This paper will highlight the effectiveness of a novel, environmentally friendly multifunctional polymeric scale inhibitor that inhibits carbonate and sulfate scales as well as halite.
The deposition of halite in the oilfield can present a challenge for operators in fields with high TDS brines. The large amounts of halite that can deposit in a short amount of time can lead to reduced production as well as a costly and logistically cumbersome remediation. A customer was controlling halite deposition by injecting a low salinity water source to dilute/dissolve the deposits. However, this remedial solution also presented an additional problem to the customer as the injection of the fresh water source led to calcium carbonate deposition due to brine incompatibility.
This paper will present laboratory test results which highlight the effectiveness of this novel multifunctional scale inhibitor against halite, carbonate and sulfate scales. These results will be compared to traditional scale inhibitors. Following laboratory testing, this environmentally acceptable scale inhibitor product was deployed in high TDS wells where halite deposition was occurring. This paper will also demonstrate the successful implementation of the product, which provided calcium carbonate inhibition and a reduction in the volume of fresh water needed for control of halite deposition. This reduction in water consumption led to significant cost savings for the customer.
The value this case study brings to the industry is an overview of the challenges halite and associated scales present to hydrocarbon recovery and the development/implementation of a multifunctional molecule rather than a chemical blend for scale control. Results of this paper have implications for other fields across the world where halite scale is a flow assurance challenge.
The Canadian Bakken has been produced for over 40 years but with advances in fracturing technology during the last 10 years, there has been an exponential increase in Bakken activity. Concurrent with this, there has been a step-change in frequency and severity of scale formation from high value, high productivity wells. This paper summarizes the scaling observations made over the producing life of this high producing formation drawn from treating and servicing over 400 wells through Southern Manitoba and Saskatchewan.
The most common scale types are calcite and anhydrite, although there is also evidence of siderite and iron sulfide. Formation of scale in Bakken wells is seen from the bottom of the tubing and open-hole sections up through the casing and rods. Formation water salinity can reach over 250,000 mg/L with up to 20,000 mg/L calcium. When combined with the high down-hole temperature, this brine causes a significant challenge for selection and application of scale inhibitor chemistries.
A typical scaling life cycle is given for a Bakken extended reach horizontal well. With production reaching maturity, the severity of scaling in this formation has been found to increase. The influence of fracturing and frequent well interventions has been discussed in terms of the profound effect these activities have on the onset of scale formation.
The experiences and strategies of over a dozen different operators have been combined, and the lessons learned from these activities used to determine a common approach in the management of scale in these challenging wells.
The paper concludes with several detailed case histories. These show how the development of an innovative scale management philosophy has been successfully put to the test in proactively preventing scale, thereby reducing the overall failure rate for the Bakken operating companies.
Selle, Olav Martin (Statoil ASA) | Nygard, Ole-Kristian (Statoil ASA) | Storas, Elisabeth (Statoil ASA) | Moen, Arild (Statoil ASA) | Matheson, Rozenn (Champion Technologies Ltd.) | Juliussen, Bjorn (Champion Technologies) | Chen, Ping (Champion Technologies Ltd.) | Haland, Torstein Sleire (Champion Technologies) | Mebratu, Amare Ambaye (Halliburton Co.) | Melien, Ingrid (Halliburton Norway)
The success of chemical treatments to prevent or remove formation damage, depend on the placement efficiency. In down-hole scale control treatments, diversion techniques are applied for improved placement of scale dissolvers or scale inhibitors in the potentially productive intervals. Foamed scale treatment is a new diversion technology developed by the operator and two oil service companies. The new approach is to foam the scale inhibitor and scale dissolver solutions for improved placement of down-hole scale inhibitor squeezes and scale dissolver treatments. An additional benefit is that the gas used to create foam is perfectly suited for wells with low reservoir pressure and with no gas lift system in place. In theory the foamed fluid will enter the highly injective zones at a higher rate than the others so that the resistance to flow increases in the zones which have accepted the foamed fluid.
The technical qualification of the foamed scale chemicals was divided into advanced bottle tests and dynamic flooding tests. The first ever field application was performed in a Norne subsea well, under challenging weather conditions from an intervention vessel. Two subsequent pumping operations; one foamed scale dissolver and one foamed scale inhibitor operation were done. The post job evaluation concluded that the foamed scale treatments were successful and the technology is qualified for future use at the Norne field. The well became protected against scaling as seen from the scale inhibitor return curve, and the well came easily on stream following each treatment. The operational challenges were mostly in connection with wave height and vessel movement affecting the Nitrogen pumping stability.
The benefits seen with this technology are: it is a solid free system, it can be deployed by bullheading, the foaming agent is environmentally friendly and the system helps a quick post treatment production.
Sanders, Laura (University of Leeds) | Hu, Xinming (University of Leeds) | Mavredaki, Eleftheria (U. of Leeds) | Eroini, Violette (U. of Leeds) | Barker, Richard (University of Leeds) | Neville, Anne (U. of Leeds)
The formation of calcium carbonate scale and the occurrence of corrosion in CO2-saturated environments in different parts of oil and gas facilities are both phenomena that have been extensively studied. However, to date, very limited work has been carried out on evaluating combined products in a combined scale/corrosion methodology. This paper presents the results from a new combined bulk jar scaling/bubble cell corrosion test. The aim of this project is to investigate the effect of two combined chemicals in a new experimental setup; to study the corrosion and scale interactions which occur simultaneously. Two combined products were assessed at 5 ppm concentration at two temperatures (60ºC and 80ºC) in a CO2-saturated brine. Bulk scale precipitation was monitored using a turbidity meter and the corrosion rate measurements were made using the linear polarisation resistance (LPR) technique. Scale deposition and corrosion mechanisms have been studied using surface analyses. The performance of the two combined products has also been tested to measure: (i) the increase in the induction time of the calcium carbonate formation in the bulk, (ii) the change of the morphology of the crystals and (iii) the formation of a partial protective layer on the sample.
According to this study, the new experimental method has enabled the corrosion and scale deposition on pipeline steel (X65) and the bulk precipitation process to be studied simultaneously. Detailed scale deposition mechanisms on the material surface in the presence of corrosion processes and combined products are addressed from this study.
Keywords: calcium carbonate, scale, corrosion, combined inhibitors
For over a decade, being able to accurately predict the risk of calcium naphthenate deposition has been one of the goals of production chemistry studies for development of new fields. In order to fulfill this challenge, many studies have been performed both within the company and through collaborations in JIPs. These studies have also shown specific behaviours of acidic crude oil / water separation depending on processing conditions. They have also permitted the improved detection and quantification of tetraprotic acids that are one of the main building blocks of these deposits. In this work, we will show how these findings have been incorporated into a workflow used to quantify naphthenate deposition risk. In particular, we will try to illustrate how the "other" naphthenic acids of the crude oil can behave as an efficient natural inhibitor of the deposits, and why, even if tetraprotic acids are detected in quite a large number of oils, only a limited number of fields have faced large scale issues related to calcium naphthenate deposits, due either to "good" process design or good fortune. "Simple" physicochemistry tests turn out to be very powerful tools in order to assess the macroscopic behavior of the naphthenic acids, and their influence on the risk analysis.
Gomes, Roberto (Petrobras S.A.) | Mackay, Eric James (Heriot-Watt U.) | Deucher, Ricardo Huntemann (Petrobras) | Bezerra, Maria Carmen Moreira (Petrobras S.A.) | Rosario, Francisca Ferreira (Nalco Company) | Jordan, Myles Martin
Evaluation of the scaling risk at production wells is generally carried out using thermodynamic prediction models. These models are generally very accurate in terms of predicting the type of scale that may form, the degree of supersaturation, and
the mass of scale that will deposit by the time the system reaches equilibrium - provided the brine composition or compositions involved are well known, and the pressure and temperatures conditions are accurately specified. However, in
performing these calculations, engineers and chemists often fail to take account of reactions occurring in the reservoir, and assume that brines reaching the production wells have not reacted in any way prior to entering the wellbore. This often leads
to a significant overestimate of the scaling risk.
The work presented in this paper addresses this issue by studying data from various fields to identify what can be learnt from the produced brine compositions. A new technique to estimate the range of scaling tendencies that takes account of
reservoir precipitation is developed, and the results are displayed in a 3D response surface. This is illustrated for barium sulphate scaling tendency, accounting for different levels of ion stripping.
In order to calibrate some simulation parameters, and to identify the more important equations that should be inserted in the reservoir simulation, studies were performed based on the observed data. Different reservoir simulations were used and
compared, with a focus on scale management to identify positive and negative aspects of each one.
This work has identified that in fields with reservoir temperatures above 120°C and calcium concentrations above 7000 mg/l, significant sulphate stripping occurs due to anhydrite precipitation. This effect is increased where ion exchange
leads to a reduction in magnesium and an increase in calcium concentration as the injected brine is displaced through the reservoir.
Silicate scaling is often induced by alkaline surfactant polymer (ASP) flooding in sandstone reservoirs. Scaling of the production tubing, rod or progressive cavity pumps, and other surface equipment causes frequent workovers, resulting in increased costs to the operator and non-productive time. The formation of silicate scale is complicated by its dependence on multiple factors including pH, silica concentration, and magnesium concentration, which vary as the flood progresses (Gill 1998). These factors affect silicate scaling tendency, and consequently, severity of the problem. Silicate scale inhibitors have been developed to mitigate problems in oilfields afflicted with silicate scaling due to ASP flooding (Qing et al. 2002). A new test method using an optical scanning device was developed to better characterize inhibition and dispersant qualities of the developed products on silicate scale in brine under static conditions. The advantage of this method is more comprehensive data generated by multiple-point measurements. Scaling reactions are more easily modified and differentiated. Water chemistries from several wells in an ASP-flooded field in Southern Alberta with known silicate scaling issues defined the tested synthetic brine. By allowing the mixed synthetic brine to react before adding inhibitor, the effect of delayed chemical injection may be studied. Performance of the tested inhibitor was significantly reduced by slight injection delay and may be attributable to the discrepancy between laboratory performance data and failures observed in the field. It is proposed that the performance of silicate scale inhibitors may be improved when applied by squeeze, where the inhibitor can inhibit silica polymerization within the formation and may provide substantial improvement over conventional continuous down-hole injection, where inhibitor reaches the water after the perforations.
Poynton, Neil (Baker Hughes Inc.) | Molliet, Annabelle (Baker Hughes Inc.) | Leontieff, Andre (Baker Hughes Inc.) | Cook, Stuart Edward (Baker Hughes Inc.) | Toivonen, Susanna (Kemira) | Griffin, Rick (Kemira Chemicals Inc)
Effective monitoring of scale inhibitor residuals following a downhole squeeze can present challenges due a variety of reasons including contamination of the produced fluid with a topside scale inhibitor, and in the case of subsea wells, often the production is commingled as several wells flow through a single riser. The introduction of phosphorus-tagged scale inhibitors has partially solved the detection issue, but more tags are still needed for subsea developments in the North Sea and for use in commingled production. Detection limits and turnaround time of the sample analysis are also concerns. A new tagged scale inhibitor has been developed combining the proven performance of sulphonated co-polymers coupled with fluorescence technology, thus allowing the scale inhibitor to be detected using fluorescence spectroscopy.
This paper discusses the development of the technology for use in a North Sea field located 130 miles northeast of Aberdeen that has a downhole barium sulphate scaling risk. It is comprised of platform wells and subsea wells that tie back to the host platform via two shared risers. The operator was experiencing difficulties in detecting the subsea squeeze returns so this new tagged scale inhibitor was introduced in one of the wells to improve the monitoring of the squeeze returns. The scale inhibitor was detected successfully in the produced water samples by spectrofluorimetry and validated with gel permeation chromatography. The ultimate goal is to analyse residual squeeze inhibitors using a portable fluorimeter for onsite detection, enabling real-time monitoring of the squeeze returns.
The development of the chemistry and detection monitoring technique and the preliminary results from the field trial, and demonstrates the validity of the analysis method is discussed. This new chemistry, being detectable in mixed fluids, reduces the need for shutting in wells or well tests for sampling, thus minimising process instability due to re-routing wells and shut-in losses.
Water flooding is the hinge pin for Gemsa Oil Field. Water injection is supplied from shallow water supply wells. Compatibility tests had indicated probable deposition of calcium sulphate scale on surface and subsurface production equipment. Calcium sulphate scale has been recognized to be a major operational problem. The bad consequences of scale formation comprised the contribution to flow restriction thus resulting in oil and gas production decrease. The nature of calcium sulphate scale is very hard and can't be dissolved with known dissolver. Sister companies that has similar problem were always going to the mechanical remover options.
Extensive lab and field work was conducted to determine the suitable chemicals to dissolve calcium sulphate scale.
This paper describes the development and field application of chemical treatment to remove scale in an offshore 8?? production line in Gemsa oil field. Continuous precipitation of calcium sulphate scale caused partial plugging of the pipeline. This partial plugging created a back pressure on production wells which decreased the productivity. The field production has been decreased to almost one tenth of the normal field production level(1).
A thorough investigation was conducted to identify the composition and location of the scale, in order to recommend a suitable chemical to remove the scale, and to assess the effectiveness of the treatment method in the field.
Based on extensive lab studies, SAG-01 was tested and applied in production line to remove the scale efficiently, the program was designed taking into consideration the nature of the scale.
The treatment program included three - staged process:
1. The use of an organic solvent
2. The main treatment (SAG-01).
3. The post flush stage (injection water),
The job results were outstanding, where as
1- Production increased by about 2,000 BOPD
2- Launcher pressure dropped by about 350 psi.
3- Decrease the back pressure on our producing wells.
4- Additional producing wells into production.
5- Efficient cost /Bbl.
The ultra-high temperature (150-250oC), pressure (1,000-2,000 bar, 15,000 to 30,000 psi) and TDS (>300,000 mg/L) in deepwater oil and gas production pose significant challenges to scaling control due to limited knowledge of mineral solubility, kinetics and inhibitor efficiency at these extreme conditions. Prediction of thermodynamic properties of common minerals is currently limited by lack of experimental data and inadequate understanding of modeling parameters. In this study, a new apparatus was built to test scale formation and inhibition at high temperatures and pressures. Solubilities of two common minerals, barite and calcite, were tested at temperature up to 250oC, pressure up to 1,500 bar (22,000 psi) and ionic strength up to 6m in solutions with elevated concentrations of mixed electrolytes (e.g., calcium, magnesium, sulfate and carbonate) representing the maximum range of interferences expected (95%CI) in oil and gas wells. As an attempt towards experimentally determining mineral solubility at high temperature, pressure and salinity, not only does this study contribute to the extremely limited data base, but it also provides a reliable approach for evaluating and adjusting model predictions at extreme conditions. Predictions by a thermodynamic model based on Pitzer's ion interaction theory were evaluated using experimental data. The dependence of Pitzer's coefficients for ion activity coefficients on temperature and pressure was examined and incorporated into the scale prediction model, whose prediction is consistent with both experimental and literature data at all conditions tested.