In early 2008, Total E&P-USA sidetracked the Mississippi Canyon 243 #A2 well on its "Matterhorn" TLP, in deepwater Gulf of Mexico. A pre-project geomechanics study identified that the mud weight/fracture pressure window in the depleted and highly unconsolidated 'A' reservoir was very narrow, creating a strong potential for mud losses during drilling and cementing the 7" liner. The risk of losses was a primary concern since the well would be frac-packed, and if a competent cement column did not reach a sufficient height, the ability to fracture the reservoir would have been compromised. To mitigate this risk, the decision was made to drill through the depleted reservoir using a 'flat rheology' synthetic-based fluid, engineered with a high concentration of bridging particles to impart a strengthening effect on the formation. The 'designer fluid' allowed the reservoir to be drilled through successfully, and the 7" liner to be run and cemented with full returns. Analysis of the frac-pack data showed that the formation breakdown pressure was lower than the wellbore pressures experienced while drilling and cementing the liner, suggesting that the designer fluid improved the fracture resistance of the formation. The results imply that using such a designer fluid can have a strengthening effect on depleted/unconsolidated formations, in which some operators have had limited success applying wellbore strengthening techniques. The implication for the industry is that this technique can and should be considered on wells with similar challenges and risks as the Matterhorn A2 well. This paper will describe the approach taken in the laboratory for the fluid design, as well as operational practices to apply the treatment on location. A post-mortem analysis will compare formation breakdown pressures taken from the fracturing operations to actual wellbore pressures experienced while drilling and cementing, to demonstrate that a strengthening effect was realized. Introduction Total E&P USA conducted sidetrack operations on the A2 well to restore production that was impaired after prolonged shutdowns due to Hurricanes in recent years. The operations included: re-entering, de-completing, side tracking and re-completing the well. The operations were done with a heavy work-over rig installed on the TLP, and used a 'flat rheology' synthetic-based mud (SBM). A geomechanics study had been conducted prior to the sidetrack, and the analysis identified that a strong potential existed for mud losses in the depleted and highly unconsolidated 'A' reservoir due to the mud weight required (and associated ECD) to control the breakout of the cap rock shales above - a common scenario faced by operators during in-field drilling operations. According to the study, the mud weight/fracture pressure window had essentially disappeared.

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Acid stimulation is one of the production enhancement methodologies applicable in both development and exploration fields. Sandstone acidizing requires a sophisticated and well-studied approach to avoid formation damage caused by acid precipitation. Although the industry has made significant technical advancements in treatment fluids over the past decades, high bottomhole temperature still presents one of the biggest challenges. A new chelant-based fluid system was tailored to stimulate sandstone formation effectively under ultrahigh-temperature conditions. The new system has been evaluated extensively in the laboratory. Laboratory work included sequential dissolution, chemical analysis, and core flow tests. Both dissolution and core flow tests were conducted up to 400°F with reservoir core samples to simulate the actual reservoir condition and treatment design. Sequential dissolution results indicated that the new chelant-based system dissolved clay minerals in each sequence without causing silica precipitation due to secondary and tertiary reactions. The increase in the permeability of the reservoir core after core flow tests further demonstrated that the new fluid system is indeed highly effective in removing the damaging clay particles. The major advantage of the new chelant-based system is that it can be pumped in a single stage, which has greatly simplified the field operation and diversion requirement. In addition, because of its mild pH, the new system has low corrosion rate and less tendency to emulsion and sludge formation. This new system is HCl acid free, and therefore it eliminates the high risk of silica precipitation due to reaction with sensitive clays at high temperature. Last, but not least, the chelant fluid is consists of a retarded HF system which enables deeper radial penetration with less near-wellbore deconsolidation and which doubles the effect of clay dissolution and stabilization.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe cost of remedial work on marginal gas wells suffering from water unloading problems can be prohibitive, especially in an offshore environment. The expected financial return often does not justify the rig costs associated with pulling and running a new completion, while the formation damage caused by many well-killing methods can reduce the production potential of already marginal wells.The paper discusses the design and execution of the operation where Coiled Tubing and jointed tubing were used as a complex velocity string in order to restore production on a gas well, while retaining the full functionality of the downhole safety valve. Particular attention will be paid to the design of the string, which had to be tailored to remain within the operating envelope of the externally flush thread.

In early 2008, Total E&P USA sidetracked the Mississippi Canyon 243 #A2 well on its "Matterhorn" tension-leg platform (TLP) in the deepwater Gulf of Mexico. A preproject geomechanics study identified that the mud-weight/fracture-pressure window in the depleted and highly unconsolidated "A" reservoir was very narrow, creating a strong potential for mud losses during drilling and cementing of the 7-in. liner. The risk of losses was a primary concern because the well would be frac packed, and if a competent cement column did not reach a sufficient height, the ability to fracture the reservoir would have been compromised. To mitigate this risk, the decision was made to drill through the depleted reservoir using a flat-rheology synthetic-based fluid, engineered with a high concentration of bridging particles to impart a strengthening effect on the formation.The designer fluid allowed the reservoir to be drilled through successfully and the 7-in. liner to be run and cemented with full returns. Analysis of the frac-pack data showed that the formation-breakdown pressure was lower than the wellbore pressures experienced while drilling and cementing the liner, suggesting that the designer fluid improved the fracture resistance of the formation. The results imply that using such a designer fluid can have a strengthening effect on depleted/unconsolidated formations, in which some operators have had limited success applying wellbore-strengthening techniques.The implication for the industry is that this technique can and should be considered on wells with challenges and risks similar to those of the Matterhorn A2 well. This paper will describe the approach taken in the laboratory for the fluid design, as well as operational practices to apply the treatment on location. A postmortem analysis will compare formation-breakdown pressures taken from the fracturing operations to actual wellbore pressures experienced while drilling and cementing, to demonstrate that a strengthening effect was realized.