Mud lubrication technique is a viable well control tool - Statistical Data Included

When a drillstring becomes plugged during a kick, an alternative to circulating and replacing the influx with mud is to lubricate mud into the hole and bleed the influx to the atmosphere

Mud lubrication is a viable alternative in well control. The mud hydrostatic simply replaces the surface pressure resulting from the presence of gas in the wellbore. In order to be successful reservoir pressure and fracture pressure at the casing shoe must be considered and calculations must be made to avoid an underground blowout or additional influx. This article outlines appropriate calculations that result in proper procedures for replacing the influx with mud and controlling the well.

INTRODUCTION

It is common in drilling operations to experience an influx during a trip. Generally, the drillstring is partially or completely out of the hole. Under these conditions, it is common for the influx to migrate to surface while decisions are being made as to the proper procedures while arrangements for equipment and services are being considered. In some instances, the drillstring becomes plugged during a kick, and it is not possible to circulate the influx out of the hole in the classic procedure.

In instances where trips, are involved, the well is under control when the trip commenced, and control is lost during the trip. In routine cases, control can be regained by merely circulating and replacing the influx with mud. In situations where the drillstring becomes plugged, regaining control is slightly more complicated. However, the same technology may be used. Under these circumstances there are generally several alternatives.

One alternative is to lubricate mud into the hole and bleed the influx to the atmosphere. This procedure is not often used. A seat-of-the-pants approach can be disastrous, and a technical approach is not well understood by most field personnel.

The objective when lubricating mud into the hole is to replace the influx with mud. In the process, it is imperative that the fracture pressure at the casing shoe not be violated. If the fracture gradient at the shoe is exceeded, an underground blowout will commence, and the condition of the well will deteriorate.

In addition, it is imperative that when influx is released from the wellbore, the remaining effective hydrostatic exceeds reservoir pressure. If reservoir pressure is permitted to exceed the hydrostatic, additional gas will enter the wellbore. As the new influx migrates to the surface, surface pressure will vary as a result of the migration and further control operations will be adversely affected.

PROPER CALCULATIONS

Operations at Santa Fe Energy Co.'s Bilbrey well, located in Lea County, New Mexico, offer a good example of well control using mud lubrication, Fig. 1. An Atoka interval at 13,912 ft had drillstem tested 10 MMcfgd at a flowing tubing pressure of 5,100 pi. Shut-in bottomhole pressure was 8,442 psi. Routine drilling operations continued following the drillstem test, and a trip for a new bit was made at 14,080 ft. While out of the hole, the well began flowing, and approximately 1,500 ft of drill collars, heavy weight drill pipe, and drill pipe were run into the hole. By that time the condition of the well had deteriorated, and the blowout preventer was closed, Fig. 2.

[Figures 1-2 ILLUSTRATION OMITTED]

Pursuant to the pit level recorder and pressure analysis, the total gain was approximately 200 bbl. The influx migrated to the surface in about 16 1/2 hr for an average migration rate of 510 fph.

The drillstring was snubbed in to total depth. With the bit on bottom, surface pressure stabilized at 1,420 psi. Calculations indicated that the annulus contained 67 bbl of gas, Fig. 3. Unfortunately, the drillstring back pressure valve plugged during the snubbing operation, and it was not possible to displace the gas using classic well control procedures.

[Figure 3 ILLUSTRATION OMITTED]

While attempts were made to clear the drillstring, mud was lubricated into the annulus through the kill line, and the influx was released through the choke line. Density of the mud in the hole was 11.7 ppg, and density of the mud lubricated into the hole was 12.8 ppg. The specific gravity of the gas was 0.6.

Gas density in psi/ft is:

[[Rho].sub.f] = [S.sub.g]P/53.3zT

=0.6(1,420)/53.3(0.82)(540) =0.035 psi/ft

The length of the gas column:

[P.sub.b] = [[Rho].sub.f]h + [[Rho].sub.m](D - h) + [p.sub.a]

8,442 = 0.035h + 0.052(11.7) (13,913-h) + 1,420

h = 2,520 ft

Therefore, the gas bubble volume is:

[V.sub.gs] = (2,520)(0.0264) = 66.5 bbl [approximately equals] 67 bbl

To inject mud without exceeding the fracture gradient, the maximum permissible pressure increase at the casing shoe must be determined. The maximum permissible pressure increase is the difference between the pressure at the shoe prior to pumping the kill mud and the pressure required to fracture the formation at the casing shoe.

Pressure required to fracture the formation at the 7-in. casing shoe (Fig. 3) is:

[P.sub.frac] = 0.052(13.5)(12,097) = 8,492 psi

Total hydrostatic pressure at the shoe:

[P.sub.shoe] = [[Rho].sub.f]h + [P.sub.a] + [[Rho].sub.m] ([D.sub.shoe]- h)

= 0.035(2,520) + 1,420 + 0.609(12,097 - 2,520)

= 7,340 psi

Therefore, the maximum permissible increase in surface pressure and hydrostatic is:

[Delta][P.sub.t] = [P.sub.frac] - [P.sub.shoe]

= 8,492 - 7,340

= 1,152 psi

The volume of kill mud, V[[Rho].sub.1], with density [[Rho].sub.1] that can be lubricated into the hole without exceeding the fracture gradient at the 7-in. casing shoe is:

[MATHEMATICAL EXPRESSION NOT REPRODUCIBLE IN ASCII]

Substituting into the above equation:

[MATHEMATICAL EXPRESSION NOT REPRODUCIBLE IN ASCII]

Therefore, from these calculations, 20 bbl of 12.8-ppg kill mud with a density of 12.8 ppg could be pumped into the annulus without fracturing the formation at the 7-in. casing shoe, Fig. 4.

[Figure 4 ILLUSTRATION OMITTED]

Since the gas would be compressed by 20 bbl, the pressure in the gas bubble would be increased according to the ideal gas law:

[P.sub.new] = [P.sub.old] [V.sub.old] / [V.sub.new]

= (1,420) 66.5 / (66.5 - 20)

= 2,030 psi

After the kill mud is pumped, the well must be shut in to permit gas to migrate to surface. Surface pressure will stabilize at 2,030 psi when the gas reaches the surface. With the gas at the surface, the annular pressure can be reduced by an amount equivalent to the incremental hydrostatic of the kill mud. The gas is removed by bleeding it through the choke line until the desired pressure is reached, Fig. 5. In this instance, the incremental hydrostatic is given by:

[Delta]Hyd = 0.052[[Rho].sub.1] V[[Rho].sub.1] / [C.sub.dpca]

= 0.052(12.8) (20 / 0.0264)

= 504 psi

[Figure 5 ILLUSTRATION OMITTED]

Therefore, as shown in Fig. 6, shut-in surface pressure could be reduced to:

[P.sub.anew] = [P.sub.a] - [Delta]Hyd

= 1,420 psi - 504 psi

= 915 psi

[Figure 6 ILLUSTRATION OMITTED]

The procedure would be repeated until all of the influx had been removed from the hole. It is absolutely imperative that only dry gas be bled from the hole. The most common mistake in this procedure is to bleed mud along with the gas. If the gas is not dry when the bleed operation commences, the well must be shut in for an additional period to allow complete separation.

At Santa Fe's Bilbrey well, calculations indicated that the influx could be safely removed in four stages. As determined in this example, the first stage was 20 bbl. Calculations for the second stage required that 19 bbl of kill mud be pumped. Calculations for the third and fourth stages indicated that 16 bbl and 10 bbl should be pumped, respectively.

The procedures were followed as dictated by the calculations. The observed conditions matched exactly those predicted by the calculations.

While the influx was being removed from the wellbore, a second snubbing unit was rigged up and the back pressure valve was retrieved. After the drill-string was cleared, the hole was circulated using classic well control procedures. Small quantities of gas that had been entrained in the annulus were circulated to surface. After the well was circulated, the drill-string was removed, the bit was changed and the drilling operations continued without difficulty.

CONCLUSION

As mud is lubricated into the wellbore, gas can be bled and the surface pressure reduced. The shut-in period between the mud pumping and the gas bleeding must be sufficient to allow complete migration and separation of gas and mud. Under no circumstances should mud be vented with gas. In the event that mud and gas are bled, the well must be shut in for an additional period to permit complete migration and separations.

NOMENCLATURE

[C.sub.dpca] = Capacity of drill pipe - casing annulus, bbl/ft

D = Depth to productive interval, ft

[D.sub.shoe] = Depth to shoe, ft

h = Height of influx, ft

[Delta]Hyd = Effective hydrostatic of increment of kill mud, psi

P = Gas pressure, psi

[P.sub.a] = Annular pressure, psi

[P.sub.new] = Annulus pressure after lubricating mud and bleeding gas

[P.sub.b] = Bottomhole pressure, psi

[P.sub.ffrac] = Pressure required to fracture at shoe, psi

[P.sub.new] = Annulus pressure after pumping kill mud, psi

[P.sub.shoe] = Effective pressure at shoe, psi

[Delta][P.sub.t] = Maximum increase in pressure, psi

[S.sub.g] = Specific gravity of gas

T = Absolute temperature, [degrees] R

[V.sub.gs] = Volume of gas influx, bbl

[V.sub.p1] = Volume of kill mud to be lubricated, bbl

z = Compressibility factor

[[Rho].sub.1] = Density of kill mud, ppg

[[Rho].sub.m1] = Density of kill mud, psi/ft

[Rho]m = Density of original mud, psi/ft

ACKNOWLEDGMENT

The authors thank the management of Santa Fe Snyder Corp. for permission to publish this article. This article was adapted from paper IAOC/SPE 35122, "Mud Lubrication--Available Alternatives in Well Control" presented at the 1996 IAOC/SPE Drilling Conference, New Orleans, Louisiana, March 12-15, 1996.

LITERATURE CITED

[1] Grace, Robert D.,Advanced Blowout and Well Control, Gulf Publishing Co., Houston, 1994.

Robert D. (Bob) Grace, president of GSM Enterprises, Inc. has more than 30 years of on-site experience as a consultant in blowouts, fires, well control and deep drilling and completing operations. He has authored numerous papers on blowouts, well control and drilling practices, and has conducted seminars worldwide in well control and drilling practices since 1968. He holds BS and MS degrees in petroleum engineering from the University of Oklahoma and is a registered professional engineer. In addition, he served as head of the Petroleum Engineering Department at Montana College of Mineral Science and Technology.

Mike Burton, drilling manager for Santa Fe Snyder Corp. in Midland, Texas, began his 25-year career as a roust about for Amoco Production Co. in the Edgewood, Texas, gas processing plant. Field supervisory experience followed with El Paso Natural Gas Co. in San Juan basin, and continued with Santa Fe Energy Resources, Inc. in several southwestern states and offshore Tunisia. Prior to his current assignment, he worked as division manager of operations for Santa Fe Energy's central division, which included the Rocky Mountain, Mid-Continent and Permian basin areas from 1991 to 1998. He holds a BS in petroleum engineering from the University of Texas at Austin.

Bob Cudd, president of Bobby Joe Cudd Co., founded and built Cudd Pressure Control into an international oil well servicing company. He is a pioneer and innovator of numerous well control operations, such as snubbing, jet cutting, fire fighting, freezing and hot tapping. He worked on his first blowout 40 years ago, and in the AI-Awda project--the oil fires of Kuwait--he personally led his teems, on a dally basis, to conquer more oil well fires than any other team that arrived at the same time. He has contributed to the industry standard, Advanced Blowout and Well Control, and has co-authored numerous technical papers.

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