Current Outlook for Oil and Gas Megaprojects: A Discussion

Christina Lake Oil Sands Project, Photo Courtesy Cenovus

Even with oil and gas prices at historical lows, top quality resources continue to be developed to meet the global demand of approximately 91 million B/D of oil and 332 Bcf/D of natural gas. TWA Forum Section Editors Craig Frenette, Samuel Ighalo, Winston Kosasi, and Rodrigo Terrazas interviewed experts from a diverse set of project types and discussed the development of the projects in the current economic context. Logan Popko, manager of asset development at Cenovus Energy speaks on the Christina Lake oil sands project; Ron Dusterhoft, technology fellow for production enhancement at Halliburton, talks about unconventional shale assets; Pete Hagen, general manager, commercial, at Chevron Australia, shares his insight on the Gorgon and Wheatstone liquefied natural gas projects; and Daniel Picard, special adviser to the director of the Libra Project, Petrobras (on secondment from Total), focuses on the offshore pre-salt megaproject, Libra, in Brazil.

Why does this resource need to be developed?

Logan Popko (LP): Despite the recent surge in oil supply from US tight oil plays and international production, high-quality, large volume resources continue to be scarce across the world and I believe that development of the Canadian oil sands will be critical to meeting the world’s increasing energy demand. The technology we apply at the Christina Lake oil sands project is called steam-assisted gravity drainage (SAGD). It involves drilling horizontal wells to target a resource that is too deep to mine and then injecting steam into it to mobilize oil that can be as hard as a hockey puck at initial reservoir conditions.

However, not all oil sands projects are created equal, and I believe that it will be the highest quality and most innovative projects that have the best chance of moving forward in future years. Fortunately, Christina Lake is well-suited to continue to be an industry leader as we have a fantastic reservoir (more than 40 m thick in some areas) and have continuously embraced and encouraged innovation to improve our economic and environmental performance. Through continued success in reducing our overall cost structures and our environmental impact, I hope that we can continue to develop this asset to help meet the energy demands of the world while ensuring responsible development for the benefit of all Canadians.

Ron Dusterhoft (RD): The reserves in place for many of the source rock reservoirs often referred to as shale are immense, and recent developments in technology have demonstrated their capability to produce huge amounts of both oil and gas. In the business environment witnessed during the past several years, oil and gas prices enabled operators to develop solutions that have proven to be very effective in exploiting these reservoirs. Even with current commodity prices, many unconventional shale plays continue to demonstrate positive economics, due to their scale and productivity.

Pete Hagen (PH): Chevron’s Australian liquefied natural gas (LNG) projects, Gorgon and Wheatstone, are well-positioned to meet the growing demand for clean-burning energy in the Asia Pacific region as well as to drive economic growth and improved living standards. This is underpinned by the size and quality of the gas resource as well as Western Australia’s long history of reliable supply from the North West Shelf Joint Venture. Proved reserves have been recognized both for the Gorgon and Wheatstone projects with an estimated economic life of more than 40 and 30 years, respectively. The Greater Gorgon Area contains 37 Tcf of natural gas, while the Wheatstone and Iago gas fields hold 9 Tcf of discovered resource.

Chevron expects to be one of the top ten LNG suppliers in the world by 2020, with a large portion of this supply attributed to the Gorgon, Wheatstone, and North West Shelf projects. Chevron-led natural gas projects in Australia have created almost 17,000 jobs and committed more than USD 45 billion in goods and services to local businesses.

What is the current outlook for the development of this resource?

LP: Christina Lake currently has a production capacity of 160,000 B/D of oil, and we anticipate adding an incremental 50,000 B/D of oil in 2016 as the Phase F facility comes on line. Given the significant headwinds the industry is facing, Cenovus continues to evaluate future expansion phases. The exact timing of renewed investment in deferred expansion projects will be dependent on continued cost-cutting success, federal fiscal and regulatory certainty, as well as sustained balance-sheet strength and financial resilience.

RD: Despite the current commodity prices in the oil and gas industry, it is generally believed that the development of unconventional shale assets will continue in North America at some level for the foreseeable future, mostly from existing plays where the necessary infrastructure has largely been developed. The potential in shale has been clearly demonstrated with the production success seen in North America. As conventional hydrocarbon fields deplete, it is logical that more operators will be forced to look at shale and other unconventional resources as an alternative to sustain production in the future.

In North American onshore operations, low-permeability oil and gas plays have been the norm for some time, and with continual advances in both hydraulic fracturing and horizontal drilling, many have managed to be competitive in the current market. However, there is a lower price limit where these plays will begin to become uneconomic, and this will play a huge role in the amount and extent of activity in these regions in the future. In new international markets, the development of shale assets will probably be much slower than was seen in North America, based upon commodity prices, availability of infrastructure, and projected capital costs.

PH: The outlook is very positive for both the Gorgon and Wheatstone projects, and they are progressing on schedule. Gorgon nameplate capacity is 15.6 million tonnes per annum (Mtpa) of LNG and Wheatstone is 8.9 Mtpa. The total production capacity for the Gorgon project is expected to be approximately 2.6 Bcf/D of natural gas, and at the Wheatstone and Iago fields and nearby third-party fields it is expected to be approximately 1.6 Bcf/D.

At Gorgon, we shipped our first cargo of LNG from train 1 in March and are in the process of ramping it up. All modules for trains 2 and 3 have been delivered to the site and construction is progressing. Lessons learned from train 1 are being applied, and key milestones are being achieved on-schedule with startups expected at approximately 6-month intervals after train 1. At Wheatstone, hookup and commissioning of the offshore platform is progressing. Eight of nine wells are drilled and completed. At the plant site, the operations center and LNG loading jetty are complete and hydrotesting of the first LNG tank has been successfully completed. First LNG cargo is expected to be in mid-2017.

What is the timeline to develop this resource, from concept to production?

LP: An SAGD project, such as Christina Lake, typically takes about 5 years to move from a concept stage to production, but it can vary depending on the location and scope of the project.

Cenovus’s approach to developing its oil sands assets is somewhat different than the traditional megaproject concept. Because of the size and nature of the resource base at Christina Lake, we determined that a large, scalable project with periodic repeatable expansion phases was the optimal way to capture value from the asset, leverage economies of scale, and apply the required technology to commercially develop the resource.   

RD: When there is existing infrastructure, these projects can be executed extremely fast, often within 1 year or less. Where there is not a lot of local infrastructure, then detailed capital planning and project development is required, which can take several years.

PH: Large-scale LNG projects typically take a decade or more from concept through front-end engineering and design to final investment decision and construction.

Daniel Picard (DP) on Petrobras’ Libra project: An offshore megaproject follows the same steps as other projects of a smaller scale. In general, it takes a long time. In some cases the development timeline may take up to 10 years from first discovery to first production of a resource.

After a discovery, the field has to be appraised to determine the extent of the resource, and if there is enough resource in place to support an economic development. After this, there is an important phase of conceptual studies to determine how to best develop the field, which could last a year or more. Subsequent to this, pilots are often undertaken of the selected concept, to assist in obtaining a better idea of the cost of the project, and how to best plan the development. At the same time, various other environmental, geological, and engineering studies must be completed, all of which can take several years.

Then, if the project appears to be accretive, the operator will request quotes from the market for the key items of the project, such as drilling, surface and subsea facilities, pipelines, and so on. When the project is shown to be economic and creating value for the operating company, the sanction of the project may be obtained, and the project itself enters into its development phase, which typically lasts between 30–50 months, depending on the complexity of the project, before it commences production.

What are some of the major external factors that influence the development of this resource?

LP: I am a strong believer in the benefits that development of the oil sands brings to Canadians and our potential to help meet the world’s growing energy demand. I am proud of working on solving the technical challenges such as reducing or potentially eliminating greenhouse gas emissions associated with our oil. Many of the challenges the industry currently faces, such as low commodity prices, lack of market access, and uncertainty about the fiscal and regulatory environment, are beyond our control. That is why we are focused on the things we can control such as reducing our costs, maintaining our financial strength, and focusing on technology and innovation to continually improve our economic and environmental competitiveness.

RD: On an absolute dollar basis, when compared to other megaprojects such as offshore and deepwater developments, the cost structure for shale wells is very attractive. Well costs in an established area will typically be less than USD 10 million, although these costs are heavily influenced by the choice of stimulation (fracturing) as well as the drilling length and depth. Plant and facility costs are also relatively inexpensive and scalable in this environment. Individual well production declines, however, are typically steep, so to sustain field-level production rates over the long term, a significant and continued drilling program is required. As a result, shale projects will typically include plans for the drilling and completion of many wellbores to achieve and sustain the desired field-level production rate.

There are several potential bottlenecks that can be encountered with the development of an unconventional resource. In international locations, it has been found that market access and regulatory requirements can be extensive and may slow down these developments when compared to similar developments in North America. Production infrastructure can also become a bottleneck when existing pipelines and facilities become overwhelmed. Service companies and operational infrastructure play a huge role. In areas where more established services are available, it is much easier to scale the business than it is to start from scratch. For new projects, these factors are all very important to evaluate in detail.

Another attractive feature about shale developments is that the reservoir is typically significantly areally extensive. Although individual well results can vary, on aggregate, field-level production can be relatively well-understood and predicted, which allows for production targets to be achieved. It is very likely that in the current economic environment more technology will be applied to further drive down the risk and improve the productivity of these assets.

PH: A best practice on large-scale LNG projects is to work closely with your key stakeholders to keep them informed of project progress through construction and first gas production. We have the benefit of the highest quality customers and joint venture participants on both the Gorgon and Wheatstone projects, and we value the long-term relationships that have been cemented throughout the development process.

DP: The key driver of a megaproject (or any project) is essentially to maximize the net present value and internal rate of return of the project. These factors are both economic drivers; however, many other objectives are also expected to be met. These may include constructing and operating the project in a safe manner; demonstrating environmental stewardship; and successfully working with local governments, regulators, and communities.

The most important driver of project economics is the oil price, which is particularly evident at times when the oil price is low. In today’s price environment, with WTI oil in the USD 30-40/bbl range, the breakeven costs of all projects must be reduced as much as possible. This is a complex but necessary task for an offshore megaproject, and it is most easily achieved during the conceptual and pre-project stages—keeping design requirements to a minimum. After the project requirements have been optimized to be as economic as possible, it is then up to the market to compete to further drive down the capital costs of the project. One risk to the market competing and adjusting to lower prices is that highly skilled and experienced staff can be lost, and it can take the industry many years to recover this expertise.

For a deep offshore megaproject, capital costs are extremely important due to the magnitude of such expenditures. As an example, a project may cost upward of USD 10 billion in capital costs, allocated roughly as USD 4 billion to drilling, USD 3 billion to surface facilities, and another USD 3 billion to subsea facilities and pipelines. All of these items are subject to an international call for tenders to receive the best cost estimates possible.

Other important factors are of course the fiscal and regulatory regimes of the country involved in the development. These factors can be significant enough to encourage or discourage development in one jurisdiction over another.

Is a manufacturing approach used? Is it successful?

LP: Yes, a manufacturing approach has helped us achieve success on the Christina Lake project. This approach for Cenovus meant that we use a templated central facility design to build our expansion phases, which has allowed us to achieve industry-leading capital efficiencies. 

To build on this success, we have recently applied a manufacturing approach to the sustaining portion (wells, pads, and associated gathering and processing infrastructure) of our business. For example, we have created a new well facility design (zero-based module design) that we expect will significantly reduce the footprint and cost of new well pads and allow us to use a repeatable design for new pads at all of our assets.

Lastly, we are currently undergoing a transition of our organizational structure to a functional model. This will allow us to better leverage our manufacturing expertise and implement its benefits across the corporate value chain. 

RD: Several operators in a variety of shale plays have attempted to incorporate a manufacturing style of drilling and completions during their operations. It is being observed that this may not be the ideal solution for all cases as there is a significant amount of reservoir heterogeneity that can negatively or positively impact well performance. The most successful operators of unconventional shale resources have achieved a good balance between a manufacturing approach to drilling as well as utilizing applied technology to create an effective solution for a specific area. It must be noted that what is successful in one area will not always work in other locations, meaning that an understanding of the reservoir is required to achieve success.

What lessons have been learned from the experiences in developing this resource?

LP: As a young professional working on the Christina Lake Project, I have been amazed at the amount of change and technical progression we have achieved over the past 5–10 years. We have found ways to improve everything we do, from our reservoir exploitation strategies to our surface facility designs; we even have drilling rigs that can now be transported by helicopter. All of these advancements have materially improved the economics of our projects and many have reduced our environmental impact.  

Despite all the progress I have seen in my career so far, I think the most exciting thing is the progress we are going to make in the future. There are many revolutionary technologies currently being worked on that could materially change the way we develop our oil sands resources. One such technology is the solvent-aided process (SAP), which involves injecting a small amount of light hydrocarbon with the steam to help extract oil from the reservoir. The SAP is expected to be up to 30% more energy efficient than SAGD, and to yield material economic and environmental benefits.

It is the development of these game-changing technologies that gets me excited to come to work every day with the hopes of one day implementing them at our operations. Harbir Chhina, Cenovus’ executive vice president for oil sands development, has a great quote that sums up my opinion of SAGD projects, both in the past and now: “SAGD development is like a baseball game and we are only in the second inning. The best is still to come.”

RD: In short, continuous improvement is a must to be successful in the long term. There are far too many lessons learned to list in full detail, but key things that have been noted are as follows:

  • Reservoir understanding is critical, and having a good data and information acquisition plan is a requirement. The use of forward-modeling tools to improve completion designs has proven to be very successful.
  • Well placement, both regionally and stratigraphically, is critical to achieving the best results.
  • Shale reservoirs are very different than conventional reservoirs. When dealing with transitioning reservoirs, pressure/volume/temperature data are highly variable and dependent upon local geology.
  • Long-term production understanding in these reservoirs is still largely unknown. As these fields age, one should expect that there will be more lessons to learn.

Ron Dusterhoft is a Halliburton technology fellow for production enhancement with 32 years of industry experience. His areas of expertise include hydraulic fracturing, FracPac completions, sand control screens, sand consolidation, sand control downhole tool systems, completion design, and reservoir simulation for shale. Dusterhoft is currently focused on drilling and completion optimization and stimulation design for unconventional shale assets. This involves the use of full asset workflows and more effective data management to maximize collaboration and knowledge-sharing between geosciences and drilling and completions engineering. Dusterhoft has been actively involved in the full-scale deployment of these workflows and solutions in large US-based field developments.

Logan Popko is manager of asset development for Christina Lake at Cenovus Energy. Popko started his career with Shell as a co-operative student in 2005, and later obtained a degree in oil and gas engineering from the University of Calgary. Since graduating, he has worked for Cenovus (and its predecessor Encana). During his time in the oil sands division, Popko has worked in a variety of roles and projects, including production, operations, reservoir, and capital projects.


Pete Hagen is general manager–commercial, at Chevron Australia. He is responsible for the Chevron Australia Commercial Function, located in Perth, Western Australia. His role encompasses upstream business development and commercial strategy formulation and implementation, commercial support for asset development and major capital projects, operations commercial support and joint venture interface, and liquefied natural gas and domestic gas lifting coordination. He has more than 35 years of experience in the oil and gas industry. Previously, he was Chevron Australia’s strategic planning manager and Greater Gorgon commercial manager. From 2008 to 2014, he was general manager, gas commercialization, for the Europe, Eurasia, and Middle East region for Chevron, based in London. Hagen graduated from the University of Michigan with a bachelor’s degree in economics.

Daniel Picard is special adviser to the director of the Libra Project, Petrobras, on secondment from Total. Picard joined the oil and gas industry in 1978. He has spent most of his career with Total in the upstream exploration and production (E&P) branch of the company. Previously, he worked as the E&P director of Total Norway, Total Qatar, and the Dalia Project, a major deepwater project offshore Angola. Later, as vice president for development, he had decisive implications in all Total E&P projects, particularly in the deep offshore West Africa megaprojects such as Pazflor, Kaombo, Clov, Moho North, and Egina, and was involved in Russian arctic offshore projects such as Shtokman. Picard graduated from École des Mines in France, and holds a master’s degree in mechanical engineering from Stanford University, and a degree from INSEAD.



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