Steam generation for the purposes of thermal recovery includes facilities to treat the water (produced water or fresh water), generate the steam, and transport it to the injection wells. A steamflood uses high-quality steam injected into an oil reservoir. The quality of steam is defined as the weight percent of steam in the vapor phase to the total weight of steam. The higher the steam quality, the more heat is carried by this steam. High-quality steam provides heat to reduce oil viscosity, which mobilizes and sweeps the crude to the producing wells.

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Fines migration is a recognized source of formation damage in some production wells, particularly in sandstones. Direct evidence of fines-induced formation damage in production wells is often difficult to come by. Although most other forms of formation damage have obvious indicators of the problem, the field symptoms of fines migration are much more subtle. Indirect evidence such as declining productivity over a period of several weeks or months is the most common symptom. This reduction in productivity can usually be reversed by mud-acid treatments.

The complete paper describes piloting the collection and analysis of distributed temperature and acoustic sensing (DTS and DAS, respectively) data to characterize flow-control-device (FCD) performance and help improve understanding of steam-assisted gravity drainage (SAGD) inflow distribution.

This commentary has been prepared by the SPE Reservoir Advisory Committee (RAC) to provide high-level insights for the discussion on the potential consequences of long-term shut-ins on conventional and unconventional reservoirs. The RAC comprises 61 subject matter experts (SMEs) covering the domain of reservoir technical discipline. The views presented in the commentary are the opinions of the SMEs and do not constitute an official position of the SPE on the subject matter. From a completions, production, and facilities perspective, there are significant, and potentially devastating, effects for the long-term shut-ins of wells. Everything we leave in the well and the surface facilities will be subject to corrosion, deterioration, and other chemical/mechanical effects. Perforations and the well itself may become plugged and deformed and the pumps and bottomhole assemblies may be rendered dysfunctional due to the settlement of sand and other debris/contaminants. Moreover, scale buildup and wax and asphaltene precipitation in and around the wellbore are well-known potential problems during shut-ins. The oil and gas industry has a very long history of well surveillance, well maintenance, and well remediation--but as an induction, we have not had any circumstances on the scale of the current situation.

Summary Late in the life of the Steam Assisted Gravity Drainage (SAGD) process, it has become common practice to drill a single, horizontal infill well (called a “Wedge Well™” by some) in the oil bank located between two mature SAGD well pairs to produce the bitumen that has been heated and mobilized but is unable to be effectively drained by gravity given the largely lateral location relative to that of the SAGD producers. Since this oil bank is surrounded by the large, depleted steam chamber created by the existing well pairs, it requires little heat to mobilize bitumen. One of the challenges, however, in producing infill wells is that non-uniform drainage and local hot spots can be readily created in the first year of their operation, that in many cases require completion retrofits, such as with Flow Control Devices (FCDs), to improve the drainage profile. Installation of FCDs in these wells is quite challenging since the dynamics of the infill wells is changing with time and there is limited time to achieve conformance. To maintain pressure in SAGD chambers the common practice is to inject non-condensable gas (NCG). NCGs, such as methane, which is most common, do not condense in the steam chamber. Some of these NCG can short-cut into the infill through the existing hot-spot. The main reason is that the hot sections of infills are locations that are closer to the SAGD steam chamber, and due to steam condensate encroachment and higher mobility create a pathway for NCG breakthrough. FCDs are designed to promote a more uniform flux distribution along the producer, and exposure to NCG can change the impact of the FCDs. The true hot-spot temperature after NCG injection is decreasing and this can be mistaken as FCD efficiency and steam blocking. In reality, this temperature reduction is due to partial pressure effects associated with NCG encroachment. In this study, a new thermodynamic model is created to explain the NCG encroachment into infill wells, and a new temperature profile along the producer as a function of NCG breakthrough is calculated. The purpose of this work is to create a productivity index (PI) relationship that is fit for purpose for infill wells adjacent to SAGD well-pairs with NCG breakthrough that can primarily be used for analysis and optimization of SAGD FCD completions. This model can also be used to evaluate FCD performance in infill wells pre- and post- NCG breakthrough.

ABSTRACT The design of Flow Control Devices (FCDs) requires performance data of an FCD’s internal nozzle under a wide range of flow scenarios. The current study specifically considers the effect of nozzle diameter and wall profile on the induced pressure loss, and subsequently the recovery performance of an FCD. For this study, a flow measurement facility is developed to test the performance of different orifice/nozzle geometries. The flow of single- and two-phase fluid at various flow rates and mass fractions, is experimented. The pressure drop data from the experiments is used to produce performance curves that characterize pressure loss across the geometries. The pressure loss for two-phase flows are compared to their single-phase counterparts to characterize the performance of the tested geometries in the two scenarios. A detailed protocol for performance testing of FCDs is followed as per Advanced Well Equipment Standard (AWES: recommended practice3362). The testing protocol was utilized to characterize the performance of different FCDs geometries under single- and two-phase flow conditions. The results showed the pressure loss characteristic obtained from the flow loop experiments match the corresponding theories. The study has thus provided promising results for the successful application of direct flow loop testing to obtain reliable data which can be used in FCD design, performance investigation, and reservoir simulation.

Abstract In wake of the biggest oil crash in history triggered by the COVID-19 pandemic; Western Canada in- situ production is under tremendous price pressure. Therefore, the operators may consider shut in the wells. Current investigation offers an insight into the effect of near-wellbore skin buildup because of such shut-in. A series of simulation studies was performed to quantitatively address the impact of well shut-in on the long-term performance of well, in particular on key performance indicators of the well including cumulative steam to oil ratio and cumulative oil production. The long-term shut-in contributes to three main modes of plugging: (1) near-wellbore pore plugging by clays and fines, (2) scaling, and (3) chemical consolidation induced by corrosion. A series of carefully designed simulations was also utilized to understand the potential of skin buildup in the near-wellbore region and within different sand control devices. The simulation results showed a higher sensitivity of well performance to shut-in for the wells in the initial stage of SAGD production. If the well is shut in during the first years, the total reduction in cumulative oil production is much higher compared to a well which is shut-in during late SAGD production life. As the induced skin due to shut-in increases, the ultimate cumulative oil production drops whose magnitude depends on well completion designs. The highest effect on the cumulative oil production is in the case of completion designs with flow control devices (liner deployed and tubing deployed completions). Therefore, wellbore hydraulics and completion design play key roles in the maintenance of uniform inflow profile, and the skin buildup due to shut-in poses a high risk of inflow problem and increases the risk of hot-spot development and steam breakthrough. This investigation offers a new understanding concerning the effect of shut-in and wellbore skin buildup on SAGD operation. It helps production and completion engineers to better understand and select candidate wells for shut-in and subsequently to minimize the skin buildup in wells.

Abstract Connacher Oil and Gas has deployed Flow Control Devices (FCDs)on an infill well liner as part of a Steam Assisted Gravity Drainage (SAGD) exploitation strategy. Infill wells are horizontal wells drilled in between offsetting SAGD well pairs in order to access bypassed pay and accelerate recovery. These wells can have huge variability in productivity, based on several factors: variable initial temperature due to variable steam chamber development and initial mobility variable injectivity from day one limiting steam circulation and stimulation significant hot spots during production that limit drawdown of the well and oil productivity FCDs have shown great value in several SAGD schemes and are becoming common throughout SAGD applications to manage similar challenges in SAGD pairs, but their application in infill wells is less prevalent and presents a novel challenge to design and evaluate performance. This case study will examine the theory, operation, and early field results of this field trial. Density-based FCDs designed for thermal operations were selected to minimize the impact of viscous fluids commonly encountered early in cold infill well production. The design also limited steam outflow during the stimulation phase, where steam is injected in order to initiate production of the well. Distributed Temperature Sensing (DTS) data, pressures and rates are utilized to analyze the impact of the FCDs towards conformance of the well in the early life. The value of FCDs has led to further piloting of this technology in a second group of nine infill wells, where further value is to be extracted using slimmer wellbores.

Abstract Steam-Assisted Gravity Drainage (SAGD) is a complex process that often requires more control relative to conventional applications during production operations. Flow Control Devices (FCDs) have been identified as one of the technologies that offer improved downhole steam utilization and injection/production efficiency. The first FCD completions, with a helical geometry, were installed in SAGD wells at the ConocoPhillips Surmont project over a decade ago. The installations have shown improved steam chamber conformance and reduced steam-oil ratio (SOR) while accelerating bitumen production. Since then, various FCD geometries have been investigated and used, with several of them explicitly designed with a steam blocking capability. This study used a numerical simulator to investigate the performance of these various FCD geometries. This comprehensive study started testing several geometries in a flow loop and using the data obtained to develop a mechanistic model to characterize the flow performance of the FCDs and finally evaluating their performance in a holistic manner via a numerical simulator. By using mechanistic modeling, it was ensured that the performance of the devices was accurately represented, and the physics of the process were considered. The analysis used a commercially available numerical simulator to evaluate the performance of the various FCD geometries in SAGD operation. Three sector models representing different reservoir qualities observed in Surmont were used for the analysis. Additionally, various operating strategies were investigated for each sector model to ensure that a comprehensive understanding of each FCD geometry was achieved. The results of this study showed that FCD flow resistance setting or nozzle size played a significant role in the production performance of the wells in liner deployed FCD applications. Additionally, the steam blocking geometries resulted in increased cumulative production and lower SOR relative to other geometries. The FCD geometry did also impact the development of the steam chamber. Nevertheless, if the FCD completions are configured with the proper flow resistance setting or nozzle size, they provide a proactive measure, which leads to significantly better performance compared to a non-FCD completion. With lower subcool, the geometry of the FCD has a greater impact on the performance of the well. It was also confirmed that an aggressive operating strategy results in better performance of the FCD completions.