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Summary The focus of this work was to obtain reliable kerogen and solid bitumen density data and to establish robust descriptions of the organic matter responsible for liquid hydrocarbon generation in the Devonian organic-rich Duvernay shale. Five wells were selected from Alberta, Canada, for investigation of the organic matter (OM) properties, particularly its density. A comprehensive workflow was designed and executed that includes the selection of representative samples for detailed evaluation of possible vertical heterogeneity of organic facies and on which to perform separation of organic matter and density measurements. The major goals were to understand the various controls on organic matter types (macerals), kerogen density, and to develop a predictive tool for calibrating density to maturity and organic matter distribution. We showed that the sole utilization of Rock-Eval pyrolysis data as the maturity proxy, following published correlations, may lead to substantial overestimation of the actual maturity, as compared to other maturity proxies. We also demonstrated that the organic petrology and the vitrinite reflectance equivalent (VRE) values derived from solid bitumen reflectance and published correlations (Jacob, 1985; Schoenherr et al., 2007) much more closely reflect the maturity of actual fluids being produced in the subject area. The rocks studied vary from 2 to10% in total organic carbon (TOC) content, with VRE values of 1 to 1.2%, and are producing light fluids that correlate with the middle upper maturity range. Geochemical markers corroborate the petrographic maturity estimations observed. The organic matter is dominated by two main constituents—amorphous organic matter (AOM) and solid bitumen—with traces of other liptinites. Kerogen density varies from 1.25 to 1.35 g/cm3, depending on the influence of solid bitumen on overall composition; however, the average density of the kerogen in this area, and taking into consideration the maturity range, was established at 1.28 +/- 0.3 g/cm3. We have also captured kerogen density variation driven by maturity, with one well showing consistently lower-density kerogen than the other four wells. Measured kerogen densities were subsequently used in advanced petrophysical analysis, with an effort to distinguish between bitumen and kerogen volumes and to determine the porosity associated with each OM constituent. While this paper uses the Duvernay shale as an example, the conclusions have universal application to all unconventional resource plays. In addition, our work can be used to better understand OM variability and its control on the type of fluids generated and produced, and it provides measured rather than assumed kerogen properties as direct input to formation evaluation and modeling software.
The PDF file of this paper is in Russian.
Today, Tatneft PJSC is intensively studying and developing production technologies for Domanic formations in Tatarstan. Over the last 3-5 years, the USA companies have made significant progress in shale reservoir development, which required billions of dollars and over 20 years of research. The USA companies’ experience could be used in Tatarstan to reduce financial and time expenditures. However, these technologies must be customized for Tatarstan fields, with due regard for their special features. This paper discusses technologies used for shale reservoir studies and development in the USA. The standard suite of core, cuttings and fluid analyses includes application of X-ray diffraction (XRD) equipment, kerogen examination, use of spectrometer and electronic scanning microscope, thin-section petrography, isotope and chromatographic analyses (RCA), proppant and fracturing agent tests, determination of capillary pressure, and rock mechanics survey. In addition, some special or supplementary survey can also be carried out. Domanic reservoirs in Tatarstan are similar to Shaly Carbonate reservoirs that are successfully produced in the USA. The initial production of oil from wells with a horizontal section 1,600-3,200 m long is 130-200 t/d after 20-40-stage fracturing. Major portion of oil is produced during the first year and a half, which is followed by pressure depletion and production decline. 2.5-3 years later, multi-stage fracturing is conducted again, and this increases well economic life by 2-2.5 years. Payback period for 4 mln dollars CAPEX (240 mln RUB) is 6-12 months. To achieve such results in the Domanic formations, extensive R&D efforts are required. Based on the numerical simulation, more fracturing stages and longer horizontal wells produce better results. The paper reviews innovative technologies and procedures based on machine learning, which enable having total high-resolution data set without expensive geophysical surveys and analyses of large amount of core and cuttings samples. Such technologies and procedures allow defining drilling location, interval and direction of horizontal drilling, placement of perforation clusters and frac stages, as well as multi-stage fracturing design and fracture growth monitoring.
В настоящее время ПАО «Татнефть» активно развивает направление по изучению и созданию технологий разработки доманиковых отложений. Для данных целей необходимо проведение большого количества исследований, моделирования, научных и производственных работ. В последние 3-5 лет компании в США добились значительного прогресса в разработке плотных нефтяных коллекторов. В статье приведены данные о технологиях, применяемых при изучении и разработке сланцевых коллекторов в США. Стандартный комплекс исследований керна, шлама и флюидов включает рентгеноструктурный анализ, изучение керогена, исследования на спектрометре и электронном сканирующем микроскопе, тонкослойную петрографию, изотопные и хроматографические анализы, определение капиллярных давлений и геомеханические исследования и др. Кроме того, возможно проведение специальных или дополнительных исследований. Отмечено, что наиболее схожими с доманиковыми отложениями являются коллекторы Shaly Carbonates, разработка которых в США характеризуется достаточной эффективностью. При длине горизонтального ствола 1600-3200 м и 20-40 стадиях гидроразрыва пласта получают начальный дебит нефти около 130-200 т/сут. Основной объем нефти добывается в первые 1,5 года. За это время стремительно падают пластовое давление и соответственно дебит нефти. Через 2,5-3 года проводят повторный многостадийный гидроразрыв пласта (МГРП), который продлевает экономически рентабельный срок эксплуатации скважины еще на 2-2,5 года. Все это позволяет при затратах на бурение в среднем 4 млн долл. окупить капитальные затраты за 6-12 мес. Численное моделирование показало, что в Республике Татарстан необходимая эффективность может быть достигнута при увеличении длины горизонтальных стволах и количества стадий МГРП относительно существующих в настоящее время. Приведены данные о новейших технологиях и методиках с использованием машинного обучения, которые с недавнего времени успешно применяются в США. Комплекс работ позволяет определить точку бурения скважин (вертикального ствола), интервал и направление проводки горизонтального ствола, расстановку кластеров перфораций и стадий МГРП, дизайн МГРП (в том числе реагенты и проппант), мониторинг роста трещин (в процессе МГРП) и их изменения (в процессе добычи).
Although unconventional resources contributed almost no production in the early 1970s, they now provide almost 30% of US domestic natural gas supply. Unconventional reservoirs have a complex lithology with heterogeneous porosity, complex fluids, or both. Ultimate recovery is typically lower than from conventional reservoirs, so effective exploitation requires more wells to drain the resource effectively. Excluding product price, capital expenditures are a critical factor in the economics and have driven a development culture focused on cost, in the absence of technology that provides a clear cost benefit to increased production and/or recovery. However, the exponential growth of production from unconventional reservoirs has not been accompanied by comparable growth in the knowledge and understanding of the rock properties and completion parameters controlling production.
Abstract Unconventional resources have been identified throughout the world and contain enormous in-place volumes but tight and unfamiliar reservoirs challenge the transformation of these resources to supplies. The key issue is whether industry can grow production from unconventional reservoirs at a rate that will offset declines from older conventional reservoirs. E&P companies are attracted to such resources because they have low exploration risk, material production volumes, long-lasting production and exist near mature, stable markets. In addition, with the exception of Canadian bitumen production, current recovery factors are low so these accumulations have the potential for a substantial "technology dividend". At some 7.5 trillion barrels, estimates of the in-place resource of bitumen, extra-heavy oil and shale oil are over three times greater than the 2.25 trillion barrels of recoverable conventional oil estimated to have been discovered to date. Unconventional liquids production from Canada and Venezuela currently comprises about 2% of world liquids production. Current projections indicate these giant resources will add no more than about 400,000 barrels of annual new production. This is les than desired to offset global declines of 5 to 6 MMb/yr. Excluding gas hydrates, remaining recoverable resources of the three principal gas resource play types are estimated at over 1,000 trillion cubic feet and there is significant potential for growth in unconventional gas resources outside North America. Even though U.S. unconventional gas well completions have tripled the growth of gas from unconventional reservoirs has not offset decliines in conventional gas production. Introduction Among the three pillars of future oil and gas supplies, the unconventional resource potential greatly exceeds that of the other two pillars - growth to known fields and yet to find fields. Estimated in-place resource of bitumen, extra-heavy oil and shale oil are about 7 times greater than the estimated recoverable conventional liquids from field growth and yet to find sources. Excluding gas hydrates, estimated in-place volumes of unconventional gas are estimated to be 4 to 5 times greater than estimated recoverable conventional gas from field growth and yet to find sources. In-place unconventional resources are huge but there are substantial challenges to transform these resources into supplies. Unconventional hydrocarbons are found in tight, low permeability, low porosity, low recovery "difficult to produce" rock formations, such as tight sands, shales, chalks and coal seams. These rocks require distinctive completion, stimulation, and / or production techniques to recover the hydrocarbons. Fractures often are critical to establish economic recoveries and unconventional reservoirs may be over or under pressured and typically are not affected by hydrodynamic influences. Unconventional reservoirs often are described as "resource plays". Many are pervasive throughout a wide area and also are referred to as "Continuous -type Deposits". Realistically, the boundaries between "conventional" and "unconventional" are gradational and change over time. For purposes of this report original definitions applied some 20 years ago to define U.S. tight gas reservoirs are used. Tight reservoirs were defined as having less than 0.1 millidarcy permeability and tight reservoirs typically have 13% or less porosity. Unconventional reservoirs also were characterized by low recovery factors - often less than 10% recovery on primary recovery. Conversion-sourced hydrocarbons such as gas to liquids and coal to liquids, fermentation of carbohydrates, non-fossil renewable resources and gas hydrates are not included in this report.