Formation damage caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability. When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.

To quantify formation damage and understand its impact on hydrocarbon production, one must have reasonable estimates of the flow efficiency or skin factor. Several methods have been proposed to evaluate these quantities for oil and gas wells. Multirate tests can be conducted on both oil and gas wells. In these tests, several stabilized flow rates, qi, are achieved at corresponding stabilized flowing bottomhole pressures, pwf. The simplest analysis considers two different stabilized rates and pressures.

The three primary functions of a drilling fluid depend on the flow of drilling fluids and the pressures associated with that flow. These functions includes: The transport of cuttings out of the wellbore, prevention of fluid influx, and the maintenance of wellbore stability. If the wellbore pressure exceeds the fracture pressure, fluids will be lost to the formation. If the wellbore pressure falls below the pore pressure, fluids will flow into the wellbore, perhaps causing a blowout. It is clear that accurate wellbore pressure prediction is necessary. To properly engineer a drilling fluid system, it is necessary to be able to predict pressures and flows of fluids in the wellbore.

It looks like a meaningless mess, which is generally how the ups and downs of difficult stages are viewed. To Adam Hoffman, a completion engineer for Chesapeake Energy, those 47-stages-worth of data look like a valuable opportunity. "We see so many stages with so many odd spikes and drops or chatter. We chop it off and say that was an odd stage. In my mind when we are looking at all those stages, we should wonder, 'what was that pressure spike telling us,'" he said. That curiosity became a research project after Chesapeake encountered a spate of blockages in recently fractured Eagle Ford wells.

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 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.

Abstract ConocoPhillips operates Surmont, which is the first Steam-Assisted Gravity Drainage (SAGD) project to implement Flow Control Devices (FCDs) in producer wells. This study was conducted to evaluate the production performance of different liner completion strategies. The analysis compared well pairs completed with slotted liners (SL) to producers completed with FCDs, both liner deployed (LD-FCD) and tubing deployed (TD-FCD), and investigated the impact of FCDs in injectors. An extensive analysis was conducted using available production and temperature data along the wells. The wells were completed using various fixed-resistance FCD settings, while some wells were completed using variable setting designs. As time went on, several of the slotted liner producer wells were retrofitted with tubing-deployed FCD completions. One of the key objectives of the study was to determine the success rate of tubing-deployed FCDs and their performance relative to liner-deployed FCD wells. Another objective was to evaluate the impact of retrofitting slotted liner SAGD injectors with tubing-deployed FCD completions. In this study, a grading system was established based on the reservoir quality along the well for both injector and producer. For similar graded well pairs, LD-FCDs had better production performance than TD-FCDs. Considering similar graded reservoir quality, FCDs consistently performed better than slotted liners, in both conformance and production acceleration. The production analysis showed that the FCD flow restriction was a major controller of the conformance, but considering the self-choking phenomenon of the reservoir, most FCDs can perform positively in different circumstances. In this study, the self-choking effect of the liquid pool is discussed and explained for different reservoirs and variable subcool. Generally, if erosion is not a factor, FCDs can create a more controlling system than liquid-pool dominant systems. In these cases, both conformance and production acceleration is enhanced if operators yield lower subcools and greater draw-down pressures.

Abstract Flow control devices (FCDs) have demonstrated significant potential in improving recovery from Steam Assisted Gravity Drainage (SAGD) production wells. Passive FCDs will allow the SAGD producer well to create additional pressure drop to balance the production influx, improving overall conformance and promoting accelerated hydrocarbon production. However, passive FCDs cannot effectively restrict steam effluents once steam breakthrough at the production well occurs. The Autonomous Inflow Control Valve (AICV) actively delivers a dynamic flow restriction with the ability to choke and/or ‘shut-off’ in response to the associated viscosity and density of the fluids flowing through the AICV. This novel AICV design behaves truly autonomously based on the Hagen-Poiseuille equation and Bernoulli’s principle. The AICV utilizes the differences in flow behaviour between the laminar and turbulent flow restrictions to differentiate the pressure-drops between oil, water, gas, and steam phases. A collaborative effort has been initiated between the AICV vendor and the Computer Modelling Group to develop reservoir simulation workflows with the AICV that will allow the user to enter characteristic performance curves for a variety of SAGD and thermal fields. The development of mechanistic wellbore modelling and developed methodology to incorporate the associated complexities of AICV behaviour has shown to be an improvement to the way FCDs are currently modelled, providing insight into the potential for AICV application in SAGD and other thermal recovery operations. Such techniques allow the reservoir simulation tools to perform realistic predictions of the AICV behaviour at downhole conditions and evaluate scenarios and relative impacts of completion designs. The development of a new characterization method of AICV performance in SAGD applications, and its implementation in reservoir simulation tools, has helped to unveil the benefits of implementing AICVs in improving recovery from SAGD operations.

After 6 years of using its custom-built drilling advisory system, Brazilian oil and gas company Petrobras has become increasingly confident in the technology's abilities to help prevent many of the complex problems that challenge pre-salt drilling operations. Between the summer of 2014 and the end of 2019, the company credits the software innovation with the prediction of more than 100 drilling issues ranging from stuck-pipe events to drillpipe leaks. Petrobras said the early warnings prevented an additional 150 days of deepwater drilling which amounts to $130 million in savings, in a new paper (SPE 199077) published in July during the SPE Virtual Latin American and Caribbean Petroleum Engineering Conference. André Leibsohn Martins, a senior consultant with Petrobras, emphasized that the headline figure is "only from diagnosis" of drilling problems and does not include gains Petrobras has made in terms of optimizing the drilling process. More details on that front may be forthcoming since he said the operator is expanding the capabilities of the software to launch a full-fledged drilling optimization campaign next year.