On the Science Side of Drilling

Mixing Oil and Water may keep Bakken Wells Flowing

Feb / Mar 2014 Donmei Wang

The current method of oil recovery from the Bakken formation relies on the natural pressure in the reservoir to push the oil through the rock to the well. However, experience has shown that after producing a relatively small fraction of oil, the natural pressure in oil reservoirs declines and subsequent production falls, sometimes leaving behind as much as 95 percent of the oil. Fortunately, the decline has yet to appear in the Bakken region. Oil production, at roughly a million barrels per day, is high and increasing because the reserves are huge and large-volume production has been underway for only a short time, which means it’s still too soon for the natural reservoir pressure to drop off. However, eventually, the pressure will decline and oil production will fall, if not stop.

What can be done to extract all that remaining oil?

A group headed by Dr. Dongmei Wang at the University of North Dakota is researching new ways to recover the vast untapped oil likely to remain beyond the reach of current extraction practices. Through funding provided under the RPSEA (Research Partnership to Secure Energy for America) program authorized by the U.S. Energy Policy Act of 2005, the researchers are attempting to develop a method that may increase oil recovery five-fold. How? In simple terms, they believe it’s possible to take hydraulic fracturing another step by using specially treated water to drive far higher quantities of oil out of the shale and into the wells. The key word is “imbibition.”

Dr. Wang’s group has shown that the Bakken shale is generally wet with oil — meaning the rock surfaces are coated with oil. In addition, the group has researched water treatments – mixtures of water and surfactants, which are similar to dish detergent – that will induce the rock to absorb water and expel oil. In other words, the process alters the “wettability” of the rock.

Once this change is made, the rock draws in the surfactant-water — a process called imbibition. As the surfactant formulation is absorbed by the rock, oil will be expelled. That oil would then be collected by the same fracturing systems and horizontal wells that are currently producing Bakken oil.

However, the research is in its early stages. So far, the UND research group has shown that ordinary brine (salt water) can drive out small quantities of oil from shale, though not enough for commercial success. Achieving high oil recovery rates requires the right surfactant, the proper salt content, the correct pH, and effective temperature. Dr. Wang’s group is seeking that optimum formulation. To help, oil companies have provided rock cores, as well as oil and water from their target oil reservoirs. With these cores and fluids, the team is studying the effects of various surfactant formulations.

The laboratory measurements are then scaled up to determine whether enough oil will be produced to make the process economic. Analytical calculations and computer simulations are being performed to scale the process for particular field applications. However, the analysis is complicated by the relatively early stage of production in the various producing fields, the size of the Bakken formation and the substantial variation in reservoir character (degree of fracturing, pressure, oil saturation, permeability, temperature). Nevertheless, results suggest that imbibition of surfactant formulations has a substantial potential to improve oil recovery in certain parts of the Bakken.

Meanwhile, the team has several scenarios in mind for field-testing. In one scenario, the surfactant-water formulation would be injected through a horizontal injection well at the bottom of the reservoir. At the same time, a horizontal production well at the top of the reservoir would be used to collect oil and other fluids. Injection and production rates would be adjusted to maximize the oil output. The optimum timing, volumes, and rates associated with this process would depend on the nature of the fracturing, local permeability,spacing between the wells, and the rate of imbibition. UND’s simulation efforts will examine these parameters and attempt to identify the best combinations for a field application.

Alternatively, the process might include the steam injection process, also known as the Huff and Puff method, in which steam is pumped into a well to heat the oil in the reservoir to a temperature at which it will flow. The process would be attempted in settings where the character of the fracturing is favorable. As with the flooding application mentioned above, optimumtiming, volume, and rate associated with this process would also depend on fracture intensity,formation pressure and the inherent imbibition rates for the rock.

Meanwhile, Dr Wang’s research efforts have caught the interest of major oil companies. In addition to funding from RPSEA, the UND group has received backing from several oil companies – Statoil, ConocoPhillips, Noble Energy – to develop the process for their shale formations, including the Niobrara in addition to the Bakken. Chemical companies – Tiorco Inc., Nalco Champion – are also participating in the research by providing surfactants to be tested as part of the new process.

In summary, due to the extraordinary opportunity for the reshaping of the domestic energy market, intense efforts to find the most productive extraction techniques are now going into high gear. This can only be good news for the country.