High water cuts during waterflood operations are a major problem encountered in mature reservoirs. Areas of the reservoir that are fractured, either naturally or hydraulically, are excellent pathways for floodwater to bypass oil-bearing pore spaces. Gel placement within fractured zones of the reservoir is a technique that has been employed to decrease water production. In order to utilize this technique more effectively, the improvement of gel placement and its performance within fractures must be investigated. For the purposes of this study, two experimental setups are developed. Initially an acrylic fracture model is developed in order to obtain qualitative information about flood fluid penetration into the placed gel. The rupture pressure of the HPAM-Cr (III) [hydrolyzed polyacrylamide-chromium (III) acetate] gel system is observed for 1x, 2x?and 3x?gel systems (multiplier refers to chromium concentration) within the fractures. The rupture pressures observed are generally higher for gel systems with greater chromium concentration. The acrylic setup also allows for visual observation of the gel's performance and behaviour during water injection. Water penetration is dominated by one major channel. Smaller channels are often observed to either branch off from the dominant channel or smaller side channels would connect and join the flow path of the major channel. Secondly, Berea sandstone slabs are cut and an experimental setup is built in order to study two main mechanisms for improved gel placement. The application of Cr (III) acetate pre-flush and overload are investigated in order to determine their effect on gel performance within fractures. Both techniques compensate for the amount of chromium lost to the matrix via molecular diffusion and the integrity of the gel is maintained. This allows for significant fracture blockage without having to place performed gel or placing the gel ant with leak-off in order to achieve a stable gel. Introduction Many reservoirs currently under production suffer from excessive water production. Water could be supplied either by a natural water source (e.g. aquifer) and/or because of waterflooding. Waterflooding is normally used in order to displace any remaining oil in the reservoir matrix after the primary stages of oil production. Presence of high permeability zones in the reservoir provides pathways for water to bypass oil-bearing regions and break through into the production wells. Areas of the reservoir that are fractured, either naturally or hydraulically, are excellent pathways for floodwater to penetrate and consequently bypass oil-bearing pore spaces. Blocking the high permeable thief zones and diverting water towards the unswept regions of the reservoir has been proposed and used by oil producers as a viable remedy for this problem. In-depth gel placement is the most widely used technique for blocking high permeable zones of reservoirs. This technique has been implemented through many field trials around the world and researchers have successfully determined the mechanisms governing this process in porous media. Although gel placement in fractures is a common practice in the field, the mechanisms controlling the performance of this technique in fractures are not well understood. This has created a challenging opportunity for researchers to study the detailed mechanisms of gel placement and performance in fractures.

More recently polymer flooding recovery processes are becoming increasingly attractive due to the improvements in polymer manufacturing, hydration and implementation successes worldwide. This is especially true in the application of polymer for enhancing heavy oil recovery. It has been suggested that the elastic nature of the polymer is equally important to the viscous properties. In the present study, a specialized rheometer was used to determine the viscoelastic properties of both hydrolyzed polyacrylamides (HPAM) and hydrophobically associating polyacrylamides (HAP) used in heavy enhanced oil recovery (EOR) processes. The rheometer has the capability to measure rheological properties in porous capillary plugs providing a more representative picture of non-Newtonian fluid flow in reservoirs. The rheological parameters were determined as influenced by polymer type, concentration, molecular weight, hydrophobicity, salinity and temperature. Increases in elastic tendencies were observed as a function of the first four; however, salinity and temperature were found to have a slightly negative effect. A medium density, hydrophobic polymer showed an earlier onset of elastic contribution at in-depth reservoir shear rates as determined by its Weissenberg number. For heavy oil reservoirs utilizing higher polymer concentrations, the viscoelastic properties of a polymer system should be evaluated in the screening process. Recent studies suggest that viscoelastic polymers can reduce the residual oil saturation below that to waterflood with two different plausible mechanisms at play, depending whether the media is water- or oil-wet. However, in both theories, polymer elasticity is believed to be the dominant force that contributes to the additional reduction in oil saturation. Aside from measuring the elasticity directly, other parameters that quantify a polymer's elastic potential are its relaxation time and Weissenberg number; therefore, the change in these parameters with respect to dynamic shear rate or flow velocity can be further useful for screening purposes.

The economic life of a typical heavy oil reservoir under primary or secondary recovery schemes can be short lived or near their limit, with recovery factors in the range of 5-15%. Waterflooding alone has been successfully practiced in the Lloydminster area of the Western Canada for decades. Heavy oils located in thick reservoirs have benefited from the application of thermal, gravity drainage processes; however, thin, unconsolidated heavy oil reservoirs are unsuitable due to lack of drainage height. These reservoirs may benefit from immiscible CO 2 or CO 2 -WAG processes.This paper examines the effect of oil viscosity, permeability and injection rate on the performance of heavy oil waterflooding, immiscible CO 2 flooding and immiscible CO 2 water-alternating-gas (WAG) processes. A series of 11 sand packfloods were conducted using 440 and 1,500 mPa·s heavy oils and sand packs with absolute permeabilities of 12 and 40 µm 2 . Water injection volumes for the waterfloods were 1.5 pore volumes (PVs) at rates of 0.112, 1.124, and 5.62 cc/min. For the CO 2 flooding process, 4.5 PVs of gas were injected at a rate of 1 cc/min. For the WAG process, the water:CO 2 slug ratios were varied from 1:1, 1:2 and 2:1. A 99.9% purity CO 2 gas stream was used for all gas floods. All experiments were performed at a controlled temperature of 25°C and 345 kPa.Among the 11 sand packfloods conducted, the waterfloods consistently yielded the highest recovery factor for both heavy oils and sand packs, with 48-52% OOIP recovered and most of this recovery occurring during 0.112 cc/min. During CO 2 flooding of the 440 mPa·s oil, 48.5% OOIP was produced from the 40 µm 2 sand pack. From the same fluid-sand system, a 1:1 slug ratio, CO 2 -WAG process produced 42% OOIP. For the 1,500 mPa·s heavy oil, 1:2 and 2:1 slug ratios of CO 2 -WAG both produced ~25% OOIP from the 40 μm 2 sand pack and a 1:1 slug ratio produced 35% OOIP from the 12 μm 2 sand pack. All WAG injection schemes were compared on a 2.5 PV injected basis. These results suggest that the role of displaced fluid viscosity plays the most prominent role in the recovery of heavy oil.

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The production flow rate in classical VAPEX is far too low for the process to be considered commercially viable. This is largely because the classical process utilizes forces of buoyancy to distribute the solvent and gravity to drain the diluted oil to the producer. This paper presents a new well pattern that may enhance the oil flow rate two to ten times over the classical approach. In the new well pattern, additional horizontal injectors, perpendicular to the injector and the producer in classical VAPEX, are placed in the top-most region of the reservoir. The enhanced oil rate mechanism for this new well pattern involves two features. First, the injection pressure of the top injectors is set slightly higher than the bottom injector pressure. This facilitates a downward driving force to assist gravity drainage of diluted oil to the producer. Second, the supplementary injectors generate an additional diluted oil profile perpendicular to the diluted oil profile of the classical VAPEX process. Therefore, in the new well pattern, the heavy oil is solvent contacted and diluted in both ik and jk planes, whereas in classical VAPEX, the heavy oil is diluted in only one. A series of numerical simulations were conducted to evaluate this process. In order to obtain reliable evaluation results, the numerical dispersion was eliminated through extrapolating the simulation results at different grid sizes to an infinitesimal grid size (?y?0). The simulation results suggest that the oil flow rate can be enhanced two to ten times greater than with classical VAPEX, depending on the well spacing of the top injectors. For example, for a well spacing of the top horizontal injectors of 120 m, the oil flow rate from the original producers will be 5.5 times higher than in the VAPEX scenario. The paper also discusses the effects of the design factors and formation/fluid uncertainties on the performance of this process. Finally, thinner reservoirs and reservoirs with a gas cap are discussed. Introduction The patented VAPEX (vapour extraction) process was developed over twenty years ago. In the classical VAPEX, a horizontal injector is stacked vertically, within a few meters, above a horizontal producer to utilize gravity to facilitate the drainage of the solvent-diluted oil to the producer. The fundamental challenge with VAPEX is that the oil rate in the field is far too low to allow a commercially viable process. Variations of VAPEX have been investigated to enhance the oil production rate. Butler and Mokrys (1998) and Frauenfeld et al. (2006) experimentally studied the VAPEX process in bottomwater reservoirs and suggested that high oil production rates are possible if an appropriate well spacing is given. Butler and Jiang (2000) presented a lateral VAPEX process, in which the horizontal producer is laterally separated from the injector and located at the bottom of the reservoir. According to their experimental observation, the lateral process allows higher production rates and makes the VAPEX process more economic. Rahnema et al. (2007) experimentally studied the VAPEX process for reservoirs with a gas cap and concluded that the lateral spacing between injector and producer has no effect on the oil recovery and delays initial well communication. Rezamei and Chatzis (2007) proposed Warm VAPEX, in which the solvent is heated above the dewpoint temperature of solvent vapours at reservoir pressure and injected into the reservoir. The superheated vapours carry some sensible heat and cause an additional driving force due to mixing. The authors claimed that the Warm VAPEX is promising in terms of enhanced oil production rates.