Mature fields

Channel Fracturing Applied in Mature Wells in Western Siberia

The new channel-fracturing technique is capable of increasing fracture conductivity by up to two orders of magnitude.


The new channel-fracturing technique is capable of increasing fracture conductivity by up to two orders of magnitude. The channel-fracturing technique allows development of an open network of flow channels within the proppant pack, enabling fracture conductivity by such channels rather than by flow through the pores between proppant grains in the proppant pack. The successful implementation of the channel-fracturing technique in brownfield development is described in detail with the case study of the Talinskoe field in Russia.


The Talinskoe section (for simplicity, referred to herein as the Talinskoe field) is part of the medium-sized, mature Krasnoleninskoe field, located near Nyagan, Russia. Exploration of this section began in 1982. It has more than 5,000 wells completed either in the Middle Jurassic Tyumenskaya suite (Formations JK2 through JK9) or the Early Jurassic Sherkalinskaya suite (Formations JK10 through JK11). More than 1,500 wells have been fractured hydraulically. Approximately 60% of all wells are idle, mainly because of water breakthrough (the average water cut throughout the field is 90%). Most hydrocarbons are found in the Sherkalinskaya suite, but, currently, water cut in many wells producing from the JK10 and JK11 formations already exceeds the economic limit. These wells are recompleted to produce from shallower formations in the Tyumenskaya suite.

The Tyumenskaya suite is characterized by a complex geology. It is an argillaceous facies with sandstone sublayers and lenses. Because of low permeabilities in the Tyumenskaya suite, most of the wells cannot be produced commercially without stimulation. To enhance well productivity in such conditions, the greatest possible fracture length is required, but it is not always possible to achieve targeted half-length because of geological limitations and formation mechanical properties. While designing for the greatest length possible, the engineer is frequently limited by low-to-moderate stress contrast between the target formation and the barrier separating the target interval from the possibly watered-out formation.

It is usually not a problem in low-permeability reservoirs to achieve target dimensionless fracture conductivity (DFC) greater than 2. But this does not always provide the best productivity results. Thorough analysis of the 3-year fracturing campaign in Nyagan showed that an DFC greater than 15–20 should be targeted for this region. Lower DFC values result in lower productivity. Lack of control over fracture-height growth (with the subsequent reduction in fracture width) is a possible reason for production underachievement.

Current fracturing practices in the Talinskoe field aim for height-growth control, longer effective fracture half-lengths, and enhanced fracture conductivity. For these purposes, several different fracturing technologies and pumping techniques were implemented. All of these technologies have demonstrated different levels of productivity increase. But all of them have a significant drawback: The screenout ratio increases with a decrease in fluid viscosity and an increase in operational complexity. In the period between 2007 and 2009, when these technologies were implemented, the average screenout ratio for Talinskoe field was 12%. Screen-out affects production in several ways. When all the designed proppant is not placed in the formation, then the fracture geometry is compromised, possibly by a lower DFC, incomplete zonal coverage (the entire net pay is not covered), or smaller skin improvement (shorter fracture length). In addition, fluid and gel recovery might suffer from lengthy workover operations, which may reduce the retained fracture conductivity.

A trial campaign for channel-fracturing technology was conducted on the Tyumenskaya suite. The campaign was aimed at increasing fracture conductivity and effective fracture half-length without an additional risk of premature screenout.

Channel Fracturing

The concept behind the new fracturing technique may be described in one word: channels. The homogeneous proppant pack is replaced by a network of flow channels (Fig. 1); now, the fracture conductivity is created not by proppant, but rather by channels. Proppant is now grouped into clusters, supporting fracture walls from closure around the channels.

Fig. 1—A conventional propped fracture (left) with respect to channel-fracturing technology (right).


Channels are created by a special pulsing pump schedule and a clustered perforation scheme. In contrast to the conventional pumping schedule, in which proppant is added homogeneously with incremental increases in proppant concentration, the new technique adds the proppant in short pulses. The proppant pulses will create the proppant clusters. The clean pulses (pulses without proppant) will promote the formation of channels. The last step of a treatment requires continuous addition of proppant, as in a conventional treatment. The goal of this step, referred to as the tail-in step, is to ensure a stable, uniform, and reliable connection between the channeled fracture and the wellbore. It is important to design the tail-in step so that it is short enough to prevent it from having a significant negative impact on the overall fracture conductivity. As for the perforation scheme, it is necessary to create clusters of perforation shots separated by nonperforated intervals. These clusters will separate proppant pulses into smaller slugs and will promote uniform distribution of proppant slugs across the fracture.

The special modeling workflow comprises proppant-transport models to calculate the placement of proppant slugs. After the proppant slugs (conglomerates) are placed, the fracture walls will bend around the slugs (Fig. 2), which will reduce the effective volume of the channels. To model this phenomenon, a special fit-for-purpose mechanical model was developed and integrated into a commercial fracturing simulator. If the width profile of the channels is known, fracture conductivity can be calculated. The developed engineering workflow thus allows us to relate what is performed at surface to what is obtained in the fracture. Furthermore, it allows optimization of the fracture design to ensure that channels will stay open.

Fig. 2—Channels narrowing around proppant slugs.


Many successful case studies of channel-fracturing implementation already have been published; some of them are based on hydraulic fracturing in ultralow-permeability reservoirs, and others concern low- and medium-permeability reservoirs. Regardless, all authors show significant productivity increases in the wells with channel fracturing compared with offset, conventionally stimulated wells. These studies proved the benefits of this technology; how-ever, all of them are related to gas and gas/condensate reservoirs.

Before initiating the pilot channel-fracturing campaign, a similar experience was reviewed carefully. A previously presented case study with the channel-fracturing technique implemented for medium-permeability oil formations in western Siberia in newly drilled wells of the Priobskoe field yielded two important conclusions:

  1. The performance of the wells treated with the new technique was 10 to 15% higher than that of wells receiving conventional treatments.
  2. The productivity index of the wells treated with the new technique was stable for 2 years, confirming the existence and reliability of the channel structures.

In addition to extraordinary fracture conductivity, improved fracture cleanup, and increased effective fracture half-length, there is another valuable benefit from the implementation of channel fracturing in Talinskoe field: a minimized risk of screenout. Currently, more than 6,500 stimulation treatments with channel-fracturing technology have been performed worldwide, and only three screenouts have occurred, which yields a success rate greater than 99.95%.

Candidate Selection and Design Considerations

Several criteria and considerations were applied in the candidate-selection process. One of the main objectives, besides those that relate to the technology itself, was to find candidates with several representative offset wells that were hydraulically fractured by use of conventional technologies and had enough production data to make correct comparison analysis. In addition, wells were screened on the basis of the following requirements:

  • Cased-hole wells with no perforation in the target interval to allow cluster perforation
  • Well deviation of less than 15° in the target interval to minimize risk of misalignment of fracture plane with the wellbore
  • A certain degree of rock stiffness: ratio of Young’s modulus to closure stress at greater than 275
  • Net height greater than 6 m
  • Lowest possible lamination of the pay interval with a minimum number of separating shale or argillite streaks
  • No additional risks of breaking into water-bearing formations in case of fracture-height growth

Channel fracturing is beneficial in two ways. First, the presence of clean pulses around proppant structures and fibers inside slurry provide bridging-free flow, which leads to increased proppant penetration inside the formation. Second, enhanced fracture permeability enables faster and more-complete recovery of the fracturing fluid during well-cleanup procedures through channels, which results in increased effective half-length and unhindered hydrocarbon flow during production. A specially developed module in the commercial simulator was used for the designing and optimizing of channel formation. The effort was made to design treatments that ensure fully opened channels through the entire length of created fractures with maximum possible conductivity.
After thorough candidate screening, with several stimulation and production specialists involved from both the operator and the service company, five wells showed the best possible compliance with the screening criteria described and were chosen to be stimulated with channel-fracturing treatment (Wells X268, X118, X473, X430, and X373). Chosen wells were distributed across the field. All were treated with water-based fracturing fluid with 3-kg/m3 (25-lbm/1,000-gal) guar-polymer loading and borate-type crosslinker. A 16/20-mesh intermediate-strength proppant was used as the main treatment, and 3 tons per job of 12/18-mesh resin-coated proppant was used as tail-in material to ensure maximum conductivity in the near-wellbore region and control over proppant flowback at the same time. All treatments were pumped as per design without screen-outs, despite a very aggressive schedule, proving the reliability of proppant placement in pulsating mode.

Production Analysis

Analysis of production is based on the productivity-index value normalized on the net-pay thickness. For each well, the productivity index was recalculated from daily-liquid-production data, with applied Vogel’s correction for production below bubblepoint pressure. Net-pay thickness was derived from log data. A robust permeability value was not known for most of the wells, so it was not used for further data normalization. The productivity index at or above bubblepoint can be simply calculated as a ratio of liquid production to applied drawdown. Wells in the Talinskoe field produce with electrical submersible pumps. It is a common practice to keep bottomhole pressure below the bubblepoint pressure. (For a detailed discussion of the -production-analysis process, please see the complete paper.)

Normalized productivity-index values for the five wells treated with the channel-fracturing technique were averaged into a single curve and compared with the averaged normalized productivity-index curve from eight offset wells after stimulation with conventional fracturing treatments. The productivity of wells treated with channel fracturing was significantly higher than that of wells stimulated with conventional fracturing. Note that because of the low number of treated wells, normalized productivity curves suffer from “noise” induced by imperfections of daily production-measurement data from each well. But the general trend is obvious: Wells treated with the channel-fracturing technique display significantly higher productivity-index values during the entire production period currently available.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 159347, “First Channel Fracturing Applied in Mature Wells Increases Production From Talinskoe Oil Field in Western Siberia,” by Rifat Kayumov, SPE, Artem Klyubin, SPE, Alexey Yudin, SPE, and Philippe Enkababian, SPE, Schlumberger, and Fedor Leskin, SPE, Igor Davidenko, SPE, and Zdenko Kaluder, SPE, TNK-BP, prepared for the 2012 SPE Russian Oil and Gas Exploration and Production Technical Conference and Exhibition, Moscow, 16–18 October. The paper has not been peer reviewed.