Optimizing the Deepwater Completion Process Offshore Israel

Topics: Offshore

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This paper describes the successful delivery of one ultrahigh-rate gas well (more than 250 MMscf/D) completed in a significant gas field offshore Israel with 7-in. production tubing and an openhole gravel pack (OHGP). The Tamar 8 well was completed approximately 4 years after the start of initial production from the Tamar development. Several operational innovations and process improvements were implemented that resulted in a significant reduction in rig time.


The Tamar field was discovered in 2009 in 5,505 ft of water at a total depth (TD) of 14,967 ft. Tamar is one of several recent gas discoveries made in the deep waters offshore northern Israel and Cyprus in the Levant Basin (Fig. 1). The field consists of three gas-bearing sandstone layers separated by two shaley units. The trap for the reservoir is a large four-way anticline cross-cut by northwest bearing faults. There is an approximately 4,900-ft-thick evaporate sequence in the shallow overburden above the field consisting of mostly halite, with interbedded anhydrite and clastics.

Fig. 1—Map of the Tamar project.


Tamar was designed as a subsea development with five initial wells tied back 150 km to a new shallow-water production-processing platform located near the existing Mari-B platform. As the world’s longest subsea tieback, the Tamar field came online in March 2013 at gas rates ranging from 600 to 950 MMscf/D from a production platform designed for 1,200 MMscf/D. Since 2013, all wells have produced with high reliability and minimal difficulty.

Tamar 8

In early 2016, a decision was made to add an additional well, Tamar 8, to the existing well stock. Accelerated well planning was conducted thereafter to be ready for a completion start date of 1 December 2016. On the basis of front-end engineering studies, several operational statements of requirements (SORs) were specified consistent with the previous Tamar completion campaign. These SORs included the following:

  • The production (9⅞-in.) casing was to be set approximately 10 ft inside the reservoir section.
  • The reservoir interval must be underreamed to 12¼ in.
  • The reservoir interval must be vertical to a low angle (less than 20°).
  • Only 115 ft of reservoir interval would be drilled/completed.

Completion Sandface. The Tamar sandface completion is an OHGP that, in simple terms, is a drilled section of the reservoir [using a qualified and fit-for-purpose reservoir drill-in fluid (RDIF)] in which a gravel pack has been placed. A key geometric attribute of the Tamar OHGP is the requirement to enlarge (underream) the drilled reservoir section; this hole enlargement (from 8½ to 12¼ in.) significantly increases the effective wellbore radius from which multiple production benefits are derived.

Temporary Plug and Abandonment (P&A)

The advent of robust retrievable V0-rated bridge plugs offered a compelling solution for the temporary P&A of Tamar 8. In addition, it was determined that the running of the production casing as a long string (the original design for Tamar Phase 1, before changes prompted by the Macondo accident) was operationally prudent and safe. As a final operational improvement, completion brine was used to displace the cement.

Wellbore Cleanout and Reservoir Drilling

Key to reducing rig time were the process improvements made for the various fluid displacements as well as the drilling and underreaming of the reservoir section. The Tamar Phase 1 wells used six bottomhole assemblies (BHAs), five fluid displacements, and numerous circulation periods to drill the reservoir section while maintaining rigorous cleanliness standards.

After a thorough analysis of the Tamar Phase 1 phase timings and a technology review with service providers, the Tamar 8 well was able to complete the same wellbore cleanout and reservoir drilling phases with only three BHAs, three fluid displacements, and three well circulations to achieve the same rigorous cleanliness standards.

Tamar 8. The initial re-entry of the Tamar 8 well was made after installation of the subsea tree and latching up of the blowout preventers (BOPs). After BOP testing, the BHA was run in hole (RIH) with seawater in the riser to a level immediately above the upper suspension packer. The casing and the riser were displaced to the riser margin brine left in the wellbore for the temporary P&A. The upper packer was released and retrieved to surface. The lower packer retrieval BHA was RIH and the lower suspension packer was retrieved.

A combination drilling, underreaming, and cleanup BHA was RIH to the float collar. Immediately following the successful cleanup of the wellbore, the indirect displacement was completed by circulating the well from clean completion brine to RDIF.

With the wellbore full of clean RDIF, the remaining shoe track and 45 m of 8½-in. hole were drilled to TD. The string was pumped out to the casing shoe before circulating to remove cuttings in the wellbore with RDIF 1. The underreamer was placed below the 9⅞‑in. casing shoe and activated by ball drop while pumping clean RDIF. The section was opened from 8½ to 12¼ in. while continuously pumping clean RDIF before deactivating the underreamer by ball drop. The openhole section and 150 m of the 9⅞-in. casing were displaced to solids-free RDIF. The BHA was pumped out to the interface before direct displacement of the casing and riser to filtered completion brine. The well was circulated until well-cleanliness standards were achieved and the BHA was pulled out of hole.


As-Built Completion. The as-built completion schematic for Tamar 8 is presented in Fig. 8 of the complete paper; this design is consistent with previous Tamar completions.

Operational Performance. The completion was installed as designed with full sand control, high-quality reservoir interface, and required mechanical integrity in approximately 58 days. The completion operations had an efficiency of 37.3 days of productive time (64.3%) and 15.3 days (26.4%) of nonproductive time (NPT).

NPT was associated with four significant events that were outside the scope and control of the completions team. Those four events included fishing a broken temporary abandonment packer (6.3 days), BOP troubleshooting (1.6 days), pulling the lower marine riser package because of leaking valves (12.2 days), and waiting on weather (2.5 days). The fishing of the packer was considered change-of-scope NPT because it involved a fish that was left in hole during the temporary abandonment of the well before the commencement of completion operations. Therefore, it was not planned and not accounted for in the original completion authorization for expenditure (AFE).

When the NPT that was accrued from these events is removed, the well cost came in at approximately $1,000,000 over AFE and slightly over the 36.1 days allotted for the AFE. This is a more-accurate depiction of the completion team’s operational performance, which was very good, with only 2.6% NPT, or 1 day. Were it not for some of the unforeseen preventative maintenance operations required by the rig during the demobilization phase, the time would have come well under the AFE.

Tamar 8 Performance

Tamar 8 Rig Well Test and Platform Flowback. The initial test of Tamar 8 used a well-test package on the rig and occurred immediately following the completion. The primary purpose of the test was to unload the tubing of completion fluids to prevent these fluids from entering the subsea infrastructure and contaminating the hydrate-inhibition and flow-assurance systems. Additionally, the well test allowed for an early evaluation of completion performance.

Following the rig well test and rig demobilization, the well was connected to the subsea infrastructure by a jumper into the existing Tamar 3 infield flowline through a well pipeline-end-termination skid. The well then was brought online for flowback into the shared Tamar 3 infield flowline, to the manifold, and through the 16-in. gathering lines to the Tamar platform.

The initial rig well test and platform flowback data indicate that completion performance improved after the maximum production rate (flowback to platform), which suggests additional cleanup of the completion, exposing additional sandface and thus lowering drawdown.

Field Performance

Initial startup of the Tamar field commenced on 31 March 2013. As of October 2017, the field had produced approximately 1.363 TCF of gas at an average daily production rate of 817 MMscf/D and a maximum daily rate of 1,103 MMscf/D. Tamar continues to have exceptional uptime performance, with approximately 8.5 days of downtime over 4.6 years (99.9% uptime). None of the downtime has been associated with the completions.


A new application to combine the use of existing technologies was identified, assessed, and successfully integrated into completion operations that enabled the drilling and underreaming of the reservoir section, as well as performing wellbore-cleanout operations and multiple fluid displacements in a single trip.

  • The Tamar 8 completion achieved rig-time savings of approximately 5 days without any compromise in production performance.
  • The sandface-design methodology (OHGP) selected proved extremely successful given the low skin.
  • Full-field performance since 2013 continues to demonstrate high completion efficiency and reliability.
  • This new approach will be used in 2018 on the first phase of the Leviathan natural-gas project (four wells).
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189637, “Optimizing the Deepwater Completion Process: Case History of the Tamar 8 Completion Design, Execution, and Initial Performance Offshore Israel,” by John Healy, SPE, Steven M. Waggoner, Ian Magin, SPE, Matt Beavers, SPE, Kevin Williams, and Russell Hebert, SPE, Noble Energy, prepared for the 2018 IADC/SPE Drilling Conference and Exhibition, Fort Worth, Texas, USA, 6–8 March. The paper has not been peer reviewed.

Optimizing the Deepwater Completion Process Offshore Israel

01 September 2018

Volume: 70 | Issue: 9


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