The Zohr subsea production system, around 180 km off the coast of Egypt in 1,500-m water depth, was configured with a novel metering system providing the necessary functionalities for optimized hydrate inhibition. Different subsea measurements from startup and normal production phases were obtained and combined to extract valuable information regarding water production and to monitor hydrate inhibitor dosage in real time. Conventional hydrate inhibition system overdesign and overdosage would have had a significant impact on the technical and financial viability of the Zohr development, considering that no monoethylene glycol (MEG) regeneration capability was available at startup due to the fast-track nature of the project. Therefore, it was critical to limit the use of MEG, selected as hydrate inhibitor, in order to manage the available storage capacity. A data interpretation model was developed for the subsea water analysis sensor based on flow loop testing and analytical methods, allowing for real-time measurement of the MEG dosage for each well. Flow assurance modeling was performed to validate subsea measurements, and to explore model limitations and enhancements. Field data comparisons provided unprecedented insight into unexpected reservoir behavior several weeks faster than measuring fluids arriving onshore, considering the 220-km tieback distance. Indeed, the produced fluids at startup contained water at an order of magnitude more than initially expected, which would normally have resulted in underinhibition and a possible hydrate blockage risk. The subsea measurement system allows for MEG dosage to be monitored and injection flow rates to be adjusted in real time, from the first day of production, to respond to the fluids produced subsea. With only two wells initially producing in a 26-in, 220-km-long flowline, up to 5 weeks were required until produced water was received onshore for sampling. Data analytics were applied to validate the measurements obtained, identify trends, and anticipate onshore fluid arrival conditions weeks in advance. The field data also allowed to identify areas requiring improvement and to specify additional functionality development needs. The use of innovative subsea metering and measurement systems has enabled a safe startup of the field while meeting the first-gas target date. This is the first time in the industry that a direct hydrate inhibitor concentration monitoring and control, aimed at real-time hydrate management, has been achieved subsea for gas fields. The success of this innovative application of a subsea water analysis sensor was made possible through an unusual level of collaboration and openness between the field operators and subsea hardware providers. The cooperation that occurred on the Zohr Field development, from early engineering activities to operational support, has allowed for the combined team to advance the data interpretation models, improve the concept and obtain great value from the subsea measurements. This pioneering application of subsea technology is a game changer that will enable unlocking additional long-distance deepwater gas reserves.

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In the Alaskan North Slope field of Nikaitchuq, the standard shut-down strategy of oil producers was to inject warm diesel inside the tubing of the wells for freeze prevention of the tubing. The procedure requires that a Gas Lift Valve (Shear Orifice Valve) located at 2,000 ft be ruptured to displace the tubing fluid inside the annulus. It was desired to evaluate whether this procedure could be avoided to reduce both operational risk and costs associated with this strategy. An evaluation was performed using a transient fluid-dynamic simulator based on oil producers. Based on geothermal gradient acquired by DTS fiber optic technology and considering the salinity of formation water, the depth of the tubing under freezing risk was defined. Simulations were performed for both the rate of cooling of the produced fluids in the tubing and the time required to reach ice formation conditions. In the paper, we will show that the sweeping effect of gas during production does not allow for water accumulation at the x-mas tree and surface piping. In addition, the vertical geometry in the tubing results that any water present falls below the permafrost line during shut-in conditions. As no bulk water is present in the well inside of the ice stability region, the risk of a blockage from ice is not present during a planned shutdown and the previous preservation strategy is not required. The change in the standard operating procedure for planned shutdowns was successfully applied, leading to a marked reduction of costs and reduced down-time with a consequential recovery of otherwise lost production.

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In the last years, the shale gas business has gained increasing emphasis within the major oil & gas companies. In particular, Quicksilver Resources and eni e&p, through its subsidiary eni US Operating Co., and are jointly involved in the development of the Alliance shale gas field in the prolific Barnett shale play located in Texas. Recently, both companies started a common effort to optimize production and lift costs. Such efforts included a deeper analysis of the artificial lift performance and exploitation of additional deliquification technologies. In fact, typical shale gas wells are adversely affected by the continuous flow-back of the huge volumes of water used for the frac jobs. In the Alliance field, the most common way to support deliquification was by injecting lift-gas through the casing. Foaming agents were only occasionally deployed and a comprehensive activity to assess their technical and economic performance has been conducted. In the last six months, extensive foamer injection tests have been performed on several wells, considering the effect of a factors such as production/injection mode (tubing or casing), foamer type and rate, lift-gas rate, gas and water rates and wellhead pressures. The uncommon synergy of continuous foamer and lift-gas injection has also been extensively exploited in horizontal wells. At the end of the test phase, more than one third of the producing wells had been treated with a foamer and relevant technoeconomic improvements had been achieved. The paper describes in detail the methodology, the field experience and the results obtained.