Downhole Gauges Meet Challenges of Operating Beside ESPs in HT Reservoir
Talisman Energy needed to enhance its continuous downhole monitoring capability at the Gyda field offshore Norway with a system that could perform in high-temperature (HT) conditions and operate beside electric submersible pumps (ESPs) in two oil production wells.
Situated in the southern Norwegian Sea 270 km from Stavanger, Gyda is a mature field in which production peaked in 1995. To address the increasing water production and decreasing reservoir pressure, the company installed ESPs in the completion of new wells A-19A and A-26 in 2011. Estimated field production for 2011 was 8,000 BOPD, according to the Norwegian Petroleum Directorate. The field’s production license was recently extended to 2028.
Challenges for New Monitoring System
The Gyda field has an extensive permanent downhole monitoring network that tracks information on individual well conditions, such as temperature and pressure. Through sensors, gauges, and other downhole operating equipment, Talisman can monitor and, if necessary, maintain pressure; control each well; and optimize field production. However, adding monitoring systems to the A-19A and A-26 wells presented special challenges.
The systems, which would need to monitor well zone conditions and the ESPs to ensure their function at the optimum points of their pump curves, would face reservoir temperatures as high as 160°C (and pressures as high as 300 bar). The HT environment can put enormous stress on instrumentation and impair its ability to generate reliable data. The standard gauges designed for the ESPs were not qualified to operate at the higher temperature levels found in the Gyda reservoir, thus further justifying the need for enhanced permanent monitoring.
Another challenge was that the new downhole monitoring systems would have to operate effectively next to the ESPs. These pumps require large amounts of power, which is transferred downhole on a three-phase cable. This cable runs alongside the ESP cable and is susceptible to noise disturbance from the pumps’ motors and variable speed drive (VSDs).
The VSDs—at 12 and 24 pulse, for example—can cause total harmonic distortion. This can be induced onto the downhole gauge control lines and interfere with downhole communication and gauge electronics, particularly during an ESP startup when the drive current can be six to eight times the normal operating current.
Gauge Selection and Testing
Talisman selected Emerson Process Management’s Roxar downhole HS gauges to meet the challenging requirements at the Gyda field. Manufactured and delivered on a fast track to meet a tight timeline, the gauges were subjected to 5 months of comprehensive onshore testing to prove that they could work seamlessly next to ESPs without being affected by the noise.
In the onshore testing, the gauges operated beside an ESP system that consisted of an integrated downhole network from Emerson that used a twisted cable pair connected to a gauge.
As part of the testing, the ESP was connected to a 12-pulse VSD using a 30-m cable. The gauge under consideration was strapped on top of the ESP cable, and 10 m of tubing encapsulated cable was run alongside the ESP cable. The ESP was operated across the full frequency range of the VSD.
Oscilloscope plots of the induced noise were obtained and analyzed, with the results showing that the new gauges experienced no noticeable loss of performance or interference when run in close proximity to the operating ESP. The gauges were fully operational at the moment the ESP started.
For comparison, a standard mono cable gauge system was also tested. This system encountered a high number of communication dropouts related to temperature and pressure measurements the moment the ESP was switched on. These problems increased as the pump continued to operate. These failures were in line with expectations regarding this type of system functioning beside an operating ESP.
Performance of New System
Following the successful tests, Talisman completed wells A-26 and A-19A in early 2011. Fig. 1 shows the diagram for the well and the alignment between the pressure and temperature sensors and ESPs.
Both wells employed two ESPs along with a motor oil temperature sensor and vibration sensors. The system consisted of two of the new gauges and two custom-made gauge carriers in addition to a twisted cable pair (tubing encapsulated) and a topside downhole network controller card.
The standard ESP gauges were installed to measure motor winding temperature and vibration. It was expected that they would begin to fail during startup as this regime would be beyond their qualified operating temperatures. The new gauges were in place to ensure the downhole monitoring could continue seamlessly. Thus, the control system was programmed to switch automatically to the new downhole system and begin obtaining data from it after 2 minutes of static data from the ESP gauges.
Once on production, well A-26 experienced temperatures of 153°C and pressures of approximately 300 bar. The downhole system and new gauges have been used for a number of months so far, maintaining the ESPs within the optimum operating conditions after the ESP gauges stopped supplying data approximately 40 days following startup.
The A-19A well experienced temperatures of 131°C and pressures of approximately 300 bar. The well, which produced as much as 65% gas, had a difficult startup with huge vibration exerted as a result of continual attempts to start the ESP with shocks of up to
4.2 G. Throughout this difficult time, with high electrical interference, extremely high vibrations, and a number of startup attempts, the new gauges functioned fully as Fig. 2 illustrates.
Reservoir Testing System Evolves to Meet New Frontier Challenges
Antonio José Gramcko Contreras, Schlumberger
As today’s deep wells challenge the bounds of pressure and temperature, accurate reservoir testing has become essential to mitigate production risk. The information contained in a series of downhole pressure transient measurements and representative reservoir fluid samples can make or break a prospect’s potential.
The consistent and accurate acquisition of this information requires the precision instrumentation and functionality of a drillstem testing system. Whereas excellent downhole logging instruments can describe the near-borehole regions, only a drillstem test can reach deeply into the reservoir to discover boundaries, faults, and fractures; confirm volumetric reserves estimations; and acquire the cleanest, most representative fluid samples to provide accurate fluid phase behavior, physical properties, and compositional analyses.
Safety, Reliability, and Efficiency
The Schlumberger Quartet high-performance downhole reservoir testing system combines four proven downhole technologies into a package that can isolate the zone, control flow, measure pressure and temperature, and acquire multiple single-phase reservoir fluid samples on a single trip into the well. The system provides enhanced safety, increased efficiency, and improved reliability to testing operations.
Compared with conventional downhole test strings, the system functions with a 35% lower tool operating pressure, 50% fewer seals, and 60% fewer connections, while requiring 90% less nitrogen. The system is four times shorter than a conventional tool string because it eliminates the requirement for a safety joint, jar, slip joints, and drill collars.
Despite its smaller size, the system is sufficiently durable to permit perforating guns to be run below the packer and fired without incurring damage to the tools or impairing their accuracy or integrity. The system also includes a below-packer circulating valve to allow a more efficient well kill following the test, which is especially important when testing gas wells.
Each of the four tools that make up the downhole reservoir testing system operates individually and collectively to perform the test. The Certis high-integrity reservoir test isolation system delivers production-quality well isolation. The isolation system combines the features of a retrievable drillstem test packer with a hydraulically set permanent packer, making the safety joint, jar, slip joints, and drill collars unnecessary. Because the system is actuated by annulus pressure, no rotational or set down forces are required.
Once the packer is set, the stinger is released and the internal seals are allowed to move in the sealbore. After testing, a straight pull releases the slips and causes the packer sealing element to collapse. A bypass valve opens to prevent swabbing the well while pulling the test string out of the hole.
The IRDV intelligent remote dual valve contains the tester valve plus a circulating valve that allows communication between the test string and the annulus. Actuated by low-level pressure pulses, the tester valve and circulating valve can be operated individually or simultaneously up to a total of 24 complete (open/close) cycles. A unique built-in feature allows the mechanical override of the tool and the option of combining two dual valve tools in the same string for independent operation or pairing one valve with another for redundancy in the string.
The Signature quartz gauge precisely measures dynamic pressure and temperature and records it in nonvolatile memory for the duration of the test. The gauge’s multichip module, pressure and temperature measurement electronics, clock, and nonvolatile memory are mounted on the same ceramic substrate, which significantly improves measurement quality and suppresses drift.
The SCAR inline independent reservoir fluid sampling system collects and retrieves multiple fluid samples and maintains them at or above reservoir pressure. The system captures contaminant-free reservoir fluid samples using eight 300 cm3 Inconel fluid samplers. Each sampler is independently precharged with nitrogen for pressure compensation, enabling the retrieval of high-shrinkage reservoir fluids at or above reservoir pressure even in low-temperature operating environments such as deep water.
Samplers can be actuated simultaneously or selectively, using surface commands by means of annular pressure, and run with the latest generation inert coatings to address H2S and other challenging questions related to trace element species concentrations.
Testing the Limit
The capabilities of the Quartet system have been achievable up to a rated temperature of 350°F. To keep pace with the industry’s expansion into the environmental frontiers, the Quartet-HT high-performance downhole reservoir testing system was recently developed. The new system maintains the features of the original, but extends the pressure, temperature, and time limits of the individual tool component systems. The system incorporates the latest all-ceramic multichip module electronics (Fig. 3) and is rated to 410°F, enabling it to perform at ultrahigh reservoir temperatures.
The high-integrity reservoir test isolation system has undergone an extensive high-pressure/high-temperature (HP/HT) testing and qualification program defined by a Schlumberger proprietary pressure and temperature mission profile, including qualification at the ISO 14310 V3 grade.
In addition to delivering a much higher testing efficiency in HP/HT environments, the new system has operated safely in extreme sour gas conditions of up to 40% H2S in the Arabian Gulf.
The ceramic substrate on which the quartz gauge components are mounted allows the gauge to withstand HP/HT conditions for an extended period so that the measurement quality remains high for the duration of the test (Fig. 4).
The Quartet-HT system maintains well integrity while testing safely, accurately, and efficiently at the extremes of the well environment. The multicycle and single-trip features provide operational efficiencies that can reduce rig time and risk. The HT capabilities allow operators to isolate, control, measure, and sample closer to the HT reservoir for better test results and more accurate reservoir characterization.