Scaling behavior of mixed waters during the reinjection of fracturing flowback water and its impact on formation damage in the presence of scale inhibitors

Effect of scale and corrosion inhibitors on well productivity in reservoirs containing asphaltenes

Summary Field engineers and reservoir modelers often question if equilibrium conditions prevail downhole, and when do super(sub)saturation conditions exist. This questioning is especially critical in designing seawater injection for pressure maintenance caused by serious barite scale problems in barium-containing formation water. This paper: (1) discusses the experimental research on rock-brine interaction to determine if equilibrium conditions and kinetics prevail, and (2) develops realistic seawater/inhibitor injection schemes for scale control during seawater injection. We have examined the question from three points of view: (1) thermodynamic equilibrium, (2) mass transport kinetics, and (3) experimental testing of flow through columns with or without scale inhibitors. If the reaction direction is from undersaturated toward saturation, then equilibrium normally occurs rapidly, being observed within approximately 5 minutes. When the reaction is going from supersaturated to the equilibrium direction, such as during seawater injection into a barium-containing formation, the precipitation reaction is often slow (i.e., equilibrium is not observed after 10 minutes of contact time. Both barite dissolution and precipitation rates on clean core material are consistent with those reported in literature with a second order rate constants for dissolution (≈30,172 L2·mol−1·m−2·sec−1, 100°C) and precipitation (= 938 L2·mol−1·m−2·sec−1, 100°C). The kinetics of barite formation can significantly slow down in the presence of scale inhibitors, and the sulfate tolerance can be increased. The kinetics of both barite dissolution and precipitation are poorly understood at the present time. Combining sulfate reduction and scale-inhibitor application in intelligent engineering design can significantly reduce the problems and costs associated with seawater injection. Equations for the engineering design of such treatment were derived from nucleation kinetics, inhibition efficiency, and inhibitor adsorption and transport. Sulfate tolerance in the presence of scale inhibitors is measured and compared with the prediction from nucleation inhibition theory with excellent agreement. An innovative inhibitor treatment by way of coreflood has been done as proof-of-concept and is discussed herein.

The co-injection of corrosion and scale inhibitors is required for an oilfield in West Africa. The corrosion inhibitor efficiency test is systematically performed in presence of the selected scale inhibitor; however, the reverse is not performed; therefore, the impact of the corrosion inhibitor on the performance of the scale inhibitor is not known. This laboratory study investigates the performance and physical compatibilities of these two chemicals. Combinations of two corrosion inhibitors and two scale inhibitors were examined for sign of incompatibilities. These tests were conducted by diluting the neat chemical into test brines, at the designed dose rates. The brines were heated at temperatures between room temperatures (20°C) and the maximum field temperature (70°C). The two scale inhibitors were evaluated for compatibility with two corrosion inhibitors in dynamic calcium carbonate scale inhibition performance tests. By performing the tests in the presence of gradually decreasing concentrations of scale inhibitor, the minimum inhibitor concentration (MIC) is determined, following which the performance of the scale inhibitors was determined in the presence of the two corrosion inhibitors. The impact on corrosion inhibitors performance from the presence of the scale inhibitors, was determined using linear polarization resistance (LPR) bubble tests. No visible signs of incompatibility were observed between any of the scale and corrosion inhibitors in standard corrosion inhibitor / scale inhibitor compatibility bottle tests. Both scale inhibitors (SI1 and SI2) exhibited a loss of performance in the presence of corrosion inhibitor CI1, which increased minimum inhibitor concentration (MIC) rates determined in dynamic scale tests. Conversely, the corrosion inhibitor CI2 was found to have no impact on the scale inhibitors’ performance. While CL2 showed the better performance of the two corrosion inhibitors in linear polarization resistance (LPR) bubble tests, it did show a slight loss of performance in the presence of either scale inhibitor. Corrosion inhibitor CI1 exhibited poorer performance in corrosion test, with the scale inhibitor having no effect on the corrosion inhibitor’s effectiveness. The laboratory tests showed no couple scale and corrosion inhibitors with no impact on the efficiency both scale and corrosion inhibitors. Although, there are some impacts on the efficiency, these are either minor or small; apart from corrosion inhibitor CI1 which shows a significant increase in the dosage of the scale inhibitor SI2.

SummaryWaterflooding is known as an affordable method to enhance oil recovery after primary depletion. However, the chemical incompatibility between injected water and the water in the reservoir may cause the formation of mineral scales. The most effective method for managing such a problem is to use a variety of scale inhibitors (SIs) along with a waterflooding plan. It is necessary to perform a comprehensive study on the incompatibility scaling issue for the candidate-brine/SI formulations, and also their effect on the reservoir-rock/fluid characteristics. In this study, both in the absence and presence of polymeric, phosphonate, and polyphosphonate SIs, the scaling tendency (ST) of different brines is evaluated through experimental and simulation works. Drop-shape analysis (DSA), environmental-scanning-electronic-microscopy (ESEM) observation, energy-dispersive X-ray (EDX) analysis, and microemulsion phase behavior are also used to study the effect of different brine/SI formulations on the rock/fluid and fluid/fluid interactions, through wettability and interfacial-tension (IFT) evaluation. In summary, sulfate (SO42−) was identified as the most problematic ion in the formulation of injected water that causes the formation of solid scales upon mixing with the cation-rich formation water (FW). In the case of SIs, solid precipitation was shifted toward a lower value, with more pronounced effects at higher SI concentrations. At different ionic compositions, the inhibition efficiency (IE%) of all SIs ranged from 16 to 50% at [SI] = 20 ppm and 38 to 81% at [SI] = 50 ppm. In general, phosphonates worked better (i.e., higher IE value) than polymeric SI. Measuring contact angles along with ESEM/EDX data also illustrated the positive effect of SIs on the wettability alteration of the aged carbonate substrates. In the absence of SIs, the contact angles for different brines were in the range of 70° ≤ θ ≤ 104°, whereas these values fell between 35 and 80° for systems containing 50 ppm of SI. In addition, phase-behavior study and IFT measurement illustrated a salinity-dependence effect of SIs on the interfacial behavior of the oil/water system.

The thermodynamics of scale precipitations have been extensively studied over the past century but integrating kinetics is essential to accurately predict real behavior of produced fluids. This integration allows for a more comprehensive understanding of the dynamic processes that govern scale formation in practical applications. This work aims at improving the understanding of calcite scale precipitation and inhibition kinetics by modelling dynamic tube blocking test data using a new "scale kinetics and inhibition tool" (SKIT). By regressing a few selected parameters, as needed, it is possible to match experimental data for scale precipitation with and without the presence of scale inhibitor. The Mixed Solvent Electrolyte (MSE) thermodynamic model and Classical nucleation theory (CNT) are the basis of the predictions. The MSE model computes the driving force for precipitation whilst CNT predicts the induction time of the precipitate. The main limitation of any kinetic model is the limited published data on the precipitation kinetics, particularly in the presence of scale inhibitors. This problem is addressed here by adding a user function that enables the regression of proprietary experimental data to produce kinetic parameters specific to that experiments, scale inhibitor or field/plant condition. Dynamic tube blocking test data for calcite (CaCO3) precipitation at variable temperature, salinity, ionic composition and inhibitor concentration were used in this study. The measured induction times were inputs to the SKIT tool along with compositions and test conditions. Up to five kinetic parameters for calcite and two parameters for each dissociated form of the scale inhibitor were regressed to match experimental data. All newly regressed parameters were stored in a private database which was subsequently utilized to calculate scale induction times under specific well conditions, from downhole to separator, and to evaluate CaCO3 kinetics with and without inhibitors. The results guided the selection of optimal scale inhibitor concentrations for a chemical field trial. This work demonstrates, for the first time, how proprietary experimental data on scale inhibition can be utilized to create a private database for modeling the kinetics of scale precipitation and inhibition. Furthermore, it illustrates how this data can be leveraged to enhance the modeling of scale behavior in real field scenarios, ultimately guiding more informed decisions on strategizing scale management through optimal chemical injection concentrations.

In this work, the process of low salinity water injection (LSWI) into reservoirs at various salt concentrations was simulated in order to study the change in the oil recovery factor during oil production. The simulation results of the recovery factor were compared with the experimental data. The results demonstrated that the simulation data were in good agreement with the experimental results. In addition, the formation damage (rock permeability reduction) in carbonate core samples was evaluated through coreflood experiments during LSWI in the range of salt concentration and temperature of 1500–4000 ppm and 25–100 °C, respectively. In the worst scenario of LSWI, the rock permeability has reached about 83% of the initial value. Our previous correlation was used to predict the formation damage in LSWI. In this case, the R-squared value between predicted and experimental data of rock permeability ratios was more than 0.97. Furthermore, the recovery factor during LSWI was analyzed with and without the use of DTPMP scale inhibitor (diethylenetriamine penta (methylene phosphonic acid)), and various nanoparticles (TiO2, SiO2, Al2O3). The results of the coreflood experiments showed that the use of scale inhibitor provides an increase in the recovery factor by more than 8%. In addition, the highest recovery factor was observed in the presence of SiO2 nanoparticles at 0.05 wt.%. The oil displacement during LSWI in the porous media with SiO2 particles was better than TiO2 and Al2O3. The recovery factor in the presence of SiO2, TiO2, and Al2O3 with DTPMP was 72.2, 62.4, and 59.8%, respectively. Among the studied nanoparticles, the lowest values of the oil viscosity and interfacial tension (IFT) between oil and water were observed when using SiO2. Moreover, the contact angle was increased by increasing the brine concentration. The contact angle with the use of SiO2, TiO2, and Al2O3 at 0.05 wt.% was reduced by 11.2, 10.6, and 9.9%, respectively.

The formation of CaCO3 mineral scale is a persistent flow assurance problem in the oil and gas industry. It deposits at various locations with different levels from reservoir to topside flowline. It could restrict well intervention, block flowline and reduce production. To make an effective mitigation strategy, it is essential to understand the location and severity of scaling, and the performance of scale inhibitor under specific operation conditions. In the work reported herein, the dynamic scale loop tests were performed to evaluate the severity of scale deposition at different locations from the reservoir to transport flowline in the absence and in the presence of scale inhibitors under dynamic conditions. The tests are carried out at various temperatures (20-130°C) and pH (6.0-8.3), which are major factors contributing to calcium carbonate formation and representative of the operating conditions at different locations from reservoir to topside flowline. The results showed low calcium carbonate risk from reservoir to wellhead under tested conditions. Although the high reservoir temperature favors calcium carbonate formation in downhole, the low pH reduces the risk of calcium carbonate formation at downhole conditions. Harsher calcium carbonate deposition is evaluated at the conditions of phase separator/degasser units due to the higher pH of produced water after released CO2 from fluid. Calcium carbonate scale can also deposit in transport flowline, especially at high temperature during summer in the desert area, along with higher pH of the produced water. Calcium carbonate scale prevention and mitigation treatments are required to inhibit scale deposition. The tested phosphonate scale inhibitor provides low dose rate to effectively inhibit calcium carbonate formation at high temperature. The corrosion inhibitor could have a negative impact on the performance of scale inhibitor, and this must be considered when designing the scale inhibitor treatment. This paper gives a comprehensive study of scaling risk evaluation from downhole to topside flowline in the absence and in the presence of scale inhibitor. It contributes to the understanding of calcium carbonate formation and inhibition in the whole production system and recommends effective scale mitigation strategies.

The calcium and bicarbonate ions, present in the produced waters in the oilfields, are two major scaling ions in CaCO3 formation. In the last decade, a lot of studies have been focused on the thermodynamic or kinetics of CaCO3 formation, including the effects of scaling ions, temperature, pH, pCO2, etc. Seldom studies are focused on the kinetics of calcium carbonate surface deposition with different levels of calcium and bicarbonate, especially in the presence of scale inhibitors. In the work reported herein, dynamic loop tests were carried out to study the kinetics of CaCO3surface deposition in three typical produced waters (Water-1, high calcium and low bicarbonate; Water-2, medium calcium and medium bicarbonate; Water-3, low calcium and high bicarbonate) with same saturation index (SI) at 150°C. Typical scale inhibitor chemistries, including phosphonate, polycarboxylic, polymaleic, polysulphonate, polyacrylic, polyaspartate based scale inhibitors, have been tested in three tested waters. The following conclusions are drawn based on the test results. SI generated by applied prediction software is a parameter indicating the thermodynamic driving force. The kinetics of scale formation, more representative field conditions, should be studied as well to give a guideline of scale formation in the fields. Comparison of calcium, bicarbonate is the dominant kinetic factor for CaCO3 formation in the absence and presence of inhibitors. Higher bicarbonate water, higher minimum inhibitor concentration (MIC) is requested, even the three tested waters with a same SI. The ranking of the performance of scale inhibitor are dependent on the water chemistries and inhibitor chemistries. Some of the best ranking phosphonates in Water-1 and Water-2 with low and medium bicarbonate showed poor performance on Water-3 with high bicarbonate. Some polymers showed contrary ranking performance. This paper gives a comprehensive study of the kinetics of CaCO3surface deposition considering the effects of calcium and bicarbonate, including prediction, laboratory evaluation, mechanisms and inhibitor selection. It will contribute to understand the kinetics of CaCO3 formation and recommend effective inhibitors for field application. Environmentally acceptable inhibitors have been developed for different CaCO3 water chemistries at elevated temperature and are suitable for applications through squeeze treatment or continuous injection.

Field engineers and reservoir modelers often question if equilibrium conditions prevail downhole and when do super(sub)saturation conditions exist. This is especially critical in designing seawater injection for pressure maintenance due to serious barite scale problem in barium containing formation. The objective of this paper is (1) to discuss the experimental research on rock-brine interaction to determine when equilibrium condition prevail and when kinetics prevail; and (2) to develop realistic seawater/inhibitor injection schemes for scale control during seawater injection.We have examined the question from three points of view: 1. thermodynamic equilibrium; 2. mass transport kinetics; and 3. experimental testing of flow through columns with or without scale inhibitors. If the reaction direction is from undersaturated toward saturation, then equilibrium normally occurs rapidly. Equilibrium is observed within about 5 min. When the reaction is going from supersaturated to equilibrium direction, such as during seawater injection into a barium containing formation, the precipitation reaction is often slow, i.e., equilibrium is not observed after 10 min of contact time. Both barite dissolution and precipitation rates on clean core material are consistent with those reported in literature with a second order rate constants for dissolution (≈ 30,172 l2·mol-1·m-2·sec-1, 100 °C) and precipitation (= 938 l2·mol-1·m-2·sec-1, 100 °C).The kinetics of barite formation can significantly slow down in the presence of scale inhibitors and the sulfate tolerance can be increased. The kinetics of both barite dissolution and precipitation are poorly understood at the present time. It is proposed that combining sulfate reduction and scale inhibitor application in intelligent engineering design can significantly reduce the problems and costs associated with seawater injection. Equations for engineering design of such treatment were derived from nucleation kinetics, inhibition efficiency, and inhibitor adsorption and transport. Sulfate tolerance in the presence of scale inhibitors is measured and compared with the prediction from nucleation inhibition theory with excellent agreement. An innovative inhibitor treatment via core flood has been done as proof-of-concept and will be discussed.

In recent decades, the widespread implementation of horizontal drilling and multistage hydraulic fracturing in unconventional plays has increased the use of fresh water in oilfield operations. The formulation of fracturing fluids with non-fresh water sources such as seawater or produced water are attracting more attention due to the long term sustainability of non-fresh water use. Fracturing fluids using seawater are available in the industry. But the compatibility between the composition of local seawater and reservoir brine can add complication in the formation damage consideration. For example, if a seawater rich in sulfate comes in contact with formation brine rich in calcium or barium, severe scale can be expected if the proper caution is not taken. Treated seawater with nano-filtration to removal sulfate is a good practice to eliminate this problem. This paper describes a fracturing fluid formulated by using nanofiltered seawater for high temperature applications at 300 to 325°F. The crosslinked fracturing fluid formulation was optimized in the lab to accommodate the nanofiltered seawater, resulting in satisfactory fluid performance thereby enabling the fracturing operations to conserve fresh water. A high-temperature crosslinked fracturing fluid system was prepared with the nanofiltered local seawater. The fluid system showed robust stability at high temperatures. For example, the fluid viscosity stayed above 400 cP (at 100 sec−1 shear rate) for 2 hr at 300°F, with 45 ppt of the polymer loading. At 325°F, the fluid maintained viscosity above 300 cP for 2 hr with 60 ppt of the polymer loading. The nanofiltered seawater-based fluids was found to be compatible with a number of commonly used fluid additives including biocide, surfactant, and clay stabilizer. The fluid system also showed low formation damage and scaling tendencies. In the coreflow tests at 300°F, a regained permeability of greater than 95% was obtained. In the scaling tests without the presence of scale inhibitor at 300°F, traceable (<0.01 wt %) amount of scale was observed in the mixture of the nanofiltered seawater and high total dissolved solids (TDS) formation brine. Overall, it was found using the nanofiltered seawater can lead to better fluid stability at elevated temperatures, better fluid cleanup, and reduced downhole scaling tendency. By careful selection of the fluid components, the nanofiltered seawater-based fluid relieve the burden of needing fresh water for hydraulic fracturing treatment, allowing for a more sustainable approach. This paper discusses the technical functions of the key fluid additives used in the fracturing fluid preparation.

The formation of barium sulphate is a persistent problem affecting the oil and gas industry. Due to its high insolubility and resistance to chemical/mechanical treatment, it is difficult to remove when formed. Barium sulphate formation can be predicted using thermodynamic models; nevertheless it is imperative to understand the kinetics of barium sulphate in order to predict more accurately the rate at which these scales are being formed and to identify the correct remediation technique. Several research works have been conducted on the kinetics of barium sulphate both in bulk precipitation and on surface deposition; however these studies were often conducted in a closed system (e.g. bulk jar test) and measurements were taken off-line. In a closed system normally the saturation ratio decreases as function of the time as scaling occurs. In the current study an experimental set-up has been designed to study the kinetics of bulk and surface scaling processes in-situ, in an open system and measurements were taken in real-time. This work presents a kinetic study of barium sulphate with the absence and presence of scale inhibitors (diethylene triamine penta methylene phosphonic Acid (DETMP) and poly-phosphino carboxylic acid (PPCA)) on bulk precipitation and surface deposition. In the study, a turbidity probe was used to follow the bulk precipitation, whereas surface deposition was assessed by analysing image taken of the stainless steel surface at different time intervals.

Abstract. The formation of barium sulphate is a persistent problem affecting the oil and gas industry. Due to its high insolubility and resistance to chemical/mechanical treatment, it is difficult to remove when formed. Barium sulphate formation can be predicted using thermodynamic models; nevertheless it is imperative to understand the kinetics of barium sulphate in order to predict more accurately the rate at which these scales are being formed and to identify the correct remediation technique. Several research works have been conducted on the kinetics of barium sulphate both in bulk precipitation and on surface deposition; however these studies were often conducted in a closed system (e.g. bulk jar test) and measurements were taken off-line. In a closed system normally the saturation ratio decreases as function of the time as scaling occurs. In the current study an experimental set-up has been designed to study the kinetics of bulk and surface scaling processes in-situ, in an open system and measurements were taken in real-time. This work presents a kinetic study of barium sulphate with the absence and presence of scale inhibitors (diethylene triamine penta methylene phosphonic Acid (DETMP), vinylSulphonate acrylic acid co-polymer (VS-Co) and poly-phosphino carboxylic acid (PPCA)) on bulk precipitation and surface deposition. In the study, a turbidity probe was used to follow the bulk precipitation, whereas surface deposition was assessed by analysing image taken of the stainless steel surface at different time intervals.

Polymer based enhanced oil recovery (EOR) technology has drawn more and more attention in the oil and gas industry. The impacts of EOR polymer on scale formation and control are not well known yet. This research investigated the impacts of EOR polymer on calcite scale formation with and without the presence of scale inhibitors. Seven different types of scale inhibitors were tested, including four different phosphonate inhibitors and three different polymeric inhibitors. Test brines included severe and moderate calcite scaling brines. The severe calcite brine is to simulate alkaline surfactant polymer (ASP) flooding conditions with high pH and high carbonate concentration. The test method used was the 24 hours static bottle test. Visual observation and the residual calcium (Ca2+) concentration determination were conducted after bottle test finished. It was found that EOR polymer can serve as a scale inhibitor in moderate calcite scaling brines, although the required dosage was significantly higher than common scale inhibitors. Strong synergistic effects were observed between EOR polymer and phosphonate scale inhibitors on calcite control, which can significantly reduce scale inhibitor dosage and provides a solution for calcite control in ASP flooding. The impact of EOR polymer on polymeric scale inhibitors varied depending on polymer types. Antagonism was observed between EOR polymer and sulfonated copolymer inhibitor, while there was weak synergism between EOR polymer and acrylic copolymer inhibitors. Therefore, when selecting scale inhibitors for polymer flooding wells in the future, the impact of EOR polymer on scale inhibitor performance should be considered.

Zinc sulfide (ZnS) is an exotic scale formed in the oil and gas fields, especially in HT/HP wells. It is relatively difficult to test ZnS formation and inhibition in the laboratory using traditional static jar and dynamic loop tests due to the oxidization during the test and its naturally ‘soft’ scale characteristic. Limited studies have been focused on ZnS and the detailed inhibition mechanisms are still unknown.In this paper, a newly developed stress test method has been applied to evaluate the performance and mechanisms of ZnS inhibition. Compared with the traditional test methods, it shows good reproducibility and provides a quick and effective way to evaluate the performance of inhibitors and information to understand the mechanisms of inhibition.More than 15 typical scale inhibitors, representing several different types, have been tested using this newly developed method. The ZnS scale inhibitors were classified as three types based on the inhibition mechanisms from this work:Type 1: Dispersion and nucleation inhibitors. These scale inhibitors showed nucleation and growth inhibition effect at low concentrations of sulfide and dispersion effect at high concentrations of sulfide.Type 2: Nucleation and growth scale inhibitors. These scale inhibitors inhibit nucleation and growth of ZnS formation, where the test can be stressed further.Type 3: Scale inhibitors with poor performance on ZnS inhibition. The turbidity and stress curve did not change obviously in the presence of scale inhibitors.This paper will give a comprehensive study of ZnS formation and inhibition, including scale prediction, development of test method and inhibitors, insight into the mechanism of ZnS inhibition and identification of environmentally acceptable inhibitors.

Potential kinetic model for scaling and scale inhibition mechanism