3. Implementation of offshore oil/gas projects

Evaluation-of-projects-forside

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Offshore oil/gas projects are generally divided into a planning phase and an implementation phase. The final work scope is prepared in the planning phase, an implementation plan is established, a contract strategy is laid, tenders from suppliers are obtained and a contractor is chosen. An important part of the planning phase is preparing good, realistic estimates for implementation times, performance and cost requirements. Through feasibility studies, concept studies and front-end engineering design, the project is matured up to a level of detail which forms the basis for a potential decision regarding development. The front-end engineering design forms an important basis for the PDO application to the authorities.

Major offshore oil/gas projects comprise several independent activities, and a successful result is contingent on all involved parties completing their deliveries on time. Activities take place at different geographical locations and extensive communication and sound cooperation between players is vital.

A common project implementation model used on the Norwegian shelf involves multiple decision points along the way during the project’s lifetime. Various forms of quality assurance are carried out prior to these decisions, both internal and external. Internal quality assurance comprises technical quality, as well as multidisciplinary and commercial quality of the project based on empirical data from other projects the operator has insight into. External quality assurance can include external benchmarking and peer reviews as contributions toward improvements, as well as to ensure good ownership of the project in the entire partnership.

The authorities’ “Guidelines for PDO and PIO (Plan for Installation and Operation), focus on planning, organisation and implementation of development projects. The guidelines state that a schedule must normally be submitted for the development and that the project should be assessed to the extent that all investment elements can be estimated with reasonable certainty before the PDO is sent to the authorities.

Project management is defined as the systems needed to prepare the plans, follow-up to ensure that the plans are realised and potentially make corrective measures along the way. The project implementation must be focused toward completion at the right time and within a given cost framework.

Figure 3.1 - Download pdf 

text in figure:

  • Prosjektutviklingsprosessen = Project development process
  • Ideutv. = Idea development
  • Leting = Exploration
  • Drift = Operation
  • Planlegging = Planning
  • Gjennomføring = Implementation
  • Mulighetsstudier = Feasibility studies
  • Konseptstudier = Concept studies
  • Forprosjektering = Front-End Engineering Design
  • Detaljprosjektering = Detail engineering
  • Bygging = Construction
  • Uttesting og oppstart = Commissioning and start-up
  • Start mulighetsstudier = Start feasibility studies
  • Start drift = Start operations
  • Erfaring 1. års drift = Experience 1 year of operation
  • Generell projektutviklingsmodell = General project development model

Figure 3.1 General project development model

 

3.1 Responsibilities

When awarding a production licence, the Ministry will appoint or approve an operator (Section 3-7 of the Petroleum Act (PA)). The operator is responsible for daily management of the joint venture's activities, including implementation of individual projects (cf. Article 3).

The licensee is the party awarded rights according to the individual licence (Section 1-3 of PA) and has overall responsibility for prudent operation of the petroleum activities.

According to current statutes, the licensee is subject to a special follow-up duty (the “supervisory duty”). In accordance with Section 10-6, last subsection, the licensee is required to ensure that everyone that performs work for the licensee complies with the provisions stipulated in or in pursuance of the Act. The licensee (normally the operator) also, by involving other participants in the activity, has direct management and control of the performance of the overall activity through e.g. stipulating requirements, terms and conditions or framework for quality and efficiency.

On behalf of and according to instructions from the other licensees in the licence, the operator is responsible for daily management of the activity. The operator therefore has a special responsibility for ensuring that the overall activities take place in a prudent manner and in accordance with the applicable rules at any given time. The other licensees (the joint venture individually and jointly) must, e.g. through audits, ensure that the operator is fulfilling its special operator duties, and facilitate the operator's work through budgets and decisions, etc..

Licensees’ supervisory duty will mainly be related to ensuring that the operator fulfils its obligations. In practice, this will entail the licensee ensuring that the operator and other participants in the activity have a satisfactory management system, have a satisfactory organisation, possess sufficient capacity, address problem areas on which the authorities place particular emphasis, obtain necessary permits and consents, etc.

The responsibility for ensuring compliance with the regulations is a general and comprehensive follow-up duty when carrying out all petroleum activities. The licensees’ follow-up duty entails that the licensee, before and during signing of the contract, as well as when implementing the activity, shall verify that all participants are competent and qualified to conduct petroleum activities.

Pursuant to the Agreement concerning petroleum activities (Article 11), all licensees must contribute in the strategy work with a focus on goals, choosing the course and monitoring the entire activity. The operator is required to make regular reports to the management committee regarding the status, nonconformities and measures.

The licensees are required to contribute to management and control of the joint venture's activities. In development cases, the licensees therefore have a responsibility to actively use the various companies’ experience and expertise to improve and verify the quality of the projects. Important milestones and decisions relating to continuation must be made by the licensees. This applies for decision points during the planning phase, as well as for status reviews and decisions regarding potential corrective measures during the implementation phase.


3.2 Project follow-up

The preconditions for a project to succeed with implementation in accordance with both the time and cost framework are established in the planning phase. The project basis must contain both realistic plans with built-in flexibility and a realistic budget with a buffer to accommodate changes. Another important precondition is that the contracts entered into with suppliers contain precise descriptions of the work scope. This will promote good communication and reduce the potential for misunderstandings between the parties. Another precondition is that both the operator and supplier, as well as sub-suppliers, have the necessary expertise.

For offshore projects on the Norwegian shelf, the operator always has overall responsibility for daily management and project implementation, and it is therefore a precondition that the operator has sound project implementation expertise, including knowledge of requirements on the Norwegian shelf. Furthermore, the operator is responsible for ensuring suppliers also have the necessary expertise. This is the operator’s responsibility regardless of the contract type chosen. Expertise, and thus quality in all stages, will be an important success criterion for a project.

Project follow-up during the implementation phase will mainly mean following up contractual factors, ensuring sound cost and progress control, managing the engineering work, following up the construction work, conducting procurement/material management and quality assurance. How these tasks are distributed between operator and supplier may vary, and this is regulated in different types of contracts. Regardless, the operator will have the overall responsibility on behalf of the licensees, and must ensure progress and costs are in accordance with the plans, as well as ensure the quality of the deliveries.

The implementation phase is divided into detailed engineering, construction and commissioning/start-up. The final basic drawings for the construction are prepared during detailed engineering. More exact calculations of weights, space and material needs are made, and procurement of materials starts.

 

3.3 Cost estimation

The costs of submitting a PDO/PIO are estimated. An estimate must take project uncertainties into account. The costs are therefore estimated within an interval with a certain degree of confidence. More detailed engineering is required to achieve greater certainty in the estimates. There will always be balancing of considerations as to how certain the estimates need to be to form the basis for a decision.

For example, a project can be estimated as costing NOK 100 +-20% within an 80% confidence interval. This means that if we implement such a project many times, in 8 out of 10 cases (80%) the costs will be between NOK 80 and 120.

The guidelines for PDOs/PIOs state that the operator must present an unbiased estimate that is estimated with reasonable certainty. To illuminate the uncertainties around this estimate, estimates with a 10/90 and 90/10 confidence level must also be presented. These estimates indicate what the project will cost in the 10% best and 10% worst outcomes of the sample space.

 

3.4 Contract types

A project can be divided up in several different ways. The degree of follow-up work on the part of the operator and contractor will vary, depending on the type of contract chosen.

The parts of a project that are included in one and the same contract will vary from project to project and operator to operator.

Table 3.3. Normal main activities included in contracts for offshore projects (English/Norwegian).

 

English

Norsk

E

Engineering

Prosjektering

P

Procurement

Innkjøp

C

Construction

Konstruksjon

I

Installation

Installasjon

C

Commissioning

Uttesting

H

Hook up

Sammenstilling

F

Fabrication

Fabrikasjon

 

Putting together different parts of a project into one single contract (total contract) entails that one primary supplier will handle the interfaces between the various deliveries. One of the advantages of this type of contact is that it is simpler to have overlapping activities. The contractor can then e.g. determine independently how much engineering needs to be completed before construction can start and procurement of equipment and bulk materials should be initiated.

An important purpose of the Norsok process (from the first half of the 1990s), was e.g. to focus on the possibilities of reducing implementation time in projects and standardising requirements. Design-build contracts became an important step in achieving this. In the time following Norsok, design-build contracts in various forms have been the dominant contract type on the Norwegian shelf. However, there have been some recent examples that indicate that the industry sees advantages of returning to use of more divided contracts. This is so that they can govern when to start activities, as well as to better utilise the strongest sides of the various suppliers.

EPCI contracts are currently commonly used for pipelines, cables and subsea installations. One contractor is assigned overall responsibility from engineering to installation. This contract type is less common for platform contracts since installation is a highly plan-sensitive activity. Installation on the Norwegian shelf is only possible during a brief weather window in the spring-summer seasons. The operator often wants to be in charge of this. Installation vessels are often a scarce resource, and if installation does not take place as planned, delays may become considerable.

EPCH contracts are very frequently used for platforms on the Norwegian shelf. The contractor will normally coordinate the various parts of the work so that construction, for example, can start before engineering is completed. This facilitates e.g. good possibilities for procurement of equipment and bulk material at the optimal time. This entails a potential for reducing the project’s overall implementation time.

Changes will normally occur during a contract. How they are handled in a specific contract type must be clearly defined in advance between the operator and contractor.

In certain cases, installation can also be included in the contract. This means that the supplier is also responsible for installation out on the field.

Dividing the contract into two parts where one part is engineering and one part is construction leads to more interfaces for the operator, but also leads to the operator having more control over the project. By dividing the project in this manner, the operator will have a greater possibility of choosing the best supplier for engineering and the best supplier for construction and fabrication. In this connection, it is important to achieve good communication between the EP and FC contractors.

There are many different types of compensation, all of which distribute risk between the operator and supplier in different ways. There are three main types of compensation used for projects on the Norwegian shelf:

  1. With a fixed-price contract, the cost of the project is negotiated before the contract is signed. All implementation risk is then placed on the suppliers. With this type of contract, the operator can generally use less resources for cost follow-up since the cost is already determined. The disadvantage of this contract type is that it provides little opportunity for changes. If the operator wishes to make changes along the way, they often turn out to be time-consuming and costly.
  2. This contract type is the most common on the Norwegian shelf. Rates and norms are negotiated to be used in calculating the project costs. The customer is responsible for the scope of the project and therefore assumes the risk associated with changes and developments in the project. The supplier is responsible for the rates and norms stipulated in the contract, this entails that the supplier must assume the risk related to efficiency and productivity.
  3. With this type of the contact the supplier is paid by the hour. The operator then assumes risk related to productivity, in addition to risk related to the work scope.

 

3.5 Cost development in projects on the Norwegian shelf

Below is a list of projects under development as presented in the 2013 fiscal budget (ref. (8)). Looking at all projects, the increase in relation to PDO/PIO is more than NOK 49 billion. This indicates that projects on the Norwegian shelf in recent years have generally become more expensive than the unbiased estimate submitted in the PDOs/PIOs.

 

Table 3.1 Cost changes for projects with an approved PDO between 2007 and 2012. The table is from Storting Proposition 1 S (2012-2013). The figures may deviate somewhat from what follows in the further review due to project development in the past year.

 

Project

PDO/PIO
approved

PDO/PIO estimate

New estimates

Change

Change %

Atla

2011

1382

1382

0

0%

Brynhild

2011

4227

4579

352

8%

Edvard
Grieg

2012

24205

24205

0

0%

Ekofisk
Sør

2011

28022

27237

-785

-3%

Eldfisk
II

2011

37987

37893

-94

0%

Gaupe

2010

2828

2376

-453

-16%

Goliat

2009

30942

37142

6200

20%

Gudrun

2010

20592

18976

-1616

-8%

Hyme

2011

4593

4780

187

4%

Jette

2012

2590

2909

319

12%

Kårstø Expansion Project
2010

2008

6675

6297

-378

-6%

Knarr

2011

11437

11527

90

1%

Martin
Linge

2012

25641

25641

0

0%

Marulk

2010

4162

4476

314

8%

Oselvar

2009

4937

5120

183

4%

Skarv

2007

35632

47162

11530

32%

Skuld

2012

9895

10147

253

3%

Stjerne

2011

5263

4976

-287

-5%

Valemon

2011

26329

26880

551

2%

Valhall Redevelop-
ment

2007

25163

46727

21564

86%

Vigdis Nordøst

2011

4194

4467

273

7%

Visund
Sør

2011

5296

5208

-88

-2%

Yme

2007

4894

14114

9220

188%

Åsgard Compression

2012

15661

17693

2031

13%

Total

 

342547

391914

49366

14%

 

The selection of projects assessed in this report represent a large part of the changes during the period. Together, Yme, Skarv and Valhall Redevelopment represent 86% of the changes. Gjøa and Tyrihans differ from the other projects as there were only minor changes as regards costs and the start-up date.

 

Table 3.2 Cost changes for Gjøa and Tyrihans

Project

PDO/PIO approved

PDO/PIO estimate

New estimates

Change

Change %

Gjøa

2007

31239

35135

3896

12%

Tyrihans

2005

14059

16627

2568

18%

Total

 

45298 

51762

6464

14%

 

Adding a range of uncertainty in the PDO estimates which, according to the authorities’ PDO guidelines, must be estimated with reasonable certainty, reveals a more differentiated picture. By using an uncertainty range of 20%, which is commonly used by operators at the time of PDO/PIO submission, only three of the projects are outside the estimated costs submitted in the PDO/PIO.

 

Figure 3.2 - Download pdf

Figure 3.2 Cost estimate in PDO with uncertainty range and cost development

 

It also becomes clear that a few projects represent the majority of the change in relation to PDO/PIO estimates. At the same time, very few end up with final costs below the unbiased estimate. Overall, this results in the substantial total change described in the 2013 fiscal budget.

 

3.6 Cost development in major international projects

Research in implementation of major projects within other industry branches (transport sector, defence projects, etc.) generally shows that major projects frequently experience considerable cost overruns and delays (ref. 12).

Overruns in major oil and gas projects are also a challenge internationally. The EY auditing and consulting company has carried out an analysis of the 20 largest upstream investment projects within the oil and gas industry that were recently approved for development (ref 9). The analysis shows that, on average, these projects have experienced overruns of 65 per cent. The overruns for these projects total USD 76 billion, or about NOK 440 billion. This results in average overruns of about NOK 22 billion per project.

EY’s study (ref. 9) generally focuses on projects with investment budgets exceeding USD 1 billion (357 projects) within oil and gas activities (LNG, pipeline projects, refining and upstream). It shows that a substantial number of the projects experience major cost overruns and delays. Of the 357 projects included in the study, updated cost estimates have been acquired for 194 of the projects. Of these, cost overruns are reported in 57% of the projects. Of the same 357 projects, information on project progress has been received from 227 projects, of which 64% report delays. Cost overruns and delays have been observed within all types of oil and gas projects, but upstream projects have the highest percentage.

The study also geographically distributes the projects in the areas Africa, Asia/Pacific Ocean, Europe, Middle East and America. The percentage of projects that experience cost overruns and delays is relatively similar for all regions.

Another study carried out by IPA (Independent Project Analysis) ref. (10), concludes that 22% of major oil and gas projects (with investment costs exceeding USD 1 billion) succeed with project implementation. In this study, a project will fail if either the cost growth is higher than 25%, cost growth is higher than 25% of the industry average, implementation time is exceeded by 25%, implementation time is more than 50% of the average in the industry or if major and lasting production problems are experienced in the first two years following start-up. All major projects in the study have low success rates. The oil and gas projects, with a success rate of 22%, have the worst result. The corresponding success rate for all mega-projects regardless of industry is 35%, while all projects regardless of size have a success rate of just over 50%.

 

3.7 Investment Committee

The Investment Committee was appointed by the Ministry of Petroleum and Energy on 29 August 1998 to analyse investment development on the continental shelf on the basis of major cost overruns in several projects. The Committee’s report is the most recent and most extensive analysis of cost overruns on the Norwegian shelf, with a review of 13 of the projects approved by the authorities in the period 1994 – 1998. The Committee highlights four main causes of cost overruns for the projects in the report:


1. Decision basis, budget, risk understanding

“The Committee believes the majority of PDO estimates from the period have been unrealistic for reasons that can be attributed to underlying factors that distinguished the period. Facilitation of the decision basis and decision process was often characterised by exaggerated optimism on the basis of positive trends, general unrealistic ambitions regarding significant further improvements and a deficient understanding of the uncertainty in fragile project maturing and introduction of new elements. A significant part of the cost overruns must be attributed to these general and often contributory reasons for unrealistic budgeting.”


2. Drilling and completion

“Drilling and completion of production and injection wells accounts for one-third of the overall cost increase. In the Committee’s opinion, this striking factor is primarily related to the operators’ insufficient detailed planning of the drilling and completion operations when preparing the PDO. All operators have noted reservoir complexity and technologically advanced wells as important characteristics in the drilling operations… The large number of subsea wells in the projects from the period have resulted in a considerable demand for mobile drilling rigs. Nearly all rig capacity that meets the quality requirements for the Norwegian continental shelf has been used. In this situation, the industry has struggled to maintain a sufficiently high and steady level of expertise. The strong demand has resulted in unusually high rates, also for rigs that must eventually be considered older, which has contributed to the cost increase.”


3. Technology

“A technology shift has taken place through the projects in the period, particularly with regard to production drilling and well completion and floating production facilities with subsea wells. The implementation of new technology has introduced considerable uncertainty factors which have not been sufficiently noted in budgeting and implementation of the projects. This particularly applies within the drilling and floaters areas” … “several projects experienced challenges with deliveries from new suppliers to the offshore industry, the shipyards. Several hulls were delivered to hook-up workshops in Norway with a considerable scope of outstanding work. This was caused by deficient qualification of these suppliers, underestimating follow-up needs, problems in applying the offshore industry’s change mechanisms in another industry and a failure in the shipyards’ understanding of complexity, quality requirements and applicable regulations, as well as in their ability to deliver. The players thus underestimated the problems associated with exploiting the advantages that were presumably entailed by use of shipyards.”


4. Project implementation

The project implementation in the relevant projects is characterised by a short project implementation time where the time in both the phase prior to start-up of the project and during the actual project has been reduced. A number of the elements that have contributed to the improvements have, however, also contributed to the overruns… there has been a pronounced transition during this period from an implementation model with many individual contracts to the full-range deliveries. The suppliers have had experience with the individual elements in these contracts, but not with the total project management which was previously the operator’s responsibility. There has been no special experience transfer from operator to supplier in this area, and there is no doubt that the suppliers have experienced problems in implementing the overall deliveries as efficiently as assumed… as regards activity level, the indications are that the activity level has been significant for the cost increase. It is probable that the basis for the cost increase was laid early in the project, and this was amplified by the fact that expertise and resource scarcity has made it difficult for the operators and suppliers to implement the projects as efficiently as possible.”

The quotes were obtained from the Summary in the Committee’s report NOU 1999:11 “Analyse av investeringsutviklingen på kontinentalsokkelen" <Analysis of investment development on the continental shelf – Trans.>.


04.11.2013