TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractRecord high prices for oil and gas have increased the opportunity for producers to maximize the value of their assets. Under current market conditions, reservoirs previously considered marginal or even noneconomic can yield an acceptable return on investment and are increasingly considered for well completion. Many are lower-permeability formations that require fracture stimulation during the completion phase to deliver economic rates. In the latter part of 2004, a new stimulation technique was introduced to the industry, providing well operators a method to achieve multiple-zone fracture stimulation while controlling stimulation costs. By mid-2005, this new process had been evaluated by several operators in the US as well as Canada and Australia with very positive results.This new process offers the opportunity to perforate and stimulate multiple pay zones with a single well intervention, often within a single day. The technique employs a hydraulic jetting assembly on coiled tubing (CT) to erode perforations, immediately followed by pumping a fracture-stimulation treatment through the annulus between CT and casing. At the completion of the first fracturing stage, small-volume, highproppant-concentration slurry is left in the wellbore to provide isolation of the just-stimulated zone from subsequent targets. In some applications, a wellbore screenout may also be induced to improve the temporary isolation of this zone. This sequence (perforate, stimulate, isolate) is repeated until all desired zones have been treated. Following the final stimulation stage, the well is cleaned out with CT and turned over to production. If needed, N 2 gas can be pumped through the CT to kick-off the return flow.This paper describes the operational aspects, advantages, and limitations of using this new multistage perforating and fracturing technique with example field applications.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractLow-permeability gas sands are often cased, perforated, and hydraulically fractured in stages. Commingled production is common, and coiled tubing (CT) has become the medium of choice for opening multiple productive intervals between fracture stages and for use as a remedial workover method.High differential pressures in the wellbore complicate CT intervention considerably. Bridging agents are sometimes used to combat severe lost circulation 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. Salt pills are widely used because they cause less formation damage, but they are ineffective at controlling severe 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 popularity for temporarily isolating low-pressure, 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 Eight field applications of the polymer have been performed, none of which have negatively affected production. This paper provides case histories for several of these field applications and defines techniques and selection criteria for applying the polymer under specific well conditions.

No abstract

TX 75083-3836, U.S.A., fax 01-972-952-9435.

fax 01-972-952-9435.References at the end of the paper. AbstractCoiled tubing (CT) is routinely deployed in wells producing from multiple pay intervals. Multizone completions induce pressure gradients that present significant operating risks to CT operations. Kicks and lost circulation can cause reservoir damage, blowouts, and lost pipe. Countless CT strings have been lost in wells because of uncontrolled well responses during treatments.Wellsite observations have improved the diagnosis and prevention of circulation problems caused by differential pressures. Some of the specific factors influencing these problems are formation fluid levels, well geometry, interval height, and temperature. Reservoir management techniques can reduce the hazards imposed by differential pressures. However, because kicks and lost circulation cannot always be avoided, contingency plans are necessary. Prejob calculations and planning procedures can help operators establish practices that minimize the adverse effects of kicks and lost circulation.A comprehensive strategy for CT operations includes contingency planning. While some risk must be assumed in all wellintervention processes, proactive planning can minimize problems and increase the potential for success.