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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.
Cao, L.. (PetroChina Tarim Oilfield Co.) | Yang, X.. (PetroChina Tarim Oilfield Co.) | Zhang, S.. (China University of Petroleum) | Wang, H.. (China University of Petroleum) | Wang, K.. (PetroChina Tarim Oilfield Co.) | Liu, J.. (PetroChina Tarim Oilfield Co.) | Zhao, J.. (Jianghan Machinery Research Inst.)
Abstract Since the coal seam is soft with low permeability in China, the stimulation effect of vertical well hydraulic fracturing technology is limited while horizontal well fracturing has instable wellbore leading to wellbore collapsing. Therefore, floor horizontal well hydraulic fracturing technology is proposed, that is drilling in the floor sandstone and connecting the coal seam by hydraulic fractures. A test area has been undertaken in 3# coal seam, southern Qinshui Basin, to demonstrate this technology. Through optimizing the well path, borehole structure, fracturing designs, and fracture propagation performance, a set of treatments were developed and applied successfully. The result shows that drilling floor horizontal well along with minimum horizontal principle stress, applying U-type well structure, and designing fractures with 3 stages, 130m half fracture length and 30D·cm flow conductivity achieves better production performance.
Abstract Propped hydraulic fracture stimulation has been one of the primary completion methods for coalbed methane wellbores for more than twenty years. However direct fracturing of coal seams has been notoriously inefficient. High fracture pressures in coal seams, coal cleating and natural fractures can lead to shear slippage and inefficient non-planar fracturing which significantly underperforms the stimulation potential compared to conventional clastic rock fracture stimulation. In 2003 the concept of indirect fracturing was introduced to significantly increase Coalbed methane (CBM) fracturing efficiency by initiating fractures in lower stress clastic rock adjacent to coal seams and allowing these induced fractures to connect and grow into the coal seams. This paper presents several examples of the application of indirect fracturing for the stimulation of coal seams in the Rockies. This paper evaluates production results, fracture pressure analysis, as well as micro seismic results and frac tracer analysis for quantifying the effectiveness of indirect fracturing for the stimulation of CBM reservoirs. From this data we present guidelines for when and where indirect fracturing is applicable and just as important, where indirect fracturing is not appropriate. Introduction: The latest production data indicates that natural gas production from subsurface coal seams averaged 4.7 BCF/day in 20051. This number is almost certainly an underestimation of the actual contribution of natural gas production from coal seams because in many basins, especially in the west, conventional clastic completions are inadvertently hydraulically connected to adjacent coal seams that are, or will be, contributing significant amount of gas to the production stream. The production contribution from these adjacent coal seams is often masked by the fact that early in productive life of these clastic completions, when the bottom hole producing pressure (BHPP) is at it's highest, very little gas will be desorbing from these adjacently connected coal seams. But later in the life of these wellbores, when the BHPP is significantly reduced, these adjacent coal seams will be contributing more and more to the production stream. Figure 1 shows a comparison of the gas release profile between a conventional clastic reservoir rock in a gas expansion drive system and the unconventional desorption from a coal seam. With few exceptions almost all Coalbed methane (CBM) completions require some sort of enhancement process to enable optimized economic production. This is partly because of the gas release profile that requires exposure to a much lower pressure in order to desorb and produce the gas, but also coal seams are highly susceptible to near wellbore permeability reduction damage or skin. This is either caused by invasion damage from the drilling fluid, completion cement, or a mechanical skin caused by hoop stresses around open hole completions. The matrix permeability of coal is extremely low, so the primary transmissibility system is from coal cleats or natural fracture systems. These fracture systems (or cleats) are generally much wider than your average pore throat in a clastic rock and therefore are much more susceptible to fluid invasion damage. In addition, the very soft nature of coal means that these fracture systems can be closed down due to mechanical hoop stress in open hole completions. Nowhere is this better exemplified than in a series of papers by Jeffery & Connell 2,3. In this piece of work small horizontal wellbores were drilled in coal seams to degas prior to mining. The wells did not produce adequately from the horizontal open hole wellbores by themselves so propped hydraulic fracturing was performed along these horizontal hole sections. Because this was conducted within longwall mine panels, the permeability, frac geometry and conductivity were well understood. In a subsequent paper 3 the production of gas was history matched using a CBM reservoir simulator. The most significant finding of this project was that the stimulation effect of the propped fractures was much greater than could be justified from the known fracture geometry and conductivity. A possible explanation for higher than expected production increase, was to assign a very high pre-frac skin to the open hole horizontal wellbore. This skin around the open hole wellbore can be explained from the hoop stress or a tangential stress around the wellbore caused by the excavation of the coal during drilling.
Abstract Lost circulation caused by low fracture gradients is the cause of many drilling related problems. Typically the operational practice when lost circulation occurs is to add loss circulation materials (LCM) to stop mud from flowing into the formations. To improve the treatment for lost circulation caused by low fracture gradients, especially designed materials in mud system are used to seal the induced fractures around the wellbore. This operation is in the literature referred to as wellbore strengthening that has been found to be a very effective in cutting Non-Productive Time (NPT) when drilling deep offshore wells. Size, type and geometry of sealing materials are debating issues when different techniques are applied. Also the phenomenon is not truly understood when these techniques applied in different sedimentary basins. This paper presents development and simulation results of a three-dimensional Finite-Element Model (FEM) for investigating wellbore strengthening mechanism. This study also describes a procedure for designing Particle Size Distribution (PSD) in field applications. To better understand the numerical results, the paper also reviews the connection between Leak of Tests (LOTs) and wellbore hoop stress and how these LOTs can mislead in fracture gradient determination. A comprehensive field database was collected from different sedimentary basins for this study. Results demonstrate that the maximum attainable wellbore pressure achieved by wellbore strengthening is strongly controlled by stress anisotropy. Results also show that Particle Size Distribution (PSD) of wellbore strengthening should be designed in order to seal the fractures close to the mouth and at fracture tip. This will result both in maximizing hoop stress restoration and tip-screening effects. In addition this model is able to show the exact fracture geometry formed around the wellbore that will help to optimize the sealing materials design in wellbore strengthening pills. To support numerical modeling results, near wellbore fracture lab experiments on Sandstone and Dolomite samples were also presented. Laboratory experiments results reveal importance of rock permeability, tensile strength and fluid leak-off in wellbore strengthening applications.
Abstract Semi-automation of hydraulic fracturing treatment designs often necessitates the application of simplified predictive models. Such models can only incorporate a limited subset of the relevant rock mechanical properties and an approximate representation of the stress state. This paper demonstrates the fundamental influence of three-dimensional stress states on the propagation of hydraulic fractures in coal seam gas (CSG) wells, and contrasts these results with those from two-dimensional simulations conducted in a one-dimensional stress state. A three-dimensional, finite element-discrete element (FEM-DEM) model of a single well stage was developed as the basis for this study. This synthetic well was informed by case studies from the Surat Basin, Queensland, featuring varying complexity of key geomechnical factors. These include the existence of ∼30 coal seams within a gross rock column of more than 300 m, stress states that vary both laterally and vertically, ductile rock properties, and varying natural fracture densities and orientations. The developed model captures the full tensor description of stress, poroelastic-plastic modelling of the rock and coal, fully coupled fluid flow, and explicit modelling of fracturing. The stress state was parametrically defined so that normal, strike-slip and reverse faulting conditions could be imposed and the magnitude of stresses varied to capture the appropriate range of varying conditions. A single perforation cluster was then used to induce a hydraulic fracture in an isotropic medium. Hydraulic fracture propagation (and propagation complexity) is influenced significantly by differential stresses, stress orientations and relative stress magnitudes. None of these are captured in two-dimensional simulations using a one-dimensional stress characterisation which is commonly derived from one-dimensional wellbore stress models. The findings of this work clearly demonstrate the ability of fractures to turn and grow preferentially when they are not constrained to a two-dimensional plane. It also shows how the initiation of fractures (i.e. orientation to stress) impacts the propagation complexity of hydraulic fractures from the direction of maximum principal stress. In general, this paper highlights the benefit of incorporating the three-dimensionality of key geomechnical parameters when designing hydraulic fracturing stimulation treatments. Future work will incorporate greater reservoir detail (e.g. pressure-dependence, heterogeneity of stress and material properties) to further investigate fracture containment and reorientation.