An important aspect for the exploitation of gas condensate reservoirs is the knowledge of the maximum retrograde condensation, due to the volume of liquid that can be trapped if the pressure reaches the zone where this phenomenon occurs because hardly reaches critical fluid saturation as so it can move toward wells. This work proposes a correlation that can be used to predict or validate this property, based on the relationship between the maximum retrograde condensation, the molecular weight (MW) of the original composition and its gas oil ratio. A real case analysis is presented which corrects the maximum retrograde condensation measured in the laboratory, reproducing the full curve of this property, without changing the thermodynamic conditions of the fluid. Also, a conceptual numerical simulation model was built to quantify the behavior and effects if is not corrected the retrograde condensation property in a PVT study.

Naturally fractured reservoirs (NFR) are highly complex from their characterization to thier exploitation; their behavior depends on two systems: the fracture and the matrix. This complex nature hinders the development and adjustment of numerical models; most parameters present high uncertainties. Simulation engineers spend a lot of time obtaining a representative and reliable model. This work was developed with the purpose to establish an assisted history matching methodology using an evolution strategy algorithm (ESA) to accelerate the construction of this reliable model. Evolution algorithms were first showcased in the 1960's and in recent years have expanded their use as a mechanism for acceleration of history matching or production optimization.Additionally we used ESA to relocate already programmed wells and thereby new potential areas for exploitation were identified, where wells weren't considered in the initial development strategy, managing to increase the ultimate recovery factor (URF). Evolution Strategy Algorithm was used successfully in a field of the south of Mexico with a numerical model available, which has a 4 year production history through 14 active wells. The field is a NFR with high production potential and strong water breakthrough in the wells. Starting from a previous simulation model, we establish 3 stages for the proposed work flow:Analysis of geological variables, the discrete fracture network (DFN) and identifying and weighting the impact on the dynamics of both fluids systems. Application of ESA using the variables identified on stage 1, analyzing several simulation models and using an objective function to quantify the miss match from our ideal model. Optimization of the proposed wells, evaluation of areas with exploitation potential and proposing of new wells in these areas using ESA.Using ESA we manage to optimize simulation times and to achieve a reliable and representative model in 75% less time than with our previous effort. This history matched model includes a DFN and reproduces the water breakthrough behavior on 90% of the wells and in 100% of wells with higher oil and water production. The result model was used to relocate the next two proposed wells into a new area applying ESA; where the cumulative oil production was maximized at the end of the simulation period, increasing URF in 2.5% respect to the original development plan and the interference with neighborhood wells were minimized.Finally as consequence of proposed well relocation, we found a new area in the field with potential to allocate an additional well. Setting the ESA to maximize cumulative oil production yield to the location optimization on this new well, thus increased URF another 1.2%. Assisted history matching using ESA reduces substantially time analysis compared with traditional methods and, it was possible to have a reliable model with DFN that reproduces water breakthrough and captures the heterogeneity of the fractured system. The methodology proposed helps to accelerate decision-making with more tec...

In the literature, there isn't a unified criterion to establish a methodology for quality assessment of PVT analysis. Worldwide, engineers have proposed the use of well-known validation methodologies but these validation methodologies not necessarily encompasses the whole consistency of a PVT study or its representativeness of the reservoir fluids. It is well known that a PVT study might have a great consistency after it's validated but when it's used in a reservoir characterization it didn't reproduce the measured behavior of the fluid present in the reservoir. These types of inconsistencies are common and could cause very important errors in analysis such as: Original volume, reserves estimation, surface facilities planning and exploitation strategies. The impact on the results and decisions taken based on the information present in a PVT study can be crucial and therefore every PVT analysis should include a level of uncertainty index that could allow to know beforehand the cost of using such information. The versatility and complexity of most the experiments conducted during a PVT study makes the task of creating a unique methodology of quality quantification difficult. The present paper proposes a methodology for quality control and uncertainty assessment. This methodology considers each of the stages involved in the process of obtaining a PVT analysis: from the fluid sampling to the experiments results. According to previous work and field experience, the most important parameters or conditions were selected at each stage. These parameters are called Critical Points; each Critical Point has and associated impact level (high, medium and low.) and weight that reflects directly in the overall quality index of the PVT study. Critical points were subsequently grouped into 6 Control Categories: Sampling conditions, reservoir conditions, experiments control, measured properties control, fluid type validation and validation of experiment consistency. An ideal value of 10.0 was established for a report PVT that has excellent condition, very low uncertainty and meets all the conditions proposed in this paper. Additionally, a Quality Index (QI) and Validation Index (VI) were proposed as two indicative values of the level of uncertainty of any PVT study. Using a proposed Nomograph, engineers can evaluate and categorize the quality results from any PVT study. The results from applying this methodology to 50 PVT studies are presented and a Material Balance and numerical simulation study were carried out to exemplify the impact of using for the same reservoir, PVT from different level of quality. The goal of this work is to have a practical methodology that can give engineers a "Quality Index" of any PVT study. This quality index could be an indicative of the level of uncertainty and the degree of reliability of the PVT study before it's subsequently used in any reservoir or well analysis. This methodology could be used worldwide without limitations

A great problem of naturally fractured reservoirs is the abrupt irruption of water in wells. To predict this behavior, a methodology that uses numerical sector models and discrete fracture Network (DFN) was designed; so-called Pseudoradial models (PRM). These models were calibrated to match the water invaded wells production history and subsequently it was applied to proposed or new wells. This methodology was used successfully in Pijije field, Mexico.The first pseudoradial models were generated in the Pijije field due to the abrupt water irruption problem it presented. Three well models were built based on the calibration of the model built for the Pijije-101 well. The DFN was generated from average characterization of fractures obtained from FMI logs and general input from the field pressure and production behavior.Once the variables of uncertainty were analyzed, a conventional radial model was initially built and calibrated with the historical production and pressure profiles. To achieve this match, the values of porosity in both systems (matrix and fracture) were changed drastically and the water front advance resulting was homogeneous and only present a coning phenomenon when the OWC reaches a minimum distance of 200 meters from the well. The second part of the analysis was carried out with the pseudoradial model; in this case, the parameters with greater impact were the characteristics of discrete fracture network. The pseudoradial model managed to reproduce the well production and pressure history. Analyzing the results, it was concluded that both scenarios were acceptable. Reviewing the water advance fronts in both cases, the pseudoradial model did not have a uniform front of OWC advance and showed areas not drained (corresponding to present or absence of fractures) and the water moves through the preferential fracture channels represented by the DFN in the model. Two methods for determining critical rates or optimal production rates (OPR) and the OWC advance were evaluated: conventional radial models and pseudoradial models.The study was carried out to the Pijije-101 and Terra JSK field wells that presented abrupt water irruption possibly associated with water conning in the producing formation. Later the methodology was applied to new wells in the same field for calculating their optimal production rates. Although conventional radial model does not consider features and phenomena present in NFR, the movement of fluids and conning effect was correctly model. The pseudoradial model, in the same way, reproduced the dynamic behavior observed in this conventional case but presenting irregular advance of the OWC and areas not drained or partially drained which according to literature is more realistic.The main difference between the two models is the distribution of permeability and how the fluids move within the reservoir. Conventional radial model presents only a vertical variation, while a tensor of permeability (i, j, k) was included in the pseudoradial models. Due to the complexity of the NFR, it is reco...

Many factors affect water movement within the reservoir; it's already known that petrophysical characteristics of the porous media, reservoir fracture networks and exploitation rhythm are some of them. In naturally fractured reservoirs containing near-critical fluids (oil systems) there is evidence that fluid properties have a direct effect in the strong water breakthrough at the time that the saturation pressure is reached in the reservoir.These reservoirs undergo substantial changes in volume and composition, due to its high oil formation volume factors that cause a sudden advance oil water contact that is aided by the presence of fracture networks. This semi-instantaneous variation can be up to 40% loss of liquid saturation and it will depend on the characteristics of the fluid itself. This effect is usually confused by channeling or water coning when conventional techniques are used to diagnose water breakthrough.This work was developed in order to demonstrate the effects and consequences of reaching the saturation pressure in the advancement of water oil contact in naturally fractured reservoirs (NFR) that contains near-critical fluids, using traditional reservoir engineering analysis, novel diagnostic plots and numerical simulation.