Fiallos Torres, Mauricio Xavier (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin) | Ganjdanesh, Reza (The University of Texas at Austin) | Kerr, Erich (EP Energy) | Sepehrnoori, Kamy (The University of Texas at Austin) | Miao, Jijun (SimTech LLC) | Ambrose, Raymond (EP Energy)
Optimizing spacing of infill wells and fractures can lead to large rewards for shale field operators, and these considerations have influences on primary and tertiary development of the field. Although several studies have been employed to show the existence of well interference, few models have also implemented Huff-n-Puff and injection containment methods to optimize further hydraulic fracture designs and pressure containment to improve the efficiency of Enhanced Oil Recovery (EOR). This study has performed a rigorous workflow for estimating the impacts of spatial variations in fracture conductivity and complexity on fracture geometries of interwell interference. Furthermore, we applied a non-intrusive embedded discrete fracture model (EDFM) method in conjunction with a commercial compositional reservoir simulator to investigate the impact of well interference through connecting fractures by multi-well history matching to propose profitable opportunities for Huff-n-Puff application. First, based on a robust understanding of fracture properties, updated production data and multi-pad wellbore image logging data from Eagle Ford, the model was constructed to perform nine wells sector model history matching. Later, inter-well connecting fractures were employed for enhanced history matching where results varied significantly from unmeasured fracture sensitivities. The result is the implementation of Huff-n-Puff models that capture inter-well interference seen in the field and their affordable impact sensitivities focused on variable injection rates/locations and multi-point water injection to mimic pressure barriers. The simulation results strengthened the understanding of modeling complex fracture geometries with robust history matching and support the need to incorporate containment strategies. Moreover, the simulation outcomes show that well interference is present and reduces effectiveness of the fracture hits when connecting natural fractures. As a result of the inter-well long fractures, the bottom hole pressure behavior of the parent wells tends to equalize, and the pressure does not recover fast enough. Furthermore, the EDFM application is strongly supported by complex fracture propagation interpretation and ductility to be represented in the reservoir. Through this study, multiple containment scenarios were proposed to contain the pressure in the area of interest.
The model has become a valuable template to inform the impacts on well location and spacing, completion design, initial huff-n-puff decisions, subsequent containment strategies (e.g. to improve cycle timing and efficiency), and to expand to other areas of the field. The simulation results and understandings afforded have been applied to the field satisfactorily to support pressure containment benefits that lead to increased pressure build, reduced gas communication, reduced offset shut-in volumes, and ultimately, improvements in net utilization and capital efficiency.
Field data have shown the decline of fracture conductivity during reservoir depletion. In addition, refracturing and infill drilling have recently gained much attention as efficient methods to enhance recovery in shale reservoirs. However, current approaches present difficulties in efficiently and accurately simulating such processes, especially for large-scale cases with complex hydraulic and natural fractures.
In this study, a general numerical method compatible with existing simulators is developed to model dynamic behaviors of complex fractures. The method is an extension of an embedded discrete-fracture model (EDFM). With a new set of EDFM formulations, the nonneighboring connections (NNCs) in the EDFM are treated as regular connections in traditional simulators, and the NNC transmissibility factors are linked with gridblock permeabilities. Hence, manipulating block permeabilities in simulators can conveniently control the fluid flow through fractures. Complex dynamic behaviors of hydraulic fractures and natural fractures can be investigated using this method.
The proposed methodology is implemented in a commercial reservoir simulator in a nonintrusive manner. We first present one synthetic case study in a shale-oil reservoir to verify the model accuracy and then combine the new model with field data to demonstrate its field applicability. Subsequently, four field-scale case studies with complex fractures in two and three dimensions are presented to illustrate the applicability of the method. These studies involve vertical- and horizontal-well refracturing in tight reservoirs, infill drilling, and fracture activation in a naturally fractured reservoir. The proposed approach is combined with empirical correlations and geomechanical criteria to model stress-dependent fracture conductivity and natural-fracture activation. It also shows convenience in dynamically adding new fractures or extending existing fractures during simulation. Results of these studies further confirm the significance of dynamic fracture behaviors and fracture complexity in the analysis and optimization of well performance.
Geochemical scale formation and deposition in reservoir is a common problem in upstream oil and gas industry, which results in equipment corrosion, wellbore plugging, and production decline. In unconventional reservoirs, the negative effect of scale formation becomes more pronounced as it can severely damage the conductivity of hydraulic fractures. Hence, it is necessary to predict the effect of scale deposition on fracture conductivity and production performance.
In this work, an integrated reactive-transport simulator is utilized to model geochemical reactions along with transport equations in conventional and unconventional reservoirs considering the damage to the fracture and formation matrix. Hence, a compositional reservoir simulator (UTCOMP), which is integrated with IPhreeqc, is utilized to predict geochemical scale formation in formation matrix and hydraulic fractures. IPhreeqc offers extensive capabilities for modeling geochemical reactions including local thermodynamic equilibrium and kinetics. Based on the amount of scale formation, porosity, permeability, and fracture aperture are modified to determine the production loss. The results suggested that interaction of the formation water/brine and injection water/hydraulic fracturing fluid is the primary cause for scale formation. The physicochemical properties such as pressure, temperature, and
During hydraulic fracturing, precipitation of barite and dissolution of calcite are identified to be the main reactions, which occur as a result of interaction between the formation brine, formation mineral composition, and injection water/hydraulic fracturing fluid. Calcite dissolution can increase the matrix porosity and permeability while barite precipitation has an opposite effect. Therefore, the overall effect and final results depend on several parameters such as HFF composition, HFF injection rate, and formation mineral/brine. Based on the fracturing fluid composition and its invasion depth in this study, the effect of barite precipitation was dominant with negative impact on cumulative gas production. The outcome of this study is a comprehensive tool for prediction of scale deposition in the reservoir which can help operators to select optimum fracturing fluid and operating conditions.
Fiallos, Mauricio Xavier (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin) | Ganjdanesh, Reza (The University of Texas at Austin) | Kerr, Erich (EP Energy) | Sepehrnoori, Kamy (The University of Texas at Austin) | Miao, Jijun (SimTech LLC) | Ambrose, Raymond (EP Energy)
Shale field operators have vested interest in optimal spacing of infill wells and further fracture optimization, which ideally should have as little interference with the existing wells as possible. Although proper modeling has been employed to show the existence of well interference, few models have forecasted the impact of multiple inter-well fractures on child wells production to optimize further hydraulic fracture designs. This study presented a rigorous workflow for estimating the impacts of spatial variations in fracture conductivity and complexity on fracture geometries of inter-well interference. Furthermore, we applied a non-intrusive embedded discrete fracture model (EDFM) method in conjunction with a commercial black oil reservoir simulator to investigate the impact of well interference through connecting fractures by multi-well history matching, based on a robust understanding of fracture properties, real production data and wellbore image logging. First, according to updated production data from Eagle Ford, the model was constructed to perform four (parent) wells history matching including five inner (child) wells. Later, fracture diagnostic results from well image logging were employed to perform sensitivity analysis on properties of long interwell connecting fractures such as number, conductivity, geometry, and explore their impacts on history matching. Finally, optimal cluster spacing was recommended considering interwell interference. The simulation results show that well interference is present and reduces effectiveness of the fracture hits when the connecting fracture conductivity, primary fracture conductivity, and number of connecting fractures increase. Because of these interwell long fractures, the bottomhole pressure behavior of the parent wells tends to equalize. Furthermore, the EDFM application is strongly supported by complex fracture propagation interpretation from image logs through the child wells in the reservoir. Through this study, three possible scenarios are shown with robust history matching of the model considering more than 20 complex dominant long interwell fracture hits and more than 2000 hydraulic fractures.
The model became a valuable stencil to decide the well location and spacing, the completion staging, and to optimize the hydraulic fracture treatment design as well as its sequence so that it can be expanded to other areas of the field. The simulation results were applied to the field successfully to afford significant reductions in offset frac interference by up to 50% and reduce completion costs up to 23% while improving new well capital efficiency.
Yu, Wei (Texas A&M University and University of Texas at Austin) | Zhang, Yuan (China University of Geosciences, Beijing) | Varavei, Abdoljalil (University of Texas at Austin) | Sepehrnoori, Kamy (University of Texas at Austin) | Zhang, Tongwei (University of Texas at Austin) | Wu, Kan (Texas A&M University) | Miao, Jijun (SimTech)
Although numerous studies proved the potential of carbon dioxide (CO2) huff ’n’ puff, relatively few models exist to comprehensively and efficiently simulate CO2 huff ’n’ puff in a way that considers the effects of molecular diffusion, nanopore confinement, and complex fractures for CO2. The objective of this study was to introduce a numerical compositional model with an embedded-discrete-fracture-model (EDFM) method to simulate this process in an actual Eagle Ford tight oil well. Through nonneighboring connections (NNCs), the EDFM method can properly and efficiently handle any complex fracture geometries. We built a 3D reservoir model with six fluid pseudocomponents. We performed history-matching with measured flow rates and bottomhole pressure (BHP). Good agreements between field data, EDFM, and local grid refinement (LGR) were achieved. However, the EDFM method performed faster than the LGR method. After that, we evaluated the CO2-enhanced-oil-recovery (EOR) effectiveness for molecular diffusion and nanopore confinement effects. The traditional phase equilibrium calculation was modified to calculate the critical fluid properties with nanopore confinement. The simulation results showed that the CO2 EOR with larger diffusion coefficients performed better than the primary production. In addition, both effects were favorable for the CO2 huff ’n’ puff effectiveness. The relative increase of cumulative oil production after 20 years was approximately 12% for this well. Furthermore, when considering complex natural fractures, the relative increase of cumulative oil production was approximately 8%. This study provided critical insights into a better understanding of the impacts of CO2 molecular diffusion, nanopore confinement, and complex natural fractures on well performance during the CO2-EOR process in tight oil reservoirs.
Carbon dioxide (CO2) injection is an effective enhanced-oil-recovery (EOR) method in unconventional oil reservoirs. However, investigation of the CO2 huff ’n’ puff process in tight oil reservoirs with nanopore confinement is lacking in the petroleum industry. The conventional models need to be modified to consider nanopore confinement in both phase equilibrium and fluid transport.
Hence, we develop an efficient model to fill this gap and apply to the field production of the Bakken tight oil reservoir. Complexfracture geometries are also handled in this model. First, we revised the phase equilibrium calculation and evaluated the fluid properties with nanopore confinement. An excellent agreement between this proposed model and the experimental data is obtained considering nanopore confinement. Afterward, we verified the calculated minimum miscibility pressure (MMP) using this model against the experimental data from a rising-bubble apparatus (RBA). We analyzed the MMP and well performance of CO2 EOR in the Bakken tight oil reservoir. On the basis of the prediction of the field data, the MMP is 450 psi lower than the MMP with bulk fluid when the pore size reduces to 10 nm. Subsequently, we examined the effects of key parameters such as matrix permeability and CO2 molecular diffusion on the CO2 huff ’n’ puff process. Results show that both CO2-diffusion and capillary pressure effects improve the oil recovery factor from tight oil reservoirs, which should be correctly implemented in the simulation model. Finally, we analyzed well performance of a field-scale horizontal well from the Bakken Formation with nonplanar fractures and natural fractures. Contributions of CO2-diffusion and capillary pressure effects are also examined in depth in field scale with complex-fracture geometries. The oil recovery factor of the CO2 huff ’n’ puff process with both CO2-diffusion and capillary pressure effects increases by as much as 5.1% in the 20-year period compared with the case without these factors.
This work efficiently analyzes the CO2 huff ’n’ puff process with complex-fracture geometries considering CO2 diffusion and nanopore confinement in the field production from the Bakken tight oil reservoir. This model can provide a strong basis for accurately predicting the long-term production with complex-fracture geometries in tight oil reservoirs.
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.
Chen, Zhiming (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing, and University of Texas at Austin) | Liao, Xinwei (China University of Petroleum, Beijing) | Yu, Wei (Texas A&M University and University of Texas at Austin) | Sepehrnoori, Kamy (University of Texas at Austin)
Fracture networks are extremely important for the management of groundwater, carbon sequestration, and petroleum resources in fractured reservoirs. Numerous efforts have been made to investigate transient behaviors with fracture networks. Unfortunately, because of the complexity and the arbitrary nature of fracture networks, it is still a challenge to study transient behaviors in a computationally efficient manner. In this work, we present a mesh-free approach to investigate transient behaviors in fractured media with complex fracture networks. Contributions of properties and geometries of fracture networks to the transient behaviors were systematically analyzed. The major findings are noted: There are approximately eight transient behaviors in fractured porous media with complex fracture networks. Each behavior has its own special features, which can be used to estimate the fluid front and quantify fracture properties. Geometries of fracture networks have important impacts on the occurrence and the duration of some transient behaviors, which provide a tool to identify the fracture geometries. The fluid production in the fractured porous media is improved with high-conductivity (denser, larger) and high-complexity fracture networks.
Peng, Yu (Southwest Petroleum University and University of Texas at Austin) | Zhao, Jinzhou (Southwest Petroleum University) | Sepehrnoori, Kamy (University of Texas at Austin) | Li, Yibo (Southwest Petroleum University) | Yu, Wei (University of Texas at Austin) | Zeng, Ji (PetroChina Southwest Oil & Gas Field Company)
Bottomhole-temperature variations have a significant influence on the rheological properties of fracturing fluid and the reaction rates of rock and acid in the operations of acid/hydraulic fracturing. In this work, a semianalytical model is developed for calculating the heat transfer in a wellbore under transient state. In the model, transient heat conduction in the cement sheath and forced convection in the tubing under different flow regimes are considered. Also in this model, calculation methods of heat-transfer coefficients of forced convection in the tubing and natural convection in the annulus are improved in relation to the existing methods. The semianalytical model is verified by monitoring the data of acid and hydraulic fracturing; it is accurate enough to estimate the physical properties of the fracturing fluid and perform simulations in the reservoirs. We studied transient heat conduction in a cement sheath, the influence of flow regimes on tubing, the variation of thermal properties in the wellbore, and the influence of vertical variations of rock type. Simulation results show that the influence of different heat-transfer states of the cement sheath on bottomhole temperature is much more significant under the injection rate of fracturing. Laminar flow is activated by extremely low injection velocity or low temperature in shallow layers. However, such low velocity can never be attained in the fracturing operation. Also, the high heat resistance caused by laminar flow in shallow layers cannot affect the bottomhole temperature significantly because of the low temperature difference between fracturing fluid and formation rock. We also found that the complex vertical variation of rock type and shale and sandstone interbedding could be approximated by the average temperature of simple models that are computationally faster and have an acceptable range of errors.
Xu, Feng (RIPED, CNPC) | Yu, Wei (The University of Texas at Austin) | Li, Xiangling (RIPED, CNPC) | Miao, Jijun (SimTech LLC, The University of Texas at Austin) | Zhao, Guoliang (RIPED, CNPC) | Sepehrnoori, Kamy (The University of Texas at Austin) | Li, Xianbin (RIPED, CNPC) | Jin, Jianli (RIPED, CNPC) | Wen, Guangyao (CNPCIC)
Natural fractures are the main producibility factor in the weathered granite reservoirs (basement rock) and volcanic-rock reservoirs. Production practices show that these reservoirs could have high production rate, but the difference of well productivity between single wells is obvious. These reservoirs have complex natural fractures oriented at medium-high angles, which could bring high complexity and heterogeneity to the reservoirs, adding anisotropy to reservoir permeability. It is very hard to effectively simulate complex fractures in naturally fractured reservoirs and study the applicability of different well type and well pattern by using common reservoir simulators. A fast EDFM (Embedded Discrete Fracture Model) method was put forward for production simulation of complex fractures in naturally fractured reservoirs. The EDFM processor combining commercial reservoir simulators (ECLIPSE or CMG) is fully integrated to forecast production performance of the weathered granite reservoir. With a new set of EDFM formulations, the non-neighboring connections (NNCs) in the EDFM are converted into regular connections in traditional reservoir simulators, and the NNCs factors are linked with gridblock permeabilities. So complex dynamic behaviors of natural fractures can be captured, which can maintain the accuracy of DFMs (discrete fracture models) and keep the efficiency offered by structured gridding. In this paper, a 3D model with complex natural fractures was built to model the performance of different well types and well patterns. The results show that wells with higher density of natural fractures produce higher oil production, and horizontal wells with higher density of natural fractures have larger oil production than vertical wells because horizontal wells have a larger contact area than vertical wells. What’s more, heterogeneity and anisotropy have a great effect on well pattern and well type, which need to be studied carefully in the oilfield development.