Hub development option helps lower deepwater costs

Impact of hub approach on the economic life of a facility. [19,567 bytes]

Adding capacity to existing infrastructure

Marshall DeLuca
Business Editor

Leonard Le Blanc
Editor-in-Chief

The use of an established or planned central production facility to support and receive production from outlying facilities was developed some years ago in the North Sea as a way to skirt high development costs. The concept, referred to as "hubbing" or "hub development," is beginning to gain much wider attention from deepwater producers in the Gulf of Mexico, West Africa, and elsewhere as a way to keep ahead of the cost curve. Producers in intermediate depths are attracted to the option as a way to jointly continue field development during low oil price conditions.

The North Sea and Gulf of Mexico have several fixed structure hub developments. The most notable one in the North Sea is Statoil's Statfjord complex in the Norwegian North Sea. Statfjord has been developed with three separate concrete platforms A, B, and C, and two satellites Statfjord North and Statfjord East.

The two satellites are tied back to the C platform, and Saga's Snorre field is tied into the A platform for final processing. The development had a peak average daily production from all three platforms of 819,091 b/d of oil in 1995.

Hub function

An offshore hub is any floating facility (semi-permanent floating production, storage, and offloading vessel, tension-leg platform, or deep-draft unit) or fixed structure (conventional platform, tower) in shallow or deep water that handles production from two or more outlying producing zones. In other words, a facility with two or more subsea tiebacks from separate fields.

The qualifier "two or more" differentiates it from single subsea tiebacks. Multiple tiebacks necessitate larger and more sophis ticated facilities.

Regulators in the US Gulf of Mexico, specifically the Minerals Management Service, accommodate hubbing and commingling of production by measuring gas or oil volumes or flows with facilities measurement point (FMP) designators. Each tieback to that structure is also given the same FMP number. A hub in the Gulf of Mexico could be further defined as a structure that serves as the measuring point for liquids and is the FMP number source of two or more tie-ins.

Hub benefits

The hub development option potentially offers a number of benefits to existing and planned facility owner-producers: (1) Allows for economic development of fields deemed marginal at current oil prices. (2) Allows for a new revenue stream, which can add economic life to production facilities. (3) Shared throughput costs on a production facility allow the owner-producer more options (enhanced recovery, etc.) to continue producing the primary field.

Generally, the following is true of most moderately mature or mature producing areas around the globe:

  • Companies, for the most part, design production facilities exclusively for development of their own fields.
  • The structures under design are built with more capacity than necessary for that particular development.
  • The producer has fully financed engineering, fabrication, installation, and operation of the facility with expected production flows from the primary field.
  • Hubbing is not a common practice in the region and companies are not designing facilities specifically to act as a hub, therefore there is not the existence of a competitive hubbing business.
If these assumptions are mostly true, then owner-producers have a number of opportunities not recognized previously. The main benefit is that hubbing-in a competitor's field allows for an additional source of revenue, and the owner-producer would be given almost full reign on setting the price for the service.

If the facility is fully financed and installed and has the capacity for extra production, the addition of a competitor's tie-in (assuming it did not require the addition of increased production capacities), would be very profitable to the owner-producer as long as the user price covered the operational expenses of the facility.

If additional capacity is required, the cost of the addition would be absorbed in the price for use of the hub. As each additional tie-in is added, the original operating cost drops further for each participant, depending upon whether the facility owner-producer chooses to pass the full savings along.

With a lack of competition in the area (based on the earlier assumption), if a producer-owner inflated the price of hubbing, it would not hurt the profit margins of the competitor, who is acquiring the capacity at little extra cost.

Because the facility's presence was based on an internal-use, fully financed, pre-existing design, a rejection of an offer for use of the facility as a hub would not impact the original project revenues and costs. Because it would be a new source of revenue and the company has not invested more capital into the facility, the only loss caused by over-inflating prices would be an opportunity cost equal to the price offered to the customer.

An owner can also set prices based on the customer's prospective costs. Pricing could be set just below the cost a potential hub customer would incur to design, build, and install its own facility. This would keep the economics within the range of the customer, and more than likely cover all costs to the owner with significant profit.

However, one major factor could impede inflationary pricing and keep costs within a reasonable range. The reliance of owner-producers on their competitors in the industry is paramount. Setting prices at exorbitant ranges could hinder future exchanges or quid pro quo between companies in the future. As a result, short run profits may hurt overall profits in the long run.

Adding facility life

Hubbing also benefits an owner-producer by extending the economic life of the production facility. Graph 1 is an example of the effect of adding an additional tie-in to a facility based on a typical production decline curve of a well.

The first curve shows the normal decline curve of actual and planned production of an offshore production facility. Production scales up as wells are brought onstream to a maximum point, then declines as individual well flows dwindle. Barring enhanced recovery applied to the field, which would push the curve to the 10% maximum point, production will decline until it reaches "economic life limit" line (see Graph 1).

At the "economic life limit," the revenue from production flows cannot surpass operating costs for the owner-producer, which may or may not be increasing toward the end of the life of the field.

With the addition of a tie-in to the facility, a second decline curve is added to the original. The added throughput extends the economic life of the facility (and field).

This addition of throughput helps to spread the costs charged to operation, or cost of recovering each bbl (lifting cost). A second accompanying graph examines the lifting costs of operation. The graph compares the lift costs of the original well with the addition of a tie-in.

The tie-in allows the lifting costs to remain lower for an overall longer time frame than can be achieved with the initial production flows. In addition to the increased income, this cost spread further extends the life of the facility far past what was expected originally.

Other implications

The initiation of hubbing, especially in the planning stages, can lead to other changes in a region. If hubbing does become an accepted form of development, a new competitive niche may evolve. Companies may begin competitively designing structures specifically for hub developments. This could lead to the re-emergence of the production contractor, which would conduct business in the same way as a drilling contractor.

Production facilities would be built on contract or speculation with capacity sold or leased to an operator. The cost of building these facilities would be tied to a day rate or throughput rate for use of the facilities (hubbing charge).

This hub leasing rate or day rate, similar to the day rate of a drilling rig, would be based on similar market conditions to that of the drilling day rate, although the lack of transportability of the service or the lack of competitive structures nearby could keep competition low.

If other low-cost development schemes become available in the area, the concept may not take as strong a hold. For example, the most likely alternative to the hub approach would be the development of a fleet of highly mobile floating production, storage, and offloading (FPSO) vessels that produce fields sequentially.

An FPSO or other similar mobile floater possibly could offer better economics for field development with deepwater subsea tiebacks, certainly if the outlying field tiebacks to reach a hub are too long and support costs for injection, pigging, and other flow intervention are not predictable.

The success of hubbing will depend on technical advancements underway in support of development in deepwater, for example:

  • The feasibility and cost of the longer-range tiebacks being investigated now
  • The protection of oil and gas production flows from wax, asphaltene, and hydrate formation as they traverse low temperature seawater conditions
  • The need for injection or well intervention.
Besides technical issues, some of which are site specific, there are a number of business issues to be considered in hubbing:

  • Who will operate the facility, handle maintenance, and monitor the flows. Will the facility be staffed with strictly owner-producer employees, or will there be a company man (tie-in producer) on the facility similar to the situation on a drilling unit?
  • How would the commingling of production flows from the separate tie-backs be handled. Most facilities use one common carrier such as a pipeline. With differences in grades of crudes, difficulty may exist when commingling the flows for pipeline throughput and some ways of compensating for the differences would have to be developed.

Case study

Shell Midstream Enterprises (SME) is an example of an organized effort to expand the concept of hub development and multi-producer tie-in. The firm has opened up access to Shell's existing production and pipeline infrastructure in the Gulf of Mexico to all other producers. Interestingly, excess capacity for outlying production is being planned for present and future Shell facilities.

In 1996, SME expanded production capacity on Shell's Bullwinkle platform from 44,000 b/d production capacity to 200,000 b/d. An agreement to tie in the nearby Troika and Angus fields enabled SME to expand the facility. Shell also plans to tie in its Europa prospect to the Mars platform with four subsea wells, and tie in the Macaroni prospect to the Auger TLP via three subsea wells.

British Borneo's Morpeth TLP is also being destined as a hub processing facility. Morpeth will handle production from nearby satellite fields such as Black Widow. The oil and gas from the fields will be exported from the TLP via the Amberjack and Discovery pipeline systems.

Several other companies have shown interest in the hub concept in the Gulf of Mexico. Hubbing could allow other operators without significant production to establish position in the US Gulf of Mexico. For example, Statoil, with previous experience in the North Sea, has expressed interest in Gulf of Mexico hub development. The operator is participating in the development of the Fuji prospect. Statoil feels that hubbing may offer an opportunity to expand international interests.

Too competitive?

Even if the technical and business challenges can be worked out, a representative from US government regulator, MMS, believes the concept will not work on a large scale in the Gulf of Mexico. The spokesperson pointed out that owner-producers of prospective hub facilities will never make it economic enough for competitors to use their production facilities. "They would rather the field not be developed than let their competitors use their facilities at a profit to them."

Indications from many operators are that such interests, however strong, might be over-ruled by economic necessity, especially in a low oil price environment. Also, there would be a greater chance for cooperation among prospective partners that might be in a position to trade positions elsewhere.

Copyright 1998 Oil & Gas Journal. All Rights Reserved.

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