|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
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.
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 The paper has not been peer reviewed.
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 a 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.
Abstract Channel fracturing combines geomechanical modeling, intermittent proppant pumping and degradable fibers and fluids to attain heterogeneous placement of proppant within a hydraulic fracture. The aim of this well stimulation technique is to promote the formation of stable voids or streaks within the proppant pack which serve as highly conductive channels for transport of oil and gas throughout the hydraulic fracture. More than 10,000 channel fracturing treatments have been performed in over 1,000 wells during the last three years in shale-, carbonate-, and sandstone-rich reservoirs worldwide. The collective dataset on job execution and well performance shows the following trends: (a) low occurrence of near wellbore screen-outs (>99.9% of all treatments achieving 100% proppant placement); (b) reduction in the amount of proppant required to complete treatments (in average, 43% less proppant than conventional techniques aiming at placing a homogeneous proppant pack as implemented in offset wells); (c) average initial and long-term well productivity and flowing pressures consistently meeting or exceeding those of wells completed with conventional fracturing techniques. This paper summarizes findings from a comprehensive technical study focused on ascertaining the enabling mechanisms for these trends. Results from laboratory experiments (large-scale slot flow, conductivity, proppant settling), yard tests (well site delivery characteristics, proppant slug integrity), and well performance evaluations (surface treatment data, well production data and reservoir simulations supported by history matching) are analyzed collectively to reach the following assessments: (a) heterogeneous proppant placement is achieved; (b) the low incidence of screen-outs is the result of the combination of reduced usage of proppant and intermittent pumping of proppant-free, fiber-laden slugs ("sweeps") which mitigate accumulation of proppant in the near-wellbore area; (c) well productivity trends are driven by the concomitant occurrence of enhanced fracture conductivity - enabled by the presence of heterogeneities within the proppant pack- and the development of larger fractured area within the reservoir effectively contributing to production. The development of larger effective contact area is enabled by the use of fibers, which enhance proppant transport within the fracture and mitigate proppant settling.
Doctor, Sergey A. (Gazpromneft-Khantos) | Tolmachev, Alexey (Gazpromneft-Khantos) | Chebykin, Nikolay (Gazpromneft-Khantos) | Yudin, Alexey (Schlumberger) | Roukhlov, Valery (Schlumberger) | Gromovenko, Alexander (Schlumberger) | Mathur, Anil (Schlumberger)
Abstract South-Priobskoe field is in process of active development for over 10 years at the moment. Main producing horizons are low-permeable sandstone formations AS10-AS12 of Neocomian age. Hydraulic fracturing in the vertical wells proved to be effective way to increase oil production and provided profitable development of the oil field for several years period. Many wells had commingled production from 2 or 3 layers; each of the layers was stimulated separately. However, recent shift of drilling and development activity towards edge areas of the field led to reduction in formation quality and seldom well intersects more than one productive interval nowadays. Most effective way for such geological conditions is combination of horizontal well drilling development and multi-stage fracturing. This concept was successful applied worldwide for number of years and recently fulfill expectation at South Priobskoe field in Russia as well. Enhancement of oil production jointly with drainage scheme optimization allowed to decrease amount of wells and associated costs for infrastructure and well completion. Main weaknesses of this approach are increased screenout risks during fracturing operation and additional costs for horizontal wellbore cleanout in such a case. Implementation of channel fracturing technology became the next step of production optimization and well completion cost reduction. New method allows increasing reliability of proppant placement while improving fracture conductivity. These results are obtained by pulsing proppant on surface in conjunction with specialized equipment and fibers. New technology was implemented in 110 vertical wells over Russia including positive experience of channel fracturing campaign in 3 wells in South-Priobskoe field. This article describes Russia's first project of multistage stimulation (MSS) combined with channel fracturing technique applied in horizontal well. New approach allowed minimizing screenout risk, reducing completions costs and at the same time improving conductivity of hydraulic fractures. First production results showed increase in well productivity of over 15% compared to the neighboring horizontal wells stimulated by conventional MSS technique.
Sadykov, A.. (Schlumberger) | Yudin, A.. (Schlumberger) | Oparin, M.. (Schlumberger) | Efremov, A.. (Schlumberger) | Doctor, S. A. (JSC "Slavneft-Megionneftegaz") | Vinohodov, M. A. (JSC "Slavneft-Megionneftegaz") | Chebykin, N. V. (JSC "Slavneft-Megionneftegaz") | Garus, I. V. (JSC "Slavneft-Megionneftegaz") | Katrich, N. M. (JSC "Slavneft-Megionneftegaz") | Rudnitsky, A. A. (JSC Slavneft)
Abstract The channel fracturing technique changes the concept of proppant fracture conductivity generation by enabling hydrocarbons to flow through open channels instead of through the proppant pack. The new technique is based on four main components: proppant pulsing at surface with fracturing equipment and software, a customized perforation strategy, a fibrous material to deliver stable channels, and a set of models to optimize channel geometry. The Taylakovskoe oil field is located in western Siberia—430 km away from the nearest settlements. The Jurassic reservoir in Taylakovskoe field is a sandstone formation with significant net pay (average 25 m) and middle-range permeability (3 to 20 mD). Bottomhole temperatures range between 85°C and 90°C. Fracturing gradient is typically 14 kPa/m. The majority of the wells are stimulated immediately after drilling. Sufficient fracture conductivity and effective fracture length are essential for adequate well performance. The optimization of hydraulic fracturing treatments conducted in recent years was based on improved fluid chemistry and pumping "aggressive" fracture designs; this yielded high-quality results. The new channel fracturing stimulation technique, which allows significant increases in fracture conductivity, became the next technological progression. With channels inside the fracture, fluid and polymer residue flow back faster than with a conventional proppant pack, improving cleanup and increasing effective fracture half-length. One of the most important advantages of the new technology is a very low risk of screenout events. The fibers make fluid more stable, while the presence of clean pulses around proppant structures promotes bridging-free flow. Reduced risk of premature treatment termination is even more important in remote operations such as in the Taylakovskoe field because of the higher costs of nonproductive time and deferred oil production. Candidate selection criteria were developed specifically for local conditions. Ten channel fracturing treatments performed in Taylakovskoe wells have already showed significant increases in incremental oil production—average 44% beyond expected production as shown by well performance analyses. We describe the performance evaluation of wells completed with this technology and future plans for applying channel fracturing methods in the Taylakovskoe field.