Patent Grant
7128150
This invention relates to a method of disposing of acid gases, and more specifically a process of disposing of acid gases in a subterranean formation.
Natural gas is an important fuel gas and it is used extensively as a basic raw material in the petrochemical and other chemical process industries. The composition of natural gas varies widely from field to field. Many natural gas reservoirs contain relatively low percentages of hydrocarbons (less than 40%, for example) and high percentages of acid gases, principally carbon dioxide, but also hydrogen sulfide, carbonyl sulfide, carbon disulfide and various mercaptans. The acid gases are detrimental to hydrocarbon handling and usage, and therefore acid gases are typically removed from the produced hydrocarbons by processes that are well known. The natural gas may also contain inert gases such as nitrogen, which are also removed by methods that are well known. The separated acid gas and inert gas often has insufficient value to justify further treatment or purification for any further commercial usage. “Waste gas” is a term that will used in this patent to describe a gas containing acidic components such as hydrogen sulfide or carbon dioxide, and may or may not contain inert gases. The waste gas typically has little or no commercial value.
Proposals have been made to re-inject the separated waste gas into disposal strata through an injection well directly into a depleted or spent zone of the hydrocarbon-bearing formation from which the gas was produced (see for example U.S. Pat. No. 5,267,614) or re-injected into a separate subterranean strata (see for example U.S. Pat. No. 6,149,344 and World Intellectual Property Organization publication number WO 00/58603). However, the prior art does not address how to simultaneously produce a gas while re-injecting a waste gas into the same formation.
There is a need for an improved method of more efficiently and effectively producing natural gas and at the same time disposing of waste gases into the same formation.
This invention is a method of recovering gas from a gas-bearing subterranean formation in which gas is produced from an upper portion of the formation and a waste gas is injected into a lower portion of the formation to dispose of the waste gas. The waste gas is injected within a 3000 foot (914 m) radial distance from the production of the gas. The injection and production can be carried out using one well or a plurality of wells.
In one embodiment, a subterranean, gas-bearing formation having one or more production wells are located in the upper portion of the formation, and one or more injection wells are located in the lower portion of the formation, with the horizontal distance between injection through the injection wells and production through any one of the production wells is at least a distance D in which:
D=h tan θ
where:
=Arccos[(0.64h2/3/R1/3A1/3(ky/kh)2/3(I/W)1/3]
The invention provides a more efficient method for re-injecting produced acid gas (such as carbon dioxide, hydrogen sulfide, carbonyl sulfide, and carbon disulfide) for pressure maintenance of gaseous hydrocarbon-bearing formations and a means for disposing of unwanted acid gas to reduce the environmental impact of releasing the acid gas at the surface.
The invention and its advantages will be better understood by referring to the drawings in which like numerals identify like functions.
The drawings illustrate specific embodiments of practicing the method of this invention. The drawings are not intended to exclude from the scope of the invention other embodiments that are the result of normal and expected modifications of these specific embodiments.
The invention will be described for producing natural gas from a subterranean formation (or reservoir) in fluid communication with one or more production completions and injecting a waste gas for disposal into one or more injection completions in fluid communication with the same formation. The waste gas injection and natural gas production can be carried out using the same well and optionally the injection and production can be carried out using one or more injection wells and one or more spaced-apart production wells. The method of the present invention may be applied to cased or uncased completions. For purposes of the present invention, the term “wellbore” is defined to encompass both cased and uncased completions. In the following description, only cased completions are described, but the invention is not limited to cased completions.
Referring to
In this patent, the term “natural gas” refers to a multi-component gas obtained from a gas bearing formation (non-associated gas). The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (C1) as a significant component. The natural gas will also typically contain ethane (C2), higher molecular weight hydrocarbons (C3+), one or more acid gases, and minor amounts of contaminants such as water, nitrogen, iron sulfide, wax, and crude oil. The term “acid gas” in this description means one or more compounds selected from the group comprising carbon dioxide, hydrogen sulfide, carbonyl sulfide, carbon disulfide, and mercaptans.
Natural gas produced from the upper part of zone 11 passes up the annular space and passes through line 80 to a conventional gas treatment unit 81, which may comprise one or more systems to dehydrate the gas, to remove natural gas liquid, and/or to sweeten the gas by removing acid gases such as H2S and CO2. All of these treatment systems are well known. The treatment unit 81 may produce (1) a product stream 82 that is suitable for introduction into a gas pipeline, into a fuel line, or it may be passed to a liquefaction plant to produce liquid natural gas (LNG) or pressurized liquid natural gas (PLNG); (2) a natural gas liquid (NGL) stream 83, and (3) a stream 84 enriched in one or more acid gases such as CO2. At least part of stream 84 may be pressurized to a higher pressure by one or more compressors 85 and may be co-mingled with a pressurized stream of water 86 and introduced into tubing string 20.
As the waste gas mixture flows down the tubing string 20, the pressure increases due to the hydrostatic column of fluid. A gas or liquid introduced into a wellbore that is pressurized by its hydrostatic head as the gas or liquid flows downhole may be referred to as undergoing “autocompression.” If it is desired that the downhole fluid pressure within tubing string 20 be higher than that generated by the hydrostatic head, the injection pressure at the wellhead can be increased by using a suitable pressurization device such as a pump or compressor 30.
One or more wellbore isolation or sealing devices are used to prevent fluid flowing down tubing string 20 from mixing with the production fluid being produced from production zone 11. These wellbore isolation or sealing devices are commonly referred to as wellbore packers and are located in at least one location between lowermost perforation of perforations 14 and the uppermost perforation of perforations 15. Two packers 40 and 41 are illustrated in
The injection rate into the lower part of the production zone is preferably controlled to maintain a ratio of the flow rate of waste gas through the tubing string 20 to the flow rate of natural gas being produced to keep the amount of waste gas that “breaks through” to the upper part of the formation and is produced again through perforations 14 below an acceptable level. By keeping the waste gas injection rate lower than the production rate, the waste gases, which will typically have a higher density and viscosity than the produced natural gas, will tend to remain in the lower portion of the production zone 11. A waste gas injection rate that minimizes breakthrough for a given recovery depends on many factors, including the natural gas production rate, the distance between the production perforations 14 and the disposal perforations 15, the vertical permeability of the producing formation relative to its horizontal permeability, the presence (or absence) of natural or induced fractures, the presence (or absence) of shale layers in the formation, and whether the waste gases are mixed with other fluids such as water. In addition, the rate of breakthrough to the production perforations 15 can be reduced through the injection of agents such as foam or polymer solution or other relative-permeability-modifying fluids in the area between the injection and production zones.
Membrane module 21 operates on the principle that a mixture of gases, the natural gas, under relatively high pressure passes across the surface of the membrane that is adapted to act as a selective barrier, permitting some components of the natural gas to pass through more readily than other components. The pressure on the feed side of the membrane is maintained at a pressure sufficiently higher than the pressure on the permeate side of the membrane to provide a driving force for the diffusion of the more permeable components of the gaseous mixture through the membrane. The partial pressure of the more permeable gaseous components is also maintained at a higher level on the feed side of the membrane than on the permeate side by constantly removing both the permeate stream and the residue of the feed stream, the retentate stream, from contact with the membrane. While the permeate stream can represent the desired product, in most permeation processes the desired product is the residue stream, and the permeate stream consists of contaminants which are removed from the feed stream.
Referring to
The retentate (represented by arrows 18) is conveyed to the earth's surface for further treatment by well-known techniques. Those skilled in the art will recognize that if the retentate does not have sufficient velocity to rise to the surface of the wellbore 10, any form of conventional pump or compressor (not shown) may be mounted within the wellbore to pressurize the retentate to a higher pressure. Such upward pumping or compressing apparatus can be carried out by conventional equipment and forms no part of the invention.
Deviated Well
Although wells illustrated in
Multiple Wells
Although
For most applications of the present invention, the following conditions exist: (1) the waste gas is more dense and more viscous than the raw natural gas it is displacing, (2) in most reservoirs, the vertical permeability is significantly less than the horizontal permeability, and (3) the amount of waste gas for disposal is appreciably less than the volume of gas to be produced. Thus, by injecting the waste gas at controlled rates as deep as practical in the reservoir perforations, the injected waste gas can displace the formation gas (the “displaced gas”) upward toward the producing well or wells. Although not shown in the drawings, the waste gas may optionally be cooled prior to injection into the formation. The cooling of the waste gas increases its density and reduces the likelihood of early breakthrough of the waste gas to the producing perforations. The density of the waste gas can also be increased by mixing the waste gas with water prior to injection into the formation, thereby providing further gravity segregation. The greater the density difference between the injectant and displaced gas, the better the stability of the displacement process. A density ratio of ρinj/ρdisp>1.05 is preferred, with a ratio of above 1.2 being more preferred. Likewise, a more viscous injectant is more stable in terms of fingering through the displaced fluid. A viscosity ratio of the injected waste gas to the gas being displaced in the reservoir (μinj/μdisp) greater than 1.05 is generally preferred with a ratio above 1.1 being more preferred.
Proximal injection of the waste gas will help maintain the reservoir pressure, improve reservoir sweep efficiency, and mitigate potential subsidence of the formation 'above the reservoir. Maintaining higher average reservoir pressure may reduce the number of production wells needed over the life of the project and/or reduce or eliminate the need for compressors on the production wells.
Persons skilled in the art will recognize that high waste gas injection and/or rates of natural gas production may cause a high pressure gradient to develop between the injector perforations and production perforations. This pressure gradient can lead to “coning” of the injected waste gas toward the production perforations. This can be mitigated by a number of factors, including for example:
Model
A geometric model was developed to estimate the minimum distance from the bottom of producing portion of the well to the top of injection portion of the well for the single wellbore case that reduces breakthrough to a desired level. The model assumed substantially uniform porosity throughout the gas-bearing formation. If the reservoir is not sufficiently thick to accommodate in a single well both gas production and waste gas injection with a desired vertical distance between the injection and production zones, a deviated well (or separate wells) can be used. For such a reservoir it is desirable to determine the minimum horizontal distance between the top perforation of the injection perforations and the bottom perforation of the producing perforations. This horizontal distance (D) can be calculated by using the following equation:
D=h tan θ
where:
θ=Arccos[(0.64h2/3/A1/3R1/3(ky/kh)2/3(I/W)1/3] Eq. 1
In the case that the expression in the brackets of Eq. 1 is equal to or greater than one, no deviation of the reservoir is necessary. Therefore, injection of waste gas can be through injection perforations on a vertical line below the production perforations. Table 1 sets forth a range of values of θ for selected reservoir and operational parameters assuming nominally constant porosity across the reservoir and assuming that both the production perforations and injection perforations are 100 vertical feet thick. It will be understood by those skilled in the art the invention is not limited by the assumptions used to calculate the data set forth in Table 1.
The minimum interwell distance between vertical wells tends to scale with drainage area, and increases with larger ky/kh and injection/withdrawal ratio. The producing well perforations are preferably located near the top of the continuous production perforations, with the injection well perforations preferably being located near the bottom of reservoir just above (or possibly below) the gas-water contact. If natural fracturing is present in the gas-bearing formation, the waste gas injectors are preferably located in a direction from the producer wells that is normal to the fracture direction.
Exceeding the suggested value of θ will typically increase the drilling costs in the single wellbore embodiment, since total drill well length will be increased. Exceeding θ may also reduce the level of pressure support gained by proximal injection, depending on reservoir permeability. The expression of Eq. 1 provides a means of balancing long-term production contamination, reservoir pressure support, and well costs.
Reservoir simulations were performed using proprietary software. Comparable results can be obtained from commercially-available reservoir simulators familiar to those skilled in the art using the teachings of this description. A single producer/injector combination (similar to the embodiment depicted in
For the purposes of the simulation example, it was assumed that 95% of the CO2 was recovered and reinjected, along with 3% of the CH4. The volume of waste gas (CO2) increased in later years of the model, as the concentration of CO2 increased in the production stream. This waste gas was injected over a 1050-foot (320 m) perforations in the bottom portion of the reservoir.
Curve 62 illustrates the effect of shortening the perforations between injector and producer, by lowering the latter to 525 feet (160 m) above the injector, without any horizontal displacement. Thus, θ is zero, which is substantially below the recommended value of 72° for a recovery factor of 0.5. The resulting level of contamination is undesirable.
Curve 63 shows that increasing the ky/kh ratio to 1.0 substantially increases contamination, or reduces the time required to attain a given level of contamination. Curve 64 shows a case where the volume of gas injected was increased by 50% over the base case, with all other parameters fixed. Again, earlier contamination of the produced gas is evident. Curve 65 shows a case where the injector was moved 1667 feet (508 m) in the horizontal direction away from the producer. Less contamination of the produced gas was calculated because of the additional distance that the waste gas must traverse to get to the producer.
Curve 73 shows that increasing the ky/kh ratio to 1.0 also improves pressure support of the producer. Curve 74 shows that injecting more waste gas in the model significantly increased production well pressure over the life of the project. Curve 75 shows that little loss in pressure support is observed when the injector is moved as far as 1667 feet (508 m) in the horizontal direction away from the producer.
A person skilled in the art, particularly one having the benefit of the teachings of this patent, will recognize many modifications and variations to the specific embodiment disclosed above. For example, a variety of temperatures and pressures may be used in accordance with the invention, depending on the overall design of the system, whether a downhole membrane separation system is used and if so the membrane system selected, the desired component separations, and the composition of the feed gas. One skilled in the art can also recognize potential improvements to the process, for example, by producing gas from the formation for a certain time period before beginning waste gas injection. Likewise, one skilled in the art can understand the benefit of arranging the wells in a certain pattern for a given type of reservoir. For example, if the producing formation is anticlinal, the production of hydrocarbons may be from a plurality of production wells positioned generally in the interior portion of the formation, while the waste gas injection wells can be placed generally at the peripheral region of the formation. Alternatively, if the formation is monoclinal, the production of hydrocarbons may be from a plurality of production wells that are placed in the updip portion of the formation, while the placement of acid gas may be through a plurality of injection wells placed in the downstructure portion of the formation in a line-drive configuration. In cases where the reservoir is partially depleted, and wells are already in place, it may be desirable in some circumstances to convert production wells into injection wells. Additionally, certain process steps may be accomplished by adding devices that are interchangeable with the devices shown.
As discussed above, the specifically disclosed embodiments and examples should not be used to limit or restrict the scope of the invention, which is to be determined by the claims below and their equivalents.
This application claims the benefit of U.S. Provisional Patent Application No. 60/318,085 filed Sep. 7, 2001. The application is related to non-provisional application Nos. 10/234,907 and 10/234,920, both filed Sep. 4, 2002, now U.S. Pat. Nos. 6,755,251 and 6,623,266, respectively, which claim the benefit of provisional patent application Nos. 60/318,080 and 60/318,087, respectively, both filed Sep. 7, 2001.
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