scholarly journals Experimental Investigation of the Impacts of Fracturing Fluid on the Evolution of Fluid Composition and Shale Characteristics: A Case Study of the Niutitang Shale in Hunan Province, South China

Energies ◽  
2020 ◽  
Vol 13 (13) ◽  
pp. 3320
Author(s):  
Jingqiang Tan ◽  
Guolai Li ◽  
Ruining Hu ◽  
Lei Li ◽  
Qiao Lyu ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Mineral Dissolution ◽  
Hunan Province ◽  
Fluid Composition ◽  
Fracturing Fluid ◽  
Specific Chemical ◽  
Metal Elements ◽  
Fracturing Process ◽  
Geochemical Reactions ◽  
Shale Reservoirs

Hydraulic fracturing is a widely used technique for oil and gas extraction from ultra-low porosity and permeability shale reservoirs. During the hydraulic fracturing process, large amounts of water along with specific chemical additives are injected into the shale reservoirs, causing a series of reactions the influence the fluid composition and shale characteristics. This paper is focused on the investigation of the geochemical reactions between shale and fracturing fluid by conducting comparative experiments on different samples at different time scales. By tracking the temporal changes of fluid composition and shale characteristics, we identify the key geochemical reactions during the experiments. The preliminary results show that the dissolution of the relatively unstable minerals in shale, including feldspar, pyrite and carbonate minerals, occurred quickly. During the process of mineral dissolution, a large number of metal elements, such as U, Pb, Ba, Sr, etc., are released, which makes the fluid highly polluted. The fluid–rock reactions also generate many pores, which are mainly caused by dissolution of feldspar and calcite, and potentially can enhance the extraction of shale gas. However, precipitation of secondary minerals like Fe-(oxy) hydroxides and CaSO4 were also observed in our experiments, which on the one hand can restrict the migration of metal elements by adsorption or co-precipitation and on the other hand can occlude the pores, therefore influencing the recovery of hydrocarbon. The different results between the experiments of different samples revealed that mineralogical texture and composition strongly affect the fluid-rock reactions. Therefore, the identification of the shale mineralogical characteristics is essential to formulate fracturing fluid with the lowest chemical reactivity to avoid the contamination released by flowback waters.

scholarly journals Hydraulic Fracturing: Paving the Way for a Sustainable Future?

2014 ◽  
Vol 2014 ◽  
pp. 1-10 ◽  
Author(s):  
Jiangang Chen ◽  
Mohammed H. Al-Wadei ◽  
Rebekah C. M. Kennedy ◽  
Paul D. Terry
Keyword(s):  
Hydraulic Fracturing ◽  
Health Care Professionals ◽  
The United States ◽  
Federal State ◽  
Future Research ◽  
Wastewater Management ◽  
Fluid Composition ◽  
Fracturing Fluid ◽  
Fracturing Process ◽  
Industrial Level

With the introduction of hydraulic fracturing technology, the United States has become the largest natural gas producer in the world with a substantial portion of the production coming from shale plays. In this review, we examined current hydraulic fracturing literature including associated wastewater management on quantity and quality of groundwater. We conclude that proper documentation/reporting systems for wastewater discharge and spills need to be enforced at the federal, state, and industrial level. Furthermore, Underground Injection Control (UIC) requirements under SDWA should be extended to hydraulic fracturing operations regardless if diesel fuel is used as a fracturing fluid or not. One of the biggest barriers that hinder the advancement of our knowledge on the hydraulic fracturing process is the lack of transparency of chemicals used in the practice. Federal laws mandating hydraulic companies to disclose fracturing fluid composition and concentration not only to federal and state regulatory agencies but also to health care professionals would encourage this practice. The full disclosure of fracturing chemicals will allow future research to fill knowledge gaps for a better understanding of the impacts of hydraulic fracturing on human health and the environment.

Investigating the Use of CO2 as a Hydraulic Fracturing Fluid for Water Sustainability and Environmental Friendliness

2021 ◽  
Author(s):  
Sherif Fakher ◽  
Abdulaziz Fakher
Keyword(s):  
Carbon Dioxide ◽  
Hydraulic Fracturing ◽  
Oil And Gas ◽  
Reservoir Rock ◽  
Future Research ◽  
Strong Impact ◽  
Fracturing Fluid ◽  
Gas Reservoirs ◽  
Environmental Friendliness ◽  
Shale Reservoirs

Abstract Hydraulic fracturing is the process by which many unconventional shale reservoirs are produced from. During this process, a highly pressurized fluid, usually water, is injected into the formation with a proppant. The fracturing fluid breaks the formation thus increasing its permeability, and the proppant ensures that the formation remains open. Although highly effective, hydraulic fracturing has several limitations including relying on a highly valuable commodity such as water. This research investigates the applicability of carbon dioxide as a fracturing fluid instead of water, and studies the main advantages and limitation of such a procedure. The main properties that could have a strong impact on the applicability of carbon dioxide based hydraulic fracturing are studied; these factors include carbon dioxide properties, proppant properties, and reservoir rock, fluid, and thermodynamic properties. This research aims to function as an initial introduction and roadmap to future research investigating the applicability of carbon dioxide as a fracturing fluid in unconventional oil and gas reservoirs.

An Efficient Numerical Hybrid Model for Multiphase Flow in Deformable Fractured-Shale Reservoirs

SPE Journal ◽  
2018 ◽  
Vol 23 (04) ◽  
pp. 1412-1437 ◽  
Author(s):  
Xia Yan ◽  
ZhaoQin Huang ◽  
Jun Yao ◽  
Yang Li ◽  
Dongyan Fan ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hybrid Model ◽  
Hydraulic Fractures ◽  
Fluid Exchange ◽  
Flow Process ◽  
Numerical Examples ◽  
Fracturing Process ◽  
The Matrix ◽  
Shale Reservoirs ◽  
Porosity Model

Summary After hydraulic fracturing, a shale reservoir usually has multiscale fractures and becomes more stress-sensitive. In this work, an adaptive hybrid model is proposed to simulate hydromechanical coupling processes in such fractured-shale reservoirs during the production period (i.e., the hydraulic-fracturing process is not considered and cannot be simulated). In our hybrid model, the single-porosity model is applied in the region outside the stimulated reservoir volume (SRV), and the matrix and natural/induced fractures in the SRV region are modeled using a double-porosity model that can accurately simulate the matrix/fracture fluid exchange during the entire transient period. Meanwhile, the fluid flow in hydraulic fractures is modeled explicitly with the embedded-discrete-fracture model (EDFM), and a stabilized extended-finite-element-method (XFEM) formulation using the polynomial-pressure-projection (PPP) technique is applied to simulate mechanical processes. The developed stabilized XFEM formulation can avoid the displacement oscillation on hydraulic-fracture interfaces. Then a modified fixed-stress sequential-implicit method is applied to solve the hybrid model, in which mixed-space discretization [i.e., finite-volume method (FVM) for flow process and stabilized XFEM for geomechanics] is used. The robustness of the proposed model is demonstrated through several numerical examples. In conclusion, several key factors for gas exploitation are investigated, such as adsorption, Klinkenberg effect, capillary pressure, and fracture deformation. In this study, all the numerical examples are 2D, and the gravity effect is neglected in these simulations. In addition, we assume there is no oil phase in the shale reservoirs, thus the gas/water two-phase model is used to simulate the flow in these reservoirs.

scholarly journals Numerical Simulation Study on Propagation of Initial Microcracks in Cement Sheath Body during Hydraulic Fracturing Process

Energies ◽  
2020 ◽  
Vol 13 (5) ◽  
pp. 1260
Author(s):  
Yuqiang Xu ◽  
Yan Yan ◽  
Shenqi Xu ◽  
Zhichuan Guan
Keyword(s):  
Elastic Modulus ◽  
Hydraulic Fracturing ◽  
Internal Pressure ◽  
Element Model ◽  
Fluid Viscosity ◽  
Fracturing Fluid ◽  
Zone Method ◽  
Geological Conditions ◽  
Fracturing Process ◽  
Cement Sheath

Microcracks caused by perforating operations in a cement sheath body and interface have the potential to further expand or even cause crossflow during hydraulic fracturing. Currently, there are few quantitative studies on the propagation of initial cement-body microcracks. In this paper, a three-dimensional finite element model for the propagation of initial microcracks of the cement sheath body along the axial and circumferential directions during hydraulic fracturing was proposed based on the combination of coupling method of fluid–solid in porous media and the Cohesive Zone Method. The influence of reservoir geological conditions, the mechanical properties of a casing-cement sheath-formation system, and fracturing constructions in the propagation of initial axial microcracks of a cement sheath body was quantitatively analyzed. It can be concluded that the axial extension length of microcracks increased with the increase of elastic modulus of the cement sheath and formation, the flow rate of fracturing fluid, and casing internal pressure, and decreased with the increase of the cement sheath tensile strength and ground stress. The elastic modulus of the cement sheath had a greater influence on the expansion of axial cracks than the formation elastic modulus and casing internal pressure. The effect of fracturing fluid viscosity on the crack expansion was negligible. In order to effectively slow the expansion of the cement sheath body crack, the elastic modulus of the cement sheath can be appropriately reduced to enhance its toughness under the premise of ensuring sufficient strength of the cement sheath.

scholarly journals Study on the evaluation method and influencing factors of fracture conductivity of hydraulic fracturing support in shale reservoir

2021 ◽  
Vol 252 ◽  
pp. 03049
Author(s):  
Yin Shun-li ◽  
Zhuang Tian-lin ◽  
Yang Li-yong ◽  
Jia Yun-peng ◽  
Liu Xue-wei ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Evaluation Method ◽  
Guar Gum ◽  
Great Influence ◽  
Clay Content ◽  
Fracturing Fluid ◽  
Fracture Conductivity ◽  
Shale Reservoir ◽  
Shale Reservoirs ◽  
Proppant Embedment

The conductivity of supporting fractures is an important parameter to evaluate the hydraulic fracturing effect of shale reservoirs, and its size is affected by many factors. In this paper, the proppant is optimized and evaluated on the basis of real rock slab simulation and actual construction proppant test. The laboratory experimental study on the influence of proppant type, sand concentration, proppant embedding and fracturing fluid residue on propping fracture conductivity is carried out, the results show that the average conductivity of 40 / 70 mesh proppant is about 7.15d · cm at 5kg / m2 sand concentration under the condition of reservoir closure pressure of about 50MPa, which can basically meet the requirements of main fracture conductivity of Kong 2 shale reservoir in Dagang Oilfield; the damage of guar gum fracturing fluid and proppant embedment are two important factors that cause the great decline of conductivity of rock slab, and the damage of guar gum fracturing fluid has a great influence on the conductivity, reaching about 50%; the stronger the mud is (the higher the clay content is), the greater the embedment degree of proppant is, and the greater the loss of conductivity is; for the same lithology, the proppant particle size has little damage to the conductivity, and the sand concentration has a greater impact on the conductivity. The larger the sand concentration is, the smaller the loss of the conductivity is.

scholarly journals Analysis Study Of The Effect In Selecting Combination Of Fracturing Fluid Types And Proppant Sizes On Folds Of Increase (FOI) To Improve Well Productivity

2020 ◽  
Vol 1 (2) ◽  
pp. 92
Author(s):  
Dimas Ramadhan ◽  
Hidayat Tulloh ◽  
Cahyadi Julianto
Keyword(s):  
Hydraulic Fracturing ◽  
High Viscosity ◽  
Test Method ◽  
Fracturing Fluid ◽  
Fracturing Fluids ◽  
Lower Viscosity ◽  
Pump Rate ◽  
Fracturing Process ◽  
Fractured Well ◽  
Selection Of

As fracturing materials, fracturing fluid and proppant are two very important parameters in doing hydraulic fracturing design. The combination of fractuirng fluid and proppant selection is the main focus and determinant of success in the hydraulic fracturing process. The high viscosity of the fracturing fluid will make it easier for the proppant to enter to fill the fractured parts, so that the conductivity of the fractured well will be better and can increase the folds of increase (FOI) compared to fracturing fluid with lower viscosity (Economides, 2000). This research was conducted by using the sensitivity test method on the selection of fracturing fluid combinations carried out at the TX-01 well with various sizes of proppants (namely; 12/18, 16/20, and 20/40 mesh) with the proppant selected being ceramic proppant type carbolite performed using the FracCADE simulator. Fracturing fluid was selected based on its viscosity, namely YF240OD and PrimeFRAC20 fluids with viscosity value of 4.123 cp and 171.1 cp, with a fixed pump rate of 14 bpm. The results showed that the combination of high-viscosity fluids (PrimeFRAC20) and 16/20 mesh proppant size resulted in a greater incremental fold (FOI) between the choice of another combination fracturing fluids and proppant sizes, namely 6.25.

scholarly journals The Impact of Oriented Perforations on Fracture Propagation and Complexity in Hydraulic Fracturing

Processes ◽  
2018 ◽  
Vol 6 (11) ◽  
pp. 213 ◽  
Author(s):  
Liyuan Liu ◽  
Lianchong Li ◽  
Derek Elsworth ◽  
Sheng Zhi ◽  
Yongjun Yu
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Hydraulic Fractures ◽  
Fracturing Fluid ◽  
Stress Criterion ◽  
Damage And Fracture ◽  
Fracturing Process ◽  
Heterogeneous Rock ◽  
The Impact

To better understand the interaction between hydraulic fracture and oriented perforation, a fully coupled finite element method (FEM)-based hydraulic-geomechanical fracture model accommodating gas sorption and damage has been developed. Damage conforms to a maximum stress criterion in tension and to Mohr–Coulomb limits in shear with heterogeneity represented by a Weibull distribution. Fracturing fluid flow, rock deformation and damage, and fracture propagation are collectively represented to study the complexity of hydraulic fracture initiation with perforations present in the near-wellbore region. The model is rigorously validated against experimental observations replicating failure stresses and styles during uniaxial compression and then hydraulic fracturing. The influences of perforation angle, in situ stress state, initial pore pressure, and properties of the fracturing fluid are fully explored. The numerical results show good agreement with experimental observations and the main features of the hydraulic fracturing process in heterogeneous rock are successfully captured. A larger perforation azimuth (angle) from the direction of the maximum principal stress induces a relatively larger curvature of the fracture during hydraulic fracture reorientation. Hydraulic fractures do not always initiate at the oriented perforations and the fractures induced in hydraulic fracturing are not always even and regular. Hydraulic fractures would initiate both around the wellbore and the oriented perforations when the perforation angle is >75°. For the liquid-based hydraulic fracturing, the critical perforation angle increases from 70° to 80°, with an increase in liquid viscosity from 10−3 Pa·s to 1 Pa·s. While for the gas fracturing, the critical perforation angle remains 62° to 63°. This study is of great significance in further understanding the near-wellbore impacts on hydraulic fracture propagation and complexity.

scholarly journals Retention of Hydraulic Fracturing Water in Shale: The Influence of Anionic Surfactant

Energies ◽  
2018 ◽  
Vol 11 (12) ◽  
pp. 3342 ◽  
Author(s):  
Hesham Abdulelah ◽  
Syed Mahmood ◽  
Sameer Al-Hajri ◽  
Mohammad Hakimi ◽  
Eswaran Padmanabhan
Keyword(s):  
Hydraulic Fracturing ◽  
Anionic Surfactant ◽  
Water Retention ◽  
Fracturing Fluid ◽  
Surface Active Agents ◽  
Tremendous Amount ◽  
The Difference ◽  
Shale Reservoirs ◽  
Internal Olefin

A tremendous amount of water-based fracturing fluid with ancillary chemicals is injected into the shale reservoirs for hydraulic fracturing, nearly half of which is retained within the shale matrix. The fate of the retained fracturing fluid is raising some environmental and technical concerns. Mitigating these issues requires a knowledge of all the factors possibly contributing to the retention process. Many previous studies have discussed the role of shale properties such as mineralogy and capillarity on fracturing fluid retention. However, the role of some surface active agents like surfactants that are added in the hydraulic fracturing mixture in this issue needs to be understood. In this study, the influence of Internal Olefin Sulfate (IOS), which is an anionic surfactant often added in the fracturing fluid cocktail on this problem was investigated. The effect on water retention of treating two shales “BG-2 and KH-2” with IOS was experimentally examined. These shales were characterized for their mineralogy, total organic carbon (TOC) and surface functional groups. The volume of retained water due to IOS treatment increases by 131% in KH-2 and 87% in BG-2 shale. The difference in the volume of retained uptakes in both shales correlates with the difference in their TOC and mineralogy. It was also inferred that the IOS treatment of these shales reduces methane (CH4) adsorption by 50% in KH-2 and 30% in BG-2. These findings show that the presence of IOS in the composition of fracturing fluid could intensify water retention in shale.

scholarly journals Numerical Simulation of Shale Reservoir Fluid-Driven Fracture Network Morphology Based on Global CZM

2021 ◽  
Vol 9 ◽  
Author(s):  
Yang Yang ◽  
Zixi Jiao ◽  
Longhuan Du ◽  
Hua Fan
Keyword(s):  
Numerical Simulation ◽  
Hydraulic Fracturing ◽  
Fracture Network ◽  
Injection Rate ◽  
Natural Fractures ◽  
Fracturing Fluid ◽  
Geological Conditions ◽  
Complex Fracture Network ◽  
Shale Reservoirs ◽  
Cement Strength

There are a large number of natural fractures in shale reservoirs, which create great challenges to hydraulic fracturing. Activating the natural fractures in reservoirs can form a complex fracture network, enhance fracturing effects, and increase shale gas production. Reservoir geological conditions (low in situ stress, natural fracture distribution, and cement strength) and operation parameters (fracturing fluid viscosity and injection rate) have an important influence on fracture network propagation. In this article, a two-dimensional hydraulic fracturing fluid-mechanic coupling numerical model for shale reservoirs with natural fractures was established. Based on the global cohesive zone model, the influence of geological conditions and operation parameters on the propagation of the hydraulic fracture network and fracturing process is investigated. The numerical simulation results show that when the horizontal in situ stress difference, approach angle, and cement strength are low, it is easier to form a complex fracture network. Research on the construction parameters indicated that when the viscosity of the fracturing fluid is low, it is easier to form a complex network of fractures, but the length of the fractures is shorter; in contrast, the fractures are straight and long. In addition, increasing the injection rate is beneficial for increasing the complexity of the fracture network while increasing the initiation pressure and width of the principal fracture reduces the risk of sand plugging. This article also proposes an optimization solution for hydraulic fracturing operations based on numerical simulation results.

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