Air injection is an effective technique for improved oil recovery in light oil reservoirs. It is speculated that the main mechanism of the process is via spontaneous low-temperature oxidation (LTO) to consume oxygen and generate “flue gas” that displaces oil out of the reservoir. In this study, laboratory experiments have been conducted to study the effects of oil composition and main reservoir parameters on the kinetics of LTO, in a range of reservoir temperatures from 70 to 150 °C. Saturates, aromatics, resins, and asphaltenes (SARA) analysis and experiments using pure oil components were preformed to study the oxidation activity of different oil compounds and components. Reaction rates of typical light and heavy oil samples were also measured for comparison. Effects of temperature, pressure, water saturation, sand type, and residence time on reaction rates and products were investigated under static and dynamic conditions. The results indicate that different oil components exhibit different reaction activity under the LTO conditions. Heavy oils can be more readily oxidized than light oils at low temperatures. The data shed more light on the mechanisms of LTO reactions and can provide guidelines for reservoir selection and air injection process design.

No abstract

A new air injection technique, low temperature oxidation (LTO) process, is described. Improved oil recovery from deep, light oil reservoirs is achieved by removing the oxygen in the injected air by LTO reactions with the residual oil in the reservoir. The product of the LTO reactions is a "flue gas," which displaces the oil. Preliminary results of LTO reaction kinetics and oil recovery have been obtained using four North Sea light oils. The paper also contains some discussion of the safety issues related to air injection offshore. Introduction Gas injection into light oil reservoirs is a proven improved oil recovery IOR technique. The IOR potential for gas injection in the United Kingdom Continental Shelf (UKCS) has been estimated at 1.4 bSTB(1). However, the application of gas injection is limited by gas availability and cost, particularly for many mature fields, with the prospect of abandonment unless economic methods can be developed to extend the field life. Therefore, there is now growing interest in air injection because of its availability. Air injection has been widely used in the past for production of viscous heavy oils, where the heat generated by in situ combustion is a necessary part of the recovery process. Air injection can also be used for the recovery of light oils, but in this case, heat generation is not necessary for the displacement. Some form of oxidation is only required in order to remove the oxygen from the air and prevent it from reaching the production wells. Yannimaras et al.(2) have discussed the benefits of air injection for IOR from deep, light oil reservoirs, wherein the principle objective was to generate flue gas (85﹪ N2, 15﹪ CO2) by in situ combustion. There are a number of ongoing successful air injection field projects, notably in the West Hackberry Field, Louisiana [Amoco(3)]; in Medicine Pole Hills Unit, North Dakota; Buffalo, South Dakota [Koch(4)]; most recently, in the Horse Creek Field, North Dakota [Total(5)]; and Total's proposed LTO pilot test in the H Field in Indonesia(6). In the latter case, core flooding studies were undertaken to investigate the effect of various parameters on oxygen uptake by the oil. Previous field projects and simulation studies have considered that high temperature oxidation (HTO, or in situ combustion) is needed to remove the oxygen and enhance oil recovery. Christopher(7) [see also Yannimaras et al.(8)] used an accelerating rate calorimeter (ARC) to screen light reservoir oils for continuous exothermicity. For light oils they found that about 20﹪ were good candidates for propagating full in situ combustion. This suggests that perhaps a majority of light oils will sustain only low temperature oxidation (LTO). Thus, when the primary objective is only to generate nitrogen and carbon dioxide in situ, then a less intensive oxidation process, without combustion, is sufficient. The focus is therefore on a spontaneous LTO process, which can be applied in all light oil reservoirs with sufficiently high reactivity to react with (and consume) oxygen in the injected air.

CO2 can be injected into gas reservoirs for enhanced gas recovery. The main benefit of CO2 injection is pressure support to prevent subsidence and water intrusion. Enhanced gas recovery can be via both displacement and repressurisation of the remaining natural gas. The objective of this paper is to investigate the process of injecting CO2 into gas reservoirs using a compositional reservoir simulator. The effects of gas mixing, CO2 diffusion and CO2 solubility in formation water are investigated. Simulation studies are performed to assess the sensitivity of various design and operating parameters to the process. In general, an incremental gas recovery of 8% can be achieved by CO2 injection for a reservoir with a primary recovery factor of 85% by natural depletion. Economic feasibility of CO2 project is also investigated. The profitability of the project is sensitive to gas price, cost of CO2, original gas composition in the reservoir, and further processing of the produced gas. Introduction Most scientists believe that various industrial activities and in particular the burning of carbon-rich fossil fuels have caused the concentration of CO2 in the atmosphere to increase from 280ppm to 370ppm since the industrial revolution. The CO2 content in the atmosphere is expected to reach a critical point within 2–3 decades if nothing is done, which could trigger serious global warming and climate changes. In order to reduce these risks, a set of solutions is being investigated to reduce CO2 emissions into the atmosphere. Long-term oceanic and geological (underground) storage is considered as an important solution for CO2 storage. Although oceanic storage can provide greater storage capacity, there are some uncertainties about the retention time and their environmental impact. The subsurface storage is, therefore, deemed more realistic and reliable at least in the near future. The main promising targets are depleted oil and gas reservoirs, underground aquifers, coalbeds and abandoned and sealed mines.[1–3] Injection of CO2 into oil reservoirs for enhanced oil recovery (EOR) has been broadly investigated. CO2 injection for enhanced gas recovery (EGR) is a new subject that has not been studied as extensively as EOR, and there are no reported field projects. This might be due to the high recovery of gas through natural depletion of the reservoirs and the concerns of potential excessive mixing of native and injected gases. Injection of CO2 for enhanced gas recovery can be an attractive option for many countries that have huge gas reserves but a limited number of oil fields. Gas reservoirs can offer vast storage capacity for CO2. Many natural gas reservoirs contain a significant quantity of CO2, which has to be separated from the gas stream to meet the required export sale gas specification. It is expected that, in the wake of the Kyoto protocol, more companies will commit to greenhouse gas management in the development of CO2 associated natural gas fields. There are several on-going and planned projects worldwide that involve separation and geological storage of CO2. One of these projects is the Sleipner gas field in the North Sea in which the separated CO2 is injected into an underground saline aquifer.[4,5] Other projects, such as the Snohvit LNG project in the Barents Sea, the In Salah gas project in central Algeria, [4] the Natuna gas field in Indonesia,[6,7] and the Gorgon gas field in Australia,8 are under design and consideration to implement effective CO2 separation and geo-storage measures. The subject of enhanced gas recovery has received significant attention in recent years as part of CO2 geo-storage study. A few experimental and simulation studies have been conducted to evaluate the feasibility of displacing natural gas with CO2.[6,9–12] Enhanced gas recovery can be via both displacement, analogous to water flooding in oil reservoirs, and repressurisation of the remaining natural gas. The effect of CO2 dispersion (diffusion) and mixing with the primary gas in the reservoir is the main concern in enhanced gas recovery process. The solubility of CO2 in formation water is also important for the potential of enhanced gas recovery.

No abstract