scholarly journals Modeling Efficiency of Energized Fluid Fracturing in Tight Gas Formations

2019 ◽  
Author(s):  
Klaudia Wilk
Keyword(s):  
Clay Minerals ◽  
Guar Gum ◽  
Tight Gas ◽  
Additional Energy ◽  
Fracture Geometry ◽  
Fracturing Fluids ◽  
Reservoir Permeability ◽  
Water Based ◽  
Permeability Damage ◽  
Fluid Fracturing

Hydraulic fracturing is the most effective method of stimulation for hydrocarbon reservoirs. However the use of water-based fracturing fluids, can be a problem in water-sensitive formations due to the permeability damage hazard caused by clay minerals swelling. For this reason, the foamed fracturing fluids with addition of natural, fast hydrating guar gum were examined. The rheology and filtration coefficients of foamed fracturing fluids were examined and compared to the properties of conventional water-based fracturing fluid. Laboratory results provided the input for numerical simulation of the fractures geometry for water-based fracturing fluids and 50% N2 foamed fluids. The results show, that the foamed fluids were able to create shorter and thinner fractures compared to the fractures induced by the non-foamed fluid. The simulation proved that the concentration of proppant in the fracture and its conductivity are similar or slightly higher when using the foamed fluid. Moreover such fluids are able to significantly reduce the amount of water necessary for fracturing treatments, limiting clay minerals swelling, and reducing the reservoir permeability damage. The foamed fluids, when injected to the reservoir, provide additional energy, that allow for more effective flowback, and maintain the proper fracture geometry and proppant placing. The results of laboratory work in combination with the 3D simulation showed, that the foamed fluids have suitable viscosity which allows opening the fracture, and transport the proppant into the fracture, providing successful fracturing operation.

scholarly journals Experimental and Simulation Studies of Energized Fracturing Fluid Efficiency in Tight Gas Formations

Energies ◽  
2019 ◽  
Vol 12 (23) ◽  
pp. 4465
Author(s):  
Klaudia Wilk
Keyword(s):  
Clay Minerals ◽  
Guar Gum ◽  
Laboratory Data ◽  
Good Alternative ◽  
Rheological Parameters ◽  
Fracturing Fluid ◽  
Additional Energy ◽  
Negative Results ◽  
Fracturing Fluids ◽  
Water Based

The use of water-based fracturing fluids during fracturing treatment can be a problem in water-sensitive formations due to the permeability damage hazard caused by clay minerals swelling. The article includes laboratory tests, analyses and simulations for nitrogen foamed fracturing fluids. The rheology and filtration coefficients of foamed fracturing fluids were examined and compared to the properties of conventional water-based fracturing fluid. Laboratory results provided the input for numerical simulation of the fractures geometry for water-based fracturing fluids and 50% N2 foamed fluids, with addition of natural, fast hydrating guar gum. The results show that the foamed fluids were able to create shorter and thinner fractures compared to the fractures induced by the non-foamed fluid. The simulation proved that the concentration of proppant in the fracture and its conductivity are similar or slightly higher when using the foamed fluid. The foamed fluids, when injected to the reservoir, provide additional energy that allows for more effective flowback, and maintain the proper fracture geometry and proppant placing. The results of laboratory work in combination with the 3D simulation showed that the foamed fluids have suitable viscosity which allows opening the fracture, and transport the proppant into the fracture, providing successful fracturing operation. The analysis of laboratory data and the performed computer simulations indicated that fracturing fluids foamed by nitrogen are a good alternative to non-foamed fluids. The N2-foamed fluids exhibit good rheological parameters and proppant-carrying capacity. Simulated fracture of water-based fracturing fluid is slightly longer and higher compared to foamed fluid. At the same time, when using a fluid with a gas additive, the water content in fracturing fluid is reduced which means the minimization of the negative results of the clay minerals swelling.

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.

Technological Advances in Water-less Fracking: A Case Study

2021 ◽  
Author(s):  
R. Bharadwaj
Keyword(s):  
Chemical Additives ◽  
Breakdown Pressure ◽  
Additional Energy ◽  
Co2 Foam ◽  
Fracturing Fluids ◽  
Technological Advances ◽  
Wide Range ◽  
Water Based ◽  
Fracking Fluid ◽  
Back Stage

Hydrofracking transfigured the concept of producing from unconventional reservoirs. The Fracking fluid used in fracturing has unlocked many tight reservoirs but in terms of an aquifer, it poses threats like consumption of large quantity of water and also, used water becomes polluted as well as recycling cost is uneconomic. This paper evaluates alternatives to water-based frac fluids and discusses their environmental & economic impact along with resource availability and commercial feasibility. Pure Propane Fracturing uses propane in combination with non-toxic man-made proppants (light glass & carbon fullerene microbeads) with desired properties. Pure Propane is fluorinated and carbonated without water or harmful additives, thereby eliminates the risk of catching fire. Pure Propane Fracturing eliminates the need for water completely and thus, a perfect option for fracturing in water scarcity regions. Fracture flow capacity of Pure Propane can be enhanced with the use of phase change chemical proppants in the slurry stage. CO2 Foam Fracturing predominantly comprises liquid carbon-dioxide which reduces the water requirement up to 80%. CO2 foam-based frac fluid uses relatively fewer chemical additives as compared to the water-based frac fluid which in-turn does minimal formation damage. Foam Fracturing fluids have high fluid recovery and clean-up efficiency. CO2 foam-based frac fluid is available in a wide range of viscosities and can also work in high pressure high temperature conditions at significantly low polymer loadings. Energized frac fluid comprises N2/CO2 (20-30%) which reduces water consumption and provides additional energy to aid in load recovery during the post-frac flow-back stage. N2 gas can propagate more easily into small pores and micro-fractures to get lower breakdown pressure and enhance fracture complexity & CO2 exists in dense phase at static bottom hole conditions, thus is less susceptible to dissipation and dissolves in crude oil which reduces its viscosity and improves cleanup and recovery.

Experimental Investigation on Damage Mechanism of Guar Gum Fracturing Fluid to Low-Permeability Reservoir Based on Nuclear Magnetic Resonance

2018 ◽  
Vol 140 (7) ◽  
Author(s):  
Tiankui Guo ◽  
Facheng Gong ◽  
Xin Lin ◽  
Qiang Lin ◽  
Xiaozhi Wang
Keyword(s):  
Guar Gum ◽  
Solid Phase ◽  
Bound Water ◽  
Damage Mechanism ◽  
Fracturing Fluid ◽  
Water Sensitivity ◽  
Fracturing Fluids ◽  
Reservoir Permeability ◽  
Core Permeability ◽  
Water Block

The damage mechanism of fracturing fluids has always been the hot research topic in the development of low-permeability reservoir with hydraulic fracturing. At present, the research in this area is conducted mostly by the conventional core fluid flow test designed with industrial standards, less in the experiment operated from a microperspective. Against the reservoir cores with different permeability, and based on the results of SEM, mercury injection experiment, and core fluid flow test, this paper uses the technology of nuclear magnetic resonance (NMR) to systematically analyze the degree and rule of water-sensitivity, water-block, and solid-phase adsorption damage resulted from hydroxypropyl guar gum (HPG) and carboxymethyl guar gum (CMG) fracturing fluids, and proposes a comprehensive test method for evaluating the fracturing fluids damage to the reservoir. The test results show that fracturing fluid infiltrating into the core causes the increase of bound water, mobile water retention, and solid-phase macromolecule substance absorption inside the core in varying degrees, decreasing the reservoir permeability. The extent of reservoir water-sensitivity damage is positively correlated with the increment of bound water, and the extent of water-block damage is positively correlated with mobile water retention volume. The adsorption and retention of solid-phase macromolecule substance causes largest loss of core permeability, averaging about 20%, and it is main damage factor of fracturing fluids, the water-sensitivity damage causes 11% of core permeability loss, and the water-block damage causes 7% of loss. As the reservoir permeability doubles, the comprehensive damage resulted from guar gum fracturing fluid decreases by 14%. The comprehensive damage of CMG fracturing fluid to reservoir is 6.6% lower than that of HPG fracturing fluid, and the lower the reservoir permeability, the larger the gap between damage of CMG and HPG fracturing fluids. With the technology of NMR, the objective and accurate evaluation of various damages to reservoir resulted from fracturing fluids is realized, and the corresponding relation between damage mechanism and damage extent is established, which provides reference for research on improvement of fracturing fluid properties and reservoir protection measures.

scholarly journals Development of Instant Linear Gel for Coal Bed Methane Gas Operations

2021 ◽  
Vol 1 (3) ◽  
Author(s):  
Ramana Murthy RVV
Keyword(s):  
Sodium Acetate ◽  
Guar Gum ◽  
Small Concentration ◽  
Coal Bed ◽  
Coal Bed Methane ◽  
Ammonium Persulphate ◽  
Gelling Agents ◽  
Fracturing Fluids ◽  
Degradation Pattern ◽  
Suspending Agents

Previously we prepared fracturing linear gel with fossil diesel, bio-diesel and also used suspending, anti-settling agents and emulsifiers. But through this research, a novel and efficient method for the preparation of linear gel directly mixed with water, guar gum and sodium acetate together instantly. In this instead of diesel, we used water and no need to mix anti-settling agents, suspending agents, emulsifiers that resulted in 30 viscosity linear gel. Ammonium persulphate or Ammonium peroxidisulphate and enzyme-G are used for oxidation purposes to break the gel gradually at a particular static temperature. The degradation pattern observed from the breaker test showed that a reduction in gel viscosity depends on time, temperature & breaker concentration. Observations from experiments revealed that a small concentration of breakers provides rapid break compared to oxidative breakers. This article, designing of fracturing fluids describes how to use the fluid's viscosity generated by the gelling agents like guar gum for CBM operations.

scholarly journals Unconventional Gas Production from Hydraulically Fractured Well-An Application of Direct Search Based Optimization Algorithm

2019 ◽  
Vol 8 (2S11) ◽  
pp. 2726-2737
Keyword(s):  
Objective Function ◽  
Fracture Propagation ◽  
Gas Production ◽  
Production Model ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Unconventional Gas ◽  
Fracture Geometry ◽  
Propagation Behavior ◽  
Fractured Well

Unconventional gas reservoirs are now the targets for meeting the demand for gas. These reservoirs are at the depth of more than 10,000 ft (even over 15000 depth as well) and are difficult to be exploited by conventional methods. For the last decades hydraulic fracturing has become the tool to develop these resources. Mathematical models (2D and pseudo-3D) have been developed for fracture geometry, which should be realistically created at the depth by surface controllable treatment parameters. If the reservoir rock is sandstone, then proppant fracturing is suitable and if the rock is carbonates, then acid fracturing is applicable. In both cases, proper design of controllable treatment parameters within constraints is essential. This needs proper optimization model which gives real controllable parametric vales. The model needs the most important analyses from geomechanical study and linear elastic fracture mechanics of rock containing unconventional gas so that fracture geometry makes maximum contact with the reservoirs for maximum recovery. Currently available software may lack proper optimization scheme containing geomechanical stress model, fracture geometry, natural fracture interactions, real field constraints and proper reservoir engineering model of unconventional gas resources, that is, production model from hydraulically fractured well (vertical and horizontal). An optimization algorithm has been developed to integrate all the modules, as mentioned above, controllable parameters, field constraints and production model with an objective function of maximum production (with or without minimization of treatment cost). Optimization is basically developed based on Direct Search Genetic and Polytope algorithm, which can handle dual objective function, non-differentiable equations, discontinuity and non-linearity. A dual objective function will meet operator’s economic requirements and investigate conflict between two objectives. The integrated model can be applied to a vertical or horizontal well in tight gas or ultra-tight shale gas deeper than over 10,000 ft. A simulation (with industrial simulators) was conducted to investigate and analyse fracture propagation behavior, under varying parameters with respect to the fracture design process, for tight gas reservoirs. Results indicate that hydraulic fracture propagation behavior is not uninhibited in deep reservoirs as some may believe that minor variations of variables such as in-situ stress, fluid properties etc. are often detrimental to fracture propagation in some conditions. Application of this model to a hypothetical tight and ultra-tight unconventional gas formations indicates a significant gas production at lower treatment cost; whereas the resources do not flow without any stimulation (hydraulic fracturing).

Biodegradation of Guar Gum in Hydraulic Fracturing Fluid under the Action of Enzyme Preparations of Basidiomycetes

2021 ◽  
Vol 37 (4) ◽  
pp. 96-105
Author(s):  
E.Yu. Kozhevnikova ◽  
A.V. Shnyreva ◽  
A.V. Barkov ◽  
Yu.A. Topolyuk ◽  
I.N. Grishina ◽  
...  
Keyword(s):  
Guar Gum ◽  
Schizophyllum Commune ◽  
Petroleum Industry ◽  
Environmentally Friendly ◽  
Gelling Agent ◽  
Fungal Mycelium ◽  
Fomitopsis Pinicola ◽  
Trametes Hirsuta ◽  
Enzyme Preparations ◽  
Fracturing Fluids

Guar gum is a polymer that is widely used as a gelling agent for technological liquids in the petroleum industry. In this paper, we have studied the potential for the environmentally friendly biodegradation of guar gum by enzymes of basidiomycetes for efficient disposal of oil industry wastes. For the first time, we compared the enzymatic activity towards guar gum of seven basidiomycete strains, namely Trametes hirsuta MT-24.24, Lactarius necator, Trametes hirsuta MT-17.24, Schizophyllum commune MT-33.01, Fomes fomentarius MT-4.05, Fomitopsis pinicola MT-5.21, and Trametes versicolor It-1. This comparison showed that the preparation based on Fomitopsis pinicola MT-5.21 fungal mycelium at a concentration of 0.05% provides the most efficient decomposition of a frac fluid containing guar gum. By varying the enzyme concentration in this fluid it is possible to control the decrease in its viscosity over time. The developed enzyme preparation is an efficient and environmentally friendly guar gum biodegradant and can be used to process waste fracturing fluids based on polysaccharides in order to reuse water resources. Key words: biodegradants, basidiomycetes, guar gum, enzymatic hydrolysis, enzyme destructors, fracturing fluids. Funding - The work was financially supported by the National University of Oil and Gas "Gubkin University" (Internal grant no. 120720 "Development of New Biotechnological Methods and Materials for Environmental Protection and Biomedicine").

Welltest analysis of hydraulically fractured tight gas reservoirs: a field example from Perth Basin, Western Australia

2012 ◽  
Vol 52 (1) ◽  
pp. 587 ◽  
Author(s):  
Hassan Bahrami ◽  
Vineeth Jayan ◽  
Reza Rezaee ◽  
Dr Mofazzal Hossain
Keyword(s):  
Radial Flow ◽  
Second Derivative ◽  
Tight Gas ◽  
Transient Pressure ◽  
Gas Reservoirs ◽  
Type Curves ◽  
Tight Gas Reservoirs ◽  
Diagnostic Plots ◽  
Reservoir Permeability ◽  
Reservoir Flow

Welltest interpretation requires the diagnosis of reservoir flow regimes to determine basic reservoir characteristics. In hydraulically fractured tight gas reservoirs, the reservoir flow regimes may not clearly be revealed on diagnostic plots of transient pressure and its derivative due to extensive wellbore storage effect, fracture characteristics, heterogeneity, and complexity of reservoir. Thus, the use of conventional welltest analysis in interpreting the limited acquired data may fail to provide reliable results, causing erroneous outcomes. To overcome such issues, the second derivative of transient pressure may help eliminate a number of uncertainties associated with welltest analysis and provide a better estimate of the reservoir dynamic parameters. This paper describes a new approach regarding welltest interpretation for hydraulically fractured tight gas reservoirs—using the second derivative of transient pressure. Reservoir simulations are run for several cases of non-fractured and hydraulically fractured wells to generate different type curves of pressure second derivative, and for use in welltest analysis. A field example from a Western Australian hydraulically fractured tight gas welltest analysis is shown, in which the radial flow regime could not be identified using standard pressure build-up diagnostic plots; therefore, it was not possible to have a reliable estimate of reservoir permeability. The proposed second derivative of pressure approach was used to predict the radial flow regime trend based on the generated type curves by reservoir simulation, to estimate the reservoir permeability and skin factor. Using this analysis approach, the permeability derived from the welltest was in good agreement with the average core permeability in the well, thus confirming the methodology’s reliability.

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