Hydraulic Fracture Treatment and Landing Zone Interval Optimization: An Eagle Ford Case Study

2022 ◽  
Author(s):  
Abdulrahim K. Al Mulhim ◽  
Jennifer L. Miskimins ◽  
Ali Tura
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Three Dimensional ◽  
Fracture Treatment ◽  
Fracturing Fluid ◽  
Eagle Ford ◽  
Landing Zone ◽  
Fracturing Fluids ◽  
Austin Chalk ◽  
The Subject

Abstract This paper focuses on optimizing future well landing zones and their corresponding hydraulic fracture treatments in the Eagle Ford shale play. The optimum landing zone and stimulation treatment were determined by analyzing multiple landing zone options, including the lower Austin Chalk, Eagle Ford, and Pepper Shale, with several hydraulic fracturing treatment possibilities. Fracturing fluids and their volume, proppant size, and cluster spacing were investigated to determine the optimum hydraulic fracturing treatment for the subject geologic area. Ranges of 75,000 to 300,000 gallons of pure gel, pure slickwater, and hybrid fracturing fluids along with 20/40, 30/50, 40/70, and 100 mesh proppant were tested. Cluster spacing of twenty feet to eighty feet were also sensitized in this study. A fully three-dimensional hydraulic fracture modeling software was used to develop a geological and geomechanical model of the studied area. The generated model was calibrated with available field data to ensure that the model reflects the area's geological and geomechanical characteristics. The developed model was used to create fracture results for each sensitized parameter. Production analysis was performed for all fracture models to determine the optimum landing zone and fracturing treatment implications. The study shows that the Eagle Ford had better production than the lower Austin Chalk in the subject area. The Pepper Shale had the highest potential hydrocarbon production, around 326 Mbbl cumulative, when fractured with a pure gel treatment. The analyses showed that a hybrid treatment with 70% gel and 30% slickwater yielded the optimum production due to the treatment economics even though the highest production was obtained using the pure gel. Treating the formation with larger proppant provided better production than smaller proppant due to conductivity concerns associated with damaging mechanisms in the studied area. Since increasing the volume above 175,000 gallons caused a negligible increase in the production, 175,000 gallons of fracturing fluid per stage appeared to be the optimum fracturing fluid volume. Thirty-foot cluster spacing was the optimum spacing in the study area. Overall, the study suggests that oil production can be improved in the Eagle Ford study area through a detailed workflow development and optimization process. The hydraulic fracture treatment and landing zone optimization workflow ensures optimum hydrocarbon extraction from the study area. The developed workflow can be applied to new unconventional plays instead of using trial and error methods.

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 Analysis of Pressure Communication between the Austin Chalk and Eagle Ford Reservoirs during a Zipper Fracturing Operation

Energies ◽  
2019 ◽  
Vol 12 (8) ◽  
pp. 1469 ◽  
Author(s):  
Sriniketh Sukumar ◽  
Ruud Weijermars ◽  
Ibere Alves ◽  
Sam Noynaert
Keyword(s):  
Hydraulic Fracturing ◽  
Field Data ◽  
Pressure Increase ◽  
Rapid Decline ◽  
Residual Pressure ◽  
Eagle Ford ◽  
Austin Chalk ◽  
Temporal Pressure ◽  
Pressure Changes ◽  
First Time

The recent interest in redeveloping the depleted Austin Chalk legacy field in Bryan (TX, USA) mandates that reservoir damage and subsurface trespassing between adjacent reservoirs be mitigated during hydraulic fracture treatments. Limiting unintended pressure communication across reservoir boundaries during hydraulic fracturing is important for operational efficiency. Our study presents field data collected in fall 2017 that measured the annular pressure changes that occurred in Austin Chalk wells during the zipper fracturing treatment of two new wells in the underlying Eagle Ford Formation. The data thereby obtained, along with associated Eagle Ford stimulation reports, was analyzed to establish the degree of pressure communication between the two reservoirs. A conceptual model for pressure communication is developed based on the pressure response pattern, duration, and intensity. Additionally, pressure depletion in the Austin Chalk reservoir is modeled based on historic production data. Pressure increases observed in the Austin Chalk wells were about 6% of the Eagle Ford injection pressures. The pressure communication during the fracture treatment was followed by a rapid decline of the pressure elevation in the Austin Chalk wells to pre-fracture reservoir pressure, once the Eagle Ford fracture operation ended. Significant production uplifts occurred in several offset Austin Chalk wells, coeval with the observed temporal pressure increase. Our study confirms that after the rapid pressure decline following the short-term pressure increase in the Austin Chalk, no residual pressure communication remained between the Austin Chalk and Eagle Ford reservoirs. Limiting pressure communication between adjacent reservoirs during hydraulic fracturing is important in order to minimize the loss of costly fracturing fluid and to avoid undue damage to the reservoir and nearby wells via unintended proppant pollution. We provide field data and a model that quantifies the degree of pressure communication between adjacent reservoirs (Austin Chalk and Eagle Ford) for the first time.

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 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 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.

Fully Coupled Hydromechanical Simulation of Hydraulic Fracturing in Three-Dimensional Discrete Fracture Networks

2015 ◽  
Author(s):  
Mark W. McClure ◽  
Mohsen Babazadeh ◽  
Sogo Shiozawa ◽  
Jian Huang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Three Dimensional ◽  
Hydraulic Fractures ◽  
Fracture Aperture ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Field Scale ◽  
Discrete Fracture Networks ◽  
Discrete Fracture

Abstract We developed a hydraulic fracturing simulator that implicitly couples fluid flow with the stresses induced by fracture deformation in large, complex, three-dimensional discrete fracture networks. The simulator can describe propagation of hydraulic fractures and opening and shear stimulation of natural fractures. Fracture elements can open or slide, depending on their stress state, fluid pressure, and mechanical properties. Fracture sliding occurs in the direction of maximum resolved shear stress. Nonlinear empirical relations are used to relate normal stress, fracture opening, and fracture sliding to fracture aperture and transmissivity. Fluid leakoff is treated with a semianalytical one-dimensional leakoff model that accounts for changing pressure in the fracture over time. Fracture propagation is treated with linear elastic fracture mechanics. Non-Darcy pressure drop in the fractures due to high flow rate is simulated using Forchheimer's equation. A crossing criterion is implemented that predicts whether propagating hydraulic fractures will cross natural fractures or terminate against them, depending on orientation and stress anisotropy. Height containment of propagating hydraulic fractures between bedding layers can be modeled with a vertically heterogeneous stress field or by explicitly imposing hydraulic fracture height containment as a model assumption. The code is efficient enough to perform field-scale simulations of hydraulic fracturing with a discrete fracture network containing thousands of fractures, using only a single compute node. Limitations of the model are that all fractures must be vertical, the mechanical calculations assume a linearly elastic and homogeneous medium, proppant transport is not included, and the locations of potentially forming hydraulic fractures must be specified in advance. Simulations were performed of a single propagating hydraulic fracture with and without leakoff to validate the code against classical analytical solutions. Field-scale simulations were performed of hydraulic fracturing in a densely naturally fractured formation. The simulations demonstrate how interaction with natural fractures in the formation can help explain the high net pressures, relatively short fracture lengths, and broad regions of microseismicity that are often observed in the field during stimulation in low permeability formations, and which are not predicted by classical hydraulic fracturing models. Depending on input parameters, our simulations predicted a variety of stimulation behaviors, from long hydraulic fractures with minimal leakoff into surrounding fractures to broad regions of dense fracturing with a branching network of many natural and newly formed fractures.

High-Resolution 3D Structural Geomechanics Modeling for Hydraulic Fracturing

2015 ◽  
Author(s):  
T.. Bérard ◽  
J.. Desroches ◽  
Y.. Yang ◽  
X.. Weng ◽  
K.. Olson
Keyword(s):  
High Resolution ◽  
Stress Field ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Three Dimensional ◽  
Image Data ◽  
Natural Fractures ◽  
Fracture Length ◽  
3D Space ◽  
Wellbore Pressure

Abstract Three-dimensional (3D) geomechanical models built at reservoir scale lack resolution at the well sector scale (e.g., hydraulic fracture scale), at least laterally. One-dimensional (1D) geomechanical models, on the other hand, have log resolution along the wellbore but no penetration away from it—along the fracture length for instance. Combining borehole structural geology based on image data and finite elements (FE) geomechanics, we constructed and calibrated a 3D, high-resolution geomechanical model, including subseismic faults and natural fractures, over a 1,500- × 5,200- × 300-ft3 sector around a vertical pilot and a 3,700-ft lateral in the Fayetteville shale play. Compared to a 1D approach, we obtained a properly equilibrated stress field in 3D space, in which the effect of the structure, combined with that of material anisotropy and heterogeneity, are accounted for. These effects were observed to be significant on the stress field, both laterally and local to the faults and natural fractures. The model was used to derive and map in 3D space a series of geomechanically based attributes potentially indicative of hydraulic fracturing performance and risks, including stress barriers, fracture geometry attributes, near-well tortuosity, and the level of stress anisotropy. An interesting match was observed between some of the derived attributes and fracturing data—near-wellbore pressure drop and overall ease and difficulty to place a treatment—encouraging their use for perforation and stage placement or placement of the next nearby lateral. The model was also used to simulate hydraulic fracturing, taking advantage of such a 3D structural and geomechanical representation. It was shown that the structure and heterogeneity captured by the model had a significant impact on hydraulic fracture final geometry.

Characterizing Pore-Scale Geochemical Alterations in Eagle Ford and Barnett Shale from Exposure to Hydraulic Fracturing Fluid and CO2/H2O

2020 ◽  
Vol 35 (1) ◽  
pp. 583-598
Author(s):  
Sean Sanguinito ◽  
Patricia Cvetic ◽  
Angela Goodman ◽  
Barbara Kutchko ◽  
Sittichai Natesakhawat
Keyword(s):  
Hydraulic Fracturing ◽  
Barnett Shale ◽  
Pore Scale ◽  
Fracturing Fluid ◽  
Eagle Ford ◽  
Hydraulic Fracturing Fluid

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.

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