bluuebunny/crossref_metadata_2025_split huggingface dataset:
Best Practices for Handling Completion Tubulars to Ensure Design Life Well Integrity in HPHT Wells
Authors: Angelle Jeremy , Alleman Neil 
Published: April 2023

Abstract
In the search for attractive hydrocarbon resources, geological targets are often encountered that are designated as high-pressure, high-temperature (HPHT). To ensure an HPHT well meets or exceeds design life, a very thorough design review is needed for all aspects of the well architecture to ensure integrity is maintained throughout. Often overlooked, improper handling and installation through lack of knowledge, equipment selection, or technology have led to many well integrity issues in HPHT wells.
The presence of certain corrosive downhole species, combined with the high temperatures and pressures of these wells can accelerate corrosion mechanisms on well bore tubulars at an early stage of the well's life. To address this challenge, corrosion resistant alloy (CRA) tubulars, along with temperature and pressure monitoring equipment, are often designed into the well architecture to ensure well integrity is preserved. These elements must be handled and installed carefully as impressions, marks, and cuts from make-up and handling operations can further accelerate corrosion failures on the tubular, such as stress corrosion cracking, while compromising the integrity of the downhole measuring equipment.
To ensure these wells have the best chance of meeting target design life, special consideration should be given to the control line and tubing handling equipment. Specialized equipment, such as control line manipulation systems, offer extra protection to lines as they are manipulated for clamp installation, as well as increased safety and efficiency within the operations. Compensation systems prevent damage to threaded connections during stabbing and make-up while intelligent connection analyzed make-up systems use artificial intelligence and machine learning to provide real-time accurate, consistent, and reliable connection integrity assessments. And lastly, specialized reduced penetration or non-marking technologies can be utilized for make-up and handling of CRA tubulars to minimize or eliminate iron transfer and impressions imparted into the tubular body. By eliminating these, the potential for corrosion cracking due to stress concentrations and other risks of corrosion are also eliminated. One industry sponsored study examined the condition of 406 injection and production wells on the Norwegian shelf. Of these wells, 18% of the wells suffered from well integrity incidents, while nearly 40% of these incidents were due to the tubular string, emphasizing the need for specialized attention and equipment selections for HPHT wells.
Partial Electrification of an FPSO Operating in the Brazilian Pre-Salt Region
Authors: Tee Ping Hong , Nguyen Hung Viet , Rinezry Wan Irfan 
Published: April 2023

Abstract
The oil and gas industry would never have imagined that the full electrification of floating, production, storage, and offloading (FPSO) units would be plausible one day. Fast forward to today, we are currently progressing towards an era that will inaugurate full electrification of an FPSO in the Brazilian waters by the end of this decade. The idea is to challenge the norm of replacing all gigantic gas turbines with electric motors and power the entire FPSO, a big step towards decarbonising the FPSOs.
However, the industry needs immediate solutions towards optimising fuel efficiency and curbing emissions as the full electrification method was not viable previously due to several reasons such as limits from local regulations on power plant sizing. Therefore, rather than solely focusing on the conceptual design of full electrification, several recently contracted FPSOs had incorporated a partial electrification concept that maximise electricity usage to reduce emissions, resulting in the first proven concept for the partial electrification of FPSOs.
The main goal of this paper is two-fold; First, to discuss the main features of a Partial-Electric FPSO currently contracted to operate in the pre-salt region of Brazilian waters that turns conventional loads into motorised loads. Several decarbonisation efforts implemented via reduced emissions and advanced monitoring tools will also be discussed for the Partial-Electric FPSO that is under construction in the shipyard at the point of this paper being published.
Second, to present the new technologies and concepts that the next generation of FPSOs can adopt in the process of transitioning into the full electrification of FPSOs, which mainly focus on the combined cycle power generation (CCPG). With the implementation of partial electrifications and new technologies like CCPG, this will prepare the FPSO industry ahead of the 1.5-degree target, and at the same time paving the way for the development of greener FPSOs.
What is Learned from Polymer Flooding Practices in Offshore Reservoirs?
Authors: Guo Hu , Wang Zhengbo , Dang Sisi , Wen Rui , Lyu Xiuqin , Liu Huifeng , Yang Meng 
Published: April 2023

AbstractPolymer flooding is very promising chemical enhanced oil recovery technique because it has been widely field tested in many oil fields and commercially applied in several countries in onshore reservoirs. The understanding of polymer flooding mechanisms is still developing, even though the principal mechanism was sweep efficiency increase due to reduced mobility ratio of water and oil due to reduced mobility of water. The incorporation of polymer flooding mechanisms and practical challenges make some projects fail to attain economical or technical goal. For offshore reservoirs, the polymer flooding becomes more difficult because of limited space and harsh reservoirs. Although there were hundreds of polymer flooding field tests in onshore reservoirs, polymer flooding in offshore reservoirs remains limited. In this paper, the previous onshore polymer flooding lessons and findings were briefly reviewed to look into the mechanisms which can guide the design of polymer flooding in offshore reservoirs. Then, the lessons learned from previous offshore reservoirs were reviewed. Advices were given to improve the field test performance. it is conclude that low concentration polymer solution with moderately-low viscosity should be injected into offshore reservoirs to keep displacing pressure between injectors and producers. The injected polymers should have good transportation ability which avoids the formation blockage. The optimum injection timing remains to be further investigated because the evidences. The injection rate should be controlled to avoid well casing damage which has been observed in onshore reservoirs. Except for Bohai oilfield, the formation blockage was not reported in offshore reservoirs. However, the microfracture can form in injectors which improved the injectivity of polymers as long as the injected polymers have good transportation capacity.
Saline Aquifer Characterization For Subsurface Co2 Sequestration: An Example From The Miocene Offshore Texas
Authors: Fick Alex , Halder Sougata , O’Reilly Cian 
Published: April 2023

Abstract
Understanding the subsurface and accurately mapping geologic elements necessary for CO2 storage and containment are essential components to any successful sequestration project. Currently, the most appropriate tools the industry has at its disposal for subsurface characterization is legacy oil and gas borehole data and seismic reflection surveys. These data have been used as the means to characterize subsurface geometries, lithology, reservoirs and seals, temperature, pressure, and other rock properties critical in assessing the likelihood of hydrocarbon accumulations. These same subsurface elements are just as critical now in identifying and characterizing potential CO2 storage locations. To date, two different CO2 subsurface storage scenarios have been proposed. One would be the utilization of depleted existing hydrocarbon fields, where geologic elements are known to be sufficient for trapping oil and gas. While some geologic risks are more certain in this scenario, numerous engineering and other geologic uncertainties such as seal integrity due to numerous penetrations, improper plugging and abandonment practices, unknown casing conditions and improper materials downhole for handling concentrated CO2 present themselves. The second route is sequestering CO2 in saline water saturated formations, off structure or above and beneath oil and gas reservoirs. Modern stratigraphic test wells would be needed to fully de-risk storage sites, but within every sedimentary basin onshore and offshore in the US, sufficient subsurface data exists to evaluate the stratigraphic column and identify play fairways for CO2 storage. In this paper we show the results of an example workflow from offshore Texas, integrating well log and seismic interpretation to map and characterize multiple Miocene horizons and assess their maximum and minimum case storage capacities. Multiple prospective saline formations have been characterized using wireline logs and cuttings descriptions from over 500 offshore wells and a dense grid of 2D seismic data. We demonstrate how the relevant reservoir and structural parameters can be efficiently mapped to identify multiple storage play fairways along the Texas coast in state and federal waters which will be critical to understand in prospecting for CO2 sequestration projects.
Fixed Wind Architecture Comparison for Offshore Green Hydrogen Production
Authors: Pliszka Dominic , Gourlay Catherine , Abdullazada Nihad , Brice Christophe , Bouras Nouzha , Lesort Anne-Laure , Ott Jorge , McWhirr Caragh , MacLeay Alan 
Published: April 2023

Abstract
This paper is a summary of a study that covers through-life economics for producing green hydrogen from offshore fixed wind turbines. The options compare production of hydrogen on the turbine itself (decentralised) with production on a dedicated production platform (centralised) and production from an onshore facility.
The economic analysis uses opensource hourly wind data from a windfarm development in the North Sea. The basis of calculation assumes a 1GW development using an array of 15MW turbines. The hydrogen infrastructure is sized at 80% of the turbine capacity. CAPEX, OPEX and revenue calculations are generated from data available to the partnering companies. Sensitivity analysis is performed to investigate the effect of tie-back distance (20,50,100 and 200 km).
The results of the economic analysis show that decentralised hydrogen production can be competitive against onshore production at longer offshore distances. The results of flow calculation will show typical pipeline sizes required for infield gathering and export pipeline systems. The results show that electrical system losses over longer distances and the additional costs of cables compared to pipelines have a significant influence on through life economics. The study will present the distribution of the various elements of the CAPEX and OPEX cost for each option as well as the sensitivity to hydrogen commodity price and indicate where it needs to be before these projects become viable. Furthermore, the study concludes that the centralised option is less competitive due to the additional costs of structures and foundations.
Vito Project: Vito Field Development
Authors: Sorgard Eirik , Oko Elizabeth Anne , Baird John Isaac , Greenaway Jason Alexander , Rabei Rob Ibrahim , Pillai Pradeep , Fresquez Stacy Marie 
Published: April 2023

Abstract
The Vito field is located in 4,100 feet of water producing from reservoirs nearly 30,000 feet below sea level. Vito was discovered in 2009 approximately 135 miles southwest of New Orleans, Louisiana. The project underwent major field development strategy change to remain competitive in 2015 oil price environment and price resiliency going forward.
The Vito project was seen as a strategic fit to the operator's existing Mars Corridor. The original Vito development strategy was to build a clone of the mega-project of Appomattox to maximize Net Present Value and Ultimate Recovery. However, as the market changed vastly in 2015, the project team refreshed the design concept to focus on capital efficiency.
This paper provides an overview of the overall revised Field Development Concept of Vito. Vito has best in class resource density when compared to other Gulf of Mexico fields, which allows for a compact field development of 8 subsea wells at a single drill center. This allowed the project to not include a drilling rig on the host platform and instead deploy a new generation Deepwater rig for drilling and completions. There is severe depletion drilling risk on Vito which led the project to drill and complete all 8 wells prior to first oil. To improve ultimate recovery with low capital efficiency in well bore gas lift was included in the design. In addition, the Mars Corridor export system was looked at and required debottlenecking on both the oil and gas side.
This paper is part of a Vito Project series at OTC 2023, and the other papers are listed in the references.
Axial Resistance of Drill & Grouted Well Conductors in Deepwater Clays Based on Operational Experience
Authors: Chen Jinbo , Cutrim Fabio S. , de Souza Charlton O. , de Souza Bruno SP. , Hu Shuang , Newlin Jason A. , Arturo Naisa VC. , Junior Nelson M. 
Published: April 2023

AbstractTypical deepwater wells in soft clay sites employ jet pipes as the well foundations, i.e., the jetted conductors. The jetting process during the installation of the conductors causes disturbance to the surrounding soil rendering the low axial capacity of the jetted conductors. An alternative well foundation to the jetted conductors is the drill & grouted (D&G) well conductors, in which case an enlarged hole will be drilled first and then the steel pipe is installed with cement pumped to the annulus to grout the soil and the steel. D&G well conductors have been successfully deployed in the deepwater Brazil Basins. The excellent field performance leads to the further refinement of the axial capacity model for D&G conductors. The objectives of this paper are (i) to calibrate the axial resistance model of D&G well conductors in deepwater soft clays based on field operations mainly in Brazilian pre-salt area, and (ii) to propose a new axial resistance model for D&G well conductors in deepwater clays for industry use. In this paper, information on 10 deepwater subsea wells was collected including the site-specific soil data, well schematics, and loading estimation on wells. Each of the 10 wells was analyzed and the maximum loading on the wellhead was compared to the theoretically predicted conductor axial resistance. Then a Monte Carlo simulation based on Bayesian updating technique was developed to calibrate the axial capacity model for D&G well conductors based on the field performance. This finding, supported by operational experience, can not only lead to cost-effective D&G conductors design, but also contribute to international industry guideline developments for D&G conductors design.
Subsea Lifting System for Deep-Seabed Rare-Earth Rich Mud
Authors: Kitago Ryuta , Naganawa Shigemi , Bjarkason Elvar Karl 
Published: April 2023

Abstract
Deep-seabed mud containing a high concentration of rare-earth elements, including yttrium, has been discovered in the western North Pacific Ocean near Minami-Torishima Island, Japan. However, production of the rare-earth rich mud is challenging because of its location at water depths of over 6000 m. We propose a new subsea lifting system for deep-seabed rare-earth rich mud. The lifting system consists of a small diameter marine riser and an inner work string. At the lower end of the work string, a hydraulic jet pump is equipped so that rare-earth rich mud slurry can be easily sucked from a sea-bottom mud collecting device and lifted through the riser annulus. The jet pump is driven with power fluid pumped from a floating mining vessel. To evaluate the suction performance of the jet pump and the flow assurance in the annulus, numerical simulations were performed for various kinds of power fluid rates and jet pump configurations. The simulation results suggested that the proposed lifting system could, in principle, lift slurry containing rare-earth rich mud continuously to a surface floating vessel. Also, the hydraulic jet pump mechanism could be optimized to maximize the suction caused by the Venturi depressurization effect and to achieve a commercially feasible mud lifting rate of 3500 ton/day. For a pump configuration with three pairs of diffusers and suction lines, a drive fluid flow rate of 700 gal/min was found to be sufficient to meet the economic production criteria.
API 17TR8 – HPHT Design Guideline for Subsea Equipment – A Focus on Fatigue
Authors: Skeels H. Brian , Shanks F. Earl , Hoshman Russell M. 
Published: April 2023

Abstract
API Technical Report 17TR8: High Pressure – High Temperature (HPHT) Design Guidelines (API 17TR8) contains detailed guidelines on design methodology, material property requirements, design validation testing of pressure-containing and pressure-controlling components along with special requirements for seals and fasteners when considering the effects of HPHT retained (wellbore) fluids passing through subsea equipment (HPHT defined here as internally operating above 15 000 psi (103.5 MPa) rated working pressure and/or 350°F (177°C) operating temperature). It has gone through two revisions since its inception in 2012, updating its contents as HPHT knowledge and experience in the upstream oil and gas industry has been accumulated. The 3rd edition focused on improvements to material characterization protocols and clarifying wording in its use as a design guideline. This paper focuses on the 3rd edition's update to fatigue screening/analysis to establish design methodology and material functional specifications for subsea equipment used in oil and gas applications. Observed issues and concerns around fatigue screening, when and where to use it, use of S-N vs. Fracture Mechanics, and updates to material characterization for different environments, and fatigue curve modification are discussed.
New Innovative Cost-Effective Methodology of Conducting Wells Surveillance Activities
Authors: Al-Ghamdi Ahmed , Alsana Mishal , Yateem Karam , Al-Dossary Faisal 
Published: April 2023

Abstract

Objective/Scope
This paper describes the second phase of sensor ball to retrieve production parameters downhole an oil well. Data retrieved from the sensor ball was compared to the conventional methodology; i.e. slickline. The paper also explains the advantages of using the sensor ball compared to the utilization of heavy equipment and the interlinked logistics and manpower.

Methods, Procedures, Process
Pressure and temperature surveys are required to measure the changes in the reservoir pressure and provide an image of the well downhole conditions especially for tubing and casing integrities. Conventional methodology of carrying out a basic surveillance activity for pressure and temperature surveys is through slickline work. A new breakthrough technology that was developed is the sensor ball, that is being used as a vehicle traveling downhole of the well logging data, such as pressure, temperature, casing collar locators and others under development. The second generation of the sensor ball has been successfully trial tested in live wells by dropping the ball freefalling then retrieved back to the surface.

Results, Observations, Conclusions
Data were retrieved, then crossed check with slickline data ran in the same well. This technology will provide great cost saving, especially on expensive offshore resources, avoiding the need for the barge to carry out simple jobs that can be replaced by the sensor ball, Moreover, the technology will be utilized to eliminate the risk of slickline activities. In this paper, technology, methodology field trial data will be shared with the rest of the industry.

Novel/Additive Information
This industrial revolution IR 4.0 technology is of paramount importance to the oil and gas industry. The easiness of the conveyance method will result in efficient and timely well surveillance. Therefore, the water cut of the oil wells can be controllable along with other parameters such as gas oil ratio.
Failures and Replacements – A Barrier to Growth in Offshore Wind?
Authors: Muren Jan , Jenkins Peter Erik , Froyd Lars 
Published: April 2023

Abstract
Everyone is used to seeing graphs predicting unprecedented growth for the offshore wind industry over the next decades. Whether or not these ambitious goals are achieved remains to be seen, as it will require nothing less than an industrial revolution in offshore construction and installation. Never have such growth projections been backed by a global sense of urgency, but unfortunately, it is not just the growth challenge that has to be met and resolved.
Data from insurance companies show a significant growth in financial losses in the offshore wind industry. For an expanding industry, an increase in insurance claims may be a result of the growth, however, even when normalizing the financial losses against industry CAPEX, number of turbines, or installed capacity, worrying trends are seen. For offshore wind to be a viable energy source in the future, the quality of design, installation and operation needs to improve significantly. Furthermore, the industry cannot continue to scale developments until it has overcome some serious reliability issues.
In offshore wind, we have seen how an extreme focus on reducing CAPEX in projects has led to low-quality engineering and choice of sub-standard products that are not fit for long-term applications exposed to dynamic loading in marine environments. Standardization is needed, reflecting the best insight, experiences, methods, and tools.
Although the challenges were never as extensive in oil and gas as in offshore wind today, the situation still resembles the quality and technology challenges faced by the offshore oil and gas industry some two decades ago. Many of the design challenges that have been overcome in oil and gas have been incorporated into codes, standards, and well-established engineering practices. Seen from a distance, the offshore wind industry experience similar trends. However, with the ongoing rapid growth, the learning and improvement processes need to be accelerated by leveraging the experiences from oil and gas. On the shoulders of a mature offshore industry and today's digital capabilities, standardization and up-scaling of offshore wind have better opportunities than oil & gas had 25 years ago. However, to leverage this opportunity a true life-of-field approach is required.