M. I. M. Khalil, C. Chang, Amierul Amran, J. C. Kok
90% of Field T production relies on Gas lift as means of artificial lift. Typical surveillance strategy in assessing the health of the gas lifted wells is to deploy flowing gradient survey (FGS) in tandem with surface welltest. However, in the case of Field T, this technology meets its limitation in investigating prolific wells due to its current well mechanical condition and dual string completion environment. Welltracer technology application in the field has broken the barrier in evaluation of these wells in Field T. The Welltracer application is a non-invasive data acquisition method which measures the travel time and concentration of the CO2 return which is introduced upstream of the gas lift header. The interpreted results allow for the identification of injection points and rate. This simple idea opens up opportunity for gas lift performance evaluation of wells in Field T that was not possible through the conventional approach of FGS. This breakthrough is vital for Field T as some of the wells are facing either one or more of the following problems i.e. dual string wells with gas robbing issues, tubing leak, restricted tubing due to pack-off and multi-point injection. Twenty-three surveys and analysis were completed during the first application in Field T. The opportunity identified from the survey were categorized depending on the resources and timeframe required to execute the changes. Four enhancement opportunities were identified which only required surface valve manipulation were executed immediately and showed instant results. Other than additional barrels, the results of the campaign have a tremendous value of information that changed the earlier comprehension of the existing problems in some of the wells. This paper discusses the results of the application of the technology in Field T. This paper will also elaborate on the lessons learned and improvement recommendations in terms of project identification, execution and planning. Another important highlight that will be discussed is the limitation and assumptions made to further enhance the understanding of the Welltracer technology.
{"title":"A Game Changer Data Acquisition Technology : Field Wide Gaslift Optimization through the Application of Welltracer Technology in a Mature Offshore Field","authors":"M. I. M. Khalil, C. Chang, Amierul Amran, J. C. Kok","doi":"10.2118/196171-ms","DOIUrl":"https://doi.org/10.2118/196171-ms","url":null,"abstract":"\u0000 90% of Field T production relies on Gas lift as means of artificial lift. Typical surveillance strategy in assessing the health of the gas lifted wells is to deploy flowing gradient survey (FGS) in tandem with surface welltest. However, in the case of Field T, this technology meets its limitation in investigating prolific wells due to its current well mechanical condition and dual string completion environment. Welltracer technology application in the field has broken the barrier in evaluation of these wells in Field T.\u0000 The Welltracer application is a non-invasive data acquisition method which measures the travel time and concentration of the CO2 return which is introduced upstream of the gas lift header. The interpreted results allow for the identification of injection points and rate. This simple idea opens up opportunity for gas lift performance evaluation of wells in Field T that was not possible through the conventional approach of FGS. This breakthrough is vital for Field T as some of the wells are facing either one or more of the following problems i.e. dual string wells with gas robbing issues, tubing leak, restricted tubing due to pack-off and multi-point injection.\u0000 Twenty-three surveys and analysis were completed during the first application in Field T. The opportunity identified from the survey were categorized depending on the resources and timeframe required to execute the changes. Four enhancement opportunities were identified which only required surface valve manipulation were executed immediately and showed instant results. Other than additional barrels, the results of the campaign have a tremendous value of information that changed the earlier comprehension of the existing problems in some of the wells.\u0000 This paper discusses the results of the application of the technology in Field T. This paper will also elaborate on the lessons learned and improvement recommendations in terms of project identification, execution and planning. Another important highlight that will be discussed is the limitation and assumptions made to further enhance the understanding of the Welltracer technology.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"223 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76124428","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}
An experimental study of a gravity-driven downhole separator for a pumped horizontal or deviated well is presented in this study. It considers the effects of the upstream flow, gas and liquid flow rates and deviation angles on the global separation efficiency and the free gas at the pump intake. The efficacy of downhole separators is typically tested under steady-state conditions where the fluids are injected above the separator. A new outdoor facility, which allows the injection of a two-phase mixture below the separator was designed, constructed, and used in this study. Gas and liquid flow rates and deviation angle are varied to study the liquid holdup in the liquid-rich outlet and the separator efficiency. The experimental results demonstrate the effects of the operation conditions and deviation angle on the behavior of downhole separators. It is found that the separator has two regions of performance; namely, high efficiency region and a region where the efficiency decreases with the liquid flow rate. Moreover, the effect of the deviation angle affects the results. The findings provide conditions under which and where the separator can be operated efficiently in the field.
{"title":"An Experimental Investigation of Dynamic Behavior of Gravity-Driven Downhole Separators","authors":"Jorge López, E. Pereyra, C. Sarica","doi":"10.2118/196197-ms","DOIUrl":"https://doi.org/10.2118/196197-ms","url":null,"abstract":"\u0000 An experimental study of a gravity-driven downhole separator for a pumped horizontal or deviated well is presented in this study. It considers the effects of the upstream flow, gas and liquid flow rates and deviation angles on the global separation efficiency and the free gas at the pump intake.\u0000 The efficacy of downhole separators is typically tested under steady-state conditions where the fluids are injected above the separator. A new outdoor facility, which allows the injection of a two-phase mixture below the separator was designed, constructed, and used in this study. Gas and liquid flow rates and deviation angle are varied to study the liquid holdup in the liquid-rich outlet and the separator efficiency.\u0000 The experimental results demonstrate the effects of the operation conditions and deviation angle on the behavior of downhole separators. It is found that the separator has two regions of performance; namely, high efficiency region and a region where the efficiency decreases with the liquid flow rate. Moreover, the effect of the deviation angle affects the results. The findings provide conditions under which and where the separator can be operated efficiently in the field.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77013919","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}
On offshore rigs, oil-based mud (OBM) cuttings can create logistical and environmental risks. Onshore disposal requires costly transport, and bad weather can halt shipping operations. The liability for waste treated onshore belongs to the operator. Although offshore disposal removes this liability, UK North Sea regulations specify that oil on cuttings (OOC) must be less than 1%. (by weight?) A rigsite thermomechanical cuttings cleaner (TCC) applies high temperatures to help reduce OOC to less than 1% and recovers base oil and water for reuse. A TCC unit was installed on a semisubmersible rig to process OBM cuttings for a 24-well program. Mechanical action is applied directly to the cuttings by means of hammers that create friction, causing temperatures to exceed the boiling points of water and oil so that hydrocarbons are separated. The oil and water vapors are removed and condensed where the base oil and water are further separated and recovered. The TCC process on this rig was supported by vacuum-pump conveyance equipment and specialized storage tanks. Cuttings were no longer shipped to shore, and crane lifts associated with "skip-and-ship" operations were minimized significantly. The TCC unit processed 14,500 metric tons (MT) of OBM cuttings throughout the duration of the 24- well program. The total footage drilled with OBM was more than 160,000 ft. All cuttings were disposed offshore. Approximately 13,500 bbl of base oil (valued at USD 135/bbl) was recovered for reuse in the drilling fluid system. The TCC unit ran for a total of 3,500 hours with zero downtime or nonproductive time (NPT) associated with cuttings disposal. The average is approximately 150 operating hours per well. One important benefit was the dramatic reduction of skips handling and crane lifts, which provided safer working conditions for rig crews. On a conventional skip-and-ship operation, the operator would fill and transport up to 35 skips per day. This translates to 2,380 crane lifts per well that were unnecessary. Offloading delays caused by bad weather were no longer a factor, thus helping reduce uncertainty and saving valuable rig time. Processing this volume of drill cuttings offshore meant that more than 57,000 skip crane lifts were avoided. The TCC mobilization process for this program was executed efficiently by coordinating with quayside contractors (welders, platers, electricians, etc.) to complete much of the installation work scope onshore. Thermal treatment enables operators to address stringent offshore discharge regulations globally, excluding countries with zero discharge policies. Cost benefits include the following: No "wait on weather" time (rig day rate = USD 300,000)No dedicated vessels for transportNo quayside cuttings handlingNo trucking to treatment and disposal facilities Safety and environmental benefits add the following value: Reduced manual handling of skipsReduced crane liftsBase oil reuseLiability for waste ends at rigsite
{"title":"Rigsite Thermal Treatment of Cuttings Enables Improved HSE Performance in 24-Well Campaign in the UK North Sea","authors":"John Smith, Graham Eccles","doi":"10.2118/196004-ms","DOIUrl":"https://doi.org/10.2118/196004-ms","url":null,"abstract":"\u0000 On offshore rigs, oil-based mud (OBM) cuttings can create logistical and environmental risks. Onshore disposal requires costly transport, and bad weather can halt shipping operations. The liability for waste treated onshore belongs to the operator. Although offshore disposal removes this liability, UK North Sea regulations specify that oil on cuttings (OOC) must be less than 1%. (by weight?) A rigsite thermomechanical cuttings cleaner (TCC) applies high temperatures to help reduce OOC to less than 1% and recovers base oil and water for reuse.\u0000 A TCC unit was installed on a semisubmersible rig to process OBM cuttings for a 24-well program. Mechanical action is applied directly to the cuttings by means of hammers that create friction, causing temperatures to exceed the boiling points of water and oil so that hydrocarbons are separated. The oil and water vapors are removed and condensed where the base oil and water are further separated and recovered. The TCC process on this rig was supported by vacuum-pump conveyance equipment and specialized storage tanks. Cuttings were no longer shipped to shore, and crane lifts associated with \"skip-and-ship\" operations were minimized significantly.\u0000 The TCC unit processed 14,500 metric tons (MT) of OBM cuttings throughout the duration of the 24- well program. The total footage drilled with OBM was more than 160,000 ft. All cuttings were disposed offshore. Approximately 13,500 bbl of base oil (valued at USD 135/bbl) was recovered for reuse in the drilling fluid system. The TCC unit ran for a total of 3,500 hours with zero downtime or nonproductive time (NPT) associated with cuttings disposal. The average is approximately 150 operating hours per well. One important benefit was the dramatic reduction of skips handling and crane lifts, which provided safer working conditions for rig crews. On a conventional skip-and-ship operation, the operator would fill and transport up to 35 skips per day. This translates to 2,380 crane lifts per well that were unnecessary. Offloading delays caused by bad weather were no longer a factor, thus helping reduce uncertainty and saving valuable rig time. Processing this volume of drill cuttings offshore meant that more than 57,000 skip crane lifts were avoided. The TCC mobilization process for this program was executed efficiently by coordinating with quayside contractors (welders, platers, electricians, etc.) to complete much of the installation work scope onshore.\u0000 Thermal treatment enables operators to address stringent offshore discharge regulations globally, excluding countries with zero discharge policies. Cost benefits include the following: No \"wait on weather\" time (rig day rate = USD 300,000)No dedicated vessels for transportNo quayside cuttings handlingNo trucking to treatment and disposal facilities\u0000 Safety and environmental benefits add the following value: Reduced manual handling of skipsReduced crane liftsBase oil reuseLiability for waste ends at rigsite","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"54 57 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80591612","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}
B. Stephenson, T. Bai, M. Fay, E. Galan, Jeff MacDonald, Ryan Carduner
A single-point entry completion architecture has been implemented in several hydraulically stimulated resource plays across North America. The objective is to understand whether the innate properties of the rock and what we can diagnose about how it hydraulically fractures can inform the question of applicability of single-versus multi-point completion designs. Wells were treated using a single-point entry design in the Montney and the Duvernay and an assessment of well performance was carried out. Multiple diagnostic pads have been carried out over several years in both formations, including microseismic and geochemical fingerprint data allowing for a general characterization of the gross geometry and connectivity. Initial results from a fiber are available in the Montney with a single point completion design. The fracture diagnostic data was compiled and described in the context of the nine main sub-surface controls on the connectivity. In the Montney, it is relatively clear how completion intensity changes, like stage length, in single-point entry wells change the production performance outcome. In the Duvernay, there is significantly more uncertainty. This contrast contributed to the decision to treat several follow-up pads in the Montney via a single-point entry design, whereas a multi-point plug and perf completion is preferred for the Duvernay wells. Costs and stage isolation are considerations, but one other contributing explanation is that the dominantly planar fracture geometry in the Montney enables each stage to contribute proportionally, thus ensuring the stimulation distribution effectiveness from the near-to the far-field. The dry-gas area of the Montney is very stiff, with an absence of natural fractures, a paucity of faults, no containment issues and no significant frac barriers. Conversely, in the Duvernay, the inherent complexity in the fracture geometry complicates the stimulation distribution effectiveness in the far-field. Furthermore, the lower mobility of a liquids-rich hydrocarbon system probably benefits from the potentially tighter frac spacing, possible in a multi-cluster design, even with a probable increase in non-uniformity over single-point. It is hypothesized that in formations that develop complex fracture geometries, ‘putting all your eggs in one basket’ with a single-point entry design, needs to be assessed along with the other value drivers for the well architecture selection.
{"title":"Sub-Surface Driven Connectivity Descriptions in the Montney and the Duvernay Inform the Applicability of Single-Point Versus Multi-Point Well Architectures","authors":"B. Stephenson, T. Bai, M. Fay, E. Galan, Jeff MacDonald, Ryan Carduner","doi":"10.2118/196169-ms","DOIUrl":"https://doi.org/10.2118/196169-ms","url":null,"abstract":"A single-point entry completion architecture has been implemented in several hydraulically stimulated resource plays across North America. The objective is to understand whether the innate properties of the rock and what we can diagnose about how it hydraulically fractures can inform the question of applicability of single-versus multi-point completion designs.\u0000 Wells were treated using a single-point entry design in the Montney and the Duvernay and an assessment of well performance was carried out. Multiple diagnostic pads have been carried out over several years in both formations, including microseismic and geochemical fingerprint data allowing for a general characterization of the gross geometry and connectivity. Initial results from a fiber are available in the Montney with a single point completion design. The fracture diagnostic data was compiled and described in the context of the nine main sub-surface controls on the connectivity.\u0000 In the Montney, it is relatively clear how completion intensity changes, like stage length, in single-point entry wells change the production performance outcome. In the Duvernay, there is significantly more uncertainty. This contrast contributed to the decision to treat several follow-up pads in the Montney via a single-point entry design, whereas a multi-point plug and perf completion is preferred for the Duvernay wells. Costs and stage isolation are considerations, but one other contributing explanation is that the dominantly planar fracture geometry in the Montney enables each stage to contribute proportionally, thus ensuring the stimulation distribution effectiveness from the near-to the far-field.\u0000 The dry-gas area of the Montney is very stiff, with an absence of natural fractures, a paucity of faults, no containment issues and no significant frac barriers. Conversely, in the Duvernay, the inherent complexity in the fracture geometry complicates the stimulation distribution effectiveness in the far-field. Furthermore, the lower mobility of a liquids-rich hydrocarbon system probably benefits from the potentially tighter frac spacing, possible in a multi-cluster design, even with a probable increase in non-uniformity over single-point.\u0000 It is hypothesized that in formations that develop complex fracture geometries, ‘putting all your eggs in one basket’ with a single-point entry design, needs to be assessed along with the other value drivers for the well architecture selection.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"141 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80601982","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}
Development of reliable models for hydrocarbon-in-place and water saturation estimation requires knowledge about wettability of mudrocks and the parameters (including rock properties and reservoir condition) affecting it. A significant volume fraction of organic-rich mudrocks is composed of kerogen. Therefore, wettability of kerogen affects the overall wettability of organic-rich mudrocks. The chemical composition and structure of kerogen varies with kerogen type and thermal maturity, which affects the surface properties of kerogen such as wettability. In a recent publication, we demonstrated using experimental techniques that kerogen could be water-wet at low thermal maturities and oil-wet at higher thermal maturities. However, the impacts of kerogen type and reservoir temperature/pressure conditions on kerogen and mudrock wettability is yet to be quantified. Therefore, the objectives of this paper include (i) quantifying the impacts of kerogen molecular structure and composition on water adsorption capacities, (ii) quantifying the impacts of reservoir pressure and temperature on water adsorption capacity of kerogen using molecular dynamics (MD) simulations. In order to achieve the aforementioned objectives, we use a combination of molecular dynamics simulations and experimental work. The inputs to the molecular dynamics simulations include realistic models of kerogen, which are condensed to porous kerogen structures. Water molecules are filled in kerogen pore structure and MD simulation is performed. The outputs of the simulations include radial distribution function (RDF), and adsorption isotherms of water on kerogen for different kerogen types, thermal maturities, and temperature conditions. The adsorption processes are modelled for pressure and temperature conditions ranging from 0 to 35 MPa and 320 to 370 K, respectively. The outcomes of molecular dynamics simulations demonstrated that the water adsorption capacities of kerogen vary significantly with kerogen type, thermal maturity, and temperature and pressure conditions. The RDF results showed that the water adsorption capacity decreased from type I to type III kerogen. The water adsorption capacity of kerogen was found to increase by 128% with 38% increase in oxygen content. The increase in the adsorption capacity was attributed to the strong attraction between oxygen containing functional groups in kerogen and water. The adsorption isotherms of water and kerogen samples showed that the water adsorption capacity decreased by 0.19 mmol/g as the temperature increased from 320 K to 370 K. The average water adsorption capacity of kerogen was found to increase by 20% with increase in pressure by 34 MPa. The results obtained from molecular dynamics simulations were found to be in good agreement with experimental results. The results of this paper can be used to predict the adsorption capacities of any kerogen with the availability of geochemical information. This important property of kerog
{"title":"Demystifying Wettability Alteration in Kerogen as a Function of its Geochemistry and Reservoir Temperature and Pressure Using Molecular Dynamics Simulations","authors":"Archana Jagadisan, Z. Heidari","doi":"10.2118/195863-ms","DOIUrl":"https://doi.org/10.2118/195863-ms","url":null,"abstract":"\u0000 Development of reliable models for hydrocarbon-in-place and water saturation estimation requires knowledge about wettability of mudrocks and the parameters (including rock properties and reservoir condition) affecting it. A significant volume fraction of organic-rich mudrocks is composed of kerogen. Therefore, wettability of kerogen affects the overall wettability of organic-rich mudrocks. The chemical composition and structure of kerogen varies with kerogen type and thermal maturity, which affects the surface properties of kerogen such as wettability. In a recent publication, we demonstrated using experimental techniques that kerogen could be water-wet at low thermal maturities and oil-wet at higher thermal maturities. However, the impacts of kerogen type and reservoir temperature/pressure conditions on kerogen and mudrock wettability is yet to be quantified. Therefore, the objectives of this paper include (i) quantifying the impacts of kerogen molecular structure and composition on water adsorption capacities, (ii) quantifying the impacts of reservoir pressure and temperature on water adsorption capacity of kerogen using molecular dynamics (MD) simulations.\u0000 In order to achieve the aforementioned objectives, we use a combination of molecular dynamics simulations and experimental work. The inputs to the molecular dynamics simulations include realistic models of kerogen, which are condensed to porous kerogen structures. Water molecules are filled in kerogen pore structure and MD simulation is performed. The outputs of the simulations include radial distribution function (RDF), and adsorption isotherms of water on kerogen for different kerogen types, thermal maturities, and temperature conditions. The adsorption processes are modelled for pressure and temperature conditions ranging from 0 to 35 MPa and 320 to 370 K, respectively. The outcomes of molecular dynamics simulations demonstrated that the water adsorption capacities of kerogen vary significantly with kerogen type, thermal maturity, and temperature and pressure conditions. The RDF results showed that the water adsorption capacity decreased from type I to type III kerogen. The water adsorption capacity of kerogen was found to increase by 128% with 38% increase in oxygen content. The increase in the adsorption capacity was attributed to the strong attraction between oxygen containing functional groups in kerogen and water. The adsorption isotherms of water and kerogen samples showed that the water adsorption capacity decreased by 0.19 mmol/g as the temperature increased from 320 K to 370 K. The average water adsorption capacity of kerogen was found to increase by 20% with increase in pressure by 34 MPa. The results obtained from molecular dynamics simulations were found to be in good agreement with experimental results. The results of this paper can be used to predict the adsorption capacities of any kerogen with the availability of geochemical information. This important property of kerog","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90448749","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 simulation of the In Situ Combustion (ISC) process is a very challenging process due to the complexity and non-linear nature of the problem. In this work, we propose an efficient technique to simulate experimental procedures for the ISC process including heterogeneity. The effects of permeability on mass flow and heat transfer were studied through a series of numerical frameworks. Different approaches to model the reactions occurring during combustion were attempted and simulation results were validated using experimental results. We focus on two different key areas: the integration of chemical reaction kinetics obtained through kinetic cell experiments, and the analysis of efficient simulations of combustion tube experiments that account for the flow element. After establishing a robust framework that accurately matches lab-scale results, combustion tube simulation results using a commercial simulator were analyzed to corroborate conclusions. Through observing the propagation of the combustion front and the oil bank in heterogeneous zones, assessments around the effects of permeability on the ISC process were performed. This work provides valuable information that would be instrumental in understanding experimental behavior of in-situ combustion and upgrading results to field scale after matching numerical results with experimental data collected in our future work.
{"title":"Efficient Simulation and Analysis of the Effects of Permeability on the In-Situ Combustion of Heavy Oils","authors":"K. Aounallah","doi":"10.2118/199775-stu","DOIUrl":"https://doi.org/10.2118/199775-stu","url":null,"abstract":"\u0000 The simulation of the In Situ Combustion (ISC) process is a very challenging process due to the complexity and non-linear nature of the problem. In this work, we propose an efficient technique to simulate experimental procedures for the ISC process including heterogeneity. The effects of permeability on mass flow and heat transfer were studied through a series of numerical frameworks. Different approaches to model the reactions occurring during combustion were attempted and simulation results were validated using experimental results. We focus on two different key areas: the integration of chemical reaction kinetics obtained through kinetic cell experiments, and the analysis of efficient simulations of combustion tube experiments that account for the flow element. After establishing a robust framework that accurately matches lab-scale results, combustion tube simulation results using a commercial simulator were analyzed to corroborate conclusions. Through observing the propagation of the combustion front and the oil bank in heterogeneous zones, assessments around the effects of permeability on the ISC process were performed. This work provides valuable information that would be instrumental in understanding experimental behavior of in-situ combustion and upgrading results to field scale after matching numerical results with experimental data collected in our future work.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"91 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91338471","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}
Khatere Sokhanvarian, A. Diarra, Jorge Fernandez, C. Stanciu
Wax and paraffin precipitation is a major problem around the world, costing the petroleum industry billions of dollars yearly. As temperature drops below the Wax Appearance or Wax Precipitation Temperature (WAT/WPT) of crudes, paraffin starts to precipitate out and restrict or block the effective flow. There are different methods, such as mechanical and chemical remediation to deal with wax issues. Among the latter ones, the use of surfactants is favorably looked upon since they are small molecules with surface activity properties. This study aims to introduce novel aliphatic non-ionic surfactants with different chain length and degree of ethoxylation. In addition to chain length, the impact of branching on the hydrophobic part of the surfactants was also studied. A waxy crude oil from Brazil was characterized through determining its carbon distribution, WAT, viscosity and density based on industry standard methods. Several surfactants with different combinations of chain length/ethoxylation number were then selected for screening. The performance of surfactants was evaluated based on data obtained from treated crude versus the control sample through different experiments. Rheology studies were conducted at 50 to -10°C and at shear rates of 5 and 300 s-1. The cold finger instrument was utilized to determine paraffin content of the untreated and treated crude. Finally, the paraffin crystal size was analyzed through microscopic studies. The results showed that shear rate can affect the wax treatment outcome as well as the effective concentration of surfactant. Therefore, it is important to assess the rheology at high and low shear rates. Some surfactants in the present study performed great at both low and high shear rates and were able to reduce the viscosity by 80% at temperatures well below WAT of the crude oil. The microscopy results confirmed that wax crystals were reduced in size and were more dispersed after treating the crude with these surfactants. The findings from High Temperature Gas Chromatography showed that the deposition of heavy fraction part of crude (C40+) is reduced after treating the crude oil with the surfactants in the present study. The current study addresses the wax precipitation/deposition challenges of heavy crudes and proposes mitigating them through the use of some new non-aromatic non-ionic surfactants. The chemistries and findings of this research help the oil and gas industry to save money and time by mitigating flow assurance problems.
{"title":"Novel Non-Aromatic Non-Ionic Rheology Modifiers for High Paraffinic Crude Oils","authors":"Khatere Sokhanvarian, A. Diarra, Jorge Fernandez, C. Stanciu","doi":"10.2118/195894-ms","DOIUrl":"https://doi.org/10.2118/195894-ms","url":null,"abstract":"\u0000 Wax and paraffin precipitation is a major problem around the world, costing the petroleum industry billions of dollars yearly. As temperature drops below the Wax Appearance or Wax Precipitation Temperature (WAT/WPT) of crudes, paraffin starts to precipitate out and restrict or block the effective flow. There are different methods, such as mechanical and chemical remediation to deal with wax issues. Among the latter ones, the use of surfactants is favorably looked upon since they are small molecules with surface activity properties. This study aims to introduce novel aliphatic non-ionic surfactants with different chain length and degree of ethoxylation. In addition to chain length, the impact of branching on the hydrophobic part of the surfactants was also studied.\u0000 A waxy crude oil from Brazil was characterized through determining its carbon distribution, WAT, viscosity and density based on industry standard methods. Several surfactants with different combinations of chain length/ethoxylation number were then selected for screening. The performance of surfactants was evaluated based on data obtained from treated crude versus the control sample through different experiments. Rheology studies were conducted at 50 to -10°C and at shear rates of 5 and 300 s-1. The cold finger instrument was utilized to determine paraffin content of the untreated and treated crude. Finally, the paraffin crystal size was analyzed through microscopic studies.\u0000 The results showed that shear rate can affect the wax treatment outcome as well as the effective concentration of surfactant. Therefore, it is important to assess the rheology at high and low shear rates. Some surfactants in the present study performed great at both low and high shear rates and were able to reduce the viscosity by 80% at temperatures well below WAT of the crude oil. The microscopy results confirmed that wax crystals were reduced in size and were more dispersed after treating the crude with these surfactants. The findings from High Temperature Gas Chromatography showed that the deposition of heavy fraction part of crude (C40+) is reduced after treating the crude oil with the surfactants in the present study.\u0000 The current study addresses the wax precipitation/deposition challenges of heavy crudes and proposes mitigating them through the use of some new non-aromatic non-ionic surfactants. The chemistries and findings of this research help the oil and gas industry to save money and time by mitigating flow assurance problems.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87355823","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}
Mingyuan Wang, K. Baek, Gayan A. Abeykoon, F. J. Argüelles-Vivas, R. Okuno
Tight oil reservoirs typically show rapid reduction in production rate within a few years. Various methods of improved oil recovery from tight reservoirs have been studied, such as cyclic injection of gas and chemical solutions. Chemical solution injection is expected to improve oil recovery through wettability alteration and water/oil interfacial tension (IFT) reduction because most tight oil reservoirs are reportedly intermediate- to oil-wet. This paper presents a comparative study of two wettability modifiers with different characters for enhancing water imbibition from a fracture into the surrounding matrix. One is 3-pentanone, a symmetric short ketone, and the other is 2-ethylhexanol-4PO-15EO, a non-ionic surfactant with an ultra-short hydrophobe. They were used as low-concentration additives (approximately 1 wt%) to reservoir brine (RB) in this research. Contact-angle experiments with oil-aged calcite surfaces showed that the two chemicals are comparable as wettability modifiers. For example, the surfactant solution was able to change the contact angle of oil droplets on oil-aged calcite surfaces from 134° to 47° within a day. Coreflooding experiments using fractured limestone cores showed that the 3-pentanone solution resulted in more rapid oil recovery by water imbibition than the surfactant solution. The incremental oil recovery factor was 30.9% for 1.6 pore-volumes injected (PVI) of the 3-pentanone solution and 8.4% for 1.2 PVI of the chase RB. For the surfactant case, it was 23.6% for 1.6 PVI of the surfactant solution and 23.7% for 7.0 PVI of the chase RB. The difference in oil recovery response between the two chemical solutions was attributed to their different characters as wettability modifiers; that is, the surfactant solution lowers the water/oil IFT from 11 mN/m to 0.21 mN/m, but the 3-pentanone solution does not. The 3-pentanone solution can keep the original water/oil IFT, and increase the capillary force for water imbibition by wettability alteration. The importance of lowering the water/oil IFT was observed during the extended chase RB injection after the surfactant slug. The oil recovery in the surfactant case was increasing even after 7.0 PVI of the chase RB.
{"title":"Oxygenated Solvent as a Novel Additive for Improved Oil Recovery in Tight Oil Reservoirs","authors":"Mingyuan Wang, K. Baek, Gayan A. Abeykoon, F. J. Argüelles-Vivas, R. Okuno","doi":"10.2118/195871-ms","DOIUrl":"https://doi.org/10.2118/195871-ms","url":null,"abstract":"\u0000 Tight oil reservoirs typically show rapid reduction in production rate within a few years. Various methods of improved oil recovery from tight reservoirs have been studied, such as cyclic injection of gas and chemical solutions. Chemical solution injection is expected to improve oil recovery through wettability alteration and water/oil interfacial tension (IFT) reduction because most tight oil reservoirs are reportedly intermediate- to oil-wet.\u0000 This paper presents a comparative study of two wettability modifiers with different characters for enhancing water imbibition from a fracture into the surrounding matrix. One is 3-pentanone, a symmetric short ketone, and the other is 2-ethylhexanol-4PO-15EO, a non-ionic surfactant with an ultra-short hydrophobe. They were used as low-concentration additives (approximately 1 wt%) to reservoir brine (RB) in this research.\u0000 Contact-angle experiments with oil-aged calcite surfaces showed that the two chemicals are comparable as wettability modifiers. For example, the surfactant solution was able to change the contact angle of oil droplets on oil-aged calcite surfaces from 134° to 47° within a day.\u0000 Coreflooding experiments using fractured limestone cores showed that the 3-pentanone solution resulted in more rapid oil recovery by water imbibition than the surfactant solution. The incremental oil recovery factor was 30.9% for 1.6 pore-volumes injected (PVI) of the 3-pentanone solution and 8.4% for 1.2 PVI of the chase RB. For the surfactant case, it was 23.6% for 1.6 PVI of the surfactant solution and 23.7% for 7.0 PVI of the chase RB.\u0000 The difference in oil recovery response between the two chemical solutions was attributed to their different characters as wettability modifiers; that is, the surfactant solution lowers the water/oil IFT from 11 mN/m to 0.21 mN/m, but the 3-pentanone solution does not. The 3-pentanone solution can keep the original water/oil IFT, and increase the capillary force for water imbibition by wettability alteration. The importance of lowering the water/oil IFT was observed during the extended chase RB injection after the surfactant slug. The oil recovery in the surfactant case was increasing even after 7.0 PVI of the chase RB.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89775614","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}
Hao Yu, A. D. Taleghani, Zhanghua Lian, Tiejun Lin
Microseismic data and production logs in our study area have confirmed an asymmetric development of the stimulation rock volume, while severe casing deformation problems have been reported frequently in this area. In this paper, we investigate the possibility of casing failure due to strong shear stresses developed by asymmetric stimulated zones. Overlapping stimulation zones in adjacent stages may intensify asymmetry of the pore pressure distribution and resultant shear forces. Although induced shearing may have a positive impact on fracture permeability, but it may also cause operational problems by inducing severe casing deformations. While most of the casing deformation models only consider rock deformations very close to the wellbore, we developed a 3D coupled model for fracture network growth and stress re-distribution during hydraulic fracturing to achieve a more realistic model for casing deformation. This reservoir-scale model is tied to a more detailed near-wellbore model including the casing and cement sheath to simulate casing deformations. Case studies were conducted using data from a shale gas well that experienced severe casing deformation during hydraulic fracturing. Impact of stage spacing, and pumping rate are incorporated to investigate their potential impacts on casing and well integrity. Multi-stage hydraulic fracturing considering the development of complex fracture network is simulated at the reservoir scale based on the microseismic events. Continuous re-distribution and re-orientation of stress field near the borehole are tracked during the development of the fracture network which reveals some pocket of tensile stresses along the casing. Asymmetric fractures are observed to generate strong shear stress on the suspended casing. These shear forces result in deflection and S-shape deformations. Some regions receive repeating treatments, which leads to increase formation stress heterogeneity and worsen casing deformation severity. Our analysis has indicated that simply increasing the flexural strength by increasing thickness of casing cannot radically mitigate casing deformation problems. This paper provides a novel workflow for a coupled modelling of casing deformation during hydraulic fracturing operations, while current modelling efforts assume symmetric fracture geometries.
{"title":"Impact of Asymmetric Stimulated Rock Volume on Casing Deformation in Multi-Stage Fracturing; A Case Study","authors":"Hao Yu, A. D. Taleghani, Zhanghua Lian, Tiejun Lin","doi":"10.2118/195944-ms","DOIUrl":"https://doi.org/10.2118/195944-ms","url":null,"abstract":"\u0000 Microseismic data and production logs in our study area have confirmed an asymmetric development of the stimulation rock volume, while severe casing deformation problems have been reported frequently in this area. In this paper, we investigate the possibility of casing failure due to strong shear stresses developed by asymmetric stimulated zones. Overlapping stimulation zones in adjacent stages may intensify asymmetry of the pore pressure distribution and resultant shear forces. Although induced shearing may have a positive impact on fracture permeability, but it may also cause operational problems by inducing severe casing deformations. While most of the casing deformation models only consider rock deformations very close to the wellbore, we developed a 3D coupled model for fracture network growth and stress re-distribution during hydraulic fracturing to achieve a more realistic model for casing deformation. This reservoir-scale model is tied to a more detailed near-wellbore model including the casing and cement sheath to simulate casing deformations. Case studies were conducted using data from a shale gas well that experienced severe casing deformation during hydraulic fracturing. Impact of stage spacing, and pumping rate are incorporated to investigate their potential impacts on casing and well integrity. Multi-stage hydraulic fracturing considering the development of complex fracture network is simulated at the reservoir scale based on the microseismic events. Continuous re-distribution and re-orientation of stress field near the borehole are tracked during the development of the fracture network which reveals some pocket of tensile stresses along the casing. Asymmetric fractures are observed to generate strong shear stress on the suspended casing. These shear forces result in deflection and S-shape deformations. Some regions receive repeating treatments, which leads to increase formation stress heterogeneity and worsen casing deformation severity. Our analysis has indicated that simply increasing the flexural strength by increasing thickness of casing cannot radically mitigate casing deformation problems. This paper provides a novel workflow for a coupled modelling of casing deformation during hydraulic fracturing operations, while current modelling efforts assume symmetric fracture geometries.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"187 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85440151","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}
Production and drilling activities in offshore installation are one of the most necessary activities of human society. To drill a subsea well and raise the crude oil to a platform, by itself, presents a series of risks. Associated with this activity, when the crude oil reaches the topside of the platform, there are a number of operations that prepare the oil and gas to be exported to land by pipelines or oil tanker vessels, which involves equipment and process that take high temperatures, high pressure and high flow rates. Understanding the dynamics of the factors that can affect the interaction of operators with all these offshore complex systems is critical, because the loss of control of these systems can cause serious accidents, resulting in injuries to workers, environmental damage, loss of production and geopolitical crises. Accidents in the oil and gas offshore installations, such as drilling rigs and FPSOs, can have tragic consequences and all efforts should be targeted to prevent its recurrence. Therefore, from the perspective of current technological developments, it is essential to consider the influence of Human Factors in the risk management of offshore industrial plants.
{"title":"Case Study: Human Factors Analysis of FPSO Operations Activities in Brazil","authors":"J. França, Isaac L. dos Santos, A. Haddad","doi":"10.2118/196021-ms","DOIUrl":"https://doi.org/10.2118/196021-ms","url":null,"abstract":"\u0000 Production and drilling activities in offshore installation are one of the most necessary activities of human society. To drill a subsea well and raise the crude oil to a platform, by itself, presents a series of risks. Associated with this activity, when the crude oil reaches the topside of the platform, there are a number of operations that prepare the oil and gas to be exported to land by pipelines or oil tanker vessels, which involves equipment and process that take high temperatures, high pressure and high flow rates. Understanding the dynamics of the factors that can affect the interaction of operators with all these offshore complex systems is critical, because the loss of control of these systems can cause serious accidents, resulting in injuries to workers, environmental damage, loss of production and geopolitical crises. Accidents in the oil and gas offshore installations, such as drilling rigs and FPSOs, can have tragic consequences and all efforts should be targeted to prevent its recurrence. Therefore, from the perspective of current technological developments, it is essential to consider the influence of Human Factors in the risk management of offshore industrial plants.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"779 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76915317","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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