scholarly journals Modeling Hydraulic Fracturing Using Natural Gas Foam as Fracturing Fluids

Energies ◽  
2021 ◽  
Vol 14 (22) ◽  
pp. 7645
Author(s):  
Shuang Zheng ◽  
Mukul M. Sharma
Keyword(s):  
Equation Of State ◽  
Natural Gas ◽  
Hydraulic Fracturing ◽  
Gas Emission ◽  
Fracturing Fluid ◽  
Fracturing Fluids ◽  
Water Based ◽  
Simulation Results ◽  
The Cost ◽  
Stranded Gas

Stranded gas emission from the field production because of the limitations in the pipeline infrastructure has become one of the major contributors to the greenhouse effects. How to handle the stranded gas is a troublesome problem under the background of global “net-zero” emission efforts. On the other hand, the cost of water for hydraulic fracturing is high and water is not accessible in some areas. The idea of using stranded gas in replace of the water-based fracturing fluid can reduce the gas emission and the cost. This paper presents some novel numerical studies on the feasibility of using stranded natural gas as fracturing fluids. Differences in the fracture creating, proppant placement, and oil/gas/water flowback are compared between natural gas fracturing fluids and water-based fracturing fluids. A fully integrated equation of state compositional hydraulic fracturing and reservoir simulator is used in this paper. Public datasets for the Permian Basin rock and fluid properties and natural gas foam properties are collected to set up simulation cases. The reservoir hydrocarbon fluid and natural gas fracturing fluids phase behavior is modeled using the Peng-Robinson equation of state. The evolving of created fracture geometry, conductivity and flowback performance during the lifecycle of the well (injection, shut-in, and production) are analyzed for the gas and water fracturing fluids. Simulation results show that natural gas and foam fracturing fluids are better than water-based fracturing fluids in terms of lower breakdown pressure, lower water leakoff into the reservoir, and higher cluster efficiency. NG foams tend to create better propped fractures with shorter length and larger width, because of their high viscosity. NG foam is also found to create better stimulated rock volume (SRV) permeability, better fracturing fluid flowback with a large water usage reduction, and high natural gas consumption. The simulation results presented in this paper are helpful to the operators in reducing natural gas emission while reducing the cost of hydraulic fracturing operation.

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.

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.

scholarly journals A Novel Hydraulic Fracturing Method Based on the Coupled CFD-DEM Numerical Simulation Study

2020 ◽  
Vol 10 (9) ◽  
pp. 3027
Author(s):  
Cong Lu ◽  
Li Ma ◽  
Zhili Li ◽  
Fenglan Huang ◽  
Chuhao Huang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Hydraulic Fracturing ◽  
Variable Viscosity ◽  
Oil Reservoirs ◽  
Fluid Viscosity ◽  
Low Density ◽  
Fracturing Fluid ◽  
Proppant Transport ◽  
Fracturing Fluids ◽  
Transport Experiment

For the development of tight oil reservoirs, hydraulic fracturing employing variable fluid viscosity and proppant density is essential for addressing the problems of uneven placement of proppants in fractures and low propping efficiency. However, the influence mechanisms of fracturing fluid viscosity and proppant density on proppant transport in fractures remain unclear. Based on computational fluid dynamics (CFD) and the discrete element method (DEM), a proppant transport model with fluid–particle two-phase coupling is established in this study. In addition, a novel large-scale visual fracture simulation device was developed to realize the online visual monitoring of proppant transport, and a proppant transport experiment under the condition of variable viscosity fracturing fluid and proppant density was conducted. By comparing the experimental results and the numerical simulation results, the accuracy of the proppant transport numerical model was verified. Subsequently, through a proppant transport numerical simulation, the effects of fracturing fluid viscosity and proppant density on proppant transport were analyzed. The results show that as the viscosity of the fracturing fluid increases, the length of the “no proppant zone” at the front end of the fracture increases, and proppant particles can be transported further. When alternately injecting fracturing fluids of different viscosities, the viscosity ratio of the fracturing fluids should be adjusted between 2 and 5 to form optimal proppant placement. During the process of variable proppant density fracturing, when high-density proppant was pumped after low-density proppant, proppants of different densities laid fractures evenly and vertically. Conversely, when low-density proppant was pumped after high-density proppant, the low-density proppant could be transported farther into the fracture to form a longer sandbank. Based on the abovementioned observations, a novel hydraulic fracturing method is proposed to optimize the placement of proppants in fractures by adjusting the fracturing fluid viscosity and proppant density. This method has been successfully applied to more than 10 oil wells of the Bohai Bay Basin in Eastern China, and the average daily oil production per well increased by 7.4 t, significantly improving the functioning of fracturing. The proppant settlement and transport laws of proppant in fractures during variable viscosity and density fracturing can be efficiently revealed through a visualized proppant transport experiment and numerical simulation study. The novel fracturing method proposed in this study can significantly improve the hydraulic fracturing effect in tight oil reservoirs.

Pilot-Scale Evaluation of Natural-Gas-Based Foam at High Pressures, Temperatures

2021 ◽  
Vol 73 (06) ◽  
pp. 60-61
Author(s):  
Chris Carpenter
Keyword(s):  
Natural Gas ◽  
Base Fluid ◽  
Produced Water ◽  
Tap Water ◽  
Pilot Scale ◽  
Test Facility ◽  
Foaming Agent ◽  
Scale Evaluation ◽  
Fracturing Fluids ◽  
Water Based

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201611, “A Pilot-Scale Evaluation of Natural-Gas-Based Foam at Elevated Pressure and Temperature Conditions,” by Griffin Beck, Swanand Bhagwat, and Carolyn Day, Southwest Research Institute, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, 5–7 October. The paper has not been peer reviewed. The complete paper presents recent results from a rigorous pilot-scale demonstration of natural-gas (NG) foam over a range of operating scenarios relevant to surface and bottomhole conditions with a variety of base-fluid mixtures. The NG foams explored in these investigations exhibited typical shear-thinning behavior observed in rheological studies of nitrogen- (N2) and carbon-dioxide- (CO2) based foams. The measured viscosity and observed stability indicate that NG foams are well-suited for fracturing applications. Test Facilities Two test facilities were used to explore properties of NG foams at a variety of relevant operating conditions to determine whether NG foam is a suitable alternative to typical water-based fracturing fluids. Pilot-Scale Foam-Test Facility. The pilot-scale foam-test facility (PFTF) is a single-pass pilot plant used to generate and characterize foams at conditions relevant to surface and reservoir conditions. The facility is capable of generating aqueous and oil-based foams using a variety of gases for the internal phase [e.g., methane (CH4), N2, and CO2]. Foams can be characterized at pressures up to 7,500 psi and temperatures up to 300°F. A key benefit of the PFTF is that it can be used to demonstrate new or challenging foaming processes before large-scale or field demonstrations. Further, these processes can be evaluated at conditions relevant to the final application. The test facility consists of three subsystems: a base-fluid system to pressurize and heat the liquid/viscosifier/surfactant mixture, a gas system to pressurize and heat the liquefied gas stream, and the foam test sections to measure various fluid properties of the NG foam. Laboratory Foam-Test Facility. Tests performed on the PFTF were limited to foams generated with pure CH4 and tap water. Additional laboratory tests were conducted to investigate the effects of multiconstituent natural gas mixtures and produced water on foam stability. For these tests, the aqueous base fluid for the foam half-life and foam rheology experiments was prepared from either de-ionized water, tap water, or a synthetic produced water based on a water sample from the Permian Basin. Foam fracturing fluids also typically contain a gelling agent and a foaming agent. The gel was prepared by slow addition of guar to a stirred water sample followed by 30 minutes of mixing to ensure complete hydration. The foaming agent was added and stirred in gently. Three foaming agents were used in this study: anionic Foamer A, nonionic Foamer B, and zwitterionic Foamer C.

In vitro cytotoxicity assessment of a hydraulic fracturing fluid

2015 ◽  
Vol 12 (3) ◽  
pp. 286 ◽  
Author(s):  
Madeleine E. Payne ◽  
Heather F. Chapman ◽  
Janet Cumming ◽  
Frederic D. L. Leusch
Keyword(s):  
Coal Seam ◽  
Hydraulic Fracturing ◽  
Human Health ◽  
Produced Water ◽  
Coal Seam Gas ◽  
Fracturing Fluid ◽  
Human Health Risks ◽  
Fracturing Fluids ◽  
Hydraulic Fracturing Fluid

Environmental context Hydraulic fracturing fluids, used in large volumes by the coal seam gas mining industry, are potentially present in the environment either in underground formations or in mine wastewater (produced water). Previous studies of the human health and environmental effects of this practice have been limited because they use only desktop methods and have not considered combined mixture toxicity. We use a novel in vitro method for toxicity assessment, and describe the toxicity of a hydraulic fracturing fluid on a human gastrointestinal cell line. Abstract Hydraulic fracturing fluids are chemical mixtures used to enhance oil and gas extraction. There are concerns that fracturing fluids are hazardous and that their release into the environment – by direct injection to coal and shale formations or as residue in produced water – may have effects on ecosystems, water quality and public health. This study aimed to characterise the acute cytotoxicity of a hydraulic fracturing fluid using a human gastrointestinal cell line and, using this data, contribute to the understanding of potential human health risks posed by coal seam gas (CSG) extraction in Queensland, Australia. Previous published research on the health effects of hydraulic fracturing fluids has been limited to desktop studies of individual chemicals. As such, this study is one of the first attempts to characterise the toxicity of a hydraulic fracturing mixture using laboratory methods. The fracturing fluid was determined to be cytotoxic, with half maximal inhibitory concentrations (IC50) values across mixture variations ranging between 25 and 51mM. When used by industry, these fracturing fluids would be at concentrations of over 200mM before injection into the coal seam. A 5-fold dilution would be sufficient to reduce the toxicity of the fluids to below the detection limit of the assay. It is unlikely that human exposure would occur at these high (‘before use’) concentrations and likely that the fluids would be diluted during use. Thus, it can be inferred that the level of acute risk to human health associated with the use of these fracturing fluids is low. However, a thorough exposure assessment and additional chronic and targeted toxicity assessments are required to conclusively determine human health risks.

scholarly journals Supramolecular dynamic binary complexes with pH and salt-responsive properties for use in unconventional reservoirs

PLoS ONE ◽  
2021 ◽  
Vol 16 (12) ◽  
pp. e0260786
Author(s):  
Bhargavi Bhat ◽  
Shuhao Liu ◽  
Yu-Ting Lin ◽  
Martin L. Sentmanat ◽  
Joseph Kwon ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Self Assembly ◽  
Energy Demand ◽  
Unconventional Reservoirs ◽  
Binary Complex ◽  
Fracturing Fluid ◽  
Zero Shear Viscosity ◽  
Fracturing Fluids ◽  
Binary Complexes ◽  
Alkaline Conditions

Hydraulic fracturing of unconventional reservoirs has seen a boom in the last century, as a means to fulfill the growing energy demand in the world. The fracturing fluid used in the process plays a substantial role in determining the results. Hence, several research and development efforts have been geared towards developing more sustainable, efficient, and improved fracturing fluids. Herein, we present a dynamic binary complex (DBC) solution, with potential to be useful in the hydraulic fracturing domain. It has a supramolecular structure formed by the self-assembly of low molecular weight viscosifiers (LMWVs) oleic acid and diethylenetriamine into an elongated entangled network under alkaline conditions. With less than 2 wt% constituents dispersed in aqueous solution, a viscous gel that exhibits high viscosities even under shear was formed. Key features include responsiveness to pH and salinity, and a zero-shear viscosity that could be tuned by a factor of ~280 by changing the pH. Furthermore, its viscous properties were more pronounced in the presence of salt. Sand settling tests revealed its potential to hold up sand particles for extended periods of time. In conclusion, this DBC solution system has potential to be utilized as a smart salt-responsive, pH-switchable hydraulic fracturing fluid.

scholarly journals FORMATION HYDRAULIC FRACTURING FLUID BASED ON CARBOXYMETHYL CELLULOSE: ITS ADVANTAGES AND LIMITATIONS, APPLICATION PROSPECTS

2016 ◽  
pp. 49-57
Author(s):  
V. R. Kalinin
Keyword(s):  
Hydraulic Fracturing ◽  
Carboxymethyl Cellulose ◽  
Low Cost ◽  
Low Permeability ◽  
Laboratory Studies ◽  
Fracturing Fluid ◽  
Fracturing Fluids ◽  
Low Permeability Reservoirs ◽  
Manufacturing Features ◽  
Hydraulic Fracturing Fluid

The article considers the advantages and limitations of hydraulic fracturing fluid based on carboxymethyl cellulose determined as a result of laboratory studies. As a result of testing the studied fluid manufacturing features compared with similar fracturing fluids it was determined that the fluid of interest can be effectively used as a fluid for formation hydraulic fracturing especially in low permeability reservoirs. This fluid is widely available and has a low cost. It can easily replace the foreign analogues.

Silica Gel Fracturing Fluids an Alternative to Guar Systems that Allows the use of West Texas Produced Water

2021 ◽  
Author(s):  
Carl Harman ◽  
Michael McDonald ◽  
Paul Short ◽  
William Ott
Keyword(s):  
Hydraulic Fracturing ◽  
Silica Gel ◽  
Fumed Silica ◽  
Produced Water ◽  
Low Cost ◽  
Field Trials ◽  
Permian Basin ◽  
West Texas ◽  
Fracturing Fluids ◽  
The Cost

Abstract The use of freshwater, near freshwater, or treated water in hydraulic fracturing represents an ever-increasing cost in the Permian Basin. Environmental concerns add to the pressure to develop methods to use significantly higher volumes of produced water in hydraulic fracture fluids. To solve the challenge of viscosifying untreated, high total dissolved solids water a move was made away from organic-based viscosifiers to silica-based technology. Fumed silica is highly effective as a viscosifier for high-density brines that has demonstrated excellent low-end rheology, exceptional suspending ability, and a nominal filter cake. However, the high cost of fumed silica and operational challenges have precluded commercial adoption. This paper describes thatsimilar rheology is achievable at a fraction of the cost using a silica gel. The focus of the paper is on the field trials in West Texas where untreated produced water was viscosified with silica gel and run as alternatives to a standard 20 lb/Mgal crosslinked guar fluid made with fresh water. Low cost and operational efficiencies were obtained bypreparingthe silica gel on-location using standard and readily available hydraulic fracturing equipment. Procedures for making the silica gel-based frac fluid were similar to those of making a crosslinked guar fluid. Field trials have demonstrated that silica-gel carries high loadings of 20/40 mesh sand even at low pump rates. Production data from the trials has varied from exceeding expectations to being similar to existing production results.On a chemical cost basis, silica gel is comparable to a borate-cross-linked guar frac fluid. The economics tip very much in favor of silica gel when factoring in the savings using untreated produced water.

Sign in / Sign up

Export Citation Format

Share Document