Manuel Gomes Correia

UNISIM-II-D: Benchmark Case Proposal Based on a Carbonate Reservoir

Brazilian pre-salt reservoirs are mainly carbonate formations and they represent a great opportunity for research development. There is an increasing need of synthetic simulation models that reproduce these Pre-salt flow features for research development in reservoir simulation. This work presents a simulation benchmark model available as public domain data that represents Brazilian pre-salt trends and add a great opportunity to test new methodologies for reservoir development and management using numerical simulation. The work structure is divided in three steps: development of a reference model with known properties, development of a simulation model under uncertainties considering a specific date that represents the field development phase, and, elaboration of a benchmark proposal for studies related to the oil field development and production strategy selection. The reference model, treated as the real field, is a fine grid model in order to guarantee a high level of geologic details. The simulation model under uncertainties is a large scale model, a result of a development project considering an initial stage of field management. The benchmark model is based in a combination of Pre-salt characteristics and Ghawar field information given its diagenetic events and flow features close to Pre-salt. Based on the available information, several uncertainty attributes were considered in structural framework, facies, petrophysical properties, discrete fracture network. Economic and technical uncertainties were also considered. There is an increasing need of synthetic simulation models that reproduce these Pre-salt flow features for research development in reservoir simulation. This work presents a simulation benchmark model available as public domain data that represents Brazilian pre-salt trends and add a great opportunity to test new methodologies for reservoir development and management using numerical simulation. The main result of this project is achieved: the construction of a reference model and the construction of a simulation model under uncertainties assuming the well log information from three wells. This work provides a great contribution for further research development in reservoirs with geologic and dynamic pre-salt trends. Introduction Pre-salt carbonate reservoirs from Santos Basin, Brazil, represent a great opportunity and an important recent oil discovery. Challenges in pre-salt of Santos Basin can be classified into three main categories: (1) description and representation of reservoirs fluids and rock heterogeneities, (2) selection of the best production strategy according to the reservoir characteristics and (3) prediction of the future reservoir performance. Formation test in ultra deep SAG reservoirs have presented very high flow rates with no indication of barriers and high vertical heterogeneity in permeability (Beltrão et al, 2009). One of the biggest challenges is how to represent the most important heterogeneities in reservoir simulation models. The reservoirs are non-conventional, quite heterogeneous, with many uncertainties and with very few analogues in the world, especially considering the environment and expected production profiles. The reservoir characterization and modeling is restricted to a few wells and consequently core volume information, resulting in a high amount of uncertainty (Nakano et al, 2009). Many of these uncertainties are related to reservoir characterization: facies distribution, hydraulic connection and existence of high permeability layers (Super-k features). The term Super-k features was first introduced to Ghawar field and is related to very thin layers with high permeability and porosity. An early partial dolomitization provides preferential fracturing allowing later diagenetic fluids to penetrate the formation and dissolve away non-dolomitized material, creating a permeable and porous material, which is mainly dolomite. Some of these dolomites are related to high flow zones, named then Super-k. Although fractures were absent in cores, their presence is proposed as a mechanism for creating Super-k properties (Swart et al, 2005). The introduction of these thin layers in reservoir simulation leads to specific challenges: (1) management of early water breakthrough which may constrain the future placement of water injection or production wells; (2) evaluation of possible drilling of complex wells with intelligent completions; (3) upscaling and numerical simulation skills to incorporate these thin high flow features for reservoir simulation purposes; (4) correct modeling of behavior of Water-Alternating-Gas (WAG) method which can significantly enhance the recovery for highly heterogeneous reservoirs; (4) make uncertainty analysis given the complex genesis of these flow features and lack of information (pre-salt reservoirs). Therefore, there is an increasing need of synthetic simulation models that reproduce these Pre-salt flow features for research activities on reservoir simulation. An example of a simulation model built for benchmark studies include UNISIM-I (Avansi and Schiozer, 2015) which represents a siliciclastic reservoir model. Objectives The purpose of this work is to develop a benchmark case (UNISIM-II) that involves a simulation model with geological trends and rock/fluid data with characteristics of the Pre-salt known behavior for reservoir simulation purposes. Given the lack of geologic information, the reservoir model is a combination of Pre-salt reservoirs data and information from Ghawar Field, a carbonate reservoir with geologic trends close to Pre-salt features. The work structure is divided in three steps: (1) development of a refined grid model with known characteristics called UNISIM-II-R, providing an opportunity to test methodologies for reservoir development; (2) build of a simulation model under uncertainties, called UNISIM-II-D, for the initial stage of field development; (3) elaboration of a benchmark proposal, also called UNISIM-II-D, for studies related to the oil field development and production strategy selection. Model Data The geologic and rock/fluid data combines Pre-salt data, Ghawar field information, real carbonate reservoir (Field A) and synthetic data. The field information taken into account for UNISIM-II-R is: ● Carbonate Reservoir of microbial origin, partially dolomitized (Pre-salt and Ghawar); ● High vertical heterogeneity in permeability (Pre-salt and Ghawar); ● High flow rates with no indication of barriers (Pre-salt and Ghawar); ● High permeability thin zones named Super-k (Pre-salt and Ghawar); 2 SPE-177140-MS

Integration of Highly Permeable Thin Layers Into Flow Simulation

Giant reservoirs such as Lula (Santos Oil Basin, Brazil) and Ghawar (Saudi Arabia) have high permeability intervals, known as super-k zones, associated with thin layers. Modeling these small-scale flow features in large-scale simulation models is complex. Current methods are limited by high computational costs or simplifications that mismatch the representation of these features in simulation grid blocks. This work has two purposes: (1) present an upscaling workflow to integrate highly laminated or inter-bedded reservoirs with thin, highly permeable layers in reservoir simulations through a combination of (a) an explicit modeling of super-k layers using Parsons (1966) formula and (b) dualmedium flow models, and (2) compare this method with two conventional upscaling approaches, available in commercial software. We use the benchmark model UNISIM-II-R, a fine single-porosity grid based on field information from the Brazilian Pre-salt and Ghawar oil fields, as the reference solution to compare the upscaling matching between the three methods. We compare; oil recovery, water cut, average reservoir pressure, waterfront, and the time consumption for simulation. Our proposed parsons dual-medium (PDP) methodology achieved better upscaling matches with the reference model and had minimal time consumption when compared with the representation of super-k layers through an implicit matrix modelling by single porosity flow models (IMP) and through the explicit representation of super-k zones in the fracture system of dual-medium flow models (DFNDP).

Quantification of Simulation Model Grid Size Impact on Polymer Flooding Application in Heavy Oil Heterogeneous Reservoir

Polymer flooding can be a viable alternative to enhance oil recovery of heavy oil fields. The comparison of water and polymer flooding requires a reliable reservoir numerical model to safely ensure the decision analysis including uncertainties and involving a significant amount of simulation runs. Reservoir engineers usually work-around this problem using fast models to reduce computational time; however, it is important to maintain the reliability of heterogeneous reservoir models. Therefore, the proposed work demonstrates how the grid size impacts on accuracy of results and both the time and computational resources. In addition, it is performed an analysis to establish how the typical physical phenomena related to the polymer flooding impact the applicability of the proposed methodology. A highly heterogeneous heavy oil field is used in our proposed studies. The application is conducted to assist pilot test wells. Initially, the definition of the reference strategy (OTM) is presented. In this case study, the OTM strategy is based on the optimization of location and number of wells. Secondly, the effect of grid size on the process is evaluated through two procedures: (1) DA method: a selection of grid size defined by drainage area of the selected wells; and (2) UP method: upscaling is performed in the simulation model. Then, production parameters resulting from models of both procedures (DA and UP) are compared with OTM results. The definition of which procedure is better to represent the wells of interest is performed. Finally, the impact of three polymer flooding physical phenomena (degradation, adsorption and Non-Newtonian effect) on production results is presented, in order to verify the accuracy of the generated fast models in maintained considering these effects. The DA method present good accuracy for reservoir response compared to the reference OTM results. Differently, UP models are not as accurate as DA models for production results indicators. In conclusion, the application of the methodology allows choosing the DA over the UP technique to support our decision in the investigated recovery methods, showing a reliable and fast procedure. Finally, this procedure shows excellent applicability and robustness when a typical polymer flooding study is carried out: the evaluation of physical phenomena impact on production results based on wells of interest. Introduction The oil industry has experienced a gradual decrease on the discovery of new oil deposits on the last decades (Alvarado and Manrique, 2010) and, the reserves that have been found lately are located in

The Impact of Rock Wettability in Fractured Reservoirs Behavior

Fractures can have a great impact on reservoir management and, therefore, the earlier the influence is determined, better is the management process. The rate at which water may transfer from the fracture to matrix system can vary according primarily to the rock wettability, matrix permeability and fracture intensity (Narr et al, 2006). Matrix-to-fracture transfer functions in reservoir simulation assume that fractures are instantaneously filled with water. However, these circumstances cannot be observed for some conditions, such as water-wet rocks. Rangel-German et al, 2010, introduce these observations by laboratorial experiments. So, depending on rock wettability, it could result in upscaling issues given the presence of imbibition forces in water-wet rocks which are not well represented in dual porosity numerical models. The purpose of this study is to show the impact of rock wettability in reservoir simulation and upscaling procedures, for fractured reservoirs. The relative permeability curves used for this work are a combination of real field data and synthetic data (Ligero and Schiozer, 2014).

Integration of Multiscale Carbonate Reservoir Heterogeneities in Reservoir Simulation

The link among geological carbonate heterogeneities, such as fractures and vugs, upscaling procedures and simulation flow models remains a challenge. This work perform an methodology aiming a suitable representation of simulation flow model and upscaling procedures approach according to small and large scale carbonate reservoir heterogeneities. The methodology is applied to one flow unit considering diffuse fractures, sub-seismic fractures and vugs. The methodology has shown several advantages: sequential control over static properties and pseudo functions along upscaling procedure; simplification of the match procedure as is done sequentially by heterogeneities scale over the upscaling; reduction of the uncertainty in the accurate simulation flow model approach; reduction of time consumption in flow simulation and project development as the methodology can be implemented for uncertainty workflows; improvement of the integration of multiscale heterogeneities in reservoir simulation. This work presents a significant methodology and analysis that can be useful for multidisciplinary areas of expertise since it integrates geostatistical modeling of carbonate reservoir heterogeneities with reservoir simulation.

Comparação de métodos de estimativa de profundidades de fontes magnéticas utilizando dados aeromagnéticos da província mineral de Carajás, Pará

With the goal of providing an effective analysis for assessment and interpretation of depth to magnetic sources, depth estimates were yielded from high density, aeromagnetic data collected over the Serra Leste region (Carajas Mineral Province, Para State, Brazil), by three distinct methods: (i) Euler Deconvolution; (ii) Analytic Signal; and (iii) Local Wavenumber. According to the results obtained by these three methods, most of the magnetic sources in the study area are located above 100 m depth. Statistical analysis showed that the Euler Deconvolution method provides more accurate depth estimates (mean standard error = 6%) and that the solutions are better correlated with geological structures and contacts, especially those related to the mineral deposits. For instance, it was verified that the Serra Pelada (Au, Pt, Pd) deposit is located over a NNE-SWW dipping magnetic trend with depths increasing from 25 to 270 m. At this deposit, the estimated depth is about 205 m.