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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.
Africa (Sub-Sahara) San Leon Energy reported encouraging performance from its OML 18 field in Nigeria. Reperforation of an oil well increased gross field production to approximately 61,000 B/D before output was temporarily scaled back to 53,000 B/D for a shut-in, upgrade, and workover of the well. A number of other field wells will be reperforated in coming months, the company said. San Leon holds a 9.72% interest in the field, which is operated by Eroton (35%). Nigerian National Petroleum Corp. holds the remaining stake. FAR said that drilling has begun on the SNE-5 appraisal well offshore Senegal. The well and the following SNE-6 well will evaluate the upper SNE reservoir units' connectivity and deliverability by oil flow testing that will include interference tests.
The drilling fluid loss or lost circulation via near-wellbore fracture is one of the critical problems in the drilling of deep oil and gas resources, which will cause other problems such as difficulty in wellbore pressure control and reservoir damage. The conventional treatment is to introduce the granular lost circulation material (LCM) into the drilling fluid system to plug the fractures. However, the low one-time success rate of fracture plugging and repeated drilling fluid loss still obstruct the exploitation of deep oil and gas resources. In order to improve the effect of fracture plugging and reduce the cost of well construction of deep oil and gas reservoirs, the visualization experimental study on the influence of the LCM injection method on the fracture plugging is carried out in this paper.
Firstly, high-resolution scanner is used to obtain the topography data of both sides of carbonate fracture, and the corresponding computer three-dimensional model is established. Then based on the model, a high-precision engraving machine is used to process the fracture surface on two transparent plexiglas plate. After assembly, a transparent fractured module is built up, and the fracture aperture of this module is consistent with the scanned carbonate fracture. In the fracture plugging visualization experiment, the solution mixed with purple particles of specific size will be injected into the module to simulate the process of the LCM plugging the near-wellbore fracture.
In the traditional fracture plugging method, all LCM will be injected at one time, where the various sizes and types of plugging materials are uniformly mixed. It is observed in the he visualization experiment that a large number of small-sized particle will flow into the depth of fracture in traditional fracture plugging method. At the same time, the small-sized particles will be mixed between the large-sized particles in the plugging zone, resulting in the plugging zone still having a certain permeability. After changing the injection sequence, which inject the large size particles first and then inject small size particles, it is found that the large-size particles will form a single-particle bridging at a specific depth of the fracture, preventing subsequent injected particles from flowing into the depth of fracture, and accumulating to plug the fracture, which increases the area of the plugging zone by 19% and make the plugged zone denser.
The visualization experiment results show that by changing the LCM injection method, the LCM utilization rate and fracture plugging effect can be significantly improved, reducing the reservoir damage. This is conducive to the efficient exploitation of deep oil and gas resources. At the same time, the visualized experimental method proposed in this paper can be also benefit to other research fields such as proppant placement, solute transport in rock fractures.
Africa (Sub-Sahara) FAR said that drilling has begun on the SNE-5 appraisal well offshore Senegal. The well and the following SNE-6 well will evaluate the upper SNE reservoir units' connectivity and deliverability by oil flow testing that will include interference tests. The new wells follow a four-well appraisal program that the company called "highly successful." FAR has a 15% interest in the SNE field, which is operated by Cairn Energy (40%). Other participants are ConocoPhillips (35%) and Petrosen (10%). San Leon Energy reported encouraging performance from its OML 18 field in Nigeria. Reperforation of an oil well increased gross field production to approximately 61,000 B/D before output was temporarily scaled back to 53,000 B/D for a shut-in, upgrade, and workover of the well.
The horizontal wells that are completed with slotted liners often suffer from a severe water production problem, which is detrimental to the oil recovery. This is because the annulus between the slotted liners and wellbore cannot be fully filled with common hydrogels with poor thixotropy, which determines the ultimate hydrogel filling outcome in the annulus. This paper presents a novel hydrogel with high thixotropy to effectively control water prod uction in the horizontal wells.
In this work, a new double-group cross-linking hydrogel with high thixotropy was developed. The hydrogel was generated through the graft copolymerization of acrylamide onto polysaccharide and the covalent cross-linking reaction between acrylamide and N, N-methylene bisacrylamide. Nano-laponite and organic titanium were employed as the thixotropic agents. This study aimed at evaluating the thixotropic performance, gelation time, and plugging efficiency. The thixotropic mechanisms of the new hydrogel were also investigated by measuring its rheological properties and examining its microstructures.
It was found that the new hydrogel became thickened rapidly after shearing. Its thixotropic recovery coefficient was 0.734, which was much higher than those for the traditional hydrogels. Visual observations also indicated that this hydrogel had excellent thixotropy. The gelation time can be controlled in the range of 2-8 h by properly adjusting the concentrations of the framework material, cross-linker, and initiator. The hydrogel could be customized for the mature oil reservoirs, at which it was stable for over 90 days. A series of laboratory physical modeling tests showed that the breakthrough pressure gradient and the plugging ratio of the hydrogel were higher than 9.5 MPa/m and 99%, respectively. The freeze-etching SEM examinations indicated that the hydrogel had a uniform grid structure, which can be broken easily and restored quickly. This led to the remarkable thixotropic performance. The formation of a metastable structure caused by the electrostatic interaction and coordination effect was considered to be the primary reason for the high thixotropy.
The successful development of the new thixotropic hydrogel not only helps to control water production from the horizontal wells but also furthers the thixotropic theory of hydrogel. This study also provides technical guidelines for further increasing the thixotropies of drilling fluids, fracturing fluids and other EOR polymers that are commonly used in the petroleum industry.
Han, Xiaodong (China University of Petroleum, Beijing and CNOOC) | Zhong, Liguo (China University of Petroleum (Beijing)) | Liu, Yigang (Tanjin Branch of CNOOC) | Zou, Jian (Tanjin Branch of CNOOC) | Wang, Qiuxia (Tanjin Branch of CNOOC)
Summary Heavy-oil resources whose underground oil viscosity is greater than 350 mPas is abundant in the Bohai oilfield. Because of the lack of effective exploitation technology, production performance with cold-production methods was not satisfactory. Seeking an effective method of heavy-oil exploitation, the multiple thermal-fluid stimulation was proposed and studied, in which hot water or steam mixed with carbon dioxide (CO 2) and nitrogen (N 2) would be injected into the formation for heating the oil and improving heavy-oil production. Considering the limitation of the offshore platform, a miniaturized multiple thermal-fluid generator was designed and developed. Integrated technologies such as seawater desalinization, heat insulation, and anticorrosion methods were also studied and developed. A pilot test of multiple thermal-fluid stimulation was conducted in Nanpu oilfield, starting in 2008. Until now, the pilot test has lasted for more than 10 years, and a total of 27 cycles of multiple thermal-fluid stimulation have been carried out. The cumulative oil produced by multiple thermal-fluid stimulation reached approximately 5.710 5 m 3, and the incremental oil production is approximately 2.610 5 m 3 . The performance of oil production was satisfactory. With the increase of the stimulation cycles, a gas-channeling problem emerged and resulted in a decrease in the oil-production rate. New methods need to be studied and used for further enhancing oil recovery in Nanpu oilfield at the late stage of multiple thermal-fluid stimulation. Introduction Heavy-oil resources are widely distributed around the world, and with the rapid depletion of conventional oil resources, economical and efficient development of heavy-oil resources is one of the most effective ways to meet future energy demands (Mohammadpoor and Torabi 2012; Ehtesabi et al. 2014; Hou et al. 2016). Based on decades of scientific research and field tests, both thermal and nonthermal recovery methods have been developed and applied to heavy-oil exploitation (Nasr and Ayodele 2005; Zhong et al. 2013; Feng et al. 2011). For cold production, waterflooding and chemical-flooding methods are the most common for heavy-oil production (Feng et al. 2010, 2013; Wang et al. 2013a; Wu et al. 2016b; Guo et al. 2018).
Jia, Hu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation of Southwest Petroleum University, China) | Chen, Hao (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation of Southwest Petroleum University, China) | Zhao, Jin-Zhou (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation of Southwest Petroleum University, China)
Effective mitigation of fluid loss and prevention of formation damage are substantial concerns during well completion and workover in low-pressure, high-permeability, and/or fractured reservoirs, especially with high temperature (HT). In this paper, a highly elastic composite gel is developed on the basis of the solution blending for “intercalated crosslinking.” The mechanism is the intercalation of polymer and crosslinker into layered silicate material (LSM) using a specific procedure. The gel is composed of HT resistant copolymer, crosslinker polyethyleneimine (PEI), LSM, and antioxidant in freshwater. The effects of main variables on the gelation performance are investigated. The mature composite gel strength is noticeably improved with increasing temperature. The elastic modulus (G') of the mature composite gel prepared at 160°C can reach up to 15 000 Pa, while only a value of 6000 Pa is obtained for the gel at 130°C. The composite gel remains robust after aging 10 days at 160°C. The pressure-bearing capacity and rigidity of the mature composite gel are noticeably improved with increasing layered silicate concentration. This unique feature can benefit stress buffering when the sealing operation is conducted under high differential pressure such as the case with a long hydrostatic column. Scanning electron microscope (SEM) is used to further reveal the intercalated crosslinking mechanism of the composite gel. A temporary plugging experiment for a fractured limestone core also supports the gel’s high-pressure (HP) resistance and low adsorption and retention to alleviate formation damage. The composite gel is promising for fluid loss mitigation that could be extended to other related near-wellbore operations in HT wells.
Luo, Donghong (CNOOC) | Dai, Zong (CNOOC) | Wang, Yahui (CNOOC) | Pei, Bailin (Anton Bailin Oilfield Technology, Beijing Co., Ltd) | Wang, Hailong (Anton Bailin Oilfield Technology, Beijing Co., Ltd) | Shen, Zheng (Anton Bailin Oilfield Technology, Beijing Co., Ltd) | Zhu, Hongxia (Anton Bailin Oilfield Technology, Beijing Co., Ltd)
Water breakthrough (WBT) in the horizontal wells often leads to water flooding in the well, especially to those heavy oil reservoirs in reef limestone carbonate. The excessive water production from the hydrocarbon producing horizontal wells can adversely affect the economic life of the well, furthermore this could result in the well permanent abandonment. Nowadays, no effective methods of water control are available for the similar reservoirs, traditional water control methods have three technology barriers: (1) can not accurately locate the WBT positions;(2) difficulty of identifying the wellbore completion, fluid, and nearby formation conditions;(3) Not being designed to control water from new water breakthrough points.
This paper shows a newly developed water control technology by using continuous Packed-off double water control technology (CPI). It was successfully implemented in a well of a fractured reef limestone oil field in South China Sea. This technology completely overcome the above shortcomings of traditional water control methods. The mechanism is to pack patent particles into the wellbore and near-wellbore fractures to create a double "artificial well wall". It suppresses radial and axial turbulence effectively. The operation procedure of CPI water control method is simple. It has been proven with lower cost and longer effective duration of controlling water, which can greatly increase oil recovery.
Results show that the water content in the well of CPI water control is only 10% to 33% of the adjacent wells at the same geological layers. The initial oil water ratio in the CPI well is 13, which is ten times better than the adjacent wells. After 2 months' production, the water content of CPI well is 13.3%, compared to 67%, 62%, and 89% of the adjacent wells.
Gao, Xiang (PetroChina Jidong Oilfield Company) | Wang, Lei (PetroChina Jidong Oilfield Company) | Tian, Jingmeng (PetroChina Jidong Oilfield Company) | Xiao, Guohua (PetroChina Jidong Oilfield Company) | Gao, Feiming (PetroChina Jidong Oilfield Company) | Liu, Xiaoxu (PetroChina Jidong Oilfield Company)
Copyright 2020, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Dhahran, Saudi Arabia, 13 - 15 January 2020. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.
Zhong, Liguo (China University of Petroleum, Beijing) | Liu, Jianbin (China University of Petroleum, Beijing) | Yuan, Xiaonan (China University of Petroleum, Beijing) | Wang, Cheng (China University of Petroleum, Beijing) | Teng, Liyong (Liaohe Oil Field Subcompany, CNPC) | Zhang, Shoujun (Liaohe Oil Field Subcompany, CNPC) | Wu, Fei (Liaohe Oil Field Subcompany, CNPC) | Shen, Wenmin (Liaohe Oil Field Subcompany, CNPC) | Jiang, Cheng (Liaohe Oil Field Subcompany, CNPC)
Summary There are a lot of sludges produced in oil production and storage processes in Liaohe Oil Field. Usually complicated chemical processes are involved in treating the sludge effectively and such surface-treatment processes are subject to high cost and environmental challenges. Therefore, the feasibility and performance of sludge injection into steam-stimulated wells, and sludge sequestration and associated heavy-oil-recovery improvement are investigated on the basis of results of laboratory research and field operation. The sludge originally produced from the reservoir comprises mainly water, some oil components, and solid phase such as mud and fine sand, and aggregation of the injected sludge components, except water, could block the void porous space. Actually, the sludge is buried into its origin, the reservoir. As the sludge is injected into the steamed reservoir through an enlarged pore at high injection pressure, the permeability of the formation could be significantly decreased (the permeability reduction rate could be more than 98% after sludge blocking in our experiments with sandpacked tubes), and the sludge blocking performance is related to the reactions of oil and solid separated from the sludge, including adherence to the sand surface, consolidation of the sands, and filling in the void porous space. Consequently, the sludge is stored in the steamed formation, and the water in the sludge is separated and produced. At the same time, steam conformance and heating efficiency could be improved by implementing a sludge blocking process, thereby significantly improving oil production. Sludge sequestration has been applied to 45 steamed wells in Shuguang Oilfield until 2018, and all the wells have been stimulated by 7-10 cycles of CSS process.