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Understanding the flow behaviour of fractured wells is crucial to operators and service companies in evaluating the effectiveness of stimulation work performed on the well. New insights in modelling of well transient pressure tests in hydraulic fractured unconsolidated sand is presented in this paper by utilizing 3-D numerical black oil simulation in single and two layered sand reservoirs with a thin shale layer in between. The upper layer perforated and fractured to treat the sand production as frack-pack technique and the well test has been conducted only on the upper layer. Porosity and permeability heterogeneities are classically evaluated from petrophysic well log measurements and through geological description of the reservoir, then possibly refined by simulation and history matching. The pressure measured in the well test in four cycles of drawdown and build up. The well bottom hole pressure (BHP) behaviour cannot be adequately described with conventional well tests analysis for the upper sand without including the flow from the lower sand. Different scenario of production from upper with adding hydraulic fractured examined to match the oil/gas production and bottom hole pressure. A range of factors are examined that may impact the introduced fracture flow behaviour based on actual fractured well flow. The main fracture and reservoir parameters investigated include absolute permeability of upper layer, gas oil contact (GOC), relative permeability endpoints to oil and gas, hydraulic fracture properties (permeability, width) and extension and finally the skin factor. The results of dynamic simulation model show that the model is very sensitive to the amount of gas production and hydraulic fracture vertical extension. We highlight through this example and sensitivity simulations that the GOC should be very close to the well preformation or else the pressure could not be matched. Hydraulic fracture vertical extension is required for matching of BHP and gas rate, without it, the gas rate will be very high in all of the simulation cases. The fracture connecting the upper layer to lower layer with only upper layer perforated. Absolute permeability from log cannot represent to the real permeably measured from well test. To match all historical data absolute permeability, need to be reduce by one order of magnitude. Finally, the model is sensitive to the skin factor for matching of pressure build up. The main business questions were answered through integrated analysis of the analytical well model and dynamic simulation of single model to identify the source of excess gas and understand the well performance to reduce the uncertainty in production forecast. Fast approach in the single well modeling and efficient approach in the integration in the workflow is described in detail in the paper.
Understanding the flow behaviour of fractured wells is crucial to operators and service companies in evaluating the effectiveness of stimulation work performed on the well. New insights in modelling of well transient pressure tests in hydraulic fractured unconsolidated sand is presented in this paper by utilizing 3-D numerical black oil simulation in single and two layered sand reservoirs with a thin shale layer in between. The upper layer perforated and fractured to treat the sand production as frack-pack technique and the well test has been conducted only on the upper layer. Porosity and permeability heterogeneities are classically evaluated from petrophysic well log measurements and through geological description of the reservoir, then possibly refined by simulation and history matching. The pressure measured in the well test in four cycles of drawdown and build up. The well bottom hole pressure (BHP) behaviour cannot be adequately described with conventional well tests analysis for the upper sand without including the flow from the lower sand. Different scenario of production from upper with adding hydraulic fractured examined to match the oil/gas production and bottom hole pressure. A range of factors are examined that may impact the introduced fracture flow behaviour based on actual fractured well flow. The main fracture and reservoir parameters investigated include absolute permeability of upper layer, gas oil contact (GOC), relative permeability endpoints to oil and gas, hydraulic fracture properties (permeability, width) and extension and finally the skin factor. The results of dynamic simulation model show that the model is very sensitive to the amount of gas production and hydraulic fracture vertical extension. We highlight through this example and sensitivity simulations that the GOC should be very close to the well preformation or else the pressure could not be matched. Hydraulic fracture vertical extension is required for matching of BHP and gas rate, without it, the gas rate will be very high in all of the simulation cases. The fracture connecting the upper layer to lower layer with only upper layer perforated. Absolute permeability from log cannot represent to the real permeably measured from well test. To match all historical data absolute permeability, need to be reduce by one order of magnitude. Finally, the model is sensitive to the skin factor for matching of pressure build up. The main business questions were answered through integrated analysis of the analytical well model and dynamic simulation of single model to identify the source of excess gas and understand the well performance to reduce the uncertainty in production forecast. Fast approach in the single well modeling and efficient approach in the integration in the workflow is described in detail in the paper.
The objective of this paper is to present well control challenges, and results of utilizing wellbore dynamic simulation to achieve safer formation tester (FT) sampling and deep transient tests (DTT) operations. Insight will be provided based on the first implementation in a Southeast-Asia offshore well, with focus on pre-job simulation that is validated with measured data to help improve understanding of gas/hydrocarbon interaction with wellbore mud during and after FT pump-out operations. FT involves obtaining formation pressure, pressure transients, and downhole fluid samples, and the latest DTT technology enables larger gas/hydrocarbon volumes to be pumped into the wellbore which requires a comprehensive understanding of the processes involved. Wellbore dynamics accurately predicts the interactions between downhole pumped hydrocarbon and drilling fluid using a dynamic multiphase flow simulator. For the sampling operation, a maximum allowable downhole gas volume is evaluated prior to operation and simulations are compared to surface gas observation obtained during a wiper trip (mud circulation). During DTT operations, pumped formation fluids are routed to a circulating sub, where they are mixed with circulated mud and the mixed fluids are simultaneously carried to surface. Downhole wellbore pressure measurements are sent to a real time cloud-based dashboard and compared with simulations. The ability to weigh measurements against simulations creates a comprehensive understanding of well control scenarios and provides a much safer execution of FT operations than conventional methods. For wireline FT operation, post job comparison showed that the simulation matched well with surface observations during the wiper trip. The simulator accurately predicted the surface free gas arrival compared to mud-gas logging measurements, which confirmed that gas stayed dissolved in the Synthetic Based Mud (SBM) downhole without migrating upwards. For DTT, wellbore pressure measurements were sent in real time to a cloud-based dashboard and are compared to simulations and simulations could be quickly re-run to account for changes in observed formation fluid, downhole flowrates or mud circulation rates. The FT and DTT operations were conducted successfully and safely and in both cases the measured data agreed well with the simulations. With the accurate wellbore dynamics simulator, changes in drilling fluid design, circulating rates, hydrocarbon composition, downhole pump rates, and pump duration for various FT design sequences are quantified, and the downhole well pressure, free-gas distribution along the well geometry, and gas rates on surface can be predicted. This insight provides more flexibility and understanding to plan advanced FT operations and enables larger volumes of hydrocarbon to be pumped downhole. Furthermore, adopting an advanced pressure transient testing method like DTT also aligns with the industrial effort of reducing carbon dioxide emission footprint.
The objective of this paper is to address the challenges related to well control and highlight the successful implementation of deep transient tests (DTT) operations in an offshore well located in Southeast Asia that was carried out by PETRONAS with the help of a dynamic well control simulation platform. The paper aims to provide insights into the pre-job simulation process, which ensured a safer operation from a well control perspective. Additionally, a comparison between simulated and actual sensor measurements during the DTT operation will be presented. The latest DTT technology enables a higher volume of gas or hydrocarbon to be pumped into wellbore compared to formation tester (FT) operation. During the DTT operation, the pumped formation fluids are mixed with mud that is pumped from surface through a circulation sub into the annulus, and the mixture of fluids is then circulated out from annulus simultaneously to the surface during the drawdown period. To ensure well control safety, it is crucial to have a comprehensive understanding of the processes involved. Therefore, a dynamic multiphase flow simulator that takes into account the interactions between downhole pumped hydrocarbon and drilling fluids is important to better simulate the pressure downhole throughout the DTT operation. In this case study, simulations were conducted prior to the job execution, considering several sensitivities, to ensure that the operation stayed within a safe operating mud weight window while meeting the surface gas handling limits. During DTT execution, real time downhole measurements were sent to a cloud-based platform, where they were plotted on a graph alongside the simulation data for monitoring purposes. Any changes in observed formation fluid, downhole flow rates and mud circulation rates during the DTT operation were quickly reflected in the simulation, this enabled effective communication between the PETRONAS project and execution teams ensuring a safe well control condition throughout the operation. As a result, the DTT operation was conducted successfully and safely, with the measured data aligning well with the simulations. The accurate wellbore dynamics simulator allowed for quantification of changes in drilling fluid design, circulating rates, hydrocarbon composition, downhole pump rates, and pump duration for various formation testing design sequences. It also facilitated predictions of downhole well pressure, free-gas distribution along the well geometry, and gas rate on the surface. This valuable insight provides PETRONAS with more flexibility in understanding and planning advanced FT operations, while enabling larger volumes of hydrocarbons to be pumped downhole. Furthermore, adopting an advanced pressure transient testing method like DTT is in line with both industry and PETRONAS's efforts to reduce carbon dioxide emissions.
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