Real time data provides key information that can be used to monitor oil and gas wells to maintain well integrity and avoid costly failures. Integrity management is at the heart of BP's operating philosophy. The company uses new technologies enabled by real time data to allow continuous improvement in well integrity management.The use of real time rate calculations has provided technical assurance to maximize production within BP's deepwater subsea field development. Production has been increased by 10,000 stb/D while maintaining well integrity and process safety assurance within safe engineering operating limits. Similarly, the Na Kika fields apply advanced flux based tools and sand alarming capabilities to protect wells from sand completion failure. Additional fields are currently using BP proprietary technology to monitor and proactively alarm on wellhead annulus pressures, successfully mitigating the well integrity risk of collapsed tubing.Well integrity management is critical for any operating company. In deep water environments where subsea well costs can exceed 100 million dollars, loss of well integrity can have serious consequences associated with production capability, loss of containment, reputational damage, and regulatory license to operate. Application of new technologies is transforming simplistic past practices into highly sophisticated automated monitoring and advanced control mechanisms enabled by real time data. These technologies have a vital role in delivering advanced capabilities so that engineers can make better decisions, faster, to help retain long term value. This paper, through case studies, will demonstrate the ability to use innovative workflows and technologies, enabled by real time data, to identify and mitigate well integrity risks. Key risks such as annulus leaks, sand control failures, and mechanical failures are monitored using Field of the Future technologies. These examples from different operating areas of BP will demonstrate continuous improvement, showing how engineers use these technologies to maintain well integrity.

Monitoring Deep Water Gulf of Mexico (DW GoM) wells with gravel-pack and frac-pack completions is an increasingly challenging task. Wells often experience increasing skin, adding to the risk of completion failure. Historically, sand control completions have experienced a 15% rate of sand related completion failures (King 2003). The industry tends to qualitatively evaluate safe target rates as skin increases. Reducing the flow rate based entirely on an increase in global skin can be too conservative and over-restrict target rate. Thus, it is important to know which components of the increase in skin can cause the completion to fail. Furthermore, it is not well understood how to quantify a safe target rate with the increased skin. This paper will present a new methodology to evaluate the components of skin increase which could cause sand control completions to fail. The failure mechanism we are addressing is perforations plugging by movement of fines and sand. Our new methodology helps quantify the risk and convert it into a safe target rate. This paper will also present case studies of oil and gas wells in the Na Kika Asset, in DW GoM where this methodology was successfully applied. The well completions are monitored with BP's flux based approach, (Tiffin 2003; Stein, Chitale, et al. 2005; Keck, et al. 2005). In all cases, the wells experienced increased skin, causing the engineers to choke back the well. The analysis showed that some of the skin increase was due to multiphase effects as the reservoir pressure was below the saturation pressure. Accounting for multiphase flow effects resulted in a 30% higher safe operating rate limit than with a conventional analysis. We also determined which skin components likely caused perforations plugging, thereby increasing the completion flux. The results allowed the Na Kika Asset to produce these wells at their maximum allowable safe operating rate with the higher skin, while producing within the BP's flux based guidelines. Introduction Setting a safe target rate for gravel packed DW GoM wells is a complex task of maximizing production while preserving the completion integrity. An industry study done by King (2003) showed a 15% failure rate in gravel packed completions. Operators control these wells using a maximum drawdown limit and generally over-constrain the production to avoid failures. Gravel packed and frac-packed wells have a tendency to build skin in and around the completion. It is believed that skin increase can cause completion damage. Before this study BP and the industry used a qualitative approach in determining the reduction in production necessary to mitigate the increased risk of well failure. Skin can increase due to various reasons such as fines migration, pseudo-skin due to relative permeability effects etc. Some of these skin components can be responsible for plugging the perforations and/or screens increasing the risk of failure and need to be accounted for in determining a safe target rate. We believe that some of the other skin components may not increase completion damage risk and can be discounted allowing favorable rate determination. To address this issue, BP set out to develop a quantitative relationship between failures and skin increase to improve upon the previously published flux based approach (Tiffin 2003). This work will present how the relevant components of skin can be used to correct the flux calculation.

An integrated multiphase flow well and electrical submersible pump model was used to optimize operating procedures for initial well clean-up and ramp up to production for a major deepwater production system before first oil. An integrated modeling approach was crucial to create and test start-up scenarios given uncertainty in the amount of completion fluid in tubing, uncertainty in density of near wellbore fluid and lack of prior experience in ESP operation. The model was used to simulate numerous well start-up scenarios:Well BS&W rate profiles as a function of frac pack fluid recovery percentageWell unloading profiles as a function of injected base volumeNatural flowing well start-up profilesChemical injection volumes and associated surface injection pressuresPressure surging across the completion during ESP start-upsNumber of "A" annulus bleeds required during initial start-up Accurately simulating such highly transient scenarios requires integrating multiphase flow phenomena in tubing to reservoir inflow and dynamic pump behavior. The integrated model proved to be very valuable in finalizing well start-up procedure with a high degree of confidence. This fully dynamic model can estimate phase, pressure, temperature and flow anywhere in the tubing including effect of well choke operations, pump pressure and temperature dynamics based on speed, effect of downhole conditions, and reservoir inflow. The transient behavior in tubing and annulus upon switching on or off ESP pump during well operation is also accurately represented. In this paper, we will present how the integrated model was developed, how it was used to simulate various scenarios and how the results were used to create and validate well start-up procedure. The methodology presented here is applicable to any well using ESP artificial lift methods. This model is a very useful tool not only for engineering simulation, but for operator training and real-time surveillance as well.

Monitoring deepwater Gulf of Mexico (DW GOM) wells with gravel-pack and frac-pack completions is an increasingly challenging task. Wells often experience increasing skin, adding to the risk of completion failure. Historically, sand-control completions have experienced a 15% rate of sand-related completion failure (King et al. 2003). The industry tends to evaluate safe target rates qualitatively as skin increases. Reducing the flow rate entirely on the basis of an increase in global skin can be too conservative and can overrestrict target rate. Thus, it is important to know which components of the increase in skin can cause the completion to fail. Furthermore, it is not well understood how to quantify a safe target rate with the increased skin.This paper will present a new methodology to evaluate the components of skin increase that could cause sand-control completions to fail. The failure mechanism we address is perforation plugging by movement of fines and sand. Our new methodology helps to quantify the risk and convert it into a safe target rate. This paper will also present case studies of oil and gas wells in the Na Kika asset in DW GOM where this methodology was applied successfully.The well completions are monitored with BP's flux-based approach (Tiffin et al. 2003;Stein et al. 2005;Keck et al. 2005). In all cases, the wells experienced increased skin, causing the engineers to choke back the wells. The analysis showed that some of the skin increase was because of multiphase effects as the reservoir pressure was below the saturation pressure. We also determined which skin components likely caused perforation plugging, thereby increasing the completion flux. Accounting for multiphase-flow effects resulted in a higher safe-operating rate limit than with a conventional analysis. The results allowed the Na Kika asset to produce these wells at their maximum allowable safe-operating rate with the higher skin while producing within BP's flux-based guidelines.

This manuscript presents the results and analyses from an integrated simulation study focused on evaluating and selecting subsea boosting systems. The integrated model uses field management strategies incorporating flow-line routing, field and gathering network constraints and rate allocation. Novel techniques to model subsea networks enable the selection of the boosting system and provide an improved understanding of dynamic conditions encountered in deep water assets. The selected boosting system ensures safe and reliable operations while improving the project's net present value. Combining responses from reservoir and network systems into an integrated model to evaluate the subsea design requirements is a unique aspect of this study, as this involves novel modeling techniques for boosting systems (pumps). The robust approach ensures consistency of phase behavior across the system components, identification of pump requirements, production optimization and cost reduction. Analysis of these outputs leads to an improved understanding of field operation strategies, equipment selection and sizing, and production forecasts. The integrated model uses Inflow Performance Relationships (IPR) from reservoir simulation and vertical lift tables to generate Performance Curves (PC), representing well deliverability as a function of Tubing Head Pressure. Comprehensive field management logic uses the PCs to determine optimal well operating rates that satisfy all subsurface and surface constraints. This approach reduces a complex set of constraints into a single operating rate. Well operating rate, is also a function of pump power, pump suction pressure and the fluid phase behavior across the pumps. The integrated model delivers pump performance within its operating envelope and ensures equipment integrity. Two components of the subsea boosting system, single- and multi-phase pumps, drove performance optimization and selection of system operating conditions. The study incorporated a comprehensive analysis of system constraints through implementation of complex field management rules that accounted for well integrity (completions), performance of network equipment (valves, boosters, pump power requirements), facility capacities, and reservoir deliverability. The integrated study identified the different limiting system constraints throughout the life of the field and improved the overall efficiency of the gathering system. Use of PCs to reduce the constraints into a single operating rate provides tremendous computational performance improvement. Moreover, unlike typical optimization problems, adding more constraints to the system did not affect computational performance significantly.