Rashod Smith, Amanda Miller, A. Mahmoudkhani, W. Samaniego, E. Granda
A major shale producer in North America with established oil and gas production was facing challenges with severe paraffin deposition in downhole tubing and flowlines. Since chemical recommendations based on traditional screenings failed to deliver adequate inhibition, the operator turned to a costly remediation program to maintain production. We aimed to revisit the case, do a root cause analysis, and look for a potential chemical solution for cost savings. The field deposit obtained from the producer proved to be quite complex and introduced limitations with our current internal HTGC method for carbon chain analysis. Upon analysis, components present in the sample were found to exceed the solidity limits of the carrier system, carbon disulfide (CS2) and would precipitate out of the solution and form a two-phased system. These components were believed to be higher molecular weight carbon chains (HMWC) above C70+ at a high enough concentration to exceed the solvents solubility limit. This was the first time encountering such a sample in our experience. A systematic approach was applied to isolate the insoluble HMWC and further outsourced analysis. A MALDI-TOF and High-Resolution Carbon-13 NMR was utilized to confirm the presence of C90+ chains within the deposit at a high enough concentration to have a trimodal paraffin distribution system. To our knowledge, this is the first time a trimodal system has been documented.
{"title":"First Occurrence of a Shale Oil with Trimodal Carbon Chain Distribution and Paraffins Higher than Nonacontane C90H182: A Real Fail Test for Existing Chemistries and Methods","authors":"Rashod Smith, Amanda Miller, A. Mahmoudkhani, W. Samaniego, E. Granda","doi":"10.2118/193621-MS","DOIUrl":"https://doi.org/10.2118/193621-MS","url":null,"abstract":"\u0000 A major shale producer in North America with established oil and gas production was facing challenges with severe paraffin deposition in downhole tubing and flowlines. Since chemical recommendations based on traditional screenings failed to deliver adequate inhibition, the operator turned to a costly remediation program to maintain production. We aimed to revisit the case, do a root cause analysis, and look for a potential chemical solution for cost savings. The field deposit obtained from the producer proved to be quite complex and introduced limitations with our current internal HTGC method for carbon chain analysis. Upon analysis, components present in the sample were found to exceed the solidity limits of the carrier system, carbon disulfide (CS2) and would precipitate out of the solution and form a two-phased system. These components were believed to be higher molecular weight carbon chains (HMWC) above C70+ at a high enough concentration to exceed the solvents solubility limit. This was the first time encountering such a sample in our experience. A systematic approach was applied to isolate the insoluble HMWC and further outsourced analysis. A MALDI-TOF and High-Resolution Carbon-13 NMR was utilized to confirm the presence of C90+ chains within the deposit at a high enough concentration to have a trimodal paraffin distribution system. To our knowledge, this is the first time a trimodal system has been documented.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85563398","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 M. Al Moajil, Bashayer Aldakkan, H. Al-badairy, S. Shen
The success of carbonate acidizing depends on the selection of proper fluid recipes, reservoir formation parameters, job design, and execution. Analysis of flowback spent acid will improve the acidizing process in future treatments, enhance the designed recipes and treatment design. The objective of this paper is to share the flowback analysis methodology following carbonate acidizing treatments with focus on solid analysis. Microstructural analysis with advanced microscopy and spectroscopy analytical techniques such as high-resolution environmental scanning electron microscopy (ESEM), energy dispersive X-ray microanalysis (EDX) and X-ray diffraction (XRD) techniques were utilized. Flowback samples were filtered through 0.45 µm filter paper. ICP was used to analyze the flowback samples. The injected acid recipes dissolved significant amount of calcite. The maximum calcium concentrations in flowback samples were 90,000-120,000 mg/L. Moreover, solid precipitates were found in flowback samples associated with pH values of 4.7-5.5. Gypsum was the dominant compound in the samples analyzed while the other compounds such as Lepidocrocite, Magnetite, Quartz, and Barite were detected in a single sample. The iron-based compounds were detected in the beginning of flowback period. Calcium and silicon rich compounds were identified in later flowback periods. The source of iron was identified to be most likely mill scale. Barite and Quartz were found to be associated with iron-based compounds. Gypsum and sodium chloride were detected with varying dominations between CaSO4 and NaCl compounds with a possible correlation as described by Dourba et al. (2017). Particles agglomerations were mainly associated with calcium, chloride and sulfate-based compounds. The rod-like and hexagonally-shaped particles were mainly found to be Si-based particles. Flower particles and dendrite structures were detected and probably associated with Gypsum precipitation amorphous and hemihydrate intermediates. The varying structures and agglomerations of sulfate compounds detected by the SEM indicated they were formed via different mechanisms and environments.
{"title":"Microstructural and Flowback Analysis Methodology in Matrix Acidized Carbonate Oil Reservoirs","authors":"Abdullah M. Al Moajil, Bashayer Aldakkan, H. Al-badairy, S. Shen","doi":"10.2118/193610-MS","DOIUrl":"https://doi.org/10.2118/193610-MS","url":null,"abstract":"\u0000 The success of carbonate acidizing depends on the selection of proper fluid recipes, reservoir formation parameters, job design, and execution. Analysis of flowback spent acid will improve the acidizing process in future treatments, enhance the designed recipes and treatment design. The objective of this paper is to share the flowback analysis methodology following carbonate acidizing treatments with focus on solid analysis.\u0000 Microstructural analysis with advanced microscopy and spectroscopy analytical techniques such as high-resolution environmental scanning electron microscopy (ESEM), energy dispersive X-ray microanalysis (EDX) and X-ray diffraction (XRD) techniques were utilized. Flowback samples were filtered through 0.45 µm filter paper. ICP was used to analyze the flowback samples.\u0000 The injected acid recipes dissolved significant amount of calcite. The maximum calcium concentrations in flowback samples were 90,000-120,000 mg/L. Moreover, solid precipitates were found in flowback samples associated with pH values of 4.7-5.5. Gypsum was the dominant compound in the samples analyzed while the other compounds such as Lepidocrocite, Magnetite, Quartz, and Barite were detected in a single sample. The iron-based compounds were detected in the beginning of flowback period. Calcium and silicon rich compounds were identified in later flowback periods. The source of iron was identified to be most likely mill scale. Barite and Quartz were found to be associated with iron-based compounds. Gypsum and sodium chloride were detected with varying dominations between CaSO4 and NaCl compounds with a possible correlation as described by Dourba et al. (2017). Particles agglomerations were mainly associated with calcium, chloride and sulfate-based compounds. The rod-like and hexagonally-shaped particles were mainly found to be Si-based particles. Flower particles and dendrite structures were detected and probably associated with Gypsum precipitation amorphous and hemihydrate intermediates. The varying structures and agglomerations of sulfate compounds detected by the SEM indicated they were formed via different mechanisms and environments.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"186 14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76440935","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}
E. Temple, M. Jordan, H. Williams, Sigrid Kjelstrup, M. Kilibarda, Kolbjorn Johansen
The impact of suspended solids and dynamic conditions on sulphate scale control is well-known. Previous work examined the effect of suspended solids, along with static and turbulent conditions, on one scale inhibitor (Vs-Co). This study has focused on the challenges experienced by an operator of a chalk reservoir field, with a significant amount of carbonate solids in the system, and a high sulphate scale risk due to high barium concentration, injection seawater breakthrough, and cool topside process conditions (20°C). The initial laboratory evaluation showed that the minimum inhibitor concentration (MIC) observed increased from 50ppm to 250ppm after 24 hours (>80% efficiency) under these conditions. A further study investigated whether a reduction in MIC could be achieved with different chemistry. Various chemicals were screened in conventional static jar tests and in stirred tests to induce turbulence incorporating mixed solids. The results showed that many of the conventional scale inhibitor chemistries, working by nucleation inhibition and crystal growth retardation, could not cope with the severe scaling conditions and were less efficient than the incumbent. However, a "novel" scale inhibitor formulation was shown to work more effectively and resulted in a significantly lower MIC than the incumbent. Under sulphate scaling conditions (80:20 FW:SW), VS-Co recorded an MIC of 250ppm which was reduced to ≤100ppm with the novel chemical. This resulted in the opportunity for the operator to reduce their chemical dose rate and logistical costs. This novel chemical works by a combination of nucleation inhibition and crystal growth retardation. As a result of this inhibition mechanism, other operators experiencing similar harsh sulphate scaling conditions could achieve a lower treat rate in high suspended solid loaded systems.
{"title":"Development of a Barium Sulphate Scale Inhibitor for Chalk Solid Loaded Conditions","authors":"E. Temple, M. Jordan, H. Williams, Sigrid Kjelstrup, M. Kilibarda, Kolbjorn Johansen","doi":"10.2118/193543-MS","DOIUrl":"https://doi.org/10.2118/193543-MS","url":null,"abstract":"\u0000 The impact of suspended solids and dynamic conditions on sulphate scale control is well-known. Previous work examined the effect of suspended solids, along with static and turbulent conditions, on one scale inhibitor (Vs-Co). This study has focused on the challenges experienced by an operator of a chalk reservoir field, with a significant amount of carbonate solids in the system, and a high sulphate scale risk due to high barium concentration, injection seawater breakthrough, and cool topside process conditions (20°C). The initial laboratory evaluation showed that the minimum inhibitor concentration (MIC) observed increased from 50ppm to 250ppm after 24 hours (>80% efficiency) under these conditions.\u0000 A further study investigated whether a reduction in MIC could be achieved with different chemistry. Various chemicals were screened in conventional static jar tests and in stirred tests to induce turbulence incorporating mixed solids. The results showed that many of the conventional scale inhibitor chemistries, working by nucleation inhibition and crystal growth retardation, could not cope with the severe scaling conditions and were less efficient than the incumbent. However, a \"novel\" scale inhibitor formulation was shown to work more effectively and resulted in a significantly lower MIC than the incumbent.\u0000 Under sulphate scaling conditions (80:20 FW:SW), VS-Co recorded an MIC of 250ppm which was reduced to ≤100ppm with the novel chemical. This resulted in the opportunity for the operator to reduce their chemical dose rate and logistical costs.\u0000 This novel chemical works by a combination of nucleation inhibition and crystal growth retardation. As a result of this inhibition mechanism, other operators experiencing similar harsh sulphate scaling conditions could achieve a lower treat rate in high suspended solid loaded systems.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73870975","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}
Recent times have seen an advancement in the area of carbonate acidizing, moving forward from single-phase to two-phase analyses, in an effort to account for the presence of the oil-phase during stimulation treatments. Yet, a lack of a complete capability to understand this complex subsurface process still exists. Characterizing the effect of CO2 (carbon dioxide), a byproduct of the chemical reaction between carbonates & HCl (hydrochloric acid) has been ignored till date, under the pretext of using high pore pressures to keep CO2 dissolved in surrounding solution. The presence of CO2 in porous media changes the dynamics of fluid flow. A three-phase two-scale simulation model is described toward the purpose of accurately modeling the physics of carbonate acidizing. A validation of the model, is conducted using published literature experiments and conducted laboratory corefloods in the area of carbonate acidizing. The acid efficiency curve for a single phase scenario from literature is matched, with the effects of the evolved CO2 being modeled. Two Indiana limestone core, 6 in. by length and 1.5 in. by diameter, are used for the purpose of a tracer injection study using 5 wt% KCl (potassium chloride) solution, and acid injection study using 15 wt% HCl solution. The experiments were conducted at 71.6°F, and 1,180 psi pore pressures. The Indiana limestone cores are characterized via CT (computed tomography) scans, and a detailed, accurate porosity profile of the core is used as input to the simulation model. The tracer fluid was used to characterize the porous environment and effective dispersion coefficients, and for subsequent calibration of the simulation model. From the conducted single phase acidizing coreflood, the experimental parameters such as pressure drop curves are closely monitored to assess acid breakthrough, and the effluents from the acid coreflood are analyzed for determining the concentrations of CaCl2 (calcium chloride) and HCl with time. CT scans of the core post acidizing describes the wormhole pattern. These parameters are accurately matched using the simulation model, and subsequent sensitivity studies with the presence of oil are performed thereof. The modeling of CO2 as a separate phase for mimicking the acid coreflood played a major role in acquiring a better match with all experimental parameters, with limited dependency on empirical pore-scale parameters. It is shown that the rock-wettability for an oil-water system has a large degree of influence on the acid PVbt (pore volumes of acid required to breakthrough), with oil-wet systems requiring higher volumes. An approximate of 30% recovery of the residual oil in place is predicted, purely based on capability of the evolved CO2 to swell the surrounding oil.
{"title":"Three-Phase Carbonate Acidizing: Quantification and Analysis of Evolved CO2 in the Presence of Oil and Water","authors":"H. Kumar, Sajjaat Muhemmed, H. Nasr-El-Din","doi":"10.2118/193617-MS","DOIUrl":"https://doi.org/10.2118/193617-MS","url":null,"abstract":"\u0000 Recent times have seen an advancement in the area of carbonate acidizing, moving forward from single-phase to two-phase analyses, in an effort to account for the presence of the oil-phase during stimulation treatments. Yet, a lack of a complete capability to understand this complex subsurface process still exists. Characterizing the effect of CO2 (carbon dioxide), a byproduct of the chemical reaction between carbonates & HCl (hydrochloric acid) has been ignored till date, under the pretext of using high pore pressures to keep CO2 dissolved in surrounding solution. The presence of CO2 in porous media changes the dynamics of fluid flow.\u0000 A three-phase two-scale simulation model is described toward the purpose of accurately modeling the physics of carbonate acidizing. A validation of the model, is conducted using published literature experiments and conducted laboratory corefloods in the area of carbonate acidizing. The acid efficiency curve for a single phase scenario from literature is matched, with the effects of the evolved CO2 being modeled. Two Indiana limestone core, 6 in. by length and 1.5 in. by diameter, are used for the purpose of a tracer injection study using 5 wt% KCl (potassium chloride) solution, and acid injection study using 15 wt% HCl solution. The experiments were conducted at 71.6°F, and 1,180 psi pore pressures. The Indiana limestone cores are characterized via CT (computed tomography) scans, and a detailed, accurate porosity profile of the core is used as input to the simulation model. The tracer fluid was used to characterize the porous environment and effective dispersion coefficients, and for subsequent calibration of the simulation model. From the conducted single phase acidizing coreflood, the experimental parameters such as pressure drop curves are closely monitored to assess acid breakthrough, and the effluents from the acid coreflood are analyzed for determining the concentrations of CaCl2 (calcium chloride) and HCl with time. CT scans of the core post acidizing describes the wormhole pattern. These parameters are accurately matched using the simulation model, and subsequent sensitivity studies with the presence of oil are performed thereof.\u0000 The modeling of CO2 as a separate phase for mimicking the acid coreflood played a major role in acquiring a better match with all experimental parameters, with limited dependency on empirical pore-scale parameters. It is shown that the rock-wettability for an oil-water system has a large degree of influence on the acid PVbt (pore volumes of acid required to breakthrough), with oil-wet systems requiring higher volumes. An approximate of 30% recovery of the residual oil in place is predicted, purely based on capability of the evolved CO2 to swell the surrounding oil.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89517657","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}
On the Vega gas condensate and oil field in the Norwegian North Sea, two high temperature, high pressure (HTHP) gas condensate wells on one subsea template in 370 m water depth were acid and scale inhibitor treated in order to improve productivity by acid scale removal and prevent future scaling. Significant amount of work was undertaken on design and qualification of the treatment fluids. In order to reduce operation time and increase efficiency, a novel one-time connection concept was utilized. During the operations, wells were kicked off after energizing with gas bullheaded from the neighbouring well. The treatment fluids were designed to reduce consequences for the host facility due to H2S generated during the operation - this required optimization after understanding of the H2S source as witnessed in prior treatments. The new concept with one-time connection was successfully employed and allowed for three subsequent well treatments in a row, thus saving at least two days vessel operations time. The gas injection from the neighbouring well - the one not treated at the moment - allowed for an efficient start-up of the treated well without need for larger nitrogen injection which would have led to contamination and potentially to flaring due to off-spec gas. The introduction of a batch with pH neutralizer and H2S scavenger batch into the treatment design to be placed into the production pipeline reduced H2S liberation and production to the host facilities, thus limiting the operational stress on the platform. Productivity of well A1 showed an immediately significant increase after the operations, whereas productivity of well A2 required a longer clean-up than originally anticipated.
{"title":"Acid and Scale Inhibitor Squeeze Treatments on Two Subsea Gas Condensate Wells: Design of Subsea Connection, Treatment, Wells Start-Up and Results of the Operation.","authors":"S. Hatscher, Maxim Kiselnikov","doi":"10.2118/193540-MS","DOIUrl":"https://doi.org/10.2118/193540-MS","url":null,"abstract":"\u0000 On the Vega gas condensate and oil field in the Norwegian North Sea, two high temperature, high pressure (HTHP) gas condensate wells on one subsea template in 370 m water depth were acid and scale inhibitor treated in order to improve productivity by acid scale removal and prevent future scaling. Significant amount of work was undertaken on design and qualification of the treatment fluids. In order to reduce operation time and increase efficiency, a novel one-time connection concept was utilized. During the operations, wells were kicked off after energizing with gas bullheaded from the neighbouring well. The treatment fluids were designed to reduce consequences for the host facility due to H2S generated during the operation - this required optimization after understanding of the H2S source as witnessed in prior treatments.\u0000 The new concept with one-time connection was successfully employed and allowed for three subsequent well treatments in a row, thus saving at least two days vessel operations time. The gas injection from the neighbouring well - the one not treated at the moment - allowed for an efficient start-up of the treated well without need for larger nitrogen injection which would have led to contamination and potentially to flaring due to off-spec gas. The introduction of a batch with pH neutralizer and H2S scavenger batch into the treatment design to be placed into the production pipeline reduced H2S liberation and production to the host facilities, thus limiting the operational stress on the platform. Productivity of well A1 showed an immediately significant increase after the operations, whereas productivity of well A2 required a longer clean-up than originally anticipated.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77619660","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}
Improving sweep efficiency from heterogenous reservoirs necessitates the injection of gel treatment and/or polymer solution to lower the degree of heterogeneity and to lower the mobility ratio, respectively. In this study, three gel systems were compared with partially hydrolyzed polyacrylamide (HPAM) solution. The purpose of this study was to show the ability of the viscoelastic properties of the HPAM to enhance the sweep efficiency compared to the selected gel systems. The model was one quarter of five- spot pattern with one injector and one producer. The injection rate was 525 bbl/day. The selected simulator to run the scenarios was UTGEL, while the selected gel systems were colloidal dispersion gel (CDG), polymer/chromium chloride gel, and polymer/chromium malonate gel. Two polymer concentrations (0.1 and 0.15 wt. %) were used and three salinities were considered (5000, 10,000, and 20,000 mg/l). This study showed interesting results regarding the ability of the viscoelastic properties of the HPAM polymer solution to yield recovery factors close or similar to those recovery factors obtained from the selected polymer gel systems. The results also revealed that lowering the salinity of post-treatment water could boost the performance of the polymer solution and make the polymer flooding more effective than gel systems. The results also showed that regardless the duration of injecting the polymer gel system, the HPAM polymer solution still yielded promising results, particularly if low-salinity water was implemented after the treatment.
{"title":"Can the Viscoelasticity of HPAM Polymer Solution Make the Polymer Flooding Compete with Gel Treatment to Improve Sweep Efficiency? A Comparison with Different Polymer Gel Systems","authors":"T. K. Khamees, R. Flori","doi":"10.2118/193592-MS","DOIUrl":"https://doi.org/10.2118/193592-MS","url":null,"abstract":"\u0000 Improving sweep efficiency from heterogenous reservoirs necessitates the injection of gel treatment and/or polymer solution to lower the degree of heterogeneity and to lower the mobility ratio, respectively. In this study, three gel systems were compared with partially hydrolyzed polyacrylamide (HPAM) solution. The purpose of this study was to show the ability of the viscoelastic properties of the HPAM to enhance the sweep efficiency compared to the selected gel systems. The model was one quarter of five- spot pattern with one injector and one producer. The injection rate was 525 bbl/day. The selected simulator to run the scenarios was UTGEL, while the selected gel systems were colloidal dispersion gel (CDG), polymer/chromium chloride gel, and polymer/chromium malonate gel. Two polymer concentrations (0.1 and 0.15 wt. %) were used and three salinities were considered (5000, 10,000, and 20,000 mg/l).\u0000 This study showed interesting results regarding the ability of the viscoelastic properties of the HPAM polymer solution to yield recovery factors close or similar to those recovery factors obtained from the selected polymer gel systems. The results also revealed that lowering the salinity of post-treatment water could boost the performance of the polymer solution and make the polymer flooding more effective than gel systems. The results also showed that regardless the duration of injecting the polymer gel system, the HPAM polymer solution still yielded promising results, particularly if low-salinity water was implemented after the treatment.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78074329","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}
W. Junwen, Jia Wenfeng, Zhang Ru-sheng, Cen Xueqi, W. Haibo, Niu Jun
The high efficient foam unloading agent was developed to solve the problem of unloading of liquid loading gas well with high gas temperature, salinity and high concentration of H2S gas and gas condensate. The Gemini anionic surfactant with special comb structure was synthesized as foaming agent molecule, the modified nanoparticles with certain size and degree of hydrophobicity was adopted as solid foam stabilizer, and the fluorocarbon surfactant was designed and synthesised as gas condensate resistance components. The indoor experiment results show that the foam unloading agent showed good foaming and foam stabilizing ability when the temperature is as high as 150°C, salinity is up to 250000 ppm and H2S concentration up to 2000 ppm. Besides, the foam unloading agent present good liquid carrying ability when the volume fraction of gas condensate is as high as 50%. The field test of this foam unloading agent in Longfengshan north 201-XY well shows that, the average gas production increased from 7256 m3/day to 11329 m3/day, increased by 56%, the average differential pressure between tubing and casing dropped from 2.66 MPa to 2.38 MPa, fell by 10.5%, both liquid yield and gas production are obvious, which prove that the foam unloading agent can meet the demand of drainage gas recovery for high content gas condensate gas field.
{"title":"The Development and Field Test of High Efficient Foam Unloading Agent Based on Gemini Surfactant and Nanomaterials","authors":"W. Junwen, Jia Wenfeng, Zhang Ru-sheng, Cen Xueqi, W. Haibo, Niu Jun","doi":"10.2118/193572-MS","DOIUrl":"https://doi.org/10.2118/193572-MS","url":null,"abstract":"\u0000 The high efficient foam unloading agent was developed to solve the problem of unloading of liquid loading gas well with high gas temperature, salinity and high concentration of H2S gas and gas condensate. The Gemini anionic surfactant with special comb structure was synthesized as foaming agent molecule, the modified nanoparticles with certain size and degree of hydrophobicity was adopted as solid foam stabilizer, and the fluorocarbon surfactant was designed and synthesised as gas condensate resistance components. The indoor experiment results show that the foam unloading agent showed good foaming and foam stabilizing ability when the temperature is as high as 150°C, salinity is up to 250000 ppm and H2S concentration up to 2000 ppm. Besides, the foam unloading agent present good liquid carrying ability when the volume fraction of gas condensate is as high as 50%. The field test of this foam unloading agent in Longfengshan north 201-XY well shows that, the average gas production increased from 7256 m3/day to 11329 m3/day, increased by 56%, the average differential pressure between tubing and casing dropped from 2.66 MPa to 2.38 MPa, fell by 10.5%, both liquid yield and gas production are obvious, which prove that the foam unloading agent can meet the demand of drainage gas recovery for high content gas condensate gas field.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"84 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85837750","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}
Joseph D. Moore, Ella Massie-Schuh, K. Wunch, Kathleen Manna, R. Daly, M. Wilkins, K. Wrighton
Hydraulic fracturing presents an ideal breeding ground for microbial proliferation due to the use of large volumes of nutrient-rich, water-based process fluids. Bacteria and/or archaea, when left uncontrolled topside or in the reservoir, can produce hydrogen sulfide, causing biogenic souring of hydrocarbons. In addition, microbial populations emerging from the downhole environment during production can colonize production equipment, leading to biofouling, microbially influenced corrosion (MIC), produced fluid separation issues, and HS&E risks. Mitigating these risks requires effective selection and application of biocides during drilling, completion, and production. To this end, a microbiological audit of a well completion operation with the objective of determining the effectiveness of a tandem chlorine dioxide (ClO2) and glutaraldehyde/quaternary ammonium (glut/quat) microbial control program was carried out. This paper describes the rationale behind selection of sampling points for a comprehensive microbiological field audit and provides the resulting critical analysis of biocide efficacy in the field using molecular assays (qPCR, ATP) and complementary culturing techniques (microtiter MPN and culture vials—commonly termed "bug bottles"). Due to the comprehensive nature of sampling and data collection, it was possible to make much more applicable and relevant observations and recommendations than it would have been using laboratory studies alone. First, multiple sources of microbial contamination were identified topside, including source waters, working tanks, hydration units, and guar. Additionally, critical analysis of biocide efficacy revealed that ClO2 treatment of source water was short-lived and ineffective for operational control, whereas glut/quat treatment of fracturing fluids at the blender was effective both topside and downhole. Analysis of the microbial load at all topside sampling points revealed that complete removal of ClO2 treatment could be offset by as little as a 10% increase in glut/quat dosage at the blender. This is a highly resolved microbiological audit of a hydraulic fracturing opration which offers new, highly relevant perspectives on the effectiveness of some biocide programs for operational control. This overview of biocide efficacies in the field will facilitate recommendations for both immediate and long-term microbial control in fractured shale reservoirs.
{"title":"Insights into Effective Microbial Control Through a Comprehensive Microbiological Audit of Hydraulic Fracturing Operations","authors":"Joseph D. Moore, Ella Massie-Schuh, K. Wunch, Kathleen Manna, R. Daly, M. Wilkins, K. Wrighton","doi":"10.2118/193606-MS","DOIUrl":"https://doi.org/10.2118/193606-MS","url":null,"abstract":"\u0000 Hydraulic fracturing presents an ideal breeding ground for microbial proliferation due to the use of large volumes of nutrient-rich, water-based process fluids. Bacteria and/or archaea, when left uncontrolled topside or in the reservoir, can produce hydrogen sulfide, causing biogenic souring of hydrocarbons. In addition, microbial populations emerging from the downhole environment during production can colonize production equipment, leading to biofouling, microbially influenced corrosion (MIC), produced fluid separation issues, and HS&E risks. Mitigating these risks requires effective selection and application of biocides during drilling, completion, and production. To this end, a microbiological audit of a well completion operation with the objective of determining the effectiveness of a tandem chlorine dioxide (ClO2) and glutaraldehyde/quaternary ammonium (glut/quat) microbial control program was carried out. This paper describes the rationale behind selection of sampling points for a comprehensive microbiological field audit and provides the resulting critical analysis of biocide efficacy in the field using molecular assays (qPCR, ATP) and complementary culturing techniques (microtiter MPN and culture vials—commonly termed \"bug bottles\").\u0000 Due to the comprehensive nature of sampling and data collection, it was possible to make much more applicable and relevant observations and recommendations than it would have been using laboratory studies alone. First, multiple sources of microbial contamination were identified topside, including source waters, working tanks, hydration units, and guar. Additionally, critical analysis of biocide efficacy revealed that ClO2 treatment of source water was short-lived and ineffective for operational control, whereas glut/quat treatment of fracturing fluids at the blender was effective both topside and downhole. Analysis of the microbial load at all topside sampling points revealed that complete removal of ClO2 treatment could be offset by as little as a 10% increase in glut/quat dosage at the blender. This is a highly resolved microbiological audit of a hydraulic fracturing opration which offers new, highly relevant perspectives on the effectiveness of some biocide programs for operational control. This overview of biocide efficacies in the field will facilitate recommendations for both immediate and long-term microbial control in fractured shale reservoirs.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78515379","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}
H. Cai, Qiang Wang, Wen-li Luo, Wang Hongzhuang, Zhou Xinyu, Jianguo Li, Y. Zheng
In recent decade, various betaine surfactants have been developed and extensively investigated for binary Surfactant-Polymer flooding (SP flooding) due to their high interfacial activity at oil-water interface, excellent thermal tolerant and salt/divalent ion resistant characteristics under harsh reservoir conditions. Herein, a new type of guerbet alkoxy betaine surfactant (GAB) was prepared and evaluated for SP flooding. In order to boost the emulsification capability of betaine surfactant, ethylene oxide (EO) functional group was incorporated into betaine molecule and guerbet alcohol was selected as hydrophobic group. Firstly, glycidyl ether was prepared by reaction of alkoxylated Guerbet alcohol and epoxy chloropropane. Then, glycidyl ether and dimethyl amine generated tertiary amine. In the last step, surfactant GAB was synthesized by quarternization reaction of tertiary amine with 3-chloro-2-hydroxyl propanesulfonic acid sodium salt. In-lab performance evaluations, including interfacial tension, long term stability, contact angle, and phase behavior were conducted for this GAB surfactant. The developed surfactant demonstrated very good compatibility with high temperature, high salinity (HTHS) reservoir conditions. Applicability range of GAB surfactant amounted to 275,000 mg/L and 120 °C. Ultralow interfacial tension with crude oil was obtained using diluted GAB solutions with weight concentration ranging from 0.03% to 0.20%. For formulation composed by 0.5% GAB and 0.5% amidobetaine, Winsor III middle phase microemulsion was formed with dehydrated light oil from a high temperature, high salinity carbonate reservoir. The solubilization ratio mounted to 16 at reservoir temperature of 95 °C and optimal salinity of 50,000 mg/L. Compared with guerbet alkoxy sulfate surfactant and conventional sulfobetaine with similar structure, the developed betaine surfactant GAB showed better thermal stability, higher interfacial activity, and intensified emulsification capability under HTHS conditions.
{"title":"Guerbet Alkoxy Betaine Surfactant for Surfactant-Polymer Flooding in High Temperature, High Salinity Reservoirs","authors":"H. Cai, Qiang Wang, Wen-li Luo, Wang Hongzhuang, Zhou Xinyu, Jianguo Li, Y. Zheng","doi":"10.2118/193534-MS","DOIUrl":"https://doi.org/10.2118/193534-MS","url":null,"abstract":"\u0000 In recent decade, various betaine surfactants have been developed and extensively investigated for binary Surfactant-Polymer flooding (SP flooding) due to their high interfacial activity at oil-water interface, excellent thermal tolerant and salt/divalent ion resistant characteristics under harsh reservoir conditions. Herein, a new type of guerbet alkoxy betaine surfactant (GAB) was prepared and evaluated for SP flooding. In order to boost the emulsification capability of betaine surfactant, ethylene oxide (EO) functional group was incorporated into betaine molecule and guerbet alcohol was selected as hydrophobic group. Firstly, glycidyl ether was prepared by reaction of alkoxylated Guerbet alcohol and epoxy chloropropane. Then, glycidyl ether and dimethyl amine generated tertiary amine. In the last step, surfactant GAB was synthesized by quarternization reaction of tertiary amine with 3-chloro-2-hydroxyl propanesulfonic acid sodium salt. In-lab performance evaluations, including interfacial tension, long term stability, contact angle, and phase behavior were conducted for this GAB surfactant. The developed surfactant demonstrated very good compatibility with high temperature, high salinity (HTHS) reservoir conditions. Applicability range of GAB surfactant amounted to 275,000 mg/L and 120 °C. Ultralow interfacial tension with crude oil was obtained using diluted GAB solutions with weight concentration ranging from 0.03% to 0.20%. For formulation composed by 0.5% GAB and 0.5% amidobetaine, Winsor III middle phase microemulsion was formed with dehydrated light oil from a high temperature, high salinity carbonate reservoir. The solubilization ratio mounted to 16 at reservoir temperature of 95 °C and optimal salinity of 50,000 mg/L. Compared with guerbet alkoxy sulfate surfactant and conventional sulfobetaine with similar structure, the developed betaine surfactant GAB showed better thermal stability, higher interfacial activity, and intensified emulsification capability under HTHS conditions.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82879299","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}
Polymeric scale inhibitors used for scale squeeze treatments to control downhole inorganic scale don't perform well when pumped into the reservoir due to the poor adsorption properties on the rock surface. However polymeric inhibitors are more temperature stable than phosphonates and have higher tolerance to elevated cation compositions in the water. Therefore, a new chemistry composed of metal nanoparticles coupled with a polymeric scale inhibitor was developed to improve the squeeze life. The use of nanoparticles in the oilfield has increased in recent years; this development shows how nanoparticles can be used to increased surface area and retention of scale inhibitor in the reservoir. Metal nanoparticles were selected because of their low environmental toxicity and low formation damage potential during injection and flowback. A fast and efficient synthesis method was developed to create a novel chemistry that couples nanoparticles with polymeric inhibitors to produce a product that it was hoped would have excellent squeeze properties in multiple rock permeabilities and compositions. Core flood experiments were conducted on intact core under onshore Permian conditions of temperature pressure and brine composition as well as conditions simulating an offshore conventional field (results will be reported separately). The experimental results will be presented to show the extended squeeze lifetime of the new product in comparison to a traditional polymeric scale inhibitor retained by adsorption and also will give insight into the mechanisms by which the nanoparticle/scale inhibitor enhances squeeze life, both by increased adsorption as well as prolonging release of scale inhibitor. The product developed is able to significantly increase the squeeze life of polymeric scale inhibitors by up to 10x depending on the minimum inhibitor concentration required. The retention of the inhibitor into the rock is significantly increased, while the release is controlled at above minimum effective concentration for extended periods. The theoretic explanation for this is a metal-inhibitor bond, proprietary to the product that allows for continuous release of inhibitor into the solution, without release from the rock. Traditional squeeze returns have a Freundlich isotherm, this product also follows a similar return curve, however does not suffer from the high concentration release at the beginning of the treatment flowback. These results show that nanoparticles can be used in the oilfield to enhance existing scale inhibitors as well as create new combination products that can improve performance. Use on nanoparticles in the oilfield is an evolving topic that has significant room to grow and expand into multiple areas of oilfield chemistry. This study showcases the application of nanoparticles to enhance performance of polymeric scale inhibitors for squeeze application while maintaining a cost effective product that is environmental responsible.
{"title":"Development of Scale Squeeze Enhancement Technology via Application of Metal Nanoparticles Coupled with Polymer Scale Inhibitors","authors":"P. Guraieb, R. Tomson, I. Littlehales","doi":"10.2118/193541-MS","DOIUrl":"https://doi.org/10.2118/193541-MS","url":null,"abstract":"\u0000 Polymeric scale inhibitors used for scale squeeze treatments to control downhole inorganic scale don't perform well when pumped into the reservoir due to the poor adsorption properties on the rock surface. However polymeric inhibitors are more temperature stable than phosphonates and have higher tolerance to elevated cation compositions in the water. Therefore, a new chemistry composed of metal nanoparticles coupled with a polymeric scale inhibitor was developed to improve the squeeze life.\u0000 The use of nanoparticles in the oilfield has increased in recent years; this development shows how nanoparticles can be used to increased surface area and retention of scale inhibitor in the reservoir. Metal nanoparticles were selected because of their low environmental toxicity and low formation damage potential during injection and flowback.\u0000 A fast and efficient synthesis method was developed to create a novel chemistry that couples nanoparticles with polymeric inhibitors to produce a product that it was hoped would have excellent squeeze properties in multiple rock permeabilities and compositions.\u0000 Core flood experiments were conducted on intact core under onshore Permian conditions of temperature pressure and brine composition as well as conditions simulating an offshore conventional field (results will be reported separately). The experimental results will be presented to show the extended squeeze lifetime of the new product in comparison to a traditional polymeric scale inhibitor retained by adsorption and also will give insight into the mechanisms by which the nanoparticle/scale inhibitor enhances squeeze life, both by increased adsorption as well as prolonging release of scale inhibitor.\u0000 The product developed is able to significantly increase the squeeze life of polymeric scale inhibitors by up to 10x depending on the minimum inhibitor concentration required. The retention of the inhibitor into the rock is significantly increased, while the release is controlled at above minimum effective concentration for extended periods. The theoretic explanation for this is a metal-inhibitor bond, proprietary to the product that allows for continuous release of inhibitor into the solution, without release from the rock. Traditional squeeze returns have a Freundlich isotherm, this product also follows a similar return curve, however does not suffer from the high concentration release at the beginning of the treatment flowback.\u0000 These results show that nanoparticles can be used in the oilfield to enhance existing scale inhibitors as well as create new combination products that can improve performance. Use on nanoparticles in the oilfield is an evolving topic that has significant room to grow and expand into multiple areas of oilfield chemistry. This study showcases the application of nanoparticles to enhance performance of polymeric scale inhibitors for squeeze application while maintaining a cost effective product that is environmental responsible.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79693255","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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