Ice-Like Hydrates Can Spell Trouble for Deepwater Hydrocarbon Flow Lines
By Gregory J. Hatton, Ph.D., and André M. Barajas
Since the mid 1990s, the oil and gas industry has increased offshore exploration and production, particularly in the deep waters of the Gulf of Mexico. In fact, oil production from the Gulf of Mexico is expected to double from that level by the year 2000, with an anticipated yield of two million barrels per day. This increased activity is due largely to technological advances that allow oil and gas production from reservoirs that lie far offshore where water depths are 3,000 feet or greater. 1 As large hydrocarbon reservoirs are discovered in water depths approaching or exceeding one mile, their commercial exploitation requires the technical community to solve new problems associated with the deepwater environment.
Hydrate formation in deepwater flow lines
One problem, or production concern, associated with deepwater fields is hydrate formation in production-stream flow lines. These flow lines carry the raw, produced fluids from the wellhead to a processing facility. If a flow line is operated in the "hydrate region" (i.e., under conditions at which hydrates can form in an oil or gas wellstream), hydrates can deposit on the pipe's inner wall and agglomerate until they completely block the flow line and stop the transport of hydrocarbons to the processing facility.
Hydrates seldom are present in shallow-water flow lines in the Gulf of Mexico because pressures are relatively low and temperatures are relatively high. However, as oil and gas production moves to deeper waters, flowline pressures rise and seawater temperatures fall, and flowline operations move into the hydrate region.
Hydrates are ice-like solids composed of water and a gas, such as methane or carbon dioxide. Hydrates have a density close to that of ice and can look like slushy ice. However, the gas molecules contained in hydrates stabilize the hydrate crystal and allow hydrates -- unlike ice -- to form at temperatures as high as 70 degrees F in hydrocarbon/water systems. While the freezing temperature of water decreases with increasing pressure at pressures below 15,000 psi, hydrates can form at increasingly higher temperatures as the pressure increases. Hydrates melt or decompose when conditions change and the pressure-temperature point moves outside of the hydrate region.
Hydrates form when water molecules arrange in a crystal lattice of cavities with pentagonal and hexagonal surfaces. Each cavity, or "cage," may enclose one methane or other "guest" molecule. The guest molecule enclosed in the water cage of a hydrate allows a crystal to form at temperatures well above the freezing point of water.
At the well, or subsea satellite, the production stream is generally warmer than 100 degrees F, too hot to be in the hydrate region. As the production stream passes through the flow line, however, heat is lost to the surrounding cold seawater. For a high-pressure flow line without insulation, the temperature falls rapidly and fluids soon enter the hydrate region. Many miles later, at the far end of the flow line where production stream pressure is lower and the shallow seawater temperature is higher, the production stream moves out of the hydrate region.
Flowline operational problems due to hydrates are most severe in high-pressure flow lines in cold environments. Around the world, deepwater temperatures are typically between 34 and 40 degrees F. To produce deepwater reservoirs economically, operators are utilizing longer and higher-pressure production-stream flow lines. Some are planned at up to 50 miles long.
A significant number of subsea multiphase flow lines from wellheads in water up to 10,000 feet deep are expected to transport fluids under conditions conducive to hydrate formation. Because of this, and because of limited access to deepwater flow lines, hydrate operational problems are more severe, and harder to remediate, in deep water.
The oil and gas industry has identified flow assurance as a key technology area for the successful development of deepwater reservoirs. Current methods for remediating hydrate blockages in deep water are expensive and risky. Both onshore and offshore, safety is a key issue in hydrate blockage clearing. Once loose, hydrate blockages can become "bullets" moving down a pipeline at high speeds, potentially causing pipeline rupture.
Onshore and, where possible, offshore, a hydrate blockage may be safely cleared by balancing the pressures on both sides of the blockage and then reducing the pressure until the pressure-temperature point is outside the hydrate region. Then, with time, the hydrate blockage melts. Pressure reduction on only one side of a hydrate blockage has led to equipment damage in some remediation operations.
In the cold subsea environment, it may not be possible from the ends of the flow line to reduce the pressure on both sides of a hydrate blockage sufficiently to move outside of the hydrate region. This is due to complications arising from limited access to flow lines and from the liquid inventory and significant elevation changes of subsea flow lines. In cases where the pressure cannot be lowered sufficiently from the ends of the flow line, it may be necessary to create one or more access points near a hydrate blockage in order to balance the pressure. This, of course, is an expensive option.
To address the needs of deepwater oil and gas producers, to better understand how hydrates form in deep water, and to develop safer and more cost-effective remediation methods, SwRI has established a hydrate research program.
The initial focus of this program is on hydrate blockage formation and remediation in long, deepwater flow lines. Typically, a hydrate blockage forms near the deepwater end of the flow line. Consequently, a significant volume of liquid settles in the flow line between the blockage and the platform. Since the blockage may be a mile or more below the platform's elevation, the pressure at the blockage may be much greater than that at the platform (due to the hydrostatic pressure of the liquid and gas inventory in the flow line between the platform and the blockage). Even if the platform pressure were reduced to atmospheric pressure, the pressure-temperature point at the blockage on the platform side still may be in the hydrate region. Furthermore, it may not be possible to reduce the pressure on the wellhead side of the blockage.
When it is not practical to depressurize and move both sides of a hydrate blockage out of the hydrate region, a one-sided depressurization procedure may be effective. However a one-sided depressurization can result in gas flowing through the plug, cooling and extending it, or in the plug breaking loose and flying down the flow line. The industry is striving to understand one-sided depressurization well enough to predict under what conditions this technique is an effective remediation method.
Hydrate field study
To study hydrate remediation using one-sided depressurization without incurring the high cost of venturing into the cold waters of the Gulf of Mexico, SwRI engineers headed to Converse County, Wyoming, to conduct a field study funded by DeepStar2, a consortium of major oil and gas producers that includes Agip, Amoco, Arco, British Gas, BHP, BP, Conoco, Chevron, Exxon, Elf, Kerr-McGee, Mobil, Marathon, Oryx, Oxy, Petrobras, Phillips, Statoil, Shell, Texaco, and Burlington Resources.
The pipeline selected for the field test was a 900-psi, 4-inch, gas-condensate gathering system flow line located in the Powder River Basin and operated by the Devon Energy/Kerr-McGee Corporation. During the winter months, this gas-condensate gathering flow line is pigged and treated with methanol injection to prevent hydrate formation. The line is normally operated at a pressure between 800 and 1,000 psig and is buried approximately five feet under ground.
Prior to the field tests, several tasks were performed to address safety issues and to determine the focus of the field test effort. The motion of a hydrate plug following the freeing of a hydrate blockage was analyzed with engineering calculations and by using OLGA, a transient multiphase-flow computer program. The hydrate plug motion in the pipe was simulated using OLGA, and the expected stresses on the pipe were calculated.
Instrumentation performance requirements and locations along the test line were specified. Five locations along the flow line were selected as electronic data collection stations for the plug formation and dissociation tests. Data collected included pressure, temperature, and differential pressure at an orifice run metering the flowline gas rate. At the fourth data collection station, a dual-station gamma-ray system was installed to monitor the velocity, length, and density of plugs during the clearing of hydrate blockages.
Four hydrate dissociation tests were conducted from January 27 to February 20, 1997. For each test, the normal injection of methanol at the wellhead was stopped, and naturally occurring hydrate blockages were allowed to form in the flow line. Once the hydrate blockages formed, the wellhead pressure rose as the well produced into the blocked flow line, and the wellhead production valves were shut. Hydrate blockage dissociation tests were then conducted, with unbalanced pressures across the blockages.
Reducing the pressure on one side of the plug to below the hydrate decomposition curve resulted in a substantial pressure difference across the plug, as well as partial dissociation of one end of the plug. Pressure difference across a plug was monitored as a function of time while the plug was stationary to determine plug permeability. Pressure difference and plug length were used to determine plug yield strength at breakaway.
During the field tests, a range of hydrate plug types was observed, from short, relatively fast moving plugs that loosely filled the flow line and broke up with time, to longer, slower moving plugs that grew in length and, in some cases, lodged as new blockages.
Some plug speeds recorded by the dual-station gamma-ray system were on the order of 60 feet per second. These velocities were consistent with the simulation predictions performed prior to the field tests.3
The field tests successfully demonstrated that one-sided depressurization can be performed safely and effectively.
SwRI-designed virtual-long multiphase flow loop
Many of the processes associated with the formation of blockages due to hydrates in multiphase flow lines are cumulative and delicate. In particular, both hydrate agglomeration and deposition on the pipe's inner wall are delicate processes that may require a long time to develop. To realistically quantify these processes, it is important to use a facility that simulates field rates and piping geometries and that does not degrade hydrates artificially.
To avoid artificial degradation, the usual proposed solution is a long test loop. The required length of the test loop is a function of the range of conditions and the topics of interest to be studied. Typically, before the study is successfully completed, the required length is not known. Of course, a test loop of very great length (many miles) may be built to reduce the risk of building too short a loop. However, the cost of such a loop would be high.
To circumvent this problem, SwRI engineers have developed a unique, cost-effective, virtual-long loop to simulate the transport of fragile solids in long flow lines without forcing the liquids and solids through a standard liquid pump. While a loop of this type cannot address all of the phenomena of a long flow line, it allows the study of solids transport.
The energy to continuously transport fluids and solids through the "test section" is provided by a gas compressor via a mechanism that, in some ways, is like gas lift. At the end of each pass of the fluids and solids around the loop, most of the gas is separated from the multiphase stream in a minimal size separator. The separated gas is compressed and cooled. The rest of the multiphase stream (solids, liquids, and small amounts of gas) quickly passes through the separator, down a vertical length of pipe (downcomer), and up a riser. In the riser, the compressed gas is commingled with the rest of the multiphase stream. With the commingled gas, the riser stream has a lower average density than the stream in the downcomer. This produces a higher pressure at the top of the riser than at the top of the downcomer, and provides the drive to transport the solids and fluids around the loop.
The loop, rated for 1,440 psig, contains a 50-foot-long, actively chilled, 3-inch pipe test section consisting of a 20-foot segment inclined in the direction of flow at an angle of approximately 5 degrees , a 10-foot horizontal segment, and a 20-foot segment declined in the direction of flow at an angle of approximately 2 degrees , with a 3-inch-diameter optical view port.
In this configuration, the test loop is capable of producing all multiphase flow patterns normally found in oil and gas pipelines. The loop is currently instrumented with pressure and temperature sensors that are connected to a data acquisition system. The loop is also instrumented with a means of detecting the onset of hydrate formation and detecting and measuring hydrate deposition on the test section pipe wall.
In 1997, hydrates in water-natural gas flow streams were studied in the SwRI virtual-long loop. Hydrate formation, agglomeration, deposition, and blockage formation were observed.
For 1998, hydrate studies with oil, water, and natural gas are proposed to address three immediate field operational issues related to the transport of produced fluids through high-pressure, cold subsea flow lines. The goal of these studies is to obtain information to aid in the design and operation of multiphase flow transport lines. Two common and critical subsea-operation situations will be simulated: startup of a flow line and steady-state operation of a flow line with produced fluids from oil wells.
Startup of a subsea flow line is a critical operational issue. At startup, a subsea flow line is in thermal equilibrium with the surrounding seawater, and is at its coldest temperature. Consequently, at startup, the flow line is in one of the conditions most conducive to hydrate formation. Because of this, large dosages of chemicals that inhibit the formation of hydrates are added to the produced-fluids stream during startups. These inhibitors reduce the temperature at which hydrates form, much as anti-freeze reduces the temperature at which water freezes in a car radiator. The most effective inhibitor dosage and the most effective way to mix the inhibitor with the produced fluid is not well understood. These will be studied in the SwRI-designed flow loop in the startup tests in which traditional inhibitors and an oil-water-natural gas mixture will be transported around the loop cooled to seafloor temperatures.
Steady-state operation of a flow line with produced fluids from oil wells is another topic of high interest to oil producers. While hydrate blockages readily form in gas-condensate lines, a number of lines transporting oil-well production streams have been operated in the hydrate region for years without hydrate blockages. Only a few oil-well production stream lines have been blocked while operating. It is believed that hydrates form in oil-well production stream lines, but that the hydrates do not necessarily block the line. The current installation and operating practice for these lines, generally, is the low-risk practice of insulating the line and chemically inhibiting the fluids. However, this practice can cost millions of dollars per flow line.
To understand better the conditions under which hydrate blockages form and insulation and chemical inhibition are required, a number of tests will be conducted in the SwRI loop. The conditions under which hydrates are transported along the flow line without forming a blockage will be differentiated from those conditions under which blockages form. This blockage formation map will be augmented by more detailed information relating to blockage formation, such as deposition characteristics at each test condition.
A third area of high interest related to operation of a flow line in the hydrate region is instrumentation to detect hydrate transport. Regardless of the flow line insulation level and chemical inhibitor system used, a device to monitor the transport of hydrates in a flow line is a useful tool. A Fluenta sand monitor mounted downstream of an elbow has been effective in monitoring the onset and transport of hydrates in the SwRI virtual-long 3-inch flow loop. This monitor is a nonintrusive acoustic device that "listens" for the impact of a solid at the pipe wall. The effectiveness of this monitor in a straight section of pipe will be tested this year. A suitable hydrate monitor would allow operators to optimize inhibitor dosage and to determine when the inhibitor delivery system fails.
As the oil and gas industry drills to, and produces from, reservoirs under greater seawater depths, the flowline environment becomes more conducive to hydrates, and hydrates become a greater operational concern. To reduce the risk and cost of developing deepwater reservoirs, the oil and gas industry is searching for ways to operate flow lines effectively in the hydrate region.
Field tests have demonstrated some ways to deal with hydrate blockages in deepwater flow lines. These hydrate blockages in flow lines can have very high cost consequences. Significant work remains to develop safer and more reliable blockage clearing techniques.
It is expected that a better understanding of hydrate formation, agglomeration, deposition, and blockage formation will lead to new procedures for dealing with hydrates thus resulting in significant cost savings and safer operations. To be more directly applicable, much of the work to increase the understanding of hydrates will be done under field conditions (pressures, temperatures, flow rates, piping geometries, and chemical compositions) and in close collaboration with oil and gas operators.
The authors acknowledge the significant contributions of Steve Zink and Richard Taylor of Devon Energy and of the participants of DeepStar to the successful Wyoming Hydrate Plug Dissociation Field Test Project.
1. Richard Wheatley, "Deepwater, Subsalt Prospects Open New Era for Gulf of Mexico Action," Oil and Gas Journal, Jan. 20, 1997.
2. Gregory J. Hatton, Veet R. Kruka, James A. Guinn, and Gary N. Greig, "Hydrate Plug Dissociation Field Test," OTC 8521, Offshore Technology Conference, Houston, Texas, 1997.
3. "Hydrate Plug Decomposition Test
Program," DeepStar internal report, October 1997.
Published in the Spring 1998 issue of Technology Today®, published by Southwest Research Institute. For more information, contact Joe Fohn.