Several R&D organizations have cutting-edge technology that will be commercialized quite soon.

Between a glimmer of an idea and a technology we take for granted is what we've dubbed "imminent technology," technology that's been in the research pipeline for a few years, has undergone its field testing and prototype growing pains and is just about ready for commercialization. Here some of the world's top oil and gas research groups discuss their offerings.

US Department of Energy

Flexible nonsteel drillpipe may help industry make strides

A lightweight nonsteel drillpipe, developed with support from the US Dept. of Energy's (DOE) National Energy Technology Laboratory, has the potential to significantly help the United States meet increasing demands for natural gas.

The flexible composite drillpipe was successfully tested in recent months.
The pipe was developed under a US $2.82 million, 5-year DOE contract by Advanced Composite Products and Technology (ACPT) of Huntington Beach, Calif.

The pipe, with an outside diameter of 2-1/2 inches with 33/8 -in. tool joints, has the potential to untap gas reserves that have been difficult to produce, said Gary Covatch, spokesman for NETL in Morgantown, W.Va. It could revolutionize the industry.

"This is more flexible than steel drillpipe, and you can achieve greater use with the same pipe," Covatch, the project manager, said. "Its flexibility allows you to economically re-enter old wells and drill horizontally to extend the life of the well. This will give us the ability to recover more gas while keeping the recovery costs low."

The flexible pipe is manufactured by winding graphite fibers and epoxy resin around a mandrel. The composite tube is cured and the supporting mandrel is removed. The pipe is machined and then coated to resist abrasion.

The pipe has undergone three field tests in which it was used to drill short-radius horizontal wells. This pipe resolves problems encountered when using steel drillpipe for the same type of wells. The composite pipe has the flexibility and strength to overcome the stress and fatigue caused by the pipe being bent for extended periods of time.

The first two tests were conducted by Grand Resources Inc. in Tulsa, Okla., in the Bird Creek field in Tulsa County. The pipe was used to drill short, 70 ft (21 m) radius build portions for horizontal laterals in existing wells that were drilled in the early 1920s. The laterals in both wells were to be drilled at a depth of 1,290 ft (393 m). The first well did not have any problems with the pipe, but the second well encountered difficulties.

In the second well, the tool joint connection separated from the composite material. As a result, ACPT redesigned the tool joint connection, which appeared to be much stronger. The tool joint failure did not stop the well, however. The broken joint was replaced with a new joint, and drilling continued with no additional problems.

The third field test was conducted in Le Flore County, in eastern Oklahoma, in a well at a depth of 1,385 ft (422 m) by JB Drilling Inc.

This test was different in two ways. This was a new well, and instead of using rotary drilling tools, an air hammer was used. The air hammer severely challenged the pipe's ability to deal with stress, its fatigue life and its mechanical strength. The protective coating on the pipe was also put to test as the formations drilled through were hard and extremely abrasive. After a week of drilling, the pipe was extracted and examined. It showed little or no signs of wear.

The composite pipe could bring new life to thousands of idle wells drilled in the early 20th century. In many fields, reserves in formations that were once considered uneconomical now may be developed economically.

Although the composite drillpipe is more expensive than conventional steel pipe, a significant decrease in drilling costs is expected because of fewer pipe failures, the need for less pipe because of shortened radius and the ability to drill more wells with a single pipe string.

Future work will include embedding of a wire in a larger 5-1/2-in. composite drillpipe, with a 7-in. tool joint, which is targeted for use in extremely deep and offshore wells. The wire will allow the transmission of information and data from the bottom of the hole to the surface while drilling is ongoing. The communications capability will help to reduce the risks in drilling deep wells, which will help keep gas prices economical.

For more information, visit www.netl.doe.gov.

Institut Français du Pétrole (IFP)

A fast and direct approach for reservoir petrophysical characterization from drill cuttings
For the first time, it is possible to obtain a true permeability log just a few days after drilling a well using an original technique, called DARCYLOG, developed by IFP (Institut Français du Pétrole). This technique is based on a measurement of permeability on cuttings collected during drilling operations. Contrary to other existing methods, the permeability is not derived from a correlation but is determined directly by measuring the pressure and the flow rate during a displacement. When cores are not available, this method is the only way to obtain reliable values of permeabilities at regular spacing that can be used directly for reservoir characterization and also to calibrate other logs. The porosity also is measured on the same samples using the routine gas expansion method in order to determine K/phi correlations.
In most of wells, cuttings are representative of the reservoir. The porosity and permeability measured on cuttings are representative of the matrix property since one single cutting contains thousands of pores (Figures 2 shows the detail of one cutting after cleaning). Considering the small size of the cuttings, it can be assumed that the cuttings travel with the mud, which means that the lag time correction applies and that the mixing between cuttings of several depths is negligible.

The proposed method does not require heavy conditioning (coating, image analysis) and is applicable on the classical range of reservoir permeabilities (up to around 100 mDarcy). Practically, the measurement is realized by establishing a flow of a liquid within the rock fragments by compression of the residual gas initially trapped inside the cuttings. The originality of the method is to combine a viscous liquid for measurable pressure drop with trapped gas for compressibility. The viscosity of the liquid can be adjusted to the range of permeability to measure. The compression of the trapped gas is obtained by a pressure test of the cuttings by the surrounding liquid. The rate of invasion depends on the fluid viscosity and the rock permeability. The permeability is calculated by using a numerical model based on the equations describing the flow of a viscous fluid into a compressible medium of spherical geometry. The method has been first validated on crushed core cuttings of known properties and then used on real drill-cuttings for reservoir characterization purposes.

As only 1 cubic centimeter of dry rock is needed to perform the porosity and permeability measurements, the preparation of the cuttings is very fast, whatever the mud type, and this approach can also be applied to revisit existing cuttings collections. The porosity log obtained from cuttings is first compared to the one obtained from the wireline tools to evaluate the degree of representativity of the cuttings and adjust the lag time correction. Then the permeability measurements can be used to establish a porosity/permeability correlation to calibrate other logs or to optimize the well completion.

For more information, visit www.ifp.fr.

Demo 2000

Eliminating the platform by means of seafloor processing and boosting

Increasing challenges - deeper water, higher recovery, environmental concerns-require new products and systems that must be "field proven" before any asset manager is willing to take them onboard. Hence field trials are essential in connecting research and development (R&D) to market entry. Demo 2000 aims at accelerating the deployment of new technology by supporting pilot testing under realistic conditions.
Founded in 1999 by the Norwegian Ministry of Oil and Energy, Demo 2000 has had strong support from operators, the service industry and research institutes. Seafloor processing and boosting has had a prime focus in the program. Subsea systems tied back to processing platforms or floaters, or directly to shore, enable operators to access reserves in deeper water. Two current major gas field developments offshore Norway with a sum of recoverable reserves of approximately 20 Tcf involve clusters of subsea wells in more than 3,000 ft (1,000 m) water depth, tied back to onshore plants over a distance of more than 60 miles (100 km), connected to the grid by long trunklines or LNG chains. In Demo 2000, the industry collaborates in the piloting of subsea gas compressors, seabed separation and reinjection systems, electrical power distribution, flow assurance, etc. Seafloor multi-phase pumping, compression and oil/gas separation are examples of components that extend tail-end production and enable marginal fields to access spare capacity at host platforms.

ENI UK recently announced its plans to host a major pilot program to test the Aker Kværner MultiBooster multi-phase pump for tail-end production at the Balmoral field. Next in line could be the seabed gas compressor systems developed by Framo Engineering and by Aker Kværner, targeted for Ormen Lange. The SEPDIS by ABB Offshore Systems has proven to serve as a key component in providing electrical power transmission and distribution for such high-power consumers. Demo 2000 also fosters a multitude of subsea processing equipment, e.g. FMC's system for sand separation management. OLGA and PETRA for multi-phase wellstream modelling are absolutely fundamental tools without which none of these development scenarios would have been viable.

Five key areas within E&P offshore upstream technology have been targeted in Demo 2000: subsurface, wells, remote processing, deep water and gas utilization. Integrating technology across discipline borders has already demonstrated large potential for increased value, for instance in the subsurface area, where process control and data acquisition are merged with reservoir management and well completion technology to meet the operators' visions for "e-fields" or "reservoirs of the future." Such technologies will play an ever-increasing role in maximizing ultimate recovery of fields already in production as well as new developments.

For more information, visit www.demo2000.no.

Gas Technology Institute (GTI)

GTI's Laser Research Program moves forward

Since 1997 the Gas Technology Institute (GTI) has been evaluating the use of high-powered lasers for faster and more cost-effective construction and completion of gas wells. Laser applications have the potential to "leapfrog" the rotary drilling and explosives-based wellbore perforation practices used for the past century.

Initial fundamental research funded by GTI, completed in 1999, established that state-of-the-art lasers had enough power to cut rock 10 to 100 times faster than rotary drills.

A second phase of research in 2000 and 2001, with an expanded research team, explored more detailed issues such as laser cutting-energy assessment, rock removal capabilities of pulsed vs. continuous-wave lasers, and the effects of lasing rock in the presence of water. Funding was provided by GTI, DOE, PDVSA-Intevep S.A. and Halliburton Energy Services.

In July 2003, DOE released funding for the next stage of research that will establish the technical feasibility of using laser tools to drill natural gas wells and conduct engineering studies leading to prototype tool development.

DOE has earmarked about US $2.1 million in total funding for the program, of which approximately $875,000 has been obligated. This funding is being supplemented by about $1 million in GTI cofunding.
As one aspect of its commitment to continued research in this arena, GTI has purchased installed a state-of-the-art laser system specifically designed to support research on petrophysics and related laser applications.

GTI also has established an exclusive working relationship with IPG Photonics Inc. of Oxford, Mass., applying that company's high-power, fiber-optic laser technology to well construction and completion tasks. A key feature of the IPG system is the use of fiber-optic cable to "deliver" the beam from the laser itself to the point where the laser energy is needed. In a gas-well application, this means that the laser source can remain on the surface, eliminating the cost and risk of placing it deep in the wellbore, while targeting energy downhole to fracture, melt, or vaporize rock.

In a parallel effort, GTI began a project in July 2003 with a major E&P industry partner to achieve proof of concept for a downhole, fiber-optic laser system for efficient and effective perforation of well casing.
For more information, visit www.gastechnology.org.