T. Alshaikhmubarak, Laila Mira, S. Ghadiry, T. Mattar
In exploration areas formation water salinity is often unknown. Several log-based techniques can be used to estimate the water resistivity, which can be used to calculate the equivalent formation water salinity, such as the Pickett's plot technique or spontaneous potential (SP log) but remain subjected to some uncertainties. Although captured down hole samples can accurately determine salinity, it can take a long time to receive the laboratory analysis results, delaying the Field Development Plan (FDP) studies and affecting current logging operations decisions. In this paper, we tested two methodologies. First, we utilized a novel dry weight chlorine (DWCL) measurement from an advanced spectroscopy tool to estimate the formation salinity at the depth of investigation of the device. This newly introduced methodology can be used in areas where formation salinity is unknown. The second methodology uses a new downhole induction resistivity cell in the formation tester tool. This cell gives a calibrated direct measurement of the water resistivity in the flowline, which can be converted into an equivalent water salinity if temperature is provided, and cross-checked with the DWCL values from the spectroscopy tool. The new chlorine measurement, along with the flowline induction resistivity measurement, provides a robust workflow to estimate the formation water salinity, enhancing the quality of the saturation evaluation for quick decision-making during logging operations, and accelerating the evaluation studies rather than waiting on laboratory results.
{"title":"Integrated Approach for Formation Water Salinity Determination","authors":"T. Alshaikhmubarak, Laila Mira, S. Ghadiry, T. Mattar","doi":"10.2523/iptc-22548-ea","DOIUrl":"https://doi.org/10.2523/iptc-22548-ea","url":null,"abstract":"\u0000 In exploration areas formation water salinity is often unknown. Several log-based techniques can be used to estimate the water resistivity, which can be used to calculate the equivalent formation water salinity, such as the Pickett's plot technique or spontaneous potential (SP log) but remain subjected to some uncertainties. Although captured down hole samples can accurately determine salinity, it can take a long time to receive the laboratory analysis results, delaying the Field Development Plan (FDP) studies and affecting current logging operations decisions.\u0000 In this paper, we tested two methodologies. First, we utilized a novel dry weight chlorine (DWCL) measurement from an advanced spectroscopy tool to estimate the formation salinity at the depth of investigation of the device. This newly introduced methodology can be used in areas where formation salinity is unknown. The second methodology uses a new downhole induction resistivity cell in the formation tester tool. This cell gives a calibrated direct measurement of the water resistivity in the flowline, which can be converted into an equivalent water salinity if temperature is provided, and cross-checked with the DWCL values from the spectroscopy tool.\u0000 The new chlorine measurement, along with the flowline induction resistivity measurement, provides a robust workflow to estimate the formation water salinity, enhancing the quality of the saturation evaluation for quick decision-making during logging operations, and accelerating the evaluation studies rather than waiting on laboratory results.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"78 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81334825","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}
Houra Mozaffar, Tore Larsen, C. Henderson, Salim Deshmukh, Ross Anderson, M. Hoopanah, B. Tohidi, Emilie Abadie, Vanessa Richon, Mark Charlesworth
Kinetic hydrate inhibitors (KHIs) offer an alternative to traditional thermodynamic hydrate inhibitors (THIs) for the prevention of gas hydrates. KHIs have several advantages over THIs, such as lower required volumes, easier logistics and reduced CAPEX. However, KHIs are once through chemicals leading to increased OPEX, are mostly non-biodegradable and therefore cannot be discharged to sea or disposal wells in fear of aquifer pollution. KHIs can also lead to fouling of process equipment, especially at elevated temperatures. To resolve these issues, a new KHI polymer removal method using a solvent extraction-based technique has been developed. In this approach, an immiscible extraction fluid is mixed into the KHI containing aqueous phase where the KHI polymer partitions into the extraction fluid, which can then be separated from the aqueous phase. In some cases, the KHI separated this way can be re-used. This process has the potential to solve problems with KHI produced water treatment/disposal, including where KHI is used in combination with MEG, reducing the costs and process fouling and protecting the environment. A new joint industry project (JIP) is underway with the aim of developing the concept into a commercial process for removal and possible re-use of KHIs upstream of PW treatment or MEG Regeneration systems. The first phase of this project is lab scale evaluation of the solvent extraction method for simulated removal and re-use of two commercial KHI formulations for a real gas-condensate field case. Both the removal efficiency and hydrate inhibition performance of 4 cycles of re-injected/re-used KHI has been successfully demonstrated. Removal of KHI from a real MEG system case was also successfully demonstrated. In the second phase of the JIP, lab scale tests were used to screen extraction and separation equipment and identify optimum process conditions. The upcoming third phase of this JIP is dedicated to demonstrating the selected process concept(s) on pilot scale in a flow loop. In this proceeding we will give highlights of the early laboratory test results from a produced water case where two field qualified KHIs are removed from PW and reused 4 times, still showing adequate hydrate inhibition performance. Successful pilot tests will confirm the operability of this process in the field.
{"title":"Multiple Recovery and Re-Use of Commercial Kinetic Hydrate Inhibitors from Produced Water and Rich Glycol","authors":"Houra Mozaffar, Tore Larsen, C. Henderson, Salim Deshmukh, Ross Anderson, M. Hoopanah, B. Tohidi, Emilie Abadie, Vanessa Richon, Mark Charlesworth","doi":"10.2523/iptc-22399-ea","DOIUrl":"https://doi.org/10.2523/iptc-22399-ea","url":null,"abstract":"\u0000 Kinetic hydrate inhibitors (KHIs) offer an alternative to traditional thermodynamic hydrate inhibitors (THIs) for the prevention of gas hydrates. KHIs have several advantages over THIs, such as lower required volumes, easier logistics and reduced CAPEX. However, KHIs are once through chemicals leading to increased OPEX, are mostly non-biodegradable and therefore cannot be discharged to sea or disposal wells in fear of aquifer pollution. KHIs can also lead to fouling of process equipment, especially at elevated temperatures.\u0000 To resolve these issues, a new KHI polymer removal method using a solvent extraction-based technique has been developed. In this approach, an immiscible extraction fluid is mixed into the KHI containing aqueous phase where the KHI polymer partitions into the extraction fluid, which can then be separated from the aqueous phase. In some cases, the KHI separated this way can be re-used. This process has the potential to solve problems with KHI produced water treatment/disposal, including where KHI is used in combination with MEG, reducing the costs and process fouling and protecting the environment.\u0000 A new joint industry project (JIP) is underway with the aim of developing the concept into a commercial process for removal and possible re-use of KHIs upstream of PW treatment or MEG Regeneration systems. The first phase of this project is lab scale evaluation of the solvent extraction method for simulated removal and re-use of two commercial KHI formulations for a real gas-condensate field case. Both the removal efficiency and hydrate inhibition performance of 4 cycles of re-injected/re-used KHI has been successfully demonstrated. Removal of KHI from a real MEG system case was also successfully demonstrated. In the second phase of the JIP, lab scale tests were used to screen extraction and separation equipment and identify optimum process conditions. The upcoming third phase of this JIP is dedicated to demonstrating the selected process concept(s) on pilot scale in a flow loop.\u0000 In this proceeding we will give highlights of the early laboratory test results from a produced water case where two field qualified KHIs are removed from PW and reused 4 times, still showing adequate hydrate inhibition performance. Successful pilot tests will confirm the operability of this process in the field.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90247811","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}
Global warming is a critical issue that has garnered significant attention during the last few decades. This temperature increase results from the emission of greenhouse gases into the atmosphere, most notably CO2. Carbon Capture and Storage (CCS) technology has been established as one of the most successful ways to store CO2 in underground layers and prevent it from being released into the atmosphere. However, CO2 is difficult to contain in subterranean layers subjected to high-pressure, high temperature (HPHT) conditions due to the degradation of Portland cement caused by chemical interaction with wet/dry CO2. Numerous studies have been conducted to increase the cement's resistance to CO2 attack, but limited effectiveness has been found when these methods have been evaluated under various settings. Given the distinctive properties of nanomaterials, such as high surface areas, quick contact, and resilience to heat, Nano Glass Flake (NGF) and Multiwall Carbon Nano Tube (MWCNT) were deemed to be suitable additional materials for increasing cement efficiency. On cement samples treated with NGFs and MWCNTs, a number of pre-carbonation and post-carbonation tests were performed. The pre-carbonation tests revealed that the density of NGFs-based cement remained constant with that of neat cement while the plastic viscosity increased. Additionally, it was recommended not to add more than 1wt% NGFs to the cement, as this would result in a high viscosity paste, which would negatively affect the pumping operation. On the other hand, this threshold for the viscosity of MWCNTs was roughly 0.25wt%. It was found that by using nanoparticles and employing a proper dispersion process, the cement's overall physical performance can be improved, and a lower amount of Portlandite is formed, which is critical for increased resistance to CO2 attack. In a static reactor, samples with the best pre-carbonation performance were subjected to water saturated supercritical CO2 for 56 days. It was then discovered that CO2 diffuses into cement and increases cement decomposition in the post-carbonation stage of the experiment. Samples weighing more than 0.5wt %. NGFs and 0.05 wt% MWCNTs had the smallest carbonated regions, indicating carbonated cement. However, the number of nanoparticles added to each sample resulted in a variable level of carbonation. Cement made using MWCNTs has a higher compressive strength due to its ability to manipulate CaCO3 crystal shape. NGFs-based cement, on the other hand, could be a better solution in terms of CO2 resistance. Due to their substantially lower cost than MWCNTs, it is possible to increase cement performance in CCS operations without imposing a high cost on projects.
{"title":"A Novel Portland Cement for CO2 Sequestration by Nanoparticles","authors":"M. Tiong, R. Gholami, Yisong Li","doi":"10.2523/iptc-22392-ms","DOIUrl":"https://doi.org/10.2523/iptc-22392-ms","url":null,"abstract":"\u0000 Global warming is a critical issue that has garnered significant attention during the last few decades. This temperature increase results from the emission of greenhouse gases into the atmosphere, most notably CO2. Carbon Capture and Storage (CCS) technology has been established as one of the most successful ways to store CO2 in underground layers and prevent it from being released into the atmosphere. However, CO2 is difficult to contain in subterranean layers subjected to high-pressure, high temperature (HPHT) conditions due to the degradation of Portland cement caused by chemical interaction with wet/dry CO2. Numerous studies have been conducted to increase the cement's resistance to CO2 attack, but limited effectiveness has been found when these methods have been evaluated under various settings. Given the distinctive properties of nanomaterials, such as high surface areas, quick contact, and resilience to heat, Nano Glass Flake (NGF) and Multiwall Carbon Nano Tube (MWCNT) were deemed to be suitable additional materials for increasing cement efficiency.\u0000 On cement samples treated with NGFs and MWCNTs, a number of pre-carbonation and post-carbonation tests were performed. The pre-carbonation tests revealed that the density of NGFs-based cement remained constant with that of neat cement while the plastic viscosity increased. Additionally, it was recommended not to add more than 1wt% NGFs to the cement, as this would result in a high viscosity paste, which would negatively affect the pumping operation. On the other hand, this threshold for the viscosity of MWCNTs was roughly 0.25wt%. It was found that by using nanoparticles and employing a proper dispersion process, the cement's overall physical performance can be improved, and a lower amount of Portlandite is formed, which is critical for increased resistance to CO2 attack.\u0000 In a static reactor, samples with the best pre-carbonation performance were subjected to water saturated supercritical CO2 for 56 days. It was then discovered that CO2 diffuses into cement and increases cement decomposition in the post-carbonation stage of the experiment. Samples weighing more than 0.5wt %. NGFs and 0.05 wt% MWCNTs had the smallest carbonated regions, indicating carbonated cement. However, the number of nanoparticles added to each sample resulted in a variable level of carbonation. Cement made using MWCNTs has a higher compressive strength due to its ability to manipulate CaCO3 crystal shape. NGFs-based cement, on the other hand, could be a better solution in terms of CO2 resistance. Due to their substantially lower cost than MWCNTs, it is possible to increase cement performance in CCS operations without imposing a high cost on projects.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87767343","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}
High torque and friction factors are major challenges while drilling. Providing lubrication helps in reducing torque and drag and increasing rate of penetration (ROP) in water-based fluids and produced water. The lubricants are inert hence, they do not react with other fluid additives or cuttings and will not affect fluid rheology. All Lubricants in the oil and gas industry are in liquid form and usually used to reduce torque and decrease coefficients of friction, they came in different chemical compositions a toxic lubricant mineral oil and non-toxic vegetable lubricants, and they have many papers talk about how they function as lubricants, but with a new generation of solids lubricants, it will be changing the whole industry. Powdered encapsulated lubricant additive comprises a liquid lubricant blended with an inert solid substrate. The solid lubricant additive compositions thus, obtained are advantageously employed in drilling fluids. Fatty acid solid lubricant is one of the aforementioned powdered lubricants. It is a dry form encapsulated lubricant composed of micronized capsules containing oil that remains held until sufficient operational pressure, friction, or shear break the encapsulation to release the oil on demand. In this paper, we present a testing plan, lab results of fatty acid solid lubricant, compare and contrast results with liquid lubricants that had the same component group in three types of salts (brine) to see the range of efficiency between solid and liquid forms.
{"title":"Laboratory Evaluation Comparison Study Between the Performance of Fatty Acid Solid Lubricant and Liquid Lubricant","authors":"Munirah Bukhawwah, Sarah Alrammah","doi":"10.2523/iptc-22590-ms","DOIUrl":"https://doi.org/10.2523/iptc-22590-ms","url":null,"abstract":"\u0000 High torque and friction factors are major challenges while drilling. Providing lubrication helps in reducing torque and drag and increasing rate of penetration (ROP) in water-based fluids and produced water. The lubricants are inert hence, they do not react with other fluid additives or cuttings and will not affect fluid rheology. All Lubricants in the oil and gas industry are in liquid form and usually used to reduce torque and decrease coefficients of friction, they came in different chemical compositions a toxic lubricant mineral oil and non-toxic vegetable lubricants, and they have many papers talk about how they function as lubricants, but with a new generation of solids lubricants, it will be changing the whole industry.\u0000 Powdered encapsulated lubricant additive comprises a liquid lubricant blended with an inert solid substrate. The solid lubricant additive compositions thus, obtained are advantageously employed in drilling fluids.\u0000 Fatty acid solid lubricant is one of the aforementioned powdered lubricants. It is a dry form encapsulated lubricant composed of micronized capsules containing oil that remains held until sufficient operational pressure, friction, or shear break the encapsulation to release the oil on demand.\u0000 In this paper, we present a testing plan, lab results of fatty acid solid lubricant, compare and contrast results with liquid lubricants that had the same component group in three types of salts (brine) to see the range of efficiency between solid and liquid forms.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88026610","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}
Ahmed Salah A. Salah, Ahmed Sabaa A. Sabaa, Ahmed Samir Abd Elhaleem A. S. Abd Elhaleem, Shehab Ali Shehab A., Sergio Ritondale S. Ritondale, Amin Sorour A. Sorou, Ayman Nady A. Nady
The electrical submersible pump (ESP), has become the most efficient and reliable artificial-lift method worldwide. However, in wells with high gas volume, they are highly affected by gas bubbles flowing through each component, affecting: the motor temperature, lifting efficiency, the integrity of the motor and cable. Thus, High gas interference might cause multiple intermittent shutdowns due to Gas Lock and eventually shorten the run life of the ESP. ESP at Well #A was first installed and directly had a problem with High Gas Interference resulting in a pre-mature ESP failure and costly well intervention to restore well-deferred production. A detailed discussion with a technology provider and reference case studies come up with an integrated solution to have the proper gas handling system in addition to adjusting VSD logic to operate on PID current mode. The present study shows a successful ESP optimization through VSD settings in combination with a comprehensive gas handling system that allowed management of low productivity high GOR ESP applications. This gas handling system for ESP was complemented by installing [PMM motor, tandem gas separators with vortex technology, compression mixed-flow stages in a wide range centrifugal pump, advanced gas handler (AGH), and Monel armor leaded power cable]. The system was able to manage GOR>2,000 SCF/STB with WC of <10%, Productivity index of 0.2 BPD/psi, and 75% of free gas flowing into the pump intake. This paper contains all the descriptions of each component in the ESP gas handling system. The system was able to increase well production by reducing gas-locking production shutdowns, stabilizing motor current fluctuations, increasing ESP lifetime, and increasing reservoir life by increasing drawdown and allowing effective pump operation at lower intake pressure. The same directions were successfully applied in another two wells with low productivity gassy behavior; Well #B and Well #C. And, by monitoring ESP performance for a longer period, the pump showed a stable operation, by successfully mitigating the high gas interference trips. Thus, the implementation of this integrated solution in wells with high GOR has been demonstrated to be an effective solution. Also, it provides opportunities to expand the use of ESP in gassy wells, previously thought to be unsuitable.
{"title":"Improving ESP Performance in Low Productivity Gassy Wells: Case Study","authors":"Ahmed Salah A. Salah, Ahmed Sabaa A. Sabaa, Ahmed Samir Abd Elhaleem A. S. Abd Elhaleem, Shehab Ali Shehab A., Sergio Ritondale S. Ritondale, Amin Sorour A. Sorou, Ayman Nady A. Nady","doi":"10.2523/iptc-22109-ms","DOIUrl":"https://doi.org/10.2523/iptc-22109-ms","url":null,"abstract":"\u0000 The electrical submersible pump (ESP), has become the most efficient and reliable artificial-lift method worldwide. However, in wells with high gas volume, they are highly affected by gas bubbles flowing through each component, affecting: the motor temperature, lifting efficiency, the integrity of the motor and cable. Thus, High gas interference might cause multiple intermittent shutdowns due to Gas Lock and eventually shorten the run life of the ESP.\u0000 ESP at Well #A was first installed and directly had a problem with High Gas Interference resulting in a pre-mature ESP failure and costly well intervention to restore well-deferred production. A detailed discussion with a technology provider and reference case studies come up with an integrated solution to have the proper gas handling system in addition to adjusting VSD logic to operate on PID current mode. The present study shows a successful ESP optimization through VSD settings in combination with a comprehensive gas handling system that allowed management of low productivity high GOR ESP applications.\u0000 This gas handling system for ESP was complemented by installing [PMM motor, tandem gas separators with vortex technology, compression mixed-flow stages in a wide range centrifugal pump, advanced gas handler (AGH), and Monel armor leaded power cable]. The system was able to manage GOR>2,000 SCF/STB with WC of <10%, Productivity index of 0.2 BPD/psi, and 75% of free gas flowing into the pump intake. This paper contains all the descriptions of each component in the ESP gas handling system. The system was able to increase well production by reducing gas-locking production shutdowns, stabilizing motor current fluctuations, increasing ESP lifetime, and increasing reservoir life by increasing drawdown and allowing effective pump operation at lower intake pressure.\u0000 The same directions were successfully applied in another two wells with low productivity gassy behavior; Well #B and Well #C. And, by monitoring ESP performance for a longer period, the pump showed a stable operation, by successfully mitigating the high gas interference trips. Thus, the implementation of this integrated solution in wells with high GOR has been demonstrated to be an effective solution. Also, it provides opportunities to expand the use of ESP in gassy wells, previously thought to be unsuitable.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"75 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86882920","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}
P. Bangert, Peter Smith, S. Helgesen, Benjamin Eckenfels
The choice of piping classes for industrial use has important ramification on engineering projects ranging from safety considerations to cost-material effiency and environmental footprint. Usually, suitable piping classes are found by consulting fixed tables, such as the ASME code for piping classes, together with other values like required pressure resistance and pipe temperatures, the later often being a decisive factor for choosing one piping class over another. For the pipe and flange temperatures today mostly the fluid temperature is used, while sometimes rough approximations based on fluid temperature percentages are used, or more rarely, slow, and expensive finite element calculations are performed for individual cases. In this paper we demonstrate the significant benefits of choosing correct piping classes using precisely calculated pipe temperatures and propose an AI-based approach for fast and precise calculation of these pipe temperatures based on a training set derived from a limited number of finite element calculations performed by the authors. We also analyze in detail the benefits of this approach and provide concrete examples.
{"title":"Using and Computing Metal Temperature for Asme Piping Class Optimization","authors":"P. Bangert, Peter Smith, S. Helgesen, Benjamin Eckenfels","doi":"10.2523/iptc-22468-ms","DOIUrl":"https://doi.org/10.2523/iptc-22468-ms","url":null,"abstract":"\u0000 The choice of piping classes for industrial use has important ramification on engineering projects ranging from safety considerations to cost-material effiency and environmental footprint. Usually, suitable piping classes are found by consulting fixed tables, such as the ASME code for piping classes, together with other values like required pressure resistance and pipe temperatures, the later often being a decisive factor for choosing one piping class over another. For the pipe and flange temperatures today mostly the fluid temperature is used, while sometimes rough approximations based on fluid temperature percentages are used, or more rarely, slow, and expensive finite element calculations are performed for individual cases. In this paper we demonstrate the significant benefits of choosing correct piping classes using precisely calculated pipe temperatures and propose an AI-based approach for fast and precise calculation of these pipe temperatures based on a training set derived from a limited number of finite element calculations performed by the authors. We also analyze in detail the benefits of this approach and provide concrete examples.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"271 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77044412","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}
N. A. Dasuki, Gurveen Singh Reekhi, H. Bakar, Tunku Indra Tunku Abdul Muthalib
In Field A, recently drilled wells D6, D7 and D8 penetrated at reservoir of good quality sands. However, the production rate declined rapidly within a year after wells kicked off. In an effort to restore new wells productivity, solid propellant technology stimulation and dynamic underbalance stimulation were evaluated for their effectiveness in permeability improvement. The candidates for solid propellant technology and dynamic underbalance stimulation were selected based on a screening workflow. Pressure data was retrieved from pressure downhole gauge to confirm skin buildup post production. The sources of production impairment were then investigated from laboratory analysis of core sample. While waiting for the results of laboratory analysis, solid propellant technology and dynamic underbalance stimulation were applied as quick solutions due relatively cheaper cost than chemical stimulation. Solid propellant technology was chosen for Well D8 whereas dynamic underbalance stimulation was selected for Well D6 and D7. Post solid propellant technology at Well D8, tubing head pressure and production rate slightly increased and sustained. On the other hand, dynamic underbalance stimulation at Well D6 and D7 showed positive results as tubing head pressure and production rates were improved. Unfortunately, production gain from dynamic underbalance at Well D7 only lived for a month before seizing to flow. The implementation of solid propellant technology and dynamic underbalance stimulation were successful to improve production performance for a short period of time. Both stimulation strategies were deemed to be repeated and improved to bypass near wellbore damage for these wells. This paper presents on the challenges and lessons learned that will be applicable to oilfields which are having similar situation to improve well productivity via mechanical stimulation.
{"title":"Case Study: Lessons Learned in Attempting to Restore New Well Productivity Via Solid Propellant Technology and Dynamic Underbalance Stimulation","authors":"N. A. Dasuki, Gurveen Singh Reekhi, H. Bakar, Tunku Indra Tunku Abdul Muthalib","doi":"10.2523/iptc-22378-ms","DOIUrl":"https://doi.org/10.2523/iptc-22378-ms","url":null,"abstract":"\u0000 In Field A, recently drilled wells D6, D7 and D8 penetrated at reservoir of good quality sands. However, the production rate declined rapidly within a year after wells kicked off. In an effort to restore new wells productivity, solid propellant technology stimulation and dynamic underbalance stimulation were evaluated for their effectiveness in permeability improvement. The candidates for solid propellant technology and dynamic underbalance stimulation were selected based on a screening workflow. Pressure data was retrieved from pressure downhole gauge to confirm skin buildup post production. The sources of production impairment were then investigated from laboratory analysis of core sample. While waiting for the results of laboratory analysis, solid propellant technology and dynamic underbalance stimulation were applied as quick solutions due relatively cheaper cost than chemical stimulation. Solid propellant technology was chosen for Well D8 whereas dynamic underbalance stimulation was selected for Well D6 and D7. Post solid propellant technology at Well D8, tubing head pressure and production rate slightly increased and sustained. On the other hand, dynamic underbalance stimulation at Well D6 and D7 showed positive results as tubing head pressure and production rates were improved. Unfortunately, production gain from dynamic underbalance at Well D7 only lived for a month before seizing to flow. The implementation of solid propellant technology and dynamic underbalance stimulation were successful to improve production performance for a short period of time. Both stimulation strategies were deemed to be repeated and improved to bypass near wellbore damage for these wells. This paper presents on the challenges and lessons learned that will be applicable to oilfields which are having similar situation to improve well productivity via mechanical stimulation.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87174348","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}
Applying new technologies to improve existing methods or techniques can be important to successfully delivering high-profile ultra-extended-reach-drilling (ERD) projects. The underreaming-while-drilling technique in ERD projects represents such an opportunity. Recently, a 14½-in. borehole required being enlarged to 16 in. due to complexities, including surface location constraints, longer stepout, and borehole instability. This paper presents the challenges, how they were addressed, and the results. A dynamic modeling system was used to model the planned drilling operation based on offset well data. The extensive engineering studies included a finite element analysis (FEA), which modeled the cutting interface designs for drilling rocks. This analysis emphasized the importance of the compatibility between the underreamer cutting structure and the drill bit, which can help to predict the drilling performance while eliminating costly trial-and-error field tests. The analysis also enhances drillstring dynamic behavior to diminish erratic torque while maintaining directional control. Taking on a challenging target dictated a multidisciplinary approach to achieve what was previously considered an impossibility. The 14½-in. borehole was enlarged to 16-in. while landing at a 90° inclination successfully for the first time worldwide in an ultraERD profile. Several notable challenges were observed during the drilling phase, which required reevaluating the initially planned operations. A significant level of shocks and vibrations were observed, which required the bottomhole assembly (BHA) design to be further optimized in terms of bit cutting structure and string stabilization. The rate of penetration was optimized using real-time data from downhole drilling mechanics. The FEA results also allowed for developing an optimized drilling parameter plan for steering across the different formation horizons to be intercepted during the drilling operations. The mechanical specific energy was used as a monitoring tool to gauge drilling performance efficiency. Together with the mechanical specific energy, the plan for drilling parameters was adjusted in real time to deliver optimal BHA performance and ensure that no BHA vibrations, axial, torsional, and lateral, negatively impacted on the rock cutting process. Connection practices were also modified to account for pilot BHA length. The successful implementation of underreaming while drilling resulted in a significant savings in rig time, and subsequent cost savings equivalent to 20% to 30% of the section authorization for expenditure. The potential benefits resulting from using existing enabling technology to further realize significant project savings exists. The application of underreaming while drilling is unique in the sense that the ERD requirements of the project are on the extreme scale of footage drilled and borehole size drilled horizontally. Lessons learned can be applied to similar projects to help sh
{"title":"Step Change to Enhance Drilling Efficiency in Extended Reach Wells Using Under Reaming While Drilling, a Worldwide Record","authors":"Hussien Alzaki, Mohamed Mohamed Al-Sharafi","doi":"10.2523/iptc-22016-ea","DOIUrl":"https://doi.org/10.2523/iptc-22016-ea","url":null,"abstract":"\u0000 Applying new technologies to improve existing methods or techniques can be important to successfully delivering high-profile ultra-extended-reach-drilling (ERD) projects. The underreaming-while-drilling technique in ERD projects represents such an opportunity. Recently, a 14½-in. borehole required being enlarged to 16 in. due to complexities, including surface location constraints, longer stepout, and borehole instability. This paper presents the challenges, how they were addressed, and the results.\u0000 A dynamic modeling system was used to model the planned drilling operation based on offset well data. The extensive engineering studies included a finite element analysis (FEA), which modeled the cutting interface designs for drilling rocks. This analysis emphasized the importance of the compatibility between the underreamer cutting structure and the drill bit, which can help to predict the drilling performance while eliminating costly trial-and-error field tests. The analysis also enhances drillstring dynamic behavior to diminish erratic torque while maintaining directional control. Taking on a challenging target dictated a multidisciplinary approach to achieve what was previously considered an impossibility.\u0000 The 14½-in. borehole was enlarged to 16-in. while landing at a 90° inclination successfully for the first time worldwide in an ultraERD profile. Several notable challenges were observed during the drilling phase, which required reevaluating the initially planned operations. A significant level of shocks and vibrations were observed, which required the bottomhole assembly (BHA) design to be further optimized in terms of bit cutting structure and string stabilization. The rate of penetration was optimized using real-time data from downhole drilling mechanics. The FEA results also allowed for developing an optimized drilling parameter plan for steering across the different formation horizons to be intercepted during the drilling operations. The mechanical specific energy was used as a monitoring tool to gauge drilling performance efficiency. Together with the mechanical specific energy, the plan for drilling parameters was adjusted in real time to deliver optimal BHA performance and ensure that no BHA vibrations, axial, torsional, and lateral, negatively impacted on the rock cutting process. Connection practices were also modified to account for pilot BHA length. The successful implementation of underreaming while drilling resulted in a significant savings in rig time, and subsequent cost savings equivalent to 20% to 30% of the section authorization for expenditure.\u0000 The potential benefits resulting from using existing enabling technology to further realize significant project savings exists. The application of underreaming while drilling is unique in the sense that the ERD requirements of the project are on the extreme scale of footage drilled and borehole size drilled horizontally. Lessons learned can be applied to similar projects to help sh","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87198068","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 O&G industry is facing big challenges which consequently raise the necessity for reforming its traditional business model and integrating digital disruptive technologies such as Digital Twins, Artificial Intelligence and Blockchain. A Digital Twin(DT) is defined as a dynamic intelligent digital replica/model of the physical system/process/service/people which enables just-in-time informed decision making and root-cause analysis using AI. DTs are implanted at different levels such as Equipment/Asset Level Twin, System Level Twin, System of Systems (SoS) Level Twin. This research introduces a novel framework which is based on a Smart Secure Digital Twin (S2DT) to bridge the development gap compared to other leading industries such as manufacturing and automotive. The proposed model relies on Tiny Machine Learning (TinyML) to implement edge intelligence and solve the problems of transfer latency and data overload and consequently achieves low carbon footprint. Edge Intelligence (EI) reduces energy consumption and enhances security and perspective maintenance. The Blockchain Technology is used to solve the privacy, and cybersecurity problems [4]. The Extended Reality (XR) will be used to ensure proper training of operators, and industry 5.0 to boost collaboration between human and machine. At the component level, security is maintained by integrated the locally generated intelligence on a blockchain to insure immutability, and enhance security.
{"title":"Smart Predictive Maintenance Framework SPMF for Gas and Oil Industry","authors":"Magdi Alameldin","doi":"10.2523/iptc-22497-ms","DOIUrl":"https://doi.org/10.2523/iptc-22497-ms","url":null,"abstract":"\u0000 The O&G industry is facing big challenges which consequently raise the necessity for reforming its traditional business model and integrating digital disruptive technologies such as Digital Twins, Artificial Intelligence and Blockchain. A Digital Twin(DT) is defined as a dynamic intelligent digital replica/model of the physical system/process/service/people which enables just-in-time informed decision making and root-cause analysis using AI. DTs are implanted at different levels such as Equipment/Asset Level Twin, System Level Twin, System of Systems (SoS) Level Twin.\u0000 This research introduces a novel framework which is based on a Smart Secure Digital Twin (S2DT) to bridge the development gap compared to other leading industries such as manufacturing and automotive. The proposed model relies on Tiny Machine Learning (TinyML) to implement edge intelligence and solve the problems of transfer latency and data overload and consequently achieves low carbon footprint. Edge Intelligence (EI) reduces energy consumption and enhances security and perspective maintenance. The Blockchain Technology is used to solve the privacy, and cybersecurity problems [4]. The Extended Reality (XR) will be used to ensure proper training of operators, and industry 5.0 to boost collaboration between human and machine. At the component level, security is maintained by integrated the locally generated intelligence on a blockchain to insure immutability, and enhance security.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"798 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90355932","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}
CO2-foam enhanced oil recovery (EOR) has been considered a proven technology to mitigate adverse effects from CO2 front instabilities in highly heterogeneous reservoirs, such as viscous fingering, gravity segregation, and superior flow in high permeability streaks, leading to premature CO2 breakthrough. A highly stable CO2-foam is required to provide significant mobility control effect that stimulates flow diversion from high-permeability to low-permeability regions, hence improved sweep efficiency. CO2-foam EOR process can also be advanced for effective CO2 utilization and long-term CO2 sequestration in addition to improved oil production. However, harsh in-situ environments of hydrocarbon reservoirs greatly determine the performance of CO2-foam and the efficiency of the entire operations, leading to a need of foam formulation optimization in addition to technical development. As an innovative solution, hydrophobically modified polymer was employed to improve overall CO2-foam properties and CO2 mobility control performance inside porous media. A comprehensive evaluation on foaming properties (foamability and foam stability) and foam rheological behavior was performed under supercritical conditions to warrant the suitability of developed formulation as high-performance foaming agent. CO2-foam was generated using the primary foaming agent (alpha olefin sulfonate and betaine) in combination with different types of hydrophobically modified polymers, referred as to HMP, and conventional polymers (HPAMs) as foam stabilizers. The steady-state foam resistance established by each foam during dynamic flow tests was assessed under reservoir conditions to indicate the extent of mobility control effect for better sweep efficiency and the capability of the developed CO2-foam formulation of suppressing CO2 migration, hence improved storage efficiency. The formulation containing the selected HMP offered an acceptable foam generation ability compared to the formulations containing classical HPAM polymers. The presence of HMP with a higher degree of hydrophobes and lower molecular weight in surfactant-stabilized foam system was able to produce an improved flow resistance. These are attributed to the formation of organized and bridged polymer network triggered by hydrophobic association in the bulk and lamella interface hence providing steric forces at the interface that leads to substantial elasticity. Results from dynamic flow experiments revealed the superior performance of HMP stabilized CO2-foam in porous media in which its flow resistance was found to be 70% and 95% higher than that of polymer-free CO2-foam, and individual CO2, respectively. This research provides an alternative solution by promoting a relatively new foam formulation which is stabilized by hydrophobically modified water-soluble polymer. Besides offering better mobility control effect during EOR process, the application of developed CO2-foam formulation was also extended to CO2 trapping imp
{"title":"Improved CO2-Foam Properties and Flow Behavior by Hydrophobically Modified Polymers: Implications for Enhanced CO2 Storage and Oil Recovery","authors":"Shehzad Ahmed, A. Hanamertani, W. Alameri","doi":"10.2523/iptc-22628-ms","DOIUrl":"https://doi.org/10.2523/iptc-22628-ms","url":null,"abstract":"\u0000 CO2-foam enhanced oil recovery (EOR) has been considered a proven technology to mitigate adverse effects from CO2 front instabilities in highly heterogeneous reservoirs, such as viscous fingering, gravity segregation, and superior flow in high permeability streaks, leading to premature CO2 breakthrough. A highly stable CO2-foam is required to provide significant mobility control effect that stimulates flow diversion from high-permeability to low-permeability regions, hence improved sweep efficiency. CO2-foam EOR process can also be advanced for effective CO2 utilization and long-term CO2 sequestration in addition to improved oil production. However, harsh in-situ environments of hydrocarbon reservoirs greatly determine the performance of CO2-foam and the efficiency of the entire operations, leading to a need of foam formulation optimization in addition to technical development. As an innovative solution, hydrophobically modified polymer was employed to improve overall CO2-foam properties and CO2 mobility control performance inside porous media. A comprehensive evaluation on foaming properties (foamability and foam stability) and foam rheological behavior was performed under supercritical conditions to warrant the suitability of developed formulation as high-performance foaming agent. CO2-foam was generated using the primary foaming agent (alpha olefin sulfonate and betaine) in combination with different types of hydrophobically modified polymers, referred as to HMP, and conventional polymers (HPAMs) as foam stabilizers. The steady-state foam resistance established by each foam during dynamic flow tests was assessed under reservoir conditions to indicate the extent of mobility control effect for better sweep efficiency and the capability of the developed CO2-foam formulation of suppressing CO2 migration, hence improved storage efficiency. The formulation containing the selected HMP offered an acceptable foam generation ability compared to the formulations containing classical HPAM polymers. The presence of HMP with a higher degree of hydrophobes and lower molecular weight in surfactant-stabilized foam system was able to produce an improved flow resistance. These are attributed to the formation of organized and bridged polymer network triggered by hydrophobic association in the bulk and lamella interface hence providing steric forces at the interface that leads to substantial elasticity. Results from dynamic flow experiments revealed the superior performance of HMP stabilized CO2-foam in porous media in which its flow resistance was found to be 70% and 95% higher than that of polymer-free CO2-foam, and individual CO2, respectively. This research provides an alternative solution by promoting a relatively new foam formulation which is stabilized by hydrophobically modified water-soluble polymer. Besides offering better mobility control effect during EOR process, the application of developed CO2-foam formulation was also extended to CO2 trapping imp","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81244536","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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