Matthew Grimes, Nicolaas Antonie Janse van Rensburg, S. Mitchell
This paper presents on a non-invasive, IoT-based method for rapidly determining the presence and location of spontaneous leaks in pressurized lines transporting any type of product (e.g., oil, gas, water, etc.). Specific applications include long-distance transmission lines, gathering networks at well sites, and offshore production risers. The methodology combines proven negative pressure wave (NPW) sensing with advanced signal processing to minimize false positives and accurately identify the presence of small spontaneous leaks within seconds of their occurrence. In the case of long-distance transmission pipelines, the location of the leak can be localized to within 20-50 feet. The solution was commercialized in 2020 and has undergone extensive testing to verify its capabilities. It is currently in use by several operators, both onshore and offshore.
{"title":"A Novel IoT-Based Method for Real-Time Detection of Spontaneous Leaks in Pipelines, Gathering Systems, and Offshore Risers","authors":"Matthew Grimes, Nicolaas Antonie Janse van Rensburg, S. Mitchell","doi":"10.2118/208092-ms","DOIUrl":"https://doi.org/10.2118/208092-ms","url":null,"abstract":"\u0000 This paper presents on a non-invasive, IoT-based method for rapidly determining the presence and location of spontaneous leaks in pressurized lines transporting any type of product (e.g., oil, gas, water, etc.). Specific applications include long-distance transmission lines, gathering networks at well sites, and offshore production risers. The methodology combines proven negative pressure wave (NPW) sensing with advanced signal processing to minimize false positives and accurately identify the presence of small spontaneous leaks within seconds of their occurrence. In the case of long-distance transmission pipelines, the location of the leak can be localized to within 20-50 feet. The solution was commercialized in 2020 and has undergone extensive testing to verify its capabilities. It is currently in use by several operators, both onshore and offshore.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90232532","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}
Dalia Abdallah, M. Grutters, R. Stalker, R. Hutchison, Christopher Stewart, Sam Wilson
ADNOC Onshore plans to use seawater as alternative to aquifer water, its source of injection water for over 40 years. However, using seawater for injection introduces a sulfate scaling risk due to incompatibility with formation water. Sulfate in the seawater and cations in the formation water (Ca, Sr) are likely to precipitate, causing scaling and related flow assurance problems and formation damage. Sulfate can be removed from the injection water by means of desulfation, but sulfate removal to well below its scaling concentration is CAPEX intensive and negatively impacts seawater flooding economics. In this paper, the economic benefits of partial sulfate reduction are evaluated, by finding a balance between controllable scaling and costs for inhibition and sulfate removal.
{"title":"The Impact of Sulfate Level Reduction on Seawater Injection Economics: Using Sulfate Scale Precipitation Kinetics to Our Advantage","authors":"Dalia Abdallah, M. Grutters, R. Stalker, R. Hutchison, Christopher Stewart, Sam Wilson","doi":"10.2118/207612-ms","DOIUrl":"https://doi.org/10.2118/207612-ms","url":null,"abstract":"\u0000 ADNOC Onshore plans to use seawater as alternative to aquifer water, its source of injection water for over 40 years. However, using seawater for injection introduces a sulfate scaling risk due to incompatibility with formation water. Sulfate in the seawater and cations in the formation water (Ca, Sr) are likely to precipitate, causing scaling and related flow assurance problems and formation damage. Sulfate can be removed from the injection water by means of desulfation, but sulfate removal to well below its scaling concentration is CAPEX intensive and negatively impacts seawater flooding economics. In this paper, the economic benefits of partial sulfate reduction are evaluated, by finding a balance between controllable scaling and costs for inhibition and sulfate removal.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84491433","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}
Klemens Katterbauer, A. Qasim, A. Marsala, A. Yousef
Hydrogen has become a very promising green energy source that can be easily stored and transported, and it has the potential to be utilized in a variety of applications. Hydrogen, as a power source, has the benefits of being easily transportable and stored over long periods of times, and does not lead to any carbon emissions related to the utilization of the power source. Thermal EOR methods are among the most commonly used recovery methods. They involve the introduction of thermal energy or heat into the reservoir to raise the temperature of the oil and reduce its viscosity. The heat makes the oil mobile and assists in moving it towards the producer wells. The heat can be added externally by injecting a hot fluid such as steam or hot water into the formations, or it can be generated internally through in-situ combustion by burning the oil in depleted gas or waterflooded reservoirs using air or oxygen. This method is an attractive alternative to produce cost-efficiently significant amounts of hydrogen from these depleted or waterflooded reservoirs. A major challenge is to optimize injection of air/oxygen to maximize hydrogen production via ensuring that the in-situ combustion sufficiently supports the breakdown of water into hydrogen molecules. In-situ combustion or fireflood is a method consisting of volumes of air or oxygen injected into a well and ignited. A burning zone is propagated through the reservoir from the injection well to the producing wells. The in-situ combustion creates a bank of steam, gas from the combustion process, and evaporated hydrocarbons that drive the reservoir oil into the producing wells. There are three types of in-situ combustion processes: dry forward, dry reverse and wet forward combustion. In a dry forward process only air is injected and the combustion front moves from the injector to the producer. The wet forward injection is the same process where air and water are injected either simultaneously or alternating. Artificial intelligence (AI) practices have allowed to significantly improve optimization of reservoir production, based on observations in the near wellbore reservoir layers. This work utilizes a data-driven physics-inspired AI model for the optimization of hydrogen recovery via the injection of oxygen, where the injection and production parameters are optimized, minimizing oxygen injection while maximizing hydrogen production and recovery. Multiple physical and data-driven models and their parameters are optimized based on observations with the objective to determine the best sustainable combination. The framework was examined on a synthetic reservoir model with multiple injector and producing wells. Historical injection and production were available for a time period of three years for various oxygen injection and hydrogen production levels. Various time-series deep learning network models were investigated, with random forest time series models incorporating a modified mass balance – reaction k
{"title":"A Data Driven Artificial Intelligence Framework for Hydrogen Production Optimization in Waterflooded Hydrocarbon Reservoir","authors":"Klemens Katterbauer, A. Qasim, A. Marsala, A. Yousef","doi":"10.2118/207847-ms","DOIUrl":"https://doi.org/10.2118/207847-ms","url":null,"abstract":"\u0000 Hydrogen has become a very promising green energy source that can be easily stored and transported, and it has the potential to be utilized in a variety of applications. Hydrogen, as a power source, has the benefits of being easily transportable and stored over long periods of times, and does not lead to any carbon emissions related to the utilization of the power source. Thermal EOR methods are among the most commonly used recovery methods. They involve the introduction of thermal energy or heat into the reservoir to raise the temperature of the oil and reduce its viscosity. The heat makes the oil mobile and assists in moving it towards the producer wells. The heat can be added externally by injecting a hot fluid such as steam or hot water into the formations, or it can be generated internally through in-situ combustion by burning the oil in depleted gas or waterflooded reservoirs using air or oxygen. This method is an attractive alternative to produce cost-efficiently significant amounts of hydrogen from these depleted or waterflooded reservoirs. A major challenge is to optimize injection of air/oxygen to maximize hydrogen production via ensuring that the in-situ combustion sufficiently supports the breakdown of water into hydrogen molecules.\u0000 In-situ combustion or fireflood is a method consisting of volumes of air or oxygen injected into a well and ignited. A burning zone is propagated through the reservoir from the injection well to the producing wells. The in-situ combustion creates a bank of steam, gas from the combustion process, and evaporated hydrocarbons that drive the reservoir oil into the producing wells. There are three types of in-situ combustion processes: dry forward, dry reverse and wet forward combustion. In a dry forward process only air is injected and the combustion front moves from the injector to the producer. The wet forward injection is the same process where air and water are injected either simultaneously or alternating.\u0000 Artificial intelligence (AI) practices have allowed to significantly improve optimization of reservoir production, based on observations in the near wellbore reservoir layers. This work utilizes a data-driven physics-inspired AI model for the optimization of hydrogen recovery via the injection of oxygen, where the injection and production parameters are optimized, minimizing oxygen injection while maximizing hydrogen production and recovery. Multiple physical and data-driven models and their parameters are optimized based on observations with the objective to determine the best sustainable combination.\u0000 The framework was examined on a synthetic reservoir model with multiple injector and producing wells. Historical injection and production were available for a time period of three years for various oxygen injection and hydrogen production levels. Various time-series deep learning network models were investigated, with random forest time series models incorporating a modified mass balance – reaction k","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"59 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86603875","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In the Middle East many of the matured fields have fractured or vugular formations where the drilling is continued without return to a surface. This situation has been commonly interpreted as lack of hole cleaning and high risk of stuck pipe. The manuscript describes a study performed to analyze the hole cleaning while blind drilling horizontal sections. Most of the losses while drilling across fractured or vugular formations happen sudden, and this represents a risk of formation instability and stuck pipe. Additionally, the cuttings accumulation may lead to a potential pack off. To understand the hole cleaning the annular pressure while drilling was introduced in different sections, what via change of the equivalent static and dynamic densities describes the cutting and cavings accumulation in the annulus. Additionally, the hole cleaning behavior with different fluids pumped through the drillstring (i.e. drilling fluid, water, water with sweeps) was studied. The proposed study was performed in 4 different fields, 9 wells, across horizontal 6⅛-in. sections with total lost circulation. It was identified that while drilling with full returns ECD vs ESD variations are within 1.5 ppg, those variations are matching with the modeling of hydraulics. Once total losses encountered the variations between ECD and ESD are very low - within 0.2 ppg - indicating that annular friction losses below the loss circulation zone are minimal. This support the theory that all the drilled cuttings are properly lifted from bottom and carried to the karst into the loss circulation zone and not fluctuating above the loss zone. Additionally, minor to no relation found in hole cleaning while drilling with mud or a water with sweeps. This finding also is aligned with the stuck pipe statistics that shows higher incidents of stuck pipe while drilling the with full circulation due to pack off. The manuscript confirms the theory of the hole cleaning in total lost circulation and application of different hole cleaning practices to improve it. The results of the study can be implemented in any project worldwide.
{"title":"Wellbore Cleanness Under Total Losses in Horizontal Wells: The Field Study","authors":"A. Ruzhnikov, E. Echevarria","doi":"10.2118/207952-ms","DOIUrl":"https://doi.org/10.2118/207952-ms","url":null,"abstract":"\u0000 In the Middle East many of the matured fields have fractured or vugular formations where the drilling is continued without return to a surface. This situation has been commonly interpreted as lack of hole cleaning and high risk of stuck pipe. The manuscript describes a study performed to analyze the hole cleaning while blind drilling horizontal sections.\u0000 Most of the losses while drilling across fractured or vugular formations happen sudden, and this represents a risk of formation instability and stuck pipe. Additionally, the cuttings accumulation may lead to a potential pack off. To understand the hole cleaning the annular pressure while drilling was introduced in different sections, what via change of the equivalent static and dynamic densities describes the cutting and cavings accumulation in the annulus. Additionally, the hole cleaning behavior with different fluids pumped through the drillstring (i.e. drilling fluid, water, water with sweeps) was studied.\u0000 The proposed study was performed in 4 different fields, 9 wells, across horizontal 6⅛-in. sections with total lost circulation. It was identified that while drilling with full returns ECD vs ESD variations are within 1.5 ppg, those variations are matching with the modeling of hydraulics. Once total losses encountered the variations between ECD and ESD are very low - within 0.2 ppg - indicating that annular friction losses below the loss circulation zone are minimal. This support the theory that all the drilled cuttings are properly lifted from bottom and carried to the karst into the loss circulation zone and not fluctuating above the loss zone. Additionally, minor to no relation found in hole cleaning while drilling with mud or a water with sweeps. This finding also is aligned with the stuck pipe statistics that shows higher incidents of stuck pipe while drilling the with full circulation due to pack off.\u0000 The manuscript confirms the theory of the hole cleaning in total lost circulation and application of different hole cleaning practices to improve it. The results of the study can be implemented in any project worldwide.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"113 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72704756","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}
Nichapa Akaramethakorn, I. Mahruqi, Mohammad Aziz, M. Radwan, Yahya Amri, Zulfa Arfi, Mohammed Al Balushi, Ilham Harthy, Mohammed Malallah Al Farsi, A. Riyami, Yoseph Susatyo, Aisha Sariri, Saif Hamimi, I. Azizi
This paper is for people to realize a strategic way of continuous improvement though optimization and standardization process with a minimum of 10% target cost reduction while developing capability in the organization in the south of Oman. BN area is one of the main production areas in PDO (Petroleum Development of Oman) and is being operated under BR cluster from 1980s. Approximately eleven fields in the BN area are contributing to the success today. Continuous improvement through optimization and cost reduction has always been a top priority, where long term production and safety has been fulfilled. In 2020, this team has been put together to look into the overall cost saving potential with the clear management steering of "Do not Leave any Stone Unturned". A mixture of experience and young team members are retained to ensure capability development in the organization. One of the key items that this team looked at is to standardize of upcoming Oil Producers and Water Injectors well design. The well design in at least 7 fields in the BN area has been reviewed and realized the value and risk through competitive scoping exercise. By avoiding looking at the fields in isolation, the team has considered a similarity of well functionality and had identified where the standard well design can be applied. Minimum functional requirements lead to minimum technical specification and building into a staircase of option with clear associated risk for each option. Through the analysis, a potential optimization of an existing well design has been discovered and is currently undergone further maturation toward design endorsement. With the maturation of the uniformity of well design in the area, it is foreseeing as an opportunity to ensure improvement can be sustained in the long run. Minimum 10% saving of well cost through standardization and efficiency in project management is a target set, aiming to provide stability in planning. In addition, the team are looking into even more than 10% cost saving through innovative contracting strategy. It could potentially help to speed up the delivery of the project, accelerate production with less waiting time i.e. improve material stock management, simplify procurement process, ensure that the experience remains in the organization and will allow for replication in the future. The approach involves a combination of integrating team from subsurface, surface, wells, contract, and procurement to enhance cost saving to the company. This has proven to be effective and aligned with the company's focus to consolidate a commercial mind-set thinking in each development.
{"title":"Standardization Lead to Potential Cost Saving in the One of the Clusters in Southern of Sultanate of Oman","authors":"Nichapa Akaramethakorn, I. Mahruqi, Mohammad Aziz, M. Radwan, Yahya Amri, Zulfa Arfi, Mohammed Al Balushi, Ilham Harthy, Mohammed Malallah Al Farsi, A. Riyami, Yoseph Susatyo, Aisha Sariri, Saif Hamimi, I. Azizi","doi":"10.2118/207309-ms","DOIUrl":"https://doi.org/10.2118/207309-ms","url":null,"abstract":"\u0000 This paper is for people to realize a strategic way of continuous improvement though optimization and standardization process with a minimum of 10% target cost reduction while developing capability in the organization in the south of Oman.\u0000 BN area is one of the main production areas in PDO (Petroleum Development of Oman) and is being operated under BR cluster from 1980s. Approximately eleven fields in the BN area are contributing to the success today. Continuous improvement through optimization and cost reduction has always been a top priority, where long term production and safety has been fulfilled. In 2020, this team has been put together to look into the overall cost saving potential with the clear management steering of \"Do not Leave any Stone Unturned\". A mixture of experience and young team members are retained to ensure capability development in the organization.\u0000 One of the key items that this team looked at is to standardize of upcoming Oil Producers and Water Injectors well design. The well design in at least 7 fields in the BN area has been reviewed and realized the value and risk through competitive scoping exercise. By avoiding looking at the fields in isolation, the team has considered a similarity of well functionality and had identified where the standard well design can be applied. Minimum functional requirements lead to minimum technical specification and building into a staircase of option with clear associated risk for each option. Through the analysis, a potential optimization of an existing well design has been discovered and is currently undergone further maturation toward design endorsement. With the maturation of the uniformity of well design in the area, it is foreseeing as an opportunity to ensure improvement can be sustained in the long run.\u0000 Minimum 10% saving of well cost through standardization and efficiency in project management is a target set, aiming to provide stability in planning. In addition, the team are looking into even more than 10% cost saving through innovative contracting strategy. It could potentially help to speed up the delivery of the project, accelerate production with less waiting time i.e. improve material stock management, simplify procurement process, ensure that the experience remains in the organization and will allow for replication in the future.\u0000 The approach involves a combination of integrating team from subsurface, surface, wells, contract, and procurement to enhance cost saving to the company. This has proven to be effective and aligned with the company's focus to consolidate a commercial mind-set thinking in each development.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75644237","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}
Romulo Bermudez Alvarado, Abdelkerim Doutoum Mahamat Habib, J. S. Duguid, Manish Srivastava, R. Medina, M. Rocha, Kresimir Vican, V. Jambunathan
This paper discusses the value of cement logs as the core input to analyze the cement quality and validate the improvements made to cementing designs and practices of the intermediate casing string in Extended-Reach Drilling (ERD) wells. The ERD wells are being drilled from artificial islands in a field offshore in the UAE. The primary cementing objectives are isolating the reservoirs from their sublayers and protecting the casing against possible future corrosion across an upper formation. Cementing challenges include higher angle deviation, higher mud weight requirements resulting from an anisotropic, unstable shale formation present above the reservoir section. Effective reservoir management requires sound zonal isolation to eliminate crossflow between different reservoir units. In combination with standard cement bond logs (CBL), ultrasonic technology has provided detailed information about cement quality and a qualitative indication of casing position in the borehole. These have also led to valuable insight into how continued cementing designs and practices improved zonal isolation. Improvements in cement quality seen as a result of enhanced casing centralization, optimized hydraulic model, modified cement rheology, displacement rate impact, among others, were confirmed with the cement log evaluation program. The paper will present the ultrasonic and standard CBL responses, which support the enhancements made to the cementing design and practices that yield the desired results. The cement quality has been improved in the ERD wells intermediate section through strategic modification in cementing practices. Cement evaluation logs have played a significant role in validating the cementing methods’ development. Consistently improved zonal isolation results have opened up the opportunity for future efficiency gains by eliminating routine CBL.
{"title":"Value of Cement Bond Logs for Evaluation and Improvement of Cementing Practices in Extended Reach Drilling ERD Wells","authors":"Romulo Bermudez Alvarado, Abdelkerim Doutoum Mahamat Habib, J. S. Duguid, Manish Srivastava, R. Medina, M. Rocha, Kresimir Vican, V. Jambunathan","doi":"10.2118/208115-ms","DOIUrl":"https://doi.org/10.2118/208115-ms","url":null,"abstract":"\u0000 This paper discusses the value of cement logs as the core input to analyze the cement quality and validate the improvements made to cementing designs and practices of the intermediate casing string in Extended-Reach Drilling (ERD) wells. The ERD wells are being drilled from artificial islands in a field offshore in the UAE. The primary cementing objectives are isolating the reservoirs from their sublayers and protecting the casing against possible future corrosion across an upper formation. Cementing challenges include higher angle deviation, higher mud weight requirements resulting from an anisotropic, unstable shale formation present above the reservoir section.\u0000 Effective reservoir management requires sound zonal isolation to eliminate crossflow between different reservoir units. In combination with standard cement bond logs (CBL), ultrasonic technology has provided detailed information about cement quality and a qualitative indication of casing position in the borehole. These have also led to valuable insight into how continued cementing designs and practices improved zonal isolation.\u0000 Improvements in cement quality seen as a result of enhanced casing centralization, optimized hydraulic model, modified cement rheology, displacement rate impact, among others, were confirmed with the cement log evaluation program. The paper will present the ultrasonic and standard CBL responses, which support the enhancements made to the cementing design and practices that yield the desired results.\u0000 The cement quality has been improved in the ERD wells intermediate section through strategic modification in cementing practices. Cement evaluation logs have played a significant role in validating the cementing methods’ development. Consistently improved zonal isolation results have opened up the opportunity for future efficiency gains by eliminating routine CBL.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84641090","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}
J. G. Garcia, Ramil Mirhasanov, Shahad Waleed AlKandari, A. Al-Rabah, A. Al-Naqi, Zakaria Swidan, Mahmoud Kalawina
Downhole fluid sampling of high quality, low contaminated oil samples with a pumpout wireline formation tester (PWFT) in a shallow unconsolidated reservoir with high H2S, high water salinity and filled with viscous oil is a quite challenging operation. Key properties, related to fluid flow in low pressure reservoirs: formation mechanical weakness, drilling invasion and the high contrast on fluid mobility, have resulted in the failure or impracticality of conventional methods for efficient sampling, resulting in a long sampling time causing high rig cost overhead and often highly contaminated oil samples. Most common problems faced during sampling are: Sand production- causing caving and lost seals and no pressure or samples. Sand plugging of the tool flowline. Operation limitation of pressure drawdown- dictated by extremely low formation pressure and mainly due to having saturated pressure around 20 to 30 psia below formation initial pressure (based on 118 bubble point samples measured in the laboratory). To maintain rock stability and low pressure draw down, fluids were pumped at a low rate, resulting in a long operation time, where a single sample take up to 15 – 20 hours of a pump out. Even with the long pumpout time the collected sample is often highly contaminated based on laboratory PVT analysis report. Understanding of the formation properties and its rock mechanics helps to design proper operating techniques to overcome the challenge of viscous oil sampling in unconsolidated sand reservoir. A pre-job geomeechanical study of unconfined sand with very low compressive strength, restricted the flow rate to a maximum drawdown per square inch to maintain rock stability while pumping out. Dual-Port Straddle Packer (figure 1) sampling was introduced to overcome the mentioned challenges. Its large flow area (>1000 in² in 8 ½″ OH section) allowed a high total pumping rate while maintaining very low flow rate per square inch at the sand face, which resulted in an ultra-low draw-down flowing pressure to prevent sand collapse and producing below bubble point pressure that could invalidate further PVT studies. Packer inflation pressure has also been limited to a maximum of 150 to 200 psia above hydrostatic pressure to achieve isolation without overcoming the sand weak compressive strength. During the clean-out operation crude oil tend to separate from water based mud (WBM) filtrate in the packed-off interval due to fluid density difference and immiscibility of the two liquids due to the lower shear rate applied (among others). So a water/oil interface forms within the packed-off interval. As pumping continues, this oil/water fluid contact moves toward the bottom inlet port allowing more clean oil to accumulate at the top. With the advantage of the dual inlet port straddle packer and the independent opening/closing operating design of each port, a clean segregated oil sample was collected from the top port at an early stage of
{"title":"Overcoming Downhole Fluid Sampling Challenge Using Dual-Port Straddle Packer in Shallow Viscous Reservoir","authors":"J. G. Garcia, Ramil Mirhasanov, Shahad Waleed AlKandari, A. Al-Rabah, A. Al-Naqi, Zakaria Swidan, Mahmoud Kalawina","doi":"10.2118/207716-ms","DOIUrl":"https://doi.org/10.2118/207716-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Downhole fluid sampling of high quality, low contaminated oil samples with a pumpout wireline formation tester (PWFT) in a shallow unconsolidated reservoir with high H2S, high water salinity and filled with viscous oil is a quite challenging operation.\u0000 Key properties, related to fluid flow in low pressure reservoirs: formation mechanical weakness, drilling invasion and the high contrast on fluid mobility, have resulted in the failure or impracticality of conventional methods for efficient sampling, resulting in a long sampling time causing high rig cost overhead and often highly contaminated oil samples.\u0000 Most common problems faced during sampling are:\u0000 Sand production- causing caving and lost seals and no pressure or samples. Sand plugging of the tool flowline. Operation limitation of pressure drawdown- dictated by extremely low formation pressure and mainly due to having saturated pressure around 20 to 30 psia below formation initial pressure (based on 118 bubble point samples measured in the laboratory). To maintain rock stability and low pressure draw down, fluids were pumped at a low rate, resulting in a long operation time, where a single sample take up to 15 – 20 hours of a pump out. Even with the long pumpout time the collected sample is often highly contaminated based on laboratory PVT analysis report.\u0000 \u0000 \u0000 \u0000 Understanding of the formation properties and its rock mechanics helps to design proper operating techniques to overcome the challenge of viscous oil sampling in unconsolidated sand reservoir.\u0000 A pre-job geomeechanical study of unconfined sand with very low compressive strength, restricted the flow rate to a maximum drawdown per square inch to maintain rock stability while pumping out.\u0000 Dual-Port Straddle Packer (figure 1) sampling was introduced to overcome the mentioned challenges. Its large flow area (>1000 in² in 8 ½″ OH section) allowed a high total pumping rate while maintaining very low flow rate per square inch at the sand face, which resulted in an ultra-low draw-down flowing pressure to prevent sand collapse and producing below bubble point pressure that could invalidate further PVT studies. Packer inflation pressure has also been limited to a maximum of 150 to 200 psia above hydrostatic pressure to achieve isolation without overcoming the sand weak compressive strength.\u0000 During the clean-out operation crude oil tend to separate from water based mud (WBM) filtrate in the packed-off interval due to fluid density difference and immiscibility of the two liquids due to the lower shear rate applied (among others). So a water/oil interface forms within the packed-off interval. As pumping continues, this oil/water fluid contact moves toward the bottom inlet port allowing more clean oil to accumulate at the top.\u0000 \u0000 \u0000 \u0000 With the advantage of the dual inlet port straddle packer and the independent opening/closing operating design of each port, a clean segregated oil sample was collected from the top port at an early stage of ","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84692099","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Abdullah Khalfan Salim Al Musalhi, Salim Hamed Thunaiyan Al Mawali, Ali Al Ruqaishi
With increasing wells connected to central facilities, it is hard to manage water flood using traditional technique. Therefore, a novel control concept named Swinging Water Injection Targets (SWIT) was developed in PDO to manage the challenges and satisfies both surface/subsurface requirements. The objectives of SWIT are: Maximize water injection well compliance. Minimize oil deferment due to water disposal restriction. Automated system that manages the variations in produced water flow with minimum interventions. SWIT concept is using the tolerance of ± 20% of desired injection target (Compliance limit) for each water injection (WI) well. So rather than having a fixed target, a minimum and maximum injection flow are giving to each WI well flow controller. Those range are provided by subsurface to ensure minimal impact for the rate fluctuation. The injection flows are driven by WI header pressure controller. When the produced water, the WI header pressure increases then the pressure controller to control the pressure asks all WI wells simultaneously increasing their injection flow at the same relative portion (Optimized distribution). Also, when the produced water decreases all WI flow starts reducing in the same way. SWIT concept proved success in PDO and it became a standard. It was first introduced in small field. Later, it was replicated across the company fields. The biggest scale implementation was in a cluster with more than 500 WI wells. Previously, in that cluster the WI header pressure was fluctuating indicating issues with water balance. Many manual adjustments were required to manage the situations when the produced water is more than the injection demand by closing oil producers leading to a considerable deferment due to water disposal restriction. Also, when the supply water is less than injection demand many WI wells start under injecting leading to low injection compliance. After SWIT was introduced in the cluster and all injectors started swinging in harmony via automatic control, it managed to balance the water system (controlled WI header pressure) regardless of the variation in produced water production. This resulted in increase of WI compliance by 5% after implementation. As SWIT optimized the water distribution to the injectors, roughly around 50 m3/d of additional oil production was achieved. It also minimized deferment from disposal restriction to a minimum level. All of this without the hustle of manual interventions.
{"title":"Swinging Water Injection Targets SWIT","authors":"Abdullah Khalfan Salim Al Musalhi, Salim Hamed Thunaiyan Al Mawali, Ali Al Ruqaishi","doi":"10.2118/207689-ms","DOIUrl":"https://doi.org/10.2118/207689-ms","url":null,"abstract":"\u0000 With increasing wells connected to central facilities, it is hard to manage water flood using traditional technique. Therefore, a novel control concept named Swinging Water Injection Targets (SWIT) was developed in PDO to manage the challenges and satisfies both surface/subsurface requirements. The objectives of SWIT are:\u0000 Maximize water injection well compliance. Minimize oil deferment due to water disposal restriction. Automated system that manages the variations in produced water flow with minimum interventions.\u0000 SWIT concept is using the tolerance of ± 20% of desired injection target (Compliance limit) for each water injection (WI) well. So rather than having a fixed target, a minimum and maximum injection flow are giving to each WI well flow controller. Those range are provided by subsurface to ensure minimal impact for the rate fluctuation. The injection flows are driven by WI header pressure controller. When the produced water, the WI header pressure increases then the pressure controller to control the pressure asks all WI wells simultaneously increasing their injection flow at the same relative portion (Optimized distribution). Also, when the produced water decreases all WI flow starts reducing in the same way.\u0000 SWIT concept proved success in PDO and it became a standard. It was first introduced in small field. Later, it was replicated across the company fields. The biggest scale implementation was in a cluster with more than 500 WI wells. Previously, in that cluster the WI header pressure was fluctuating indicating issues with water balance. Many manual adjustments were required to manage the situations when the produced water is more than the injection demand by closing oil producers leading to a considerable deferment due to water disposal restriction. Also, when the supply water is less than injection demand many WI wells start under injecting leading to low injection compliance. After SWIT was introduced in the cluster and all injectors started swinging in harmony via automatic control, it managed to balance the water system (controlled WI header pressure) regardless of the variation in produced water production.\u0000 This resulted in increase of WI compliance by 5% after implementation. As SWIT optimized the water distribution to the injectors, roughly around 50 m3/d of additional oil production was achieved. It also minimized deferment from disposal restriction to a minimum level. All of this without the hustle of manual interventions.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84857650","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}
Abdulla Aljaberi, S. A. Farzaneh, S. Aghabozorgi, Mohammad Saeid Ataei, M. Sohrabi
Oil recovery by low salinity waterflood is significantly affected by fluid-fluid interaction through the micro-dispersion effect. This interaction influences rock wettability and relative permeability functions. Therefore, to gain a better insight into multiphase flow in porous media and perform numerical simulations, reliable relative permeability data is crucial. Unsteady-state or steady-state displacement methods are commonly used in the laboratory to measure water-oil relative permeability curves of a core sample. Experimentally, the unsteady-state core flood technique is more straightforward and less time-consuming compared to the steady-state method. However, the obtained data is limited to a small saturation range, and the associated uncertainty is not negligible. On the other hand, the steady-state method provides a more accurate dataset of two-phase relative permeability needed in the reservoir simulator for a reliable prediction of the high salinity and low salinity waterflood displacement performance. Considering the limitations of the unsteady state method, steady-state high salinity and low salinity brine experiments waterflood experiments were performed to compare the obtained relative permeability curves. The experiments were performed on a carbonate reservoir sample using a live reservoir crude oil under reservoir conditions. The test was designed so that the production and pressure drop curve covers a wider saturation range and provides enough data for analysis. Consequently, reliable relative permeability functions were obtained, initially, for a better comparison and prediction of the high salinity and the low salinity waterflood injections and then, to quantify the effect of low salinity waterflood under steady-state conditions. The results confirm the difference in relative permeability curves between high salinity and low salinity injections due to the micro-dispersion effect, which caused a decrease in water relative permeability and an increase in the oil relative permeability. These results also proved that low salinity brine can change the rock wettability from oil-wet or mixed-wet to more water-wet conditions. Furthermore, the obtained relative permeability curves extend across a substantial saturation range, making it valuable information required for numerical simulations. To the best of our knowledge, the reported data in this work is a pioneer in quantifying the impact of low salinity waterflood at steady-state conditions using a reservoir crude oil and reservoir rock, which is of utmost importance for the oil and gas industry.
{"title":"An Experimental Investigation of High and Low Salinity Waterflood Displacement Under the Steady-State Condition","authors":"Abdulla Aljaberi, S. A. Farzaneh, S. Aghabozorgi, Mohammad Saeid Ataei, M. Sohrabi","doi":"10.2118/207339-ms","DOIUrl":"https://doi.org/10.2118/207339-ms","url":null,"abstract":"\u0000 Oil recovery by low salinity waterflood is significantly affected by fluid-fluid interaction through the micro-dispersion effect. This interaction influences rock wettability and relative permeability functions. Therefore, to gain a better insight into multiphase flow in porous media and perform numerical simulations, reliable relative permeability data is crucial. Unsteady-state or steady-state displacement methods are commonly used in the laboratory to measure water-oil relative permeability curves of a core sample. Experimentally, the unsteady-state core flood technique is more straightforward and less time-consuming compared to the steady-state method. However, the obtained data is limited to a small saturation range, and the associated uncertainty is not negligible. On the other hand, the steady-state method provides a more accurate dataset of two-phase relative permeability needed in the reservoir simulator for a reliable prediction of the high salinity and low salinity waterflood displacement performance.\u0000 Considering the limitations of the unsteady state method, steady-state high salinity and low salinity brine experiments waterflood experiments were performed to compare the obtained relative permeability curves. The experiments were performed on a carbonate reservoir sample using a live reservoir crude oil under reservoir conditions. The test was designed so that the production and pressure drop curve covers a wider saturation range and provides enough data for analysis. Consequently, reliable relative permeability functions were obtained, initially, for a better comparison and prediction of the high salinity and the low salinity waterflood injections and then, to quantify the effect of low salinity waterflood under steady-state conditions.\u0000 The results confirm the difference in relative permeability curves between high salinity and low salinity injections due to the micro-dispersion effect, which caused a decrease in water relative permeability and an increase in the oil relative permeability. These results also proved that low salinity brine can change the rock wettability from oil-wet or mixed-wet to more water-wet conditions. Furthermore, the obtained relative permeability curves extend across a substantial saturation range, making it valuable information required for numerical simulations. To the best of our knowledge, the reported data in this work is a pioneer in quantifying the impact of low salinity waterflood at steady-state conditions using a reservoir crude oil and reservoir rock, which is of utmost importance for the oil and gas industry.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89582073","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Ragaglia, Antonio Carotenuto, L. Napoleone, Guerino De Dominicis, Sergey Sakharov, A. Latypov, R. Newman, Carlos Guevara, Hakim Rachi, Kjell Revheim
To rapidly increase production from the Goliat Field without adding costly subsea equipment and infrastructure or mobilizing a high-end subsea construction vessel, an operator transformed two single-bore subsea wells into multilateral producers with independently controlled branches. A multidisciplinary team was assigned to perform a feasibility study for the introduction of multilateral wells. Work started with a reservoir geomechanics/wellbore stability review, based on which well construction/completion basis of design was made. The design and operations sequence were analyzed by a well engineering team. As a result, the main risks, uncertainties, and assumptions were clarified. Two candidate wells were identified, and then a multidisciplinary team was assigned to manage the project, finalize design, initiate procurement, and write procedures. Workshop preparation was closely monitored and reported on a weekly basis. The onshore team closely followed up and supported operational execution. The new laterals were added to the existing wells, and multilateral junctions were installed and tested. An intelligent completion was installed, and independent branch production started. In addition, the estimated reduction in generation of CO2 is estimated to be between 10 to 20 thousand metric tons per well as compared with drilling two new subsea wells and installing the associated infrastructure. The technology enables an exploration and production (E&P) company to introduce subsea reentry multilateral technology to increase production while minimizing costs. The process includes well candidate identification, planning, and execution. This practical example can be used for future reference by drilling and production-focused petroleum industry professionals to better understand the benefits and limitations of existing technologies.
{"title":"Industry First Subsea Reentry Multilateral Wells: Case Study","authors":"S. Ragaglia, Antonio Carotenuto, L. Napoleone, Guerino De Dominicis, Sergey Sakharov, A. Latypov, R. Newman, Carlos Guevara, Hakim Rachi, Kjell Revheim","doi":"10.2118/207960-ms","DOIUrl":"https://doi.org/10.2118/207960-ms","url":null,"abstract":"\u0000 To rapidly increase production from the Goliat Field without adding costly subsea equipment and infrastructure or mobilizing a high-end subsea construction vessel, an operator transformed two single-bore subsea wells into multilateral producers with independently controlled branches.\u0000 A multidisciplinary team was assigned to perform a feasibility study for the introduction of multilateral wells. Work started with a reservoir geomechanics/wellbore stability review, based on which well construction/completion basis of design was made. The design and operations sequence were analyzed by a well engineering team. As a result, the main risks, uncertainties, and assumptions were clarified. Two candidate wells were identified, and then a multidisciplinary team was assigned to manage the project, finalize design, initiate procurement, and write procedures. Workshop preparation was closely monitored and reported on a weekly basis. The onshore team closely followed up and supported operational execution.\u0000 The new laterals were added to the existing wells, and multilateral junctions were installed and tested. An intelligent completion was installed, and independent branch production started. In addition, the estimated reduction in generation of CO2 is estimated to be between 10 to 20 thousand metric tons per well as compared with drilling two new subsea wells and installing the associated infrastructure.\u0000 The technology enables an exploration and production (E&P) company to introduce subsea reentry multilateral technology to increase production while minimizing costs. The process includes well candidate identification, planning, and execution. This practical example can be used for future reference by drilling and production-focused petroleum industry professionals to better understand the benefits and limitations of existing technologies.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"108 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91551112","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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