bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Production Analysis Using the Concept of Dynamic Drainage Volume: Modelling, Simulation and Field Applications
Authors: Yuan Bin , Zheng Da , Ghanbarnezhad Moghanloo Rouzbeh 
Published: August 2016

Abstract
This paper adopts an empirical-analytical hybrid model of dynamic drainage volume (DDV) into a novel workflow of integrated production analysis to evaluate and predicate the performance of multi-stage fractured horizontal well (MFHW). A weak (integral) form of macroscopic mass balance model with moving boundary is developed for the expanding productive region (drainage volume) during long-term transient-flow regimes in non-static shale reservoirs saturated with compressible fluids. An analytical-empirical formulation of DDV is derived using concept of impulse response and multi-variable regression method, which includes the effects of different diffusivity within both stimulated-reservoir volume (SRV) and unstimulated matrix, fracture half-length, and fracture spacing etc. The effects of stress-dependent reservoir and pressure-dependent fluid properties on production analysis are incorporated by a pressure-dependent correction factor. To verify the accuracy of our integrated analysis, firstly, we start with a synthetic simulation example with known parameters. In the next stages, several field examples are examined with our integrated analysis approach to evaluate and predicate the performance of MFHW.
The size of DDV and associated average reservoir pressure, recovery factor (RF) and phase saturation (oil/gas/water) are achieved. The half-length of primary fracture and diffusivity within SRV are also evaluated by coupled with a correction factor, and the ultimate drainage volume (estimated as ultimate recovery, EUR) is also predicated at abandonment condition, which indicates the maximum size of system affected by single-well production for us to optimize well spacing. Moreover, the contributions of both unstimulated-reservoir matrix and stimulated-reservoir volume (SRV) are quantified with changing time, respectively.
The proposed approach has the following novel contributions: (1) capability to ascertain DDV and associated average reservoir pressure throughout different transient-flow regimes; (2) coupled the non-static, fluid compressibility, multi-phase flow and moving flow boundary effects into production history analysis; and 3) simplicity and efficiency; does not require comprehensive inputs as opposed to sophisticated numerical simulations, but could obtain almost all of the necessary parameters for evaluation and predication.
Reducing Uncertainties of Fracture Characterization on Production Performance by Incorporating Microseismic and Core Analysis Data
Authors: Gamboa Edith Sotelo , Sun Jianlei , Schechter David 
Published: August 2016

Abstract
Hydraulic fracture treatments may induce complex network geometries that are challenging to incorporate in numerical flow simulators. To capture this complexity, we propose a workflow that integrates a semi-stochastic Discrete Fracture Network (DFN) generator constrained by Microseismic events, core data and an efficient Perpendicular Bisector (PEBI) grid generator for the explicit discretization of the network. We applied this workflow to evaluate the effect of DFN related uncertainties on production performance.
We developed a DFN model that constrains the location of natural fractures by microseismic events and samples fracture characteristics from core-data-based Probability Density Functions (PDFs). The model also interconnects natural and hydraulic fractures through a geomechanics-based algorithm. For an efficient fracture discretization, we developed a PEBI meshing technique capable to conform to low-angle intersections of extensively clustered network, incorporating optimization algorithms that reduce highly skewed cells, and ensure good mesh quality. Finally, to evaluate the impact of DFN related uncertainties on production, we implemented an efficient Monte Carlo (MC) methodology that minimizes flow simulations.
We implemented the workflow in a stage of a hydraulic fracture treatment to evaluate the impact of two type of DFN related uncertainties on production: those coming from the randomness of DFN modeling and those coming from the lack of accurate knowledge of PDF parameters. We show that the proposed DFN modeling approach can be applied to calculate the "Fluid-Producing DFN (FP-DFN)," which is the network area connected to the well and able to produce, to minimize flow simulations for the MC runs. After performing efficient-based MC simulations with our DFN model, we were able to generate the FP-DFN Cumulative Density Function (CDF) incorporating the aforementioned uncertainties. From this CDF, different percentiles were selected with the respective DFN realizations for fluid simulations. We show that the developed PEBI meshing algorithm is capable to grid efficiently these complex DFN geometries with good mesh quality. Finally, 20-year production simulations suggest that a difference of several MSTB between the lowest and highest percentiles may exist revealing the effect of the DFN related uncertainties on production.
Our integrated workflow provides a methodology to efficiently model and mesh explicitly complex DFN systems for numerical fluid simulations, incorporating microseismic and core data. Furthermore, this methodology, together with the implementation of an efficient MC technique, allows a quantitative evaluation of the impact on production forecast of DFN related uncertainties.
Development of Seawater-Based Fracturing Fluid for High-Temperature Wells
Authors: Vo L. K. , Biyani M. V. , Cortez J.. , Hoeman K.. 
Published: August 2016

Abstract
The development of a high-temperature seawater-based fracturing fluid has received much attention because it offers a solution to fresh water shortages; however, the rheological properties suffer significantly as a result of interactions between dissolved ions with fluid components. Various strategies have been investigated to address this challenge, including seawater treatments that ultimately remove the highly soluble and insoluble ionic moieties to yield a fracturing fluid with reliable rheological characteristics.
Most polymer-based fracturing fluids have limited salt tolerance. Interactions between the polymer and divalent cations in seawater inhibit proper polymer hydration, thus preventing generation of an elastic polymer network and potentially affecting the crosslinking mechanism. In this study, concentrations of critical ions in seawater were reduced using a reliable seawater treatment. This treatment allowed a reliable fluid at higher temperatures and also considerably reduced the scaling tendency of the fluid. The fluid presented herein, designed in the treated seawater, yields a stable elastic polymer network when used in conjunction with stabilizing additives and is capable of effectively delivering proppant down hole.
This newly developed formulation uses a combination of instant and delayed crosslinkers and additional stabilizing additives required at optimum concentrations to yield a stable fluid system in the treated seawater. At high temperatures, the addition of typical ion sequestration agents failed to eliminate the negative interaction between dissolved ions and fluid stability, thus requiring water pre-treatment. The fluid system exhibits reliable rheological properties and yields a clean broken fluid for excellent proppant pack cleanup in high total dissolved solids (TDS) waters up to 350°F. Typical guar-based fracturing fluids require a high pH (greater than 10) to maintain rheological stability at high temperatures. The fracturing fluid presented herein was developed at pH 9 in treated seawater and maintained its elasticity and viscosity over a long period of time at temperatures up to 350°F. An added benefit of controlling the pH and not surpassing pH 9.5 was also revealed—scale control.
This study discusses the development of a new seawater-based fracturing fluid for use in high-temperature wells. This can result in a paradigm shift in source water use for hydraulic fracturing.
The Evolution and Control of Fluid Phase During Liquid CO2 Fracturing
Authors: Meng Siwei , Liu He , Xu Jianguo , Duan Yongwei , Yang Qinghai , Yao Zixiu 
Published: August 2016

Abstract
Liquid CO2 fracturing is a novel stimulation technology, which helps realize multiple objectives such as conservation of water, sequestration of greenhouse gases and enhancement of single-well productivity and ultimate recovery. During operations, CO2 flows through storage tank, booster pump, blender, fracturing pump, and eventually into wellbore and production zone, generating a changing temperature and pressure distribution. CO2‘s phase state, density and viscosity properties change consequently, which influence significantly the reliability and stimulation effect.
In a liquid CO2 fracturing field test for tight oil, temperature and pressure sensors are positioned at 12 critical nodes (including booster pump, blender, fracturing pump, wellhead and bottom hole) to monitor CO2 fluid. To ensure the reliability, CO2 is required to maintain in liquid state both on the surface and subsurface. Inlet, inside and outlet pressure of the blender should be concerned, because the blender utilizes non-mechanical pump, which requires sufficient motive flow to draw proppants into the main pipe, while the pressure difference directly impacts the flow rate of motive flow.
The field test is successfully implemented with satisfactory result, 21 m3 proppants are added into the formation. The main conclusions are as follow. (1) In low-pressure fluid feeding stage, partial CO2 is gasified, which influences the stability of fluid feeding; In future a buffer vessel will be placed between storage tanks and booster pumps, which will provide adjustment for phase control; And a heat exchanger may help by further reduce the temperature of CO2.(2) Pressure difference among inlet, inside and outlet pressure of blender fluctuates during the whole process, with the probable reason of two additional static mixers, which create system pressure drop. (3) The temperature of CO2 is very low in low-pressure stage, and the pipes are frosted; When pumping pressure reaches 38MPa, the temperature gradually exceeds 0°C, and the pipes are defrosted.
Phase evolution during liquid CO2 fracturing has been identified, and phase control method has been determined. This helps improvethe stability of fluid feeding and sand adding, and enhances the success ratio and stimulation result of fracturing.
Modeling of Injection Induced Seismic Events
Authors: Zhang Xi , Jeffrey Robert G. , Wu Bisheng , Zhang Guangqing 
Published: August 2016

Abstract
Using a BEM-based hydraulic fracture model and the Coulomb frictional law, the generation of slip and shear rupturing produced by fluid injection is investigated. A wide range of factors can contribute to injection-induced seismicity. In addition to injection rate, fluid viscosity and existing permeability, several other factors are considered in this paper to determine their effects on slip development during continuous fluid injection and during shut-in. These factors include dilatant strengthening, slip weakening of frictional coefficients, structural complexities along a rupturing path like jogs and branches and the application of far-field wave-form stresses. The numerical method is summarized and the theoretical formulation of the above physical processes associated with generation of seismic events is provided. The numerical results show a rich and complex local slip rate change during extension of the slip zone. Under fluid injection, the slip can first produce a seismic event either caused by rapidly increasing pressure or by abrupt slip initiation, and then slows. When the permeability is large enough, the slip pattern manifests itself as long-term slow slip period coupled with aseismic slip transients. The long-duration and low-magnitude seismic events are associated with the slipping state in the conditionally stable regime, in which fluid pressure is marginally equal to a value required to produce slip using the effective stress and the static frictional strength. A small perturbation in the fluid pressure caused by any of the above factors can stop and/or generate relatively faster slip rates. The slip continues varying with time after shut-in in the presence of the above influencing factors. The slow slip on a fault, which is difficult to detect by seismology, could be a significant process in dissipating elastic strain energy during hydraulic fracturing stimulations. In addition, the model can capture a tendency of the slip rate to become significantly large. The results demonstrate the importance of fracture and fault permeability enhancement on variations of fluid pressure and slip rates.
Thermal-Stress Induced Fracture Propagation by Cold Fluid - An Improved Hydraulic Fracturing Treatment for Unconventional Gas Reservoirs
Authors: Song Huifang , Liang Zhirong , Chen Zhixi , Gholizadeh Doonechaly Nima , Arns Ji-Youn , S. Rahman Sheik 
Published: August 2016

Abstract
Unconventional gas reservoirs (shale gas, tight gas and coal bed methane) constitute a large percentage of natural gas supply. Hydraulic fracturing is commonly used to break-up rock matrix and connect natural fractures and cleats to create gas flow pathways. Application of hydraulic fracturing, however, poses several problems including extremely low matrix permeability and poor connectivity between matrix and fractures. Several studies have been made in field and in laboratory to open and interconnect these natural fractures and cleat system with cold fluid, results of which are found to be promising. In this paper we present a parametric design analysis as to the application of thermal stress (due to cold fluid injection) induced hydraulic fracture treatment.
Propagation of natural fractures and cleats surrounding the induced hydraulic fracture by thermal induced stress is investigated in hydro-thermo-mechanical (THM) framework both numerically and experimentally to quantify the effect of thermal shock. Increase in fracture (natural fractures and cleats) aperture and propagation is modelled by cohesive zone method. Numerical results were validated by injecting cold liquid in 1 in diameter coal sample and changes in permeability were recorded. During the same time, the changes in aperture and length of cleat and fractures respectively were monitored by μ-CT.
Numerical results show that as the cooling front due to invasion of cold fluid moves into the matrix, it facilitates initiation of cracks in planes of weakness and/ or causes the cleats and natural fractures to open and propagate some distance away from the hydraulic fracture surface. This phenomenon is more pronounced around crack tips due to severe thermal straining. It was also observed that SIF and J-integral of cracks are much higher than that without thermal effect.
Thermal stress induced cleats and natural fracture propagation surrounding the treatment area extends the reach of the hydraulic fracture which otherwise could not have been connected. In this paper we present a quantitative analysis of the effect of thermal stress on fracture/ cleat propagation behaviour so that an improved understanding is gained with regard to the application of low temperature fracturing.
A Comprehensive Evaluation of Well Completion and Production Performance in Bakken Shale Using Data-Driven Approaches
Authors: Wang Shuhua , Chen Shengnan 
Published: August 2016

Abstract
The Bakken unconventional resource in Williston Basin is becoming an important component of hydrocarbon sources in North America. Although advanced horizontal drilling and multi-stage stimulation techniques being successful to exploit Bakken formations, appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery of the shale or tight reservoirs. Data-driven approaches, such as deep neural network modeling and global sensitivity analysis, are promising methods to evaluate hidden correlations between multi-stage hydraulic fracturing strategies and well productions.
In this study, a total of 2919 wells including 2780 multi-stage hydraulically fractured horizontal wells and 139 vertical wells in the Bakken formation were collected and analyzed using a deep learning method and Sobol's sensitivity analysis. 18 features of a single horizontal well were extracted from the raw data resources. These features contain five aspects: well location and geometry, Bakken formation thickness, hydraulic fracture characterization, fracturing fluid, and proppant. 6 months' and 18 months' cumulative production were utilized to characterize the after-stimulation performance of horizontal wells. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, Batch Normalization, Adadelta optimizer were applied to develop the reliable deep neural network. Moreover, k-fold cross validation approach was used to evaluate the prediction ability and robustness of the models. Finally, the importance of each parameter was studied using the Sobol's sensitivity analysis.
Deep learning neural networks were firstly and successfully developed to predict the oil production of hydraulically fractured horizontal wells. The overall performance of deep network models is acceptable with a low mean squared error between estimated and measured oil production. The configuration type of networks has little effect on the performance of deep network models. While the number of layers and neurons in each layer have a significant effect on the performance of models. The best number of layers ranges from 4 to 7, and best number of neurons in each layer is between 100 and 200. Sobol's sensitivity analysis indicates that the average proppant placed per stage is the most important parameter contributing to ~ 35% of both the 6 months' and 18 months' cumulative oil production variability. Moreover, the interaction effects among parameters should be considered during the hydraulic fracturing design.
Results from this work can be used to optimize multi-stage hydraulic fracturing design for new Bakken wells. The proposed deep learning method and sensitivity analysis provide a potential workflow to evaluate well after-stimulation performance for multi-stage fractured horizontal wells and can be integrated into reservoir decision-making routines.
Production Logging of Shale Gas Well in China
Authors: Wei Pang , Dejia Di , Jun Mao , Tongyi Zhang , Ying He , Shuang Ai 
Published: August 2016

Abstract
China is the first country achieving shale gas breakthrough outside the North America. Fuling shale gas play is one of the most successful shale gas reservoirs by far in China. However, production loggings of shale gas wells illustrate that only about one third to one half of hydraulic fractures produces. Meanwhile, the productive fractures contribute differently to the production rate. Therefore, production logging technology is needed to evaluate the production status and contribution per stage or cluster, and get clear understanding of post-fracturing performance.
The paper generalized the difficulties and challenges for production logging taking the geology and well condition into consideration in Fuling shale gas play in China. These challenges include snubbing operation, production logging tools selection, tools conveying, unclean wellbore and complex flow regime in horizontal wellbore.
Aiming at solving the above the difficulties, one design of coiled tubing conveyed combination of conventional tools with single sensor and array tools with multiple sensors is formed. The array tools are used to diagnose fluid phase and measure gas/liquid holdup, thus data from single sensor tools and multiple-sensor array tools measurements can be combined to enhance the quality of the interpretation results. By comparison, the coiled tubing is more suitable for conveying the downhole tools in deep well with long horizontal wells. The Appropriate coiled tubing diameter is chosen and the coiled tubing passing ability in the horizontal lateral is simulated. The characteristics of array testing tools produced by Schlumberger and Sondex are analyzed. Since the array tools have the potential risks of being blocked or even damaged by fragments of bridge plugs, therefore, the borehole cleaning technique is considered. By statistics of wellhead pressure of shale gas wells in Fuling shale play, the BOP should be with pressure capacity over 50 MPa.
One case well in Fuling shale gas play shows that it is feasible to use coiled tubing conveyed array tools for production logging in shale gas well. The testing data interpretation results demonstrate the reliability of data interpretation method and the significance of production logging. For the case well, one half (6 stages out of 11 stages) fractures produce gas and the other half contribute nothing. The productive fractures also present different performance and the most predominant fracture contribute 36.47% of the total production. By production logging, not only fracture contribution to total production rate can be obtained, the flow regime and dynamic liquid level can also be determined. The production logging can be helpful for downhole fluid dynamic analysis and production optimization, and it may partly help the design of horizontal laterals and fractures scenarios.
Understanding Production Mechanism to Optimise Well Stimulation by Production Analysis in Keshen HPHT and Natural Fractured Tight Gas Reservoir
Authors: Yang Xiangtong , Huang Yongjie , Liu Ju , Xian Chenggang , Qiu Kaibin , Teng Qi , Gu Xiao , Zhao Meng , Pan Yuanwei , Wang Nan 
Published: August 2016

Abstract
The main pay of the Keshen gas field is a tight sand formation with very low porosity (2% to 7%) and permeability (0.001md-0.1md). Due to the ultra-deep formation depth and superior high reservoir pressure (greater than 116 MPa) and temperatures (above 160°C), the well construction and field development costs are very high. Therefore, stimulation treatments is essential for achieving sufficiently high production rate and the basis for justifying the costs. Natural fractures (NF) are developed in the reservoir with high heterogeneity which leads to complex production mechanism due to interaction between matrix and NFs, and causes difficulties on stimulation optimization.
To better understand the reservoir and optimize the well stimulation, the matrix properties, natural fracture, geomechanical data and stimulation data has been reviewed along with production data. Massive production history matching work has been done to evaluate the NFs. Other dynamic data like the well testing data and pressure data also reviewed to help understand NFs development in the full field scal. Production analysis was conducted to link the rock properties, NFs and wells' performance, and provided full understanding of production controlling factor in this reservoir. The post production analysis helped to understand the efficiency of stimulation. The production behavior for different stimulation strategy also have been illustrated by the simulation models to investigate the impaction on the stimualtion optimization strategy by the interaction between matrix and NFs.
The study provided a good understanding of the production mechanism in this kind of natural fractured reservoir and NF's impact on the stimulation efficiency. The heterogeneity of NF results in very different production mechanism given similar matrix petrophysical behavior. Based on production mechanism, each well requires a customized stimulation to maximize the production potential.
This study presented a case study for evaluating the production mechanism and highlighted the importance on evaluating the production mechanism on optimizing the stimulation for the naturally fractured tight reservoir.