Mixing proppant and fluid downhole reduces the risk, increases the efficiency and lowers the cost of fracturing wells.
During the 1960s, Japanese automakers adapted several American assembly line and quality control processes into an approach called just-in-time manufacturing. The idea was to have everything required to build a car component arrive at the right place, at the right time - no sooner, no later. Its success is one reason many of us drive Toyotas.
The same idea has been applied to fracturing treatments - mixing proppant and fluid downhole at the perforations just in time for delivery into a fracture. While the well test results are limited, they are encouraging, and could be applicable for numerous reservoirs that require stimulation.
Pumping fracture treatments at high pressures is expensive and can be a safety hazard, particularly in wells with older tubulars in mature fields. For both reasons, stripper wells often are rejected as candidates for high-pressure fracturing stimulation treatments that could result in improved oil or gas recovery. A US Department of Energy (DOE) project has shown that mixing fracture fluids at the bottom of the well, rather than on the surface, may lead to a safer process with lower pumping pressures and lower costs. A second benefit is an increased ability to alter the treatment mixture at the perforations during the treatment (in real time), thus facilitating more precise control and fewer out-of-zone fractures.
RealTimeZone Inc. (RTZ), of Roswell, N.M., used its downhole mixing technique for the first time in November 2001, in a 12,300-ft (3,752-m) Morrow gas well in the Sand Point field of Eddy County, N.M.
"The treatment consisted of a methanol gel with 7,000 lb of bauxite proppant pumped down the annulus and 40 tons of liquid CO2 pumped down the tubing. Tubing pressure never got above 6,000 psi, and the casing side was never above 5,000 psi. Pressures averaged around 5,000 psi, but if we had pumped the job in the conventional manner, the pressures would have averaged closer to 10,000 psi," said George Scott, president of RTZ.
Liquid CO2 was used because after the proppant has been placed in the reservoir fracture, the drop in bottomhole treating pressure turns the liquid CO2 to gas, allowing the fracturing fluid to be produced back from the formation at a faster rate. Originally scheduled for abandonment, the Sand Point well's post-fracture production was 200 Mcf/d to 250 Mcf/d. A post-fracture tracer log showed the treatment had been placed in the zone as designed.
"The value of this approach is twofold," Scott said. "Lower friction pressures mean less hydraulic horsepower and thus less cost, and surface control of the mixing downhole process permits the operator to exert real-time influence over the treatment. That isn't possible when you're mixing the treatment fluids at the surface." Changes in stimulation pressures monitored at the surface also allow an operator to know if the fracture is being created as planned. If necessary, the operator can alter the mixture, at the perforations, to ensure that a fracture goes into its intended zone. This can mean the difference between success and failure, particularly in wells that have a tendency to screen out prematurely.
RTZ can combine this downhole mixing methodology with a downhole, real-time, surface readout fracture monitoring system to give an even more accurate picture of where the fracturing fluids are going. Working with Halliburton Energy Services to incorporate its gamma-ray Spectrascan log, RTZ performed a treatment in another Eddy Co., N.M., well completed in the Willow Lake Delaware oil reservoir. Spectrascan uses distinctive radioactive tags on both proppant and fluid to reveal the relative distribution of pumped material within the reservoir fracture.
The Willow Lake well was considered a dry hole. The Delaware sandstone showed about 40 ft to 50 ft (12 m to 15 m) of net pay at a 5,000-ft (1,525-m) depth, with a wet zone 40 ft to 50 ft (12 m to 15 m) thick directly below the pay and no stratigraphic barriers. Most wells in the area produce at 60% to 90% water cut because hydraulic fractures invariably grow out of zone. "Tracer logs showed frac heights of 100 to 200-plus ft (31 m to 61 m) in most wells in this field," Scott said.
RTZ pumped gelled lease oil and proppant down the tubing while pumping CO2 down the annulus, carefully controlling rates to achieve the appropriate mixing at the perforations. The result was an economic well: 8 b/d to 10 b/d at only 20% water cut.
A third test well completed this spring was an acid-CO2 treatment pumped to a Wolfcamp reservoir at 10,500 ft (3,203 m), also in New Mexico's Permian Basin. By pumping the acid down the tubing and the CO2 down the annulus, treating pressures could be maintained around 5,800 psi, rather than 9,000 to 10,000 psi. "We were able to complete the job using only two acid trucks," Scott said. "When a job can be pumped with less pressure, less horsepower and less fuel, it opens up opportunities for older wells with older tubing and lower incremental reserves to be stimulated economically." This treatment also was successful, and the well is producing gas and light oil with a 2,200-psi bottomhole pressure.
DOE's National Energy Technology Laboratory began working with RTZ on this methodology in early 1999. The project is in the final phases of field testing, and Halliburton Energy Services has licensed the process. With further testing, downhole mixing of fracturing fluids could find increased application in a variety of treatments, including perhaps the mixing of cross-linked gels downhole.

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