As a new developing method, fishbone well injection has been used in buried hill reservoirs. Based on numerical simulation, optimization research on the new reservoir developing method, which means fishbone wells injecting water at the bottom and horizontal wells producing oil at the top, is present. Compared with horizontal well injection, the results show that the fishbone well can increase the control area, form planar flooding, and hold the injection water upward slowly and evenly. The reasonable fishbone well parameters, such as branching angle, branch number, and branch length, are obtained. The fishbone well injection provides a new technical method for developing buried hill reservoirs efficiently.

In-situ combustion simulation from laboratory to field scale has always been challenging, due to difficulties in deciding the reaction model and Arrhenius kinetics parameters, together with erroneous results observed in simulations when using large-sized grid blocks. We present a workflow of successful simulation of heavy oil in-situ combustion process from laboratory to field scale. We choose the ongoing PetroChina Liaohe D block in-situ combustion project as a case of study. First, we conduct kinetic cell (ramped temperature oxidation) experiments, establish a suitable kinetic reaction model, and perform corresponding history match to obtain Arrhenius kinetics parameters. Second, combustion tube experiments are conducted and history matched to further determine other simulation parameters and to determine the fuel amount per unit reservoir volume. Third, we upscale the Arrhenius kinetics to the upscaled reaction model for field-scale simulations. The upscaled reaction model shows consistent results with different grid sizes. Finally, field-scale simulation forecast is conducted for the D block in-situ combustion process using computationally affordable grid sizes. In conclusion, this work demonstrates the practical workflow for predictive simulation of in-situ combustion from laboratory to field scale for a major project in China.

Integrating in-situ combustion from laboratory scale into field scale has always been challenging, due to difficulties in deciding the reaction model and Arrhenius kinetics parameters, together with erroneous results observed in simulations when using large sized grid blocks. Based on the methodology proposed in our previous work, we present a case study on the successful simulation heavy oil in-situ combustion from laboratory experiment history match to field scale process modeling. We choose the ongoing PetroChina Liaohe Du-66 block heavy oil in-situ combustion project as the case of study. The workflow includes kinetic cell and combustion tube laboratory experiments, test data interpretations, establishing the kinetic reaction model, isoconversional activation energy analysis, history match of the experiments, and finally field-scale reservoir simulation using the proposed upscaled reaction model. The reaction upscaling methodology uses standard thermal reactive reservoir simulator with a different upscaled reaction source or sink term. First, we established a suitable kinetic reaction model, deduced the necessary information from the kinetic cell experiment, and performed detailed history match of the kinetic cell to obtain matched Arrhenius kinetics parameters. Second, the laboratory combustion tube experiment was history matched to further determine other simulation parameters and also to calculate the fuel amount per unit reservoir volume. We have found matching of the experiments highly ill-conditioned with multiple possible inputs, if only matched to combustion tube experiment without information from the kinetic cell. Finally, we upscaled the Arrhenius kinetics to upscaled reaction models for field scale simulations. The model with upscaled models showed consistent results with different grid sizes, which is favorable for field scale simulations. Field scale production forecast was conducted for the Du-66 block in-situ combustion process in Liaohe oil field, using computationally affordable grid block sizes. In conclusion, this work shows the successful implementation of the integrated simulation methodology on a major in-situ combustion project in China, which demonstrates the practical workflow for predictive modeling of in-situ combustion from laboratory scale to field scale.

All heavy oil reservoirs in TaoBao oil field are shallowly buried, thin, and multilayered in which natural production and cold production technologies have been implemented in past seven years, and obvious increase in oil production was achieved by cold production(up to 9 times than natural production method). However, due to the low reservoir pressure, heterogeneity, and limited formation thickness, the oil production has rapidly decreased, and more than half of the wells have been shut off now.At present, more than 94% oil remained in place is difficult to exploit, and different recovery methods are being investtigated, as a result, only in-situ combustion is more potential and seems feasible to enhance oil recovery for such reservoir.To investigate the feasibility of in-situ combustion, reactor experiment and combustion tube experiment have been carried out at first, the result shows that the optimal fire temperature is above 400℃, and the ultimate oil recovery is more than 80%. Additionally, air injection rate, combustion front velocity and other parameters have been measured or calculated. At the same time, primary reservoir numerical simulation for selected block in Bai92 reservoir are implemented considering that more importance should be attached to the feasibility of in-situ combustion in reservoir scale. Some important factors such as air injection rate are investigated. Moreover, the progress in pilot test of in-situ combustion in B92 reservoir is introduced briefly.The results of primary experiments, reservoir numerical simulation and pilot test show that in-situ combustion is feasible to enhance oil recovery of such shallow, thin and multilayered heavy oil reservoir as B92.

Fire flooding process has been applied to the thick and deep heavy oil reservoirs G3618 and G3 in Liaohe oil field in China. Currently, there are two main operating issues: the serious combustion front gravity override, and the low areal sweep efficiency. Thus, research of process control is conducted for the entire project area, each layer, and also individual well patterns, with the objective of achieving better vertical and areal conformance. G3 and G3618 have average thickness of 68.6m and 103.8m, with similar depth of 1600m. Three major process control methods are used: using vertical-horizontal well configuration, reconfiguring to line drive plus vertical-horizontal hybrid configuration, and air injecting at top positions. We establish geological model with focus on interlayer vertical communications. Through reservoir simulation and field data analysis, we test potential benefits of using horizontal producers. We further compare the different performances of line drive and pattern flood in G3618 and G3. Finally, with G3618 having 20 degree dip angle, we test the effect of air injection at higher elevations through simulations and laboratory experiments. First, we have found 2m as the critical thickness for shale interlayer barriers to prevent vertical communications and to minimize gravity override. The combination of vertical and horizontal wells shows great improvements in conformance, since the horizontal producer at bottom of the reservoir could more effectively drain the reservoir. Second, we find line drive is more effective than pattern flood with recovery improvement of around 10%, proven by reservoir simulations and field production analysis. Third, if we inject from top, we benefit from high recovery of gravity drainage, with much oil accumulated at reservoir bottom. We recommend conducting top injection when reservoir thickness is above the critical value of 20m. Finally, we have establish line drive fire flooding configuration in G3 reservoir with air injectors located at top positions of the reservoir, which causes oil production rate to increase by about 80% since initiating these adjustments. For G3618 reservoir, we have also reconfigured the well patterns to line drive with air injectors at elevated locations, with daily production rate increased by 30%. Through field experience, we have found that controlling combustion front override and improving areal sweep efficiency are great technical challenges for fire flooding process. We demonstrate that measures of implementing line drive, injecting at the top while producing at deeper locations, and configuration of vertical injectors and horizontal producers have already made significant improvements in fire flooding production performance in Liaohe oil field in China.