The dissolution of gas in both water and bitumen as a mechanism contributing to gas production in SAGD is studied. The contribution of this mechanism to the production of gas in SAGD is evaluated through the implementation of appropriate thermodynamic models into a series of numerical simulations in order to more accurately represent the physics of gas behavior inside the SAGD chamber. Methane, carbon dioxide and hydrogen sulphide are considered.
It is observed from the numerical simulation results that the production of a gas in SAGD is directly proportional to the solubility of that gas in the liquid phases being produced. Additionally, these results lead to the conclusion that gas dissolution is an important mechanism in gas production.
Results from this study also confirm the findings observed by other researchers that gas will accumulate at the front and top of the SAGD chamber, thus reducing SOR and oil production rates. The degree of such accumulation of gas depends, among other operational and reservoir conditions, on the solubility of that gas in the liquid phases under the temperature and pressure conditions inside the steam chamber.
New slug flow data and closure relationships for heavy oils have recently become available in the literature for both horizontal and vertical flow. This laboratory data allows the testing of current modeling technology to understand what modeling gaps must be addressed and where more data is needed. Comparisons of the data with typical one-dimensional slug flow models were performed at conditions where the liquid flow in the liquid slug is either laminar, transition or weakly turbulent flow. The closure relationships such as distribution parameter, drift velocity, and holdup in liquid slug are discussed along with the impact of these choices.
The operational production period in Toe-to-Heel Air Injection (THAI) has been investigated via numerical simulation of a field scale section of the Conklin THAI pilot in the Athabasca Oil Sands. THAI is an advanced horizontal well development of the in situ combustion process for heavy oil recovery. It operates as a 'short-distance' displacement process, and is being applied to bitumen and heavy oil reservoirs.
Breakthrough of oxygen into the production well is predicted to occur after 10.8 years of oil production. This occurs during the declining oil rate period, which follows a sustained period of constant rate production. Prior to oil rate decline, the oil recovery factor was 63 %. High combustion temperatures aid continued expansion of the steam bank, maximizing oil recovery. Economic and also safety factors determine the ultimate decision point, concerning termination of operations. On the one hand, maximum oil recovery is determined by longer operation time, but this is also influenced by safety considerations, principally, the approach to oxygen breakthrough. Terminating the process early maximises the financial rate of return, but at the expense of total oil recovery. Reduction in the oil price is probably the most significant factor affecting profitability, but this also depends on timing and degree of financial risk.
Zolotukhin, Anatoly Boris (Gubkin Russian State University of Oil & Gas) | Bokserman, Arkady (Zarubezhneft Joint Stock Company) | Kokorev, Valery (RITEK ltd.) | Nevedeev, Andrey (D-Sintez) | Ushakova, Alexandra (Zarubezhneft Joint Stock Company) | Shchekoldin, Konstantin (RITEK ltd)
Heavy oil and bitumen are found in many places worldwide, with the largest deposits in the world being in Canada (Alberta), Venezuela and the former Soviet Union.
Among huge conventional and unconventional oil resources so-called Bazhenov series represent one of the highest hydrocarbons potential in Russia. Its resources of light oil considerably exceed conventional oil resources, and extra heavy oil resources are estimated to be hundreds of billion tons (some estimates go beyond 2 trillion tons). Despite huge geological HC resources allocated in BS technology for their effective development is still a challenge.
Thermogas is one of the promising EOR technologies that are under development in Russia. First theoretical as well as experimental and pilot results indicate that this technology could be successfully deployed for the development of hydrocarbons located in Bazhenov series.
It is anticipated that the use of Thermogas technology for extraction of hydrocarbons from BS, based on successful application of similar technology for enhanced recovery of light oils from fractured dolomite formations in USA, can result in recovery of at least 35-40% of their resources. This could open up huge yet poorly estimated world unconventional oil resources that enable sustainable production of hydrocarbons at a global scale for many decades.
Technology of "cold?? mechanical oil processing is another "attraction point?? of intensive research in Russia. This new approach is based on extremely localized "injection?? of required amount of energy in order to break intermolecular and intramolecular chemical bonds in hydrocarbon compounds and molecular conglomerates. Technological effect is gained by means of initiation of the cavitation processes in the treated medium.
Heavy organic molecules (asphaltenes, long paraffin and other complexes) and their conglomerates present in crude oil and subjected to this technology undergo breakdown of chemical bonds and, as a result, drastic changes in crude oil properties like viscosity and, to a lesser extent, density.
Although technology is at its initial, i.e. "nucleus?? development phase, its applications are perceptible in many potential areas of application, from up- to mid- and to downstream petroleum sectors.
Recent developments in Thermogas EOR as well as in cold mechanical oil processing are described in this paper.
Among several oil recovery techniques, hot waterflooding through thermal displacement processes could potentially increase oil recovery by decreasing oil viscosity, thus decreasing the mobility ratio at a relatively low cost compared to other thermal methods such as SAGD or in-situ combustion. These methods can also be applied in specific in-situ conditions such as formation sensitivity to fresh water. This paper examines the performance and feasibility of hot waterflooding and compares the performance with a conventional recovery scheme of a heavy oil reservoir with an oil gravity of 10.6 °API and viscosity of 13,400 mPa·s (at 22 °C) from the Lloydminster area (Canada); the approach includes numerical thermal simulation and economical analysis of each process. First, the performance of a hot waterflood on a generic model consisting of a 5-spot injection pattern was investigated. Then four field designs were recognized from several previously analyzed patterns. The effect of well spacing, horizontal well configuration,injection parameters, as well as the impact of incremental temperature adjustment of waterflood on heavy oil recovery were studied. More than 220 models were built on the final patterns and the most economic configuration was found to have four horizontal producers and four horizontal injectors with a well spacing of 67 m. This arrangement resulted in a recovery factor of more than 30 % of the oil originally in place (OOIP). The most economic injection rate was determined to be 400 m3/day of water at optimum injection temperature of 80 °C. It was also observed that by increasing the temperature of the injected water, the oil viscosity could be reduced to less than 100 mPa·s. This improved the oil recovery and production rate, delayed injection breakthrough, and reduced water cut. From the results, the highest injection temperature of 100 °C could be recommended; however, the incremental oil versus the amount of heat and facilities required would not be justifiable from an economic point of view.
Low temperature air injection (LTAI) can be a possibility if injected air diffuses into matrix effectively to oxidize oil in it creating enhanced gravity drainage of lower viscosity oil. However, early breakthrough of air with partial consumption of oxygen due to the highly conductive nature of the reservoirs is a concern. Once it is controlled by proper injection scheme and consumption of air injected through efficient diffusion into matrix, LTAI can be an alternative technique for heavy-oil recovery from deep NFR.
Limited number of studies on light oils showed that this process was highly dependant on oxygen diffusion coefficient and matrix permeability. In this process, oil production is governed by drainage and stripping of light oil components has a greater effect on recovery than the swelling of oil.
In present study, static laboratory tests were performed by immersing heavy-oil saturated porous media in air filled reactors to determine critical parameters on recovery; diffusion coefficient and gravity drainage rate. A data acquisition system was established for continuous monitoring of pressure at different temperatures. Also analyzed was the possibility of hydrocarbon gas additive to air to enhance diffusion into matrix. A numerical model of air diffusion into a single matrix was created to obtain diffusion coefficient through matching the lab results. This, sensitivity runs were performed for different matrix properties and composition of inject gas (air and hydrocarbon).
It is imperative that enough timing is required for diffusion process before injected air filling to fracture network breakthrough. This implies to huff and puff type injection is an option as opposed to continuos injection of air. The optimal design and duration of the cycles were also tested experimentally and numerically for a single matrix case.
The analysis of fluid transport in fractured reservoirs is of great concern in petroleum and environmental engineering. The objective of this work is to study mass transfer between the matrix and the fracture network in such complex formations. In this study, the impact of adsorption on mass transfer in a fractured medium with variable fracture spacing is investigated.
Development of a mathematical model for mass transfer in dual porosity systems enhances predictions of the rate of mass transfer between matrix and fracture. In addition, it provides a tool for an appropriate design of advanced oil and gas recovery processes. Mass transfer is modeled based on the advective-dispersive transport with adsorption in an infinite acting dual porosity reservoir under radially divergent and continuous injection. The fracture spacing has been taken into account by including the variable rock matrix block size distribution in the developed model.
By employing this model, the effects of the adsorption rate on the mass transport in a subsurface environment are analyzed. The impact of the rate of adsorption on the accumulation of the injected tracer (catalyst) in a reservoir is investigated.
An understanding of the effect of adsorption on advective-dispersive mass transport with variable fracture intensity can be a key finding to develop and design advanced oil recovery processes.
A dual porosity model was introduced by Warren and Root (1963) based on the findings of Barenblatt et al. (1960). These models have been employed to define the fluid transport in fractured rocks. The dual porosity models have been used to handle the complexity of the fluid flow and transport in naturally fractured reservoirs. These models have been developed in the past to enhance the predictions of field scale mass transfer in fractured and heterogeneous formations (Aguilera, 1995; Haggerty and Gorelick, 1995; Jardine et al., 1999; Neretnieks, 1980). Based on the laboratory and field studies, analytical models were developed by many investigators (Rasmusen and Neretinieks, 1980; 1981; Sudicky and McLaren, 1992; Tang et al., 1981). In this study a model which describes the effect of adsorption on mass transfer in dual porosity media is developed. This model is then used to obtain a better understanding of the mass transfer between rock matrix blocks and fracture networks. This study can be employed for the design of ultra dispersed catalyst injection for in situ upgrading of heavy oil and subsurface mass transport in fractured reservoirs. The role of adsorption of the injected tracer or catalyst on the mass transfer in matrix and fracture is studied. Results show their importance in the mass transport processes.
A divergent radial flow system in a fractured reservoir with impermeable top and bottom boundaries is considered. Planar shape rock matrix blocks are assumed to exist in the reservoir. In this study we consider the flow of a single incompressible fluid. The physical properties of the rock and fluid are assumed to be constant. We further assume continuous injection through the total pay zone. The mass transfer in the rock matrix blocks is assumed to be diffusion dominated while in the fracture both advection and dispersion contribute to the mass transfer. The rate of adsorption in the fracture and matrix is represented by the retardation factors, which will be described in the next section. Figure 1 shows the schematic of the system used in this work.
Steam Assisted gravity drainage (SAGD) is demonstrated as a proven technology to unlock heavy oil and bitumen in Canadian reservoirs. One of the long-term concerns with the SAGD process is high energy intensity and related environmental impacts. The addition of suitable hydrocarbon solvents to steam has long been regarded as the simplest and most effective method to increase SAGD performance. Higher oil recovery, accelerated oil production rate, reduced steam to oil ratio and generally more favorable economics is expected from the addition of potential hydrocarbon additives to steam.
This paper summarizes experimental results of addition of potential solvents to steam in SAGD process. N-Hexane and nheptane were co-injected with the steam and the experimental results were compared with pure steam injection. In addition,
pure heated n-hexane was injected in one experiment to assess the performance of solvent-based processes. Experiments were conducted using a scaled two-dimensional physical model. Peace River Bitumen samples were used to conduct the experiments at 80 psia.
Experimental results were analyzed to determine the key variables involved in Solvent Assisted SAGD (SA-SAGD) processes. Solvent choice is not solely dependent on mobility improvement capability but also reservoir properties and operational conditions. Co-injection of suitable solvents with the steam led to accelerated oil production rate, higher oil recovery and lower energy to oil ratio. Solvent requirement for pure heated n-hexane injection was considerably high. The vaporized solvent chamber expansion was slow due to low heat content of the solvent and heat losses.
Solvent-based processes have demonstrated a significant potential to enhance heavy oil recovery. However, their applicability needs to be investigated for different solvents and operating conditions. In this study, a comprehensive experimental and reservoir simulation analysis was conducted on the feasibility of solvent-based, huff-n-puff method to enhance heavy oil recovery. Carbon dioxide (CO2), methane (CH4), propane (C3H8), and butane (C4H10) were tested under different operating conditions. A physical model with a1800-md permeability and 24% porosity Berea core mounted in a high-pressure core holder was designed. For all tests, the core was saturated with a Saskatchewan heavy oil with viscosity of 1423 mPa·s at 22 °C. Fourteen huff-n-puff experiments were conducted. The effect of operating pressure, soaking time, and solvent composition were investigated. According to the results, for all types of solvent the produced oil at elevated pressure was lighter (in terms of density and viscosity) and the recovery factor was higher. The highest recovery of 71% was obtained by injecting pure CO2 at near-supercritical conditions (7239 kPa at 28 °C), while pure CH4 at the highest operating pressure of 6895 kPa was 50%. Also, adding 19% hydrocarbon solvent to pure CO2 increased the recovery factor by 10% at aoperating pressure (e.g., 2317kPa). The governing mechanisms that contributed to the production were recognized to be solution gas drive, viscosity reduction, extraction of lighter components, formation of foamy oil, and to a lesser degree, the diffusion process. The oil viscosity was reduced to 62 mPa·s by injecting CO2 at 7239 kPa. The highest incremental recovery for CO2-based solvents and CH4 occurred at the 2nd and 3rd cycle, respectively. Longer soaking time improved the incremental recovery of the first cycles, though the final recovery did not noticeably change. The result of history matching with the simulated model was quite reasonable with maximum 10% discrepancy between recovery factors of these two approaches.
Among several non-thermal oil recovery methods, solvent-based processes such as vapor extraction (VAPEX) and cyclic solvent injection have demonstrated substantial potential in enhancing heavy oil recovery. The solvent can be carbon dioxide (CO2), flue gas, and light hydrocarbon gases such as, natural gas, methane (CH4), ethane (C2H6), propane (C3H8), and butane (C4H10). The solvents dissolve into the heavy oil via molecular diffusion and convective dispersion processes which reduce the oil?s viscosity. Moreover, oil swelling occurs due to solvent dissolution, which makes the residual oil more mobile and increases connected oil saturation which improves the relative permeability of oil (Grogan and Pinczewski, 1987; Farouq Ali, 2003; Yazdani and Maini, 2004; Tharanivasan et al., 2006; Yang and Gu, 2006). Recently, huff-n-puff process (cyclic solvent injection) has received a great deal of attention because it is a fairly easy process to implement and considered to be very cost effective (Liu et al., 2005). It is a single-well, enhanced oil recovery (EOR) method which was initially considered to be an alternative to cyclic steam injection for heavy oil. It is performed by injecting gas into a well (huff cycle), followed by a shut-in time to allow for solvent interaction with the formation oil, and then the well is returned to production after a soaking time (puff cycle).
There is an abundance of literature available in regards to the application of the huff-n-puff method in light oil reservoirs. However, only a few papers have been published with respect to cyclic stimulation techniques on heavy oil reservoirs (Sayegh and Maini, 1984; Palmer et al., 1986; Monger and Coma, 1988; Simpson, 1988; Brock and Bryan, 1989; Haskin and Alston, 1989; Miller, 1990; Thomas and Monger-McClure, 1991; Shayegi, 1996; Mohammed-Singh et al., 2006; Torabi and Asghari, 2010, Qazvini Firouz, 2011; Torabi et al., 2012).
With increasing world demand for energy, greater attention has been placed on the exploitation of the huge existing resources of heavy oil and bitumen. Although thermal in-situ recovery methods such as steam assisted gravity drainage (SAGD) have been very successful in exploiting such resources, the thermal efficiency of SAGD, its greenhouse gas emissions and water requirements remain major concerns.
Co-injection of solvent with steam shows promise for enhancing oil rates as well as reducing energy and water consumption with correspondingly lower environmental impacts. In hybrid steam-solvent methods, there is a balance between the solubility of the solvent and its ability to reduce bitumen viscosity. Proper selection of the solvent for the reservoir operating conditions is key for optimizing process efficiency and maximizing performance improvement over the steam-only method.
Convective mixing at the edge of the steam chamber enhances heat and mass transfer rates which increases oil mobility and production rate. In this study, the convective mixing at the steam-bitumen interface is examined using theoretical stability analysis of the thermal-solvent boundary layer. Several alkane solvents were compared based on the time required for the onset of the buoyancy-driven instabilities in the system. The results show that there is a higher degree of convective mixing for some intermediate solvents, which is in agreement with reported laboratory and simulation results. The onset of convective mixing and the wavelength of the instabilities are obtained as a function of reservoir and fluid properties for various solvents.
These results can aid in the screening and selection of appropriate solvent additives to steam for a given reservoir and bitumen properties; also this analysis can be applied for mixtures of solvents to optimize the overall efficiency of the steam-solvent recovery method.