With US natural gas prices pushing $4/Mcf, and shortages predicted for this winter, many companies are scrambling to find an economic means of exploiting stranded gas in remote shallow and deepwater fields. As the option to flare gas produced along with crude oil (associated gas) becomes less attractive and restrictions on injecting gas increase, operators are looking for ways to turn the liability of stranded gas into a profitable venture.
The dynamics of stranded gas are simple. As with any energy source, to make money on a gas well, there must be a way to get the product to market economically. To accomplish this, exotic solutions exist, including LNG and CNG, but these require a large product stream, some very expensive equipment, and steady, long-term contracts. Long-term contracts are more difficult to negotiate now because of the diversity of supply sources and developing paper markets.
The most popular way to move gas to consumer distribution networks has been via pipeline. In the Gulf of Mexico, for example, where an extensive on-shelf pipeline grid is already in place, piping gas to shore from deepwater fields has become a secondary business for the majors. Companies such as Shell already have substantial field and pipeline networks in place along the edge of the continental shelf and on the deepwater slope.
Production from new deepwater gas fields coming onstream can be tied back to these platforms for introduction into the pipeline grid. Fields large enough to justify the cost get their own surface facilities, which in turn can offer tieback opportunities to smaller fields further off the shelf. In this manner, the production infrastructure is working its way into ultra-deepwater following new developments.
FPSOs and gas
Although designed for oil recovery, a new production system for deepwater in the Gulf of Mexico could alter the economics of stranded gas. In a matter of months, the floating production, storage, and offloading (FPSO) vessel could be introduced as an alternative floating production solution. Already the system of choice for oil and gas theaters from Brazil to West Africa, the FPSO is portable and efficient for the processing of fluids for either early production, production testing, or full production from remote and deepwater fields.
Expensive to build, FPSOs can be used on several fields during their life span, helping to recover construction costs. If a field plays out sooner than expected, the operator is not liable for the full cost of the production facilities. The FPSO can simply move on to another project.
While it is a viable solution for fluid processing and storage, the FPSO falls short on the question of stranded gas. Some areas of the world would not consider this a drawback, but the Gulf of Mexico is known for natural gas and has a ready market onshore.
Many of the ultra-deepwater exploration plays, while considered primarily oil nevertheless have a large associated gas component that must be developed in one way or another. In areas of the world where FPSOs now are in operation, the associated gas component is used to power generators, flared, or re-injected into the formation. These solutions do not answer all the questions of the Gulf of Mexico. There, flaring is allowed only during well testing and cannot be considered a long-term option.
Flaring is diminishing for many reasons in other areas of the world as well, and there are serious concerns that flaring will be curtailed completely in coming years. That leaves power generation and re-injection. Power generation can only burn a finite amount of gas, and even large generation capacity cannot consume much of the gas from larger fields.
The re-injection op-tion appears attractive, offering the added advantage of maintaining reservoir pressure, but the costs also are high. In the Gulf of Mexico, there are regulatory restrictions on when produced gas can be re-injected, and the understanding is that this gas will eventually have to be produced. Added to this obligation are the drilling and completion of the injection wells, the subsurface equipment, and the topsides equipment required to clean, pressurize, and inject the gas. All of this is sunk cost, since no value is gained from the gas. It is basically making a very expensive round trip from the production well to the topsides and back down the injection well.
If the gas market continues to climb, and several analysts believe this will be the case, the incentive to find a profitable alternative for these gas fields will increase. If flaring is eliminated as an option worldwide, then it will become necessary to find an alternative means of dealing with it.
Active options
Dante Caravaggio, Manager of Upstream Business Development for Jacobs Engineering, said there are a variety of options for monetizing gas from remote deepwater locations without building a pipeline. None of these currently is economic, but each is being investigated concurrently. Basically, "economic" for such new applications would mean less expensive than a pipeline, while maintaining an acceptable rate of return.
If there is enough natural gas present to feed a new pipeline and the market justifies the cost, then that would be the solution. Along the same lines, if the gas volume is small enough that it can be consumed for power generation on the rig, then that would be the way to go. When gas volumes are greater than the consumption volume for topsides, or less than that necessary to make a pipeline transport feasible, "stranded" gas results, and a producer must decide which option best meets both the environmental needs of the area and business needs of the producer.
The following solutions are options for taking the gas and compressing it, chilling it, or otherwise converting it so that transportation to market is economic.
- LNG: Of these technologies, liquefied natural gas (LNG) is the best known. This technology chills gas to a liquid state. The gas is then transported on board refrigerated tankers to market. The up-front costs of LNG are extremely high. To justify it requires a reliable feedstock, a long-term market, and a dependable transportation system.
If volumes and gas reserves are inadequate to support the huge LNG investment, then less costly, but more risky options exist. There is work underway to develop a mini-LNG system, which would have lower up-front costs, and requiring a smaller volume of gas production for feedstock. However, transportation requires a tanker that can keep the gas below -150° C. Such tankers are very expensive, making the transportation costs of this technology very high.
- CNG: Compressed natural gas accomplishes basically the same objective, shifting the gas into a liquid state for transportation, using pressure rather than temperature. This means specialized, heavy, compression equipment and tankers with a wall thickness great enough to hold the gas at 15,000 psi.
- Methanol: Methanol is a gas-to-liquids option that has been around since World War II. While it can turn gas into a liquid fuel, it is an inefficient conversion process that uses a lot of gas to produce a small amount of methanol. In addition, the market for methanol is small. There are other Fischer Tropsch methods of liquefying gas, but they all fall into the same category of converting the gas into a liquid that can later be converted back and sold. The liquid is shipped to shore on a shuttle tanker.
- Power plant: Another option is using the gas to fuel an offshore power plant, which would generate electricity for sale onshore or to other offshore customers. Many feel this defeats the purpose of an alternative solution, since installing high-power lines to reach the shoreline is almost as expensive as pipelines.
Depending on the volume, rate, and pressure of the gas, the liquids content of the gas, the available markets and the available capital for investment, Caravaggio said the options are as simple as combining the gas and oil in one pipeline, to as complex as Thermal Acoustic Refrigeration. The utility consumption for many of these processes is very high, but the reward to producers of realizing $33/bbl oil and $4.25/Mcf gas make this a huge new frontier that greatly improves both the environment and bottom line profitability - at the same time.
Associated gas
There are two major issues to consider when trying to process associated gas offshore, according to Ken Arnold, President of Paragon Engineering Services. These are safety and complexity. Generally, the simpler the system, the safer it is, Arnold said. For gas processing, there are several criteria unique to an offshore application. Though the goals may be similar, the approach is fundamentally different than an onshore plant.
An offshore facility has to be tolerant of abrupt changes to the inlet flow rate. While processing is underway, the gas production level from one field may drop rapidly, cutting the flow rate to the processing equipment, while another field may just be coming on line, increasing the flow rate.
In addition to varying flow rates, there may be a difference in the composition of gas from the different fields feeding the plant. This composition may fluctuate for each feed stream as well. For a typical offshore design, the process plant is sitting on top of the storage facility, which could be an FPSO.
If there is a potential problem, the plant must be able to shut down quickly to keep a small incident from escalating. The shutdown system itself must be safe. On most platforms the plant can shut down and the trapped energy released to the flare. Any complicated process that requires a purge cycle or a cool-down cycle before it can shut down, violates these criteria.
Aside from shutting down easily, the process has to be able to start up quickly, otherwise operators will be too hesitant to ever shut down the process. A system needs to be able to shut down in around 60 seconds then start up again in about an hour to ensure a shutdown is considered a realistic option by operators. "Otherwise, by the time a decision is made to shut the system down, it will be too late," Arnold said.
Moving processes offshore
The industry typically does not have chemical plants offshore, Arnold said. Typically, gas processing on platforms and rigs is limited to gravity separation systems. To make the jump to full processing simplicity must be the watchword. This means such plants may lose some efficiencies of conversion and include fewer redundancies than the industry is used to. All this is an effort to keep the process simple, and therefore safe. This is critical to any offshore gas-to-liquids plant, Arnold said.
When dealing with associated gas, the assumption is that this gas will not be a profit center; it is a waste product of oil production. In the case of US operations, the Minerals Management Service (MMS) will not allow the operator to flare the gas or re-inject it, so what is the least costly way to get rid of this associated gas. "It is either going to cost nothing or be expensive," he said.
Rather than starting from scratch, Arnold said there is another way to look at the associated gas question. Instead of dealing with the gas itself, why not assume it will be converted to methanol. "How do we make simple methanol processes work?" he said, "and how do we find a market for the methanol?"
There are a number of potential processes, not fully studied, that could convert the gas to methanol. But, assuming the process could be developed, without a market none of these solutions will be viable. So then the question becomes: How do I make a market for methanol?
Methanol could be marketed as a feedstock for a chemical plant to produce other hydrocarbons or to drive electric turbines. This, according to Arnold, is the simplest solution. The goal of making a high-priced product of gas offshore is not going to work for these small gas reserves. Such solutions require equipment that is too expensive and complex to be economical.
On the other hand, stranded gas, with much greater volumes, might make the economics work for a complex gas-to-liquids or LNG plant offshore. To be a viable solution, this process would have to be less expensive than the typical $1.5 million/mile deepwater pipeline it is replacing. Arnold said if an operator has a small gas field about 100 miles from the gas infrastructure, the operator is looking at $150 million to pipe it into the grid. Once the gas reserves are exhausted, the salvage value of that pipeline goes to zero. With a floating system, once the reserves play out the plant can be moved to another field elsewhere. In this way, the upfront costs could be spread over several projects.
In the Gulf of Mexico, there are a number of hurdles that must be cleared before such a solution can even be considered. First of all is the question of FPSOs. The MMS must allow FPSOs in the Gulf before novel solutions for associated and stranded gas issues can be considered. If an FPSO is brought in, Arnold said the operator will have to do something with the gas. If a gas pipeline must be laid, then the operator might just as well install an oil line, eliminating the advantage of the FPSO. While this is not always the case, an alternative gas solution will be required since injection and flaring are not allowed.
To properly address the two scenarios of stranded and associated gas, Arnold said two gas strategies would be needed. At this time, the most likely solution, in his opinion, will be gas-to-liquids, accompanied by a market strategy for the product. To solve such a broad problem will require what Arnold calls a total energy company, meaning one that looks at gas, electricity, and other power sources equally.
