bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of the Type of Grinding Wheel on the Surface Characteristics of a Titanium Alloy with Internal Coolant Supply
Authors: Nagatoshi Nakatsuka , Toyokawa Sumito , Kusakabe Atsushi , Nakatsukasa Shinya , Sasahara Hiroyuki
Published: October 2019

The objective of this paper is to clarify the effect of grinding surface characteristics in the grinding of a titanium alloy with a coolant supply from the inner side of the grinding wheel. In this paper, we selected a white aluminum oxide (WA) vitrified bonded grinding wheel and a green silicon carbide (GC) vitrified bonded grinding wheel, and compared their grinding characteristics. As a result, in the case of the GC vitrified bonded grinding wheel, the surface roughness decreased by about 54% and the compressive residual stress increased by about 128%.
Flexible Joint Stiffness Modelling Improving Ultra Deep Water Rigid Risers Fatigue Damage
Authors: Venero Germain , Gomes Victor , Corrignan Hugues , Carneiro Daniel
Published: October 2019

Fatigue is one of the key governing conditions in the design of rigid risers, in particular those in ultra-deep water. One effective way of improving fatigue is to adopt a lazy wave configuration, rather than a simple catenary. Steel Lazy Wave Risers (SLWR) have been successfully used offshore Brazil (Hoffman et al. 2010, Oliveira et al. 2017) and in the Gulf of Mexico (Beattie et al. 2013), and have been considered for the North Sea (Felista et al. 2015) and offshore Australia (Vijayaraghavan et al. 2015). Yet, it is probably the most computational-intensive aspect of it. Fatigue analyses require a very large number of load cases to be run, on complex, non-linear models. Methods for simplifying aspects of the analysis are highly desirable, but they must be weighed to provide the required safety levels whilst not introducing uneconomical, overconservative assumptions.

The top first weld is a crucial hotspot, in particular for production SLWRs (Senra et al. 2011). These typically adopt flexible joints (FJ) at the connection to the vessel/platform, and linearization of the FJ stiffness is one of these key simplifications that bring significant value in reducing analysis cost.

This paper describes a method for estimating the characteristic angle used for the linearization, which results in significant stiffness reduction in contrast with the usual, simpler method.

Non-linear FJ stiffness curves are usually available, and they provide stiffness associated to the FJ absolute angle. The FJ stiffness significantly reduces with the angle of rotation. The conventional method adopts the stiffness corresponding to the most likely riser angle – absolute value measured from the static configuration. Conversely, the proposed methodology for estimating the most likely change in angle. As the angles often turn up in alternate angles, the proposed method results in much higher characteristic angle, and hence much lower FJ stiffness. The outcome is significantly less conservative designs, whilst still meeting the same required safety margins.
Libra: Applied Technologies Adding Value to a Giant Ultra Deep Water Pre-salt Field - Santos Basin, Brazil
Authors: Anjos Sylvia M.C. , Passarelli Fabio M. , Wambersie Olivier E. , Lewis Keith , Rovina Paulo Sergio , Coelho Osmond , Martins Mariela , Ribeiro Orlando J. Soares , Fernandes Ricardo A. Rosa , Borges Fernando A.
Published: October 2019

Libra reservoirs are among the most productive in Brazil pre-salt province, with oil columns up to 400 m thick. These heterogeneous carbonate reservoirs contain oil with a relatively high Gas Oil Ratio (GOR) and CO2 levels ranging from 40 to 45% in the associated gas. It is also characterized by sparse occurrences of intrusive and extrusive igneous rock within the pre-salt and post salt horizons, which causes additional challenges for seismic imaging and reservoir architecture modelling. Driven by the challenges and fueled by an innovation spirit, the Libra Consortium have been developing a portfolio of technologies to address those challenges and close the technical and operational gaps, in order to add value by reducing and managing uncertainties, optimizing production and overall improving hydrocarbon recovery. Since Libra development strategy is based on full reinjection of produced gas for CO2 disposal purposes and enhanced oil recovery, gas management and its operational robustness over the full life cycle of the field are key. In this context, a focused and robust technological approach based on applied technology portfolio has been adopted to address the many unique challenges and add value to the project through the implementation of new and innovative solutions as well as technologies over the life cycle of the projects.
Exploratory Potential of the Brazilian Equatorial Margin
Authors: d'Almeida Katia Souza , de Souza Marcos Frederico Farias , de Castro Nathália Oliveira , Vilela Pamela Cardoso , Leggieri Raul Fagundes , Fernandes Regina Freitas , Cardoso Roberta de Albuquerque
Published: October 2019

This regional study proposes a regional evaluation of the petroleum potential of the Brazilian Equatorial Margin (EQM), based on the analysis of exploratory plays, in the geological context of the sedimentary basins that compose it. A methodological approach is adopted where plays are the key geological concept and the Geographic Information System (GIS) is the computational tool. The first step is the mapping of the plays' factors (charge, reservoir and trap systems). Subsequently, using geoprocessing techniques, the segments of the plays' factors (subplays) are qualitatively evaluated for geological favorability knowledge. The knowledge of charge, reservoir and trap elements of each exploratory play allows to observe the prospectivity of the area, despite the limitation of data availability at the exploratory frontier basins that make up the EQM. In this work, we have mapped exploratory superplays associated to the EQM's reservoirs with different characteristics and ages. The greatest chances of hydrocarbon discovery were observed in the central portion of the basins that make up the Brazilian EQM, near the 1,500 m isobath; medium and low chances occured in the rest of the effective basin.
Gimbal Joint Riser: Enabling Free-Hanging and Buoyancy-Free Rigid Risers
Authors: Cruz Ivan Pimentel , Ramiro Andre , Karunakaran Daniel , Nicoletti Frederico , Hepner Gustavo Queiroz , Lemos Luiz , Chiodo Mario , Gouveia Joao Carlos Carvalho
Published: October 2019

The novel ‘Gimbal Joint Riser’ (GJR) device is an invention that allows for a free-hanging riser catenary configuration by providing the functionality of adding a ‘hinge’ or articulation in midway of the riser column. Such mid-length articulation allows that dynamic bending and compression at touchdown zone (TDZ) be reduced enough to get within acceptable design limits, what is not achievable with a traditional steel catenary riser (SCR) connected to a spread-moored FPSO in ultra-deep-water scenarios like Santos Basin in Brazil. The aim of the invention is to offer an economic competitive option to current state-of-the-art solution of applying Steel Lazy Wave Risers (SLWR), by eliminating the need of relatively expensive buoyancy modules. The objective of this paper is to present this new concept and simulations results.
The Branched Steel Catenary Riser Interference Study
Authors: Ogbeifun Michael Achoyamen , Oterkus Selda , Race Julia , Naik Harit , Decnop Eduardo , Moorthy Dakshina , Bhowmik Subrata
Published: October 2019

A novel riser concept is being investigated. This is the branched riser system (BRS) with different configuration types including the branched steel catenary riser (BSCR), the branched steel lazy wave riser (BSLWR) and the branched lazy wave hybrid riser (BLWHR). As part of the design and operational requirement for riser systems, riser interference or clash checks is important especially in cases when risers are positioned closely from each other and the external excitations including hydrodynamic interactions are significant. This paper presents findings from the investigation of the interference response of the branches of the BSCR.

The BSCR, with different half branch angles(β = 0.1deg, 0.5deg and 1deg), are hosted by a floating production system in a water depth of 1500m and subjected to different loading conditions including current loads, vessel offsets, variation in branches’ weight, dynamic loads from ocean wave excitations and drag amplification due to VIV. Under these conditions, the minimum clearance between the BSCR branches were calculated and checked against the minimum clearance requirements.

Results from this study showed that the global displacement responses of the BSCR branches are in tandem with each other for non-VIV scenarios and that the minimum clearances between them satisfy the no-clash criteria. This is due to the close drag-to-apparent-weight (DAW) ratio of the branches. Wave load excitations on the BSCR were observed to cause little changes on the branches’ clearance, even when imposed on a combination of worst static conditions. For ‘lockin’ conditions during VIV, it is found that the transverse vibrational amplitude-to-diameter (A/D) ratio of the branches, which impact amplification on the inline drag force can be different for the two branches. This can result in differential deflection of the branches and higher clash possibilities. Under VIV conditions with the current profile typical of Gulf of Mexico (GoM), the BSCR configuration with half branch angle, β = 0.1deg, was found not to satisfy the interference criteria while the BSCR (β=1deg) survived. This indicates that high half branch angle will be required for the BSCR design under high intensity and shearing current profiles acting on the branches. However, all BSCR configurations with half branch angles (β =0.1deg, 0.5deg and 1deg) were found to satisfy the interference requirement when subjected to constant current profiles (slab currents) and current profile typical of West of Africa (WoA), though slab current profile resulted in very high A/D ratio. These results provide positive indications for continuing investigation of other aspects of the BSCR.
Data Science and Business Intelligence Techniques for Learning from Environmental Accident Analysis for Offshore Oil Fields
Authors: Loretti Rômulo Alves , Da Costa Vitor Felipe Pereira , Memoria Daniel Geraldo De Oliveira , Barbosa Andrezza Neves , Oliveira Helton Luiz Santana , Wegner Issac Rafael , Zank Cristiano Andre Christmann
Published: October 2019

Incorporating data science and business intelligence (BI) techniques as a strategy and tool for improving and evolving process safety for the oil and gas industry is a no-return method that should provide extraordinary gains. The technology is a powerful and necessary partner for the oil industry to overcome the challenges of new frontiers for oil exploration and production. Additionally, this applies to the health, safety, and environmental segment of business because more challenging scenarios imply greater potential risks; therefore, access to information within the appropriate time, clearly, and consistently allows the longevity of business. Digital transformation, helped current activities supported by weak instruments (i.e., spreadsheets, e-mails, etc.) to migrate to a database structure that facilitated the understanding of their real situation within the appropriate time—at macro and micro levels—allowing adequate support for decision-making.

BI tools aided by data science techniques facilitate decision-making, often extracting productive information from content-rich texts. The combination of data science techniques with BI tools enables a full-blown experience for business analysts through new insights, background connections not yet discussed, more professional visualizations, and telling the same or a new story using more complete, and often complex, innovative questions and answers. Answering essential questions for process safety in the oil and gas industry when analyzing environmental accidents, atmospheric dispersions, emissions, leaks, and spills in a structured method (presenting graphically within the context of rigs), multiple views of the problem allow improved management of efforts, which reduces the number of cases. The same concept can be expanded to questions related to injuries, machinery and/or equipment damage, performance, etc.
Automated Supervision of Personal Protective Equipment Usage
Authors: Gessoni Lucas Dalmedico , Gadbem Edgar Vilela , Alves Pedro Gonçalves , Ferreira Matheus Pedroza , de Alcântara André Luís Michels , Fernandes Claudio Santos , Colombo Danilo
Published: October 2019

The workers of many fields must follow strict safety rules, and not complying with them may put these workers into severe danger. Oil and Gas workers are subject to hazards and accidents in their workplace frequently. The use of personal protective equipment (PPE) is of summary importance to professionals who work with heavy-duty machinery or in unsafe environments, reducing the risk of serious injuries or even death. The workers are supposed to wear PPE, some of which are gloves, hardhat, and Steel-Toed Boots, during their activities. However, PPE is commonly misused or unused, incurring the need for recurrent inspection. There is no guarantee that the safety equipment is being used correctly, safely and continuously. These threats to the safety of the workers are increased significantly when they are working offshore due to either the harsh conditions they might be working on or inherent dangers that O&G workplaces can offer to the workers such as machinery and dangerous areas with risk of collision and accidents. Detecting the lack of PPE can prevent injuries during work. For this purpose, we propose a surveillance system solution to automatically analyze video footage and detect oil and gas (O&G) workers who are not using adequate protective equipment. This project developed a multi-step detection system using Deep Learning techniques in a pipeline for monitoring workers through camera images. Being able to detect violations to the established rules is an important step towards reducing the impact of incidents and accidents. Using computer vision, deep neural networks, and video footage, we created a web solution for analyzing the imagery in real-time and issuing alerts when a violation happens. For this specific domain, we accomplished the best results by using YOLOv3 as a person detector in conjunction with the Xception network for classification. We achieved 98% precision for the classification step and 78% precision for the joint solution (detection and classification steps) while running in real-time in an NVIDIA Titan X GPU.
Integrated Simulation of Offshore Oil and Gas Production Systems During Project Design
Authors: Fulchignoni Lívia Paiva , Cardoso Marco Antonio , Oshiro Anderson Takehiro , dos Santos Thiago Duarte Fonseca , Pinto Leandro de Assis , Rocha Djalene Maria
Published: October 2019

The conceptual stage of an oil and gas production projects comprises the identification and the subsequent evaluation of a suite of feasible alternatives for the production system. The evaluation process embraces several disciplines, both technical and economical. It is a common practice for each discipline to work individually, following its own internal process, where external information is treated as a definite input. When organized in this way, the process of evaluating the global production system tends to be complex, involving many professionals and information exchange, and time consuming, since it is performed sequentially. In addition, it is necessary to ensure that the results of each discipline converge to a common point, which is the global result for each production system scenario. In order to achieve this convergence, cycles of iteration between the disciplines may be required, which also contributes to the longer duration of the process.

This paper proposes a framework that integrates individual simulation models of Reservoir and Flow Assurance with organizational economic premises. The framework was set to give as a result the NPV (Net Present Value) of each offshore production systems alternative, among other operational and economic metrics. The framework also integrates optimizers that propose the best reservoir drainage plan, FPU (Floating Production Unit) location and subsea layout for each alternative. A real case study is presented in order to exemplify its functionalities. The production system considered consists of three independent offshore reservoirs producing to the same production facility, through subsea manifolds and long tie-backs.

The integrated simulation allowed for a quick and easy selection process of the production system alternative with higher economic return. There was a drastic reduction on the response time for the evaluation of the alternatives, which is essential to meet the growing dynamism of the oil and gas industry. The results confirmed the importance of the integrated simulation, both for the optimization of the alternatives evaluation process, and for the identification of gains of synergy among the several disciplines involved in project of high complexity. The use of integrated simulation is expected to continue increasing in the coming years in the oil and gas industry, as well as the robustness of the technique.

The novelty of the integrated simulation framework is in the ability to efficiently run a wide number of simulations and optimizations for the production system and help to select the most suitable one.
Determining Produced Fluid Properties for Accurate Production Profiling During a Drill Stem Test Using Thermal Imaging Technology.
Authors: Lavery David , Fyfe David , Hasan Abu Rashid
Published: October 2019

This paper describes the use of a Downhole Temperature Sensor Array, during a commingled Drill Stem Test, to accurately determine the density of the produced fluids. In a typical Drill Stem Test, using only downhole pressure gauges, any fluid contacts between the pressure gauges would be missed and the produced fluid density calculated would be erroneous.

Accurate calculation of the produced fluid densities is of great importance to the reservoir engineer since it forms a critical component of the equations of state used in the modelling of the reservoir. The main purpose of this paper is to show that knowledge of the produced fluid densities from each of the perforated intervals provides a more robust calculation of the zonal flowrate contributions using conservation of mass principles.

In this case study, the well was produced across three intervals with the deepest perforated interval producing a fluid with a higher density than the shallower perforated intervals. The higher density of the produced fluid from this deeper interval caused the wellbore fluids to slug during the flow periods with a measureable response in the pressure and temperature data. If this difference in the fluid properties is not taken into account then the zonal allocation flowrate will be in error since it relies on the density and specific heat capacity. Qualitative assessment of the temperature array data identified the producing zones and clearly highlighted the different fluid interfaces in detail that would remain hidden if relying solely on the pressure gauges.

This method is enabled by the deployment of a Downhole Temperature Sensor Array consisting of an array of discrete electronic temperature sensors alongside the TCP guns, generating continuous thermal profiles across the three intervals. This is augmented by a wireless data system of pressure points. All the data is collected real time throughout the entire Drill Stem Test.
Atlanta Field: Constructing Long Horizontal Wells in a Challenging Environment
Authors: Pedroso Carlos Alberto , Salies Jacques Braile , Aguiar Rogerio Campos , Lemos Daniel G , Kenupp Rafael , Oliveira Pablo , Costa Wallace Albuquerque , Soares Robson Tomaz , Cova Carolina Latini , Tocchetto Andre , Simôes Bruno , Nunes Mauro J
Published: October 2019

Atlanta is a post-salt oil field located offshore Brazil in the Santos Basin, 150 km southeast of Rio de Janeiro. The combination of ultra-deep water (1550m), heavy and viscous oil (14 API), unconsolidated sandstones, low overburden (800m), faulted reservoir rock, etc., composes a unique and challenging scenario for which the remarkable solutions applied have been already detailed (Marsili et al. 2015; Pedroso et al. 2017; Monteiro et al. 2015; Pedroso et al. 2015; Rausis et al. 2015; Pedroso et al. 2015).

The Atlanta field project was planned to be developed in two phases: the Early Production System (EPS) with three production wells, and the Definitive Production System (DPS) with up to nine wells. No injection wells have been planned.

In 2013 and 2014 the first two wells, here called ATL-2 and ATL-3 (ATL-1 was a pilot well), were successfully drilled, completed, and tested as described in the above references. In May 2018, they started production. After almost one year and 5,000,000 bbl of produced oil, the third EPS well was constructed.

The lessons learned in each phase of the well construction - drilling, lower completion, and upper completion - were applied in the third well, repeating the good operational performance. An analysis of this comparative performance is presented.

Technology improvements were implemented, such as the use of autonomous inflow control devices (AICD), the use of micro-tortuosity logging to better position the electrical submersible pump (ESP), the use of an annulus diverter valve (ADV) to avoid the pressure drop across the ESP in case of failure, etc.

The result was a well constructed ahead the planned time with a Productivity Index (PI) that exceeded expectations.
Mechanical Characterization of Grainstone and Dolomite Rock Samples from Quissamã Formation, Campos Basin
Authors: Garcia Paulo Fernando Villafañe , Rossi Diogo Folador , Ferreira Francisco Henriques , Santos Erick Slis Raggio , Borba Anselmo Machado
Published: October 2019

Results from mechanical tests on grainstone and dolomite wellcore samples obtained from the Quissamã formation are presented. Unconfined compressive strength (UCS) logs obtained from scratch tests are compared to known relations. Elastic compressibility moduli, obtained from cyclic hydrostatic and oedometer compression tests, are compared to analytical formulation. Mohr-Coulomb strength envelopes are obtained from compressive tests, such as Brazilian tests, drained uniaxial compression and drained triaxial compression.

The mechanical test campaign consisted of the following steps: 1) scratch test of three full wellcore sets from Quissamã formation to obtain UCS logs, 2) wholecore sampling for cylindrical rock plugging, 3) microtomography imaging of new cylindrical rock samples for internal structural integrity preview and 4) compression tests of plugged rock samples to obtain static elastic properties (Poisson's ratio, Young moduli, bulk moduli, grain compressibility moduli and oedometric compressibility moduli) and mechanical resistance properties (indirect tensile strength, drained UCS and drained confined compressive strength (CCS)). Experimental results were compared to literature UCS relations and analytical compressibility moduli formulation.

It was possible to observe good concordance between UCS obtained from drained uniaxial compression tests and scratch testing profiles. Using the internal friction angle obtained from Mohr-Coulomb envelopes and the UCS results, it was possible to indirectly obtain an estimation of cohesion through Mohr-Coulomb criteria relations. Compressibility moduli obtained from experiments also were in good concordance with classical formulation for elastic deformation regime. In the end, the mechanical characterization campaign was succesful in obtaining resistance and elastic static properties for loading conditions and some unloading conditions.
ULTRA: Flow Assurance Coating Technology - Product Portfolio for Distinct Operating Scenarios
Authors: Cunha Normando da Mota
Published: October 2019

ULTRA™ is a novel and advanced flow assurance coating technology recently introduced in the Brazilian market for upcoming, and challenging, offshore projects expected in the next years. This coating technology has been used for over 9 years, and has been designed, applied and installed in offshore projects worldwide. Particularly over the last year, this thermal insulation system has been applied for a major project in Brazil. It is a thermal insulation system composed of fusion bonded epoxy and styrenic materials. A base 3-layer coating, followed by one or more insulation layers of solid or foamed styrene, and a high ductility outer shield were engineered to outperform some of existing solutions in terms of hydrostatic pressure, subsea stability, overall insulation thickness and associated installation costs. Application trials have been successfully performed to validate plant capabilities for applying the wide range of styrene-based system solutions, for shallow and deep waters. Test results demonstrated that foam and solid versions have a sweet spot in which the system outperforms similar to the wet insulation solutions existing in the Brazilian market. Its solid and foam systems demonstrated capability of delivering lower U - values (Overall Heat Transfer Coefficient) due to their lower thermal conductivity. The benefit of lower thermal conductivity is reflected in a reduced coating thickness and opportunities for potential savings during the transportation and installation activities. In the coming years, the offshore industry in Brazil will demand wet insulation systems delivering improved thermal performance. Hence, lower U value with lower CAPEX and in deeper water depths. This insulation system is a proven flow assurance coating technology, addressing those challenges and now available in the Brazilian market.
Implementation of a Two-Phase Simulator Based on the Brinkman's Equation for Vuggy-Karstified Reservoirs
Authors: Hallack Daniel Metanias Carvalho , Cavalcante Filho Jose Sergio De Araujo , Couto Paulo
Published: October 2019

Due to the chemically active nature of carbonates rocks they are highly susceptible to the phenomenon of rock dissolution, a diagenetic process by which minerals are dissolved and removed by the fluid that fills the porous space creating and modifying the porous medium. This phenomenon might occur in small and medium proportions generating the so-called vugs, regions with pore volumes orders of magnitude greater than the conventional intergranular spaces. The dissolutions might also occur in much larger scales, generating extensive networks of caves. The validity of Darcy's flow equation to model flow in vuggy-karstified petroleum reservoirs can be questionable since viscous stresses of the fluid are not contemplated. The Brinkman equation can be a more general approach to model the flow in the presence of both: open spaces and porous media, even though not commonly used in hydrocarbon (HC) flow problems. The importance of understanding and modeling viscous fluid stresses in HC flow is highlighted by the fact that commercial reservoir simulators do not contemplate such effects.

In this work, we developed a numerical simulator able to represent the single and two-phase flow (water-oil) using both Darcy and Brinkman equations. Equations were discretized using a finite difference method (FDM) and solved using the IMPES formulation. The simulator was verified against representative cases of 1D and 2D reservoirs submitted to water injection. Results from both equations are compared in terms of the velocity field, water saturation front, recovery factor, and water breakthrough in the producing well. In our results, we observe significant differences between the Brinkman and Darcy formulations when higher orders of permeabilities are attributed to high porosity media. Regions with high porosity (attributed to the karstified region) presented worse areal sweep efficiency and better displacement efficiency when the flow is modeled by Brinkman's equation. No influence of Brinkman's viscous term on conventional porous media is observed. This work shows that the Brinkman-based simulator is able to couple the use of Darcy's formulation in regions with low Darcy numbers (Da) (conventional reservoirs) and the use of Stokes' formulation in regions with high Da numbers (regions of intense karstification).
Starting with the End in Mind: More Certain Field Development
Authors: McLachlan Duncan James , Isherwood Jim , Peile Max
Published: October 2019

An industry study published by the Independent Project Analysis group in 2012 reported that 78% of upstream projects in 2011 faced either cost or schedule overruns (Merrow, 2012). A similar report, published by EY in 2014, found 64% of projects faced cost overruns and 73% of projects faced schedule overruns (EY, 2014). Similarly, in 2017, the UK Oil & Gas Authority (OGA) published a study of lessons learned from UKCS oil & gas projects between 2011-2016, which reported "since 2011 fewer than 25% of oil and gas projects have been delivered on time with projects averaging 10 months' delay and coming in around 35% over budget." (OGA, 2017) This level of cost and schedule underperformance was not sustainable in the high oil price economic environment and is inconceivable in the lower oil price environment in which we now operate. We cannot continue to make the same mistakes, the need to learn is no more critical than in the deepwater arena: Wood McKenzie report the cost of developing a deepwater project has fallen by more than 50% since 2013 (Offshore, 2018), the increased investment in deepwater is likely to drive an upturn in cyclical costs meaning developments become increasingly marginal and unable to sustain overruns or delays and remain economic.
Optimizing the Separation Process in Floating Facilities : The Wash Tank Oil Processing Technology
Authors: Thierens Danny , Pedenaud Pierre
Published: October 2019

This paper describes Total's patented wash tank oil processing system, now globally licensed to Sulzer 1, which optimizes the water-from-oil separation by relocating part of the process from the FPSO's topsides to specifically designed hull tanks while eliminating the need for electrostatic coalescers and/or desalters. As a result, this technology reduces the topsides oil processing system weight, complexity and CAPEX. Sulzer's patented inlet distributors and static mixers are key building blocks to achieving the performance required.

The technology principles, both from a theoretical and a qualification view, as well as selected operational feedback from the FPSO's which are currently using this system are covered. The proper functioning of the wash tank system relies on the controlled creation of a dense packed zone (DPZ), which consists of a layer of dense droplets located between the water layer and the oil layer which acts as efficient water droplet coalescence promotor to allow gravity to separate these enlarged water droplets from the outlet oil. The behavior of the DPZ and its impact on the water-from-oil separation efficiency is experimentally verified in a wash tank pilot system which operates with actual field oil samples to ensure the full scale production unit will achieve the performance required. The water-from-oil separation efficiency observed at the FPSO's in operation meets typical industry standards for oil export of 0,5 % BS&W (basic sediment & water), while matching with design model predictions and pilot testing results. This is achieved with simplified process topsides and without the use of electrostatic coalescers/desalters and/or excessive heat input to reduce oil viscosity. Because of the large holdup volume and residence time within the wash tanks, the system shows a robust performance and extensive flexibility towards production flow rate variations.

The wash tank oil processing system has demonstrated its separation performance on a total of 5 FPSO's & FPU's currently in operation and can thus be considered a reliable and robust technology. Through the license agreement between Total and Sulzer, this technology is now available for the entire oil processing community for deployment on new-build FPSO's, FPU's or PSO's and converted tankers.
Optimization Algorithm of Hydrogen Sulfide Scavenging Process in Oil Production Industry
Authors: Souza Fabio Carvalho de , Pessoa Fernando Luiz P. , Ferreira Tatiana Felix , Calixto Ewerton E. S. , Bonfim André L. C.
Published: October 2019

Hydrogen sulfide (H2S), usually present in oil reservoirs, is a toxic and corrosive gas that may have its origin associated with bacteria's metabolism or thermochemical reactions. This gas which is already present in the atmosphere can be converted into sulfur dioxide (SO2), contributing to the greenhouse effect. In presence of water it forms sulfuric acid and precipitates as acid rain. Given its physicochemical properties, H2S tends to accumulate in spaces with little ventilation; being a serious condition in operational processes. Even in low concentrations it causes health problems, and itis lethal in concentrations close to 700 ppm. Nevertheless, the corrosive potential must also be considered, mainly during production due to the piping can be affected with leaks. Therefore, the treatment should still be effective close to the reservoir during the oil production process. These problems must be overcome by the effective reduction or removal of this gas from the oil stream. The use of H2S scavengers in oil industry is a useful practice in order to remove or reduce gas concentration. Hydrogen sulfide scavengers based on triazines are used, since they are liquid substances that can be used in gas systems, being able to be injected directly into the stream with great mixing capacity. The triazine reacts with H2S producing soluble and inert products, which are collected during production system. In order to monitoring H2S concentration, a software SIMSeq 1.0 was used to simulate operational conditions based on real data from oil wells. Using this software, several simulations were carried out and the optimum injection volume was determined. After the volume set, sensitivities analysis was carried out for different injection depths of scavengers along the well string. The results allowed to draw the best correlation between triazine flowrate and its injection depth. It was done by comparing the scavenger injection depth along the points of injection into wellbore. These results were used to build a predictive model in STATISTICA software with a distribution between volume of injection and sequestration efficiency to support economic feasibility studies for fields and oil wells. Results from this study lead us to believe that for the well studied, considering simulations e statistical analysis performed, the optimum injection depth and flowrate to have H2S concentrations below 5 ppm should be 9500 m for depth and 46 L/h flow rate.
Non-Linear Time Domain Drilling Riser VIV Modelling
Authors: Truche Sylvain , Malassagne Aubin , Aljarah Raghid , Saunier Claire , Minguez Matthieu , Ulanov Alexander , Moe Per Thomas
Published: October 2019

A new time-domain Vortex Induces Vibration (VIV) model is here proposed and applied to modelling of drilling riser and wellhead fatigue. The model challenges the industry best practices for VIV predictions which are known to be conservative. The paper is divided in two main parts. The first part is devoted to a validation process considering a rigorous benchmark with the ExxonMobil database. The second part treats the application of the model to a study of a drilling riser configuration. In both parts the proposed time domain model is compared to the industry best practice representated by SHEAR7 v4.10.

The model development has been driven by project requirements. It carefully balances CPU consumption and targeted / required accuracy. The model is based on a hybrid approach integrating concepts from both frequential model and existing time domain wake oscillators. It consists of a hydrodynamic solver capable of balancing both Vortex Induced Excitation and Hydrodynamic Damping at each predetermined node along the mechanical model. The solver is then coupled with a Finite Element (FE) model (or equivalent) to assess the resulting riser dynamics. The different nonlinearities of the riser model (e.g. soil, riser flexible joint) can consequently be accounted for in the usual manner for the global riser analysis.

The proposed model is first benchmarked using a reference database. The model produces riser responses that match well for both uniform and shear current conditions. Results obtained from the proposed model are also compared to results obtained from SHEAR7 with different choices of parameters (including the recommended values). Although mode shapes are in good agreement, the conservatism of the latter is demonstrated and challenged by the proposed model which appears to be a promising candidate for VIV analysis.

A nonlinear model of a 400m long drilling riser is considered as the use case. The VIV analysis is first performed using SHEAR7 and a linearized version of the riser model. The results are compared to those obtained for the proposed time-domain model with the same linearized drilling riser model. While the two approaches again produce the same mode shapes, the proposed model produces much less conservative results (approx 50% reduction of the vibration amplitude).

Finally, the different nonlinearities of the riser model (wellhead, riser flexible joint) are considered to assess their possible impact on global riser behavior and local impact (i.e. at well head). Depending on the nonlinearities to be considered, the local impact of the model is clearly demonstrated.
Thermoplastic Composite Pipes: A Reliable Cost-Effective Solution for Pre-salt
Authors: Barbosa Teofilo , Bastos Renato , De Boer Henk , Rojas-Díaz Ramón
Published: October 2019

Thermoplastic Composite Pipe (TCP) has a solid wall construction constituted from a single polymer material with embedded (melt-fused) fibre reinforcements. It is a disruptive technology where all the advantages for ultra-deep water developments come together: high strength, light weight, corrosion free, low CAPEX, etc. TCP is therefore one of the most promising solutions to overcome the recent failures found on pre-salt fields related to corrosion under high concentrations of H2S and CO2.

However, introducing a new technology on very challenging applications such as deep water production risers, requires careful consideration and mitigation of all technical and project execution risks.

This paper starts presenting a historical review of some of the new technologies applied offshore Brazil over the last 20 years making a parallel with the increasing acceptance of Thermoplastic Composite Pipe in the Brazilian market.

Following the historical review, TCP technology is presented and strategy to enable free hanging catenary systems for ultra-deep water environments discussed.

The basis of the study is a typical offshore Brazil pre-salt field and feasibility of 6" and 8" free hanging TCP risers were assessed. Study was performed in close cooperation with a major operator and an installation contractor in Brazil. Global, installation and local analyses of the TCP Riser system have shown the feasibility of installation as well as operations in a free hanging catenary configuration throughout the 30 years' service life. In 2017, this pre-FEED study was used as basis for a FMECA (Failure mode, Effects and Criticality Analysis). The FMECA exercise was carried out together with a third-party certification body and two major Oil & Gas companies very active in Brazil.

A detailed business case study was performed in order to quantify the potential CAPEX savings that TCP technology can bring compared to the low lazy wave systems currently installed in pre-salt fields, offshore Brazil. Result is that if TCP is adopted as primary technology for Risers&Flowlines, significant savings are expected. Savings comes both from pipe and ancillary's procurement costs since TCP technology enables free hanging catenary configuration, avoiding purchase of expensive buoyancy modules.

The outcome of this work lead to a qualification program currently being sponsored by one major operator active in Brazil. Technology Roadmap was established in phases being the ultimate goal the qualification of pre-salt 8.0in production lines. Reasons for adopting this qualification strategy is presented. The qualification is driven by DNV-ST-F-119, a dedicated standard for TCP design and qualification.
Optimization of CO-WAG and Calcite Scale Management in Pre-Salt Carbonate Reservoirs
Authors: Rodrigues Hydra , Mackay Eric , Arnold Daniel , Silva Duarte
Published: October 2019

CO2-WAG (Water-Alternating-Gas) has been applied in offshore Brazilian oilfields to improve recovery rates and mitigate the environmental impact that venting produced CO2 would bring. Although CO2 is highly miscible in oil under these reservoirs conditions, this gas is also extremely mobile, and its speciation in the aqueous phase drives reactions with carbonates that can cause severe inorganic scaling problems in production systems. It is crucial, therefore, to effectively design CO2-WAG operations for mobility control and, consequently, enhance reservoir performance, CO2 utilization and flow assurance.

This paper addresses the design optimization of coupled CO2-EOR and storage operations applied to the Brazilian Pre-salt offshore context (reservoir properties, infrastructure, regulatory framework and economic characteristics), examining the trade-offs of project profitability, CO2 utilization and calcite scale risk. Several compositional simulations of miscible WAG scenarios were performed and key design parameters were optimized using statistical sampling and evolutionary algorithms. Aqueous and mineral reactions were included in the calculations, allowing us to quantify the calcite mass that can potentially deposit in the perforations and production system.

The results showed how optimizing WAG operations can significantly improve the economics and the scale management of oil production from carbonate reservoirs. The optimal WAG design greatly increased incremental NPV per volume of CO2 stored and reduced calcite scale risk by simply rearranging the WAG slugs in a tapered manner.

Here we demonstrate that this methodology can be used to determine how to recycle CO2 in a given field for better economics and lower carbon footprint, doing so without triggering calcite mineral deposition to the point of permanent jeopardy of production wells and facilities operability. Therefore, the workflow integrates critical challenges that are correlated, yet often addressed independently, supporting the complex decision-making of CO2-EOR operational design in carbonate reservoirs.
The Use of Drones and Deep Learning to Identify Igneous Rocks and Fractures
Authors: Oliveira Maria José Resende , Savastano Vitor , Matos Gabriel , Schmitt Renata Silva , Valente Valente Castro , Araújo Mário Neto , Inocêncio Leonardo Campos
Published: October 2019

Igneous (or magmatic) rocks may be critical elements in the petroleum systems. They may be related with generation, migration and trapping of oil and gas and also generate hydrothermal processes that can affect the reservoirs. In Campos and Santos basins, they occur as volcanic and intrusive bodies, affecting the pre-, intra- and post-salt sequences. Associated with fractures and faults, igneous intrusives were emplaced during reactivation of preexisting discontinuities or weakness zones, although they also cross cut them. In the continental area, adjacent to the Campos and Santos basins, intrusive igneous bodies crop out as dykes, sills and stocks. The area selected for this study is the "Pontal do Atalaia", in the city of Arraial do Cabo (RJ). The use of drone images allowed to identify the structural framework of the igneous bodies and fractures patterns associated with them. By developing tools of deep learning, it was possible to analyze the fractures and compare the results with visual interpretation. In both cases, the results indicate the predominance of fractures along roughly N-S and E-W trends. The outcomes allow the comparison and correlation to the offshore geological features to better understand the role of the igneous rocks and fractures in the tectonic evolution of Campos and Santos basins.
Case Study: Brazil Deepwater, Pre-Salt – Successful Intermediate Casing Shoe Squeeze Using Microcement
Authors: Freitas Rodrigo , Rossi Lucas , Gregatti Ana Carolina , Moretti Fabricio , Pagani Leonardo
Published: October 2019

Drilling the Marlim field at the Campos Basin has shown quite a challenge in the last few years. The field is located 110 km from Sao Tome cape at the north coast of Rio de Janeiro State, at the Campos Basin, have started commercial exploration for in 1991 and with water depths varying between 600 to 1000 m. The reservoir is composed of sandstone formation and just recently, an exploratory campaign at the field surroundings.

The project of the well in the Marlim field was always complex with eight phases predicted. For the phase 4, due to the narrow fracture and pore pressure window, and also the high number of potential flow zones to be isolated, the client has decided to run a 13 5/8" stage collar in order to isolate all sandstone formations and cement the combined 14" × 13 5/8" Intermediate Casing. The idea of using the stage collar was to isolate the water holder formation, Carapebus Lambrusco sandstone, located just at the stage collar depth and then open the stage collar and cement the remaining sandstone all the way to the last water holder formation, Carapebus Marlim sandstone. The other objective of this job was to provide enough integrity to the shoe, set at the salt formation, in order to allow drilling the subsequent 14 ¾"open hole all the way to the carbonate formation.

After drilled the 16 1/2" open hole of an offshore well, the intermediate casing had to be cemented with a two stage collar with sub sea release plug set, to bring the top of cement higher and isolate upper formation. Due to operational issues, there was a failure in the first stage cement job, which was confirmed with a failed formation integrity test - necessary 13.0 lb/gal to drill ahead the subsequent 14 3/4" phase.

To solve the issue, to achieve formation integrity test of 13 lb/gal, it was necessary to perform a Casing Shoe Squeeze Cement job. The problem is that historically those intervals experience very narrow gaps, which means low injectivity. After several failed attempts with conventional cement, a novel technology was used combining microcement with a strong fluid loss control that could enable the cement to be injected into narrow gaps. The use of microcement alone provides rapid compressive strength development, very low rheology and combining with a fluid loss additive enables to provide the system with very high injectivity