A new methodology for template-directed polymerization is described which is suitable for easy microbead formation. Cationic polymerization of a bis-epoxy silicone monomer by a diaryliodonium salt photoinitiator was found to occur fast enough to polymerize the droplets of an aerosol spray of the monomer, photoinitiator, and template in flight. Symmetric microbeads averaging 31 µm in diameter were produced and captured by electrostatic precipitation. The effect of numerous functional groups on the rate of polymerization is discussed. Nitrogenous bases were found to be detrimental to polymer bead formation, as were certain carboxylic acids. Beads imprinted with morphine analogue thebaine displayed stronger molecular recognition properties for thebaine than did nonimprinted beads. However, both thebaine-templated and nonimprinted beads retained similar amounts of the thebaine derivative 17,18-bis(methoxycarbonyl)-6,14-ethenocodeine methyl ether.
Water-soluble cellulose based polymers such as hydroxyethyl cellulose (HEC), methylhydroxyethyl cellulose (MHEC), and carboxymethylhydroxyethyl cellulose (CMHEC) are commonly used additives to control important cement slurry properties like fluid loss, free fluid, and slurry stability. They typically hydrate quickly after contact with the mix water resulting in instant slurry viscosification and potential mixing difficulties especially at higher loadings. Adding cement dispersants to the cementing system design can facilitate slurry mixing but this does not always work out as expected. Sometimes incompatibilities between the dispersant and the other additives result in even more difficult slurry mixing. Furthermore the addition of dispersants to compensate mixing problems can enhance thermal thinning leading to severe settling issues once the slurry is exposed to the elevated downhole temperatures in the wellbore. To overcome these challenges, the use of large particle size cement additives to lower the surface mixing viscosity and the effect of important slurry properties were studied. The cement fluid loss, free fluid control, and slurry rheology performance of large particle size polymeric additives were evaluated in cement slurries. Different particle sizes for polymeric additive were tested in assorted cement densities and temperatures. Cement testing procedures, lab test results, and a case history is presented and discussed. The study demonstrates that the hydration of the cellulosic polymers is delayed as particle size of polymeric additives increases. It could be concluded that the use of larger size cellulosic polymers greatly facilitates slurry mixing, requires less mixing energy or reduces slurry mixing time, and results in a lower initial slurry rheology without negatively affecting other slurry properties (in some cases the fluid loss performance was even significantly improved).
A novel cement additive, capable of creating an insoluble barrier at the first sign of acid attack, is offered. When present in small quantities, it allows ordinary Portland cement (OPC) to protect itself from acid corrosion as shown by laboratory tests. This corrosion resistance is critical especially in regards to attack from carbonic acid produced when CO2 combines with water or from naturally occurring H2S in the well. These acids can turn OPC porous and weak, rendering it incapable of maintaining zonal isolation. CO2 gas can enter the wellbore as part of either a stimulation technique to energize production or to sequester this green-house underground in hopes of reducing global warming. Cement used in a CO2-sequestering well must maintain its integrity for hundreds if not thousands of years to keep the CO2 trapped; otherwise, the CO2 can reenter the atmosphere. Damage to the cement sheath in the short -term can lead to contaminated aquifers or annular leakage of natural gas, both of which can have devastating results. Laboratory testing of this commercially-available additive was performed under temperature and pressure in CO2-saturated brines for weeks. Corrosion of the tested cement samples was measured optically and through a variety of chemical analysis procedures. Samples of OPC containing the additive stopped penetration of carbonic acid near the surface whereas sample without suffered deep corrosion penetration. When it is known in advance that the well will be highly acidic it may be cemented with acidresistant alumina-silicate cement (ASC) rather than OPC. However, this technique requires specially isolated pumping equipment to avoid flash set of the ASC, making the process more expensive and error-prone. Addition of the novel dry-powder, acid-activated, barrier-creating compound is much easier. The additive remains inert in the set OPC until acid corrosion occurs. Release of calcium ions by acid attack triggers the formation of an insoluble barrier which reduces further acid damage.
Chemical and physical modification of a sustainable, derivatized-cellulose polymer has created a single material capable of replacing several different cement additives. This slowly-hydrating, hydrophilic biopolymer is capable of performing as a fluid loss agent, suspending agent, free water control agent, and extender for use in wells up to 225°F and in some conditions up to 250 °F. The single, new cement additive effectively and economically replaces separate fluid loss additives, free water control, and slurry stabilizers as well as reduces retarder loadings. Laboratory and field results, operational aspects, and slurry design simplification are conferred in this publication. Standard API test results using Class H ordinary Portland cement slurries with densities ranging from 13.5 ppg to 15.5 ppg including a 14.5 ppg cement blend containing 50% fly ash at multiple temperatures are presented. The biopolymer works best with the lower and middle density cements. Unlike most fluid loss polymers, this new additive doesn't produce the high initial viscosities, thereby reducing pumping horsepower requirements and equipment wear and tear. A field case in an 18,000 ft horizontal well (8k ft vertical, 10k ft horizontal) confirms the polymer's effectiveness. Preventing fluid loss is critical in maintaining the proper amount of water to give the cement proper density and mechanical properties. Without adequate suspension and free water control, cement particles will settle at the bottom of the slurry resulting in poor zonal isolation. Slurries containing the cellulose biopolymer performed equal to or better than slurries containing multiple, traditional additives. These additives can interact with each other both antagonistically and cooperatively so that a minor change in one can cause unwanted ripple effects to the slurry properties. This makes slurry design complicated and time-consuming. Replacing several of the commonly-used additives with this modified cellulose minimizes and even removes these complicating ripple effects. The polymer's ability to serve different roles at the same time leads to smaller additive inventories, easier logistics, less time spent on slurry design iterations, and simplified field operations which all add up to improved economics and reduced chance of error during placement of the cement.
The rigorous environmental regulations of the North Sea oil and gas fields have required fundamental changes in the way service companies acidize wells. Traditionally, acid corrosion inhibitors have been some of the most toxic chemicals routinely pumped downhole. This paper describes a new acid corrosion inhibitor (NSACI) that meets the Norwegian environmental "Yellow" specifications for chemicals. This inhibitor functions in both mineral and organic acids and has been successfully used in the larger fields on the Norwegian Continental Shelf. Laboratory data is presented in detail along with field references to explain both the strengths and limitations of this new, environmentally-friendly acid corrosion inhibitor. Introduction Clean-up and stimulation of wells with acid is a technology over one hundred years old1. Hydrochloric acid is used to dissolve carbonate material from both the well tubulars (scale) and the formation (limestone/dolomite) itself. If a steel or formation is sensitive to HCl then organic acids such as acetic and formic acid are used for these same tasks. During the production of oil and gas carbonate scale is usually deposited from formation water high in carbon dioxide. As the pressure on this water lessens the dissolved carbon dioxide will effervesce. The loss of this CO2 results in a lowered solubility to carbonates allowing precipitates to form. Divalent iron and calcium are the two most common counter ions in this precipitate. The general formula is written as follows: CO2 + CaCO3 + H2O -» Ca(HCO3)2 Removal of this carbonate scale is economically achieved with either HCl acid, acetic acid or formic acid. Use of Hydrochloric Acid Hydrochloric acid is the most common acid used for scale removal and carbonate formation stimulation. As a common industrial side-product it is relatively cheap and readily available. In its most concentrated aqueous form it may be found at 37–38% by weight. When used to acidize a well it is cut anywhere from 28% down to 3% HCl. 15% HCl is commonly recommended when acidizing Norwegian sector wells, many of which have bottom hole temperatures under 200 oF. Any of these strengths will damage steel tubulars, especially as the bottom hole temperature and contact times climb. Hydrochloric acid is capable of dissolving up to 3.66lbs of limestone per gallon of HCl at a concentration of 28% by the reaction: 2HCl + CaCO3-» CaCl2 + H2O + CO2 Dolomite, which is a mixture of calcium and magnesium carbonate, reacts somewhat slower with hydrochloric acid by the formula: 4HCl + CaMg(CO3)2-» CaCl2 + MgCl2 + 2H2O + 2CO2 Use of Organic Acids Organic acids are used instead of HCl with some formations and tubulars where HCl cannot be used. For example, some sandstone formations will produce excessive fines or suffer other problems if acidized with HCl. Also, certain alloys such as chrome steels, brass and aluminum can be difficult to protect from the hydrochloric acid, especially at elevated temperatures. Formic and acetic acid are much weaker acids than HCl. However, the concentrations of the organic acid must be kept below 15% for acetic acid and under 10% for the formic acid to prevent precipitation of (CH3COO)2Ca and (HCOO)2Ca.
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