Improved Recovery of Light / Medium Heavy Oils in Heterogeneous Reservoirs Using Air Injection / Insitu Combustion (ISC). Abstract. A one-quarter of a 5-spot physical model was used to carry out a series of low pressure air injection / insitu combustion (ISC) tests on light and medium heavy crude oils, to investigate the effect of reservoir heterogeneity on oil recovery. It was found that a horizontal producer well does not act as a high permeability streak, but actually increases and brings forward production. Extensive work on the construction and saturation of an artificial consolidated porous media was successfully undertaken and is now ready for further combustion experiments. Introduction. The demand for oil world-wide is rising at about 1-2% a year. This, combined with the increasing difficulty of finding new large reservoirs has put pressure on major consuming countries, especially in mature field areas such as N. America and the UK Continental Shelf (North Sea), to develop new recovery techniques, i.e. improved oil recovery (IOR) - Gregory, 1995. When the reservoir energy is great enough (initially), the oil will normally flow to the producing well and up to the surface without any additional pumping. This is called primary recovery. When the natural energy becomes too low the well needs to be pumped or injected with water or gas to displace more oil. The latter is called secondary recovery. Waterflood is a secondary recovery method and is used extensively to increase recovery up to 50% of the original oil in place (OOIP). Oil is left in a reservoir after waterflooding for two principal reasons: -Some oil remains in parts of the reservoir that have not been adequately swept by water. This inefficient sweep can be caused by viscous fingering, - Peters et al, 1987, (pronounced in both light and heavy oil reservoirs), but also by adverse heterogeneity and channelling effects in the reservoir. Significant oil, at high saturations, may also be trapped beneath shale layers, which are difficult to locate precisely.In the regions that have been frilly swept, oil is trapped in the form of droplets, or ganglia in the pores of the rock by capillary forces. Clearly, with at least 50% of OOIP still remaining in the reservoir, increased attention needs to be focused on ways of increasing the recovery. Improved oil recovery techniques (IOR), especially enhanced oil recovery (EOR) processes such as air injection (low temperature oxidation and in-situ combustion - high temperature oxidation) need to be investigated. The principle of insitu combustion is to burn part of the oil (or fuel fraction, i.e. coke), to mobilise the remaining oil. Combustion is started by an ignition device, or by spontaneous ignition, which raises the zone surrounding an injection well to a significantly high temperature, so that continued injection of air or oxygen containing gas causes the combustion to self propagate. P. 435

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractCoreflood experiments on gas condensate flow behavior were conducted for a Libyan gas condensate reservoir. The objectives were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeability's, hydrocarbon recovery and trapping by water injection, and incremental recovery by subsequent blowdown and vaporization by dry gas injection.The water/gas relative permeability data were generated using implicit historical matching simulator which uses a reverse history matching technique to generate a full suite of relative permeability curves over the range of interest. The results of the tests on the reduction in gas permeability due to retrograde condensate accumulation demonstrated that, in general, the effective permeability to gas decreased significantly at pressures below the dew point pressure due to the condensate trapping effect for all the stacks investigated in this study. Permeability continues to drop at very low pressures even though theoretically condensate should be revaporizing. The recoveries of the liquid condensate during the vaporization by dry gas injection at pressures below the dew point pressure were generally high. The recovery ranged from 66% to 70% for the high permeability core stack and 86% to 98% for the lower permeability core stack. In theory, it is possible for all of the condensate to be revaporized into the methane gas stream. However, in practice, the recovery is usually less than 100% due to macroscopic sweep efficiency limitations and mass transfer limitations within the rock matrix.Poor mobility ratio and viscous fingering during the methane injection characterize the re-vaporization of gas condensate by methane gas. This results in early breakthrough of the methane gas and very high gas/liquid ratios during the test. The volume of methane gas injection required to recover a significant amount of the condensate liquid in the core is a function of temperature, pressure, composition of the gas, heterogeneity and especially the permeability of the core sample.

The effect of reservoir heterogeneity on the stability, sweep, and fluids production during in situ combustion of medium heavy West of Shetlands Clair oil has been investigated in a three-dimensional combustion cell. The experimental conditions simulated a post-waterflood state, and the process of air injection involved a producer well arrangement, such that the combustion front propagation and hence displacement of oil occurred in a toe-to-heel manner. This is called the "Toe-to-Heel" -Horizontal Wells Process (THHW). Five experiments were conducted, using two base homogeneous sandpacks. The heterogeneous sandpacks involved two dual permeability layers, one with the higher permeability in the top layer and the other with the higher permeability layer in the bottom layer. The third heterogeneity type was a central high permeability streak layer, sandwiched between two homogenous sand layers. The results show that the steam and combustion gases downstream of the combustion front tend to channel through the high permeability layer causing some measure of gas override. This effect is less exaggerated when the high permeability layer is at the bottom of the sandpack. The presence of a high permeability streak layer promotes the channeling and bypassing of the injected air around the combustion front. In all cases, stability was enhanced by the gravity assist mechanism created by the drawdown of steam and combustion gases into the exposed section of the horizontal producer well, ahead of the combustion front. The increased stability and control achieved by the THHW process enabled the propagation of the combustion front to be sustained. Very high oil recoveries were achieved, except for the case involving the high permeability streak layer. Introduction The study of air injection into oil reservoirs requires specific investigation of kinetic parameters using differential or adiabatic calorimetry, fuel and combustion parameters using a combustion tube or oxidation tube, and sweep and fluids production using a three-dimensional combustion cell. Studies of in situ combustion using 3D geometries are very limited, because of the extra complexity and cost. Nevertheless, the effort in this direction is worthwhile because of the valuable understanding to be gained from a physical scaled model of the process. Ultimately, it should be possible to achieve a full understanding of the process by virtue of the rigorous validation of a 3D numerical model. The key to this is matching the scaled model parameters, especially the dynamic combustion front temperature and also the fluid production rate. In the presence of reservoir heterogeneities, and this is always the case in practice, they are site specific, i.e., they respond to local matrix property conditions-rock composition, permeability. This dual response constraint, in three dimensions, therefore represents an extremely tight condition to be solved for. The solution thereby obtained, for a reasonably scaled model, should provide a good platform for detailed reservoir studies. Binder et al.(1) carried out 3D model studies of dry and wet oxygen in situ combustion. This was done in two cylindrical cells, one having a volume 325 times greater than the other.

An engineering feasibility study has been conducted on the major operated oil field of waha oil company to determine the feasibility of applying downhole oil/water separation technology (DHOWS) and to rank candidate wells within this field on the basis of their suitability for a DHOWS instalilations. Under operations consistent with the existing field development (or any future developments), the nature of the GE reservoir is such that, the remaining oil reserves will have to be produced at high and constantly increasing watercuts. Downhole separation and disposal of produced water represents a material opportunity to improve the current and future operations of the field. A screening template was developed to review the reservoir and well characteristics in more details and to identify a list of candidate wells for the possible implementation of DHOWS technology. Several operational risk and concerns exists in respect of the candidate wells were identified. Eighteen wells our of twenty four wells demonstrated favourable reservoir and well characteristics and meet the initial DHOWS screening criteria. The screening template may be used to evaluate other fields for potential conventional DHOWS applications. A preliminary design of a DHOWS application for three wells is presented in this paper. Introduction It is widely known that the continouse increase in the amount of water production hinder the oil production rate, contributes to high operation expense and is a major source of environmental concern to the oil companies. In the past, the response of operators to increasing water poroduction rates was to production to the top section of the oil well away from the rising water, while trying to slow the advance of water with sequeze cement and cement plug techniques. The oil industry experiences with these techniques have shown mixed results. Meanwhile, if water cannot be stopped and the cost of handling the water in additional to other costs exceed the revenue, the operator has to abandon the well despite the fact that significant volume of oil are still being produced. The Center for Engineering Research Inc. initiated a feasibility study in 1991 to test a new technique to reduce water-handling costs by reducing the volume of water produced at the surface. This work produced the idea of combining separation and pumping systems downhole and simultanouse injection of the produced water in the same wellbore. Mattews et al.1 presented a novel system for downhole separation and same well reinjection of produced water. The technique was applied to two wells in the Alliance Field and the results indicated an increase in oil rates. Peachey et al.2 presented a brief summary of field trails completed and the key results achieved, including oil production increases, water reduction, predicted increases in reserves recovery and general factore affecting the a successful DHOWS application. Shaw et al.3 indicated that The DHOWS technology could be applied successfully in a low risk wells. They defined risk as a fuction of workover cost and deferred production; high risk therefore being a prolific well with high workover costs. Scaramuzza et al.4 described the seperation system implemented in Grey, Red and Green sands of Barrancas formation, the candidate wells selected, the results of pilot field trails. Li et al.5 conducted indoors dynamic simulation experiments to test downhole separation and injection technique for rod pumping well. Jokhio et al.6 reviewed in some detail the economic parameters that effects DOWS and summarized the characteristics of a waterflood operation that can benefit economically from this technology. The aime of this feasibility study is to determine the technical and economic feasibility to use the downhole oil/water separation system in GE reservoir, to rank candidate wells within this field on the basis of their suitability for a DHOWS instalilations, and to develop a screening template that can vbe used in evaluation of oil fields for potantial DHOWS applications. Reservoir Characteristics The suitability of the GE reservoir, for DHOWS applications, was examined in respect of the observed/demonstrated reservoir behaviour. GE reservoir has been under primary recovery operations since 1964. The succeeding sections individually examine each of the following reservoir characteristics: reservoir geology, drive mechanism, production history, and water disposal/injection zone potential.