|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Abstract In this case study, we apply a novel fracture imaging and interpretation workflow to take a systematic look at hydraulic fractures captured during thorugh fracture coring at the Hydraulic Fracturing Test Site (HFTS) in Midland Basin. Digital fracture maps rendered using high resolution 3D laser scans are analyzed for fracture morphology and roughness. Analysis of hydraulic fracture faces show that the roughness varies systematically in clusters with average cluster separation of approximately 20' along the core. While isolated smooth hydraulic fractures are observed in the dataset, very rough fractures are found to be accompanied by proximal smoother fractures. Roughness distribution also helps understand the effect of stresses on fracture distribution. Locally, fracture roughness seems to vary with fracture orientations indicating possible inter-fracture stress effects. At the scale of stage lengths however, we see evidence of inter-stage stress effects. We also observe fracture morphology being strongly driven by rock properties and changes in lithology. Identified proppant distribution along the cored interval is also correlated with roughness variations and we observe strong positive correlation between proppant concentrations and fracture roughness at the local scale. Finally, based on the observed distribution of hydraulic fracture properties, we propose a conceptual spatio-temporal model of fracture propagation which can help explain the hydraulic fracture roughness distribution and ties in other observations as well.
Hui, Zhao (School of Petroleum Engineering, Yangtze University) | Guanglong, Sheng (School of Petroleum Engineering, Yangtze University) | Luoyi, Huang (School of Petroleum Engineering, Yangtze University) | Xun, Zhong (School of Petroleum Engineering, Yangtze University) | Jingang, Fu (School of Petroleum Engineering, China University of Petroleum, East China) | Yuhui, Zhou (School of Petroleum Engineering, Yangtze University) | Jialing, Ma (School of Petroleum Engineering, Yangtze University) | Jiayu, Ruan (School of Petroleum Engineering, Yangtze University) | Zhouxiang, Hu (Shenzhen Branch, China National Offshore Oil Corporation) | Shumin, Sun (School of Petroleum Engineering, Yangtze University)
Abstract Accurately characterizing fracture network morphology is necessary for flow simulation and fracturing evaluation. The complex natural fractures and reservoir heterogeneity in unconventional reservoirs make the induced fracture network resulting from hydraulic fracturing more difficult to describe. Existing fracture propagation simulation and fracture network inversion methods cannot accurately match actual fracture network morphology. Considering the lightning breakdown similar as fracture propagation, a new efficient approach for inversion of fracture network morphology is proposed. Based on the dielectric breakdown model (DBM) for lightning breakdown simulation and similarity principle, an induced fracture propagation algorithm integrating reservoir in-situ stress, rock mechanical parameters, and stress shadow effect is proposed. The fractal index and random function are coupled to quantitatively characterize the probability distribution of induced fracture propagation path. At the same time, a matching rate function is proposed to quantitatively evaluate the fitting between fracture network morphology and the micro seismic data. Combined with automatic history matching method, the actual fracture network morphology can be inverted with the matching rate as objective function. The proposed approach is applied to fracture network simulation of mult-fractured horizontal wells of shale oil reservoir in China, and the fracture networks from inversion fit well with the micro seismic data. A simulation of 94 fractures in the 32 section of Well X2 shows that the well propagates more obvious branch fractures. The single-wing fracture network communicates approximately 200m horizontally and approximately 10m vertically. In single fracture flow simulation, it is necessary to consider the influence of complex fracture network morphology, but when simulating fluid flow for a single well or even a reservoir, only the main fracture needs to be considered. This paper proposes an induced fracture propagation algorithm that integrates reservoir in-situ stress, rock mechanical parameters, and stress shadowing effects. This algorithm greatly improves the calculation efficiency on the premise of ensuring the accuracy of induced fracture network morphology. The approach in this paper provides a theoretical basis for flow simulation of stimulated reservoirs and optimization of fracture networks.
Chen, Chi (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Wang, Shouxin (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Lu, Cong (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Wang, Kun (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Lai, Jie (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Liu, Yuxuan (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Abstract Hydraulic fracturing technology provides a guarantee for effective production increase and economic exploitation of shale gas wells reservoirs. Propped fractures formed in the formation after fracturing are the key channels for shale gas production. Accurate evaluation of local propped fracture conductivity is of great significance to the effective development of shale gas. Due to the complex lithology and well-developed bedding of shale, the fracture surface morphology after fracturing is rougher than that of sandstone. This roughness will affect the placement of the proppant in the fracture and thus affect the conductivity. At present, fracture conductivity tests in laboratories are generally based on the standard/modified API/ISO method, ignoring the influence of fracture surface roughness. The inability to obtain the rock samples with the same rough morphology to carry out conductivity testing has always been a predicament in the experimental study on propped fracture conductivity. Herein, we propose a new method to reproduce the original fracture surface, and conductivity test samples with uniform surface morphology, consistent mechanical properties were produced. Then, we have carried out experimental research on shale-propped fracture conductivity. The results show that the fracture surfaces produced by the new method are basically the same as the original fracture surfaces, which fully meet the requirements of the conductivity test. The propped fracture conductivity is affected by proppant properties and fracture surface, especially at low proppant concentration. And increasing proppant concentration will help increase the predictability of conductivity. Due to the influence of the roughness of the fracture surface, there may be an optimal proppant concentration under a certain closure pressure.
Guo, Tiankui (China University of Petroleum (Huadong)) | Tang, Songjun (China University of Petroleum (Huadong)) | Liu, Shun (Xi'an Shiyou University) | Liu, Xiaoqiang (China University of Petroleum) | Xu, Jianchun (China University of Petroleum) | Qi, Ning (China University of Petroleum) | Rui, Zhenhua (Massachusetts Institute of Technology and China University of Petroleum (Beijing))
Summary Hydraulic fracturing is an indispensable technology in developing tight oil and gas resources. However, the development of tight oil and gas is not consistently satisfactory. Further understanding of hydraulic fracturing of tight sandstone is required, which increases the production of tight oil and gas reservoirs, particularly in China. Currently, there are a few true triaxial hydraulic fracturing physical simulations of large tight sandstone outcrops. To weaken the boundary effect, this study performed simulations using large tight sandstone outcrops (500 × 500 × 500 mm and 500 × 500 × 800 mm) in the Shahezi Formation (Fm.), Jilin Province, China. The effect of natural fracture (NF) development degree, in-situ stress conditions, fracturing treatment parameters, and temporary plugging on fracture propagation were investigated. Furthermore, fracture propagation was investigated based on post-fracturing fine reconstruction, high-energy computed tomography (CT) scan, acoustic emission monitoring (AEM), and analysis of a fracturing pressure curve. Finally, suggestions on fracturing treatment were proposed. The results show that the NF is a key factor in determining the hydraulic fracture (HF) morphology in the tight sandstone reservoir. Further, the number, approaching angle, and cementation strength of the preexisting NF affect the HF propagation path; these are the key factors for forming complex fractures. In the tight sandstone reservoir with well-developed NFs, the fracture morphology is dominated by the NF under horizontal differential stress ≤ 9 MPa. A single fracture is more likely to occur under horizontal differential stress ≥ 12 MPa, which is less affected by the NF. In the fracturing at variable injection rates, a low rate facilitates fluid penetration into the NF, while a high rate facilitates deep HF propagation. A low-viscosity fracturing fluid at a high rate facilitates further propagation of the temporary plugging agent (TPA), thus achieving deep temporary plugging and fracture diversion. A high-viscosity fluid does not facilitate accumulation and plugging of particulate TPA. Higher horizontal differential stress leads to a smaller diversion radius of new HF, which is closer to the original HF, leading to poorer stimulation effect. The results provide a reference for the fracturing design of the tight sandstone.
In chemical-looping combustion (CLC), oxygen is transferred from an air reactor to a fuel reactor by means of a solid oxygen carrier. Direct contact between air and fuel is avoided, resulting in an undiluted carbon dioxide (CO2) exhaust stream. As such, CLC has been identified recently as a high-potential carbon-capture-and-storage technology. While initial focus has been on storage projects, CO2 is increasingly considered as a valuable chemical substance for enhanced-oil-and-gas-recovery projects as well as for the production of chemicals, polymers, or building materials. Carbon capture, transport, use, and storage (CCTUS) form an important aspect of many national and global strategies to combat climate change. A main challenge regarding capture of CO2, especially for high volumes, is its separation from other gases.
Tao, Jiaping (China University of Petroleum) | Meng, Siwei (PetroChina Research Inst Petr Expl & Dev) | Cao, Gang (PetroChina Research Inst Petr Expl & Dev) | Gao, Yang (PetroChina Research Inst Petr Expl & Dev) | Liu, He (PetroChina Research Inst Petr Expl & Dev)
Initial hydraulic fracturing of shale oil reservoirs has often resulted in disappointing results, with low connected volumes and productivity degradation with depletion. To improve the single well production and oil recovery, re-fracturing techniques have received increased attention, but face the challenges of economy, applicability and feasibility.
In this paper, the propagation mechanism during re-fracturing operations is explored through laboratory experiments. Firstly, mechanical analysis and fracturing simulation experiments were performed using the formation cores. After the fracturing simulation experiment, the fractured core was soaked in supercritical CO2 to enhance the re-fracturing effect. Then a re-fracturing simulation experiment was performed to analyze the fracturing propagation mechanism. Meanwhile, some new cores are soaked into supercritical CO2 to explore the changes of mechanical properties under different soak time.
The mechanical analysis experiment showed that supercritical CO2 soak has a strong influence on the uniaxial compressive and tensile strength of shale. With an increase of soak time, both the compressive and tensile strength clearly decreased. During the first fracturing operation, fractures propagated only along the horizontal bedding and could not open the rock matrix. After supercritical CO2 soak, re-fracturing could open the horizontal bedding more easily as well as extend to the rock matrix, creating a more complex fractured system, enhancing oil recovery.
Magsipoc, E. (University of Toronto) | Li, M. (University of Toronto) | Abdelaziz, A. (University of Toronto) | Ha, J. (University of Toronto) | Peterson, K. (University of Toronto) | Grasselli, G. (University of Toronto)
The serial section technique was used to construct a high-resolution and high-quality fracture network image stack of a true triaxial hydraulic fracturing experiment on a shale sample from the Montney formation. The stack was used to create a point cloud and fracture surface meshes that were used for fracture analysis. Fractures were separated by subtracting the fracture intersections from the point cloud then applying a connected components algorithm to separate them. Point clouds were generated from these fractures and were thinned to achieve a 1-voxel thickness. After thinning, they were smoothed to reduce the aliasing effect from the image stack grid structure. Fractures were identified as either a bedding or non-bedding fracture by proxy of their orientation. Then, their surfaces were analyzed using a directional roughness metric. This roughness metric was used along with information about the stress state to evaluate the peak shear strength criterion for each individual fracture. The slipping potential of these fractures under the stress state applied by the true triaxial frame was estimated by the ratio of the actual shear stress on the fracture and the peak shear strength criterion.
Hydraulic fracturing (HF) creates flow channels either by opening pre-existing planes of weakness or by creating new ones within the rock matrix. The geometries of these fractures differ depending on a variety of influencers such as bedding, rock fabric, material strength, the local stress environment, and spatial heterogeneities embedded within the rock mass. The morphologies of these fractures can provide useful information on the expected fracture geometry and production of a reservoir. This can be achieved by fracture geometry quantification with roughness metrics and aperture to gain information for estimating fluid resistance and proppant performance. However, this information is not easy to obtain from the field.
Laboratory HF experiments provide useful insights to the mechanics of hydraulic fracturing performed in the field. Because they are physically accessible, the fractures created by the experiment can be opened and examined. Tan et al. (2017) illustrates an example of an examination of the fracture networks of multiple HF experiments performed under true triaxial stress. Their experiments provided insights on the sensitivity of the fracture network geometry to fluid viscosity and injection rate. However, this required them to take apart the sample to gain access to internal fractures. While they were only interested in the general fracture structure, this action may have potentially lost information on the smaller fractures within the network.
Zhu, Jialei (Beijing Institute of Petrochemical Technology) | Jiao, Xiangdong (Beijing Institute of Petrochemical Technology) | Wang, Kai (Beijing University of Chemical Technology) | Gu, Yanhong (Beijing Institute of Petrochemical Technology) | Cai, Zhihai (Army Academy of Armored Forces)
In view of the problems of underwater wet laser welding, such as power attenuation, poor surface forming and narrow adaptability of welding water depth, the defects and causes of wet laser welding are expounded. The local dry underwater laser wire filling welding process is proposed to improve the quality of weld and increase the applicable of water depth. In order to verify the feasibility of the local dry underwater welding process, the quality and characteristics of the welds are compared and analyzed. The experimental results show that the local dry method can effectively increase the water depth and improve the welding quality, and the main mechanical properties of the weld are equivalent to that in the air welding.
With the increasing development of offshore oil and gas resources, there are more and more construction and maintenance of offshore oil and gas equipment. Underwater welding is one important part of underwater maintenance technology for offshore engineering equipments. At present, underwater welding uses mainly arc welding. With the increase of water depth, the environment pressure of underwater arc welding gradually increases, the reliability of arc welding gradually decreases, however, the welding quality and stability cannot be guaranteed
In order to study the quality and performance of underwater laser welding, the weld quality of wet welding and local dry underwater welding are compared and analyzed. Specifically, the macro morphology, microstructure, hardness, mechanical properties and fracture morphology, and the effects of water depth and local drying environment on weld quality are studied.
Most drilling rigs in the West Texas Delaware Basin (WTX) are supplied with 5" 19.50# S-135 grade drill pipe. Exposure of this pipe to hydrogen sulfide (H2S) creates potential of cracking from hydrogen stress cracking (HSC). Such cracked pipes often exhibit longitudinal cracks with crack origination at OD or ID depending on local stress concentrators. This poses a unique challenge as traditionally used drill pipe inspections specificed in API RP 7G-2 (2015) (referred to as API) and
To remedy this problem, a drill pipe inspection program designed for cracks from exposure to H2S was developed. A trial program was undertaken, wherein various inspection technologies with specific coverage and procedures were executed on pipe exposed to H2S. Initially, the pipe was inspected and re-inspected using multiple technologies to document effectiveness of specific inspection methods. The crack morphology including location, orientation and size was cataloged to understand characteristics of H2S induced cracks and determine effectiveness of an inspection method in detecting specific crack types. Crack data collected across numerous inspections was analyzed to determine trends on crack occurrence and morphology. This analysis aided in development of an optimized inspection program that was effective and cost efficient. To address various exposure levels and pipe conditions, three inspection categories with increasing coverage and criticality were designed. Implementation of this optimized inspection program has aided in detecting over 100 cracked drill pipe joints and prevented twist off incidents. The cracks detected with this H2S specific inspection program would have gone undetected using traditional (DS-1 and API) used drill-pipe inspection categories.
This paper details various inspection methods and the modified inspection coverage and procedures implemented. The H2S induced drill pipe crack data and analyzed trends on crack occurrence and morphology collected over the testing program are included. The paper presents the inspection program designed for detecting cracks induced in drill pipe from H2S exposure. Also included is discussion on three separate inspection categories with increasing criticality to address various exposure levels and pipe conditions.