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Though expensive and complex, extended-reach drilling (ERD) is moving more into the mainstream as the industry is driven to develop frontier reserves in fragile environments like the Arctic where drilling from shore to offshore targets reduces a project's infrastructure costs and environmental footprint. A form of directional drilling, ERD is also being used increasingly to tap into hard-to-produce reservoirs, making viable projects that might otherwise be written off as noncommercial. This article highlights how the Russian Far East became the ERD epicenter in the past decade, given ExxonMobil and Rosneft's extensive use of ERD in developing Arctic resources offshore Sakhalin Island, and how ERD is becoming more widely used in regions as diverse as the Gulf of Thailand, offshore Brazil, and the Arab Gulf. By definition, an extended-reach well (ERW) is one in which the ratio of the measured depth (MD) vs. the true vertical depth (TVD) is at least 2:1 (PetroWiki). An ERW differs from a horizontal well in that the ERW is a high-angle directional well drilled to intersect a target point, a feat requiring specialized planning to execute well construction.
Russia has taken its first steps toward regulating carbon emissions since joining the Paris climate accords in 2019 with President Vladimir Putin's signing of legislation in early July requiring the country's largest greenhouse-gas emitters (GHG) to report carbon data to a new government agency. The new law makes carbon reporting mandatory as of January 2023 for companies emitting 150,000 tons of carbon or more, and January 2025 for carbon emitters in the 50,000 to 150,000 range, according to the Russian news agency TASS. "An accounting system is being introduced, carbon dioxide is becoming a substance subject to government regulation," Greenpeace spokesman Vladimir Chuprov told Reuters. "An emissions accounting and reduction system is emerging. This is a prerequisite for a greenhouse-gas emissions trading system."
India is on track to overtake China within the next year or two as the world's most populous nation, pandemic or not. So, while near-term forecasts suggest that the current health crisis has slowed industrial growth, and thus muted the expected rise in demand for energy, India's baseline metrics are not likely to change, nor will the country's impact on global energy markets. By 2040, India will be the world's biggest energy consumer, and the country is betting on natural gas, developed in parallel with renewable energy, to reduce its carbon footprint, which, in 2020, saw India ranked third in greenhouse gas (GHG) emissions after China and the United States, according to the International Energy Agency's (IEA) India Energy Outlook 2021. Gas demand is growing, too, as the Indian government sees gas as critical to controlling carbon emissions while it develops renewables in parallel to provide energy to a population that is forecast to grow to 1.6 billion by 2040. Now fast-forward to 2040 when India is projected to account for 25% of the growth in world energy demand, more than any other country, according to the IEA's Sustained Energy Policy Scenario outlined in its 2021 outlook.
Gazprom and partner RusGazDobycha have begun construction of a massive gas processing complex near the port of Ust-Luga on the Baltic Sea. Poised to become Russia's largest gas processing plant and one of the world's largest by volume, the new facility is part of Gazprom's strategy shift toward processing and will combine a gas processing plant with a gas chemical and natural gas liquefaction complex Russian Deputy Prime Minister Alexander Novak, speaking during the televised ceremony to mark the start of construction, said the complex will help Russia gain a greater share of the global market for LNG and gas processing. Russia plans to triple LNG production to some 140 million tonnes annually by 2035 and raise its global LNG market share to 20%. "Here in the northwestern part of Russia, in the Leningrad Region, we have launched the construction of a fundamentally new and high-tech industrial cluster," said Alexei Miller, chairman and chief executive of Gazprom, speaking at the dedication ceremony. "It is essential for the region and the country at large. Advanced processing is the most efficient way to maximize the potential of the immense reserves of ethane-containing gas in Russia."
Abstract The problem of capricious log response is one that has persistently troubled formation evaluation experts since the Schlumberger brothers ran their first log in Pechelbronn, France. Since the advent of 6FF40 induction logs in the 1950’s, subtle differences have been noted between laterolog and induction response. As field resistivity measurements have evolved to array induction and array laterolog tools, resultant resistivity variability has increased. (Gianzero, 1999) This paper examines how the resistivity discrepancies between laterolog and induction response in an electrically anisotropic rock can greatly affect calculated water saturations (Sw), and ultimately oil in place. Further, several possible solutions are posited to resolve the riddle of resistivity. The root cause of the differences between the two measurement techniques is in how each tool measures the vertical resistivity (Rv) and horizontal resistivity (Rh) in addition to dielectric effects. In isotropic formations, the difference between Rv and Rh is miniscule. However most organic shales and many laminated low porosity formations are anisotropic. (Klein et al., 1997) In anisotropic formations, the ratio of Rv/Rh is not constant over the possible range of resistivities. This ratio has been observed to be as high as 5 at less than 1 ohmm of Rh, and approaches unity at infinite resistivity. Due to the high Rv/Rh ratio, at low resistivities, differences between laterolog response (Rh + fraction of Rv) and induction response (Rh) has a dramatic impact on resultant water saturation values. Laterolog array measurements exhibit a systematically higher resistivity than array induction measurements in the same formation. Variances in Sw as high as 30% has been observed. Since most North American unconventional fields have a mix of historical laterolog and induction data from different eras, it is imperative to address this apparent contradiction in values. Further confounding the issue, the mud salinity required to run both tools at peak performance is nearly mutually exclusive. This complicates efforts to resolve the conundrum because the tools cannot be run simultaneously. The closest measurements on the same rock come from sidetracked wells where one has a laterolog and the other induction. The next best possible measurement is the tri-axial resistivity which can be used to model the Rv and Rh. The issue with tri-axial tools, is that the laterolog apparent resistivity does not conform to either end member of the Rv or Rh. Since the detailed field measurements have been lost to time and only the measured resistivities are available in public LAS data sets, several practical solutions have been devised by the authors to untangle this mess. First, sets of proximal wells (<1000 ft apart) with either tool were depth-shifted and oriented for analysis. Wells with tri-axial resistivity modeled Rv and Rh supplemented the data set. Once the data was collected, the authors utilized simple x-y regression, multilinear regression, artificial neural net, and random forest regression to predict true Rh. The results of each predictor algorithm is discussed, as the optimal solution is situationally dependent.
Zhang, D. Leslie (CNPC USA Corp.) | Qi, Chunyan (Beijing Huamei Century International Technology Co.) | Shi, Xiaodong (Exploration and Development Research Institute of Daqing Oilfield Company Ltd.) | Zhan, Jianfei (Exploration and Development Research Institute of Daqing Oilfield Company Ltd.) | Han, Xue (Exploration and Development Research Institute of Daqing Oilfield Company Ltd.) | Li, Xiangyun (Beijing Huamei Century International Technology Co. Ltd.) | Wang, Ze (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Abstract Relative permeability is one of the most important petrophysical parameters to evaluate a reservoir’s production during primary and subsequent secondary or enhanced oil recovery processes. Yet measured relative permeability data for tight oil reservoirs are very scarce to find in the literature, mainly because the measurement is difficult and time consuming to make. In this paper the protocol and results of water/oil, surfactant /oil, CO2/oil, and N2/oil relative permeability are presented, and compared to the digital core analysis results where wettability was set to water-wet or mixed-wet, as well as the Brooks-Corey model. Amott-Harvey wettability index was measured to explain the differences. The target formation is a sandstone tight oil formation located in Songliao Basin, China. Its permeability is mostly in the 0.01-5mD range. Core and oil samples from the target formation were used in the wettability and relative permeability determination. Relative permeability was measured at reservoir conditions using a customized core flow setup. Core samples were cleaned then wettability restored. To match the reservoir fluid viscosity and avoid changing wettability, stock tank oil was blended with kerosene to reservoir fluid viscosity at reservoir temperature. Relative permeability was measured using the unsteady-state method. Amott-Harvey wettability index was measured on core samples from the same formation at reservoir temperature. Amott-Harvey wettability index results show that the restored wettability ranged from water-wet to oil-wet, with most samples being mixed-wt. The addition of non-ionic surfactant promoted wettability change toward more water-wetness. However, anionic surfactant had little effect on reversing wettability. Oil relative permeability (Kro) results obtained from the digital rock analysis (DRA) assuming uniform water-wetness are consistent with relative permeability calculated from mercury injection capillary pressure using Brooks-Corey model. When wettability of the digital rock model was set to mixed-wet, the resulted Kro matches the measured Kro of a sister plug to the sample used to build the digital rock model, which is consistent with the wettability measurements. The addition of surfactants increased both water and oil relative permeability through wettability alteration and IFT reduction. CO2 flood was conducted as an immiscible flood due to reservoir pressure lower than MMP. CO2 flood left high residual oil saturation compared with water floods. N2 flood left even more oil behind compared with CO2 flood. Relative permeability provides key input parameters for formation evaluation and the subsequent EOR processes such as huff-n-puff operations. There are very little published relative permeability data for tight oil reservoirs. This work extends the relative permeability database, and is a starting point for future EOR work.
Shareholders of Russia's second-largest gas producer, Novatek, have approved $11 billion in external financing for the Arctic LNG 2 project on which Novatek has pledged its 60% equity stake in the project as collateral. The approval came 23 April at the company's annual shareholders' meeting. In making the announcement, Novatek CEO Leonid Mikhelson said that responsibility for fundraising will be split three ways between Russia, China, and the tandem of Japan and Europe acting together. The $21-billion project, which received final investment approval in 2019, is expected to launch production in 2023 as Novatek expands its LNG exports east and west along Russia's now navigable Arctic coast. Arctic LNG 2 will reach full capacity of almost 20 mtpa in 2026, according to the company.
Potapenko, Dmitriy Ivanovich (Member) | Hart, Timothy Brian (Fremont Petroleum Corporation) | Waters, George Alan (Member) | Lewis, Richard E. (Member) | Utter, Robert J. (New Ventures Energy Consulting) | Brown, J. Ernest (Member) | Goudy, Guy Thomas (Formerly Fremont Petroleum Corporation) | Jelsma, Henk H (Radial Drilling Services, Inc.)
Abstract This paper describes the first application of a novel reservoir-stimulation methodology that combines oriented extended perforation tunnels of lengths up to 300 feet with specially designed hydraulic fracturing operations in the Niobrara Formation in the Florence Field in Colorado. The technology was extensively tested in two vertical wells completed with two and five pairs of the extended perforation tunnels respectively. Extended perforation tunnels were jetted using radial drilling technique with the tools deployed using micro coil tubing. The jetting operation on each well was followed by a fracture stimulation treatment. The use of radial drilling technology to create extended perforation tunnels for the vertical wells offered a cost-effective way to significantly increase the reservoir contact area of the wellbore, making it similar to that of horizontal wells in the area. The engineered fracture treatments were performed at low treating pressures, and low proppant and fluid volumes. The stabilized production rates of both project vertical wells included in this technology test exceeded expectations and are comparable to the stabilized production rate of the offset horizontal well that was completed in the same zone with significantly higher volumes of proppant and fluid. The initial evaluation of the completion efficiency of this novel reservoir stimulation technology showed that its deployment delivered an improved stabilized production rate to cost ratio for the second vertical well, compared to the reference horizontal well. Based on the test results from the two wells, we conclude that the proposed reservoir stimulation methodology leads to substantial improvements in well production performance compared to traditional reservoir stimulation methods. Both the applied cost-effective approach for increasing the reservoir contact and the significantly lower resource intensity required for the hydraulic fracturing treatment further improve the economic benefits of this methodology. This novel reservoir stimulation methodology opens the way for reconsidering well completion practices in the Niobrara Formation and holds significant potential for improving the hydrocarbon production economics in the Florence Field.
Summary A new classification of gas-hydrate deposits is proposed that takes into account their location (marine vs. permafrost), porosity type (matrix vs. fracture), and gas origin (biogenic, thermogenic, or mixed). Furthermore, by incorporating currently used Classes 1 through 4, which describe the nature of adjacent strata, a total of 16 classes of hydrate deposits have been identified. This new classification provides detailed information on the properties of the hydrate-bearing layer and adjacent strata that can be used for both scientific research and ranking of field-development potential. Using this new classification system, a qualitative ranking of field-development potential for different classes of hydrate deposits according to likely productivity, capital, and operating costs can be conducted. Finally, we demonstrate the usefulness of this new classification by applying it to 11 well-knowngas-hydrate deposits worldwide.
Aidoo, Ato (Nostrum Oil & Gas plc.) | Zenzin, Valeriy (Nostrum Oil & Gas plc.) | Kropochev, Yuriy (Nostrum Oil & Gas plc.) | Akulov, Konstantin (Nostrum Oil & Gas plc.) | Vitvitckii, Evgenii (Nostrum Oil & Gas plc.) | Arystan, Abylaikhan (Nostrum Oil & Gas plc.) | Juchiac, Emil (Nostrum Oil & Gas plc.) | Palten, Peter-Joern (Nostrum Oil & Gas plc.) | Amanbayev, Yerlan (Weatherford) | Higginson, Tim (Weatherford) | Amangeldiyeva, Diana (Weatherford) | Aliyeva, Aida (Weatherford)
Abstract This case study describes the approach taken when drilling an 11 5/8-in. hole section through a salt formation on the Chinarevskoye field in the West Kazakhstan Oblast region where high-intensity brine influxes and subsequent flow had been encountered. The intensity of the brine flow, when encountered, had ranged from 5,000 to 6,000 L/min at an equivalent kick density of 2.2 SG, and it is believed to be among the most intense brine flow experienced in the world during drilling operations. Standard well control measures proved to be inefficient because of the narrow margin between pore pressure and fracture pressure gradients. Several techniques were applied to combat such influxes in a safe manner with minimum associated nonproductive time (NPT). The high-pressured formation in this hole section is associated not only with brine influxes, but also with losses and gas increase scenarios. As a result, the company adopted unconventional drilling techniques with a combination of planned flow-while-drilling (FWD) and mud-cap drilling techniques to reach total depth (TD). These two techniques created a viable and cost-effective solution to mitigate such challenges, helped the company to drill to the planned section TD, and consequently complete the well within the defined authorization for expenditure (AFE) without associated NPT. The paper will cover and emphasize techniques, along with details on running casing and cementing the hole section, which required an unconventional approach for success. The paper will also briefly outline the equipment used, such as rotating control devices (RCDs), a choke manifold, and a separator when drilling this section and their limitations. Despite the complications, the well was successfully drilled, and this experience provided an opportunity for learning. The marked improvements in well control, loss management, and cementation displayed that combining knowledge and experience can reduce the negative impact on well costs when drilling similar cases.