• Korean Journal of Digital Imaging in Medicine
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• v.16 no.1
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• pp.13-19
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• 2014

Purpose: FLAIR image is beneficial for the diagnosis of various bran diseases including ischemic CVS, brain tumors and infections. However the border between the legion of brain metastasis and surrounding edema may not be clear. Therefore, this study aims to investigate the practical benefits of delayed imaging by comparing the image from a patient with brain metastasis before a contrast enhancement and the image 10 minutes after a contrast enhancement. Materials and methods: Of the 92 people who underwent MRI brain metastases in suspected patients 13 people in three patients there is no video to target the 37 people confirmed cases, and motion artifacts brain metastases in our hospital June-December 2013, 18 people measurement position except for the three incorrect patient (male: 11 people, female: 7 people, average age: 60 years) in the target, test equipment, 3.0T MR System (ACHIEVA Release, Philips, I was 8ChannelSENSE Head Coil use Best, and the Netherlands). TR 11000 ms, TE 125 ms, TI2800 ms, Slice Thickness 5 mm, gap 5 mm, is a Slice number 21, the parameters of the 3D FFE, T2 FLAIR variable that was used to test, TR 8.1 ms, TE 3.7 ms, Slice number 240 I set to. The experiment was conducted by acquiring the FLAIR prior to contrast enhancement (heretofore referred to as Pre FLAIR), and acquiring the 3D FFE CE five minutes after the contrast enhancement, and recomposing the images in an axial plane of S/T 3mm, G 0mm (heretofore referred to as MPR TRA CE). Using the FLAIR 10 minutes after the contrast enhancement (heretofore referred to as Post FLAIR) and Pi-View, a retrospective study was conducted. Using MRIcro on the image of a patient confirmed for his diagnosis, the images before and after the contrast media, as well as the CNR and SNR of the MPR TRA CE images of the lesion and the site absent of lesion were compared and analyzed using a one-way analysis of variance. Results: CNR for Pre FLAIR and Post FLAIR were 34.35 and 60.13, respectively, with MPR TRA CE at 23.77 showing no significant difference (p<0.050). Post-experiment analysis shows a difference between Pre FLAIR and Post FLAIR in terms of CNR (p<0.050), but no difference in CNR between Post FLAIR and MPR TRA CE (p>0.050), indicating that the contrast media had an effect only on Pre FLAIR and Post FLAIR. The SNR for the normal site Pre FLAIR was 106.43, and for the lesion site 140.79. Post FLAIR for the normal site was 107.79, and for the lesion site 167.91. MPR TRA CE for the normal site was 140.23 and for the lesion site 183.19, showing significant difference (p<0.050), and post-experiment analysis shows that there was a difference in SNR only on the lesion sites for Pre FLAIR and Post FLAIR (p<0.050). There was no difference in SNR between the normal site and lesion site for Post FLAIR and MPR TRA CE, indicating no effect from the contrast media (p>0.050). Conclusions: This experiment shows that Post FLAIR has a higher contrast than Pre FLAIR, and a higher SNR for lesions, It was not not statistically significant and MPR TRA CE but CNR came out high. Inspection of post-contrast which is used in a high magnetic field is frequently used images of 3D T1 but, since the signal of the contrast medium and the blood flow is included, this method can be diagnostic accuracy is reduced, it is believed that when used in combination with Post FLAIR, and that can provide video information added to the diagnosis of brain metastases.

• 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.