Many cost components must be considered to determine the most cost effective deepwater production system for a particular site. Too often, only the well systems CAPEX 1 is adequately included in field development alternative studies. OPEX, RAMEX and RISKEX depend largely on reservoir characteristics, specific well system designs and operating procedures. The effect of these factors nearly always outweigh differences in well system CAPEX. Optimization of total lifecycle cost of deepwater production systems must include all of these factors.The risks associated with blowouts are often an important factor in choosing one dry tree tieback well system over another. Another important factor often overlooked is the cost of well system component failures. As oil exploration and production moves into deeper and deeper water, the costs to repair well system component failures escalate dramatically. This paper presents the methodology developed by a Joint Industry Project to quantify capital, operational, blowout risk and reliability costs associated with deepwater well systems. Five well systems have been modeled to demonstrate the methodology: a dual casing dry tree system, a single casing dry tree system, a tubing riser dry tree system, a conventional tree subsea system and a horizontal tree subsea system. Case examples demonstrate the model for these five well systems.The methodology, results and main conclusions from this Joint Industry Project are presented.
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.
This paper will describe the risk assessment exercise carried out for pull-in and tie-in of the pipelines at the Troll GBS (Gravity Base Structure). The Troll Platform GBS will be installed and then the pipelines for the export of gas have to be pulled into the bottom of the riser shaft. Once the pipelines have been pulled in and sealed they have to be tied into the already pre-installed risers in the GBS. This pull-in and tie-in operation presents many hazards associated with working in a congested space at the bottom of a 300m riser shaft. The study will describe the HAZID methodology used, the method used to rank the risk and then the method of assessing risk reduction measure on grounds of effectiveness and ease of implementation, to reduce risk to As Low As Reasonable Practicable. Background The Troll field is located 80 km west Northwest of Bergen and extends over the North Sea Norwegian licence blocks 31/2, 31/3, 31/5 and 31/6. A/S Norske Shell intends to install two 36 inch pipelines (P10 and P11) for the transportation of untreated gas from an offshore production platform to an onshore processing plant at Kollsnes Oygarden. These pipelines will be laid from a conventional laybarge and will be pulled into the platform by means of a winch installed on the topsides. The pipelines will penetrate the bottom of the riser shaft and will finally be connected to pre-installed risers in dry atmospheric conditions. To enable this, seal tubes have been installed in the GBS during the construction phase. After pull-in temporary barriers will be activated to allow pipeline to riser connection. Finally permanent barriers are installed for long term protection. Of major importance is the use of temporary and permanent water barriers to protect personnel working in the riser shaft from flooding and the total integrity of the platform. A/S Norske Shell have concluded that due to the nature of the operation of pulling-in and tie-in of the pipelines at the platform, there are present various hazards. These hazards can be classified into two distinct areas namely hazards to personnel and potential schedule delays. Hazards to personnel safety present the potential to result in injury or fatalities, whilst schedule delays could result in the late completion of the project with a corresponding financial cost. Therefore A/S Norske Shell have commissioned DNV Technica to evaluate the hazards and risks associated with the pipeline pull-in and sealtube operations, and assess any possible risk reduction measures with the following objectives:To identify the problems and hazards which could occur with the pipeline pull-in and tie-in.To assess the risks to both the workforce of potenial safety hazards and the schedule delay from hazards which could cause a delay.Identify risk reduction measures which would reduce the potential problem areas.Provide guidance on which risk reduction measures would bring the greatest benefit. Methodology The application of this type of pull-in was unproven in this depth of water and with a GBS. As a result the design of the pull-in equipment had been subjected to a very detailed design review and analysis. The control of the operation is very dependent upon the procedures that are were written to enable to operation to be undertaken. The use of procedures for new or novel operations is that the procedures form the basis of a system of controls which enables the pipelines to be pulled into the GBS. Due to the novel nature of the operation and to ensure the safety and efficient implementation of such procedures a review to identify hazards and operability problems prior to construction was to be part of the review process.
Such classic riskassessment techniques as failure mode and effect analysis (FM EA) and fault-tree analysis (FT A) are in common use by engineers but have a number of shortcomings. Dynamic simulation, a new computer technique, counters many of these deficiencies by introducing a time element that accommodates realistic component-failure characteristics and testing and inspection activities. This paper demonstrates how FMEA and FT A have been used to help design North Sea well completions and how dynamic simulation models complex systems realistically to allow comparison of designs and to provide insight into operating availability and component-testing frequencies.
Regulatory changes in recent years have shown more stringent drilling riser inspection and maintenance criteria with the objective of minimizing Health, Safety and Environmental (HSE) risks, as evident with the December 2009 draft MMS NTL on integrity issues surrounding dedicated drilling risers used on floating production facilities. Additionally, the catastrophic Macondo incident has brought to the forefront the risks associated with traditional offshore drilling, which lends an added emphasis to clear assessment and management of HSE risks for all drilling and production risers. This paper presents the methodology proposed for the risk-based comparison of different production and drilling riser system configurations. The methodology is recommended for the concept selection phase of any new drilling riser development to enable a side-by-side comparison of the critical risks within each system. This risk approach facilitates the identification of required mitigation measures to reduce risks to As Low As Reasonably Practical (ALARP). In addition an Integrity Management Strategy is proposed and recommended mitigation measures are compiled in different categories: design, inspection and operating measures. An action tracking database then assigns the implementation of mitigation measures to appropriate development phases (including the operations phase) to allow traceability and ensure risks remain ALARP. The authors will demonstrate the implementation of this methodology for three drilling riser configurations: a monobore drilling riser (base case), a drilling riser with an insert casing riser system, and a monobore drilling riser with a Subsea Isolation Device (SID) system. The case study will consider a deepwater, normally pressured Gulf of Mexico field, taking into account the following scenarios: running the drilling riser; running of drill string and casing; drilling, before and in the hydrocarbon payzone; simultaneous operations (SIMOPs); and other vessel-related activities. Following typical practices for deepwater developments in the Gulf of Mexico, a surface blowout preventer (SBOP) is assumed to be employed for managing well control. The insert riser system and the SID system will be considered by comparison to the monobore system to facilitate the presentation of each option. The most critical risks associated with all three drilling riser systems will be determined in a clear and transparent manner, along with the measures that are required to mitigate these risks to ALARP.
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