Sebastian Zavaleta, P. M. Adrian, Ricardo Marcelo Michel
Although various novel techniques were developed in reservoir engineering for estimation of hydrocarbons initially in place (HCIIP), conventional material balance still remains as one of the most reliable. Average reservoir pressure is critical input data for material balance, which is usually obtained by well shut-in. Nevertheless, this operation might be restricted due to economic and operational restrictions such as water production in gas wells. In contrast, daily production data is commonly available and can be used to calculate the HCIIP by applying any production data analysis techniques such as the Dynamic Material Balance (DMB) method. The application of such methods to volumetric gas reservoirs and naturally fractured reservoirs resulted in accurate and reliable estimations. However, for water drive gas reservoirs, where the water influx term should be introduced into the iterative process, research and field case applications are limited. This paper presents an extension to the DMB technique to water-drive gas reservoirs. A simultaneous estimation of the Original Gas-in-place (OGIP) and the water influx term is achieved by coupling the DMB technique with the Fetkovich aquifer model. Average reservoir pressure estimation can also be attained as a result of the coupled method. Results were validated by means of numerical simulation on a synthetic model and a field study case. Synthetic production data was generated by a commercial simulator and then analized with the coupled method. The calculated OGIP, water influx volumes and average reservoir pressure resulted comparable to simulator output as they presented a low relative error. Furthermore, application of the coupled method to the field study case yielded comparable results to those obtained by volumetric method.
{"title":"Estimation of OGIP in a Water-Drive Gas Reservoir Coupling Dynamic Material Balance and Fetkovich Aquifer Model","authors":"Sebastian Zavaleta, P. M. Adrian, Ricardo Marcelo Michel","doi":"10.2118/191224-MS","DOIUrl":"https://doi.org/10.2118/191224-MS","url":null,"abstract":"\u0000 Although various novel techniques were developed in reservoir engineering for estimation of hydrocarbons initially in place (HCIIP), conventional material balance still remains as one of the most reliable. Average reservoir pressure is critical input data for material balance, which is usually obtained by well shut-in. Nevertheless, this operation might be restricted due to economic and operational restrictions such as water production in gas wells.\u0000 In contrast, daily production data is commonly available and can be used to calculate the HCIIP by applying any production data analysis techniques such as the Dynamic Material Balance (DMB) method. The application of such methods to volumetric gas reservoirs and naturally fractured reservoirs resulted in accurate and reliable estimations. However, for water drive gas reservoirs, where the water influx term should be introduced into the iterative process, research and field case applications are limited.\u0000 This paper presents an extension to the DMB technique to water-drive gas reservoirs. A simultaneous estimation of the Original Gas-in-place (OGIP) and the water influx term is achieved by coupling the DMB technique with the Fetkovich aquifer model. Average reservoir pressure estimation can also be attained as a result of the coupled method.\u0000 Results were validated by means of numerical simulation on a synthetic model and a field study case. Synthetic production data was generated by a commercial simulator and then analized with the coupled method. The calculated OGIP, water influx volumes and average reservoir pressure resulted comparable to simulator output as they presented a low relative error. Furthermore, application of the coupled method to the field study case yielded comparable results to those obtained by volumetric method.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123557287","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}
L. Cassie, Elyes Yaich, Sidharth Singh, A. Kaasa, A. Jamankulov
A single well, satellite gas accumulation offshore North Trinidad exhibits a strong water drive mechanism and is in pressure communication with two neighbouring fields through a common aquifer. Monitoring and predicting the movement of the gas water contact (GWC) is critical to reservoir management and resources estimation. This paper is the culmination of a study that was conducted over a five-year period, analyzing high quality downhole pressure buildup data to track the GWC movement in the field. Analysis of late time boundary dominated flow regime in multiple time lapsed pressure derivatives indicated a movement in the gas-water phase boundary, believed to be the contact. Pressure transient analysis (PTA) enabled the translation of shifting pressure derivatives to alternate GWC contour realizations. These matched derivatives provided a quantitative estimation of the contours which were then converted to an equivalent contact radius. For both edge water or bottom water drive mechanisms, the equivalent contact radius was then correlated to the field's cumulative gas produced. Prediction of water breakthrough was done by estimating a range of contours arriving near the well and calculating the corresponding recoverable gas volume from the generated correlation. Multiple analytically derived functions were used to correlate the equivalent contact radius with the gas produced. A strong correlation was observed on regressing produced volumes with the interpreted contact radii. Due to inherent uncertainties with sweep efficiency, as a proxy, three idealized cases were defined for arrival of water close to the well to capture a low, mid and high scenario. Using these cases, water breakthrough was predicted to occur for produced volumes in the range of 58 Bscf to 70 Bscf, with a mid-case of 64 Bscf. In May 2015, actual water breakthrough occurred after 62 Bscf of production thus, strongly validating the robustness of the time lapse pressure derivative analysis study. For gas reservoirs supported by moderate to strong aquifer drive, we suggest this as a robust workflow independent of 3D numerical reservoir simulation to predict recoverable volumes and water breakthrough timing. The observation of contact movement for gas reservoirs connected through a common aquifer could have significant implications on the conventional understanding around such reservoirs and their optimum management strategy.
{"title":"Application of Time-Lapse Pressure Transient Analysis to Predict Gas Water Contact Movement and Water Breakthrough Time: Results from a Reservoir off the North Coast of Trinidad","authors":"L. Cassie, Elyes Yaich, Sidharth Singh, A. Kaasa, A. Jamankulov","doi":"10.2118/191186-MS","DOIUrl":"https://doi.org/10.2118/191186-MS","url":null,"abstract":"\u0000 A single well, satellite gas accumulation offshore North Trinidad exhibits a strong water drive mechanism and is in pressure communication with two neighbouring fields through a common aquifer. Monitoring and predicting the movement of the gas water contact (GWC) is critical to reservoir management and resources estimation. This paper is the culmination of a study that was conducted over a five-year period, analyzing high quality downhole pressure buildup data to track the GWC movement in the field. Analysis of late time boundary dominated flow regime in multiple time lapsed pressure derivatives indicated a movement in the gas-water phase boundary, believed to be the contact. Pressure transient analysis (PTA) enabled the translation of shifting pressure derivatives to alternate GWC contour realizations. These matched derivatives provided a quantitative estimation of the contours which were then converted to an equivalent contact radius. For both edge water or bottom water drive mechanisms, the equivalent contact radius was then correlated to the field's cumulative gas produced. Prediction of water breakthrough was done by estimating a range of contours arriving near the well and calculating the corresponding recoverable gas volume from the generated correlation.\u0000 Multiple analytically derived functions were used to correlate the equivalent contact radius with the gas produced. A strong correlation was observed on regressing produced volumes with the interpreted contact radii. Due to inherent uncertainties with sweep efficiency, as a proxy, three idealized cases were defined for arrival of water close to the well to capture a low, mid and high scenario. Using these cases, water breakthrough was predicted to occur for produced volumes in the range of 58 Bscf to 70 Bscf, with a mid-case of 64 Bscf. In May 2015, actual water breakthrough occurred after 62 Bscf of production thus, strongly validating the robustness of the time lapse pressure derivative analysis study.\u0000 For gas reservoirs supported by moderate to strong aquifer drive, we suggest this as a robust workflow independent of 3D numerical reservoir simulation to predict recoverable volumes and water breakthrough timing. The observation of contact movement for gas reservoirs connected through a common aquifer could have significant implications on the conventional understanding around such reservoirs and their optimum management strategy.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131394958","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}
In May 2015, ExxonMobil successfully brought in the Liza 1 wildcat well, 120 miles off the coast of the South American nation of Guyana in the Stabroek block, in the Guyana-Suriname basin. Prior to the Liza 1 success, there were 22 wells drilled by other companies, all of which proved to be non-commercial. ExxonMobil stated that recoverable reserves from the Liza field – Phase 1 development would be in the range of 0.8 – 1.4 billion barrels of oil equivalent. The Liza field is part of one of the most prospective basins in South America based on a US Geological survey report - the Guyana-Suriname basin. A representative model was created using Petrel, Wellplot Digitizer, PROSPER, CMG and Microsoft Excel and consists of eight (8) producers, three (3) gas injectors and six (6) water injectors as outlined in the ExxonMobil Phase 1 development plan. Simulation results indicate that over a twenty-five (25) year period approximately 456 MMSTB of oil and 3.5 TCF of gas, equivalent to 1.04 billion BOE will be recovered from the Liza Phase 1 development. Based on the Production Sharing Agreement between the Guyana government and ExxonMobil, an economic assessment was undertaken which quantifies the government share of revenues to be obtained from the Liza field – Phase 1 development. The variables in this economic evaluation included capital expenditure (CAPEX), oil and gas price, operational expenditure (OPEX), 2% royalty payment, cost recovery mechanism and 50% profit split to the Guyana government. Based on ExxonMobil estimated capital investment of $US 4.5 billion, an oil price of $US 50/bbl, gas price of $US 2.50/MMBTU and this project's projected operational expenses over the twenty five year period, total new revenue to Guyana over this period will amount to $US8.9 billion. It is also estimated that Guyana's share of the development cost will be paid back within six (6) years of commencement of production of the Liza field.
{"title":"Liza Field Development - The Guyanese Perspective","authors":"Keron Alleyne, L. Layne, M. Soroush","doi":"10.2118/191239-MS","DOIUrl":"https://doi.org/10.2118/191239-MS","url":null,"abstract":"\u0000 In May 2015, ExxonMobil successfully brought in the Liza 1 wildcat well, 120 miles off the coast of the South American nation of Guyana in the Stabroek block, in the Guyana-Suriname basin. Prior to the Liza 1 success, there were 22 wells drilled by other companies, all of which proved to be non-commercial. ExxonMobil stated that recoverable reserves from the Liza field – Phase 1 development would be in the range of 0.8 – 1.4 billion barrels of oil equivalent.\u0000 The Liza field is part of one of the most prospective basins in South America based on a US Geological survey report - the Guyana-Suriname basin. A representative model was created using Petrel, Wellplot Digitizer, PROSPER, CMG and Microsoft Excel and consists of eight (8) producers, three (3) gas injectors and six (6) water injectors as outlined in the ExxonMobil Phase 1 development plan. Simulation results indicate that over a twenty-five (25) year period approximately 456 MMSTB of oil and 3.5 TCF of gas, equivalent to 1.04 billion BOE will be recovered from the Liza Phase 1 development.\u0000 Based on the Production Sharing Agreement between the Guyana government and ExxonMobil, an economic assessment was undertaken which quantifies the government share of revenues to be obtained from the Liza field – Phase 1 development. The variables in this economic evaluation included capital expenditure (CAPEX), oil and gas price, operational expenditure (OPEX), 2% royalty payment, cost recovery mechanism and 50% profit split to the Guyana government.\u0000 Based on ExxonMobil estimated capital investment of $US 4.5 billion, an oil price of $US 50/bbl, gas price of $US 2.50/MMBTU and this project's projected operational expenses over the twenty five year period, total new revenue to Guyana over this period will amount to $US8.9 billion. It is also estimated that Guyana's share of the development cost will be paid back within six (6) years of commencement of production of the Liza field.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"76 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127362732","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}
Ren-yuan Sun, Ying Sun, Fan Kunkun, Shikai Yang, Qiao Mingquan, Wang Xuezhong, Yang Yuanliang
In order to develop the super-heavy oil reservoir with thin layer, low reservoir temperature and shallow depth in CF oilfield of China, a new technology of HDNS (Horizontal well, viscosity Depressant, Nitrogen and Steam) was proposed and a series of experiments were conducted and the factors effecting oil recovery factor were analyzed. The self-designed equipment, which includes the steam generation system, gas injection system, chemical injection system, the sand-parking sample system, the temperature-controlled system, the metering system of produced fluids and the data collecting system, was used for the experimental studies. Experiments shows that the displacement efficiency increases with the increase of the steam temperature and the injection rate of steam, but too high steam injection rate will decrease the displacement efficiency because of Steam channeling. Compared with steam huff and puff, the displacement efficiency of viscosity depressant assisted steam (DS) increases about 20% because of the thermal chemical effect. The viscosity depressant, N2 assisted steam huff and puff (DNS) can increase the displacement efficiency in about 18% by using the synergistic effects of viscosity depressant, N2 and steam. In the process of DNS stimulation, the viscosity depressant can reduce the viscosity of super heavy oil combined with the effect of steam, which is called as thermal chemical effect. The N2 can prevent the steam chanelling in the reservoir and decrease the heat loss in the process of steam stimulation. The DNS stimulation can effectively reduce the oil viscosity and the steam injection pressure, expand the steam sweep efficiency. By using this technology, Block X of CF oilfield has been successfully developed in these years.
{"title":"Experiment Studies on Horizontal Well - N2 - Viscosity Depressant - Steam Stimulation for Shallow Thin Super-heavy Oil Reservoirs","authors":"Ren-yuan Sun, Ying Sun, Fan Kunkun, Shikai Yang, Qiao Mingquan, Wang Xuezhong, Yang Yuanliang","doi":"10.2118/191252-MS","DOIUrl":"https://doi.org/10.2118/191252-MS","url":null,"abstract":"\u0000 In order to develop the super-heavy oil reservoir with thin layer, low reservoir temperature and shallow depth in CF oilfield of China, a new technology of HDNS (Horizontal well, viscosity Depressant, Nitrogen and Steam) was proposed and a series of experiments were conducted and the factors effecting oil recovery factor were analyzed. The self-designed equipment, which includes the steam generation system, gas injection system, chemical injection system, the sand-parking sample system, the temperature-controlled system, the metering system of produced fluids and the data collecting system, was used for the experimental studies. Experiments shows that the displacement efficiency increases with the increase of the steam temperature and the injection rate of steam, but too high steam injection rate will decrease the displacement efficiency because of Steam channeling. Compared with steam huff and puff, the displacement efficiency of viscosity depressant assisted steam (DS) increases about 20% because of the thermal chemical effect. The viscosity depressant, N2 assisted steam huff and puff (DNS) can increase the displacement efficiency in about 18% by using the synergistic effects of viscosity depressant, N2 and steam. In the process of DNS stimulation, the viscosity depressant can reduce the viscosity of super heavy oil combined with the effect of steam, which is called as thermal chemical effect. The N2 can prevent the steam chanelling in the reservoir and decrease the heat loss in the process of steam stimulation. The DNS stimulation can effectively reduce the oil viscosity and the steam injection pressure, expand the steam sweep efficiency. By using this technology, Block X of CF oilfield has been successfully developed in these years.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123773253","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}
Jonathan Ramnath, Elroi Felix, A. Shah, M. Soroush, Nykesi Omokughegbe, Francis Jaipaulsingh
Decreasing oil production and increasing quantities of greenhouse gases continue to be an issue plaguing Trinidad and Tobago's energy sector. While CO2 EOR has been proven to be an effective solution to both of these problems it is often overlooked in Trinidad due to the inability of the gas to achieve miscibility with the crude oil as well as operational limitations such as an absence of transportation pipelines for the CO2. Even though miscibility may not be achieved, immiscible CO2 EOR can effectively increase production and sequester CO2 resulting in an increase of revenue as well as decreasing the quantity of greenhouse gases vented to the atmosphere. This paper aims to highlight the possibility of implementing immiscible CO2 projects in Trinidad. The scientific processes that are responsible for increased crude oil production are discussed and the operational considerations for a safe and economically feasible project in Trinidad South West fields are examined. It was seen that the vaporizing gas drive process would not result in miscibility in the shallow low pressure fields of the South West Trinidad however it would cause a significant reduction in the interfacial tension, this in turn causes an increase in the capillary number which would result in additional oil recovery. It was also found that the high viscosity of the non-carbonated oil of the region would result in an even greater reduction in viscosity when it is mixed with the CO2 gas resulting in more favourable oil mobility. The high solubility of CO2 in hydrocarbon liquids result in the swelling of crude oil. In the water wet formations, the oil within the pore spaces swells, resulting in an increase of relative permeability aiding in additional oil recovery. In the field evaluated, it is proposed that the CO2 be acquired from Atlantic LNG, tube trailers be used to transport the CO2, 100mmscf of gas injected per day with a 5spot injection pattern and the produced gas compressed and reinjected. From simulation this was found to produce an additional 389,360bbls of oil where CO2 would be sequestered and an additional profit of US$ 21,414,800 would be acquired within a 20 year period.
{"title":"Determining the Feasibility of Immiscible CO2 EOR Projects in Trinidad's Mature Fields","authors":"Jonathan Ramnath, Elroi Felix, A. Shah, M. Soroush, Nykesi Omokughegbe, Francis Jaipaulsingh","doi":"10.2118/191220-MS","DOIUrl":"https://doi.org/10.2118/191220-MS","url":null,"abstract":"\u0000 Decreasing oil production and increasing quantities of greenhouse gases continue to be an issue plaguing Trinidad and Tobago's energy sector. While CO2 EOR has been proven to be an effective solution to both of these problems it is often overlooked in Trinidad due to the inability of the gas to achieve miscibility with the crude oil as well as operational limitations such as an absence of transportation pipelines for the CO2.\u0000 Even though miscibility may not be achieved, immiscible CO2 EOR can effectively increase production and sequester CO2 resulting in an increase of revenue as well as decreasing the quantity of greenhouse gases vented to the atmosphere. This paper aims to highlight the possibility of implementing immiscible CO2 projects in Trinidad. The scientific processes that are responsible for increased crude oil production are discussed and the operational considerations for a safe and economically feasible project in Trinidad South West fields are examined.\u0000 It was seen that the vaporizing gas drive process would not result in miscibility in the shallow low pressure fields of the South West Trinidad however it would cause a significant reduction in the interfacial tension, this in turn causes an increase in the capillary number which would result in additional oil recovery. It was also found that the high viscosity of the non-carbonated oil of the region would result in an even greater reduction in viscosity when it is mixed with the CO2 gas resulting in more favourable oil mobility. The high solubility of CO2 in hydrocarbon liquids result in the swelling of crude oil. In the water wet formations, the oil within the pore spaces swells, resulting in an increase of relative permeability aiding in additional oil recovery.\u0000 In the field evaluated, it is proposed that the CO2 be acquired from Atlantic LNG, tube trailers be used to transport the CO2, 100mmscf of gas injected per day with a 5spot injection pattern and the produced gas compressed and reinjected. From simulation this was found to produce an additional 389,360bbls of oil where CO2 would be sequestered and an additional profit of US$ 21,414,800 would be acquired within a 20 year period.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126543683","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}
The foamy extra-heavy oil reservoirs in the eastern Orinoco Belt, Venezuela with high initial dissolved gas oil ratio and flow ability in situ, have been exploited by the Cold Heavy Oil Production (CHOP) method, with recovery of only 8%-12% OOIP. SAGD has proved to be one of commercially active post-CHOP processes. Whereas during the SAGD process the dissolved gas as non-condensable gas accumulated at the edges of the steam chamber causes a resistance to heat transfer between steam and oil, thus slowing down growth of the steam chamber and oil recovery. Therefore a novel SAGD process using alternate imbalance operating-pressure (AIOP-SAGD) is studied for the purpose of improving foamy oil SAGD performance. The novel SAGD process involves multi SAGD well pairs, and with the growth of steam chambers, a significant pressure gradient is deliberately created between two steam injection wells. Moreover the higher and lower operation pressure of the two injection wells is periodically alternate. In this work, the potential evaluation and optimization of foamy oil AIOP-SAGD are studied, through extensive simulations utilizing a sector model, which is from a sector with representative oil and reservoir characteristics of Eastern Orinoco Belt, considering the mechanism of foamy oil and thermal recovery. Simulation results indicate that the AIOP-SAGD process shows significant improvement in oil recovery, at least 10% higher than traditional SAGD. The mechanism includes two aspects: firstly the pressure gradient between two adjacent SAGD well pairs brings a sweep of dissolved gas from steam chambers; secondly, based on the flow ability of foamy extra-heavy oil, the pressure gradient helps to exploit oil between two SAGD pairs which is typically difficult to be recovered with conventional SAGD. The optimization of operating parameters shows that the optimal start time of AIOP-SAGD is when the oil rate of SAGD reaches the peak and the steam chamber extends to the top of the reservoir. High steam quality helps improve the performance of AIOP-SAGD. Moreover the parameters of alternate time, imbalance time, imbalance pressure difference were optimized.
{"title":"Alternate Imbalance Operating-Pressure Process Improving SAGD Performance of Foamy Extra-Heavy Oil Reservoirs in the Eastern Orinoco Belt, Venezuela","authors":"Zhao-peng Yang, Xingmin Li, Heping Chen, Zhang-cong Liu, Yanyan Luo, L. Fang","doi":"10.2118/191156-MS","DOIUrl":"https://doi.org/10.2118/191156-MS","url":null,"abstract":"\u0000 The foamy extra-heavy oil reservoirs in the eastern Orinoco Belt, Venezuela with high initial dissolved gas oil ratio and flow ability in situ, have been exploited by the Cold Heavy Oil Production (CHOP) method, with recovery of only 8%-12% OOIP. SAGD has proved to be one of commercially active post-CHOP processes. Whereas during the SAGD process the dissolved gas as non-condensable gas accumulated at the edges of the steam chamber causes a resistance to heat transfer between steam and oil, thus slowing down growth of the steam chamber and oil recovery. Therefore a novel SAGD process using alternate imbalance operating-pressure (AIOP-SAGD) is studied for the purpose of improving foamy oil SAGD performance.\u0000 The novel SAGD process involves multi SAGD well pairs, and with the growth of steam chambers, a significant pressure gradient is deliberately created between two steam injection wells. Moreover the higher and lower operation pressure of the two injection wells is periodically alternate. In this work, the potential evaluation and optimization of foamy oil AIOP-SAGD are studied, through extensive simulations utilizing a sector model, which is from a sector with representative oil and reservoir characteristics of Eastern Orinoco Belt, considering the mechanism of foamy oil and thermal recovery.\u0000 Simulation results indicate that the AIOP-SAGD process shows significant improvement in oil recovery, at least 10% higher than traditional SAGD. The mechanism includes two aspects: firstly the pressure gradient between two adjacent SAGD well pairs brings a sweep of dissolved gas from steam chambers; secondly, based on the flow ability of foamy extra-heavy oil, the pressure gradient helps to exploit oil between two SAGD pairs which is typically difficult to be recovered with conventional SAGD. The optimization of operating parameters shows that the optimal start time of AIOP-SAGD is when the oil rate of SAGD reaches the peak and the steam chamber extends to the top of the reservoir. High steam quality helps improve the performance of AIOP-SAGD. Moreover the parameters of alternate time, imbalance time, imbalance pressure difference were optimized.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"52 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116927885","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}
Although Trinidad and Tobago has an abundant supply of relatively pure CO2 and more than 1 billion barrels of heavy oil deposits there are no active enhanced oil recovery (EOR) projects using carbon dioxide (CO2). In this paper, we have performed black oil simulation studies to evaluate several injection strategies with carbonated water, varying the salinity and viscosity of injected water. The salinity was varied by 1,000 and 35,000 ppm. The viscosity was increased by adding 0.1 weight percent polymer to injected water. The investigation was carried out using a commercial reservoir simulator. The simulation grid represents the properties of a quarter five-spot of the Lower Forest sand of the Forest Reserve Field. The reservoir simulation components used are water, polymer, H, Na, Cl-, dead oil, solution gas and CO2. The Stone #1 three-phase relative permeability model was used to calculate the three-phase relative permeabilities from two-phase data. In addition, a factorial experimental design was utilized and twelve simulation runs were done along with nine benchmark runs for comparison to other EOR methods. From the results obtained the following was concluded: water salinity has no effect on either oil recovery or carbon dioxide storage; polymer injection increases oil recovery and carbon dioxide storage. We found the optimal injection strategy to be a cycling of carbonated water alternating with polymer injection.
{"title":"Evaluation of the Effect of Water Salinity, Water Viscosity, and Injection Strategy on Heavy Oil Recovery and Carbon Dioxide Storage in the Forest Reserve Field, Trinidad","authors":"C. Dewan, Lorraine E. Sobers","doi":"10.2118/191167-MS","DOIUrl":"https://doi.org/10.2118/191167-MS","url":null,"abstract":"\u0000 Although Trinidad and Tobago has an abundant supply of relatively pure CO2 and more than 1 billion barrels of heavy oil deposits there are no active enhanced oil recovery (EOR) projects using carbon dioxide (CO2).\u0000 In this paper, we have performed black oil simulation studies to evaluate several injection strategies with carbonated water, varying the salinity and viscosity of injected water. The salinity was varied by 1,000 and 35,000 ppm. The viscosity was increased by adding 0.1 weight percent polymer to injected water. The investigation was carried out using a commercial reservoir simulator. The simulation grid represents the properties of a quarter five-spot of the Lower Forest sand of the Forest Reserve Field. The reservoir simulation components used are water, polymer, H, Na, Cl-, dead oil, solution gas and CO2. The Stone #1 three-phase relative permeability model was used to calculate the three-phase relative permeabilities from two-phase data. In addition, a factorial experimental design was utilized and twelve simulation runs were done along with nine benchmark runs for comparison to other EOR methods.\u0000 From the results obtained the following was concluded: water salinity has no effect on either oil recovery or carbon dioxide storage; polymer injection increases oil recovery and carbon dioxide storage. We found the optimal injection strategy to be a cycling of carbonated water alternating with polymer injection.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"16 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121611330","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}
Abdullah M. Al Moajil, M. Al-Khaldi, Hassan Hazzazi, S. Çalışkan
Drilling horizontal and highly permeable sandstone acid-sensitive reservoirs with oil based drilling fluids are normally followed by filter cake and associated organic sludge removal treatments. The acid or cleaning recipes should be compatible with the formation minerals, especially when losses are encountered. The objectives of this paper were to conduct a comprehensive evaluation of HCl/formic acid recipe to dissolve oil-based filter cake, characterize and dissolve associated organic sludges, and assess compatibility with highly permeable acid-sensitive sandstone core plugs. Filter press experiments were conducted to optimize the fluid recipe. Core flood testing was conducted on sandstone core plugs at 160°F. Compatibility with reservoir fluids were assessed using aging cells. TGA was used to identify organic/inorganic composition of sludge samples XRD and ESEM were used to characterize core plugs and sludge samples. ICP analysis was conducted to analyses effluent from coreflood experiments. GC and GC-MS analysis was conducted to identify and characterize sludge samples. Micro CT scan was used to assess the dissolution of rock minerals. The removal efficiencies of the oil-based filter cake were between 85-100% by weight using HCl/Formic acid recipe. The characterization of the sludge samples revealed the presence of mainly diesel. The inorganic compounds (50% by weight) were mainly quartz with small amounts of calcite, dolomite, kaolinite, microcline, and pyrite. Maximum solubility of nearly 60 wt% was achieved. Core flooding tests of the acid recipe indicated reduction in permeability of core plug. The coreflood effluent analysis indicated dissolution of mainly Ca, Fe, and Mg with small amounts of Al, Si, and Sr with indication of Si-based precipitation. No major indication of precipitation occured. ESEM and EDS spot analysis of the core plug particles showed the sample was comprised Si, O, Fe, S as the main constituents with small amounts of Al. XRD analysis of the core plug after coreflood testing showed the presence of mainly Quartz and small amounts of Microcline, Pyrite, and Palygorskite. The CT scan of core plug before/after coreflooding indicated the acid dissolved rock minerals. There was no clear indication of core damage or solids plugging.
{"title":"Acidizing Highly Permeable Sandstone Stringers: Drill-in Fluid Damage and Compatibility with Rock Minerals","authors":"Abdullah M. Al Moajil, M. Al-Khaldi, Hassan Hazzazi, S. Çalışkan","doi":"10.2118/191172-MS","DOIUrl":"https://doi.org/10.2118/191172-MS","url":null,"abstract":"\u0000 Drilling horizontal and highly permeable sandstone acid-sensitive reservoirs with oil based drilling fluids are normally followed by filter cake and associated organic sludge removal treatments. The acid or cleaning recipes should be compatible with the formation minerals, especially when losses are encountered. The objectives of this paper were to conduct a comprehensive evaluation of HCl/formic acid recipe to dissolve oil-based filter cake, characterize and dissolve associated organic sludges, and assess compatibility with highly permeable acid-sensitive sandstone core plugs.\u0000 Filter press experiments were conducted to optimize the fluid recipe. Core flood testing was conducted on sandstone core plugs at 160°F. Compatibility with reservoir fluids were assessed using aging cells. TGA was used to identify organic/inorganic composition of sludge samples XRD and ESEM were used to characterize core plugs and sludge samples. ICP analysis was conducted to analyses effluent from coreflood experiments. GC and GC-MS analysis was conducted to identify and characterize sludge samples. Micro CT scan was used to assess the dissolution of rock minerals.\u0000 The removal efficiencies of the oil-based filter cake were between 85-100% by weight using HCl/Formic acid recipe. The characterization of the sludge samples revealed the presence of mainly diesel. The inorganic compounds (50% by weight) were mainly quartz with small amounts of calcite, dolomite, kaolinite, microcline, and pyrite. Maximum solubility of nearly 60 wt% was achieved. Core flooding tests of the acid recipe indicated reduction in permeability of core plug. The coreflood effluent analysis indicated dissolution of mainly Ca, Fe, and Mg with small amounts of Al, Si, and Sr with indication of Si-based precipitation. No major indication of precipitation occured. ESEM and EDS spot analysis of the core plug particles showed the sample was comprised Si, O, Fe, S as the main constituents with small amounts of Al. XRD analysis of the core plug after coreflood testing showed the presence of mainly Quartz and small amounts of Microcline, Pyrite, and Palygorskite. The CT scan of core plug before/after coreflooding indicated the acid dissolved rock minerals. There was no clear indication of core damage or solids plugging.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116871101","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}
During oil production, when crude oil flows into a wellbore, pressure and temperature are reduced. The micelle structure of the crude oil is destabilized, allowing paraffin (wax) and/or asphaltene molecules to precipitate into the oil, increasing oil viscosity and allowing deposition in the well tubulars. This causes plugging of production and flow lines which decreases oil production. Wax deposition can be mitigated by the application of passive energy waves or a chemical solvent. Passive energy waves are generated by a tool containing a vibrating quartz and semi-precious metal core. This passive vibrational energy stabilizes the original micelle structure in oil and prevents wax deposition and viscosity changes. A chemical solvent is injected to dissolve and remove wax deposits. In this study, both methods of wax treatment were applied on a waxy oil well in Trinidad, to determine which was more effective and economical. An average oil production rate of 14.4 barrels of oil per day (bopd) was attained from chemical solvent injection and an average oil production rate of 13.4 bopd from passive energy wave application, resulting in cumulative oil volumes of 374 barrels and 349 barrels respectively. Oil inflow into the wellbore, or Productivity Index, increased significantly from pre-treatment conditions by factors of 10.4 with chemical solvent injection and 8.8 with passive energy wave application. From an analysis using profit per barrel of oil (Netback) economics, the total workover cost for passive energy application, including tool rental and installation costs, paid out in 58 days at an average production rate of 13.4 bopd. The total workover cost for chemical solvent injection, including chemical and injection equipment costs, paid out in 12 days at an average production rate of 14.4 bopd. Decline curve analysis showed that the historical production from the well followed an exponential decline model. This model was applied to production outputs resulting from both treatments and the analysis showed that the producing life of the well was altered by 19% with passive energy wave application and by 20% with chemical solvent injection. From oil sample testing, passive energy wave application caused an increase in oil API gravity from 22.5 to 28.8 °API and a decrease in oil viscosity from 439.1 to 23.7 centiPoise (cP). Production outputs and economics showed that chemical solvent injection was the more feasible wax treatment option for the waxy well studied. However, passive energy wave application was able to positively alter crude oil properties and showed notable success in preventing wax formation in this well.
{"title":"A Comparative Analysis of Two Methods of Wax Treatment for a Waxy Oil Well in Southwest Trinidad","authors":"N. Persad, R. Hosein, A. Jupiter","doi":"10.2118/191221-MS","DOIUrl":"https://doi.org/10.2118/191221-MS","url":null,"abstract":"\u0000 During oil production, when crude oil flows into a wellbore, pressure and temperature are reduced. The micelle structure of the crude oil is destabilized, allowing paraffin (wax) and/or asphaltene molecules to precipitate into the oil, increasing oil viscosity and allowing deposition in the well tubulars. This causes plugging of production and flow lines which decreases oil production. Wax deposition can be mitigated by the application of passive energy waves or a chemical solvent. Passive energy waves are generated by a tool containing a vibrating quartz and semi-precious metal core. This passive vibrational energy stabilizes the original micelle structure in oil and prevents wax deposition and viscosity changes. A chemical solvent is injected to dissolve and remove wax deposits.\u0000 In this study, both methods of wax treatment were applied on a waxy oil well in Trinidad, to determine which was more effective and economical. An average oil production rate of 14.4 barrels of oil per day (bopd) was attained from chemical solvent injection and an average oil production rate of 13.4 bopd from passive energy wave application, resulting in cumulative oil volumes of 374 barrels and 349 barrels respectively. Oil inflow into the wellbore, or Productivity Index, increased significantly from pre-treatment conditions by factors of 10.4 with chemical solvent injection and 8.8 with passive energy wave application. From an analysis using profit per barrel of oil (Netback) economics, the total workover cost for passive energy application, including tool rental and installation costs, paid out in 58 days at an average production rate of 13.4 bopd. The total workover cost for chemical solvent injection, including chemical and injection equipment costs, paid out in 12 days at an average production rate of 14.4 bopd.\u0000 Decline curve analysis showed that the historical production from the well followed an exponential decline model. This model was applied to production outputs resulting from both treatments and the analysis showed that the producing life of the well was altered by 19% with passive energy wave application and by 20% with chemical solvent injection. From oil sample testing, passive energy wave application caused an increase in oil API gravity from 22.5 to 28.8 °API and a decrease in oil viscosity from 439.1 to 23.7 centiPoise (cP). Production outputs and economics showed that chemical solvent injection was the more feasible wax treatment option for the waxy well studied. However, passive energy wave application was able to positively alter crude oil properties and showed notable success in preventing wax formation in this well.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"520 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123076877","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}
Y. Miao, Xiangfang Li, John W. Lee, Chaojie Zhao, Yunjian Zhou, Hang Li, Yucui Chang, Wenjing Lin, Zhihua Xiao, Nan Wu
In recent years, improving the accuracy of production forecast in unconventional reservoirs has been of growing interest to oil and gas industries. Decline curve analysis (DCA) models have been recognized as the most efficient and easiest approaches to estimate gas rate. However, fluid flow regime and well rate decline curves are highly affected by the geological properties of formations. Therefore, the selection of DCA models based on completion designs and geological properties of formations is important for production rate prediction. Traditional DCA methods, particularly Arps' decline model, was originally developed for predicting boundary dominated hydrocarbon well rate decline, which differs from the dominant long-duration transient flow regime in shale reservoirs. The Stretched Exponential model, the Duong model, the Arps model with a minimum terminal decline rate and the scaling method by Patzek were developed to match and forecast wells with transient flow followed by boundary dominated flow (BDF). In this paper, firstly we developed a new model to estimate production in shale gas reserviors by considering both Knudsen diffusion of bulk gas and surface diffusion of adsorbed gas based on the traditional equation of rate versus square-root-of-time. This proposed model can provide better fits to data in transient linear flow regimes. In addition, a systematic analysis of numerical simulation cases in CMG were performed to compare with the traditional model. The results demonstrated that, in most cases, our model which is demonstrated in this paper, provide more accurate estimation of reserves for numerically simulated cases compared with the traditional decline methods. Therefore, the work offers critical insights into evaluating production in shale gas reserviors in a more efficient way.
{"title":"Comparison of Various Rate-Decline Analysis Models for Horizontal Wells with Multiple Fractures in Shale gas Reservoirs","authors":"Y. Miao, Xiangfang Li, John W. Lee, Chaojie Zhao, Yunjian Zhou, Hang Li, Yucui Chang, Wenjing Lin, Zhihua Xiao, Nan Wu","doi":"10.2118/191185-MS","DOIUrl":"https://doi.org/10.2118/191185-MS","url":null,"abstract":"\u0000 In recent years, improving the accuracy of production forecast in unconventional reservoirs has been of growing interest to oil and gas industries. Decline curve analysis (DCA) models have been recognized as the most efficient and easiest approaches to estimate gas rate. However, fluid flow regime and well rate decline curves are highly affected by the geological properties of formations. Therefore, the selection of DCA models based on completion designs and geological properties of formations is important for production rate prediction.\u0000 Traditional DCA methods, particularly Arps' decline model, was originally developed for predicting boundary dominated hydrocarbon well rate decline, which differs from the dominant long-duration transient flow regime in shale reservoirs. The Stretched Exponential model, the Duong model, the Arps model with a minimum terminal decline rate and the scaling method by Patzek were developed to match and forecast wells with transient flow followed by boundary dominated flow (BDF). In this paper, firstly we developed a new model to estimate production in shale gas reserviors by considering both Knudsen diffusion of bulk gas and surface diffusion of adsorbed gas based on the traditional equation of rate versus square-root-of-time. This proposed model can provide better fits to data in transient linear flow regimes. In addition, a systematic analysis of numerical simulation cases in CMG were performed to compare with the traditional model.\u0000 The results demonstrated that, in most cases, our model which is demonstrated in this paper, provide more accurate estimation of reserves for numerically simulated cases compared with the traditional decline methods. Therefore, the work offers critical insights into evaluating production in shale gas reserviors in a more efficient way.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116998753","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}
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