Optimized Clay Control Fracturing Fluid Used in a Highly Water-Sensitive Tight Oil Reservoir Hydraulic Fracturing Application in Xinjiang Oil Field: Case Study

2021 ◽  
Author(s):  
Xinjun Mao ◽  
Chaofeng Chen ◽  
Renzhong Gan ◽  
Shubo Zhou ◽  
Zichao Wang ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Recovery Rate ◽  
Oil Field ◽  
National Standard ◽  
Working Fluid ◽  
Tight Oil ◽  
Fracturing Fluid ◽  
Core Flow ◽  
Velocity Sensitivity ◽  
Highly Sensitive

Abstract The candidate wells are tight oil wells and most of the wells in the area have a low recovery rate of fracturing fluid after fracturing treatment. The lithology is glutenite with weak cementation and a high sensitivity tendency. This paper presents the process of sensitivity evaluation and fracturing fluid evaluation. Also, this paper introduces a customized and optimized clay control fracturing fluid wells in a highly sensitive reservoir. Per local national standard, traditional methods of swelling test (ST) and x-ray diffraction (XRD) were employed for qualitative formation cutting analysis. An innovative trial was then developed to evaluate cores quantitatively by water sensitivity. A clay stabilizer was then chosen to be used for the highly sensitive cores and regain permeability testing of the broken fracturing fluid was performed. Based on the analysis and evaluation, a customized treatment design was initiated for the hydraulic fracturing treatment. The qualitative evaluation showed the rock is highly water sensitive and the cores easily collapse because of weak cementation. No flow could be established during traditional core flow tests with brine. The newly developed method used kerosene as the working fluid to prevent the cores from contact with water or brine. The core flow tests resulted in a velocity sensitivity damage rate of 92%, which is considered as highly velocity sensitive. Accordingly, a special clay stabilizer was chosen to be used in the fracturing fluid and the permeability damage of the broken fracturing fluid is only 26.9%(Table 16). Field results have shown that the fracturing fluid recovery rate in treated wells is higher than the area average level and treated wells have significant oil production increase. The innovative clay control fracturing fluid and its field application reduces the influence of water and velocity sensitivity. The customized treatment with special clay stabilizer helps increase the recovery rate of fracturing fluid in reservoirs with severe clay stability and weak cementation issues.

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.

Considerations for Using a Hydraulic Fracturing Fluid for Breaking Crude Oil Emulsion from Reservoir

2018 ◽  
Vol 69 (6) ◽  
pp. 1498-1500
Author(s):  
Lacramioara Olarasu ◽  
Maria Stoicescu ◽  
Ion Malureanu ◽  
Ion Onutu
Keyword(s):  
Hydraulic Fracturing ◽  
Crude Oil ◽  
Oil Production ◽  
Oil Field ◽  
Reservoir Rock ◽  
Oil Well ◽  
Strong Impact ◽  
Fracturing Fluid ◽  
Oil Emulsion ◽  
Oil Emulsions

In the oil industry, crude oil emulsions appear very frequently in almost all activities, starting with drilling and continuing with completion, production, transportation and processing. They are usually formed naturally or during oil production and their presence can have a strong impact on oil production and facilities. In this paper we addressed the problem of oil emulsions present in a reservoir with unfavorable flow properties. It is known that the presence of emulsions in a reservoir can influence both flow capacity and the quality of its crude oil, especially when they are associated with porous medium�s low values of permeability. Considering this, we have introduced a new procedure for selecting a special fluid of fracture. This fluid has two main roles: to create new flow paths from the reservoir rock to wells; to produce emulsion breaking of emulsified oil from pore of rocks. Best fracturing fluid performance was determined by laboratory tests. Selected fluid was then used to stimulate an oil well located on an oil field from Romania. In the final section of this paper,we are presenting a short analysis of the efficiency of the operation of hydraulic fracturing stimulation probe associated with the crude oil emulsion breaking process.

Getting More with Less: Low-Viscosity Fluid Implementation for a Conventional Formation in Western Siberia, Russia

2021 ◽  
Author(s):  
Fedor Yurievich Leskin ◽  
Inna Aleksandrovna Sakhipova ◽  
Nikita Mikhailovich Zorkalt?ev ◽  
Alan Kazbekovich Dzutcev ◽  
Svetlana Rafailievna Pavlova ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
High Precision ◽  
Technology Implementation ◽  
Western Siberia ◽  
Height Growth ◽  
Production Optimization ◽  
Oil Field ◽  
Low Permeability ◽  
Fracturing Fluid ◽  
Low Viscosity

Abstract Oil-saturated strata of Western Siberia fields are represented by laminated low-permeability sandstone separated by shale layers. Therefore, when designing hydraulic fractures, it is important to create longer propped fracture half-length and provide coverage of oil-saturated layers along the entire net height. Implementation of high-volume proppant fractures in combination with high-viscosity crosslinked fluids leads to excessive fracture height growth. In some cases it results in ineffective proppant distribution in the target layer and, moreover, to unwanted water production if the water contact or water bearing formation is close. To overcome these issues, it was proposed to use a novel hydraulic fracturing fluid that is a viscous slickwater based on synthetic polymer-polyacrylamide (also known as HiVis FR or HVFR). The low viscosity of HVFR (about 10 times lower than that of a crosslinked gel) allows a long fracture to be created and restricts height growth. Additionally, use of polyacrylamide instead of guar gives a larger value of retained conductivity. The full workflow for implementing HVFR for hydraulic fracturing in conventional formations includes candidate evaluation, HVFR laboratory testing, an integrated engineering approach to fracture modeling, operational considerations, and post-fracturing production analysis. The workflow evolved during the technology implementation cycle in a specific oil field, particularly the modeling step, which used a new high precision multiphysics (MP) model. The MP model provides an advanced, high-quality high- precision fracturing design to properly evaluate fracture geometry and proppant distribution by accounting for proppant settling in viscoelastic fluid and an accurate simulation of proppant placement when using a pulsing schedule. During the 2-year project, considerable success was achieved in expanding of the technology implementation scope. Several records were achieved on Kondinskoe oil field - a 150-t of ceramic proppant (SG, specific gravity,~3.1) were placed in a conventional reservoir by low-viscosity fracturing fluid and the first worldwide combination of viscous slickwater with channel fracturing technology was successfully performed. The use of HVFR, due to ability of fracture growth control, prevented breakthrough into the water-bearing zone. In addition, considerable improvement of operational efficiency was achieved due to use of cold water, lower amounts of additives, and less equipment, which resulted in a smaller location and environmental footprint. This first implementation of the viscous slickwater in conventional wells in Western Siberia enabled evaluating its effect on production rate. Increasing demand for maximizing production from low- permeability formations makes the result of this viscous slickwater implementation campaign of special interest. The application of a full engineering workflow, including design, execution, and evaluation of the Viscous slickwater treatments is a key to successful technology implementation and production optimization.

Hydraulic Fracturing of Ultrahigh Stress Tight Oil Reservoir - A Case Study of Yumen Oilfield in China

2016 ◽  
Author(s):  
Peng Yi ◽  
Weng Dingwei ◽  
Xu Yun ◽  
Wang Liwei ◽  
Lu Yongjun ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Tight Oil ◽  
Oil Reservoir ◽  
Tight Oil Reservoir

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.

Optimization on Fracturing Fluid Flowback Model after Hydraulic Fracturing in Oil Well

2021 ◽  
pp. 108703
Author(s):  
Zhanqing Qu ◽  
Jiwei Wang ◽  
Tiankui Guo ◽  
Lin Shen ◽  
Hualin Liao ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Well ◽  
Fracturing Fluid

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.

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