Monday, July 15, 2019

Permanent Monitoring- Looking at Lifetime Reservoir Dynamics

Permanent monitoring systems measure and record well performance and reservoir behavior from sensors placed downhole during completion. These measurements give engineers information essential to dynamically manage hydrocarbon assets, allowing them to optimize production techniques, diagnose problems, refine field development and adjust reservoir models. 

Reservoir development and management traditionally rely on early data gathered during short periods of logging and testing before wells are placed on production. Additional data may be acquired several months later, either as a planned exercise or when unforeseen problems arise. Such data acquisition requires well intervention and nearly always means loss of production, increased risk, inconvenience and logistical problems, and may also involve the additional expense and time of bringing a rig onto location. 

Permanent monitoring systems allow a different approach. Sensors are placed downhole with the completion string close to the heart of the reservoir. Modern communications provide direct access to sensor measurements from anywhere in the world. Reservoir and well behavior may now be monitored easily in real time, 24 hours a day, day after day, throughout the lifetime of the reservoir. Engineers can watch performance daily, examine responses to changes in production or secondary recovery processes and also have a record of events to help diagnose problems and monitor remedial actions, rather like monitors in a power plant's control room.

Most systems in operation record bottom hole pressure and temperature, but other measurements, such as downhole flow rate, are being introduced and may become common in the future. However, pressure and temperature provide dozens of beneficial applications. This article reviews the development of permanent monitoring, looks at applications with several examples and describes the hardware.

 Early Days

Permanent monitoring has its roots in the early 1960s on land wells in the USA. Pressure gauges were needed to monitor the performance of secondary recovery projects, such as waterfloods or artificial lift schmes, where they were required downhole for several weeks. In many cases, the only option available was to run a standard pressure gauge on the end of the completion string. The cable for power and data transmission was passed through an insulated connector in the Christmas tree, strapped to the outside of the tubing and then ported back inside the tubing just above the gauge leaving the bore free of any obstructions. Even though the hardware was simple by today's standards, these early examples proved invaluable to oil companies and showed the diverse use of and benefits from the pressure data gathered. 




 One example from 1962 is typical of the period. Henderson 6 was the second well completed by the Coronado Company in the Bell Sand of the Old Woman Anticline, Wyoming, USA. A permanent pressure gauge was placed below a conventional pump in a 2400-ft well for interference testing and to determine the productivity index. Initial bottomhole pressure (BHP) was 680 psi. 

The well produced 340 barrels of oil per day (BOPD) with a 60-psi drawdown, but quickly suffered from increasing water cut. Bottomhole pressure returned to 680 psi indicating complete water breakthrough - possibly by water coning. By modifying production and monitoring downhole pressure changes it quickly became apparent that the coning problem would not repair itself and that the well would have to undergo workover. Afterward the well was put back on production and, this time, the pressure gauge measurements were used to control drawdown to just 40 psi to prevent recurrence of water coning.

Other examples from the 1960s show how pressure gauges were used to monitor progress of secondary recovery fronts across fields, to check the operation of subsurface pumps, to provide reservoir data and to calculate individual well drainage during the life of the reservoir. 

The first permanent pressure gauge run by $$$ was for Elf in Gabon (Africa) in 1972 followed one year later by the first North Sea installation on Shell's Auk platform. These early systems were essentially adaptations of electric wireline technology. A standard strain pressure gauge was clamped to the tubing and ported to monitor tubing pressure. A stranded single-conductor logging cable was strapped to the outside of the tubing exiting at the wellhead. Data were recorded on a standard acquisition unit. 

Many early failures were caused by damage during installation or by cable problems at a later date - either by loss of electrical continuity or breakdown of insulation causing a short circuit. Statoil report that many cable failures occured at splices and now request splice-free cables. Detailed analysis , such as that performed by Petrobras on systems run in Brazil and the North Sea, shows how reliability has improved. More recently a detailed research and development project has resulted in development of a new generation permanent gauge and its associated components for even greater reliability. 

Present systems are engineered specifically for the permanent monitoring market and have a life expectancy of several years. Gauges have digital electronics designed for extended exposure to high temperature and undergo extensive design qualification life tests and strict quality checks during manufacture before being hermetically sealed. They are not designed for maintenance.

Cables for permanent installations are encased in stainless steel or nickel alloy pressure-tight tubing that is polymer-encapsulated for added protection. All connections are verified by pressure testing during installation.

Connections through tubing hanger and wellhead vary depending on the type of completion- subsea, platform or land but components are standard, tried and tested designs made in conjuction with the tubing hanger and wellhead manufacturers.

Data transmission and recording are tailored to oil company needs, and wherever possible industry standards are used so that signals may be integrated with other systems. For example, many subsea completions have memory modules called data loggers that record, for instance, wellhead pressure or the status of control values. Permanent gauge data may be fed to interface cards located in the data-logger so that data transfer may be executed in one step. 
















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