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 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.

Dual-Polymer Hydraulic-Fracturing Fluids: A Synergy Between Polysaccharides and Polyacrylamides

SPE Journal ◽  
2019 ◽  
Vol 24 (06) ◽  
pp. 2635-2652 ◽  
Author(s):  
Tariq Almubarak ◽  
Jun Hong Ng ◽  
Hisham A. Nasr–El–Din ◽  
Khatere Sokhanvarian ◽  
Mohammed AlKhaldi
Keyword(s):  
Hydraulic Fracturing ◽  
Polymer Concentration ◽  
Polymer System ◽  
Polymer Mixture ◽  
Fracturing Fluid ◽  
Positive Interaction ◽  
Geomechanical Properties ◽  
Fracturing Fluids ◽  
Polymer Loading ◽  
Polymer Ratio

Summary As exploration for oil and gas continues, it becomes necessary to produce from deeper formations, and to meet the challenge of low permeability and higher temperatures. Unconventional shale formations are addressed with slickwater fracturing fluids, owing to the shale's unique geomechanical properties. On the other hand, conventional formations require crosslinked fracturing fluids to properly enhance productivity. Guar and its derivatives have a history of success in crosslinked hydraulic–fracturing fluids. However, they require higher polymer loading to withstand higher–temperature environments. This leads to an increase in mixing time and additive requirements. Most importantly, as a result of high polymer loading, they do not break completely and thus generate residual–polymer fragments that can plug the formation and significantly reduce fracture conductivity. In this work, a new hybrid dual–polymer hydraulic–fracturing fluid was developed. The fluid consists of a guar derivative and a polyacrylamide–based synthetic polymer. Compared with conventional fracturing fluids, this new system is easily hydrated, requires fewer additives, can be mixed “on the fly,” and is capable of maintaining excellent rheological performance at low polymer loadings. The polymer mixture solutions were prepared at a total polymer concentration of 20 to 40 lbm/1,000 gal at volume ratios of 2:1, 1:1, and 1:2. The fluids were crosslinked with a metallic crosslinker and broken with an oxidizer at 300°F. Testing focused on crosslinker/polymer–ratio analysis to effectively lower loading while maintaining sufficient performance to carry proppant at this temperature. A high–pressure/high–temperature (HP/HT) rheometer was used to measure viscosity, storage modulus, and fluid–breaking performance. An HP/HT aging cell and HP/HT see–through cell were used for proppant settling. Fourier–transform infrared (FTIR) spectroscopy, Cryo scanning electron microscopy (Cryo–SEM), and an HP/HT rheometer were also used to understand the interaction. Results indicated that the dual–polymer fracturing fluid was able to generate stable viscosity at 300°F and 100 s−1 as well as generate a higher viscosity compared with the individual–polymer fracturing fluid. Also, properly understanding and tuning the crosslinker to the polymer ratio generated excellent performance at 20 lbm/1,000 gal. The two polymers formed an improved crosslinking network that enhanced proppant–carrying properties. This fluid also demonstrated a clean and controlled breaking performance with an oxidizer. Extensive experiments were pursued to evaluate the new dual–polymer system for the first time. This system exhibited a positive interaction between the polysaccharide and polyacrylamide families and generated excellent rheological properties. The major benefit of using a mixed–polymer system is reduced polymer loading. Lower loading is highly desirable because it reduces material cost, eases field operation, and potentially lowers damage to the fracture face, proppant pack, and formation.

Optimizing Seawater Based Fracture Fluids Rheology Utilizing Chelating Agents

2021 ◽  
Author(s):  
Amro Othman ◽  
Murtada Saleh Aljawad ◽  
Muhammad Shahzad Kamal ◽  
Mohamed Mahmoud ◽  
Shirish Patil
Keyword(s):  
Chelating Agents ◽  
Guar Gum ◽  
Polymer Concentration ◽  
High Viscosity ◽  
Fluid Viscosity ◽  
Fracturing Fluid ◽  
Gulf Region ◽  
Low Viscosity ◽  
Fracturing Fluids ◽  
Ph Level

Abstract Due to the scarcity and high cost of freshwater, especially in the Gulf region, utilization of seawater as a fracturing fluid gained noticeable interest. However, seawater contains high total dissolved solids (TDS) that may damage the formation and degrade the performance of the fracturing fluids. Numerous additives are required to reduce the damaging effect and improve the viscosity resulting in an expensive and non-eco-friendly fracturing fluid system. Chelating agents, which are environmentally benign, are proposed in this study as the replacement of many additives for seawater fracturing fluids. This study focuses on optimizing chelating agents to achieve high viscosity employing the standard industry rheometers. Carboxymethyl Hydroxypropyl Guar Gum (CMHPG) polymer, which is effective in hydraulic fracturing, was used in this research with 0.5 and 1.0 wt% in deionized water (DW) as well as seawater (SW). It was first tested as a standalone additive at different conditions to provide a benchmark then combined with different concentrations, and pH level chelating agents. In this study the hydration test was conducted through different conditions. It was observed that CMHPG, when tested as a standalone additive, provided slightly higher viscosity in SW compared to DW. Also, increasing polymer concentration from 0.5 to 1.0 wt% provided three folds of viscosity. The viscosity did not show time dependence behavior at room temperature for the aforementioned experiments where all hydration tests were run at 511 1/s shear rate. Temperature, however, had a significant impact on both viscosity magnitude and behavior. At 70 °C, the fluid viscosity increased with time where low viscosity was achieved early on but kept increasing with shearing time. Similarly, high pH chelating agents provided time dependant viscosity behavior when mixed with CMHPG. This behavior is important as low viscosity is favorable during pumping but high viscosity when the fluids hit the formation. The study investigates the possibility of utilizing chelating agents with seawater to replace numerous additives. It acts as a crosslinker at early shearing times, where a gradual increase in viscosity was observed and a breaker in the reservoir harsh conditions. It also captures the divalent ions that are common in seawater, which replaces the need for scale inhibitors. The viscosity increase behavior can be controlled by adjusting the pH level, which could be desirable during operations.

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 Potential Use of Water Associated with Conventional Oil Production and Sea Water as Base Fluids for Hydraulic Fracturing Operations: Effect of Water Chemistry on Crosslinking and Breaking Behaviors of Guar Gum-Based Fracturing Fluid Formulations

2016 ◽  
Vol 6 (1) ◽  
pp. 31 ◽  
Author(s):  
Dayanand Saini ◽  
Timea Mezei
Keyword(s):  
Los Angeles ◽  
Hydraulic Fracturing ◽  
Water Chemistry ◽  
Fresh Water ◽  
Oil And Gas ◽  
Guar Gum ◽  
Sea Water ◽  
Oil Production ◽  
Fracturing Fluid ◽  
Conventional Oil

 Even though water consumption per hydraulic fracturing (or fracturing) job is relatively low; nearly all of the fresh water used for fracturing in California is in the regions of high water stress such as San Jouquin and Los Angeles Basins. However, water availability should not be a concern as huge volumes of water are being produced along with oil and gas from conventional formations (i.e. associated water) in the Kern County of California, a region where most of the fracturing activities take place. This associated water can potentially be used for preparing fracturing fluids in stimulating the unconventional formations. The present study reports on the relevant investigation done in this area of interest.The results suggest that associated water chemistry has limited effect on the viscosity of cross-linked formulations. However, guar gum concentration was found to affect the breaking behaviors of cross-linked fracturing fluid formulations. The new type of commercially available biodegradable breaker was found to be effective in breaking the tested cross-linked formulations at elevated temperature which was as high as 85°C (185°F). Both crosslinking and breaking behaviors of fracturing fluid formulations evaluated in this study were found comparable to the behaviors of commonly used cross-linked formulation (guar gum + 2% potassium chloride). These results suggest that both the associated water (i.e. water resulting from regional conventional oil production activites) and sea water (offshore oil fields) could serve as alternative sources of base fluid for use in fracturing jobs without putting significant burden on precious regional fresh water resources.

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.

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.

Chemically Modified Natural Gum for Use in Well Stimulation

1977 ◽  
Vol 17 (01) ◽  
pp. 5-10 ◽  
Author(s):  
C.J. Githens ◽  
J.W. Burnham
Keyword(s):  
Hydraulic Fracturing ◽  
Apparent Viscosity ◽  
Guar Gum ◽  
Gelling Agent ◽  
Polymer Emulsion ◽  
Gelling Agents ◽  
Chemically Modified ◽  
Well Stimulation ◽  
Fracturing Fluids ◽  
New Material

Abstract A new polymer gelling agent has been developed to help satisfy the growing demand for "clean" hydraulic fracturing fluids. This polymer is a guar derivative that exhibits the desirable characteristics of conventional guar and that leaves low residue upon breaking. The derivatized guar was evaluated for its ability to function as a fracturing-fluid gelling agent in comparison with both a conventional guar and a nonionic cellulose derivative. The guar derivative possesses a number of advantages over both the conventional guar and the cellulose derivative. Laboratory experimental data and field results are presented. Introduction Hydraulic fracturing has been used successfully for oil- and gas-well stimulation for about 27 years. During this time the size of the treatments has grown from the original "tank of oil and sack of sand" to the current massive hydraulic fracturing treatments, entailing several hundred thousand gallons of fluid and large amounts of sand. These massive treatments have become routine in some areas of this country. Although many types of fluids have been used successfully, aqueous fluids have been preferred recently. Because of economic and safety considerations, aqueous fluids will likely continue to be preferred. Treatment designs usually require that the fluids possess a particular apparent viscosity. These stipulated viscosities are particular apparent viscosity. These stipulated viscosities are often many times higher than that of the base fluid in its natural state. The increased apparent viscosities are generally attained by the addition of hydrophilic polymeric "gelling agents." A variety of gelling agents for aqueous fluids is available. Each gelling agent possesses inherent chemical properties that often make it particularly applicable for a special function. These properties are a direct result of the chemical structure and stereochemistry of the repeating unit of the polymer, and the resulting conformation or macrostructure that the polymer assumes in the fluid. Polysaccharides, such as the guar polymer, possess many of the properties desired of a gelling agent. However, the relatively high percentage of insolubles (residue) present in commercial guar has been a matter of serious concern. Many believe that guar-gum residue can contribute to permanent formation and fracture conductivity damage. Because of the complexity of the situation, experimental evaluation of the over-all effect of this residue on the formation permeability and fracture flow capacity is difficult. However, there should be no question that the presence of the residue could result in damage to the formation and the proppant system, and that a reduction in the amount of residue proppant system, and that a reduction in the amount of residue present diminishes this possibility. present diminishes this possibility. A new low-residue, derivatized-guar (derivatized polysaccharide) gelling agent has been developed. This chemically polysaccharide) gelling agent has been developed. This chemically modified guar results in an 85-percent reduction in inherent residue over conventional guar gum, yet retains the desirable properties of the guar polymer. In addition, it provides an properties of the guar polymer. In addition, it provides an extension of guar chemistry and versatility into several new approaches for designing hydraulic fracturing fluids. This versatile polymer has application in most aqueous and polymer-emulsion hydraulic fracturing processes. polymer-emulsion hydraulic fracturing processes. In addition to possessing the obvious advantage of low residue, this new material can be dispersed controllably in aqueous fluids, thereby effectively reducing gel lumping tendencies. The result is a smooth, lump-free gel. It yields equivalent or slightly higher apparent viscosity values in fresh water and the usual brines compared with the old, conventional, guar-gum gelling agents. Alcohol tolerance of this new material is good, and it is readily complexed or crosslinked in water or alcohol-water mixtures with crosslinking agents. Fluids prepared with this new polymer may be manipulated to achieve temperature stability surpassing that of any gelled-water fracturing fluid containing the polysaccharides we have used in the past. SPEJ P. 5

scholarly journals Research on Property of Multicomponent Thickening Water Fracturing Fluid and Application in Low Permeability Oil Reservoirs

2018 ◽  
Vol 2018 ◽  
pp. 1-10 ◽  
Author(s):  
Chengli Zhang ◽  
Peng Wang ◽  
Guoliang Song
Keyword(s):  
Guar Gum ◽  
New Technology ◽  
Oil Field ◽  
Ammonium Bromide ◽  
Low Permeability ◽  
Fracturing Fluid ◽  
Fluid System ◽  
Fracture Conductivity ◽  
Hydroxypropyl Guar ◽  
Actual Production

The clean fracturing fluid, thickening water, is a new technology product, which promotes the advantages of clean fracturing fluid to the greatest extent and makes up for the deficiency of clean fracturing fluid. And it is a supplement to the low permeability reservoir in fracturing research. In this paper, the study on property evaluation for the new multicomponent and recoverable thickening fracturing fluid system (2.2% octadecyl methyl dihydroxyethyl ammonium bromide (OHDAB) +1.4% dodecyl sulfonate sodium +1.8% potassium chloride and 1.6% organic acids) and guar gum fracturing fluid system (hydroxypropyl guar gum (HGG)) was done in these experiments. The proppant concentration (sand/liquid ratio) at static suspended sand is up to 30% when the apparent viscosity of thickening water is 60 mPa·s, which is equivalent to the sand-carrying capacity of guar gum at 120 mPa·s. When the dynamic sand ratio is 40%, the fracturing fluid is not layered, and the gel breaking property is excellent. Continuous shear at room temperature for 60 min showed almost no change in viscosity. The thickening fracturing fluid system has good temperature resistance performance in medium and low temperature formations. The fracture conductivity of thickening water is between 50.6 μm2·cm and 150.4 μm2·cm, and the fracture conductivity damage rate of thickening water is between 8.9% and 17.9%. The fracture conductivity conservation rate of thickening water is more than 80% closing up of fractures, which are superior to the guar gum fracturing fluid system. The new wells have been fractured by thickening water in A block of YC low permeability oil field. It shows that the new type thickening water fracturing system is suitable for A block and can be used in actual production. The actual production of A block shows that the damage of thickening fracturing fluid is low, and the long retention in reservoir will not cause great damage to reservoir.

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