Deepwater Hydraulic Well Intervention: A Creative Hybrid Solution
Authors: Carpenter Chris 
Published: June 2017

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 The paper has not been peer reviewed.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.

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.

Introduction

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 preemptively 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.