In situ generated proppants for shale reservoirs

Tong, Songyang; Miller, Chammi; Mohanty, Kishore K.

doi:10.1016/j.fuel.2022.123776

Cited by 6 publications

(5 citation statements)

References 25 publications

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“…The success of hydraulic fracturing relies on a multitude of parameters such as proppant transport and placement efficiency, ,− proppant strength relative to the downhole minimum horizontal stress, − hardness of the proppant and fractured formation shaping the proppant embedment tendency, − fracturing fluid leak-off into the formation and its flow-back, − and fracture propagation. − Although surface properties directly impact flow and transport, there are very few studies that examined the effect of proppant wettability characteristics on fracture flow performance. Those studies performed either microscale or macroscale core flooding or proxy experiments like sandpack flooding and column testing to infer the fluid flow efficiency for different proppant affinities.…”

Section: Introductionmentioning

confidence: 99%

Pore-Scale Study of Wettability Alteration and Fluid Flow in Propped Fractures of Ultra-Tight Carbonates

Elkhatib

Xie

Mohamed³

et al. 2023

Langmuir

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The in situ change in oil flow behavior inside propped fractures due to wettability alteration of proppant grains and fracture surfaces was thoroughly investigated for the first time in this study. A series of microscale flow experiments were performed in mixed-wet fractured and propped miniature ultra-tight carbonate cores where the effect of wettability on oil bridging and fracture oil layer integrity was probed during oil production. During the initial production, proppant wettability changed toward an intermediate-wet state (contact angle (CA) = 96°) while that of fracture surfaces became strongly oil-wet (CA = 139°). Consequently, the fracture oil layer grew in size on both fracture surfaces and imbibed into the proppant pack through piston-like displacement and pore body filling until oil bridges were formed during oil injection. However, subsequent waterflooding induced thinning and rupturing of those bridges due to the accompanying reduction in the threshold capillary pressure of the proppant at higher aging times. The in situ chemical treatment of the proppant by a cationic surfactant (dodecyl tri-methyl ammonium bromide) could reverse its wettability toward weakly water-wet state (CA = 78°) after oil solubilization from the sand grains followed by substitutive surfactant adsorption. Surfactant injection also impacted the wettability of the fracture surface due to oil solubilization, reducing its mean contact angle down to an intermediate range (CA = 99°). As a result, the following oil production cycle yielded a smaller fracture oil layer. The surfactant effect on proppant wettability lasted for 2 weeks while its effect on fracture wettability lasted for more than 6 weeks. Similar flow cycles were performed with an anionic nanoparticle (graphene quantum dot) with hydrogen bonding ability. The nanoparticle solution yielded a quick reduction of the proppant and fracture surface contact angles to nearly 77° and 115°, respectively. Proppant wettability alteration occurred because the nanoparticles self-assembled at the three-point contact region between adsorbed oil and quartz surfaces, leading to oil solubilization in intermediate-wet regions while oil-wet regions remained unchanged. Therefore, re-introducing oil into the fracture instantaneously re-instated the initial wettability state of proppant grains (CA = 88°), deeming the nanoparticle solution ineffective. This study revealed that oil production through hydraulic fractures can be enhanced by monitoring the wettability of the proppant pack. If the production has a high water cut, it is beneficial to use chemical agents that reduce the proppant contact angles to a weakly water-wet state in order to preserve the hydraulic conductivity of the oil layer.

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Section: Introductionmentioning

confidence: 99%

Pore-Scale Study of Wettability Alteration and Fluid Flow in Propped Fractures of Ultra-Tight Carbonates

Elkhatib

Xie

Mohamed³

et al. 2023

Langmuir

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“…In complex fracture networks, a solid proppant may not be able to turn effectively at the junction of cross fractures, which limits the distance the proppant can travel in branching fractures, It may even be possible to bridge at fracture intersections, resulting in the proppant supporting only the main fracture surface . However, the fracture network may be closed due to proppant-free proppant support, which reduces the conductivity of the fracture network. , …”

Section: Introductionmentioning

confidence: 99%

Experimental Study on a Liquid–Solid Phase-Change Autogenous Proppant Fracturing Fluid System

et al. 2023

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In this paper, a liquid–solid phase-change autogenous proppant fracturing fluid system (LSPCAP) was proposed to solve the problems that was caused by “sand-carrying” in conventional fracturing technology in oil and gas fields. The characteristic of the new fluid system is that no solid particles will be injected in the whole process of fracturing construction except liquids. The fluid itself will transform into solid particles under the formation temperature to resist the closure stress in the fractures. There are two kinds of liquids that make up the new fracturing fluid system. One of the liquids is called phase-change liquid (PCL) which occurs in the liquid–solid phase change under the formation temperature to form solid particles. Another is called nonphase-change liquid (NPCL) which controls the dispersity and size of PCL in the two-phase fluid system. Based on the molecular interaction theory and organic chemistry, bisphenol-A epoxy resin was selected as the building unit of the PCL, and the NPCL consisted of deionized water + nonionic surfactant. The test results indicated that the new fracturing fluid shows the properties of non-Newtonian fluid and has no wall-building property. The new fluid system has good compatibility with the formation fluid, conventional fracturing fluid, and hydrochloric acid. Through the filtration test, the filtration coefficients of PCL, NPCL, and mixture are found to be 1.56 × 10–4 m/s1/2, 2.66 × 10–4 m/s1/2, and 1.7 × 10–4 m/s1/2, respectively, and the damage rate of mixture and NPCL is 18 and 17.7%. The friction test results show that the resistance reduction rate reaches 69% when the volume ratio of PCL and NPCL is 1:10. The shear rate and time only affect the size of the autogenous solid particles, and the sorting coefficient (S) of the particles is 1.04–1.73, indicating good sorting. Crushing resistance and conductivity test results show that the crush rate of autogenous solid particles is 3.56–8.42%. The conductivity of the autogenous solid particles is better than those of quartz sand and ceramsite under a pressure of 10–30 MPa.

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“…For optimization of propping and conductivity of multilevel fractures, a lot of efforts have been put in research on the influencing factors of proppant conductivity [15][16][17] and the effect of proppant embedment on fracture conductivity [18][19][20][21][22], but the softening mechanism of deep shale is rarely reported [23,24]. Tong et al measured the rock hardness after immersion in liquid, the hardness data showed that properly designed formulations could avoid the shale softening and even increase the hardness of the fracture surface (from 230 to 280 MPa) [30].…”

Section: Introductionmentioning

confidence: 99%

Study on Postfrac Softening Mechanism of Deep Marine Shale Reservoir in South Sichuan Basin

Zhou

Duan

He³

et al. 2023

Geofluids

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Shale softening is an important factor affecting fracturing effect. Through the Brinell hardness measurement of deep marine shale reservoir in South Sichuan Basin, the softening mechanism of shale after fracturing is explored. Through laboratory test, the key parameters of shale Brinell hardness measurement are proposed as follows: indenter size 5 mm, loading force 613 N, 1226 N, and 2452 N, and holding time > 10 s . It is determined that the content of quartz and clay is the main factor controlling the Brinell hardness of dry shale samples, and the mineral composition, microstructure, and fluid system jointly affect the shale softening process. The results show that (1) the marine shale in the South Sichuan Basin softens obviously, with the Brinell hardness decrease by more than 50%, (2) microfracture propagation and clay hydration expansion accelerate the shale softening process, leading to the decreased porosity and the increased number of micro-pores, and (3) the softening process is different between middeep shale and deep shale, with the latter characterized by high initial hardness and low softening rate.

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In situ generated proppants for shale reservoirs

Cited by 6 publications

References 25 publications

Pore-Scale Study of Wettability Alteration and Fluid Flow in Propped Fractures of Ultra-Tight Carbonates

Pore-Scale Study of Wettability Alteration and Fluid Flow in Propped Fractures of Ultra-Tight Carbonates

Experimental Study on a Liquid–Solid Phase-Change Autogenous Proppant Fracturing Fluid System

Study on Postfrac Softening Mechanism of Deep Marine Shale Reservoir in South Sichuan Basin

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