Summary This paper discusses the effects of Ca2+, Mg2+, and Fe2+ on inhibitor retention and release. Better understanding of phosphonate reactions during inhibitor squeeze treatments has direct implication on how to design and improve scale inhibitor squeeze treatments for optimum scale control. Putting various amounts of metal ions in the inhibitor pill adds another degree of freedom in squeeze design, especially in controlling return concentrations and squeeze life. Phosphonate reactions during squeeze treatments involve a series of self-regulating reactions with calcite and other minerals. However, excess calcite does not improve the retention of phosphonate due to the surface poisoning effect of Ca2+. The squeeze can be designed so that maximum squeeze life is achieved by forming a low solubility phase in the formation. Addition of Ca2+, Mg2+, and Fe2+ in the pill solution at 0.1 to 1 molar ratios significantly improves the retention of phosphonate. Alternatively, these metal ions can be dissolved from the formation while an acidic inhibitor pill is in contact with the formation minerals. Both BHPMP and DTPMP returns were significantly extended by the addition of metal ions (e.g., Ca2+ and Fe2+). The addition of Mg2+ may increase the long-term return concentration, which is important for some wells where a higher inhibitor return concentration is needed. The laboratory squeeze simulations were compared to return data obtained from squeeze treatments performed on two wells located in a sandstone reservoir in Saudi Arabia. The sandstone formation contains significant amounts of iron-bearing minerals. Introduction Mineral scale formation is a persistent problem in oil and gas production, especially in older reservoirs with increased water production and drawdown. Inhibitor squeezes are commonly used to deposit a suitable scale inhibitor in the formation. During an inhibitor squeeze treatment, a predetermined volume of the inhibitor solution is pumped into the formation and followed by injecting another volume of brine or diesel to place the inhibitor further away from the wellbore and allowing it to react with the existing rock. During production following a squeeze treatment, the inhibitor is slowly desorbed or dissolved into the formation water. Earlier efforts have focused on describing what happens and when to resqueeze (Hong and Shuler 1988; Rogers et al. 1990). More recent papers have advanced the knowledge of inhibitor reactions under various production conditions (Benton et al. 1993; Sweeney and Cooper 1993; Lawless et al. 1993; Sorbie et al. 1994; Jordan et al. 1994; Jordan et al. 1995; Jordan et al. 1997; Lawless and Smith 1998; Smith et al. 2000; Collins 2003). The primary conclusions from several previous studies (Al-Thubaiti et al. 2004; Kan et al. 2004a; Kan et al. 2004b; Tomson et al. 2006) of NTMP(aminotri(methylene phosphonic acid))-calcite reaction are:The extent of NTMP retention by carbonate-rich formation rock is limited by the amount of calcite that can dissolve prior to inhibitor-induced surface poisoning;calcite-surface poisoning effect is observed after approximately 20 molecular layers of phosphonate surface coverage that retards further calcite dissolution; andthe consequence of retarded calcite dissolution is that less basic ion, CO2-3, is released into solution, leaving the solution more acidic; therefore, more soluble calcium phosphonate solid phases form. The inhibitor return concentration can be altered by changing the inhibitor concentration in the pill. The ability to control the high inhibitor return may be useful in initial water breakthrough where high inhibitor return is desired. Kan et al. (2005) also compared the retention of NTMP, DTPMP (diethylenetriamine penta (methylene phosphonic acid)), BHPMP (bis-hexamethylenetriamine penta (methylene phosphonic acid)), and PPCA (phosphinopolycarboxylic acid) with pure calcite, a calcite-rich chalk rock, a calcite and clay-rich formation rock from Guerra Ranch, McAllen, Texas, and a quartz sandstone with very little calcite from Frio formation, Galveston County, Texas. Similar inhibitor returns were observed in both calcite-rich and low-calcite rock, suggesting that calcite is the primary solid responsible for phosphonate retention. Clays or other minerals play a secondary role in phosphonate retention. The retention of the polymer-based inhibitors is much lower than phosphonates. The data show that BHPMP provides the highest squeeze life at MIC > 50 mg/L. DTPMP is the preferred inhibitor at MIC between 1 and 50 mg/L and NTMP is the preferred inhibitor at MIC < 0.3 mg/L. Calcium ion (Ca2+) is the predominant divalent metal ion in most oilfield produced waters. Previously, several reports indicated that Ca2+ and Mg2+ have a strong effect on inhibition of barite by common inhibitors (Fernandez-Diaz et al. 1990; Boak et al. 1999; Collins 1999). Collins (1999) observed a clear change in crystal habit between barite growth in the presence and absence of Ca. Xiao et al. (2001) noted that Ca significantly enhanced the inhibitor efficiency; however, Ca had no effect on barite nucleation time in the absence of scale inhibitor. Collins (1999) reported a similar effect of Ca with polyaspartate as a barite inhibitor. The enhanced inhibition efficiency may be attributed to the reduction of net negative charge of the polyion due to complexation of the polyaspartate with divalent cations (Tomson et al. 2003). In the present paper, the influence of metal ions, e.g., Ca2+, Mg2+, and Fe2+ on the inhibitor retention and release was evaluated in both laboratory simulation and field case studies. These metal ions were either originally added to the inhibitor pill solutions or generated in-situ because of the dissolution of reservoir minerals by acidic inhibitors.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper discusses the effects of Ca 2+ , Mg 2+ , and Fe 2+ on inhibitor retention and release. Better understanding of phosphonate reactions during inhibitor squeeze treatments has direct implication on how to design and improve scale inhibitor squeeze treatments for optimum scale control. Putting various amounts of metal ions in the inhibitor pill adds another degree of freedom in squeeze design, especially in controlling return concentrations and squeeze life.Phosphonate reactions during squeeze treatments involve a series of self-regulating reactions with calcite and other minerals. However, excess calcite does not improve the retention of phosphonate due to the surface poisoning effect of Ca 2+ . The squeeze can be designed so that maximum squeeze life is achieved by forming a low solubility phase in the formation. Addition of Ca 2+ , Mg 2+ , and Fe 2+ in the pill solution at 0.1 to 1 molar ratios significantly improves the retention of phosphonate. Alternatively, these metal ions can be dissolved from the formation while an acidic inhibitor pill is in contact with the formation minerals. Both BHPMP and DTPMP returns were significantly extended by the addition of metal ions, e.g. Ca 2+ and Fe 2+ . The addition of Mg 2+ may increase the long-term return concentration, which is important for some wells where a higher inhibitor return concentration is needed.The laboratory squeeze simulations were compared to two field return data obtained from squeeze treatments performed on two wells located in a sandstone reservoir in Saudi Arabia. The sandstone formation contains significant amounts of ironbearing minerals.
Calcium carbonate scale was detected in several vertical wells in a sandstone reservoir in Saudi Arabia. The scale was detected downhole, plugging gravel packing screens and the intake of submersible pumps. Scale build up caused significant decline in oil production from this field. The sandstone reservoir is water-sensitive and has a bottom hole temperature of 160°F. An emulsified scale inhibitor (phosphonate-type) treatment was designed to mitigate scale in this field. Recently, Nasr-El-Din et al.1 discussed the development of this new treatment and reported initial field results. So far the treatment was successfully applied in more than twenty wells. Some of these wells were de-scaled before the treatment, while other wells were treated before scale detection. The objectives of the present paper are to assess the outcome of this treatment based on field data and to optimize the scale squeeze treatment based on the analysis of well flow back samples. Samples of produced water from these wells were collected and analyzed for nearly three years. Results, Observations, Conclusions The scale treatment was successfully conducted in more than twenty wells with various water cuts. No scale was detected in any of the treated wells for nearly three years. No significant decline in oil production was observed. Based on field data, it is known that the treatment lifetime is greater than two years and is estimated to be 3–4 years. Application This paper describes fieldwork done to optimize the performance of a novel emulsified scale squeeze treatment in a sandstone reservoir. It also discusses the importance of well flow back analysis and how it can be used to enhance the outcome of a scale squeeze treatment. The emulsified chemical was successful in meeting the main objective of the treatment, i.e., providing scale mitigation for greater than three years, while maintaining the integrity of the formation. Technical Contributions
A critical challenge facing the integrity of many assets throughout the oil and gas industry is directly related to corrosion under insulation (CUI). Unfortunately, the lack of adequate inspection technologies adds to this well-known industrial challenge. Presented in this paper is an inspection tool enhanced using Artificial Intelligence (AI) that can provide field inspection engineers with a facility heat map of insulated asset integrity allowing inspection prioritization. The approach used in this research, and presented here, was to enhance the output of already known and field approved thermographic technologies using a purpose built AI based on Machine Learning (ML). By examining the progression of thermal images, captured over time (<20 minutes), corrosion and factors that cause this degradation are predicted by extracting thermal anomaly features and correlating them with corrosion and irregularities in the structural integrity of assets verified visually during the initial learning phase of the ML algorithm. Additional benefits to this technique include enhanced safety through remote inspection and additional cost savings from monitoring assets online. To develop and verify the CUI technology results from in-house laboratory tests followed by field validation outcomes will be presented. Laboratory trials were carried out using a series of insulated field assets with different levels of degradation and structural integrity set up to mimic the thermal behavior of in-process assets. This initial feasibility study allowed the definition of key parameters required to build an effective ML model. Following in-house trials a series of field tests and visual verification was performed on both hot and cold insulated assets to gather a sufficient amount of datasets to train the predictive algorithm. To enhance this learning process, synthetic data was created based on real field asset configurations and operating parameters. Finally, during the technology validation phase, again on field assets, the AI technique coupled with a commercial field approved thermographic camera returned a predictive accuracy in the range of 85 – 90%. The work presented in this paper provides a solution for the current lack of technologies to monitor the presence of CUI by enabling and enhancing the output from already known and field approved technologies, such as thermography, using AI. Additional benefits of this approach include safety enhancement through non-contact online inspection and cost savings by reducing the complexity of asset preparation (scaffolding) and downtime.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractHorizontal, extended-reach, and multi-lateral wells are drilled to maximize production from oil and gas reservoirs. Treating these wells with scale inhibitor is a real challenge. This is mainly due to reservoir heterogeneity and chemical placement.Several horizontal wells were drilled in a sandstone oil reservoir. These wells were completed with 1,000 to 1,500 ft of pre-packed screens and produced wet crude with water-cut ranging from 5 to 30 vol%. The total dissolved solids of the produced water was nearly 8,000 mg/L. The bottom hole temperature is 152°F. The porosity varied from 5 to 30 vol%, whereas the permeability varied from 1 to 3,000 md.Calcium carbonate scale was detected downhole due to temperature and pressure changes that occur at the intake of the electrical submersible pumps. The scale was removed by an acid treatment. However, there was a need to develop a chemical treatment to mitigate scale in these horizontal wells.An emulsified scale inhibitor squeeze treatment was developed and applied in several horizontal wells in the sandstone reservoir. The emulsified inhibitor has high viscosity which decreases with the shear rate (shear thinning behavior). These rheological properties enhanced placement of the inhibitor across the target zone. Coiled tubing was also used to place the emulsified inhibitor, which also enhanced the placement of the inhibitor across the target zone. The treatments were successfully applied and no operational problems were encountered. Oil production and water-cut did not change as a result of the scale inhibitor (phosphonate-type) squeeze treatment. This paper will discuss the design of the emulsified scale inhibitor squeeze treatment, field application, and analysis of produced fluids.
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