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Collaborating Authors
Xu, Jianhua
An Alternative Tool for Production Logging in Horizontal Wells
Husein, Nadir (GEOSPLIT LLC) | Xu, Jianhua (GEOSPLIT LLC) | Novikov, Igor (GEOSPLIT LLC) | Gazizov, Ruslan (GEOSPLIT LLC) | Buyanov, Anton (GEOSPLIT LLC) | Wang, Guangyu (GEOSPLIT LLC) | Lysova, Dina (GEOSPLIT LLC) | Upadhye, Vishwajit (GEOSPLIT LLC)
Abstract From year to year, well drilling is becoming more technologically advanced and more complex, therefore we observe the active development of drilling technologies, well completion and production intensification. It forms the trend towards the complex well geometry and growth of the length of horizontal sections and therefore an increase of the hydraulic fracturing stages at each well. It's obvious, that oil producing companies frequently don't have proved analytical data on the actual distribution of formation fluid in the inflow profiles for some reasons. Conventional logging methods in horizontal sections require coiled tubing (CT) or downhole tractors, and the well preparation such as drilling the ball seat causing technical difficulties, risks of downhole equipment getting lost or stuck in the well. Sometimes the length of horizontal sections is too long to use conventional logging methods due to their limitations. In this regard, efficient solution of objectives related to the production and development of fields with horizontal wells is complicated due to the shortage of instruments allowing to justify the horizontal well optimal length and the number of MultiFrac stages, difficulties in evaluating the reservoir management system efficiency, etc. A new method of tracer based production profiling technologies are increasingly applied in the global oil industry. This approach benefits through excluding well intervention operations for production logging, allows continuous production profiling operations without the necessity of well shut-in, and without involving additional equipment and personal to be located at wellsite.
Technology for Determining the Inflow from Near and Far Zones of Fractures During Hydraulic Fracturing by Chemical Tracers in a Production Well
Filev, Maksim (JSC NK Kondaneft) | Soldatov, Vadim (JSC NK Kondaneft) | Novikov, Igor (GeoSplit LLC) | Xu, Jianhua (GeoSplit LLC) | Ovchinnikov, Kirill (GeoSplit LLC) | Belova, Anna (GeoSplit LLC) | Drobot, Albina (GeoSplit LLC)
Abstract The tracer-based production logging technology can be used to obtain the well production data continuously for several years without the need for risky well interventions and expensive equipment. The paper examines the case of placing polymer-coated tracers dopped proppant in a horizontal well with ten multi-stage frac intervals and using two different tracers dopped proppant codes for two frac ports (the first and the last ones) to identify the performance of the far and near zones of a hydraulic fracture. Upon the completion of the hydraulic fracturing operations, the collected reservoir fluid samples were studied in the laboratory. Chemical tracers contained in the samples were detected by flow cytofluorometry using custom-tailored machine learning-based software. The studies helped identify the productivity of each frac port, calculate the contribution of each port in percentage points, and also evaluate the productivity of the near and far hydraulic fracture zones in the first and the last intervals. The analysis provided data on the exact content of oil and water in the production profile for each frac interval. The results of tracer-based logging in the well in question revealed that the interval productivity is changing in the course of several months of surveillance. The most productive ports and those showing increasing oil flow rate were identified during quantitative analysis. The use of tracer dopped proppant with different codes within one multi-stage frac interval enabled detecting a peak release of chemical tracers from the far fracture zone in the initial periods of well operation followed by a consistent smoothing of the far and near zones’ production profiles. Laboratory analysis of reservoir fluid samples and hydraulic fracturing simulations proved the uniform distribution of proppant across the entire reservoir pay zone and laid the foundation for further research required to better understand the fracture geometry and reduce uncertainties in production optimization operations.
- North America > United States (0.46)
- Asia > Russia (0.29)
Deep and Thin Overpressure Reservoir Characterization of Paleogene Formation Wenchang in the Enping 17 Sag of the South China Sea
Liu, Jun (CNOOC China Ltd. Shenzhen) | Li, Yingwei (CNOOC China Ltd. Shenzhen) | Liang, Donghai (Schlumberger) | Peng, Guangrong (CNOOC China Ltd. Shenzhen) | Bai, Haijun (CNOOC China Ltd. Shenzhen) | Ruan, Xiaomin (Schlumberger) | Xu, Jianhua (Schlumberger) | Zeng, Rui (Schlumberger)
Abstract Only one wildcat well had been drilled for deep formation hydrocarbon exploration (4400 m to 4800 m) and partially penetrated into Lower Paleogene Formation Wenchang (FM WC) without commercial oil discovery in the Enping 17 Sag, northern of the Pearl River Mouth Basin in the South China Sea. Although large thicknesses of grey lacustrine mudstone with abundant organic material are proven to be the regional source rock, lack of a good reservoir for hydrocarbon accumulation in FM WC is the failure reason for this well. Encountering a 9-m-thick sand layer at a depth of 4650 m indicates that braided fluvial delta and lowstand turbidite sandstone may develop in the FM WC, and the zones below upper section 1 of FM WC are proved to be overpressure. It protects pores in the deep reservoir from compaction. Condensate gas was observed by drill stem test (DST) in overpressure sand layer while no gas was measured in sand layers above the overpressure zone. Aiming at delineating effective reservoir in FM WC, an integrated workflow for 3D seismic reservoir characterization of offshore deep and thin layers was developed for this area without sufficient well data. The workflow includes seismic data reprocessing, well log-based rock physics analysis, seismic structure interpretation, 3D simultaneous amplitude variation with offset (AVO) inversion, 3D lithology prediction, and geological integrated analysis. We present four key solutions to address four specific challenges in this case study: 1) application of adaptive deghosting (AD) techniques to remove the source and streamer depth-related ghost notches in the seismic data spectrum and the bandwidth extension (BWXT) technique to improve the seismic data resolution; 2) a practical rock physics modeling approach to consider the formation overpressure for pseudo-shear sonic log prediction; 3) interactive and synchronized workflow between prestack 3D AVO inversion and seismic processing to predict a 9-m-thick layer in FM WC after 60+ rounds of cyclic tests; 4) cross validation between seismic qualitative attributes and quantitative inversion results to verify the lithology prediction result with limited well data.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.99)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.75)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Evaluating Natural Fracture Effectiveness to Optimize Well Stimulation Method for HTHP Tight Gas Reservoir
Yang, Xiangtong (PetroChina) | Xu, Jianhua (Schlumberger) | Teng, Qi (PetroChina) | Abbott, William E. (Schlumberger) | Zhang, Yang (PetroChina) | Zhao, Meng (Schlumberger) | Zhang, Chen (PetroChina) | Gu, Xiao (Schlumberger) | Li, Wei (PetroChina) | Fan, Wentong (PetroChina)
Abstract Keshen gas field, located on the northern margin of the Tarim basin, Western China, is an unconventional sandstone tight gas reservoir with extreme reservoir conditions: ultra-deep, low porosity, low matrix permeability, high temperature and high pore pressure. In order to gain economic production most wells should be stimulated to enhance single well performance. Previous studies show that natural fractures (NF) play the most important role on productivity. Detailed studies on block KS2 found that well performance is controlled by the intersection angle (θ) between NF strike and direction of the maximum horizontal stress. When the interaction angle is small, well productivity is good. Otherwise, well productivity is poor. Based on this conclusion, different simulation options were proposed: 1) Acid hydraulic fracturing for wells with small angle, and 2) Proppant hydraulic fracturing for wells with big angle. New problems were meet when we applied this rule to other blocks, such as block KS8. In this block most wells reached a good production even if the intersection angle is big (>40°). Therefore, it is unreasonable to determine stimulation options based on the intersection angle for these wells. In order to establish alternative stimulation options, deeper analyze focused on natural fractures has been conducted. First, the tectonic history was studied to understand the NF creation and it was found that natural fractures are associated with two main tectonic phases. Most of the natural fractures developed during the earliest phase are infilled by calcite or shale(set 1), Whereas NFs developed during the last phase are open or partially open, have high permeability and are contributing to the production(set 2). Wells with reticular NFs have two sets of NFs and have high production. Advanced analyses of borehole images, including fracture classification according to the tectonic events, fracture density, and intersection angle computation, allowed us to create four main classes: class 1: presence of reticular fractures, class 2: parallel fractures with small intersection angle, class 3: parallel fractures with big intersection angle, and class 4: no natural fractures. New stimulation options were proposed based on these four classes: class 1: acidizing without hydraulic fracturing, class 2: acid hydraulic fracturing, class 3: proppant hydraulic fracturing, and class 4: it is hard to get economic production for these wells, even if the proppant hydraulic fracturing is operated. These new stimulation options have been applied in new blocks of Keshen tight gas field and provide a practical way to optimize the stimulation, to ensure well performance, and to reduce the cost associated with multiple stimulation phases in this tight gas field.
- Asia > China > Xinjiang Uyghur Autonomous Region (0.70)
- North America > United States > Texas (0.46)
- Geology > Structural Geology > Tectonics (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Geophysics > Borehole Geophysics (0.90)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.34)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin > Keshen Field (0.99)
- Asia > Thailand > Gulf of Thailand > Western Basin (0.91)
Decipher Productivity Secret to Optimise Well Stimulation for Keshen Tight Gas Reservoir
Yang, Xiangtong (PetroChina Tarim Oilfield Company) | Xu, Jianhua (Schlumberger) | Zhang, Yang (PetroChina Tarim Oilfield Company) | Wang, Hao (Schlumberger) | Li, Wei (PetroChina Tarim Oilfield Company) | Wang, Lipeng (Schlumberger) | Fan, Wentong (PetroChina Tarim Oilfield Company)
Abstract Keshen Gas Field is part of Kuqa Foreland thrust belt, located in Southern foothill of Tianshan Mountain, northern margin of the Tarim basin, West China. The main pay zone, Cretaceous Bashijiqike (K1bs), has extreme reservoir conditions of ultra-deep (6500-8000 m), high temperature (170-190°C), high pressure (110-120 MPa)(HTHP). Thick salt and gypsum layers with high dip angle above the pay zone also increase safety concerns during drilling and completion. Because of its low porosity (2-7%), low matrix permeability (0.001-0.5 md) and high heterogeneity of nature fractures (NF), well production rates vary largely, ranging from zero to 300,000 m/d. Stimulation has become the only way to enhance single well performance and gain economic production for the long run. Finding controlling factors for well production and effective workflow is the key to realize efficient field development for this tight gas reservoir. In this study, an integrated workflow covering comprehensive reservoir characterization (evaluations of geology, geophysics, geomechanics and reservoir engineering), engineering design and execution (stimulation design and operation) was formulated and conducted to discover main controlling factors which influence production. Firstly, wells were divided in three groups based on their current production rates. Wells in best group have good production in DST tests and higher production after stimulation. Wells in better group have no production in DST tests but obtaining good production after stimulation. Wells in bad group have no production in DST tests, yet very low production after stimulation. Then correlate well production with structure, reservoir property, geomechanics and natural fracture properties to reveal the key controlling factors. Further study was focused on combining multiple parameters to decipher productivity secret based on multi-domain evaluation results. Lastly it was found out that the well performance in this field is controlled by both Stress and NF, i.e. the angle (θ) between NF and the maximum horizontal stress. When θ is small, well productivity is good. Otherwise well productivity is poor. According to this new finding, different stimulation methods were chosen, designed and executed in the field. Through integrated study on different levels, from core analysis to reservoir evaluation, the main factors controlling the tight gas field productivity were deciphered. Together with the understanding of the reservoir, the selection criteria for well stimulation were formulated with the intersection angleθ. After application of study results in stimulation design, gas production shows significant improvement: the average daily production rate increases 50% per well.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.35)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (0.68)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin > Keshen Field (0.99)
- Asia > Thailand > Gulf of Thailand > Western Basin (0.91)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- (3 more...)
Application of a Novel Temporary Blocking Agent in Refracturing
Xue, Shijie (ENTI PERC Petrotech Corp.) | Zhang, Zhiyong (ENTI PERC Petrotech Corp.) | Wu, Guotao (ENTI PERC Petrotech Corp.) | Wang, Yongxian (ENTI PERC Petrotech Corp.) | Wu, Jun (Tangshan Jidong Oilfield Energy Development Co. Ltd) | Xu, Jianhua (Tangshan Jidong Oilfield Energy Development Co. Ltd)
Abstract A novel temporary blocking and A novel temporary blocking agent used as diverting/re-orientation agent in refracturing was introduced in this paper[1]. Laboratory results and field application show that the agent can effectively improve the refracturing well production[2]. The temporary blocking agents include two types, fiber and granular shape. The diverting/re-orientation mechanism is that the fiber agent firstly bridge in the original old fractures, then the granular agent can further accumulate on the shaped bridge in the fracture. And the granular agent can form effective plugging because it is deformable and expandable. Then the new fractures can initiate and propagate along a new path where the direction of in-situ stress has altered after the long-term production from the old hydraulic fracture. Thus the well production can increase because the fracture extend into new oil drainage area. Both of the temporary blocking agents can be completely degraded and the degradation time is controllable, which will bring minimum damage to the formation. Laboratory results show that by "bridging and plugging" the temporary blocking agents can effectively block the old hydraulic fracture. The blocking strength can be up to 40MPa. The main factors affecting temporary blocking strength include the agent volume, size, adding timing, adding speed and manner, etc. These factors can be optimized according to the blocking requirements in fracturing designs. Field case study show that the agents can effectively "bridge and plugging" the old fracture, then the new fracture initiation can be observed obviously. Meanwhile, the production of re-fractured well increased significantly, which is much better than the previous refracturing treatment results in the same oilfield. This novel temporary blocking agents and diverting/re-orientating technology provides effective means which can enhance the controllability, success rate and effectiveness of the refracturing.
- North America > Canada (0.29)
- Asia > China (0.29)
- North America > United States > New York (0.16)
- Asia > China > Jilin > Yanji Basin > Jilin Field (0.99)
- Asia > China > Bohai Bay > Bohai Basin > Jidong Nanpu Field (0.99)
Hydraulic Fracturing in HPHT Deep Naturally Fractured Reservoir in China
Li, Yongping (ENTI PERC Oil & Gas Technology Co. Ltd.) | Xu, Jianhua (Jidong Oilfiled Co. Ltd., CNPC) | Yan, Fei (Jidong Oilfiled Co. Ltd., CNPC) | Zeng, Siyun (Nanfang E&P Company, CNPC) | Cheng, Xingsheng (ENTI PERC Oil & Gas Technology Co. Ltd.) | Zhang, Fuxiang (Tarim Oilfiled Co. Ltd., CNPC)
Abstract The KQ Foreland Thrust is a typical HP/HT deep gas reservoir in China. The production formation is often buried below 6000m, where the reservoir pore pressure is often over 110MPa and the temperature is over 150 °C. Moreover, the natural fractures richly distribute in the formation. All these factors make the hydraulic fracturing in the KQ challenging, though the fracturing is necessary because the well initial production is often lower than the economic limit production. In previous, even the 20,000psi fracturing equipment was used in the field, the wells can't be totally hydraulic fractured because of the high surface treatment pressure and the limited pumping rate. The high-density fracturing fluid is the key for HP/HT deep well fracturing, but the fluid weighted with bromide or the VES weighted with CaCl2 are both too expensive to use in the field. So a new fracturing fluid system weighted with nitrate is developed to lower the treatment pressure. The new delayed cross-linked fluid system is high temperature-stability and shearing resistance, and the density can reach 1.35 g/cm3. More important, the cost of new fluid is only 1/5 of the fluid weighted with bromide. Other measures were adopted to ensure the treatment safety and success, such as larger ID pumping tubing, 20,000 psi fracturing equipment and Christmas tree, proppant slug, et al. Nine layers in six wells were successfully fractured with integrated measures. And the stimulated deepest well is 6988m, and the highest treatment pressure is 136MPa. The well production after fracturing increased by 3 times comparing with the initial production. This makes the well can be economically developed. These series of technology will provide reference for the similar HP/HT reservoir fracturing to significantly increase the well production.
- Asia > China (0.71)
- North America > United States > Texas (0.70)
- Geology > Geological Subdiscipline > Geomechanics (0.70)
- Geology > Mineral > Halide (0.55)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > HP/HT reservoirs (1.00)