A Quantitative Study of Sr2+ Impact on Barite Crystallization and Inhibition Kinetics

Scale inhibitors have been widely used for barite scale control. Our group has developed several barite crystallization and inhibition models to predict the crystallization and inhibition kinetics of pure barite with different inhibitors and calculate the minimum inhibitor concentration (MIC) required. However, instead of pure barite scale formation, the incorporation of Sr2+ can be frequently found in the oilfield, because of the coexistence of Ba2+ and Sr2+ in the produced water, which can influence the kinetics of crystallization and inhibition significantly. As a result, the MIC predicted could be off significantly. Therefore, in this study, the effect of Sr2+ on barite crystallization and inhibition kinetics is quantitatively investigated to evaluate the accuracy of MIC values under various conditions. The induction time of barite with different concentrations of Sr2+ was measured by laser apparatus without or with different concentrations of scale inhibitor diethylenetriamine penta(methylene phosphonic acid) (DTPMP) at the conditions: barite saturation index (SI) from 1.5 to 1.8; temperature (T) from 40 to 70 ℃; and [Sr2+]/[Ba2+] molar ratios from 0 to 15, all with celestite SI < 0. The results show that the induction time of the barite increases with [Sr2+]/[Ba2+] ratio at a fixed barite SI, T and DTPMP dosage. That means the MIC will be overestimated if it is calculated by previous semiempirical pure barite crystallization and inhibition models, without considering the presence of Sr2+. Based on the experimental results, the novel quantitative barite crystallization and inhibition models that include the influence of Sr2+ were developed for the first time as follows: Barite crystallization model with the influence of Sr2+: l o g 10 t 0 B a S O 4 , S r = ( 1.523 − 10.88 S I − 895.67 T ( K ) + 5477 S I × T ( K ) + 0.829 × [ C a 2 + ] ) + ( 0.823 S I + 85.44 T ( K ) − 0.667 ) × ( [ Sr 2 + ] [ B a 2 + ] ) Barite inhibition model including the influence of Sr2+ l o g 10 ( t i n h B a s o 4 , S r t 0 B a S O 4 , S r ) = b B a S O 4 , S r × C i n h l o g 10 b B a S O 4 , S r = ( − 2.187 − 1.411 × S I + 1329.29 T ( K ) + 0.153 × p H ) + ( 0.0983 × S I − 74.66 T ( K ) + 0.099 ) × ( [ Sr 2 + ] [ B a 2 + ] ) These novel models are in good agreement with the experimental data. They are used to predict the induction time and MIC more accurately at these common Ba2+ and Sr2+ coexisting scenarios. The observations and new models proposed in this study will significantly improve the barite scale management when Ba2+ and Sr2+ coexist in the oilfield.

A Semiempirical Model for Predicting Celestite Scale Formation and Inhibition in Oilfield Operating Conditions

Mineral scale formation has always been a serious problem during production. Most scales can be treated by adding threshold scale inhibitors. Several crystallization and inhibition models have previously been reported to predict the minimum inhibitor concentration (MIC) needed to control the barite and calcite scale. Recently, more attentions have been paid to the formation of celestite scale in the oilfield. However, no related models have been developed to help determine the MIC needed for the celestite scale control. Therefore, in this study, the crystallization and inhibition kinetics data of celestite under a wide range of celestite saturation index (SI = 0.7 – 2.6), temperature (T = 25 – 90 °C), ionic strength (IS = 1.075 – 3.075 M) and pH (4 – 6.7) with one phosphonate inhibitor (diethylenetriamine penta(methylene phosphonic acid, DTPMP) and two polymeric inhibitors (phophinopolycarboxylate, PPCA and polyvinyl sulfonate, PVS) were measured by laser apparatus or collected from previous studies. Then, based on the results, the celestite crystallization and inhibition models were established accordingly. Good agreements between the experimental results and calculated results from the models can be found. By using these newly developed models, the MIC needed for three commonly seen inhibitors, DTPMP, PPCA and PVS on celestite scale control can be predicted under extensive production conditions. The developed models can fill in the blank in scaling management strategies for high Sr2+ and SO42- concentrations in the produced waters.

Theories and Work Towards Understanding a Mysterious Case of Severe Bakken Brine Incompatibility

The Bakken formation is well known for producing brine very high in total dissolved solids (TDS). Halite, calcium carbonate, and barium sulfate scales all can pose substantial production challenges. Trademarks of Bakken produced brine include elevated concentrations of sodium (>90,000 mg/L), chloride (>200,000 mg/L), and calcium (>30,000 mg/L), contrasted against low concentration of bicarbonate (50-500 mg/L). In the past 3 years, operators have experienced unexpected instances of severe calcium carbonate scale on surface where produced fluids from the production tubing commingled with the gas produced up the casing. Initially treated as one-off scale deposits despite the application of scale inhibitor, acid remediation jobs or surface line replacement were typical solutions. As time has passed, this issue has become more and more prevalent across the Bakken. Investigation of this surface issue discovered a most unexpected culprit: a low TDS, high alkalinity brine (up to 92,000 mg/L alkalinity measured to date) produced up the casing with the gas. When mixing with the high calcium brine typically produced in the Bakken, the resulting incompatibility posed remarkable scale control challenges. The uniqueness of this challenge required thorough analytical work to confirm the species and concentrations of the dissolved ions in the brine produced with the gas. Scale control products were tested to evaluate their abilities and limitations regarding adequate control of this massive incompatibility. The theory that corrosion contributed to this situation has been supported by a unique modelling approach. Once corrosion was identified as the likely source of the high alkalinity brine, corrosion programs were instituted to help address the surface scaling. This paper highlights the evaluations conducted to fully grasp the severity of the incompatibility, the theories put forth to date, work conducted to try to replicate the phenomena in the lab and in models, and chemical programs used in the field to address corrosion and scale. While not known to exist in other oilfield basins, conventional or unconventional, this discovery may have implications for the broader industry if similar situations occur. The possible explanations for why this may be happening may have implications for scale control, asset integrity, and potentially even the methods by which wells are produced.

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.

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.

Enhanced Nanofiltration Process of Thin Film Composite Membrane Using Dodecyl Phenol Ethoxylate and Oleic Acid Ethoxylate for Oilfield Calcite Scale Control

This research studied the enhancing effect on the nanofiltration composite (TFCNF) membrane of two non-ionic surfactants on a thin-film composite nanofiltration membrane (TFCNF) for calcite scale (CaCO3) inhibition in oilfield application to develop a multifunctional filtration system: nanofiltration, antiscalant, and scale inhibitors. The effectiveness of dodecyl phenol ethoxylate (DPE) and oleic acid ethoxylate (OAE) as novel scale inhibitors were studied using the dynamic method. Scaling tests on the membrane were performed to measure the scaling of the inhibited membrane with and without scale inhibitors for salt rejection, permeability, and flux decline. The results revealed that the TFCNF membrane flux decline was improved in the presence of scale inhibitors from 22% to about 15%. The rejection of the membrane scales increases from 72% for blank membranes, reaching 97.2% and 88% for both DPE and OAE, respectively. These confirmed that scale inhibitor DPE had superior anti-scaling properties against calcite deposits on TFCNF membranes. Inhibited scaled TFCNF membrane was characterized using environmental scanning electron (ESEM), FTIR, and XRD techniques. The results of the prepared TFCNF membrane extensively scaled by the calcite deposits were correlated to its morphology.