The most important parameters in the calculation of the rate and extent of gas dissolution during solvent-based heavy oil recovery processes are diffusion coefficient and solubility. However, there is a lack of sufficient experimental data on these parameters. Further, significant differences associated with reported values of diffusivities because of various nonphysical approximations made in development of the models used for calculation of this coefficient from the pressure-decay tests.
This paper presents an inverse solution technique for determining solubility, diffusion coefficient and interface mass transfer coefficient of gases in liquids (bitumens) using pressure-decay data. The approach, which is based on modeling the rate of pressure decline in response to gas diffusion, couples gas mass balance equation with the diffusion equation. Analytical solution for the forward problem is obtained by assigning physically meaningful initial and boundary conditions. Then, the forward solution is utilized to develop an interpretation technique for simultaneous determination of the equilibrium solubility, diffusivity and interface mass transfer coefficient of gas into oil. To evaluate the validity of the proposed technique, literature pressure-decay data of CH4 and CO2 dissolution in Athabasca bitumen at two different temperatures (50 and 90 °C) and initial pressure of 8 MPa were used. The simultaneous estimation of the three mass transfer parameters is the main advantage of the new methodology over the existing ones. Additionally, the calculation method doesn't depend on empirically-defined unknowns such as Henry's constant, density of solvent-bitumen mixture and etc. Eventually, the effect of neglecting gas-bitumen interface resistance on the predicted values of gas solubility and diffusivity was investigated.
The two key challenges of primary heavy oil production using the process of Cold Heavy Oil Production with Sand (CHOPS) are limited recovery and the environmental footprint. With estimated remaining heavy oil in Western Canada of up to 300 billion barrels there is a significant opportunity for industry. Recovery of this oil using CHOPS is generally limited to 15% maximum brought on by high operating costs due to sand handling and interruption of the reservoir production process due to sand related workovers. The large CHOPS environmental footprint is driven by the significant surface disturbance due to close well spacing, greenhouse gas emissions from the use of heated lease tanks and handling and the long term disposal of produced sand.
Ongoing evaluations show that the SuperSump System has the potential to reduce the environmental footprint and increase recovery of typical CHOPS operations both in new heavy oil fields and in revitalizing existing fields. The technology uses a gravity stable process to drain oil through multiple wells from an upper viscous oil reservoir into a small fit for purpose cavern washed from underlying salt formations. Oil, water, and sand separate in the cavern and clean oil is produced from a single wellbore to surface. The environmental footprint is reduced by eliminating sand handling, reducing lease sizes, and reducing fluid storage and processing on surface. The SuperSump technology also has the potential to reduce operating costs, allowing increased recovery by prolonging the economic well life as production rates decline. In addition, early well failures due to sudden, massive sand influx may be virtually eliminated, encouraging the uninterrupted development of the sand production mechanism in the reservoir. Plugging problems and pump failures may also be eliminated as the wells mature because sand, oil and water are allowed to drain into the cavern below, where sand settles, water separates and sand-free, clean oil is produced to surface.
Simulation work has demonstrated that the SuperSump System could improve CHOPS operations in the following ways: Recovery factors are 50% higher; Operating costs are 30% lower; Energy efficiency is better by 75%; and Greenhouse Gas Emissions are lower by 95%. Estimated costs indicate very favourable economics compared to conventional CHOPS operations.
The analysis of SuperSump System currently focuses on CHOPS operations in the Western Canadian Sedimentary Basin, but could be used anywhere CHOPS is applied. It appears to be especially effective for developing new small fields where the cost of surface facilities constitute a significant portion of the field development cost. SuperSump could also be beneficial in applications where high density drilling is required but there are sensitivities to surface footprint. SuperSump could also be a cost effective precursor to EOR/IOR.
Canada's oil sands are one of the world's largest hydrocarbon resources. The initial volume of crude bitumen in place is estimated to be approximately 260 billion cubic metres with 11 percent or 28 billion cubic metres recoverable under current economic conditions. Continually improving economics, bolstered by recent higher crude oil prices, has resulted in the International recognition of the vast potential of Canada's oil sands. Based on publicly announced development plans through to 2015, over C$60 billion could be invested in numerous projects to develop the oil sands.
Various factors have to be considered to select the proper cement for zonal isolation of thermal recovery heavy-oil wells. First the cement should be flexible enough to withstand the stresses which occur when casing expands during the heating up of the well. To reduce these stresses, the cement thermal expansion coefficient should be similar to the thermal expansion coefficient of the casing. Finally, cement mechanical properties should not degrade during the whole steam injection process, i.e. when it is subjected to extremely high temperatures (up to 350 degC) for extended periods of time.
Specifically in Canada, the majority of the steam injection wells are drilled in shallow sandstone formations. This requires the cement to have high flexibility to resist the stresses. Moreover, during steam injection, a reaction between the sandstone formation and the cement sheath may occur, impacting the cement matrix and hence changing its properties.
This paper describes the application of a new thermally responsive cement for zonal isolation of heavy oil wells in Canada. This system is designed to have excellent strength, flexibility and thermal properties even upon interaction with sandstone formations. It minimizes the mechanical stresses exerted on the cement sheath during steam injection, thus reducing the risk of loss of well integrity. The numerical simulations performed with these long-term material properties (six months of exposure to 350 degC) for typical Canadian heavy oil wells conditions predict reliable and durable zonal isolation under these extreme conditions. These simulation results are confirmed by several field applications in wells which have not leaked after months of steam injection.
Non-Condensable Gasses (NCG) are gasses such as carbon dioxide, hydrogen sulphide, methane and nitrogen which can be present in a SAGD steam chamber but do not condense into the liquid phase to any large degree. Recent theoretical and laboratory work has shown that these gasses can enhance the thermal efficiency of SAGD without a significant reduction in productivity. There has been considerable discussion, both positive and negative, regarding the behavior of these gases in the steam chamber. Benefits to SAGD productivity have been suggested by some, while other authors have projected impacts on bitumen recovery.
This paper highlights how numerical simulation can be used as a tool to analyze the impact of NCG in SAGD through modification of K-value based on thermodynamic theory. As the simulated bitumen production rates were much less than those found in the field. It is necessary to adjust physical properties so as to make the gas more soluble, e.g. by artificially modifying the K values. The author has developed a method of modeling the effects of NCG in a steam zone using the new modified K value table. This paper will present the results of these simulations with and without modification of K-value and predict impact of NCG on SAGD performance.
Steam-assisted gravity drainage (SAGD) has become a method of choice for in-situ production of bitumen for oil sands projects in Alberta, Canada. Fluid production using SAGD results in the formation of a high water cut complex emulsion requiring the use of both reverse emulsion breakers and emulsion breakers in order to produce saleable oil to the pipeline and clean water for reuse or steam generation. As a facility grows and adds more well pairs to the system, maintaining the water quality from the separation vessels becomes increasingly important to growing the daily bitumen production. The enclosed paper will detail the development of a new solution polymer designed to treat the produced complex emulsion. Through an improved synergy with the demulsifier, the newly developed reverse emulsion breaker reduced the required levels of demulsifier to treat the fluids while maintaining or improving the system water qualities observed.
Hydrogen sulfide (H2S) generated by aquathermolysis—a high-temperature reaction of condensed steam (water) with sulfur-bearing bitumen in the reservoir rock—may increase the risk of sulfide stress cracking (SSC) in cyclically steam stimulated (CSS) wells. In a given field, H2S levels and wellbore conditions vary significantly among wells and so do their SSC-susceptibility. Identifying the SSC-susceptible wells is important in terms of reducing SSC risk by allocating resources and implementing pro-active intervention measures to the SSC-susceptible wells. A comprehensive research program, with a dedicated instrumented CSS well as the centerpiece, has been undertaken by Imperial Oil Resources with the objectives of characterizing H2S evolution in the wellbore and developing a tool for identifying the SSC-susceptible wells. The research includes laboratory and field tests, and statistical, phase behaviour and kinetic modelling. The SSC-susceptible zone for Cold Lake CSS has been established from Cyclic Slow Strain Rate (CSSR) laboratory tests incorporating CSS fluid chemistry, stress-strain environments, casing metallurgy, and variable temperature and H2S partial pressure. A statistical logistic model matches the experimental CSSR data well. The instrumented well data validate the phase behavior model, which in turn explains the measured H2S profile in the wellbore. An aquathermolysis kinetic model has been developed for the instrumented well and validated with data from nine other CSS wells. The research has led to the development of an engineering tool for identifying the wells at the risk of falling into the SSC-susceptible zone.
As oil reserves decrease, the level of difficulty to extract oil increases. With this increased difficulty, the service conditions involved in Steam Assisted Gravity Drainage (SAGD) are increasingly more aggressive. In an effort to maintain low raw material prices without sacrificing performance, duplex and superduplex stainless steels have been used for many applications to resist corrosion from chlorides, withstand extremely high pressure and still stay cost competitive. This summary of case histories shows where duplex stainless steels have been successfully utilized in the Alberta Oil Sands as well as across the globe. Duplex stainless steels have replaced leaner austenitic stainless steels and low alloy steels because of their increased corrosion resistance. In other cases, duplex and superduplex stainless steels have replaced higher nickel-chromium-molybdenum grades because of their lower cost and similar performance. For example, super duplex stainless steel has already been used as an alternate to six percent molybdenum grades in brine concentrators throughout Alberta, Canada.
The majority of bitumen and extra heavy oil is produced by steam-based recovery processes yet these methods are energy intensive and emit large amounts of greenhouse gas to the atmosphere. Not only is the emissions intensity high due to steam generation, but also the water handling and treating facilities required for these recovery methods is expensive both to purchase and install but also to operate. A lot of focus of research has been on reduced steam processes, such as thermal-solvent techniques, as well as in situ combustion technologies such as Air Injection. Here, air injection is evaluated as a follow-up process to Cyclic Steam Stimulation in a deep thick heavy oil reservoir. The reservoir simulation model is obtained from a history-match to existing cyclic steam stimulation (CSS) field data. The results demonstrate that an additional 33% oil recovery is reached by using an air injection follow-up process. This gives a total recovery factor equal to about 55%. Based on incremental cumulative energy-to-oil ratio, the results suggest that air injection follow-up processes should be considered for post-CSS operations but that further improvement of the energy intensity is needed.
The Lloydminster Saskatchewan area Pikes Peak steam project has been on production since 1982. A key part of the development strategy was use of an undeveloped pressure isolation wall to allow the two halves of the pool to be developed using different time schedules and exploitation processes.
Use of the pressure isolation wall allowed different exploitation options to be used, but during late project life the oil left in the wall needed to be recovered to enhance project economics. A significant challenge to recovery of the oil in the wall was the lack of pressure containment or oil saturation on both flanks, resulting in the need for a very gentle recovery process to avoid pushing the oil outside the wall.
On the basis of numerical simulation results the recovery process selected for the wall was use of two CSS horizontal wells operated in a gentle manner. After the horizontal wells were drilled, however, temperature logs showed the reservoir surrounding one of the horizontal wells had already been heated by offsetting steam injection, and that well has been continually produced at good rates without the need for steam stimulation. The second new horizontal wall well has been successfully operated using the CSS process designed using numerical simulation.
The results of this field study show that the oil in a wall used to pressure isolate sections of a steam project pool can be economically recovered without pushing the oil into the adjacent depleted areas by use of processes designed to account for local wall conditions.
Steam projects are typically developed in phases due to economic constraints, and this strategy was employed at Husky's Pikes Peak project where simultaneous development was started at the east and west boundaries, and grew toward the middle of the bottom water free area of the pool1-4.
As the east and west development lobes grew toward each other, a decision was made to leave an undeveloped wall from north to south across the bottom water free area about twice as wide as the nominal 100 meter well spacing to allow pressure isolation between those two areas (Figure 1, 2). This allowed the area on each side of the pressure isolation wall to be developed and operated in an individual manner.
Both sides of the isolation wall had been developed and greatly depleted by 2002 when initiation of SAGD development south of the bottom water free area on the west side of the wall resulted in apparent steam migration away from the SAGD area to the lower pressure region on the west side of the wall, indicating a need to re-pressure that area. Steam migration has also been observed in other SAGD projects5. To address the steam leakoff casing gas collection and injection was initiated using a shut-in centrally located former drive pattern producer, and between 2002 and 2005 the pressure on the west side of the wall was increased approximately 400 kPa to over 900 kPa.
Jia, Hu (Southwest Petroleum University) | Yuan, Cheng-dong (Southwest Petroleum University) | Zhang, Yuchuan (Southwest Petroleum University) | Peng, Huan (Southwest Petroleum University) | Zhong, Dong (Southwest Petroleum University) | Zhao, Jinzhou (Southwest Petroleum University)
High-Pressure Air Injection (HPAI) in light oil reservoirs has been proven to be a valuable IOR (Improved Oil Recovery) process and caused more attention worldwide. In this paper, we give an overview of the recent progress of HPAI technique, based on a review of some representative HPAI projects including completed and ongoing projects. Some most important aspects for HPAI field application are discussed in depth, including reservoir screening criterion, recognition of recovery mechanism, laboratory study, numerical simulation, gas breakthrough control, tubing corrosion consideration and safety monitoring. With the successful HPAI application in Zhong Yuan Oil Field in China, it is estimated that foam or polymer gel assisted air injection should continue to grow in the next decade as a derived technology of HPAI for application in high-temperature high-heterogeneity reservoirs. The purpose of this paper is to investigate the ranges of some key parameters, new understanding based on laboratory test and successful field application, thus to provide lessons learnt and best practices for the guideline to achieve high-performance HPAI project.