Ethanol as an alternative to water vapor for saving energy and fossil fuels in thermoelectric plants

This article proposes the use of ethanol in a 96% azeotropic mixture as an alternative to water vapor in thermoelectric generators with notable advantages in saving fuel. As is known, water is a cheap resource, available everywhere in a liquid state. However, water has an unusually high heat of vaporization and an equally high boiling point, so converting water to steam requires consuming large amounts of fossil fuels to break the hydrogen bonds in this substance. In contrast, evaporating ethanol requires only 37 percent of the fuel needed to evaporate water. In addition, water, before turning into steam, needs to be softened and treated with chemicals to prevent oxidation and scale deposits in pipes. If quality ethanol is used, this process of adjusting the water would not be necessary, which represents another saving. On the other hand, it is possible to resort to the use of solar heaters to raise the temperature of the ethanol to around 70ºC to later heat it to 80ºC or more, if necessary, with fossil fuels, making more significant savings. Objectives: To propose the replacement of water vapor by ethanol vapor as a working fluid to move the turbines of thermoelectric plants to reduce the consumption of fossil fuels. Methodology: Analyze the physical properties of water and compare them with those of ethanol to know the advantages and disadvantages of one and the other as working fluids Contribution: Through small modifications in thermoelectric plants it is possible to reconvert them to operate with ethanol vapor and save on fossil fuels.

Calcium Carbonate Scale Inhibition with Ultrasonication and a Commercial Antiscalant

In this study, ultrasonication-assisted calcium carbonate scale inhibition was investigated compared with a commercial antiscalant ATMP (amino tris(methyl phosphonic acid)). The effects of varying ultrasound amplitude, pH, and inhibition duration were evaluated. The inhibition of calcium carbonate scale formation was measured based on the concentration of calcium in the solution after subjecting to different conditions. Scale deposits were also characterized using scanning electron microscopy and X-ray diffraction spectroscopy. Inhibition of scale formation was supported at a pH of 7 for an ultrasound amplitude of 150 W. A 94% calcium carbonate inhibition was recorded when the experiment was carried out with ultrasonication. The use of 5 mg/L ATMP achieved a 90% calcium carbonate inhibition of ATMP. The result of the characterization revealed that the morphology of the crystals was unaffected by ultrasonic irradiation. Sample treatment was performed with two different membranes to evaluate the calcium carbonate deposition, and data reveals that, at identical conditions, ultrasonication provides less deposition when compared to the control experiments.

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 Squeeze Inhibitor as Preventive Treatment in Brani Wells, Offshore North West Java

The Brani-Field is located offshore Northwest Java and currently produces hydrocarbons from a sandstone reservoir with an average watercut of 83%. Some high watercut wells are prone to scale problems and need repetitive clean outs to overcome production decline. In 2019, downhole scale inhibitor treatment was evaluated and planned for application in these wells. Scale inhibitors are able to prevent the formation of scale so the well is able to deliver higher average oil production with lower intervention cost. In Brani wells, scale deposits are formed in perforations, downhole completion equipment, and flowlines depending on the water composition, temperature, and a reduction in dissolved carbon dioxide partial pressure. These scales deposits restrict the fluid flow causing significant production loss. In extreme conditions, the production tubing was blocked completely with the scale deposits and cease the production. Normally, the scale restriction problem in Brani wells were handled by a combination of mechanical and acidizing treatment using Coiled Tubing (CT) for downhole completion and acidizing treatment for flowline restrictions. These treatment were performed periodically every 2-4 months depending on well conditions with scaling becoming more severe in higher watercut wells. From an economic standpoint, current scale treatment methods lead to very high well intervention costs due to expensive liftboat and CT unit daily rates. The economics of these conventional treatments is further deterred by low yearly average oil production. Evaluation for scale inhibitor treatment started with the candidate selection, fluids compatibility test, core re-gain permeability test, and economic evaluation. BRG-10 well was selected as first candidate due to scale problem severity and low oil production rate. This well normally delivers 140 bopd with 90% watercut, but scale build up in the tubing and flowline prevented the fluids flow and lowered the production to 30 bopd in just two months. Laboratory test results demonstrated that the core regained permeability with the main pill fluids to a relatively high, 77.96% without any fluids compatibility issues. Deployment of a scale inhibitor squeeze treatment in BRG-10 well was executed in Jan 2020 by bullheading 657 bbl inhibitor fluids into the formation. The well was then shut in for 24 hours of soaking time. The post treatment results showed a very promising result with much more stable oil production after 11 months treatment, welltest on December 2020 showed the well was still producing 130 bopd with 90% watercut. Following the successful application in BRG-10, the scale inhibitor treatment was applied in other wells, BRK-7 in June 2020 and BRG-5L in August 2020. So far, those two wells show good production performance with 93 bopd with 85% watercut for BRK-7 and 264 bopd with 76% for BRG-5L.

A Novel Chemical Treatment and Well Completion Strategy to Prevent Scale and Production Losses in Shushufindi Aguarico Field

In this case study, EP Petroecuador and Consorcio Shushufindi evaluate a chemical treatment and completion strategies to reduce the extensive impact of bottomhole scale deposits on oil production, electrical submersible pumps (ESP) run life, and operating costs of wells completed in the high-scaling tendencies reservoir. The positive impact on oil production optimization resulting from these strategies will also be discussed and the advantages, lessons learned, and constraints of this work. Conventionally, corrosion and scale chemical inhibitors are deployed through capillary lines; this method is effective up to the pump depth but does not prevent deposits at the perforations or at the lower completion and near wellbore. Rapid production decline or complete loss of production is observed, requiring costly well interventions. Laboratory analysis and evidences from the interventions show that lower T-sand fluids present a high-scale tendency at the bottomhole; therefore, a process to identify candidates and deploy chemical treatment in the rathole to prevent scale deposits was defined and proved. The technology selected was encapsulated scale inhibitors (microcaps). Based on the process, two wells were selected from a portfolio of 12 wells that match the criteria to apply the method to deploy the technology. The following observations were drawn: -Calcium carbonate (CaCO3) is the most common scale-ESP parameters and production surveillance are essential for early detection of problems associated with scale deposits at bottomhole-The action of microcaps and the installation of a pipe tail below the ESP base sensor allowed to deepen the continuous dosage of scale inhibitor and has already doubled the run life of the ESP equipment, with direct savings on operations costs (approximately USD 240,000) in the short time and continue and can continue to yield more.-According to post workover (WO) production tests of the two candidates and the performance of ESP parameters, the application of this strategy made possible to restore the productivity indexes and sustain them over time. This leads to reduction in production losses of 310 BOPD or 60% of the actual production in the similar period before the treatment.-The microcaps can be applied and refilled through rig-less annulus-It is a low-cost solution for scale problems at bottomhole. This document presents an analysis to reduce operating costs in wells that produce fluids with a high-scaling tendency at bottom hole, through an unconventional and low-cost strategy of chemical treatment from the sand face to the wellhead. This novel process and microcaps application can be used in wells in remote and difficult areas to service on a regular basis.

Controlled Growth of Strontium Sulfate Particles in Aqueous Solution: Inhibition Effects of a Bubble Column Evaporator

In the oil industry, strontium sulfate (SrSO4) scale deposits have long plagued oilfield and gas production operations. This remains an unsolved problem. We here show how the bubble column evaporator (BCE) can be used to control aqueous precipitation from salt solutions. Mixtures of strontium nitrate and sodium sulfate in the BCE system were used to precipitate strontium sulfate at different degrees of supersaturation. The effectiveness of the BCE system was compared to standard mechanical stirring. The precipitation of strontium sulfate in both processes was monitored through turbidimeter, particle counting, Dynamic Light Scattering (DLS) and Scanning Electron Microscopy (SEM). The results show that the BCE system has a significant inhibition effect and so can be used to control precipitation growth rate, even from supersaturated solutions. This remarkable effect also provides new insights into mechanisms of crystallisation, of bubble interactions and mineral flotation.

MULTI-FACTORIAL MATHEMATICAL STATISTICAL SIMULATION OF OIL PRODUCTION

Oil and gas deposits differ depending on the bed size, geological-physical development conditions, oil quality and geographic location. Including them in the development is connected with various investments to the main constructions; subsistence and current material expenses also differ. Therefore, from the point of view of economic efficiency, oil and gas deposits are not equal. Location of oil and industry leads to the problem of the sequence of putting of various deposits into operation and their development rate. The sizes of oil and gas beds and available oil and gas reserves in them give reason to say which of these beds will be put into operation in the near future. Completion and development of large scale deposits require less investments compared to small scale deposits. Such deposits are usually highly productive, expenses per a production unit in them is small. All these determined importance of the use of reserves in large scale deposits in the first turn.

Water well acidization revisited: includes oil and geothermal well perspectives

Borehole acidization has two objectives: to remove drilling damage at the well face and to enhance formation permeability. Acid applications have been mainly on carbonates, granitic and metamorphic rocks in geothermal wells and on sandstones in oil and gas wells. In geothermal wells, acidizations have been especially useful in removing accumulated scale deposits. Hydrochloric acid is the most commonly used as it has a high dissolving power, a lower cost and is relatively easy to handle. It reacts easily with carbonates but not with silicates in sandstones for which a mixture of hydrofluoric and hydrochloric acid is used. There are no known water well acidizations with hydrofluoric acid. Acidization of limestone water wells with hydrochloric acid has been generally successful in naturally fractured rock with productivity improvements of two or more times the original yield. Second and third acidizations can enhance yields further and are usually economically justifiable. Water well acidizations may benefit from higher injection rates than is currently practised. Acid fracturing is widely used in the oil and gas industry. In water wells it may prove useful in hard crystalline limestones, but not in soft low strength carbonates, such as UK Chalk.