Conventional Hydraulic Fracturing Research Articles

On the Role of Poroelasticity in the Propagation Mode of Natural Fractures in Reservoir Rocks

Almost all reservoir rocks contain natural fractures. The presence of such discontinuities affects reservoir stimulation to a certain degree. The interaction between the natural and hydraulic fractures determines the overall fracture trajectory and the stimulated reservoir volume. In contrast to conventional hydraulic fracturing, natural fractures do not propagate in a tensile-dominated regime. Propagation of mechanically closed fractures lies in the mixed-mode propagation regime which differs from that of open fractures. Therefore, the response of natural fractures to pore pressure and stress perturbations should be carefully addressed within the context of reservoir stimulation. This study aims at investigating the response of closed natural fractures to water injection in poroelastic rocks. A poroelastic displacement discontinuity (DD) model is developed and used to shed light on the propagation of closed natural fractures. Mohr–Coulomb contact elements are used in this study to identify the contact status of the elements in the transverse direction. Moreover, fracture propagation is effectively accounted for based on linear elastic fracture mechanics. Hydro-mechanical coupling is achieved by combining an implicit finite difference scheme with the poroelastic DD model. Our simulation results indicate that natural fracture shear slip and propagation are likely to occur when the closed natural fractures are subject to direct water injection. The injection pressure required to maintain the propagation in poroelastic rocks was found to be consistently higher than the pressure in its elastic counterpart. The propagation trajectory of the wing cracks was, on the other hand, found to be similar to that in elastic rocks. It was found in our results that the formation of wing cracks and shear (secondary) cracks is an integral part of the reservoir stimulation in geothermal systems where natural fractures are in direct contact with the injection wells. This point is often overlooked or poorly treated and has led to erroneous interpretations from the reservoir stimulation standpoint.

Effect of excavation stress condition on hydraulic fracture behaviour

The fracture behaviour of single- and multi-stage hydraulic fracturing (HF) under varying excavation stress conditions was studied using a flow-coupled discrete element method (DEM). Conventional HF theories and analytical solutions for excavation stress redistribution are used to verify the numerical model. The numerical simulation results indicated that for the single-stage HF, both the in situ stresses and injection location have major influences on the HF propagation path, caused by the redistributions of the local maximum and minimum principal stresses under excavation conditions. Fractures generally propagate perpendicular to the local minimum principal stress (σmin) and also propagate preferentially towards the area with lower σmin. Hydraulic fractures propagation is dominated by tensile failure, and the generation of fracture branches is disfavored because of the high local compressive stress field induced by the HF process itself. As for multi-stage HF, different excavation stress conditions may cause different fracture development performances because of alterations of the preferred fracture orientation, blunting of propagating fractures, or creating a more complex fracture geometry in the affected zone. Therefore, when using high-pressure HF for preconditioning the rock mass to assist mechanical excavation in hard rock mining, performance can be enhanced by understanding the impact of stress changes and careful selection of appropriate HF methods depending on the in situ stress.

Lessons Learned from Stimulation of Dibei Tight Gas Reservoir with Strong Heterogeneity in Tarim Basin

The Dibei gas field is a naturally fractured tight sandstone gas reservoir in the Tarim Basin, West China. It is characterized by large depth (4600–5200 m), huge thickness (100–200 m), low abundance, low matrix permeability, high pressure (80–95 MPa), high temperature (140 – 150°C) and strong heterogeneity. Different stimulation techniques were applied to improve well production. For the wells with good development of natural fractures, matrix acidizing, acid fracturing or conventional hydraulic fracturing is used. For the wells with low fracture density and huge thickness, separate-layer acid-fracturing, massive separate-layer hybrid fracturing or composite diverting agent is applied to improve stimulation efficiency. The low-damage high-temperature weighted fracturing fluids are used to reduce the effect of reservoir sensitivity and the treatment pressure, and high-strength proppant is used at the same time to keep high fracture conductivity. Meanwhile, large-diameter fracturing string with 3-1/2″ and 4-1/2″ connections is used to decrease pump pressure and increase pump rate. The above technologies were applied in more than twenty treatments in seven wells, of which more than half witnessed production increase. The matrix acidizing or conventional hydraulic fracturing is well performed for the wells with natural fractures, but inefficient for the extremely tight gas wells. In Well A without fractures, the massive separate-layer hybrid fracturing was used. In the treatment, a total of 1,328 m3 fracturing fluid was used, with 50 m3 proppant; the pump rate was 8 m3/min and the maximum pump pressure was 92 MPa. Unfortunately, the post-frac production was not as expected, mainly due to the damage of killing well. In Well B with fractures, high gas production was achieved by acid fracturing, but the gas rate dropped from 258,000 m3 to 51,000 m3 after killing well, and the gas rate never recovered even by acid fracturing, hydraulic fracturing and relieving damage with methanol. The development of natural fractures is the key controlling factor for gas production. Well C, less than 800 m from well B, The development of natural fractures is quite different from Well B, and 98,000 m3 gas rate was acquired after hydraulic fracturing with more than 1,000 m3 low damage high-temperature weighted fracturing fluid and 30 m3 proppant. The development of natural fractures is the key controlling factor for gas production and killing well damage is the fatal blow to the gas production, so the stimulation techniques and working fluid system should be prudently optimized.

A novel experimental method to investigate the plugging characteristics of diversion agents within hydro-fracture

Temporary plugging and diverting fracturing (TPDF) technique has been widely used in exploiting hydrocarbon resources in conventional/unconventional formations. The key to ensuring the success of this technique lies in the efficient plugging of the previously created fractures. However, the plugging characteristics of diversion agents influenced by the fracture geometry have not been efficiently investigated through experiments. In this study, the conventional true tri-axial hydraulic fracturing system was modified, then a series of investigative experiments were carried out and a novel experimental method was proposed to systematically investigate the plugging characteristics of diversion agents within the fracture. This method can not only investigate the effects of fracture geometry on the diversion agent distribution, plugging capacity, and plugging speed within fracture, but also optimize the diversion agent recipe for plugging various geometries fracture with different apertures, thus saving the dosage of diversion agents and fracturing fluids. Moreover, under certain conditions, as for the common four types of fractures i.e., distorted (type-Ⅰ) fracture, inclined and flat (type-Ⅱ) fracture, longitudinal and flat (type-Ⅲ) fracture, and transverse and flat (type-Ⅳ) fracture, the required ratio of diversion agent dosage for plugging is approximately 1:7:15:3.

Enhanced Tight Oil Recovery by Volume Fracturing in Chang 7 Reservoir: Experimental Study and Field Practice

The Chang 7 reservoir in Changqing oilfield is rich in tight oil. However, due to the low formation permeability, it is very difficult to obtain economical oil production without stimulation treatments. Volume fracturing seems to be a more efficient tight oil recovery enhancement (EOR) method in Chang 7 pilot tests compared with conventional hydraulic fracturing. In this study, Chang 7 tight oil reservoir was first characterized by its geological property, hydrocarbon source rock distribution, and formation physiochemical property. Tight core flooding tests were then conducted to experimentally investigate the EOR ability of the volume fracturing technique. The field-scale practice was also demonstrated and analyzed. The results show that Chang 7 reservoir is favorable for the generation of a large amount of tight oil. Fractures created in tight cores can significantly improve the fluid flow conductivity and enhance the imbibition of displacing water, resulting in a greater tight oil recovery increment. Volume fracturing is an effective way to generate a larger number of fractures. Field application indicates that volume fracturing treatment can form a much greater reservoir stimulation volume. Daily oil production in the volume-fracturing-treated wells can be more than twice as high as that in the conventional-fracturing-treated wells.

Bipropellant high energy stimulation for oil and gas applications

Large-scale extraction of oil and natural gas requires an effective method of generating a high surface area network of fractures, or the stimulation of existing fractures, in a formation in order to increase permeability. Conventional hydraulic fracturing has limited utility in this application. In this work, Sandia National Laboratories is exploring high rate pressurization techniques employing tailored energetic materials systems to control both pressure rise rate and peak pressure in order to optimally stimulate potential rock formations. Rapid pressurization, at rates far exceeding quasi-static conventional hydraulic rates, can generate multiple radial well bore fractures and potentially provide a mechanism to induce shear destabilization within the formation that enables the fractures to be self-propping. Multiple fractures from the well bore allow efficient coupling to the existing formation fracture network and increase near field well bore permeability. Furthermore, these techniques can allow for repeated stimulations and produce energetic events within the fractures thereby allowing fractures to be extended further. Controlled rate pressurization is a useful tool for the efficient generation of fracture networks and has potential application to increase oil and gas production. This paper provides an overview of the concept of controlled rate pressurization, laboratory experiments and field trials that are being conducted. The present work investigates detonations of a stoichiometric mixture of ethylene and nitrous oxide (C2H4 + 6N2O) at high initial pressures ranging from 0.862 to 2.068 MPa as a method of fracturing rock below the ground surface. The experiments investigate the fracture generation as a function of the initial pressure of the mixture. In the current configuration, the combustion reaction is initiated by an electrically fired igniter at the ground surface and quickly transitions to a detonation. The experimental setup accommodates one high pressure (690 MPa) transducer, placed downstream of the igniter, to measure peak pressure. The pressure transducer recorded peak pressures, which are 2.3–2.6 times in excess of the Chapman-Jouguet (CJ) values as a result of pre-compression of the unburned gas mixture during the flame acceleration prior to deflagration-to-detonation transition (DDT). Analysis of the data indicated an increase in rock permeability due to detonations and this was confirmed by the core drilled sections at the test site.

Experiment and Simulation for Controlling Propagation Direction of Hydrofracture By Multi-Boreholes Hydraulic Fracturing

Hydraulic fracturing has been applied to enhance CBM production and prevent gas dynamical hazard in underground coal mines in China. However, affected by in situ stress orientation, hydrofracture can hardly continuously propagate within coal seam but may easily extend to the adjacent roof-floor strata, causing ineffective permeability enhancement in coal seam and increasing the risk of gas transfinite during mining coal. Thus, it is very necessary to artificially control the propagation direction of hydrofracture and make it well-aligned in large scale in coal seam. In this study, a method for controlling propagation direction of hydrofracture by multi-boreholes is investigated by theoretical analysis, laboratory experiment and numerical simulation. And this is followed by an on-site test in an underground coal mine to verify this method. Firstly, stress intensity factor at the hydrofracture tip is analyzed where pore pressure is taken into consideration. Results show that the pore pressure is able to increase the stress intensity factor and reduce hydrofracture propagation pressure. Based on this, a method of hydraulic fracturing using multi-boreholes to control hydrofracture direction is proposed. Afterwards, laboratory experiments are conducted to explore the impact of pore pressure on hydrofracture propagation. The experimental results agree with the theoretical analysis very well. Later on, a series of numerical simulations are performed to examine the influence of principal stress difference, the angle between assistance drillholes and the maximum principal stress, and the fluid pressure of the assistance drillholes on hydrofracture propagation. Finally, an on-site test in an underground coalmine is practiced where this proposed method is used to enhance the CBM production. Results show the scope of the hydro-fracture resulting from the multi-boreholes hydraulic fracturing method increases 2.7 times compared with that of conventional hydraulic fracturing. And gas production rate also increases 4.1 times compared with that of conventional hydraulic fracturing and 12.3 times compared with direct borehole extraction without fracturing.

Multi-fractured stimulation technique of hydraulic fracturing assisted by radial slim holes

The SRV fracturing is the core of commercial exploitation of shale gas, and the design philosophy of the SRV fracturing is gradually introduced into the stimulation of conventional low permeability reservoir and unconventional reservoir. However, in reservoirs with poorly developed natural fractures or high horizontal principal stress difference, it is difficult to achieve the multi-fracture or fracture network by conventional hydraulic fracturing, and effectively stimulating reservoir needs other assisting methods. This paper aims to present a method of guiding the multi-directional hydraulic fractures by multiple radial slim holes drilled in spatial positions, and creating multi-fractures and even complex fracture network. In this paper, a 3D hydraulic fracturing extended finite element numerical model in the vertical well assisted by planar multi-radial slim holes was established, and the effect of radial slim hole number, diameter, length, vertical density, azimuth and phase angle, Poisson's ratio, horizontal principal stress difference and rock Young's modulus, fracturing fluid viscosity and injection rate, reservoir permeability, etc. on guidance of radial slim holes were investigated. Then, we conducted the true tri-axial hydraulic fracturing test with the artificial core, and the feasibility of the technology was verified. The results show that decreasing azimuth and phase angle and increasing hole diameter, length and vertical density strengthen the guiding effect of planar multi-radial slim holes, and increasing Poisson's ratio, reservoir permeability, and fracturing fluid injection rate and viscosity enhance the guidance effect of radial slim holes. Increasing horizontal principal stress difference and reservoir Young's modulus weaken the radial slim holes guiding effect. The physical modeling experiment proves that controlling generation of complex multi-fractures is feasible by rationally arranging the spatial positions of radial slim holes. The spatial arrangement of four planar radial slim holes with phase angle of 90°, azimuth of 45° and vertical density not less than 2 holes/m in the vertical well is a scientific scheme. With the reasonable treatment scheme, creating 6 main fractures is possible. The research results provide theoretical support for multi-fractured stimulation assisted by planar multi-radial slim holes, and help the design of well completion parameters and fracturing treatment parameters of the technology.

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.

A combined stimulation technology for coalbed methane wells: Part 1. Theory and technology

As there are numerous coalbed methane (CBM) wells with low or zero gas production after traditional hydraulic fracturing in China, new technologies are needed for both the secondary stimulation of these wells and new wells’ stimulation. Based on the results of laboratory tests and theoretical analysis, this paper, the first of a two-part series, demonstrates the theory of a new combined stimulation technology for CBM wells. Firstly, gas contents in the coal seam, neighbouring shale and sandstone were measured and calculated. Then, the geomechanic, mineral composition and permeability of the tight sandstone were tested. Based on these tests and calculations, a combined stimulation technology is demonstrated. This new technology is to expand gas production from coal seams to coal measures; to expand the stimulation object from unitary coal seams to coal measures; and to change the stimulation method from the conventional hydraulic fracturing to fracture network stimulation. Results show that: (1) in addition to CBM, significant amounts of shale gas and tight sandstone gas can serve as complements of CBM; (2) the highest fracability formation is tight sandstone, followed by mudstone and coal. It is concluded that this combined stimulation technology can be demonstrated as conducting combined fracture network stimulation for coal measure gas reservoirs through multilayer and multi-cluster perforation, quadruplex hydraulic fracturing and other auxiliary technologies, e.g., ball-injection temporary plugging and limited entry fracturing. In part 2, the application of this combined stimulation technology to a CBM well in the Sunan Syncline is described.

Application of Dimensional Analysis to Project Laboratory Scale Numerical Modelling Prescribed Hydraulic Fracturing Results to Field Scales

Hydraulic fracturing has been applied in the cave mining industry with the purpose of re-creating an orebody rock mass condition that is suitable for caving. Prescribed hydraulic fracturing was proposed in a previous study as a supplement to the conventional hydraulic fracturing strategy. In this paper; dimensional analysis is used to project laboratory scale numerical modelling results to field scales in order to study the applicability of creating prescribed hydraulic fractures (PHFs) under field conditions. The results indicate that field scale PHFs are feasible if the stress shadows of the pre-located fractures are properly utilized. Water can be used to create the pre-located fractures that induce the local stress change in a low differential stress state; and the use of more proppants and a shorter pre-located fracture spacing lead to PHFs propagating more quickly towards the pre-located fractures. For field condition having high differential stresses, more viscous fluid must be used to create the pre-located fractures in order to enhance the stress shadows. In this case, a shorter pre-located fracture spacing does not necessarily result in the re-orientation of PHFs towards the pre-located fractures and may even lead to unsatisfactory pre-conditioning. A sufficiently high pre-located fracture net pressure to the differential stress ratio (close to 0.5) is the prerequisite for creating PHFs.

Permeability Enhancement and Fracture Development of Hydraulic In Situ Experiments in the Äspö Hard Rock Laboratory, Sweden

A new advanced protocol of progressively increased cyclic injection and pulsed injection design for hydraulic fracturing experiments was implemented at 410 m depth in the Aspo Hard Rock Laboratory in Sweden. A monitoring array was installed around the tested horizontal borehole to detect the acoustic emissions and micro-seismic events during the fracturing process. The aim is to identify optimized injection schemes to reduce the seismicity related to the fracturing processes. The cyclic stimulation scheme of loading and unloading the fracturing net pressure leads to a lower accompanied seismicity if compared to the conventional hydraulic fracturing with constant flow rates. The related permeability of the tested rock interval can be increased, but this increase is less pronounced than that of the conventional treatments and, especially, if compared to the last of the re-fracturing series with high seismicity increase. Despite these limitations, in field applications with expected high risk of unwanted seismic events, this advanced protocol can be a feasible option to reduce this risk.

How to Reduce Fluid-Injection-Induced Seismicity

The recent growth in energy technologies and the management of subsurface reservoirs has led to increased human interaction with the Earth’s crust. One consequence of this is the overall increase of anthropogenic earthquakes. To manage fluid-injection-induced seismicity, in this study, we propose to use an advanced fluid-injection scheme. First, long-term fluid-injection experiments are separated from short-term fluid-injection experiments. Of the short-term experiments, enhanced geothermal systems stimulations have shown a higher propensity to produce larger seismic events compared to hydraulic fracturing in oil and gas. Among the factors discussed for influencing the likelihood of an induced seismic event to occur are injection rate, cumulative injected volume, wellhead pressure, injection depth, stress state, rock type, and proximity to faults. We present and discuss the concept of fatigue hydraulic fracturing at different scales in geothermal applications. In contrast to the conventional hydraulic fracturing with monotonic injection of high-pressure fluids, in fatigue hydraulic fracturing, the fluid is injected in pressure cycles with increasing target pressure, separated by depressurization phases for relaxing the crack tip stresses. During pressurization phases, the target pressure level is modified by pulse hydraulic fracturing generated with a second pump system. This combination of two pumps with multiple-flow rates may allow a more complex fracture pattern to be designed, with arresting and branching fractures, forming a broader fracture process zone. Small-scale laboratory fluid-injection tests on granite cores and intermediate-scale fluid-injection experiments in a hard rock underground test site are described. At laboratory scale, cyclic fluid-injection tests with acoustic emission analysis are reported with subsequent X-ray CT fracture pattern analysis. At intermediate scale, in a controlled underground experiment at constant depth with well-known stress state in granitic rock, we test advanced fluid-injection schemes. The goal is to optimize the fracture network and mitigate larger seismic events. General findings in granitic rock, independent of scale, are summarized. First, the fracture breakdown pressure in fatigue hydraulic testing is lower than that in the conventional hydraulic fracturing. Second, compared to continuous injection, the magnitude of the largest induced seismic event seems to be systematically reduced by cyclic injection. Third, the fracture pattern in fatigue testing is different from that in the conventional injection tests at high pressures. Cyclic fracture patterns seem to result from chiefly generated low energy grain boundary cracks forming a wider process zone. Fourth, cyclic injection increases the permeability of the system. A combination of cyclic progressive and pulse pressurization leads to the best hydraulic performance of all schemes tested. One advantage of fatigue testing is the fact that this soft stimulation method can be applied in circumstances where the conventional stimulation might otherwise be abandoned based on site-specific seismic hazard estimates.

Experimental study of directional propagation of hydraulic fracture guided by multi-radial slim holes

The conventional hydraulic fracturing fails in the target oil/gas zone (remaining oil, closed reservoir, etc.) which is not located in the azimuth of maximum horizontal stress of available wellbores. The technology of directional propagation of hydraulic fracture guided by vertical multi-radial slim holes is innovatively developed. In order to verify this technology, lots of true triaxial hydraulic fracturing simulation experiments were carried out with artificial cores, aiming at investigating the influence of in-situ stress, fracturing fluid displacement, and azimuth, diameter, number, and spacing of radial slim holes on fracture propagation. The results show that directional propagation of hydraulic fractures guided by vertical multi-radial slim holes is feasible. Regardless of varied radial slim hole and in-situ stress parameters, hydraulic fracture always initiates in the heel of radial slim hole. For hydraulic fracturing assisted by single radial slim hole, smaller horizontal stress difference (3 MPa, σH/σh = 1.25) and smaller radial slim hole azimuth (15°) may guide propagation of hydraulic fractures along radial slim hole, and larger horizontal stress difference (6 MPa, σH/σh = 1.67) can sharply reduce guidance of radial slim hole. Affected by mutual interference from guidance of radial slim holes and controlling of horizontal in-situ stress, fractures tend to distort along fracture length and fracture height. For hydraulic fracturing assisted by vertical multi-radial slim holes, horizontal stress difference is one of key factors influencing the directional propagation effect of hydraulic fracture. Larger horizontal in-situ stress difference (>6 MPa, σH/σh > 1.67) hardly results in directional propagation of hydraulic fracture along radial slim hole row, and creates bigger diversion angle of fracture, and larger azimuth (>45°) of radial slim hole row reduces the guidance strength, resulting small fracture diversion radius. In conditions of larger angle between target zone and maximum horizontal stress, and requirement of large azimuth of radial slim hole row, the effective hydraulic fracture propagation along radial slim holes and ideal fracture height will be achieved through human intervention, e.g. increment of the number and diameter of radial slim holes, reduction of radial slim holes spacing, increment of fracturing fluid displacement, etc. The simulation results provide methods for designing directional propagation of hydraulic fractures guided by vertical multi-radial slim holes.

Experimental study on crack propagation control and mechanism analysis of directional hydraulic fracturing

Hydraulic fracturing is mainly used for increasing large-scale coal seam permeability in coal mines to exploit coalbed methane and prevent coal and gas outbursts. However, conventional hydraulic fracturing cracks tend to propagate along the direction of maximum principal stress, which is inconsistent with reinforcement direction engineering and/or project area needs and makes identification of the orientation or specified location of increased coal seam permeability difficult. To address these problems, we have conducted physical similarity simulation experiments and numerical analysis of directional hydraulic fracturing (DHF) and obtained the crack propagation law of DHF technology. By analyzing the variation law of the maximum principal stress inside the rock mass, the crack propagation control mechanism of DHF technique is revealed. The influence of horizontal stress difference coefficients and angles between the hydraulic slotting direction and maximum principal stress direction (i.e., the hydraulic slotting deviation angle) on the crack propagation deflection is investigated. The results show that the DHF technique can achieve crack-oriented propagation along the desired direction. The maximum principal stress range in the rock mass is redistributed after slotting. A directional fracturing induction region is formed between the slots. In addition, DHF hydraulic pressure curves show a secondary fracturing stage when cracks connect the hydraulic fracturing and hydraulic slotting boreholes. Initiation pressures and values of maximum principle stress in the directional fracturing zone increase with increasing horizontal stress difference coefficients and slotting deviation angles. However, increasing the horizontal stress difference coefficient does not significantly influence the directional fracturing zone range. The results provide a reliable basis for subsequent theoretical research and engineering applications.

Research on Annular Frictional Pressure Loss of Hydraulic-Fracturing in Buckling Coiled Tubing

Compared with conventional hydraulic fracturing, coiled tubing (CT) annular delivery sand fracturing technology is a new method to enhance the recovery ratio of low permeability reservoir. Friction pressure loss through CT has been a concern in fracturing. The small diameter of CT limits the cross-sectional area open to flow, therefore, to meet large discharge capacity, annular delivery sand technology has been gradually developed in oilfield. Friction pressure is useful for determining the required pump horsepower and fracturing construction design programs. Coiled tubing can buckle when the axial compressive load acting on the tubing is greater than critical buckling load, then the geometry shape of annular will change. Annular friction pressure loss elevates dramatically with increasing of discharge capacity, especially eccentricity and CT buckling. Despite the frequency occurrence of CT buckling in oilfield operations, traditionally annular flow frictional pressure loss considered concentric and eccentric annuli, not discussing the effects of for discharge capacity and sand ratio varying degree of CT buckling. The measured data shows that the factors mentioned above cannot be ignored in the prediction of annular pressure loss. It is necessary to carry out analysis of annulus flow pressure drop loss in coiled tubing annular with the methods of theoretical analysis and numerical simulation. Coiled tubing buckling has great influence on pressure loss of fracturing fluid. Therefore, the correlations have been developed for turbulent flow of Newtonian fluids and Two-phase flow (sand-liquid), and that improve the friction pressure loss estimation in coiled tubing operations involving a considerable level of buckling. Quartz sand evidently increases pressure loss in buckling annular, rising as high as 40%-60% more than fresh water. Meanwhile, annulus flow wetted perimeter increases with decreasing helical buckling pitch of coiled tubing, therefore, the annulus flow frictional pressure loss rapidly increases with decreasing helical buckling pitch. The research achievement provides theoretical guidance for coiled tubing annular delivery sand fracturing operation and design.

Pulse hydraulic fracturing technology and its application in coalbed methane extraction

The sealing and operating procedures of pulse hydraulic fracturing (PHF) were systematically introduced to increase the methane reservoir permeability. The results of a pilot application conducted at Sv719 working face in Daxing coal mine, China, shown that both the sealing and cracking were successfully operated. The injection time and water quantity were positively correlated with the fracturing initiation pressure. The fracturing mechanism of PHF was theoretically analysed, and the relationship between fatigue-loaded coal strength and injecting frequency was studied. A criterion for determining the fracture pressure was established. Compared to conventional hydraulic fracturing and deep-hole blasting, PHF technology is superior in gas-extraction performance, with a relatively high extraction concentration and less gas attenuation. Moreover, the content and pressure of residual gas in the fractured coal seams were reduced below the regulatory limits, with decrease of 46.15-83.67% and 61.61%, respectively. [Received: January 22, 2016; Accepted: May 17, 2017]

Pulse hydraulic fracturing technology and its application in coalbed methane extraction

The sealing and operating procedures of pulse hydraulic fracturing (PHF) were systematically introduced to increase the methane reservoir permeability. The results of a pilot application conducted at Sv719 working face in Daxing coal mine, China, shown that both the sealing and cracking were successfully operated. The injection time and water quantity were positively correlated with the fracturing initiation pressure. The fracturing mechanism of PHF was theoretically analysed, and the relationship between fatigue-loaded coal strength and injecting frequency was studied. A criterion for determining the fracture pressure was established. Compared to conventional hydraulic fracturing and deep-hole blasting, PHF technology is superior in gas-extraction performance, with a relatively high extraction concentration and less gas attenuation. Moreover, the content and pressure of residual gas in the fractured coal seams were reduced below the regulatory limits, with decrease of 46.15-83.67% and 61.61%, respectively. [Received: January 22, 2016; Accepted: May 17, 2017]

Development of an LPG fracturing fluid with improved temperature stability

Continued exploitation of unconventional reservoirs using conventional hydraulic fracturing fluid technologies requires large volumes of water, which may lead to water resource shortage and environmental pollution problems. To mitigate these issues, we have developed a waterless fracturing fluid system, an LPG (Liquefied Petroleum Gas) fracturing fluid, which exhibits excellent rheological properties, at high temperatures.In order to develop this high-performance LPG fracturing fluid, two series of metal cross-linkers (aluminum cross-linkers and iron cross-linkers) were formulated. Crosslinking performance was examined via visual observation at room temperature and by rheological testing at raised temperatures. After optimizing the crosslinker formulation, the breaking performance and the regain permeability of the new LPG fracturing fluid were also examined. The new LPG fracturing fluid breaks almost completely at 90 °C and achieves an average regain permeability of 96.97% even at 25 °C, suggesting low damage in the field applications. A fracturing fluid with such good performance can satisfy the requirements of unconventional reservoir operations. Also, as far as we know, it is the first time that all of the important characteristics of an LPG fracturing fluid are reported.

Numerical Simulation of Hydraulic Fracture Propagation Guided by Single Radial Boreholes

Conventional hydraulic fracturing is not effective in target oil development zones with available wellbores located in the azimuth of the non-maximum horizontal in-situ stress. To some extent, we think that the radial hydraulic jet drilling has the function of guiding hydraulic fracture propagation direction and promoting deep penetration, but this notion currently lacks an effective theoretical support for fracture propagation. In order to verify the technology, a 3D extended finite element numerical model of hydraulic fracturing promoted by the single radial borehole was established, and the influences of nine factors on propagation of hydraulic fracture guided by the single radial borehole were comprehensively analyzed. Moreover, the term ‘Guidance factor (Gf)’ was introduced for the first time to effectively quantify the radial borehole guidance. The guidance of nine factors was evaluated through gray correlation analysis. The experimental results were consistent with the numerical simulation results to a certain extent. The study provides theoretical evidence for the artificial control technology of directional propagation of hydraulic fracture promoted by the single radial borehole, and it predicts the guidance effect of a single radial borehole on hydraulic fracture to a certain extent, which is helpful for planning well-completion and fracturing operation parameters in radial borehole-promoted hydraulic fracturing technology.