Slickwater Fracturing Fluid Research Articles

Preparation and performance evaluation of nano-composite fracturing fluid with good oil displacement ability in tight reservoir

Using slickwater fracturing fluid is an efficient stimulation method in low-permeability reservoirs. The drag reducing ability of drag reducing agents is very important for fracturing fluids. In this paper, we developed a new nanomaterial and added it to the slickwater fracturing fluid to enhance the performance of the NCS (nanomaterial composite slickwater) fracturing fluid and make it has a certain oil displacement ability. The nanomaterials was synthesized by a two-step synthesis method. The experimental results show that the novel nanomaterial has better performance than the commercial nanomaterials. The composite fracturing fluid shows a good stability at 90 °C, and the particle size of the nanomaterials in the fracturing fluid does not significantly change. The experimental results demonstrate that the drag reduction ability of the composite fracturing fluid can be maintained at more than 70%. In addition, the core displacement experiments show that the composite fracturing fluid has a very low-permeability reduction of 1.03%. In the imbibition experiment, the oil recovery rate of the composite fracturing fluid reaches 36%, the oil recovery rate of the pure water is less than 30%. In the end, the mechanism of enhanced oil recovery by nanomaterials and the mechanism of synergistic drag reduction between nanomaterials and polymers, are studied. The proposed NCS fracturing fluids, with both fracturing and oil displacement capabilities, and is expected to become a potential method for tight oil reservoir development.

Analyzing the Benefits of Designing a Multifunctional Surfactant Blend From Laboratory Scale to Field Scale in Hydraulic Fracturing under High-Salinity Conditions: A Case Study of the Mississippian Limestone Play

Summary Surfactants are typically used in hydraulic fracturing applications to perform a single function, which results in multiple surfactants being used during operations. In this study, flow loop and coreflood tests were conducted with slickwater fracturing fluid systems and analyzed in conjunction to observe the effectiveness of flowback surfactants and their ability to increase friction reducer performance. A multifunctional surfactant blend (MSB) is tested against surfactant formulations commonly used either as a flowback aid or as a performance enhancer for low-cost friction reducers in harsh conditions. A case study is conducted using wells in the Mississippian limestone play to correlate laboratory investigations to field observations. Each surfactant solution was tested with a friction-reducing polymer in synthetic brine containing a salt concentration of 200 000 mg/L representative of harsh field conditions in the laboratory evaluation. Coreflood tests were conducted under reservoir conditions to evaluate flowback efficiency quantified by regained permeability. To test the ability of the surfactants to improve friction reduction (FR) performance, a 0.4-in. inner diameter friction flow loop was used. In the field-scale application, four wells were hydraulically fractured with two wells acting as control cases and two wells including the addition of the MSB. Completions and production data are presented to compare the performances of the wells and the efficacy of the MSB at the field scale. Friction flow loop testing showed that slickwater fluids with commonly used flowback surfactant formulations, including the MSB, can greatly improve the performance of economical freshwater friction reducers, even in a high calcium (13 000 mg/L) synthetic brine. The same slickwater/surfactant fluids used in the flow loop tests were evaluated in coreflood tests. Depending on the degree of polymer-induced damage created in the core samples, fluids containing the MSB offered the most consistent regained permeability. The laboratory-scale study shows that the MSB is functional for both polymer damage mitigation and acts as a performance booster for the FR, allowing a more economical friction reducer to be selected for slickwater fracturing. In field applications, including the MSB in the fracturing fluid resulted in increased oil production volumes and/or a reduced need for remedial operations throughout the early life of the well. The results of this study show that by properly utilizing the friction flow loop and coreflood laboratory-scale experiments, an optimized MSB can be selected for hydraulic fracturing operations at the field scale. By selecting a flowback surfactant formulation that also increases friction reducer performance, a lower friction reducer dosage or a more economical friction reducer can potentially lead to operational savings at the field scale.

Impact of Pyrite Oxidation on the Pore-Structure Characteristics of Shale Reservoir Rocks under the Interaction of Fracturing Fluid.

Hydraulic fracturing combined with horizontal drilling is widely used to develop shale gas resources, and huge amounts of fracturing fluid are injected into shale reservoirs. However, the fracturing fluid is ineluctably retained in reservoir rocks after fracturing, resulting in the alteration of shale pore systems and further affecting the hydrocarbons production efficiency. In this work, two types of shales with different pyrite contents, namely, pyrite rich (PR, Niutitang Formation) and pyrite poor (PP, Xiamaling Formation), were emphasized to illustrate the effect of pyrite oxidation on pore structure after fracturing operation. Slickwater fracturing fluid was used to treat the shale samples for a period of 3 days, under the condition of 100 °C and 50 MPa. The field emission scanning electron microscopy (FE-SEM) and X-ray diffraction (XRD) were utilized to determine the surface morphology and mineral composition. The low-temperature N2 adsorption was performed to quantify the pore structure. The results showed that the pyrite oxidation induced the dissolution of both the pyrite and calcite and generated many dissolution pores for the pyrite-rich shale after slickwater treatment. The mineral dissolution led to an increase in the number of mesopores, enlarged the total specific surface area (TSSA) and total pore volume (TPV), and strengthened the pore-structure complexity. On the other hand, the pyrite-poor shale only experienced clay swelling after slickwater treatment. Its pore surface roughness and pore-structure complexity degraded with the loss of nanopores and the reductions in TSSA and TPV. The results of this study enhance the understanding of the impact of pyrite oxidation on the pore structure and provide new insight into the optimization of fracturing operation conditions based on shale’s mineral composition characteristics.

Optimizing Composition of Fracturing Fluids for Energy Storage Hydraulic Fracturing Operations in Tight Oil Reservoirs

Energy storage fracturing technology is a technical means by which oil displacement fluid is injected into the reservoir before the traditional hydraulic fracturing and subsequent implement fracturing. It provides a good solution for developing tight oil reservoirs. The efficiency of this technology significantly depends on the injection performance of the fracturing fluid, and the ability of its liquid phase to penetrate the formation. According to the needs of energy storage fracturing, four surfactants were selected. Then, based on the performance evaluation of the four surfactants, the compositions of two surfactant systems were determined. The performance of slickwater fracturing fluids for energy storage hydraulic fracturing was evaluated. The mechanism of tight oil displacement in energy storage hydraulic fracturing was analyzed. The results showed that the compositions of oil–displacement agents 1 and 2 for energy storage fracturing were successfully acquired. The performance of oil–displacement agent 2 was slightly better than that of oil–displacement agent 1 at a concentration of 0.25 wt%. The defined composition of the fracturing fluid met requirements for energy storage hydraulic fracturing. It was demonstrated that the tight oil in small pores was effectively substituted by the fracturing fluid, and subsequently aggregated in the large pores. The tight oil displacement ratio increased with an increase in temperature, and the difference among the tight oil displacement ratios of tight sandstone cores increased with increases in their permeability differences.

Study on the Effect of Fracturing Fluid on the Structure and Mechanical Properties of Igneous Rock.

Igneous rock oil and gas reservoirs have great development potential. Hydraulic fracturing is an important means for the development of these reservoirs. In the process of fracturing and increasing production, fracturing fluid is prone to a hydration reaction with clay minerals in igneous rock, and then, the structure and mechanical properties of the igneous rock are changed, affecting increased production. Therefore, it is necessary to establish a systematic water–rock reaction experiment method to understand the influence of fracturing fluid on the structure and mechanical properties of igneous rocks and to optimize the fracturing fluid system of igneous rock reservoirs. In this experiment, four solutions were used: slickwater, guar fracturing fluid, 2% KCl aqueous solution, and 4% KCl aqueous solution. Acoustic testing, porosity and permeability testing, XRD analysis, micro-CT scanning, and displacement experiments were performed. The influence of different fracturing fluids on the structure and mechanical properties of igneous rocks was studied. Igneous rock samples with a permeability of 0.05–0.1 mD and average porosity of 7–14% were used. The results show that all four liquid systems will reduce the permeability, Young’s modulus, and brittleness index and increase the porosity and Poisson’s ratio of the rock after fracturing. Among them, the permeability damage rate is as high as 37.37%, which may be related to the plugging of pores with solid residues in the gel breaking liquid; CT results show that there are microcracks in the rock, which increase over time, up to 13.54%. The brittleness index decreases. Among the fluids, the influence of slickwater on the rock brittleness index is the smallest, no more than 5%. Guar gum had the greatest effect on the Gel breaking liquid, up to 58%. One of the reasons for the increase in porosity is that adding a clay stabilizer composed of inorganic salts and organic cationic polymers to the slickwater fracturing fluid can effectively reduce the damage caused by the fracturing fluid to the rock during the fracturing process and can reduce the maximum by 50%. This paper can clarify the damage law of fracturing fluid systems to igneous rock reservoirs and provide the theoretical basis for the hydraulic fracturing of igneous rock reservoirs.

Ten years of gas shale fracturing in China: Review and prospect

The first fractured shale gas well of China was constructed in 2010. After 10 years of development, China has become the second country that possesses the core technology of shale gas development around the world, realized the shale gas fracturing techniques from zero to one and from lagging to partially leading, and constructed the fracturing theory and technology system suitable for middle–shallow marine shale gas exploitation. In order to provide beneficial guidance for the efficient exploitation of shale gas in China in the future, this paper comprehensively reviews development history and status of domestic fundamental theories, optimized design methods, fluid systems, tools and technologies of shale gas fracturing and summarizes the research results in fundamental theories and optimized design methods, such as fracturing sweet-spot cognition, fracture network propagation simulation and control, rock hydration and flowback control, and SRV (stimulated reservoir volume) evaluation and characterization. The development and application of slick-water fracturing fluid system and new fracturing fluid with little or no water is discussed. The development and independent research & development level of multi-stage fracturing tools are evaluated, including drillable composite plug, soluble plug, large-diameter plug and casing cementing sleeve. The implementation situations of field technologies and processes are illustrated, including the early conventional multi-stage multi-cluster fracturing and the current “dense cluster” fracturing and temporary plugging fracturing. Based on this, the current challenges to domestic shale gas fracturing technologies are analyzed systematically, and the development direction of related technologies is forecast. In conclusion, it is necessary for China to continuously research the fracturing theories, technologies and methods suitable for domestic deep and ultra-deep marine shale gas, terrestrial shale gas and transitional shale gas to facilitate the future efficient development of shale gas in China.

Investigation on the microscopic damage mechanism of fracturing fluids to low-permeability sandstone oil reservoir by nuclear magnetic resonance

Hydraulic fracturing has become an essential stimulation treatment for improving the development efficiency of low-permeability oil reservoirs. However, fracturing fluid inevitably causes reservoir damage. This study proposed a combined method of microscopic and macroscopic experiments to investigate the nature of formation damage of fracturing fluid by quantifying its influence on porosity, permeability, and pore structure. Nuclear magnetic resonance technology combined with core flooding test and parallel sample comparison method was applied to quantitatively evaluate the damage degree and identify the main damage types of hydroxypropyl guar (HPG) fracturing fluid and slickwater fracturing fluid. The microscopic damage mechanisms of these fracturing fluids were analyzed by thin section petrography, X-ray diffraction, rate-controlled mercury intrusion, scanning electron microscopy, and wettability tests. The results show that the total permeability damage degree of HPG fracturing fluid filtrate is 30.43%, of which water sensitivity, water lock, and macromolecule adsorption account for 6.06%, 23.26%, and 1.11%, respectively. Water lock is the major damage factor. Regarding the damage of slickwater fracturing fluid filtrate, water sensitivity causes the severest damage, corresponding to 39.08% of core permeability loss, whereas macromolecule adsorption and water lock contribute 13.21% and 0.97%, respectively. Water sensitivity damage causes reduced porosity, decreased permeability, and narrower pores, resulting from hydration, swelling, dispersion and migration of clay minerals. Water lock damage increases the movable pore volume, decreases the permeability, increases the pore radius, decreases the throat radius, and increases the pore throat ratio, which increases the flow resistance to the oil phase. The magnitude of water lock damage is closely related to the surfactant content and performance, rock wettability, and pore throat radius ratio. Macromolecule adsorption damage leads to a decrease in permeability, a reduction in the number of large pores, an increase in the number of small throats, and an increase in the pore throat radius ratio due to the absorption and retention of macromolecules on the surfaces of the pores and throats. Increasing the flowback volume of slickwater fracturing fluid can recover part of the macromolecule absorption damage. This research can provide a reliable reference for the optimization of fracturing fluid performance, enhancement of the fracturing effect and reservoir protection of low-permeability reservoirs.

Probing the mechanism of external fluids invasion of nanopores in fractured tight sandstone reservoir

The oilfield development process is accompanied by reservoir damage, which affects the reservoir permeability and reduces production. In this study, the mechanism of external-fluid invasion was analyzed to maintain oil-well productivity. The characteristics of the damage caused by external fluids to tight sandstone reservoirs were examined via scanning electron microscopy and high-pressure mercury-invasion experiments. Then, seepage models for fluids in the nanopores of tight sandstone reservoirs were established to investigate the effects of the natural fracture parameters and fluid properties on the seepage characteristics and damage mechanism of fractured tight sandstone reservoirs. The results indicated that the damage rates of water-based drilling fluid, oil-based drilling fluid, guar-gum fracturing fluid, and slick-water fracturing fluid for the natural core of tight sandstone are 53.20%, 33.87%, 23.64%, and 19.10%, respectively. The proportion of nanopores in fractured tight sandstone reservoirs ranges from 44.62% to 62.45%. The invasion of external fluids leads to a reduction in the permeability as well as the number of microfractures and their lengths. The changes in permeability barely affect the seepage characteristics of the fluid in the nanopores. The reductions in the lengths and number of microfractures change the connectivity of the entire flow space, affecting the seepage characteristics. The effect of the lengths of the microfractures is more significant than that of the number of microfractures. Additionally, the invasion speed of the external fluids has the most significant effect on the seepage characteristics. A higher viscosity of the external fluids corresponds to less damage to the nanopores. Drilling fluid causes less damage to nanopores than fracturing fluid does. The recovery of fractured tight oil reservoirs with nanopores can be enhanced by reducing the degree of external-fluid invasion.

Influence Factors of Multifunctional Viscous Drag Reducers and Their Optimization for Unconventional Oil and Gas Reservoirs.

Owing to the problems of guar gum fracturing fluid and conventional slickwater fracturing fluid systems in hydraulic fracturing of tight oil reservoirs, such as bad fracture network capacity, high damage, and low sand-carrying performance, researchers are actively looking for new alternative fracturing fluids. This study takes four commonly used additives for hydraulic fracturing of tight oil and gas reservoirs in western China, including the conventional polyacrylamide friction reducer EM30S, bioglue, thickener CHS-1, and high-viscosity friction reducer HVFR-1. By testing the water solubility, rheological properties, drag reduction, sand-carrying performance, imbibition oil displacement effect, and residue content of the four additives, the best additives suitable for hydraulic fracturing of tight oil and gas reservoirs were selected, and a set of indoor evaluations and the experimental method of screening hydraulic fracturing additives for tight oil and gas reservoirs were established. The research results show that the high-viscosity slickwater system composed of CND + HVFR-1 is more suitable for hydraulic fracturing of tight oil and gas reservoirs. Compared with the other three types of additives, CND + HVFR-1 fracturing fluid has good water solubility, and the dissolution time is less than 30 s. Therefore, in order to save construction time, the CND + HVFR-1 high-viscosity slickwater system is first recommended for field application. The research results of rheological properties show that although the apparent viscosity of high-concentration HVFR-1 + CND is low, the cross value of G′ and G″ is the smallest (0.006 Hz) and the elastic modulus is the largest (4.554 Pa) corresponding to 1 Hz. HVFR-1 + CND has better sand-carrying performance when used as a sand-carrying liquid. CND + HVFR-1 not only achieves a friction reduction rate of more than 60% but also has the effect of imbibition oil displacement to improve oil recovery; it can easily break gels, and its low residue content can ensure rapid flowback after construction is completed, and the lower residue content also causes the least damage to the reservoir. At the same time, the establishment of this evaluation method provides a certain reference for other researchers who select fracturing fluids for tight oil and gas reservoirs.

Progress of Development and Application of Drag Reduction Agents for Slick-Water Fracturing

Fracturing technology is the key technology of shale oil and gas exploitation in the United States. The key of hydraulic fracturing lies in the formulation of fracturing fluid, which can improve the permeability of shale gas layer, reduce pumping resistance, optimize production conditions, reduce strata damage and other purposes. Slick-water is widely used in water-based fracturing for unconventional oil and gas exploitation, which can reduce the friction resistance. As the core of the slickwater fracturing fluid, the friction reducer determine the fluid’s performances. Combining with the related literature at home and abroad, this paper analyzes the mechanism of friction reducer, introduces the research and application progress of natural polysaccharide, surfactant and polyacrylamide. It is considered that both the instant powder polymer and W/W dispersion polymer have great application potential. The friction reducer with high-efficiency sand-carrying and salt resistance is the focus of future research.

Enhanced regained permeability and fluid flowback from tight sandstone and carbonate oil reservoirs with unique flowback chemistry

AbstractLarge amounts of aqueous‐based fluids used in hydraulic fracturing of tight formations are not fully recovered immediately after treatment, resulting in increased water saturation, water blockage, clay swelling, reduced relative permeability, and long‐lasting formation damage that impedes production. To enhance flowback fluid recovery, nano‐emulsion based flowback aids were developed for oil‐bearing sandstone and carbonate formations. The flowback aids were formulated using a blend of high‐temperature stable ester‐based solvents, alcohols, and surfactants to form optically clear nano‐emulsions. All the developed flowback aids demonstrated low surface tension (22–30 mN/m) and interfacial tension (<6 mN/m), which is necessary for reducing capillary pressure. The particle size of the nano‐emulsions was found to be 5–15 nm. The flowback aids were able to prevent the formation of the emulsion with crude oil. It has been found that nano‐emulsions formulated using non‐ionic and anionic surfactants worked better for sandstone, whereas non‐ionic and cationic surfactant‐based formulations worked better for carbonate. These formulations not only provide quick aqueous fluid displacement in column tests but also greatly enhance the rate of oil flow in core flow experiments conducted with broken slickwater fracturing fluids. It was determined that in the absence of a flowback aid, the regained permeability was around 40%, whereas with flowback aids it was increased to 65%–75%. The paper demonstrates the effectiveness of flowback enhancers to quickly recover the injected aqueous fracturing fluid, thereby reducing water saturation, which in turn enhances productivity, and shows the benefit of applying chemistry for low permeability oil reservoirs.

Fracturing fluid retention in shale gas reservoir from the perspective of pore size based on nuclear magnetic resonance

Shale gas development requires large-scale hydraulic fracturing, but a large amount of the slickwater fracturing fluid injected into the reservoir cannot be brought back to the surface. In this study, spontaneous imbibition and reverse displacement experiments were carried out on shale core to simulate fracturing fluid imbibition into the matrix during the fracturing stage of a shale gas reservoir and the displacement of fracturing fluid by reservoir gas during the flowback stage. With the help of low-field nuclear magnetic resonance technology to dynamically monitor the volume change in the liquid in the shale core throughout the entire process, the volume distribution of the liquid in the pores of the different scales were calculated at each time. The reason for the low flowback efficiency of shale gas reservoirs from the perspective of pore size was studied, and the influence of the fracturing fluid’s salinity on the flowback process was analyzed. The research results show that there is a certain pore size threshold in the shale gas reservoir. When the fracturing fluid enters pores smaller than this size threshold, it is difficult to displace it during flowback. The relative volume of the fracturing fluid entering the pores smaller than the size threshold determines the flowback efficiency. The higher the proportion of this part of the fracturing fluid to the total volume, the lower the flowback efficiency. Using a fracturing fluid with a higher salinity can reduce the volume of liquid entering the pores less than the pore threshold to a certain extent, thereby increasing the flowback efficiency. This research is important for gaining a better understanding the low flowback efficiency in shale gas reservoirs and for evaluating the safety of groundwater resources.

Synthesis and evaluation of new slickwater fracturing fluid for drag reduction

Currently, slip water fracturing fluid is widely used as a fracturing fluid for shale reservoirs. Non-ionic hydrophobic modified polyacrylamide (HM-PAM), partially hydrolyzed water-soluble hydrophobic associating polyacrylamide (HMWSP) and partially hydrolyzed anionic polyacrylamide (HPAM) solutions were modeled by molecular simulation software Materials Studio. The radius of gyration (Rg) and mean square displacement (MSD) of HPAM and HMWSP at different NaCl concentrations were calculated. From the simulation results, compared with HPAM and HM-PAM, HMWSP had a larger radius of gyration, a larger intrinsic viscosity number, and a larger hydrodynamic size, which would produce better drag reduction effects. Using acrylamide (AM), acrylic acid, 2-acrylamido-2-methylpropanesulfonic acid (AMPS) as basic raw materials, a hydrophobic associative drag reducer (HMWSP) was prepared by an inverse emulsion method. Infrared spectroscopy (FIIR) was used to characterize the synthesized products, and fluorescence chromatography was used to test the association of polymer solutions. Using a friction tester to test the drag reduction performance of the drag reducer, HMWSP has good resistance to salt reduction. HMWSP had good resistance reducing salt performance.

Research on the Characteristics of Microscopic Damage to Different Pore Types by Slippery Water Fracturing Fluid in the Chang Member Tight Sandstone Reservoir, Ordos Basin, NW China

This paper examines the damage caused by slickwater fracturing fluid to the microscopic pore structure of tight sandstone in the Chang 7 member in the Ordos Basin. A submicron CT in situ displacement system was used to analyze and graphically represent changes in pores in core samples following fracturing fluid damage. The results show the following: (1) the damage caused by slickwater fracturing fluid to tight sandstone fractures mainly occurs in the early stage of fluid incursion. The damage is characterized by a decrease in the effective pore volume, increase in the number of pores, and insignificant subsequent damage. The main causes of pore damage by slickwater fracturing fluid are retention of slickwater in the liquid phase and hydration swelling of clay minerals in the pores. (2) After the high pressure intrusion of slickwater fluid, the pore size of large-size intergranular pores increases, and there is no obvious damage after water flooding. However, fractures and small dissolution pores in the cores are the main areas of fluid retention after fracturing fluid invasion due to their small flowing radius and complex structure. These are the locations where damage mostly occurs.

Low-carbon hydrocarbon fracturing fluid with fast cross-linking rate based on n-hexane/n-octane: synthesis and properties

ABSTRACT The use of slick-water fracturing fluids has been greatly limited owing to the shortage of water and transportation difficulties in some areas. Serious formation damage occurred in the shale gas reservoirs with low porosity and permeability during the slick-water fracturing with large amounts of water. A fast cross-linking waterless fracturing fluid using the n-hexane/n-octane low-carbon hydrocarbons was prepared in this work. Firstly, a polyphosphate intermediate was synthesized by triethyl phosphate reacting with phosphorus pentoxide, which then reacted with a mixed alcohol of n-butanol, n-octanol, and dodecanol to get the dialkyl phosphate (named as gelling agent). Ferric sulfate, ethylene glycol, sodium citrate, sodium edetate were used to prepare a composite iron-based cross linker with an excellent gelation time and gelation performance, which was composed of 30% ferric sulfate, 10% glycol, 11% trisodium citrate, 9% sodium edetate, and 30% deionized water. By optimizing the ratio of gelling agent to cross linker and the content of gelling agent, an anhydrous fracturing fluid formulation based on n-hexane/n-octane was prepared: n-hexane/n-octyl (mass percent 100%) + gelling agent (1.6%-1.8%)+cross linker (0.6%-0.8%) + gel breaker (0.6%-1.0%).The n-hexane and n-octane fracturing fluids can be used in the formation temperature of 60°C, and 100°C, and the viscosity for the fracturing fluid was 178 and 230 mPa.s under the shear rate of 170 s−1 and shear time for 90 min. The sedimentation velocity of a single ceramsite was 0.2780 cm/min, and the sedimentation velocity of the mixed ceramsite was 0.0022 cm/min, which fully satisfied the fracturing suspension performance. The crushing time of n-hexane and n-octane fracturing fluid was controllable (5–10 h), and the gel breaking effect was excellent (less than 2 mpa.s).

Theory and Application of Pseudo-Reservoir Hydraulic Stimulation for Coalbed Methane Indirect Extraction in Horizontal Well: Part 2—Application

This paper provides details of the application of pseudo-reservoir stimulation technique to a U-shaped coalbed methane (CBM) well (i.e., Well ZU-01) in Jiaozuo mining area. Multistage hydrojet fracturing and channel fracturing were adopted to promote fracture network forming and fracture vertical propagation in pseudo-reservoir. The results of the pseudo-reservoir stimulation indicate that influenced by the reservoir lithology and coal structure between the horizontal well and coal seam, the fractures at the first stimulation stage only propagated in the pseudo-reservoir. However, the stimulations at the second, third and fourth stages achieved integrated stimulation of pseudo-reservoir and coal seam. The gas production rate of Well ZU-01 was only 1000 m3/d in the stable production stage. However, through negative-pressure extraction in the mine roadway, the joint gas extraction rate from the underground roadway and Well ZU-01 reached 6000 m3/d. After 450 days of extraction, the cumulative gas production was 15.55 × 105 m3, and the CBM extraction rate reached approximately 50%, indicating that good pseudo-reservoir stimulation and gas pre-extraction effects were achieved. The results of the adsorption/desorption and wettability tests show that water blocking damage caused by the slickwater fracturing fluid severely hindered the gas desorption and production processes, which was the main reason for the low gas production of the well. However, the water blocking damage was mitigated through negative-pressure extraction, resulting in a significant increase in CBM production.

Effect of slick-water fracturing fluid on the frictional properties of shale reservoir rock gouges

“Slick-water” fluids routinely used in hydraulic fracturing contain friction-reducing agents and clay-stabilizers that may influence on the strength and stability of reservoir rocks and preexisting faults. We performed laboratory measurements on four powered shale reservoir rocks with different carbonate contents recovered from Longmaxi Formation in Sichuan Basin of China, to examine the potential effects of slick-water fracturing fluids on gouge friction. Velocity-stepping experiments were conducted at shear velocities of 0.122 and 1.22 μm/s, a confining pressure of 60 MPa, a pore fluid pressure of 30 MPa and a temperature of 90 °C, typifying the ~ 2.3 km depth of producing reservoirs. Two pore fluids, i.e., DI water and acidic slick-water, were selected to probe the chemical effects of fracturing fluids. Results show that the frictional properties of studied shale gouges are not only controlled by both the phyllosilicate and carbonate contents, but also affected by slick-water. Acidic slick-water dissolves carbonates from the shale gouges and this mineralogic alteration exerts a negligible influence on frictional strength μ but increases the frictional stability (a − b), regardless of the mass of carbonate removed. Clay stabilizers are shown to exert minimal influence on either frictional strength or stability at high confined stresses, possibly due to the unchanged mineral contacts. Our results imply that the acidity of slick-water fluids can impact the frictional responses in carbonate-rich fault gouges through corrosion and dissolution, and have important implications in understanding the chemical effects from the fracturing fluids on subsurface fault stability during shale reservoir stimulation.

Research and Application of an Environmental-Friendly Low-Damage and High Salt-Resistance Slick Water Fracturing Fluid System

The Sulige gas field is a typical low-pressure low-permeability tight sandstone gas reservoir. The reservoir has poor seepage capacity, strong heterogeneity, high mineralization of formation water and extremely scarce water resources on the site. These unfavorable factors have brought great difficulties to the on-site mining process. Now, a nano-composite green environmental protection slick water fracturing fluid system CQFR can be quickly dissolved because of the larger specific surface area, and the small molecular size makes the damage to the reservoir less than 5%, and the average drag reduction effect can reach more than 73%. It can quickly and well dissolve and maintain performance under high salinity conditions and fracturing flowback fluids. It responds well to the complex reservoir conditions on the construction site and makes the flowback fluid recyable, which greatly reduces the consumption of water resources on the construction site and effectively improves the construction efficiency and economic benefits.

Shale Sector’s Switch to Slickwater Highlights Compatibility Issues with Produced Water

Switching from guar-based gels to slickwater fracturing fluids has delivered one of the biggest cost wins for the North American shale sector. First movers began the transition after guar prices spiked 300% in 2013. Shale producers have since reported they are trimming 20–35% from their completion chemical budget by using slickwater over the alternatives, while also reducing the pressure pumping power needed to move proppant into a tight reservoir. The replacement of gel treatments is possible thanks to the comparably low price of the key ingredient in slickwater recipes: polyacrylamide, or what some refer to as a high-viscosity friction reducer (HVFR). Beyond chemical savings, operators have experienced positive production results, too—adding fuel to the relatively quick adoption of slickwater treatments across every major play in North America. But since HVFR is a newly commoditized chemical with dozens of suppliers in North America and China, opera-tors are being advised to not let price be the sole deciding factor in which variety they pump downhole. A number of recent industry studies argue that aggressive screening is needed to make the right choice—especially if an operator is recycling or reusing produced water. “As a product, friction reducer can be different from company to company,” said Mohammed Ba Geri, a petroleum engineering PhD candidate at Missouri University of Science and Technology. “Most types work well with fresh water, but by increasing the salinity or changing the [total dissolved solids (TDS)] of the water, we see that everything changes.” Ba Geri spent more than 2 years running tests on about 30 different commercial friction reducers as part of a wider research effort that is chronicled in half a dozen SPE papers. He shared the latest of these at the recent Unconventional Resources Technology Conference (URTeC) in Denver. The variations in performance that Ba Geri cites, including in one of the papers he delivered at the conference (URTeC• 99), represent an important consideration given that more shale producers are shifting away from fresh water and toward using produced water for hydraulic fracturing. This development is being driven by a mix of regulatory, sustainability, and economic factors. By opting for produced water, distinguished by its high-salinity and TDS content, operators are essentially opting out of using linear or crosslink gels since they react so poorly to the lower-quality fluid. Per industry research, producers should also be careful in assuming this same risk is completely abated by taking the slickwater route. Friction reducers tend to hold up much better in a high-salinity and high-TDS environment. However, Ba Geri said that when the salinity or TDS rise above certain ranges, “all the polymer chains will break, and the viscosity and elasticity of that type of fluid will be less effective.” As the reaction takes place, globs of material will coagulate and reduce the ability of the friction reducer to carry proppant from the wellbore into the reservoir. Operationally, the effects can increase well costs quickly and reverse the advantages of using slickwater as stimulation rates drop, which in turn, would need to be offset with more pumping horsepower.

Dual-Polymer Hydraulic-Fracturing Fluids: A Synergy Between Polysaccharides and Polyacrylamides

Summary As exploration for oil and gas continues, it becomes necessary to produce from deeper formations, and to meet the challenge of low permeability and higher temperatures. Unconventional shale formations are addressed with slickwater fracturing fluids, owing to the shale's unique geomechanical properties. On the other hand, conventional formations require crosslinked fracturing fluids to properly enhance productivity. Guar and its derivatives have a history of success in crosslinked hydraulic–fracturing fluids. However, they require higher polymer loading to withstand higher–temperature environments. This leads to an increase in mixing time and additive requirements. Most importantly, as a result of high polymer loading, they do not break completely and thus generate residual–polymer fragments that can plug the formation and significantly reduce fracture conductivity. In this work, a new hybrid dual–polymer hydraulic–fracturing fluid was developed. The fluid consists of a guar derivative and a polyacrylamide–based synthetic polymer. Compared with conventional fracturing fluids, this new system is easily hydrated, requires fewer additives, can be mixed “on the fly,” and is capable of maintaining excellent rheological performance at low polymer loadings. The polymer mixture solutions were prepared at a total polymer concentration of 20 to 40 lbm/1,000 gal at volume ratios of 2:1, 1:1, and 1:2. The fluids were crosslinked with a metallic crosslinker and broken with an oxidizer at 300°F. Testing focused on crosslinker/polymer–ratio analysis to effectively lower loading while maintaining sufficient performance to carry proppant at this temperature. A high–pressure/high–temperature (HP/HT) rheometer was used to measure viscosity, storage modulus, and fluid–breaking performance. An HP/HT aging cell and HP/HT see–through cell were used for proppant settling. Fourier–transform infrared (FTIR) spectroscopy, Cryo scanning electron microscopy (Cryo–SEM), and an HP/HT rheometer were also used to understand the interaction. Results indicated that the dual–polymer fracturing fluid was able to generate stable viscosity at 300°F and 100 s−1 as well as generate a higher viscosity compared with the individual–polymer fracturing fluid. Also, properly understanding and tuning the crosslinker to the polymer ratio generated excellent performance at 20 lbm/1,000 gal. The two polymers formed an improved crosslinking network that enhanced proppant–carrying properties. This fluid also demonstrated a clean and controlled breaking performance with an oxidizer. Extensive experiments were pursued to evaluate the new dual–polymer system for the first time. This system exhibited a positive interaction between the polysaccharide and polyacrylamide families and generated excellent rheological properties. The major benefit of using a mixed–polymer system is reduced polymer loading. Lower loading is highly desirable because it reduces material cost, eases field operation, and potentially lowers damage to the fracture face, proppant pack, and formation.