bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

AbstractAtlanta 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.