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Publication numberUS3351132 A
Publication typeGrant
Publication dateNov 7, 1967
Filing dateJul 16, 1965
Priority dateJul 16, 1965
Also published asDE1267185B
Publication numberUS 3351132 A, US 3351132A, US-A-3351132, US3351132 A, US3351132A
InventorsLynn Dougan John, Samuel Reynolds Fred
Original AssigneeEquity Oil Company
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Post-primary thermal method of recovering oil from oil wells and the like
US 3351132 A
Abstract  available in
Previous page
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Claims  available in
Description  (OCR text may contain errors)


Nov. 7, 1967 Filed July 16, 1965 OIL WELLS AND THE LIKE 3 Sheets-Sheet 2 c i3ricondu\ b0! Critical point z if Q/ 1 1-.

3 Cricondon but Critical point l O 3000 Original 4 Reservoir Condition 21 El K I E \Q '0 "Q 0 i I 2000 E 8 .5 5 '6 o E Q --Selectud Initial 2 Opuruiinq Conditions S 3 a. 0, i000 L 5" Cricondentharm E Q E 5 '3 Prnsent Ruservoir Condition 0 500 I E T6038 700 0 I00 200 300 NV N O TEMPERATURE JOHN LYNN DOUGAN FRED SAMUEL REYNOLDS BY W FIG. 2 W



x 4 U1 2 E m Locus a gicondenitheryu emporo ure 5.? so FIG. 3 Q 2 I E 2 I 5 I u D Locus E 8 cricondeniherm 0. (Pressure) 9 90 a so 0 E "r 70 E E LU 6 5O 0: e D 5 50 FIG. 4

Z O 4 40 g 7 X- 8 O I: O I a: 3 30 Z 2 20 3 I Ill Q.


3,351,132 Patented Nov. 7, 1967 3,351,132 POST-PRIMARY THERMAL METHOD OF RECOV- ERING OIL FROM OIL WELLS AND THE LIKE John Lynn Dougan, Salt Lake City, Utah, and Fred Samuel Reynolds, Fort Worth, Tex., assignors to Equity Oil Company, Salt Lake City, Utah, a corporation of Colorado Filed July 16, 1965, Ser. No. 472,649 6 Claims. (Cl. 16611) ABSTRACT OF THE DISCLOSURE A method of stimulating recovery of hydrocarbon liquids from natural oil and gas reservoirs underground by injecting into and circulating through such a reservoir, to a recovery well, hot natural gas having a. temperature high enough to vaporize hydrocarbon liquids in the reservoir and to maintain them above dew point temperature and above the cricondentherm when the pressure is as high as the cricondentherm pressure.

This invention relates to methods applied to natural oil reservoirs underground for stimulating secondary or tertiary recovery following pimary depletion. It is particularly concerned with post-primary thermal methods, whereby heat is introduced into the underground reservoir by the injection thereinto of a heat-transfer fluid. In comparison with known processes of thermal or other type, such as water-flooding or gas-repressurizing, it presents highly significant advantages, especially in effecting recoveries commensurate with those obtained from natural gas reservoirs and in being universally applicable to the many different situations encountered in practice.

Both hot water and steam have been used heretofore as heating media in thermal methods. The latter has aroused considerable enthusiasm in the industry and is being employed to an ever-increasing extent. Nonetheless, it has inherent disadvantages. Thus, condensation of the steam promotes corrosion of pipe and equipment and emulsification of the oil being produced, thereby complicating operations and necessitating special extraction procedures at the surface. Moreover, the multiple phases existing in the formation reduce the permeability of the reservoir rock to flow of the respective fluids.

In-situ combustion of residual hydrocarbons in part of the reservoir has also been proposed for supplying heatcarrying gases to the remainder of the reservoir formation. However, this necessitates the introduction of oxygen, which promotes corrosion and is detrimental to the resulting products from a chemical standpoint.

Both steam and in-situ combustion rely on reduction of viscosity of the native or residual oil by reason of increase in temperature, and both result in zones of condensation ahead of the heat front.

The present invention makes use of heated natural gas as a miscible heat-transfer fluid, and utilizes both the thermal and the solvent properties of this medium to promote vaporization and to thereby effect the desired additional recovery from the well. No difliculty is experienced from condensation of the injected gas in the formation, and corrosion of well equipment is minimized. Essentially the absolute permeability of the rock reservoir is utilized for hydrocarbon recovery, because there is but a single, free-flowing, substantially gaseous phase within the formation following injection of the heated gas and the attainment of a pre-selected operating temperature above the dew point for the mixture of hydrocarbons concerned; however, if operating pressure is as high as the cricondentherm pressure, such operating temperature is maintained above the cricondentherm, where vaporization of the hydrocarbon mixture is assured. Continued injection of natural gas and the resulting dilution of the reservoir fluid with such natural gas, shifts the phase diagram characteristics and lowers the cricondentherm, thereby permitting continued operation at progressively lower temperatures. Moreover, natural gas is beneficial on fugacities and equilibrium ratios for both subsurface and surface phase relations.

The cricondentherm for a selected operating pressure will vary in accordance with hydrocarbon constituents. It is essentially correlative with A.P.l. gravity of oil or condensate (higher gravities have lower vaporization temperatures); contrariwise, ratios of various constituents also affect phase relations, and criticals are not rigorously correlative with A.P.I. gravity. It is well known that a temperature range of 400 F. to 1000 F. will vaporize most oils. However, with natural gas serving as a diluent, the vaporization temperature will be somewhat lower. Thus, for any given use of the invention, a phase diagram applicable to the particular mixture of natural gas and reservoir fluid is constructed in the laboratory or by mathematical computation for the reservoir fluid concerned, so that an optimum operating temperature and pressure can be selected. Thereafter, the temperature to which the circulating gas is heated will be lowered, by pre-determined temperature decrements from time to time for most economical operation above the dew point, by computing or measuring the phase behavior in the operational range for existing hydrocarbon constituents found by periodic samplings of production.

By the use of heated natural gas in accordance with this invention, there is an exceptionally great reduction in viscosity of the residual hydrocarbons in the formation being treated, usually from ten to one-hundred fold or more, by reason of the vaporization thereof and complete miscibility of the gas therewith. This results in excellent fluid-flow characteristics and high recoveries. Also, in instances of heterogeneous or anisotropic permeability, capillary end edects are minimized. Again, retrograde condensation is prevented by isothermal depletion above the cricondentherm. Recoveries, including intermediate and heavy ends of hydrocarbons, approach conventional gas reservoir recoveries attained by pressure depletion.

A closed gas reservoir experiences isothermal-pressure depletion; but if the temperature is maintained above the cricondentherm, no condensate will form in the reservoir and all hydrocarbon components will be recovered with equivalent efficiency. It should be noted, too, that pressure-depletion gas recoveries normally exceed, several fold, pressure-depletion oil recoveries, especially in low permeability rock and/or with high viscosity oil, and often approach recovery.

Utilization of natural gas for the miscible displacement of residual hydrocarbons in the post primary treatment of oil and gas wells has been proposed heretofore, looking toward almost complete recovery from the reservoirs concerned. in accordance with that proposal (see Paper No. 909-6, AIME, Petroleum Vaporization Recovery by High Pressure Gas Injection, C. L. Barney, October 1957), the natural gas would be injected into a reservoir under sufliciently high pressure to establish and maintain a pressure therein above the critical pressure, i.e. cricondenbar, so that the injected and reservoir fluids approach the same density (one phase) e.g. 6000 pounds per square inch absolute. The exact conditions in each instance would be determined by constructing a phase diagram to show changes in the gas-oil ratio at ambient reservoir temperature, which is normally a constant and relatively low temperature, e.g. 180 F. Although it is recognized that, ideally, the pressure should be high enough so the reservoir fluid phase will not drop below the cricondenbar and a single phase will be maintained, it is also recognized that it will often be impractical or impossible to do this. The present invention does, however, enable the maintenance on a practical basis of substantially a single gaseous phase in those portions of the reservoir undergoing treatment. This is made both possible and practical by changing the previously proposed high pressure injection of low temperature natural gas to relatively low pressure injection of relatively high temperature natural gas and by maintaining control as previously explained.

Principal objects in the making of the invention, therefore, were to eliminate the difficulties inherent in the present thermal processes of secondary and tertiary recovery, and to provide a practical, miscible displacement, vaporization process.

Other objects were to provide a highly economical process that is applicable to all types of crude oil, gas condensates, and various other hydrocarbon liquids, without contamination of the end products; to provide such a process which may be conveniently subjected to close control; to minimize capillary end effects in instances of heterogeneous or anisotropic permeability; and to prevent retrograde condensation.

Principal features in the accomplishment of these objects are the use of natural gas, heated to a temperature above the formation temperature of the area concerned (e.g. within the range of about 300 F. to 1000 F.), as the thermal medium for injection at a relatively low pressure exceeding reservoir pressure, but never exceeding overburden pressure of approximately the product of unity and depth in feet as pounds per square inch of the reservoir to be treated; the maintaining of the temperature of the reservoir fluid above the dew point (and, where required, above the cricondentherm) by means of the injected gas; and, preferably, by the further step of lowering the temperature to which the gas is heated from time to time commensurate with reduction in dew point (because of dilution with the injected natural gas), so that vaporization will be maintained at minimum cost.

Previously, the utilization of high-pressure miscible displacement in many shallow oil reservoirs has been impractical, because, in these reservoirs, the crieondenbar for the reservoir oil exceeds overburden pressure; hence; in addition to the hazards, fracturing will result in decreased displacement efficiency.

The term natural gas" is here used in its ordinarily understood sense, i.e. the gas commonly derived from oil and gas wells, which contains methane as a major constituent, usually over 90% by volume, along with minor quantities of ethane, propane, butane, etc.

There is shown in the accompanying drawings a specific procedure representing What is presently regarded as the best mode of carrying out and controlling the process of the invention. From the following detailed description, other more specific objects and features will become apparent.

In the drawings:

FIG. 1 is a schematic showing in vertical section of one possible system for carrying out the process;

FIG. 2 a phase diagram constructed for use in initially applying the process to a specific oil reservoir in which there has been isothermal-pressure primary depletion;

FIG. 3, a double graph plotting both temperature and pressure as abscissas and the percent of injected gas in the production flow stream as ordinate to show the cricondenbar locus and the cricondcntherm locus for the phase diagram of FIG. 2; and

FIG. 4, a graph showing calculated performance, on an idealized basis, of the miscible displacement process of this invention (stratification not considered) in applying such process to the oil reservoir concerned in FIGS. 2 and 3.

Referring to the drawings:

In applying the method of the invention to a reservoir 10, FIG. 1, requiring treatment of the type concerned for stimulating hydrocarbon recovery, natural gas is injected into the reservoir through a string of tubing 11 within a well casing 12 that is driven into the formation by usual drilling techniques.

Provision is made, usually at the surface, for heating the natural gas injected into the delivery tubing 11 following compression by any suitable compressor 13 to a proper pressure for the well concerned. Heating can be accomplished in any suitable manner, but a heater l4 equipped with tubes for conducting the gas through a direct-fired chamber in heat exchange relationship with combustion of any suitable fuel taking place therein, has been found very satisfactory. To prevent dissipation of the heat as the natural gas passes downwardly through tubing 11, thermal insulation 15 is placed in casing 12. A sub-surface heater can be used if desired.

At its lower end, which extends into reservoir 10, casing 12 is perforated in customary manner as at 16, or an open-hole completion can be utilized, for passage of the heated natural gas directly into the underground reservoir formation. Packer l7 seals off the anulus between tubing 11 and the upper reaches of casing 12.

By reason of the injection pressure, heated natural gas travels through the reservoir formation to one or more recovery wells 18 of preferably the same construction as the injection well and either thermally insulated or not as may be found desirable.

In practice, a so-called five-spot or an inverted five-spot injection pattern (one injection well surrounded by four recovery wells) is often found desirable, although other injection patterns can be utilized.

Viscous crude oil or other form of hydrocarbon not otherwise recoverable is vaporized by the heated natural gas and intermingles therewith, being carried thereby to the surface through recovery well 18. Separation of other than natural gas from the gaseous fluid mixture is effected in any suitable manner known to the art, as, for example, by cooling or absorption and by collecting the resulting condensate, see the apparatus indicated generally at 19, FIG. 1.

The separated gas is sent through a compressor 13 for recycling, following the bleeding off of such portions thereof as may be found desirable in view of the increase to be expected from the vaporized reservoir hydrocarbons, see bleed-ofli' valve and piping 20. It will usually be desirable to fire the heater with natural gas so derived.

In accordance with the invention, a phase diagram based on temperature and pressure, such as that shown in FIG. 2, is constructed initially to determine the temperature to which the natural gas injected into the well as a thermal medium should be heated. This must be high enough to maintain the treated portion of the res ervoir above the dew point, and, if necessary above the cricondentherm, that is to say, above the minimum temperature that will assure vaporization of the hydrocarbons in the reservoir.

Inasmuch as dilution of the reservoir hydrocarbon mixture occurs by continuing the injection above the dew point, the operating temperature should be gradually decreased. This is done by the aid of additional computation and/or laboratory measurements from time to time on samples collected in accordance with sampling procedures known to the art.

Following is a typical example of the invention as applied to an oil reservoir that has undergone primary depletion, but that represents a case of low viscosity oil with low permeability that is not normally susceptible of successful treatment by secondary recovery. The phase diagram and graphs of FIGS. 2-4 are constructed from this reservoir data.

OIL RESERVOIR Physical properties of reservoir rock Average porosity, percent 12.7 Average permeability, millidarcys 1.3 Average interstitial water saturation, percent 31.6

Composition of original reservoir oil Characteristics of reservoir fluids Average gravity of stock tank oil, degrees API 43.2

Original formation volume factor, barrels per barrel 1.75 Viscosity original reservoil oil, centipoises 0.23 Viscosity reservoil oil at 1200 p.s.i 0.30 Original reservoir temperature, F 145 PROCEDURE From the above data, mathematical computations familiar to those skilled in the art were used to construct the phase diagram shown by solid lines in FIG. 2, and an initial operating temperature of 390 F. at an operating pressure of 1200 p.s.i.a. was selected. The phase diagram shown by the broken line indicates the condition of the reservoir hydrocarbon mixture after attaining the initial operating temperature and pressure.

It will be realized that variations in either the initial composition of the hydrocarbons concerned or the composition brought about by pressure changes will cause a shifting of the phase diagram. If the reservoir pressure were raised to approximately 4200 p.s.i.a. by injection of high pressure natural gas, without altering the reservoir temperature, as is proposed by the aforementioned Barney publication, the reservoir hydrocarbon mixture would become a single phase, but not necessarily gaseous. Moreover, as dilution occurred during miscible displacement, the pressure would have to be increased to maintain the single phase condition. Contrariwise, with the present method, as dilution occurs, the operating temperature can and should be gradually decreased. The advantages of the latter and the disadvantages of the former are depicted on the graphs of FIG. 3, where elevation of the cricondenbar and lowering of the cricondentherm is depicted through a broader range of dilution with the injected gas.

In this example, the primary oil was produced by isothermal-pressure or normal depletion. Consequently, there was gas saturation in the reservoir which was created by the liberation of solution gas and shrinkage of reservoir oil. Because of the volatile nature of the reservoir oil and the extremely low permeability, primary recovery was less than percent of the original stock tank oil in place. The viscosity of the reservoir oil was low, but by vaporization it would be lowered twenty-six fold. Its mobility or flow characteristics would be improved by this factor, even though there were no improvement in permeability.

FIG. 4 shows the calculated performance for miscible displacement of this reservoir according to the invention, based on one stage separation at 65 F. and 100 p.s.i.a. It evinces high recoveries with limited injected volumes. The calculations make no allowance for varying permeability and Stratification. Actual performance will be somewhat dilferent than shown, depending on the variable nature of the reservoir. Thermal expansion of the reservoir fluids in the zones of limited or dead-end permeability will cause higher recovery than other forms of miscible displacement. Although the computations are for a mobility ratio of one, such ratio is actually less than one (probably in the order of 0.65), because the low molecular weight, injected gas has a higher viscosity than the high molecular weight, displaced gas.

In reservoirs with variable or dead-end permeability, the utilization of high-pressure gas in a miscible displacement procedure, such as the aforementioned Barney method, would compress the reservoir fluids in the limited or dead-end permeability zones and bypass these areas during the recovery process. A lower recovery than is depicted in FIGURE 4, would be realized, also a much greater gas volume would be necessary to attain and sustain miscibility during the recovery process. Contrariwise, the present process recovers, by thermal expansion, 21 large portion of the hydrocarbons contained in the areas of limited permeability, and only a comparatively small volume of injected gas is necessary to accomplish this.

Although the temperature indicated and selected for this example was 390 F., it is preferable to start with a somewhat higher temperature and to use this for the early period of injection, so as to insure delivery of the gas at a temperature adequate to start the miscible driving force before reduction in temperature to that selected. In this connection, it should be realized that operation is simplified if the sand-face temperature at the injection well is maintained below the saturated water vapor point for interstitial water. For the present example, a temperature of 550 F. would be permissible at the 1200 p.s.i.a. injection pressure. However, it should be realized that, for some reservoir oils, it may be impossible to obtain miscibility below the vaporization temperature of water. Laboratory tests on production samples will determine this in any given instance.

The foregoing is just one example of the possible applications of the method of this invention. Highly viscous crudes are prime candidates for the method. They have inherently low normal recoveries even in highly permeable rock. The viscosity reduction for such highly viscous crudes may be many thousand fold.

It should be realized that the present method of thermal recovery is not only capable of use where conventional thermal methods are ineffective, but can be employed as an alternative to all secondary recovery methods to yield considerably higher recoveries. In idealized cases of miscible displacement in accordance with the invention, almost complete recovery is feasible.

In some instances, it may be desirable to utilize the present method for tertiary recovery following secondary recovery by water-flooding, or other conventional procedures.

Another type of reservoir to which the method may be advantageously applied is a gas-condensate reservoir wherein the heating costs for lower pressure gas are less than compression costs for maintaining original reservoir pressure. If retrograde condensation has already occurred in such a reservoir, it may be simpler and less expensive to re-vaporize it with heat than with pressure.

Also, it should be realized that, While vaporization of the normally unrecoverable liquid hydrocarbons in a reservoir to which the present process is applicable will ordinarily occur, there are some instances where the use of heated natural gas will render such liquid hydrocarbons sufliciently mobile for recovery purposes without vaporization.

Although the invention has been characterized as a post-primary" method, it is to be understood that there are many reservoirs wherein conditions are such that primary recovery is not practical (c.g. those containing hydrocarbons that are too viscous) and that the invention may also be applied to such reservoirs.

Whereas there are here specifically set forth certain preferred procedures and apparatus which are presently regarded as the best mode of carrying out the invention, it should be understood that various changes may be made and other procedures adopted without departing from the inventive subject matter particularly pointed out and claimed herebelow.

We claim:

1, A method of stimulating recovery of hydrocarbon liquids from natural oil and gas reservoirs underground, comprising circulating heated gas consisting essentially of natural gas under pressure, not exceeding overburden pressure, through at least a portion of such a reservoir from an injunction well to a recovery well, the temperature of said gas being high enough to vaporize hydrocarbon liquids in said reservoir and maintain such vaporized liquids above the dew point, and above the cricondentherm when the pressure is as high as the cricondentherm pressure, so said natural gas is substantially completely miscible with said vaporized liquids.

2. A method according to claim 1, wherein the temperature of the gas is within the range of about 300 F. to about 1000 F.

3. A method according to claim 1, wherein the gas is recycled at reduced temperatures when reductions in dew point permit, the temperature reductions being substantially in accordance with dew point reductions.

4. A method according to claim 3, wherein the temperature of the gas is within the range of about 300 F. to about 1000 F.

5. A method of recovering hydrocarbon liquids from wells have been drilled, comprising introducing heated gas consisting essentially of natural gas under pressure, not exceeding overburden pressure, into at least a portion of such a reservoir through at least one of said wells, said gas having a temperature high enough to vaporize hydrocarbon liquids in said reservoir and maintain such vaporized liquids above the dew point, and above the cricondentherm when the pressure is as high as the cricorldentherm pressure so said gas is substantially completely miscible with said vapdrized liquids; withdrawing through at least one other of said wells said gas and such volatilized hydrocarbons as may be intermixed therewith; separating natural gas constituents from the mixture; and recycling such natural gas constituents through said reseryou.

6. A method according to claim 5, wherein the gas is recycled at reduced temperatures when reductions in dew point permit, the temperature reductions being substantially in accordance with dew point reductions.

References Cited UNITED STATES PATENTS 895,612 8/1908 Baker 166-1l X 2,670,802 3/1954 Ackley l6611 2,813,583 11/1957 Marx et al. 166l1 2,906,337 9/1959 Hennig 166l1 3,040,809 6/1962 Pelzer 166-11 3,241,611 3/1966 Dougan 166-1l X natural oil and gas reservoirs underground into which STEPHEN J. NOVOSAD, Primary Examiner.

UNITED STATES PATENT OFFICE CERTIFICATE OF CORRECTION Patent No 3 ,351 ,132 November 7 1967 John Lynn Dougan et a1 It is hereby certified that error appears in the above numbered patent requiring correction and that the said Letters Patent should read as corrected below.

Column 7 line 12 for "injunction" read injection Signed and sealed this 31st day of December 1968 (SEAL) Attest:

EDWARD J. BRENNER Edward M. Fletcher, Jr.

Commissioner of Patents Attesting Officer

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U.S. Classification166/266, 166/272.1
International ClassificationE21B43/16, E21B43/24
Cooperative ClassificationE21B43/24
European ClassificationE21B43/24