Steam Requirements Research Articles

Lowered Emissions Schemes for Upgrading Ultra Heavy Petroleum Feeds

Several commercial processes have been successfully used for upgrading heavy petroleum feeds containing less than 300 ppm of V + Ni. For problematic petroleum feeds, metal content exceeds this level and may approach 1000 ppm of V + Ni. Frequently, the upgrading battery is located in remote locations in the proximity of the heavy crude producing wells. In this case, the objective of upgrading is a syncrude suitable for pipelining. The complexity of upgrading increases with increasing content of metals, resins, and asphaltenes. The database of processing parameters has to be established for selecting optimal upgrading schemes, e.g., catalytic versus noncatalytic routes. From a processing point of view, the information on the yield of syncrude, steam, and electricity requirements, as well as hydrogen and catalyst consumption, are of primary interest. The parameters determining the environmental impact on the upgrading schemes have to be considered as well. The processes suitable for upgrading problematic feeds under evaluation include catalytic hydroprocessing, slurry bed hydrocracking, and coking. Various combinations of these processes have been used as well. Deasphalting combined with catalytic processes may be an attractive route providing that the rejected asphalt can be efficiently utilized on site. Lowered emissions can be achieved by utilizing asphalt and other residues from upgrading on gasification island for production of hydrogen, carbon dioxide, steam, and electricity. Compared with combustion, an integrated gasification-combined cycle operates at higher overall thermal efficiency with all emissions being significantly lower.

A New Process Combining Cyclic Steam Stimulation and Steam-Assisted Gravity Drainage: Hybrid SAGD

Abstract A new thermal recovery scheme is proposed that utilizes Steam-Assisted Gravity Drainage (SAGD) well pairs as well as Cyclic Steam Stimulation (CSS) wells placed in between the SAGD well pairs. The wells are operated in CSS mode until the steam chambers are in contact with each other and then switched to SAGD operation. It is shown that the new process recovers greater amounts of bitumen with lower injected steam in shorter operation time than is achieved with SAGD, Fast-SAGD and CSS. Introduction Alberta's major oil sands deposits, with an estimated 1.7 trillion bbls of bitumen-in-place, account for approximately 40% of the world's bitumen resource(1). The estimated remaining recoverable bitumen from this resource is 170 billion bbls, which dwarfs the remaining conventional reserves of crude oil in Alberta by more than two orders of magnitude(2). While shallow oil sands reserves can be extracted by mining, most of these reserves (82%) are accessible through in situ thermal processes only(2). Two commercially-applied in situ production methods are Steam-Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS). These methods are technically effective but can be rendered uneconomic due to steam requirements. Although the first commercially applied thermal recovery process was CSS, there are a number of commercial and smaller SAGD projects under way at present in Alberta(3). The main attraction of SAGD compared to CSS is that higher recoveries in excess of 50% can be obtained because of the efficiency and effectiveness of the gravity drainage process. However, a challenge for SAGD is to try to promote the lateral and downward expansion of the steam chamber(4). Recently, a new process called Fast-SAGD has been proposed to overcome this problem(5–10). Fast-SAGD Process In the Fast-SAGD process, additional single offset horizontal wells are drilled in between and parallel to the SAGD well pairs. The offset wells are placed at the same elevation as the SAGD producers and can be 50 to 80 m away from the SAGD well pairs. The concept relies on operating the SAGD wells until the steam chamber reaches the top of the formation and then starting a CSS operation at the offset wells at considerably higher pressure than the SAGD wells. The purpose of injecting steam into the offset CSS well is to accelerate growth and propagation of the steam chamber laterally. Once the inter-well area between the SAGD well pairs is heated enough, ideally when the two steam chambers come into contact, the offset well is converted into a producer and the SAGD operation continues. Authors of Fast-SAGD articles reported the results of thermal numerical simulations to initially analyze the response in a Cold Lake-type reservoir and later in Athabasca- and Peace River-type reservoirs(5–10). Their numerical models were generic, two dimensional (2D) homogeneous layer cake models. Results reported were quite impressive in these idealized models where bitumen production rates increased significantly and energy efficiency, as measured by steam-oil ratio (SOR), was better compared to conventional SAGD. Given the encouraging results, it was suggested that a field test should be carried out.

Dynamic simulation of a supercritical once-through heat recovery steam generator during load changes and start-up procedures

This paper presents a static and dynamic simulation model of a supercritical once-through heat recovery steam generator (SC HRSG) and its application to investigate the load changes and start-up processes for next generation high efficiency combined cycles. The scale and complexity of the modern combined cycle power plants based on high pressure and temperature steam requirements are increasing. To design such a system, it is necessary to generate detailed computer models. This study describes the upgrading of a validated sub-critical heat recovery steam generator model to a supercritical once-through heat recovery steam generator up to 250 bars in the high pressure circuit. The SC HRSG model is built using commercial simulation software named Advanced Process Simulation Software (APROS). The model includes advanced control circuits to have a high level of accuracy, especially during start-up. The comparison between the simulation results and the designed data in steady state and different load changes are documented. The obtained results demonstrate that the simulation is very reliable to predict the start-up procedure for the SC HRSG. Through a comparative study, the differences in the thermal efficiency and the steam parameters between super/sub-critical heat recovery steam generators during warm start-up process are assessed.

Multiphase reactor scale-up for Cu–Cl thermochemical hydrogen production

This paper examines selected design issues associated with reactor scale-up in the thermochemical copper–chlorine (Cu–Cl) cycle of hydrogen production. The thermochemical cycle decomposes water into oxygen and hydrogen, through intermediate copper and chlorine compounds. In this paper, emphasis is focused on the hydrogen, oxygen and hydrolysis reactors. A sedimentation cell for copper separation and HCl gas absorption tower are discussed for the thermochemical hydrogen reactor. A molten salt reactor is investigated for decomposition of an intermediate compound, copper oxychloride (CuO·Cl 2), into oxygen gas and molten cuprous chloride. Scale-up design issues are examined for handling three phases within the molten salt reactor, i.e., solid copper oxychloride particles, liquid (melting salt) and exiting gas (oxygen). Also, different variations of hydrolysis reactions are compared, including 5, 3 and 2-step Cu–Cl cycles that utilize reactive spray drying, instead of separate drying and hydrolysis processes. The spray drying involves evaporation of aqueous feed by mixing the spray and drying streams. Results are presented for the required capacities of feed materials for the multiphase reactors, steam and heat requirements, and other key design parameters for reactor scale-up to a pilot-scale capacity.

Removal and recovery of compressed CO2 from flue gas by a novel thermal swing chemisorption process

AbstractA synopsis of the published literature on removal of CO2 from a flue gas is given. A novel thermal swing chemisorption (TSC) process concept is proposed for removal and recovery of compressed CO2 from a flue gas without precompression, predrying, or precooling. The process uses Na2O promoted alumina as a reversible CO2 selective chemisorbent in conjunction with the principles of rapid thermal swing adsorption for direct production of compressed CO2 from a flue gas. Several complementary process steps are used in the design to compress the product CO2 and to achieve high CO2 recovery and sorbent capacity utilization. Judicious steam purge steps are used for highly efficient sorbent regeneration and to minimize the steam requirement. The CO2 chemisorption characteristics of the sorbent are reviewed and a model simulation of the TSC process performance is reported. © 2008 American Institute of Chemical Engineers AIChE J, 2008

A life-cycle comparison between inorganic and biological catalysis for the production of biodiesel

Life cycle assessment (LCA) has been used to compare inorganic and biological catalysis for the production of biodiesel by transesterification. The inorganic route, using catalysis by sodium hydroxide, has been compared with a conceptual biological one using enzymatic catalysis by the lipase produced by Candida antarctica. Although biological catalysis has not been used for industrial production of biodiesel to date, results from laboratory experiments suggest that it could have distinct advantages over the inorganic route, particularly with regard to a simplified flowsheet for purification and concomitant energy savings. Five flowsheet options have been included in the study to investigate the alkali and enzyme catalysed production routes from rapeseed oil, use of methanol or ethanol for transesterification and the effect of efficiency of alcohol recovery. The LCA shows that the enzymatic production route is environmentally more favourable. Improvements are seen in all impact categories. Global warming, acidification, and photochemical oxidation are reduced by 5%. Certain toxicity levels have more than halved. These results are mainly due to lower steam requirements for heating in the biological process.

Analysis of process steam demand reduction and electricity generation in sugar and ethanol production from sugarcane

The sugarcane industry represents one of the most important economic activities in Brazil, producing sugar and ethanol for the internal and external markets. Moreover, thermal and electric energy is produced for self-consumption, using sugarcane bagasse as fuel in cogeneration plants. Almost all the sugarcane plants in Brazil are self-sufficient in terms of energy supply and in the last few years some of them have been selling their surplus electricity for the grid. The reduction of process steam requirements and the use of more efficient cogeneration systems are new alternatives to increase the surplus electricity generation. The purpose of this paper is to analyze the steam demand reduction on sugar and ethanol process and alternatives for cogeneration systems in sugarcane plants, aiming at the surplus electricity generation increase.

Steam Injection in Fractured Carbonate Reservoirs

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 102186, "The Physics of Steam Injection in Fractured Carbonate Reservoirs: Engineering Development Options That Minimize Risk," by G.T. Shahin Jr., SPE, Shell E&P Technology; R. Moosa, SPE, PDO; and B. Kharusi and G. Chilek, Shell E&P Technology, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September. The economic success of the Qarn Alam project depends on the ability to predict steam requirements and oil production. Two key oil-production mechanisms are heat transport through the fractures and into the matrix and gas-cap generation resulting from thermal volatilization of the oil. The process mechanisms involved in thermally assisted gas/oil gravity drainage (TAGOGD) were validated through laboratory experiments, while the field-forecast model results were validated by history matching pilot-performance data. Introduction The Qarn Alam field was first brought on production in 1975. When the field came on stream, the net oil production peaked at 6000 m3/d, despite the high oil viscosity. Water breakthrough followed rapidly, and by 1978, net oil production declined and remained low thereafter. During the initial peak in oil production, the oil contained in the highly permeable and pervasive network of fractures was produced and replaced mostly by formation water. After this period, a rim of oil remained, separating the newly formed fracture water/oil contact (WOC) and the newly formed fracture gas/oil contact (GOC). Under primary production, the reservoir produces on average approximately 100 m3/d of 16°API oil, at a 10 m3/m3 gas/oil ratio (GOR). The purpose of TAGOGD in Qarn Alam is to develop additional oil by increasing the field recovery from 4% under isothermal gas/oil gravity drainage (GOGD) to 27% of original oil in place. TAGOGD is a novel enhanced-oil-recovery development concept that has as yet no full-field analog. Despite the lack of commercial analogs, several field trials have occurred on a pilot scale. Isothermal GOGD in this viscous (220 cp)-oil reservoir is economically unattractive because of the low oil mobility. Reservoir heating by steam injection significantly lowers the oil viscosity to approximately 2 cp, increases the gas cap as a result of thermal vaporization of the oil, and increases the GOGD rate by a factor of approximately 60. This development concept has been piloted in the Qarn Alam field and was found to be economically attractive. The attractiveness of the concept stems from the fact that the dense fracture spacing in the reservoir effectively distributes the steam and is a conduit to collect the oil in the oil rim. This type of development requires significantly fewer wells than an equivalent conventional steamflood.

Comparison of pulp-mill-integrated hydrogen production from gasified black liquor with stand-alone production from gasified biomass

When gasified black liquor is used for hydrogen production, significant amounts of biomass must be imported. This paper compares two alternative options for producing hydrogen from biomass: (A) pulp-mill-integrated hydrogen production from gasified back liquor; and (B) stand-alone production of hydrogen from gasified biomass. The comparison assumes that the same amount of biomass that is imported in Alternative A is supplied to a stand-alone hydrogen production plant and that the gasified black liquor in Alternative B is used in a black liquor gasification combined cycle (BLGCC) CHP unit. The comparison is based upon equal amounts of black liquor fed to the gasifier, and identical steam and power requirements for the pulp mill. The two systems are compared on the basis of total CO 2 emission consequences, based upon different assumptions for the reference energy system that reflect different societal CO 2 emissions reduction target levels. Ambitions targets are expected to lead to a more CO 2–lean reference energy system, in which case hydrogen production from gasified black liquor (Alternative A) is best from a CO 2 emissions’ perspective, whereas with high CO 2 emissions associated with electricity production, hydrogen from gasified biomass and electricity from gasified black liquor (Alternative B) is preferable.

Effects of electrolyte type and flow pattern on performance of methanol-fuelled solid oxide fuel cells

A comparison is made of the performances of methanol-fuelled solid oxide fuel cells (SOFCs) with different types of electrolyte (i.e., oxygen ion- and proton-conducting electrolytes) and flow patterns (i.e., plug flow (PF) and mixed flow (MF)). Although it was demonstrated earlier that, under the same inlet steam:methane ratio, an SOFC with a proton-conducting electrolyte (SOFC-H +) thermodynamically offers higher efficiency than one with an oxygen ion-conducting electrolyte (SOFC-O 2−), the benefit of a lower steam requirement for the SOFC-O 2− was not taken into account. Therefore, this study attempts to consider the benefit of differences in the steam requirement on the performance of SOFCs operated with different electrolytes and flow patterns. The efficiencies under the best conditions are compared in the temperature range of 900–1300 K. It is found that the maximum efficiencies decrease with increasing temperature and follow the sequence: SOFC-H + (PF) > SOFC-O 2− (PF) > SOFC-H + (MF) > SOFC-O 2− (MF). The corresponding inlet H 2O:MeOH ratios are at the carbon formation boundary for the SOFC-O 2− electrolyte, but are about 1.3–1.5 times the stoichiometric ratio for the SOFC-H +. It is clearly demonstrated that the PF mode is superior to the MF mode and that, although the benefit from the lower steam requirement is realized for the SOFC-O 2−, the use of the proton-conducting electrolyte in the SOFCs is more promising.

Energy Conservation in Boiler House by Using Variable Speed Control

ABSTRACT Boilers should always be supplied with more combustion air than theoretically required in order to ensure complete combustion and safe operation. At the same time, boiler efficiency is very dependent on the excess air rate. Therefore, the excess air should be optimized to increase the system efficiency. In this study, the effect of the excess air ratio on the efficiency of the boiler system was investigated in a water tube boiler that has the capacity of producing 20 bar pressure and 55 ton steam at 245°C. The boiler combustion air is supplied from a fan driven by a 30kW at 1450 rpm induction motor. Since the fan motor, running at nominal speed, has supplied the same air flow rate, excess air amount and exhaust gas temperature were very high at low loads. In that stage, boiler efficiency was low due to thermal energy losses, which also consequently leads to electrical energy losses. The steam requirement of the factory changes because of the tire process. For example, in the tire cooking machines...

Modeling of CO2 capture by aqueous monoethanolamine

AbstractThe process for CO2 removal from flue gases was modeled with RateFrac. It consists of an absorber, a stripper, and a cross heat exchanger. The solvent used in the model contains about 30 wt % monoethanolamine (MEA) in water. MEA reacts with CO2 in the packed absorber. The finite reaction rate requires a kinetic characterization. The RateFrac absorber model was integrated with a FORTRAN user kinetic subroutine to make the model consistent with the interface pseudo‐first‐order model and with a regressed Electrolyte‐NRTL equilibrium model. It was adjusted with laboratory wetted wall column data and field data from a commercial plant. Sensitivity analyses were performed on process variables to find operating conditions at low steam requirement. Many variables strongly affect the process performance, but an overall optimization shows that there are no economical ways to reduce the steam requirements by more than 10%. The reboiler duty can be reduced from that of a base case representing current industrial operating conditions, by 5% if acids are added to the solvent, by 10% if the absorber height is increased by 20%, and by 4% if the absorber is intercooled with a duty of one‐third of the reboiler duty. The power plant lost work is affected by varying stripper pressure, but not significantly, so any convenient pressure can be chosen to operate the stripper.

A material and energy flow model for co-production of heat and power

Co-production of electricity, district heat and industrial heat/process steam (heat and power, CHP) has been applied to a large, national scale, in only a few countries in the world, Denmark, The Netherlands and Finland. In this production method, the waste energy from electricity production is used in two quality levels. First, industrial process steam requirements can be met with this residual energy. Second, the waste energy is used in local district heating networks for households and other buildings in a city. In this integrated production method, a total fuel efficiency of 85% can be achieved. Through the technique of fluidized bed combustion, modern CHP plants can use coal and oil, and in addition, heterogeneous fuels such as biomass, industrial wastes and recycled fuels from households. In this paper, the CHP method is considered in terms of four categories of material and energy flows. For the purpose of considering the potential environmental gains and the difficulties of this production method when applied to integrated waste management and energy production, the four suggested categories are: matter (biomass) (1), nutrients (2), energy (3) and carbon (4). Corporate environmental management inventory tools, decision-making tools, management, organisational and administrative tools as well as information management tools that could be used in CHP-related material and energy flow management are shortly discussed. It is argued that for CHP energy and environmental management, it can be important to adopt an approach to networks of firms, rather than to an individual firm. The presented material and energy flow model may contribute to assessing, planning and implementing of CHP-based waste management and cleaner energy production.

Laboratory investigation of an ultralow NO x premixed combustion concept for industrial boilers

A combustion concept to achieve ultralow emissions (NOx≤2 ppm and CO≤20 ppm) was tested on a 18 kW low-swirl burner (LSB). It is based on lean premixed combustion combusned with flue gas recirculation (FGR) and partially reformed natural gas (PRNG). Flame stability and emissions were assessed as a function of , FGR, and PRNG. The results show that PRNG improves flame stability and reduces CO, with no impact on NOx at =0.8. A one-dimensional flame simulation satisfactorily predicted prompt NOx under lean conditions with high FGR. Two catalysts were tested in a prototype steam reformer, and the results were used to estimate reactor volume and steam requirements in a practical system. An advanced Sud Chemie catalyst displayed good conversion efficiency at relatively low temperatures and high space velocities, which indicates that the reformer can be small and will track load changes. Tests conducted on the LSB with FGR and 0.05 PRNG show that boilers using a LSB with PRNG and high FGR andclose to stoichiometry can operate with low emissions and high efficiency.

Mapping of combined heat and power systems in cane sugar industry

Cogenerating systems based on steam turbines (1–20 MW t) are indispensable when the source of energy is a solid fuel such as bagasse as in a sugar industry. These systems provide a wide range of heat to power ratios from 0 to as high as 100. The energy productivity of sugar plants differ vastly because of variations in equipment efficiency, system configuration and operating steam conditions. In this paper a mapping of the entire operating range of steam based combined heat and power plants spanning pure back pressure to pure condensing environments, based on standard steam conditions in installations and efficiencies which are currently being achieved experimentally, is presented. This will enable the rational choice of combinations, which will yield the best economic advantage. As the operating steam pressure is increased (and consequently the matching superheated temperatures) the in-house steam requirement reduces drastically and simultaneously the exportable power increases. Improvements in the systems by the use of advanced designs of steam turbines and introduction of information technologies and associated supervision control and data acquisition, energy management system, multi-media interaction, etc., is also briefly highlighted. The maximum exportable electrical power from a sugar mill after meeting the internal requirement is around 146 kW h/t of cane. The maximum exportable of steam (no power export) is around 0.65 t/t of cane.

Some Recent Developments in SAGD

Abstract Steam Assisted Gravity Drainage (SAGD) is being used increasingly for the recovery of bitumen and heavy oil in Canada. Four large SAGD projects are under construction in Athabasca and two others have been announced. These projects are expected to produce bitumen economically and with a recovery greater than 50%. Productivity will be close to 1000 B/d per well pair. There are also many successful smaller, and growing, projects and pilots in Athabasca, Cold Lake and Lloydminster. Because of the rising costs of fuel it is desirable to reduce steam requirements for SAGD. Means for doing this include cogeneration of steam and power, alternate fuels, choosing better reservoirs, improved heat recovery, and the newer related processes, SAGP and Vapex. In Steam Assisted Gravity Drainage (SAGD)(1), Steam and Gas Push (SAGP)(2), and Vapour Extraction (Vapex)(3) the oil isduced in viscosity and produced by gravity drainage to horizontalells placed low in the reservoir. As the oil drains, the vacatedreservoir pores are filled largely with gas/steam in SAGD, steam lus non-condensible gas in SAGP and solvent vapour plus noncondensible gas in Vapex. A common feature of the three processes is that the use of long horizontal wells combined with the reduced viscosity of the produced oil allows the production of oil with essentially no by-pass of free gas. In suitable reservoirs economic rates are achieved whereas with conventional wells or without adequate viscosity reduction there would be intolerable gas coning. High recoveries are obtained because of the systematic nature of the drainage. Since the author's earlier paper in this series(4) there has been a great increase in the interest in this subject and there are now many substantial field projects in various stages of planning and construction. Advanced Commercial SAGD Projects In Athabasca SAGD is at the stage where several major field projects to recover bitumen from Athabasca are either under construction or about to be. In most cases, the reservoirs are thicker than those that have been exploited previously and superior results are anticipated. The initial investment for large SAGD projects is of the order of $10,000 Canadian per B/d of capacity and the Steam Oil Ratio (SOR) is about 1.9 to 2.5. The supply costs for bitumen will probably be less than $10 Canadian per barrel, including return but excluding the fuel cost. This important cost is discussed later. Generally product lifting from the reservoir is by natural flow, a technique first demonstrated by Sceptre Resources and now used in several of the pilots. Four large commercial SAGD projects are described below. A recovery of over 50﹪ of the oil in place is expected in each. Figure 1 shows the approximate locations of the projects discussed below. Alberta Energy Company (AEC) Foster Creek (T70 R4 W4M)(5) This is a commercial expansion of AEC's pilot project, which produces 2,000 B/d from three SAGD well pairs.

Steam and Gas Push (SAGP)-3;Recent Theoretical Developments and Laboratory Results

Abstract SAGP is a thermal oil recovery process that is similar to Steam-Assisted Gravity Drainage (SAGD) but which involves the addition of a small concentration of a non-condensable gas to the steam. This paper is a continuation of parts 1 and 2 presented at the 48th and 49th Annual Technical Meetings of the Petroleum Society. Theoretical developments and laboratory experiments continue to show significant improvements for the process as compared to SAGD. Experimental results have now been obtained with Athabasca crude oil as well as Cold Lake and Lloydminster type oils. In SAGP much of the oil displacement is caused by the flow of fingers of gas/steam rising counter-currently to the draining oil, rather than by the simple advance of a continuous steam chamber. The rising gas fingers raise the pressure in the reservoir above and this increase in pressure towards the top of the reservoir tends to push the oil down. Gas accumulates in the upper part of the reservoir and oil drains to the production well near to the bottom. The mechanism is discussed in the paper together with results from recent scaled, physical model experiments. The work demonstrates that SAGP may be expected to produce oil at rates nearly equivalent to SAGD but with much lower steam consumption. Introduction The successful applications of the Steam-Assisted Gravity Drainage (SAGD) process in the fields have provided tremendous opportunities for the development of heavy oil and bitumen resources. SAGD field projects are continuing to be constructed following the successful testing of the process at AOSTRA's Underground Test Facility (UTF) (now Northstar's Dover project). In addition to Canadian projects, this process has also been field tested in other countries(1). Most recently, the SAGD project in the Tia Juana field in Venezuela(2) is reported to produce average oil rates of 700 bpd per well pair from the first year's operation. Although SAGD is effective in producing bitumen and heavy oils, it requires a large quantity of heat to heat the whole chamber to saturated steam temperature and the heat loss to the overburden is high. The process may become uneconomic in some reservoirs such as those with thin sands, low porosity, low oil saturation, and bottom water zones. To extend the range of reservoirs that can be produced economically with SAGD technology, a new process was developed to reduce the heat loss to the overburden while maintaining high oil drainage rates. The Steam and Gas Push (SAGP) process involves the addition of a small amount of non-condensible gas, such as nitrogen or methane, to the steam. The accumulation of gas in the upper part of the chamber reduces the average temperature in the chamber and the heat loss to the overburden. As a result, the steam requirement is reduced and oil/steam ratio is improved. Both theoretical and physical model studies have been carried out at the University of Calgary with support from participants from industry, since the process was first described(3). Some mechanisms and model test results were described at the 49th ATM(4) and the 7th UNITAR International Conference on Heavy Crude and Tar Sands(5).

The Best Process for Cold Lake: CSS vs. SAGD

Hilda Lake is a Steam Assisted Gravity Drainage (SAGD) project. The Mahkeses project is an expansion of the Imperial Oil Resources Limited commercial Cold Lake project based on Cyclic Steam Stimulation (CSS). Both projects are being implemented in the same Clearwater reservoir and will be adjacent to each other at the lease boundary. The projected performance of CSS at Mahkeses as given in the Alberta Energy Board Application for Approval is compared with the predicted and actual performance of SAGD at Hilda Lake. Parameters to be compared include: production rates, steam requirements, electrical power requirements, projected recovery factors, and produced water quality.Introduction. The CSS process as operated by Imperial Oil is described in the Application(1) to the Alberta Energy Utilities Board (EUB) for expansion of the Cold Lake Project which was submitted in February 1997. The SAGD process is described by Butler(2). In his 1997 paper Batycky(3) compared the actual CSS performance to numerical simulations of SAGD and concluded that the performance parameters for CSS were better in all respects. These parameters included cumulative steam oil ratio (CSOR) and ultimate recovery. Ali(4, 5) has repeated this assertion and in his more recent presentation has stated that SAGD is not economic. During 1997 two pilot projects were initiated to test the SAGD process in the Clearwater formation in the Cold Lake area. The first is the Burnt Lake Project operated by Suncor which consists of three horizontal well pairs. The second is the Hilda Lake Project operated by BlackRock which consists of one well pair. Baker(6) indicates that the Burnt Lake Project is meeting expectations. The design of the Hilda Lake Project is described by Donnelly(7) and the performance of the pilot is compared to numerical simulation predictions by Donnelly(8). This comparison given in Figure 1 for production rate and in Figure 2 for steam oil ratio indicates that the pilot is performing as predicted. In this paper parameters that can be extracted from the predictions for the Hilda Lake Project and from the actual operating data are compared to the projections for CSS provided in the Imperial Oil Application(1) and the supplemental information submitted to the EUB in January 1998(9).FIGURE 1: Hilda Lake, prediction compared to actual. (Available in full paper)FIGURE 2: Hilda Lake, steam oil ratio, prediction compared to actual. (Available in full paper)Reservoir Development. Table 1 compares the typical reservoir properties of the Mahkeses Cold Lake Expansion with those of the Hilda Lake Pilot. The Mahkeses properties are based on Figure 2–7 of the of the expansion application(1) which gives the properties of the wellTABLE 1: Average reservoir properties. (Available in full paper)FIGURE 3: Production forecast. (Available in full paper)8–32–64–3 W4. The Hilda Lake properties are based on the 20 m above the horizontal well for the well 15-17-64-3 W4 which is located near the project because the other 18 m of reservoir are of very low quality. The reservoir quality based on permeability and initial oil saturation at Mahkeses is equivalent to that at Hilda Lake.

The Best Process for Cold Lake: CSS vs. SAGD

Abstract Hilda Lake is a Steam Assisted Gravity Drainage (SAGD) project. The Mahkeses project is an expansion of the Imperial Oil Resources Limited commercial Cold Lake project based on Cyclic Steam Stimulation (CSS). Both projects are being implemented in the same Clearwater reservoir and will be adjacent to each other at the lease boundary. The projected performance of CSS at Mahkeses as given in the Alberta Energy Board Application for Approval is compared with the predicted and actual performance of SAGD at Hilda Lake. Parameters to be compared include: production rates, steam requirements, electrical power requirements, projected recovery factors, and produced water quality. Introduction The CSS process as operated by Imperial Oil is described in the Application(1) to the Alberta Energy Utilities Board (EUB) for expansion of the Cold Lake Project which was submitted in February 1997. The SAGD process is described by Butler(2). In his 1997 paper Batycky(3) compared the actual CSS performance to numerical simulations of SAGD and concluded that the performance parameters for CSS were better in all respects. These parameters included cumulative steam oil ratio (CSOR) and ultimate recovery. Ali(4, 5) has repeated this assertion and in his more recent presentation has stated that SAGD is not economic. During 1997 two pilot projects were initiated to test the SAGD process in the Clearwater formation in the Cold Lake area. The first is the Burnt Lake Project operated by Suncor which consists of three horizontal well pairs. The second is the Hilda Lake Project operated by BlackRock which consists of one well pair. Baker(6) indicates that the Burnt Lake Project is meeting expectations. The design of the Hilda Lake Project is described by Donnelly(7) and the performance of the pilot is compared to numerical simulation predictions by Donnelly(8). This comparison given in Figure 1 for production rate and in Figure 2 for steam oil ratio indicates that the pilot is performing as predicted. In this paper parameters that can be extracted from the predictions for the Hilda Lake Project and from the actual operating data are compared to the projections for CSS provided in the Imperial Oil Application(1) and the supplemental information submitted to the EUB in January 1998(9). FIGURE 1: Hilda Lake, prediction compared to actual. (Available in full paper) FIGURE 2: Hilda Lake, steam oil ratio, prediction compared to actual. (Available in full paper) Reservoir Development Table 1 compares the typical reservoir properties of the Mahkeses Cold Lake Expansion with those of the Hilda Lake Pilot. The Mahkeses properties are based on Figure 2–7 of the of the expansion application(1) which gives the properties of the well TABLE 1: Average reservoir properties. (Available in full paper) FIGURE 3: Production forecast. (Available in full paper) 8–32–64–3 W4. The Hilda Lake properties are based on the 20 m above the horizontal well for the well 15-17-64-3 W4 which is located near the project because the other 18 m of reservoir are of very low quality. The reservoir quality based on permeability and initial oil saturation at Mahkeses is equivalent to that at Hilda Lake.

Stripping medium requirement in continuous countercurrent deodorization

AbstractA mathematical formula was derived that allows the stripping steam requirement of the countercurrent deodorization process to be calculated as a function of system pressure, vapor pressure of the pure volatile compound, initial and final volatiles contents, and the number of transfer units (an equipment parameter) of the countercurrent deodorizer. Just as in batch or cross‐flow deodorization systems, the steam requirement in countercurrent systems is proportional to the system pressure and inversely proportional to the vapor pressure of the pure volatile compound. Increasing the number of transfer units (for instance, by increasing column height) to more than two makes the countercurrent system require less steam than cross‐flow systems with a vaporization efficiency of 0.6. In addition, the short residence time in a countercurrent deodorization column minimizes side reactions and allows the deodorization temperature to be raised without generating unwanted by‐products such as trans‐isomers and/or oligomers of unsaturated fatty acids. The increased deodorization temperature increases the vapor pressure of the pure volatiles and leads to further savings in stripping medium and motive steam. Countercurrent deodorization systems therefore require less energy than cross‐flow deodorization systems and/or produce oil with fewer unwanted by‐products.