Multistage solvent extraction method for high-density oil pools
FIELD: oil and gas industry.
SUBSTANCE: group of inventions is related to production of heavy hydrocarbons. In the in situ multistage solvent extraction method of heavy oil from oil pools at first liquids and gases are extracted from zones of contact with heavy oil in order to increase interfacial area of unextracted heavy oil subject to contact with solvent. Then solvent is injected in the form of steam to the above zones in order to increase pressure in the pool up to accumulation of sufficient quantity of solvent in the form of liquid to ensure contact with enlarged interfacial surface of heavy oil. Then the pool is isolated for the period sufficient to ensure diffusion of solvent to unextracted oil through the interfacial surface at ageing stage so that the mixture of solvent and oil with low viscosity is obtained. One or more parameters of the pool are measured to determine the degree of unextracted oil liquefaction in the pool by solvent. Oil extraction from the pool is commenced by gravity drainage when viscosity of oil becomes rather low to flow through the pool to the production well.
EFFECT: maximising liquefaction of heavy oil and maximising its extraction as a result.
19 cl, 11 dwg
AREA of TECHNOLOGY
The present invention relates to extraction of hydrocarbons, and more particularly, to the extraction of heavy oil from underground formations. In particular, the invention relates to a multistage method for the extraction of heavy oil, which can be applied, for example, after primary extraction becomes ineffective. Mainly, the present invention relates to improved based on the use of multistage solvent method of extraction of heavy oil.
The term "heavy oil" has a broad definition, but usually under a heavy oil implied to some extent deteriorated, and viscous oil, which may contain bitumen. Heavy oil under reservoir conditions typically has low mobility, so the seam is difficult to develop, and it has a very low coefficient of oil recovery. Heavy oil is typically more viscous than easy or normal oil, but less viscous than asphalt, which can be detected in the oil sand. Heavy oil is a mineral oil having a density in degrees ANI (American petroleum Institute) is in the range from about 10 to 22 with a viscosity comprised between approximately 100 to 10,000 CPS. In the context of the present description under the heavy oil �onimaetsya oil, corresponding to the given definition.
The heavy oil In situ (in place) is available in bulk quantities, but it is difficult to extract. The recent (2003) calculation of the resource held by the Geological service of the USA using the estimated recovery factor of oil 19%, evaluates theoretically recoverable reserves of heavy oil only in North America in the 35.3 billion barrels. This calculation USGS (from the English. - United States Geological Survey) implies that the total internal resource of heavy oil in North America is approximately 200 billion barrels, and that over 80% of these domestic reserves of heavy oil are unrecoverable in applying best modern extraction technology. The USGS report also claims that the world heavy oil resource is 3.3 trillion barrels, and that 87% of this resource are unrecoverable or difficult to recover with the help of modern technology. Thus, there is significant commercial interest in improving the technology of extraction of oil. More specifically, if the improvement in extraction technology will increase oil recovery of heavy oil from today's 13% to just 25%, it will be expressed on a global scale in an additional 400 billion barrels of recoverable oil.
Bituminous oil Sands in Canada, Kee�cabins much attention due to the huge content of hydrocarbons. However, a fairly small increase in the average world oil recovery factor of heavy oil, with 13% to 18% of the reservoir oil to obtain an additional quantity of oil equal to the assessment of commercial reserves of oil in the canadian oil Sands.
Given peak oil and limited opportunities for new discoveries, extraction of stranded heavy oil is becoming more important. In addition, it is very desirable to have additional oil recovery using energy-saving extraction technology. Long been recognized that the solvents have a theoretical potential to give mobility and extraction of stranded heavy oil. Theoretically, the solvent does not require the use of high temperatures and, therefore, no high energy consumption and greenhouse gas emissions, so characteristic, for example, for steam extraction of bitumen.
Currently, using the most sophisticated existing models, based on computer modeling, specialists in the art will understand that the solvent diffuses quickly and deeply with formation of heavy oil. This is described in the published results of computer simulation (Tadahiro et al., may 2005 of jcpt, p. 41, Fig.18), which show the penetration ol�parovogo solvent for 8 meters (25 feet) from the edge of the steam chamber in the heavy oil with a viscosity component 5200 CPS. Das (2005 SPE paper 97924 Fig.12) also reports that we can expect that the propane solvent will penetrate to 5 meters beyond the edge of the camera in the Athabasca Deposit.
However, laboratory studies conducted by the author of the invention (Nenniger CIPC paper 2008-139, Fig.1 and 2) showed that the mechanism of extraction solvents for heavy oil and oil Sands is very different from the predicted computer simulation. In particular, instead of a deep diffusion of the solvent into the oil bearing zone is observed the formation of a pronounced solvent boundary with nerazgadannoi oil, which can be described as a discontinuity surface concentration. A surface of discontinuity of concentration arises from the fact that the solvent hardly diffuses or penetrates into the oil of high viscosity, such as heavy oil or bitumen. During the experiment on the modeling layer the inventor observed the deposition of asphaltene on the distance of the length of raw bitumen, which means that the concentration gradient at small distances is very large.
Typical physical scale of the observed liquefaction process solvent heavy oil is the length of the individual pores, which is approximately 100 microns in the sand with a permeability of 5 Darcy. The assumption that two irreducible mix of uglevodorodno�e liquid such as oil and solvent are mixed quickly and easily, seemed reasonable and was confirmed by the simulation and Tadahiro Das. Therefore, experimental observation of the concentration jump was unexpected. More specifically, the detection of a discontinuity surface concentrations showed that the broadly held view of the rapid dilution of heavy oil and bitumen by diffusion of the solvent wrongly.
Previously, in the prior art, there have been a multitude of attempts to develop extraction processes solvent-based. For example, in patent US 5720350 described method of extracting oil remaining in the reservoir of conventional oil after the initial extraction of conventional oil. In this way the applied gravitational drainage from the formation, wherein amenable to mixing with the oil a solvent having a density higher than the density of the gas contained in the gas cap, is pumped into the formation above the liquid level. After the injection of solvent oil production started from the lower part of the formation. The idea was that the solvent displaces the remaining oil in a second borehole. However, traditional extraction is usually very good - can be extracted from 30% to 60% or more of the reservoir's oil, therefore, to extract any significant portion �remaining oil can be very large and potentially uneconomic volumes of solvent.
In the patent US 5273111 described method of extraction of hydrocarbons through offset laterally and vertically horizontal wells, which used a continuous process that combines gravity drainage and the displacement or movement of gas (i.e. displacement pressure) for oil production from vertical and horizontal wells special configuration. This patent States that the configuration of wells should be optimized to reduce consobrina and breakthrough of the solvent in the space between the holes: but the use of displacement or movement of gas will lead to selective extraction using part of the reservoir with higher permeability. Thus, although consobrina and breakthrough of solvent can be reduced, they will remain significant, and therefore, apparently, the process of displacement and do not capture most of tight oil.
In the patent US 5065821 the described method of gas injection in undeveloped reservoir with horizontal and vertical wells, including injection of gas through the first vertical hole simultaneously with the implementation of cyclic injection, impregnation and extraction of gas through the horizontal well, and then establishes a connection with a vertical well vertical well becomes operational well, and the horizon�of obayatelnaya, charming well becomes the injection well. This method is also based on continuous injection of a gaseous solvent (i.e. crowding-out pressure) in the reservoir after the connection is established between the wells. In the initial stages is very difficult to deliver the solvent to the undeveloped layer to diffuse into the oil and thinning, which makes the process slow and impractical.
In the patent application Canada No. 2494391 in the name Nexen describes a different extraction technology-based solvents, which adopts a continuous injection of solvent or extraction, which can be characterized as a displacement or movement of the solvent in the system of horizontal and vertical wells. But here, any attempt to push the oil through solvent displacement leads to a rapid consobrina, shorting, no takeover of the challenging oil and only minimal recovery.
Despite these and many other previous attempts to improve the method of extracting heavy oil-based solvents, the results remain unsatisfactory. Obviously, it is necessary to achieve a different and significantly better understanding of how to effectively use solvents to improve heavy oil recovery in order to increase the capture of heavy oil solvent. It is necessary to develop this method of oil extraction� solvent, account of the slowness of the penetration of the solvent with formation of heavy oil and would be directly aimed at the solution of this problem.
Summary of the INVENTION
It is now clear that the initial penetration of the solvent in the oil is very slow. On the other hand, as only a small amount of solvent - perhaps only one or two per cent, will proiformiruet in oil contained in a single pore in a productive zone, further diluting the partially liquefied oil is very fast. This creates a distinct boundary between the solvent/liquefied crude and heavy oil, which slowly progresses through the productive zone of the formation from pore to pore. The present invention provides a method and process, considering that the slow advance of the solvent front and, therefore, an object of the invention is to provide an efficient and predictable make mobility difficult to recover in situ (in place) of heavy oil and extract large amounts of oil.
The present invention takes into account the difficulty of obtaining uniform distribution of the solvent in a productive zone of the reservoir of heavy oil and provides for the separation method on the stages that contribute to the diffusion and homogeneity of the solvent. The small penetration depth and high g�adient concentration on the surface of the gap means, the rate of liquefaction solvent of stranded oil on a broad base of the reservoir is limited by two key parameters, namely the size of the surface section of tight oil are available for solvent, and the time during which the solvent is in contact with the surface of section. The degree of viscosity of the mixture of solvent/oil is determined by the degree of dilution solvent heavy oil, and, in turn, directly affects the mobility of the mixture of heavy oil in the reservoir and, consequently, the possibility of its extraction from the production well by gravity drainage.
In accordance with the present invention the method that maximizes the dilution of heavy oil solvent, maximizes the possibility of recovery of stranded heavy oil.
Thus, the present invention consists in a procedure that contains several stages, including an increase in the surface section by the removal of blockers of the solvent from the voids formed in the layer during primary extraction. Cleaning of voids allows you to put into the formation a larger amount of solvent, which ensures contact of a larger amount of solvent with a large number of stranded oil, and thereby allows to obtain the speed of the extraction process significantly p�Eviews speed, possible undeveloped reservoir or even partially developed in the layer containing voids filled with a blocking solvent reservoir fluids and gases. In addition, the invention provides a sufficient duration of exposure to the solvent and the oil phase of maturation, to allow the solvent slowly, but sufficiently to penetrate the oil filled pores and to achieve an acceptable degree of homogeneity or liquefy at microscale level throughout the reservoir. In accordance with one aspect of the present invention, the degree of maturation in situ is measured, which allows to determine the moment when to proceed to the next stage of the extraction process, consisting in the actual extraction of oil from the formation through gravitational drainage.
Thus, in accordance with one aspect of the present invention provides a method for the multistage extraction of oil in situ in situ for heavy oil reservoirs, the method is based on the use of a solvent and comprises following steps:
and. the removal of liquids and gases from the zones of contact with a heavy oil to increase the surface section of unexploded heavy oil to be in contact with the solvent;
b. injection of solvent in vapor form in these zones to increase the pressure � the formation until the formation of a sufficient amount of a solvent in liquid form, to ensure contact with the increased surface section of heavy oil;
C. isolation of a formation at the stage of maturation at the time, sufficient to ensure diffusion of the solvent in uncovered oil through the surface of section, to produce a mixture of solvent and oil with reduced viscosity;
d. measuring one or more parameters of a formation in order to verify the degree of dilution solvent uncovered oil in the reservoir, and
E. extraction of oil from the reservoir based on gravity drainage after the mixture viscosity will be low enough to allow it to flow through the formation to a production well.
BRIEF DESCRIPTION of GRAPHIC MATERIALS
Below, preferred embodiments of the present invention, given only as examples, will be described with reference to the accompanying drawings.
Fig.1 presents the target heavy oil reservoir with a horizontal well located at the bottom of the production zone, and a vertical injection well.
Fig.2 shows a graph of the total transmissive capacity for a typical heavy oil reservoir permeability from millidarcy.
Fig.3 shows a graph of pressure in the reservoir from time to example of a formation in accordance with the present invention.
Fig.4 performance�of Allen graph of viscosity versus temperature for different ratios of solvent and oil in heavy oil, liquefied solvent.
Fig.5 shows the curve of the vapor pressure of the particular solvent, ethane, depending on the volume concentration of ethane dissolved in heavy oil, in accordance with the present invention.
Fig.6 presents the time of passage of the solvent preset distance through the reservoir of heavy oil (in days) due to the dilution of heavy oil in accordance with the present invention.
Fig.7 shows the calculated rate of extraction of oil for a horizontal well with a length of 800 m with a 10-meter productive area depending on the degree of dilution with a solvent oil to the reservoir with an average permeability of 1 Darcy in accordance with the present invention.
Fig.8 shows the calculated rate of extraction of oil for a horizontal well with a length of 800 m with a 10-meter productive area depending on the degree of dilution with a solvent oil to the reservoir with an average permeability 7 Darcy in accordance with the present invention.
Fig.9 presents the estimated cost of solvent per cubic meter of extracted oil to heavy oil reservoir with permeability 7 Darcy in Fig.7 depending on the volume concentration of solvent in oil (for ethane or C2) given that, in accordance with the present invention the solvent in the final stateinvited in the process of purging.
Fig.10 shows the dependence of the pressure in the reservoir from time to time in accordance with the present invention, if the solvent is extracted together with the oil is not re-injected into the reservoir.
Fig.11 presents the estimated volumes of injection and extraction depending on time for the method of extraction according to the present invention for a reservoir with an active aquifer or reservoir pressure of another type, so that the pressure in the reservoir is effectively limited to a constant value.
DETAILED DESCRIPTION of PREFERRED embodiments of the INVENTION
The present invention is most applicable to heavy oil reservoirs subjected to primary extraction and demonstrating good restriction. In accordance with the present invention, the primary extraction leads to the appearance in the reservoir depleted zone containing gas filled or water voids. The preferred layer is a layer, which was subjected to a primary extraction, during which it was extracted from 5% to 25% of the original reservoir oil, and most preferably from 8% to 15%. Most preferably corresponding to the target formation should have substantial thickness of the productive formation without horizontal barriers large extent, sufficient to lower the viscosity of heavy �of eti in situ could be gravitational drainage. Although the strata passed through the primary extraction are preferred, the present invention is also suitable for undeveloped formations containing natural drainable voids having a volume of from about 5% to 25% of the original reservoir oil. An example of such a layer is the layer with the saturation, component from 20% to 40%, and oil saturation, accounting for between 60% to 80%, clearly limited in porous rock.
Fig.1 schematically shows a target oil reservoir with a vertical bore 20 and a horizontal operational bore 22. Horizontal well 22 is usually located at the bottom of the production zone 24 and is operating well through which the current through the formation fluids can be recovered by gravity drainage. Typical productive area 24 contains layers of different permeability, the indicated positions 28, 30, 32, 34, 36, 38 40. Most preferably the producing zone 24 is limited to impermeable layer 25 overlying sediments and underlying impermeable layer 26, but the experts in the field of petroleum engineering is clear that the present invention also provides for the possibility of using artificial means of restriction. Preferably the producing zone 24 is designed to the extent possible using conventional technologies from primary�treatment such as cold heavy oil production with sand (CHOPS). "Cold Heavy Oil Production with Sand"), resulting in a zone, which can be called the area of the extracted oil, remained void of a significant amount. Although layers 28-40 productive zones can be fairly uniform, usually there are some variations in the permeability due to, for example, the original process fat. Usually there are also some natural variation in the quality of the oil and its viscosity depending on the position in the reservoir.
After primary oil recovery from the reservoir zone of greatest permeability in the production zone 24, in this case, the layers 30 and 38, preferably will be developed, whereas the zones 28, 32, 34, 36 and 40 having slightly lower permeability, basically will not be affected and, thus, will be more difficult to extract oil. If the reservoir was initially developed without reservoir pressure, developed zone, apparently, will also have a certain level of saturation, since it naturally occurs in situ dissolved gas is released from solution and fills the pores as the oil extraction. In the voids of the areas extracted oil productive zones will be, apparently, also be present a significant amount of water or salt solution, especially where flooding was applied. The solvent is injected as p�shown by the arrow 44, in vertical bore 20, and the mixture 46 of the mixed solvent and the oil is extracted, for example, by means of a pump 48.
Fig.2 curve 49 shows that the oil reservoir with some "average" permeability usually contains a wide range of pores of different sizes and, therefore, apparently, has the distribution of permeability over a wide range, which varies widely from one pore to another, and from one layer to another. This means that any extraction process, based on the displacement of gas or liquid (in which the pressure of the gas or liquid is used to eject oil from formations), suffers from the disadvantage that the displacing liquid, e.g. a solution, moves primarily primarily through the large pores with the highest permeability, and thus, avoids a significant amount of oil contained in the smaller pores with lower permeability. This oil, remaining after passage of the displacing fluid, non-mobility at speeds of industrial extraction in situ, and is hard-to-recover oil. This phenomenon of nebulette part of oil in the extraction process creates a particularly big problem for extraction processes solvent, since the solvent tends to dilute the oil along the paths with the highest Prony�uemastu, compounding the problem of shorting and consobrina. There are several ways to physically measure and quantify the heterogeneity of the natural permeability of the productive area, including the logging device and the measurement of porosity. So, Fig.2 shows that a significant portion of oil retained in the pores of the lower permeability in the production zone.
Fig.3 shows the sequence of stages of extraction in accordance with one of preferred embodiments of the present invention in the form of a sequence of pressure changes in the reservoir over time. Fig.3 shows the stage 50 of the creation of voids, step 52, the injection of solvent, stage 54 of maturation stage 56 of oil extraction with simultaneous return of the solvent into the formation and stage 58 purge solvent. All of these preferred phases will be discussed in more detail below. Fig.3 shows a schematic graph of the process in accordance with the present invention as applied to a layer, in which the solvent is ethane, the initial temperature in the reservoir is 20°C and then increases to 24°C (see Fig.4), and the values of the porosity and viscosity of stranded heavy oil conform.
The first stage 50 of the creation of voids is carried out as a pretreatment step, or GE�topically stage. Moving fluids and gases, which for clarity will hereinafter be called blockers solvent is pumped or extracted from the reservoir. Most preferably the blockers of the solvent can be recovered through existing wells that remained after the initial extraction, but in some cases it may be preferable to install horizontal wells, leading to the lower part of the formation, and its application to retrieve blockers solvent. It is believed that the most powerful blockers of the solvent are water, brine and methane, and they may be present in the reservoir after primary recovery loses its effectiveness. The creation of additional voids in the production zone 24 can be further enhanced through the introduction of the solvent vapor layer under a relatively low pressure to remove as much dissolved in the oil and gas methane. The preferred solvent is ethane, although in some conditions of the reservoir you can also use propane. The choice of solvent depends on several factors, including the effectiveness of the solvent at the pressure existing in the reservoir (which often depends on the depth of the reservoir), and the cost of the solvent on the open market at a given time. It is preferable to use ethane for seams that are located n� depth, exceeding 1000 feet, and propane for formations over the shallow. The creation of voids in accordance with the present invention occurs in stages, in accordance with a well-organized sequence of shifts to maximize the removal of water and methane from the production zone 24 deposits. Thus, an advantage of the present invention is the ability to save any remaining after primary oil recovery configuration of wells.
An important aspect of the present invention is also the purity of the solvent. In any environment with mixed solvents, soluble components are mainly readily diffuse into the oil, leaving worse soluble components at the interface with the oil. Thus, after some time, worse soluble components concentrate at the interface with the oil and block the diffusion of soluble components in the oil, thereby preventing thin the oil. Thus, one aspect of the present invention is the substitution of relatively insoluble elements such as methane, which can naturally be present in the formation, sufficiently pure solvent at high concentrations, such as ethane or propane to worse soluble elements could not slow down the thinning of oil or hinder him. If between�the oil and solvent water is present, it also acts as a barrier to solvent, and therefore, in accordance with the present invention, it preferably should also be removed from voids as possible. Therefore, blockers of the solvent can be a gas or liquid under conditions of the reservoir, which preferably should be removed.
In accordance with the present invention the stage of creation of voids can be achieved by maintaining reservoir pressure or without it, depending on the conditions of formation. In some cases you need to apply the pressure maintenance to minimize the inflow of the active aquifer in the process of creating voids and the next phase of the loading solvent. In other cases, the reservoir can be isolated enough and stable enough not to require such reservoir pressure maintenance. However, the present invention provides for both the creation of voids, depending on which one is most suitable for the specific conditions of the reservoir.
The next step 52 of the present invention is a stage of loading of the solvent. This stage continues the introduction into the reservoir of the solvent in the form of steam to gently increase the pressure in the reservoir to a value slightly greater than saturation pressure of the oil vapors of the solvent to fill the entire volume of voids, �formed in the first stage, liquid solvent. In accordance with the present invention, by introducing a solvent in vapor form is attempting to spread the solvent in the distant emptiness, and then, by raising the pressure above the saturation pressure, the filling liquid solvent of the total volume of voids created at the first stage. Introduction most of the solvent in vapor form it is preferable to provide easier penetration of the solvent into the voids in the entire productive zone 24 without the formation of liquid or other barriers to further penetration of the solvent. In accordance with the present invention in the latter stages of injection pressure injection high enough most of the solvent was in a dense liquid-like phase. For this it is necessary to provide a sufficient volume of solvent sufficient to liquefy and therefore give sufficient mobility to the number of stranded oil. At this boot stage should be carefully monitored injection pressure to avoid the risk of possible loss limits the formation with the consequent loss of solvent.
In accordance with the present invention there are several methods of injection or introduction of the solvent depending on a particular layer. Most preferably, the introduction of solvent OS�of Directors carries out the so to ensure the penetration of the solvent into the voids created in the first stage of the method. In some cases this is best accomplished by using the already existing vertical wells reaching a zone of high formation permeability. Also it may be preferable to use in a vertical oil well packers or other similar means to secure the premises of the solvent in the appropriate area of the voids in the reservoir. In addition, if the removal of the blocking liquid from the sump through a horizontal well is sufficiently large, the solvent can also be injected through a horizontal well. In accordance with the present invention it is desirable to introduce the solvent as close to the voids created at the first stage of the present invention to attempt to fill these voids as possible. Exactly how this can be done, depends on the Geology and the characteristics of a specific layer, but this can be done through one or more vertical and horizontal wells at the same time.
The next step of the present invention is the stage 54 exposure time, or maturation, which provided enough time for the slow diffusion of the solvent in the crude oil in smaller and less accessible pores, thinning the oil and pangeni� its viscosity, to get moving fully diluted or homogenized mixture into the formation. This process of homogenization is also important to ensure that seepage of oil into the pores filled with solvent, simultaneously with the infiltration of the solvent into the pores filled with oil. In accordance with the present invention, such a homogenization of the solvent in the oil helps to prevent the associated oil into contact with the solvent on the phase of operation. In properly confined aquifer at maturation stage the pressure in the reservoir falls as relatively pure solvent miscible with oil, and its pressure steam is reduced. This pressure drop in the reservoir is in accordance with Henry's law. In caverns with pure solvent will remain high interstitial pressure, characteristic of the vapor pressure of pure solvent. In accordance with the present invention the shape of the curve of pressure drop and to assess whether they have reached the pressure of the expected asymptotic value, can serve as a useful criterion for the diagnosis of the degree of homogeneity of the solvent content in oil around the seam. In particular, insufficient pressure drop relative to the initial pressure of the loaded solvent is an indicator of poor penetration of the solvent.
Present image�eenie provides for different times of maturation for different layers. One of the arguments is the distance covered by diffusion, which in some cases may be specified, if known permeability and reservoir heterogeneity. The present invention also allows to predict the optimal duration of the stage of maturation depending on the heterogeneity and the physical characteristics of oil. For example, the rate of dilution of oil is very different, and while the light oil with a high content of initial voids can reach the homogeneity in short time, for example per day, for bitumens with high viscosity and low distribution of voids (and solvent) may be required for this extended period, perhaps even tens of years.
It is now clear why, in accordance with the present invention, it is desirable to obtain a sufficiently homogeneous penetration or absorption of the solvent into the oil. When a reservoir containing two fluids, one of which viscosity is significantly lower than the viscosity of other, mostly will be extracted more moving parts. When a sufficient degree of heterogeneity, will essentially be only one fluid, namely oil, liquefied solvent, which increases the likelihood that oil will be given full mobility, which can greatly reduce nevolence�their oil in interaction with the solvent and consobrina. For each formation, in accordance with its features, is typical, apparently, of its own maximum value complete extraction due to natural anomalies, etc. However, in accordance with the present invention provides that the maturation step is carried out up to the maximum possible in the circumstances (for example, for a given volume of voids) of the value to extract the maximum possible amount of oil in the conditions of formation of productive zones. In accordance with the present invention also provides that at the time, as the extraction of oil has already begun in one area productive area, to another area at a time can be slow dilution of the oil with a solvent, and thus, it is not always necessary to wait a maximum dilution of oil in the reservoir to begin the stage of extraction in cases where the process of mining in one part affects the liquefaction solvent in another part.
However, if the maturation stage is over too quickly, it is likely that the extractable fluid will consist mainly of a solvent containing only a small amount of oil. This result is typical of many methods of displacement from the reservoir in accordance with the prior art, where due to low viscosity of the displacing fluid (i.e., the solution�a dye or a pair, or water, or gas) the majority of the target oil is not involved in the process. Consequently, high concentration of solvent in the extracted fluid can be an effective diagnostic criterion that allows to test if there was a length of maturation, at least in a cylindrical volume surrounding development well.
The next step of the present invention is the step 56 of extracting oil. If we take, for example, that the volume of injected solvent was sufficient to achieve a certain volume content of solvent in the oil, extracted fluids should be carefully monitored to keep track of, does not exceed the content of the solvent of this setpoint. If the volume content of the liquid solvent is extracted in a mixture of solvent/oil is higher than the expected, then the solvent Raziel not all hard-to-recover oil, which should be available for dilution, and, apparently, a significant amount of oil had remained unaffected. If the rate of extraction of liquid solvent is too high compared to the rate of extraction of oil, so you should restrict the rate of oil production or again to isolate the reservoir to extend the stage 54 of maturation, to get a more complete liquefaction of oil.
As stated above, �Tapa oil recovery remove the solvent, dissolved in oil. In accordance with the present invention the solvent can be re-injected into the formation, or may be sold or delivered to the next place of extraction of oil, or even flared, or as a gaseous fuel.
In accordance with the present invention, if it is desirable to maintain a sufficiently high concentration of solvent in the oil to lower the viscosity of the oil to a specific predetermined value, the pressure in the extraction process may also be enhanced by recycling of the solvent or by additional injection of solvent. It gives the possibility to increase the ratio of solvent to oil over time, which may be useful to maintain high speeds without excessive oil production of consobrina after depletion of the reservoir. However, additional pumping of the solvent also increases the risk of deasphalting solvent and a possible failure of the formation. To maintain the pressure in the late stage of oil extraction, when the amount of solvent in the oil is enough and blocking of solvent at the interface is not the problem, it may be preferable to fix prestorage fluid, such as methane, nitrogen, etc.
The last step of the method of extraction is the stage 58 of the purge and the extraction solvent�'el. If there are restrictions on the pressure, such as the presence of an active aquifer, it may be desirable to solvent displacement by another gas, such as methane, carbon dioxide or nitrogen.
Fig.4 shows a graph of the typical viscosity of heavy oil from the degree of dilution of oil by solvent and temperature of the solvent. This graph allows us to estimate the decrease in viscosity when applying a specific amount of solvent to a specific heavy oil. The graph also shows that the viscosity of pure solvent can be 100,000 times smaller than the viscosity of the natural oil, so that the step 54 of maturation, allowing the solvent enough time to thin the oil, it is very important to prevent nebulette oil in the liquefaction process solvent. In accordance with the present invention similar graphs can be constructed for other combinations of oil and solvent. The beginning of the arrows 60 and 62 represent the values of the viscosity of pure unheated solvent and heavy oil in the injection fluid, and arrow heads indicate that the viscosity of the homogeneous mixture of the oil/solvent will be somewhat greater than 100 CPS. The graph shows that for this example, the temperature rise is small, due to the latent heat of condensation. However, in this particular case, it is clear that comfort�tion temperature would not lead to a substantial reduction in viscosity. The graph of Fig.4 also allows us to predict the viscosity of the homogeneous mixture of the solvent/oil depending on the volume content of solvent. For example, increasing the volume of solvent to 20% will lead to a decrease in the viscosity of the mixture 10 times, up to about 13 CPS.
Fig.5 shows a curve 64 of the expected vapor pressure of the preferred solvent ethane, depending on the volume concentration of ethane dissolved in heavy oil. Saturation pressure for pure ethane at 24°C is about 4100 kPa (absolute), i.e., the injection amount is the minimum required to fill the volume of voids with a liquid equivalent of ethane. The total pressure is slightly higher, depending on the amount of methane remaining in the voids at the end of the first stage of creation of voids. However, at 10% volume concentration of ethane in the oil vapor pressure of ethane is only 1600 kPa (absolute). This means that if at the stage of maturation is obtained a homogeneous mixture of oil and solvent, the partial pressure of ethane drops to 4100 kPa (absolute) to about 1600 kPa (absolute). Thus, in accordance with the present invention, the pressure in the reservoir will be released to the asymptote at the value of about 2500 kPa below the pressure of injection. Specialists in the art will understand �implies, the reservoir is limited and there is no pressure maintenance through the aquifer or gas cap.
Interestingly, if we assume that the solvent penetrates so deeply, as shown by computer simulation Das and Okazawa, the deviation of pressure can be interpreted only as the loss of solvent in the absorption zone and, therefore, should limit further downloading of solvent and start removing the solvent as quickly as possible. This is described in the patent 2494391, which apply very high pressure gradients to maximize the speed of downloading and extracting the diluent from the formation.
Fig.6 shows the approximate time required for stage 54 of maturation, depending on the distance that must pass the solvent front to the producing zone 24 for layers containing in situ hydrocarbons from bitumen to conventional oil, with curves 70 for bitumen, 72 for heavy oil and 74 for conventional oil. Figure 6 also shows the benefit of the initial stage 50 of the creation of voids, which increases the amount of solvent that can be safely pumped into the target formation at stage 52, so that the distance that the solvent must diffuse is reduced and the time required for maturation stage 54 also decreases. For example, you can expect �then doubling the amount of solvent is from 10% to 20% may provide a more effective dispersion of the solvent in the target area of enhanced oil recovery and to halve the time of ripening.
It is assumed that the conventional oil reservoir with productive zone 24 contains oil with a viscosity of 10 CPS, and has a permeability of 100 millidarcy. It is assumed that the permeability of heavy oil is 1 Darcy and oil viscosity is 10,000 CPS, and the permeability of the bitumen is 5 Darcy and a viscosity of 6 million centipoise. The duration of stage 54 of maturation is determined by the speed with which a surface of discontinuity in the concentration progresses through the formation. The advance rate is derived from a correlation presented by the author of an invention in the previous patent application 2591354.
Fig.6 also presents another curve 75 characterizing stationary counterflow diffusion, which is the second way to estimate the diffusion rate of the solvent in the reservoir. Curve 75 suggests that the penetration of the solvent, or the distance of advance is proportional to the square root of time of maturation for this model. Counterflow model gives a slightly higher penetration rate for short distances and significantly lower for long distances for a specific heavy oil. Although in order to select the specific model of the permeation rate of the solvent is required to calibrate the well, both models lead to the conclusion that the length of penetration of RA�solvent for relatively short distances of promotion can be very long (years or even decades). This allows you to evaluate the advantages of the present invention, which consists in attaining a wide dispersal of the solvent by removal of the blockers of the solvent and to minimize the distance that must pass the solvent to coming in contact with hard-to-recover heavy oil.
Fig.7 shows the curve 76 the expected speed of oil recovery by gravity drainage to horizontal wells with a length of 800 m with a 10-meter productive area for heavy oil with viscosity, component 10000 CPS at initial reservoir conditions. This graph shows that the average permeability of 1 Darcy is the expected speed of recovery is only about 10 m3/day. Fig.7 shows the importance of obtaining a sufficient concentration of solvent in oil; doubling the concentration of the solvent oil from 10% to 20% by volume increases the speed of recovery in 15 times. Moreover, the volumetric concentration of the solvent is below 10% is completely useless.
Fig.8 shows the curve 78 of the expected rate of oil recovery by gravity drainage wells and oil of Fig.7, but with an average permeability 7 Darcy. Fig.8 shows that for download of the solvent in a volumetric concentration of 10%, with an average permeability 7 Darcy expected with�Orest oil recovery is 100 m 3/day. This means that, in accordance with the present invention it is highly preferred productive zones of higher permeability, as they reduce the amount of solvent needed to obtain a given rate of oil recovery. Preferably most of the solvent is recovered and reused, which greatly helps to offset its cost.
Fig.9 by the curve 80 shows the calculated solvent for heavy oil reservoir with permeability 7 Darcy in Fig.8, given the fact that the solvent is eventually removed or extracted from the mixture of solvent/oil, or during the final purge. Fig.9 shows that the cost of solvent per 1 m3oil recovery decreases with increasing volume concentration of solvent in the produced mixture solvent/oil. This unexpected result shows that the high cost of the solvent in accordance with the invention is more than compensated by the reduced time of extraction (faster retrieval) tight oil, because time costs money, too. Hence, here we see that the method is aimed to be cheap in relation to the number of the employed solvent, as in most cases in the prior art, is not Economics�m for the maximum value. Figure 9 further emphasizes the benefit of the initial stage of creation of voids in accordance with the present invention, which allows to maximize the volume of solvent delivered close to tight oil.
Fig.10 shows the curve 82 dependence of the pressure in the reservoir from time to time in the case where the solvent is extracted together with the oil, then pumped back into the reservoir. As shown by the slope of the graph, the pressure in the reservoir decreases slightly over time during the productive phase. Clearly, this reduction is not due to the further diffusion of the solvent into the oil, and removing produced fluid from the production zone in a well-confined layer in accordance with the present invention.
Curve 84 in Fig.11 shows the dependence of the aggregate injection of solvent and the volume of production of the present invention, as applied to the reservoir with an active aquifer or reservoir pressure of another type. The formation of this type is less desirable because the quality of thin the oil with a solvent and the appropriate time of ripening cannot be estimated using remote measurement of the pressure in the reservoir, as the pressure in the reservoir is effectively limited to a constant value. It should be understood that the extraction method in accordance with �aseason invention, however, it may be successfully applied to the formation of this type, but the assessment of the relevant time of maturity will be less reliable, it may largely be based on the estimation of the ratio of solvent to oil in the produced fluids and to improve this assessment will be useful for detailed study of reservoir heterogeneity.
Now become clearer advantages of the present invention. Although the amount of solvent introduced into the reservoir, especially during the preparation phase in accordance with the present invention, the concentration of solvent in the extracted fluid is very small, since the primary and secondary extract is often ranges from 10% to 20% of the original oil contained in the reservoir. Consequently, the number and value of solvent extracted together with the oil, are much less than in the methods in accordance with the prior art, described for example in patent 2299790. In accordance with the present invention in some cases more economical can be a complete abandonment of solvent extraction to minimize the capital cost of field installation. Another advantage of the present invention is that due to the relatively low ratio of solvent/oil, is expected to be weak deposition of asphaltenes or the lack of it. With the other hand, it is expected only a slight improvement in crude oil or the lack of it. Furthermore, the method according to the present invention is not a continuous process, since the solvent must be completely downloaded almost from the beginning, i.e. at the stage of maturation is not expected to be significant operating costs.
In addition, you can use different solvents. Fig.6 shows that when the duration of maturation, component one month, the preferred solvent can move 5 meters in a conventional oil reservoir. However, it is expected that diffusion of unheated solvent on the same 5 meters in a very viscous bitumen oil Sands will require 6 years or more. Additional commercial benefits include the opportunity to purchase land with oil wells and operating equipment at low prices, if the development of the depleted heavy oil reservoir is recognized as uneconomical.
Additional new aspects include, inter alia, the following:
- stage cleaning/removal of impurities to create voids and remove unwanted contaminants such as water and methane;
- the use of solvent sensors to monitor the penetration of the solvent at the stage of removal of impurities;
- stage discharge pressure to achieve pressure� saturation allowing you to download in emptiness the maximum amount of solvent;
- maturation step with monitoring of pressure drop in the reservoir to control the growth of mixing; and
control the ratio solvent/oil for the detection and suppression of consobrina and nebulette solvent in contact with the oil.
The advantage of the application of gravitational drainage in accordance with the present invention is that it provides for the extraction of 60% or more of the original oil in place. If the primary extract extract provides only 10% of the original oil in place, subsequent gravity drainage solvent can provide the total oil recovery, 5 or more times greater than that which is obtained during primary and secondary production cycles.
Example: Consider Lloydminster heavy oil, where the viscosity of the natural reservoir is 10,000 CPS, permeability, Darcy is 7, and the thickness of the productive zone is 10 m. the Extraction after the primary cold heavy oil production with sand and subsequent flooding is 270 celeberrima, representing 15% of the original oil in the reservoir conditions. At the first stage of the present invention the pressure in the reservoir fell to an absolute pressure of 500 kPa after removal of blockers of a solvent consisting of a salt in�of water and methane. Then the solvent in the form of steam was injected to facilitate movement of the movable water and methane from the reservoir and ensuring the penetration of vapors of the solvent accessible voids of the formation.
This phase of drainage allows you to create voids, the volume of which is 15% of the first space and which can then be filled with a solvent. Was injected amount of ethane solvent sufficient to fill the 15% voids with a liquid equivalent of solvent (i.e., equivalent to 270 liquid kilometres ethane). Assume that the voids created during the initial extraction, were created mainly in the lower part of the productive zone, then the solvent must diffuse approximately 10 m, the mixture became homogeneous over the entire height of the reservoir. The necessary duration of maturation was evaluated approximately one year. After injection of the solvent, the pressure in the reservoir was measured to detect lowering it with 4600 kPa to 3000 kPa.
Then the reservoir was put into operation through a horizontal well, and the calculated initial rate of oil extraction was 250 m3/day (1500 bbls/day) or more. The extracted fluids are carefully controlled to ensure no shorting of the solvent. If we accept that the liquefaction solvent tight oil is �auromere, it can be estimated that in the next three years can be extracted additionally approximately 820000 barrels of heavy oil. By the end of the production cycle, the rate of recovery falls and starts the purge cycle to extract as many of the remaining solvent. It is estimated that at the end of the production cycle each barrel pumped solvent extracts the 3 extra barrels of oil. At current prices, the cost of ethane solvent is 13 USD. per barrel, and oil can be sold at $ 60. per barrel. Thus, the cost of the solvent in the absence of its removal is approximately $ 4. one barrel of oil, or -6% of the cost of oil.
Specialists in the art it is clear that, although the invention is described in relation to certain preferred variants of its implementation, there are various options and modifications without deviation from the essence of the present invention limited by the appended claims of the invention. Some of them have been described above, others will be clear to experts. For example, the solvent can be pumped into the source through the vertical bore, at the stage of loading of the solvent it can also be injected through a horizontal well or even simultaneously through both �of Kvasiny. The present invention is limited only by the appended claims of the invention.
1. The multistep method of in situ extraction of heavy oil from formations with the use of a solvent, comprising the following steps:
and. removing liquids and gases from the contact areas with heavy oil to increase the surface section of unexploded heavy oil to be in contact with the solvent;
b. injected solvent in vapor form in these zones to increase the pressure in the reservoir up to the formation of a sufficient amount of a solvent in liquid form to provide contact with an increased surface section of heavy oil;
C. isolate the reservoir for a time sufficient to allow diffusion of the solvent in uncovered oil through the surface of section in phase of maturation, to produce a mixture of solvent and oil with reduced viscosity;
d. measure one or more parameters of a formation to determine the degree of dilution solvent uncovered oil in the reservoir, and
E. begin extracting oil from the reservoir based on gravity drainage after the mixture viscosity will be low enough to allow it to flow through the formation to a production well.
2. A method according to claim 1, characterized in that at the stage of injection of solvent from the area of the extracted oil displace the blocking of solvent fluid�STI and gases.
3. A method according to claim 1, characterized in that the isolation stage comprises a stage of pressure control to monitor the degree of dilution of heavy oil solvent.
4. A method according to claim 1, characterized in that the phase retrieval based on gravity drainage involves removing a mixture of solvent/oil from horizontal wells.
5. A method according to claim 1, characterized in that the solvent is propane or ethane.
6. A method according to claim 1, characterized in that the solvent is essentially pure, to avoid freezing thin the oil with a solvent blockers solvent.
7. A method according to claim 1, characterized in that it further includes the step of extracting the solvent from the extracted mixture.
8. A method according to claim 1, characterized in that in the extraction process is carried out maintaining the pressure in the reservoir.
9. A method according to claim 1, characterized in that in the extraction process do not exercise pressure maintenance in the reservoir.
10. A method according to claim 1, characterized in that it further includes the step of measuring the concentration of solvent in the extracted mixture and control the speed of extraction on the basis of the measured content of the solvent.
11. A method according to claim 1, characterized in that it further includes the step of gas injection for pressure maintenance in the reservoir after reaching DOS�sharpening the degree of dilution of heavy oil with a solvent in situ.
12. A method according to claim 1, characterized in that the stage of removal of the movable fluids includes removal of liquids and gases already present in the reservoir.
13. A method according to claim 12, characterized in that the movable fluid is removed through already existing in the reservoir wells.
14. A method according to claim 12, characterized in that the movable fluid is removed by pumping.
15. A method according to claim 1, characterized in that it includes the final stage of the purge reservoir to capture the remaining solvent.
16. A method according to claim 1, characterized in that at the stage of injection of solvent in vapor form, the solvent is gradually injected into the reservoir to achieve a high concentration of liquid solvent in the reservoir.
17. A method according to claim 1, characterized in that the cycle is repeated to extract additional oil from the reservoir.
18. A method according to claim 1, characterized in that it further includes calculating the expected speed of penetration of the solvent, compare the rate of penetration of the solvent with the measured pressure decrease and start extracting oil from the reservoir after the calculations showed that a predetermined amount of solvent has moved into the formation.
19. The multistep method of in situ extraction of heavy oil from formations with the use of a solvent, comprising the following steps:
and. removed from the reservoir by removing impurities from the reservoir b�of acathrow solvent to create voids;
b. pumped into the voids of the solvent in vapor form to increase the reservoir pressure up to the formation of a sufficient amount of a solvent in liquid form to fill the voids;
C. isolate the reservoir for a time sufficient to allow diffusion of the solvent in uncovered oil near the voids at the stage of maturation to produce a mixture of solvent and oil with reduced viscosity;
d. measure one or more parameters of a formation during the maturation stage to assess the extent of the liquefaction solvent uncovered oil in the reservoir, and
E. begin extracting oil from the reservoir based on gravity drainage after the mixture viscosity will be low enough to allow it to flow through the formation to a production well.
FIELD: oil and gas industry.
SUBSTANCE: method involves displacement of the first fluid on a hydrocarbon basis, which is present at a non-cased interval of a well shaft, with the second fluid, contact of the second fluid to acid natural formation fluid so that the third fluid is formed, where the second fluid contains aqueous liquid dispersed as a disperse phase in oily liquid, and surface active substance (SAS) based on amine and chosen so that the above contact performs protonation of at least some part of SAS with formation of the third fluid included in an emulsion containing oily liquid reversely dispersed as a disperse phase in aqueous liquid, where at least 40 vol % of any solid substances that do not refer to a proppant and are present in the fluid are water-soluble at pH that is lower than or equal to 6.5, and SAS has the above said structure. An underground well treatment system. The fluid containing a reversible invert emulsion containing an aqueous liquid dispersed as a disperse phase in oily phase and the above SAS.
EFFECT: improving destruction efficiency of a filter cake.
20 cl, 6 dwg, 3 tbl, 2 ex
FIELD: oil and gas industry.
SUBSTANCE: under the method of development of oil deposits with nonuniform permeability comprising successive injection via the injection well of the water suspension containing polymer, mud powder and SAS solution, prior to the suspension injection in the deposit the initial intake of the injection well is determined under pressure in water line ands water mineralisation; in water with salinity level 0.15-40 g/l complex action SASs with pour point not exceeding minus 30°C and kinematical viscosity 35-50 sSt are used, i.e. water-alcohol solution of non-ionic SAS-monoalkyl esters of PEG at the following ratio wt %: specified SAS 0.001-1.0, specified water rest, suspension and SAS solution are injected in volume ratio (1-3):1 depending on initial intake of the injection well - at intake 200-400 m3/day - 1-2:1, 400-500 m3/day - 2-3:1, over 500 m3/d - 3:1, between suspension and SAS solution water with salinity level 0.15-40 g/l or water suspension of polyacrylimide with concentration 0.0001-0.1 wt % is injected. Under another option during this method in water with salinity level 40-300 g/l the complex SAS with pour point minus 40°C max is used, containing complex action SAS with pour point minus 30°C max. and kinematical viscosity 35-50 sSt - water-alcohol solution of non-ionic SAS - monoalkyl esters polyoxyethylene glycol 90 wt % and alkyldimethylbenzylammonium chloride 10 % at following ratio of components in wt %: specified SAS 0.001-1.0, specified water - rest, suspension and SA solution are injected to the deposit in volume ratio (1-3): 1 depending on initial intake of the injection well at water line pressure - at intake 200-400 m3/day - 1-2:1, 400-500 m3/day - 2-3:1, over 500 m3/day - 3:1, and between suspension and solution the water with salinity level 40-300 g/l or water suspension of polyacrylimide with concentration 0.0001 0.1 wt % are injected.
EFFECT: increased oil recovery of the deposit.
2 cl, 4 ex, 4 tbl
FIELD: oil and gas industry.
SUBSTANCE: under method of oil deposit development comprising determination of the injection well intake, oil recovery via the production wells, and injection via at least one injection well of the water dispersion of the water-soluble polymer and alkali metal hydroxide, this dispersion contains in wt %: water-soluble polymer 0.01-0.05, alkali 0.5-1.0, at definite intake values of the injection well the specified dispersion is injected until injection pressure increasing by 20-30%, its flushing in the deposit by the injected water in volume of tubing plus 1.0 m3, alkali composition in volume 10-30% of volume of injection of the specified dispersion is injected until specific intake decreasing by 10-20% and achievement of the injection pressure not exceeding the maximum permitted pressure on production string and production deposits, the specified compositions at specified water salinity under each of three options, and flush by water in volume 10-15 m3.
EFFECT: increased oil recovery of deposits and watercut reduction of production wells, spreading of process abilities.
3 cl, 1 ex, 2 tbl
FIELD: oil and gas industry.
SUBSTANCE: method envisages the usage of aqueous solutions of binary mixtures - inorganic or organic nitrate or hydrate of alkali metals, which are injected through individual channels. The method includes the mounting of equipment in wells at the selected area of a deposit. Each well is equipped with devices to control the temperature, pressure and composition of reaction products in a real time mode. Formation areas in vicinity to the well with a volume of at least 20 m3 are heated preliminarily up to a temperature of at least 100°C by injection of at least 2 t of binary mixture reagents. Cyclic heating of the formation area in vicinity to the well with a volume of at least 100 m3 and weight of 250 t is made up to a temperature of at least 140°C due to a reaction of at least 12 t of the binary mixture reagents. At that the first level of explosion safety is ensured by the alternation of injection of saltpetre solution portions, 1 t each, with portions of industrial water of at least 0.05 t each. The second level of explosive safety in the borehole is ensured by the continuous control and monitoring of the reaction process with the temperature limitation in the well bore below the pre-blasting temperature. This temperature is determined against signs of the reaction self-acceleration at recorded charts of time-temperature and time-pressure curves. In case of these signs the injection of a saltpetre decomposition initiator is stopped to the well. Further injection of the saltpetre solution with the weight of at least 10 t is made to the preheated formation. At that the third level of explosive safety is implemented in the reaction process in the formation, which is catalysed by the heat accumulated during the previous cycles. The third level of explosive safety is ensured by a ratio of the weight of the saltpetre injected to the pores and fractures of the formation to the weight of the rock. The ratio is equal mainly to 1 to 20. Low explosive probability, close to zero, is ensured by a mixture of 95 wt % of rock and 5 wt % of saltpetre. The injection of reagents at all cycles is made at continuous temperature control in the reaction zone and pressure and temperature control in the zone near the packer and in the process of the reagents injection for the purpose of timely cessation of the reaction when the parameters of the reaction exceed limits of permitted modes.
EFFECT: improved efficiency of oil production at worked-out deposits with an increased production safety.
FIELD: oil and gas industry.
SUBSTANCE: this invention is related to production of oil-in-water emulsions with low viscosity during operations with oil. The method for reduction of apparent viscosity for hydrocarbon fluids occurring at oil extraction and transportation includes contact of the above hydrocarbon medium with effective quantity of composite containing at least one polymer with at least 25 mole percent of cationic monomers. The invention has been developed in dependent claims.
EFFECT: increase in oil production.
15 cl, 9 ex, 4 tbl, 4 dwg
FIELD: oil and gas industry.
SUBSTANCE: treatment method of underground hydrocarbon-containing formations involves the following: a) provision of a composition including a thickening initiator measuring pH, and a polymer capable of hydration in a certain pH range; b) pumping of a composition with pH value beyond the limits of the above pH range; c) activation of an action of pH thickening initiator for displacement of pH composition to the above range of its values, and d) provision of a possibility of increasing viscosity of the composition and shaping of a plug. According to another version, a processing method of underground hydrocarbon-containing formations involves the following: a) provision of a composition containing a polymer capable of hydration in a certain pH range; b) pumping of the composition with pH value beyond the limits of the above pH range; c) provision of a pH changing thickening initiator; d) activation of the action of the thickening initiator for displacement of pH composition to the above range of its values, and e) provision of a possibility of increasing viscosity of a composition and shaping of a plug. The invention has been developed in dependent claims.
EFFECT: improving efficiency of initiation and control of plug formation.
15 cl, 5 ex, 3 dwg
FIELD: oil-and-gas industry.
SUBSTANCE: invention relates to oil production, particularly, to from underground oil deposits. In compliance with this invention, at least one production well and one injection well can be used. Temperature distribution in the zone between said wells is analysed. In case temperature is distributed between said zones so that minimum temperature makes at least 20°C, maximum temperature does not exceed 320°C, while their difference makes at least 20°C, aqueous gel-forming preparations are injected via injection well that contain one or several chemical components. These preparations after injection in the deposit form gels under the effects of deposit temperature. Said preparations differ in type and/or concentration of chemical components. Chemical components and/or their concentration are selected to make gel-forming temperature and/or geol-forming time of the second and, if required, any other injected portion, differ from portions injected there before.
EFFECT: higher efficiency of oil extraction due to levelling of injectivity.
19 cl, 4 tbl, 7 dwg
FIELD: oil and gas industry.
SUBSTANCE: according to the method the first and second banks are injected through a hydrocarbon- or water-based displacement fluid to the designed area of the well. At that the availability of a residual saturation area is determined in productive formations with loose - loosely cemented porous and/or fractured reservoirs. The availability of an ultimate water saturation area, an undersaturated transition interval with a film water area and an intensive flow of water diffuse layers and a subarea of high oil content is determined. The availability of ultimate oil saturation is determined. The availability or unavailability of shale barriers at boundaries of the ultimate water saturation area and the transition interval is considered. The water saturated area is cut from the ultimate oil saturation area and an oil inflow is ensured to the productive formation from the subarea of high oil content. Injection is made to the design area of a producer and/or injector. At that the displacement fluid in injected in a quantity of 0.1 up to 500% of the first bank volume. The second bank is injected in a quantity of 0.1-250% of the first bank volume. Polymer resin is used as the first bank. Polymer hardener is used as the second bank. Upon injection the well is transferred to the hydrocarbon inflow mode.
EFFECT: increased efficiency of the method.
24 cl, 47 ex, 1 dwg
FIELD: oil and gas industry.
SUBSTANCE: in the development method of a non-homogeneous oil formation that includes injection to the formation of an aqueous solution of polyacrylamide (PAA), chrome acetate and magnesium oxide, the solution contains additionally a glass or basalt reinforcing microfiber pretreated by a 1-5% aqueous solution of AF9-6 or AF9-12 or constructional reinforcing microfiber (CRF) with the following concentration of components in the solution, wt %: PAA 0.3-1.0, chrome acetate 0.03-0.1, magnesium oxide 0.015-0.07, the above fibre 0.1-0.5.
EFFECT: increased efficiency of the method.
1 dwg, 2 tbl, 1 ex
FIELD: oil and gas industry.
SUBSTANCE: invention is related to hydrocarbons from underground formation. The method of raw oil recovery from a reservoir, including at least one oil-bearing porous underground subsurface with connate water and oil in cavities of the rock pores having API density less than 25° and containing suspended undissolved solids (SUS), lies in injection of input water to the rock, wherein the input water contains SUS and total content of dissolved solids (TCDS) in it is equal to 30000 ppm or less, the ratio of total content of multivalent cations (MC) in the input water to total MC content in connate water is less than 0.9, and receipt of water-in-oil emulsion inside hydrocarbon-bearing rock; total SUS content in the input water and raw oil is sufficient for SUS content in emulsion to be at least 0.05% per emulsion mass and SUS in the input water is equal to at lest 0.05 kg/m3 and average size of particles is 10 mcm or less, raw oil in pores contains at least 0.05% of SUS with the same average size, total acid number (TAN) of oil is at least 0.5 mg of KOH/g, asphaltene content in it is at least 1-20 wt % and resin content is 5-30 wt %. The invention also suggests increase in recovery degree of raw oil from the above reservoir with connate water and oil in cavities of the rock pores having API density less than 25° and containing SUS with average diameter less than 2 mcm in quantity equal to at least 0.01 wt %, with TAN of at least 0.5mg of KOH/g, asphaltene content of at least 1 wt % and resin content of 5-30 wt %, and the input water is injected to the rock in order to receive water-in-oil emulsion in it, where this water is collected by determination of MC content in connate water, extraction of the input water containing dissolved solids (DS) in quantity less than 30000 ppm, the total MC content is such that the ratio of total MC content in the input water to total MC content in connate water is less than 0.9 and contains at least 0.05 wt % of SUS with average diameter less than 2 mcm in the above water. Invention has been developed in dependent claims.
EFFECT: improving washing efficiency and reducing quantity of residual oil in the rock.
9 cl, 3 ex, 4 dwg, 4 tbl
FIELD: oil and gas production.
SUBSTANCE: invention provides a method of developing oil pool allowing production of oil from water-rich oil reservoir under difficult geological-tectonic conditions in the last development stage. In the method, neutral salt of carbonic acid and acid solution are forced into formation through injecting well with water generated in gas-liquid fringe created in formation. After pumping of neutral salt of carbonic acid, acid solution is pumped by portions alternating with water pumping. Before pumping of acid solution portions beginning by at least second portion, selective insulation of high-permeable formation intervals is performed. Aforesaid neutral salt of carbonic acid utilized is sodium carbonate aqueous solution or aqueous suspension of calcium carbonate and aforesaid acid solution is aqueous hydrochloric acid solution. Selective insulation of high-permeable formation intervals involves use of freshly prepared controllable viscoelastic composition containing water-soluble acrylic polymer, cross-linking agent, thermal stabilizer, surfactant, and water. Summary concentration of acid solution is determined from concentration of neutral salt of carbonic acid on the base of stoichiometric proportions.
EFFECT: increased efficiency of maintaining formation pressure and thereby oil recovery of formation due to leveled displacement front and reduced probability of the rupture of formation rock backbone, and simplified control of phase state of gas-liquid fringe by changing pressure of pumped acid solution portions.
FIELD: oil and gas production.
SUBSTANCE: invention aims at increasing productivity of oil- and gas-producing and injecting wells exposing high-temperature low-permeable oil reservoirs. In the treatment method according to invention including forcing enzyme substrate and separate enzyme into formation and creating conditions to enzymatically convert substrate into acid, geologic and productive characteristics for each interval of bottom zone are determined in order to pick out low-permeable intervals of oil reservoir for treatment, whereupon properties of enzyme substrate and separate enzyme as well as conditions for their pumping are chosen. Substrate utilized in the method is head fraction of methyl- and/or ethyl-, and/or butyl acetate production, to which aliphatic alcohols are added, and enzyme is an acid solution. Substrate is pumped simultaneously and/or before, and/or after pumping of enzyme, after which well is closed for some time and then opened and placed under predetermined operational conditions.
EFFECT: enhanced efficiency of acid treatment due to increased phase permeability for oil and deepness of active acid-treated zone of low-permeable oil reservoirs.
25 cl, 1 tbl, 3 ex
FIELD: oil and gas production.
SUBSTANCE: invention is intended for use during development of oil pools at different waterflooding phase for intensifying functioning of producing wells and increasing current oil recovery of formation. Composition contains, wt %: liquid hydrocarbon 10.0-20.0, oil-soluble surfactant 0.3-5.0, water-soluble or water-oil-soluble surfactant 0.1-1.0, superfine hydrophobic material 0.1-2.0, and water (the rest). Composition may further contain 0.3-5.0% calcium chloride. Oil recovery is increased owing to hydrophobization of formation structure, reduction of surface tension in water/rock/oil phase boundary, increase in detergent power of polluted surface, increase in composition viscosity, and increase of relative permeability of the formation for hydrocarbon phase as compared with water phase.
EFFECT: increased oil recovery.
2 cl, 2 tbl, 2 ex
FIELD: oil and gas production.
SUBSTANCE: composition contains 0.05-2.5% of hydrophobic power, 0.05-10% of ethylene/vinyl acetate copolymer, and organic solvent. Composition intensifies oil production owing to increased effective radius of formation bottom area treatment, prevention of moistening inversion effect upon fall of hydrophobic agent concentration, and, consequently, decreased volume of simultaneously produced water.
EFFECT: increased oil production, prolonged overhaul period, improved environmental safety, and lowered production expenses.
2 tbl, 3 ex
FIELD: oil and gas extractive industry.
SUBSTANCE: method includes drilling product and force wells, forcing gas and water through force wells into separate zones of productive bed and extraction of hydrocarbons from product wells, forming separate gas, water and hydrocarbon saturated areas with major contents of respectively gas, collected therein for later use, water and hydrocarbons, periodical pumping of collected gas from formed gas saturated zones to water saturated zones, periodical pumping of water to gas saturated zones is performed. It is possible to pump collected gas to water saturated zones in form of gas-water mixture. It is possible to pump in passing gas of current deposit. It is possible to pump hydrocarbon or non-hydrocarbon gas from other sources. It is possible to pump water with admixture of specifically selected chemical reagents or compositions thereof. When gas content in water saturated zones reaches from 0.1 to 28% from water content in water saturated zones it is reasonable to generate resilient waves with frequency within range from 0.0001 to 45 KHz and amplitude within range from 0.02 to 2.8 MPa. It is reasonable to pump gas and water to separate areas of productive bed with concurrent generation of resilient waves in there with frequency within range from 0.0001 to 45 KHz and amplitude within limits from 0.02 to 2.8 MPa.
EFFECT: higher efficiency.
7 cl, 5 dwg
FIELD: oil extractive industry.
SUBSTANCE: method includes pumping of Sulfacella water dispersion into bed through force well and extraction of oil through extracting well, said dispersion additionally containing non-ionogenic surfactant AF9-12 with following ratio of components, in percents of mass: Sulfacella 0.5-1, AF9-12 0.01-0.1, water- the rest, while, before pumping of said dispersion mineralized water is pumped with total mineralization until 290 g/l in amount of 10% from volume of said dispersion, when pumping said dispersion prepared in fresh water, drain water is previously pumped, and when pumping said dispersion made from drain or bed water, bed water is previously pumped. For preparation of said dispersion fresh, drain or bed water is used with mineralization till 290 g/l.
EFFECT: higher efficiency.
2 cl, 2 tbl
FIELD: oil and gas extractive industry.
SUBSTANCE: method includes examination of operation well for gas-condensation and periodical cleaning of face-adjacent well area from precipitating hydrocarbon condensate by pumping hydrocarbon condensate solvent into bed, exposure of well for period of condensate dissolution and following removal of received solution from face-adjacent area during well launch, as solvent binary mixture is used with unlimited mutual solubility of components, while at least one of them has unlimited mutual solubility with hydrocarbon condensate, and relation of binary mixture components is determined from previously built phase diagram of three-component system, formed during dissolution of hydrocarbon condensate. As binary mixture with unlimited mutual solubility of components a mixture of acetone and methanol is used, or chloroform and methanol, or chloroform and aniline, or chloroform and acetone.
EFFECT: higher productiveness.
2 cl, 3 ex, 6 tbl, 2 dwg
FIELD: oil and gas extractive industry.
SUBSTANCE: method includes placing water solution of carnallite ore, either modified, concentrated, or mixtures thereof, said solution is used at maximal for well temperature conditions concentration and is pumped in amount, necessary and enough for forming a hydraulic column in well shaft above ceiling of productive bed and along remaining shaft height well is filled with water up to mouth. Carnallite ore used has composition, in percents of mass: potassium chloride 20.5-21.5; sodium chloride 19.5-22.5; magnesium chloride 24.0-27.0; crystallization water 29.5-30.5. Modified ore has composition, in percents of mass: potassium chloride 23.0-29.5; magnesium chloride 31.8-46.0; crystallization water - the rest. Said water solution is prepared by dissolving ore in fresh technical water, drained from oil preparation plants, or in bed water. In case of dissolving in bed water, the latter is pumped from well at temperature 60-90°C. During perforation of well, value of technological liquid hydraulic column above productive bed ceiling is taken equal to (1.03-1.07)-(1.05-1.1)Pb, where Pb - productive bed pressure. Water solution of carnallite ore is used at density 1.23-1.37 t/m3. During use of said solution as working body of force wells it is used at density 1.05-1.20 t/m3, and solution also contains swelling inhibitor for argillaceous component of oil and gas bearing bed, like oxyethylenedendiphosphone acid, in amount 0.05-0.15% of used dissolved ore mass.
EFFECT: higher efficiency.
1 cl, 4 ex
FIELD: oil industry.
SUBSTANCE: method includes treatment of face area of oil bed by hydrophobic agent in organic solvent and pressing oil from collector with following delivery of oil from face area of product well for treatment of oil terrigenic bed, in form of hydrophobic agent solution of ethylene copolymer with vinylacetate in ethylbenzol or fraction thereof is used in relation 1:1 - 10, treatment of face area is performed with following ratio of components, in percents of mass: ethylene copolymer with vinylacetate 0.05-2.0, ethylbenzol or fraction 0.05-20.0, organic solvent - the rest.
EFFECT: higher efficiency.
2 tbl, 2 ex
FIELD: mining industry and alternative fuels.
SUBSTANCE: coal is affected by methanogenic consortium of microorganisms with culture medium utilizing continuous pumping of culture medium through wells and tank wherein methanogenic consortium of microorganisms with culture medium is placed. Tank is installed on the surface above wells and pumping of culture medium from the bottom of tank through methanogenic consortium of microorganisms. Process produces biogas and coal-water fuel.
EFFECT: increased yield of biogas to continuously effecting culturing of microorganisms.
1 dwg, 2 tbl