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.

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.

The Clipper Field, Blocks 48/19a, 48/19c, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 691-698
Author(s):  
M. J. Sarginson
Keyword(s):  
North Sea ◽  
Upper Permian ◽  
Lower Permian ◽  
Reservoir Properties ◽  
Gas Field ◽  
Field Development ◽  
Matrix Permeability ◽  
Recoverable Reserves ◽  
Reservoir Permeability ◽  
Sandstone Formation

AbstractThe Clipper Gas Field is a moderate-sized faulted anticlinal trap located in Blocks 48/19a, 48/19c and 48/20a within the Sole Pit area of the southern North Sea Gas Basin. The reservoir is formed by the Lower Permian Leman Sandstone Formation, lying between truncated Westphalian Coal Measures and the Upper Permian evaporitic Zechstein Group which form source and seal respectively. Reservoir permeability is very low, mainly as a result of compaction and diagenesis which accompanied deep burial of the Sole Pit Trough, a sub basin within the main gas basin. The Leman Sandstone Formation is on average about 715 ft thick, laterally heterogeneous and zoned vertically with the best reservoir properties located in the middle of the formation. Porosity is fair with a field average of 11.1%. Matrix permeability, however, is less than one millidarcy on average. Well productivity depends on intersecting open natural fractures or permeable streaks within aeolian dune slipface sandstones. Field development started in 1988. 24 development wells have been drilled to date. Expected recoverable reserves are 753 BCF.

scholarly journals Pilot test of study on brine injection into shallow formation for mitigating land subsidence in the Southern Kanto Gas Field in Japan

2020 ◽  
Vol 382 ◽  
pp. 787-790
Author(s):  
Noriyuki Muraoka ◽  
Yuji Hayashi ◽  
Katsuhiro Nakamura ◽  
Toshiaki Yamaguchi ◽  
Kazunori Ono ◽  
...  
Keyword(s):  
Natural Gas ◽  
Land Subsidence ◽  
Ground Level ◽  
Pilot Test ◽  
Formation Water ◽  
Gas Field ◽  
Bottom Hole ◽  
Test Study ◽  
Water Formation ◽  
Brine Injection

Abstract. In the Southern Kanto Gas Field, natural gas dissolved in water has been produced for over 80 years. In order to produce the natural gas dissolved in water, formation water must be pumped from a reservoir in the gas field. The production of formation water is considered to be one of the causes of land subsidence. Because brine injection into shallow formations is expected to be effective to mitigate land subsidence, our association is planning to conduct the pilot test study. In this test, the production and injection of brine are going to be performed, and we will observe a deformation of the shallow formation and a change of ground level and the bottom hole pressure. As a result of these tests, if the land subsidence mitigation effect by injection into shallow formation is confirmed, it is expected that it will be connected to increased production and to reservoir management in consideration of land subsidence mitigation in the future.

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.

Research and Application on Fracturing Fluid Loss Model for Glutenite Formation

2013 ◽  
Vol 295-298 ◽  
pp. 2842-2847
Author(s):  
Yong Ming Li ◽  
Pan Luo ◽  
Jin Zhou Zhao ◽  
Ya Zhou Li
Keyword(s):  
Filtration Rate ◽  
Orthogonal Transformation ◽  
Transformation Method ◽  
Fluid Loss ◽  
Natural Fractures ◽  
Matrix Permeability ◽  
Fracturing Fluids ◽  
Gravel Size ◽  
Dual Porosity Model ◽  
Porosity Model

Gravels and natural fractures in glutenite formation have significant impacts on fluid loss when hydraulic fracturing is conducted. Matrix permeability and porosity were computed through Kozeny-Carman equation when gravels contents and size are known. Then a pebbly dual permeability dual porosity model was used to quantitatively evaluate the fracturing fluids loss in glutenite formation. Filtration rate curves could be plotted from the pressure distribution function which was obtained through orthogonal transformation method. Different gravels contents and multi-size-gravels were taken into accounts in this paper. The results show that both filtration rates in matrix and natural fractures decrease with increasing gravels content in matrix; and the filtration rate in matrix decrease much more. Impacts of gravel content are more significant than impacts of gravel size. Natural fractures have much more significant impacts than gravels.

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.

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