Day 1 Mon, December 10, 2018最新文献

{"title":"Fluid Contact Identification for a Heavy Oil Shaly Sand Reservoir with a Biodegraded Oil Column","authors":"Fathiya Battashi, A. Khattak, R. Svec","doi":"10.2118/193716-MS","DOIUrl":"https://doi.org/10.2118/193716-MS","url":null,"abstract":"\u0000 This paper reviews the fluid contact analysis of the Marmul Gharif South Rim (MM GSR) heavy oil field in the South of the Sultanate of Oman. The field is highly compartmentalized by several faults into 17 blocks in total with a large variation in well density within those blocks. The reservoir in this field is the shaly-sand Gharif formation, in which the Middle and Lower Gharif are separated from each other by either a paleosol or competent shale. The hydrocarbon in these sands has an observed viscosity variation as a function of height above free water level (HAFWL) due to biodegradation. This variable viscosity has been observed in a large number of oil samples with higher viscosity close to the oil-water contact (OWC). The sands tend to be vertically discontinuous in the wells, so that direct observation of the OWC on logs is very rare, causing most well logs to yield only water up to (WUT) or oil down to (ODT). Accurate pressure gradients are difficult to obtain due to the low density contrast of heavy oil against the fresh formation water. Consequently, the OWC is not readily identified in certain blocks. This has resulted in either over-estimating oil volumes when substituting WUT or under-estimating volumes when substituting ODT in specific blocks of the field. In addition these cases also result in a lack of reliable constraints for estimating high and low case oil contacts.\u0000 \u0000 \u0000 A viscosity based approach was used to overcome gaps in the fluid contacts data-set and provide essential information for future field development. The approach utilizes the viscosity data in each block to determine representative base case contact along with shallow and deep cases. The results of this analysis were confirmed by production data and are consistant with the ODTs from horizontal wells.\u0000 The resulting fluid contact is then used as an input to the saturation height function which is used later as an input to calculate in-place volumes.\u0000 \u0000 \u0000 \u0000 Viscosity based contact provides a more robust fluid contact definition in areas where traditional methods resulted in data gaps. The paper presents a detailed methodology of this approach.\u0000 \u0000 \u0000 \u0000 The results of this work are an essential component of optimizing the understanding of the fluid contact in the field, which helps to develop the field efficiently by drilling the oil producers and water injectors in more optimum locations.\u0000","PeriodicalId":202774,"journal":{"name":"Day 1 Mon, December 10, 2018","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-12-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125084897","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Evaluation of Surfactants Wettability Alteration Using the Washburn Contact Angle Method","authors":"A. Fuseni, Badr H. Al-Zahrani, Ammar J. Al-Shehri, A. Alsofi","doi":"10.2118/193751-MS","DOIUrl":"https://doi.org/10.2118/193751-MS","url":null,"abstract":"\u0000 Changes in crude oil wetting of carbonate rock when treated with various surfactants was evaluated using the Washburn method by the sorption of crude oil into packed rock powders. This method served to circumvent the difficulties of direct contact angle measurements on rock-chips where the low interfacial tension between the crude oil and surfactant leads to the spreading and eventual escape of the oil droplet without being attached to the rock chip.\u0000 Four surfactants were used in the study including an anionic alfa olefin sulfonate, a cationic quaternary ammonium salt, an amphoteric surfactant and a nanosurfactant. Rock powders from a carbonate rock with a mesh size between 80 and 100 were coated with the tested surfactant solutions and compacted in a sample holder for the sorption experiments. Crude oil was raised to the bottom of the powder pack and allowed to rise into the powder by capillarity. A sensitive balance was used to measure the mass of crude oil imbibing into the powder until imbibition ceased. A plot of the square of oil mass against time enabled calculation of the contact angle using the modified Washburn equation. Earlier, a sorption experiment using n-hexane was used to deduce the rock constant for the grain packing, which was necessary for calculation of the crude oil contact angle.\u0000 The contact angle results demonstrated the surfactant solution's efficiency in altering the crude-oil wetting behavior. An increasing washburn contact angle through coating indicates that the carbonate rock is rendered less oil-wet, which implies better oil displacement. At ambient temperatures, the nanosurfactant gave the highest contact angle implying the least oil-wetting; in second place was the amphoteric surfactant. The anionic surfactant had little effect on oil-wetting while the cationic surfactant decreased oil-wetting to a lesser extent. At higher temperatures, the nanosurfactant maintained its superior effectiveness followed by the cationic and amphoteric surfactants. The anionic surfactant saw little change.\u0000 The use of sorption to obtain contact angle of crude oil for rock surfaces treated with surfactants eliminates the difficulties associated with direct contact angle measurements for low and ultra-low surfactant solutions where attachment an oil-droplet is almost impossible. With the Washburn method rapid evaluation of surfactants ability to change rocks wettability can be made to better guide further evaluations of such processes. As the washburn method measures contact angle between solids and a liquid surrounded by air, the contact angles obtained are not to be interpreted directly as those obtained in a liquid-liquid environment.","PeriodicalId":202774,"journal":{"name":"Day 1 Mon, December 10, 2018","volume":"151 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-12-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121989994","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Spatial Distribution of Clay Minerals in the Neogene Sediments of North Kuwait and its Impact on Thermal Production","authors":"P. Mishra, Khalid Ahmad, Jassim Al Khandari","doi":"10.2118/193711-MS","DOIUrl":"https://doi.org/10.2118/193711-MS","url":null,"abstract":"\u0000 Clay minerals are commonly observed in the Neogene succession of North Kuwait, both in the two viscous oil rich sandstone reservoirs (S1, S2) and intervening shale layers. SEM and XRD analysis of the core samples explain that Smectite is the dominant and Palygorskite, Illite and Kaolinite as minor clay mineral constituents. The paper describes the vertical and lateral distribution of these minerals in different sedimentary facies from bottom to top and the impact of steam on them.\u0000 The bottom and second channel-dominated sand and intervening shale (S2B sand, S2 Shale, S2A sand) layers show variation in total average clay content, as well as the swelling clay (smectite, illite-smectite) and fibrous palygorskite, with a low content in the north and center (2-4.6%), a moderate content in the east (6.7-7.3%) and a high content in the south (11.2-14.4%).\u0000 The Middle shale layer (MShale), is recognized as a flooding surface, observed at base of muddy interdistributory bay/lagoonal or floodplain deposits, sharply overlaying the channel-filled sandstones. Smectite –Illite is the dominant clay constituent.\u0000 The first channel-dominated sand and intervening shale (S1B sand and S1 Shale) layers contain predominantly smectite, illite-smectite and palygorskite content. The northern, southwestern and southeastern parts of the field, with more argillaceous channels and floodplain facies associations, have a high average total clay content (9.6-20%). The central part of the field, which is predominantly contains clean channel sand bodies, has a lower, average total clay content (4.9-12.6%).\u0000 The topmost sand (S1A sand) layer contains higher proportion of muddier channels and interdistributary bay facies, in the northern part and has high (>7%) total clay content, but generally <2% swelling clays and palygorskite. The central part of the field, with clean channel sands, has relatively low (<7%) total clay content, with 0.8-3.2% swelling clays and palygorskite. The southern part of the field, with argillaceous channels, has a relatively high (>7%) total clay content, with 2.2-6.3% swelling clays and palygorskite.\u0000 The sealing Cap Shale (bound by maximum flooding surface at the base and an erosive surface at the top) comprises of marine and restricted marine shales capping the underlying S1A sandstones. The clay mineral comprises of illite-smectite, kaolinite and chlorite, with no palygorskite content,\u0000 As this viscous oil is planned to be produced by thermal applications, Clay stabilization experiments were conducted to ascertain the permeability reduction in the reservoir due to swelling of clay minerals and changes after exposure to steam. The steam flood experiments are conducted at 32, 65 and 232°C on actual core plugs and the conversion of Illite-smectite to smectite was observed, reducing the permeability. Chemical stabilizers were suggested for controlling these damaging effects at higher temperature.","PeriodicalId":202774,"journal":{"name":"Day 1 Mon, December 10, 2018","volume":"144 6","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-12-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114029845","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Resolving Contract Mangement Challenges in Research Collaboration Agreements","authors":"S. Chaturvedi","doi":"10.2118/193742-MS","DOIUrl":"https://doi.org/10.2118/193742-MS","url":null,"abstract":"\u0000 \u0000 \u0000 Research and innovation have become necessary for sustainability and profitability in Oil and Gas industry in present times. Oil and Gas Companies (Companies) have established procedures and contract templates for commercial contracts. Research Collaboration Agreements (Agreements) have very different requirements and pose Contract Management challenges. This paper deals with the resolution of such challenges.\u0000 \u0000 \u0000 \u0000 In process of developing this paper, a number of Research Collaboration Agreements have been studied with respect to their (i) objectives, (ii) Research Collaborators Concerns, (iii) Research Collaborator's business model and expectation from the Agreement (iv) major issues which contradict with the Oil and Gas Company's contract templates and procedures and (v) mutually acceptable resolution to various issues.\u0000 Based on the study, this paper has been developed to systematically analyse the issues and share the successful strategies and mutually acceptable provisions of the Agreement.\u0000 \u0000 \u0000 \u0000 In commercial contracts, we deal with conventional contractors. In Research Collaboration agreements, contractors are Research Collaborators. The Research Collaborators have unique requirements, which are different from conventional contractors. They have different business models, pricing expectations, legal sensitivity and risk tolerance capabilities.\u0000 Further, the Research Collaboration Agreements need to be flexible in terms of scope of services, contract period, resource requirements, payment methods etc., so that the researchers can exploit even their intermediate and unforeseen findings to arrive at meaningful outcome. This is in contrast to conventional contracts, which have definitive requirements.\u0000 While required flexibility needs to be built-in the Agreements, the Company needs to ensure that it has suitable controls in the Agreement to ensure value for its investment.\u0000 In course of time, contracting strategies and Agreement provisions have been developed to:build up flexibility in the Agreements without deviating from basics of contract management andaddress the unique requirements of Research Collaborators without compromising the objectives and control of Oil and Gas companies.\u0000 Efforts have been made by the author to share the resolution of contract management challenges through contracting strategies and contract provisions, developed for Research Collaboration Agreement.\u0000","PeriodicalId":202774,"journal":{"name":"Day 1 Mon, December 10, 2018","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-12-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131757938","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Non-Equilibrium Interactions Between Heavy Oil and Liquid Propane","authors":"K. Athar, M. Yassin, H. Dehghanpour","doi":"10.2118/193770-MS","DOIUrl":"https://doi.org/10.2118/193770-MS","url":null,"abstract":"\u0000 In this study, we use a custom-designed visual cell to investigate nonequilibrium interactions between liquid propane (C3(1)) and a heavy oil sample (7.2°API) at 55°C. The heavy oil sample is taken from Clearwater Formation located in Western Canadian Sedimentary Basin (WCSB). We inject C3(1) into the visual cell containing the heavy oil sample (pressure buildup process) and allow the injected C3(1) to interact with the oil sample (soaking process). After the pressure buildup process, we observe three phases in the visual cell: 1) heavy oil (0.67 mol), 2) liquid C3 (C3(1),0.60 mol), and gaseous C3 (C3(g), 0.20 mol). We measure visual-cell pressure and observe the C3-heavy oil interactions during the pressure buildup and soaking processes. Nonequilibrium interactions occurring at the interfaces of C3(1)-heavy oil and C3(1)-C3(g) are recorded over time.\u0000 The results show that complete mixing of heavy oil with C3(1) occurs in two stages. First, upward extracting flow of hydrocarbon components from bulk heavy oil phase toward C3(1) phase form a distinguished layer (L1) during the soaking process. The extracted oil components become denser over time and move down (draining flows) towards the C3(1)-heavy oil interface due to gravity. The gradual color change of L1 from colorless to black suggests the mixing of hydrocarbon components from heavy oil. After L1 becomes homogenous, a second layer (L2) is formed at the upper part of the bulk C3(1) phase (above L1). Extracting and draining flows becomes active once again, leading to mixing of oil components from L1 into L2. At equilibrium condition, heavy oil and C3(1) are completely mixed and form a single homogenous phase.","PeriodicalId":202774,"journal":{"name":"Day 1 Mon, December 10, 2018","volume":"24 14","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-12-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132275105","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Identification of Field-Wide Well Performance Enhancement Strategies in a Heavy Oil Field in Northern Kuwait Using Parametric Analysis Techniques","authors":"J. G. Garcia, A. Kharghoria, A. Al-Rabah, J. Montero","doi":"10.2118/193795-MS","DOIUrl":"https://doi.org/10.2118/193795-MS","url":null,"abstract":"\u0000 Production in a green, heavy oil field in Northern Kuwait with limited production history is in a fast track delivery to increase production in the short term. A fast but insightful evaluation was required to identify field-wide productivity enhancement opportunities needed to increase oil production. A parametric analysis methodology was applied to a \"typical well\" to first obtain the factors that limit the well's production thorough understanding of the overall well potential, to finaly identify inflow and outflow enhancement opportunities.\u0000 Nodal analysis based on Darcy inflow model was utilized and multiple sensitivities were run for parameters prevoisuly identified. The parameters were expanded in value considering possible technical solutions applicable but not limited to: completion and perforation design, artificial lift performance and surface equipment, in order to determine technical limits applicable for each parameter using a combination of proven and novel technologies.\u0000 The parametric analysis helped to identify inflow and outflow enhancement opportunities (from the sand face to the separator), including but not limited to: well stimulation, re-perforation, pump efficiency and back pressure reduction. The range of the theoretical oil rate improvement identified from the analysis was from 20 to 50%. Based on the model results, additional resources were alloactred for a more detailed validation and study work using simulation. The parametric modeling approach was subsequently crosschecked on individual well reviews, where detailed inflow and outflow evaluations were conducted resulting in good agreement in terms of value in production gains.\u0000 The applied methodology showed to be a valid and fast track approach, readily to identify field-wide production issues and opportunities, particularly at the start of field production. The results obtained from this study provide a comprehensive approach to understand how well design, engineering decisions and field operational practices will impact well productivity. The methodology can be easily replicated by engineers in similar fields.","PeriodicalId":202774,"journal":{"name":"Day 1 Mon, December 10, 2018","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-12-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115518649","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Laboratory Experimental Study on New Polymer in Xinjiang Lukeqin High Temperature and High Salt Reservoir","authors":"M. Wang, Q. Xiao, Y. Gou, Frank Deng, B. Wang, D. Zhang","doi":"10.2118/193649-MS","DOIUrl":"https://doi.org/10.2118/193649-MS","url":null,"abstract":"\u0000 The Lukeqin Triassic reservoir in Xinjiang, China, is a heavy oil reservoir with high temperature and high salinity. The formation conditions are harsh. With the deepening of oilfield development, the reservoir enters into a high water cut period and faces the problem of stable oil and water control in the middle and late stage of development. In addition, the heavy oil reservoir has complex characteristics, such as deep, thin, thick and so on, so it can not be converted to conventional thermal recovery mode. Therefore, a solution to the reservoir conditions is urgently needed. In order to improve the mobility ratio of water drive, a new type of high temperature resistance and high salinity polymer SWP322 has been developed. In this study, the compatibility, viscosity, temperature resistance, salt resistance and shear resistance of the polymer in Lukeqin reservoir were evaluated and compared with that of HPAM. Finally, the formation conditions of Lukeqin reservoir are simulated to test the percolation and oil displacement ability of the new polymer SWP322 under the conditions of high temperature and high salinity. Experiments show that the polymer has a temperature resistance of 100°C and a salinity resistance level of 2.0×105 mg/L. The experimental results show that the polymer SWP322 has a lower dissolution rate at room temperature than HPAM, but its temperature resistance, salt resistance, shear resistance, and temperature resistance are far better than those of HPAM. With the increase of temperature and salinity, the apparent viscosity of HPAM decreased rapidly, while SWP322 was almost independent of temperature and salinity, and the viscosity retention rate was more than 99%; at the same time, the viscosity retention rate of SWP322 after core shearing also reached 98.6%, which proves that SWP322 is superior to HPAM in its resistance to temperature and salt, and excellent shear resistance also helps to maintain the viscoelasticity of the polymer in the formation. Increase oil displacement efficiency. In terms of seepage capacity, the flow resistance of SWP322 is much better than that of HPAM, and the resistance coefficient and residual resistance coefficient are all more than 5 times that of HPAM; in the process of simulated oil displacement, the displacement efficiency of water flooding is 30.43%, while the flooding efficiency of first polymer flooding and subsequent water flooding is 16.6% higher than that of water flooding; the oil displacement efficiency of double-pipe polymer flooding is 13.19% higher than that of water flooding; the oil displacement efficiency of single tube and double tube flooding system is 16.1% and 23.2% higher than that of water flooding, respectively.","PeriodicalId":202774,"journal":{"name":"Day 1 Mon, December 10, 2018","volume":"171 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-12-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116004055","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Wellbore Trajectory Optimization Using Rate of Penetration and Wellbore Stability Analysis","authors":"A. Abbas, U. Alameedy, M. Alsaba, S. Rushdi","doi":"10.2118/193755-MS","DOIUrl":"https://doi.org/10.2118/193755-MS","url":null,"abstract":"\u0000 Drilling deviated wells is a frequently used approach in the oil and gas industry to increase the productivity of wells in reservoirs with a small thickness. Drilling these wells has been a challenge due to the low rate of penetration (ROP) and severe wellbore instability issues. The objective of this research is to reach a better drilling performance by reducing drilling time and increasing wellbore stability.\u0000 In this work, the first step was to develop a model that predicts the ROP for deviated wells by applying Artificial Neural Networks (ANNs). In the modeling, azimuth (AZI) and inclination (INC) of the wellbore trajectory, controllable drilling parameters, unconfined compressive strength (UCS), formation pore pressure, and in-situ stresses of the studied area were included as inputs. The second step was by optimizing the process using a genetic algorithm (GA), as a class of optimizing methods for complex functions, to obtain the maximum ROP along with the related wellbore trajectory (AZI and INC). Finally, the suggested azimuth (AZI) and inclination (INC) are premeditated by considering the results of wellbore stability analysis using wireline logging measurements, core and drilling data from the offset wells.\u0000 The results showed that the optimized wellbore trajectory based on wellbore stability analysis was compatible with the results of the genetic algorithm (GA) that used to reach higher ROP. The recommended orientation that leads to maximum ROP and maintains the stability of drilling deviated wells (i.e., inclination ranged between 40°—50°) is parallel to (140°—150°) direction. The present study emphasizes that the proposed methodology can be applied as a cost-effective tool to optimize the wellbore trajectory and to calculate approximately the drilling time for future highly deviated wells.","PeriodicalId":202774,"journal":{"name":"Day 1 Mon, December 10, 2018","volume":"137 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-12-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127344463","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Integrated Approach for Evaluation of Free Gas Distribution Assists in Improved Well Management Practices in a Northern Kuwait Heavy Oil Field","authors":"Pabitra Saikia, Saad Al-Rashdan, Fatma Taqi, Khalid Al-Dohaiem, A. Al-Rabah, A. Tyagi, P. Choudhary, Khalid Ahmad, A. Kharghoria, Satinder Malik, Ian Zhang, M. Cheers","doi":"10.2118/193721-MS","DOIUrl":"https://doi.org/10.2118/193721-MS","url":null,"abstract":"\u0000 Free gas along with heavy oil production affects the progressive cavity pump (PCP) performance. This necessitates the strategy to perforate away from the free gas zone. To be able to do this, it requires an integrated approach to evaluate and map the spread of the free gas accumulation in the field. The paper shall present how this resulted in improved well performance with less free gas interference.\u0000 The methodology included the understanding of the production data, sub-surface geology and petrophysics; reservoir heterogeneity and free gas presence from wireline logs, core data and isotope analysis of gas collected during mud-logging and creation of maps and cross-sections showing both vertical and aerial spread of free gas accumulation. This was then integrated with existing production and well management practices, along with numerical simulation results. Such in-depth analysis helps to bring significant changes in well completion strategy and is a vital contribution to the WRFM strategy.\u0000 Unlike in conventional fields where depth is more and buoyancy pressures are large, gas can easily displace oil to accumulate in structural highs, in shallow heavy oil fields, free gas accumulation is a result of combination of structural and stratigraphic entrapment process. Vertical migration and lateral migration of gas is likely restricted by non-reservoir facies. As a result a consistent gas-oil contact (GOC) may not be present across large distances. Gas oil contact separates heavy oil by possible structural spill point and lithological boundary, dipping from south to north. Structurally higher areas are prone to localized gas accumulation. The completion stand-off from the gas base has a direct correlation with gas production. So the well management and production practice is to increase the stand-off from gas base to top perforations in future wells and to perform gas shut-off job in current wells to avoid free gas production.\u0000 The novelty of the current approach is that it will proactively help in completion strategy to reduce future free gas production, subsequent loss in natural reservoir energy and maintain the oil production target.","PeriodicalId":202774,"journal":{"name":"Day 1 Mon, December 10, 2018","volume":"71 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-12-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126249309","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Study on the Characteristics of Production Performance and Steam Chamber of SAGD Considering Interlayer","authors":"Yun Xia, Shijun Huang, Xiao Chen, M. Cao, Lijie Yang","doi":"10.2118/193759-MS","DOIUrl":"https://doi.org/10.2118/193759-MS","url":null,"abstract":"\u0000 Steam assisted gravity drainage (SAGD) is widely applied in the exploitation of oil sand reservoirs, however, the development process is affected by complex geological conditions, wherein the interlayer has a great impact. Specifically, it has a great influence on heat and mass transfer of steam and on the effective flow of crude oil. For this reason, the characteristics of steam chamber and the production performance were investigated in detail to clarify the influence mechanism of interlayer.\u0000 In this paper, based on the reservoir parameters of Long Lake oil sands, a series of numerical simulations were conducted to study the characteristics of SAGD process with interlayers. First of all, the numerical simulation method was used to study the influence mechanism of interlayer on heat and mass transfer. Then, based on the above analysis, we reclassified the production stages. Finally, we completed a series of numerical simulations with different parameters of interlayer to determine the influence level of main factors.\u0000 The results of temperature profile show that the upper zone of the interlayer is mainly heated by heat conduction, whereas the area far from the interlayer is heated by the coupling effect of heat conduction and heat convection, hence, the steam chamber above the interlayer develops slower and the steam chamber in the area without interlayer develops faster. At the same time, it can be seen from the oil saturation profile that a dead oil zone is formed near the formation just above the interlayer. In addition, the production stage is no longer the classic \"three-stage\", due to the interlayer, the oil production rate is fluctuating, appearing peak production. Finally, we summarized the regular of the influence of each parameters and determined the main parameters, we considered the location, size, porosity, permeability, and thermal conductivity of interlayer comprehensively, the results show that the influence of thermal conductivity is smaller than other parameters.","PeriodicalId":202774,"journal":{"name":"Day 1 Mon, December 10, 2018","volume":"20 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-12-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121108334","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}