RU2496818C2 - Selection method of polymer gel-forming composition to increase oil recovery of formations and waterproofing work - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: in selection method of polymer gel-forming composition to increase oil recovery of formations and waterproofing work based on acrylamide polymer, a cross-linking agent and water, which involves determination of formation parameters for a certain well, experimental determination of characteristics of the above composition, including time of gel formation and static shear stress, calculation of initial pressure gradient, minimum radius of a gel screen and minimum volume of pumped composition, distance Rk in a zone that is located at some distance from injection well working face and where a gel screen shall be formed is set, temperature value is defined for the above distance as per the pre-built diagram of dependence of distribution as per distance in the formation of temperature values calculated considering temperature of pumped water, its pumping rate and time, temperature, porosity and heat conductivity of the formation, and pressure value as per the pre-built diagram of dependence of distribution as per the distance in the formation of pressure values designed as per the specified formula, and composition is selected based on the following conditions: time of gel formation at the temperature determined for the same zone, which is not less than time of composition pumping to that zone of formation, and initial pressure gradient is higher than depression to which the gel will be subject in the same formation zone.

EFFECT: improving processing quality in the formation zone that is distant from the well working face at simultaneous improvement of preservation period of quality of the installed screen due to reducing the influence of depression on gel-forming composition.

1 ex, 3 dwg

Description

The invention relates to the field of oil industry, in particular to methods for processing heterogeneous oil reservoirs to increase their coverage by water flooding and, accordingly, increase oil recovery.

To increase the coefficient of reservoir coverage by water flooding, a wide range of technologies is used, including flow-deflecting ones, the essence of which is the selective creation of hydrodynamic drags in highly permeable, water-washed layers and an increase in the proportion of water displacing oil from low-permeable oil-saturated layers. Hydrodynamic resistances can be created due to the formation of various kinds of structures in the formation in the form of inorganic and polymer hydrogels formed as a result of the injection of reagents into an inhomogeneous formation in the form of aqueous solutions or suspensions.

A known method of processing a heterogeneous oil reservoir, aimed at equalizing the injectivity profile in injection and limiting water inflows in producing wells, including injecting into the reservoir an insulating composition based on polymers, a crosslinker and water, while the insulating composition is forced into the reservoir for a distance to avoid influence gel depression to a safe level (RF patent No. 2169258, E21B 43/22). The disadvantages of this method include the lack of indications of the optimal size of the diaphragm screen and the required volume of the injected composition.

Closest to the proposed method is a method of selecting a polymer gel-forming composition to enhance oil recovery and waterproofing based on polyacrylamide, a crosslinker and water, carried out taking into account the characteristics of the formation and a specific well, experimentally determined composition properties and calculated technological characteristics (RF patent No. 2272899, E21B 43/22). However, screens formed from such compositions, which are usually installed in the bottomhole zone, where the highest pressure drops are realized, as a result of high loads are destroyed quite quickly, which requires repeated treatments and the associated additional costs. A disadvantage of the technology for treating the bottom-hole zone with gel-forming compositions is also the need to inject an intensifying composition after gel formation in the formation in order to reduce hydrodynamic resistances in the low-permeability layer.

The problem to which the invention is directed is to increase the efficiency of processing heterogeneous oil reservoirs to increase their coverage by water flooding and, accordingly, increase oil recovery when using a gelling composition based on polyacrylamide, a crosslinker and water.

The technical result achieved by the implementation of this invention is to improve the quality of processing in the formation zone remote from the bottom of the well while increasing the retention time of the quality of the installed screen by reducing the effect of depression on the gelling composition to a safe level.

To solve the problem with the achievement of the specified technical result in the method of selecting a polymer gel-forming composition to increase oil recovery and waterproofing based on a polymer of acrylamide, a crosslinker and water, including determining the parameters of the formation for a particular well, experimental determination of the characteristics of the specified composition, including time gelation and static shear stress, calculation of the initial pressure gradient, the minimum radius of the gel screen and the minimum the volume of the injected composition, according to the proposed technical solution, set the distance in the zone where the gel screen should be formed, remote from the bottom of the injection well, determine the temperature value for this distance according to a previously constructed graph of the distribution of the temperature values calculated according to the temperature over the distance in the formation the injected water, the speed and time of its injection, temperature, porosity and thermal conductivity of the reservoir, and pressure values - precede In accordance with the constructed graph of the dependence of the distribution over the distance in the formation of pressure values determined by the calculation formula, the composition is selected from the conditions: the gelation time at a temperature defined for a given zone is not less than the time the composition was injected into this formation zone, and the initial pressure gradient is higher than the depression, which will test the gel in this area of the reservoir.

The problem is solved by performing the following set of operations:

1. The distance R _K (removal radius) is set in the formation zone remote from the bottom of the injection well where the gel screen is planned to be formed. As a rule, this distance is set taking into account the preservation of the previous injectivity of the injection well after processing.

2. The temperature distribution in the formation is calculated to the specified distance, taking into account the temperature of the injected water and the time of its injection.

3. A composition is selected whose gelation time, when the temperature is set in a given zone of the formation, is greater than or equal to the time it was pumped into this formation zone. The pressure gradient that the composition can withstand without breaking is determined.

4. The magnitude of the depression that the gel will experience under reservoir conditions at a given distance from the injection well is calculated.

5. Calculate the volume of the composition, providing the length of the screen, which withstands the pressure gradient in the reservoir at a given distance.

When calculating the optimal compositions and volumes of gel-forming compositions, knowledge of real temperatures in the area of installation of the gel screen is necessary.

In the process of water flooding with a temperature lower than the temperature of the formation, the formation is cooled. The determining factors affecting the degree of formation cooling is the difference between the reservoir temperature and the temperature of the water entering the bottom of the well and the injectivity of the well.

The temperature distribution in the injection well zone can be calculated using the mathematical model for calculating the temperature field of the “Temperature Field” oil reservoir, based on the solution of the Fourier heat equation in partial derivatives by numerical methods (Certificate No. 2001610296 on state registration of computer programs dated March 19, 2001).

The optimal composition composition is determined experimentally taking into account the gelation time of the composition at a temperature in a given zone of the formation. In this case, the reagents are selected in such a way that the gelation start time at the formation temperature is not less than the delivery time of the composition rim to the specified formation zone. The gelation time at a given temperature, depending on the properties of the starting components and their concentration in the composition, is determined using rheometers according to known methods. The delivery time of the composition to a given zone of the reservoir depends on the injectivity of the well.

Strength characteristics are determined for the selected composition.

(Па/м), которые воздействуют на нее в пласте. Градиент давления, который полимерный гель выдерживает без разрушения, пропорционален СНС и обратно пропорционален характерному размеру проводящих каналов. В случае пористой среды характерным размером является величина $$\sqrt{\frac{32K}{m}}$$

, где K - проницаемость, a m - пористость. Для круглых каналов - это диаметр, а для трещин - ширина раскрытия трещин.After the formation and hardening of the structure in the reservoir, the composition must have the required mechanical strength or static shear stress (SSS), and withstand those pressure gradients $$\frac{\Delta P}{l}$$

(Pa / m) that affect it in the reservoir. The pressure gradient that the polymer gel can withstand without destruction is proportional to the SNA and inversely proportional to the characteristic size of the conductive channels. In the case of a porous medium, the characteristic size is $$\sqrt{\frac{32K}{m}}$$

where K is the permeability, am is the porosity. For round channels, this is the diameter, and for cracks, the width of the crack opening.

SNA (τ) is determined by the method of rotational viscometry in the constant shear stress mode using special rheometers.

Choose the composition for which the initial pressure gradient is higher than the depression that the gel will experience in the formation at a given distance.

Moreover, the initial pressure gradient is calculated from the following relationships:

ΔP / l = τ (m / 2k) ^0.5 - for the pore collector;

ΔP / l = τ / 1,02b - for a fractured reservoir,

Where:

ΔР / l - initial pressure gradient, Pa / m

τ is the static shear stress, Pa

m - porosity

k - permeability, m ²

b - crack opening width, m

The distribution of pressure gradients in the reservoir is calculated for a particular well using the Dupuis equation (a particular solution to Darcy's law):

или в общем виде ΔP/l=Q·µ/k·2π·h·R_k, где $$Q=\frac{2\pi \cdot k\cdot h\cdot \Delta \rho }{\mu \cdot \ln \left(\frac{Rk}{Rc}\right)}$$

or in general form ΔP / l = Q · µ / k · 2π · h · R _k , where

Q - fluid flow, m ³ / s

k - permeability, m ²

h - reservoir thickness, m

R _k is the radius of removal, m

R _with - well radius, m

Δp is the difference between reservoir and bottomhole pressures, Pa

µ is the viscosity, Pa · s.

In accordance with the Dupuis equation for a plane-radial flow regime, the pressure gradient as a function of radius changes according to the logarithmic law. The distribution of pressure gradients depends on the radius of the distance from the injection well, and the maximum pressure gradients are realized in the near-wellbore zone. This means that the length of the gel screen in the remote zone of the formation may be less than in the near-well zone.

It was established in experiments that polymer gels withstand a pressure gradient in a pore reservoir of 20-100 atm / m (~ 20 · 10 ⁵ -100 · 10 ⁵ Pa / m). In the presence of cracks, this indicator decreases by 2-3 times.

When calculating the volume of the injected composition, it must be taken into account that it must be such that the gel screen in the processing zone withstands the pressure drop acting on it. Based on the obtained laboratory data and formation parameters, the minimum radius of the gel screen is calculated from the ratio:

R _e ≥ [P _PL -P _Zab ] / (ΔP / l),

Where:

R _e - the minimum radius of the gel screen, m;

P _PL - reservoir pressure, Pa;

P _zab - bottomhole pressure, Pa;

ΔP / l - initial pressure gradient, Pa / m.

Next, calculate the minimum volume of the composition necessary for the formation of a gel screen, according to the formula:

, где: $$V_{\mathrm{to}\mathrm{about}m}=\pi {\left(R_{\mathrm{uh}}+R_{\mathrm{from}}\right)}^{2}hm-\pi hm{R}_c^2$$

where:

V _com - the minimum volume of the injected composition, m ³ ;

R _e - the minimum radius of the gel screen, m;

R _with - well radius, m;

h is the thickness of the reservoir, m;

m is the porosity of the reservoir.

Example 1

1. Assume that the distance R _k for installing the gel screen is 50 m, which will completely preserve the injectivity of the injection well after treatment.

2. The temperature distribution in the reservoir is calculated to the specified distance, taking into account the temperature of the injected water and the time of its injection.

Let be:

Injection water temperature = 25 ° C

Reservoir temperature = 91 ° C

Water injection rate = 52 m ³ / day

Download time = 5 years

Formation porosity = 0.2 units

Formation thermal conductivity = 2.0 W / m K

Heat capacity in the water layer = 0.5 Wh / kg K

The dependence of the temperature in the reservoir on the distance from the well and the time of water injection is shown in FIG. 1. As can be seen from the graph, despite the high initial reservoir temperature (91 ° C), in the installation area of the gel screen (R _k = 50 m), the reservoir is cooled to 30-35 ° C.

3. The composition "polymer + crosslinker" is selected, the gelation time of which at a given temperature is greater than or equal to the time it was pumped into a certain zone of the formation (50 m). The composition is selected based on experimental data. For this, samples of solutions are prepared that are included in the composition with different concentrations of the polymer and crosslinker. Testing of these compositions to determine the gelation time at a temperature of 35 ° C. The gel time is determined using the Relaxometer.

In the composition “polymer + crosslinker” hydrolyzed polymers, for example, polyacrylomide, are used, and salts of trivalent metals of organic acids, for example, chromium acetate, chromium propinate and others, can be used as a crosslinker. Let the gelation time of the selected composition at a temperature of 35 ° C be 24 hours. As a result of filtration studies conducted in laboratory conditions, the value of the initial pressure gradient that this composition withstands in the pore reservoir and fracture is established on the reservoir model. For this, the selected composition is tested in a pore reservoir (fracture) on a bulk reservoir model (fracture model) with permeability close to the reservoir. The reservoir model is prepared from quartz sand with the addition of a certain amount of ground quartz in order to select the required permeability (the fracture model is made in the form of a stainless steel capillary with a diameter simulating the crack opening). The sand model of the formation is placed in a core holder and saturated with water. Then, the selected composition is pumped into the model core in the amount necessary to fill the entire pore volume. The core holder with the composition is placed in a heating cabinet with a temperature of 35 ° C for 24 hours (gelation time of the composition). Then, water is pumped through the core at a flow rate realized in the installation area of the gel screen, with the measurement of the injection pressure. The initial pressure gradient ΔP / l for the polymer composition is the pressure at which the filtration of water through the gel begins. For this example, it was found that the initial pressure gradient for the selected composition in the pore reservoir is 20 atm / m (~ 20 · 10 ⁵ Pa / m) and 5 atm / m (~ 5 · 10 ⁵ Pa / m) in the fracture.

4. The pressure gradient in the reservoir is calculated at a distance R _to from the injection well. The distribution of pressure gradients across the reservoir with increasing distance from the injection well is shown in FIG. 2 for the source data:

k = 4 · 10 ^-12 m ²

h = 2.0 m

R _k = 50 m

R _c = 0.1 m

Δp = P _PL -P _Zab = 50 atm (~ 50 · 10 ⁵ Pa)

µ = 2 · 10 ⁶ Pa · s

Q = 10 m ³ / s

Calculations show that with a distance of 50 m from the injection wells, the pressure gradient decreases from 23 atm / m (~ 23 · 10 ⁵ Pa / m) to 0.06 atm / m (~ 6 · 10 ³ Pa / m).

The composition selected as a result of experimental studies satisfies the strength with a large margin.

5. The minimum volume of the composition is calculated.

a) the minimum screen radius for the bottomhole zone is:

R _e ≥ [P _PL -P _Zab ] / (ΔP / l)

- for a pore collector R _e = 50/20 = 2.5 m;

- for a crack R _e = 50/5 = 10 m;

b) the minimum volume of the composition:

$$V_{\mathrm{to}\mathrm{about}m}=\pi {\left(R_{\mathrm{uh}}+R_{\mathrm{from}}\right)}^{2}hm-\pi hm{R}_c^2$$

- for pore collector:

V _com = 3.14 · (2.5 + 0.1) ² · 2 · 0.2-3.14 · 2 · 0.2 · 0.1 ² = 8.49-0.01256 = 8.5 m ³

- for a crack:

V _com = 3.14 · (10 + 0.1) ² · 2 · 0.2-3.14 · 2 · 0.2 · 0.1 ² = 128.1-0.01256 = 128 m ³

Thus, for the selected composition with the indicated strength and at a pressure difference between the reservoir and bottomhole equal to 50 atm (~ 50 · 10 ⁵ Pa), the injected volume should be 8.5 m ³ and 128 m ³ for the fracture for the pore collector. Taking into account the adsorption phenomena and diffusion processes in the formation, the injected volume of the composition is increased by 5-10 times (depending on the distances over which the composition is pushed).

The method has passed pilot tests, the results of which have shown a positive effect, expressed in a decrease in the water cut in the production of production wells of the environment.

For the implementation of pilot industrial works on the installation of a gel screen in a remote area, an industrial area was selected consisting of one injection well No. 15243 and seven surrounding wells of the Priobskoye field. Clearly, the plot is presented in figure 3.

Analysis of the main geological and physical characteristics of the reservoir allows us to draw the following conclusions:

1) The formation is mainly represented by sandstone with clay inclusions.

The average values of the characteristics of the reservoir:

- porosity (m) 0.136

- permeability (k) 5.9 m ²

- reservoir thickness (h) 18 m

2) There is a high dissection of the section (Kp = 5), which indirectly justifies the avalanche-like flooding of the products.

3) In addition to high layer-by-layer heterogeneity, a pronounced, permeability heterogeneity can be noted (coefficient. Var. = 1.23).

4) The collector is highly clogged (Clin. = 10.35%).

At the time of processing wells. No. 15243 the water content of the environment is 73.8%. Flooding of products took place like an avalanche:

- from May to September 2007 (from 10% to 30%)

- from January to April 2008 (from 23% to 44%)

- from December 2009 to June 2010 (from 52% to 70%).

Waterlogging of products is associated with high fragmentation and the presence of a network of technogenic cracks.

To reduce the amount of produced water and increase the final oil recovery, a technology was recommended to align the injectivity profile by installing a gel screen in a remote area.

The injection of a crosslinkable polymer system (SPS) into the formation was started on September 8, 2011 with an initial wellhead pressure of P _beginning = 116 atm ((~ 116 · 10 ⁵ Pa) and a well injectivity of 256 m ³ / day. 987 m ³ was injected into the formation flow-deflecting composition with a polymer concentration of C _paa = 0.5% and a crosslinker concentration of C _ax = 0.05%. The gelation time of this composition was determined experimentally in the laboratory and amounted to 16 full days.

The injection of the above volume was carried out for six full days and was discontinued on September 14, 2011. The composition was successfully downloaded in full.

, м³ где R_к - заданное расстояние, на котором устанавливается экран, м; R_с - радиус скважины, м; h - толщина пласта, м; m - пористость пласта. Для продавки раствора полимерной композиции в глубь пласта было закачено 1000 м³ воды. Закачка воды производилась в течение 10 суток. При этом композиция была продвинута на расстояние 17-20 м от нагнетательной скважины. После продавки скважина была остановлена на 24 часа для процесса гелеобразования и укрепления гелевого экрана.After the polymer system was pumped into the formation, the composition was sold with water. The volume of injected water V _water required to push the gelling composition to a distance specified from the bottom of the well is determined from the ratio $$V_{\mathrm{at}\mathrm{about}ds}=\pi {\left(R_{\mathrm{to}}+R_{\mathrm{from}}\right)}^{2}hm-\pi R_c^{2}hm$$

, m ³ where R _to - a given distance at which the screen is installed, m; R _with - well radius, m; h is the thickness of the reservoir, m; m is the porosity of the reservoir. To sell a solution of the polymer composition into the reservoir, 1000 m ^{3 of} water was pumped. Water injection was carried out for 10 days. In this case, the composition was advanced at a distance of 17-20 m from the injection well. After the sale, the well was stopped for 24 hours for the gelation process and gel screen strengthening.

After the start-up of the well, the injectivity was measured, which decreased slightly and amounted to 245 m ³ / day. It should be noted that when installing a gel screen in the bottom-hole zone, the injectivity varies greatly, and when installing the screen in the remote zone, it practically does not change. Preservation of throttle response is a positive factor of the proposed method, because its implementation does not require the injection of an intensifying composition.

The analysis of the main technological parameters of the operation of the environment wells showed that during the month of operation in the production wells, a decrease in produced water was observed by 1.2%, which indicates the manifestation of the technological effect when a screen is formed in the remote zone of the reservoir, formed from the polymer gel-forming composition selected by the proposed method .

The calculation of the forecast development indicators and the planned additional production shows that during the month of operation there will be a decrease in the produced water by 0.5%, i.e. in fact, there is a more intense decrease in produced water than in the calculation, and as a result, an increase in oil production.

Claims (1)

A method for selecting a polymer gel-forming composition to enhance oil recovery and waterproofing based on a polymer of acrylamide, a crosslinker and water, including determining the parameters of the formation for a particular well, experimentally characterizing the composition, including gelation time and static shear stress, calculating the initial pressure gradient, gel minimum radius of the screen and the minimum volume of the injected composition, characterized in that the distance is set to R _k removed the zone where the gel screen is to be formed from the bottom of the injection well, the temperature values are determined for this distance according to a previously constructed graph of the distribution of the temperature values calculated according to the temperature of the injected water, speed and time of injection, temperature, porosity and thermal conductivity of the formation, and pressure values - according to a previously constructed graph of the distribution of pressure values over the distance in the formation, calculated according to the formula
ΔP / l = Q · µ / k · 2π · h · R _k ,
where Q is the flow of fluid, m ³ / s,
k - permeability, m ² ,
h is the thickness of the reservoir, m,
R _k is the radius of removal, m,
µ - viscosity, Pa · s,
and the composition is selected from the conditions: the gelation time at a temperature defined for a given zone is not less than the time the composition is injected into this formation zone, and the initial pressure gradient is higher than the depression that the gel will experience in this formation zone.

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