Zou, Jian (CNOOC Ltd, Tianjin Branch) | Han, Xiaodong (CNOOC Ltd, Tianjin Branch) | Liu, Yigang (CNOOC Ltd, Tianjin Branch) | Wang, Qiuxia (CNOOC Ltd, Tianjin Branch) | Zhang, Hua (CNOOC Ltd, Tianjin Branch) | Liu, Hao (CNOOC Ltd, Tianjin Branch) | Wang, Hongyu (CNOOC Ltd, Tianjin Branch) | Han, Chao (China University of Petroleum (East China))
Thermal recovery method with horizontal wells has been conducted in Bohai Oilfield for almost ten years. The horizontal section length of the horizontal well is about 300 m. For thermal wells, monitoring the real-time temperature data downhole is of importance for analyzing the temperature distribution and variation rules along the wellbore, and consequently improving the produced degree of the horizontal wells.
Different kinds of high-temperature monitoring technologies are summarized and the high-temperature optical fiber is selected for temperature monitoring of the offshore thermal wells. The steam injection tubing with functions of temperature monitoring is designed by using the optical fiber. In the horizontal section, the optical fiber is installed inside the steam injection tubing, goes outside of the tubing through a Y-joint, and connects to the surface along the annulus. Thus, the optical fiber could monitoring temperature of both the horizontal section and the annulus. Two target well are selected for project design and put into field application during the steam injection process. The monitoring results show that the high-temperature optical fiber works normally for about one month while the steam injection temperature is about 350°C. Besides, with the real-time temperature monitoring, the upward movement of the steam in the annulus is also observed and controlled by adjusting the Nitrogen injection parameters in the annulus.
This is the first time that the optical fiber technology is applied in offshore thermal wells, which would be important for verification of wellbore parameter calculation and analysis of the casing variation when heated during the steam injection process. The successful application of the optical fiber in offshore thermal well would provide a guidance for the subsequent offshore thermal exploitation.
Li, Kun (China University of Petroleum (East China)) | Zhu, Ming (Shenzhen Branch of CNOOC Ltd) | Du, Jiayuan (Shenzhen Branch of CNOOC Ltd) | Liu, Daoli (Shenzhen Branch of CNOOC Ltd) | Yin, Xingyao (China University of Petroleum (East China)) | Zong, Zhaoyun (China University of Petroleum (East China))
Lithology prediction and geofluid discrimination are the ultimate objectives of rock physical analysis and prestack seismic inversion. For prestack Bayesian estimation and geostatistical simulation, the prior probability density distribution of model parameters are usually influenced by subsurface lithologies and geofluid facies, which consist of several Gaussian probability components with different means and covariances. With the assumption of Gaussian mixture a priori, one improved prestack EVA inversion (elastic impedance variation with angle) conditioned by seismic and well data in mixed-domain is proposed to realize the estimation of discrete lithofacies and continuous geofluid parameters. The peaks number of prior Gaussian probability density is the same as classifications of sedimentary lithologies. For the resolution of seismic inversion, sequential simulation algorithm is utilized to sample the posterior probability distributions. Besides, the low frequency regularization and nonlinear bounding constraint strategy are introduced into the proposed method, which can enhance the stability of prestack EVA inversion and overcome the unrealistic solutions of elastic parameters. Finally, model tests and the applications on field prestack seismic data can verify the effectiveness and practicability in geofluid discrimination of the proposed algorithm.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 206A (Anaheim Convention Center)
Presentation Type: Oral
Yan, Xia (China University of Petroleum (East China)) | Huang, ZhaoQin (Heriot-Watt University) | Yao, Jun (China University of Petroleum (East China)) | Li, Yang (China University of Petroleum (East China)) | Fan, Dongyan (Sinopec) | Sun, Hai (China University of Petroleum (East China)) | Zhang, Kai (China University of Petroleum (East China))
After hydraulic fracturing, a shale reservoir usually has multiscale fractures and becomes more stress-sensitive. In this work, an adaptive hybrid model is proposed to simulate hydromechanical coupling processes in such fractured-shale reservoirs during the production period (i.e., the hydraulic-fracturing process is not considered and cannot be simulated). In our hybrid model, the single-porosity model is applied in the region outside the stimulated reservoir volume (SRV), and the matrix and natural/induced fractures in the SRV region are modeled using a double-porosity model that can accurately simulate the matrix/fracture fluid exchange during the entire transient period. Meanwhile, the fluid flow in hydraulic fractures is modeled explicitly with the embedded-discrete-fracture model (EDFM), and a stabilized extended-finite-element-method (XFEM) formulation using the polynomial-pressure-projection (PPP) technique is applied to simulate mechanical processes. The developed stabilized XFEM formulation can avoid the displacement oscillation on hydraulic-fracture interfaces. Then a modified fixed-stress sequential-implicit method is applied to solve the hybrid model, in which mixed-space discretization [i.e., finite-volume method (FVM) for flow process and stabilized XFEM for geomechanics] is used. The robustness of the proposed model is demonstrated through several numerical examples. In conclusion, several key factors for gas exploitation are investigated, such as adsorption, Klinkenberg effect, capillary pressure, and fracture deformation. In this study, all the numerical examples are 2D, and the gravity effect is neglected in these simulations. In addition, we assume there is no oil phase in the shale reservoirs, thus the gas/water two-phase model is used to simulate the flow in these reservoirs.
Zhao, Chong (China University of Petroleum (East China)) | Yu, Guijie (China University of Petroleum (East China)) | Chi, Jianwei (China University of Petroleum (East China)) | Zhang, Jiaxing (China University of Petroleum (East China)) | Guo, Zhuang (China University of Petroleum (East China))
Chong Zhao, Guijie Yu, Jianwei Chi, Jiaxing Zhang, and Zhuang Guo, China University of Petroleum (East China) Summary Coiled tubing is continuous thin-walled steel tubing several thousands of meters in length without screwed connections. Cyclic plasticbending deformation occurs during tubing spooling on the reel and when passing through the gooseneck arc guide. The coupling effect of cyclic plastic bending and internal pressure causes coiled-tubing diametral growth and wall thinning (referred to as ratcheting). This paper presents a numerical algorithm to calculate the deformations of the diameter and wall thickness on the basis of the incremental plasticity theory and the principle of virtual work. It is shown that predictions with the algorithm correlate well with experimental results. Introduction Coiled tubing originated from submarine pipelines during the Second World War.
Wang, Zhiyuan (China University of Petroleum (East China)) | Zhao, Yang (China University of Petroleum (East China)) | Zhang, Jianbo (China University of Petroleum (East China)) | Wang, Xuerui (China University of Petroleum (East China)) | Yu, Jing (China University of Petroleum (East China)) | Sun, Baojiang (China University of Petroleum (East China))
Hydrate-associated problems pose a key concern to the oil and gas industry when moving toward deeper-offshore reservoir development. A better understanding of hydrate-blockage-development behavior can help flow-assurance engineers develop more-economical and environmentally friendly hydrate-management strategies for deepwater operations. In this work, a model is proposed to describe the hydrate-blockage-formation behavior in testing tubing during deepwater-gas-well testing. The reliability of the model is verified with drillstem-testing (DST) data. Case studies are performed with the proposed model. They indicate that hydrates form and deposit on the tubing walls, creating a continuously growing hydrate layer, which narrows the tubing, increases the pressure drop, and finally results in conduit blockage. The hydrate-layer thickness is nonuniform. At some places, the hydrate layer grows more quickly, and this is the high-blockage-risk region (HBRR). The HBRR is not located where the lowest ambient temperature is encountered, but rather at the position where maximum subcooling of the produced gas is presented. As an example case—a deepwater gas well with a water depth of 1565 m and a gas-production rate of 45 × 104 m3/d—the hydrate blockage first forms at the depth of 150 m. In the section with a depth from 50 to 350 m, hydrates deposit more rapidly and this is the HBRR. As the water depth increases and/or the gas-flow rate decreases, the HBRR becomes deeper. Inhibitors can delay the occurrence of hydrate blockage. The hydrate problems can be handled with a smaller amount of inhibitors during deepwater well-testing operations. This work provides new insights for engineers to develop a new-generation flow-assurance technique to handle hydrate-associated problems during deepwater operations.
Liu, Yongge (China University of Petroleum (East China)) | Hou, Jian (China University of Petroleum (East China)) | Liu, Lingling (China University of Petroleum (East China)) | Zhou, Kang (China University of Petroleum (East China)) | Zhang, Yanhui (Tianjin Bohai Oilfield Institute) | Dai, Tao (Sinopec Shengli Oilfield Company) | Guo, Lanlei (Sinopec Shengli Oilfield Company) | Cao, Weidong (Sinopec Shengli Oilfield Company)
Reliable relative permeability curves of polymer flooding are of great importance to the history matching, production prediction, and design of the injection and production plan. Currently, the relative permeability curves of polymer flooding are obtained mainly by the steady-state, nonsteady-state, and pore-network methods. However, the steady-state method is extremely time-consuming and sometimes produces huge errors, while the nonsteady-state method suffers from its excessive assumptions and is incapable of capturing the effects of diffusion and adsorption. As for the pore-network method, its scale is very small, which leads to great size differences with the real core sample or the field. In this paper, an inversion method of relative permeability curves in polymer flooding is proposed by combining the polymer-flooding numerical-simulation model and the Levenberg-Marquardt (LM) algorithm. Because the polymer-flooding numerical-simulation model by far offers the most-complete characterization of the flowing mechanisms of polymer, the proposed method is able to capture the effects of polymer viscosity, residual resistance, diffusion, and adsorption on the relative permeability. The inversion method was then validated and applied to calculate the relative permeability curve from the experimental data of polymer flooding. Finally, the effects of the influencing factors on the inversion error were analyzed, through which the inversion-error-prediction model of the relative permeability curve was built by means of multivariable nonlinear regression. The results show that the water relative permeability in polymer flooding is still far less than that in waterflooding, although the residual resistance of the polymer has been considered in the numerical-simulation model. Moreover, the accuracy of the polymer parameters has great effect on that of the inversed relative permeability curve, and errors do occur in the inversed water relative permeability curve—the measurements of the polymer solution viscosity, residual resistance factor, inaccessible pore-volume (PV) fraction, or maximum adsorption concentration have errors.
Yang, Liu (Institute of Mechanics) | Shi, Xian (China University of Petroleum (East China)) | Zhang, Kunheng (China University of Petroleum (East China)) | Ge, Hongkui (China University of Petroleum (East China)) | Gao, Jian (Research Institute of Petroleum Exploration and Development) | Tan, Xiqun (Research Institute of Petroleum Exploration and Development) | Xu, Peng (Research Institute of Petroleum Exploration and Development) | Li, Lingdong (Research Institute of Petroleum Exploration and Development)
ABSTRACT: The fact that salt ions in shale pores diffuse into fracturing fluids is key factor to lead to recovered water with high salinity. In this paper, the authors conduct the test of mineral composition and SEM to understand the reservoir characteristics. The diffusion experiments are conducted on crushed samples, and a new method is proposed to differentiate between matrix and microfractures by using diffusion data. A large amount of salt ions exit in shale pores and can diffuse into fracturing fluids after fracturing operations. To a great extent, ion diffusion rate is determined by the development of microfractures. The crushed samples with smaller grain diameter contain have lower diffusion rate due to the low probability of microfractures development. When the grain diameter is lower than critical value, the crushed samples cannot contain microfractures. As for Longmaxi formation sample, the fracture-matrix boundary is about 80mesh.The research contributes to understanding the reservoir characteristics and salinity profiles of gas shale.
The field observations show that the salinity of recovered water is generally high. What’s more, the salinity increases continuously over time and even exceeds 10%. It should be noted that the salinity of slick water is about 0.1%. The researchers tend to attribute this observation to the salt ions diffusion into fracturing fluids (Wang et al., 2016).
The salt ions concentration and type in recovered water can act as the indicator to evaluate the development of fracture network. Unlike primary fractures, the secondary fractures are induced fractures that are covered by connate water film. The connate water film can mixes easily with fracturing fluids to increase the salinity of fracturing fluids (Woodroof et al., 2003). The secondary fractures with smaller aperture size tend to forms high exposure area that can enhance the ion diffusion capacity. In addition, the ion type in secondary fractures is different from that in primary fractures (Gdanski et al., 2007). The study found that Ba2+ exits in secondary fractures and the development of microfractures are evaluated based on the concentration of Ba2+ (Agrawal and Sharma, 2013).
Yang, Liu (China University of Petroleum (Beijing)) | Shi, Xian (China University of Petroleum (East China)) | Zhang, Kunheng (China University of Petroleum (East China)) | Ge, Hongkui (China University of Petroleum (East China)) | Gao, Jian (Research Institute of Petroleum Exploration and Development) | Tan, Xiqun (Research Institute of Petroleum Exploration and Development) | Xu, Peng (Research Institute of Petroleum Exploration and Development) | Li, Lingdong (Research Institute of Petroleum Exploration and Development)
ABSTRACT: Field observations indicate that larger than 70% of injected water cannot be recovered due to fracturing fluids imbibition during shut-in periods. However, the effects of imbibition on fracture conductivity are still unclear. In this paper, the fracture conductivity and imbibition experiments are conducted, and the correlativity between fracturing fluid imbibition and fracture conductivity damage is analyzed to explore the micro mechanism. The study finds out that fracturing fluid imbibition can obviously reduce fracture conductivity, and the conductivity damage degree of shale is much higher than that of conventional reservoir. After fracturing fluid entering shale, the interaction between shale and fracturing fluids is so strong as to cause the strength weakness and creep aggravation, which results in proppant embedment and fracture conductivity reduction. The interaction strength is not related to imbibition rate, but it is positively correlated with driving force coefficient. The research is significant for a deep recognition on interaction between fracturing fluid and shale.
Multistage fracturing is the most important technology to form massive complicated fracture network in shale reservoirs and achieve efficient exploitation of shale gas. However, the efficient exploitation not only depends on the fracture network, but also needs to keep sufficient conductivity of artificial fracture network (Novlesky et al., 2011). The phenomena that the proppant is seriously imbedded into fracture surface can obviously reduce the artificial fracture conductivity and the shale gas production (Pritz et al., 2011).
The fracture conductivity has received Considerable attention. However, there are few researches on the influences of fracturing fluid imbibition on fracture conductivity. Field observations indicate that more than 70% of fracturing fluid are detained in shale formation (Makhanov et al., 2014). It is generally recognized that the fracturing fluids imbibition into matrix pores is the key factor to result in low flowback efficiency. To a large extent, the interaction between fracturing fluid and shale is caused by imbibition, which both reduces the shale strength and proppant embedment (Zhou et al., 2016; Zhang et al., 2015).
Gao, Yonghai (China University of Petroleum (East China)) | Sun, Baojiang (China University of Petroleum (East China)) | Xu, Boyue (University of Oklahoma) | Wu, Xingru (University of Oklahoma) | Chen, Ye (China University of Petroleum (East China)) | Zhao, Xinxin (China University of Petroleum (East China)) | Chen, Litao (China University of Petroleum (East China))
On the basis of the wellbore and reservoir heat-transfer process during deepwater drilling, a heat-transfer model between wellbore and formation is built up for two different conditions: without riser and with riser. Wellbore and formation temperature distributions under different drilling-fluid-injection temperatures, flow rates, circulating times, and drilling depths are simulated by use of this model. Taking the hydrate-phase equilibrium into consideration, a possible region of hydrate-formation dissociation is analyzed, and effective methods are proposed to control the hydrate dissociation. The results indicate that, during shallow formation drilling, the increase of drilling-fluid flow rate will cause the wellbore temperature to rise, but below the hydrate-dissociation temperature in the whole process; during deep-formation drilling, drilling fluid is heated, and the heat is transferred from the deeper formation to the shallower formation through fluid circulation. Thus, the hydrate-reservoir temperature increases gradually along the wellbore radial direction. Hydrates will dissociate after the hydrate equilibrium temperature is reached; this may cause wellbore collapse or methane leak from the reservoir and result in disaster. To control hydrate dissociation during deepwater drilling, attention should be paid to the period of deep-formation drilling. Sensitivity studies indicate that the risk of hydrate dissociation rises as the drilling-fluid-injection temperature, flow rate, and circulating time increase.
Zhang, Feng (China University of Petroleum (East China)) | Tian, Lili (China University of Petroleum (East China)) | Liu, Juntao (China University of Petroleum (East China)) | Zhang, Quanying (China University of Petroleum (East China)) | Wang, Xinguang (China University of Petroleum (East China)) | Chen, Qian (China University of Petroleum (East China))
In the exploration of shale gas reservoir, the evaluation parameters such as lithology and gas content has the great significant for search of "sweet spot". This article introduces a multi-detectors pulsed neutron logging technology used for determining formation gas saturation and elemental concentration. The response of thermal neutron and gamma count ratio to gas saturation and gamma specturm to elemental concentration under borehole condition was simulated by using Monte Carlo method. A controlled neutron element tool (CNET) based on D-T neutron generator, two He-3 tubes and a LaBr3 detector was developed. This new logging technology was applied in Xinjiang oil field and the elemental interpretation results is consistent with the core analysis result.
Presentation Date: Thursday, October 20, 2016
Start Time: 10:10:00 AM
Presentation Type: ORAL