Well intervention

Deepwater Hydraulic Well Intervention: A Creative Hybrid Solution

This technical paper describes the planning and execution of a multiservice-vessel (MSV) -based hydraulic-intervention campaign in Chevron’s Tahiti field in the US Gulf of Mexico.

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This technical paper describes the planning and execution of a multiservice-vessel (MSV) -based hydraulic-intervention campaign in Chevron’s Tahiti field in the US Gulf of Mexico. The five-well campaign was executed incident-free during 2015, delivering a total treatment volume of almost 30,000 bbl, resulting in 8,500‑BOPD gross initial production uplift and cost savings of 85% in comparison with traditional rig-based methods.


The Tahiti reservoirs comprise stacked turbidite sandstone deposits. The three major reservoirs are M-XX, M-YY, and M-ZZ, which account for approximately 82, 9, and 9% of proved reserves in the field, respectively. The M-XX reservoir, of which all intervention candidate wells are a subset, is further separated into two distinct pay intervals, the M-XXA and the M-XXB. Tahiti producers are installed as cased-hole frac-packed completions, with stacked frac packs and commingled production the norm for these M-XXA and M-XXB wells. Of the six “first-oil” production wells, there are two exceptions to this norm; one well (Well 2) was completed in the M-XXA interval only, and another well (Well 5) was completed as a single-trip frac pack across the two M-XXA and M-XXB intervals.

All Tahiti wells are installed with downhole gauges, which, in conjunction with subsea trees and topside instrumentation, allow continuous real-time monitoring of pressure, temperature, and rate-estimate profiles.

Over the 1–2 years following attainment of peak production, results of routine well tests showed noticeable ­productivity-index (PI) declines on several wells, and pressure-transient-­analysis evaluations revealed significant skin increases. By the time of mobilization on the subject-well intervention campaign, skin values on the candidate wells would range from 36 to 212, with PI values as low as 3 to 30% of original levels, and one well (Well 2) was pre-emptively shut in to preserve productivity/injectivity in order to allow successful hydraulic intervention. A dedicated initiative to integrate specific field data, laboratory data, and simulation modeling led to the diagnosis of fines migration as the primary contributor to skin issues. Acid stimulation became the identified solution, thus initiating detailed core testing, fluid-compatibility testing, and ­materials-compatibility qualification regimes to qualify a suitable formulation. Ultimately, a combination organic-acid/mud-acid formulation was selected. With this key qualification milestone achieved, and presented with a single-well acid-stimulation opportunity that was enabled by a rig-availability slot and a candidate well that was known to be beyond the pressure rating of available subsea-well-intervention systems, a rig-based early acid-stimulation job was performed in late 2014.

Phase Two of Tahiti’s staged field development successfully maneuvered the startup and early-life operations phases, which brought about the onset of water injection. Water injection specifically targeted the primary M-XX reservoir, and introduced the concept of scaling risk to the production wells. However, given the varying proximities of M-XX production and injection wells, only a subset of the producers are considered to be at risk. Engineering efforts were initiated toward an MSV-based deployment system and related subsea hardware specifically suited for application for the Tahiti infrastructure.

Front-End Engineering and Design

The rigless subsea-well-intervention system for this project would ultimately be required to deliver multistage chemical treatments to five existing subsea-production wells located in approximately 4,200 ft of water. Key early decisions included the choice of an MSV as the pumping and equipment-deployment platform, a stimulation vessel as the treatment-fluid carrier, open-water coiled tubing as the delivery conduit, and enhanced subsea choke inserts as the tree/wellbore injection access method. On this basis, a dedicated front-end-engineering-and-design (FEED) study was sanctioned. Several critical components of the proposed system drew the majority of the focus during FEED, given that the expected operational conditions were untested or undocumented relative to their design basis, or their original design basis was being modified. These components included the following: coiled-tubing-riser analysis, coiled-­tubing fatigue, subsea-foundation analysis, emergency disconnect system, and barrier philosophy. These components are described in detail in the complete paper.

The outcome of the FEED study was the validation of a subsea hydraulic well-intervention system. The MSV used for this campaign was a 340-ft-long, dynamically positioned vessel with a 130-ton subsea crane. It offered two fully integrated remotely operated vehicles (ROVs) with a heave-compensated launch and recovery system, a deck area of 8,000 ft2, and an integrated moonpool. Four high-pressure pumps were installed on the MSV.

While pressure-boosting capacity was provided from the MSV, the large treatment volume of each job warranted a separate stimulation vessel as the fluid-inventory carrier. Premixed treatment fluids, for one well at a time, were transferred at low pressure during treatment operations through a 4-in. hose from the stimulation vessel to the MSV. The transfer hose was self-buoyant, allowing visual monitoring and management throughout each job, and a breakaway connector was installed in a midline position. To ensure attainment of optimal treatment rates, two independently deployed coiled-tubing risers were used to deliver treatment fluids to the subsea wells.

The MSV-deployed stimulation module was rated for 10,000 psi and a 10,000-ft water depth. Each flow side of the module houses a ball valve for flow isolation, and has the capability to be completely ROV-operable. The acoustic (active) and deadman (passive) control features enable automatic shut-in by accumulator pressure activation under emergency-disconnect circumstances.

With the selected hybrid intervention system decoupling the riser connection/stimulation module from the subsea production tree (SSPT), jumper hoses were required to span the distance from the suction-pile locations to the candidate trees. Two-inch flexible hoses with hotstab end connections were used, with lengths on the order of 100 to 200 ft depending on the well. The tree end of the jumper hose ultimately mated with the valve module that was landed on the choke at the SSPT. The final retrievable components of the intervention system’s subsea-equipment package were the enhanced choke inserts, which had been preinstalled in the candidate trees by MSV before mobilization of the MSV-based intervention spread.

Finally, it is worth noting that the Tahiti host facility (a spar platform) maintained control of the candidate SSPTs across all operational phases by a central control room using a project-specific communications plan.

Well-Treatment Operations

Low-pressure vessel-to-vessel fluid transfer was selected as the means of managing treatment fluids during the project (Fig. 1). In the preferred solution, high-pressure pumps were stationed on the MSV and were fed fluid that had been transported to location on the stimulation vessel. Transfer from vessel to vessel was performed by a 4-in. flexible hose, featuring attached buoyancy modules to provide flotation of the hose between vessels. Hose cradles were fastened on both vessels to allow for hose security during operations, reducing the chance of exceeding minimum-bend-radius constraints.

Fig. 1—Vessel-to-vessel configuration with the low-pressure transfer hose deployed.


Upon connection of the low-pressure hose to the MSV components, the stimulation vessel was positioned to suit the weather conditions at the commencement of pumping operations. In practice, this typically meant an optimal standoff between both vessels of approximately 400 ft, which ensured adequate flexibility to withstand some degree of changing conditions before position adjustments were required. The campaign was preplanned to move from each of the five candidate wells sequentially and back-to-back, thus leveraging a single instance of MSV mobilization/demobilization efforts and cost.

The same, qualified acid-treatment design was pumped on all five wells, this being an organic-mud-acid system. On the basis of learnings and results from the sole prior acid stimulation in the field (that being the preceding year’s rig-based job), two changes were made to enhance the acid effectiveness, those being an increase in the concentration of hydrofluoric acid (from 1 to 1.5%) and the addition of formic acid to the main treatment stage.

Total volume pumped across the entire campaign was approximately 30,000 bbl, and a consistent average of approximately 4 bbl/min was achieved. Surface pump pressures throughout the campaign ranged from 4,500 to 7,300 psi, with pumping durations ranging from 12 to 60 hours.

Monoethylene glycol was used in the leading fluid to assist in hydrate prevention during initial contact with hydrocarbons and in the displacement fluid for well turnaround to begin flowback operations, which are detailed in the complete paper.

Campaign Performance Summary

In response to early-life well-­productivity-decline challenges caused by fines migration and scaling risk, a creative, hybrid approach to stimulate and protect well productivity was developed and executed successfully. Five candidate wells were identified for treatment, with post-job success highlighted by more than 100,000 incident-free offshore man-hours, which is a credit to the comprehensive FEED study and the on-site diligence of the operations personnel.

Project success was also underscored by a projectwide increase in production of 52%.

Lessons Learned

Though the project experienced success, several observations may allow increased success on similar projects in the future.

  • Treatment-diversion techniques are likely a natural enhancement to future hydraulic-intervention campaigns, especially given the stacked-reservoir setting in the Tahiti Field.
  • The ROV workload included more flow-intensive activities than originally anticipated, and additional ROV-tooling optimization could shorten critical-path ROV activities significantly.
  • Low-cycle fatigue was the predominant factor in coiled-tubing-fatigue-life consumption.
  • The designed system possibly included too many levels of fail-safe mechanisms and nominated barriers; the acquired confidence in the system may enable streamlined philosophies in this regard for future campaigns, with a view to improved operational efficiency.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 26984, “Deepwater Hydraulic Well Intervention in Tahiti: A Creative Hybrid Solution,” by J. Beard, J. Boiteau, R. Chauvin, B. Conner, C. Courtois, and T. Theall, Chevron, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission.