A pilot test of an integrated sand and erosion alarming process has been implemented in the NaKika field, in the Gulf of Mexico. All wells have sand control completions. Except for one well with a gravel pack completion problem, all the other wells are controlled by a flux limit (SPE Paper 84495). A Microsoft Excel based program was developed to automatically receive daily morning report data, and perform nodal analysis calculations on all of the wells, in order to estimate: mechanical skin corrected for relative permeability changes, pressure drawdown, gravel pack flux, and wellhead velocities. The wellhead velocities were utilized to calculate erosion rate to estimate metal loss. Corrosion rate at the wellhead was also estimated. All calculated results are sent to OSI PI as data tags and viewable through a commercial real time trend-analysis program. The Excel program results are also automatically emailed to the engineers. The gravel pack flux limits are used to make sure we do not produce the wells at rates which increase the probability of sand control failure. Monitoring of the flux results were subsequently used to increase the gas rate of one well by 15 MMSCF/D, and an oil well by 4.8 MBOE/D. Wells were ramped up in a controlled manner via programmable logic controllers. Acoustic sand detectors showed very little sand production, primarily during ramp up. The controlled ramp up is believed to be the most important reason that we have not observed any sustained sand production. After a year of operation, we have had only one minor separator cleanup for sand, most of which has been proppant from double and triple frac packs. Introduction BP produces from the NaKika host a collection of oil and gas fields in 6300 ft of water in the Gulf of Mexico. All wells were developed with sub sea completions. The various oil and gas wells produce from the Miocene age sands. There are ten wells, seven that produce from oil bearing sands, and three that produce from gas sands. Individual oil wells produce as much as 35,000 STB/D, and one gas well has produced as much as 168 MMSCF/D. The formations are prone to produce sand. Eight of the wells are completed with frac pack completions. In some cases, there are double frac packs with sliding sleeve completions, and in three wells, there are three commingled frac packs. Two wells are horizontal with open-hole gravel packs. One of those wells failed to have all of the sand placed behind the screen. The nine wells with good frac pack and gravel pack completions were limited by the flux through the gravel pack. Tiffin et el1 discussed how oil and gas wells with sand control can be controlled by monitoring flow through gravel pack screen to minimize the risk of screen erosion. Tiffin et el1 reported that a high frequency of screen erosion failures occurred when the flux exceeded 60, and no failures occurred below 60. The well with a poorly executed gravel pack completion was draw-down limited. Oil and gas fields that produce sand can have erosion at the wellheads, wellhead chokes, wellbore restrictions, and topsides. A common practice is to perform erosion calculations for the maximum expected velocities through various piping. Corrosion can be made worse in sand prone environments because erosion and corrosion can work together to yield greater metal loss. While the tubing and wellhead metallurgy is 13 chrome steel, carbon steel is used immediately after the wellheads.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA pilot test of an integrated sand and erosion alarming process has been implemented in the NaKika field, in the Gulf of Mexico. All wells have sand control completions. Except for one well with a gravel pack completion problem, all the other wells are controlled by a flux limit (SPE Paper 84495).A Microsoft Excel based program was developed to automatically receive daily morning report data, and perform nodal analysis calculations on all of the wells, in order to estimate: mechanical skin corrected for relative permeability changes, pressure drawdown, gravel pack flux, and wellhead velocities. The wellhead velocities were utilized to calculate erosion rate to estimate metal loss. Corrosion rate at the wellhead was also estimated. All calculated results are sent to OSI PI as data tags and viewable through a commercial real time trend-analysis program. The Excel program results are also automatically emailed to the engineers.The gravel pack flux limits are used to make sure we do not produce the wells at rates which increase the probability of sand control failure. Monitoring of the flux results were subsequently used to increase the gas rate of one well by 15 MMSCF/D, and an oil well by 4.8 MBOE/D. Wells were ramped up in a controlled manner via programmable logic controllers. Acoustic sand detectors showed very little sand production, primarily during ramp up. The controlled ramp up is believed to be the most important reason that we have not observed any sustained sand production. After a year of operation, we have had only one minor separator cleanup for sand, most of which has been proppant from double and triple frac packs.

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.

Mangala field (India) is one of the largest polymer flooding fields in the world with hundreds of wells and waxy crude oil. Field-scale optimization of polymer injection is challenging due to the geologic heterogeneity and operational constraints. This paper demonstrates an application of streamline-based injection optimization for the Mangala field. The paper will cover the mathematical foundation, optimization studies, and considerations for field implementation. Our field application consists of five key stages: i) Problem framing. This includes defining optimization objectives, tuning parameters and constraints such as optimization start/end times, schedule update intervals, field rate targets, and injection/production limits for each well. ii) Rate optimization by streamline method. The optimizer iteratively reallocates the well rates, diverting the injected fluid to high efficiency injector-producer pairs located in upswept oil regions. iii) Optimal schedule interpretation. The rate change, flow pattern alteration and injection efficiency improvement are systematically examined, providing decision makers physical explanations of the suggested rate changes. iv) Selection of key injectors for field implementation. To avoid the risk of large-scale field implementation, limited number of injectors contributing the most to the oil production increase or water production decrease are selected for initial deployment. v) Potential field implementation and validation of the proposed plan based on field observations. Data from offset producers surrounding the rate-reallocated injectors can help evaluate oil production improvement or alleviated decline. The optimized rate schedule is first compared with the current schedule in the field, honoring the field total liquid injection/production rates. The optimized case redistributes the rate allocation among high efficiency injectors within predefined bottom hole pressure and rate constraints. The cumulative oil production increase for the short-term optimization period, 11 months, is 0.66 MMbbl. The efficiency plots show efficient utilization of injected fluid after optimization and the bubble plots and streamline maps indicate that the optimizer alters the flow pattern for a better sweep of the remaining oil. Based on the full field optimization, 20 key injectors are selected for field implementation. Numerical simulation shows that 75% of total oil gain can be achieved from optimization of the key injectors. For field validation, offset producers are expected to show an arrest in the oil decline rate due to improved pressure support and, also reduced water cut increase after field implementation.