Study of Fracturing Fluid on Gel Breaking Performance and Damage to fracture conductivity

Wang, Jie; Huang, Yixiao; Zhang, Yan; Zhou, Fujian; Yao, Erdong; Wang, Rui

doi:10.1016/j.petrol.2020.107443

Cited by 41 publications

(12 citation statements)

References 19 publications

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“…In the process of hydraulic fracturing, many factors, such as the gel-breaker residue, water blockage, emulsification phenomenon, and reservoir sensitivity, will cause the reservoir matrix to become damaged, which is not conducive to the flow of crude oil from the matrix into the fractures [25][26][27]. Formation damage experiments were evaluated by a multi-functional core flow system as shown in Figure 2.…”

Section: Formation Damage Testmentioning

confidence: 99%

“…Once the highly viscous sand-carrying fluid completes the migration and settlement of the proppant, a gel breaker is required to break up the formed guar fracturing fluid and reduce its viscosity so that it can be easily re-discharged from the fractures. Commonly used gel-breaking methods include oxidative breakage, potential acid breakage, and biological enzyme breakage [27].…”

Section: Gel-breaking Performancementioning

confidence: 99%

“…of the proppant, a gel breaker is required to break up the form reduce its viscosity so that it can be easily re-discharged fro used gel-breaking methods include oxidative breakage, pote logical enzyme breakage [27].…”

Section: Gel-breaking Performancementioning

confidence: 99%

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Reusing Flowback and Produced Water with Different Salinity to Prepare Guar Fracturing Fluid

Yao

et al. 2021

Energies

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Economical and environmental concerns have forced the oil and gas industry to consider reusing flowback and produced water for fracturing operations. The major challenge is that the high-salinity of flowback water usually prevents its compatibility with several fracturing fluid additives. In this paper, the authors explored an economic and effective method to prepare guar fracturing fluids with different salinity waters. The main research idea was to use chelating agents to mask metal ions, such as calcium and magnesium, that are harmful to crosslinking. Firstly, a complexometric titration test was conducted to measure the chelating ability of three chelating agents. Secondly, through viscosity, crosslinking, and hanging tests, it was verified that the complex masking method could cope with the problem of high-valence metal ions affecting crosslinking. Thirdly, the preferred chelating agent was mixed with several other additives, including thickeners, crosslinkers, and pH regulators, to prepare the novel guar fracturing fluid. The comprehensive performances of the novel fluid system were tested such as temperature and shear resistance, friction reduction, gel-breaking performance, and core damage rate. The results show that the organophosphate chelating agent (i.e., CA-5) had the greatest ability to chelate calcium and magnesium ions. There was a good linear relationship between the dosage of CA-5 and the total molar concentration of calcium and magnesium ions in brine water. The main mechanism was that the chelating agent formed a complex with calcium and magnesium ions at a chelation ratio of 1:5. The test results of the comprehensive performance evaluation indicate that the prepared guar fracturing fluid met the requirements for field application, and the lower the salinity of the flowback water, the more it is economical and effective.

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Section: Formation Damage Testmentioning

confidence: 99%

Section: Gel-breaking Performancementioning

confidence: 99%

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Reusing Flowback and Produced Water with Different Salinity to Prepare Guar Fracturing Fluid

Yao

et al. 2021

Energies

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“…However, the crosslinked gel cannot completely degrade and its residues can adsorb on the rock surface, thus inhibiting the hydrocarbon flow from the reservoir rock to the created fractures; meanwhile, the residues can also plug the propped fractures and reduce the fracture conductivity 15 – 17 . Laboratory measurements have shown that the conductivity reduction due to gel residues can be as large as 50–60% 18 , 19 . Slickwater is made of water and the friction reducer, whose concentration is typically about 0.1% 20 .…”

Section: Introductionmentioning

confidence: 99%

Field experiments of different fracturing designs in tight conglomerate oil reservoirs

Zhang¹,

Zhang³

et al. 2022

Sci Rep

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Mahu oilfield is currently the largest tight conglomerate reservoir in the world, where Ma-131 and Ma-18 plays are the first two commercially developed reservoirs. In order to reduce the cost and explore the best fracturing parameters, field experiments have been conducted in these two plays since 2017. Types of proppant and fracturing fluid, the slickwater ratio, and the fracture spacing are mainly changed for comparison, and fracturing effects are evaluated to establish a reference for developing neighboring plays in the Mahu oilfield. This paper summarizes the fracturing parameters and production histories of 74 wells in Ma-131 and Ma-18 plays during four years of field operations. Firstly, results indicate that silica sands perform similar to ceramics in the Ma-131 play where the reservoir depth is smaller than 3300 m; however, in the Ma-18 play where the reservoir is deeper than 3500 m, increasing the sand volume by 1.1–1.2 times still cannot reach the production in wells using ceramics. Secondly, when the fracture spacing is reduced, both oil production and water flowback become even smaller in wells using sands than those using ceramics; this is due to the increase of closure pressure and decrease of fluid volume per cluster respectively. Thirdly, when the crosslinked guar is replaced by the slickwater, no obvious change in oil production is noticed even though the volume of fracturing fluid is almost doubled; limited lengths of propped fractures due to the poor proppant-carrying ability of slickwater likely offset the production enhancement from the decrease of formation damage by slickwater. This paper summarizes learnings from the field experiments during the four-year development of the Mahu oilfield, and help guide the optimization of hydraulic fracturing parameters for future wells.

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“…However, the crosslinked gel cannot completely degrade and its residues can adsorb on the rock surface, thus inhibiting the hydrocarbon ow from the reservoir rock to the created fractures; meanwhile, the residues can also plug the propped fractures and reduce the fracture conductivity (Sarwar et al, 2011;Xu et al, 2011;Zhang et al, 2016). Laboratory measurements have shown that the conductivity reduction due to gel residues can be as large as 50% -60% (Kim and Losacano, 1985;Wang et al, 2020). Slickwater is made of water and the friction reducer, whose concentration is typically about 0.1% (Liang et al, 2017).…”

Section: Introductionmentioning

confidence: 99%

Field Experiments of Different Fracturing Designs in Tight Conglomerate Oil Reservoirs

Dai-yan

Zhang

et al. 2021

Preprint

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Mahu oilfield is currently the largest tight conglomerate reservoir in the world, where Ma-131 and Ma-18 plays are the first two commercially developed reservoirs. In order to reduce the cost and explore the best fracturing parameters, field experiments have been conducted in these two plays since 2017. The types of proppant and fracturing fluid, the slickwater ratio, and the fracture spacing are mainly changed for comparison, and fracturing effects are evaluated to establish a reference for developing the neighboring plays in Mahu oilfield. This paper summarizes the fracturing parameters and production histories of 74 wells in Ma-131 and Ma-18 plays during four years of field operations. Firstly, results indicate that silica sands perform similar to ceramics in the Ma-131 play where the reservoir depth is smaller than 3300 m; however, in the Ma-18 play where the reservoir is deeper than 3500m, increasing the sand volume by 1.1 times still cannot reach the production in wells using ceramics. Secondly, when the fracture spacing is reduced, both oil production and water flowback become even smaller in wells using sands than those using ceramics; this is due to the increase of closure pressure and decrease of fluid volume per cluster respectively. Thirdly, when the crosslinked guar is replaced by the slickwater, no obvious change in oil production is noticed even though the volume of fracturing fluid is almost doubled; limited lengths of propped fractures due to the poor proppant-carrying ability of slickwater likely offset the production enhancement from the decrease of formation damage by slickwater. This paper summarizes learnings from the field experiments during four years of development in Mahu oilfield, and help guide the optimization of hydraulic fracturing parameters for future wells.

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Study of Fracturing Fluid on Gel Breaking Performance and Damage to fracture conductivity

Cited by 41 publications

References 19 publications

Reusing Flowback and Produced Water with Different Salinity to Prepare Guar Fracturing Fluid

Reusing Flowback and Produced Water with Different Salinity to Prepare Guar Fracturing Fluid

Field experiments of different fracturing designs in tight conglomerate oil reservoirs

Field Experiments of Different Fracturing Designs in Tight Conglomerate Oil Reservoirs

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