RU2528343C1 - Method of water influx isolation and limitation to horizontal wells - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: method includes pumping and flushing of the polymer solution and well shutdown for the period of polymer gelling. According to the invention geophysical survey is made in order to specify the interval of water influx. Computational experiments are made on the basis of water influx isolation and limitation mathematical model thus evaluating stability of polymer screens for different viscosity and volume of polymer solutions in oil- and water-bearing areas of the productive stratum at the limit depression and depression in service, residual water and oil resistance factors for injected polymer solutions considering type of the productive stratum as well as water cut of the produced oil and its flow rate after insulation and limitation of water influx. At that viscosity of polymer solutions are evaluated in time at temperature of the productive stratum. Then the polymer is selected with required viscosity and volume of injection ensuring stability of the screen based on the above polymer in oil-bearing area of the productive stratum. The selected polymer solution is injected in the calculated volume.

EFFECT: increased efficiency of the method.

2 cl, 4 dwg, 1 tbl

Description

The invention relates to the oil industry, in particular to methods for isolating and restricting water inflows into horizontal trunks of production wells.

A known method of isolating water inflows in a horizontal wellbore of a producing well using a sleeveless long pipe, which consists in filling a horizontal portion of a wellbore with blocking fluid and then pumping a water-insulating composition into the flooded interval of the formation (RF patent No. 2235873, published on September 10, 2004).

The disadvantage of this method is the attraction of additional equipment, in particular a sleeveless long pipe, an increase in the number of tripping operations and the time of the event, the difficulty of pushing the water-insulating composition into the isolation interval by the outgoing pouring method, at which the filling speed of the insulated horizontal hole interval must correspond to the lifting speed of the sleeveless long pipe .

There is a method of isolating water inflows in a horizontal wellbore of producing wells, including filling a portion of the horizontal wellbore with blocking fluid to create a preventive filtration layer, then injecting a polymer solution into the bottomhole zone, pumping a polymer solution, stopping a well while the polymer solution is curing, drilling a cured polymer solution and injecting acid, or diesel fuel, or mineralized solution to remove prophylactic filtration from oya (RF patent №2286448, publ. 27.10.2006 city).

The disadvantage of this method is the complexity of the repair and the increase in the time it takes to carry out the event due to the need to drill a cured polymer solution and inject acid, or diesel fuel, or a mineralized solution to remove the preventive filtration layer.

Closest to the proposed technical solution is a method of interval isolation and restriction of water inflow into horizontal wells (RF patent No. 2363841, publ. 10.08.2009).

The essence of this method lies in the fact that in the method of interval isolation and limiting water inflow into horizontal wells, which includes injecting the polymer into each interval, pumping the polymer solution with water, stopping the well for the period of polymer formation after processing each interval, before injecting the polymer solution into each interval in a blocking fluid is pumped into the well with an optimal “life” time, during which injection of a given volume of polymer into the insulated interval is ensured, according to after which the self-destruction of the blocking fluid occurs, in the amount necessary to fill the horizontal wellbore from the bottom of the well to the closest to the bottom of the boundary of the interval of treatment with the polymer solution, after exposure to the period of polymer structure formation in the last processed interval, the polymer destructor is pumped into the well, which is then forced through water into the formation in the near borehole zone and incubated for the period of destruction of the polymer in this zone.

The specified method is not effective enough due to the use of an unreasonable volume of polymer solution, which can lead to insufficient isolation of water inflow (insignificant decrease in water production or lack thereof) or, conversely, excessive insulation when, along with limiting water in the produced products, a significant decrease in oil production occurs. A disadvantage is the need to use a polymer destructor for forced formation decolmation due to the injection of an unreasonable volume of polymer solution into it, which increases the duration and cost of repairs and reduces the manufacturability of the method.

The objective of the invention is to increase the efficiency of the isolation method and to limit water inflow into horizontal wells by increasing the accuracy of determining the volume of the polymer solution and selecting the injected polymer solution with the most suitable properties in this particular case, as well as improving the manufacturability of the method by simplifying the technology and reducing time well repair.

The technical result is an increase in the isolation efficiency and limitation of water inflow into horizontal wells due to the formation of a stable polymer screen in the water inflow interval and, conversely, unstable in the productive interval (as a result of selecting a polymer solution with the most suitable properties and calculating the volume of the polymer solution). Accordingly, according to the proposed method, there is no need to use a polymer destructor, which reduces the duration and cost of repairs and increases its manufacturability.

The specified technical result is achieved by the fact that in the method of isolating and restricting water inflow into horizontal wells, including injecting and selling polymer solution, stopping the well for the period of polymer formation, according to the invention, geophysical studies are preliminarily carried out to clarify the interval of water inflow, computational experiments based on a mathematical model are carried out the process of isolation and limitation of water inflow, evaluating for different viscosity solutions of polymers and volumes the solution polymer stability of polymer screens in the oil and water saturated zones of the reservoir at extreme depression and depression during operation, factors of residual resistance of the injected polymer solutions in water and oil, taking into account the type of reservoir, and the water cut of the produced oil and its flow rate after isolation and limitation of water inflows, moreover, the viscosity of polymer solutions is evaluated over time at the temperature of the reservoir, then choose a polymer with the desired viscosity and injection volume, providing the stability of the screen from it in the water-saturated zone and the instability of the screen in the oil-saturated zone of the reservoir, and the selected polymer solution is pumped in the calculated volume. In addition, if necessary, a temporary blocking composition that is not filtered into the reservoir is pumped before the polymer solution is injected.

As the polymer composition can be used, for example, a composition containing, parts by weight: polyacrylamide 0.5-2.5, water 97-99.45, a crosslinking agent, chromium acetate 0.05-0.5.

As a temporary blocking composition that is not filtered into the reservoir, for example, an inverse emulsion can be used, containing, by volume: oil 25-45, water repellent ADB 4-5, water 50-70.

The results of laboratory studies necessary to calculate the volume of the polymer solution and the selection of its properties can be obtained by conducting a laboratory study of the polymer solution immediately before isolation and restricting water inflow into horizontal wells or from literary sources (Nikishov Vyacheslav Ivanovich. Improving the technology of repair and insulation works on the correction of a leaky cement ring on the example of deposits in Western Siberia: the dissertation of the candidate tehnich science; Ufa, 2010. - 177 pp., ill .; Oleg Tyapov. Increasing the efficiency of developing complex deposits by shutting off the upper layer: the dissertation of the candidate of technical sciences: 25.00.17 / Oleg Anatolyevich Tyapov; [Place of defense: Institute of Transport Problems energy resources]. - Ufa, 2010. - 162 pp .: ill. RSL OD, 61 10-5 / 1744; Nigmatullin T.E., Borisov I.M., Kornilov A.V., Politov M.E., Telin A.G. Laboratory testing of materials for repair and insulation works in horizontal wells // Scientific and Technical Bulletin of Rosneft Oil Company. - 2012. - No. 2. - S.12-15).

The principal difference of the proposed method of isolation and limitation of water inflow into horizontal wells is the design of insulation and limitation of water inflow due to the choice of polymer solution and its volume based on the results of computational experiments based on a mathematical model of the process of limiting and isolating water inflow, which is optimal from the standpoint of achieving the technical result.

The method is carried out by the following sequence of operations:

1. In the well, geophysical studies are carried out to clarify the interval of water inflow.

2. Carry out computational experiments based on a mathematical model of the process of isolation and limitation of water inflow, calculating for different polymer solutions and polymer solution volumes an increase in oil production and a reduction in water cut after treatment, select the polymer solution and its volume that allows to obtain the largest increase in oil production and the greatest reduction in water production after treatment.

3. The selected polymer solution is pumped into the well through the tubing string in the calculated volume. The injection is initially carried out with the annular valve open; when the polymer solution reaches the tubing shoe, the valve is closed. The polymer fills the wellbore and is filtered into the formation, and more to the area of water inflow, which is achieved by the selectivity of polymer filtration.

4. Carry out the injection into the reservoir of a polymer solution with water. The well is cleaned of the remains of the polymer solution by washing with water.

5. Spend technological exposure for the period of gelation lasting 24-72 hours.

If necessary, for example, when the interval of water inflow is close to the interval of set of curvature (heel) of the horizontal trunk, a temporarily blocking composition that is not filtered into the reservoir is preliminarily pumped before injection of the polymer solution.

Computational experiments, allowing to calculate oil flow rate and water cut after well repair using a certain polymer solution in a certain volume, are carried out, for example, by the following operations:

1. The viscosity of the polymer solution based on laboratory tests is presented as a function of time, for example, in the form of:

$$\mu \left(t\right)={\mu }_0{e}^{bt},\left(\mathrm{one}\right)$$

Where

t is the time

µ (t) is the viscosity of the polymer solution at time t,

µ ₀ is the initial viscosity of the polymer solution or viscosity at time t = 0,

b is the rate of increase in the viscosity of the polymer solution with time.

2. In the case of zonal heterogeneity of the layers along the wellbore, the weighted average parameters of the oil and water saturated zones are determined:

$$m_{\mathrm{one}}=\frac{\mathrm{one}}{l_{\mathrm{one}}}{\displaystyle \sum _{i=\mathrm{one}}^{n_{\mathrm{one}}}{l}_{\mathrm{one}i}{m}_{\mathrm{one}i}},m_2=\frac{\mathrm{one}}{l_2}{\displaystyle \sum _{i=\mathrm{one}}^{n_2}{l}_{2i}{m}_{2i}},\left(2\right)$$

$$k_{\mathrm{one}}=\frac{\mathrm{one}}{l_{\mathrm{one}}}{\displaystyle \sum _{i=\mathrm{one}}^{n_{\mathrm{one}}}{l}_{\mathrm{one}i}{k}_{\mathrm{one}i}},k_2=\frac{\mathrm{one}}{l_2}{\displaystyle \sum _{i=\mathrm{one}}^{n_2}{l}_{2i}{k}_{2i}},\left(3\right)$$

, $$l_{\mathrm{1,2}}={\displaystyle \sum _{i=\mathrm{one}}^{n_{\mathrm{1,2}}}{l}_{\mathrm{1,2}i}}$$

,

Where

m ₁ - weighted average porosity of the oil-saturated zone of the reservoir,

l ₁ - the total length of the oil-saturated zones of the reservoir,

n ₁ - the number of oil-saturated zones of the reservoir,

i is the serial number of the oil or water saturated zone in the reservoir,

l _1i - the length of the i-th oil-saturated zone of the reservoir,

m _1i - porosity of the i-th oil-saturated zone of the reservoir,

m ₂ - weighted average porosity of the water-saturated zone of the reservoir,

l ₂ - the total length of the water-saturated zones of the reservoir,

n ₂ - the number of water-saturated zones of the reservoir,

l _2i - the length of the i-th water-saturated zone of the reservoir,

m _2i - porosity of the i-th water-saturated zone of the reservoir,

k ₁ - weighted average permeability of the oil-saturated zone of the reservoir,

k _1i is the permeability of the i-th oil-saturated zone of the reservoir,

k ₂ - weighted average permeability of the water-saturated zone of the reservoir,

k _2i is the permeability of the i-th water-saturated zone of the reservoir.

3. Determine the length of the semimajor axis of the drain ellipse:

Where

a is the length of the major axis of the drain ellipse,

L is the length of the horizontal wellbore of the horizontal well (HS),

R _k is the radius of the power circuit.

4. Determine the radius of the perturbed pressure zone in the reservoir:

Where

R * is the radius of the perturbed pressure zone in the reservoir.

5. The pseudo-skin factor S * is determined by the parameters of the well’s operation before sharp watering, taking into account contamination of the bottom-hole region of the horizontal well, asymmetry of location, and also slope to the horizon:

Where

S * - pseudo-skin factor,

h ₁ - the thickness of the reservoir,

- пластовое давление в продуктивном пласте до обводнения ГС, $${\tilde{p}}_{k\mathrm{one}}$$

- reservoir pressure in the reservoir before flooding GS,

- давление на забое до обводнения ГС, $${\tilde{p}}_w$$

- pressure at the bottom to watering the well,

- вязкость нефти до обводнения ГС, $${\tilde{\mu }}_o$$

- the viscosity of the oil before watering the HS,

- вязкость пластовой воды до обводнения ГС, $${\tilde{\mu }}_o$$

- viscosity of produced water prior to watering of the horizontal well,

- дебит жидкости из продуктивного пласта до обводнения скважины. $${\tilde{Q}}_{\mathrm{one}}$$

- fluid flow rate from the reservoir to the watering of the well.

6. Determine the coefficient of piezoconductivity of oil and water saturated zones of the reservoir occupied by oil and water, respectively:

$${\chi }_{\mathrm{one}}=\frac{k_{\mathrm{one}}}{{\mu }_o\left(m_{\mathrm{one}}{\beta }_o+{\beta }_{\mathrm{one}}\right)},\left(7\right)$$

Where

χ ₁ - the coefficient of piezoconductivity of the oil-saturated zone of the reservoir occupied by oil,

χ ₁ - the coefficient of piezoconductivity of the water-saturated zone of the reservoir, occupied by water,

µ _o - oil viscosity at the time of isolation and limitation of water inflows,

µ _a - viscosity of produced water at the time of isolation and limitation of water inflows,

β _o - coefficient of elastic compressibility of oil,

β _a - coefficient of elastic compressibility of water,

β ₁ - coefficient of elastic compressibility of the oil-saturated zone of the reservoir,

β ₂ - coefficient of elastic compressibility of the water-saturated zone of the reservoir.

7. The radii of the front of the polymer solution in the reservoir after injection of the polymer solution are determined, together solving the system of equations:

$$\frac{\partial u\left(x,t\right)}{\partial x}=-\frac{2m_{\mathrm{one}}}{R_w}{\upsilon }_n\left(x,t\right),\left(8\right)$$

$$\frac{\partial u\left(x,t\right)}{\partial t}+\frac{\partial u{\left(x,t\right)}^2}{\partial x}=-\frac{\mathrm{one}}{\rho }\frac{\partial p\left(x,t\right)}{\partial x}+g\cos \varphi -\frac{\left(\mathrm{one}-m_{\mathrm{one}}\right)C_{w}u{\left(x,t\right)}^2}{R_w},\left(9\right)$$

$$\frac{d{x}_{TM}\left(t\right)}{dt}=u\left(x_{TM},t\right)\left(10\right)$$

with initial and boundary conditions:

for pumping from the “heel” of the horizontal trunk

$$u\left(x0\right)=0p\left(x0\right)=p_{k\mathrm{one}},u\left(x_s,t\right)=\frac{Q}{\pi R_w^2},u\left(x_f,t\right)=0x_{TM}\left(0\right)=0\tau \left(x_s\right)=0\left(11.1\right)$$

for pumping from the bottom of a horizontal trunk

$$u\left(x0\right)=0p\left(x0\right)=p_k,u\left(x_s,t\right)=\frac{Q}{\pi \left(R_w^2-R_{out}^2\right)},u\left(x_f,t\right)=0x_{TM}\left(0\right)=0\tau \left(x_s\right)=0\left(11.2\right)$$

Where

x is the coordinate of the point, the distance from the entrance of the reservoir to the given point,

u (x, t) is the average flow rate over the cross section of the HS when pumping the polymer solution at a point with coordinate x at time t,

p (x, t) is the pressure at a point with coordinate x along the trunk of the horizontal well at time t,

R _w is the radius of the horizontal wellbore along the bit,

υ _n (x, t) is the rate of fluid flow into the reservoir when pumping the polymer solution,

g is the gravity field,

φ is the angle of deviation of the well from the vertical,

ρ is the density of the polymer solution during injection,

C _w = λ (Re) / 4 - coefficient of proportionality between the friction stress and dynamic pressure,

x _TM (t) is the position of the leading front of the polymer solution in the horizontal wellbore during injection,

Q is the constant flow rate of the polymer solution when injecting TM,

x _s is the coordinate with which the injection of the composition into the formation begins,

x _f - coordinate along the wellbore to which the front of the polymer solution moves along the wellbore (x _s ≤x≤x _f ),

p _k1 - pressure on the supply circuit in the reservoir;

τ (x) is the point in time at which the front of the polymer solution reaches the point with coordinate x,

R _out is the outer diameter of the flexible tubing (CT).

7.1. The coordinates x _s and x _{f of the} beginning and end of front movement along the horizontal trunk of the horizontal well are defined as follows:

7.1.1. When pumping the polymer solution from the interval of the set of curvature, the coordinates x _s and x _{f are} set in accordance with paragraphs 7.1.1.1-7.1.1.3.

7.1.1.1. If the polymer solution is pumped by a single filter without using a temporarily blocking composition (BBC), then x _s ≡ 0, x _f = L.

7.1.1.2. If the polymer solution is pumped using WBS, then x _s ≡ 0, and x _f coincides with the coordinate of the contact of the water fronts and the WBS.

7.1.1.3. If the download occurs in the interval between two packers, then x _s is determined by the position of the packer closest to the adapter, and x _f - by the far one.

7.1.2. When pumping the polymer solution from the interval of set of curvature, they pass to a coordinate system whose origin is located at point x _s and is located on the side of the bottom of the horizontal axis, and the abscissa axis is directed towards the interval of set of curvature. Then the coordinates x _s and x _f set in accordance with paragraphs 7.1.2.1-7.1.2.3.

7.1.2.1. If the polymer solution is pumped by a single filter without the use of VSS, then in the coordinate system specified in Section 3.5, x _s = 0, x _f = L.

7.1.2.2. If the polymer solution is injected using WBS, then in the coordinate system specified in Section 3.5, x _s ≡ 0, and x _f coincides with the coordinate of the interface between the water fronts and the WBS.

7.1.2.3. If the polymer solution is pumped in the interval between two packers, then x _s is determined by the position of the packer closest to the bottom and x _f by the far one.

7.2. At x≤x _TM (t), the flow rate of fluids into the formation during injection of the polymer solution is determined according to the expressions:

$${\upsilon }_n\left(x,t\right)=\frac{k_{\mathrm{one}}}{m_{\mathrm{one}}\mu \left(t\right)}\frac{p\left(x,t\right)-p_{k\mathrm{one}}}{\left[R_{TM}\left(x,t\right)-R_w+\frac{{\mu }_o}{\mu \left(t\right)}\ln \frac{\sqrt{R_w^2+\mathrm{four}{\chi }_{\mathrm{one}}t}}{R_{TM}\left(x,t\right)}\right]},x_s\le x<x_{wl},x_{wr}<x\le x_f,\left(12\right)$$

$$R_{TM}\left(x,t\right)=\sqrt{R_w^2+2R_w{\displaystyle \underset{\tau \left(x\right)}{\overset{t}{\int }}{\upsilon }_n\left(x,t\right)dt}},\left(\mathrm{fourteen}\right)$$

Where

R _TM (x, t) is the radius of the screen from the polymer solution at the point of the reservoir with the x coordinate at time t,

x _wl - coordinate of the border of the water-saturated zone closest to the adapter,

x _wr is the coordinate of the boundary of the saturated zone from the adapter.

7.2.1. When pumping a polymer solution into an open hole

$$\mathrm{Re}=\frac{2\rho u\left(x,t\right)R_w}{\mu \left(t\right)},\left(\mathrm{fifteen}\right)$$

Where

Re is the Reynolds number,

7.2.1.1. in case of laminar flow (Re≤2300)

$$\lambda \left(\mathrm{Re}\right)=\frac{64}{\mathrm{Re}},\left(16\right)$$

Where

λ (Re) - coefficient of hydraulic resistance.

7.2.1.2. in turbulent flows (Re> 2300)

$$\lambda \left(\mathrm{Re}\right)=\frac{0.3164}{\sqrt[\mathrm{four}]{\mathrm{Re}}}.\left(17\right)$$

7.2.2. In the case of completion of the well with a centered (not cemented) shank with casing packers

$$\mathrm{Re}=\frac{2\rho u\left(x,t\right)R_{lin}}{\mu \left(t\right)},\left(\mathrm{eighteen}\right)$$

Where

R _lin is the inner radius of the shank.

7.2.3. In the case of completion of the well with a centered shank without packers

$$\mathrm{Re}=\frac{2\rho u\left(x,t\right)\left(R_w-R_{lout}\right)}{\mu \left(t\right)},\left(19\right)$$

Where

R _lout is the outer radius of the shank.

7.2.3.1. in case of laminar flow (Re≤2000)

$$\lambda \left(\mathrm{Re}\right)=\frac{\mathrm{one}-d^2}{\mathrm{one}+d^2+\left(\mathrm{one}-d^2\right)/\ln d}\cdot \frac{64}{\mathrm{Re}},\left(\mathrm{twenty}\right)$$

Where

d = R _lout / R _w .

7.2.3.2. in turbulent flows (Re> 2000)

$$\lambda \left(\mathrm{Re}\right)=\left(0.02d+0.98\right)\left(\frac{\mathrm{one}}{{\lambda }^{*}}-0.27d+0.1\right),\left(21\right)$$

where λ ^{* is} calculated by the formula (17), assuming that the Reynolds number is determined by the expression (19).

7.2.4. In the case of completion of a well with a cased shank, the coefficient of hydraulic resistance and the Reynolds number are determined by formulas (16), (17) and (18).

7.3. At x> x _TM (t), the rate of flow of the polymer solution into the formation is determined by the expression:

$$R\left(x,t\right)=\sqrt{R_w^2+2R_w{\displaystyle \underset{0}{\overset{t}{\int }}{\upsilon }_n\left(x,t\right)dt}},\left(24\right)$$

and the coefficient of hydraulic resistance λ (Re) is determined in accordance with paragraphs 7.2.1-7.2.4.

7.4. At each time step, the following quantities are determined:

7.4.1. The residence time of the polymer solution in a flexible tubing (CT)

$$T_{\tilde{A}\stackrel{\text{'}\text{'}}{I}\widehat{E}\stackrel{\text{'}\text{'}}{O}}=\frac{\pi D_{in}^2{h}_{\tilde{A}\stackrel{\text{'}\text{'}}{I}\widehat{E}\stackrel{\text{'}\text{'}}{O}}}{\mathrm{four}Q},\left(26\right)$$

Where

- время нахождения раствора полимера в ГНКТ, $$T_{\tilde{A}\stackrel{\text{'}\text{'}}{I}\widehat{E}\stackrel{\text{'}\text{'}}{O}}$$

- the residence time of the polymer solution in CT

D _in - the inner diameter of the CT,

h _CT - depth of descent of CT.

7.4.2. The average dynamic viscosity of the polymer solution during CT flow:

$$\overline{\mu }=-\frac{{\mu }_0}{b{T}_{\tilde{A}\stackrel{\text{'}\text{'}}{I}\widehat{E}\stackrel{\text{'}\text{'}}{O}}}\left(e^{-b{T}_{\tilde{A}\stackrel{\text{'}\text{'}}{I}\widehat{E}\stackrel{\text{'}\text{'}}{O}}}-\mathrm{one}\right),\left(27\right)$$

Where

- средняя динамическая вязкость раствора полимера при течении по ГНКТ. $$\overline{\mu }$$

- the average dynamic viscosity of the polymer solution during flow along the CT.

7.4.3. Reynolds number during the flow of a polymer solution by CT:

$$\mathrm{Re}=\frac{\mathrm{four}\rho Q}{\pi \overline{\mu }{D}_{in}}.\left(28\right)$$

7.4.4. The coefficient of hydraulic friction during the flow of polymer solution in coiled tubing

7.4.4.1. for laminar flow (Re≤2300)

$$\lambda =\frac{64}{\mathrm{Re}},\left(\mathrm{29th}\right)$$

7.4.4.2. for turbulent flow regime (Re> 2300)

$$\lambda =0.0032+\frac{0.221}{{\mathrm{Re}}^{0.237}},\left(\mathrm{thirty}\right)$$

7.4.5. At each time step, the pressure at the wellhead is determined according to:

$$p_{wh}\left(t\right)=p\left(0t\right)-\rho g{h}_{\tilde{A}\stackrel{\text{'}\text{'}}{I}\widehat{E}\stackrel{\text{'}\text{'}}{O}}+8h_{\tilde{A}\stackrel{\text{'}\text{'}}{I}\widehat{E}\stackrel{\text{'}\text{'}}{O}}\lambda \left(\mathrm{Re}\right)\frac{\rho Q^2}{{\pi }^2{D}_{in}^5},\left(31\right)$$

Where

p _wh (t) is the pressure at the wellhead at time t when pumping the polymer solution.

7.4.6. Determine the volume of polymer solution pumped into the formation at each time step using the formula:

$$V\left(t\right)=\pi \left[m_{\mathrm{one}}{\displaystyle \underset{x_s}{\overset{x_{wl}}{\int }}\left(R_{TM}^2-R_w^2\right)dx+m_2}{\displaystyle \underset{x_{wl}}{\overset{x_{wr}}{\int }}\left(R_{TM}^2-R_w^2\right)dx+m_{\mathrm{one}}}{\displaystyle \underset{x_{wr}}{\overset{x_{TM}}{\int }}\left(R_{TM}^2-R_w^2\right)dx}\right].\left(32\right)$$

7.5. The calculation of the injection of the polymer solution is stopped at time t ₁ , determined by the fulfillment of one of the following conditions:

7.5.1. The required volume of polymer solution has been pumped.

$$V\left(t_{\mathrm{one}}\right)+\pi R_w^2{x}_{TM}\left(t_{\mathrm{one}}\right)\ge V_{TM}\mathrm{and}l\mathrm{and}Q{t}_{\mathrm{one}}\ge V_{TM},\left(33\right)$$

Where

V _TM - the planned volume of injection of the polymer solution.

7.5.2. The pressure on the mouth has grown above acceptable

$$p_{wh}\left(t_{\mathrm{one}}\right)\ge p_{cr},\left(34\right)$$

Where

p _cr is the critical value of the pressure at the wellhead.

8. If the polymer solution was pumped from the bottom of the horizontal well, they switch to a coordinate system in which the beginning of the abscissa axis coincides with the center of the vertical horizontal wellbore, and the axis itself is directed towards the horizontal bottom of the horizontal well.

9. Determine the technological success of isolation and limitation of water inflows by checking the fulfillment of the following conditions for the stability of the polymer solution in the isolated area of the reservoir:

9.1. if the polymer solution is injected into the terrigenous reservoir, then

$$\Delta p=p_{k\mathrm{one}p}-p_{wp}<\frac{0.55\left(R_{TM}\left(x_{wr},t_{\mathrm{one}}\right)-R_w\right){\tau }_g}{\sqrt{k_2}},\left(35.1\right)$$

Where

x _wr coincides with the coordinate along the wellbore, where the radius of the cement composition in the water-saturated zone of the formation is minimal,

τ _g is the ultimate static shear stress of the polymer;

9.2. if the polymer solution is injected into the carbonate formation, then

where (∂p / ∂r) _2cr is the critical pressure gradient of the polymer in the water-insulated zone along the wellbore.

If the conditions (35.1) or (35.2) are not satisfied, change the planned volume of the polymer solution and repeat paragraphs 7-9.

10. Determine the area of stability of the gel in the oil-saturated formation, checking the following conditions:

9.1. if the polymer solution is injected into the terrigenous reservoir, then

for all x from the interval (0, x (t ₁ ));

9.2. if the polymer solution is injected into the carbonate formation, then

for all x in the intervals (x _s , x _wl ) and (x _wr , x (t ₁ )),

Where

(∂p / ∂r) _1cr is the critical pressure gradient of the polymer in the oil-saturated zone along the wellbore.

11. The following values are determined:

11.1. Residual Resistance Factors for a polymer in a carbonate formation:

11.1.1. if the screen in the water-saturated zone is stable, then the residual water resistance factor

Z _a = ∞,

where Z _a is the residual resistance factor of the polymer solution in water,

11.1.2. if the screen in the water-saturated zone is unstable, then the residual water resistance factor

Where

C ₂ , ω ₂ - constants characteristic of this polymer,

11.1.3. if the screen in the oil-saturated zone is stable, then the residual oil resistance factor

Z _o = ∝,

Where

Z _o - residual resistance factor for oil,

11.1.4. if the screen in the oil saturated area is unstable

Where

C ₁ , ω ₁ are constants characteristic of this polymer.

11.2. The flow rate of fluid from the reservoir after isolation and limitation of water inflows:

11.2.1. for terrigenous strata

Where

p _k1p is the contour pressure in the reservoir after isolation and limitation of water inflows,

p _wp - bottomhole pressure after isolation and limitation of water inflows,

L _go - the length of the oil-saturated region in the reservoir, occupied by the polymer,

L _ga - the length of the water-saturated region in the reservoir occupied by the polymer, Z _o - the residual resistance of the polymer to oil,

Z _a - factor of residual polymer resistance to water,

11.2.2. for carbonate formation

$$Q_p=\frac{2\pi k_{\mathrm{one}}{h}_{\mathrm{one}}\left(p_{k\mathrm{one}p}-p_{wp}\right)}{{\mu }_{o}L\left[\ln R*+\frac{h_{\mathrm{one}}}{L}\ln \left(\frac{h_{\mathrm{one}}}{2R_w}\right)+S*\right]}\cdot \left(\left(L-L_g\right)+\frac{L_{g-}}{Z_o}\right),\left(40\right)$$

where L _g - the length of the region in the reservoir, which when pumped into the polymer,

L _g– is the extent of the oil-saturated region in the reservoir occupied by an unstable polymer screen.

11.3. Water cut after isolation and limitation of water inflows:

11.3.1. in case of terrigenous stratum

Where

- обводненность продукции до резкого обводнения скважины; $$\tilde{\eta }$$

- water cut to a sharp water cut of the well;

11.3.2. in the case of a carbonate formation

$${\eta }_p=\tilde{\eta },\left(41.2\right)$$

11.4. Oil production after isolation and limitation of water inflows:

$$Q_{op}=\left(\mathrm{one}-{\eta }_p\right)Q_p.\left(42\right)$$

Carrying out the calculations according to formulas (1) - (42) for various polymer solutions and various volumes of polymer solution, the polymer solution and its volume are selected that lead to a maximum increase in oil production and a maximum decrease in water cut in well production.

As an example, we consider the isolation and limitation of water inflows in a horizontal well of the Tarasovskoye field operating a terrigenous reservoir.

General information: the depth of the upper (closest to the interval of curvature ("heel") horizontal hole) perforation holes 2915.8 m (2429.4 m in absolute depth), lower ones - 3179.8 m (2429.0 m in absolute depth) ; perforated formation thickness 270 m; radius of a food contour of 250 m; oil viscosity at reservoir conditions 0.52 cPz; oil density 0.822 kg / m ³ ; viscosity of formation fluid (water-oil mixture) 1.26 cPz; density of produced water 1.011 kg / m ³ .

The parameters of the waterlogged well: reservoir pressure of 240 atm, bottomhole pressure of 158 atm, oil flow rate of 4.7 tons / day, fluid rate of 260 m ³ / day, water cut of 97.8%.

Limitations in the process of injection of the polymer solution: the maximum allowable pressure at the wellhead is 115 atm.

Let us give an example of work on isolation and limitation of water inflows in the horizontal well under consideration according to the prototype.

As an insulating material, by expert judgment, an aqueous solution of the polymer (polyacrylamide) WSO-955 with a concentration of 0.7% by mass was selected. with a crosslinking agent chromium acetate concentration of 0.088% of the mass. Based on the field experience of isolating and limiting water inflow into horizontal wells, it was planned to pump 100 m ^{3 of} this polymer solution.

A polymer solution is pumped into the well through a tubing string with an open annular valve; when the polymer solution reaches the tubing shoe, the valve is closed and pumping continues. After the injection is completed, the well is washed from the remnants of the polymer solution with water and technological exposure is carried out for the gelation period of the polymer solution for 24 hours.

We calculate the injection of the polymer solution according to the formulas (1) - (42) to assess the effectiveness of the application of the prototype method.

According to laboratory studies conducted by the authors, the dependence of the viscosity of the polymer solution (polyacrylamide) WSO-955 on time at 75 ° C (reservoir temperature) has the form:

µ (t) = 45 exp (0,000088t),

where time (t) is in seconds and viscosity (µ) is in MPa · s.

Also, according to the results of laboratory studies of the authors, the factors of residual resistance of the injected polymer solution for water and oil in the terrigenous reservoir are 1500 and 20, respectively.

The calculation according to formulas (1) - (42) shows that when injected with a flow rate of 172 m ³ / day (for example, pumping with a CA-320 unit at a second speed) in 116 minutes (from the moment of delivery of the polymer solution to the perforation holes of a horizontal well), the horizontal well will be pumped with 4.5 m ³ of polymer solution, after which the pressure at the mouth will reach a limit of 115 atm.

The dependence of the pressure at the wellhead and the position of the front of the polymer solution in the horizontal well during pumping versus time is shown in graphical form in Fig. 1. The solid curve in Fig. 1 shows the time dependence of the pressure at the wellhead during injection of the polymer solution. It can be seen that in 116 minutes the pressure at the mouth reaches a limit of 115 atm, which will stop the pumping process. The dashed curve in figure 1 shows the dependence of the position of the front of the polymer solution on time in the horizontal well when pumping the polymer solution. By the time the maximum allowable pressure at the wellhead reaches 115 atm, the front of the polymer solution along the horizontal wellbore will pass 260 m out of 266 m. Moreover, according to the calculation, in the water-saturated zone of the formation, the radius of the polymer screen will be about 10 cm.

To analyze the effectiveness of works on isolation and limitation of water inflows, it is necessary to assess the stability of the obtained polymer screens in the oil and water saturated zones of the reservoir. To do this, it is necessary to compare the maximum depression that the polymer screen can withstand, with the depression on the polymer screen, planned during the operation of the well (see figure 2). In figure 2:

the horizontal axis represents the distance from the upper perforation holes along the horizontal trunk;

the value of depression is depicted on the left vertical axis (the maximum depression that the polymer screen can withstand, or the depression on the polymer screen that is planned during well operation);

the radius of the polymer screen from the central axis of the horizontal trunk is plotted on the right vertical axis;

the horizontally shaded area shows the portion of the horizontal barrel filled with the polymer solution at the end of the polymer solution injection process;

the area shaded with a fine square grid shows the distribution of the polymer screen in the oil-saturated zone of the reservoir;

the upper boundary of this region - a solid thin line - shows the radius of the polymer screen in the oil-saturated zone of the reservoir;

the area shaded by a large square grid shows the distribution of the polymer screen in the water-saturated zone of the reservoir;

the upper boundary of this region — a solid thin line — shows the size of the polymer screen in the water-saturated zone;

the solid bold line indicates the extreme depression that the polymer screen can withstand;

dashed bold line shows the amount of depression on the polymer screen, planned during the operation of the well.

Figure 2 shows that the polymer screen is stable in the water-saturated zone of the formation (the solid bold line lies above the dashed bold line in the area shaded by a large square grid) with a safety margin of about 260 atm. In addition, the polymer screen will be stable in a significant part of the oil-saturated zone of the formation (the solid bold line lies above the dashed bold line in the area shaded by a fine square grid) with a safety margin of up to 30 atm.

According to the calculations, the oil flow rate after isolation and limitation of water inflows will be 0.4 tons / day (due to the stable polymer screen in the oil-saturated part of the reservoir), the liquid flow rate is 4.2 m ³ / day with a water cut of 87.2%.

Thus, according to the calculation results, the initially injected volume of the polymer was chosen incorrectly, and only 13.3 m ³ of polymer solution can be injected into the well. In addition, this volume of a polymer solution with these properties is not the best, since the water-proof screen remains stable in the oil-saturated zone during well operation after isolation and limitation of water inflow, which leads to a significant decrease in oil production.

Since, according to the prototype, the oil flow rate after isolation and limitation of water inflows is predicted to be extremely low according to the calculation results, a polymer solution was selected that is better filtered (has a lower viscosity) than the polymer solution (polyacrylamide) WSO to increase the efficiency of work on limiting and isolating water inflows. -955, and after gelation, it has lower strength characteristics so that the condition of stability of the polymer screen in the water-saturated part of the formation and the condition of instability of poly measuring screen in the oil saturated zone.

According to the invention:

1. Geophysical studies of the well were carried out, according to the results of which it was determined that the interval 3036.9-3043.0 m, which is part of the zone with serial number 8 in the table, is water saturated.

Zone number The depth of the roof layer (measured), m Interlayer thickness, m The depth of the sole of the layer (measured), m Porosity,% Permeability, MD one 2915.8 15.6 2931.4 21.8 1,6 2 2931.4 26,4 2957.8 19.6 2.2 3 2957.8 11.5 2969.3 20,2 5 four 2969.3 12.8 2982.1 22.2 12.8 5 2982.1 28,4 3010.5 22.3 8 6 3010.5 6.9 3017.4 22.3 11.8 7 3017.4 8 3025,4 20.5 3.6 8 3025,4 18.2 3043.6 20.8 6.1 9 3043.6 13,4 3057 21.6 7.8 10 3057 20.5 3077.5 20.9 6.9 eleven 3077.5 15.9 3093.4 19.7 9.5 12 3093.4 19.9 3113.3 19.9 12,2 13 3113.3 1.7 3115 21.5 11.5 fourteen 3115 9 3124 19,4 8.5 fifteen 3124 5,4 3129,4 17.5 3,5 16 3129,4 27 3156.4 18.9 1.8 17 3156.4 13.9 3170.3 17.7 2,3 eighteen 3170.3 9.5 3179.8 17.3 3,7

2. As an insulating material, a solution of polymer (polyacrylamide) Poly-T-101 with a concentration of 0.5% by mass was selected. with a crosslinking agent chromium acetate concentration of 0.05% of the mass. The choice of the volume of the polymer solution (polyacrylamide) Poly-T-101 was carried out using a computational experiment according to formulas (1) - (42).

According to laboratory studies conducted by the authors, the dependence of the viscosity of a given polymer solution on time at 75 ° C (reservoir temperature) has the form:

µ (t) = 24 exp (0,000045t),

where time (t) is in seconds and viscosity (µ) is in MPa · s.

Also, according to the results of laboratory studies of the authors, the factors of residual resistance of the injected polymer solution for water and oil in the terrigenous reservoir are 440 and 10, respectively.

The calculation according to formulas (1) - (42) showed that when injected with a flow rate of 172 m ³ / day (for example, pumping with a CA-320 unit at a second speed) in 58 minutes (from the moment of delivery of the polymer solution to the perforation holes of a horizontal well), a horizontal trunk will be pumped with 6.9 m ³ of polymer solution, after which the pressure at the mouth will reach a limit of 115 atm.

The dependence of the pressure at the wellhead and the position of the front of the polymer solution in the horizontal well during pumping versus time is shown in graphical form in FIG. 3. The solid curve in Fig. 3 shows the time dependence of the pressure at the wellhead during injection of the polymer solution. It can be seen that in 58 minutes the pressure at the mouth reaches a limit of 115 atm, which will stop the pumping process. The dashed curve in Fig. 3 shows the time dependence of the front of the polymer solution in the horizontal well when pumping the polymer solution. By the time the maximum allowable pressure at the wellhead is reached 115 atm, the polymer solution front along the horizontal wellbore will pass 264 m out of 266 m. According to the calculation, in the water-saturated zone of the formation, the radius of the polymer screen will be about 11 cm.

To analyze the effectiveness of works on isolation and limitation of water inflows, it is necessary to assess the stability of the obtained polymer screens in the oil and water saturated zones of the reservoir. For this, it is necessary to compare the extreme depression that the polymer screen can withstand with the depression on the polymer screen, which is planned during the operation of the well (see figure 4). In figure 4:

the horizontal axis represents the distance from the upper perforation holes along the horizontal trunk;

the value of depression is depicted on the left vertical axis (the maximum depression that the polymer screen can withstand, or the depression on the polymer screen that is planned during well operation);

the radius of the polymer screen from the central axis of the horizontal trunk is plotted on the right vertical axis;

the horizontally shaded area shows the portion of the horizontal barrel filled with the polymer solution at the end of the polymer solution injection process;

the area shaded with a fine square grid shows the distribution of the polymer screen in the oil-saturated zone of the reservoir;

the upper boundary of this region - a solid thin line - shows the radius of the polymer screen in the oil-saturated zone of the reservoir;

the area shaded by a large square grid shows the distribution of the polymer screen in the water-saturated zone of the reservoir;

the upper boundary of this region — a solid thin line — shows the size of the polymer screen in the water-saturated zone;

the solid bold line indicates the extreme depression that the polymer screen can withstand;

dashed bold line shows the amount of depression on the polymer screen, planned during the operation of the well.

Since the viscosity of the polymer solution (polyacrylamide) Poly-T-101 at each time point is less than the viscosity of the polymer solution (polyacrylamide) WSO-955, the radius of the polymer screen in the formation when isolating and limiting water inflows according to the invention (Fig. 4) is greater than prototype (figure 2).

Figure 4 shows that the polymer screen is stable in the water-saturated zone of the formation (the solid bold line lies above the dashed bold line in the area shaded by a large square grid) with a safety margin of about 30 atm. In the oil-saturated zone of the formation, the polymer screen will be unstable (the solid bold line lies below the dashed bold line in the area shaded by a fine square grid) and will be displaced over time, which will restore the productivity of the oil-saturated zone of the formation.

According to the calculations, the oil flow rate after isolation and limitation of water inflows will be 5.8 tons / day, the liquid flow rate is 55.4 m ³ / day with a water cut of 87.2%.

The calculated oil flow rate after isolation and water inflow restriction using the polymer solution (Polyacrylamide) Poly-T-101 is 14 times higher than the oil flow rate after injection of the polymer solution (polyacrylamide) WSO-955.

3. A solution of polymer (polyacrylamide) Poly-T-101 of the specified formulation in a volume of 7 m ^{3 is} pumped into the well through a tubing string. The injection is initially carried out with the annular valve open; when the polymer solution reaches the tubing shoe, the valve is closed.

4. Carry out the injection into the reservoir of a polymer solution with water.

5. Clean the well from the remnants of the polymer solution by washing with water.

6. Close the well for technological exposure for the gelation period of 24 hours.

Thus, when injecting into the reservoir, opened by the horizontal well of the Tarasovskoye field under consideration, a polymer solution (Polyacrylamide) Poly-T-101 in a volume of 7 m ³ to isolate water inflow, the waterproofing screen in the water-saturated part of the reservoir will be stable, and in the oil-saturated part unstable, which, along with a decrease in water cut, it will lead to an increase in oil production after repair (14 times compared with the prototype). The injection of the polymer destructor is not required, which reduces the duration of the repair, its cost and increases its manufacturability.

Thus, the variation of the properties of the polymer solution during the computational experiment based on the mathematical model of isolation and limitation of water inflow leads to an increase in the efficiency of isolation and limitation of water inflow into horizontal wells. In addition, a correctly calculated volume of polymer solution allows to reduce repair time and to avoid unjustified consumption of reagents and process fluids.

The proposed method allows to increase the efficiency of isolation and restriction of water inflow into horizontal wells due to the formation of a stable polymer screen in the interval of water inflow and, conversely, unstable - in the productive interval, as a result of selecting a polymer solution with the most suitable properties in this particular case and calculating the volume of the polymer solution.

Claims (2)

1. The method of isolation and restriction of water inflow into horizontal wells, including the injection and delivery of a polymer solution, stopping the well for the period of polymer formation, characterized in that geophysical studies are preliminarily carried out to clarify the interval of water inflow, and computational experiments are carried out based on a mathematical model of the isolation process and restrictions water inflow, evaluating for different viscosity solutions of polymers and volumes of polymer solution the stability of polymer screens in oil and saturated zones of the productive formation at extreme depression and depression during operation, factors of residual resistance of the injected polymer solutions by water and oil, taking into account the type of the productive formation, as well as the water cut of the produced oil and its flow rate after isolation and limitation of water inflows, and the viscosity of polymer solutions is estimated over time at the temperature of the reservoir, then choose a polymer with the necessary viscosity and injection volume, ensuring the stability of the screen from it in a water-saturated zone and not the stability of the screen in the oil-saturated zone of the reservoir, and the selected polymer solution is pumped in the calculated volume. 2. The method according to claim 1, characterized in that before the injection of the polymer solution, a temporarily blocking composition is pumped, which is not filtered into the reservoir.

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