Clean Fracturing Research Articles

Damage mechanism and protection measures of a coalbed methane reservoir in the Zhengzhuang block

The Zhengzhuang block is an important development area in Qinshui basin in Shanxi Province, China. In this block, the amount of gas produced in many wells is not consistent with that predicted according to data concerning reservoir properties, even after fracturing (i.e., with clean fracturing fluid) or the implementation of horizontal boreholes through the reservoir. To investigate the damage mechanism, mineral composition and microstructures were analyzed using X-ray diffraction, scanning electron microscopy and thin section analysis; pore parameters were determined by a mercury intrusion test; hydration properties were tested by a dispersion and expansion experiment; the contact angle of water on reservoir cores was measured to analyze the wettability; and the sensitivities of NO. 3 coal cores were analyzed according to core flow experiments and an isothermal adsorption test. Based on the test results, the factors causing damage to the coalbed methane (CBM) reservoir in the NO. 3 coal seam included serious water blocking and stress sensitivity, followed by velocity sensitivity, water sensitivity, alkali sensitivity and acid sensitivity. To eliminate water blocking, an agent to adjust core wettability was chosen. Moreover, a new cheap inhibitor was provided to reduce core water sensitivity. Using the selected wettability adjustment agent, the inhibitor and other necessary additives, drilling fluid and fracturing liquid systems were optimized, causing considerably less damage to CBM reservoir cores, both in the wet and dry states, according to the results of core permeability tests. Compared with surface water and drilling mud applied during drilling in the gas field of the Zhengzhuang block, the optimized drilling fluid and fracturing liquid can promote methane desorption by reducing the Langmuir volume and increasing the Langmuir pressure of coal, thereby increasing gas production and recoverability of the CBM reservoir.

Research on and Application of Clean Fracturing Fluids in Coal-Bed Methane

The development history of fracturing fluids is reviewed, the compositions and action mechanisms of the clean fracturing fluid systems used currently are analyzed, the recent research and application of the clean fracturing fluids in coal—bed methane production are summarized, and the development trend of clean fracturing fluids is presented in this paper.

Self-assembly networks of wormlike micelles and hydrophobically modified polyacrylamide with high performance in fracturing fluid application

Dynamic rheology and steady shear viscosity of an aqueous salt solution of 2 wt% viscoelastic gemini surfactant 1,2-N,N′-bis (dimethyloctadecyl) ethene ammonium bromide and its mixture with low molecular weight hydrophobically modified polyacrylamide (HMPAM) were investigated. The solution of surfactant in the presence of potassium chloride exhibited typical Maxwellian fluid behavior with a single stress relaxation time, indicating the formation of transient networks of entangled wormlike micelles (WLMs). Polymer profoundly affected the rheological properties of WLMs. The WLMs/HMPAM system demonstrated higher plateau modulus and zero-shear viscosity than the single WLMs system by self-assembling into common networks which was identified by scanning electron microscopy morphology. In contrast to the WLMs system, the WLMs/HMPAM system exhibited better temperature and shear resistance while retaining complete responsiveness to hydrocarbons. Based on the fracturing fluid application evaluation, the WLMs/HMPAM system had an applicable temperature, which was 30 °C higher than the WLMs system, and the core damage rate showed that the WLMs/HMPAM system was very promising in clean fracturing fluid application.

Research and application of a novel strong acidic clean fracturing fluid

Clean fracturing fluids used in the oil-fracturing field are basically alkaline currently. The insoluble precipitate which produced from the reaction of strong alkaline liquid and reservoir formation will cause serious injury to the reservoir's permeability, and the dirt onthe surface of construction equipment is difficult to remove. The strong acidic clean fracturing fluid described here is a novel clean fracturing fluid for proppant-fracturing. It is a viscoelastic solution formed by surfactant and counter ion salt in acid solution, whichcan work in strong acid condition(pH2). It can carry and transport proppant into the specified formation location effectively in the reservoir formation up to 80°C. It has excellent shear-resistant performance and sand-carrying properties, and erode-inhibiting effectalso. The demulsification rate can reach to 90% and more. The novel acidic clean fracturing fluid will break completely when it have encountered hydrocarbons or water but no permanent damage to the formation was caused. The fracturing fluid has both etching effectand proppant-fracturing effect to calcium sandstone reservoir yield significantly. The novel acidic clean fracturing fluid has been successfully applied to the Daqing Oilfield and got remarkable results. Increasing production reached to 9 times for single well, and thestimulation ratio is 2–4 times to ordinary fractured wells.

Preparation and Property Evaluation of Anionic Clean Fracturing Fluid

An anionic surfactant clean fracturing fluid was synthesized and its main performance was studied. The viscosity of fracturing fluid increased with increasing dosage of anionic surfactant. And the viscosity of fracturing fluid increased first, and then decreased with increasing concentration of KCl. The viscosity reached maximum 360 mPa•s when the KCl content is 2.7%. The results showed that the fracturing fluid had best temperature resistance and shear resistance performance under the condition of 100°C and at the shearing rate of 170 s-1. The sedimentation velocity of sand in the fracturing fluid are about 11.124, 18.840 mm/min at the temperature of 80°C and 120°C respectively. It indicated that the fracturing fluid has a better sand-carrying performance. The viscosity of fracturing fluid decreased below 5 mPa•s during 70 minutes when the dosage of kerosene was 3%, and the surface tension of the breaker fluid is 26.10 mN/m while the interfacial tension is 0.73mN/m. The low surface tension can meet the requirements of operation. The damage rate to the core is 7.65% and the fracturing fluid has lower damage to core than guar gel.

Development of Hydraulic Fracturing New Technique

Introducing several new types of fracturing fluid which consist the low damage fracturing fluid (HPF), a new clean fracturing fluid (EFAS), alcohol radical fracturing fluid, summarizing several new technology such as floating prop pant fracturing technology, end sand strip controlling seam height fracturing technology, hydraulic injection layer fracturing technology and seam height controlled technology during fracturing, analyzing the corresponding fracturing Modification Techniques of different reservoir types. Developing the hydraulic fracturing technology for their oil fields based on the study at home and abroad is proposed.

“Green” anionic wormlike micelles induced by choline

In such application fields as oilwell stimulation, tertiary oil recovery and drug release, environmental-friendly wormlike micelles are largely preferred. The present work reports a “green” wormlike micellar system formed by a bio-based anionic surfactant, sodium erucate (NaOEr), and a biodegradable hydrotrope, choline. The micellar solutions were examined by means of rheology and cryo-TEM observation. Besides possessing lower toxicity, choline exhibits a stronger ability to induce micelle growth than tetramethylammonium, which is commonly used to promote the formation of anionic worms, and the choline–NaOEr system is more thermosensitive with increasing counterion concentration. These notable advantages enable the choline–NaOEr wormlike micellar system to find potential applications in biomedical areas and clean fracturing fluids.

Evaluation of Fracturing Results in Deviated Wellbores Through On-Site Measurements

Summary Four adjacent oil wells in the Kuparuk River oil field, with deviated angles of 6°5′, 24°6′, 27°, and 36°7′ from the vertical at the perforations, were analyzed with prefracturing tests. The total fluid volume for these tests varied from 645 to 840 bbl [103 to 134 m3] of either clean lease oil or water-based fracturing fluid at low to intermediate rates (up to 15 bbl/min [2.4 m3/min]). These wells Were subsequently fractured with proppant-laden fluid. A series of instantaneous shut-in pressures (ISIP's) was obtained for each well. ISIP's and fracturing pressures decreased with time in two of the four wells with a relatively high friction pressure at the end of the pumping. A radially propagating fracture from a point source of pressure explains this decreasing pressure with time. The elasticity theory predicts that a fracture in a deviated, cased wellbore should intersect the wellbore at one location. Only when the deviated wellbore azimuth is near that of the fracture orientation does the fracture sweep the entire perforated zone. This observation of the fracture orientation relative to the wellbore azimuth based on the pressure analysis is enhanced further by postfracture temperature surveys. It appears that only a relatively small volume of proppant could be displaced in a deviated wellbore. The degree of deviation, however, did not appear to be a major concern in the treatment size.

Improved Procedures for Injecting Radioisotopes During Fracturing Operations

The injection of sand-entrained radioisotopes at the latest time before fracturing fluid enters the wellbore minimizes personnel exposure to radiation, contamination of surface equipment, and hazards of transporting radioactive material. This paper presents design and operational details of the devices used for wellhead injection of radioisotopes, transportation considerations, disposal of leftover radioactive sand, closed-loop control of injection, and a comparison of the injection plan with the actual injection.

Factors Affecting Water Blocking and Gas Flow From Hydraulically Fractured Gas Wells

This paper demonstrates the combined effects of formation permeability damage and relative permeability damage in the invaded zone of a hydraulically fractured gas well. Study results indicate that the damaged zone permeability must be reduced by several orders of magnitude and the capillary pressure altered before a serious water block to gas flow will occur. Introduction To optimize profit from low-permeability gas reservoirs, well stimulation normally is required. In a majority of the cases, a long hydraulic fracture will provide the most efficient and economic means of stimulation. To create long hydraulic fractures, a large volume of fluid, mixed with additives and granular propping agents, must be pumped into the formation. Such treatments can be expensive and require extensive engineering effort. The fluid injected during the fracturing treatment will leak off into the formation and will reduce the relative permeability to gas in the invaded region. Near the fracture, the permeability to gas will be reduced to zero. After injection has ceased, imbibition will begin to alter the fluid distribution, and when production begins, the fracturing fluid will flow from the formation into the fracture. As the fracturing fluid is produced, the relative permeability to gas in the invaded zone will increase and gas will begin to flow into the fracture. In some cases, the injected fracturing fluid may reduce the formation permeability in the invaded zone. Such damage can be caused by clay swelling, precipitation of solids, or migration of released fines. In reality, all fracturing fluids, no matter how expensive, do some damage to the reservoir adjacent to the fracture. Using clean fracturing fluids that are compatible with the formation rock and the reservoir fluid helps minimize such damage. However, in some reservoirs, the injected fracturing fluid does not readily clean up and several months of production may be required before the maximum gas flow rate is achieved. In the most extreme cases, a complete water block to gas flow can occur. To effectively design a fracture treatment for a water-sensitive reservoir, it is essential to understand the basic reservoir mechanisms that govern flow between the fracture and the formation. Gas and water relative permeability, relative permeability hysteresis, capillary pressure, and reservoir damage all tend to complicate the analysis of reservoir flow in fractured formations. By considering the combined effects of the above parameters, it is possible to analyze a given reservoir and determine the cause of slow cleanup and reduced gas productivity.