METHOD FOR HYDRAULIC FRACTURING OF A HYDROCARBON FORMATION

Abstract

A fracturing fluid is injected under a high pressure into a well drilled in a formation to create a hydraulic fracture. Then a suspension of the hydraulic fracturing fluid mixed with proppant particles is injected into the well and the created hydraulic fracture, the suspension having a consistency coefficient greater than 0.1 Pa sn at any flow index n and a yield stress higher than 5 Pa. Then, an overflush fluid having a consistency coefficient lower than 0.01 Pa·sn is injected into the well.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to Russian Application No. 2016140355 filed Oct. 13, 2016, which is incorporated herein by reference in its entirety.

BACKGROUND

The disclosure relates to oil and gas industry and can be used to increase the productivity of both newly introduced and operating production and injection wells.

The methods for stimulating oil or gas production by means of hydraulic fracturing of a hydrocarbon formation is widely known. Typically, a fracture is created by injecting a clean hydraulic fracturing fluid under a high pressure through a well into the rock. The open fracture is then filled with a suspension of the fluid mixed with sand (proppant particles), which then keeps the fracture open. Finally, a small amount of a clean fluid is injected into the well to clean the wellbore from solid particles, and a part of this fluid can go into the fracture. This last step is called injection of an overflush fluid.

The practice of injecting an overflush fluid, i.e., displacement of a hydraulic fracturing suspension from a wellbore into the fracture by a low-viscosity fluid, is usually applied at completion of horizontal wells drilled in formations of unconventional gas by a method of multi-stage hydraulic fracturing. It provides purification from solid particles (proppant) for subsequent operations or steps and prevents the flowback of solid particles from the fracture when a well is started. However, the injection of the overflush fluid can negatively affect the overall production of the fractures due to a combination of factors. First, the proppant can be displaced quite far from the well into the fracture, so that the fracture will be unsupported near the well and can close there at any moment of the operation time of the well, when the fluid pressure is not enough to keep the fracture open (from the beginning of the production till the next moment in the process of operating the well). Furthermore, after stopping the injection, the fracture is closed long enough in low permeable reservoirs (the fluid outflow into the rock through the walls of the fracture takes a long time). In the process of closing the fracture, the suspension can swell to the bottom of the fracture by gravity, while the pure fluid rises upward, leaving a significant part of the near-field area without support and blocking the access to the top of the reservoir.

Various methods for improving operation of hydraulic fracturing with injection of an overflush fluid are known from the prior art. Thus, U.S. Pat. No. 7,104,325 proposes sealing a phase injected prior to injection of the overflush fluid by adding a proppant coated with resin.

In U.S. Pat. No. 3,752,233 the addition of hydrazine to a phase of an overflush fluid is provided to restore permeability, wherein the permeability is adversely affected by the high molecular weight of a polymer in a fracturing fluid.

U.S. Pat. No. 2,859,819 discloses a last phase of a pure low-viscosity fluid (overflush fluid) to remove particles from a wellbore into the fracture for cleaning the well.

In all known methods, the risk of closing the fracture remains due to the possibility of creating an unfixed region in the near-field area of the fracture.

SUMMARY

The technical result achieved in implementation of the disclosure includes significant reduction of the risk of fracture closure and loss of hydraulic connection between a well and a fracture due to the reduction of a proppant particle-free unfixed region in a near-field area of the fracture.

In accordance with the proposed method, a fracturing fluid is injected under a high pressure into a well drilled in a formation to create a hydraulic fracture. Then a suspension of the hydraulic fracturing fluid mixed with proppant particles is injected into the well and the created hydraulic fracture, the suspension having a consistency coefficient greater than 0.1 Pa sⁿ at any flow index n and a yield stress higher than 5 Pa. An overflush fluid having a consistency coefficient lower than 0.01 Pa·sⁿ is then injected into the well.

In accordance with an embodiment of the disclosure, the overflush fluid comprises a chemical breaker capable of reacting with the suspension fluid to transform the suspension into a power linear gel without yield stress.

Optimal parameters of the suspension and the overflush fluid are determined using numerical simulation of the overflush fluid injection operation.

In accordance with a further embodiment of the disclosure, a diameter of the proppant particle-free region created by the overflush fluid is adjusted in the near-field area within the fracture by adjusting an injection rate of the overflush fluid. The overflush fluid is injected at a rate higher than a threshold rate u_c at the suspension—overflush fluid interface when a behavior factor of the overflush fluid is greater than that of the fracturing fluid, or at a rate lower than the threshold rate u_c at the suspension—overflush fluid interface when the behavior factor of the overflush fluid is lower than that of the fracturing fluid.

BRIEF DESCRIPTION OF DRAWINGS

The disclosure is illustrated by the drawings, where

FIG. 1 is a schematic layout of a horizontal well intersecting a transverse hydraulic fracture, with an overflush fluid displacing a suspension;

FIG. 2 shows simulation results for displacement of the suspension by the overflush fluid in the right half of the fracture; and

FIG. 3 shows the relationship of effective viscosities of the fluids versus a local linear velocity in the fracture.

DETAILED DESCRIPTION

The disclosure is aimed at optimizing an area of that portion of the fracture that may remain unfixed before significant closure of the fracture occurs when the pressure in the formation decreases. The disclosure provides a reliable limit for the volumes of an overflush fluid. The disclosure is based on mathematical simulation of this process and the parametric study of various strategies for the overflush fluid injection, with attention being paid to displacing a suspension by the overflush fluid, changing volume and injection velocity of the overflush fluid, and the rheological contrast between the suspension and the overflush fluid. The shape of a proppant particle-free region can be regulated by the injection rate of the overflush fluid based on the Seffman-Taylor instability criteria applied to the phase interface between the overflush fluid and the suspension with the proppant particles. It was found that (i) when “fingers” of the overflush fluid are formed at the overflush fluid—suspension interface in the near-field area, large suspension pillars can be maintained that can keep the fracture open; (ii) the swelling of the suspension with the proppant can be reduced by means of rheology with a yield stress for the suspension and/or high viscosity of the base fluid used for preparation of the suspension (viscosity of the base fluid is characterized by the consistency index for the case of power rheology); (iii) for a certain distance from perforations, there is a threshold injection rate (calculated on the basis of the rheological properties of the fluid), which determines the instability of the interface between the overflush fluid and the fracturing fluids.

The hydraulic fracturing job in a sub horizontal well drilled in an unconventional gas or oil bearing formation, has been optimized.

This optimization focuses on a final stage of the hydraulic fracturing job; when after the injection of the fluid suspension with the particles for propping the fractures (proppant), a small amount of clean fluid is introduced to clean the well from the proppant particles and to displace all particles into the fractures (the “injection of an overflush fluid” stage).

The properties of the suspension and the overflush fluid are adjusted so that the proppant-free region in the near-wellbore zone of the fracture is minimized thereby decreasing the risk of closure and loss of the hydraulic connection between the well and the fracture.

More specifically, the suspension injected immediately before the stage of injection of the overflush fluid shall have rheological properties according to the Herschel-Balkley model (shear dilution in combination with the yield stress), and the consistency coefficient shall be greater than 0.1 Paⁿ sⁿ, and the yield stress—greater than 5 Pa.

Within the specified range of properties, the displacement of the suspension by a clean “overflush” fluid causes development of small “fingers” of the overflush fluid penetrating into the suspension (unlike the large “islands” of the clean fluid when the suspension has a lower consistency or yield stress) thereby decreasing an area unsupported by the proppant, and minimizing the risk of fracture closing in the near-wellbore zone (see FIG. 1). FIG. 2 shows simulation results for displacing the suspension by the overflush fluid in the right half of the fracture, where an unfixed cavity in the immediate vicinity of the well is shown on the left side as a semicircle in gray.

The overflush fluid can contain an admixture of chemicals which act as a “breaker” for a crosslinked gel containing particles (suspension). Because of the reaction of this breaker with the suspension, the crosslinks between the polymer molecules in the carrier fluid of the suspension are broken, the yield stress disappears, and the particles move from the suspension to the fingers of the overflush fluid. Therefore, the fingers of the overflush fluid, that initially were not supported, are filled finally with some amount of proppant, and the risk of closing the fracture inside these fingers is reduced. Oxidants, enzymes or acids can be used as diluents.

The exact values of the properties of the suspension and the overflush fluid in the specified range can be determined by numerical simulation of the injection operation of the overflush fluid. Numerical simulation is based on implementation of a mathematical model for multiphase flow in a fracture. The optimal properties can be obtained from the analysis of the unfixed portions calculated during the simulation for different values of the properties of the suspension and the overflush fluid within the specified range.

When the rheology of fracturing fluids and an overflush fluid is a power law fluid, or when the overflush fluid is a Newtonian fluid (for example, water) and the fracturing fluid is a power law fluid, there is a threshold of linear velocity inside the fracture that defines the front instability during the injection of the overflush fluid. Consequently, it is possible to control the shape of the injection region of the overflush fluid within the fracture. In particular, it is possible to initiate the instability and development of viscous fingers at a certain distance from the wellbore, thus providing the following effects: (i) reduction of proppant flow to the well by fully displacing the hydraulic fracturing fluid in a certain (small) region of the hydraulic fracture near perforations; and (ii) initiation of instability at the interface between the overflush fluid and hydraulic fracturing fluid at a certain distance from the perforations to cause the development of proppant columns and to reduce the development of an excessively unfixed (proppant-free) region.

The control of the displacement process and the shape of the region with the overflush fluid within the hydraulic fracture is described by a difference in the effective viscosities of the fluids in the formation, which depend on the local linear velocity inside the fracture. This will be described in more details below.

At the first stage, a hydraulic fracturing fluid is injected under a high pressure into a well drilled in a formation. Linear or crosslinked gels with density of 1000 kg/m³ and viscosity of 0.01 Pa·s for a linear gel or 0.1 Pa·s for a crosslinked gel can be used as the hydraulic fracturing fluid. For example, the use can be made of water-based linear gels and crosslinked gels that are obtained from the linear gels by adding a crosslinker, for example, based on borate. An example of a gel used is an aqueous gel having the following composition: 1 L of water, 20 g of KCl, 4 g of guar, 0.14 g of boric acid and 0.14 g of sodium hydroxide.

At the next stage, the hydraulic fracturing fluid suspension mixed with proppant particles is injected into the well and the created hydraulic fracture, and then—an overflush fluid. Fresh or formation water can be used as the overflush fluid.

Let a first fluid be an overflush fluid determined by a power rheology with a consistency coefficient K₁ and a flow index n₁, and a second fluid be a hydraulic fracturing fluid with a rheology determined by the parameters K₂ and n₂. The effective viscosity of the fluid flowing through hydraulic fracture is defined as follows:

$\begin{array}{cc}{\mu }_{\mathrm{eff}}={K\left(\frac{1+2n}{3n}\right)}^n{\stackrel{.}{\gamma }}^{n-1}& \left(1\right)\end{array}$

This expression is derived from the relationship between the width-averaged velocity inside hydraulic fracture and the pressure gradient in proximity of the thin layer (the “lubrication approximation”) for the 3D Navier-Stokes equations. Here, {dot over (y)}=6u/w is the local (width-average of the fracture) shear velocity, involving the local width-average velocity u and the fracture width w. The parameters K and n are the consistency coefficient and the flow index.

Consider the displacement of the second fluid, which fills the hydraulic fracture, with the first fluid entering the transverse fracture through the perforations. Near the perforations the flow is radial, so the mass conservation equation gives the following expression for the velocity:

$\begin{array}{cc}u\left(r\right)=\frac{u_0r_0}{r}& \left(2\right)\end{array}$

Here, r₀ is a radius of the well, r is a distance between the well axis and the specific location inside the fracture, u₀ is a velocity in perforations (for simplicity, assume that the perforations are distributed evenly along the well casing string).

The instability at the interface between these fluids occurs when the local effective viscosity of the first fluid is less than the local effective viscosity of the second fluid. This condition can be expressed as follows:

$\begin{array}{cc}{K_1\left(\frac{1+2n_1}{3n_1}\right)}^{n_1}{\stackrel{.}{\gamma }}^{n_1-1}<{K_2\left(\frac{1+2n_2}{3n_2}\right)}^{n_2}{\stackrel{.}{\gamma }}^{n_2-1}& \left(3\right)\end{array}$

Inequality (3) gives the following threshold velocity u_c at the interface:

$\begin{array}{cc}{u}_c=\frac{w}{6}{\left(\frac{K_2}{K_1}\right)}^{1/\left(n_1-n_2\right)}{\left(\frac{1+2n_1}{3n_1}\right)}^{-n_1/\left(n_1-n_2\right)}{\left(\frac{1+2n_2}{3n_2}\right)}^{n_2/\left(n_1-n_2\right)}& \left(4\right)\end{array}$

So that if n₁>n₂:μ_eff,1<μ_eff,2⇔u<u_c, and if n₁<n₂:μ_eff,1<μ_eff,2⇔u>u_c.

In particular, if the first fluid is Newtonian (μ_eff,1=K₁=μ, n₁=1), and the second is not Newtonian (power law), then the instability criterion is formulated as follows (0<n₂<1):

$\begin{array}{cc}u<u_c=\frac{w}{6}{\left(\frac{K_2}{\mu }\right)}^{1/\left(1-n_2\right)}{\left(\frac{1+2n_2}{3n_2}\right)}^{n_2/\left(1-n_2\right)}& \left(5\right)\end{array}$

At a constant injection rate, the linear velocity decreases inversely proportional to the distance to the well axis (see equation (2)). Consequently, the equations (5) (and (4) for the case n₁>n₂) and (2) can be combined to calculate the velocity in the perforations u₀, which determines the occurrence of instability at a certain distance to the axis R of the well. Alternatively, if one specifies the outer radius of the proppant particle-free cavity R, one can find the velocity in the perforations u₀ (which is related to the injection rate) necessary to create this cavity. In both cases the following relation is used:

$\begin{array}{cc}{u}_c=\frac{u_0r_0}{R}& \left(6\right)\end{array}$

Below is the relationship between the effective viscosities of the first fluid and the second fluid for different fluids (see Table 1) and the calculated linear velocity thresholds (FIG. 3). Further (for the table and FIG. 3), it should be explained that the crosslinked gel and the linear gel are a suspension with proppant, while water is the overflush fluid.

TABLE 1
Rheological parameters of the fluids considered as an example
	Consistency
	coefficient K	Flow index n
	(Pa · sn)	(dimensionless)
	Water	0.001	1
	Linear gel 1	0.2	0.4
	Linear gel 2	0.1	0.5
	Crosslinked gel	1.8	0.35

Referring to FIG. 3, curve 1 denotes water displacing the linear gel 1; curve 2 is water displacing linear gel 2; curve 3 is a linear gel 1 displacing the crosslinked gel. The rheological parameters of these fluids are given in Table 1. The critical velocity u_c, which determines the beginning of formation of viscous fingers, is determined from μ₁/μ₂=1.

Claims

1. A method for hydraulic fracturing of a hydrocarbon formation, comprising:

injecting under a high pressure a hydraulic fracturing fluid into a well drilled in the formation to create a hydraulic fracture;

injecting a suspension of the hydraulic fracturing fluid mixed with proppant particles into the well and the created hydraulic fracture, the suspension having a consistency coefficient greater than 0.1 Pa·sn at any flow index n and a yield stress higher than 5 Pa; and

injecting an overflush fluid with a consistency coefficient lower than 0.01 Pa·sn into the well.

2. The method of claim 1, wherein the overflush fluid comprises a chemical diluent capable of reacting with the suspension to transform the suspension into a power linear gel without yield stress.

3. The method of claim 1, wherein optimal parameters of the suspension and the overflush fluid are determined based on numerical simulation of the overflush fluid injection operation.

4. The method of claim 1, wherein a diameter of a proppant particles-free region created by the overflush fluid in a near-wellbore area within the fracture is adjusted by adjusting an injection rate of the overflush fluid.

5. The method of claim 4, wherein the injection rate of the overflush fluid is higher than a threshold rate uc at a suspension—overflush fluid interface when a behavior factor of the overflush fluid is greater than that of the hydraulic fracturing fluid, or the injection rate of the overflush fluid is lower than the threshold rate uc at the suspension—overflush fluid interface when the behavior factor of the overflush fluid is lower than that of the hydraulic fracturing fluid.