Langfang Branch of Research Institute of Petroleum Exploration and Development

Langfang, China

Langfang Branch of Research Institute of Petroleum Exploration and Development

Langfang, China

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Ming H.,Langfang Branch of Research Institute of Petroleum Exploration and Development | Ming H.,China National Petroleum Corporation | Zhai W.,Langfang Branch of Research Institute of Petroleum Exploration and Development | Zhai W.,China National Petroleum Corporation | And 3 more authors.
Drilling Fluid and Completion Fluid | Year: 2016

FAD-120, a modified (through etherification) biopolymer is made to overcome conventional biopolymer's deficiency, such as high consumption and low temperature stability. FAD-120 is suitable for use in fracturing tight reservoirs, whose formation temperature is in the range of 70-130 ℃. FAD-120 is ready to dissolve in water, even in high salinity saltwater. FAD-120 solution has low friction coefficient, good sand-carrying capacity and low residue (hence low formation damage), and is environmentally friendly. Fracturing with FAD-120 is much easier to operate than guar gum. FAD-120 is also cheaper than guar gum, and can be used in water of different quality. In a field application in Block Chi-228 in Changqing, shallow underground water having salinity of 3, 334 mg/L was used to prepare the fracturing fluid; the maximum sand content was as high as 25%. In the same block, sand consumption in fracturing a single well is almost the same as guar gum fracturing fluid. The success of FAD-120 is of great significance in fracturing fluid preparation with water of different quality, reducing the cost of fracturing fluid, and in ensuring the operation of large-scale volumetric stimulation of reservoir. © 2016, North China Petroleum Administration Drilling Technology Research Institute. All right reserved.


Ji S.,Xi'an Shiyou University | Yang J.,Xi'an Shiyou University | Yang J.,Langfang Branch of Research Institute of Petroleum Exploration and Development | Li R.,Xi'an Shiyou University | And 2 more authors.
Drilling Fluid and Completion Fluid | Year: 2016

Supermolecules used in fracturing fluids form associative structures, making the gels of the fracturing fluids very difficult to break. Studies on the effects of several additives on the gel breaking performance of fracturing fluids at 90℃ were conducted. The fracturing fluids used have supermolecular associative structures in them, and the additives tested include organic solvents, peroxide, diesel oil, kerosene, alcohols and mixture of these additives. It is found that at 90℃, addition of 0.5% ethylene glycol monobutylether and 0.5% triethanolamine in a fracturing fluid reduces the viscosity of the fracturing fluid by 80 mPa·s and 77 mPa·s, respectively, and the minimum viscosity of the fracturing fluid maintains at 30 mPa·s. Addition of 0.1% sodium persulfate in a fracturing fluid reduces the viscosity of the fracturing fluid to 4.312 mPa·s in 120 min, showing remarkable potential in gel breaking. Addition of 0.6% diesel and 0.6% kerosene in a fracturing fluid, breaks the gel in 50 min and 40 min, respectively. Interaction between poly fatty alcohols and the association polymers will reduce the viscosity of the fracturing fluid; addition of 1.0% n-octanol reduces the viscosity of fracturing fluids containing supermolecular associative structure to 24 mPa·s. Mixture of chemicals can also reduce the time for gel breaking. For instance, a mixture of 0.03% FeSO4 and 0.1% ammonium persulfate reduces the time by 60 min, and so does the mixture of 0.05% FeS and 0.1% ammonium persulfate. Using the methods described above, gels of fracturing fluids containing supermolecular associative structures can be broken, with no intervention from crude oil. © 2016, The Editorial Board of Drilling Fluid & Completion Fluid. All right reserved.


Zhang H.,China University of Petroleum - Beijing | Wang Z.,China University of Petroleum - Beijing | Zheng Y.,China University of Geosciences | Zheng Y.,Langfang Branch of Research Institute of Petroleum Exploration and Development | And 2 more authors.
Safety Science | Year: 2012

To evaluate the effect of the long-term operation of a salt cavern in a given construction on rock deformation and its stability, tri-axial creep tests to the glauberite, anhydrite, and argillaceous rock salt are conducted, from which the creep curves as well as exponential functions of strain rate during the steady creep stage and creep constitutive equations of different rock salt in the experimental process derived are obtained. The study results show that: (i) Under the same deviatoric stress, the strain rate of argillaceous rock salt is lower than the glauberite and anhydrite, and the difference becomes larger with the increase of the deviatoric stress; (ii) The creep constitutive equations of different kinds of rock salt are in good agreement with the Burgers model, besides which the respective characteristics of these two creep models are compared. The change of creep parameters also illustrates the discrepancy of rock salt. The researching results can provide some references for long-term stability analysis of gas storage in salt caverns. © 2011 Elsevier Ltd.


Cheng W.,State Key Laboratory of Petroleum Resources and Prospecting | Jin Y.,State Key Laboratory of Petroleum Resources and Prospecting | Chen Y.,State Key Laboratory of Petroleum Resources and Prospecting | Zhang Y.,State Key Laboratory of Petroleum Resources and Prospecting | And 2 more authors.
ISRM International Symposium - 8th Asian Rock Mechanics Symposium, ARMS 2014 | Year: 2014

The complex interaction between hydraulic and natural fracture was believed to have a significant impact on hydraulic fracture complexity. Extensive theoretical and experimental works had proved this interaction was affected by several parameters, such as stress difference, approaching angle, frictional coefficient and fracturing parameters etc. However, only engineering parameters, such as pump displacement and viscosity of fracturing fluid, could be controlled by field engineers. How these two parameters affect the interaction remain poorly understood. In this study, a piece of white paper with the dimensions of 200 mm×150 mm×0.1 mm was spread to simulate a planar naturalfracture in the specimen. Two groups of fracturing tests were conducted under tri-axial stresses in large-sized fracturing system. In the first group, different pump displacements with the same viscosity of fracturing fluid were applied. In the second group, fracturing fluid with different viscosities was applied while pump displacement were strictly the same. Experimental results showed that hydraulic fracture can cross the natural fracture under large pump displacement and high viscosity. A critical pump displacement and a critical viscosity were observed respectively. Above this critical displacement or above this critical viscosity, hydraulic fracture can cross the natural fracture; below this critical displacement or below this critical viscosity, hydraulic fracture only propagates along the plane of the nature fracture to its ends rather than cross it. These two critical values can help field engineer design the fracturing parameters. © 2014 by Japanese Committee for Rock Mechanics.


Hou B.,State Key Laboratory of Petroleum Resources and Prospecting | Cheng W.,State Key Laboratory of Petroleum Resources and Prospecting | Jin Y.,State Key Laboratory of Petroleum Resources and Prospecting | Diao C.,State Key Laboratory of Petroleum Resources and Prospecting | And 2 more authors.
ISRM International Symposium - 8th Asian Rock Mechanics Symposium, ARMS 2014 | Year: 2014

Horizontal-well multi-stage fracturing was an effective stimulation technique, which was commonly used in unconventional reservoir. The complex interactions between multiple hydraulic fractures were believed to have a significant impact on fracture geometry inside the rock mass. Many theoretical models proposed to predict the hydraulic fracture geometry and stress interference in multi-stage fracturing had not been experimentally proved. In this study, a multi-stage fracturing test utilizing gal solution as fracturing fluid were conducted utilizing tri-axial fracturing system. Multi fractures were observed in a cubic rock sample. Experimental results showed that first stage fracture was a planar fracture while the second stage fracture was a concave fracture (bowl-shaped fracture). Stress interference between those two main fractures caused the growing of secondary cracks which were parallel to the simulated wellbore, but decreasing the width of sequent main fractures. Penny-shaped fracture model was believed to be more suitable than rectangular fracture model to simulate the real hydraulic fracture geometry in horizontal well. Fracture spacing design should be a significant work in multi-stage fracturing in horizontal well. © 2014 by Japanese Committee for Rock Mechanics.


Sun J.-C.,CAS Institute of Mechanics | Guo H.-K.,Langfang Branch of Research Institute of Petroleum Exploration and Development | Yang Z.-M.,Langfang Branch of Research Institute of Petroleum Exploration and Development | Jiang P.,Sinopec | Yan J.,CAS Institute of Mechanics
Xinan Shiyou Daxue Xuebao/Journal of Southwest Petroleum University | Year: 2011

Porosity is one of the most important parameters for calculating the reserve and formation evaluation. Nuclear magnetic resonance (NMR) technology is an effective method quantifying the value of porosity. Considering to the fact that the diagenetic mechanism, pore structure and mineral composition of volcanic gas reservoir are different from sedimentary reservoir, the response characteristics and NMR porosity of volcanic rock core samples were studied with NMR technology. The results indicate that the NMR porosity of rhyolite and tuff rock sample are very close to their conventional porosity, but the NMR porosity of trachyte, trachyte volcanic breccia and granite porphyry are not consistent with their conventional porosity. Plasma emission spectroscopy experimental results suggest that the difference in element content of different lithologic rock is the main reason leading to NMR porosity error. The more the content of the paramagnetic material including iron and manganese, the larger of the NMR porosity error. Meanwhile, the quantitative relationship between the NMR porosity relative error and the content of paramagnetic material is established. Additionally, this paper also analyzed the effect of paramagnetic material on the reservoir evaluation by using the NMR well logging technology.


Tang M.,China University of Petroleum - Beijing | Wang Z.,China University of Petroleum - Beijing | Ding G.,Langfang Branch of Research Institute of Petroleum Exploration and Development
Yanshilixue Yu Gongcheng Xuebao/Chinese Journal of Rock Mechanics and Engineering | Year: 2010

For investigation on the mechanical characteristics of layered salt rocks in Huai'an Salt Mine, Jiangsu Province, and in consideration of the laminative geological structural character of most salt mines in China, experimental studies of uniaxial and triaxial compressions are carried out on three kinds of rock samples which are rock salt, mudstone and salt-mudstone interlayer. The experiment results indicate that: (1) The strain-stress relationship of rock salt and salt-mudstone interlayer under uniaxial compression or triaxial compression performs obviously strain hardening-softening properties. (2) The rock salt and salt-mudstone interlayer have obvious plastic deformation ability. The elastic modulus measured by the cycle loading-unloading curve is better than that measured directly from the primeval loading curve. (3) For the rock salt, the cohesive force is getting smaller and smaller while the internal friction angle first increases and then decreases with the plastic shear deformation increasing. (4) The presence of mudstone interlayer affects the mechanical characteristics of samples remarkably. The primary phenomenon is the strength's increasing. The failure modes of the mudstone interlayer rock salt are determined by their states.


Hou B.,China University of Petroleum - Beijing | Chen M.,China University of Petroleum - Beijing | Li Z.,China University of Petroleum - Beijing | Wang Y.,Langfang Branch of Research Institute of Petroleum Exploration and Development | Diao C.,China University of Petroleum - Beijing
Petroleum Exploration and Development | Year: 2014

Based on hydraulic fracturing experiments in laboratory, the hydraulic fracture propagation in shale is analyzed, a method for evaluating the fracture propagation extent is proposed, and the effects of geological factors and engineering factors on fracture propagation are studied. "Stimulated Rock Area (. SRA)" is proposed as an evaluation index for the hydraulic fracturing results. By analyzing the experiment results, it is found that hydraulic fracturing in shale reservoirs can generate a complex fracture network; a lower stress difference in brittle shale formation and a shorter distance between hydraulic fracture and bedding plane lead to a larger SRA and more complex fracture geometry; a fracture network is more likely to generate in the case that the angle between horizontal maximum stress direction and bedding plane is 90° or large enough, or the approaching angle between hydraulic fracture and well-opened natural fracture is close to 90° a higher brittle mineral content leads to better fracturing ability; low fluid viscosity and high flow rate lead to a large SRA; a variable flow rate increases the possibility that the hydraulic fracture communicates with bedding planes and natural fractures. © 2014 Research Institute of Petroleum Exploration & Development, PetroChina.


Xiong B.,China University of Petroleum - Beijing | Xiong B.,Langfang Branch of Research Institute of Petroleum Exploration and Development | Xu M.,Langfang Branch of Research Institute of Petroleum Exploration and Development | Wang L.,Langfang Branch of Research Institute of Petroleum Exploration and Development | And 2 more authors.
Drilling Fluid and Completion Fluid | Year: 2016

Several autogenetic heat fracturing fluids find their use in reservoir fracturing. In autogenetic heat fracturing, activating agent is added into the fracturing fluid for heat generation, and this makes the process much less efficient. A clear autogenetic fracturing fluid was prepared using a hydrophobic polymer as the thickening agent. The thickening agent has a salt-resistant component added during its synthesis, enabling the thickening agent to be readily dissolving in saltwater. Using organo-zirconiumacidic crosslinking agent, activating agent using for heat generation and modifying agent for crosslinking reaction are not necessary anymore. Fracturing fluid treated with 0.6% of the thickening agent has good heat-resistance and shear-resistance, good elasticity and gel breaking capacity. After shearing for 60 min at 100℃ and 170 s-1, the fracturing fluid retains a viscosity of about 140 mPa·s, and its visco-elasticity equivalent to that of conventional guar gum fracturing fluids. Residue of the fracturing fluid is 11.9 mg/L. This fracturing fluid is suitable for use in fracturing medium- to low-temperature reservoirs. By monitoring pressure changes of the reaction, the extent of reaction of heat generators is measured on a HTHP dynamic acidizing corrosion tester, and this measurement is both simple and accurate, suitable for the optimization of the formulation of autogenetic heat fracturing fluids, and the assessment of the extent of reaction of heat generators. The study shows that no reaction has ever taken place between heat generators in base fluid at 40℃, and 55% of the heat generators react at 80℃, while at 120℃, all heat generators react with each other, indicating that the fracturing fluid should be prepared in advance, and the operation process is the same as that of conventional fracturing fluids. © 2016, The Editorial Board of Drilling Fluid & Completion Fluid. All right reserved.


Peng F.,East China University of Science and Technology | Fang B.,East China University of Science and Technology | Lu Y.,Langfang Branch of Research Institute of Petroleum Exploration and Development | Qiu X.,Langfang Branch of Research Institute of Petroleum Exploration and Development | And 2 more authors.
Drilling Fluid and Completion Fluid | Year: 2016

A hydrophobic amphoteric quadripolymer PAADC was synthesized for use as a drag reducer in slippery water fracturing fluids. PAADC, made from monomers AM, AMPS, DMAM and CDAAC, was studied in laboratory on its rheology and drag reduction capacity, and the rheology of PAADC solution at different concentrations is measured. Change of the friction coefficient and rate of drag reduction of the PAADC solutions with generalized Reynolds number is discussed in this paper. Comparison between the rheology and drag reduction capacity of PAADC and those of another water-soluble terpolymer PAAD (synthesized from AM, AMPS and DMAM) was conducted. PAADC solution has, as the studies indicated, very good shear thinning capacity, and the thixotropy of PAADC is better than that of PAAD at the same concentration. The maximum rates of drag reduction of PAADC solution of different concentrations (0.1%, 0.2%, 0.3%, and 0.4%) are 32.29%, 63.32%, 69.52% and 67.35%, respectively, indicating that PAADC concentration remarkably affects the drag reduction capacity of thesolutions, and 0.3% PAADC solution is preferred in drag reduction. © 2016, The Editorial Board of Drilling Fluid & Completion Fluid. All right reserved.

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