Method of Hydraulic Fracturing of Horizontal Wells, Resulting in

Increased Production

Introduction

This invention relates hydraulic fracturing in subterranean formations and, more particularly, to methods for optimizing fracture conductivity. Hydraulic fracturing is a primary tool for enhancing well productivity by placing or extending highly conductive fractures from the wellbore into the reservoir. Conventional hydraulic fracturing treatment is generally considered to have several distinct stages.

During the first stage, hydraulic fracturing fluid is injected through wellbore into a subterranean formation at high rates and pressures. The fracturing fluid injection rate exceeds the filtration rate into the formation producing increasing hydraulic pressure at the sandface. When the fluid pressure exceeds a threshold value, the formation strata or rock cracks and fractures. Hydraulic fracture initiates and starts to propagate into the formation as injection of fracturing fluid continues.

During the next stage, proppant is admixed to fracturing fluid and transported throughout hydraulic fracture. Proppant deposited in created fracture over the designed length mechanically prevents fracture from closure after injection stops. The oil/gas inflows to the fracture and flows through the proppant pack down to the wellbore once the fracturing treatment is over and the well is shifted to the production mode. The production rate of oil/gas essentially depends upon the number of the parameters, including formation permeability, hydraulic pressure in the formation, properties of the production fluid, shape of the fracture, etc. The most essential parameter and the one, which can be controlled and tweaked

in hydraulic fracturing is the proppant pack permeability. There are numerous cases when an increase of hydraulic conductivity of proppant pack above the limits of conventional technology may result in significant improvement of stimulation economics.

Prior Art

A lot of inventions, disclosed to date, aim in increasing hydraulic conductivity of the fracture created in hydrocarbon bearing zone.

Other inventions proposed creating highly conductive channels in a proppant pack. These channels are assumed to be free of proppant and provide conductive pathway to reservoir fluids.

In the patents (US3850247A1, US3592266, US5411091A1, US20050274523A1, US6776235) high conductivity channels are created by pumping alternating intervals of fracturing slurries which are different in at least one of their parameters. For example, in the US3592266 it is proposed to create heterogeneity in a proppant pack by pumping alternating volumes of fluids which are significantly different in their viscosity. In the US6776235 fluids differ by their proppant carrying capacity and/or concentration of proppant. All patents assume that heterogeneity introduced at the early stage of hydraulic fracturing treatment that is at the time when fluids are mixed and pumped into the wellbore, will preserve throughout complete hydraulic fracturing treatment. Heterogeneity in fracturing slurry is believed to result in heterogeneity of created proppant pack.

Summary of the Invention

The new technique of production stimulation for horizontal wells is proposed. The technique is based on slugging approach, combined with

special perforation strategy. The invention is focused on a substantial increase in the fracture conductivity achieved by loading a heterogeneous proppant pack into the fracture.

Detailed Description of the Invention Including Examples and Drawings

The current invention proposes a method of creation of a heterogeneous proppant packs in hydraulic fractures in horizontal well applications and therefore a creation of a network of a conductive open available for flow.

Hydraulic fractures covered by such a heterogeneous proppant pack will have an essentially higher conductivity than conventional (uniformly propped) fractures and therefore will increase the oil and gas production rate.

The method for forming of a heterogeneous proppant packs in the fracture is based on the alternate injection of a fracturing fluid and fracturing fluid loaded with proppant into a fracture, coupled with a special perforation scheme.

The present invention does not cover the alternate injection of fracturing fluid and fracturing fluid with proppant, but rather it is focused on new perforation schemes.

The alternate injection of fracturing fluid and fracturing fluid with proppant contains a number of stages, described in details below.

The first stage is injection of a fracturing fluid and formation/propagation of the fracture.

The second stage is addition of the given volume of the proppant to the fracturing fluid with the help of the special equipment (which is not a subject of the given patent). The given volume of the proppant, mixed with

the fracturing fluid (at given proppant concentration) is called a proppant slug. It is being transported down the wellbore to the perforation zone. The volume of the proppant inside one proppant slug is an important parameter and has an essential influence upon the desired properties of the final fracture. To calculate that volume, one should know formation parameters as the Young modulus of the rock and the crack closure pressure. Depending on those parameters of the oil/gas containing rock, the sizes of the proppant slugs are calculated such that the injected proppant portions are capable of preventing the crack from closure. It was found that, in order to achieve an essential conductivity increase, it is required that the time of single slug pumping (on surface) should be less than 30-40 sec at the usual present pumping rate.

The third stage is injection of a given volume of a fracturing fluid without proppant. The volume injected during the third stage is a key parameter for creation of a highly permeable heterogeneous proppant structures. The volume of a fracturing fluid without proppant is determined from the parameters as the Young modulus of the rock, the crack closure pressure and the size of the proppant slug. It was found that the time of third stage pumping is below 30-40 sec at the present pumping rates to prevent the crack from closure.

The proppant slug generated during second stage is transported down the wellbore to a perforation zone. The proppant slug, which has arrived to the perforation zone, is divided onto a number of smaller parts, so-called proppant pillars. Amount and size of perforation clusters and the slug volume determine the number of pillars formed from one slug. The pillars are transported down to the fracture by a fracturing fluid. The stages two and three are repeated a required number of times. Duration of each stage and proppant concentration in a fluid can vary.

As a result the heterogeneous proppant structures (slugs) are formed in the fracture. After the fracture closure the stable proppant formations hold the fracture walls and preventing from complete closure. The special perforation strategy is a key part of the current invention. The perforation strategy will vary for different types of fractures in horizontal wells. The state of art knows two types of the hydraulic fractures in horizontal well applications. They differ by direction of fracturing; this produce longitudinal or lateral fractures.

The current invention also uses some descriptions of perforation techniques. While the perforation techniques by themselves are not a part of the current invention, one may find the good description of techniques in Oilfield Review, Autumn 2006, p. 18-35 "New Practices to Enhance Perforation Results". In the description below one may see usage of both oriented and non-oriented perforation techniques.

The proposed perforation strategy is the following:

1. For longitudinal fractures the heterogeneous placement is achieved by creation of sets of perforation clusters, coupled with special pumping schedule when proppant is pumped in form of slugs (Figure 2). By perforation clusters we mean the perforation interval with high perforation density. The clusters are divided by a non- perforated interval.

2. For transverse fractures the heterogeneous proppant placement is achieved by creating several perforation holes, located at the same plane, but with different phasing (Figure 4). The separation of the proppant slug will occur at differently oriented perforations. The proppant should be pumped in slugs of a very small volume to prevent adjacent proppant slugs from coalescing during transportation.

3. For transverse fractures the heterogeneous proppant placement is achieved by creating several perforation holes, located at the same plane, but with different phasing (Figure 5). The proppant should be pumped in slugs of a very small volume followed by no-proppant stage of lower viscosity. Low viscosity stage without proppant splits the slug because of fingering effect. (Homsy G. Viscous fingering in porous media. // Annual Rev. of Fluid Mech., 1987. - V.19. - P.271 - 314).

4. For longitudinal fractures an orientation of perforation channels (phasing of perforation places) relative to Preferred Fracture Plane (PFP) may vary for neighboring channels of perforations within one cluster, or may vary between two neighboring clusters (while within one cluster the orientation of all perforation channels is the same). Thus, in other words, in the case of non-oriented perforations, one channel may have 120deg phasing, and the other may have 60deg phasing. Or, in the case of oriented perforations - one tunnel may be oriented with 30deg to PFP, while the neighboring one can be oriented with IOdeg to PFP. Such a variation in perforation tunnels orientation will result in different pressure drops between the wellbore and the pressure inside the fracture, which will result in different velocities of the proppant slugs penetration, coming through neighboring perforation holes. In this manner, one may achieve the effect when neighboring pillars are separated from each other.

This technique is illustrated in the Figure 6. By changing an angle of orientation of a perforation tunnels relative to the Main PFP between different clusters, one would introduce a difference between hydraulic impedances of two neighboring perforation clusters and this would promote distinct separation of two adjacent proppant

pillars. Figure 5 depicts a case of 180 deg phase perforations but obviously the use of this angle modulation technique is not limited to the case of 180 deg oriented perforations. Variation of near-wellbore hydraulic impedance by angle modulation can be used with other perforation phasing including 60 deg phasing.

Summarizing, the offered new method of hydraulic fracturing comprises the following key concepts:

1. Fracturing horizontal wells by alternate pumping of a fracturing fluid and fluid containing proppant;

2. Creation of special perforation strategy, forming clusters of perforation shots with high shot density. As an extreme case, the perforation slots may be created. The type of perforation strategy depends on the type of the fracture initiation.

3. For longitudinal fractures the injection times for slug (stage two) and clear fracturing fluid (stage three) should be small. According to our calculations the significant hydraulic conductivity increase may be achieved only if the injection time for stages two and three is less than 30-40 seconds.

4. For transverse fractures the volume of the proppant slurry and clear fracturing fluid going through the perforation to same fracture should be very small for a significant growth in conductivity. One may achieve the desired effect by using limited entry technique and fracturing several transverse fractures simultaneously. The injection times for stages two and three in this case still should be less than 30-40 seconds. This will result in the fact that during stage two and stage three of pumping, the amount of fluid and proppant slurry

going to one transverse fracture is be small and this provides enhanced conductivity.

Description of Figures

Figure 1 describes the process of conventional homogeneous placement of proppant for making a longitudinal fracture in horizontal well (initiation stage).

Notations: 1 - wellbore, 2 - proppant, 3 - arrangement of perforation holes on the casing.

Figure 2 describes the process of heterogeneous placement of proppant for making a longitudinal fracture in horizontal well (initiation stage). Notations: 1 — wellbore, 2 - proppant, 3 - arrangement of perforation holes on the casing.

Figure 3 shows heterogeneous proppant placement fro making a transverse fracture in horizontal well (initiation stage).

Notations: 1 — wellbore, 3 — arrangement of perforation holes on the casing, 4 — transverse fracture

Figure 4 shows the schematics of heterogeneous placement in transverse fracture. The slug of proppant arrived to the perforation zone is divided in the perforations into a number of pillars, which are traveling from the wellbore in a radial direction.

Notations: 1 — wellbore, 2 - proppant, 3 - arrangement of perforation holes on the casing, 4 - transverse fractures

Figure 5 shows the schematics of heterogeneous placement in transverse fracture. The slug of proppant followed by low viscosity base fluid injection is shown.

Notations: 1 - wellbore, 2 - proppant, 3 - arrangement of perforation holes on the casing, 4 - transverse fracture, 5 - low viscosity fluid injected, fingering through the proppant pillars

Figure 6 shows the variation in perforation orientation between neighboring clusters. Such a variation results in a pressure drops across the perforations which will be different for neighboring clusters. Difference in pressure drops will result in a different velocity of pre-pillars, coming through neighboring clusters, preventing them from lumping together and providing heterogeneous proppant placement.

Notations: 1 - wellbore, 3 - arrangement of perforation holes on the casing, 6 - direction of the fracture growth, so called Preferred Fracture Plane (PFP).

The technical solution disclosed herein will be further exemplified as follows.

A transparent cell simulating the walls of a fracture was provided having the sizes of 1 m x 40 cm x 1 cm. Hydrofracturing fluid was pumped through said cell. The fluid was pumped into the cell through a 1 cm hole acting as a perforation. The fluid pumped through said cell was cross- linked gel containing 2.4 g/1 polysaccharide. The proppant slag was cross- linked gel containing 2.4 g/1 polysaccharide with AcFrac CR 20/40 proppant addition. The proppant content was 960 g per 1 1 of cross-linked gel. When the slugs of clean gel and proppant containing gel was alternated, heterogeneous proppant slugs formed in the cell. The pumping rate was varied from 1 to 20 1/min. Simulation of heterogeneous proppant slugs in a hydraulic permeability measuring instrument showed a

significant increase in the hydraulic permeability of the cell. Standard proppant pack provided a hydraulic permeability of 150 Darcy at a 6.9 MPa load, whereas the cell containing heterogeneous proppant slugs provided a hydraulic permeability of 3000 Darcy at a 6.9 MPa load.