Production Optimization by Nodal Analysis

As gas field development is a costly business, it is important to ensure that each component in the production system (from the dwonhole completion all the way to the separator) is functioning to its best utilization. The goal of field optimization is to establish the ranges of operating parameters that will ensure then and help achieving the operator’s objective, such as maximizing the production rate of the entire field. This rate is sustainable for the conditions established by the system components (tubing, pipeline, choke, etc.), reservoir pressure, and separator pressure. Nodal Analysis provides a sound method to aid the decision making process for optimization. This project presents the results of a study conducted on the ‘X’ gas field which is producing with two wells. First step was optimizing tubing size for each well. Then a field wide network model was constructed to include the wells and surface facilities. Predictive simulation was run at the network, considering three cases. There are: i) base case, ii) installing surface compressor, iii) drilling a new well. The comparative analysis shows that case 3 is the optimum production strategy for the ‘X’ gas field which provide an increment by around 14% in gas recovery, compared to the base case

A comparison of two-phase inflow performance relationships

Thesis (M.S.)--University of Oklahoma, 1997.Includes bibliographical references (leaves 81-82).In this research, the individual performance of vertical oil wells are investigated. The objective of this study was to verify the suitability of certain empirical relations to predict the rate-pressure behavior of a single oil well producing from solution-gas drive reservoirs. Inflow performance curves were generated for 26 cases based on actual field data. The predicted rates where then compared to actual measured rate and pressure data. The variation between the measured and predicted rates by the various methods studied has been analyzed. Based on this analysis, multipoint performance methods generally provide the most reliable estimates of well performance. Fetkovich' s multipoint method was the most consistent performance predictionfor the cases studied. In addition, it was observed that no one method presented the best results for all cases and it is recommended that multipoint performance methods be utilized to yield a range of potential pressure-production behavior

Analysis of IPR curves in North Slope horizontal producers supported by waterflood and water alternating gas EOR processes

Master's Project (M.S.) University of Alaska Fairbanks, 2019The shape and behavior of IPR curves in waterflooded reservoirs has not previously been defined despite their common use for optimization activities in such systems. This work begins to define the behavior of IPR curves in both water flood and water‐alternating‐gas EOR systems using a fine scale model of the Alpine A‐sand. The behavior of IPRs is extended to 3 additional reservoir systems with differing mobility ratios. Traditionally derived (Vogel, Fetkovich) IPR curves are found to be poor representations of well performance and are shown to lead to non‐optimal gas lift allocations in compression limited production networks. Additionally, the seemingly trivial solution to gas lift optimization in an unconstrained system is shown to be more complex than simply minimizing the bottom hole pressure of the producing well; maximized economic value is achieved at FBHPs greater than zero psi

OPTIMIZATION OF GAS LIFT SYSTEM

The intent behind this study was to optimize the Gas Lift System in order to achieve the target of maximizing the oil production from the four oil wells. To accomplish the optimization process, hurdles or constraints associated were addressed efficiently which resulted in effective outcome. Initial gas injection rates and oil production rates were analyzed by using Well Flo3.8.7 and maximum economic waters cuts were calculated for each well. Increasing water cuts is one of the major constraint that limits the injection gas volume which needs to be optimized and this constraint was addressed by calculating the optimum gas injection rates for all wells using Well Flo3.8.7. The overall comparison between the initial conditions and optimized conditions for all wells were presented in order to provide a clear picture of optimization in terms of oil production and maximum economic water cut. The results for total increase in all production were found to be 25954stb/day and initially it was 19099stb/day. The maximum economic water cut has been improved from 52% to 78%. The second major constraint is the ability of compressor to handle the optimized gas lift volumes and to deliver these gas volumes at sufficient discharge pressure for effective gas lift process, which were addressed by making use of HYSIS simulator. A model of three stage compression system is run in HYSIS simulator by using the designed capacity of compressor in terms of volume and discharge pressure to validate the design ratings and the load of compressor was also calculated at these conditions which includes power consumption by each compression stage and respective inter stage coolers. Another model is run in HYSIS simulator for compression train and the results for the optimum injection gas lift rates (23.8 MMSCFD) were used as an input in this model and hence an optimized model of compression train was obtained which could handle the optimized gas lift volumes at sufficient discharge pressure (3100 psig). In the end the total power consumption for both models was compared together and small increase of 253 KWH were observed which is acceptable in terms of increase in oil production

Performance considerations for horizontal and unconventional wellbore configurations

Thesis (M.S.) University of Alaska Fairbanks, 2002The goal of this study was to investigate the performance of horizontal and unconventional well configurations and formulate guidelines for selecting optimum configuration. The simulation model was validated by comparing the productivity of numerical model for a horizontal well with the analytical models. The productivity of horizontal, snake wells and fishbone wellbore configurations was studied by varying four parameters, vertical position of well in the payzone, permeability anisotropy, partial completion and well length. Effect of friction loss correlations on estimation of well productivity losses was also studied. The study concludes that the ratio vertical position of well, Zw to the payzone thickness, h decreases the productivity of the wells increases. There is no significant change in performance of the wells for different configurations. As the permeability anisotropy ratio decreases the productivity decreases. The cumulative production does not decrease by half when the perforated well length is decreased by half. Also, the productivity index increases with increase in well length. Based on the results obtained we formulate guidelines for selecting well bore configurations. The results of this study can be applied to the design of horizontal and unconventional well configurations to aid reservoir management