The objective of this study is to characterize fluid distributions in a presalt field by using well data including downhole fluid analysis (DFA) from wireline formation testers (WFT), openhole logs, and a simplified structural/geological model of the field. From an understanding of the petroleum system context of the field, reservoir fluid geodynamics (RFG) scenarios are developed to link the observations in the existing datasets and suggest opportunities to optimize the field development plan (FDP). DFA measurements of optical density (OD), fluorescence, inferred quantities of CO2 content, hydrocarbon composition, and gas/oil ratio of fluids sampled at discrete depth in six presalt wells are the basis of this study. DFA data at various depths captures fluid gradients for thermodynamic analysis of the reservoir fluids. OD linearly correlates with reservoir fluid asphaltene content. Gas-liquid equilibria are modeled with the Peng-Robinson equation of state (EOS) and solution-asphaltene equilibria with the Flory-Huggins-Zuo EOS based on the Yen-Mullins asphaltenes model. OD and other DFA measurements link the distribution of the gas, liquid, and solid fractions of hydrocarbon in the reservoir with reservoir architecture, hydrocarbon charging history, and postcharge RFG processes. Asphaltene gradient modeling with DFA reduces uncertainty in reservoir connectivity. The CO2 content in some sections of the field fluids limits the solubility of asphaltene in the oil, and the small asphaltene fraction exists in a molecular dispersion state according to the Yen-Mullins model. Low values of OD and small asphaltene gradients seen in most of the upper zones reflect the small asphaltenes concentration in the crude oil. The CO2 concentration was modeled with the modified Peng-Robinson EOS in good agreement with measurements in upper reservoir zones. Matching pressure regimes and asphaltene gradients in Wells B and C indicate lateral connectivity. The hydrocarbon column in this part of the reservoir is in thermodynamic equilibrium. In Wells A, C, D, E, and F the OD of the oil indicates an asphaltene content increase by a factor of four at the base of the reservoir as compared with the crest of the reservoir. This tripled the viscosity in Wells C and D, as indicated by in-situ viscosity measurements. The accumulation of asphaltenes at the bottom of the reservoir is most likely driven by a change in solubility resulting from thermogenic CO2 diffusion into the oil column from the top down. The challenge of the limited number of wells in the development phase of a presalt field for obtaining data to evaluate reservoir connectivity before the FDP is ably addressed by deploying the latest WFT technologies, including probes for efficient filtrate cleanup and fluid properties measurement. These measurements and methodology using a dissolved-asphaltene EOS enabled developing insightful RFG scenarios.

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This paper describes a new technique for measuring pH on live formation water samples in the laboratory at high temperature and pressure. The technique involves adding pH sensitive dyes to pressurized single phase water samples collected using a formation tester and spectroscopically determining the pH in the laboratory at reservoir conditions. Water chemistry and pH are important inputs for scale and corrosion modeling. Due to the lack of standard laboratory techniques for such measurements at high temperatures and pressures, current practice involves flashing the single phase water sample, analyzing the flashed water and gas phases, and then using water chemistry models to predict pH at reservoir conditions. Uncertainties in the thermodynamic models for formation waters at high temperature and pressure, as well as uncertainties associated with the flash process and possible precipitation of salts, can propagate as errors into scale and corrosion models. It is proposed that the direct pH measurement on live water samples described here be used as an additional input for the water chemistry models to improve confidence in their predictions. This will allow for more efficient selection of completion materials and planning for scale treatment and mitigation. In this paper, we present results of laboratory pH measurements on formation water samples from two offshore Gulf of Mexico wells for pressures to 20,000 psi and temperatures to 242°F. Results are compared to predictions from two commercial thermodynamic models that use the flashed gas and water analysis data as inputs. The setup can also measure the sensitivity of pH to pressure and temperature. Comparison of the laboratory pH measurement to real-time in situ downhole pH measurements made on the same formation water with a formation tester showed good agreement. This is an example of the implementation of the chain of custody concept, which compares a measurement made downhole with that made in the laboratory on the same sample using the same technique, to validate the representativeness of the sample as it is transported from downhole to the laboratory. Introduction Water sampling in exploration wells is usually done to obtain information regarding the scaling and corrosion potential of the water, understand reservoir connectivity, and establish the salinity of the water for petrophysical evaluation. Corrosion potential of the water is important for material selection for tubing, pipeline, and process equipment. Scaling potential is critical for the selection of an optimal development strategy to prevent scale formation by choice of operating conditions, to select and deploy scale inhibitors when needed, or both. Correct water resistivity is important for interpreting openhole wireline logs accurately. In addition, analysis related to various environmental aspects like concentration of organic compounds and heavy metals in water is performed. Dissolved organic acids also affect water chemistry because they can influence the pH of the solution. Good quality formation-water data can improve the ability to make the right decisions early in development planning. These data can give information about compartments and communication in the reservoir. Later in the production cycle, these data can be used to differentiate produced connate water from aquifer or injection water breakthrough.

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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.