Evaluating the Effectiveness of Red Onion Skin Extract Derivatives as Oilfield Scale Inhibitors

With growing awareness of the environmental impact of some conventional production chemicals and concerns about the depletion of non-renewable natural resources, increased efforts are being made to use renewable and non-toxic materials in the oilfield. In this study, a potential green scale inhibitor was developed from the skin of red onions and evaluated for calcium sulphate, calcium carbonate and barium scale inhibition. Based on the different extraction processes utilized, two products were obtained and characterized using FTIR and SEM and evaluated using a static jar test procedure. The FTIR results confirmed the bands that make up the major constituents (quercetin) and other important compounds, which supports the present study. Laboratory evaluation show that ROSE can efficiently inhibit calcium sulphate scale and barium sulphate scales with a good inhibition rate of greater than 75% at an optimum dosage. Effect of temperature and dosage on inhibition performance revealed that ROSE is stable at higher temperatures and can effectively inhibit calcium and barium sulphate scales at nearly the same rate without degradation but requires additional dosage to produce same result for calcium carbonate scale. Also, the effect of time reveals that scale inhibitor performs a continuous CaSO4 and CaCO3 inhibition. Not only does ROSE perform excellently in the laboratory condition as a green scale inhibitor, but it also show a relatively close performance rate when compared to an existing commercial inhibitor which indicate that ROSE has a high potential for use in the oil industry.

The Evolution of CaCO3 Scaling Potential in ADNOC Reservoirs Under Water Flooding and CO2 WAG Scenarios

Wells producing from an oilfield in Abu Dhabi were investigated to understand the CaCO3 scaling risk at current production conditions, and to predict how the downhole and topside scaling potential will change during a planned CO2 WAG project. The results of this study will be used to design the correct scale inhibitor treatment for each production phase. A rigorous scale prediction procedure for pH dependent scales previously published by the authors was applied using a commercial integrated PVT and aqueous modelling software package to produce scale prediction profiles through the system. This procedure was applied to run many sensitivity studies and determine the impact of field data variables on the final scale predictions. These results were used to examine the scaling potential of current and future fluids by creating a diagnostic "what if" chart. Some of the main variables investigated include changes in operating pressure, CO2 and H2S concentrations and variable water cut. Scale prediction profiles through the entire system from reservoir to stock tank conditions were obtained using the above modelling procedure. The main findings in this study are: (i) That CaCO3 scale is not predicted to form at separator conditions under any of the current or future scenarios investigated for these wells. This is due to the high separator pressure which holds enough CO2 in solution to keep the pH low and prevent scale precipitation. (ii) The water at stock tank conditions was found to be the critical point in the system where the CaCO3 scaling risk is severe, and where preventative action must be taken. (iii) Implementing CO2 WAG does not affect CaCO3 scaling risk at separator conditions where fluids remain undersaturated. However, the additional CO2 dissolves more CaCO3 rock in the reservoir producing higher alkalinity fluids which result in more CaCO3 scale precipitation at stock tank conditions. (iv) Fluids entering the wellbore are likely to precipitate some CaCO3 (albeit at a fairly low saturation ratio, SR) due to a significant pressure drop and the relatively high temperature, and this is not associated with the-bubble point in this case. This downhole scaling potential becomes slightly worse by an increase in CO2 concentration during CO2 WAG operations.(v) Scale inhibitor may or may not be required to treat downhole fluids depending on the wellbore pressure drop, but it is always necessary to treat fluids downstream of the separator due to the very high scaling potential at stock tank conditions. By applying a rigorous scale prediction procedure, it was possible to study the impact of CO2 WAG on the risk of CaCO3 scale precipitation downhole and topside for this field. These results highlight the current threat downhole and at stock tank conditions in particular and show how this will worsen with the implementation of CO2 WAG and this will require a chemical treatment review.

Scale Control for Long Term Well and Facility Preservation

Oilfield scale and corrosion at oil and gas wells and topside facilities are well known problems. There are many studies towards the control and mitigation of scaling risk during production. However, there has been limited research conducted to investigate the effectiveness of scale control approaches for the preservation of wells and facility during a potential long term shut-in period, which could last more than 6 months. Due to low oil price and harsh economic environment, the need to shut-in wells and facilities can become necessary for operations. Understanding of scale control for a long term period is important to ensure both subsurface and surface production integrity during the shut-in period. The right strategy and treatment approaches in scale management will reduce reservoir and facility damage as well as the resulting cost for mitigation. In this paper, we will review and assess the scale risk for different scenarios for operation shut-in periods and utilize laboratory study to improve the understanding of long-term impact and identify appropriate mitigation strategy. Simulated brine compositions from both conventional and unconventional fields are tested. Commercially available scale inhibitors are used for testing. Various conditions including temperature (131-171 °F), saturation index (1.28-1.73), pH (7.04-8.03) and ratio of scaling ions are evaluated. The tested inhibitor dosage range was 0-300 mg/L. Inhibitor-brine incompatibility was also investigated. Sulfate and carbonate scales such as barium sulfate, strontium sulfate and calcium carbonate are studied as example. This paper will provide an important guidance for the management of well shut- in scenarios for the industry, for both conventional and unconventional fields. Performance of two scale inhibitors for same water composition are demonstrated. The efficiency of scale inhibitor #2 is lower than that of inhibitor #1. A linear correlation is observed for long term scale inhibitor performance in this case. Protection time is thus predicted from data collected from the first 8-week experiments. The predicted protection time at 250 mg/L of inhibitor A and B is 100 weeks and 16 weeks respectively. The actual protection time will be compared to the predicted value. The inhibitor-rock interaction has also been preliminarily studied. The effects of inhibitor adsorption onto formation rock should be considered for chemical treatment design and performance/dosage optimization. This study provides novel information of scale control in a much longer time frame (up to 6 months). Various parameters may have effects on their long term control. Results will benefit the chemical selection and evaluation for long term well shut-in scenario. In addition, brine-inhibitor compatibility is evaluated simultaneously.

Dry Cationic Friction Reducers: New Alternative for High TDS Slickwater

Currently, well stimulation in North America has evolved almost entirely to slickwater fracturing with friction reducers (FRs). Some parts of North America are notorious for their poor water quality, so wells are commonly treated using high total dissolved solids (TDS)-containing flow-back or produced water. Cationic FRs are usually applied in these systems due to their tolerance to multivalent cations in such waters. Additionally, dry friction reducers have gained momentum for better economics and logistics. In this paper, a dry cationic FR is systematically studied with respect to its "on the fly" hydration capability, friction reduction, mechanical stability, compatibility with other anionic chemical additives, and thermal stability in different levels of TDS brines. The cationic FR solution was subjected to varying shearing rates to understand its hydration capability, friction reduction, and mechanical stability. Its compatibility with anionic additives, such as a scale inhibitor, was also tested in a laboratory friction loop. Thermal stability of the cationic FR solution was studied at 150°F using a viscometer and Multi-Angle Laser Light Scattering (MALLS) method to obtain molecular weight information. The charge characteristics of the cationic FR, indicative of self-degradation properties, with exposure to heat, were also studied. Potential formation damage of the FR solution was evaluated with core flow tests in the absence of oxidizing breakers. Friction reduction and hydration tests show that the FR performs well in high TDS waters, even at low temperature, reaching its peak performance rapidly. The cationic FR possesses high mechanical stability even after being exposed to high pumping rates in the friction loop. It is well known that cationic FRs are not compatible with polyanionic scale inhibitors; in this study, a compatible scale inhibitor, SI-1, is identified. Additionally, there has historically been hesitation to use such cationic materials due to concerns of formation compatibility with negatively charged source rocks or flocculation in water treatment plants. Thermal testing with cationic FRs reveals that the material degrades to anionic without the aid of any other additive, which is confirmed by the fact that addition of polycationic additive, C1, caused coacervation in the heat-treated sample. As a result, concerns over effects of rock wettability or incompatibility with water treatment additives can be alleviated. No anionic FRs undergo similar change of the ionic charge. Thermal testing with cationic FR solutions also shows a significant viscosity drop, surprisingly without pronounced molecular weight loss (via MALLS). However, core flow testing of cationic FR fluids shows good regained permeability, even without breakers, further confirming self-cleaning capability. The degradation mechanism of these FRs will be shown. The self-cleaning capability of the dry cationic FR, even at relatively low bottomhole temperature (BHT), in combination with its high salt-tolerance, makes it an excellent friction reducer for multiple applications, especially with low quality water.

How Does EOR Polymer Impact Scale Control During ASP Flooding?

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.

Calcite Scale Mitigation in a Very Low Watercut, Low Salinity, HPHT Environment: Lessons Learned in Surveillance, Mitigation and Scale Inhibitor Performance Monitoring for an Onshore Field

A prolific Southeast Asia onshore oilfield has enjoyed scale free production for many years before recently experiencing a series of unexpected and harsh calcite scaling events. Well watercuts were barely measurable, yet mineral scale deposits accumulated quickly across topside wellhead chokes and within downstream flowlines. This paper describes the scale management experience, and the specific challenges presented by this extraordinarily low well water cut, low pH, calcium carbonate scaling environment. To the knowledge of the authors, no previous literature works have been published regarding such an unusual and aggressive mineral scale control scenario. A detailed analysis of the scaling experience is provided, including plant layout, scaling locations, scale surveillance and monitoring programs, laboratory testing, product selection and implementation, and scale inhibitor efficacy surveillance and monitoring programs. The surveillance and application techniques themselves are notable, and feature important lessons learned for addressing similar very low water cut and moderate pH calcium carbonate scaling scenarios. For example, under ultra-low watercut high temperature well production conditions, it was found that a heavily diluted scale inhibitor was necessary to achieve optimum scale control, and a detailed laboratory and field implementation process is described that led to this key learning lesson. The sudden and immediate nature of the occurrence demanded a fast-track laboratory testing approach to rapidly identify a suitable scale inhibitor for the high temperature topside calcium carbonate scaling scenario. The streamlined selection program is detailed, however what could not be readily tested for via conventional laboratory testing was the effect of <1% water cut, and how the product would perform in that environment. A risk-managed field surveillance program was initiated to determine field efficiency of the identified polymeric scale inhibitor and involved field-trialing on a single well using a temporary restriction orifice plate (ROP) to modify the residence time of the injected chemical. The technique proved very successful and identifed that product dispersibility was important, and that dilution of the active scale inhibitor had a positive effect on dispersibility for optimum inhibitor action. The lessons learned were rolled out to all at-risk field producers with positive results. The ongoing success of this program continues and will be detailed in the manuscript and presentation. This paper demonstrates a unique situation of calcium carbonate scale formation and control that utilized a previously unreported and analytical surveillance approach. The cumulative performance derived by improving not only chemical selection, but the way the wells were managed via surveillance and chemical management decision making processes is compelling and of value to other production chemists working in the scaling arena.

Implication of Turbulent Flow Induced by Gas Lift on Strontium Sulphate Scale Formation and Control Within Production Tubing

Sulphate scale can be predicted from thermodynamic models and over recent years better kinetics data has improved the prediction for field conditions. However, these models have not been able to predict the observed deposits where flow disruptions occur such as chokes, gas lift and safety valves. In recent years it has been recognised that the turbulence found at these locations increases the likelihood of scale formation and experiments have been able to demonstrate that with increased turbulence there is an increase in the mass of scale observed and an increased concentration of scale inhibitor is required to prevent its formation. In this paper a field case is investigated where strontium sulphate was observed in a location downstream of a gas lift valve. Laboratory tests were conducted to confirm whether the expected scaling was observed in a low shear flow loop and also to investigate whether the location of the scale changed when additional turbulence (gas injection) was introduced to the system. The flowrate was chosen so that the shear stress generated on the test piece was approximately 1-2 Pa, similar to the value expected in typical field pipe flow. At the end of the test, the scale adhered to each of the five sections of the test piece pipe work was analysed separately to give data on both the mass and location of scale. A second test was also carried out to investigate the effect shear and turbulence induced by gas lift had on scale formation by modifying the test piece to introduce a flow of gas into the system. The test method was then used to evaluate a scale inhibitor and assess whether its performance was affected by the different flow regimes. The introduction of the ‘gas lift’ had a significant effect on the location of scale. Instead of being spread evenly throughout the test piece, the majority of the scale deposited upstream of the gas injection point. This is likely due to the induced turbulence and expansion in the tubing diameter at the T-piece increasing the residence time and thereby enhancing scale growth. A significant difference in scale location was also observed when the inhibitor dose was too low to prevent deposition and a higher dose was required to achieve complete inhibition in the ‘gas lift’ system. The findings from this study have significant impact on the design of test methods of evaluating scale risk in low saturation ratio brines and the screening methods for scale inhibitor for field application that should be utilised to develop suitable chemicals that perform better under higher shear conditions.