In March of this year what may well prove to be a revolutionary moment in reservoir monitoring history took place in the North Sea. The watershed event came after a 3-year service company/operator collaboration culminated in the installation of the world’s first offshore permanent in-well optical seismic system. On this injector well the system was used to augment the operator’s permanent ocean-bottom seismic arrangement.

The Clarion permanent in-well seismic system from Weatherford consists of highly sensitive

Figure 1. Weatherford technicians install the world’s first offshore permanent in-well optical seismic system in the North Sea. (Images courtesy of Weatherford International)
multicomponent miniature optical accelerometers and uses advanced optical multiplexing, based on Bragg grating technology. The in-well system also includes an optical pressure/temperature gauge deployed on the same cable. This installation is one of a growing number designed to provide 4-D seismic information by comparing images derived at different times. Changes in the images can indicate fluid movement in the reservoir, allowing operators to determine how efficiently they are draining the formation.

Sensors enhance the accuracy and understanding of the resultant images by providing a constant reference point throughout the years-long process of 4-D seismic. Ocean-bottom sensors deliver an image in time only. To translate that image to one that is representative of the real subsurface, the operator must convert time to depth — something done routinely for individual surveys. But after moving to 4-D — over 5, 6, 10 or 20 years — there are variables that can make it very difficult to compare one survey to the next. The sensors used on this operation give a calibration constant that enables them to get much better comparative images than ocean-bottom cables.

Enhancing the data

The tubing-deployed sensors, or seismic stations, are run much closer to the reservoir than the permanent ocean-bottom cable sensors, as they are part of the completion string. A specially designed active clamping system optimally couples each three-component sensor to
Figure 2. Electronic sensors follow the classic ‘bath tub’ failure characteristic — infant mortalities do occur, followed by a period of level reliability and then a wear-out phase. The wear-out phase produces a sudden and sharp increase in failure rates. The higher the operating temperature, the sooner this wear-out phase occurs.
the casing and substantially decouples it from the production tubing. An optical pressure/temperature gauge is deployed along with the seismic sensors on a single fiber-optic cable. Apart from enhancing data from the surface and the ocean-bottom cable system, the sensors also produce a very detailed around-the-borehole image. And their very sensitive nature lets them detect and map microseismic events — the opening and closing of fractures in rock — as they occur, when fluids are produced from or injected into a formation. By following these events, operators are able to determine where fluid is moving so that they can test their predictions of fluid flow through the reservoir and take required remedial steps early. That ability is especially applicable for today’s North Sea operator, whose goal in the maturing province is production optimization through reservoir life extension and increased recoverable reserves.

Operators know that monitoring the reservoir from day one enables them to know much better what is going on in their reservoir. The old idea of sticking a hole in the reservoir and producing as long and hard as possible is becoming a thing of the past. Today reservoir monitoring helps to squeeze every bit out of the field through the use of sophisticated technologies and to best determine the optimal reservoirs.

Gearing up for a long life

This project is expected to continue for up to 20 years. Given this extended time scale, the reliability of the optical sensors is of paramount importance for the operator. By definition, to serve as a constant throughout the life of the field, the sensors must never be moved. The reliability of the fiber-optics is the key. Once the sensors are in the well, they stay in the well. Electronic systems can have problems with that. They are very much restricted to a 3- to 5-year life span, or less, and once anything is pulled from a well it is extremely unlikely it can be placed back in the well in precisely the same spot.

Years of development have also resulted in the use of proprietary materials, chemicals and
Figure 3. An optical acquisition system interrogates the seismic sensors (pictured) and converts measured optical wavelength to recordable analog or digital data.
processing solutions to combat a failure mechanism that has long plagued fiber optics used in oil and gas wells. At very high temperatures and for unprotected fiber, the “hydrogen darkening” phenomenon can occur through absorption by the impure glass fiber of the highly permeating hydrogen gas. In time the glass grows so dark that the light-dependent optical sensor is undetectable.

For this job, several layers of protection were installed to make sure hydrogen does not actually get to the glass. Even if the glass does darken over time, the sensitivity of the system is such that there is unlikely to be any problem.

The other enemy of sensor life is vibration, a constant and extreme element in downhole production and injection environments. Traditional electronic sensors are highly susceptible to vibration-induced failure as they contain numerous moving parts that literally shake themselves apart in high-rate flow. Fiber-optic sensors, on the other hand, contain no moving parts. And while it may be counterintuitive to think of glass being stronger than steel, the tensile strength of glass is, in fact, superior.

The right techniques for engineering and manufacturing glass microstructures and packaging them for durable installation render a very robust system.

An evolving purpose

Especially in light of the prolonged term of this 4-D seismic application, this project is still in its infancy. The system has given the operator more than expected in terms of data from downhole. Indeed, the original purpose for the optical sensors as an enhancement to the ocean-bottom seismic system may prove to be but one part of the value eventually realized by the operator. Initially, the operator was just looking to improve the ocean-bottom
seismic, which provided the economic justification for the project.

But with the optics now installed in the well, engineers believe there is a lot more they can do with the system. For now the company has the system continually “switched on” and is gathering accelerometer data to establish what might be thought of as an acoustic baseline for standard production operations by gathering data kilometers from the injector well in which it resides.

Comments