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Abstract Residual hydrocarbons occur in a range of habitats and can take various forms: they may be oil or gas, they may be present within high-quality or poor reservoirs; and may appear as a single palaeo-column or as thin columns interspersed with beds of producible hydrocarbons. Residual hydrocarbons are sometimes easy to identify but when not recognised they may lead to optimistic reserves estimates. This paper illustrates the range of habitats of residual hydrocarbons and provides techniques to enable their identification, such as novel log cross-plots and log overlays. In most cases the non-productive nature of the residual hydrocarbon can be confirmed using flow tests, with the possible exception of very low permeability reservoirs containing residual gas. The results of not recognising residual hydrocarbons include (a) overbooking of reserves which may have serious commercial consequences, (b) the application of incorrect saturation-height functions, (c) pessimism in calculated formation-water resistivities estimated from water legs containing residual hydrocarbons, (d) lower effective permeabilities in water legs which may affect waterflood design, and (e) excessive expenditure on wireline formation testing and drill stem testing. From an exploration perspective, residual hydrocarbons provide direct evidence of migrated hydrocarbons and/or breached oil fields and hydrocarbon loss due to regional post-migration tilt. Thus they provide important clues to the location of additional traps along the migration pathways. We present examples of residual hydrocarbons from the Indian subcontinent and elsewhere. The subcontinent is particularly prone to the presence of residual hydrocarbons as many basins have undergone polyphase deformation and multiple periods of secondary migration and fill. By raising the awareness of residual hydrocarbons, we hope that this paper leads to greater accuracy in reserves estimates, and perhaps even the discovery of additional hydrocarbons.
Abstract Many gas reservoirs at the appraisal stage exhibit evidence of persistent gas saturations below free water levels (FWL's). The amounts of gas contained here may, under some situations, be a sizable fraction of the gas cap volumes. Many engineers appear poorly equipped to include, and model, paleo gas in simulation models. This often results in paleo gas being simply ignored when development plans are being considered. This is unfortunate because paleo gas upon pressure depletion can expand, displacing brine towards well completions. This means that while some additional gas production may occur from the paleo zone, the risk of water production may be significantly underestimated if paleo gas is simply omitted. This work discusses the evidence for paleo gas and shows that it may be described and incorporated in simple simulation models provided the user avoids some common misconceptions. It is demonstrated that under depletion conditions, paleo gas can be entirely visible to material balance pressure responses, while at the same time increasing the risk of produced water volumes. For higher pressure paleo gas reservoirs the common P on Z diagnostic plots can also provide early trends that are frequently misinterpreted. This work quantifies the curvature that can result in such systems, and shows that simulation models inherently predict the expected curvature in P on Z. The approach taken here is by design simplistic and is applicable to scoping evaluations where the paleo gas volumes could be a significant volumetric uncertainty. Where possible, we indicate where additional, or more rigorous, descriptions can be applied.
Burkhanov, Ramis Nurutdinovich (Almetevsk State Oil Institute) | Lutfullin, Azat Abuzarovich (PJSC Tatneft) | Ibragimov, Ildar Ilyasovich (Almetevsk State Oil Institute) | Maksyutin, Alexander Valeryevich (CSC Tetrasoftsevice)
Abstract The composition and properties of oil change during its flow through the reservoir, which is associated with the high molecular weight resins and asphaltenes retained in the pores. Oil is retained in the thinnest capillaries and narrow contacts of hydrophilic mineral grains (capillary-retained oil) and as a film on the surface of hydrophobic minerals (oil films). To confirm this, core analysis tests were performed on three pre-prepared core columns made up of standard core samples with different porosity ϕ, absolute permeability k, irreducible water saturation Swir and other properties. Oil was flowing through the column and displaced by water with pre-determined physical properties. The properties of the core specimens, oil and water, as well as the thermobaric conditions of flow experiments were selected so that they corresponded to the reservoir conditions of the Pashian horizon of the Romashkinskoye oilfield of the Republic of Tatarstan. In the case of the mature Romashkinskoye oilfield, the relevant objective is to quantify and localize the remaining reserves of capillary-retained oil and oil films and substantiate effective technologies for their extraction. To prove that the composition of oil change during flow through porous media, the light absorption coefficient of oil kla was investigated that depends on the relative content of resins and asphaltenes in the oil. Oil was studied using a photometer in a continuous mode during the entire period of oil displacement test. Oil samples were collected and subjected to preparation at the inlet and outlet of the core column, their optical density D, light absorption and transmission coefficients were measured in vitro, and statistical data were processed. It has been found that regular changes in the oil kla occur both at the stage of the core column saturation with oil (a regular decrease), and as oil is displaced from the core samples by water (a regular increase). The identified patterns are the function of the rock and oil properties, the established rate of the column saturation with oil and oil displacement by water, and the amount of residual and displaced oil. The obtained data have shown the promising outlook for continuing laboratory experiments to study not only changes in the properties of oil when it is displaced by water, simulating the development processes, but also those occurring in the column as it is saturated with oil, simulating the processes of primary migration and accumulation of oil in a natural reservoir.
Abstract Recently, Saudi Aramco upstream activities in unconventional gas, and in particular tight gas sands, have been identified as a focus area. Integral to understanding the potential of tight gas as a resource, is an understanding of the petrophysical characterization of tight gas intervals. This paper presents a review of the petrophysical challenges in the evaluation of tight gas intervals encountered within an existing producing field producing from formation U. This formation can be highly variable and although it can be highly productive, in some areas the geology has produced poorer reservoir quality rock. Production from wells which penetrate these areas can exhibit "Tight Gas" characteristics. Core and log data from existing fields are abundant and cover both good and poorer quality reservoir intervals. The factors which impact the evaluation of these "Tight Gas" intervals, in this relatively well sampled environment, can be generalized to the evaluation of less well studied tight gas formations. The results of this review identify many areas where current techniques and tools fall short of providing an adequate characterization. In particular, the quantification of mineralogy and diagenesis is seen as important, as is the quantification of saturations and accurate measurement of micro-Darcy permeabilities. Areas where current techniques require improvement are highlighted and projects that are in progress to address these issues and improve the evaluation of tight gas are detailed. One area which is highlighted as holding potential is rock typing, which can categorize different types of tight gas interval based on clay content or mineralogy. Three wells have been selected for a fracturing exercise as a proof of concept to assess the production potential. The results of the fracturing exercise are presented relative to the petrophysical evaluation of these wells.