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Permanent Fiber-Optic System Monitors Oil-Rim Movement

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In highly fractured carbonate reservoirs, the conventional method of monitoring oil-rim movement is running wireline gradiometric surveys periodically. However, some operators have found that this method is inconclusive and is unable to provide information in a manner timely enough to influence operations because the gradiometric surveys are only run a few times a year. In this paper, the authors describe a project to design, field trial, and qualify an alternative solution for real-time monitoring of the oil rim in carbonate reservoirs that overcomes these disadvantages.

Current Methodology

The methodology of performing gradiometric surveys can be applied in reservoirs successfully where the permeability of the formation is high and where the formation is fractured such that good communication exists between fluid within the formation and within the observation well (given that the well casing is highly perforated across the full length of the reservoir section). Under these conditions, the fluid levels measured by the gradiometric surveys give the operator enough information about the oil rim within the reservoir to adopt an active smart-field production method. The term “smart field” is used by the operator to describe oilfield operations where surface decisions are supported by measurements from within the reservoirs.

While the use of gradiometric surveys for production optimization is helpful, it does have disadvantages. Each survey requires a well intervention; as can be imagined, the process is relatively expensive and introduces health, safety, and environmental (HSE) risks while the well is open. Consequently, gradiometric surveys are generally commissioned at a low frequency, perhaps only one or two measurements per year within key observation wells.

New Methodology

In the early 2000s, a potential was recognized to provide an array of permanently deployed pressure gauges in the wellbore to measure the density of the media between adjacent gauges. From this measurement, the interfaces between the media of different densities could be derived accurately.

The idea of measuring pressure within a well is not new; pressure transducers based on numerous electronic measurement principles have been used by the industry for decades. However, these electronic gauges are not optimal for use in the described application because of their relatively short service life at the elevated temperatures found in wellbores and because of the logistical difficulties and high cost associated with deploying a string of multiple electronic gauges in a single well. The operator’s in-well technology team examined the emerging use of optical-fiber Bragg gratings (FBGs) for pressure metrology applications in extreme environments. The gauges used in this technology required no downhole electronics and offered long service at elevated downhole temperatures. The technology offered the long-term stability required to detect the subtle pressure changes resulting from small fluid-level changes. Dozens of such gauges could be deployed in a series on one optical cable connected to a single surface-acquisition unit (interrogator).

System Development and Trial Deployments

In 2003, the operator approached a company involved in the development and commercialization of FBG technology across numerous industrial sectors. The company had recently developed a diaphragm pressure transducer for monitoring the load within a high-performance aerospace composite. The transducer converted changes in the hydrostatic pressure of its surroundings into the deformation of a pressure-sensitive diaphragm, and then into the strain, within an optical fiber attached to the diaphragm.

For oil and gas applications, use of the optical fiber as a means of data transmission brings several benefits, including the following:

  • The efficiency of transmission allows the interrogator to be located several tens of kilometers away from the downhole gauges, allowing use in very deep wells and even in deepwater subsea wells at the end of long tiebacks.
  • Data are encoded in the wavelength of the light, which is not affected by attenuating features within the fiber, meaning that data quality and accuracy are maintained even with long transmission lengths.
  • Data are immune to the electromagnetic influence of machines often found in the downhole, subsea, and surface environments.

Collaboration toward a downhole FBG distributed pressure and temperature sensing (DPTS) system began in 2003. The first trial deployment was made in 2010, when nine downhole gauges were installed in an observation well (Fig. 1). The gauges were tubing-deployed, strapped to the outside of a 3½-in. tubing string that was run in hole by a workover rig. The optical cable connecting the downhole gauges to the surface interrogator was strapped to the tubing as the string was run in hole and then passed through a surface pressure barrier after penetrating the wellhead. From there, the optical cable was trenched to the location of a pole-mounted instrument cabinet some tens of meters away in a nearby safe area. Here, the surface interrogator collected the data from the downhole gauges and passed them to an industrial computer, which then transmitted the data to the local flow station through a remote telemetry unit.

Fig. 1—Images of initial DPTS installation. Left: pressure gauges being clamped to tubing string. Middle: fiber-optic cable exits the wellhead. Right: solar-powered surface instrumentation records and transmits pressure data.

 

The first deployment encouraged the sponsors to support further work on improvements to the system:

  • The mechanical design of the gauge was amended to reduce the cross section to a ¾-in. diameter and to relocate the sensitive pressure diaphragm from the outside of the gauge to inside.
  • The optical cable interconnection between the gauges was changed from a commercial optical connector, which had proved unreliable, to a custom-built splicing chamber, within which permanent spliced fiber connections could be isolated from wellbore fluids and pressure.
  • The surface interrogator evolved from a laboratory-grade instrument to a field-grade model. A power-hungry and temperature-range-limited polarization scrambler was removed. An industrial computer was removed by integrating its functionality into the field interrogator. The operating temperature range of the interrogator hardware was increased steadily to suit summer desert wellhead temperatures.
  • The company’s software engineers worked on an algorithm to convert the pressure data into fluid-contact or “cut” levels. This algorithm took advantage of the multitude of combined data points between the various gauges in the system to deliver a result with lower uncertainty. Furthermore, the algorithm automatically identified and discounted erroneous data points within the system.

Two further trial deployments were conducted to demonstrate that the solution could be replicated and to validate the system-design improvements.

Results

The three trial deployments progressively provided more accurate data and greater system reliability. In particular, the stability of the pressure measurements from the downhole optical gauges was very high—critical in avoiding a false indication of fluid-contact movement.

Pressure and temperature measurements, and system-health and self-diagnostic data, are transmitted from the wellhead interrogator into a database at 3-hour intervals. When new data sets are received, an algorithm processes them into gas/oil-contact and oil/water-contact locations. Using a suite of visualization tools, engineers are able to view real-time and historical pressure, temperature, and fluid-level data, which are used to influence the production-optimization program.

DPTS technology has been continually developed since the trial deployments in the Sultanate of Oman, with two goals in mind: improved deployment methodology and increased service temperature.

Further developments to the manufacturing process of the downhole pressure gauges will enable application of the system to production monitoring in ultrahigh-temperature thermal-recovery wells, where fluid temperatures up to 280°C can be expected.

System Value

Providing a quantitative statement of system value is not possible because of the confidential nature of production rates and other operational statistics. However, the ways in which the system has provided value, in addition to improved reservoir understanding, can be summarized as follows:

  • Reduction of production deferment—Use of real-time monitoring prevents the repeat of previous situations in which gradiometric surveys missed the thinning and the lowering of the oil rim.
  • Operational expenditure reduction—Long-term cost reductions can be seen when comparing the cost of a single DPTS system deployment with that of repeated gradiometric surveys.
  • HSE risk reduction—A DPTS system requires only one well intervention during the life of the well completion.
  • System-expansion capability—The fiber used in the DPTS system could also be used for distributed acoustic sensing, vertical seismic profiling, or distributed temperature sensing, enabling the simple addition of other monitoring systems.

Conclusions

The authors present a project in which the possibility of measuring fluid levels in a wellbore using optical pressure gauges was conceived, prototyped, field-trialed, and refined to the point of widespread commercialization. The system provides real-time data to the desk of the operator’s reservoir engineers, informing production-optimization decisions and delivering significant value. The performance of the final trial deployment led to the determination that the system was sufficiently mature to pass its final technology-readiness level, informing operating units that the DPTS solution was commercially available.

For a limited time, the complete paper SPE 188868 is free to SPE members.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 188868, “Development and Field Application of a Permanent Fiber-Optic Wellbore-Fluid-Level Monitoring System,” by C. Staveley, SPE, C. Doyle, and C. Coetzee, Smart Fibres; A. Franzen, H. Den Boer, A. van Rooyen, and W. Birch, Shell; and A.B. Biderkab and E. Moes, Petroleum Development Oman, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed.

Permanent Fiber-Optic System Monitors Oil-Rim Movement

01 March 2019

Volume: 71 | Issue: 3

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