New approach to field development can improve project feasibility
Field development planning requires seamless collaboration and interface between subject matter experts from three major disciplines: subsurface reservoir management, drilling and completion, and subsea plus surface facilities with associated production planning.
Field development planning requires seamless collaboration and interface between subject matter experts from three major disciplines: subsurface reservoir management, drilling and completion, and subsea plus surface facilities with associated production planning. Each step is bound by the science of business economics of systems selection, engineering, procurement and contracting strategy, regional politics, technology risk and opportunity, and health and environmental safety. The process is challenged by the risk of reservoir uncertainty while trying to justify a robust business case capturing the possible potential, especially when estimated net recovery is low (marginal fields).
Afield development plan consists of a reservoir depletion management plan, drilling and completion plan, production management plan, and facilities systems concepts. These are selected through iterative interactions from multitudes of variations of the three main disciplines subsurface, drilling completion, and surface facilities. Each reservoir comes with its unique constraints in terms of reservoir and other associated parameters influencing system selection. This makes it difficult to use reservoir depletion analog, especially for recent high-pressure/high-temperature discoveries in ultra-deep Lower Tertiary subsalt Paleogene sands where adequate past experience history is very limited.
There is no perfect solution in terms of life cycle cost (capex + opex) and safety primarily due to reservoir uncertainty in terms of well count, completion and intervention, net recovery, and fluid properties. Even considering a given reservoir of absolute certainty, different system concepts and development plans may be justified as a strong business case depending on company or individual bias. Only time can really tell if a selected concept is fit for purpose and fulfilled expectation relative to competing concepts.
Field development evaluation must consider strategies of procurement, project delivery, and contracting early on as they have significant impact on cost and schedule, thus ultimate success of the selected field development plan. Absence, inadequate, or inefficient strategies may jeopardize the success of an otherwise sound field development concept plan. These strategies add robustness by reducing project execution risk and other associated uncertainties.
The following depicts a pragmatic fit-for-purpose approach that combines the best practice for each major discipline. The procedure needs a multi-discipline experienced team, with deep understanding in their respective and interfacing domains, using a systems approach challenging each constituent functional element, system, and procedure in terms of technology assurance of quality, risk, and opportunity. Empowered champions must take the lead to step changes challenging the current techniques and practices. If not, high costs associated with offshore oil and gas exploration and production will continue to be a barrier to futuredeepwater field development especially for challenging small fields.
Managing field development concept economics and risk are a series of decision making processes with the objective to reduce risk and maximize potential. Poor framing of problems, missed important aspects and opportunities, or sometimes topics addressed inadequately with full spectrum of possible outcomes are some of the unknown pitfalls in a decision making process. Framing of problems must be robust to ensure consistency of results. There should be a procedure in place to measure compliance with risk criteria, value generating decisions, and mitigation of risks associated with options. The process will address how and to what extent each option will satisfy objectives, which represents “value” in terms of cost, schedule, operability, and constructability. Risk is the barometer of uncertainty and unexpected events affecting value proposition negatively (risk) or positively (opportunity).
Following discovery of a prospect and initial reservoir characterization, high level preliminary evaluation is made in terms of operator’s strategic vision, commercial and technical risk, safety requirement, potential for maximum return on investment (ROI), and minimum risk to capital, life, and environment. The assessment is performed based on past experience, data, knowledge, and/or lack of it. The prospect will be further pursued only if all the findings are positive.
The final field development plan is selected by comparing risked life cycle financial values in terms of net present value (NPV) or ROI of the competing plans. These consist of different development scenarios with different logical and intuitive combinations of a reservoir depletion plan, production plan, and choice of drilling, completion, and facilities. The plan with highest median (P-50) NPV and lowest spread between P-90 and P-10 NPVs with the shortest schedule will be selected. A high P-50 represents maximum return and lower difference between P-90 and P-10 reflects reduced uncertainty. Individual companies have their own levels of requirement of these probable NPV values for a plan to pass this gate. In addition, actual procedure for determining the P-10 and P-90 value may be different.
|Effective field development planning requires seamless collaboration between subsurface reservoir management, drilling and completion, and subsea plus surface facilities.|
Uncertainties in high value spending and revenues are included through assigned probability distributions representing uncertainty and risk. For example, a spar platform has higher execution risk as opposed to a semisubmersible due to increased offshore marine operations for installation and commissioning. A risk reduction factor may be used on the ground of past successful executions. A platform-based drilling operation has high capex but less opex and uncertainty compared to using a mobile offshore drilling unit (MODU) with increased cost and schedule uncertainty. The screening process must consider both capex and opex.
The selection screening process requires specialized tools, extensive reliable database, lessons learned, and an integrated team of highly experienced personnel with deep understanding from all disciplines to guide in a rational and fit for purpose manner. The field development plan management team should produce capex, opex, and schedule estimates of competing scenarios. Generally, estimates are made at -20% to +30% accuracy. Estimates are validated extensively through benchmarking, standardization, and normalization for consistency and financial equivalency between competing scenarios.
Oil and gas projects run on status quo. There is a natural reluctance to be the first to adopt a new technology or solution. Engineers will find creative ways to push technical solution boundaries when challenged with a problem. Eventually, we will face the technical limits where we will have to change the game. We need visionary executive leadership empowered to take decisions who will embrace step changing technology.
Enabling technology. When pushed to the limit, an enabling technology may get a chance through proper qualification and verification. Here limit means there is no other alternative than to abandon or postpone the project. Cost of an enabling technology is not a factor any more as long as overall NPV satisfies the company requirements.
Technology of opportunity. Promoting technology of opportunity is very difficult in a high consequence environment where it is easier to follow than lead to adopt new technology of opportunity to reduce cost. However, for small deepwater fields technology of opportunity must be developed and pursued in low risk areas where reward exceeds risk otherwise they will never satisfy economic criteria. For example, low cost dry tree capable semi type hull or TLP for deeper waters.
Standardization of technology, design, contracting, and sourcing can reduce cost and improve schedule significantly. This is more so for procurement schedule where it may become an enabler for long lead items. All big operating companies take advantage of standardization one way or other at least for procurement contracts. Design standardization is not so common within oil and gas field development. Exceptions are MODU rig designs which are built on payload steps and BOPs and trees that are built on pressure rating steps. In most cases, floating systems, topsides facilities, and subsea hardware and risers are purposely designed, specified, and constructed. However, these systems may be designed and built in a standardized approach, based on step change. For example:
- Hull form designs in 3,000-ton payload increments, three steps of environments, and three steps of water depth
- Topsides facilities with steps in pressure rating and sweet or sour service
- Subsea hardware and pipelines based on pressure and water depth steps plus sweet and sour service
- Flowlines and different types of risers in steps of pressure rating and sweet and sour service.
Procurement is a key element in the execution and delivery of any design and construction project. There should be a dedicated team in charge of sourcing suppliers, buying, expediting orders, inspecting bulk materials and manufacturing, and organizing delivery and logistics. The team has full ownership of the budget and the delivery responsibility bounded by all stakeholder policies and code of ethics. The focus is on global procurement increasing supplier base through sourcing and qualification of new suppliers and products with target on high value items as well as dissemination of market intelligence and trends across all groups. Oil and gas exploration and production is driven by changing technology and long lead capital intensive procurement. Informed decision making is critically important. Supply and demand information on raw materials, equipment, fabrication, engineering, MODU, and construction and installation vessels can help give visibility over future pricing changes and potential of any disruption. This is valuable information for operating companies to have during field development planning.
Project delivery strategy
Field development engineering is not only limited to selection of system concepts. It must also take account of the impact on cost, schedule, and execution risk of all attendant project delivery strategy and contracting. A well thought-out delivery strategy including contracting can help the bottom line NPV and reduce project execution risk.
Strategy is formulated based on iterative discussions early on of any project, which then gives shape to subsequent plans and actions. Often, we are quick and use past experience analog, which may have had different size, complexity, or risk than the one in hand. It is worth spending some time at the beginning to bring everyone together, develop strategy, and document in the project execution plan. Without clear strategy, direction, and a project execution plan, inefficiencies and misalignments can occur, resulting in major financial consequence. For large offshore projects (half to several billion dollars), it is better to have a main overall project execution plan and then separate front-end and execution plans for several convenient related project packages. A full field development project program may be managed in separate projects as drilling, production, facilities, hull and mooring, and SURF facilities with proper interface links. Economy of scale comes from the common execution plan strategies applied across all projects.
The program execution plan should outline ways on how the team will avoid inefficiencies of a very large project “diseconomy of scale” and achieve economy of scale through proper standardization, optimization, and integration across the entire project. The front-end plan provides project scopes, plan, and optimization prior to sanction, based on the following:
- Evaluate alternate field development options, including system designs and concepts
- Outline scope and system design concept options
- Develop project execution plan
- Identify and propose mitigation of all risks
- Implement best practice on project organization and management, team alignment, value-improving practice, opportunity and risk management, and lessons learned.
The project execution plan describes the planning for design, construction, installation, commissioning, and start-up of the facilities. The focus is on execution after sanction creating the project level plan for:
- Meeting project functional and HSE objectives
- Organizing, contracting, and conducting execution plan
- Managing risk, opportunity, and changes
- Aligning the team for project execution and interface
- Manage quality, cost, schedule, and resource.
During the past few decades, large oil and gas projects were managed by commissioning outside contractors on an engineering, procurement, construction, and installation (EPCI) or lump-sum turnkey (LSTK) basis and combine with in-house resources, forming a dedicated project team in charge of preparation, execution, and delivery of the project. While most of the elements for success were often present, this approach did not always bring anticipated benefits to owners or contractors. In recent years, contractors have suffered heavy losses and operators faced schedule delays, cost overruns, and operability problems. Some of the reasons may be attributed to the following:
- Lack of proper placement of project risks
- Absence of clear definition of the work scope
- Tendency to be overly optimistic in all aspects, including superiority complex and complaisance
- Biased approach from team members or stakeholders
- Not understanding potential negative events and local content issues
- Operators relying on contractor to provide new technology solutions when contractor has limited capital resources
- Lack of deep understanding of the system design, construction, installation, and not properly including the potential impact of project delivery and contracting strategy.
In recent years, offshore projects are extremely large, complex, and less frequent. They require significant amount of upfront capital, expertise, and technology resources and pose high potential downside losses. Technology driven and evolving field developments require high competency from all parties. Small field developments also depend on enabling or opportunity technology to be economically viable. Technology subject matter experts with broad and deep understanding in linked disciplines are in short supply, particularly within the operating companies due to re-organizations in the past.
Problems with the past EPCI contracts and the escalated costs which followed have resulted in a demand for an alternative approach assuming that the direct owner’s team approach is not feasible. In an owner’s team approach all contracts are direct between company and service provider. The company mostly assumes all risks, and success depends on company’s ability to manage multitudes of contracts and stakeholders interactions. For various reasons, even if a company has the resources, this approach may only work for smaller repeated projects. Primary issues with EPCI contracts echoed within the industry are allocation of risk and lack of definition of work scope. Based on this, an alternative is an engineering, procurement, and construction management (EPCM) contract.
The EPCM approach is somewhere in between owner’s team and EPCI approach. In the EPCM approach all contracts are between company and contractors thereby risk is with the company. A professional EPCM service company performs design, engineering, and construction management but not a party to any contract related to construction or vendor provision. The relationship is like an owner-agent where the owner monitors and influences performance and progress of the project. The main responsibilities of an EPCM service provider are:
- Design including FEED as necessary to complete the project efficiently
- Planning procurement, bidding, and administration of contracts
- Maintain overall schedule on track
- Administration of construction and vendor contracts
- Manage interface, changes, and report to owner.
Some of the major limitations for the owner in an EPCM approach are:
- Owner must be very pro-active to meet the construction responsibility
- Owner needs to integrate key people in strategic positions within the EPCM organization to ensure day-to-day monitoring and control
- Owner takes the ultimate responsibility on cost and schedule.
In an EPCM approach, the owner must have adequate resources to integrate with EPCM project team during all phases of the project. Some of the universal characteristics of a successful project are:
- Strong cross-functional and integrated project team
- Adequate front-end loading by project knowledgeable business leadership
- Engineering and project functions report to owner directly
- A system of continuous improvement (sign of excellence)
- Systematic progress and performance measurement
- In-house resources to develop and shape projects ready for detail design.
Contracting strategy of a large offshore project can take various forms. There is no unique ideal solution. It will depend on many factors, namely market condition, project type and size, operator and contractor resources, level of engineering definition, and finally a good project execution plan. It must be recognized that at the end of the day operating companies take all risks and pay for it all one way or other. The philosophy should be to use a pragmatic, well-defined/task-based, fit-for--purpose approach. Develop a strong project management plan, provide contingency measures for any indication of cost overruns or schedule delay, and then hope for the best and prepare for the worst.
Generating economic value and control risk of a field development plan comes through the art of linking varieties of disciplines, applying the science of logical determination of boundaries, and finally engineering, planning, and managing with courage and persistence.
The high cost of oil and gas exploration and production in deepwater and deep reservoirs means that only large fields will be able to satisfy rigorous economic screening. A pragmatic fit-for-purpose approach and responsible use of game-changing technology is required to make smaller fields economically viable.
A phased development plan by using early production system may help better manage capital risk of reservoir uncertainty and provide necessary flexibility to capture potential upside benefits.
Exploration and development costs can be reduced by using improved drilling and completion technology, more dry tree production using new hull forms, and conversion or life extension where feasible.
Unless empowered champions use step changes in technology, the high costs of offshore oil and gas exploration and production will continue to be a barrier to future deepwater field development, especially for challenging small fields.