CRA pipe, cladded wellheads help move multiphase flow with very high
H2S and CO2 components
H2S and CO2 components
Petrobras, Brazil's national oil company, is planning to put on production a new offshore oil and gas field discovered in Santos Basin. Located off the coastline of Santa Catarina, the Santos Basin is comprised of five reservoirs: Tubarao B1, Tubarao B2, Coral, Estrela do Mar, and Caravela.
Production from six oil wells and two gas wells will be routed to one floating production system, a semisubmersible platform, which will be moored on Tubarao or Estrela do Mar Field in 485 ft of water. Production is expected to start during the third quarter of 1996. The processing plant of this platform will handle 20,000 b/d of oil production.
In fact, Petrobras has been using one oil well of the Caravela Field as a proving ground or test lab. A second oil well will be hooked up to the flexible flowline which will transport production to a semisubmersible platform, positioned in 640 ft of water, in December of this year. The processing plant on the Caravela Field platform will handle 2,000 b/d of oil production.
Studies indicate that drastic reduction in investment can be achieved if unprocessed multiphase wellstreams are transported from satellite wells on neighboring fields to a central processing platform.
The challenge facing Petrobras is to avoid serious material loss caused by corrosion in carbon steel oil and gas lines, tubing, and wellhead equipment.
The two completed gas wells, in Tubarao B2 Field, have extremely harsh operating conditions with high temperatures and pressures, and high concentrations of hydrogen sulfide (H2S) and carbon dioxide (CO2). The reservoir's original pressure was 8,400 psig at 15,400 ft subsea. Bottom hole temperature (BHT) is 290°F. The CO2 and H2S content of the gas is approximately 0.8 mol % and 1.0 mol % respectively.
The oil wells also have harsh operating conditions with high temperatures and pressure, and high concentrations of CO2 and brine. Bottom hole temperature is 300°F and the reservoir's original pressure is 8,300 psig at 15,740 ft subsea. The CO2 content of the gas is 1.4 mol % and the salinity of produced brine is 150,000 ppm chlorine.
Such environments require special materials for downhole and surface equipment. Completion of sour, hot-gas producers is challenging because of the need for appropriate steel to withstand high pressure and temperature conditions.
Based on the de Waard et al model (Sheel), CORMED model (Elf Aquitaine), Strategy model (CLI) and laboratory test results, it was decided to select corrosion-resistant alloys (CRA) tubing material and cladded wet christmas trees. All pipelines were designed to transport unprocessed well fluid from subsea installations to an offshore production platform, using a carbon-manganese steel and a sour service carbon steel, both with continuous corrosion inhibitor injection for oil and gas respectively. Selection of CRA would solve the technical problem but added considerably to the cost.
In these subsea projects under development, the pipelines costs are a considerable part of the investment. Using pipelines made of carbon steel instead of CRA can result in several hundreds of dollars in investment savings.
The severe corrosive environment predicted in Santos Basin will require an extensive and complex laboratory corrosion inhibitor screening program to determine the most efficient and cost-effective corrosion inhibitor program (autoclave, jet impingement, pipe flow loop, and RCE/RDE tests). Traditional bench top tests and even static autoclave tests at simulated operating conditions are not sufficient to produce representative data of near actual conditions to provide a selection criterion for inhibitors. For subsea pipelines, inhibitor selection should be based on simulated operating conditions including fluid velocity and flow regimes.
Corrosion monitoring of offshore pipelines containing CO2 and high H2S concentrations is one of the more challenging problems facing the industry. The more limited the corrosion monitoring information, the more difficult corrosion control becomes. Typically, corrosion control and monitoring for offshore pipelines consists of injecting corrosion inhibitors, collecting iron count data, and monitoring corrosion coupons placed at the end of the pipeline. These monitoring programs have been unable to provide information on the variables in corrosion behavior throughout the pipeline. Successful subsea pipelines operation relies on effective corrosion control and corrosion monitoring.
One of Petrobras's goals is to improve the monitoring by using a modeling of the multiphase fluid behavior to determine the effectiveness of corrosion inhibitor distribution. In addition, Petrobras has been studying in its Cenpes research center, electrochemical techniques to be used in the inhibitor laboratory studies and as a monitoring tool in the field.
These techniques, such as electrochemical impedance and noise, can be used to predict if inhibitor film formation is kinetically feasible, if the film can be removed mechanically, and if new film form s when a protective film has been destroyed locally. Electrochemical monitoring of corrosion is essential to the understanding of corrosion variation with time and performance of inhibitors. However, in sour gas/condensate pipelines these electrochemical techniques might not be viable and therefore an alternative on-line monitoring system will be studied using a permeation cell to assess the inhibitor efficiency, besides E/R and weight loss measurements.
Pedro Altoe Ferreira is a research scientist in the Production Research Division of Petrobras's Cenpes Center. From 1988 to 1993, he worked within the gas production division in Campos Basin.
Copyright 1995 Offshore. All Rights Reserved.