Selecting appropriate field development plans, risk management, and modifying project implementation methods is essential to maintaining the viability of deepwater oil and gas projects.
The second part of this two-part article lays out considerations for flow control and assurance, processing and support, transportation and storage, schedules, abandonment, and other aspects of complex projects.
Flow control and assurance
Flow assurance aspects represent both revenue and cost risks.
Any upset in flow from the wells will directly impact the volume of product available for sale, and the cost of rectifying a flow problem in deep and cold water will represent a formidable cost risk.
Increasing the robustness of a system to very high levels implies increased equipment costs, which ultimately may make the project uneconomic. Hence, it is necessary to strike a satisfactory balance between the capital investment requirement and an acceptable level of risk. Flow assurance is a critical issue for concept evaluation, commissioning, safety, security, start-up, and post start-up phases especially in long distance tieback field developments.
Innovative technology and flexible well intervention contingency plans and options should operational problems arise are the key to addressing flow assurance issues and can influence the cost risks. The implementation of transient multiphase modeling will normally provide guidelines to safe operational strategy development and in assessments of operational risks.
Most deepwater developments include a host surface facility with multiple subsea well tiebacks in order to cover the full area extent of the reservoir.
This host facility commonly only accounts for substantially less than 25% of the total project costs; however, if it fails to perform or its operations are adversely impacted (e.g., Thunder Horse platform in the Gulf of Mexico) all the expensive wells tied back to it also are unable to perform.
Even if the host facility has dry trees for the initial suite of production wells, additional subsea tiebacks in later field life are usually envisaged.
The host facility design must therefore make adequate provision for the flow assurance and operability requirements of subsea tiebacks, both initial and future, i.e., redundancy must be built in. The more redundancy that is built in the more complex the facility, and as complexity often translates into high cost some critical tradeoff decisions must be made.
Flow impedance issues such as formation, mitigation and control of hydrates, wax, and asphaltenes, sands, and scales must be assessed and modelled in detail. Particular issues which industry’s experience has shown require careful consideration7 8 include:
- Arrival temperature management-provision for heating or cooling of arriving fluids may be required, over a range of operating conditions;
- Liquids management-multiphase fluids from subsea tiebacks may generate significant slugging, either during steady state operation or during start-up and ramp-up following a turndown. Liquids carryover may also occur during flowline depressurization (blowdown). Such occurrences must be accommodated in the sizing of the host facility slug catcher/separator.
- Hydrates management-if MEG injection subsea is proposed for hydrates management, then the storage, injection, and regeneration system and its associated utilities (particularly power for heating or cooling) may be a significant space and weight consideration for topsides design. If methanol or glycol is proposed, again the storage and injection systems need to be accommodated.
- Wax management-if hot oil circulation is selected to warm up the subsea systems prior to start-up to avoid wax deposition, then the circulation system must be provided topsides. It is important to size the system to accommodate possible additional tiebacks if these are contemplated. If wax inhibitor injection is proposed, again the storage and injection systems need to be accommodated.
- Chemicals injection-topsides storage, injection and resupply logistics must be considered. Chemicals injected subsea may include scale inhibitor, wax inhibitor, antiagglomerant, and corrosion inhibitor. This may impact integrity issues such as design and management of corrosion and erosion problems.
- Deliverability issues such as optimization of flowline sizes, artificial lifting, topsides equipment and arrival pressures, and viscosity management for heavy oil system and emulsions.
- Stability issues such as control of system upsets and slugging during normal and transient operations;
- Safety and security issues-at the flow assurance stage there is still sufficient flexibility to design inherent safety and security features into a facility.
Hence, key technology needs to provide a robust solution with acceptable risks to future production in the above-mentioned items.
Processing and support
To stabilize produced well fluids, and to separate marketable products from them, they must be processed.
Facilities to carry out some processing are usually located offshore at or close to the field but are sometimes located fully or partially onshore and linked to the wells by a long-distance multiphase pipeline. Processing facilities usually require:
- Deck and structures (fixed or floating) to support the deck.
- Manifolds to tie in producing wells to processing vessels.
- Heat tracing/insulation capabilities such as electrically heated flowlines.
- Separation, stabilization, and gas and water treatment vessels.
- Testing and metering equipment.
- Compressors and pumps.
- Export systems with metering.
- Utility, power, and safety systems.
- Personnel accommodation facilities.
Processing facilities for deepwater fields are commonly placed on floating structures. In some instances it is possible to use tension-leg platforms (TLPs), but large-scale barge-like FPSOs are becoming more widely used for the processing facilities of large remote deepwater fields. Alternatives to this include:
- Placing substantial process functions downstream linked to shore-based facilities by multiphase pipelines.
- Placing some process functions (e.g., water separation) upstream of the offshore surface facilities (e.g., subsea manifolds linked to downhole or subsea processing equipment).
New subsea technology options may offer less weight and reduced cost for the surface facilities but usually increase operating cost risk and revenue risk. Such higher risks should be factored into the project economic evaluations. Some technology that is currently under development to improve project economics and recovery includes:4
- Extra long (up to 150 km) composite umbilicals for controls, methanol injection, and signals.
- Fiber optic technology for controls of up to 300 km length.
- Advanced flow assurance techniques to design for and mitigate hydrate formation.
- Subsea multiphase pumping.
- Subsea gas/liquid separation and liquid pumping.
- Subsea gas compression.
- Two or three phase subsea separation.
Designing facilities to be flexible to facilitate the addition of extra capacity or evolving technology improvements can lead to substantial economic benefits on a life of field basis for acceptable additional costs.
Failing to design in flexibility for future unforeseen expansion of facilities may lead to prohibitive future costs and an inability to exploit opportunities as they materialize in the future.
Transportation and storage
Access to and reliability of third-party transportation and storage facilities represent a potential revenue risk.
Recent technological advances in floating LNG and floating storage and regasification units enable gas storage and transportation costs to be reduced and can ease access to gas distribution networks. Such developments offer the potential to unlock many stranded offshore gas fields for development. LNG regasification plants, now becoming more widely distributed in the main global gas markets, offer a ready market for this gas.
Building large complex floating storage and offloading (FPSO) systems, designed specifically for a field’s reservoir performance characteristics and capacities, is often the critical long-lead time item in a deepwater field development. Consequently, delays in completing the construction of these vessels also pose a significant revenue risk.
Schedules
Achieving early production from a field development can significantly enhance project economics.
However, if a project’s planned schedule to achieve early production is too ambitious it often leads to added costs being incurred to achieve it. Robust project planning, teamwork, cost control, and contracting strategy are essential to achieving production on schedule.
It is important to recognize that serious accidents and incidents (safety and/or climatic) can lead to persistent project delays many months after such events occur (e.g., Hurricane Katrina, 2005; Petronius accident in 1998 where a $70 million platform deck sank in the Gulf of Mexico).
Resources deployed to rectify impacts and investigate causes of incidents can seriously impede project progress. Building contingencies into project schedules and budgets for unforeseen eventualities can help to partially mitigate their impact on a project schedule.
Design-build time cycles are becoming more compact and schedule and start-up delays in deepwater fields, due to a variety of reasons, can have a substantial negative impact on project costs and ultimate project profitability, often destroying value that cannot easily be recovered.
Cash flow sensitivity analysis of deepwater projects shows that they are particularly vulnerable to cost and timing overruns because they are high-cost projects to begin with and each day of delay is so expensive.
For most onshore or shallow water field developments cash flow sensitivity analysis suggests that oil price and reservoir performance (production rate and reserves) are the key factors determining profitability. In the case of deepwater projects costs and project schedule (time to first production) can have comparable impacts on profitability.
Consider a cash flow sensitivity analysis for a deepwater field offshore Nigeria (Fig. 5). The wider the horizontal bars, the greater the project’s economic sensitivity to that factor.
The capital expenditure bar is wider than the others (typical of large deepwater and LNG development projects). The production timing sensitivity case in this example were delaying (which extends bar to left) and accelerating (which extends bar to right) production by 1 year. Longer delays would extend the production timing sensitivity bar to the right.
Some may say in the current oil and gas price environments that what is lost in delayed scheduling can be recouped by high product prices. Obviously this is a risky approach as there is no guaranty that prices will remain high over project lives measured in decades. But Fig. 3 (Part 1 of this article) shows that this is actually not the case.
The bar for oil price sensitivity is asymmetrical with more downside than upside. This is due to the impact of fiscal terms that ensure that the government and national oil companies (NOCs) see most of the upside in high price environments, whereas the international oil companies (IOCs) see all of the downside risk of cost and timing overruns. IOCs therefore have added incentives to carefully manage project costs and schedule risks and mitigate carefully against overruns.
Indeed an early stage risk management strategy could be to seek tax incentives (i.e., a greater share of the upside) from governments in return for making high-risk investments offshore. This, however, is easier said than done. It was achieved in the mid-1990s in Nigeria, but once giant fields were discovered and perceived exploration risks reduced the government soon clawed back most of the incentives.
Wet gas can provide substantially more robust project economics than dry gas particularly if liquids can be tied into existing infrastructure at low cost. This additional revenue stream can help to offset the high capital cost risks of deepwater gas field developments. In a similar way integrated projects including deepwater gas field and onshore processing plant and-or LNG and GTL facilities provide more economically attractive projects than stand-alone gas field developments.
As well as revenue/cost benefits key advantages of integrated projects are that risks are spread along the gas supply chain and the projects can be made more contractually robust, mitigating some of the risks associated with government or third-party manipulation.
Managing the risks
Risk standards and tolerance levels must be set for effective project execution.
Skilled project participants are often highly specialized and are located continents and time zones apart, when different components of a complex facility are fabricated in different yards by isolated teams.
A key role can be played in this regard by an experienced interface coordinator with the objective of promoting closer teamwork and minimizing duplication of effort.
Ideally, the personnel should be familiar with the local conditions and culture, but it may be difficult to assemble such a team(s), e.g., in Southeast Asia, only one major deepwater EPC development has been installed (Unocal West Seno, Indonesia, 1,000 m of water) and only two or three others are through FEED phase.
However, a number of major engineering and construction companies in the region have executed similar projects globally and can draw on these resources if required. Also, especially in today’s vibrant market, it is not always possible to have a team of superstars.
Nonetheless lack of communication is not uncommon between commercial asset managers, geologists, geophysicists, drillers, engineering and installation contractors, supply chain managers and, ultimately, those who will be tasked with operating and maintaining the deepwater facility once completed.3
Interface management should be able to avoid this. So can effective executive reporting-data collected from all project teams is compiled into a concise report that allows other teams, project managers, directors, partners, investors, and all stakeholders to understand the project status.
Such reports can succinctly communicate, in both commercial and technical terms, the outstanding risks and existing mitigation plans, the forecast final cost at completion, the most likely date for project completion, together with safety and quality performance issues.
Integrated execution
To effectively establish an integrated project execution framework or model it is important to formulate from the outset a contracting strategy, a holistic risk assessment methodology, an experienced and dedicated team, an applicable design criteria, and integrating this into a project execution plan and model.
Using such an integrated project execution model that identifies and manages risks throughout project execution is an essential success factor.
Project team
The organization of the team is another factor.
A dedicated team means the personnel are always available for the project, but this requires a larger personnel budget. A team shared with other projects, however, risks personnel resources being in short supply when they are required, although knowledge transfer between projects becomes possible.
Experience is invaluable, not only in the exploration and development phases, when risk assessment may frequently be called for, but also during the execution of the project, when risks have to be controlled and managed. The other aspect of team structure is contracting, i.e., the number and nature of contractors, spreading risks, expediting supplies and services, and managing the number of interfaces and communication channels.
When new technologies or complex projects are involved, it may be advisable to limit the number of contractors and EPC contracts, especially if it involves working extensively with unfamiliar parties. In all these cases, stringent gate reviews and quality milestones will help manage the technical and cost risks.
A clear understanding of the potential risks in all the phases of the project will enable the operators and contractors to set up strategies specific for a deepwater field development. It is well worth taking the time to understand the project, especially any unique traits or requirements.
In the exploration phase, the fundamental risk is reservoir uncertainty. This risk can, to a certain degree, be mitigated by appraisal drilling and advanced seismic, but economics dictate limited early investments. Reservoir uncertainties must therefore be reflected in flexible development schemes, e.g., phased developments, where large capital expenditures can be delayed until reservoir performance is verified by some production history.
During the development phase, risk analysis techniques provide a means to estimate the risks and reliability during every stage of development and during production.
By comparing the estimated risk costs and projected revenues, the operator can select the preferred alternatives. Seemingly costly feasibility and engineering studies may incur additional expense, but this is frequently justified when the information gained provides a major reduction in total costs and risks.
Substantial cost overruns in several high-profile, remote, offshore projects over the past couple of years (e.g., Bonga field Nigeria, Snohvit LNG Norway, and Sakhalin II Russia) can be attributed to a large degree to failures in the feasibility and early stage planning to adequately identify risks and to devise and employ appropriate risk mitigation strategies.
During project execution, the cost risk may be handled by limiting the use of new and unproven technology, and by employing project execution models, which are based on thorough and mutual understanding of project requirements and risks by all parties in the execution scheme.
Abandonment
The abandonment of a deepwater field challenges a company’s ability to control expenses and liability.
More conventional techniques are used for abandoning dry-tree type completions, but tubing retrieval and abandonment of subsea completions require the same specialized equipment used for initial installation at a very high cost.2
Advances in new technology and techniques should provide the industry with cost- and risk-reduction opportunities for deepwater field abandonments. The technology, concept design and the complexity of deepwater operations have changed dramatically in the last 5 years.
To sustain the growth of deepwater operations, the industry will be continually challenged to make new advances. It is in the interests of both operator and service industry to provide solutions to the technical challenges we will face.
Acknowledgment
The authors thank Satinder Purewal of Imperial College, London, and Robert J. Wilkens, University of Dayton, for assistance, comments, and suggestions.
References
- Hauge, L.H., and Cramer, E., “Project Risk Management in Deepwater Field Developments,” US DOT 2002, New Orleans, 2002.
- Cromb, J.R., “Managing Deepwater Risk and Challenges,” Schlumberger Oilfield Review Magazine, Vol. 11, No. 4, winter 1999.
- Yale, R., and Knudsen, J.I., “Business Risk Management: An Essential Tool,” World Oil, Vol. 227, No. 1, January 2006.
- Shelton, R., “Managing Challenges in Deepwater Projects,” PetroMin, July 2005, pp. 16-22.
- Wood, D., “E&P Asset and Portfolio Risk Analysis: Addressing a Many Faceted Problem,” OGJ, Sept. 29, 2003, pp. 49-56.
- Wood, D., “More Aspects of E&P Asset and Portfolio Risk Analysis,” OGJ, Oct. 6, 2003, pp. 28-32.
- Wilkens, R.J., “Chapter 29: Flow Assurance,” in Saleh, J., ed., “Fluid Flow Handbook,” McGraw-Hill, New York, 2002.
- Smith, N., and Shirley, R., “Key Issues in Deepwater Project Implementation,” PetroMin, August 2005, pp. 30-37.
Bibliography
Wood, D., “Portfolio Valuation: Benefits of Integrating Risk and Strategic Goals Models,” Petroleum Economist, June 2002.
Wood, D., “Nigeria: Evolution and Economic Performance of Production Sharing Terms,” Petroleum Review, January 2003, pp. 36-40.
The authors
David Wood ([email protected]) is a consultant who specializes in the integration of technical, economic, risk, and strategic information. His services include project evaluation, research, and training on a wide range of technical and commercial topics. He is based in Lincoln, UK but operates worldwide. He holds a PhD from Imperial College.
Saeid Mokhatab is a natural gas engineering research advisor to the University of Wyoming and a senior project consultant for hydraulic design and engineering of natural gas transmission pipelines and processing plants. His research is widely published, and he is a member of the SPE Distinguished Lecturer Committee and several other professional committees.
