bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.
Downhole Mineral Scale Dissolution Booster
Authors: Jiang Li , Stewart Suzanne , Abbott Jonathan 
Published: April 2022

Abstract
Mineral scale formation in the wellbore represents a widespread and serious threat to flow assurance and ultimately to well productivity. Scale formation is generally attributable to the incompatibility between reservoir and injection waters and the main mineral scale types include carbonate, sulfate and sulfide salts of divalent cations. Currently available scale dissolvers for the latter two types are often based on chelating ligand chemistry, restricted by a kinetically sluggish process of displacing the cations plus near static scale-fluid interface at the scale surface area in downhole scenarios.
We wish to report two newly generated material developments aimed at accelerating downhole scale dissolution treatment performance by using either or both: Discrete surfactants able to encapsulate entrained gases in the form of micro- and nano-bubbles that migrate in the fluid body along the pressure differential.Gas generating reactions catalyzed by freshly produced divalent cations at the scale-fluid interface.
It has been demonstrated through systematic, lab-based proof of concept tests that these minor additives can promote interfacial mass transfer of both reactant and products as such that some of the current physical and engineering challenges of downhole mineral scale treatment can be circumvented, resulting in remarkably enhanced scale dissolution rates. Further increase of scale dissolution rates can also be achieved by the inclusion of a genuinely sustainable biosurfactant which, at certain concentration range, can effectively remove any hydrocarbon coatings that might have saturated the mineral scale surface, hence eliminate the often-hazardous organic solvent based preflush.
In addition to the aforementioned example, it is believed that the methodology reported in this manuscript can also be applicable to enhance other chemistry oriented downhole treatments where mechanic agitation is not viable.
Produced Water Management; Case Study
Authors: Mahmud Walid Mohamed , Elmabrouk Saber Kh. , Abdussalam Omran Elhamali 
Published: April 2022

Abstract
Lined evaporation pits are a common way to dispose produced water, especially within hot climate where there is an absence of rainfall and high prevailing evaporation rates. Produced water generated through the separation of crude oil within this case study has been, for many years, disposed into evaporative pits. However, the historical use of unlined pits for the disposal of produced water has a high potential to result in soil and groundwater contamination and may cause severe harm to the environment due to hydrocarbons, residues from process chemicals, heavy metals and naturally occurring radioactive material (NORM).
The area of the present study is an open flat desert environment that receives no rainfall and is exposed to strong sunlight and high temperatures. The facility management commissioned a study to identify applicable disposal options of produced water and generate capital cost estimates for each option. Options considered must have constituent of the produced water and the concentration of the dispersed oil in the water within acceptable regulatory limits for inland discharge besides being environmentally friendly.
Two disposal options were developed, with each generating different levels of produced water management and utilization. Facility management was able to use and implement the results of the study to which obtained an excellent outcome and reduced the estimated cost of produced water disposal requirements.
The study presents impact assessment of long-term disposal of produced water and the environmental remediation of historically contaminated areas. The study also provides the best technically viable options to utilize and dispose produced water.