Wei, Chenji (University of Wyoming) | Wang, Hongyan (National Energy Shale Gas R&D (Experiment) Center/PetroChina Co. Ltd.) | Sun, Shasha (PetroChina Co. Ltd.) | Xiao, Yuanpu (Chengdu University of Technology) | Zhu, Yanming (China University Of Mining & Technology (Xuzhou)) | Qin, Guan (University of Houston)
The shale gas development has more than 3 decades of history. In China, the development is still in the early stage due the technology limitation. The estimated technically recoverable shale gas reserve is 882 Tcf in China. The predicted shale gas production in 2020 is 3.5 Tcf which will contribute 26% of natural gas consumption in China. In order to stabilize the gas output to meet the demand of economic development, increasing recoverable shale gas reserve becomes more and more important.
In this study, a Qiongzhusi reservoir was taken as an example to investigate the potential of shale gas in southern China. The methodologies involved in this investigation include experimental study on core analysis with Total Organic Content (TOC) and Vitrinite Reflectance, outcrops study, geostatistical analysis, and geo-modeling. Besides these methods, an irreplaceable step was to compare the reservoir conditions of given reservoir with successful developments in Barnett and Marcellus in the United States.
By integrating all above technologies and methods, the study forecasted the sedimentary facies, estimated shale gas distribution, and evaluated the petrophysical properties of the shale play. The result indicates that most of the Qiongzhusi reservoirs have promising thickness, favorable kerogen type (type I), high TOC, and encouraging maturity. This paper also predicted favorable zones in the middle and upper Yangtze area with properties of thickness more than 60 meters, TOC not less than 2.0%, and Vitrinite Reflectance from 2.5% to 4.6%.
The study would bring the reservoir engineers and geologists with detailed evidence to support the development of Qiongzhusi reservoirs, and furthermore, it offers the methodology to the research of other shale plays with similar properties.
Sand control is vitally important to operation integrity in producing heavy-oil from unconsolidated reservoirs. Among various sand exclusion technologies, the open-hole gravel pack (OHGP) has been widely used in horizontal well completions. It is thus critical to quantitatively evaluate gravel packing layer damage and understand its mechanisms.
In this paper, we propose an integrated study to quantitatively evaluate gravel packing damage based on the real-world scenarios and, thus provided design criteria for gavel packing. We have designed an experimental system that can measure the core pressure at multiple points in gravel layers at high pressure condition as well as track sand migration. Preliminary results indicate that pore structure of gravel packing layer changes and the permeability decreases with sand migration and plugging. Sand volume fraction, fluid viscosity, and sand radius are the main factors that cause gravel packing layer damage.
We have developed a numerical model based on experimental observations. The numerical model considers liquid-solid fluid flow processes, sand migration and plugging in gravel layer. Numerical simulation studies are then performed on the gravel damage at different sand volume fraction, fluid viscosity, and sand radius. The simulated results are in agreement with experimental results. The numerical simulation studies on real-world scenarios are under investigation and we will report the numerical results in later reports.
With the depletion of conventional oil reservoirs, the unconventional reservoirs (i.e. heavy-oil reservoir, low-permeable reservoirs, and fractural reservoirs) become significant in oil and gas development, especially the heavy-oil reservoir has been main part of unconventional reservoir , which represents an estimated 5.5 trillion barrels of global reserves(Z. Shouliang,2004). The heavy oil is high viscosity and traditionally reserved in weak, unconsolidated sandstone reservoirs that require some form of lateral borehole support and/ or sand control solution. The key to successful heavy oil exploitation is increasing the mobility of high viscosity liquids within the reservoir matrix and sand control. Sanding is one of the main problems in petroleum exploitation, especially in loose sandstone reservior. Rock failure surrounding wellbore is prone to happen because of weak bonding strength, resulting in large mass of sanding. The sand production in well will not only lead to serious abrasion wear on down-hole and surface equipment, even well sand-up or sand burial accident, but also decrease of recovery efficiency and oil well abandonment (Tian, H., et al., 2005; Li ,A.F., et al., 2004; Shao, X.J., et al., 2004).
Sand production in oil-producing wells is usually related to the following two mechanisms (Veeken et al, 1991):
1. Mechanical instabilities and localized failure (damage) of the rock in the vicinity of wellbore due to stress concentration,
2.Hydro-mechanical instabilities due to internal and surface erosion, which manifest themselves in releasing and transferring of particles, caused by the action of seepage forces.
Many studies have been performed in the past on different aspects of sand production. However, they have mainly concentrated on finding effective methods to avoid sand production because of the high operating costs involved in handling and disposing of produced sand (Travis W. Cavende, 2004, Brígida Meza-Díaz, 2011).
Sun, Fujie (China National Offshore Oil Corp.) | Zhang, Xiansong (CNOOC Ltd.) | Kang, Xiaodong (CNOOC) | Gong, Bin (Peking University) | Liu, Wei (Monix Energy Solution, Ltd.) | Qin, Guan (University of Wyoming) | Xu, Jinchao (Pennsylvania State University)
As one of the major enhanced oil recovery mechanisms, chemical flooding procedure has been widely and successfully used in matured fields and the overall sweep efficiency has been improved between 5??12% due to various chemical flooding treatments. China National Offshore Oil Company (Cnooc) started its pilot offshore chemical flooding projects to evaluate the chemical flooding opportunities at early development phase. In this paper, we present numerical simulation studies on overall evaluation of a Cnooc's offshore heavy oil chemical flooding project using chemical flooding simulator.
In the numerical simulation studies, we have developed a numerical model with the focus on various complex chemical flooding procedures. Moreover, we have also developed a dynamic well model that is capable of modeling multi??phase flow inside complex multi??lateral wellbores. An algebraic multi??grid linear solver has been developed and implemented into the simulator. As the simulator has been developed following the advanced software architecture design and it can be easily expanded other field applications.
The targeted field in this paper is an offshore heavy??oil field with hundreds of wells and a complex fault system. The production started in 1999, and waterflooding in 2000. In 2007, all water injectors have been switched to polymer injection for
better conformance control. In this field??scale reservoir simulation study, the polymer solution, reservoir brine and the injected water are represented as miscible components of the aqueous phase. Key factors such as inaccessible pore volume, polymer shear thinning effect, polymer adsorption, and relative permeability reduction factors have been taken into account for the construction of the mathematical model. Simulations have been run for evaluation on optimal polymer injection timing, amount and pattern.
As one of the major enhanced oil recovery mechanisms, chemical flooding procedure has been widely used in matured fields in the past several decades. The overall sweep efficiency can be improved by chemical flooding in the range of 5-12% due to various chemical flooding treatments. Usually, chemical flooding procedure is applied for large-scale matured onshore fields with high water cut to improve the sweep efficiency. China National Offshore Oil Company (Cnooc) has initiated a pilot offshore chemical flooding project to evaluate the chemical flooding opportunities at early development stage to achieve better enhance oil recovery performance. The targeted offshore field is an offshore heavy oil field and it started production in 1999, and waterflodding in 2000. In 2007, all the water injectors have been switched to polymer injectors for better conformance control.
Hydraulic fracturing treatment has been proven to be the key factor for shale gas to flow at economic rate. Micro-seismic mapping has shown the extreme complexity of the hydraulic fracture network after the stimulation due to the geological complexity of shale formations. It becomes vitally important to understand the impact of the hydraulic fracture treatment, especially the massive multistage, multi-cluster hydraulic fracturing stimulations, to optimize stimulation and development plans of shale gas reservoirs.
Recent advances in micro-seismic mapping enable realistic modeling of hydraulic fracture network, though with significant uncertainty. Consequently, it is possible, to certain extent, to represent actual large-scale fracture distribution in reservoir modeling and simulation of shale gas development. In this paper, we propose a simulation method that is able to generate highly likely realizations of fracture network based on micro-seismic data, taking into account of data and shale formation uncertainty. The simulated realizations are then used to construct highly constrained unstructured gridding and a connection list of all neighboring cells (SPE 143590), using the Discrete Fracture Modeling (DFM) approach. DFM enables the prediction of production yield curve. With real production data, statistical analysis is done to calibrate and refine the simulation attributes. Based on a well calibrated simulation system, and linking initial hydraulic stimulation, induced fracture network and production data, we predict future stimulated reservoir volume and production yield curve, hence enabling the optimization of stimulation and development.
The proposed approach is extremely computational intensive. Approximations, efficient implementation and parallelization are used to make the approach practical. The approach was tested with success on real field experiments and data and the numerical results have shown great potential of the proposed approach to better understand the impact of hydraulic fracturing treatment.
Shale formations are usually extremely tight with complex pre-existing natural fractures at multiple length scales. Various stimulation technologies, most commonly hydraulic fracturing treatment, are used to create induced fracture network allowing gas flow to production wells at economical rates. The induced fracture networks often have complicated geometry that is difficult to be characterized resulting inaccurate production performance predictions.
The production performance of a shale gas well mainly depends on the induced fracture network and its impacting volume or stimulated reservoir volume (SRV) near the wellbore. Frequent drillings and stimulation treatments are required to maintain global production scale. It is thus vitally important to accurately characterize the induced fracture networks and the resulting stimulated reservoir volumes for optimizing development plan and quantifying reserve estimation uncertainties.
Hydraulic fracturing stimulation is one of the key technologies for shale gas development. The recent advances in microseismic data acquisition and processing suggest that hydraulic fracturing stimulation has often resulted in complex fracture network due to the pre-existing natural fractures. Modeling hydraulic fracturing processes needs to couple in-situ stress response and flow of engineered fluid that includes water, proppant and other chemicals. Moreover, the high Reynolds number indicates that the flow in the hydraulic fracturing processes is either in transition or turbulent flow regime. Consequently, the resulting mathematical model is complex and needs to be numerically solved.
In this paper, we have developed a hydraulic fracturing model considering the in-situ stress response to turbulent flow process. The mixed finite element method is employed for numerical solution of the resulting system of coupled nonlinear partial different equations. The proposed model has been validated with bi-wing hydraulic fracture model through regression tests. The preliminary numerical results show the significant differences in hydraulic fracture growth in comparison with the models that assume laminar flow in hydraulic fracturing processes. We have also integrated proposed hydraulic fracturing model into a numerical reservoir simulator and are currently conducting field-scale numerical simulation studies. The preliminary results also suggest that the proposed model is also capable of modeling the interactions between the hydraulic fracture and pre-existing natural fractures based on initial fracture mapping.
The proposed model provides an opportunity to optimize hydraulic fracturing stimulation design through numerical simulations, which is vital in unconventional reservoir production.