JP2008082023A - Recovery method of water soluble natural gas by carbon dioxide dissolved water - Google Patents

Abstract

<P>PROBLEM TO BE SOLVED: To provide a recovery method of water soluble natural gas by carbon dioxide dissolved water capable of recovering the substantially whole quantity of water soluble natural gas and iodine buried without sinking the ground, and capable of stably storing CO<SB>2</SB>in a storage layer after development drilling without causing leakage over a long period of time. <P>SOLUTION: CO<SB>2</SB>dissolved water 3 of higher density than that of stratum water 2 is pressed in the stratum water 2 existing storage layer from a press-in well 4 arranged in a structural position lower than a production well 5, and the stratum water 2 is pushed up toward the production well 5 by this CO<SB>2</SB>dissolved water 3. At this time, a press-in quantity of the CO<SB>2</SB>dissolved water 3 and a pumping-up quantity of the stratum water 2 are adjusted so that pressure in the storage layer becomes hydrostatic pressure. Next, the stratum water 2 pumped up from the production well 5 is separated into the water soluble natural gas 12 and brackish water 13, and the iodine is also recovered from the brackish water 13. The brackish water after recovering the iodine is reused as the CO<SB>2</SB>dissolved water 3 by mixing CO<SB>2</SB>. <P>COPYRIGHT: (C)2008,JPO&INPIT

Description

In the present invention, carbon dioxide (CO ₂ ) -dissolved water is injected into the ground, formation water containing water-soluble natural gas such as methane is pumped up from the underground reservoir, and natural water such as methane is extracted from the formation water. The present invention relates to a method for recovering water-soluble natural gas using CO ₂ dissolved water that recovers gas and iodine.

Water-soluble natural gas mainly composed of methane exists in the formation water in the underground reservoir, and its production volume is about the amount of natural gas produced in Japan (about ³ billion m ³ / year). It accounts for 30% (900 million m ³ / year) and is estimated to have recoverable reserves of 600 to 800 years (over 500 billion m ³ ) in current annual production. In addition, the formation water containing water-soluble natural gas contains iodine, and iodine is usually recovered from formation water after separation of natural gas such as methane (hereinafter referred to as brine). Estimated reserves of iodine in Japan are estimated to be 4.9 million tons. Currently, the amount of production accounts for 40% (7200 t / year) of global production (about 18,000 t / year), and is important to be exported overseas. Mineral resources.

  Conventionally, when such water-soluble natural gas and iodine are recovered, formation water containing them is pumped up by a pump or the like, and methane is first recovered. And iodine is further collect | recovered from the brine after methane separation, and in order to suppress land subsidence, a part of the brine after iodine recovery is returned to the underground reservoir. Specifically, about 10% (about 5.5 million t / year) is returned to the underground reservoir with respect to the amount of formation water (about 55 million t / year). In this way, the amount of brine that is returned to the underground reservoir is limited to about 10% of the pumped-up amount of formation water because water-soluble natural gas and iodine deposits are diluted by the reduced brine. This is to prevent it.

On the other hand, recently, for the purpose of reducing the emission amount of CO _{2 into} the atmosphere, a technique for storing CO ₂ in the ground (see, for example, Patent Document 1) and CO ₂ is dissolved in water or hydrated. The technology (for example, refer to patent document 2) etc. which are isolated and stored in the ocean or the ground, etc. is examined. In addition, studies have been made to store CO ₂ in a structural reservoir after mining oil-soluble natural gas and free natural gas produced together with crude oil. Furthermore, a technique for utilizing CO ₂ for secondary recovery of crude oil remaining in the pores of the oil layer has been developed by utilizing the property that supercritical CO ₂ easily dissolves crude oil.

JP-A-6-170215 JP 2004-50167 A

  However, the above-described conventional technique and the technique being studied have the following problems. That is, the conventional water-soluble natural gas recovery method that draws a large amount of formation water and reduces only a part of it to the underground reservoir is only about 30 to 40% of the total water-soluble natural gas present in the underground reservoir. There is a problem that about 60 to 70% remains in the underground reservoir and cannot be recovered, and the recovery rate of water-soluble natural gas is low. At present, water-soluble natural gas has a small annual production compared to the recoverable reserves, and there is room for significant increase. However, the conventional recovery method as described above will further increase the groundwater by pumping a large amount of groundwater. There is also a problem that the production cannot be increased because there is a risk of settlement. Furthermore, in order to prevent land subsidence, it is essential to return the brine after recovering water-soluble natural gas and iodine to the underground reservoir as much as possible. Since the water-soluble natural gas and iodine deposits present in the seawater are diluted, at present, only about 10% of the amount of formation water pumped up can be returned.

On the other hand, the CO ₂ storage method currently being studied to store CO ₂ in a structural reservoir such as an oil field or a gas field that has become abandoned ore as described in Patent Documents 1 and 2 is a structural storage. because utilizing the sealing layer directly above the layer are stored CO ₂ at a supercritical state, if the sealing layer is destroyed by an earthquake or the like, CO _2, which is stored at high pressure is pressed into the reservoir layer There is a risk of leakage.

The present invention has been devised in view of the above-described problems, and can recover almost all of the water-soluble natural gas and iodine that are buried without causing land subsidence. It is an object of the present invention to provide a method for recovering water-soluble natural gas using CO ₂ dissolved water that can stably store CO ₂ in a later reservoir without leaking for a long time.

The method for recovering water-soluble natural gas using carbon dioxide-dissolved water according to the present invention is a method for recovering water-soluble natural gas and iodine from formation water existing under the surface of the earth, and is provided at a lower structure than the production well. press-fitting the CO ₂ dissolved water from injection well to a reservoir of the formation water is present, by utilizing the fact that the CO ₂ dissolved water is denser than the formation water, the formation water by the CO ₂ dissolved water To the production well, pumping the formation water from the production well, separating it into water-soluble natural gas and brine, recovering iodine from the brine, and brine after iodine recovery A step of mixing CO ₂ to make the CO ₂ dissolved water, and adjusting the pressure of the CO ₂ dissolved water and the pumping amount of the formation water to adjust the pressure in the reservoir to a hydrostatic pressure. It is characterized by holding .

In the present invention, by dissolving the CO ₂ into brine after iodine recovered as CO ₂ dissolved water, reducing pressed density than the formation water is a high CO ₂ dissolved water underground reservoir, CO ₂ dissolved water The formation water is pushed up toward the production well using the density difference between the water and the formation water. The CO ₂ dissolved water and the formation water have the same physical properties, and there is no difference in interfacial tension, viscosity, etc. between them, so the CO ₂ dissolved water that has been reduced and injected is the mineral that constitutes the reservoir Smoothly extrude formation water that originally existed in the gaps (interparticle pores) formed between particles, and reduce the amount of formation water that contains water-soluble natural gas and iodine left in the reservoir as much as possible Can do. That is, according to the present invention, water-soluble natural gas and iodine can be recovered in high yield while preventing the occurrence of ground subsidence. As a result, the water-soluble natural gas recovery method using carbon dioxide-dissolved water according to the present invention contributes to dramatically increasing the recoverable reserves of water-soluble natural gas and iodine. In the method for recovering water soluble natural gas with carbon dioxide dissolved water of the present invention, as a raw material for CO ₂ dissolved water, since it is possible to use the CO ₂ discharged from a factory or the like, water soluble natural gas field ( Such CO ₂ can be stored underground in a non-structural reservoir in which water-soluble natural gas is buried. Further, in the method for recovering water soluble natural gas with carbon dioxide dissolved water of the present invention, in order to become hydrostatic pressure as a whole pressure of the reservoir, there is no risk of subsidence and CO ₂ leakage, to earthquakes However, safety can be ensured. Accordingly, even in a water-soluble natural gas field in the vicinity of a metropolitan area, CO ₂ can be stably sequestered in the ground for a long period of time while safely mining water-soluble natural gas.

According to the present invention, since the CO ₂ -dissolved water in which CO ₂ is dissolved in the brine is pressed into the reservoir so as to have a hydrostatic pressure, the embedded water solution without causing ground subsidence. it is possible to recover the sexual natural gas in high yield, the CO ₂ in the reservoir after the water-soluble natural gas extraction, in a state dissolved in water, i.e. as a CO ₂ dissolved water, and long-term stable Can be stored.

Hereinafter, a method for recovering water-soluble natural gas according to an embodiment of the present invention will be described in detail with reference to the accompanying drawings. FIG. 1 is a diagram schematically showing a water-soluble natural gas recovery method of the present embodiment. As shown in FIG. 1, formation water 2 containing water-soluble natural gas mainly composed of methane exists in a non-structural reservoir between seal mudstone layers 1. Therefore, in the water-soluble gas recovery method of the present embodiment, the injection well 4 and the production well 5 that reach the unstructured reservoir in which the formation water 2 exists are excavated, and the injection well 4 enters the reservoir. CO ₂ dissolved water 3 in which CO _{2 is} dissolved is injected and the formation water 2 is pumped up from the production well 5.

Since the CO ₂ dissolved water 3 has a density of about 1.08 and is denser and heavier than the formation water 2 (density of about 1.03), these density differences (0.05) are utilized to Provided on the lower side of the structure than the production well 5, the formation water 2 is pushed up toward the production well 5 with the CO ₂ dissolved water 3. The formation water 2 and the CO ₂ -dissolved water 3 have almost the same physical properties, and these boundary surfaces 20 exist stably over a long period of time, so water-soluble natural gas and iodine are efficiently recovered from the formation water 2 pumped up. can do. The fact that the boundary surface 20 between the formation water 2 and the CO ₂ dissolved water 3 is stably present for a long period of time is generally known from the CO ₂ long-term behavior simulation, CO ₂ ocean fixation research, and the like (T. Sato, 1 other, “Numerical Prediction of Dilution Process and Biological Impacts in CO ₂ Ocean Sequestration”, Journal of Marine Science and Technology, June 2002, p. 169-180, and Y. Song, 5 others, “ Measurement on Density of CO ₂ Solution by Mach-zehnder Interferometry ”, Annals of the New York Academy of Science, October 2002, Vol. 972, p. On the other hand, when a fluid whose physical properties are significantly different from the formation water 2 is injected, the injected fluid comes into contact with the formation water 2 existing in the interparticle pores of a specific size in the reservoir, but the physical property difference ( Due to differences in interfacial tension, viscosity, etc., the formation water 2 cannot be taken in, and flows around that part. As a result, the formation water 2 existing in the interparticle pores of this specific size is left alone. Such a phenomenon is known as residual gas, residual oil, or immobile water in the field of oil reservoir engineering, and is the largest factor in the reduction of secondary recovery efficiency of oil and natural gas.

At this time, the press-fitting pump 6 and the pumping pump 7 respectively adjust the press-fitting amount of the CO ₂ dissolved water 3 and the pumping amount of the formation water 2 to keep the pressure in the reservoir at a hydrostatic pressure. Thereby, while being able to reduce the risk that the CO ₂ dissolved water 3 leaks to the ground surface, ground subsidence can be suppressed.

Moreover, CO ₂ dissolved water 2, for example, the CO ₂ which is stored in the CO ₂ tank 9 via the pipeline 17 or the like is discharged from the CO ₂ emission sources 8 such as factories, natural gas stored in the brine tank 16 And it can produce by mixing the brine after collect | recovering iodine with the mixer 10. FIG. FIG. 2 is a graph showing the relationship between the solubility of CO ₂ in pure water at 40 ° C., the pressure and the underground depth, with the horizontal axis representing pressure and underground depth and the vertical axis representing CO ₂ solubility. Note that 40 ° C. corresponds to an underground temperature of 1000 to 2000 m in depth. As shown in FIG. 2, the solubility of CO ₂ in water increases as the pressure increases or as the underground depth increases. Since the pressure in the injection well 4 increases as the depth increases, the CO ₂ solubility increases as the brine flows down the pipe, and the CO ₂ mixed in the brine is completely dissolved near the bottom of the well. A part of the mixer 10 may be installed in the pipe of the injection well 4, and as the mixer 10, CO ₂ is introduced into the brine using a microbubble generator and a liquid CO ₂ mixing device. It may be dispersed.

Next, the pumped-up formation water 2 is separated into natural gas 12 mainly composed of methane and brine 13 by a separator 11. The natural gas 12 is stored in a gas tank 14 and supplied to a factory or the like via a gas pipeline 18. On the other hand, the brine 13 is introduced into the iodine separator 15 and collects iodine contained therein. Furthermore, the brine after iodine recovery is stored in the brine tank 16 via the reduced water pipeline 19 and reused as a raw material for the CO ₂ dissolved water 3. In the conventional method for recovering water-soluble natural gas, about 10% of the brine after iodine recovery was returned to the reservoir and the remaining about 90% was discharged into the sea. In the recovery method, all of the brine after iodine recovery is reduced to the reservoir as CO ₂ dissolved water 3, so that land subsidence can be prevented and the manufacturing cost and environmental load can be greatly reduced. it can.

In the water-soluble natural gas recovery method of this embodiment, the concentration of CO ₂ dissolved in the brine can be set as appropriate according to the depth of injection, surface temperature, formation pressure, and the like. For example, as shown in FIG. 2, when the press-fitting depth is 1500 to 2000 m, it is desirable that the depth be around 6% by mass. As a result, the CO ₂ concentration in the brine is saturated, and more CO ₂ can be stored.

As described above, in the method for recovering water-soluble natural gas according to the present embodiment, CO ₂ is mixed with the brine after iodine recovery, which has been mostly discharged into the sea, and is dissolved in the reservoir as CO ₂ dissolved water. Since reduction press-fitting is performed, the occurrence of land subsidence can be prevented. As a result, the amount of formation water pumped up to prevent subsidence can be increased, so the production volume of water-soluble natural gas and iodine, which were set lower than the maximum possible production volume, was increased. It becomes possible to do. In addition, since CO ₂ dissolved water has the same physical properties as formation water, the amount of water-soluble natural gas and iodine left in the reservoir can be reduced as much as possible. As a result, the recoverable reserves of natural gas and iodine are dramatically increased.

Further, by using the CO ₂ discharged from factories or the like as a raw material of CO ₂ dissolved water, the CO ₂ discharged from factories as CO ₂ dissolved water, stably without leaking long term underground reservoir Can be stored. And estimated from the amount of mining in domestic water-soluble natural gas fields, about 1% (about 3 million tons / year) of CO ₂ (about 300 million tons / year) currently emitted in the energy sector in Japan. It will be possible to store underground. Thus, by applying the water-soluble natural gas recovery method of the present embodiment, it is possible to reduce the amount of CO ₂ discharged from the factory or the like into the atmosphere. Furthermore, since the reservoir pressure is set to hydrostatic pressure as a whole, there is no risk of ground subsidence and CO ₂ leakage, and safety against earthquakes can be secured. However, it is possible to stably sequester CO ₂ in the ground for a long period of time while safely mining water-soluble natural gas.

As described above, the present invention is an epoch-making technology that can realize an economical and long-term stable non-structural CO ₂ underground storage technology in combination with the secondary recovery technology of water-soluble natural gas. This technology is suitable for Japan, which consumes a large amount, while urgently needing countermeasures against global warming. In addition, since there is no risk of CO ₂ surface leakage, it is also a technology that enables sequestration of CO _{2 in} the earthquake country, Japan, more safely than previously proposed technologies.

Hereinafter, the effects of the present invention will be specifically described with reference to Examples and Comparative Examples. FIG. 3 is a diagram schematically showing the experimental apparatus of this example. As shown in FIG. 3, in this embodiment, a glass tube 21 having an inner diameter of 20 mm and a length of 300 mm inclined to about 40 ° is filled with glass beads 22 to reproduce a non-structural single inclined structure reservoir. did. Then, fresh water (density 1.00) imitating formation water was poured into the glass tube 21 from below, and the gap between the glass beads 22 was completely filled with fresh water. Next, a salt water (density 1.05, salt concentration 5 mass%) colored with an ink simulating CO ₂ dissolved water in a glass tube 21 using a syringe 27 at a flow rate of about 2.25 mm / second from below. ) Was injected, and the state in which salt water pushes up (sweeps) fresh water was observed.

  First, the above-described sweep experiment was performed without filling the glass tube 21 with the beads 22. 4 (a) to 4 (f) are diagrams showing the results. FIG. 4 (a) is 20 seconds after injection, FIG. 4 (b) is 40 seconds after injection, and FIG. 4 (c) is after injection. After 60 seconds, FIG. 4 (d) shows 80 seconds after injection, FIG. 4 (e) shows 100 seconds after injection, and FIG. 4 (f) shows 120 seconds after injection. As shown in FIGS. 4A to 4F, in this experiment, it was observed that the salt water 23 colored with ink pushed up the fresh water 24 due to the density difference while forming a clean interface.

  Next, the glass tube 21 was filled with beads having a diameter of 3 mm with a 1 mm hole in the center, and the above-described sweep experiment was performed. 5 (a) to 5 (f) are diagrams showing the results. FIG. 5 (a) is 20 seconds after injection, FIG. 5 (b) is 40 seconds after injection, and FIG. 5 (c) is after injection. After 60 seconds, FIG. 5 (d) shows 80 seconds after injection, FIG. 5 (e) shows 100 seconds after injection, and FIG. 5 (f) shows 120 seconds after injection. As shown in FIGS. 5A to 5F, in this experiment, it was observed that the salt water 23 colored with ink pushed up the fresh water 24. However, since the fluid flow is disturbed between the glass bead particles, the interface between them is somewhat unclear.

  Next, the glass tube 21 was filled with beads having a diameter of 0.05 mm, and the above-described sweep experiment was performed. 6 (a) to 6 (f) are diagrams showing the results. FIG. 6 (a) is 20 seconds after injection, FIG. 6 (b) is 40 seconds after injection, and FIG. 6 (c) is after injection. After 60 seconds, FIG. 6 (d) shows 80 seconds after injection, FIG. 6 (e) shows 100 seconds after injection, and FIG. 6 (f) shows 120 seconds after injection. As shown in FIGS. 6A to 6F, in this experiment, it was observed that the salt water 23 colored with ink pushed up the fresh water 24. In this experiment, the interface between the two is less clear than in the experiment shown in FIG. 5. This is because the permeability of the glass beads and the wall surface of the glass tube 21 decreases because the diameter of the glass beads is small. It is considered that the salt water 23 easily flows through a large gap formed between them.

  Next, beads having a diameter of 3 mm were filled in the glass tube 21, the ink-colored fresh water 26 was pushed up with uncolored salt water 25, and the recovery efficiency was examined from the colored state of the fresh water 26 remaining in the glass tube 21. FIGS. 7 (a) to (f) are diagrams showing the results. FIG. 7 (a) is 20 seconds after injection, FIG. 7 (b) is 40 seconds after injection, and FIG. 7 (c) is after injection. After 60 seconds, FIG. 7 (d) shows 80 seconds after injection, FIG. 7 (e) shows 100 seconds after injection, and FIG. 7 (f) shows 120 seconds after injection. As shown in FIGS. 7A to 7F, in this experiment as well, in each experiment, the salt water 25 pushed up the fresh water 26, and the portion replaced with the salt water 25 was almost transparent. Furthermore, with a simple colorimetric method, the recovery rate was 98% or more in the replacement of one volume of the glass tube.

It is a figure which shows typically the collection | recovery method of the water-soluble natural gas which concerns on embodiment of this invention. Take pressure and subsurface depth on the horizontal axis and the vertical axis represents the CO ₂ solubility is a graph showing the relationship between the solubility and the pressure and groundwater depth of CO ₂ in pure water at 40 ° C.. It is a figure which shows typically the experimental apparatus of the Example of this invention. (A)-(f) is a figure which shows the result of the sweep experiment conducted without filling a bead to a glass tube. (A)-(f) is a figure which shows the result of the sweep experiment performed by filling the glass tube with the bead with a diameter of 3 mm in which the hole of 1 mm is opened in the center. (A)-(f) is a figure which shows the result of the sweep experiment conducted by filling the glass tube with the bead with a diameter of 0.05 mm. (A)-(f) is a figure which shows the result of the sweep experiment which filled the glass tube with the bead with a diameter of 3 mm, and pushed up the ink-colored fresh water with the uncolored salt water.

Explanation of symbols

1 seal mudstone 2 formation water 3 CO ₂ dissolved water 4 Injection well 5 production wells 6,7 pump 8 CO ₂ emission sources 9 CO ₂ tank 10 mixer 11 separator 12 water soluble natural gas 13 brine 14 gas tank 15 iodine separator 16 brine Tank 17 CO ₂ Pipeline 18 Gas Pipeline 19 Reduced Water Pipeline 20 Boundary Surface between Formation Water 2 and CO ₂ Dissolved Water 3 21 Glass Tube 22 Beads 23 and 25 Salt Water 24 and 26 Fresh Water 27 Syringe

Claims (1)

A method for recovering water-soluble natural gas and iodine from underground water existing under the surface,
Utilizing the fact that carbon dioxide-dissolved water is injected into a reservoir in which the formation water is present from an injection well provided in a lower structure than the production well, and the carbon dioxide-dissolved water has a higher density than the formation water. , Pushing up the formation water toward the production well with the carbon dioxide-dissolved water;
Pumping the formation water from the production well and separating it into water-soluble natural gas and brine;
Recovering iodine from the brine;
Mixing carbon dioxide into the brine after iodine recovery to make the carbon dioxide-dissolved water,
A method for recovering water-soluble natural gas using carbon dioxide-dissolved water, wherein the pressure of the carbon dioxide-dissolved water and the pumping amount of the formation water are adjusted to maintain the pressure in the reservoir at a hydrostatic pressure. .

Images