|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Petroleum is any hydrocarbon recovered from the subsurface of the earth after drilling such as oil and gas.Oil and gas provide about 60% of all the energy used by the society today. They provide fuel for means of transportation and they are a must for the daily life requirements including: heating, lighting and cooking. They are used in most of manufacturing processes around us such as: synthetic fabrics, plastics, fertilizers, detergent and many other purposes. Briefly, no one can imagine the world without oil and gas. Most people know the source of petroleum is plants and animals that died millions of years ago.
Summary Shale, which has pores as small as 10 nm, is economically viable for hydrocarbon recovery when it is fractured. Although the fracture toughness dictates the required energy for the improvement, the existing techniques are not suitable for characterization at scales smaller than 1 cm. Developing practical methods for characterization is crucial because fractures can contribute to an accessible pore volume at different scales. This study proposes a conceptual model to characterize the anisotropic fracture toughness of shale using nanoindentations on a sub-1-cm scale. The conceptual model reveals the complexities of characterizing shales and explains why induced fractures differ from those observed in more-homogeneous media, such as fused silica. Samples from the Wolfcamp Formation were tested using Berkovich and cube-corner tips, and the interpreted fracture toughness values are promising. The conceptual model is the first application of the effective-medium theory for fracture toughness characterization using nanoindentation. In addition, it can quantify fracture toughness variations when using small samples, such as drill cuttings. Introduction Shale is a sedimentary rock containing clay minerals and silt-sized particles (Blatt and Tracy 1996) with a pore size of smaller than 100 nm in its matrix, which results in ultralow permeability. Shale gas was first extracted in 1821 (Hill et al. 2004) and has recently become economically viable because of hydraulic fracturing. This has made the US a significant fossil fuel producer. Since the Stanolind Oil and Gas Corporation performed the first hydraulic fracturing using water-based muds in 1947 (King 2012), many stimulations have shown favorable results and an increased recovery rate.
Xu, Guoqing (Sinopec Research Institute of Petroleum Engineering (Corresponding author) | Han, Yujiao (email: email@example.com)) | Jiang, Yun (Sinopec Research Institute of Petroleum Engineering) | Shi, Yang (Research Institute of Petroleum Exploration & Development, PetroChina (Corresponding author) | Wang, Mingxian (email: firstname.lastname@example.org)) | Zeng, XingHang (Research Institute of Petroleum Exploration & Development, PetroChina (Corresponding author)
Summary Spontaneous imbibition (SI) is regarded as an effective method to improve the oil recovery in a tight sandstone reservoir, which leads to a significant change in fracturing design and flowback treatment. However, a longtime shut-in period would aggravate the retention of fracturing fluid, which is in contradiction with high production in the field. It is imperative to understand how SI works during shut-in time, so as to maximize the effect of imbibition in oil recovery enhancement. In this study, a series of experiments were conducted to simulate the status of residual oil saturation so that the inner mechanism of imbibition on oil recovery can be investigated. Low-field nuclear magnetic resonance (LF-NMR) was used to provide direct observation of phase changes in different pore sizes. The experimental results show a positive effect of imbibition on residual oil reduction. This phenomenon further elucidates the observations made during the well shut-in, soaking period, and low flowback efficiency. This study aims to understand the mechanism of SI behavior and help to improve the accuracy of production prediction.
Ju, Yang (China University of Mining and Technology (Corresponding author) | Wu, Guangjie (emails: email@example.com or firstname.lastname@example.org)) | Wang, Yongliang (China University of Mining and Technology) | Liu, Peng (China University of Mining and Technology) | Yang, Yongming (China University of Mining and Technology)
Summary In this paper, we introduce the entropy weight method (EWM) to establish a comprehensive evaluation model able to quantify the brittleness of reservoir rocks. Based on the evaluation model and using the adaptive finite element-discrete element (FE-DE) method, a 3D model is established to simulate and compare the propagation behavior of hydraulic fractures in different brittle and ductile reservoirs. A failure criterion combining the Mohr-Coulomb strength criterion and the Rankine tensile criterion is used to characterize the softening and yielding behavior of the fracture tip and the shear plastic failure behavior away from the crack tip during the propagation of a fracture. To understand the effects of rock brittleness and ductility on hydraulic fracture propagation more intuitively, two groups of ideal cases with a single failure mode are designed, and the fracture propagation characteristics are compared and analyzed. By combining natural rock core scenarios with single failure mode cases, a comprehensive evaluation index BIf for reservoir brittleness and ductility is constructed. The simulation experiment results indicate that fractures in brittle reservoirs tended to form a complex network. With enhanced ductility, the yielding and softening of reservoirs hamper fracture propagation, leading to the formation of a simple network, smaller fracture area (FA), larger fracture volume, and the need for higher initiation pressure. The comprehensive index BIf can be used to define brittleness or ductility as the dominant factor of fracturing behavior. That is, 0 < BIf ≤ 0.46 indicates that the reservoir has enhanced ductility and ductile fracturing prevails; 0.72 < BIf < 1 indicates that the reservoir has enhanced brittleness and brittle fracturing prevails; and 0.46 < BIf ≤ 0.72 means a transition from brittle to ductile fracturing. Based on fitting analysis results, the relationship between the calculated FAr and BIf is constructed to quantify the influence of reservoir brittleness and ductility on fracturing. The study provides new perspectives for designing, predicting, and optimizing the fracturing stimulation of tight reservoirs with various brittleness and ductility.
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.
Summary Stimulated reservoir volume (SRV) is a prime factor controlling well performance in unconventional shale plays. In general, SRV describes the extent of connected conductive fracture networks within the formation. Being a pre-existing weak interface, natural fractures (NFs) are the preferred failure paths. Therefore, the interaction of hydraulic fractures (HFs) and NFs is fundamental to fracture growth in a formation. Field observations of induced fracture systems have suggested complex failure zones occurring in the vicinity of HFs, which makes characterizing the SRV a significant challenge. Thus, this work uses a broad range of subsurface conditions to investigate the near-tip processes and to rank their influences on HF-NF interaction. In this study, a 2D analytical workflow is presented that delineates the potential slip zone (PSZ) induced by a HF. The explicit description of failure modes in the near-tip region explains possible mechanisms of fracture complexity observed in the field. The parametric analysis shows varying influences of HF-NF relative angle, stress state, net pressure, frictional coefficient, and HF length to the NF slip. This work analytically proves that an NF at a 30 ± 5° relative angle to an HF has the highest potential to be reactivated, which dominantly depends on the frictional coefficient of the interface. The spatial extension of the PSZ normal to the HF converges as the fracture propagates away and exhibits asymmetry depending on the relative angle. Then a machine-learning (ML) model [random forest (RF) regression] is built to replicate the physics-based model and statistically investigate parametric influences on NF slips. The ML model finds statistical significance of the predicting features in the order of relative angle between HF and NF, fracture gradient, frictional coefficient of the NF, overpressure index, stress differential, formation depth, and net pressure. The ML result is compared with sensitivity analysis and provides a new perspective on HF-NF interaction using statistical measures. The importance of formation depth on HF-NF interaction is stressed in both the physics-based and data-driven models, thus providing insight for field development of stacked resource plays. The proposed concept of PSZ can be used to measure and compare the intensity of HF-NF interactions at various geological settings.
Yang, Ruiyue (China University of Petroleum) | Hong, Chunyang (China University of Petroleum) | Huang, Zhongwei (China University of Petroleum) | Wen, Haitao (China University of Petroleum) | Li, Xiaojiang (Sinopec Research Institute of Petroleum Engineering) | Huang, Pengpeng (China University of Petroleum) | Liu, Wei (China University of Petroleum) | Chen, Jianxiang (China University of Petroleum)
Summary Multistage hydraulic fracturing is widely used in developing tight reservoirs. However, the economic and environmental burden of freshwater souring, transportation, treatment, and disposal in hydraulic fracturing operations has been a topic of great importance to the energy industry and public alike. Waterless fracturing is one possible method of solving these water‐related issues. Liquid nitrogen (LN2) is considered a promising alternate fracturing fluid that can create fractures by coupled hydraulic/thermal loadings and, more importantly, pose no threats to the environment. However, there are few laboratory experiments that use LN2 directly as a fracturing fluid. In this work, we examine the performance of LN2 fracturing based on a newly developed cryogenic‐fracturing system under true‐triaxial loadings. The breakdown pressure and fracture morphologies are compared with water fracturing. Moreover, fracture‐initiation behavior under cryogenic in‐situ conditions revealed by cryo‐scanning electron microscopy (cryo‐SEM) is presented, and the role of thermal stress is quantified by a coupled thermoporoelastic‐damage numerical simulation. Finally, the potential application considerations of LN2 fracturing in the field site are discussed. The results demonstrate that LN2 fracturing can lower fracture initiation and propagation pressure and generate higher conductive fractures with numerous thermally induced cracks in the vicinity of the wellbore. Thermal gradient could generate enormously high‐tensile hoop stress and bring about extensive rock damage. Fracture‐propagation direction is inclined to be influenced by the thermal stress. Furthermore, phase transition during the fracturing process and low fluid viscosity of LN2 can also facilitate the fracture propagation and network generation. The key findings obtained in this work are expected to provide a viable alternative for the sustainable development of tight‐reservoir resources in an efficient and environmentally acceptable way.
Oil production from shale and tight formations accounted for more than half of total US oil production in 2015 (EIA, 2016). Such amount is expected to grow significantly as the active development of low-permeability reservoirs continues. The current technique to produce shale oil is through primary depletion using horizontal wells with multiple transverse fractures. The oil recovery in shale oil reservoirs is less than 10% (Sheng, 2015a), or 3–6%, according to the EIA 2013 report (US DOE, 2013). The oil recovery in tight formations is also low.
At some point during the first half of this year, Colombia replaced politically and economically crippled Venezuela as Latin America's third-largest oil-producing country. Since Brazil ended state-owned Petrobras' monopoly and opened up its industry to international companies in the late 1990s, the country's oil output has almost tripled as it found and tapped into its giant offshore presalt fields. Output from Mexico's state-owned Pemex, meanwhile, has fallen to its lowest level since at least 1990, and President Andrés Manuel López Obrador is working to stymie energy reforms implemented in 2013 to rejuvenate industry in the country. With the lessons of its resource-rich neighbors in mind, Colombia finds itself in a similar position where it must carefully choose a path forward for its industry or risk squandering great potential, or worse, losing what took years to build. The Andean country in the early 2000s overhauled its regulatory framework, reduced government take, and held licensing rounds with the intent of attracting foreign investment.
Matrix acidizing is commonly used as a preflush to the hydraulic-fracturing stimulation of shale formations. The process dissolves sediments and mud solids that inhibit the permeability of the rock, enlarging the natural pores of the reservoir and stimulating flow of hydrocarbons. In this paper, the mineralogical and physical responses to matrix acidizing of several important North American shale formations are evaluated. A few studies have quantified the effect of hydrochloric acid (HCl) matrix acidizing on mineralogical and physical properties of shale formations. However, less is known about the development of conductivity and the acid concentrations necessary to optimize conductivity and, by extension, the impact on production and rock stability.