Commonly when a conventional gas reservoir is produced always the recovery factor expected is between 80-90%, but when the water appears always the plans are subjected to changes, different considerations and several questions raises regarding how the reservoir will be affected. The most common questions are if the recovery factor will be affected, if the current production strategy will change, if we need to consider critical rates per well, if the plateau will change, reserves, production facilities, etc. The presence of water influx can alter the way the gas is produced by the reservoir as the water invades the gas reservoir, the displacement is not 100% efficient (M.Kelkar, 2008). On the other hand it has long been realized that gas recovery from a water-drive gas reservoir may be poor because of high residual saturations under water drive. The Agarwal study (Agarwal, 1965) showed the quantitative potential importance of water influx; its results indicate that gas recovery may be very low in some cases: perhaps as low as 45 per cent of the initial gas in place. So the important fact is that in gas reservoirs with water influx can change drastically the recovery then the expectations, unfortunately, water influx has forced abandonment of a number of gas reservoirs at extraordinarily high pressures, hence the importance to understand the effect of water in the reservoir based on static and dynamic reservoir parameters, and highlight the importance of gas recovery under water drive appears to depend in an important way on: (1) the production rate and manner of production; (2) the residual gas saturation; (3) aquifer properties; and (4) the volumetric displacement efficiency of water invading the gas reservoir. In certain cases, it appears that gas recovery can be increased significantly by controlling the production rate and manner of production. For this reason, the potential importance of water influx in particular gas reservoirs should be investigated early to permit adequate planning to optimize the gas reserves. The methodology presented on this paper appraises the evaluation of four different exploitation scheme, trying to understand and determine the best exploitation strategy using a reservoir simulation model applied to two different reservoirs of the Veracruz Basin with different static and dynamic properties, and quantify the benefits to use the proper one to maximize the recovery factor. A detailed description of each reservoir will be review and results will be compared to emphasis that there is no rules to create exploitation plans for gas reservoirs it will depend on several factors.

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.

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.

Selection of the most economical artificial lift method is necessary for the operators to realize the maximum potential from developing any oil or gas field 1 . In artificial lift design the engineer is faced with matching facility constraints, artificial lift capabilities and the well productivity so that an efficient lift installation results. Energy efficiency will partially determine the cost of operation, but this is only one of many factors to be considered. Based on the above consideration and some other limitations in any project usually 2-3 methods of artificial lift will be candidate to maintain or increase the production from a particular field and a final decision on the type of lift will be made after doing economic studies on different scenarios and several other non-technical considerations 1 .Traditionally any decision on engineering design and debottlenecking of surface network and in particular the type of the artificial lift methods are performed by production engineers with their stand-alone tools considering a production forecast profile from a reservoir simulation model. There are lots of simplifications and limitations to generate these profiles, for example well targets in the reservoir simulation model can be unrealistic from production engineering point of view and can cause over or under sizing the production and surface facilities 2 . Another example can be when different reservoirs are sharing the same network to produce and also there is an artificial lift plan for one of the reservoirs in the field and the production engineer is being asked to evaluate the capacity of the current production network to handle production changes. The answer to these questions if not impossible is a very tedious task to be practiced by traditional field development planning methods.In this paper authors try to review the concept of Integrated Asset modeling with emphasizing on the artificial lift method screening and analysis. An example application of IAM in a field in Mexico will be shown and the benefits of the integration workflow will be demonstrated in bulk of the paper.

The objective of this paper is to show and demonstrate how technology and especially software application in the field of heavy oil can change our view regarding the method of development and economical feasibility of the pilots. Different real challenges regarding heavy oil exploitation and production have been addressed and the solution has been provided with best in class technology and software in the market at the time of these studies.The first case is about injected steam conformance in a horizontal well and in a loose fluvial sand reservoir. The lack of conformance has been modeled and after that simulated using proper reservoir modeling and simulation applications. The second case which has been studied is evaluating and feasibility study of implementing of in situ combustion in thin sands which previous attempts of developing them with cyclic steam stimulation was not successful because of high energy loss to the over and under Burdon layers. The third case is to show how efficient production scenarios can be sensitized and selected with application of a reservoir simulator to surface coupler platform technology in a continuous steam injection project. The idea of applying this technology is to bring different domain knowledge and understanding in a common platform in order to optimize energy value.In this study a wide variety of cases like different reservoir rocks and fluids will be reviewed and due to large amount of materials available the focus will be to a basic explanation of the situation, method of implementation of the technology or solution and ultimately final results that were concluded at the time of study. The idea is to show how different method of development can be considered for field development of heavy oil reservoirs and also how simulation and pilot studies can save a considerable amount of money in these projects.