Zhao, X. G. (Beijing Research Institute of Uranium Geology) | Wang, J. (Beijing Research Institute of Uranium Geology) | Chen, L. (Beijing Research Institute of Uranium Geology) | Zhao, Z. (Tsinghua University)
Granitic rocks are potential rock types for hosting high-level radioactive waste (HLW) repositories at depth. A better understanding of rock thermal conductivity is essential to develop HLW repositories successfully. In this work, experimental investigations on the thermal conductivity of thermally treated Beishan granite were conducted. Disc specimens preconditioned at 105 °C were heated to different temperatures (200, 300, 400, 550, 650, and 800 °C) and then cooled to room temperature for testing. Scanning electron microscope (SEM) was used to characterize thermally induced microcracks in the rock. Thermal conductivities of the treated specimens under dry and water-saturated conditions were determined using the Transient Plane Source (TPS) method, and the effect of water saturation on the thermal conductivity was investigated. The influences of temperature and axial compression stress on the thermal conductivity were also studied. Results indicate that the thermal conductivity of the specimens depends strongly on the thermal treatment temperature. The thermal conductivity decreases nonlinearly with applied temperature, because of growth and propagation of microcracks in the specimens. On the other hand, water saturation plays an important role in increasing the thermal conductivity. In addition, significant differences exist in the thermal conductivity behaviors of the specimens when subjected to different ambient temperatures and compression stresses. Based on the experimental data, models considering the effect of porosity were established for describing the effects of water saturation, ambient temperature, and compression stress on the thermal conductivity of thermally treated rock.
Safe disposal of high-level radioactive waste (HLW) is a challenging rock engineering task for all countries using nuclear energy. HLW repositories can be situated in rocks that are suitable for permanent disposal of the HLW, such as granite, clay, rock salt, and tuff. During the operation of a repository, the HLW will release heat continually and cause long-term temperature increases in the host rock. Thermal properties of the host rock determine rate of HLW heat dissipation. Among all the thermal properties of the host rock, the thermal conductivity is a key parameter to describe the heat transfer capability. For example, rocks with higher conductivities are more efficient at transferring heat energy. An accurate evaluation of host rock thermal conductivity is necessary for planning the size, layout, and cost of HLW repository systems (Sundberg et al., 2009). On the other hand, damage near the excavation boundary may occur as a result of sustained thermal loading, which may reduce the thermal conductivity of the host rock. Hence, a better understanding of the thermal conductivity of surrounding rocks under elevated temperatures is essential to designing HLW repositories.
Wang, J. (Beijing Research Institute of Uranium Geology) | Chen, L. (Beijing Research Institute of Uranium Geology) | Zhao, H. G. (Beijing Research Institute of Uranium Geology) | Zhao, X. G. (Beijing Research Institute of Uranium Geology)
With the rapid development of nuclear power in China, the disposal of high-level radioactive waste (HLW) has become an important issue for nuclear safety and environmental protection. Deep geological disposal is internationally accepted as a feasible and safe way to dispose of HLW, and underground research laboratories (URLs) play an important role in the development of HLW repositories. This paper introduces the overall planning and the latest progress for China’s URL. On the basis of the proposed strategy to build an area-specific URL in combination with a comprehensive evaluation of the site selection results obtained during the last 33 years, the Xinchang site in the Beishan area, located in Gansu Province of northwestern China, has been determined as the final site for China’s first URL in granite. In the process of characterizing the Xinchang URL site, a series of investigations, including borehole drilling, geological mapping, geophysical surveying, hydraulic testing and in-situ stress measurements, have been conducted. The investigation results indicate that the geological, hydrogeological and engineering geological conditions of the Xinchang site are very suitable for URL construction. According to the achievements of the characterization of the URL site, a preliminary design of the URL with a maximum depth of 560 m is proposed.
Safe disposal of high-level radioactive waste (HLW) is a challenging task for the sustainable development of nuclear energy and environmental protection. Geological disposal is considered as a feasible and safe option for the long-term management of HLW worldwide, and many countries have considered building deep geological repositories (DGRs) in which to dispose of spent fuel or vitrified HLW. In order to investigate the suitability of geological rock formations for hosting DGRs, to develop and test disposal concepts and technologies, to gain knowledge about multi-field coupled processes in geological and engineered barriers, and finally to assess and demonstrate the long-term performance and safety of DGRs, a number of underground research laboratories (URLs) have been constructed around the world (Kickmaier and McKinley, 1997; NEA, 2001; Wang, 2007).
URLs can generally be divided into generic URLs and site-specific URLs. Generic URLs are facilities developed for research and testing purposes at a site that will not be used for waste disposal while site-specific URLs are facilities developed as a potential site for waste disposal and a precursor to the development of a repository at the site (NEA, 2001; Ahn and Apted, 2010). In the past few decades, generic URLs have been developed within pre-existing underground excavations, such as mines and tunnels; e.g., the Grimsel Test Site and Mont Terri road tunnel in Switzerland and the Tournemire facility in France. There are also purpose-built generic URLs in specific rock types, such as the Äspӧ Hard Rock Laboratory in granite in Sweden and the Whiteshell URL in granite in Canada. The site-specific URL may be constructed either adjacent to or within the proposed repository location. Site-specific URLs include the ONKALO URL in granite in Finland, the Meuse/Haute Marne URL in claystone in France (Delay et al., 2010), the Gorleben URL in salt in Germany, and the ESF in volcanic tuff in the United States (NEA, 2001).
A large number of laboratory experiments about the influence of heating or heating-cooling cycles on the mechanical properties of various granites are reviewed. Both scanning electron microscopy (SEM) and particle-based discrete element modeling (DEM) are employed to quantitatively elucidate the mechanisms responsible for temperature-dependent mechanical properties of granites, from a perspective of microcracking. Both SEM observations and DEM simulations give consistent results and show that there exists a temperature threshold beyond which the thermally-induced microcracks increase drastically. Both intergranular and intragranular microcracks are observed in the granites after thermal treatment, and intergranular ones are dominant. A continuous increase in temperature can generally weaken granites, mainly by inducing significant thermal stress and generating tensile microcracks. The weakening of granites after a heating-cooling cycle is due only to the thermally induced microcracks. With increasing grain size the magnitude of Brazilian tensile strength reduction of granites due to thermal treatments becomes small, whereas with increasing heterogeneity in grain size distribution, the magnitude of Brazilian tensile strength reduction of granites due to thermal treatments becomes great. This is because the two competing mechanisms, i.e., the length and number of the thermally induced microcracks in granites.
Since the first enhanced geothermal system (EGS) was conceived at the Fenton Hill project, the United States, in the 1970s, EGS projects have been pursued around the world (McClure and Horne, 2014). EGS projects involve finding vast blocks with high temperature (> ~200 °C) and connected fracture networks. Working fluid (e.g., water or supercritical CO2) is first injected and circulated through the fracture networks in geothermal reservoirs and eventually pumped back to the surface as steam. In the world EGS projects are commonly located in granite rocks with various mineralogical properties (Zhao et al. 2018). The mechanical response of “hot granites” to cooling becomes an important question to geologists and engineers.
Yin, Chen (Chengdu University of Technology, Sichuan Geophysical Company of CNPC) | Wu, Furong (Sichuan Geophysical Company of CNPC) | Li, Yalin (Sichuan Geophysical Company of CNPC) | He, Guangmin (Sichuan Geophysical Company of CNPC) | Liu, Liting (Sichuan Geophysical Company of CNPC) | Yuan, Fengyao (Sichuan Geophysical Company of CNPC)
Sichuan is a fault rich area because the long term extrusion force of the Eurasian plate. The fault can be the pipe of the fluid flowing and accumulation, and also be the barriers for unconventional reservoir exploitation, e.g., (1) Resulting in the fracturing liquid leakage; (2) Communicating the harmful layer such as water layer and resulting in the water flood; (3) Triggering the small earthquake. It is difficult to detect some hidden faults for seismic resolution and those faults are stimulated to release the energy in the form of microseismic event (ME) during the hydraulic fracturing. This paper provides a composite method to differentiate the hydraulic microfracture (MF, the cloud of fractures which stimulated by hydraulic fracturing operation) and natural fault by the ME characteristics such as the waveform, frequency, source mechanism and time-space distribution and so on. Through theoretical analysis and actual data application, it can help us to effectively distinguish the fault from MF, lower fracturing risk and provide the optimized directions for the unconventional exploitation.
As the further exploration and exploitation of fossil energy, the new explored reservoir is more and more complex. Sichuan basin is abundant of unconventional resource and has been the National Shale Gas Test Base from the year 2011. Through the exploration of decades of years, it shows many faults existing in each of the layers because of the long term polycyclic geologic function. How to detect the natural fault has been the key emphasis in exploration because it has the strong affection on the fluid flowing and accumulation, and engineer operation during the exploitation stage.
In recent 30 years, people has done much work to detect natural fault by traditional discontinued attributes technologies from 3D seismic data, such as layer tracker, fault slice, coherent body, variance body, dip & azimuth attribute and enhanced edge detection and so on. However, these technologies are constrained by seismic quality and resolution, and results in ignoring of small scaled faults, and eventually produce serious influence to the recovery, e.g., the leakage of the fracturing liquid and water flood. In recent 5 years, the microseismic monitoring (MSM) has been widely applied to assess the fracturing of unconventional reservoir, whose potential in detecting the hidden faults gradually came into light (Baig et al., 2010). As the injection pressure increases during the fracturing operation, more and more energy accumulates in the reservoir and once the pressure reaches and exceeds the rock maximum rupture strength (Wu, 2013), the rock starts to crack to release energy in the form of the ME. The rock rupture has the similar characteristics in both fault and MF (Zhu, 2012), which shows the apparent seismic dynamic attributes whether the seismic wave is stimulated by the hydraulic fracturing or plate movement (Kikuchi and Kanamori, 1982; Valle and Bouchon, 2004; Fischer, 2005). Thus, those similarities increase the difficulties by MSM data to differentiate the natural fault and fractured MF.
Hansen, Kirk S (Shell India Markets Pvt. Ltd.) | Purkayastha, Anjanava Das (Shell India Markets Pvt. Ltd.) | Kumar, Mrityunjay (Shell Intl. E&P Inc.) | Zhang, Zhiyi (Shell China E&P Co. Ltd.) | Wang, Yan (Shell China E&P Co. Ltd.) | Li, Xuekang (Southwest Oil & Gas Field Co., PetroChina) | Christensen, Christopher J. (Noble Energy)
Prediction methods for pore pressure (PP) and fracture gradient (FG) developed for conventional resources include the use of normal compaction trends derived from correlations of log-based porosity with vertical effective stress (VES) and translation of pressures from offset wells to prospect locations using fluid densities and contacts. These techniques are less effective in unconventional plays like tight sands and shales because of disconnected fluids and difficulties in distinguishing PP from gas effects on the shale resistivity and compressional sonic velocities typically used for determining porosity.
Unconventional resources require alternative prediction techniques such as pressure cell models, in which individual formation layers exhibit either constant overpressure (OP, difference between PP and hydrostatic pressure) or constant VES (difference between overburden stress and PP). Direct measurements from pressure gauges or estimated pressures from drilling indicators such as connection gases and kicks are used to calibrate the amount of OP or VES for each layer or pressure cell. The modeled pressures are translated to specific well locations by adjusting for differences in stratigraphic depth following either constant OP (typical for permeable formations) or constant VES (for tight formations). Fracture gradients are calculated from the PP forecasts based on horizontal-to-vertical effective stress ratios (ESRs) calibrated against total horizontal stresses determined from field data such as leak-off tests and drilling losses.
Pressure cell models developed for the Sichuan Basin and evaluated against subsequent drilling experience indicate that: (1) consideration of all available offset data in combination with local geology is required to determine whether constant OP or constant VES is appropriate for each formation layer; (2) pressure-cell values can vary with both depth and area; (3) different ESRs are required for different lithologies and for depleted versus virgin pressures; and (4) all available field data (not only the nearest offset well) needs to be considered to provide realistic lower and upper bounds on PP and FG.
The pressure-cell techniques described here can be calibrated with local field data and applied to unconventional resources worldwide to provide an effective method for predicting PP and FG in environments where conventional PP-FG prediction methods break down.
Prediction methods for pore pressure (PP) and fracture gradient (FG) developed for conventional resources include the use of normal compaction trends derived from correlations of log-based porosity with vertical effective stress (VES) and translation of pressures from offset wells to prospect locations using fluid densities and contacts (Bowers 1995; Purkayastha et al. 2014). These techniques are less effective in unconventional plays like tight sands and shales because of disconnected fluids and difficulties in distinguishing PP from gas effects on the shale resistivity and compressional sonic velocities typically used for determining porosity (Couzens-Schultz et al. 2013).
For unconventional resources exploration and development, hydraulic fracture pattern, geometry and associated dimensions are critical elements in determining if the uneconomically low-permeability reservoirs can be effectively and efficiently stimulated. In principle, hydraulic fracture growth pattern is dominated by the state of stress in the subsurface, and commonly and optimally, hydraulic fractures are expected to grow vertically from deep wells and to have sufficient height growth to
connect stacked hydrocarbon-bearing and horizontally more permeable reservoir packages while being contained to stay away from water-rich intervals. While the tectonic setting and in-situ stress conditions for vertical fracture development have been well studied, those for horizontal or complex fractures remain unclear or not well reported. In this paper, a case study is presented on the complex hydraulic fracture in a highly over-pressured and tectonically stressed tight gas field in the Sichuan
Basin of southwest China.
During deep well hydraulic stimulation of the primary reservoirs of the Upper Triassic Xujiahe formation in the central western Sichuan Basin, difficulties are encountered in formation breakdown, injectivity establishment, proppant placement, pump equipment shut down, continuous high treating pressures, casing shear, and screen-out. These difficulties are preceded by larger-than-overburden breakdown pressures and ISIPs (Instantaneous Shut-In Pressure) during diagnostic pre-fracture injection tests, which imply that hydraulic fracture may have initiated and propagated horizontally. Different fracture monitoring techniques, however, have indicated that instead of getting purely horizontal fracture geometry, hydraulic fractures may have formed a complex network characteristic of T-shape or I-shape geometry. The main causes for such complex fracture geometry and limited fracture height are investigated and studied.
To quantitatively evaluate the fracturing performance and strategy, two classes of numerical hydraulic fracture models are undertaken. In addition to the LEFM (Linear Elastic Fracture Mechanics) based hydraulic fracture simulation, a fully-coupled
finite-element based model is developed that takes into account a full suite of rock mechanical properties of sandstone and shale sequences and geological features that may limit or facilitate the fracture growth. The modeling results indicate that in addition to the typical stress control on the growth of fracture height, contrast in mechanical property and the presence of bed-parallel geological features may act as fracture baffles or barriers that prematurely arrest the vertical growth and facilitate
development of horizontal fractures.
Dongxia, Chen (China University of Petroleum, Beijing) | Mingxian, Xie (China University of Petroleum, Beijing) | Xiaopeng, Zhang (Sinopec Southwest Co. Ltd.) | Liang, Xiong (Sinopec Southwest Co. Ltd.) | Liming, Wei (Sinopec Southwest Co. Ltd.) | Hongliang, Shi (Sinopec Southwest Co. Ltd.)
Very little attention were paid for the continental shale sequence compared to marine shale of the Sichuan Basin, although the continental shale owns good conditions for the shale gas accumulation. The further research of shale gas accumulation conditions is meaningful to realize the exploration and development prospects effectively, and to expand the field of exploration and development. Based on the research of the development characteristics, organic type of shale grade of maturity, abundance of organic matter, rock and ore characteristics,physical properties of reservoir, type of pore, and preservative conditions of the continental shale of the 5thsector of the Xujiahe Formation of Upper Triassic in Western Sichuan Depression,oil-bearing property and resource potential are comprehensive studied. The research shows that the thickness of shallow lake facies black mud shale in the 5thsector of the Xujiahe Formation is about 250to 300 m, and the average of TOC is more than 2% in the mature to high mature stage. The micro-fractures, nano-micron level pores, clay mineral intergranular micro pores and slightly soluble holes are developed in shale, and the quantity of brittle minerals such as quartz, feldspar, carbonates is more than 60%. In spite of multiphase tectonic evolution, the shale's preservation conditions of shale are excellent. The shale shows very well oil-bearing property. Natural gas was generally released while drilling, and the real quantity of shale gas of the in-situ sample ranges from 0.42 to 6.27 cubic meters per ton, with an average of 1.37 cubic meters per ton, and to absorbed gas mainly, which shows the better characteristics of gas content. The Xujiahe Formation shale has high gas resource potential and high abundance of gas resources. The quantity of the shale gas resource with depth less than 3500m is 0.01 Tcf, gas-bearing abundance is from 10.06×108to 13.15×108cubic meters per square kilometer. The quantity of brittle mineral of the continental shale reservoir in the Xujiahe Formation (quartz and carbonate) is high, which predicts that fracturing is easier to form network fractures, to achieve volume transformation and showing a good development prospects.
Hydraulic Fracturing (HF) is a mature technique to rehabilitate the productivity of a hydrocarbon formation, but Iranian oil companies are taking the primary steps to practice it in their oil fields. A couple of operations have been practiced but the unproductive results emphasized on the importance of Candidate Selection method. There is not a standard procedure or computerized tool to select primary candidates from Iranian carbonate oil fields. This paper presents the development of a locally written interface to automatically select specific zones for special operations like HF. The program is written in MATLAB in such a way to anticipate the missing data by Neural Network and Fuzzy Logic technique and then integrate large amount of data from different disciplines. In the end, data are mechanically screened based on the user selected parameters, cut-offs and weight factors. Results of screening within the limitations are prioritized in stacked bars to make decision easier. This tool is applied for a purpose of candidate selection for HF in M oil field located in south of Iran. This field has 585 zones which each zone has more than 30 parameters form different disciplines. The result of this programming is printed schematically and it is easy to see the quality of each criteria. This technique can be applied for unlimited number of zones and wells.
Most of Iranian oil fields have passed their plateau production rate and about 200,000 bbl/d of crude production be lost annually due to natural pressure declines of the fields1. Moreover, with natural flow only 20% to 25% of the original oil in place is extracted from Iranian carbonate oil reservoirs, which is 10% less than the world average. Therefore, the new era to look for new technology just started to maintain and increase the production. Application of gas lifting system, electrical submersible pumps, sucker rod pumps and hydraulically fracturing the formation are being considered to maintain the well production rate. HF technology as introduced worldwide is an effective approach that can make the difference and can grant new life to old mature fields2. Various advantages make HF a superior type of production enhancement in carbonate reservoirs. This subject along with the needs for HF was addressed briefly by Zoveidavianpoor et al. (2010, 2011b)3, 4.
Although HF operation has more than 60 years of history and every day hundreds of treatment is performed around the globe, however, still there is not any report of successful HF operation in Iran. In order to have well-adapted HF technology, detailed geomechanical studies and well integrity test such as leak-off test, minifrac test, calibration test, etc., have to be performed. Unfortunately, those bottom-line studies are not implementing in Iran. Investigation of Shadizadeh and Zoveidavianpoor, 20105; Zoveidavianpoor et al. 2011a6., have shown that the lack of data/information about rock mechanical properties, regional in-situ stress, and specially no consideration of candidate selection study, were the main reasons of failure in HF operation.
The advantages of successful HF are so much that Iranian oil companies are trying to develop HF technologies in some oil fields. As clearly cited in the literatures, successful HF operation primarily depends on systematic candidate selection. The disappointment of a rare cases of HF in southern Iranian oilfields indicate that to accept HF technology as a replacement stimulation method and also, increasing the recovery factor, significant efforts have to be concentrated on zone and well candidate selection. As a result, a research project has been proposed and started in National Iranian South Oil Company (NISOC) to investigate candidate selection for HF in three oilfields named: "A??, "M??, and "AR??.
Xu, Cheng-yuan (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation) | Kang, Yi-li (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation) | You, Li-jun (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation) | Li, Song (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation) | Chen, Fei (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation)
A new high-strength, high-stability (HSHS) pill system for controlling lost circulation has been developed and optimized on the base of a physical model of stable plugged zone. This new HSHS pill system provides a stronger and more effective seal than traditional treatments.
Controlling lost circulation with plugged zone formed with lost circulation material (LCM) in the fracture has achieved tremendous success in the past years. However, investigation into the strength and stability of the plugged zone has not been reported. Ignorance of such knowledge often leads to excess costs from repeatedly fluid loss and rig time, increases the difficulty and complexity of loss-zone diagnosis.
The new HSHS pill system addresses these shortcomings. Surface friction coefficient, LCM volume fraction and amount of contact deformation are the main influencing factors of the strength and stability of the plugged zone. The strength of the plugged zone is enhanced with the increase of the above factors considering which the physical model of stable plugged zone is established. The pill system based on the model provides an engineered combination of rigid granules, fibers and deformable particles. The sealing efficiency and the pressure-bearing capacity are greatly enhanced. It was validated in several field trials in West China. Operational practices that facilitate the safe use of the HSHS system with overbalance exceeding 2,174 psi are discussed. In addition to the field trial results, this paper also described the laboratory-scale tests, which were used for developing the new system.
With the development of the physical model and the HSHS pill system it is now possible to optimize and select the types, properties and matching relations of the LCM. This technology can also be used to guide the design of wellbore strengthening scheme and make sure the long-term effectiveness of wellbore strengthening measures.
The formation pressure-bearing capacity is the comprehensive reflection of structural integrity and strength of formation, drilling fluid property and the interaction between formation and drilling fluid. Low strength of rock, high development degree of fracture, poor plugging ability of drilling fluid often lead to wellbore breakdown, natural and induced fracture propagation. This can be seen by formation low pressure-bearing capacity, massive losses of drilling fluid associated with other downhole troubles, which seriously hindered the development of oil and gas resources.
An API study published in 1991 includes data1 indicating that up to 45% of all wells require an intermediate casing string to prevent severe lost circulation while drilling to total depth (TD). Even when using these extra strings, lost circulation events still occurred in 18 to 26% of all hole sections. Some areas reported many more occurrences of lost circulation events ranging from 40% to 80% of wells. In recent years, these percentages have increased as the number of shallow, easy-to-find reservoirs has steadily declined and industry operators have intensified their search for deeper reservoirs and drilled through depleted or partially depleted formations. Conventional LCM including pills, squeezes, pretreatments, and drilling procedures employing equivalent circulating density (ECD) management have reached their limit in effectiveness and become unsuccessful in the deeper hole conditions where some formations are depleted, structurally weak, or naturally fractured and faulted.
Yuan, Roger (Shell China Exploration and Production Co. Ltd.) | Jin, Liang (Shell China Exploration and Production Co. Ltd.) | Zhu, Changlong (Shell China Exploration and Production Co. Ltd.) | Zhou, Ming (Shell China Exploration and Production Co. Ltd.) | Vitthal, Sanjay (Shell Canada Limited)
Development of unconventional tight gas fields require effective and optimal placement of hydraulic fractures that enhance insitu permeability and improved accessibility to reservoirs. Optimally, hydraulic fractures are expected to have sufficient
vertical height growth to connect stacked gas-bearing and horizontally more permeable reservoir packages while being contained to stay away from water-rich intervals. In this paper, a case study is presented on the complex hydraulic fracture geometry in a highly over-pressured and tectonically stressed tight gas field in the Western Sichuan Basin.
Difficulties in formation breakdown and proppant placement, pump truck failure, continuous high treating pressures, screen-out, and casing shear are encountered during the hydraulic stimulation of the Xujiahe members of the upper Triassic Xujiahe formation. These difficulties are preceded by larger-than-overburden breakdown pressures and ISIPs during diagnostic pre-fracture injection tests, which imply that hydraulic fracture may have initiated and propagated horizontally. Instead of concluding with a purely horizontal fracture geometry, evidence supports that the hydraulic fractures, as delineated by different fracture monitoring techniques, may form a complex fracture network characteristic of T- and I-shape geometry.
The main causes for such complex fracture geometry and limited fracture height are investigated and studied. A fit-for-purpose zone selection and perforation strategy is implemented which avoids high water saturation, less fraccable and highly laminated intervals. The findings and experience underline the importance of integrating geology, geomechanics, and fracture diagnostics to understand hydraulic stimulation effectiveness and to improve operational performance in the unconventional tight gas field development.