Jet pumping has been considered as an efficient artificial lifting technique for deep oil production due to its simplicity and lack of moving parts. If light oil is used as power fluid, jet pumping becomes one of the preferred artificial lift methods for the deep-heavy-oil reservoirs by dramatically reducing both viscosity of the reservoir fluid and the pressure loss along the production string. In practice, the amount of light oil required as the power fluid can be as high as three times of the reservoir fluid, among which only a small portion of the light oil is actually needed for viscosity reduction. In this paper, a novel technique has been developed and successfully applied to significantly reduce the amount of light oil usage in a deep-heavyoil reservoir. More specifically, two approaches are developed and compared. As for Approach A, the oil well is produced with jet pumping driven by light oil first, and then the produced fluid is reinjected into the well as the power fluid. This process keeps circulating until viscosity of the produced fluid is too high to be utilized for jet pumping. As for Approach B, partial produced fluid is combined with the light oil at any reasonable ratios, and subsequently the produced fluid-light oil mixture is reinjected into the well as the power fluid. In the latter approach, viscosity of the mixture keeps increasing and will reach its equilibrium value in a few days, and thus, stable production will be achieved as well. Theoretic models are developed to determine the viscosity of the power fluid for each circulation and the maximum cycle number for the former approach as well as the equilibrium viscosity of the mixed power fluid and the optimum ratio of light oil to the produced fluid-light oil mixture for the latter approach. Field applications show that the reservoir fluid produced from deep heavy oil wells is increased by three times and that the amount of light oil can be reduced by more than 60% for either approach.
Deep-heavy-oil reservoirs, usually referred to those with depth of more than 3000 m (Christ and Petrie 1989), are different from the conventional heavy oil reservoirs. In general, reservoir fluid can flow more easily in the formation as well as around the bottomhole in a deep heavy oil well at a higher temperature. However, during its path along the production string, viscosity of the reservoir fluid increases dramatically due to heat loss and release of the dissolved gas, which results in great pressure drop along the wellbore. Thus, artificial lifting methods need to be adopted to pump the reservoir fluids to the surface.
Among the artificial lifting techniques, jet pumping has been proven to be an efficient method in producing oil from deep heavy oil reservoirs (Cunningham 1957; Petrie et al. 1983a; Petrie et al. 1983b; Petrie et al. 1984; Tjondrodiputro et al. 1986; Tjondodiputro et al. 1987). Jet pump is a venturi-type device where a high-pressure power fluid is used to accelerate to reach a higher velocity and thereby create a lower pressure area into which reservoir fluids will flow (Mueller 1964). Because of its small size, simplicity, lack of moving parts, a jet pump can be installed in the wellbore at a deep location. It also has a strong ability to pump fluids with high viscosity and/or serious corrosivity (Petrie et al. 1983c). For heavy oil production, light oil can be used as the power fluid because it reduces viscosity of the reservoir fluid and the pressure drop in the production string as well (Qu et al. 2000). The reduction of the pressure drop is mainly ascribed to instantaneous and thorough blending of the light oil and the reservoir fluid in the jet pump throat (De Ghetto et al. 1994).
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.
The production of extra heavy oil or bitumen through Thermal methods (e.g. SAGD - Steam Assisted Gravity Drainage) requires the generation and injection into the reservoir of significant quantities of steam which is finally recirculed with the produced bitumen. Considering the need to minimize fresh water consumption and the possibility of increasingly stringent environmental regulations, it is likely that maximization of the recycling of the produced water into steam will be mandatory.
The SAGD water treatment scheme is complex because it depends on the water characteristics, the steam generator type selected (OTSG or conventional boiler) and the decision to completely eliminate waste water disposal (zero liquid reject) or use other waste handling and disposal methods. SAGD water treatment also faces some additional specific challenges compared with oil fields worldwide, such as the high silica content in the produced water.
An overview of the current water treatment process options for SAGD will be presented, followed by a new patented process called SIBE (ie Silica Inhibition and Blowdown Evaporation). The principle of this new process is based on TOTAL's research in the area of silica inhibition and an optimized application of conventional water treatment equipment with Zero Liquid Discharge process (e.g. evaporators and Crystalliazer). An estimate of the economic benefit of the new SIBE process relative to conventional process schemes will be presented.
The use of optical fibers in the oil and gas industry is becoming more viable for several permanent monitoring applications, such as distributed temperature sensing (DTS) and optical pressure transducers. However, long-term performance of fibers, especially at elevated temperatures, is still an issue yet to be fully resolved. This problem is critically important in steam-assisted gravity drainage (SAGD) applications, where wells operate in extreme conditions of high temperatures, often exceeding 250oC, as well as in high pressures within a hydrogen-rich environment.
Optical fiber performance is seriously affected by many factors, including:
• Hydrogen ingression
• Thermal resistance of the materials
• Mechanical resistance of the fiber
Exposure of optical fibers to hydrogen changes the performance of the fibers through what is referred to in the industry as "hydrogen aging?? or "hydrogen darkening.?? Hydrogen darkening is increased absorption or light loss due to various chemical species in the glass fiber resulting from the presence of hydrogen.
Value of DTS in SAGD Applications
It is known that temperature monitoring in SAGD wells is of significant importance because it provides a good understanding of the temperature distribution along the horizontal section. Conventionally, thermocouples have been used to measure and monitor the temperature along the horizontal section, and are typically installed at heel, middle and toe of the section. Since thermocouples (TC) inherently provide temperature data at these discrete points, temperature information between the TCs is
usually interpolated to understand the temperature distribution. As a result of this interpolation, there could be sections of the wellbore that would require more data from different sources for a detailed analysis instead of just being able to visualize the temperature behavior. Hence, there is a need for a tool that can provide temperature data along the entire length of the horizontal section. In addition, the installation must be simple in order to keep it safe and cost-effective. The optical fiberbased DTS technology has been applied in the past successfully and it is known that the optical fiber-based DTS technique provides temperature data along the entire length of the fiber. This temperature data provides information;, e.g., what sections of the lateral are operating at "sub cool,?? and enabling users to:
• Quickly identify anomalies
• Immediately implement corrective action
• Allow for better steam utilization
The majority of the world's petroleum resources are contained in heavy oil and oil sand reservoirs. Average recoveries from heavy oil and oil sand reservoirs are typically low ranging from 5 to 15 percent for cold heavy oil production and from 30 to 85 percent for steam-based in situ processes. There are two reasons for this: first, geological heterogeneity in the form of variable porosity and permeability properties and secondly, fluid heterogeneities in the form of variable saturations, fluid compositions and thus viscosity. Geological heterogeneities refer to spatial variations of porosity, permeability, relativepermeability curves, shale and mud layers, etc. Fluid heterogeneities refer to spatial variations of the fluid composition and properties such as viscosity and density. Given that the permeability often varies by less than an order of magnitude whereas the oil viscosity varies by up to two orders of magnitude in a bitumen reservoir, the controlling variable on recovery of these resources is often fluid compositional variations. Due to the large viscosity contrast between oil and water at native reservoir conditions water is often the most mobile phase within a bitumen reservoir. This research identifies preconditioning techniques that can be used to alter reservoir or fluid (oil or water) properties prior to thermal recovery reducing adverse reservoir factors and improving recovery, environmental impact and process economics. We describe here a simulation study of one application related to modifying the variation of oil viscosity in the reservoir prior to steam injection. The methods make use of mobile water within the reservoir, to distribute viscosity-reducing agents before steam injection, and represent another means of geotailoring recovery processes to the features of the reservoir. The main benefit is that recovery process performance, both in terms of oil production rate and thermal efficiency, is improved.
ConocoPhillips has been on a quest to find a high volume artificial lift system that will operate reliably in a 250°C (482oF) downhole environment, which exists in certain SAGD applications. This presented two problems: 1) there were no commercially available technologies for such a high temperature; and 2) there were no facilities capable of testing these systems.
This paper describes the complexity of building and operating a high temperature flow loop rated for 250°C, and the lessons learned while upgrading an existing flow loop, from the initial design through the final commissioning phases. The paper also describes the issues encountered with the first artificial lift system tested at 250°C, which was a metallic stator progressing cavity pump system, rated for 1100 m3/d (6919 bpd) at 500 rpm.
In the end, the test program not only served to validate and define the pump's performance, but also provided valuable lessons on the completion configuration and operational procedures.
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.
Zhong, Liguo (Daqing Petroleum Institute) | Yu, Di (Daqing Petroleum Institute) | Gong, Yuning (Expl & Dev Rsch Inst Liaohe Co.) | Wang, Ping (Huabei Oilfield) | Zhang, Lishu (Huabei Oilfield) | Liu, Changbao (Jilin Oilfield Co)
All heavy oil reservoirs in TaoBao oil field are shallowly buried, thin, and multilayered in which natural production and cold production technologies have been implemented in past seven years, and obvious increase in oil production was achieved by cold production(up to 9 times than natural production method). However, due to the low reservoir pressure, heterogeneity, and limited formation thickness, the oil production has rapidly decreased, and more than half of the wells have been shut off now.At present, more than 94% oil remained in place is difficult to exploit, and different recovery methods are being investtigated, as a result, only in-situ combustion is more potential and seems feasible to enhance oil recovery for such reservoir.
To investigate the feasibility of in-situ combustion, reactor experiment and combustion tube experiment have been carried out at first, the result shows that the optimal fire temperature is above 400?, and the ultimate oil recovery is more than 80%. Additionally, air injection rate, combustion front velocity and other parameters have been measured or calculated. At the same time, primary reservoir numerical simulation for selected block in Bai92 reservoir are implemented considering that more importance should be attached to the feasibility of in-situ combustion in reservoir scale. Some important factors such as air injection rate are investigated. Moreover, the progress in pilot test of in-situ combustion in B92 reservoir is introduced briefly.
The results of primary experiments, reservoir numerical simulation and pilot test show that in-situ combustion is feasible to enhance oil recovery of such shallow, thin and multilayered heavy oil reservoir as B92.
Canadian oil sands in the province of Alberta are a hydrocarbon source for North America. By the year 2015, the oil sands will be producing in excess of 3 million barrels/day of crude oil. A number of companies operate Upgraders that convert the bitumen that is extracted from the oil sands into light sweet crude oil. Steam is required to heat utilities at the Upgrader facility.
In one major oil sands extraction site, well water is being used as feed water for the boilers producing this steam. Reverse Osmosis (RO) systems were designed and installed to produce high quality water required for this application. The pretreatment system was designed with conventional multimedia technology. The RO system required feed water with silt density index (SDI) of 3 or less. Due to ineffectiveness of the conventional pretreatment system, the SDI of the RO feed water was in the range of 12-20. This resulted in severe fouling of the RO membranes and production losses.
In order to optimize the performance of the RO membrane system, a pressurized microfiltration membrane system was delivered and commissioned within 5 days to replace the existing pre-treatment system. The new unit contained an automated PVDF hollow fiber microfiltration membrane system mounted in a trailer. SDI values in the range of 1.0-2.5 were immediately observed in the feed water to the RO system. The end user has enjoyed significant cost savings and ease of operation as a result of this innovative technology. This paper describes the details of the installation and the superior performance data gathered at the end user site.
A. Oil Sands Deposits.
The Oil and Gas Journal has reported nearly 175 billion barrels of reserves from oil sands in Alberta, Canada in 2005, (1) making it one of the largest oil reserves in the world. They are located in three distinct areas in northern Alberta—the largest deposits are along the Athabasca River and there are smaller deposits in Cold Lake and Peace River. Current production of approximately 1 million bbl/day of crude oil from bitumen is predicted to increase to over 3 millon bbl/day by Y2015. With oil prices now in excess of $80/bbl, there are nearly 100 oil sands projects totaling about $100 billion in capital investment. Tax incentives are no longer necessary to encourage oil sands investments.
B. Extraction Methods.
Currently, two-thirds of the bitumen output is produced by strip mining (2) and a quarter by in-situ methods such as Steam Assisted Gravity Drainage (SAGD). But since 80% of the recoverable bitumen is buried too deep for strip mining, the in-situ methods are expected to dominate the scene in the coming years. In the SAGD process, two horizontal wells are drilled into the oil sands, one near the bottom of the formation and another one, typically 5 meters above it. These wells can extend up to a kilometer in all directions. Steam is injected into the upper well. The heat decreases the viscosity of the bitumen, which allows it to flow into the lower well, from where it is produced.
Numerical simulation of thermal recovery processes like steam injection often involves localized phenomena such as saturation and temperature fronts due to hyperbolic features of governing conservation laws, Treating more efficiently convective terms could help to diminish spurious oscillation and/or numerical dispersion and better tracking of discontinuity shocks . But in regions near the shock numerical dispersion can only be removed by the use of very fine uniform grids with many grid blocks. To avoid expensive solution of such a finely girded domain, we develop a moving mesh approach combined with higher order up-winding schemes.
Numerical solver here have been employed is Finite volume method. A MMPDE(moving mesh PDE) is solved associated with physical PDE's of steam injection process in order to relocates the mesh nodes to concentrate them in regions of sharp discontinuity and Equi-distribute a measure of error-estimate (monitor function) over the meshes. Solution will advance more rapidly on course meshes and fluxes at the coarse-fine grid interfaces are refined to guarantee mass conservation. . Since the region surrounding the sharp discontinuity and requiring high resolution consists of only a small fraction of the entire domain, prescribed locally time stepping results in a great saving in computational time. Specific features of moving mesh methods like monitor-function smoothing, control of mesh widths and readjustment of solutions further to mesh movement are addressed. Numerical experiments are carried out to demonstrate the efficiency and robustness of the proposed method in 1-D and 2-D.However numerical results for moving coordinates are compared with those obtained from simulation on non-adapted mesh framework. Preferences of higher-order solvers over lower-order ones in terms of shock capturing is being investigated. .Although we have limited our modeling to steam flooding process, but simulation demonstrates main features of our approach, applicable to other EOR processes such as VAPEX, SAGD, and In Situ Combustion Process.