SHEAR RAM USE AFFECTED BY ACCUMULATOR SIZE

Brian E. Varcoe
Gulf Canada Resources Ltd.
Calgary

On many onshore drilling operations, once the annular blowout preventer (BOP) is closed, there may be insufficient remaining accumulator pressure to shear the drill pipe immediately.

Initial function tests of several onshore accumulator systems identified significant differences between actual and calculated remaining system pressure.

The remaining system pressure becomes important because various drill pipe sizes, weights, and grades require different shearing pressures. The temperature and pressure drops associated with nitrogen expansion (accumulator gas) after BOP functioning dramatically impact remaining system pressure.

Subsequent to the last "Lodgepole blowout" in October 1982 and the issuance in July 1987 of the Alberta Recommended Practices (ARPS) for Drilling Critical Sour Wells, the Energy Resources and Conservation Board (ERCB) has required shear rams for many critical sour wells.'

A critical sour well, according to ERCB, is a classification based on H2S release rate potential and well proximity to populated centers.

As a result of this regulatory requirement, Gulf Canada Resources Ltd. conducted a study of accumulator systems because little onshore operational data on shear ram deployment were available.

Most of the operational knowledge resides within the offshore drilling industry where accumulator systems are typically four to five times larger in volumetric capacity than those for onshore units. Therefore, remaining pressure or fluid volume after BOP functioning is not a concern with offshore systems.

SHEARING METHODOLOGY

In 1977, shear rams became a requirement for any offshore rig under the jurisdiction of the Alaskan Oil & Gas Conservation Commission. Shear/blind rams were initially designed primarily to facilitate emergency wellhead disconnects for floating drilling vessels.

The drill pipe is hung off in the BOP and sheared as follows:

Position the tool joint above the lower pipe ram.
Close the lower ram.
Close the top ram, possibly applying tension to the pipe.
Close the shear/blind ram.

Some operators may have minor variations of this procedure, but the principle is essentially the same.

Onshore, shear ram placement in the BOP is intended to minimize the risk of an uncontrolled H2S release. However, to date shear/blind rams have yet to be deployed for purposes of well control in Alberta.

One proposed shearing procedure recommends not hanging off the drill pipe .2 Rather, the pipe should be sheared under full string tension as follows:

Position the tool joint above the lower pipe ram.
Close the shear/blind ram.

As a result, the following concerns have been raised:

Is there sufficient vertical clearance between the lower pipe ram and shear ram after the drill pipe is hung off to ensure the shear blades are adjacent to the pipe body rather than to the tool joint?
Is there a reduction in hang-off load capacity for sour service ram blocks?
Is there sufficient remaining accumulator pressure to complete a shear after performing any one or number of BOP functions?
What effect does tension have on required shear pressure?
What are the consequences on the surface if drill pipe is sheared while subject to a large tensile load?
What are the downhole consequences after the drill pipe is sheared? Could it damage the casing while dropping downhole?

For sufficient vertical clearance, a spacer spool should be placed between the lower pipe and shear rams. This suggests that only BOP stack alternatives No. 1 or No. 3, per ERCB Interim Directive 87-2, are suitable for hang off and subsequent shearing operations (Fig. 1). Both configurations facilitate shearing the drill pipe body without letting the string drop downhole.

Because drill pipe tool joints typically have an 18 tapered shoulder and are harder than sour service ram blocks, the blocks can be deformed during hang off operations. Consequently, this may create a leak path upon retraction of the blocks into the ram body.

The hang off load capacities of standard sour service pipe ram blocks have subsequently been reduced by some manufacturers (Table 1).

ACCUMULATOR DESIGN

The American Petroleum Institute (API) has outlined the minimum requirements for accumulator system sizing.' With the hydraulic pump off, the accumulator system must have sufficient usable volume to open the hydraulically controlled remote (HCR) valve, close the annular BOP, and close one pipe ram.

The remaining pressure shall be 200 psi greater than precharge pressure .3 Additional requirements on preventer closing time generally have minimal impact on sizing.

Alberta's Petroleum Industry Training Service (PITS) recommends that the usable fluid volume must be sufficient to sequentially close three BOP components, one of which must be the annular preventer, with the pump off. A minimum system pressure of 1,200 psi and 50% of the original fluid volume should remain in reserve after functioning .4 The ERCB has similar requirements.

Shaffer recommends having sufficient remaining fluid volume to close the annular preventer and three pipe rams with the pump off. The minimum remaining pressure should be 1,200 psi. A safety factor of three ensures that 50% reserve volume remains.

Valvcon uses a methodology similar to Shaffer's except it includes the close and open volumes. A safety factor of two establishes recommended minimum total accumulator capacity.

Table 2 illustrates the variation in recommended minimum accumulator size based on design methodology assuming a 135/8 in. x 5,000 psi BOP configuration. Boyle's gas law equation, neglecting temperature effects, was used to determine usable fluid volume.

ACCUMULATOR FIELD TESTS

The objective of the accumulator field tests was to verify whether existing accumulator units could meet ARP 1.1.6.3 which requires sufficient available volume to open the HCR, close the annular BOP, and close-open-close one pipe ram with the pump off. Minimum remaining system pressure must be 1,200 psi at the end of this operating sequence.

Ten field tests on various onshore rigs were conducted. Observed pressure loss ranged 50-125% greater than that calculated with Boyle's gas law equation. The results were reviewed with various manufacturers without determining a suitable explanation for the discrepancies.

It was believed that the pressure loss may be a result of temperature drop associated with the increase in nitrogen volume within the bladder.

After each BOP function, the bladder expands. Thus, nitrogen gas volume increases with a resultant temperature and pressure reduction. Theoretical calculations with adiabatic equations indicated a significant temperature drop should occur.

LABORATORY TESTING

Equipment was selected to simulate a typical BOP system for critical sour wells: a 135/8 in. x 5,000 psi stack consisting of a Shaffer annular preventer, a type SL pipe ram with a 10-in. OD piston, and a 189-gal accumulator system.

Pressure and temperature gauges and transducers were installed on the first, middle, and last accumulator bottles. These locations were selected to determine if pressure and temperature were drawn down equally in all bottles after each BOP function.

Other gauges were installed at various locations to record line pressure loss and four-way control valve pressure loss. A 16-channel data acquisition unit and chart recorders documented information. A separate tank collected the fluid volume used for each function. All transducers and gauges were calibrated and precharge pressures on each bottle checked prior to the tests.

STABILIZED FUNCTION TEST

The stabilized function test recorded changes of pressure recovery and time elapsed during temperature stabilization. The system was charged to 3,000 psi, the hydraulic pump turned off, and the nitrogen gas temperature allowed to stabilize.

The system was considered stabilized after three consecutive temperature readings at 15-min intervals differed by less than 2 F. This procedure was repeated until pressure and temperature reached 3,000 psi and room temperature, respectively.

A BOP was closed, system temperature stabilized, and then the BOP was opened. After the temperature stopped changing, this sequence was repeated until only 1,200 psi remained. The 1,200-psi final pressure was selected based on minimum allowable system pressure requirements specified by Alberta regulatory agencies.

An average pressure drop of 1,102 psi and temperature drop of 43.2 F. was observed after the first closing of the annular BOP (Figs. 23).

As nitrogen gas in the bladders returned to ambient temperature, primarily because of the warmer surrounding hydraulic fluid, the pressure increased. After 11/2 min, system pressure recovered 150 psi. This is 58% of the fully stabilized system pressure recovery observed after 1 hr.

An average pressure drop of 392 psi and temperature drop of 12.3 F. was observed after closing the pipe ram once (Figs. 2-3). Initial ambient temperature for this test was considerably lower than for the annular BOP test (67.lo F. compared to 86.5 F.) but was not considered detrimental to test results.

After 11/2 min, the system pressure recovered 72 psi. This is 50% of the fully stabilize system pressure recovery observed after 30 min.

RAPID FUNCTION LEST

The rapid function test determined the additive effects of temperature and pressure change from rapid, repetitive equipment functioning. The system was charged to 3,000 psi, the hydraulic pump turned off, and the system allowed to stabilize.

The BOP was closed, opened, and closed with a 5-sec wait between each function until only 1,200 psi remained in the system.

This test confirmed the detrimental effect of rapid functioning of BOP equipment on usable remaining system pressure (Figs. 4-5). With a 5-sec wait between functions, very little pressure recovery occurred. Compared to stabilized testing, the annular BOP could only be cycled one and one-half times, not two times, and the pipe ram only six and one-half times, not nine times.

This reduction in operating cycles implies that the industry safety factor of 1.5 used for accumulator design is not applicable for rapid, repetitive equipment functioning.

The temperature/time lag illustrated in Figs. 3 and 5 is a result of slow sensor recording response.

ARP FUNCTION TEST

The ARP function test was conducted in accordance with ARP 1.1.6.3 requirements, except an HCR valve was not available for functioning. The system was recharged and allowed to stabilize similar to the manner of the previous tests.

The annular preventer was closed, and then the pipe ram was closed, opened, and closed with a 5-sec wait between each function. This sequence was repeated with the pump on to quantify its contribution.

Even with the large accumulator system, final system pressure was near the minimum requirements of ARP 1.1.6.3. The remaining system pressure safety factor was 1.2. With the hydraulic pump (rated at 9 gpm) left on, pressure recovery was only 150-218 psi.

SHEARING CAPABILITIES

From these test results, remaining system pressure after each BOP function was determined. These pressures were compared to pressures specified by Shaffer to determine shearable drill pipe sizes, weights, and grades (Table 3).

Shear pressure equal to 15% above the mean value was used as recommended by Shaffer.

A 135/8 in. x 5,000 psi Shaffer BOP stack with a 189-gal accumulator system was assumed to estimate remaining system pressure. The shear/blind ram was equipped with a 14-in. diameter piston.

Tension effects are not considered in the following cases, which assume an uncontrolled flow has been experienced and rig power has been lost.

For the first case, the annular preventer was closed, and remaining system pressure was 1,814 psi. Next the shear ram was closed, and remaining pressure was estimated at 1,509 psi. With no safety factor applied, only 31/2 in., 13.3 lb/ft and 15.5 lb/ft Grade E drill pipe could be sheared.

For the second case, the pipe ram was closed with a remaining system pressure of 2,604 psi. After closing the shear ram, remaining pressure was estimated at 2,051 psi, 542 psi greater than that in the first case. In addition to shearing the same pipe as in the first case, 41/2 i n., 1 6.6 1 b/ft and 20.0 lb/ft as well as 5 in., 19.5 lb/ft Grade E drill pipe could be successfully sheared.

For the third case, the shear ram was closed with an estimated remaining system pressure of 2,305 psi, an increase of 796 psi over the first case. In addition to shearing the drill pipe listed in the above cases, 31/2 i n., 1 3.3 lb/ft and 15.5 lb/ft and 41/2 in., 16.6 lb/ft Grade G drill pipe could be successfully sheared.

SHEARING UNDER TENSION

A shear test procedure under applied tensile load was developed to quantify the effect of tension on required shear pressure. Initially, 5 in. OD, 19.5 lb/ft Grade G drill pipe was tested at various tensile loads.

The drill pipe came from the same lot and met all API dimensional and mechanical requirements.

Even with an applied tensile load of 180,000 lb, only a 228-psi reduction in shear pressure was observed. This is within the pressure variance observed in previous shear tests conducted with no applied tension.

Because Grade G drill pipe is typically much tougher than Grade E drill pipe, a sample of Grade E was similarly tested. At 107,000 lb of tension, only a 275-psi pressure reduction was recorded.

Only two tests were conducted; however, the pressure reduction is still within the variance noted on previous tests.

Consequently, the pressure reduction is not considered sufficient to warrant the potential risks associated with shearing under high tensile loads.

If the drill pipe has to be sheared under full string tension, the operator needs to consider the consequences at the surface, including the possibility of igniting the well during shear operations. Furthermore, the operator must always keep in mind the downhole consequences.

An operator should keep in mind some of the following while sizing BOP systems:

There is insufficient remaining system pressure available on most accumulator systems to shear many sizes, weights, and grades of drill pipe if the annular is closed first with the pump shut off. If possible, the annular BOP should not be closed immediately before attempting to shear the drill pipe.
Shear/blind rams should be equipped with 10-in. pistons.
The minimum recommended accumulator size to satisfy ARP 1.1.6.3 requirements is 165 gal for most 135/8-in. and 11-in. BOP stacks.
To ensure availability of sufficient volume and pressure to shear 5-in. OD drill pipe, an operator should consider using a sequencing valve mechanism.
The temperature and pressure drop associated with nitrogen expansion after BOP functioning, dramatically impacts remaining system pressure.
Required shear pressure is not greatly reduced by drillstring tension.
Required shear pressure varies significantly dependant upon drill pipe dimensional and mechanical properties.

ACKNOWLEDGMENT

The author thanks Shaffer and Gulf Canada Resources Ltd. for permission to publish this article, and Roland Harper of Shaffer and Bryan Hnatiuk of Gulf for assistance in its preparation.

REFERENCES

Energy Resources Conservation Board, Interim Directive 87-2.
Heenan, R.H., "The use of shear blind rams on critical sour gas wells," paper No. 87-4 presented at the CADE/CAODC spring drilling conference, Calgary, April 1987.
API RP 53, second edition, Section 5-A, May 1984.
Alberta's Petroleum industry Training Service, Guide G-36.