The paper reviews operational issues that arise when MEG is used for hydrate inhibition, especially when it is regenerated and recirculated. Thermodynamic equilibrium software can assess the scaling risk to some extent. Utilisation of data on nucleation and growth of scale formers like calcium carbonate can enhance the accuracy of the predictions. The presence of MEG and the conditions encountered in MEG systems favour aragonite crystallisation when the MEG solutions become supersaturated in CaCO3. MEG retards the growth rate of all three CaCO3 polymorphs, but the reduction is smaller for aragonite than for calcite and vaterite. The growth rate of siderite is also slowed down by MEG. However, MEG does not inhibit the nucleation and growth of carbonates. Alkalinity in recycled MEG will enhance the scaling risk downstream of the MEG injection point when there is calcium in the produced water. Scale can be mitigated by scale inhibitors, but the selection process must ensure that the chemicals are tested at relevant conditions; i.e. with the expected MEG concentration, alkalinity and pH. Many MEG recovery units have a pre-treatment system for controlled removal of carbonates and to some extent hydroxides. This reduces the amount of scale that may form in the regeneration system. In the pre-treatment, alkalinity dosed as hydroxide and/or carbonate forces precipitation of calcium, strontium and iron carbonates and magnesium hydroxide. The supersaturation is generally so high that scale inhibitors are not able to prevent precipitation of the solids.
{"title":"Scale Management in Monoethylene Glycol MEG Systems - A Review","authors":"M. Seiersten, S. Kundu","doi":"10.2118/190738-MS","DOIUrl":"https://doi.org/10.2118/190738-MS","url":null,"abstract":"\u0000 The paper reviews operational issues that arise when MEG is used for hydrate inhibition, especially when it is regenerated and recirculated. Thermodynamic equilibrium software can assess the scaling risk to some extent. Utilisation of data on nucleation and growth of scale formers like calcium carbonate can enhance the accuracy of the predictions.\u0000 The presence of MEG and the conditions encountered in MEG systems favour aragonite crystallisation when the MEG solutions become supersaturated in CaCO3. MEG retards the growth rate of all three CaCO3 polymorphs, but the reduction is smaller for aragonite than for calcite and vaterite. The growth rate of siderite is also slowed down by MEG. However, MEG does not inhibit the nucleation and growth of carbonates.\u0000 Alkalinity in recycled MEG will enhance the scaling risk downstream of the MEG injection point when there is calcium in the produced water. Scale can be mitigated by scale inhibitors, but the selection process must ensure that the chemicals are tested at relevant conditions; i.e. with the expected MEG concentration, alkalinity and pH.\u0000 Many MEG recovery units have a pre-treatment system for controlled removal of carbonates and to some extent hydroxides. This reduces the amount of scale that may form in the regeneration system. In the pre-treatment, alkalinity dosed as hydroxide and/or carbonate forces precipitation of calcium, strontium and iron carbonates and magnesium hydroxide. The supersaturation is generally so high that scale inhibitors are not able to prevent precipitation of the solids.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75826177","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}
Produced water can be routely re-injected into reservoir for purposes including pressure support and environmentally acceptable disposal. Scale prevention and control is required to maintain well injectivity and longetivity. This paper presents a comprehensive scale study to reliably access injection well scaling potential and establish fit-for-purpose/optimal scale management strategy. Field water samples were appropriately collected and characterized. Laboratory testing was well designed/conducted to understand scale formation potential, and determine required scale inhibitor dosage. Study results suggest calcite and silicate scales can be of potential concern, and increase of downhole temperature or/and fluid residence time (e.g., under abnormal operation condition with low injection rate or well shut in) at near wellbore formation can lead to higher scaling risk. Testing results show that one scale inhibitor product (originally recommended by chemical vendor) at high dosage can potentially accelerate scale formation leading to more solid precipitation. Alternative inhibitor products were tested and scale inhibitor selection and treatment strategy was optimized based on testing results.
{"title":"Scale Formation and Inhibition Study for Water Injection Wells","authors":"Wei Wang, Wei Wei, N. Ferrier, N. Arismendi","doi":"10.2118/190732-MS","DOIUrl":"https://doi.org/10.2118/190732-MS","url":null,"abstract":"\u0000 Produced water can be routely re-injected into reservoir for purposes including pressure support and environmentally acceptable disposal. Scale prevention and control is required to maintain well injectivity and longetivity. This paper presents a comprehensive scale study to reliably access injection well scaling potential and establish fit-for-purpose/optimal scale management strategy. Field water samples were appropriately collected and characterized. Laboratory testing was well designed/conducted to understand scale formation potential, and determine required scale inhibitor dosage. Study results suggest calcite and silicate scales can be of potential concern, and increase of downhole temperature or/and fluid residence time (e.g., under abnormal operation condition with low injection rate or well shut in) at near wellbore formation can lead to higher scaling risk. Testing results show that one scale inhibitor product (originally recommended by chemical vendor) at high dosage can potentially accelerate scale formation leading to more solid precipitation. Alternative inhibitor products were tested and scale inhibitor selection and treatment strategy was optimized based on testing results.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"69 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72861965","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 advent of wells with extremely long producing intervals, extended-reach and multilateral wells, typically completed in heterogeneous formations, brings with it challenges regarding completion design to maximize overall production in a sustained manner. Judicious placement of Inflow Control Devices (ICDs) can ensure a more even inflow of fluids along the full length of the interval, delaying water or gas breakthrough and in some cases restricting water production. Such devices also influence the placement of chemical treatments, such as scale-inhibitor "squeeze" treatments, which in turn affects the subsequent treatment lifetimes and efficiency. This paper presents a new analytical model to explicitly simulate the effect of ICDs on squeeze treatments and, in particular, on treatment placement and consequent lifetimes. The explicit method of modelling ICDs, which is based on Bernoulli's theorem of constricted flow through a pipe, is compared with other implicit phenomenological approaches, such as modelling the effect of an ICD as a damaged region using a dual-permeability model. By this comparison, the relevance of dual permeability modelling for simulating ICDs is presented. The relationship between chemical placement and inhibitor return has been clearly demonstrated in other publications (James et al., 2005, Sorbie et al. 2005). This paper illustrates the additional effects that ICDs bring to the placement challenge, highlighting the key parameters that can influence the zonal injectivity behaviour. The presence of ICDs in the well is shown not only to benefit the well's inflow profile during production but can also favourably influence the outcome of squeeze chemical treatments. In summary, the paper describes the development of an important new tool to assist in the design of optimum chemical treatment strategies in wells completed with ICDs, without the need to use more complex reservoir simulators for near-wellbore treatment in complex completions.
超长生产层段、大位移井和分支井的出现，通常是在非均质地层中完成的，这给完井设计带来了挑战，如何以持续的方式最大化总产量。明智地放置流入控制装置(icd)可以确保整个井段的流体流入更加均匀，延迟水或气的突破，在某些情况下还可以限制产水。此类装置还会影响化学处理的放置，例如阻垢剂“挤压”处理，从而影响后续处理的使用寿命和效率。本文提出了一个新的分析模型来明确模拟icd对挤压处理的影响，特别是对处理位置和随后的使用寿命的影响。基于伯努利管道收缩流动定理的显式ICD建模方法与其他隐式现象学方法进行了比较，例如使用双渗透率模型将ICD的影响建模为受损区域。通过比较，提出了双渗透率模型在模拟icd中的适用性。其他出版物已经清楚地证明了化学放置和抑制剂返回之间的关系(James et al.， 2005, Sorbie et al. 2005)。本文阐述了icd给布置带来的额外影响，重点介绍了影响层间注入能力的关键参数。研究表明，在生产过程中，icd的存在不仅有利于井的流入剖面，而且对挤压化学处理的结果也有积极的影响。综上所述，本文描述了一种重要的新工具的开发，该工具可以帮助在使用icd完井的井中设计最佳化学处理策略，而无需在复杂完井中使用更复杂的油藏模拟器进行近井处理。
{"title":"Simulating Squeeze Treatments in Wells Completed with Inflow Control Devices","authors":"A. Kaur, R. Stalker, G. Graham","doi":"10.2118/190740-MS","DOIUrl":"https://doi.org/10.2118/190740-MS","url":null,"abstract":"\u0000 The advent of wells with extremely long producing intervals, extended-reach and multilateral wells, typically completed in heterogeneous formations, brings with it challenges regarding completion design to maximize overall production in a sustained manner. Judicious placement of Inflow Control Devices (ICDs) can ensure a more even inflow of fluids along the full length of the interval, delaying water or gas breakthrough and in some cases restricting water production. Such devices also influence the placement of chemical treatments, such as scale-inhibitor \"squeeze\" treatments, which in turn affects the subsequent treatment lifetimes and efficiency.\u0000 This paper presents a new analytical model to explicitly simulate the effect of ICDs on squeeze treatments and, in particular, on treatment placement and consequent lifetimes. The explicit method of modelling ICDs, which is based on Bernoulli's theorem of constricted flow through a pipe, is compared with other implicit phenomenological approaches, such as modelling the effect of an ICD as a damaged region using a dual-permeability model. By this comparison, the relevance of dual permeability modelling for simulating ICDs is presented. The relationship between chemical placement and inhibitor return has been clearly demonstrated in other publications (James et al., 2005, Sorbie et al. 2005). This paper illustrates the additional effects that ICDs bring to the placement challenge, highlighting the key parameters that can influence the zonal injectivity behaviour. The presence of ICDs in the well is shown not only to benefit the well's inflow profile during production but can also favourably influence the outcome of squeeze chemical treatments.\u0000 In summary, the paper describes the development of an important new tool to assist in the design of optimum chemical treatment strategies in wells completed with ICDs, without the need to use more complex reservoir simulators for near-wellbore treatment in complex completions.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"95 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74061667","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}
Hydraulic fracturing for shale gas production involves pumping large volumes of water; as a consequence of this, produced water management is an important topic to address in order to sustainably produce shale gas. It has been well documented that only approximately 10-40% of the pumped fluids will be produced back to the surface, and that there will be increased concentrations of various ions in the flowback water during this process. This flowback water, with high total dissolved solids and high concentrations of certain ions, presents a significant risk of mineral scaling (Blauch, 2009). In general, it can be very challenging to identify the in situ formation water composition in shale reservoirs since samples of the formation water can be difficult to obtain. They may have been contaminated during the drilling process, reactions may have taken place due to fluid mixing between the injected fluid and the formation water, or simply they may not have been preserved appropriately (Pan, 2017). Some calculations of formation water compositions require to be preceded based on the observed compositional data; thereafter, the predicted formation water compositions are validated by comparison with the observed total dissolved solids (TDS) data. A two-phase 3D numerical flow model has been developed that includes a hydraulic fracture and is populated with shale reservoir properties. (This model assumes the hydraulic fracture is already established – i.e. the calculations include coupled flow and component transport, but the geomechanics are not considered). It is used to simulate fluid transport mechanisms within the shale system and to address the question – what causes the significant retention of fracture fluid in shale reservoirs. A series of simulations was performed to achieve a history match with observed flowback water data in a western Canadian basin (the Horn River Basin). A further two-phase 3D flow model was developed to examine the scaling tendency due to the evolving produced brine composition over the lifetime of the well. It is based on the previously history matched model and includes the fracture fluid and formation water compositions to predict precipitation of minerals. Finally, scale inhibitor injection was simulated to examine the impact of inhibitor retention on well protection.
{"title":"Simulation Study for Scale Management During Shale Gas Production","authors":"Xu Wang, E. Mackay","doi":"10.2118/190717-MS","DOIUrl":"https://doi.org/10.2118/190717-MS","url":null,"abstract":"\u0000 Hydraulic fracturing for shale gas production involves pumping large volumes of water; as a consequence of this, produced water management is an important topic to address in order to sustainably produce shale gas. It has been well documented that only approximately 10-40% of the pumped fluids will be produced back to the surface, and that there will be increased concentrations of various ions in the flowback water during this process. This flowback water, with high total dissolved solids and high concentrations of certain ions, presents a significant risk of mineral scaling (Blauch, 2009).\u0000 In general, it can be very challenging to identify the in situ formation water composition in shale reservoirs since samples of the formation water can be difficult to obtain. They may have been contaminated during the drilling process, reactions may have taken place due to fluid mixing between the injected fluid and the formation water, or simply they may not have been preserved appropriately (Pan, 2017). Some calculations of formation water compositions require to be preceded based on the observed compositional data; thereafter, the predicted formation water compositions are validated by comparison with the observed total dissolved solids (TDS) data. A two-phase 3D numerical flow model has been developed that includes a hydraulic fracture and is populated with shale reservoir properties. (This model assumes the hydraulic fracture is already established – i.e. the calculations include coupled flow and component transport, but the geomechanics are not considered). It is used to simulate fluid transport mechanisms within the shale system and to address the question – what causes the significant retention of fracture fluid in shale reservoirs. A series of simulations was performed to achieve a history match with observed flowback water data in a western Canadian basin (the Horn River Basin).\u0000 A further two-phase 3D flow model was developed to examine the scaling tendency due to the evolving produced brine composition over the lifetime of the well. It is based on the previously history matched model and includes the fracture fluid and formation water compositions to predict precipitation of minerals. Finally, scale inhibitor injection was simulated to examine the impact of inhibitor retention on well protection.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82412865","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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