D. L. Cotrell, R. Wood, D. Stanley, S. Chaudhary, M. Chavez, R. Hill, R. Hollier, D. Alonso
Sand, or fines as some may call it, entering currently producing wells is one of the earliest problems faced by the Oil and Gas Industry in hydrocarbon recovery [Rogers, 1954; Carlson et al. 1992; McLeod 1994; JPT Staff 1995; Barrilleaux et al. 1996], and one of the toughest to solve in general [McLeod 1997]. Every year the petroleum industry spends significant capitol in cleaning and disposal costs, repair problems related to sand production, and lost revenues due to lower production rates due to mitigation efforts [Mathis 2003; Palmer et al. 2003]. Thus, sand control is, and should be, an integral part of well planning [Guerrero 2014] in unconsolidated reservoirs [Willson et al 2002; Chang 2006; Jaimes 2012], i.e., reservoirs where the rock has little or no natural inter-grain cementation. Sand production [Veeken et al. 1991; Subbiah et al. 2021] is caused by structural failure of the borehole wall rock due to drilling, degree of consolidation (very low compressive strength), the interaction between the rock and flowing fluids (production creates pressure differential and frictional drag forces that can combine to exceed the formation compressive strength), excessive drawdown causing fines and sand grain movement to the wellbore, or reduction of reservoir pressure. Sand production leads to adverse effects on various components in the wellbore and near wellbore area [Zamberi et al. 2014], such as tubing, casing, flowlines, and pumps, as well as surface equipment [Peden et al. 1984; Lidwin et al. 2013]. In addition, sand production may allow for the creation of downhole cavities [Peden et al. 1985] resulting in loss of structural integrity of the reservoir around the wellbore and ultimately possible collapse of the wellbore. Along with these possible issues, there is an additional economic impact in that sand must be separated out and disposed of at the surface and can be a few liters to several hundred cubic meters [Lidwin et al. 2013]. Decisions around sand production are not purely economic these days because regulatory and environmental restrictions have come to play a significant role in the decisions of how sand production will be handled. In general, what constitutes an acceptable level of sand production depends on operational constraints such as the ability to use erosion resistant materials, fluid separator capacity, sand disposal capability, and artificial lift equipment's capability to remove slurry from the well, but with that said, sand control methods that allow unconsolidated reservoirs to be exploited often reduce production efficiency. Thus, an effective design is always a balance between keeping formation sand in place without unduly restricting current and future productivity [Saucier 1974; Mathis 2003; Palmer et al. 2003; Lastre et al. 2013]. There are two primary methods of sand control these days, namely passive and active, where passive sand control uses perforation orientation and placement to try and mitigate sand produ
{"title":"Lessons Learned During Sand Control Operations in the Gulf of Mexico where Bridging is a Strong Possibility","authors":"D. L. Cotrell, R. Wood, D. Stanley, S. Chaudhary, M. Chavez, R. Hill, R. Hollier, D. Alonso","doi":"10.2118/217880-ms","DOIUrl":"https://doi.org/10.2118/217880-ms","url":null,"abstract":"Sand, or fines as some may call it, entering currently producing wells is one of the earliest problems faced by the Oil and Gas Industry in hydrocarbon recovery [Rogers, 1954; Carlson et al. 1992; McLeod 1994; JPT Staff 1995; Barrilleaux et al. 1996], and one of the toughest to solve in general [McLeod 1997]. Every year the petroleum industry spends significant capitol in cleaning and disposal costs, repair problems related to sand production, and lost revenues due to lower production rates due to mitigation efforts [Mathis 2003; Palmer et al. 2003]. Thus, sand control is, and should be, an integral part of well planning [Guerrero 2014] in unconsolidated reservoirs [Willson et al 2002; Chang 2006; Jaimes 2012], i.e., reservoirs where the rock has little or no natural inter-grain cementation. Sand production [Veeken et al. 1991; Subbiah et al. 2021] is caused by structural failure of the borehole wall rock due to drilling, degree of consolidation (very low compressive strength), the interaction between the rock and flowing fluids (production creates pressure differential and frictional drag forces that can combine to exceed the formation compressive strength), excessive drawdown causing fines and sand grain movement to the wellbore, or reduction of reservoir pressure. Sand production leads to adverse effects on various components in the wellbore and near wellbore area [Zamberi et al. 2014], such as tubing, casing, flowlines, and pumps, as well as surface equipment [Peden et al. 1984; Lidwin et al. 2013]. In addition, sand production may allow for the creation of downhole cavities [Peden et al. 1985] resulting in loss of structural integrity of the reservoir around the wellbore and ultimately possible collapse of the wellbore. Along with these possible issues, there is an additional economic impact in that sand must be separated out and disposed of at the surface and can be a few liters to several hundred cubic meters [Lidwin et al. 2013]. Decisions around sand production are not purely economic these days because regulatory and environmental restrictions have come to play a significant role in the decisions of how sand production will be handled. In general, what constitutes an acceptable level of sand production depends on operational constraints such as the ability to use erosion resistant materials, fluid separator capacity, sand disposal capability, and artificial lift equipment's capability to remove slurry from the well, but with that said, sand control methods that allow unconsolidated reservoirs to be exploited often reduce production efficiency. Thus, an effective design is always a balance between keeping formation sand in place without unduly restricting current and future productivity [Saucier 1974; Mathis 2003; Palmer et al. 2003; Lastre et al. 2013].\u0000 There are two primary methods of sand control these days, namely passive and active, where passive sand control uses perforation orientation and placement to try and mitigate sand produ","PeriodicalId":518997,"journal":{"name":"Day 1 Wed, February 21, 2024","volume":"1157 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527571","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}
Nabe Konate, Saeed Salehi, Mehdi Mokhtari, A. Ghalambor
Shale drilling remains one of the oil industry's most challenging and expensive operations. One of the main concerns in shale drilling is the instability of the wellbore, which can be attributed to the physio-chemical interaction between the drilling fluid systems and the shale formation. This poor interaction is primarily caused by the presence of high-reactive clays, which are known to cause swelling and dispersion issues during drilling. This paper evaluates the linear swelling characteristics of a shale formation dominated by high-reactive clay. A comparative analysis of various drilling fluids’ performance in controlling shale swelling is performed for four (4) clay-dominated wells drilled in the Tuscaloosa Marine Shale (TMS). The mineralogy concentration of samples obtained from different wells drilled in the shale formations is characterized using Fourier-transform infrared spectroscopy (FTIR). Additionally, clay swelling tests are performed in accordance with the American Society of Material Testing (ASTM) Standard Section D5890 to determine the swelling indices of the wells under investigation when exposed to different drilling fluid systems. The study reveals that all the wells tested have a clay concentration of at least 50%. Furthermore, the choice of drilling fluid systems significantly affects the swelling rate. High-performance water-based mud (HPWBM) systems, such as KCl and high salinity formate brine, exhibit improved swelling inhibition and compatibility with high-reactive shale formations. The study revealed that the use of high-performance water-based systems reduces the swelling tendency of clay by as much as 60% compared to conventional water-based systems. The use of inhibitive mud systems also minimized the size of the opening of the tetrahedral sheet of the clay during water invasion as opposed to the conventional water-based mud systems.
{"title":"Experimental Characterization of Linear Swelling of Reactive Clays Dominated Wells: Comparison of Drilling Fluid Systems","authors":"Nabe Konate, Saeed Salehi, Mehdi Mokhtari, A. Ghalambor","doi":"10.2118/217869-ms","DOIUrl":"https://doi.org/10.2118/217869-ms","url":null,"abstract":"\u0000 Shale drilling remains one of the oil industry's most challenging and expensive operations. One of the main concerns in shale drilling is the instability of the wellbore, which can be attributed to the physio-chemical interaction between the drilling fluid systems and the shale formation. This poor interaction is primarily caused by the presence of high-reactive clays, which are known to cause swelling and dispersion issues during drilling. This paper evaluates the linear swelling characteristics of a shale formation dominated by high-reactive clay. A comparative analysis of various drilling fluids’ performance in controlling shale swelling is performed for four (4) clay-dominated wells drilled in the Tuscaloosa Marine Shale (TMS). The mineralogy concentration of samples obtained from different wells drilled in the shale formations is characterized using Fourier-transform infrared spectroscopy (FTIR). Additionally, clay swelling tests are performed in accordance with the American Society of Material Testing (ASTM) Standard Section D5890 to determine the swelling indices of the wells under investigation when exposed to different drilling fluid systems. The study reveals that all the wells tested have a clay concentration of at least 50%. Furthermore, the choice of drilling fluid systems significantly affects the swelling rate. High-performance water-based mud (HPWBM) systems, such as KCl and high salinity formate brine, exhibit improved swelling inhibition and compatibility with high-reactive shale formations. The study revealed that the use of high-performance water-based systems reduces the swelling tendency of clay by as much as 60% compared to conventional water-based systems. The use of inhibitive mud systems also minimized the size of the opening of the tetrahedral sheet of the clay during water invasion as opposed to the conventional water-based mud systems.","PeriodicalId":518997,"journal":{"name":"Day 1 Wed, February 21, 2024","volume":"88 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527708","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A series of long-term coreflood tests has shown the importance of considering the self-breaking rate of biopolymers when designing coreflood tests of low-solids and solids-free brine-based drilling and completion fluids that naturally contaminate the core plug with biopolymers during testing. The tests were conducted with a solids-free potassium formate brine–based reservoir drilling fluid, formulated with xanthan gum and starch, which when exposed to overbalanced pressure, invaded deep into the core plug. The coreflood test simulated filtrate invasion into a water-saturated formation while drilling an injection well. In this scenario the core plug was initially 100% saturated with formation water, and return permeability was measured by injecting formation water through the core in the same direction as the test fluid filtrate invasion. Testing was conducted at two temperatures, 121 and 149°C (250 and 300°F). At both test temperatures there was a very good correlation between the cleanup or permeability recovery rate of the core plug and the biopolymer self-breaking rates, which had been measured in an earlier study. Due to the low cleanup rate at the lowest temperature, this test was terminated as soon as the cleanup rate was fully established, and the testing was continued at the higher temperature until the permeability had reached close to 100% of its initial value. The initial 49-hours cleanup with formation water at 121°C (250°F) resulted in a return permeability to formation water of only 3.8%, explaining why laboratory coreflood tests with low-solids/solids-free brine-based drilling and completion fluids containing biopolymeric additives are generally unable to reproduce or predict the excellent well performance the same fluids deliver in the field after days, weeks, or months of steady clean-up. The results also give us useful insights into what to expect when such fluids are used to drill injection wells. Although the biopolymer self-breaking rate is much higher in the low-salinity injection water, it takes time for biopolymers to break down enough in the protective ionic environment of the formate brine for the filtrate to be diluted and displaced locally by the flow of injection water. The desire to reduce fluid screening and qualification costs unfortunately often means that reservoir drilling and completion fluid selection decisions are based on the results of short-term coreflood tests. This may be the correct procedure for fluids that cause permanent intractable damage from solids plugging. However, for solids-free or low-solids fluids containing self-breaking biopolymers, relying on such short-term tests can mean that the wrong fluid selection decisions are made.
{"title":"Long-term Coreflood Testing with Biopolymers—A Laboratory Investigation Showing How Return Permeability Improves From 0 to 100 Percent by Getting a Critical Parameter Right","authors":"S. Howard, Montogomery, Tx","doi":"10.2118/217909-ms","DOIUrl":"https://doi.org/10.2118/217909-ms","url":null,"abstract":"\u0000 A series of long-term coreflood tests has shown the importance of considering the self-breaking rate of biopolymers when designing coreflood tests of low-solids and solids-free brine-based drilling and completion fluids that naturally contaminate the core plug with biopolymers during testing.\u0000 The tests were conducted with a solids-free potassium formate brine–based reservoir drilling fluid, formulated with xanthan gum and starch, which when exposed to overbalanced pressure, invaded deep into the core plug. The coreflood test simulated filtrate invasion into a water-saturated formation while drilling an injection well. In this scenario the core plug was initially 100% saturated with formation water, and return permeability was measured by injecting formation water through the core in the same direction as the test fluid filtrate invasion.\u0000 Testing was conducted at two temperatures, 121 and 149°C (250 and 300°F). At both test temperatures there was a very good correlation between the cleanup or permeability recovery rate of the core plug and the biopolymer self-breaking rates, which had been measured in an earlier study. Due to the low cleanup rate at the lowest temperature, this test was terminated as soon as the cleanup rate was fully established, and the testing was continued at the higher temperature until the permeability had reached close to 100% of its initial value.\u0000 The initial 49-hours cleanup with formation water at 121°C (250°F) resulted in a return permeability to formation water of only 3.8%, explaining why laboratory coreflood tests with low-solids/solids-free brine-based drilling and completion fluids containing biopolymeric additives are generally unable to reproduce or predict the excellent well performance the same fluids deliver in the field after days, weeks, or months of steady clean-up.\u0000 The results also give us useful insights into what to expect when such fluids are used to drill injection wells. Although the biopolymer self-breaking rate is much higher in the low-salinity injection water, it takes time for biopolymers to break down enough in the protective ionic environment of the formate brine for the filtrate to be diluted and displaced locally by the flow of injection water.\u0000 The desire to reduce fluid screening and qualification costs unfortunately often means that reservoir drilling and completion fluid selection decisions are based on the results of short-term coreflood tests. This may be the correct procedure for fluids that cause permanent intractable damage from solids plugging. However, for solids-free or low-solids fluids containing self-breaking biopolymers, relying on such short-term tests can mean that the wrong fluid selection decisions are made.","PeriodicalId":518997,"journal":{"name":"Day 1 Wed, February 21, 2024","volume":"1165 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527570","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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