Scale Inhibition: A Challenge and a Mitigation Study in Fracturing with High-Brine Water

Vo, Loan; Cortez, J.; Hoeman, K.; Rahal, Raed; Biyani, Mahesh

doi:10.2118/183728-ms

Cited by 5 publications

(3 citation statements)

References 5 publications

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“…However, using seawater as a base water to design fracturing fluids requires solving various problems resulting from the high salinity and total dissolved solids (TDS) of seawater and the presence of calcium, magnesium and sulfate ions that cause delayed hydration, alteration of the crosslinking mechanism, fluid instability at high temperatures and high scale formation [65]. Sulfate ions from seawater can react with barium from the formation water to form a barium sulfate scale that causes formation damage and restrictions in the flow through pipes [65,67]. To effectively mitigate this serious scale problem, a combination of water treatment and chemical scale inhibitor is recommended.…”

Section: Seawater Fracturing Technologymentioning

confidence: 99%

“…To effectively mitigate this serious scale problem, a combination of water treatment and chemical scale inhibitor is recommended. Nanofiltration (NF) technology can be successfully applied to water treatment because it specifically removes sulfate ions from water sources with a high sulfate content [67]. A combination of NF technology and sulfonatebased scale inhibitor offers effective scale inhibition for seawater fracturing technology applied in high-temperature formations [67].…”

Section: Seawater Fracturing Technologymentioning

confidence: 99%

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Fracturing Fluids and Their Application in the Republic of Croatia

Gaurina-Međimurec

Brkić

Topolovec³

et al. 2021

Applied Sciences

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Hydraulic fracturing operations are performed to enhance well performance and to achieve economic success from improved production rates and the ultimate reserve recovery. To achieve these goals, fracturing fluid is pumped into the well at rates and pressures that result in the creation of a hydraulic fracture. Fracturing fluid selection presents the main requirement for the successful performance of hydraulic fracturing. The selected fracturing fluid should create a fracture with sufficient width and length for proppant placement and should carry the proppant from the surface to the created fracture. To accomplish all those demands, additives are added in fluids to adjust their properties. This paper describes the classification of fracturing fluids, additives for the adjustment of fluid properties and the requirements for fluid selection. Furthermore, laboratory tests of fracturing fluid, fracture stimulation design steps are presented in the paper, as well as a few examples of fracturing fluids used in Croatia with case studies and finally, hydraulic fracturing performance and post-frac well production results. The total gas production was increased by 43% and condensate production by 106% in selected wells including wellhead pressure, which allowed for a longer production well life.

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Section: Seawater Fracturing Technologymentioning

confidence: 99%

Section: Seawater Fracturing Technologymentioning

confidence: 99%

Fracturing Fluids and Their Application in the Republic of Croatia

Gaurina-Međimurec

Brkić

Topolovec³

et al. 2021

Applied Sciences

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“…e formed sulfate precipitates could lead to severe formation damages, overall reduction in hydrocarbon production capacity, and some other adverse e ects [6,7]. erefore, the sulfate concentration in seawater should be reduced by >90% for a successful seawater hydraulic fracturing, especially when normal scale mitigation strategies perform poorly in high-temperature reservoirs [8,9].…”

Section: Introductionmentioning

confidence: 99%

Removal of High-Concentration Sulfate from Seawater by Ettringite Precipitation

Hou¹,

Alghunaimi

Han

et al. 2022

Journal of Chemistry

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Due to the worldwide scarcity of fresh water, seawater becomes an alternative base fluid in hydraulic fracturing for oil and gas production. However, the injection of seawater that contains high concentration of sulfate will induce the scale formation and thus reduce hydrocarbon production. One of the most effective ways to solve this problem is to remove sulfate ions from seawater before fracturing application. The objective of this study is to develop an effective and environment-friendly approach to remove sulfate ions from seawater based on coprecipitation of SO42− with NaAlO2 and CaO as ettringite (Ca6Al2(SO4)3(OH)12·26H2O). Residual sulfate concentration in treated seawater was determined when NaAlO2 and CaO dosed at different molar ratios to sulfate. Results showed the efficiency of sulfate removal was more than 90% (4290 ppm to ∼400 ppm) when Al : Ca : S = 2 : 6 : 1. It was found the sulfate precipitation completed in 15 mins with stirring under an alkaline condition (pH ≈ 12) and was not affected by temperature (15°C to 45°C). Increasing the Na+ concentration from 0 to 25,000 ppm in waters resulted in the increment of residual sulfate concentration from 250 to ∼600 ppm, decreasing the removal efficiency. Besides, the analysis of Ca2+ and Mg2+ in treated seawater showed the Ca2+ concentrations were on the similar level as that before the treatment and Mg2+ was removed in the precipitation process, which is beneficial to the application of the treated seawater. The morphology and element analysis of the collected precipitates showed that the ettringites were in a layered shape with composition between Ca6Al2(SO4)3(OH)12 and Ca4Al2(SO4)(OH)12 at the optimized chemical dosage; therefore, the developed ettringite precipitation method could effectively remove sulfate from seawater without toxic chemicals involved, which benefits seawater hydraulic fracturing in an economic way, and this contributes to water sustainability.

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Mitigation of Scaling Potential of Seawater in High Temperature Environment Using Phosphonate Scale Inhibitor

Yamak

Nasr‐El‐Din

Rahim

et al. 2019

Day 2 Tue, November 12, 2019

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Laboratory analysis was conducted in order to study the effect of a phosphonate scale inhibitor on a mixture of hypersaline Arabian Gulf seawater and formation water under high temperature/high pressure (HT/HP) applications. The objective of this study was to identify the minimum scale inhibitor concentration required at various temperatures to achieve a cost-effective solution in minimizing the formation of common oilfield scales. Development of such a product would aid in the utilization of seawater-based fracturing fluids by controlling the scaling tendencies of the system, especially when exposed to formation waters. Utilizing a scaling software, various types of scales were modeled by testing different seawater/formation water ratios at temperatures ranging from 270 – 330°F. A dynamic scale loop was used which allowed seawater and formation water to be pumped into the system, thereby generating differential pressure data. The exponential increase in pressure would indicate scale formation. Various concentrations of scale inhibitor were then introduced to the mixtures and tested to determine the minimum scale inhibitor required for scale mitigation. Compatibility tests were also conducted to test for the efficacy of the scale inhibitor. Based on the scaling software, barite was identified as the primary scale generated. Barite scale has a low solubility of 2 mg/L and is one of the most difficult scales to mitigate. The highest concentration of barite scale occurred in a 50/50 ratio mixture of formation water and seawater. For all the temperatures tested, the scale loop was run at the concentration with the most barium sulfate present. The results for this research concluded that at 270°F and 300°F, the minimum scale inhibitor concentration was 2000 ppm and 1500 ppm, respectively. Both treatments successfully mitigated the following types of scales: barium sulfate, calcium sulfate(s), and strontium sulfate. At 330°F, the minimum scale inhibitor concentration was lower. This decreasing trend in scale inhibitor concentration as temperature was increased is attributed to the temperature constraint of phosphonate scale inhibitors. As a result, adding the phosphonate scale inhibitor contributed to the formation of calcium phosphonate complexes that led to the rise in pressure in the scale loop test. This hindered the efficiency of the treatment and portrayed the dramatic effects of temperature and inhibitor concentration on scale mitigation. This research pushes the thermal constraints of a phosphonate scale inhibitor up to 330°F to test its efficiency and overall treatment integrity. There are also fracturing fluid applications introduced utilizing a seawater source with one of the highest total dissolved solids (TDS) concentrations in the world. Barium sulfate and other scales were successfully mitigated at various high-temperature applications for these systems utilizing a phosphate scale inhibitor.

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Scale Inhibition: A Challenge and a Mitigation Study in Fracturing with High-Brine Water

Cited by 5 publications

References 5 publications

Fracturing Fluids and Their Application in the Republic of Croatia

Fracturing Fluids and Their Application in the Republic of Croatia

Removal of High-Concentration Sulfate from Seawater by Ettringite Precipitation

Mitigation of Scaling Potential of Seawater in High Temperature Environment Using Phosphonate Scale Inhibitor

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