Offshore frac packs benefit from seawater-based borate fluid

Sept. 28, 1998
This report covers a diverse range of technologies. Offshore frac packs, which in the past few years have become common in high-permeability sands, are now benefiting from seawater-based frac fluids. Also offshore, more operators are installing probes for monitoring sand and erosion that could cause severe problems if not detected. With a number of control valves to select from and the availability of PID controllers, production equipment design is now more adaptable for the varying flow rates
Syed A. Ali, William M. Pickering, Byron C. Sketchler
Chevron U.S.A. Production Co.
New Orleans

Ronald J. Powell, Phillip C. Harris
Halliburton Energy Services
Duncan, Okla.

Steven K. Smith, Sanjay Vitthal
Halliburton Energy Services
New Orleans

About this report

This report covers a diverse range of technologies. Offshore frac packs, which in the past few years have become common in high-permeability sands, are now benefiting from seawater-based frac fluids. Also offshore, more operators are installing probes for monitoring sand and erosion that could cause severe problems if not detected. With a number of control valves to select from and the availability of PID controllers, production equipment design is now more adaptable for the varying flow rates often encountered in oil fields.

Seawater has replaced freshwater in a borate fluid system for frac packing wells in the Gulf of Mexico.

In one example, Chevron U.S.A. Production Co. used a seawater-based fluid containing 25 lb/1,000 gal of an optimized low-guar, borate-cross linked (OLGB) fracturing fluid with a chlorine-based, oxidizing breaker (CBOB) to frac pack a relatively thin oil sand.

Initial oil production after treatment was 850 bo/d, with 1.6 MMscfd gas, a two-fold increase over typical frac-packed wells in the area.

The fracturing gel composition allowed seawater to be used. Seawater reduces logistical costs in offshore operations. This translates into significant cost savings over freshwater, which must be purchased and shipped to the well site.

In the Chevron example, seawater and gel were mixed on the fly from liquid gel concentrate. On the fly mixing enables various size jobs without the tank-cleaning costs associated with batch-mixing.

OLGB system

Borate-crosslinked guar fluids are the most commonly used fluids in Gulf of Mexico frac packs. 1-3

Borate-crosslinked frac fluid systems have become increasingly popular for the following reasons:4

  • Borate systems provide superior viscosity.
  • Borate gels reheal under shear conditions, with minimal deterioration, because of the continual breaking and reforming of the borate crosslinks.
  • Borate salts are inexpensive and have properties that make them cost-effective in fracturing.
The mechanism by which a borate imparts crosslinking to a guar fluid is chemically different from other crosslinkers. The rapid exchange equilibria of the borate ion on the guar polymer and the low bond energy of the borate crosslink to the guar backbone contribute to the rehealing character of borate-crosslinked fluids.

Borate crosslinks are chemically reversible and will uncrosslink when pH is lowered. These fluids are less sensitive to shear under normal conditions.4

Although 30-35 lb/1,000 gal borate-crosslinked fluids have been routinely used for frac packing, emphasis recently has been placed on lowering the polymer loading to minimize conductivity damage. Highly conductive fractures connecting the well bore and formation are recognized as the key for successful frac packs.5

OLGB is an optimized borate-crosslinked fluid with a low guar content. This system also combines minimal polymer concentrations and maximum breaker loadings in a manner that does not interfere with fracturing fluid rheology during treatments.

The reduced guar concentration (20-25 lb/1,000 gal) required for OLGB lessens formation damage and allows for more complete proppant cleanup than conventional borate systems. The reduced proppant-pack impairment provides for better fracture conductivity and increased production.4

OLGB rheology

Fig. 1 [55,923 bytes] compares the viscosities of 20 lb/1,000 gal OLGB fluid and 30 lb/1,000 gal conventional borate-crosslinked fluid at 120° F. The viscosities are similar but the OLGB has 10 lb/1,000 gal less polymer.

Less polymer offers many advantages in fluid recovery and well performance. One obvious advantage is that about 20-25% less gel residue is pumped into the formation and proppant pack. This results in less potential formation and fracture damage.4 6

Furthermore, the filter cake buildup will be less because of less gel in the fracture. This improves fracture conductivity.

Fracturing fluids with less gelling agent are obviously easier to break. The OLGB fluid system has a single component buffer/crosslink additive. This adds a crosslinker to the system and buffers fluid pH to the desired level, regardless of the source-water pH. In addition, the buffer consistently maintains the optimum pH level without further adjustment at the rig site.5

Breaker system

A new breaker was developed for use with OLGB fluid in high-permeability zones and in temperatures from 170 to 200° F. The delayed mechanism of this chlorine-based, oxidizing breaker (CBOB) provides the fluid system with crosslinked viscosity early in the fracturing process with predictable viscosity reduction. 7

The new breaker system is characterized by an initial delay followed by a rapid break. This is desirable for treatments in high-permeability formations. This breaker system can be used throughout the treatment, including the pad fluid, the proppant-bearing fluid, and the flush.

Fig. 2 [56,386 bytes] shows typical laboratory test results of the CBOB breaker system in an OLGB fluid. The CBOB allows the break time to be tailored to the individual treatment requirements.

Conventional enzyme breakers work well in bottom hole static temperatures (BHSTs) up to 140° F., and conventional persulfate products of this type have good performance records in temperatures ranging from 140 to 170° F. None of the conventional breakers, however, has met expectations at 170-200° F.

The OLGB system with the chlorine-based, oxidizing breaker (CBOB) was developed specifically for such applications, and has demonstrated substantial success since its introduction.5

Fluid loss

Conventional borate-crosslinked fluids are extremely efficient at controlling fluid loss.8 The OLGB fluid system is no exception. 6 7

On high-permeability Berea core, the 25 lb/1,000 gal OLGB fluid at 180° F. has a 0.6 gal/100 sq ft spurt loss and a 0.0039 ft/min1/2 Cw.

Table 1 [40,476 bytes] compares a conventional 35 lb/1,000 gal borate-crosslinked fluid with a 0.13 sq ft spurt loss and a 0.0035 ft/min1/2 Cw.

The higher spurt loss is primarily due to the higher permeability of the Berea core. The measured Cw for the OLGB, while slightly higher, is within the experimental limits of the equipment. Higher leakoff can be a desirable characteristic for packing proppant into the fracture after a tip screen out.

The good fluid-loss control on high-permeability cores would suggest that the OLGB fluid system is appropriate for frac packing.


Past studies have shown that fracture conductivity impairment depends on the fracturing fluid used.9 10

Reduced polymer loading inherently reduces the amount of gel and insoluble residue pumped into fracture and formation. This has been shown to improve retained conductivity. Fig. 3 [57,662 bytes] presents conductivity test results with 25 lb/1,000 gal OLGB fluid at 180° F.

Conventional borate-crosslinked fluids show 20-35% retained conductivity, whereas OLGB fluids exhibit 50-75% retained conductivity. Improved conductivity improves long-term production.

Proppant transport

The dynamic proppant transport capabilities of a 25 lb/1,000 gal OLGB fluid were compared to that of a 35 lb/1,000 gal conventional borate-crosslinked fluid. Tests showed that both systems seemed to exhibit good dynamic proppant transport capabilities, but the OLGB fluid had a more homogenous proppant distribution throughout the fracture height.

The conventional borate-crosslinked fluid showed signs of stratification and had a more pronounced proppant concentration gradient. The highest proppant concentration was near the bottom of the fracture simulator.

The OLGB fluid also showed a near-perfect laminar flow profile while the conventional borate-crosslinked fluid exhibited distinct layers of proppant-laden fluid traveling at different velocities and possessing different apparent viscosities.5 Both the laminar flow profile and uniform proppant distribution in the OLGB fluid should result in better proppant placement throughout the length and height of the fracture.

Proppant-laden OLGB fluids with typical field breaker concentrations were also tested. Breaker addition to the OLGB fluid caused no apparent effect on the fluid capability to provide proppant through the fracture simulator.4

Freshwater use

Before the OLGB system was adapted for use with seawater, freshwater was used as the base fluid in fracturing treatments both offshore and onshore.

The first fracturing treatments with OLGB fluid were in a well in New Mexico's Blinebry formation. The treatments resulted in a relatively steady production rate of 70 bo/d and 2.5 MMcfd for about 16 months.4

In another OLGB freshwater treatment, a frac pack in a Eugene Island reservoir targeted a 500-md permeability, 24 ft oil-bearing sand interval. A well deviation was 70° at the perforations.

In this treatment, 20 lb/1,000 gal OLGB frac fluid was mixed with freshwater at the dock in holding tanks. Crosslinkers and breakers were added on the fly as the gel was pumped into the well.5

Seawater use

The OLGB fluid system has been adapted for use in seawater for offshore operations. The practicality, as well as the profitability, behind this adaptation is readily understood. Seawater is not only more economical than freshwater, but it is also more plentiful and more convenient.

Besides the obvious difference in the cost of a free commodity and one with a price, the expense and logistics involved in shipping freshwater to a well site are avoided when using seawater. This significantly saves costs.

In many cases, the time needed to return to a dock to load freshwater and then return to the location can be 10-12 hr. In addition, seawater helps increase the availability of the stimulation vessels and reduces the chances that a rig may have to wait for an available vessel.

By eliminating these associated travel, freshwater loading, and rig charges, an operator can potentially save thousands of dollars on completion costs. Finally, seawater helps to conserve freshwater use for other purposes.

Seawater posed challenge

The introduction of seawater into the fracturing process, however, has not been without its challenges. The adaptation of the OLGB system for treatments using seawater required a systematic approach for developing a comprehensive fluid system that addressed its mineralogical, conductivity, and operational aspects.

Previously, to establish a satisfactory compatibility between the frac fluid and the seawater, substantial amounts of a caustic agent were introduced into conventional borate-crosslinked frac fluids to counteract the high concentrations of calcium and magnesium ions present in the water. However, in solutions with a pH of 10 or greater, levels characteristic of conventional borates, the calcium and magnesium ions present in the seawater react by precipitating into solid particulates termed hydroxides.

The hydroxides, in turn, tend to consume the caustic introduced to increase fluid pH. This action necessitates replacement of the consumed caustic.

To counter the formation of hydroxides, researchers lowered the pH value in the OLGB system. This lower pH has proven effective in prohibiting precipitation.

The presence of natural salts in the seawater has also received attention in the adaptation process. To inhibit the migration or swelling of clay fines in the formation, either of which is capable of impairing conductivity, a 7% salt concentration may be included in the fracturing fluid. The salt content of seawater is about 31/2%; therefore, to protect the formation, potassium chloride was added to the liquid gel concentrate in quantities designed to bring the salt level up to 7%.

Moreover, particular reservoirs contain water-sensitive minerals, and the additional KCl also ensures compatibility between the OLGB fluid and such water-sensitive formations.

Because Gulf of Mexico formation waters often contain significant barium concentrations, the seawater was preconditioned with a scale inhibitor and a biocide, a normal Chevron operating procedure for overcoming barium sulfate scaling problem and bacterial activity.

A systematic study evaluated the amount of scale inhibitor required for different formation water compositions. The scale inhibitor concentration was optimized and designed to prevent scaling in the worst case scenario.

Table 2 [38,416 bytes] compares a water analysis of Gulf of Mexico seawater and a formation water sample that is expected to show significant scaling tendencies. Mixing the two fluids together produces large amounts of barium and strontium scale precipitation, as seen in Table 3 [23,120 bytes].

A great deal of laboratory testing was done to select the type and amount of scale inhibitor required to prevent the barium sulfate scaling tendency. Table 3 also shows that the scale inhibitor was successful in preventing scaling for all the cations. Additional tests were performed to ensure that the addition of scale inhibitor would not affect the OLGB fluid rheology.

Seawater success

The OLGB system was selected for a frac-pack completion on a zone that is typically untested due to marginal economics. When evaluated in the past, this thin, Pliocene deltaic oil reservoir has been modeled as a zone with low production rates that would not economically support a gravel pack. The 22-ft interval has about a 500-md permeability. The top of the perforations is at 10,560 ft measured depth, and the well deviation is 47°. Without a gravel pack, this zone would most likely have very short-term production before the interval sanded up.

In wells with a conventional acid prepack or high-rate water pack completion, the expected rate for this zone is 200 bo/d. To economically justify the additional expense of a conventional completion, a 400 bo/d production rate would be required.

It was determined that a frac-pack completion could probably attain the desired rate, but the cost was too high.

The OLGB system blended the frac-pack technology at a small incremental cost difference over the conventional sand-control cost, with the benefit of increased sustained production, typically associated with high-permeability frac packs.

The OLGB gel system permitted a 33% reduction in the quantity of crosslinked polymer used in the treatment compared to conventional gels. The treatment was designed with a fracture design simulator. Prior to the treatment, a step-rate test and a minifrac were performed to optimize the treatment.

Fig. 4 [58,409 bytes] shows the pressure response during these two diagnostic tests, and Fig. 5 [57,148 bytes] shows the minifrac pressure decline. Based on the analysis, the closure pressure was determined to be 5,573 psi with a fluid efficiency of 30.4%. Based on the minifrac analysis, the frac-pack design was modified to ensure a tip screenout.

Table 4 [22,182 bytes] shows the pumping schedule for the main treatment, and Fig. 6 [58,055 bytes] illustrates the treatment pressures and rates.

A tip screenout was initiated when 4-5 ppg was at the perforations. The net pressure continued to climb and a screenout was obtained with a 9 ppg proppant stage at the perforations.

A total of 8,000 gal of OLGB fluid containing 32,000 lb of a 20/40-mesh intermediate-strength synthetic proppant was pumped at a rate of 10 bbl/min. There was a total rise in net pressure of more than 1,000 psi based on bottom hole gauge data.

The well was brought into production yielding 848 bo/d and 1.6 MMscfd gas, more than double the projected rate. The sustained production was 600 bo/d, 50% more than well predictions.

This production level created incremental economic value in excess of $217,000, based on a 200 bo/d production over 60 days.

Due to logistics, the well remained shut in for 8 weeks following completion and prior to sustained production. Frac packs with extended shut-in periods sometimes require jetting to facilitate production and/or protracted cleanup operations. This completion produced naturally, and cleanup was accomplished quickly because the lower gel concentration deposited less polymer residue on the formation.

Based on a 50% probability that the OLGB fluid eliminated the need for jetting, the treatment was responsible for a savings of $15,000. A combination of reduced loading time and a reduction in cleanup expenses, associated with the pumping vessel, resulted in an additional savings of $10,000.

The economic value to Chevron totaled about $242,000.

The OLGB system's record of success has been established in more than 3,000 frac jobs to date. From August 1997 to May 1998, the system was used in at least 60 wells in the Gulf of Mexico. Reservoir temperatures ranged between 120 and 200° F.

In about half of these jobs, the fracturing fluid was mixed with seawater. The system's adjustable crosslink time and other characteristics have contributed to a versatility that permits its application in both shallow and deepwater, higher temperature wells.

The OLGB design factor that combines the buffer and crosslinker into a single component supplies consistent quality and ease of operation.


The authors thank the management of Chevron U.S.A. Production Co. and Halliburton Energy Services for granting permission to publish this article. We gratefully acknowledge the assistance of Billy Slabaugh and John Terracina for on-location quality control and operational assistance, and David Griffin and Wes Lavin for fluid testing.


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The Authors

Syed A. Ali is technical advisor for Chevron U.S.A. Production Co., New Orleans. 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.
William M. Pickering is a staff petroleum engineer for the Chevron U.S.A. GOM shelf business unit. He has been involved in a variety of positions involving well completions, workovers, and remedial operations. Pickering earned a BS in petroleum engineering from Texas A&M University and is a member of SPE.
Byron Sketchler is a project drilling superintendent for the Chevron U.S.A. GOM shelf business unit He has held multiple positions in the Gulf of Mexico since 1980, and has gained expertise in drilling, fluids, and completions over the past several years. Sketchler has a BS in mechanical engineering from Louisiana State University.
Ronald Powell is a development chemist at the Halliburton Energy Services technology center in Duncan, Okla., where he has worked for 7 years in fracturing fluid research and development. Powell has BS in chemistry from San Jose State University and PhD in inorganic chemistry from the University of Texas at Austin.

Steve Smith is a production enhancement technical advisor for Halliburton Energy Services in New Orleans. His area of expertise is acidizing, gravel packing, and high-permeability fracturing. He has been with Halliburton for 15 years, specializing in sand control.
Phillip C. Harris is a principal technologist at the Halliburton Energy Services technology center in Duncan, Okla. Since joining Halliburton in 1979, he has conducted research on the chemical and physical properties of foams and crosslinked-gel fracturing fluids. Harris has an MS from Oklahoma State University. He is a member of SPE.
Sanjay Vitthal is a technical analyst of production enhancement for Halliburton Energy Services in New Orleans. Vitthal earned an MS and a PhD in petroleum engineering from the University at Texas at Austin.

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