Preferred Fluids Management

Well Construction

Each of Preferred’s two proposed wells have identical designs, incorporating all necessary design, operation, and monitoring features to ensure that the waste fluids are injected only into the permitted injection zone and remain securely isolated from the ecosphere for geologic time.

Each well is constructed of a series of three pipes and two layers of cement to isolate the waste fluids from the fresh water. As part of the permitting process, the depth of the lowermost underground source of drinking water, called the USDW (A) has been identified as the Berea Sand at a depth of approximately 600 feet. After the drilling rig drills through the USDW, it then inserts a steel pipe of 9 5/8” diameter called the surface casing (B) through the bottom of the USDW. The next step is to cement the casing in place by circulating cement down the hole, then back up the outside of the casing all the way back up to the surface. This jacket of surface cement (C) forms a secure seal that prevents any communication between the USDW and any deeper part of the hole, either during subsequent drilling or during injection operations. The drilling rig then drills out from the bottom of the surface casing to a depth of about 5,300 feet—through the lowermost portion of the injection zone (D) called the Mount Simon Sandstone.  Steel pipe of 7” diameter called the production casing (E) is then inserted into the hole to the top of the Conasauga Sandstone, the uppermost layer of the injection zone. Again, the pipe is sealed in place by a layer of cement, called the production casing cement (F), pumped down the hole and circulated up the outside of the production casing back to surface.  Finally, a smaller steel pipe of 4.5” diameter called the injection string (G) is run in the hole and sealed in place by a removable packer (H) which forms a tight seal between the production casing and the injection string, thus preventing fluids introduced into the injection zones from migrating back uphole. The space between the packer and the tubing, called the annulus (I) is filled with a heavy packer fluid (J) that exerts weight on the top of the packer to keep it securely in place. This fluid-filled annulus is held under a constant pressure which can then be monitored at the wellhead with the annular pressure gauge (K). The wellhead is also equipped with an injection pressure gauge (L) that monitors downhole pressure during injection operations.

At each stage of the construction process, rigorous testing procedures are performed to test the integrity of the pipe and the cement seals. The effectiveness of the cement’s bond to the pipe is measured through electric wireline logging tools that record readings for every foot of the wellbore, and pipe strength is pressure-tested at pressures much higher than those permitted during operations.

During operations, fluid is pumped from surface tankage through the wellhead and downhole through the injection string. By terms of the permit, injection pressure is limited to 1,025 pounds per square inch. If the injection pressure gauge indicates that the injection is occurring in excess of permitted pressure, an automatic switch shuts the injection pump down immediately. Likewise, if the production tubing, the injection string or the packer experience a leak, the annular pressure monitor would detect a change in pressure and the well would shut down immediately.
With minor variations to suit local conditions and individual operator preferences, this basic well design and operating procedure is the standard for Class II wells across the United States. Thousands of wells have been installed in the era of modern disposal well regulations and, almost without exception, have never failed to protect the groundwater. Although mechanical failures do occur, the many redundant protective design features serve to ensure that the injected fluid does not enter the wellbore outside the injection. The injected fluid is isolated from the groundwater—both on its downhole pathway through the injection string and once in place in the injection zone—by three pipes and two layers of cement, as well as the annular fluid barrier. Terms of the permit also require a periodic pressure testing of the casing, called a mechanical integrity test.

Preferred’s design and operating practices will exceed regulatory requirements in at least two important ways:

• The production casing is cemented back to surface, rather than just a few hundred feet above the top of the injection zone, thus ensuring that the entire void around the surface pipe is filled with cement for the depth of the well.
• Monitor gauges for injection pressure and annular pressure will be wired to automatically shut down the injection pump when the appropriate operating parameters are exceeded.