The unusually high primary recovery factors (RFs) observed in numerous heavy-oil reservoirs are often attributed to foamy oil flow (i.e., the non-Darcy flow involving formation and flow of gas-in-oil dispersion). It occurs when the wells are produced aggressively at high drawdown pressures that led to conditions in which the viscous forces become sufficiently strong to overcome the capillary forces in pushing dispersed bubbles through pore throats. The role of gravitational forces in generating such dispersed flow has not been studied adequately. This work was intended to evaluate the contribution of gravitational forces in primary depletion of heavy-oil formations under foamy flow conditions.
Primary-depletion tests were conducted in a 200-cm-long sandpack that was held in either horizontal or vertical orientation. The results of horizontal depletion tests were compared with the depletion tests conducted with the sandpack in the vertical direction. Vertical depletions showed better recoveries at slower depletion rates compared with horizontal depletions.
The RFs of both horizontal and vertical depletions were correlated against the average drawdown pressure available to move the oil. It was found that the RF shows a strong dependence on the average drawdown pressure. It was also found that the curve of RF vs. average drawdown pressure moves slightly toward higher recoveries in the presence of an added foaming agent (i.e., with increased oil foaminess).
The commercial viability of the steam-assisted gravity-drainage (SAGD) process is affected negatively by several undesirable reservoir features, such as pronounced heterogeneity, low vertical permeability, thick and areally extensive shale barriers, and steam thief zones. The efficiency of SAGD projects is also affected by the presence of higher water saturation in the target zone. Although the presence of small mobile-water saturation is not considered harmful, reservoirs with high water saturation may be poorly suited for the SAGD process. Nonetheless, SAGD remains the only practical technology for in-situ extraction of oil from oil-sand reservoirs, even when mobile water is present. This raises the question of how much mobile water is prohibitive.
To investigate the effect of water saturation on SAGD performance, high-pressure physical-model experiments were carried out. Different levels of water saturations were established in the model by modifying the packing and saturating techniques. SAGD experiments were carried out by injecting superheated steam at controlled rates and producing the oil from the production well at constant pressure. The injection rate was selected to keep the pressure difference between the injector and the producer at a low level.
The oil-production behavior was analyzed to evaluate the effect of water saturation on the thermal efficiency of the process. On the basis of the results of low- (immobile) and high- (mobile) water-saturation experiments, it was observed that the oil-recovery factor dropped by 6.6% when the initial water saturation was increased from 14.7% to 31.8%.
In Situ Combustion, ISC, is a process with strong potential to compliment Steam Assisted Gravity Drainage by extending the economic life of the SAGD pattern and hence improving the ultimate recovery. Implementing In-Situ Combustion, as a follow-up process to SAGD can improve recovery from the pattern by displacing residual oil from the steam chamber and more importantly by recovering oil from the wedge zones. Theoretically the temperature and residual oil saturation within the SAGD chamber are high enough to initiate and sustain the combustion process by switching from steam to air injection; however laboratory investigations of the hybrid process have shown that the in situ combustion behavior within the steam zone has some special features which must be considered.
Injection of air into the SAGD injection well is the desired option from an economic view point, however laboratory tests showed that the combustion zone tended to be more stable when air was injected at a location higher up in the chamber. This behavior relates to the fact that the combustion reactions were primarily occurring within the vapor phase, hence gravity plays a dominant role controlling the distribution of air flux within the chamber as well as the drainage of oil and water out of the combustion zone. Laboratory tests also confirmed the importance of promoting air flux across the walls of the original steamed chamber.
Incorporating some heat injection along with the solvent injection appears to be the most viable option for improving the oil drainage rate of Vapex in extra-heavy oil formations. This study was aimed at quantifying the potential increase in Vapex drainage rate that can be obtained by increasing the formation temperature.
The experimental phase of this study involved conducting Vapex experiments in a large high-pressure physical model, packed with 250 Darcy sand, using propane as the solvent. The physical model was warmed up to 40, 50 and 60 °C and propane was injected at the same test temperature but different injection pressures to observe how injection pressure affects oil drainage rate at elevated temperatures.
In the experiments at elevated temperatures but without increasing the injection pressure, higher rate of oil production was achieved in the early stages of the process. However, stabilized rate of oil production did not show pronounced improvement due to lower solubility of propane in the oil at higher temperatures. Increasing injection pressure along with increasing the test temperatures was successful in accelerating the oil production.
The oil, used in these experiments, was found to become mobile with the increase in temperature even without solvent dissolution. As a result, the total rate of oil production appeared to be controlled by two mechanisms. First, by solvent dissolution and oil mobilization at the boundaries of the vapor chamber and second by pure free fall gravity drainage beyond the vapor chamber wherever gravity head was sufficient to push the mobile oil toward the production well.
The results of this these tests define the upper limit of oil rates achievable with heated solvent injection. They can also be used to assess the applicability of Vapex to naturally warm reservoirs such as in Venezuela and reservoirs with mobile oil in place.
Solvent SAGD hybrid processes have attracted considerable attention in recent years. The perceived benefits of solvent addition to steam in SAGD are higher oil rate, lower energy and water consumption, higher recovery by lowering residual oil saturation (Sor) and higher return on investment. Despite numerous investigations that have been published regarding different aspects of solvent SAGD processes, this hybrid process is poorly understood and the solvent effects are difficult to predict. In fact, there is no available theory to model to the transport phenomena and the role of solvent within the steam chamber. Numerical simulation studies typically model the viscosity reduction of bitumen by solvent dissolution but do not capture other plausible mechanisms that yield higher oil rate and recovery, for example, lowering of Sor or partial in-situ upgrading. Laboratory experiments at realistic reservoir conditions are needed to gain more insight into these hybrid processes.
This paper presents the results of a series of laboratory experiments for evaluation of solvent addition to SAGD. These experiments were conducted at different representative reservoir pressure in a 3-D scaled physical model. Hexane, which has shown the best performance in many studies, was co-injected as solvent with steam in these experiments. Oil rate, recovery, and steam oil ratio were compared and the hybrid solvent/SAGD process performance was evaluated at different operating conditions. Additionally post-test sand samples were extracted from the model to examine residual oil saturation in different parts of the model after each experiment. Experimental results showed improved performance of SAGD with addition of hexane, both at high and low operating pressure. However, the impact of hexane on the shape of the steam chamber and distribution of residual oil was significantly affected by operating pressure. This behavior of hexane, which appears to be related to its phase behavior, shows that solvent SAGD processes are considerably more complex than first thought.
Cold heavy oil production with sand (CHOPS) is widely used as primary recovery method for heavy oil in western Canada. This process involves sand production in massive amounts. Sand production creates high permeability zones (wormholes) which extend the drainage radius. Typically 5-10% of the OOIP is recovered by this process. Therefore, the need to find a follow-up process is paramount.
The objective of this work was to experimentally evaluate the potential of using cyclic CO2 injection for recovering additional oil from depleted foamy oil reservoirs. A total of five depletion tests were conducted in a two meters long sand-pack kept in a vertical orientation. The primary depletions at different depletion rates were followed by one or two huff-n-puff cycles of CO2 injection.
The total recovery factor after cyclic CO2 injection reached 30% indicating the potential of solvent injection as a secondary oil recovery method. Interestingly, the recovery after the cyclic CO2 injection was more or less independent of depletion rate used in the primary production. It was found that the cyclic CO2 injection was more efficient when the primary depletion was at slow rate and resulted in lower primary depletion recovery.
The results of this study show that it may be possible to re-energize the depleted heavy oil reservoirs by injecting CO2, especially those that did not give high recovery factors during the primary depletion.
The unusually high primary recovery factors observed in many heavy oil reservoirs are often attributed to foamy oil flow, i.e. the non-Darcy flow involving formation and flow of gas-in-oil dispersion. It occurs when the wells are produced aggressively at high drawdown pressures that lead to conditions in which the viscous forces become strong enough to overcome the capillary forces in pushing dispersed bubbles through pore throats. The role of gravitational forces in generating such dispersed flow has not been adequately studied. This work was aimed at evaluating the contribution of gravitational forces in primary depletion of heavy oil formations under foamy flow conditions.
Primary depletion tests were conducted in a 200 cm long sand-pack that was held in either horizontal or vertical orientation. The results of horizontal depletion tests were compared with the depletion tests conducted with the sand-pack in vertical direction. Vertical depletions showed better recoveries at slower depletion rates compared to horizontal depletions.
The recovery factors of both horizontal and vertical depletions were correlated against the average drawdown pressure available to move the oil. It was found that the recovery factor show a strong dependence on the average drawdown pressure. It was also found that the curve of recovery factor versus average drawdown pressure moves slightly towards higher recoveries in the presence of an added foaming agent which increases the oil foaminess.
Heavy oil and bitumen are expected to become increasingly important sources of fuel in the coming decades. There are extensive deposits in Alberta that could be a principal source of fuel in the coming century. The Athabasca oil sands, the largest petroleum accumulation in the world; the Cold Lake oil deposit; and the Lloydminster reservoir are all major Canadian oil-sands deposits. Steam-assisted gravity drainage (SAGD), which has shown considerable promise in all three of these major deposits, remains an expensive technique and requires large energy input. The energy intensity of SAGD and the environmental concerns make it imperative to find new oil-extraction technologies.
Coinjecting hydrocarbon additives with steam offers the potential of lower energy and water consumption and reduced greenhouse-gas emission by improving the oil rates and recoveries. In a previous paper by the same authors (Hosseininejad Mohebati et al. 2010), we showed that the selection of a suitable hydrocarbon additive and the effectiveness of this hybrid process are strongly dependent on the operating conditions, reservoir-fluid composition, the heavy-oil viscosity, and the petrophysical properties of the reservoir. Among these factors, the heavy-oil viscosity, which is the main difference between these three reservoirs, could be a very important parameter in the performance of this hybrid process. Therefore, it is necessary to optimize the hydrocarbon additives to SAGD for these three oil-sand deposits separately.
Extensive numerical studies in a 3D model by means of a fully implicit thermal simulator were conducted to evaluate the efficiency of each hydrocarbon additive with different heavy-oil viscosities (resembling those of Athabasca bitumen, Cold Lake heavy oil, and Lloydminster heavy oil). Varying mole percents of hexane, butane, and methane were coinjected with steam to each reservoir with different heavy-oil viscosity. The optimum amount of hydrocarbon injection was reported in each case. This culminated in a novel method for selecting the most advantageous hydrocarbon additive and its optimum concentration considering the heavy-oil viscosity.
Large quantity of heavy oil resources are present in variety of complex thin reservoirs in Lloydminster area which are situated in east-central Alberta and west-central Saskatchewan. Primary depletion and waterflooding are the principal recovery techniques. Although these techniques work, the recovery factors remain low and large volumes of oil are left unrecovered when these methods have been exhausted. Because of the large quantities of sand production, many of these reservoirs end up with a network of wormholes that makes most of the displacement type enhanced oil recovery techniques inapplicable. Because of these high conductivity channels, only gravity drainage based techniques have a good chance of success.
Among the applicable methods in Lloydminster area, SAGD has not received adequate attention, mostly due to the notion that heat loss in thin reservoirs would make the process uneconomical. While this may be true, the limiting reservoir thickness for SAGD under varying conditions has not been established. These reservoirs contain light oil with sufficient mobility. Therefore the communication between the SAGD well pairs is no longer a hurdle. This opens up the possibility of increasing the distance between the two wells and introducing elements of steamflooding into the process in order to compensate for the small thickness of the reservoir.
The main objective of this study was to evaluate the effect of well configuration on SAGD performance and develop a methodology for enhancement of the SAGD performance through optimizing the well configurations for Lloydminster type of reservoir.
A new well configuration was able to significantly improve the application of SAGD in thin reservoirs of Lloydminster. It provided high RF at reasonable cSOR. The effects of some common Lloydminster reservoir characteristics, which are problematic for the SAGD process (such as initial gas saturation, bottom water, and gas-cap) were investigated for the most promising well configuration.
Foamy-oil viscosity is a controversial topic among researchers regarding what happens to the oil viscosity when the solution gas starts coming out of solution because of decreasing pressure and the released gas starts migrating with the oil in the form of dispersed gas bubbles. For conventional oils, below the true bubblepoint pressure, the oil viscosity increases as the gas freely evolves from the oil. For foamy oils, it has been suggested that the apparent oil viscosity remains relatively constant or perhaps declines slightly between the true bubblepoint and a characteristic lower pressure, called pseudobubblepoint, which is the pressure at which the gas starts separating from the oil. Below this pressure, the viscosity increases, reaching the dead-oil value at atmospheric pressure. However, it is a well-known fact in dispersion rheology that the viscosity of dispersion is higher than the viscosity of the continuous phase. Therefore, the concept of foamy-oil viscosity being lower than the oil viscosity is counterintuitive. It is likely that the apparent viscosity for flow of foamy oil in porous media is not the true dispersion viscosity because of the size of dispersed bubbles being comparable to the pore sizes.
This study investigates this issue by measuring the foamy-oil viscosity under varied conditions. The effect of several parameters, such as flow rate, gas volume fraction, and type of viscometer employed, on foamy-oil viscosity was evaluated experimentally. Three different viscosity-measurement techniques, including Cambridge falling-needle viscometer, capillary tube, and a slimtube packed with sand, were used to measure the apparent viscosity of gas-in-oil dispersions. The results show that the type of measuring device used has a significant effect. The results obtained with Cambridge falling-needle viscometer correlate better with the observed behaviour in the sand-packed slimtube than the capillary viscometer results. Overall, the apparent viscosity of foamy oil was found to be similar to live-oil viscosity for a range of gas volume fractions.