Synthesis of HEDP/PMMA Submicron Capsules for Long-Term Scale Inhibition in Oil Reservoirs

In typical bulk barite inhibition efficiency (IE) experiments testing scale inhibitors (SI), the IE is determined by comparing the concentrations of the barium ion in the mix to that in an uninhibited "blank" solution. That is, [Ba2+] vs. time is monitored for both a blank and an inhibited solution. The fate of the scale inhibitor itself over this test time period is rarely monitored although this can give some important insights into the inhibition mechanism. This paper presents a series of long-term (up to 96 hour) barium sulphate static inhibition efficiency (IE) experiments in which both the supernatant scale inhibitor concentration, [SI], and [Ba2+] are assayed at multiple sampling times after initial mixing of sea water (SW) and formation water (FW) brines. In standard IE tests to determine SI minimum inhibitor concentration (MIC), sampling is normally carried out at 2 hours and 22 hours only. The long-term IE experiments described in this paper involve up to eleven sampling times, typically at t = 0.5, 1, 2, 3, 4, 5, 6, 22, 48, 72 and 96 hours after mixing. The aim of this type of experiment is to determine the fate of the SI over time, and secondly, to determine whether the IE and %SI in solution versus time profiles correlate with each other. Clearly, SI removed from solution is consumed into the forming barium sulphate lattice in the barite precipitate. IE and solution SI often continue to decline beyond 22 hours, up to 96 hours after the mixing stage. In these experiments, the SI concentration is set at a pre-2 hour MIC threshold concentration, such that the IE and %SI consumption profiles will both decline sufficiently over time, possibly even as early as 0.5 hour after mixing. The SI consumption profiles obtained testing an extensive range of phosphonate and polymeric SIs are compared and discussed. Normally a phosphorus-containing SI is selected for evaluation, to facilitate assay of SI by means of inductively coupled plasma (ICP) spectroscopy. However, intriguing results are also presented where selected polymeric SIs were assayed by non-ICP analytical techniques. We interpret this extensive series of SI lattice consumption experiments in terms of the mechanisms of barite inhibition and Type 1 / Type 2 SI classifications presented in previous papers (Shaw et al., 2012a, 2012b).

The formation of mineral scale is a complex problem during the oilfield operations. Scale inhibitors are widely used to prevent salt precipitation within reservoirs, in downhole equipment, and in production facilities. The scale inhibitors not only must have high effectiveness to prevent scale formation, but also have good adsorption–desorption characteristics, which determine the operation duration of the scale inhibitors. This work is focused on the development of a new scale inhibitor for preventing calcium carbonate formation in three different synthetic formation waters. Scale inhibition efficiency, optical density of the solution, induction time of calcium carbonate formation, corrosion activity, and adsorption–desorption ability were investigated for the developed scale inhibitor. The optimum concentration of hydrochloric acid in the inhibitor was determined by surface tension measurement on the boundary layer between oil and the aqueous scale inhibitor solution. The results show that the optimum mass percentage of 5 % hydrochloric acid solution in the inhibitor was in the range of 8 % to 10 %. The new scale inhibitor had high efficiency at a concentration of 30 mg/L. The results indicate that the induction period for calcium carbonate nucleation in the presence of the new inhibitor was about 3.5 times longer than the value in the absence of the inhibitors. During the desorption process at reservoir conditions, the number of pore volumes injected into the carbonate core for the developed inhibitor was significantly greater than the volume of a tested industrial inhibitor, showing better adsorption/desorption capacity.

Scale inhibitor "squeeze" treatments are used extensively to control problems with downhole carbonate and sulphate scale formation. The return curve from an adsorption/desorption squeeze is governed by the inhibitor/rock interaction which, in turn, is described by the adsorption isotherm. Several factors, such as pH, [Ca2+], temperature, rock mineralogy etc, affect the adsorption level and the shape of the adsorption isotherm. However, these same factors may also lead to deleterious effects in terms of both formation damage and inhibitor solution effectiveness; the latter effect is referred to in this work as "fluid damage". In this paper, results and discussion are presented on the potential for formation damage and inhibitor fluid damage when acid phosphonates are applied in clastic reservoir formations. Results are presented from an extensive series of phosphonate (DETPMP) scale inhibitor core flooding experiments using Brent Group (North Sea) sandstone cores as the adsorbing substrate. Careful effluent analysis along with detailed petrography and permeability measurement before and after core flooding are shown to be invaluable in assessing the degree of formation damage (and "fluid damage") arising due to several factors. Most of the points raised here are quite general and they are illustrated by the specific field results. This work therefore contributes to the development of safer field applications of scale inhibitor squeeze treatments in the light of individual reservoir petrography.

Study of adsorption/desorption properties of a new scale inhibitor package to prevent calcium carbonate formation during water injection in oil reservoirs

Increasing efficiency of calcium sulfate scale prevention using a new mixture of phosphonate scale inhibitors during waterflooding

Horizontal, 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.

Summary Shale formations are one of the unconventional reservoirs, development and operation of which requires special technologies. Waterflooding can be used for improving recovery factor in the shale reservoirs under specific conditions. Inorganic salt precipitation can occur during water injection into shale reservoir depending on the pressure and temperature. Scale formation reduces rock permeability, and damages the production equipment. In this work, prediction of barium sulfate scale deposits was investigated at different reservoir pressures (0.1 to 70 MPa) and temperatures (40°C to 150°C). The scaling tendency of barium sulfate was increased by increasing pressure and decreasing temperature. However, temperature did not affect the amount of salt precipitation. In addition, scale inhibition was studied using five different scale inhibitors under static and dynamic conditions. One of them is a new scale inhibitor package. The experimental results showed that the new scale inhibitor had the highest inhibition performance (more than 90%). Temperature and mixing ratio had a negligible effect on the scaling inhibition efficiency. The minimum inhibitory concentration of the new inhibitor package was 25 mg/L. Also, the new inhibitor had an enhanced adsorption and desorption rate on the shale rocks.

Summary The deposition of inorganic salts in the bottomhole formation zone and on the surface of the oilfield equipment causes a reduction in the well production rate, service life and the rock permeability. The precipitation of calcium sulfate often occurs when mixing incompatible waters during waterflooding of reservoirs. In this work, conditions for the precipitation of calcium sulfate were determined depending on the reservoir conditions and the volume ratio of the injection and formation waters. The effects of reservoir temperature and pressure on the formation of calcium sulfate scale were studied. The results of scale prediction showed that with increasing temperature and decreasing pressure, the amount of forming calcium sulfate is significantly increased. To analyze the inhibition efficiency of calcium sulfate under static conditions, five different scale inhibitors were used. Results of studies on the evaluation of the efficiency of the developed scale inhibitor and industrial scale inhibitors under static and dynamic conditions were presented. The developed scale inhibitor has the highest efficiency for preventing the calcium sulfate scale formation at a concentration of 30 mg/L. Despite the decrease in solubility of calcium sulfate with increasing temperature, the effectiveness of the developed inhibitor does not significantly decrease with increasing temperature.

Summary In typical bulk barite inhibition-efficiency (IE) experiments testing scale inhibitors (SIs), the IE is determined by comparing the concentrations of the barium ion in the mix to that in an uninhibited "blank" solution. That is, [Ba2+] vs. time is monitored for both a blank and an inhibited solution. The fate of the SI itself over this test time period is rarely monitored, although this can give some important insights into the inhibition mechanism. This paper presents a series of long-term (up to 96 hours) barium sulfate static IE experiments in which both the supernatant SI concentration, [SI], and [Ba2+] are assayed at multiple sampling times after initial mixing of seawater (SW) and formation-water (FW) brines. In standard IE tests to determine SI minimum inhibitor concentration (MIC), sampling is normally carried out at 2 hours and 22 hours only. The long-term IE experiments described in this paper involve up to eleven sampling times, typically at t = 0.5, 1, 2, 3, 4, 5, 6, 22, 48, 72, and 96 hours after mixing. The aim of this type of experiment is to determine the fate of the SI over time and to determine whether the IE and percentage of SI (%SI) in solution vs. time profiles correlate with each other. Clearly, SI removed from solution is consumed into the forming barium sulfate lattice in the barite precipitate. IE and solution SI often continue to decline beyond 22 hours, up to 96 hours after the mixing stage. In these experiments, the SI concentration is set at a pre-2-hour MIC threshold concentration, such that the IE and %SI consumption profiles will both decline sufficiently over time, possibly even as early as one-half hour after mixing. The SI consumption profiles obtained by testing an extensive range of phosphonate and polymeric SIs are compared and discussed. Normally, a phosphorus-containing SI is selected for evaluation to facilitate assay of SI by means of inductively coupled plasma (ICP) spectroscopy. However, some novel results are also presented in which selected polymeric SIs were assayed by non-ICP analytical techniques. We interpret this extensive series of SI lattice-consumption experiments in terms of the mechanisms of barite inhibition and Type 1/Type 2 SI classifications presented in previous papers (Shaw et al. 2012a, b). The relevance and practical application of these findings are also discussed.

Time dependent anti-corrosion and anti-scaling efficiency of polyepoxysuccinic acid inhibitor in simulated hard water

This paper presents a case study of improving scale inhibition treatments in the Sharon Ridge Canyon Unit (SRCU), West Texas in response to the increased scaling conditions that has arisen from carbon dioxide (CO2) injection into the oil reservoir. In anticipation of increased scale deposition, a proactive approach was taken by carrying out a comprehensive field system analysis and scale survey prior to the commencement of CO2 flooding at SRCU. This analysis/survey was intended to assess the new situation and come up with a cost effective scale treatment program. A laboratory evaluation of a number of scale inhibitors was then carried out. Based on our understanding of the problem and the lab evaluation results, a new scale inhibitor and a new chemical treatment program were developed and implemented in the field. This paper describes the system analysis/scale survey and highlights its importance in understanding the changing situation and the new challenges in scale inhibition arising from CO2 flood. The laboratory evaluation for identifying the most suitable and cost-effective inhibitor is then briefly described. The paper then discusses the new scale inhibition treatment program and scale monitoring program. The field results from implementing the new treatment program are presented and discussed. Owing to the proactive approach and the improved inhibitor and treatment, the field production system and water re-injection system have not been troubled with scale deposition.

Understanding the mechanisms of scale inhibitor (SI) retention in carbonate formations is key to designing efficient SI “squeeze” treatments in oil reservoirs. By performing “apparent adsorption” e...

In oil reservoirs, changes in conditions (such as pH, pressure, and temperature.) of brine and formation water cause various minerals to precipitate out and to form inorganic scale. One of the most effective methods for preventing mineral scale formation in oilfields is downhole injection of chemical scale inhibitors. This study focused on the calcium divalent cation which forms calcium carbonate scale. 1-Hydroxyethylidene-1,1-diphosphonic acid (HEDP) was used as a scale inhibitor because HEDP can combine with Ca2+ to form Ca2+/HEDP precipitates. There are two distinct types of Ca2+/HEDP precipitates: spindle 1:1 and spherical 2:1 types which form at pH=2.0 and 6.0, respectively. The experimental results showed that 1:1 Ca2+/HEDP precipitate transformed to 2:1 precipitate in saturated solution of pH=6.0. Similarly, 2:1 Ca2+/HEDP precipitate placed in a saturated solution of pH=2.0 transformed to the 1: precipitate. Dissolution experiments were conducted using both high and low calcium formation water in a differential reactor. The results showed that the high calcium formation water dissolved the precipitate slower than the low calcium formation water. The results of micromodel experiments showed similar trends of dissolution rate along with the visual observations of the elution process.

This paper was prepared for the Oilfield Chemistry Symposium of the Society of Petroleum Engineers of AIME, to be held in Denver, Colo., May 24–25, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Chemical reactions in an oil reservoir are often an unknown and can only be simulated in the laboratory. One aid in correlating downhole reactions with lab tests is analysis of returned treating fluids from the reservoir. Analytical chemistry provides powerful tools for monitoring oil well treating chemicals. Visible absorption spectrophotometry provides methods for cationic, anionic and nonionic surfactants as well as for acrylate- and phosphorus-based scale inhibitors. It is useful for measuring sequestrant concentrations from their reactions with metal ions, alcohols by chromate reduction, arsenic-based acidizing inhibitors, nitrogen-based downhole inhibitors, polyacryldemide- and carbohydrate-based fracturing and inverting chemicals. Ultraviolet spectrophot metry is well suited to the measurement of cement-setting retarder concentrations and organic acidizing inhibitors. Gas-liquid chromatography measures nonreactive solvent concentrations and acetylenic alcohols used in acidizing inhibitors. Direct titrimetric analysis can be applied to organophosphonate scale inhibitors, iron (III) sequestrants such as NTA, reactive solvents such as the inorganic acids and EDTA. Titration of reaction products permits the measurement of cationic surfactants permits the measurement of cationic surfactants following their reaction with eosin and glycols after their reaction with periodic acid. Specific ion electrodes are particularly useful for the determination of fluoride. Introduction Chemical reactions during well treatment are studied in the laboratory under conditions simulating those existing in the well. Further insight is gained by analyzing returned treating fluids. During acidizing, how completely does the acid spend? How much inhibitor is left in the returned fluids? Were fluid loss additives present in designed amounts? Do the returned present in designed amounts? Do the returned fluids contain natural formation fluids also? These are examples of many questions which arise from treating oil or gas wells. It is our purpose here to emphasize the analytical chemistry purpose here to emphasize the analytical chemistry involved in monitoring treating chemicals in returned well fluids. We have not intended to be exhaustive in our treatment of the subject but wish to show the types of treating chemicals which have been monitored by visible and ultraviolet absorption spectrophotometry, gas-liquid chromatography, direct and indirect titrimetry, and specific ion potentiometry.

The production of oil and natural gas has a great impact on modern industry, but a large amount of produced water is generated during the oilfield development process, especially for large-scale oilfield. The water production in the produced liquid gradually increases, and direct discharge of produced water can have adverse effects on the environment, which has become a serious concern. With the long-term stable production of oilfields achieved by these operators in the Middle East through water injection development, the shortage of injection water sources and the urgent need for water injection to maintain pressure in oil reservoirs, the high investment treatment costs for produced water with high hydrogen sulfide content, and the compatibility between produced water re-injection and reservoir compatibility have become prominent issues. It is urgent to maximize the economic benefits of oil fields and meet the environmental protection requirements of countries. The paper focuses on the challenges and bottlenecks encountered in the re-injection of produced water in the D oilfield with high hydrogen sulfide content in the Middle East. Based on indoor core experiments, production performance analysis, wellbore corrosion monitoring, and differentiated injection allocation, an optimization strategy and design plan for re-injection of produced water are proposed. In the paper, the parameters and characteristics of different water qualities were determined through indoor experiments for the available water resources in the oilfield. It was clarified that the produced water is high in salinity, chloride ion content, sulfide content, and oil content, while the fresh water is oxygen and bacteria containing. The mechanism and reasons for the decrease in injectivity and corrosion of wellbore and surface pipelines caused by early implementation of produced water re-injection were analyzed. The paper proposes an optimization method for fresh and produced water injection based on reservoir physical properties, H2S content, reservoir type, and production performance. An integrated fresh and produced water injection plan is designed. High hydrogen sulfide and low permeability reservoirs are connected to fresh water pipelines, and low H2S and medium high permeability reservoirs are treated with produced water and re-injected, combined with new anti-corrosion pipes to suppress corrosion in the surface injection system. The optimization strategy and technical Roadmap in the paper has been applied in D oilfield, which can avoid pipeline corrosion and formation pollution, reduce the complexity of injected water quality, meet the water quality requirements of poor physical properties layers, and play the role of low salinity water in improving oil recovery in low permeability reservoirs. It is beneficial for corrosion prevention and scale inhibition, full utilization of produced water, and maintaining the injection capacity of water injection wells, achieving the goals of good water injection development effect and low investment cost. Most carbonate reservoirs in the Middle East contain hydrogen sulfide and lack fresh water sources. D oilfield improved the development effect of low permeability reservoirs, reduces corrosion and the cost of OPEX through optimisation and application of produced water re-injection. This study has good reference significance for similar oilfield produced water re-injection programs.