bluuebunny/crossref_metadata_2025 huggingface dataset:
A Subsea Oil Spill Response Solution for a Toppled Platform that has Been Leaking Oil into the Gulf of Mexico Since 2004
Authors: Hoffmann Dillon Raymond , Couvillion Timothy Michael , Kennelley Kevin James , Couch Walter Jack
Published: April 2023

Twelve miles off the coast of Louisiana a low probability high consequence event occurred in September of 2004 during Hurricane Ivan which resulted in a producing oil and gas platform being toppled over in approximately 470 ft of water and dragged off station approximately 600 ft. Twenty-eight oil and gas well conductors were buried beneath the mudline under sediment and have continually been discharging oil and gas into the Gulf of Mexico since the incident occurred.

In November of 2018, the United States Coast Guard partially federalized the worksite and solicited oil spill response proposals to design, build, install and operate a system to capture the ongoing release of oil at the site. The subsea RRS (Rapid Response System) solution that was proposed and built included a subsea collection device supported from the downed jacket lying on the seabed. The collection device was placed on a porch structure that was suspended off the jacket leg directly above four hydrocarbon plumes emanating from the seabed. The collected hydrocarbons were routed to a patented subsea separator that separates the oil from the water and gas. Oil is sent to subsea oil containment vessels located on top of the jacket and offloaded via hydraulic pump on a monthly basis to a surface vessel where the crude is then transported to shore and recycled.

The paper will discuss the design installation and performance of the subsea collection system over a span of approximately three years. The methods, procedures and processes that were utilized to design, build, test, install and operate this system in conjunction with safety protocols utilized in this oil spill response will be described as well. Since the system became operational in 2019 over 1,200,000 gallons of oil with less than 1% water has been safely collected and recycled from the site which would have otherwise been discharged into the Gulf of Mexico.
Numerical Investigation of Fatal Accident Involving Toppling of Hydraulic Workover Unit
Authors: Nardi Luiz Fernando Bermero , Braga Matheus Batista , Abreu Leonardo Teixeira Fernandes , Rodrigues Mario Sergio Magalhaes , Fonseca Ygor Alexandre De Aquino , E Medeiros Claudio Henrique Maia
Published: April 2023

In 2022, a Hydraulic Workover Unit (HWU), operating in Gulf of Mexico, toppled while being erected on a caisson. Photographs taken on site suggest that conductor casing lost stability, while submitted to weight of the HWU, combined with environmental loads. Since HWU activity is expected to intensify in Brazilian shore, Petrobras team decided to study this accident and prevent similar events from happening on its fleet.

A finite element model was constructed, based on photographic records of the accident site. The model was loaded with the expected weight on deck, as well as environmental loads (wind gusts and waves), calculated as per (DNVGL-RP-C205, 2014). Numerical simulations were performed to assess safety factors of operation, considering the 120 klbf weight-on-deck reported on the safety alert (BSEE, 2022). Operation was found to be safe, if weigh-on-deck is not exceeded, and conductor casing is integer.

A secondary batch of simulations considered several types of degradation that could incur to the workover unit, such as maritime corrosion and factory imperfections. Depending on the corrosion state of the conductor casing, safety factors were as low as 0.58, indicating high risk of catastrophic failure.

Simulations were replicated to Workover Units expected to be employed in Brazilian Coast. For these units, risk of catastrophic failure was found neglectable, while risk of excessive bending to wind gusts was found more likely. Preventive actions were suggested, concerning periodic inspection of installations and Personal Protective Equipment (PPE).
External Power Supply for Ultra-Deep Water O&G Assets: Synergies, Scale Effects and Challenges
Authors: Silva Daniel Fonseca de Carvalho , Freire Ronaldo Lucas Alkmin , Borges Gilcelia Carlos , Ribeiro Leonardo da Silva , Lemos Daniel Faro do Amaral , Marinho José Mauro Teixeira , Cavaliere Carlos André Carreiro , Matheus Caio Rabello Vaz , Passarelli Fabio Menezes , Musse Ana Paula Santana , de Oliveira Ana Margarida , Guimaraes Paula Silva , Malateaux Ezequiel Costa , Prunzel Paulo Frederico , Oliveira Felipe Silva
Published: April 2023

A dramatic reduction of greenhouse gas emissions in offshore oil and gas production facilities in the coming decades is foreseen, which will require profound changes in offshore electrical power supply. In this paper, several scenarios comprising offshore oil & gas production facilities were analyzed in terms of fluid production curves and primary processing plants schemes, so that power and heat demand are estimated. Assuming that heat remains supplied through simple-cycle gas turbines with waste heat recovery units like existing facilities, power importing margins were determined for optimum heat recovery in a number of offshore assets. Three low-carbon external power supply options were investigated: (i) Power from shore; (ii) Offshore power generation with post-combustion carbon capture and storage (CCUS) and (iii) Floating offshore wind. Results are analyzed in terms of technical feasibility, economic indicators and emissions reduction potential. The present study consists in evaluating and comparing the LCOE (Levelized Cost of Electricity) and emissions reduction of offshore oil and gas projects with power import alternatives. Practical limitations for implementation in brownfields for each scenario are discussed when presenting the challenges that must be faced. Scenarios comprising a wide range of external power supply capacity, and consequently many power import systems, were analyzed and compared. With production units far from the coast, importing power from the national grid may require a lower LCOE than implementing a power hub with CCUS, according to the results of this study, but the required investments (CAPEX and OPEX) are substantial, especially in brownfield projects where the upgrade to external power supply would be redundant with the already existing power generation system of the offshore facility. Additionally, floating offshore wind alternative, in turn, has restrictions because of the intermittent generation and relatively low capacity factor. Nevertheless, the results present some insights regarding the intercomparison among all alternatives to large scale offshore hubs connected to multiple offshore assets. Despite external power supply alternatives requiring substantially higher costs, it is expected for these costs to reduce in the near future with standardization of the required technologies. This trend can unlock opportunities to provide energy to additional subsea Processing & boosting, which may be the key to accelerate the adoption of external and low carbon power supply of O&G assets.
How Texas Can Become the Leader in Offshore Wind in North and South America by Using New Technology and Leveraging Existing Infrastructure and Expertise
Authors: Shelley Steffen Allan , Boo Sung Youn , Luyties William H. , Griffith D. Todd
Published: April 2023

Large fixed and floating wind farms are planned in the US, the first of which will come on stream along the East Coast, and then possibly followed by the West Coast in deepwater. However, there are other regions in North and South America, and even the Caribbean that are rapidly aiming for offshore wind farms. One of those locations, offshore Texas, may develop ahead of the West Coast by taking advantage of the unparalleled expertise in ocean engineering in Texas gained through over 40 years of offshore oil and gas developments.

In addition, Texas has regional competitive advantages that could result in another offshore boom for the region. Texas is the leading state for onshore wind power and consequently has some highly innovative research institutions and initiatives that could further push Texas to the forefront of regional, if not global, offshore wind technology development and deployment. The additional advantages that Texas can provide to wind farm developers based on its proximity to the Caribbean and South American offshore wind markets are also presented.

As an example of innovation in Texas, the University of Texas at Dallas, DOE ARPA-E (Department of Energy Advanced Research Projects Agency – Energy) funded vertical axis wind turbine (VAWT) development is summarized (ARPA-E, 2020). While elements of VAWT technology are transferable to horizontal axis wind turbine (HAWT) technology to improve HAWT performance, more generally, the deployment of VAWTs overcomes many logistical and performance problems inherent in deploying HAWTs offshore. Such VAWT advantages are discussed.

Two cases are presented comparing HAWT versus VAWT floating wind farms. The technology and execution differences of the two cases are compared and the net present value and internal rate of return are calculated conserving the technology differences. Discussion of forthcoming additional financing opportunities is also presented to illustrate how even in low-cost electric rate markets, offshore wind can still be feasible.
Advanced Analytic Tool Development for GHG Emissions Monitoring in Well Operations
Authors: Iorio Vanessa Silvia , Farina Daniele , Racca Stefano , Dal Forno Luca , Concina Fabio
Published: April 2023

In the global effort to reach near-term reductions in Green-House Gas (GHG) emissions, all Energy Companies have set an integrated strategy for a low-carbon future. The decarbonization target makes evident the need to also quantify the carbon footprint of well construction activities.

The major direct emission source in Drilling and Completion (D&C) is represented by the fuel burnt by diesel generators at rig site to feed tools, machinery, and auxiliary systems. Therefore, data related to fuel consumption are fundamental to have a clear understanding of rig carbon footprint. In this framework, a dedicated GHG module was introduced within an existing real-time advanced analytic tool to unlock the possibility to track and map the CO2 equivalent emissions associated to the fuel consumption of Eni's rigs.

This tool has been designed to collect and analyze the different data sources available at the rig site, typically sensor data, recorded at high frequency (1-5 sec), and reporting data, recorded at low frequency (1-2 hrs). The data are combined, with a specific algorithm, to automatically identify the activity ongoing and its related emissions. After that, data are gathered and consolidated to make them available in headquarters in near real-time. Furthermore, the tool was also applied to a case study by comparing its outcomes with the data directly provided by a rig contractor, showing a good level of reliability and consistency. The capability to monitor GHG emissions during D&C activities allows a better understanding of their related impact. It provides useful insights to implement corrective action and tackle them promptly. Finally, operation monitoring is directly linked with its related GHG emissions allowing new types of analysis and considerations.

This integrated tool, able to recognize the most carbon-demanding activities, optimizes the process of targeting suitable solutions for GHG abatements during the well construction process. Having CO2 emissions reduction become crucial, this approach will certainly be the backbone of the transformation that Oil & Gas sector will have to undergo to reach its carbon neutrality commitments.
Dynamic High Voltage Subsea Cables and Fatigue of its Components
Authors: Johanson Audun , Gjølmesli Elisabeth
Published: April 2023

Subsea cables plays a pivotal role in the offshore energy space. Increased expectations considering offshore renewable power production- or electrification requirements, represents primary drivers for continued innovation of dynamic cables. Larger transmission capacity- either by increased voltage or conductor cross-sections, increase the physical footprint of cable components or introduce completely new components in a dynamic cable context- Most notably a radial water barrier. Fatigue as a failure mode becomes an increasingly relevant and critical failure mode where the relevant mechanisms, material selection and environment differentiate from prior art. The scope of this work is to investigate fatigue as a failure mode in a state-of-the art subsea cable context, as well as highlight current technology level of high voltage dynamic subsea cables.
Electrically Heat-Traced Flowline on Aerfugl Phase 2 Project -Performance and Operational Feedbacks
Authors: Guy Mencarelli , Camille Pradeilles , Pierre Reboul , Per Forbord , David Gibson , Kenneth Vullum-Bruer
Published: April 2023

As part of the Skarv field development strategy, the Ærfugl phase 2 project is a ~13km tie-back requiring an electrical heating flowline to provide reliable and cost-effective hydrate management.

This paper will present the results of the in-field performance test and how they compare to the system intended basis of design then evaluate the operational advantages of such technical solution for an Operator.

In production since November 2021, the operational feedback on the highly insulated Pipe-in-Pipe associated to the Distributed Temperature monitoring System (DTS) and data gathered during the performance test at first shutdown are used to confirm the system thermal & electrical heating performances as delivered, compare against the intended design basis, validate the operational benefits of the system in both passive and active modes for the Operator and quantify the operational gains during production shutdown.

In close collaboration with the operator, the temperature monitoring data have been collected and processed to be correlated with the thermal insulation efficiency to validate the design envelop. In addition, several months of production feedback, it is demonstrated that the combination of the very efficient passive thermal insulation obtained using Izoflex in a reduced-pressure environment and a distributed temperature sensing system leads to reduced production risks and an increased operational flexibility

The performance test data of the electrical heating system confirming the design prediction is the ultimate demonstration of the readiness of the Electrically Heat-Traced Flowline at a project scale. This is a major achievement for such technology which thanks to its improved maturity level is confirmed as playing an important role in future subsea developments to safely increase production and provide operational flexibility with low carbon emissions.

This paper will show for the very first time on a sizable project the actual performance of an electrical heating pipe-in-pipe in conjunction with in-depth operational feedback on the use of a temperature monitoring system in a flowline. The associated operational gains for a particular case study are now demonstrated.
Remote Characterization of Produced Water via Subsea Multiphase Metering
Authors: Darab Mahdi , Røyset Ola-Marius Langelo , Nygaard Rune , Odai Lowestein , Singh Arvinder Paul
Published: April 2023

Multiphase flowmeters (MPFM) are used to measure oil, water, and gas volumetric flow rates in real time without phase separation. Field-proven MPFM play an important role in oilfield operations as the trusted flow measurements enable production optimization and flow assurance. However, accurate multiphase flow metering requires knowledge of the reservoir fluid properties. Therefore, operators require reliable methods to keep the MPFM configuration updated and representative of the production fluids. This is particularly important for subsea fields where physical access to the MPFM can be difficult.

This paper describes a successful remote water-phase characterization leading to reconfiguration of a dual-energy spectral gamma ray MPFM for an oil well in a deepwater field offshore Ghana. Reconfiguration of the MPFM was performed using data from when the well was shut in and the flowmeter venturi throat was filled with water at static flow conditions. The data was taken from Subsea Live data-driven performance service from OneSubsea (the vendor), which offers real-time data for health, operational and production insights for subsea assets. The mass attenuation coefficients for water were updated in the MPFM configuration to more representative values, determined using historical data. After the remote reconfiguration, the reconfigured MPFM demonstrated good accuracy when benchmarked against topside separator measurements, showing a proper agreement between the estimated in-situ values using historical flow metering data and the experimental measurements for both high energy and low energy water mass attenuation coefficients.
Offshore Industry and Research Community Collaborating to Enable Greater Ocean Access for Scientific Research
Authors: Olivier Blaringhem James , Woolgar Andy , Gates Andrew R. , Bishop Phil , Clare Mike , Flohr Anita , Sands Carla , Lichtschlag Anna
Published: April 2023

BORA Blue Ocean Research Alliance® aims to advance scientific knowledge of the ocean through integrating science into routine offshore operations and data collection, done in parallel to commercial work and as automated as possible. This can be through integration of novel sensors, deployment of scientific research equipment or through recognising where valuable data can be derived from other operational information. To achieve this requires deep understanding of the types of work carried out by each alliance party.

BORA Blue Ocean Research Alliance® is science focussed, increasing global reach for ocean observation into areas in which Subsea7 are operating. Fundamental to the scientific value of each project is to ensure that derived data are openly accessible and aim to meet FAIR data standards (Findable, Accessible, Interoperable, Reusable), so that the findings can be re-analysed in future or contribute to wider assessments of ocean health.

Building on the blend of Subsea7's global deep-water reach and the breadth of science of NOC, BORA Blue Ocean Research Alliance® is delivering new marine research on a global scale not possible before, from shallow to deep water, expanding knowledge for the benefit of society.
Low Temperature Geothermal for Offshore Use
Authors: Furtado Ivan , Robinson Roy
Published: April 2023

Geothermal energy is a baseload power generation system which uses the high temperature of the deep layers below the Earth’s surface. It has traditionally relied on very high temperature wells, usually at temperatures over 180°C, but no less than 100°C (Ref 5). The largest geothermal plant in the US, The Geysers Plant in California, uses steam that is over 250°C (Ref 4). The systems are costly and available locations limited by the depth required to achieve these temperatures. Using organic Rankine cycle technology much lower temperatures can be and are used to generate electricity. Ocean Thermal Energy Conversion (OTEC) famously runs on a 20°C temperature difference, with the hot side being about 25°C and the cold side being 5°C or colder.

This paper will provide a practical design and thermodynamic analysis of a system designed to run at no more than 100°C. This is a temperature that can be encountered at a reasonable depth onshore and offshore. In the Gulf of Mexico many of the legacy reservoirs are hotter than this (Ref 6).

Offshore we will also take advantage of the immense heat sink that is the ocean. The system will utilize well derived heat and cold water to run a power cycle.

It is expected that low temperature geothermal will be a practical source for offshore baseload power. One possible use is to power oil and gas platforms, which as they transition need green energy. Unlike wind offshore geothermal will not need battery backup, and once the field has played out, geothermal can then be used to supply power to shore or other nearby platforms.

Novel/Additive Information: The system will use both novel well configurations and a novel organic Rankine cycle system for power.
Machine-Learning-Based Proxy Modelling for Geothermal Field Development Optimisation
Authors: Otchere Daniel Asante , Latiff Abdul Halim Abdul , Taki Mohamed Yassir , Dafyak Longtong Abedenego
Published: April 2023

More than 40 billion tonnes of CO2 are released annually, hampering climate change efforts. The goal of current research is to utilise these gases in generating energy. The oil and gas industry faces increasing expectations to clarify the implications of energy transitions for their operations and business models, reduce greenhouse gas emissions, and achieve the Paris Agreement and Glasgow Climate Pact targets. A solution is integrating machine learning and geothermal energy to optimise field development to reduce CO2 emissions while meeting energy demands.

The study area is a simulated actual field data, with three existing geothermal doublets and six exploration wells. The development plan aims to satisfy the energy demand for two locations, D1 and D2, for the next 100 years, using geothermal energy and optimising field development plans via machine learning models as surrogate models. A pseudo-geological model was developed using limited field data to identify sweet spots for further drilling. Four separate model cases were simulated using DARTS. The time-energy data from DARTS was then used to train and test several machine learning models to serve as a proxy model to optimise the best strategy to meet the energy demand. The economic model was simulated for 20 years for the selected strategy for field development.

Using an injection rate of 500 m3/day per well to validate the ML models, the best-performing model had a mean absolute error within the range of 0.6 to 1.5 MW for all the doublets. Based on the ML results, the computational power and time required for field development plan simulation were dramatically reduced, and several configurations were performed. The optimal strategy for this field comprises 7 geothermal doublets, 3 for D1 and 4 for D2. This strategy uses all available wells to avoid lost investment or excess cost when those wells are needed to complement production when decline sets in after 20 years, allowing a reliable and long-term energy supply. This strategy will achieve a net energy output of 108 MW for D2 and 82 for D1. This strategy uses machine learning energy estimation for the optimum configuration and addresses the issues of excess energy storage, uncertainty in production, and rising energy demand. The economic model was based on a fixed OPEX, an estimated Capex based on field development strategy, and an associated discount rate of 7%. The project resulted in a Levelized Cost of Energy of €11.16/MWH for 20 years whiles reducing annual CO2 emissions by about 367,000 metric tons. This study shows that geothermal energy is a crucial step toward cleaner energy. ML can speed up the energy transition by optimising geothermal field development. This research aims to reduce CO2 emissions while meeting energy needs.
The Development of a Free-Standing Integrated Riser
Authors: Bomfimsilva Carlos Terencio Pires
Published: April 2023

Free-standing hybrid risers (FSHR) are well established in deepwater field developments in the oil & gas industry. The major advantages foreseen for the FSHR are the possibility of safely accelerate production ramp-up and requiring significantly reduced payloads at the Floating Production Unit (FPU). This work addresses the feasibility of an optimized FSHR concept, the Free-Standing Integrated Riser (FSIR), where the pipeline is integrated to the riser by means of a transition section, which is kept in place by a multiple line mooring system, which is designed to keep the functionality and integrity of the entire riser along its lifetime. The work applies numerical analysis simulated in Orcaflex; a finite element simulation software dedicated to global analysis of risers. As part of the FSIR evaluation, screening static analysis was performed to identify the most promises configurations for the multiple line mooring system, followed by a series of dynamic analyzes to evaluate the behavior of the riser in extreme conditions. In addition, several investigations were performed to assess the functionality and the robustness of the system, including parametric studies to check for installation and dimensional tolerances, assessment of fatigue damage, and checking how the pipe sizes would impact the design. The work also provides an economic analysis to evaluate how the application of the FSIR can influence the project Net Present Value (NPV) in deepwater fields such as in the Pre-Salt developments.

As a result, the FSIR has shown to be a potential solution for deepwater developments, demonstrating significant benefits against the most conventional FSHR, due to its simplicity, eliminating the need for the rigid spool, the flex-joint at the foundation, the Pipe Line End Termination (PLET), the riser lower assembly and the stress joint at the bottom of the riser. In conclusion, the novel riser system should be more economical and safer than the traditional FSHR, being possible to obtain large savings with equipment and installation time, while keeping the same advantages of being decoupled from the FPU motions and allowing for the pre-installation of the subsea system, limiting the installation schedule risk and allowing for an accelerated production ramp-up, when compared to other traditional dynamic riser systems. Overall, this new concept should lead to a considerable increase in the NPV for the projects. It is important to highlight, however, that the availability of the technology still requires the qualification program to be completed, in order to ensure that all potential risks have been properly identified, evaluated and controlled.
Best Practices for Handling Completion Tubulars to Ensure Design Life Well Integrity in HPHT Wells
Authors: Angelle Jeremy , Alleman Neil
Published: April 2023

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

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

Polymer 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

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

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

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

Typical 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

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

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

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.