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Journal articles on the topic 'Oil well drilling rigs'
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1
Nae, Ion, Gabriela Cristina Ionescu, and Octavian Narcis Ionescu. "Planning, Monitoring and Controlling Assembling Activities for Oil Well Drilling Rigs." Applied Mechanics and Materials 657 (October 2014): 364–68. http://dx.doi.org/10.4028/www.scientific.net/amm.657.364.
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Lake, B. D., and V. Santostefano. "BASS STRAIT DRILLING - PREPARING FOR THE NINETIES." APPEA Journal 30, no. 1 (1990): 300. http://dx.doi.org/10.1071/aj89019.
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Future development drilling in Bass Strait will be challenged by small field sizes, thin oil columns and increasing drilling difficulty due to greater hole angle and reach. New drilling technology successfully introduced in the recent Bream, Whiting, Perch and Dolphin developments including Steerable Drilling Systems (SDS), Polycrystalline Diamond Compact (PDC) bits and Logging While Drilling (LWD) tools, coupled with the successful use of jackup rigs for miniplatform development, has given Esso the tools and confidence to meet the development challenges of the 'nineties. Bass Strait's first horizontal well has been successfully drilled and completed with further wells planned in the current Bream development. There still remain some areas requiring improvements, including hole cleaning in high angle holes. Improvements in this and other areas will further improve drilling capability.Given the right incentives Bass Strait drilling technology is well positioned for the challenge of oil development in the 'nineties.
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Brown, Alan S. "Storm Warning." Mechanical Engineering 128, no. 06 (June 1, 2006): 24–29. http://dx.doi.org/10.1115/1.2006-jun-1.
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This article focuses on measures for preventing damages to oil drilling setups post hurricanes or typhoons. According to engineers, today, it is a complex network of fixed and floating production platforms, mobile drilling units, undersea wells, and oil and gas pipelines. No single solution will ensure the safety of the entire system. The exploration wells under the drilling rigs are also vulnerable. Mobile drilling units, such as jackups and semisubmersibles, which drill test wells and then move to another location, proved especially vulnerable during Katrina and Rita. When the American Petroleum Institute rolled out its first post-Katrina recommendations in April, it took an initial step on a road that will eventually demand changes in everything from air gaps, tie-downs, and deck design to moorings, tethers, clamps, and piping supports. New standards are expected to improve the odds for newer platforms and rigs if they continue to face larger and larger hurricanes.
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Shepelev, A. A., and M. V. Kosnyreva. "GEOPHYSICAL RESEARCH AS PART OF ENGINEERING SURVEYS ON THE SHELF OF THE OKHOTSK SEA." Bulletin of Dubna International University for Nature, Society, and Man. Series: Natural and engineering sciences, no. 2 (47) (September 14, 2020): 51–59. http://dx.doi.org/10.37005/1818-0744-2020-2-51-59.
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The paper deals with the results of marine engineering surveys on the shelf of the Okhotsk Sea. According to the results of the study, potentially hazardous geological and technogenic objects were localized, and a network of buried river paleo–incisions was identified. The work performed allowed us to obtain materials that ensure the safe installation of floating drilling rigs for the period of well drilling, design and construction of oil and gas field facilities.
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Khonji, Najla Abdulaziz, and Saad M. A. Suliman. "Product Mix Optimization for an Oil Field Operating Company." Modern Applied Science 14, no. 10 (September 24, 2020): 20. http://dx.doi.org/10.5539/mas.v14n10p20.
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In this study, a mathematical model is formulated to select the optimal product mix of wells in terms of numbers and types of wells that helps to maximize profit. The optimization model comprises two main components, the first component is revenue which includes forecasting of production and oil price, and the second component is cost which includes capital and operating costs. In addition, the model considers all related constraints such as budget, production targets, surface facility limitations, drilling rigs availability and others. Time has influence on the model, since its output is not limited only to the types and numbers of wells to be drilled during the planned period, but also when each well to be drilled for the same plan. Actual planning data for three consecutive years is used for model testing. The results show that 42% to 47% cost saving can be achieved by using the model. The analysis shows that with every 10% increase in oil price, the profit increases by about 6%. Also, it shows that the number of rigs and the rig daily cost affect the profit tremendously, where by reducing these two parameters by 50% an increase of 66% in oil profit can be achieved. The study confirms that oil field operating companies can stand a better chance of maximizing their profit by using product mix optimization model to define the optimum schedule for the number of wells, type of wells and time of drilling.
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Vazquez, Jennifer, and Donald Larry Crumbley. "Flared Gas Can Reduce Some Risks in Crypto Mining as Well as Oil and Gas Operations." Risks 10, no. 6 (June 16, 2022): 127. http://dx.doi.org/10.3390/risks10060127.
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There are numerous risks associated with mining and owning cryptocurrencies, and exploring and producing oil and natural gas are highly risky, costly, and controversial. A marriage of digital mining and exploring and producing oil and natural gas has reduced the major risks and costs for both the crypto miner and the petroleum industry. On the one hand, crypto mining requires an enormous amount of electricity, which is not environmentally friendly. On the other hand, when drilling for petroleum resources, natural gas is often discovered, but due to a lack of resources or pipeline availability, a massive amount of natural gas is vented into the atmosphere or burned (called flaring). Today, however, this normally wasted gas (called stranded natural gas) is being used to create cheap electricity for mining server containers stationed near drilling rigs, which are used to create cryptocurrencies. This results in reduced CO2 emissions, lower costs for drillers, and greater royalties going to landowners.
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Leksin, V. K., V. I. Samarin, and P. N. Liskovyi. "RESULTS OF INTERPRETATION OF SEISMIC SECTIONS DURING ENGINEERING SURVEYS WITHIN OF THE SOUTH-KIRINSKOYE OIL AND GAS CONDENSATE FIELD (SHELF OF SAKHALIN ISLAND)." Engineering survey 12, no. 9-10 (April 4, 2019): 64–73. http://dx.doi.org/10.25296/1997-8650-2018-12-9-10-64-73.
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High-resolution 2D seismic is the main and optimal method in marine engineering geophysics, which for many years has worked well for the production of semi-submersible drilling rigs, self-lifting drilling rigs, construction of berthing facilities and bridges. The main objective of this method is to identify near-surface gas, faults, which are geological hazards. The method used for performing marine research is longitudinal profiling of reflected waves with a 48-fold overlap of the reflecting horizons. To obtain high-quality seismic migrated sections, we have previously developed a unified data processing algorithm for the offshore areas of the South-Kirinskoye oil and gas condensate field (Sakhalin shelf). More than 8,000 line km of seismic data were processed. The article presents the sequence of interpretation, as well as an analysis of the presence of hazards in the project wells (objects). To isolate potentially dangerous objects for each horizon, a dynamic analysis was carried out, which included the definition of the following parameters: maximum and minimum peak amplitude. The systematization and classification of amplitude anomalies was carried out according to such features as a phase change, frequency reduction, the presence of a supply channel and distortion (false deflection) of all underlying boundaries, indicating the possible presence of gas. The probable hazard levels for drilling operations were determined. All the identified anomalies in the process of interpreting seismic sections were mapped to the geological hazards to select the optimal and safe installation point for drilling a prospecting or exploration well.
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Utomo, Budi. "PENGEBORAN LEPAS PANTAI." Gema Teknologi 16, no. 3 (February 6, 2012): 113. http://dx.doi.org/10.14710/gt.v16i3.4705.
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Budi Utomo, in this paper explain that offshore drilling carried out to obtain crude oil through the oil wells. The means that must exist in the operation of offshore drilling is a bridge structure (plate form) as a place to put the drilling equipment. Known two kinds of platforms, that is platforms permanent (fixed) which stands on the feet of reinforced concrete, and the bridge is not fixed like swamp barges, drilling ship (floaters) and jack-up rig. Jack up rig is one of the offshore rigs that have the ability to elevation in accordance with a sea depth of drilling. Drilling equipment is a range of equipment that is prepared in such a way, so that such a drill rod, and all this equipment has a hole inside that allows for fluid or mud circulation. Key word: Drilling equipment
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Huang, Lu Meng, Yan Ting Zhang, Lei Zhang, and Mei Ying Liu. "Simulation Study on Drawworks Heave Compensation System of Offshore Oil Drilling." Applied Mechanics and Materials 385-386 (August 2013): 951–55. http://dx.doi.org/10.4028/www.scientific.net/amm.385-386.951.
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In order to improve the efficiency of offshore oil drilling, simplify the structure of drilling rigs, a new type of heave compensaton drawworks is put forward to realize decoupling control of motion and energy saving by hydraulic energy storage. In order to study the compensation performance of drawworks, mathematical simulation model is built, heave compensation displacement controller of fuzzy-PI and bit pressure controller of BP neural network are designed based on the high inertia load and nonlinear time-varying characteristics of the system. The simulation results show that the heave compensation maintains the absolute displacement of the hook within certain premises and reduces the effects on bit pressure by platform heave movement, automatic bit feeding keeps bit pressure steady, the bit pressure is kept in the scope prescribed by work. The research result shows that the device well meets the performance requirements of offshore drilling.
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Rao, T. Kishan, M. Shankar Lingam, Manish Prateek, and E. G. Rajan. "SUBSURFACE IMAGING USING GROUND PENETRATING RADAR FOR UNDERGROUND OIL AND MINERALS EXPLORATION." International Journal of Engineering Science Technologies 4, no. 6 (January 6, 2021): 71–79. http://dx.doi.org/10.29121/ijoest.v4.i6.2020.139.
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A drilling company operates in accordance with a contract which specifies that an oil well will be drilled to a specific depth. The average cost to find and develop an oil and gas property in the United States is $17.01/ barrels-of-oil-equivalent from 2005 to 2007. The cost for onshore development was $13.38/BOE and for offshore development was $49.54/BOE. Based on some statistics one out of five rigs drilled in an area yields oil recovery. This means $20 million has to be spent for prospecting and locating one oil well. The question that arises now is whether it is worth trying all possibilities of reducing the cost of locating an oil well to $4 million and save $16 million. Well, the research presented in this paper is aimed at showing such a possibility.
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Alimin, Ahmad R., Sumayyah N. Syahidah, and Dedy Sushandoyo. "The Influence of Safety Slogan and Safety Program to Safety Culture: Case study at Drilling and Well Intervention Division one of Indonesia’s Oil and Gas Company." European Journal of Business and Management Research 8, no. 1 (January 10, 2023): 64–70. http://dx.doi.org/10.24018/ejbmr.2023.8.1.1768.
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In the Oil and Gas Industry, Occupational Safety and Health are prioritized. This is not only based on the high risk in this industry but also part of maintaining the name of a company in developing its business. Because if a company's occupational safety and health record is bad, then investors will re-think for investing in the company. Occupational Safety and Health will be included as one of the points in the Key Performance Indicator of the company. The PTM as a subsidiary of one of oil company in developing country also considering that maintaining occupational safety and health properly is the main thing. As one of the upstream businesses in the field of oil and gas consisting of exploration and production, work operations at PTM have a high level of accident and occupational health risk. Mainly in drilling and well intervention operation. The company's vision and mission are then carried out with a Safety Management System and use a safety slogan as the objective of the organization. The embodiment of this slogan is through safety programs which was implemented in drilling rigs and well intervention barges with purpose to create free accident on working environment for PTM workers and their contractors. The transfer of management of the operational Block from previous operator to PTM in 2018 also affected the culture of occupational safety and health in the work area, especially in the field. Based on these conditions, this research was conducted to find out whether the safety culture practiced by PTM employees in the Drilling and Well Intervention division in the field is good enough. And to find out whether the safety slogans and safety programs that were carried out in part at the previous operator had an influence on the existing safety culture. The research method uses quantitative methods with research instruments in the form of questionnaires using a Likert scale. The population in this study were permanent and contractor employees who worked on drilling rigs and well intervention barges. The results showed that in general, the Company has a safety slogan and safety program that influences the safety culture implemented by employees. However, there is still a need to transform and improve the safety program in PHM in general and in the implementation of Drilling and Intervention.
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Shavranskii, M. V., V. I. Sheketa, and V. M. Shavranskii. "An intellectual system for supporting decision making in the control of the borring process." METHODS AND DEVICES OF QUALITY CONTROL, no. 1(44) (June 28, 2020): 119–37. http://dx.doi.org/10.31471/1993-9981-2020-1(44)-119-137.
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The problem of development of the method of identification of complications arising in the process of drilling of oil and gas wells, which operates under the conditions of a priori and current uncertainty under the influence of various perturbations based on methods of fuzzy set theory and fuzzy logic, is considered. A methodological approach to the estimation of the level of complications in the drilling of oil and gas wells, based on the principles of linguistic parameters of the drilling process, linguistic and hierarchical knowledge about the complications in the drilling of wells is proposed. Mathematical models of a controlled object have been developed that, unlike deterministic mathematical models, allow to describe in natural language the cause and effect relationships between the parameters of the drilling process and the possible complication. These models reflect the logic of the operator's reasoning with the involvement of non-numerical and fuzzy information from an expert to formalize Fuzzy Logic decision-making procedures using the parameters and indicators of the oil and gas drilling process. The structure of the decision support system for controlling the drilling of wells in the conditions of complications is proposed. The results of simulation modeling of the developed methods of modeling of complications based on the methods of fuzzy set theory and fuzzy logic are presented. Their advantages over the well-known in accuracy of the tasks of identification of an estimation and control in the conditions of uncertainty concerning structure and parameters of object are shown. The real complications have been identified, the elimination of which will increase the level of safety of the drilling process. It is shown that the developed methods and models can find application for modeling and identification of a wide class of complications on drilling rigs operating under the conditions of a priori and current uncertainty regarding their structure, parameters and geographic environment.
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Al-Jubair, Haider Saad, and Hiba Abdul Hussein Saheb. "Finite Element Analysis of Well Pads in Basra Province." Wasit Journal of Engineering Sciences 7, no. 1 (April 15, 2019): 73–86. http://dx.doi.org/10.31185/ejuow.vol7.iss1.116.
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After the year 2003, the oil / gas sector evolved and gained investment. International companies of different origins utilized heavy drilling rigs (to achieve high drilling depths) and entered our region. Meanwhile, some drilling problems were recorded, accompanied by well-pad failure cases. This research aims to study the behavior of well-pads with different geometric configurations, under the effects of drilling rigs with various characteristics, within the Basra province. Four case studies have been selected to represent four fields, namely: Siba, Zubair, West Qurna-2, and Zubair-Mishrif fields. The finite element method is utilized to conduct a stress analysis process, adopting an elastic–plastic constitutive relation for soil, based on Drucker-Prager's yield criterion. The maximum contact pressure applied on soil (under the working loads) is compared to its bearing capacity. When a rigid method is used to calculate the contact pressure, it is compared with the ultimate soil-bearing capacity, as calculated by Reddy and Srinivasan's method for cohesive soils, with allowable bearing capacity taken from the Peck, Hanson, and Thornburn's method for cohesionless soils. The contact pressure calculated via the finite element method is compared with the ultimate soil-bearing capacity calculated using the same method, based on a settlement of 50 mm. The extreme values of the bending moments and shear forces developed in the well-pad sections (under the factored loads), are compared with the section capacities calculated by using the ultimate strength design method. Regarding the geotechnical side, the results indicate insufficient safety factors against soil shear failure for some cases, especially for cohesive soil profiles. For cohesionless soil profiles, the provided safety factors are sufficient. The finite element method reveals higher contact pressures compared to the conventional rigid method. For cohesionless soil profiles, the Peck, Hanson, and Thornburn's method, gives a bigger safety margin than the finite element method. The immediate settlement values are almost tolerable. Regarding the structural side, it has been identified that a uniform section is adopted for all locations of each pad, for individual wells. In most cases, the provided reinforcing steel is less than the minimum code requirement. This leads to a violation of the section capacity of bending, at least near the cellar. The beam shear capacity is rarely violated. Using strip footings beneath the rig skids, permits utilizing a heavy section that satisfies the requirements of structural safety, without violating the economic considerations.
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Alexey, Neroslov. "The Method of Cluster Drilling in the Western Ural as the Beginning of the Technical and Economic Revolution in the World Drilling." TECHNOLOGOS, no. 3 (2020): 47–57. http://dx.doi.org/10.15593/perm.kipf/2020.3.03.
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In 1943, at the height of the Great Patriotic War, the new revolutionary drilling technique with high efficiency was used in Krasnokamsk oilfield of Molotov (Perm) Oblast for the first time in the world – the cluster turbodrilling method. The development of oil industry in Prikamye in the 1940s was associated with certain complications. The main deposits of the Krasnokasmk oilfield discovered before the war turned out to be located due to a number of reasons within the area of industrial and residential construction of the city of Krasnokamsk and under the Kama river and the Paltinskoye swamp close to the city. Conventional drilling methods could not be used for their development. The way out was to use the method of directional drilling that was little known at that moment. The development of the innovative technology in Krasnokamsk oilfield in 1942 was largely due to the involvement of the specialists of the Experimental Turbodrilling Bureau evacuated from Baku. Directional drilling which involved the deviation of the bottom hole (the ultimate lowest point of the well) from the wellhead (the initial uppermost location) by several hundred metres opened up broad opportunities for developing hard-to-recover oil deposits while significantly accelerating and ensuring cost savings of the drilling process. The directional drilling served as the basis for the development in Prikamye of an advanced technology of cluster drilling when several directional wells with different azimuths were drilled from a small well pad. In 1943–1944, cluster drilling was tested and successfully used in Krasnokamsk oilfield. The cluster drilling comprised an entire range of innovative solutions including the movement of assembled drilling rigs without dismantling power equipment. Also, it resulted in the reduction of total labour costs, scope of construction and assembly works, costs of building oilfield roads, power lines and pipelines, and transportation costs. People’s Commissariat of Oil Industry of the USSR initiated a large-scale rollout of the advanced method of cluster drilling in the largest oil-producing regions of the Soviet Union – Azerbaijan and the North Caucasus, and the area of the “second Baku” – Bashkiria, Tatary, and Kuybyshev oblast. The transition to the advanced and cost-saving technology of cluster drilling laid the foundation for the technical and economic revolution of the world drilling practices.
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Korzhov, A. V., Yu I. Khokhlov, M. A. Grigorev, D. Yu Khryukin, and V. A. Kushnarev. "IMPROVING POWER AND RELIABILITY OF MULTILEVEL FREQUENCY CONVERTERS FOR DRILLING RIGS." Bulletin of the South Ural State University series "Power Engineering" 21, no. 4 (2021): 94–101. http://dx.doi.org/10.14529/power210411.
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Modern electric drives used in the oil and gas sector are made based on two-level power circuits for volta¬ges up to 1 kV and have a modular cabinet design. The paper presents improvements based on the op-timization of the number of modular frequency converters aimed at insuring smooth operation of critical oil and gas applications. Using the method of numerical analysis, the criteria for optimizing the number of phases of the power circuits of the converter in terms of cost, electrical losses and reliability were derived, based on the data on the cost of two-level frequency converters. An economic justification for reducing capital and operating costs when using multilevel frequency converters is given. It is revealed that the proposed optimization methods allow reducing electrical losses due to the reduction of overvoltages on the electromechanical con-verter, as well those in the DC link. The reliability increase is determined by the operability of the electro-mechanical converter in the event of a failure of one of its phase winding, taking into account the decrease in the installed power. The results of the introduction of multilevel frequency converters “MOMENTUM” of the MT-1000/MT-2000 series of the Scientific and Technical Center “Privodnaya Tekhnika” LLC are presented.
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Andriishyn, N. M. "The Conceptual Principles of Improving the Management of the Gas Production Complex of Ukraine on the Bases of the Experience of Leading Oil and Gas Companies." Business Inform 12, no. 515 (2020): 165–72. http://dx.doi.org/10.32983/2222-4459-2020-12-165-172.
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The main directions of improvement of the gas production complex management and the role of individual factors affecting the efficiency of its activities are determined. Taking into account that the oil and gas complex is a system of enterprises and organizations for various functional purposes, united to meet the needs of consumers in provision of natural gas, on the example of improving the organizational structure and management system of NK «YUKOS», all stages of its transformation into a world–class oil company are considered. Recommendations on the use of positive experience in Ukraine are provided. It is shown what achievements of NK «YUKOS» have already been taken into account in the reform of the management system of JSC «Ukrgasvydobuvannya», – in particular, today it is conditionally represented by three large sectors: upstream, midstream and downstream. The upstream sector includes the search for potential underground or underwater natural gas fields, drilling of exploration wells, drilling and operation of the wells extracting unprocessed natural «wet» gas; the midstream sector provides transportation (pipelines, railways, barges, oil trucks or regular trucks), storage and wholesale of gas, while networks of natural gas pipelines aggregate gas from natural gas purification stations and deliver it to consumers – local utilities; the downstream sector usually refers to the processing and purification of natural gas, crude oil, as well as the sale and distribution of products derived from natural gas and crude oil. Distribution by sector in gas production allows to classify fixed assets in accordance with the above–mentioned sectors: drilling rigs, offshore drilling platforms, well repair machines, software for geological exploration and geophysical research – upstream; well plumes, inter–industrial gas pipelines, condensate pipelines, oil pipelines, booster compressor stations, equipment for the complex gas preparation – midstream; gas processing and oil refineries, petrol stations – downstream. Much attention is paid to the development of the intellectual potential of the gas production complex, as it ensures both the successful development of production and the formation of effective management of the company.
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Thatcher, M., and D. B. Marietta. "SUBSEA PRODUCTION FOR WELLS DRILLED FROM JACKUP DRILLING UNITS." APPEA Journal 27, no. 1 (1987): 357. http://dx.doi.org/10.1071/aj86030.
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Subsea production systems have been an accepted method of developing offshore oil and gas fields since the installation of the first subsea trees in the early 1960s offshore California. Generally subsea completions have been done from floating drilling vessels on wells with subsea wellhead equipment. A number of wells have been completed subsea by bottom supported jackup rigs on wells drilled using mudline suspension equipment. The subsea completion equipment and methods utilised to adapt mudline suspension wells for a subsea production tree are described. This method of completion offers important benefits as it allows completion of wildcat or delineation wells, it can be used in areas of small, scattered reservoirs, and it can be used in conjunction with floating production systems. The cost associated with these subsea completions is roughly equivalent to those of standard subsea completions from floating vessels. An overview of a typical completion system is presented and compared.
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Hadid, Dr Mahmoud M., and Ahmed A. Mohammed. "Optimal Choice of Travelling System Structure depending on Design Parameters of Hoisting System in Drilling Units of Oil and Gas Wells." Journal of Petroleum Research and Studies 12, no. 1 (March 20, 2022): 121–36. http://dx.doi.org/10.52716/jprs.v12i1.594.
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Most drilling rigs are designed based on the max static load on the hook of great travelling system structure as 6×7. But when change the depth of the well, the load on the hook changes, so it was necessary to determine the travelling system structure, which ensures the best design indicators of hoisting system.
This research studied the impact of travelling system structure on design parameters of hoisting system and the best indicators of hoisting systems at less drilling lines number suitable with max allowable load on hook for oil and gas wells drilling units.
In this work, A methodology depending on graphical solution for hoisting system indicators curves has been developed. (MATLAB) has been used in order to develop a program that facilitates the application of this methodology and accelerate the work. The most important technical parameters for different drilling unit, in addition to the allowable hookload, by using the most important design indicators that positively or negatively affecting the system with changing travelling system structure. This program depending on graphical solution for set of these indicators in relation with number of drilling lines by finding equilibrium point between positive and negative effects that has the algebraic sum of the slopes is as close as possible to zero. This point represent optimal drilling lines compatible with hookload at practical technical parameters for drilling units.
This study achieves the best indicators for hoisting system working at ideal travelling system and decrease the time required for drilling by increasing hook velocity rate by 12% and the efficiency of hoisting system by 10%. In addition, the lengths of drilling line rate decreased by 40% that cause reduction in material cost and achieving better economic feasibility in comparison with design travelling system.
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Liakh, Mykhailo, Teodoziia Yatsyshyn, Svitlana Gavryliv, Yuriy Gavryliv, Lesia Shkitsa, Katarina Monkova, Peter Pavol Monka, and Vasyl-Danylo Liakh. "Environmentally-efficient approaches to oil and gas producing sites." E3S Web of Conferences 280 (2021): 09002. http://dx.doi.org/10.1051/e3sconf/202128009002.
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We have offered the investigations aimed at the design of eco-efficient technologies during oil and gas producing sites life cycle. The authors have conducted the analysis of conditions causing environmentally hazardous situations at oil and gas producing sites. We have established the necessity of quick maintenance of operation during emergencies that makes it possible to reduce material costs and environmental pollution. The increase of environmental safety in the process of winding up oil and gas wells emergencies that took place as a result of catching drilling string or some other pipe is crucial. We have analyzed different ways and various structural designs of the devices for pipe unscrewing from caught strings. We have established the ways of negative environmental impact reduction in the winding up emergencies at operating as well at stack oil and gas rigs. The recommendations regarding the structural design of the device are given. The device design is patented and the prototype model of the device is designed and manufactured. The device functions as the transformer of clockwise drilling string rotation into anticlockwise rotation of fishing tools. We have highlighted the positive effects after the implementation of the given device. We have noted the importance of innovative technologies design as well as the importance of forming adequate response skills during emergencies when wellsites are being constructed. The technical solutions and recommendations we have introduced make it possible to prevent negative environmental impact and reduce resource flows at different stages of wellsite life cycle.
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Chastko, Paul A. (Paul Anthony). "Roughnecks, Rock Bits and Rigs: The Evolution of Oil Well Drilling Technology in Alberta, 1883–1970 (review)." Canadian Historical Review 88, no. 4 (2007): 652–53. http://dx.doi.org/10.1353/can.2008.0001.
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Cravens, Daniel. "US experiences in water management of shale gas developments." APPEA Journal 54, no. 2 (2014): 541. http://dx.doi.org/10.1071/aj13114.
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More than 1,700 drilling rigs are operating in the US, with more than half in Texas. The avid and dry Permian Basin in southwest Texas is one of the most prolific oil and gas basins in the US. Vertical drilling to depths of 4,000 m, with horizontal laterals 2,000 m, is common. The fraccing of a horizontal well requires large amounts of water. In areas that completely depend on groundwater for frac water, the demand for the resource is high. Water transport and treatment costs can threaten the viability of even the best of projects. The volume of water required for different horizontal frac operations, changes depending on the formation, frac solutions, and lateral frac distances. Discoveries are being made that have determined that larger diameter horizontal fracs are yielding more product, but they require even more water. The oil and gas industry is beginning to realise that groundwater drilling and resource management can make or break an oil and gas project. In these areas where water availability depends initially on groundwater supply, a complete understanding of the available groundwater resource is critical. Economically viable solutions can ultimately be a combination of new wells, treated water, moveable water distribution systems, mobile treatment plants, surface storage, and deep injection of brine fluids. In this extended abstract, the experiences gained on existing shale gas developments in the US are used to address specific challenges faced in Australia.
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Wright, D. J., and S. R. le Poidevin. "DEVELOPMENT OPTIONS FOR OFFSHORE OIL AND GAS FIELDS: IMPLICATIONS FOR OPTIMUM LONG-TERM RECOVERY." APPEA Journal 32, no. 1 (1992): 391. http://dx.doi.org/10.1071/aj91030.
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Technology used in the Australian offshore oil and gas industry in recent years has diversified with the introduction of innovative concepts for field developments. These innovations are aimed at cost reduction and greater access to reserves, especially those in small and remote fields. Further innovations are anticipated as research progresses in several areas of potential cost reduction. Changes in technology can dramatically affect the relative economics of data acquisition, contingency planning and the extent of field development. Drilling and workover economics, well servicing, reservoir surveillance and the opportunities for infrastructure development are strongly dependent on the choice of development technology. These choices, in turn, have implications for long-term recovery, including the discovery and development of new pools and extensions to known pools, overall field recovery factors, the opportunities for development of gas caps and nearby fields, and the future potential for enhanced oil recovery (EOR).Government involvement in development approvals in various countries has diverse objectives. The Australian Petroleum (Submerged Lands) Act specifies as one objective the optimum long-term recovery of petroleum. Critical areas of interest are pre-development planning with necessarily incomplete information, the phenomenon of unexpected reserves growth, and provision for contingencies such as well failures. Early drilling and completion decisions and infrastructure planning have major effects on future developments. Subjects of direct relevance for future improvements in development economics include reductions in pipeline construction costs, reductions in the cost of drilling from mobile rigs and flexibility in completion design.
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Feder, Judy. "Implementation of an Intelligent Drilling Automation System in the Middle East." Journal of Petroleum Technology 73, no. 02 (February 1, 2021): 45–46. http://dx.doi.org/10.2118/0221-0045-jpt.
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This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 203251, “Drilling in the Digital Age: Harnessing Intelligent Automation To Deliver Superior Well-Construction Performance in a Major Middle Eastern Gas Field,” by Brennan Goodkey, Gerardo Hernandez, and Andres Nunez, Schlumberger, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. While breakthroughs in digital technology have rewarded many industries with a step change in productivity and efficiency during the past decade, the drilling industry has yet to benefit on a large scale from these advances. The complete paper details the introduction of a drilling automation system (DAS) to deliver superior well-construction performance in a major gas field in the Middle East. The DAS was deployed on two onshore gas drilling rigs. The paper discusses the technology itself, the deployment process, implementation challenges, the agile development model, and the results achieved. Introduction In 2018, Schlumberger partnered with a major Middle Eastern national oil company on one of the world’s largest lump-sum, turnkey gas-well-delivery projects, where drilling operations had already been optimized by targeting high-impact, low-effort areas of opportunity. Drilling automation was pursued to achieve an improvement in performance, specifically to shift the technical limit and to minimize the frequency of service incidents that could cost days of nonproductive time (NPT). An in-house solution under development for some time was designed to take control of the rig’s surface equipment to automate and optimize most drilling tasks and to generate value in the following areas: Automation of drilling actions to perform exactly as planned, within the safe limits of operation, by eliminating the inconsistency of manual operation and its susceptibility to human factors Identification and mitigation of drilling dysfunctions that could lead to costly tool failures and incidents by using intelligence engines that would adapt drilling parameters continuously for best performance Technology Overview The DAS was developed as the execution component of a well-construction platform designed to link planning and execution. The planning component allowed for all well-design stakeholders to collaborate online and create the well plan simultaneously. Once prepared, the plan would be exported to the rig as a machine-interpretable digital drilling plan that the DAS could digest. With the validation of rig personnel, the DAS would then take control of a selection of drilling actions and execute exactly as instructed in the well plan. While drilling, extensive information would be collected to serve as a vehicle to drive performance when planning future wells. In the deployment summarized in the complete paper, a pilot version of the drilling automation module was deployed as a standalone product. The key objectives of design included three categories - dynamic planning, safety and resilience, and interoperability.
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Philo, Ross, and Jay Hollingsworth. "Reducing rig personnel requirements with standards-based real-time data streaming." APPEA Journal 58, no. 2 (2018): 736. http://dx.doi.org/10.1071/aj17110.
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Cost reductions have become an essential response to lower oil and gas prices. Drilling rigs operate in distant and sometimes hostile environments, so relocating rig-based experts to remote control centres saves costs and improves health, safety and environment (HSE). Key staff can work in an improved environment and movements to-and-from the rig are fewer, lowering transport-related costs and risks. The offsite experts can apply their expertise to the operations of multiple drilling rigs from a single location. To make this a reality, data from thousands of sensors on the rig and from measurement devices such as logging while drilling must be fed to the control room instantaneously and continuously. Legacy systems that poll rig-based devices for new data consume significant bandwidth and deliver data in a discontinuous manner with delays of 15 s or more. This does not meet the criteria for safe and reliable remote control of a rig and has been the reason why many roles have remained rig-based. This paper describes a new set of protocols that establish a continuous stream of data from devices on the rig to the control room with sub-second lag time. The new protocol also uses an order of magnitude less bandwidth, thus allowing more data to be carried in less time. Associated with industry-standard well-site information transfer standard mark-up language data transfer formats, the process operates with numerous service providers and software systems transparently. This paper includes a case-study to which the new protocol is applied, resulting in fewer permanent staff on a North Sea rig and fewer visits by an intervention contractor to the rig, with clear cost savings and HSE risk mitigation.
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Aliyeva, Sevda, Javida Damirova, and Sevinc Abasova. "Research of the problem of optimization and development of a calculation method for two-stage chain drives used in heavy industrial vehicles in conditions of economic efficiency." EUREKA: Physics and Engineering, no. 4 (July 23, 2021): 105–12. http://dx.doi.org/10.21303/2461-4262.2021.001930.
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The article is dedicated to the problem of optimization of chain drives of the drilling unit. At present, increasing the power per machine to the optimal limits, reducing the material and energy consumption per unit capacity of the machine, as well as operating costs are considered topical issues. The machines that are designed and constructed to optimal limits must be very powerful and productive. The machines that are applied to perform drilling works in the oil and gas industry must be easy to operate, reliable and have ability to operate for a long time. When constructing such machines, their being lightweight, economical, as well as their preparation in a short time and at low cost should be taken into account in advance. In order to ensure the reliable operation of drilling rigs, it is more expedient to apply chain drive in their mechanical transmission. First of all, the application of chain drive in drilling units and hoisting mechanisms is considered. Then a calculation method was developed for the chain drives of the drilling unit used in deep exploration wells and the exploitation of wells, and, accordingly, the calculation of the chain drive was carried out. The chain drive consists of drive and driven sprockets and a chain that encompasses the sprockets and engages in their teeth. Chain drives with several driven sprockets are also used. In addition to the basic listed elements, chain drives include tensioners, lubricating device and guards. The chain consists of hinged links that provide mobility or “flexibility” of the chain. Chain drives can be performed in a wide range of parameters. The calculation took into account the quality of the material, the service life and durability of the chain drive construction
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Kern, J. G. C., G. P. Montagna, and M. F. Borges. "TECHNIQUES FOR DETERMINING SIZE AND SHAPE OF DRILL CUTTINGS." Brazilian Journal of Petroleum and Gas 16, no. 2 (June 28, 2022): 65–77. http://dx.doi.org/10.5419/bjpg2022-0006.
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In the oil and gas industry, the presence of cuttings during the well drilling stage creates a concerning problem known as erosion. The risks of catastrophic failure caused by erosion in hydraulic systems become even greater (e.g., choke line and MPD) when observing control and safety wells on drilling rigs. The geometric characteristics of the particles are important physical attributes, as they influence the wear mechanisms of the materials directly. Therefore, this work presents an analysis of the methodology used for determining the size and shape of particles. Initially, the collection of samples was obtained by Chute Riffling technique. The samples were tested using vibrating sieves for particle size analysis. The study uses computerized image analysis to determine the particle size distribution, as well as shape parameters. The application of both techniques demonstrates that the image analysis results were very similar to the sieving, even when a much smaller sub-sample is under analysis. The granulometric analysis of the diameter of the drill cuttings by the method of vibratory sieving showed a range of size ranging from 0.10 mm to 3.35 mm, and, by the image analysis, it showed a range of size going from 0.11mm to 4.2mm. The shape parameters of the majority of drill cuttings analyzed in the present work was classified as “high circularity” and “well-rounded.”
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Rassenfoss, Stephen. "Drilling Automation - A Robot Takes Over the Drilling Floor." Journal of Petroleum Technology 73, no. 12 (December 1, 2021): 18–22. http://dx.doi.org/10.2118/1221-0018-jpt.
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The work on the drilling floor of the PaceR801 rig revolves around a stout robot methodically picking up sections of pipe and moving them precisely over the drilling center to rapidly connect the pipe. While it is one of many technological advances on the rig Nabors bills as “the world’s first fully automated land rig,” the robot is the one “that gets most people interested and excited,” said Travis Purvis, senior vice president, global operations for Nabors Industries Ltd. As of 18 October, the PaceR801 had completed the first well on an ExxonMobil pad and was drilling the lateral on the second well of the three-well pad. After the third is done, the extended test will move to the next pad. It is risky to announce who came in first in a competitive race in a secretive business. But Nabors stands out because the PaceR801 has an automated drilling floor, a range of other automated functions above and below ground, and most significantly, it is the only one using its rig to drill producing wells for a customer. Jason Gahr, operations manager for unconventional drilling at ExxonMobil, said the research collaboration “demonstrates the ability to optimize drilling using the combined power of robotics, automation, computing, and data.” Since the announcement, Nabors has heard from other oil companies. “There is strong interest in the rig in many markets,” Purvis said. The companies’ interests range from automating more drilling functions by retrofitting rigs, to wanting to hire the rig, whose name is frequently shortened in conversations to R801. There is only one PaceR801 and it is going to be tied up for a while. “We expect to drill multiple test wells on multiple pads and continue to work on the technology” with ExxonMobil, Purvis said. It was created to show off the fruits of a 5-year drive to create a totally automated version of its Pace high- specification rig. Nabors likens it to the concept cars built by automakers to show off their vision of the future and to promote innovation within the company. In this case, it is a vision of the near future. While the automated drilling floor is new, much of the rest is recently proven technology. Two of the drilling automation programs used—Nabors’ SmartSLIDE and SmartNAV—are already on 30% of the Nabors fleet, said Austin Groover, director of operations for smart products at Nabors. Those applications, which manage drilling of the curve and directional drilling, plus a third that automates drilling a stand of pipe, SmartDRILL, have been used by ExxonMobil for 2 years. Maximizing the performance of a rig with multiple proven technologies plus a new one such as a robotic drilling floor required developing a system that coordinates the movements of those apps and the rig hardware while drilling. When Nabors experts describe that process, they rely on musical metaphors, from the robot doing its little dance to a conductor leading a symphony.
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Jacobs, Trent. "Shallow Water: The Next Frontier for Deepwater Rigs, or Just a Passing Fad?" Journal of Petroleum Technology 74, no. 07 (July 1, 2022): 22–27. http://dx.doi.org/10.2118/0722-0022-jpt.
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Petrobras, one of the world’s top offshore operators, has shared new information about how it used an ultradeepwater rig in a place where it was never intended to work—in shallow water. What makes its recent subsea campaign novel is that the Brazilian national oil company avoided mooring the rig and instead relied on dynamic positioning (DP). Two key pieces of technology made this possible. The first is called a blowout preventer (BOP)-tethering system which sits on the seabed and absorbs much of the load being placed onto the wellhead structure. The second is a digital twin software that determines the safety of the rig’s position during drilling. Petrobras is not the first to accomplish such a feat in depths less than 2,000 ft. But it is among the few to recount its learnings in multiple technical papers as it did at the recent Offshore Technology Conference (OTC) in Houston. The fresh insights surrounding the Petrobras projects stem from an initial well drilled and completed 2 years ago with a sixth-generation drillship, the Norbe VIII, owned by Brazilian contractor Ocyan. The new well is in the Albacora field within the Campos Basin and was the first of several planned to be drilled or plugged and abandoned by Petrobras in DP-only mode. Over a 16-day period in May 2020, the Norbe VIII worked in water depths of about 1,475 ft where it successfully tapped into a pre-salt oil reservoir with a total depth of more than 16,000 ft. For both firms, the project in the Campos Basin marked a first. Never before had they used a rig in DP-only mode at such shallow depths, which amounted to about 15% of the rig’s maximum depth rating. Following the first well, Petrobras drilled at least one more in June 2021 in DP-only mode. Notably, Petrobras was in the midst of selling off the Albacora field during its experimentation with DP-only shallow-water drilling. The mature asset was discovered by the state-run operator in 1984 about 75 miles from the coast and has been producing from post-salt reservoirs for the past 35 years. But earlier this year, the company said it was hoping to fetch a higher price based on better-than-expected reservoir tests from the deeper pre-salt target it drilled in May 2020.
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Ouyang, Dan, Xiaotian Lei, and Honglei Zheng. "Recent Advances in Biomass-Based Materials for Oil Spill Cleanup." Nanomaterials 13, no. 3 (February 3, 2023): 620. http://dx.doi.org/10.3390/nano13030620.
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Oil spill on sea surfaces, which mainly produced by the oil leakage accident happened on tankers, offshore platforms, drilling rigs and wells, has bring irreversible damage to marine environments and ecosystems. Among various spill oil handling methods, using sorbents to absorb and recover spill oils is a perspective method because they are cost-effective and enable a high recovery and without secondary pollution to the ecosystem. Currently, sorbents based on biomass materials have aroused extensively attention thanks to their features of inexpensive, abundant, biodegradable, and sustainable. Herein, we comprehensively review the state-of-the-art development of biomass-based sorbents for spill oil cleanup in the recent five years. After briefly introducing the background, the basic theory and material characteristics for the separation of oil from water and the adsorption of oils is also presented. Various modification methods for biomass materials are summarized in section three. Section four discusses the recent progress of biomass as oil sorbents for oil spill cleanup, in which the emphasis is placed on the oil sorption capacity and the separation efficiency. Finally, the challenge and future development directions is outlined.
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Jacobs, Trent. "Robo-Labs, Mysterious Bakken Scale, and New Nano-Detectors All Highlight the Innovative Thinking in Oilfield Chemistry." Journal of Petroleum Technology 74, no. 02 (February 1, 2022): 24–31. http://dx.doi.org/10.2118/0222-0024-jpt.
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When you think about robots in the oil and gas industry today, the first images that might come to mind are drones, automated drilling rigs, or maybe a robotic inspection dog called Spot. Next time, you may think about robots that toil around the clock to create a chemical package destined for an oil well or pipeline. That’s not the future but the new reality inside the laboratories at Clariant Oil Services in The Woodlands, Texas. The recent adoption of lab robotics was the focus of one of the published technical papers from the 2021 International Conference on Oilfield Chemistry held in November in the Houston area. Two other papers presented at the conference also helped highlight the innovative thinking that is shaping the industry’s chemical sector. Authors from ChampionX and Hess Corp. shared their apparently successful attempt to unravel a “mysterious case of severe Bakken brine incompatibility.” The problem addressed in their paper was severe enough to force hundreds of Bakken wells to temporarily shut in over the past 3 years. Another paper from Baker Hughes addressed the more widely shared problem of knowing when to add production chemicals to a well and the quantity of those chemicals. The common thread between each of these new papers is that they address some aspect of the industry’s complications with corrosion inhibitors.
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Rassenfoss, Stephen. "Drilling Automation - Drilling Automation: Are We There Yet?" Journal of Petroleum Technology 73, no. 12 (December 1, 2021): 25–26. http://dx.doi.org/10.2118/1221-0025-jpt.
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Predictions about how technology will evolve a decade from now are likely to be wrong. In 2012, a group of 120 drilling and automation experts at an SPE workshop in Vail, Colorado, wrote a statement predicting what automated drilling would look like in 2025. After working through the issues over 3 days in groups, they agreed on a short statement that offers a useful yardstick for how far the industry has progressed in the 9 years since. Drilling automation is a dream that is just beginning to be realized. Since 2012, it has progressed further than many people thought possible back then. The workshop participants, 30% of whom were from outside the oil industry—including the operator for the Mars Rover that was then on its journey to the planet—spent a weekend arguing about the future and crafted a vision statement summarizing what drilling will look like in 2025. At the time, the statement seemed like a pipe dream to a lot of folks, said John de Wardt, who co-chaired the workshop. Since then he has tracked how drilling automation has evolved as the person in charge of the Drilling Automation Roadmap, an effort backed by the SPE Drilling Systems Automation Technical Section (DSATS) that lays out what needs to be done to make automation a reality and pro-vides information about the work already done. Based on what he has been seeing lately, he thinks the predictions by the people at the workshop are looking good. “In another 4 years, I am beginning to believe this thing” will look pretty accurate. He is also aware there are those who contend the skeptics got it right. Those conflicting views will likely come up at a presentation about the vision statement which is on the agenda of the seminar DSATS will hold before the 2022 IADC/SPE International Drilling Conference in March in Galveston, Texas. “That should be an interesting debate, as some have told me it is coming true and others push back in absolute terms,” de Wardt said. Sentence by Sentence Right or wrong, the statement offers a workable checklist for what must be done for drilling automation to become a reality. A close reading of the statement reveals a huge amount of change packed in every sentence. By 2025 DSATS predicted rigs for which “well plans are uploaded into an interoperable drilling system that automatically delivers a quality wellbore into the best geological location.” So far, automation’s impact is more focused. There is growing use of programs that directly control certain critical functions such as directional drilling or tripping. More functions are being added over time, informed by increasing amounts of digital data analysis. The next step is difficult: integrating all the automated functions to ensure maximum performance. The performance of a highly automated rig, such as the Nabors PaceR801, is based on how well it coordinates a complex sequence of steps.
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Slesarev, D. A., O. P. Potekhin, I. I. Shpakov, V. Yu Volokhovsky, and A. N. Vorontsov. "MONITORING OF TECHNICAL CONDITION OF THE WIRE ROPES OF DRILLING RIGS FOR PRODUCTION AND EXPLORATORY DRILLING OF OIL AND GAS WELLS: TECHNOLOGY, EFFICIENCY, PROSPECTS." Occupational Safety in Industry, no. 6 (June 2018): 13–22. http://dx.doi.org/10.24000/0409-2961-2018-6-13-22.
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Aliyeva, Sevda, and Mahmud Ismayilov. "RESEARCH OF THE WAVE FACTOR INFLUENCING HYDRAULIC STRUCTURES." ETM - Equipment, Technologies, Materials 05, no. 01 (January 20, 2021): 81. http://dx.doi.org/10.36962/etm0501202081.
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It is known that a large block of deep-sea foundations consists of a truss sheathed with wood, a metal beam system, floating structures and four pyramidal metal blocks with a truss structure. The design characteristics of the foundations of oil platforms depend on the conditions under which the vertical interaction, along with the calculation of permanent and temporary loads, is accompanied by the specific gravity of drilling equipment and rigs or horizontal wind pressure, as well as the influence of horizontal wave loads on the foundation blocks. Horizontal waves and wind loads can be constant and variable in different conditions, therefore the effect of each of these loads on the device must be considered separately. To determine the wave pressure acting on the support blocks of stationary offshore installations, SN-92-60 was used under the editorship of the team of authors under the leadership of Doctor of Technical Sciences, Professor N.N.Tsunkov. Keywords: hydraulic structures, wave factor, wave pressure, wave profile, pressure diagrams, 3D model.
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Weatherl, Michael H. "Technology Focus: Drilling Automation and Innovation (February 2021)." Journal of Petroleum Technology 73, no. 02 (February 1, 2021): 44. http://dx.doi.org/10.2118/0221-0044-jpt.
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Drilling automation and innovation continue as dominant trends despite market downturns and unprecedented challenges in the past year. In many ways, the drive toward new efficiencies and step changes in well-construction performance has taken on an even greater sense of urgency. Further advancements in automation and innovation in well construction are recognized globally as keys to unlocking new opportunities in the ever-changing world in which we live. OTC Live sessions in late 2020 included a fascinating session titled “Opportunities and Challenges in Frontier Basins and Emerging Offshore Areas.” Despite pandemic-induced uncertainty, a significant number of high-impact exploration efforts, including projects in deepwater Gulf of Mexico, Brazil, west Africa, the Mediterranean, and Asia were ongoing. Panelists agreed, given world population and energy consumption being forecast to grow 20% by 2040, that increased hydrocarbon supplies, in addition to renewables, are essential to meeting future demand. The discussion also highlighted increased emphasis on carbon footprint reduction. Leaders from Shell, Expro, Wood Mackenzie, and others spoke to a CO2-intensity/barrel of oil equivalent chart comparing relative values for deep water, unconventionals, oil sands, and liquefied natural gas. It is noteworthy that deepwater production represents the lowest carbon footprint of all hydrocarbon sources by a significant margin. This advantage, combined with the potential for large resource size, high flow rates, and low well count, suggest that deepwater assets will compete in long-term portfolios for many operators. Referring to the current selection of SPE drilling-related manuscripts, automation of land rigs within onshore unconventional basins remains a widely published subject. More specifically, automation of the directional drilling process continues to yield improvements in performance and efficiency. It is often noted that well costs have been reduced by more than 50% with advancements related to horizontal technology, digitalization of well construction, and rig automation. These technologies were largely initiated within onshore, unconventional projects, but application is now wide-spread for offshore, complex wells. Selected papers in this feature are chosen to highlight the latest achievements and near-term opportunities across the full spectrum of upstream projects. A consistent message from paper SPE 203251 regarding drilling automation in the digital age reads, “industry has yet to benefit on a large scale from these advancements and…significant value remains untapped.” This reoccurring theme appears across operator and geographical boundaries, revealing significant opportunity and the need for ongoing emphasis. Software and hardware evolution progresses along with more- comprehensive integration of rig equipment and functionality. Industry now is more focused on moving from automation of individual tasks toward automation of the full well-construction process from plan to completed borehole. This idea is presented in paper SPE 201763. Change management remains a key issue within the process to ensure adequate control, early buy-in from stakeholders, and strong leadership. In summary, impressive examples of ongoing innovation span domestic unconventional plays, remote/international locations, geologically complex thrustbelt fields, and deep water with managed-pressure drilling in narrow pore pressure/fracture gradient environments. The few selections that appear here are a reflection of many more published by SPE in the past year and are a powerful testament to the ingenuity and perseverance of those involved.
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Aliev, T. A., N. F. Musaeva, and B. I. Gazizade. "Technologies for Monitoring the Dynamics of Damage Development in Drilling Rigs Using High-Order Moments of the Noise." Mekhatronika, Avtomatizatsiya, Upravlenie 21, no. 4 (April 11, 2020): 213–23. http://dx.doi.org/10.17587/mau.21.213-223.
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The paper deals with the development of algorithms for calculating the high-order moments of the noise of noisy signals and their use in the analysis of the technical condition of industrial facilities. It is shown that for monitoring and controlling the onset of an emergency at oil production facilities, random vibration signals are used, which, in addition to the noise caused by external factors at the time of the initiation of the malfunction, also contain additional noise. The characteristics of this noise contain certain information about the technical condition of the drilling rig. Earlier, algorithms were developed for calculating the variance, standard deviation, and density distribution function of the noise that cannot be separated from the noisy signal. In this paper, it is shown that high-order moments of the noise can be used as a diagnostic indicator for determining the presence and degree of damage development in drilling rigs during the latent period of damage initiation. Possible options for calculating the high-order moments of the noise are analyzed. Recursive algorithms are developed for expressing high-order moments of a normally distributed noise through its variance. The possibility of calculating the high-order moments of the noise through the distribution density functions is also shown. A matrix consisting of estimates of the high-order moments of the noise calculated at different instants of time is built. It is shown that at the first stage, it is possible to determine the presence and degree of the damage based on the values of the matrix elements. At the second stage, the intensity of damage development is determined by comparing the values of the noise characteristics at different instants of time. Calculations are performed for all signals coming from the sensors. Training is carried out and, the correspondence is established between the values of the high-order moments and degrees and intensity of damage development. The possibility of using the proposed algorithms and technologies in the system of noise control of the beginning and development dynamics of accidents at drilling rigs is shown. It is noted that even if the estimates of the high-order moments of the sum noisy vibration signals change within a wide range during drilling, their high-order noise moments do not exceed a predetermined value in the absence of a malfunction. In the event of a malfunction, the estimates of the highorder moments of the noise exceed the predetermined threshold level and, as the defect develops, their values also change. If adverse processes are stabilized, the variation of these estimates stops as well. Moreover, depending on the degree and intensity of stabilization of the technical condition of the drilling rig, the change in the estimates of the moments, starting from the highest to the lowest or vice versa, stops one by one. This specific feature of estimates of high-order noise moments of vibration signals allows us to identify the beginning and to control the development dynamics of the latent period of an emergency state of the drilling process.
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Pratt, David L. "Severance vs. Servitude: Understanding the Differences Between Texas and Louisiana Law Regarding Mineral Rights." Texas Wesleyan Law Review 16, no. 1 (October 2009): 71–78. http://dx.doi.org/10.37419/twlr.v16.i1.6.
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Over the past several years, advances in drilling technology and skyrocketing prices for natural gas have led to extraordinary events in the oil and gas exploration industry. At the height of the boom, increased exploration for natural gas in urban areas created opportunities never thought possible before by owners of urban lands-gas rigs began popping up in urban neighborhoods like dandelions in the front yard, natural gas companies began paying unprecedented bonus payments of $30,000 or more per acre, and contractual royalty payments virtually doubled to a now-typical rate of 25%. Of the many beneficiaries of these events, landowners and mineral owners within the Barnett Shale region of Texas are among the most prominent and well-known. Although the natural gas boom has dramatically fallen away since late 2008, there can be no doubt that the market will one day recover. And when it does, a great deal of emphasis will likely be placed on the Haynesville Shale, which spans portions of east Texas, northwestern Louisiana, and southeastern Arkansas. As the development of the Haynesville Shale progresses, and as many of the oil and gas professionals in Texas begin to migrate eastward, it is important for those accustomed to Texas oil and gas law to develop an understanding of Louisiana law as it relates to mineral interests. Indeed, there are critical differences between the laws of Texas and Louisiana that can have a significant impact on identifying who has the capacity to enter into mineral leases, timing the commencement of drilling operations, and classifying those who are entitled to receive financial benefit from production-differences that those involved in the process must be prepared to navigate. This paper is intended to serve as a starting point in that endeavor.
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Demeshko, G., and R. Detsik. "Design and operation peculiarities of platform support vessels (PSVs)." Transactions of the Krylov State Research Centre 1, no. 395 (March 9, 2021): 85–98. http://dx.doi.org/10.24937/2542-2324-2021-1-395-85-98.
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Object and purpose of research. This papers discusses PSVs (or, in RS classification, Supply Vessels): special ships that provide offshore drilling rigs with drilling supplies, fuel, water, provisions, spare parts for equipment, as well as deliver personnel shifts to/from the platform and perform the functions of duty, rescue, fire, and environmental protection vessels. The purpose of the study is to develop a physical model of PSV functioning and give design recommendations for proper de-termination of its characteristics and properties. Materials and methods. Generalization and analysis of PSV design and operation, as well as analysis of Russian and foreign publications about PSV specifics, supported by systematized statistical materials sufficient for design recommendations. Main results. This work summarized the data on PSV properties, characteristics, design and operation requirements, as well as the ways to implement them in terms of hull shape, general arrangement, mission-specific equipment, conceptual type and power plant, suggesting a vision of PSV as design object. Regressive analysis performed by the authors is supported by a wide scope of design materials that summarizes PSV operation experience and development trends, thus preparing the basis for future PSV designs. Conclusion. PSVs are the main link in the offshore oil and gas production. The ships of this type are becoming more and more popular, especially in their multi-purpose variant. This paper makes it possible to formulate design requirements for them, as well as to trace the ways of their implementation. This paper also suggests the methods for determination of PSV dimensions, conceptual type and mission-specific equipment, as well as main design parameters, properties and transportation and operation capabilities.
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Carpenter, Chris. "Optimization With Real-Time Monitoring Results in Enhanced Drilling Performance." Journal of Petroleum Technology 73, no. 12 (December 1, 2021): 51–52. http://dx.doi.org/10.2118/1221-0051-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205152, “Offset Data Analysis and Seamless Execution Through Real-Time Monitoring Results in Step Change in Drilling Performance,” by Anurag Singh Yadav and Muhammad Imran Chohan, Weatherford, prepared for the 2021 SPE Europec featured at the 82nd EAGE Conference and Exhibition, Amsterdam, 18–21 October. The paper has not been peer reviewed. This project drilled horizontal wells with bottomhole assemblies (BHAs) with a topdrive as the primary drive mechanism. The rig in question was struggling to provide not only the required rotational speed but also to deliver consistent necessary torque. The complete paper analyzes how severe rig limitations were overcome through an optimization plan in which the optimal BHA was designed, and drilling practices were customized, for safe and successful execution of wells. Challenge The project involved drilling multiple re-entry wells for oil and gas production. A typical well design in this operation featured a whipstock set in a 9⅝-in. casing, followed by drilling of 8½-in. hole through the whipstock; the well was completed in a production hole of 6 in. The wells were drilled with a rotary steerable tool in the BHA. Most of the rigs used to drill these re-entry wells had limited capacity with respect to rotational speed and torque limits on the topdrives. This topdrive limitation was proving to be a major impediment to achieving optimal drilling performance. Offset Well Analysis To fully comprehend these challenges with topdrive capabilities, offset wells were studied. Typically, weight on bit (WOB) appeared to play a key role in determining behavior of drilling dynamics. WOB typically had to be varied in order to mitigate stick/slip. For example, with elevated levels of WOB (greater than 20,000 lbf), stick/slip levels were always severe, whereas stick/slip levels were lower when WOB was reduced. Furthermore, it was observed that, with variation of stick/slip, not only stick levels were being elevated but also torque behavior was becoming erratic. This analysis revealed that the degree of erratic behavior with regard to torque differed between bits. When comparing a bit with a 47-cutter count of 16-mm size with another bit that was slightly less aggressive with a six-cutter count of 13 mm on the face, the torque behavior did not change in terms of erratic behavior; however, it was possible to drill with higher WOB with the latter. Further analysis revealed that behavior of stick/slip also depended upon type of formation drilled (i.e., whenever a well was drilled through a denser formation, elevated levels of stick/slip were encountered). In addition, one rig had issues with rotational speed from the topdrive. Surface rotation speed was approximately 90–100 rev/min, resulting in severe levels of stick along with high and erratic torque.
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Hegdal, T., R. T. Dixon, and R. Martinsen. "Production Forecasting of an Unstable Compacting Chalk Field Using Uncertainty Analysis." SPE Reservoir Evaluation & Engineering 3, no. 03 (June 1, 2000): 189–96. http://dx.doi.org/10.2118/64296-pa.
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Summary Past years' forecasting performance has demonstrated that single "most likely" (deterministic) prediction of future production, without quantifying the associated uncertainties, is inadequate for management and planning purposes. Based on this an effort was initiated to improve the forecasting methodology and procedures with special emphasis on quantifying the uncertainty in short-term production forecasting (STPF). The Valhall field, offshore Norway, presented special problems for production forecasting because many unusual events affect production, even for STPF. The soft compacting reservoir chalk causes well collapses and chalk influxes and makes drilling difficult. Modeling of reservoir fracturing and therefore well performance is also uncertain. A probabilistic forecasting approach was adopted using a customized spreadsheet and commercially available statistical analysis add ins which allowed deterministic forecasting, partially probabilistic analysis, or fully integrated uncertainty analysis. Uncertainties were characterized by distributions based on historical data where possible. Communication and integration of knowledge were also key success factors since the process required input from several departments and many individuals to ensure that the "company knowledge" was fully reflected. A "common language" to communicate uncertainty and an auditable process to ensure buy in and consistency were also critical. Introduction The Valhall field is a high porosity naturally fractured chalk reservoir located 290 km offshore, in the southwest corner of the Norwegian North Sea. The field was discovered in 1975, with first oil in October 1982. Production drilling is currently ongoing from two drilling rigs, and is expected to result in peak production from Valhall in 2000 from a total of 49 wells. The oil originally in place is approximately 2,350 mm STB, located in two main reservoir layers, the Tor formation and the Hod formation. Due to the weakness of the high porosity chalk and the very low original net stress, the Tor formation exhibits exceptional drive energy through pore collapse and compaction.1–3 The expected field recovery factor under primary depletion is close to 28%. The downside of the compaction drive is movement of the reservoir and overburden by approximately 25 cm/yr at the center of the subsidence bowl, causing wells to deform and ultimately collapse. Furthermore, the soft high porosity chalk is prone to mechanical failure under drawdown, leading to solid influx into the wells. The well failures at Valhall play a dominant role in the overall uncertainty related to STPF, but drilling time and initial rates are also significant contributors to the total uncertainty. The historical production and Enterprise's STPFs, presented in Fig. 1, reflect the difficulty in predicting these uncertainties deterministically. A cyclical trend of over-, then underpredicting, is seen with increased error with increased activity. With the installation of a new wellhead platform in 1996, the Valhall well operation went from one to two drilling rigs, and this increased the uncertainty in the production forecasting. Past years' forecasting performance has demonstrated that single most likely (deterministic) prediction of future production, without quantifying the associated uncertainties, is inadequate for management and planning purposes. Based on this an effort was initiated to improve the forecasting methodology and procedures with special emphasis on quantifying the uncertainty in STPF. Although the model and principles applied to probabilistic forecasting are not sophisticated as such, the integration and management of all elements in the process make the approach relatively complex. A comprehensive understanding of the input data, that is, the elements generating uncertainty, is essential to improve the quality of the production forecast. Objectives The particular production problems experienced at Valhall have made production forecasting very challenging. The random nature of the well failures makes the range of possible outcomes for a given production scenario wider and less predictable than is normally the case. To improve management of the uncertainty, an improvement project was defined with the following objectives:a complete review of the STPF process to identify areas for improvement (tools, communication, roles, and responsibilities, etc.);development of procedures and methodology for STPF;inclusion of statistical methods (i.e., probabilistic model) in order to quantify the uncertainties;a strong focus on the description of the input parameters and distributions;development of a fit for purpose STPF tool with a balance between flexibility and ease of use, and level of detail and complexity.
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Jézéquel, Ronan, Karine Duboscq, Léa Sylvi, Emma Michaud, Lise Millera Ferriz, Enora Roic, Robert Duran, et al. "Assessment of oil weathering and impact in mangrove ecosystem: PRISME Experiment." International Oil Spill Conference Proceedings 2017, no. 1 (May 1, 2017): 634–56. http://dx.doi.org/10.7901/2169-3358-2017.1.634.
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Abstract 2017-410 Mangroves are among the most sensitive marine ecosystems to oil pollution due both to the sensitivity of mangroves species and to the high persistence of hydrocarbons in these environments. Despite their ecological and socio-economic value, the potential effects of an oil spill on French Guiana mangroves remain so far unknown. Yet, there is an increasing transboundary risk of oil spill due to Brazilian offshore oil exploitation (in mid-April 2013, there were 122 offshore drilling rigs in Brazil, including 29 under construction – Brazilian Amapá region located in the French Guiana border area is thought to become an important world oil production area in the coming years). The aim of the PRISME project was to assess the natural degradation of oil in mangrove sediment as well as its impact on benthic communities (micro, meio and macrobenthos): a one-month in situ experiment was conducted in the young French Guianese mangrove (around 3 years old) at the mouth of the Sinnamary estuary. The experimental units consisted in eight plastic cores (Ø : 10 cm ; height: 30 cm) manually introduced within sediments. A thin layer of oiled sediment (2 cm, 20 000 ppm) was applied on four cores while the remaining four cores were considered as control (no oil addition). Three cores were additionally sampled at the beginning of the experiment as initial control sediments. After one month in situ, the eight cores were collected and sliced on site into different sedimentary layers aliquots for later analyses (hydrocarbons, bacterial, meio, macrofauna fauna diversity, bioturbation, biogeochemical parameters). Samples were sent to the different laboratories involved in this multidisciplinary project. Results and knowledge gained from this experimental work were used to develop an approach for assessing coastal vulnerability for oil spills preparedness in mangroves.
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Penny, Glenn, John T. Pursley, and David Holcomb. "Microemulsion Additives Enable Optimized Formation Damage Repair and Prevention." Journal of Energy Resources Technology 127, no. 3 (April 24, 2005): 233–39. http://dx.doi.org/10.1115/1.1937419.
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A new microemulsion additive has been developed that is effective in remediating damaged wells and is highly effective in fluid recovery and relative permeability enhancement when applied in drilling and stimulation treatments at dilute concentrations. The microemulsion is a unique blend of biodegradable solvent, surfactant, co-solvent and water. The nanometer-sized structures are modeled after Veronoi structures which when dispersed in the base treating fluid of water or oil permit a greater ease of entry into a damaged area of the reservoir or fracture system. The structures maximize surface energy interaction by expanding to twelve times their individual surface areas to allow maximum contact efficiency at low concentrations (0.1–0.5%). Higher loadings on the order of 2% can be applied in the removal of water blocks and polymer damage. Lab data are shown for the microemulsion in speeding the cleanup of injected fluids in tight gas cores. Further tests show that the microemulsion additive results in lower pressures to displace frac fluids from propped fractures resulting in lower damage and higher production rates. This reduced pressure is also evident in pumping operations where friction is lowered by 10–15% when the microemulsion is added to fracturing fluids. Field examples are shown for remediation and fracture treating of coals, shales and sandstone reservoirs, where productivity is increased by 20–50% depending on the treatment parameters. Drilling examples are shown in horizontal drilling where wells cleanup without the aid of workover rigs where offsets typically require weeks of workover.
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Rakhmatullin, Nail Ravilovich, Raphail Anvarovich Suleymanov, and Timur Kamilevich Valeev. "Hygienic and environmental problems of oil and gas production on the offshore shelf." Sanitarnyj vrač (Sanitary Doctor), no. 4 (March 29, 2022): 282–94. http://dx.doi.org/10.33920/med-08-2204-05.
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The article discusses the results of research carried out within the framework of the industry program of Rospotrebnadzor “Hygienic scientific justification for minimizing risks to the health of the population of Russia” for 2016–2020 (p. 2. 16). During the development of oil and gas fields of the shelf in the waters of the Northern, etc. In addition to climatic conditions, dangerous and harmful factors of the production environment have a significant impact on working conditions: intense industrial noise, general and local vibration, insufficient lighting, contamination of the working area with dangerous chemicals and gases. Often, oil and gas in wells are under high pressure, which creates a threat of explosive emissions and fires. Among the unfavorable factors, the leading place is also occupied by noise, which affects workers during the entire shift from 7 to 30 or more days continuously. The noise sources are power plants and working mechanisms. Sound pressure levels in workplaces reach 72–107 dBA, in cabins 52–67 dBA. The equivalent daily sound levels are 71–102 dBA, and the total doses of acoustic energy affecting personnel exceed the permissible requirements by tens of times. In order to ensure the implementation of industrial and environmental control during the development of oil and gas fields on the offshore shelf, the main parameters, sources and mechanisms of marine water pollution have been determined. The sanitary and hygienic characteristics of the quality of sea water, ways and mechanisms of monitoring the state of sea waters are given. The analysis and updating of a number of existing regulatory and methodological documents in the field of ensuring the sanitary and epidemiological well-being of the population and the safety of environmental objects, including the draft SanPiN 2.2.3... “Sanitary rules and regulations for drilling rigs and structures used in the development of offshore hydrocarbon deposits” has been prepared.
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Carpenter, Chris. "Wellhead Design Enables Offline Cementing and a Shift in Operational Efficiency." Journal of Petroleum Technology 73, no. 05 (May 1, 2021): 68–69. http://dx.doi.org/10.2118/0521-0068-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202439, “Pushing Malaysia’s Drilling Industry Into a New Frontier: How a Distinctive Wellhead Design Enabled Implementation of a Fully Offline Well Cementing Resulting in a Significant Shift in Operational Efficiency,” by Fauzi Abbas and Azrynizam M. Nor, Vestigo, and Daryl Chang, Cameron, a Schlumberger Company, prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Traditionally, rigs are positioned over a well from the moment the surface casing is drilled until the installation of the wellhead tree. This results in the loss of precious time as the rig idles during online cementing. However, in mature Field A offshore Terengganu, Malaysia, a new approach eliminated such inefficiency dramatically. Operational Planning With oil production in Field A initiated in October 2015, historical data on well lithology, formation pressure, and potential issues during drilling were available and were studied to ensure that wells would not experience lost circulation. This preplanning is crucial to ensure that the offline cementing activity meets the operator’s barrier requirements. Petronas Procedures and Guidelines for Upstream Activities (PPGUA 4.0) was used for the development of five subject wells in Field A. In this standard, two well barriers are required during all well activities, including for suspended wells, to prevent uncontrolled outflow from the well to the external environment. For Field A, two barrier types, mechanical and fluid, allowed by PPGUA 4.0 were selected to complement the field’s geological conditions. As defined in PPGUA 4.0, the fluid barrier is the hydrostatic column pressure, which exceeds the flow zone pore pressure, while the mechanical barrier is an element that achieves sealing in the wellbore, such as plugs. The fluid barrier was used because the wells in Field A were not known to have circulation losses. For the development of Field A, the selected rig featured a light-duty crane to assist with equipment spotting on the platform. Once barriers and rig selection are finalized, planning out the drill sequence for rig skidding is imperative. Space required by drillers, cementers, and equipment are among the considerations that affect rig-skid sequence, as well as the necessity of increased manpower. Offline Cementing Equipment and Application In Field A, the casing program was 9⅝×7×3½ in. with a slimhole well design. The wellhead used was a monobore wellhead system with quick connectors. The standard 11-in. nominal wellhead design was used for the wells with no modifications required. All three sections of the casing program were offline cemented. They were the 9⅝-in. surface casing, 7-in. production casing, and 3½-in. tubing. The 9⅝-in. surface casing is threaded to the wellhead housing and was run and landed with the last casing joint. Subsequent wellhead 7-in. casing hangers and a 3½-in. tubing hanger then were run and landed into the compact housing.
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Narayanan, Keshav. "Technology Focus: Intelligent Operations (May 2022)." Journal of Petroleum Technology 74, no. 05 (May 1, 2022): 68–69. http://dx.doi.org/10.2118/0522-0068-jpt.
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The trend of increasing automation and integration of digital work flows continues in all disciplines within the industry. An obvious driver is the increasing digital nature of our world; today’s phones and tablets connected to the cloud perhaps have more computing capabilities than supercomputers from 5 or 10 years ago. Another key driver, arguably the reason why intelligent operations came on the radar of most companies, is being able to improve safety and efficiency in the complex operations that are routinely performed in the oil patch. The last couple of years, I have highlighted efforts around remote operations of fields, smart wells, and the acquisition and integration of real-time data. This year, I have focused on recent drilling-related papers that highlight how safety and performance can be improved with more intelligent operations. Paper SPE 208711 discusses a key requirement I see for successful intelligent operations, especially when the operations span disciplines and companies. Having a standard, consistent, and unambiguous lexicon is critical for automation and digital work flows. This paper highlights an effort to spur the standardization of codes across companies to describe drilling, completions, and other well activities. Anybody who has gone through old well files will recognize immediately the value and the need for such standardization of well activity codes. The other two papers (SPE 208764 and SPE 208784) highlight how automation can lead to increased safety on rigs during operations. Companies are using a combination of cameras, wearables, and other technology to monitor personnel in safety zones on rigs to ensure no one is unknowingly in the wrong spot at the wrong time. A familiar analog to this would be the safety improvements in driving because of collision-avoidance systems in cars (where a combination of technologies including cameras, radar, and lidar are used). Standardization of Well Activity Codes. - Paper SPE 208711 describes the efforts of one operator to standardize well activity reporting codes. A key highlighted improvement is a new coding system that captures both what was done (the typical focus of historical well activity codes) and the broader context on why the activity was performed. The new codes have enabled more granular tracking of performance metrics and a simplification of reporting. Significantly, the operator has recognized the need for a standardized set of codes across the industry and has donated the codes they have developed to an industrywide open-source environment. I hope this spurs wider adoption and refinement of reporting standards across the industry. Using Computer Vision To Monitor Safety Zones and Automate Drillpipe Tallies. - Paper SPE 208764 highlights how digitalization can result in safer operations and improved accuracy through the automation of manual tasks. The paper discusses a computer vision system coupled with a neural network model that detects if any personnel are within a restricted pipe-delivery red zone at an unsafe time and sets off an audible warning alarm. The paper also describes how the use of multiple cameras on different levels of the mast automates the measurement and tallying of the drillpipe being run into the hole. Both these aspects have enhanced existing processes (such as the use of buffer zones and barricades and the manual counting of drill pipe) to further improve safety and accuracy. This article in JPT might also be of interest. Automatic Kick Detection and Dynamic Well Monitoring. - Paper SPE 208784 discusses how to reduce the time gap between when drilling operators detect a kick and when they activate the blowout preventers (BOPs). The paper identifies accurate positioning of the drillstring before activating BOPs as a critical step that affects the time gap. The paper describes an architecture that allows automation of the space-out operation and achieves quick and accurate positioning of the tool joint with minimum movement of the drillstring. A critical enabler that the authors describe is being aware in real time of the depth of each tool joint in the wellbore.
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JPT staff, _. "E&P Notes (August 2021)." Journal of Petroleum Technology 73, no. 08 (August 1, 2021): 15–17. http://dx.doi.org/10.2118/0821-0015-jpt.
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Energean Secures Rig for Multiwell Program off Israel Energean has signed a contract with Stena Drilling for an up to five-well drilling program offshore Israel, which is expected to target the derisking of unrisked prospective recoverable resources of more than 1 billion BOE. The contract is for the drilling of three firm wells and two optional wells using drillship Stena Icemax. The first firm well is expected to spud in early 2022. The firm wells are all expected to be drilled during 2022. “Our five-well growth program off-shore Israel, commencing in the first quarter of 2022, has the potential to double Energean reserve base with resource volumes that can be quickly, economically, and safely monetized,” said Mathios Rigas, chief executive of Energean. “Combined with first gas from our flagship Karish gas development project in mid-2022, the next 12 months are set to be truly transformational for Energean.” One of the firm wells is the Karish North development well. The scope includes re-entry, sidetracking, and completion of the previously drilled Karish North well and completion as a producer. The Karish North development will commercialize 1.2 Tcf of natural gas plus 31 million bbl of liquids and is expected to deliver first gas during the first half of 2023. The program also includes the Karish Main-04 appraisal well and the Athena exploration well, located in Block 12, directly between the Karish and Tanin leases. Athena is estimated to contain unrisked recoverable prospective resource volumes of 0.7 Tcf of gas plus 4 million bbl of liquids. Exxon Hits, Misses off Guyana ExxonMobil made another new discovery in the Stabroek Block offshore Guyana but came away empty with a well on the Canje block. The Longtail-3 well on the Stabroek block struck 230 ft of net pay, including newly identified reservoirs below those intervals found in the Longtail-1 probe. “Longtail-3, combined with our recent discovery at Uaru-2, has the potential to increase our resource estimate within the Stabroek block, demonstrating further growth of this world-class resource and our high-potential development opportunities offshore Guyana,” said Mike Cousins, senior vice president of exploration and new ventures at ExxonMobil. Exxon operates the 6.6-million-acre Stabroek Block as part of a consortium that includes Hess and China’s CNOOC. The new well was drilled 2 miles south of Longtail-1, which was drilled in 2018 and encountered 256 ft of oil-bearing sandstone. The Uaru-2 well in the Stabroek Block was announced in April. That well struck 120 ft of pay. While Stabroek drilling success continues, the operator suffered a set-back on the nearby Canje block and its Jabillo-1 well. The Stena Carron drillship reached a planned target depth of 6475 m; however the well failed to encounter commercial hydrocarbons. According to partner Eco Oil and Gas, the well was drilled to test Upper Cretaceous reservoirs in a stratigraphic trap. Drillship Stena Drillmax will next mobilize to drill the Sapote-1 prospect located in the south-eastern section of Canje, in a separate and distinct target from Jabillo. Sapote-1 lies approximately 100 km southeast of Jabillo and approximately 50 km north of the Haimara discovery in the Stabroek Block, which encountered 207 ft of gas-condensate-bearing sandstone reservoir. Erdogan Touts Turkish Black Sea Natural Gas Discoveries Turkey President Recep Tayyip Erdogan announced the discovery of new natural gas deposits in the Black Sea, where the country plans to start production in 2023. State energy company Tpao found 135 Bcm of gas at the Amasra-1 off-shore well, bringing the total amount of deposits discovered over the past year to 540 Bcm, according to Erdogan. Turkey has ramped up offshore exploration for hydrocarbons over the past few years. Last year, explorers found 405 Bcm of gas at the Tuna-1 well in Sakarya field. Turkey currently imports nearly all the 50 Bcm of gas it consumes annually. Equinor Hits Oil Near Visund Equinor struck oil in Production License 554 with a pair of wells at its Garantiana West prospect. Exploration wells 34/6-5 S and 34/6-5 ST2 were drilled some 10 km north-east of the Visund field, with the former encountering a total oil column of 86 m in the Cook formation. The latter well encountered sandstones in the Nansen formation, but did not encounter commercial hydro-carbons. Recoverable resources are esti-mated at between 8 and 23 million BOE. “This is the first Equinor-operated well in the production license, and the fifth discovery on the Norwegian continental shelf this year,” said Rune Nedregaard, senior vice president, exploration and production south. “The discovery is in line with our roadmap of exploring near existing infrastructure in order to increase the commerciality.” Well 34/6-5 S was drilled using Seadrill semisubmersible rig West Hercules. Equinor operates the discovery; partners include Var Energi and Aker BP. ExxonMobil Eyes Flemish Pass Well ExxonMobil is looking to secure a semi-submersible to complete the drilling of a deepwater wildcat in the Flemish Pass offshore eastern Canada. The operator began drilling the Hampden K-41 probe in the spring of last year using Seadrill semisubmersible rig West Aquarius, but the unit was pulled off the well soon thereafter for reasons unknown. ExxonMobil is currently prequalifying companies to supply a mobile offshore drilling unit to continue the well at Hampden in Exploration License (EL) 1165A. The operator is targeting a mid-year 2022 start to the probe to be drilled in around 1175 m of water, some 454 km from St. John’s, Newfoundland. Meanwhile, China’s CNOCC has wrapped up drilling on its Pelles prospect, its first exploration well offshore Newfoundland. The prospect, in about 1163 m of water, is located within license EL 1144. The wildcat was originally set to spud in early 2020 but was delayed due to impacts of the COVID-19 pandemic. The company confirmed that drilling operations onboard drillship Stena Forth were complete and the rig plugged and abandoned the well. The results of the well were not released. Equinor To Drop Mexican Offshore Leases Equinor will exit two Mexican deepwater blocks as part its upstream investment strategy to focus on assets offering rapid and strong returns. The two blocks located in the Salina Sureste basin were acquired in Mexico’s 1.4 bid round in an equal equity split with BP and TotalEnergies. Block 3, where Equinor holds a 33% operating interest, has water depths ranging from 900 to 2500 m. Block 1, where BP is the operator, has water depths ranging from 200 to 3100 m. Exploration commitments include a single well on each block, not yet drilled. The announcement to exit Mexico was made by Executive Vice President for E&P International Al Cook during the company’s Capital Markets Day event held in June. The company also unveiled plans to leave Nicaragua and Australia, as part of its upstream investment plans. Cook added that Equinor will only operate offshore assets moving forward and will no longer operate onshore, unconventional projects. The company will instead opt to partner with others on those projects. Equinor will also look to offload its exploration assets in the Austin Chalk play in the US and Terra Nova in Canada, he said. Var Energi Strikes North Sea Oil Var Energi has confirmed a discovery at its King and Prince exploration wells in the Balder area in the Southern North Sea. Success at the combined King and Prince exploration wells lifts preliminary estimates of recoverable oil equivalents between 60 and 135 million bbl. King/Prince was drilled in PL 027 by semisubmersible rig Scarabeo 8. The Prince well encountered an oil column of about 35 m in the Triassic Skagerrak formation within good to moderate reservoir sandstones, while the King well discovered a gas column of about 30 m and a light oil column of about 55 m with some thick Paleogene sandstone. An additional King appraisal side-track further confirmed a 40-m gas column and an oil column of about 55 m of which about 35 m are formed by thick and massive oil-bearing sandstone with excellent reservoir quality. The licensees consider the discoveries to be commercial and will assess tie-in to the existing infrastructure in the Balder area. The wells are located about 6 km north of the Balder field and 3 km west of the Ringhorne platform. Var Energi operates and holds a 90% stake of the license. Mime Petroleum holds the remaining 10%.
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Thorhaug, Anitra. "Petroleum Industry's Use of Seagrass Restoration as Mitigation for Construction and as a Potential Cleanup Tool." International Oil Spill Conference Proceedings 2001, no. 1 (March 1, 2001): 385–89. http://dx.doi.org/10.7901/2169-3358-2001-1-385.
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ABSTRACT The Laguna Madre in Corpus Christi, Texas has a great deal of petroleum and natural gas activity while housing a national seashore. The area is a flyway for a wide array of bird species, as well as heavily fished. Historically, the laguna had a series of infrastructure modifications, gas and oil rigs, and real estate development. In the process of placing a drilling rig, a winter storm blew the vessel with the rig off a narrow channel. To remove the vessel, other vessels had to be called. A 35-acre accident occurred. In mitigation, 75 acres of the seagrass Halodule wrightii was planted in three areas: (1) a 15-acre dredge island where a portion of the island was scraped down from upland-spoil deposit to −2 ft mlw; (2) a mile-long channel where seagrasses were restored from −7 to 10 ft mlw to −3 to ft mlw; and (3) a persistently barren site for decades (scraped by another petroleum company's vessel) was restored in the shallows while holes were filled in and seagrass planted on top. The fill throughout was from the scraping from the dredge islands. The fill was transmitted several miles by a new device. Planting of Halodule plugs proceeded from March to July 1999. Within 3 months, the shallow sites had been covered with the restored Halodule,. Endangered species of roseate spoonbills, brown pelicans, great white herons and other wading and fishing birds were regularly feeding at two sites. The deeper sites had heavy fish populations return to the area, fished by man, seagulls and pelicans. Despite a direct hit by Hurricane Bret in 1999, lateral growth at all depths was deemed governmentally satisfactory. This same procedure with seagrasses is recommended for after-effects of estuarine oil spill cleanup, and mitigation banks of seagrasses are recommended for construction or operations mitigation.
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Carpenter, Chris. "Invasive Sun Coral Species Challenges Decommissioning of Structures Offshore Brazil." Journal of Petroleum Technology 73, no. 08 (August 1, 2021): 58–59. http://dx.doi.org/10.2118/0821-0058-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30656, “Decommissioning of Subsea Structures in Brazil: Effect of Invasive Species and Genome Sequence of the Azooxanthellate Coral Tubastraea sp.,” by João Humberto Guandalini Batista, SPE, Repsol; Mauro Rebelo, Universidade Federal do Rio de Janeiro; and Giordano Soares-Souza, SENAI CETIQT, prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Decommissioning of offshore assets in Brazil is subject to high levels of uncertainty because of Tubastraea, an invasive species of sun coral. This species has a high capacity for dispersion and recruitment and has been associated with the replacement of native species in rocky shores, exerting a serious effect on native biodiversity. The complete paper explores the biology of the invasive species, aiming to identify methods to eliminate or diminish its spread. The authors write that data generated in this study will foster the development of effective technologies in coral-species management, whether species are invasive or threatened. Introduction Originally from the Coral Triangle in the Pacific Ocean—a highly diverse region with hundreds of coral species—Tubastraea was first observed in the Campos Basin in the 1980s. Tubastraea sp. have high fecundity and growth rates with the ability to reproduce asexually, establishing very dense populations. This fast reproduction allows larvae to outcompete native species in both natural and artificial substrates in the sea. Sun coral is extremely resistant to environmental change. It has been found in shallow waters, sometimes exposed to air, showing tolerance even to short periods of desiccation. Recently, new species have been identified in Brazilian waters, heightening concern over the proliferation of sun coral. In the past, the common understanding was that subspecies coccinea and tagusensis were those found in Brazilian waters. However, recent studies dedicated to the research of the Tubastraea genus raised suspicion of the presence of diaphana and aurea, with the possible occurrence of hybrids as well. The preference of Tubastraea is to live in structures that are static or mostly motionless, such as production platforms, subsea structures, and drilling rigs. This trait has made sun coral a major challenge for the local oil and gas industry. While in the Campos Basin, the main objective is to decrease dispersion of already bioencrusted production units and subsea structures, in the Santos Basin, the goal is to avoid colonization in structures in operation or those scheduled to be installed soon. To further complicate matters, drilling and intervention vessels and rigs are contracted to service both basins. They work in dynamic-positioning mode, stationary around the production units and subsea structures for lengths of time that exceed the reproduction cycle time of the sun coral, allowing larval dispersion.
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Kranakis, Eda. "Roughnecks, Rock Bits, and Rigs: The Evolution of Oil Well Drilling Technology in Alberta, 183-1970. By Sandy Gow. (Calgary: University of Calgary Press, 2005. 674 p., ill., bibl., app., isbn 1-55238-067-x $44.95)." Scientia Canadensis: Canadian Journal of the History of Science, Technology and Medicine 31, no. 1-2 (2008): 199. http://dx.doi.org/10.7202/019772ar.
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Zhu, Hui, Gongxu Jia, Qingling Zhang, Shan Zhang, Xiaoli Lin, and Yanmin Shuai. "Detecting Offshore Drilling Rigs with Multitemporal NDWI: A Case Study in the Caspian Sea." Remote Sensing 13, no. 8 (April 19, 2021): 1576. http://dx.doi.org/10.3390/rs13081576.
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Offshore drilling rigs are the foundation of oil and gas exploitation in water areas. Their spatial and temporal distribution, state attributes and other information directly reflect the exploitation level of regional oil and gas resources. Therefore, it is very important to build an automatic detecting method for offshore drilling rigs with good performance to accurately capture the temporal and spatial distribution and state of oil and gas exploitation activities. At present, there are two main groups of methods for offshore drilling rigs: invariant feature-based methods and nighttime firelight-based methods. Methods based on invariant location are more subjective in terms of their parameter settings and require intensive computation. Nighttime light-based methods are largely unable to identify offshore drilling rigs without associated waste gas ignition. Furthermore, multiple offshore drilling rigs in close proximity to one another cannot be effectively distinguished with low spatial resolution imagery. To address these shortcomings, we propose a new method for the automatic identification of offshore drilling rigs based on Landsat-7 ETM+ images from 2018 to 2019, taking the Caspian Sea as the research area. We build a nominal annual cloud and cloud shadow-free Normalized Difference Water Index (NDWI) composite by designing an optimal NDWI compositing method based of the influence of cloud and cloud shadow on the NDWI values of water, bare land (island) and offshore drilling rigs. The classification of these objects is simultaneously done during the compositing process, with the following rules: water body (Max_NDWI > 0.55), bare land (island) (Min_NDWI < −0.05) and offshore drilling rig (0 < Mean_NDWI < 0.4). A threshold segmentation and postprocessing were carried out to further refine the results. Using this method, 497 offshore platforms were automatically identified using a nominal annual cloud and cloud shadow-free NDWI composite image and Google Earth Engine. Validation using Sentinel-2 Multispectral Imager (MSI) and Google Earth images demonstrated that the correct rate of offshore drilling rig detection in the Caspian Sea is 90.2%, the missing judgment rate is 5.3% and the wrong judgment rate is 4.5%, proving the performance of the proposed method. This method can be used to identify offshore drilling rigs within a large water surface area relatively quickly, which is of great significance for exploring the exploitation status of offshore oil and gas resources. It can also be extended to finer spatial resolution optical remote sensing images; thus small-size drilling rigs can be effectively detected.
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Baird, Pat Herron. "Concentrations of Seabirds at Oil-Drilling Rigs." Condor 92, no. 3 (August 1990): 768. http://dx.doi.org/10.2307/1368697.
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