bluuebunny/crossref_metadata_2025 huggingface dataset:
Structural Design of a Floating Offshore Wind Turbine Foundation
Authors: Pacheco A. A. , Moreno C. A. S. , Faisca R. G.
Published: October 2023

Nowadays, there is a search for renewable energy sources that are more attractive in terms of cost-effectiveness. Thus, the wind has been considered as one of these sources. Therefore, wind turbines have been installed. As a consequence, it is necessary to develop technologies, mathematical models, capable of analyzing the behavior of the structure in operational and accidental conditions. The present research is mainly focused on the structural design and analysis of a floating offshore wind turbine foundation, which supports the tower of the turbine. Furthermore, the work includes the behavior analysis of the platform in four different conditions: Intact, one broken line, two broken lines and three broken lines. For each condition, it was evaluated the effective tension of the mooring lines extremities. Thus, it was possible to check the mooring lines MBL (Minimum Breaking Load), and finally, it was checked too, the stress levels at the base of the tower. To fulfill the established objective, initially, the shape of the platform was idealized, the thickness of the platform plates were designed, the material plates were defined, etc. After, motion analysis was carried out using the OrcaFlex and AQWA softwares. Subsequently, a mooring system was designed, thereby, for the proposed case study, a global numerical analysis of the system was performed, using the OrcaFlex software, imposing the environmental loads. Finally, the results in terms of the platform motions, mooring lines effective tension and stress level at the base of the tower were evaluated. Therefore, the intact and accidental condition of the platform were analyzed for the wind turbine supposedly installed in the region of Rio de Janeiro, Brazil.
Mineralogical Characterization of Mature Oil Well Cement Pastes Exposed to Downhole Conditions for 30+ Years
Authors: Mello e Alvim Thiago Monteiro , Beltrán-Jiménez Katherine , Gardner David J. , Toledo Filho Romildo Dias , Mendoza Reales Oscar A.
Published: October 2023

The objective of this work is to characterize the alteration on cement pastes exposed to 30+ years of natural ageing at downhole conditions. The cement samples used in this study were recovered from two production wells drilled in the Norwegian continental shelf completed in the late 1980's. Sandwich sections comprised of an inner and outer casing section with cement in between were recovered to surface prior to well abandonment. After recovery, cement samples were cut and studied to investigate signs of alteration and degradation. The characterization was performed using chemical and mineralogical characterization techniques such as: Thermogravimetric Analysis (TGA), X-Ray Diffraction (XRD), Scanning Electron Microscopy (SEM) and X-Ray Fluorescence (XRF). Along with the two well cement samples, an additional class G cement, control sample, was produced and cured in control condition so that it could be used as a reference for a younger cement.

The cement samples studied in this article were not exposed to aggressive agents such as CO2 and H2S either at downhole conditions or in the lab, therefore the main driver for alteration or degradation was ageing. The results indicate that after an exposure time frame comparable with the service life of an oil well at relatively low temperatures, the conditions did not induce significant chemical or mineralogical changes. When comparing the recovered samples with the control sample, the main alteration identified was the higher level of carbonation process. This process indicates natural ageing of the cement during the 40-year period that finally led to a reduction of strength. This work supports the understanding of the durability of well cement and well integrity. The results presented help to establish a base line and to identify the alteration and degradation due to ageing through the end of the wells production life and the start of the abandonment phase.
Enhancing Predictive Models Through Cuttings Reinterpretation: An Ecosystem to Leverage AI Applications for Well Drilling Technologies
Authors: Oliveira L. H. L. , Nóbrega T. , Jacinto M. V. G. , Medeiros D. R. , Silva M. A. , Medeiros G. C. , Montalvão L. C. , Sátiro L. S. P. , de Almeida R. V.
Published: October 2023

This paper discusses a methodology to enhance machine learning (ML) models developed to predict lithology from real-time mud logging data. Inaccuracies of geological data obtained in the field can lead to inconsistencies in model predictions. To address this, drilling cuttings collected from the field were transported, re-described, and re-evaluated by a team of geologists in a laboratory environment with more favorable conditions. The analysis process carried out was composed of consistent and robust analysis methods and processes, such as microscopic examination (for rock type identification, percentage of each lithotype, color, texture, hardness, cement/matrix material, accessory minerals and fossils, sedimentary structures, and visual estimation of porosity), HCl (10%) test, and fluorescence to describe the cuttings samples. Additionally, calcimetry was used to determine the percentage of carbonate in the rock samples. The results of this study demonstrate that a more accurate reinterpreting of cuttings samples can increase the predictive capability of the ML model (which was able to estimate expected lithotypes with greater reliability). It is worth noting that the continuous description of new samples from other wells in various geological contexts of the same basin is fundamental to improving model performance and making it more trustworthy and representative of reality. One of the importance of these models is to assist the geologist in estimating the rock type being drilled in real-time, based on drilling parameters and gamma-ray data. In this sense, the model becomes more reliable during the decision-making process in drilling operations, contributing to the effectiveness, efficiency and automation of exploration for oil and gas fields. These findings have important implications for the development and implementation of ML solutions in the O&G industry, highlighting the importance of continually improving geological databases to enhance the accuracy and reliability of such models.
The Challenge for the Oil & Gas Industry to Face a New Way of Working
Authors: Paiva R. L. , Silva J. B. , Gonzalez L. J.
Published: October 2023

OBJECTIVES

As a result of the COVID-19 pandemic, most companies had to adopt home as an office to stay safe and continue operations. Based on the above, the purpose of this article is to present how a cloud solution helped Oil & Gas companies adopt a new working scheme during a global health crisis.

PROCESS

With the introduction of cloud solutions to help transition to a new working scheme, it was necessary to implement a migration process that would be the least impactful to both operations and end users. This migration process consisted of the following elements: (1) Infrastructure preparation based on workflows executed and computational demand;(2) Data Migration defining what is priority and what is not; (3) On boarding sessions guiding the users during the adoption of new way of working, explaining the new infrastructure, how to connect, find data, request support, and how the backup works, and (4) Online support avalable24*7 managing basic, medium, and advanced levels.

CONCLUSIONS

The emerging new way of working taught us that integration of teams can be achieved digitally, and independently of where teams are located under the following premises: : (1) The infrastructure was prepared to face company's needs, like disk space, workflow demand and memory; (2) Data was available in an organized, clean, and single environment; (3) Data was protected in very rigorous backup plan; (4) Users were able to work in a collaborative, secure and confident environment that let them to reach their business objectives during the pandemic; (5) A Support system was in place to guide the users during the transition and adoption phase; (6) The pieces of the puzzle (infrastructure, data, applications, users) were integrated to give the Oil & Gas business the continuity it needed in a difficult period of consolidation.

A more intelligent work framework is available, where artificial intelligence is used to create automatic interpretations improving considerably the time dedicated to critical tasks and allowing end users to focus on other jobs. Data Managers and Infrastructure Engineers can use this document as a reference of how crisis have been addressed in the past and how project innovation and digital enhancements have been a key part of the solution.
Static Modelling and Fault Seal Analysis of the Migrant Rollover Structure, Sable Subbasin, Offshore Nova Scotia, Canada
Authors: Martyns-Yellowe K. T. , Richards F. W. , Watson N. , Wach G. D.
Published: October 2023

Crestal faulting can lead to breach of trap integrity and leakage. The Migrant structure is an example of a potentially breached trap due to fault leakage and juxtaposition. In this paper we use 3D geocellular modeling, populated with new interpretation of input parameters, including shale volume, to examine the possible mechanism for leakage (crestal faulting). A fault plane profile (Allan diagram) was constructed, which can be taken a further step into dynamic modelling and simulation (not presented in this study).

Located in the Sable Sub-basin, the Migrant structure is a fault controlled, four-way dip anticlinal closure, which formed as one of a series of related structures during rift basin extension, sediment loading and salt mobilization in the Cretaceous. Genetically related rollover structures (e.g., the Distal Thebaud Field) in a similar structural and stratigraphic setting have proved viable as a commercial trap.

The Migrant N-20 well was drilled to test for hydrocarbons trapped in Late Jurassic to Early Cretaceous deltaic and fluvial-deltaic reservoirs in the structure. The well encountered gas from a deep sand reservoir during drill stem testing (DST 2) with a reported flow rate of 10 million standard cubic feet per day. However, over the duration of the test, an associated decline in flow rate and pressure depletion was observed, which led the operators to consider the target reservoir as non-commercial.

In this paper we present a re-appraisal to assess why this trap failed by integrating well data (logs, checkshot and pressure) and 3D seismic to produce a static model demonstrating the trapping mechanism in the Migrant Structure. Initial observation of the 3D seismic shows shallow crestal faults while preliminary observation of well logs from the Migrant N-20 well suggests a diminishing sand/shale ratio from the shallow to deep sections of the trap.

This study of the Migrant Structure contributes to the understanding of the relationship between reservoir and seal thicknesses relative to fault displacement and its role in subsurface fluid trapping or cross-fault leakage, through upward and outward displacement (stair-stepping) between reservoirs of different ages across a given fault.

The paper shows how data integration and workflows have been combined effectively and is an important contribution for risk assessment in the Sable Subbasin. The proposed model can be applied in other basins including the similar salt cored basins like those offshore Brazil.
Well Clean-Up and Flowback Optimization Considering Emission Reductions
Authors: Theuveny B. , Rashid K. , Bailey W. , Hay G. , Gemmell D. , Comley R.
Published: October 2023

Ultimately, most new wells need to be put into production, whether it is for temporary well testing during the exploration and appraisal phase or during the development phase prior to commercial flows. This process, commonly known as clean-up, encompasses tasks such as handling contaminated fluids, ensuring proper disposal methods, and managing flow instability during the initial stages. These aspects pose various challenges that need to be addressed.

Regrettably, the conventional approach to fluid disposal has been through flaring. The primary concerns of cost efficiency and expediting commercial production have outweighed other considerations. However, some commendable local regulations, like the one currently in effect in Brazil or the Gulf of Mexico, have mandated the storage of liquid effluents during these operations. The driving force behind such mandates is primarily focused on reducing the visibility of fluid releases into the environment, rather than addressing the actual environmental impact. It is important to note that these "non-routine" flaring operations contribute to less than 5% of the total emission footprint and should not be overlooked. Based on an analysis of over 300 clean-up operations worldwide, we have concluded that it is feasible to reduce the required amount of flaring for well start-up and clean-up operations by 50%, without compromising the future performance of production systems.

The paper illustrates how a thorough assessment of field development architecture, operation scheduling, and overall emission footprint can result in a mutually beneficial solution for clean-up. Interestingly, and somewhat counterintuitively, we demonstrate that it is feasible to minimize the quantity of flared hydrocarbons through an intricate operational sequencing of clean-up operations. These seemingly improbable (and non-intuitive) operational sequences are made possible by implementing remotely controlled and automated choke sequences, coupled with real-time monitoring of well conditions.

Accurately measuring the potential reduction in emissions plays a crucial role in successfully implementing these innovative methodologies. The adoption of such approaches by regulators, operating companies, and service providers hinges on the combination of quantifiable environmental impact, operational reliability, safety, and economic considerations. This paper showcases the implementation of these processes in both land and deep-water operations, offering insightful comparisons between different options. The challenges associated with deployment are discussed, and practical lessons learned from the Middle East and deep-water operations are shared, demonstrating how emissions during clean-ups can be reduced by up to 50% while also lowering operational costs.
A Future Pathway for CO2 Geological Storage (CCS) in the Offshore Pre-Salt of Santos Basin
Authors: Pizarro Jorge O. S. , Branco Celso C. M.
Published: October 2023

Carbon Capture Utilization and Storage (CCUS) operations in the Pre-salt Santos basin oil fields should injected, by 2025, a total of 80 million tons of CO2, as additional production units enter operation. This stands as one of the largest CCUS projects in the world, since the CO2 originally dissolved in the oil is reinjected as an Enhanced Oil Recovery method. The infrastructure already placed in the Pre-salt, the characteristics of the reservoirs, the continuous technological advances and the acquired experience, allow us to glimpse a future scenario in which current CCUS operations will open opportunities for strict CCS (Carbon Capture and Storage) projects disposing of anthropogenic CO2. This paper aims to discuss the long-term perspectives for CCS projects in Brazil taking as a case study a hypothetical Pre-salt field, inspired on a real one, resulting in a preliminary estimate of CO2 storage capacity.

The text encompasses an overview of the CO2 sources in Brazil, a review of the main mechanisms of CO2 entrapment in porous media and a summary of the technical requirements for proper injection and permanent CO2 underground storage. Sound reasons may justify the future exhausted/depleted Pre-salt fields as a scenario for CCS projects: reservoirs with large storage and sealing capacity, good injectivity, presence of infrastructure of wells and pipelines (production units will probably need to be replaced in the long term), among others. We propose a workflow, based on material balance, to reach a preliminary estimate of the CO2 mass that could be stored in the field case study. The adopted procedure uses publicly available data and assumes parameters for total reservoir compressibility, reservoir pressure and CO2 water solubility in formation brine.

The exercise carried out for the case study, admitting the field at the end of its producing stage, pointed to a CO2 storage capacity of around 26 million tons trapped under the mechanisms of structural imprisonment in porous medium and dissolution of CO2 in brine. The obtained results highlight the vocation of the present Pre-salt oil fields as an important player for future CCS initiatives.
Preliminary Feasibility Study of an Ocean Thermal Energy Converter (OTEC) Platform for Offshore Brazil
Authors: Sales Joel Sena , Alho Alexandre Texeira , Souza Roberto Valente de , Fernandes Antonio Carlos
Published: October 2023

This study aims to identify the technical and operational challenges that impact the feasibility for the implementation of a 1MW (gross) Brazilian offshore Ocean Thermal Energy Conversion (OTEC) pilot plant. The OTEC technology utilizes the thermal gradient available between different layers (and depths) in the ocean to operate a heat engine to produce power output. It is expected to become mature enough to establish commercial power plants. The analysis is done by using coupled models in which ocean characteristics, the sizing of engineering apparatus and operational aspects of an OTEC plant are taken into account. A closed Rankine cycle with ammonia as the working fluid was considered for the plant. The Brazilian Blue Amazon is a geographic region defined along the Brazilian coast with a high potential for thermal gradient applications due to temperature gradients of more than 20 °C between sea surface and water depths of 600m z 1000 m throughout the year. This study focuses in such region, called CHT field, in Campos Basin. Campos Basin is an attractive location suitable for offshore floating OTEC plants in Blue Amazon that is also located near the Brazilian Offshore Oil fields. Because of this, a synergy may appear between Offshore Oil Production know-how and floating OTEC applications, since its clean and renewable energy source may also be used to Decarbonize FPSOs and other offshore structures. The available thermal power is analyzed in terms of an average annual estimated for the CHTfield, based on different thermal gradients. For each thermal gradient, the mass flows of sea Hot Water Pipe (HWP) and Cold Water Pipe (CWP), Working Fluid (WF), the pipe diameters, the WT, HWP and CWP pump capacities, and operational parameters of the offshore OTEC plant are calculated. One of the outcomes of this study is the possibility of analyzing greater operational capacities of offshore OTEC plants, such as 10 and 100 MW.
4D Geomechanical Analysis to Support Field Strategy on Production and Well Positioning in an Ultradeep-Water Reservoir
Authors: Macias J. , Pedroso C. A. , Pessoa T. F.
Published: October 2023

Fault reactivation due to reservoir depletion in normal faulting areas is well-documented in the technical literature. Ultra-deep water (1550m) combined with low overburden gradient impose additional operational and environmental constraints in fault-bounded reservoir developments. Under this scenario, an accurate assessment of fault reactivation potential is required. This paper presents the results of a risk assessment analysis for a deepwater offshore field located in the post-salt section of Santos Basin, Brazil.

The initial 1D geomechanical model of existing wells indicated a stress state close to the frictional limit. A 4D geomechanical (Finite Element) analysis was performed to gain understanding on the pre-production stress state at the reservoir scale and its variation with depletion, via a one-way coupling to the reservoir flow (simulation) model. Stresses were mapped to seven fault planes, over which three index-ratios were estimated (Sh_ratio, τ_ratio, OT_ratio), which were later transformed to a traffic-light type representation of the risk of reactivation.

Results show an overall stress-path trend towards a more stable condition inside the reservoir (away from the frictional limit) with increasing depletion. Some isolated points, however, show favorable conditions for faulting that should be avoided in future drilling campaigns. Regarding reservoir delimiting faults, a stable but close to the frictional limit condition was observed in all planes for the pre-production state of stresses. A tendency to more stability is expected with depletion, similar to the central reservoir’s response. Some fault planes show local patches with potential for reactivation following different time sequences. This analysis highlights the importance of considering the potential risk of a hydraulic communication between the reactivated patches and shallower zones where a low burial condition could facilitate the opening of the fault. The main uncertainties in the analysis are related to fault strength parameters and the accurate estimation of differential pressures across fault planes, both having a decisive impact on the risk assessment.

An accurate estimation of fault reactivation potential is of great relevance in well planning, construction of safe mud windows and in particular the definition of safe limits for injection/depletion pressures. The later have the potential to impact the production forecast and economy of the project.
Test Procedures for Subsea Wellhead Annulus Seal Assembly Under Extreme Loads
Authors: Weidlich M. C. , Rossatto T. T. , Alle L. S. R. , Mattei F. , Buzzatti D. T. , Buzzatti J. T. , Oliveira M. O. , Moreira N. , Pinto T. S. , Oliveira F. L. , Resende D. L. , Souza C. O. , Santos C. M. , Gerber J. P. , Reguly A. , Potter P.
Published: October 2023

During production start-ups and shutdowns, the ASA (Annulus Seal Assembly) is subjected to compression and tension cycling loads, featuring the normal condition loads, and for this reason, demanding an endurance qualification procedure. Furthermore, in a real well, these loads are not applied separately. As a result, the ASA is always under cyclic and combined loads that can affect its sealing capacity. In addition to the normal condition loads, some events may be characterized as an extreme event, in accordance with the API Standard 17G (Design and Manufacture of Subsea Well Intervention Equipment).

This paper will present the methodology and description of the test performed to evaluate the performance of ASA under extreme conditions, which falls beyond the scope of the API SPEC 17D (Specification for Subsea Wellhead and Tree Equipment) requirements and normal condition loads definition, in order to replicate the load conditions of a subsea well considering an extreme event. A full-scale experimental test facility has been built in a controlled laboratory environment to evaluate the behavior of the ASA under these extreme loads. The test facility was built to simulate the real conditions of the well, reproducing cyclic and combined axial and pressure loads. In this test facility, the ASA is tested together with the High-Pressure Housing and Casing Hanger, thus evaluating the whole subsea wellhead system.

The results showed downward CH displacement due to ballooning effect at 4,500 and 5,000 psi, as pressure end load increases, a significant upward displacement is seen before assembly failure, indicating the limit if the ASA. The test enabled the creation of a performance envelope that exceeds the parameters of the API 6A PR-2F and API 17D testing procedure. The device not only enhance the safety and efficiency, but also fosters the development of novel testing methodologies and equipment for the petroleum industry. With its ability to accurately assess equipment performance, the facility stands as a significant asset, empowering operators to make informed decisions and optimize their production processes.
Smart Water as a Sustainable Enhanced Oil Recovery Fluid: Covariant Saline Optimization
Authors: Quintella C. M. , Rodrigues P. D. , Silva H. R. , Carvalho E. B. , Souza E. Ramos de , Santos E. , Nicoleti J. L. , Hanna S. A.
Published: October 2023

Although the migration to renewable energies is accelerating, for several decades the fossil fuels will still be essential for mankind. More environment friendly EOR methods are a current challenge. Recently, injection of aqueous fluids with low salinity (Smart Waters) had good performance and reduced environmental impact. However, there still is no consensus on the best ion concentrations, which may be due to experimental designs being linear whilst EOR processes are covariantly synergistic. This work optimized the pre-salt oil recovery factor in limestone by injecting smart water with 30 formulations defined by covariant statistical experimental design, with Doehlert Matrix, for NaCl, CaCl2 and NaHCO3. Injected and produced fluids were characterized by rheology, pH, conductivity, molecular fluorescence spectroscopy and X-ray fluorescence. No direct univariate relationships between recovery factor and pH, TDS or ionic concentration were found. The recovery factor was maximized from 35.9% up to 52.5%. Two optimal regions were discovered, one with slightly lower salinity and the other with slightly higher salinity, which may explain the lack of convergence in the literature on linear concentration variation. NaHCO3 concentration presented the highest statistical significance, which is attributed to the maximization of the reduction in the oil/oil and oil/rock interface tension. Its presence synergistically favored lower concentrations of NaCl. Separately, NaCl CaCl2 showed opposite statistical significances. However, their synergy was evident in the high positive significance of their association, due to the association of monovalent and bivalent cations. In addition, molecular dynamics calculation revealed that monovalent ions improve the wettability of water on the carbonate rock. There was no preferential production of any type of asphaltenes. Total dissolved solids influenced the rheological profiles when at high concentrations. The dynamic evolution of the roles of Cl− and Ca+2 ions was identified as more porous volumes of smart water are injected, through variations in their concentration in the aqueous fraction produced, which was attributed to the fact that, as oil is produced and the intelligent injection of water continues, the interaction of the chlorine anions with the rock intensifies, leading to the gradual release of calcium cations until the surface saturation process occurs.
Implementation of Risk-Based Inspection Program for Eight Jacket Structures in Brazil
Authors: Sarabi A. , Barbosa V. , Rodrigues R. , Lopes M. , Souza M. , Amaral R.
Published: October 2023

Objectives/Scope

This paper presents a case study of the development of a risk-based inspection plan as part of the structural integrity management (SIM) of eight fixed offshore structures in Brazil. Alternatively, to the consequence-based approach, a risk-based philosophy was adopted to optimize inspection efforts related to the SIM program of eight jackets in Brazil.

Methods, Procedure, Process

The procedure to select what to inspect and how to inspect was based on API-RP-2SIM and ISO 19901-9 standard. The procedure considered quantitative methods to evaluate the level of redundancy of the platforms under extreme storms, and a semi-quantitative method to classify the importance of each joint to the global integrity of the platform jacket. Firstly, the probability of failure by fatigue of each joint was assessed following DNV recommended practice. In sequence, depending on the structural importance of each joint, a reduction factor of the global reserve strength of the jacket was considered in case such joint would fail due to fatigue. Finally, it was possible to define the potential increase of jacket global collapse probability under hypothetical joint fatigue failure scenarios.

Results, Observations, Conclusions

By combining the importance of each joint to the overall jacket strength and the fatigue probability of failure, it became possible to understand, on a life extension perspective, which joints represent significant global failure risk increase to the platform. The riskier joints could then be prioritized by the inspection program and the joints which were not increasing the risk of global failure could be disregarded. In addition, it was possible to differentiate the joints worth of GVI, CVI or NDT, depending on the risk level each joint represents to the safe operation within design life. The application of the proposed procedure to the selection of joints to be inspected for eight jacket structures in Brazil coast demonstrated that, conversely to the consequence-based inspection program, by adopting semi-quantitative and quantitative methods, it was possible to significantly reduce the inspection scope, while at the same time, not reducing the global failure risk of the platform.

Novel, Additive Information

The present study applied available software tools to better assess the risk of each joint with focus on the global strength of jacket structures, independently to the year this platform was designed, demonstrating that to inspect less joints does not necessarily mean running intolerable risk.
Safety Management Systems for Offshore Energy - We Can Learn from Each Other
Authors: Holmes R.
Published: October 2023

For more than a decade, the Center for Offshore Safety, established by the American Petroleum Institute (API), has been at the forefront of promoting safety, environmental protection, operational integrity and risk management on the United States Outer Continental Shelf. Since its creation, the COS has driven advancements in offshore safety by fostering effective leadership, communication, teamwork, disciplined management systems and independent third-party auditing and certification. Membership includes oil and gas producers, drillers, service and supply companies, regulators, academia, and other industry stakeholders.

To truly understand the significance of COS and its mission, a short look back at the industry's history is helpful.
Predicting Emulsion Viscosity Using Artificial Intelligence
Authors: Silva Victor H. C. , Souza Troner A. , Ahón Victor R. R.
Published: October 2023

Water-in-oil (W/O) emulsions are present in some stages of exploration and operation of oil fields. Therefore, it is important to define the dynamic viscosity behavior of these emulsions for flow assurance purposes. This study applied an Artificial Intelligence Algorithm called Artificial Neural Network in order to predict the emulsion dynamic viscosity of thirty (30) oils from Brazilian basins. The Artificial Neural Network used as inputs rheological data considering different values of temperature, shear rate, oil °API and water fraction in order to predict the dynamic viscosity. All the algorithms and data handling were made using Python computational language. Nevertheless, the results obtained in this paper were statistically compared to the results obtained using other classical correlations presented in the literature. The model proposed could generate predictions with more precision when compared to the other correlations.
Corrosion Resistant Alloys for Mechanically Lined Pipes
Authors: Faveret Signorelli Rodrigo , Helmersson Björn
Published: October 2023

Mechanically Lined Pipes (MLP) have shown to be a cost effective solution in several oil fields for risers and flowlines, based on the fact that only a small thickness of the pipe is produced with corrosion resistant alloys (CRA). Only the CRA liner will be exposed to the corrosive conditions inside the pipe, which can vary between different projects.

From the beginning, mainly nickel alloys such as N08825 and N06625 have been selected for MLPs. Lately, stainless steels have been increasing its presence in this application. Grades like UNS S31603, UNS S31703, UNS N08904 are already utilized in MLPs. Alternatively, higher corrosion resistant grades like UNS S31254, UNS N08935 and UNS S32654 could be a good fit. The introduction of additional alloys to this application enables better optimization of material selection in terms of performance and cost.

This paper aims at reviewing and comparing the aspects of the different CRAs available for MLPs. Among the aspects evaluated are mechanical properties, localized corrosion resistance, chloride stress corrosion cracking, resistance to sour service environments as well as commercial aspect pertinent to this application.
Operability Wave Study for Upgrading Aged FPSO Using Flotel
Authors: Passos R. B. , Fernandes A. C.
Published: October 2023

In recent years, there has been a significant increase in the demand for updating and maintenance services for on board systems in FPSO-type units, positioned at long distances from the coast. Dozens of these units were built in the mid-1990s and are now approaching to the end of their project life expectancy, usually around 25 years. As they are quite aging units, there are some updating needs on board.

Because there is an enormous difficulty in transporting the units to a complete docking in traditional coast drydock, operators around the world use as an alternative to bring the facilities of a shipyard to the oil exploration field, without interrupting production. Each on-site FPSO maintenance reduces considerably the operational costs. Naturally, this includes making available and maintaining hundreds of workers in the offshore environment as a floating shipyard. The main services are varied, including the replacement of old pipes, updating the air conditioning system of the accommodations, as well as improving the process plant of the stationary production vessel, returning to an optimum point of production, usually outdated by new technologies.

The essential services to preserve structural integrity of the FPSO are of equal importance. In this context, the use of Flotel-type vessels has become a concrete concept in the offshore industry. These floating hotels can provide an extra 500 vacancies on board that would hardly be accommodated in the FPSO unit itself. In general, Flotel units have a Dynamic Positioning system (DP) and can stay in close proximity beside the FPSO for long periods up to 6 months.
A Vision of the Use of Meta Data in a Digital Field Map to Accelerate the Acceptance of Subsea Autonomy in Assuring Asset Integrity
Authors: Gower A. S. , Britto A. , Lima C. d. , Marinho J. T. , Lopes L. , Peçanha R.
Published: October 2023

The development of capable subsea vehicles to perform autonomous inspection missions is nearing the point where deployment and operational use is becoming a reality. The challenge for the widespread deployment is initially the acceptance of autonomous vehicles to perform missions and to be confident in the performance of the vehicle.

The suitability of the near shore testing areas (playgrounds) to de-risk the performance of the vehicle, is starting to be understood, and it is broadly expected that the gap between emulating an offshore environment in a playground, and performing autonomous missions on an operational site, will require support. Today, this is typically addressed by the presence of a crewed surface vessel providing selective status information to the operating crew on board the vessel due to the limitation of data transfer through water.

Use of widespread subsea based communication networks could provide a meshed network subsea, improving the available data, but this is challenging for a brownfield application, especially in a Life Extension Context due to anticipated limitations in the supporting Subsea Production System electrical infrastructure.

In support of an ambition to develop geo-referencing of a resident autonomous underwater vehicle, operating without the aid of a surface vessel, an onboard Digital Field Map, DFM, capability is relevant to overcome those limitations. The DFM provides the opportunity to encode Mission Intelligence into the meta data of the DFM. The use of Mission Intelligence potentially reduces the complexity of Artificial Intelligence and offers an opportunity to establish clear acceptance criteria. The definition of acceptance criteria presents a clear demonstration of the validation of the actions of the vehicle rather than a subjective assessment of the performance of the vehicle under Artificial Intelligence control.

In addition, the DFM also presents an opportunity to be used for Mission Planning, providing a visualization of the intended mission profile and to define and implement mitigations identified at a Risk Assessment directly into the vehicle without the risk of loss of detail when implementing mitigations in code, as well as simplifying the validation of the implementation of the mitigating steps.
Integration of Machine Learning and Proxy Models to Optimize Formation Testing and Sampling Efficiency: A Pre-Job Performance Study
Authors: Dantas M. , Bertolini A. , Simoes V.
Published: October 2023

Wireline formation testers (WFT) play a key role in reservoir characterization and are the first tool to make dynamic contact with reservoirs and collect reservoir fluid samples. However, there is an industry challenge to collect clean samples due to mud filtrate contamination. Because of that, the time to sample could last from hours to over half a day, which can scale up for long reservoirs with multiple sampling depths. Therefore, this work aims to reduce the CO2 footprint and risks related to sampling jobs by optimizing the sampling time.

The workflow developed uses petrophysics information, usually acquired in previous logging runs, to apply a machine learning proxy that generates a smart guide with optimal sampling flags. This is then used to define in the acquisition program the best depths for sampling based on the depth of the drilling fluid invasion and the optimal WFT technology for maximum efficiency. The workflow integrating the petrophysical data, the machine learning proxy, and operations planning are used to reduce the cleanup time to collect a low-contamination reservoir fluid sample, therefore reducing the CO2e emissions for achieving the same quality of reservoir fluid sample.

The study has been conducted in pre-salt wells, including two of the largest reservoir producers in Brazil; for this, we integrated a quick petrophysical interpretation with the machine learning proxy to create a smart guide to help the decision process of sampling depth. The machine learning proxy has been trained on 350 thousand reservoir simulations, reflecting a remarkably high accuracy. With petrophysics and the predicted depth of invasion, we use numerical reservoir simulation to estimate and match the actual time to sample and compare it to nearby depths with similar reservoir quality but a shallower invasion. The results show that for achieving the same quality of the fluid sample, when using this smart guide in the operations planning, there is a potential to reduce up to half of the sampling time per well, therefore reducing the same amount of the CO2 footprint from these activities related to Scopes 1 and 3 from Greenhouse Gas Protocol, and the risks related to tool imprisonment inherited from this type of job.

The study presented here, enabled by a machine learning proxy, provides a method to improve sampling operation efficiency and contributes to achieving safer, economically improved, and lower CO2 footprint operations. When reducing the cleanup time, the proposed methodology addresses one of the main challenges in decision-making when designing an acquisition program due to the long-lasting sampling jobs.
Revolutionizing Drilling Operations: An Automated Approach for Drilling Analysis and Optimization Using Real-Time Data
Authors: Belov D. , Silva F. , Malik A. , Liland E.
Published: October 2023

This paper presents a novel approach for drilling analysis, optimization, and bottomhole assembly (BHA) component maintenance. The approach uses automation to report shift statistics and process parameter evaluations based on real-time drilling data. Included in the approach are data quality assessment, risk assessments for shock and vibration, and prognostics and health management (PHM) modules for BHA components.

The proposed core algorithm evaluates the content of the various time-based drilling channels and then outputs relevant statistics by classifying the drilling events. This hybrid approach combines the data-driven approaches with machine-learning techniques. Shock and vibration risk assessment algorithms derive the risk levels for each drilling operation under consideration in accordance with industry standards. The integrated PHM algorithms analyze the cumulative risk of component fatigue failure and produce BHA component health information using unique, industry-specific, physics-based, appropriate models.

The set of advanced algorithms are successfully integrated into the system level before they are released to commercial users. This solution provides users with a comprehensive set of high-level information necessary to analyze drilling jobs. The drilling journal is a key output of the solution, playing a crucial role in offset analysis, trajectory design, BHA design, etc. Enabling proactive thinking and decision making helps the user anticipate future actions needed for subsequent job activities.

In addition to providing the drilling crew with valuable insights about the cumulative exposure conditions of equipment, the solution also formalizes the drilling process through business systems for equipment exposure analysis. The insights and formalization help achieve full field adherence and promote standardization and consistency within decision-making processes.

The solution also includes PHM modules that standardize decision-making processes concerning reusing BHA components, helping to reduce field fatigue-related failures. Remarkable results were achieved with the commercial exploitation of the PHM algorithm for the mud motor power section. Implementation resulted in a dramatic decrease in motor-related field failures.

Overall, this innovative and complex solution provides an efficient and reliable method to analyze drilling job data, promote field adherence, and reduce field failures. This first-time published approach distinguishes itself by means of a sophisticated use of real-time drilling data to extract decisive statistics for ongoing monitoring and rapid decision making during the drilling operation. With the aid of advanced PHM models, the proposed innovative solution significantly enhances the cumulative commercial impact.
Challenges on the Governance of Libra PSC
Authors: Francisco F. F. , Flach E. B. , Amendola A. F. , Rodrigues F. M. , Santos G. S. S.
Published: October 2023

The Governance of a Production Sharing Contract was one of the challenges for Libra Project. In this 10th anniversary of first round bidding in Brazil there are a lot of celebrate. Libra Project created a robust governance project. The aim of this paper is to show how this governance process supported Libra Project during these 10 years. It begins with an overview of Libra PSC, after it discuss about all challenges in the development strategy, remarking the new technologies created by Libra team. It brings the importance of the Libra Governance and cost oil recovery process, and finishes discussing Libra new challenges that are production and greenhouse emissions.
How to Deal with Problems Caused by Low-Temperature of Arrival Produced Fluids?
Authors: Khalil de Oliveira Marcia C. , Karnitz Osvaldo , Miranda Daniele F. S. , Marques Luiz C. C. , Simões Saul , Alvim Eduardo D.
Published: October 2023

Objective and scope

In different production scenarios, the partial shutting of the choke valve can be a suitable alternative to sustain the oil production rate in case of high gas-oil ratio (GOR) or excessive gas production. However, it has been observed that this procedure can lead both produced liquids: oil and water, to out-of-spec conditions, thus causing production losses and hurdles to water management and disposal, especially in offshore production installations where the capital expenditure (CAPEX) and the operational costs (OPEX) are traditionally high.

To shed light on this problem a comprehensive evaluation of the produced fluids properties was carried out. Also, both pressure and temperature profiles along the production process were monitored. The big change noticed by the operation team was the sharp temperature drop (< 20°C) of the produced fluids arriving at the topside facilities when the wells were choked-down This thermodynamic phenomenon is provoked by gas expansion, the so-called Joule-Thomson (cooling) effect. In this way, a series of lab tests were performed to mimic the operational field conditions. After analyzing the lab results, an alternative solution was proposed to avoid the drawback of producing out-of-spec fluids, whenever necessary to partially close the choke valve during oil and gas production. This is especially true when waxy crude oils are produced at low temperatures, thence increasing the probability of formation of both Pickering-type- and/or viscous- emulsions.
A Decade of Multilateral Technology Installation Improvements Down Under
Authors: Cappiello Stefano , Pasicznyk Adam
Published: October 2023

Multilateral completions increase reservoir exposure while reducing the investment by minimizing the equipment and the installation time compared to two individual wells. multilaterals (MLT) wells in the Northwest shelf of Australia have been installed for over a decade now. An overview of these operations, well architectures, technology evolution, reliability and efficiency are discussed in the paper.

This paper reviews the custom solutions developed throughout the past decade illustrating not only the industry maturity, but also specific advancements in multilateral completion technology that were pioneered in the region. The study is focused on subsea multilateral campaigns, where multiple global and regional first installations took place in mature fields.

Operational and technological advancements were implemented throughout the campaigns based on lessons learned. Inaugural deployments featured pre-milled windows, inner-string based liner orientation methods, and a dedicated cleanout trip. Operational modifications and new technologies were introduced to significantly reduce installation time and costs.

The first multilateral installation completed in Australia by the service company was in 2006. Over several different projects with different operators in Australia, one particular system was the basis for successfully deployed variants, delivering over thirty productive laterals where mechanical and hydraulic integrity was achieved at each junction.

The study demonstrates how the continual advancement of technologies and efficiencies resulted in a reduction of MLT installation time by nearly half since the first system was installed. This encompasses not only new installations, but also infill re-entry applications as well. Additional cost reductions were realized with the introduction of trilateral well construction. This was accomplished by addressing and mitigating risks inherent to adding more junctions to the configuration.

This case study focuses on the offshore MLT well construction techniques and demonstrates how introducing both technology and efficiency changes can drive optimized time and costs amid oil price uncertainty. This paper also provides insight as to methodology for continually improving reliability of MLT installations, even while well complexity increases.