Fracturing Fluid Design: A Closer Look at Breaker and Surfactant Selection

Abstract Guar and its derivatives are the most commonly used gelling agents for fracturing fluids. At high temperature, higher polymer loadings are required to maintain sufficient viscosity for proper proppant carry and creating the fracture geometry. To minimize fracturing fluids damage and optimize fracture conductivity, it is necessary to design a fluid that is easy to clean up by ensuring proper breaking and sufficiently low surface tension for flow back. Therefore, breakers and surfactants must be carefully selected and optimally dosed to ensure the success of fracturing treatments. In this study, two fracturing fluids were evaluated for moderate to high temperature applications with a focus on post-treatment cleanup efficiency. The first is a guar-based fluid with a borate crosslinker evaluated at 280°F and the second is a CMHPG-based fluid with a zirconate crosslinker evaluated at 320°F. The shear viscosities of both fluids were tested with a live sodium bromate breaker, a polymer encapsulated ammonium persulfate breaker and a dual breaker system combining the two breakers. Different anionic and nonionic surfactant chemistries (aminosulfonic acid and alcohol based) were investigated by measuring surface tension of the surfactant solutions at different concentrations. The compatibility of the surfactants with other fracturing fluid additives and their adsorption in Berea sandstone was also investigated. Finally, the damage caused by leak-off for each fracturing fluid was simulated by using coreflooding experiments and Berea sandstone core plugs. Lab results showed the guar and CMHPG fluids maintained sufficient viscosity for the first two hours at baseline, respectively. The encapsulated breaker proved to be effective in delaying the breaking of the fracturing fluids. The dual breaker system was the most effective and the loading was optimized for each tested temperature to provide the desired viscosity profile. Two of the examined surfactants were effective in lowering surface tension (below 30 dyne/cm) and were stable for all tested temperatures. The guar broken fluid showed better regained permeability (up to 94%) when compared to the CMHPG (up to 53%) fluid for Berea sandstone. This paper outlines a methodical approach to selecting and optimizing fracturing fluid chemical additives for better post-treatment cleanup and subsequent well productivity.

Download Full-text

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

Energies ◽

10.3390/en14061783 ◽

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.

Download Full-text

Performance Evaluation of Enzyme Breaker for Fracturing Applications under Simulated Reservoir Conditions

Molecules ◽

10.3390/molecules26113133 ◽

2021 ◽

Vol 26 (11) ◽

pp. 3133

Author(s):

Yuling Meng ◽

Fei Zhao ◽

Xianwei Jin ◽

Yun Feng ◽

Gangzheng Sun ◽

...

Keyword(s):

Hydraulic Fracturing ◽

Shear Resistance ◽

Ammonium Persulfate ◽

Fracturing Fluid ◽

Medium Temperature ◽

Fracture Conductivity ◽

Wide Range ◽

Reservoir Conditions ◽

Alkaline Conditions ◽

Resistance Performance

Fracturing fluids are being increasingly used for viscosity development and proppant transport during hydraulic fracturing operations. Furthermore, the breaker is an important additive in fracturing fluid to extensively degrade the polymer mass after fracturing operations, thereby maximizing fracture conductivity and minimizing residual damaging materials. In this study, the efficacy of different enzyme breakers was examined in alkaline and medium-temperature reservoirs. The parameters considered were the effect of the breaker on shear resistance performance and sand-suspending performance of the fracturing fluid, its damage to the reservoir after gel breaking, and its gel-breaking efficiency. The experimental results verified that mannanase II is an enzyme breaker with excellent gel-breaking performance at medium temperatures and alkaline conditions. In addition, mannanase II did not adversely affect the shear resistance performance and sand-suspending performance of the fracturing fluid during hydraulic fracturing. For the same gel-breaking result, the concentration of mannanase II used was only one fifth of other enzyme breakers (e.g., mannanase I, galactosidase, and amylase). Moreover, the amount of residue and the particle size of the residues generated were also significantly lower than those of the ammonium persulfate breaker. Finally, we also examined the viscosity-reducing capability of mannanase II under a wide range of temperatures (104–158 °F) and pH values (7–8.5) to recommend its best-use concentrations under different fracturing conditions. The mannanase has potential for applications in low-permeability oilfield development and to maximize long-term productivity from unconventional oilwells.

Download Full-text

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

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.774-776.303 ◽

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.

Download Full-text

Mechanism and Prevention Method of Producing Hydrogen Sulfide in High Temperature Hydraulic Fracturing Well

10.2523/iptc-21826-ms ◽

2021 ◽

Author(s):

Zebo Yuan ◽

Xiaoqiang Wang ◽

Lizhi Zhou ◽

Huifeng Liu ◽

Xu Li ◽

...

Keyword(s):

Hydrogen Sulfide ◽

High Temperature ◽

Hydraulic Fracturing ◽

Sodium Thiosulfate ◽

Ammonium Persulfate ◽

Gas Reservoir ◽

Fracturing Fluids ◽

Series Of Experiments ◽

Prevention Method ◽

Fractured Well

Abstract For a successful hydraulic fracturing operation, shear recovery and thermal stability are critical in terms of successful fracture creation and proppant placement. Sodium thiosulfate is one of the most commonly used gel stabilizers in fracturing gel. This paper reported a well in sulfur-free gas reservoir produced hydrogen sulfide as much as 20000ppm after hydraulic fracturing operation. A series of experiments were carried out to reveal the mechanism of hydrogen sulfide production. Results showed that in solution with PH less than 6.5, when the temperature is higher than 119 degrees Celsius, sodium thiosulfate will react with hydrogen ions to generate hydrogen sulfide. In this complex reaction, there is also precipitation of elemental sulfur, which may block the pores of the reservoir and thence counteract the effect of hydraulic fracturing. The acidic solution in a fractured well is from (1) Spent acid left downhole due to pre-acid used to reduce fracturing pressure, and (2) Sulfuric acid produced by the decomposition of ammonium persulfate which is used as gel breaker at high temperature. This paper proposed two solutions to the problem of high-temperature fracturing fluids,one is to use a sulfur-free temperature stabilizer,and the other is to create a non-acid downhole environment. The opinions provided by this paper can help the operators reduce the risk of the damage of hydrogen sulfide and protect the integrity of the well of high temperature fracturing wells.

Download Full-text

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

SPE Journal ◽

10.2118/195597-pa ◽

2019 ◽

Vol 24 (04) ◽

pp. 1929-1946 ◽

Cited By ~ 3

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.

Download Full-text

Research Progress of High Temperature Resistant Fracturing Fluid System

Journal of Physics Conference Series ◽

10.1088/1742-6596/2076/1/012039 ◽

2021 ◽

Vol 2076 (1) ◽

pp. 012039

Author(s):

Ke Xu ◽

Yongjun Lu ◽

Jin Chang ◽

Yang Li

Keyword(s):

High Temperature ◽

Oil And Gas ◽

Guar Gum ◽

Crosslinking Agent ◽

Research Progress ◽

Fracturing Fluid ◽

Fluid System ◽

Fracturing Fluids ◽

Ultra High Temperature ◽

Exploration And Development

Abstract China has made significant progress in the efficient exploration and development of deep-seated oil and gas wells. Reservoir reformation, as the core tool of high-temperature deep-seated exploration and development, puts forward a strong demand for fracturing fluids. The ultra-high temperature fracturing fluid system developed in my country is mainly divided into two types: ultra-high temperature guar gum fracturing fluid and ultra-high temperature synthetic polyacrylamide fracturing fluid. The high temperature resistant fracturing fluid system is mainly composed of high temperature resistant thickener, high temperature resistant crosslinking agent and temperature stabilizing additives and other additives. Based on indoor research and a large amount of literature, this article summarizes the research and application of high temperature resistant fracturing fluid system, high temperature resistant thickener, high temperature resistant crosslinking agent and temperature stabilizing additives in my country in recent years, and pointed out the shortcomings and limitations of the high-temperature fracturing fluid, the technical direction of the development of high-temperature resistant fracturing fluid technology is proposed.

Download Full-text

Performance evaluation of synthetic and natural polymers in nitrogen foam-based fracturing fluids in the Cooper Basin, South Australia

The APPEA Journal ◽

10.1071/aj19062 ◽

2020 ◽

Vol 60 (1) ◽

pp. 227

Author(s):

Tuan Tran ◽

M. E. Gonzalez Perdomo ◽

Klaudia Wilk ◽

Piotr Kasza ◽

Khalid Amrouch

Keyword(s):

High Temperature ◽

Foam Stability ◽

South Australia ◽

Propagation Model ◽

Natural Polymers ◽

Fracturing Fluid ◽

Additional Energy ◽

Fracturing Fluids ◽

Nitrogen Foam ◽

Cooper Basin

Hydraulic fracturing is a well-known stimulation technique for creating fractures in a subsurface formation to achieve profitable production rates in low-permeability reservoirs. Slickwater has been widely used as a traditional fracturing fluid. However, it has multiple disadvantages, such as high consumption of water, clay swelling and low flowback recovery. Foam, as an alternative fracturing fluid, consumes less liquid and provides additional energy. However, foam bubbles are typically unstable due to the degradation of surfactants, particularly in high temperature reservoirs, which reduces their capabilities of carrying and placing proppants into fractures. The purpose of this study is to provide general guidelines for an optimised application of polymers to improve the foam stability in high temperature reservoirs while increasing the proppant placement and water usage efficiencies. In this paper, the effects of natural hydroxypropyl guar (HPG) and synthetic polyacrylamide (PAM) polymers on the rheological properties of nitrogen foam-based fluids were examined by laboratory experiments conducted using temperatures up to 110°C. Then, a 3D hydraulic fracture propagation model was developed to study the fracturing performance of HPG-foamed and PAM-foamed fluids in the Toolachee Formation, Cooper Basin. It was found that synthetic PAM polymers were more effective than natural HPG polymers in stabilising foam viscosity under high temperature conditions. The simulation results indicate that foam-based fluids totally outperform slickwater in the field case application. This paper emphasises the significance of crosslinkers, foam quality and thermal stability on the performance of foams in high temperature environments.

Download Full-text

A High Density Fracturing Fluid System for HPHT Reservoir Stimulation Treatment

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.680.312 ◽

2013 ◽

Vol 680 ◽

pp. 312-314

Author(s):

Ping Li Liu ◽

Qi Zhu ◽

Xi Jin Xing

Keyword(s):

High Temperature ◽

Petroleum Industry ◽

Temperature Stability ◽

High Density ◽

Fracturing Fluid ◽

Fluid System ◽

Shear Properties ◽

Proppant Transport ◽

Reservoir Stimulation ◽

Fracturing Fluids

Petroleum industry is focusing on HPHT reservoir. In high-temperature conditions, fracturing fluids especially need to be stable and induce minimum damage, and have good proppant transport capabilities. In order to overcome these problems, a novel high density fracturing fluid system has been developed whose density can reach up to 1.21 g/cm3. This paper summarizes a study on formulating weighted agent, and extensive studies were also conducted to determine temperature stability and anti-shear properties and compatibility with additives.

Download Full-text