ABSTRACT
Volatile light hydrocarbons (VLH) are an essential component of reservoir petroleum fluids. Understanding of their origin and fate is crucial not only in exploration but increasingly also in petroleum engineering, as this greatly impacts fluid typing, proper mapping, recoverability and economic value. Due to their sensitivity to subsurface thermal stress and geological alteration processes, their proper characterisation holds promise to understanding the thermal conditions under which petroleum fluids were generated and subsequent fluid modifications during migration and within the reservoir. To study the behaviour of these hydrocarbons under different geological conditions we selected oil and gas fields from two giant conventional petroleum systems in the Arabian Peninsula collectively spanning the entire petroleum spectrum from heavy oil to dry and sour gas. In situ representative bottomhole or recombined pressure-volume-temperature (PVT) fluid composition data were constrained with molecular and stable carbon isotope geochemistry in key wells. Systematic covariance among the slope factor (SF) of propane to pentane and the isomer ratios of butane and pentane with reservoir engineering and geochemical variables in well-constrained black oil to gas condensate petroleum systems allowed the derivation of three formulas to calculate thermal maturity in terms of vitrinite reflectance equivalent from VLH fluid composition: (1) %VRe(SF) = 0.38 SF + 0.41, (2) %VRe(i4) = 1.70 (iC4/nC4) + 0.61, and (3) %VRe(i5) = 0.89 (iC5/nC5) + 0.56. The slope factor, iC4/nC4, and iC5/nC5 ratios all increase monotonically with the thermal evolution of unaltered fluids, allowing for effective application of their derived %VRe formulas across the entire unaltered fluid spectrum, from heavy oil to dry gas. Deviations from indigenous-fluid trends do occur for fluids altered by phase separation, biodegradation, thermal cracking, and thermochemical sulfate reduction (TSR), but corrections can be made to minimize uncertainty in assessing true thermal maturity of altered fluids while respecting other reservoir fluid properties such as gas-to-oil ratio (GOR) and saturation pressure relationships. For instance, although a single charge that has been phase fractionated yields fluids with variable GORs, saturation pressures and slope factors, their butane and pentane isomer ratios remain reflective of the original fluid maturity. In contrast, biodegradation-induced overestimation of maturity based on the isomer ratios of butane and pentane can be corrected by the less affected SF-derived maturity parameter. Reversal to lower apparent SF-derived maturity in thermally and TSR cracked fluids can, on the other hand, be corrected by considering the less affected butane and pentane isomer ratios. Overall, maturities calculated using VLH composition correspond well with fluid type defined based on phase behaviour and source-rock kinetics, thereby putting forward new tools to quantify thermal maturity of reservoir fluids that may be applicable in other petroleum systems.
ABSTRACT
Phase envelopes are routinely employed by reservoir engineers for fluid characterisation. These envelopes are controlled by reservoir fluid composition, pressure and temperature. As a result of increasing source-rock maturation, fluids with decreasing molecular weights and densities and increasing gas-to-oil ratios (and hence different phase envelopes) are generated, which are thus linked to fluid history. In addition to their importance for exploration, charge models can play a key role in constraining reservoir models and optimising field development, particularly when pressure-volume-temperature (PVT) data are properly integrated with fluid geochemistry. Two contrasting scenarios of fluid phase evolution from two different fields are presented, and their relations to charge analysis and reservoir models are discussed. The first example discusses the identification, based on hydrocarbon geochemistry complemented by overlapping modeled phase envelopes, of compartmentalised filling cycles in what was initially considered a single oil-rimmed gas accumulation. The second example presents an opposite scenario where two wet gas accumulations 20-km apart laterally and 400-feet average depth difference appear to represent a single more-expansive accumulation spread over areas of variable PVT conditions and reservoir qualities. The wet gas across both accumulations is characterised by a continuous phase evolution pattern that shrinks systematically (cricondentherm shifts to lower temperature and cricondenbar to lower pressure), suggestive of phase fractionation of a charge of single maturity. The proposed gas distribution model represents a discovery of a hybrid conventional and unconventional (tight sand) system, with potential for basin-centered gas. These findings provided better understanding of observed and projected fluids, impacting the development and completion plans by locating new gas producers. A recent well drilled midway between the two accumulations indeed tested wet gas, confirming fluid connectivity. Future work will attempt to link the gas distribution model with seismic attributes.
