Lin, Ran (Southwest Petroleum University) | Ren, Lan (Southwest Petroleum University) | Zhao, Jinzhou (Southwest Petroleum University) | Tao, Yongfu (Exploration and Development Research Institute, Yumen Oilfield Company) | Tan, Xiucheng (Southwest Petroleum University) | Zhao, Jiangyu (Southwest Petroleum University)
Multi-stage & multi-cluster fracturing in horizontal well drilling is the core technology in for commercial exploitation of shale gas resevoir. According to vast field data, there is remarkable positive correlation relationship between stimulated reservoir volume (SRV) and shale gas production. Hence, estimating the SRV is essential for both pre-fracturing design and post-fracturing evaluation. However, the forming process of SRV involves with many complex mechanisms, making it is difficult to be simulated.
In this paper, we establish a mathematical model to estimate the SRV by simulating multiple hydraulic fractures propagate, formation stress change and reservoir pressure rise; consequently, the stress and pressure change might make natural fractures occur tensile failure or shear failure, generating a high-conductivity zone (i.e., SRV) in the shale reservoir.
To solve the model, displacement discontinuity method (DDM) is applied to simulate non-planar propagation of multiple hydraulic fractures and calculate formation stress change. Finite difference method (FDM) is used to compute reservoir pressure rise. The natural fractures failure state is determined by tensor formulae derived from Warpinski's failure theory. This SRV estimation method involves a variety of complex but crucial physical mechanisms during shale fracturing process which include unequal flow-rate distribution in different hydraulic fractures, non-planar hydraulic fractures propagation under stress interference, reservoir permeability increases with SRV expanding, two types of natural fracture failure and so on.
A field case study was performed to show the dynamic processes of hydraulic fractures propagation, reservoir permeability increase, and the SRV expansion during shale gas fracturing. Then we compared the simulation results with analytical solution, published papers and on-site microseismic monitoring data to verify our model. Finally, the influence of geological condition and engineering parameters on SRV was investigated by sensitivity analysis.
Zeng, Jie (The University of Western Australia) | Li, Wai (The University of Western Australia) | Liu, Jishan (The University of Western Australia) | Leong, Yee-Kwong (The University of Western Australia) | Elsworth, Derek (The Pennsylvania State University) | Tian, Jianwei (The University of Western Australia) | Guo, Jianchun (Southwest Petroleum University)
After performing hydraulic fracturing treatments in shale reservoirs, the hydraulic fractures and their adjacent reservoir rocks can be damaged. Typically, the following fracture damage scenarios may occur: (1) choked fractures with near-wellbore damage; (2) partially propped fractures with unpropped or poorly propped sections within the fractures; (3) fracture face damage; and (4) multiple damage cases. The basic equations of fracture skin factors, which are widely used to depict fracture damage, are derived under steady-state conditions. They are not accurate when the damaged length is relatively long and are not applicable for multiple fracture damage and partially propped fractures. In this paper, a new composite linear flow model is established considering all above-mentioned fracture damage mechanisms, complex gas transport mechanisms, and the stimulated reservoir volume (SRV) of shale gas reservoirs.
The matrix model is modified from de Swaan-O's spherical element model considering the slip flow, Knudsen diffusion, surface diffusion, and desorption. Natural fractures are idealized as a thin layer that evenly covers the matrix. The reservoir-fracture flow model is extended from the seven-region linear flow model with four additional sub-regions to handle single and multiple fracture damage mechanisms. Specifically, the inner reservoir region near the primary hydraulic fracture is treated as the SRV where the secondary fracture permeability is higher than that of other unstimulated dual-porosity regions and obeys a power-law decreasing trend due to the attenuate stimulation intensity within the SRV. The flows in different regions are coupled through flux and pressure continuity conditions at their interfaces.
This model is validated by matching with the Marcellus Shale production data. And the degraded model's calculation matches well with that of the seven-region linear flow model validated by KAPPA software. Type curves with five typical flow regimes are generated and sensitivity analyses are conducted. Results indicate that the presence of the SRV diminishes pressure and derivative values in certain flow regimes depending on the SRV properties. Fracture face damage, choked fracture damage, and partially propped fractures all control specific flow regimes but the fracture face damage shows the smallest influence, only dominating the late fracture linear flow regime and the matrix-fracture transient regime. In the multiple fracture damage case, some typical flow regimes can be easily identified except the partially propped fractures. The field application example further ensures the applicability in dealing with real field data.
Wei, Bing (Southwest Petroleum University) | Wang, Yuanyuan (Southwest Petroleum University) | Chen, Shengen (Southwest Petroleum University) | Mao, Runxue (Southwest Petroleum University) | Ning, Jian (Southwest Petroleum University) | Wang, Wanlu (Southwest Petroleum University)
Foams were introduced to enhanced oil recovery (EOR) for the purpose of improving sweep efficiency via mitigating gas breakthrough. In prior works, well-defined nanocellulose-based nanofluids, which can well stabilize foam film as a green alternative to reduce the environmental impact, were successfully prepared in our group. However, due to the costly manufacturing process, its field scale application is restricted. In order to further simply the manufacturing process and minimize the cost, in this study, we proposed another family of functional nanocellulose, in which lignin fraction was remained as well as carboxyl groups. The primary objective of the present work is to investigate the synergism between the lignin-nanocellulose (L-NC) and surfactant in foam film stabilization. Particular attention was placed on the relation between the chemical composition of L-NC and its stabilizing effect. Direct measurements of foamability, drainage half-time, foam morphology, foam decay, etc., were performed. The results showed that after the contents of lignin and carboxyl group were well tailored, the resultant L-NC can significantly improve the stability of foam either in the absence or presence of crude oil. The flooding dynamics observed in core plugs indicated that the L-NC stabilized foams could properly migrate in porous media and generated larger flow resistance accross the cores than surfactant-only foam.
Ma, Yingxian (Southwest Petroleum University) | Ma, Leyao (Southwest Petroleum University) | Guo, Jianchun (Southwest Petroleum University) | Lai, Jie (Southwest Petroleum University) | Zhou, Han (Downhole Service Company, CNPC Chuanqing Drilling Engineering Company Limited) | Li, Jia (Downhole Service Company, CNPC Chuanqing Drilling Engineering Company Limited)
We prepared physically linked allyl alcohol polymer/polyacrylamide double network hydrogels via onepot strategy. These double network supermolecular fracturing fluids were found to have a better viscosity at high temperature compared to the conventional polyacrylamide systems. After testing with a rheometer, the fluid viscosity could stay 320 mPa s at 150 C under 170/s shear rate. With NMR and FT-IR results' help, we determined that abundant polar groups of chains were still free, which could complex ions to keep, even enhance the chain stability. Thus, these double network systems showed excellent salt resistance with the non-covalent interactions and physical entanglements, and the viscosity of the allyl alcohol polymer/ polyacrylamide system did not drop but increase. The viscosity in high salinity could increase nearly 40 % compared with the initial situation. Overall, the novel fracturing fluid system could maintain a high viscosity and better rheological properties under high salinity and showed excellent high-temperature stability, to make up the lack of fracturing fluid at this stage. It is expected to potential fluid issues caused by low water quality and harsh downhole temperatures were resolved or mitigated.
Zhao, Tianhong (Southwest Petroleum University) | Chen, Ying (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University) | Wei, Bing (Southwest Petroleum University) | He, Yi (Southwest Petroleum University) | Zhang, Yiwen (Southwest Petroleum University)
Nanofluid flooding injection technique whereby nanomaterial or nanocomposite fluids for enhanced oil recovery (EOR) have garnered attention. Although a variety of nanomaterials have been used as EOR agents, there are still some defects such as toxicity, high cost and low-efficiency displacement, which restricted the further application of these nanoparticles. Considering these problems mentioned above, it is necessary to search for another nanomaterial which is inexpensive, environmentally friendly and results in high efficiency displacement.
In this work, a natural aluminosilicate nanomaterial halloysite nanotubes (HNTs) was focused. As a new kind of nanomaterial, the effectiveness of halloysite nanotubes (HNTs) in enhancing oil recovery has not been reported yet and it is still in its infancy. The use of pristine halloysite nanotube is at risk of blocking the rock pore channel due to the intrinsic drawback of aggregation, which may be the reason. To prolong the suspension time of fluids during seeping into the small pores of low permeable reservoirs, we have proposed the HNTs/SiO2 nanocomposites. The effect of HNTs/SiO2 nanocomposites-based nanofluids on wettability alteration and oil displacement efficiency was experimentally studied. The HNTs/SiO2 nanocomposites have been prepared by sol-gel method and characterized with X-ray (XRD), Transmission Electron Microscopy (TEM) and Thermal Gravimetric Analysis (TGA). The effect of the chemical modification on the suspension stability was investigated by measuring Zeta potential and dynamic laser scattering. Results show that the HNTs/SiO2 nanofluid could significantly change the water wettability from oil-wet to water-wet condition and enhance oil production. The optimal concentration of HNTs/SiO2 was 500 ppm, which corresponded to the highest ultimate oil recovery of 39%.
Yang, Ruoyu (Southwest Petroleum University) | Guo, Jianchun (Southwest Petroleum University) | Zhang, Tao (Southwest Petroleum University) | Zhang, Xudong (Southwest Petroleum University) | Ma, Jian (Sinopec) | Li, Yang (Southwest Petroleum University)
Slick-water fracturing treatment is one of the most effective method to develop shale reservoir, which creates complex fracture system by connecting the pre-existing natural fractures. However, the proppant transport and placement behavior is quite different from that in conventional bi-wing fractures due to the low viscosity fluid system and intersections between fractures. The goal of this work is to simulate and understand the characteristic of proppant transport behavior in Complex Fractures network.
A Eulerian multiphase model is introduced to simulate the transport and settling behavior in the hydraulic fracture network, which takes turbulence effects and friction stress between the proppant particles into consideration and fully couple the fluid phase with particle phase. Simulation work was conducted to investigate the control mechanism and influencing factors for proppant transportation from main fracture into secondary and tertiary fractures.
The simulation results indicate that a small proppant dune quickly forms in the main fractures first, and almost no proppant enters the lower grade fracture until the proppant dune in the intersection reaches a specific height. With continuous injection of slurry fluid, majority of the proppant enters in the lower grade fracture which is controlled by gravity rolling from the dune in main fractures and fluid drag force, and the proppant settles quickly and gradually reach their own equilibrium height. Parametric study shows that smaller proppant density and particle size can also help proppant transport into secondary fractures and form a higher equilibrium height dune, resulting in larger effective propped area. Moreover, when the lower grade fracture is closer to the inlet entrance, the proppant is more likely to transport in, and the height of sand dunes formed in the fractures is higher.
The proppant transport process in complex fracture systems is simulated by Eulerian Multiphase Model in this paper. This study extends the understanding of the process and mechanism of proppant transport in complex fracture system and controlling factors, which helps optimize hydraulic fracturing design in shale formation.
Lu, Cong (Southwest Petroleum University) | Li, Junfeng (Southwest Petroleum University) | Luo, Yang (SINOPEC Southwest Oil & Gas field Company) | Chen, Chi (Southwest Petroleum University) | Xiao, Yongjun (Sichuan Changning Gas Development Co. Ltd) | Liu, Wang (Sichuan Changning Gas Development Co. Ltd) | Lu, Hongguang (Huayou Group Company Oilfied Chemistry Company of Southwest) | Guo, Jianchun (Southwest Petroleum University)
Temporary plugging during fracturing operation has become an efficient method to create complex fracture network in tight reservoirs with natural fractures. Accurate prediction of network propagation process plays a critical role in the plugging and fracturing parameters optimization. In this paper, the interaction between one single hydraulic fracture within temporary plugging segment and multiple natural fractures was simulated using a complex fracture development model. A new opening criterion for NF penetrated by non-orthogonal HF already was implemented to identify the dominate propagation direction of HF under plugging condition. Fracture displacements and induced stress field were determined by the three dimensional displacement discontinuity method, and the Gauss-Jordan and Levenberg-Marquardt methods were combined to handle the coupling between rock mechanics and fluid flow numerically. Numerical results demonstrate that the opening and development of NF are mainly dominated by its approaching angle and relative location. For a certain NF crossed by HF within plugging segment, HF tends to propagate along the relative upper part when the approaching angle is less than 90°, otherwise the lower part will be easier to open. The farther interaction position is away from HF tip, the easier NF with approaching angle less than 30° or larger than 150° can be open, and the outcome will be opposite if the approaching angle is larger than 45° or less than 135°. Higher approaching angle and plugging strength is necessary for expanding the position scope of NF that can be opened around HF. Under the impact of plugging, fluid pressure in HF plummets at the beginning of NF opening and keeps decreasing until NF extending for a certain distance or encountering secondary NFs. Fluid pressure drop occurs mainly in the unturned NF, together with the width of unturned NF is significantly lower than that of turned NF and HF. Sensitivity analysis shows that the main factors, such as geometry, aperture profile, and fluid pressure distribution, affecting the network progress under temporary plugging condition are the horizontal differential stress, NF position, approaching angle, plugging time, and plugging segment length. The simulation results provide critical insight into complex fracture propagation progress under temporary plugging condition, which should serve as guidelines for welling choosing and plugging optimization in temporary plugging fracturing.
Li, Nianyin (Southwest Petroleum University) | Kang, Jia (Southwest Petroleum University) | Zhang, Qian (Southwest Petroleum University, Research Institute of Natural Gas Technology, PetroChina Southwest Oil & Gas field Company) | Wu, Yu (Southwest Petroleum University) | Zhang, Haotian (Southwest Petroleum University)
Considering characteristics of complex carbonate reservoirs (e.g., high depth, high temperature, and fracture cave development), this paper simulates expansion of the acid wormhole when combining diverting acid and a solid diverting agent for acid fracturing. Using the theory of reaction kinetics, tests of diverting acid reaction kinetics, and flow reaction experiments on the long core and parallel core, this paper presents tests of the acid–rock reaction for a mathematical model of acid diversion. On the basis of a rheological behavior test of diverting acid, we studied the influences of Ca2+ concentration, pH, fiber concentration, and temperature on acid system viscosity. Then, we established a mathematical model of changes in diverting acid viscosity under a multi-factor cooperative control mechanism. On the basis of the kriging method, we established a three-dimensional (3D) geological model involving a random normal distribution and spatial correlation of multi-fracture and pore-permeability properties. We used four models (acid rock reaction rate, viscosity change, 3D acid wormhole expansion, and fluid–solid coupling) of a complex system to study dynamic cooperation characterization of diverting acid and a solid diverting agent under multiple factors. Simulation results show that the temporary plugging of acid and expansion of acid wormholes are mutually restricted. The solid diverting agent blocked the fracture, and a dense filter cake formed at the start of the fracture; thus, the physical flow direction of diverting acid changed, the acid wormhole length increased, and filtration of diverting acid declined to improve the acid's effect. Diverting acid and solid diverting agent work more effectively together. This paper is novel because we consider the respective influences of Ca2+ concentration, pH, flow rate, diverting acid rheological properties, injection parameters, and solid diverting agent concentration on the synergistic steering of steering acid and a solid diverting agent. We then establish a mathematical model to reflect complex stratigraphic conditions and objectively describe the acid flow reaction. We also innovatively solve the problem of predicting acid wormhole expansion given complex fractures and uneven pore distribution. Findings provide a theoretical basis and technical support for the application of acid fracturing in complex carbonate reservoirs.
Jia, Wenlong (Southwest Petroleum University) | Yang, Fan (Southwest Petroleum University) | Mu, JunCheng (Kongsberg Gigital AS) | Cheng, Tingting (Southwest Petroleum University) | Li, Changjun (Southwest Petroleum University) | Zhang, Qi (Deepwater Engineering & Construction Center CNOOC China Ltd.-Shenzhen Branch)
Co-existence of gas, water and glycol is commonly in produced fluids of high-pressure gas wells due to formation water production and hydrate inhibitor injection. The interaction between the polar water and glycol molecules can affect the phase behavior and subsequent temperature change during gas flowing through chokes at wellheads. This paper presents an isenthalpic flash method based on the cubic-plus-association equation of state (CPA EOS) to calculate the temperature at the downstream of the choke. In comparison with the traditional isenthalpic flash algorithm, this new method accounts for the self- and cross-association between polar water and glycol molecules, yielding more accurate enthalpy calculation results for fluid containing water and glycol as well as choke temperatures. The proposed model is validated with field test data. Results demonstrate that the average absolute deviations between the measured and calculated temperatures at downstream of chokes based on the proposed method are less than 1.6°C even for vapor-liquid-aqueous three-phase mixtures at pressures up to 100 MPa. Results yield from the proposed method are more accurate than those calculated from the SRK EOS combining with the Peneloux volume shift method and the Huron-Vidal mixing rule.
Li, Yang (Southwest Petroleum University) | Guo, Jianchun (Southwest Petroleum University) | Wang, Shibin (Southwest Petroleum University) | Yang, Ruoyu (Southwest Petroleum University) | Lu, Qianli (Southwest Petroleum University)
This study is to demonstrate the application potential of silica nanoparticles (SNP) in adsorption-entanglement of the fracturing fluid and the adsorption-blocking in the tight reservoir caused by hydroxypropyl guar gum (HPG).
An amount of fracturing fluid is required in tight reservoir stimulation. It results in so much HPG to be injected into the tight reservoir. The HPG will be adsorbed in the sandstone and decrease the permeability of the reservoir. For improving the production the tight gas well after being stimulated, SNP were added to the HPG fracturing fluid to reduce the adsorption capacity of HPG molecules on rock surface, increase the flow space of core and reduce the damage of HPG fracturing fluid to reservoir.
The results indicate that the SNP can decrease the adsorption capacity in sandstone porous media by breaking the hydrogen bonding and recover the permeability effectively In conclusion, it is believed that the SNP competitive adsorption seems to be a new approach for remediation of the permeability damage by HPG fracturing fluid and has great potential in oilfield application. The understandings of this paper was meaningful to grasp and utilize the behaviors of tight reservoir adsorption properties, particular in the optimizing of HPG fracturing fluid and improving construction parameters during hydraulic fracturing of tight gas wells.