Ala S. AlDogail, R. Gajbhiye, Mustafa Alnaser, Abdullatif Alnajim
This study aims to propose an intelligent operational advisory solution that guides the plant operation team to optimal HPPT/LPPT pressure settings that compensate for the variation in ambient temperature effect to maximize plant revenue. Traditional industry practice is to operate a gas-oil-separation-plant (GOSP) at fixed operating conditions ignoring the variation in the ambient temperature (Ta) leading to a loss in oil recovery and associated revenue. The variation of ambient temperature (Ta) highly affects the separation process, where ambient temperature varies greatly from summer to winter. To develop a correlation, a GOSP model was constructed by OmegaLand dynamic simulator using a typical Saudi Aramco GOSP design. Oil recovery values were determined by running the process simulation for a typical range of high-pressure production trap (HPPT), low-pressure production trap (LPPT), and ambient temperature (Ta). Then, an intelligent approach was built to determine the optimum pressure of LPPT and HPPT units for each ambient temperature condition using an artificial intelligence technique. Results show that liquid recovery decreases with an increase in ambient temperature at constant HPPT and LPPT pressures, indicating adjustment in HPPT or LPPT pressure responding to the temperature variations can improve the oil recovery. At constant LPPT pressure and ambient temperature, the oil recovery increases with an increase in HPPT pressure until it reaches the optimum value and then decreases with further increase in the HPPTpressure suggesting that there is an optimum HPPT pressure at which oil recovery is maximum. At fixed ambient temperature and fixed HPPT pressure, liquid recovery increases with increasing LPPT pressure until it reaches the optimum value, and then it decreases with further increase in the LPPT pressure suggesting that there is an optimum LPPT pressure at which oil recovery is maximum.
{"title":"Intelligent Approach for GOSP Oil Recovery Enhancement","authors":"Ala S. AlDogail, R. Gajbhiye, Mustafa Alnaser, Abdullatif Alnajim","doi":"10.2118/206045-ms","DOIUrl":"https://doi.org/10.2118/206045-ms","url":null,"abstract":"\u0000 This study aims to propose an intelligent operational advisory solution that guides the plant operation team to optimal HPPT/LPPT pressure settings that compensate for the variation in ambient temperature effect to maximize plant revenue. Traditional industry practice is to operate a gas-oil-separation-plant (GOSP) at fixed operating conditions ignoring the variation in the ambient temperature (Ta) leading to a loss in oil recovery and associated revenue. The variation of ambient temperature (Ta) highly affects the separation process, where ambient temperature varies greatly from summer to winter.\u0000 To develop a correlation, a GOSP model was constructed by OmegaLand dynamic simulator using a typical Saudi Aramco GOSP design. Oil recovery values were determined by running the process simulation for a typical range of high-pressure production trap (HPPT), low-pressure production trap (LPPT), and ambient temperature (Ta). Then, an intelligent approach was built to determine the optimum pressure of LPPT and HPPT units for each ambient temperature condition using an artificial intelligence technique.\u0000 Results show that liquid recovery decreases with an increase in ambient temperature at constant HPPT and LPPT pressures, indicating adjustment in HPPT or LPPT pressure responding to the temperature variations can improve the oil recovery. At constant LPPT pressure and ambient temperature, the oil recovery increases with an increase in HPPT pressure until it reaches the optimum value and then decreases with further increase in the HPPTpressure suggesting that there is an optimum HPPT pressure at which oil recovery is maximum. At fixed ambient temperature and fixed HPPT pressure, liquid recovery increases with increasing LPPT pressure until it reaches the optimum value, and then it decreases with further increase in the LPPT pressure suggesting that there is an optimum LPPT pressure at which oil recovery is maximum.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"95 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82222599","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}
Characterizing the naturally fractured reservoir in a mature field is always a challenging task due to minimal subsurface data availability and the technology was not as advanced as nowadays. Therefore, this paper is proposed to provide an alternative solution to identify the presence of the fractures, classify them into the fractured quality related flowability, and distribute them vertically within the well interval and propose a lateral distribution method for reservoir modeling. This research was conducted based on a case study of basement fractured carbonate reservoir in Hungary. I used more than twenty development wells which mainly drilled during 1980-2000's. The fractures presence is simply identified by using gamma-ray and density logs. The relative movement of density log to the defined fractured baselines was directed to classify the fracture quality within three groups of macro-fracture, micro-fracture, and host-rock. These groups were validated by core data and the acoustic image log from the newest drilled wells. Furthermore, I implemented the self-organizing map (SOM) for distributing the fracture group to other wells which having limited subsurface data. Since the fracture classes were distributed along the well depth interval, then the well test (DST) results and production flow test data validated the flowability of them. As a result, the main flow contribution intervals of the fracture can be well-recognized. The macro-fracture consistently indicates the fracture class showing the main contribution of the liquid flowrate more than 10 m3/d along the perforated intervals. The rock properties of this class have porosity range around 1-2% with permeability dominantly more than 100 mD. In contrast, the host-rock class is defined as a protolith/non-fractured rock. The porosity and permeability are extremely low (tight rock). This class does not give any flow contribution due to the high content of the marl or clay, the absence of the fracture, or the fractures had been re-cemented by calcite or quartz minerals. Meanwhile, the micro-fracture denotes the group of rock with porosity range around 2-10% and permeability average between 1-10 mD. In general, the flowrate coming from this fracture class was lower than 10 m3/d of liquid during the flow-test. As a novelty, this proposed approach with the machine learning of SOM-clustering effectively assists us to recognize the fracture presence and its quality along the well-depth interval from the absence of the advanced technologies of image logs and production logging (PLT) measurement. Also, the defined fracture class here can take a role as a fracture facies or rock typing in terms of 3D reservoir modeling and distributed laterally based on fault-likelihood attribute and fault zone defined by distance-to-fault.
{"title":"Naturally Fractured Basement Reservoir Characterization in a Mature Field","authors":"M. Akbar","doi":"10.2118/206027-ms","DOIUrl":"https://doi.org/10.2118/206027-ms","url":null,"abstract":"\u0000 Characterizing the naturally fractured reservoir in a mature field is always a challenging task due to minimal subsurface data availability and the technology was not as advanced as nowadays. Therefore, this paper is proposed to provide an alternative solution to identify the presence of the fractures, classify them into the fractured quality related flowability, and distribute them vertically within the well interval and propose a lateral distribution method for reservoir modeling.\u0000 This research was conducted based on a case study of basement fractured carbonate reservoir in Hungary. I used more than twenty development wells which mainly drilled during 1980-2000's. The fractures presence is simply identified by using gamma-ray and density logs. The relative movement of density log to the defined fractured baselines was directed to classify the fracture quality within three groups of macro-fracture, micro-fracture, and host-rock. These groups were validated by core data and the acoustic image log from the newest drilled wells. Furthermore, I implemented the self-organizing map (SOM) for distributing the fracture group to other wells which having limited subsurface data.\u0000 Since the fracture classes were distributed along the well depth interval, then the well test (DST) results and production flow test data validated the flowability of them. As a result, the main flow contribution intervals of the fracture can be well-recognized. The macro-fracture consistently indicates the fracture class showing the main contribution of the liquid flowrate more than 10 m3/d along the perforated intervals. The rock properties of this class have porosity range around 1-2% with permeability dominantly more than 100 mD. In contrast, the host-rock class is defined as a protolith/non-fractured rock. The porosity and permeability are extremely low (tight rock). This class does not give any flow contribution due to the high content of the marl or clay, the absence of the fracture, or the fractures had been re-cemented by calcite or quartz minerals. Meanwhile, the micro-fracture denotes the group of rock with porosity range around 2-10% and permeability average between 1-10 mD. In general, the flowrate coming from this fracture class was lower than 10 m3/d of liquid during the flow-test.\u0000 As a novelty, this proposed approach with the machine learning of SOM-clustering effectively assists us to recognize the fracture presence and its quality along the well-depth interval from the absence of the advanced technologies of image logs and production logging (PLT) measurement. Also, the defined fracture class here can take a role as a fracture facies or rock typing in terms of 3D reservoir modeling and distributed laterally based on fault-likelihood attribute and fault zone defined by distance-to-fault.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84285019","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 complexity, high cost, and potential environmental concerns of chemical enhanced oil recovery (EOR) methods have diminished their field applications considerably. However, considering the significant incremental oil recoveries that can be obtained from these methods encourage researchers to explore ways to reduce both complexity, cost, and environmental concerns of such systems. This is especially important in carbonate formations, where after waterflooding, much of the oil remains trapped in complex reservoir pores—especially if the reservoir contains an interconnected fracture network of flow channels within the bulk rock matrix. In this paper, we present an experimental assessment of several simple chemical EOR waterflooding systems comprising of small concentrations of a low cost, low molecular weight ketone and a non-ionic surfactant in association with low-salinity brine. The experiments were conducted in carbonate cores from a Permian Basin San Andres Formation. Four different oil displacement scenarios were investigated using San Andres carbonate cores from the Central Vacuum Field in New Mexico. This included 1) low-salinity brine, 2) low-salinity brine with a surfactant, 3) low-salinity brine with a ketone, and 4) low-salinity brine with a combined ketone-surfactant system. Static imbibition experiments were conducted using a spontaneous imbibition apparatus in addition to the use of a high-speed centrifuge to saturate the cores to irreducible brine saturation. Adding a 1% concentration of 3-pentanone and a 1% non-ionic surfactant to a low-salinity brine yielded oil recoveries of 44% from the 3-pentanone system, compared to 11.4% from low-salinity brine only. The oil recovery is enhanced by a single mechanism or synergy of several mechanisms that includes interfacial tension (IFT) reduction by surfactant, capillary imbibition, favorable wettability alteration by ketone, and osmotic low-salinity brine imbibition. The IFT decreased to 1.79 mN/m upon addition of non-ionic surfactant to low-salinity brine, and it reduced to 2.96 mN/m in a mixture of 3-pentanone and non-ionic surfactant in low-salinity brine. Furthermore, ketone improved the core wettability by reducing the contact angle to 43.9° from 50.7° in the low-salinity brine experiment. In addition, the low-salinity brine systems caused mineral dissolution, which created an alkali environment confirmed by an increase in the brine pH. We believe the increase in pH increased the hydrophilic character of the pores; thus, increasing oil recovery.
{"title":"Cost-Effective Chemical EOR for Heterogenous Carbonate Reservoirs Using a Ketone-Surfactant System","authors":"Etaf Alghunaim, O. Uzun, H. Kazemi, J. Sarg","doi":"10.2118/205910-ms","DOIUrl":"https://doi.org/10.2118/205910-ms","url":null,"abstract":"\u0000 The complexity, high cost, and potential environmental concerns of chemical enhanced oil recovery (EOR) methods have diminished their field applications considerably. However, considering the significant incremental oil recoveries that can be obtained from these methods encourage researchers to explore ways to reduce both complexity, cost, and environmental concerns of such systems. This is especially important in carbonate formations, where after waterflooding, much of the oil remains trapped in complex reservoir pores—especially if the reservoir contains an interconnected fracture network of flow channels within the bulk rock matrix.\u0000 In this paper, we present an experimental assessment of several simple chemical EOR waterflooding systems comprising of small concentrations of a low cost, low molecular weight ketone and a non-ionic surfactant in association with low-salinity brine. The experiments were conducted in carbonate cores from a Permian Basin San Andres Formation. Four different oil displacement scenarios were investigated using San Andres carbonate cores from the Central Vacuum Field in New Mexico. This included 1) low-salinity brine, 2) low-salinity brine with a surfactant, 3) low-salinity brine with a ketone, and 4) low-salinity brine with a combined ketone-surfactant system. Static imbibition experiments were conducted using a spontaneous imbibition apparatus in addition to the use of a high-speed centrifuge to saturate the cores to irreducible brine saturation.\u0000 Adding a 1% concentration of 3-pentanone and a 1% non-ionic surfactant to a low-salinity brine yielded oil recoveries of 44% from the 3-pentanone system, compared to 11.4% from low-salinity brine only. The oil recovery is enhanced by a single mechanism or synergy of several mechanisms that includes interfacial tension (IFT) reduction by surfactant, capillary imbibition, favorable wettability alteration by ketone, and osmotic low-salinity brine imbibition. The IFT decreased to 1.79 mN/m upon addition of non-ionic surfactant to low-salinity brine, and it reduced to 2.96 mN/m in a mixture of 3-pentanone and non-ionic surfactant in low-salinity brine. Furthermore, ketone improved the core wettability by reducing the contact angle to 43.9° from 50.7° in the low-salinity brine experiment. In addition, the low-salinity brine systems caused mineral dissolution, which created an alkali environment confirmed by an increase in the brine pH. We believe the increase in pH increased the hydrophilic character of the pores; thus, increasing oil recovery.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"402 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77475754","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}
Cathrine Mehus, V. Keerthivasan, T. Koløy, D. Young, Tore Sørheim
A toe initiation sleeve is a tool installed in the toe of a completion liner and is used to establish a flowpath to the reservoir without the use of intervention. Conventional toe initiation sleeves require either intervention or increasing pressure to higher than the liner test pressure to activate. These methods have inherent cost and operational risks. This paper will present the development, qualification, and deployment of a multicycle, time-delay cementable toe initiation sleeve that allows for interventionless activation without exceeding the liner test pressure. This development greatly improves operational efficiency and eliminates risk associated with conventional toe initiation sleeves. A major operator in the North Sea required an ISO V0 rated toe initiation sleeve to be developed and qualified. Design criteria for the tool was identified, and the design was developed based on field-qualified seal technology. Individual component and full-scale validation testing was performed to complete the product qualification, followed by field trials in 2019. With its unique time-delay feature, the newly developed ATS (Advanced Toe Sleeve) allows for an unlimited number of pressure cycles to be performed while also keeping the well V0 barrier in place, and activates at below liner test pressure. This paper will discuss the technology development and implementation project, resulting in ISO 14998 V0-qualified cemented ATS being installed in nearly 40 wells in the same field. This paper will also provide insight into how the ATS provides unique benefits to the operator during various phases of the well's life. Cementing: One moving part and opening sleeve isolated from the inside diameter (ID) allow for pumping darts through the ATS without the risk of opening Setting liner/testing liner: Time-delay features allow for setting liner and testing the liner at higher pressures than ATS opening pressure. Well cleanup/displacing to lower density fluid: Time-delay function allows for opening the ATS at lower pressure than the well has seen during previous operations. Completion: ATS design and qualification grade reduce completion steps and costs for the operator. Stimulation: ATS eliminates the need for intervention, reducing the operational steps and costs for the operator. The advanced toe sleeve with built-in time-delay features maintains the liner integrity throughout the various well operations. The number of available pressure cycles can be predetermined, and the activation of the various cycles can be precisely controlled thereby also controlling when the tool is activated to achieve injectivity. This paper will present the development and field-wide implementation of the ATS technology, which has rapidly gained operator acceptance and resulted in significant time and cost savings.
{"title":"Toe Initiation Sleeve With Time-Delay Functionality Improves Operational Efficiency of Offshore NCS Wells","authors":"Cathrine Mehus, V. Keerthivasan, T. Koløy, D. Young, Tore Sørheim","doi":"10.2118/206268-ms","DOIUrl":"https://doi.org/10.2118/206268-ms","url":null,"abstract":"\u0000 A toe initiation sleeve is a tool installed in the toe of a completion liner and is used to establish a flowpath to the reservoir without the use of intervention. Conventional toe initiation sleeves require either intervention or increasing pressure to higher than the liner test pressure to activate. These methods have inherent cost and operational risks. This paper will present the development, qualification, and deployment of a multicycle, time-delay cementable toe initiation sleeve that allows for interventionless activation without exceeding the liner test pressure. This development greatly improves operational efficiency and eliminates risk associated with conventional toe initiation sleeves.\u0000 A major operator in the North Sea required an ISO V0 rated toe initiation sleeve to be developed and qualified. Design criteria for the tool was identified, and the design was developed based on field-qualified seal technology. Individual component and full-scale validation testing was performed to complete the product qualification, followed by field trials in 2019. With its unique time-delay feature, the newly developed ATS (Advanced Toe Sleeve) allows for an unlimited number of pressure cycles to be performed while also keeping the well V0 barrier in place, and activates at below liner test pressure.\u0000 This paper will discuss the technology development and implementation project, resulting in ISO 14998 V0-qualified cemented ATS being installed in nearly 40 wells in the same field. This paper will also provide insight into how the ATS provides unique benefits to the operator during various phases of the well's life.\u0000 Cementing: One moving part and opening sleeve isolated from the inside diameter (ID) allow for pumping darts through the ATS without the risk of opening Setting liner/testing liner: Time-delay features allow for setting liner and testing the liner at higher pressures than ATS opening pressure. Well cleanup/displacing to lower density fluid: Time-delay function allows for opening the ATS at lower pressure than the well has seen during previous operations. Completion: ATS design and qualification grade reduce completion steps and costs for the operator. Stimulation: ATS eliminates the need for intervention, reducing the operational steps and costs for the operator.\u0000 The advanced toe sleeve with built-in time-delay features maintains the liner integrity throughout the various well operations. The number of available pressure cycles can be predetermined, and the activation of the various cycles can be precisely controlled thereby also controlling when the tool is activated to achieve injectivity. This paper will present the development and field-wide implementation of the ATS technology, which has rapidly gained operator acceptance and resulted in significant time and cost savings.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78992154","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}
Improved Oil Recovery, IOR, in shales is a topic of growing interest due to the low oil recovery observed in shales. Evaluating different IOR chemicals at the lab scale has proved difficult and time consuming due to their ultra-low permeability and low porosity. Conventional core procedures (such as core floods) are often not practical to use with such samples since they take too long. In this study, we introduce a new laboratory method for measuring the oil recovery in a huff-and-puff IOR process in shales. In huff-and-puff IOR, a treatment additive and a gas are typically injected in combination into the reservoir. Oil production is initiated after a shut-in period. Our experimental protocol starts by saturating preserved shales with oil by exposing them to the reservoir oil under pressure for an extended time. To speed up this process the preserved shale sample is crushed and sieved to 5-10 mesh. The pressure vessels are then loaded with these oil-saturated 5-10 mesh shale particles and the desired IOR fluid is injected into the pressure vessel. The vessel is rotated to ensure full contact with the shale. The samples are heated to ensure that the fluid is at reservoir pressure and temperature. Several tests were done to ensure that the fluid temperature and pressure inside the vessels were at the desired conditions throughout the 72-hour test period. T2 NMR scans were carried out before and after treatment to determine the amount of incremental oil recovery from the treatment. In tests where the two fluid phases were indistinguishable, deuterium was used in the treatment fluid in lieu of water. Excellent reproducible results were obtained with this method. This new method has been used to test a number of different treatment fluids, gases and solvents under a variety of conditions. The test can be completed in a matter of a few days as compared to several weeks that would be required for a core flood. Several tests can be run simultaneously, further speeding up the process. The results of the laboratory tests can be scaled to the field by using suitable surface-to-volume ratios in the lab and comparing them to the field. With this new method we have a fast and robust method for conducting these huff-and-puff experiments in a repeatable, and precise manner. This allows us to quickly evaluate different IOR fluids for a particular shale-fluid system at reservoir conditions.
{"title":"A New Experimental Method for Measuring Improved Oil Recovery in Shales","authors":"Zach Quintanilla, R. Russell, M. Sharma","doi":"10.2118/206016-ms","DOIUrl":"https://doi.org/10.2118/206016-ms","url":null,"abstract":"\u0000 Improved Oil Recovery, IOR, in shales is a topic of growing interest due to the low oil recovery observed in shales. Evaluating different IOR chemicals at the lab scale has proved difficult and time consuming due to their ultra-low permeability and low porosity. Conventional core procedures (such as core floods) are often not practical to use with such samples since they take too long.\u0000 In this study, we introduce a new laboratory method for measuring the oil recovery in a huff-and-puff IOR process in shales. In huff-and-puff IOR, a treatment additive and a gas are typically injected in combination into the reservoir. Oil production is initiated after a shut-in period. Our experimental protocol starts by saturating preserved shales with oil by exposing them to the reservoir oil under pressure for an extended time. To speed up this process the preserved shale sample is crushed and sieved to 5-10 mesh. The pressure vessels are then loaded with these oil-saturated 5-10 mesh shale particles and the desired IOR fluid is injected into the pressure vessel. The vessel is rotated to ensure full contact with the shale. The samples are heated to ensure that the fluid is at reservoir pressure and temperature. Several tests were done to ensure that the fluid temperature and pressure inside the vessels were at the desired conditions throughout the 72-hour test period. T2 NMR scans were carried out before and after treatment to determine the amount of incremental oil recovery from the treatment. In tests where the two fluid phases were indistinguishable, deuterium was used in the treatment fluid in lieu of water. Excellent reproducible results were obtained with this method. This new method has been used to test a number of different treatment fluids, gases and solvents under a variety of conditions. The test can be completed in a matter of a few days as compared to several weeks that would be required for a core flood. Several tests can be run simultaneously, further speeding up the process. The results of the laboratory tests can be scaled to the field by using suitable surface-to-volume ratios in the lab and comparing them to the field.\u0000 With this new method we have a fast and robust method for conducting these huff-and-puff experiments in a repeatable, and precise manner. This allows us to quickly evaluate different IOR fluids for a particular shale-fluid system at reservoir conditions.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82736477","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 present paper is concerned with improving matrix acidizing in carbonate formation. For this purpose, ultrasonic waves were added to conventional matrix acid stimulation to increase the acid reach inside the rock. This concept is based on a phonophoresis effect of the acid, applying a similar concept in pushing the stimulation acid deeper in the formation during matrix acidizing. This effect will have a great benefit in reaching larger stimulated areas and increasing the overall well productivity. Extensive laboratory experiments have shown that the rate of penetration of the acid when exposed simultaneously to ultrasonic wave irradiation reached almost 90% more than the acid only. This phenomena has been investigated through the use of CT scan analysis on the core samples. The penetration was instantaneous and rapid in reaching deeper length of the plug sample.
{"title":"Enhancing Matrix Acid Stimulation Using Ultrasonic Waves","authors":"Mohammed H. Khaldi, S. Çalışkan, M. Noui-Mehidi","doi":"10.2118/205838-ms","DOIUrl":"https://doi.org/10.2118/205838-ms","url":null,"abstract":"\u0000 The present paper is concerned with improving matrix acidizing in carbonate formation. For this purpose, ultrasonic waves were added to conventional matrix acid stimulation to increase the acid reach inside the rock. This concept is based on a phonophoresis effect of the acid, applying a similar concept in pushing the stimulation acid deeper in the formation during matrix acidizing. This effect will have a great benefit in reaching larger stimulated areas and increasing the overall well productivity. Extensive laboratory experiments have shown that the rate of penetration of the acid when exposed simultaneously to ultrasonic wave irradiation reached almost 90% more than the acid only. This phenomena has been investigated through the use of CT scan analysis on the core samples. The penetration was instantaneous and rapid in reaching deeper length of the plug sample.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"628 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77024373","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}
Jing Wang, Tuozheng Zhang, Huiqing Liu, Xiaohu Dong, Xiaobo Li, Yang Min, Hongguang Liu, Gaixing Hu, K. Sepehrnoori
Fractured-vuggy reservoir is significantly different from porous reservoirs. Ordovician reservoir in T Oilfield in China is the largest FVCR around the world. Water flooding has been applied as a prospective method in more than 140 units, but water channeling is especially serious and the recovery is only about 15%. In such reservoir, cavities and fractures are the main storage spaces and flow channels, respectively. Because the fractures and cavities are spatially non-stratified and discretized, the waterflood pattern differs significantly from that in sandstone or porous carbonate reservoirs. It is very essential to construct a spatial well pattern to match the distribution and connectivity of fractures and cavities, which is a very popular topic in recent years. In this work, we presented a multistage construction method of spatial well pattern combining reservoir engineering with numerical simulation methods. Firstly, the economic concepts of Lorenz curve and Gini coefficient were introduced to choose the injector from all wells to achieve equilibrium displacement of injected water in the plane. Secondly, displacement and drainage equilibrium index (DDEI) was presented to determine the vertical location of the injector to achieve equilibrium displacement and drainage in vertical direction. Thirdly, the vertical locations of the producers were determined based on the distribution of reserves in vertical direction. Fourthly, the local producers were further optimized based on the cavities along the wellbore by numerical simulation. Finally, this method was successfully used to construct the spatial well patterns of fractured-vuggy units with different karst features in A unit of T Oilfield. The results show that the oil recovery factor is inversely proportional to the Gini coefficient calculated with the combined variable of flow resistance and crude reserve rather than that calculated with flow resistance in pore reservoirs. The ratio of the reserve to formation factor, V/(kh), can be used to determine the vertical location of the injector. And the optimal DDEI which is the ratio of V/(kh) in upper reservoir of the wellbore to that in lower reservoir of the wellbore is equal to 1. The vertical locations of producers are related to the vertical distributions of reserve and cavities in different karst units. At last, the principles of constructing spatial well pattern in fractured-vuggy carbonate reservoirs were proposed. This work provides an innovative and effective method to establish a spatial well pattern for FVCRs, which will break new ground for efficient development of FVCRs by water flooding.
{"title":"A Novel Method of Constructing Spatial Well Pattern for Water Flooding in Fractured-Vuggy Carbonate Reservoirs FVCRs","authors":"Jing Wang, Tuozheng Zhang, Huiqing Liu, Xiaohu Dong, Xiaobo Li, Yang Min, Hongguang Liu, Gaixing Hu, K. Sepehrnoori","doi":"10.2118/206017-ms","DOIUrl":"https://doi.org/10.2118/206017-ms","url":null,"abstract":"\u0000 Fractured-vuggy reservoir is significantly different from porous reservoirs. Ordovician reservoir in T Oilfield in China is the largest FVCR around the world. Water flooding has been applied as a prospective method in more than 140 units, but water channeling is especially serious and the recovery is only about 15%. In such reservoir, cavities and fractures are the main storage spaces and flow channels, respectively. Because the fractures and cavities are spatially non-stratified and discretized, the waterflood pattern differs significantly from that in sandstone or porous carbonate reservoirs. It is very essential to construct a spatial well pattern to match the distribution and connectivity of fractures and cavities, which is a very popular topic in recent years.\u0000 In this work, we presented a multistage construction method of spatial well pattern combining reservoir engineering with numerical simulation methods. Firstly, the economic concepts of Lorenz curve and Gini coefficient were introduced to choose the injector from all wells to achieve equilibrium displacement of injected water in the plane. Secondly, displacement and drainage equilibrium index (DDEI) was presented to determine the vertical location of the injector to achieve equilibrium displacement and drainage in vertical direction. Thirdly, the vertical locations of the producers were determined based on the distribution of reserves in vertical direction. Fourthly, the local producers were further optimized based on the cavities along the wellbore by numerical simulation. Finally, this method was successfully used to construct the spatial well patterns of fractured-vuggy units with different karst features in A unit of T Oilfield.\u0000 The results show that the oil recovery factor is inversely proportional to the Gini coefficient calculated with the combined variable of flow resistance and crude reserve rather than that calculated with flow resistance in pore reservoirs. The ratio of the reserve to formation factor, V/(kh), can be used to determine the vertical location of the injector. And the optimal DDEI which is the ratio of V/(kh) in upper reservoir of the wellbore to that in lower reservoir of the wellbore is equal to 1. The vertical locations of producers are related to the vertical distributions of reserve and cavities in different karst units. At last, the principles of constructing spatial well pattern in fractured-vuggy carbonate reservoirs were proposed.\u0000 This work provides an innovative and effective method to establish a spatial well pattern for FVCRs, which will break new ground for efficient development of FVCRs by water flooding.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77173576","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}
M. Y. Alklih, N. M. Aljneibi, K. Khan, Melike Dilsiz
Miscible HC-WAG injection is a globally implemented EOR method and seems robust in so many cases. Some of the largest HC-WAG projects are found in major carbonate oil reservoirs in the Middle-East, with miscibility being the first measure to expect the success of a HC-WAG injection. Yet, several miscible injection projects reported disappointing outcomes and challenging implementation that reduces the economic attractiveness of the miscible processes. To date, there are still some arguments on the interpretation of laboratory and field data and predictive modeling. For a miscible flood, to be an efficient process for a given reservoir, several conditions must be satisfied; given that the incremental oil recovery is largely dependent on reservoir properties and fluid characteristic. Experiences gained from a miscible rich HC-WAG project in Abu Dhabi, implemented since 2006, indicate that an incremental recovery of 10% of the original oil in place can be achieved, compared to water flooding. However, experiences also show that several complexities are being faced, including but not limited to, issues of water injectivity in the mixed wettability nature of the reservoir, achieving miscibility conditions full field, maintaining VRR and corresponding flow behavior, suitability of monitoring strategy, UTC optimization efforts by gas curtailment and most importantly challenges of modeling the miscibility behavior across the reservoir. A number of mitigation plans and actions are put in place to chase the positive impacts of enhanced oil recovery by HC-WAG injection. If gas injection is controlled for gravity and dissolution along with proper understanding on the limitations of WAG, then miscible flood will lead to excellent results in the field. The low frequency of certain reservoir monitoring activities, hence less available data for assessment and modeling, can severely bound the benefits of HC-WAG and make it more difficult to justify the injection of gas, particularly in those days when domestic gas market arises. This work aims to discuss the lessons learned from the ongoing development of HC-WAG and attempts to comprehend miscible flood assessment methods.
{"title":"Does Miscibility Alone Predict the Success of WAG Projects? Key Issues in Miscible HC-WAG Injection","authors":"M. Y. Alklih, N. M. Aljneibi, K. Khan, Melike Dilsiz","doi":"10.2118/206116-ms","DOIUrl":"https://doi.org/10.2118/206116-ms","url":null,"abstract":"\u0000 Miscible HC-WAG injection is a globally implemented EOR method and seems robust in so many cases. Some of the largest HC-WAG projects are found in major carbonate oil reservoirs in the Middle-East, with miscibility being the first measure to expect the success of a HC-WAG injection. Yet, several miscible injection projects reported disappointing outcomes and challenging implementation that reduces the economic attractiveness of the miscible processes. To date, there are still some arguments on the interpretation of laboratory and field data and predictive modeling.\u0000 For a miscible flood, to be an efficient process for a given reservoir, several conditions must be satisfied; given that the incremental oil recovery is largely dependent on reservoir properties and fluid characteristic. Experiences gained from a miscible rich HC-WAG project in Abu Dhabi, implemented since 2006, indicate that an incremental recovery of 10% of the original oil in place can be achieved, compared to water flooding. However, experiences also show that several complexities are being faced, including but not limited to, issues of water injectivity in the mixed wettability nature of the reservoir, achieving miscibility conditions full field, maintaining VRR and corresponding flow behavior, suitability of monitoring strategy, UTC optimization efforts by gas curtailment and most importantly challenges of modeling the miscibility behavior across the reservoir.\u0000 A number of mitigation plans and actions are put in place to chase the positive impacts of enhanced oil recovery by HC-WAG injection. If gas injection is controlled for gravity and dissolution along with proper understanding on the limitations of WAG, then miscible flood will lead to excellent results in the field. The low frequency of certain reservoir monitoring activities, hence less available data for assessment and modeling, can severely bound the benefits of HC-WAG and make it more difficult to justify the injection of gas, particularly in those days when domestic gas market arises.\u0000 This work aims to discuss the lessons learned from the ongoing development of HC-WAG and attempts to comprehend miscible flood assessment methods.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80969831","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}
Mohamed Alhammadi, S. Masalmeh, B. Al-Shehhi, M. Sohrabi, A. Farzaneh
This study aims to compare the roles of rock and crude oil in improving recovery by low salinity water injection (LSWI) and, particularly, to explore the significance of micro-dispersion formation in LSWI performance. Core samples and crude oil were taken from two carbonate reservoirs (A and B) in Abu Dhabi. The oil samples were selected such that one of them would form micro-dispersion when in contact with low salinity brine while the other would not. A series of coreflood experiments was performed in secondary and tertiary modes under reservoir conditions. First, a core sample from reservoir A was initialized and aged with crude oil from reservoir A and a core sample from reservoir B was initialized and aged with crude oil from reservoir B. The cores were then swapped, and the performance of low salinity injection was tested using rock from reservoir A and crude from reservoir B, and vice versa. For the first set of experiments, we found that the crude oil sample capable of forming micro-dispersion (we call this oil "positive", from reservoir A) resulted in extra oil recovery in both secondary and tertiary LSWI modes, compared to high salinity flooding. Moreover, in the secondary LSWI mode we observed significant acceleration of oil production, with higher ultimate oil recovery (12.5%) compared to tertiary mode (6.5%). To ensure repeatability, the tertiary experiment was repeated, and the results were reproduced. The core flood test performed using "negative" crude oil that did not form micro-dispersion (from reservoir B) showed no improvement in oil recovery compared to high salinity waterflooding. In the "cross-over" experiments (when cores were swapped), the positive crude oil showed a similar improvement in oil recovery and the negative crude oil showed no improvement in oil recovery even though each of them was used with a core sample from the other reservoir. These results suggest that it is the properties of crude oil rather than the rock that play the greater role in oil recovery. These results suggest that the ability of crude oil to form micro-dispersion when contacted with low salinity water is an important factor in determining whether low salinity injection will lead to extra oil recovery during both secondary and tertiary LSWI. The pH and ionic composition of the core effluent were measured for all experiments and were unaffected by the combination of core and oil used in each experiment. This work provides new experimental evidence regarding real reservoir rock and oil under reservoir conditions. The novel crossover approach in which crude oil from one reservoir was tested in another reservoir rock was helpful for understanding the relative roles of crude oil and rock in the low salinity water mechanism. Our approach suggests a simple, rapid and low-cost methodology for screening target reservoirs for LSWI.
{"title":"Experimental Investigation of the Impact of Crude Oil and Rock on Improved Recovery by Low Salinity Water Injection","authors":"Mohamed Alhammadi, S. Masalmeh, B. Al-Shehhi, M. Sohrabi, A. Farzaneh","doi":"10.2118/206118-ms","DOIUrl":"https://doi.org/10.2118/206118-ms","url":null,"abstract":"\u0000 This study aims to compare the roles of rock and crude oil in improving recovery by low salinity water injection (LSWI) and, particularly, to explore the significance of micro-dispersion formation in LSWI performance. Core samples and crude oil were taken from two carbonate reservoirs (A and B) in Abu Dhabi. The oil samples were selected such that one of them would form micro-dispersion when in contact with low salinity brine while the other would not.\u0000 A series of coreflood experiments was performed in secondary and tertiary modes under reservoir conditions. First, a core sample from reservoir A was initialized and aged with crude oil from reservoir A and a core sample from reservoir B was initialized and aged with crude oil from reservoir B. The cores were then swapped, and the performance of low salinity injection was tested using rock from reservoir A and crude from reservoir B, and vice versa.\u0000 For the first set of experiments, we found that the crude oil sample capable of forming micro-dispersion (we call this oil \"positive\", from reservoir A) resulted in extra oil recovery in both secondary and tertiary LSWI modes, compared to high salinity flooding. Moreover, in the secondary LSWI mode we observed significant acceleration of oil production, with higher ultimate oil recovery (12.5%) compared to tertiary mode (6.5%). To ensure repeatability, the tertiary experiment was repeated, and the results were reproduced. The core flood test performed using \"negative\" crude oil that did not form micro-dispersion (from reservoir B) showed no improvement in oil recovery compared to high salinity waterflooding. In the \"cross-over\" experiments (when cores were swapped), the positive crude oil showed a similar improvement in oil recovery and the negative crude oil showed no improvement in oil recovery even though each of them was used with a core sample from the other reservoir. These results suggest that it is the properties of crude oil rather than the rock that play the greater role in oil recovery. These results suggest that the ability of crude oil to form micro-dispersion when contacted with low salinity water is an important factor in determining whether low salinity injection will lead to extra oil recovery during both secondary and tertiary LSWI. The pH and ionic composition of the core effluent were measured for all experiments and were unaffected by the combination of core and oil used in each experiment.\u0000 This work provides new experimental evidence regarding real reservoir rock and oil under reservoir conditions. The novel crossover approach in which crude oil from one reservoir was tested in another reservoir rock was helpful for understanding the relative roles of crude oil and rock in the low salinity water mechanism. Our approach suggests a simple, rapid and low-cost methodology for screening target reservoirs for LSWI.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"44 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87829112","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 a fast drilling environment, suchas shale drilling, refining advanced technologies for preventing downhole toolfailures is paramount. Challenges are still very much associated with complex bottom-hole assemblies and the vibration of the drill string when used with a downhole mud motor. The mud positive displacement motor with various lobe configurations and designs becomes an additional excitation source of vibration. Further, it affects the transient behavior of the performance mud motor. Unbalanced force exists because the center ofmass of the motor rotor does not coincide with the axis of rotation.Further, the vector of full acceleration of the center of the rotor can be decomposed into two perpendicular projections—tangent and normal—which aretaken into account and integrated intothe full drill string forced frequency modelas force and displacement at the motorlocation. The paper includes two models, first one to predict the critical speeds and the second one to see the transient behavior of the downhole parameters when the mud motor is used.The model also considers the effect of the stringspeed. The unbalanced force is more pronounced at the lower pair or lobe configuration as compared to the higher pairlobe configuration because of the larger eccentricity. The unbalance is modeled in terms of an equivalent mass of therotor with the eccentricity of the rotor. Also, the analysis provides an estimation of relative bending stresses, shear forces, lateral displacements and transient bit rpm, bit torque, and weightone bit for the assembly used. Based onthe study, severe vibrations causing potentially damaging operating conditionswhen transient downhole forcing parametersare used for the vibration model.It has been found that when a mud motor isused using static forcing parameters may not provide the conservative estimation of the critical speeds as opposed totransient parameters. This is because coupled oscillations fundamentally can create new dynamic phenomena, which cannot be predicted from the characteristics of isolated elements of the drilling system.
{"title":"Mud Motor PDM Dynamics: An Analytical Model","authors":"Robello Samuel, F. Baldenko, D. Baldenko","doi":"10.2118/206064-ms","DOIUrl":"https://doi.org/10.2118/206064-ms","url":null,"abstract":"\u0000 In a fast drilling environment, suchas shale drilling, refining advanced technologies for preventing downhole toolfailures is paramount. Challenges are still very much associated with complex bottom-hole assemblies and the vibration of the drill string when used with a downhole mud motor. The mud positive displacement motor with various lobe configurations and designs becomes an additional excitation source of vibration. Further, it affects the transient behavior of the performance mud motor. Unbalanced force exists because the center ofmass of the motor rotor does not coincide with the axis of rotation.Further, the vector of full acceleration of the center of the rotor can be decomposed into two perpendicular projections—tangent and normal—which aretaken into account and integrated intothe full drill string forced frequency modelas force and displacement at the motorlocation. The paper includes two models, first one to predict the critical speeds and the second one to see the transient behavior of the downhole parameters when the mud motor is used.The model also considers the effect of the stringspeed. The unbalanced force is more pronounced at the lower pair or lobe configuration as compared to the higher pairlobe configuration because of the larger eccentricity. The unbalance is modeled in terms of an equivalent mass of therotor with the eccentricity of the rotor. Also, the analysis provides an estimation of relative bending stresses, shear forces, lateral displacements and transient bit rpm, bit torque, and weightone bit for the assembly used. Based onthe study, severe vibrations causing potentially damaging operating conditionswhen transient downhole forcing parametersare used for the vibration model.It has been found that when a mud motor isused using static forcing parameters may not provide the conservative estimation of the critical speeds as opposed totransient parameters. This is because coupled oscillations fundamentally can create new dynamic phenomena, which cannot be predicted from the characteristics of isolated elements of the drilling system.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"56 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85223902","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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