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Martins, A. L. (Petrobras) | Santos, H. F .L. (Petrobras) | Castro, B. B. (Petrobras) | Gonçalves, A. S. (Interdisciplinary Center for Fluid Dynamics, NIDF/UFRJ.) | Maffra, D. A. (Interdisciplinary Center for Fluid Dynamics, NIDF/UFRJ.) | Loureiro, J. B. R. (Interdisciplinary Center for Fluid Dynamics, NIDF/UFRJ.)
Downhole carbonate scaling is a major concern in offshore scenarios, where workover operations are associated with very high costs. Intelligent completion concepts are also a requirement for reservoir management optimization. These systems however, introduce several elements in the production string which may constitute hotspots for scaling. The goal of this work is to present pilot scale test facilities and procedures designed to mimic real field situations. Results presented include pH, conductivity and particle size distributions from samples taken along the pipe length and along periodic time intervals. Severe, but representative of some of Brazilian pre-salt scenarios, scaling conditions (S between 3 and 3.4 and pH around 7.5) enable comparative results with a reasonable test volume. Pressure drop on the valve and along the pipe length is also discussed. The scale adherent to the pipe wall and on the valve have been dried and weighted after the experiment. X-ray diffraction and scanning electron microscopy have been used for further characterization of the scale structure. The role of flow rates, water composition and valve opening (creating different localized pressure drops) is experimentally investigated. A discussion on scaling mechanisms is presented. Additionally, the use of non-chemical strategies to delay pressure drop increase is also shown. Results show the present experimental set up is able to reproduce hydrodynamics and scaling conditions of downhole scenario. In this work reproducible large scale test procedures have been established. The flow loop allows the evaluation of chemical injection devices besides non chemical mitigation alternatives, including coatings and physical strategies.
Poletto, V. G. (Federal University of Technology - Parana) | De Lai, F. C. (Federal University of Technology - Parana) | Ferreira, M. V. D. (Petrobras) | Martins, A. L. (Petrobras) | Junqueira, S. L. M. (Federal University of Technology - Parana)
This work provides a preliminary study of solids adherence on the surfaces of a sliding-sleeve valve (SSV), aiming to mimic inorganic scaling process. SSVs assembled in production sites subjected to water flooding might suffer from scale deposits of barium sulphate. Scaling may result in production stops, production restriction and also heavy workover jobs, reducing project profitability. The simulation of the scaling formation process allows the observation of fouling hotspots and, shortly, it can become a powerful tool to increase the valves reliability in scaling-prone scenarios. In the present problem, a four-way coupled CFD-DEM technique simulates the liquid-solid two-phase flow considering the solids particles as precipitated of barium sulfate crystals. The Discrete Element method allows the evaluation of inter particles interactions, such as collision, friction and adhesion, accounting for relevant phenomena such as particulate agglomerates build-up and particles adhesion on surfaces. The fluid-particle interaction forces arise from the simulation of the flow field through CFD. The main motivation is to analyze the influence of particle granulometry over the fouling process, keeping constant the scale index. The size distribution follows a normal distribution and reducing the mean dimension (smaller particles) results in more particles within the domain. The increase in the number of particles stimulate the formation of particulate agglomerates, which adhere on the grooves and holes of the SSV. Furthermore, agglomerates of tinier particles are less permeable, which accentuates the increase of the pressure drop in the valve.
Numerical reservoir simulation often requires upscaling of fine-scale detailed models and coarse-scale models are necessary to reduce computational time for dynamic evaluations. However, these simplifications may degenerate results due to loss of resolution of the small-scale phenomena, averaging of sub-grid heterogeneity and numerical dispersion, especially in oil fields where miscible gas is injected.
Most of the existing upscaling techniques focus on reproducing the results of a specific geological realization, in a deterministic approach. Nowadays, however, reservoir simulation studies commonly include uncertainty quantifications, which is performed by simulating multiple geological realizations. For that, the use of fine-scale models can be computationally prohibitive and this requires a proper procedure to upscale the coarse-scale simulation models in multiple realizations environment.
In this work, we propose and test an ensemble-level upscaling technique for compositional systems with miscible gas injection. The new approach considers the classical Koval factor, calculated for the fine-scale models, as a guide for selecting representative fine-scale models to train pseudo-functions for the coarse-models. Only a few fine models are simulated (about 1%), and the uncertainty quantification process with coarse-scale models can be significantly improved.
The proposed workflow is guided by ranking the fine-scale models in increasing order of their Koval Factor. We selected representative models and applied a two-step methodology to improve upscaled coarse-scale results for these models. We then propose a consistent procedure to expand the fitted pseudo-functions to all the coarse models, providing an effective ensemble-level upscaling.
The correlation between Koval factor and oil recovery is a useful guide to extrapolate the pseudo-functions obtained for each selected representative model, enabling better coarse-scale simulation results when multiple realizations are considered. This procedure can be applied for continuous miscible gas injection and can be adapted for WAG scheme.
This work was motivated by the lack of practical procedures to improve coarse-scale results at the ensemble-level. With our approach, we can better represent uncertainty quantification using coarse-scale models with reduced computational cost and requiring only a few fine-scale simulation runs.
Carbonate formations, which are candidates for acid fracturing, are usually naturally fractured. The existence of fracture networks has important impacts on fracture design outcomes. Previous studies have investigated the interaction between induced and natural fractures. However, these studies have seldom considered the impact of reactive fluid systems. In this work, a model was developed to explain acid distribution in hydraulic and intersecting natural fractures. This model was then used to optimize acid fracture design parameters based on the goal of maximizing productivity.
A fracture propagation model coupled with acid transport, reaction, and heat transfer was employed to determine the acid etched-width distribution and stimulated reservoir area. The outcome of the coupled model was the acid dissolution and conductivity distribution of a natural fracture network intersecting a hydraulic fracture. Then, a productivity model was utilized to evaluate the performance of the acid fractured well.
A parametric study was also conducted to understand the impact of natural fractures on the optimum design conditions. Different natural fracture intensities (i.e., spacing) were investigated at different reservoir permeability. It was observed that the existence of natural fractures significantly altered acid placement in the reservoir. The result was well productivity quite different from what was seen in cases with no natural fractures. Also, the optimum design conditions (e.g., injection rate) differed based on the natural fractures' characteristics and reservoir properties. It was found that the existence of natural fractures significantly reduced the productivity of fractured wells.
The model developed here was used to explain the complex interactions of acid fractures in naturally fractured carbonate formations. The effects of natural fractures on acid placement and optimum design conditions can now be estimated. Such information, which has rarely been considered, is imperative for better stimulation design in this type of formation.
Most wells in carbonate reservoirs are stimulated. Because of their low cost and simpler operations, acid-stimulation methods are usually preferred if they are sufficient. Matrix acidizing can effectively stimulate carbonate reservoirs, often resulting in skin factors on the order of –3 to –4. In low confining stress and hard rocks, acid fracturing can yield better results than matrix acidizing. However, acid fracturing is less effective in high permeability, high confining stress, or soft rocks. There is a combination of parameters, among them permeability, confining stress, and rock geomechanical properties, that can be used as criteria to decide whether matrix acidizing or acid fracturing is the best acid-stimulation technique for a given scenario.
This study compares the productivity of matrix-acidized and acid-fractured wells in carbonate reservoirs. The criterion used to decide the preferred method is the largest productivity obtained using the same volume of acid for both operations. The productivity of the acid-fractured wells is estimated using a fully coupled acid-fracturing simulator, which integrates the geomechanics (fracture propagation), pad and acid transport, heat transfer, temperature effect on reaction rate, effect of wormhole propagation on acid leakoff, and finally calculates the well productivity by simulating the flow in the reservoir toward the acid fracture. Using this simulator, the acid-fracturing operation is optimized, resulting in the operational conditions (injection rate, type of fluid, amount of pad, and so forth) that lead to the best possible acid fracture that can be created with a given amount of acid. The productivity of the matrix-acidized wells is estimated using the most recent wormhole-propagation models scaled up to field conditions.
Results are presented for different types of rock and reservoir scenarios, such as shallow and deep reservoirs, soft and hard limestones, chalks, and dolomites. Most of the presented results considered vertical wells. A theoretical extension to horizontal wells is also presented using analytical considerations. For each type of reservoir rock and confining stress, there is a cutoff permeability less than which acid fracturing results in a more productive well; at higher than this cutoff permeability, matrix acidizing should be preferred. This result agrees with the general industry practice, and the estimated productivity agrees with the results obtained in the field. However, the value of the cutoff permeability changes for each case, and simple equations for calculating it are presented. For example, for harder rocks or shallower reservoirs, acid fracturing is more efficient up to higher permeabilities than in softer rocks or at deeper depths.
This method provides an engineered criterion to decide the best acid-stimulation method for a given carbonate reservoir. The decision criterion is presented for several different scenarios. A simplified concise analytical decision criterion is also presented: a single dimensionless number that incorporates all pertinent reservoir properties and determines which stimulation method yields the most productive well, without needing any simulations.
The industry has been developing numerical models to simulate the wormholing phenomenon in carbonate matrix acidizing, both to save cost and time with experiments and to scale up the laboratory results to field scale. The two-scale continuum model is a fundamental model that has been successfully used for this end. Previous studies with this model only simulated single-phase flow: injection of acid into a water-saturated rock. However, significantly different behavior is observed experimentally by injecting acid into oil- or gas-saturated cores. In this work, we present a fundamental multiphase model for wormhole formation using the two-scale continuum approach, allowing the simulation of wormholing for acid injection into oil- or gas-bearing rocks, with different saturations.
The two-scale continuum model represents the fluid flow and acid transport in the porous medium at the Darcy scale but calculates the acid-rock reaction with dissolution of the rock at the pore-scale. This model was implemented in transient 3D anisotropic form. Each phase occupies a volume fraction in each gridblock, defined by the porosity and fluid saturations. The fluid flow is calculated by solving the Darcy-Brinkman-Stokes equation, in which the relative permeabilities are functions of the saturations. The acid transport and reaction equations are solved, and as the acid injection proceeds and the rock is dissolved, the porosity increases in the gridblocks where dissolution occurs. The pore properties, such as permeability, pore radius, and specific surface area, are updated as porosity evolves, being scaled up from pore to Darcy scale. The simulation keeps track of the different fluid phases by calculating the saturations using the Implicit Pressure Explicit Saturation (IMPES) method.
The developed model was implemented in an open-source computational fluid dynamics package and validated against experimental data. For the validation, the adjustable parameters in the model were calibrated so that the simulation results represent the different dissolution patterns and correctly reproduce the acid efficiency curves obtained experimentally. The same calibrated model was used to simulate the coreflooding experiments with water- and oil-saturated cores. The dissolution patterns (face dissolution, conical wormhole, dominant wormhole, etc.) and acid efficiency curves predicted by the new model match the experimental data. Other simulations presented include the shift in the acid efficiency curves observed for different oil viscosities, residual oil saturations, and different water saturations.
To our knowledge, this is the first 3D two-scale continuum model to simulate wormhole propagation including multiphase flow. With adequate history match, it was shown to accurately predict the acidizing results for different fluid saturations, as observed in experiments.
Nair, Aravind (DNV GL) | Jaiswal, Vivek (DNV GL) | Fyrileiv, Olav (DNV GL) | Vedeld, Knut (DNV GL) | Zheng, Haining (ExxonMobil) | Huang, Jerry (ExxonMobil) | Tognarelli, Michael (BP) | Goes, Rafael (Petrobras) | Bruschi, Roberto (Saipem) | Bartolini, Lorenzo (Saipem) | Vitali, Luigio (Saipem)
To date, there are no publicly available, validated tools or industry accepted guidelines for the assessment of Vortex-Induced Vibration (VIV) fatigue of rigid Jumper (spool) systems. The existing state of practice has been to treat rigid jumper systems as free spanning pipelines and apply the associated design principles in DNV GL recommended practice DNV-RP-F105/DNVGL-RP-F105 (Free Spanning Pipelines). However, widely used rigid jumper systems such as the M-shape jumper systems are subjected to complex flow fields around their legs and bends and fall outside of the test data used to generate the free-span response model in DNV GL Recommended Practice (RP). A Joint Industry Project (JIP) ‘Jumper VIV JIP’ that included BP, ExxonMobil, Petrobras, Saipem and DNV GL was conducted between Dec. of 2014-2016 to collectively tackle the technical issues related to the VIV design of rigid jumper systems.
Through the JIP study, measured responses from ExxonMobil's jumper tow test data were used to develop new response curves for jumper systems in pure-current condition. Curves for in-line and cross-flow responses were initially developed by classifying the measured responses into in-line or cross-flow directions and compared against the existing DNVGL-RP-F105 response curves. Due to potential ambiguity in classification and application to Jumper Design, a more general curve that does not rely on directional classification has also been generated. Due to the differences in behavior of rigid jumper systems to that of free spanning pipelines, a new VIV guidance report was developed as part of the JIP deliverable. Principles and philosophies in the DNV-RP-F105 were followed in the development, but with the intent of identifying unique behavior of jumper systems for a subsequent update of the RP.
This paper presents the Guidance notes from the JIP and forms the first release of Jumper VIV fatigue assessment approach to the Industry. ExxonMobil's model test data, the only known test data available in the industry, was used in the development of unique response model and the new design guidance. The paper includes the new response model along with VIV screening, safety factors and unique considerations required for fatigue assessment of jumper systems.
Weidlich, Marcos Correa (Petrobras) | Pereira, Gustavo Henrique (Petrobras) | De Souza, Bruno Sergio Pimentel (Petrobras) | Borges, Alexandre Thomaz (Petrobras) | de Melo, Everton (Petrobras) | Santos, Rodrigo Ossemer (Petrobras)
The annulus seal assembly is an essential component of the subsea wellhead system, providing hydraulic isolation to other annuli. A failure of that device can lead to a very costly replacement intervention, due to the need of removal of the subsea equipment and production string, or even serious integrity consequences, such as underground blowout or cascade collapse of the casing strings. During the well lifetime, the annulus seal assembly is submitted to various types of loads, depending on the well temperature and the operated pressure of the "A" annulus. The analysis of those loads identified critical moments for the annulus seal assembly, which could exceed the capacity of that device if the proper lock mechanism is not installed, and cyclic loads could further depreciate its capacity. The objective of the present paper is to present a methodology to evaluate the critical loads, failure modes and qualification procedures for long-term well integrity.
Implementing deep-offshore Enhanced/Improved Oil Recovery (EOR/IOR) is not an easy task. Bigger reservoirs, larger well spacings, injection/production/logistics constraints and difficulties to quantify benefits are some of the challenges that may be faced.
This paper presents the status and future vision for the main offshore EOR/IOR research and field application initiatives of a brazilian Operator. Most promising technologies and issues will be described. Overall research structure, as well as adopted strategies to test and implement those techniques will be addressed. Difficulties eventually faced will be mentioned.
The most promising methods in terms of water-compatible EOR are customized-composition waterflood, novel conformance control solutions and optimal reservoir management. Regarding gas-based technologies, the focus is on WAG flood, foam, subsea gas/liquid separation/reinjection and gas injection optimization.
Affonso, Italo Dourado (Petrobras) | Santos, Marcelo Brandão dos (Petrobras) | Aragão, Rodrigo Rodrigues (Petrobras) | Vieira, Pedro Fonseca (Petrobras) | Diniz, Filipe Castello (Petrobras) | Rodrigues, Breno Augusto (Petrobras) | Queiroz, Jackson Luan (Petrobras)
Even though digital innovation is currently a priority for companies worldwide, very few have a structured process designed to collect ideas and transform them into successful innovation projects. Most traditional companies are familiar with creating processes to standardize better practices. However, these processes can make them more resistant to change and kill innovation in their early stages. A second factor that can take its toll on innovation is the predictive, risk–averse approach of traditional project management, which demands a well–defined scope, fixed expectations on results, with inflexible deadlines or standard KPIs.
Another common mistake when starting to implement digital transformation projects is focusing exclusively on technologies. Probably the most significant challenge concerning digital transformation is changing people's mindset to understanding the potential of digital technologies and seek opportunities within their work. The oil and gas industry traditionally focus its innovation effort on R&D. Digital innovation, however, is dispersed and should occur in all sectors of the organization; thus, workforce engagement is essential.
Engineering has excellent opportunities since most processes are still document-centric as opposed to data-centric. For example, schedule and design progress are entirely based on the publishing and approval of documents. Design team member's performance is usually measured by elaborating and reviewing documents. The most significant part of design handover is comprised of documents, and several KPIs are evaluated based on documentation. Redesigning these processes to a data–centric approach, in which everything revolves around databases, attributes, and data models, can increase quality and data consistency as well as reducing design cost and time.