He, Youwei (China University of Petroleum, Beijing) | Cheng, Shiqing (China University of Petroleum, Beijing) | Chai, Zhi (Texas A&M University) | Patil, Shirish (King Fahd University of Petroleum and Minerals) | Rui, Ray (Massachusetts Institute of Technology) | Yu, Haiyang (China University of Petroleum, Beijing)
Applications of cluster wells and hydraulic fracturing enable commercial productivity from unconventional reservoirs. However, well productivity decrease rapidly for this type of reservoirs, and in many cases, it is difficult to maintain a productivity that is economical. Enhanced oil recovery (EOR) is therefore needed to improve well performance. Traditional fluid injection from other wells are not feasible due to the ultra-low permeability, and fluid Huff-n-Puff also fails to meet the expected recovery. This work investigates the feasibility of the inter-fracture injection and production (IFIP) approach to increase oil production of multiple multi-fractured horizontal wells (MFHW).
Three MFHWs are considered in a cluster well. Each MFHW includes injection fractures (IFs) and recovery fractures (RFs). The fractures with even and odd indexes are assigned to be IFs or RFs, respectively. The injection/production schedule falls into two categories: synchronous inter-fracture injection and production (s-IFIP) and asynchronous inter-fracture injection and production (a-IFIP). To analyze the well performance of multiple MFHWs using the IFIP method, this work performs numerical simulation based on the compartmental embedded discrete fracture model (cEDFM) and compares the production performance of three MFHWs using four different producing methods (i.e., primary depletion, CO2 Huff-n-Puff, s-IFIP, and a-IFIP). Although the number of producing fractures is reduced by about 50% for s-IFIP and a-IFIP, they achieve much higher oil rates than primary depletion and CO2 Huff-n-Puff. Sensitivity analysis is performed to investigate the impact of parameters on the IFIP. The fracture spacing between IFs and RFs, CO2 injection rates, and connectivity of fracture networks affect the oil production significantly, followed by length of RFs, well spacing among MFHWs and length of IFs. The suggested well completion scheme is presented for the a-IFIP and s-IFIP methods. This work demonstrates the ability of the IFIP method in enhancing oil production of multiple MFHWs in unconventional reservoirs.
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.
Xu, Zhengming (China University of Petroleum, Beijing) | Wu, Kan (Texas A&M University) | Song, Xianzhi (China University of Petroleum, Beijing) | Li, Gensheng (China University of Petroleum, Beijing) | Zhu, Zhaopeng (China University of Petroleum, Beijing) | Sun, Baojiang (China University of Petroleum, East China)
Energized fracturing fluids, including foams, carbon dioxide (CO2), and nitrogen (N2), are widely used for multistage fracturing in horizontal wells. However, because density, rheology, and thermal properties are sensitive to temperature and pressure, it is important to understand the flow and thermal behaviors of energized fracturing fluids along the wellbore. In this study, a unified steady-state model is developed to simulate the flow and thermal behaviors of different energized fracturing fluids and to investigate the changes of fluid properties from the wellhead to the toe of the horizontal wellbore. The velocity and pressure are calculated using continuity and momentum equations. Temperature profiles of the whole wellbore/formation system are obtained by simultaneously solving energy equations of different thermal regions. Temperature, pressure, and energized-fluid properties are coupled in both depth and radial directions using an iteration scheme. This model is verified against field data from energized-fluid-injection operations. The relative average errors for pressure and temperature are less than 5%. The effects of injection pressure, mass-flow rate, annulus-fluid type, foam quality, and proppant volumetric concentration on pressure and temperature distributions are analyzed. Influence degrees of these operating parameters on the bottomhole pressure (BHP) for different energized fracturing fluids are calculated. The required injection parameters at the surface to achieve designed bottomhole treating parameters for different energized fracturing fluids are compared. The results of this study might help field operators to select the most-suitable energized fluid and further optimize energized-fluid-fracturing treatments.
Liu, Yigang (CNOOC China Ltd, Tianjin Branch) | Zou, Jian (CNOOC China Ltd, Tianjin Branch) | Han, Xiaodong (CNOOC China Ltd, Tianjin Branch) | Wang, Qiuxia (CNOOC China Ltd, Tianjin Branch) | Zhang, Hua (CNOOC China Ltd, Tianjin Branch) | Liu, Hao (CNOOC China Ltd, Tianjin Branch) | Wang, Hongyu (CNOOC China Ltd, Tianjin Branch) | Wu, Wenwei (China University of Petroleum, Beijing) | Wang, Cheng (China University of Petroleum, Beijing)
Steam and flue gas stimulation technology has been applied for heavy oil exploitation in Bohai Oilfield for almost ten years. For the special fuel and water requirement of the current thermal generator, large amount of diesel and desalinated seawater are needed during the thermal injection process. Besides, treatment of the produced oily wastewater on the platform becomes more difficult as the oil output increases.
Aimed at solving the existing problems and taking the advantage of characteristics of the supercritical water, a new type of supercritical steam and flue gas generator for offshore oilfield is proposed and studied. The newly proposed generator is mainly consisted of two sections, which are the supercritical water gasification reactor and combustion reactor, respectively. The produced oily wastewater could be directly used for steam generation. A series of experiments are carried out for its feasibility research and structure optimization.
A prototype of the generator is made for indoor experiment. During the gasification process, wastewater and the organic material mixed inside is placed in the supercritical conditions in the gasification reactor whose temperature and pressure are about 600-700°C and 23MPa, respectively. And the reaction product would be mainly H2, CO2 and water. Gasification Experiments of both the diesel and oily wastewater are conducted. And the combustion experiment is also conducted and the gasified gas is reacted with O2 under conditions of 25MPa and 500-550°C. Composition of the produced fluid in each experiments are analyzed. Besides, the structure of the generator is also designed and optimized for improving its working efficiency.
The proposed new-type supercritical steam and flue gas generator has the characteristics of high efficiency, waste water treatment and higher temperature and pressure delivery capacity. And there would be a promising perspective for its application on offshore platform.
Non-Darcy flow and the stress-sensitivity effect are two fundamental issues that have been widely investigated in transient pressure analysis for fractured wells. The main object of this work is to establish a semianalytical solution to quantify the combined effects of non-Darcy flow and stress sensitivity on the transient pressure behavior for a fractured horizontal well in a naturally fractured reservoir. More specifically, the Barree-Conway model is used to quantify the non-Darcy flow behavior in the hydraulic fractures (HFs), while the permeability modulus is incorporated into mathematical models to take into account the stress-sensitivity effect. In this way, the resulting nonlinearity of the mathematical models is weakened by using Pedrosa’s transform formulation. Then a semianalytical method is applied to solve the coupled nonlinear mathematical models by discretizing each HF into small segments. Furthermore, the pressure response and its corresponding derivative type curve are generated to examine the combined effects of non-Darcy flow and stress sensitivity. In particular, stress sensitivity in HF and natural-fracture (NF) subsystems can be respectively analyzed, while the assumption of an equal stress-sensitivity coefficient in the two subsystems is no longer required. It is found that non-Darcy flow mainly affects the early stage bilinear and linear flow regime, leading to an increase in pressure drop and pressure derivative. The stress-sensitivity effect is found to play a significant role in those flow regimes beyond the compound-linear flow regime. The existence of non-Darcy flow makes the effect of stress sensitivity more remarkable, especially for the low-conductivity cases, while the stress sensitivity in fractures has a negligible influence on the early time period, which is dominated by non-Darcy flow behavior. Other parameters such as storage ratio and crossflow coefficient are also analyzed and discussed. It is found from field applications that the coupled model tends to obtain the most-reasonable matching results, and for that model there is an excellent agreement between the measured and simulated pressure response.
Liu, Yongsheng (China University of Petroleum, Beijing) | Gao, Deli (China University of Petroleum, Beijing) | Li, Xin (China University of Petroleum, Beijing) | Qin, Xing (China University of Petroleum, Beijing) | Li, He (China University of Petroleum, Beijing) | Liu, Hang (Yibin Natural Gas Development Company Limited)
Jet comminuting technology has proved to be an effective means of solid particle pulverization, and current research attempts to introduce it for drilling work to reduce cuttings size, because smaller cuttings are easy to circulate out of the bottom, thus can effectively prevent the formation of cuttings bed, especially in horizontal drilling. In this paper, the feasibility of cuttings’ comminution by jet is studied by means of numerical simulation with secondary development. The coupling analysis methods—including the computational-fluid-dynamics/discrete-element-model (CFD/DEM) modeling for the interaction between fluid and cuttings and the particle replacement and bonding modeling for cuttings breakage—are used to characterize the jet comminuting process of cuttings. Input parameters of simulation are reliable and verified by uniaxial compression tests. Case studies presented here indicate that cuttings can be considerably accelerated by 20 to 30 m/s through the throat, which provides a good effective speed for the cuttings. After being accelerated by the fluid and crushed with the target, the vast majority of cuttings results in smaller debris. Also, increasing the inlet speed affects the crushing efficiency. The inclination of the target at near 65 shows good results. This paper proposes a new perspective to introduce the jet comminuting technique for drilling operations, and its findings could help in guiding engineering design in the future.
Modern multifractured shale-gas/oil wells are horizontal wells completed with simultaneous-fracturing, zipper-fracturing, and (in particular) modified-zipper-fracturing techniques. An analytical model was developed in this study for predicting the long-term productivity of these wells under conditions of pseudosteady-state (PSSS) flow, considering the cross-bilinear flow in the rock matrix and hydraulic fractures. Performance of the model was verified with the well-productivity data obtained from a shale-gas well and a shale-oil well. Sensitivity analyses were performed to identify key parameters of hydraulic fracturing affecting well productivity. The conducted field case studies show that the analytical model overpredicts shale-gas-well productivity by 2.3% and underpredicts shale-oil productivity by 7.4%. A sensitivity analysis with the model indicates that well productivity increases with reduced fracture spacing, increased fracture length, and increased fracture width, but not proportionally. Whenever operational restrictions permit, more fractures with high density should be created in the hydraulic-fracturing process to maximize well productivity. The benefit of increasing fracture width should diminish as the fracture width becomes large. Increasing fracture length by pumping more fracturing fluid can increase well-production rate nearly proportionally. Therefore, it is desirable to create long fractures by pumping high volumes of fracturing fluid in the hydraulic-fracturing process.
Xiong, Hao (University of Oklahoma) | Huang, Shijun (China University of Petroleum, Beijing) | Devegowda, Deepak (University of Oklahoma) | Liu, Hao (China University of Petroleum, Beijing) | Li, Hao (University of Oklahoma) | Padgett, Zack (Univiersity of Oklahoma)
Hao Xiong, University of Oklahoma; Shijun Huang, China University of Petroleum, Beijing; Deepak Devegowda, University of Oklahoma; Hao Liu, China University of Petroleum, Beijing; and Hao Li and Zack Padgett, University of Oklahoma Summary Steam-assisted gravity drainage (SAGD) is the most-effective thermal recovery method to exploit oil sand. The driving force of gravity is generally acknowledged as the most-significant driving mechanism in the SAGD process. However, an increasing number of field cases have shown that pressure difference might play an important role in the process. The objective of this paper is to simulate the effects of injector/producer-pressure difference on steam-chamber evolution and SAGD production performance. A series of 2D numerical simulations was conducted using the MacKay River and Dover reservoirs in western Canada to investigate the influence of pressure difference on SAGD recovery. Meanwhile, the effects of pressure difference on oil-production rate, stable production time, and steam-chamber development were studied in detail. Moreover, by combining Darcy's law and heat conduction along with a mass balance in the reservoir, a modified mathematical model considering the effects of pressure difference is established to predict the SAGD production performance. Finally, the proposed model is validated by comparing calculated cumulative oil production and oil-production rate with the results from numerical and experimental simulations. The results indicate that the oil production first increases rapidly and then slows down when a certain pressure difference is reached. However, at the expansion stage, lower pressure difference can achieve the same effect as high pressure difference. In addition, it is shown that the steam-chamber-expansion angle is a function of pressure difference. Using this finding, a new mathematical model is established considering the modification of the expansion angle, which (Butler 1991) treated as a constant. With the proposed model, production performance such as cumulative oil production and oil-production rate can be predicted. The steam-chamber shape is redefined at the rising stage, changing from a fanlike shape to a hexagonal shape, but not the single fanlike shape defined by (Butler 1991). This shape redefinition can clearly explain why the greatest oil-production rate does not occur when the steam chamber reaches the caprock.
Li, Xiaojiang (China University of Petroleum, Beijing, and Sinopec Research Institute of Petroleum Engineering) | Li, Gensheng (China University of Petroleum, Beijing) | Sepehrnoori, Kamy (University of Texas at Austin) | Yu, Wei (Texas A&M University) | Wang, Haizhu (China University of Petroleum, Beijing) | Liu, Qingling (China University of Petroleum, Beijing) | Zhang, Hongyuan (China University of Petroleum, Beijing) | Chen, Zhiming (China University of Petroleum, Beijing)
The push to extend fracturing to arid regions is drawing attention to water-free techniques, such as liquid/supercritical carbon dioxide (CO2) fracturing. It is important to understand CO2 flow behavior and thus to estimate the friction loss accurately in CO2 fracturing, but no focus on CO2 friction loss in large-scale tubulars has been made until now. Because of the difficulty in conducting field-scale experiments, we develop a computational-fluid-dynamics (CFD) model to simulate CO2 flow in circular pipes in this paper. The realizable k-e turbulence model is used to simulate the large-Reynolds-number fully turbulent flow. An accurate equation of state (EOS) and transport models of CO2 are used to account for CO2-properties variations with pressure and temperature. The roughness of the pipe wall also is considered. Our model is verified by comparing the simulation results with the experimental data of liquid CO2 and correlations developed for water-based fluid. It is confirmed that the friction loss of CO2 follows the phenomenological Darcy-Weisbach equation, regardless of the sensitivity of CO2 properties to pressure and temperature. The commonly used correlations also can give good predictions of the Darcy friction factor of CO2 within an acceptable tolerance of 4.5%, where the pressure range is 8 to 80 MPa, the temperature range is 250 to 400 K, the tubular-diameter range is 25.4 to 222.4 mm, and the Reynolds-number range is 105–108. Of all correlations used in this paper, the ones proposed by Colebrook and White (1937), Swamee and Jain (1976), Churchill (1977), and Haaland (1983) are recommended for field use. Finally, we investigate the influence of flowing pressure and temperature on Reynolds number, Darcy friction factor, and friction loss of CO2, and compare the difference between friction loss of water and of CO2 at different pressure, temperature, and flow-rate conditions.
Guo, Hu (China University of Petroleum, Beijing) | Li, Yiqiang (China University of Petroleum, Beijing) | Kong, Debin (China University of Petroleum, Beijing) | Ma, Ruicheng (China University of Petroleum, Beijing) | Li, Binhui (China University of Petroleum, Beijing) | Wang, Fuyong (China University of Petroleum, Beijing)
Although the alkali/surfactant/polymer (ASP) flooding technique used for enhanced oil recovery (EOR) was put forward many years ago, it was not until 2014 that it was first put into practice in industrial applications with hundreds of injectors and producers in the Daqing Oil Field in China. In this study, 30 ASP-flooding field tests in China were reviewed to promote the better use of this promising technology. Up to the present, ASP flooding in the Daqing Oil Field deserves the most attention.
Alkali type does affect the ASP-flooding effect. Strong alkali [using sodium hydroxide (NaOH)] ASP flooding (SASP) was given more emphasis than weak alkali [using sodium carbonate (Na2CO3)] ASP flooding (WASP) for a long time in the Daqing Oil Field because of the lower interfacial tension (IFT) of the surfactant and the higher recovery associated with NaOH than with Na2CO3. Other ASP-flooding field tests completed in China all used Na2CO3. With progress in surfactant production, a recent large-scale WASP field test in the Daqing Oil Field produced an incremental oil recovery nearly 30% higher than most previous SASP recoveries and close to the value of the most-successful SASP test. However, the most-successful SASP test was partly attributed to the weak alkali factor. Recent studies have shown that the WASP incremental oil recovery factor could be as good as that of SASP but with much-better economic benefits.
Screening of surfactant by IFT test is very important in the ASP-flooding practice in China. Whether dynamic or equilibrium IFT should be selected as criteria in surfactant screening is still in dispute. Many believe the equilibrium IFT is more important than the dynamic IFT in terms of the displacement efficiency; thus, it is better to choose a lower dynamic IFT when the equilibrium IFT meets the 10–3 order-of-magnitude requirement. However, it is impossible for many surfactants to form ultralow equilibrium IFT. Because of the low acid value of the Daqing crude oil, the asphaltene and resin components play a very important role in reducing the oil/water IFT and asphaltene is believed to be more influential, although more work is required to resolve this controversial issue.
Whether polymer viscoelasticity can reduce the residual oil saturation is still a matter of debate. Advances in surfactant production and in the overcoming of scaling and produced-fluid-handling challenges form the foundation of the industrial application of ASP flooding. Further work is advised on the emulsification effect of ASP flooding. According to one field test, the EOR routine should be selected depending on consideration of the residual oil type to decide whether to increase the sweep volume and/or displacement efficiency. The micellar flooding failure in one ASP field test in China has led all subsequent field tests in China to choose the “low concentration, large slug” technical route instead of the “high concentration, small slug” one. ASP flooding can increase oil recovery by 30% at a cost of less than USD 30/bbl; thus, this technique can be used in response to low-oil-price challenges.