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.
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.
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, 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.
Lai, Jie (Southwest Petroleum University) | Guo, Jianchun (Southwest Petroleum University) | Chen, Chi (Southwest Petroleum University) | Wu, Kaidi (Southwest Petroleum University) | Ma, Huiyun (Petro China Southwest Oil & Gasfield Company) | Zhou, Changlin (Petro China Southwest Oil & Gasfield Company) | Wang, Shibin (Southwest Petroleum University) | Ren, Jichuan (Southwest Petroleum University) | Wang, Zhi (Southwest Petroleum University)
As the most commonly used technology to exploit tight dolomite reservoirs, acid fracturing usually begins with injecting pad fluid to create rough-surface fractures, followed by pumping acid to form non-uniform etching on fracture surfaces. Thus, the etching pattern and acid fracture conductivity depend largely on initial character of rough-surface fractures. In this work, experiments were conducted to examine the effects of initial roughness and mechanical property of fracture surface on acid fracture conductivity.
Eight artificially split core samples were collected from tight dolomite outcrops and classified into three categories based on the surface topography and splitting force curve. Rough fracture surfaces were scanned utilizing the 3D laser scanner. Then, dynamic acid etching tests were conducted, varying the acid flow rate and acid-rock contact time. Besides, the roughness of fracture surfaces were measured utilizing the 3D laser scanner again. After that, acid fracture conductivity was determined. The effects of acid flow rate, acid-rock contact time, fracture surface topography and mechanical property on acid etching and acid fracture conductivity were discussed.
The experimental results demonstrated that the initial fracture surface topography and acid flow rate jointly controlled the acid etching pattern and the resulting acid fracture surface topography. The orientation of the fractures distributed on the fracture surface had significant effects on the acid fracture conductivity. Dissolved mass increased with longer acid-rock contact time. Longer acid-rock contact time brought higher acid fracture conductivity under low closure stress, while shorter contact time sustained higher acid fracture conductivity under high closure stress. Higher maximum splitting force referred to higher mechanical property, and more breaking stages referred to more microfractures developed. Rock samples with higher maximum splitting force and only one breaking stage exhibited higher acid fracture conductivity.
This paper provides a systematic method to study the effects of initial roughness and mechanical property of fracture surfaces on acid fracture conductivity. Compared with the results based on smooth-surface fracture, the experimental results based on rough-surface fracture can guide acid fracturing design and optimization in a more accurate way. Accordingly, a cost-effective stimulation outcome can be expected.
Xiao, Yong (China Zhenhua Oil Co., Ltd) | Wang, Hehua (China Zhenhua Oil Co., Ltd) | Guo, Jianchun (State Key Laboratory on Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Lu, Lize (China Zhenhua Oil Co., Ltd) | Cheng, Yi (Chengdu Northern Petroleum Exploration and Development Technology Co. Ltd.) | Chen, Mengting (Borehole Operation Branch Office of Sinopec Southwest Petroleum Engineering Co., Ltd.) | Fan, Fengying (Chengdu Northern Petroleum Exploration and Development Technology Co. Ltd.) | Xue, Heng (China Zhenhua Oil Co., Ltd)
The low permeability reservoir of Ahdeb field discovered in the 80's, has more than 250 active wells with low initial production and rapid decline compared to other reservoirs. Matrix acidizing is the main stimulation method to recover and enhance production performance in Ahdeb oilfield, but short-distance deblocking acidizing can't communicate with the deep reservoir, and it is impossible to expand the effective seepage radius. Therefore, High reservoir heterogeneity, low permeability, poor pore pressure necessitates the move from conventional matrix stimulation to acid fracturing technology targeting better fracture conductivity and deep penetration for effective productivity and recovery enhancement.
The acid fracturing feasibility research shows that the interlayer characteristics, lithologic barrier, stress barrier and oil-water relationship of the low permeability reservoirs are favorable for fracture initiation, expansion and geometry control. Acid fracturing is one of the best ways to stimulate the potential production in low-permeability reservoirs of the Ahdeb oilfield. The acid fracturing optimization includes fracture conductivity, fluid system and fracturing parameters. Pad acid fracturing and gel acid with multi-stage alternating and closed acid fracturing are the suitable technologies for low permeability reservoir stimulation.
An experiment well has been simulated and designed, and the expected production increase is 1.5 times. Base on this paper's research, a wide-scale development strategy will be planned, and many wells will be stimulated for increase the production performance.
Lu, Cong (Southwest Petroleum University) | Li, Zhili (Southwest Petroleum University) | Zheng, Yunchuan (CNPC Chuanqing Drilling Engineering Co., Ltd.) | Yin, Congbin (CNPC Chuanqing Drilling Engineering Co., Ltd.) | Yuan, Canming (CNPC Chuanqing Drilling Engineering Co., Ltd.) | Zhou, Yulong (SINOPEC Shengli Oilfield Luming Oil and Gas Exploration and Development Co., Ltd.) | Zhang, Tao (Southwest Petroleum University) | Guo, Jianchun (Southwest Petroleum University)
The pulse fracturing is widely used in unconventional reservoirs. It alternately pulse pumping the proppant slurry and clean fluid to form discontinuous placement proppant pillars in the artificial fractures and the pulse fracture conductivity is several orders of magnitude higher than conventional hydraulic fracture conductivity. However, the understanding of the deformation law of proppant pillar under the action of closure pressure and proppant normal stress is unclear, resulting in difficult to calculate the fracture conductivity and prefer proppant.
Firstly, replacement construction and experimental displacement by Renault Similarity Criteria, three typical proppant pillars placement structures are extracted through the large-scale visualized flat plate device. The Young's modulus of the proppant pillars are calculated in modified API conductivity cell. Secondly, proppant pillars are dispersed into particles by the Smooth Particle Method (SPH). Using the parameters obtain from the above experiments, fracture-proppant pillar contact models are established to simulate the deformation process of proppant pillar and get normal stress of proppant particles. Thirdly, extracting the shape of stabilized proppant pillars, establish the fracture-proppant pillar flow model, calculate the fracture conductivity in different closure pressure.
The simulation results show that as the closure pressure increases from 14MPa to 41MPa, the fracture width present an accelerated downward trend, The fracture width under the support of the initial radius of 9 mm proppant pillars are the largest, decreasing from 2.52mm to 1.72mm, the larger the radius of the proppant pillar, the greater the fracture width, the normal stress of three types of proppant pillar particles are both changed from 73MPa to 110MPa. The elliptical cylinder proppant pillar has the largest fracture conductivity. Its fracture conductivity is reduced from 12500D•cm to 3630D•cm. The larger the construction displacement and the pulse time of proppant slurry, the greater the fracture conductivity.
The model in this article can calculate the normal stress of proppant particle and fracture conductivity in different closure pressure, which can significantly guide the choice of construction parameters and the type of proppant.
Zeng, Fanhui (Southwest Petroleum University) | Peng, Fan (Southwest Petroleum University) | Guo, Jianchun (Southwest Petroleum University) | Rui, Zhenhua (Southwest Petroleum University and Massachusetts Institute of Technology) | Xiang, Jianhua (PetroChina Company Limited Southwest Oil and Gas Field Branch)
Microfractures are commonly observed in shale reservoirs. During the shale gas-production process, stress sensitivity induces a change in the width of the microfractures, which is a significant factor that affects shale gas mass transport. By using research methods based on desorption theory and elastic-plastic mechanics, a shale gas mass transport model that considers the dynamic variations in the microfracture width is established in this paper. This model comprehensively fuses the surface diffusion model, slip flow model, Knudsen diffusion model, and cubic grid model. The reliability of this model is verified using molecular simulations, which do not include surface diffusion. The shale gas is considered as pure methane. Then, the different contributions of the gas mass transport mechanisms to the total mass transport are discussed in detail. The results demonstrate the following findings: (1) The studied flows are well-simulated by the proposed model. (2) Stress sensitivity results in a decrease in gas mass transport when the formation pressure exceeds 3.4 MPa, and the minimum value is approximately 0.45 times smaller than that when the width change is not considered. Moreover, stress sensitivity results in an increase in gas mass transport when the formation pressure is lower than 3.4 MPa, and the maximum value is approximately 4.5 times higher than that when the width change is not considered. (3) Shale gas mass transport is positively associated with the Young’s modulus and Poisson’s ratio, whereas it is negatively associated with the microfracture compressibility. When the formation pressure is less than 4 MPa, shale gas transport is positively correlated with the desorption capacity, whereas when the formation pressure exceeds 4 MPa, the effect of different desorption capacities on gas transport is nearly consistent. (4) When the microfracture width is at nanoscale and the reservoir pressure is lower than 15 MPa, surface diffusion has an obvious effect on the shale gas mass transport process. When the contribution of surface diffusion to the total shale gas mass transport is relatively small, the contributions of slip flow and Knudsen flow to shale gas mass transport exhibit the trend of “shifting each other.” When the surface diffusion contribution is larger, a reduction in its contribution leads to simultaneous initial increases in the contributions of slip flow and Knudsen flow to shale gas mass transport, and then these flows begin “shifting each other.”
Lai, Jie (Southwest Petroleum University) | Guo, Jianchun (Southwest Petroleum University) | Zhou, Hangyu (Southwest Petroleum University) | Wang, Shibin (Southwest Petroleum University) | Luo, Bo (Southwest Petroleum University) | Ren, Jichuan (Southwest Petroleum University) | Chen, Fuhu (SINOPEC North China Petroleum Bureau)
ABSTRACT: Due to low permeability, acid can hardly penetrate deep into the tight limestone, causing pore structure and mechanical property change on the surface of the rock. In this study, the porosity, permeability, and acoustic velocity of the tight limestone were first tested, followed by acid coreflood tests. Then, triaxial compression test and surface indentation hardness test were conducted. After mechanical tests, fragments of the broken core samples were collected to carry out SEM investigation, keeping the consistency of core samples. Experimental results indicated that the acid could not penetrate deep into the core with continuously high pumping pressure up to 8 MPa, showing that acid-rock reaction mainly occurred on the surface of the core. The fact that triaxial compressive strength after reaction had barely changed also confirmed that. However, there was an obvious reduction in Young’s modulus and surface indentation hardness, with the reduction extent jointly dominated by acid concentration and rock permeability. SEM images illustrated that there were many pores on the surface of the core after reaction. This study reflects the characteristics of pore structure and mechanical property change on the surface of the tight limestone, rather than the entire core sample, after acid-rock reaction.
Nowadays, carbonate reservoirs are playing an increasingly important role for oil and gas exploitation. Because of deep buried depth, low porosity and low permeability, carbonate formation stimulation works are encountered with brand new and abstruse difficulties, such as high fracturing pressure. To effectively fracture the carbonate formation, researchers proposed various methods like weighted fracturing fluid (Yuan et al., 2013, 2017), high-energy gas fracturing (Sun et al., 2010; Wu et al., 2011), perforation optimization (Zhao et al., 2017). Among various methods, acid pretreatment has obtained great success and expanded its use in sandstone and shale reservoirs (Tan et al., 2018).
For conventional carbonate reservoirs with moderate porosity and permeability, the acid can flow through the pore structure of core samples readily, and obvious changes in porosity, permeability and mechanical property can be observed (Zhou et al., 2007). However, with increasing buried depth, porosity and permeability decrease quickly. On this condition, acid can not penetrate deep into the rock matrix and mainly reacts with the rock on the fracture surface, causing influence on fracture conductivity (Nasr-El-Din et al., 2007; Gomaa and Nasr- El-Din, 2009). Thus, it is necessary to understand pore structure and mechanical property change on the surface of deep-buried carbonate after acid-rock reaction, as well as the effect of acid type, acid concentration, contact time, etc. (Shi et al., 2017; Feng and Gray, 2017).