Most of the Nuclear Magnetic Resonance (NMR) log based permeability models require the estimation of the irreducible water saturation (Swirr). Several methods are available for calculating this parameter using NMR relaxometry. The most straightforward method with the lowest accuracy is to consider a fixed relaxation time (T2) value. It has been suggested to use a T2-cutoff equal to 10 ms for tight reservoirs. Another traditional experimental method involves centrifuging core plugs to Swirr. In this paper, an additional approach to separate free and bound water using NMR relaxation time is introduced. This method involves the area under the amplitude-T2 relaxation time graph.
A series of experiments were conducted on 81 core plugs. These samples are mainly from the Western Canadian Sedimentary Basin. Core plugs are from Montney, Nordegg, Mist Mountain, Red Beds, Doig, Killam, Lathom, York River, Wapiti, Teslimkoy, Kesan, and Ordivician Quartz formations. NMR measurements were obtained initially on the dry cores to establish the presence of any liquids that were not cleaned or any isolated porosity. The air permeability was measured using an in-house permeameter. The cores were then brine saturated in two steps of spontaneous imbibition followed by forced imbibition under vacuum. The Archimedes principle was used to measure the sample pore volumes. Porosity was subsequently calculated. NMR relaxation data were then acquired on the brine-saturated cores. Then the core plugs were centrifuged under air to an expected irreducible saturation. NMR relaxation times were obtained on all cores at Swirr.
NMR porosity, T2gm, Irreducible Bulk Volume (BVI), and Free Fluid Index (FFI) were calculated. Swirr was calculated with the three aforementioned methods. Excel Visual Basic for Applications (VBA) programming language was employed for analyzing the relaxation times. The Timur-Coates model was applied for permeability calculation using all the aforementioned Swirr estimation methods. Data were analyzed, and discrepancy analysis was conducted.
The implemented area analysis method has been used previously in reservoir typing based on formation types and also as a factor in one permeability model. However, this is the first time this approach is used in calculating FFI/BVI exclusively. This method is faster than conventional estimators, and it is the only method that can implement Timur-Coates based permeability models for logging tools. From the experimental point of view, only a single NMR measurement is needed. Centrifuging the cores is not necessary. The possibility of cracking these cores due to spinning is eliminated. This new approach is less computationally demanding, and calculations are easier to perform. It is proven that the fast peak area method is more accurate than the fixed T2-cuttoff and in some cases the centrifuge method.
Although heavy oil reserves are abundant, recovering them efficiently and economically remains a crucial technical challenge as a result of their high viscosity. Solvent based non-thermal recovery processes are designed to reduce the heavy oil viscosity through mixing and dilution with solvent. Solvent and heavy oil mixing occurs over a narrow zone, so localized viscous fingering can have a significant impact on the effectiveness of the solvent. In this study, direct pore scale modeling was used to simulate viscous fingering phenomenon during unfavorable mobility ratio miscible displacement of heavy oil in a three dimensional heterogeneous porous medium pattern.
In direct pore-level modeling, Navier-Stokes, Diffusion-Convection and Continuity equations, as the governing equations of dispersion, are directly applied and solved on the 3-D porous medium without any simplification in medium geometry.
To study the impact of unfavorable mobility ratio on the miscible displacement at the sub pore scale level, simulations have been run to model miscible displacement at five different unfavorable mobility ratios on the same porous medium pattern. Additional simulations were run to investigate the effect of pore pattern and different injection rates on the patterns, which were generated based on the process/object based reconstruction method. Base line simulations also have been done to model miscible displacement on the same medium when the mobility ratio is equal to one.
Heterogeneity of the pattern and lower viscosity of the solvent leads to appearance of some fingers just after starting solvent injection. The results show that growth rate of the fingers become smaller by decreasing mobility ratio. Finger transitions are the same for different mobility ratios but the fingers size and growth rate of the fingers are different for different mobility ratios. Generated fingers accelerate concentration spreading, so the solvent is mixed faster than that predicted by Convection-Dispersion equation. As the mobility ratio decrease toward one, growth of mixing zone length tends to 0.5, which is the growth rate caused by dispersion alone. By increasing the mobility ratio, fingers causes the mixing zone length growth tends to 1, so, for large mobility ratio, mixing zone grows because of two mechanisms: Dispersion and Fingering.
Alberta contains significant bitumen resource volumes in heterogeneous carbonate formations. Recovery of this bitumen requires reduction of oil viscosity, coupled with drainage of low viscosity oil to high permeability production pathways. Oil viscosity reduction is most commonly accomplished through heat, via steam injection into the reservoir. While steam leads to fast drainage of oil from high permeable secondary porosity, access to the matrix is more difficult. Imbibition of water (steam condensate) can potentially lead to some access to the rock matrix, but wettability is still not well-defined in these systems. This work considers the results of several core flooding studies whereby solvent is used to recover bypassed oil in the carbonate pore matrix.
Solvent soaking tests are presented, validating the potential for solvent processes to mobilize bitumen at low and intermediate temperatures. Subsequently the results are provided for full diameter carbonate cores, which were first exposed to steam, and then were circulated in steam/solvent and solvent with varying temperatures. A process is described, whereby a heated reservoir is contacted by solvent while it cools. The combination of initial heat (elevated mass transfer) and subsequent cooling (elevated solvent solubility) leads to significant incremental oil production beyond that of steam alone. The application of solvent as a post-steam recovery process has considerable potential for increasing oil recovery by accessing previous bypassed oil within the carbonate matrix.
Bitumen-bearing carbonate reservoirs, dominated by the 406 billion barrel resource in the Grosmont formation, will provide billions of barrels of recoverable oil for the Province of Alberta. A small contribution to this development was an extensive series of initial laboratory experiments that were conducted for multiple producers under a variety of conditions. The experiments include measuring oil recovery to varying water and steam processes, both separately and in combination with each other. Displacement procedures included both washing/soaking and direct floods with temperatures ranging up to 260°C. These laboratory tests were conducted over a six year period.
As this research was conducted across several producers independently, a planned statistical design was not addressed through this process. Rather, the experiments are exploratory in nature, examining the primary recovery mechanisms contributing to production performance and ultimate recovery of bitumen in these heterogeneous systems. It has been shown that bitumen can be readily recovered from fractured and connected open porosity that is accessible to steam through a gravity drainage process. Furthermore, carbonates at elevated temperatures become more water wet, and water imbibition can play a significant role in accessing recovery from the oil-bearing rock matrix. The impact of imbibition is significant, and wet steam proves a much more efficient displacing medium than dry steam. The recovery of oil from lab-scale models also shows a significant impact of thermal expansion and gas drive, which can lead to significant oil displacements at early times, particularly in areas where the localized open porosity network is extensive. Bitumen recovery from carbonate systems is achieved through a combination of these processes: thermal expansion, gas drive, gravity drainage of oil out of connected open porosity, and imbibition of water into the rock matrix.
At the end of primary production in heavy oil reservoirs, significant volumes of continuous oil remain in place. As production rates decline this EOR target has tremendous value for heavy oil producers. Many of these reservoirs are poor candidates for thermal recovery. Furthermore in regional sands or post-CHOPS systems, it may not be easy to pressurize these reservoirs for solvent-based recovery. Chemical flooding has potential for EOR in these systems, because the injection of chemicals can lead to the buildup of pressure gradients between injectors and producers, at least at the laboratory scale. These pressure gradients evolve due to improved viscosity of polymer solutions, the formation of emulsions in surfactant or AS floods, or both. The objective of this work is to improve our understanding of the mechanisms by which heavy oils are produced through chemical flooding.
Linear core floods were run on systems containing two heavy oils of variable viscosity: 500 mPa's and 16,000 mPa's. For the lower viscosity oil polymer floods and ASP floods are compared. These tests illustrate the impact of improving the injection fluid viscosity vs. the additional benefit from the addition of surfactant. It was observed that heavy oil is produced more efficiently from ASP flooding compared to polymer flooding alone. The residual oil saturations are lower in ASP floods, even with lower differential pressure across the core. For the higher viscosity oil some production was achieved through AS flooding alone, but the addition of polymer was important for improving recovery.
Tests were also run on a parallel core system, containing cores of relatively high and low permeability. This was a representation of a post-CHOPS reservoir containing preferential flow channels due to the presence of wormholes. Both surfactant and ASP solutions only accessed the high permeability core, so oil was bypassed in the lower permeability sand even with the addition of chemicals to water. This result demonstrates that laboratory studies may be dramatically over-estimating the success of chemical flooding in heavy oil, and poses a challenge for successful implementation of chemical floods in heterogeneous post-CHOPS heavy oil fields.
In western Canada, there have been more than 300 heavy oil waterflooding projects. Most of these projects displayed good economical and efficient variability even though they were operated in marginal pools. Although waterflooding of heavy oil has almost 50 years history, its mechanisms, especially in the situation of high oil water viscosity ratio, are still not well understood. In the situation of high viscosity ratio, fractional flow theory does not work because of severe water fingering and other mechanisms that are different from conventional waterfloods. The operation strategies of heavy oil waterflooding, such as water injection rate, injection pressure and VRR, are still under controversy.
In a water-wet environment, waterflooding (water displacing oil) represents a process of water imbibition. In this paper, the water imbibition mechanisms and their effects on the heavy oil recovery are studied using a water-wet micromodel. The effects of time, viscosity ratio and water injection rate on the imbibition rate are also studied. The imbibition rate of water was found to be proportional to the reciprocal of the square root of time, and inversely related to oil viscosity. The effects of injection rate on imbibition rate are complicated. At low injection rates, waterflooding becomes more efficient, and significant volume of oil is produced discontinuously. Images of the imbibition process were recorded and analyzed from visual micromodel studies. Water broke through quickly because of water fingering, and a considerable portion of recovery comes from post-breakthrough production of oil, under high water cuts. In the cases of low rate water injection, water imbibed into the original oil region perpendicularly to the water channel. In this stage, capillary imbibition was a key factor. Water film thickening and snap-off were the two main mechanisms that made water imbibition work. Emulsification was also another important mechanism observed, with W/O emulsions primarily being formed.
Since the 1950's, the use of carbon dioxide to increase heavy oil recovery has attract more attention from industry and laboratory research. The injection of carbon dixode has shown technical and economical advantages for enhancing heavy oil and bitumen recovery, because it can effectively reduce viscosity under the reservoir conditions. When carbon dioxide is injected into the reservoir, it partially dissolves into the heavy oil and mass transfer is the first mechanism to occur. Consequently, the accurate prediction and evaluation of the diffusion coefficient of carbon dioxide in heavy oil is one of the key parameters to develop technology for extraction of heavy oil in a feasible and cost-effective way. However, few experimental data for diffusivity of carbon dioxide in heavy oil are available in the literature. Therefore, this study conducted in order to add to the existing the laboratory data for evaluation and calculation of diffusion coefficient of carbon dioxide into heavy oil. In the past, experimental methods used to determine the diffusion coefficient of a gas in heavy oil were conducted under a constant gas pressure, which assumed that oil phase can be contacted with infinite gas at a fixed pressure. In this study, by employing X-ray Computed Assisted Tomography (CAT) and a non-iterative finite volume method, the purpose is to evaluate and compare experimental diffusion coefficients of carbon dioxide in heavy oil under the constant pressure and decaying pressue at the same time. Moreover, investigation of impacts of pressure on diffusion coefficients is conducted.
It is found that the diffusvity of carbon dioxide in heavy oil is sensitive to the system pressure. The comparison between carbon dioxide diffusion coefficients under the constant pressure and those measured under the decaying pressrue showed an obvious difference. The results of study are essential for understanding oil recovery through carbon dioxide injection.
Injection of carbon dioxide has shown process and economical advantages for enhancing the heavy oil and bitumen recovery by reducing viscosity under the reservoir conditions. Mass transfer is the first mechanism to occur when carbon dioxide is injected into the reservoir. Consequently, the measurement and evaluation of the diffusion coefficient is essential to develop feasible and economic technology for extraction of heavy oil and bitumen. However, not much effort has been put into the experiments of carbon dioxide and heavy oil for understanding and calculation of the gas-liquid diffusion coefficient. The purpose of this study is to evaluate the feasibility of determining experimental diffusion coefficients of carbon dioxide in heavy oil by employing X-ray Computed Assisted Tomography (CAT) and a non-iterative finite volume method, and investigate the impact of different experimental conditions on diffusion coefficients.
The results indicated that the measured carbon dioxide diffusion coefficients are consistent with those reported in the literature for similar gas-heavy oil systems. X-ray Computed Assisted Tomography (CAT) and a non-iterative finite volume method were successfully applied to study the diffusivity of carbon dioxide in heavy oil. In addition, the concentration and diffusion coefficients of carbon dioxide in heavy oil depend on diffusion distance as well as on diffusion time and pressure.
In Canada, as conventional oil reserves become depleted, interest continues to grow in the improved recovery and utilization of heavy oil and bitumen. Among a number of non-thermal techniques, injection of carbon dioxide has become as an attractive way to enhance heavy oil and bitumen production. Compared to the other non-thermal techniques, it is more cost-effective. It is well-known that, carbon dioxide is injected into the heavy oil and bitumen reservoirs, and then significantly reduces oil viscosity under the reservoir conditions. Obviously, mass transfer is the first mechanism during the carbon dioxide injection process, which is controlled by the diffusion coefficient. Consequently, the measurement and evaluation of the diffusion coefficient is important to develop feasible technology for extraction of heavy oil and bitumen.
For measuring the diffusivity of a gas in heavy oil or bitumen, the experimental methods can be roughly categorized into two methods: conventional and nonconventional . Several experiments have been published using conventional composition analysis [2, 3], monitor pressure decay [4-9], monitor gas-oil interface position , dynamic pendant drop volume analysis [1, 11], and low field nuclear magnetic resonance (NMR) spectra [12, 13].
X-ray Computer Assisted Tomography (CAT) has also been a revolutionary technique for application in the area of petroleum industry and research projects. Employing X-ray CAT techniques to generate solvent and bitumen concentration profiles, Salama and Kantzas  and Luo et al.  have done experiments on determining of diffusion coefficients of hydrocarbon solvents in heavy oil. Guerrero-Aconcha and Kantzas  developed a numerical technique to estimate gas diffusion coefficients from concentration profiles obtained from X-ray CAT scan. The results agreed very well with the theory of diffusion in binary mixtures.
With the depletion of conventional oil resources, heavy oil and bitumen play an increasingly important role as the main resources for crude oil. This is particularly true in Alberta since it has in excess of 400 x 109m3 of heavy oil and bitumen. In Canada, most of heavy oil and bitumen resources are developed with thermal methods. Thermal methods for heavy oil and bitumen recovery include the injection of steam in the form of SAGD (steam assisted gravity drainage), CSS (cyclic steam stimulation), and steam flooding, whereby thermal energy is given to the oil, reduces its viscosity and allows it to flow towards a production spot. These methods have not been yet investigated for the large fraction (in excess of 50%) of oil sands that are thinner, less permeable, heterogeneous, or contacted by water. Electrothermal methods have attracted more and more attention as an alternative to conventional thermal methods for the difficult reservoirs where conventional thermal methods are not expected to work well.
In this study, a series of comparative studies are carried out using a simulation tool developed by CMG (Computer Modeling Group). In a series of marginal reservoirs such as thin reservoirs, low permeability reservoirs, and reservoirs with bottom water, both the SAGD process and the electrothermal process are applied. The resulting recoveries are compared and economics are evaluated for both methods for each case. The typical SAGD problem of the McMurray oil sands is used as the base case benchmark.
Our results to date indicate that under favorable conditions, electrothermal methods have the potential to recover thin bitumen reservoirs that cannot economically be produced by the SAGD process. Furthermore, electrothermal methods can achieve recovery factors superior to SAGD in terms of the production of thin bitumen reservoirs with bottom water and low permeability bitumen reservoirs. Controlled heating seems to be beneficial in electrothermal processes. Innovative well placement also appears to have favorable effects.
Many reservoirs in Canada are too small or thin for energy-intensive thermal EOR operations. The reservoirs may also be disturbed during primary production, generating low-resistance flow-pathways between injectors and producers, thus injected fluids will follow these pathways and not contact additional oil. In these conditions, alkali-surfactant injection has considerable potential as a technique for additional non-thermal recovery of heavy oil.
During unstable displacement of heavy oil by water, water breakthrough occurs early, and subsequent water injection will channel mostly through the water fingers and bypass significant volumes of continuous oil. It has been shown in other works that alkali and/or surfactant injection can lead to improved heavy oil recovery compared to waterflooding, but researchers have proposed different reasons for this response. This work summarizes the mechanisms that are responsible for improved heavy oil recovery and presents the results of 30 laboratory core floods investigating alkali-surfactant injection into sandpacks containing heavy oil (viscosity 11,500 mPa·s at 23°C).
By injecting less than 1% of alkali-surfactant (AS) solution with water, a combination of oil-in-water (O/W) and water-inoil (W/O) emulsions will form in the water channels, effectively blocking them off. Further injected solution will therefore contact fresh regions of the core. It is shown that this design of AS injection in heavy oil leads to improved sweep efficiency of the flood. This corresponds to lower apparent relative permeability values to the aqueous phase, and a discussion is provided regarding how AS floods can be controlled and optimized.
In any heavy oil reservoir that is considered a viable candidate for waterflooding, AS flooding can also potentially be applied. The significance of this work is that it describes the mechanisms responsible for the improved oil recovery, which allows for optimized design of chemical flooding conditions. This study demonstrates how a small amount of chemical injected along with water can lead to dramatic improvements in the recovery from previously flooded heavy oil fields.