Gel controls fluid loss in gravel-packed completions

June 3, 2002
A carbonate-laden gel pill, placed inside a sand-control screen and optimized for particle size distribution of the bridging particles for specific sand-control screens, minimizes fluid loss and potential damage to a gravel pack and formation.

A carbonate-laden gel pill, placed inside a sand-control screen and optimized for particle size distribution of the bridging particles for specific sand-control screens, minimizes fluid loss and potential damage to a gravel pack and formation.

Additives to the pill enhance filter cake lift-off and temperature stability, allowing one to apply the pill in relatively small volumes, thus minimizing the need for remedial treatments.

The carbonate-laden gel pill (SEAL-N-PEEL) is placed below the packer to seal off the area defined by the inner wrap or mesh of a sand-control screen. Carbonate loading, particle size distribution, pill size, and density are important factors for designing the application.

Field experience shows the diversity of the pills and their ability to produce near zero skin without the need for costly and risky remedial treatments.

Fluid-loss control

Literature has documented the negative ramifications associated with inadequate fluid-loss control in gravel packed or frac-packed completion.1-3 Completion fluid losses to the formation can negatively impact well productivity, particularly if the completion fluid is a high-density brine.

After the pack has been pumped, the next step in the job reverses out excess proppant or gravel from the workstring and pulls the washpipe from the screen. This exposes the completion to wellbore fluids, raising the possibility of substantial fluid loss to the formation. Most gravel or frac-packed completions incorporate methods to control these losses, either mechanical devices or chemical (pumpable) means, such as fluid-loss control pills.

Controlling fluid losses before and after pack placement is critical to the success of the operation and, in many cases, in optimizing well productivity.

Several methods can control fluid loss, but as Ross pointed out, until recently little investigation has been undertaken to determine the best pumpable method for specific applications.3

Generally, the preferred method uses a mechanical device such as a spring-loaded flapper valve mounted inside a sub. During pumping operations, a washpipe extends through the flapper-valve sub to hold the valve open.

The flapper closes after one removes the service tool and washpipe from the packer upon completion of the frac or gravel pack. This prevents fluid losses by isolating the formation from the wellbore above the valve.

To allow production, one can break the flapper by extending production tubing, using wireline or coiled tubing, or increasing pressure on the tubing.

Another option to prevent fluid loss is a sliding-sleeve mechanism that usually is installed on an isolation pipe in the completion assembly. Ports in the sleeve allow communication with the reservoir. One can shift the internal sleeve with wireline, coiled tubing, or a washpipe that extends through the gravel-pack assembly.

After the completion of the pack, one pulls the assembly through the isolation pipe, closing the ports. Failures usually result from damaged internal o-rings or debris preventing the sleeve from closing completely.

Companies almost always employ postperforation fluid-loss control pills when the fluid-loss rate is too high to allow running pipe and the completion assemblies. In these cases, a mechanical device is not yet in the hole.

The fluid-loss pills typically consist of a viscosified completion brine that may or may not contain acid or water-soluble bridging solids, starch, or crosslinking agents.

Although most companies prefer mechanical devices for preventing fluid loss after a gravel pack, these devices sometimes fail or leak when the service tools are pulled from the production packer. In other cases, one cannot use the tools because of their size or other restrictions.

In such instances, jobs can include chemical fluid-loss control pills, similar in composition to postperforation pills. This option, unfortunately, often requires remedial treatments that add cost and cause problems, such as formation damage.

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An informal survey (Table 1) of nine operators, majors and independents, in the Gulf of Mexico during 2001 indicates that about 95% of the completions included a mechanical device with 21% requiring a fluid-loss pill after the device either failed to seal or leaked to a degree above the operator's tolerance.

Conventional pills

Fluid-loss control pills employed in post gravel or frac packs can be categorized as those containing solids and those that are solids-free. Sized salt and sized-carbonate are common solids in pills. But these have several limitations.

In some cases, an "all-in-one-sack" approach determines the size distribution of the salt particles.

This non-customized approach to particle-size distribution prevents the typical sized-salt pill from being optimized for a wide range of premium and wire-wrapped screens. Also salt pills require a comparatively high solids loading because salt solubility increases with the amount of free water in the system and with temperature. Furthermore, temperature and pressure affect salt particle size.

One, therefore, cannot accurately control the size distribution of these salt bridging particles. This inability increases the potential of particle invasion into the interior of the screen matrix and gravel pack.

Controlling excessive leak-off may require large pills that can dehydrate in the screen. This dehydration may produce a solid plug that can be difficult to remove completely, even with the best remedial treatment.

Except for issues relating to solubility in the brine, the typical sized-carbonate pill suffers some of the same limitations as salt pills. Many of these limitations are the direct result of formulations not being optimized to match the specific downhole hardware and conditions.

Carbonate pills usually contain 75-120 lbm/bbl of solids. As with salt pills, high solids loading, large pill volumes, and less-than-ideal leak-off can plug the screen and sometimes the packer assembly and blank pipe. The removal of these plugs often requires mechanical intervention.

Solids-free, crosslinked polymer pills can be effective for preventing fluid invasion into the screen, gravel pack, and formation matrix. Although solids plugging is not a problem with these crosslinked pills, they have a relatively large volume and require remedial treatments for removal. In many cases, producing-interval permeability, bottomhole temperature (BHT), or completion brine density prevent these pills from either being employed or being effective.

After fluid-loss control is not required, one can remove the conventional pills with a chemical breaker such as acid, oxidizer, or enzyme. The breaker, which is either bullheaded or spotted with coiled tubing, dissolves bridging particles or polymers in the pill. In many cases, an external breaker is not effective for removing a pill from inside the screen. In every case, such treatments are an additional cost.

The breaker can be corrosive to the screens, other downhole tools, and the production tubing. And as the breaker leaks-off into the formation, it can carry undissolved fines particles that plug and damage the formation or produce other undesirable reactions within the formation matrix.

Calcium carbonate pill

The developmental program for designing the calcium carbonate-laden gel pill included laboratory screening of many different formulations, followed by performance verification in a purpose-built, large-scale screen flow model.

The use of calcium carbonate as the bridging solid ensures quality control of the particle size distribution both at the surface and under bottomhole conditions. Conventional biopolymers and starch are the primary viscosifying and bonding agents, and nonconventional additives act as stabilizers and lift-off agents to ensure performance objectives.

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Another objective of the program was to formulate a series of customized blends, specific to given sand-control screens (Fig. 1). Each pill should seal the inner drainage screen with a thin, stable filter cake without excessive matrix plugging and lift-off or flow back once the well is placed on production. The lab oratory screening uses screen cutouts prepared from actual screen materials.

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The flow-model incorporated a 3-ft by 4 1/2-in. screen inside a 5-ft by 9 5/8-in. casing, large volume holding vessels, pressure and rate controlled pumps, pressure gauges, transducers, and temperature controllers. This model allowed optimized laboratory formulations to be tested under simulated field conditions.4

Key lessons learned from the developmental studies and early field experience include the following:

  • The pill needs screen-specific particle sizing of the carbonate to form an immediate, low-permeability filter cake with minimal matrix invasion.
  • A successful application with reduced matrix plugging requires spurt-loss control through the screen. Table 2 shows gravel-pack sand pore throat diameters and Fig. 2 shows the particle size distribution of the spurt-loss filtrate through a 125-μm premium screen. Based on the one-seventh plugging rule,5 these data suggest that this filtrate would pass freely through pore diameters greater than 145-μm in size.
  • Carbonate loading can be adjusted according to the inner or drainage screen opening (Fig. 3).
  • Friction-reducing agents help prevent stringing out the pill and reduce adhesive forces that hold the pill onto the screen surface.
  • Pill rheology must be maintained under bottomhole conditions for the duration of its residence inside the screen.

Pill placement

One places the carbonate-laden gel below the packer to seal off the area defined by the inner wrap (or mesh) of a sand-control screen. Carbonate loading, particle size distribution, and pill size and density are important factors to the successful application.

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A fluid-loss test in the laboratory can determine the required loading. Especially at higher temperatures, carbonate loading can affect pill stability and the pill's ability to form an effective seal.

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Compared to conventional carbonate pills with an 80-120 lbm/bbl loading, the 25-40 lbm/bbl carbonate loading in the new formulation is low. This low loading ensures that only a portion of the screen would be occupied by solids under the worst scenario in which 100% of the carbonate settles out and descends to the bottom or low-side of the screen

For example, a 5-bbl pill with a 30 lbm/bbl carbonate loading in a 110 ft, 8-gauge, wire-wrapped screen with a 1.875 in. ID would fill about 42% of the screen with solids (Fig. 4a). This compares to an 80 lbm/bbl loading that could fill the screen and 12 ft of the blank pipe with solids (Fig. 4b).

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Table 3 compares various carbonate loading schedules with the resulting plugging or filling of the screen and blank pipe. This shows the need to consider tubing, completion, and pill volumes.

Solid distribution also depends on type of screen and the size of the slots or mesh openings. Pill size is a function of screen volume and relative difficulty of placement.

Pill density should exceed that of the working brine by at least 0.5-1.0 lbm/gal. This ensures that the pill will fall into the screen void when positive pump pressure is removed.

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One runs the pill with two viscous pads consisting of the same base without the carbonate. The typical size is a 3-5 bbl lead pad with a sufficient tail to clear out the pump and lines. Sometimes, the lead pad size may be increased to enhance the pill's effectiveness in case high fluid loss to a thief zone leaches the liquid portion of the pill, resulting in a dehydrated bridge of carbonate inside the screen.

Our experience shows that increasing lead pad size by two or three times mitigates this effect by reducing pill dilution and slowing the fluid-loss rate to the thief zones before the pill reaches the interval.

Early pill applications experienced commingling between the completion brine with the lead volume of the pill because the job spotted the pill too far above the packer, sometimes as much as 300-400 ft. In these instances, the initial pill reduced losses only marginally, requiring a second pill to reduce losses to acceptable levels.

The dilution effect reduces the rheological properties to the point of rendering the solids suspension-carrying capacity ineffective.

There are two recommended techniques for placing a carbonate-laden gel pill after unacceptable fluid loss appears following the setting of a sand-control screen. The technique depends on whether the allowed pump rates can exceed the fluid-loss rate without exceeding frac pressure.

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After completing the frac or gravel pack and pulling out the crossover ports from the packer, one should establish circulating rates with the formation exposed to the full hydrostatic pressure in the wellbore. One should spot the pill in the annulus as a balanced plug if returns can be taken from the annulus when the washpipe is pulled out of the gravel-pack packer (Fig. 5).

One should pump the pill, including lead and tail pads, at a rate exceeding the fluid-loss rate. When the pump is shut off, the pill will fall into the production screen and seal it off.

It is not possible to spot the pill as a balanced plug if there are no returns from the annulus with the washpipe pulled and fluid circulation through the crossover ports above the packer. In this event, one should pump at a maximum allowable rate, increase the lead pad volume, and idle the pump when the leading edge of the lead pad is at the crossover.

In either case, one should pull the washpipe above the gravel-pack packer before spotting the pill. This also is the recommended technique when initiating a workover with a pill for killing the well. The kill fluid weight must be sufficient to provide hydrostatic control.

In depleted reservoirs with a moderate to extreme overbalance, one should pump the pill down the tubing into the production screen to enable the kill-weight fluid column to remain in the wellbore.

The overbalance will cause the pill and the displacing fluid (kill-weight) to fall downhole. In this case, one should chase downhole the pill at a maximum pump rate until the lead pad is near the gravel-pack packer. At that point, one needs to idle the pump and slowly apply hydraulic pressure on the interior of the screen as it is sealed off.

Case histories

As of this writing, operators have pumped carbonate-laden gel pills in more than 100 wells in the Gulf of Mexico. Ten applications involved the following:

The first application of the pill was in a Gulf of Mexico completion in February 1999. The completion included a frac pack in a 37° wellbore and used a flapper valve for post gravel-pack fluid-loss control. The flapper worked successfully; however, during postintervention, the flapper shattered while reentering the 125 μm sand-control screen.

The well had 168 bbl/hr initial losses and the operator spotted a 10 bbl carbonate-laden gel pill inside the sand-control screen. This reduced losses to 2 bbl/hr within 1 hr after spotting the pill, but losses of 0.25-0.50 bbl/hr continued.

The operator left the pill in place for 8 days while running the production tubing.

The well produced with a 19,000 bo/d initial rate and required no remedial treatment for removing pill. This completion had a calculated skin value of about -1.

The second example is for a dual selective completion that had two zones perforated and gravel-packed in a 4.276-in. ID liner. The liner ID prevented the use of a flapper valve. Completion fluid was 13.5 lbm/gal CaCl2-CaBr2 brine at about 230° F. BHT.

Both completions required 8 gauge, wire-wrapped screens and 50-70 gravel. The elevated temperature and expected exposure time required that the base pill include a buffer to enhance thermal stability.

The job spotted a 7-bbl balanced pill with no spacers and a final carbonate loading of 27 lbm/bbl when losses exceeded 10 bbl/hr.

Mechanical problems resulted in leaving the pill in the wellbore for 12 days. The well was unloaded on a 9/64-in. choke, with no remedial treatment. The well produced 10.8 MMcfd and 71 bo/d compared to an expected initial production of 10-15 MMcfd of dry gas.

The third example included a single gravel pack over a perforated interval from 13,848-13,961 ft.

A well with an 8-gauge, 120-ft prepacked screen was gravel packed with 20-40 gravel. This completion required 15 lbm/gal CaCl2-CaBr2-ZnBr2 brine. The flapper failed and initial losses were 180 bbl/hr. The job then spotted a balanced 8 bbl, 15.7 lbm/gal pill out of the workstring.

Lead and tail 3-bbl spacers prevented pill dilution. The pill remained in the well for 21 days at 216° F. The well produced without the need for a cleanup.

The well currently produces 29,886 MMcfd of gas, 45 bw/d, and 1,755 bo/d on a 40.5/64-in. choke with a 7,302 psig flowing pressure.

The fourth example also was a single gravel pack in a zone completed with seawater. The completion included perforating the target zone from 11,040 to 11,276 ft, and installing a 344 ft, 6-gauge, wire-wrapped screen (2.875 in. OD).

A small-bore flapper controlled fluid loss. When the flapper failed, initial losses were about 15 bbl/hr. A 3-bbl balanced 8.9 lbm/gal pill without lead or tail spacers decreased the losses to 4.5 bbl/hr and after 1 hr the well became static. The pill remained in the well for 4 days at a 180° F. BHT. The well currently produces 18,000 MMcfd of gas and did not require a remedial treatment to remove the pill.

The fifth completion was a single gravel pack in a formation with a 180° F. BHT. A large-bore disk flapper controlled fluid loss. The completion had a 120-ft, 6-gauge screen, with 50-70 gravel. Completion fluid used was 8.4 lbm/gal KCl.

When the flapper failed, the job spotted 5 bbl, 8.9 lbm/gal pill, reducing the initial losses of 20-40 bbl/hr to zero. The pill remained in the well for 3 days before the well was placed on production without any clean up. It currently produces 15,000 bo/d on a 24/64-in. choke.

The sixth example was a well with a single frac pack. The target zone had an 8,015-psi BHP, 154° F. BHT, and maximum wellbore deviation of 16°. The completion included a 90 ft, 5 in., 150-μm premium screen, and 30-50 gravel. The completion fluid was 12.9 lbm/gal CaCl2-CaBr2.

A flapper valve controlled fluid loss. A decision to restress the gravel pack subsequently led to the shearing of the flapper valve. Initial losses were 225 bbl/hr.

A 10-bbl pill with a carbonate loading of 39 lbm/bbl and a final density of 13.6 lbm/gal slowed the losses immediately and subsequently decreased them to zero. The pill remained in the well for 8 days.

The well currently produces 13,000 bo/d.

The seventh example was also for a well with a single frac pack. The completed target zone had perforations from 17,798 to 18,158 ft and included a 200 ft, 6-gauge wire-wrapped screen (5.665 in. OD) prepacked with 30-50 proppant. The completion fluid was 12.8 lbm/gal CaCl2-CaBr2.

A flapper device controlled fluid loss until it failed, resulting in initial 25-bbl/hr fluid losses. A 15-bbl pill with a carbonate loading of 39 lbm/bbl and no spacers slowed losses immediately and after awhile the well went static.

The pill remained in the well for 5 days at a 165° F. BHT. No cleanup was required to remove the pill.

The well currently produces 20,000 bo/d, which is 10% better than expected.

In the eighth example, the operator designed the completion as an openhole frac pack in a 2,200-ft horizontal lateral. The target zone had a 180° F. BHT.

The completion included a 2,125 ft, 4.4 in. ID, 7-gauge prepacked screen. The completion fluid was 12.5 lbm/gal CaCl2-CaBr2.

A flapper device controlled fluid loss until it failed, leading to initial losses of 120-144 bo/d. A 38-bbl pill with a carbonate loading of 39 lbm/bbl and a final density of 13.5 lbm/gal slowed the losses immediately to 12-18 bbl/hr and stabilized the losses to 3 bbl/hr after 1 hr. The pill was spotted balanced at the end of the workstring with no spacers.

The pill remained in the well for 7 days, and the well did not require remedial treatment to remove it. The well now produces between 30,000 and 40,000 bo/d.

The ninth example was a frac-pack completion at 12,960 ft TVD. The target zone had a 163° F. BHT and a 0° deviation at mid-perforations. The completion included a 137 ft, 4.408 in. ID, 175-μm premium screen. Completion fluid was 12.1 lbm/gal CaCl2-CaBr2.

A flapper device controlled fluid loss until it failed, resulting in losses of 90-200 bbl/hr. A balanced 7-bbl pill with a carbonate loading of 39 lbm/bbl and a final density of 12.5 lbm/gal but without spaces immediately slowed losses. After the well became static, the workstring was pulled from the hole. For spotting the fluid-loss control pill, the workstring had been placed inside the sand-control screen.

Calculations performed in the planning stage confirmed that the largest carbonate particle diameter in the pill was less than the tolerance between the washpipe and the packer bore.

This method minimized dilution effects on the fluid-loss pill. The pill remained in the well for 9 days, and no remedial treatment was required to remove it.

The well produces about 27,000 boe/d with a 2.8 calculated skin.

  1. In the last example, the operator designed this completion as a frac pack completed at 12,357 ft. TVD. The target zone had a 155° F. BHT and a 8,065-psi BHP and was at a 66° deviation at mid-perforations. The completion included a 271 ft, 3.5 in. ID, 175-μm premium screen.

    The operator completed the zone with 12.9 lbm/gal CaCl2-CaBr2 and included a flapper device for fluid-loss control.

    While running the tubing back in the well, the operator experienced problems while stinging into the packer. A sweep pill removed suspected solids, but a decision to pressure up on the flapper led to breaking it while stinging in with the workstring.

    Initial losses were 36 bbl/hr and the operator spotted a balanced 7-bbl pill with a carbonate loading of 39 lbm/bbl and a final density of 13.4 lbm/gal. The pill did not have any spacers.

    Losses slowed immediately to 12 bbl/hr and after 1 hr the well was static. The pill remained in the well for 7 days and did not require a cleanup to remove it.

    The well produced at 21,000 boe/day with a 3.0 calculated skin.

References

  1. Dewprashad, B., Cole, C., Costas, C., and Soybel, J., "Technique for Fluid-loss Control and Enhanced Clean-Up," Paper No. SPE 39445, International Symposium on Formation Damage Control, Lafayette, La., Feb. 18-19, 1998.
  2. Hines, R.E., Dahl, J.A., and Foley, K.A., "Low Damage Fluid-loss Control for Well Completions," Paper No. SPE 22355, Offshore Europe Conference, Aberdeen, Sept. 3-6, 1991.
  3. Ross, C.M. and Todd, B.L., "Current Materials and Devices for Control of Fluid-loss," Paper No. SPE 39593, International Symposium on Formation Damage Control, Lafayette, La., Feb. 18-19, 1998.
  4. Luyster, M.R., Foxenberg, W.E., and Ali, S.A., "Development of a Novel Fluid-Loss Control Pill for Placement Inside Gravel-Pack Screens," Paper No. SPE 58734, SPE International Symposium on Formation Damage, Lafayette, La., Feb. 23-24, 2000.
  5. Lau, H.C., and Davis, C.L., "Laboratory Studies of Plugging and Clean-Up of Production Screens in Horizontal Wellbores," Paper No. SPE 38638, SPE Annual Technical Conference and Exhibition, San Antonio, Oct. 5-8, 1997.

The authors

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Syed A. Ali is a senior staff research scientist for ChevronTexaco E & P Technology Co., Houston. He specializes in sandstone acidizing, formation damage control, rock-fluid interaction, mineralogy, and oil field chemistry. Ali has an MS from Ohio State University and a PhD from Rensselaer Polytechnic Institute. He is a member of SPE.

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Mark R. Luyster is a senior technical engineer with M-I LLC. Completions, New Orleans. He managed the M-I completions laboratory in New Orleans for 3 years before assuming his current position. His main area of interest is rock petrophysics. Luyster has a BS in geology from the University of Akron.

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William E. Foxenberg is technical manager for M-I LLC. Completion Fluids, Houston. He has worked in the oil and gas industry for the past 22 years, specializing in completion fluids for the past 15 years. His interests include formation damage, displacement technology, sand control and fluid-loss control. William holds a BS in chemistry from the State University of New York College of Environmental Science and Forestry.

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Michael Darring is senior technical representative with M-I LLC Completion Fluids, Houston. He has 24 years experience in the industry, specializing in matrix stimulation and sand control, completion fluids, and fluid-loss control. Darring has a BS in philosophy from the University of Tennessee.