Break the burro and see a spray of new ideas, most spurred by the quest for the 'smart' well.

In this Christmas month, the petroleum industry abounds with emerging oil and gas production technologies, with its "piñata" chock full. It might be safe to say that more new ideas than ever before have sprung from recent "smart" well technology development.
Laser drilling
In 1997, the Gas Technology Institute (GTI) began to investigate adapting high-powered military lasers for drilling and completion. Different rock types were exposed to laser action, revealing that laser technology is more than sufficient to break, melt or vaporize any subsurface lithology. Tests also determined that significantly lower laser power was needed to do so than was thought previously.
One laser process in particular has the potential to substantially reduce the time and materials required for conventional well construction. While penetrating rock, a laser can create a stable, impermeable ceramic sheath around the borehole wall, potentially eliminating the need for steel casing.
Tests reveal that the melting needed to produce this sheath can be controlled with laser properties, including discharge type (continuous or pulsed), wave length, peak power, average power, intensity, repetition rate and pulse width.
A high-power laser can spall, melt or vaporize rock by raising the local temperature. Mineral melt begins when the rock's rate of heat dissipation is exceeded by the rate of energy it absorbs. As time increases, accumulated heat raises the minerals' local temperatures enough to produce a glassy melt. The degree of melt is a function of temperature distribution, rock mineralogy and the intergranular space in the rock matrix. The more closely packed the grains are, the more the heat is distributed among them, resulting in more melt.
In experiments, the most melting occurred in rocks with large percentages of quartz, the major mineral component in sandstones. Figure 1 shows a lased sandstone core. The top portion of the sample's original rock matrix was removed to expose the glassy inner sheath lining the borehole. Although its strength characteristics have not been sufficiently measured, the integrity of the sheath obviously is greater than the rock from which it was manufactured. For other lithologies with lower percentages of quartz minerals, it's proposed that silica or other sheath manufacturing minerals could be suspended in a circulating fluid. As the hole is bored, separate fiber-optic lasers could be used to layer those suspended minerals onto the rock face to the thickness and strength desired.
Once the well is constructed and lined, another laser could be used to perforate the ceramic sheath to expose the producing reservoir.
Brian C. Gahan, brian.gahan@gastech nology.org, principal project manager for the laser drilling program at GTI, supplied this information. For more information, call 1-847-768-0931.
'Cavity-like' completions
The Global Petroleum Research Institute (GPRI), a cooperative of nine oil companies and several adjunct members, has joined Advantek International Corp. in a project to determine when, where and how to implement an advanced well completion technique based on deliberately producing sand to induce "cavities" in the wellbore to increase productivity.
The project is still under way, even though some field trials have been conducted.
Table 1 shows the relative improvement that could be afforded by this new technology.
The concept of the cavity completion is straightforward. When sand is deliberately produced, which can vary from 5 b/d to 5,000 b/d, production can be improved as long as the cavity is stabilized. This results in a greater flow rate and an increase in the well's productivity index (PI), or injectivity index. However, the risk of catastrophic sand production or casing buckling also is increased, so the technique must be applied judiciously, and casing hardware design must be maximized.
By deliberately producing sand, the operator is increasing the effective wellbore radius, regardless of cavity size or shape, as well as reducing near-wellbore skin.
Cavities generally have been found ultimately to stabilize. Thus flow velocity is reduced because the effective wellbore radius has increased, as have drag forces that act to remove the sand particles.
Removing even a small amount of sand can result in a more negative skin factor than expected, and can be explained as due to a sheet-like or planar zone of enhanced permeability, somewhat like a fracture. In other words, a spherical zone cannot give a low enough skin factor. Figure 2 is one conceptual model of this. A cavity beneath a cap rock (relatively rigid overburden) may consist of interface flow channels much like the spokes of a wheel (the wheel may be elongated due to stress or permeability anisotropy). Alternatively, a cavity may form elsewhere in the pay - under a strong shale stringer, for example.
The goal of this study is to identify where, when and how a cavity-like completion can be used to obtain maximum productivity increase without sacrificing casing stability, causing significant subsidence or leading to unmanageable sand production.
Cavity-like completions can embrace any geometry that results from sand removal - from voids at one extreme to enhanced permeability zones of disaggregated sand at the other.
The joint venture is creating a model to optimize a cavity completion by evaluating the PI, cavity stability and sand disposal costs. An analytical theory for failure of a cap rock above a cavity, based on the strength of a "dome," has been developed. A preliminary effort also has been made to unify the various cavity-like completions by seeking a relationship between skin factor and produced sand volume. This research covers a huge spectrum, from large-block lab tests to cold production of heavy oil in Canada. The project has the potential to serve as a predictor for field cavity completions. The results are relevant to other business areas, as well - for example, sand management, increases in injectivity for injection wells and underbalanced drilling, perforating and surging applications.
A field trial was conducted at the Thums Long Beach field in Wilmington, Calif., in 2000 to determine if recompleting wells with the technology would boost production from depleted zones. Results are being evaluated.
GPRI members and adjunct members who have funded the 2001 program include BP, Phillips, Texaco, TotalFinaElf and Schlumberger. GPRI is a cooperative of major oil companies that created a platform for development of joint ventures.
Ian D. Palmer, palmerid@bp.com, and Hans H. Vaziri, vazirih@bp.com, of BP in Houston, Texas; John D. McLennan, jdmclennan@advantekinternational.com, of Advantek International Corp., Houston; and David Burnett, burnett@gpri.org, of Global Petroleum Research Institute, College Station, Texas, supplied this information.
Subsea multiphase pump module
With the Norwegian government's Demo 2000 research and development program and at least one producing company (Norsk Hydro), Kværner Eureka and Kværner Oilfield Products have designed and manufactured a compact subsea multiphase pump module for handling dry and wet production in up to 6,500 ft (2,000 m) of water.
Under the research program, the Norwegian government granted Kværner Eureka funds for maximizing, testing, verifying and documenting the subsea wet gas compressor and multiphase pump module. It is believed to be one of only two twin-screw, volumetric pumps under development for subsea applications. The company said that compared to helico-axial pump systems also being developed for subsea use, the Kværner twin-screw pump has a rugged, uncomplicated design.
The multiphase pump project is among several being undertaken by Kværner under Demo 2000, said Ove F. Jahnsen, Kværner senior technical adviser. The others involve miniaturizing or maximizing larger production components used by the offshore petroleum industry, he said.
The Demo 2000 multiphase pump module will weigh about 45 tons. And though its design life is 20 years - with estimated maintenance intervals from 2 to 5 years - it will have a "plug-and-play" capability that would allow a floating vessel to switch out entire pump modules with a minimum of downtime and cost, Jahnsen said.
The subsea multiphase design data are based on specifications dictated by Norsk Hydro's Sogn development area in the North Sea (though the pump is designed for much deeper water). This area includes the Fram and Gjøa fields and their satellites, among others. Gas production from this general area contains high concentrations of propane and butane. The multiphase pump's ability to act as a pump and compressor would allow stripping out of these gas products for transport to shore, which given enough volume from Sogn area reservoirs, could give Norway a petro-chemicals manufacturing capability.
The subsea multiphase pump is based on a twin-screw, positive displacement pump, which can transport liquids and gases. The pressure boost is independent of gas void fraction, said Jahnsen, so the pump would be ideal as a wet gas compressor capable of handling gas slugs. In addition to the 6,500-ft (1,983-m) water depth capability, the pump must be able to operate with 2,900-psi differential pressure across the housing, which translates to 5,800-psi internal pressure at the full design water depth.
In this project, Kværner Eureka is working with Germany's Bornemann Pumps, which will supply the twin-screw pump, an off-the-shelf product modified to work inside the compact, subsea module (Figure 3).
In Norway, a prototype subsea multiphase pump is being tested at the Kværner Eureka production facility near Oslo, said Jahnsen. The test medium for initial pump testing is water.
Officials with Kværner Oilfield Products said the completed pump module would be offered for use in similar field setups in the Gulf of Mexico and off West Africa.

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