Downhole Fluid Analysis Tools and Methods: Laboratory Measurements vs. Downhole Fluid Analysis

Abstract

Over the past decade, explosive development in downhole tools and measurement techniques has facilitated subsurface acquisition of rock and fluid data during drilling and testing. In addition to rock and rock-fluid data such as porosity, permeability, and fluid saturations, downhole tools enable measurement of fluid properties such as the gas/oil ratios (GOR), saturation pressure, fluid density and viscosity, compositions, and asphaltene gradient. Downhole fluid analysis (DFA) is accomplished through a combination of spectroscopic and fluorescence techniques coupled with density and viscosity measurements. Early acquisition of downhole rock and fluid data is extremely critical to appraising, planning, and executing fast-track projects to maximize the asset's potential. The potential benefits of early data acquisition demonstrate DFA technology as a quick solution for decision-making parameters in scoping productivity analysis. DFA results are later validated and adjusted by laboratory measurements for in-depth reservoir performance predictions. Furthermore, early DFA measurements aid in the acquisition of cleaner reservoir fluid samples, well testing and completion design, and establishing fluid gradients and reservoir connectivity. Proper planning, interpretation expertise, and knowledge of modeling techniques are necessary to exploit the information from DFA. Using field examples of DFA measurements and laboratory results, we found that GOR and fluid composition by DFA measurements are fairly accurate with low uncertainties for black oils in comparison with laboratory data. However, in the case of volatile oils and gas condensates, the uncertainty seems to increase as the GOR increases, which is confirmed by a close comparison of DFA data with laboratory analysis of companion fluid samples. We investigated likely sources for these discrepancies, particularly with reference to the spectroscopic data interpretation and the models used to translate the spectroscopic response into fluid compositions and GOR. Different approaches can be used to improve composition and GOR estimates from the DFA results, including enhanced modeling techniques of the spectroscopic data. Introduction The type of reservoir fluid and its pressure/volume/temperature (PVT) behavior plays a critical role in estimating in-place hydrocarbon volumes, planning for reservoir development strategies and production processes, facilities design, and the mitigation of flow-assurance problems. In addition, reservoir and facilities simulation studies to predict reservoir performance and facilities optimization require fluid models based on measured data to capture fluid property variations with changes in operating conditions. Thus, fluid properties data are vital for planning reservoir development very early in the exploration and predevelopment stages. However, acquisition of representative fluid samples and subsequent laboratory analysis usually take a long time, as much as 3 to 6 months, resulting in undesirable project delays. In this environment, downhole fluid analysis (DFA) (Mullins et al. 2005; Betancourt et al. 2007; Fujisawa et al. 2008) tools offer the significant advantage of obtaining fairly accurate in-situ fluid bulk properties such as fluid density, viscosity, and gas/oil ratio (GOR).

Applications of wireline formation testing (WFT) and downhole fluid analysis (DFA): Reviewing the importance of this technology in reservoir evaluation

“…Since H S and 2 crude oils' molecular structure. When GOR rises nitrogen are not visible in this wavelength range, it that means the fraction of methane rises too and the might influence depending on the concentrations of fraction of oil declines, and therefore the peak of the other components [39].…”

“…For highly undersaturated oils, the channel, and such channels are utilized in order to DFA GOR is consistently lower in some reservoirs measure GOR from live crude oils [47], [48]. GOR than the lab value by 15-20 % [39]. can be calculated by the following equation: Oil wells are drilled with a drilling fluid which may Recombining the gas and liquid phases at the be either oil or water based.…”