RU2049913C1 - Method for development of oil gas fields - Google Patents

Abstract

FIELD: development of oil fields. SUBSTANCE: heat carrier is injected into formation simultaneously with barrier water flooding. Barrier water flooding is effected by injection of water with temperature higher than that of initial formation temperature. Temperature of hot water injected along gas-oil contact is 60-300 C or is maintained equal to temperature up to which roof of oil fringe is heated for the whole period of field development. Upper part of string is assembled of heat-insulated pipes. length of heat-insulated part of string is selected so that temperature of water supplied through annulus in the zone of gas-oil contact is equal to preset value. EFFECT: higher oil recovery and rate of field development, and reduced consumption of heat carrier and specific consumption of heat for oil production and attainment of required temperature of water injected into gas cap. 4 cl, 1 dwg

Description

 The invention relates to a method for developing oil and gas fields.

 There is a method of developing oil and gas deposits by implementing barrier waterflooding at the oil-gas interface to prevent depletion of the gas cap. With barrier waterflooding, conditions are created for the simultaneous operation of the oil rim and gas cap. The disadvantage of this method is the low efficiency of the displacement of highly viscous oil by injected water. As a result, oil recovery does not increase significantly and remains extremely low.

 There is a method of developing water-floating deposits of high viscosity oils by pumping coolant into injection wells. The injected coolant breaks into production wells along the water-saturated part of the reservoir, due to which the oil-saturated part of the reservoir is heated. Due to the heating of oil, its viscosity decreases, and oil recovery increases. The disadvantage of this method is the slow heating of the entire thickness of the oil rim, because of which the coverage of the formation with a displacing agent in the thickness is low, and the specific heat carrier consumption for the extraction of a unit mass of oil is high.

 A known method of developing oil and gas deposits, including the injection of inert gas into the gas-oil contact area to prevent breakthrough in the gas cap of the coolant, which is injected into the oil-saturated part of the reservoir. The disadvantage of this method is the slow heating of the oil rim and the low efficiency of oil displacement in the area adjacent to the gas-oil contact.

The aim of the invention is to increase oil recovery and the pace of development of deposits. This goal is achieved due to the fact that they carry out the injection of hot coolant into the reservoir and barrier flooding, and barrier flooding is carried out by pumping water with a temperature exceeding the initial reservoir along the gas-oil contact. The temperature of the hot water pumped along the gas-oil contact, is 60-250 ^{° C} or maintained at the temperature to which the oil warms roof rim for the whole development.

 The use of these distinguishing features to achieve this goal has not been found in the literature, which suggests that the proposed technical solution meets the criteria of "novelty" and "significant differences".

The efficiency of displacing viscous oil depends to a large extent on temperature. Warming productive portion of the formation to a temperature of 80-120 ^{° C} results in a sharp decrease in oil viscosity, thereby significantly increasing the efficiency of its displacement. To warm the collector, coolant is pumped into the reservoir. If the reservoir is a rim of oil with a gas cap and active bottom water, then the injected coolant flows mainly into the water-saturated part of the reservoir, since the filtration resistances are several orders of magnitude lower compared to the oil-saturated part of the reservoir. In order to prevent breakthroughs of the coolant into the gas cap and gas breakthroughs in the producing wells, along with the thermal effect, barrier flooding is implemented by pumping cold water into the gas cap. However, with a large thickness of the oil rim, the heating of the formation by the coolant pumped into the oil-water contact area is extremely slow. As a result, the rate of oil recovery remains extremely low, and the specific flow rate of the coolant increases. It is more efficient to develop waterflood deposits by pumping a coolant both in the gas cap and in the area of the oil-water contact. In the latter case, the heating of the oil rim is carried out twice as fast, and the pace of development is almost twice as high.

 The method is illustrated in the drawing.

 The method is as follows. In the injection well, the production string is perforated not only in the oil-saturated part of the reservoir, but also several meters above the gas-oil contact and several meters below the water-oil contact. The perforation interval in the water-saturated and gas-saturated zones is determined based on the projected flow rates of the coolant in the gas cap and the water-saturated part of the collector.

 For barrier flooding, it is necessary to pump water into the gas cap, and in this case, hot water. In order to reduce heat loss in the injection well bore, it is advisable to pump the hot agent through the pipe string, and cold water through the annular space. It is advisable to make a pipe string through which a hot agent is pumped (hot water or steam) when the upper part of the column is assembled from heat-insulated pipes and the lower from non-heat-insulated pipes. When cold water comes in contact with thermally insulated pipes, it is heated and the temperature of the agents can almost equalize. If during heat exchange with the steam injected into the formation, the latter condenses completely and turns into hot water, then installing the packer on the bottom of the injection well is not required. If, after heat exchange, water vapor enters the bottom of the injection well, installation of a packer is required that separates the gas-saturated and oil-saturated parts of the reservoir, since the use of steam as a barrier is not practical. To calculate the heat transfer process between cold water moving along the annular space and the hot agent entering the pipe string, a special technique developed at MING is used.

1-e

+a₅Z+a₆Z²
(1)
Температуру холодной воды:
τ=t_s +

1-e

-(t_s-τ_x)e

+

Z
(2)
При полной конденсации пара в колонне НКТ в горячую воду или в случае закачки ее с поверхности температуру горячей воды определяют следующим образом: t a₁₂ exp (a₁₀z) + a₁₁ exp (a₉z) + a₈ + Г_z, (3) а температуру холодного теплоносителя:

+

x

a₁₀Z)

+a

exp(a₉Z)+
(4)
где a₁

a

a₂

a₃

a₄=a₂+a₃; a₅

a₆

a₇=a

+a₂+a₃; a₈=a

a₃θ_o-a₇Г; a₉=

+

a₁₀

a₁₁

a₁₂

где х текущая степень сухости пара на глубине z;
х_о степень сухости пара на устье скважины
t_s температура пара или горячей воды на устье, ^оС;
τ_x температура холодной воды на устье, ^оС;
τ_х' температура холодной воды на глубине полной конденсации пара, ^оС;
τ- текущая температура холодной воды на глубине z, ^оС;
z глубина рассматриваемого сечения скважины, м;
Г геометрический градиент, ^оС/м;
К₁ коэффициент теплопередачи от горячего теплоносителя к горным породам, Вт/(м²К);
К₂ коэффициент теплопередачи от холодного теплоносителя к горным породам, Вт/м²К);
r скрытая теплота парообразования, Дж/кгК;
С_рг, С_рх удельная теплоемкость горячего и холодного теплоносителя соответственно. Дж/кгК;
d₁ внутренний диаметр НКТ. м;
d₂ внутренний диаметр обсадной колонны м;
θ- температура окружающих горных пород в данном сечении скважины, ^оС;
θ_о- температура невозмущенного слоя горных пород, ^оС.Based on the planned dynamics of fluid selection, injectivity of wells and technical capabilities, the costs of hot (G _g ) and cold (G _x ) coolants are set. The degree of dryness of steam (hot fluid) is determined by the following relationship:
X = X _o

1st

+ a ₅ Z + a ₆ Z ²
(1)
Cold water temperature:
τ = t _s +

1st

- (t _s -τ _x ) e

+

Z
(2)
When steam is completely condensed in the tubing string into hot water or if it is pumped from the surface, the hot water temperature is determined as follows: ta ₁₂ exp (a ₁₀ z) + a ₁₁ exp (a ₉ z) + a ₈ + Г _z , (3 ) and the temperature of the coolant:

+

x

a ₁₀ Z)

+ a

exp (a ₉ Z) +
(4)
where a ₁

a

a ₂

a ₃

a ₄ = a ₂ + a ₃ ; a ₅

a ₆

a ₇ = a

+ a ₂ + a ₃ ; a ₈ = a

a ₃ θ _o -a ₇ G; a ₉ =

+

a ₁₀

a ₁₁

a ₁₂

where x is the current degree of steam dryness at depth z;
x _{about the} degree of dryness of the steam at the wellhead
t _s temperature of steam or hot water at the mouth, ^о С;
τ _x temperature of cold water at the mouth, ^о С;
τ _x 'cold water temperature at the depth of full condensation of the steam, ^of C;
τ is the current temperature of cold water at a depth of z, ^о С;
z depth of the considered section of the well, m;
G geometric gradient, ^o C / m;
K ₁ heat transfer coefficient from the hot coolant to the rocks, W / (m ² K);
K ₂ heat transfer coefficient from cold coolant to rocks, W / m ² K);
r latent heat of vaporization, J / kgK;
C _rg , C _rx specific heat of hot and cold coolant, respectively. J / kgK;
d _{1 the} inner diameter of the tubing. m;
d ₂ inner diameter of the casing m;
θ- temperature surrounding rocks in a given section of the well, ^of C;
θ _о - temperature of the undisturbed rock layer, ^о С.

), (1) где t_s температура закачиваемого теплоносителя на устье;
t(l, η) температура пласта на расстоянии l от подошвы нефтяной оторочки через время η после начала нагнетания теплоносителя;
t_о начальная температура пласта;
а коэффициент температуропроводности пласта;
Способ осуществляется следующим образом.The temperature of the steam injected into the reservoir depends on the reservoir pressure. At significant reservoir pressures, the vapor temperature can be much higher than necessary for the effective displacement of oil. If water vapor enters the water-saturated zone of the reservoir, it quickly condenses, mixing with produced water, and then filtered as hot water. In the gas cap, a high-temperature coolant is not needed, since to a certain limit the increase in oil recovery with increasing temperature is significant, and then, gradually decreasing, it becomes invisible. For such deposits, in order to reduce heat loss, it is advisable to limit the temperature of the water entering the gas cap. This temperature is determined based on the results of laboratory experiments on oil displacement at various temperatures. Previous methods of applying heat to oil deposits indicates that the temperature of the injected water into a gas cap should be 60 ^{° C} for fields lying at a shallow depth with a low formation temperature and high viscosity oil. At lower water temperatures, oil displacement is ineffective, and oil recovery is not sufficiently increased. The maximum temperature of the injected water reaches ^{300 °} C, since at a lower temperature in fractured reservoir pore capillary impregnation efficiency may be low, and does not provide an adequate gain recovery. At a higher temperature of the injected water, the increase in oil recovery does not compensate for the costs of heating the water to a higher temperature. If the oil rim has a small thickness, and the distance between the wells is large, then the entire oil-saturated part of the reservoir is heated to a significant temperature. In this case, cold water will lower the temperature of the oil rim, contributing to a drop in oil recovery. When developing such deposits, the temperature of the water injected into the gas cap should be higher than the temperature to which the roof of the oil rim is heated over the entire development period. To calculate the temperature of the roof, you can use the following formula:
t (l, η) = t _s - (t _s -t _o ) erf (l / 2

), (1) where t _{s is the} temperature of the injected coolant at the mouth;
t (l, η) the temperature of the reservoir at a distance l from the bottom of the oil rim after a time η after the start of the injection of coolant;
t _{about the} initial temperature of the reservoir;
and the coefficient of thermal diffusivity of the reservoir;
The method is as follows.

At a field lying at a depth of 400 m, an oil rim 30 m thick is not lined with water and is covered with a gas cap. Oil with a viscosity of 100 mPa˙s is very slowly displaced by water and gas to production wells, as a result of which the maximum water cut and gas factors are achieved with oil recovery of only 20%. In order to increase the efficiency of oil displacement, it was decided to pump the coolant both along the oil-water contact and along the gas-oil contact. Laboratory experiments showed that the effective displacement of the oil is achieved at a temperature of 60 ° ^C. It was therefore decided to use for further flooding water at 60 ^C. For this purpose, the borehole component lowered column, the upper part of which consists of a thermally insulated pipes, and the lower from non-insulated pipes. The annular space is isolated from the bottom of the injection well using a thermally insulated packer. Water-oil steam with a temperature of 250 ^о С is pumped into the oil-water contact zone at a temperature of 250 ^о С in the amount of 200 t / day, and cold water is supplied through the annular space to the well at a rate of 100 t / day, which is heated until the gas-oil contact reaches the temperature of 60 ^о С To achieve this temperature, the composite column should consist of heat-insulated pipes 70 m long and non-insulated pipes 330 m long. The heat carrier is injected into the formation cyclically (half an injection and half a break). Due to the application of the method, the development time of one element of the well placement system is reduced by 1.5 times from 15 to 10 years, and oil recovery is increased by 15%
At a field lying at a depth of 1400 m, the reservoir of which is represented by fractured-pore limestone, an oil rim 45 m thick is lined with water and covered with a gas cap. Oil viscosity 1 Pa˙s vtesnyaetsya virtually no gas is displaced and very poorly water at the reservoir temperature of 20 ° ^C. It has been found that the effective capillary infiltration occurs at a temperature ^of 180-200 C, so it was decided to inject water into the gas cap at a temperature 320 ^{° C,} and into the annulus of the injection well 75 serves tons / day of cold water which is at a temperature ^of 300 C is supplied along the gas-oil contact. Cold water for heating ^to 300 ° C Column pumping pipes must consist of insulated pipes (upper 350 m) and neteploizolirovannyh pipe (lower 1050 m). Due to the application of the method, the development time of the deposit is reduced by 1.8 times, and the specific coolant flow rate will decrease by 1.2 times.

At the field, an oil rim 10 m thick is lined with bottom water and covered with a gas cap. Oil viscosity 300 mPa˙s very bad displaced gas and water with an initial reservoir temperature (30 ° ^C). With natural oil recovery operation does not exceed 10% To improve the oil recovery factor decided injected into the formation water vapor having a temperature of 320 ^C. The coolant is pumped to the oil-water contact, will effectively heat the oil saturation of the reservoir. To create a barrier between the gas cap and the oil rim, water is pumped into the gas-oil contact area. However, if the water pumped during the barrier flooding is cold, the oil rim will cool and the oil recovery will decrease. The development period of one element of the well placement system reaches 10 years. For the time of discharge of coolant oil rim roof warms up to a temperature of 130 ^C. Therefore, to prevent the formation into the cooling gas contact region to be injected with a water temperature of 130 ° ^C. For carrying out the method in an injection well drained component sucker pipe, the upper part of which consists of thermally insulated pipes, and the lower of non-insulated pipes. The length of the non-insulated part of the column at a steam injection rate of 200 t / s, and cold water at 100 t / day will be 400 m with a total column length of 950 m. Due to the application of the method, oil recovery compared to the prototype will increase by 5% and the development period will decrease by 1 ,4 times.

Claims (4)

 1. METHOD FOR THE DEVELOPMENT OF OIL AND GAS DEPOSITS, including the injection of coolant through the pipe string into the formation and an agent that prevents gas breakthroughs from the gas cap into production wells, characterized in that, in order to increase oil recovery and the rate of reservoir development, as an agent that prevents gas breakthrough From the gas cap to the producing wells, hot water with a temperature above the initial formation is used. 2. The method according to claim 1, characterized in that, in order to reduce the specific flow rate of the coolant, the temperature of the hot water pumped along the gas-oil contact is 60 300 ^o C.  3. The method according to claim 1, characterized in that the temperature of the water pumped along the gas-oil contact is maintained equal to the temperature to which the roof of the oil rim warms up over the entire development period.  4. The method according to PP.1 to 3, characterized in that, in order to reduce the specific heat consumption for oil production and achieve the required temperature of the water pumped into the gas cap, the pipe string, through which the coolant enters the reservoir, consists of heat-insulated pipes in the upper part and the lower part consists of non-insulated pipes, and the length of the non-insulated pipes is selected based on the temperature condition pumped through the annular space of hot water.

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