Lifetime Risk-Adjusted Cost Comparison for Deepwater Well Riser Systems
Authors: Goldsmith Riley , Eriksen Remi , Deegan F. Jonathan 
Published: October 2008

Abstract
A methodology was developed by a Joint Industry Project (JIP), sponsored by 12 oil companies and US Minerals Management Service (MMS), to estimate the Risk Cost (the probability of blowout during field life multiplied by the cost of a blowout) for various well riser alternatives. The methodology was demonstrated by comparing dual casing riser ("3 pipe"), single casing riser ("2 pipe") and tubing riser ("1 pipe") alternatives for SPARs and TLPs in 4000 and 6000 feet of water depth.
This paper illustrates how modern risk and reliability techniques can facilitate the decision making process. Traditionally, focus has been on obtaining estimates of Capital Expenses (CAPEX) and Operational Expenses (OPEX) without much effort to assess the magnitude of the Risk Cost. Recent studies have shown that the cost element associated with risk and unreliability represents in most cases a significant part of the overall cost picture. The methodology developed by this JIP can be used to select the well riser system with the lowest total cost (CAPEX, OPEX and Risk Cost) taking site specific conditions into account.
For instance, a single casing riser system costs less to install than a dual casing riser system and this difference in CAPEX becomes greater as water depth increases. Risk Costs are low with single casing risers in shallow water for relatively low pressured reservoirs, but increase faster than dual casing riser Risk Costs as water depth and reservoir pressures increase. The fundamental question is whether the greater CAPEX of a dual casing riser is justified for improved safety as compared with a single casing riser. Ultimately this question can be addressed using cost benefit analysis for the particular application.
As part of the methodology development individual completion components were identified and ranked according to sealing mechanisms, installation difficulty and operating conditions to estimate completion component reliabilities where statistical data were unavailable or sparse. Fault Trees were developed to calculate the lifetime system probability of an uncontrolled leak to the environment based on individual completion component reliabilities for each alternative well system and leak size. Several hundred fault tree calculations were carried out to estimate probabilities of an uncontrolled leak to the environment (limited, major and extreme) during the production mode and each step of the well intervention operations. The leak frequencies predicted by the system reliability models developed by this JIP are very close to the historical frequency of uncontrolled leaks from well systems.
Risk Costs were calculated for specific alternatives where CAPEX and OPEX were known. The methodology, results and main conclusions obtained by this JIP are presented.

Introduction
The current deep and ultra-deep water developments in the Gulf of Mexico are forcing operators and manufacturers to look for cost efficient solutions without compromising the safety to human life, property and environment. Offshore field developments are associated with various types of technical risks and uncertainties. Moving into deeper water makes it more important to control these uncertainties, and to include the risk factor in the decision making process. Risk and reliability techniques are commonly used to assist the development of novel offshore systems and to extend the application of these systems to deeper water where the industry experience is limited. This paper presents a risk and reliability methodology to quantify the Risk Costs for three alternative Dry Tree Tieback Systems. A Dry Tree Tieback System is a well system that extends the wellbore to the surface by a production riser. The Chr