Sable Island, GB 386 fields challenges for operators

High tech combatting high temperatures

William Furlow
Technology Editor

• The Sable Offshore Gas Project is the most recent example of significant challenges in HP/HT drilling. [39,453 bytes]

High pressures and high temperatures (HP/HT) are a common drilling problem in a variety of theaters from Mobile Bay, Alabama, to Ras Laffan, and from the Arctic to Latin America's Southern Cone. Safety and efficiency are a priority as traditional and new solutions to the problems are applied.

In North America, the Sable Offshore Gas Project is the most recent example of significant challenges in HP/HT drilling. The project's fields are located on the Scotian shelf, 200 km off Nova Scotia and contain gas reserves estimated at 18 Tcf in deposits and 3 Tcf of recoverables.

The first phase of development will include 12 wells. Currently, the jackets have been placed on two of the fields. Working in the Venture field, the Rowan Gorilla II has batch drilled five wells to the surface casing, and has drilled two wells to the intermediate casing level.

The rig is currently drilling to a TD of 5,000 meters on one of these. Sante Fe is bringing in the new Galaxy II rig this fall to begin a five-year drilling program. The new rig will drill five wells in the Thebaud field. First gas from this project is scheduled for late 1999.

These rigs are specially outfitted for HP/HT. This includes special well control equipment rated to 15,000 psi and 350°F. They have advanced kick control equipment supplied by Baker Hughes Inteq at the surface and Sperry-Sun real-time technology to detect flow into the borehole while drilling. Graeme Connell, Public Affairs Manager for SOG, said there were also some metallurgy challenges in designing tubulars that could withstand the harsh HP/HT downhole environment.

The wells are monobore completions that contractor Baker Oil Tools (BOT) rates as 12,000 psi and 300°F. To withstand such critical temperature/pressure conditions, BOT will install the Flex Lock Liner Hanger with JMZXP packer technology and snap-in-snap-out shear release tie-back seal assembly technology. This is the same technology BOT uses on HP/HT fields in Mobil Bay.

In addition, the rig crews receive special well control training for working in an HP/HT field and there is a strong emphasis placed on preventive maintenance.

US Gulf HP/HT

In Garden Banks Block 386, EEX, Pan Canada, Mobil, and Enterprise Oil are drilling the deepest well in the Gulf of Mexico. The Llano prospect has been drilled to a MD of 27,864 ft. The field lies in 2,700 ft of water.

Sperry-Sun, and Baroid Drilling Fluids, both divisions of Dresser Industries, handled the measurement while drilling (MWD), pressure while drilling, and fluid requirements of this high pressure well. According to Sperry-Sun, a decision to sidetrack the wells meant encountering extreme well depths and associated pressures. In order to monitor the high circulation densities, the annular pressure had to be pulsed to the surface so the true density could be known. The Sperry-Sun downhole pressure tool system was able to provide these real-time pressure measurements, so EEX had the information it needed to continue drilling and avoid fracturing the formation. The Sperry-Sun downhole pressure tool has a conventional limit of 20,000 psi. For the extreme conditions of this well, those limits had to be boosted to 22,500 psi.

Jay Martin, Sperry-Sun Program Support Engineer, said the downhole pressure tool surface software was modified to report pressures up to 25,000 psi. The downhole pressure tool was designed to handle pressures up to 22,500 psi, however other components of the MWD system were only rated to 20,000 psi. The company evaluated the 20,000 psi components and added some backup rings to raise the maximum psi rating of these parts. Sperry-Sun is currently testing the upper tolerance of this system with an eye to modifications that will take it beyond this threshold of 22,500 psi. These increasingly high pressures are a function of the industry taking exploration to record depths.

Fluid challenges

Baroid provided a synthetics-based mud introduced at 18,171 ft to decrease torque and drag and increase the ROP after the drilling operation encountered differential sticking. The ester and synthetic-based fluid was specially formulated to maintain high lubricity and hole cleaning characteristics under HP/HT conditions. During a 90 day delay, while the rig was replaced, this mud sat static at 25,342 ft in temperatures greater than 235°F but required only minimal conditioning to recirculate.

Although technically, Llano does not fit the most broad definitions of high temperature (most put the beginning threshold at 300°F), Llano is 265°F. It still presents significant fluid challenges.

Darryl Fett, Technical Service Representative for Baroid, said fluids subjected to these conditions must perform through a broad temperature range. Deepwater HP/HT wells present a unique set of challenges for the design of synthetics. These muds are pumped at surface temperatures of around 85°F, sent downhole into a formation that nears 300°F, then back through the annulus, exposed to near freezing temperatures at the mudline.

While the viscosity of water-based muds would stay more consistent through these temperature variances, synthetics are often the fluids of choice for these deepwater HP/HT fields. The base fluid for these muds is water in a synthetic oil emulsion, commonly called "invert emulsions." The rheology of this fluid is affected by broad temperature fluctuations, due primarily to the kinematic viscosity of the oil fraction in this fluid.

Synthetics are chosen because they offer superior lubricity and increased rate of penetration, and maximum inhibition of hydratable shales through osmotic dehydration. This osmotic effect is a function of the invert emulsion in the fluid. The water phase of the fluid is encapsulated within a semipermiable oil membrane.

This water phase has a salinity higher than that of the formation water. The osmotic effect resulting from this imbalance in salinity draws the water from the near wellbore formation through the oil membrane, dehydrating the formation and creating greater stability in the wellbore.

By promoting osmotic dehydration of the formation wall, this emulsion increases wellbore stability. This osmotic effect also dehydrates the drill cuttings. This causes the cuttings to consolidate preventing balling and sticking, and promoting easy removal.

As the well deepens and formation temperatures rise, adjustments to the rheology must be made to allow the fluid to maintain its design characteristics at downhole conditions while providing hole cleaning and barite suspension. Because of the large variation in temperature these fluids are subjected to, the challenge lies in finding a formulation that will allow for optimum downhole performance.

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