Socio-Inspired Multi-Cohort Intelligence and Teaching-Learning-Based Optimization for Hydraulic Fracturing Parameters Design in Tight Formations

2021 ◽  
pp. 1-18
Author(s):  
Temoor Muther ◽  
Fahad Iqbal Syed ◽  
Amirmasoud Kalantari Dahaghi ◽  
Shahin Negahban
Keyword(s):  
Hydraulic Fracturing ◽  
High Performance ◽  
Local Maximum ◽  
Gas Production ◽  
Production Performance ◽  
Design Parameters ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
Teaching Learning Based Optimization ◽  
Teaching Learning

Abstract Hydraulic fracturing is one of the revolutionary technologies widely applied to develop tight hydrocarbon reservoirs. Moreover, hydraulic fracture design optimization is an essential step to optimize production from tight reservoirs. This study presents the implementation of three new socio-inspired algorithms on hydraulic fracturing optimization. The work integrates reservoir simulation, artificial neural networks, and preceding optimization algorithms to attain the optimized fractures. For this study, a tight gas production dataset is initially generated numerically for a defined set of the fracture half-length, fracture height, fracture width, fracture conductivity, and the number of fractures' values. Secondly, the generated dataset is trained through a neural network to predict the effects of preceding parameters on gas production. Lastly, three new socio-inspired algorithms including Cohort Intelligence (CI), Multi-cohort Intelligence (Multi-CI), and Teaching Learning-based optimization (TLBO) are applied to the regressor output to obtain optimized gas production performance with the combination of optimum fracture design parameters. The results are then compared with the traditionally used optimizers including Particle Swarm Optimization (PSO) and Genetic Algorithm (GA). The results demonstrated that the Multi-CI and TLBO converge at the global best position more often with a success rate of atleast 95% as compared to CI, PSO, and GA. Moreover, the CI, PSO, and GA are found to stuck many times at the local maximum. This concludes that the Multi-CI and TLBO are good alternatives to PSO and GA considering their high performance in determining the optimum fracture design parameters, in comparison.

Impact of the Cluster Spacing on Hydraulic Fracture Conductivity and Productivity of a Marcellus Shale Horizontal Well

2021 ◽  
Author(s):  
Mohamed El Sgher ◽  
Kashy Aminian ◽  
Ameri Samuel
Keyword(s):  
Hydraulic Fracture ◽  
Marcellus Shale ◽  
Technical Information ◽  
Gas Production ◽  
Production Performance ◽  
Valuable Insight ◽  
Fracture Conductivity ◽  
Fracture Properties ◽  
Gas Recovery ◽  
The Impact

Abstract The objective of this study was to investigate the impact of the hydraulic fracturing treatment design, including cluster spacing and fracturing fluid volume on the hydraulic fracture properties and consequently, the productivity of a horizontal Marcellus Shale well with multi-stage fractures. The availability of a significant amount of advanced technical information from the Marcellus Shale Energy and Environment Laboratory (MSEEL) provided an opportunity to perform an integrated analysis to gain valuable insight into optimizing fracturing treatment and the gas recovery from Marcellus shale. The available technical information from a horizontal well at MSEEL includes well logs, image logs (both vertical and lateral), diagnostic fracture injection test (DFIT), fracturing treatment data, microseismic recording during the fracturing treatment, production logging data, and production data. The analysis of core data, image logs, and DFIT provided the necessary data for accurate prediction of the hydraulic fracture properties and confirmed the presence and distribution of natural fractures (fissures) in the formation. Furthermore, the results of the microseismic interpretation were utilized to adjust the stress conditions in the adjacent layers. The predicted hydraulic fracture properties were then imported into a reservoir simulation model, developed based on the Marcellus Shale properties, to predict the production performance of the well. Marcellus Shale properties, including porosity, permeability, adsorption characteristics, were obtained from the measurements on the core plugs and the well log data. The Quanta Geo borehole image log from the lateral section of the well was utilized to estimate the fissure distribution s in the shale. The measured and published data were utilized to develop the geomechnical factors to account for the hydraulic fracture conductivity and the formation (matrix and fissure) permeability impairments caused by the reservoir pressure depletion during the production. Stress shadowing and the geomechanical factors were found to play major roles in production performance. Their inclusion in the reservoir model provided a close agreement with the actual production performance of the well. The impact of stress shadowing is significant for Marcellus shale because of the low in-situ stress contrast between the pay zone and the adjacent zones. Stress shadowing appears to have a significant impact on hydraulic fracture properties and as result on the production during the early stages. The geomechanical factors, caused by the net stress changes have a more significant impact on the production during later stages. The cumulative gas production was found to increase as the cluster spacing was decreased (larger number of clusters). At the same time, the stress shadowing caused by the closer cluster spacing resulted in a lower fracture conductivity which in turn diminished the increase in gas production. However, the total fracture volume has more of an impact than the fracture conductivity on gas recovery. The analysis provided valuable insight for optimizing the cluster spacing and the gas recovery from Marcellus shale.

scholarly journals OPTIMISATION OF HYDRAULIC FRACTURING DESIGN IN LOWER OLIGOCENE RESERVOIR, KINH NGU TRANG OILFIELD

2018 ◽  
Vol 18 (3) ◽  
pp. 323-337
Author(s):  
Nguyen Huu Truong
Keyword(s):  
Hydraulic Fracturing ◽  
Complex Structure ◽  
Power Requirement ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
The North ◽  
Fracture Closure ◽  
Average Water ◽  
White Tiger ◽  
Fracture Height

Kinh Ngu Trang oilfield is of the block 09-2/09 offshore Vietnam, which is located in the Cuu Long basin, the distance from that field to Port of Vung Tau is around 140 km and it is about 14 km from the north of Rang Dong oilfield of the block 15.2, and around 50 km from the east of White Tiger in the block 09.1. That block accounts for total area of 992 km2 with the average water depth of around 50 m to 70 m. The characteristic of Oligocene E reservoir is tight oil in sandstone, very complicated with complex structure. Therefore, the big challenges in this reservoir are the low permeability and the low porosity of around 0.2 md to less than 1 md and 1% to less than 13%, respectively, leading to very low fracture conductivity among the fractures. Through the Minifrac test for reservoir with reservoir depth from 3,501 mMD to 3,525 mMD, the total leak-off coefficient and fracture closure pressure were determined as 0.005 ft/min0.5 and 9,100 psi, respectively. To create new fracture dimensions, hydraulic fracturing stimulation has been used to stimulate this reservoir, including proppant selection and fluid selection, pump power requirement. In this article, the authors present optimisation of hydraulic fracturing design using unified fracture design, the results show that optimum fracture dimensions include fracture half-length, fracture width and fracture height of 216 m, 0.34 inches and 31 m, respectively when using proppant mass of 150,000 lbs of 20/40 ISP Carbolite Ceramic proppant.

Geologic Controls on Gas Production and Hydraulic-Fracturing Flowback in Tight Gas Sandstones of the Late Jurassic Monteith Formation, Deep Basin, Alberta, Canada

2016 ◽  
Vol 19 (01) ◽  
pp. 024-040 ◽  
Author(s):  
Liliana Zambrano ◽  
Per K. Pedersen ◽  
Roberto Aguilera
Keyword(s):  
Hydraulic Fracturing ◽  
Gas Production ◽  
Production Performance ◽  
Rock Properties ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Deep Basin ◽  
Rock Types ◽  
Sandstone Reservoirs ◽  
Geologic Controls

Summary A comparison of rock properties integrated with production performance and hydraulic-fracturing flowback (FB) of the uppermost lithostratigraphic “Monteith A” and the lowermost portion “Monteith C” of the Monteith Formation in the Western Canada Sedimentary Basin (WCSB) in Alberta is carried out with the use of existing producing gas wells. The analyses are targeted to understand the major geologic controls that differentiate the two tight gas sandstone reservoirs. This study consists of basic analytical tools available for geological characterization of tight gas reservoirs that is based on the identification and comparison of different rock types such as depositional, petrographic, and hydraulic for each lithostratigraphic unit of the Monteith Formation. As these low-matrix-permeability sandstone reservoirs were subjected to intense post-depositional diagenesis, a comparison of the various rock types allows the generation of more-accurate reservoir description, and a better understanding of the key geologic characteristics that control gas-production potential and possible impact on hydraulic-fracturing FB. Well performance and FB were the focus of many previous simulation and geochemical studies. In contrast, we find that an adequate understanding of the rocks hosting hydraulic fractures is a necessary complement to those studies for estimating FB times. This understanding was lacking in some previous studies. As a result, a new method is proposed on the basis of a crossplot of cumulative gas production vs. square root of time for estimating FB time. It is concluded that the “Monteith A” unit has better rock quality than the “Monteith C” unit because of less-heterogeneous reservoir geometry, less-complex mineralogical composition, and larger pore-throat apertures.

Comparison of stationary and rotary matrix heat exchangers using teaching-learning-based optimization algorithm

2017 ◽  
Vol 232 (4) ◽  
pp. 493-502 ◽  
Author(s):  
Hassan Hajabdollahi
Keyword(s):  
Heat Exchanger ◽  
Pressure Drop ◽  
Optimization Algorithm ◽  
Heat Exchangers ◽  
Design Parameters ◽  
Matrix Heat Exchanger ◽  
Teaching Learning Based Optimization ◽  
Mass Flow Rates ◽  
Teaching Learning ◽  
Matrix Heat

In this paper, two kinds of compact heat exchanger including plate fin heat exchanger and rotary regenerator, respectively the stationary and rotary matrix heat exchanger, are compared. For this purpose, both heat exchangers are optimized by considering three simultaneous objective functions including effectiveness, heat exchanger volume, and total pressure drop using multi-objective teaching learning based optimization algorithm. Six different design parameters are considered for the both plate fin heat exchanger and rotary regenerator. Optimization is performed for the same and different hot and cold side mass flow rates. The optimum results reveal 13.26% growth in the effectiveness, 475.17% increase in the volume, and 95.45% reduction in the pressure drop in RR as compared with plate fin heat exchanger and for the final optimum point. As a result, rotary regenerator is more suitable in the case of high effectiveness and low pressure drop while plate fin heat exchanger is more suitable in the case of space limitation (lower heat exchanger volume).

scholarly journals Implementation of Hydraulic Fracturing Operation for a Reservoir in KRG

2019 ◽  
Vol 3 (2) ◽  
pp. 10-21
Author(s):  
Akram Humoodi ◽  
Maha Hamoudi ◽  
Rasan Sarbast
Keyword(s):  
Hydraulic Fracturing ◽  
Design Procedure ◽  
Oil Field ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
Fracturing Process ◽  
Before And After ◽  
Fracture Height ◽  
Well Data ◽  
Field Formation

This study focuses on procedures to enhance permeability and flow rate for a low permeability formation by creating a conductive path using the hydraulic fracturing model. Well data are collected from the Qamchuqa KRG oil field formation. A Fracpro simulator is used for modelling the hydraulic fracturing process in an effective way. The study focuses on an effective hydraulic fracturing design procedure and the parameters affecting the fracture design. Optimum design of fracturing is achieved by selecting the proper fracturing fluid with a suitable proppant carried in a slurry, determining the formation fracturing pressure, selection of a fracture propagation fluid, and also a good proppant injection schedule, using a high pump rate and good viscosity. Permeability and conductivity are calculated before and after applying the hydraulic fracturing. Fracture height, length, and width are calculated from the Fracpro software, among other parameters, and the production rate changes. From the results, it is observed that by using hydraulic fracturing technology, production will increase and permeability will be much higher. The original formation permeability is 2.55 md, and after treatment, the average fracture conductivity has significantly increased to 1742.3 md-ft. The results showed that average fracture width is 0.187 inch. The proppant used in this treatment has a permeability of 122581 md. The suitable fluid choice is hyper with an apparent viscosity of 227.95 cp, and the proper proppant type is Brady sand with a conductivity of 2173.41 md-ft. Fracture orientation from the Khurmala oil field in Kurdistan is vertical fractures produced at a depth of 1868 m. Fracture half-length, total fracture height, and average fracture width are 220 ft, 42 ft, and 0.47 inch, respectively. After fracturing, the maximum and average area of fracture are 33.748 and 17.248 ft2, respectively. The recommended pump hydraulic horse power is 3200 HHP, and the total required fluid is 1076.3 bbl. In this study, hydraulic fracture is designed, and then, it has been analyzed after that production is optimized.

Zipper Fracturing of Horizontal Cluster Wells: Game Changing Unconventional Fracturing in UAE

2021 ◽  
Author(s):  
Yang Wu ◽  
Ole Sorensen ◽  
Nabila Lazreq ◽  
Yin Luo ◽  
Tomislav Bukovac ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
United Arab Emirates ◽  
Shale Gas ◽  
New Technology ◽  
Operational Efficiency ◽  
Gas Production ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Fracture Width ◽  
Friction Reducer

Abstract Following the increase in demand for natural gas production in the United Arab Emirates (UAE), unconventional hydraulic fracturing in the country has grown exponentially and with it the demand for new technology and efficiency to fast-track the process from fracturing to production. Diyab field has historically been a challenging field for fracturing given the high-pressure/high-temperature (HP/HT) conditions, presence of H2S, and the strike-slip to thrust faulting conditions. Meanwhile, operational efficiency is necessary for economic development of this shale gas reservoir. Hence "zipper fracturing" was introduced in UAE with modern technologies to enable both operational efficiency and reservoir stimulation performance. The introduction of zipper fracturing in UAE is considered a game changer as it shifted the focus from single-well fracturing to multiple well pads that allow for fracturing to take place in one well while the adjacent well is undergoing a pumpdown plug-and-perf operation using wireline. The overall setup of the zipper surface manifold allowed for faster transitions between the two wells; hence, it also rendered using large storage tanks a viable option since the turnover between stages would be short. Thus, two large modular tanks were installed and utilised to allow 160,000 bbl of water storage on site. Similarly, the use of high-viscosity friction reducer (HVFR) has directly replaced the common friction reducer additive or guar-based gel for shale gas operation. HVFR provides higher viscosity to carry larger proppant concentrations without the reservoir damage, and the flexibility and simplicity of optimizing fluid viscosity on-the-fly to ensure adequate fracture width and balance near-wellbore fracture complexity. Fully utilizing dissolvable fracture plugs was also applied to mitigate the risk of casing deformation and the subsequent difficulty of milling plugs after the fracturing treatment. Furthermore, fracture and completion design based on geologic modelling helped reduce risk of interaction between the hydraulic fractures and geologic abnormalities. With the application of advanced logistical planning, personnel proficiency, the zipper operation field process, clustered fracture placement, and the pump-down plug-and-perforation operation, the speed of fracturing reached a maximum of 4.5 stages per day, completing 67 stages in total between two wells placing nearly 27 million lbm of proppant across Hanifa formation. The maximum proppant per stage achieved was 606,000 lbm. The novelty of this project lies in the first-time application of zipper fracturing, as well as the first application of dry HVFR fracturing fluid and dissolvable fracturing plugs in UAE. These introductions helped in improving the overall efficiency of hydraulic fracturing in one of UAE's most challenging unconventional basins in the country, which is quickly demanding quicker well turnovers from fracturing to production.

scholarly journals Intelligent CAD System for Automatic Detection of Mitotic Cells from Breast Cancer Histology Slide Images Based on Teaching-Learning-Based Optimization

2014 ◽  
Vol 2014 ◽  
pp. 1-9 ◽  
Author(s):  
Ramin Nateghi ◽  
Habibollah Danyali ◽  
Mohammad Sadegh Helfroush ◽  
Ashkan Tashk
Keyword(s):  
Breast Cancer ◽  
High Performance ◽  
False Positives ◽  
Support Vector ◽  
Svm Classifier ◽  
Computer Assisted ◽  
Cad System ◽  
Teaching Learning Based Optimization ◽  
Teaching Learning ◽  
Mitotic Cells

This paper introduces a computer-assisted diagnosis (CAD) system for automatic mitosis detection from breast cancer histopathology slide images. In this system, a new approach for reducing the number of false positives is proposed based on Teaching-Learning-Based optimization (TLBO). The proposed CAD system is implemented on the histopathology slide images acquired by Aperio XT scanner (scanner A). In TLBO algorithm, the number of false positives (falsely detected nonmitosis candidates as mitosis ones) is defined as a cost function and, by minimizing it, many of nonmitosis candidates will be removed. Then some color and texture (textural) features such as those derived from cooccurrence and run-length matrices are extracted from the remaining candidates and finally mitotic cells are classified using a specific support vector machine (SVM) classifier. The simulation results have proven the claims about the high performance and efficiency of the proposed CAD system.

scholarly journals Multi-Size Proppant Pumping Schedule of Hydraulic Fracturing: Application to a MP-PIC Model of Unconventional Reservoir for Enhanced Gas Production

Processes ◽  
2020 ◽  
Vol 8 (5) ◽  
pp. 570 ◽  
Author(s):  
Prashanth Siddhamshetty ◽  
Shaowen Mao ◽  
Kan Wu ◽  
Joseph Sang-Il Kwon
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Computational Cost ◽  
Three Dimensional ◽  
Sensitivity Study ◽  
Gas Production ◽  
Field Scale ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Proppant Transport

Slickwater hydraulic fracturing is becoming a prevalent approach to economically recovering shale hydrocarbon. It is very important to understand the proppant’s transport behavior during slickwater hydraulic fracturing treatment for effective creation of a desired propped fracture geometry. The currently available models are either oversimplified or have been performed at limited length scales to avoid high computational requirements. Another limitation is that the currently available hydraulic fracturing simulators are developed using only single-sized proppant particles. Motivated by this, in this work, a computationally efficient, three-dimensional, multiphase particle-in-cell (MP-PIC) model was employed to simulate the multi-size proppant transport in a field-scale geometry using the Eulerian–Lagrangian framework. Instead of tracking each particle, groups of particles (called parcels) are tracked, which allows one to simulate the proppant transport in field-scale geometries at an affordable computational cost. Then, we found from our sensitivity study that pumping schedules significantly affect propped fracture surface area and average fracture conductivity, thereby influencing shale gas production. Motivated by these results, we propose an optimization framework using the MP-PIC model to design the multi-size proppant pumping schedule that maximizes shale gas production from unconventional reservoirs for given fracturing resources.

scholarly journals OPTIMIZATION OF OPERATING FRACTURING PARAMETERS FOR IMPROVING OIL PRODUCTION IN LOWER OLIGOCENE E RESERVOIR USING RESPONSE SURFACE METHOD, OFFSHORE VIETNAM: A CASE STUDY

2019 ◽  
Vol 18 (4) ◽  
pp. 422-432
Author(s):  
Truong Nguyen Huu
Keyword(s):  
Net Present Value ◽  
Oil Production ◽  
Geological Structure ◽  
Injection Rate ◽  
Production Performance ◽  
Injection Time ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
Fractured Well

In the recent days, hydraulic fracturing technique has been widely used to improve oil production with different reservoir characteristics such as low or high formation permeability, low or high formation porosity, formation damage. However, previous research did not mention the optimization for fracturing parameters including the injection rate, injection time, and leak-off coefficient to stimulate the Oligocene E reservoir, which is based on optimum oil production performance at which maximum net present value has been achieved. The problems in the Oligocene reservoir are too low production rate due to high reservoir depth, high closure pressure up to 7,700 psi, low reservoir permeability, low porosity and geological structure with heterogeneous reservoir, high temperature, resulting in low conductivity. To deal with these problems, fracturing technique is the best choice to stimulate this reservoir. The study focuses on optimizing fracturing parameters by applying the CCD and RSM  by which economic production performance has been maximized at 119 $ in 10 years. The optimum fracturing parameters have been found as injection rate of 47 bpm, injection time of 119 minutes and leak-off coefficient of 0.003 ft/min0.5 in 50 pounds per thousand gallons of polymer (HPG). The optimal fracture geometry has been obtained with the fracture half-length of 1,449.44 ft and fracture width of 0.567 in. The rest of experimental laboratory is to measure fracture conductivity at 3,400 mD.ft in terms of proppant fracture concentration of 1.78 lb/ft2 and high closure pressure of 7700 psi. The post fractured well shows an increase in oil productivity of 7.5 folds.

Modeling and experimental investigation of the evolution of altered zones at the shale-fluid interface

2020 ◽  
Author(s):  
Hang Deng ◽  
Sergi Molins ◽  
Carl Steefel ◽  
John Bargar ◽  
Adam Jew ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Reactive Transport ◽  
Oil And Gas ◽  
Transport Model ◽  
Gas Production ◽  
Production Performance ◽  
Fracture Permeability ◽  
Oil And Gas Production ◽  
Fracturing Fluids ◽  
The Matrix

<p>Unconventional oil and gas production involves the use of acidic hydraulic fracturing fluids that interact with the rock matrix bordering the fractures. As a result, fracture permeability and mass transfer between the matrix and the fracture can be altered, affecting production performance. The evolution of the altered zones are controlled by the gradients of pH and concentrations of various species perpendicular to the fracture-matrix interface, mineral reactions in the matrix as the reactive fluid diffuse into the matrix, and potential mineral coating on the fracture surface where the matrix fluid and fracture fluid mix. In this study, we use reactive transport model to investigate the evolution of the altered zones bordering the fractures. The simulations are based on batch and fracture flow experiments of shales and syntheized hydraulic fracturing fluids. Through the simulations, we quantify the reaction front of different mineral phases and the change of local porosity, and examine their dependence on mineral composition and fluid chemistry. We also discuss the impacts of the altered zones on matrix diffusivity and fracture permeability.</p>

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