Drilling Fluid Disposal System

Drilling fluid disposal are cost prohibitive, environmentally risky and/or threaten the mechanical integrity of the well. Chemical solidification of the pit contents and disposal into a permitted commercial injection well are expensive, particularly where large quantities of high-chloride (>5,000 ppm) mud are being injected into a commercial disposal. For a typical 14,000 ft well in Western Oklahoma, it would not be unusual to spend $60,000 for either of these methods of disposal.

figure A
figure A

There is also the potential of future liability if either of these methods results in the contamination of a fresh (potable) water source. As a result, many operators have chosen downhole annular injection as a more economical way to dispose of their drilling fluids and cuttings. However, the traditional procedures for downhole annular injection have increased the potential for a mechanical failure and contamination of a potable water source.

Operators presently inject mud by one of the following methods:

  • Inject the mud into the pattially cemented conductor (water string) by sufface casing annulus, either during or after drilling the production hole. (See Figure A.)
  • Inject the mud into the surface casing by production casing annulus. (See Figure B.)

This new method of downhole annular injection of drilling mud waste allows injection into a cemented casing interval which reduces the risk of a casing failure and contamination of potable water sources.

Drilling Fluid Disposal History

The Elder 1-34 well in Washita County, Oklahoma, was the first well in

Figure B
Figure B

which the new drilling fluid disposal system was run. A closed mud system was used because the well was in a WPA, and a landowner requested for no
reserve pit. A permit for downhole annular injection was filed with the Oklahoma Corporation Commission (OCC), notice was sent to offset operators, and a notice of heafing was published. (Administrative permission can be granted if no protests are made. The OCC Underground Injection Control Division has the authority to give approval of all permits for onsite mud injection.) Once approval was granted, the actual preparation of the fluid disposal system was initiated.

Buckling calculations were made, taking into effect the forces that would take place during fluid injection, to determine if any of the conditions would release the external casing packers. The buckling forces to be encountered during cementing, drilling and fluid injection were also considered for the casing design. A standard port collar was modified to accommodate the large quantity of solids-laden mud to prevent fluid cutting. The standard ports were enlarged, and a special corrosion and hardening treatment was performed on the port collar.

It was planned to perforate the sutface casing in the zone of injection prior to running the production casing. The potential for lost returns existed since the production hole would be full of heavier mud (9.7 ppg) when the surface casing was perforated. The potential well control problem was evaluated to determine if the heavier mud could be replaced with water and still maintain sufficient bottomhole pressure to control the well. The heavier mud could be replaced with 3,000 ft of water and still control the wells well’s pore pressure at TD.

Implementation Of Mud Disposal

A 12-1/4” hole was drilled to 3,940 ft, and 8-5/8” surface casing was run to TD. The surface casing was cemented in two stages to cover the potential lost circulation zone (injection zone) and allow cement circulation to surface, There were no mud losses encountered in the surface hole while drilling or cementing. The high-chloride (65,000 ppm) surface hole mud was stored in frac tanks after cementing.

API Shale shaker working
shale shaker working

A 7-7/8” hole was drilled with a water-based drilling mud (final MW 9.7 ppg) to a total depth of 11,400 ft. After running open hole logs, wirelin conveyed perforating guns were used to perforate the 8-5/8” surface casing from 3,394-3,414 ft and 3,450-3,470 ft with one shot per foot. No mud losses were encountered upon perforating. The 5-1/2” production casing was run with the disposal zone isolation equipment to TD. The isolation equipment consisted of a 7“ OD external casing packer (ECP), modified port collar, and i: OD extemai easing packer. The ECPS were run to a depth of 3,552 ft and 3,287 ft,and the port collar was run to 3246ft, (See Figure 1.) The bottom ECP was shear pinned to set at 1,250 psi and the top ECP was pinned to set at 2,000 psi. The shear values were based on cement being displaced 1,300 ft up the annulus. The actual surface pressure required displace the cement was 2,300 psi, so the ECPS were inflated prior to landing the plug. The higher surface pressure was required to displace more cement than was initially planned.

Drilling fluid disposal
Drilling fluid disposal was managed by Aipu solids control equipment

It was initially planned to displace the cement, bump the plug and set the bottom ECP first; this Wouid have allowed a pull test to be performed on the bottom ECP before setting the top ECP. Once the plug bumped, the pressure was increased to 3,000 psi and held for 10 minutes to ensure proper inflation of the ECPS. The top ECP was pressure tested by way of the annulus to 2,000psi, indicating that the top ECP was set. The operation was suspended at this point while the drilling rig was rigged down and a workover rig was moved in.

Once the workover rig was in place, the actual disposal process began. The tools used to isolate and open the port collar consisted of, from top to bottom,: 2-7/8” tubing,; tension set retrievable cementing packer; a port collar shifting tool; and a retrievable bridge plug. (See Figure 2.) The tools were run in the hole and the bridge plug was set at 3,611 ft. (See Figure 3.) The tubing was picked up to locate the port collar with the shifting tool, but the port collar could not be located. The cementing packer was laid down to see if it was interfering with the shifting tool, but the port collar still could not be located. An electric wireline collar locator was run to pinpoint the port collar, and it was opened with no additional problems. (See Figure 4.)

After opening the port collar, an injection rate of 2 6PM at 1,250 psi was established. Our OCC injection permit did not allow a surface injection pressure greater than 1,000psi, so the mud disposal was stopped. The tubing was tripped, and the retrievable cementing packer was run and set at 3,370 ft. (See Figure 5.) An acid treatment was performed using 1,000 gallons of 7-1/2 percent HCL acid. The injection pressure dropped from 1,200 psi to 600 psig at 3-4 6PM after displacing the acid. The mud disposal was resumed, pumping a total of 9,500 barrels of mud over three days. (See Figure 6.) The 8-5/8” x 5-1/2” annulus was monitored throughout the job to make sure that the top ECP was holding. The last 1-1/2 ft volumes of the frac tank’s mud had to be thinned with water and rolled when the mud became too thick to pump. Upon completion of pumping the mud, the well was allowed to flow back till it bled down to 0 psi over a period of one hour. the packer was released, and the tubing was lower to the port collar (see figure 7). The port collar was shifted closed. It was initially planned to displace the final volume of mud with cement to isolate the injected mud from the casing. However, due to the difficulty in locating the port collar, it was decided not to pump the cement. The casing was tested to 3,000 psi with no bleed-off. The retrievable packer and bridge plug were retrieved, and completion procedures were initiated. (See Figure 8.)


  1. If an ECP fails to set or if the port collar fails to open, the alternative is to continue with the annular downhole injection without zonal isolation or dispose by alternative methods. If the port collar fails to close after displacement, a squeeze cement job becomes necessary.
  2. The time to locate and open the port collar can be shortened considerably by running a collar locator when opening the port collar. The retrievable cementing packer should also be run with the locating tool to save time.
  3. The shear pin on the ECPs should be set to pervent the inflation of the ECP until the cement is displaced if possible. This will allow the bottom packer to be pull tested to determine if it is set prior to inflating the top ECP.
  4. Cement should be pumped upon displacement of the mud to provide a corrosion barrier to the casing and minimize the chances of the port collar leaking in the future.


  1. The initial run of the drilling fluid disposal system was a success. There were several problems which occurred during the job, but the only goal which was not accomplished was displacement of the cement following the mud injection.
  2. This fluid injection system provides a more economical method of displacing the drilling fluids and reduces the risk of contaminating potable water sources and jeopardizing the mechanical integrity of the well.
  3. The modified port collar allows the casing to be shut off after mud injection to retain the mechanical integrity of the wellbore and allows the casing to be protected with cement.
  4. On the Elder #1-34, well the total cost of this system was less than 30,000 . That inciudes downhole tools, frac tank rental, workover rig, pumps and other miscellaneous expenses.
  5. The use of ECPS is not recommended in open hole “without cement isolation above and below the packers. The packers isolate too short an interval to prevent communication with the annulus due to frac height growth during injection.
  6. This method of mud disposal is limited to wells with mud weights at TD which will not exceed the fracture gradient in the injection to pervent loss circulation and possible well control problems.
Figure 5 - 8
Figure 5 – 8
Figure 1 - 4
Figure 1 – 4

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