CA2513070A1

CA2513070A1 - Advanced gas injection method and apparatus liquid hydrocarbon recovery complex

Info

Publication number: CA2513070A1
Application number: CA002513070A
Authority: CA
Inventors: Terry Earl Kelley
Original assignee: Individual
Current assignee: Individual
Priority date: 2003-01-09
Filing date: 2004-01-05
Publication date: 2004-07-29
Also published as: GB2414754A; WO2004063310A3; CN100347403C; BRPI0406719A; US20030141073A1; GB0514180D0; MXPA05007415A; CN1756891A; WO2004063310A2

Abstract

The invention provides for injecting of high-pressare miscible natural gas directly into a newly opened or previously produced liquid hydrocarbon reservoir (LH) to saturate liquid hydrocarbons with solution gas to improve their mobility to flow toward and into producing wells. Concurrent injection of gas, miscible or otherwise, into hydrocarbon zone's gas cap (GC) supplies additional pressuring effects to aid there-saturation process. DownLole float operated injectors (DOLI) are improved to operate at high pressare maintained within the wellbore to assure liquid hydrocarbon flow completely out of the formation. The improved injector system then senses the difference between liquid and gas and closes its valve to retain the gas within the wellbore and hydrocarbon formation. Any excessive gas pressure is relieved into the reservoir's gas cap for its continued benefits. All liquid-producing systems utilize an isxtended-float-length injector to permit the injeetor's float to open at high differential pressure created by maintaining the wellbore at pressare above gas into solution liquid saturation levels.

Description

ADVANCED GAS INJECTION METHOD AND
APPARATUS LIQUID HYDROCARBON RECOVERY COMPLEX
FIELD OF INVENTION
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 re-injection into the gas cap. Periodic reversal of the proposed invention-well system into production wells, and vice versa, is proposed for efficierit drainage of the surrounding oil reservoir.
The High-Pressure Bottomhole Liquid Injector and Fluid Recovery Complex, hereafter called HPI invention addition (filed July 5, 2002, U.S. PTO
N° 60~3935~ 5) 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. The invention 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. These high pressure levels could be in primary high-pressure reservoirs or after continued high-pressure injection into the reservoir's gas cap and/or oil zone. It is shown and claimed that producing under such high pressures maintained in the reservoir's gas cap and/or oil zone and adjacent wellbore will recover liquid hydrocarbons to maximum levels of recovery unable to be reached by prior art systems.
BACKGROUND OF THE INVENTION
The various processes used or proposed by the industry are described in U.S.
Patent 5,778,977, Bowzer et al, July 14, 1998. These include established industry practices of: 1 ) injecting gas into the gas cap to retain or increase reservoir pressure, including the added benefit of encouraging gravity drainage of oil liquids retained in rock volumes depleted of primary mobile oil liquids; 2) application of oil-miscible gases, such as C02 or methane, above reservoir oil liquids and thus increase their mobility within reservoir pore spaces or fractured systems; 3) intermittent injection of gas and water, and even foam; 4) injection of COZ into vertically fractured reservoirs; 5) injection of a coolant to thereby increase the miscibility of C02 in crudes; 6) determination of the critical properties of various crude components to achieve first-contact miscibility. Principal problems discussed include the likelihood of injecting gas breakthrough back to the producing wells) instead of creation of an effective flood front to drive the more mobile crudes toward lower pressure producing zones.
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.
COZ 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 COZ (high percentage of nitrogen) is used to propagate the COZ downwardly. Also, nitrogen is used by the Mexican national oil company Pemex as a reservoir gas-cap expansion and oil re-pressuring mechanism in its giant Cantaretl 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 January 9, 2002, with U.S. PTO 60/346311. The HPI with the Extended Float System invention is also meant to produce other high-pressure scenarios other than those disclosed in this present invention.

The present invention provides nevi and novel injection, production, and recovery systems, and methods not seen in the prior art, and never before known or used in the world oil and gas industry. These important advanced methods and .
techniques for increasing ultimate recovery of liquid hydrocarbon reserves, are here after disclosed.
SUMMARY OF THE INVENTION
The basic production system proposed herein is described in U.S. Patents US
6,089,322 July 18, 2000, US 6,237,691 B1 May 29, 2001, US 6,325,152 B1 Dec. 4, 2001, and US 6,22,791 B2 September 23, 2003 with international application number PCT/US97/21801 .entitled "Method and Apparatus for Increasing Fluid Recovery frorn a Subterranean Forrraation", and succeeding divisional applications, which describe an downhole oil liquid injector (DOLI) and several new applications in various types of oil and gas producing scenarios. These production systems can be used in certain limited production scenarios, while entirety new high pressure production configurations will be used to produce the GIC when the hydrocarbon reservoir injection welts are converted to production wells. Further improvements in the DOLI
system are described herein to produce special downhole liquid-gas definition at high pressures and selection effects described.
Because of the importance of the major objects of the present invention, see "Statement of the Object of the Invention", which are concerned with recovering vast amounts or presently unrecoverable liquid hydrocarbon reserves to become recoverable with this invention and, further, because the present invention's liquid hydrocarbon recovery processes have various phases, this section is given to also help explain a full disclosure of the present invention, to better understand the section entitled "Detailed Description of the Invention".
The present invention discloses systems and methods: (1 ) to reenergize hydrocarbon reservoirs that are losing their original natural gas pressures and gas energy, particularly 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 critically valuable solution gas in the crude oil, by returning solution gas, energy and pressure to the in-place crude 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. (3) To newly, and additionally energize, thereby maximally increasing crude oil mobility, gas energy and pressure in various primary hydrocarbon reservoirs that contain high, average, medium, and especially lower gravity (heavier) crude oils, again by pressurizing and energizing, adding critically valuable solution gas, pressure, energy and mobility to the in-place crude oil considerably decreasing its viscosity, capillarity and adhesiveness, as well as increasing the pressure in the overlying gas cap. In order to do this, the gas injection re-pressuring system will target an entire hydrocarbon reservoir or chosen sections of that same reservoir in synchronized patterns.
In all the foregoing gas injection applications the present invention provides that, the critically valuable return of solution gas, pressure, energy and mobility to the in-place crude oil and free gas pressure and energy drive to the gas cap is maintained and locked-in in the entire hydrocarbon reservoir during the complete production and recovery process of the injected into in-place liquid hydrocarbons.
The present invention also provides that, thus, after the gas injection period, during the extensive liquid hydrocarbon production and recovery period, highly valuable re-injected solution gas will continue to remain in solution within the total in-place injected oil, where it has re-entered solution within that crude oil under a predetermined injection pressure, which is maintained, until it has been fully recovered, completely out of the hydrocarbon formation rock into the production tubing string on towards the surface. After leaving the formation rock producing liquid hydrocarbons first enter the high pressure bottomhole liquid injector opening its extended float system and its production valve mechanism, where the then producing crude oil filled with solution gas senses an abrupt pressure drop, and only then solution gas can break out of solution where it flows the valuable liquid hydrocarbon crude oil through the production tubing string on towards the surface separating facilities.
During the gas injection process, the surface compressor, the surface wellhead casing gas control valve with its surface pressure gauge, and an optimally set downhole injection-production packer, all contribute to holding and maintaining this required high pressure on the entire chosen hydrocarbon reservoir. After the gas injection process this critically required predetermined high pressure must be continually held and maintained on the entire liquid hydrocarbon reservoir.

The present invention provides that during the extensive liquid and gaseous hydrocarbon production and recovery process this overhead high pressure is operated and controlled from two basic control points; the surface wellhead casing annulus control valve with its surface pressure gauge, and the preset downhole production packer with its pressure relief gas lift valve operated vent tube. The surface wellhead casing valve with its pressure gauge, cuts back or completely closes off gas flow from the casing wellbore annulus, depending upon the type of production scenario and reservoir. While the production packer when used relieves gas pressure into the upper wellbore annulus above the liquid hydrocarbon crude oil zone where it has been preset. .
The initial and principal gas 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. Here, any variety of chosen gases can be used, such as, but not limited to, natural gas, CO2, or nitrogen (it should be noted that many fields are already using COZ or nitrogen). Multi-zone 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 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, whether horizontal boreholes or perforations. Here, a second source gas SG2, is pressurized at the surface by a compressor assisted optionally with temperature control so that the SG2 will enter the liquid hydrocarbon zone as a compressed, pressurized gas, entering and going into solution with the in-place crude oil at an optimum injection pressure. Here, it is described that the oil zone will be horizontally drilled optionally with deep jet perforations. Here, 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.
Natural or miscible gas that is chosen to be compatible with the crude oil in its reservoir is injected directly into the pre-indicated crude oil zone, through its horizontal boreholes or perforations. This injected gas, at an optimum given pressure level enters solution with the crude oil it comes into contact with. When the crude oil zone, under an optimum injection pressure reaches an optimum gas saturation level, with the injected gas having entered into solution within the crude oil through the permeable formation, the critically important production and recovery process will be ready. The foregoing, novel, process of injecting gas under pressure into the crude oil within its natural formation and maintaining that pressure throughout the reservoir and its producing wellbores entire production and recovery life is claimed in the present invention as a new and novel process which overcomes serious limitations the prior art cannot.
The following liquid hydrocarbon production and recovery process allows re-energized crude oil zones with newly injected solution gas, together with the present solution gas, if any within the in-place crude oil to be recovered and produced under pressure, thereby not losing the crude oil's new life's mobility. Recovering and producing under pressure prevents solution gas and pressure from breaking out and escaping. Producing under pressure recovers the total in-place crude. oil injected with gas. The injection process and production process work together as a complete recovery process. Therefore, the novel advantages of the injection process and the production phase process are claimed and overcome gas injection and liquid hydrocarbon production and total ultimate recovery limitations that prior art cannot.
One major problem with producing liquid-only inflow under high pressure applications, as needed in the above application, is that excessively high bottomhole pressure will prevent the injector valve from opening. 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, approximately 5,500 psi bellow or above during its production and recovery 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 level 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. In other words, a 316' pilot tip and seat as designed in the prior art, that opens to relieve lesser pressures in order to dislodge the main tip off tts ~~~~6' 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.
THE EXTENDED FLOAT SYSTEM
The present invention provides a specially lengthened float to the Downhole Oil Liquid Injector DOLI as seen in figure 3, 4, and 7, as an absolute solution having no high pressure and related 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 3/~6' pilot valve at very high pressures. An example: a 3/~6' pilot valve will open at 1,000 psi at an excess float weight of 27.6 pounds. Therefore, a 3/~6' pilot valve will open at 5,500 psi bottomhole pressure with an excess weight of 151.8 pounds created by an extended float. Therefore, the lengthened float, in pre-calculated lengths will open the pilot valve at 5,500 psi bottomhole pressure. The present invention proposes to have the EFS as short in length as possible, in order to allow the injector's perforated/screened liquid production section inlet to be as tow as possible in relation to the newly high pressured oil production zone. Therefore, some typical installation dimensions are as follows: in a 5 'h" OD casing a 16 gauge 2 'h" OD steel float inside a 4" OD
injector flush joint jacket housing will require 98' of EFS to open the injector pilot valve. In 6 5/8" OD casing, a 5" OD injector flush joint jacket with a 3 '/2" OD 14 gauge steel float would require 60' of EFS. in 7' casing, a 5 'h" OD injector flush joint jacket would allow a 4" OD float of 14 gauge steel that would require 53' of EFS.
This novel and operative extended float 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. As the flowing liquid hydrocarbon column is lifted in deeper wells, 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 the well's tubing flow surface receiving system, typically a surface separator. The inventor whom presently manufactures the DOLI as seen in prior art, makes claim to the practicality and operativeness of the new and novel EFS invention.
The extended float system EFS will produce all depth wells without any depth or pressure limitations. The unique and novel advantages of this invention are claimed and overcome all extreme high pressure limitations and related extreme high volume and depth lift limitations that the prior art cannot.
METHODS TO IMPROVE OR ASSIST THE DOLI OPERATION
Because it is impractical to use an injector valve's pilot valve smaller than 3/~6' diameter pilot port, two other application procedures are proposed. If not already existing in subject producing welts, these two application procedures are: to drill a sufficiently deep rathole in the well and/or to ream out an open hole and rathole in order to allow larger dimension DOLIs to operate, where feasible. A larger dimension injector with a larger float mechanism will help open a larger pilot valve with a larger main port against higher-pressure scenario extremes with the aid of the EFS
and/or LC-BPV, the EFS being the preferable scenario. Also, this invention proposes to specially drill and complete new wells in order to accommodate an extra large dimension DOLI system.
A DESCRIPTION OF THE GAS CAP REPRESSURING
The purpose of the gas cap re-pressuring, 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 may go into solution with the oil bellow the gas cap.
A DESCRIPTION OF THE LIQUID HYDROCARBON (OIL) ZONE REPRESSURING
A gas is chosen that is identical or compatible with the reservoir liquid hydrocarbons. The purpose of the oil zone re-pressuring is several fold: (1 ) To permeate the oil with pressurized gas which will readily go into solution or re-enter 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 crude oil, solution gas pressure returns to the oil. (3) As pressurized gas goes into solution within the oil, increasing the oil's mobility, and its propulsive force, it decreases its density, viscosity, capilarity, and adhesiveness, making it lighter by lighter density gas going into solution with a heavier density liquid the in-place oil. (4) The final result and purpose, being that the combination of the aforementioned benefits makes and allows the injected in-place crude oil to migrate more freely and rapidly as a newly lighten mobile fluid towards the wellbores, horizontal andlor vertical, to be produced at a higher rate while efficiently enhancing total in-place oil ultimate recovery.
The pressured light oil buildup starts around the perimeter and slowly migrates into other, less energized, oil in the radius around the vertical wellbore and or 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 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, non-pressurized oil in the outlying borders.
This high-pressured gas wilt move away from the re-pressured zone around the wellbore, contacting even more reservoir liquids as banks of saturated crude form.
GAS INJECTION PERIOD
(See GIC, Fig. 1 ) 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 re-injected. 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 re-pressuring 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.
When the GIC is injecting into the chosen sections of the reservoir rather than the entire reservoir, the sections that were producing will be converted to oil zone injection wells and the oil zones sections that were being injected into will be converted to producing wells. It should be noted that the injection and producing section patterns of the reservoir will be determined by studies of the reservoir. The feasibility of the alternative can be studied: to inject into the entire oil zone section of the reservoir at one time.
The present invention requires that the entire oil reservoir, both injection and production sections, be continually held under pressure from day one throughout the production life of that reservoir by improved downhole oil liquid injectors with the extended fload system (EFS) at the surface wellhead casing valve, with its surface pressure gauge and, or with packer configurations being permanently in place above the liquid hydrocarbon production sections. In some production scenarios only liquid hydrocarbons wilt be produced, while any gas breaking out of solution from the producing liquid hydrocarbons will be re-injected back into the reservoir and or used to operate surface systems. While in other productions scenarios, natural gas can be produced from the upper hydrocarbon reservoir at a controlled rate.
INSTALLING PRODUCTION SYSTEM PRIOR TO HIGH PRESSURE GAS INJECTION INTO
CRUDE OIL ZONES
The present invention will employ oil industry known and provided equipment and services for its installation into the well. This installation procedure will be made prior to high pressure gas injection into the oil zone. First by killing and controlling the well with non-damaging liquid fill, then the DOLI, with the EFS on the injection/production tubing string is lowered into the well to its predetermined producing position relative to the oil zone. The principal industry provided components on the tubing string are:
1.- A wireline operated from the surface well head through a pressure sealing lubricator, opening and closing a pressure sealing sliding sleeve tool on the tubing string above the DOLI. The sliding sleeve tubing joint is located at the predetermined injection into the oil zone area above the DOLI where it is opened by surface wireline control, for the present invention's high pressure gas injection procedure from surface through tubing into the opened oil zone.
Once the injection procedure is finished, the pressure sealing sleeve on the tool is then closed from the surface for the production period.
2.- The combination injection and production packer is supplied by the oil industry's global companies, such as Baker Oil Tools', Weatherford, and others.
The to be permanently set packer is on the tubing string above the sliding sleeve, which will.~be located at the top of the predetermined liquid hydrocarbon zone area below the gas cap where the to be pressurized oil zone's annulus is separated and sealed off from the gas cap annulus. This packer has two functions, to pressure seal the annulus during the injection procedure, and then later to relief gas build up pressure through its to be activated pressure relief vent orifice. The vent tube is a gas lift type valve which will operate on a side pocket mandrel above the packer for 5 '/z", 6 5/8", or 7" casing as shown in figure 9. The gas lift mandrel will contain a wireline operated dummy valve plug, which is removed and exchanged for the actual high pressure gas lift type valve by the wireline operating through a surface pressure control lubricator. The high pressure gas lift type valve is to relief gas pressure built up at a predetermined setting over the critical pressure of approximately 5,500 psi.
3.- Above the packer, on the tubing string are one or more gas lift valve mandrels which contain, again wire line operated dummy valves which maintain the high pressure seal during the gas injection process. When it is time for the production process, these dummy valves are pulled by the wire line and pre-set pressure gas lift valves are installed by the wire line.
Weatherford and other major gas lift valve companies supply such wireline operated gas lift valves and service.
AN OPTIONAL INSTALLATION PROCEDURE
In active high pressure wells where the above installation procedure was not feasible the following oil industry provided installation procedure can be used.
Once the gas injection process has completed a planned phase in which a predetermined volume of in-place crude has been solution gas saturated by gas entering solution with the crude oil under high-pressure, the present invention's production system can be installed. In active high pressure wells a principal objective of converting to the production scenario is to install the production system without killing the well with higher-density liquids, which is impractical at pressures exceeding 5,500 psi, and could be detrimental to near-wellbore permeability's.
A high pressure production system installation will use industry-available pressure-control services and systems for installing the present invention's downhole production equipment under excessively high wellbore pressures. Such pressure-control services are provided by known companies specializing in high pressure installations, such as Halliburton HW, Cudd Pressure Control, and others. An installation, under pressure, will entail providing high-pressure equipment on the surface wellhead that includes properly sized blowout preventers with dual hydraulic snubbing packers that close around the outside diameter of pipe sections to allow into and out of the well, pipe movement as the pipe slides along the pressure seal. When collars or other changes in pipe diameter such as gas lift mandrels, reach the sliding seal, the hydraulic packer sliding seal element above the collar is closed and the packer seal below the collar is opened to allow passage of the collar.
The two-packer opening/closing process is then reversed and pipe moving continues.
This process is called "snubbing" in the oil industry.
The snubbing process can be used to install the present invention's Downhole Oil Liquid Injector's DOLI closed at the bottom pipe housing containing the extended float system and its related internal parts, valve mechanism, 1 " discharge production line, and collars being assembled at the surface before actually entering the snubbing unit. This snubbing process continues until the DOLI's open perforated pipe section is reached. The snubbing unit then uses a specially designed lubricator which is built to scale to encase the open perforated pipe section approximately 30' to 38' in length.
The lubricator is then towered over the perforated pipe section and screwed into the lower snubbing unit. The top of the lubricator is equipped with a second set of snubbing packers, which will operate on the main tubing string, opening and closing for tubing collars, gas lift mandrels, and any production packers. With the top snubber closed on the tubing joint, the original snubbers can be opened, allowing communication of the DOLI to the tubing-casing annulus. Tubing string installation then continues for the complete well installation with the snubbing packers.
It should be noted that a wireline removable plug may optionally be installed directly above check valve on top of the DOLI in order to close off the tubing while going into or out of the wellbore in order to prevent liquid flow through the DOLI. Such wire line plugs are provided by Weatherford and other leading gas lift providers.
THE PRODUCTION WELL SYSTEM
Here it must be clearly explained and emphasized that the entire hydrocarbon reservoir, its gas cap(s), and liquid hydrocarbon zones) must be maintained under required high pressure levels, or shut-in pressure levels, in order to produce and recover the newly energized with solution gas and pressure liquid hydrocarbons within their given formations. These high pressure levels will be maintained in the wellbore and corresponding formations throughout the entire liquid hydrocarbon recovery process until the total in-place liquid hydrocarbon is recovered from the entire reservoir. Only then will the gas cap gas be released and produced in any substantial volume.
In order to produce the hydrocarbon reservoir's newly pressured oil zones, the DOLI is installed on a production tubing string in the deepest part possible of the wellbore, or its rathole, when possible, ideally below the oil zone horizontal borehole or perforations in order to obtain the maximum drainage/liquid recovery 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 pre-calculated 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 wellbore 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 once pressure exceeds gas cap reservoir pressure. , After the oil zone reservoir has been injected into the wells perforations and/or through a horizontal borehole or boreholes, pressurized gas, dissolvedlin solution with the oil, will gradually accumulate in the borehole radius of the oil zone. 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.
After the injection phase is completed, the well's production process begins.
Any and all liquid hydrocarbon 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, according to its given pressure, 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 back pressure on the wellbores. However, when the injector with tubing string to surface is present within the wellbores entering that reservoir, then, in effect, a new wellbore is created within the initial back pressured wellbore annulus. In a well operating with an EFS, 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 up through the EFS as gas breaks out of solution.
AN OPTIONAL GIC PRODUCTION WELL VARIATION
Reference is made to Figs. 1-12 of the following U.S. Patents Granted to Kelley et al., US 6,089,322 July 18, 2000, US 6,237,691 B1 May 29, 2001, US 6,325,152 Dec. 4, 2001, and US 6,622,791 B2 Sept. 23, 2003 mentioned under SUMMARY OF
THE
INVENTION, 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 re-pressurized/re-energized hydrocarbon reservoir, in the production wells, because of packer placement as seen in Figs. 4, 5, 6, 7, 10 and 12, noted above, the re-injected gas, both in the gas cap and in the oil zone, would not escape/dissipate through the production system, as only re-pressurized/re-energized liquid hydrocarbons will be produced through the liquid injector on up through the artificial lift system in the production tubing on to the surface. f An exception to this is when pressurized gas is produced with the oil and then is re-injected back into the reservoir injection system. This is noted in the use of Figs. 3, and 8, where optimally released gas is re-injected back into the reservoir from the surface operation. The extended float system can be applied on these production scenarios where high pressure prevents the injector valve's opening.
A SOURCE NATURAL GAS INJENCTION SYSTEM

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 re-injected through a gas repressing 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.
Here 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. In very thick, massive zones, multi-horizontal boreholes can be used at strategic liquid hydrocarbon (oil) levels in the reservoir. Where not feasible, deep jet perforations can be used in the vertical wellbore.

If needed, a different outside gas (example: other source natural gas, CO2, 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 re-pressuring/re-energizing its lower liquid hydrocarbon (oil) zone. However, 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. Further, gas pressure should not be notably lost during injection into the oil zone, as no substantial gas volume is spent.
Here, all gas breaking out of solution in produced liquid hydrocarbons during the production process can be re-injected 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.
IMPROVED DOWNHOLE OIL LIQUID INJECTOR
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 wilt 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 PRESSURE PROBLEM
When the screen's rib section's slots are plugged with fine formation sand, excessive high pressure can cause the screen to collapse. Therefore, the screen must be built on a collapse-resistant, reinforced perforated pipe base in order to not collapse the entire upper part of the injector in excessively high-pressure wells. All other high pressure level problems for all depth wells are completely overcome by the extended float system (EFS).
THE VOLUME PROBLEM
The screen's rib section slot orifice size openings are restrictive to large volumes of liquid hydrocarbons and/or waters (LH, W). Ex: 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). For new application in wells that are producing in the thousands of barrels of LH, W per day, the screen length will be increased. Going from the present position, as seen in Fig. 3 in an upper direction, whatever screen length required, the top of it with its perforated pipe base would make into the Injector's head, i.e., the injector's head would be the production tubing and/or pump connection. Ex: If 3.75 ft. of screen equals 750 bpd and a well is producing 7,500 bpd, then the Imp Inj would need 37.5 ft. of screen section on perforated pipe. If the screen section goes over the standard tubing pipe 30 foot length, then screw flush couplings will be used.
AN IMPROVED DESIGN OF THE INJECTOR SCREEN FOR THE SAND PROBLEM
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. For more effective sand control, screen slots can be sized in 0.001" increments to retain formation sand. This new vertical design is not seen in the prior art.
WELL DIMENSION PROBLEMS
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 perforated pipe head 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.
STATEMENT OF THE OBJECT OF THE INVENTION
The present invention has several objects:
1. To reactivate unrecoverable crude oil to become recoverable, such oil having Lost its solution gas to flowing the oil with gas methods. The U.S. and the world have vast amounts of this unrecoverable oil still in place,. sometimes as high as 80% of the original oil is left in place, dormant without solution gas.
2. To recover the total in-place liquid hydrocarbons in reservoirs that are still producing liquid hydrocarbons with gas in solution.
3. To enhance the recovery process of low gravity heavy crude oil. A large percentage of the U.S. and world oil supply is low gravity or heavy crude oil.
4. To generally enhance the recovery of all gravity crude oils by adding solution gas and pressure to the in-place oil.
It should be noted that the production system in the above technology eliminates flowing oil with gas, as it allows only liquid hydrocarbon recovery while retaining gas and pressure in the hydrocarbon reservoir. This production system, combined with injecting solution gas and pressure to the in-place crude oil, is considered to be a major liquid and gaseous hydrocarbon recovery advance for the U.S. and world oil industry, as it will recover the majority of the U.S.' and the world's in-place liquid hydrocarbons while keeping the reservoir's natural gas within its natural gas cap, stored for future production methods. Thus, the foregoing objects with their U.S. and global benefits are claimed and overcome all prior art, U.S. and world-wide.
Brief Description of the Drawings Figure 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.
Individually and above a packer isolating the liquid hydrocarbon 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.
Figure 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 re-injected through the tubing string of the same well directly into its own compatible liquid-hydrocarbon zone.
Figure 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.
Figure 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.
Figure 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.
Figure 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 back pressure valve.
Figure 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 50 ft. up to and over 230 ft. for high volume, excessively high pressure wells.
Figure ~ illustrates a well under high pressure miscible gas injection into both the gas cap and the liquid hydrocarbon zone from surface compressors, in this case through deep perforations in the vertical wellbore and through horizontal boreholes extending deep into the formation. The Downhole Liquid Injector (DOLI) is run on the tubing string with a permanent check valve directly above it and a wireline operated sliding sleeve valve above the check valve, which is opened and closed by wireline to allow either high pressure gas injection through the tubing into the formation through the lower tubing-casing annulus, or production of formation liquids up the closed tubing, respectively, without pulling the tubing string. For the packer vent tube relief valve and the one or more gas lift valves above the packer, wireline installed and removed dummy valve plugs are set into the mandrels for the injection process, as shown. This figure relates to Figure 1, of which the previous description discusses the injection process.
Figure 9 illustrates the production scenario following high pressure gas injection, with the downhole liquid injector, check valve, sliding sleeve tubing tool, packer with vent tube, and upper gas lift valves) already in place, as per Figure 8, and relating to Figure 5. To prepare for production, as shown, a wireline operated through a surface lubricator will be used to pull the dummy valves and install the gas lift valves, and gas lift type vent tube pressure releif valve shown. It will also shift the sliding sleeve valve to the close position. This will make the well system ready to flow saturated liquid hydrocarbons through the downhole injector while preventing free gas entry into the tubing, where gas pressure build up is relieved up the annulus by the packer and the vent tube arrangement. In figure 8 and 9, a bridge plug is shown below the DOLI, which wilt isolate any extensive rat hole or lower formations from the selected zone gas injection/production process.
Detailed Description of the Invention High Pressure Gas Injection into Liquid Hydrocarbon Reservoir Formations Figure 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. These oil reserves are now marginal with the majority of the original in-place oil unrecoverable or becoming unrecoverable, and a great part of the world's reserves are presently or in the stages of becoming marginal. Therefore the present invention injection process is used for all various types of crude oil gravities in production stages of primary (new oil) through to marginal (old, becoming dormant oil). These in-place liquid hydrocarbons LH (crudes) are injected into with high pressure natural gas from a surface compressor C that is compatible with their oil types, preferably natural gas produced from their same, or similar, reservoir field areas. Therefore, 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.

To most efficiently contact liquid hydrocarbons with the miscible natural gas, combinations of deeply penetrating perforations DP--such as those created by modern jet perforators--in the original casing string CS, and/or one or more horizontal boreholes HB, with the horizontal borehole's perforated casings directed away from the main wellbore in a predetermined direction and pattern to contact as much liquid hydrocarbon LH reservoir as possible. Miscible natural gas directed into the annulus A around and below the tubing string TS will contact liquid hydrocarbons LH
deep within the reservoirs as well as those in the near-wellbore area, by continued compression from compressor C, increasing solution gas and pressure reentry.
Re-saturation of liquid hydrocarbons LH around the wellbore from which natural gas is in the process of breaking out or broke out as a reaction to producing early high rates at low wellbore pressures is critical for converting unrecoverable oil to recoverable crude oil for total crude oil recovery. Flowing oil with gas practices rapidly degas crudes and create channels of released gas into the wellbore which is increasing the "marginal oil" problem in hydrocarbon reservoirs throughout all U.S. and world oil fields. Early operators saw these problems manifested in increasing gas/oil ratios and falling crude production as they blew off reservoir gas in flush production operations.
Natural gas enters into miscibility with liquid hydrocarbons at extremely high pressures. This identical injection process is also shown in figure B where the production system has been installed prior to the injection process. High pressure gas is injected from the surface compressor C through the well head WH down the tubing string TS as the high pressure sealing dummy gas lift valves DV and vent tube dummy valve DV hold the pressure seal. The closed packer P holds pressure from the top of the liquid hydrocarbon LH zone down to where the bridge plug BP holds the pressure bellow the liquid hydrocarbon LH zone. Injection gas exits out through the opened sliding sleeve's SS ports where the gas is high pressure compressed into the opened liquid hydrocarbon LH zone via deep perforations DP andlor horizontal boreholes HB.
The gas cap GC is also being injected into, from the surface compressor C via the casing string CS where dummy gas Lift valves DV on the tubing string TS hold the pressure seal as gas is compressed through deep perforations DP and/or horizontal boreholes HB into the gas cap GC. Thus the present invention discloses injection of a natural gas directly into liquid hydrocarbon LH zones pressurized by surface compression.
For gas cap re-pressuring, C02 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 re-pressurizes 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 C02 could be an alternative, or nitrogen with its various economic and environmental benefits, when available, where natural gas is not available.
Figure 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 andlor one or more horizontal boreholes HB with deeply penetrating perforations DP. As wilt be emphasized in other features of the invention, 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.
Improved Downhole Liquid Injector Features and Operation Figure 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 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 functionality to produce and recover high pressure re-energized crude oil is described in Figure 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, or 14 gauge and 2'/2in., 3 in., or 3'/z in. in outside diameter, depending of wellbore and Downhole Liquid Injector DOLI size, approxiimately 24 ft. long, in conventional downhole injectors. The float 12 operates within an outer housing 10 of basic carbon steel, 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. 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 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 3/16-in diameter. The pilot valve tip 1~ is located on a short valve stem 19 attached to the bottom of the float. The tip contacts the 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 fitter 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.
Figure 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. In the extended float 12 system EFS, 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 Figure 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. And the exterior of the float 12 has half spheres of about 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. For example, a 3.75 ft., 4'/2-in. outside diameter screen section can handle about 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.
Production Systems Producing at Maintained High Pressure Figure 5 illustrates a production system of the invention which has a Downhote Liquid Injector DOLI as shown in Fig. 4 (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 H8 deeply penetrating the liquid hydrocarbon LH
zone. The major portion of the extended float system EFS described in detail in Figure 4 operates within a rat hole when possible or an extended portion of the casing string CS wellbore isolated at the lower end of the Downhole Liquid Injector DOLI with extended float system EFS by a bridge plug. The extended float system EFS
alone, as detailed in Figure 4, will be approximately 60 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.
Thus, the improved performance of the extended float system EFS allows opening of the 3116-in. diameter pilot valve and subsequently the 11 /16-in.
main valve to allow production of all incoming liquid volume into the production tubing string TS at excessively high pressures. When the extended float system EFS
opens the injector's shutoff valve SV, then the result is that extremely high pressure flows, columns or slugs of liquids into and upward in the tubing where liquid flow is aided by gas breaking out of solution and are further flowed to surface by entering lift gas from the higher pressured gas from casing annulus through required number of stage lift gas-lift valves GLV which are activated by sensing the pressure of the flowing liquid column above their given level in the tubing. The gas lift valves GLV will be spaced, as needed, above the liquid hydrocarbon LH zone into the tubing string TS onto the surface.
At the depth of the bottom of the gas cap GC and the top of the liquid hydrocarbon LN zone, 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 back pressure 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. The 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 welt 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. Approaching the tubing string TS wellbore surface, venturi jets VJ wilt 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. This identical production process is shown in figure 9 where the production system was installed before the injection process. The dummy valves have been wireline retrieved and actual operative gas lift valves GLV have been wireline installed on the production tubing string TS. The injection/production packer P is now converted to its production phase by its dummy valve DV having been also wireline retrieved and an actual pressure relief vent tube VT gas lift valve installed by a wireline. The pressure sealing sliding sleeve SS has been closed by wireline and the well is put on to its production phase.
Here it should be clearly noted that only lift gas will be used from the gas cap GC annulus A, that the gas cap GC will not produce gas to the surface. Rather gas pressure will remain shut in, as likewise pressure will be kept on the liquid hydrocarbon formation during its entire production and recovery life. The purpose is to keep high pressure on the reservoir's gas cap and the liquid hydrocarbon zone so that no substantial gas volume will break out of solution. If substantial pressure were released (primary or injected gas pressure) the liquid hydrocarbons would lose their recovery life mobility from the original or new solution gas and pressure ~Nithin the liquid hydrocarbons.
Figure 6 the improved downhole oil liquid injector DOLI with the extended float system EFS as seen in Fig. 4 and explained in Fig. 5, will open the downhole liquid injector's DOLI double shutoff valve SV, as seen in Fig. 3 and Fig. 4, under all various extremely high maintained pressure-operating conditions witho~rt pressure limitations. The extended float system can be lengthened to any required length without limitation in the liquid hydrocarbon LH wellbore annulus A, with or without a wellbore annulus rathole. Therefore Figure 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 in-flowing liquid hydrocarbons' optimum mobility within the reservoir permeability by remaining gas saturated under pressure, i.e., the entire hydrocarbon reservoir remains under maintained operating high pressure as well as alt 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 float and opens its internal valve by submerging to allow only liquid hydrocarbon inflow 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 maintained overhead pressure, conservation and continued benefits of gas injection.
The present invention illustrates a maintained high operating pressure in the liquid hydrocarbon LH formation as well as in the gas cap GC formation. .
Natural gas will not be produced from the gas cap GC formation at any stage of the liquid hydrocarbon production and recovery period, unless it is desirous in massive thick natural gas formations to produce natural gas at a controlled rate while also producing liquid hydrocarbons. To the contrary, the reservoir's total gas cap GC must remain shut in as well as the. re-energized with solution gas and pressure liquid hydrocarbon LH formation in all producing wellbores in the entire producing field.
The producing system shown here uses no lift gas injected or introduced from the gas cap GC or the liquid hydrocarbon LH wellbore annulus A, nor is there any artificial lift system in the production tubing string TS. This invention's production system works by extremely high pressure solution gas breaking out of solution, as the high pressure liquid hydrocarbon passes the downhole injector's DOLI shutoff valve's main seat port.
Here the very high pressure liquid hydrocarbon enters a sudden extreme pressure drop, as it is exposed to this pressure drop and surged by high bottomhole pressure through the injector shutoff valve mechanism into the very low, close to atmospheric pressure production tubing string TS. This sudden pressure drop allows incoming produced injected with solution gas liquid hydrocarbon to burst out of solution, where extremely high pressure gas breaks .out, to then flow the liquid hydrocarbon upward through the production tubing string TS, to be flowed out at the wellhead WH
tubing exit port. A typical well operating at 5,500 psi wilt support 0.32 gravity crude oil up the tubing string TS surface to 17,187.5 feet. Therefore, the exceptionally high bottomhole pressure immediately passes all incoming liquid production through the downhote liquid injector DOLL into the much lesser pressure production tubing string.
This incoming liquid production will maintain a constant liquid level LL at the downhole liquid injector DOLI vertical screen fitter VF. These incoming production liquids immediately enter through the downhole liquid injector DOLI into the lesser pressure production tubing string TS, where at given levels of the liquid hydrocarbons movement upward, high pressure solution gas continues to break out of solution to flow off in Rowing heads of liquid hydrocarbons. Thus, these flowing heads of liquid hydrocarbons are flowed on out to the surface by high pressure gas within these liquids breaking out of solution. This flowing process of this invention flows alt produced liquid hydrocarbons out through the wellhead WH production tubing string TS exit port on to the surface separating facilities. Note only gas breaks out of solution in liquid hydrocarbons that have left the liquid hydrocarbon LH
reservoir formation in transit through the injector DOLI into production tubing string TS onto the surface recovery system, because of maintained high back pressure or shut in pressure on the entire hydrocarbon formation and its well bores.
This production system's depth restrictions are related to the system's chosen wellbore operation pressures, i.e., 5,500 psi will easily flow produced liquid hydrocarbons in wells of approximately 16,000 feet or less. However, in deeper wells the production system shown in Fig. 5 is the preferred lift system because of its gas lift valve with venturi jet tube increased lifting abilities. This production system as well as the production system shown in Fig. 5 can produce a Multi-zone wellbore by isolating chosen zones in groups or individually.
Figure 7 the present invention operates without any packer in wells that have gas zones in oil zones at close to equal pressure and illustrates schematically the total improved Downhole Liquid Injector DOLI with an extended float system EFS in a vertical casing string CS wel.lbore in the well rat hole just below liquid hydrocarbon LH
formation(s). Here it is shown with various sections of 24 ft. float length connected by special light weight float material collars for recovering liquid hydrocarbons in wells operating at estimated required pressures of 5,500 to 6,000 psi. Total float lengths, depend upon casing size and related float OD size required in order to produce the high pressure gas injection scenarios, as seen in Figure 1 and Figure 2.
No other downhole~ tool or production system is available in today's oil and gas industry or shown in any prior art that will produce at these high pressure levels while retaining high solution gas and free gas pressure in the wellbore and the reservoir's liquid hydrocarbons LH and gas cap GC formations. This improved Downhole Liquid Injector DOLI with an extended float system EFS can produce at all high pressures for a variety of high pressure injection scenarios in wells up to 10,000 psi or above.
Sufficient rat hole below the producing formations, if not available, can be specially drilled for this advanced recovery system. Also, all high extreme volumes of liquids present no limitations, as once the extended float system EFS opens, liquids flow at all incoming volumes to continue to drain the reservoir into the lesser pressure tubing string because the extended float opens with little liquid hydrocarbon volume.
Even 250 ft. total of an extended section float will open with very tittle proportionate liquid hydrocarbon volume to open at 10,000 psi as a high pressure example.
Therefore, the improved Downhole Liquid Injector DOLI with the extended float system EFS will keep the reservoir liquid hydrocarbon zone maintained at shut-in high pressures during the entire production and recovery life of the reservoir after the application of the advanced gas injection process stage shown in Figure 1 and Figure 2, for which this production system was especially invented and designed. In other words, after the natural gas injection into the crude oil zone at the given high pressure level where gas enters miscibility with the liquid hydrocarbon, this pressure absolutely must be maintained at or above its critical pressure level to prevent solution gas break out, forward through the entire production and recovery stage of this invention until total in place liquid hydrocarbons (crude oil and condensate) are recovered from liquid hydrocarbon formations to surface. Fig. 7 does not show any packer with pressure relief vent tube, therefore in this scenario a downhole liquid injector DOLL with an extended float system EFS could be used without a packer by keeping both the open liquid hydrocarbon zone LH and the open gas cap in an open wellbore communication: This can be done in order to produce liquid hydrocarbons through downhole liquid injector DOLI onto surface through tubing string TS
with or without artificial lift systems in high pressure shut in well bores. In reservoirs with massively thick upper gas zones gas can be produced at a controlled back pressure rate. It is estimated in average scenarios that approximately 5,500 psi to 6,500 psi or above must be maintained to fully recover all liquid hydrocarbons (crude oil and condensate) from their place in the formation on through the wellbore flow into the improved Downhole Liquid Injector DOLL with extended float system EFS,. where only then, inside the production tubing string TS, can a substantial pressure drop be permitted for total ultimate liquid and gaseous hydrocarbon recovery.
Therefore, in conclusion to all the foregoing production scenarios Fig. 5, 6 and 7, both the opened gas caps) and the opened liquid hydrocarbon zones) are always maintained shut-in during the total Liquid hydrocarbon recovery process. This shut-in pressure is also maintained in the entire wellbore. The improved Downhote 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 back pressure.
The foregoing disclosure and description of the invention from the total specification are thus explanatory thereof. It will be appreciated by those skilled in the art that various changes in the size, shape and materials, as well as in the details of the illustrated construction and systems, combination of the features, and methods as discussed herein may be made without departing from this invention. Although the invention has thus been described in detail for various embodiments, it should be understood that this explanation is for illustration, and the invention is not limited to these embodiments. Modifications to the system and methods described. herein will be apparent to those skilled in the art in view of this disclosure. Such modifications will be made without departing from the invention, which is defined by the claims.

Claims

1. A system for increasing liquid hydrocarbon recovery from a downhole liquid hydrocarbon formation through an injection tubing string, comprising:
a vertical wellbore opened both into a gas cap and the liquid hydrocarbon zones with horizontal boreholes and or perforations;
the injection tubing string from its connection to a surface compressor down the vertical wellbore to be open ended by the selected opened liquid hydrocarbon zone;
a packer selectively positioned above the downhole liquid hydrocarbon formation for sealing a well annulus outward from the injection tubing string;
a bridge plug placed previously at an optimum level below the liquid hydrocarbon zone to isolate the choice injection area;
the surface compressor for injecting high pressure miscible natural gas through the injection tubing string below the packer out the vertical tubing's open end directly into the open horizontal borehole or boreholes and or perforations compressing high pressure natural gas into the selected liquid hydrocarbon zone or zones where it enters solution with the liquid hydrocarbon to increases pressure and reduce its viscosity, thereby increasing its mobility and expulsive force to be produced and recovered under maintained high pressure; and maintaining gas cap and liquid hydrocarbon zone or zones under high pressure forward to the production and recovery process of this invention.

2. The system as defined in Claim 1 wherein the surface compressor injects miscible and or other gases from surface at high pressures through a well annulus into existing gas cap formation through a horizontal borehole or boreholes and or perforations above the tubing packer and in communication with underlying liquid hydrocarbon formation.

3. A method of increasing liquid hydrocarbon recovery from a downhole liquid hydrocarbon formation through an injection tubing string comprising:
providing a vertical wellbore annulus with horizontal borehole or boreholes and or perforations indirect communication with the liquid hydrocarbon zone or zones;
positioning the injection tubing string from its connection to the surface compressor down the vertical wellbore open ended by the opened liquid hydrocarbon zone;
positioning a packer above the liquid hydrocarbon zone for sealing the well annulus outward from injection tubing string;
setting a bridge plug at an optimum level below the selected liquid hydrocarbon zone or zones, isolating the chosen injection area;

injecting high pressure gas from surface compressor through the injection tubing string below the packer out the vertical tubing's open end directly into the open horizontal borehole or boreholes and or perforations compressing gas deep into the liquid hydrocarbon zone or zones to enter solution under pressure with the liquid hydrocarbon;
establishing increased pressure and viscosity reduction increasing liquid hydrocarbon's expulsive force and mobility through high pressure gas going into solution with liquid hydrocarbon to be recovered under a maintained high pressure level; and maintaining opened gas cap and opened liquid hydrocarbon zone or zones under high pressure forward through the production and recovery process of this invention.

4. The method as defined in Claim 3 further comprising:
injecting miscible gas and or other gases through the well's upper annulus above top packer into the horizontal borehole or boreholes and or perforated gas cap overlying the liquid hydrocarbon zone, and establishing increased overall formation gas cap pressure by the surface compressor injection to increase efficiency of miscible gas injection into the lower liquid hydrocarbon zone.

5. The method as defined in Claim 4 further comprising:

enhancing gravity flow of lower liquid hydrocarbons flow movement on into producing wellbores by maintaining high gas cap pressure throughout the formation maintaining the selected hydrocarbon formation or formations, both liquid hydrocarbon zone or zones and gas cap under high pressure forward to and during the entire production and recovery process of this invention.

6. A system for enhancing liquid hydrocarbon recovery from a downhole liquid hydrocarbon formation through an injection tubing string comprising:
a vertical wellbore opened both into a gas cap and the liquid hydrocarbon zone or zones with horizontal borehole or boreholes and or perforations;
a packer positioned between the liquid hydrocarbon zone or zones and the gas cap on the injection tubing string for sealing a well annulus outward from the tubing string, thereby isolating the gaseous hydrocarbon zone from the liquid hydrocarbon zone or zones;
a bridge plug previously set at an optimum level below the selected liquid hydrocarbon zone or zones for isolating chosen injection area;
the wellbore annulus for flowing of natural gas from the formation's opened gas cap through the annulus above the top packer directly into a surface compressor;

the surface compressor compressing the flowing gas cap's gas under high pressure into the injection tubing string;
the injection tubing string open-ended at the lower part of the vertical wellbore near the horizontal borehole or boreholes and or perforations injecting high pressure compressed natural gas directly into the open selected liquid hydrocarbon zone or zones; and the liquid hydrocarbon zone injected with high pressure natural gas entering and going into solution with the liquid hydrocarbon adding pressure and solution gas energy to the liquid hydrocarbon thereby increasing its expulsive force and mobility and decreasing its viscosity, capillarity and adhesiveness with its own compatible gas cap formations natural gas.

7. A method of enhancing liquid hydrocarbon recovery from a downhole formation through an injection tubing string comprising:
providing a vertical wellbore annulus with horizontal borehole or boreholes and or perforations in direct communication with both a liquid hydrocarbon or zones and a gas cap;
positioning the injection tubing string from its connection to a surface compressor down into the vertical wellbore, where the injection tubing string is open ended by the opened liquid hydrocarbon zone;
positioning a packer above the selected liquid hydrocarbon zone or zones for sealing a wellbore annulus outward from the injection tubing string;

previously having set a bridge plug at an optimum level below the selected hydrocarbon zone isolating the chosen injection area;
flowing natural gas off the formation's gas cap through the well annulus above the top packer directly into the surface compressor;
providing the surface compressor for injecting high pressure gas into the injection tubing string past the optimally set top packer compressing gas out of the open ended tubing directly into the opened horizontal borehole and or perforated selected liquid hydrocarbon zone or zones;
establishing increased pressure and viscosity capillarity and adhesiveness reduction increasing the liquid hydrocarbon's expulsive force and mobility through high pressure miscible natural gas going into solution with its own compatible liquid hydrocarbon; and maintaining high gas pressure on the entire selected hydrocarbon formation's liquid hydrocarbon zone or zones and gas cap through on to and during production and recovery process of this invention.

8. The method as defined in Claim 7, further comprising:
maintaining a high gas cap pressure when the gas cap is lowered in volume and pressure by the surface compressor injecting miscible and or other gases into the gas cap.

9. An improved downhole injector for positioning downhole within or below a liquid hydrocarbon recovery zone in a vertical wellbore to permit all liquids under all conditions to freely pass from a downhole formation through the injector first through a sand screen filter then through an opened double shutoff valve then through a check valve and on into a production tubing string while positively, under all conditions preventing any free gases from passing through the injector into the production tubing string the injector comprising:
an injector housing having an double shutoff valve having a main tip and port seat with a small 3/6" being of a 0.0276" cross-sectional area pilot tip and port seat affixed thereto;
a liquid responsive float open at the top and closed at the bottom connected to the double shutoff valve by means of the pilot valve working stem movable within the injector housing subject to buoyancy created by permanent liquid surrounding the float in the injector housing;
a double shutoff valve member movably responsive to the up and down movement of the float thereby opening and closing the double shutoff valve as float fills or empties with liquids;
a liquid discharge 1" pipe leading from double shutoff valve through the float with fin-like guides extending from it to help center float without friction contact discharge 1" pipe making into injector's head at production tubing connection;
the liquid responsive float wherein the float is substantially extended as needed in section lengths of approximately 24' or less each by connecting threaded collars and reinforced threaded float ends to add float opening weight with increased float closing buoyancy in order to open injector's double shutoff valve at alt variable excessively high pressures; and a check valve directly above injector head tubing outlet for preventing liquids from returning to injector.

10. The improved injector as defined in Claim 9 wherein the filter screen has vertical entry slots thereby preventing sand particles from plugging screen slots by constantly entering the same horizontal slot area as in prior art, thereby multiplying screen protective rib entry areas for improved sand settlement outside of the screen area into the vertical wellbore annulus.

11. The improved injector vertical slotted screen as defined in Claim 10 having a reinforced pipe base with multi ports for excessive high pressure collapse resistance and the vertical slotted screen with its pipe base being variable in section lengths to accommodate low volume to high volume high pressure liquid inflow rates while screen sections will be threaded on their pipe base for connecting threaded collars in approximate lengths of 5', 10' and 20' to 30'.

12. The improved injector as defined in Claim 11 wherein the sand screen filter has a vertical slotted filter screen on the liquid and gas inflow entry on the upper injector housing, the vertical slots having increments of 0.001" the vertical slotted filter screen preventing selectively sized sand and or debris particles from entering the injector housing.

13. A system for recovering liquid hydrocarbons from a downhole liquid hydrocarbon formation through a production tubing string comprising:
a vertical wellbore opened both into a gas cap and the liquid hydrocarbon zones with perforations and or horizontal bore holes;
an improved downhole injector as defined in Claim 9 and its dependent claims positioned downhole within or below a liquid hydrocarbon recovery zone for passing formation liquids through the injector and into the production tubing string while preventing excessively high pressure free gases from passing through the injector;
a packer positioned above the downhole injector for sealing the well annulus outward from the production tubing string at the optimum top level of the liquid hydrocarbon zone;
a gas pressure relief vent tube sealingly extending upward through the packer said pressure relief vent tube opening at a predetermined pressure such that excessive gas pressure can be relieved through the vent tube and into the annulus of a opened gas cap formation above the packer;
a tubing pressure activated gas lift valve on an inside or outside pocket mandrel on the production tubing string directly above the packer at the gas cap bottom for injecting high pressure lift gas into the production tubing;

a venturi jet tube directly above gas lift valve centered inside the production tubing to increase gas velocity flow through its venturi shaped cone to create a more efficient gas liquid mixture and sweeping action by forming a gaseous piston to help lift the flowing liquid hydrocarbon column to next gas lift combined with venturi jet tube stage lift uphole;
one or more fluid operated gas lift valves optimally spaced on the production tubing string without venturi jet tubes to complete flowing liquid hydrocarbon process onto the surface;
a sufficiently opened internal tubing string depth for swabbing the well when necessary; and a surface wellhead casing gas control valve and the packer for maintaining required high gas pressure on the entire selected hydrocarbon formation's opened liquid hydrocarbon zone or zones and its own wellbore annulus and opened gas cap and its wellbore annulus throughout the entire production and recovery process of this invention.

14. A method of recovering liquid hydrocarbons from a downhole liquid hydrocarbon formation through a production tubing string comprising:
providing a vertical wellbore opened both into a gas cap and the liquid hydrocarbon zones with perforations and or horizontal bore holes;
providing an improved downhole injector as defined in Claim 9 with its dependent claims and in entry communication with the production tubing string;

positioning an improved downhole injector optimally bottomhole within or below an opened horizontal borehole or perforated liquid hydrocarbon zone;
positioning a packer above an improved downhole injector for sealing a well annulus outward from the production tubing at an optimum top level of the liquid hydrocarbon zone entering the gas cap above;
providing a gas pressure relief vent tube sealingly extending upward through the packer said pressure relief vent tube opening at a predetermined pressure setting, venting excessive high gas pressure buildup to the open gas cap above;
providing a tubing fluid pressure activated gas lift valve mounted on an outside or inside pocket mandrel on production tubing string directly above top packer at optimum lower gas cap level injecting high pressure lift gas into production tubing when predetermined tubing fluid pressure opens gas lift valve;
providing a venturi jet tube directly above gas lift valve centered inside the production tubing string for increasing gas velocity flow through its venturi shaped cone for creating a more efficient gas liquid mixture sweeping action when flowing to form a gaseous piston to help drive flowing liquid hydrocarbons upward;
providing additional tubing fluid pressure activated gas lift valves with venturi jet tubes optimally spaced uphole for stage lifting deep wells;

providing additional fluid operated gas lift valves on mandrels uphole on the production tubing string without venturi jet tubes for assisting flowing liquid hydrocarbon process on out to surface separating facilities;
providing a sufficiently deep internal production tubing string depth for swabbing well when necessary; and maintaining required high gas pressure on the entire selected hydrocarbon formation's opened liquid hydrocarbon zone or zones and its wellbore annulus and opened gas cap and its wellbore annulus throughout the entire production and recovery process of this invention.

15. A system for recovering liquid hydrocarbons from a downhole liquid hydrocarbon formation through a production tubing string comprising:
a vertical wellbore opened both into a gas cap and the liquid hydrocarbon zones with perforations and or horizontal bore holes;
an improved downhole injector as defined in Claim 9 and its dependent claims positioned downhole within or below a liquid hydrocarbon recovery zone for producing formation hydrocarbon liquids through the injector and into the production tubing string while preventing high pressure free gas from passing through the injector;
a packer positioned above the downhole injector for sealing a well annulus outward from the production tubing string;
a gas pressure relief vent tube sealingly extending upward through the packer said pressure relief vent tube opening at a predetermined pressure setting, such that excessive high gas pressure can be relieved through the vent tube and into the annulus of the opened horizontal borehole and or perforated gas cap above the packer; and an open production tubing string from its connection to an improved downhole liquid injector housing head extending upward through a vertical wellbore to surface wellhead exit port without a back pressure valve or any other restrictions for flowing liquid hydrocarbons into surface separator facilities;
the improved downhole liquid injector with an extended float system in required float lengths to open downhole liquid injector's double shutoff valve at all various excessive high pressures for producing and recovering liquid hydrocarbons;
the open production tubing string for producing and recovering liquid hydrocarbons through to surface using high bottomhole wellbore formation pressure;
the open production tubing string for flowing producing liquid hydrocarbons through on to open surface exit port by flowing with high pressure gas breaking out of solution as producing liquid hydrocarbons reach solution gas breakout sudden pressure drop point after passing through injector's shutoff valve's main port seat; and a surface wellhead casing gas control valve and the packer for maintaining required high gas pressure on the entire selected hydrocarbon formation's opened liquid hydrocarbon zone or zones and its wellbore annulus and opened gas cap and its wellbore annulus throughout the entire production and recovery process of this invention.

16. The system as defined in Claim 15 further comprising:
the open production tubing string for flowing liquid hydrocarbon production to surface without any artificial lift system in excessively high bottomhole pressure wells with rathole or no rathole at shallow to deep well depths, so that high bottomhole wellbore formation pressure flows liquid hydrocarbons out at the surface wellhead tubing exit port discharge into the surface separating facilities.

17. A method for recovering liquid hydrocarbons from a downhole liquid hydrocarbon formation through a production tubing string, comprising:
providing a vertical wellbore opened both into a gas cap and the liquid hydrocarbon zones with perforations and or horizontal bore holes;
positioning an improved downhole liquid injector as defined in Claim 9 with its dependent claims downhole within or below a liquid hydrocarbon recovery zone for producing and recovering liquid hydrocarbons through the injector and into the production tubing string while preventing any and all high pressure free gas from passing through the injector;
positioning a packer above the downhole liquid injector for sealing a well annulus outward from the production tubing string;

providing a gas pressure relief vent tube sealingly extending upward through the packer said pressure relief vent tube opening at a predetermined pressure setting relieving excessive high gas pressure through the vent tube into the annulus of the opened horizontal borehole and or perforated gas cap above the packer;
providing an open production tubing string from its connection to an improved downhole liquid injector housing head extending upward through a vertical wellbore to surface wellhead exit port without a back pressure valve or any other restrictions for flowing liquid hydrocarbons out into surface separator facilities;
producing and recovering liquid hydrocarbons through an improved downhole liquid injector with an extended float system in required float lengths to open downhole injector's double shutoff valve at all extreme maintained high pressures;
producing and recovering liquid hydrocarbons up through an open production tubing string onto surface using maintained high bottomhole wellbore formation pressure;
producing and recovering liquid hydrocarbons through open production tubing string upward by flowing with gas breaking out of solution as liquid hydrocarbons reach sudden pressure drop gas breakout point after passing through injector's shutoff valve's main port seat on into open production tubing to surface wellhead tubing exit port on to surface separating facilities; and maintaining required high gas pressure on the entire selected hydrocarbon formation's opened liquid hydrocarbon zone or zones and its wellbore annulus and opened gas cap and its wellbore annulus throughout the entire production and recovery process of this invention.

18. The method as defined in Claim 17 further comprising:
flowing liquid hydrocarbon production to surface without any artificial lift system in high bottomhole pressure wells with or without rathole in shallow wells of 1,000 feet or less to deep wells of 15,000 feet or more, so that high pressure gas breaking out of solution flows liquid hydrocarbons from downhole injector's internal tubing outlet point on up and through surface wellhead tubing exit port discharge.

19. A system for recovering liquid hydrocarbons from a downhole liquid hydrocarbon formation through a production tubing string, comprising:
a vertical wellbore opened both into a gas cap and the liquid hydrocarbon zones with perforations and or horizontal bore holes;
an improved downhole injector as defined in Claim 9 with it's dependent claims positioned downhole within or below the liquid hydrocarbon recovery zone for passing formation liquids through the injector and into the production tubing string while preventing excessively high pressure free gases from passing through the injector;

a wellhead surface control valve and a surface pressure gauge for controllably and comparatively closing off the well annulus outward from the production tubing string to the optimum operating wellbore pressure on the opened liquid hydrocarbon zone and opened the gas cap;
a tubing pressure activated gas lift valve on an inside or outside pocket mandrel on the production tubing string for injecting high pressure lift gas into production tubing;
a venturi jet tube directly above gas lift valve centered inside the production tubing to increase gas-velocity flow through its venturi-shaped cone to create a more efficient gas-liquid mixture and sweeping action by forming a gaseous piston to help lift the flowing liquid hydrocarbon column to next gas lift combined with venturi jet tube stage lift uphole;
one or more fluid operated gas lift valves optimally spaced on the production tubing string without venturi jet tubes to complete flowing liquid hydrocarbon process onto the surface;
a sufficiently opened internal tubing string depth for swabbing the well when necessary; and the surface wellhead casing gas control valve with its pressure gauge for maintaining required high gas pressure on the entire selected hydrocarbon formation's opened liquid hydrocarbon zone or zones and its wellbore annulus and opened gas cap and its wellbore annulus throughout the entire production and recovery process of this invention.

20. A method of recovering liquid hydrocarbons from a downhole liquid hydrocarbon formation through a production tubing string comprising:
providing a vertical wellbore opened both into a gas cap and the liquid hydrocarbon zones with perforations and or horizontal bore holes;
providing an improved downhole injector as defined in Claim 9 with it's dependent claims and in entry communication with the production tubing string;
positioning an improved downhole injector optimally bottomhole within or below an opened horizontal borehole or perforated liquid hydrocarbon zone;
providing a wellhead standard casing surface control valve and a standard surface pressure gauge for controllably and comparatively closing off gas flow from the wellbore annulus to maintain the desired optimum operating pressure on the opened liquid hydrocarbon zone and opened gas cap;
providing a venturi jet tube directly above gas lift valve centered inside the production tubing string for increasing gas velocity flow through its venturi-shaped cone for creating a more efficient gas-liquid mixture sweeping action When flowing to form a gaseous piston to help drive flowing liquid hydrocarbons upward;
providing additional tubing fluid pressure activated gas lift valves with venturi jet tubes optimally spaced uphole for stage-lifting deep wells;

providing additional fluid operated gas lift valves on mandrels uphole on the production tubing string without venturi jet tubes for assisting the flowing liquid hydrocarbon process on out to surface separating facilities;
providing a sufficiently deep internal production tubing string depth for swabbing well when necessary; and maintaining required high gas pressure on the entire selected hydrocarbon formations opened liquid hydrocarbon zone or zones and its wellbore annulus and opened gas cap and its wellbore annulus throughout the entire production and recovery process of this invention.

21. The method as defined in Claim 20 wherein a liquid level is maintained at the downhole injectors sand screen liquid inlet as incoming high pressure liquid hydrocarbon flows through the injectors opened float double valve into the lower pressure tubing string, while maintaining any lower pressure free gas breakout in the wellbore and opened gas cap above.

22. A system for recovering liquid hydrocarbons from a downhole liquid hydrocarbon formation through a production tubing string, comprising:
a surface wellhead casing gas flow pressure regulator valve and a surface pressure gauge for controllably cutting off or closing off gas flow and pressure and measuring pressure while maintaining a predetermined operating high pressure on a wellbore annulus.

the wellbore being perforated and or opened with one or more horizontal and alternatively highly angled boreholes for fluid communication in both a liquid hydrocarbon zone or zones and a gas cap;
an improved downhole injector as defined in Claim 9 and it's dependent claims, positioned downhole within or below a liquid hydrocarbon recovery zone for producing formation hydrocarbon liquids through the injector and into the production tubing string while preventing high pressure free gas from passing through the injector;
the improved downhole liquid injector for producing and recovering liquid hydrocarbons with an extended float system in required float lengths to open the improved injector's double shutoff valve at all various excessive high pressures;
the open production tubing string for producing and increasing ultimate recovery of liquid hydrocarbons up to the surface using maintained high wellbore and formation pressure;
the open production tubing string on to open surface exit port for flowing producing liquid hydrocarbons through by flowing with high pressure gas breaking out of solution as producing liquid hydrocarbons reach solution gas breakout sudden pressure drop point after passing through injector's shutoff valve's main port seat; and the surface wellhead control valve for maintaining required high gas pressure on the entire selected hydrocarbon formation's liquid hydrocarbon zone or zones and its wellbore annulus and gas cap and its wellbore annulus throughout the entire production and recovery process of this invention for total ultimate recovery of in place liquid hydrocarbons.

23. The system as defined in Claim 22 further comprising:
the production tubing string for flowing liquid hydrocarbon production to surface without any artificial lift system in excessively high wellbore and formation pressure wells with rathole or no rathole at shallow to deep well depths, so that high wellbore and formation pressure flows liquid hydrocarbons out at the surface wellhead tubing exit port discharge into the surface separating facilities.

24. A method for recovering liquid hydrocarbons from a downhole liquid hydrocarbon formation through a production tubing string comprising:
positioning an improved downhole liquid injector as defined in Claim 9 and it's dependent claims downhole within or below a liquid hydrocarbon recovery zone for producing and recovering liquid hydrocarbons through the injector and into the production tubing string while preventing any and all high pressure free gas from passing through the injector;
providing a surface gas flow pressure regulator valve and a surface pressure gauge on the casing wellhead annulus exit port for respectively controlling gas flow and pressure and measuring while maintaining a predetermined operating flow pressure on the wellbore annulus;

providing perforations and or horizontal boreholes in the wellbore for fluid communication with the downhole hydrocarbon formation both above and below a gas-fluid interface separating fluids from a gas cap above the fluids;
producing and recovering liquid hydrocarbons through an improved downhole liquid injector with an extended float system in required float lengths to open downhole injector's double shutoff valve at all extreme maintained high pressures;
producing and recovering liquid hydrocarbons up through an open production tubing string onto surface using maintained high wellbore formation pressure;
producing and recovering liquid hydrocarbons through open production tubing string upward by flowing with gas breaking out of solution as liquid hydrocarbons reach sudden pressure drop gas breakout point, after passing through injector's shutoff valve's main port seat on into open production tubing to surface wellhead tubing exit port on to surface separating facilities; and maintaining required high gas pressure on the entire selected hydrocarbon formation's opened liquid hydrocarbon zone or zones and its wellbore annulus and opened gas cap and its wellbore annulus throughout the entire production and recovery process of this invention for total ultimate recovery of in place liquid hydrocarbons.

25. The method as defined in Claim 24, further comprising:

flowing liquid hydrocarbon production to surface without any artificial lift system in high wellbore and formation pressure welts with or without rathole in shallow wells of 1,000 feet or less, to deep wells of 15,000 feet or more so that high pressure gas breaking out of solution flows liquid hydrocarbons from downhole injector's internal tubing outlet point on up and through surface wellhead tubing exit port discharge.