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Collaborating Authors
Tarim Basin
Summary Produced water (PW) is an undesirable byproduct generated from oil and natural gas production. Due to the large volume produced, managing its disposal is challenging. Generally, PW is used internally for oil and gas operations while different types of means dispose of the remaining volumes. Recently, there has been a need to repurpose the volume of water customarily disposed of for other industries’ applications. This presents a potential opportunity to reduce excessive freshwater usage in oil and gas operations and reduce water depletion in other industries, thus aiding water conservation as one of the goals for sustainable development. While the external uses are the viable and logical solution, there are challenges relating to PW characterization, treatment technology, and economics of such a project. Therefore, the effective treatment technology, utilization, and disposal of PW remain critical issues for the petroleum industry with consideration of the environment, technical aspects, and economics. There must be collaboration among all stakeholders to harness the potential opportunities and merits of external reuse of PW for cost-effective and environmentally sustainable solutions in treatment technology and every other aspect of PW management. This review presents a comprehensive overview of PW management, current practices in the petroleum industry, and opportunities to be used in other sectors. A detailed account of each disposal method and possible external uses are enumerated with associated challenges, and how these can be mitigated.
- South America (1.00)
- North America > United States > Texas (1.00)
- Europe (1.00)
- (2 more...)
- Overview (1.00)
- Research Report > New Finding (0.46)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Reuse (0.68)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (34 more...)
- Production and Well Operations > Well Operations and Optimization > Produced water management and control (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Pressure Transient Behaviors of Discretely Fractured Reservoirs Using a Numerical Discrete Fracture Model
Chen, Zhiming (China University of Petroleum at Beijing (Corresponding author)) | Zhou, Biao (China University of Petroleum at Beijing) | Zhang, Shaoqi (China University of Petroleum at Beijing) | Yu, Wei (The University of Texas at Austin)
Summary The conventional dual-porosity model (Warren and Root 1963) may not apply to naturally fractured reservoirs (NFRs), which have poorly connected fractures. To narrow this gap, a new discrete fracture model (DFM)-based numerical well-testing model is developed for pressure transient analysis in vertical wells interacting with natural fractures (NFs). The numerical model is based on a DFM and unstructured perpendicular bisector (PEBI) grid system. The accuracy and practicality of the proposed model have been demonstrated by model verifications with a commercial numerical software. The results show that the flow regimes of the vertical well interacting with NFs can be divided into wellbore storage and skin effects, bilinear flow, linear flow, radial flow, NF effect, and boundary-dominated flow. This is the radial flow of the formation before pressure propagates to NFs, which is virtually quite different from that in the conventional dual-porosity model. However, there are no bilinear and linear flow stages in the vertical well interacting with no NFs. It is found that the vertical well interacting with NFs has a lower pressure depletion. It is also found that the “V-shape” caused by the NF effect in the pressure derivative curve becomes deeper when there are more NFs, longer NFs, and higher fracture conductivity. Furthermore, the “V-shape” appears earlier, and the duration of the NF effect is longer as the number of NFs increases. Besides, with the decrease of the distance between the fracture and the well, the impacts of NFs on pressure transient behaviors of the vertical well are more significant. This work provides a meaningful way to understand the pressure transient behaviors of discrete NFs.
- Asia (0.94)
- North America > United States > Texas (0.46)
- Geology > Geological Subdiscipline (0.47)
- Geology > Rock Type (0.46)
A Model Ranking Approach for Liquid Loading Onset Predictions
Jia, Hao (China University of Petroleum–Beijing) | Zhu, Jianjun (China University of Petroleum–Beijing (Corresponding author)) | Cao, Guangqiang (China National Petroleum Corporation) | Lu, Yingda (University of Texas at Austin) | Lu, Bo (University of Pennsylvania) | Zhu, Haiwen (University of Tulsa (Corresponding author))
Summary As a natural gas well ages, liquid loading is frequently encountered, leading to the decrease of gas production rate and many other side effects, which may in turn cease the gas production. Thus, to accurately predict liquid loading onset is of significant importance in gas wells for the sake of stable production. With years of research and development in the natural gas industry, the liquid loading onset prediction models prevail in the existing literature. Based on varying mechanisms (e.g., droplet falling back, liquid film reversal, etc.), the critical gas velocities or flow rates corresponding to flow pattern transitions in gas wells can then be calculated. However, a universally validated model, whether empirical or non-empirical, that is applicable to predict the onset of liquid loading in versatile gas wells conditions (e.g., horizontal, vertical, and inclined) is, as yet, still unavailable. In this paper, we conduct a complete literature review and investigation of these existing liquid loading onset prediction models. First, we obtained detailed information of more than 600 gas wells, including well geometries, gas properties, operation conditions, and so on, from different gas fields. Then, we evaluate the validity of various liquid loading onset prediction models by use of a novel model ranking approach. To fully account for the effects of gas well properties (including but not limited to production, wellhead pressure, and pipe diameter) to the model prediction accuracy, the proposed method in this paper employs data clustering and normalization techniques, as well as the statistical relative error analysis, to rank and select the best suitable model for each specific gas well. Extensive comparison and verification of the ranking approach indicate that the proposed method provides a good reference for the rational production allocation and stable production of gas wells.
- Asia > China (1.00)
- North America > United States > Texas (0.68)
- Research Report (0.68)
- Overview (0.67)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Numerical Study on Mechanism and Parameters Optimization of Temporary Plugging by Particles in Wellbore
Zhang, Tao (Southwest Petroleum University) | Li, Ming (Southwest Petroleum University (Corresponding author)) | Guo, Jianchun (Southwest Petroleum University) | Gou, Haoran (Southwest Petroleum University) | Mu, Kefan (Southwest Petroleum University)
Summary The temporary plugging by particles in the wellbore can open new perforation clusters and increase stimulated reservoir volume, but the temporary plugging process of particles is not clear. Therefore, in this paper, we take an ultradeep well in the Tarim Basin as the research object and establish a numerical model based on the coupled computational fluid dynamics-discrete element technology (CFD-DEM) approach, which accurately describes the movement process and mechanism of the temporary plugging particles in the wellbore. Furthermore, the influence of flow rate, concentration of injected particles, and the injected mass ratio of particle size on the temporary plugging effect were studied, respectively. In addition, based on the results of the orthogonal experimental analysis, we obtained the pump rate as the primary factor affecting the effect of temporary plugging, and we recommended the optimal operation parameters for temporary plugging by particles in the field: The pump rate is 2 m/min, the concentration of the injected temporary plugging particles is 20%, and the ratio of the mass of the injected temporary plugging particles with particle size 1 to 5 mm to the mass of the temporary plugging particles with particle size 5 to 10 mm is 3:1. Finally, a single well that had implemented temporary plugging by particles was used to verify the recommended optimal temporary plugging operation parameters. The research results of this paper provide important guidance and suggestions for the design of temporary plugging schemes on the field.
- North America > United States > Texas (0.28)
- Asia > China > Xinjiang Uyghur Autonomous Region (0.24)
- Research Report > New Finding (0.87)
- Research Report > Experimental Study (0.66)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin (0.99)
- North America > Canada > Alberta > Hill Field > Aecog (W) Et Al Clearwatr 9-5-86-11 Well (0.97)
Numerical Study on Particle Transport and Placement Behaviors of Ultralow Density Particles in Fracture-Vuggy Reservoirs
Zhang, Tao (College of Petroleum and Natural Gas Engineering, Southwest Petroleum University, Chengdu (Corresponding author)) | Gou, Haoran (College of Petroleum and Natural Gas Engineering, Southwest Petroleum University, Chengdu) | Mu, Kefan (College of Petroleum and Natural Gas Engineering, Southwest Petroleum University, Chengdu) | Guo, Jianchun (College of Petroleum and Natural Gas Engineering, Southwest Petroleum University, Chengdu) | Yang, Ruoyu (College of Petroleum and Natural Gas Engineering, Southwest Petroleum University, Chengdu) | Li, Ming (College of Petroleum and Natural Gas Engineering, Southwest Petroleum University, Chengdu)
Summary A solid/liquid two-phase flow numerical model based on the computational fluid dynamics-discrete element method (CFD-DEM) model was established to study the transport and settlement law of ultralow-density (ULD) particles during the waterdrive channel adjustment of the Tahe carbonate fractured-vuggy reservoir. The mass, momentum, and turbulence equations of the fluid phase were established in Euler coordinates, whereas the particle motion equations were established based on Newton's second law. The interaction between the ULD particles was described using a soft sphere model, and the water and particle phases were bidirectionally coupled. Meanwhile, virtual experiments were conducted to calibrate the contact parameters of the particles, and parallel plate experiments were performed to validate the model. Using numerical simulations of particle transport behavior in fractures, the process and characteristics of particle transport and placement in fractures are demonstrated, which can be described by the settlement profile angle and equilibrium gap height. According to parameterized simulations, the change law of the settlement profile angle and equilibrium gap height with different parameters such as particle size, pump displacement, and fracture width are demonstrated, which is helpful for the prediction of migration and accumulation of ULD particles in fracture-vuggy reservoirs. Introduction Carbonate reservoirs have broad development prospects that contain over 60% of the world's oil and gas resources. By the end of 2015, China's total proven geological reserves of carbonate reservoirs were 29.34 10 The Ordovician reservoir in the Tahe oilfield is the largest carbonate fractured-vuggy reservoir in China. The reservoir space comprises large-scale karst caves and fracture-level dissolution pores with an average fracture density of 3-4 fractures per meter, which are characterized by discontinuous distribution, complex connection, and strong heterogeneity (Yang 2013; Li et al. 2016, 2017; Jiao 2019).
- North America > United States > Texas (0.46)
- Asia > China > Xinjiang Uyghur Autonomous Region (0.34)
Numerical Study on Mechanism and Parameters Optimization of Temporary Plugging by Particles in Wellbore
Zhang, Tao (Southwest Petroleum University) | Li, Ming (Southwest Petroleum University (Corresponding author) | Guo, Jianchun (email: liming0785@126.com)) | Gou, Haoran (Southwest Petroleum University) | Mu, Kefan (Southwest Petroleum University)
Summary The temporary plugging by particles in the wellbore can open new perforation clusters and increase stimulated reservoir volume, but the temporary plugging process of particles is not clear. Therefore, in this paper, we take an ultradeep well in the Tarim Basin as the research object and establish a numerical model based on the coupled computational fluid dynamics-discrete element technology (CFD-DEM) approach, which accurately describes the movement process and mechanism of the temporary plugging particles in the wellbore. Furthermore, the influence of flow rate, concentration of injected particles, and the injected mass ratio of particle size on the temporary plugging effect were studied, respectively. In addition, based on the results of the orthogonal experimental analysis, we obtained the pump rate as the primary factor affecting the effect of temporary plugging, and we recommended the optimal operation parameters for temporary plugging by particles in the field: The pump rate is 2 m/min, the concentration of the injected temporary plugging particles is 20%, and the ratio of the mass of the injected temporary plugging particles with particle size 1 to 5 mm to the mass of the temporary plugging particles with particle size 5 to 10 mm is 3:1. Finally, a single well that had implemented temporary plugging by particles was used to verify the recommended optimal temporary plugging operation parameters. The research results of this paper provide important guidance and suggestions for the design of temporary plugging schemes on the field.
- North America > United States > Texas (0.28)
- Asia > China > Xinjiang Uyghur Autonomous Region (0.24)
- Research Report > New Finding (0.87)
- Research Report > Experimental Study (0.66)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin (0.99)
- North America > Canada > Alberta > Hill Field > Aecog (W) Et Al Clearwatr 9-5-86-11 Well (0.97)
Predicting Sand Production Rate in High-Pressure, High-Temperature Wells in the Tarim Basin
Liu, Hongtao (PetroChina Tarim Oilfield Company) | Wang, Haotian (University of Texas at Austin) | Zhang, Wei (PetroChina Tarim Oilfield Company) | Liu, Junyan (PetroChina Tarim Oilfield Company) | Zhang, Yutao (Chengdu Zhongpu Oil & Gas Technology Co., Ltd.) | Sharma, Mukul M. (University of Texas at Austin)
Summary Sand production has been a very serious concern for the high-pressure, high-temperature (HPHT) gas wells in the Tarim Basin. However, the possible reasons and mechanisms remain unclear because there is no sufficient model to predict both onset of sanding and sand‐production rate. The objective of this study is to develop a three‐dimensional (3D) numerical sand production‐prediction model and apply it to these HPHT gas wells to determine the main mechanisms for sand production and to propose completion designs to minimize sand production. This paper presents the development of a fully coupled 3D, poro‐elasto‐plastic sand‐production model and the simulation results for two key wells that are prone to sanding. The sand‐production model was used to model the different completion designs and flowback strategies that were used in the field. The model couples multiphase fluid flow and elasto‐plasticity to simulate pressure transient behavior and rock deformation during production. The sanding criterion is a combination of both mechanical failure (shear/tensile/compressive failure) and fluid erosion. A novel cell‐removal algorithm has been implemented to predict the dynamic (time dependent) sand‐production process. In addition, the complex geometry of the wells and perforations are explicitly modeled to show cavity propagation around hole/perforations during sand production. For this case study, triaxial tests on core samples were conducted, and the stress‐strain curves under different confining stresses are analyzed to obtain rock properties for both the preyield and post‐yield period. The wells were categorized into ones that had massive sand production and ones that showed much less sand production. Operational and mechanical factors that were empirically found to result in sand production were identified. The sand‐production model was run to verify the role played by different factors. It is shown that completion design, rock strength, and post‐failure behavior of the rock are key factors responsible for the observed sanding in these wells. In addition, the drawdown strategy and the associated bottomhole pressure (BHP) change and the extent of depletion play an important role in the sanding rate. Several strategies for minimizing sand production are suggested for these wells. These include drawdown management, completion, and perforation design. In this study, we show for the first time that data from HPHT gas wells that have severe sand‐production problems can be analyzed quantitatively with the developed model to determine the mechanisms of sand production. This allows us to make operational recommendations to minimize sanding risk in these wells.
- Europe (1.00)
- North America > United States > Texas (0.93)
- Asia > China > Xinjiang Uyghur Autonomous Region (0.60)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.67)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 23/26 > Erskine Field (0.99)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin (0.99)
- Asia > Thailand > Gulf of Thailand > Western Basin (0.91)
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)
The Potential of Using Cr3+/Salt-Tolerant Polymer Gel for Well Workover in Low-Temperature Reservoir: Laboratory Investigation and Pilot Test
Jia, Hu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation at Southwest Petroleum University) | Chen, Hao (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation at Southwest Petroleum University)
Summary Using mature Cr/partially hydrolyzed polyacrylamide (HPAM) gel can reduce filtration for water shutoff in the fractured reservoir. Whether the mature gel can act as a fluid-loss-control pill for well-workover operation is worth investigating. In this paper, we start a systematic experimental study to reveal the physical process and fluid-loss-control mechanism of the Cr/KYPAM (salt-tolerant polymer) gel used for overbalanced well workover. The polymer gel used in this study is formulated with a combination of 0.4 to 0.6 wt% KYPAM and added 0.02 to 0.04 wt% chromium acetate, which can provide a gelation time between 2 and 4 hours, and with a maximum gel strength of Code G at a temperature of 30°C. Results show that the mature Cr/KYPAM gel can withstand positive pressure of 10 MPa for a period of 120 minutes with average fluid-loss volume of 15 cm for the core permeability between 9.18 and 217 md, indicating a favorable fluid-loss-control performance. The regained-permeability recovery can reach up to 85% for different core permeabilities. Scanning-electron-microscope (SEM) pictures show that a dense structure was formed in the gel filter cake during fluid-loss experiment. The wettability results show that the core has a greater potential to increase its water-wet ability after interacting with Cr/KYPAM mature gel. Field test shows that a small amount of gel leakoff was observed during each reperforation process, whereas water cut decreased from 89.1 to 52.1% and oil production increased from 0.15 to 1.11 m/d. This study suggests that the mature Cr/KYPAM gel can act as a fluid-loss-control pill in high-water-cut oil wells, which can provide an avenue to bridge the design philosophy of well workover and water shutoff.
- Asia > China (0.93)
- Europe (0.93)
- North America > United States > Louisiana (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
A Comparative Research of Microwave, Conventional-Heating, and Microwave/Chemical Demulsification of Tahe Heavy-Oil-in-Water Emulsion
Sun, N. N. (Petroleum Engineering College, Xi’an Shiyou University) | Jiang, H. Y. (Petroleum Engineering College, Xi’an Shiyou University) | Wang, Y. L. (Petroleum Engineering College, Xi’an Shiyou University) | Qi, A. J. (Petroleum Engineering College, Xi’an Shiyou University)
Summary We consider the emulsion stabilized by organic base and compound surfactants too stable to separate automatically. To obtain an efficient demulsification technique, the influences of microwave-radiation, conventional-heating, and microwave/chemical methods on the demulsification of heavy-oil-in-water (O/W) emulsions were investigated separately. The results showed that as microwaveradiation time increased, the water-separation rate increased initially and then decreased; with increasing microwave-radiation power, the water-separation rate increased sharply first and then increased moderately; and for both microwave and conventional heating, a higher temperature did not imply a better demulsification effect. In addition, the demulsification efficiency was higher and the separated water was clearer by use of the microwave/chemical approach, which needs less demulsifier in a shorter time for O/W emulsion. Introduction With the contradiction between an increase in global-energy consumption and a decline in conventional oil production, heavy crude oils have been presented as a relevant hydrocarbon resource for use in the future. However, the demand for heavy crude oil has been minimal because of its high viscosity and complex composition, which make it difficult to produce, transport, and refine. To be suitable for transportation from reservoir to refinery with conventional pipelines, a favorable pipeline technique is the transport of viscous crude oils as an O/W emulsion (Simon and Poynter 1970; Ahmed et al. 1999). In this method, the oil phase is dispersed in the water phase to favorably reduce the friction force of heavy crude oils. However, it is necessary to realize the demulsification when the emulsion is transported to the pipeline terminal.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Oil/Grease/Xylene/Methanol (0.61)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin > Tahe Field (0.99)
- Asia > Pakistan > Missan Field (0.98)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (0.85)