What's new in production

	Vol. 224 No. 9
ROBERT E. SNYDER, EXECUTIVE ENGINEERING EDITOR

New Tools/technology. Three recent releases from developing companies unveil interesting new technologies worth noting. These include: 1) a new process for upgrading heavy oil; 2) a downhole stimulation tool; and 3) subsea compression to boost offshore oil and gas production.

 For the first innovation, a contract was signed between Ivanhoe Energy and Ensyn Petroleum International, a Boston-based private company, to test the latter’s Rapid Thermal Processing (RPT) technology designed to upgrade heavy oil quality by producing high yields of lighter, more valuable crude. Under this proprietary process, the heaviest material from the oil stream is consumed, providing an energy source to generate steam used in the enhanced production of heavy oils. This lowers operating expenses by reducing need to purchase natural gas for steam generation. And the resulting higher quality crude can be sold at higher prices and flow more easily through pipelines. 

Under terms of the contract, Ivanhoe will have the rights to test its heavy crude in a 250-bpd demonstration plant in California’s San Joaquin Valley. The contract also gives Ivanhoe exclusive rights to apply this technology in two foreign countries with proven heavy oil fields. Ensyn’s plant is under construction, and the test, utilizing oil produced by Ivanhoe in South Midway field, should be completed before year-end. Ensyn has a pilot facility in Canada and has completed over 90 test runs on heavy oil. 

For the second development, oilfield services provider Expro International Group PLC recently provided expertise in stimulation services on a successful job for Unocal in the Gulf of Mexico, where Expro’s StimTube process was utilized to stimulate a gas well with zero production.

StimTube is an oxidizer-based tool for reservoir stimulation which, when detonated, can generate large volumes of high-pressure gas – as much as 20,000 psi at the reservoir face. These high-pressure pulses are effective in perforation breakdown, fracture initiation and elimination of near-wellbore damage. It can be run through tubing or on slickline to stimulate existing perforations and eliminate need for additional stimulation. 

Unocal’s well, in Brazos Block A105, had been initially completed with 300 ft of open perforation in the low-permeability Big Hum “D” formation. Rates and pressures had decreased over time and large-diameter tubing hindered natural lifting capabilities, until the well was unable to produce against 500-psi system pressure. A decision was made to isolate the bottom 138 ft of perforations due to water and sand production and leave 162 ft of perforations open to flow. But when production was brought online, it dropped to below line pressure. 

Expro ran a gamma ray/casing collar locator/pressure and temperature survey, and the decision was made to run three 15-ft StimTube assemblies and treat 75 ft of total interval. Upon firing the three tubes, a total increase of 120 psi was observed, and the well was brought online at a stable rate of 4 MMscfd. 

Regarding the third new technology, GE Oil & Gas and Aker Kvaerner-Kvaerner Oilfield Products (KOP) have signed an agreement for continued development/commercialization of subsea compression technology designed to reduce costs of deepwater oil/gas field exploitation. An initial joint development agreement focused on qualification of the subsea compressor technology through testing of a prototype, 850 kW module and subsequent design/development of larger, 2.5 and 5-MW units (See World Oil, Nov. 2002). A subsea module featuring GE’s 2.5 MW, Blue-C Subsea Centrifugal Compressor, was introduced in 2002 at the Offshore Northern Seas Conference. The recent agreement replaces the JDA and covers ongoing development, focusing on deepwater gas fields located at long distances from shore or from a central offshore platform. 

GE and KOP are working on a pilot project to develop a 12.5-MW compression unit. The first modules are expected to be ready for commercial service by 2008. The joint effort began as part of a program launched by the Norwegian government to support development of subsea systems to economically recover gas and oil from deepwater fields. Until now, it has not been profitable to exploit many subsea gas fields, particularly at depths of 500 m or more, largely due to the cost of conventional offshore platforms.

The new subsea compressor module is a self-contained, turnkey system that can be installed on the seabed. It can transport the well stream to a central platform, or directly to an onshore site, which would eliminate need for the platform. The 12.5 MW module will undergo tests under actual operating conditions on a subsea gas field after being tested and qualified onshore and on the seabed. Feasibility studies have been performed with several oil companies for potential locations in the North Sea and the Norwegian Sea. 

Tail production off Norway. Statoil is investigating ways to increase declining production from several large fields it has interests in, within the Tampen area, the farthest NW of three major field areas in the Northern North Sea, the other two being Troll/Oseberg and Frigg/Heimdal. Principal fields in Tampen include Statfjord, Gullfaks, Snorre, Visund, Tordis and Vigdis. 

Statoil says the tail phase of a field is characterized by falling oil/gas output and rising watercuts. The company’s goal is to “operate the fields efficiently until their wells have to be P&A’d for good.” Overall, the aim is to extend oil/gas output by a decade. While Tampen reservoirs contain up to 4 Bbbl excluded from present production plans, time and new technology are needed as the cost/bbl will continually increase. 

A major challenge is “unitizing,” in effect, the area, as field characteristics differ, e.g., low-pressure production may be best for Statfjord, while pressure maintenance via gas and water injection may be appropriate for Gullfaks and Snorre. Transition from field-based to area-based development will also call for “joint commitment by all license partners across field boundaries.” Twelve companies, each with its own agenda, are involved in Tampen’s eight production licenses. 

Tampen 2020, as the present project is called, has two goals – identifying an optimum operating model for the whole area, specifying when each field and platform must shut in; and how today’s inter-platform processing links can be reshaped as installations are shut down. Statfjord late life is the first major project launched. That project alone foresees additional production of 40 Bm³ gas and 125 MMbbl oil.