Zhai, Wenbao (China University of Petroleum) | Li, Jun (China University of Petroleum) | Chen, Zhaowei (CNPC Engineering Technology R&D Company Limited) | Zhou, Yingcao (CNPC Engineering Technology R&D Company Limited)
Many weakness planes (such as faults, joints, and micro-fractures, etc.) are usually pre-existed in rock. However, the stress statement changed by hydraulic fracture (HF) propagation may have an important impact on hydraulic fracturing, which is closely related to stress statement of weakness planes. Firstly, the rock samples containing the pre-existing weakness planes were analyzed according to the curves of volumetric strain versus stress difference acquired by laboratory experiment. Secondly, the effective normal stress and shear stress of weakness planes were calculated by the tensor transformation method. And then, weakness planes were divided into four kinds according to the relationship between stress statements of weakness planes and failure lines of Mohr diagram and the kinds of weakness planes were visually described in the Mohr diagram. Finally, it was respectively discussed that pre-existing weakness planes did have an influence on hydraulic fracturing under different stress statements. The research results show that when the effective stress is more than zero, with the effective stress decrease, weakness planes are the more easily inclined to become the dilatation phenomenon where the self-propping effect can improve the reservoirs permeability due to surface asperities of weakness planes. However, there are very complex mechanical phenomena induced by weakness planes under higher effective stress. When hydraulic fractures encounter the pre-existing weakness planes under the approximate stress statement, it may be easy to occur shear slipping of weakness planes or it is difficult to be opened by hydraulic fractures. The latter is extremely beneficial to not become the maximum simulated reservoir volume (SRV) and should be avoided by fracturing operation as early as possible. It is somewhat different that the influence of different mechanical phenomena on hydraulic fracturing, which has a certain guidance for improving hydraulic fracturing stimulation.
Compared to the conventional oil and gas resources, there is usually not natural production in unconventional oil and gas resources, and it needs to rely on hydraulic fracturing to improve development effectiveness (Shrivastava and Sharma, 2018). The complex fracture networks may be created in hydraulic fracturing, which is a combination of shear and tensile failures (Lin et al., 2018). The shear failure of weakness planes (such as faults, joints, and micro-cracks, etc.) resulted in long-term geological tectonic movement is anticipated to dominate in hydraulic fracturing. However, it is a fact that rock dilatation may be caused by rock plastic behavior that the horizontal stress is balanced by the pressure near the fractures tip in hydraulic fracturing (Alko and Economides, 1995). With the development of unconventional oil and gas resources, these weakness planes are a double-edged sword that they can act as a good oil and gas flowing channel, but they can also lead to hydraulic fracturing failure (Ye, 2017). Therefore, it is necessary that considering the role of weakness planes in hydraulic fracturing will be used to optimize the hydraulic fracturing design.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by, the author(s). The information herein does not necessarily reflect any position of URTeC.
ABSTRACT: Micro-annuli existing on the interface of cement-sheath might lead to the failure of wellbore integrity. Based on the solutions of the elastic and elastic-plastic deformations of a thick-walled cylinder with the internal and external pressures; meanwhile combining with the displacement continuity, a nonlinear equation set about the interfacial pressures and displacements of a casing-cement-formation system in the loading and unloading processes is established. Via solving the nonlinear equation set, the interfacial pressures and the displacements can be obtained. If the obtained interfacial pressure is larger than the bonding strength of rock, micro-annuli appear on the interface, and its size is equal to the difference of the interfacial displacement in the loading process and that in the unloading process. Numerical examples show that the micro-annuli are at an order of tens of micrometers. Moreover, as the increase of the elastic modulus of cement, the micro-annuli become broader. As a comparison, if the uniaxial compressive strength of cement increases, the micro-annuli become narrower. Therefore, to avoid the generation and development of micro-annuli, it is suggested that the cement with high uniaxial compressive strength and low elastic modulus should be used for the field practices.
Wellbore integrity needs to be investigated in the whole life cycle of a well, and the sealing of the cement sheath is the key. In the completion and production process, a variety of reasons can lead to the sealing failure of the cement sheath. For instance, both the wellbore uncleanness and the residual mud cake can result in the reduction of the cementing quality. During the hardening process of cement slurry, gas channel formed by weight loss can trigger the sealing failure. Due to the rapid change of the internal casing pressure, or the variation of the casing temperature, the cement interface can also separate from formation.
Bois et al  mentioned that the loading and unloading process of the internal casing pressure is one of the key factors affecting the cement sealing. During the oil test, pressure test, or hydraulic fracturing, etc., the loading and unloading process of the internal casing pressure is inevitable. Under these situations, the cement will experience the similar process. Once the load applied on the cement sheath overcomes its elastic limitation, the cement sheath will appear plastic deformation, which will be remained after unloading, thus microannuli form on the interfaces, including the first and the second interfaces.
Yang, Zhenning (University of Massachusetts Amherst) | Wang, Liming (University of Massachusetts Amherst) | Chen, Zhaowei (China National Petroleum Corporation) | Xiang, Degui (China National Petroleum Corporation) | Hou, Dongwei (Shanghai Jiao Tong University) | Ho, Carlton L (University of Massachusetts Amherst) | Zhang, Guoping (University of Massachusetts Amherst)
Mitigation and prevention of shale-formation damage caused by hydraulic-fracturing fluid/rock interactions play an important role in well-production stability and subsequent refracturing design. In this paper, the effect of converting typically hydrophilic fractured surfaces to hydrophobic ones on fluid-induced softening of shales was investigated. Specifically, nanoindentation was used to characterize changes in the mechanical properties of shale samples after different surface treatments. A thin layer of octadecyltrimethoxysilane (OTMS) coating was deposited on the initially hydrophilic surface of shale, followed by inundation in water for certain periods of time to allow for fluid/rock interactions. Nanoindentation testing was then conducted on the treated shales to characterize their hardness, Young’s modulus, and fracture toughness to examine the alteration of shale’s mechanical properties caused by fluid/rock interactions and to check whether hydrophobic coating can mitigate shale-softening. Results fro nanoindentation testing were analyzed by a newly proposed clay-matrix criterion for data screening. Different rock-surface treatments lead to changes in rock properties. Both the hardness and Young’s modulus of the treated samples converge and stabilize at relatively large depths. Samples with hydrophobic surfaces exhibit a much lower degree of softening, as reflected by their better mechanical properties (e.g., 40% increase in hardness, 25% increase in Young’s modulus, and 35% increase in fracture toughness), compared with untreated shale samples. The results of this study also demonstrate that the continuous-stiffness-measurement (CSM) method and the repeated loading method for nanoindentation loading yield similar ranges of micromechanical properties of the bulk shale. However, the CSM method, if combined with the newly proposed clay-matrix-based criterion for data screening can better define and characterize fluid/shale interactions or softening of shales.
Liu, Huifeng (Tarim Oilfield Company of Petrochina) | Yang, Xiangtong (Tarim Oilfield Company of Petrochina) | Yuan, Xuefang (Tarim Oilfield Company of Petrochina) | Liu, Jiangyu (Tarim Oilfield Company of Petrochina) | Chen, Zhaowei (Drilling Research Institute of China National Petroleum Corporation) | Tian, Shouceng (China University of Petroleum-Beijing)
Silurian reservoir in Ta-zhong Oilfield, western china, is a thin-interbed, low-permeability reservoir with buried depth from 4000 to 4500m. The sand distribution in this reservoir is heterogeneous both vertically and horizontally. Horizontal well with segregated completion and multi-stage fracturing is taken as an efficient technology to exploit this kind of reservoir. However, the existence of many mudstone interlayers makes the design of completion and fracturing difficult.
This paper will provide a case study on design and operation of multi-stage fracturing of a horizontal well in Ta-zhong Silurian reservoir. This well was fractured twice using two different technologies, firstly hydraulic jetting fracturing and then packer-segregated fracturing. Both the two operations encountered abnormal pumping pressure and sand out. The design and implementation process of both technologies will be introduced in this paper, and the challenges facing the completion and fracturing design will be highlighted. The causes to the abnormal pumping pressure and sand out will be analyzed comprehensively through numerical modeling and comparative calculation.
The results show that the defective completion design is the main cause of the failures of the two operations. For hydraulic jetting fracturing, the ill-considered jetting points and improper jetting space cause the difficulties for fracture initiation and propagation and therefore the sand out. For packer-segregated fracturing, the inappropriate perforating interval leads to simultaneous initiation of multiple fractures in each stage. These fractures interfere with each other during propagation, leading to great near-wellbore pressure loss and width reduction for each fracture, therefore the abnormal high pumping pressure and sand out were encountered. The acting mechanism of induced stress and fracture interaction and reorientation are illuminated in this paper. A bunch of ways to avoid these problems during multi-stage fracturing of a thin-interbed sandstone reservoir is also proposed from both designing aspect and operating aspect.
Nowadays, horizontal well with multi-stage fracturing is a common-used technique in tight thin-interbed formations. However, the design of a segregated completion and multi-stage fracturing is still a nodus for such formations. This paper gives a detailed introduction of a failure case and comprehensively analyzes the causes of these failures from geology to engineering, therefore gives a lesson for avoiding this kind of failures and optimizing a staged fracturing design in tight thin-interbed reservoirs.
Abstract: A fluid-solid-chemistry coupling model is built considering fluid flow and ion transmission induced by shale-drilling fluid system electrochemical potential osmosis, nonlinearity of flow and solute diffusion in shale-drilling fluid system, and solid deformation resulted by fluid flow and ion transmission. Pore pressure and stress field around the wellbore wall was computed by finite element method, and the effect of shale and drilling fluid parameters on collapse index and caving pressure was analyzed. The research results demonstrate that large shale permeability, large solute diffusion coefficient were favor of shale stability. Drilling fluid with high concentration and reflection coefficient was beneficial for shale stability. High mud weight can sometimes result instability for shale formation. While the swelling coefficient of shale-drilling fluid system decreases, the shale hydration can be alleviated. Especially for the case that the drilling fluid concentration was larger than the shale pore fluid, the chemical reverse osmosis may cause shale dehydration. The collapse index of small shale wellbore altered with time was more obvious than large wellbore.