Simultaneous approach can minimize field development time
Genesis Engineering Consultants
The biggest benefit in this approach is clearly the significant reduction that can be achieved in development time. However, the important question to answer is: what are the facets of parallel engineering that allow this to happen?
A significant upside is the early recognition of what is important to the field development. Identifying what is really hurting, in terms of sub-surface and surface uncertainties, and main cost contributors. This allows scarce time to be spent where it matters most.
Even prior to specific field/prospect development work, bringing the surface and sub-surface together allows a better match of any planned exploration or appraisal targets with what is available for a possible full field development - in terms of existing infrastructure and potential ullage.
In addition, early thoughts on how a prospect could be best developed can influence positioning of planned exploration/appraisal wells. This may mean a more deviated or complex well, but this has to be offset against future cost savings/benefits from having an optimally grouped subsea layout.
Fortunately, the quality of well appraisal has improved immensely from the 1970s and early '80s. Then it is fair to say that the focus of appraisal was more on proving up presence and size. Sound PVT information, fluid properties and the presence of nasties such as H2S and asphaltenes took a back seat, with the result that the appraisal data tended to be not very conclusive.
With parallel engineering, the peculiarities associated with surface processing (off and onshore) of the well fluids can be fed into the appraisal campaign early on, and hard facts generated. A classic example is the firming up of the dewatering capability/characteristics of the wellstream.
Getting an earlier picture of more credible full field development scenarios can also assist in making headway in farm-in discussions, more straightforward partner approvals, and earlier discussions with third parties over using their infrastructure or bringing in their prospects.
But there are also downsides to parallel engineering. By reducing the time to first oil from over, say, eight years to less than three, something has to give - doesn't it? A knock-on effect of such haste is that the team can become blinkered.
Pressures on getting to first oil can lead to opportunities for integration with other prospects in the vicinity being missed or even dropped because "they don't fit with the schedule or because their subsurface work is still maturing." Currently, use of early production systems and FPSOs are in vogue as a result arguably of the market rates, and this can also lead to thoughts of going it alone. Surely there is scope for more clustered field developments?
Contracts to produce are also in vogue. During the pre-projects phase, such contracts are drawn up by the oil company and a whole range of competitive tendering methods are used to select the field operator. There is a potential danger here that by squeezing the front-end too far, too much is being asked of the consortia in terms of handling risk and uncertainty.
Running sub-surface and surface engineering in parallel is all about getting a handle on the uncertainty associated with both. Traditionally at full project sanction, the uncertainty associated with the project would have been worked to a position where the reserves and production were known to within 20%, capex to within 10% and well numbers and cost also to within 10%. Fine, but this took time and money to assess and perhaps instilled a degree of confidence that was simply not justified.
Successful parallel engineering is concerned with putting in sufficient effort to ensure that there is confidence in achieving a successful outcome (in terms of all the relevant economic indicators) by understanding more fully the nature and effects of the uncertainty.
If looking at the equation for ultimate recovery, it is easy to see how such large error bands can be accumulated:
Clearly there is much uncertainty associated with the geological and petrophysical aspects of the sub-surface, but at the interface with the surface engineering, it is the uncertainties in reservoir engineering and production technology that have the greatest significance. For example:
- Drive mechanism (solution gas, water drive, gravity drainage)
- Water coning/gas cusping/timing of water and/or gas breakthrough
- Well inflow performance, well numbers, completion type
- Flowing wellhead pressure and temperature
- Fluid composition, viscosity, wax, asphaltenes, scaling
- Sand production/exclusion
- Artificial lift (when, where?)
Surface uncertainty (& constraints)The main sources of surface uncertainty can often manifest themselves as being more like constraints to the field development. Notwithstanding the biggest uncertainty, the oil price, this list includes:
- Gas disposal (re-inject:? market?)
- Potential hosts (spare ullage? tariff structure? specifications?)
- Potential for third party development
- Government, partner and internal approvals
- Availability and costs of rigs, EWT spreads
- Construction market (fabrication capacity, tanker and FPSO availability).
It is something of a truism to say that petroleum engineers want total and permanent flexibility, while the process engineer wants everything frozen. Given this backdrop, it is crucial that they reach a common understanding of each other's expertise. The petroleum engineer needs to know the surface impact of his requirements for flexibility, while the process engineer needs to know the basis and scope of the sub-surface uncertainty.
Nothing should be taken for granted. There is a need to continually challenge each other's assumptions within the parallel engineering team and to update assumptions and thinking as new information becomes available. This is not just restricted to field-specific technical information, but should include data such as third party changes, unexpected rig or FPSO availability, technology breakthroughs. The team must remain flexible to change and should be positioned to take advantage of opportunities as they arise.
Computing capabilityProcessing power and data handling has inspired major advances in parallel engineering. The possibility to genuinely integrate geological, reservoir and process models is starting to happen. However, iteration within the team must be made as slick as possible.
Cumbersome cost-estimating and economic models will not do. Effects of changes must be evaluated rapidly in order to maintain momentum and aid decision making. Graphs should be generated where possible showing clearly the levels of uncertainty and where break points or step changes occur.
Reservoirs have an irritating habit of turning out much more than just the oil and gas you were expecting: often the wellstream fluid behaves quite differently to what you expected when mixed with some of your third party wellstream. The peculiarites of the reservoir fluid and the effects of commingling with other reservoirs needs to be well defined before proceeding with any full field development.
To this end, all exploration and appraisal should be focused to gain conclusive information. Nor should price impact of peculiarities be overlooked: for this reason, it is advisable that downstream specialists should get involved at an early stage so that the entire product chain can be analyzed.
Early production systems are now used widely to aid proving up of a reservoir and at the same time get in some welcome revenue. Mostly, this involves pre-drilling of one or two wells and production via a converted semisub or FPSO. If converted drill rigs are used for this purpose, then appraisal drilling (perhaps through coiled tubing) may be possible simultaneous with production. This is particularly appealing in areas of highly clustered reservoirs and/or heavy faulting.
To conclude, here are some suggestions based on the author's personal experience:
- Choose your gas options early and with vigor - this is the biggest single reason for project sanction delay.
- Keep up to date models and data on third party infrastructure and throughput.
- If running a prospect with several partners, get some partner people onto the team: it's amazing what this can do to speed up approvals.
- Drilling costs have a habit of dominating the development cost picture - so address the subject early.
- Run with a processing configuration which meets most stringent gas and oil export specs.
- The importance of flowing wellhead pressure prediction over field life cannot be overstated.
- Accurate characterization of reservoir fluids is crucial, takes time and needs an experienced practitioner.
- Minimize technical reviews by functional heads - use joint and peer group reviews.
Capitalizing on Low Cost Fast Track Field Development, Conference, London, September 1996.
Copyright 1997 Offshore. All Rights Reserved.