No abstract

The use of oil-based fluids in the western Siberian oil industry for hydraulic proppant-fracturing treatments in water-sensitive formations to prevent clay swelling was widespread. The added advantage of using oil-based fluids for cold weather conditions is obvious. However, with the growing number of treatments and increasing treatment sizes, the use of oil or diesel, from an economical point of view, becomes less attractive. In addition, there is a growing environmental concern with respect to using oil for mixing and pumping fracturing fluids. The use of gelled water is cheaper, and from an environmental perspective, more attractive. The addition of 2% KCl to water-based fracturing fluid for temporarily controlling clay swelling is widely accepted as a standard practice. In situations where water-sensitive sandstone formations have been treated and longer protection has been required, very often additional clay stabilizing agents are added to the water-based fracturing fluids. Research on the technology of matrix acidizing treatments has revealed that the use of 2% KCl transforms into 1.5% saltwater as a result of ion exchange. The 1.5% saltwater solution is too weak to prevent clay swelling. Clay swelling can be prevented using a 1 molar (7%) KCl salt solution. Based on acidizing treatment research, it was decided to use 7% KCl as a temporary clay control additive in water-based fracturing fluids for treatments in western Siberia. One-molar salt solutions have been used for all the treatments performed during the last four years. Model 50 viscometer measurements were made to identify the influence of increasing KCl concentration from 2% to 7% on the viscosity development of borate crosslinked fluid. Water retention problems have not been reported since 7% KCl has been used. From a study of the pre- and post-fracturing production data, it was apparent that in general the percentage of water produced with the oil did not reduce. It is postulated that this is an indication of good temporary clay control. This study excluded treatments that clearly contacted a water-bearing zone. Introduction In 1997, it was estimated1that more than 90% of fracturing fluids used during the 1990s were crosslinked water-based fracturing fluids. The assumption is that this percentage has only increased in recent years. Oil-based fracturing fluids are still in use, mostly in water-sensitive, depleted, and undersaturated2 tight sandstones from which water-based fluids are difficult to recover. Factors to take into account when selecting a frac fluid include availability, safety, environmental impact, economics, viscosity, formation compatibility, load recovery, and surface treatment parameters, to name a few. All these factors are discussed in detail in this paper for the two base fluid options, with emphasis on some specific conditions encountered in various oilfields in western Siberia. Availability Water and oil or diesel are considered to be readily available for use as base fluids for fracturing treatments in western Siberia. This is also true in wintertime conditions. Heated water (30° to 40°C) is used during all operations in the area because steam heating equipment is readily available for heating fluids. Water-based fracturing fluids can be used in temperatures as low as -32°C. This is the lowest temperature limit for all operations, including oil-based treatments, because steel becomes brittle at lower temperatures and can result in high-pressure equipment failure. Safety Pumping oil-based fracturing fluids is known to be dangerous. Consequently, pumping hydrocarbon-based treatments in darkness is not permitted. Water-based fluids may be pumped during the nighttime on the condition that adequate and sufficient lighting is provided on location. Environmental Impact Any land spill of fluids in excess of approximately 100 liters (or close to 25 US gallons) is considered a recordable environmental incident. The strategy with respect to environmental issues is to reduce incidents to avoid remediation costs. The risk of spilling for both water- and oil-based fluids is equal; however, from a remediation standpoint, the environmental impact of an oil-based fracturing fluid spill is considered far more costly.

Major oil producers in western Siberia widely use hydraulic fracturing to increase recovery from maturing reservoirs. Minimizing the quantity of produced water that typically accompanies increased hydrocarbon production is considered to be of the utmost importance. The traditional approach has been to limit well selection for fracturing treatments to candidates where stimulation can be efficiently performed without a subsequent increase of post-frac water cut. This significantly reduces the desired development of targeted fields.In general, there are two main reasons for water production increase: (1) fracture propagation to water-saturated formations caused by the absence of reliable barriers and (2) phenomenon of water coning caused by pressure drawdown through a highly conductive fracture channel during the exploitation period. To mitigate the problem of post-stimulation water production increase, a relative permeability modifier (RPM) can be applied. The RPM itself is a polymer that can be pumped as a preflush to fracturing treatments or throughout the whole job. Under formation conditions, RPMs decrease the relative permeability of rock (reservoir) to water with almost no effect on the permeability of hydrocarbons. This is crucial to increase the oil-mobility ratio because it allows production of higher oil volumes without unacceptable quantities of associated water production.Several fracturing job RPM treatments have been performed on different oilfields in western Siberia, and not all of them can be considered successful. Both satisfactory and unsatisfactory results were analyzed to classify the major groups of parameters that had the most impact on the final well performance. Based on this data, the candidate selection process for fracturing combined with RPM treatments for western Siberia oilfields should be improved to achieve more desirable treatment results. This paper contains guidelines to select the proper well for this type of treatment and, based on the case study, brings attention to different groups of parameters, related not only to formation properties but also to well preparation process and design criteria, that can significantly affect the final result.

Особенности применения одномолярных солевых растворов при стабилизации глины в жидкостях на водной основе для гидроразрыва пласта в условиях Западной Сибири Авторы статьи: Klaas van Gijtenbeek, SPE, Алла Нейфельд, Антонина Прудникова, Halliburton, Russia Copyright 2006, Общество инженеров-нефтяников Настоящий документ подготовлен для выступления в ходе нефтегазовой технической конференции и выставке, проводимой с 3 по 6 октября 2006 года в Москве под эгидой SPE.Настоящий документ выбран для доклада Комитетом SPE по выработке программы после анализа информации, содержащейся в аннотации, представленной автором (авторами). Содержание доклада, в том виде, в котором с ним предполагается выступить, не было проанализировано Обществом инженеров-нефтяников и поэтому подлежит корректировке со стороны автора (авторов). Представляемый материал может не отражать позицию Общества инженеров-нефтяников, его сотрудников или членов. Доклады, представляемые на заседаниях SPE, перед публикацией подвергаются анализу со стороны Редакционного комитета Общества. Воспроизведение в электронном виде, распространение или хранение любой части данного доклада в коммерческих целях без письменного согласия со стороны Общества инженеров-нефтяников запрещены. Разрешение на воспроизведение в печатном виде ограничивается лишь аннотацией в объеме не более 300 слов, а копирование иллюстраций не допускается. На видном месте в аннотации должна быть помещена информация о том, где и кем данный доклад был сделан. Писать: Библиотекарю,, SPE, P.O. Box 833836, Richardson, TX 75083-3836 U.S.A., fax 01-972-952-9435.

Moho Nord deep offshore field is located 80 kilometers offshore Pointe-Noire in the Republic of the Congo. The wells produce crude from the Albian age reservoir and lithology consists of alternating sequences of carbonates and sandstone layers with high heterogeneity and permeability contrast, including the presence vacuolar layers called "hyperdrains". This paper describes the application of a novel acid system and the methodology successfully applied to effectively acid stimulate the Albian drain. The combination of long perforation intervals with lithology and permeability contrasts, natural fractures, and the potential for asphaltene deposition resulted in adoption of a Modified Carbonate Emulsion Acid (MCEA) fluid system containing a solvent to provide asphaltene deposition prevention. The MCEA stimulation treatments were bullheaded from a stimulation vessel and an engineered diversion process was implemented for effective acid diversion using a combination of mechanical ball sealers and a degradable particle system (DPS). The selection of number of ball sealers and the DPS diverter design depended upon the interpretation of zone permeability profile from the logs, and the final distribution of perforations selected along the drain. A fluid placement simulator indicated low sealing efficiency of the ball sealers would lead to an overstimulation of the highest permeability areas. Subsequent simulations indicated that the DPS would provide better acid coverage with lower skin (S). Results and observations presented indicate that the decision to improve the acid diversion design and combine ball sealers with a DPS diversion technique to improve zonal coverage was validated. During the stimulation treatment execution, the high stimulation treatment efficiency was clearly apparent from the pressure responses to the acid and the diverter system which sealed off perforations and diverted the treatment to other layers with lower permeability. The MCEA also has proven to have self-diverting properties due to its high viscosity and low reaction rate which creates a better coverage of the drain, even with limited pumping rate, allowing live acid penetrating deeper into the formation. The production results reported from the 15 wells stimulation campaign (10 producers, 5 injectors) indicated that the productivity indexes (PI) exceeded expectations and resultant post-stimulation skin values ranged from −2.5 to −4.1. The Moho Nord deep offshore stimulation campaign yielded outstanding production results and showed significant validation for use of the MCEA system and the diversion methodology applied. On the producer wells the use of both chemical and mechanical diversion was valuable, as the DPS proved to complement the Ball Sealers for layers with lower injectivity and also at the high injection rates. High injectivity gain coupled with effective diversion was crucial for enhanced wormholing and good drain coverage.