Jetting tool and drill-in fluid remove well bore damage

John C. Welch Baker
Hughes Inteq
Houston

Robert D. Haymes
Tulsa

Well bore damage created by conventional drilling fluids, under conditions of low bottom-hole pressures, can be removed during the completion operation with a high-pressure jetting tool, utilizing a carbonate-based drill-in fluid system.

This combination allows operators to perform completion operations in depleted zones, under conditions of extreme overbalance. For the purpose of jetting damaged well bore sections, a special drill-in fluid was developed to withstand differential pressures up to 5,000 psi, while sealing the formation with a very thin, nondamaging filter cake.

Drill-in fluids are specifically engineered to preserve as much reservoir flow capacity as possible in a pay zone while retaining the normal drilling fluid properties of bit lubricity, cuttings transport, and shale stability.

In many oil field operations, operators replace the mud system with these drill-in fluids before entering pay zones. Application of the drill-in fluid allows the pay zone to be completed with an open-hole gravel pack without the need for further stimulation.

Because of high overburden pressures, the drill-in fluid needs to quickly seal depleted zones during the jetting process, yet be easily removed under conditions of low production pressures.

The jetting and drill-in fluid system was field-tested by Kaiser Francis, an oil operator, in the Nickerson No. 1 well, located in Southern Louisiana. This provided and ideal test situation because a thick filter cake, induced by drilling with a bentonite-based drilling fluid, had built up across the pay zone, effectively plugging the well bore.

Jetting system

An under reamer was not used to remove the well bore damage over concerns of differential sticking and its inability to pass through the casing string. Instead, a jetting tool, specially designed by Kaiser Francis, was used to wash away the damaging filter cake.

Previous laboratory testing indicated that a 2,000 psi pressure drop across a nozzle, while rotating at 6 rpm for 10 min with a 2 ppg slurry of 20/40 sand, can cut through 5.5-in. casing and erode 7 in. of Berea sandstone.

Based on this testing, a 33/8-in. OD pipe was fitted with three 3/16-in. OD jets, creating a pressure drop of 2,500 psi at 3.5 bbl/min. The 33/8-in. OD tool allowed sufficient clearance through the 4.276-in. ID casing and minimized formation standoff.

The goal consisted of cleaning out the hole to an OD of 10 in. The sand slurry was reduced to 0.25-0.50 ppg because there was no casing in this section of the hole. The pressure drop was increased to 2,500 psi to allow for increased jet erosion.

Drill-in fluid

The reservoir interval was drilled with a 9.5 ppg water-based bentonite drilling fluid, overbalanced by 4,750 psi to the producing formation. This mud density was needed to prevent the shale sections above and below the pay sand from sloughing.

During the drilling operation, the drillstring became stuck several times because of the abnormally high hydrostatic-vs.-reservoir pressure differential, despite the use of a very low fluid-loss system. In order to avoid the previously encountered problems, a new type of fluid had to be employed in the jetting operation.

The drill-in fluid used for jetting had to withstand 5,000 psi of differential pressure to control fluid loss while removing the mud filter cake. The fluid also had to be nondamaging to the formation with the resulting filter cake still being capable of flowing through a gravel pack.

A calcium carbonate drill-in fluid system, using high-performance polymers, was selected for evaluation as a candidate fluid based on previous laboratory tests and field trials.1

Review of available information on the system's performance indicated that further laboratory testing was required to characterize this drill-in fluids performance under extreme pressure conditions. A special test was designed and conducted to determine the leak-off characteristics of the drill-in fluid system at very high differential pressure. Fig. 1 [65,469 bytes] shows the core testing apparatus.

A Berea core sample with 500 md of air measure permeability, approximately 1 in. in diameter and 3 in. long, was tested by the following procedure:

1. Measure and record the sample's length, diameter, and dry weight.
2. Vacuum saturate the sample with 2% potassium chloride and re-weigh. Note that the pore volume calculated from the weight difference was 7.7 cc with a porosity of 21.9%.
3. Load saturated core into hydrostatic core holder. Note that the core holder end piece located against the injection face of the core was hollowed out 1/8 in. to allow mud to be circulated across the injection face of the core.
4. Mix and load a fresh drill-in fluid system into the transfer vessel using a specially sized bridging agent.
5. Perform mud-off stage. This step pressurizes the drill-in fluid against the core and is carried out by increasing the pressure differential across the core to 6,000 psi in increments of 500 psi over a 30-min period. Two Waters Model 590 programmable pumps are employed. One pump applies confining stress to the core while the other pump pressures the drill-in fluid against the injection face of the core. The two pumps are coordinated to maintain a net confining stress of 1,000 psi on the core. Each pressure increment occurs over the span of a few seconds.
6. Note and record any fluid expelled (leak off) from the core at each pressure increment.
7. Once the test achieves a maximum differential pressure of 6,000 psi, record leak-off data every 5 min for an additional 30 min.

The selected drill-in fluid system appeared to bridge the core immediately. The first drop of filtrate appeared after 17 min into the test at a differential pressure of 2,500 psi.

After holding 6,000 psi differential for 30 min, the cumulative leak-off was only 1 cc. Results are shown in Fig. 2 [34,230 bytes].

Permeability testing

Additional testing was performed to further evaluate the return gas permeability after exposure to the drill-in fluid system, simulating a gas well with very low bhp. Maximum pressure used in previous return permeability tests involved 2,000 psi mud-off pressure.

The considerations of extreme overbalance (5,000 psi) and a low-pressure flowing phase of gas (500 psi bhp) required the use of specially constructed equipment to qualify the candidate drill-in fluid system for use in the well referred to in this article.

The return gas permeability test was conducted with essentially the apparatus used for leak-off testing, but with special modifications to measure and simulate reservoir conditions. A computer was used to control and maintain constant temperature as well as digitize pressure and flow data.

During the tests, the computer constantly displayed temperatures, pressures, and flow rates. Also, data were logged to disk for subsequent analysis.

A second Berea core sample with 650 md of air-measured permeability, approximately 1 in. in diameter and 3 in. long, was tested by the following procedure:

1. Measure and record length, diameter, and dry weight.
2. Load core sample into a Hassler-type cell.
3. Apply 6,000 psi confining stress to the core and raise temperature to 200° F.
4. Measure initial gas permeability.
5. Flow-saturate core with 2% potassium chloride at 400 psi back pressure. Liquid permeability for the sample was determined to be 182 md.
6. Flow humidified nitrogen gas in the production direction with no back-pressure until the pressure drop across the core stabilizes.
7. Record initial pressure and check pressure drop over a succession of five flow rates, ensuring presence of laminar flow conditions in the core. The pressure drop was plotted against flow rate for initial, final, and after-acid permeability. Interpolated pressure drops were used for permeability calculations. The initial permeability for the sample was 366 md.

The mud-off stage of this test was carried out at 5,000 psi according to the following procedure.

First, the drill-in fluid system, a base brine containing 2% potassium chloride, was flowed across the injection face of the core.

Next, the bleed valve was closed and the pressure against the drill-in fluid system was increased to 5,000 psi and held for 30 min. Because the production side flow lines were filled with gas during mud-off, it was not possible to determine spurt loss or leak-off in this phase of testing.

After mud-off, the injection lines and flow head were rinsed with 2% potassium chloride and a flow of nitrogen was started in the production direction. The break-out pressure, the net amount of pressure required to initiate flow after mud-off for return flow, remained between 3 and 7 psi.

Flow was sustained until the pressure drop across the core stabilized. The final pressure drop was recorded for several flow rates to ensure laminar flow. The return gas permeability was calculated to be 329 md.

The return permeability, calculated by dividing final permeability by initial permeability, was calculated to be 90%.

The leak-off testing indicated that the drill-in fluid system filter cake was capable of bridging a gas-saturated rock with low leak-off volumes under pressures as great as 5,000 psi and temperatures of 200° F.

Return gas permeability testing verified that the drill-in fluid system was a good fluid selection for low bhp gas wells, indicated by the low-net break-out pressure required to initiate return gas flow and the high return permeability value.

Jetting operation

Fig. 3 [84,226 bytes] shows a diagram of the jetting process. For the purpose of pay zone identification, the well was open-hole logged from 10,950 to 11,065 ft. Next, a 41/8-in. bit was run in the hole on 27/8-in. and 41/2-in. drill pipe to the bottom sand.

The annular volume was pumped and circulated out of the well bore. Ten bbl of 9.3 ppg brine, followed by 15 bbl of drill-in fluid, were pumped and spotted in the open hole. The bit was pulled into casing and the casing was displaced with 9.3 ppg brine. A rabbit was dropped and the rest of the string pulled out of the hole.

Next, the bottom-hole assembly was tripped in the hole with the 33/8-in. OD jetting tool, dressed with three 3/16 in. jets and one blank. A swivel was rigged up and spaced out to jet the pay sand. When the tool reached the top of the pay sand, pumping was started.

Fifty bbl of the sand-less drill-in fluid system were pumped at a rate of 1 bbl/min, followed by 120 bbl of the drill-in fluid system using 0.25 lb proppant/gravel added per gallon of fluid (20/40 sand) followed by 30 bbl of drill-in fluid without sand. After eroding the damaged zone with the jetting action, the drill-in fluid was displaced with brine at a rate of 31/2 bbl/min.

While displacing the hole, the jetting tool was rotated at 10 rpm, and the tool was worked down the hole at 1-2 fpm. When the jetting operation reached the bottom of the sand, the tool was picked up and the jetting operation repeated.

At the end of displacement, the pump rate was reduced to 1 bbl/min and the tool picked up into the casing. The circulating port was opened and bottoms-up circulated at 3 bbl/min. The tool was pulled out of the hole and laid down.

Finally, a 41/8-in. bit was run into the hole to total depth. One hundred forty bbl of brine were circulated while rotating and working the pipe in the open hole. When finished, the bit was pulled into the casing and bottoms-up circulated again.

The bit was then tripped back to bottom and the open hole displaced with brine filtered to 15 national turbidity units. The drillstring was pulled into casing and the casing volume reverse circulated out of the hole.

After the jetting tool was pulled from the hole, a gravel packed completion was installed across the open hole. The well was completed with 65 ft of 6 gauge (0.006 in.), 2.8 in. OD wire wrap screen.

The completion operation used 2,500 lb of 40/60 gravel that was placed with 2,345 lb covering the screen and 155 lb of gravel covering the blank at the top of the screen. The gravel was pumped at a concentration of 1 ppg. A hook-up nipple was latched on the gravel pack assembly and the packer set. A pumping unit was installed and the well put on production. The finished well assembly is shown schematically in Fig. 4 [40,557 bytes].

The production resulting from the jetting operation exceeded the replaced well and is producing gas on par with the best producing wells in the field.

Reference

1. Donovan, J.P., and Jones, T.A., "Specific Selection Criteria and Testing Protocol Optimize Reservoir Drill-in Fluid Design," paper SPE 30104 presented at the European Formation Damage Conference held in The Hague, The Netherlands, May 15-16, 1995.

The Authors