Low-permeability gas sands are often cased, perforated, and hydraulically fractured in stages. Commingled production is common, and coiled tubing (CT) has become the prevalent medium for communicating multiple productive intervals between fracture stages and for use as a remedial workover method.

High differential pressures in the wellbore complicate CT intervention considerably. Fluid and solid bridging agents are sometimes used to combat fluid losses and associated well control problems. Calcium carbonate may be the most common bridging agent because it is inexpensive and easy to mix; however, removing the damage caused by calcium carbonate slurries to the formation and proppant packs is difficult and costly. Rock salt is widely used because it causes less formation damage, but it is ineffective against fluid loss. Furthermore, to prevent dissolution of the pill, saturated brine must be used as a workover fluid, increasing costs and contributing to scaling problems.

A unique fluid-loss control agent has been gaining acceptance for temporarily isolating fractured sands. This double-derivatized, crosslinkable, hydroxyethyl cellulose (DDHEC) polymer leaves less than 0.5% gel residue by weight, minimizing impact on production. It has demonstrated a regained permeability of 91 to 93% under laboratory conditions and can be completely removed by acid. The polymer has been used in conjunction with 1.25- and 1.75-in. CT with a high degree of success. It does not require expensive brines, is resistant to solvents, and can be used with foam.1,2

The polymer has been applied in eight coiled tubing operations in south Texas, none of which has negatively affected production. This paper provides case histories for several of these field applications.


Multizone completions cause potentially massive differential pressures in the wellbore. Some south Texas wells produce from as many as 15 distinct sand lenses. The reservoirs are low-permeability sand and siltstone with varied clay content, having temperature gradients in the range of 1.7 to 2.2 °F/100 ft. These tight gas sands typically are hydraulically fractured upon completion. Several perforated intervals in the well may be open at once, with geopressure differentials as high as 8,000 psi.

Fluid dynamics under these conditions can prevent control of annular velocity and lifting efficiencies during milling and cleaning operations. Undetected fluid losses to an upper zone reduce annular velocity to surface and may cause cuttings to fall out of the return fluid, eventually lodging the CT in the well. Rapid crossflow can differentially stick coiled tubing even in clean wellbore environments, and solids-laden crossflow has been responsible for critically damaging CT and tools. Gas kicks resulting from annular fluid loss have led to a substantial number of blowouts in the industry.

Relatively little analytical work has been done to quantify kicks in completed wellbores, and workover specialists traditionally defer to drilling industry practices for managing circulation problems. Modeling performed for drilling applications has traditionally focused on pressure gradients, loss rates, and fracture propagation.3 However, the drilling models often are inadequate for cased-hole intervention because, by design, few pressure gradients are intersected in a single drilling stage. Furthermore, drilling practices typically rely on mud-weight manipulation and lost-circulation materials (LCMs) to heal propagated fractures, and neither option is attractive to thru-tubing workovers.4

Fluid-loss control agents have been used in workovers in south Texas for several years. A crosslinkable HEC developed for sand control in high-permeability formations has found a new application in this hard-rock environment. During eight recent CT operations performed in south Texas, this gel was used to mitigate crossflow and maintain well control. The applications have varied from the mundane to the unprecedented, and in all cases the gel enabled successful CT intervention with little to no impact on production.

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