Search Images Maps Play YouTube News Gmail Drive More »
Sign in
Screen reader users: click this link for accessible mode. Accessible mode has the same essential features but works better with your reader.

Patents

  1. Advanced Patent Search
Publication numberUS3182721 A
Publication typeGrant
Publication dateMay 11, 1965
Filing dateNov 2, 1962
Priority dateNov 2, 1962
Publication numberUS 3182721 A, US 3182721A, US-A-3182721, US3182721 A, US3182721A
InventorsHardy William C
Original AssigneeSun Oil Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Method of petroleum production by forward in situ combustion
US 3182721 A
Abstract  available in
Images(1)
Previous page
Next page
Claims  available in
Description  (OCR text may contain errors)

w. c. HARDY 3,182,721

METHOD OF PETROLEUM PRODUCTION BY FORWARD IN SITU COMBUSTION May 11, 1965 Filed Nov. 2, 1962 Production cracking Oondumoflon Unolhnd Zone Zone 2on0 combustion Zone Burnod Zone FIG.

Tcmporaturo Dinonco FIG. 2.

Sflmc Prusun Tomporuiun INVENTOR. WILLIAM C. HARDY FIG.3.

ATTORN 2Y5 United States Patent 3,182,721 ME'IHGD 0F PETROLEUM PRODUCTION BY FORWARD IN SITU COMBUSTION William C. Hardy, Richardson, Tex assignor to Sun Gil Company, Philadelphia, Pa., a corporation of New Jersey 3 Filed Nov. 2, 1962, Ser. No. 235,028

3 Claims. (Cl. 166-41) This invention relates to a method for recovery of hydrocarbons from oil-bearing formations, and has particular reference to recovery processes involving in situ combustion. r

Recovery of hydrocarbons by the use of in situ combustion procedures is known, there being'two classes of such procedure involving, respectively, forward or backward burning. The present invention is concerned with the forward burning procedure.

In carrying out this procedure, the petroleum-bearing formation from which recovery is sought is penetrated by one or more injection cells and one or more production wells suitably drilled in what appears from prior knowledge of the formation to be optimum locations. The procedure involves injection of air intothe injection well or wells, the initiation and maintenance of burning starting at the injection point, and the collection of the resulting product from the producing well or wells. Particular procedures for carrying this out are well known and need not be described in detail. The combustion process is used usually as a secondary recovery process, but may be used when other procedures have failed either to initiate or continue production. For example, due to its geologic history, some beds e.g. tar sands, may, when first located, contain only, or largely, highly viscous and non-volatile hydrocarbon residues which cannot be made to flow by ordinary methods. In other cases, more conventional methods may have been used to remove more mobile and volatile constituents leaving residually in the formation pores residues which are so viscous as not to flow or which are in such quantities as to be held by wetting of the rock constituents without existing in a continuous liquid phase. I To attack these or similar conditions, the burning process is used, which consuming some of the hydrocarbon residues, provides heatwhich cracks other portions of the residues producing gaseous and/or liquid products which will flow to the production point.

In the combustion process, however, a difliculty arise-s due primarily to the condensation of water arising from the combustion of hydrocarbons or, more generally, from both this and vaporized interstitial water. This water, existing as steam where a temperature is sufliciently high, is condensed further on in progress throughthe formation where temperatures are sufficiently low considering the existing pressure. This water has the well-known Jamin eifect producing viscous blocking in the zone of condensation. This viscous blocking retards the flow of air and all other fluid materials in the various zones involved in the process, and seriously impairs the performance of the process.

It is one object of the present invention to provide a production procedure, which, taking advantage of temperature and pressure variations, will reduce the blocking action and permit the reestablishment of normal operation. It is found, further, that the procedure in accordance with the invention has additional advantages in making use, for drive, purposes, of both gases changed from liquid phase and gases dissolved in the liquids, both oil and water, in the condensation and subsequent zones. A further object of the inventon is to provide a procedure taking advantage of this situation.

Further objects of the invention relating to details, as well as the attainment of those already described, will become apparent from the following description, read in conjunction with the accompanying drawing in which:

FIGURE 1 is a diagram, in the form of a vertical section illustrating a portion of an oil reservoir to which the invention is applied;

FIGURE 2 is a plot of temperature versus distance, explanatory of aspects of operation; and FIGURE 3 is a static pressure versus temperature chart further explanatory of the invention.

Referring first to FIGURE 1, one or more injection wells are indicated at 2, provided with control valves 4, and penetrating at their lower end 6 a' hydrocarbon-containing formation indicated at 8. Spaced from these are production wells 10 illustrated as provided with control ice valves 12, which wells penetrate the same formation at 14. It will be understood that while these wells are merely diagrammed, they may be provided in accordance with well-known practices which need not be described in detail, having no bearing on the essential aspect of the invention. The production wells may, of course, be pumped if required The wells are also relatively located in accordance with conventional good practices depending upon the knowledge of the producing formation, this knowledge being secured by preliminary conventional production, by the drilling of test holes with core sampling, etc. In brief, the arrangement adopted is to secure, ultimately, maximum recovery with minimum cost. It might be stated, as a summary, that the locations are such as to secure a sweeping of desired products from a maximum region consistent with the adoption of the forward burning procedure.

Considering the wells indicated in FIGURE 1, the formation between the injection well or wells and the production well or wells, contains identifiable zones though the boundaries of transition from each zone to the next may not be sharply defined; in fact they may be quite indefinite. These zones, in sequence, are a burned zone 16, a combustion zone 18, a cracking zone 20, a condensation zone 22, and an unaltered zone which, for reasons which will become apparent later, is somewhat arbitrarily illustrated as having two portions 24 and 26, quite indefinitely differentiated.

As the production with burning proceeds, these zones shiftfrom left to right, as viewed in FIGURE 1, and the positions illustratedare merely arbitrarily shown both as to location and extent, both of these matters varying with time and in dependence on the formation and its contents as well as its surroundings.

Considering the zones individually, there is first the burned zone 16 which, after progress of the procedure, will surround each injection well and later probably surrounds, as a single zone, all of a group of injection wells. This burned zone will generally be devoid of, or quite low in content of, carbonaceous material.

Surrounding this zone 16 in the direction of flow through the formation is a combustion zone 18, and beyond this also in the direction of flow is a cracking zone 20. In considering these zones, the progress and results of the combustion may be described. Initial burning in a particular region may involve the combustion of substantial amounts of the volatile hydrocarbon contents. The generated heat produces cracking, however, and the resulting volatile constituents are, to a considerable extent, vaporized passing off as hydrocarbons in the combustion products. This cracking produces coking, which, at the high temperatures involved, burns. Accordingly, as the combustion procedure goes on, the residual coke is the burning material primarily involved in the combustion zone such as 18 and in view of the relatively large quantities of this which accumulate, the greater part of the oxygen in the injected air is utilized in burning this coke to carbon monoxide and dioxide, producing, to flow from that zone, hot gas, largely consisting of nitrogen, carbon monoxide and carbon dioxide, with some water resulting from the burning of hydrocarbons, which hot gas will not support further combustion. It is the heat of this gas which cracks the carbonaceous materials in the subsequent cracking zone in which oxidation is at a minimum, resulting inthe production of volatile hydrocarbon products together with the formation of coke which is later burned as the combustion zone progresses. From the standpoint of the present invention, the next zone, condensation zone 22, is of special significance. Pressures involved in both the combustion and maintenance of flow, during the active part of the combustioncracking procedure, are such that water, and at least relatively non-volatile hydrocarbons are condensed due to the lower ambient temperature of the formation. As a result, there exists the zone 22 in which such condensation occurs. The condensed water originates, in part, because, while coke is the primary burned material, there is always some substantial burning of hydrocarbons, particularly in the initial stages of the procedure. Additionally, there is condensed water which originated as interstitial water and which in a preceding region was volatilized. It will be evident that this accumulation of water condensate is cumulative, the condensation zone as it moves forwardly not only containing water from its previous location, but also added water resulting from combustion and further progressive volatilization of the interstitial water. Thus a point is reached where the water concentration becomes quite high.

' At the same, time, hydrocarbons are condensed, and

this also is a cumulative phenomenon.

The ultimate result is that the condensed water gives rise, by Jamin effect, to a blocking condition which restricts liquid permeability and also to a reduced gas satucombustion are no longer secured.

The temperature in the condensation zone will, in general, be close to the condensation temperature of water 'at the pressure involved. This temperature will range well above 212 F., depending upon the pressure on the 4 system.

Water condensation has so far been primarily considered. Hydrocarbon constituents less volatile than water at the pressures involved will also condense in the condensation zone, particularly, at least, in the first portion thereof. Hydrocarbons more volatile than water at the pressures involved will progressively condense in the latter portion of and beyond the water condensation zone. The mostv volatile products and fixed gases, these gases including carbon dioxide, will, further, pass into solution in the interstitial hydrocarbons beyond the condensation zone, carbon dioxide also going into solution in interstitial water. The result, then, is a somewhat ill-defined (spacially) zone 24 which has been referred to as part of the unaltered zone, this term being here used for the zone in which the original contents have not been substantially affected, though the hot combustion gases may, in part, have volatilized the more volatile constituents and may have, merely by temperature rise, driven some dissolved gases out of the liquid phase. The zone 24, as will appear, plays an important part in the operation in accordance with the invention. Beyond this is the zone portion Zd which may only have been affected by either removal of dissolved gases or by solution of gases in view of the high pressures involved. 1

The procedure in accordance with the invention may now be described. First, forward burning is carried out in conventional fashion. This is initiated in unsual fashion, as by locating an electrical heater within the Well at the level of the formation to be produced, with injection of air to start combustion in the region immediately surrounding the well. Alternatively,'gas or liquid fuel may from the foregoing measurements.

be burned in the air at the bottom of the well to produce a flame to ignite the immediately surrounding region. After ignition of the formation has been accomplished, the heater may be removed or the initiating fuel discontinued. If the contents of the formation are such as to maintain combustion poorly, there may be for a time injected with the air, gas or other fuel in an amount less than that of a self-combustible percentage so that in the formation proper burning conditions are maintained. This is generally only a transient condition, since temperatures are rapidly produced which will involve permanent maintenance of combustion. Generally, to maintain suflicient rapidity of combustion, the air is introduced at high pressure and the outputs from the producing wells may be throttled to maintain optimum pressure conditions in the formation, though, generally, the pressures are desirably maintained by sufi'icient air introduction with little or no measured, and gas analyses of the production are made.

These, as is Well-known, will give full information concerning the progress of the process, being considered along with'the information previously obtained as to the nature of the formation derived from coring, or the previous production history, or in some other conventional fashion.

The beginning of blocking of flow will become evident In particular, if a given flow of air is maintained, as by the use of a positive compressor, a rise of thepressure differential be tween the injection wells and the. producing wells will indicate the building up of resistance to flow; or, alternatively, if pressures are maintained, and non-positive compressors, such as centrifugal compressors are used, the building up of resistance will be evidenced by reduction of injected air flow. Initial building up of resistance to flow may be tolerated; but when the pressure differential or the decreased air flow rate reaches such a value that, again considering known reservoir conditions, the progress of the conventional procedure is considered unsatisfactory, there will be brought into play, in accordance with the invention, the novel steps of the procedures.

These. involve, basically, first, the reduction of pressure. This may be accomplished in one, or preferably both, of the following ways:

The rate of injection of air may be substantially reduced without change of throttling at the producing wells. Alternatively, the injection air flow rate may be maintained, but the throttling action at the producing wells may be reduced so as to increase the rate of produced flow. If pumping is used to remove the fluids from the producing wells, the rate of pumping may be substantially increased.

Preferably, however, both expedients are used, the rate of air injection being lowered and the rate of withdrawal from the producing wells being increased. The net result of any of these procedures is to produce lowering of the pressures existing in the formation.

The air injection may be stopped entirely for several days; however cessation of air injection for extended periods would be undesirable for several reasons:

First, it is not desirable to have the combustion zone drop below the ignition temperature since it may then will immediately appear, the desired results in accordance with the invention involve the vaporization of water and other volatile constituents from the condensation zone, and the volatilization involves the absorption of heat. Most desirable, therefore, is the maintenance of sufiicient air flow to maintain active combustion and production of desired flow, though some reduction of air flow injection is desirable to produce as great a lowering of pressure as possible. The extent to which lowering of injected air rate is effected depends upon the known conditions of the (formation and the location of the condensation zone. If, between this zone and the producing well there is such a considerable distance that there is a large pressure drop, the pressure on the condensation zone may be said to be primarily due to the injection rate. In such case the injection rate should belowered as far as is safe and consistent with the desired maintenance of heat. On the other hand, if the condensation zone is closer to the producing wells so that the major pressure drop due to flow is between the injection wells and the condensation zone, a higher flow rate of injected air may be maintained, the pressure reduction in the condensation zone being then primarily due to increased rates of withdrawal.

The lowering of pressure in the formation, and specifically in the condensation zone, produces volatilization of the condensed water and at least the more volatile hydrocarbons therein. As has already been mentioned, the temperature in this condensation zone will, considering water its primary condensate, be approximately that of condensation of water at the high pressure maintained during the conventional burning procedure. Thus, even a moderate reduction of pressure in the condensation zone will result in vaporization of the water therein. This vaporiza tion is accompanied by absorption of heat, and hence cooling takes place which would ultimately stop the vaporization operation. Accordingly it is desirable to lower the pressure as far as possible below the original pressure maintained previously. It will now be seen that the continuation of combustion has a considerable advantage: coupled with the reduction of pressure, heat is continuously added to the condensation zone to maintain the temperature above the boiling point of the water at the.

lowered pressure, and if the rate of combustion is sufficiently maintained, a quite complete vaporization of the water from the condensation zone may be accomplished.

At this point it might appear that the result of the foregoing might be merely that of moving the condensation zone further downstream. While this may occur to some extent, the maintenance of flow of combustion gases will produce a mobile gas phase which will carry the volatilized Water along with it, as vapor saturation, and since these gases are hot, though progressively cooled in passing through the formation, a quite considerable portion of the water will be carried with them out of the producing wells. .But this same situation has another effect which results in re-establishing proper flow conditions: even though a water condensation may occur further downstream, the region through which this takes place is so extended that at any point the condensation will result only in relatively small increase in water content in the formation. It is generally a high water content which will produce the blocking action.

But in addition to this, there is another result due to the liberation of dissolved gases downstream of the condensation zone. Under the reduced pressure, large volumes of these gases are produced, giving rise to a driving and sweeping action which will further carry the water vapor along with the morevolatile constituents of the hydrocarbons present. Under the reduced pressure, the great volume of these dissolved gases produced would efiect a driving action even if the injected air were cut off. The sum total of the situation, then, is the production of a very large amount of gaseous fluid comprising variously at different downstream locations, steam, volatilized hydrocarbons, products of combustion, previously dissolved gases, and vapors of water and more volatile hydrocarbons carried thereby. The result, therefore, is not merely the displacement of the blocking zone to a position further downstream.

Attending the evolution of dissolved gases, the liquid phases in the condensation and following zones shrink in volume so as to contribute to the volume of the gas phase in the porosity of the formation. This further contributes tothe reestablishment of free flow conditions. Increase in oil production rate is due to gas expansion from solution, change of phase, and pressure reduction.

What happens progressively during this reduced pressure phase of the operation may be ascertained by analysis of the products passing from the producing wells. The removal of the blocking condition in the condensation zone may be checked by increasing the flow of injected air and measuring the rate of increase of pressure. When it has thus been ascertained that proper flow conditions have been re-established, repressuring may be carried out by increasing the air injection rate and decreasing the production by throttling or by decreasing the pumping rate at the producing wells, as the particular situation determines. If the formation is not toodeep, the injection air pressure may be used to drive the products, a mixture of liquids. and gases, out of the producing wells; but in the case of deep wells, pumping may be resorted to in the usual fashion.

Following the reestablishment of normal forward buming, this may be continued until blocking in a condensation zone reappears and assumes such a magnitude as to interfere again with the desired rate of progress. The procedure involving the reduction of pressure may then be repeated, and in the complete procedure of burning out the entire formation, this cycle of high and low pressure operations may be repeated as often as may be required.

FIGURE 2 is a diagram which may serve to give a better visualization of What occurs in the carrying out.

of a procedure as above-described. This is a plot of temperature against distance, the assumption being that the injection region is at the left of this diagram and the production region at or beyond its right, there being arbitrarily assumed conditions existing initially in which the combustion zone is about midway between the injection and producing locations. The curve portion at 28 indicates temperature conditions in the burned zone. 30

indicates the maximum temperature conditions characterizing the combustion zone. As already indicated, the

zones will never be sharply defined, and generally some combustion will continue in the burned zone though the temperature will be lowered adjacent to the injection wells due to the cooling action of the incoming air. Following the maximum temperature point, there is the cracking zone through which the temperature drops as shown by the portion of the curve at 34. This merges with the plateau 34 of .the curve which characterizes the condensation zone. The plateau of temperature here corresponds to the temperature at which condensation, largely of water, takes place at the existing pressure which at this time will be considered to be that involved during normal fonward burning. Beyond this condensation region, the temperature aga-in drops due to absorption of heat from the flowing gases, the final temperature reachedat 34 being essentially the ambient temperature of the unchanged part of the formation. In the region of this last drop of temperature and beyond, solution of gases takes place. i

The portions of the curve so far described correspond to normal fonward burning, and may be considered as those existing when it is found desirable, because of blocking, to reduce the pressure as described above.

With-reduction of pressure, which, of course, does not occur instantaneously but. gradually, as equilibrium conditions are approached in dependence on flow rate, the portions of the curve 34, 34' and 34 shift to 36, 36'

' l? and 36 and then to 38, 38 and 38". It may be assumed that the curve made up of the last mentioned portions is that corresponding to the termination of the pressure-reduction part of the cycle.

The curve portion 36 corresponds to the advance of higher temperatures and progress of the cracking zone. 36 is another condensation zone plateau, and the tempera-ture here is that corresponding to the condensation temperature at the partially reduced pressure reached during the pressure change. Finally as pressure equilibrium conditions are established, the cracking zone reaches the location of curve portion 38 and the plateau 38 represents the condensation zone temperature corresponding s earer to the final pressure achieved. When the region at 38 is reached, the greater part of the water will have been removed in the form of vapor carried by the flowing gases, which gases will not only be the combustion products but will include the dissolved gases separating out of the liquid phase together wit-h the more volatile hydrocarbons.

It will be noted that the plateau 38 is more extensive spacially than the plateau 34. This represents a reduced concentration of the liquid phase in the formation, increasing the elfective permeability from the standpoint of gas flow.

The curves .0 and 42. represent the condition existing as repressuring takes place, the curve 42 representing the completion of the repressuring operation and the beginning of normal continuation of the forward burning. The plateau at 42' represents the temperature of condensation corresponding to the reestablished high pres-- sure. The shift to ambient pressure at 42" is now displaced in the direction of fiow.

The diagram shown in FIGURE 3 is a plot of static pressure against temperature and showing equilibrium conditions in the condensation zone. The curve 43 represents 100% liquid phase and the curve 44, liquid phase, i.e., 100% vapor phase. The intermediate curves indicate variations of percentage liquid content, the critical pointbeing indicated at as. The point 48 represents the static pressure condition at the time the normal forward burning is interrupted and pressure reduction started. Point 59 represents the condition which would be attained if theoretically instantaneous pressure drop occurred to the ultimate reduced pressure reached. 52 represents the point corresponding to reduction of tempera-' ture at this pressure. Actually, due to how conditions, the pressure cannot drop instantaneously, but is delayed in time, with temperature drops occurring simultaneously with pressure drops so that the actual changing conditions occur as indicated by the line '4. Repressuring also is somewhat gradual so that it takes place along a line such as 56.

As has already been indicated, the conditions of oporation vary widely with the particular formation which is undergoing treatment, depending upon the adoption of optimum rates of burning, as controlled by air injection, and as determined by thebest conclusions for desired operation which may be deduced from all circumstances. Accordingly, each particular situation presents its individual problem, and the solution to the Problem,

from the standpoint of pressures adopted, times permit-' ted for equilibrium, etc., must be at the discretion of the operator guided by the measurements and analyzes already discussed.

As an example of the foregoing procedure, the burning prior to substantial blocking may be carried out under pressures ranging from about 50 to 2000 lbs. per square inch, with the average pressure gradient between the injection point and production point of the order of 0.1 to 2.0 lbs. per square inch per foot of distance. As fluid blocking builds up, this average pressure-gradient may increase to around 3 to 5 lbs. per square inch per root of distance for a continuous uniform flow of in- ;ected air. Localized pres-sure gradients between the injection and production points may vary over a Wide range depending upon the relative position of the point of measurement to the five zones created in the hydrocarbon bearing strata by the thermal process. Pressure gradients may go from as low as 0.1 lb. per square inch per foot in the burned zone to as high as 60.0 lbs. per square inch per foot in the condensation zone. When the average pressure gradient between injection and production points approaches the maximum stated, the input pressure may become prohibitively high for economical production. Accordingly, when such blocking occurs the pressure would typically be reduced in the formation by the amount of 10 to 50%; for example, by cutting down the inflow of air by 25 to 100% of the rate theretofore maintained, for an appropriate duration, while maintaining production at substantially the same rate as at an increased rate by pumping. This reduction of pressure in the formation will result in a lowering of the boiiing pointof water and hydrocarbons to the extent oi about 50 to 150 F. to provide the evaporation condition previously described. As a result there would typically arise the following conditions:

(1) An increase in gas saturation would accompany the reduction in temperature and pressure of the condensation zone ranging from 5 to 30% of the pore volume due to vaporization of water and volatile hydrocarbons.

(2) Evolution of gas, both hydrocarbon and products of combustion, from solution in the oil in the ambient zone would occur.

(3) An expansion of free gas existing at the pressure theretofore would occur in proportion to the change in its temperature and pressure in accordance with Boyles law.

(4) T he expansion of gases and vaporization of liquids would necessitate the removal of products at the producing well at a rate two to five times greater than the theretofore preceding rate. This increase in production rate would result in a more rapid recovery of oil.

(5) An increase in gas permeability due to the increase in gas saturation resulting in an increase in the air injection capacity of as much as twice that of the theretofore injection capacity.

(6) The increase in oil production rate and air injection capacity both working to make the process more profitable and of shorter duration.

While theprogress of the method here involved may be followed and controlled by taking into account measurements made as it progresses, as described above, it has been found useful to attempt to simulate on a much reduced scale what is occurring by the operation of a model chosen to conform with the actual conditions being encountered in the field. Operation of such a model with its results extrapolated to field conditions will frequently serve as a useful guide. Such a model may, for example, be provided by a heat-insulated tube of suitable length, the tube then representing a flow tube in the actual formation, i.e. a bundle of streamlines having a particular limited cross-section. By measurement of the progress of the process in such a model, and by taking into account the aspects of analogy with the field, a guide is afforded as to what is actually occurring and what should be done, checking, of course, being continuously made against actual measurements in the field operation. Since such a model is highly informative of what actually occurs, it will be instructive to describe operation in a typical model of this sort, as follows:

In such a model a forward burn was initiated in a porous medium containing oil,'water and gas at respective saturations of 59.0%, 14.7% and 26.3%. The forward burn was conducted to approximately 25% of the distance through the combustion tube, and a fluid block developed reducing air flux from an initial 36.5 standard cubic feet per hour per square foot of cross-sectional area to 4.5 standard cubic feet per hour per square foot. The rate of advance of the combustion zone was found to de- 9 crease from 4.1 feet per day to 1.4 feet per day as the fluid block developed and restricted air flow. At the time pressure reduction was then eliected, the combustion zone temperature, the condensation zone temperature and the ambient zone temperature were respectively found to be 1000 F., 381 F. and 78 F. The static pressures through the system, when the pressure reduction was initiated, were approximately 250 lbs. per square inch in the burned zone, 200 lbs. per square inch in the condensation zone, and 195 lbs. per square inch in the ambient zone. The reduction in static pressure in the system was accomplished in approximately 45 minutes and this pressure reduction was accompanied by a reduction in temperature of 30 F. and an increase in length of the condensation zone of 100%. Further reduction in static pressure in the condensation zone to the extent of 150 lbs. per square inch and 200 lbs. per square inch resulted in reductions in temperature therein to the extent of 55 F. and 105 F., respectively. During the pressure reduction process the production of oil increased 5.25 fold. When the pressure in the continuation zone reached 50 lbs. per square inch, air injection was again resumed and sustained at a flux of 36.85 standard cubic feet per hour per square foot. The

.pressures in the burned zone, condensation zone and ambient zone were restored by this flow to 250 lbs. per square inch, 225 lbs. per square inch and 220 lbs. per square inch, respectively. Repetitions of such a cycle will be found to be possible, with restoration of air injectivity following each pressure reduction.

It will be evident from the foregoing that numerous variations in specific procedure may be adopted without departing from the invention as defined in the following claims.

What is claimed is:

1. The method of production of hydrocarbon materials from a hydrocarbon-containing formation penetrated by at least two wells comprising:

injecting into one of said wells an oxygen-containing gas and supporting thereby combustion of carbonaceous material in said formation with progression of the combustion towards the other of said wells and removal of products from the latter, the foregoing procedure being carried out under elevated pressure conditions in the formation;

maintaining the foregoing procedure until a substantial resistance to flow through the formation appears between said wells;

then effecting lowering of the pressure in the formation while maintaining pressure conditions to continue flow of products through the second mentioned well, said lowering of pressure being maintained until said resistance to flow is substantially decreased by reason of vaporization of condensed liquids; and

thereafter continuing the procedure first above mentioned under elevated pressure conditions in the formation.

2. The method of production of hydrocarbon materials from a hydrocarbon-containing formation penetrated by at least two wells comprising:

injecting into one of said wells an oxygen-containing gas and supporting thereby combustion of carbonaceous material in said formation with progression of the combustion towards the other of said wells and removal of products from the latter, the foregoing procedure being carried out under elevated pressure conditions in the formation;

maintaining the foregoing procedure until a substantial resistance to flow through the formation appears between said wells;

then effecting lowering of the pressure in the formation while continuing the injection of oxygen-containing gas to maintain combustion, and while maintaining pressure conditions to continue flow of products through the second mentioned well, said lowering of pressure being maintained until said resistance to flow is substantially decreased by reason of vaporization of condensed liquid; and

thereafter continuing the procedure first above mentioned under elevated pressure conditions in the formation.

3. The method of production of hydrocarbon materials from a hydrocarbon-containing formation penetrated by at least two wells comprising:

injecting into one of said wells an oxygen-containing gas and supporting thereby combustion of carbonaceous material in said formation with progression of the combustion towards the other of said wells and removal of products from the latter, the foregoing procedure being carried out under elevated pressure conditions in the formation;

. maintaining the foregoing procedure until a substantial resistance to flow through the formation ap pears between said wells;

then effecting lowering of the pressure in the formation while continuing the injection of oxygen-containing gas, but at a reduced rate, to maintain combustion, and while maintaining pressure conditions to continue flow of products through the second mentioned well, said lowering of pressure being maintained until said resistance to flow is substantially decreased by reason of vaporization of condensed liquid; and

thereafter continuing the procedure first above mentioned under elevated pressure conditions in the formation.

5/57 Morse 166-11 12/58 Baron van Utenhove et a1. 166-11 BENJAMIN HERSH, Primary Examiner.

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US2642943 *May 20, 1949Jun 23, 1953Sinclair Oil & Gas CoOil recovery process
US2771951 *Sep 11, 1953Nov 27, 1956California Research CorpMethod of oil recovery by in situ combustion
US2793696 *Jul 22, 1954May 28, 1957Pan American Petroleum CorpOil recovery by underground combustion
US2862557 *Sep 12, 1955Dec 2, 1958Shell DevPetroleum production by underground combustion
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US3346044 *Sep 8, 1965Oct 10, 1967Mobil Oil CorpMethod and structure for retorting oil shale in situ by cycling fluid flows
US3362471 *Sep 8, 1965Jan 9, 1968Mobil Oil CorpIn situ retorting of oil shale by transient state fluid flows
US3434541 *Oct 11, 1967Mar 25, 1969Mobil Oil CorpIn situ combustion process
US3448807 *Dec 8, 1967Jun 10, 1969Shell Oil CoProcess for the thermal recovery of hydrocarbons from an underground formation
US3628929 *Dec 8, 1969Dec 21, 1971Cities Service Oil CoMethod for recovery of coal energy
US4120354 *Jun 3, 1977Oct 17, 1978Occidental Oil Shale, Inc.Determining the locus of a processing zone in an in situ oil shale retort by pressure monitoring
US4162706 *Jan 12, 1978Jul 31, 1979Occidental Oil Shale, Inc.Determining the locus of a processing zone in an oil shale retort by monitoring pressure drop across the retort
US4465135 *May 3, 1983Aug 14, 1984The United States Of America As Represented By The United States Department Of EnergyFire flood method for recovering petroleum from oil reservoirs of low permeability and temperature
US4651826 *Jan 17, 1985Mar 24, 1987Mobil Oil CorporationOil recovery method
US4886118 *Feb 17, 1988Dec 12, 1989Shell Oil CompanyConductively heating a subterranean oil shale to create permeability and subsequently produce oil
US6581684Apr 24, 2001Jun 24, 2003Shell Oil CompanyIn Situ thermal processing of a hydrocarbon containing formation to produce sulfur containing formation fluids
US6588504Apr 24, 2001Jul 8, 2003Shell Oil CompanyIn situ thermal processing of a coal formation to produce nitrogen and/or sulfur containing formation fluids
US6591906Apr 24, 2001Jul 15, 2003Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation with a selected oxygen content
US6591907Apr 24, 2001Jul 15, 2003Shell Oil CompanyIn situ thermal processing of a coal formation with a selected vitrinite reflectance
US6607033Apr 24, 2001Aug 19, 2003Shell Oil CompanyIn Situ thermal processing of a coal formation to produce a condensate
US6609570Apr 24, 2001Aug 26, 2003Shell Oil CompanyIn situ thermal processing of a coal formation and ammonia production
US6688387Apr 24, 2001Feb 10, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to produce a hydrocarbon condensate
US6698515Apr 24, 2001Mar 2, 2004Shell Oil CompanyIn situ thermal processing of a coal formation using a relatively slow heating rate
US6702016Apr 24, 2001Mar 9, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation with heat sources located at an edge of a formation layer
US6708758Apr 24, 2001Mar 23, 2004Shell Oil CompanyIn situ thermal processing of a coal formation leaving one or more selected unprocessed areas
US6712135Apr 24, 2001Mar 30, 2004Shell Oil CompanyIn situ thermal processing of a coal formation in reducing environment
US6712136Apr 24, 2001Mar 30, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using a selected production well spacing
US6712137Apr 24, 2001Mar 30, 2004Shell Oil CompanyIn situ thermal processing of a coal formation to pyrolyze a selected percentage of hydrocarbon material
US6715546Apr 24, 2001Apr 6, 2004Shell Oil CompanyIn situ production of synthesis gas from a hydrocarbon containing formation through a heat source wellbore
US6715547Apr 24, 2001Apr 6, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to form a substantially uniform, high permeability formation
US6715548Apr 24, 2001Apr 6, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to produce nitrogen containing formation fluids
US6715549Apr 24, 2001Apr 6, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation with a selected atomic oxygen to carbon ratio
US6722429Apr 24, 2001Apr 20, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation leaving one or more selected unprocessed areas
US6722430Apr 24, 2001Apr 20, 2004Shell Oil CompanyIn situ thermal processing of a coal formation with a selected oxygen content and/or selected O/C ratio
US6722431Apr 24, 2001Apr 20, 2004Shell Oil CompanyIn situ thermal processing of hydrocarbons within a relatively permeable formation
US6725920Apr 24, 2001Apr 27, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to convert a selected amount of total organic carbon into hydrocarbon products
US6725921Apr 24, 2001Apr 27, 2004Shell Oil CompanyIn situ thermal processing of a coal formation by controlling a pressure of the formation
US6725928Apr 24, 2001Apr 27, 2004Shell Oil CompanyIn situ thermal processing of a coal formation using a distributed combustor
US6729395Apr 24, 2001May 4, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation with a selected ratio of heat sources to production wells
US6729396Apr 24, 2001May 4, 2004Shell Oil CompanyIn situ thermal processing of a coal formation to produce hydrocarbons having a selected carbon number range
US6729397Apr 24, 2001May 4, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation with a selected vitrinite reflectance
US6729401Apr 24, 2001May 4, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation and ammonia production
US6732794Apr 24, 2001May 11, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to produce a mixture with a selected hydrogen content
US6732795Apr 24, 2001May 11, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to pyrolyze a selected percentage of hydrocarbon material
US6732796Apr 24, 2001May 11, 2004Shell Oil CompanyIn situ production of synthesis gas from a hydrocarbon containing formation, the synthesis gas having a selected H2 to CO ratio
US6736215Apr 24, 2001May 18, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation, in situ production of synthesis gas, and carbon dioxide sequestration
US6739393Apr 24, 2001May 25, 2004Shell Oil CompanyIn situ thermal processing of a coal formation and tuning production
US6739394Apr 24, 2001May 25, 2004Shell Oil CompanyProduction of synthesis gas from a hydrocarbon containing formation
US6742587Apr 24, 2001Jun 1, 2004Shell Oil CompanyIn situ thermal processing of a coal formation to form a substantially uniform, relatively high permeable formation
US6742588Apr 24, 2001Jun 1, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to produce formation fluids having a relatively low olefin content
US6742589Apr 24, 2001Jun 1, 2004Shell Oil CompanyIn situ thermal processing of a coal formation using repeating triangular patterns of heat sources
US6742593Apr 24, 2001Jun 1, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using heat transfer from a heat transfer fluid to heat the formation
US6745831Apr 24, 2001Jun 8, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation by controlling a pressure of the formation
US6745832Apr 24, 2001Jun 8, 2004Shell Oil CompanySitu thermal processing of a hydrocarbon containing formation to control product composition
US6745837Apr 24, 2001Jun 8, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using a controlled heating rate
US6749021Apr 24, 2001Jun 15, 2004Shell Oil CompanyIn situ thermal processing of a coal formation using a controlled heating rate
US6752210Apr 24, 2001Jun 22, 2004Shell Oil CompanyIn situ thermal processing of a coal formation using heat sources positioned within open wellbores
US6758268Apr 24, 2001Jul 6, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using a relatively slow heating rate
US6761216Apr 24, 2001Jul 13, 2004Shell Oil CompanyIn situ thermal processing of a coal formation to produce hydrocarbon fluids and synthesis gas
US6763886Apr 24, 2001Jul 20, 2004Shell Oil CompanyIn situ thermal processing of a coal formation with carbon dioxide sequestration
US6769483Apr 24, 2001Aug 3, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using conductor in conduit heat sources
US6769485Apr 24, 2001Aug 3, 2004Shell Oil CompanyIn situ production of synthesis gas from a coal formation through a heat source wellbore
US6789625Apr 24, 2001Sep 14, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using exposed metal heat sources
US6805195Apr 24, 2001Oct 19, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to produce hydrocarbon fluids and synthesis gas
US6820688Apr 24, 2001Nov 23, 2004Shell Oil CompanyIn situ thermal processing of coal formation with a selected hydrogen content and/or selected H/C ratio
US6866097Apr 24, 2001Mar 15, 2005Shell Oil CompanyIn situ thermal processing of a coal formation to increase a permeability/porosity of the formation
US6871707Apr 24, 2001Mar 29, 2005Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation with carbon dioxide sequestration
US6877554Apr 24, 2001Apr 12, 2005Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using pressure and/or temperature control
US6880635Apr 24, 2001Apr 19, 2005Shell Oil CompanyIn situ production of synthesis gas from a coal formation, the synthesis gas having a selected H2 to CO ratio
US6889769Apr 24, 2001May 10, 2005Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation with a selected moisture content
US6896053Apr 24, 2001May 24, 2005Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using repeating triangular patterns of heat sources
US6902003Apr 24, 2001Jun 7, 2005Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation having a selected total organic carbon content
US6902004Apr 24, 2001Jun 7, 2005Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using a movable heating element
US6910536Apr 24, 2001Jun 28, 2005Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using a natural distributed combustor
US6913078Apr 24, 2001Jul 5, 2005Shell Oil CompanyIn Situ thermal processing of hydrocarbons within a relatively impermeable formation
US6923258Jun 12, 2003Aug 2, 2005Shell Oil CompanyIn situ thermal processsing of a hydrocarbon containing formation to produce a mixture with a selected hydrogen content
US6948563Apr 24, 2001Sep 27, 2005Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation with a selected hydrogen content
US6953087Apr 24, 2001Oct 11, 2005Shell Oil CompanyThermal processing of a hydrocarbon containing formation to increase a permeability of the formation
US6959761Apr 24, 2001Nov 1, 2005Shell Oil CompanyIn situ thermal processing of a coal formation with a selected ratio of heat sources to production wells
US6966372Apr 24, 2001Nov 22, 2005Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to produce oxygen containing formation fluids
US6973967Apr 24, 2001Dec 13, 2005Shell Oil CompanySitu thermal processing of a coal formation using pressure and/or temperature control
US6991031Apr 24, 2001Jan 31, 2006Shell Oil CompanyIn situ thermal processing of a coal formation to convert a selected total organic carbon content into hydrocarbon products
US6994160Apr 24, 2001Feb 7, 2006Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to produce hydrocarbons having a selected carbon number range
US6994161Apr 24, 2001Feb 7, 2006Kevin Albert MaherIn situ thermal processing of a coal formation with a selected moisture content
US6994168 *Apr 24, 2001Feb 7, 2006Scott Lee WellingtonIn situ thermal processing of a hydrocarbon containing formation with a selected hydrogen to carbon ratio
US6997255Apr 24, 2001Feb 14, 2006Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation in a reducing environment
US7017661Apr 24, 2001Mar 28, 2006Shell Oil CompanyProduction of synthesis gas from a coal formation
US7032660Apr 24, 2002Apr 25, 2006Shell Oil CompanyIn situ thermal processing and inhibiting migration of fluids into or out of an in situ oil shale formation
US7036583Sep 24, 2001May 2, 2006Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to increase a porosity of the formation
US7077198Oct 24, 2002Jul 18, 2006Shell Oil CompanyIn situ recovery from a hydrocarbon containing formation using barriers
US7086468Apr 24, 2001Aug 8, 2006Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using heat sources positioned within open wellbores
US7096941Apr 24, 2001Aug 29, 2006Shell Oil CompanyIn situ thermal processing of a coal formation with heat sources located at an edge of a coal layer
US7096953Apr 24, 2001Aug 29, 2006Shell Oil CompanyIn situ thermal processing of a coal formation using a movable heating element
US7644765Oct 19, 2007Jan 12, 2010Shell Oil CompanyHeating tar sands formations while controlling pressure
US7673681Oct 19, 2007Mar 9, 2010Shell Oil CompanyTreating tar sands formations with karsted zones
US7673786Apr 20, 2007Mar 9, 2010Shell Oil CompanyWelding shield for coupling heaters
US7677310Oct 19, 2007Mar 16, 2010Shell Oil CompanyCreating and maintaining a gas cap in tar sands formations
US7677314Oct 19, 2007Mar 16, 2010Shell Oil CompanyMethod of condensing vaporized water in situ to treat tar sands formations
US7681647Mar 23, 2010Shell Oil CompanyMethod of producing drive fluid in situ in tar sands formations
US7683296Mar 23, 2010Shell Oil CompanyAdjusting alloy compositions for selected properties in temperature limited heaters
US7703513Oct 19, 2007Apr 27, 2010Shell Oil CompanyWax barrier for use with in situ processes for treating formations
US7717171Oct 19, 2007May 18, 2010Shell Oil CompanyMoving hydrocarbons through portions of tar sands formations with a fluid
US7730945Oct 19, 2007Jun 8, 2010Shell Oil CompanyUsing geothermal energy to heat a portion of a formation for an in situ heat treatment process
US7730946Oct 19, 2007Jun 8, 2010Shell Oil CompanyTreating tar sands formations with dolomite
US7730947Oct 19, 2007Jun 8, 2010Shell Oil CompanyCreating fluid injectivity in tar sands formations
US7735935Jun 1, 2007Jun 15, 2010Shell Oil CompanyIn situ thermal processing of an oil shale formation containing carbonate minerals
US7785427Apr 20, 2007Aug 31, 2010Shell Oil CompanyHigh strength alloys
US7793722Apr 20, 2007Sep 14, 2010Shell Oil CompanyNon-ferromagnetic overburden casing
US7798220Apr 18, 2008Sep 21, 2010Shell Oil CompanyIn situ heat treatment of a tar sands formation after drive process treatment
US7798221Sep 21, 2010Shell Oil CompanyIn situ recovery from a hydrocarbon containing formation
US7831134Apr 21, 2006Nov 9, 2010Shell Oil CompanyGrouped exposed metal heaters
US7832484Apr 18, 2008Nov 16, 2010Shell Oil CompanyMolten salt as a heat transfer fluid for heating a subsurface formation
US7841401Oct 19, 2007Nov 30, 2010Shell Oil CompanyGas injection to inhibit migration during an in situ heat treatment process
US7841408Apr 18, 2008Nov 30, 2010Shell Oil CompanyIn situ heat treatment from multiple layers of a tar sands formation
US7841425Nov 30, 2010Shell Oil CompanyDrilling subsurface wellbores with cutting structures
US7845411Dec 7, 2010Shell Oil CompanyIn situ heat treatment process utilizing a closed loop heating system
US7849922Dec 14, 2010Shell Oil CompanyIn situ recovery from residually heated sections in a hydrocarbon containing formation
US7860377Apr 21, 2006Dec 28, 2010Shell Oil CompanySubsurface connection methods for subsurface heaters
US7866385Apr 20, 2007Jan 11, 2011Shell Oil CompanyPower systems utilizing the heat of produced formation fluid
US7866386Oct 13, 2008Jan 11, 2011Shell Oil CompanyIn situ oxidation of subsurface formations
US7866388Jan 11, 2011Shell Oil CompanyHigh temperature methods for forming oxidizer fuel
US7912358Apr 20, 2007Mar 22, 2011Shell Oil CompanyAlternate energy source usage for in situ heat treatment processes
US7931086Apr 18, 2008Apr 26, 2011Shell Oil CompanyHeating systems for heating subsurface formations
US7942197Apr 21, 2006May 17, 2011Shell Oil CompanyMethods and systems for producing fluid from an in situ conversion process
US7942203May 17, 2011Shell Oil CompanyThermal processes for subsurface formations
US7950453Apr 18, 2008May 31, 2011Shell Oil CompanyDownhole burner systems and methods for heating subsurface formations
US7986869Apr 21, 2006Jul 26, 2011Shell Oil CompanyVarying properties along lengths of temperature limited heaters
US8011451Sep 6, 2011Shell Oil CompanyRanging methods for developing wellbores in subsurface formations
US8027571Sep 27, 2011Shell Oil CompanyIn situ conversion process systems utilizing wellbores in at least two regions of a formation
US8042610Oct 25, 2011Shell Oil CompanyParallel heater system for subsurface formations
US8070840Apr 21, 2006Dec 6, 2011Shell Oil CompanyTreatment of gas from an in situ conversion process
US8083813Dec 27, 2011Shell Oil CompanyMethods of producing transportation fuel
US8113272Oct 13, 2008Feb 14, 2012Shell Oil CompanyThree-phase heaters with common overburden sections for heating subsurface formations
US8146661Oct 13, 2008Apr 3, 2012Shell Oil CompanyCryogenic treatment of gas
US8146669Oct 13, 2008Apr 3, 2012Shell Oil CompanyMulti-step heater deployment in a subsurface formation
US8151880Dec 9, 2010Apr 10, 2012Shell Oil CompanyMethods of making transportation fuel
US8151907Apr 10, 2009Apr 10, 2012Shell Oil CompanyDual motor systems and non-rotating sensors for use in developing wellbores in subsurface formations
US8162059Apr 24, 2012Shell Oil CompanyInduction heaters used to heat subsurface formations
US8162405Apr 24, 2012Shell Oil CompanyUsing tunnels for treating subsurface hydrocarbon containing formations
US8172335May 8, 2012Shell Oil CompanyElectrical current flow between tunnels for use in heating subsurface hydrocarbon containing formations
US8177305Apr 10, 2009May 15, 2012Shell Oil CompanyHeater connections in mines and tunnels for use in treating subsurface hydrocarbon containing formations
US8191630Apr 28, 2010Jun 5, 2012Shell Oil CompanyCreating fluid injectivity in tar sands formations
US8192682Apr 26, 2010Jun 5, 2012Shell Oil CompanyHigh strength alloys
US8196658Jun 12, 2012Shell Oil CompanyIrregular spacing of heat sources for treating hydrocarbon containing formations
US8220539Jul 17, 2012Shell Oil CompanyControlling hydrogen pressure in self-regulating nuclear reactors used to treat a subsurface formation
US8224163Oct 24, 2003Jul 17, 2012Shell Oil CompanyVariable frequency temperature limited heaters
US8224164Oct 24, 2003Jul 17, 2012Shell Oil CompanyInsulated conductor temperature limited heaters
US8224165Jul 17, 2012Shell Oil CompanyTemperature limited heater utilizing non-ferromagnetic conductor
US8225866Jul 21, 2010Jul 24, 2012Shell Oil CompanyIn situ recovery from a hydrocarbon containing formation
US8230927May 16, 2011Jul 31, 2012Shell Oil CompanyMethods and systems for producing fluid from an in situ conversion process
US8233782Jul 31, 2012Shell Oil CompanyGrouped exposed metal heaters
US8238730Aug 7, 2012Shell Oil CompanyHigh voltage temperature limited heaters
US8240774Aug 14, 2012Shell Oil CompanySolution mining and in situ treatment of nahcolite beds
US8256512Oct 9, 2009Sep 4, 2012Shell Oil CompanyMovable heaters for treating subsurface hydrocarbon containing formations
US8261832Sep 11, 2012Shell Oil CompanyHeating subsurface formations with fluids
US8267170Sep 18, 2012Shell Oil CompanyOffset barrier wells in subsurface formations
US8267185Sep 18, 2012Shell Oil CompanyCirculated heated transfer fluid systems used to treat a subsurface formation
US8272455Sep 25, 2012Shell Oil CompanyMethods for forming wellbores in heated formations
US8276661Oct 2, 2012Shell Oil CompanyHeating subsurface formations by oxidizing fuel on a fuel carrier
US8281861Oct 9, 2012Shell Oil CompanyCirculated heated transfer fluid heating of subsurface hydrocarbon formations
US8327681Dec 11, 2012Shell Oil CompanyWellbore manufacturing processes for in situ heat treatment processes
US8327932Apr 9, 2010Dec 11, 2012Shell Oil CompanyRecovering energy from a subsurface formation
US8353347Oct 9, 2009Jan 15, 2013Shell Oil CompanyDeployment of insulated conductors for treating subsurface formations
US8355623Jan 15, 2013Shell Oil CompanyTemperature limited heaters with high power factors
US8381815Apr 18, 2008Feb 26, 2013Shell Oil CompanyProduction from multiple zones of a tar sands formation
US8434555Apr 9, 2010May 7, 2013Shell Oil CompanyIrregular pattern treatment of a subsurface formation
US8448707May 28, 2013Shell Oil CompanyNon-conducting heater casings
US8459359Apr 18, 2008Jun 11, 2013Shell Oil CompanyTreating nahcolite containing formations and saline zones
US8485252Jul 11, 2012Jul 16, 2013Shell Oil CompanyIn situ recovery from a hydrocarbon containing formation
US8536497Oct 13, 2008Sep 17, 2013Shell Oil CompanyMethods for forming long subsurface heaters
US8555971May 31, 2012Oct 15, 2013Shell Oil CompanyTreating tar sands formations with dolomite
US8562078Nov 25, 2009Oct 22, 2013Shell Oil CompanyHydrocarbon production from mines and tunnels used in treating subsurface hydrocarbon containing formations
US8579031May 17, 2011Nov 12, 2013Shell Oil CompanyThermal processes for subsurface formations
US8606091Oct 20, 2006Dec 10, 2013Shell Oil CompanySubsurface heaters with low sulfidation rates
US8608249Apr 26, 2010Dec 17, 2013Shell Oil CompanyIn situ thermal processing of an oil shale formation
US8627887Dec 8, 2008Jan 14, 2014Shell Oil CompanyIn situ recovery from a hydrocarbon containing formation
US8631866Apr 8, 2011Jan 21, 2014Shell Oil CompanyLeak detection in circulated fluid systems for heating subsurface formations
US8636323Nov 25, 2009Jan 28, 2014Shell Oil CompanyMines and tunnels for use in treating subsurface hydrocarbon containing formations
US8662175Apr 18, 2008Mar 4, 2014Shell Oil CompanyVarying properties of in situ heat treatment of a tar sands formation based on assessed viscosities
US8701768Apr 8, 2011Apr 22, 2014Shell Oil CompanyMethods for treating hydrocarbon formations
US8701769Apr 8, 2011Apr 22, 2014Shell Oil CompanyMethods for treating hydrocarbon formations based on geology
US8739874Apr 8, 2011Jun 3, 2014Shell Oil CompanyMethods for heating with slots in hydrocarbon formations
US8752904Apr 10, 2009Jun 17, 2014Shell Oil CompanyHeated fluid flow in mines and tunnels used in heating subsurface hydrocarbon containing formations
US8789586Jul 12, 2013Jul 29, 2014Shell Oil CompanyIn situ recovery from a hydrocarbon containing formation
US8791396Apr 18, 2008Jul 29, 2014Shell Oil CompanyFloating insulated conductors for heating subsurface formations
US8820406Apr 8, 2011Sep 2, 2014Shell Oil CompanyElectrodes for electrical current flow heating of subsurface formations with conductive material in wellbore
US8833453Apr 8, 2011Sep 16, 2014Shell Oil CompanyElectrodes for electrical current flow heating of subsurface formations with tapered copper thickness
US8851170Apr 9, 2010Oct 7, 2014Shell Oil CompanyHeater assisted fluid treatment of a subsurface formation
US8857506May 24, 2013Oct 14, 2014Shell Oil CompanyAlternate energy source usage methods for in situ heat treatment processes
US8881806Oct 9, 2009Nov 11, 2014Shell Oil CompanySystems and methods for treating a subsurface formation with electrical conductors
US9016370Apr 6, 2012Apr 28, 2015Shell Oil CompanyPartial solution mining of hydrocarbon containing layers prior to in situ heat treatment
US9022109Jan 21, 2014May 5, 2015Shell Oil CompanyLeak detection in circulated fluid systems for heating subsurface formations
US9022118Oct 9, 2009May 5, 2015Shell Oil CompanyDouble insulated heaters for treating subsurface formations
US9033042Apr 8, 2011May 19, 2015Shell Oil CompanyForming bitumen barriers in subsurface hydrocarbon formations
US9051829Oct 9, 2009Jun 9, 2015Shell Oil CompanyPerforated electrical conductors for treating subsurface formations
US9127523Apr 8, 2011Sep 8, 2015Shell Oil CompanyBarrier methods for use in subsurface hydrocarbon formations
US9127538Apr 8, 2011Sep 8, 2015Shell Oil CompanyMethodologies for treatment of hydrocarbon formations using staged pyrolyzation
US9129728Oct 9, 2009Sep 8, 2015Shell Oil CompanySystems and methods of forming subsurface wellbores
US9181780Apr 18, 2008Nov 10, 2015Shell Oil CompanyControlling and assessing pressure conditions during treatment of tar sands formations
US9309755Oct 4, 2012Apr 12, 2016Shell Oil CompanyThermal expansion accommodation for circulated fluid systems used to heat subsurface formations
US20020046883 *Apr 24, 2001Apr 25, 2002Wellington Scott LeeIn situ thermal processing of a coal formation using pressure and/or temperature control
US20030131995 *Apr 24, 2002Jul 17, 2003De Rouffignac Eric PierreIn situ thermal processing of a relatively impermeable formation to increase permeability of the formation
US20040144541 *Oct 24, 2003Jul 29, 2004Picha Mark GregoryForming wellbores using acoustic methods
US20080035346 *Apr 20, 2007Feb 14, 2008Vijay NairMethods of producing transportation fuel
US20080035348 *Apr 20, 2007Feb 14, 2008Vitek John MTemperature limited heaters using phase transformation of ferromagnetic material
US20080038144 *Apr 20, 2007Feb 14, 2008Maziasz Phillip JHigh strength alloys
US20080107577 *Oct 20, 2006May 8, 2008Vinegar Harold JVarying heating in dawsonite zones in hydrocarbon containing formations
US20080128134 *Oct 19, 2007Jun 5, 2008Ramesh Raju MudunuriProducing drive fluid in situ in tar sands formations
US20080135244 *Oct 19, 2007Jun 12, 2008David Scott MillerHeating hydrocarbon containing formations in a line drive staged process
US20080135253 *Oct 19, 2007Jun 12, 2008Vinegar Harold JTreating tar sands formations with karsted zones
US20080135254 *Oct 19, 2007Jun 12, 2008Vinegar Harold JIn situ heat treatment process utilizing a closed loop heating system
US20080173442 *Apr 20, 2007Jul 24, 2008Vinegar Harold JSulfur barrier for use with in situ processes for treating formations
US20080173444 *Apr 20, 2007Jul 24, 2008Francis Marion StoneAlternate energy source usage for in situ heat treatment processes
US20080173450 *Apr 20, 2007Jul 24, 2008Bernard GoldbergTime sequenced heating of multiple layers in a hydrocarbon containing formation
US20080277113 *Oct 19, 2007Nov 13, 2008George Leo StegemeierHeating tar sands formations while controlling pressure
US20090014180 *Oct 19, 2007Jan 15, 2009George Leo StegemeierMoving hydrocarbons through portions of tar sands formations with a fluid
US20090071652 *Apr 18, 2008Mar 19, 2009Vinegar Harold JIn situ heat treatment from multiple layers of a tar sands formation
US20090078461 *Apr 18, 2008Mar 26, 2009Arthur James MansureDrilling subsurface wellbores with cutting structures
US20090084547 *Apr 18, 2008Apr 2, 2009Walter Farman FarmayanDownhole burner systems and methods for heating subsurface formations
US20090090509 *Apr 18, 2008Apr 9, 2009Vinegar Harold JIn situ recovery from residually heated sections in a hydrocarbon containing formation
US20090095476 *Apr 18, 2008Apr 16, 2009Scott Vinh NguyenMolten salt as a heat transfer fluid for heating a subsurface formation
US20090095477 *Apr 18, 2008Apr 16, 2009Scott Vinh NguyenHeating systems for heating subsurface formations
US20090095479 *Apr 18, 2008Apr 16, 2009John Michael KaranikasProduction from multiple zones of a tar sands formation
US20090194269 *Oct 13, 2008Aug 6, 2009Vinegar Harold JThree-phase heaters with common overburden sections for heating subsurface formations
US20090194282 *Oct 13, 2008Aug 6, 2009Gary Lee BeerIn situ oxidation of subsurface formations
US20090194329 *Oct 13, 2008Aug 6, 2009Rosalvina Ramona GuimeransMethods for forming wellbores in heated formations
US20090194524 *Oct 13, 2008Aug 6, 2009Dong Sub KimMethods for forming long subsurface heaters
US20090200025 *Oct 13, 2008Aug 13, 2009Jose Luis BravoHigh temperature methods for forming oxidizer fuel
US20090200031 *Oct 13, 2008Aug 13, 2009David Scott MillerIrregular spacing of heat sources for treating hydrocarbon containing formations
US20090200854 *Oct 13, 2008Aug 13, 2009Vinegar Harold JSolution mining and in situ treatment of nahcolite beds
US20090260823 *Oct 22, 2009Robert George Prince-WrightMines and tunnels for use in treating subsurface hydrocarbon containing formations
US20090260824 *Oct 22, 2009David Booth BurnsHydrocarbon production from mines and tunnels used in treating subsurface hydrocarbon containing formations
US20090272533 *Apr 10, 2009Nov 5, 2009David Booth BurnsHeated fluid flow in mines and tunnels used in heating subsurface hydrocarbon containing formations
US20090272535 *Nov 5, 2009David Booth BurnsUsing tunnels for treating subsurface hydrocarbon containing formations
US20090272578 *Nov 5, 2009Macdonald Duncan CharlesDual motor systems and non-rotating sensors for use in developing wellbores in subsurface formations
US20100089586 *Oct 9, 2009Apr 15, 2010John Andrew StaneckiMovable heaters for treating subsurface hydrocarbon containing formations
US20100096137 *Oct 9, 2009Apr 22, 2010Scott Vinh NguyenCirculated heated transfer fluid heating of subsurface hydrocarbon formations
US20100101783 *Oct 9, 2009Apr 29, 2010Vinegar Harold JUsing self-regulating nuclear reactors in treating a subsurface formation
US20100101784 *Oct 9, 2009Apr 29, 2010Vinegar Harold JControlling hydrogen pressure in self-regulating nuclear reactors used to treat a subsurface formation
US20100108310 *Oct 9, 2009May 6, 2010Thomas David FowlerOffset barrier wells in subsurface formations
DE1231192B *Sep 27, 1965Dec 29, 1966Shell Int ResearchVerfahren zur Gewinnung von Kohlenwasserstoffen
Classifications
U.S. Classification166/256
International ClassificationE21B43/16, E21B43/243
Cooperative ClassificationE21B43/243
European ClassificationE21B43/243