• The KSFM Journal of Fluid Machinery
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• v.19 no.3
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• pp.19-24
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• 2016

Oil sands are a mixture of sand, clay, and a high-viscosity petroleum called bitumen. Steam-Assisted Gravity Drainage (SAGD) is the most viable and environmentally safe recovery technology for extracting bitumen. It extracts the viscosity-lowered bitumen by high pressure, high temperature steam injected into the bitumen reservoir. The steam is produced at the Central Processing Facility (CPF). Typically, more than 90% of the energy consumed in producing bitumen are used to generate the steam. Fuels are employed in the process, which cause economic and environmental problems. This paper explores the retrofit of heat exchanger network to reduce the usage of hot and cold utilities. The hot and cold utilities are reduced respectively 6% and 37.3% which in turn resulted in 5.3% saving of total annual cost by improving the existing heat exchanger network of the CPF.

• Applied Chemistry for Engineering
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• v.25 no.1
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• pp.113-115
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• 2014

Lab scale simulated steam assisted gravity drainage (SAGD) process devices were used to investigate the effect of inorganic additives for the bitumen recovery from oil sand. An extra heavy oil similar with bitumen and 1.5 mm diameter of the glass bead instead of clay was mixed to simulate the oil sand. In addition, $FeO_X$ synthesized from the inorganic process was introduced as an inorganic additive for improving the recovery. Finally, the steam heat transfer rate of approximately 40% following the introduction of inorganic additives which also increased the recovery rate by about 30%.

• International Journal of Advanced Culture Technology
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• v.8 no.2
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• pp.260-269
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• 2020

The Steam Assisted Gravity Drainage (SAGD) process is an enhanced method to extract oil from bitumen which involves surface and central process facilities. This paper describes the Central Process Facilities (CPF) of SAGD and proposes several retrofit plans to the Heat Exchanger Network (HEN). In this approach, the process integration scheme is applied to estimate the energy saving in HENs, and various cases are modeled in favor of a commercial simulator. Throughout this work, a minimum approach temperature of 10℃ is assumed. The results reveal that, due to the HEN optimization using process integration, the heating and cooling duties can be reduced to 29.68MW and 1.886MW, respectively. Compared with the Husky case, all cases considered in this study indicate a potential reduction of at least 6% in total cost, including investment and operation costs.

• Economic and Environmental Geology
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• v.50 no.3
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• pp.225-238
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• 2017

In this study, two viable measures of mean length and cumulative thickness of sand layers as important spatial statistics responsible for optimal SAGD (Steam Assisted Gravity Drainage) location for oil sand development were compared. For the comparisons, various deposits composed of sand and clay media were realized using a geostatistical simulator and the extent of steam chamber is simulated using multiphysics numerical simulator (dualphase flow and heat transfer). Based on the spatial statistics of each realization and the corresponding size of simulated steam chamber, the representativeness of two candidate measures (cumulative thickness and mean length of permeable media) were compared. The results of the geostatistical and SAGD simulations suggest that the mean length of permeable media is better correlated to the size of steam chamber than the cumulative thickness. Given those two-dimensional results, it is concluded that the cumulative thickness of the permeable media alone may not be a sufficient criterion for determining an optimal SAGD location and the mean length needs to be complementarily considered for the sound selections.

• Applied Chemistry for Engineering
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• v.25 no.3
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• pp.262-267
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• 2014

SAGD (steam assisted gravity drainage) process is the most commonly used in-situ technology for the recovery of bitumen from oil sand. It was investigated that the effects of different additives on bitumen recovery rate from oil sand in SAGD process among many possible mechanisms studied throughout the study. Bitumen recovery from thin layer oil sand reservoirs was simulated by using an experimental SAGD apparatus with scale of 150:1. To improve the simulation accuracy of thin layer oil reservoir, we have attached geological model (GM). Oil sand was simulated by using a mixture of extra heavy oil and glass beads with a diameter of 1.5 mm. $CO_2$ was used as an additive and the evolution of steam chambers were closely monitored, and the effects of $CO_2$ as an additive was investigated. Two types of injection methods were tested; continuous ($cCO_2$-SAGD) and sequential interruption ($sCO_2$-SAGD) $CO_2$ injection. For the $sCO_2$-SAGD experiment, it was observed that the recovery rates and CSOR were efficiently improved control experiment from 60.2% to 69.3% and 7.1 to 6.0, respectively, whereas $cCO_2$-SAGD experiment decreased from 60.2% to 57.6% and 7.1 to 7.3.

• Journal of the Korean Society for Geothermal and Hydrothermal Energy
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• v.18 no.4
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• pp.12-21
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• 2022

Steam assisted gravity drainage(SAGD) is a process that drills well in the underground oil sands layer, injects hightemperature steam, lowers the viscosity of buried bitumen, and recovers it to the ground. Recently, direct contact steam generator(DCSG) is being developed to maximize steam efficiency for SAGD process. The DCSG requires high technology to achieve pressurized combustion and steam generation in accordance with underground pressurized conditions. Therefore, it is necessary to develop a combustion technology that can control the heat load and exhaust gas composition. In this study, process analysis of high-pressurized DCSG was conducted to apply oxygen enrichment technology in which nitrogen of the air was partially removed for increasing steam production and reducing fuel consumption. As the process analysis conditions, methane as the fuel and normal air or oxygen enriched air as the oxidizing agent were applied to high-pressurized DCSG process model. A simple combustion reaction program was used to calculate the property variations for combustion temperature, steam ratio and residual heat in exhaust gas. As a major results, the steam production efficiency of DCSG using the pure oxygen was about 6% higher than that of the normal air due to the reducing nitrogen in the air. The results of this study will be used as operating data to test the demonstration device.

• Korean Journal of Remote Sensing
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• v.38 no.2
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• pp.139-151
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• 2022

SAGD (Steam-Assisted Gravity Drainage) method is widely used for oil recovery in oil sands regions. The SAGD operation causes surface displacement, which can affect the stability of oil recovery plants and trigger various geological disasters. Therefore, it isimportant to monitor the surface displacement due to SAGD in the oil sands region. In this study, the surface displacement due to SAGD operations of the Athabasca oil sands region in Alberta, Canada, was observed by applying Permanent Scatterer Interferometric Synthetic Aperture Radar (PSInSAR) technique to the Sentinel-1 time series SAR data acquired from 2016 to 2021. We also investigated the construction and expansion of SAGD facilitiesfrom Landsat-7/8 time seriesimages, from which the characteristics of the surface displacement according to the oil production activity of SAGD were analyzed. Uplift rates of 0.3-2.5 cm/yr in the direction of line of sight were observed over the SAGDs and their vicinity, whereas subsidence rates of -0.3--0.6 cm/yr were observed in areas more than several kilometers away from the SAGDs and not affected by oil recovery activities. Through the analysis of Landsat-7/8 images, we could confirm that the SAGDs operating after 2012 and showing high oil production activity caused uplift rates greater than 1.6 cm/yr due to the subsurface steam injection. Meanwhile, very small uplift rates of several mm per year occurred over SAGDs which have been operated for a longer period of time and show relatively low oil production activity. This was probably due to the compression of reservoir sandstone due to continuous oil recovery. The subsidence observed in areas except for the SAGDs and their vicinity estimated to be a gradual land subsidence caused by melting of the permafrost. Considering the subsidence, it was expected that the uplift due to SAGD operation would be greater than that observed by the PSInSAR. The results of this study confirm that the PSInSAR can be used as an effective means for evaluating productivity and stability of SAGD in the extreme cold regions.

• 한국지구물리탐사학회:학술대회논문집
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• 2009.05a
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• pp.35-45
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• 2009

Reservoir Characterization (RC) using 3-D seismic attributes analysis can provide properties of the oil sand reservoirs, beyond seismic resolution. For example, distributions and temporal bed thicknesses of reservoirs could be characterized by Spectral Decomposition (SD) and additional seismic attributes such as wavelet classification. To extract physical properties of the reservoirs, we applied 3-D seismic attributes analysis to the oil sand reservoirs in McMurray formation, in BlackGold Oilsands Lease, Alberta Canada. Because of high viscosity of the bitumen, Enhanced Oil Recovery (EOR) technology will be necessarily applied to produce the bitumen in a steam chamber generated by Steam Assisted Gravity Drainage (SAGD). To optimize the application of SAGD, it is critical to identify the distributions and thicknesses of the channel sand reservoirs and shale barriers in the promising areas. By 3-D seismic attributes analysis, we could understand the expected paleo-channel and characteristics of the reservoirs. However, further seismic analysis (e.g., elastic impedance inversion and AVO inversion) as well as geological interpretations are still required to improve the resolution and quality of RC.

• The KSFM Journal of Fluid Machinery
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• v.19 no.3
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• pp.5-9
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• 2016

The purpose of this paper is to define criteria to be used as part of the engineering design for an oil sands plant equipped with the steam assisted gravity drainage process. In this effort, the oil treatment process of an oil sands plant on a pilot scale was focused for detailed investigation. The thermodynamic properties of the process fluid, which is mainly composed of bitumen and water, were estimated with the CPA model. The commercial tool aspen HYSYS was used for the analysis throughout this work along with the provided input data and some necessary assumptions. From the simulation results, the heat and mass balances for a 300 BPD plant were established in order to define standard data for its modular design. In particular, the basis of design for equipment size, heat transfer areas, capital cost and operation cost was extensively discussed.

• The Korean Journal of Petroleum Geology
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• v.14 no.1
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• pp.1-11
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• 2008

As conventional oil and gas reservoirs become depleted, interests for oil sands has rapidly increased in the last decade. Oil sands are mixture of bitumen, water, and host sediments of sand and clay. Most oil sand is unconsolidated sand that is held together by bitumen. Bitumen has hydrocarbon in situ viscosity of >10,000 centipoises (cP) at reservoir condition and has API gravity between $8-14^{\circ}$. The largest oil sand deposits are in Alberta and Saskatchewan, Canada. The reverves are approximated at 1.7 trillion barrels of initial oil-in-place and 173 billion barrels of remaining established reserves. Alberta has a number of oil sands deposits which are grouped into three oil sand development areas - the Athabasca, Cold Lake, and Peace River, with the largest current bitumen production from Athabasca. Principal oil sands deposits consist of the McMurray Fm and Wabiskaw Mbr in Athabasca area, the Gething and Bluesky formations in Peace River area, and relatively thin multi-reservoir deposits of McMurray, Clearwater, and Grand Rapid formations in Cold Lake area. The reservoir sediments were deposited in the foreland basin (Western Canada Sedimentary Basin) formed by collision between the Pacific and North America plates and the subsequent thrusting movements in the Mesozoic. The deposits are underlain by basement rocks of Paleozoic carbonates with highly variable topography. The oil sands deposits were formed during the Early Cretaceous transgression which occurred along the Cretaceous Interior Seaway in North America. The oil-sands-hosting McMurray and Wabiskaw deposits in the Athabasca area consist of the lower fluvial and the upper estuarine-offshore sediments, reflecting the broad and overall transgression. The deposits are characterized by facies heterogeneity of channelized reservoir sands and non-reservoir muds. Main reservoir bodies of the McMurray Formation are fluvial and estuarine channel-point bar complexes which are interbedded with fine-grained deposits formed in floodplain, tidal flat, and estuarine bay. The Wabiskaw deposits (basal member of the Clearwater Formation) commonly comprise sheet-shaped offshore muds and sands, but occasionally show deep-incision into the McMurray deposits, forming channelized reservoir sand bodies of oil sands. In Canada, bitumen of oil sands deposits is produced by surface mining or in-situ thermal recovery processes. Bitumen sands recovered by surface mining are changed into synthetic crude oil through extraction and upgrading processes. On the other hand, bitumen produced by in-situ thermal recovery is transported to refinery only through bitumen blending process. The in-situ thermal recovery technology is represented by Steam-Assisted Gravity Drainage and Cyclic Steam Stimulation. These technologies are based on steam injection into bitumen sand reservoirs for increase in reservoir in-situ temperature and in bitumen mobility. In oil sands reservoirs, efficiency for steam propagation is controlled mainly by reservoir geology. Accordingly, understanding of geological factors and characteristics of oil sands reservoir deposits is prerequisite for well-designed development planning and effective bitumen production. As significant geological factors and characteristics in oil sands reservoir deposits, this study suggests (1) pay of bitumen sands and connectivity, (2) bitumen content and saturation, (3) geologic structure, (4) distribution of mud baffles and plugs, (5) thickness and lateral continuity of mud interbeds, (6) distribution of water-saturated sands, (7) distribution of gas-saturated sands, (8) direction of lateral accretion of point bar, (9) distribution of diagenetic layers and nodules, and (10) texture and fabric change within reservoir sand body.