Summary
Designing matrix-acid stimulation treatments in vuggy and naturally fractured carbonate reservoirs is a challenging problem in the petroleum industry. It is often difficult to physically model this process, and current mathematical models do not consider vugs or fractures. There is a significant gap in the literature for models that design and evaluate matrix-acid stimulation in vuggy and naturally fractured carbonate reservoirs. The objective of this work is to develop a new model to simulate matrix acidizing under field conditions in vuggy and naturally fractured carbonates.
To obtain accurate and reliable simulation parameters, acidizing coreflood experiments were modeled using a reactive-flow simulator. A 3D radial field-scale model was used to study the flow of acid in the presence of vugs (pore spaces that are significantly larger than grains) and natural fractures (breaks in the reservoir that were formed naturally by tectonic events). The vugs’ size and distribution effects on acid propagation were studied under field conditions. The fracture length, conductivity, and orientation, and the number of fractures in the formation, were studied by the radial model. The results of the numerical simulation were used to construct Gaussian-process (GP)-based surrogate models for predicting acid propagation in vuggy and naturally fractured carbonates.
Finally, the acid propagation in vuggy/naturally fractured carbonates was evaluated, as well.The simulation results of vuggy carbonates show that the presence of vugs in carbonates results in faster and deeper acid propagation in the formation when compared with homogeneous reservoirs at injection velocities lower than 8×10–4 m/s. Results also revealed that the size and density of the vugs have a significant impact on acid consumption and the overall performance of the acid treatment. The output of the fracture model illustrates that under field conditions, fracture orientations do not affect the acid-propagation velocity. The acid does not touch all of the fractures around the well. The GP model predictions have an accuracy of approximately 90% for both vuggy and naturally fractured cases. The vuggy/naturally fractured model simulations reveal that fractures are the main reason behind the fast acid propagation in these highly heterogeneous reservoirs.
