An investigation team reports that gas hydrates could become a source of natural gas within a few years
According to a 2001 report by the Minerals Management Service as much as 519 trillion cubic feet of natural gas could lie under the permafrost of northern Alaska in the form of gas hydrates. With the prospect of a gas export line from the North Slope, could any of this vast resource be brought to market?
A team from industry, government and university is taking the first steps towards the use of gas hydrates on the North Slope by investigating known deposits of the material in the central North Slope. BP Exploration (Alaska), ASRC Energy Services, Ryder Scott Co., the U.S. Geological Survey, the U.S. Department of Energy, the University of Alaska Fairbanks and the University of Arizona are all collaborating in this project.
The team has completed the first phase of its work, Robert Hunter of ASRC Energy Services and Dr. Timothy Collett of the USGS recently told a joint meeting of the Alaska Geological Society and the Geophysical Society of Alaska. Phase one included reservoir characterization, reservoir engineering, petroleum engineering and reservoir economic modeling.
Collett said that phase one of the investigation also formed part of a USGS North Slope-wide gas hydrate assessment for the Bureau of Land Management — the USGS plans to use seismic techniques to locate gas hydrates in the subsurface.
“We’re developing seismic attributes with which we can go … to look at the more sparsely drilled area of state lands and federal lands across the North Slope of Alaska,” Collett said.
Gas hydrates concentrate huge volumes of methane gas by combining methane with water under certain temperature and pressure conditions.
“Typically we have a methane molecule within a lattice of water and this forms a solid substance within the pores in the subsurface,” Hunter explained. “The gas storage capacity’s tremendous — that’s one thing that makes hydrates very attractive as an unconventional gas resource.”
When gas hydrate crystals break down or disassociate they can yield 164 to 180 times their volume of free gas, Hunter said.
Gas hydrates occur in many places worldwide, in deep-ocean or Arctic conditions where low temperatures and elevated pressures enable their formation. However, the U.S. Department of Energy has taken a particular interest in gas hydrates in the Gulf of Mexico and onshore Alaska, Hunter said. These areas offer economic potential because they’re associated with known petroleum systems and they contain existing oil and gas production infrastructures. Also there are known technologies for extracting gas from hydrates in these areas and established business models for gas production.
Under the North Slope there is an approximately 900 meter thick zone of temperature and pressure within which gas hydrates can exist as stable crystals, Hunter said.
“On the North Slope of Alaska … that pressure/temperature regime in which gas hydrates can exist is anywhere north of the Brooks Range,” Collett said. The gas hydrate stability field extends from inside the permafrost zone to well below the permafrost, he said.
Investigating confirmed accumulations
Although people believe that gas hydrates occur in many locations across the North Slope, the gas hydrate investigation is focusing on the only confirmed accumulations. These accumulations occur in the so-called Tarn and Eileen trends that lie in an area over parts of the Prudhoe Bay, Milne Point and Kuparuk River oil fields — drilling programs associated with these oil fields have found gas hydrates near the surface.
The gas hydrates in these trends have accumulated in shallow reservoirs that form part of the same petroleum system as the oil fields that lie below them — chemical analysis shows that the gas must have leaked up fault zones from the underlying oil fields. For example, it is possible to link the Eileen trend with the Prudhoe Bay field, part of which lies below Eileen.
“When we look at the geochemical evidence from … drilling programs we see about 70 percent — about half the gas — within the Eileen accumulation to be linked directly to leakage from the Prudhoe Bay field,” Collett said.
Gas hydrate accumulations of the Tarn trend occur in the same reservoir rocks as the West Sak and Ugnu heavy oil accumulations. The gas hydrates lie up dip of the heavy oil, where the rock strata approach and enter the base of the permafrost. The gas probably migrated into the reservoir by the same general mechanism as the heavy oil.
“These are basically hydrocarbon gases and oil that have migrated into this shallow section due to the tilting of (the Prudhoe Bay) Sadlerochit reservoir at some 20 to 30 million years ago,” Collett said.
Gas hydrate deposits can best be viewed as shallow gas fields in which pressure and temperature conditions caused the gas to turn into gas hydrate. Free gas often lies trapped directly below the gas hydrates, where the reservoir rocks dip below the base of the gas hydrate stability zone. The gas hydrates probably formed when the North Slope cooled to Arctic temperatures about 1.6 million years ago, Collett said.
Detection from the seismic
With an abundance of well data in the areas of the Eileen and Tarn trends, the investigation team has been able to use actual gas hydrate accumulations to calibrate techniques for identifying and quantifying gas hydrate accumulations from seismic data. By calibrating the seismic data from known accumulations it is then possible to use seismic data from other areas to find and assess accumulations where there is no well data.
The seismic techniques depend on the fact that the velocity of sound in the gas hydrates is exceptionally high, while the velocity of sound in free gas is relatively low. Abrupt changes in sound velocity at the edges of hydrate or gas accumulations result in high-amplitude seismic reflections with recognizable characteristics.
Geophysicists on the team have also found that the extent to which the gas hydrates saturate the reservoir rocks strongly affects the sound velocity within the reservoir. So it is possible to determine the hydrate saturation at each point in a reservoir by measuring the amplitude of the seismic reflections at that point.
“When we look at hydrates that are about 60 percent saturated in a sandstone reservoir, we get significant reflective coefficient characteristics,” Collett said.
However, the technique is not sensitive enough to detect hydrates in reservoirs less than 25 to 30 feet thick or where the hydrate saturation is low.
But, where there is a reasonably thick reservoir containing plenty of gas hydrate the amplitudes of the seismic reflections in a 3-D survey enable the geophysicist to plot maps of hydrate saturation. Maps of this type help people to estimate the volume of gas hydrates in reservoirs.
The fact that the seismic techniques only identify the more substantial gas hydrate deposits may help focus attention on prospects that are large enough to develop. However, the practical viability of extracting gas from the hydrates depends both on the size of a deposit and on the location of a reservoir beneath the permafrost. Extracting gas from hydrates within the permafrost becomes difficult because the disassociation of gas hydrate into methane and water cools the reservoir by absorbing heat — any proximity to the permafrost exacerbates this cooling effect.
“If you’re already in a permafrost section or near a permafrost section, you start freezing the flow water so you have a permeability problem,” Collett said.
The team has completed a detailed evaluation of some prospects in the Milne Point area, to assess the volumes of both gas hydrates and free gas in viable looking accumulations. The team identified 15 prospects below the permafrost in this area, Hunter said. Nine of these prospects contain free gas as well as gas hydrates, he said.
By assessing the gas hydrate volumes in these prospects and then applying some statistical analysis the team has estimated that there could be more than 600 billion cubic feet of gas in gas hydrates above the northern portion of the Milne Point field. In addition there could be 59 billion cubic feet of free gas immediately below the hydrates.
And the area associated with these volumes represents just a small part of the Tarn and Eileen trends — the USGS has estimated that the two trends together contain as much as 100 trillion cubic feet of gas. That compares with total reserves in place of 47 tcf of conventional natural gas on the North Slope, Hunter said.
To assess the economics of developing the gas hydrates it is necessary to look at potential techniques for disassociating the hydrates into gas and water within a reservoir — different techniques incur different costs for development and production.
Reducing the reservoir pressure by extracting free gas adjacent to the hydrates offers the simplest approach. The pressure reduction causes the gas hydrate to start to disassociate. Continued extraction of gas then keeps the reservoir pressure low and causes more and more hydrate to break down.
“The key is finding that free gas association with the hydrate,” Hunter said.
Where there is no free gas, it is necessary to apply heat or chemicals.
For example, raising the reservoir temperature will release gas from the hydrates. So the team has been looking at different techniques for pumping heat down well holes. Intriguingly, there is the possibility of employing the same heating techniques as those already in use for nearby heavy oil production.
“The gas hydrates are in similar geographic locations (to heavy oil) on the North Slope,” Hunter said.
The location of gas hydrate deposits above producing oil fields might also enable hot fluids from the oil fields to be piped through the gas hydrate reservoirs.
Chemical methods of disassociating the hydrates involve pumping materials such as salt or methanol into the reservoirs.
“None of this has been field tested but all hold some promise,” Hunter said.
Modeling of a gas hydrate reservoir requires special techniques because gas production from hydrates involves both gaseous and solid phases — the team elected to use a University of Calgary system that can handle multiple phase fluids.
“We modified this to handle hydrates as a fluid phase within the reservoir,” Hunter said. A University of Alaska Fairbanks team led the petroleum and reservoir engineering research. Scott Wilson of Ryder Scott Co. did the detailed reservoir modeling.
The results proved particularly exciting when simulating the production of gas from a prospect that contained both gas hydrates and free gas.
“The result of the model in this one prospect is that we see a very significant (production) increase, almost two times … that you would achieve from free gas alone,” Hunter said. “The economics are improved dramatically by the addition of that gas hydrate derived free gas.”
The team calculated net present values for the gas production using estimated tax and tariff rates for an assumed gas export pipeline.
“We’re actually seeing results for the free gas plus the gas hydrate component giving us a very reasonable net present value rate of return with a fairly quick payout over two years,” Hunter said.
Gas hydrate deposits not associated with free gas also produced a positive rate of return but required a longer payout period. Researchers in Canada have reached broadly similar conclusions on the economics of gas hydrate production, Hunter said.
“For each well we need fairly water-free production rates greater than 2 to 3 million (cubic feet) a day to achieve a positive net present value and we think we can achieve that based upon the models that we’ve run,” Hunter said.
Local uses for the gas
The potential for the local use of gas presents one factor that may be unique to the North Slope. The gas from gas hydrate consists of methane: production of this gas could reduce the need to consume heavier, more valuable gas from the oil fields.
In fact local use of the gas could prompt the development of gas hydrate production prior to the construction of a North Slope gas export line. For example, it might be possible to incorporate the use of gas hydrates into heavy oil production.
“That may in the near future provide us with the means to produce some local gas and use it for heating within the infrastructure for producing the viscous oil accumulations,” Hunter said.
Other potential uses include electricity generation and gas lift.
In addition, fresh water forms a major byproduct of gas production from gas hydrates. This fresh water production might provide a viable alternative to seawater desalination plants for supplying water for water flood, Hunter said.
Need field testing
Although the economics of the gas hydrates look good Hunter emphasized that many uncertainties remain. It is just not possible to pin down these uncertainties without testing the production of gas in a prototype development. This field testing forms the next phase of the investigation.
“What we’re working on right now is developing plans to go into actual operations on the North Slope,” Hunter said. “If we decide to go forward with these plans it would (involve) designing a drilling program to assess the potential of gas hydrates to produce gas.” However, the results of the phase one investigation already show that gas hydrates hold much promise.
“We think that the future may be sooner than some of us are considering … in parts of the world such as the North Slope with unique motivations hydrates may become a very stable source of natural gas within the next five to 10 years,” Hunter said.