Geochemical characteristics and origins of biodegraded oils in the Bongor Basin (Chad) and their implications for petroleum exploration

The Bongor Basin is a typical lacustrine passive-rifted basin situated in the West and Central African Rift System (WCARS). It has experienced two phases of tectonic inversion and features a complex process of petroleum generation and accumulation. A total of 41 crude oil samples from the basin were geochemically analyzed to investigate their compositions of molecular markers. The results show that the oils have similar origins and are likely to belong to the same oil population. However, there are significant differences in geochemical characteristics and physical properties, caused by the secondary alteration. The relative contents and distribution patterns of normal alkanes and acyclic isoprenoids indicate that some of the oils have suffered biodegradation to varying degrees. The samples can be divided into three categories according to their relative degrees of degradation: normal oil, slightly biodegraded oil (PM 1–3), and severely biodegraded oil (PM 5–7). The burial depth of oil reservoirs in this area is the predominant factor impacting on the level of biodegradation. Crude oils in reservoirs with burial depths of less than 800 m are all severely biodegraded, while oils in reservoirs with burial depths greater than 1300 m have experienced no evident biodegradation. In reservoirs with burial depths between 800 m and 1300 m, the biodegradation degrees vary from normal to severely biodegraded. Oil reservoirs with burial depths less than 1300 m and adjacent to major faults are readily subject to biodegradation, while reservoirs with similar burial depths, but a certain distance away from major faults, have suffered no evident biodegradation. Moreover, if primary reservoirs have been modified by tectonic activity after accumulation, the crude oils are more likely to be biodegraded. Faulted anticline traps may create more favorable geological conditions for preservation of crude oil than reverse extrusion anticline reservoirs. This study may provide practical guidance for the assessment and prediction of oil quality in future oil exploration.

Tight oil reservoir production characteristics developed by CO2 huff ‘n’ puff under well pattern conditions

Tight oil reservoirs have poor physical properties, and the problems including rapid oil rate decline and low oil recovery degree are quite common after volume fracturing. To obtain a general understanding of tight oil reservoir production improvement by CO2 huff ‘n’ puff, the high-pressure physical properties of typical tight oil samples are measured. Combining the typical reservoir parameters, the production characteristics of the tight oil reservoir developed by the CO2 huff ‘n’ puff are numerically studied on the basis of highly fitted experimental results. The results show that: (1) during the natural depletion stage, the oil production rate decreases rapidly and the oil recovery degree is low because of the decrease in oil displacement energy and the increase in fluid seepage resistance. (2) CO2 huff ‘n’ puff can improve the development effect of tight oil reservoirs by supplementing reservoir energy and improving oil mobility, but the development effect gradually worsens with increasing cycle number. (3) The earlier the CO2 injection timing is, the better the development effect of the tight reservoir is, but the less sufficient natural energy utilization is. When carrying out CO2 stimulation, full use should be made of the natural energy, and the appropriate injection timing should be determined by comprehensively considering the formation-saturation pressure difference and oil production rate. The research results are helpful for strengthening the understanding of the production characteristics of tight oil reservoirs developed by CO2 huff ‘n’ puff.

CO2 Mass Transfer and Oil Replacement Capacity in Fractured Shale Oil Reservoirs: From Laboratory to Field

CO2-based fracturing is widely introduced to stimulate shale oil reservoirs for its multiple advantages. However, the range of CO2 entering the matrix around fractures and CO2-oil replacement capacity between matrix and fractures cannot be fully explained. To address this issue, a radial constant volume diffusion experiment on shale cores was designed in this study, and the pressure drop curve history was matched through numerical model to determine the composition effective diffusion coefficient. A field-scale numerical model was established, in which a series of certain grids were used to explicitly characterize fracture and quantify the prosess of CO2 mass transfer and oil replacement. Based on the field-scale numerical model, the process of shut-in, flow back, and oil production was simulated. The distribution of CO2 in fractured shale oil formation and its impact on crude oil during shut-in stage and flow back stage were investigated. This study concludes that CO2 gradually exchanges the oil in matrix into fractures and improve the fluidity of oil in matrix until the component concentrations of the whole reservoir reaches equilibrium during the shut-in process. Finally, about 30∼35 mole % of CO2 in fractures exchanges for oil in matrix. The range of CO2 entering the matrix around fractures is only 1.5 m, and oil in matrix beyond this distance will not be affected by CO2. During the process of flow back and production, the CO2 in fracture flows back quickly, but the CO2 in matrix is keeping dissolved in oil and will not be quickly produced. It is conclued that the longest possible shut-in time is conducive to making full use of the CO2-EOR mechanism in fractured shale oil reservoirs. However, due to the pursuit of economic value, a shut-in time of 10 days is the more suitable choice. This work can provide a better understanding of CO2 mass transfer mechanism in fractured shale oil reservoirs. It also provides a reference for the evaluation of the shut-in time and production management after CO2 fracturing.