Typhoon Project: Flow Assurance Issues- How They Were Identified And Resolved
Authors: Pausche P. , Creek Jefferson Louis , Stair Mark A. 
Published: October 2008

The flow assurance issues addressed by the Typhoon production system hardware configuration and operating strategies include potential hydrate formation, paraffin deposition, and asphaltene deposition. The operating environment for the 4 Typhoon subsea wells includes well offsets ranging from 3,000 feet to 10,400 feet, oil production with initial shut-in wellhead pressures ranging from 7,100 to 8,100 psi, a subsea bottom temperature of 43 degrees Fahrenheit, and a produced brine that is expected to be incompatible with methanol. Additionally, the subsea configuration provides multiple well locations with each well having a single flowline.

This paper describes the methodologies used to identify and evaluate the severity of the flow assurance issues and hardware configurations and operating strategies provided to mitigate the issues. The operating situations considered whenevaluating the issues included normal steady-state production operations, planned and unplanned shut-ins operations, and production restart operations. This paper additionally describes how the flow assurance issues are addressed forthese operations and the initial start-up operations.

Overview

The Typhoon Field is located in Green Canyon Block 236 and 237 in some 2,100 feet of water approximately 170 miles south-southwest of New Orleans, LA. The field has been developed using a TLP located to the western side of Block 2371, reference Figures 1 and 2. Four subsea wells, three located in Block 237 to the east of the TLP and one well located in Block 236 to the west of the TLP, are tied back to the TLP, each through a single flexible flowline2. Oil is exported through a 10" SCR × 12" pipeline to Green Canyon Block 19 and gas through an 18" SCR × 20" pipeline to Eugene Island Block 371. The production system is design for the 4 wells to produce oil having stock tank API gravity in the order of 32° and an average GOR of 1500 scf/STBO with total system design rates of 40,000 bopd, 60 mmscf/d, and 15,000 bwpd. Well SITP was anticipated to be as high as 8,100 psi and the flowlines were designed with 9,000 MAOP.

The wells were completed using horizontal trees3. The trees are controlled from the TLP via a direct hydraulic control system that is operated from a control room operator interface. The wells are equipped with DHPT sensors and the trees with annulus pressure, wellhead pressure, wellhead temperature, and flowline pressure sensors. All pressure and temperature data are displayed at the control room operator interface and logged for future reference. The subsea trees are equipped with chokes. The topsides chemical injection unit, umbilical, tree, and well systems provide for separate asphaltene inhibitor injection into the tubing above the completion packer, paraffin inhibitor injection into the tree upstream of the subsea choke, and methanol injection also upstream of the choke. However, as is discussed in a following section, methanol injection is not required for normal production, shutin, or production re-start operations.