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Combatting brine crystallisation

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Oilfield Technology,

In an exclusive article for the July/August 2020 issue of Oilfield Technology, Samy Helmy, TETRA Technologies, USA, reviews a series of high density, solids-free completion fluids designed for environmentally sensitive wells.

Oilfield completion fluids are solutions of salts (usually halides or formates) in water. At lowered temperatures or increased pressures these fluids can crystallise, causing severe operational problems. This article describes the development and successful use of a novel class of completion fluids by TETRA Technologies. TETRA CS Neptune® completion fluids mitigate the risk of crystallisation, are environmentally acceptable, and are sustainably sourced. Although originally developed to service deepwater projects, they are well suited for use in the North Sea and other environmentally-sensitive areas as cost-effective alternatives to cesium formate.

Brine crystallisation

The crystallisation temperature of oilfield brines is a function of dissolved salt concentration; the relationship is not linear however. Plots of crystallisation temperature vs brine density (salt concentration) typically follow the form shown in Figure 1.

Figure 1. Plot of salt concentration vs crystallisation temperature. 

The inflection point in the plot (the eutectic point) represents the lowest crystallisation temperature achievable with a specific brine chemistry. Increases in brine density below the eutectic point lower the crystallisation temperature, whereas density increases above the eutectic result in increases in the crystallisation temperature. The eutectic point for calcium bromide brines occurs at approximately 13.2 ppg (1.58 g/ml) and -37°F (-38°C). At 14.2 ppg (1.70 g/ml), calcium bromide exhibits a crystallisation temperature of 10°F (-12°C). However, at 14.9 ppg (1.785 g/ml) the crystallisation temperature of calcium bromide brine has risen to 57°F (14°C) and it can no longer be considered an operationally viable fluid for a major part of well applications.

High pressures, such as those experienced by completion fluids in deepwater risers and during blowout preventer (BOP) tests, cause fluids to the right of the eutectic point to exhibit even higher crystallisation temperatures due to the compressibility of water within the brine. Table 1 illustrates the effect of pressure on the crystallisation temperature of a specific brine blend above its eutectic density. The value of this subsequent shift in crystallisation temperature is commonly referred to as pressure crystallisation temperature (PCT).

TETRA CS Neptune completion fluids were developed to address the crystallisation problems associated with the use of high density brines.

Initial development and field validation

In June 2014, the company was asked by a major US operator to develop a novel clear brine. The fluid was to have a density of up to 15.4 ppg (1.85 g/ml), a PCT of <30°F (<-1°C) at 15 000 psi and could not contain zinc (due to environmental concerns) or formate ions (due to concerns with hydrogen-induced cracking).

A key decision early in the project was how to measure the crystallisation temperature of the candidate brines at high pressure. No industry standard methodology exists for the measurement of PCT and many of the ‘prototype’ instruments used to generate PCT data in the early 2000s were no longer operational. TETRA had already been considering the use of differential scanning calorimetry (DSC) as a way to automate the measurement of crystallisation temperature. Differential scanning calorimeters detect thermal changes within a material. The instrument measures the amount of energy that must be transferred to the material to achieve specific temperatures relative to that required for an inert ‘control’ sample as they are both subjected to a heating or cooling cycle. Crystallisation of halide brines is an exothermic process (heat is released) and hence can be detected by DSC. DSC instruments are used throughout the chemical industry, but pressurised differential scanning calorimeters (HPDSCs) were not widely available and consequently were entirely unproven in this application. The company approached a respected manufacturer of this instrumentation and conducted extensive testing on various brine types at their development laboratories in France. This testing indicated that PCT could be measured and replicated consistently using an HPDSC instrument. In addition, the instrument was small enough and sufficiently robust to permit usage at the rig site, if required. An example HPDSC plot is shown in Figure 2.

Figure 2. HPDSC plot.

Initial development work on the novel fluid, to validate proof of concept, was completed within two months and the fluid was then subjected to intensive testing to verify its suitability. The testing programme was performed internally and at recognised external laboratories. The test programme included: crystallisation temperature (true crystallisation temperature [TCT] and PCT), thermal stability (up to 325°F/163°C), compatibility with elastomers and downhole fluids, corrosion (general and environmentally assisted cracking), temperature and pressure effects, environmental acceptability (Gulf of Mexico and North Sea), hydrate inhibition, shale stability, regained permeability, and plant mixing trials. In each case, the results were exemplary, providing confidence to progress with the first field trial. A detailed description of the testing programme is beyond the scope of this article, so elected examples of the testing have been summarised:

PCT data

Figure 3 indicates the PCT values obtained on various fluids by the company and a respected, independent laboratory.

Figure 3. PCT comparison data.


Stress cracking tests involved the corrosion resistant alloys (CRAs) 13Cr110, 15Cr125 , and Alloy 718, and a carbon steel (Q125). Tests were conducted on C-Rings, Tensile Bars and Crevice Coupons, as shown in Figure 4, in a carbon dioxide (CO2) rich environment for 30 days at 265°F/129°C.

Figure 4. Corrosion test coupons

All CRAs and carbon steel specimens tested passed and the novel fluid achieved performance comparable to an effectively inhibited calcium bromide brine.

General corrosion rates in the new fluid were also low and were comparable to those for an equivalent density calcium bromide brine.

Health, safety and environment (HSE)

The new fluid was classified as non-hazardous and obtained environmental approval for use in both the Gulf of Mexico and the North Sea. OSPAR pre-screening test data for the fluid is provided in Table 2 and demonstrates its low toxicity, low bioaccumulation potential, and ready biodegradability.

Wellbore validation

In February 2015, a TETRA CS Neptune completion fluid was used for the first time in a Gulf of Mexico project. Water depth was 7200 ft, total vertical depth (TVD) was >30 000 ft and the bottomhole temperature was 265°F (129°C). The project included a BOP test at 15 000 psi and <40°F (<4°C). The fluid was used as the completion brine, base for wellbore treatment pills, and packer fluid. The fluid performed well, with no operational or HSE issues. It was used successfully in four subsequent wells, one temporary abandonment and one well intervention.

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