Projects

The Lunskoye gas field, located 8 km offshore the Sakhalin Island in 48 m of water, will be developed from a single platform with minimum processing facilities. The field shall be developed and operated according to western standards. The gas wells will be large bore 9 5/8” completions with an initial production rate of 10.8 million Sm3/day with a flowing wellhead pressure of 107 bar. A large part of the Lunskoye field is overlain by a gas chimney resulting in an increased risk of shallow gas problems. The overall area is subject to seismic activity. The area has extreme temperature variations between 35 degrees C in summer to -39 degrees C in winter. During wintertime there will be floating ice present.

The objective of the project was to establish probabilities wrt. leak/blowout to sea during drilling, completion, production and intervention phases for the Lunskoye wells. Further, to identify risk reduction measures wrt. well, X-mas tree and operational procedures.

The project is based on Fault tree analyses and BlowFAM analyses. The fault tree analyses focuses on the well and X-mas tree layout in the production phase. In this section of the report the absolute calculated leak/blowout probability is not focused, but the relative difference between the leak/blowout probabilities under a series of different assumptions. The BlowFAM analysis is comparing the Lunskoye wells with a “North Sea Standard” well with respect to blowout frequencies, reservoir characteristics, equipment and operational procedures.

The main sources for input experience data related to component failures and blowouts are the Wellmaster database, the Oreda database and the SINTEF Offshore Blowout Database.

The Snorre P35 TLP well was drilled during autumn 2000. A leakage was observed in the production casing before the completion was run. The leakage was localised to approximately 140 m TVD above the reservoir. A scab liner was run inside the casing to seal off the leakage, but it was unsuccessful. The leak off pressure was however higher than the leak off pressure before running the scab liner.

NPD approved that Norsk Hydro could produce oil from the well for a limited period of time. The well was thereafter completed.

Norsk Hydro is now planning to convert the well to a gas injector. During gas injection the well pressures will be different compared to the oil production period.

In this report the well barrier situation during the gas injection phase have been analysed.

The report is based on five different big bore completion alternatives for the Ormen Lange gas wells. The wells are 9 5/8” wells with some bottlenecks with a 9 5/8” subsea X-mas tree. The reliability data established through the Wellmaster study (well equipment reliability data), the OREDA subsea database (subsea equipment reliability data) and a series of assumptions have been the input to the study.

This was a SINTEF project, but an ExproSoft employee completed it when he decided to start working for ExproSoft in May 2001.

A reliability study of subsea BOPs was performed in 1999. This is a follow up study focusing on the deepwater kicks and associated BOP problems and safety availability aspects. The study is based on information from 83 wells drilled in water depths ranging from 400 meters (1312 feet) to more than 2000 meters (6562 feet) in the US GoM OCS. These wells have been drilled with 26 different rigs in the years 1997 and 1998.

A total of 117 BOP failures and 48 well kicks were observed in these wells. The main information source from the study has been the daily drilling reports.

Detailed kick statistics and parameters affecting the kick occurrence and kick killing operation are discussed. The occurrences of BOP failures as a result of wear and tear during the kick killing operations have been investigated.

The BOP as a safety barrier has been analyzed based on the relevant kick experience and the BOP configuration. An alternative BOP configuration and a BOP test procedure that will improve the safety availability and save costly rig time have been proposed.

Per Holand has carried out a series of Subsea BOP studies since the early 80-ties when they were employed by SINTEF. Below a description of the main projects and a complete reference list is given.

From 1981 to 2001, Per Holand has documented results from a number of reliability studies of Subsea Blowout Preventer (BOP) systems, on behalf of various oil companies, the Norwegian Petroleum Directorate (NPD), and the US Minerals Management Service (MMS)

Operational experience data from subsea BOPs used in Norwegian, Brazilian and US GoM OCS waters in the period 1978 and 1998 has been collected and analyzed in several BOP studies to reveal BOP reliability problems. The results from the various studies focus on rig downtime caused by BOP failures, criticality of failures in terms of ability to control a well kick, and BOP subsea test time consumption.

The results from each BOP reliability study have been compared with corresponding results from previous studies. The two last studies have focused on deepwater subsea BOPs. An overall conclusion from the latest study is that there are no main differences in the overall reliability of deepwater BOPs vs. BOPs operating in "normal" water depths, except for the increased downtime caused by increased BOP handling time in deep waters.

Main projects
The following main projects have been carried out.

· Phase I study was based on failure data from 61 exploration/appraisal wells drilled from semisubmersible rigs in the Norwegian sector of the North Sea in the period 1978 - 1981. The report presented failure rates and downtime for the various BOP components.

· Phase II study was based on failure data from 99 exploration/appraisal wells drilled from semisubmersible rigs in the Norwegian sector of the North Sea in the period 1978 - 1983. The study also included a mechanical evaluation of BOP components. The reliability of control systems was documented in a separate report.

· Phase III included no further data collection. The study focused on the operation and maintenance of subsea BOP components.

· Phase IV study was based on data from 58 exploration/appraisal wells, drilled in the period 1982 -1986. The availability of the BOP as a safety barrier against blowout was assessed by fault tree analysis. Time consumptions for weekly BOP testing and associated problems were recorded and discussed.

· Phase V study was based on data from 47 exploration/appraisal wells, drilled in the period 1987 -1989. BOP failures were recorded and analyzed. Recommendations with respect to BOP test intervals were given. Time consumption for weekly BOP testing was recorded and discussed.

· Phase I DW (Deepwater) study was mainly based on data from deepwater wells drilled in Brazilian waters and "shallow" Norwegian waters in the period 1992 - 1997. A total of 144 wells were examined, whereof 100 were deepwater wells. The report presents the data collected and further highlights deepwater (deeper than 400m) specific problems.

· Phase II DW study was completed in October 1999. The study was based on experience from deepwater wells drilled in the US GoM OCS in 1997 and 1998. A total of 83 wells were included.

· Performance of Deepwater Blowout Preventer (BOP) Equipment During Well Control Events study was completed in August 2001. This is a follow up study of the Phase II DW study focusing on the deepwater kicks and associated BOP problems and safety availability aspects. Detailed kick statistics and parameters affecting the kick occurrence and kick killing operation are discussed. The occurrences of BOP failures as a result of wear and tear during the kick killing operations have been investigated.

In addition, Per Holand has carried out a reliability study related to platform located BOPs used for development drilling. The analysis was based on failure data from 48 development wells drilled from three North Sea platforms in the period 1986 - 1990. The study was completed in 1992.

Several minor studies have also been carried out to study specific BOP problems. A complete list of the BOP related projects carried out since the early 80-ties is shown below.

During Phase I DW (/7-9/) a tailor-made computer program for handling BOP reliability information and BOP preventive maintenance information was developed. This software is described on http://www.exprosoft.com/subsea_bop_master.htm.

All rights to the BOP software has now been transferred to ExproSoft. All requests related to this software should be addressed to per.holand@exprosoft.com.

References
1. Holand, P.: "Deepwater Kicks and BOP Performance" SINTEF Report STF38 AA01419, (Unrestricted version)

2. Holand, P.: "Reliability of Deepwater Subsea BOPs", SPE paper 66186, published in SPE Drilling & Completion, March 2001

3. Holand, P.: "Reliability of Subsea BOP Systems for Deepwater Application, Phase II DW" SINTEF Report STF38 A99426 (Unrestricted version).

4. Holand, P.: "Visund BOP control system verification" SINTEF Report STF38 F99411 (Restricted).

5. Holand, P.: "Evaluation of the Ocean Alliance Blowout Preventer (BOP) with respect to Deepwater Application". SINTEF Report STF38 F98427. (Restricted).

6. Holand, P.: "Evaluation of the Need for an Acoustic Backup Control System for the Snorre II BOP". SINTEF Report STF38 F98409. (Restricted)

7. Holand, P., Reliability of Subsea BOP Systems for Deepwater Application, SINTEF Report STF38 F97417, Trondheim, Norway, 1997. (Restricted)

8. Holand, P., Reliability of Subsea BOP Systems, Fault Tree Analysis, SINTEF Report STF38 F97425, Trondheim, Norway, 1997. (Restricted)

9. Blowout Preventer (BOP), Data Collection and Reliability Analyses Tool, Users’ manual, SINTEF Industrial Management, Safety and Reliability, Trondheim, Norway 1997.

10. Holand, P., Subsea BOP Systems, Reliability and Testing Phase V, revision 1 (this revision 1 is based on a report with the same title published in 1990), SINTEF report STF 75 A89054, Trondheim, Norway, 1995.

11. Holand, P.: Reliability of Surface Blowout Preventers (BOPs)". SINTEF Report STF75 A92026, Trondheim, Norway, 1992.

12. Holand, P.: "Subsea Blowout-Preventer Systems: Reliability and testing". SPE Drilling Engineering, SPE 17083, USA, December 1991

13. Holand, P.: "Reliability of Subsea BOP Systems". IADC, European Well Conference, June 11 – 13 1991, Stavanger

14. Holand, P., Rausand, M.: "Reliability of Subsea BOP Systems". Reliability Engineering 19 (1987) 263-275, Elsevier Applied Science Publisher Ltd, England, 1987

15. Holand, P.: "Reliability of Subsea BOP Systems – Phase IV". SINTEF Report STF75 F87007, Trondheim, Norway, 1987. (Restricted)

16. Holand, P., Molnes, E. & Rausand, M.: "Subsea BOP Failures and Malfunctions". SINTEF Report STF75 F86009 (Restricted)

17. Holand, P., Molnes, E.: "Reliability of Subsea BOP Systems – Phase III, Testing and Maintenance, Summary Report ". SINTEF Report STF75 F86005, Trondheim, Norway, 1986. (Restricted)

18. Holand, P., Molnes, E.: "Reliability of Subsea BOP Systems – Phase III, Testing and Maintenance, Main Report ". SINTEF Report STF75 F86004, Trondheim, Norway, 1986. (Restricted)

19. Hals, T., Molnes, E.: "Reliability of Subsea BOP Systems – Phase II Control Systems". SINTEF Report STF 18 F84516, Trondheim, Norway, 1984. (Restricted)

20. Holand, P., Husebye, R.,Lydersen, S., Molnes, E., Rausand, M., Ulleberg, T.: "Reliability of Subsea BOP Systems – Phase II Main Report". SINTEF Report STF18 F84515, Trondheim, Norway, 1984. (Restricted)

21. Holand, P., Rausand, M.: "Reliability of Subsea BOP Systems- Phase II Summary Report". SINTEF Report STF18 F84517, Trondheim, Norway, 1984. (Restricted)

22. Rausand, M., Engen, G.: "Reliability of Subsea BOP Systems". OTC 4444 Offshore Technology Conference, Houston 1983.

23. Rausand, M.: "Reliability of Subsea BOP Systems". SINTEF Report STF18 F83003, Trondheim, Norway, 1983. (Restricted)

For further information please contact Per Holand:
Telephone: +47 73 59 11 79
Fax: +47 73 59 11 49
E-mail: Per.Holand@exprosoft.com

The objective of the study was to quantify rig intervention requirement related to downhole failures for the different subsea completion configurations utilised at the Haltenbanken area. The analysis was performed with basis in relevant reliability data extracted from Wellmaster and analytical modelling.

The report is based on an assumed Case A completion alternative for an Ormen Lange gas well. The well is a plain 7” completion with a 7” subsea X-mas tree. The reliability data established through the Wellmaster study (well equipment reliability data), the OREDA subsea database (subsea equipment reliability data) and a series of assumptions have been the input to the study. A LCC simulation model developed in the Wellmaster project has been used for the analyses.

The Oseberg B51 well is a satellite subsea well. The well is controlled from, and flowed back to, the Oseberg B platform.

The well is equipped with a horizontal X-mas tree.The well is presently closed in because the Crossover valve (COV) is leaking and the Annulus Master valve (AMV) did not satisfy the leak criteria.

Norsk Hydro is now planning to workover the well. They want to implement risk-reducing measures and then continue the production from the well until they are ready to perform the workover.

The objective of the project has been to assess the effect of the known failures in the Oseberg B51 X-mas tree on the leakage to sea probability. Further to assess the effect of risk reduction measures on the total probability to experience a leakage to sea from the well.

The project is based on Fault tree analyses. The component input reliability stems from the Wellmaster database and the Oreda subsea database.

Includes a study of the large bore (9 5/8”) gas production wells at the Lunskoye field. The project objective was to quantify the operational performance measures of the wells as a result of potential intrinsic equipment failures and planned well interventions.

Amongst others, the following well performance measures was deduced utilising the WellMaster life-cycle cost simulation tool in the study;

- Well downtime and average well production availability (uptime)
- Completion performance (production capacity assessment)
- Well intervention frequency
- Well intervention costs

Main objective is to establish a set of criteria, requirements and guidelines for systematic evaluation and selection of appropriate equipment/systems and methods for improved sand control functionality in well completions. Sand control equipment/systems and methods in this respect includes gravel pack, sand screens (various types/designs) and/or combined/integrated solutions for well completions.

A part of the project involves shaping a in-depth specification for collection of experience/failure data (Wellmaster) on sand control systems. E.g., linking basic failure/degradation mechansims and causes to procedural, production- and formation/reservoir- parameters in a systematic way.

The reliability of acoustic BOP control systems have been evaluated based on experienced acoustic BOP failures from subsea BOPs that have been used in the North Sea and Brazilian waters for wells drilled between 1980 and 1996 and an evaluation of technological improvements in newer type acoustic BOP control system.

Further the reports discuss alternative controls for a Subsea Shut Off and Disconnect Device (SSODD) and other factors that should be addressed associated to the use of a SSODD.

This study represents a risk assessment of gas lifted oil production wells on the Ekofisk 2/4X, Eldfisk Alpha and Bravo platforms (2/7A, 2/7B)operated by Phillips Petroleum Company Norway (PPCoN). These wells were originally planned with annular safety valves (ASV) as a barrier in the annulus flow path. However, due to an increased intervention frequency and operational problems/difficulties in pulling the completion strings with the ASV (packer type), PPCoN has prompted the search for alternative solutions. An alternative solution investigated was the use of check valves in the wellhead inlets to the tubing by the casing annulus valves. The risk assessment is performed in order to quantify whether this alternative well configuration gives an acceptable leakage/blowout risk level on the platforms or not.

Risk assessment of alternative annulus barrier configurations for new gas lift production wells on the Ekofisk 2/4B platform.

The Njord field is located at some 330 meter water depth in blocks 6407/7 and 6407/10, approximately 130 kilometres northwest of Kristiansund and 30 kilometres west of the Draugen field. The field is developed with subsea wells tied back to the Njord A floating platform.

The objective of the risk analysis has been to assess the effect of a small tubing to annulus leak located above the TR-SCSSV on the "leakage to the surroundings" probability for a gas injection well, and further to assess the effect of potential risk reducing measures.

Tune is a subsea gas/condensate development at ~100 meter water depth some 10 kilometres southwest of the Oseberg field centre. The Tune subsea wells are tied back to the Oseberg D platform via a subsea template and two pipelines.

The objective of the project has been to assess the effect of a known barrier failure (tubing to annulus communication below the SCSSV) on the well "leakage to the surroundings" probability, and further to assess the effect of potential risk reducing measures that can be implemented.

A risk assessment was carried out for an oil production well which is planned converted to continuous gas lift at the Varg A unmanned wellhead platform. The risk assessment was performed in order to investigate the risk level associated with the unsupported portion of the 24”-13 3/8”-10 3/4”x9 5/8” casing/cement program during gas lift operations, and to evaluate different alternative annulus barrier configurations for the well.

The increased platform risk level related to lift gas releases in the wellhead area with respect to escalation effects (fire/explosion) was also evaluated in the study.

An extension of the well risk analysis was later performed to investigate the feasibility of converting additional oil production wells on the Varg A platform to gas lift with an alternative annulus barrier configuration (without TR-SCASSV). A special factor considered was the limited remaining operational lifetime of the wells.

The objective of the study was to assess and compare the performance of four different subsea X-mas tree concepts for the Ormen Lange development project, with emphasis on the wellhead to X-mas tree annulus interface design. I.e., how annulus communication is established and routed between the X-mas tree and the downhole well completion at the wellhead.

Shell Deepwater Services has developed a surface BOP system suitable for floating drilling operations in moderate operating environments, such as the Gulf of Mexico, West Africa, Brazil and the Mediterranean.

In this study, the proposed surface BOP arrangement was compared with a conventional deepwater BOP arrangement concerning handling of critical situations.

A series of scenarios representing critical situations that may occur has been analysed. Pros and cons of the two alternatives have been evaluated. The frequency of critical situations has been discussed.

The objective of the study was to evaluate the economic impacts of different SCSSV configurations for the Byggve and Skirne subsea developments. The Wellmaster life-cycle cost simulator was utilised in conjuction with reliability data, intervention data, well operational philosophy, and production data to evaluate the alternatives.

The SubseaMaster project was kicked off in April 1999 with Petrobras as the client. The objective of the project was to develop and implement an experience database on subsea production systems for Petrobras’ operations. The main focus of the project is collection and analysis of reliability data and systematic learning and improvement on the basis of failure cause analysis and feedback to involved parties.

SubseaMaster Phase I was achieved through combining Petrobras’ own expertise on subsea production systems with SINTEF/ExproSoft's experience from design and maintenance of major experience databases. Phase I was run under a contract between Petrobras and SINTEF with ExproSoft taking over the commercial rights of the software and database product upon Phase I completion.

The SubseaMaster software and database was made integral to the existing WellMaster product and became the first database worldwide to integrate a full description of well completions and subsea production systems with full reliability data input, retrieval and analysis capability.

Among other, the following equipment is included in the SubseaMaster database:
- Wellhead
- X-mas tree, tree block, structure
- Connectors
- Tree valves
- Isolation valves
- Injection valves
- Control and monitoring systems w/SCM internals
- Flowlines/Umbilicals/Jumpers
- Manifolds (structure, piping, connections, sensors)
- Choke valves
- Multiphase flow meters
- Wireline/Workover BOPs
- Intervention tools/systems (ROT/ROV)
- Completion risers
- Pipelines
- Top tension riser systems


Benefits:
A variety of benefits/applications can be expected from SubseaMaster as have been experienced for the WellMaster project:
- Benchmarking and comparison of performance of various systems/suppliers
- Improved understanding of failure mechanisms as input to new field developments
- Source for generation of input data to RAMS analyses
- Future platform for exchange of experience data with other operating companies


Software and database solution:
The software is developed based on use of the following tools:
- Visual Basic version 6.0
- Microsoft Visual C++ 6.0
- ORACLE database

The system is implemented as a client/server network system allowing accessibility from multiple sites worldwide.


User interface:
The majority of input is via a graphical user interface, with close similarity to solutions implemented in ExproSoft's WellMaster software. This incorporates graphical symbols for the different subsea equipment items, as well as full drawing capability for flow diagrams illustrating manifolds, X-mas trees, pipeline end terminals, etc. Input of failure data and repair/intervention data will also be via this graphical interface.


Project history:

Phase I:
April 1999 through July 2000. Participation and funding from Petrobras and ExproSoft, with major influence on database modelling and program specification from Petrobras’ engineers. The program is made in an English base version, with features included for easy translation of commands/dialog boxes/reports to a Portuguese version. A simplified reporting module will be prepared with reliability analysis capability. The program is made as a 32-bits version for Windows 95/Windows NT, making extensive use of socalled Active-X controls. This will make it possible to run the program as an Internet/Intranet application in the future.

Phase II:
May 2001 through May 2003. Phase II was launched as a Joint Industry Project (JIP) with participation from a group of subsea operators. In Phase II, the database was populated with data provided by the participants and the capability of the software was improved. As a result of Phase II, the JIP database included data on 50 subsea X-mas trees and 14 manifolds with associated lines. The Phase II resulted in, e.g., a total some 5000 years of service time collected on various type of actuated subsea valves.

Phase III:
JIP scheduled for launch in 2004. In Phase III, the focus will be on continued population of the database and further development of the software for enhanced data input, reporting, and analysis friendliness.