
Published: April 2022

High-pressure high-temperature (HPHT) oil fields in the Gulf of Mexico demand upstream subsea production system (SPS) equipment such as trees, connectors, and manifolds rated for 20-ksi or 400°F. This paper covers the project execution of production equipment for the world's first developed 20-ksi subsea field. This paper includes introduction of new technologies, digitalization efforts, and challenges encountered during the development, manufacturing, and factory testing of this equipment.

The development phase of the project began as a multi-year joint venture between OEM and energy companies. This phase included API qualifications and design of core components to industry guidelines such as API 17TR8. Digital analysis tools such as computer-aided design and 3D modeling and tolerancing (CAD and CATS), structural and fatigue analysis using finite element methods (FEA), simulated assembly and operation of equipment in a virtual involvement, and integrated multiplatform optimization software were leveraged for rapid final product development with minimal need for physical testing. To push design ratings to HPHT levels, it was necessary to implement new patented technologies into the design such as couplers, seals, tooling, and lockdowns.

The equipment-build phase included upgrading involved plants to state-of-the-art manufacturing and testing facilities. New processes were developed such as using custom fastener pre-load equipment, ultrasonic inspection methods, virtual-build simulations, and new high-pressure test cells with automated remote monitoring and testing capabilities. Subsea deployment of this equipment is planned for 2023.

Production systems rated to 20-ksi were built and tested for the first time. New technologies and processes were successfully integrated and validated in an overall assembly. Higher capacity systems introduced new failure modes. The general strategy for HPHT component design is to leverage existing, lower capacity designs but to make the geometry bulkier and the material stronger. A second strategy for design is to reduce the overall loads by reducing pressurized areas, pressure balancing, and offsetting weights. Both approaches lead to new challenges such as weight management, material failures, material sourcing difficulties, seal failures, size restrictions, industry requirement interpretations, cost requirements, assembly complexity, and safety considerations. Development of equipment for 20-ksi fields can be completed in a safe and sustainable manner.

The paper presents challenges faced at each stage of project execution and solutions to those challenges. Further, the paper showcases new patented technologies and processes introduced into the system.
Above Ground Risks - Recognizing and Managing its Impact to Project Value
Authors: Zainal Abidin Mohamad Adib , Lot Hasnor , Husain Darwis
Published: April 2022

While industry players are well-versed on "below-ground" risks, the treatment of "above-ground" risks has yet to be fully explored and properly used in making investment decisions. To address this deficiency, some authors have proposed adjustments to the discount rate. Others have adopted the use of Horner's pseudo-rate. And yet others have recommended the application of an "attrition" rate to the cash flows. There have also been suggestions to use probabilistic approaches to cater for risks. This paper examines the concepts and methodologies proposed to address above-ground risks. The advantages and disadvantages of each method are discussed.

Objectives/Scope

Many ventures sanctioned at certain investment decision stages were later found to be technically challenging to implement and economically less profitable than had been anticipated. Brashear et al. reported that in the 1990s the average return on net assets by oil majors was only 7% compared to their promises of surpassing the hurdle rate of 15% (Brashear et al. 2000). Among the reasons contributing to these ventures being under-performing may involve perception of above-ground risks and their treatment.

Methods, Procedures, Process

Most companies have a good understanding in dealing with project risks through the use of multiple-level technical data sets scenarios with deterministic approach. As for above-ground risks, there are several ways oil majors have addressed them 1. Discount rate adjustment 2. Adoption of Horner's pseudo-rate and 3. Incorporation of attrition rate in the cash flow.

Results, Observations, Conclusions

The proposed attrition rate method (Method 3) will provide comfort to decision makers on the impact of above-ground risks. From the business case shown, the project economics indicators IRR & NPV@10% have changed from the initial assessment of IRR = 15% and NPV@10% = US$ 214 mil to the risk-adjusted IRR = 11% and NPV@10% = US$ 22 mil.

Novel/Additive Information

Recognizing above-ground risks and managing their impact early on through the proposed approach will enable decision makers to exercise proper techno-commercial judgement on project viability and make informed decision on its attractiveness, thus, safeguarding project value.
Fracture Interference Effect on Shale Well Performance, RTA and Numerical Simulation Workflow with Economic Analysis
Authors: Ibrahim Ahmed Farid
Published: April 2022

The cluster spacing was considered up to 700 ft in Barnett and Bakken shale formations. At this time, tight cluster spacing has been used up to 15 ft apart in Eagle Ford and DJ Basin. The drive for applying tight fracture spacing is to increase the initial production rate. However, a higher initial production rate is at the expense of higher operation and completion costs in addition to operational complexity. This study presents an integrated workflow to investigate the effect of cluster interference on well performance. Analytical rate transient analysis (RTA) was combined with reservoir numerical simulation to calculate the effective fracture surface area for hydrocarbon production. The ratio of the effective fracture surface area from RTA analysis to the actual stimulated fracture area from the numerical simulation will be correlated to the cluster spacing. The economic study was added to investigate the optimum spacing based on the profitability of the well. The results showed that the well with a higher stage number and tighter cluster spacing will have high cluster interference with low effective to actual fracture surface area ratio. In addition, the well will drain the production area near the wellbore faster with the high initial production rate but with high production declining rate. Increasing the cluster spacing, with the same injected proppant volume, shows an increase in the effective to actual fracture surface area ratio, and low cluster interference. A lower initial rate was observed with a low production declining rate. From the economic study, spacing of 60 ft was found to be the optimum spacing based on the formation properties, capital cost, and gas price. As the interest rate and gas prices increases, or low capital costs, the optimum completion tends to be with tighter spacing to accelerate the production. The results from this study will assist the completion and help reservoir engineers to optimize the cluster spacing to maximize the well revenue.
Smart Safety Management Systems: Leveraging Blockchain Technology for an Effective Safety System in Oil and Gas Industry
Authors: Laskar Sandipan
Published: April 2022

In last decade the oil and gas industry gradually adopted new innovative technologies and began shifting towards intelligence and digitalization. Emerging Technologies such as the autonomous car, Blockchain and the Internet of Things are playing a more vital role in improving efficiency and effectiveness in many businesses around the globe. Presently blockchain technology applications are more focused around financial and data security sectors. There exists a tremendous opportunity to leverage blockchain technology and explore possible applications in oil and gas. This paper focuses on blockchain technology and answers three basic questions (why, what and how) related to application of blockchain technology and use of distributed ledgers to leverage safety management systems.

The novel methodology mentioned in this paper could be used extensively to develop consistent company best practices thereby improving health and safety performance in oil and gas and other related sectors. In addition to the increased efficiency, the Safety Management System section provides a company with an effective tool for designing, developing and implementing a safety management program that helps to be in compliance with regulation. Additionally, it will provide a basis for safe process operation, production and facility equipment reliabality.
Factors Controlling Water-Steam Flow in Fractured Reservoirs: Application to Enhanced Geothermal Systems
Authors: Zheng Shuang , Sharma Mukul Mani
Published: April 2022

A model for the flow of water and steam in a fractured geothermal reservoir is presented. The flow is coupled with thermal processes and phase behavior in the reservoir and fractures using the pressure-enthalpy formulation and water-steam phase behavior. Both an implicit pressure, explicit enthalpy and a fully implicit solution algorithm have been developed. The model is validated with analytical solutions. The model is then used to demonstrate the factors that control the heat extraction rate from enhanced geothermal systems (EGS). It is found that injection rate, fracture spacing, well spacing, and effective fracture surface area have the biggest impact on the heat extraction rate. Heat conduction is the main contributor to the heat flux while convective fluid flow does not contribute much when the reservoir permeability i.e., the rate of gravity driven convection is low. The heat flux from the earth does not affect short-term EGS production but can be an important factor for long-term EGS development. The general, 3-D, multi-phase, geothermal reservoir model presented in this paper can be used to optimize and design EGS in geothermal fields (fracture spacing, well spacing, injection rate, etc.).
The Environmental Benefits of Offshore Platform Structural Optimization
Authors: Li Zhongwei , Wang Aimin
Published: April 2022

The objective of this study is to provide an approach to quantify the environmental benefits of the structural optimization in offshore platform design. As the interest in Environmental, Social and Governance (ESG) has surged among investors and corporate stakeholders, the offshore industry will be able to use the quantitative calculations to demonstrate the effort in addressing climate issues.

Offshore platforms are usually constructed in the yards in East Asia and towed to the installation sites in the Gulf of Mexico, Asia Pacific, Europe, or West Africa. The carbon dioxide emission (CO2) starts from steel production and continues in the construction, transportation, and installation. The environmental impact is measured quantitatively for the structural steel of offshore platforms during its life cycle up to the installation. Three optimally designed offshore platforms are compared with nearly thirty offshore platforms to quantify the reduction of greenhouse gas emission by structural optimization.

The study shows that the optimized offshore platform designs significantly reduced carbon dioxide emission and other environmental impact. The quantified results are comparable to other measures addressing the climate issue. The awareness of ESG has posted additional challenges to the offshore industry. For example, Harvard University has decided not to invest in fossil fuel industry. Recently, ExxonMobile board was challenged by shareholders to address the climate issue. While providing important contributions to the economy and energy demand, the offshore industry needs to embrace the challenges and show the focus on ESG. In the past, structural optimization is usually not prioritized or only for cost and performance objectives of having less material purchase and more payload. Now using the quantitative approach to calculate the reduced environment impact from structural optimization, the engineers will have additional incentives to carry on structural optimizationregarding ESG. The same approach can be applied to designs related to renewable energy like offshore wind turbines to show the benefits in ESG from structural optimization.

The quantitative measures to calculate the environmental benefits of reducing structural weight are provided by this study for the offshore industry. This important tool enables the offshore industry to show the emphasis on ESG to investors and stakeholders starting from the engineering design stage.
How to Improve the Benefit of Greenfield Development – Case Study of an Offshore Marginal Oilfield
Authors: Shi Hongfu , Cai Hui , Xu Zhongbo
Published: April 2022

Well-known offshore oil-gas-bearing basin such as the Gulf of Mexico, the North Sea, and the Bohai Bay has entered the middle and late stages of development, which can also be called the mature stage. As a mature petroliferous basin, there are always two sides to everything. Taking the Bohai Bay Basin as an example, six major regional oil production areas have been built in the basin. There are stable logistics links between the regions, including natural gas pipelines, power transmission, Floating Production Storage and Offloading (FPSO) sharing, and mature onshore oil and gas processing terminals. However, the oil and gas exploration in the Bohai Bay Basin has entered the late stage of its peak, and the discovery of giant and large oil fields is becoming more and more difficult. Many low-quality medium and small oil fields have been discovered. Under the current economic conditions, development technology and tax policies, the development of such oil fields is not profitable, so it is called marginal oil fields? How to develop such small and medium oil fields cost-effectively is one of the biggest challenges. This paper expounds that the development of green maiginal oil fields is promoted through multi-disciplinary cooperation and innovation, case stuy of maiginal oil field in Bohai Bay.
Scale-Up and Modeling Efforts Using an Omniphobic Surface Treatment for Mitigating Solids Deposition
Authors: Brown Erika , Pickarts Marshall , Delgado-Linares Jose , Qin Hao , Koh Carolyn , Thapa Sumil , Matthew Nakatsuka , Veedu Vinod
Published: April 2022

Gas hydrates, waxes and asphaltenes represent some of the most significant flow assurance challenges, especially in subsea lines, where treatment options can be limited. Currently, complete avoidance is the primary strategy for hydrate management, while chemical or mechanical flushing/pigging may be utilized for other solids. Each system must also be treated with individualized solutions, as there have been no proved one-size-fits-all technologies demonstrated to date. As an alternative to constant chemical injection or thermodynamic controls such as insulation or heating, a robust omniphobic surface treatment material has been developed which has been shown in previous studies to significantly reduce the adhesion of flow assurance solids, resulting in lower risk for deposition and plugging of gas hydrates, waxes, and asphaltenes. As part of a Department of Energy study, laboratory scale tests were performed on a variety of apparatuses ranging from micromechanical force (micron scale) to laboratory flow loop testing (meter scale). While the results from these tests have been promising, there can be some disconnects between lab-scale observations and field-scale testing.

Several factors can result in discrepancies between small-scale bench-top studies and deployment-scale efforts. These include flow conditions (Reynolds number, flow regime), chemistry (synthetic vs. crude oils, gas composition, and additives), physical differences (pipeline material, size, and geometry), etc. This work will describe the actions taken to better understand the deployment and performance of a material such as this omniphobic surface treatment in field scenarios, and to build confidence for deployment in a production scenario. These efforts include modeling field production scenarios using models developed from lab observations, application of the material to field-scale equipment to better understand application challenges, and expanded survivability and longevity testing. Understanding the bridge between laboratory testing and full-scale deployment allows for better technique and risk mitigation for field scale testing.
Proof-Of-Concept: Subsea Dehydration Using TSA Adsorption
Authors: Rondon Marianna , Khabzina Yoldes , Orsikowsky Alejandro , Laudet Jean-Benoit , Zhao He , Perraud Olivier , Gyllenhammar Emil , Kolbu Jostein
Published: April 2022

In the current energy transition scenario, gas represents one of the main pillars for a greener energy mix. In 2015, we presented two promising schemes to produce a challenging notional gas field located 2500 meters water depth and 300 km from shore using only subsea processing [1]. The first scheme consists of subsea gas/liquid separation, gas compression and liquid boosting for multiphase export to shore; the second, developing a subsea high-pressure dehydration system for up to 300 Bara, using adsorption, to avoid the use of a monothylene glycol (MEG) loop and export dry gas directly from subsea. Performance of desiccants at such high pressure has not been studied thoroughly and qualification was necessary.

This paper presents the proof-of-concept of a subsea dehydration technology at high pressure. Several criteria were used to evaluate the potential technologies: treatment performance, power consumption, production at varying pressure, sensitivity to feed contaminants, CAPEX, OPEX, weight & size, among others. The preferred solution was concluded to be temperature swing adsorption (TSA).

Once TSA was selected as the most promising dehydration technology, different laboratory tests were performed and several parameters were identified to screen the potential desiccants: adsorbent working capacity, water/CH4 selectivity, water adsorption energy and regeneration temperature.

Finally, a pilot was built and a test matrix was run in order to prove the concept.

The adsorption, and specifically a TSA Process, was the technology selected in the first part of the study. The choice was based mainly on the energy efficiency and the technology readiness level. In the second part of this project, the feasibility of the process at high pressure (up to 300 Bara) and its application subsea were proven through experimental tests performed at a laboratory pilot.

Characterization tests and water and methane adsorption/desorption isotherms are briefly presented. Based on these results, zeolite, alumina and activated carbon adsorbents were identified. Finally, complete adsorption/desorption cycles at different pressures and temperatures were performed, proving the concept and its potential.

This is the first study proving experimentally the concept, and presenting the potential, of the TSA Process for subsea dehydration at high pressure. This is one of the subsea processing building blocks identified in many gas field architectures and it is especially required to produce remote and deep reservoirs at competitive costs.