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One of the flow assurance challenges facing the deepwater oil and gas field development and production is mineral scale control. In a deepwater production system, barium sulfate scale deposition may arise from two causes, namely: a) commingling of injected seawater with connate formation water, and b) temperature cooling from well bottomhole to wellhead and then in a long subsea flowline. The first phenomenon has already been well understood in the offshore oil industry. However, there is very little knowledge in barium sulfate scaling and inhibition mechanisms in a deepwater subsea system, where the fluid temperature can be cooled to a few degrees Celsius. This lack of knowledge is further hampered by the lack of barium sulfate solubility data at the appropriate temperatures.
In this work, barium sulfate solubilities were measured in BaSO4-NaCl-H2O system at 5°C, in which sodium chloride concentrations ranged from 0 to 5 molal in the solutions. This new solubility data is presented in this paper in comparison with the published solubility data for 25°C and 95°C. Significant reduction in barium sulfate solubility from 25°C to 5°C (and even more from 95°C) was noted, which is more pronounced at higher solution ionic strength (NaCl molality). This paper then presents new results from a series of laboratory experiments that investigate the effect of a wide range of temperatures from 95°C to 5°C on barium sulfate scale precipitation and inhibitor efficacy. The inhibitor effectiveness is studied both dependent and independent of barium sulfate scaling tendency change. Both static jar tests and dynamic scale tube-blocking experiments were carried out. It is found that the apparent reduction or loss of inhibitor effectiveness at colder temperatures in a given brine, as seen in the static tests, is mostly due to increased barium sulfate scaling tendency as temperature decreases, while the inhibitor function may have changed little from one temperature to the other. The other interesting finding is that, although the supersaturation of barium sulfate increases considerably as temperature lowers, the kinetic rate of scale precipitation also slows down at colder temperatures. As a result, barium sulfate supersaturation is not the only driving force for it to precipitate, but temperature plays a role as well. This conflict between thermodynamic and kinetic effects of temperature cooling on barium sulfate scaling results in clearly different results between static scale inhibition tests and dynamic tube-blocking tests. That is, in a given brine, a scale inhibitor apparently performs better or equally at a lower temperature than at higher temperature in a flowing system, while apparently performs worse at lower temperatures in a static solution. Also, as far as barium sulfate inhibition is concerned, the two inhibitor chemistries included in this study did not correspond to temperature change or different test methods in exactly the same manner.
In the deepwater development and production of oil and gas fields, flow assurance both assumes a critical importance and involves technological challenges1,2. Mineral scale control is one of the flow assurance issues. One distinct feature in the deepwater that is relevant to scale formation and inhibition is the cold temperature environment in the subsea systems, where the seabed temperature is typically about 4°C3, where the produced fluids may get cooled to the seabed temperature in a long subsea flowline.
In order to fill the gap in barium sulfate solubility data in the literature that is relevant to deepwater subsea temperatures, barium sulfate solubilities were measured in BaSO4-NaCl-H2O system at 5°C, in which sodium chloride concentrations ranged from 0 to 5 molal.
The author et al. previously investigated barium sulfate scale formation and inhibition as a function of temperature, ranging from 95°C to 23°C4-5. It is found that, for a given brine, barium sulfate scaling tendency increases significantly as temperature decreases, and scale inhibitor effectiveness (expressed as %BaSO4 Inhibition) reduces correspondingly.
Methods of studying oilfield mineral scale deposition in the laboratory do not work for barium sulfate because only small nonadhering crystals are formed. On the other hand, barium sulfate scale found in down-hole or surface equipment is strongly adhering and may contain very large crystals. Results suggest that most of the difference derives from the extremely low solubility of barium sulfate. Firm adherence of scale and the consistent development of oriented crystals 100 microns and larger suggest a relationship between scale adherence and crystal growth. Data from this study indicate some reasons for barium sulfate's occurring as a deposit in oilfield waters. The unique characteristics as well as the associative properties of barium sulfate scale as related to calcium carbonate and calcium sulfate are shown.
The first observed deposition of barium sulfate scale in oilfield production equipment is unknown but probably coincides closely with the beginnings of the oil industry itself. Moore described barite oolites in some producing wells in the Saratoga field, Tex., in 1914. Currently, positive identification of barium sulfate deposition is recorded in most of the major oil-producing areas of the United States. As efforts continue to identify the composition and functions of the materials found in scale deposits. the geographic and economic importance of the part played by barium sulfate will become even more important. This belief is based on the following facts. 1. Many oil fields in the U. S. are in or entering their mature phase and the volume of produced water is increasing; thus, the cumulative effects of low-solubility minerals become more significant. 2. Secondary recovery techniques and increased emphasis on waste disposal systems require controlling the behavior of all constituents of water to prevent formation plugging. 3. The more general use of instrumental analysis has reduced the time and improved the accuracy of complete scale and water analysis. 4. Once formed, barium sulfate scale is resistant to present methods of chemical removal; therefore, costly mechanical methods are necessary. Thus, new methods of prevention and control will require specialized chemical techniques and better knowledge of the causes of scaling. Consider the results of some simulated field deposition studies illustrating this need (Fig. 1). The studies utilized a Scale Deposition Test Cell* and each coupon was exposed to 8,000 ml of a 300 me/liter solution of the various types of mineral scale. All tests were conducted at 140F. Only the calcium sulfate and calcium carbonate deposited scale. The solution containing 300 me/liter of barium sulfate exhibited copious amounts of precipitate, but none of the precipitate adhered. The fluids from the effluents were also allowed to impinge on glass slides. Fig. 1 shows the relative adherence of the three types of scale on unetched glass. The barium sulfate failed to deposit in the same manner as the calcium carbonate and calcium sulfate solutions.
Abdelgawad, Khaled (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Elkatatny, Salaheldin (King Fahd University of Petroleum & Minerals) | Patil, Shirish (King Fahd University of Petroleum & Minerals)
Abstract Barium Sulfate (Barite) is one of the common oil and gas field scales formed inside the production equipment and in the reservoir. Barite is also a common weighting material used during drilling oil and gas wells. Barium sulfate scale may exist as well in carbonate formations. The removal of barium sulfate from calcium carbonate formation is a challenging problem because of the solubility of calcium carbonate is higher compared to that of barium sulfate in different acids. In addition, barium sulfate is not soluble in the regular acids such as hydrochloric (HCl) acid and other organic acids. In this paper, the effect of calcium carbonate on barium sulfate solubility in a chelating agent and converter catalyst was investigated using solubility experiments at 80°C as a function of time. 20 wt.% DTPA with 6 wt.% potassium carbonate (converter) were used at pH of 12. The effect of calcium chelation on the barium sulfate solubility was studied in two scenarios. The first scenario when Barium sulfate is dissolved first then the solution reacts with calcium carbonate. The second scenario when both calcium carbonate and barium sulfate are exposed to the DTPA solution at the same time. In addition, the effect of calcium carbonate loading on the barium sulfate solubility was determined using 25, 50, 75, and 100 wt.% of the scale as calcium carbonate. As an evaluation criterion, inductively coupled plasma (ICP) was used to analyze the cation concentration and determine the solubility of each scale type. For the two scenarios of barium sulfate dissolution, the presence of calcium carbonate had a significant effect on the solubility of barium sulfate. When DTPA solution got saturated first with barium cations after 24 hours, and the addition of calcium carbonate to the solution will cause immediate barium drop of solution (concentration drop from 2140 to 1984 ppm in 30 min in 50 ml solution) which cause precipitation of barium sulfate. In addition, simultaneous chelation of both calcium carbonate and barium sulfate showed a low barium sulfate solubility compared to calcium carbonate. This can be explained by the high affinity of DTPA to calcium compared to barium. It is highly recommended to account for the presence of any calcium source during the design of the chemical formulation for barium sulfate scale removal using DTPA. Therefore, DTPA treatment formulation is recommended in sandstone formations. Field results can be completely different from laboratory results if Ca chelation from carbonate rocks is ignored.
Oddo, John E. (Water Research Institute, Inc.) | Zhou, Xinliang (Water Research Institute, Inc.) | Linz, David G. (Gas Research Institute) | He, Shiliang (Rice University) | Tomson, Mason B. (Rice University)
Some oil field scales have the potential to contain regulated levels of naturally occurring radioactive materials (NORM). It is estimated that between 300,000 and 1,000,000 tons of NORM scale are produced each year. In addition, scale deposition in producing facilities negatively impacts rates of production and is expensive to treat and remediate. The most common NORM containing scale is BaSO4, or barite. This paper presents the results of a Gas Research Institute study that investigates the causes of NORM scale formation and mitigation techniques employed in the field.
Chemical threshold scale inhibitors are generally employed to inhibit scale formation in production systems. However, there is little agreement on which scale inhibitor is most effective with respect to differing water chemistries, temperatures and conditions encountered. Results using a GRI patented inhibitor evaluation apparatus can be used to determine the most effective inhibitor for a specific field application. Work in the Michigan Basin presented in the last conference indicated that a phosphinopolycarboxylate was most effective against NORM barium sulfate scale formation at low temperatures in relatively fresh water. Further work in this study identifies phosphonates as being more effective in the higher ionic strength (TDS) waters and higher temperature regimes that can be expected in the Gulf Coast. A matrix of ionic strength and temperatures with inhibition response is presented.
Although more NORM fields were studied, two are presented in detail. In these fields, three causes of NORM scale were identified; 1) Incipient scale in a well due to production; 2) Scale formation due to previous seawater floods and; 3) The commingling of waters from different zones or wells. Field treatment techniques employed in the two fields studied are summarized in the paper.
Inhibitor squeeze procedures were also studied in the laboratory and in the field. A squeeze simulation apparatus was constructed to research inhibitor squeeze practices in the laboratory. Results from this work resulted in successful inhibitor squeeze applications in the field. The inhibitor squeeze apparatus and the field results are discussed in the paper. Squeeze life has been extended from an average of two to six months to two to three years or more as a result of the work.