Summary Air injection into light-oil reservoirs is now a proven field technique. Because of the unlimited availability and the nil access cost of the injectant, the application potential of this improved recovery process is promising when associated with the lack of available hydrocarbon gas sources for injection. One of the keys of a successful air injection project is the evaluation of the process by carrying out representative laboratory studies. Therefore, an original laboratory strategy was proposed to assess the recovery potential by air injection into light-oil reservoirs, and to help the determination and the quantification of optimal operating conditions. In this paper, the air injection technique applied to light-oil reservoirs is explained. Then, the laboratory strategy proposed for the evaluation of an air injection project is described, and the experimental objectives, devices, and procedures are explained. In order to provide reliable experimental data, high-pressure and high-temperature experiments (up to 40 MPa and 500°C) are performed with consolidated reservoir cores and reservoir oils, at representative conditions of the air injection process in light-oil reservoirs. Finally, a laboratory evaluation regarding a potential application for an air injection pilot in the Handil field (Mahakam delta, Indonesia) is presented and discussed. Introduction Air Injection Process into Light-Oil Reservoirs. When air is injected into a reservoir, the oxygen contained in the air reacts with the hydrocarbons by various oxidation reactions. Heat is evolved from these reactions. High initial reservoir temperatures promote larger heat production. Two study cases must then be differentiated in the light-oil reservoir.When the thermal losses through the rock are limited compared with the heat generated by the reactions, the temperature in the reservoir increases. In this case, complete oxidation reactions providing carbon-oxide gases can be self-ignited in the reservoir. As reported in recent studies, 1 the oxygen is then consumed in a confined zone called an oxidation (or combustion)front. The size of this zone depends on the air injection rate, the characteristics of the oil, and the formation. In light-oil reservoirs, typical oxidation front temperatures of 200 to 400°C (about 400 to 800°F) can be reached. The produced combustion gases consist of CO 2 and CO with CO/CO2˜0.15, depending on the temperatures reached and the oil characteristics.When the thermal losses through the rock are high, or when the heat release is not high enough to increase the temperature significantly (in the case of high-water saturations or low-oil saturations), the oxidation reactions occur at a temperature close to the initial reservoir temperature. In this case, oxidation reactions can be partial with a lower carbon-oxide generation than in the previous case. The oxygen consumption occurs then through a larger reservoir zone, the size of which depends upon the oil reactivity.2 Several field experiences**3,4 have shown that high levels of CO2 may be produced. This would suggest that spontaneous ignition, with generation of a high-temperature front and the production of associated carbon-oxide gases, is most likely occurring in light-oil reservoirs. The generation of a high-temperature oxidation zone (200 to 400°C) is preferable because of a higher oxygen uptake potential, a more efficient carbon-oxide generation, and the creation of an oil bank downstream of the thermal front. Both of the latter factors contribute to the improvement of the recovery. In both cases, the important point to assess is oxygen consumption to prevent oxygen arrival at the producers. This is one of the main objectives of air injection experiments. Reservoir Zones to be Distinguished. When a high-temperature thermal front is ignited, four main zones can be distinguished in the reservoir (Fig. 1):The zone swept by the combustion front, where the residual oil saturation is low and the temperature higher than the initial reservoir temperature.The oxidation front where oxygen is consumed. The temperature can reach400°C Part of the original oil is burnt (about 5 to 10% OOIP) and CO2 and CO are produced. The gas formed by the remaining nitrogen from the air and the combustion gases is called "flue gas" (typically, 85% of N2 13% of CO2 and 2%of CO) and sweeps the reservoir downstream.A short zone downstream of the combustion front where thermal effects participate in the formation of an oil bank. This oil bank is partially displaced by the flue gas and by hot water or a steam front according to the reservoir conditions.A wide zone downstream of the combustion front where no thermal effects occur. This zone, which contains original oil, is not affected by the thermal effects and is swept by the flue gas. When the oxidation reactions occur at low temperature (close to the reservoir temperature), three main zones can be distinguished:A zone around the injector which is swept by the injected air. In this area, residual oil saturation is low. The oil is partially oxidized but can no longer consume oxygen.A large oxidation zone where oxygen is consumed by the residual oil left after flue gas sweeping. The oxygen concentration in the gas phase progressively decreases from 21 to 0%.A wide zone downstream of the oxidation zone, swept by the flue gas at reservoir temperature, as in the previous case (high-temperature front).However, in this case, less carbon oxides have been generated by oxidation reactions and the flue gas is mainly composed of nitrogen. In practice, both cases can co-exist in a given reservoir, according to the local reservoir properties.

This paper was prepared for presentation at the 1999 SPE Asia Pacific Oil and Gas Conference and Exhibition held in Jakarta, Indonesia, 20–22 April 1999.

This paper was prepared for presentation at the 8th Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, U.A.E., 11-14 October 1998.

Fast track development projects, with timely data acquisition plans for development optimization, are very challenging for tight and heterogeneous carbonate reservoirs. This paper presents the challenges and key learning from initial stages of reservoir development with limited available data. Focus of this study is several stacked carbonate reservoirs in a giant field located in onshore Abu Dhabi. These undeveloped lower cretaceous reservoirs consist of porous sediments inter-bedded with dense layers deposited in a near shore lagoonal environment. The average permeability of these reservoirs is in the range of 0.5-5 md. Mapping the static properties of these reservoirs is difficult since they are not resolved on seismic due to the low acoustic impedance contrast with adjacent dense layers. Petrophysical evaluation of thin porous bodies inter-bedded with dense layers in highly deviated wells pose significant challenges. Laterolog type LWD resistivity measurements which are less affected by environmental effects, offer more accurate formation resistivity compared to propagation type measurements. With limited suite of logs, some of the zones with complex lithology had to be evaluated innovatively as detailed in the paper. Integrated studies are initiated to improve reservoir description by carrying out accurate permeability mapping, SCAL, geomechanical and diagenesis & rock typing studies. Significant challenges exist regarding the development of thin, tight and highly heterogeneous reservoirs, in terms of recovery mechanism, well architecture, well count, drilling, well completion and economics. Static and dynamic models were used extensively to evaluate different development scenarios and conduct sensitivity studies to bracket uncertainties. Various geo-steering options were discussed and the paper also details maximizing the reservoir productivity using long reach MRC (Maximum Reservoir Contact) wells. Tight and heterogeneous reservoirs call for extensive and real time reservoir surveillance activities to assess well performance and reservoir connectivity. This paper highlights how these challenges are overcome through upfront surveillance planning and proactive well completion strategy.

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