| CPC G01N 7/16 (2013.01) [G01N 15/0806 (2013.01); G01N 33/241 (2013.01)] | 6 Claims |
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1. A method for testing the gas loss amount which simulates a wireline coring process, characterized in that the method comprises the following steps:
providing a programmable temperature control constant temperature module, for simulating temperature changes in a wireline coring process; providing a simulated center pipe body, for constructing a simulated environment of the center pipe body being filled with drilling fluid or clean water; providing a simulated coring barrel, for drilling for and retaining a core sample, wherein the simulated coring barrel is provided at its bottom with a connecting rod which is connected to a sealing cover body for simulating the actual state of the coring barrel being hung and lifted, the simulated coring barrel is provided at its bottom with an elastic supporting body, the connecting rod is used to simulate the actual state of the coring barrel being hung and lifted, and the elastic supporting body is used to support and fix the core sample inside the simulated coring barrel; providing a gas injection control and recovery module, for gas injection, pressurization and vacuuming inside the simulated center pipe body; providing a liquid injection control and recovery module, for injecting water or simulated drilling fluid into the simulated center pipe body to construct a simulated drilling fluid or clean water environment inside the simulated center pipe body, and for removing and recovering the remaining liquid from the simulated center pipe body after the simulation is completed; providing a drainage and gas collection metering module, for metering the drainage and gas collection of the gas-water mixed fluid discharged from the simulated center pipe body;
determining a reservoir pressure, a reservoir temperature, a drilling and coring depth, a bottom hole pressure, a bottom hole temperature and a core lift time, based on existing geological evaluation data;
selecting a large rock sample to drill for a core sample and performing a gas tightness check of the testing device;
constructing a simulated liquid-phase filling environment before the wireline coring to determine the total occurrence amount of methane gas in the core sample; and
simulating the coordinated change process of liquid-phase pressure and temperature in lifting the core to a wellhead, to calculate the gas loss amount and the gas loss ratio in a simulated process of the core sample arriving at the wellhead;
wherein, the step of selecting a large rock sample to drill for a core sample and performing a gas tightness check of the testing device, comprises the following steps:
selecting a large rock sample, using the simulated coring barrel to drill into the large rock sample for the core sample, and then retaining the core sample in the simulated coring barrel, and placing the simulated coring barrel into the simulated center pipe body, with the connecting rod at the bottom of the simulated coring barrel connected to the sealing cover body, and with the core sample inside the suspended inverted simulated coring barrel in contact with the elastic supporting body at the bottom of the simulated center pipe body; using the sealing cover body to seal the simulated center pipe body, and connecting pipelines; and
turning on the programmable temperature control constant temperature module, setting a test temperature to the reservoir temperature level, turning on the gas injection control and recovery module to inject helium gas into the simulated center pipe body at a pressure level 1 to 2 MPa higher than the reservoir pressure, and turning off the gas injection control and recovery module with standing for 12 to 24 hours, and checking the gas tightness of the testing device;
wherein, the step of constructing a simulated liquid-phase filling environment before the wireline coring to determine the total occurrence amount of methane gas in the core sample, comprises the following steps:
turning on the gas injection control and recovery module to continuously vacuum the testing device for 6 to 12 hours;
injecting methane gas into the simulated center pipe body at a constant pressure through the gas injection control and recovery module, and then, turning off the gas injection control and recovery module; until a second pressure gauge has been having a stable reading without change for 6 to 12 hours, recording readings of a gas mass flow meter and the second pressure gauge to determine the cumulative methane gas injection amount Cg1 and the balanced system pressure P1;
starting the liquid injection control and recovery module to inject simulated formation water into the simulated center pipe body at a constant low injection rate, and continuously recording pressure changes inside the simulated center pipe body through the second pressure gauge; after the reading of the second pressure gauge reaches the reservoir pressure, the liquid injection control and recovery module changing to continue to inject the simulated formation water into the simulated center pipe body 2 at a constant pressure until the reading of the second pressure gauge does not change significantly within 12 to 24 hours;
setting the test temperature of the programmable temperature control constant temperature module to the bottom hole temperature, setting the pressure level of a program-controlled constant pressure valve to the bottom hole pressure, the liquid injection control and recovery module continuing to inject the simulated drilling fluid into the simulated center pipe body at a constant pressure higher than the bottom hole pressure, separately metering the cumulative discharge amount of methane gas through the drainage and gas collection metering module; when the metered value of the cumulative methane gas discharge amount Cg2 has no significant change within 3 to 6 hours, considering that at this time the free gas has been completely discharged from the simulated center pipe body, and determining that the core sample inside the simulated center pipe body reaches the underground temperature and pressure conditions and the occurrence state during drilling and coring in the environment of the pipe body being filled with drilling fluid; and
turning off the drainage and gas collection metering module, and the liquid injection control and recovery module; until the reading of the second pressure gauge has no significant change within 12 to 24 hours, calculating the total occurrence amount of methane gas in the core sample with the following formula:
 where Cg is the total occurrence amount of methane gas in the core sample, measured in cm3;
wherein, the step of simulating the coordinated change process of liquid-phase pressure and temperature in lifting the core to a wellhead, to calculate the gas loss amount and the gas loss ratio in a simulated process of the core sample arriving at the wellhead, comprises the following steps:
setting the automatic descent path of a simulated lift pressure from the bottom hole pressure to a wellhead pressure and the synchronous automatic descent path of a simulated temperature from the bottom hole temperature to a wellhead temperature, according to the core lift time;
adjusting the liquid outlet pressure level according to the set descent path of the simulated lift pressure, adjusting the temperature level inside the simulated center pipe body according to the set synchronous automatic descent path of the temperature, to reproduce dynamic changes in pressure and temperature conditions inside the coring barrel during the wireline coring and lifting process; and then, recording the changes in fluid pressure at the liquid outlet with time through a first pressure gauge, recording the changes in fluid pressure inside the simulated center pipe body with time through the second pressure gauge, and separately metering changes in the total amount of discharged methane gas with time through the drainage and gas collection metering module; until the program-controlled constant pressure valve and the programmable temperature control constant temperature module synchronously reach the simulated wellhead pressure and wellhead temperature conditions, recording the total amount Cg3 of discharged methane gas separately metered by the drainage and gas collection metering module, and calculating the gas loss amount and the gas loss ratio in the simulated process of the core sample arriving at the wellhead with the following formulas:
 where Cg1 is the gas loss amount in the core sample, measured in cm3; Rg1 is the gas loss ratio in the core sample.
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