Projects

Client SINTEF Teknologiledelse/Odfjell Drilling
Abstract The new rig DeepSea Atlantic experienced severe problems with the BOP control system. NTNU, SINTEF and ExproSoft formed a project group to investigate the causes of the problems and recommend solutions to prevent reoccurrence

Client A/S Norske Shell
Abstract A/S Norske Shell was investigation if there is a need to drill the upper part of a well with a BOP with three pipe rams and one blind shear ram, while using two pipe rams and two blind shear rams when drilling in the reservoir. This would cause that the BOP has to be pulled to surface for the ram replacement while drilling the well. This is time consuming, and thereby costly. ExproSoft was contacted to advise Shell with the BOP configuration to use for the specific well.

Client RPS/Canadian Association of Petroleum Producers (CAPP)
Abstract The objective with the work carried out in association with this report has been to estimate a blowout probability for drilling in the Beaufort Sea. We were subcontracted by RPS Calgary to perform this work as a part of the study "Same Season Relief Well Study" for drilling in the Beaufort Sea.

The report is mainly based on:
• Blowout experience based on the SINTEF Offshore Blowout Database from:
o Norwegian waters
o UK water
o US GoM OCS (Outer Continental Shelf)
• Kick experience from: The Beaufort Sea
o Norwegian waters
o Canada East Coast
o US GoM OCS
In addition the report contain statistics from kick and blowout data from both onshore and onshore activities in Canada.

Based analyses of the above data the blowout probability has been estimated for the Beaufort Sea.

Client ENI Group
Abstract This report is based on a review of the information stored in the SINTEF Offshore Blowout Database per June 2006.

The objective of the study has been to utilize knowledge from SINTEF’s Offshore Blowout Database to analyze causes and consequences of offshore drilling blowouts. This will be the done as part of ENI’s efforts to reduce the probability of occurrence of blowouts from ENI’s future E&P activities.

The report has been divided in two main parts, one focusing on shallow gas blowouts/well release and one part focusing on “deep” blowouts well releases. This split has mainly been done because the well barrier situation will be different for shallow gas vs. deep incidents.

The report focuses on the causes of the blowouts/well releases. The consequences, or characteristics, have also been briefly presented and discussed.

The experienced blowout/well releases analysed mainly stems from the US Gulf of Mexico (GoM) Outer Continental Shelf (OCS) and Norwegian and UK waters. Blowout experience from other parts have been briefly discussed.

Client Statoil
Abstract The objective of this study has been to investigate if a surface blowout preventer (BOP) may be applicable in Norwegian waters both with respect to:
• overall risk level
• compliance with Norwegian regulations and NORSOK

A study originally carried out on behalf of Shell Deepwater Services in Houston was the basis for this study. Further the experience Shell has from drilling several wells in Brazil and Egypt with this type of BOP system has been evaluated, and areas for improvement pinpointed.

The study is a semi-quantitative analysis that takes a comparative approach where the risk related to surface BOP operations are compared to the risk related to conventional drilling with subsea BOPs.

Operational restrictions related to rig heave and ability to drill has been investigated. The effect on the weather window was analysed coarsely. These evaluations were carried out with the specifications of the Stena Dee and Stena Don rigs in mind.

The study further addressed the compliancy with Norwegian regulations.

Client Norsk Agip A/S
Abstract ENI E&P Division is evaluating surface BOP system suitable for floating drilling operations.

In this study a state of the art description of surface BOP concepts have been carried out. Based on this two different surface BOP arrangements were selected, one with a SOD (subsea Shut Off and Disconnect device) and one without. These arrangements have been 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.

Client Shell Deepwater Services
Abstract 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.

Client Shell Deepwater Services
Abstract 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.

Client Mineral Management Service (MMS) US / SINTEF
Abstract Introduction
This was a SINTEF project, but an ExproSoft employee completed it when he decided to start working for ExproSoft in May 2001.

Abstract
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.

More about BOP reliability
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 20 04 08
E-mail: Per.Holand@exprosoft.com

Client StatoilHydro ASA
Abstract In longer screen sections, and in particular in horizontal wells, the pressure drop will not be the same all along the total length of the screen section. This means that the inflow will be un-evenly distributed along the screen section, and the water coning effect or a gas break-through may occur too soon. To mitigate or reduce these effects in long horizontal wells with sand screens, it has become more common to include an inflow control device (ICD) with the screens. The optimal restrictor design for ICD’s is when the pressure drop through the restrictor is higher for water than for the oil. The ICD will thus prefer to produce oil if premature water breakthrough occurs. The aMAZE is a new ICD made by Baker Oil Tools (BOT) aiming to satisfy this need, combined with high erosion- and plugging resistance.

ExproSoft has performed a FMECA of the new ICV design.

Client Statoil
Abstract Statoil wanted to improve equipment and procedures for control line running in order to reduce the potential for HSE consequences during completion operations. The new system should be designed without major negative influence of the quality and efficiency.
ExproSoft assisted Statoil during the following phases of the project:

1. Development of the requirement specification
2. Concept evaluation of several candidates
3. Detail design evaluation

Client Norsk Hydro
Abstract Hydro is involved in the development, testing and use of the SmarTest formation tester made by PetroTech. ExproSoft had an advisory function during the project. The objective of the work was to reduce the probability of technical faults and human errors during the onshore and offshore test of the SmarTest tool.

Client Norsk Hydro
Abstract The project included two FMECA's and a production facility evaluation related to an autonomous valve.

Client Petroleum Technology Company as
Abstract This project includes multiple qualification activities of equipment made by Petroleum Technology Company (PTC).

FMECA of gas lift valves (GLVs):

1. Safelift Operational Gas Lift Valve - 1.00"
2. Safelift Operational Gas Lift Valve - 1.50"
3. Safelift Operational Gas Lift Valve - 1.75"
4. Safelift-S (shear) Operational Gas Lift Valve - 1.50"
5. Safelift IPO Unloading Gas Lift Valve - 1.00"
6. Safelift IPO Unloading Gas Lift Valve - 1.50"

FMECA of H-SAS valves:
7. H-SAS - 1.75"
8. H-SAS - 2.00"

FMECA of M-SAS valves:
9. M-SAS - 2.00"
10. M-SAS - 2.50"
11. M-SAS valve GAP analysis

Testing:
12. Test program for GLV as a barrier
13. Fire testing of M-SAS

Client Statoil
Abstract ExproSoft participated in the following activities related to completion selection and qualification for the Tyrihans field:

1. Development of the requirement specification
2. Bid preparations
3. Technical evaluation of bids
4. Development of TQP's
5. Following up of qualification activities (e.g. Titanium production packer and gas lift valves)

Client Chevron Australia
Abstract This report addresses the material selection issues for the tubing and liner for the Gorgon field production wells, focusing on the qualification process and risk aspects. The three main material candidates considered are:

-Modified 13Cr
-Super Duplex
-Ti-6246

Chevron has performed several qualification activities for each material candidate. ExproSoft’s role in this project was to:

-Review and evaluate qualification activities performed by Chevron
-Perform an FMECA for tubing and liner options
-Report identified gaps related to existing or missing qualification work
-Recommend materials and completion design

Client Statoil
Abstract The project included development of the following guidelines:

1. Guideline for project planning (requirement specification, bid, etc)
2. Guideline for project execution (qualification, etc)
3. Guideline for FMECA performance
4. Guideline for OPERA performance
5. Guideline for AEA performance

Client Norsk Hydro
Abstract This report summarise an FMECA study of the Inflow Control Device (ICD) made by Weatherford.

Client Norsk Hydro
Abstract The objective has been to review a Halliburton Technology Development Project which had to apply the TQP guideline, as basis for improving and revise the referenced TQP guideline for Norsk Hydro, and to subsequently provide Norsk Hydro with the updated TQP guideline and procedure documents for implementation within the Hydro organisation. This work also took into consideration additional experiences and learning obtained by ExproSoft during other technology projects run in 2005 and 2006.

Client Norsk Hydro
Abstract This report summarise an ExproSoft study of the hydraulically actuated surface controlled valve (H-SAS) made by Petroleum Technology Company (PTC). The valve is located in the fire protective envelop area of the tubing head. The main objective is to find out if the H-SAS valve is qualified for use at Brage. This goal is achieved by

1. Clarify the Hydro requirement specification
2. Control if the H-SAS is qualified in accordance with Hydro’s qualification guideline
3. Describe and discuss potential gaps

Most gaps revealed can be closed by minor time-efforts and costs. From ExproSoft point of view, three high-cost issues need to be discussed and clarified:

1. Fire resistance
2. Falling load resistance
3. Qualification for Brage conditions (160ºC)

All gaps are discussed in the final section of this report.

Client Chevron
Abstract During the process of selecting completion design for the Gorgon wells, Chevron evaluated three material candidates for the tubing and liner. These were:

1. Modified 13Cr
2. Superduplex
3. Ti-6246

Chevron had performed several qualification activities for each material candidate. ExproSoft’s role in this project was to:

1. Review and evaluate qualification activities performed by Chevron
2. Perform an FMECA for all tubing and liner options
3. Report identified gaps related to existing or missing qualification work
4. Recommend materials and completion design

Client Statoil
Abstract The objective of the project was to conduct a 3rd party follow-up on manufacturing and qualification testing of critical well completion equipment for the Statoil Norne subsea satelite wells, such as the DIACS systems and the Down Hole Safety Valves. The work was performed through a number of visits to the manufacturer's sites for manufacturing and testing for witnessing, and through review of governing documentation for testing and QA and of test reports and results.

Client Norsk Hydro
Abstract A guideline for well technology qualification was developed together with Norsk Hydro.

Client Norsk Hydro
Abstract This project executed a FMECA of the concentric safety valve from Halliburton that may be used at Oseberg East Well E-2. Injection gas will be injected through a tube in the centre of the CSV. Produced hydrocarbons will be routed through the annulus between the injection tube and the traditional safety valve bore. The flapper valve closes both the injection tube and the annulus in closed position, and allows communication between the injection tubing and the annulus above the flapper. The main objective of the FMECA was to identify failure modes, causes and consequences in order to provide risk reducing recommendations.

Client Statoil
Abstract In this project the following were carried out:

1. Development of requirement specification for Gas Lift Valve
2. FMECA of Tronic dry-mate connectors in subsea installations
3. Specification of SCRAMS Chemical Injection Sub

Client Norsk Hydro
Abstract The objective of this project was to develop and implement a technology qualification program (TQP) for Norsk Hydro. The TQP for well technology is used for qualification of new drilling, completion, subsea and intervention products.

Client Norsk Hydro
Abstract TMAFS is a downhole tool that allows flow of hydrocarbons through the annulus after wireline shifting of the tool. The TMAFS tool has been installed in two wells. In both cases there were problems with actuation of the sleeve.

The main objective of this project was to identify causes for having problems with shifting the sleeve to open position, in order to provide recommendations which will allow shifting of the sleeve within normal operating limits.

The project included:

1. Familiarisation with the tool, design process, well design and operations
2. Review operational experiences in F-26 and E-6
3. Witness disassembly of the TMAFS pulled from F-26
4. Performance of a FMECA
5. Critical findings and recommendations for further work

Client A/S Norske Shell
Abstract The project run from 2002 to 2005 qualified the 7" Tubing Retrievable DHSV for the Ormen Lange big bore deepwater gas wells . The project was divided into several phases; Requirement Specification Document, Invitation to Tender, evaluation of Tenders, system analysis, establishing a detailed qualification test program, review of relevant test sites, preparing and conducting the test program with candidate prototype valves from three valve manufacturers, review of test results, follow-up on required valve design improvements, review of solutions for lock-out of failed valves, project documentation and follow-up with the client and the valve manufacturers, final report with results, conclusions and recommendations on valve selection. The last phase included a final test sequence with the selected valve design in order to verify its equalizing function. The work was performed in a joint project with DNV, Oslo.

Client Multiclient
Abstract 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.

Client Chevron
Abstract Process using SubseaMaster to structure, analyse and report out on subsea equipment reliability experiences for Chevron as input to design for reliability and major capital projects

Client StatoilHydro ASA
Abstract This study includes results from an early assessment of downhole safety valve configuration concepts considered for the wells in the Shtokman field. The following well cases have been defined and analysed:
• Base Case (BC): Single gas production well with a single downhole safety valve (DHSV) including single hydraulic control line.
• Case 1 (C1): Single gas production well with two DHSVs with single control lines in a hot backup configuration. Otherwise as for the Base Case.

The production availability of the well case has been modelled and analysed under the assumption of interventions only during a 4 month ‘summer season’ using ExproSoft’s FieldSim software package. FieldSim is a tailor made oil field simulation software with special focus on prediction of smart field operating expenditures (OPEX) and well zonal production availability.

Client ENI Norge A/S
Abstract This report documents a operational risk assessment made for the baseline Marulk field development comprising 5 gas production wells having horizontal trees and a basic straight well completion design with:

- One tubing retrievable safety valve (DHSV) without insert valve capability, but with dual redundant control system as per Eni global recommendation (redundant valve internal actuator with separate control line).
- Downhole chemical injection
- Sand control

The operational performance of the wells in the field has been modelled and analysed using ExproSoft’s FieldSim software package. FieldSim is a tailor made oil field simulation software with special focus on prediction of smart field operating expenditures (OPEX) and well zonal production availability.

Client ENI Norge A/S
Abstract This report documents an operational risk assessment made for different well completion design options proposed for gas lifted oil producers (OP) at the Goliat field development. The following well cases have been defined and analysed:
• Base Case (BC): 2-Zone DIACS well with a single tubing retrievable safety valve (TR-SCSSV) including dual redundant hydraulic controls and insert valve capability.
• Case 1 (C1): Well includes two TR-SCSSVs with single control lines in a hot backup configuration. Otherwise as for the Base Case.
• Case 2A/B (C2A/C2B): Well includes a packer type annulus safety valve system (ASV). Otherwise as for the Base Case. Two distinct operational philosophies were assessed for this case. A traditional situation where the ASV system is considered the only well primary barrier on the A-annulus side and an alternative situation where the ASV is considered redundant as primary well barrier with the production string below the ASV packer.
• Case 3 (C3): Well without DIACS. Otherwise as for the Base Case.

The operational performance of the well case has been modelled and analysed using ExproSoft’s FieldSim software package. FieldSim is a tailor made oil field simulation software with special focus on prediction of smart field operating expenditures (OPEX) and well zonal production availability.

Client ENI Norge A/S
Abstract The objective of the study has been to assess Goliat subsea base case well intervention frequencies and costs, with the two cases of applying a semi-rig for all intervention tasks on the wells and alternatively with a monohull vessel for light well interventions with wireline.

The scope has been to perform a preliminary, simplified spreadsheet-based (high-level) study addressing the intervention frequencies and intervention related costs which can be expected for the Goliat wells. The study addresses both reservoir/formation related interventions (wax inhibition/removal, scale, sand, zone isolation, etc.) and interventions related to equipment failures of the completions (including the x-mas tree). Reliability data from the WellMaster and SubseaMaster databases are applied and adapted to Goliat specific well conditions. In addition relevant open sources are also used for assumptions related to the reservoir/ formation induced interventions. The study is based on the “base case” definition assuming conventional single boresubsea wells (no multilaterals). The study covers the wells lifetime to abandonment.

Client Shell EP Europe
Abstract The scope is to provide probability of failure estimates for different types of well failure per year over the course of remaining Draugen's lifetime

Client Statoil
Abstract This report documents a reliability assessment made for the Base Case well completion design options proposed for the Gjøa field development. On the basis of a proposed field development plan, the following basic field well case has been defined and analysed:

Base Case (BC): All wells in field include a single tubing retrievable safety valve (TR-SCSSV) with insert capability. I.e., an insert safety valve (WR-SCSSV) can be run as a replacement inside the TR-SCSSV in most situations of TR-SCSSV failure. Redundancy assumed between DIACS valves in the DIACS configured wells. I.e., that only failure to operate or open both DIACS valves on demand will introduce the need for one or more (on average every 3 required DIACS year) light well interventions to carry out production logging (PLT) or to mechanically operate the DIACS valve.

The operational performance of the field case has been modelled and analysed using ExproSoft’s FieldSim software package. FieldSim is a tailor made oil field simulation software with special focus on prediction of smart field operating expenditures (OPEX) and well zonal production availability.

Client Shell Ireland
Abstract This report documents a reliability assessment made for the five subsea wells planned at the Corrib gas field development. The field case defined and analysed in this study is as follows:

• All wells in field include a horizontal X-mas tree
• All wells involve a conventional completion with sliding sleeve, PBR seal assembly and a single tubing retrievable safety valve (TR-SCSSV) with insert valve capability (WR-SCSSV).

The operational performance of the field case has been modelled and analysed/simulated in ExproSoft’s FieldSim software package with special focus on prediction of field intervention requirement, operating expenditures (OPEX) and field well downtime/production availability. Note in particular related to well downtime that the Corrib field is subject to severe sea currents and weather conditions in the winter season (October through February) making work on the wells in this period very difficult. A special focus of the study has therefore been on assessment of the impact of seasonal variations in well maintenance work on the gas delivery requirements of the field.

The basis for FieldSim simulation was input from Shell on planned completion/intervention activities, intervention logistics and field operational philosophy. In addition, generic equipment reliability data was applied based on the WellMaster, SubseaMaster and OREDA equipment reliability databases.

Client NAM
Abstract This report documents a risk analysis made for dry tree gas production wells on basis of intervention logistics, downhole safety valve concepts and well barrier test intervals. Two main well cases have been defined and analysed with respect to leakage risk in this study:

• Base Case: Dry tree well with a single tubing retrievable safety valve (TR-SCSSV) with insert capability. 6 or 12 months test interval assumed for SCSSV and X-mas tree master valve.
• Case 1: Dry tree well with two tubing retrievable safety valves (TR-SCSSV) with insert capability in a hot back-up configuration. 6 or 12 months test interval assumed for SCSSV and X-mas tree master valve.

As part of the study, the operational performance of the well cases for three different platform types (manned, unmanned with helicopter deck and crane, unmanned without helicopter deck or crane) have been modelled and analysed in ExproSoft’s FieldSim software package with special focus on prediction of the well case intervention frequencies (and intervention risk), operating expenditures (OPEX) and well downtime.

Client ENI Norge A/S
Abstract The purpose of the report is to establish and present data from various available sources on subsea
well equipment failures, well production, intervention and work over operations and methods for
assessing subsea intervention frequency data to be used during field development planning, and create
input to subsea well performance simulation tools (such as the FieldSim tool by ExproSoft). Sources
applied are:

• External open sources (listed in the report) – equipment failures, interventions/work over data (interventions, times, vessels, systems, historical field data)
• WellMaster database on well completions – equipment failures and interventions/workovers of subsea wells (data extracted from ‘well operation log’)
• SubseaMaster and OREDA databases on subsea equipment – failures and interventions, repair data if any is available (OREDA is scarce on intervention data)

Examples of typical well and subsea equipment intervention and workover frequencies are presented.
A brief technology review with data on intervention systems, tools and vessels is also included.
Three Excel datasheets with collected data are enclosed as separate Appendices to the report.

Client Total E&P UK PLC
Abstract The Forvie North well is a subsea well tied-back to the Alwyn platform. The valves are all controlled from the Dunbar platform. The objective of the study was to:

1) Identify the probability of occurrence of an ESD0, which would exceed 72 hours.
2) Provide a probability of occurrence of any other shut-down exceeding 72 hrs (including all other ESDs and subsea well’s reliability).

Client Total E&P UK PLC
Abstract The objective was to assess alternative ESD pump configurations and to discuss if there is any technical or reliability advantage or disadvantage in spending additional time and money to pull the pump (workover) while present with the rig.

Client Statoil
Abstract This report documents a reliability assessment made for well completion design options proposed for the Tyrihans field development. The study report covers an initial assessment of well design concept for subsurface safety valve and downhole instrumentation and control system (DIACS). Three main field well cases have been defined and analysed in this study:

• Base Case: All wells in field include a single tubing retrievable safety valve (TR-SCSSV) with insert capability. No redundancy assumed between DIACS valves in wells
• Case 1: All wells in field include two tubing retrievable safety valves with insert capability in a “hot” backup/tandem configuration. No redundancy assumed between DIACS valves in wells
• Case 2: As Base Case, except that the two DIACS valves in the DIACS configured wells are considered redundant.

In addition, sensitivity studies where performed to assess the impact of uncertainty in the DIACS systems reliability data.

The operational performance of the field cases have been modelled and analysed in ExproSoft’s FieldSim software package with special focus on prediction of smart field intervention requirement, operating expenditures (OPEX) and well downtime / zonal production availability.

Client Total E&P UK PLC
Abstract The objective was to assess alternative ESD pump configurations.

Client Shell Deepwater Services Shell International/Jager de Koning IT b.v.
Abstract This report documents an Operating Expenses (OPEX) study of development options for Shell’s Mariscal Sucre LNG (MSLNG) project offshore Venezuela. The project objective has been for screening purposes to quantify the operational cost range of the different field development options as a result of potential intrinsic well equipment failures. Two well cases have been established and analysed for two different intervention strategies as part of the study:
1. Dry and subsea X-mas tree gas wells with immediate failure remediation of upper completion and wellhead/subsea equipment as required to minimise well downtime and safety unavailability.
2. Dry and subsea X-mas tree gas wells with average 5-year periodic rig intervention following field drilling campaigns to minimise rig intervention costs. Note however that light vessel and surface remediation work in this case is performed immediately as required.

Amongst others, the following performance measures have been established for the well cases and three field development options defined in this study:
- Well/Field intervention costs (OPEX)
- Well/Field intervention frequency
- Well downtime and average well/field production availability

Client Statoil
Abstract This report gives an evaluation of the Åsgard well intervention requirements. The analysis is based on the most recent reliability data on TR-SCSSV and other completion items included in WellMaster. Generic data from the OREDA handbook was available for x-mas tree failures.

The study includes the following well types
• Midgard - gas producer
• Smørbukk - gas/condensate producer
• Smørbukk and Smørbukk Sør - gas injector
• Smørbukk Sør - oil producer

For each well type the following simulations have been performed:
• Insert of WR-SCSSV in the event of TR-SCSSV failure
• Replacement of TR-SCSSV in the event of TR-SCSSV failure

Client Statoil
Abstract 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.

Client Sakhalin Energy
Abstract 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

Client Norsk Hydro
Abstract 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.

Client ENI Norge A/S
Abstract The objective of the study has been to assess the leakage risk of three alternative well completion designs for the Goliat field gas lifted oil producers. The three alternative well completion designs consider different schemes for annulus safety as follows:

• Base Case: Gas lifted production wells with no ASV and shallow set TRSCSSV
• Case 1: Gas lifted production wells without ASV, but with TR-SCSSV set deep below the side pocket mandrel (SPM) that holds the gas lift valve (GLV)
• Case 2: Conventional gas lifted production wells with ASV and shallow set TRSCSSV

The study primarily addresses risk associated with release of lift gas inventory from the A-annulus and blowout from the reservoir to the sea during the well production phase. The leakage risk during other phases like drilling, completion and intervention is not included, as these are not deemed significant for the relative ranking purpose of the study. The other well operational phases are, however, included as a source of “external hazards” in the wellhead area (dropped objects).

Subcontractors have been used for separate analyses of consequences of lift gas released at the seabed. Also, a specific analysis related to blowout rates through a failed gas lift valve has been carried out.

Client StatoilHydro Petroleum AS
Abstract The objective of the study has been to assess the leakage risk of two proposed well completion designs for the Gjøa field gas lifted oil producers. Further, the study objective has been to provide a relative ranking of the two proposed completion designs, including a discussion on risk reducing measures that can affect the ranking between the concepts from a total risk level viewpoint. The two alternative well completion designs consider different schemes for annulus safety as follows:

• Base Case: Conventional gas lifted production wells with ASV and shallow set TRSCSSV
• Case II: Gas lifted production wells with no ASV and shallow set TRSCSSV

The study primarily addresses risk associated with release of lift gas inventory from the A-annulus and blowout from the reservoir to the sea during the well production phase. The leakage risk during other phases like drilling, completion, and intervention is not included, as these are not deemed significant for the relative ranking purpose of the study. The other well operational phases are, however, included as a source of “external hazards” in the wellhead area (dropped objects), which potentially can damage and cause a lift gas release or blowout from a neighbouring well.

Subcontractors have been used for separate analyses of consequences of lift gas released at the seabed. Also, a specific analysis related to blowout rates through a failed gas lift valve has been carried out.

Client APA Petroleum Engineering/Total Canada
Abstract In order to help taking a better decision on heavy oil thermal well safety policy, TOTAL Canada launched a risk assessment project with RPS-APA and ExproSoft to better address safety issues with thermal in situ type heavy oil projects. This report documents a risk analysis made to evaluate general steam assisted gravity drainage (SAGD) well risks on basis of a review of historical thermal heavy oil well blowout/release experience data in combination with quantitative fault tree analysis to compare a single SAGD well barrier design versus a hypothetical dual barrier well design. Input data to quantitative modelling in study has been deduced from the OREDA, WellMaster and SubseaMaster component reliability databases.

Client A/S Norske Shell
Abstract This report documents a risk assessment that investigates the effect of variations in Ormen Lange X-mas tree and tandem tubing retrievable-surface controlled subsurface safety valves (TR-SCSSV) test philosophies on overall well safety availability and leakage risk. In particular, deviations from the Norwegian Petroleum Safety Authority’s (PSA) regulations on first year “burn-in” test frequencies for downhole safety valves are considered. The study is based on a common baseline comparison approach where the Ormen Lange well leakage risk level is assessed versus comparative acceptable industry well leakage risk levels.

The well leakage risk level following different X-mas tree and SCSSV test philosophies is assessed in the study using a fault tree modelling approach for well blowout situations in the operational phase. Reliability input data to the study has been based on results from the Ormen Lange SCSSV qualification program coupled with the WellMaster-, SubseaMaster- and OREDA- industry component reliability databases.

Client Chevron Australia
Abstract This report documents an operational quantitative risk analysis (QRA) made for alternative Gorgon wells. Focus of the study has been to assess the intervention requirement and OPEX of two main well completion designs proposed for the Gorgon development. These two options further include some variations in water breakthrough risk, tubing and casing configuration. For the purpose of the study, two main generic well completion cases are modelled:
• Case 1: Subsea HXMT, well completion with a single tubing retrievable safety valve (TR-SCSSV) with insert SCSSV (WR-SCSSV) capability.
• Case 2: Subsea HXMT, well completion with two tubing retrievable safety valves (TR-SCSSV) with insert SCSSV capability in a hot back-up configuration.

To account for Gorgon well casing alternatives, two well options have been defined in addition to the well completion cases. One option including traditional full length threaded production casing and the other involving large bore production casing which is parted with a liner hang-off. The (11 ¾”) production packer is set in liner making the liner hanger/packer part of well barrier envelope.

Client Statoil
Abstract The objective of the study has been to assess the risk related to operation of the Tyrihans subsea gas lifted oil producers for the following three different completion designs:

• Base Case: Gas lifted production wells with ASV and shallow set TRSCSSV
• Case II: Gas lifted production wells with no ASV and shallow set TRSCSSV
• Case III: Gas lifted production wells with no ASV and deep set TRSCSSV

The study primarily addresses uncontrolled leakage of gas lift gas and blowout from the reservoir to the sea during the production phase. Blowouts during drilling, completion and workover in a specific well are not included. Drilling, completion, and workover operations are, however, included as a potential dropped objects source.

Subcontractors have carried out separate analyses related to consequences of gas released at the seafloor. Further, a specific analysis related to blowout rates through a failed gas lift valve has been carried out.

Client Statoil
Abstract The objective of the study has been to assess the risk related to operation of the Skinfaks N-template gas lifted oil producing wells for the following three different completion designs:

• Base Case: Gas lifted production wells with ASV and shallow set TRSCSSV
• Case II: Gas lifted production wells with no ASV and shallow set TRSCSSV
• Case III: Gas lifted production wells with no ASV and deepset TRSCSSV

The study primarily addresses uncontrolled leakage of gas lift gas and blowout from the reservoir to the sea during the production phase. Blowouts during drilling, completion and workover in a specific well are not included. Drilling, completion, and workover operations are, however, included as a potential dropped objects source.

Subcontractors have carried out separate analyses related to consequences of gas released at the seafloor. Further, a specific analysis related to blowout rates through a failed gas lift valve has been carried out.

Client Statoil
Abstract The objective of the study has been to assess the risk related to operation of the Norne Satellite gas lifted oil producers for the following three different completion designs:

• Base Case: Gas lifted production wells with ASV and shallow set TR-SCSSV
• Case II: Gas lifted production wells with no ASV and shallow set TR-SCSSV
• Case III: Gas lifted production wells with no ASV and deep set TR-SCSSV

The study primarily addresses uncontrolled leakage of gas lift gas and blowout from the reservoir to the sea during the production phase.

Subcontractors have carried out separate analyses related to consequences of gas released at the seafloor. Further, a specific analysis related to blowout rates through a failed gas lift valve has been carried out.

Client Sakhalin Energy
Abstract This report documents a risk analysis performed to evaluate the reliability and suitability of the Base Case production well gas lift design at Sakhalin Energy’s Piltun development. The focus of this study has been to evaluate the risk of intrinsic equipment failures and external hazardous events that results in escape of the A-annulus lift gas inventory to the environment. The frequency of lift gas releases have been calculated for four distinct release rate categories;

A) Very small: 0+ to 0.3kg/s with a representative rate of 0.1kg/s
B) Small: 0.3 to 3kg/s with a representative rate of 1kg/s
C) Medium: 3 to 30kg/s with a representative rate of 10kg/s
D) Large: >30kg/s with a representative rate of 100kg/s

A coarse assessment of failure induced well intervention requirements and resulting well downtimes has also been included as part of the study.

The study is mainly based on fault tree modelling of the lift gas barrier system. Input data for the study has been obtained from the Piltun total platform risk analysis, and from the WellMaster and OREDA equipment reliability databases.

Client Norsk Hydro
Abstract This report documents a risk analysis performed to evaluate the hydrocarbon leakage risk of alternative valve configurations of chemical injection (CI) systems for surface X-mas trees.

Client Norsk Hydro
Abstract The report is based on four different proposed well completion alternatives for the Ormen Lange gas wells. The wells are 7”/9 5/8” wells with some bottlenecks. The subsea X-mas tree is not included in the analyses, only the casing program and formation.

The reliability data established through the WellMaster study (well equipment reliability data) and a series of assumptions were used as input to the study.

The leak probability for the four different alternatives has been assessed.

Client Norsk Hydro
Abstract 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.

Client Norsk Hydro
Abstract The objective of the study has been to assess and compared the performance of four different subsea X-mas tree concepts for the Ormen Lange project, with emphasis on the wellhead to X-mas tree annulus interface design. Four different X-mas tree annulus access design concepts (all offered by the same vendor) have been evaluated in the study:

1. 6 5/8” wellhead completion tree with a concentric annulus sliding sleeve valve which has nipple profile for wireline override (contingency). The concept accepts use of maximum 7” tubing.
2. 6 3/8” wellhead completion tree with hydraulic annulus sliding sleeve (no contingency feature). The concept accepts use of maximum 7” tubing.
3. 7 1/16” tubing head tree with an annulus by-pass valve arrangement. The concept accepts use of maximum 7 5/8” tubing.
4. 6 3/8”x2” parallel bore wellhead completion tree with hydraulic annulus sliding sleeve valve with wireline (contingency). Contingency option for override operation of valve or to set a plug. The concept accepts use of maximum 7” tubing.

All four concepts are based on a vertical parallel bore X-mas tree design. The trees are different in the way annulus communication is established and routed between the X-mas tree and the downhole well completion at the wellhead interface. For comparison, the study also include some reference results for a conventional parallel bore X-mas tree and a horizontal X-mas tree design.

Client Norsk Hydro
Abstract 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.

Client Sakhalin Energy
Abstract 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.

Client TotalFinaElf
Abstract 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.

Client ConocoPhillips Skandinavia AS
Abstract Water Injection Valves (WIVs) are typically used in water injection wells where there exist a leak in the tubing below the SCSSV and above the production packer. The WIV will then act as the primary barrier for these wells.

There has been reliability issues with these valves, so in 2004 CoPNo started to run a new type of valves to reduce the reliability problems. In this short study the reliability of the WIVs in CoPNo wells were analyzed and test intervals suggested to ensure that the safety availability of a WIV is acceptable.

Client StatoilHydro ASA
Abstract A review of all deviations on the Grane wells were performed to assess the affect these deviations would have on the platform risk level.

Client A/S Norske Shell
Abstract Shell Norge AS asked ExproSoft to perform a quantitative risk assessment of the well integrity for various operational scenarios.

Client ConocoPhillips
Abstract This study is an amendment to the report "Risk Assessment Associated with Annulus Protection of Gas Lifted Wells for Greater Ekofisk Area”

The objective of the study has been to investigate if the use of an ASCV and a HSAS valve in the wellhead instead of an ASV in the well will ensure a safety level that can be accepted.

The safety level for a gas lifted well with an ASV is regarded as the accepted safety level.

Client Statoil
Abstract The objective of the study has been to assess the risk effect of accepting a higher leak criteria for SCSSVs in subsea wells, and further to propose a revised acceptance criteria that will not increase the risk for the Gullfaks area.

A sub-objective has been to form a methodology basis to investigate other subsea areas, with the objective to propose revised NORSOK leak criteria for SCSSVs in subsea wells

The scope of work included the following tasks:
1. Re-familiarization with a previously performed Skinfaks/Rimfaks risk assessment study
2. Assessing the probability of an incident where the SCSSV is the only remaining barrier and evaluate remedial actions
3. Assessing the environmental impact from such leaks to the surroundings
4. Evaluate the risk related to the intervention
5. Evaluation of leak reduction measures
6. Compare risks and conclude

Client ConocoPhillips
Abstract The growing number of old wells is a general concern within the industry. CoPNo realize this situation and wants to develop a basis for a future procedure for risk assessment of wells in operation. ExproSoft was approached by CoPNo and asked to develop a tool for assessment of well risk in the event of well component failures.

Client Statoil
Abstract The objective of the study has been to compare the risk level associated with continuing the current practice in Veslefrikk against an alternative practice which involves well interventions for testing of gas lift valves (a wireline plug must be set below the gas lift valve to allow testing of the GLV).

Client A/S Norske Shell
Abstract The objective of this project has been to establish risk estimates with respect to how an increase of the acceptance leak rate criteria through a closed valve (SCSSV or Master valve) will influence on the risk.

The following tasks have been carried out:
1. Familiarization with study objects
2. Establish barrier models with respect to leaks from the well where the SCSSV is the only remaining barrier
3. Assessing the environmental impact from such leaks to the surroundings
4. Evaluate the risk related to the intervention
5. Evaluation of leak reduction measures
6. Compare risks and conclude

Client Hydro Oil & Energy
Abstract The objective of the study has been to perform an assessment of the risk related to four gas lift designs for the BrageA-11 C well and to compare the risk.

The project has examined different aspects of risk associated with gas lift gas in the annulus.

The four gas lift well designs considered are:

1. Base case: This is the well design as planned, with an ASV
2. Case II: No ASV, Annulus Safety Check Valve (ASCV) located in the VR profile on the gas inlet side of the wellhead
3. Case III: No ASV, a Hydraulic Annulus Safety Check Valve (H-ASCV) located in the VR profile on the gas inlet side of the wellhead. Plugging the opposite outlet of the wellhead with a VR plug and a blind flange
4. Case IV: As an alternative compensating measure for the failed ASV the opposite outlet of the wellhead will be plugged with a VR plug and a blind flange to reduce the possible leakage paths

The results have been merged with the results from the Brage QRAs.

Client Statoil
Abstract The objective of the study has been to perform an assessment of the total risk of two proposed gas lift designs for the Statfjord wells.

The project has examined different aspects of risk associated with gas lift gas in the annulus.

Two main gas lift well designs have been considered:

1. Base case design with an annulus safety valve ASV and one to four gas lift valves (GLV)
2. Retrofit design without ASV, gas lift located in a straddle inside tubing and a hydraulic check valve (H-ASCV) in a dedicated block on the A-annulus outlet

The results have been merged with the results from the Statfjord QRAs

Client Anzon Australia Pty Ltd.
Abstract This report summarizes findings from a brief review of the Basker-2 subsea completion. The objective of this review was to provide an independent view on the Basker-2 completion configuration and general guidance on selection of completion hardware, with emphasis on reliability issues on SCSSVs, packers and downhole flow control devices.

Anzon is not a member of the WellMaster JIP on reliability of well completions. The review is accordingly based on completion reliability data available in the public domain (WellMaster Phase III, 1999), review of available assembly drawings and sound engineering judgment. It is emphasized that the subject study is a coarse assessment completed under a very tight time schedule.

Client Statoil
Abstract The objective of the project has been to assess the effect of the known tubing to annulus communication in the Åsgard production well L-1H on the probability of oil leakage to the environment via the annulus side.

Client ConocoPhillips
Abstract The main objective of the study was to evaluate the risk associated with various alternatives for annulus protection of the wells on the Greater Ekofisk installations. The project has examined different aspects of risk associated with gas lift gas in the annulus. Meetings (Hazop and interviews) with onshore and offshore operating personnel have been arranged in order to identify problems related to gas lift gas equipment, both from an operational and a maintenance viewpoint. Systematic risk analyses have been carried to evaluate the risk related to a large variety of gas lift protection alternatives.

Client ConocoPhillips Norway
Abstract 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.

An extension of the project concerned risk assessment of alternative annulus barrier configurations for new gas lift production wells on the Ekofisk 2/4B platform.

Client Statoil
Abstract The objective of the risk analysis has been to assess the effect of barrier element failures in the Snorre C-4 HT2 well on the well leakage to the surroundings risk, and further to assess the effect of potential risk reducing measures. The blowout risk is assessed to be the dimensioning criterion for the well, and the main basis for definition of risk acceptance criteria in the study has been the estimated blowout risk associated with common industry operating practice of an identical configured well (base case well).

The project is largely based on barrier- and fault tree analysis modelling of the Snorre C-4 HT2 well and a base case well. The component input reliability data for the study is extracted from the WellMaster and the OREDA databases.

Client Norsk Hydro
Abstract The objective of this project was to alternative risk reducing measures/solutions in order to compensate for leaking tubing hanger seals

Client Norsk Hydro
Abstract The objective of the risk analysis has been to assess the effect of the known tubing to annulus communication failure in the A-5AH well on the well leakage to the surroundings probability, and further to assess the effect of potential risk reducing measures. The basis for definition of risk acceptance criteria in the study has been the estimated leakage to the surroundings probability associated with common industry operating practice of an identical configured well (base case well).

The project is based on barrier- and fault tree analysis modelling of the Njord A-5AH and base case well. The component input reliability data for the study is extracted from the WellMaster and the OREDA subsea databases.

Client Norsk Hydro
Abstract 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.

Client Norsk Hydro
Abstract 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.

Client Norsk Hydro
Abstract 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.

Client Norsk Hydro
Abstract 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.

Client Norsk Hydro
Abstract 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.

Client Talisman Energy Norge AS
Abstract Development of a software tool that can be used as a 'well oprational tool' in well delivery process from planning through offshore installations of well completions. Special focus is on: tally handling, visualisation of the wellbore in various phases of well life and on creation of well barrier schematics for the operational phase

Client StatoilHydro Algeria AS
Abstract This course was a basic introduction to drilling fluids for coming drilling supervisors.

Client StatoilHydro ASA
Abstract The objective with this study was to explore risk related to tight gas onshore drilling and production in the US.

Client StatoilHydro ASA
Abstract The work has included collection and review of relevant data for establishing the neccessary well barrier diagrams (WBS) for all Statoil operated wells on the NCS after the merger with Norsk Hydro, and work out the actual diagrams for each individual well (two diagrams per well; As run status, and Monitoring) based on the requirements given in NORSOK D-010 and on detailed additional WBS template requirements set up by Statoil. In all, over 1100 wells have been covered in the project, which was concluded mid March 2010.

Client StatoilHydro Petroleum AS
Abstract Course activity since 2006 with Norsk Hydro through present with Statoil relative to internal recommended method for handling of well annular leaks. This recommended method provides guidance in well operational phase to:

• ensure early detection of downhole leak(s)
• ensure safe diagnosis and that data are recorded and interpreted in order to obtain best possible knowledge about the leak (rate / location / direction / barrier status)
• definition of risk accept criteria
• define and implement measures after a risk evaluation
• improve well completion design for new wells
• ensure consistent handling of leaks in all fields / wells.

The course is given as two separate courses with different focus for operations personnel and well engineers, respectively. Course material also includes basic well design (for operations personnel) – like found at; www.exprobase.com, some historical well incidents and basic well risk analysis theory. By end 2009, most Statoil operations and well engineers had attended the course.

Client BP Norge AS
Abstract The main objective of the guideline is to systematically evaluate the risk after a well leak is identified and to recommend risk reducing measures in order to reduce the risk to an acceptable level.

Well risk is assessed from different perspectives to get a complete understanding of the risk picture. The guideline includes methods to analyze and assess whether risk is acceptable or not. In addition to traditional risk methods the guideline also includes minimum requirements to ensure that commonly accepted industry standards are not neglected.

Client Norsk Hydro
Abstract The work included collection and review of relevant data for establishing the necessary well barrier diagrams (WBS) for the Troll oil (Troll B & C) wells, and work out the actual diagrams for each individual well, based on the requirements given in NORSOK D-010 and on additional WBS template requirements set up by Norsk Hydro.

Client BP Norge AS
Abstract A risk evaluation guide line for evaluating well leaks was developed. The main objective of this guideline is to systematically evaluate the risk after a well leak is identified and to recommend risk reducing measures in order to reduce the risk to an acceptable level. Detailed objectives are:

1 To offer a comprehensive and systematic documentation of the leak situation
2 To identify all aspects of well risk
3 To identify failure causes and failure cause reducing action
4 To identify risk mitigating measures to bring risk to an acceptable level

Client SINTEF IKT Anvendt kybernetikk
Abstract A review of the Transocean Winner Draw work controls were carried out in co-operation with Professor Tor Onshus at NTNU. The objective with the review was to identify why uncontrolled lowering of the block occurred, and to verify a design change to prevent further occurrences.

Client Herbert Smith LLP
Abstract Per Holand Acting as technical expert together with Professor Tor Onshus, NTNU, in the High Court of Justice, Queens Defence Division, Commercial Court, London

Client SICOM AS
Abstract Sicom, Servi and ExproSoft were working together to develop a new concept for a subsea BOP control system, a so-called Modular Control System.

Client Oljeindustriens Landsforening (OLF)
Abstract This report sums up parameters related to subsea pipeline and installation leak experience. The report is mainly based on experience from Norwegian waters, but also supported by a report published in UK that covers leak experience from the complete North Sea area.

Experience from leaks in the US GoM OCS has also been investigated.

Client ChevronTexaco
Abstract The objective of the work was to collect and assess information and data regarding material failures in subsea production systems, mainly from open sources available such as databases, conference and SPE papers/articles, journal articles, company information, open reports from NPD and others, and news bulletins published on the internet and in various news publications. The information and data was presented to Chevron in an Excel style spreadsheet where also information on remedial actions, downtime and loss of production & revenue was given.

Client Norsk Hydro
Abstract The project work has been carried out in two phases to establish a procedure for Norsk Hydro on management of well annular leaks.

The objective of the project has been to establish a simple and general operational procedure for management of well annular leaks within the Norsk Hydro operated fields. Key items in this procedure are:
- The procedure should be applicable for all Norsk Hydro operated fields without the need for major modifications
- The procedure should be in compliance with the governing acts and regulations issued on Health, the Environment and Safety (HES) risk for the upstream sector of the oil industry. In particular, this includes focus on identification and reduction of the activity risk level.
- The procedure should include guidelines for detection, diagnosis, and response to well barrier leaks.

Client Hydro Oil & Energy
Abstract The objective of this study was to perform a review of ExproSoft studies and projects performed for Norsk Hydro, mainly during 2002 and 2003, in order to identify costs and benefits to Norsk Hydro. Both quantitative and qualitative criteria should be used, in order to allow Norsk Hydro to assess future strategies and improvement potential for application of risk and reliability engineering based approaches to managing risk in its new field developments and producing wells.