One of the strategic targets in Yamal autonomous district, the Turonian siltstone formation, lies above the Cenomanian formation and is separated by a massive argillite barrier. Successful stimulation experience in vertical wells in the North-Kharampurskoe field during 2008 to 2010 encouraged the operator planning the next step of field exploration to consider horizontal well completions using multistage stimulation. The paper will describe pilot campaign in details. The Yamal Turonian formation was formed in a coastal marine environment with slow deposition rates and is composed primarily of siltstone. The major challenges of the Turonian formation are low permeability (∼0.5 md) and extremely high clay content—chlorite, kaolinite, illite, and mixed-layer illite-montmorillonite. The low temperature of the Turonian formation (below 80°F) also presents a significant challenge for gas production. An operator must produce at minimum drawdown to avoid hydrates creation. The shallow reservoir depth (∼ 3,000 ft) restricts recovering potential energy stored inside of the formation (initial reservoir pressure of about 1600 psi); therefore, hydraulic fracturing is a must for economic development of the Turonian formation. Selecting the correct fracturing fluid required extensive laboratory tests for compatibility and rheology adjustments. Thorough optimization of the fracturing fluid with clay stabilizer was applied during the course of this project. Additional challenges included proppant flowback tendency and inefficiency of conventional methods (resin-coated proppant) at such low temperatures. The project began by stimulating a vertical well that was used as a reference for the fracture horizontal well that was stimulated in three stages. Coring and a full logging suite were performed on the reference well, including acoustic measurements, post-frac, to obtain fracture height growth. It was shown that fracture is vertical at such depth and that it covers the whole interval without vertical growth into argillaceous barriers. Bottom hole gauges were used to complete the precise mechanical modeling of the stimulated reference well. Evaluation of the mechanical and properties were completed using E&P software platform-based simulator to optimize the multistage fracturing design in the horizontal well. This paper includes a detailed sequence of the operations performed and explains conclusions made concerning fracture geometry. The lessons learned during the assessment campaign are described. This stimulation project performed in the North-Kharampurskoe field is fundamental in development of the field and serves as important step toward unlocking the gas potential of other Turonian siltstones.

Hydraulic fracturing in Western Siberia is continually evolving into larger and more aggressive fracture treatments to achieve higher conductivity than conventionally planned. At the same time some of the fields that have been waterflooded for 20 years or more for pressure maintenance, have become highly water-saturated. In the past, stimulation treatments were designed based on old log interpretations showing water saturation at original conditions and post-fracture water production was frequently under-estimated, while over-estimating oil production. A comprehensive study was conducted into the water- flooding pattern of a Western Siberia oil field, and water-cut maps were generated to determine which areas of the field were more water-saturated. This study included a statistical analysis of the effect of various fracture parameters on the post-fracture water-cut. Also the relationship between nearby water injectors and post-fracture water production was analyzed. It was found that injectors in a NNW proximity to the fractured well contributed higher post-fracture water rate. Generally, fractures grow in this direction, which is the maximum principal stress orientation across much of the Western Siberian Basin. This paper presents and discusses the statistical approach we developed. A new method of predicting post-fracture production involving a multi-phase reservoir simulator, was employed. The water and oil production match achieved using this simulator allowed us to re-calibrate the layer information from the original log interpretations, resulting in highly accurate production forecasts. A brief discussion of the simulator is also included in the paper. The trend toward larger treatments and coarser proppant has (1) produced higher-conductivity fractures and (2) significantly improved production from fields in western Siberia. At the same time, the trend has created longer effective fractures and in some instances increased access to water through inter-well communication. This development has underlined the importance of understanding reservoir saturation and waterflood patterns, so that full advantage can be taken of the increased conductivity through gain in oil productivity. These techniques of reservoir simulation and studying injector proximity were then employed in the field for candidate selection. The result has allowed fracturing to be performed in this field with greater confidence in predictability of post-fracture productivity. This paper presents the field study illustrating the developed methodology. Introduction The first known methods of obtaining oil in Russia came from the gathering of oil seeps from riverbeds. This method of oil gathering produced the first deliveries of oil to Moscow from the Ukhta River in 1567. Oil and gas seeps were also recorded on the western shores of the Caspian Sea in Baku near were the world's first oil well was drilled at Bibi-Aybat in 1846, a decade before the first well was drilled in the United States. This marked the birth of the modern oil industry. Newer fields were under development in the Volga Urals from the 1930s and by the 1960s the Soviet Union had replaced Venezuela as the second largest oil producer in the world. The 1960s saw the first major discoveries of oil in Western Siberia, culminating in the discovery of super-giant Samotlor field in 1965. In 1975 Kholomogorskoye began production from the most northern oilfield at the time, which in 1981 became part of Noyabrskneftegaz. By 1988, largely because of the investment in the development of fields in western Siberia, the Soviet Union had become the largest oil producer in the world at that point in time, with production of 11.4 million BOPD. Poor reservoir management techniques and old-fashioned technology, along with the post-Soviet Union economic crisis that halted spending in new exploration and drilling, caused a collapse in the beginning of the 1990s where Russian oil production dropped to almost one-half its peak by 1997. This was despite major investments in the mid 1990s that yielded only marginal improvements.

Before the mid-1990s, the main goal of hydraulic-fracturing operations in Russia was preventing near wellbore damage. Typical fracturing treatments used a crosslinked polymer-based gel as carrier fluid to place 5 to 20 MT of proppant into the formation. Because of the results, a new phase started, whereby "real" production enhancement treatments achieving skins of well beyond -4 were pumped with proppant volumes from 50 to over 100 MT. Because of Russian oil production practices at the time, it became apparent that the hydraulic fracturing technology combined with drilling horizontal wells increased production and was therefore beneficial to the Russian economy. When the optimization process started, quality control in the field became mandatory in addition to an enhanced focus on health, safety and environment. Service companies focused on cleaner fluids with less polymer loadings and better breaker systems. Prejob, on-the-job, and postjob quality control procedures were developed specifically for the Russian environment and reached a standard unlike anywhere else in the world. The number of unwanted screenouts was reduced significantly by following proper perforating practices and optimizing the treatments designs in real time. The new goal was a skin of -5, and the design process was optimized to achieve this number by designing each job to achieve optimum production for the given reservoir parameters, especially permeability. Treatments of 300–400 MT are not uncommon these days for low permeability reservoirs with a large reservoir height sometimes covering several zones. This lead to the optimization process that is currently practiced. Because many sandstone reservoirs, particularly in Siberia, are laminated, the vertical permeability is often an order of magnitude or more lower than compared to the horizontal permeability. Several times, horizontal wells did not yield the expected results. Hydraulic fracturing treatments placed in the horizontal wellbore can be the solution for further production optimization. This paper describes how this can be established through several techniques. Hydraulic fracturing includes propped hydraulic fracturing in both oil and gas reservoirs, as well as carbonate fracture acidizing. This paper discusses propped hydraulic fracturing in oil reservoirs. Covering propped hydraulic fracturing in gas reservoirs, although still at the beginning stages, could reveal enough material for a paper on its own. However, carbonate fracture acidizing is not frequently used. Introduction In 2009, the oil and gas industry will celebrate 60 years of hydraulic fracturing. In March, 1949, a team of Halliburton Oil Well Cementing Company and Stanolind Oil Company personnel gathered at a wellsite near Duncan, Oklahoma, U.S.A., to make oilfield history by performing the first commercial hydraulic-fracturing treatment (Fig. 1). Tens of thousands of wells have been treated using this technology and several improvements have been made since in the Western world. Exploration for oil was active in the former Soviet Union in the 1840s in the vicinity of Baku (the first modern oil well was drilled in 1846 by Russian engineer F.N. Semyenov) in the Caspian and was revived significantly after World War II. Soviet explorers were able to apply scientific methods free of commercial constraints. Boreholes were drilled for geological information and Russian explorers pioneered the geochemical breakthrough that identified the source rocks and generating belts.

Авторское право 2015 г., Общество инженеров нефтегазовой промышленности Этот доклад был подготовлен для презентации на Российской нефтегазовой технической конференции SPE, 26 -28 октября, 2015, Москва, Россия.Данный доклад был выбран для проведения презентации Программным комитетом SPE по результатам экспертизы информации, содержащейся в представленном авторами реферате. Экспертиза содержания доклада Обществом инженеров нефтегазовой промышленности не выполнялась, и внесение исправлений и изменений является обязанностью авторов. Материал в том виде, в котором он представлен, не обязательно отражает точку зрения SPE, его должностных лиц или участников. Электронное копирование, распространение или хранение любой части данного доклада без предварительного письменного согласия SPE запрещается. Разрешение на воспроизведение в печатном виде распространяется только на реферат объемом не более 300 слов; при этом копировать иллюстрации не разрешается. Реферат должен содержать явно выраженную ссылку на авторское право SPE. РезюмеТуронский газоносный пласт, один из основных стратегических ресурсов в Ямало-Ненецком округе, залегает над Сеноманским песчаником и отделен мощной толщей аргиллитов. Успешная кампания по гидроразрыву пласта в вертикальных скважинах Северо-Харампурского месторождения в 2008 и 2010 годах стала предпосылкой для следующего шага недропользователей в изучении перспектив разработки залежи. Статья содержит детальное описание проекта МГРП.Туронская залежь Северо-Харампурского месторождения представляет собой алевритистый песчаник. Основными трудностями эксплуатации объекта являются низкая проницаемость (~0.5 мД) и высокое содержание глинистых фракций -хлорита, каолинита, иллита и монтмориллонита. Низкая пластовая температура (менее 27°С) представляет вызов для разработки из-за риска формирования газовых гидратов. Небольшая глубина залегания (менее 1 км) в свою очередь ограничивает потенциальное энергию на подъем углеводородов (пластовое давление порядка 110 атм). Таким образом, гидроразрыв пласта является единственным способом рентабельной эксплуатации объекта. Была проведена оптимизация жидкости ГРП по стабилизации пластовых глин. Дополнительные сложности, заключались в тенденции к выносу пропанта из трещины и температурным ограничениям традиционных пропантов со смоляным покрытием (RCP).Кампания началась с гидроразрыва вертикальной скважины, спроектированной в качестве опорной исследовательской скважины для последующего трех-стадийного ГРП в горизонтальной скважине. Исследовательская скважина обеспечила максимальную полноту информации -в ней были проведены отбор керна и расширенный комплекс каротажных исследований, включающих запись широкополосной акустики позволивший определить границы вертикального роста трещины. Так, было показано, что трещина ГРП распространяется вертикально и вскрывает всю толщу туронской залежи. При этом отсутствует вертикальный рост в покрышки аргиллитов сверху и снизу газоносного пласта. Датчики забойного давления были использованы при ГРП для более точного моделирования геометрии т...

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