US20030141073A1 - Advanced gas injection method and apparatus liquid hydrocarbon recovery complex - Google Patents

Advanced gas injection method and apparatus liquid hydrocarbon recovery complex Download PDF

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US20030141073A1
US20030141073A1 US10/340,818 US34081803A US2003141073A1 US 20030141073 A1 US20030141073 A1 US 20030141073A1 US 34081803 A US34081803 A US 34081803A US 2003141073 A1 US2003141073 A1 US 2003141073A1
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gas
pressure
liquid hydrocarbon
liquid
injector
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Terry Kelley
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Priority to US10/340,818 priority Critical patent/US20030141073A1/en
Publication of US20030141073A1 publication Critical patent/US20030141073A1/en
Priority to BR0406719-3A priority patent/BRPI0406719A/pt
Priority to PCT/US2004/000057 priority patent/WO2004063310A2/en
Priority to MXPA05007415A priority patent/MXPA05007415A/es
Priority to CA002513070A priority patent/CA2513070A1/en
Priority to GB0514180A priority patent/GB2414754A/en
Priority to CNB2004800056196A priority patent/CN100347403C/zh
Priority to US11/408,413 priority patent/US7506690B2/en
Abandoned legal-status Critical Current

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/164—Injecting CO2 or carbonated water
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E21B43/121—Lifting well fluids
    • E21B43/122—Gas lift
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/14—Obtaining from a multiple-zone well
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
    • E21B43/168—Injecting a gaseous medium
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/30—Specific pattern of wells, e.g. optimising the spacing of wells
    • E21B43/305—Specific pattern of wells, e.g. optimising the spacing of wells comprising at least one inclined or horizontal well
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
    • Y02P90/70—Combining sequestration of CO2 and exploitation of hydrocarbons by injecting CO2 or carbonated water in oil wells

Definitions

  • the present invention relates to the process of improving and increasing liquid hydrocarbon recovery from an oil bearing reservoir by combining the effects of reservoir pressure increase and oil mobility increase through injection of natural gas or another miscible gas into the oil reservoir and injection of high-pressure gas into the gas cap above the liquid zone. Injection into the oil zone would be facilitated by use of horizontal borehole(s) or deep, high permeability, jet-type perforations from the main well bore.
  • the advantages of the higher pressure and more mobile oil would be realized with a new production scheme utilizing a float-control valve system on the lower end of the production tubing which recognizes the difference between producible liquid hydrocarbons and gas, the latter which is desirable to retain downhole for automatic reinjection into the gas cap.
  • Periodic reversal of the proposed invention-well system into production wells, and vice versa, is proposed for efficient drainage of the surrounding oil reservoir.
  • HPI invention addition (filed Jul. 5, 2002, U.S. PTO No. 60/393,55) relates to producing, offshore or onshore, excessively high-pressure reservoirs by producing liquid-only inflow at a high rate through the production tubing while maintaining the natural gas for its valuable liquid hydrocarbon recovery benefits within the reservoir, in the gas cap and in solution within the oil.
  • HPI invention addition also relates to methods for recovering liquid hydrocarbons in shut-in wellbore-reservoir scenarios at new high-pressure levels to produce onto the surface while continuously maintaining pressure at levels never before produced at.
  • the Bowzer Patent further describes an improved process of recovering oil from an oil-bearing formation having a natural fractured network with vertical communication, and wherein gravity drainage is the primary means of recovery.
  • CO 2 is concentrated in a displacing slug at the gas-liquid hydrocarbon contact and the slug is displaced downwardly to help move oil liquids toward a production well(s).
  • a chase gas with a density lower than CO 2 (high percentage of nitrogen) is used to propagate the CO 2 downwardly.
  • nitrogen is used by the Mexican national oil company Pemex as a reservoir gas-cap expansion and oil repressuring mechanism in its giant Cantarell Complex offshore operation in the Bay of Campeche, Gulf of Mexico.
  • the HPI invention discloses a downhole oil liquid injector to produce liquid hydrocarbons and/or waters under extremely high pressure.
  • the new, high-pressure bottomhole oil liquid injector (HPI), together with a liquid column back-pressure valve invention (LC-BPV) and/or with an addition entitled extended float system EFS, described later, is especially designed and invented to produce extremely high-pressure applications as shown in the gas injection complex GIC filed Jan. 9, 2002, with U.S. PTO No. 60/346,311, and “Method and Apparatus for Increasing Fluid Recovery from a Subterranean Formation”, U.S. application Ser. No. 08/978,702, with U.S. Divisional Patents issued U.S. Pat. Nos.
  • the present invention discloses systems and methods: (1) to reenergize hydrocarbon reservoirs that are losing their original natural gas pressures and gas energy, both in solution within the oil as well as in the overlying gas cap in defined reservoirs in producing areas or fields by principally returning solution gas to the oil and, secondly, gas to the gas cap. (2) To reenergize hydrocarbon reservoirs that have lost solution gas in the oil by returning solution gas, energy and pressure to the in-place oil and, secondly, gas to the gas cap in fields that are now anywhere approaching marginal or considered to be marginal, thereby transforming unrecoverable crude oil to recoverable.
  • This injection process is done in the following manner. Using a chosen “source gas” SG, the injection gas will be injected through the casing head annulus which communicates directly to the open horizontally drilled or perforated gas zone via the casing annulus.
  • a chosen “source gas” SG any variety of chosen gases can be used, such as, but not limited to, natural gas, CO 2 , or nitrogen (it should be noted that many fields are already using CO 2 or nitrogen).
  • Multizone gas caps can be injected into individually. The gas cap injection process works to benefit the following oil zone injection process and helps recovery by added gas cap pressure.
  • the most critically important gas injection process is done through the central tubing injection string that will go through the first #1 packer which is located directly below the gas cap at the top of the liquid hydrocarbon (oil) zone.
  • a bridge plug optionally can be used at the bottom of the permeable oil zone in order to seal off the area being injected into (horizontal boreholes or perforations.)
  • a second source gas SG 2 is pressurized at the surface by a compressor assisted optionally with temperature control so that the SG 2 will enter the liquid hydrocarbon zone as a compressed, pressurized gas, entering and going into solution with the in-place crude oil.
  • the oil zone will be horizontally drilled optionally with deep jet perforations (optionally air-drilled open hole for clean entry, eliminating drill mud blockage).
  • the horizontal borehole(s) can be one or more; however, the vertical wellbore can also be just perforated in certain configurations/wells.
  • High performance, deeply penetrating jet perforations are available to communicate beyond the wellbore(s) through cement sheaths and the skin or permeability-damaged zone.
  • the purpose of the deeper jet perforations is to allow the injected, pressurized gas to “permeate” as deeply as possible into the oil in the oil zone. If multiple oil zones exist that are separated by non-permeable barriers, the system described can be applied sequentially to individual oil zones.
  • HPI high bottomhole pressure
  • the HPI invention provides a workable solution to this excessive high pressure problem.
  • An example is a reservoir that must maintain, in the reservoir and wellbore, 5,500 psi and above during its production from wellbore to surface.
  • the present invention is designed to produce liquid hydrocarbons while maintaining the 5,500 psi (or above) at the oil intake at the bottom of the wellbore.
  • the double-valve mechanism which is designed to open at lesser pressures, will not open due to a very high-pressure. seal.
  • a ⁇ fraction (3/16) ⁇ ′′ pilot tip and seat as designed in the prior art that opens to relieve lesser pressures in order to dislodge the main tip off its ⁇ fraction (11/16) ⁇ ′′ port seat cannot dislodge with 5,500 psi opposing a partial vacuum being drawn by a pumping system or even at an atmospheric pressure tubing string. Therefore, a back-pressure valve is provided on the wellhead on the production tubing at the surface. The back pressure valve is preset to a back pressure that will be less than the operating wellbore pressure, but at the same time set high enough to prevent excessively high extremes in pressure differentials that would prevent the downhole injector's pilot valve from opening.
  • the back pressure is created, in part, for the purpose of this invention, by a predetermined column of oil or liquids in the tubing string.
  • This column of oil directly above the HPI's discharge to the surface will be maintained by the back pressure valve BPV on the production tubing wellhead.
  • the BPV will usually be set at a back pressure that will prevent a substantial volume of gas from breaking out of solution in the column of oil as it reaches its surface.
  • the BPV opens produced crude oil will flow out, and only then will a substantial volume of gas break out of solution. The produced oil and gas will then be separated at the surface at the well's separating facilities.
  • the liquid column with surface back pressure valve can be adjusted to any range, lower or higher:
  • 4,500 psi, up to 5,000 psi can be created by a liquid column combined with BPV setting as desired, giving desired differential pressure of 500 psi to 1,000 psi, as needed, in order to open the injector valve's small pilot valve.
  • This bottomhole operation differential created by a liquid column with an accurate BPV setting can vary, higher or lower, as needed in the injector-wellbore operation.
  • the liquid column BPV helps control and allow the injector to operate at any extreme high bottomhole pressure, whether 1,000 psi to 5,500 psi up to 10,000 psi or higher, for a complete range of injected pressure relative to well depth
  • LC-BPV liquid column BPV
  • the injector enter the injector to open its float mechanism by submerging it and are produced surging the lower pressure liquid towards the surface through the LC-BPV by the force of higher bottomhole pressure.
  • the tubing wellhead BPV produces all incoming liquids at the surface at a high flow rate, injected by higher pressure annulus gas downhole.
  • High bottomhole pressure injecting the incoming liquid hydrocarbon or water is the injection motor in the production tubing and the wellbore.
  • This injection motor operates the HPI to produce liquids up the tubing and, in certain scenarios, maintains free high-pressure gas in the open gas zone as it enters the wellbore due to the incoming liquid's higher hydrostatic head pressure.
  • the HPI on the bottom of the tubing string which leads to the surface is the casing annulus liquid pressure drawdown point. Special designs have been invented to prevent the high influx and accumulation of formation sand and debris that high volumes of liquid hydrocarbons could carry (see separate heading, entitled “Improved Downhole Oil Liquid Injector”).
  • the present invention provides a lengthened float to the DOLI as an alternative absolute solution having no high pressure or well depth limitations for the GIC high pressure reservoir wellbore operating system.
  • the float is open at the top and closed at the bottom. The closed bottom is opened with a hole to receive a valve stem that operates the DOLI valve.
  • the float device can be lengthened to various lengths by connecting light-weight float material collars threaded to receive reinforced threaded float ends. Collar connections can be made up inside float in order to maintain float's restricted outside diameter i.e., a float in designated lengths of approximately 20 feet to 30 feet can be connected by threaded collars and assembled as the tool is lowered into the wellbore at the wellhead.
  • a lengthened outside jacket, also with threaded collars, is required for the DOLI, which likewise can be assembled first as the tool enters the wellbore (being made up at the wellhead.)
  • the double valve will remain in the lower part of the float with its discharge line leading to the injector head, the injector head being the production tubing connection.
  • the distinct advantage of a lengthened float is its added weight to open the ⁇ fraction (3/16) ⁇ ′′ pilot valve at very high pressures.
  • An example: a ⁇ fraction (3/16) ⁇ ′′ pilot valve will open at 1,000 psi at an excess float weight of 27.6 pounds.
  • a ⁇ fraction (3/16) ⁇ ′′ pilot valve will open at 5,500 psi bottomhole pressure with an excess weight of 151.8 pounds created by an extended float in a total length of approximately 107 feet. Therefore, the lengthened float will open the pilot valve at 5,500 psi bottomhole pressure.
  • this system will discharge high pressure oil to a sudden drop in pressure in the tubing where a volume of gas breaks out of solution and flows crude oil towards the surface.
  • the oil flow can be aided by fluid-operated gas lift valves.
  • Above the lower gas lift valves on the tubing is located a Venturi tube device, which by the velocity flow through its inner throat creates a more efficient gas-liquid mixture piston sweeping action to help drive the flowing liquid column to the surface.
  • additional gas lift valves without Venturi tubes are spaced at higher levels and activated by the tubing pressure which flows liquids using high-pressure annulus gas onto the surface to well's tubing flow surface receiving system, typically a surface separator.
  • the purpose of the gas cap repressuring (if it is an older gas zone) or newly pressuring (if it is an original new zone) is to increase the pressure on the gas cap to a chosen, high optimum pressure.
  • Some of the injection gas here can go into solution with the oil (is solubilized into the oil—see CO 2 patent mentioned in background) on the upper crest of the gas cap.
  • a pressurized gas is chosen that is identical or compatible with the reservoir liquid hydrocarbons.
  • the purpose of the oil zone repressuring is severalfold: (1) To permeate the oil with pressurized gas which will go into solution with the oil under a designated pressure. Such pressure is created to the required optimum pressure by the surface compressor, which compresses pressurized gas into the oil zone. (2) As pressurized gas goes into solution within the oil, solution gas pressure returns to the oil. (3) As pressurized gas goes into solution within the oil, increasing the oil's mobility, it decreases its density, making it lighter by lighter density gas going into solution with a heavier density liquid (the in-place oil). (4) The combination of the aforementioned benefits makes the oil migrate more freely and rapidly towards the wellbores, horizontal and/or vertical, to be produced at a higher rate while efficiently enhancing ultimate recovery.
  • the pressured light oil buildup starts around the perimeter and slowly migrates into other, less energized, oil in the radius around the horizontal borehole. This process continues supplying solution gas into the surrounding oil, continually providing solution gas to the oil as it migrates outward, until it reaches saturation points at given moderate to higher pressures. This process tends to build up as rising, high-pressure injected gas meets gas-saturated oil, forcing the pressurized gas to the lower pressure, nonpressurized oil in the outlying borders. This high-pressured gas will move away from the repressured zone around the wellbore, contacting even more reservoir liquids as banks of saturated crude form.
  • the gas injection period in chosen areas of the hydrocarbon reservoir into the gas cap is continuous or intermittent until a desired pressure is reached. Also, produced gas breaking out of solution from producing liquid hydrocarbons is reinjected. It should be noted that the gas cap will communicate throughout the upper part of the entire reservoir due to the permeability of the overlying gas cap.
  • the oil zone repressuring is separate and will periodically cease when the oil zone reaches an optimum point to where the oil has both increased maximum mobility through pressurized gas saturation and is considered to be at the optimum pressure within the liquid hydrocarbon zone by injected gas reentering solution within the oil. At the ideal point, these injection (into the oil zone) wells will be converted to production wells.
  • the DOLI In order to produce the hydrocarbon reservoir's newly pressured gas cap and oil zones, the DOLI is installed on a production tubing string in the deepest part possible of the wellbore (rathole, when possible), ideally below the oil zone horizontal borehole or perforations in order to obtain the maximum drainage/liquid reservoir drawdown from that zone.
  • the DOLI will operate with an EFS as needed, which opens the DOLI's valve at the indicated bottomhole pressure.
  • a packer is installed at the precalculated liquid hydrocarbon (crude oil) reservoir level below the gas cap.
  • the packer will have a pressure relief valve discharge tube (PRVD tube).
  • the PRVD tube will be set to open in order to relieve pressurized gas buildup in the upper well bore below the packer during the production process, through the packer into the upper reservoir gas cap within the wellbore. Any relief gas relieved through the PRVD tube can reenter the upper open gas cap in shut-in pressure scenarios. Relieved pressurized gas in the upper reservoir will reenter the open gas zone when outside gas is being injected into the gas cap via casing annulus once injection pressure exceeds gas cap reservoir pressure.
  • pressurized gas dissolved/in solution with the oil
  • the gas in solution with oil levels will depend upon the prior period of pressurized gas injection. Injected pressurized gas will tend to surge out in a flooding pattern, subject to the reservoir's permeability, thereby seeking non-gas-saturated oil at its levels.
  • the wells will be killed with a kill liquid (usually water or oil) in order to run the injector system.
  • This kill liquid would then be swabbed back to bring the well around and put on production at its critical pressure level.
  • the well Once the well is producing, it will stabilize according to the amount of liquid entering from the liquid hydrocarbon reservoir. Any and all liquid hydrocarbon or water production entering the vertical wellbore will accumulate into the lesser pressure tubing string.
  • the injector tubing string to the surface is the casing annulus liquid draw-down point.
  • each reservoir will maintain a given fluid level within all the wellbores entering that reservoir, and, further, that this fluid level is consistent and varies only with backpressure on the wellbores.
  • this new wellbore is created within the initial backpressured wellbore annulus.
  • this new injector to tubing string wellbore will be open to close to atmospheric pressure (the well's surface separating system) for flowing heads of oil through the EFS as gas breaks out of solution.
  • FIGS. 1-12 of the following U.S. patents Granted to Kelley et al., U.S. Pat. No. 6,089,322 Jul. 18, 2000, U.S. Pat. No. 6,237,691 B1 May 29, 2001, U.S. Pat. No. 6,325,152 B1 Dec. 4, 2001, entitled “Method and Apparatus for Increasing Fluid Recovery from a Subterranean Formation”, particularly FIGS. 4, 5, 6, 7, 9, 10, 11 and 12, but not excluding FIGS. 3, and 8, for special production scenarios. It should be noted that in the production period of the repressurized/reenergized hydrocarbon reservoir, in the production wells, because of packer placement as seen in FIGS.
  • the present invention is applied in primary or middle-aged fields, where high, average, to lower gravity crude oils are found with substantial gas in place in the virgin gas cap.
  • This variation of the invention will be a valuable enhanced recovery method in areas where gas flaring is not permitted, or where gas pipelines are not available in many U.S. and world oil fields that lack gas handling and marketing facilities.
  • the natural gas found in the gas cap is produced to the surface for the sole purpose of being compressed by a compressor complex into a pressurized gas to be reinjected through a gas repressuring center tubing string to pass through one packer that is directly above the liquid hydrocarbon (oil) zone.
  • This compressed (optionally temperature controlled) pressurized injection gas is pumped/compressed into the mother oil zone, where it finds its own compatible oil to go into solution with, thereby adding further solution gas to the in-place oil to increase its pressure and mobility for enhanced recovery.
  • the oil zone is opened with a horizontal borehole or boreholes with deep perforations, or with deep perforations in the vertical wellbore.
  • the horizontal boreholes would be in the optimal part of the oil zone in order to fully saturate the oil by gas reentering solution with the oil in the radius around the borehole during the injection process.
  • multihorizontal boreholes can be used at strategic liquid hydrocarbon (oil) levels in the reservoir.
  • deep jet perforations can be used in the vertical wellbore.
  • a different outside gas (example: other source natural gas, CO 2 , or nitrogen) can be injected into the gas cap to increase its pressure to the optimum desired during and/or after drawing its natural gas off for repressuring/reenergizing its lower liquid hydrocarbon (oil) zone.
  • a relatively large volume of gas cap gas is not needed in related volume when newly energizing and pressuring the oil zone to intensify enhanced recovery.
  • gas pressure should not be notably lost during injection into the oil zone, as no substantial gas volume is spent.
  • all gas breaking out of solution in produced liquid hydrocarbons during the production process can be reinjected into the reservoir's gas cap and/or oil zone through the surface injection system. The only gas used from the reservoir is to run the surface injection systems, compressors, pumping systems, etc.
  • the Improved Injector (Imp Inj) disclosed is one of the most functionally important bottomhole (BH) tools for the production of liquid hydrocarbons and waters for today's oil and gas industry.
  • the Imp Inj has two basic functions: (1) To allow liquids to enter the production tubing freely and instantaneously, without any hindrance, as they enter the wellbore from the reservoir. (2) To keep out any and all free gas under all various pressure conditions. There are four production condition problems that the Imp Inj is meant to overcome: pressures, volumes, sands and well dimensions. There are certain orifice size restrictions and pressure/volume/sand/well dimension problems that the Imp Inj will overcome that the prior art will not. The Imp Inj in today's industry will be producing extremely large volumes of liquids under very high BH pressures and in cases with severe influx of very fine formation sands.
  • the screen's rib section slot orifice size openings are restrictive to large volumes of liquid hydrocarbons and/or waters (LH, W).
  • the present screen is 3.75 ft. by 4.5 in. OD and has an open flow area of 39.0 sq. in. per foot. and has a flow rate of 750 barrels per day (bpd).
  • the screen length will be increased. Going from the present position, as seen in FIG.
  • the injector screen will be used with the open slot rib section in a vertical position.
  • a vertical screen is shown on the injector at the oil/liquid inlet level.
  • the vertical screen provides more effective sand control, the vertical screen configuration prevents the liquid hydrocarbon/water contact that may carry fine formation sand from entering the screen rib section at the same level.
  • the vertical slots allow the sands more space to settle out to the bottom of the wellbore.
  • screen slots can be sized in 0.001′′ increments to retain formation sand. This new vertical design is not seen in the prior art.
  • the present invention also discloses an improved injector housing (not illustrated in figure drawings) by providing a thin shroud made of thin steel or synthetic material, rather than the standard, thicker pipe material.
  • the shrouded protective cover would be open at the top and closed or open at the bottom with a vertical screen inside thin, perforated shroud bottom when opened.
  • the improved shrouded design is particularly for wells with little or no sand influx, which is not uncommon in many oil fields. If needed, a vertical sand screen inside a thin perforated shroud may also be used on the upper injector's oil and gas intake to keep out well debris.
  • This thinner shrouded body to the injector would allow injector installation in smaller diameter wells which is common in many oil fields where its internal components can be changed proportionately and herein is claimed as a needed improvement to the invention.
  • the present invention has several objects:
  • the upper reservoir with packer with PRVD tube at desired liquid hydrocarbon level with DOLI on a tubing string can be used to produce these liquids.
  • a good example is deep, high pressure gas formations, which are mostly high-pressure gas but have valuable liquid hydrocarbons in the deeper, lower part.
  • Gas lift or pumping may be chosen, according to volume and pressure limitations and feasibility, to lift the liquid hydrocarbons or water to the surface. Because gas wells normally operate at a lower pressure than the exceptionally high pressure GIC, the EFS may or may not be required.
  • the new injector shown in the provisional patent application GIC, FIG. 4 shows a spring, or with a springy hollow bellows, closed at the top and open at the bottom, affixed to the float bottom that holds the pilot valve stem that holds the main tip on the main port outlet into the injector's discharged intake line.
  • This spring and/or bellows configuration will be designed to stay closed when any light gradient liquid CO 2 gas is present within the injector's float chamber.
  • This special injector system can also benefit by the EFS and/or the LC-BPV addition, so that its valve will open under various high pressures.
  • this spring and/or bellows configuration is designed to compress by the downward movement of the float and the attached valve stem only after the weight of fluid in the float surpasses that of liquid CO 2 or whatever liquid hydrostatic pressure the float is designed to open with.
  • This new spring and/or bellows addition to the injector is designed to open at a designated float-filled fluid density, coordinated with the injector's pilot valve orifice size.
  • the injector float when the injector float is filled with liquid CO 2 in the closed valve position, the float will not submerge or open the valve due to the closing power of the spring and/or bellows below it. However, at any predesignated hydrostatic head/weight exceeding that of liquid CO 2 , the spring and/or bellows would then be compressed, beginning at the opening of the injector's valve.
  • the pilot valve's orifice size also is critical to the operation of this new design.
  • the spring and/or bellows would be designed to fully compress when the injector's float is full of oil or the designated liquid.
  • FIG. 1 illustrates the concept of compressing a miscible gas to high pressure and injecting it directly into a downhole liquid hydrocarbon bearing reservoir through a tubing string, both through perforations in the main casing string and/or a horizontal wellbore extending laterally into the liquid hydrocarbon bearing zone.
  • compressed high pressure gas is injected into the tubing-casing annulus and into a horizontal borehole and/or perforations into the gas cap overlying the liquid hydrocarbon zone.
  • Arrows indicate miscible gas directly contacting liquid hydrocarbons and gas in the gas cap contacting a large area of the liquid hydrocarbon zone.
  • FIG. 2 illustrates a variation of high-pressure gas injection into the liquid-hydrocarbon bearing reservoir in which gas cap gas flows to a surface compressor through the tubing-casing annulus, isolated by a packer and is reinjected through the tubing string of the same well directly into its own compatible liquid-hydrocarbon zone.
  • FIG. 3 illustrates the components and operating principles of the Downhole Liquid Injector with its float-operated shutoff valve system permanently immersed in a liquid contained within the outer housing, and the sand screen featuring vertical slots around an internal ported base pipe.
  • FIG. 4 illustrates principal components of the extended float system in which float length is extended as much as four or five times that of conventional systems.
  • the sand screen with its ported base pipe is shown elongated also by addition of one or more sections.
  • FIG. 5 illustrates a second liquid-hydrocarbon zone producing system in which an extended-length float system operates under high bottomhole pressure to supply partial columns or slugs of liquids into the production tubing strung, through which they are lifted to surface using gas lift valves connected to the tubing-casing annulus, and in cooperation with a new venturi jet system.
  • FIG. 6 illustrates a system of producing a well under high bottomhole pressures utilizing a Downhole Liquid Injector system that allows only reservoir liquids to flow into the tubing string. Shown on the tubing string is a packer directly below the gas cap with a vent tube and gas pressure relief valve into the gas cap. Within the tubing, a full column of reservoir fluid flows through a surface backpressure valve.
  • FIG. 7 illustrates schematically an improved Downhole Liquid Injector with an extended float system as it would look in the wellbore's rat hole below the open-to-liquid-hydrocarbon (perforated) zone, to better appreciated its extended length in the wellbore.
  • Lengths of the improved liquid injector can vary from 120 ft. up to and over 530 ft. for high volume, excessively high pressure wells.
  • FIG. 1 schematically depicts principal features of the present invention in which liquid hydrocarbons within the downhole liquid hydrocarbons LH reservoir, which can be in various stages of crude oil recovery.
  • the present invention process is designed for crude oils of all gravities and is particularly vitally important for increasing recovery of all primary through marginal lower gravity heavy crude oils, of which there are vast reserve deposits in North America (U.S., Canada and Mexico), South America (Venezuela) and throughout the oil-producing world.
  • This invented gas solution and pressure reentry process is also extremely vital for converting unrecoverable oil reserves to become recoverable that have been depleted from their original state of being saturated with natural gas that was originally in solution within the crude oil under their original high virgin reservoir pressure.
  • the invention process's principal purpose is to reenergize with solution gas and pressure liquid hydrocarbon LH zones with high pressure natural gas where the crude is contacted directly with miscible natural gas pressurized by surface compression from compressor C and injected into the liquid hydrocarbon LH reservoir through an injection tubing string TS isolated from other reservoirs such as the upper gas cap GC and any deeper reservoirs by a packer P and bridge plug BP, respectively.
  • Natural gas enters into miscibility with liquid hydrocarbons at extremely high pressures.
  • the present invention discloses injection of a natural gas directly into liquid hydrocarbon LH zones pressurized by surface compression.
  • CO 2 is commonly used, and sometimes nitrogen; however, in this invention miscible natural gas is preferably used, when available, for injection into the liquid hydrocarbon LH reservoir's gas cap GC. Therefore, natural gas is preferably used when available through deeply penetrating horizontal boreholes HB drilled from the main wellbore and open to the tubing-casing annulus A above the packer P. Such a configuration pressures a very large area of the gas cap GC as the more friction-free gas moves through the higher permeability away from the horizontal borehole HB. Gas cap GC injection contacts and repressurizes a large area of the liquid hydrocarbon LH reservoir to work in conjunction with the miscible natural gas injection. It will also act to increase the efficiency of gravity oil drainage from within any portion of the gas cap GC above the liquid hydrocarbon zone.
  • the miscibility of CO 2 could be an alternative, or nitrogen with its various economic and environmental benefits, when available, where natural gas is not available.
  • FIG. 2 illustrates a claimed benefit of high-pressure natural gas injection in which the source of the high pressure miscible natural gas injection is the natural gas from the gas cap GC above its own liquid hydrocarbon LH zone and separated by a optimally placed packer P on the tubing string TS.
  • the natural gas is produced from the liquid hydrocarbon LH reservoir's gas cap GC up through the upper wellbore annulus A above the packer P into a surface compressor C, which compresses the natural gas at high pressures into the injection tubing string TS and into perforations of the liquid hydrocarbon LH zone in the main casing string CS and/or one or more horizontal boreholes HB with deeply penetrating perforations DP.
  • gas is not produced with the liquid hydrocarbons, so essentially all gas remains in, or is circulated back into, the downhole system into gas cap GC and/or liquid hydrocarbon LH formations to achieve optimally increased liquid hydrocarbon LH (crude oil and condensate) recovery.
  • FIG. 3 illustrates the primary components of the improved Downhole Liquid Injector DOLI disclosed in the present invention as the principal novel component of an improved downhole producing system process that will allow the system to produce liquid hydrocarbons at high pressures and volumes while maintaining these high pressures until the liquid hydrocarbons reach the production tubing having left the reservoir's formation in order to completely and thoroughly utilize of the newly increased crude oil mobility, crude pressure and reduced viscosity/density while retaining high pressure gases downhole in the gas cap and the liquid hydrocarbon reservoir in solution under pressure within the crude oil within the formation.
  • the Downhole Liquid Injector DOLI illustrated comprises the following basic components.
  • the extended float system EFS a major component advance, improving the Downhole Liquid Injector DOLI's functionability to produce and recover high pressure reenergized crude oil is described in FIG. 4.
  • the extended float system EFS and the vertical sand screen filter allow the Downhole Liquid Injector DOLI to produce all variable high pressures and volumes.
  • a float 12 constructed of a relatively thin steel, ex. 16 gauge, and 21 ⁇ 2 or 3 in. in diameter, depending of wellbore and Downhole Liquid Injector DOLI size, approximately 24 ft. long, in conventional downhole injectors.
  • the float 12 operates within an outer housing 10 of basic carbon steel of 4 in. outside diameter, typically containing male threads on top and bottom for connection of a top collar and a bottom female bull plug 11 with threads for either a male bull plug or an additional length of tubing for powdery sand collection.
  • the housing 10 will be permanently filled with a liquid level LL such as treated brine.
  • a liquid level LL such as treated brine.
  • the float 12 operates within this liquid, and its buoyancy, i.e., whether its rises or falls, depends on the density of fluids (liquids or free gases) that enter the top of the float 12 from the wellbore. Liquid hydrocarbons or water will add sufficient weight to cause the float to submerge. Gas will increase the buoyancy of the float, causing it to rise.
  • the function of float 12 movement is to open or close the shutoff valve SV attached to the bottom of the discharge line 13 extending from the bottom of the tubing string through the injector head 14 which contains the female thread for direct connection to the production tubing string.
  • the bottom of the discharge line 13 is the valve seat 16 for the main valve tip 17 .
  • This main valve is ⁇ fraction (11/16) ⁇ -in. in diameter.
  • the Downhole Liquid Injector DOLI of the invention features a double valve—through which pressure differential between wellbore, as applied into the float and onto the main valve, vs. lower pressure within the discharge line to the tubing—is reduced by the initial opening of a pilot valve of ⁇ fraction (3/16) ⁇ -in diameter.
  • the pilot valve tip 18 is located on a short valve stem 19 attached to the bottom of the float.
  • the tip contacts the ⁇ fraction (3/16) ⁇ -in. opening through the main valve tip which opens first, breaking the pressure differential seal and allowing the falling float 12 to pull open the main shutoff valve SV.
  • the injector is equipped with a novel, effective, vertical screen type sand/debris filter VF which is screwed into the top collar of the housing and into the bottom thread of the injector head 14 .
  • the screen filter of the invention features a base pipe with multiple ports 20 offering a high screen collapse rating and vertical screen slotted openings 21 featuring slots of 0.001-in. width for optimum efficiency and downhole life.
  • the vertical slotted screen is an improved sand screen in this invention and is claimed over prior art as being novel and more effective.
  • FIG. 4 illustrates principal features of the invention's Extended Float System EFS in which the injector's float 12 length is substantially increased, by four to five times or more, to provide increased net float weight to open the shutoff valve's SV pilot tip against excessively high pressure differentials which provide a novel advance and positive solution for high-pressure liquid hydrocarbon production.
  • injector housing length 10 is increased by adding housing threaded pipe with threaded collar sections.
  • the bottom bull plug arrangement is unchanged 11 in this injector version.
  • the shutoff valve system of FIG. 3 remains essentially the same.
  • the discharge tube 13 is equipped with fin-type centralizers 23 to keep float centered to discharge tube in wells deviated from vertical.
  • the exterior of the float 12 has half spheres of about ⁇ fraction (3/4 ) ⁇ in. diameter 24 spaced on the outer surface to prevent friction contact of the float against the housing 10 internal diameter.
  • Float sections are connected by internal special float material collars and threads 22 to achieve desired length and maintain original outside diameters. Each float section is specially precision-reinforced on the float 12 ends to be threaded for collar connectors 22 .
  • the screen filter will be lengthened as needed to give the vertical filter VF surrounding the ported base pipe 20 now additional needed flow volume.
  • a 3.75 ft., 41 ⁇ 2-in. outside diameter screen section can handle about 750 bbl/day flow.
  • Additional filter sections 25 can be added for high liquid volume, as needed, by screwing into a collar connection 28 .
  • the top section screws into the injector head 14 into which the bottom of the tubing string TS is connected.
  • FIG. 5 illustrates a production system of the invention which has a Downhole Liquid Injector DOLI (the actual tool is extremely long but is shown short for drawing) with an extended float system EFS and is located such that its long vertical screen filter VF liquid and gas intake rib section is in the vertical borehole near the bottom of the liquid hydrocarbon LH reservoir which produces into the wellbore from perforations in the casing string CS or in one or more perforated casing or open hole horizontal boreholes HB deeply penetrating the liquid hydrocarbon LH zone.
  • DOLI Downhole Liquid Injector
  • EFS extended float system
  • the extended float system EFS alone, as detailed in FIG. 4, will be approximately 120 ft. or more in length for excessively high pressure wells.
  • the claimed advantage of the Downhole Liquid Injector DOLI with vertical screen filter VF and with extended float system EFS is its ability to inject only reservoir liquids, hydrocarbons and/or water, under all extreme high pressure and volume conditions, that flow into the wellbore on into the production tubing string, while it detects the presence of free gas in the wellbore and positively prevents its flow into the tubing, while settling out on to the bottom wellbore possible high formation sand influx.
  • Further features of the extended float system EFS invention are derived from its section lengthened float system which gives the float required weight, when submerged in liquid, sufficient to open the shutoff valve at excessively high pressures inside the bottom of the float, to introduce immediate liquid production.
  • a prior serious limitation of the Downhole Liquid Injector DOLI and its float at conventional lengths is that excessive high wellbore pressures needed to maintain liquid hydrocarbons in a pressure-gas-saturated state for optimum inflow from the liquid hydrocarbon LH reservoir, create an unworkable or prohibitive seriously high pressure differential seal across the pilot tip of the two-part shutoff valve that prevents its opening.
  • the improved performance of the extended float system EFS allows opening of the ⁇ fraction (3/16) ⁇ -in. diameter pilot valve and subsequently the ⁇ fraction (11/16) ⁇ -in. main valve to allow production of all incoming liquid volume into the production tubing string TS at excessively high pressures.
  • a packer P containing a gas pressure relief vent tube VT is located on the tubing.
  • the vent tube VT is to release any free gas pressure buildup in the wellbore that exceeds the required maintained backpressure on the liquid hydrocarbon LH zone, also discharge excessive gas pressure rejected by the extended float system EFS, so it can reenter the gas cap GC for conservation and benefits of gas injection.
  • a high velocity flow novel improvement to the liquid hydrocarbon lift system is the venturi jet tube VJ.
  • the venturi jet has a short internal tube with a tapering construction in its middle that causes an increase in the velocity of flowing fluid which creates high velocity flow toward the well surface in the production tubing string TS.
  • This high velocity flow is combined with the lift forces of gas breaking out of solution in the flowing liquid hydrocarbon, with the injected lift force of higher pressure gas being introduced by the gas lift valve GLV directly below the venturi jet tube VJ.
  • the gas lift valve GLV introduces high pressure gas from the gas cap GC wellbore annulus A to flow liquid hydrocarbons being admitted by the Downhole Liquid Injector DOLI by the operation of the extended float system EFS opening at no pressure or volume limitations.
  • venturi jet tube VJ system with gas lift valves GLV is spaced at predetermined levels up the wellbore tubing string TS to efficiently lift all incoming volume of liquids with higher pressure gas.
  • the number of venturi jets VJ with gas lift valves GLV will depend upon well depth and each venturi jet tube VJ with its gas injection source gas lift valve GLV will be effectively spaced at predetermined levels on the tubing string TS to lift all variety of depth and pressure wells, from shallow (1,000 ft.), average (6,000 ft.), deep (15,000 ft.), to very deep (30,000 ft.), or below and above.
  • venturi jets VJ will not be used in order to keep a free open tubing space for swabbing the well when needed. Therefore, at a predetermined level only gas lift valves GLV mounted on outside mandrels will be used to complete high pressure injection gas lift from the open wellbore annulus A in order to lift all volumes of liquids at all various depths onto the surface of the well leading to the well's surface separating facilities.
  • FIG. 6 illustrates a second production system of the invention for producing liquids only from a liquid hydrocarbon LH reservoir through deeply penetrating perforations DP in the casing string CS or one or more horizontal boreholes HB and, as in FIG. 5, maintaining under pressure all reservoir fluids at a sufficiently high pressure within the wellbore in the annulus A to maintain inflowing liquid hydrocarbons' optimum mobility within the reservoir permeability by remaining gas saturated under pressure, i.e., the entire hydrocarbon reservoir remains under pressure as well as its producing wellbores in the field.
  • the Downhole Liquid Injector DOLI operating within the permanent liquid level LL fill in the injector's housing senses the difference between high pressure gas and liquid flowing into the submerged float and opens its internal valve to allow only liquid inflow, hydrocarbon or water, into the tubing string TS.
  • a packer P on the tubing string TS at the level of the top of the liquid hydrocarbon LH reservoir contains a gas pressure relief vent tube VT which allows excessive high pressure gas separated from the liquids in the wellbore to vent upward and reenter the gas cap for pressure conservation and continued benefits of gas injection.
  • the producing system invention shown serves to provide an increased pressure in the bottom of the tubing by maintaining a full column of fluid pressure within the tubing above the Downhole Liquid Injector DOLI and its associated check valve CV and adding to the column's pressure head with a backpressure valve BPV on the outlet of the tubing from the wellhead WH.
  • This pressure in the tubing string on the discharge side of the Downhole Liquid Injector DOLI's shutoff is designed by varying the backpressure valve BPV setting and calculating fluid column density to prevent substantial volume of gas breaking out of solution at all levels in the full-column hydrostatic head with end results to reduce the differential across the valve between wellbore and tubing such that the weight of a conventional or extended float system as described in FIG.
  • FIG. 7 illustrates schematically the total improved Downhole Liquid Injector DOLI with an extended float system EFS in a vertical casing string CS wellbore in the well rat hole just below liquid hydrocarbon LH formation(s).
  • EFS extended float system
  • both the gas cap(s) and the liquid hydrocarbon zone(s) are always maintained shut-in during total liquid hydrocarbon recovery.
  • This shut-in pressure is also maintained in the entire wellbore.
  • the improved Downhole Liquid Injector DOLI with extended float system EFS on into the production tubing string TS to surface creates the liquid pressure drawdown as this tubing string with Downhole Liquid Injector creates a new wellbore that removes only liquid flow without restrictions and shuts off the entrance of all free gas, at all pressures.
  • This new wellbore tubing string TS above the Downhole Liquid Injector DOLI uses lift gas from the wellbore annulus injected through gas lift valves GLV operating venturi jet tubes VJ. However, this lift gas is recycled back into the producing well system by the surface compressor in order to maintain required backpressure.

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US10/340,818 2002-01-09 2003-01-09 Advanced gas injection method and apparatus liquid hydrocarbon recovery complex Abandoned US20030141073A1 (en)

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US10/340,818 US20030141073A1 (en) 2002-01-09 2003-01-09 Advanced gas injection method and apparatus liquid hydrocarbon recovery complex
BR0406719-3A BRPI0406719A (pt) 2003-01-09 2004-01-05 Sistemas e métodos para aumentar a produção e recuperação do hidrocarboneto lìquido, petróleo bruto e/ou condensado, dentro de uma formação subterrânea de hidrocarboneto lìquido atraves de injeção de gás
PCT/US2004/000057 WO2004063310A2 (en) 2003-01-09 2004-01-05 Advanced gas injection method and apparatus liquid hydrocarbon recovery complex
MXPA05007415A MXPA05007415A (es) 2003-01-09 2004-01-05 Metodo avanzado de inyeccion de gas y aparato complejo para recuperacion de hidrocarburos liquidos.
CA002513070A CA2513070A1 (en) 2003-01-09 2004-01-05 Advanced gas injection method and apparatus liquid hydrocarbon recovery complex
GB0514180A GB2414754A (en) 2003-01-09 2004-01-05 Advanced gas injection method and apparatus liquid hydrocarbon recovery complex
CNB2004800056196A CN100347403C (zh) 2003-01-09 2004-01-05 先进气体注入方法及设备和液态碳氢化合物采收系统
US11/408,413 US7506690B2 (en) 2002-01-09 2006-04-21 Enhanced liquid hydrocarbon recovery by miscible gas injection water drive

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WO2013106205A1 (en) * 2012-01-10 2013-07-18 Conocophillips Company Heavy oil production with em preheat and gas injection
RU2505668C1 (ru) * 2012-07-27 2014-01-27 Открытое акционерное общество "Татнефть" имени В.Д. Шашина Способ разработки нефтяной залежи с применением разветвленных горизонтальных скважин
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US20140166280A1 (en) * 2011-08-16 2014-06-19 Schlumberger Technology Corporation Hydrocarbon recovery employing an injection well and a production well having multiple tubing strings with active feedback control
US8905139B2 (en) 2009-04-24 2014-12-09 Chevron U.S.A. Inc. Blapper valve tools and related methods
WO2015062922A1 (de) 2013-10-29 2015-05-07 Wintershall Holding GmbH Verfahren zur förderung von erdgas und erdgaskondensat aus gaskondensat-lagerstätten
EP2406460B1 (en) * 2009-03-13 2015-11-11 BP Alternative Energy International Limited Fluid injection
CN106285602A (zh) * 2016-08-22 2017-01-04 中国科学院力学研究所 一种用于页岩气开发的二氧化碳粉化开采装置及方法
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US8936091B2 (en) * 2009-01-30 2015-01-20 Boris Anatolievich Dudnichenko Well jet pumping assembly for degassing coal beds
US20110272047A1 (en) * 2009-01-30 2011-11-10 Boris Anatolievich Dudnichenko Well jet pumping assembly for degassing coal beds
EP2406460B1 (en) * 2009-03-13 2015-11-11 BP Alternative Energy International Limited Fluid injection
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US8905139B2 (en) 2009-04-24 2014-12-09 Chevron U.S.A. Inc. Blapper valve tools and related methods
US8607884B2 (en) 2010-01-29 2013-12-17 Conocophillips Company Processes of recovering reserves with steam and carbon dioxide injection
US20110186292A1 (en) * 2010-01-29 2011-08-04 Conocophillips Company Processes of recovering reserves with steam and carbon dioxide injection
US8733443B2 (en) 2010-12-21 2014-05-27 Saudi Arabian Oil Company Inducing flowback of damaging mud-induced materials and debris to improve acid stimulation of long horizontal injection wells in tight carbonate formations
US10669827B2 (en) 2011-06-28 2020-06-02 Conocophilips Company Recycling CO2 in heavy oil or bitumen production
US9540917B2 (en) * 2011-08-16 2017-01-10 Schlumberger Technology Corporation Hydrocarbon recovery employing an injection well and a production well having multiple tubing strings with active feedback control
US20140166280A1 (en) * 2011-08-16 2014-06-19 Schlumberger Technology Corporation Hydrocarbon recovery employing an injection well and a production well having multiple tubing strings with active feedback control
WO2013106205A1 (en) * 2012-01-10 2013-07-18 Conocophillips Company Heavy oil production with em preheat and gas injection
US9458709B2 (en) 2012-01-10 2016-10-04 Conocophillips Company Heavy oil production with EM preheat and gas injection
RU2505668C1 (ru) * 2012-07-27 2014-01-27 Открытое акционерное общество "Татнефть" имени В.Д. Шашина Способ разработки нефтяной залежи с применением разветвленных горизонтальных скважин
WO2015062922A1 (de) 2013-10-29 2015-05-07 Wintershall Holding GmbH Verfahren zur förderung von erdgas und erdgaskondensat aus gaskondensat-lagerstätten
CN106285602A (zh) * 2016-08-22 2017-01-04 中国科学院力学研究所 一种用于页岩气开发的二氧化碳粉化开采装置及方法
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CN1756891A (zh) 2006-04-05
CA2513070A1 (en) 2004-07-29
WO2004063310A2 (en) 2004-07-29
GB2414754A (en) 2005-12-07
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WO2004063310A3 (en) 2005-05-06
BRPI0406719A (pt) 2006-01-17

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