4. Project review

Evaluation-of-projects-forside
04.11.2013

This chapter contains a review of each project. The review emphasises development in costs and implementation time compared with the plans in the PDO, causes of the development, as well as potential lessons learned from the projects. The review is mainly based on information received from the operators both in the form of written replies to the NPD’s requests, as well as in meetings with the NPD.

 

Contents on this page

  • 4.1 Gjøa
    4.1.1 Project description
    4.1.2 Brief description and status
    4.1.3 Development in project costs and implementation time
    4.1.4 Project experience
    4.1.5 Lessons from the project

  • 4.2 Skarv
    4.2.1 Project description
    4.2.2 Brief description and status
    4.2.3 Development in project costs and implementation time
    4.2.4 Project experience
    4.2.5 Lessons from the project

  • 4.3 Tyrihans
    4.3.1 Project description
    4.3.2 Brief description and status
    4.3.3 Development in project costs and implementation time
    4.3.4 Project experience
    4.3.5 Lessons from the project

  • 4.4 Valhall Redevelopment (Valhall VRD)
    4.4.1 Project description
    4.4.2 Brief description and status
    4.4.3 Development in project costs and implementation time
    4.4.4 Project experience
    4.4.5 Lessons from the project

  • 4.5 Yme
    4.5.1 Project description
    4.5.2 Brief description and status
    4.5.3 Development in project costs and implementation time
    4.5.4 Project experience
    4.5.5 Lessons from the project
     

 

4.1 Gjøa

 

4.1.1 Project description

Gjøa is located in blocks 35/9 and 36/7, approx. 65 km southwest of Florø, 70 km northeast of Troll B and 80 km northeast of Kvitebjørn. Gjøa is located entirely in production licence 153.

Statoil was the operator in the development phase, while Gaz de France is the operator in the operations phase.

In the PDO, recoverable reserves were estimated at 13.2 MSm³ oil and condensate and 39.7 GSm³ gas.

The field is developed with a semi-submersible production platform. Four subsea templates with a total of 13 wells will be connected to the production platform. The Gjøa facility will receive most of its power supply from shore. The Vega and Vega Sør fields are tied in to the Gjøa facility. Gjøa is produced with natural depressurisation. Stabilised oil is exported by pipeline to Troll oljerør II <Troll Oil Pipeline II – Trans.> and on to Mongstad. Rich gas is exported by pipeline to St. Fergus via the FLAGS pipeline system.

 

Licensees June 2013

GDF Suez E&P Norge AS

30%

Petoro AS

30%

Statoil Petroleum AS

20%

A/S Norske Shell

12%

RWE Dea Norge AS

8%

 

Figure 4.1 - Download pdf 

<text in figure:

  • 3. parts tilknytning Vega – Third party tie-in Vega
  • Gasseksport – Gas export
  • Strøm fra land – Power from shore
  • Oljeeksport – Oil export

Figure 4.1 Gjøa development concept

 

4.1.2 Brief description and status

The application for development and operation of Gjøa was submitted to the MPE on 15 December 2006 and approved by the King in Council on 11 May 2007. In the PDO, Gjøa’s production start date was in October 2010, and Gjøa has been producing since 7 November 2010.

Some of the key contracts in the project included: Aker Kværner had an EPCI contract for the production facility. FMC had an EPC contract for the subsea facilities, Transocean had contractual responsibility for drilling and completion, ABB had an EPCI contract for the power cable from shore and NKT had an EPC contract for the flexible risers. The production facility’s deck was built by Aker Kværner Stord, the living quarters was built by Leirvik Modul Teknologi (EPC) and the jacket was built by Samsung Heavy Industries in South Korea (FC contract).

 

4.1.3 Development in project costs and implementation time

 

Table 4.1 Cost development for the Gjøa project from PDO to completion, * Vega’s share of the investment estimate approx. NOK 2.2 billion.

 

 

MNOK (2012)PDO

MNOK (2012)
Completion
2012
 

MNOK (2012)increase


%
increase

Pre-PDO investments

308

286

-22

-7%

Project
personnel
and studies

2988

2580

-408

-13%

Production
platform
- topsides

12336

15198

2862

23%

Production
platform
- hull

1456

1129

-327

-22%

Export
pipelines

3882

3868

-14

0%

Subsea installations

4282

4750

468

11%

Drilling
and wells

5987

7324

1337

22%

Total *

31239 *

35135

3896

12%

 

The Gjøa project had a cost increase of NOK 3 307 million compared with the unbiased estimate in the PDO. However, this is still within the PDO estimate’s uncertainty margin of 20%. The largest growth was within drilling and wells, as well as within the deck facility (topsides) of the production facility.

Less than 50% of the total budget was covered by contracts entered into before the PDO was submitted.

100% of FEED was completed when the PDO was submitted.

 

4.1.4 Project experience

Though this project also experienced cost overruns in relation to the expected estimate in the PDO, the project was a success overall. Start-up only one week behind schedule, as well as a final cost of 10% over the estimate in the PDO is within the uncertainty range described in the PDO plans.

The cost for drilling and wells was one of the parts of the project with the largest increase in relation to the estimate in the PDO. An important reason for the increase was that the original estimated number of days needed for drilling and completion of the wells was too optimistic. With a basis in experience from surrounding fields, the estimates for the number of days was increased significantly after the PDO. The increase was also caused by design changes along the way. For example, it was discovered during the process that sand screens had to be installed instead of the original design with liner and oriented perforations. Furthermore, some of the segments to be drilled turned out to be dry. These planned producers therefore had to be plugged before the next well could be drilled, which also led to a cost increase.

The weight of the topsides was increased by 3 000 tonnes compared with the estimate in the PDO. The topsides costs also increased.

Engineering took longer than planned, and greater resources than assumed were needed. It was more difficult than expected for the supplier to recruit sufficient personnel with experience for the project. The engineering work took place partly in Oslo and partly in Mumbai (India). It took time to establish an efficient cooperation between the two engineering offices, which contributed to reduced efficiency in the beginning.

Another cause of the weight increases was that several of the sub-suppliers focused on delivering on time and at the agreed cost, at the expense of maintaining sufficient focus on keeping the weights within the estimates. The weight therefore increased overall, which had to be offset with other measures.

Late in the project it was discovered that many of the fittings being used on the platform were of poorer quality than what was required. Due to too many incoming orders, the sub-supplier of these fittings had increased capacity in its facility by simplifying and thus breaching the set procedure for heat treatment of the pipes for increased strength. This led to impaired quality and all fittings had to be replaced. The replacement task was extensive, and made a considerable contribution to the cost increase for the topsides. Using incentives, a joint willingness to solve the problems was achieved, thus avoiding major delays in the project.

Construction of the jacket in Korea took place in accordance with quality, costs and the schedule. The hull supplier was required to review the engineering work Aker had carried out, and therefore visited with Aker in Oslo prior to starting up to ensure Aker’s design and Norwegian standards were completely understood. Pre-fabrication meetings were also held with the supplier and sub-suppliers to ensure the sub-suppliers had a sound understanding of the requirements. This was important to achieve the desired quality and progress.

Having a well-defined work scope, as well as being able to handle changes in an orderly manner was very important to achieve a good result in the construction contract with Samsung. With a well-defined work scope, the operator was able to limit the changes along the way to a minimum. Only one major change was implemented along the way during construction. Despite this, when the change was described in detail and handled in an orderly manner, Samsung was able to complete the delivery on schedule and at a lower cost than the operator had budgeted for.

The operator had a team with both technical and commercial expertise for follow-up of the construction contract with Samsung. They also hired a local company to follow-up specific quality requirements. This company worked at the construction site to inspect the quality of the work being carried out. Prior to the construction, these personnel also visited Norway to familiarise themselves with Norwegian requirements and standards.

After the start-up in November 2010, vibration problems were discovered in the gas export risers. This resulted in significantly lower gas export for 2011 than planned. The riser was replaced around the turn of the year 2011/2012.

According to information from the operator, the partnership was active in the project. Besides active participation and input at licence meetings (TC/MC), as well as joint workshops during the project, the other licensees carried out a PEER review on the operator’s geology and reservoir work. “Value Improvements Processes” (VIP) were carried out with participation from the entire licensee group where proposed improvements were included in the project. Shell’s system for maturing and project status was adopted and used in the project. In addition to Statoil’s internal benchmarks, the other licensees carried out their own, independent benchmarks. Statoil, as the operator during the development phase, had a close cooperation with the operator for the operations phase (GdfSuez) and GdfSuez personnel participated in Statoil’s development team. The project had a quality and safety supervisor from Shell.

 

4.1.5 Lessons from the project

A key lesson from the Gjøa project is the importance of maintaining a focus and control over the uncertainty associated with the reservoir. All licensees agreed at an early stage on the best strategy for draining the resources in the best possible manner. When this decision was made, it was also important that all licensees were able to stand by this decision without having to renegotiate along the way.

The right decisions at the right time are necessary to achieve a successful project. The crucial factor is then being able to prepare a sufficient basis for making these decisions. Having the right personnel in the key disciplines for all phases of a project will ensure this. This is particularly important during an early phase of the project as decisions that are not optimal could delay the project and lead to additional problems along the way.

To ensure the right quality is delivered for construction, it is very important to have a dedicated follow-up team with the correct expertise at the construction site. If external personnel will be used to assist in the follow-up work, it must be ensured that they have extensive knowledge of Norwegian regulations and standards.

Prequalification of relevant suppliers for the project was a key activity in order to succeed with a good project implementation on Gjøa. In general, the operator succeeded by using companies that were able to deliver in accordance with the requirements stipulated by the project. The sub-supper of fittings in the Gjøa project had previously been qualified through the operator’s extensive system for prequalification of suppliers. Due to a high activity level, the sub-supplier did not use the same procedures used when the operator carried out the prequalification. This shows that prequalification of suppliers provides no guarantee for good deliveries, but is still an important contribution in reducing project risk.

  

4.2 Skarv

 

4.2.1 Project description

Skarv is located in production licences 212, 212B, 262 and 159 and is situated in the Norwegian Sea about halfway between Norne and Heidrun. The development is a unitisation of the 6507/5-1 (Skarv) and 6507/3-3 (Idun) deposits. The 6507/5-3(Snadd) deposit is included in Skarv, but is not yet part of the development. Water depth is between 350 – 450 metres. Recoverable reserves have been estimated at 43.4 GSm³ gas and 15.5 MSm³ oil and 5.6 mill. tonnes NGL.

The field is developed with a floating production storage and offloading installation (FPSO). Five subsea templates are tied in to the ship. The oil is buoy-loaded onto tanker ships, while the gas is transported via an 80 km pipeline to Åsgard Transport.

The PDO called for 16 wells, seven oil producers, five gas producers and four gas injectors. The plan is to return the gas injectors to gas producers during the late phase of the field’s lifetime.

 

Licensees June 2013

Statoil Petroleum AS

36.17%

E.ON E&P Norge AS

28.08%

BP Norge AS

23.84%

PGNiG Norway AS

11.92%

 

BP is the operator for development and operation of the field.

 

Figure 4.2 - Download pdf 

Figure 4.2 Skarv development concept

 

4.2.2 Brief description and status

The application for development and operation of Skarv was submitted to the MPE on 29 June 2007 and approved by the King in Council on 9 November 2007. The project consisted of two main elements:

  • Drilling and wells, which includes lease of a drilling rig and costs of well materials.
  • Facilities, which includes a production facility, subsea templates including pipelines and umbilicals and gas export pipelines.

The production facility was manufactured by Samsung in South Korea via an EPC contract, the turret was manufactured by SBM in Singapore as a sub-contract for the production facility. The subsea equipment was built by Vetco.

Skarv has been producing since the turn of the year 2012/2013.

 

4.2.3 Development in project costs and implementation time

Skarv FPSO was impacted by major cost increases and a very delayed start-up.

 

 

Table 4.2 Cost development for the Skarv project from PDO to completion

 

MNOK (2012)
PDO

MNOK
(2012)
Completion
(June 2013)

MNOK (2012)change

% change

Project Management
Team/ Owners’ costs

4987

6509

1522

31%

Engineering, procurement & construction management

1412

1779

367

26%

FPSO Hull & Living Quarters, Marine operations

3772

3485

-287

-8%

FPSO Topsides Fabrication, Integration,
Control system & Major Equipment

6438

9994

3556

55%

Turret & Mooring System

2289

2765

476

21%

SURF (Subsea Production System, Umbilicals, Risers & Flowlines)

7391

10882

3491

47%

Gas Export
Pipeline

2101

1721

-380

-18%

Drilling & Completions

6651

9248

2597

39%

 

Total

 

35038

 

46379

 

11341

 

32%

 

Drilling of production wells started in 2010. The production ship was completed and installed on the field in August 2011. Skarv was scheduled to start producing in August 2011, but due to major delays for various reasons, production did not start until the turn of the year 2012/2013.

50% of the total budget was covered by contracts entered into before the PDO was submitted.

59% of FEED was completed when the PDO was submitted.

 

4.2.4 Project experience

The operator notes deficient follow-up of the turret constructed in Singapore as a main reason for the overruns. One month was set aside in the original plans for mechanical completion at Stord following transport from South Korea before the ship went out to the field. The production ship arrived at Stord according to the plan, and at this time the licensees still maintained the planned production start-up date. However, several leaks were discovered in the turret that needed to be repaired, and the time at Stord was extended to five months. This delay also led to missing the planned weather window for pulling in risers. More faults and deficiencies were discovered during this period in the crane vessels that were be used in connection with the offshore installation. However, a decision was made to keep the installation vessels at the field so they could use “good weather periods” for installation work. However, there were very few of these periods, so pulling in risers during autumn and winter was not possible. Having specialised vessels remaining idle on location is costly.

The operator experienced the greatest challenges during the construction phase in connection with building the FPSO and understanding of Norwegian working environment requirements. Neither the supplier nor operator had a sufficient focus on these requirements at an early stage in the construction phase. Faults and deficiencies were therefore discovered late, and it became challenging and cost-intensive to comply with requirements.

The consequences of the Norwegian Working Environment Act, particularly with regard to use of overtime, were miscalculated in the operator’s early estimates. This led to work performed in Norway becoming more personnel-intensive than assumed in the PDO.

The delayed commissioning was worsened by the operator not being granted an exemption for using 25 reversible beds, as was planned.

Several equipment packages were ordered early due to long delivery times. However, engineering was not sufficiently completed when the equipment was ordered. This led to many changes along the way, which in turn led to cost overruns and delays.

The operator was early in securing a rig for drilling wells. Rates for this new rig were used as a basis for the estimates at an early phase. It turned out after a short while that this rig would not be finished in time, and the operator therefore decided to terminate the contract with the rig supplier. By signing a new contract with another supplier, the operator ensured the wells would be drilled on time. The new contract was more expensive than the original and led to increased drilling costs.

According to information from the operator, the project and project progress were regularly reviewed with the other licensees. Until start-up of the field, all-day workshops were held every three months prior to the technical committee meeting, relating to cost development and further plans. Meetings were also held in the licensee group to address specific technical issues. Technical expertise from the operator, as well as other licensees, participated in these meetings. Internal benchmarking was carried out based on the operator’s project experience data and from use of consultants. There were no personnel from the other licensees in the project organisation.

 

4.2.5 Lessons from the project

The operator experienced many problems with equipment packages and their quality. Some equipment packages turned out to be so important to follow up with regard to time, quality and cost that they should have been excluded from the contract with the main contractor and followed up directly by the operator. This should have been done from the beginning.

The project experienced major delays and cost overruns due to deficient vessels. In hindsight, this could have been avoided with more time set aside for prequalification of companies and quality control of the vessels prior to entering into the installation contracts.

Putting all marine operations under one contract turned out to be a successful action according to the operator. There are many operations that need to be performed simultaneously, and coordination of these activities is therefore important. The fact that one supplier handled all interfaces between these operations simplified prioritisation of the operations.

Involving operations personnel early in the project is generally very important to achieve a facility which facilitates sound operations. The operator also involved operations personnel in this project, but inadequate continuity of operations personnel during the construction phase was unfortunate. Several of the requests from the operations personnel during the construction phase were therefore not sufficiently anchored in the project management and resulted in some cases of additional work and cost increases.

The project experienced several suppliers being unable to deliver what they had promised. Decisions were therefore made along the way to replace suppliers and terminate some of the contracts. Had this not been done, the delays and cost overruns would have been even greater. According to the operator, the ability to be bold enough to replace suppliers along the way was important for realisation of the project, and was thus an important lesson learned.

During construction of the platform, the operator had many discussions with the contractor regarding change orders. Having a strong commercial team at the construction site thus turned out to be very valuable. Many of the proposed changes were communicated at an early stage and the final cost was far lower than had the change orders been accepted uncritically.

Another lesson is that the accommodation needs in connection with offshore hook-up and completion should have been taken into consideration to a greater extent when the final bed capacity at the ship (FPSO) was determined.

 


4.3 Tyrihans

 

4.3.1 Project description

Tyrihans consists of Tyrihans Nord and Tyrihans Sør and is located in blocks 6406/3 and 6407/1. The field is located in the southern part of Haltenbanken, 40 km southeast of Kristin and 170 km from Vikna on the border between Nord-Trøndelag County and Nordland County.

Tyrihans is part of production licences 073, 073B and 091. Statoil is the operator on the field. Total recoverable reserves were estimated at 29 MSm³ oil and 34.8 GSm³ gas in the PDO.

The field is developed with a subsea production facility tied in to Kristin for processing of the wellstream and Åsgard B for import of gas for gas injection.

In the PDO, the plan was for Tyrihans to be developed with 12 wells distributed over five templates. Of these, 11 were scheduled to be drilled by 2011 and one in 2015.

Production started as planned in July 2009.

 

Licensees June 2013

Statoil Petroleum AS

58.84%

Total E&P Norge AS

23.15%

Exxon Mobil Exploration & Production Norway AS

11.79%

Eni Norge AS

6.23%

 

Figure 4.3 - Download pdf 

Figure 4.3 Tyrihans development concept

 

4.3.2 Brief description and status

The application for development and operation of Tyrihans was submitted to the MPE on 11 July 2005 and approved by the King in Council on 2 December 2005.

A large part of the Tyrihans development was based on use of new technology that had to be qualified. This primarily applied to the subsea production systems, where subsea pumps were chosen for injection of raw seawater. This had not previously been done on the Norwegian shelf. Aker was awarded the contract for delivering these pumps. FMC had the EPC contract for the subsea facility. An advanced control and workover system was subject to qualification here. Nexan had a contract for delivery of the umbilical and DEH (direct electrical heating). DEH also required qualification as this was used on pipelines over longer distances than ever before for Tyrihans. Acergy had a contract for installing pipelines. Reinertsen was awarded an EPC contract for necessary modification work on Kristin, and a contract was signed with Transocean Arctic for drilling the wells.

Production started as planned in July 2009 with production from four wells.

4.3.3 Development in project costs and implementation time

 

Table 4.3 Cost development for the Tyrihans project from PDO to completion

 

MNOK (2012)PDO

MNOK (2012) Completion(Sept. 2013)

MNOK (2012) Change

 

%
change

Project
management

198

180

-18

-9%

Insurance

218

219

1

0.5%

Modifications
Åsgard

390

251

-139

-36%

Modifications
Kristin

692

1353

661

96%

Low pressure separator Kristin

468

 

 

 

Subsea
prod. system

5595

7248

1653

30%

Drilling/
completion

6498

7377

879

14%

Total

14059

16627

2568

18%

 

Eleven wells have been drilled in Tyrihans as of September 2013. The PDO estimate assumed that 11 wells would be producing by 2011, i.e. two years after production start-up and that the 12th well would be drilled in 2015. Drilling of the wells has taken somewhat longer than planned. The reason for this was that most of the production wells were optimised with a significantly longer horizontal section in the reservoir which has, however, turned out to be beneficial for the recovery. Tyrihans is now planning to have more wells than assumed in the PDO with an expected higher recovery rate.

An estimated 10% of the total budget was covered by contracts entered into before the PDO was submitted.

100% of FEED was completed upon PDO submission.

 

4.3.4 Project experience

Important development elements with new technology were identified early on as one of the major risks in the project. To achieve sound project control over these key elements in the development, the operator chose to enter into direct contracts with the suppliers of these equipment components. This e.g. related to deliveries of both subsea pumps for injection of raw seawater and deliveries of pipes with direct heating. In retrospect, this is considered a successful strategy. Furthermore, the scope of work was well-defined in the PDO, which was an important reason why there was only one change after the PDO was approved.

Due to a clearly identified risk picture and a focus on qualification of new technology, this part of the project proceeded as expected. It was more challenging to get all necessary deliveries in place at the right time so as to not inhibit progress.

The cost increase for the subsea facility was mainly caused by an increase in key input factors due to a major increase in the activity level in the period 2005/2006.

For the Kristin modifications, the cost increase was e.g. caused by a significantly higher number of engineering hours than assumed, and that the weights increased to twice the estimate. Initially, it was not assumed that there was major risk associated with implementation of the modification on Kristin. It was not considered to be critical, and the work therefore did not start immediately after the PDO was approved. However, the operator sees in hindsight that the complexity and scope of modification work on Kristin was underestimated and that this work could well have started earlier. Modification work simultaneously with operations on Kristin was more complicated than previously assumed. Efforts required to achieve the planned production start-up contributed to cost increases.

The progress in the engineering was deficient and ended up behind schedule. The modification work therefore started before the drawing basis was sufficiently completed. This e.g. resulted in some work being done in the incorrect order and having to redo the same work. The reason for the problems was primarily that the supplier lacked personnel with sufficient experience to perform the engineering as planned. There was a high activity level in the industry and thus difficult to increase staffing through recruitment or loan of personnel from partners, which was a precondition when entering into contracts.

According to information from the operator, the licensee group was highly involved and contributed in a constructive manner through the licence meetings (TC/MC) both during the planning and implementation phases. A review was carried out during the implementation phase of the scope of work on topsides with associated plans. The entire licensee group participated in this. There were no formal benchmarks in the project beyond assessing the Tyrihans project against others based on the steep price development the project experienced in 2006 and 2007. No personnel from the licensees participated in the operator’s project organisation.

 

4.3.5 Lessons from the project

Tyrihans was a successful project delivered at the expected cost and time. The project experienced some challenges along the way, but was still able to stay within the planned implementation time and budget. The most important lessons learned from the project are:

Implementation of the subsea facility aspect of the project went according to plan. An important success factor was that the implementation took place based on a well-defined scope of work in the PDO. There was only one significant change during the construction phase.

Qualification of new technology was identified early on as one of the largest risks in the project. The operator therefore chose to remain in control of choosing important new technology and entered into direct contracts with suppliers of these technology elements. This was successful and deliveries in these parts of the project took place according to plan.

Understanding and maturing of the scope of work of a modification was underestimated in the project. This should have been assigned greater focus, and it should have been confirmed that the supplier had sufficient personnel resources for good engineering prior to entering into contracts.

Good interaction between the various disciplines in the company is crucial. Operation of the Kristin field in parallel with modification work resulted in challenges along the way with regard to prioritisation of personnel and offshore bed capacity.

 

 

4.4 Valhall Redevelopment
(Valhall VRD)

 

4.4.1 Project description

The Valhall field is located in blocks 2/8 and 2/11 in the southernmost part of the Norwegian continental shelf. BP is the operator of the field.

The first platforms on the Valhall field were installed in 1981, and started producing in 1982. The field has subsequently been developed in multiple phases. The first phase consisted of a processing platform, a drilling platform and a living quarters platform. A wellhead platform and a water injection platform were subsequently installed on the field.

Redevelopment of the field comprises installation of a new process platform and extensive modification work on the existing platforms for extended operations and adaptation to future production on the field. The remaining reserves on the field are 41.5 million Sm3 oil, 6.9 billion Sm3 gas and 2.2 million tonnes NGL.

 

Licensees June 2013

Hess Norge AS

64.05%

BP Norge AS

35.95%

 

Figure 4.4 Download pdf 

Figure 4.4 Valhall Redevelopment concept

 

4.4.2 Brief description and status

The application for development and operation of Valhall VRD was submitted on 22 March 2007 and approved by the King in Council on 25 May 2007.

Valhall VRD was first initiated due to subsidence and expiry of the design lifetime of the existing field centre. Furthermore, there was a need for a facility more adapted to the future needs on the field. The project was complex as it included both newbuilds, a considerable modification of the existing facility, as well as new technology in connection with transition to electricity from shore. In addition, it was assumed that the project would be carried out with simultaneous operations at the existing facility. The project consisted of a new steel platform resting on the seabed for production and accommodation, connected by gangway to the existing Valhall centre. The project included a conversion from gas-generated power to power from shore via a DC interconnector from Lista.

Engineering was carried out by Mustang (US). The new platform was mainly built at four different locations: The living quarters module in STL (UK), the jacket at Aker Verdal, construction and hook up of the deck facility at Heerema (Holland). Furthermore, ABB was responsible for power from shore and Subsea7 was responsible for all pipe work. About 45% of the contracts went to Norwegian suppliers.

Following considerable delays and cost overruns, production from the new field centre started on 26 January 2013.

 

4.4.3 Development in project costs and implementation time

 

Table 4.4 The cost development for Valhall VRD from PDO (2007) to completion in 2013

 

MNOK (2012)PDO

 

MNOK (2012)Completion (May 2013)

MNOK (2012)Change from PDO

%Change from PDO

Project
owners

2098

2101

3

0%

Ready for
Operations

807

1000

193

24%

Topsides

5322

7691

2369

45%

Structure

620

689

69

11%

Power from
Shore

1841

2067

226

12%

Living
Quarters

833

1903

1070

128%

Safety
Automation
Systems

440

618

178

40%

Transport and installations

584

552

-32

-5%

Subsea
pipelines

642

1262

620

97%

Brownfield Modifications

1482

3137

1655

112%

Hook Up and Commissioning

720

5503

4783

664%

Project
Handover

 

567

567

 

Un-Allocated provision

 

-2205

-2205

 

TOTAL

15391

24887

9496

62%

 

 

 

 

 

Well costs Valhall Redevelopment

3277

13986

10709

327%

 

The expected start-up in the PDO was November 2010, i.e. a project implementation time of three years and eight months. However, the actual start-up was in January 2013 which results in a total project implementation of five years and nine months. The project was therefore two years and one month delayed in relation to expected start-up in the PDO. The field was shut down for six months in connection with hook up and commissioning of VRD. The planned shutdown in the PDO was three months.

40% of the total budget was covered by contracts entered into before the PDO was submitted. 100% of FEED was completed when the PDO was submitted.

 

4.4.4 Project experience

A powerful wave hit the field centre at Valhall in November 2006, causing considerable damage to both the production facility and living quarters platform. Several lifeboats were also torn off the facility. Due to this incident, the operator pushed forward the Valhall VRD plans, and the project was under major pressure to be carried out quickly. The project was therefore schedule-driven from the start. Too little time and too few resources were used in the early phase of the project. This led to underestimating dimensions and the weight of the new platform, which was first discovered late in the detail engineering phase. For example, in FEED it was concluded that the platform could be lifted in place in two lifts. Late in the detail engineering phase this was changed to five lifts, which entailed completely different requirements for time and resource use in the hook up and commissioning phase than previously assumed. Another indication that sufficient time was not allocated in the early engineering phase was that a very high number of change orders were initiated during the implementation phase of the project.

The results of a new Valhall reservoir review were also published in the early phase of the project (late 2006). This concluded that the future potential at the field was far smaller than previously assumed. Consequently, Valhall VRD should, based on this, have been subject to an audit both with regard to dimensions and thet design lifetime it was constructed for. However, it was considered that there was not enough time for this, and the plans were therefore continued as they were.

Valhall VRD was designed for a 40-year lifetime as a long production period was originally expected. A 40-year lifetime generally sets higher requirements for material qualities than is the case for a 25-year design lifetime. These materials are more expensive, and some areas require more special expertise for processing in the construction phase. A far tighter market than assumed in the PDO resulted in the project experiencing a general scarcity of expertise. This was particularly evident in areas where special expertise was required. For example, there was a lack of qualified welders that could weld titanium. It was challenging for the suppliers to deliver equipment with sufficient quality. A tight market in combination with special design requirements therefore contributed to cost increases, quality issues and delays.

Though the operator chose many experienced and recognised equipment suppliers, there was a high degree of flaws and inadequacies in many equipment packages. This was in part caused by deficient quality follow-up of the sub-suppliers. The quality inadequacies were discovered late, and entailed correction work and detailed mechanical completion, which in turn impacted final commissioning and start-up.

The company responsible for construction of the new living quarters module went bankrupt before the work was completed. BP then had to go in and secure operations until completion. This was both resource-intensive and costly for the project.

The challenge of offshore hook up and commissioning/start-up simultaneously with operation of existing facilities was underestimated in the PDO. Simultaneous operations also made all necessary modification work on existing facilities considerably more challenging than assumed in the PDO. Prioritisation of the limited bed capacity became a source of continuous discussion between the project and operations organisation. Use of a flotel that was not permanently anchored contributed further complications. This was far more weather-sensitive than a permanently anchored flotel and resulted in the flotel being disconnected for large parts of the time. Completion of the project therefore took longer than estimated.

The increase in well costs is caused by development in reservoir understanding and a much greater need for wells than assumed in the PDO. The costs associated with drilling and completion of the individual wells was also higher than expected.

According to information from the operator, frequent updates were provided with reviews of the project status in the partnership. Formally, this took place in the quarterly licence meetings (TC, MC). The partnership also supported the work by making the companies’ experts available to the project prior to decision points during the project. The operator carried out a benchmark of the project based on project experience data, as well as using external consultants. Many senior personnel from Hess participated in the project organisation, e.g. as

"PH Offshore Delivery managers" and "Hook Up and Commissioning managers".

 

4.4.5 Lessons from the project

Too little time was spent at the early phase of the project. The project should have incorporated the new reservoir information and conducted a new design review which could have entailed changes in the topsides weight, size, requirements for design lifetime, number of change orders along the way and offshore hook up. The fact that the project was driven by an implementation plan from the start was unfortunate and had major consequences in the further project implementation.

Follow-up of quality in large equipment packages was inadequate. The lesson learned is that the operator should have had a more direct supervision of fabrication of the large equipment packages, including the work from the sub-suppliers.

The challenges in connection with modification work, hook up, completion and start-up of new facilities, in parallel with maintaining operations of existing facilities, was underestimated. This was very complex and the need for offshore bed capacity was underestimated.

 

4.5 Yme

 

4.5.1 Project description 

Yme is located in blocks 9/2 and 9/5 and is situated approx. 100 km from the Norwegian coast. Water depths at Yme are between 77-93 metres. Yme was originally developed and operated by Statoil up to 2001 when production ceased. The plan was for Yme to be the first field to be reopened on the Norwegian shelf.

Talisman is the operator of the field.

The licensees planned to develop Yme with a mobile production facility with storage. This is the same concept used on the Siri field in the Danish sector. In principle, this is a jack-up platform over a storage tank on the seabed.

The Yme PDO called for a development with 12 wells – seven producers and five injectors. The recoverable reserves are 14.1 million Sm3 oil. Planned production start was in February 2009.

 

Licensees June 2013

Talisman Energy Norge AS

60%

Lotos Exploration and Production Norge AS

20%

Wintershall Norge AS

10%

Norske AEDC A/S

10%

 

Figure 4.5 - Download pdf 

Figure 4.5 Yme development concept

 

4.5.2 Brief description and status 

The application for development and operation of Yme re-development was submitted to the MPE on 9 January 2007 and approved by the Government on 11 May 2007. The project consisted of three main elements:

  • Drilling/completion of production and injection wells
  • Subsea production facilities, including pipelines and umbilicals
  • Construction of a leased mobile production unit with storage (MOPU)

For the MOPU, an EPCIC contract was signed with Single Buoy Moorings Inc. (SBM), which would also be the owners of the facility. The Yme licensees were then to pay rent to SBM under a so-called Bareboat Charter agreement throughout the field's lifetime.

The storage tank was installed on the field in the summer of 2008, followed by start-up of drilling and well completion. The subsea production facility, pipelines and umbilicals were completed in 2009 according to schedule. As regards the MOPU, however, it was installed offshore almost three years later than planned – in the summer of 2011. Significant faults and defects were identified on the MOPU in parallel with the installation offshore. This caused an increase in the completion work offshore and the MOPU delays continued. In July 2012, the operator decided to remove personnel from the MOPU due to the discovery of significant structural design faults, in addition to cracks in the foundation which fastened the MOPU to the storage tank on the seabed. In December 2012, the owner, SBM, decided to scrap MOPU. Therefore, the project as described in the 2007 PDO will never be realised. On this basis, the licensees have applied to the Ministry of Petroleum and Energy (MPE) for approval of deviations from the PDO in order to replace the MOPU with an alternative production facility.

 

4.5.3 Development in project costs and implementation time 


Table 4.5 Cost development for the Yme project from PDO to cessation

 

MNOK
2012 at
PDO

MNOK
2012
Dec. 2012

MNOK
2012
increase

% increase

Wells

3076

4299

1223

+40%

Subsea
facility

1159

1350

192

17%

Mobilisation and insuring facilities

209

3595

3386

1620%

Project
management

450

2315

1865

414%

 

Total

 

4894

 

11558

 

6664

 

136%

 

An additional production well was drilled compared with the number of production wells described in the PDO. The planned wells were somewhat more expensive due to the drilling of extra sidetracks to adjust for coal formations that were encountered. Moreover, the cost estimate in the PDO had a limited contingency for dealing with unforeseen incidents. Including such a contingency is common practice when estimating costs, and the drilling cost estimate was therefore rather optimistic.

The increase in "Mobilisation & insuring facilities" is linked to direct financial contributions to SBM during the course of the construction phase in order to enhance progress and quality. These were either direct intervention payments from the operator/licensees or payments pursuant to "Side Agreements" to the contract negotiated because interim progress and deliveries were not in accordance with the main contract. These factors were not incorporated in the PDO assumptions and were not included in the cost estimate. Therefore, this portion of the costs was estimated at a relatively small amount in the PDO.

The cost development in Project management is also linked to the fact that the operator identified an increased need for own follow-up during the construction process, as well as that the duration of the project became much longer than estimated in the PDO. This caused an increase in the operator's project follow-up costs.

The total project implementation from start-up of detail engineering to production start was estimated as two years and four months in the PDO. Six years and three months into the project, the licensees decided to halt the project even though it was not completed.

About 2% of the total budget was covered by contracts entered into before PDO submission.

Large parts of the necessary FEED documentation were not complete when the PDO was submitted.

 

4.5.4 Project experience 

Drilling/completion of the subsea facilities was completed without major time and cost overruns. Therefore, the further description of project experience will focus on the design and construction of the MOPU production unit. It was this part of the project that caused substantial additional work, delays and cost overruns. 

Hindsight reveals some crucial errors in judgement in the important early phase of the project. The project was considered to be economically marginal, and it could only become financially robust through a development with little extra cost exposure in the early phase. In terms of value, it was considered better to distribute the costs over the field's lifetime. The economic lifetime of the project was also very uncertain, and the licensees therefore decided in the early screening phase to base the development solution selection on a leased concept. This thus became a normative assumption for further realisation of the project.

The operating company generally had little development experience and had not yet implemented a good internal decision system with sufficient quality assurance and maturing of projects up to final project approval, in line with the established industry standards in this area. While the operator had involved Norwegian employees with development experience from other projects on the Norwegian shelf in the Yme project, the operator only had experience from developments in the UK sector going back to 2003, and no development experience as operator on the Norwegian shelf. A leasing concept with a lump sum EPCIC contract therefore appeared attractive, as the responsibility under the contract for the entire project implementation, from engineering, procurement, building the installation to commissioning, rested with the contractor.

In general, there were few bidders in the tender process. In practice, SBM emerged as the only real candidate. After a review of all bidders, the others were either considered to be unqualified or were eliminated from the list for other reasons.

The possibility of carrying out well intervention was an important criterion for selecting the development solution. SBM's MOPU solution would provide both "dry" wellheads and oil storage, and was thus regarded as being more attractive than the other leasing options. SBM owned Gusto engineering, the developer of the MOPU concept. This concept had also been used by Statoil on the Danish Siri field, and was therefore regarded as being well-suited for petroleum activity on the Norwegian shelf as well. SBM was the world's largest operator of FPSOs, and the company also had good HSE statistics. Moreover, the company also had experience with several shipyards in Asia.

Based on this, there was a great deal of confidence that SBM could deliver according to the bid it had submitted, in spite of the fact that SBM also lacked experience in implementing major construction projects entailing building according to Norwegian requirements. Although the licensees had identified the supplier's lack of experience with Norwegian offshore projects as an implementation risk, critical questions surrounding this factor were not granted sufficient weight in the licensees' selection of contractor.

The contract entered into with SBM was characterised by considerable optimism. Far too little consideration was given to the possibility that everything might not go according to plan. SBM owned the facility. The most important incentive SBM had was to complete engineering, procurement, fabrication and construction so that the field could start up and the company could start to collect rental income. Therefore, from the very beginning, the project was driven by the desire to achieve completion at the earliest possible date (schedule-driven). This was a poor point of departure for achieving good project quality. The consequences for the Yme project were insufficient allocation of time for both completion of the FEED phase or detail engineering prior to fabrication. The detail engineering started before the FEED phase was completed, and fabrication and procurement were initiated far too early in relation to completion of detail engineering. In short, this led to a lot of futile fabrication work that had to be done over. This led to schedule delays, cost overruns, and a significant increase in the weight of the facility. The deck facilities on MOPU had an overall weight increase of 39%.

Prior to the PDO, the operator had identified that lack of compliance with Norwegian regulatory requirements and standards could pose an important risk for project implementation. Several measures were therefore instituted in the form of seminars, courses, as well as follow-up of the contractor's engineers with a view toward reducing this risk. However, these measures fell short. A lack of understanding of Norwegian regulations and NORSOK standards was a pervasive problem through the entire construction phase, and was the reason why much of the work had to be done over. This lack of expertise and understanding was a problem both on the part of the contractor as well as subcontractors. More and more nonconformities were uncovered as the production unit was gradually completed. In general, there were nonconformities in all system areas, with a particularly high number within working environment and technical safety. According to the contract form selected, there should, in principle, have been no need for extremely vigilant follow-up by the operator throughout the project. The operator had established a small project follow-up team consisting of experienced Norwegian professionals in Abu Dhabi with the aim of following the MOPU completion process. As more and more nonconformities were uncovered, the operator had to send an increasing number of its own staff and hired personnel to follow up the project. This resulted in higher follow-up costs, as well as uncovering even more nonconformities. One problem was that many nonconformities were discovered at such a late stage that much of the work was already completed. Another problem was the ability to ascertain a correct picture of the scope of these nonconformities. The contract form, with SBM as owner of the facility, restricted the operator's opportunity to carry out inspection, intervention and follow-up of the subcontractors, and to influence the solutions chosen during the process.

According to the contract, potential nonconformities uncovered during the construction phase were to be corrected. Therefore, many of the discussions between operator and contractor related to agreeing on what needed to be corrected. Furthermore, the operator's perception was that the supplier's incentive to complete the delivery would be seriously impaired if they were to cover correction of all of the defects free of charge. Several economic incentives (direct intervention payments to subcontractors, resource support (personnel/equipment/flotel) for the supplier's completion and formalised "side arrangements" to the contract) to improve progress and changes. In retrospect, the conclusion is that these measures were ineffective as regards ensuring both progress and adequate quality, as the incentive schemes themselves quite often resulted in disputes between supplier and operator.

The production facility therefore left the yard in Abu Dhabi, bound for the Rosenberg shipyard, with quite a number of defects. The work that, according to the contract, should have been completed in Abu Dhabi thus had to be completed in Norway, at a substantially higher cost level. The scope of work now also proved to be considerably greater than previously assumed. However, in order to avoid additional delays, a decision was made to put the production facility out on the field before winter set in, even with a considerable number of defects and flaws (approx. 74% completed). Work that should have been completed on land had to be completed offshore, with even higher costs.

In July 2012, the operator made the decision to remove personnel from the MOPU due to the discovery of significant structural flaws and cracks in the foundation that fastened the MOPU legs to the storage tank on the seabed. The MOPU owner (SBM) declared the unit to be scrap in December 2012.

According to the operator, all important decisions in the production licence were processed in ordinary (and extraordinary) committee meetings, and resolutions were made either in the management committee or through License to share (L2S). The frequency of meetings in the licence was ramped up as the challenges in the project unfolded. In an early phase of the project, an exchange of information/experience was carried out between the Yme project and Dong for the purpose of benchmarking costs and the implementation plan for the Yme topside vis-à-vis the Siri topside on the Danish sector. Late in the project, in the spring of 2012, the other licensees called for a project audit. The final report was presented on 10 July 2012, and the operator's comments regarding this were issued on 12 August 2012. The platform had been de-manned at this time.

 

4.5.5 Lessons from the project 

The most important lessons from this project are linked to the decisions made in the early phases of the project. The project got off on the wrong foot, and the remainder of the time since was largely spent on trying to rectify this. The operator is currently working on an in-depth review of the project so as to extract maximum lessons learned. Based on the information the NPD has received, some of the most important lessons are listed below:

  1. More work in the early phase of the project
    - Have an internal system in place to ensure maturing and quality towards final project approval
    - Allow sufficient time to complete the FEED phase prior to PDO submission and detail engineering
    - Perform thorough work as regards assessing contractors' quality, experience and expertise
  2. Avoid the EPCIC – lease contract form. It would have been better if the operator was the owner of the facility during construction. After completion, the facility could have been sold, if applicable, and then leased back in for the operations phase.
  3. Use the contract to its fullest extent in the project implementation. Set the standard early in the project as regards ensuring deliveries in accordance with contract stipulations.
  4. Place much greater focus on project follow-up. Ensure own expertise in Norwegian regulations, in addition to project follow-up experience and capacity.