Deep gas wells exhibit characteristics such as high temperature and pressure that present challenges in terms of drilling and completions. To overcome these hindrances and deliver the wells in a timely manner, casing design has been optimized by utilizing the latest cutting-edge technology in the oil and gas industry. The subject area has numerous multiple reservoir pressures, which can be troublesome when drilling in one hole section. In the past, these reservoirs had to be isolated from each other by introducing casing strings, or take the risk of drilling through transient zones. The formation characteristics are troublesome as well. Starting from shale swelling to fractures. These shales are very reactive and force controlled drilling parameters while closely watching the fluid properties just to mitigate the trouble zone. Too many casing strings means an expensive well and high target well days. This is a complete review, which will discuss implementation of different technologies in a deep gas well. Advanced bridging agents drilling fluid enabled the well to avoid the operation risks of stuck pipe and optimize the rate of penetration through multiple reservoirs pressures. A 4 ½-in by 7-in completion system capable of 15K hydraulic fracturing was used. Innovative way of locating abnormal pressure formation, even though they are unpredictable. The paper describes a robust solution to well slimming, utilizing the latest technologies, drilling methods and fluid types, while following the original well plan.
Optimum fluid placement is crucial for a successful acid stimulation treatment, especially in thick, highly heterogeneous carbonate formations with multiple zones and/or extensive productive intervals. A variety of diversion methods are applied in acidizing treatments to evenly place acid along the well, but the effectiveness of these diversion methods is generally only inferred from the rate and pressure behavior during the treatment, and is not known with any certainty. Recently, distributed temperature sensing technology has enabled us to observe dynamic temperature profiles along the wellbore during and immediately following an acid treatment. This technology allows us to monitor and evaluate treatments and diversion methods in real-time from captured sequence of temperature profiles at different times during and after acid injection. We presented a mathematical model in previous papers to simulate the temperature behavior in the formation and along the wellbore, during and shortly after an acid treatment (Tan, 2009 and 2011). An inversion procedure was also included to interpret the acid distribution profile from the measured temperature data in a hypothetical example. In this paper, we apply our model to a field case. The well is a gas producers and was stimulated with acid treatments. The temperature data was measured with DTS tool during shut-in period, and shortly after each stage of the treatments. The model is used to quantify the acid distribution with the temperature data to evaluate the efficiency of acid treatments. We have focused on diagnosing the volume of acid placed in each zone with the shut-in temperature data. Results indicate that the model is applicable in the field operation for acid profiling and is helpful to evaluate and optimize acid treatments.
The new advancements in well monitoring tools have increased the amount of data that could be retrieved with great accuracy. The new challenge that we are facing today is to maximize the benefits of the large amount of data provided by these tools. One of these benefits is to utilize the continuous stream of data to determine the flow rate in real time of a multilateral well. Temperature and pressure changes are harder to predict in horizontal laterals compared with vertical wells because of the lack of variation in elevation and geothermal gradient. Thus the need of accurate and high precision gauges becomes critical. A theoretical model is developed to predict temperature and pressure in trilateral wells. The model is used as a forward engine in the study and an inversion procedure is then added to interpret the data to flow profiles. The forward model starts from a specified reservoir with a defined well structure. Pressure, temperature and flow rate in the well system are calculated in the motherbore (main hole) and in the laterals. Then we use the inverse model to interpret the flow rate profiles from the temperature and pressure data measured by the downhole sensors. A gradient-based inversion algorithm is used in this work, which is fast and applicable for real-time monitoring of production performance. In the inverse model, the flow profile is calculated until the one that matches the temperature and pressure in the well is identified. The production distribution from each lateral is determined based on this approach. Examples are presented in the paper. The value of the model approach for production optimization for trilateral wells is illustrated through parametric study.
The new advancements in well monitoring tools have increased the amount of data that could be retrieved with great accuracy. The new challenge that we are facing today is to maximize the benefits of the large amount of data provided by these tools. One of these benefits is to utilize the continuous stream of data to determine the flow rate in real time of a multilateral well. Temperature and pressure changes are harder to predict in horizontal laterals compared with vertical wells because of the lack of variation in elevation and geothermal gradient. Thus the need of accurate and high precision gauges becomes critical. A theoretical model is developed to predict temperature and pressure in trilateral wells. The model is used as a forward engine in the study and an inversion procedure is then added to interpret the data to flow profiles. The forward model starts from a specified reservoir with a defined well structure. Pressure, temperature and flow rate in the well system are calculated in the mother bore (main hole) and in the laterals. Then we use the inverse model to interpret the flow rate profiles from the temperature and pressure data measured by the downhole sensors. A gradient-based inversion algorithm is used in this work, which is fast and applicable for real-time monitoring of production performance. In the inverse model, the flow profile is calculated until the one that matches the temperature and pressure in the well is identified. The production distribution from each lateral is determined based on this approach. Examples are presented in the paper. The value of the model approach for production optimization for trilateral wells is illustrated through parametric study.
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