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Collaborating Authors
SPE Heavy Oil Conference Canada
Abstract Two closed circuit flow loops have been constructed for X-ray CT imaging of multiphase flows. A 3 generation helical scanner provides 3D images with a voxel size as small as 0.35×0.35×0.30mm. By "folding" the loops, flows have been imaged over a 16m section of 3.8 cm (1-1/2") pipe. In future, larger bores could be accommodated with a shorter overall length, dictated by the aperture and weight limit of the scanner. Sand slurry flows have been imaged in both laminar and turbulent regimes (using silicone oil and water, respectively) over a range of velocities reflective of typical in situ pressure gradients. Flowing sand concentrations up to 20% by volume were achieved by adjusting the total sand content in the loop. With proper calibration the CT images provide detailed, quantitative measures of sand concentration and, indirectly, the partitioning between moving and settled regions of the flow. The flowing density profiles vary significantly with the sand content and flow velocity, indicative of changing sand transport mechanisms. Fluctuations over the observable length of the loop show evidence of settling overlaid on the flow-induced resuspension. The effects of the end loops on both aspects of sand transport are considered.
Abstract For the last two decades major oil companies in Canada have been paying much more attention to heavy oil, which is an alternative unconventional reservoir (Canada and Venezuela have some of the largest bitumen deposits in the world). The main reasons for development could be the continued high price of oil, and improved technology to extract heavy oil, with a high recovery factor (up to 60% of the oil in place). Injecting steam is the most distinctive technique of heating up the formation rock and assisting in oil flow. Controlling steam injection and its distribution, and achieving economical recovery in an effective manner, has been a continuous mind-boggling issue for the heavy oil producers, and has been a great challenge. High-temperature water and oil swellable packers have been developed to aid, and optimize, cyclic steam stimulation and Steam Assisted Gravity Drainage (SAGD) applications in heavy oil reservoirs. Simplicity is one of the great advantages of the swellable packers, which provide an ease of operation. The packer allows for uniform, or selective, placement of steam along the entire length of horizontal section, and is designed to handle high temperature 575°F (302°C), and more than adequate differential pressures associated with steam injection. Screens or slotted liners are run in hole to allow steam to be pumped in between the well pairs. Steam breakthrough, or diversion, has been experienced in numerous wells due to lost circulation, or sand erosion and/or plugging of the slotted liners, which creates problems for continuous production. Swellable packers can be installed in conjunction with inflatable packers, screens, slotted liner, or scab liners, in order to distribute steam and provide zonal isolation. In the event of steam breakthrough, swellable packers can be deployed to isolate the affected zone(s). This intervention technique will assist in efficient continued production and the elimination of steam breakthrough. The technique of steam injection has been improving over the years, but still has room for refining of the processes. Some older wells have encountered issues of steam channeling through the cemented casing & breaking out at the surface; which has been seen to create a threat to the environment. A horizontal well completed with slotted liner, or recently with specially designed type of screens, provides a far better method than perforated casing for injecting steam into the formation. This paper presents a solution with a unique technique, for SAGD wells, for resolving wasted steam injection at the toe section of the well, and repair of steam breakthrough in production legs. Every operator is coming across new learning experiences almost every day, although most of this information is proprietary, we are proposing a different solution path to overcome some of these issues.
- North America > United States (1.00)
- North America > Canada (0.69)
- South America > Venezuela (0.93)
- North America > Canada (0.93)
Abstract 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.
- North America > Canada (1.00)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
Abstract There are numerous flow assurance and processing challenges associated with the production of heavy oil. These challenges are generally addressed in the early stage of the development and include; sizing of separators, internal design of the vessels, the process vessel configuration and the optimum means of handling solids and water. A critical aspect of the design is the accuracy and the reliability of the fluid characterization data. Numerous operators can attest to the difficulties in processing heavy oil and many make attempts to minimize the impact of these issues in the design stage. However, there are critical factors associated with produced fluid characterization data that are regularly either overlooked or misinterpreted. It is the importance of this data reliability and accurate interpretation that is the subject of this paper. The high viscosity and low gravity of heavy oil is usually the principle concern of the design team in addressing process components and operational practices. However, there are numerous horror stories associated with flow assurance issues that should have been taken into consideration during detailed design. The impact of asphaltenes, paraffin, naphthenates, inorganic scale deposition and emulsion stability are a few of the more common challenges that can, and should, be addressed prior to detailed design. The impact of these constituents on processing and operations can make or break the economics of the development, particularly when taking into account the long-term OPEX associated with chemical treatment cost if these constituents are not adequately addressed. In addition, brown field development of heavy oil and the subsequent processing through an existing infrastructure will create other challenges, especially if the existing production infrastructure is designed to handle mid and high API gravity crude. By following some fairly rigorous, but necessary, guidelines on data accumulation and interpretation most if not all of these problems can adequately be addressed during detailed design and the development of operating procedures. Therefore a holistic approach in assessing the design of these facilities will be crucial to maintaining a low CAPEX and OPEX for processing heavy oil effectively. This paper aims to outline the different aspects associated with these challenges and will cover design, operation, monitoring and, where relevant, upgrades and retrofit issues.
- Europe > United Kingdom > North Sea (0.34)
- North America > Canada (0.28)
Abstract High molecular weight polyacrylamides are key components in oil recovery, particularly in the stimulation, production, and enhanced oil recovery of oil and gas wells. These polymers can be divided into three broad classes based on their physical state: dry polyacrylamides (DPAMs), emulsion polyacrylamides (EPAMs) and solution polyacrylamides (SPAMs). While the molecular weights of these polymers can range from 1 million to more than 30 million Daltons, molecular weight is limited by physical state. In general, EPAMs can reach higher molecular weights and consequently exhibit better performance than DPAMs and SPAMs. However, standard EPAMs exhibit poor freeze tolerance and irreversible inversions, while DPAMs suffer from extremely slow dissolution rates and require additional capital expenses such as makedown and storage equipment. Next-generation winterized EPAMs have been developed that are capable of withstanding temperatures down to −35 °C without freezing. These polymers invert rapidly, reaching complete dissolution within 60 seconds in fresh water, hard water, and other concentrated brines, allowing for higher throughput and overall energy savings. The new EPAMs were compared to commercially available EPAMs used in friction reduction and EOR applications. The emulsion stability was assessed by freeze-thaw and rheological measurements, while stimulation and EOR performance were characterized using a friction loop and core flooding apparatuses. These next-gen EPAMs demonstrate values for viscosities, shear resistance, inversion times, freeze tolerance, and filterability that make them superior to commercially available dry and emulsion polyacrylamides. Furthermore, these polymers are formulated to be environmentally friendly and readily biodegradable. A family of emulsion polymers has been developed that exhibits low-temperature tolerance, increased dissolution rates and biodegradability without sacrificing EOR and stimulation performance in various brines. The modular nature of these products has led to the creation of a flexible polymer platform that allows for customizing products for specific application needs.
- North America > Canada (0.47)
- North America > United States (0.47)
Abstract Ionizing electron particles were used as an efficient means of delivering energy to heavy hydrocarbon molecules. Although heavy oil reserves are known as rich sources of energy, their contribution to the energy market has been impacted by the fact that the conventional thermal or catalytic upgrading and visbreaking methods always demand a considerable energy and money investment. Therefore, application of potential alternatives with lower operating costs and higher process throughput appears to be extremely crucial in such a competitive market. In this research, high-energy electron processing technology was offered as a remedy to reduce the viscosity of heavy petroleum samples. Irradiated fluids exhibited lower viscosities than thermally cracked samples. Moreover, reaction temperature was observed to have a substantial influence on radiolysis process. At relatively low temperatures, radiation-induced upgrading stays inactive without any contribution to the viscosity reduction process. However, as the temperature exceeds a specific threshold, radiation-induced chain reactions become activated, decreasing the viscosity of irradiated samples. At the end, we have investigated the effect of different additives upon radiolysis of hydrocarbon molecules. Interestingly, radiolytic reactions were completely suppressed by some of these additives.
- North America > Canada (0.29)
- North America > Mexico (0.28)
- North America > United States (0.28)
- Management (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (0.50)
- Facilities Design, Construction and Operation > Processing Systems and Design > Heavy oil upgrading (0.47)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (0.46)
Full Field Applicability of MWAGD Process Coupled With Horizontal Well Pair Model to Recover Extra Heavy Oil and Bitumen
Bansal, Gopal (School of Petroleum Technology, Pandit Deendayal Petroleum University) | Jha, Ashutosh Kumar (School of Petroleum Technology, Pandit Deendayal Petroleum University) | Chauhan, Nitesh (School of Petroleum Technology, Pandit Deendayal Petroleum University) | Sharma, Tushar (Indian Institute of Technology, Madras)
Abstract Applicability, assessment and work-how of Micro-Wave Assisted Gravity Drainage (MWAGD) process in Mehsana (India) heavy oil field along with added advantages over SAGD were presented in the previous part of this paper [1]. Various studies have been done during last 10 years illustrating wider applications of micro-wave heating of heavy oil reservoirs through quantitative and qualitative exercises. But the main problem that arises in micro-wave heating is very low penetration depth of micro-wave radiations which limits the application of this unconventional thermal EOR method on full field scale. The scope of this paper is to eliminate this problem by using horizontal well pair combination which enhances the drainage area within the heating radius of micro-wave radiations.The phenomenon of conversion of Micro-wave energy to heat energy is described and finally, a mathematical model based on energy balance principle is developed. Two parallel and vertically aligned horizontal wells are drilled. The upper well is production well and lower well is micro-wave source well with their length and vertical separation on the order of 500 meters and 15 meters respectively. In the lower well micro-wave sources are installed at various positions along the length with longitudinal spacing on the order of 20 meters. Advantages of heating of oil from the lower well are explained in lucid manner. This type of installation model confirms the coverage of larger reservoir volume in spite of short penetration depth of micro-wave radiations. Along with volumetric and selective heating in this process heat is developed within the formation fluid rather than being brought to it from the outside, and hence the fluid is heated more uniformly throughout the medium. Also, above proposed model can be applied effectively in case of carbonate formations where uneven sweeping occurs along steam assisted gravity drainage (SAGD) well pairs due to vuggs and fractures.
- North America > United States (0.95)
- North America > Canada > Alberta (0.15)
Abstract Russkoye field, discovered in 1968, is a giant high-viscous oil field located above the Polar Circle in Russia. The commercial development of the field has been a tremendous challenge due to several factors such as a very complex heterogeneous shallow reservoir with a large gas cap, an active bottom aquifer, unconsolidated sands, low temperature, and permafrost zone. At this stage, the development of the field is still on the pilot testing stage in order to understand and evaluate different possible development strategies that assure the maximum recoverable reserves for this kind of field. As part of the development strategy, eight water injection pattern schemes including horizontal and vertical wells, and different well spacings were simulated to find the optimal waterflooding patterns, and to evaluate different well trajectories, and different injection bottomhole pressures, for the next pilot area. The water injection pattern schemes evaluated were horizontal wells line drive, 7-spot, 7-spot inverted, 9-spot, 9-spot inverted, 5 spot, combined line drive with horizontal producers and two deviated injectors, and combined line drive with horizontal producers and three deviated injectors. The complete analysis was carried out on the basis of the technical results and the economical evaluation. Several parameters were studied to compare performance and efficiency of different water injection patterns, such as voidage replacement ratio, cumulative oil, water and gas, production profiles, sweep efficiency, injected pore volume, and reservoir pressure behavior. The optimization of the four well spacings between 100 m and 400 m and the injection bottomhole pressure range was performed using an analytical approximation. The economical evaluation for each water injection pattern analyzed was executed by means of the economical standard analysis: net present value, internal rate of return, profitability index, lifting cost, and payback period.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract The pore-level recovery mechanisms of the SA-SAGD process have been recently studied in the Porous Media Lab at the University of Waterloo using glass-etched micromodels. The experiments were conducted at controlled environmental conditions of an inverted-bell vacuum chamber to reduce the excessive heat loss to the surroundings. Different chemical additives (n-pentane and n-hexane) were added to steam prior to injecting into the models. Local temperatures along the model’s height and width were measured and collected on a real time basis using a data acquisition system. An integrated data acquisition and control system was used to control, monitor and adjust the environmental vacuum pressure. The pore-scale events were videotaped and the captured snapshots were analyzed thoroughly using image processing techniques. The relevant pore-scale mechanisms responsible for the in-situ oil mobilization and drainage in a SA-SAGD process were addressed; transport and capillary phenomena at the poreevel were qualitatively documented including fluid flow, and heat and mass transfer aspects of the process. The pore-scale visualizations revealed that the gravity drainage process takes place within a thin layer of pores, composed of 1–5 pores in thickness, in the direction of gravity parallel to the apparent oil-vapour mixture interface in a so-called SA-SAGD mobilized region. The interplay between gravity and capillary forces results in the drainage of the mobile oil, whose viscosity is significantly reduced as a result of combined heat and mass transfer at the micro-scale. Heat transfer is believed to take place by conductive and convective mechanisms at the pore-level. The solvent content of the injected vapour mixture diffuses into the oil phase, hence reduces its viscosity following dilution as a result of molecular diffusion as well as convective mass transfer. The visualization results demonstrated the formation of water-in-oil emulsions at the interface because of the condensation of steam. The extent of emulsification depends on the temperature gradient between the gaseous mixture and the mobile oil phase. Water in oil emulsion is formed due to the non-spreading nature of water over the mobile oil phase in the presence of a gas phase. Asphaltene precipitation was observed when the condensed solvent reached the bitumen interface. Other pore-scale phenomena include localized entrapment of steam and solvent vapour within the continuum of the mobile oil at the interface due to capillary instabilities followed by subsequent condensation, relatively sharp temperature gradient along the SA-SAGD mobilized region, and snap-off of liquid films. In the absence of direct measurement of production data, the average horizontal advancement velocity of the apparent SA-SAGD interface was measured and was correlated with system parameters such as operating temperature, macroscopic and pore-scale properties of porous media, and heavy oil properties within the range of experimental conditions. This average sweep rate of the SA-SAGD process, along with the ultimate recovery factor values at the end of each particular test were considered as representatives of the SA-SAGD process performance at the pore-scale. Normal hexane was found to be a more effective steam additive compared to n-pentane at similar operating conditions. Increasing the solvent content in the injecting vapour mixture accelerates the recovery process at the pore-scale, and results in greater ultimate recovery factor values. When all other experimental variables are remain unchanged, the smaller the in-situ oil viscosity is, the greater would be the horizontal sweep rate and the ultimate recovery factor value. The pore-level interface advancement velocity was found to be a function of the pore-scale characteristics of the porous media. Different pore-scale properties such as pore-to-pore distance, pore body width, pore throat width, and diffusion distance affect the measured horizontal sweep rate of the SA-SAGD process. Macroscopic porous media properties such as permeability and porosity are influential parameters affecting the pore-scale SA-SAGD interface advancement velocity.
- North America > Canada (0.93)
- Asia (0.92)
- North America > United States > California (0.67)
- Research Report > Experimental Study (0.93)
- Research Report > New Finding (0.93)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Venezuela > Anzoátegui > Eastern Venezuela Basin > Maturin Basin > Hamaca Area > Hamaca Area Field (0.94)
- Asia > Indonesia > Sumatra > South Sumatra > South Sumatra Basin > Rokan Block > Rokan Block > Duri Field (0.94)
Abstract Phase behaviour of C3H8-n-C4H10-heavy oil systems at high pressures and elevated temperatures has been experimentally and theoretically investigated. Experimentally, a versatile pressure-volume-temperature (PVT) system is utilized to determine the liquid-vapour phase boundary (i.e., saturation pressure lines) and swelling factors of C3H8-n-C/H10-heavy oil systems with varying compositions at high pressures up to 5030 kPa and elevated temperatures up to 396.15 K. The viscosities of the corresponding solvent(s)-saturated heavy oil systems are measured by using a customized-capillary viscometer at 298.85 K. Theoretically, the volume-translated Peng-Robinson equation of state (PR EOS) with a modified alpha function is used to model the experimental phase behaviour of C3H8-n-C/H10-heavy oil systems. Two binary interaction coefficient (BIP) correlations, respectively developed for the C3H8-heavy oil system and n-C4H10-heavy oil system, are incorporated into the volume-translated PR EOS model. The two BIP correlations together with the volume-translated PR EOS are found to be capable of predicting the phase behaviour of the C3H8-n-C4H10-heavy oil systems with a good accuracy. In addition, comparison of five commonly used mixing rules indicates that the Lobe’s mixing rule is the most appropriate to predict the viscosity of heavy oil diluted by C3H8 and/or n-C4H10.