CA1246998A - Controlling steam distribution - Google Patents
Controlling steam distributionInfo
- Publication number
- CA1246998A CA1246998A CA000507230A CA507230A CA1246998A CA 1246998 A CA1246998 A CA 1246998A CA 000507230 A CA000507230 A CA 000507230A CA 507230 A CA507230 A CA 507230A CA 1246998 A CA1246998 A CA 1246998A
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- CA
- Canada
- Prior art keywords
- well
- formation
- producing
- fluid
- oil
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired
Links
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
- E21B43/2405—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection in association with fracturing or crevice forming processes
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/30—Specific pattern of wells, e.g. optimizing the spacing of wells
Abstract
Abstract Of The Disclosure An enhanced oil recovery technique includes the prede-termination of a desired steam distribution within a steam flood pattern, which preferably is proportional to the vol-umes of oil in place within various sectors of an area of a subsurface formation. These sectors are associated with the various producing wells of the steam flood pattern. Initial steam distribution is then determined. Subsequently, one or more of the producing wells has its production rate modified so that the final steam distribution within the formation will more closely approximate the predetermined preferred steam distribution. A preferred technique for stimulating production from a given producing well includes the steps of initially notching and initiating a small unpropped fracture in the formation adjacent the well, then perforating the well over the entire depth of the formation, and sub-sequently creating a larger propped fracture at that same location after it has been determined that natural steam flow toward the particular producing well is not as great as is desired.
Description
: ' ICR~-7499 ~ 7510 CONTROLLING STEAM DISTRIBUTION
B ckground Of The Invention 1. Field Of The Invention The present invention relates generally to enhanced oil recovery techniques, and particularly to techniques for controlling the distribution of an injection fluid, such as steam, through~ut an area of a subsurface oil bearing for-mation to a plurality of producing wells.
B ckground Of The Invention 1. Field Of The Invention The present invention relates generally to enhanced oil recovery techniques, and particularly to techniques for controlling the distribution of an injection fluid, such as steam, through~ut an area of a subsurface oil bearing for-mation to a plurality of producing wells.
2. Description Of The Prior Art It is well known that most oil bearing formations will produce only a relatively small portion of the total oil in place through conventional production techniques. As a result a number of processes have been developed which are referred to a~ enhancsd oil recovery techniques, for pro-ducing some of the oil which is left behind after primary production techniques.
One such technique is steam flooding. Steam is injected into a formation to heat and mobilize the oil in the for-mation and drive that oil toward producing wells. Such techniques are particularly useful in fields where the oil deposits are relatively heavy and viscous.
Summary Of The Invention The present invention provides an enhanced oil recovery method which i8 particularly applicable to steam flooding operations.
By the method of the present invention, improved tech-niques are provided for determining a preferred steam distribution within a steam flood pattern, and for modifying the ~team distribution within the pattern so that it more closely approximates the previou~ly determined preferred steam distribution.
A pattern of wells is provided which includes at least - 35 one injection well intersecting an underground oil bearing ~a -~
-2- ~
formation or injecting an injectio~ fluid, preferably ~team, into an area of the formation ~urrounding the injec-tion well. The pattern also includes a plurality of pro-ducing wells intersecting said area of said formation for producing oil and other fluids from a plurality of sectors of said area. Each of said sectors is associated with one of said producing well~ and defines a portion of the area to be drained by its associated producing well.
A preferred steam distribution within each of the sec-10 tors of the area is determined by first determining an esti-mated volume of oil in place in each of the sectors, and thus determining a relative portion of the total oil volume of the area which is in place within each of ~he sectors.
The preferred relative steam distribution is one which is equiv~lent within each sector to the relative oil distribu-tion within that sector.
Steam is injected into the formation through the injec-tion well. The actual r~lative portions, of the -total volume of injected s~eam, which are ~lowing to each of the producing wells are determined by monitoring the relati~e fluid production rates of each of the producing wells.
Then, if the actual steam distribution is different from the preferred steam distribution corresponding to the oil in place distribution, the distribution pattern of the injected steam i~ modified.
This is accomplished by increasing fluid production from producing wells which are not producing the desired propor-tion of the total injected steam, and by decreasing fluid production from those wells which are determined to be receiving more than their preferred share of the injected steam.
A decrea~e in fluid production from a given well is accomplished by increasing the fluid level within that well and/or choking the wellhead pro~uction line to limit fluid production from that well.
An increase in fluid production from a given producing well is accomplished by pumping down the fluid level in the
One such technique is steam flooding. Steam is injected into a formation to heat and mobilize the oil in the for-mation and drive that oil toward producing wells. Such techniques are particularly useful in fields where the oil deposits are relatively heavy and viscous.
Summary Of The Invention The present invention provides an enhanced oil recovery method which i8 particularly applicable to steam flooding operations.
By the method of the present invention, improved tech-niques are provided for determining a preferred steam distribution within a steam flood pattern, and for modifying the ~team distribution within the pattern so that it more closely approximates the previou~ly determined preferred steam distribution.
A pattern of wells is provided which includes at least - 35 one injection well intersecting an underground oil bearing ~a -~
-2- ~
formation or injecting an injectio~ fluid, preferably ~team, into an area of the formation ~urrounding the injec-tion well. The pattern also includes a plurality of pro-ducing wells intersecting said area of said formation for producing oil and other fluids from a plurality of sectors of said area. Each of said sectors is associated with one of said producing well~ and defines a portion of the area to be drained by its associated producing well.
A preferred steam distribution within each of the sec-10 tors of the area is determined by first determining an esti-mated volume of oil in place in each of the sectors, and thus determining a relative portion of the total oil volume of the area which is in place within each of ~he sectors.
The preferred relative steam distribution is one which is equiv~lent within each sector to the relative oil distribu-tion within that sector.
Steam is injected into the formation through the injec-tion well. The actual r~lative portions, of the -total volume of injected s~eam, which are ~lowing to each of the producing wells are determined by monitoring the relati~e fluid production rates of each of the producing wells.
Then, if the actual steam distribution is different from the preferred steam distribution corresponding to the oil in place distribution, the distribution pattern of the injected steam i~ modified.
This is accomplished by increasing fluid production from producing wells which are not producing the desired propor-tion of the total injected steam, and by decreasing fluid production from those wells which are determined to be receiving more than their preferred share of the injected steam.
A decrea~e in fluid production from a given well is accomplished by increasing the fluid level within that well and/or choking the wellhead pro~uction line to limit fluid production from that well.
An increase in fluid production from a given producing well is accomplished by pumping down the fluid level in the
3 ~ ~J~ 3 ~
well to create a pressure sin~ within the formation adjac~nt that particular p~oducing well, and if that is not suf-ficient, a propped frac job is conducted on that producing well.
In anticipation of the potential need for performing a propped frac job on a given well, that well preferably is initially notched through hydraulic jetting or the like and an initial relatively small unpropped horizontal fracture is created within the formation at the notch and then allowed to reclose before the steam injection operation is begun.
Then, the well i~ perforated over the entire depth of the formation. Then, if it later is necessary to perform a propped frac job on that particular ~ell, it is assured that the propped fracture will be created at the location of the initial unpropped fracture, yet this is accomplished without initially in1uencing the flow of injected steam toward this particular producing well. Al~o, by perforating the well over the entire depth of the formation, that entire depth i3 drained.
Through the u~e of these techniques, an improved steam flood method is provided which significantly increases or enhances ~he recovery of oil from the formation.
An object of the invention is to provide improved enhanced oil recovery methods, ~uch as ~team flood opera-tions or other operations involving injected fluid, by dis~ributing the steam or other injected fluid in a pre-ferred manner that overcomes ini~ial flow tendencies within the formation such as are created by non-homogenous oil saturation distributions and/or non-homogenous rock proper-ties within the formation.
Another object i3 to provide an improved method of sti-mulating a producing well during a steam flood operation.
Numerous other ob~ects, features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the following disclosure when - taken in conjunction with the accompanying drawings.
well to create a pressure sin~ within the formation adjac~nt that particular p~oducing well, and if that is not suf-ficient, a propped frac job is conducted on that producing well.
In anticipation of the potential need for performing a propped frac job on a given well, that well preferably is initially notched through hydraulic jetting or the like and an initial relatively small unpropped horizontal fracture is created within the formation at the notch and then allowed to reclose before the steam injection operation is begun.
Then, the well i~ perforated over the entire depth of the formation. Then, if it later is necessary to perform a propped frac job on that particular ~ell, it is assured that the propped fracture will be created at the location of the initial unpropped fracture, yet this is accomplished without initially in1uencing the flow of injected steam toward this particular producing well. Al~o, by perforating the well over the entire depth of the formation, that entire depth i3 drained.
Through the u~e of these techniques, an improved steam flood method is provided which significantly increases or enhances ~he recovery of oil from the formation.
An object of the invention is to provide improved enhanced oil recovery methods, ~uch as ~team flood opera-tions or other operations involving injected fluid, by dis~ributing the steam or other injected fluid in a pre-ferred manner that overcomes ini~ial flow tendencies within the formation such as are created by non-homogenous oil saturation distributions and/or non-homogenous rock proper-ties within the formation.
Another object i3 to provide an improved method of sti-mulating a producing well during a steam flood operation.
Numerous other ob~ects, features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the following disclosure when - taken in conjunction with the accompanying drawings.
-4~ g~ 8 FIG. 1 is a schematic plan view of an inverted five spot pattern including one injection well and four producing wells for a steam flood project.
FIG. 2 is a somewhat schematic sectioned elevation view taken along line 2-2 showing the injection well and one of the producing wells along with the various associated sub-surface strata.
Detailed Dascription Of The Preferred Embodiments In a typical enhanced oil recovery project utilizin~
injected steam to heat and move vi3cous oil deposits to pro-ducing wells, a pattern of wells is generally utilized having a plurality of producing wells surrounding one or more injection wells.
FIG. 1 illustrate~ what i9 commonly referred to as an inverted five spot pattern having four producing wells A, B, C and D which are located a the four corners of a s~uare, with a single injection well ~ l~cated in the center of the square.
FIG. 2, which is a somewhat :chema~ic elevation section view taken along line 2~2 of FIG. 1 shows the producing well D on the left and the injection w~:ll E on the right.
Each of the wells A, B, C, D and E intersects an underground oil bearing formation 10. The purpose of the injection well E is to inject steam or in some instances other fluids into the formation 10 and to cause oil con-tained wi~hin formation 10 to move toward and be produced from the producing wells such as D.
In FIG. 1, an imaginary area of formation 10 in a square shape defined a~ it~ corner~ by the ~our producing wells A-D
i9 shown in phantom lines and designated by the numeral 12.
Furtherg phantom lines divide ~he area 12 into a plurality of sectors 14, 16, 18 and 20 associated with the producing wells A, B~ C and D, respectively~ Each of the sectors 14, - 16, 18 and 20 is associa~ed with one of the producing wells and defines a portion of the ar~a 12 of formation 10 to be drained by it~ a~sociated producing well.
As will be understood by those skilled in the art, steam flow from injection well E is not totally confined to area 12. Generally, however, the flow of steam is confined within area 12 by a combination of natural barriers which may exist and~or injection of back-up water into surrounding wells to prevent any significant flow of steam outside of area 12.
Determining The Preferred Steam Distribution A particular problem to which the present invention is directed is that of poor distribution of steam within the pattern represented in FIG. 1. Such problems are par-ticularly acute when, as i~ often the case, there have beenwater flood secondary recovery operations performed prior to ~he steam flood operations.
Due to such prior water flood operations and/or natural non-homogenous conditions occurring within the formation 10, the ~team injected into well E will generally follow chan-nel~ through the formation 10 which provide the least re~istance to ~team 1OW. Generally these channels will be through depleted zones and will avoid zones of high oil ~aturation where in fact it is most desired to direct the steam.
Furthermore, even if the properties of reservoir 10 are 3uch that steam does flow evenly into the four sectors 14, 16, 18 and 20, that still may not be the most effective distribution of team to achieve the maximum oil recovery.
It has been determined that the most efficient use of ~team in a steam injection process is accomplished if ~he steam i9 distributed throughout the various sector~ 14, 16, 18 and 20 of area 12 of formation 10 in the ~ame porpor~ion~
as oil is present within those sectors. This is preferable to an uncontrolled distribution, to an even distribution within the ~ectors when oil i~ not evenly distributed, and to a steam distribution based on reservoir pore volume di~tribution.
The preference for distributing steam based on the volume of oil in place as opposed to the reservoir pore volume can be illustrated with a ~imple thought experiment.
Consider two blocks of rock of equal pore volume connected to a common steam injection well. For the first case, let both blocks of rock have the same oil saturation so that they contain equal volume~ of oil (hydrocarbon pore volumes). In this case, it would be desirable for both blocks to receive equal ~uantities of steam. This satisfies the distribution based on reservoir pore volume as well as one based on hydrocarbon pore volume. In the second case, let one blocX contain recoverable hydrocarbons and the other be devoid of any oil. In thi~ case, it would be desirable to direct all of the steam to the block containing the hydrocarbons. This satisies a desired qteam distribution based vnly on hydrocarbon pore volume. A diRtribution based on reservoir pore volume would in the second case allow steam to move into the blocX where no oil exists and would be a waste of the investment in the steam. Consequently, when variations in oil ~aturation might exist, as is often the case in a previously water flooded formation, the desired steam distribution should be based on the distribu-tion of hydrocarbon within the steam flood pattern.
Thus, the fir~t step in determining the desired relativeproportions oX ~team distribution within the ~ectors 14, 16, 18 and 20, is to determine the estimated volume of oil in place within each sector; which can be accomplished by con-ventional reservoir analyses and engineering calculations.This is then converted to a desired steam distribution as shown by the following example.
E~ mple Con~ider an inverted five ~pot pa~tern a~ illustrated in FIG. 1 with available information obtained from reservoir analyses and engineering calculations showing ~he respective estima~ed volume~ of oil in place within ~he sectors 14, 16, 18 and 20 as shown on the foll~wing Tabl~ I.
Table I
10Sector Estimated Volume of Oil In Place (bbls) 14~ ~ - ïo,ooo 1~ 30,000 18 40,000 3~,000 The desired steam distribution is then determined by lS dividing the estimated sector oil in place by the total estimated volume of oil in place within the entire area 12 which gives a desired steam distribution to each ~ector as a percentage of total injected steam as s~own in the following Table II.
T,able II
Sector _ Desired Steam Distribution 16 26%
18 35%
~0 30%
Assuming a steam injection ra~e of 1500 B/D ~barrels per day), cold water equivalent, and initially a~suming that the total volume of fluid produced is equal to the cold water equivalent volume of steam injected, the desired production of fluid from each of the producer wells A, B, C and D would be as .qhown on the following Table III.
Table III
Sector Well I Desired Production, B/D
14 - A ¦ 1500 x 0.09 - 135 16 B î 1500 x 0.26 = 390 18 C 1 1500 x 0.30 = 450 D 1 1500 x 0.35 = 525 Total - ~ = 1500 The usual ~ituation in a steam flood operation, however, is that the rate of total fluid production from all of the producing well3 exceeds the rate at which steam is being injected into the injection well. This is because formation fluids are di~placed by 3team vapor, at least some of which remains in a vapor phase, and this steam vapor displaces a volume of formation fluids much greater than its cold water equiva~ent volume. I~ ~uch a situation the observed total production should also be distributed in proportion to the desired steam di6~ribution percentages. Assuming a total production of 2000 B/D from produciny wells A, B, C and D, the desired production for each well is as shown in the following Table IV~ These fluids will generally include oil, some formation water~ and 30me condensed steam.
Table IV
25 Sector _ Well ¦ Desired Production, B/D
14 A ¦ 2000 x 0.09 = 180 16 B ¦ 2000 x 0.26 = 520 18 C 1 2000 x 0.30 = ~00 D ¦ 2000 x 0.35 = 700 Total = 2000 These proportional volumes of fluid being produced from each of the wells will generally correspond to the propor-tional amount of injected steam which i5 moving into the sector as~ociated with eac~ well and displacing the produced fluids from those sectors.
This techni~ue just describe~ of determining the rela-tive portion o,- steam flowing to each of the producing wells _9_ ~
A, B~ C and D can be more generally de~cribed a~ determining a relative injection fluid portion of a total volume of injection fluid being injected into the area 12 at injection well E which is flowing toward each of the producing wells A, B, C and D.
W~en a well such as well D, for example, is determined to be producing significantly les~ than its desired portion of the total produced fluid, one or more of the other wells A, B or C will obviously be producing more than its desired portion of the total produced fluid. Thus, to correct an undesirable steam distribution pattern, a production capabi-lity of at least one of the producinq wells A, B, C or D
must be modified. One or more of those producing wells A, B, C or D which is producing less than its desired portion of the total produc~d fluid will be pumped down and/or sti-mulated to increase its production and/o~ one or more of the wells which are producing more than their desired portion of the total produced fluid will have their fluid production restrictedO Such modifying actions will cause the steam distribu~ion within the pattern to change to more closely approximate ~he desired ~team di~tribu~ion.
- It will be appr~ciated upon reviewing the more detailed explanation of the preferred stimulation and restriction techniques di~cu~sed below, that these techniques do not provide preci~e control of the steam dist~ibution. It often will not be po sible to 80 modify the ~team distribution as to have it exactly approximate the previously determined degired 8 eam distribution. Nevertheless~ the techniques de~cribed below will generally cause the steam distribution to more closely approximate the predetermined desired steam distribution and will thereby increa~e the overall effi-ciency of steam flooding of the area 12 to increase the total volume of oil recovered from all of the producing wells A, B, C and D as compared to the ~otal volume of oil which would be recovered in the ab~ence of modifying the production capabilities of at least one of the producinq well~.
~r~ tl~n ~ d~
For producing wells located in sectors that are receiving more than the desired portion of in~ected steamt production modification is relatively easy. In the first instance, fluid production from a well such as well D seen in FIG. 2 is restricted by increasing the production fluid level within the well. Thi5 i3 accomplished by reducing the pumping rate of downhole pump 22 which is operated by a con-ventional string of sucker rods 23 extending through a stuffing box 25. If the back pres~ure exerted upon the for-mation 10 by a full column of fluid within producing well D
does not reduce the steam flow to producing well D ~o the desired level, then production is choked by partially closing a valve 24 in wellhead production line 26. If necesqary, the valve 24 can be completely closed to shut in the well D and completely stop production therefrom.
If the portion o~ inj~cted ~team flowing toward well D
~8 lower than the pref~rred proportion thereof, the first approach to increa~ing flow toward well D is to pump down the level of fluid within well D as low as possible to create a pressure ~ink within the formation 10 adjacent the well D. Quite often, howevert ~imply pumping down the fluid l.evel in the non-responding well iq no~ sufficient to draw the desired portion of steam toward that well.
A particularly useful technique has been developed for stimulating a non-re~ponding producing well to increase the proportional flow of injection steam toward that well. This technique involves the initial notching of the well, sub-sequently performing a small unpropped frac job at the notch, and then perorating the well over the entire depth of formation 10. Later, if necessary, a propped frac job can be performed to stimulate production from the well.
This technique can be better understood after the well structure illu~trated in FIG. 2 is further described.
~ 35 The producing well D is defined by a casing 28 which i9 cemented within a borehole 30 by cement material 32.
The well D intersects the subsurface oil bearing for mation 10 which is definea by upper and lower boundaries 34 and 36.
Prior to beginning the steam flood operation, an annular notch 37 is created which ex~ends through casing 28 and the cement material 32 into the formation 10. Notch 37 pre-ferably i~ located at appro~imately a middle elevation of the formation 10. The notch 37 can be created in two ways.
The first method of creating notch 37, which is illustrated in FIG. 2, comprises cutting a win~ow 38 through the casing 28 and cement material 32.
The window 38 is preferably approximately three inches in heigh~, and its necessary height is determined by the potential thermal expansion of casing 28. The window 38 should be sufficiently wide that it cannot be closed by sub-~equent thermal expansion of the casing 28.
The window can be cut ~ith a rotatable hydraulic jetting tool which i8 lowered into the well on a string o tubing.
Such a tool prefer~bly i~ rotated at an angular velocity of approximately five revolu~ions per minu~e while pumping gelled brine containing 1.0 pounas per gallon of 20-40 mesh sand at a rate of approximately ive barrels per minute.
Thi9 process is repeàted three additional times, raising the tubin~ 3/4 inch between cut3. Thus, four 3/4-inch cuts create a three-inch wide window.
A second manner of creating the notch 37 is by high den-sity perforation techniques. Preferably, an interval of 12 to 18 inches of casing 28 is perforated with a very high perforation den~ity. Although this does not actually sever the ca~ing 28, it will cause a ~ubsequent frac job to occur at the location of the hi~h den~ity perforations, and it will aid in obtaining a horizon~al fracture orientation.
The term "notch" i3 u~ed in this application to refer g~nerally to any technique, such a~ the two just described, which will serve to initiate a horizontal fracture extending ~ radially from a predetermined location on the casing.
-12~ 8 Once the notch 37 i~ created in the well D, by either of the tWQ described techniqu~, a small unpropped fracture 40 is initiated by p~nping from 20 to 200 barrels of fracturing fluid (brine) through the notch 37 into the formation 10.
Preferably, about 100 barrel~ of fracturing fluid are used.
Then, fracturing fluid pressure is released allowing the relatively small unpropped fracture 40 to close as shown in FIG. 2.
Finally, after creating notch 37 and the unpropped frac-ture 40, the entire depth of formation 10 is perforated asindicatad by perforations 42 to facilitate draining of the entire formation 10.
The purpose of this notching and initiation of the small unpropped fracture 40 is to predetermine the location of ~
possible subsequent propped fracture which may be necessary to stimulate the well.
By the technique of notching and fracturing before per-forating, the location of any subsequent propped fracture is predetermined, and also the fracture i8 a~ least initiated as a substantially horizontal fracture which is the pre-ferred type of fracture for stimulation of the well.
By allowing the fracture to close back up as shown in FIG. 2t the initial flow of injected steam to well D from injection well E will not be affected.
Then the producing well D is completed with production tubing 44 which receives pump 22 previously mentioned.
Injection well E is ~imilarly constructed from a casing 48, borehole 50 and cement 52.
The well E i8 notched at 54 near the lower boundary 36 of formation 10, and i~ hydraulically fractured and propped to create a large propped fracture 56. Then the well E is perforated as indicated at 58 ~hroughout ~he entire depth of formation 10.
Steam injection tubing 60 i5 then located within the well and sealed off above formation 1~ by packer 62.
~ steam supply line 64 provides ~tea~n to the well E from a conventional source of steam supply.
-13- ~
Preferably, steam is injected into formation 10 at a pressure less than ~he frac pressure of injection well E, so that the fracture 56 will not open ~urther and allow disrup-tion of the proppant material contained therein.
In a steam injection pattern like that illustrated in FIG. 1, each of the producing wells A, B, C and D that has not previously been fractured i~ preferably prepared by notching and creating an initial unpropped fracture as shown on well D in FIG. 2. It will be appreciated, however, that if certain ones of the producing wells A, B, C and D have previously been fractured during primary or ~econdary recov-ery techniques, it will not be possible to control a sub-sequent fracturing job in the manner described with regard to well D. This i because those wells which have pre-viously been fractured would refracture at the location of their initial fractures if an attempt was later made to fracture them again.
Thus, the technique described with reference to well D
is generally concerned only with wells that have been newly drilled for purpo3es of the steam flood project, or which in any event have not previously been fractured.
After the steam injection project has begun, and the initial steam di~tribution i~ determined in the manner described previou~ly, well D can be ~timulated if it is not receiving its desired portion of injected steam by hydrauli-cally fracturing well D to extend the relatively small unpropped fracture 40 to ~reate a larger fracture 66 extending further into the formation as indicated in phantom lines in FIGo 2J and by concurrenkly propping the fracture 66 with a proppant material to create a larger propped frac-ture~
This will t~en stimulate produc~ion from the well D and generally will draw more of the injected steam toward well D
so that more of the oil in place in sector 20 as~ociated with well D will be heated and caused to be produced.
~ By combining the various techniques discussed above to cause the d's-tribution of ;njected steam within the area 12 to more closely approximate the preferred ~team distribution which should be proportional to the relative volumes of oil in place within the various ~ectors 14, 16, 18 and 20, the total oil produced during the steam injection project will be increased as comparea to what it would otherwise be in the absence of the production modification techniques of increasing production from non-responding wells, and decreasing or shutting down production from overly actively responding wells a~ the case ~ay be.
0 ThU8 it is seen that the methods of the present inven-tion readily achieve the ends and advantages mentioned as well as those inherent therein. While certain preferred embodiment~ of the invention have been illustrated and described above in detail for the purposes of the present disclo~ure, numerous changes in the arrangement and make-up of the various ~tep~ may be made by tho~e skilled in the art, which changes are encompassed with~n the scope and spirit of the presen~ invention a~ defined by the appended claims.
What is claimed i~:
FIG. 2 is a somewhat schematic sectioned elevation view taken along line 2-2 showing the injection well and one of the producing wells along with the various associated sub-surface strata.
Detailed Dascription Of The Preferred Embodiments In a typical enhanced oil recovery project utilizin~
injected steam to heat and move vi3cous oil deposits to pro-ducing wells, a pattern of wells is generally utilized having a plurality of producing wells surrounding one or more injection wells.
FIG. 1 illustrate~ what i9 commonly referred to as an inverted five spot pattern having four producing wells A, B, C and D which are located a the four corners of a s~uare, with a single injection well ~ l~cated in the center of the square.
FIG. 2, which is a somewhat :chema~ic elevation section view taken along line 2~2 of FIG. 1 shows the producing well D on the left and the injection w~:ll E on the right.
Each of the wells A, B, C, D and E intersects an underground oil bearing formation 10. The purpose of the injection well E is to inject steam or in some instances other fluids into the formation 10 and to cause oil con-tained wi~hin formation 10 to move toward and be produced from the producing wells such as D.
In FIG. 1, an imaginary area of formation 10 in a square shape defined a~ it~ corner~ by the ~our producing wells A-D
i9 shown in phantom lines and designated by the numeral 12.
Furtherg phantom lines divide ~he area 12 into a plurality of sectors 14, 16, 18 and 20 associated with the producing wells A, B~ C and D, respectively~ Each of the sectors 14, - 16, 18 and 20 is associa~ed with one of the producing wells and defines a portion of the ar~a 12 of formation 10 to be drained by it~ a~sociated producing well.
As will be understood by those skilled in the art, steam flow from injection well E is not totally confined to area 12. Generally, however, the flow of steam is confined within area 12 by a combination of natural barriers which may exist and~or injection of back-up water into surrounding wells to prevent any significant flow of steam outside of area 12.
Determining The Preferred Steam Distribution A particular problem to which the present invention is directed is that of poor distribution of steam within the pattern represented in FIG. 1. Such problems are par-ticularly acute when, as i~ often the case, there have beenwater flood secondary recovery operations performed prior to ~he steam flood operations.
Due to such prior water flood operations and/or natural non-homogenous conditions occurring within the formation 10, the ~team injected into well E will generally follow chan-nel~ through the formation 10 which provide the least re~istance to ~team 1OW. Generally these channels will be through depleted zones and will avoid zones of high oil ~aturation where in fact it is most desired to direct the steam.
Furthermore, even if the properties of reservoir 10 are 3uch that steam does flow evenly into the four sectors 14, 16, 18 and 20, that still may not be the most effective distribution of team to achieve the maximum oil recovery.
It has been determined that the most efficient use of ~team in a steam injection process is accomplished if ~he steam i9 distributed throughout the various sector~ 14, 16, 18 and 20 of area 12 of formation 10 in the ~ame porpor~ion~
as oil is present within those sectors. This is preferable to an uncontrolled distribution, to an even distribution within the ~ectors when oil i~ not evenly distributed, and to a steam distribution based on reservoir pore volume di~tribution.
The preference for distributing steam based on the volume of oil in place as opposed to the reservoir pore volume can be illustrated with a ~imple thought experiment.
Consider two blocks of rock of equal pore volume connected to a common steam injection well. For the first case, let both blocks of rock have the same oil saturation so that they contain equal volume~ of oil (hydrocarbon pore volumes). In this case, it would be desirable for both blocks to receive equal ~uantities of steam. This satisfies the distribution based on reservoir pore volume as well as one based on hydrocarbon pore volume. In the second case, let one blocX contain recoverable hydrocarbons and the other be devoid of any oil. In thi~ case, it would be desirable to direct all of the steam to the block containing the hydrocarbons. This satisies a desired qteam distribution based vnly on hydrocarbon pore volume. A diRtribution based on reservoir pore volume would in the second case allow steam to move into the blocX where no oil exists and would be a waste of the investment in the steam. Consequently, when variations in oil ~aturation might exist, as is often the case in a previously water flooded formation, the desired steam distribution should be based on the distribu-tion of hydrocarbon within the steam flood pattern.
Thus, the fir~t step in determining the desired relativeproportions oX ~team distribution within the ~ectors 14, 16, 18 and 20, is to determine the estimated volume of oil in place within each sector; which can be accomplished by con-ventional reservoir analyses and engineering calculations.This is then converted to a desired steam distribution as shown by the following example.
E~ mple Con~ider an inverted five ~pot pa~tern a~ illustrated in FIG. 1 with available information obtained from reservoir analyses and engineering calculations showing ~he respective estima~ed volume~ of oil in place within ~he sectors 14, 16, 18 and 20 as shown on the foll~wing Tabl~ I.
Table I
10Sector Estimated Volume of Oil In Place (bbls) 14~ ~ - ïo,ooo 1~ 30,000 18 40,000 3~,000 The desired steam distribution is then determined by lS dividing the estimated sector oil in place by the total estimated volume of oil in place within the entire area 12 which gives a desired steam distribution to each ~ector as a percentage of total injected steam as s~own in the following Table II.
T,able II
Sector _ Desired Steam Distribution 16 26%
18 35%
~0 30%
Assuming a steam injection ra~e of 1500 B/D ~barrels per day), cold water equivalent, and initially a~suming that the total volume of fluid produced is equal to the cold water equivalent volume of steam injected, the desired production of fluid from each of the producer wells A, B, C and D would be as .qhown on the following Table III.
Table III
Sector Well I Desired Production, B/D
14 - A ¦ 1500 x 0.09 - 135 16 B î 1500 x 0.26 = 390 18 C 1 1500 x 0.30 = 450 D 1 1500 x 0.35 = 525 Total - ~ = 1500 The usual ~ituation in a steam flood operation, however, is that the rate of total fluid production from all of the producing well3 exceeds the rate at which steam is being injected into the injection well. This is because formation fluids are di~placed by 3team vapor, at least some of which remains in a vapor phase, and this steam vapor displaces a volume of formation fluids much greater than its cold water equiva~ent volume. I~ ~uch a situation the observed total production should also be distributed in proportion to the desired steam di6~ribution percentages. Assuming a total production of 2000 B/D from produciny wells A, B, C and D, the desired production for each well is as shown in the following Table IV~ These fluids will generally include oil, some formation water~ and 30me condensed steam.
Table IV
25 Sector _ Well ¦ Desired Production, B/D
14 A ¦ 2000 x 0.09 = 180 16 B ¦ 2000 x 0.26 = 520 18 C 1 2000 x 0.30 = ~00 D ¦ 2000 x 0.35 = 700 Total = 2000 These proportional volumes of fluid being produced from each of the wells will generally correspond to the propor-tional amount of injected steam which i5 moving into the sector as~ociated with eac~ well and displacing the produced fluids from those sectors.
This techni~ue just describe~ of determining the rela-tive portion o,- steam flowing to each of the producing wells _9_ ~
A, B~ C and D can be more generally de~cribed a~ determining a relative injection fluid portion of a total volume of injection fluid being injected into the area 12 at injection well E which is flowing toward each of the producing wells A, B, C and D.
W~en a well such as well D, for example, is determined to be producing significantly les~ than its desired portion of the total produced fluid, one or more of the other wells A, B or C will obviously be producing more than its desired portion of the total produced fluid. Thus, to correct an undesirable steam distribution pattern, a production capabi-lity of at least one of the producinq wells A, B, C or D
must be modified. One or more of those producing wells A, B, C or D which is producing less than its desired portion of the total produc~d fluid will be pumped down and/or sti-mulated to increase its production and/o~ one or more of the wells which are producing more than their desired portion of the total produced fluid will have their fluid production restrictedO Such modifying actions will cause the steam distribu~ion within the pattern to change to more closely approximate ~he desired ~team di~tribu~ion.
- It will be appr~ciated upon reviewing the more detailed explanation of the preferred stimulation and restriction techniques di~cu~sed below, that these techniques do not provide preci~e control of the steam dist~ibution. It often will not be po sible to 80 modify the ~team distribution as to have it exactly approximate the previously determined degired 8 eam distribution. Nevertheless~ the techniques de~cribed below will generally cause the steam distribution to more closely approximate the predetermined desired steam distribution and will thereby increa~e the overall effi-ciency of steam flooding of the area 12 to increase the total volume of oil recovered from all of the producing wells A, B, C and D as compared to the ~otal volume of oil which would be recovered in the ab~ence of modifying the production capabilities of at least one of the producinq well~.
~r~ tl~n ~ d~
For producing wells located in sectors that are receiving more than the desired portion of in~ected steamt production modification is relatively easy. In the first instance, fluid production from a well such as well D seen in FIG. 2 is restricted by increasing the production fluid level within the well. Thi5 i3 accomplished by reducing the pumping rate of downhole pump 22 which is operated by a con-ventional string of sucker rods 23 extending through a stuffing box 25. If the back pres~ure exerted upon the for-mation 10 by a full column of fluid within producing well D
does not reduce the steam flow to producing well D ~o the desired level, then production is choked by partially closing a valve 24 in wellhead production line 26. If necesqary, the valve 24 can be completely closed to shut in the well D and completely stop production therefrom.
If the portion o~ inj~cted ~team flowing toward well D
~8 lower than the pref~rred proportion thereof, the first approach to increa~ing flow toward well D is to pump down the level of fluid within well D as low as possible to create a pressure ~ink within the formation 10 adjacent the well D. Quite often, howevert ~imply pumping down the fluid l.evel in the non-responding well iq no~ sufficient to draw the desired portion of steam toward that well.
A particularly useful technique has been developed for stimulating a non-re~ponding producing well to increase the proportional flow of injection steam toward that well. This technique involves the initial notching of the well, sub-sequently performing a small unpropped frac job at the notch, and then perorating the well over the entire depth of formation 10. Later, if necessary, a propped frac job can be performed to stimulate production from the well.
This technique can be better understood after the well structure illu~trated in FIG. 2 is further described.
~ 35 The producing well D is defined by a casing 28 which i9 cemented within a borehole 30 by cement material 32.
The well D intersects the subsurface oil bearing for mation 10 which is definea by upper and lower boundaries 34 and 36.
Prior to beginning the steam flood operation, an annular notch 37 is created which ex~ends through casing 28 and the cement material 32 into the formation 10. Notch 37 pre-ferably i~ located at appro~imately a middle elevation of the formation 10. The notch 37 can be created in two ways.
The first method of creating notch 37, which is illustrated in FIG. 2, comprises cutting a win~ow 38 through the casing 28 and cement material 32.
The window 38 is preferably approximately three inches in heigh~, and its necessary height is determined by the potential thermal expansion of casing 28. The window 38 should be sufficiently wide that it cannot be closed by sub-~equent thermal expansion of the casing 28.
The window can be cut ~ith a rotatable hydraulic jetting tool which i8 lowered into the well on a string o tubing.
Such a tool prefer~bly i~ rotated at an angular velocity of approximately five revolu~ions per minu~e while pumping gelled brine containing 1.0 pounas per gallon of 20-40 mesh sand at a rate of approximately ive barrels per minute.
Thi9 process is repeàted three additional times, raising the tubin~ 3/4 inch between cut3. Thus, four 3/4-inch cuts create a three-inch wide window.
A second manner of creating the notch 37 is by high den-sity perforation techniques. Preferably, an interval of 12 to 18 inches of casing 28 is perforated with a very high perforation den~ity. Although this does not actually sever the ca~ing 28, it will cause a ~ubsequent frac job to occur at the location of the hi~h den~ity perforations, and it will aid in obtaining a horizon~al fracture orientation.
The term "notch" i3 u~ed in this application to refer g~nerally to any technique, such a~ the two just described, which will serve to initiate a horizontal fracture extending ~ radially from a predetermined location on the casing.
-12~ 8 Once the notch 37 i~ created in the well D, by either of the tWQ described techniqu~, a small unpropped fracture 40 is initiated by p~nping from 20 to 200 barrels of fracturing fluid (brine) through the notch 37 into the formation 10.
Preferably, about 100 barrel~ of fracturing fluid are used.
Then, fracturing fluid pressure is released allowing the relatively small unpropped fracture 40 to close as shown in FIG. 2.
Finally, after creating notch 37 and the unpropped frac-ture 40, the entire depth of formation 10 is perforated asindicatad by perforations 42 to facilitate draining of the entire formation 10.
The purpose of this notching and initiation of the small unpropped fracture 40 is to predetermine the location of ~
possible subsequent propped fracture which may be necessary to stimulate the well.
By the technique of notching and fracturing before per-forating, the location of any subsequent propped fracture is predetermined, and also the fracture i8 a~ least initiated as a substantially horizontal fracture which is the pre-ferred type of fracture for stimulation of the well.
By allowing the fracture to close back up as shown in FIG. 2t the initial flow of injected steam to well D from injection well E will not be affected.
Then the producing well D is completed with production tubing 44 which receives pump 22 previously mentioned.
Injection well E is ~imilarly constructed from a casing 48, borehole 50 and cement 52.
The well E i8 notched at 54 near the lower boundary 36 of formation 10, and i~ hydraulically fractured and propped to create a large propped fracture 56. Then the well E is perforated as indicated at 58 ~hroughout ~he entire depth of formation 10.
Steam injection tubing 60 i5 then located within the well and sealed off above formation 1~ by packer 62.
~ steam supply line 64 provides ~tea~n to the well E from a conventional source of steam supply.
-13- ~
Preferably, steam is injected into formation 10 at a pressure less than ~he frac pressure of injection well E, so that the fracture 56 will not open ~urther and allow disrup-tion of the proppant material contained therein.
In a steam injection pattern like that illustrated in FIG. 1, each of the producing wells A, B, C and D that has not previously been fractured i~ preferably prepared by notching and creating an initial unpropped fracture as shown on well D in FIG. 2. It will be appreciated, however, that if certain ones of the producing wells A, B, C and D have previously been fractured during primary or ~econdary recov-ery techniques, it will not be possible to control a sub-sequent fracturing job in the manner described with regard to well D. This i because those wells which have pre-viously been fractured would refracture at the location of their initial fractures if an attempt was later made to fracture them again.
Thus, the technique described with reference to well D
is generally concerned only with wells that have been newly drilled for purpo3es of the steam flood project, or which in any event have not previously been fractured.
After the steam injection project has begun, and the initial steam di~tribution i~ determined in the manner described previou~ly, well D can be ~timulated if it is not receiving its desired portion of injected steam by hydrauli-cally fracturing well D to extend the relatively small unpropped fracture 40 to ~reate a larger fracture 66 extending further into the formation as indicated in phantom lines in FIGo 2J and by concurrenkly propping the fracture 66 with a proppant material to create a larger propped frac-ture~
This will t~en stimulate produc~ion from the well D and generally will draw more of the injected steam toward well D
so that more of the oil in place in sector 20 as~ociated with well D will be heated and caused to be produced.
~ By combining the various techniques discussed above to cause the d's-tribution of ;njected steam within the area 12 to more closely approximate the preferred ~team distribution which should be proportional to the relative volumes of oil in place within the various ~ectors 14, 16, 18 and 20, the total oil produced during the steam injection project will be increased as comparea to what it would otherwise be in the absence of the production modification techniques of increasing production from non-responding wells, and decreasing or shutting down production from overly actively responding wells a~ the case ~ay be.
0 ThU8 it is seen that the methods of the present inven-tion readily achieve the ends and advantages mentioned as well as those inherent therein. While certain preferred embodiment~ of the invention have been illustrated and described above in detail for the purposes of the present disclo~ure, numerous changes in the arrangement and make-up of the various ~tep~ may be made by tho~e skilled in the art, which changes are encompassed with~n the scope and spirit of the presen~ invention a~ defined by the appended claims.
What is claimed i~:
Claims (17)
1. An enhanced oil recovery method comprising steps of:
(a) providing a pattern of wells, including at least one injection well intersecting an underground oil bearing formation for injecting an injection fluid into an area of said formation surrounding said injection well, and including a plurality of producing wells intersecting said area of said formation for producing oil and other fluids from a plurality of sectors of said area, each of said sec-tors being associated with one of said producing wells and defining a portion of said area to be drained by its asso-ciated producing well;
(b) determining an estimated volume of oil in place in each of said sectors, and thus determining a relative oil portion of a total area oil volume which is in place in each of said sectors;
(c) injecting injection fluid into said formation through said injection well;
(d) determining a relative injection fluid portion of the total amount of injection fluid being injected into said area which is flowing toward each of said producing wells:
(e) then modifying a production capability of at least one of said producing wells and thus changing the relative injection fluid portion of at least two of said producing wells to more closely approximate the relative oil portions of the sectors associated with said at least two producing wells; and (f) thereby increasing a total volume of oil reco-vered as compared to the total volume of oil which would have been recovered in the absence of step (e).
(a) providing a pattern of wells, including at least one injection well intersecting an underground oil bearing formation for injecting an injection fluid into an area of said formation surrounding said injection well, and including a plurality of producing wells intersecting said area of said formation for producing oil and other fluids from a plurality of sectors of said area, each of said sec-tors being associated with one of said producing wells and defining a portion of said area to be drained by its asso-ciated producing well;
(b) determining an estimated volume of oil in place in each of said sectors, and thus determining a relative oil portion of a total area oil volume which is in place in each of said sectors;
(c) injecting injection fluid into said formation through said injection well;
(d) determining a relative injection fluid portion of the total amount of injection fluid being injected into said area which is flowing toward each of said producing wells:
(e) then modifying a production capability of at least one of said producing wells and thus changing the relative injection fluid portion of at least two of said producing wells to more closely approximate the relative oil portions of the sectors associated with said at least two producing wells; and (f) thereby increasing a total volume of oil reco-vered as compared to the total volume of oil which would have been recovered in the absence of step (e).
2. The method of claim 1, wherein:
said step (e) is further characterized in that sub-sequent to said modifying step, the relative injection fluid portion of each of said plurality of producing wells approximates the relative oil portion of the sector asso-ciated therewith.
said step (e) is further characterized in that sub-sequent to said modifying step, the relative injection fluid portion of each of said plurality of producing wells approximates the relative oil portion of the sector asso-ciated therewith.
3. The method of claim 1, wherein:
said step (e) is further characterized in that said modifying step includes a step of restricting fluid produc-tion from said at least one producing well.
said step (e) is further characterized in that said modifying step includes a step of restricting fluid produc-tion from said at least one producing well.
4. The method of claim 3, wherein:
said step (e) is further characterized in that fluid production is restricted from said at least one pro-ducing well by increasing a fluid level within said at least one producing well.
said step (e) is further characterized in that fluid production is restricted from said at least one pro-ducing well by increasing a fluid level within said at least one producing well.
5. The method of claim 4, wherein:
said step (e) is further characterized in that fluid production from said at least one producing well is restricted by choking a production fluid outlet from said at least one producing well.
said step (e) is further characterized in that fluid production from said at least one producing well is restricted by choking a production fluid outlet from said at least one producing well.
6. The method of claim 1, wherein:
said step (e) is further characterized in that fluid production from said at least one producing well is increased by pumping down a fluid level within said at least one producing well to create a pressure sink within said formation adjacent said at least one producing well.
said step (e) is further characterized in that fluid production from said at least one producing well is increased by pumping down a fluid level within said at least one producing well to create a pressure sink within said formation adjacent said at least one producing well.
7. The method of claim 1, wherein:
said step (e) is further characterized in that said modifying step includes a step of stimulating said at least one producing well to increase fluid production therefrom.
said step (e) is further characterized in that said modifying step includes a step of stimulating said at least one producing well to increase fluid production therefrom.
8. The method of claim 7, wherein:
said step of stimulating said at least one pro-ducing well is further characterized as inducing a fracture from said at least one producing well into said formation and propping said fracture with a proppant material thus creating a propped fracture.
said step of stimulating said at least one pro-ducing well is further characterized as inducing a fracture from said at least one producing well into said formation and propping said fracture with a proppant material thus creating a propped fracture.
9. The method of claim 8, further comprising the steps of:
prior to step (c):
creating an annular notch extending from said at least one producing well into said formation;
initiating a relatively small unpropped frac-ture from said notch into said formation;
releasing fracturing fluid pressure and allowing said relatively small unpropped fracture to close; and then perforating said at least one producing well over the entire depth of said formation;
so that a location of the propped fracture created in step (e) is predetermined by the location of said notch without influencing an initial relative injection fluid por-tion directed to said at least one producing well while still accomplishing draining of the entire depth of said formation.
prior to step (c):
creating an annular notch extending from said at least one producing well into said formation;
initiating a relatively small unpropped frac-ture from said notch into said formation;
releasing fracturing fluid pressure and allowing said relatively small unpropped fracture to close; and then perforating said at least one producing well over the entire depth of said formation;
so that a location of the propped fracture created in step (e) is predetermined by the location of said notch without influencing an initial relative injection fluid por-tion directed to said at least one producing well while still accomplishing draining of the entire depth of said formation.
10. The method of claim 9, wherein:
said initiating step is further characterized in that an amount of fracturing fluid forced into said relati-vely small unpropped fracture is in the range of 20 to 200 barrels.
said initiating step is further characterized in that an amount of fracturing fluid forced into said relati-vely small unpropped fracture is in the range of 20 to 200 barrels.
11. The method of claim 10, wherein said amount of fracturing fluid is approximately 100 barrels.
12. The method of claim 1, wherein said injection fluid is steam.
13. The method of claim 1, wherein:
step (d) includes a step of determining a relative portion of total produced fluid, produced from all of said producing wells, which is being produced by each of said producing wells.
step (d) includes a step of determining a relative portion of total produced fluid, produced from all of said producing wells, which is being produced by each of said producing wells.
14. An enhanced oil recovery method comprising steps of:
(a) providing a pattern of wells, including at least one injection well intersecting an underground oil bearing formation for injecting an injection fluid into an area of said formation surrounding said injection well, and including a plurality of producing wells intersecting said area of said formation for producing oil and other fluids from said area;
(b) creating an annular notch extending from at least one of said producing wells into said formation;
(c) initiating a relatively small unpropped frac-ture from said notch into said formation;
(d) releasing fracturing fluid pressure and allowing said relatively small unpropped fracture to close;
(e) perforating said at least one producing well over the entire depth of said formation;
(f) whereby a location of a potential subsequent propped fracture is predetermined by the location of said notch without initially influencing any tendency of said injection fluid to flow from said injection well to said at least one producing well, while still accomplishing draining of the entire depth of said formation;
(g) injecting injection fluid into said formation through said injection well;
(h) determining an extent to which said at least one producing well is initially responding to the injecting of injection fluid into the formation;
(i) then stimulating production from said at least one producing well by hydraulically fracturing said at least one producing well to extend said relatively small unpropped fracture and propping the same with a proppant material to create a larger propped fracture extending further into said formation; and (j) thereby increasing a flow of injection fluid from said injection well to said at least one producing well and increasing a production rate of oil from said at least one producing well.
(a) providing a pattern of wells, including at least one injection well intersecting an underground oil bearing formation for injecting an injection fluid into an area of said formation surrounding said injection well, and including a plurality of producing wells intersecting said area of said formation for producing oil and other fluids from said area;
(b) creating an annular notch extending from at least one of said producing wells into said formation;
(c) initiating a relatively small unpropped frac-ture from said notch into said formation;
(d) releasing fracturing fluid pressure and allowing said relatively small unpropped fracture to close;
(e) perforating said at least one producing well over the entire depth of said formation;
(f) whereby a location of a potential subsequent propped fracture is predetermined by the location of said notch without initially influencing any tendency of said injection fluid to flow from said injection well to said at least one producing well, while still accomplishing draining of the entire depth of said formation;
(g) injecting injection fluid into said formation through said injection well;
(h) determining an extent to which said at least one producing well is initially responding to the injecting of injection fluid into the formation;
(i) then stimulating production from said at least one producing well by hydraulically fracturing said at least one producing well to extend said relatively small unpropped fracture and propping the same with a proppant material to create a larger propped fracture extending further into said formation; and (j) thereby increasing a flow of injection fluid from said injection well to said at least one producing well and increasing a production rate of oil from said at least one producing well.
15. The method of claim 14, wherein:
said initiating step is further characterized in that an amount of fracturing fluid forced into said rela-tively small unpropped fracture is in the range of 20 to 200 barrels.
said initiating step is further characterized in that an amount of fracturing fluid forced into said rela-tively small unpropped fracture is in the range of 20 to 200 barrels.
16. The method of claim 15, wherein said amount of fracturing fluid is approximately 100 barrels.
17. The method of claim 13, wherein said injection fluid is steam.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US735,795 | 1985-05-17 | ||
| US06/735,795 US4641709A (en) | 1985-05-17 | 1985-05-17 | Controlling steam distribution |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1246998A true CA1246998A (en) | 1988-12-20 |
Family
ID=24957211
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000507230A Expired CA1246998A (en) | 1985-05-17 | 1986-04-22 | Controlling steam distribution |
Country Status (2)
| Country | Link |
|---|---|
| US (1) | US4641709A (en) |
| CA (1) | CA1246998A (en) |
Families Citing this family (7)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4754808A (en) * | 1986-06-20 | 1988-07-05 | Conoco Inc. | Methods for obtaining well-to-well flow communication |
| US5246071A (en) * | 1992-01-31 | 1993-09-21 | Texaco Inc. | Steamflooding with alternating injection and production cycles |
| ATE531895T1 (en) * | 2005-02-04 | 2011-11-15 | Oxane Materials Inc | COMPOSITION AND METHOD FOR PRODUCING A SUPPORTANT |
| US7867613B2 (en) * | 2005-02-04 | 2011-01-11 | Oxane Materials, Inc. | Composition and method for making a proppant |
| US8012533B2 (en) * | 2005-02-04 | 2011-09-06 | Oxane Materials, Inc. | Composition and method for making a proppant |
| US7491444B2 (en) * | 2005-02-04 | 2009-02-17 | Oxane Materials, Inc. | Composition and method for making a proppant |
| MX2012007248A (en) * | 2009-12-22 | 2012-07-30 | Oxane Materials Inc | A proppant having a glass-ceramic material. |
Family Cites Families (19)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US2352834A (en) * | 1942-05-09 | 1944-07-04 | Shell Dev | Method of and means for adjusting flow rates of fluids through formations traversed by boreholes |
| US2390770A (en) * | 1942-10-10 | 1945-12-11 | Sun Oil Co | Method of producing petroleum |
| US3199587A (en) * | 1962-09-10 | 1965-08-10 | Phillips Petroleum Co | Recovery of oil by improved fluid drive |
| US3129761A (en) * | 1963-01-23 | 1964-04-21 | Dow Chemical Co | Method of establishing communication between wells |
| US3333633A (en) * | 1964-03-16 | 1967-08-01 | Esso Production Company | Method for injecting fluids in secondary recovery |
| US3346048A (en) * | 1964-12-17 | 1967-10-10 | Mobil Oil Corp | Thermal recovery method for oil sands |
| US3434541A (en) * | 1967-10-11 | 1969-03-25 | Mobil Oil Corp | In situ combustion process |
| US3515212A (en) * | 1968-09-20 | 1970-06-02 | Texaco Inc | Oil recovery by steam stimulation and in situ combustion |
| US3565173A (en) * | 1969-09-17 | 1971-02-23 | Mobil Oil Corp | Methods of selectively improving the fluid communication of earth formations |
| US3682244A (en) * | 1971-03-05 | 1972-08-08 | Shell Oil Co | Control of a steam zone |
| US3771598A (en) * | 1972-05-19 | 1973-11-13 | Tennco Oil Co | Method of secondary recovery of hydrocarbons |
| US3848671A (en) * | 1973-10-24 | 1974-11-19 | Atlantic Richfield Co | Method of producing bitumen from a subterranean tar sand formation |
| US3905422A (en) * | 1974-09-23 | 1975-09-16 | Texaco Inc | Method for recovering viscous petroleum |
| US3999606A (en) * | 1975-10-06 | 1976-12-28 | Cities Service Company | Oil recovery rate by throttling production wells during combustion drive |
| US4071458A (en) * | 1975-12-29 | 1978-01-31 | Texaco Inc. | Oil displacement fluid containing a solubilizing agent |
| US4129182A (en) * | 1977-02-28 | 1978-12-12 | Standard Oil Company (Indiana) | Miscible drive in heterogeneous reservoirs |
| US4168746A (en) * | 1978-03-02 | 1979-09-25 | Continental Oil Company | Single well surfactant test to evaluate surfactant floods using multi tracer method |
| US4182416A (en) * | 1978-03-27 | 1980-01-08 | Phillips Petroleum Company | Induced oil recovery process |
| US4265310A (en) * | 1978-10-03 | 1981-05-05 | Continental Oil Company | Fracture preheat oil recovery process |
-
1985
- 1985-05-17 US US06/735,795 patent/US4641709A/en not_active Expired - Fee Related
-
1986
- 1986-04-22 CA CA000507230A patent/CA1246998A/en not_active Expired
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| US4641709A (en) | 1987-02-10 |
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