|Publication number||US3490527 A|
|Publication date||Jan 20, 1970|
|Filing date||Jul 31, 1968|
|Priority date||Jul 31, 1968|
|Publication number||US 3490527 A, US 3490527A, US-A-3490527, US3490527 A, US3490527A|
|Inventors||Cook Evin L, Dimon Carl A|
|Original Assignee||Mobil Oil Corp|
|Export Citation||BiBTeX, EndNote, RefMan|
|Non-Patent Citations (1), Referenced by (8), Classifications (10)|
|External Links: USPTO, USPTO Assignment, Espacenet|
Jan. 20, .1970 5 100 ET AL IMBIBIIION WATERFLOODING PROCESS Filed July 31, 1968 FIG. 3
EVIN L. COOK CARL. A. DlMON INVENTORS ATTORNEY United States Patent O US. Cl. 166-245 10 Claims ABSTRACT OF THE DISCLOSURE The specification discloses an improved, imbibition waterflooding process to be carried out in a tight, natur ally fractured, partially depleted reservoir having a free gas phase therein. The process comprises injecting water into the reservoir at a controlled rate until the pressure throughout the reservoir increases to a level equal to or greater than the pressure necessary to recompress and redissolve the free gas phase. The reservoir is normally produced during this repressuring. After this necessary increase in pressure, injection is continued at either said controlled rate or any other desired rate until the reservoir pressure is raised to a level sufiicient to reopen partially closed fractures. This is usually substantially equal to or greater than the original reservoir pressure. Production of the reservoir is then continued while maintaining the reservoir at said latter pressure level by substantially matching the injection and withdrawal rates. The controlled rate in the initial repressuring is critical and must be slow enough to avoid pushing oil back from the fracture face into the interior of the rock matrix.
BACKGROUND OF THE INVENTION The present invention relates to a process for recovering petroleum from a subterranean reservoir and more particularly relates to an improved imbibition waterflooding process for recovering petroleum.
It is Well known in the oil industry that so-called secondary recovery processes are employed to produce an additional volume of gas and oil from a subterranean reservoir after production by primary means, such as pumping, has declined to an uneconomical level. However, in some types of reservoirs due to geological features of the formations involved, the more common of these secondary recovery processes, such as waterflooding or gas drive, have little or no effect in increasing recovery. Such reservoirs require special secondary recovery procedures capable of taking into account the particular characteristics of these formations.
An example of such a reservoir is one which is comprised of tight, highly fractured formations in which most of the available oil is stored in the rock matrix with little or no oil present in the fracture network. The rock matrix is strongly water-Wet and has low permeability with the effective permeability of the reservoir depending primarily on the interconnecting fracture network therethrough. The Spraberry Trend of West Texas is such a reservoir.
It was realized early in the production history of the Spraberry Trend that normal secondary recovery processes would have little of their usual utility in increasing the final recovery of oil therefrom since it appeared that the injected water or gas merely channeled through the fracture network Without displacing any oil from the matrix. This realization led to the development of a specialized water-flooding process which is now known as imbibition waterflooding. This process is known in the art and has been described in the literature, specifically in a paper by E. R. Brownscombe and A. B. Dyes presented 3,490,527 Patented Jan. 20, 1970 at the thirty-second annual A.P.I. meeting in Chicago, Illinois, November 1952, and published in the Oil and Gas Journal, v. 51, No. 28, Nov. 17, 1952.
In an imbibition waterflood process the fracture network of the reservoir is flooded with water but, unlike a conventional waterfiood, there is no cocurrent flow of water and oil through the rock matrix. In other words, the water does not push the oil ahead of it so there is no flow of oil and water through the rock matrix in the same direction. Instead, capillary action causes Water in the fractures to soak or imbibe into the matrix through the fracture face. The oil displaced by this Water in turn flows from the matrix into the fracture through the same fracture face by means of countercurrent flow. The displaced or exchanged oil is then produced from the fracture net-work by excess water flowing therethrough.
Imbibition, as mentioned above, is a secondary recovery process and as such is generally initiated after the primary production rate has undergone some decline. This means that the pressure within the reservoir will have substantially declined from its original value. In fractured, low permeability formations, a decrease in pressure normally causes two things to happen. One, as the pressure decreases below the bubble point of the oil, a free gas phase is established throughout the reservoir. Second, the pressure exerted on the reservoir by the overburden compresses the formations and closes some of the naturally occurring fractures therein, thereby further decreasing the fracture face area available for imbibition and the permeability of the reservoir.
In a typical imbibition process, water is injected into the reservoir to raise the reservoir pressure back to near the original reservoir pressure which is believed to open most of the partially closed fractures. In the past, opening of partially closed fractures has been suggested to improve permeability or well productivity. In the present process, the objective in opening these fractures is to increase the fracture face available for imbibition. Previously, this injection of water has been carried out over relatively short periods of time since a rapid repressuring rate appeared to be most desirable fr m an economical standpoint. However, it was found that an imbibition process wherein the repressurization of the reservoir was quickly carried out fell far short of the expected efliciency of the process. Upon analysis, this decrease in efficiency was found to be caused by the free gas phase normally present in the reservoir at the start of water injection. Apparently, the rapid injection of water displaced the oil back from the fracture face into the matrix. Forcing the oil away from the fracture face seriously restricts the flow of oil into the fracture network and accordingly severely affects production from the reservoir.
SUMMARY OF THE INVENTION The present invention provides an improved, imbition waterflooding process for increasing oil and gas recovery from a tight, naturally fractured reservoir which has a free gas phase therein.
The present process is basically comprised of three steps, a first repressuring step, a second repressuring step, and a sustained production step. The first step involves repressuring the reservoir up to a pressure level at which substantially all the free gas in the reservoir will be redissolved in the oil in the matrix. The net injection rate, i.e., the amount of liquid injected minus the amount withdrawn during the same period, at'which this repressurization is carried out is critical. This rate must be such that the free gas in the reservoir is slowly redissolved into the oil and so that the water entering the matrix will not drive the oil back from the fracture faces into the matrix. Generally speaking, this net rate is such that a known volume of liquid, e.g., water, is injected uniformly over a predetermined time. The net volume of water to be injected is equal to that volume of pore space in the reservoir which is initially occupied by the free gas phase. The time over which this net volume of water must be injected is dictated by characteristics of the reservoir formations and the procedure for arriving at this time will be described in detailed discussion below. Further, since it is desirable to produce the reservoir during the first repressuring step, the actual injection rate during this first step is preferably equal to the net rate necessary to fill the free gas pore space, as discussed above, plus a rate equal to the withdrawal rate from the reservoir, i.e., the rate at which fluids are being produced.
Once the entire reservoir has reached the pressure where no free gas is present, injection of liquid is continued while back pressure may be maintained on the production wells so that the pressure within the reservoir is rapidly raised substantially to or above the original reservoir pressure, i.e., that pressure which existed in the reservoir prior to any production therefrom. This constitutes the second step of the present method. By raising the reservoir pressure back substantially to or greater than what it was originally, the pressure exerted by the overburden is counteracted and most natural fractures which were closed upon the decline of reservoir pressure will now be opened. This increase in the fracture network is of definite value in the imbition process and will be described more fully in following discussions.
The third step of the present process involves continuously producing the reservoir while maintaining the reservoir substantially at or above its original pressure. This keeps the fractures open during the sustained production period and provide added efficiency to the overall process. The injection rate of water during this period is preferably matched to the withdrawal rate of produced fluids from the reservoir so that the injection rate substantially equals the withdrawal rate.
For a better understanding of the present invention, reference may be had to the following detailed description taken in conjunction with the accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS FIGURE 1 is an elevational cross-sectional view of a reservoir in which the present invention is to be utilized;
FIGURE 2 is an enlarged view of the area within line 22 of FIGURE 1; and
FIGURE 3 is a schematic view of different flow mechanisms which occur in a reservoir in accordance with the imbition waterflooding process during the first repressuring step.
DESCRIPTION OF THE PREFERRED EMBODIMENT In certain reservoirs, conventional secondary recovery methods have little or no effect on the recovery of oil and gas therefrom. One such reservoir is comprised of tight, naturally fractured formations wherein the recoverable oil is almost entirely stored in the rock matrix of the formations with little or no oil present in the fractures. The rock matrix, itself, is water-wet and has an extremely low permeability which prevents ready flow therethrough. The Spraberry Trend of West Texas is an actual example of such a reservoir.
A horizontal, cross-sectional view of a tight, highly fractured reservoir is shown in FIGURE 1. Reservoir is comprised of a tight formation which has a natural fracture network therein. This network is comprised of a plurality of elongated fractures 11 which are interconnected by secondary fractures 12. Fractures 11 normally occur along the natural fracture trend of the formation. These fractures are substantially parallel to each other and are spaced at substantially equal distances from each other. The distance 2L between fractures 11 is of extreme importance in the present invention as will become evident from the discussion below. Fractures 12 also occur naturally in reservoir 10 and are substantially perpendicular to fractures 11 but follow a more random spacing throughout the reservoir. Fractures 11 and 12 effectively divide the reservoir into a plurality of water-wet, rock matrix blocks 14 in which almost all of the recoverable oil in the reservoir is stored. Due to the low permeability of the rock matrix blocks 14, the effective permeability of reservoir 10 is provided by the fracture network therethrough. As is typical in secondary recovery processes involving fluid injection, one or more injection wells 20 are provided on one side of the reservoir with one or more production wells 21 on the opposite side thereof. An example of a predominant flow path which occurs through reservoir 10 during the present process is shown by heavy line 13 with the arrows indicating the direction of flow from injection well 20 to production well 21.
To better understand the present invention, a more detailed discussion of an imbibition waterflooding process is deemed beneficial. To aid this discussion, there is schematically shown in FIGURE 3 a cross-sectional view of a block 14 of the rock matrix from reservoir 10. A full block 14 having a length 2L is shown but it should be recognized that for the purposes of the present discussion, one block 14 actually forms two blocks 14a, 14b, of length L, each being a mirror image of the other. The block is effectively sealed on the two sides 15 by abutting, adjacent blocks 14 in the reservoir and for the purpose of this discussion is considered sealed along centerline 15a since any flow from block 140 into 14b will be canceled by flow from 14b into 1411. The blocks 14a and 14b are open on only one side, 16a and 1612, respectively, these being fracture faces which front parallel fractures 11 (FIGURE 1). Since 14a and 14b are identical, only the effects of imbibition on 140 will be described.
The pore space in rock matrix block 14a is initially filled with oil, water, and free gas. This is the situation which normally exists in reservoir 10 after it has been partially depleted by primary recovery means, such as solution gas drive and pumping. A free gas phase will form in the reservoir whenever the reservoir pressure declines from its original pressure to one which is below the bubble point of the oil. This decrease in pressure allows the gas to be expelled out of the oil and occupy itihedfree pore space in the reservoir left by produced ur s.
In an imbibition process, the fracture network of reservoir 10 is flooded with imbibing liquid, such as Water, so that water flows through the reservoir and contacts the matrix blocks 14 only along fracture faces 16 (FIG- URE 2). It should be recognized that water as used herein refers to those liquids normally referred to as water in common waterflooding techniques and includes brines, fresh water, water plus additives, etc. In repressuring such a reservoir, the water in contact with fracture faces 16 undergoes an increase in pressure with time. Under these conditions, two distinct fluid flow mechanisms take place within the. rock matrix 14w at the same time. One mechanism is the usual cocurrent fiow which takes place in compressible three-phase flow. This compressive, cocurrent flow normally occurs when free gas is present and is the type of flow normally associated with regular waterflooding techniques. The pressure being higher at the fracture face 16a forces water into the block 14a which compresses and redissolves the free gas and causes oil, gas, and water to flow into block 14a away from fracture face 1 6. This flow mechanism is illustrated by the vector arrows within the dotted block A in FIGURE 3.
The second flow mechanism taking place in the matrix is countercurrent flow which results from a capillary pressure gradient caused by a saturation gradient rather than an imposed pressure gradient as described above. This flow arises due to the capillary action of the rock matrix 14a. This type of flow normally occurs with no free gas present and is the same as that which is responsible for the exchange of oil and water. in an imbibition process when only oil and water are present in the rock. Capillary action causes the water to be imbibed into the rock but unlike compressive fiow, the oil and gas do not flow inward. Instead, the capillary action causes the oil and gas to flow in the opposite direction from that of the water. In this countercurrent flow process, the sum of the oil and gas flows exactly counterbalances the water flow and the relative amount of oil and gas flowing toward fracture face 16 is determined by the mobilities of the oil and gas within the rock matrix. This type of flow mechanism is illustrated by the vector arrows within the dotted section B of FIGURE 3.
The total flow occurring within the matrix 14a will simply be the sum of both of these types of fiow since both occur at the same time. Water flows inward in both of these fiow mechanisms so that the flow of water will always be directed inward when both of these flow mechanisms take place simultaneously. On the other hand, the flows of both oil and gas are directed inward in the compressive or cocurrent flow mechanism but are directed toward the fracture face in the capillary or countercurrent flow mechanism. This means that the directions of oil fi-ow and gas fiow depend upon whether the compressible or the capillary flow mechanism is dominant. Usually, with free gas present the compressible flow mechanism can take place much more rapidly than the capillary flow mechanism. Hence, the compressible flow mechanism will be dominant unless the pressure at fracture face 16 is raised slowly enough to redissolve the free gas into the oil rather than compress it to drive the oil away from the fracture face.
From the above, it is seen that the rate at which reservoir is repressurized definitely affects oil recovery from an imbibition process. If the repressurizing rate is too fast while free gas is present, the compressible flow mechanism will completely dominate the capillary flow mechanism and the oil, water and gas fiows will all be directed inward. Hence, oil and gas will be displaced away from fracture face 16 and a region of high water saturation will build up in the matrix near the fracture face. Accordingly, repressurizing the reservoir at too fast a rate pushes oil back from the fracture face and effectively shuts off oil production during repressurization.
Even after the repressuring of the reservoir has been achieved using too fast a rate, the oil must move back through this zone of high water saturation before, it can reach the fracture face to be exchanged. This build-up of a high water saturation zone near the fracture face delays the oil recovery even after the repressurization is completed. Experimental and mathematical studies have borne out this observation.
Therefore, a rapid or fast injection rate for repressurization is undesirable in a partially depleted reservoir having a free gas phase present therein. Accordingly, the injection rate for the repressuring of reservoir 10 must be slow enough so that the capillary flow mechanism can occur more rapidly than the compressive flow mechanism even when free gas is present. Under such conditions there will always be a net flow of oil toward fracture face 16a. Hence, there will be some recovery of oil by capillary action even while the reservoir is being repressured. In addition, oil recovery after repressurization will not be delayed because oil has not been pushed back from the fracture face.
To summarize, the present invention provides an improved imbibition waterfiooding process which is basically comprised of three steps. First, the partially depleted reservoir 10 having a free gas phase therein is slowly repressured by injecting water at a carefully controlled rate until the pressure throughout the reservoir is equal to or slightly greater than the pressure necessary to redissolve completely the free gas phase. Second, injection of water is continued after this pressure is reached until the reservoir is repressured to a level at which most of the partially closed, natural fractures in the reservoir are opened, this usually being at or above the original reservoir pressure. Third, the reservoir is produced while this latter pressure level is maintained therein by substantially matching the withdrawal rates with the injection rates.
In the present invention, the initial step of repressuring partially depleted reservoir 10 must be carried out by injecting imbibing liquid, e.g., water, at a carefully controlled rate. This rate of injection, which is critical, is continued until the overall pressure in reservoir 10 is substantially equal to or slightly above the pressure necessary to redissolve completely the free gas phase. This rate must be slow enough to allow the free gas to redissolve into the oil present in the reservoir without pushing the oil back from the fracture face. By so controlling the injection rate, compressive flow will occur slowly in the rock matrix blocks 14, thereby allowing the capillary flow mechanism within these blocks to predominate so that oil will be produced even during this initial repressurization of the reservoir.
where Q =injection rate of liquid during first repressuring step necessary to fill V,
V=pore volume initially occupied by free gas phase,
t=total time required for the first repressuring step.
The time t in the above expression is the key to the first repressuring step. For the repressuring to be slow enough to accomplish its objectives, the injection of the desired volume of liquid must not occur in a time less than that dictated by the characteristics of rock matrix blocks 14. From the three-phase Darcy laws, known relationships of capillary pressure behavior, and the theory of diffusion processes, the time t necessary for the first repressuring step can be expressed as the following relationship:
t=time in years,
L=distance from fracture face to center of a matrix block in feet (see FIGURES 1 and 3), and
D=dilfusivity parameter for the imbibition process for rock matrix in square feet per year,
where D is related to the fluid characteristics of the rock by the expression:
2.31=constant to standardize units,
K=specific permeability of the rock matrix in milli- Darcies,
p=porosity of the rock matrix expressed as a fraction,
k k k =relative permeabilities of water, oil, and gas,
respectively, at reservoir conditions,
,u ,u =viscosities of water, oil, and gas, respectively,
at reservoir conditions in centipoises,
AP =oil-Water capillary pressure difference in pounds per square inch, and
AS =difference in water saturation in the matrix between the beginning of the first injection step and completion thereof.
Although the diffusivity parameter D is expressed in a mathematical relationship, it should be realized that the manner in which D is derived is not critical to the time required since D may be experimentally derived. However, D arrived at experimentally would still be represented by Equation 3 above.
The critical time value 1, expressed above, is sufficient to allow the capillary flow process to dominate the compressive flow process and thus avoid pushing oil back from the fracture face.
Since it is preferred to produce the reservoir during the first repressuring step, the rate Q at which fluids, e.g., oil, gas, and water, are withdrawn from the reservoir must be considered to determine the preferred total injection rate. In this case, the rate of withdrawal Q will be added to injection rate Q,,, defined above, to determine the rate Q at which liquid is to be injected during the first repressuring step. Some water must be produced along with oil and gas during this first step to insure that sufficient water is present in the reservoir to allow imbibition to take place. During this step, the water-to-oil ratio of the withdrawn fluids is preferably maintained as close to one as possible although this is not critical. Injection of liquid is continued at or less than rate Q until the pressure within reservoir 10 reaches or slightly exceeds the pressure at which the free gas phase will be redissolved. At this point, the first step of the present invention will be complete.
The second step of the present invention comprises injecting liquid into reservoir 10 until the pressure throughout the reservoir is raised from the pressure at which the free gas phase is redissolved substantially to or greater than that pressure which originally existed in the reservoir prior to any production therefrom. This increase in pressure opens or reopens several of the natural fractures which had been previously cloosed due to the decline in pressure within the reservoir. It is believed that the force exerted by the overburden formations compresses the blocks 14 in the reservoir when the formation pressure declines from its original pressure thereby closing several of the spaces between blocks 14, i.e., naturally occurring fractures. Since there is no longer any free gas phase present in reservoir 10, the rate at which this second repressurization step can be carried out is no longer critical. The injection rate can be the same as that used during the first step or it can vary therefrom. During this second step, back pressure may be maintained on the production wells 21 so that the second repressurization takes place in a relatively short period of time. It is again emphasized that during this second repressurization there is substantially no free gas available in the reservoir so there is no danger of forcing the oil back from the fracture face.
The primary purpose of opening or reopening any natural fractures that may have closed due to pressure decline is not so much to increase the effective permeabilit of reservoir 10 as to increase the effective imbibition rate. As intermediate fractures are opened by the increased pressure, the distance 2L between parallel fractures 11 is decreased and the fracture face area in contact with water increases. This substantially increases the rate of imbibi- 8 tion since this rate varies proportionally with the square of L.
After the reservoir has been repressured substantially to or above the original reservoir pressure, the third step of the process is caried out. This third step comprises producing from the reservoir while maintaining the entire reservoir substantially at or above its original pressure. This is done by matching the injection rate to the withdrawal rate of produced fluids from the reservoir and also by maintaining a substantial back pressure on the production wells. The injection rate and hence the withdrawal rate should be approximately equal to the imbibition rate of the reservoir plus an excess volume of water so that there will always be water available in the fracture network for imbibing and so that production of oil can occur while imbibition is taking place. During this third step the imbibition rate slows down with time so that if a constant injection rate is used, the water-to-oil ratio will increase because less and less oil is being produced from the rock matrices. During this third step, the water injected to match the imbibition rate is decreased so that the watertooil ratio of the withdrawn fluids is preferably maintained between one and two, although it could greatly exceed this number without departing from the present invention. By matching substantially the injection rate to the withdrawal or production rate and by maintaining a back pressure on the production wells, the pressure within reservoir 10 is maintained substantially at or above its original pressure thereby keeping the natural fractures within the reservoirv open.
Although the above-described improved imbibition waterflooding process may be carried out in any commonly known waterflooding pattern, e.g., five-spot, it is preferably utilized in a pattern commonly referred to as a line-drive which is illustrated in FIGURE 1. In a linedrive pattern, the injection wells 20 lie along a first line while production wells 21 lie along a second line which is substantially parallel to said first line. Also, the injection wells and production wells preferably should be positioned with relation to the reservoir so that flooding takes place across the natural fracture trend of the reservoir, this technique being illustrated in FIGURE 1.
Having described a specific embodiment of the present invention. it will be understood that modifications thereof may be suggested to those skilled in the art, and it is intended to cover all such modifications as fall within the scope of the appended claims.
What is claimed is:
1. In an improved imbibition waterflooding process to be carried out in a partially depleted, tight, naturally fractured reservoir having a free gas phase therein and having recoverable oil stored in a water-wet, low permeable rock matrix, said reservoir having a facture network comprising elongated fractures running along the natural fracture trend and interconnecting fractures substantially perpendicular thereto, said reservoir having at least one injection well and at least one production well, the process comprising the steps of:
injecting imbibing fluid into said reservoir through said at least one injection well at a rate slow enough to allow the capillary flow mechanism of said matrix to dominate the compressive flow mechanism of said rock matrix,
continuing said injection of imbibing fluid at said rate until the overall pressure in said reservoir equals or exceeds the pressure at which the free gas phase will be redissolved in the oil in said matrix,
injecting imbibing fluid into said reservoir after said free gas phase is redissolved to increase the overall pressure in said reservoir to a pressure substantially at or greater than the original pressure at said reservoir prior to partial depletion, and
producing fluids from said reservoir through said at least one production well during said injection steps.
2. In an improved imbibition waterflooding process to be carried out in a partially depleted, tight, naturally frac tured reservoir having a free gas phase therein and having recoverable oil stored in a water-wet, low permeable rock matrix, said reservoir having a fracture network comprising elongated fractures running along the natural fracture trend and interconnecting fractures substantially perpendicular thereto, said elongated fractures being substantially parallel and spaced at substantially equal distances from each other, said reservoir having at least one injection well and at least one production well, the process comprising the steps of:
injecting water into said reservoir through said at least one injection well at a controlled rate not greater than QT: where:
where Q =rate of water injection which matches that rate at which fluids are withdrawn from the reservoir, and
V=volume of pore space in said reservoir occupied by said free gas phase at the beginning of said process, and t=time in years=L /D, and
where L=one-half distance between said substantially parallel,
elongated fractures in feet, and
D=diffusivity parameter for imbibition process for rock matrix in square feet per year,
producing fluids from said reservoir through said at least one production well at said rate Q 3. The process of claim 2 wherein the digusivity parameter is defined as:
where the beginning of the first injection step and completion thereof.
4. The process of claim 2 including:
continuing said injection of water at said controlled rate not greater than Q until the overall pressure in said reservoir equals or exceeds the pressure at which the free gas phase will be redissolved in the oil in said matrix.
5. The process of claim 4 including:
injecting Water at any desired rate into said reservoir through said at least one injection well after said free gas phase is redissolved to increase the overall pressure in said reservoir to a pressure substantially at or greater than the original pressure of said reservoir prior to the partial depletion thereof.
6. The process of claim 5 including:
maintaining a substantial back pressure on said at least one production well during said injection of water after said free gas phase is redissolved until the pressure in said reservoir is substantially at or greater than said original reservoir pressure.
7. The process of claim 6 including:
maintaining the overall pressure in said reservoir substantially at or greater than said original'reservoir pressure; and
producing fluids from said reservoir through said at least one production well.
8. The process of claim 7 wherein the step of maintaining said pressure in said reservoir substantially at or greater than said original reservoir pressure includes:
injecting water into said reservoir through said at least one injection well at substantially the same rate as that rate at which fluids are produced from said reservoir through said at least one production well.
9. The process of claim 8 wherein:
said reservoir has a plurality of injection wells which lie along a first line and a plurality of production wells which lie along a second line which is spaced from and substantially parallel to said first line.
10. The process of claim 9 wherein:
said line of injection wells and said line of production wells is positioned with relation to said reservoir so that flooding of said reservoir will be across the natural fracture trend of said reservoir.
References Cited AS =difference in Water saturation in the matrix between STEPHEN I. N OVOSAD, Primary Examiner I. A. CALVERT, Assistant Examiner U.S. C1. X.R. 166-268
|Citing Patent||Filing date||Publication date||Applicant||Title|
|US4364431 *||Dec 17, 1980||Dec 21, 1982||National Iranian Oil Company||Method for recovering oil from an underground formation|
|US4842065 *||May 11, 1988||Jun 27, 1989||Marathon Oil Company||Oil recovery process employing cyclic wettability alteration|
|US5377756 *||Oct 28, 1993||Jan 3, 1995||Mobil Oil Corporation||Method for producing low permeability reservoirs using a single well|
|US5415231 *||Mar 21, 1994||May 16, 1995||Mobil Oil Corporation||Method for producing low permeability reservoirs using steam|
|US8061422 *||Feb 16, 2009||Nov 22, 2011||University Of Houston System||Process for enhancing the production of oil from depleted, fractured reservoirs using surfactants and gas pressurization|
|US9140109 *||Sep 29, 2010||Sep 22, 2015||Schlumberger Technology Corporation||Method for increasing fracture area|
|US20090205823 *||Feb 16, 2009||Aug 20, 2009||University Of Houston System||Process for enhancing the production of oil from depleted, fractured reservoirs using surfactants and gas pressurization|
|US20130140020 *||Sep 29, 2010||Jun 6, 2013||Schlumberger Technology Corporation||Method for increasing fracture area|
|U.S. Classification||166/245, 166/268|
|International Classification||E21B43/30, E21B43/16, E21B43/00, E21B43/20|
|Cooperative Classification||E21B43/20, E21B43/30|
|European Classification||E21B43/30, E21B43/20|