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Results
Effect of ultrasonic intensity and frequency on heavy-oil recovery from different wettability rocks
Naderi, Khosrow (U. of Alberta) | Babadagli, Tayfun (U. of Alberta)
Abstract Using acoustic energy in enhanced oil recovery is not a new idea but yet is categorized as an unconventional method. In previous studies at our institution, the effect of ultrasonic radiation on capillary imbibition recovery of light oil from a water wet medium was widely investigated. Upon promising results, the study was extended to more challenging cases such as oil wet matrix (with and without initial water) and heavy oil. The effects of ultrasonic intensity and frequency were also included. Cylindrical sandstone cores were placed into imbibition cells where they contacted with aqueous phase. Each experiment was run with and without ultrasonic radiation keeping all other conditions and parameters constant. The experiments were designed to investigate how the presence of initial water saturation can affect the recovery (Swi=0 to 40%), and also how the recovery changes for different oil viscosities (35 to 1600 cp). Furthermore, the samples were tendered oil-wet by treating with dryfilm to quantify the effects of wettability. In addition, the specifications of acoustic source such as ultrasonic intensity (45 to 84 W/ sq cm) and frequency (22 and 40 kHz) were also changed. An increase in recovery was observed with ultrasonic energy in all cases. This change was more remarkable for oil-wet medium. The additional recovery with ultrasonic energy became lower as the oil viscosity increased. The results revealed that the ultrasonic intensity and frequency are very critical on the performance. This is a critical issue as the ultrasonic waves have limited penetration into porous medium and the intensity reduces while penetrating into porous medium. This is a major drawback in commercializing this promising process for well stimulation. Hence, we designed a set-up to measure the ultrasonic energy penetration capacity in different media, namely air, water, and slurry (sand+water mixture). A one-meter long water or slurry filled medium was prepared and the ultrasonic intensity and frequency were monitored as a function of distance from the source. The imbibition cells were placed at certain distances from the sources and the oil recovery was recorded. Then, the imbibition recovery was related to the ultrasonic intensity, frequency, and distance from the ultrasonic source. Introduction Using acoustic waves as an enhanced oil recovery technique has been of interest in the past decades. The main idea behind these studies was to observe how and to what extend acoustic energy might affect oil recovery. In a pioneering study, Duhon and Campbell (1965) conducted waterflood tests under ultrasonic energy and showed that ultrasonic energy causes an improvement in oil recovery. They also related the ultimate recovery to the frequency. Nosov (1965) observed a decrease in the viscosity of polystyrene solution under sound waves. Chen (1969) and Fairbanks and Chen (1971) reported increase in oil percolation rate through porous medium. Chen (1969) also showed that the effect of heat generated by ultrasonic radiation was minimal on the observed oil recovery increase. Johnston (1971) studied the influence of ultrasound on decreasing polymer viscosity. Cherskiy et al. (1977) described a sharp increase in permeability of core samples saturated with fresh water in the presence of acoustic field. Neretin and Yudin (1981) observed an increase in rate of oil displacement by water through loose sand under ultrasound. Pogosyan et al. (1989) showed that gravitational separation of water and kerosene accelerates due to acoustic field.
- North America > United States > Texas (0.68)
- North America > Canada > Alberta (0.47)
- Research Report (0.46)
- Overview (0.34)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.86)
Abstract Under the expected operating conditions of a Steam Assisted Gravity Drainage (SAGD) pilot project, it is anticipated that both the injection and the production wells will be able to flow unassisted to surface should a loss of well control incident occur. Industry practice regarding the design of such flowing wells dictates that the well completion include double barriers in the production tubing string and the production casing annulus. Unfortunately, downhole equipment suitable for such a high temperature application does not currently exist. To help evaluate the comparative risk between a double and single barrier completion, a reservoir modeling study was conducted to investigate the flowing potential (flow rates, durations and composition of the fluids) of the SAGD pilot wells under various blowout scenarios. This paper presents the results of this reservoir modeling study in terms of the coupled wellbore/reservoir behavior during the blowout condition. A commercial coupled wellbore/reservoir simulator was used along with a "custom" code developed to include a critical choke velocity constraint into the reservoir simulation considerations. The various blowout scenarios investigated include flow through both the injection and the production wells, at three different points during the production life of the well pair (beginning of the steam injection phase, middle of the steam chamber development and end of the steam injection phase) and through three possible flow paths (through the tubing, through the tubing-casing annulus and through both the tubing and the annulus). The reservoir modeling confirmed that both the injection and the production wells in this SAGD application have the potential for a blowout lasting for significant periods of times should a loss of well control occur, and with liquid rates that can be over 50 times the normal production liquid rates. Introduction The availability of successfully tested technology to exploit the huge bitumen and heavy oil reserves worldwide, along with the high oil price scenario are boosting the feasibility of bitumen and heavy oil production projects. In this context, Steam Assisted Gravity Drainage (SAGD) has emerged as one of the most efficient thermal recovery technologies to produce those resources. The usual way to predict the production performance of SAGD processes is by using reservoir thermal simulation. When long term production predictions are made, a classical sink/source formulation to describe the wellbore in the reservoir model is commonly used, under the assumption that localized transient phenomena within the wellbore doesn't affect the final SAGD oil recovery. That formulation assumes that the production/injection constraints, which normally include constant pressure or constant flow rate, will be independently applied at each point within the gridblocks where the wellbore is placed, in the reservoir simulation model, without any consideration of the fluids flow through the wellbore.
- North America > Canada > Alberta (0.29)
- North America > United States > California (0.28)
Abstract Bitumen extraction efficiency is increased in oil sands ore-water slurry based extraction process by increasing solubility of naturally occurred asphaltic acids by addition of CaO (lime) and/or by oxidation of bitumen asphaltenes by Ozone (O3) to surfactant species, at as low as 35 oC temperature. Experimental findings suggest that a non-caustic bitumen extraction process (i.e. without using NaOH as extraction process aid) could be used commercially by conditioning the oil sands orewater slurry with CaO and/or Ozone, which would allow high extraction efficiencies at about 35 oC temperature, reduce energy consumption and CO2 emission for the extraction of bitumen and eliminate the accumulation of Na+ ions in the recycled release water. Further tests are on-going to provide sufficient data for the commercial implementation of the use of CaO and/or Ozone at oil sands-ore water slurry based extraction plants. Introduction In northern Alberta, Canada oil sands resource presents one of the vast world hydrocarbon deposits, which extends over 77,000 km2, distributed in three principle regions: Athabasca, Cold Lake and Peace River. The oil sands deposits of the Athabasca Fort McMurray Formation are shallow enough to enable surface mining, in which bitumen content ranges from 0 to 19 %, averaging 12 %; water runs 3 to 6 %, increasing as bitumen content decreases; mineral content, predominantly quartz, silts and clay, runs 84 to 86 % (all by weight). Clays are occluded in the forms of discontinuous beds or bands varying from 1 cm to 15 cm in thickness. The in-place reserves of crude bitumen in these principal oil sands deposits exceed 1.7 trillion barrels. Of this total, only a small fraction (4 billion barrels) is under development permits. Overburden in the Athabasca deposits is in the range of zero to 600 m. Also, it is estimated that 75 billion barrels crude bitumen is placed in 0 to 45 m overburden and 550 billion barrels in 45 m to 600 m overburden. In northern Alberta three commercial plants produce bitumen from surface mineable Athabasca oil sands that amounts to almost 1,000,000 bbl/d. Recent investments made in the development of surface mineable oil sands indicate that bitumen production capacity would reach 2,000,000 bbl/d by 2010. All of the commercial plants which are operating, in construction or planned for future production use oil sands ore-water slurry based extraction processes which are based on the original work of Clark (Clark and Pasternack, 1932; Clark, 1939). These processes use additives such as NaOH or sodium salts of weak acids increasing the pH of the ore-water slurry. Increase in the pH of the ore-water slurry promotes the solubility of asphaltic acids (partly aromatic, containing oxygen functional groups such as phenolic, carboxylic and sulphonic types) present in bitumen which act as surfactants reducing the surface and interfacial tensions and promote the swelling of clay and disintegration of oil sands structure and promote the liberation of bitumen (Moschopedis et al., 1977 and 1980; Speight and Moschopedis, 1977; Baptista and Bowman, 1969; Bowman, 1968). Oil sands plants in northern Alberta operate with no-discharge policy, therefore, the release water recovered from the tailings effluent has to be recycled. Addition of sodium based additives as process aids; however, results in the accumulation of Na+ ions in the recycle water which cause concerns for the long term operability of the extraction plants. Over the few decades alternative non-caustic and low energy extraction processes have been investigated and commercially applied. Significant research and development have been devoted to improvement extraction efficiency, reduce extraction temperature, improve tailings disposal practice and to improve release water chemistry.
- North America > Canada > Alberta > Athabasca Oil Sands (0.35)
- North America > Canada > Alberta > Census Division No. 16 > Regional Municipality of Wood Buffalo > Fort McMurray (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
Abstract Electrical heating for heavy-oil recovery is not a new idea but commercialization and wider application of this technique require detailed analyses for determination of optimal application conditions. In this study, applicability of electrical heating for heavy-oil recovery from two heavy-oil fields in Turkey (Bati Raman and Camurlu) was tested experimentally and numerically. The physical and chemical properties of the oil samples for the two fields were compiled and measured. Then, core samples were exposed to electrical heating and oil recovery performances by the retort technique were determined for different conditions. Experiments with and without using iron powder were analyzed and in-situ viscosity reduction during the heating process was determined through a history matching process using the simulation of the laboratory experiments. Experimentally obtained oil recovery and temperature distributions were used in this history matching exercise. Iron powder addition to oil samples causes a decrease in the polar components of oil and the viscosity of oil can strongly be influenced by the magnetic fields created by iron powders. Therefore, three different iron powder types at three different doses were tested to observe their impact on oil recovery. Experimental observations showed that viscosity reductions were accomplished as 88% and 63% for Bati Raman and Camurlu crude oils, respectively, after 0.5% Fe addition, which was determined as the optimum type and dose for both crude oil samples. Different parameters (thermal diffusion coefficients, oil viscosity, and relative permeabilities) that are needed in numerical modeling as data were determined through experimentally validated numerical modeling study. Furthermore, field scale recovery was tested numerically using the parameters obtained from laboratory scale experimental and numerical modeling results. The power of the system, operation period and the number of heaters were optimized. Economic evaluation done using the field scale numerical modeling study showed that the production of one barrel petroleum costs about 5 USD and at the end of 70 days, 320 barrels petroleum can be produced. When 0.5% Fe is added, oil production increased to 440 barrels for the same operational time period. Introduction Crude oils whose API gravity smaller than 20 are called heavy oil (Conaway, 1999). The key to produce oil from these resources is to reduce oil viscosity, and that is best accomplished by heating these resources which can be achieved by thermal methods; i.e., hot-fluid injection, in-situ combustion and thermal stimulation (Farouq Ali, 2003; Prats, 1982). Apart from the common thermal methods, electromagnetic heating and electrical heating can also be considered as alternative thermal methods. While steam-based methods have been more successful economically and technically than others, alternative heating methods were found uneconomical for heavy-oil recovery due to the high operating costs in the past (Thomas, 2007). Because of recent increase in oil prices, electrical heating technique could be considered as a commercial method (Campbell and Laherrere, 1998). Electrical heating tools and their applications can be divided into three different categories based on frequency of electrical current used by the tool (Sahni and Kumar, 2000). (1) Low frequency currents are used in Resistive/Ohmic heating and (2) High frequency currents are used in Microwave heating methods. (3) The Induction tools have the ability to use a wide range of low to medium frequency currents depending on heat requirements and desired temperature. These methods are applied in the field by using a downhole magnetron or heater (Prats, 1982).
- North America > United States (1.00)
- Asia > Middle East > Turkey (0.90)
- North America > Canada (0.70)
- Asia > Middle East > Turkey > Bati Raman Field (0.94)
- Asia > Middle East > Turkey > Raman Field (0.93)
Abstract In heavy-oil recovery, although steam injection has no alternative in many circumstances, it may not be an efficient process under certain reservoir conditions. These conditions include deep reservoirs, where steam injection may turn out to be ineffective hot-water flooding due to excessive heat loss, and oil-wet fractured carbonates, where steam channels through fractures without effectively sweeping the matrix oil. Solutions for heavy oil recovery in consolidated/unconsolidated sandstones have been proposed and some of them are currently in the commercial phase, including steamflooding and its different versions. A more challenging case is heavy-oil fractured carbonates where the recovery is usually limited only to matrix oil drainage gravity due to unfavourable wettability or thermal expansion if heat is introduced during the process. Wettability alteration is usually thought to occur at elevated temperatures which are difficult to achieve in deep reservoirs. Thus, improvement of matrix oil recovery requires different methodologies. We propose a new approach to improve steam/hot-water injection effectiveness and efficiency for this type of reservoir. Static imbibition experiments were run on Berea sandstone and carbonate cores with different wettabilities and for different oil viscosities ranging between 200 cp and 14,000 cP. For wettability alteration, cores were either aged or treated by a wettability altering agent. The experiments were conducted initially in imbibition cells in a 90 oC oven to mimic the matrixfracture interaction in steam condensation zones. Due to its high boiling point, heptane was selected as the solvent and the core samples were exposed alternately to high temperature imbibition and solvent diffusion. The main ideas behind this process were to enhance capillary and gravity interaction by reducing viscosity (heat and solvent effect) and altering wettability (solvent effect). The results showed that further reduction in oil saturation due to s solvent diffusion process preceded by hot water is remarkably fast and the ultimate recovery is high. The magnitude of recovery depends on wettability and the amount of water existing in the core. It was also observed that solvent retrieval is a very fast process and may increase to 85โ90% depending on core type, wettability, and saturation history. Introduction Carbonate reservoirs introduce great challenges due to their complex fabric nature (low matrix permeability, poor effective porosity, fractures) and unfavorable wettability. These challenges are further displayed when combined with increased depth and low grade oil (low API and high viscosity). A huge amount of oil is contained in such reservoirs without any technological breakthrough for improving the recovery efficiently.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.45)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Word Group > San Andreas Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Grayburg Formation > San Andreas Formation (0.99)
- Europe > France > Nouvelle-Aquitaine > Lacq Basin > Lacq Superieur Field (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- (4 more...)
Abstract Spatial distribution of permeability is an important factor in the prediction of performance of Steam Assisted Gravity Drainage (SAGD) well pairs. Presence of short-scale variability in sand/shale sequences, preferential sampling of core data, and uncertainty in upscaling parameters are complications that make the inference of a reliable porosity - permeability relationship impossible. A simple yet effective way of overcoming these complications is micro-modeling. The central idea in micro-modeling is to use an additional source of information, namely digitized core images, to quantify the uncertainty in power-law averaging parameters and construct the porosity-permeability bivariate relationship by Monte Carlo Simulations (MCS). The work-flow in micro-modeling is comprised of a few steps from digitizing the selected core images to building 3D geo-blocks of binary sand/shale mixture, populating them with porosity/permeability values, upscaling the populated binary mixture by flow simulations, determining the uncertainty in power-law parameters and implementing MCS. The porosity-permeability relationships are constructed on a by-facies basis. Results of this research suggest that effective properties of clean sand are changing with the volume fraction of shale; and it has ultimately resulted in the development of an extended version of power-law formalism. Introduction Mini-modeling technique (McLennan et al. 2006) was developed to (1) mitigate the bias in core porosity and permeability measurements, (2) infer bivariate relationship between porosity and permeability with limited core data and (3) account for the difference between the scales of core data and geological modeling grid blocks. However, there are a number of shortcomings associated with mini-modeling: implementation of mini-modeling still requires a number of representative parameters at the core-scale; it ignores the effect of laminae on core permeability measurements; and it neglects the uncertainty in the upscaling parameters. Micro-modeling through the use of digitized core images has been recently developed to investigate the uncertainty in upscaling parameters in different scales, to account for important micro-scale features with high permeability contrasts, to account for preferentially sampled porosity and permeability data, and finally to support the establishment of representative statistics for mini-modeling. A direct result of micro-modeling is by-facies porosity-permeability relationship that would support the reservoir modeling at scales larger than core plug scale. Digitized core images carry important information about micro-scale features and laminae which have profound impact on the fluid flow and are often dismissed in core data sampling efforts (Figure 1). High-resolution core photographs usually have pixel sizes equal to or smaller than a millimeter. The photographs used in this work have pixel sizes of 500 ยตm on each side. The overall workflow in micro-modeling includes selecting and digitizing by-facies core-photos, creating 3D training images (TIs) from the 2D data sets, creating 3D geo-blocks of sand/shale binary mixture, populating the binary mixture with appropriate porosity and permeability values, upscaling them to core-plug size, finding the distribution of upscaling parameters and performing MCS to find the representative porosity-permeability relationship on a by facies basis. The details of the proposed methodology are discussed in the following paragraphs.
- North America > Canada > Alberta (0.29)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.54)
Sand Transport in a Horizontal Well: A Numerical Study
Doan, Q. (U. of Alberta) | Ali, S.M. Farouq (U. of Alberta) | Oguztoreli, M. (U. of Alberta) | George, A.E. (ERL/CANMET)
Abstract Horizontal wells have been shown to be successful in improving oil recovery for marginal heavy oil reservoirs in Saskatchewan and Alberta. One commonly encountered problem in recovery operations for these unconsolidated reservoirs is the production of sand and fines. The settling and accumulation of the solid particles inside the horizontal wellbore represents a serious problem, with the horizontal well becoming partially plugged being a real possibility. This study investigates this problem, with focus on determining the roles played by different flow parameters on the settling and transport process. The physical model described in this work examines the transport process mechanistically. Conservation equations for the solid phase (sand particles) and the fluid phase (oil) are formulated, with the interaction between the phases described by empirical correlations. The oil is assumed to be a Newtonian fluid, and the sand particles are assumed to be spherical in shape and uniform in size. The system of equations is solved numerically to determine the distribution of sand particles and oil, and the respective pressure and velocity distributions as a result of the presence of a constriction inside the horizontal well. According to the simulation results, oil viscosity and particle size play important roles in the transport process, including controlling the gravitational settling tendency of solid particles inside the horizontal wellbore. The results provide insight into the mechanisms involved in the transport process; as such, they provide guidelines for production operations involving horizontal wells in unconsolidated and poorly consolidated reservoirs. Introduction One of the most common applications of horizontal well technology in Canada is to recover oil from heavy oil reservoirs in Saskatchewan and Alberta. In heavy oil reservoirs underlain with bottom-water, the use of horizontal wells has been found to improve primary recovery performance prior to water coning - recovering up to 15% of the initial oil in place (in shorter time, also), compared with only 5% for a vertical well. Horizontal wells have also been successfully used for increasing steamflood recovery. However, recovery operations in these heavy oil reservoirs are usually susceptible to sand production due to their unconsolidated nature. The produced sand could give rise to production problems. as the sand fill up the wellbore, prevent the operations of downhole pumps, etc. In the case of horizontal wells, sand production potentially poses an even more serious problem, due to the settlement and accumulation of sand particles at different positions along the well - leading to the reduction of the cross-sectional area of the wellbore open to flow (Figure 1). The ultimate effect of sand deposition could be the partitioning of the horizontal well into several segments, leading to a loss of production and a negation of the principal advantage of horizontal wells (large contact area with the reservoir). The study reported here investigates this problem. Specifically the study examines, through numerical simulation, the transport and distribution of sand particles, pressure, and velocity distributions in a horizontal well. A special feature of the physical model is the presence of a constriction inside the horizontal well. Solid-liquid flow encompasses many different areas of science and engineering, including the transport of colloids in rain water, sediment transport in river streams, slurry pipeline transportation, drill cuttings removal, transport of proppants in hydraulically fractured wells, etc. The large number of independent variables involved in these transport processes, coupled with the complex interaction between the variables have precluded comprehensive analytical studies of these processes mechanistically. Instead, many experimental studies have been carried out over the years. P. 471^
- North America > Canada > Alberta (0.54)
- North America > Canada > Saskatchewan (0.44)