PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.
Cold heavy oil production with sand (CHOPS) involves the deliberate initiation of sand influx during the completion procedure, maintenance of sand influx during the productive life of the well, and implementation of methods to separate the sand from the oil for disposal. No sand exclusion devices (screens, liners, gravel packs, etc.) are used. The sand is produced along with oil, water, and gas and separated from the oil before upgrading to a synthetic crude. To date, deliberate massive sand influx has been used only in unconsolidated sandstone (UCSS) reservoirs (φ 30%) containing viscous oil (μ 500 cp). It has been used almost exclusively in the Canadian heavy-oil belt and in shallow ( 800 m), low-production-rate wells (up to 100 to 125 m3/d).
The claim that the world is irresponsible in rapidly consuming irreplaceable resources ignores technical progress, market pressures, and the historical record. For example, the "Club of Rome," with the use of exponential growth assumptions and extrapolations under static technology, predicted serious commodity shortages before 2000, including massive oil shortages and famine. First, the new production technologies are proof that science and knowledge continue to advance and that further advances are anticipated. Second, oil prices will not skyrocket because technologies such as manufacturing synthetic oil from coal are waiting in the wings. Third, the new technologies have been forced to become efficient and profitable, even with unfavorable refining penalties. Fourth, exploration costs for new conventional oil production capacity will continue to rise in all mature basins, whereas technologies such as CHOPS can lower production costs in such basins. Fifth, technological feedback from heavy-oil production is improving conventional oil recovery. Finally, the heavy-oil resource in UCSS is vast. Although it is obvious that the amount of conventional (light) oil is limited, the impact of this limitation, while relevant in the short term (2000 to 2030), is likely to be inconsequential to the energy industry in the long term (50 to 200 years). The first discoveries in the Canadian heavy-oil belt were made in the Lloydminster area in the late 1920s. Typically, 10- to 12-mm diameter perforations were used, and pump jacks were limited by slow rod-fall velocity in the viscous oil to a maximum of 8 to 10 m3/d of production, usually less. Operators had to cope with small amounts of sand, approximately 1% in more viscous oils. Small local operators learned empirically that wells that continued to produce sand tended to be better producers, and efforts to exclude sand with screens usually led to total loss of production. Operators spread the waste sand on local gravel roads and, in some areas, the roadbeds are now up to 1.5 m higher because of repeated sand spreading. The sharp oil price increases in the 1970s and 1980s led to great interest in heavy-oil-belt resources (approximately 10 109m3). Many international companies arrived and introduced the latest screen and gravel-pack technology but, in all cases, greatly impaired productivity or total failure to bring the well on production was the result. To this day, there are hundreds of inactive wells with expensive screens and gravel packs. The advent of progressing cavity (PC) pumps in the 1980s changed the nonthermal heavy-oil industry in Canada. The first PC pumps had low lifespans and were not particularly cost-effective, but better quality control and continued advances led to longer life and fewer problems. The rate limits of beam pumps were no longer a barrier and, between 1990 and 1995, operators changed their view of well management.
Ding, Shuaiwei (National & Local Joint Engineering Research Center for Carbon Capture and Sequestration Technology, State Key Laboratory for Continental Dynamics, Northwest University) | Liu, Guangwei (CNOOC Research Institute) | Li, Peng (National Engineering Laboratory for Exploration and Development of Low-Permeability Oil & Gas Fields) | Xi, Yi (Exploration and Development Research Institute, Petro-China Changqing Oil Field Company Ltd) | Ma, Jinfeng (National Engineering Laboratory for Exploration and Development of Low-Permeability Oil & Gas Fields)
Oil reservoirs are considered good storage structures for CO2 geological storage. With the right selection of candidate reservoir, injection of CO2 into tertiary and depleted oil reservoirs can result in enhanced oil recovery (EOR) and permanent sequestration of CO2 underground. The selection of candidate reservoirs for future CO2-EOR and storage projects mainly depends on storage potential evaluation. The aim of this work is to estimate the storage potential of CO2 stored in tertiary (CO2-EOR) and depleted oil reservoirs. In tertiary oil reservoirs, a method to estimate the geological CO2 storage capacity (CO2SC) in the reservoir during well open operations (EOR operations), which is a function of reservoir parameters, original geological reserves and oil volume factor is first built. In depleted oil reservoirs, a method to calculate the CO2SC in the reservoir during well shut down operations, which is based on the material balance method is proposed. In both cases, the methodology of storage capacity of CO2 dissolved in remaining oil, formation water and by mineral trapping is presented based on the model established by
Liu, Guoqiang (PetroChina Exploration and Production Company) | Hou, Yuting (PetroChina Changqing Oilfield Company) | He, Junling (PetroChina Jilin Oilfield Company) | Zhang, Hao (PetroChina Xinjiang Oilfield Company) | Wu, Jinlong (Schlumberger) | Zhao, Xianran (Schlumberger) | Li, Huayang (Schlumberger) | Wu, Fangfang (Schlumberger) | Li, Shenzhuan (Schlumberger) | Wang, Yuxi (Schlumberger)
Most shale oil resources in China are lacustrine deposit. The reservoirs are usually characterized by complex lithology and high heterogeneity with various mineral compositions (quartz, carbonates, feldspars, pyrites and volcanic ash), total organic carbon and pore structure. How to delineate the shale oil reservoir, how to identify the ‘sweet spots’ and its distribution are the two major challenges and objectives for this study.
To answer the question, a systematic workflow was proposed by integrating the advanced logging technologies (such as nuclear magnetic resonance, micro-resistivity imager, spectroscopy data, array dielectric tool) with special core measurement data. Firstly, the shale oil reservoir was classified into different types according to the logging responses. Secondly, core samples were chosen from each type and sent out to lab for a series of core special experiments to test the microscopic properties. Finally, the advanced core analysis results and logging technologies were integrated to depict the characters of the different types of shale oil reservoirs from microscopic to macroscopic scale. And by comparing with testing data, the features of best shale oil reservoir type can be identified, and the distribution and potential of shale oil reservoir can be unraveled.
The new approach helped to get a thorough understanding of the shale oil reservoirs characteristics, such as lithology, mineral composition, pore types, pore size distribution, oil content, kerogen type and maturity of organic matter, organic carbon content and distribution. Six different kinds of shale oil reservoir facies were classfied from loging responses, inculding super high gamma ray siliceous shale, high gamma ray siliceous shale, high gamma ray argillaceous shale, high gamma ray tuffaceous shale, medium gamma ray siliceous shale and medium gamma ray argillaceous shale. High gamma ray siliceous shale and medium gamma ray siliceous shale are proved to be the best shale oil reserovir, which contains 2~8% of TOC, 2~12% of effective porosity, more than 50% of quartz content and high propotion of macropores.
The method proposed in this project has been implemented in many unconventional reservoirs in china to evaluate the resource potential and get a comprehensive understanding of the shale oil reservoir.
The wells tested based on the recommendation has got promising production after fracturing, which brought client big confidence for future exploration.
Zhao, Jianzhong (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | He, Jun (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | He, Yong (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | Sun, Pingtao (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | Li, Yanbo (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | Chen, Hongliang (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | Zhang, Shengliang (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company) | Guo, Yu (Drilling Technology Research Institute of PetroChina Jilin Oilfield Company)
Objectives/scope: The poor quality of resources, low utilization of reserves,high investment in capacity building are the main problems faced in low permeability reservoir in Jilin Oilfield.The objective of this research is to form a intensive drilling model of large platforms which can improve the drilling quality,efficiency and management level. By applying this model,we can increase the single well production,block recovery rate and reduce the production construction investments,the development and production costs in low permeability oilfield. Methods,Procedures,Process: This research based on the production capacity construction in the Jilin Oilfield.This drilling model is different from the traditional model which is inefficient and the investments are higher.Our main procedures included the drilling plan optimization,intensive drilling application,efficient drilling technology application and drilling production management optimization. From 2015 to 2017,we have applied this drilling model successfully in Jilin Oilfield. Result,Observations,Conclusions: 1 Drilling Plan Optimization Technology The single well and small platforms are commonly used in the reservoir development of Jilin oilfield. Because of the low oil price,we changed our train of thought from traditional development mode to intensive drilling model of large platforms large platforms.It can reduce the land occupation area of well sites,reduce integrated management costs,and improve economical benefits of development effectively.By applying the lowest costs of investment principles,drilling engineering formed integrated drilling plan optimization technology which satisfied the requirements of geological deployment,fracturing and lifting,ground engineering,intensive drilling,economical development.It formed the platform size optimization technology that determined the most economical well number of the platforms.The oil field development investments contain 6 main parts,including drilling engineering,mud log engineering,logging engineering,oil recovery engineering,surface construction engineering and land occupation investments.With the increasing of the platform scale,the investments of drilling engineering increases,because the costs of drilling bits,drilling mud,casing,cement increase,which caused by the increasing of the well depth.The increasing of mud log 2 IPTC-19374-MS
Xu, Jianguo (PetroChina Jilin Oilfield Company) | Zhao, Chenxu (PetroChina Jilin Oilfield Company) | Zheng, Jiangang (PetroChina Changqing Oilfield Company) | Xuan, Gaoliang (PetroChina Jilin Oilfield Company) | Zhang, Ruquan (PetroChina Changqing Oilfield Company) | Peng, Chong (PetroChina Changqing Oilfield Company) | Liu, Hongxia (PetroChina Jilin Oilfield Company)
In recent years, the investment of new area productivity construction in Jilin oil field is high, stabilized production becomes more and more difficulty, so the strategic center of oil field transfers to the refracturing of old well, however, the comprehensive water cut and recovery of old oil field is high, and the remaining oil dispersed, increasing production and increasing efficiency by refracturing becomes more and more difficulty. In order to deal with these challenges and realize the benefits of tapping in old area, the new idea of "group fracturing" was proposed basing on the concept of volumetric fracturing, starting from the reconsideration of reservoir geology, injection production unit for the smallest study unit, and integrating multiple fracturing method, we conduct a series of technical studies and field experiment in the old area of Jilin oilfield. The group fracturing technology series mainly includes the following: (1) The high strength positioning and plugging technique for reorientation fracturing; (2) Energy develop before fracturing and fast energy storage technique in fracturing; (3) Synchronous fracturing technique of multi wells; (4) Synchronous fracturing technique of oil and water well, reorientation fracturing technique of water well; (5) Fracturing combining with rapid profile control and water plugging technique; (6) "Factory-oriented construction".Since 2016, the group fracturing has carried out a total of 143 wells in 14 blocks in the old area, which has achieved good results. Compared with the conventional fracturing in the same area, the economic efficiency is increased by 10.2%, the oil increase of the single well is increased by 1 times, and the effective period of the measure is raised by 50%. The practice shows that the group fracturing technique is an effective measure to exploit the benefits of the old area in the low permeability oilfield.
Sun, Junchang (Research Institute of Petroleum Exploration & Development, PetroChina) | Zhang, Shijie (Xinjiang Oilfield Company, PetroChina) | Wang, Jieming (Research Institute of Petroleum Exploration & Development, PetroChina) | Guo, Hekun (Research Institute of Petroleum Exploration & Development, PetroChina) | Li, Chun (Research Institute of Petroleum Exploration & Development, PetroChina) | Xu, Hongcheng (Research Institute of Petroleum Exploration & Development, PetroChina) | Zhu, Sinan (Research Institute of Petroleum Exploration & Development, PetroChina) | Zhao, Kai (Research Institute of Petroleum Exploration & Development, PetroChina)
Compared with sandstones and carbonates, volcanic reservoirs are much more complex and heterogeneous due to the special eruption diagenesis mechanism, many types of rock lithology, various mineral compositions and a broad wide of pore sizes according to previous studies. Consequently, accurate characterization of volcanic reservoirs using the powerful nuclear magnetic resonance (NMR) logging requires a comprehensive laboratory NMR investigation of volcanic rock because currently used NMR interpreted methods were only developed for sedimentary reservoirs.
To gain an in-depth understanding of NMR characteristics of volcanic reservoirs with different lithology, a total of 108 low-permeability volcanic reservoir rock plugs from three large volcanic gas reservoirs named Xushen, Changling and Dixi, respectively, were prepared to perform NMR measurements and other related tests including CT scans, thin section petrography, mercury injection and mineral compositions analysis. The selected plugs comprise 9 types of lithology representing the main producing formation lithology of the three reservoirs. Specially, centrifuge tests were conducted with the maximum centrifugal forces up to 500 psi to explore the suitable capillary pressure for
Results indicate that, obviously different from sandstone and carbonate plugs, NMR porosity of volcanic plugs at fully brine-saturated state is strongly dependent on rock lithology. NMR porosities of trachyte, trachytic volcanic and granite porphyry are significantly less than the conventional ones measured by the Archimedes method, which means that, accurate identification of reservoir intervals lithology is a primary prerequisite before correct interpretations of NMR logging. Paramagnetic minerals mainly iron and manganese elements contained in volcanic reservoirs are the fundamental cause resulting in this abnormal phenomenon. The critical values of iron and manganese elements contents are approximately 2% and 0.06% by weight, respectively, above which the NMR porosity will be considerably less than the conventional one suggesting by inductively coupled plasma-atomic emission spectrometry (ICP-AES) tests on 14 representative plugs. Then, a new NMR porosity corrected formula was developed to improve interpreted quality of NMR logging. It was found that the suitable capillary pressure for determination of T2 cutoff of volcanic reservoirs is 400psi, 3 times larger than the commonly recommended standard (100psi) for sandstones. The calculated
The laboratory NMR results were used to interpret NMR logging of the Xushen reservoir of Daqing oilfield in eastern China and aided in detailed reservoirs evaluation. The outcome of beneficial intervals selection and high productivity well completion based on the NMR logging interpretation is very encouraging. This study indicated that a comprehensive laboratory NMR tests is very essential to successful application of NMR logging for complex reservoirs such as volcanic reservoirs.
Shi, Junfeng (RIPED, CNPC) | Chen, Shiwen (RIPED, CNPC) | Zhang, Xishun (RIPED, CNPC) | Zhao, Ruidong (RIPED, CNPC) | Liu, Zhaoyu (Drilling & Production Engineering Department of Jilin Oilfield Company, CNPC) | Liu, Meng (RIPED, CNPC) | Zhang, Na (RIPED, CNPC) | Sun, Dakui (Drilling & Production Engineering Department of Jilin Oilfield Company, CNPC)
The best artificial lifting method for a well is to lifting more with less during the whole life cycle, however, it is difficult to select the best method because there are many factors affecting the choice of artificial lifting methods and most factors cannot be described with mathematical models. At present, the selection mainly depends on experts’ experience, which results in many incorrect decisions and lead to huge economic loss. In China, there are a large number of artificial lifting wells, and the large amount of data generated by the wells is of great value, which can be used to select the best artificial lifting method for different type of oil wells. This paper selects 11 parameters, including well fluid characteristics, fluid production capacity, well trajectory, pump depth, pump efficiency, pump inspection period, and maintenance cost per year as influence factors. About 40,000 artificial lifting wells of CNPC were selected as the big data analysis sample initially. As not all the wells are good samples, an effect evaluation function is established by taking pump efficiency, power consumption with lifting per ton liquid 100m, annual operating maintenance cost into account, then the samples are selected further according to the value of effect evaluation function, which ensured all the samples participated in machine learning are good samples. A deep recurrent neural network was established which can select the best artificial lifting method through deep learning. Experimental results showed that the neural network model had fast convergence and high prediction accuracy. With the application of this model, artificial lifting method selecting and effect analysis have been conducted for more than 5,000 oil wells of CNPC with different reservoir characteristics, different wellbore structures and different fluid characteristics. The coincidence rate between calculation results of this model and actual production situation is 90.56%. Big data analysis provides a reliable, practical and intelligent method for optimizing and selecting artificial lift.
Is Surfactant Environmentally Safe for Offshore Use and Discharge? The current presentation date and time shown is a TENTATIVE schedule. The final/confirm presentation schedule will be notified/available in February 2019. Designing Cement Jobs for Success - Get It Right the First Time! Connected Reservoir Regions Map Created From Time-Lapse Pressure Data Shows Similarity to Other Reservoir Quality Maps in a Heterogeneous Carbonate Reservoir. X. Du, Y. Jin, X. Wu, U. of Houston; Y. Liu, X. Wu, O. Awan, J. Roth, K.C. See, N. Tognini, Shell Intl.