R. Hincapie, Ante Borovina, E. Neubauer, Samhar Saleh, Vladislav Arekhov, M. Biernat, T. Clemens, Muhammad Tahir
Even though the influence of wettability alteration on imbibition is well-documented, its synergy with Interfacial-Tension (IFT) for Alkali/Nanoparticles/Polymer flooding requires additional investigation. Particularly, when the oil Total Acid Number (TAN) may determine the wetting-state of the reservoir and influences IFT. Therefore, a laboratory evaluation workflow is presented that combines complementary assessments such as spontaneous imbibition tests, IFT and contact angles measurements. This workflow aims at evaluating wettability alteration and IFT changes when injecting Alkali, Nanoparticles and Polymers or a combination of them. Dynamics and mechanism of imbibition was tracked by analyzing the recovery change with the inverse Bond number. Three sandstone types (outcrops) were used that mainly differ in clay content and permeability. Oils with low and high-TAN were used, the latter from the potential field pilot 16TH reservoir in the Matzen field (Austria). We have identified the conditions leading to an increase of recovery rates as well as ultimate recovery by imbibition of Alkali/Nanoparticles/Polymer aqueous phases. Data obtained demonstrate how oil TAN number (low and high), chemical agent and reservoir mineralogy influence fluid-fluid and rock-fluid interactions. Application of alkali with high-TAN oil resulted in a low-equilibrium IFT. Alkali-alone fall short to mobilize trapped low-TAN oil. Alkali-polymer is efficient in wettability alteration of oil-wet core plugs towards water-wet state for high-TAN oil. The investigated nanofluids manage to restore a water-wet state in cores with high clay content along with improving gravity driven flow. IFT reduction between oil and surface-modified nanoparticles is unaffected by the acidity of the oil. Furthermore, contact angle in high-TAN oil remained similar even after 1000 min of observation for 2.5% clay cores in synthetic brine, but increases significantly when in contact with alkali/polymer. Comparing porosity and permeability before and after imbibition, a slight reduction was observed after imbibition with brine and nanofluids. We preliminary conclude that permeability reduction is not associated to the tested nanoparticles present in solution. We observed evidence of change in the imbibition mechanism from counter-current (capillary driven/high inverse Bond number) to co-current (gravity driven/low inverse Bond number) for nanoparticles/alkali. The calculated inverse Bond number correlates with the ultimate recovery, larger inverse Bond number leading to lower ultimate recovery. This work presents novel data on the synergy of IFT, contact angles and Amott imbibition for the chemical processes studied. We leverage from complementary laboratory techniques to define a comprehensive workflow that allows understanding wettability-alteration when injecting Alkali, Nanoparticles and Polymers or a combination of them. Obtained results show that the workflow can be used as an efficien
{"title":"Dynamics of Wettability Alteration from Alkali/Nanoparticles/Polymer Flooding - Integrating Data of Imbibition, Contact Angle and Interfacial-Tension to Screen Injection Agents","authors":"R. Hincapie, Ante Borovina, E. Neubauer, Samhar Saleh, Vladislav Arekhov, M. Biernat, T. Clemens, Muhammad Tahir","doi":"10.2118/206242-ms","DOIUrl":"https://doi.org/10.2118/206242-ms","url":null,"abstract":"\u0000 Even though the influence of wettability alteration on imbibition is well-documented, its synergy with Interfacial-Tension (IFT) for Alkali/Nanoparticles/Polymer flooding requires additional investigation. Particularly, when the oil Total Acid Number (TAN) may determine the wetting-state of the reservoir and influences IFT. Therefore, a laboratory evaluation workflow is presented that combines complementary assessments such as spontaneous imbibition tests, IFT and contact angles measurements. This workflow aims at evaluating wettability alteration and IFT changes when injecting Alkali, Nanoparticles and Polymers or a combination of them. Dynamics and mechanism of imbibition was tracked by analyzing the recovery change with the inverse Bond number. Three sandstone types (outcrops) were used that mainly differ in clay content and permeability. Oils with low and high-TAN were used, the latter from the potential field pilot 16TH reservoir in the Matzen field (Austria).\u0000 We have identified the conditions leading to an increase of recovery rates as well as ultimate recovery by imbibition of Alkali/Nanoparticles/Polymer aqueous phases. Data obtained demonstrate how oil TAN number (low and high), chemical agent and reservoir mineralogy influence fluid-fluid and rock-fluid interactions.\u0000 Application of alkali with high-TAN oil resulted in a low-equilibrium IFT. Alkali-alone fall short to mobilize trapped low-TAN oil. Alkali-polymer is efficient in wettability alteration of oil-wet core plugs towards water-wet state for high-TAN oil. The investigated nanofluids manage to restore a water-wet state in cores with high clay content along with improving gravity driven flow. IFT reduction between oil and surface-modified nanoparticles is unaffected by the acidity of the oil. Furthermore, contact angle in high-TAN oil remained similar even after 1000 min of observation for 2.5% clay cores in synthetic brine, but increases significantly when in contact with alkali/polymer.\u0000 Comparing porosity and permeability before and after imbibition, a slight reduction was observed after imbibition with brine and nanofluids. We preliminary conclude that permeability reduction is not associated to the tested nanoparticles present in solution. We observed evidence of change in the imbibition mechanism from counter-current (capillary driven/high inverse Bond number) to co-current (gravity driven/low inverse Bond number) for nanoparticles/alkali. The calculated inverse Bond number correlates with the ultimate recovery, larger inverse Bond number leading to lower ultimate recovery.\u0000 This work presents novel data on the synergy of IFT, contact angles and Amott imbibition for the chemical processes studied. We leverage from complementary laboratory techniques to define a comprehensive workflow that allows understanding wettability-alteration when injecting Alkali, Nanoparticles and Polymers or a combination of them. Obtained results show that the workflow can be used as an efficien","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73061811","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 uncommon facet of Formation Evaluation is the assessment of flow-related in situ properties of rocks. Most of the models used to describe two-phase flow properties of porous rocks assume homogeneous and/or isotropic media, which is hardly the case with actual reservoir rocks, regardless of scale; carbonates and grain-laminated sandstones are but two common examples of this situation. The degree of spatial complexity of rocks and its effect on the mobility of hydrocarbons are of paramount importance for the description of multiphase fluid flow in most contemporary reservoirs. There is thus a need for experimental and numerical methods that integrate all salient details about fluid-fluid and rock-fluid interactions. Such hybrid, laboratory-simulation projects are necessary to develop realistic models of fractional flow, i.e., saturation-dependent capillary pressure and relative permeability. We document a new high-resolution visualization technique that provides experimental insight to quantify fluid saturation patterns in heterogeneous rocks and allows for the evaluation of effective two-phase flow properties. The experimental apparatus consists of an X-ray microfocus scanner and an automated syringe pump. Rather than using traditional cylindrical cores, thin rectangular rock samples are examined, their thickness being one order of magnitude smaller than the remaining two dimensions. During the experiment, the core is scanned quasi-continuously while the fluids are being injected, allowing for time-lapse visualization of the flood front. Numerical simulations are then conducted to match the experimental data and quantify effective saturation-dependent relative permeability and capillary pressure. Experimental results indicate that flow patterns and in situ saturations are highly dependent on the nature of the heterogeneity and bedding-plane orientation during both imbibition and drainage cycles. In homogeneous rocks, fluid displacement is piston-like, as predicted by the Buckley-Leverett theory of fractional flow. Assessment of capillary pressure and relative permeability is performed by examining the time-lapse water saturation profiles. In spatially complex rocks, high-resolution time-lapse images reveal preferential flow paths along high permeability sections and a lowered sweep efficiency. Our experimental procedure emphasizes that capillary pressure and transmissibility differences play an important role in fluid-saturation distribution and sweep efficiency at late times. The method is fast and reliable to assess mixing laws for fluid-transport properties of rocks in spatially complex formations.
{"title":"Experimental Investigation of Two-Phase Flow Properties of Heterogeneous Rocks for Advanced Formation Evaluation","authors":"P. Aérens, C. Torres‐Verdín, D. Espinoza","doi":"10.2118/206334-ms","DOIUrl":"https://doi.org/10.2118/206334-ms","url":null,"abstract":"\u0000 An uncommon facet of Formation Evaluation is the assessment of flow-related in situ properties of rocks. Most of the models used to describe two-phase flow properties of porous rocks assume homogeneous and/or isotropic media, which is hardly the case with actual reservoir rocks, regardless of scale; carbonates and grain-laminated sandstones are but two common examples of this situation. The degree of spatial complexity of rocks and its effect on the mobility of hydrocarbons are of paramount importance for the description of multiphase fluid flow in most contemporary reservoirs. There is thus a need for experimental and numerical methods that integrate all salient details about fluid-fluid and rock-fluid interactions. Such hybrid, laboratory-simulation projects are necessary to develop realistic models of fractional flow, i.e., saturation-dependent capillary pressure and relative permeability.\u0000 We document a new high-resolution visualization technique that provides experimental insight to quantify fluid saturation patterns in heterogeneous rocks and allows for the evaluation of effective two-phase flow properties. The experimental apparatus consists of an X-ray microfocus scanner and an automated syringe pump. Rather than using traditional cylindrical cores, thin rectangular rock samples are examined, their thickness being one order of magnitude smaller than the remaining two dimensions. During the experiment, the core is scanned quasi-continuously while the fluids are being injected, allowing for time-lapse visualization of the flood front. Numerical simulations are then conducted to match the experimental data and quantify effective saturation-dependent relative permeability and capillary pressure.\u0000 Experimental results indicate that flow patterns and in situ saturations are highly dependent on the nature of the heterogeneity and bedding-plane orientation during both imbibition and drainage cycles. In homogeneous rocks, fluid displacement is piston-like, as predicted by the Buckley-Leverett theory of fractional flow. Assessment of capillary pressure and relative permeability is performed by examining the time-lapse water saturation profiles. In spatially complex rocks, high-resolution time-lapse images reveal preferential flow paths along high permeability sections and a lowered sweep efficiency.\u0000 Our experimental procedure emphasizes that capillary pressure and transmissibility differences play an important role in fluid-saturation distribution and sweep efficiency at late times. The method is fast and reliable to assess mixing laws for fluid-transport properties of rocks in spatially complex formations.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75524937","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}
F. Sajjad, S. Chandra, A. Wirawan, Silvya Dewi Rahmawati, Michelle Santoso, Wingky Suganda
In the implementation of gas lift, understanding flow behavior in highly-deviated well is critical in avoiding production loss due to liquid fallback and blockage, even in highly-productive reservoir. In this work, we utilize Computational Fluid Dynamics (CFD) to optimize gas lift design under various flow behavior in highly-deviated well. The analysis is directly implemented into Arjuna offshore field case. Arjuna offshore field has gas-lifted wells, producing from a high-permeability reservoir. However, several wells suffer from huge production loss due to the effect of well's deviation. In deviated well, there exists frequent liquid fallback causes blockage, therefore, reducing the production. Motivated by this issue, we use CFD framework to perform gas lift optimization. We firstly adopt the geometry of gas-lifted wells as the computational domains for our simulation. An image-based meshing technique is deployed to capture the well's trajectory and internal geometry. We secondly utilize compressible Navier-Stokes equation and Finite Volume Method to evaluate the flow behavior. We capture the location of liquid fallback and liquid accumulation at elbows to estimate production loss. We consider the variation of viscosity, density, gas lift valve placement, injected gas rate, and reservoir pressure. We finally perform gradient-based optimization utilizing production loss as the objective function to obtain optimum design. The final result is then used to optimize the current design. The simulation results show that productivity index, pipe diameter, and deviation heavily influence the amount of production loss. At big pipe diameter and high deviation, the gravitational force governs the fluid flow. Therefore, slugs are developed and accumulated at elbows. This accumulation blocks gas flow and reduces production. Changing the gas injection rate affects the lifted density. High injection rate triggers segregation between the liquid and gas, while low injection rate does not reduce the liquid density. Shifting the gas lift valve placement influence the mixing between the liquid and gas. It also determines the cost of gas injection. Hence, we need to optimize both parameters at once. Six of thirty wells in Arjuna field experience severe liquid fallback, therefore, the production significantly decreases. The simulation shows up to 40% coverage of the pipe internal diameter, which blocks the gas flow. We perform the optimization by shifting the gas lift valve placement and adjusting the gas injection rate. By implementing the study result into the field case, we manage to improve the production by 20%. We provide an effective way to connect high-resolution simulation to the field design and revise the current concept in designing gas lift well completion. The simulation allows engineers to provide more insight on flow assurance in highly deviated wells.
{"title":"Computational Fluid Dynamics for Gas Lift Optimization in Highly Deviated Wells","authors":"F. Sajjad, S. Chandra, A. Wirawan, Silvya Dewi Rahmawati, Michelle Santoso, Wingky Suganda","doi":"10.2118/206198-ms","DOIUrl":"https://doi.org/10.2118/206198-ms","url":null,"abstract":"\u0000 In the implementation of gas lift, understanding flow behavior in highly-deviated well is critical in avoiding production loss due to liquid fallback and blockage, even in highly-productive reservoir. In this work, we utilize Computational Fluid Dynamics (CFD) to optimize gas lift design under various flow behavior in highly-deviated well. The analysis is directly implemented into Arjuna offshore field case.\u0000 Arjuna offshore field has gas-lifted wells, producing from a high-permeability reservoir. However, several wells suffer from huge production loss due to the effect of well's deviation. In deviated well, there exists frequent liquid fallback causes blockage, therefore, reducing the production. Motivated by this issue, we use CFD framework to perform gas lift optimization.\u0000 We firstly adopt the geometry of gas-lifted wells as the computational domains for our simulation. An image-based meshing technique is deployed to capture the well's trajectory and internal geometry. We secondly utilize compressible Navier-Stokes equation and Finite Volume Method to evaluate the flow behavior. We capture the location of liquid fallback and liquid accumulation at elbows to estimate production loss. We consider the variation of viscosity, density, gas lift valve placement, injected gas rate, and reservoir pressure. We finally perform gradient-based optimization utilizing production loss as the objective function to obtain optimum design. The final result is then used to optimize the current design.\u0000 The simulation results show that productivity index, pipe diameter, and deviation heavily influence the amount of production loss. At big pipe diameter and high deviation, the gravitational force governs the fluid flow. Therefore, slugs are developed and accumulated at elbows. This accumulation blocks gas flow and reduces production.\u0000 Changing the gas injection rate affects the lifted density. High injection rate triggers segregation between the liquid and gas, while low injection rate does not reduce the liquid density. Shifting the gas lift valve placement influence the mixing between the liquid and gas. It also determines the cost of gas injection. Hence, we need to optimize both parameters at once.\u0000 Six of thirty wells in Arjuna field experience severe liquid fallback, therefore, the production significantly decreases. The simulation shows up to 40% coverage of the pipe internal diameter, which blocks the gas flow. We perform the optimization by shifting the gas lift valve placement and adjusting the gas injection rate. By implementing the study result into the field case, we manage to improve the production by 20%.\u0000 We provide an effective way to connect high-resolution simulation to the field design and revise the current concept in designing gas lift well completion. The simulation allows engineers to provide more insight on flow assurance in highly deviated wells.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76058353","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. Cely, A. Zaostrovski, Tao Yang, K. Uleberg, M. Kopal
There are increased development activities in shale reservoirs with ultra-low permeability thanks to the advances in drilling and fracking technology. However, representative reservoir fluid samples are still difficult to acquire. The challenge leads to limited reservoir fluid data and large uncertainties for shale play evaluation, field development, and production optimization. In this work, we built a large unconventional reservoir fluid database with more than 2400 samples from shale reservoirs in Canada, Argentina, and the USA, comprising early production surface gas data and traditional PVT data from selected shale assets. A machine learning approach was applied to the database to predict gas to oil ratio (GOR) in shale reservoirs. To enhance regional correlations and obtain a more accurate GOR prediction, we developed a machine learning model focused on Canada shale plays data, intended for wells with limited reservoir fluid data available and located within the same region. Both surface gas compositional data and well location and are input features to this model. In addition, we developed an additional machine learning model for the objective of a generic GOR prediction model without shale dependency. The database includes Canada shale data and Argentina and USA shale data. The GOR predictions obtained from both models are good. The machine learning model circumscribed to the Canada shale reservoirs has a mean percentage error (MAPE) of 4.31. In contrast, the generic machine learning model, which includes additional data from Argentina and USA shale assets, has a MAPE of 4.86. The better accuracy of the circumscribed Canada model is due to the introduction of the geospatial well location to the model features. This study confirms that early production surface gas data can be used to predict well GOR in shale reservoirs, providing an economical alternative for the sampling challenges during early field development. Furthermore, the GOR prediction offers access to a complete set of reservoir fluid properties which assists the decision-making process for shale play evaluation, completion concept selection, and production optimization.
{"title":"Well GOR Prediction from Surface Gas Composition in Shale Reservoirs","authors":"A. Cely, A. Zaostrovski, Tao Yang, K. Uleberg, M. Kopal","doi":"10.2118/205842-ms","DOIUrl":"https://doi.org/10.2118/205842-ms","url":null,"abstract":"\u0000 There are increased development activities in shale reservoirs with ultra-low permeability thanks to the advances in drilling and fracking technology. However, representative reservoir fluid samples are still difficult to acquire. The challenge leads to limited reservoir fluid data and large uncertainties for shale play evaluation, field development, and production optimization.\u0000 In this work, we built a large unconventional reservoir fluid database with more than 2400 samples from shale reservoirs in Canada, Argentina, and the USA, comprising early production surface gas data and traditional PVT data from selected shale assets. A machine learning approach was applied to the database to predict gas to oil ratio (GOR) in shale reservoirs.\u0000 To enhance regional correlations and obtain a more accurate GOR prediction, we developed a machine learning model focused on Canada shale plays data, intended for wells with limited reservoir fluid data available and located within the same region. Both surface gas compositional data and well location and are input features to this model. In addition, we developed an additional machine learning model for the objective of a generic GOR prediction model without shale dependency. The database includes Canada shale data and Argentina and USA shale data.\u0000 The GOR predictions obtained from both models are good. The machine learning model circumscribed to the Canada shale reservoirs has a mean percentage error (MAPE) of 4.31. In contrast, the generic machine learning model, which includes additional data from Argentina and USA shale assets, has a MAPE of 4.86. The better accuracy of the circumscribed Canada model is due to the introduction of the geospatial well location to the model features.\u0000 This study confirms that early production surface gas data can be used to predict well GOR in shale reservoirs, providing an economical alternative for the sampling challenges during early field development. Furthermore, the GOR prediction offers access to a complete set of reservoir fluid properties which assists the decision-making process for shale play evaluation, completion concept selection, and production optimization.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"77 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75725209","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}
V. Brun, E. Morgan, Brad Gerl, L. Cardozo, J. Batias
Surmont is a heavy oil field located in northeast Alberta which is currently being developed by a joint venture between ConocoPhillips and Total using Steam Assisted Gravity Drainage (SAGD). To monitor the enhanced oil recovery process and caprock integrity, highly repeatable 4D seismic surveys using dynamite have been completed over the years. In order to maximize the value of information while controlling costs, a novel light seismic monitoring approach has been "blind-tested" on existing 4D data. The concept requires the use of only one source and one receiver couple, optimally placed in the field to monitor one or several subsurface spots, using time redundancy to detect 4D changes in these zones of interest. Three spot locations have been defined by the client on a well pad for which the history was not provided. For each of these spots, specific series of seismic processing steps have enabled the identification of the optimum source/receiver locations. Then, these optimum raw seismic traces extracted from different 4D campaigns have been analysed to detect potential time shift changes in the selected horizon induced by the growth of the steam chamber. Time-shift changes were plotted for all 3 spots. An increase was observed for one of the spots (Spot 3) from the first 4D monitor in 2010 up to the last monitor in 2015. An increase was also plotted between March 2013 and September 2013 for another spot (Spot 1), changes attributed to the dynamics of the steam chamber. On the contrary, spot 1 did not see any effect of the steam. These time-shift changes were then successfully cross-checked with temperature data from observation wells, confirming the qualitative variations attributed to the effects of the steam chamber evolution. It demonstrated the viability of this innovative seismic and focused monitoring approach to monitor the evolution of the steam chamber in Surmont. This also paves the way for a simpler and yet reliable and cost-effective way of monitoring the evolution of the steam chamber to further optimize production and increase rentability.
{"title":"Aplicability of an Innovative and Light Seismic Approach to Monitor SAGD Operations in Surmont: A Blind Test","authors":"V. Brun, E. Morgan, Brad Gerl, L. Cardozo, J. Batias","doi":"10.2118/206127-ms","DOIUrl":"https://doi.org/10.2118/206127-ms","url":null,"abstract":"\u0000 Surmont is a heavy oil field located in northeast Alberta which is currently being developed by a joint venture between ConocoPhillips and Total using Steam Assisted Gravity Drainage (SAGD). To monitor the enhanced oil recovery process and caprock integrity, highly repeatable 4D seismic surveys using dynamite have been completed over the years. In order to maximize the value of information while controlling costs, a novel light seismic monitoring approach has been \"blind-tested\" on existing 4D data.\u0000 The concept requires the use of only one source and one receiver couple, optimally placed in the field to monitor one or several subsurface spots, using time redundancy to detect 4D changes in these zones of interest. Three spot locations have been defined by the client on a well pad for which the history was not provided. For each of these spots, specific series of seismic processing steps have enabled the identification of the optimum source/receiver locations. Then, these optimum raw seismic traces extracted from different 4D campaigns have been analysed to detect potential time shift changes in the selected horizon induced by the growth of the steam chamber.\u0000 Time-shift changes were plotted for all 3 spots. An increase was observed for one of the spots (Spot 3) from the first 4D monitor in 2010 up to the last monitor in 2015. An increase was also plotted between March 2013 and September 2013 for another spot (Spot 1), changes attributed to the dynamics of the steam chamber. On the contrary, spot 1 did not see any effect of the steam. These time-shift changes were then successfully cross-checked with temperature data from observation wells, confirming the qualitative variations attributed to the effects of the steam chamber evolution.\u0000 It demonstrated the viability of this innovative seismic and focused monitoring approach to monitor the evolution of the steam chamber in Surmont. This also paves the way for a simpler and yet reliable and cost-effective way of monitoring the evolution of the steam chamber to further optimize production and increase rentability.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73331472","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}
Conventional ICDs were invented for long horizontal wells to promote a more uniform inflow profile. Later, AICDs were developed, which utilize viscosity contrast between fluids to impose a larger hydraulic resistance in sections with inflow of undesired fluids, like gas and water. However, these AICD technologies cannot be used to choke back inflow of water in reservoirs where oil and water have similar viscosities, and they also tend to impose large pressure drops even for single-phase oil at high flow rates. The objective of the work presented here has therefore been to develop an inflow control technology that removes these limitations. The resulting Density Activated Recovery (DAR™) technology utilizes difference in fluid density rather than viscosity contrast to control fluids downhole. It is a fully autonomous, binary system that is either fully open or closed, where "closed" means that it only allows a small pilot flow. More specifically, it can be considered a "dual ICD" with flow through a large port when open, and a small port when "closed". The flow capacity and choking efficiency are therefore fully defined by the diameters of these two ports. Furthermore, it can close and reopen at any pre-determined water and gas fractions, that are completely insensitive to flow rate, viscosity and Reynolds number. This makes it universally applicable to control any wellbore fluid along the entire reservoir section. After successful prototype testing in 2018, the DAR technology has now undergone a comprehensive full-scale system-qualification program including a final flow performance test where the system was tested at 240 bar and 90ºC with saturated 0.8 cP oil. The tests demonstrated up to seven times higher flow capacity with the density-based DAR technology compared with viscosity-dependent AICD technologies. The system successfully and repeatedly closed and reopened for both gas and water. As oil and water had similar viscosities, the tests also proved how this technology can be used to stop undesired inflow of water in light-oil reservoirs. Being insensitive to flow rate, the DAR system is also insensitive to local variations in pressure and productivity along the reservoir section, which reduces the negative consequences of geological uncertainty and allows the same design to be used at every location in the well. It can also be configured to ensure complete mud removal during well cleanup and can even stop inflow of water in gas wells, where the undesired fluid has higher viscosity than the desired fluid. More importantly, this technology can deliver automated reservoir management to a level where it influences how wells are drilled and fields are developed. Accelerated oil production and the reduced need for reinjection of gas/water will also reduce the associated greenhouse gas (GHG) emissions considerably.
{"title":"Delivering Automated Reservoir Management with Birth of the First Ever Universal Inflow Control System UICS","authors":"R. Killie, Grant J. Paterson, Thorleif Lager","doi":"10.2118/205868-ms","DOIUrl":"https://doi.org/10.2118/205868-ms","url":null,"abstract":"Conventional ICDs were invented for long horizontal wells to promote a more uniform inflow profile. Later, AICDs were developed, which utilize viscosity contrast between fluids to impose a larger hydraulic resistance in sections with inflow of undesired fluids, like gas and water. However, these AICD technologies cannot be used to choke back inflow of water in reservoirs where oil and water have similar viscosities, and they also tend to impose large pressure drops even for single-phase oil at high flow rates. The objective of the work presented here has therefore been to develop an inflow control technology that removes these limitations.\u0000 The resulting Density Activated Recovery (DAR™) technology utilizes difference in fluid density rather than viscosity contrast to control fluids downhole. It is a fully autonomous, binary system that is either fully open or closed, where \"closed\" means that it only allows a small pilot flow. More specifically, it can be considered a \"dual ICD\" with flow through a large port when open, and a small port when \"closed\". The flow capacity and choking efficiency are therefore fully defined by the diameters of these two ports. Furthermore, it can close and reopen at any pre-determined water and gas fractions, that are completely insensitive to flow rate, viscosity and Reynolds number. This makes it universally applicable to control any wellbore fluid along the entire reservoir section.\u0000 After successful prototype testing in 2018, the DAR technology has now undergone a comprehensive full-scale system-qualification program including a final flow performance test where the system was tested at 240 bar and 90ºC with saturated 0.8 cP oil. The tests demonstrated up to seven times higher flow capacity with the density-based DAR technology compared with viscosity-dependent AICD technologies. The system successfully and repeatedly closed and reopened for both gas and water. As oil and water had similar viscosities, the tests also proved how this technology can be used to stop undesired inflow of water in light-oil reservoirs.\u0000 Being insensitive to flow rate, the DAR system is also insensitive to local variations in pressure and productivity along the reservoir section, which reduces the negative consequences of geological uncertainty and allows the same design to be used at every location in the well. It can also be configured to ensure complete mud removal during well cleanup and can even stop inflow of water in gas wells, where the undesired fluid has higher viscosity than the desired fluid. More importantly, this technology can deliver automated reservoir management to a level where it influences how wells are drilled and fields are developed. Accelerated oil production and the reduced need for reinjection of gas/water will also reduce the associated greenhouse gas (GHG) emissions considerably.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85176897","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}
Predicting accurate erosion rate due to sand particles in oil and gas production is important for maintaining safe and reliable operations while maximizing output efficiency. Computational Fluid Dynamic (CFD) is a powerful tool for erosion prediction as it provides detailed erosion pattern in complex geometry. In an effort to improve accuracy of erosion prediction, this paper proposes an algorithm to accurately represent particle shape in CFD erosion simulation through coupling with Discrete Element Method (DEM) for non-spherical shape particles. The fluid motions are predicted by CFD and the particle movements (including particle-particle and particle-wall collisions) and fluid-particle interaction are calculated using DEM. It is widely known that sand particles are of finite volume with a non-spherical shape, accurate representation of sand particles is important in CFD modelling for accurate prediction of erosion rate. Traditional CFD approach usages lagrangian tracking of sand particles through Discrete Phase Model (DPM), where a particle is assumed as a point mass for the calculation of trajectory and particle-wall interaction. Particle impact velocity and impact angle are important parameter in determining erosion. Assumption of point mass in DPM approach, will not capture particle-wall interaction accurately especially when particles are of non-spherical in shape. In additional, DPM approach ignores particle-particle interactions. This can adversary affect the accuracy of erosion predictions. Integrating non-spherical DEM collision algorithm with CFD erosion simulation, will overcome these limitations and improve erosion predictions. Benefits of this CFD-DEM erosion modelling was demonstrated for gas-solid flow in a 2" pipework which consists of out-of-plane elbows in series and blind-tees. Experimental dataset [1] for erosion pattern on each elbow was used to validate CFD predictions. Three different erosion CFD simulations were performed, traditional DPM based CFD simulation, CFD-DEM simulation for spherical shape particles and CFD-DEM simulation for non-spherical shape particles. CFD-DEM coupled simulations clearly show an improvement on erosion predictions compared to DPM based CFD simulation. Effect of non-spherical shape on rebound angle during particle-wall collision is captured accurately in CFD-DEM simulation. CFD-DEM simulation using non-spherical particle, was able to predict erosion pattern closer to experimental observations. This paper will demonstrate an increase in accuracy of sand erosion prediction by integrating DEM collision algorithm in CFD modelling. The prediction results of elbow erosion subject to a condition of dilute gas-particle flow are validated against experimental data. Improved prediction of erosion risk will increase the safety and reliability of oil & gas operations, while maximizing output efficiency.
{"title":"Improved Prediction of Sand Erosion by Accurate Particle Shape Representation in CFD-DEM Modelling","authors":"M. Agrawal, Ahmadreza Haghnegahdar, R. Bharadwaj","doi":"10.2118/206122-ms","DOIUrl":"https://doi.org/10.2118/206122-ms","url":null,"abstract":"Predicting accurate erosion rate due to sand particles in oil and gas production is important for maintaining safe and reliable operations while maximizing output efficiency. Computational Fluid Dynamic (CFD) is a powerful tool for erosion prediction as it provides detailed erosion pattern in complex geometry. In an effort to improve accuracy of erosion prediction, this paper proposes an algorithm to accurately represent particle shape in CFD erosion simulation through coupling with Discrete Element Method (DEM) for non-spherical shape particles. The fluid motions are predicted by CFD and the particle movements (including particle-particle and particle-wall collisions) and fluid-particle interaction are calculated using DEM.\u0000 It is widely known that sand particles are of finite volume with a non-spherical shape, accurate representation of sand particles is important in CFD modelling for accurate prediction of erosion rate. Traditional CFD approach usages lagrangian tracking of sand particles through Discrete Phase Model (DPM), where a particle is assumed as a point mass for the calculation of trajectory and particle-wall interaction. Particle impact velocity and impact angle are important parameter in determining erosion. Assumption of point mass in DPM approach, will not capture particle-wall interaction accurately especially when particles are of non-spherical in shape. In additional, DPM approach ignores particle-particle interactions. This can adversary affect the accuracy of erosion predictions. Integrating non-spherical DEM collision algorithm with CFD erosion simulation, will overcome these limitations and improve erosion predictions.\u0000 Benefits of this CFD-DEM erosion modelling was demonstrated for gas-solid flow in a 2\" pipework which consists of out-of-plane elbows in series and blind-tees. Experimental dataset [1] for erosion pattern on each elbow was used to validate CFD predictions. Three different erosion CFD simulations were performed, traditional DPM based CFD simulation, CFD-DEM simulation for spherical shape particles and CFD-DEM simulation for non-spherical shape particles. CFD-DEM coupled simulations clearly show an improvement on erosion predictions compared to DPM based CFD simulation. Effect of non-spherical shape on rebound angle during particle-wall collision is captured accurately in CFD-DEM simulation. CFD-DEM simulation using non-spherical particle, was able to predict erosion pattern closer to experimental observations.\u0000 This paper will demonstrate an increase in accuracy of sand erosion prediction by integrating DEM collision algorithm in CFD modelling. The prediction results of elbow erosion subject to a condition of dilute gas-particle flow are validated against experimental data. Improved prediction of erosion risk will increase the safety and reliability of oil & gas operations, while maximizing output efficiency.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81555989","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. S. Sequeira, Okechukwu M. Egbukole, Ahmed M. Sahl
High quality composition and PVT data can directly improve a wide range of upstream and downstreamengineering calculations. The quality of PVT Black oil experiments depends on awide variety of factors that includes type of PVT system, pressure-temperature conditions, stability and composition. The objective of this study is to emphasize the need to use material balance calculations obtainedfrom separator test data to back-calculate the reservoir composition andvalidate it against the original reservoir fluid composition. The methodologies employed in this study involve the following steps;
{"title":"A Novel Approach to Determine Reservoir Fluid Composition from Separator Test Data","authors":"D. S. Sequeira, Okechukwu M. Egbukole, Ahmed M. Sahl","doi":"10.2118/206330-ms","DOIUrl":"https://doi.org/10.2118/206330-ms","url":null,"abstract":"\u0000 High quality composition and PVT data can directly improve a wide range of upstream and downstreamengineering calculations. The quality of PVT Black oil experiments depends on awide variety of factors that includes type of PVT system, pressure-temperature conditions, stability and composition. The objective of this study is to emphasize the need to use material balance calculations obtainedfrom separator test data to back-calculate the reservoir composition andvalidate it against the original reservoir fluid composition.\u0000 The methodologies employed in this study involve the following steps;","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78754996","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}
Zheng Zheng, O. Jaramillo, Jhon Patiño, John Reina, Carlos Pacheco
This paper presents the successful stimulation workflow case for a carbonate acidizing pilot project performed in Gigante field in the Matambo block of the Upper Magdalena Valley basin in Colombia. An adecuate diagnostic, laboratory testing, treatment fluid selection, on-site QAQC and placement technique selection was fundamental to obtain a successful design and an optimized application. Gigante field production is mainly coming from Tetuan and Caballos units producing 32-degree API crude oil during several years. Specifically, in Gigante-2 ST well, oil production has declined until its commercial limit. During a candidate wells review, it was identified a previous acid stimulation treatment performed in Tobo-Monserrate formation in Gigante-1 with very poor results in oil production –short production time in natural flow– giving to this zone a low potential as oil producer and it was not considered as a primary target zone. The well was completed in its main target at Tetuan formation leaving Tobo-Monserrate behind an intermediate 7 in casing with no future expectatives to produce. After a reservoir evaluation of Tobo-Monserrate formation done in Gigante-2 ST well, it was selected as a candidate for an intermedia matrix stimulation job to evaluate the real potential of this formation in Matambo block. During this phase, reservoir samples were tested against different acid treatments in the laboratory. A gelled HCL based acid was selected based on their laboratory testing performance to delay acid reaction –improving acid penetration– and having fluid loss control to enhance reservoir coverage. The complete chemical formula was customized to match the oil-treatment compatibility. An organic solvents treatment was added to dissolve organic scale prior to the acidizing. Acid was deployed directly through a TCP string to optimatize the operational time and managing treatment rate according to the pressure behavior. During the acid pumping, a pressure drop is observed and treatment rate was increased to generate rate diversion. Gigante-2 ST well came in production at natural flow reaching 502 BOPD and 105 MSCFD evaluated after 35 days of the stimulation job proving and adding important hydrocarbon reserves from Tobo-Monserrate formation. A post job evaluation using a specialized chemical stimulation simulator shows a significant skin removal. Measured treatment pressure and rate were matched with the simulated parameters resulting in −3.24 of skin value post acid stimulation having a productivity improvement factor of 4.35 and an average wormhole penetration estimated from 60 to 75 in into the reservoir. A correct diagnostic, reservoir understanding, design, laboratory testing, execution and post job evaluation was the right route to obtain a successful stimulation job in operational terms and production results. This paper is intended as a guideline for stimulation jobs in future interventions where the exact reservoir mineralogy is unknown
{"title":"Successful Acid Stimulation in Limestone - Tobo-Monserrate Formation in Gigante Field - Colombia","authors":"Zheng Zheng, O. Jaramillo, Jhon Patiño, John Reina, Carlos Pacheco","doi":"10.2118/206037-ms","DOIUrl":"https://doi.org/10.2118/206037-ms","url":null,"abstract":"\u0000 This paper presents the successful stimulation workflow case for a carbonate acidizing pilot project performed in Gigante field in the Matambo block of the Upper Magdalena Valley basin in Colombia. An adecuate diagnostic, laboratory testing, treatment fluid selection, on-site QAQC and placement technique selection was fundamental to obtain a successful design and an optimized application.\u0000 Gigante field production is mainly coming from Tetuan and Caballos units producing 32-degree API crude oil during several years. Specifically, in Gigante-2 ST well, oil production has declined until its commercial limit.\u0000 During a candidate wells review, it was identified a previous acid stimulation treatment performed in Tobo-Monserrate formation in Gigante-1 with very poor results in oil production –short production time in natural flow– giving to this zone a low potential as oil producer and it was not considered as a primary target zone. The well was completed in its main target at Tetuan formation leaving Tobo-Monserrate behind an intermediate 7 in casing with no future expectatives to produce.\u0000 After a reservoir evaluation of Tobo-Monserrate formation done in Gigante-2 ST well, it was selected as a candidate for an intermedia matrix stimulation job to evaluate the real potential of this formation in Matambo block. During this phase, reservoir samples were tested against different acid treatments in the laboratory.\u0000 A gelled HCL based acid was selected based on their laboratory testing performance to delay acid reaction –improving acid penetration– and having fluid loss control to enhance reservoir coverage.\u0000 The complete chemical formula was customized to match the oil-treatment compatibility. An organic solvents treatment was added to dissolve organic scale prior to the acidizing. Acid was deployed directly through a TCP string to optimatize the operational time and managing treatment rate according to the pressure behavior.\u0000 During the acid pumping, a pressure drop is observed and treatment rate was increased to generate rate diversion. Gigante-2 ST well came in production at natural flow reaching 502 BOPD and 105 MSCFD evaluated after 35 days of the stimulation job proving and adding important hydrocarbon reserves from Tobo-Monserrate formation. A post job evaluation using a specialized chemical stimulation simulator shows a significant skin removal. Measured treatment pressure and rate were matched with the simulated parameters resulting in −3.24 of skin value post acid stimulation having a productivity improvement factor of 4.35 and an average wormhole penetration estimated from 60 to 75 in into the reservoir. A correct diagnostic, reservoir understanding, design, laboratory testing, execution and post job evaluation was the right route to obtain a successful stimulation job in operational terms and production results.\u0000 This paper is intended as a guideline for stimulation jobs in future interventions where the exact reservoir mineralogy is unknown","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89813203","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}
K. Whaley, P. Jackson, M. Wolański, T. Aliyev, Gumru Muradova, Arziman Eyyubov, Carl Thomesen, Hidayat Samadov, Arunesh Kumar, Pavithiran Chandran, Reza Majidi
Open Hole Gravel Pack (OHGP) completions have been the primary completion type for production wells in the Azeri-Chirag-Gunashli (ACG) field in Azerbaijan for 20 years. In recent years, it has been required to use well bore strengthening mud systems to allow drilling the more depleted parts of the field. This paper describes the major engineering effort that was undertaken to develop systems and techniques that would allow the successful installation of OHGP completions in this environment. OHGP completions have evolved over the last 3 decades, significantly increasing the window of suitable installation environments such that if a well could be drilled it could, in most cases, be completed as an OHGP if desired. Drilling fluids technology has also advanced to allow the drilling of highly depleted reservoirs with the development of well bore strengthening mud systems which use oversized solids in the mud system to prevent fracture propagation. This paper describes laboratory testing and development of well construction procedures to allow OHGPs to be successfully installed in wells drilled with well bore strengthening mud systems. Laboratory testing results showed that low levels of formation damage could be achieved in OHGPs using well bore strengthening mud systems that are comparable to those drilled with conventional mud systems. These drilling fluid formulations along with the rigorous mud conditioning and well clean-up practices that were developed were first implemented in mid-2019 and have now been used in 6 OHGP wells. All 6 wells showed that suitable levels of drilling mud cleanliness could be achieved with limited additional time added to the well construction process and operations and all of them have robust sand control reliability and technical limit skins. Historically it was thought that productive, reliable OHGP completions could not be delivered when using well bore strengthening mud systems due to the inability to effectively produce back filter cakes with large solids through the gravel pack and the ability to condition the mud system to allow sand screen deployment without plugging occurring. The engineering work and field results presented demonstrate that these hurdles can be overcome through appropriate fluid designs and well construction practices.
{"title":"Paradigm Shift in Completion Limits: Open Hole Gravel Pack in Highly Depleted Reservoirs Drilled with Well Bore Strengthening Technology","authors":"K. Whaley, P. Jackson, M. Wolański, T. Aliyev, Gumru Muradova, Arziman Eyyubov, Carl Thomesen, Hidayat Samadov, Arunesh Kumar, Pavithiran Chandran, Reza Majidi","doi":"10.2118/206079-ms","DOIUrl":"https://doi.org/10.2118/206079-ms","url":null,"abstract":"\u0000 Open Hole Gravel Pack (OHGP) completions have been the primary completion type for production wells in the Azeri-Chirag-Gunashli (ACG) field in Azerbaijan for 20 years. In recent years, it has been required to use well bore strengthening mud systems to allow drilling the more depleted parts of the field. This paper describes the major engineering effort that was undertaken to develop systems and techniques that would allow the successful installation of OHGP completions in this environment.\u0000 OHGP completions have evolved over the last 3 decades, significantly increasing the window of suitable installation environments such that if a well could be drilled it could, in most cases, be completed as an OHGP if desired. Drilling fluids technology has also advanced to allow the drilling of highly depleted reservoirs with the development of well bore strengthening mud systems which use oversized solids in the mud system to prevent fracture propagation. This paper describes laboratory testing and development of well construction procedures to allow OHGPs to be successfully installed in wells drilled with well bore strengthening mud systems.\u0000 Laboratory testing results showed that low levels of formation damage could be achieved in OHGPs using well bore strengthening mud systems that are comparable to those drilled with conventional mud systems. These drilling fluid formulations along with the rigorous mud conditioning and well clean-up practices that were developed were first implemented in mid-2019 and have now been used in 6 OHGP wells. All 6 wells showed that suitable levels of drilling mud cleanliness could be achieved with limited additional time added to the well construction process and operations and all of them have robust sand control reliability and technical limit skins.\u0000 Historically it was thought that productive, reliable OHGP completions could not be delivered when using well bore strengthening mud systems due to the inability to effectively produce back filter cakes with large solids through the gravel pack and the ability to condition the mud system to allow sand screen deployment without plugging occurring. The engineering work and field results presented demonstrate that these hurdles can be overcome through appropriate fluid designs and well construction practices.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86708407","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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