Incorporation of Sustainability and Economic Considerations in Process Control of Hydraulic Fracturing in Unconventional Reservoirs

Typically, the term shale oil refers to natural oil trapped in rock of low porosity and ultralow permeability. What has made the recovery of shale oil and gas economically viable is the extensive use of hydraulic fracturing. Research on the relationship between the distribution of propping agent, called proppant, and well performance indicates that uniformity of proppant bank height and suspended proppant concentration across the fracture at the end of pumping determines the productivity of produced wells. However, it is important to note that traditional pumping schedules have not considered the environmental and economic impacts of the post-fracturing process such as treatment and reuse of flowback water from fractured wells. Motivated by this consideration, a control framework is proposed to integrate sustainability considerations of the post-fracturing process into the hydraulic fracturing process. In this regard, a dynamic model is developed to describe the flow rate and the concentration of total dissolved solids (TDS) in flowback water from fractured wells. Then, a thermal membrane distillation (TMD) system is considered for the removal of TDS. A multi-objective problem is formulated to optimize the entire superstructure that consists of hydraulic fracturing, storage, transportation, and water treatment, minimizing annualized cost from recovered water per period and the water footprint of the process. The capabilities of the proposed approach are illustrated through the simulation of different scenarios that are performed to examine the effects of water availability on the productivity of stimulated wells. Finally, the impact of flowback water generation is evaluated using TRACI, a tool for the reduction and assessment of chemical and other environmental impacts

Modeling of Hydraulic Fracturing and Design of Online Optimal Pumping Schedule for Enhanced Productivity in Shale Formations

In hydraulic fracturing, the proppant-filled fracture length at the end of pumping strongly influences the fluid conductivity of natural oil and gas. Therefore, it is very important to regulate proppant bank height and suspended proppant concentration across the fracture to increase the recovery of shale hydrocarbon. From a control engineering viewpoint, hydraulic fracturing has been traditionally viewed as an open-loop problem. Well logs and mini-frac test results are interpreted prior to operation in order to obtain petrophysical and rock-mechanical properties of the formation. The operation is designed based on the properties and then is conducted accordingly. However, the open-loop operation may lead to poor performance if there are large disturbances and plant-model mismatch. In this research, a model predictive control framework is developed for the design of pumping schedules to regulate the spatial variation of proppant concentration across the fracture at the end of pumping for both of conventional and unconventional reservoirs. To this end, we initially focus on the development of a first-principle model of hydraulic fracturing process to obtain fundamental understanding of the proppant bank formation mechanism and its relationship to manipulated input variables such as proppant concentration and flow rate of the injected fracturing fluids by considering a single fracture. Then, a model-based feedback controller is developed to achieve the uniform proppant bank height and suspended proppant concentration along the fracture at the end of pumping for both of conventional and unconventional reservoirs by explicitly taking into account the desired fracture geometry, type of the fracturing fluid injected, total amount of injected proppant, actuator limitations, and safety considerations. Then, we extend this study to multi-stage hydraulic fracturing, where in each stage, multiple simultaneously propagating fractures are generated. In multi-stage hydraulic fracturing treatments, simultaneously propagating multiple fractures with close spacing often induce non-uniform fracture development due to “stress shadow effects”. In order to mitigate these undesired stress-shadow effects, we propose a model-based design technique by utilizing the limited entry design technique to compute the flow rate of fracturing fluids and the perforation conditions which will promote equal distribution of fracturing fluids to achieve uniform growth of multiple fractures. Then, a model-based feedback controller is developed to achieve a uniform proppant bank height in simultaneously propagating multiple fractures at the end of pumping by handling the undesired stress-shadow effects using the optimal perforation conditions. In hydraulic fracturing, higher fracturing fluid injection rates can trigger increased stress, thereby creating more microseismic events; particularly, simultaneously occurring multiple microseismic events can reduce measurement errors. This suggests a new state and output estimation scheme that utilizes the dependence between the fracturing fluid injection rate (i.e., manipulated input) and measurement errors. Motivated by this, we improve our control framework for measurement uncertainty reduction while achieving the original control task of proppant bank height control in hydraulic fracturing. Specifically, the developed model-based feedback control system regulates the uniformity of proppant bank height along the fracture length and achieve accurate state and output estimation by manipulating the fracturing fluid pumping schedule that includes the fracturing fluid injection rate and proppant concentration at the wellbore. In some of the unconventional reservoirs, natural fractures (discontinuities in shale rock formations) are commonly observed using advanced fracture diagnostic techniques such as microseismic monitoring, core samples and outcrops. In naturally fractured unconventional reservoirs, naturally present fractures will interact with hydraulic fractures and divert fracture propagation. Because of complex fracture growth, the ultimate goal of hydraulic fracturing operation in naturally fractured unconventional reservoirs should be changed from achieving a desired fracture geometry to maximizing the total fracture surface area (TFSA) for given fracturing resources, as it will allow more drainage area available for oil recovery. To further consider the interaction between hydraulic fractures and natural fractures, we develop a model-based pumping schedule that maximizes the TFSA by utilizing a recently developed unconventional complex fracture propagation model called Mangrove describing complex fracture networks in naturally fractured unconventional reservoirs

Hydraulic fracturing design for horizontal wells in the Bakken formation, Williston Basin

Unconventional hydrocarbon reservoirs have proved to be challenging in terms of reservoir characterization, predicting production potential, estimating ultimate recovery, and optimizing hydraulic fracture stimulations. The methods by which these resources are extracted use progressive, or unconventional, technologies. Today, through the use of hydraulic fracturing and horizontal drilling, extraordinary amounts of oil and natural gas from deep shale formations across the United States and around the world are being safely produced. Performing a hydraulic fracture design requires modeling of fracture propagation and tracking the fluid front in the created fracture. In this dissertation, the roles of all effective parameters and properties on the design and performance of hydraulic fracturing in the Bakken Formation, Williston Basin, are examined. To accomplish the above objectives, this dissertation is divided into four major sections that include: 1) basic principles of geology, lithology, and reservoir aspects of the Bakken Formation, 2) the fundamental concepts of hydraulic fracturing, 3) technology aspects are integrated into one cohesive unit to model and optimize the entire hydraulic fracture treatments, and 4) a comprehensive approach to the uncertainty assessment of the complex numerical simulations is described. In this research by integrating reservoir and hydraulic fracture simulations, a robust workflow was used to evaluate several combinations of fracturing materials (i.e. fluids and proppants) and well/fracture parameters (i.e. lateral length, fracture spacing, and fracture half-length) to identify the best candidate(s) for well stimulation planning. Using an automated history matching procedure, the reservoir properties of the Bakken Formation were estimated that can be used in future reservoir simulation projects. The fully 3D/FEM* fracture simulation showed that a fracturing treatment with injecting slickwater as the pad followed by crosslinked gel together with ceramic or resin-coated sand would guarantee that most proppants would stay within the Bakken Formation. The results from this research also suggest that in a Bakken well with a long lateral length (e.g. 10,000 ft), a fracturing strategy that leads to a relatively high fracture half-length (e.g. 1000 ft) with a high number of fractures (36 or more) would return an efficient balance between the operating charges, fracture treatment costs, drilling expenses, and the benefits earned from the incremental oil production. The pump schedule developed for the optimal fracture treatment, obtained from the fully 3D fracture modeling, would also guarantee fracture confinement within the Bakken Formation

Incorporation of Sustainability and Economic Considerations in Process Control of Hydraulic Fracturing in Unconventional Reservoirs

Typically, the term shale oil refers to natural oil trapped in rock of low porosity and ultralow permeability. What has made the recovery of shale oil and gas economically viable is the extensive use of hydraulic fracturing. Research on the relationship between the distribution of propping agent, called proppant, and well performance indicates that uniformity of proppant bank height and suspended proppant concentration across the fracture at the end of pumping determines the productivity of produced wells. However, it is important to note that traditional pumping schedules have not considered the environmental and economic impacts of the post-fracturing process such as treatment and reuse of flowback water from fractured wells. Motivated by this consideration, a control framework is proposed to integrate sustainability considerations of the post-fracturing process into the hydraulic fracturing process. In this regard, a dynamic model is developed to describe the flow rate and the concentration of total dissolved solids (TDS) in flowback water from fractured wells. Then, a thermal membrane distillation (TMD) system is considered for the removal of TDS. A multi-objective problem is formulated to optimize the entire superstructure that consists of hydraulic fracturing, storage, transportation, and water treatment, minimizing annualized cost from recovered water per period and the water footprint of the process. The capabilities of the proposed approach are illustrated through the simulation of different scenarios that are performed to examine the effects of water availability on the productivity of stimulated wells. Finally, the impact of flowback water generation is evaluated using TRACI, a tool for the reduction and assessment of chemical and other environmental impacts

Integration of Pumping Profile Design and Water Management Optimization for Shale Gas Production Systems

Unconventional shale gas production in the United States has been largely improved due to the development of hydraulic fracturing technology. However, the shale gas production system is generally complex; further, such enhanced levels of production have generated great concerns on its accompanying environmental implications, especially regarding shale gas water management. To handle the complexity associated with shale gas production system and identify the sustainable water management strategy, many optimization-based approaches have been developed. However, few of them considered the hydraulic fracturing operation as a dynamic process, where the pumping profile directly determines the volume of freshwater consumed and affects the production rates of both shale gas and wastewater. Considering the significant spatiotemporal variation in water footprint of hydraulic fracturing, those obtained planning and operational decisions of shale gas production system could be suboptimal and thus need to be updated when well development strategy changes. From another perspective, one problem could be that the pumping profile is generally designed to only maximize well productivity, without considering the impact of water management. To handle these challenges, the overall objective of this research is to develop a framework for the integration of pumping profile design and water management optimization to achieve the economically viable and environmentally sustainable water management strategy along with maximizing shale gas production. To this end, we initially focus on the development of a novel controller design framework for hydraulic fracturing while explicitly taking into account the associated post-fracturing water management. In particular, a dynamic input-output model is developed to estimate the characteristics of shale gas wastewater produced; and, a mapping-based technique is proposed to estimate the total annual cost of wastewater management and total revenue from shale gas. This framework is demonstrated to be capable to balance the trade-offs between hydraulic fracturing and water management by manipulating the pumping profile. Subsequently, we further extend this study by considering the following practical considerations. First, to better understand the significant spatiotemporal variation in water footprint associated with shale gas well development, the real water-use and flowback and produced (FP) water production data for individual shale gas wells drilled in the Eagle Ford and Marcellus shale regions are collected and analyzed. Herein, a typical model of shale gas production system is utilized to demonstrate how the variation in water recovery ratio can affect the optimal design and operation decisions. Second, to better describe the complex shale gas production system, an optimization model for shale gas supply chain network (SGSCN) incorporating of hydraulic fracturing water cycle is developed. Herein, capacity planning for both large-scale conventional facility and small-scale modular device is considered to achieve a flexible and efficient water management strategy. Third, to better integrate the optimization of shale gas production system and control of hydraulic fracturing, an online integrated scheduling and control framework with two feedback loops is proposed. Herein, the offset-free model predictive control (MPC) scheme is designed to compensate for plant-model mismatch

Economic Model-Based Controller Design Framework for Hydraulic Fracturing to Optimize Shale Gas Production and Water Usage

As water issues associated with hydraulic fracturing have received much attention, several optimization approaches have been developed for effective water management. However, most of them have not considered pumping schedules for hydraulic fracturing, which determine the productivity of a shale well as well as the total amount of freshwater required. Motivated by this consideration, a novel model-based control framework is proposed for hydraulic fracturing to maximize the net profit from shale gas development which simultaneously minimizes the total cost associated with water management. The framework is as follows; initially a reduced-order model and a Kalman filter are developed based on the simulation data generated from a high-fidelity hydraulic fracturing model to correlate the pumping schedule and the final fracture geometry. Then, a numerical reservoir simulator and mixed-integer nonlinear programming model are used to generate two maps describing the revenue from selling shale gas produced and cost from managing wastewater recovered, respectively. Finally, by applying a data-based dynamic input-output model to connect the two maps, a model predictive control system is formulated. The proposed control framework enables 62% of the generated wastewater to be reused through the application of thermal membrane distillation technology in treatment process and results in a 11% reduction in overall freshwater consumption, while maintaining the productivity of shale wells at its theoretical maximum

Shale fracturing enhancement by using polymer-free foams and ultra-light weight proppants

textSlickwater with sand is the most commonly used hydraulic fracturing treatment for shale reservoirs. The slickwater treatment produces long skinny fractures, but only the near wellbore region is propped due to fast settling of sand. Adding gel into water can prevent the fast settling of sand, but gel may damage the fracture surface and proppant pack. Moreover, current water-based fracturing consumes a large amount of water, has high water leakage, and imposes high water disposal costs. The goal of this project is to develop non-damaging, less water-intensive fracturing treatments for shale gas reservoirs with improved proppant placement efficiency. Earlier studies have proposed to replace sand with ultra-light weight proppants (ULWP) to enhance proppant transport, but it is not used commonly in field. This study evaluates the performance of three kinds of ULWPs covering a wide range of specific gravity and representing the three typical manufacturing methods. In addition to replacing sand with ULWPs, replacing water with foams can be an alternative treatment that reduces water usage and decreases proppant settling. Polymer-added foams have been used in conventional reservoirs to improve proppant placement efficiency. However, polymers can damage shale permeability in unconventional reservoirs. This dissertation studies polymer-free foams (PFF) and evaluates their performance. This study uses both experiments and simulations to assess the productivity and profitability of the ULWP treatment and PFF treatment. First, a reservoir simulation model is built in CMG to study the impact of fracture conductivity and propped length on fracture productivity. This model assumes a single fracture intersecting a few reactivated natural fractures. Second, a 2D fracturing model is used to simulate the fracture propagation and proppant transport. Third, strength, API conductivity and gravity settling rates are measured for three ULWPs. Fourth, foam stability tests are conducted to screen the best PFF agents and the selected foams are put into a circulating loop to study their rheology. Finally, empirical correlations from the experiments are applied in the fracturing model and reservoir model to predict productivity by using the ULWPs with slickwater or using the PFFs with sand. Experimental results suggest that, at 4000 psi with concentrations varying from partial monolayer (0.05 lb/ft²) to multilayer (1 lb/ft²), ULW-1 (polymeric) is the most deformable with conductivity of 1-10 md-ft. ULW-2 (resin coated and impregnated ground walnut hull) is the second most deformable with similar conductivity. ULW-3 (resin coated porous ceramic) is the least deformable with conductivity of 20-1000 md-ft, which is comparable to sand. Three foam formulations (A, B: regular surfactant foam, C: viscoelastic surfactant foam) are selected based on the stability results of fourteen surfactants. All PFFs exhibit power-law rheological behavior in a laminar flow regime. The power law parameters of the regular surfactant PFF depend on both quality and pressure when quality is higher than 60% but depend on quality only when quality is lower than 60%. Simulation results suggest that under the optimal concentration of 0.04-0.06 v/v (0.37-0.55 lb/gal) for both ULW-1 and ULW-2, and 0.1 v/v (1.46 lb/gal) for ULW-3, 1-year cumulative production for 0.1 µD shale reservoir is higher than sand by 127% for ULW-1, 28% for ULW-2, and 38% for ULW-3. The productivity benefits decrease as shale permeability increases for all three ULWPs. ULW-1 and ULW-2 have higher productivity benefits for longer production time, while ULW-3 has relatively constant productivity benefits over time. The economic profit of ULW-1 when priced at $5/lb is 2.2 times larger than that of sand for 1-year production in 0.1 µD shale reservoirs; the acceptable maximum price is$10/lb for ULW-1, $6/lb for ULW-2, and$2.5/lb for ULW-3. The maximum price increases as production time increases. The PFFs with a quality of 60% carrying mesh 40 sand at a partial monolayer concentration of 0.04 v/v (0.88 lb/gal) can generate 50% higher productivity, 74% higher economic profit, and over 300% higher water efficiency than the best slickwater-sand case (mesh 40 sand at 0.1 v/v) for 1-year production in 0.1µD shale reservoirs. The benefits of using the PFFs decrease with increasing shale permeability, increasing production time, or decreasing pumping time. This dissertation gives a range of field conditions where the ULWP and PFF may be more effective than slickwater-sand fracturing.Petroleum and Geosystems Engineerin

The Effect of Different Fracturing Fluids on the Productivity of Multi-Staged Fractured Marcellus Shale Horizontal Wells

While hydraulic fracturing has undeniably improved the production from oil and gas reservoirs, this technology is not without limitations. The primary hurdles lie in the areas of proppant transport, fluid rheology, and stress management. Despite the extensive research conducted in this domain, there remains a considerable amount of work to be done for comprehensive solutions that account for the complex interactions among fracturing fluid, proppant distribution, and geomechanical conditions. Achieving this will then make room for a holistic and efficient hydraulic fracturing strategy. This study addresses the above-mentioned problem by examining the impact of fluid type on proppant transport and distribution leading to productivity improvement for a multi-staged fractured Marcellus Shale horizontal well. In addition, stress shadow impact and the extent to which various fracture properties contribute to production are evaluated. The findings can be used to enhance fracture treatment design in the Marcellus shale through optimum fluid selection and stage spacing to reduce the impact of the stress shadow. Available core plug measurements, well logs, and image logs were analyzed to determine the shale petrophysical and geomechanical properties, including natural fracture (fissure) distribution, to develop a horizontal Marcellus Shale well model. Available laboratory measurements and published data were analyzed to determine the gas adsorption characteristics and the shale compressibility. The impact of the shale compressibility as a function of net stress was then incorporated into the model by developing multipliers for fissure and matrix permeability as well as the hydraulic fracture conductivity. The hydraulic fracture properties estimated using the GOHFER 3D software were incorporated into the developed reservoir model and ultimately, the impact of fluid type and stress shadow on proppant transport and the gas production were investigated. The reservoir model’s credibility was confirmed by a close match between the actual and predicted production. The fracture heights induced by all the fluids remained within the pay zone and the entire fracture height contributed to the production. High Viscosity Friction Reducer (HVFR) resulted in relatively larger fracture volume (with increased fracture height) in comparison to Slickwater, Crosslinked Gel, and Hybrid fluids thus resulting in improved productivity. The cross-linked gel also improved productivity but was found to be inferior to HVFR. High Percentage Reduction indicated the adverse impact of stress shadow on hydraulic fracture properties and gas production. The impact of the stress shadow on the production is, however, more pronounced during early production due to higher production rates

Enlarging the Domain of Attraction of Local Dynamic Mode Decomposition with Control Technique: Application to Hydraulic Fracturing

Local Dynamic Mode Decomposition with control (LDMDc) technique combines the concept of unsupervised learning and DMDc technique to extract the relevant local dynamics associated with highly nonlinear processes to build temporally local reduced-order models (ROMs). But the limited domain of attraction (DOA) of LDMDc hinders its widespread use in prediction. To systematically enlarge the DOA of the LDMDc technique, we utilize both the states of the system and the applied inputs from the data generated using multiple ‘training’ inputs. We implement a clustering strategy to divide the data into clusters, use DMDc to build multiple local ROMs, and implement the k-nearest neighbors technique to make a selection amongst the set of ROMs during prediction. The proposed algorithm is applied to hydraulic fracturing to demonstrate the enlarged DOA of the LDMDc technique