Looking forward, many of the world’s oil producers will have to think more carefully about heavy crudes and the challenges they pose for processing, storage, and transportation. To date, most of the world’s ongoing demand for crude has focused on lighter grades, which until relatively recently have been the primary, commercially available resource. However, those lighter, premium resources are in decline, leaving a growing percentage of the world’s oil supply to increasingly heavier grades. And supplies of the heavier grades remain plentiful. Current production accounts for less than 3% of the discovered heavy oil originally in place.
Most heavy oil is found at the margins of geologic basins and is believed to be the residue of what was once light oil that became dense through degradation by bacteria, water washing, and evaporation. The world’s supply of recoverable oil is about 434 billion bbl, about 69% of which is in the Western Hemisphere, according to estimates from the United States Geological Survey (USGS).
Compared with light oil, heavy oil is more costly to produce, process, and transport. In many cases, extra heavy oil must be chemically upgraded to lower density. In the Venezuelan Orinoco heavy oil belt, for example, about 1 bbl of diluent is required for every 3 or 4 bbl of extra-heavy oil.
There is no universally accepted definition of what constitutes heavy oil; however, it generally has a high density, with an API of between 10°API and 22°API and a viscosity above 100 cp. Almost all heavy oil is an alteration of products of conventional oil. Worldwide, the total known accumulations of heavy oil are around 3.4 trillion bbl of oil in place, of which about 30 billion bbl are considered prospective as additional oil, according to data from the USGS.
Heavy oil also has a high proportion of asphaltic molecules, including resins and asphaltenes. Asphaltenes are those in the crude fraction that precipitate upon the addition of an alkane, usually pentane or heptane, but remain soluble in toluene or benzene. A sample of heavy crudes showed that asphaltenes account for 12.7% of heavy crudes by weight, based on USGS data. Metals, including aluminum, iron, nickel, vanadium, and their residues, were high by comparison to conventional and medium-grade oil (Table 1). Each of these elements presents challenges to processing. Further, viscosity for heavy oils is generally higher at any given temperature than conventional and medium-grade oil.
Wally Georgie, principal consultant of processing and flow assurance at Maxoil Solutions, said engineers need to consider the unique characteristics of the fluids when designing treating facilities for them. The production of heavy oil poses numerous processing challenges, which need to be considered when deciding factors such as the size of separators, the internal design of the vessels, vessel configuration, and the optimum means of handling solids and water. Fluids from a given reservoir are generally tested so that engineers have an idea of the effects of solids production, asphaltenes, paraffin, naphthenates, inorganic scale, and emulsion stability before they design the vessels that will treat them. An improper design can lead to higher than expected operating expenses once production begins.
It is common for many heavy crudes to show similar characteristics, including high total acid number, low hydrogen/carbon ratios, high viscosity, high carbon residues, and a generally high level of asphaltenes, sulfur, heavy metals, and nitrogen. Because there is no universally accepted definition of what constitutes heavy crude, the term is relative in different regions. In the North Sea, for example, heavy crude is typically between 15°API and 20°API. In Canada, heavy crudes are as low as 8°API. In Alaska’s North Slope, many current production crudes fall between 18°API and 21°API, and are known as “high-viscosity crudes.” However, potentially there is more lower-API, heavier crude with lower fluid temperature that can be extracted with the correct technology and design.
In general, the best separation is enabled by gravity, which takes time and heat. “The reality is that if we start from scratch and we know we have heavy crude, the best thing to do is to provide enough time for separation,” Georgie said. The vessel needs to be large enough to allow for separation. It is a common practice to heat heavy oils to reduce viscosity, so most heavy crudes go through a heat exchanger before they enter the separator at one stage of the process.
Fig. 1 shows the decreases in viscosities associated with heating for some Alberta, Canada, oil samples.
For greenfield developments, engineers design the facilities to the correct size and configuration for the crude emerging from the field based on field tests done before production. Brownfield developments are more complex. There are cases in which a given facility can be upgraded to take on heavier crude. “Sometimes that is not feasible … sometimes you have to remove and replace,” he said.
Although vessels that process heavy crude are larger and therefore require more material, they do not necessarily cost more to make than those for lighter crudes. Lighter crudes generally come from higher pressure reservoirs, which require vessels built to withstand those pressures. Emulsions are part of the separation. Heavier crudes have more stable and complex emulsions that are difficult to separate. Lighter crudes generally have less stable emulsions that are easier to separate.
Facilities design is essential, particularly when working with fields that produce from multiple reservoirs. Defining the nature of the crude is crucial as part of an optimum new design. In many cases, one field may draw crude from two or three reservoirs, each with different characteristics. The equipment must first be optimized before the treatment of the crude can begin. There are different oils produced from different reservoirs and sometimes they must be processed through the same facilities. And they have different characteristics. Sometimes the crude oils are compatible and sometimes they are not. The design of treating facilities must take into consideration the characteristics of the crude that passes through them. Occasionally, crudes cannot be commingled without damaging the overall value of the mix. In those cases, they are usually kept separate. “Sometimes you can commingle, but you can lose a premium price if you do,” Georgie said.
The higher viscosities found in heavy crudes make flow assurance a challenge to operators. Phaneendra Kondapi, an engineering manager of flow management at FMC Technologies and an adjunct professor of subsea engineering at the University of Houston, said there is a range of mature technologies designed to keep production flowing. Many of these technologies allow production to flow from reservoirs that previously could not be produced economically. Asphaltenes in heavy crude is one example of a naturally occurring substance that originates in the fluid itself. “You cannot eliminate these issues. They are going to happen. You have to have some kind of remediation method or some kind of prevention method,” he said. Other challenges from heavy crude stem from the removal or reduction of unwanted substances. “They are naturally occurring from the fluid. Hydrogen sulfide (H2S) for example, is part of the fluid. You cannot stop it from coming out,” he said.
In response to these naturally occurring issues, operators have developed a range of technologies designed to keep the fluids flowing. Thermal insulation of flowlines is a mature technology, which is designed to prevent hydrates and waxes from building up. The technology itself is mature, but there is an ongoing evolution in the materials used to prevent the buildup. Materials that are strong enough to sustain pressure at 3,000 to 4,000 ft may not be suitable for deeper depths. Operators began using foamed polypropylene on subsea insulation systems starting in the mid-1980s. Other operators working in the US Gulf of Mexico (GOM) in water depths between 2,000 and 7,600 ft have encased their equipment with an epoxy-based syntactic insulation. “Thermal insulation is an established technology, but there is still a lot of research into new materials,” Kondapi said.
Direct electric heating is a mature technology for shallow water applications and pipelines that are shorter than 50 km in length. “It is still an emerging technology for deepwater applications,” he said. “They are doing research for deep water and for longer pipelines.” The technology is designed to reduce or prevent the formation of hydrates by keeping fluid temperatures above the hydrate formation temperature and above the wax appearance temperature. It is most actively applied in North Sea fields.
Although many of the chemical applications used to keep fluids flowing are mature, they are tailored to the specifics of a given field, Kondapi said. “Any chemical application is manufactured based on the fluid properties of a field. It all depends on the behavior and composition of the fluid. … You don’t get the same chemical for two different fields,” he said.
Low-dosage hydrate inhibitor (LDHI) is a mature chemical technology designed to prevent hydrates. In use since the late 1990s, it is used in projects worldwide, with the exception of the Norwegian North Sea. LDHI is a replacement for other thermodynamic hydrate inhibitors, such as methanol and monoethylene glycol. Its application requires a lower dosage.
Defoamers are another mature chemical technology that operators have applied to onshore operations in the US and Canada and some offshore applications. The chemicals are designed to reduce oil and gas condensate droplets in the gas stream, help separators operate more efficiently, increase oil and gas production rates, and reduce the formation of deposits, which means less downtime and cleaning costs.
Paraffin inhibitors have been used since the early 1990s, and the technology continues to mature as researchers look for ways to apply it in colder regions, where it can be applied through umbilicals in ultradeepwater and Arctic applications. A paraffin inhibitor was applied to a field offshore Norway with three wells to treat wax deposits and to meet environmental regulations set by the Norwegian Pollution Control Authority. In general, paraffin inhibitors keep pipelines and tubing strings clear of wax plugs that reduce flow rates, prevent higher pressure drops that wax deposits can cause, and reduce the frequency that pipeline needs to be pigged for wax removal. The application is customized to the behavior of the fluid from any given field, but Kondapi said it is typically applied downstream from the choke. “It’s completely dependent on the temperature,” he said.
Operators have the option of applying H2S scavengers, which is a mature technology that is seeing ongoing development. Some H2S scavengers have been discontinued amid stricter environmental regulations, while others have been developed. The chemicals improve the safety of facility personnel by reducing H2S concentrations and help control corrosion, which extends the life of system piping, vessels, and processing equipment.
Although the use of subsea separation technologies is growing, it is still developing. The technology is attractive because subsea separation units are designed to increase recoverable reserves and to accelerate current production. The emerging technology, however, still faces serious challenges when separating liquids and gas from liquids in heavy crudes. Researchers are also working to make the units more compact and to dispose of the separated water. Despite those challenges, operators have installed subsea separation projects in the North Sea and GOM, and offshore west Africa and Brazil. The units are designed to reduce backpressure on wells, accelerate and increase recovery, reduce reservoir uncertainty, and improve flow assurance in harsh environments.
Kondapi also described other emerging technologies. Subsea coolers and subsea compressors are embryonic technologies that are often used alongside subsea separators and multiphase boosting. Subsea technologies are rapidly evolving because of potential savings in operating expenditures by moving some of the traditional fluid processing activities to the seabed. Operators have used real-time online monitoring and flow assurance advisory systems for nearly 20 years and the technology has been applied around the world. The systems allow the operators to know in real time when flow problems arise based on pressure readings acquired throughout the fluids' transportation.
Other technologies also address demulsification. Oil and water separation or “demulsification,” for which Baker Hughes scientist William Barnickel was the first to be awarded a patent in the early 1900s, is a well-known technology. Asphaltenes are a common component of heavy crudes and are usually stable in solution as long as they are undisturbed in the reservoir. However, when the reservoir is produced and a pressure reduction is applied, they can become unstable and precipitate, fall out of suspension, and eventually block flowlines and separators (Fig. 2).
From a chemical solutions perspective, asphaltene problems can be resolved by using inhibitors and dispersants. Asphaltene dispersant chemicals work by breaking up the solids already formed by the precipitated resins, and sending them back into the oil. However, asphaltene inhibitors work by preventing the precipitations in the first place. “It’s better to try to inhibit a problem rather than try to remedy it afterwards,” said Adrian J. Wiggett, technical operations manager for the Middle East at Baker Hughes. Advanced inhibitors allow heavier crudes to be produced that would otherwise stay in the formation. “We’ve developed products that can deal with the asphaltenes and help reduce viscosity,” he said.
Baker Hughes has developed a practical inhibitor technique that works to maintain the asphaltene in solution, making it easier to demulsify. The inhibitors help prevent precipitation of the solids that can gum up separators and flowlines. The purpose of these chemicals is to optimize processes and keep production flowing.
Baker Hughes tested both asphaltene dispersants and inhibitors with certain demulsifiers and found that the best resolutions came from the inhibitor, which can also be applied by capillary injection to prevent downhole precipitation. Without asphaltene inhibitors, the disruption of the reservoir could lead to blockage and loss of well production.
Operators are seeing more heavy crudes, bringing with them the high viscosity and higher asphaltene contents. “These aren’t the easy crudes from 20 odd years ago,” Wiggett said. Today, the crudes are heavier and more viscous. “If operators don’t apply a chemical treatment program at a point upstream of where you have the problem, then it’s difficult to produce these fields,” he said. “After a relatively short period of time, the wells can block up.”
The technology exists for widespread commercial use of asphaltene inhibitors, although their application is customized to a specific formation and crude. “Different crudes need to be tested to see how they will perform,” he said.
In one test case, the company was working with an operator that was investigating how to pump heavy crude with 17% asphaltene content by weight and an emulsion of 40% to 46%. The operator needed to find a way to lower the viscosity, and one way was to control or eliminate asphaltene precipitation.
The idea behind the test was to stop asphaltene precipitation before it reached the treating facilities. “If you don’t deal with the asphaltenes early enough, they will precipitate out, possibly making it necessary to dig out vessels,” Wiggett said. “The concentration of the asphaltene inhibitor needs to be maintained from the wellhead or downhole by continuous injection.”
Asphaltenes tend to precipitate when there is a pressure change, so it is best to get the inhibitor as far upstream as possible, either in the well or in the formation itself. Asphaltenes are stable until pressures around them start to change. “If you’re doing a gas lift or any kind of artificial lift recovery method, you can destabilize the asphaltene resins, causing the asphaltenes to precipitate out pretty readily,” he said.
Like the asphalt on a highway, asphaltenes can gum up a wellbore or a flowline and can slow or halt production. Heat treatment generally does not work and mineral acids do not break them up. “It’s better to try and keep them in solution,” he said. Many chemical applications are best when used as a continuous process, while others lend themselves more to batch applications. Asphaltenes and demulsifiers lend themselves more to a continuous process, said George Murphy, business development manager for the Eastern Hemisphere at Baker Hughes. “Continuous injection is much the preferred way to apply the product,” he said, adding that it allows production to flow uninterrupted. The inhibitor is oil-soluble and stays in the crude all the way to the refinery. Dispersants tend to be used in batch processes, because they are used to clean up wellbores and other downhole items.
The application of asphaltene inhibitors is a necessary business cost for producing many of the crudes today. Without them, many of the heavier crudes would never come to market.
In the past, chemical treatment using a capillary injection tube inside a well was expensive and difficult. “But today, as operators produce more and more difficult crudes, they need to put in these capillaries and electrical submersible pumping systems to recover the crude,” Wiggett said. As a result, injecting an asphaltene inhibitor is not considered expensive when compared with the cost of drilling wells in challenging formations and with using other artificial lift technologies.
In many cases, the challenge is predicting when asphaltenes will precipitate. They are not discrete molecules, but are a series of molecules with a micelle around it. If the micelle is broken, the asphaltene precipitates and gums up vessels and flowlines. Refiners, for example, regularly blend multiple grades of crude. They might buy one crude with a high asphaltene content, which is not a problem because the asphaltene is stable and suspended in solution. If they mix and blend that crude with one that is paraffinic in nature, they run the risk of disturbing the solubility and the asphaltenes can precipitate. So a precipitation problem may not occur in the production or processing facilities, but it can crop up in refining farther downstream, depending on the type of crude it is blended with. “The solutions need to be tailored to the particular conditions of pressure and stability of the asphaltenes,” Murphy said.
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