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Phosphonate-Based Inhibitor Reduces Scaling Potential of Seawater

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In this study, a laboratory analysis was conducted to study the effect of a phosphonate-based scale inhibitor on a mixture of hypersaline Arabian Gulf seawater and formation water under high-temperature/high-pressure conditions. The objective was to identify the minimum scale-inhibitor concentration required at various temperatures to achieve a cost-effective solution in minimizing the formation of common oilfield scales. This research pushes the thermal constraints of a phosphonate-based scale inhibitor to 330°F to test its efficiency and treatment integrity.

Introduction

Produced water, seawater, and nanofiltered seawater have been explored as environmentally friendly and cost-effective alternatives to fresh water in fracturing fluids at different ratios. Consequently, total-dissolved-solids (TDS) levels, salinity, and bottomhole temperatures have increased, making scale inhibitors more important than ever.

In this study, raw Arabian Gulf sea­water and a water mixture from the Jafurah formation was used at various ratios and at different temperatures to determine the efficiency of a phosphonate-based scale inhibitor in the presence of ion complexes. High scale formation was associated with the ionic effect on the fluid, especially because of the high content of sulfate in seawater and high barium and calcium concentrations in connate water. Scale-advisory-software results indicated that barium sulfate was the major scale. Additionally, specific ions can affect the pH of the fluid severely, thereby inhibiting the operational function of the buffer systems.

Scaling is a natural byproduct of seawater-based fracturing. As a result, various water treatments have been implemented to decrease scale formation. One such method involves nanofiltration. Experimental results have shown that nanofiltration caused sulfate reduction in seawater sources down to 300 ppm. This lowers the scaling tendency to a point at which it is controllable by conventional chemical treatments.

To address the issue of freshwater scarcity and associated treatment costs of alternatives such as waste water, the use of raw seawater has received attention. The TDS content of the source water used in this paper is one of the highest in the world, given that the Arabian Gulf is known for its hypersaline conditions. Furthermore, the cations present in the water, namely calcium and magnesium, are known to cause problems in the formulation process of hydraulic-fracturing fluid. As a result, it is expected that certain fracturing-fluid additives must be increased to meet these challenges and ultimately create a stable seawater-based fracturing-fluid system with appropriate gelation timing that meets industry standards.

This study aims to find an alternative source to freshwater-based fracturing fluid and contribute to the study of scale inhibition as dirtier water sources are considered.

Procedure

The seawater was collected from the Arabian Gulf, while the formation water was collected from a field in eastern Saudi Arabia. The samples were analyzed through an inductively coupled plasma spectrophotometer to generate cation concentration. To measure sulfate and iron, the team used an ultraviolet-visible spectrophotometry instrument. Reagents were added and effectively dissolved within the seawater sample. The equipment then read the total content in milligrams/liter.

Salts were added to deionized water to generate a 50/50 formation water/sea­water mixture—similar to proportions of mixtures investigated elsewhere in the literature—and then the anions and cations were separated. This mixture was chosen because it is the most expensive to remove and produces the highest concentration of barium sulfate. The cation and anion samples would be used later in the scale-loop experiments. The dynamic scale loop was used to measure the pressure differential in the coiled tubing. The primary purpose of the scale loop is to portray the severity of scale formation qualitatively and quantitatively by examining pressure-differential data. The pressure-differential results were then transferred to software that indicated presence of scale. The seawater and formation-water mixture was kept at 50/50 and tested at temperatures ranging from 270 to 330°F. A phosphonate-based scale inhibitor was used to mitigate scale formation at different concentrations.

Results and Discussion

Other researchers have tried to find ways to deal with barium sulfate, including attempts to decrease the size of the scale to increase the solubility. Investigators have also found that freshly precipitated barium sulfate dissolves eight times faster than scale that is 30 hours old. Barium sulfate is soluble in sulfuric acid, but it forms an acid sulfate so that, when diluted in water, barium sulfate reprecipitates. Previous tests concluded that the size of freshly precipitated barium-sulfate scale generally increased with the decrease in the total concentration of barium sulfate.

Using the dynamic scale loop, the seawater/formation-water mixture was tested at 270, 300, and 330°F. A phosphonate-based scale inhibitor was used to find the minimum inhibitory concentration for the mixture at the aforementioned temperature ranges. The phosphonate-based scale inhibitor product preferentially binds to metal-ion cations. In the brine mixture, the concentrations of calcium and magnesium ions are the highest. Calcium ions are known to be useful to the barium-sulfate-inhibition efficiency of phosphonate-based scale inhibitors. Magnesium cannot be included into the growing barite scale because of its small size. Barite ions are even larger than calcium ions, making their size irrelevant to phosphonate binding. Several reports have pointed out that calcium ions enhanced inhibitor efficiency while having no evident effect on barite-nucleation time. Rates of nucleation or barite growth without scale inhibitor are a function of the saturation index. As a result, multiple kinetic models have been developed for prediction of nucleation and crystal-growth rates. The scale inhibitor appears to adsorb at the surface of the active growth site of the crystal, ­inhibiting expansion.

Dynamic scale-loop tests were performed to determine the critical inhibitor concentration for the seawater/formation-water mixture. Each test began with a blank run in which no scale inhibitor was present. The blank test had a time of 7 minutes before the differential-pressure data exponentially increased, indicating extreme scale buildup. Tripling the blank test time, known as the hold time, is an industry standard.

At 270°F, the scale inhibitor succeeds in mitigating scale at 3,000 and 2,000 ppm. At 2,000 ppm, differential pressure dramatically increases at approximately 23 minutes, which passes the tripled blank test. The blank test serves as a reference point at which the mixture is tested with scale inhibitor absent. This reference point was included for all scale-loop graphs.

At 300°F, 3,000 and 2,000 ppm of the scale inhibitor successfully passes the test for more than 35 minutes. At 1,500 ppm, the differential pressure rises above 1 psi, indicating scale formation. However, the scale buildup is not severe and the exponential increase typical of extreme scale buildup is not evident. As a result, chelating agents can be used; however, this will incur additional costs for the well operator. At the same time, the concentration of the scale inhibitor will be less, so the tradeoff must be examined on the basis of financial factors.

At 330°F, as shown in Fig. 1, the scale inhibitor concentrations from 250 to 750 ppm were successful in passing the tripled blank test. At 1,500 and 2,500 ppm, the scale inhibitor did not pass. Interestingly, the higher scale-­inhibitor concentration showed fewer successful results. This can be explained by previous research on precipitation of calcium phosphonates which occurs because of the concentration of calcium, the concentration of scale inhibitor, solution pH, or the test temperature. Phosphonate-based scale inhibitors are known for thermal instability, especially when temperature exceeds 130°C.

Fig. 1—Scale inhibition analysis at 330°F.

 

As a result of this high temperature accompanied by the high volume of scale inhibitor, the molar ratio between magnesium ions and phosphonates will increase and cause precipitation of calcium phosphonate. If high-enough concentrations of calcium and inhibitor are brought together, even at room temperature, it is possible to generate calcium-­inhibitor complexes. The fact that the scale inhibitor also has strong ligands that will bind with metal ions contributes to the precipitation phenomena.

Calcium precipitate more readily forms as temperature increases. Research has been conducted to find the most thermally stable phosphonate-derivative scale inhibitor. Tetraphosphonate provided thermal stability up to 160°C because of linkages that reduce steric strain within the molecules. As a result, less scale inhibitor may yield better results.

Summary

The phosphonate-based scale inhibitor proved successful in mitigating scale of different chemistries, including barium sulfate. The concentration of the inhibitor was adjusted as temperature increased to generate the desired mitigation time. The inhibitor was effective for high-temperature applications. As a result, the use of this scale inhibitor builds upon the assertion that seawater-based fracturing fluid is a viable option as the oil and gas industry continues to search for alternatives to fresh water.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of “Mitigation of Scaling Potential of Seawater in High-Temperature Environment Using Phosphonate Scale Inhibitor,” by Raafat M. Yamak and Hisham Nasr-El-Din, SPE, Texas A&M University; Sabiq Rahim, SPE, Halliburton; and Moussa Taleb, University of Calgary, prepared for the 2019 SPE Kingdom of Saudi Arabia Annual Technical Symposium and Exhibition, Dammam, Saudi Arabia, 16–18 April. The paper has not been peer reviewed.

Phosphonate-Based Inhibitor Reduces Scaling Potential of Seawater

01 June 2019

Volume: 71 | Issue: 6

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