R. Fazlyeva, D. Mallory, R. Moore, S. Mehta, A. Cheremisin
Air injection has immense potential for hydrocarbon recovery from various reservoirs. One of the screening techniques which can be applied to evaluate a candidate oil for the air injection process is the accelerating rate calorimeter (ARC). The unique feature of this instrument is that it can provide adiabatic conditions and handle experiments at high pressures. This paper reviews four tests performed in closed and flowing ARCs to fingerprint and observe the thermal behavior of a crude oil. The crude oil used for this study is characterized as a 19.3°API and viscosity of 710 mPa.s at 21°C. The oxidation experiments were performed under two scenarios of oil-only and oil in the presence of native carbonate core. Initial starting conditions of each test were at a temperature of 23°C and a reservoir pressure of 13.8 MPa. Flowing ARC experiments showed that Low-Temperature Oxidation occurs at a temperature of about 150°C, whereas ignition occurs at about 350°C when High-Temperature Oxidation region was dominant. However, when using the closed ARC, the thermal behavior of the studied oil appeared to have different temperature characteristics, and the onset of the maximum self-heat rate occurred at temperature of 288°C. The effect of the vapor phase combustion as well as the calculation of kinetic parameters are also discussed in this work.
{"title":"Screening In Situ Combustion Applicability for a Heavy Oil Candidate Reservoir with an Accelerating Rate Calorimeter","authors":"R. Fazlyeva, D. Mallory, R. Moore, S. Mehta, A. Cheremisin","doi":"10.2118/196773-ms","DOIUrl":"https://doi.org/10.2118/196773-ms","url":null,"abstract":"\u0000 Air injection has immense potential for hydrocarbon recovery from various reservoirs. One of the screening techniques which can be applied to evaluate a candidate oil for the air injection process is the accelerating rate calorimeter (ARC). The unique feature of this instrument is that it can provide adiabatic conditions and handle experiments at high pressures. This paper reviews four tests performed in closed and flowing ARCs to fingerprint and observe the thermal behavior of a crude oil. The crude oil used for this study is characterized as a 19.3°API and viscosity of 710 mPa.s at 21°C. The oxidation experiments were performed under two scenarios of oil-only and oil in the presence of native carbonate core. Initial starting conditions of each test were at a temperature of 23°C and a reservoir pressure of 13.8 MPa. Flowing ARC experiments showed that Low-Temperature Oxidation occurs at a temperature of about 150°C, whereas ignition occurs at about 350°C when High-Temperature Oxidation region was dominant. However, when using the closed ARC, the thermal behavior of the studied oil appeared to have different temperature characteristics, and the onset of the maximum self-heat rate occurred at temperature of 288°C. The effect of the vapor phase combustion as well as the calculation of kinetic parameters are also discussed in this work.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83456366","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}
Oil industry knows dozens of hundreds of different EOR/IOR methods to improve reservoir recovery efficiency. Among today's priorities are assessment of various EOR/IOR and bottomhole treatment technologies and selection of the most effective ones that will meet the specific reservoir conditions. For assessment of stimulation efficiency, different techniques can be used: decline curve analysis (DCA), production rates analysis before and after stimulation, analysis of reservoir properties in the near-wellbore zone and in the reservoir using pressure build-up (PUB) curves. Each technique has advantages and disadvantages. Thus, comparison of production performance ignores bottomhole pressure changes before and after stimulation, pressure buildup curves are not infrequently of a rather low quality, DCA is based on empirical relationships liable to misinterpretation because of subjective estimate. Devoid of these drawbacks is the rate transient analysis (RTA). The advantage of this method is that it makes allowance for change of production rates always occurring following stimulation. This is achieved through use of diffusion equations. Practice has shown that RTA provides a comparative analysis of production rates and cumulative oil production through time, porosity and permeability before and after stimulation, being, thus, a comprehensive tool for efficiency evaluation. Variation in oil production is the most reliable parameter, because it accounts for changes in bottomhole pressure and water cut before and after stimulation. To determine this parameter, an algorithm based on the pressure drop change is offered. RTA allows production forecast by two scenarios, the scenario involving stimulation, and the scenario without any production enhancement operations with a view to assess cumulative incremental production. In conclusion, it can be said that rate/pressure transient analysis allows assessment of efficiency of a large variety of EOR/IOR projects and a long-term production forecast. The offered approach may serve a good alternative to the decline curve analysis and comparison of production rates and PUB curves before and after stimulation.
{"title":"Assessment of Efficiency of EOR/IOR Technologies Using Rate Transient Analysis","authors":"V. Iktissanov, R. Sakhabutdinov, I. Bobb","doi":"10.2118/196760-ms","DOIUrl":"https://doi.org/10.2118/196760-ms","url":null,"abstract":"\u0000 Oil industry knows dozens of hundreds of different EOR/IOR methods to improve reservoir recovery efficiency. Among today's priorities are assessment of various EOR/IOR and bottomhole treatment technologies and selection of the most effective ones that will meet the specific reservoir conditions.\u0000 For assessment of stimulation efficiency, different techniques can be used: decline curve analysis (DCA), production rates analysis before and after stimulation, analysis of reservoir properties in the near-wellbore zone and in the reservoir using pressure build-up (PUB) curves.\u0000 Each technique has advantages and disadvantages. Thus, comparison of production performance ignores bottomhole pressure changes before and after stimulation, pressure buildup curves are not infrequently of a rather low quality, DCA is based on empirical relationships liable to misinterpretation because of subjective estimate.\u0000 Devoid of these drawbacks is the rate transient analysis (RTA). The advantage of this method is that it makes allowance for change of production rates always occurring following stimulation. This is achieved through use of diffusion equations.\u0000 Practice has shown that RTA provides a comparative analysis of production rates and cumulative oil production through time, porosity and permeability before and after stimulation, being, thus, a comprehensive tool for efficiency evaluation. Variation in oil production is the most reliable parameter, because it accounts for changes in bottomhole pressure and water cut before and after stimulation. To determine this parameter, an algorithm based on the pressure drop change is offered. RTA allows production forecast by two scenarios, the scenario involving stimulation, and the scenario without any production enhancement operations with a view to assess cumulative incremental production.\u0000 In conclusion, it can be said that rate/pressure transient analysis allows assessment of efficiency of a large variety of EOR/IOR projects and a long-term production forecast. The offered approach may serve a good alternative to the decline curve analysis and comparison of production rates and PUB curves before and after stimulation.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88551236","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 drilling fluid properties are critical for drilling parameters such as ECD (equivalent circulating density), surge and swab pressures and hole cleaning properties. To be able to optimize drilling parameters and improve drilling efficiency also the drilling fluid must be at optimum specifications. To have a more proactive fluid engineering where the drilling fluid at all times is as desired continuous measurements of drilling fluid properties are necessary. This paper will present the development of new equipment for offshore use for automatic viscosity and density measurements. The paper will discuss the technology in use, the implementation and qualification into harsh offshore environment as well as the resulting data obtained, transformed into digital data received at onshore operation centers. The measurements of drilling fluids properties and chemical compositions have been more or less unchanged for decades. The tests in use are manual and performed by the mud engineer normally four times a day. Based on these tests the fluid properties are engineered within given set points of selected parameters. This limited number of tests will often drive the fluid engineering into a reactive mode, where fluid properties must be adjusted due to drift in measured values. In this paper the experiences from introducing continuous measurements of drilling fluids density and rheology will be presented. Automatic measurements have been introduced by an operator on several offshore installations, both semi-submersible drilling rigs as well as jack-ups and fixed platforms. The use of the data in the fluid engineering process as well as in the drilling process will be discussed. Drilling Fluid parameters can now be measured automatically on the rig. The fluid properties can then be monitored from operation centers 24/7.This ensure improved quality of drilling fluid. When this is performed in combination with online hydraulic calculations improved drilling performance is obtained.
{"title":"Automatic Drilling Fluid Measurements","authors":"K. Taugbøl, Jan Ove Brevik, B. Rudshaug","doi":"10.2118/196793-ms","DOIUrl":"https://doi.org/10.2118/196793-ms","url":null,"abstract":"\u0000 The drilling fluid properties are critical for drilling parameters such as ECD (equivalent circulating density), surge and swab pressures and hole cleaning properties. To be able to optimize drilling parameters and improve drilling efficiency also the drilling fluid must be at optimum specifications.\u0000 To have a more proactive fluid engineering where the drilling fluid at all times is as desired continuous measurements of drilling fluid properties are necessary. This paper will present the development of new equipment for offshore use for automatic viscosity and density measurements. The paper will discuss the technology in use, the implementation and qualification into harsh offshore environment as well as the resulting data obtained, transformed into digital data received at onshore operation centers.\u0000 The measurements of drilling fluids properties and chemical compositions have been more or less unchanged for decades. The tests in use are manual and performed by the mud engineer normally four times a day. Based on these tests the fluid properties are engineered within given set points of selected parameters. This limited number of tests will often drive the fluid engineering into a reactive mode, where fluid properties must be adjusted due to drift in measured values.\u0000 In this paper the experiences from introducing continuous measurements of drilling fluids density and rheology will be presented. Automatic measurements have been introduced by an operator on several offshore installations, both semi-submersible drilling rigs as well as jack-ups and fixed platforms. The use of the data in the fluid engineering process as well as in the drilling process will be discussed.\u0000 Drilling Fluid parameters can now be measured automatically on the rig. The fluid properties can then be monitored from operation centers 24/7.This ensure improved quality of drilling fluid. When this is performed in combination with online hydraulic calculations improved drilling performance is obtained.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84883704","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}
D. Chaplygin, D. Khamadaliev, Victor Yashnev, Ya.G. Gorbachev, A. Chernyshev, S. Vitthal, P. Fair
After hydraulic fracturing treatment, wellbore clean-out takes significant amount of time, and therefore, the commissioning of the well is delayed. In addition to production losses, production companies CAPEX and OPEX are also increasing proportionally to frac fleet activity. As a common practice, in western Siberia fracturing treatment is underflushed by about 0.5 cubic meters. This is supposed to prevent unintentional overflush and, as a result, hydraulic fracture closure at the wellbore. The loss of contact between the propped fracture and the perforated section of the well can neutralize the effect of hydraulic fracturing. This can happen in the first days of production after the operation or in a long-term perspective. On the other hand, overflush during hydraulic fracturing is common practice for unconventional formations. It allows to use various well completion technologies with the cemented liners and significantly reduces time required to complete multistage fracturing treatment. The objective of this paper is to show the approach and experience of the company "Salym petroleum development" (SPD). Positive result was obtained with proppant slurry overflush operation during treatment of conventional reservoirs.
{"title":"Hydraulic Fracturing Overflush on Conventional Reservoirs","authors":"D. Chaplygin, D. Khamadaliev, Victor Yashnev, Ya.G. Gorbachev, A. Chernyshev, S. Vitthal, P. Fair","doi":"10.2118/196967-ms","DOIUrl":"https://doi.org/10.2118/196967-ms","url":null,"abstract":"\u0000 After hydraulic fracturing treatment, wellbore clean-out takes significant amount of time, and therefore, the commissioning of the well is delayed. In addition to production losses, production companies CAPEX and OPEX are also increasing proportionally to frac fleet activity. As a common practice, in western Siberia fracturing treatment is underflushed by about 0.5 cubic meters. This is supposed to prevent unintentional overflush and, as a result, hydraulic fracture closure at the wellbore. The loss of contact between the propped fracture and the perforated section of the well can neutralize the effect of hydraulic fracturing. This can happen in the first days of production after the operation or in a long-term perspective.\u0000 On the other hand, overflush during hydraulic fracturing is common practice for unconventional formations. It allows to use various well completion technologies with the cemented liners and significantly reduces time required to complete multistage fracturing treatment.\u0000 The objective of this paper is to show the approach and experience of the company \"Salym petroleum development\" (SPD). Positive result was obtained with proppant slurry overflush operation during treatment of conventional reservoirs.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88109817","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}
A. Byakov, D. Eliseev, A. Senkov, R. Shafikov, A. Mavrin, A.N. Lesnoy, M. Sibilev, I. Bulygin
The Yuri Korchagin field is the first of the fields introduced by LUKOIL in the Northern part of the Caspian Sea. The main object of development – Neocom-Volzhskaya Deposit is represented by a thin oil rim, with the underlying bottom water over the entire area of the Deposit with a massive gas cap. Given the elongated configuration of the deposits and dimensions of the Eastern and Western parts, for drilling and production of hydrocarbons in the square fields placed one offshore ice-resistant fixed platform (OIFP) in the Western sector and the block-the conductor (BC) on the Eastern section. In order to ensure the effective development of oil rims of the im field. Yu. Korchagina and reduction of geological risks associated with the lack of detailed information on the geological structure of the layers in the locations of producing wells, the adopted system of field development by horizontal wells of large extent. In total, more than two dozen production wells with the length of horizontal wells from 450 to 4900 meters have been drilled at the field. In the conditions of the shelf field. Yu. Korchagina the most important aspect in the production of hydrocarbons is to ensure a constant and uniform flow of fluid to the horizontal barrel. The basis for this is to maintain equal depression at all points of the horizontal section and reduce the risks of gas and water breakthrough. This paper describes the evolution of the completion strategy of horizontal wells of extreme length, reveals the main characteristics of the completion systems used, the results of their operation.
{"title":"Completion Technologies Evolution of Yuri Korchagina Wells and Operation Experience of the Intelligent Wells","authors":"A. Byakov, D. Eliseev, A. Senkov, R. Shafikov, A. Mavrin, A.N. Lesnoy, M. Sibilev, I. Bulygin","doi":"10.2118/196923-ms","DOIUrl":"https://doi.org/10.2118/196923-ms","url":null,"abstract":"\u0000 The Yuri Korchagin field is the first of the fields introduced by LUKOIL in the Northern part of the Caspian Sea. The main object of development – Neocom-Volzhskaya Deposit is represented by a thin oil rim, with the underlying bottom water over the entire area of the Deposit with a massive gas cap.\u0000 Given the elongated configuration of the deposits and dimensions of the Eastern and Western parts, for drilling and production of hydrocarbons in the square fields placed one offshore ice-resistant fixed platform (OIFP) in the Western sector and the block-the conductor (BC) on the Eastern section.\u0000 In order to ensure the effective development of oil rims of the im field. Yu. Korchagina and reduction of geological risks associated with the lack of detailed information on the geological structure of the layers in the locations of producing wells, the adopted system of field development by horizontal wells of large extent. In total, more than two dozen production wells with the length of horizontal wells from 450 to 4900 meters have been drilled at the field.\u0000 In the conditions of the shelf field. Yu. Korchagina the most important aspect in the production of hydrocarbons is to ensure a constant and uniform flow of fluid to the horizontal barrel. The basis for this is to maintain equal depression at all points of the horizontal section and reduce the risks of gas and water breakthrough. This paper describes the evolution of the completion strategy of horizontal wells of extreme length, reveals the main characteristics of the completion systems used, the results of their operation.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86260979","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}
Izyurov, A. Kharitonov, I. Semenikhin, E. Korsunov, A. Gassan, E. Tikhonov, G. Jadan, Stashko, I. Blagonadeshniy, A. Manikhin, S. Medvedev
Differential sticking problems and drilling fluids losses reducing permeability as a result of deep invasion of drilling and completion fluids are still main challenges. Under the conditions of development of mature fields, these problems become more acute due to the uncompensated drainage of formation fluid from the pay zone. The resolution for one of these problems is a high-quality plugging of permeable formation. The paper states a wide review of research papers on this topic, laboratory testing of one of the selection methods, an example of technical application of one of the methods, and and prospects for further development of the topic to improve the approaches of practical application.
{"title":"Selecting Bridging Agents’ Particle Size Distribution for Optimum Plugging While Drilling in Permeable Zones","authors":"Izyurov, A. Kharitonov, I. Semenikhin, E. Korsunov, A. Gassan, E. Tikhonov, G. Jadan, Stashko, I. Blagonadeshniy, A. Manikhin, S. Medvedev","doi":"10.2118/197009-ms","DOIUrl":"https://doi.org/10.2118/197009-ms","url":null,"abstract":"\u0000 Differential sticking problems and drilling fluids losses reducing permeability as a result of deep invasion of drilling and completion fluids are still main challenges. Under the conditions of development of mature fields, these problems become more acute due to the uncompensated drainage of formation fluid from the pay zone. The resolution for one of these problems is a high-quality plugging of permeable formation.\u0000 The paper states a wide review of research papers on this topic, laboratory testing of one of the selection methods, an example of technical application of one of the methods, and and prospects for further development of the topic to improve the approaches of practical application.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87379441","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}
Every year the resource base of the LUKOIL fields located in Western Siberia undergoes changes in the direction of increasing the share of reserves in the deposits with low permeability and more complex geological conditions of their development, the so-called hard-to-recover oil reserves (HRR). Such deposits are confined to the deposits of the Tyumen, Bazhenov, Abalak suites, as well as to low-permeability reservoirs of the Achimov strata and sediments of the yu1 formation. At the beginning of 2019, there are about 290 million tons of oil reserves (figure 1), and the accumulated production of them already exceeds 15 million tons of oil (figure 2).
{"title":"Experience in the Use of Horizontal Wells of Various Designs for the Development of Hard-to-Recover Oil Reserves in LLC Lukoil – Western Siberia","authors":"Emil Lozanovich","doi":"10.2118/196744-ms","DOIUrl":"https://doi.org/10.2118/196744-ms","url":null,"abstract":"Every year the resource base of the LUKOIL fields located in Western Siberia undergoes changes in the direction of increasing the share of reserves in the deposits with low permeability and more complex geological conditions of their development, the so-called hard-to-recover oil reserves (HRR). Such deposits are confined to the deposits of the Tyumen, Bazhenov, Abalak suites, as well as to low-permeability reservoirs of the Achimov strata and sediments of the yu1 formation. At the beginning of 2019, there are about 290 million tons of oil reserves (figure 1), and the accumulated production of them already exceeds 15 million tons of oil (figure 2).","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83136409","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}
S. Arefyev, V. Makienko, Dmitry Shestakov, M. Galiev, K. Ovchinnikov, E. Malyavko, Igor Novikov
In recent years, oil and gas producing companies have increasingly migrated towards using tracer-based methods to obtain data on horizontal wells operation. The interest in these technologies is largely due to their ability to obtain data over a long period of time with a radical decrease in the required resources, thereby providing new opportunities for well management and increasing cumulative production. The aim of this article is to compare the results of applying different tracer-based systems in one well. Tracer-based technologies produced by different manufacturers vary in physical principles of operation, as well as in the methods of their injection into the well or reservoir. Tracers designed for long-term work are injected into the reservoir with marked proppant or lowered into the wells in the lower completion cassettes. For the first time, alternative tracer-based systems were applied in one well, ensuring the selectivity of work with oil and water. This allowed us to compare the results and evaluate the technology's advantages and disadvantages. The well was completed by multi-stage hydraulic fracturing with the possibility of subsequent port control using coiled tubing. Each of five well intervals were equipped with two tracer cartridges fixed on an MFrac sleeve on both sides. In addition, proppant with markers was pumped in 3 months. The unique signature of the marker was used for each fracturing stage (5 unique signatures for each of 5 fracturing stages). As a result of this world-first field application of alternative tracer-based systems, valuable analytical material was obtained related to the quantitative analysis of various tracers, the performance of different polymers, and the stability of the tracers’ allocation in the formation fluid. The data obtained confirmed the character of the marked proppant pack washing out with the formation fluid in comparison with the tracer casings attached to MFrac port on both sides. The following results were achieved upon completion: additional tools were obtained for the correlation of data on the tracers amount and concentration, and comparative indicators of different tracer technologies in terms of efficiency and work accuracy were identified. It was also confirmed that the marked proppant is not washed out into the well under these reservoir conditions. The authors of this article were the first to compare the technologies with different approaches to the tracers’ placement in a well within one project. Based on the project results, the obtained data allowed us to answer many pressing questions from oil and gas producing companies related to the comparison of tracer systems.
{"title":"Comparison of Various Tracer-Based Production Logging Technologies Application Results in One Well","authors":"S. Arefyev, V. Makienko, Dmitry Shestakov, M. Galiev, K. Ovchinnikov, E. Malyavko, Igor Novikov","doi":"10.2118/196829-ms","DOIUrl":"https://doi.org/10.2118/196829-ms","url":null,"abstract":"\u0000 In recent years, oil and gas producing companies have increasingly migrated towards using tracer-based methods to obtain data on horizontal wells operation. The interest in these technologies is largely due to their ability to obtain data over a long period of time with a radical decrease in the required resources, thereby providing new opportunities for well management and increasing cumulative production. The aim of this article is to compare the results of applying different tracer-based systems in one well.\u0000 Tracer-based technologies produced by different manufacturers vary in physical principles of operation, as well as in the methods of their injection into the well or reservoir. Tracers designed for long-term work are injected into the reservoir with marked proppant or lowered into the wells in the lower completion cassettes. For the first time, alternative tracer-based systems were applied in one well, ensuring the selectivity of work with oil and water. This allowed us to compare the results and evaluate the technology's advantages and disadvantages. The well was completed by multi-stage hydraulic fracturing with the possibility of subsequent port control using coiled tubing. Each of five well intervals were equipped with two tracer cartridges fixed on an MFrac sleeve on both sides. In addition, proppant with markers was pumped in 3 months. The unique signature of the marker was used for each fracturing stage (5 unique signatures for each of 5 fracturing stages).\u0000 As a result of this world-first field application of alternative tracer-based systems, valuable analytical material was obtained related to the quantitative analysis of various tracers, the performance of different polymers, and the stability of the tracers’ allocation in the formation fluid. The data obtained confirmed the character of the marked proppant pack washing out with the formation fluid in comparison with the tracer casings attached to MFrac port on both sides.\u0000 The following results were achieved upon completion: additional tools were obtained for the correlation of data on the tracers amount and concentration, and comparative indicators of different tracer technologies in terms of efficiency and work accuracy were identified. It was also confirmed that the marked proppant is not washed out into the well under these reservoir conditions. The authors of this article were the first to compare the technologies with different approaches to the tracers’ placement in a well within one project. Based on the project results, the obtained data allowed us to answer many pressing questions from oil and gas producing companies related to the comparison of tracer systems.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80557219","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}
A modified ASP flooding technology, in which polymer and alkali-surfactant solution are injected alternatively for several turns, rather than being injected simultaneously as the traditional way, is studied by both lab experiments and a field test. Experimental results show that the viscosity of polymer solution will be reduced by 30% if alkalis and surfactants are added, while the dynamical interfacial tension is much higher in ASP-oil-water system than in AS-oil-water system. To give full play of these three chemicals on oil recovery, we alternatively inject polymer and alkali-surfactant slugs, and this modified ASP flooding is named A/S-P alternating flooding. A pilot test is then carried out in a water flooded reservoir since November 2008, which is employed in a block of 28 injection wells and 40 production wells. In the pilot test, alkali-surfactant slugs and polymer slugs are alternatively injected for five turns after a leading polymer slug. Injecting pressure increases in each polymer slug and decreases in the following A/S slug. In the following polymer slug, the injecting pressure of test area is 1.5MPa lower than contrast area and the injection rate per well is 9m3/d higher, while the production is 18% more. Profile tests show that the proportion of injectable thickness to total effective thickness keeps 80% or higher during the whole flooding process of the test area, while the proportion of contrast area is only 70% in the late stage. The minimum water cut during A/S-P alternating flooding is 82.0%, which is 6.1% lower than ASP flooding. However, the water cut increases significantly when A/S slugs are injected, which is an important weakness of A/S-P flooding. When chemical flooding is over, 17.8% of the original oil in place (OOIP) has been exploited by A/S-P alternating flooding, which is more than 7% higher than the contrast area flooded by ASP, while the total chemical cost is 11.3% lower. Therefore, A/S-P alternating flooding can be a cost effective enhanced oil recovery technology. A/S-P alternating flooding has more injection and production, displaces more zones, gets a higher oil recovery and uses fewer chemicals, which can be a cost effective technology.
{"title":"A/S-P Alternating Flooding, A Modified ASP Flooding Technology","authors":"Huang Wenqing, Yeliang Dong, Zhao Jinyi, Xiaobo Liu, Yu Fan, Hongjun Bai, Hao Jinsheng","doi":"10.2118/196768-ms","DOIUrl":"https://doi.org/10.2118/196768-ms","url":null,"abstract":"\u0000 A modified ASP flooding technology, in which polymer and alkali-surfactant solution are injected alternatively for several turns, rather than being injected simultaneously as the traditional way, is studied by both lab experiments and a field test.\u0000 Experimental results show that the viscosity of polymer solution will be reduced by 30% if alkalis and surfactants are added, while the dynamical interfacial tension is much higher in ASP-oil-water system than in AS-oil-water system. To give full play of these three chemicals on oil recovery, we alternatively inject polymer and alkali-surfactant slugs, and this modified ASP flooding is named A/S-P alternating flooding. A pilot test is then carried out in a water flooded reservoir since November 2008, which is employed in a block of 28 injection wells and 40 production wells.\u0000 In the pilot test, alkali-surfactant slugs and polymer slugs are alternatively injected for five turns after a leading polymer slug. Injecting pressure increases in each polymer slug and decreases in the following A/S slug. In the following polymer slug, the injecting pressure of test area is 1.5MPa lower than contrast area and the injection rate per well is 9m3/d higher, while the production is 18% more. Profile tests show that the proportion of injectable thickness to total effective thickness keeps 80% or higher during the whole flooding process of the test area, while the proportion of contrast area is only 70% in the late stage. The minimum water cut during A/S-P alternating flooding is 82.0%, which is 6.1% lower than ASP flooding. However, the water cut increases significantly when A/S slugs are injected, which is an important weakness of A/S-P flooding. When chemical flooding is over, 17.8% of the original oil in place (OOIP) has been exploited by A/S-P alternating flooding, which is more than 7% higher than the contrast area flooded by ASP, while the total chemical cost is 11.3% lower. Therefore, A/S-P alternating flooding can be a cost effective enhanced oil recovery technology.\u0000 A/S-P alternating flooding has more injection and production, displaces more zones, gets a higher oil recovery and uses fewer chemicals, which can be a cost effective technology.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80944530","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}
A. Krasnikov, R. Melikov, V. Pavlov, N. Pavlyukov, M. Subbotin
Development of complex-build oil and gas reservoirs is associated with advanced technologies such as horizontal wells drilling and multi-stage hydraulic fracturing. Geomechanical modeling for hydraulic fracturing purposes is a fundamental tool for assessing technological constraints and risks, as well as increasing efficiency of reservoir treatment. In proposed approach of horizontal stresses modeling and calibration to the actual hydraulic fracturing data additional features considered to compensate low contrast of Poisson's ratio calculated from broadband acoustics: elastic properties TIV-anisotropy, variation of Biot coefficient adjusted to mechanical facies, correlations between static elastic properties and petrophysical parameters based on core measurements. Lab measurements on oriented core samples revealed elastic properties anisotropy that caused difference of the static young's modulus parallel and perpendicular to the formation bedding up to 80 – 100%, and for the Poisson's ratio is up to 10 – 20%. Considering these results stress calculation leads to a difference between an isotropic and anisotropic profile up to 20%, this has significant impact on the hydraulic fracture geometry. The rock behavior under load is different and is determined by the properties of the rock grains and the contact between them. Thus, the section separation into mechanical facies plays an important role when estimating elastic parameters, including Biot coefficient (α), which is different for shales, sand and/or carbonate, for example. Correct estimation of α with respect to mechanical facies allows achieving good agreement between stress calculation and actual measurements obtained with a mini-frac job, thereby increasing fracture geometry prediction accuracy. Another tool to compensate lack of stress contrast calculated based on standard 1D geomechanical workflow is the use of petrophysical parameters such as porosity, clay content, neutron density and its correlation with static elastic properties to estimate minimum horizontal stress. This method may improve geomechanical model matching with field observations, but it has a limited scope of application. In this paper demonstrated that additional study of the rock properties with special logging and core measurements at initial phase of field development planning may significantly reduce geomechanical modeling uncertainties and improve understanding of hydraulic fracturing and fracture geometry, which is a basis for hydrocarbon production and economic evaluation of the project or the whole asset. The paper presents adapted geomechanical modeling workflow based on special lab core testing and elastic properties anisotropy and Biot coefficient evaluation to adjust the horizontal stresses profiles in complex-build reservoirs to the field measurements and observations as well as to fracturing data in existing wells.
{"title":"Consideration of Elastic Properties and Stresses Anisotropy in Fracturing Planning","authors":"A. Krasnikov, R. Melikov, V. Pavlov, N. Pavlyukov, M. Subbotin","doi":"10.2118/196899-ms","DOIUrl":"https://doi.org/10.2118/196899-ms","url":null,"abstract":"\u0000 Development of complex-build oil and gas reservoirs is associated with advanced technologies such as horizontal wells drilling and multi-stage hydraulic fracturing. Geomechanical modeling for hydraulic fracturing purposes is a fundamental tool for assessing technological constraints and risks, as well as increasing efficiency of reservoir treatment.\u0000 In proposed approach of horizontal stresses modeling and calibration to the actual hydraulic fracturing data additional features considered to compensate low contrast of Poisson's ratio calculated from broadband acoustics: elastic properties TIV-anisotropy, variation of Biot coefficient adjusted to mechanical facies, correlations between static elastic properties and petrophysical parameters based on core measurements.\u0000 Lab measurements on oriented core samples revealed elastic properties anisotropy that caused difference of the static young's modulus parallel and perpendicular to the formation bedding up to 80 – 100%, and for the Poisson's ratio is up to 10 – 20%. Considering these results stress calculation leads to a difference between an isotropic and anisotropic profile up to 20%, this has significant impact on the hydraulic fracture geometry.\u0000 The rock behavior under load is different and is determined by the properties of the rock grains and the contact between them. Thus, the section separation into mechanical facies plays an important role when estimating elastic parameters, including Biot coefficient (α), which is different for shales, sand and/or carbonate, for example. Correct estimation of α with respect to mechanical facies allows achieving good agreement between stress calculation and actual measurements obtained with a mini-frac job, thereby increasing fracture geometry prediction accuracy.\u0000 Another tool to compensate lack of stress contrast calculated based on standard 1D geomechanical workflow is the use of petrophysical parameters such as porosity, clay content, neutron density and its correlation with static elastic properties to estimate minimum horizontal stress. This method may improve geomechanical model matching with field observations, but it has a limited scope of application.\u0000 In this paper demonstrated that additional study of the rock properties with special logging and core measurements at initial phase of field development planning may significantly reduce geomechanical modeling uncertainties and improve understanding of hydraulic fracturing and fracture geometry, which is a basis for hydrocarbon production and economic evaluation of the project or the whole asset.\u0000 The paper presents adapted geomechanical modeling workflow based on special lab core testing and elastic properties anisotropy and Biot coefficient evaluation to adjust the horizontal stresses profiles in complex-build reservoirs to the field measurements and observations as well as to fracturing data in existing wells.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77930480","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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