Xu, Wei (CNOOC Research Institute Co., Ltd.) | Chen, Kaiyuan (Beijing Key Laboratory of Unconventional Natural Gas Geological Evalution and Development Engineeing, China University of Geosciences Beijing) | Fang, Lei (Beijing Key Laboratory of Unconventional Natural Gas Geological Evalution and Development Engineeing, China University of Geosciences Beijing) | Zhang, Yingchun (CNOOC Research Institute Co., Ltd.) | Jing, Zhiyi (CNOOC Research Institute Co., Ltd.) | Liu, Jun (CNOOC Research Institute Co., Ltd.) | Zou, Jingyun (CNOOC Research Institute Co., Ltd.)
The lacustrine delta sandbody deposited in the north of Albert Basin is unconsolidated due to the shallow burial depth, which leads to an ultra-high permeability (up to 20 D) with large variation and poor diagenesis. Log derived permeability differs greatly with DST results. Thus, permeability simulation is challenging in 3D geomodeling. A hierarchical geomodeling approach is presented to bridge the gap among the ultra-high permeability log, model and DST results. The ultimate permeability model successfully matched the logging data and DST results into the geological model.
Based on the study of sedimentary microfacies, the new method identifies different discrete rocktypes (DRT) according to the analyis of core, thin section and conventional and special core analysis (e.g., capillary pressure). In this procedure, pore throat radius, flow zone index (FZI) and other parameters are taken into account to identify the DRT. Then, hierarchical modeling approach is utilized in the geomodeling. Firstly, the sedimentary microfacies model is established within the stratigraphic framework. Secondly, the spatial distribution model of DRT is established under the control of sedimentary microfacies. Thirdly, the permeability distribution is simulated according to the different pore-permeability relation functions derived from each DRT. Finally, the permeability model is compared with the logging and testing results.
Winland equation was improved based on the capillary pressure (Pc) data of special core analysis. It is found that the highest correlation between pore throat radius and reservoir properties was reached when mercury injection was 35%. The corresponding formula of R35 is selected to calculate the radius of reservoir pore throat. Reservoirs are divided into four discrete rock types according to parameters such as pore throat radius and flow zone index. Each rock type has its respective lithology, thin section feature and pore-permeability relationship. The ultra-high permeability obtained by DST test reaches up to 20 D, which belongs to the first class (DRT1) quality reservoir. It is located in the center of the delta channel with high degree of sorting and roundness. DRT4 is mainly located in the bank of the channels. It has a much higher shale content and the permeability is generally less than 50 mD. Through three-dimensional geological model, sedimentary facies, rock types and pore-permeability model are coupled hierarchically. Different pore-permeability relationships are given to different DRTs. After reconstructing the permeability model, the simulation results are highly matched with the log and DST test results.
This hierarchical geomodeling approach can effectively solve the simulation problem in the ultra-high permeability reservoir. It realizes a quantitative characterization for the complex reservoir heterogeneity. The method presented can be applied to clastic reservoir. It also plays a significant positive role in carbonate reservoir characterization.
Dong, Xiaohu (China University of Petroleum, Beijing) | Liu, Huiqing (China University of Petroleum, Beijing) | Lu, Ning (China University of Petroleum, Beijing) | Zheng, Aiping (Xinjiang Oilfield Company, CNPC) | Wu, Keliu (China University of Petroleum, Beijing) | Xiao, Qianhua (Chongqing University of Science & Technology) | Wang, Kung (University of Calgary) | Chen, Zhangxin (University of Calgary)
Considering the non-uniform steam conformance of conventional horizontal well, dual-pipe steam injection technique has currently demonstrated technical potential for improving heavy oil recovery. It can delay the occurrence of steam fingering and homogenize the steam injection profile along horizontal wellbore. But in some field tests, it is observed that the results were far greater than such an approach would have justified. In addition, the actual physics are still unclear, and not demonstrated. In this paper, first, we built a cylindrical wellbore physical model to experimentally study steam injection profiles of a single pipe horizontal well and a concentric dual-pipe horizontal well. Thus, the heat and mass transfer behavior of steam along horizontal well with a single-pipe well configuration and a dual-pipe well configuration was addressed. Subsequently, considering the effect of pressure drops and heat loss, a semi-analytical model for the gas-liquid two-phase flow in horizontal wellbore was developed to numerically match the experimental observation. Next, a sensitivity analysis on the physical parameters and operation properties of a steam injection process was conducted. The effect of the injection fluid type was also investigated.
Experimental results indicated that under the same steam injection condition, an application of the dual-pipe well configuration can significantly enhance the oil drainage volume by about 35% than the single-pipe well configuration. During the experiments, both a temperature distribution and liquid production along the horizontal wellbore were obtained. A bimodal temperature distribution can be observed for the dual-pipe well configuration. From this proposed model, an excellent agreement can be found between the simulation results and the experimental data. Because of the effect of variable-mass flowing behavior and pressure drops, the wellbore segment closed to the steam outflow point can have a higher heating radius than that far from the steam outflow point. From the results of sensitivity analysis, permeability heterogeneity and steam injection parameters have a tremendous impact on the steam injection profile along wellbore. Compared with a pure steam injection process, the co-injection of steam and NCG (non-condensable gas) can improve the effective heating wellbore length by over 25%. Furthermore, this model is also applied to predict the steam conformance of an actual horizontal well in Liaohe oilfield. This paper presents some information regarding the heat and mass transfer of a dual-pipe horizontal well, as well as imparts some of the lessons learned from its field operation. It plays an important role for the performance evaluation and remaining reserve prediction in a dual-pipe thermal recovery project.
This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
SPE is educating the next generation of aspiring engineers, scientists and managers about the oil and gas industry. This is an opportunity for school students in grades 9–12, studying Mathematics, Physics, Chemistry, Geography or interested in Petroleum Engineering are invited to join SPE members from all over the globe to discover the world of Petroleum Engineering. School teachers are invited to bring a group of 10–15 students. Students will be treated to a range of hands-on activities and presentations from renowned engineers. The oil price outlook coupled with the response of each oil and gas company to make ends meet has led to severe exploration budget cuts.
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.
Achieving zero harm has been the talk of the industrial sector to reduce harm to as low as possible. The management of health, safety, security and environment (HSSE) should not be stagnant. It is time to rethink and reassess how the industry can prepare, mitigate and respond to stay ahead of emerging technical, regulatory and societal challenges. This session will engage leaders to discuss opportunities and challenges, share experiences and lessons learnt, and on how technology and digitalisation may affect the quality and productivity of the work sites - all of which are critical in shaping the future of HSSE in the region. The current presentation date and time shown is a TENTATIVE schedule.