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In this paper, a standard air-cooled high-density storage system is reengineered to demonstrate the use of single-phase immersion cooling. The storage system consists primarily of seventy-two hard drives, two single socket nodes, two SAS expander cards, NIC and a power distribution board in a 4OU form factor. It is successfully demonstrated that the storage systems can be designed to support single phase immersion cooling while supporting hot swap and cooling redundancy requirement like an air-cooled system. In an air-cooled system, temperature gradient between the drives was as high as 19°C. The drives placed at the front of the system received cooler air while the drives placed in the rear received preheated air thus resulting in a temperature gradient. The drives used for the study were 20GB Helium filled sealed drives. For immersion cooling, seventy-two drives were cooled in parallel with temperature variance of less than 3°C. The other system components such as CPU, DIMMs, SAS chip and NIC had sufficient thermal margin. It was demonstrated that the system can operate reliably for facility coolant supply temperature as high as 40°C. The resulting power consumption of the pump was less than five percent of the total IT power. In addition, the proposed cooling solution may help mitigate acoustic vibrational issues for drives often encountered in air-cooling solution. The solution is virtually silent in operation.

The Vapor Extraction (Vapex) process and its many hybrid variants have attracted a great deal of attention as potentially less energy intensive alternatives for exploiting heavy oil and bitumen resources. However, despite much work over the past two decades, uncertainty remains about the basic mechanisms, the scaling aspects and the most appropriate methods of numerically simulating these processes. This paper offers some insights into several of these outstanding questions. The questions are examined in the context of an extensive and well-documented set of Vapex experiments carried out by Maini and his colleagues over the past 10 years. We have experimented with different methods of simulating these experiments using a physics-based reservoir simulator. Despite the high permeability (greater than 200 Darcys in all of the experiments), we find that capillary pressure plays a significant role in the drainage. The simulations suggest that most of the drainage takes place in the capillary transition zone along the edge of the vapor chamber, rather than in the single-phase zone ahead of it which has not yet been contacted by vapor. It has been emphasized in the literature that the near-linear scaling of oil rate with height observed in the experiments is dramatically different from the square root of height dependence predicted by the original analytic model of Vapex. However, the experiments also show an increasing solvent fraction in the produced oil phase as height increases. When this "solvent mixing" effect is separated out of the rates, the remaining height dependence is less than linear, though still greater than square root of height. The relative roles of molecular diffusion and mechanical dispersion in Vapex have been widely discussed in the literature. Generally, mechanical dispersion is expected to play a larger role in these high permeability experiments (vis-à-vis the field), due to larger fluid velocities. We present a method of inferring the diffusion/dispersion present in the simulations, despite a hidden component of numerical dispersion caused by the numerical method itself. We find that the experiments are well matched with values of diffusion and dispersion in line with literature correlations, and that the contribution of mechanical dispersion is perhaps not as large relative to that of molecular diffusion as might be expected. The paper also provides some thoughts on questions we believe are still unanswered, including mechanisms behind the height dependent mixing phenomenon and the scaling of the experimental results to the much greater heights and lower permeabilities characteristic of the field.

Summary A proper and effective startup of the steam-assisted-gravity-drainage (SAGD) well pairs, where both horizontal wells inject steam, is a key parameter to SAGD performance. In the past, a number of investigations have been conducted on the optimum startup strategy and operational procedures; however, fewer studies have modelled the heat requirements of the process. This study proposes an effective practical method that correlates the heat flux inside the horizontal wellbore with the temperature outside the wellbore wall. A transient conductive-heat-transfer equation in a cylindrical coordinate system is adopted for two different startup strategies: (a) variable heat flux (steam circulation in the well pair) to maintain a constant desired temperature at the wellbore wall and (b) constant heat flux (electrical heating of the well pair) to gradually increase temperature and finally reach a desired temperature on the wellbore wall. A novel and simple mathematical technique is presented for each startup approach to evaluate the instantaneous and cumulative heat requirements to keep the wellbore hot. Excellent agreements between the results of the proposed techniques and outputs of a commercial reservoir simulator are demonstrated. Accurate quantitative evaluation of heat requirements for the startup phase of SAGD enables optimum planning for steam requirements and practical design of any other heat sources employed in the process.

Summary In earlier work (Pathak et al. 2010, 2011), we presented the initial results for heavy-oil and bitumen recovery using heated solvent vapors. The heavy-oil- and bitumen-saturated sandpack samples of different heights were exposed to heated vapors of butane or propane at a constant temperature and pressure for an extended duration of time. The produced oil was analyzed for recovery, asphaltene content, viscosity, composition, and refractive index. Recovery was found to be very sensitive to temperature and pressure. The current work was undertaken to better understand the physics of the process and to explain the observations of the earlier experiments using additional experiments on tighter samples of different sizes, numerical simulation, and visualization experiments. The effects of temperature and pressure on the recovery were studied using a commercial reservoir simulator. Propane and butane were used as solvents. Asphaltene precipitation was also modeled. A qualitative history match with the experiments on different porous-media types was achieved by mainly considering the permeability reduction caused by asphaltene precipitation; pore plugging; the extent of interaction between the solvent and oil phases; and parameters such as model height, vertical permeability, and gravity. The effect of asphaltene deposition on models of varying permeabilities was also studied. To investigate the phenomenon further, visualization experiments were performed. 2D Hele-Shaw models of different dimensions were constructed by joining two Plexiglass sheets from three sides, or in some experiments, from all sides. The models were saturated with heavy oil and left open on one side (or all sides) and were exposed to different types of solvents. The setup was monitored continuously to observe fluid fronts and asphaltene precipitation. By use of this analysis, the mechanics of the process was clarified from the effect of solvent type on the recovery process. The optimum operating temperature for the hot-solvent process and the dominant mechanisms were identified. The dynamics of the asphaltene deposition and its effect on oil recovery were clarified through visual and numerical models.

Shanghai in the late nineteenth and early twentieth centuries was home to communities and musicians from all parts of the world. Among the over 20,000 Russians living there, a significant population of musicians contributed to the musical life of the city, particularly the Conservatory of Music founded in November 1927. This article reveals an overlooked phase of musical exchange between China and the West by 1) tracing the context and early development of the Conservatory; 2) identifying and discussing the activities of the Russian pedagogues (including Boris Zakharov, Vladimir Shushlin, and Sergei Aksakov amongst others) and their more notable Chinese students’ (including Li Delun, Ding Shande, Wu Leyi, and Yi Kaiji amongst others) reaction to them; 3) assessing the role that Russians played in the affairs of the Conservatory; and 4) demonstrating how Russian pedagogues influenced the development of Western classical music in China through their students’ notable achievements.

Thermal and miscible methods are commonly used for in situ recovery of heavy oil and bitumen. Both techniques have their own limitations and benefits. However, these methods can be combined by co-injecting solvent with steam or injecting solvent into a pre-heated reservoir. The current work was undertaken to study the performance of solvents at higher temperatures for heavy oil/bitumen recovery. Glass bead packs and Berea sandstone cores were used in the experiments to represent different types of pore structures, porosity and permeability. After saturating with heavy oil, the samples were exposed to the vapor of paraffinic solvents (propane and butane) at a temperature above the boiling point of the solvent, and a constant pressure of 1500 kPa. A mechanical convection oven was used to maintain constant temperature across the setup. The setup was designed in such a way that a reasonably long sample (up to 30 cm) can be tested to analyze the gravity effect. The oil recovered from each of these experiments was collected using a specifically designed collection system and analyzed for composition, viscosity and asphaltene content. The final amount of oil recovered in each case (recovery factor but not extraction rate) was also analyzed and the quantity and nature of asphaltene precipitated with each of the tested solvents under the prevailing temperature and pressure of the experiment was reported. Optimal conditions for each solvent type were identified for the highest ultimate recovery. It was observed that recovery decreased with increasing temperature and pressure of the system for both solvents, and that the best results were found when experimental temperature is only slightly higher than the saturation temperature of the solvent used. It was also noticed that butane diluted the oil more than propane which resulted in lower asphaltene content and viscosity of oil produced with butane as a solvent.

Summary A new strategy for heavy oil recovery is identified for layered reservoirs, where hydraulic restrictions or barriers to vertical flow separate adjacent oil-saturated strata. Passive heat conduction from a thermal operation in one layer is used to preheat bitumen in the adjacent strata. Once preheated, the oil properties within the adjacent strata are favourably conditioned to either primary production or the effective in-situ application of solvents. This strategy permits greater thermal efficiency for heat either applied or generated within the reservoir, producing a higher recovery and access to otherwise uneconomic pay intervals. A key insight in the passive heating assisted recovery method (PHARM) process is that the reservoir is preheated without the introduction of a secondary working fluid for heat transfer. To the exploitation of the secondary zone, this forms something of an ideal situation. In thermal, solvent-assisted or pure solvent applications, a means of heating heavy oils is essential to an economically effective process. Commonly, heat is introduced to the formation directly by means of a preheated working fluid. Working fluids, such as steam or condensing solvents, carry related costs, design restrictions and potential productivity impairment limitations with their application. If heat otherwise lost from an offsetting thermal process, or in-situ heat generated from waste fuel in offsetting strata, can be harnessed, the desired bitumen heating can be achieved independent to the introduction of an in-situ working fluid for heat transfer. Limitations inherent to the cycling of a working fluid for heat transfer are consequently overcome. As an example, the PHARM strategy can be applied within the bitumen-saturated Grosmont formation, per the geological stratification within Laricina's Saleski project. Here, the Upper Grosmont C and D strata are separated by a regional marlstone, which, in areas forming a vertical hydraulic flow restriction, does not constitute a thermal barrier. Thermal processes in either layer will passively heat the adjacent strata by conduction. The preheated bitumen layer, rather than presenting a process heat loss, can now be more effectively exploited. The inherent advantage permits incremental bitumen volumes to be accessed at a markedly reduced CSOR equivalent. For a steam assisted gravity drainage (SAGD) process, a generic example provided illustrates an overall CSOR reduction from 3.2-2.5 for primary drainage, with potential system CSOR reductions below two with the application of solvents. Solvents further permit access to a significantly lower-permeability reservoir where the host rock below 100 md may be resourced.

Summary This paper describes the application of a genetic algorithm to the development of a solvent-additive SAGD process. A review of related field projects and key simulation studies is provided, together with a discussion of the pros and cons of potential alkane solvents. Economics and the impact of dynamic and ultimate retention are discussed. A general conclusion drawn from literature is that optimal solvent application to SAGD will likely involve time variations in both rate and composition of the solvent. This results in an optimization problem that has a large number of dimensions, and is nonlinear. We have found genetic algorithms, which mimic biological evolution, have been found to be extremely effective in addressing such problems. The general methodology of application to solvent additives by Laricina Energy Ltd. is described. A key product of this effort, optimized for a simple clastic reservoir, is presented. The genetic algorithm produced an operable process, which could be described as a new combination of preexisting concepts. The process offers material improvements in thermal bitumen supply costs, as well as recovery factor. Major reductions in the physical steam/oil ratio (SOR), (and therefore) capital intensity and carbon emissions, are indicated.

Summary The majority of steam assisted gravity drainage (SAGD) development to date has been concentrated in the McMurray formation in the Eastern Athabasca fairway. More recently operators have identified projects with considerable resources located in shoreface sands of the Grand Rapids formation in the Wabasca area. Laricina Energy's Germain thermal project in Grand Rapids has associated basal water underlying much of the reservoir. In this paper the authors show that SAGD can be configured to maximize bitumen recovery for such reservoirs, based on laboratory and new simulation studies. The result is a SAGD configuration where the producers are placed at the base of porosity, within the basal water zone.

Abstract The last few years have seen the end of the Athabasca land play and the revival of interest in Alberta's bitumen resources in carbonate reservoirs. Of these, the Grosmont Formation is the most promising in terms of resource size and concentration. It is also the best known, in terms of having been the subject of several in situ pilots operated in the late '70s and early '80s. The data recorded from these early pilots is priceless in terms of having a touchstone of reality for new process concepts. On the other hand, the interpretations written in those days ('before gravity') are not necessarily as helpful. This paper looks at the Grosmont in terms of facts and fundamentals, and presents the case for Grosmont exploitation. There is good evidence that the Grosmont has very high bulk permeability as a result of karst porosity development and fracturing. This bodes well for the use of modern gravity drainage methods in the Grosmont. Introduction Grosmont Piloting History The Grosmont Formation in north-central Alberta is a dolomitized, karsted and fractured platform carbonate containing a massive bitumen accumulation. An excellent historical summary of various Grosmont pilots was recently provided by Alvarez et al.(1) Cyclic Steam Stimulation (CSS), steam drive and forward combustion were all attempted in the Grosmont during the '70s and '80s. CSS was the most widely and successfully piloted method. The best well, at 10A-5-88-19W4, recovered about 100,000 bbls of oil over 10 cycles, with a cumulative steam-oil ratio (CSOR) of about 6. Results of other tests were mixed, as were the operating procedures; most of these were based on horizontal flooding concepts. However, responses to well-executed CSS first cycles were reasonably similar at a number of widely-spaced wells. Notably, steam injectivity was generally sufficient so that a few hundred tonnes/day could be injected at pressures that were significantly below overburden pressure (ruling out geomechanical enhancement of permeability). A degree of pessimism, or at least great caution, has been expressed with respect to the supposed complexity of the reservoir, and hence, prospects for commercial recovery. In particular, it is often said that the reservoir is very heterogenous, and that this explains the historical failure of attempted steam drive and fire flood processes. Review of the Unocal Buffalo Creek and McLean scheme reports(2, 3) suggest that much of this originates in the interpretations of the contemporary operators, who largely explored conventional EOR concepts involving horizontal displacement. They expected to recover oil by means of horizontal, radial flow. When this failed, it was natural to assume that the problem lay in a failure to maintain the 'radial' part of the prescription, due to permeability heterogeneity. Figure 1 presents the performance of the Buffalo Creek 10A-5 CSS test in perspective with a contemporary test and two modern-day, commercially-optimized CSS wells (the data is publicly available from the Alberta Energy Resources Conservation Board). It can be seen that the Grosmont well had comparable performance to a Clearwater CSS test of the same vintage.

This article examines the British Broadcasting Corporation's broadcasting of contemporary art music during the 1960s and early 1970s. Particular reference is made to the ideas and activities of William Glock, controller of music at the BBC from 1959 to 1973, contemporary composers whose music the BBC either neglected or championed during this period because of the idiom in which they composed, and Glock's controversial legacy. Setting Glock's ideas and activities in a historical and philosophical context provokes reflection on aspects of music and broadcasting history, and provides a case study in two aesthetic assumptions which dominated the three decades after the Second World War: change is preferable to stability, and novelty guarantees value. Doing so also helps explain why the labels ‘contemporary’ and ‘avant-garde’ became indistinguishable during the 1960s, and the logic by which more traditional but still contemporary works were excluded from programmes devoted to twentieth century music.

Solvent-additive processes (SAP) are a promising, but challenging technology. Perhaps the biggest challenge from an engineering point of view, is that simulators probably work some of the time, but not all of the time; and there is no information about where the line between occurs, or what the correct answer should be, after the line is crossed. Other serious problems are the many degrees of freedom in SAP process design, and the non-linear relationships between process inputs and economic results. There are too many possible designs to try randomly for even a single reservoir, and there is limited theory to interpolate or scale available experimental data. This paper attempts to assemble some known pieces of the puzzle, and to explore how they may fit together to explain and predict SAP performance characteristics First, some familiar PVT relationships are presented, with examples using temperature as the independent variable. This helps to clarify the choice of solvent, as a function of reservoir pressure, and also to understand the effect of the increasing solvent "dose". It is shown that SAP will create a double front, one where the water is condensed, and a second where the solvent is absorbed by, and drains with, the oil. A vapor blanket separates the two fronts. Secondly, simple estimates are given for the temperature distribution in the vapor blanket (i.e. solvent-active zone). Together with PVT data for the same pressure, these allow the thickness of a vapor blanket to be estimated. Finally, SAP mass transport limits are considered, by observing that the second front essentially constitutes VAPEX. The Butler-Mokrys theory is discussed, in view of its failure to predict certain experimental results; it is argued that this results from neglect of capillary pressure effects, which in fact are dominant at the front. A purely empirical correlation by Nenniger is introduced, which can be rearranged to predict the maximum solvent speed, also as a function of temperature.

With the decrease in conventional oil and gas reserves throughout the world and an ever-increasing demand for fossil-fuel based energy and resulting high oil prices, focus has been shifting to unconventional and heavy oil and bitumen. Grosmont carbonates in Northern Alberta have been estimated to contain at least 300 billion barrels of heavy oil or bitumen. However, recovering this oil is extremely difficult because of the complexity associated with carbonate reservoirs in general, e.g., the Grosmont unit is known to possess a triple porosity system – matrix, fractures and vugs, based on core studies. The second problem is the fluid itself, which is highly viscous bitumen, immobile at reservoir conditions. To extract this bitumen from very heterogeneous carbonate rock, both heat and dilution using solvents may be needed. This paper reports the results and analysis of hot solvent experiments conducted on original Grosmont carbonate cores. Three experiments were conducted using propane and one using butane as solvent. After heating the entire system containing the core sample, solvent gas was injected. The rock was allowed to soak in the hot solvent for a long time. The experimental temperature and pressure were decided on the basis of the results of our earlier work that suggested to be just above the saturation line of the particular solvent.. An attempt was made to keep the conditions close to the saturation conditions of the solvent being used to maximize the dilution and hence, the recovery. The oil produced was analyzed for viscosity and asphaltene content. The results in terms of recovery, the degree of dilution and upgrading achieved suggested that butane was a better solvent for this bitumen. Finally, the optimum conditions for operation of the hot solvent process were verified for Grosmont carbonates.

Many authors have published effects of Non Condensable Gas (NCG) injection during steam assisted gravity drainage (SAGD) operation, on one hand it provides an insulation blanket to the steam chamber and avoids heat loss to the over burden and improves the economics of the project, but on the other hand it can stall the steam chamber growth in the middle of high pay zone, provided the reservoir has high solution gas. All the commercial simulators predict the accumulation of the gas blanket ahead of steam front. However, field operations have proved that the NCG are produced along with bitumen and water and doesn't accumulate, but simulators are unable to predict the right amount when it comes to history matching and accurate predictions. This paper is focused on numerically findings of the gas transport mechanism in the SAGD operations. Many possible mechanisms were considered and found that most of the commercial simulators lack the function of gas production due to viscous liquid drag, which contributes a lot towards gas production especially during early years of SAGD. Solubility exclusion of the two major NCG i.e. CO2 and CH4 in both water and oil phases is another reason for under-estimating the gas production. Along with the above two mechanisms, interestingly, the constraints on the production wells in the simulators also account for a great deal of NCG production. Now instead of using a fraction of GOR, simulation engineers can include the complete GOR of the Alberta bitumen reservoirs to history match and predict the correct amount of bitumen and gas production.

Abstract A recent field test of the Steam Assisted Gravity Drainage (SAGD) process at the Alberta Oil Sands Technology Research Authority (AOSTRA) Underground Test Facility (UTF) has proven that the process mechanisms work in the field as expected from previous laboratory, analytical, and numerical work. The UTF test used well pairs that were completed for only about 5 m, however, as compared to lengths of several hundred metres which will be required for commercial application. Accordingly, the UTF Phase B test currently under construction will use wells with a full 500 m of completion. This paper reviews the design and operating requirements that have been developed to ensure that the full lengths of the Phase B well pairs contribute to bitumen recovery, i.e. that the production rates will scale up in proportion to length. The discussion proceeds from the conditions required to initiate drainage at a given location along the well pair, to the means of establishing and maintaining such conditions at every location. Numerical examples show that, for typical formation permeabilities, start-up can be achieved with thermal conduction and gravity alone, two highly predictable phenomena. This leads to consideration of design and operational requirements to ensure that conduction heating is maintained on the one hand, and gravity is not defeated (by adverse pressure gradients) on the other. In summary these are:the well pairs must be drilled so that the interwell spacing remains within specific tolerances;the liner and tubing must be large enough, relative to the completion length and expected formation productivity, so that pressure gradients are kept below certain values, anda full length tubing string must be combined with correct operating policy to ensure that the full lengths of both injection and production liners are kept hot throughout the life of the well. Introduction Butler et al(1), and Edmunds et al(2) have previously described the mechanics of two dimensional SAGD to a pair of horizontal wellbores. The recent Phase A test of SAGD at the AOSTRA UTF(3) showed that the process mechanisms work in the field as expected from previous laboratory, analytical, and numerical work. Phase A well pairs were completed for only about 55 m, however, whereas economic commercial application requires several hundred metres of active completion. AOSTRA is accordingly proceeding with a Phase B Test of three long well pairs, with 500 m completed length. In a reservoir of immobile bitumen, fluid mobility must be artificially FIGURE 1: Three dimensional start-up of a long well pair. created between a well pair before SAGD can proceed. With reference to Figure 1, it should be easy to force communication between an injector and producer over at least one section of a long well pair, but it is less clear how the remainder of the pair can be made to follow in a reasonable time, say a few months. Long delays will incur very significant economic penalties; not only will the Calendar Day Oil Rate (CDOR) be reduced, but also, because a longer time will be required to recover the same amount of oil, the Stearn/Oil Ratio (SOR) will be increased.

Thermal and miscible methods are commonly used for in-situ recovery of heavy oil and bitumen. Both techniques have their own limitations and associated shortcomings, often times yielding an inefficient process. The most common thermal method is steam injection, which is highly energy intensive. Steam generation costs and water production affect the economics of the thermal technique adversely. On the other hand, miscible methods are energy effective but their economics depends on the solvent retrieval. Various combinations of these two techniques such as co-or alternate injection of steam and solvent have been proposed as a solution, but no optimum method has yet been developed. Thermal and miscible methods can be combined by co-injecting solvent with steam or injecting solvent into a pre-heated reservoir. Current work was undertaken to study the performance of solvents at higher temperatures for heavy oil/bitumen recovery. Glass bead packs and Berea sandstone cores were used in the experiments to represent different types of pore structures, porosity and permeability. After saturating with heavy oil, the samples were exposed to the vapor of paraffinic solvents (propane and butane) at a temperature above the boiling point of the solvent, and a constant pressure of 1500 kPa. A mechanical convection oven was used to maintain constant temperature across the setup. The setup was designed in such a way that a reasonably long sample (up to 30 cm) can be tested to analyze the gravity effect. The oil recovered from each of these experiments was collected using a specifically designed collection system and analyzed for composition, viscosity and asphaltene content. The amount of oil recovered in each case was also analyzed and the quantity and nature of asphaltene precipitated with each of the tested solvents under the prevailing temperature and pressure of the experiment was reported. Optimal conditions for each solvent type were identified for the highest ultimate recovery. It was observed that recovery decreased with increasing temperature and pressure of the system. It was also noticed that butane diluted the oil more than propane which resulted in lower asphaltene content and viscosity of oil produced with butane as a solvent.

As a result of the October Revolution, the ideas and activities that had been confined to an artistic, intellectual, or aristocratic minority, became overnight the property of the masses. In September 1918, the musicologist and educationalist Nadezhda Bryusova spelt out the role of music in the new society 'Music should give a capacity to live and a capacity to build life'.1 Led by the musical departments of Narkompros (the Ministry of Education and Culture) and Proletkul't (the proletarian cultural-education organizations), concerted efforts were made to break down the barriers between professional musicians, composers, and the general public. Attempts were also made to raise the standards of musical knowledge amongst the new audience. However, it soon became apparent that there was a need for a new breed of composer who was in tune with the desires and aspirations of the new society. A group of politically-minded composers which soon fell into this category was formed at the Moscow Conservatory in January 1925 as a result of a competition to compose a work commemorating the first anniversary of Lenin's death. That group was known as Prokoll, an abbreviation of Proizvodstvennii kollektiv (Production Collective). The specific aims of Prokoll were firstly 'to search for new musical forms consonant with the times and based on the achievements of past and present musical culture', and secondly 'to create new mass musical forms (marches, mass songs, placards, and others) designed for mass performance'.2 The founding members of the group included Aleksandr Davidenko, Genrikh Bruk, Boris Shekhter, Viktor Belyy, Sergey Ryauzov, Marian Koval', Nikolay Chemberdzhi, and Zara Levina. By the time the group had disbanded in April 1932, several of its founding members had joined the like-minded Russian Association of Proletarian Musicians (RAPM). But they were

Abstract This paper summarizes evidence of gas effects in several Athabasca SAGD projects and shows that these effects can be easily reproduced with simple 1D column simulations. Solution gas probably has a material impact on SAGD rise, and therefore production rates in general, especially where the operating pressure is significantly below the initial pressure. Introduction Following the UTF Phase A SAGD test, it was reported that: "No significant accumulations [of non-condensable gas] were observed in the steam chamber. This was fortunate because such accumulations appear to be harmful because they inhibit steam transport to the front. " "Current simulators incorrectly predict that even small amounts of gas???will accumulate in a steam chamber and substantially impair drainage???more work is required to account for gas transport mechanisms adequately so that reasonable predictions can be made for reservoirs containing greater amounts of gas(1). " Simulators still do not properly account for known amounts of solution gas in the McMurray formation in the sense that it is not generally possible to produce a reasonable history match of field behaviour if the full amount of solution gas is included(2). The question of how the gas is being removed from the chamber, and therefore what is missing from the simulators, remains unresolved, and is beyond the scope of this paper. Meanwhile, two important points have been passed over. The first is that, even at UTF, some insignificant gas accumulations can be found in the data, for example as reported by Ito et al.(3). The second is that "reservoirs containing greater amounts of gas " than UTF or Dover, include most of the current McMurray SAGD projects. In the case of Foster Creek, at the deep end, saturation pressure is 2,800 kPa and the solution GOR is estimated to be about five times that of Dover. Since the gas removal mechanism(s) is unknown, it has always been possible that it was strong enough under UTF circumstances to prevent "significant " accumulations, but not strong enough to do this in deeper Athabasca reservoirs. However, the difficult nature of the SAGD gas problem, combined with the apparent success of UTF history matching without it, has understandably encouraged a situation where it has become standard practice to ignore solution gas in SAGD simulations. Standard practice is also to arbitrarily lower absolute and/or relative permeabilities in order to match field performance. In the case of the UTF project, there was good correspondence between measured core and history match permeabilities using "open " relative permeabilities. This correspondence does not seem to apply to deeper, thicker reservoirs such as Surmont or Foster Creek, particularly with respect to steam rise rates. Field Evidence Hangingstone Ito et al.(3,4) conducted detailed analyses and history matching of observation well temperature data from the UTF Phase B and Hangingstone Phase I projects. Although the Hangingstone situation is complicated by the high operating pressure of 5 MPa at a depth of 280 m (i.e. 18 kPa/m, which they demonstrated by cold water injection was enough to begin deformation of the sand matrix), it show anomalies in the rise rates at some wells where steam rise would "suddenly stop " for a while and then resume.

Introduction During the recent Surmont gas-over-bitumen Alberta Energy and Utilities Board (EUB) hearing, a number of technical issues regarding the optimum operating pressure for steam assisted gravity drainage (SAGD) schemes were raised(1). From the evidence presented, the EUB concluded that there was a detrimental effect on SAGD recovery with decreasing gas pool pressure. The objective of this paper is to present technical and practical evidence of what is the most economical optimum operating pressure for a SAGD project in northeast Alberta. We believe that the effect of operating pressure on SAGD recovery has been misunderstood, and that economics will in fact drive SAGD producers to develop low pressure recovery technology over time, regardless of the presence or status of contiguous gas caps. We first present historical evidence that the high recoveries associated with SAGD will remain so at very low pressures. Secondly, analytical predictions of oil rate and steam-oil ratio (SOR) vs. pressure are considered. Finally, the effects of pressure on full-cycle scheme design and economics are calculated, based on simulation studies typical of oil sands reservoirs in northeast Alberta. The results support an economic optimum SAGD pressure in the range of 300 – 900 kPa. Historical Steam Assisted Gravity Drainage Experience and developed in Alberta. In reality, although Alberta may have been the first horizontal well application of SAGD technology, there are other examples of SAGD projects using vertical wells. In California, this has normally been referred to as steam flooding; but in a large number of those fields, gravity drainage has been a dominant recovery mechanism in comparison to other mechanisms, such as steam drag, steam drive, solution gas drive, thermal expansion, and steam distillation. Steam assisted gravity drainage in these fields has resulted in average oil recoveries exceeding 50% and as high as 85% OOIP(2–4). An example is the Kern River field in California, one of the largest steam floods in the world. The formation depth varies from 300 – 1,400 ft. (90 – 430 m), initial reservoir pressure is 50 – 140 psig (345 – 965 kPag), oil gravity varies from 9 – 16 °CDATA [API, porosity is 35% and permeability varies from 1,000 – 7,600 mD(4, 5). At Kern River, the primary production recovery ranged from 10 – 13% OOIP, but steam flood recovery ranges from 43 to 73 % of the pre-steam oil in place. Most importantly, the normal operating steam zone pressure during infill drilling was measured to be 6 psia (180 kPaa)(2). Another successful field example reported steam zone pressure of 40 psia (275 kPaa)(2). It is the combination of very high recoveries and very low pressures which makes the case for gravity dominance in these cases; there are really no other plausible candidate mechanisms. The low operating pressures also give a clue as to the economics of low pressure gravity drainage: apparently, the operators consider the additional steam capacity they would require to raise the pressure to be an unattractive investment. Greaser and Shore(5) reported on a number of steam flooding expansion projects in the Kern River field.

Abstract World-wide experience indicates that thermal methods are the only effective methods for the in-situ recovery of heavy oils. Furthermore, the steady progress within horizontal well technology increases the applicability of thermal methods in conjunction with horizontal wells. The steam-assisted gravity drainage (SAGD) process is the prominent example of the synergism of horizontal wells with steam injection. The major portion of the dollar per barrel operational cost for steam injection is currently attributed to the generation of steam and water handling requirements. In the future, more stringent environmental regulation might further prohibit the use of water for the recovery of heavy oils. Naptha is present at the site as a diluent for pumping and pipe line transport of the produced heavy oil. The injection of naptha vapour instead of water vapour combines an effective thermal process with the diluent mechanism of the naptha. We present the results of simple analytical calculations, demonstrating the applicability of naptha-assisted gravity drainage (NAGD) compared to the SAGD process. Numerical simulations have been performed on a two-dimensional cross section perpendicular to the horizontal well pair. We discuss in detail the reservoir mechanisms present during NAGD. For the conditions studied naptha circulation rates are some 14 times the bitumen production rate. Evaluation of the process shows that it will be economic with naptha recycling and by minimising the naptha remaining in the reservoir. Introduction Heavy oil and bitumen resources can more than double the earth's hydrocarbon reserves. Unfortunately, most heavy oil and bitumen accumulations cannot be produced economically with current in situ recovery technology. Canada owns some 40 per cent of these unrecoverable resources. The emergence of horizontal wells allowed a larger reservoir exposure, which increases productivity, accelerates recovery, and reduces coning tendencies. For example, horizontal wells are used, at present, for the primary recovery of heavy oil and bitumen in Canada. The combination of thermal methods and horizontal wells for heavy oil recovery increases the potential for more economic operations. In the SAGD process, heat is injected in the form of saturated steam through a horizontal injector. The injector is located above and more or less parallel to a horizontal producer. The distance between the two is dictated by early-time communication considerations. The SAGD process has proven successful at the UTF site in Alberta, Canada. As shown at the UTF site, an optimised process demands that the wells are regulated in such a way as to let the drainage mechanism operate freely. Hence, fluids need to be produced when they arrive at the producer, and injection rates need to satisfy the heat demand of an expanding steam zone. At the same time, a liquid level has to be established above the producer to limit the production of steam. Butler has given a basic description of the SAGD process. P. 475