This paper describes the practical applicacion of a method known as Flowing Gas Material Balance FGMB (L. Mattar and Mcneil, 1997) for reserve's estimation using bottomhole flowing pressure data in two dry gas fields in Mexico. The main purpose of this work is to apply the method in real cases having enough data and make a comparison with other standard methods of reserves estimation (J. Lee, 1996 and G.J. DeSorcy, 1994) such as Volumetric, Decline Curve Analysis, Conventional Material Balance and Numerical Simulation to see the results and validate the efficacy of its application.There are some premises should be considered before its application that will be explained, besides the advantages and results of this comparison which showed differences no greater than 10% with respect to the method more trustable to report reserves for these reservoirs.

Many producing fields worldwide have reached the mature phase of development, these fields have been producing for several years (25 to 40 years or more), which is typically beyond the design life, and at this stage there are several challenges from different perspectives from the reservoir to the surface and there are nevertheless a number of viable options for extending the economic life. Recent studies estimate than hydrocarbon production from mature fields will account for more than one-half of the global energy mix for the next 20 years, and probably munch longer (Syed,2008), hence the importance of apply technologies and methodologies (IAM) capable to capture all the interaction in this complex system. There are several key factors in developing mature oil fields. Reservoir conditions, oil prices, development costs, surrounding pipeline infrastructure, and regulatory frameworks. The recovery and production from these fields can be enhanced by infill drilling, different stimulation and remediation techniques, artificial lift systems, secondary or enhanced recovery, etc. Selecting the optimal strategy requires an integrated approach in the total production system and be able to forecast and evaluate different options of integrated performance, linked to the economic value to support the decision making process. This paper describes a case study where the implementation of an integrated asset model was performed, taking into account the production system elements (well, reservoir, and production network) as part of the reservoir management strategies developed with the purpose of evaluating, designing and optimizing the field exploitation to increase the recovery factor and profitability of the field. Different studies were performed using the reservoir, surface production network and well modeling, under this integrated approach to quantify the possible production rates, identify the potential effect of artificial lift systems, production capacity and all the technical – economical viable options that can help to reach the goals of the asset in terms of investment and production, justify with high level of engineering all the investment vs benefits; and also helping to generate the plans and actions associated in the execution phase. Several challenges shown by this field are due to its extensive previous exploitation activity, which leads to the integrated approach becoming the key factor for predicting the real alternatives previously mentioned. As a result, an integrated field management proposal was developed seeking for production optimization and evaluation of different artificial lift options along with recovery schemes such as water injection for pressure maintenance.

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The objective of this work is to present a comprehensive workflow to optimize the value of a hydrocarbon asset evaluation project under high degrees of uncertainty. This workflow is applicable to both conventional and unconventional assets. However, because of the considerable level of subsurface uncertainty and high initial costs (mainly due to drilling and hydraulic fracturing operations), unconventional resources are good examples for demonstrating the benefits of the workflow. For the case of an unconventional asset, well spacing and perforation cluster spacing are usually the decision parameters that need to be optimized to increase its value. The workflow begins with the construction of a representative base case single well gas simulation model for production history matching. Petrophysical, geological, geomechanical, stimulation, completions and production data are interpreted and analyzed together to better understand drivers that could be influencing the production. If this can be repeated with several wells in the block with sufficient production data, the process is enriched as so the level of confidence, as the range of history-matching parameters from these different wells across the block can be captured for sensitivity and uncertainty analysis. Several sets of sensitivities and uncertainty runs are then performed to get a probabilistic production profile in the presence of the most influential parameters. It is important to highlight that usually, the limited number of wells, short production histories, different dynamic behavior in neighboring blocks and the lack of necessary data to help understand well performance all contribute to the high uncertainty in predicting production. Given the high cost of drilling and hydraulic fracturing and on the other hand the high gas price in Argentina, optimizing well spacing and cluster spacing are critical parameters in the process of unconventional resource evaluation considering the high degree of uncertainty.

The current business strategy of Operators in Mexico has considered finance Enhance Oil Recovery projects. Moreover, the potential in Mexico for EOR is represented by 80% of the total production coming from mature fields. However, these projects are difficult to be executed below current circumstances, oil prices and existing fiscal terms. For this reason, there is an opportunity to evaluate how to switch the situation and generate scenarios where it might be possible to perform such as complex project. Therefore, this study presents a methodology from a technical and economical perspective that includes the selection of a representative reservoir, evaluating different production forecast scenarios below EOR schemes, comparing fiscal models and running sensitivity analysis to end up with an incentive adjustment, to evaluate the potential benefits of fiscal incentives and how they could be applied effectively to EOR implementation projects. To demonstrate the potential of these projects in Mexico, a reservoir with specific characteristics had been selected to simulate the performance of a mature field where thermal pilot projects are conceptualized. Nevertheless, the focus of this study is to evaluate the current fiscal terms and taxes versus innovative fiscal terms with applied incentives. This work pursuits to find a window of opportunity for complex projects that embraces current oil prices, appropriate fiscal terms, tax incentives, and technical considerations. Overall, the proposed methodology defines how to apply the appropriate incentive in combination with several parameter to enable the execution of these projects. Finally, as a result of this study, it had been demonstrated that at given conditions and adding a package of incentives, there is a win-win schema where the Government and the Operators obtain higher returns than the conditions of exploiting the fields only with natural depletion. These proposed conditions can be used to promote economic benefits that encourage EOR projects and attract investment in Mexico, and consequently, increase recovery factor of mature fields.