195 results about "Tight gas" patented technology

The invention provides a method for testing a gas-water relative permeability curve by using a tight sandstone steady state method. The method comprises the following steps: preparing a stone core; preparing simulation stratum water; vacuuming till the simulation stratum water is saturated; connecting an experiment device and heating to experiment temperature; putting the stone core into the experiment device, pressurizing, releasing the pressure, testing the mass and the liquid phase permeability of the stone core; establishing irreducible water saturation; controlling the flowing speed of gas, and injecting the simulation stratum water at a relatively slow flowing speed, after the gas flow at an outlet is stable, increasing the flowing speed of liquid, and measuring a next point till displacement pressure meets the maximum set value and the flowing speed of the gas at the outlet is reduced to 0.1mL / minute, and terminating the experiment; according to improved phase permeability equations, calculating water saturation and relative permeability of different points. By adopting the method, two-phase permeation characteristics in the tight gas reservoir production process under stratum conditions can be simulated, the influence of the temperature on gas-water viscosity is taken into account, the influence of pressurization on the water content of the stone core is also taken into account, the irreducible water saturation and the relative permeability curve can be relatively accurate and reliable, and high-value data can be provided for gas reservoir production evaluation.

Provided is a method and composition for the in-situ generation of synthetic sweet spots in tight-gas formations. The composition can include nitrogen generating compounds, which upon activation, react to generate heat and nitrogen gas. The method of using the composition includes injecting the composition into a tight-gas formation such that upon activation, the heat and nitrogen gas generated

Subterranean formations, such as tight gas formations, may be subjected to hydraulic fracturing by introducing into the formation a fracturing fluid of an aqueous fluid, a hydratable polymer, a crosslinking agent and proppant. The fracturing fluid is prepared in a blender and then pumped from the blender into the wellbore which penetrates the formation. The fluid enters the reservoir through an entrance site. The apparent viscosity of the fluid decreases distally from the entrance site such that at least one of the following conditions prevails at in situ conditions:(a) the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the apparent viscosity of the fracturing fluid at the entrance site;(b) the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 15% of the apparent viscosity of the fracturing fluid at the entrance site; or(c) the apparent viscosity of the fracturing fluid is less than 10 cP within 15 minutes after being introduced through the entrance site.

Provided is a method and composition for the in-situ generation of synthetic sweet spots in tight-gas formations. The composition can include nitrogen generating compounds, which upon activation, react to generate heat and nitrogen gas. The method of using the composition includes injecting the composition into a tight-gas formation such that upon activation, heat and nitrogen gas are generated. Upon the generation of nitrogen gas and heat within the formation, microfractures are produced within the formation and the hydrostatic pressure within the reservoir is reduced to less than the reservoir fluid pressure, such that the rate of production of hydrocarbons from the formation is increased.

The invention relates to a numerical analysis method for dense gas multi-section volume fracturing horizontal well, comprising the following steps: step 1, establishing a geological structure model ofthe network fracture of the multi-section volume fracturing horizontal well; 2, establishing a heterogeneous geological body of fractured horizontal well network fracture; 3, establish a well test mathematical model of a compact gas multi-stage fracturing horizontal well base on that fracture network form; 4, carrying out numerical solution on a network fractured horizontal well test model by using a mixed element finite element method; 5, generating a multi-section volume fracturing horizontal well actual t well curve according to that well test data, and fitting the theoretical curve solvedby the model in the step 4 with the actual measurement curve to obtain the well test interpretation parameters. This method is of great significance to improve the interpretation accuracy of volume fracturing horizontal wells, to obtain the parameters of volume fracturing network and to evaluate the effect of volume fracturing. The invention has the characteristics of good well test curve fitting, accurate interpretation result, strong practicability and the like.

The invention relates to a nanometer emulsion type water control fracturing fluid for a tight gas reservation well and a preparation method of the nanometer emulsion type water control fracturing fluid. The nanometer emulsion type water control fracturing fluid is prepared by 0.3-0.5 part of amino silicon oil nanometer emulsion and 100 parts of water by weight. The preparation method comprises the following steps of: adding an emulsifying agent and a low-molecule alcohol into the amino silicon oil; uniformly mixing the emulsifying agent, the low-molecule alcohol and the amino silicon oil; adding an organic acid and some water; continuously stirring, then adding an electrolyte and the rest water, stirring until the phase is homogeneous, and then obtaining amino silicon oil nanometer emulsion. The preparation process mentioned in the invention is simple, the process is easy to control, and the nanometer emulsion type water control fracturing fluid obtained has hydrophobicity, obvious water control effect, low viscosity, small grain size, low surface tension and stable performance, so the nanometer emulsion type water control fracturing fluid is suitable for water control fracturing improvement of a near-water or high-water content tight gas reservation well.

The invention belongs to the field of gas field development research, and particularly relates to a method for evaluating the reproduction potential of water-flooded gas wells in tight gas reservoirs, comprising the following steps: according to the geology and development characteristics of water-flooded gas wells in tight gas reservoirs, determining the production resumption target; using analytic hierarchy process Establish a hierarchical structure model for evaluating the resumption potential of different water-flooded gas wells using the method; use the hierarchical structure model to construct a judgment matrix and determine the weight of each evaluation factor; use the fuzzy mathematics comprehensive evaluation method to formulate the evaluation grading standards for each index, and establish Target gas well comprehensive evaluation transformation matrix. According to the weight of each evaluation factor and the comprehensive evaluation transformation matrix of the target gas well, the fuzzy mathematical comprehensive evaluation calculation model of the target gas well is determined, and the comprehensive evaluation value of the resumption potential of the water-flooded gas well is obtained, and the optimal resumption sequence of the gas well is determined. The invention can obtain the pros and cons of each evaluation factor and the comprehensive evaluation of the recovery potential of water-flooded gas wells, and provides a scientific and effective method for the recovery of water-flooded wells in tight gas reservoirs.

Subterranean formations, such as tight gas formations, may be subjected to hydraulic fracturing by introducing into the formation a fracturing fluid of an aqueous fluid, a hydratable polymer, a crosslinking agent and proppant. The fluid enters the reservoir through an entrance site. The apparent viscosity of the fluid decreases distally from the entrance site such that at in situ conditions:(a) the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the apparent viscosity of the fracturing fluid at the entrance site;(b) the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 15% of the apparent viscosity of the fracturing fluid at the entrance site; and / or(c) the apparent viscosity of the fracturing fluid is less than 10 cP within 15 minutes after being introduced through the entrance site.