With drilling programs moving further off the continental shelf, the challenge of developing deepwater and ultra-deepwater fields quickly takes center stage. While con ventional methods of moving crude oil and natural gas to shore have adequately served fields in the US Gulf of Mexico and other global areas, new solutions will be needed to economically transport production from remote fields in greater water depths.
In the US Gulf of Mexico, operators have developed a great deal of technology to produce oil from deepwater fields. This technology has been in the form of production concepts such as SPARs (spar-shaped deep-draft vessels), tension leg platforms (TLP), compliant towers, and perhaps floating production, storage, and offloading (FPSO) and floating storage and offloading (FSO) vessels in the near future.
While an array of production options exists, the options for transporting the product to shore for refinement are extremely limited. The only options for a deepwater producer are a pipeline or export by shuttle tanker.
The prevalent driver in determining the deep water development option or set of options is simply cost. As water depths increase, costs rise very quickly, some times in geometric progression.
As more fields are discovered in deepwater and ultra-deepwater, the costs associated with product transportation are very significant. As a result, some concerned operators and contractors are generating studies to analyze cost differentials in the two major transport options.
One study addressing the situation directly is being conducted by Aker Engineering, but reports show that others may be getting underway. Aker Engineering is seeking to identify comparable costs of the different transportation methods. The study is being headed by Preston McNeely, Project Manager for Naval Architecture & Marine Engineering, representing the vessel side, and Sandor Karpathy, Principal Engineer for Subsea & Marine Pipeline Engineering, on the pipeline side.
"We have had several inquiries relating to associated transportation issues and we started researching the subject," the two stated recently. "We are going through this exercise to determine where the economics are. In the analysis, we will be comparing pipeline costs and risks, to shuttle tanker costs and risks."
However, an analysis of the two systems does not lend itself to an easy direct comparison, the two point out. There are a broad number of factors that must be addressed before a base case analysis can be made.
The Gulf of Mexico has the world's most elaborate pipeline infrastructure. It is a testament to the massive success of offshore drilling in this region that this pipeline grid covers virtually all of the Gulf of Mexico continental shelf. However, deepwater is a different story.
Currently, the only solution available for the transport of deepwater production is a very long and very expensive subsea pipeline. These lines must travel over some very difficult terrain and up the slope, as they make their way to the on-shelf infrastructure for tie-in. To handle the volumes needed to justify the expensive deepwater developments, the pipelines will have to be large in diameter. The diameter and wall thickness make the lines difficult to lay in ultra-deepwater, and difficult to insulate against the very cold ultra-deepwater conditions.
As discoveries move deeper, operators are trying to tie-in to the existing pipeline network and expand it beyond the shelf. However, the more the network expands, the costlier it becomes, "There is a strong infrastructure in the Gulf of Mexico; companies keep tying-in new pipelines to the existing infrastructure," Karpathy explained. "The questions are: Where can you go (with the pipeline)? Where is your discovery? Where is the closest tie-in point?"
Still, operators do not have many places to go for pipeline tie-in. For example, the deepest pipeline in the Gulf is the one routed to the Mensa complex in about 5,000 ft water depths. Several industry estimates have placed deepwater pipeline costs in excess of $1 million/mile. This cost is due to a multitude of factors.
First is the seafloor environment. The Gulf of Mexico continental shelf is a fairly benign subsea environment for pipeline installation. The shelf seabed is soft, easy to jet, and relatively flat, with a gradual slope. By contrast, the slope seabed environment is much more challenging.
"If you look at the terrain, it is not as smooth as the shelf surface," Karpathy said. "There is a major challenge in physically placing the line out there. There are obstacles never encountered in the past (on the shelf)." He cited the following as some of the more prominent difficulties:
- Salt structures that cannot be easily avoided
- Ridges that require expensive pipeline spans or alteration of the seabed
- Steep inclines and declines that may cause stability and pipeline anchoring problems.
Added to the terrain problems are the extreme pressures and temperatures inherent in deepwater. The pipe has to be designed with a large enough internal diameter (ID) to move the volumes of crude needed to justify the cost of the development. As the ID increases, the wall thickness (WT) also has to increase to support the pipeline's resistance to outside hydrostatic pressures as well as higher pressures associated with high throughput volumes.
Eventually, the larger ID and required WT challenges the welding technology used to join the pipe sections. The required pipe string becomes very heavy, requiring J-Lay or specialized S-Lay installation vessels. Because the thick-walled pipe is also relatively rigid and installed on a seabed as much as 6,000 ft below the pipelay vessel, it must be suspended in an almost vertical configuration to avoid damaging the pipe and initiating a buckle.
J-lay (a vertical pipelaying configuration, versus conventional S-lay, which is a more horizontal configuration) is a relatively new development for pipelay vessels. Any deepwater installation would require a large installation vessel with a premium day rate. There are other problems in deepwater pipeline transportation:
- Flow assurance: The insulation may help prevent the formation of hydrate crystals or paraffin wax, but flow assurance through chemical means or pigging technology is costly.
- Line servicing: "Typically, pipelines are relatively safe since you don't have to repair one unless something acts on it," Karpathy said. "But when you do have to repair one, major costs are involved. Depending on where the pipeline damage occurs, it is not so easy to isolate the problem. You are basically emptying this big long line because you have valves on the end and you can't shut it off in between."
Commingling crude is another major concern that has not received much attention. This scenario could have a direct impact on the production costs. If an operator ties into a common pipeline and has a higher quality crude oil, once it intermingles with the other crude coming in the line, the value of the initial crude drops. The operator could have asked a premium price for crude, whereas now the quality has dropped along with the price.
Conversely, if an operator has lower quality crude, a tariff is usually assessed for intermingling the low grades with the higher grades. In addition, with each different tie-in to other pipelines, more tariffs can be charged.
McNeely cited one example where crude going from one point to another resulted in two to three separate tariffs. Thus, the operator pays in either situation. However, when using a shuttle tanker, the quality remains consistent and tariffs can be avoided.
Shuttle tanker option
Shuttle tankers, on the other hand, offer producers the ability to produce from deepwater fields at a potentially lower transportation cost. However, several other factors are involved that can impact the usefulness of the pipeline option. The most important factor is the availability of shuttle tankers in the Gulf of Mexico.
According to McNeely, there are two concerns with regard to availability for shuttle tankers for Gulf of Mexico operations as well as other water bodies with similarly regulated environments:
- "Are there any existing shuttle tankers available to transport the oil? So far, all indications are that there are not, because they are going to have to be US Flag Jones Act OPA 90 compliant tankers.
- "There are some US Flag OPA 90 compliant tankers in existence that could be converted to shuttle service, but my understanding is that all existing Jones Act tankers are busy and will probably remain busy for the foreseeable future, and the cost of converting them may be prohibitive."
According to the Jones Act, all vessels operating from US port to US port must be built in the US by a US shipyard, US flagged, and US crewed. In addition, these shuttle tankers will have to meet OPA 90 requirements, which requires a number of safeguards for oil spillage including a double hull.
According to McNeely, most of the lighter ing tankers now operating in the Gulf of Mexico are foreign flagged vessels and do not qualify as Jones Act tankers, and the ones that do, are not available.
Beyond the Jones Act tanker availability difficulty, there is a cost issue involved with meeting US regulations.
- Fabrication costs for US-built vessels are much higher than prices of comparable vessels built in other foreign yards, particularly those in the Asia/Pacific region.
- Operating costs for US-based shuttle tankers will be higher due to the fact that US crew requirements are more expensive than international crews and the US manning requirements call for larger crews.
As a result, alternatives to tankers are being sought. One alternative is the use of an ATB (articulated tug barge) or ITB (integrated tug barge). The ATB or ITB is actually two separate structures - a barge and a tug that can be mechanically connected together - thus acting as one unit. Either unit can act alone as its original designation (barge or tug) and both are classed independently. However, most of these vessels are purpose-built for this articulated or integrated operation.
The advantage that the ATB/ITB offers over a shuttle tanker is cost. The vessels are less expensive and can perform the same function as a ship (tanker), but require a much smaller crew and thereby reduce operating costs. Crewing requirements for vessels are based on gross tonnage. A tug requires 7-8 people (the barge is classed as unmanned), while a conventional tanker requires over 20. In essence, the ATB/ITB can be used to reduce overall operating costs.
The ATB/ITB does have its shortcomings, however. Currently, the maximum storage capacity of an existing vessel of this type is around 300,000 bbl, while conventional crude oil tankers can be easily built to handle the 500,000 bbl maximum capacity limited by Gulf of Mexico refineries. It has been speculated that ATB/ITB's can be designed and built to handle up to 500,000 bbl capacity, although this design is still on the drawing board.
Another shortcoming is speed. The ATB/ ITB is somewhat slower than a shuttle tanker, however in the Gulf of Mexico with voyage distances only being 100 to 300 miles, this may not be an important factor. And in terms of offloading or loading product, the ATB/ITB can be configured to meet the requirements.
Supply and demand
While the ATB/ITB may help alleviate some of the concerns of the shuttle tanker, the problem still lies in supply. Like the crude oil tanker, there are very few ATB/ITBs currently available, and those that are have a maximum 300,000 bbl capacity and none of the existing ATB or ITBs are set up for shuttle service.
One company interested in designing and building the ATB/ITB shuttle tankers for the Gulf is Alabama Shipyard. The company is currently building and marketing smaller ATBs (100,000 - 150,000 bbl capacity) as replacement tonnage for single-hulled oil barges (ATBs, ITBs, or towed barges) one OPA 90 regulations go into effect.
There are currently a large number of these smaller barges that will not meet the OPA 90 requirements and have to be replaced in the near future and could cause a US shipyard capacity problem. Compounded with OPA 90 replacement tonnage, the shuttle tanker issue may present a real crunch for shipyard space as the demand for these shuttle tankers becomes more apparent.
Alabama Shipyard is currently investigating the demand for ATB Shuttle Tankers and is discussing what will be required with many potential players in order to develop a standard design with standard options that will work for the intended service and help reduce the overall costs to everyone involved. The company said it has seen a lot of interest both within the oilfield itself and with current tanker operators looking for new opportunities. However, in order for the shuttle tankers to be ready when they are needed to support deepwater production the design and development needs to start immediately. They added that it is important to remember that when discussing the issue of shuttle tankers for the Gulf of Mexico that this equipment, or any other equipment that could do the job, does not exist. Even if there are existing US Flag Jones Act Tankers that could be used, they would have to undergo extensive conversions in order to be used for shuttle service.
Aker is also examining forecasted demand in their transportation costs study, as well as some key elements associated with FPSOs in the Gulf of Mexico. "What we're evaluating is a straight SPAR without storage, for example, which would feature direct offloading to a shuttle tanker. We are comparing this production option to an FPSO or FSO, with storage and offloading periodically to a shuttle tanker.
"Another possible combination under evaluation is producing directly to a tanker, versus producing with storage, to determine if the number of shuttle tankers can be reduced, and secondarily, establishing the optimum operating cost for each option.
"We are assuming there is a problem (with pipelines), and I think there is. The demand for shuttle tankers is going to be there as soon as they are out there producing beyond the reach of the pipelines," McNeely said.
Dealing with the gas
While either option can be used to deliver the oil to shore, gas is a different story. Other than in a test situation or an emergency, it is illegal to flare produced gas in the Gulf of Mexico and other water bodies. That leaves only two options for operators to deal with the gas.
If there is very limited gas content in the production, it can be re-injected into the formation as a means of disposal. In addition, smaller volumes can be stripped off and used for power generation in the field. But, if there are sizeable amounts of gas, which is a common occurrence in the Gulf of Mexico, then operators have little choice but to pipe the gas to shore.
Regardless of the transportation solution chosen, there could be a pipeline on virtually all ultra-deepwater fields if the gas volumes are significant. This presumes that a low-cost (economical) method of liquefying produced gas has not emerged before many deepwater production decisions have to be made.
McNeely summed up the dilemma: "You have the shuttle tanker, but you still need a pipeline for the gas sales. The only thing you can do with the gas (at the present) is re-inject it or send it to shore."
Does the need for one pipeline to shore or shallow water change the economics for the project with regard to shuttle tankers, possibly making the laying of a second crude line more economic? This is another question that will have to be answered in the selection of field development and transport systems.
There are strong arguments for both product transport solutions, and the decision needs to be made on a case-by-case basis, according to McNeely and Karpathy. "The main reason for a shuttle tanker is that you cannot get a pipeline to the well site economically. We are moving to a part of the Gulf of Mexico where putting in a pipeline to service those areas is very prohibitive," Karpathy said. "So, a shuttle tanker may be cheaper.
"Pipelines, particularly those in deepwater, rarely have something acting on them and are considered relatively safe. But with a shuttle tanker, there is product handling, which could result in an accident," he pointed out.
"The pipeline is more expensive when you get into deep water and we don't have enough shuttle tankers to handle the transportation of the crude - although we do not know what the demand is going to be at this point. Today, there are none available for shuttle duty in deep water."
Therefore, no matter what development option, whether it be TLP, SPAR, FSO, or FPSO, the product must get to shore. While pipeline costs may be getting exhorbitantly higher as water depths increase, it may be the only option if shuttle tanker costs and availability is as bleak as it appears to be. The industry will find a way to get the oil to market - it's just a matter of getting an accurate view of the costs of each transport option and the production option it will be matched with.