Pre-salt Fields Research Articles

Multidisciplinary Approach Underpins Development of Marginal Presalt Reservoir

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35273, “Sururu Central: Appraisal and Development Plan for a Marginal Presalt Reservoir,” by Thiago E.S. Azevedo, L.M. Hayashi, and Rodrigo R.S. Leal, SPE, Petrobras, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ The complete paper presents a multidisciplinary view of the evolution of the concept of a development project for the central area of the Sururu reservoir and the method applied to address challenges and propose solutions. The central area presents distinct characteristics from typical Brazilian presalt fields, with low permeabilities despite high porosity. Sururu Reservoir The reservoir is in the Santos Basin 230 km offshore Rio de Janeiro at water depths ranging from 2000 to 2300 m. The wildcat in the reservoir, 1-BRSA-618-RJS (1-RJS-656), is in the central area of the field, which is the main subject of the present work. The well exhibited reasonably high average porosity while presenting low permeabilities and low productivity when compared with other presalt wells. The second well, 3-BRSA-891A-RJS (3-RJS-682A), was drilled in 2011 in an area known as Iara Horst, also in the central area of the Sururu reservoir and presenting the same challenges faced by the wildcat. The third well, 3-BRSA-1181D-RJS (3-RJS-715D), was drilled in 2013 as a high-angle multifractured well consisting of an alternative architecture. Productivity results, however, were similar to the ones obtained in the previous wells. Investments were made in acquiring and reprocessing seismic data, ultimately leading to the drilling of the fourth well, 9-BRSA-1212-RJS (9-RJS-726). This well, in the Sururu Oeste area, revealed characteristics more similar to other Brazilian presalt fields and cleared the path to the later drilling of other Sururu Oeste wells. These good results paved the way for floating production, storage, and offloading (FPSO) vessel Petrobras 68 (P-68), which has produced both the Berbigão and Sururu reservoirs since November of 2019. P-68 is a 150,000-BOPD, 6-million std m³/d gas processing “replicant” FPSO that includes 10 producers (five from Berbigão and five from Sururu) and seven injectors (four in Berbigão and three in Sururu). However, the idea of developing an alternative for producing the Sururu Central area was never abandoned. In 2020, the ninth Sururu well and the fourth well in the central area, 9-SRR-5-RJS, was drilled near some of the main Sururu Central faults, aiming to test the existence of better reservoir quality or the presence of conductive in-situ fractures. The results from the well were in line with the results from the previous three wells drilled in the area, confirming the challenging nature of Sururu Central productivity. A suitable development strategy for the area was increasingly dependent on the attainment of long-term dynamic data that could support a modeling hypothesis for this unique presalt reservoir.

Technology Focus: Field Development (September 2024)

As the industry progresses, the need for further collaboration is imperative on all fronts. Academic expertise, operational experience, and knowledge gathered through trial-and-error analysis must be meshed in order to achieve the optimizations that are increasingly needed with the depletions we experience in various fields globally. The challenges that we face as an industry will require development of new technologies, whether workflows or other innovative solutions, that we never thought possible because of the need for supporting infrastructure to address them. The challenges also require more closely coupled connections between stakeholders—the innovators in academia and industry and the doers who close the gap of technology deployment. Deployment requires taking the ideas and tried and tested opportunities to fruition, where the knowledge is shared and highlighted for our community at large. The three papers synopsized in this feature include a discussion of augmented depletion development, a technique in which openhole wells are drilled within the fractured network of a pad; an approach to well-path generation that relies on the collection of experienced-based constraints from each discipline to generate possible alternatives to the well path; and a multidisciplinary approach used to develop a presalt field offshore Brazil. The hope is that the technical articles in this feature can demonstrate to the reader the scope of collaboration and the effect of technical knowledge sharing that our industry currently enjoys—and requires. I hope they drive more questions and provoke further and deeper understanding of the content to the benefit of all. More importantly, I hope they highlight the complexity that is involved in addressing the industry challenges in field development and project management.

Selection of well opening schedules in pre-salt reservoirs using WAG-CO2

In field development projects involving many wells, the limitation of available rigs can increase the need for investments. In our literature research about the definition of well opening schedules, we found some proposals but could not find studies that deep dive into this topic, nor any that propose an approach that could be applied to the Brazilian pre-salt fields. Therefore, this research focuses on evaluating the influence in the NPV of well opening schedule of a project using WAG-CO2, inspired in pre-salt fields, and we propose a simple procedure to specify the well opening schedule without having to perform many simulations or complex analysis. We used the UNISIM-II-D-BO benchmark (synthetic simulation model with characteristics of a Brazilian pre-salt field) and a well configuration proposed in a previous study, with 11 producers and 10 injectors. First, we calculated the distance between the producer and injector wells and evaluated the well economic indicator (WEI) of each well by opening all at the same time at the beginning of the production schedule. We then evaluated 252 combinations of those injector wells, where five of them were injecting water and the other five were injecting gas, from where we defined three reference alternatives to check the repeatability of the results. With all these data, we tested predefined schedules: (1) with the 1st injector well injecting only gas or participating in the WAG cycle; (2) the producers' opening sequence based on their WEI; (3) the injectors’ opening based on their WEI or distance to producers; and (4) testing the relationship between producers and injectors (number of producers to open before the injectors), making sure that all the gas could be reinjected. For comparison purposes, we then run an optimization algorithm to select the schedule, using 2,660 simulations. At the end, we verified that the difference between the optimization with the algorithm (demanding thousands of simulations runs) and the proposed schedules (demanding few simulations) in the NPV was about 2%. Thus, to speed-up decision making, it is possible to have an opening schedule with good performance considering a simple procedure, as follows: 1st injector well collaborating with the WAG; producer wells opening from the highest to the lowest WEI; injector wells opening from the closest to the furthest distance to the producers; and the relationship between producers and injectors has to be investigated, not only aiming to find the best economic return, but also because of the environmental restriction (the need to reinject all the produced gas). This procedure reduces the number of simulations that must be performed if an engineer decides to use an optimization technique.

Analysis of APB in vertical wells with evaporite layers: A 1D axisymmetric multilayer thermomechanical model

Temperature increases and creep in saline rocks can cause annular pressure buildup (APB), presenting a significant challenge in oil well operations, particularly in deep and ultra-deep pre-salt fields. This paper proposes a one-dimensional axisymmetric multilayer thermomechanical model that accounts for the influence of evaporite layers and thermomechanical effects on APB. We developed a finite element model that integrates heat transfer and thermomechanical interactions, utilizing a double deformation mechanism as a constitutive model to represent the viscous behavior of the rock formation. Additionally, this model enables the iterative calculation of fluid properties based on temperature and pressure conditions. To validate the model, we conducted case studies using widely adopted commercial finite element software. Its consistent results provide a deeper understanding of the pressure increases caused by the influence of saline rock and thermal effects, offering valuable insights into the safe and efficient operation of oil wells using a model with reduced computational complexity.

A REVIEW ON CARBON DIOXIDE (CO2) – ASPHALTENES INTERACTIONS

WAG - CO2 is an oil enhanced recovery method that has been applied successfully to some of the largest pre-salt fields in Brazilian offshore oil provinces. This recovery method provides the advantage of reducing the emission of green-house gas (CO2) to the atmosphere. However, the re-injection of CO2 gas into reservoirs may also provoke deleterious effects on asphaltenes equilibria under reservoir conditions, promote pore plugging, and inflow formation damage. Thus, it is crucial that researchers investigate with caution the use of WAG- CO2 method to avoid unwanted situations. This technical contribution reviews the state of the art of WAG- CO2 recovery method, provides useful pieces of information of laboratory studies on the behavior of asphaltenes in presence of CO2, and, finally, it presents prescriptive guidelines for addressing pivotal CO2 - asphaltenes issues.

High-Pressure Separation: New Technology in the Subsea Toolbox

_ Subsea production systems have come far in the more than 60 years since the first deployment in the US Gulf of Mexico, helping many countries unlock their offshore hydrocarbon riches in the years that followed. For Brazil, it was a combination of advances in subsea technologies and floating production, storage, and offloading vessel (FPSO) designs that supported the growth of its offshore oil and gas prowess. From those first forays into the Sergipe-Alagoas basin in the northeast during the 1970s, the country’s offshore oil and gas footprint has grown significantly, with today’s production from the pre-salt Campos and Santos basins—located farther from shore and in much deeper water—launching state-run oil company Petrobras to a top spot among the ranks of global producers. The ongoing development of its offshore fields will continue to boost the country’s oil and natural gas production in 2024. Since December 2022, five FPSOs have been brought online, with four installed in 2023 delivering record output. The fifth one—the FPSO Sepetiba—delivered a New Year’s Day surprise when it came online at Mero 2 oil field on 31 December 2023. HISEP, a new subsea technology currently being readied for pilot testing, could potentially ensure continued future production of the Mero field and others by capturing CO2-rich dense gases directly from the wellstream and reinjecting it into the reservoir. The technology also frees up much-needed space and reduces weight on the FPSO’s topside by moving the separation process to the seafloor. Challenges and Solutions Brazil’s challenging offshore pre-salt region—first explored by Petrobras in 2005—contains estimated reserves of 30 to 40 billion BOE and comes with an extensive list of development challenges. Its Santos Basin, for example, lies in ultradeep water with hydrocarbon reservoirs located at extreme depths ranging from 5500 to 7600 m below sea level and under salt layers more than 2000 m thick. But the challenges do not end there. Managing the basin’s high gas/oil ratio (GOR) and CO2 content leaves a significant operational footprint. In OTC 29762, authors from Petrobras noted that developing the pre-salt reservoirs requires “large production facilities with complex gas processing plants that limit the oil processing and storage capacities.” In the paper presented at the 2019 Offshore Technology Conference (OTC) Brasil, the authors said that the gas processing plants for some pre-salt fields with high production indexes, GOR, and CO2 content account for nearly 60% of the total FPSO topsides area. The Santos Basin is home to the Mero oil field, the country’s third-largest pre-salt field and the first under a production-sharing contract awarded to the Petrobras-led Libra Consortium. The field is considered one of the largest hydrocarbon discoveries in the past decade, covering about 320 km2 of the Libra block and with a net pay zone reaching 420 m filled with 29 °API oil and high productivity, according to Ana Luiza Neder, et al. (OTC 32784).

Use of near-infrared spectroscopy for the online monitoring of natural gas composition (hydrocarbons, water and CO2 content) at high pressure

The natural gas production from Brazilian pre-salt fields imposed new challenges for petrochemical industry. Actual treatment facilities are not adequate for this new scenario and studies have been conducted to apply new adsorbents materials and membranes for water and CO2 removal from natural gas at high pressures. To better develop such investigations, sensors for on-line monitoring of natural gas properties like CO2 and water content are important, since their presence affects the quality of the final product. Near infrared (NIR) spectroscopy associated to chemometric models (partial least squares) were employed for on-line monitoring of representative natural gas systems (methane/CO2, methane/water and methane/CO2/water) and a real natural gas at temperature and pressure ranges from 20 to 60 °C and 10 to 200 bar, respectively, water content up to gas saturation and CO2 content up to 50 wt%. Water solubility values used as reference for NIR Spectrometer calibration in model systems were taken from the literature and for real natural gas calculated with Cubic Plus Association (CPA) Equation of State (EoS), while CO2 content was experimentally controlled aiming to calibrate the chemometric models in the full range of pressure and temperature. Several strategies were adopted for the chemometric model’s development to obtain the best correlation between NIR spectra and experimental data. Results indicate good correlation in both calibration and validation steps attaining linear correlation coefficients (R2) higher than 0.96 for all systems investigated. The proposed methodology is a potential tool for on-line monitoring of natural gas composition, including CO2 and water content, at high-pressures and can be applied at petrochemical industries or in laboratories, dispensing sampling or any sample preparation.

MODEL-BASED OPTIMIZATION OF ICVs’ CONTROL FOR PRODUCERS, INJECTORS, AND WAG-CO2 CYCLES SIZE IN A CARBONATE RESERVOIR UNDER UNCERTAINTY

Life cycle management of oil fields involves complex decisions, with many variables to be considered. In some fields of the Brazilian pre-salt, this task is even more challenging given the ultra-deep water location, with an expressive amount of gas (including CO2) production. This feature becomes a restricting factor for oil production in these types of fields, and a proper management is essential to overcome this issue, improving both production and economic returns. Therefore, Water-Alternate-Gas (WAG) is often used as an Enhanced Oil Recovery- EOR mechanism, providing a better mobility control, improving reservoir sweep and oil recovery. Moreover, WAG can be an alternative for recycling the produced gas, providing an adequate destination (mainly for CO2) and avoiding environmental problems. In this case, we name the method as WAG-CO2. Moreover, Interval Control Valves (ICVs) are also a good alternative to deal with these fields, since they work as flow control devices and allow for a better balance of the fluid flow in the reservoir. In this work, we evaluate the impact of the use of ICVs in producers, injectors, along with WAG cycles size to improve the performance of a developed field. The work consists of two parts. In Part I, using a single simulation model, we performed (1) six hierarchical optimization approaches to verify if the order in which the optimization occurs influences the final results, and (2) a joint optimization of all parameters for comparison purposes. The final strategies are simulated in a reference case (representing the “true response” of the field) to evaluate how the achieved control rules would behave in a real field. In Part II, we considered a probabilistic procedure, applying one of the hierarchical approaches in several representative models (RMs) expressing uncertain scenarios. In this case, we compared nominal optimization of individual RMs against a robust optimization (in which all RMs are optimized simultaneously). The study is applied to the benchmark case SEC1_2022, a synthetic model analogous to a pre-salt field. The results show an expressive increase in the economic return of the field with a proper operation of the ICVs and size of the WAG-CO2 cycles, despite the platform being restricted by gas production capacity. This result occurred because of a better balance in fluid flow through the reservoir and among wells. Moreover, in the first part of the work, all hierarchical approaches presented very similar results in terms of NPV, so the order of the optimization steps did not significantly affect the results. The non-hierarchical approach presented a slightly better result, but still close to those obtained in the hierarchical approaches. Furthermore, the most impacting variable was the ICV for producers, followed by ICV for injectors and, then, WAG-CO2 cycles. Similar tendencies were observed in the second part of the work, with higher expected economic return for the robust optimization.

Integrated approach to improve numerical and geostatistical performance on a naturally fractured carbonate reservoir

The numerical simulation of carbonate reservoirs, while keeping the heterogeneous behavior in a reasonable development time, is a challenge. This study introduces a new method to improve simulation of complex carbonate reservoirs, balancing speed and accuracy by using multiple stochastic techniques and hierarchical upscaling. The methodology has five main steps: (1) develop the geological model, (2) hierarchical upscaling and numerical validation, (3) define the probabilistic workflow, (4) Discretized Latin Hypercube combined with geostatistical realizations, and (5) computational cost. The methodology is applied to a Brazilian pre-salt field. The time consumption for the numerical simulation and geomodelling of the proposed workflow was compared against conventional procedures. Notably, the hierarchical upscaling approach allowed the use of a reference model for the dynamic matching procedure. Innovative elements include implicit modeling of small-scale fractures within the matrix domain using analytical averaging techniques, the incorporation of pseudo-functions, and the direct integration of the discrete fracture network into the simulation grid. These advancements result in a remarkable reduction of 20% in simulation time and a 60% decrease in the time required to generate new geostatistical images. The innovative approach presented herein promises to address critical challenges in carbonate reservoir simulation, advancing the field’s understanding and practice.

Coquina depositional model, Buzios Field, Brazil

Increasingly relevant as petroleum reservoirs, the coquina deposits of the pre-salt section of the Santos and Campos Basin display a wide variety of sedimentary systems that reflect a complex storm-dominated depositional environment. This complexity resulted in the deposition of numerous sedimentary facies distributed among structural lows and highs, and their understanding is an essential aspect in order to reduce exploration risks. Therefore, the aims of this contribution are twofold: (a) to understand the depositional processes during the generation of the Itapema Formation coquina deposits in the offshore pre-salt Buzios Field, Santos Basin, and (b) to establish a depositional model and identify stacking patterns in the coquina section. The facies analysis was based on rock texture, structure, allochemical composition, taxonomic composition, and taphonomic characteristics of bivalve shells, such as fragmentation, abrasion, sorting, thickness, orientation, and articulation. We described 695 thin-sections and sidewall samples distributed among ten wells in the field area. The analysis resulted in sixteen facies grouped into eight facies associations: (1) bioclastic bars, (2) washover deposits, (3) backshore, (4) bioclastic beaches, (5) tempestites, (6) tempestites with articulated shells, (7) offshore and offshore transition deposits, and (8) offshore siliciclastic mudstones. These carbonate facies associations were deposited mainly under the influence of waves and currents in isolated ramp-shaped margined platforms with low continental input associated with active faults, characteristic of the rift phase of the basin evolution. The stacking of the facies associations indicates that the Itapema Formation coquinas were deposited in an environment that became progressively shallower towards the top contact with the overlying Barra Velha Formation. Siliciclastic mudstones mark the top of the Itapema Formation immediately below the Pre-Alagoas unconformity, indicating a significant lake deepening that drowned the coquina section. The depositional model is the first one about the Buzios Field and the first about the pre-salt fields coquinas based on field-scale information.

Evaluation of fluid–fluid and rock–fluid interfacial interactions using silica nanofluids and crude oil for a deepwater carbonate pre-salt field

Evaluation of fluid–fluid and rock–fluid interfacial interactions using silica nanofluids and crude oil for a deepwater carbonate pre-salt field

Synthetic seismic-stratigraphic interpretation from a sedimentological forward model in a pre-salt field in the Santos Basin

Forward modelling of sedimentary systems is a method that simulates sedimentation processes over geological time to generate a set of facies distributed in a depositional space. The objective of using forward modelling in this work was to build a 3D facies model from which a synthetic seismic simulation was generated, and then to analyse the relation of seismic-stratigraphic interpretations with the knowledge of the a priori generated sedimentological model. This modelling methodology was applied in a pre-salt field in the Santos Basin, Brazilian offshore, focused on the Barra Velha Formation. The modelling parameters used were: (i) the initial surface of bathymetric depth; (ii) the lake-level variation; (iii) the subsidence map; and (iv) the deposition rates of the facies. Average-constant of acoustic impedance values were assigned to each facies and a synthetic seismic was obtained. With the facies and synthetic models available, it was possible to analyse: (i) the distribution of thicknesses and proportion of facies by region; (ii) the vertical stacking pattern and lateral facies variation; (iii) the Wheeler distance × time diagram; and (iv) the seismic reflector patterns through the seismic facies classification. Through these analyses it was possible to better understand the possibilities and limitations of seismic stratigraphy as an interpretation auxiliary tool in pre-salt carbonate environments.

Scale inhibitor qualification: evaluation for treatment in Brazilian pre-salt fields

Scale inhibitor qualification: evaluation for treatment in Brazilian pre-salt fields

An experimental assessment of seawater alternating near-miscible CO2 for EOR in pre-salt carbonate reservoirs

Enhanced oil recovery (EOR) methods considering the injection of seawater and CO2 have been widely investigated and applied in the Brazilian pre-salt fields. The high availability of these fluids in offshore facilities makes seawater alternating CO2 (CO2WAG) a viable and environmentally friendly EOR method. It combines the advantages of seawater injection and CO2 injection to improve fluid mobility control and viscous fingering attenuation. In this study, in addition to the core flooding test of secondary seawater flooding and the tertiary CO2WAG, different experimental determinations provided a better understanding of the mechanisms related to the EOR methods applied to a carbonate core composed mainly of dolomite, and their interactions with pre-salt oil, brines and CO2. A 13.30% incremental oil recovery was achieved by alternating seawater with CO2. Considering formation brine, non-carbonated seawater, or seawater saturated with CO2, contact angle measurements revealed that the wettability alteration is not significant when dolomite is slightly water-wet, even in the presence of CO2. On the other hand, measures of brine/oil, brine/CO2/oil and CO2/oil interfacial tension emphasize the beneficial effects of this gas for EOR, in near-miscible conditions. This is achieved by the reduction of capillary and interfacial forces that act by trapping the oil in the pores of the medium. The brine salinity, the presence of magnesium in dolomite and the oil's low TAN/TBN ratio proved to be essential factors in determining the slightly water-wet wettability of the dolomitic rock and the interfacial tension between the phases. Furthermore, for the experiments carried out in the presence of brine with solubilized CO2, a considerable variation in the oil drop volume was observed due to the mass transfer of CO2 between the phases. Finally, experimental results showed that the additional oil recovery was mainly associated with oil swelling, viscosity reduction, and mobility increase, which occur even in near-miscible conditions during CO2WAG.

Mineralogical Modeling and Petrophysical Properties of the Barra Velha Formation, Santos Basin, Brazil

The Santos Basin, offshore Brazil, has the most significant petroleum carbonate reservoir province in South America. The presalt carbonates reservoirs of the Barra Velha Formation (BVF) present a complex mineralogic distribution and heterogeneous physical properties, making it challenging to construct a reliable mineralogical model. Understanding rock mineralogy is important to petroleum prospects and the study of porous media, besides calibrating seismic facies. In this paper, we present a mineralogical inversion procedure to model reservoir and nonreservoir intervals within the BVF in a presalt field applying multicomponent inversion. The uppermost 15 to 28 m of the BVF, known as “Lula Fingers,” present higher values of gamma ray when compared with deeper intervals and are characterized by high modeled dolomite contents. Below the Lula Fingers region, the Upper BVF can be divided into BVF100 (top), which is characterized by low gamma ray values just above the BVF200 (bottom). They are formed mainly by shrub and spherulite-rich in-situ facies with fewer clay and Mg-clays contents, which are often replaced by dolomite and quartz. The bottom part of Upper BVF (BVF200) presents a microporous Mg-clay-rich interval, mainly in the structural flanks region, or a macroporous Mg-clay-poor interval, mainly in high levels. The present model fits well with the stratigraphic interval and allows a better understanding of the mineralogical distribution over the entire BVF100 and BVF200, particularly the lateral mineralogical variability in regions with structural highs and flanks.

Special Connections for Representing Multiscale Heterogeneities in Reservoir Simulation

Summary The significant quantities of oil contained in fractured karst reservoirs in Brazilian presalt fields add new challenges to the development of upscaling procedures to reduce time on numerical simulations. This work aims to represent multiscale heterogeneities in reservoir simulators based on special connections between matrix, karst, and fracture mediums, both modeled in different grid domains within a single porosity flow model. The objective of this representation is to strike a good balance between accuracy and simulation time. Therefore, this work extends the approach of special connections developed by Correia et al. (2019) to integrate both karst and fracture mediums modeled in different grid domains and block scales. The transmissibility calculation between the three domains is a combination of the conventional formulation based on two-point flux approximation schemes and the matrix-fracture fluid transfer formulation. The flow inside each domain is governed by Darcy’s equation and implicitly solved by the simulator. For proper validation and numerical verification, we applied the methodology to a simple case (two-phase and three-phase flow) and a real case (two-phase flow). For the simple case, the reference model is a refined grid model with (1) an arrangement of large conduits (karsts), which are poorly connected; (2) a well-connected and orthogonal system of fractures; and (3) a background medium (matrix). The real case is a section of a Brazilian presalt field, characterized as a naturally fractured carbonate reservoir. The reference is the geological model. The simulation model consists of a structural model with different gridblock sizes according to the scale of the heterogeneities—small-scale karst geometries, medium-scale matrix properties, and larger-scale fracture features—interconnected by special connections. The results for both cases show a significant performance improvement regarding a dynamic matching response with the reference model, within a suitable simulation time and maintaining the dynamic resolution according to the representative elementary volume of heterogeneities, without using an unstructured grid. In comparison to the reference model, for the simple case and the real case, the simulation time was reduced by 42% and 87%, respectively. The proposed method contributes to a multiscale flow simulation solution to manage heterogeneous geological scenarios using structured grids while preserving the high resolution of small-scale heterogeneities and providing a good relationship between accuracy and simulation time.

Cavern integrity for underground hydrogen storage in the Brazilian pre-salt fields

Over the years, energy has depended on petroleum-based fuels. However, global warming and the energy crisis have drastically impacted the markets. It urges investing in renewable energy resources, such as hydrogen. Therefore, this work focuses on the hydrogen storage process in salt caverns, as these rocks have relevant properties, such as low permeability, relevant creep, and self-healing. A workflow for cavity integrity analysis is proposed. Hydrogen storage provokes variations in temperature and pressure inside the cavern. The gas thermodynamics is represented through a diabatic solution, which updates the gas pressure and temperature at each time step. The thermomechanical formulation is implemented into an in-house framework GeMA, which couples different physics. Four case studies are analyzed, and the discussions compared mechanical and thermomechanical models. Results demonstrate the importance of thermal effects, as temperature amplitudes may compromise rock integrity, for instance, inducing tensile stresses and affecting permeability.

UNISIM-IV: BENCHMARK PROPOSAL FOR LIGHT OIL CARBONATE RESERVOIR WITH HIGH CO2 CONTENT

The Brazilian pre-salt fields are carbonate reservoirs with good quality oils, but they can present high amount of CO2 in dissolution, which leads to a high amount of produced gas and can limit oil production. Therefore, the development and management of fields with those characteristics are complex tasks that involve many decisions, with a large number of variables to be considered. Thus, numerical simulation plays an important role in overcoming the challenges that arise from the management of these fields, integrating different subjects such as geosciences and reservoir characterization, data assimilation, production facilities, production optimization processes, economic evaluation, and decision analyses under uncertainty. Open source benchmarks are often used in numerical simulation studies to evaluate and compare techniques and methods, using the same comparison basis. The objective of this paper is to present UNISIM-IV, a set of carbonate benchmarks analogous to a pre-salt field, adding new possibilities to the scientific community and organizations that can improve workflows in the context of reservoirs with the characteristics mentioned above. The benchmark is divided into four different cases: UNISIM-IV-2019, UNISIM-IV-2022, UNISIM-IV-2024, and UNISIM-IV-2026, where the date refers to the date of the analysis. The main differences among these cases involve the stage of field’s life cycle, ranging from early development phase (2019) to a developed reservoir with eight years of production (2026). Thus, the available history data and the mapped uncertainties differ between the cases. The users can choose the case that best suits their needs, depending on specific research objectives. Each of these cases comprise: (1) an ensemble of prior uncertainties, (2) production, injection, and pressure history data, and (3) a history-matched simulation model suggested as a base case. There is also a reference case, named UNISIM-IV-R, which consists of a model with a very refined grid and known information used as the “true response” to generate all data that could be measured in a real field, such as production history and well logs.

Full-waveform inversion based on generalized Rényi entropy using patched Green's function techniques.

The estimation of physical parameters from data analyses is a crucial process for the description and modeling of many complex systems. Based on Rényi α-Gaussian distribution and patched Green's function (PGF) techniques, we propose a robust framework for data inversion using a wave-equation based methodology named full-waveform inversion (FWI). From the assumption that the residual seismic data (the difference between the modeled and observed data) obeys the Rényi α-Gaussian probability distribution, we introduce an outlier-resistant criterion to deal with erratic measures in the FWI context, in which the classical FWI based on l2-norm is a particular case. The new misfit function arises from the probabilistic maximum-likelihood method associated with the α-Gaussian distribution. The PGF technique works on the forward modeling process by dividing the computational domain into outside target area and target area, where the wave equation is solved only once on the outside target (before FWI). During the FWI processing, Green's functions related only to the target area are computed instead of the entire computational domain, saving computational efforts. We show the effectiveness of our proposed approach by considering two distinct realistic P-wave velocity models, in which the first one is inspired in the Kwanza Basin in Angola and the second in a region of great economic interest in the Brazilian pre-salt field. We call our proposal by the abbreviation α-PGF-FWI. The results reveal that the α-PGF-FWI is robust against additive Gaussian noise and non-Gaussian noise with outliers in the limit α → 2/3, being α the Rényi entropic index.

Geomechanical effects of natural fractures on fluid flow in a pre-salt field

The discovery of carbonate reservoirs in the Brazilian pre-salt field has raised several engineering challenges. These reservoirs are naturally fractured and much stiffer than conventional reservoirs. Thus, the study of fluid flow through natural fractures has received significant attention from the petroleum industry because the production capacity of these fields is associated with the hydraulic behavior of such fractures. However, pressure changes induced by the oil recovery alter the fracture aperture. In turn, changes in the fracture aperture affect the fluid flow inside the fracture channels, increasing or reducing the production capacity of the reservoir. This work investigates the hydromechanical effect of natural fractures on the reservoir behavior at the production unit Tupi pilot of the Brazilian pre-salt. The enhanced dual-porosity/dual permeability model (EDPDP) is adopted to simulate more realistically the hydromechanical behavior of fractured carbonate rock formation. This approach updates the stiffness and permeability tensors considering the fracture orientation and the stress-induced aperture changes. The shape factor is also improved to represent multi-block domains formed by several multiscale fracture sets with different orientations, apertures, and spacing. The hydromechanical formulation of EDPDP implemented in an in-house framework GeMA (Geo Modeling Analysis) is adopted to study the hydromechanical effect of fractures with multiple lengths on the Tupi pilot. The numerical results demonstrate that the complex fracture network is responsible for fluid migration through a preferential pathway. A parametric analysis of the main parameters that affect reservoir behavior was carried out. The parametric study shows higher pore pressure dissipation for smaller dip angles. Then, horizontal fractures are more sensitive to vertical displacements. In addition, smaller spacing and larger fracture aperture enhance permeability, increasing pore pressure dissipation and mechanical deformation. Finally, numerical results were compared against field measurements showing excellent agreement, demonstrating the applicability of the EDPDP model to simulate naturally fractured reservoirs.