S. Sharaf, P. Bangert, Mohamed Fardan, Khalil Alqassab, M. Abubakr, Mahmood Ahmed
A beam or a sucker rod pump is an artificial-lift pumping system using a surface power source to drive a downhole pump assembly. A beam and crank assembly creates reciprocating motion in a sucker-rod string that connects to the downhole pump assembly. The pump contains a plunger and valve assembly to convert the reciprocating motion to vertical fluid movement. A dynamometer is a diagnostic device used on sucker rod pumped wells that measures the load on the top rod and plots this load in relation to the polished rod position as the pumping unit moves through each stroke cycle. The analysis of the dynamometer card data delivers valuable insights on the status of the pump and indicates if future actions are required. In practice, the load versus displacement plot shape can be visually categorized in different classes where each shape has a specific meaning and indicates certain operating conditions. Machine learning algorithms are computing systems that learn to perform tasks by considering examples, generally without being programmed with any task-specific rules. During a period of approximately two (2) months, we collected 5,380,163 different cards from 297 beam pumps deployed in the Bahrain Field using the Supervisory Control and Data Acquisition (SCADA) system with an Open Platform Communication (OPC) interface. 35,292 cards are manually labelled by experts into twelve (12) classes. The dataset is split into 80% training and 20% holdout datasets. A training dataset is split into 5-fold cross validation. Different machine learning algorithms are evaluated predicting pump card class and their performance is compared. The top performing model, Gradient Boosting Machines (GBM) Classifier, achieves 99.98% accuracy in cross validation and 100% accuracy on holdout dataset without any extensive feature engineering. This paper explains the steps taken to improve surveillance of beam pumps using dynamometer card data and machine learning techniques and the lessons learned from executing the first Artificial Intelligence (AI) project within Tatweer Petroleum.
{"title":"Beam Pump Dynamometer Card Classification Using Machine Learning","authors":"S. Sharaf, P. Bangert, Mohamed Fardan, Khalil Alqassab, M. Abubakr, Mahmood Ahmed","doi":"10.2118/194949-MS","DOIUrl":"https://doi.org/10.2118/194949-MS","url":null,"abstract":"A beam or a sucker rod pump is an artificial-lift pumping system using a surface power source to drive a downhole pump assembly. A beam and crank assembly creates reciprocating motion in a sucker-rod string that connects to the downhole pump assembly. The pump contains a plunger and valve assembly to convert the reciprocating motion to vertical fluid movement. A dynamometer is a diagnostic device used on sucker rod pumped wells that measures the load on the top rod and plots this load in relation to the polished rod position as the pumping unit moves through each stroke cycle.\u0000 The analysis of the dynamometer card data delivers valuable insights on the status of the pump and indicates if future actions are required. In practice, the load versus displacement plot shape can be visually categorized in different classes where each shape has a specific meaning and indicates certain operating conditions. Machine learning algorithms are computing systems that learn to perform tasks by considering examples, generally without being programmed with any task-specific rules. During a period of approximately two (2) months, we collected 5,380,163 different cards from 297 beam pumps deployed in the Bahrain Field using the Supervisory Control and Data Acquisition (SCADA) system with an Open Platform Communication (OPC) interface. 35,292 cards are manually labelled by experts into twelve (12) classes. The dataset is split into 80% training and 20% holdout datasets. A training dataset is split into 5-fold cross validation. Different machine learning algorithms are evaluated predicting pump card class and their performance is compared. The top performing model, Gradient Boosting Machines (GBM) Classifier, achieves 99.98% accuracy in cross validation and 100% accuracy on holdout dataset without any extensive feature engineering.\u0000 This paper explains the steps taken to improve surveillance of beam pumps using dynamometer card data and machine learning techniques and the lessons learned from executing the first Artificial Intelligence (AI) project within Tatweer Petroleum.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88276435","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}
Located in south of Eastern Venezuela Basin, Orinoco Oilfield is an onshore heavy oil field in South America. The heavy oil is known for its high content of acids, heavy metals and asphaltenes with a viscosity of 1000-10000mPa·s. According to the reserve report released by PDVSA by the end of 2016, JUNIN Block that is situated in east of Orinoco Oilfield has an OOIP of 178*108bbl. Data of drilled wells and distances between offset horizontal intervals in Orinoco were both studied to improve ultimate production rates. 3-dimension borehole trajectories were designed and the most effective anti-collision measures were taken. After optimziation 8-12 horizontal wells are distributed on one pad. As the horizontal interval extends, the stable production time is prolonged and the accumulative production per well improves. However, the recovery rate stops increasing when the horizontal interval is over 1600m in JUNIN Block. Economically a large space between offset horizontal intervals results in fewer wells and lower costs, but a smaller space contributes to a higher production efficiency per well. If the space exceeds 600m, the accumulative production rate increases much more slightly. A three-dimension well trajectory consists of a vertical interval, an angle building interval, an angle holding interval, an angle building & direction changing interval, a direction turning interval as well as an absolute horizontal interval. Since Petrobras developed the first ever offshore deep reservoir (Lula) by scale in 2006, Brazil has been conducting a progressive campaign targeting hydrocarbons buried under deep water, which contributes to discovery of Lula, Carioca, Jupiter, Buzios, Libra and other giant presalt reservoirs in Santos Basin after Campos Basin, where there are 9 oil fields ranking among the top 20 offshore oil fields in terms of OOIP. By June 2017 over 160×104bbl oil and gas were produced per day in deep water of Santos Basin, taking up 57.1% of the total yield of Campos and Satos. Creep deformation of ultra-thick salt beds, severe loss of limestones, poor drillability of formations and insufficiency of deep water drilling equipment all make drilling and completion challenges more complicated. Mud systems and casing programs are optimized to conquer creep of salt and formation of hydrates due to low downhole temperature. Turbines + impregnated bits are deployed to improve drilling efficiency of siliceous carbonates (Lagoa Feia A Group). Precise control of ECD and efficient LCMs solved engineering challenges caused by narrow density windows (Lagoa Feia B Group and Lagoa Feia C Group).
Orinoco油田位于委内瑞拉东部盆地南部，是南美洲的一个陆上重油油田。重油以酸、重金属和沥青质含量高而闻名，粘度为1000-10000mPa·s。根据PDVSA于2016年底发布的储量报告，位于Orinoco油田东部的JUNIN区块的OOIP为178*108bbl。为了提高最终产量，研究了Orinoco油田的钻井数据和邻距水平段之间的距离。设计了三维井眼轨迹，并采取了最有效的防撞措施。优化后，8-12口水平井分布在一个区块上。随着水平段的延长，稳定生产时间延长，单井累计产量提高。而在JUNIN区块，当水平层距超过1600m时，采收率停止增长。从经济角度来看，邻距水平段之间的较大空间可以减少井数，降低成本，但较小的空间可以提高每口井的生产效率。当空间超过600m时，累计产量增加幅度要小得多。三维井眼轨迹包括垂直井段、造角井段、持角井段、造角变向井段、转向井段和绝对水平井段。自2006年巴西国家石油公司(Petrobras)首次大规模开发海上深层油藏(Lula)以来，巴西一直在开展针对深水油气的活动，在Campos盆地之后，在Santos盆地发现了Lula、Carioca、Jupiter、Buzios、Libra等大型盐下油藏，其中有9个油田在OOIP排名前20位的海上油田。截至2017年6月，Santos盆地深水油气日产量超过160×104bbl，占Campos和Satos总产量的57.1%。超厚盐层的蠕变变形、灰岩的严重损失、地层可钻性差以及深水钻井设备的不足，都使钻井完井挑战更加复杂。泥浆系统和套管方案进行了优化，以克服由于井下温度低而导致的盐蠕变和水合物地层。采用涡轮+浸渍钻头提高碳化硅钻井效率(Lagoa Feia A Group)。精确的ECD控制和高效的lcm解决了窄密度窗口带来的工程挑战(Lagoa Feia B组和Lagoa Feia C组)。
{"title":"Research of Drilling and Completion Technologies for Heavy Oil in Venezuela and Offshore Presalt Hydrocarbons in Brazil","authors":"Jin Fu, Xi Wang, Shunyuan Zhang, Chen Chen","doi":"10.2118/194989-MS","DOIUrl":"https://doi.org/10.2118/194989-MS","url":null,"abstract":"\u0000 Located in south of Eastern Venezuela Basin, Orinoco Oilfield is an onshore heavy oil field in South America. The heavy oil is known for its high content of acids, heavy metals and asphaltenes with a viscosity of 1000-10000mPa·s. According to the reserve report released by PDVSA by the end of 2016, JUNIN Block that is situated in east of Orinoco Oilfield has an OOIP of 178*108bbl.\u0000 Data of drilled wells and distances between offset horizontal intervals in Orinoco were both studied to improve ultimate production rates. 3-dimension borehole trajectories were designed and the most effective anti-collision measures were taken.\u0000 After optimziation 8-12 horizontal wells are distributed on one pad. As the horizontal interval extends, the stable production time is prolonged and the accumulative production per well improves. However, the recovery rate stops increasing when the horizontal interval is over 1600m in JUNIN Block. Economically a large space between offset horizontal intervals results in fewer wells and lower costs, but a smaller space contributes to a higher production efficiency per well. If the space exceeds 600m, the accumulative production rate increases much more slightly. A three-dimension well trajectory consists of a vertical interval, an angle building interval, an angle holding interval, an angle building & direction changing interval, a direction turning interval as well as an absolute horizontal interval.\u0000 Since Petrobras developed the first ever offshore deep reservoir (Lula) by scale in 2006, Brazil has been conducting a progressive campaign targeting hydrocarbons buried under deep water, which contributes to discovery of Lula, Carioca, Jupiter, Buzios, Libra and other giant presalt reservoirs in Santos Basin after Campos Basin, where there are 9 oil fields ranking among the top 20 offshore oil fields in terms of OOIP. By June 2017 over 160×104bbl oil and gas were produced per day in deep water of Santos Basin, taking up 57.1% of the total yield of Campos and Satos.\u0000 Creep deformation of ultra-thick salt beds, severe loss of limestones, poor drillability of formations and insufficiency of deep water drilling equipment all make drilling and completion challenges more complicated. Mud systems and casing programs are optimized to conquer creep of salt and formation of hydrates due to low downhole temperature. Turbines + impregnated bits are deployed to improve drilling efficiency of siliceous carbonates (Lagoa Feia A Group). Precise control of ECD and efficient LCMs solved engineering challenges caused by narrow density windows (Lagoa Feia B Group and Lagoa Feia C Group).","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85789913","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Nielsen, K. G. Poulsen, J. H. Christensen, T. Sølling
Mature fields often times surprise with respect to the production from the various wells across reservoir sections. This is for example the case in a tight chalk field that we have used as a case study for newly developed technique that employs oil finger printing in the analysis of production data. A small subset of wells has been found to produce significantly better than the remainder and we set out to explore whether the root cause is that there is a connection to higher lying reservoir sections through natural or artificial fractures. This was done with advanced analytical chemistry (GC-MS) and a principal component analysis to map differences between key constituents of the oil from wells across the reservoir section. The comparative parameters are mainly derived from biomarker properties but we also developed a way to directly include production numbers. The approach provides means to correlate the molecular properties of the oil with the production and the general composition that determines density and adhesive (to the rock) properties. Thus, the results provide a new angle on the flow properties of the oil and on the charging history of the reservoir. It is clear from the analysis that the subset of wells does not produce better because of a connection to an upper reservoir section that contributes to the production with oil of a different composition because the molecular mix is indeed quite similar in each of the investigated wells. It is not possible to rule out that there is a connection to an upper-lying section with oil from the same source. One aspect that does differs across the field is the ratio of heavy versus light molecules within each group of molecules and the results show that the region that produce better has the lighter components. We take that to indicate that the lighter components come from oil that flows better and thus is produced more easily. The reservoir section with the lighter oil also lies higher on the structure and is therefore must likely to have been charged first so part of the favorable production seems to be a matter of "first in" "first out". A GC-MS approach such as the one proposed here is cost-effective, fast and highly promising for future predictions on where to perform infill campaigns because the results are indicative of charging history and flow properties of the oil.
{"title":"Tracing Production with Analytical Chemistry: Can Oil Finger Printing Provide New Answers","authors":"J. Nielsen, K. G. Poulsen, J. H. Christensen, T. Sølling","doi":"10.2118/194916-MS","DOIUrl":"https://doi.org/10.2118/194916-MS","url":null,"abstract":"\u0000 Mature fields often times surprise with respect to the production from the various wells across reservoir sections. This is for example the case in a tight chalk field that we have used as a case study for newly developed technique that employs oil finger printing in the analysis of production data. A small subset of wells has been found to produce significantly better than the remainder and we set out to explore whether the root cause is that there is a connection to higher lying reservoir sections through natural or artificial fractures. This was done with advanced analytical chemistry (GC-MS) and a principal component analysis to map differences between key constituents of the oil from wells across the reservoir section. The comparative parameters are mainly derived from biomarker properties but we also developed a way to directly include production numbers. The approach provides means to correlate the molecular properties of the oil with the production and the general composition that determines density and adhesive (to the rock) properties. Thus, the results provide a new angle on the flow properties of the oil and on the charging history of the reservoir. It is clear from the analysis that the subset of wells does not produce better because of a connection to an upper reservoir section that contributes to the production with oil of a different composition because the molecular mix is indeed quite similar in each of the investigated wells. It is not possible to rule out that there is a connection to an upper-lying section with oil from the same source. One aspect that does differs across the field is the ratio of heavy versus light molecules within each group of molecules and the results show that the region that produce better has the lighter components. We take that to indicate that the lighter components come from oil that flows better and thus is produced more easily. The reservoir section with the lighter oil also lies higher on the structure and is therefore must likely to have been charged first so part of the favorable production seems to be a matter of \"first in\" \"first out\". A GC-MS approach such as the one proposed here is cost-effective, fast and highly promising for future predictions on where to perform infill campaigns because the results are indicative of charging history and flow properties of the oil.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"68 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86285945","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}
Standard Rock-Eval pyrolysis is commonly used to estimate the thermal maturity of source rocks. However, measuring the maturity of overmature samples with high Tmax values (> 470°C) is very challenging due to the weak development of S2 peaks. Moreover, measuring the vitrinite reflectance of dispersed organic matter high thermal maturity samples is commonly used when the Tmax (°C) of the sample is unreliable. Nevertheless, vitrinite assemblages are very rare/absent in marine samples particularly in marlstones or pre-Carboniferous source rocks. The current study addresses a new thermal maturity parameter that used the carbon monoxide CO released during Rock Eval-6 oxidations. A total of 14 marine source rock samples were analyzed by Rock Eval-6 to assess their generative potential. The samples range in Tmax from 420° to 475°C indicating wide thermal maturity range from immature to overmature. During Rock-Eval analyses, CO released from the kerogens and their peak temperature (Tco) was recorded. A strong positive correlation was observed between the Tmax and the Tco (r=0.94). Note that the CO is released from the organic oxygen compounds that are none/or less liable compared to pure hydrocarbon compounds. Thus, Tco is more reliable than Tmax in assessing high thermal maturity levels. The new method provides a robust and quick interpretation of high thermal maturity source rocks especially for pre-Carboniferous samples that lack a well-devolved S2 peak. Carbon monoxide generation is not affected by carbonate decay to CO2 and is also not affected by contamination used in drilling fluids. Testing of different source rocks is needed to establish this further and to improve the trend observed.
{"title":"Overmature and Vitrinite-Barren Source Rocks: A Novel Thermal Maturity Parameter","authors":"Sebastian Henderson, B. Ghassal","doi":"10.2118/194946-MS","DOIUrl":"https://doi.org/10.2118/194946-MS","url":null,"abstract":"\u0000 Standard Rock-Eval pyrolysis is commonly used to estimate the thermal maturity of source rocks. However, measuring the maturity of overmature samples with high Tmax values (> 470°C) is very challenging due to the weak development of S2 peaks. Moreover, measuring the vitrinite reflectance of dispersed organic matter high thermal maturity samples is commonly used when the Tmax (°C) of the sample is unreliable. Nevertheless, vitrinite assemblages are very rare/absent in marine samples particularly in marlstones or pre-Carboniferous source rocks. The current study addresses a new thermal maturity parameter that used the carbon monoxide CO released during Rock Eval-6 oxidations.\u0000 A total of 14 marine source rock samples were analyzed by Rock Eval-6 to assess their generative potential. The samples range in Tmax from 420° to 475°C indicating wide thermal maturity range from immature to overmature. During Rock-Eval analyses, CO released from the kerogens and their peak temperature (Tco) was recorded. A strong positive correlation was observed between the Tmax and the Tco (r=0.94). Note that the CO is released from the organic oxygen compounds that are none/or less liable compared to pure hydrocarbon compounds. Thus, Tco is more reliable than Tmax in assessing high thermal maturity levels.\u0000 The new method provides a robust and quick interpretation of high thermal maturity source rocks especially for pre-Carboniferous samples that lack a well-devolved S2 peak. Carbon monoxide generation is not affected by carbonate decay to CO2 and is also not affected by contamination used in drilling fluids. Testing of different source rocks is needed to establish this further and to improve the trend observed.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87693457","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}
Amjed Hassan, Abdulaziz Al-Majed, M. Mahmoud, S. Elkatatny, A. Abdulraheem
Oil is considered one of the main drivers that affects the world economy and a key factor in its continuous development. Several operations are used to ensure continues oil production, these operations include; exploration, drilling, production, and reservoir management. Numerous uncertainties and complexities are involved in those operations, which reduce the production performance and increase the operational cost. Several attempts were reported to predict the performance of oil production systems using different approaches, including analytical and numerical methods. However, severe estimation errors and significant deviations were observed between the predicted results and actual field data. This could be due to the different assumptions used to simplify the problems. Therefore, searching for quick and rigorous models to evaluate the oil-production system and anticipate production problems is highly needed. This paper presents a new application of artificial intelligent (AI) techniques to determine the efficiency of several operations including; drilling, production and reservoir performance. For each operation, the most common conditions were applied to develop and evaluate the model reliability. The developed models investigate the significance of different well and reservoir configurations on the system performance. Parameters such as, reservoir permeability, drainage size, wellbore completions, hydrocarbon production rate and choke performance were studied. The primary oil production and enhanced oil recovery (EOR) operations were considered as well as the stimulation processes. Actual data from several oil-fields were used to develop and validate the intelligent models. The novelty of this paper is that the proposed models are reliable and outperform the current methods. This work introduces an effective approach for estimating the performance of oil production system and refine the current numerical or analytical models to improve the reservoir managements.
{"title":"Improved Predictions in Oil Operations Using Artificial Intelligent Techniques","authors":"Amjed Hassan, Abdulaziz Al-Majed, M. Mahmoud, S. Elkatatny, A. Abdulraheem","doi":"10.2118/194994-MS","DOIUrl":"https://doi.org/10.2118/194994-MS","url":null,"abstract":"\u0000 Oil is considered one of the main drivers that affects the world economy and a key factor in its continuous development. Several operations are used to ensure continues oil production, these operations include; exploration, drilling, production, and reservoir management. Numerous uncertainties and complexities are involved in those operations, which reduce the production performance and increase the operational cost.\u0000 Several attempts were reported to predict the performance of oil production systems using different approaches, including analytical and numerical methods. However, severe estimation errors and significant deviations were observed between the predicted results and actual field data. This could be due to the different assumptions used to simplify the problems. Therefore, searching for quick and rigorous models to evaluate the oil-production system and anticipate production problems is highly needed.\u0000 This paper presents a new application of artificial intelligent (AI) techniques to determine the efficiency of several operations including; drilling, production and reservoir performance. For each operation, the most common conditions were applied to develop and evaluate the model reliability. The developed models investigate the significance of different well and reservoir configurations on the system performance. Parameters such as, reservoir permeability, drainage size, wellbore completions, hydrocarbon production rate and choke performance were studied. The primary oil production and enhanced oil recovery (EOR) operations were considered as well as the stimulation processes. Actual data from several oil-fields were used to develop and validate the intelligent models.\u0000 The novelty of this paper is that the proposed models are reliable and outperform the current methods. This work introduces an effective approach for estimating the performance of oil production system and refine the current numerical or analytical models to improve the reservoir managements.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"112 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87705144","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 paper discusses the feasibility study approach of polymer flooding enhanced oil recovery. This work is focused on understanding and quantifying key aspects of polymer flooding and design parameter optimization case. A synthetic reservoir simulation model was employed for the study. The first stage is to identify and understand key factors that have most significant impact to polymer flooding response. There are eight parameters that are considered in the analysis, such as polymer concentration, polymer thermal degradation, polymer injection duration, and polymer-rock properties (adsorption, residual resistance factor, etc.). The impact of each parameter to oil recovery response was sensitized with its low, mid, and high values. The difference of high to low oil recovery output for all parameters was ranked to determine their significance levels. The top three parameters obtained from the sensitivity analysis are polymer injection duration, thermal degradation, and polymer concentration. Sensitivity cases of polymer injectivity and thermal degradation effects were covered in this work. The second stage is to determine optimum design parameters of polymer flooding. The most significant parameters from the sensitivity analysis results were considered for further optimization. Three parameters that were selected for design optimization include polymer injection duration, polymer concentration, and well spacing. An optimization workflow with simplex algorithm is linked with a reservoir simulator to generate optimization cases by varying values of optimized parameters. The optimization iteration stops when the maximum value of the objective function, which is the net revenue, is reached. The optimization cycle was done for rock permeability of 500 md and 1000 md. For a low rock permeability reservoir, the well spacing should be short and a lower polymer concentration is sufficient to provide a good response, in addition to avoiding potential injectivity problem. There should be minimum injectivity problem for reservoir with permeability above 1000 md. It is very important to apply polymer thermal degradation in the simulation model to avoid an optimistic performance prediction. The sensitivity analysis results provide a good understanding on the significance impact of parameters controlling polymer injection response and potential challenges. The optimization approach used in the study aids in investigating many optimization scenario within a short period of time.
{"title":"Polymer Flooding Simulation Modeling Feasibility Study: Understanding Key Aspects and Design Optimization","authors":"W. Hidayat, Nasser ALMolhem","doi":"10.2118/194774-MS","DOIUrl":"https://doi.org/10.2118/194774-MS","url":null,"abstract":"\u0000 The paper discusses the feasibility study approach of polymer flooding enhanced oil recovery. This work is focused on understanding and quantifying key aspects of polymer flooding and design parameter optimization case. A synthetic reservoir simulation model was employed for the study.\u0000 The first stage is to identify and understand key factors that have most significant impact to polymer flooding response. There are eight parameters that are considered in the analysis, such as polymer concentration, polymer thermal degradation, polymer injection duration, and polymer-rock properties (adsorption, residual resistance factor, etc.). The impact of each parameter to oil recovery response was sensitized with its low, mid, and high values. The difference of high to low oil recovery output for all parameters was ranked to determine their significance levels. The top three parameters obtained from the sensitivity analysis are polymer injection duration, thermal degradation, and polymer concentration. Sensitivity cases of polymer injectivity and thermal degradation effects were covered in this work.\u0000 The second stage is to determine optimum design parameters of polymer flooding. The most significant parameters from the sensitivity analysis results were considered for further optimization. Three parameters that were selected for design optimization include polymer injection duration, polymer concentration, and well spacing. An optimization workflow with simplex algorithm is linked with a reservoir simulator to generate optimization cases by varying values of optimized parameters. The optimization iteration stops when the maximum value of the objective function, which is the net revenue, is reached. The optimization cycle was done for rock permeability of 500 md and 1000 md.\u0000 For a low rock permeability reservoir, the well spacing should be short and a lower polymer concentration is sufficient to provide a good response, in addition to avoiding potential injectivity problem. There should be minimum injectivity problem for reservoir with permeability above 1000 md. It is very important to apply polymer thermal degradation in the simulation model to avoid an optimistic performance prediction. The sensitivity analysis results provide a good understanding on the significance impact of parameters controlling polymer injection response and potential challenges. The optimization approach used in the study aids in investigating many optimization scenario within a short period of time.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"93 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75852065","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}
Wai Li, Jishan Liu, Jie Zeng, Jianwei Tian, Lin Li, Min Zhang, Jia Jia, Yufei Li, Hui Peng, Xionghu Zhao, Ji-wei Jiang
Nanomaterials have drawn considerable attention of the oil and gas industry due to their peculiar properties and interesting behaviors. Many experiments, trials and practices were conducted by petroleum scientists and engineers in the last two decades to use various novel nanomaterials to improve exploration and production. Based on the published literature, this article comprehensively reviews the strategies and experience of nanomaterial application in frac fluids, the current problems, and relevant challenges. Based on elaborated design, the nanomaterials such as nano-sized metal, metal oxide, silica, carbonate, carbon, polymer, fiber, organic-inorganic hybrid and other composites can be incorporated in frac fluids to greatly enhance or precisely tune the properties and performances. Consequently, nanomaterial-assisted frac fluids perform well in different aspects including density, rheology, stability, heat conductivity, specific heat capacity, fluid loss, breaking, clean up, proppant suspendability and frictional drag. To optimize the performance and cost-effectiveness of nano-frac fluids, advanced principles and theories in physical chemistry, heat and mass transfer, mechanics and rheology along with industrial design philosophy have been considered and applied. According to the investigation of the literature, nanomaterials have successfully fulfilled the following functions in frac fluids: (1) Improving the rheological behavior by intermolecular interactions (e.g., pseudo-crosslinking in frac fluids, or changing the aggregation pattern of surface-active molecules in surfactant based fluids); (2) Increasing the stability of fluids by enhancing the interfacial strength and toughness, especially in foams and emulsions; (3) Forming a low-permeability pseudo-filter cake to lower the fluid loss; (4) Increasing the viscosifying effect of polymers, which dramatically decreases the required loading of polymer in the fluid; (5) Boosting the thermal stability of frac fluids; (6) Improving the regained fracture conductivity; (7) Reducing the frictional drag of frac fluids; (8) Helping self-suspended proppants achieve better performance and (9) Reducing the required displacing pressure for the residual frac fluid by decreasing interfacial tension to help clean up. These achievements, along with the related design ideas, are reviewed. This paper also discusses the major difficulties and challenges for nano-frac fluids including compatibility, cost and HSE issues. Comprehensive laboratory work should be performed before field application to ensure the reliability of nano-assisted fluid formulations. Large-scale industrial production and a steady supply of nanomaterials will promote the application of nano-frac fluids. Exposure risk, eco-toxicity and biodegradability of nanomateials should be paid more attention. Incorporating the attractive, cutting-edged achievements in chemical and material sciences, nano-frac fluid is predicted to be fully accepted
{"title":"A Critical Review of the Application of Nanomaterials in Frac Fluids: The State of the Art and Challenges","authors":"Wai Li, Jishan Liu, Jie Zeng, Jianwei Tian, Lin Li, Min Zhang, Jia Jia, Yufei Li, Hui Peng, Xionghu Zhao, Ji-wei Jiang","doi":"10.2118/195029-MS","DOIUrl":"https://doi.org/10.2118/195029-MS","url":null,"abstract":"\u0000 Nanomaterials have drawn considerable attention of the oil and gas industry due to their peculiar properties and interesting behaviors. Many experiments, trials and practices were conducted by petroleum scientists and engineers in the last two decades to use various novel nanomaterials to improve exploration and production. Based on the published literature, this article comprehensively reviews the strategies and experience of nanomaterial application in frac fluids, the current problems, and relevant challenges. Based on elaborated design, the nanomaterials such as nano-sized metal, metal oxide, silica, carbonate, carbon, polymer, fiber, organic-inorganic hybrid and other composites can be incorporated in frac fluids to greatly enhance or precisely tune the properties and performances. Consequently, nanomaterial-assisted frac fluids perform well in different aspects including density, rheology, stability, heat conductivity, specific heat capacity, fluid loss, breaking, clean up, proppant suspendability and frictional drag. To optimize the performance and cost-effectiveness of nano-frac fluids, advanced principles and theories in physical chemistry, heat and mass transfer, mechanics and rheology along with industrial design philosophy have been considered and applied. According to the investigation of the literature, nanomaterials have successfully fulfilled the following functions in frac fluids: (1) Improving the rheological behavior by intermolecular interactions (e.g., pseudo-crosslinking in frac fluids, or changing the aggregation pattern of surface-active molecules in surfactant based fluids); (2) Increasing the stability of fluids by enhancing the interfacial strength and toughness, especially in foams and emulsions; (3) Forming a low-permeability pseudo-filter cake to lower the fluid loss; (4) Increasing the viscosifying effect of polymers, which dramatically decreases the required loading of polymer in the fluid; (5) Boosting the thermal stability of frac fluids; (6) Improving the regained fracture conductivity; (7) Reducing the frictional drag of frac fluids; (8) Helping self-suspended proppants achieve better performance and (9) Reducing the required displacing pressure for the residual frac fluid by decreasing interfacial tension to help clean up. These achievements, along with the related design ideas, are reviewed. This paper also discusses the major difficulties and challenges for nano-frac fluids including compatibility, cost and HSE issues. Comprehensive laboratory work should be performed before field application to ensure the reliability of nano-assisted fluid formulations. Large-scale industrial production and a steady supply of nanomaterials will promote the application of nano-frac fluids. Exposure risk, eco-toxicity and biodegradability of nanomateials should be paid more attention. Incorporating the attractive, cutting-edged achievements in chemical and material sciences, nano-frac fluid is predicted to be fully accepted","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81369346","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}
Karem Al-Garadi, A. Aldughaither, Mustafa Ba alawi, H. Al-Hashim, Najmudeen Sibaweihi, M. Said
Condensate banking has been identified to cause significant drop in gas relative permeability and consequently reduction of the productivity of gas condensate wells. To overcome this problem, hydraulic fracturing has been used as a mean to minimize or eliminate this phenomenon. Furthermore multistage hydraulic fracturing techniques have been used to enhance the productivity of horizontal gas condensate wells especially in low permeability formation. Even though multistage hydraulic fracturing has provided an effective solution for condensate blockage to some extent as it promotes linear flow modes which will minimize the pressure drops and consequently improves the inflow performance considerably. However, this technique is very costly, and has to be optimized to get the best long-term performance of the multistage fractured horizontal gas condensate wells. In this paper, multiple sensitivity analyses were conducted in order to come up with an optimum multistage hydraulic fracturing scenario. In these analyses, our manipulations were focused mainly on the operational parameters such as fractures half length, fractures conductivity using compositional commercial simulator. CMG-GEM simulator was used to investigate the different cases proposed for applying multistage hydraulic fracturing of horizontal gas condensate wells. The investigation began with a base case scenario where the fractures half-length were fixed for all stages with equal spacing between them. Then, six more fractures half-length patterns were created by introducing new approach where the well performance was studied if they are in increasing trend away from the wellbore (coning-up), or in a decreasing trend (coning-down). Well performance is furtherly addressed when the fractures half-length arrangements formed parabolic shapes including both occasions of concaving upward and downward. Finally, the last two patterns illustrated the effect of having the fractures half-length arrangements both skewed to the left and right on well productivity. The investigation of the effect of changing the multistage hydraulic fractures half-length distribution patterns on the performance of a gas condensate well was conducted and resulted in parabolic up distribution pattern to be the optimum pattern amongst the other tested ones. It results in the highest cumulative both gas and condensate production. It also maintains the gas flow rate and bottom hole pressure more efficiently. The parabolic up distribution pattern confirms that the majority of gas production was fed by the fractures at the heel and at the toe of the horizontal drainhole which is in agreement with the flux distribution along the horizontal well.
{"title":"A Novel Approach for Optimizing Multistage Hydraulic Fracturing of Gas Condensate Horizontal Wells","authors":"Karem Al-Garadi, A. Aldughaither, Mustafa Ba alawi, H. Al-Hashim, Najmudeen Sibaweihi, M. Said","doi":"10.2118/194971-MS","DOIUrl":"https://doi.org/10.2118/194971-MS","url":null,"abstract":"Condensate banking has been identified to cause significant drop in gas relative permeability and consequently reduction of the productivity of gas condensate wells. To overcome this problem, hydraulic fracturing has been used as a mean to minimize or eliminate this phenomenon. Furthermore multistage hydraulic fracturing techniques have been used to enhance the productivity of horizontal gas condensate wells especially in low permeability formation. Even though multistage hydraulic fracturing has provided an effective solution for condensate blockage to some extent as it promotes linear flow modes which will minimize the pressure drops and consequently improves the inflow performance considerably. However, this technique is very costly, and has to be optimized to get the best long-term performance of the multistage fractured horizontal gas condensate wells.\u0000 In this paper, multiple sensitivity analyses were conducted in order to come up with an optimum multistage hydraulic fracturing scenario. In these analyses, our manipulations were focused mainly on the operational parameters such as fractures half length, fractures conductivity using compositional commercial simulator. CMG-GEM simulator was used to investigate the different cases proposed for applying multistage hydraulic fracturing of horizontal gas condensate wells. The investigation began with a base case scenario where the fractures half-length were fixed for all stages with equal spacing between them. Then, six more fractures half-length patterns were created by introducing new approach where the well performance was studied if they are in increasing trend away from the wellbore (coning-up), or in a decreasing trend (coning-down). Well performance is furtherly addressed when the fractures half-length arrangements formed parabolic shapes including both occasions of concaving upward and downward. Finally, the last two patterns illustrated the effect of having the fractures half-length arrangements both skewed to the left and right on well productivity.\u0000 The investigation of the effect of changing the multistage hydraulic fractures half-length distribution patterns on the performance of a gas condensate well was conducted and resulted in parabolic up distribution pattern to be the optimum pattern amongst the other tested ones. It results in the highest cumulative both gas and condensate production. It also maintains the gas flow rate and bottom hole pressure more efficiently. The parabolic up distribution pattern confirms that the majority of gas production was fed by the fractures at the heel and at the toe of the horizontal drainhole which is in agreement with the flux distribution along the horizontal well.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81522463","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. N. S. Zainuddin, S. X. Xie, N. I. Kechut, B. Kantaatmadja, P. Singer, G. Hirasaki
Nuclear magnetic resonance (NMR) T2 spin-spin relaxation is a well-established technique in petrophysics labs for quantifying bound/free water and pore-size distribution of reservoir rocks. The method has also been used to measure oil and water saturations, and to characterize wettability alterations for oil/water/rock systems. The T2 relaxation distribution measured by hydrogen NMR is the sum of contributions from both oil and water in the core. It is therefore necessary to separate the T2 signals of oil from water. Since deuterium oxide (D2O) does not have a NMR signal at the resonance frequency for hydrogen, brine made with D2O is commonly used as the aqueous phase to determine the oil saturation from NMR. The objective of this work was twofold: (1) to validate the oil saturations in the core with NMR T2 relaxation at connate water saturation (before and after aging) and residual oil saturation after waterflooding; and (2) to investigate the potential hydrogen-deuterium (H-D) ion exchange between rock minerals and D2O. Berea sandstone cores were used along with the crude oil from one of the fields in the Sarawak Basin, Malaysia. The aqueous phase was a synthetic brine made with either deionized water or D2O. Two cores containing the crude oil with D2O brine as the connate (or initial) water were aged at 75eC for up to 65 days. During the aging period, the cores were scanned three times for T2 measurements. The measured T2 volumes (supposedly a measure of the oil volume) of the two cores kept increasing as the aging time increased. However, mass balance indicated that the oil saturation was the same before and after aging. The inconsistent oil saturation measured by NMR indicated that there was H-D ion exchange between the rock minerals and D2O. The cores were then flooded with the fresh D2O brine, after which the residual oil from NMR agreed with that from mass balance, indicating that the fresh D2O had replaced the connate D2O brine affected by H-D ion exchange. Additionally, two cores fully saturated with D2O brine were also measured by NMR before and after aging at 75°C, again confirming the H-D ion exchange between the rock minerals and D2O. Finally, the mixture of the crude oil and D2O was measured by NMR before and after aging at 75°C, indicating that the interactions between the crude oil and D2O increased the T2 relaxation time. The total T2 volume was not affected. This work provides evidence of H-D ion exchange between rock minerals and D2O at elevated temperature. It is recommended that such interactions between the rock minerals and D2O brine be considered for related tests, especially when elevated temperature is involved.
{"title":"Hydrogen-Deuterium Exchange Between Rock Minerals and D2O","authors":"W. N. S. Zainuddin, S. X. Xie, N. I. Kechut, B. Kantaatmadja, P. Singer, G. Hirasaki","doi":"10.2118/194978-MS","DOIUrl":"https://doi.org/10.2118/194978-MS","url":null,"abstract":"\u0000 Nuclear magnetic resonance (NMR) T2 spin-spin relaxation is a well-established technique in petrophysics labs for quantifying bound/free water and pore-size distribution of reservoir rocks. The method has also been used to measure oil and water saturations, and to characterize wettability alterations for oil/water/rock systems. The T2 relaxation distribution measured by hydrogen NMR is the sum of contributions from both oil and water in the core. It is therefore necessary to separate the T2 signals of oil from water. Since deuterium oxide (D2O) does not have a NMR signal at the resonance frequency for hydrogen, brine made with D2O is commonly used as the aqueous phase to determine the oil saturation from NMR.\u0000 The objective of this work was twofold: (1) to validate the oil saturations in the core with NMR T2 relaxation at connate water saturation (before and after aging) and residual oil saturation after waterflooding; and (2) to investigate the potential hydrogen-deuterium (H-D) ion exchange between rock minerals and D2O. Berea sandstone cores were used along with the crude oil from one of the fields in the Sarawak Basin, Malaysia. The aqueous phase was a synthetic brine made with either deionized water or D2O.\u0000 Two cores containing the crude oil with D2O brine as the connate (or initial) water were aged at 75eC for up to 65 days. During the aging period, the cores were scanned three times for T2 measurements. The measured T2 volumes (supposedly a measure of the oil volume) of the two cores kept increasing as the aging time increased. However, mass balance indicated that the oil saturation was the same before and after aging. The inconsistent oil saturation measured by NMR indicated that there was H-D ion exchange between the rock minerals and D2O. The cores were then flooded with the fresh D2O brine, after which the residual oil from NMR agreed with that from mass balance, indicating that the fresh D2O had replaced the connate D2O brine affected by H-D ion exchange.\u0000 Additionally, two cores fully saturated with D2O brine were also measured by NMR before and after aging at 75°C, again confirming the H-D ion exchange between the rock minerals and D2O. Finally, the mixture of the crude oil and D2O was measured by NMR before and after aging at 75°C, indicating that the interactions between the crude oil and D2O increased the T2 relaxation time. The total T2 volume was not affected.\u0000 This work provides evidence of H-D ion exchange between rock minerals and D2O at elevated temperature. It is recommended that such interactions between the rock minerals and D2O brine be considered for related tests, especially when elevated temperature is involved.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89948637","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}
Iron sulfide is a $1.4 billion/year problem in the oil and gas industry receiving little R&D attention. The low success rate of organic acids and polyaminocarboxylic acids (PACA) prompts a more focused investigation and development of new dissolvers for the treatment of iron sulfide scales. This study evaluates the solubility of the iron sulfide scale by commonly used simple organic acids and describes two new blends that outperform the aforementioned standalone dissolvers at 1,000 psi and 150°F. Bottle and autoclave tests evaluated the efficacy of various dissolvers to dissolve the iron sulfide scale. Bottle tests helped in evaluating the dissolvers’ potential to dissolve iron sulfide. A Hastelloy-B autoclave with a maximum operating pressure and temperature of 1,800 psi and 350°F, respectively, contained the iron sulfide and the dissolver for the anoxic dissolution tests. Formic acid, maleic acid, lactic acid, citric acid, oxalic acid, ethylenediaminetetraacetic acid disodium salt (Na2EDTA), and pentapotassium diethyltriaminepentaacetic acid (K5DTPA) were used. The simple organic acids added to Na2EDTA helped in improving the solubility of the scale. Two final experiments with the most successful blends were conducted for 24 hours. Concentration of the dissolver varied from 1-10 wt%. The experiments were conducted for 4 hours at 150°F, and a pressure of 1,000 psi. Elemental analysis using the Inductively Coupled Plasma (ICP) determined the efficiency of scale removal. Dräger tubes measured the H2S concentration inside the autoclave at the end of the experiment. The degree of saturation of the dissolvers calculated from the ICP measurements helped in evaluating its utilization. An XRD study showed the initial iron sulfide scale was mainly pyrrhotite (67%), mackinawite (23%), troilite (5%), and remaining wuestite (5%). Bottle tests showed that maleic acid is the best reactant for iron sulfide in terms of the speed of the reaction. However, citric acid can react with the iron sulfide at lower concentrations and is more effective. Similar to the bottle test, maleic acid yielded the maximum solubility among standalone treatments. An inductively coupled plasma analysis of iron concentration showed a solubility of 10.6 g/L iron in maleic acid. The next best treatment was with formic acid, dissolving a maximum of 9.7 g/L iron. Oxalic acid converted the iron sulfide to iron (II) oxalate, which is insoluble in water. K5DTPA was a poor dissolver of iron sulfide with less than 1 g/L iron solubility. Blends of Na2EDTA and a synergist helped in improving the dissolution. Adding 5 wt% potassium oxalate to 15 wt% Na2EDTA helped in dissolving 70.1% of the initial iron at 1,000 psi, 150°F, and 24 hours soaking time. A blend of 15 wt% Na2EDTA and 5 wt% potassium citrate dissolved 87% of iron at the same conditions. Development of novel dissolvers that are less corrosive and safer than traditional dissolvers is a necessary step to improve the dissolution of i
{"title":"Improving the Dissolution of Iron Sulfide by Blending Chelating Agents and its Synergists","authors":"R. Ramanathan, H. Nasr-El-Din","doi":"10.2118/195128-MS","DOIUrl":"https://doi.org/10.2118/195128-MS","url":null,"abstract":"\u0000 Iron sulfide is a $1.4 billion/year problem in the oil and gas industry receiving little R&D attention. The low success rate of organic acids and polyaminocarboxylic acids (PACA) prompts a more focused investigation and development of new dissolvers for the treatment of iron sulfide scales. This study evaluates the solubility of the iron sulfide scale by commonly used simple organic acids and describes two new blends that outperform the aforementioned standalone dissolvers at 1,000 psi and 150°F.\u0000 Bottle and autoclave tests evaluated the efficacy of various dissolvers to dissolve the iron sulfide scale. Bottle tests helped in evaluating the dissolvers’ potential to dissolve iron sulfide. A Hastelloy-B autoclave with a maximum operating pressure and temperature of 1,800 psi and 350°F, respectively, contained the iron sulfide and the dissolver for the anoxic dissolution tests. Formic acid, maleic acid, lactic acid, citric acid, oxalic acid, ethylenediaminetetraacetic acid disodium salt (Na2EDTA), and pentapotassium diethyltriaminepentaacetic acid (K5DTPA) were used. The simple organic acids added to Na2EDTA helped in improving the solubility of the scale. Two final experiments with the most successful blends were conducted for 24 hours. Concentration of the dissolver varied from 1-10 wt%. The experiments were conducted for 4 hours at 150°F, and a pressure of 1,000 psi. Elemental analysis using the Inductively Coupled Plasma (ICP) determined the efficiency of scale removal. Dräger tubes measured the H2S concentration inside the autoclave at the end of the experiment. The degree of saturation of the dissolvers calculated from the ICP measurements helped in evaluating its utilization.\u0000 An XRD study showed the initial iron sulfide scale was mainly pyrrhotite (67%), mackinawite (23%), troilite (5%), and remaining wuestite (5%). Bottle tests showed that maleic acid is the best reactant for iron sulfide in terms of the speed of the reaction. However, citric acid can react with the iron sulfide at lower concentrations and is more effective. Similar to the bottle test, maleic acid yielded the maximum solubility among standalone treatments. An inductively coupled plasma analysis of iron concentration showed a solubility of 10.6 g/L iron in maleic acid. The next best treatment was with formic acid, dissolving a maximum of 9.7 g/L iron. Oxalic acid converted the iron sulfide to iron (II) oxalate, which is insoluble in water. K5DTPA was a poor dissolver of iron sulfide with less than 1 g/L iron solubility. Blends of Na2EDTA and a synergist helped in improving the dissolution. Adding 5 wt% potassium oxalate to 15 wt% Na2EDTA helped in dissolving 70.1% of the initial iron at 1,000 psi, 150°F, and 24 hours soaking time. A blend of 15 wt% Na2EDTA and 5 wt% potassium citrate dissolved 87% of iron at the same conditions.\u0000 Development of novel dissolvers that are less corrosive and safer than traditional dissolvers is a necessary step to improve the dissolution of i","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89955616","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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