This paper presents a case study of a North Sea appraisal well where a large vertical fluid composition variation, missed by a conventional pressure gradient analysis method, was observed in situ in real time by a new fluid composition analyzer utilizing visible near-infrared (NIR) spectroscopy. For optimal oil production, it is as vital to assess the spatial variation of fluid properties as it is to assess the spatial variation of formation properties.
Conventional wireline triple combo measurements showed the interval of interest was uniform and free from noticeable impermeable layers. A resistivity log showed an approximate oil/water contact. Wireline pressure testing identified three different pressure gradients corresponding to gas, oil, and water, all in hydraulic communication. However, the pressure testing did not indicate a gradient in hydrocarbon composition. Fluid was sampled and analyzed in real time by a wireline fluid sampling-analyzing toolstring that included the fluid composition analyzer. This tool analyzes petroleum fluid and gives concentrations for four group compositions (C1, C2-C5, C6+, and CO2), gas/oil ratio (GOR), and qualitative information regarding heavy-end content and stock-tank crude density. The analyzer showed the hydrocarbon fluid in an oil-bearing zone was not vertically homogeneous but instead had a large vertical variation. The samples captured by the wireline sampling tool were sent for a laboratory compositional analysis that confirmed the variation determined by the downhole analysis. Both results identified the heterogeneity of hydrocarbon fluid in the interval.
This paper also covers briefly the measurement principle of the analyzer and discusses the impact and benefit the new technology brings. The concept of flexible fluid sampling is particularly important because it enables operators to make sampling decisions based on real-time fluid analysis results rather than a predetermined job plan.
It is known that some oil reservoirs show a large fluid compositional variation over relatively short vertical intervals. Such reservoirs are of great interest for reservoir engineers and petrophysicists because a proper assessment of the formation fluid gradients is critical to optimum hydrocarbon production. There are several different mechanisms that create fluid compositional gradients. Fluid gradients can be caused by gravitation, thermal gradients, biodegradation, water washing, multiple reservoir charges, and leaky seals. Because it is difficult to predict the existence of fluid gradients apriori, it is prudent to determine the magnitude of these gradients by actual measurements. Current wireline formation evaluation is inadequate to determine the magnitude of fluid compositional gradients. Even multiple sampling with subsequent laboratory analysis is somewhat risky because a variation of fluid properties measured in separate sample bottles might be due to differing levels of oil-based mud (OBM) filtrate contamination or to some degree of nonrepresentative sampling. In addition, it is often difficult in practice to justify the extra cost of taking multiple samples in a small interval without some hints of fluid variations. It is much more preferable to perform the sample analysis in-situ so that the subsequent sampling program can be optimized in real time by comparing observations to predictions.
Visible to near infrared (VIS/NIR) absorption spectroscopy is widely used to assist wireline fluid sampling today. Identification of gas, oil, and water is now well established.1 Problematic OBM contamination is quantified during sampling jobs using build-up curves of spectral data.2,3 Recent advances have enabled analysis of live fluid properties in-situ. For example, in-situ GOR measurement by NIR spectroscopy has been established4 and is now commercially available.5 A recent study showed conceptually the feasibility of downhole fluid composition analysis.6 The authors built prediction models using principal components regression to various hydrocarbon spectra measured at high-pressure and high-temperature conditions typical for oil and gas reservoirs. The fluid composition analyzer built based on this principle estimates the concentration of C1, C2-C5, C6+, and CO2 in the fluid in the flowline and its GOR. The first field application of the tool allowed accurate downhole fluid characterization of a complex miscible flood program.7 This downhole fluid analysis (DFA) technique was also found useful for detecting formation compartmentalization.8