Slim wells, subsea heated lines, Cantarell among OTC tech highlights

Advances in slim-well construction, start-up of the first subsea heated pipeline bundle, and an update on Mexico's Cantarell megaproject were among the highlights of technical sessions at the Offshore Technology Conference in Houston last week.

Slim-well construction

Searching for ways to drill in deeper water, many offshore operators have renewed interest in slimmer well construction. Dan Turner of XL Technology, speaking on behalf of a group of operators, said, "One of the key drawbacks to slim-well technology is that you lose your diameter across the reservoir."

However, "If you start at the reservoir, and keep the desired borehole that you need across your (pay zone), you can then look at decreasing the top-hole size (in a bottom-up manner)." Thus, by decreasing the top-hole casing and riser sizes-and with the reduced materials-handling logistics that result-it is possible to decrease costs.

The slim-well test project, to begin later this year, will employ three casing systems. The first will use flush-jointed pipe. Turner said that, apart from issues regarding pipe-handling, this should provide the easiest and fastest way to implement the technology. Future phases of the project will use either amorphous butt-welded joints of pipe or seam-welded coiled tubing. Turner anticipates that the welded option offers the smallest clearances, predicting this technology will eventually provide the largest cost savings.

A typical well construction sequence is to:

Jet in and cement the 133/8-in. surface conductor string to the desired depth.
Run a 16-in. or smaller riser as a conduit back to the drilling unit.
Deepen the well with reaming-while-drilling tools.
At subsequent casing points, instead of conveying casing by landing the string in the wellhead housing, install liners at the necessary setting depth and terminate in the previous liner shoe.
As dictated by specific casing design, use tie-backs as needed to provide pressure integrity. Install the tie-backs so that they go to surface or terminate at an intermediary position in the well.
When setting the final liner across the pay zone, convey production tubing string and then land back at the surface.

Turner says the same conveyance and setting equipment is used throughout the construction process. For each liner or tieback, termination by a metal-to-metal seal is made to the previous tubing string.

Subsea heated pipeline

Third quarter 1998 saw operation of the first subsea heated pipeline bundle, on the Britannia project in U.K. North Sea.

A hot-water heated bundle concept provided the best technical solution to prevent hydrate and paraffin formation in the 15-km subsea tie-back, according to a paper by Conoco Inc.'s Lloyd D. Brown, et al.

Corrosion control was key to achieving a 25-year design life for production and safety integrity of the subsea heat exchanger.

The Britannia heated bundle system prevents hydrate and paraffin formation in the 15-km, subsea production pipeline tie-back to the Britannia platform by maintaining a minimum temperature of 21° C. in the production pipelines. The subsea piping system is in a bundle configuration in which a 37-in. carrier pipe encloses pipelines for production (14 in.), production testing (8 in.), heated water (12 in.), and methanol supply (3 in.).

The carrier wall and the 14-in. production pipeline are separated by less than 40 mm at the 6 o'clock position. The authors stated that bundle configuration provided the best technical solution for the 140-m deep subsea tie-back.

Unlike typical bundles, said the authors, 8,300 cu m of water medium heats the bundled piping as the water circulates, at a rate of 13,200 cu m/day, between the carrier annulus, the hot-water pipeline, and the platform.

Water circulation distributes heat in the subsea system and significantly increases the thermal mass of the system to improve the thermal control required for the subsea tie-back. The topsides equipment provides heating, expansion tanks, pumps, and system monitoring. For safety monitoring of possible methane in the heating medium, the topsides expansion tanks are blanketed with nitrogen having at most 1% oxygen.

Cantarell

OTC highlighted a number of significantly different methods for developing offshore hydrocarbon resources. Most aimed at developing new discoveries, but some, such as Pemex Exploraci?n y Producci?n's ambitious Cantarell project, are aimed at revitalizing an aging field.

The prolific Cantarell oil-producing area has been producing since 1979 in the Bay of Campeche, 50 miles off Mexico in about 100 ft of water. In April 1981, Cantarell reached a 1.16 million b/d peak from 40 wells, and Pemex sustained output at about 1 million b/d until early 1996 by drilling 139 development wells, starting artificial lift by gas lift, and reducing back-pressure restrictions on the wells.

But, as described by Tom s Lim?n Hern ndez, Pemex E&P manager of scheduling and evaluations, by 1996, Cantarell reservoir pressure had declined to 1,607 psi from an initial 3,840 psi. The pressure drop had decreased well productivity to an average 6,400 b/d/well vs. a 30,000 b/d/well peak. Also, with pressure below bubblepoint, a secondary gas cap was being created, and water was encroaching into the thick fractured carbonate reservoir, threatening to decrease ultimate recovery.

That is when Pemex decided to implement a revitalization project at Cantarell that is expected to cost $5 billion for additional production facilities, pipelines, and drilling. Another $1 billion is the estimated capital cost for a 1.2 bcfd nitrogen extraction plant, onshore at Atasa, that will supply nitrogen for injecting into Cantarell reservoirs in order to maintain reservoir pressures (OGJ, Sept. 7, 1998, p. 30). Pemex estimates nitrogen injection will increase oil recovery by 2 billion bbl.

The project's first phase, including drilling 69 wells and debottlenecking existing facilities, has already increased oil production to about 1.4 million b/d. Associated gas production is 760 MMscfd. Further work will increase production capacity to 2.4 million b/d by 2001, but actual producing rates will be determined by government policy, according to Lim?n. Pemex expects that substantially all of the work will be completed by 2001, although some drilling and other work will continue to 2005.

One completed aspect is the installation of the region's first floating storage and offloading (FSO) vessel. The converted 350,000 dwt tanker Ta'Kuntah was installed in August 1998. This tanker will add flexibility to the field's export capacity, which now uses either the Cayo Arcas Island or Dos Bocas export facilities. During its first 51/2 months, the FSO has already prevented the shut-in of 12.5 million bbl of oil production, according to Sid Sircar of Bechtel International Inc., the prime contractor for the project. Sircar noted that a second FSO is still a possibility, if economics allow it.

Pemex expects Module 1 of the nitrogen plant to begin deliveries in April 2000, with the fourth module ready by September 2000. Each module has the capacity to deliver 300 MMscfd of nitrogen, compressed at 1,500 psig.

Pemex has awarded 31 engineering, procurement, and construction (EPC) contracts, three have been completed. Three additional EPC contracts are being developed, and two are in the bidding process. The contracts include installation of 25 new platforms and 69 new pipelines covering a total length of 260 miles-including two 36-in., 55-mile nitrogen injection lines and a 30-in., 20-mile export line to the FSO.

To lay the new lines, Pemex has had to bury deeper many of its existing 80 Cantarell pipelines. Alan Speirs, Bechtel International Inc., described the process as working in a "bowl of spaghetti," because the project requires over 200 pipeline crossings.