Accurate individual well production rates are essential to meet corporate production target plans, optimize reservoir performance and make reservoir management decisions that may require well intervention. Short of installing rate measurement devices on each well, a "back allocation" method is generally employed to assign well production rates, using multiplying factors based on well tests conducted the month before. Apart from the inherent errors, based on the assumption that the wells produce at the same rate throughout the month, the process is also not suited for real-time field management that requires production rates to be known much more frequently.This paper describes the implementation of a system that automates the calculation of individual well production rates using real-time pressure data from permanent sensors installed on the wells. The system, based on integrated physical models of the reservoir, well and surface network, has been successfully used to implement crude blend management in a large Saudi Arabian field, producing from three different reservoirs. The paper also describes how the system is used to automate the validation of well test measurements, allowing the engineers to focus their time on problem wells while ensuring that all wells are reviewed. In addition, field models are kept evergreen and can be utilized by different disciplines for production forecasts. Application of the system could result in significant cost savings, due to reduction in the requirements for physical metering of well production. The system also provides unique optimization opportunities, allowing the engineer to determine the optimum settings to maximize production or revenue. Other benefits include, faster resolution of production problems due to early problem detection, focus on exceptions rather than bulk and massive troubleshooting, and zero-latency applicationassisted decision making, all combining to bring real-time field management and optimization to the engineer's desktop.

Well Ba-E-1 was drilled in the Tompa prospect (now the Ba-IX Mining Plot) in Hungary targeting the Miocene and Cretaceous formations between 2600 and 3500 mTVD. These are tight sandstones and the expected permeabilities were in the range of 0.001 to 0.5 mD. Two hydraulic fracture treatments were performed. The first fracture treatment was in the lower part and the second treatment was in the upper part of the deepest interval. With no previous propped fracturing experience in this field, the first treatment was designed as a conventional crosslinked gel treatment to minimize the risk of a premature screenout. Following the analysis of the data from the first zone, it became clear that the average permeability was closer to the minimum expectation of 0.001 mD. Due to lower than expected stimulation effectiveness of the first fracture, and the confirmation of the low permeability, the 2 nd fracture treatment was changed to a waterfrac design. This formation clearly falls into the category 'unconventional', and consequently was a good candidate for a waterfrac.This paper describes the pre-frac diagnostics, fracture execution and post-frac production evaluation of this unconventional gas well. Special emphasis is placed on the use of small volume injection tests (DFIT) to obtain an estimate of the in-situ kh, since it is impossible to perform pre-fracture welltests in such a formation. The result of the DFIT analysis is then used to constrain the post-fracture welltest analysis in a numerical simulation model that includes fracture filtrate cleanup modeling. Post-frac analysis showed that the initial proppant pack damage is high and effective fracture length is much smaller than the created length, especially with crosslinked gel. The crosslinked gel treatment was not able to cleanup effectively, and therefore showed limited stimulation effectiveness. The first ever waterfrac in a gas reservoir performed in Europe showed a more significant production improvement during the short post-frac test. The results from this well suggest that, as in North America, waterfracs appear to have better initial production than crosslinked gel fracs due to better fracture cleanup in European reservoirs with micro Darcy permeability.