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Summary In this paper, the use of a quartz crystal microbalance (QCM) with a quartz crystal sensor coated with iron oxide is proposed to evaluate the efficacy of inhibitors in the prevention of scale formation. The quartz crystal was first iron-plated by electrodeposition over the original gold film on the outer side of the crystal and then oxidized. The iron oxide layer is more representative for an evaluation of the inhibitor's effectiveness because tubing and equipment in oil-industry facilities are made of low carbon steel that is coated with an iron oxide layer. The scale formation was conducted under a steady supersaturation condition. The experiments were performed with slow addition (0.2 cm/min) of 40 cm of Na2CO3 solution (1,000 ppm) to 200 cm of synthetic formation water (AF-W2). The performance at 10 ppm concentration of two commercial scale inhibitors, diethylenetriamine penta(methylenephosphonic acid) (DETPMPA) and polyphosphonocarboxylic acid (PPCA), was evaluated. The mass variation on the iron oxide plated QCM crystal sensor, caused by CaCO3 deposition, is related to supersaturation, pH value, and efficacy of scale inhibitor. Scanning-electron-microscope (SEM) images show that besides calcite crystals, there are also deposits in the form of spherical lenses, which is characteristic of the polymorph vaterite.
- South America > Brazil (0.47)
- Europe (0.46)
- North America > United States > Texas (0.28)
- Geology > Mineral > Silicate > Tectosilicate > Quartz (1.00)
- Geology > Mineral > Oxide > Iron Oxide (0.86)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract A number of gas fields have been developed in the Middle East, Offshore Western Australia and in the Asia-Pacific region for the last five years as the demand for Liquefied Natural Gas (LNG) has grown tremendously worldwide. Most of these gas field production systems consist of long subsea flowlines, which are flowing with three phase fluids gas, condensate and water. The cold temperatures of the subsea environment pose a flow assurance risk to production, especially for hydrate blockages. The only solution currently being considered to address the risk for hydrate blockages in gas fields is the usage of Kinetic Hydrate Inhibitors (KHIs), not Anti-Agglomerate Low Dose Hydrate Inhibitors (AAHIs). The most significant production concern for all producers associated with this production scenario is that the performance of the KHI is compromised in the presence of the Corrosion Inhibitor (CI). The reason for not considering the AAHIs for this application, whose performance is not compromised by the corrosion inhibitor, is the general belief that these chemistries are predominantly water soluble and therefore increase the toxicity of the produced water. The published literature to-date is focused on understanding the interactions between the KHI and the CI chemistries to solve the incompatibility issue. The lack of literature to-date showcasing the success of such an understanding warrants a solution with a different perspective. Data is available for new generation chemistries currently being used in the industry that show greater than 99% oil solubility and would hence overcome the toxicity concern that was valid for the first generation AAHI chemistry. This new generation chemistry was tested by Heriot-Watt University in the United Kingdom (UK) that shows the product effectiveness up to 90% water cut at a reasonable subcooling, applicable for these subsea flowlines in discussion. The performance at these high water cuts will make this new generation chemistry more applicable for these subsea flowlines without the risk of hydrate blockages. Introduction Gas hydrates are solid inclusions that are similar to ice in appearance but differ in structure. Under certain conditions of high pressure and low temperature, water physically entraps the molecules of a hydrate-former inside a hydrogen bonded solid lattice. Hydrate-formers include nitrogen, carbon dioxide, hydrogen sulfide, methane, ethane, propane and butane and are the main components of natural gas (Makogon 1998; Sloan 1998). Gas hydrates are not stable at ambient temperature and pressure. Hydrate agglomerationss can be even formed with low concentrations of water. To protect a system against gas hydrate formation, the right chemical at the right dose rate needs to be injected into the system. Currently there are two mechanisms of low-dose hydrate inhibition available as an alternative to Thermodynamic Hydrate Inhibitors (THIs); Anti-Agglomerate Hydrate Inhibitors (AAHIs) and KHIs. The AAHIs and KHIs are normally classified as Low Dosage Hydrate Inhibitors (LDHIs).
- Asia (0.70)
- North America > United States > Texas (0.28)
- Oceania > Australia > Western Australia (0.26)
Abstract The use of Low Dosage Hydrate Inhibitors (LDHIs) is one of the optimum methods to control gas hydrate formation issues and provide flow assurance in offshore gas production systems. The application of this technology has several advantages to operators including providing the opportunity for significant cost savings, extending the life of gas systems, as well as providing the option to use combination products. This paper will review the use of Kinetic Hydrate Inhibitors (KHIs) and Anti-Agglomerants (AA) through recent case histories. It will also illustrate how these products can be used in conjunction with Corrosion Inhibitors (CI) as is typically required in gas condensate production systems, either as individual products or as combination products. The novel illustration of the use of LDHIs in sour conditions will also be provided via case histories at low to moderate subcoolings. Hydrates can form different structures depending on the gas composition of the produced fluids. The nature of the LDHI used needs to take this into account and new product developments in this area will be covered. Introduction Natural Gas Hydrates. When considering the production of hydrocarbon fluids from offshore gas systems, flow assurance is a significant issue which needs to be taken into account. An important element of flow assurance is the investigation into the possibility of gas hydrate formation and its subsequent control. The inhibition of gas hydrate formation needs to be taken into account as part of the production of offshore gas, especially as hydrates typically form at lower temperatures and higher pressures. Production facilities, particularly offshore wells and offshore transmission lines, may be operating under conditions where hydrate formation is favourable. Gas hydrate formation occurs when natural gas molecules are surrounded by water molecules to form 'cage'-like structures. Gas hydrates are similar in appearance to ice. Both materials have crystalline structures that exhibit similar characteristics โ with the important difference that the natural gas hydrate has a natural gas guest molecule as an integral part of its structure. Examples of typical hydrate forming gases include Nitrogen, Carbon Dioxide (CO2), Hydrogen Sulfide (H2S) and light hydrocarbons (such as methane through to heptanes). Depending on the gas composition and the pressure, gas hydrates can form at temperatures of up to 86 ยฐF where gas co-exists with water.
- North America > United States > Texas (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Hibernia Field > Hibernia Formation (0.98)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Hibernia Field > Avalon Formation (0.98)
This paper is to represent reviews of low dosage hydrate inhibitor's (LDHI) evolution and advances, and to provide a general guide for LDHI considerations, historically, hydrate risk has been managed by keeping the fluids warm, removing water, and/or by injecting thermodynamic hydrate inhibitors (THI), commonly methanol or glycol. THIs require high dosage rate therefore production systems can reach a treatment limited by supply, storage, and umbilical injection constraints. Besides, high dosage of MeOH can cause crude contamination for downstream refineries, which may result in penalty. Over last two decades LDHIs have been extensively researched and developed as an alternative hydrate management chemical for oil and gas industry. LDHIs are divided into two main categories; Kinetic Hydrate Inhibitor (KHI) and Anti-Agglomerant (AA), both have been successfully used in field applications, but each comes with their unique challenges for applications, OPEX and CAPEX considerations. LDHIs have proven track records in numerous fields in their performance, either as stand-alone chemical treatment or reducing amounts of methanol/glycol usage, which has directly resulted in CAPEX and OPEX reduction. LDHIs have been instrumental in managing risks of early water breakthrough, high cost of THI storage and transportation, HSSE concerns around THI handling, and undersized pump capacity for required chemical volumes. Switching to LDHIs also offers an economic advantage by reducing umbilical line diameter. Latest advances in the LDHI technology is breaking barriers and pushing limits. The paper summarizes historical advancements in LDHIs over the last two decades, discusses application advantages and limitations, and the criterions to consider for selecting LDHIs.
- Asia (1.00)
- Europe > United Kingdom > North Sea (0.93)
- Europe > Norway (0.68)
- North America > United States > Texas > Harris County > Houston (0.29)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin > Central Deep Basin > Permit VIC/RL3 > Sole Field > Latrobe Formation > Kingfish Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 43/26a > Ravenspurn Field (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Alwyn Area > Block 3/25a > Alwyn Area > Nuggets Field (0.99)
- (12 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Hydrates (1.00)
Abstract The adsorption of four phosphonic acids an the calcium sulfate dehydrate crystal surface has been studied as a function of pH. Tendencies toward adsorption increase as the pH of the solution is raised from 4 to 7, then level off or fall off as the pH is further increased from 7 to 9. Among the phosphonic acids studied, surface affinity is well correlated to the performance of these same materials as calcium sulfate dehydrate crystal growth inhibitors. Yet at surface saturation the amount of inhibitor adsorbed is sufficient to cover only one percent or less of the total available surface area. These findings are in accord with the idea that adsorption of inhibitor at active growth sites is responsible for inhibition. Introduction It has been known for many years that additives or impurities alter both the rate of crystallization and the morphology of crystals formed in solution. The now widely accepted use of a trace amount of an additive such as a polymeric carboxylic acid, a polyphosphoric acid, an ester of orthophosphoric acid, polyphosphoric acid, an ester of orthophosphoric acid, or any one of several phosphonic acids to control an industrial scale problem is an example of the intentional use of an additive to inhibit crystal growth. Although the exact mechanism of inhibitor action is not yet understood, adsorption of the inhibitor on newly formed nuclei, on existing surfaces, or in general on any active crystal growth site is often proposed as a primary step in the overall inhibition proposed as a primary step in the overall inhibition process. Supporting this proposal are a number of process. Supporting this proposal are a number of studies showing, for example, that polyphosphoric acids that are active as inhibitors are adsorbed on a variety of crystalline materials including calcium carbonate, strontium sulfate, calcium sulfate dehydrate, and calcium oxalate. Additionally, Crawford and Smith found that polyacrylic acid is incorporated into calcium sulfate dehydrate crystals grown in the presence of this additive, and Nestler, in a deliberate study of the adsorption of polyacrylic acid on the calcium sulfate dehydrate crystal surface, showed that tendencies toward adsorption are strong, particularly with increasing degrees of polyacrylic acid deprotonation. As a class, the phosphonic acids have received relatively little attention, at least from the point of view of their adsorption tendencies. Exceptions are several studies concerned with the application of these materials by a squeeze treatment technique showing that adsorption occurs readily on the surface of silica sand. Another exception, and one that is more closely related to the process of scale inhibition, is a study by Weintritt and Cowan showing that nitrilotri (methylenephosphcnic acid) is rapidly adsorbed on the barium sulfate crystal surface. In the same system, Leung and Nancollas discovered that at an inhibitor concentration sufficient to prevent crystal growth, only a small fraction of the total available surface area is occupied by the inhibitor. The latter finding was interpreted to indicate that adsorption occurs selectively on active growth sites. The present study is concerned with the adsorption of phosphonic acids, particularly -aminomethylphosphonic acids, on the calcium sulfate dehydrate crystal surface. It is specifically concerned with the influence of pH on adsorption and the correlation between surface affinity and inhibition activity. Four phosphonic acids of contrasting activity as calcium sulfate dehydrate crystal growth inhibitors have been studied. They are, in decreasing order of effectiveness: hexamethylenediamine- N,N,N',N'-tetra(methylenephosphonic acid); ethylenediamine- N,N,N'N'-tetra(methylenephosphonic acid); ethylenediamine- N,N di(methylenephosphonic acid); and ethylenediamine- N,N'-dimethyl-N,N'-di(methylenephosphonic acid). Following the abbreviated scheme of nomenclature used in the preceding article, these materials from this point on will be designated as HMDP4, EDP4, EDP2, and point on will be designated as HMDP4, EDP4, EDP2, and EDMe2P2, respectively.