REMEDIAL SQUEEZE SYSTEMS-2

Properly conducted squeeze procedures eliminate downhole troubles

Ronald E. Sweatman, Calvin W. Kessler
Halliburton Energy Services
Houston
John M. Hillier
HoustonSonat Exploration Co.
Houston

When proper field squeeze procedures are followed, downhole problems, including lost circulation and underground blowouts, can be effectively eliminated.

It is necessary to acquire quality information and establish efficient communications between field personnel.

Once engineers have enough data to identify the problem and define the objectives for a lost-circulation material (LCM) squeeze system treatment, they should obtain well bore fluid samples and test against the candidate LCM squeeze system slurry. A chemical analysis is needed if samples are not available.

After satisfactory laboratory test results are obtained with the field-laboratory test procedure, job procedures for the LCM squeeze system treatment can be prepared and presented to the operator for review and approval.

Dual-injection LCM squeeze system

The procedure for stopping mud losses normally consists of a dual-injection LCM squeeze system. This requires two pumps: one to pump the LCM squeeze system slurry down the drill pipe and the other to pump the activator fluid (mud) down the drill pipe/casing annulus.

In an underground blowout, the placement procedure is different because the activator fluid is either the formation fluid or a mixture of mud pumped down the annulus with the formation fluid flowing into the weak zone. Variations of the placement procedure are also required when the well is on vacuum and a minimal mud column is needed to overbalance a high-pressure zone.

The end of the drill pipe is typically placed above the weak zone, inside the casing. To prevent the drill pipe from sticking, operators should be certain that no part of the drill pipe is placed across a zone that may break down under the planned downhole pressures.

The end of the drill pipe should also be placed to allow most of the LCM squeeze system slurry to clear the drill pipe before the slurry reaches the weak zone. This practice helps prevent any excess LCM squeeze system from settling in the drill pipe after the maximum squeeze pressure is obtained.

The severity of the mud losses or the degree of uncontrolled formation fluid flow rate determines the volume of LCM squeeze system needed. The spacer volume located ahead of the LCM squeeze system is based on the mud type, pump rate, and especially for oil-based mud, a mud-film removal test with a field-laboratory rotational viscometer.

Water-based muds may only require 100-200 linear ft of spacer spotted ahead of the treatment, compared to some sticky oil-based muds that may need 1,000-2,000 linear ft of spacer. The type of spacer may be a simple, single-recipe fluid or a complex recipe consisting of multiple fluids, depending on the type of mud and the pump rate.

The spacer volume behind the LCM squeeze system may be minimized to prevent displacement fluid fingering. The LCM squeeze system should be surface-tested with a field laboratory test before it is pumped. This will ensure that the optimum fracture-plugging consistency (FPC) is formed within the desired period.

Table 1 [36,302 bytes] shows an example for spotting an oil-based, LCM squeeze system slurry inside and near the bottom of the drill pipe based on the dual-injection placement technique. A typical downhole application is shown in Fig. 1 [71,487 bytes]. The job procedure should include the following rig-site test procedure as a quality-control test.

Rig-site procedure

Field-laboratory mixtures of the new LCM squeeze system slurries and activator fluid are tested for FPC time in order to design LCM squeeze system formulations. This test also determines the required FPC time needed to qualify the LCM squeeze system slurry before it is pumped into the well.

FPC time starts when an LCM squeeze system/activator-fluid slurry is mixed and ends when the FPC is observed. A sample of the LCM squeeze system slurry from the mixing tank is mixed with the designed ratio of activator fluid, then the time to reach a rubbery mass is recorded. To determine a dual-injection pump-rate range, personnel start testing with a 1:1 mix of LCM squeeze system and activator.

Depending on the planned placement procedure, personnel will test various ratios of LCM squeeze system and activator-fluid mixtures to establish a range of FPC times. The sample volumes of LCM squeeze system and activator fluid can be as small as a typical coffee cup or as great as one-half gallon for each substance.

The LCM squeeze system and activator are stirred together by hand with a metal spoon or other stirring instrument. If possible, the rig crew should be present during testing to observe the plugging effect. They should be cautioned against pumping the LCM squeeze system in the drill pipe, hole, or pipe annulus.

The LCM squeeze system yield and activator mixture determines the appearance of the FPC and texture of the reacted mass including the degree of cohesive, adhesive, and elastic properties. To seal the weak zone effectively, the texture of the FPC should be stiff and flexible.

Squeeze-pressure schedule design

Applied pressure is required to force the FPC of the new LCM squeeze systems into the lost-circulation or influx flowing zone. This pressure must be great enough to overbalance all the forces resisting the FPC flow, including the formation pore pressure, friction pressure, extrusion pressure, and the pressure from bridging.

A positive pressure differential (DP) is used to overcome all FPC flow-resisting forces. When most of the LCM squeeze system has entered the formation, operators must carefully apply this positive DP. Sufficient LCM squeeze system volume is needed to fill the spaces in the formations opened by the positive pressures.

The LCM squeeze system plugging-treatment pump operator and all relevant job site personnel should have a copy of the schedule for the varying maximum pump pressures that may be applied while the slurry is placed in the well (Table 2 [13,919 bytes]). Obviously, most jobs require operators to pump various fluids with differing densities including the LCM squeeze system slurry, mud, and spacer with different densities into the pipe.

As the column height for each fluid changes throughout the job, the hydrostatic head will also vary accordingly. To determine the hydrostatic-head pressure change, operators must calculate the hydrostatic head for each barrel of displacement fluid pumped and enter the results in the respective schedule column.

An easy way to calculate the change is to express it as psi/bbl differential in the hydrostatic head of one fluid-density compared to a different fluid. For example, pumping 40 psi/bbl of displacement may be the hydrostatic head of 1 bbl of plug slurry inside the drill pipe, subtracted from the hydrostatic head of 1 bbl of displacement mud inside the drill pipe.

As each barrel of lighter-weight mud is pumped into the top of the drill pipe, a bbl of the heavier LCM squeeze system slurry enters the formation, allowing the pump pressure to increase 40 psi for each bbl of mud.

Certain pumping and well conditions may not require this schedule, including wells on vacuum, and wells in which the back side of the hole is partially full. Many jobs require that the actual bottom-hole squeeze pressure never exceed the maximum bottom-hole pressure.

Wells with combination drill pipe strings and various well bore sizes below the drill pipe require more complex calculations for the squeeze-pressure schedule. Existing computer software designed for low-pressure cement squeeze procedures can perform these calculations.

Pump rates should also be listed in a column on the squeeze pressure schedule to indicate the following:

The changing pump rates resulting from circulating and spotting the LCM squeeze system near the end of the drill pipe
The matching drill pipe and casing-annulus pump rates produced from dual injection
The drill pipe pump rate when the LCM squeeze system cannot be spotted in a well on vacuum
The long-distance LCM squeeze system travel rates where there are hundreds of feet between the end of the drill pipe and the weak zone.

Rig practices

Rig personnel should be involved early in the design process to advise on the best practices for the rig. It is important to determine how to dispose of the excess LCM squeeze system slurry left over in the batch mixer, lines, and drill pipe after the maximum squeeze and slow bleed-off pressures are obtained.

It is also important to use mud buckets to drain off the mud when pulling any excess LCM squeeze system slurry remaining in the bottom of the drill pipe. This practice keeps the rig floor clean.

Finally, it is important to get an agreement from the operator's representative and rig toolpusher to remove possible excess LCM squeeze system from the drill pipe by using one of the following four methods:

Place the bottom of the drill pipe far enough above the weak zone to clear the LCM squeeze system out of the drill pipe before the system enters the weak zone. If conditions do not allow this method to be used, operators can choose from one of the three remaining procedures.
Reverse the slurry out to a pit or disposal container. If the pressure increases, shut the well down when it equals the maximum squeeze pressure and pull all the drill pipe out of the hole. If the backside starts to swab, use this procedure.
Immediately pull enough drill pipe out of the hole to allow any excess LCM squeeze system slurry to fall into the hole or perform a second squeeze with drill pipe above the thief zone. If the excess slurry U-Tubes and forms an FPC in the drill pipe/hole or pipe annulus, the fluid in the annulus may start swabbing as the drill pipe is pulled out of the hole. To remedy this swabbing, close the hydril and pump one stand of mud down the annulus. This will push the FPC out of the annulus while pulling the drill pipe out of the hole. While pulling the drill pipe, continuously monitor the annulus and stop pulling as soon as swabbing occurs. After the drill pipe is clear of LCM squeeze system, wash the excess LCM squeeze system while running the bottom hole assembly (BHA) before drilling ahead.
Determine if the excess volume of LCM squeeze system is small enough to pump into an induced fracture created from the application of higher squeeze pressures. If the LCM squeeze system volume is too small to fill the induced fractures, a second LCM squeeze system treatment may be required to seal the zone.

Sufficient reserve mud may also be needed to keep the hole full while the second LCM squeeze system is mixed. The company representative should decide on the increases in maximum squeeze pressure and understand the risk involved.

Test the hydril and make sure it can hold pressure equal to the maximum squeeze pressure. There should be no packer isolating the back side. Test the hydril again while rotating and reciprocating the drill pipe.

Rotate or reciprocate drill pipe while pumping the LCM squeeze system, especially when the drill pipe is inside open hole. Drillstring rotation and reciprocation will help prevent the pipe from sticking if the LCM squeeze system flows into the annulus and forms an FPC.

If the pump rate is accurate to 1/2 bbl/min, operators can pump down the annulus. Service pumps are preferred because pump rates are more accurate. Thus, pressure and rate recordings can be made and fewer communication problems will occur.

The rig toolpusher, company representative, rig crew, and service company crew should be trained and briefed before the job. All parties should agree upon fully understood communications and contingency plans.

Field test results

Between March and November 1996, over 15 field tests of the new LCM squeeze systems were performed. The following details two field tests. Other test data are summarized in Table 3 [22,858 bytes] and Table 4 [20,840 bytes].

Field Test 1

On May 7, 1996, a well in Webb County, Texas, was treated with a new LCM squeeze system for a single squeeze job. The operation effectively sealed numerous points along a 1,200-ft open hole section across the Queen City formation (Table 5 [15,428 bytes] and Table 6 [24,940 bytes]).

The final squeeze pressure achieved a drill-ahead equivalent mud weight (EMW) of 10.0 ppg, and all mud losses were stopped. This EMW is compared to the 8.8 ppg mud losses at 60 bbl/hr before the job began. Unfortunately, the bottom 200 ft of drill pipe became temporarily stuck because the numerous diverted LCM squeeze system sealed weak points between 2,800 and 4,000 ft.

The LCM squeeze system moved into the drill pipe/hole annulus and stuck the drill pipe because an unknown weak zone broke down above the drill pipe end at 3,000 ft. This condition resulted in even longer distances between the end of the drill pipe and the predicted top of the weak zone used for subsequent field tests.

Instead of the 400-ft distance used for this squeeze job, the drill pipe was positioned 2,000 ft from the top of the weak zone while the drill pipe was in open hole. The 2,000-ft distance can be applied to open or cased-hole sections when operators want to clear excess LCM squeeze system out of the drill pipe after the final squeeze.

Future field tests may extend this distance even more when the desired squeeze pressure EMW is close to the formation mud weight (FMW) just below the shoe of the last string and when the bottom of the open hole's weak zone is several thousand feet deeper.

This treatment was judged an overall success because it allowed drilling to continue from 4,880 to 6,122 ft. The next string was set without any further mud losses. Conventional LCMs and cement plugs failed to seal the Queen City weak zone and allowed mud losses to continue. About $150,000 was spent before the LCM squeeze system job.

Field Test 2

On May 17, 1996, in a deeper-hole section of the same well, 11.0-ppg mud losses at 20 bbl/hr continued after the application of large LCM pill volumes failed to seal a weak zone. This led to the second use of the treatment, which successfully achieved a 13.5 ppg drill-ahead EMW (Table 7 [12,032 bytes] and Table 8 [36,252 bytes]).

The treatment was inadvertently pumped down the drill pipe after some of the excess LCM squeeze system U-tubed out the drill pipe while pulling the string. As a result, all 8 bbl of excess LCM squeeze system was placed in the annulus, forming a temporary pressure seal. The formation seal then failed when pump pressure was applied in an attempt to establish circulation.

This field test was the only one that did not provide economic value for the well operator. A best practices document has been written to instruct personnel how to avoid the recurrence of the problem.

When planning future jobs, operators will pump the excess LCM squeeze system out of the drill pipe during the squeeze job by either increasing the planned maximum pressure or pulling the drill pipe. This will clear the LCM squeeze system out before reaching the zone, or if swabbing occurs, by following Messenger's traditional procedure of pulling the drill pipe out of the hole and pumping down the annulus if swabbing occurs.¹

Table 3 [22,858 bytes] shows that the field tests covered a wide range of well conditions. Most of the new LCM squeeze system treatments followed unsuccessful conventional LCM pill treatments and old LCM squeeze systems that did not have a self-diverting function or the capability to:

Form an FPC
Substantially increase the FMW of a weak zone
Overcome the diluting effect of crossflows.

Field-test results demonstrate that casing design and mud program economics can be improved if the high EMW squeeze pressure continues in future field tests. Thus, contingency pipe strings and associated oversized pipe diameters may be deleted from casing programs.

Later, even traditionally planned intermediate liners and drilling liners may be eliminated. If high-pressure, nonpay zones can be sealed allowing lower mud weights, and weak zones sealed allowing higher circulation rates, lower-weight drilling muds may be safely used to increase penetration rates, clean the hole, and improve primary cementing.

Acknowledgments

The authors thank the management of Sonat Exploration and Halliburton Energy Services for their support and permission to publish this article. Special thanks go to Paul Scott and Randy Ray for the use of their laboratory at M-I Drilling Fluids.