Process For Producing Natural Gas And Natural Gas Condensate From Underground Gas Condensate Deposits

- WINTERSHALL HOLDING GMBH

A process for producing natural gas and/or natural gas condensate from an underground gas condensate deposit comprising a gas mixture having retrograde condensation characteristics, comprising at least the process steps of: a) sinking at least one production well into the underground gas condensate deposit and producing natural gas and/or natural gas condensate from the underground production well through the at least one production well, b) injecting a solution (S) comprising a solvent and urea through the at least one production well into the underground gas condensate deposit, c) waiting for a rest phase in which the urea present in the solution (S) is hydrolyzed, d) producing natural gas and/or natural gas condensate from the underground gas condensate deposit through the at least one production well.

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Description

The present invention relates to a process for producing natural gas and/or natural gas condensate from underground gas condensate deposits comprising a gas mixture having retrograde condensation characteristics.

Gas mixtures having retrograde condensation characteristics, coming from the gas phase range, undergo partial condensation as the pressure is lowered isothermally and move back over to the gas phase as the pressure is lowered further. In general, retrograde condensation characteristics occur in a gas mixture whose temperature is above the critical temperature of the gas mixture. Natural gas mixtures comprising, for example, as well as methane, ethane, propanes and butanes, 2 to 20% by volume of heavy hydrocarbons (C5+; for example pentanes and hexanes) generally have retrograde condensation characteristics. The phase characteristics of gas mixtures having retrograde condensation characteristics are shown by way of example in FIG. 1.

In the development of gas condensate deposits comprising gas mixtures having retrograde condensation characteristics (also referred to as retrograde gas condensate deposits), the condensation characteristics of the above-described retrograde gas mixtures lead to problems. As natural gas and/or natural gas condensate is withdrawn from such deposits through a production well, the pressure in the deposit is reduced, while the temperature of the deposit remains very substantially unchanged. This quasi-isothermal lowering of the pressure in the deposit results in partial condensation of the natural gas present in the deposit. The lowering of the pressure is at its most marked in the vicinity of the production well (near-well zone). As a result of the partial condensation, especially in the region of the near-well zone, a liquid gas condensate is formed. This liquid gas condensate can block the near-well zone, greatly reducing the production rate of natural gas and/or natural gas condensate through the production well or even stopping it completely. This effect is particularly marked in the case of production of natural gas and/or natural gas condensate deposits having low permeability.

The blockage of the porous rocks in the region of the near-well zone greatly restricts the flow of natural gas and/or natural gas condensate to the production well or even stops it completely. Depending on the geological properties of the deposit and the pressure and temperature conditions in the deposit, the region in which the liquid gas condensate blocks the flow of natural gas and/or natural gas condensate to the production well may be 5 to 100 m in width. The region in which the blockage by the liquid gas condensate is brought about generally has a quasi-cylindrical shape with the production well in the center. The lowering of the deposit pressure which occurs as a result of the production and through the associated blockage with liquid gas condensate can in some cases even lead to the loss of the deposit.

The prior art describes processes which lead to a reduction in the formation of liquid gas condensate and to an improvement in the production of natural gas and/or natural gas condensate from a gas condensate deposit.

RU 2018639 describes a process for preventive avoidance of the formation of liquid gas condensate in a gas condensate deposit. The process described therein is also known as a “cycling process”. This involves, in the course of gas production, separating the heavy hydrocarbons (C5+) above ground from light hydrocarbons (for example methane, ethane and propanes). The light hydrocarbons are injected back into the deposit as “dry gas”, in order to increase the deposit pressure. The “cycling” process is very inconvenient and costly. In addition, this process cannot reliably avoid the formation of liquid gas condensate in gas condensate deposits.

SU 605429 describes a process for development of gas condensate deposits. In this process, the deposit is flooded with highly mineralized water. The high mineralization prevents the dissolution of gases in the flooding water and thus allows the displacement of the natural gas and of the natural gas condensate from the region of the near-well zone of the production well. A disadvantage of this process is the massive watering-out of the deposit as a result of the flooding water injected. In addition, the flooding water injected can itself lead to blockage of the near-well zone. This process does not enable effective enhancement of the production rates.

SU 1596081 and RU 2064572 disclose processes in which the gas condensate deposit is treated with seismic waves. The seismic waves are supposed to lead to an increase in the production rate from the gas condensate deposit. Especially in the case of low-lying deposits, this process is not very efficient.

RU 2415257 describes a process for stimulating the production rates of gas condensate deposits by means of electromagnetic waves. This process too is unsuitable, especially for low-lying deposits.

RU 2245997 discloses a process in which solvents are injected at cyclic intervals into the near-well zone, in order to dissolve the liquid condensate. The solvents used for this purpose are aqueous mixtures of acetone and methanol, chloroform and methanol or acetone and chloroform. A disadvantage of this process is that the aqueous mixtures introduced likewise lead to watering-out of the near-well zone. In addition, the process is associated with enormous costs due to the organic solvents used. The organic solvents used additionally lead to environmental problems resulting from their toxicity.

It was thus an object of the present invention to provide an improved process for producing natural gas and/or natural gas condensate from underground gas condensate deposits comprising a gas mixture having retrograde condensation characteristics. The process shall have the disadvantages of the prior art described above only to a reduced degree, if at all. The process according to the invention shall be inexpensive and simple to perform, and lead to an effective increase in the production rate of natural gas and/or natural gas condensate from gas condensate deposits after the near-well zone has been at least partly blocked by liquid gas condensate.

The object is achieved by a process for producing natural gas and/or natural gas condensate from an underground gas condensate deposit comprising a gas mixture having retrograde condensation characteristics, comprising at least the process steps of

    • a) sinking at least one production well into the underground gas condensate deposit and producing natural gas and/or natural gas condensate from the underground production well through the at least one production well,
    • b) injecting a solution (S) comprising a solvent and urea through the at least one production well into the underground gas condensate deposit,
    • c) waiting for a rest phase in which the urea present in the solution (S) is hydrolyzed,
    • d) producing natural gas and/or natural gas condensate from the underground gas condensate deposit through the at least one production well.

The object is also achieved by a process for producing natural gas and/or natural gas condensate from an underground gas condensate deposit comprising a gas mixture having retrograde condensation characteristics, comprising at least the process steps of

    • a) sinking at least one production well into the underground gas condensate deposit and producing natural gas and/or natural gas condensate from the underground gas condensate deposit through the at least one production well,
    • b) injecting a solution (S) comprising a solvent and urea through the at least one production well into the underground gas condensate deposit,
    • c) waiting for a rest phase in which the urea present in the solution (S) is hydrolyzed,
    • d) producing natural gas and/or natural gas condensate from the underground gas condensate deposit through the at least one production well.

The process according to the invention enables the effective enhancement of the production rate of natural gas and/or natural gas condensate from a gas condensate deposit in which the near-well zone has been blocked by liquid natural gas condensate. The process according to the invention has the advantage that it works with inexpensive and toxicologically safe substances. The process according to the invention prevents watering-out of the near-well zone of the gas condensate deposit.

Process Step a)

In process step a), at least one production well is sunk into the underground gas condensate deposit. The sinking of the at least one production well into the underground gas condensate deposit is effected by conventional methods known to those skilled in the art and is described, for example in EP 0 952 300. The production well may be a vertical, horizontal or directional well. The production well is preferably a directional well comprising a quasi-vertical and a quasi-horizontal section.

The gas condensate deposit comprises a gas mixture having retrograde condensation characteristics. Such gas condensate deposits are also referred to as retrograde gas condensate deposits. The gas mixture present in the underground gas condensate deposit comprises generally 80 to 98% by volume of light hydrocarbons and 2 to 20% by volume of heavy hydrocarbons. Light hydrocarbons are understood in accordance with the invention to mean methane, ethane, propanes and butanes. Heavy hydrocarbons are understood in accordance with the invention to mean hydrocarbons having 5 or more carbon atoms, for example pentanes, hexanes and heptanes, and possibly higher hydrocarbons. The terms “propanes”, “butanes”, “pentanes”, “hexanes” and “heptanes” are understood in the present context to mean both the unbranched hydrocarbon compounds and all branched isomers of the above hydrocarbon compounds.

The properties of gas mixtures having retrograde condensation characteristics are shown purely by way of example in FIG. 1. The region labeled (al) describes the monophasic region in which the gas mixture is exclusively in liquid form. The monophasic region labeled (av) shows the region in which the gas mixture is exclusively in gaseous form. The region labeled (l+v) shows the biphasic region in which one portion of the gas mixture is in liquid form and another portion is in gaseous form. (CP) shows the critical point of the gas mixture which connects the bubble point curve (bpc) to the dew point curve (dpc).

The bubble point curve (bpc) separates the monophasic liquid region (al) from the biphasic region (l+v). On the bubble point curve (bpc), the gas mixture is virtually 100% liquid and comprises only infinitesimal amounts of gas.

The dew point curve (dpc) separates the monophasic gaseous region (av) from the biphasic region (c+v). On the dew point curve (dpc), the gas mixture is virtually 100% gaseous and comprises only infinitesimal amounts of liquid.

On the horizontal axis is plotted the temperature (T), and on the vertical axis the pressure (P).

A gas mixture having retrograde condensation characteristics undergoes partial condensation as the pressure is lowered isothermally and moves back over to the gas phase as the pressure is lowered further. The retrograde condensation characteristics generally occur at temperatures above the critical point (CP) of the gas mixture. There follows, by way of example, a description of the behavior of a mixture at a given temperature above the critical point (CP).

At a given temperature (T1), the gas mixture having retrograde condensation characteristics is in gaseous and monophasic form at point (A). As the pressure is lowered isothermally (indicated in FIG. 1 by the dotted line), the gas mixture reaches the dew point curve (dpc) at point (B). At this point, the gas mixture is virtually 100% in gaseous form, but an infinitesimal amount of liquid begins to form. As the pressure is lowered further, the gas mixture moves over into the biphasic region (l+v) in which a liquid phase also forms alongside the gas phase as a result of partial condensation. At point (C), natural gas and liquid natural gas condensate are thus present alongside one another in a biphasic system. If the pressure is lowered further isothermally, the gas mixture reaches the dew point curve (dpc) again (indicated in FIG. 1 by point (D)). Passing over the dew point curve (dpc), the gas mixture moves back into the monophasic gaseous state. At point (E) in FIG. 1, the gas mixture is again in gaseous and monophasic form. The diagram in FIG. 1 serves merely to illustrate the condensation behavior of retrograde gas mixtures without restricting the present invention.

The deposit temperature TD of the gas condensate deposits from which the process according to the invention produces natural gas and/or natural gas condensate is typically in the range from 60 to 200° C., preferably in the range from 70 to 150° C., more preferably in the range from 80 to 140° C. and especially in the range from 85° C. to 120° C.

The deposit temperature TD of the gas condensate deposits must meet the following conditions:

    • 1) TD is higher than the crystallization temperature of the solution
    • 2) TD must, within a relatively short period, for example within 1 to 20 days, allow the full hydrolysis of the urea.

The present invention thus also provides a process in which the underground gas condensate deposit has a deposit temperature (TD) in the range from 60 to 200° C., preferably in the range from 70 to 150° C., more preferably in the range from 80 to 140° C. and especially in the range from 85 to 120° C.

The initial deposit pressure, i.e. the pressure prior to performance of the process according to the invention, is typically in the range from 80 to 1500 bar; the initial deposit pressure in the case of gas condensate deposits is normally 300 to 600 bar.

The permeability of the underground gas condensate deposits is generally in the range from 0.01 to 10 mD (millidarcies).

The porosity of the underground gas condensate deposits is generally in the range from 0.1 to 30%.

After the production well has been sunk into the underground deposit, the deposit pressure is generally at first sufficient to produce natural gas and/or natural gas condensate through the production well by conventional methods. The terms “natural gas” and “natural gas condensate” in this context do not of course mean a pure hydrocarbon mixture. The natural gas and/or natural gas condensate may of course, as well as methane, ethane, propanes, butanes, hexanes and heptanes, and possibly higher hydrocarbons, also comprise other substances.

Further substances may, for example, be sulfur-containing hydrocarbons or formation water. Formation water in the present context is understood to mean water originally present in the deposit, and water which has been introduced into the deposit by process steps of secondary and tertiary production, for example what is called flood water. The formation water also comprises water which may have been introduced into the gas condensate deposit by the process according to the invention.

A gas mixture having retrograde condensation characteristics has, for example, the following composition (figures in mol %):

methane 74.6% ethane 8.9% propane 3.8% butane 1.8% pentane 6.4% nitrogen 4.5% original density 0.745 g/cm3

“Natural gas” is understood in the present context to mean gaseous gas mixtures which are produced from the gas condensate deposit. “Natural gas condensate” is understood to mean liquid mixtures which are produced from the gas condensate deposit. The state of matter of the mixtures produced from the gas condensate deposit depends on the temperature and the pressure in the deposit or in the production well.

By the process according to the invention, it is possible to produce exclusively natural gas through the production well. In addition, it is possible to produce exclusively natural gas condensate through the production well. It is also possible to produce a mixture of natural gas and natural gas condensate through the production well. The state of matter of any further substances present in the natural gas or in the natural gas condensate likewise depends on the pressure and temperature in the deposit or in the production well. The further substances may likewise be present in liquid form or in gaseous form in the mixture produced through the production well.

If, after the production well has been sunk (process step a)), the deposit pressure is sufficient to produce natural gas and/or natural gas condensate from the deposit through the production well, this is done by conventional production methods. The present invention thus also provides a process in which, after the at least one production well has been sunk into the underground gas condensate deposit (process step a)) and before the solution (S) has been injected into the underground gas condensate deposit (process step b)), natural gas and/or natural gas condensate is first produced (by conventional methods) through the at least one production well.

However, this is not absolutely necessary. It is also possible to perform process step b) as a preventive measure directly after the sinking of the production well, in order to avoid the formation of natural gas condensate.

In general, after process step a), however, natural gas and/or natural gas condensate is first produced by conventional methods from the gas condensate deposit. As a result of the production of natural gas and/or natural gas condensate from the gas condensate deposit, the pressure in the gas condensate deposit decreases, while the temperature of the gas condensate deposit remains very substantially unchanged. Thus, the production of natural gas and/or natural gas condensate from the gas condensate deposit leads to an isothermal lowering of the pressure. “Isothermal” is understood in the present context to mean that the temperature of the gas condensate deposit in the course of performance of the process according to the invention remains very substantially constant, which means that the temperature of the gas condensate deposit changes by not more than +/−20° C., preferably by +/−10° C. and more preferably by +/−5° C. in the course of performance of the process according to the invention compared to the initial deposit temperature prior to performance of the process according to the invention.

The lowering of the pressure is at its most marked in the vicinity of the production well and decreases with increasing distance from the production well. FIG. 2 shows, by way of example, the pressure profile in the underground gas condensate deposit as a function of distance from the production well. The distance from the production well is plotted on the horizontal axis in meters. The deposit pressure (P) is plotted on the dotted vertical axis. At a particular distance from the production well, the deposit pressure (P) reaches a value at which the partial condensation of the retrograde gas mixture commences. This distance is shown by the vertical dotted line in FIG. 2. At point (B) on the dotted deposit pressure curve (P), the formation of a biphasic mixture comprising natural gas and natural gas condensate commences. Point (B) on the dotted deposit pressure curve (P) corresponds to point (B) in FIG. 1. To the left of the dotted line, the gas mixture is in biphasic form ((l+v) region). To the right of the dotted line, the gas mixture is in monophasic form ((av) region).

With onset of the partial condensation, there is a rise in the proportion of liquid natural gas condensate. The proportion of liquid natural gas condensate is plotted on the vertical axis (CG) and is shown by the solid curve (CG) in FIG. 2. From a certain concentration of liquid natural gas condensate, the near-well zone is blocked, as a result of which the production rates of natural gas and/or natural gas condensate from the gas condensate deposit decrease or stop completely. This critical region is shown by the region (CR) shaded gray in FIG. 2. The critical concentration of the liquid natural gas condensate in the gas mixture is shown by the point (CC) on the curve (CG) in FIG. 2. FIG. 2 illustrates, merely by way of example, the conditions in a gas condensate deposit comprising a gas mixture having retrograde condensation characteristics, without restricting the present invention thereto.

The production of natural gas and/or natural gas condensate from the underground gas condensate deposit through the at least one production well is generally continued until a reduction in the production rate of natural gas and/or natural gas condensate is registered.

The reduction in the production rate is attributable to the formation of the critical region (CR) at least partly blocked by liquid natural gas condensate.

The present invention thus also provides a process in which the underground gas condensate deposit prior to performance of process step b) has a critical region (CR) at least partly blocked by liquid natural gas condensate.

Prior to the injection of the solution (S) in process step b), the production of natural gas and/or natural gas condensate is generally stopped.

The present invention thus also provides a process in which process step a) comprises the sinking of at least one production well into the underground gas condensate deposit, the production of natural gas and/or natural gas condensate from the underground gas condensate deposit until formation of a critical region (CR) at least partly blocked by liquid natural gas condensate and the stopping of the production of natural gas and/or natural gas condensate from the underground gas condensate deposit through the at least one production well.

Process Step b)

In process step b), a solution (S) comprising a solvent and urea is injected through the production well into the underground gas condensate deposit.

The solution (S) typically comprises 50 to 79% by weight of urea and 21 to 50% by weight of solvent, the solvent comprising water, alcohol or a mixture of water and alcohol, based on the total weight of the solution (S). The solution (S) preferably comprises 60 to 78% by weight of urea and 22 to 40% by weight of solvent, based on the total weight of the solution (S). The solution (S) more preferably comprises 65 to 77% by weight of urea and 23 to 35% by weight of solvent, based on the total weight of the solution (S). In a further particularly preferred embodiment, the solution (S) comprises 75 to 77% by weight of urea and 23 to 25% by weight of solvent, based on the total weight of the solution (S).

The present invention thus also provides a process in which the solution (S) comprises 50 to 79% by weight of urea and 21 to 50% by weight of solvent, the solvent comprising water, alcohol or a mixture of water and alcohol, based in each case on the total weight of the solution (S).

The solvent used may thus be solely water. It is also possible to use solely alcohol as the solvent. The use of a solvent comprising only alcohol is possible when sufficient formation water is present in the production well and/or the underground gas condensate deposit for the hydrolysis of the urea. In addition, it is possible to use a mixture of water and alcohol as the solvent. The alcohol used may be exactly one alcohol. It is also possible to use a mixture of two or more alcohols. The alcohol used may be methanol, ethanol, 1-propanol, 2-propanol or a mixture of two or more of these alcohols. A preferred alcohol is methanol.

In a further particularly preferred embodiment, the solution (S) comprises urea and water in a stoichiometric ratio of water to urea of 1:1. At this ratio, the urea present in the solution (S) reacts fully with the water to give ammonia and carbon dioxide. This fully consumes the water present in the solution (S) and prevents contamination of the gas condensate deposit by water. If the solution (S) comprises solely water as the solvent, the solution (S) then comprises water and urea in a % by weight ratio of 23.1% by weight of water to 76.9% by weight of urea.

The solution (S) may consist merely of solvent and urea, with corresponding application of the above details and preferences. However, it is also possible to add at least one surface-active component (surfactant) to the solution (S). In this case, the solution (S) comprises preferably 0.1 to 5% by weight, more preferably 0.5 to 1% by weight, of at least one surfactant, based on the total weight of the solution (S).

The surface-active components used may be anionic, cationic and nonionic surfactants.

Commonly used nonionic surfactants are, for example, ethoxylated mono-, di- and trialkylphenols, ethoxylated fatty alcohols and polyalkylene oxides. In addition to the unmixed polyalkylene oxides, preferably C2-C4-alkylene oxides and phenyl-substituted C2-C4-alkylene oxides, especially polyethylene oxides, polypropylene oxides and poly(phenylethylene oxides), particularly block copolymers, especially polymers having polypropylene oxide and polyethylene oxide blocks or poly(phenylethylene oxide) and polyethylene oxide blocks, and also random copolymers of these alkylene oxides, are suitable. Such alkylene oxide block copolymers are known and are commercially available, for example, under the Tetronic and Pluronic names (BASF).

Typical anionic surfactants are, for example, alkali metal and ammonium salts of alkyl sulfates (alkyl radical: C8-C12), of sulfuric monoesters of ethoxylated alkanols (alkyl radical: C12-C18) and ethoxylated alkylphenols (alkyl radicals: C4-C12), and of alkylsulfonic acids (alkyl radical: C12-C18).

Suitable cationic surfactants are, for example, the following salts having C6-C18-alkyl, alkylaryl or heterocyclic radicals: primary, secondary, tertiary or quaternary ammonium salts, pyridinium salts, imidazolinium salts, oxazolinium salts, morpholinium salts, propylium salts, sulfonium salts and phosphonium salts. Examples include dodecylammonium acetate or the corresponding sulfate, disulfates or acetates of the various 2-(N,N,N-trimethylammonium)ethylparaffin esters, N-cetylpyridinium sulfate and N-laurylpyridinium salts, cetyltrimethylammonium bromide and sodium laurylsulfate.

The use of surface-active components in the solution (S) lowers the surface tension of the solution (S). This allows the solution (S) to better penetrate the regions of the near-well zone blocked by the natural gas condensate, and to displace the natural gas condensate.

Urea is converted in the presence of water by hydrolysis to ammonia and carbon dioxide according to the following equation:


H2N—CO—NH2+H2O→2NH3+CO2

One mole of urea and one mole of water form two moles of ammonia and one mole of carbon dioxide. The hydrolysis of urea with water under the action of heat is also referred to as thermohydrolysis. From a temperature of approx. 60° C., the hydrolysis of urea and water proceeds with sufficient rapidity to fully hydrolyze the urea and the water to carbon dioxide and ammonia within economically viable periods of time. The rate of hydrolysis of the urea present in the solution (S) rises with increasing temperature.

The solution (S) is typically provided above ground by dissolving the urea in the solvent. It is optionally also possible to add further additives, for example surface-active components (surfactants). The urea is typically used in the form of granules.

In order to accelerate the dissolution of the urea in the solvent and the preparation of the solution (S), the solution (S) can be heated. The present invention thus also provides a process in which the solution (S) is heated prior to or during the injection in process step b).

The present invention thus also provides a process in which the solution (S) is heated prior to or during the injection in process step b).

The solution (S) can also be used in the form of a true solution (S). It is also possible to use, as the solution (S), a mixture comprising solvent and urea in dissolved form and urea in undissolved form, for example in the form of crystals. For the process according to the invention, it is sufficient if the solution (S) can be pumped into the gas condensate deposit by conventional pumps. The solution (S) used is preferably a true solution.

The dissolution behavior of urea in water is shown in the phase diagram in FIG. 3. The horizontal axis shows the urea content of the solution (S) in % by weight, based on the total weight of the solution (S). The right-hand vertical axis shows the temperature in ° C. The left-hand vertical axis and the dotted curve (1) show the proportion of the residual water (RW) remaining after the hydrolysis of the urea, based on the total weight of the solution (S) used.

The dotted vertical line (2) in FIG. 3 indicates the urea concentration (76.9% by weight) at which the water present in the solution (S) is consumed completely in the hydrolysis of the urea, meaning that the proportion of residual water (RW) remaining after the hydrolysis of the urea is 0. If solutions (S) with relatively low urea concentrations are used, residual water (RW) remains after the hydrolysis of the urea. The amount of residual water (RW) remaining as a function of the urea concentration of the solution (S) used is shown in FIG. 3 by the dotted curve (1).

The residual water (RW) which remains after the urea hydrolysis if the solvent used is solely water can be calculated by the following formula:


RW=100% by weight−(KH·1.3)

RW therein states the proportion of residual water (RW) remaining after the hydrolysis of the urea in % by weight, based on the total weight of the solution (S) used, in the case that solely water is used as the solvent.

KH therein states the urea content of the solution (S) used in % by weight, based on the total weight of the solution (S) used.

If the solution (S) used is a solution comprising 60% by weight of urea (i.e. KH=60% by weight) and 40% by weight of water (based on the total weight of the solution (S)), the proportion of the residual water (RW) remaining after the hydrolysis is calculated as


RW=100% by weight−(60% by weight·1.3)=22% by weight

In a preferred embodiment, proceeding from a hypothetical solution (S) comprising only urea and water, the proportion of hypothetical residual water (RW) in % by weight that would remain in the case of urea hydrolysis in this hypothetical solution (S) is first calculated.

Subsequently, the proportion of hypothetical residual water (RW) calculated in the solution (S) is replaced by the corresponding weight of an alcohol. Suitable alcohols are methanol, ethanol or mixtures of ethanol and methanol, preference being given to methanol. If the solution (S) comprises less than 76.9% by weight of urea, based on the total weight of the solution (S), the solution (S) comprises, as a solvent, preferably a mixture of water and alcohol. The preferred amount of the alcohol corresponds to the proportion of hypothetical residual water (RW) and is calculated by the following formula:


KA=100% by weight−(KH*1.3).

KA states the preferred amount of the alcohol present in the solution (S).

KH states the urea content of the solution (S) in % by weight.

In the case of urea concentrations of 50% by weight, the solution (S) comprises preferably 50% by weight of urea, 35% by weight of alcohol and 15% by weight of water.

In the case of a urea concentration of 55% by weight, the solution (S) comprises preferably 28.5% by weight of alcohol and 16.5% by weight of water.

In the case of a urea concentration of 60% by weight, the solution (S) comprises preferably 22% by weight of alcohol and 18% by weight of water.

In the case of a urea concentration of 65% by weight, the solution (S) comprises preferably 15.5% by weight of alcohol and 19.5% by weight of water.

In the case of a urea concentration of 70% by weight, the solution (S) comprises preferably 9% by weight of alcohol and 21% by weight of water.

In the case of a urea concentration of 75% by weight, the solution (S) comprises preferably 2.5% by weight of alcohol and 22.5% by weight of water.

The present invention thus also provides a process in which the solution (S) comprises

    • 50 to <76.9% by weight of urea,
    • >0 to 35% by weight of alcohol and
    • 15 to 50% by weight of water.

The sum of urea, alcohol and water preferably adds up to 100% by weight.

The present invention further provides a process in which the solution (S) comprises

    • 50 to <76.9% by weight of urea,
    • KA % by weight of alcohol and
    • 15 to 50% by weight of water,

where KA is defined by the following formula:


KA=100% by weight−(KH*1.3)

in which KA states the amount of alcohol present in the solution (S) in % by weight and KH states the amount of urea present in the solution (S) in % by weight.

The sum of urea, alcohol and water preferably adds up to 100% by weight.

For the solution (S) used in process step b), the urea concentration is preferably selected such that the crystallization temperature (TC) of the solution (S) is below the deposit temperature (TD) of the underground gas condensate deposit, the crystallization temperature (TC) being understood to mean the temperature below which urea present in dissolved form in the solution (S) crystallizes out, such that the solution (S) comprises water, urea in dissolved form and urea in undissolved form.

In other words, the deposit temperature TD is preferably above the crystallization temperature TC of the solution (S) used. The crystallization temperature TC of the solution (S) corresponds, in FIG. 1, to the curve which separates the gray-hatched region “solution” from the region “solution+crystals”. If TD is greater than TC, the crystallization of urea out of the solution (S) in the underground gas condensate deposit can be reliably avoided. The crystallization of urea in the underground gas condensate deposit could lead to blockage of the near-well zone of the underground gas condensate deposit.

The present invention thus also provides a process in which the solution (S) has a crystallization temperature (TC) below the deposit temperature (TD) of the underground gas condensate deposit.

The present invention further provides a process in which the deposit temperature (TD) of the underground gas condensate deposit is higher than the crystallization temperature (TC) of the solution (S).

The solutions (S) used are preferably solutions having a urea concentration in the range from 50 to 76.9% by weight, based on the total weight of the solution (S). At these urea concentrations, 60 to 100% by weight of the water originally present in the solution (S) is consumed in the hydrolysis of the urea. This prevents or at least reduces contamination of the underground natural gas deposit with water.

The present invention further provides a process in which the duration of the rest phase is selected such that the urea originally present in the solution (S) is fully hydrolyzed in the underground gas condensate deposit to carbon dioxide and ammonia, and 60 to 100% by weight of the water originally present in the solution (S) is consumed.

The present invention thus also provides a process in which the solution (S) comprises 50 to 76.9% by weight of urea and 23.1 to 50% by weight of water, based in each case on the total weight of the solution (S).

In a preferred embodiment, a solution (S) comprising 65 to 72% by weight of urea, preferably comprising 69 to 71% by weight of urea, based on the total weight of the solution (S), is used. As is evident from FIG. 3, these amounts of urea can be prepared at temperatures in the range from 50 to 55° C. to form a true solution (S). The relatively low temperatures of 50 to 55° C. have the advantage that the hydrolysis of the urea proceeds very slowly at these temperatures, and so no significant amounts of ammonia and carbon dioxide are formed. The solution (S) is heated by customary heating elements, for example an electrical heater. The vessels used for production of the solution (S) may, for example, be stirred tanks with a propeller stirrer.

In addition, it is possible first to prepare, at the surface, a solution (S) comprising water, urea in dissolved form and urea in undissolved form, for example in the form of crystals. This solution can subsequently be introduced into the gas condensate deposit through the production well. In this embodiment, a heating element is present in the production well, above the gas condensate deposit, in order to dissolve the urea present in undissolved form in the solution (S). Such a heating element, however, is not absolutely necessary. As stated above, it is sufficient if the deposit temperature TD is above the crystallization temperature TC of the solution (S). The complete dissolution of the urea in undissolved form is then effected directly in the deposit. This embodiment can be selected when the solution (S) is injected into fractures in the underground gas condensate deposit (see, for example, FIG. 4c, reference numeral 5). Any fracture filled with proppant has a very high permeability and porosity and can “absorb” the crystals.

In a further preferred embodiment, a solution (S) having a urea content in the range of >72% by weight to 76.9% by weight, preferably in the range from 75% by weight to 76.9% by weight of urea, based in each case on the total weight of the solution (S), is used. For preparation of a true solution (S), temperatures in the range from 60 to 70° C. are needed for this purpose. At these temperatures, noticeable hydrolysis of the urea already takes place to form ammonia and carbon dioxide. In order to minimize gas formation, it is possible to prepare the solution (S) by briefly heating it to the temperatures needed for dissolution and subsequently to cool it to temperatures in the range from 50 to 55° C. The brief heating minimizes the formation of carbon dioxide and ammonia. The oversaturated solution (S) thus formed is stable over a prolonged period, since the process of crystallization of urea out of the oversaturated solution (S) proceeds slowly. The oversaturated solution (S) can be prepared at the surface as described above and then injected into the underground gas condensate deposit through the production well.

In addition, it is also possible to only partly dissolve the urea in the solution (S) at the surface, such that the solution (S) comprises water, urea in dissolved form and urea in undissolved form. This solution (S) is, as described above, subsequently injected into the underground gas condensate deposit through the production well. In this case, it is again possible for a heating element to be present in the production well above the deposit, such that the urea in undissolved form is dissolved in the solution (S) in the production well. However, this is not absolutely necessary. It is also possible to inject the solution (S) comprising water, urea in dissolved form and urea in undissolved form into the underground gas condensate deposit. In this embodiment, the urea in undissolved form is dissolved in the solution (S) in the underground gas condensate deposit. The above remarks always apply with the assumption that the deposit temperature TD is higher than the crystallization temperature TC of the solution (S).

The use of aqueous urea solutions for development of oil deposits comprising viscous oil is described in patent application EP 121 72571, which was yet to be published at the priority date of the present application.

The amount of the solution (S) injected in process step b) depends on the geological parameters of the underground gas condensate deposit, including the permeability of the deposit and the size of the region (critical region according to FIG. 2) in which the near-well zone is blocked by liquid natural gas condensate. The solution (S) is preferably injected in volumes corresponding to not more than the pore volume of the critical region (CR) blocked by the liquid natural gas condensate. Suitable volumes of the solution (S) injected in process step b) are in the range from 1 to 10 m3 per 1 m of the production well surrounded by the critical region (CR), preferably in the range from 2 to 8 m3, more preferably in the range from 3 to 7 m3.

The present invention thus also provides a process in which the solution is injected in process step b) in volumes which lead, in the hydrolysis of urea, to a gas volume of carbon dioxide and ammonia corresponding at least to the pore volume of the critical region (CR).

In the final phase of the injection of the solution (S) in process step b), methanol can be added to the solution (S). “Final phase” is understood in the present context to mean that at least 90% by weight of the solution (S) has been injected, based on the total weight of the solution (S) injected in process step b).

It is also possible to inject the solution (S) in full and subsequently to inject methanol.

This fills the production well with methanol. This facilitates the restarting of the production of natural gas and/or natural gas condensate in process step d).

The present invention thus also provides a process in which, together with the injection of the solution (S) or after the injection of the solution (S) in process step b), methanol is injected into the production well.

The solution (S) described can also be used for flooding of gas condensate deposits. In this case, at least one well is used as a continuous injection well. The solution (S) is injected into this well. The solution (S) forms gases in the deposit. This process can be used particularly efficiently in the development of deposits which have been abandoned owing to massive dropout of a retrograde gas condensate.

Process Step c)

The injection of the solution (S) is generally followed by a rest phase in which the urea in the underground gas condensate deposit is hydrolyzed to ammonia and carbon dioxide. In a preferred embodiment, the duration of this rest phase is selected such that complete hydrolysis of the urea takes place.

The rate with which the hydrolysis of the urea proceeds depends on the deposit temperature TD of the underground gas condensate deposit and the temperature with which the solution (S) is injected in process step b). At high deposit temperatures TD, the hydrolysis proceeds correspondingly more rapidly, and so the rest phase can be selected with a relatively short duration. The duration of the rest phase is generally in the range from 1 to 10 days. At deposit temperatures TD of 100° C., the rest phase selected may be relatively short, for example 1 to 5 days. At deposit temperatures TD in the range from 80 to <100° C., the duration selected for the rest phase is a range from 5 to 10 days. If the deposit temperature TD is within the range from 60 to <80° C., the rest phase selected must be correspondingly longer, for example in the range from 15 to 20 days.

The rest phase results in full hydrolysis of the urea present in the solution (S) in the underground gas condensate deposit.

During the rest phase, in a preferred embodiment, the production well is closed. This can be done by customary means, for example packers. As a result of the closure of the production well, the pressure in the critical region of the underground gas condensate deposit rises, as a result of which the efficiency of the process according to the invention is increased.

The present invention thus also provides a process in which the at least one production well is closed during the rest phase in step c).

The carbon dioxide formed dissolves partly in the natural gas and predominantly in the liquid natural gas condensate. This lowers the viscosity of the liquid natural gas condensate, as a result of which the mobility of the liquid natural gas condensate in the critical region (CR) of the gas condensate deposit is distinctly enhanced. The ammonia formed dissolves in the formation water present in the deposit and in the water injected with the solution (S), and forms an alkaline ammonia buffer system having a pH of 9 to 10. If the deposit is slightly watered out, highly alkaline solutions are formed. Under particular conditions, ammonia can also be partly liquefied in the deposit. Liquid ammonia and aqueous ammonia solutions are very good solvents. This additionally increases the mobility of the gas condensate.

This buffer system has a surfactant-like effect in the underground gas condensate deposit. This reduces the interfacial tension between the phases, i.e. between the natural gas phase and the liquid natural gas condensate phase and possibly the formation water phase. The formation of the gases (ammonia and carbon dioxide) in the underground gas condensate deposit additionally also has a purely mechanical displacing action on the liquid natural gas condensate. The lowering of the viscosity of the liquid natural gas condensate and the increasing of the mobility of the liquid natural gas condensate facilitate the production of natural gas and liquid natural gas condensate from the underground gas condensate deposit. This distinctly enhances the production rate. In the course of production of natural gas, the natural gas also purges the liquid natural gas condensate present in the critical region (CR) of the underground gas condensate deposit in the direction of the production well. This leads to a further enhancement of the production rate.

In a preferred embodiment, in process step b), the solution (S) is introduced in such amounts that the gas volume formed in the hydrolysis of urea corresponds at least to the pore region of the critical region of the underground gas condensate deposit.

The present invention thus also provides for the use of a solution (S) comprising water and urea as a means of enhancing the production rates of natural gas and/or natural gas condensate from a gas condensate deposit comprising a gas mixture having retrograde condensation characteristics. For the use of the solution (S) as a means for enhancing the production rates, the above details and preferences in relation to the solution (S) apply correspondingly.

Process Step d)

In process step d), natural gas and/or natural gas condensate is produced from the underground gas condensate deposit, i.e. it is restarted. The production is effected by conventional methods. The natural gas and the natural gas condensate can be produced through the production well through which the solution (S) was injected in process step b) into the underground gas condensate deposit. It is also possible to sink further wells into the underground gas condensate deposit. The production of natural gas and natural gas condensate can then be effected through the production well or through the further well. The production well can also fulfill the function of an injection well through which a flooding medium is injected into the underground gas condensate deposit, in which case the actual production is then effected through the one or more further wells. It is also possible to inject a flooding medium through the one or more further wells into the underground gas condensate deposit and to undertake production through the production well through which the solution (S) was injected in process step b).

The production of natural gas and/or natural gas condensate from the underground gas condensate deposit in process step d) is continued until the lowering of the pressure which has occurred as a result in the underground gas condensate deposit leads again to formation of liquid natural gas condensate, as a result of which the critical region (CR) arises and the production rates decrease significantly. In this case, steps b) and c) are performed again. Steps b) and c) of the process according to the invention are thus performed whenever a critical region (CR) which has been blocked by liquid natural gas condensate forms again in the underground gas condensate deposit.

The present invention thus also provides for the use of a solution (S) as a means of enhancing the production rates of natural gas and/or natural gas condensate from an underground gas condensate deposit comprising a gas mixture having retrograde condensation characteristics.

The present invention is illustrated in detail by the example which follows and FIGS. 1, 2, 3 and 4, without being restricted thereto. The meanings of the reference symbols in the figures are as follows:

    • al monophasic liquid region
    • bpc bubble point curve
    • l+v biphasic region
    • dpc dew point curve
    • CP critical point
    • av monophasic gaseous region
    • A, B, C, D and E points in the isothermal lowering of the pressure of the retrograde gas mixture
    • CG concentration of the liquid natural gas condensate in the gas mixture
    • CR critical region
    • CC critical concentration of the liquid natural gas condensate in the gas mixture
    • P pressure
    • T temperature
    • (1) concentration of the residual water after the hydrolysis of the urea in the solution (S) used
    • (2) concentration of urea at which the water in the solution (S) is fully consumed in the hydrolysis
    • 3 production well
    • 4 critical region (CR) blocked with liquid natural gas condensate
    • 5 fracture in the underground gas condensate deposit

The individual figures show:

FIG. 1

The phase behavior of gas mixtures having retrograde condensation characteristics.

FIG. 2

The pressure profile and the concentration of liquid natural gas condensate in an underground gas condensate deposit as a function of the distance from the production well.

FIG. 3

The phase diagram of an aqueous urea solution.

FIGS. 4a, 4b, 4c

Various embodiments of the production well 3.

FIGS. 1, 2 and 3 have already been described in the description of the present invention.

FIG. 4 shows different embodiments of a sunk well 3. FIG. 4a shows a vertical production well. The region 4 is the region blocked by liquid natural gas condensate. FIG. 4b shows an embodiment in which a directional well has been sunk. FIG. 4c shows an embodiment in which a directional well has been sunk and in which the underground gas condensate deposit has a fracture 5.

EXAMPLE

For development of a gas condensate deposit at a depth in the range from 3400 to 3700 m, a directional production well 3 according to FIG. 4b or FIG. 4c is sunk. The thickness of the productive stratum is 50 to 80 m. The deposit temperature TD is 105° C. The deposit pressure is approx. 650 atm (658.6 bar). The permeability of the deposit is low and is between 0.5 and 5.0 mD. After the directional production well 3 has been sunk, it is fracked in the region of the productive stratum, forming a fissured zone 5. The porosity of the gas condensate deposit is in the range from 0.2 to 0.25%. The sinking and fracking of the production well 3 is followed by commencement of the production of natural gas and/or natural gas condensate by conventional methods. After a year of production of natural gas and/or natural gas condensate, a significant reduction in the production rate is registered. The reduction in the production rate is attributable to blockage of the near-well zone by liquid natural gas condensate. The critical region 4 in which the blockage by liquid natural gas condensate has occurred is estimated to have a radius of approx. 20 m. The region has a cylindrical shape with the production well 3 in the center. In order to dissolve the blockage, 100 m3 of the solution (S) comprising urea and water, having a urea concentration of 70% by weight, based on the total weight of the solution (S), are injected through the production well 3 into the critical region 4 of the gas condensate deposit. To prepare the solution (S), 70 t of urea are dissolved in 30 t of water. After the solution (S) has been injected into the gas condensate deposit, the urea is hydrolyzed in the gas condensate deposit, forming approx. 85 000 m3 of gases (ammonia and carbon dioxide). To prepare the solution (S), urea is used in granule form. To prepare the solution (S), it is heated using conventional heaters. Directly prior to the injection of the aqueous solution (S), the solution (S) has a temperature of 50° C., in order to prevent the crystallization of urea out of the solution (S). The solution (S) is injected by means of conventional pumps. The injection of the solution (S) into the gas condensate deposit is followed by a rest phase. The rest phase is 3 to 5 days. During the rest phase, the urea is fully hydrolyzed in the underground gas condensate deposit. During the rest phase, the production well is closed. This raises the pressure in the critical region of the underground gas condensate deposit, increasing the efficiency of the process according to the invention. In the final phase of the injection, methanol can additionally be used. This fills the production well with methanol during the rest phase. This subsequently facilitates the restarting of production. The hydrolysis of the urea results in almost complete consumption of the water injected into the underground gas condensate deposit with the solution (S). Blockage of the near-well zone by water is prevented as a result.

After the rest phase, production is restarted by means of conventional methods. The hydrolysis of the urea in the underground gas condensate deposit distinctly enhances the mobility of the gas mixture present in the deposit. The natural gas subsequently produced likewise purges any liquid natural gas condensate still present in the direction of the production well. This further reduces blockage of the critical region. After the rest phase, natural gas and liquid natural gas condensate are produced from the underground gas condensate deposit.

Claims

1. A process for producing natural gas and/or natural gas condensate from an underground gas condensate deposit comprising a gas mixture having retrograde condensation characteristics, comprising at least the process steps of

a) sinking at least one production well into the underground gas condensate deposit and producing natural gas and/or natural gas condensate from the underground production well through the at least one production well,
b) injecting a solution (S) comprising a solvent and urea through the at least one production well into the underground gas condensate deposit,
c) waiting for a rest phase in which the urea present in the solution (S) is hydrolyzed,
d) producing natural gas and/or natural gas condensate from the underground gas condensate deposit through the at least one production well.

2. The process according to claim 1, wherein the underground gas condensate deposit has a deposit temperature (TD) in the range from 60 to 200° C., preferably in the range from 70 to 150° C., more preferably in the range from 80 to 140° C. and especially in the range from 85 to 120° C.

3. The process according to claim 1, wherein the solution (S) comprises 50 to 79% by weight of urea and 21 to 50% by weight of solvent, the solvent comprising water, alcohol or a mixture of water and alcohol, based in each case on the total weight of the solution (S).

4. The process according to claim 1, wherein the solution (S) has a crystallization temperature (TC) below the deposit temperature (TD) of the underground gas condensate deposit.

5. The process according to claim 1, wherein the solution (S) is heated prior to or during the injection in process step b).

6. The process according to claim 1, wherein the deposit temperature (TD) of the underground gas condensate deposit is higher than the crystallization temperature (TC) of the solution (S).

7. The process according to claim 1, wherein the solution (S) is injected in process step b) with a temperature higher than the crystallization temperature (TC), and the deposit temperature (TD) of the underground gas condensate deposit is higher than the crystallization temperature (TC) of the solution (S).

8. The process according to claim 1, wherein the underground gas condensate deposit prior to performance of process step b) has a critical region (CR) at least partly blocked by liquid natural gas condensate.

9. The process according to claim 1, wherein the duration of the rest phase is selected such that the urea originally present in the solution (S) is fully hydrolyzed in the underground gas condensate deposit to carbon dioxide and ammonia, and 60 to 100% by weight of the water originally present in the solution (S) is consumed.

10. The process according to claim 1, wherein the at least one production well is closed during the rest phase in process step c).

11. The process according to claim 1, wherein the solution (S) comprises

50 to <76.9% by weight of urea,
>0 to 35% by weight of alcohol and
15 to 50% by weight of water.

12. The process according to claim 1, wherein the solution (S) comprises

50 to <76.9% by weight of urea,
KA % by weight of alcohol and
15 to 50% by weight of water,
where KA is defined by the following formula: KA=100% by weight−(KH*1.3)
in which KA states the amount of alcohol present in the solution (S) in % by weight and KH states the amount of urea present in the solution (S) in % by weight.

13. The process according to claim 1, wherein the solution (S) is injected in process step b) in volumes corresponding to not more than the pore volume of the critical region (CR).

14. The process according to claim 1, wherein the solution (S) is injected in process step b) in volumes which lead, in the hydrolysis of urea, to a gas volume of carbon dioxide and ammonia corresponding at least to the pore volume of the critical region (CR).

15. (canceled)

Patent History
Publication number: 20150240608
Type: Application
Filed: Sep 25, 2013
Publication Date: Aug 27, 2015
Applicant: WINTERSHALL HOLDING GMBH (Kassel)
Inventor: Vladimir Stehle (Kassel)
Application Number: 14/431,001
Classifications
International Classification: E21B 43/16 (20060101);