All producing wells experience reservoir pressure depletion which will ultimately cause production to cease. However, the accumulation of wellbore liquid known as liquid loading can reduce production at a faster rate bringing forward the end of well life. In theory, there are many works written on liquid loading in unconventional wells however, these assumptions are challenged when implemented in the field. The aim of this paper is to investigate the relationship between empirical and mechanistic methods used to determine liquid loading critical rates for volatile oil and gas condensate wells, improving liquid loading forecast workflow for future wells. The study was carried on a wide Pressure, Volume, and Temperature (PVT) window with varying compositions ranging from gas condensate to volatile oils. Wells with liquid loading exhibit sharp drops and fluctuations in production. Due to the wide variation in composition however, correlations used must be varied whilst accounting for both composition and horizontal configuration of the well. Using Nodal Analysis methods, Inflow Performance Relationships (IPR) and Vertical Lift Profile (VLP) curves were created from different correlation models fitted for multiple wells selected for this study to optimize well performance. By combining theoretical analysis and field practices for estimating liquid loading critical rate, the appropriate workflow was determined for the volatile oil and gas condensate wells. When comparing the critical rate for liquid loading calculated from theoretical methods against actual rates seen in the field, an inconsistency was observed between the two values for several wells. By establishing a relationship between field estimate and theoretical calculations, liquid loading was forecasted with greater certainty for varying PVT windows. When the liquid loading rate is determined earlier on, the production efficiency can be improved by deploying unloading measures, increasing the well’s producing life, and ultimately alleviating economic losses. By investigating, we were able to establish a suitable process to predict liquid loading critical rates for volatile oil and gas condensate wells. This workflow can be utilized by production engineers to arrange for liquid loading mitigation increasing well life and improving well economics.
Unlike conventional reservoirs, unconventional shale reservoirs have significantly lower permeabilities and therefore exhibit transient behavior for longer periods of time, creating uncertainty in reservoir parameters during simulation. Currently, there is no standard industry technique to assess gas deliverability in unconventional reservoirs. The aim of this paper is to present a workflow to calculate Estimated Ultimate Recovery (EUR) and optimize field development that was applied for a multistage fractured horizontal well in a shale play in Saudi Arabia. The workflow starts with using a combination of Decline Curve Analysis (DCA) and Rate Transient Analysis (RTA) methods performed with reservoir simulation software. To achieve an initial estimate of the EUR, we employed the following decline curve models: Stretched Exponential and Duong. After establishing a range of EUR values, a history match was carried out by varying porosity, permeability, stage number, fracture half-length, lateral length, and the Stimulated Reservoir Volume (SRV). We then performed a numerical simulation, where reservoir properties and compeletion pamaters were altered until the simulated data matched the production data. We then performed a sensitivity analysis on the results where the reservoir and well parameters were changed and compared against the cumulative gas production to assess the influence of each parameter on well deliverability while considering the economics of such sensitivities. The economic analysis was carried out by calculating the Net Present Value (NPV), which is dependent on the gas rate, shrinkage, and price, and stimulation and operation costs. The economic evaluation was then carried out by sensitizing different completion parameters, which were then determined for subsequent wells in the area. The results of the sensitivity analysis indicate that increasing the fracture half-length has the most significant impact on the gas production when compared to other completion parameters such as the number of fractured stages. The proposed workflow can be used to determine the EUR and the optimum field development plan for an unconventional shale well in Saudi Arabia to maximize gas production while reducing costs. The workflow can be also used, through the suggested tools, to improve our understanding of the behavior of unconventional gas plays
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