Physical fluid samples collected in situ provide evidence for verification of exploration prospects, optimization of formation evaluation and reservoir production. Downhole fluid analyzers (DFA) are developed essentially to ensure the quality of formation samples. Advanced DFA are emerging for more advanced fluid compositional analyses in situ, as well as for studying the effect of pressure on fluid physical and chemical properties, those typically determined in the laboratories. Laboratory tests such as PVT (pressure-volume-temperature) analysis are still used as reference in reservoir engineering, provided the sample tested is representative of formation fluid and also differences among different laboratories are minimized. This study focuses on crude oil compositional analyses during pumpout with a wireline formation tester. It summarizes experience with the in-situ measurement of methane, ethane, propane, saturates, aromatics and GOR based on multivariate optical computing (MOC) conducted at over 200 pumpout stations in a total of 37 wells drilled with a variety of inclinations, bit sizes, drilling fluids in several oil and gas fields. The results and lessons learnt enhanced technology development including hardware improvements, capability expansion for new components, processing software upgrades and the foundation of a local center of excellence for operations and study support. Examples of individual pumpout stations within the context of an integrated petrophysical analysis of wireline logs are presented to demonstrate data quality control and basic interpretation in oil and gas wells in the presence of water- and oil-based muds. The data are cross-validated by correlations with laboratory and other sensor data. Fine but consistent field-wide compositional variations suggest the possibility of new geological understanding and advanced reservoir fluid modeling from the newly acquired DFA data base.

In wireline formation testing and sampling, a difficult and long standing challenge is the differentiation between mud filtrate and formation fluids, especially in oil-based mud (OBM) (diesel/water mixture) and multiphase formation fluids (oil/formation water) environments. This challenge can cause ambiguities during the interpretation of downhole fluid properties and determination of the contamination levels before sampling.Often, during the sampling process, fluid mixing increases fluid property sensor noise and causes difficulties with accurate fluid identification and contamination levels. Consequently, noisy sensor readings are attributed to the transitional phase of sampling and pertinent information is ignored.This paper presents several examples where fluid mixing has occurred. A high-resolution volumetric densitometer is used to accurately identify fluid properties. It monitors the change of frequency of a vibrating tube immersed in the fluid sample.Because of the high accuracy of this technique, it is also possible to determine additional fluid properties, such as density, water salinity, and fluid compressibility. Furthermore, new processing methods are illustrated, which provide a clearer understanding of flow behavior and allow more accurate estimates of fluid contamination. The examples are verified using fluid volumetrically maintained at the reservoir pressure and temperature (PVT) lab results comparing the downhole real-time fluid property measurements and interpretation with the actual fluid samples recovered.

Relative permeability is an essential parameter for reservoir description, engineering, and management. Relative permeabilities are typically obtained in the laboratory through evaluation of the dynamic behavior in cores using fluids that are assumed to be representative of those in the reservoir. In-situ measurements of effective permeability can provide valuable information about fluids, rock, pressure, temperature, and their interactions in the evaluated formation at original reservoir conditions. Recent technological advances allow data obtained from formation testers to be analyzed and interpreted for estimating relative permeabilities. Formation testers are typically run when wells are drilled; therefore, using acquired data for estimating effective permeability can be cost-effective and less time-intensive compared to existing effective permeability estimation methodologies. However, the measurement process, the meaning of the acquired data, the interpretation of the data, and the resulting relative permeability values are affected by the uncertain environment associated with the entire process, which also affects the confidence of the estimated relative permeabilities and their use as an input for reservoir description, engineering, and management. Although the use of formation testers as a tool to estimate relative permeabilities is promising, it is crucial to understand the environment in which the dynamic events occur and the impact of the uncertainties related to the physical phenomena and interactions associated with the measurement and interpretation processes. Conversion of the acquired information at the oil/gas well into inputs to properly interpret the acquired data, the models available to interpret the phenomena, and the formation tester tool capabilities all require understanding of the uncertainties associated with the entire process. These uncertainties, when properly qualified and quantified, can serve as the decision criteria to estimate the value of information (VOI) of relative permeability determination using in-situ formation tester data. This work provides a detailed description of the uncertainties related to relative permeability estimation based on in-situ measurements of formation testers and its impact on the interpretation outputs.

Wireline formation testers (WFTs) are a major component of providing quantitative geomechanical information obtained through induced hydraulic fractures, commonly called (Micro-Frac). This type of information is used to infer critical data such as borehole stability studies, field stress mapping, stimulation planning, seal integrity tests, and other applications. Likewise, vertical interference testing (VIT) conducted with WFTs provides valuable information about flow barriers, zone connectivity, and quantitatively determine localized horizontal and vertical permeabilities. Both techniques are used over separate stations and different depths as it may involve different hardware in different trips in the wellbore. In this paper, a novel technique to combine both tests simultaneously using an optimized hardware configuration and interpretation will be demonstrated. Pressure tests data in low permeability reservoirs is commonly affected by "super-charging" fluid that leaks into the invaded zone from hydrostatic pressure and cannot quickly dissipate, thereby making it difficult to accurately obtain true formation pressure measurements. This, in turn, affects the VIT tests where the pressure response at the observation point is influenced by the supercharged pressure resulting in erroneous calculation of vertical permeability. By initiating a micro-fracture while monitoring its response, this provides a better estimate to reservoir pressure and improves VIT success in low permeability formation. The combination of a Micro-Frac and VIT test at the same depth provides unique information about the reservoir and may enhance the data quality on these stations. Not only the safety and cost are positively impacted in improving the operational efficiency. New methods and techniques can emerge from the utilization of this methodology and improve reservoir understanding and characterization. In fact, a feasibility test using this unique approach was conducted and validated in a carbonate reservoir. The results indicate that the created micro-fractures provide a means of dissipating the "super-charging" effect masking the true formation pressure and reduce the uncertainty in the calculated reservoir properties using the VIT data. This technique may be further developed to include, for future implementation, other sensors at different places and positions in the downhole modular tools in order to acquire more information that will bring novel insight on the tested reservoir zones.