Insights into Field Application of EOR Techniques from Modeling of Tight Reservoirs with Complex High-Density Fracture Network

Aiming at the stress sensitivity problem of tight reservoirs with different microfractures, the cores of H oilfield and J oilfield with different microfractures were obtained through the fractures experiment, so as to study the change of gas permeability in tight sandstone core plug during the change of confining pressure. Besides, we use the nuclear magnetic resonance (NMR) spectra of the core before and after saturation to verify whether the core has been successfully fractured. Based on Terzaghi’s effective stress principle, the permeability damage rate (D) and the stress sensitivity coefficient (Ss) are used to evaluate the stress sensitivity of the core, which show consistency in evaluating the stress sensitivity. At the same time, we have studied the petrological characteristics of tight sandstone in detail using thin section (TS) and scanning electron microscope (SEM). The results show that the existence of microfractures is the main factor for the high stress sensitivity of tight sandstone. In addition, because of the small throat of the tight reservoir core, the throat closes when the overlying stress increases. As a result, the tight sandstone pore size is greatly reduced and the permeability is gradually reduced. Therefore, in the development of tight reservoirs, we should not only consider the complex fracture network produced by fracturing, but also pay attention to the permanent damage of reservoirs caused by stress sensitivity.

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Experimental Study of the Factors Influencing Filtrate Loss of the High-Density Brine Drilling Fluid

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.361-363.461 ◽

2011 ◽

Vol 361-363 ◽

pp. 461-464

Author(s):

Ming Zhang ◽

Tian Tai Li ◽

Xi Feng Zhang

Keyword(s):

Laboratory Experiments ◽

Oil And Gas ◽

Drilling Fluid ◽

Field Application ◽

High Density ◽

Fluid Loss ◽

Affecting Factors ◽

Oil And Gas Fields ◽

Filtrate Loss ◽

Gas Fields

High density brine drilling fluid has been widely applied in the high pressure and complex oil and gas fields. Effectively controlling high density brine drilling fluid loss is an important factor for reducing the reservoir damage and keeping well stability. Base on general drilling fluid formulations，the affecting factors of filtrate loss of high density brine drilling fluid were analysed through mass laboratory experiments. The results show that the main fctor was the content of caustic soda and bentonite, secondly the density and the shape of adding product. The combination of adding product is one of effective method to control the filtration property of high density brine drilling fluid. The results will provide reliable foundation for successful field application.

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Paleozoic Tight Reservoirs in Algeria; Fault and Fracture Network Modeling in a Challenging Complex Geological Environment

10.3997/2214-4609.2019x621008 ◽

2019 ◽

Author(s):

J.P. Van Dijk ◽

A.T. Ajayi ◽

L. De Vincenzi ◽

H. Ellen ◽

H. Guney ◽

...

Keyword(s):

Network Modeling ◽

Fracture Network ◽

Geological Environment ◽

Tight Reservoirs ◽

Fracture Network Modeling

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Use of a CO2-Hybrid Fracturing Design to Enhance Production from Unpropped Fracture Networks

10.2118/spe-173380-ms ◽

2015 ◽

Author(s):

Lionel H. Ribeiro ◽

Huina Li ◽

Jason E. Bryant

Keyword(s):

Fracture Network ◽

Fracturing Fluid ◽

Fracture Conductivity ◽

Low Viscosity ◽

Bottom Hole ◽

Complex Fracture Network ◽

Tight Reservoirs ◽

The Many ◽

Fluid Design ◽

Present Simulation

Abstract This paper introduces a new CO2-hybrid fracturing fluid design that intends to improve production from ultra-tight reservoirs and reduces freshwater usage. The design consists of: (1) injecting pure CO2 as the pad fluid to generate a complex fracture network, and (2) injecting a gelled slurry (water- or foamed-based) to generate near-wellbore conductivity. The motivation behind this design is that while current aqueous fluids provide sufficient primary hydraulic fracture conductivity back to the wellbore, they under-stimulate the reservoir and leave behind damaged stimulated regions deeper in the fracture network. Much of that (unpropped) stimulated area is ineffective for production due to interfacial tension effects, fines generation, and/or polymer damage. We present simulation work that demonstrates how CO2, with its low viscosity, can extend the bottom-hole treating pressure deeper in the reservoir and generate a larger producible surface area. We also present experimental evidence that CO2 leaves behind higher unpropped fracture conductivities than slick water. This paper does not address the many operational and logistical challenges of using CO2 as a fracturing fluid. Rather, it intends to demonstrate the production uplift potential of the proposed design, which seems particularly attractive in reservoirs capable of sustaining production from unpropped fractures (e.g., reservoirs with low stress anisotropy, high Young's modulus, and a pervasive set of natural fractures).

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Pore Pressure Disturbance Induced by Multistage Hydraulic Fracturing in Shale Gas: Modelling and Field Application

Geofluids ◽

10.1155/2019/1315451 ◽

2019 ◽

Vol 2019 ◽

pp. 1-11 ◽

Cited By ~ 1

Author(s):

Yijin Zeng ◽

Zizhen Wang ◽

Yanbin Zang ◽

Ruihe Wang ◽

Feifei Wang ◽

...

Keyword(s):

Pore Pressure ◽

Shale Gas ◽

Fracture Network ◽

Field Application ◽

Differential Pressure ◽

Fluid Viscosity ◽

Fracturing Fluid ◽

Pressure Disturbance ◽

Modelling Method ◽

Lower Permeability

Currently, there is no proper method to predict the pore pressure disturbance caused by multistage fracturing in shale gas, which has challenged drilling engineering in practice, especially for the infilling well drilling within/near the fractured zones. A numerical modelling method of pore pressure redistribution around the multistage fractured horizontal wellbore was put forward based on the theory of fluid transportation in porous media. The fracture network of each stage was represented by an elliptical zone with high permeability. Five stages of fracturing were modelled simultaneously to consider the interactions among fractures. The effects of formation permeability, fracturing fluid viscosity, and pressure within the fractures on the pore pressure disturbance were numerically investigated. Modelling results indicated that the pore pressure disturbance zone expands as the permeability and/or the differential pressure increases, while it decreases when the viscosity of the fracturing fluid increases. The pore pressure disturbance level becomes weaker from the fracture tip to the far field along the main-fracture propagation direction. The pore pressure disturbance contours obviously have larger slopes with the variation of permeability than those of the differential pressure. The distances between the pore pressure disturbance contours are smaller at lower permeability and higher viscosity. The modelling results of the updated pore pressure distribution are of great importance for safe drilling. A case study of three wells within one platform showed that the modelling method could provide a reliable estimation of the pore pressure disturbance area caused by multistage fracturing.

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Analysis of Application Parameters of Hydraulic Slotting Technology in Jointed Coal Reservoirs

Applied Sciences ◽

10.3390/app9245536 ◽

2019 ◽

Vol 9 (24) ◽

pp. 5536

Author(s):

Zhaolong Ge ◽

Shaojie Zuo ◽

Yingwei Wang ◽

Youchang Lyu ◽

Xinyan Feng

Keyword(s):

Coal Seam ◽

Rotation Speed ◽

Experimental Testing ◽

Water Pressure ◽

High Water ◽

Fracture Network ◽

Field Application ◽

Water Jet ◽

Jet Impact ◽

Complex Fracture Network

Hydraulic slotting technology is typically used in coal mines to enhance permeability and prevent gas outbursts. Because a coal seam contains many cleats and joints, this study investigated the influence of conventional application parameters on the hydraulic slotting effect by numerical simulation and experimental testing. The cleats in the coal generated stress concentration and initiated with the water jet impact, which promoted the formation of a complex fracture network. The optimized arrangement included angles with an inclination of 20–45° between the borehole and the coal seam strike. The water jet pressure and rotation speed determined the shape of the slot. A high water jet pressure and low rotation speed promoted the formation of cracks at the end of the slot and strengthened the permeability-enhancing effect. Coal fragments could more easily peel off from the sides of the seam and block the borehole. The high water pressure and low rotation speed application parameters were optimized without blocking the borehole. Results obtained by field application revealed that the gas extraction flow after optimization was 1.3 times that of conventional hydraulic slotting. An appropriate angle between the cleats and borehole can more effectively increase the permeability of the coal seam and results in higher gas drainage flow. The results of this study can be useful as guidelines for field applications of hydraulic slotting technology.

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