Real-Time Fiber Optic Monitoring Applications in Various Downhole Situations

The distributed fiber-optic sensors have proven their ability to provide significantly valuable information from drilling through the completion, production, and intervention stages of a well and to monitor pipelines transporting hydrocarbons over great distances in the oil and gas industry.

Following are a few field cases where this technology has helped companies make decisions and produced outstanding results.

Cementing Casing Evaluation (Well Integrity Monitoring)

A fiber-optic cable was permanently installed along the 18 5/8-in. casing and the 21-in.-hole section of a geothermal well. During the cementing operations, the temperature was continuously recorded using distributed temperature sensing (DTS) technology to monitor the cement placement. During the drilling and injection testing phases carried out in the 12 1/4-in. open hole section, as shown in Figure 1, DAS data was compiled continuously for 9 days. The signals along the optical fiber are the result of the elastic deformation induced by mechanical energy applied from either inside the casing by the drilling activities or from seismic activity outside of the well. The results indicate that the collected data trends are similar to those of a conventional cement-bond log (CBL). This can be an indication that DAS data acquired during different drilling and testing operations can be used to monitor the mechanical bonding between cemented casing strings and the surrounding formations, or, in other words, the cement integrity. In this way, the potential use of DTS and DAS technology in downhole evaluations could be extended to the real-time monitoring and assessment of cement integrity changes.?

Observations

The DTS data acquired during a cementing operation enabled evaluation of the pumping and setting stages, showing an interval with a different thermal signature, as depicted in Figure 2. Temperature data indicate nonoptimal cement bonding. The same interval correlates with a higher CBL amplitude, which also points to nonoptimal cement bonding. This finding might present a chance to employ optical fibers to study the application of low-density foam cements, which present difficulties for standard cement-evaluation techniques. A clear limitation of the DAS technology is the absence of radial investigation, which might be solved by installing more than one fiber-optic cable or using the currently emerging cables that allow for the acquisition of three-component data. Also, for permanent monitoring applications in harsh environments, special carbon coatings and advanced glass compositions should be deployed. In this manner, distributed fiber-optic sensor devices can be utilized to continuously track the mechanical characteristics of the cemented annulus during a well's lifetime. Real-time monitoring will thereby allow for analyzing load cycles during production or injection, particularly if the sensing system is attached to the production casing (liner), which will be more affected by those operational changes. This will reduce the need for expensive intervention operations and, in the end, ensure the longevity of downhole installations.

Cross Flow Behind the Casing Identification

Instead of using the traditional memory gauge tools, which require days to retrieve the data from downhole memory gauges, and a jet pump as an artificial lift system, which implies that the process data and evaluation take a long time, an operator in South America realized that this static process of collecting the data was unable to reveal unexpected facts like increased reservoir pressure due to a cross flow situation.?To avoid this, the decision was made to use the fiber optic inside a CT string. A crossflow between the existing zones A and B was identified due to the distributed temperature sensing (DTS) profiling, as shown in Figure 3, which prompted the company to take corrective action to address this unforeseen issue. Evaluation of perforations open in a completed interval is another application for the real-time distributed sensing, in the same way.??

Additionally, the CT real-time pressure was deployed to perform a pressure build up test. The flow period evaluation was achieved using nitrogen as the lifting method. See Figure 4.?Following this protocol, an intervention with conventional WO rig was eliminated, which saved time and resources.?

Plugged ICDs in Horizontal wells.

The drilling and completion of horizontal wells allows to increase the reservoir contact and thus achieve a productivity increase. This increase in horizontal length also allows the contact with heterogeneous formation, and varying reservoir properties, such as permeability and pressure, among others. Most permeable layers, under the same pressure drop, will be the ones to produce their fluids faster, leaving the less permeable layers unproductive. Same situation happens with horizons with different pressures, where the higher-pressure zones will be produced preferentially. High permeable zones will promote earlier water or gas breakthrough as well. To mitigate those challenges, different types of inflow control devices (ICDs) have been developed. The ICDs generate an extra pressure drop which lead to balancing the pressure drops in the wellbore segments, equalizing the inflow from the producing segments along the entire wellbore. The main interrelated outcomes, due to the use of those ICDs are:

1.????Regulating the inflow along the length of the wellbore trajectory

2.????Reduce water production (or gas in oil well)

The remarkable increase of reservoir oil recovery is a consequence of the above actions.

Due to the different flow paths of the ICDs being either small opening (orifices) or tortuous pathway mechanisms, the pressure drop lead to potential solids or fines precipitation, plugging those devices, reducing the inflow into the wellbore. Also, the high velocity created lead to erosion by the sand particles aggravating the plugging problem.

One operator in the Middle East, having installed around 20 ICDs in two wells, and based on the decreased productivity, decided to intervene the wells to identify the plugged ICDs and proceed with a selective cleaning out process to restore the productivity of those zones.?

Every ICD contributes with flow from a specific zone, which is segregated behind the casing by packers, as shown in Figure 5(a). As seen in the DTS response from layer n-2, if the ICD is plugged (b), there won't be a contribution from that zone. Once the plugged ICDs are identified with a fiber optic coil tubing DTS profile, straddle packers are required to isolate the target ICDs to perform a clean-out treatment. Monitoring of the remediation operation with live data acquisition can confirm the success of the treatment. According to the operator, this intervention allowed for an increase of more than fifty percent in the pretreatment production. In this case, the benefit came from both the increased productivity and the removal of the required traditional WO rig, which would have taken days to complete the intervention. If a permanent DTS system were installed along the ICD's completion, it would be able to identify any plugged zones and take corrective action without incurring a large loss in productivity.

Matrix Acidizing with Fluids Diversion in carbonate Formations

An operator in Mexico used the distributed temperature sensing (DTS) run with coil tubing to record temperature profiles along the carbonate reservoir being stimulated to reduce near-wellbore damage. To support the DTS system, a modular BHA containing pressure, temperature, and depth correlation sensors was deployed.

In cases where high permeable carbonate formations are stimulated, due to the natural fracture occurrence, the treatment fluid will move along those high permeability paths. As a result, the operation's effectiveness is low because the lower permeability sections will not be impacted by the stimulation. The use of mechanical diverters is one of the solutions leading to increased fluid contact with the rock matrix, which is less permeable than natural fractures. This is the first time they evaluated the effectiveness of the diversion treatment in real time, monitoring the sections being treated and being able to take decisions during the operation.

Zones with different degrees of fluid admission were identified with the real-time fiber-optic (RTFO) system. Based on this data, the original scheduled pumping rates and volumes of diverting fluids were adjusted accordingly, as were the stimulation fluids being pumped during the different stages of the treatment operation. A continuous correlation between depth and the treatment temperature fluctuations was registered, which was the driver for modifying the stimulation parameters. The successful evaluation of the fluids and diverter performance was attributed to the deployment of the RTFO. A well productivity increase of circa 60% was the result of this effort. (SPE 173686).

Other Applications

In hydraulic fracturing, combining optical fiber monitoring data with micro-seismic, micro-deformation and inter-well pressure parameters can give a clue to understanding the fluid flow in the reservoir. Also, it helps to comprehend the influence of fracture initiation location and the geometry of far-field fractures.

In the artificial lift area, particularly with the ESP system, the optical fiber surveillance will identify the dynamic fluid level which is critical for the pump optimum performance.

A permanent DTS installation along a sand control screen may be used to monitor the integrity of the screen and the potential plugging of the same. Figure 6 depicts this configuration.?

Using optical fiber CT logging in horizontal wells will be useful in applications such as logging, perforation, gas lift, acidification, well clean-out, etc. The weight in this case is lower than the conventional logging system, and it is easy to install and remove from the CT at any time.

Summary

The field cases presented showed some applications of the fiber optic monitoring system, which helped identify situations that otherwise would not be possible to detect. The deployment of those systems is used in conjunction with other tools, enhancing the data evaluation process. The main attribute of this technology is the simplification of the operations, which eliminates the need for WO interventions or multiple runs in the wellbore. Those benefits entail savings and faster decisions that, in most cases, lead to an improvement in the well's productivity.