Mature fields

Extending North Sea Asset Operating Life With Large-Diameter Velocity Strings

In the southern North Sea, many fields suffer from declining gas production because of reservoir-pressure depletion and associated liquid loading.

Jackup vessel next to Platform X, with the full support tower rigged up.
Fig. 2—Jackup vessel next to Platform X, with the full support tower rigged up.

In the southern North Sea, many fields suffer from declining gas production because of reservoir-pressure depletion and associated liquid loading. At some time during the operating life of offshore production facilities, the ability for these facilities to operate economically with further decline in gas production will need to be evaluated. To avoid early abandonment of these offshore assets, well-dewatering or liquid-unloading techniques, such as velocity-string (VS) installations, are considered for extending the operating life of these mature fields.

Introduction

As more fields in the southern North Sea begin to mature, it becomes important to keep the wells producing economically for as long as possible. In the case of depleting gas wells, this life extension involves preventing liquid loading in the wellbore.

In most gas reservoirs, the reservoir pressure will become insufficient to lift the water or condensate to the surface. As a result, the liquids accumulate in the wellbore and first will choke production then, later, will kill the well. This gas-well liquid loading occurs when the velocity of the gas up the wellbore becomes insufficient to drag the associated liquids to surface. Although many methods of liquid removal are available, only intermittent production, continuous injection of foam, and permanent installation of velocity strings are currently considered suitable for large-scale offshore application.

Because many of these wells produce from small production platforms or normally unmanned installations (NUIs), a self-propelled jackup vessel was used to accommodate the coiled tubing (CT) and associated equipment. The jackup vessel has its own crane, which is large enough to lift the heavy weights, including large-diameter CT reels, onto the deck.

Large-diameter (2⅜- and 2⅞-in.) chrome CT strings are being installed in deep gas wells in the southern North Sea as part of a large-scale installation project, including 20 wells over a 2-year period. The self-propelled jackup work vessel is used to house all the CT, well test, and associated equipment needed to enable well interventions on the small production platforms and NUIs. Critical to success of the project was the cross-discipline approach to preparing, selecting, and testing appropriate CT hardware and tools; performing hazard analyses; and implementing logistical coordination.

Engineering-Preparation Phase

From a large number of wells, the best 20 to 30 candidate wells were selected. It was clear that some of these wells would require a CT cleanout before VS installation because of some holdup depth in the well. The cleanout operations would be performed with the jackup vessel, before installation of the VS. The following conceptual choices were made.

VS Deployment and Material Type. Only CT-insert strings were considered because of excessive costs of installing jointed pipe. A corrosion-resistant alloy was selected to ensure long-term integrity and to safeguard future abandonment. The available diameter of 16Cr CT was constrained to 2⅞ in. or smaller.

VS Diameter. The VS reduces the minimum achievable reservoir pressure (abandonment pressure) (Pmin), thus increasing gas recovery. It does, however, increase friction and thereby reduces the well’s flow capacity (Qcap), which introduces deferment. Fig. 1 shows the example of Well X-102, for which the 2⅞-in. VS presents the best option.

jpt-2013-06-extendingnsf1.jpg
Fig. 1—Effect of VS diameter on flow rate at different bottomhole pressures. IPC=inflow-performance curve, IPR=inflow-performance ratio.

 

VS Flow Option. A sliding side door is installed just below the VS hanger to allow annular flow between the tubing and VS, or concurrent flow both inside and outside the VS. The ­annular-flow, or dead-string (DS)-flow, option provides higher capacity than VS flow, and hence can compensate part of the production deferment caused by the VS installation.

VS Hanger. Usually, VSs are installed below the surface-controlled subsurface safety valve (SC-SSSV). However, in this campaign, the VS hangers are installed in the landing-nipple profile of the SC-SSSV. The original SC-SSSV is either locked out [tubing retrievable (TR)] or pulled [wireline retrievable (WR)], and the original control line is used to supply hydraulic pressure to the new WR SC-SSSV installed in the VS hanger.

CT Pressure Barriers. The CT bottomhole assembly contains two wireline plugs for pressure isolation during installation and retrieval, rather than pump-out plugs. Pump-out plugs are sensitive to overpressure during installation, and they can cause a wellbore obstruction.

Operational Preparation Phase

Because of the magnitude of the project, 10-months preparation time was scheduled to get all of the equipment ready and to make necessary modifications to equipment and tools as needed. At the end of the preparation phase, a full mockup was organized in Emmen, the Netherlands, to test the equipment and running procedures before sending it offshore. The main modifications to equipment and tools are summarized in the complete paper.

Case Histories

Shell operates approximately 300 gas wells in the southern North Sea, which produce almost exclusively from the Rotliegend sandstone reservoir at depths of 2000 to 4000 m with reservoir temperatures of 60 to 140°C. The wells typically are deviated and are drilled from platforms, cased and perforated across the reservoir, and completed with 4½- to 7-in.-diameter tubing. The first platform and wells date back to the 1960s, and their numbers have gradually expanded with new wells.

The original reservoir pressure varied between 220 and 460 bar. The reservoir pressure in most wells has depleted significantly, resulting in a significant decline of well capacity from an initial 1×106 to 3×106 std m3/d down to less than the critical or liquid-loading rate, ranging from 0.03×106 to 0.3×106 std m3/d (value depends on tubing diameter and surface pressure). Surface compression has been used to reduce the flowing wellhead pressure from original export-pipeline pressures of 70 to 100 bar down to 5 to 15 bar, both to increase well capacity and to prevent or mitigate liquid loading.

VS Installation. At the time of writing this paper, nine VSs have been installed: six 2⅜-in. CTs to a maximum depth of 4754 m, and three 2⅞-in. CTs to a maximum depth of 3525 m. Fig. 2 and Fig. 3 show a work platform next to the first satellite platform—Platform X—during installation of a 2⅞-in. VS. This work platform was selected because it is self-propelled and because its main and auxiliary cranes can handle the heavy CT-weight loads.
 

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Fig. 3—Overview of the rig up with the jackup vessel in position.

The operational sequence was as follows:

  • After rigging up the CT, the setting of the pipe straightener was tested by checking the straightness of the CT.
  • A drift ball was pumped, and pressure tests were performed.
  • Thereafter, the CT was displaced with nitrogen.
  • Two plugs were preinstalled in the landing nipples of the bottomhole assembly (BHA) of the VS, and the BHA was connected to the CT.
  • The two plugs were pressure tested.
  • After the well was opened, the CT was run into the hole to the end depth of the VS.
  • The CT was then pulled out of hole over a distance equal to the depth of the TR SC-SSSV landing nipple and the length at surface from where the CT was cut. Then, the VS was temporary hung off in the slips of the blowout preventer (BOP).

During the campaign, the same crews were used as much as possible. By doing so, the learnings from previous installations were accumulated within the group, resulting in improved efficiencies and faster installation times. On the first well, X-102, the operations took longer than expected. Because of the time of the year, the offshore-weather conditions led to some forced nonoperational time. The slickline operations had some startup problems, and the VS installation itself required 11 days, not the 8 days anticipated for the VS installation for the first well. After the VS installation, the 3½-in. top string was installed. However, after multiple attempts, the WR SC-SSSV could not be set inside the VS hanger because of insufficient clearance. It was decided to pull the 3½-in. top string out and to remove it from the program of subsequent wells.

On the second well, X-104, an uncontrolled drop of the VS from the running string occurred at the flow-release pulling tool when the slip rams of the BOP were opened. The VS dropped to the bottom of the well (i.e., the hanger did not set and seal). As a result, flow could occur only through the VS annulus until a special packer was set and plugs were retrieved.

On Well X-103, no major issues arose, except for some slickline difficulties. On subsequent wells, producing from the Y platform, the crew had become familiar with the operations and a notable reduction in operating time was observed.

On Well Z-101, after hanging off the VS, the lower seals from the hanger appeared to be leaking because no positive pressure test could be obtained from the control line. The VS was retrieved from the well, the hanger redressed, and the string reinstalled. Unfortunately, the hanger did not seal this time either. The VS was pulled again, and the hanger was replaced. This time, the VS was run to depth and the replacement hanger tested successfully.

On the next two wells, operations were very smooth and efficient, which resulted in short operational times.

VS Performance. Well tests were carried out on each well after installation of the VS. Production results showed that actual production was close to anticipated rates. Well X-102 was programmed for DS flow; however, because of the problems on this first well, production was possible only through the VS, resulting in a lower production rate than anticipated. In Well Y-101, a water-shutoff treatment was performed before the installation of the velocity string, which also shut off some of the gas-producing sections of the well.

Conclusions

  • The operating life of mature offshore assets can be extended with the use of dewatering techniques, such as VS installations.
  • Large-diameter 16Cr CT can be used as VSs.
  • Large-scale offshore VS installations can be performed in the southern North Sea with the use of a dedicated jackup vessel and proper preparation.
  • Anticipated production rates were close to actual production rates, confirming the suitability of the model used.

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163905, “Extending the Operating Life of Mature North Sea Assets With Big-Scale Offshore Installation of Large-Diameter Chrome-Coiled-Tubing Velocity Strings,” by R.M. de Jonge, SPE, D. Ambergen, and U.A. Tousis, SPE, Baker Hughes, and K. Veeken, SPE, L. Hoekstra, and S. Gesterkamp, NAM, prepared for the 2013 SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition, The Woodlands, Texas, 26–27 March. The paper has not been peer reviewed.