GE Seeks To Change Downhole Sensor Technology Game
Seeing further potential for oil and gas downhole sensors, GE Oil & Gas is not just seeking incremental improvements through its research and development, but new game-changing sensors altogether.
The company has been involved in the downhole sensor space since the 1950s, and offers three commercial sensors to the oil and gas industry: neutron, gamma, and directional sensors. But GE Oil & Gas believes the challenges associated with these sensors limit their full potential.
One type of sensor technology, gamma sensors, have been utilized in the oil and gas industry since the late 1970s and early 1980s. A common material used in gamma sensors, a salt crystal called sodium iodide, has served industry well. However, it has limitations. One is that it doesn’t perform well at higher temperatures, with its light output dropping by as much as 40%. With most oil and gas wells now being drilled to deeper depths, higher temperatures are being encountered. Therefore, that material is not very suitable for this application.
Another limitation is that it’s not very dense. The more dense the material, the more counts per second can be produced. More counts provide operators with better confidence in their measurement. Even if an operator is happy with their confidence level, a more sensitive sensor can create advantages in tool design, such as a more compact sensor. Sodium iodide’s long decay time also limits its use in more sophisticated measuring techniques, such as differentiating between elastic and inelastic interactions in pulsed neutron applications.
To address the shortcomings of sodium iodide, GE has developed a material called lanthanum halide to handle rugged oil and gas drilling environments and offer greater light and output. This material was developed in collaboration between GE Oil & Gas, GE Healthcare and the old GE Security business, as well as GE’s Global Research Center. Similar materials have been available for some time, but GE has been able to optimize the chemical composition to further enhance light output and resolution.
In addition, due to very high costs, oil and gas companies have been skittish about using lanthanum halide sensors, which can cost as much as $50,000, in environments where they could lose the sensor and halt operations. Besides cost, downtime is another major issue facing oil and gas companies. In fact, offshore operators can face losses of hundreds of thousands of dollars a day from downtime. GE is leveraging its ruggedization capability that has been proven over the last two decades to bring lanthanum halide scintillators to the harshest oil and gas environments, thereby offering customers the enhanced performance and high reliability that they need.
To meet its customer’s high temperature and reliability challenges, GE is seeking to replace the photo multiplier tubes in gamma sensors. Photomultiplier tubes rely on the traditional technology of bi-alkali photocathodes and amplifying dynodes to detect the light pulses and convert them to electrical pulses. The technology requires high voltage operation, and steadily drops in performance with increasing time and temperature, which severely limits operating envelope and expected life. GE is developing a silicon carbide-based photo detector that will be capable of operating continuously at 230 degrees Celsius with a 3x-4x increase in reliability due to lower voltage operation. This technology leverages extensive work that has been done by GE Power and the Global Research Center in the application of SiC to power generation and flame detection applications.
GE is also seeking to enhance the capability of directional sensor technology, which has not been enhanced in decades. By design, these sensors are sensitive to magnetic interference, limiting where they can be placed on the drillstring or wireline logging tool. Because they are sensitive to magnetic interference, the sensors also cannot be used in proximity of magnetic material such as existing casing from adjacent wells. Finally, due to their inherent design, the sensors provide a high quality response only every 90 feet as a new drillpipe stand is added and the mud pumps are turned off.
To compensate for shortcomings, these sensors must be complemented with dedicated gyro-while-drilling, requiring additional time and cost. GE’s new technology leverages gyro designs that were initially designed for GE Aviation. This technology is integrated with the existing directional sensor design, thereby saving the service company as much as 1-2 days and $20,000 per well. It also holds the promise of enhancing reliability by a factor of 2x, and enabling continuous surveying (instead of only every 90 feet), which in turn allows for closer well spacing, thereby enhancing ultimate recovery by as much as 40%.
Step changes in downhole sensor technology are needed as the oil and gas industry tackles the new challenges in offshore and onshore fields. GE’s interest in enhancing sensor technology also has grown along with shale development activity. Drilling wells faster is part of this strategy. In 2009, it took 15 to 20 days. Now, companies are pushing for as few as five days. With faster drilling and higher rates of penetration, the tools experience greater vibration. Every new downhole sensor technology development at GE is focused on enhancing performance and reliability under high temperature and vibration.
In short, GE is not just seeking to incrementally change technology, but take downhole sensor technology to a whole new level. This new level of technology – developed through the collaborative efforts of GE’s divisions – will be needed as the exploration and production game continues to grow in complexity.
Swellable Packer Technology Tackles Slow-Swell Conditions
Swellable packer technology is one of the few technologies that has been readily accepted by the industry in a very short period of time, about 15 years. Since its development, hundreds of thousands of swellable packers have been included in well designs. Initially, oil swellable packers were used to provide compartmentalization in horizontal wells that were drilled in thin oil reservoirs. In the spaces between the packers were slotted liners, sand screens, and/or inflow control devices (ICDs). Water swellable packers were also developed for non-cemented injector completions.
It did not take long, though, for the technology to be adopted in many other well designs, primarily the horizontal multi-stage fracture design. The use of swellable packers to test and/or ensure well integrity is also a typical application, where packers are used to complement cement jobs and increase the likelihood of cement providing long-term well integrity.
Many features of swellable technology make packers attractive for use in well designs. For one thing, they are very simple to implement. The packer is designed to work with the planned wellbore fluids. So, manipulating the tubulars or applying hydraulic pressure is not required to activate the packers. Instead the packers react to the wellbore fluids over time and eventually swell to fill the annular gap. The challenge in well design using packers is to get a proper balance between the swell rate in regards to installing the packer and the swell rate in regards to operating the well.
Obviously, the swell rate to install the packer cannot be too fast: any interference arising from the packer’s reaction with wellbore fluids would impede the installation. Yet, the time to seal cannot be so long as to delay production. In an overwhelming majority of the applications, these challenges can be managed, resulting in a successful use of the technology. However, in some instances well constraints create a slow swell environment, where the rate is too slow.
A slow swell environment is often associated with low temperature wellbores. At low temperatures, heavy or viscous oils typically pose a challenge for oil swellable packers. Often this challenge can be overcome by adjusting the elastomer chemistry. As with the oil swellable packer, the water swellable elastomer can face difficulties at low temperatures. But a larger contribution to a very slow water swell environment is the amount and type of dissolved minerals found in the completion fluids and formation waters; these dissolved minerals are usually Na, K, Ca, and Cl. The higher the mineral concentration or the salinity of the water, the slower the rate of swell.
Often at high temperatures, greater than 250 degrees Fahrenheit (121.1 degrees Celsius), the rate of swell is acceptable, but depending on the concentration of each dissolved element, the rate can still be unacceptably low. While the elastomer chemistry can be changed to adjust the oil swellable packer to slow swell environments, the water swell technology does not have that option.
To address this limitation imposed by slow swell conditions, TAM International developed TAM FastSwell? technology. This is a manufacturing approach to increase the rate of swell. This proven, patent-pending technology can be used with any of our swellable elastomer chemistries. It is simple in that the chemistry of the elastomer is the same. What the technology has added is a method to increase the surface area exposed to the wellbore fluids.
It does this without increasing the length of the packer or reducing its differential pressure rating. Through extensive research and testing, a method was developed to expose differing amounts of surface area to the fluids, which then manages the rate of swell. The novelty of this technology is that it offers several ways to do this, depending on the desired results and on the geometry of the packer. The figure shows a typical design that is used in multistage fracture wells where the swelling fluid can have a salinity of 25% or greater.
A common example would be the use of a 10 ppg brine for a completion fluid. With NaCl as the salt, this brine has about 26% salinity. The standard water swellable packer responding to this brine would create a 5000 psi seal in approximately 25 days. With the application of the TAM FastSwell? technology, this time can be reduced to 16 days, saving over a week’s time.
In the case of an oil swellable packer in contact with an oil having an API gravity of 22° at 120°F (48.9°C), the time to swell and seal is 39 days. Implementing the TAM FastSwell? technology reduces that to 18 days. As can be seen, the technology makes a significant difference. This allows swellable technology to be used in areas where it was once technically disqualified.
Since the technology is a manufacturing process, existing packer inventory can be used, which can bring a savings opportunity for companies with inventory they can no longer use due to changing well designs and conditions.
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