Fracturing Fluids and Fracturing Fluid Additives

2018 ◽  
pp. 237-257
Author(s):  
Caili Dai ◽  
Fulin Zhao
Keyword(s):  
Fracturing Fluid ◽  
Fracturing Fluids

scholarly journals Laboratory Testing of Fracture Conductivity Damage by Foam-Based Fracturing Fluids in Low Permeability Tight Gas Formations

Energies ◽  
2021 ◽  
Vol 14 (6) ◽  
pp. 1783
Author(s):  
Klaudia Wilk-Zajdel ◽  
Piotr Kasza ◽  
Mateusz Masłowski
Keyword(s):  
Hydraulic Fracturing ◽  
Guar Gum ◽  
Polymer Concentration ◽  
Laboratory Research ◽  
Damage Effect ◽  
Tight Gas ◽  
Fracturing Fluid ◽  
Fracture Conductivity ◽  
Fracturing Fluids ◽  
Sandstone Rock

In the case of fracturing of the reservoirs using fracturing fluids, the size of damage to the proppant conductivity caused by treatment fluids is significant, which greatly influence the effective execution of hydraulic fracturing operations. The fracturing fluid should be characterized by the minimum damage to the conductivity of a fracture filled with proppant. A laboratory research procedure has been developed to study the damage effect caused by foamed and non-foamed fracturing fluids in the fractures filled with proppant material. The paper discusses the results for high quality foamed guar-based linear gels, which is an innovative aspect of the work compared to the non-foamed frac described in most of the studies and simulations. The tests were performed for the fracturing fluid based on a linear polymer (HPG—hydroxypropyl guar, in liquid and powder form). The rheology of nitrogen foamed-based fracturing fluids (FF) with a quality of 70% was investigated. The quartz sand and ceramic light proppant LCP proppant was placed between two Ohio sandstone rock slabs and subjected to a given compressive stress of 4000–6000 psi, at a temperature of 60 °C for 5 h. A significant reduction in damage to the quartz proppant was observed for the foamed fluid compared to that damaged by the 7.5 L/m3 natural polymer-based non-foamed linear fluid. The damage was 72.3% for the non-foamed fluid and 31.5% for the 70% foamed fluid, which are superior to the guar gum non-foamed fracturing fluid system. For tests based on a polymer concentration of 4.88 g/L, the damage to the fracture conductivity by the non-foamed fluid was 64.8%, and 26.3% for the foamed fluid. These results lead to the conclusion that foamed fluids could damage the fracture filled with proppant much less during hydraulic fracturing treatment. At the same time, when using foamed fluids, the viscosity coefficient increases a few times compared to the use of non-foamed fluids, which is necessary for proppant carrying capacities and properly conducted stimulation treatment. The research results can be beneficial for optimizing the type and performance of fracturing fluid for hydraulic fracturing in tight gas formations.

Experimental Research on Damage to Fracture Conductivity Caused by Fracturing Fluid Residues

2013 ◽  
Vol 774-776 ◽  
pp. 303-307
Author(s):  
Lei Wang
Keyword(s):  
Experimental Research ◽  
Evaluation System ◽  
Fracturing Fluid ◽  
Fracture Conductivity ◽  
Fracturing Fluids ◽  
Different Types ◽  
Degree Of Damage ◽  
First Time

Experimental research on damage to fracture conductivity caused by fracturing fluid residues has been done for the first time in China using FCES-100 (Fracture Conductivity Evaluation System). In the experiments, the degree of damage to conductivity caused by different types and concentrations of fracturing fluids were studied in the condition of different concentrations and types of proppants. The mechanism of damage to conductivity was studied and some methods on how to decrease the damage were brought forward, which is significant for the research on development of fracturing fluids and also for field treatments.

scholarly journals Synthesis of phosphates for liquefied petroleum gas (LPG) fracturing fluid

2019 ◽  
Vol 9 (3-4) ◽  
pp. 179-184
Author(s):  
Pengfei Chen ◽  
Honggang Chang ◽  
Gang Xiong ◽  
Yan Zhang ◽  
Xueqin Zheng
Keyword(s):  
Reaction Times ◽  
Triethyl Phosphate ◽  
Liquefied Petroleum Gas ◽  
Fracturing Fluid ◽  
Reaction Conditions ◽  
Phosphorous Pentoxide ◽  
Gelling Agents ◽  
Fracturing Fluids ◽  
Phosphate Product ◽  
Synthesis Reactions

Abstract Herein, a study of phosphate synthesis reactions with triethyl phosphate, phosphorous pentoxide and mixed alcohols is described. The synthesized phosphates are used as gelling agents in LPG fracturing fluids. By this study, a phosphate product with good performance has been obtain by screening different combination of alcohols and various reaction conditions including the ratios of reactants, reaction temperatures and reaction times. The LPG fracturing fluid prepared with the phosphate product we optimized maintains a viscosity of 200 mPa s for 1.5 h at 90 °C and 170 s−1 shear rate.

Leak-Off Coefficient Analysis in Stimulation Treatment Design

2014 ◽  
Vol 933 ◽  
pp. 202-205
Author(s):  
Bo Cai ◽  
Yun Hong Ding ◽  
Yong Jun Lu ◽  
Chun Ming He ◽  
Gui Fu Duan
Keyword(s):  
Hydraulic Fracturing ◽  
Field Method ◽  
Oil Field ◽  
Low Permeability ◽  
Analysis Model ◽  
Fracturing Fluid ◽  
Real Time Analysis ◽  
Fracturing Fluids ◽  
Common Technique ◽  
Treatment Design

Hydraulic fracturing was first used in the late 1940s and has become a common technique to enhance the production of low-permeability formations.Hydraulic fracturing treatments were pumped into permeable formations with permeable fluids. This means that as the fracturing fluid was being pumped into the formation, a certain proportion of this fluid will being lost into formation as fluid leak-off. Therefore, leak-off coefficient is the most leading parameters of fracturing fluids. The accurate understanding of leak-off coefficient of fracturing fluid is an important guidance to hydraulic fracturing industry design. In this paper, a new field method of leak-off coefficient real time analysis model was presented based on instantaneous shut-in pressure (ISIP). More than 100 wells were fractured using this method in oil field. The results show that average liquid rates of post-fracturing was 22m3/d which double improvement compared with the past treatment wells. It had an important role for hydraulic fracturing stimulation treatment design in low permeability reservoirs and was proven that the new model for hydraulic fracturing treatment is greatly improved.

scholarly journals Understanding the temperature–resistance performance of a borate cross-linked hydroxypropyl guar gum fracturing fluid based on a facile evaluation method

RSC Advances ◽  
2017 ◽  
Vol 7 (84) ◽  
pp. 53290-53300 ◽  
Author(s):  
Haiming Fan ◽  
Zheng Gong ◽  
Zhiyi Wei ◽  
Haolin Chen ◽  
Haijian Fan ◽  
...  
Keyword(s):  
Evaluation Method ◽  
Guar Gum ◽  
Temperature Tolerance ◽  
Fracturing Fluid ◽  
Temperature Resistance ◽  
Hydroxypropyl Guar ◽  
Fracturing Fluids ◽  
Resistance Performance ◽  
Hydroxypropyl Guar Gum

A facile procedure has been proposed to evaluate the temperature–resistance performance of fracturing fluids, which was used to understand the temperature–tolerance performance of a borate cross-linked hydroxypropyl guar gum fracturing fluid.

scholarly journals Modeling Hydraulic Fracturing Using Natural Gas Foam as Fracturing Fluids

Energies ◽  
2021 ◽  
Vol 14 (22) ◽  
pp. 7645
Author(s):  
Shuang Zheng ◽  
Mukul M. Sharma
Keyword(s):  
Equation Of State ◽  
Natural Gas ◽  
Hydraulic Fracturing ◽  
Gas Emission ◽  
Fracturing Fluid ◽  
Fracturing Fluids ◽  
Water Based ◽  
Simulation Results ◽  
The Cost ◽  
Stranded Gas

Stranded gas emission from the field production because of the limitations in the pipeline infrastructure has become one of the major contributors to the greenhouse effects. How to handle the stranded gas is a troublesome problem under the background of global “net-zero” emission efforts. On the other hand, the cost of water for hydraulic fracturing is high and water is not accessible in some areas. The idea of using stranded gas in replace of the water-based fracturing fluid can reduce the gas emission and the cost. This paper presents some novel numerical studies on the feasibility of using stranded natural gas as fracturing fluids. Differences in the fracture creating, proppant placement, and oil/gas/water flowback are compared between natural gas fracturing fluids and water-based fracturing fluids. A fully integrated equation of state compositional hydraulic fracturing and reservoir simulator is used in this paper. Public datasets for the Permian Basin rock and fluid properties and natural gas foam properties are collected to set up simulation cases. The reservoir hydrocarbon fluid and natural gas fracturing fluids phase behavior is modeled using the Peng-Robinson equation of state. The evolving of created fracture geometry, conductivity and flowback performance during the lifecycle of the well (injection, shut-in, and production) are analyzed for the gas and water fracturing fluids. Simulation results show that natural gas and foam fracturing fluids are better than water-based fracturing fluids in terms of lower breakdown pressure, lower water leakoff into the reservoir, and higher cluster efficiency. NG foams tend to create better propped fractures with shorter length and larger width, because of their high viscosity. NG foam is also found to create better stimulated rock volume (SRV) permeability, better fracturing fluid flowback with a large water usage reduction, and high natural gas consumption. The simulation results presented in this paper are helpful to the operators in reducing natural gas emission while reducing the cost of hydraulic fracturing operation.

scholarly journals A Novel Hydraulic Fracturing Method Based on the Coupled CFD-DEM Numerical Simulation Study

2020 ◽  
Vol 10 (9) ◽  
pp. 3027
Author(s):  
Cong Lu ◽  
Li Ma ◽  
Zhili Li ◽  
Fenglan Huang ◽  
Chuhao Huang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Hydraulic Fracturing ◽  
Variable Viscosity ◽  
Oil Reservoirs ◽  
Fluid Viscosity ◽  
Low Density ◽  
Fracturing Fluid ◽  
Proppant Transport ◽  
Fracturing Fluids ◽  
Transport Experiment

For the development of tight oil reservoirs, hydraulic fracturing employing variable fluid viscosity and proppant density is essential for addressing the problems of uneven placement of proppants in fractures and low propping efficiency. However, the influence mechanisms of fracturing fluid viscosity and proppant density on proppant transport in fractures remain unclear. Based on computational fluid dynamics (CFD) and the discrete element method (DEM), a proppant transport model with fluid–particle two-phase coupling is established in this study. In addition, a novel large-scale visual fracture simulation device was developed to realize the online visual monitoring of proppant transport, and a proppant transport experiment under the condition of variable viscosity fracturing fluid and proppant density was conducted. By comparing the experimental results and the numerical simulation results, the accuracy of the proppant transport numerical model was verified. Subsequently, through a proppant transport numerical simulation, the effects of fracturing fluid viscosity and proppant density on proppant transport were analyzed. The results show that as the viscosity of the fracturing fluid increases, the length of the “no proppant zone” at the front end of the fracture increases, and proppant particles can be transported further. When alternately injecting fracturing fluids of different viscosities, the viscosity ratio of the fracturing fluids should be adjusted between 2 and 5 to form optimal proppant placement. During the process of variable proppant density fracturing, when high-density proppant was pumped after low-density proppant, proppants of different densities laid fractures evenly and vertically. Conversely, when low-density proppant was pumped after high-density proppant, the low-density proppant could be transported farther into the fracture to form a longer sandbank. Based on the abovementioned observations, a novel hydraulic fracturing method is proposed to optimize the placement of proppants in fractures by adjusting the fracturing fluid viscosity and proppant density. This method has been successfully applied to more than 10 oil wells of the Bohai Bay Basin in Eastern China, and the average daily oil production per well increased by 7.4 t, significantly improving the functioning of fracturing. The proppant settlement and transport laws of proppant in fractures during variable viscosity and density fracturing can be efficiently revealed through a visualized proppant transport experiment and numerical simulation study. The novel fracturing method proposed in this study can significantly improve the hydraulic fracturing effect in tight oil reservoirs.

scholarly journals Application of a Zwitterionic Hydrophobic Associating Polymer with High Salt and Heat Tolerance in Brine-Based Fracturing Fluid

Polymers ◽  
2019 ◽  
Vol 11 (12) ◽  
pp. 2005 ◽  
Author(s):  
Jizhen Tian ◽  
Jincheng Mao ◽  
Wenlong Zhang ◽  
Xiaojiang Yang ◽  
Chong Lin ◽  
...  
Keyword(s):  
Strong Association ◽  
Common Salt ◽  
Formation Water ◽  
Fracturing Fluid ◽  
Gas Field ◽  
High Salinity Water ◽  
Matrix Permeability ◽  
Fracturing Fluids ◽  
Polyelectrolyte Effect ◽  
Associating Polymer

ZID16PM, a zwitterionic hydrophobic associating polymer, has equivalent positive and negative charges and some hydrophobic monomers with twin-tailed long hydrophobic chains. It exhibits a great heat resistance and salt tolerance to the common salt in formation brine (MgCl2, CaCl2, NaCl, and KCl), which is attributed to its anti-polyelectrolyte effect and strong association force. High-salinity water (seawater or formation water) can be prepared as a fracturing fluid directly. In this paper, the formation water of the West Sichuan Gas Field is directly prepared into fracturing fluid with a concentration of 0.3% ZID16PM (Fluid-1), and the seawater of the Gulf of Mexico is directly prepared into fracturing fluid with a concentration of 0.3% ZID16PM (Fluid-2). Finally, rheological measurements, proppant suspension tests, and core matrix permeability damage rate tests for the Fluid-1 and Fluid-2 are conducted. Results show that after 120 min of shearing at 140 and 160 °C, respectively, the viscosity of Fluid-1 remains in the range of 50–85 mPa·s, and the viscosity of Fluid-2 remains in the range of 60–95 mPa·s. And the wastewater produced by an oilfield in Shaanxi, Xinjiang, and Jiangsu are also prepared into fracturing fluids with a concentration of 0.3% ZID16PM, the viscosity of these fracturing fluids can remain 32, 42, and 45 mPa·s, respectively, after 120 min of shearing at 160 °C. All results demonstrate that the polymer ZID16PM displays prominent performance in fracturing fluids.

Performance and field implementation of a new fracturing fluid consisting of hydrophobically associating polyacrylamide and anionic surfactant

2016 ◽  
Vol 36 (1) ◽  
pp. 13-21 ◽  
Author(s):  
Zhongcong Zhao ◽  
Tongyi Liu ◽  
Pingya Luo ◽  
Yan Li ◽  
Jianxin Liu ◽  
...  
Keyword(s):  
Network Structure ◽  
Anionic Surfactant ◽  
Self Assembly ◽  
Fracturing Fluid ◽  
Hydroxypropyl Guar ◽  
Fluid Field ◽  
Fracturing Fluids ◽  
Hydrophobically Associating Polyacrylamide ◽  
Hydrophobically Associating ◽  
Static Conditions

Abstract The fundamental cause of the proppant suspension behavior in hydraulic fracturing fluids lies in its internal microcosmic network structure and structural strength. In addition to chemical crosslinking, another method to form a network structure is established in this paper. Hydrophobically associating polyacrylamide and an anionic surfactant self-assembly process was applied to form a network structure. Compared with crosslinked hydroxypropyl guar gel, the new fracturing fluid even has better proppant suspending properties in static conditions. The capability does not result from crosslinkage but from reinforced physical associations between chains. The performance of this new fracturing fluid was tested and the results showed that it can fully satisfy the requirement of fracturing fluid. Field test shows excellent stimulation effects during its applications in 400 wells in eight oilfields in China.

Design and Application of High-Temperature Raw-Seawater-Based Fracturing Fluids

SPE Journal ◽  
2019 ◽  
Vol 24 (04) ◽  
pp. 1929-1946 ◽  
Author(s):  
Tariq Almubarak ◽  
Mohammed AlKhaldi ◽  
Jun Hong Ng ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
High Temperature ◽  
Calcium Sulfate ◽  
Ph Value ◽  
Fracturing Fluid ◽  
Remote Areas ◽  
Fracturing Fluids ◽  
High Pressure High Temperature ◽  
Negative Effect ◽  
Static Conditions ◽  
First Time

Summary Typically, water-based fracturing treatments consume a large volume of fresh water. Providing consistent freshwater sources is difficult and sometimes not feasible, especially in remote areas and offshore operations. Therefore, several seawater-based fracturing fluids have been developed in an effort to preserve freshwater resources. However, none of these fluids minimizes fracture-face skin and proppant-conductivity impairment, which can be critical for unconventional well treatments. Several experiments and design iterations were conducted to tailor raw-seawater-based fracturing fluids. These fluids were designed to have rheological properties that can transport proppant under dynamic and static conditions. The optimized seawater-based fracturing-fluid formulas were developed such that no scale forms when additives are mixed in or when the fracturing-fluid filtrate is mixed with different formation brines. The tests were conducted using a high-pressure/high-temperature (HP/HT) rheometer, coreflood, and by aging cells at 250 to 300°F. The developed seawater-based fracturing fluids were optimized with an apparent viscosity greater than 100 cp at a shear rate of 100 seconds–1 and a temperature of 300°F for more than 1 hour. The use of polymeric- and phosphonate-based scale inhibitors (SIs) prevented the formation of severe calcium sulfate (CaSO4) scale in mixtures of seawater and formation brines at 300°F. Controlling the pH of fracturing fluids prevented magnesium and calcium hydroxide precipitation that occurs at a pH value of greater than 9.5. Most importantly, SIs had a negative effect on the viscosity of seawater fracturing fluid during testing because of their negative interaction with metallic crosslinkers. The developed seawater-based fracturing fluids were applied for the first time in an unconventional and a conventional carbonate well and showed very promising results; details of field treatments are discussed in this paper.

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