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Author: Dongkeun Lee
Publisher:
ISBN:
Category :
Languages : en
Pages : 390
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Book Description
Hydraulic fracturing in unconsolidated or poorly consolidated formations has been used as a technique for well stimulation and for sand control. Although a large number of hydraulic fracturing operations have been performed in soft formations, the exact mechanisms of failure and fracture propagation remain an unresolved issue. Conventional hydraulic fracturing models based on the theory of linear elastic fracture mechanics (LEFM) consistently predict lower net fracturing pressure, smaller fracture widths and longer fracture lengths in soft formations than observed in the field. Operators who want to design and analyze frac-pack treatments routinely use a hard rock model and need to calibrate and often manipulate input parameters beyond a physically reasonable range to match the net fracturing pressure and well performance data. In this dissertation, we have developed a fully-coupled, three-dimensional hydraulic fracture model for poro-elasto-plastic materials and fluid flow coupled with proppant transport. A computational framework for fluid-structure interaction (FSI) based on finite volume method was developed for modeling of hydraulic fracturing and proppant placement in soft formations. Two separate domains, a fracture and a reservoir domain, are discretized individually, separate equations are solved in the two domains, and their interactions are modeled. The model includes the fully coupled process of power-law fluid flow inside the fracture with proppant transport, fluid leak-off from the fracture into the porous reservoir, pore pressure diffusion into the reservoir, inelastic deformation of the poro-elasto-plastic reservoir, and fracture propagation using a cohesive zone model along with a dynamic meshing procedure. Fully-coupled processes between the two domains, and pressure, flow and displacement coupling within each domain are modeled by an iterative and segregated solution procedure, where each component of the field variable is solved separately, consecutively, and iteratively. We verified the essential components of the model by comparing our simulation results with several well-known analytical solutions (elastoplastic deformation and failure problem, KGD model in a 2-D elastic domain, and KGD model in storage-toughness dominated regime). We applied the model to design and analyze frac-pack operations conducted in a Gulf of Mexico oilfield. Our model is capable of capturing the high net fracturing pressure commonly observed during frac-packing operations without adjusting any input parameters. The model shows quantitatively that plasticity causes lower stress concentration around the fracture tip which shields the tip of the propagating fracture from the fracturing pressure, and retards fracture growth. Our model predicts shorter fracture lengths and wider widths compared to a hard rock model. Shear failure around the fracture and ahead of the tip are modeled. Low cohesion sands tend to fail in shear first then in tension if sufficient pore pressure builds up. We investigated the effect of fluid viscosity, injection rate, and proppant diameter on fracture growth and proppant placement using sensitivity studies. Higher apparent fluid viscosity and injection rate results in wider fractures with better proppant placement, when the fracture is expected to be contained within the payzone. Utilizing larger diameter of proppant leads to settling-dominant proppant placement resulting in the formation of a proppant bank at the bottom of the induced fracture. The new frac-pack model for the first time allows operators to design and analyze hydraulic fracturing stimulations in soft, elastoplastic formations when complex fracturing fluids are used. Our results also provide guidelines for the selection of fracturing fluid rheology, proppant size, and injection rates.
Author: Dongkeun Lee
Publisher:
ISBN:
Category :
Languages : en
Pages : 390
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Book Description
Hydraulic fracturing in unconsolidated or poorly consolidated formations has been used as a technique for well stimulation and for sand control. Although a large number of hydraulic fracturing operations have been performed in soft formations, the exact mechanisms of failure and fracture propagation remain an unresolved issue. Conventional hydraulic fracturing models based on the theory of linear elastic fracture mechanics (LEFM) consistently predict lower net fracturing pressure, smaller fracture widths and longer fracture lengths in soft formations than observed in the field. Operators who want to design and analyze frac-pack treatments routinely use a hard rock model and need to calibrate and often manipulate input parameters beyond a physically reasonable range to match the net fracturing pressure and well performance data. In this dissertation, we have developed a fully-coupled, three-dimensional hydraulic fracture model for poro-elasto-plastic materials and fluid flow coupled with proppant transport. A computational framework for fluid-structure interaction (FSI) based on finite volume method was developed for modeling of hydraulic fracturing and proppant placement in soft formations. Two separate domains, a fracture and a reservoir domain, are discretized individually, separate equations are solved in the two domains, and their interactions are modeled. The model includes the fully coupled process of power-law fluid flow inside the fracture with proppant transport, fluid leak-off from the fracture into the porous reservoir, pore pressure diffusion into the reservoir, inelastic deformation of the poro-elasto-plastic reservoir, and fracture propagation using a cohesive zone model along with a dynamic meshing procedure. Fully-coupled processes between the two domains, and pressure, flow and displacement coupling within each domain are modeled by an iterative and segregated solution procedure, where each component of the field variable is solved separately, consecutively, and iteratively. We verified the essential components of the model by comparing our simulation results with several well-known analytical solutions (elastoplastic deformation and failure problem, KGD model in a 2-D elastic domain, and KGD model in storage-toughness dominated regime). We applied the model to design and analyze frac-pack operations conducted in a Gulf of Mexico oilfield. Our model is capable of capturing the high net fracturing pressure commonly observed during frac-packing operations without adjusting any input parameters. The model shows quantitatively that plasticity causes lower stress concentration around the fracture tip which shields the tip of the propagating fracture from the fracturing pressure, and retards fracture growth. Our model predicts shorter fracture lengths and wider widths compared to a hard rock model. Shear failure around the fracture and ahead of the tip are modeled. Low cohesion sands tend to fail in shear first then in tension if sufficient pore pressure builds up. We investigated the effect of fluid viscosity, injection rate, and proppant diameter on fracture growth and proppant placement using sensitivity studies. Higher apparent fluid viscosity and injection rate results in wider fractures with better proppant placement, when the fracture is expected to be contained within the payzone. Utilizing larger diameter of proppant leads to settling-dominant proppant placement resulting in the formation of a proppant bank at the bottom of the induced fracture. The new frac-pack model for the first time allows operators to design and analyze hydraulic fracturing stimulations in soft, elastoplastic formations when complex fracturing fluids are used. Our results also provide guidelines for the selection of fracturing fluid rheology, proppant size, and injection rates.
Author: D. Mader
Publisher: Elsevier
ISBN: 0080868843
Category : Technology & Engineering
Languages : en
Pages : 1277
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Book Description
Many aspects of hydraulic proppant fracturing have changed since its innovation in 1947. The main significance of this book is its combination of technical and economical aspects to provide an integrated overview of the various applications of proppants in hydraulic fracturing, and gravel in sand control. The monitoring of fractures and gravel packs by well-logging and seismic techniques is also included.The book's extensive coverage of the subject should be of special interest to reservoir geologists and engineers, production engineers and technologists, and well log analysts.
Author: Ming Gu
Publisher:
ISBN:
Category :
Languages : en
Pages : 0
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Book Description
Slickwater 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 [mu]D 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 [mu]D 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 0.1[mu]D 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.
Author: Kenneth Imo-Imo Israel Eshiet
Publisher: BoD – Books on Demand
ISBN: 183768331X
Category :
Languages : en
Pages : 134
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Book Description
Author: Yanan Ding
Publisher:
ISBN:
Category :
Languages : en
Pages : 0
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Book Description
In addition to conventional enhanced oil recovery (EOR) technologies, extensive efforts have been made to explore new approaches to sustain the increasing global oil and gas consumption while lowering the operational costs. In recent decades, nanoparticles (NPs) have seen their promising potentials in recovering hydrocarbons from numerous laboratory experiments and field pilots. Also, hydraulic fracturing techniques have unlocked a significant quantity of hydrocarbon resources from unconventional reservoirs. Solid particle transport including NP transport, dispersion, and distribution in hydrocarbon reservoirs, proppant placement within hydraulic fractures, and sand production is critical to the efficient and effective hydrocarbon exploitation. Considering the petrophysical complexity as well as the intricate interactions among particles, fluids, and rock matrix, it is, therefore, an extremely challenging task to accurately predict the associated transport and placement behaviour of solid particles in a hydrocarbon reservoir. Theoretically, a robust and pragmatic method has been developed and validated to analytically determine the dynamic dispersion coefficients for particles flowing in a parallel-plate fracture with instantaneous point source as well as uniform and volumetric line sourcess, in which particle gravity settling effect has been considered. It is found that the point source and the uniform line source are respectively the most and least sensitive to the gravity effect. An increase of particle size larger than its critical value decreases the asymptotical dispersion coefficient for all the source conditions, while gravity settling promotes the dispersion phenomenon during the early-stage of point source condition. Particle-tracking simulations have been performed and validated on polydisperse dense particle transport in a randomly-orientated fracture with spatially variable apertures. The simulated results indicate that the mass breakthrough efficiency of particles and particle plume distribution in a randomly-orientated rough fracture are significantly influenced by different factors when particle gravity settling occurs. In addition, particle attachment consisting of reversible and irreversible adsorptions on an aperture surface is quantified applying the Derjaguin-Landau-Verwey-Overbeek (DLVO) kinetics. With sensitivity analysis performed, the impacts of different factors on particle attachment are found to vary with each other through non-unique patterns. By integrating the Perkins-Kern-Nordgren-Carter (PKN-C) fracture propagation model and the particle tracking algorithm, a novel Eulerian-Lagrangian (E-L) model has been developed and validated to simulate field-scale proppant transport during hydraulic fracturing operations. Such an E-L model incorporates pertinent empirical correlations determined from regressing experimental measurements regarding the proppant settling velocity and the drag/lift forces, which is applicable to both the Newtonian and non- Newtonian fluid conditions. The non-Newtonian fluid is usually found to yield a less "heel-biased" pattern of proppant distribution in a hydraulic fracture, e.g., a larger slurry coverage together with a longer proppant dune, while distinct patterns of the dominant factors are observed and evaluated.
Author: Songyang Tong
Publisher:
ISBN:
Category :
Languages : en
Pages : 0
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Book Description
During hydraulic fracturing treatments, proppants - usually sand - are placed inside fractures to improve fracture conductivity. However, a large portion of the generated hydraulic fractures often remain unpropped after fracturing treatments. There are two primary reasons for this poor proppant placement. First, proppants settle quickly in common fracturing fluids (e.g., slickwater), which results in unpropped sections at the tip or top of the fracture. Second, a large number of the microfractures are too narrow to accommodate any common commercial proppant. Such unpropped fractures hold a large potential flow capacity as they exhibit a large contact area with the reservoir. However, their potential flow capacity is diminished during production due to closing of unpropped fractures because of closure stress. In this study, fractures are categorized as wider fractures, which are accessible to proppant, and narrower fractures, which are inaccessible to proppant. For wider fractures, proppant transport is important as proppant is needed for keeping them open. For narrower fractures, a chemical formulation is proposed as there is less physical restriction for fluids to flow inside across them. The chemical formulation is expected to improve fracture conductivity by generating roughness on fracture surfaces. This dissertation uses experiments and simulations to investigate proppant transport in a complex fracture network with laboratory-scale transparent fracture slots. Proppant size, injection flow rate and bypass fracture angle are varied and their effects are systematically evaluated. Based on experimental results, a straight-line relationship can be used to quantify the fraction of proppant that flows into bypass fractures with the total amount of proppant injected. A Computational Fluid Dynamics (CFD) model is developed to simulate the experiments; both qualitative and quantitative matches are achieved with this model. It is concluded that the fraction of proppant which flows into bypass fractures could be small unless a significant amount of proppant is injected, which indicates the inefficiency of slickwater in transporting proppant. An alternative fracturing fluid - foam - has been proposed to improve proppant placement because of its proppant carrying capacity. Foam is not a single-phase fluid, and it suffers liquid drainage with time due to gravity. Additionally, the existence of foam bubbles and lamellae could alter the movement of proppants. Experiments and simulations are performed to evaluate proppant placement in field-scale foam fracturing application. A liquid drainage model and a proppant settling correlation are developed and incorporated into an in-housing fracturing simulator. Results indicate that liquid drainage could negatively affect proppant placement, while dry foams could lead to negligible proppant settling and consequently uniform proppant placement. For narrower fractures, two chemical stimulation techniques are proposed to improve fracture conductivity by increasing fracture surface roughness. The first is a nanoparticle-microencapsulated acid (MEA) system for shale acidizing applications, and the second is a new technology which can generate mineral crystals on the shale surface to act as in-situ proppants. The MEA could be released as the fracture closes and the released acid could etch the surface of the rock locally, in a non-uniform way, to improve fracture conductivity (up to 40 times). Furthermore, the in-situ proppant generation technology can lead to crystal growth in both fracking water and formation brine conditions, and it also improves fracture conductivity (up to 10 times) based on core flooding experiments
Author: Michael Berry Smith
Publisher: CRC Press
ISBN: 1466566922
Category : Science
Languages : en
Pages : 793
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Book Description
Hydraulic Fracturing effectively busts the myths associated with hydraulic fracturing. It explains how to properly engineer and optimize a hydraulically fractured well by selecting the right materials, evaluating the economic benefits of the project, and ensuring the safety and success of the people, environment, and equipment. From data estimation
Author: Mengting Li
Publisher: Cuvillier Verlag
ISBN: 3736989342
Category : Technology & Engineering
Languages : en
Pages : 208
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Book Description
Hydraulic fracturing is essential technology for the development of unconventional resources such as tight gas. So far, there are no numerical tools which can optimize the whole process from geological modeling, hydraulic fracturing until production simulation with the same 3D model with consideration of the thermo-hydro-mechanical coupling. In this dissertation, a workflow and a numerical tool chain were developed for design and optimization of multistage hydraulic fracturing in horizontal well regarding a maximum productivity of the tight gas wellbore. After the verification a full 3D reservoir model is generated based on a real tight gas field in the North German Basin. Through analysis of simulation results, a new calculation formula of FCD was proposed, which takes the proppant position and concentration into account and can predict the gas production rate more accurately. However, not only FCD but also proppant distribution and hydraulic connection of stimulated fractures to the well, geological structure and the interaction between fractures are determinant for the gas production volume. Through analysis the numerical results of sensitivity analysis and optimization variations, there is no unique criterion to determine the optimal number and spacing of the fractures, it should be analyzed firstly in detail to the actual situation and decided then from case to case.
Author: Yu-Shu Wu
Publisher: Gulf Professional Publishing
ISBN: 0128129999
Category : Technology & Engineering
Languages : en
Pages : 568
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Book Description
Hydraulic Fracture Modeling delivers all the pertinent technology and solutions in one product to become the go-to source for petroleum and reservoir engineers. Providing tools and approaches, this multi-contributed reference presents current and upcoming developments for modeling rock fracturing including their limitations and problem-solving applications. Fractures are common in oil and gas reservoir formations, and with the ongoing increase in development of unconventional reservoirs, more petroleum engineers today need to know the latest technology surrounding hydraulic fracturing technology such as fracture rock modeling. There is tremendous research in the area but not all located in one place. Covering two types of modeling technologies, various effective fracturing approaches and model applications for fracturing, the book equips today’s petroleum engineer with an all-inclusive product to characterize and optimize today’s more complex reservoirs. Offers understanding of the details surrounding fracturing and fracture modeling technology, including theories and quantitative methods Provides academic and practical perspective from multiple contributors at the forefront of hydraulic fracturing and rock mechanics Provides today’s petroleum engineer with model validation tools backed by real-world case studies
Author: Davorin Matanovic
Publisher: Springer Science & Business Media
ISBN: 3642256139
Category : Science
Languages : en
Pages : 205
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Book Description
Produced sand causes a lot of problems. From that reasons sand production must be monitored and kept within acceptable limits. Sand control problems in wells result from improper completion techniques or changes in reservoir properties. The idea is to provide support to the formation to prevent movement under stresses resulting from fluid flow from reservoir to well bore. That means that sand control often result with reduced well production. Control of sand production is achieved by: reducing drag forces (the cheapest and most effective method), mechanical sand bridging (screens, gravel packs) and increasing of formation strength (chemical consolidation). For open hole completions or with un-cemented slotted liners/screens sand failure will occur and must be predicted. Main problem is plugging. To combat well failures due to plugging and sand breakthrough Water-Packing or Shunt-Packing are used.
