Wellbore temperature and pressure calculation model for coiled tubing drilling with supercritical carbon dioxide

To better control the state of carbon dioxide during supercritical carbon dioxide drilling, a mathematical model is established to analyze the wellbore carbon dioxide temperature and pressure influencing factors. In this model, the influences of formation temperature change and fluid-friction-generated heat on wellbore temperature distribution are considered. Additionally, the impact of casing, tubing, and cement sheath thermal resistance on heat transfer are considered. The model is validated by comparing the wellbore temperature data calculated from this model with data from previous models. Based on the model, the factors that may affect the wellbore carbon dioxide temperature and pressure are analyzed. The results show that the downhole temperature decreases with the decrease in nozzle diameter and geothermal gradient, and with the increase in injection rate. The injection temperature significantly affects the wellbore temperature near the wellhead, but it does not affect the downhole temperature. Therefore, for low geothermal gradient formation, reducing the injection rate and increasing the nozzle diameter are two effective methods to maintain the CO₂ at the downhole in the supercritical state. The pressure inside the coiled tubing increases with the increase in injection rate and decrease in nozzle diameter, but the injection temperature and geothermal gradient has little effect on the pressure inside both the coiled tubing and annulus.     

Phase Prediction of Supercritical Carbon Dioxide and its Application in Fracturing Oil Wellbores

In recent oil and gas exploration, the most reservoirs are low permeability with abundant reserves. Conventional mining of low permeability reservoir is commonly utilizing the hydraulic fracturing technology, whereas, it encounters various technical issues, such as clay expansion and water lock damage. Using the fluid of supercritical carbon dioxide(S-CO_2) to exploit the low permeability oil and gas reservoirs is attracting more attention. The implementation of S-CO_2, without liquid phase, can help avoid the aforementioned problems. Nevertheless, the phase change of CO_2 during fracturing is complicate, and it is difficult to accurately predict the CO_2 phase transition. In this work, first, the physical properties of S-CO_2 were analyzed by the Span-Wagner model and Vesovic model. Next, S-CO_2 was applied to a typical oilfield, and an unsteady coupling model of heat transfer and pressure drop was developed. Then the staggered grid method and iteration procedures were used for numerical solutions, and the temperature and pressure distributions of wellbores were investigated. The results indicate that the temperature control of a wellbore is the key to the phase prediction of S-CO_2; CO_2 within the single-diameter pipeline below 2300 m can maintain the supercritical state, while CO_2 within the stepped pipeline can maintain the supercritical state at the depth of 2280 m. Moreover, compared with the single-diameter pipeline, the bottom pressure of the stepped pipeline is lower and the bottom temperature is higher. By analyzing the flow and heat transfer of S-CO_2 in the wellbores, the phase state of S-CO_2 was well predicted, which is helpful to improve the exploring performance of low permeability oil and gas reservoirs.     

Multifracture response to supercritical CO2‐EGS and water‐EGS based on thermo‐hydro‐mechanical coupling method

Hydraulic‐fracturing treatments have become an essential technology for the development of deep hot dry rocks (HDRs). The deep rock formation often contains natural fractures (NFs) at micro and macroscales. In the presence of the NF, the hydraulic‐fracturing process may form a complex fracture network caused by the interaction between hydraulic fractures and NF. In this study, analysis of carbon dioxide (CO₂)‐based enhanced geothermal system (EGS) and water‐based EGS in complex fracture network was performed based on the thermo‐hydro‐mechanical (THM) coupling method, with various rock constitutive models. The complexity of the fracture geometry influences the fluid flow path and heat transfer efficiency of the thermal reservoir. Compared with CO₂‐based EGS, water‐based EGS had an earlier thermal breakthrough with a rapid decline in production temperature. CO₂ can easily gain heat rising its temperature thus reducing the effect of a premature thermal breakthrough. Both CO₂‐based EGS and water‐based EGS are affected by in‐situ stress; the increase in stress ratio improved the fracture permeability but resulted in an early cold thermal breakthrough. When the same injection rate is applied to water‐based EGS and CO₂‐based EGS, water‐based EGS displayed higher injection pressure buildup. Water‐based EGS had higher reservoir deformation area than CO₂‐based EGS, and thermoelastic constitutive model for water‐based EGS showed larger deformed area ratio than thermo‐poroelastic rock model. Furthermore, higher values of rock modulus accelerated the reservoir deformation for water‐based EGS. This study established a novel discussion investigating the performance of CO₂‐based EGS and water‐based EGS in a complex fractured reservoir. The findings from this study will help in deepening the understanding of the mechanisms involved when using CO₂ or water as a working fluid in EGS.     

An innovative technology of directional propagation of hydraulic fracture guided by radial holes in fossil hydrogen energy development

Conventional hydraulic fracturing fails to develop low permeability reservoirs of fossil hydrogen energy that are not located in the direction of maximum principal in-situ stress. A new technology of fracture propagation guided by radial holes is proposed, which can realize directional propagation of hydraulic fracture along radial holes in fossil hydrogen energy development. In order to verify this new technology, a model of radial holes combined with hydraulic fracturing is established by the ABAQUS extended finite element method. Simulation results show that radial holes play a guiding role in fractures propagation. The influence extent of seven factors on the directional propagation of hydraulic fracture is listed as follows (from strong to weak): azimuth of radial holes > horizontal in-situ stress difference of fossil hydrogen reservoir > injection rate of fracturing fluid > Young's modulus of rock > permeability of fossil hydrogen reservoir > Poisson ratio of rock > viscosity of fracturing fluid. True tri-axial experiment is carried out to verify the accuracy of numerical simulation, and the result is consistent with numerical model, which indicates that numerical simulation is reliable.     

低渗复杂断块油藏采油技术对策

海拉尔油田构造、岩性复杂,断块破碎,储层物性差,存在储隔层应力差小、窜槽问题突出,施工压力大、裂缝延伸困难,单井产量低、注水压力高,以及储层多而薄等特点.对此,采用人工隔层、变排量和动态胶塞等控缝高技术及高施工压力对策,有效控制窜槽和施工压力高的问题,提高了压裂成功率和增产效果.通过实施矩形井网整体压裂、复杂岩性储层细分多层压裂和多分支缝压裂等技术,薄差层动用程度提高,单井产量增加,注水压力降低.抽油机安装前应根据油井井况和抽油机工况,初步测算平衡块质量和位置,避免出现严重的不平衡现象.对已出现不平衡的在用抽油机,可采取在游梁尾部焊接连接支座、连接配重,或在游梁尾部焊接短游梁、连接配重的改造措施.安装抽油机深井减载或二次减速装置,也可改善抽油机平衡状况,延长系统使用寿命.应用减载装置,降低杆柱下行时的轴向压力;通过扶正器的合理配置、油管锚定及抽汲参数的优化,可有效降低杆柱磨损几率,延长检泵周期.     

Numerical simulation of fracture reorientation during hydraulic fracturing in perforated horizontal well in shale reservoirs

Fracture reorientation affects hydraulic fracturing much in perforated wells. A finite element model used for investigating fracture reorientation is established using the extended finite element method with ABAQUS software. Based on this, both fracture reorientation and fracture propagation during fracturing operation in shale reservoirs are analyzed. Meanwhile, the effect of the difference between the maximum and minimum principal stresses on fracture reorientation during fracturing in shale reservoirs has also been studied. The results demonstrate that the fracture reorients to the direction of the maximum principal stress gradually, and the difference between the maximum and minimum principal stresses impacts the fracture reorientation more than fracture propagation.     

Theoretical research on radial wells orientating hydraulically created fracture directional extended

Hydraulic fracturing of radial wells have become new technologies to effectively develop low permeability reservoir, thin reservoir, fractured reservoir, “dead area” after water injection etc. Influenced by ground stress and reservoir heterogeneity, hydraulically created fracture will probably not extend smoothly to connect the target area along the direction of radial wells, the reservoir stimulation effect is not ideal. Based on the pressure analysis of fracturing initiation of multiple radial holes and the theory of plasticity district, criterion of multiple radial wells orientating directional fracture propagation in the condition of ground stress is derived. In this condition, multiple radial wells will produce a continuous plasticity district in the reservoirs, while maintaining the fracture extending in plastic zone directionally without the effect of ground stress, which guarantees that fracture is interconnected between the radial wells during fracturing operation, to form the main crack along the direction of radial wells’ axis plane. In consideration of economy, maximum spacing of radial wells are optimized, in order to provide a reliable scientific basis for effectively implementation of hydraulic fracturing technology in radial wells.     

新疆油田火山岩气藏体积压裂机理研究及应用

进行火山岩气藏压裂改造时,通常采用形成单一裂缝的增产改造技术,气井稳产时间较短.借鉴页岩气开发理念,深入研究火山岩气藏体积压裂机理.根据缝内压力传导的力学模型,研究不同液体体系对压力传导的影响,分析无滤饼压裂液体系对体积压裂的作用,优选出压裂液体系;建立不同角度天然裂缝开启的力学模型,确立体积形成的关键力学条件,并针对火山岩气藏压裂目的层的地应力结构进行实际分析.从储层矿物角度出发,研究对比火山岩储层的脆性系数;根据力学条件,结合压裂工艺过程,建立相关模型,优化研究体积压裂关键工艺参数,包括排量、压裂规模等;分析降阻水、线性胶、浓胶液三种不同黏度液体对裂缝网络的作用.在上述研究基础上,针对新疆油田DX1413井实际地质条件,分析该井进行体积压裂的有利条件,并进行压裂设计与改造施工,对施工曲线、施工过程、施工结果进行分析,得到了一些有益的结论,这些结论对火山岩气藏的开发有重要的启迪作用.     

河北献县东部雾迷山组碳酸盐岩热储酸化压裂试验研究

通过对河北献县东部雾迷山组碳酸盐岩进行大尺寸高地应力酸化压裂物理模拟试验与小尺寸温度应力耦合环境下酸化压裂试验,讨论地应力、温度、酸液排量以及压裂模式等因素与碳酸盐岩压裂效果之间的关系,找到碳酸盐岩储层压裂裂缝的生长规律。研究表明：将裂缝发育与裂缝不发育储层碳酸盐岩压裂曲线对比发现,储层岩石裂缝发育程度可明显降低破裂压力;压裂试验中储层岩石内裂缝激活对破裂压力具有显著影响,现场压裂过程中应当考虑到储层工程地质中裂缝发育程度的问题;酸液处理可显著降低破裂压力,更有利于形成复杂裂缝网络,破裂过程中诱发更多声发射事件,同时储层岩石裂缝发育程度直接影响到压裂效果。     

二次加砂工艺技术在玛北百口泉组砂砾岩的应用

准噶尔盆地环玛湖凹陷西斜坡三叠系百口泉组砂砾岩储层厚度大,具有低孔、低渗特征,油层居于储层上部,局部存在水层,储层压裂改造难点是控制人工裂缝向下延伸以及支撑剂的合理铺置。所谓二次加砂技术,是在压裂过程中,完成第一级加砂后停泵,待裂缝闭合,进行第二级加砂,每级加砂都是相对独立完整的泵注过程,该技术具有下列优点:控制裂缝高度向下延伸,具有控缝高作用,二次加砂压裂后的裂缝长度大于一次加砂(同等加砂规模下);支撑剂向上充填,正好充填在油层位置,有利于油气生产;压裂缝具有支撑裂缝宽度大,填砂浓度高,导流能力强等优点,满足低渗透油藏对裂缝导流能力的要求。在二次加砂技术基础上,针对不同的储层类型,开发出三种组合压裂工艺,分别为二次加砂+分层压裂组合工艺、二次加砂+前置滑溜水组合工艺、二次加砂+控缝高组合工艺。经过多井次试验,三种工艺均获得理想压裂效果。实践证明,二次加砂及其组合技术在玛湖凹陷储层具有很好的适应性。     

Numerical simulation of supercritical carbon dioxide flows across critical point

Numerical study of supercritical carbon-dioxide flows across the critical point is presented. The present numerical method is based on the preconditioning method developed by Yamamoto and mathematical models of thermophysical properties for carbon dioxide programmed in the program package for thermophysical properties of fluids, developed by Kyushu University. First, the two-dimensional natural convection of carbon dioxide between two parallel plates is calculated while changing the bulk pressure. The calculated thermophysical properties of the carbon-dioxide flow under supercritical pressure are compared with those in a gas condition. Next, the natural convection of carbon dioxide in an O-shaped cyclic channel is calculated, and the effect of the density difference induced by the phase change to the flow is investigated. For application to high-speed flows, supercritical carbon dioxide flows through a nozzle with free-jet expansion (known as the process of rapid expansion of supercritical solutions) process are calculated. The calculated shock distance to the Mach disk generated in the free jet is compared with experiments and the density variations in the nozzle while changing the inlet temperature are numerically predicted.     

Numerical Investigation of Jet Impingement Cooling of a Flat Plate with Carbon Dioxide at Supercritical Pressures

Confined round jet impingement cooling of a flat plate at constant heat flux with carbon dioxide at supercritical pressures was investigated numerically. The pressure ranged from 7.8 to 10.0 MPa, which is greater than the critical pressure of carbon dioxide, 7.38 MPa. The inlet temperature varied from 270 to 320 K and the heat flux ranged from 0.6 to 1.6 MW/m². The shear-stress transport turbulence model was used and the numerical model was validated by comparison with experimental results for jet impingement heating with hot water at supercritical pressures. Radial conduction in the jet impingement plate was also considered. The sharp variations of the thermal-physical properties of the fluid near the pseudocritical point significantly influence heat transfer on the target wall. For a given heat flux, the high specific heat near the wall for the proper inlet temperature and pressure maximizes the average heat transfer coefficient. For a given inlet temperature, the heat transfer coefficient remains almost unchanged with increasing surface heat flux at first and then decreases rapidly as the heat flux becomes higher due to the combined effects of the thinner high specific heat layer and the smaller thermal conductivity at higher temperature.     

HDR Experiments at Falkenberg/Bavaria

A test site for HDR experiments has been set up in granite in the Bohemian massif in east Bavaria. A large fracture was stimulated by hydraulic fracturing in a depth of 250 m. The orientation of the fracture was investigated by seismo-acoustic recording during the frac-experiments and by examining the fracture pattern initiated in the injection interval of the borehole by an impression packer and by acoustic televiewer measurements. Geoelectric measurements for fracture location at the surface were also tested before attempting to drill through the fracture. The fracture has now been intersected by 6 additional boreholes at distances between 2 m and 70 m from the initiation interval.According to the results of seismo-acoustic recording, temperature logging and acoustic televiewer measurements in the intersection boreholes, a single plane artificial fracture has been produced, striking E-W and dipping 50°S. The orientation of the fracture, which should be normal to the least compressive principal stress, and the value of the normal stress on the fracture are not consistent with the direction and the values of the principal stresses determined by wire line hydraulic fracturing stress measurements.Various hydraulic experiments were performed in the different boreholes to investigate the mechanical reaction of the fracture due to varying fluid pressure, the hydraulic properties of the fracture, the fluid losses and the heat exchange within the fracture. The models developed to interpret the results make it possible to translate the results to greater depth and higher flow rates.     

A dual-porosity dual-permeability model for acid gas injection process evaluation in hydrogen-carbonate reservoirs

The Pre-Caspian basin is one of the most prolific in terms of oil and gas exploration and hydrogen and carbon compounds energy production around the world. The major hydrogen and carbon compounds reservoirs are Carboniferous reef and platform hydrogen-carbonate rocks. The original fluids under subsurface conditions contain 15% hydrogen sulfide and 4% carbon dioxide. Acid hydrogen and carbon compounds reinjection is not only an environmentally friendly solution for disposal of produced greenhouse gases but also enhances oil recovery and supplies more fuel energy. On the other hand, the presence of fractures makes hydrogen-carbonate reservoir characteristics nature more complicated than conventional sandstone reservoirs, which leads to a tremendous challenge to evaluate the gas injection process. In this work, a dual-porosity dual-permeability formulation was used to model the dual-medium nature incorporating matrix system with high porosity and low permeability and fracture network with low porosity and high permeability. After matching PVT experiments, a ten pseudo-components fluid model was generated for running compositional simulation. The miscible hydrogen and carbon compounds injection was simulated as an effective enhanced oil recovery approach. Sensitivity analysis such as timing of injection gas, injection rate, well spacing and completion interval have proposed the optimal condition for the miscible hydrogen and carbon compounds flooding. The recommended optimum hydrogen and carbon compounds injection scenario is twice higher oil recovery compared with natural depletion. The results of this study illustrate further the practicability of pseudo-components splitting and lumping for compositional simulation to evaluate the performance of hydrogen and carbon compounds injection processes, and are of great importance using the dual-porosity dual-permeability method performing numerical simulation of naturally fractured hydrogen-carbonate reservoirs.     

低腐蚀性加重酸室内研究及应用

加重酸化是针对深井、超深井高破裂储层酸压改造的降低地层破裂压力的预处理技术。但因深井、超深井地层温度高,加重酸液体系的腐蚀性强,其应用受到很大限制。针对四川元坝地区储层埋深大、温度高,破裂压力高等特点,开展了加重酸液类型、主体酸浓度和加重剂、缓蚀剂等添加剂的实验优选及配方优化,获得了适合元坝地区深井/超深井高温、高破裂储层酸压改造的低腐蚀性加重酸液体系。优选获得的加重酸液密度达1.8g/cm3以上,在160℃高温条件下,其动态腐蚀速率小于30g/(m2.h),放置稳定性好(室温放置8d不分层、不沉淀)、溶蚀能力好,属典型低腐蚀性加重酸液体系。元坝YB2-X井须二段4600～4640m储层,此前采用密度为1.98g/cm3泥浆两次试挤,井底压力梯度超过3.71MPa/100m,地层仍无破裂迹象,随后采用40m3密度为1.85g/cm3低腐蚀性加重酸进行试破,施工排量由1.0m3/min升至2.4m3/min,酸化吸酸指数最大达19.38L/(min.MPa),地层具明显压裂显示。采用加重酸化技术,对深井超高破裂压力储层进行预处理,可取得较好增产效果。     

服役工况下汽轮机平衡盘区域强度及间隙变化

以某超超临界机组的高压模块的平衡盘作为研究对象,利用ABAQUS软件建立高压模块的轴对称模型,并根据电厂实际运行工况的蒸汽温度压力数据计算加载边界条件,分析了实际启动和满负荷运行工况下高压平衡盘及前后密封区域的温度、应力和位移的变化及密封处径向间隙变化规律。研究表明:运行过程中服役工况下温度和应力产生了波动,在启动阶段最为剧烈,稳态运行时波动幅度较小;启动阶段径向间隙会明显减小。     

松南深层气藏压裂井井下压力、温度监测技术应用

吉林油田松南深层气井由于储层温度高、地应力高、非均质性强等因素的影响,在压裂过程中不能按设计程序执行,降低了压后增产效果。通过在压裂施工前将可存储式电子压力计随压裂管柱下人到目的层,完整地记录压裂施工过程和压后排液阶段的真实井底压力、温度变化情况,利用所录取的数据,准确地计算出压裂施工不同阶段管柱的实际摩阻,建立深层气井压裂液摩阻图版。该技术应用后可科学指导破胶剂追加,确保压裂液及时破胶返排;优化设计固化剂固化温度和固化时间,有效防止气井压后返排时发生支撑剂回流现象;解释、拟合人工裂缝长度和储层渗透率等参数,有效评价压后增产效果。该技术在松南深层气井的实际应用中取得了良好的效果,提高了压后分析评价水平。同时为进一步优化深层气井的压裂施工设计提供了理论依据。     

Unsteady seepage solutions for hydraulic fracturing around vertical wellbores in hydrocarbon reservoirs

This paper establishes an analytical model to study the influence mechanism of hydraulic fracturing around vertical wellbores under the unsteady seepage in hydrocarbon reservoirs, deduces the analytical solution of water pressure and hydraulic gradient of the model, and compares the law of water pressure and hydraulic gradient changing with time with the results of numerical simulation. The results confirm the accuracy of these analytical solutions. The variation laws of water pressure and hydraulic gradient in the sample under unsteady seepage are analysed by using the COMSOL Multiphysics software. The results show that: the increasing rate and amplitude of water pressure decrease with the distance of water inlet, however, hydraulic gradient near the water inlet is the largest and decreasing with the distance. In order to better understand the mechanism of hydraulic fracturing of rock mass, we studied the influence of permeability and water injection pressure on water pressure and hydraulic gradient of rock mass. The results show that: large permeability coefficient and high hydraulic gradient will increase the probability of rock mass hydraulic fracturing. The permeability and hydraulic gradient of rock mass is important factor in determining whether the rock has hydraulic fracturing. The distribution law of water pressure and hydraulic gradient in rock mass under unsteady seepage provides important reference and basis in hydrogen developing reservoirs.     

定北区块复杂储层压裂工艺技术研究与应用

定北区块上古生界储层具有低孔、致密、高温、天然裂缝发育、基本无自然产能等复杂特征。勘探前期因地层参数缺乏．采用常规硼交联压裂液体系及常规压裂技术实施作业,压裂工艺的针对性不强,施工过程中极易出现砂堵现象。为此．开展了高温暂堵压裂液体系及测试压裂工艺技术应用研究,研制了有机锆交联高温暂堵压裂液体系,并选择定北7井2储层首先开展了小型压裂测试,获取了储层、压裂裂缝、压裂液等相关参数。根据测试压裂结果,对该储层进行压裂设计与施工：设计排量4．5m3／min．前置液比例37％,平均砂比24％,加砂量38m3,全程使用有机锆交联高温压裂液．前置液添加l％屏蔽暂堵剂。压裂施工结束后,对主压裂数据进行压力拟合,结果显示,研制的高温暂堵压裂液体系能满足区块高温、微裂缝发育储层的压裂造缝、携砂等施工需要,压裂改造达到了预期效果。     

Modelling of fractured horizontal wells with complex fracture network in natural gas hydrate reservoirs

Shale gas resources (SGR), as a representative of natural gas hydrate reservoirs, have been the main energy supply for the energy consumption currently. The multi-scale pore structure of shale, complicated seepage mechanisms, including Knudsen diffusion, matrix deformation, stress sensitivity, non-Darcy flow and spatial fracture network stimulated by hydraulic fracturing technology have posed huge challenges to an accurate prediction and assessment of shale gas recovery. A full understanding of gas seepage mechanism of shale gas is the critical and scientific issue to develop carbon hydrogen energy resources effectively. It is very urgent to establish a comprehensive mathematical model to analyze the productivity capacity through simultaneously considering various flow mechanisms and fractures network system. To fill this gap, this paper presents a comprehensive numerical model of hydraulic fracturing horizontal well with discrete fracture network where embedded discrete fracture model (EDFM) is employed to characterize the coupled phenomenon between discrete fracture network and fractured SGR. And then two numerical discretization methods, e.g., finite difference and finite-volume, are used to numerically discretize the equations, subsequently, the Newton-Raphson iterative method is adopted to obtain the final solutions. Finally, the sensitivity analysis experiments are employed to investigate the effects of the key parameters. The results can provide some certain guidance for the optimization of stimulated treatment in natural gas hydrate reservoirs.