The Shah Deniz development in the Caspian Sea off Azerbaijan took its place among the giant producing oil and gas fields of the world in 2006 with gas reaching its commercial market via the Baku-Tbilisi-Ceyhan pipeline from the Caspian to Turkey.
Shan Deniz is some 70 km (43 mi) southeast of Baku in the Caspian Sea.
Development at Shah Deniz was spurred by the immense reserves, estimated at 1.5-3 Bbbl of oil and 50-100 bcm of gas, but had to overcome the difficult weather, deep, high pressure reservoir, minimal pore pressure range, hole stability problems, and lack of open sea access. To put the reserves in perspective, operator BP noted that Shah Deniz is its largest discovery since Prudhoe Bay about 30 years ago. Full production could reach 37,000 b/d of condensate and 20 MMcf/d of gas. Spending for upstream and midstream development is expected to exceed $3 billion.
The partnership developing the field consists of BP as operator with 25.5%; Statoil with 25.5%; the State Oil Company of Azerbaijan Republic with 10%; Lukoil at 10%; Nico 10%; Total 10%; and TPAO 9%.
The Shah Deniz structure is in the south Caspian Sea 70 km (43 mi) southeast of Baku. Water depths range from 50 m (164 ft) in the northwest to 600 m (1,969 ft) in the southeast. The production sharing agreement covers 860 sq km (332 sq mi). Vertical relief for the structure is more than 1.5 km (1 mi), the mapped structure is 300 sq km (116 sq mi) in size, and the main reservoir is at about 5-6.5 km (3-4 mi) depth in a dip-closed anticline.
While there had been a minimum amount of unsuccessful drilling in the area, the SDX-01 exploration well in June 1999 and an appraisal well 6 km (4 mi) to its south were the start of the activity. In theses two wells, testing of the Fasila Suite and the Valakhany VIII interval suggested the size of the condensate reserves. Further drilling of deeper pre-Fasila discovered additional gas. The discovery well was a measured TD of 6,316 m (20,722 ft) with a combined net pay of 220 m (722 ft). The lowest producing horizon tested at an equipment-restricted 50 MMcf/d of gas and 2,965 b/d of condensate through a 38/64-in. choke with flowing wellhead pressure of 7,126 psi. TheDada Gorgud semisubmersible began drilling the well in 135 m (443 ft) of water, but could drill only to 2,500 m (8,202 ft) due to capacity limitations. Once that was done, a rig that was upgraded at the Kaspmornefteflot yard and renamed Istiglal returned to finish the drilling.
According to BP, the field reaches as much as 6,500 m (21,325 ft) below the seabed with downhole pressures reaching 14,000 psi. Further, there is a small pore pressure window to deal with while drilling compounded by borehole stability problems. There also are seabed and shallow-depth drilling hazards.
Caspian Geophysical conducted 22,000 km (13,670 mi) of 3D seismic from the M/VBaki in 1997 followed by detailed bathymetry. Hazards identified included unconsolidated sediments and a dozen mud volcanoes plus the potential for seabed slides.
Offshore facilities consist of a fixed, 10-well platform of the self-installing proprietary jackup design TPG 500. Technip SA was awarded the front-end engineering contract on the platform. KCA Drilling Ltd. conducted the front-end design, construction and commissioning on the drilling facilities and operations. Plans for later in the field’s life call for a second drilling center in 300 m (984 ft) of water, 5 km (3 mi) south of the first one. That second center is expected to be a subsea satellite with wells tied back to a manifold and flowlines to the fixed platform for gas/liquids separation, and subsequent subsea pipeline to shore.
J. Ray McDermott Middle East Inc. transported and installed the field pipelines, while McDermott Caspian Contractors Inc. installed the platform. Brown & Root did the upstream overall field concept while Kvaerner AS did the pipeline engineering concept.
Gene Kliewer, Technology Editor
