No abstract

The distribution of acid over all layers of interest is a critical measure of matrix acidizing efficiency. Chemical and mechanical techniques have been widely adapted for enhancing acid diversion. However, it was demonstrated that these often impact the formation with damage after the acid job is completed. This study introduces, for the first time, a novel solution to improve acid diversion using thermochemical fluids. This method involves generating nitrogen gas at the downhole condition, where the generated gas will contribute in diverting the injected acids into low-permeability formations. In this work, both lab-scale numerical and field-scale analytical models were developed to evaluate the performance of the proposed technique. In addition, experimental measurements were carried out in order to demonstrate the application of thermochemical in improving the acid diversion. The results showed that a thermochemical approach has an effective performance in diverting the injected acids into low-permeability rocks. After treatment, continuous wormholes were generated in the high-permeability rocks as well as in low-permeability rocks. The lab-scale model was able to replicate the wormholing impact observed in the lab. In addition, alternating injection of thermochemical and acid fluids reduced the acid volume 3.6 times compared to the single stage of thermochemical injection. Finally, sensitivity analysis indicates that the formation porosity and permeability have major impacts on the acidizing treatment, while the formations pressures have minor effect on the diversion performance.

Capillary pressure and relative permeability are essential measurements that are directly affecting multi-phase fluid flow in porous media. The difficulty of calculating them rises being constrained to core analysis in the laboratory with many challenges of mimicking reservoir conditions. This makes capillary pressure measurement process to be both time consuming and expensive. However, as resistivity is conveniently obtainable, it can be used to predict both capillary pressure and relative permeability given all relation to wetting phase saturation. Artificial intelligence methods have achieved promising results in modeling extremely complicated phenomena in oil and gas industry. This study aims to find a relation between all of resistivity, capillary pressure and relative permeability. Ultimately, we are going to generate a model by utilizing Artificial Neural Network (ANN) technique to predict both capillary pressure and relative permeability from resistivity. In addition, the implemented technique will be used to improve the data quality and to extend its resolution to thousands of data points. After that, as countless artificial neural network architectures can be created, the most efficient one will be evaluated given its performance and accuracy results. This paper presents the use of artificial neural network technique to both model and predict capillary pressure and relative permeability from resistivity attained from core analysis, and define core samples pore distribution systems. It was found artificial neural network architecture captures the complexity of the physics of the problem. Thus, it successfully fulfilled the required prediction objective. Additionally, compared to the traditional methods, this is proved to be accurate, fast, and significantly cost effective. Consequently, this process could replace the current traditional approaches. Finally, as artificial intelligence techniques are improving exponentially over time nowadays, this will increase the accuracy of the model predictability majorly.

Condensate banking has been identified to cause significant drop in gas relative permeability and consequently reduction of the productivity of gas condensate wells. To overcome this problem, hydraulic fracturing has been used as a mean to minimize or eliminate this phenomenon. Furthermore multistage hydraulic fracturing techniques have been used to enhance the productivity of horizontal gas condensate wells especially in low permeability formation. Even though multistage hydraulic fracturing has provided an effective solution for condensate blockage to some extent as it promotes linear flow modes which will minimize the pressure drops and consequently improves the inflow performance considerably. However, this technique is very costly, and has to be optimized to get the best long-term performance of the multistage fractured horizontal gas condensate wells. In this paper, multiple sensitivity analyses were conducted in order to come up with an optimum multistage hydraulic fracturing scenario. In these analyses, our manipulations were focused mainly on the operational parameters such as fractures half length, fractures conductivity using compositional commercial simulator. CMG-GEM simulator was used to investigate the different cases proposed for applying multistage hydraulic fracturing of horizontal gas condensate wells. The investigation began with a base case scenario where the fractures half-length were fixed for all stages with equal spacing between them. Then, six more fractures half-length patterns were created by introducing new approach where the well performance was studied if they are in increasing trend away from the wellbore (coning-up), or in a decreasing trend (coning-down). Well performance is furtherly addressed when the fractures half-length arrangements formed parabolic shapes including both occasions of concaving upward and downward. Finally, the last two patterns illustrated the effect of having the fractures half-length arrangements both skewed to the left and right on well productivity. The investigation of the effect of changing the multistage hydraulic fractures half-length distribution patterns on the performance of a gas condensate well was conducted and resulted in parabolic up distribution pattern to be the optimum pattern amongst the other tested ones. It results in the highest cumulative both gas and condensate production. It also maintains the gas flow rate and bottom hole pressure more efficiently. The parabolic up distribution pattern confirms that the majority of gas production was fed by the fractures at the heel and at the toe of the horizontal drainhole which is in agreement with the flux distribution along the horizontal well.