A systematic approach to brine selection helps identify optimum fluids for deepwater environments.

Choosing the right completion fluid is important because inappropriate fluids can have a significant impact on a project, not only during completion operations and startup, but also throughout the well's productive life.
Experience has shown that some completion practices that work well on the shelf of the Gulf of Mexico do not transfer directly to the deepwater environment. What makes deepwater completions more challenging is the combination of younger formations, colder seafloor temperature, greater hydrostatic pressure and interaction with subsea systems and control fluids. A new method of formulating appropriate completion fluids for deepwater Gulf of Mexico wells overcomes these challenges.
Since its initial application in early 2000, the approach has led to seven successful completions on oil and gas wells in water depths from 800 ft to 4,200 ft (244 m to 1,281 m). The brines used varied from 10.0 lb/gal CaCl2 to 14.8 lb/gal ZnBr2/CaBr2. Each time, the completion brine was displaced to a compatible packer fluid after the interval was completed and before running the production string and tubing hanger. These wells experienced no subsea control difficulties, no hydrates or blocked control lines, and no intermittent loss of installation and workover control systems function. The productivities demonstrated high completion efficiencies and low skin factors, meeting or surpassing expectations.
Selection drivers
While sufficient density is needed to control formation pressure in any well, in deepwater wells it is also necessary to be able to modify the density without any adverse effect on crystallization and hydrate inhibition at seafloor temperature and maximum anticipated pressure.
The completions fluid must be compatible with:
• reservoir matrix;
• shale formations;
• reservoir fluids;
• subsea control fluids;
• gravel- or frac-pack fluids;
• stimulation chemicals and acids;
• corrosion inhibitors;
• packer fluid additives; and
• fluid-loss control materials.
The recommended selection process suggests culling candidate brines by two mandatory parameters: density and crystallization temperature. Next, narrow the field using models to identify hydrate inhibitor needs. Evaluate formation sensitivity using petrophysical data, and test core samples to confirm the candidate brine's compatibility with the producing formation and adjacent shales. Then test candidate brines for compatibility with reservoir fluids (are scale, sludge or emulsion inhibitors needed?) and subsea control fluids. Check compatibilities between reservoir fluids and all other completion fluids (frac gels, acids, packer fluid additives and corrosion inhibitors). Finally, compare candidates in terms of cost, benefits, risks, logistics and environmental issues.
Density
For most deepwater Gulf of Mexico wells, temperature-related change in density is insignificant (typically less than 0.1 lb/gal), because reservoir temperature gradients are relatively low (1.2° F to 1.5°F per 100 ft). The density gain due to colder seafloor temperatures can offset the loss with increasing formation temperature. The relative range of densities for several brines is shown in Figure 1.
Crystallization point
True crystallization temperature (TCT) of a brine is the temperature at which salt crystals begin falling out of solution at atmospheric pressure, given sufficient time and proper nucleation conditions. For single-salt brines, TCT depends on fluid density and cannot be adjusted. With multisalt brines, TCT for a given density can be adjusted by varying the relative amounts of each salt. For example, a 12.0 lb/gal CaCl2/CaBr2 brine can be blended to achieve a TCT range of 70°F (21°C) to below 0°F (-18°C). Generally, the lower the TCT, the more expensive the brine (a higher proportion of heavier salt is used) and the lower the hydrate inhibition (more "free" water in the solution).
With divalent brines made from calcium and zinc salts, the crystallization temperature increases with increasing pressure. In deepwater completion brines, the pressure-dependent crystallization temperature (PCT) is the definitive parameter due to colder temperatures and higher pressures at the seafloor. Applying 10,000 psia raises the crystallization temperature of divalent brines by 10°F to 20°F and monovalent brines by only 1°F to 5°F. Figure 2 shows the PCT for three blends of a 12 lb/gal CaBr2/CaCl2 brine over a range of pressures.
In deeper water, crystallization is most likely to occur at the seafloor, as well as in the wellhead, subsea tree, blowout prevention (BOP) stack, and choke and kill lines. Choke and kill lines are most vulnerable because they can reach seafloor temperature within 30 minutes after circulation stops. Modeling can be used to predict temperature response.
To avoid crystallization, a salt blend is recommended with a PCT 10°F (5.6°C) below the lowest anticipated temperature at the highest anticipated pressure, such as during BOP testing. For a well in 5,000-ft (1,525-m) waters with 11.0 lb/gal fluid and a BOP test pressure of 7,500 psig (measured at surface), the pressure at the BOP stack is 10,400 psia (7,500-psig test + 15-psia atmospheric + 2,860-psi hydrostatic). With a seafloor temperature of 38°F (3.3°C), specify the 14°F (-10°C) TCT brine and confirm in the lab that it has a PCT of 28°F (-2.2°C) at the anticipated BOP test pressure.
Density and salt composition
Increasing or maintaining density by adding dry salt or volumes of a saturated "spike" brine can change the proportion of salts in a multisalt blend, altering the brine's PCT. Hence, the common practice of slugging the workstring with a spike fluid before tripping should be done with caution. Adding water to reduce density causes the hydrate equilibrium curve to shift, possibly increasing the risk of forming hydrates. Adding lighter salt brine or adding drill water along with a hydrate inhibitor might be safer options.
Hydrates
Gas hydrates (natural gas molecules trapped inside "cages" of water ice molecules) can form quickly - plugging tubing, cementing workstrings in place, interfering with valve and BOP equipment function, plugging choke and kill lines and trapping pressure.
Deepwater environments often present the four required elements for hydrate formation:
• low seafloor temperature;
• hydrostatic pressure at the seafloor;
• hydrocarbon gas; and
• free water from water-based drilling mud, formation water, seawater or completion brines.
Laboratory measurements can determine the pressure and temperature conditions at which hydrates can exist for a given gas composition and water-based fluid. As shown in Figure 3, risk of eventual hydrate formation exists in the area left of the equilibrium curve. With this particular brine and gas at a seafloor temperature of 38°F (3.3°C), the maximum hydrate-free pressure is about 5,000 psia at the seafloor.
Pumping seawater to kill a deepwater well, a common practice on the Gulf shelf, can pose a hydrate risk. Seawater at 38°F (3.3°C) can form stable hydrates at less than 500 psia, which is less than the hydrostatic pressure in 1,100-ft (336-m) waters.
Computer models based on hundreds of laboratory measurements are available to predict hydrate equilibrium conditions for a variety of completion brines. Some models include the effect of dosing the brine with thermodynamic hydrate inhibitors such as glycol and methanol (Figure 4). One model also includes thermal analysis of the wellbore to help predict when hydrate equilibrium conditions will be reached after shut-in.
Formation compatibility
The younger formations being exploited in the deepwater Gulf of Mexico often contain clays that are sensitive to either divalent or monovalent brines. Some of the thick, clean sandstones have little or no cementation with low confining stress and are unconsolidated and friable. Thick, highly-laminated, lower-resistivity pay intervals where high-clay intervals will be exposed to completion fluids also exist. Completion fluids that won't destabilize these sensitive formations are recommended. Core sensitivity studies should include reservoir rock, shale laminae and adjacent shales.
Mineralogy is also a compatibility issue. For example, aluminum-rich zeolites are sensitive to acid and low pH. Petrographic description and clay mineralogy can be useful in ranking one brine system over another.
As for drilling fluid compatibility, some synthetic drilling fluids can oil-wet the near-wellbore region. With changing invert surfactant systems, conventional approaches such as xylene washes can result in tight emulsions and even greater impairment. Such interactions should be thoroughly studied.
Laboratory tests using core samples with candidate brines then should be conducted, including:
• core flood tests to measure reservoir flow;
• return permeability tests to measure reservoir flow and cleanup;
• linear swell testing on the shale; and
• capillary suction time measurement on the shale.
Reservoir fluid compatibility
Several investigative tools are helpful in evaluating completion fluid interaction with reservoir fluids. If the formation water composition is known, barium sulfate and carbonate scaling potential can be estimated using scale prediction software. Bench-top tests on formation water samples can confirm scaling tendency and determine the required inhibitor dosing.
Native Gulf crudes exhibit varied emulsion potential when exposed to water-based completion brines. Emulsions can seriously impair productivity, and some inverted drilling mud systems compound the problem. Testing the crude with the proposed brine is recommended to determine if an emulsion inhibitor is needed.
Some native crudes and condensates form sludge when contacted with acid. Testing the completions fluids with all proposed acid treatments is recommended, including acid used to clean up any loss-control pills or frac-pack gels.
Compatibility of completion fluids
Potential incompatibilities between each of the many fluid systems and chemicals used on a deepwater Gulf of Mexico well should be investigated:
• drilling mud, drill-in fluid and filtrate;
• completion brine with hydrate inhibitors;
• fluid-loss control materials and cleanup chemicals;
• prefrac cleanup acid and additives;
• frac- or gravel-pack gels, surfactants and pH modifiers;
• post-frac fluid-loss control materials;
• packer fluid additives (corrosion inhibitor, oxygen scavenger, biocide and pH modifiers);
• methanol;
• contaminants from tubulars (iron, pipe dope); and
• salts from previous jobs or other sources.
For example, will the iron sequestrate used in the acid treatment be compromised by the high concentration of divalent salt and brine alkalinity and pH? Under certain conditions, zinc residue can react with formate brines to form an insoluble precipitate. Sulfates in seawater mixed with barium salts in formation waters can form barium sulfate scale. These incompatibilities should be investigated and mitigated.
Subsea control fluid
In some subsea trees, completion brine can mix with methanol and control fluid - used to operate subsea systems and the subsurface safety valve (SSV) - just prior to landing the tubing hanger in a subsea tree. Lab tests confirm most heavy brines are incompatible with methanol and some brines are incompatible with certain control fluids. Precipitation of brine salts and separation of control fluid components occur immediately on contact. With some control fluids, contact with brine causes separation of the fluid's dye, lubricity package and corrosion inhibitor, suggesting a loss in control fluid performance.
Salt precipitation, most pronounced with divalent brines (CaCl2, CaBr2 and ZnBr2), can be sufficient to plug SSV control lines or block a chemical injection supply line or annulus bleed-off line. Precipitation appears to be less problematic with mixtures of monovalent brines and control fluids, although precipitation can occur when methanol is added. To avoid salt precipitation, sodium bromide has been successfully employed as a packer fluid, with the addition of ethylene glycol as needed for hydrate inhibition.
The results of mixing of various brines with one control fluid showed that some combinations produced smaller crystals that did not agglomerate or stick to the glass lab vessel, resulting in a "pumpable" slurry. Others showed heavy precipitation.
Many completion teams and subsea tree vendors have modified installation procedures to minimize the mixing of brine with control fluid and have eliminated opportunities for brine back-flow into control systems. However, intimate contact between brine, control fluid and methanol still occurs and cannot be avoided.
Confirmation testing
Once the completion fluid has been selected, the following tests should be performed:
• measure the PCT of the specific brine composition with additives;
• confirm the hydrate equilibrium curve;
• confirm formation compatibility with brine and other completion fluids (frac fluid and acids) when iron is present;
• confirm brine compatibility with reservoir fluids when iron is present;
• measure corrosion rates on coupons of specific metals of the tubing and production equipment; and
• determine the necessary dosage of corrosion inhibitors, pH modifiers and oxygen scavengers.
Corrosion rates should be measured for a minimum of 28 days.
Avoid problems to contain costs
The costs related to completion fluids are greater for deepwater wells because of the larger volumes - often two to three times more than required for shelf wells - and the different fluid chemistries needed. The cost for completion fluids, including brine, displacement chemicals, filtration, fluid-loss control materials and scale and hydrate inhibitors, can account for US $500,000 to $2 million per well, representing10% to 20% of well completion costs.
While cost control is always helpful, project profitability may be better assured by reducing formation damage that reduces well deliverability. With the more marginal prospects, profitability may hinge more on avoiding operational problems during the completion.
Also key to project profitability is reducing the potential need for future intervention to correct subsea control problems. The cost of mobilizing a semisubmersible rig to return to the well can easily reach $2 million. Add to that any troubleshooting operations, or possibly pulling the subsea tree or production tubing to retrieve a failed SSV, and potential profits can quickly evaporate.
Preventive spending can avoid these operational problems by ensuring fluid compatibility and avoiding pressure-related crystallization and hydrate formation. The selection process described, including proper testing and modeling, has proven itself repeatedly on challenging deepwater wells.

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