A new optimized method in wellbore to improve gas recovery in shale reservoirs

With the scale development of shale gas, the importance of selecting appropriate deliquification process has become increasingly evident in maintaining well productivity and improving shale gas recovery rate. At present, the preferred deliquification process are macro-control plate method and field experience method. The existing methods can only qualitatively select the deliquification process by considering limited influencing factors, resulting in poor process implementation. Based on the results of error analysis, the Gray model was optimized to calculate the pressure distribution in the shale gas wellbore and determine the applicable pressure limit. The W.Z.B. empirical model, which fully considers the influence of wellbore inclination, is used to calculate the gas-liquid carrying situation and determine the applicable liquid carrying limit. By analyzing the technical limits of five commonly used deliquification processes in the Changning shale gas field, namely, plunger lift, optimizing pipe string, gas lift, foam drainage, and intermittent production, a quantitative optimization method for deliquification processes was established. This method was then used to obtain the optimization chart for deliquification processes in shale gas wells. This method was applied in Well Ning 209-X, where the corresponding optimization chart for deliquification processes was drawn based on the production characteristics of the gas well. By quantitatively optimizing the deliquification processes and adjusting to suitable techniques, it effectively guided the production of the gas well and improved the gas field recovery rate

Transient multiphase flow simulation for unloading of frac hit gas wells

This work seeks to develop a fully step-by-step transient multiphase flow simulation valid for unloading gas wells using nitrogen. It studies the behavior of nitrogen for unloading horizontal gas wells with gas injection in the annulus. The work investigates unloading non-Newtonian fluids such as those which invade offset wells when a frac hit occurs during hydraulic fracturing operations in unconventional wells. The effect of varying tubing depth and injection pressure are included in the study. Results show that as the plastic viscosity increases, the nitrogen volume and time to unload will be increased. As tubing depth increases, the nitrogen volume and time to unload the liquid will be increased. However, deepening the tubing has the impact of sweeping more fluids from the lateral section and reducing the hold-up in the horizontal section. As nitrogen injection pressure increases, the nitrogen volume and the time to unload the fluids decrease. Increasing the injection rate of nitrogen will increase the nitrogen volume required to unload but decrease the time to unloading. Several case studies are simulated using methane as an alternative for nitrogen. The results show that unloading with methane requires a higher volume than nitrogen. Changing the casing size impacts the unloading process as well. This work serves as a practical guideline for unloading frac hits in unconventional shale play gas wells --Abstract, page iii

Prediction of Liquid Accumulation in Gas Wells to Forecast the Critical Flowrate and the Loading Status of Individual Wells

Liquid accumulation is a major problem in gas wells. The inability of gas to lift coproduced liquids to the surface imposes back pressure on the reservoir, limits the ultimate recovery and ultimately kills the well if improperly managed. Therefore, accurate prediction of its occurrence and reliable monitoring strategy is key to effectively handling liquid accumulation in gas wells. In this study, machine learning algorithms were used to develop regression and classification models to accurately predict the critical flowrate and the loading status of individual wells. The regression models used are the feed-forward neural network and a least squares support vector machine models while the decision trees model was used as the classification model to characterize the loading status of the wells investigated. These models were validated using actual published data and it was observed that the feed-forward neural network performed better in predicting the critical rate compared to the least squares support vector machine model with an R2 value of 0.9833, and thus was adopted. The feed-forward neural network model was further compared with other critical rate models; and a consistent result with least percent error of 5.571% was also observed.  Form this study, it is obvious that the neural network model provide benefits and good prospects in investigating liquid loading phenomena in gas wells compared to empirical models that apply so many simplifying assumptions

Modeling Two-Phase Pipe Flow in Liquid Loading Gas Wells Using The Concept of Characteristic Velocity

This work focuses on situations of particular significance in natural gas producing wells, when a certain condition brings about drastic liquid content increase, leading to a rich group of phenomena in the field, known as "liquid loading". Under circumstances believed to precede liquid loading, the still steady-state and stable liquid holdup may be several folds larger than the inlet volumetric fraction of the liquid due to partial flow reversal. This leads to increased resistance in the pathway of the produced gas, triggering instability in the coupled well-reservoir system and ultimately causing the end of the natural flow of gas from the reservoir to the surface. In contrast to the standard models of liquid loading that relate the “onset of liquid loading” to the concept of “critical gas velocity,” we present a new wellbore model that is able to track the most important liquid loading symptom, namely the long-term gradual increase of overall wellbore liquid content and the progression of the strongly related bottomhole pressure. The new empirical correlation was developed based on the multiphase upward flow measurement in a long vertical pipe. The model is shown to have capability in reproducing various published experimental and vertical gas well data sets with a reasonable accuracy. Additionally, we applied the new wellbore formulation in deviated gas wells affected by both liquid loading situations as well as artificial lift systems. The new model is a flow-pattern-dependent correlation, hence, convenient to be used for simultaneous multi-well calculations. The derivation is straightforward, while still able to capture the physics of two-phase conditions. The results indicate that the new wellbore model is suitable to be used in analyzing and diagnosing liquid loading culmination processes. An increased was observed in the liquid content and corresponding flowing bottomhole pressure before gas production became interrupted. Additionally, the new correlation provides a more realistic contribution from each pressure gradient component

Fluid Flow and Heat Modeling in the Wellbore and its Applications

Heat and fluid transport govern many problems in the field of petroleum engineering. Their applications are widespread in almost all aspects of the petroleum production system. This study focuses on one aspect of this system: the wellbore conduit and the fluid and thermal flow inside the wellbore. In this work, multiple fluid and heat flow models are developed to aid in different applications such as transient testing, production rate estimation, and artificial lift. All the models developed are validated using field data or data from literature. The first category of models is developed for short-term testing. Given that short-duration tests (closed-chamber tests (CCT) and slug) can last only a few minutes, particularly in high-conductivity reservoirs, the challenge was approached with a two-fold strategy. First, a forward model was developed to design the chamber length to ensure that interpretable test data was collected. Second, the CCT and slug tests were combined so that the total test duration could be controlled, particularly in high-conductivity reservoirs. The approach presented here allowed individual treatment of slug, CCT, and reverse-slug or injection test for underpressured reservoirs. Overall, the models present a simple, yet complete approach to design and analysis of these short-term tests. The next category of models helps to determine production rate by analyzing thermal flow from the wellbore into the formation. The objective of this part of the study is two-fold: to estimate rate from measured temperature data available for downhole telemetry with a rigorous transient analytical model, and to show the possible use of the computed rates to perform pressure transient analysis for both the pre- and post-cleanup periods. Comparing and contrasting permeability estimates from the two periods provides guidance on the suitability of this approach. Another application presented here explores determining zonal contributions similarly using transient analytical model and temperature logging data gathered during a production logging job. Lastly, a simplified modeling approach is presented for the design of plunger lift for wells in gas reservoirs with significant water production. The proposed model allows for an efficient design of plunger lift by incorporating energy balance in the wellbore

Oilfield Flare Gas Electricity Systems (OFFGASES Project)

The Oilfield Flare Gas Electricity Systems (OFFGASES) project was developed in response to a cooperative agreement offering by the U.S. Department of Energy (DOE) and the National Energy Technology Laboratory (NETL) under Preferred Upstream Management Projects (PUMP III). Project partners included the Interstate Oil and Gas Compact Commission (IOGCC) as lead agency working with the California Energy Commission (CEC) and the California Oil Producers Electric Cooperative (COPE). The project was designed to demonstrate that the entire range of oilfield 'stranded gases' (gas production that can not be delivered to a commercial market because it is poor quality, or the quantity is too small to be economically sold, or there are no pipeline facilities to transport it to market) can be cost-effectively harnessed to make electricity. The utilization of existing, proven distribution generation (DG) technologies to generate electricity was field-tested successfully at four marginal well sites, selected to cover a variety of potential scenarios: high Btu, medium Btu, ultra-low Btu gas, as well as a 'harsh', or high contaminant, gas. Two of the four sites for the OFFGASES project were idle wells that were shut in because of a lack of viable solutions for the stranded noncommercial gas that they produced. Converting stranded gas to useable electrical energy eliminates a waste stream that has potential negative environmental impacts to the oil production operation. The electricity produced will offset that which normally would be purchased from an electric utility, potentially lowering operating costs and extending the economic life of the oil wells. Of the piloted sites, the most promising technologies to handle the range were microturbines that have very low emissions. One recently developed product, the Flex-Microturbine, has the potential to handle the entire range of oilfield gases. It is deployed at an oilfield near Santa Barbara to run on waste gas that is only 4% the strength of natural gas. The cost of producing oil is to a large extent the cost of electric power used to extract and deliver the oil. Researchers have identified stranded and flared gas in California that could generate 400 megawatts of power, and believe that there is at least an additional 2,000 megawatts that have not been identified. Since California accounts for about 14.5% of the total domestic oil production, it is reasonable to assume that about 16,500 megawatts could be generated throughout the United States. This power could restore the cost-effectiveness of thousands of oil wells, increasing oil production by millions of barrels a year, while reducing emissions and greenhouse gas emissions by burning the gas in clean distributed generators rather than flaring or venting the stranded gases. Most turbines and engines are designed for standardized, high-quality gas. However, emerging technologies such as microturbines have increased the options for a broader range of fuels. By demonstrating practical means to consume the four gas streams, the project showed that any gases whose properties are between the extreme conditions also could be utilized. The economics of doing so depends on factors such as the value of additional oil recovered, the price of electricity produced, and the alternate costs to dispose of stranded gas