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

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.

scholarly journals New insights into hydraulic fracturing fluids used for high-temperature wells

Petroleum ◽  
2020 ◽  
Author(s):  
Tariq Almubarak ◽  
Leiming Li ◽  
Jun Hong Ng ◽  
Hisham Nasr-El-Din ◽  
Mohammed AlKhaldi
Keyword(s):  
High Temperature ◽  
Hydraulic Fracturing ◽  
Fracturing Fluids

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.

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

2021 ◽  
Author(s):  
Basil Alfakher ◽  
Ali Al-Taq ◽  
Sajjad Aldarweesh ◽  
Luai Alhamad
Keyword(s):  
Surface Tension ◽  
High Temperature ◽  
Ammonium Persulfate ◽  
Post Treatment ◽  
Berea Sandstone ◽  
Chemical Additives ◽  
Fracturing Fluid ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Fracturing Fluids

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.

NIROSTA 4002

Alloy Digest ◽  
2002 ◽  
Vol 51 (6) ◽  
Keyword(s):  
Hydrogen Sulfide ◽  
High Temperature ◽  
Physical Properties ◽  
Structural Steel ◽  
Oil Industry ◽  
Heat Treating ◽  
Mineral Oil ◽  
Chromium Steel ◽  
Temperature Performance ◽  
High Level

Abstract NIROSTA 4002 is an apparatus structural steel with 13% Cr. It is used for crack-resistant installations in the mineral oil industry because it has a high level of resistance against hydrogen and hydrogen sulfide. This chromium steel requires a smoothened surface free from residues in order to achieve optimal resistance to corrosion. This datasheet provides information on composition, physical properties, hardness, elasticity, and tensile properties. It also includes information on high temperature performance as well as forming, heat treating, machining, and joining. Filing Code: SS-856. Producer or source: ThyssenKrupp Nirosta GmbH.

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.

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

Molecules ◽  
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.

scholarly journals On the relative attractions of sulphuric acid for water, under particular circumstances: with suggestion of means of improving the ordinary process of manufacturing sulphuric acid

1843 ◽  
Vol 4 ◽  
pp. 81-82
Keyword(s):  
High Temperature ◽  
Specific Gravity ◽  
Sulphuric Acid ◽  
Conclusive Evidence ◽  
Dew Point ◽  
Chemical Affinity ◽  
Dilute Acid ◽  
Atmospheric Air ◽  
Open Atmosphere ◽  
Series Of Experiments

The object of the inquiry detailed in the present paper is to determine at what degree of concentration the affinity of sulphuric acid for aqueous vapour is equal to that of anhydrous space for the same vapour at given temperatures. It has long been known that concentrated sulphuric acid abstracts moisture from the atmosphere, but the amount and the rate of this absorption have never been ascertained with accuracy; and consequently, in applying this acid to purposes of exsiccation, the experimenter has often been at a loss to know whether the acid was sufficiently strong to render the space in which it was confined perfectly anhydrous. By placing portions of the acid, previously weighed, and diluted with known quantities of water, under the receiver of an air-pump, with equal portions of concentrated acid, of the specific gravity 1·8428, in similar dishes, the author ascertained that the dilute acid could be concentrated to the specific gravity 1·814, at a temperature varying from 65° to 57°: whence he concludes that acid of such strength is capable of drying a vacuum when the temperature does not exceed 57°. By making similar experiments in air, the author compared together the weights lost by ten grains of dilute sulphuric acid of the specific gravity 1·135, at three different periods of the day for six days, taking note of the dew-point and the temperature; and infers that when the affinity of space for vapour, or the evaporating force, is equal to 0·15 of an inch of mercury, it is just able to balance the affinity for water of sulphuric acid of the specific gravity 1·249. The author next instituted a series of experiments to ascertain whether the evaporation of water from dilute sulphuric acid is capable of being carried on to the same extent in air as in vacuo, and found that the evaporating force of air exerted upon such acid is less than that of a vacuum at the same temperature. He observes that his experiments offer conclusive evidence that the evaporation of water is not owing to the existence of a chemical affinity between the vapour of the liquid and atmospheric air; but thinks that they favour the notion that the obstruction to this process in the open atmosphere is rather owing to the pressure than to the inertiæ of the particles of air. He is also of opinion that improvements will hereafter arise from this inquiry with regard to the economical management of the process of manufacturing sulphuric acid, which process would be greatly expedited by the regulated admission of steam into the condensing chambers kept at a constant high temperature.

scholarly journals pH-responsive viscoelastic supramolecular viscosifiers based on dynamic complexation of zwitterionic octadecylamidopropyl betaine and triamine for hydraulic fracturing applications

RSC Advances ◽  
2021 ◽  
Vol 11 (37) ◽  
pp. 22517-22529
Author(s):  
Shuhao Liu ◽  
Yu-Ting Lin ◽  
Bhargavi Bhat ◽  
Kai-Yuan Kuan ◽  
Joseph Sang-II Kwon ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Ph Responsive ◽  
Fracturing Fluids ◽  
Efficient Transport ◽  
Critical Components

Viscosity modifying agents are one of the most critical components of hydraulic fracturing fluids, ensuring the efficient transport and deposition of proppant into fissures.

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