A review of recent advances in foam-based fracturing fluid application in unconventional reservoirs

Yekeen, Nurudeen; Padmanabhan, Eswaran; Idris, Ahmad Kamal

doi:10.1016/j.jiec.2018.05.039

Cited by 100 publications

(68 citation statements)

References 97 publications

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“…Shale swelling is one of the main technical concerns associated with the use of water-based hydraulic fracturing fluids. 9 It is also known that water-based fracturing fluids consume a substantial amount of freshwater, which endangers drinking water resources. Besides, the various types of chemical additives that are tailored within the composition of water-based fracturing fluids necessitate a great deal of disposals for the recovered water.…”

Section: Introductionmentioning

confidence: 99%

“… 20 Apart from reducing environmental footprints, foam-based fracturing fluids have a better proppant-carrying capacity than water-based fluids that allow efficient distribution of proppants in the fractures. 9 The proppants’ settling velocity in the foam is about 85% lower than that in water due to the lower viscosity of water compared to foam. 21 Other advantages of foam-based fracturing fluids include low fluid loss, low formation damage, and reduced flowback time.…”

Section: Introductionmentioning

confidence: 99%

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Synergetic Effect of Surfactant Concentration, Salinity, and Pressure on Adsorbed Methane in Shale at Low Pressure: An Experimental and Modeling Study

et al. 2020

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The influence of an anionic surfactant, a cationic surfactant, and salinity on adsorbed methane (CH 4 ) in shale was assessed and modeled in a series of systematically designed experiments. Two cases were investigated. In case 1, the crushed Marcellus shale samples were allowed to react with anionic sodium dodecyl sulfate (SDS) and brine. In case 2, another set of crushed Marcellus shale samples were treated with cetyltrimethylammonium bromide (CTAB) and brine. The surfactant concentration and salinity of brine were varied following the Box–Behnken experimental design. CH 4 adsorption was then assessed volumetrically in the treated shale at varying pressures (1–50 bar) and a constant temperature of 30 °C using a pressure equilibrium cell. Mathematical analysis of the experimental data yielded two separate models, which expressed the amount of adsorbed CH 4 as a function of SDS/CTAB concentration, salinity, and pressure. In case 1, the highest amount of adsorbed CH 4 was about 1 mmol/g. Such an amount was achieved at 50 bar, provided that the SDS concentration is kept close to its critical micelle concentration (CMC), which is 0.2 wt %, and salinity is in the range of 0.1–20 ppt. However, in case 2, the maximum amount of adsorbed CH 4 was just 0.3 mmol/g. This value was obtained at 50 bar and high salinity (∼75 ppt) when the CTAB concentration was above the CMC (>0.029 wt %). The findings provide researchers with insights that can help in optimizing the ratio of salinity and surfactant concentration used in shale gas fracturing fluid.

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Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Synergetic Effect of Surfactant Concentration, Salinity, and Pressure on Adsorbed Methane in Shale at Low Pressure: An Experimental and Modeling Study

et al. 2020

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“…With the increasing oil and gas consumption, more attentions have recently been directed to exploit the unconventional resources (Schmoker, 2002;Jia, 2017;Yekeen et al, 2018;Gao et al, 2018;Chen et al, 2019). As an important and unconventional clean fossil fuel, tight oil is expected to play an increasingly important role in meeting the energy demand (Song et al, 2015;Yang et al, 2015a;Song and Yang, 2017;Wang M. et al, 2018;Amjed et al, 2019;Jiang et al, 2020a).…”

Section: Introductionmentioning

confidence: 99%

Effect of Stress-Sensitive Fracture Conductivity on Transient Pressure Behavior for a Multi-Well Pad With Multistage Fractures in a Naturally Fractured Tight Reservoir

Meng

Tan

et al. 2020

Front. Energy Res.

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This paper presents a semianalytical solution for evaluating transient pressure behavior of a multi-well pad with multistage fractures in a naturally fractured tight reservoir by considering the stress-sensitive effect imposed by both natural and hydraulic fractures. More specifically, the model pertaining to matrix/natural fractures is considered as a dual-porosity continuum, while its analytical flow model can be obtained by use of a slab-source function in the Laplace domain. The hydraulic fracture model is solved by discretizing each fracture into small segments to describe the flow behavior, while stress sensitivity in both the natural fracture (NF) subsystem and hydraulic fracture (HF) subsystem has been taken into account. To validate the newly developed semianalytical model, its solution has been obtained and compared with those of a commercial numerical simulator. By generating the type curves, there may exhibit eight flow regimes: pure wellbore storage, skin effect transition flow, linear flow regime within HFs, early radial flow, biradial flow, transition flow, pseudo-steady diffusion, and the late-time pseudo-radial flow. Furthermore, late-time flow regimes are found to be significantly distorted by the multi-well pressure interference. The smaller the well-rate ratio is, the more distorted the pressure and pressure derivative curves will be. In addition, well spacing and fracture length are found to dominate the flow behavior when multi-well pressure interference occurs. As the well spacing is decreased, the fracture length is increased, and thus occurrence of multi-well pressure interference is initiated earlier. Permeability moduli of NFs and HFs impose no impact on the multi-well pressure interference; however, it can distort flow regimes, leading to a severe distortion of pressure and pressure derivative curves. Similarly, the effect of HF permeability modulus on the flow in a hydraulic fracture, the minimum fracture conductivity is another key factor affecting the “hump” on the pressure curve. As the crossflow coefficient is increased, flow exchange between matrix and NFs is increased. With an increase in the storage ratio, flow exchange lasts longer and the second “dip” on the pressure curve becomes deeper.

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“…These types of unconventional reservoirs possess a plethora of distinctive features, which include small pore throats, high specific surface area, severe heterogeneity and presence of low viscosity crude oil [5,6,7]. For these reasons, some researchers have studied gas and water injection to restore reservoir energy for enhanced oil recovery (EOR).…”

Section: Introductionmentioning

confidence: 99%

Feasibility Study of Applying Modified Nano-SiO2 Hyperbranched Copolymers for Enhanced Oil Recovery in Low-Mid Permeability Reservoirs

et al. 2019

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To improve oil recovery significantly in low-mid permeability reservoirs, a novel modified nano-SiO2 hyperbranched copolymer (HPBS), consisting of polyacrylamide as hydrophilic branched chains and modified nano-SiO2 as the core, was synthesized via an in situ free radical polymerization reaction. The structure and properties of the hyperbranched copolymer were characterized through a range of experiments, which showed that HBPS copolymers have better stability and enhanced oil recovery (EOR) capacity and also smaller hydrodynamic radius in comparison with hydrolyzed polyacrylamide (HPAM). The flooding experiments indicated that when a 1000 mg/L HPBS solution was injected, the resistance factor (RF) and residual resistance factor (RRF) increased after the injection. Following a 98% water cut after preliminary water flooding, 0.3 pore volume (PV) and 1000 mg/L HPBS solution flooding and extended water flooding (EWF) can further increase the oil recovery by 18.74% in comparison with 8.12% oil recovery when using HPAM. In this study, one can recognize that polymer flooding would be applicable in low-mid permeability reservoirs.

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A review of recent advances in foam-based fracturing fluid application in unconventional reservoirs

Cited by 100 publications

References 97 publications

Synergetic Effect of Surfactant Concentration, Salinity, and Pressure on Adsorbed Methane in Shale at Low Pressure: An Experimental and Modeling Study

Synergetic Effect of Surfactant Concentration, Salinity, and Pressure on Adsorbed Methane in Shale at Low Pressure: An Experimental and Modeling Study

Effect of Stress-Sensitive Fracture Conductivity on Transient Pressure Behavior for a Multi-Well Pad With Multistage Fractures in a Naturally Fractured Tight Reservoir

Feasibility Study of Applying Modified Nano-SiO2 Hyperbranched Copolymers for Enhanced Oil Recovery in Low-Mid Permeability Reservoirs

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