1. SPE-180176-MS
Resilient Field Developments That Can Accommodate Uncertainty Are the
Best Solution for a Sustained Low Oil Price Environment
C. T. Hopper, Moving Future
Copyright 2016, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Europec featured at 78th EAGE Conference and Exhibition held in Vienna, Austria, 30 May – 2 June 2016.
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Abstract
The upstream industry has been unable to deliver projects successfully over the last ten years, with up to
70% of projects failing to meet schedule or cost targets. This failure rate did not matter when the oil price
was high as the projects remained profitable. However, after the oil price dropped in 2015, this level of
project failure has become untenable.
The linear gated project management systems adopted by the industry over the last fifteen years are
suitable for straightforward projects that can be well defined. However, they are not suitable for many of
today’s projects that are more complex and have significant uncertainty, which require a different
approach.
This paper describes a project management process developed in the UKCS in the 1990’s that was used
to bring three projects stuck for 15 years to project sanction. In addition, a recent project is described
where the development was designed to accommodate a range of outcomes and by doing so allowed the
project to be sanctioned with significant uncertainty still remaining.
In the current environment of a sustained low oil price, across the board cuts are often implemented in an
attempt to make projects economic. Arbitrary cuts on their own are unlikely to make projects viable and
instead the industry needs to take a step back and question the processes that have been used and why they
have failed. A different approach is suggested; one that embraces uncertainty to produce resilient projects
that can accommodate change. Implementing this will require a change in mindset as much as a change
in process.

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Introduction
The reduction in oil price between the end of 2014 and today has led to a major retrenchment in the
industry, with a significant number of projects being deferred or cancelled and major Capex reductions
announced by all the major oil companies. It is a commonly held view that this retrenchment is primarily
due to a low oil price, however, a closer inspection shows that even when the oil price was high, the
industry was having significant difficulties delivering projects.
Ernst & Young (2014) evaluated 365 mega projects and concluded that 78% of European upstream
projects faced schedule delays and 65% faced cost overruns, with an average cost overrun of 53%.
Nandurdikar (2014) in a presentation for IPA, came to a similar conclusion and found that E&P
megaprojects had a success rate of 22%, compared with a success rate of 52% in other industries. This
presentation drew similar conclusions to an earlier IPA study published in 2011, which showed that 78%
of upstream mega projects had either cost overruns or delays and that this failure rate was significantly
higher than in 2003, when only 50% of projects failed.
These reports illustrate that the level of project failures in the E&P business has increased over the last ten
years and is significantly worse than in other industries This level of project failure was only sustainable
because unusually high oil prices kept projects profitable, but this bubble has now burst. For projects to
be successful in a low oil price environment project delivery needs to be improved.
In the late 1990’s the E&P industry adopted linear decision making processes that became the norm in
virtually all companies, Figure 1. These processes first specify Givens which are used to define a Frame
that bounds a solution. A Universe of Opportunities is generated that lies within this Frame and a rigorous
step wise process used to establish the highest value option.
Figure 1—Conventional Gated Process
These processes work well when the Givens can be clearly defined and a Frame set up that includes all
the possible solutions. However, they do not work well when the Givens change or new solutions that are
outside the Frame become apparent. The rigorous linear nature of these processes cannot easily
accommodate new information so commonly the project either presses on regardless or goes into a major
recycle, both of which significantly increase the risk of cost and schedule overruns.

3. SPE-180176-MS 3
A key feature of these processes is to optimize the solution by undertaking extensive engineering studies
with the aim of increasing the Front End Loading (FEL). The cost savings resulting from these facilities
optimization are often small and are commonly within the noise of the estimating accuracy, yet they are
almost always incorporated. Including these changes often increases the execution risk by introducing
uncertainty for very little gain. The average cost overrun of 53% seen on recent upstream projects shows
that the probabilistic cost and schedule evaluations undertaken on most projects do not include some of
the major risks in their assessments.
Cost overruns in recent years have been blamed on a hot market causing prices to increase. This has led
to arbitrary across the board cost cuts in to attempts to reduce costs. While these cuts will reduce costs in
the short term, they will not be sufficient on their own to make unprofitable projects profitable. Arbitrary
cost cuts will reduce costs, but are also likely to increase the risk of project failures unless accompanied
by a change in the way the project is run. A recent study of cost reductions in the current oil price
environment concluded that while reduced prices can contribute to reduced costs, they will only account
for about 25% of the required reductions. The remaining 75% has to come from doing the project
differently.
A significant number of the recent cost overruns have been caused by changes in scope late in a project’s
life cycle. This is the worst time to make changes to the design and almost inevitably leads to cost and
schedule overruns. It also goes against the whole concept of Front End Loading, where the aim is to fully
engineer and optimize the solution before detailed engineering and construction starts. These late changes
are often the result of unforeseen new information appearing that challenges the set of assumptions used to
define the project.
While some things in the E&P business are unpredictable, the majority are known but uncertain. In the
subsurface world, uncertainty and ranges of outcome are an accepted way of doing business. However,
when it comes to development projects, this uncertainty is forgotten and a single set of reserves and
production profiles are often used as the basis for design. Most projects then focus on looking at options
and optimizing a solution and in doing so lose sight of the fact that this single design point is just one
outcome within a range of outcomes. The end result of this approach is a fragile project that cannot
accommodate the inevitable changes that occur as a project progresses.
In addition to uncertainties that are predictable, some uncertainties are unpredictable. While it is relatively
straightforward to design a project to be able to accommodate a range of outcomes that are uncertain but
predictable, it is much more difficult to design a project for events that are both uncertain and unpredictable.
To cope with unpredictable events, projects need to be more than just not fragile, they need to be robust
and able to accommodate change.
This phenomenon has been described by Taleb (2007) using what he terms Black Swan events. These are
events that cannot be predicted, but have a catastrophic impact. The same phenomenon was also described
by Rumsfeld (2002) as the Unknown Unknowns, which are the ones we don’t know we don’t know. Taleb
concludes that there is little point in trying to predict these events and instead suggests that projects should
be designed to be resilient and able to accommodate uncertainty. He also suggests that instead of projects
just being made resilient to shocks, they should use uncertainty to improve and get better.

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To make projects resilient, they need to be able to accommodate a range of outcomes. The project systems
and processes used to deliver projects should also be able to accommodate change and incorporate new
information as it becomes apparent. This paper describes a process developed by the author in the 1990’s
that was used to take three stranded North Sea projects to sanction. The process was expanded to make it
more generally applicable, documented and successfully applied to development projects throughout the
world. The paper finally describes a project in the North Sea that was recently taken to sanction, where the
development plan was designed to accommodate a range of outcomes in a project that had a high degree of
uncertainty.
North Sea History
The early history of the UKCS is typical of the life cycle of a mature basin, with an increase in production
to a peak followed by a decline, Figure 2. First production occurred in 1975 from the Argyll field and
increased to a maximum of 2.5 mm bbls/d in 1985. From this peak, production dropped steadily down to
1.8 mm bbls/d in 1990, where it remained at about the same level until 1994. In 1995, production increased
from 1.9 mm bbls/d to a second peak of 2.6 mm bbls/d in 2000, which was followed by a decline to the
750,000 bbls/d we see today.
Figure 2—UKCS Production between 1975 & 2015 vs Number of Sanctioned Projects and Oil Price
This increase in production to a second peak between 1995 and 2000 was both unusual and unexpected.
One would normally expect such an increase to be caused either by an increase in oil price or by a string
of new discoveries. However, Figure 2 shows that the oil price during this period was flat between $30 and
$40/bbl (in $2015) and so oil price was not a key driver.
Figure 2 also shows that there was a significant increase in the number of projects sanctioned between 1989
and 1998, with an average of 10.0 projects/year sanctioned during that period, compared with 3

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projects/year in the preceding years. The number of sanctioned projects peaked in 1995, when 19 projects
were sanctioned in a single year.
While some of these sanctioned projects were new discoveries, a significant number were projects that had
been stranded for many years. The thing that changed between 1989 and 1998 was that these projects did
business differently. Rather than trying to reduce costs or increase reserves, different business models were
used. The resulting projects included regional processing hubs, alliance contracts, the first use of third party
processing, the first HPHT fields, collaborative contractor agreements and the first heavy oil fields. Instead
of holding back developments, a low oil price environment provided the stimulus to encourage innovation
and unleash creative solutions.
Historical Project Examples
Between 1989 and 1998, the author put together development plans for three projects; Strathspey
(sanctioned in 1991), Captain (sanctioned in 1995) and Galley (sanctioned in 1997). The discovery driven
approach described in this paper was developed using experiences gained on these projects.
Strathspey
Strathspey had two reservoirs; a high GOR black oil reservoir and a gas condensate reservoir. It was
discovered in 1975 and lay stranded for 15 years. Project sanction was in 1991, 18 months after a
commercialization initiative was started, with first oil in 1993. The project was the largest subsea
development of its day, with 18 subsea wells and required several technological firsts. Solving the technical
problems was a challenge, but the critical issues were all commercial. Strathspey was the first third party
tieback in the UKCS, which meant that securing a processing agreement with the Ninian Joint Venture was
the major challenge.
One of the main reasons for Strathspey’s success was the use of a fully integrated team, where everyone
reported to the project manager and support services such as legal and contracts were part of the team.
Many problems were solved by taking a holistic view and coming to an integrated solution. For example,
the gas sales contractual obligations were solved by redefining the gas swing, modifying the facilities
design and adding a horizontal well to increase the liquid loading of the subsea flowline and so increase
the arrival temperature. Each of these changes on their own would not have solved the problem, but in
combination they did the job. A compartmentalized project would never have come up with this solution.
Captain
Captain was a heavy oil field discovered in 1977 that had lain stranded for 15 years. Project sanction was
in 1995, two years after a commercialization initiative was started, with first oil in 1997. Again, the project
required many technical innovations as it was the first high viscosity heavy oil field to be developed in the
North Sea. A phased development was adopted, where the best part of the reservoir was developed first
and full appraisal of the remainder of the field deferred until after first oil.
As the best development option was not obvious, a funded design contest was undertaken between a fixed
platform, a jack up production system and a wellhead platform tied back to an FPSO. The concept was
selected once hard money bids were available for each option. The contract was awarded to a contractor

6. 6 SPE-180176-MS
alliance who supplied the complete field facilities of a wellhead platform and an FPSO under a single
contract. This was one of the first times a design contest had been used to select a development option.
Texaco had 100% of the Captain equity and tried to farm down 50% to fund an extended well test. Farming
in would have cost about $12mm, but Texaco got no takers and so continued the funding the total cost of
the commercialization program itself. About 18 months later around project sanction, 15% of the equity
was sold for $215mm, valuing the asset at $1,500mm. This increase in value was not the result of a change
in reserves or development concept. What had changed was that people believed the commercialization
plan would work.
Galley
Galley was a small light oil field discovered in 1974. It had lain stranded for 20 years, during which time
11 appraisal wells were drilled that had proven up reserves of 20 mm bbls. When the commercialization
program kicked off, the first action was to shut down further appraisal and reverse engineer how to make a
stand-alone project work with 20 mm bbls. Project sanction was in 1997, two years after the
commercialization initiative started, with first oil in 1998.
A stand-alone development was not economic with reserves of 20 mm bbls and 25,000 bbls/d peak
production. So instead of trying to reduce costs, the facilities were increased in size to 45,000 bbls/d and
FPSO contractors approached about a gain share contract. The contractors were asked to provide a facility
at minimum cost in exchange for a per barrel tariff paid on upside production over 20 mm bbls. To convince
them to bid, a data room was opened to provide details of the upside potential. A contract was eventually
awarded for the supply of the Northern Producer and production increased to 40,000 bbls/d, which was
significantly greater than the 25,000 bbls/d predicted by the reservoir models. Additional wells were added
and eventually over 50 mm bbls were produced though the production facility.
At project sanction, the Galley reserves were 20 mm bbls proven, with a likely outcome somewhere in the
range of 20 to 70 mm bbls. The economics showed that the project was economic at 20 mm bbls and that
any upside was very profitable. As it turned out, Galley eventually produced 65 mm bbls of oil and at its
peak provided 10% of Texaco’s worldwide earnings. The project was sanctioned with a wide range of
possible outcomes on the basis that it had the downside protected and the upside unconstrained. In that
respect, it was a resilient project.
A Discovery Driven Approach
The three projects described above were used to develop a process for bringing difficult and complex
project to sanction. The process can be split into two parts: First; treat the project as a holistic problem,
where all aspects of the project are addressed together using an integrated approach. Second; assume that
the solution is uncertain and will be evolved using an iterative prototyping approach. This process is
described in more detail in Hopper (2009).
Any project can be split into its Strategic, Business and Technical components, Figure 3. The Technical
Frame contains the subsurface and facilities, the Business Frame contains the commercial aspects such as
tariffs, government and partners, while the Strategic Frame contains the business model.

7. SPE-180176-MS 7
Figure 3—Commercialization Venn Diagram
Conventionally these components are dealt with separately and by different groups. The Strategic Frame is
often defined by executive management and set as Givens to the project team. The Business Frame is
commonly undertaken by a commercial group separate from the project and even the Technical Frame is
often split between facilities and subsurface. This compartmentalization is not an issue when the project is
straightforward as there is little interaction between the component parts. However, this linear and
deterministic approach does not work for complex projects, where the three Frames have to be dealt with
together.
The second component of the process is the use of an iterative prototyping approach to problem solving.
The starting point is to define a Reference Case, RC1, based on assumptions and best guesses. RC1 is tested
in an iterative cycle to gain an understanding of the underlying drivers and to flush out new information.
The insights gained at each iteration are used to define the next Reference Case and the process repeated.
A final solution is evolved rather than selected from pre-defined options and so the final solution often lies
outside the universe of opportunities originally conceived. The final solution is often not predicted or
anticipated at the outset and so unexpected and higher value solutions are common outcomes of the process.
This is illustrated in Figure 4.
Figure 4—Iterative Approach to Evolve a Final Development Plan

8. 8 SPE-180176-MS
Similar Processes
An iterative approach is used in other industries when there is uncertainty. McGrath and MacMillan (1995)
describe Discovery Driven Planning; here the assumptions are defined, a solution reverse engineered and
a prototype tested to establish the underlying drivers. The insights from this testing are used to update the
prototype and the process repeated in an iterative manner until a solution is found.
Klein (2011) describes how Adaptive Decision Making can be used to account for uncertainty and a
solution developed using an iterative approach. He describes a process he terms Management by Discovery
(MBD) where goals are changed as new information becomes available and concludes that The MDB
mindset is to look for opportunities to figure out better goals than the ones specified at the beginning.
Hass (2007) describes how project failures were a common feature of the IT industry and that a survey
undertaken in 2006 showed that 65% of IT projects failed and had cost and schedule overruns of more than
46%, The cause of these failures was attributed to the use of a Waterfall life cycle model, where one activity
follows another in a linear sequential manner. The proposed solution was Agile Project Management, where
a key feature is the use of rapid iterative planning and development cycles to deal with requirements that
are elusive, volatile and subject to change.
Current Project Example
The most recent application of the approach is on a heavy oil field in the North Sea that is currently under
construction and due to come on stream in 2016. It was discovered in 1985 and was stranded for 18 years
until a new operator took over in 2003, who then drilled two appraisal wells in 2007 and 2008. A
commercialization initiative was started at the beginning of 2010 and a Reference Case, RC1 defined. The
reservoir had a sweet spot characterized by seismic hydrocarbon indicators, which gave confidence in
reserves of between 50 and 80 mm bbls. An RC1 development plan was put together that showed the project
could be economic in the low reserves case, see Figure 5.
Figure 5—Reference Case Development
The insights gained from RC1 were used to generate an updated case, RC2, based on higher reserves and
the process repeated to confirm that the project was still viable. In mid-2010 an additional appraisal well
was drilled and the information used to generate RC3 based on 103 mm bbls in early 2011. The size of the
facilities for RC3 was increased from 30,000 bbls/d to 60,000 bbls/d to accommodate both the increase in
known reserves and the potential upside of the field. Further evaluations of both the facilities and subsurface
led to an RC4 and an RC5 in mid-2011, based on about 130 mm bbls. The capacity of the facilities was not

9. SPE-180176-MS 9
changed as the upside had been anticipated and the new cases were to account for changes in assumptions
such as fuel supply and injection water makeup. Finally, a horizontal well was drilled and tested in Q4
2011. The results of this well test were used to generate the final development solution, RC6 in December
2011, based on 174 mm bbls of reserves and an unchanged facilities design.
While the reserves were being firmed up, the development plan was being progressed in parallel. The
facilities solution was technically challenging and consisted of an all subsea development using Hydraulic
Submersible Pumps (HSP’s) tied back to an FPSO. HSP’s enable the use of subsea wells with heavy oil by
eliminating flow assurance problems in the subsea flowlines as a result of flipping the emulsion into a water
continuous phase in the pump using the returning power fluid. It is only the second field in the world to use
HSP’s; Captain was the first.
The oil processing capacity of the FPSO was 60,000 bbls/day, with a total liquids processing of 500,000
bbls/d due to the high water cut wells typical of heavy oil and the returning power fluid from the HSP’s.
This size of topsides required a SuezMax hull, which will make it the largest FPSO in the North Sea.
The facilities were sized to be able to accommodate a range of outcomes, see Figure 6. Phase 1 developed
a sweet spot in the reservoir, which had seismic hydrocarbon indicators. Phase 2 developed the remainder
of the reservoir and would be finally defined using production history from Phase 1. Phase 3 is an
exploration prospect to the west of the main field.
Figure 6 shows the logic of the facilities sizing. The Phase 1 P90 reserves produce 30,000 bbls/d of oil and
give break even economics. The Phase 1 P50 reserves produce 40,000 bbls/d of oil, are economic and were
used to justify the project. The Phase 12 P50 reserves produce 55,000 bbls/d of oil and provide upside
production and value. The facilities were sized for 60,000 bbls/d and so could accommodate the Phase 12
P50 reserves, the Phase 12 P10 reserves and any Phase 3 exploration success. Configuring the project in
this way made it resilient to changes in reserves, reservoir performance and exploration success.
Figure 6—Phased Development Production Profiles

10. 10 SPE-180176-MS
The facilities sizing was updated in parallel with the appraisal program and frozen once it matched the risk
profile of the reservoir and the contracting strategy for the FPSO. Once it became clear that the ultimate
reserves would be over 100 mm bbls, the facilities were increased in size from 30,000 bbls/d to 60,000
bbls/d. This step function change allowed the design to be frozen and the larger facilities defined and
engineered up front to improve the Front End Loading, with the final facilities design being confirmed by
the results of the appraisal program rather than being initiated by it.
The FPSO contractors were engaged very early in the process and involved in the development of the
facilities design. They were regularly updated on progress in the subsurface to allow them to evaluate risk
and to take a view on residual value. The contract negotiations produced a day rate mechanism that provided
an underpinning to the downside case, while allowing the upsides to be produced without constraint.
An Expression of Interest for the FPSO was issued in May 2011 based on a 60,000 bbls/d FPSO before the
fourth appraisal well was drilled. The results of this well, combined with responses to the EOI were used
to obtain a CPR that defined 160 mm bbls of 2C reserves in June 2011. The horizontal well test was
completed in Oct 2011 and bids for the FPSO received in Dec 2011. The results of the well test confirmed
the facility sizing and along with the FPSO bids was used to obtain a CPR that defined 170 mm bbls of 2P
reserves in Feb 2012.
The horizontal well test undertaken in Oct 2011 was the first time significant hydrocarbons had been
produced to surface from the field, the previous well test in 2010 having been aborted due to mechanical
failure. Bidding the FPSO in parallel with the appraisal program meant that 2P reserves were defined in a
CPR four months after the first meaningful well test. This significantly compressed the appraisal program
and allowed rapid progress to project sanction.
Designing the FPSO for a range of outcomes and freezing the design of the FPSO early gave the FPSO
contractors confidence to bid a competitive capex to dayrate conversion factor. Fixing the capex to dayrate
conversion factor made the absolute levels of capex less important. Any reduction in capex that might have
been achieved by optimizing the facilities around a single design point was more than outweighed by the
reduction in execution risk and ultimate FPSO dayrate achieved by freezing the design early.
60% of the equity in the field was put up for sale in Jan 2011, but there were no takers. Six months later,
30% of the equity was sold in June 2011 for about $0.50/bbl after the CPR report defining 160 mm bbls of
2C reserves was produced. A further six months later, 45% of the equity was sold in Jan 2012 for $6.00/bbl
once the well test, FPSO bids and a CPR defining 170 mm bbls of 2P reserves were available. This sale
valued the asset at $960mm, twelve months after it was considered worthless. The increase in value was
not the result of a change in reserves or development concept. What had changed was that people believed
that the commercialization plan would work.
Conclusions
The upstream industry has been unable to successfully deliver projects over the last ten years, with up to
70% of projects failing to meet schedule or cost targets. This failure rate did not matter when the oil price
was high as the projects remained profitable. However, once the oil price dropped in 2015, this level of

11. SPE-180176-MS 11
project failure became unacceptable. A lot of blame for these failures is levelled on a hot market and greedy
contractors. While this was part of the problem, it is not the only cause.
The inflexible and rigid approach adopted by the industry to the project management of major projects is
one of the causes of these project failures. While this approach has been successful for large conventional
projects, it comes unstuck when dealing with projects that are complex or have significant uncertainty. A
lot of time and effort is spent optimizing a facility around a single design point, which results in an inflexible
solution that cannot accommodate change to the basic assumptions. Building flexibility into the design and
making a project resilient to change reduces the execution risk and allows projects to be delivered on budget
and on schedule.
A resilient development plan that is economic with the downside cases and unconstrained with the upside
cases allows projects to be sanctioned while uncertainty remains. This allows projects to be accelerated and
appraisal programs shortened by reducing risk using the development plan rather than by increasing
technical definition.
The oil industry is starting to change and is looking for ways to improve the success ratio on major projects.
The key to achieving this is to embrace uncertainty rather than fight it and to build projects that are resilient
rather than fragile. Making these changes will require a change in mindset as much as a change in process.
This will not be easy, but the current failure rate in major projects combined with a sustained period of low
oil price makes this change inevitable.
E Mail: chrishopper@movingfuture.com
References
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Hass, K. 2007. The Blending of Traditional and Agile Project Management, Project Smart, Pmworldtoday.net, May 2014.
Hopper, C.T. 2009. Accelerating the Commercialization of Exploration Success by the Application of Discovery Driven
Development Planning. Presented at Offshore Europe, Aberdeen, 8-11 September 2009. SPE 124229.
Klein, G. 2011. Streetlights and Shadows: Searching for the Keys to Adaptive Decision Making, Bradford Books, ISBN
978-0-262-01339-0, 2011.
McGrath, R.G and MacMillan, C. 1995. Discovery –Driven Planning, Harvard Business Review, July –August, 1995.
Nandurdikar, N. 2014. Improving E&P Asset Development Economics. Presented to SPE Gulf Coast Section, Houston,
14th October 2014.
Rumsfeld, D. 2002. Briefing for the US Department of Defense, February 12th 2002.
Taleb, N. 2007. The Black Swan: The Impact of the Highly Improbable, Random House, 2007.