Document Actions
Keys to heavy oil: Characterizing fluids and the reservoir
By Shawn Taylor - Success with heavy oil depends as much on understanding the fluid properties of the reservoir as it does on knowing the geology of the reservoir itself.
The reason is that the chemical differences between heavy oil and conventional oil ultimately affect their viscosity. Viscosity, in turn, influences every other aspect of a heavy oil development. Technology that was developed for conventional plays does not address the issues of producing heavy oil. Viscosity is the key.
Every new heavy oil development eventually requires some form of enhanced oil recovery (EOR), which generally means steam, solvents or a combination of both. Without EOR, the recovery factor from what the industry calls “cold” production might be as little as one percent and no more than 10 percent. With thermal recovery, typical rates run from 30 to 70 percent. In thermal processes, however, the cost of generating the steam is typically the single greatest operating expense.
Thermal recovery options in some reservoirs include the use of cyclical steam (“huff 'n' puff”), downhole heaters, or a relatively new commercial process called Steam Assisted Gravity Drainage (SAGD). Other techniques, such as injecting slugs of water alternating with gas (WAG) are less efficient than thermal recovery, but also less expensive.
Sampling fluid properties
The mobility of reservoir fluids influences recovery rates, but the enhanced oil recovery and artificial lift methods needed to produce them changes the already complex fluid characteristics of heavy oil.
To properly specify the field’s surface and downhole equipment, it is important to understand those fluid properties and how they might change throughout the system. In Alaska’s West Sak and Schrader Bluff formations, for example, heavy oil viscosities range from about 30 to 3,000 centipoise.
Determining the true viscosity of heavy oil is a complex process involving both in situ testing with wireline tools, and the laboratory analysis of fluid and core samples taken from the well. These are common procedures in reservoirs with lighter crude, but with heavy oil, even the physical task of drawing the viscous fluid into a sample container can be difficult.
Getting a representative open-hole fluid sample can take more than a full day of rig time because the first fluids to come up will be thick with drilling mud, sand, water and other contaminants. The fluid properties of new wells may continue to change over weeks or months.
Foaming oil
Foaming complicates the process even more. When heavy oil contains associated gas, foaming may occur at any point in the reservoir, wellbore, flowlines or production equipment at the surface. It happens when gas reaches its bubble point and comes out of suspension as the pressure and temperature of the fluids change.
Gas separates from lighter crudes much faster and more predictably than it does from heavy oil. The ability of the oil to foam depends on its viscosity, so higher viscosity oil is more likely to foam, and the foam it makes will be longer lasting.
While foaming can be a problem, it can also work in the operator’s favor. Since any foam that forms in the reservoir increases pressure, it can serve as a temporary gas drive, pushing oil toward the wellbore.
The trick, of course, is to understand enough about the fluid properties to know where and when the foaming is likely to occur. It won’t help you much if the foaming does not begin until fluids reach the production separator.
Fluid samples that contain oil-based drilling mud (OBM) can alter a fluid’s bubble point and viscosity. If the true bubble point is 2,000 psi, for example, OBM in the fluid sample might drop the measured bubble point to 1,000 psi. If surface equipment is then designed based on the 1000 psi value, however, operators could be surprised by gas coming out of suspension much sooner than than expected, and their facilities would not have enough capacity to handle it.
Testing also shows how the well fluids will react when mixed with other fluids, such as gas, solvents or lighter crude. The emulsions formed in heavy oil are harder to break than they are with less viscous fluids.
The danger of not doing enough fluid testing is that the design of the field’s surface production equipment will not be adequate to handle the flow.
Understanding the full picture
When the time comes to make key decisions such as well placement or completion design, operators with the most accurate picture of their reservoir will make the best choices for their wells and surface facilities.
Detailed reservoir characterizations are also the foundation for future decisions, such as selecting the right time and follow-up production method to enhance overall recovery.
That improved ability to predict how a reservoir will behave benefits every decision maker on the project team, from the geologist and production engineers to the asset manager. The time and money operators spend in the beginning to learn about their reservoir will pay off many times in the end.