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Collaborating Authors
Results
Study of Gel Plug for Temporary Blocking and Well-Killing Technology in Low-Pressure, Leakage-Prone Gas Well
Ying, Xiong (Research Institute of Natural Gas Technology, PetroChina Southwest Oil & Gas Field Company) | Yuan, Xu (Research Institute of Natural Gas Technology, PetroChina Southwest Oil & Gas Field Company) | Yadong, Zhang (Research Institute of Natural Gas Technology, PetroChina Southwest Oil & Gas Field Company) | Ziyi, Fu (Research Institute of Natural Gas Technology, PetroChina Southwest Oil & Gas Field Company)
Summary A gel-plug system for temporary blocking technology is proposed in this paper to address the prevalent leakage of killing fluid in low-pressure wells; the low technical strength of existing gel plugs for temporary blocking in well killing; difficult-to-control crosslinking time; and gel embrittlement and the difficulty of breaking certain gel plugs. A mixture of etherified galactomannan plant gum, isooctanol polyoxyethylene ether surfactant, and oil phase was used as a thickener. An inorganic salt complex containing long-chain polyhydroxy alcohol was used as a crosslinker and the concentration of long-chain polyhydroxy alcohol far exceeds the theoretical amount required to complex the metal ion. A mixture of polyhydroxy alcohol with a small amount of weak acid was used as a crosslinking regulator. Finally, a mixture of sodium thiosulfate and long-chain quaternary ammonium salt surfactant was used as a stabilizer. Laboratory evaluations showed that this gel-plug system can be directly pumped into the wellbore after being mixed homogeneously, and the viscosity of the system on the surface can be controlled by the amount of crosslinking regulator. The viscosity of the gel-plug system after gelling was high (viscoelastic solid colloid); the initial viscosity reached 30 000 mPa·s at 120°C and retained a semisolid gel shape after aging for 72 hours. Right-angle thickening occurred when the gel warmed to target-zone temperature. The acidic liquid breaker acted quickly, and the viscosity of the broken fluid was lower than 5 mPa·s after 1 to 4 hours. This gel plug for temporary blocking and well-killing technology was successfully applied in a low-pressure, leakage-prone gas well. No gas, pressure, or liquid remained in the open well after killing, the wellhead was successfully replaced, and the tubing was successfully removed. The gel plug also exhibited self-healing: The hole formed by the tubing could be filled and sealed automatically by the gel plug in the annulus. The static friction (outer wall) of 73-mm tubing in the gel plug was 39.6 t/km; the dynamic friction (outer wall) after tubing removal was 7.2 t/km. This gel plug thus shows promise as a temporary blocking technology in workover operations of low-pressure, leakage-prone gas wells.
- North America > United States (1.00)
- Europe (0.93)
- Asia > China > Sichuan Province (0.28)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin > Yaha Field (0.99)
- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin > Hutubi Field (0.99)
- Asia > China > Sichuan > Sichuan Basin > Southwest Field > Longwangmiao Formation (0.99)
Study and Pilot Test of Multiple Thermal-Fluid Stimulation in Offshore Nanpu Oilfield
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 mPa·s 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 (CO2) and nitrogen (N2) 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 oil‐production rate and periodic‐oil production amount of the thermal wells were both greatly improved. The cumulative oil produced by multiple thermal‐fluid stimulation reached approximately 5.710 m, and the incremental oil production is approximately 2.610 m. The performance of oil production was satisfactory. As the first offshore thermal pilot area, the application experience showed that multiple thermal‐fluid stimulation was effective for exploitation of heavy oilfields. 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. Correction Notice: This paper has been updated from its originally published version to change the spelling of "Nanbao" to "Nanpu" throughout. No other changes to the paper were made.
- Research Report > New Finding (0.46)
- Overview > Innovation (0.34)
- North America > Trinidad and Tobago > North Atlantic Ocean > Eastern Venezuela Basin (0.99)
- Asia > China > Liaoning > Bohai Basin > Liaohe Basin > Liaohe Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- (3 more...)
Summary The presence of oxygen and carbon dioxide in the injection and production streams of any high-pressure-air-injection (HPAI) project or the high oxygen partial pressures associated with enriched-air-/oxygen-injection projects may create serious safety concerns such as the potential for explosion or corrosion. Compilation of field problems and reported solutions from such projects indicate that no insurmountable problems exist in the implementation of HPAI projects. Generally, the operators have implemented safe operations successfully when injecting at pressures as high as 6,000 psi. The long-term successes of the HPAI projects in the Williston basin, which were initiated in 1978 by Koch Industries and continue to be operated today by Continental Resources, have confirmed that HPAI is a viable and safe process for recovering light oils. A number of oilfield oxygen-injection projects have also been undertaken since the early 1980s, when Greenwich Oil operated the first oxygen-injection project at Forest Hills, Texas. In Canada during the 1980s, oxygen was injected by BP/AOSTRA at Marguerite Lake, by Dome Petroleum at Lindberg, by Husky Energy at Golden Lake, by Mobil Oil at Fosterton, and by Gulf Canada at Pelican. In the US, oxygen-injection pilots were operated by Arco in the Holt Sand Unit (HSU), Texas, and more recently by NiMin Energy at Pleito Creek, California. With increased oxygen partial pressure, there is a greater chance of safety or corrosion problems. In fact, the high oxygen content associated with the HSU project in west Texas caused a severe energy release that resulted in test termination. The reported data on this field are scarce, and the nature of the energy release has not been discussed in detail. This paper will first review the operational aspects of some key air-injection field tests. Then, some important details on the HSU oxygen-injection pilot test will be discussed as a case study. The reasons behind the energy release in the HSU project will be discussed by use of the surveillance data, as well as combustion-tube-test and numerical-modeling results. Finally, best practices for future operation of HPAI tests will be reviewed. This paper is intended to provide a better understanding of the safety aspects of air/oxygen handling and proper practices in such operations.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.46)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Geology > Mineral (0.46)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.41)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)
- North America > United States > Texas > East Texas Salt Basin > Forest Hill Field > Harris Sand Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Buffalo Field (0.99)
- North America > United States > South Dakota > Williston Basin (0.99)
- (6 more...)
Summary The mobility and flow distribution of liquid injected after foam control the effectiveness of foam/acid matrix well-stimulation treatments and the injectivity of liquid in many foam improved-oil-recovery processes. We present a computed-topography (CT) study of liquid injection following foam, in which both mobility and the sweep of liquid are determined directly, the latter by CT imaging. Earlier experimental work is extended in that the effects of foam quality, foam-injection rate, post-foam liquid-injection rate, and core heterogeneity on liquid mobility and displacement pattern are observed directly. CT images show that liquid fingers through foam rather than displacing it evenly. As a result, 1D models for the displacement cannot represent the process accurately. The formation of the finger is at least partly stochastic: In different experiments in the same core, with similar initial foam states, the liquid finger took markedly different paths through the core. Liquid injected after foam does not follow simply the path of mobile gas in the foam. In these experiments, post-foam brine injection was not qualitatively less effective than post-foam surfactant injection, though there were differences in both post-foam mobility and fingering pattern. Implications of field application of foam-acid diversion in matrix-stimulation treatments are discussed.
- Europe > Netherlands > South Holland (0.28)
- North America > United States > Oklahoma (0.28)
- North America > United States > California (0.28)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (0.68)