This paper proposes a two-stage multi-system architecture for forecasting post-fracturing responses in a tight oil reservoir using historical fracturing data. The first stage predicts the 180-day cumulative liquid (oil + water) production directly, and the second stage uses differential correction to predict the prediction error resulting from the first stage. The final prediction is a combination of the two stages. 5-fold cross-validation is used in each stage, resulting in five forecasters for each stage. The average of the five predictions is taken as the output of the corresponding stage. Each of the five forecasters in each stage consists of three independent subsystems (Location, Completion and Fracturing), whose inputs are subsets of the well properties. The Location subsystem is constructed by a weighted average, whereas Completion and Fracturing are constructed by fuzzy logic systems. The parameters of the three subsystems are optimized simultaneously using simulated annealing. The final design achieved over 70% prediction accuracy for more than 96% of the testing wells. The main advantages of our approach are that 1) it does not require a large training dataset; 2) it can cope well with incomplete data entries and uncertainties; and, 3) the redundancy in the input parameters is used to improve accuracy.

This paper presents a comprehensive simulation study demonstrating technical merits of automatic intermittent and distributed heating for reducing back pressure and maintaining flow in low pressure gas wells. Reduction or elimination of the additional wellbore backpressure plays a key role in boosting gas wells productivity and extending the lifetime of the field. The backpressure is mostly due to the development of excess liquid water along the tubing stopping the low pressure gas flow. We present two-phase thermal flow simulations to study the impact of intermittent volumetric heating along the wellbore to reduce or eliminate the excess backpressure caused by either water condensation in the upper part of the wellbore, or the overall increase of density of the two-phase fluid. The proposed method helps in continuous prevention of the excess water development enabling the well to produce without interruption up to its natural limit. Modeling the thermal exchange in the wellbore, two-phase flow pressure simulation demonstrates that flowing and thermo-dynamic conditions of the water/gas mixture along the wellbore have a substantial impact on the overall backpressure. Our results show that by modifying the thermal profile of the wellbore fluid at specific locations and times, we can maintain significantly lower backpressures and increase well productivity. Our case studies highlight that for very low pressure gas wells, the external power requirements can be more acquiescent to automation and control than the existing methods. The results yield valuable insight in the development of a novel liquid unloading techniques based on volumetric heating of the wellbore fluid. Our results can also be applied to the elimination of hydrates in gas wells. Introduction Liquid-loading is the main cause of productivity loss in gas wells and it can affect all type of wells and gas fields. The net physical effect of water loading is a dramatic increase in the overall back-pressure along the wellbore tubing which results in a bottomhole pressure (BHP) substantially higher than the one of an otherwise not loaded well. Initially, this increase in BHP reduces productivity rates and after a while it can completely halt well production. Several artificial lift methods [2] have been developed over the years and are successfully used under different conditions and well types. However, each of these artificial lift methods have a defined range of conditions for which they can be applied efficiently and most of them reach their limit of efficacy for low reservoir pressure conditions. It is precisely for these low-pressure gas wells that the reduction or elimination of any additional wellbore backpressure plays a more predominant role in boosting gas wells productivity and extending the lifetime of the field. The additional liquid-loading related backpressure can take several forms. In some cases the back pressure might be due to increase in liquid water content in misty form all along the walls and the interior of the tubing, in other cases it might occur as a liquid column down at the bottom of the wellbore and in other cases it appears as an increase of pressure gradient in the upper part of the wellbore due to condensation caused by thermal loss. However, these three different cases share the common fact that severe liquid loading can be avoided if the natural energy to lift liquid with gas is preserved and hence water droplets are prevented from falling back and accumulate in at the bottom of the wellbore. In low-pressure reservoirs, the back-pressure effect alone can halt production and labor-intensive methods must be constantly applied in order to sustain production.