Wired drillpipe (WDP) technology was implemented on a multiple-well project located offshore the Norwegian Continental Shelf. The operator’s main objective was to drill each well as cost-effectively as possible while making sure that the wellbore placement was optimum. Achieving this goal required the use of specific LWD equipment together with the WDP Network. This high-speed data network enables instantaneous transmission of all downhole data and saves valuable rig time.

Full real-time understanding of the downhole drilling environment as well as the formations drilled enables quick actions for mitigating drilling dysfunctions and equivalent circulating density management as well as optimal well placement. The planned extended-reach wells had a very tight pressure window. Landing and geosteering the reservoir sections required the latest LWD technologies on WDP to achieve the goals of the project.

Complex drilling application

The drilling targets consisted of an oil reservoir and several deeper structurally complex high-pressure gas and condensate reservoirs. The oil reservoir was developed with long horizontal wells. Several deviated wells were drilled to unlock the gas and condensate reserves. The field was initially discovered 40 years ago but proved too complex to develop until now.

Over the years several exploration and appraisal wells were drilled within a narrow pressure window, with multiple bottomhole assembly (BHA) runs per section. The complex drilling environment posed many challenges, including severe losses, influxes and unstable formations. Excessive downhole shock and vibration also challenged successful delivery of MWD/LWD signals to surface. To overcome these challenges, WDP technology was implemented from the start of the field development.

To overcome these challenges, WDP technology was implemented from the start of the field development.

The realized quantifiable benefits outweighed the initial upfront investment and recurring operating and maintenance costs compared to a drilling operation with mud pulse telemetry. This translated into direct net rig time savings, providing a return on the technology investment, which doesn’t take into account additional upside benefits identified. These benefits included significantly lower geological uncertainties and reduced risk of high-impact events such as well collapse or catastrophic flow events, providing not only economic benefits but also HSE benefits. Enabling the full use of LWD technology for improved well placement and the quality of the drains drilled without compromising well integrity was also a significant benefit of the WPD implementation.

New drilling technologies on WDP

NOV’s BlackStream Along String Measurements (ASM) technology provides real-time measurement reading from sensors embedded at multiple points throughout the drillstring. The technology acquires temperature, annular and bore pressure, rotational velocity, and three-axis vibration data at high frequencies. The data are streamed to surface via WDP.

The ASM data enable an improved understanding of the downhole environment not only at the BHA but throughout the entire openhole and cased sections. The tools provide flow-off readings, which proved useful on this tight margin application. The main benefits of running this technology are:

  • annular pressure measurements over the entire openhole section, with or without flow;
  • monitoring of hole cleaning efficiency and real-time adjustments of parameters such as ROP and circulation time;
  • enhanced MPD management, with the ability to monitor annular pressure fluctuations during connections and tripping;
  • safe management of critical situations; and
  • determination of pack-off point.

Baker Hughes’ GaugePro Echo on-command digital reamer consists of a main reamer plus a near-bit reamer integrated in the BHA. Both reamers were initially activated through the use of mud pulse downlinks.

During the project the service company was able to adapt the integrated reamer technology such that it could be digitally activated and deactivated through WDP telemetry. Activating and controlling both the near-bit reamer and main reamer with WDP telemetry was a world’s first.

Activating and controlling both the near-bit reamer and main reamer with WDP telemetry was a world’s first.

The main reamer was used to open up the hole and also enabled easier pulling out of hole. The near-bit reamer eliminated the need for a dedicated reamer run to open up the rat hole. At least three dedicated reamer runs were saved by using the integrated dual-reamer setup.

A main benefit of running dual integrated reamers on WDP is the elimination of the old-fashioned use of “dropping a ball” to activate or deactivate the reamer. The reamer can be activated and deactivated unlimited times as activation and deactivation commands are transmitted though downlinking.

Latest MWD/LWD technology applied on WDP

In tight pressure regimes there is a great need for geostopping to avoid a blowout. Looking ahead of the well path was deemed essential for safe operations. In addition to crossing pressure regimes in different formations, these wells had a very tight mud pressure window. The wells were drilled with managed-pressure drilling due to these pressure constraints. In this environment even pressure fluctuations from a downlink to the tool can be disastrous for wellbore stability. WDP downlinks are instantaneous and do not induce any downhole pressure fluctuations. Thus they are currently the only technology providing a solution for these kinds of applications.

There were large geological and seismic uncertainties in terms of depth to reach the reservoir. Not only was it important to land the well at the right true vertical depth (TVD) for maximum reservoir exposure, but also setting casing as close as possible to formations with different pressure regimes was imperative from a safety point of view. Borehole seismic-while- drilling was seen as the most cost-effective solution.

The WDP Network transmitted the seismic memory data in real time to surface, enabling detection of formations ahead of the bit.

This is the first time that this has been achieved.

The seismic-while-drilling tool detected relevant formations 200 m (656 ft) TVD below the tool in real time. Real-time first-break data were used to update velocity profiles for reduction of the surface seismic. In addition, reflective data were processed continually after each connection to look below the bit for distances up to 200 m TVD. Although this achievement could have been done with mud pulse telemetry, such results would have taken significantly longer, and data quality would have suffered.

Final results

Valuable rig time was saved due to the instantaneous data transmission enabled by WDP, and at least three dedicated reamer runs were saved by using the integrated dual reamer setup.

The wells were landed and navigated within the reservoir with real-time recorded quality formation evaluation, annular pressure and drilling dynamics data from the BHA and annular pressure and drilling dynamics data measured all along the string with ASM tools. High-resolution images were available for real-time decision making, and images such as short-spaced density images were used for wellbore breakout indicators.

This resulted in improved geological understanding based on enhanced formation evaluation data acquired in real time that led to subsequent improved wellbore placement and increased reservoir section length. Netto- gross ratio was increased by more than 28% compared to expected and more than 200 m more reservoir was drilled and completed. In total, the geosteering optimized net sands by about 1,000 m (3,281 ft) measured depth over three horizontal sections.

This extension in drain length, together with the optimum wellbore placement within the reservoir, actually saved the operator from drilling another well since planned drain section length and quality already had been achieved.

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