Upfront Reservoir Monitoring Investment Promises Long-Term Rewards

The industry’s continued migration into deeper, hotter, and more unconventional oil and gas reservoirs carries the potential for significant financial rewards and major economic risks.

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The industry’s continued migration into deeper, hotter, and more unconventional oil and gas reservoirs carries the potential for significant financial rewards and major economic risks. Because the development of unconventional reservoirs often requires some form of stimulation—thermal stimulation for heavy oil formations and hydraulic fracturing for shale plays—well construction costs are reaching new highs. Rather than developing these wells in a trial-and-error or even blind fashion, more operators realize that the only way to maximize the value of these assets is through real-time monitoring at the reservoir level.

Permanent reservoir monitoring calls for the deployment of one or more downhole sensors to monitor and record a number of reservoir properties, such as temperature, pressure, and flow rates at various locations in and around the wellbore. By monitoring these properties in real time and over time, operators can gauge the progress of reservoir development at each stage of the well’s life cycle.

Full-Asset Life Cycle Benefits

During fracture stimulation of shale wells, for example, a permanent monitoring solution can reliably report information on the fracture network being created, including data on both the quantity and quality of fractures being created in different zones. In steam-assisted gravity drainage (SAGD) wells, downhole temperature sensors can track the propagation of steam moving into the formation, and then the progress of heated oil moving into the producing well.

Once the well is brought onto production, these same monitoring tools can accurately measure the pressures, temperatures, and flow rates of fluids at different points in the wellbore and from different producing zones. Such insight informs when the operator may need to implement some form of remediation or artificial lift in the well to boost dwindling production rates. Once artificial lift has begun, the real-time reservoir data can help optimize the pumping rates of various lift technologies to maintain production at desired rates.

The benefits of permanent reservoir monitoring extend past a single well to encompass production optimization at a field level. For example, by installing permanent sensors in producing, injection, and monitor wells as part of an enhanced oil recovery (EOR) campaign, the operator can feed these data into simulation models to track production across the reservoir. Such information can then be used to aid development decisions—an expansion of EOR or the drilling of additional wells—to boost the long-term production of an entire field.

Weighing Monitoring Options

The past 2 decades have brought an impressive pace of development for different permanent downhole monitoring options. For operators, the choice of a system is a function of several interrelated factors.

The first relates to the relative complexity and harshness of the reservoir to be monitored. The downhole environment in many wells, including its temperature, pressure, and the presence of corrosive liquids or gases, can put stress on ­sensors and must be factored into the decision process. For wells with relatively stable ambient environments and temperatures below 302°F (150°C), an ­electronic-based monitoring system may fit the bill.

A common electronic system incorporates a piezoresistive transducer that measures pressure changes in the reservoir by converting pressure into a change in resistance. This sensor technology also measures wellbore temperature, simultaneously compensating for any temperature-induced errors that may limit the accuracy of the pressure transducer output. Such systems have been used for many years to provide a reliable monitoring solution for artificial lift systems in conventional oil wells.

Sophisticated Approach

For higher-value wells with harsher and more complex operating environments, such as higher temperatures and pressures, and commingled production from multiple zones, the operator may choose to implement more sophisticated permanent monitoring solutions. Both quartz gauges and optical sensors are used in these cases, and the choice of technology depends on the application and amount of sensing desired.

For example, quartz gauges have been used extensively in offshore subsea applications, in which their measurement resolution is unmatched by other electronic sensors. Optical sensors have only recently been deployed in a few wells. For high-pressure/high-temperature (HP/HT) applications, quartz gauges have generally provided reliable data up to 150°C (302°F). Quartz gauges use a quartz transducer, which incorporates a high-temperature hybrid design to measure changes to reservoir pressure and temperature.

Newer hybrid circuit designs are contained in a hermetic package, making them qualified for operation in high-shock/high-temperature wells up to 392°F (200°C) and for accelerated testing as high as 437°F (225°C). While applications above 150°C still present challenges, even for the latest designs, quartz gauge technology continues to improve for HP/HT applications and to be the sensor of choice for subsea permanent downhole monitoring.

Optical sensing systems offer a unique capability to reliably deploy a wide range of point sensors and distributed sensors within a single cable downhole. These systems use optical technologies to measure downhole temperatures, pressures, and both single-phase and multiphase flows in HP/HT environments, including providing reliable monitoring in thermal recovery wells.

For example, these robust sensors can be used during the circulation phase of an SAGD operation at ultrahigh temperatures that can reach 572°F (300°C) continuously to monitor temperature changes in the reservoir. This information can be used to track the growth of the thermal profile of the well, which tells the operator how efficiently and uniformly the steam is being distributed along the lateral. This subsequently indicates when to switch to production mode and how uniform production will be from the producing well.

Increased reservoir complexity is also introduced as operators shift from developing individual wells to operating many wells from a single pad. In addition, the average number of zones in a fracture-stimulated well has increased from roughly five to as many as 20 in the past decade. This combination of more wells to a pad and more producing zones along a horizontal wellbore creates a dynamic monitoring environment for reservoir optimization.

Again, the best monitoring choice may be an optics-based system consisting of several gauges distributed along the length of a lateral and across several wells, all tied to a central data collection system that resides on the pad. Distributed sensing is easily combined with optical gauges in a single cable to provide a tremendous amount and range of real-time downhole sensing. Such a system serves as a watchdog for the reservoir, tracking the contribution of each zone or well to the production of the entire system.

In addition, this monitoring option provides a vital well integrity function by detecting sudden changes to pressure or temperature that might indicate changes in flow characteristics, pressure buildups, or water breakthrough at discrete locations in the reservoir.

Cost and Confidence

As with any investment in the field, operators also weigh the costs of a permanent reservoir monitoring solution against its purported benefits. The upfront investment includes the cost of the system hardware and software, the installation costs, and training required to get personnel comfortable with the monitoring system and to be able to interpret the data.

Although permanently installed wellsite data acquisition systems are generally reliable, they can incur additional costs over time if not maintained properly and protected from other wellsite operations. The management and use of continuous real-time well data is possible with a robust data collection system, data historian, and data visualization and analysis software tools.

This investment must be compared with the overall investment cost of the well, its production potential, and the risks associated with suboptimal performance or noncompliance with regulatory guidelines relating to safety and the environment. For “high-value wells,” the risks may justify the operator allocating a certain portion of its budget for permanent reservoir monitoring. ­Values differ among operators and wells. The desire to have downhole measurements in unconventional wells is often echoed by operators because of the complex dynamic behavior of these wells over their life cycle.

An operator’s confidence, or lack thereof, in monitoring systems also weighs heavily on the investment decision. Lagging reliability concerns in distributed temperature systems (DTS), for example, have historically resulted in a drag in the uptake of all fiber-optic monitoring solutions. Installation problems from improper training and poor project management have also resulted in many unsuccessful fiber-optic permanent monitoring programs.

In reality, many fiber-optics monitoring systems, particularly those based on Bragg grating technology, have performed reliably for many years in wells both onshore and offshore. An operator in the North Sea installed such a system to monitor phase flow rates, pressure, and temperature for 27 wells over a 5-year period. The solution, which comprised in-well two-phase flowmeters, optical pressure/temperature (P/T) gauges and DTS, allowed the operator to log data for real-time production monitoring, optimization, and allocation.

The P/T gauges allowed for important drawdown management and sand control while two-phase downhole flowmeters provided valuable real time, accurate hourly well production allocation. DTS sensors provided qualitative information including leak detection and confirmation. The system provided the useful data for temperature profiling for calibration and flow correlation in well performance modeling, as well as gas lift monitoring and management to check injection points.

The multiparameter, real-time permanent monitoring system allowed the operator to reduce the frequency of testing with the test separator from once per month to once every 3 months, resulting in a quantitative impact on deferment by roughly 5%. Based on comprehensive program management and these performance metrics, the operator expanded the permanent reservoir monitoring system to include a total of 37 wells across the field.

In hundreds of SAGD wells, thermal monitoring based on the use of thousands of high-density fiber Bragg grating (FBG) has proven to be reliable as a permanent monitoring solution for managing complex steam injection and oil production processes.

Successes such as these are helping to break down the barriers to more widespread industry acceptance, particularly as we move from the initial “early adopter” stage of the technology to a more mature stage of 15-plus years of increasingly successful deployments around the world. And as further technology add-ons, such as intelligent visualization and interpretation tools, keep coming to the market, these barriers will likely keep crumbling and permanent monitoring will become ubiquitous in the majority of high-value wells.

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Tad Bostick, SPE, is vice president production optimization at Weatherford International. He has more than 32 years of experience in the industry with Western Geophysical, Western Atlas, CiDRA, and Weatherford, where he most recently headed the Production and Reservoir Monitoring business unit. He is currently charged with business unit leadership and integrating technologies used to optimize production to help operators get the most out of their wells and fields. His areas of expertise include borehole seismic data acquisition systems, and development and commercialization of electronic and fiber-optic sensing systems. He holds BS and MS degrees in electrical engineering from Stanford University.