K. Jarrahian, K. Sorbie, Michael A. Singleton, L. Boak, A. Graham
Scale inhibitor (SI) squeeze treatments in carbonate reservoirs are often affected by the chemical reactivity between the SI and the carbonate mineral substrate. This chemical interaction may lead to a controlled precipitation of the SI through the formation of a sparingly soluble Ca/SI complex which can lead to an extended squeeze lifetime. However, the same interaction may in some cases lead to uncontrolled SI precipitation causing near-well formation damage in the treated zone. This paper presents a detailed study of the various retention mechanisms of SI in carbonate formations, considering system variables such as the (carbonate) formation mineralogy, the type of SI and the system conditions. Apparent adsorption (Γapp) experiments, described previously (Kahrwad et al. 2008), are used to show when the SI/substrate interaction is pure adsorption (Γ) or coupled adsorption (Γ)/precipitation (∏). Experiments were performed for different SIs at various operational conditions, i.e. initial pH values, minerologies - calcite, limestone and dolomite - and temperatures; the overall results from these coupled Γ/∏ experiments are summarised in Table 3. The SI species used in this study included 1 phosphonate (DETPMP), 1 phosphate ester (PAPE) and 3 polymeric scale inhibitors (PPCA, PFC, VS-Co); the full names of these SIs are given in the paper. All precipitates were studied using Environmental Scanning Electron Microscopy/Energy Dispersive X-Ray (ESEM/EDX) and Particle Size Analysis (PSA). These measurements confirmed that when precipitation occurred, it was mainly in the bulk solution and not on the rock surface. For all SIs, both adsorption (Γ) and precipitation (∏) retention mechanisms were observed, with the dominant mechanism depending on SI chemistry, temperature and mineralogy. Differences were observed between the "apparent adsorption" (Γapp) levels of polymeric, phosphonate and phosphate ester scale inhibitors, as follows: For the polymeric SIs (PPCA, PFC and VS-Co), the highest retention levels were observed at low pH for all carbonate substrates, due to the increase in divalent cations (Ca2+ and Mg2+) available from rock dissolution for SI-M2+ precipitation. For phosphonate (DETPMP) and phosphate ester (PAPE) SIs, the retention level was greatest at higher pH values, as the SI functional groups were more dissociated and hence available for complexation with M2+ ions.The polymeric VS-Co showed the lowest amount of precipitation (Γapp ~ 1.2 mg/g) in contact with dolomite substrate due to the presence of sulphonate groups (low pKa); indeed this showed low Γapp which was predominantly pure adsorption. However, a small amount of precipitate was observed by ESEM/EDX and PSA.For polymeric inhibitors, the retention level (Γapp) was highest on calcite (highest relative calcium content), followed by limestone and then dolomite. Phosphonate and phosphate ester SIs showed the highest retention levels on dolomite (higher final solution pH and more SI d
碳酸盐储层中的阻垢剂(SI)挤压处理通常受到SI与碳酸盐矿物基质之间化学反应性的影响。这种化学相互作用可以通过形成少溶的Ca/SI络合物导致SI的可控沉淀，从而延长挤压寿命。然而，在某些情况下，同样的相互作用可能导致不受控制的SI降水，导致处理区域的近井地层受损。本文详细研究了碳酸盐地层中SI的各种保留机制，并考虑了诸如(碳酸盐)地层矿物学、SI类型和系统条件等系统变量。先前描述的表观吸附(Γapp)实验(Kahrwad et al. 2008)用于显示SI/底物相互作用是纯吸附(Γ)还是耦合吸附(Γ)/沉淀(∏)。实验在不同的操作条件下进行，即初始pH值，矿物学-方解石，石灰石和白云石-和温度;这些耦合Γ/∏实验的总体结果总结在表3中。本研究使用的阻垢剂包括1种磷酸盐(DETPMP)、1种磷酸酯(PAPE)和3种聚合物阻垢剂(PPCA、PFC、VS-Co);文中给出了这些si的全名。采用环境扫描电镜/能量色散x射线(ESEM/EDX)和粒度分析(PSA)对所有沉淀物进行了研究。这些测量证实，当降水发生时，它主要是在整体溶液中，而不是在岩石表面。对于所有SI，都观察到吸附(Γ)和沉淀(∏)保留机制，主要机制取决于SI化学，温度和矿物学。在聚合物、膦酸盐和磷酸酯阻垢剂的“表观吸附”(Γapp)水平之间观察到的差异如下:对于聚合物SIs (PPCA、PFC和VS-Co)，在低pH下，所有碳酸盐基质的保留水平最高，这是由于岩石溶解中可用于SI-M2+沉淀的二价阳离子(Ca2+和Mg2+)的增加。对于磷酸盐(DETPMP)和磷酸酯(PAPE) SI，在较高的pH值下保留水平最大，因为SI官能团更容易解离，因此可与M2+离子络合。聚合物VS-Co由于存在低pKa的磺酸基，与白云石基质接触时析出量最低(Γapp ~ 1.2 mg/g);确实，这表明Γapp低，主要是纯吸附。但ESEM/EDX和PSA均观察到少量析出物。对于聚合物抑制剂，方解石(相对钙含量最高)的保留水平最高(Γapp)，其次是石灰石，然后是白云石。磷酸盐和磷酸酯SI在白云石上的保留率最高(最终溶液pH值较高，SI解离率较高)，其次是石灰石和方解石。对于所有SI物种，在高温下观察到更高的保留率(更多的降水，∏)。在较低的温度下，观察到所有si的纯吸附区域更大。本研究提供的信息将有助于我们根据矿物学和储层条件选择具有较长挤压寿命的碳酸盐储层挤压处理的SI产品。此外，该研究为验证SI/碳酸盐/Ca/Mg体系模型提供了有价值的数据，这些模型可用于挤压设计模拟。
{"title":"Building a Fundamental Understanding of Scale Inhibitor Retention in Carbonate Formations","authors":"K. Jarrahian, K. Sorbie, Michael A. Singleton, L. Boak, A. Graham","doi":"10.2118/193635-MS","DOIUrl":"https://doi.org/10.2118/193635-MS","url":null,"abstract":"\u0000 Scale inhibitor (SI) squeeze treatments in carbonate reservoirs are often affected by the chemical reactivity between the SI and the carbonate mineral substrate. This chemical interaction may lead to a controlled precipitation of the SI through the formation of a sparingly soluble Ca/SI complex which can lead to an extended squeeze lifetime. However, the same interaction may in some cases lead to uncontrolled SI precipitation causing near-well formation damage in the treated zone. This paper presents a detailed study of the various retention mechanisms of SI in carbonate formations, considering system variables such as the (carbonate) formation mineralogy, the type of SI and the system conditions. Apparent adsorption (Γapp) experiments, described previously (Kahrwad et al. 2008), are used to show when the SI/substrate interaction is pure adsorption (Γ) or coupled adsorption (Γ)/precipitation (∏). Experiments were performed for different SIs at various operational conditions, i.e. initial pH values, minerologies - calcite, limestone and dolomite - and temperatures; the overall results from these coupled Γ/∏ experiments are summarised in Table 3. The SI species used in this study included 1 phosphonate (DETPMP), 1 phosphate ester (PAPE) and 3 polymeric scale inhibitors (PPCA, PFC, VS-Co); the full names of these SIs are given in the paper. All precipitates were studied using Environmental Scanning Electron Microscopy/Energy Dispersive X-Ray (ESEM/EDX) and Particle Size Analysis (PSA). These measurements confirmed that when precipitation occurred, it was mainly in the bulk solution and not on the rock surface.\u0000 For all SIs, both adsorption (Γ) and precipitation (∏) retention mechanisms were observed, with the dominant mechanism depending on SI chemistry, temperature and mineralogy. Differences were observed between the \"apparent adsorption\" (Γapp) levels of polymeric, phosphonate and phosphate ester scale inhibitors, as follows: For the polymeric SIs (PPCA, PFC and VS-Co), the highest retention levels were observed at low pH for all carbonate substrates, due to the increase in divalent cations (Ca2+ and Mg2+) available from rock dissolution for SI-M2+ precipitation. For phosphonate (DETPMP) and phosphate ester (PAPE) SIs, the retention level was greatest at higher pH values, as the SI functional groups were more dissociated and hence available for complexation with M2+ ions.The polymeric VS-Co showed the lowest amount of precipitation (Γapp ~ 1.2 mg/g) in contact with dolomite substrate due to the presence of sulphonate groups (low pKa); indeed this showed low Γapp which was predominantly pure adsorption. However, a small amount of precipitate was observed by ESEM/EDX and PSA.For polymeric inhibitors, the retention level (Γapp) was highest on calcite (highest relative calcium content), followed by limestone and then dolomite. Phosphonate and phosphate ester SIs showed the highest retention levels on dolomite (higher final solution pH and more SI d","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90038316","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}
Several polymer technologies are commonly used as fluid loss control additives. Working mechanisms were studied by Plank et al. (Plank et al. 2009) and most of the time these can be classified into 2 categories: adsorbing polymers and pore plugging "microgel" like systems. In addition, these polymers have a strong influence on the cement slurry rheology and are also often expected to play a role on cement particle suspension, cement sheath homogeneity and to prevent settling. The scope of this paper is to investigate the impact of several types of fluid loss polymers on cement slurry stability. Then, an effort is made to correlate the working mechanism of the fluid loss additive with cement slurry rheological behavior and its ability to prevent segregation or settling. On top of conventional tests on fluid loss and flow rheology, refined evaluations of the rheological behavior are performed in oscillatory rheometry at very-low strain. This technique allows some insight into the microscopic interactions at stake in cement slurries. In particular a "yield stress model" is applied to formulated oil well cement slurries at 90°C providing additional insight on the impact of adsorbing or non-adsorbing polymers. From this study it can be confirmed that adsorbing polymers have a strong impact on rheological properties with a surprisingly lower yield stress combined with improved slurry stability. On the other hand non adsorbing polymers of either linear or μgel form have a very limited impact on slurry yield stress and a variable impact on slurry stability through either viscosification of the interstitial fluid for linear polymers or enhanced settling hindrance from μgels.
几种聚合物技术通常被用作防滤失添加剂。Plank等人(Plank et al. 2009)对其工作机理进行了研究，大多数情况下可将其分为两类:吸附聚合物和孔隙堵塞“微凝胶”类系统。此外，这些聚合物对水泥浆的流变性有很强的影响，也经常被期望在水泥颗粒悬浮、水泥环均匀性和防止沉降方面发挥作用。本文的研究范围是研究几种降滤失聚合物对水泥浆稳定性的影响。然后，努力将降滤失剂的工作机制与水泥浆流变行为及其防止离析或沉降的能力联系起来。在流体损失和流动流变的常规测试之上，在非常低的应变下，通过振荡流变法对流变行为进行了精细的评估。这项技术可以让我们深入了解水泥浆中的微观相互作用。特别是，“屈服应力模型”应用于90°C下的配方油井水泥浆，为吸附或非吸附聚合物的影响提供了额外的见解。从这项研究中可以证实，吸附聚合物对流变特性有很强的影响，具有令人惊讶的低屈服应力和提高浆体稳定性。另一方面，线性或μ凝胶形式的非吸附聚合物对浆体屈服应力的影响非常有限，而对浆体稳定性的影响则是可变的，这可能是由于线性聚合物对间隙流体的粘滞作用或μ凝胶对沉降阻碍的增强。
{"title":"Effect of Fluid Loss Polymers Architecture on Cement Slurry Rheology : Impact of Adsorption and Microstructure","authors":"A. Cadix, V. Molinie, James Wilson","doi":"10.2118/193620-MS","DOIUrl":"https://doi.org/10.2118/193620-MS","url":null,"abstract":"\u0000 Several polymer technologies are commonly used as fluid loss control additives. Working mechanisms were studied by Plank et al. (Plank et al. 2009) and most of the time these can be classified into 2 categories: adsorbing polymers and pore plugging \"microgel\" like systems. In addition, these polymers have a strong influence on the cement slurry rheology and are also often expected to play a role on cement particle suspension, cement sheath homogeneity and to prevent settling.\u0000 The scope of this paper is to investigate the impact of several types of fluid loss polymers on cement slurry stability. Then, an effort is made to correlate the working mechanism of the fluid loss additive with cement slurry rheological behavior and its ability to prevent segregation or settling.\u0000 On top of conventional tests on fluid loss and flow rheology, refined evaluations of the rheological behavior are performed in oscillatory rheometry at very-low strain. This technique allows some insight into the microscopic interactions at stake in cement slurries. In particular a \"yield stress model\" is applied to formulated oil well cement slurries at 90°C providing additional insight on the impact of adsorbing or non-adsorbing polymers.\u0000 From this study it can be confirmed that adsorbing polymers have a strong impact on rheological properties with a surprisingly lower yield stress combined with improved slurry stability. On the other hand non adsorbing polymers of either linear or μgel form have a very limited impact on slurry yield stress and a variable impact on slurry stability through either viscosification of the interstitial fluid for linear polymers or enhanced settling hindrance from μgels.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88173283","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}
Acid stimulation in sandstone reservoirs containing significant amount of clays can end up with undesired results due to unexpected reactions between stimulation fluids and formation clays. This paper demonstrates how heavily damaged clay-rich sandstone reservoir completed with cased hole gravel pack (CHGP) in offshore Myanmar can be successfully established for commercial production with organic clay acid stimulation treatment. The formation is laminated dirty sand with very high clay content (up to 30%) and large gross height (>100m MD). Production logging results showed only a small portion of perforated intervals contributing to production. Thus, an appropriate stimulation treatment is required to unlock well potential and prevent screen failures from concentrated flow through a small interval. Given high clay content as well as presence of acid sensitive clays, conventional treatments using HCl as preflush and hydrofluoric (HF) acids as main fluids would result in potential damages from secondary and tertiary reactions. Furthermore, undissolved clays in the critical matrix left over from the treatment would potentially migrate and plug the pore throat. The new acid system was designed to generate small amount of HF in-situ (∼0.1%) at any given time with total strength of 1% HF, which would greatly minimize second and tertiary reactions and also permits acids travel deeper into the formation. Furthermore, the reaction products would react with the clays and physically "welding" the undissolved clays to the surface of the pore spaces permanently and prevent them from migration. The treatment was designed in three stages: 1) screen and gravel pack cleanup using coiled tubing (CT) jetting; 2) injectivity test; 3) main treatment consisting of acetic acids as preflush, and new acid system as main fluids followed by overflush. A newly designed linear gel containing relative permeability modifier was used for diversions. Two underperforming CHGP wells were treated, and both wells yielded 100% increase in productivity with no fine production observed at the surface. The success of the campaign owes to the sophisticated engineering workflow which starts from diagnostic of the damage zone and root-cause of the formation damage, followed by detailed analysis of various skin components using radial numerical reservoir modeling for all the reservoir layers that led to a proper treatment strategy and fluid design based on the damage and formation mineralogy as well as comprehensive laboratory tests. This has helped to minimize the risk of the treatment and eventually unlocked the production from the heavily damaged sandstone reservoir.
{"title":"Innovative Acidizing Solutions for Severely Damaged Clay-Rich Sandstone Reservoir with Gravel Pack Completions in Offshore Myanmar","authors":"DongKyoon Kim, Y. Bae, Hai Liu","doi":"10.2118/193569-MS","DOIUrl":"https://doi.org/10.2118/193569-MS","url":null,"abstract":"\u0000 Acid stimulation in sandstone reservoirs containing significant amount of clays can end up with undesired results due to unexpected reactions between stimulation fluids and formation clays. This paper demonstrates how heavily damaged clay-rich sandstone reservoir completed with cased hole gravel pack (CHGP) in offshore Myanmar can be successfully established for commercial production with organic clay acid stimulation treatment. The formation is laminated dirty sand with very high clay content (up to 30%) and large gross height (>100m MD). Production logging results showed only a small portion of perforated intervals contributing to production. Thus, an appropriate stimulation treatment is required to unlock well potential and prevent screen failures from concentrated flow through a small interval.\u0000 Given high clay content as well as presence of acid sensitive clays, conventional treatments using HCl as preflush and hydrofluoric (HF) acids as main fluids would result in potential damages from secondary and tertiary reactions. Furthermore, undissolved clays in the critical matrix left over from the treatment would potentially migrate and plug the pore throat. The new acid system was designed to generate small amount of HF in-situ (∼0.1%) at any given time with total strength of 1% HF, which would greatly minimize second and tertiary reactions and also permits acids travel deeper into the formation. Furthermore, the reaction products would react with the clays and physically \"welding\" the undissolved clays to the surface of the pore spaces permanently and prevent them from migration.\u0000 The treatment was designed in three stages: 1) screen and gravel pack cleanup using coiled tubing (CT) jetting; 2) injectivity test; 3) main treatment consisting of acetic acids as preflush, and new acid system as main fluids followed by overflush. A newly designed linear gel containing relative permeability modifier was used for diversions. Two underperforming CHGP wells were treated, and both wells yielded 100% increase in productivity with no fine production observed at the surface.\u0000 The success of the campaign owes to the sophisticated engineering workflow which starts from diagnostic of the damage zone and root-cause of the formation damage, followed by detailed analysis of various skin components using radial numerical reservoir modeling for all the reservoir layers that led to a proper treatment strategy and fluid design based on the damage and formation mineralogy as well as comprehensive laboratory tests. This has helped to minimize the risk of the treatment and eventually unlocked the production from the heavily damaged sandstone reservoir.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79859143","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}
Barium Sulfate (Barite) is one of the common oil and gas field scales formed inside the production equipment and in the reservoir. Barite is also a common weighting material used during drilling oil and gas wells. Barium sulfate scale may exist as well in carbonate formations. The removal of barium sulfate from calcium carbonate formation is a challenging problem because of the solubility of calcium carbonate is higher compared to that of barium sulfate in different acids. In addition, barium sulfate is not soluble in the regular acids such as hydrochloric (HCl) acid and other organic acids. In this paper, the effect of calcium carbonate on barium sulfate solubility in a chelating agent and converter catalyst was investigated using solubility experiments at 80°C as a function of time. 20 wt.% DTPA with 6 wt.% potassium carbonate (converter) were used at pH of 12. The effect of calcium chelation on the barium sulfate solubility was studied in two scenarios. The first scenario when Barium sulfate is dissolved first then the solution reacts with calcium carbonate. The second scenario when both calcium carbonate and barium sulfate are exposed to the DTPA solution at the same time. In addition, the effect of calcium carbonate loading on the barium sulfate solubility was determined using 25, 50, 75, and 100 wt.% of the scale as calcium carbonate. As an evaluation criterion, inductively coupled plasma (ICP) was used to analyze the cation concentration and determine the solubility of each scale type. For the two scenarios of barium sulfate dissolution, the presence of calcium carbonate had a significant effect on the solubility of barium sulfate. When DTPA solution got saturated first with barium cations after 24 hours, and the addition of calcium carbonate to the solution will cause immediate barium drop of solution (concentration drop from 2140 to 1984 ppm in 30 min in 50 ml solution) which cause precipitation of barium sulfate. In addition, simultaneous chelation of both calcium carbonate and barium sulfate showed a low barium sulfate solubility compared to calcium carbonate. This can be explained by the high affinity of DTPA to calcium compared to barium. It is highly recommended to account for the presence of any calcium source during the design of the chemical formulation for barium sulfate scale removal using DTPA. Therefore, DTPA treatment formulation is recommended in sandstone formations. Field results can be completely different from laboratory results if Ca2+ chelation from carbonate rocks is ignored.
{"title":"Effect of Calcium Carbonate on Barite Solubility Using a Chelating Agent and Converter","authors":"K. Abdelgawad, M. Mahmoud, S. Elkatatny, S. Patil","doi":"10.2118/193566-MS","DOIUrl":"https://doi.org/10.2118/193566-MS","url":null,"abstract":"\u0000 Barium Sulfate (Barite) is one of the common oil and gas field scales formed inside the production equipment and in the reservoir. Barite is also a common weighting material used during drilling oil and gas wells. Barium sulfate scale may exist as well in carbonate formations. The removal of barium sulfate from calcium carbonate formation is a challenging problem because of the solubility of calcium carbonate is higher compared to that of barium sulfate in different acids. In addition, barium sulfate is not soluble in the regular acids such as hydrochloric (HCl) acid and other organic acids.\u0000 In this paper, the effect of calcium carbonate on barium sulfate solubility in a chelating agent and converter catalyst was investigated using solubility experiments at 80°C as a function of time. 20 wt.% DTPA with 6 wt.% potassium carbonate (converter) were used at pH of 12. The effect of calcium chelation on the barium sulfate solubility was studied in two scenarios. The first scenario when Barium sulfate is dissolved first then the solution reacts with calcium carbonate. The second scenario when both calcium carbonate and barium sulfate are exposed to the DTPA solution at the same time. In addition, the effect of calcium carbonate loading on the barium sulfate solubility was determined using 25, 50, 75, and 100 wt.% of the scale as calcium carbonate. As an evaluation criterion, inductively coupled plasma (ICP) was used to analyze the cation concentration and determine the solubility of each scale type.\u0000 For the two scenarios of barium sulfate dissolution, the presence of calcium carbonate had a significant effect on the solubility of barium sulfate. When DTPA solution got saturated first with barium cations after 24 hours, and the addition of calcium carbonate to the solution will cause immediate barium drop of solution (concentration drop from 2140 to 1984 ppm in 30 min in 50 ml solution) which cause precipitation of barium sulfate. In addition, simultaneous chelation of both calcium carbonate and barium sulfate showed a low barium sulfate solubility compared to calcium carbonate. This can be explained by the high affinity of DTPA to calcium compared to barium.\u0000 It is highly recommended to account for the presence of any calcium source during the design of the chemical formulation for barium sulfate scale removal using DTPA. Therefore, DTPA treatment formulation is recommended in sandstone formations. Field results can be completely different from laboratory results if Ca2+ chelation from carbonate rocks is ignored.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83515586","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Jordan, E. Temple, A. Sham, H. Williams, C. McCallum
Inorganic scale control of sulphate and carbonate scales with polymer, phosphonate and phosphate ester scale inhibitors is well established within the oilfield service industry. The environments in which these chemical work best have been published such as vinyl sulphonates are known to be very effective for sulphate scale control in low temperatures whereas phosphonates are much less effective under these same conditions but improve at higher temperatures. What is less well understood is the potential for synergistic interaction with blends of polymers/phosphonates/phosphate esters to give reduced treatment rates, lower chemical discharge volumes and potentially lower treatment cost. In this paper evaluation of two North Sea produced waters will be outlined. Both produced brines have a high barium sulphate scale tendency but differ in the temperature at which the fluids arrive and depart the topside process one case with a temperature of 20C and the other at 90C. Static bottle test data will be presented to evaluate the crystal growth performance of single scale inhibitors and the improvements observed when blends of these same inhibitors are applied. Select dynamic tube blocking tests data to evaluate nucleation inhibition will also be presented so that mechanism of inhibition for the blended chemicals can clearly be highlighted. The generic inhibitor evaluated included vinyl sulphonates co polymer, phosphate esters, poly aspartic acid. In the lower temperature environment, it was observed that a vinyl sulphonate/phosphate ester blend was more effective than either of the components by themselves. Poly aspartic acid blende with phosphate ester also give a synergistic interaction but the performance of this chemical required higher treatment rates than the vinyl sulphonate co polymer blend. At higher temperature the overall treatment rates were reduced as the sulphate scale saturation values were reduced and the synergistic effects of the polymers and phosphate ester blends were evident. As well as classic static bottle tests performance tests were carried out in the presence of reservoir solids with stirring to further understand if the interaction of the generic chemicals within the blends with suspended solids would reduce the observed performance in the solids free test solutions. The current regulatory challenges with REACH mean that the methods outlined in this study offer the potential to reduce chemical treatment rate, cost and environmental impact by evaluating the synergistic interaction of the current range of commercially available scale inhibitors so cutting out the very high registration costs/ time delays to the market associated with new molecule development.
{"title":"Investigation into the Synergistic Interaction of a Range of Generic Scale Inhibitors for Improved Sulphate Scale Control in North Sea Topside Processes","authors":"M. Jordan, E. Temple, A. Sham, H. Williams, C. McCallum","doi":"10.2118/193613-MS","DOIUrl":"https://doi.org/10.2118/193613-MS","url":null,"abstract":"\u0000 Inorganic scale control of sulphate and carbonate scales with polymer, phosphonate and phosphate ester scale inhibitors is well established within the oilfield service industry. The environments in which these chemical work best have been published such as vinyl sulphonates are known to be very effective for sulphate scale control in low temperatures whereas phosphonates are much less effective under these same conditions but improve at higher temperatures. What is less well understood is the potential for synergistic interaction with blends of polymers/phosphonates/phosphate esters to give reduced treatment rates, lower chemical discharge volumes and potentially lower treatment cost.\u0000 In this paper evaluation of two North Sea produced waters will be outlined. Both produced brines have a high barium sulphate scale tendency but differ in the temperature at which the fluids arrive and depart the topside process one case with a temperature of 20C and the other at 90C. Static bottle test data will be presented to evaluate the crystal growth performance of single scale inhibitors and the improvements observed when blends of these same inhibitors are applied. Select dynamic tube blocking tests data to evaluate nucleation inhibition will also be presented so that mechanism of inhibition for the blended chemicals can clearly be highlighted.\u0000 The generic inhibitor evaluated included vinyl sulphonates co polymer, phosphate esters, poly aspartic acid. In the lower temperature environment, it was observed that a vinyl sulphonate/phosphate ester blend was more effective than either of the components by themselves. Poly aspartic acid blende with phosphate ester also give a synergistic interaction but the performance of this chemical required higher treatment rates than the vinyl sulphonate co polymer blend. At higher temperature the overall treatment rates were reduced as the sulphate scale saturation values were reduced and the synergistic effects of the polymers and phosphate ester blends were evident.\u0000 As well as classic static bottle tests performance tests were carried out in the presence of reservoir solids with stirring to further understand if the interaction of the generic chemicals within the blends with suspended solids would reduce the observed performance in the solids free test solutions.\u0000 The current regulatory challenges with REACH mean that the methods outlined in this study offer the potential to reduce chemical treatment rate, cost and environmental impact by evaluating the synergistic interaction of the current range of commercially available scale inhibitors so cutting out the very high registration costs/ time delays to the market associated with new molecule development.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84526371","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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