Jesus Alberto Canas

Fluorescence Methods for Downhole Fluid Analysis of Heavy Oil Emulsions

Acquisition of oil samples from the reservoir prior to oil production is essential in order to design production strategies and production facilities. In addition, reservoir compartmentalization and hydrocarbon compositional grading magnify the necessity to map fluid properties vertically and laterally in the reservoir prior to production. Downhole fluid analysis (DFA), performed in situ in the oil well, helps optimize this fluid mapping process. However, for heavy oil reservoirs drilled with water based muds, fluid mapping has been largely precluded due to the formation of stable water‐in‐oil (w/o) emulsions, which add significant complexity to sample acquisition and which can preclude standard DFA measurements. Here, fluorescence measurements are shown to be dependent on oil type but independent of the state of emulsion even at very high water fractions. Thus, downhole fluorescence measurements can be used to perform hydrocarbon fluid mapping in the reservoir. The sensitivities of fluorescence and optical absorption measurements are determined for different excitation wavelengths, oil type, and oil concentration.

DFA Connectivity Advisor: A New Workflow to Use Measured and Modeled Fluid Gradients for Analysis of Reservoir Connectivity

In deepwater and other high-cost environments, reservoir compartmentalization has proven to be a vexing, persistent problem that mandates new approaches for reservoir analysis. In particular, methods involving reservoir fluids can often identify compartments; however, it is far more desirable to identify reservoir connectivity. Downhole fluid analysis (DFA) has enabled cost-effective measurement of compositional gradients of reservoir fluids both vertically and laterally. Modeling of dissolved gas-liquid gradients is readily accomplished using a cubic equation of state (EOS). Modeling of dissolved solid (asphaltenes)liquid gradients can be achieved using the newly developed Flory-Huggins-Zuo equation of state (FHZ EOS) with its reliance on the nanocolloidal description of asphaltenes within the Yen-Mullins model. The combination of new technology (DFA) and new science (FHZ EOS) provides a powerful means to address reservoir connectivity. It has previously been established that the process of equilibration of reservoir fluids generally requires good reservoir connectivity. Consequently, measured and modeled fluid equilibration is an excellent indicator of reservoir connectivity. However, some reservoir fluid processes are faster than equilibration rates of reservoir fluids. The often slow rate of fluid equilibration makes it a suitable indicator of connectivity. Consequently, measurement of disequilibrium can still be consistent with reservoir connectivity. Moreover, the two fluid gradients, dissolved gas-liquid versus dissolved solid-liquid can be separately responsive to different fluid processes, thereby complicating understanding. A workflow is developed, the DFA reservoir connectivity advisor, to enable interpretation of the implications of measured fluid gradients specifically with regard to reservoir connectivity. Reservoir connectivity is difficult to establish in any event; analyses of fluid gradients can be placed in a context of the probability of connectivity, thereby significantly improving risk management.

WBM Contamination Monitoring While Sampling Formation Water with Formation Testers: A Novel Approach

Formation water sampling is important for characterizing hydrocarbon/water transition zones, understanding scaling and corrosion potential of the water, and determining compatibility between formation water and injection water. When sampling water with wireline formation testers at wells drilled with water-base muds (WBM), it is important to track mud filtrate contamination by distinguishing between formation water and mud filtrate in real time while sampling. Current techniques are mainly qualitative (e.g., resistivity sensors), use readings by stations (e.g., downhole pH measurements), or require colouring the mud (e.g., blue dye) and do not always allow a continuous quantitative monitoring. We present a solution that allows continuous monitoring of the water sampling cleanup process as a way to better understand cleanup profiles. To achieve this goal, a fluorescent tracer was added to the mud system while drilling the zone of interest. By adding this tracer, we were able to continuously monitor the cleanup process by means of the downhole fluorescence sensor of a wireline formation tester (WFT) string. Prejob calibrations allowed us to interpret the fluorescence sensor’s reading, considering that the formation water is free of fluorescence response and that any response will indirectly indicate the presence of filtrate in the flowing fluid. The fluorescent tracer was found appropriate to this task because it is detectable at very low concentration levels during qualification tests performed at surface conditions. Additionally, there were no detected tracer absorption issues in the reservoir affecting the process. Field examples are presented of downhole fluid sampling operations in heterogeneous offshore carbonate systems, which are compared with laboratory results that confirm the success of this real-time monitoring solution. It also helps to improve best practices for selection of formation sampling stations and formation testers as function of the reservoir heterogeneity, wellbore drilling parameters, and formation testers’ capabilities. Introduction Analysis of formation water can provide crucial input to analyses during every stage in the life of a reservoir (Abdou et al. 2011). It provides information about the scaling and corrosion potential of the water, establishes the salinity of the water for petrophysical evaluation, and helps evaluate reservoir connectivity. It is a critical input to field development planning and economics. Representative downhole water samples of the formation of interest should be free of any contamination by drilling fluids. Water-sample quality depends strongly on drilling-fluid type and on sampling technique and monitoring. Oil-base mud (OBM) usually allows acquisition of good water samples because the mud filtrate, being immiscible with water, does not contaminate the sample of formation water (Schroer et al. 2000). In contrast, water-base mud (WBM) is miscible with formation water, causing chemical reactions and mixing that can contaminate formation-water samples. For example, a WBM containing sulfates in contact with a formation water containing barium could cause precipitation of barium from the water sample. Analysis of the resulting water sample would underestimate barium content and thus underestimate scaling potential of the formation water (Raghuraman, O’Keefe et al. 2005). Good water-sampling techniques must allow for precise monitoring and control of the presence of WBM or water from the drilling fluid. Reservoir water samples are usually collected with a wireline formation tester, comprising a probe or packer module, pumpout module, fluid analyzer and sample-collection chambers. Fluids are drawn from the reservoir into a flowline in the device, in which resistivity and optical properties are measured. Early in the sampling process, fluid content is dominated by

Carbonate Reservoir Characterization at Different Scales: Proving the Value of Integration

Much has been written about carbonate reservoir complexities, heterogeneity, and data integration at different scales. However, there are not many published examples that show a comparison of producibility modeling predictions and actual field results that include data from core, advanced openhole well logs, formation testers, and drillstem tests. In this study, we present the integration of data and measurements from advanced technologies to evaluate reservoir heterogeneity of carbonate formations on multiple scales. Quantitative textural analyses based on a comprehensive suite of petrophysical logging measurements were integrated with core data and formation testing data to characterize hydrocarbon/water transition zones and formation permeability and producibility. The offshore carbonate reservoir studied is composed of limestones and dolomites. Despite the inherent chemical complexities and hidden modes of origin, dolomites often exhibit favorable reservoir quality with high porosity and permeability properties. For this reason, E&P companies continue to predict where drilling targets are most likely to encounter these sweet spots. Traditional permeability correlations are not effective in these systems, leading to overdependence on porosity-based reservoir descriptions to predict fluid flow. Using nonparametric regression, we have established a relationship between permeability and porosity from logs that are available fieldwide. Subsequent integration of this data with interval pressure transient test data in zones selected based on the observed rock heterogeneity enables further optimization of the final permeability correlation. The descriptions of the field examples confirm the success of this integrated approach and include the planning, real-time monitoring, and final validation of permeability and anisotropy at different scale during the exploration phase of a field. Selecting the well locations for development using the proposed approach has proved valuable for improving field development practices. The results have led to enhanced reservoir characterization based on flow (permeability) and storagecapacity analyses (porosity partitioning), and a better understanding of the reservoir heterogeneity at different scales; the results have been used to improve drillstem test designs and reservoir production strategies. Introduction Petrophysical analysis of carbonate reservoirs can prove challenging for a variety of reasons. All aspects of evaluation— whether mineralogy, porosity, permeability, rock types, saturation, relative permeability, or capillary pressures (Elshahawi et al. 2000)—can pose unique challenges, and techniques that work well in siliciclastic reservoirs often fail in carbonates. To achieve the maximum potential of the well or the reservoir, one must understand the carbonate rock formation along the wellbore and reservoir boundaries. Therefore, a quantitative textural analysis based on a comprehensive suite of petrophysical logs, core data, and data from advanced formation testing technologies will help E&P companies to meet the specific challenges and optimally drill, produce, and develop these reservoirs. Brazil has a huge sedimentary area, covering more than 6,000,000 km in onshore and offshore basins. On a geological timescale, the carbonate rocks vary from the Precambrian to Quaternary age. Despite their abundance, they comprise less than 4% of the proved hydrocarbon reserves in Brazil (Spadini 2008), mainly because of their varying reservoir quality. In this paper it is proposed a workflow to characterize the reservoir at different scales to support the decisions behind vertical and horizontal well placement, well completion and testing this kind of reservoir. Almost ten wells were drilled in the studied area following this reservoir characterization workflow but only three of them are presented in this article; the first vertical drilled well (Well A), a slightly deviated well (Well B) that was the pilot for a sidetrack horizontal well (Well C).