scholarly journals A Novel Low-Temperature Non-Corrosive Sulfate/Sulfide Scale Dissolver

2020 ◽  
Vol 12 (6) ◽  
pp. 2455
Author(s):  
Hany Gamal ◽  
Salaheldin Elkatatny ◽  
Dhafer Al Shehri ◽  
Mohamed Bahgat
Keyword(s):  
Low Temperature ◽  
Corrosion Rate ◽  
High Performance ◽  
Oil And Gas ◽  
Ethylenediaminetetraacetic Acid ◽  
Gas Production ◽  
Operating Conditions ◽  
Superior Performance ◽  
X Ray ◽  
Dissolution Efficiency

The oil and gas production operations suffer from scale depositions. The scale precipitations have a damaging impact on the reservoir pores, perforations, downhole and completion equipment, pipeline network, wellhead chokes, and surface facilities. Hydrocarbon production possibly decreased because of the scale accumulation in the well tubular, leading to a well plugging, this requires wells to be shut-in in severe cases to perform a clean-out job. Therefore, scale deposition is badly affecting petroleum economics. This research aims to design a scale dissolver with low cost, non-damaging for the well equipment and has a high performance at the field operating conditions. This paper presents a novel non-corrosive dissolver for sulfate and sulfide composite scale in alkaline pH and works at low-temperature conditions. The scale samples were collected from a production platform from different locations. A complete description of the scale samples was performed as X-ray diffraction (XRD) and X-ray fluorescence (XRF). The new scale dissolver was prepared in different concentrations to examine its dissolution efficiency for the scale with time at low temperatures. The experimental design studied the solid to fluid ratio, temperature, solubility time, and dissolution efficiency in order to achieve the optimum and most economic performance of solubility in terms of high dissolution efficiency with the smallest possible amount of scale dissolver. A solubility comparison was performed with other commercial-scale-dissolvers and the corrosion rate was tested. The experimental work results demonstrated the superior performance of the new scale dissolver. The new scale dissolver showed a solubility efficiency of 91.8% at a low temperature of 45 °C and 79% at 35 °C. The new scale dissolver showed a higher solubility ratio for the scale sample than the ethylenediaminetetraacetic acid (EDTA) (20 wt. %), diethylenetriamine pentaacetic acid (DTPA) (20 wt. %), and HCl (10 wt. %). The corrosion rate for the new non-corrosive dissolver was 0.01357 kg/m2 (0.00278 lb./ft²) which was considered a very low rate and non-damaging for the equipment. The low corrosive effect of the new dissolver will save the extra cost of adding the corrosion inhibitors and save the equipment from the damaging effect of the corrosive acids.

scholarly journals Barium Sulfate Scale Removal at Low-Temperature

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-12
Author(s):  
Hany Gamal ◽  
Saad Al-Afnan ◽  
Salaheldin Elkatatny ◽  
Mohamed Bahgat
Keyword(s):  
Corrosion Rate ◽  
Barium Sulfate ◽  
Oil And Gas ◽  
Ethylenediaminetetraacetic Acid ◽  
Chelating Agent ◽  
Gas Production ◽  
Oil Field ◽  
Rock Interaction ◽  
Dissolution Efficiency ◽  
Diethylenetriamine Pentaacetic Acid

Precipitation of the scale in the oil and gas reservoirs, surface and subsurface equipment, and processing and production facilities is a big problem as it affects petroleum production. The scale precipitations decrease the oil and gas production and cause economical loss. Solving this issue requires an engineering investigation to provide a safe, efficient, and economic solution. Consequently, this study proposed a developed dissolver for barium sulfate scales, where two field-scale samples were collected from different locations. The compositional analysis for scale samples showed that sample 1 is 100% barium sulfate where sample 2 has 97.75% barium sulfate and 2.25% of quartz. The composition of the developed dissolver has diethylenetriamine pentaacetic acid (DTPA) as a chelating agent, oxalic acid, and tannic acids as an activator, nonionic surfactant, and water as the base fluid. The new dissolver was investigated with extensive lab tests to determine the dissolution efficiency, precipitation tendency for the dissolved scale solids, corrosion rate, and fluid-rock interaction. The obtained successful results indicated that the developed dissolver had a dissolution efficiency for two real barium scale samples as the results showed 76.9 and 71.2% at 35°C and 91.3 and 78.4% at 90°C for samples 1 and 2, respectively. The new solution has a great performance compared with common scale dissolvers in the oil field as hydrochloric acid, ethylenediaminetetraacetic acid, and diethylenetriamine pentaacetic acid. The developed dissolver showed a very low precipitation tendency for the scale dissolved solids (1.9 and 3.2% for samples 1 and 2, respectively) under 35°C for 24 hours. Without any additives of corrosion inhibitors, the corrosion rate was 0.001835 g/cm2 at 6.9 MPa and 100°C for 6 hours. Injecting the developed dissolver for damaged sandstone core sample with barite mud by flooding test showed a return permeability of 115%.

Effect of Film Cooling on Low Temperature Hot Corrosion in a Coal Fired Gas Turbine

2003 ◽  
Author(s):  
Vaidyanathan Krishnan ◽  
J. S. Kapat ◽  
Y. H. Sohn ◽  
V. H. Desai
Keyword(s):  
Low Temperature ◽  
Corrosion Rate ◽  
Hot Corrosion ◽  
Film Cooling ◽  
Gas Turbines ◽  
Primary Source ◽  
Operating Conditions ◽  
Coal Gas ◽  
A Chain ◽  
Lower Corrosion Rate

In recent times, the use of coal gas in gas turbines has gained a lot of interest, as coal is quite abundant as a primary source of energy. However, use of coal gas produces a few detrimental effects that need closer attention. This paper concentrates on one such effect, namely hot corrosion, where trace amounts of sulfur can cause corrosion (or sulfidation) of hot and exposed surfaces, thereby reducing the life of the material. In low temperature hot corrosion, which is the focus of this paper, transport of SO2 from the hot gas stream is the primary process that leads to a chain of events, ultimately causing hot corrosion. The corrosion rate depends on SO2 mass flux to the wall as well as wall surface temperature, both of which are affected in the presence of any film cooling. An analytical model is developed to describe the associated transport phenomena of both heat and mass in the presence of film cooling The model predicts how corrosion rates may be affected under operating conditions. It is found that although use of film cooling typically leads to lower corrosion rate, there are combinations of operating parameters under which corrosion rate can actually increase in the presence of film cooling.

Stimulation of Wells Damaged by Barite Present in Filter Cake or Scale

SPE Journal ◽  
2021 ◽  
pp. 1-11
Author(s):  
Igor Ivanishin ◽  
Hisham A. Nasr-El-Din ◽  
Dmitriy Solnyshkin ◽  
Artem Klyubin
Keyword(s):  
High Temperature ◽  
Filter Cake ◽  
Ethylenediaminetetraacetic Acid ◽  
Solid Phase ◽  
Barium Carbonate ◽  
Process Analysis ◽  
Drilling Fluid ◽  
Field Application ◽  
X Ray ◽  
Dissolution Efficiency

Summary High-temperature (HT) deep carbonate reservoirs are typically drilled using barite (BaSO4) as a weighting material. Primary production in these tight reservoirs comes from the network of natural fractures, which are damaged by the invasion of mud filtrate during drilling operations. For this study, weighting material and drilling fluid were sampled at the same drillsite. X-ray diffraction (XRD) and X-ray fluorescence analyses confirmed the complex composition of the weighting material: 43.2 ± 3.8 wt% of BaSO4 and 47.8 ± 3.3 wt% of calcite (CaCO3); quartz and illite comprised the rest. The drilling fluid was used to form the filter cake in a high-pressure/high-temperature (HP/HT) filter-press apparatus at a temperature of 300°F and differential pressure of 500 psig. Compared with the weighting material, the filter cake contained less CaCO3, but more nondissolvable minerals, including quartz, illite, and kaolinite. This difference in mineral composition makes the filter cake more difficult to remove. Dissolution of laboratory-grade BaSO4, the field sample of the weighting material, and drilling-fluid filter cake were studied at 300°F and 1,000 to 1,050 psig using an autoclave equipped with a magnetic stirrer drive. Two independent techniques were used to investigate the dissolution process: analysis of the withdrawn-fluid samples using inductively coupled plasma-optical emission spectroscopy, and XRD analysis of the solid material left after the tests. The dissolution efficiency of commercial K5-diethylenetriaminepentaacetic acid (DTPA), two K4-ethylenediaminetetraacetic acid (EDTA), Na4-EDTA solutions, and two “barite dissolvers” of unknown composition was compared. K5-DTPA and K4-EDTA have similar efficiency in dissolving BaSO4 as a laboratory-grade chemical and a component of the calcite-containing weighting material. No pronounced dissolution-selectivity effect (i.e., preferential dissolution of CaCO3) was noted during the 6-hour dissolution tests with both solutions. Reported for the first time is the precipitation of barium carbonate (BaCO3) when a mixture of BaSO4 and CaCO3 is dissolved in DTPA or EDTA solutions. BaCO3 composes up to 30 wt% of the solid phase at the end of the 6-hour reaction, and can be dissolved during the field operations by 5 wt% hydrochloric acid. Being cheaper, K4-EDTA is the preferable stimulation fluid. Dilution of this chelate increases its dissolution efficiency. Compared with commonly recommended solutions of 0.5 to 0.6 M, a more dilute solution is suggested here for field application. The polymer breaker and K4-EDTA solution are incompatible; therefore, the damage should be removed in two stages if the polymer breaker is used.

scholarly journals Predictive Modelling of Wellhead Corrosion due to Operating Conditions: A Field Data Approach

2012 ◽  
Vol 2012 ◽  
pp. 1-8 ◽  
Author(s):  
Chinedu I. Ossai
Keyword(s):  
Corrosion Rate ◽  
Field Data ◽  
Oil And Gas ◽  
Multiple Linear Regression Model ◽  
Predictive Modelling ◽  
Operating Conditions ◽  
Experimental Results ◽  
Operating Parameters ◽  
Oil And Gas Fields ◽  
The Impact

The flow of crude oil, water, and gas from the reservoirs through the wellheads results in its deterioration. This deterioration which is due to the impact of turbulence, corrosion, and erosion significantly reduces the integrity of the wellheads. Effectively managing the wellheads, therefore, requires the knowledge of the extent to which these factors contribute to its degradation. In this paper, the contribution of some operating parameters (temperature, CO2 partial pressure, flow rate, and pH) on the corrosion rate of oil and gas wellheads was studied. Field data from onshore oil and gas fields were analysed with multiple linear regression model to determine the dependency of the corrosion rate on the operating parameters. ANOVA, value test, and multiple regression coefficients were used in the statistical analysis of the results, while in previous experimental results, de Waard-Milliams models and de Waard-Lotz model were used to validate the modelled wellhead corrosion rates. The study shows that the operating parameters contribute to about 26% of the wellhead corrosion rate. The predicted corrosion models also showed a good agreement with the field data and the de Waard-Lotz models but mixed results with the experimental results and the de Waard-Milliams models.

scholarly journals The inhibition performance of mono-ethylene glycol on corrosion rate of x-80 grade carbon steel in saturated brine environment.

2020 ◽  
Vol 1 (1) ◽  
Keyword(s):  
Acetic Acid ◽  
Charge Transfer ◽  
Carbon Steel ◽  
Corrosion Rate ◽  
Ethylene Glycol ◽  
Oil And Gas ◽  
Gas Production ◽  
Electrochemical Measurements ◽  
Co2 Corrosion ◽  
Formation Water

The formation/deposition of hydrate and scale in gas production and transportation pipeline has continue to be a major challenge in the oil and gas industry. Pipeline transport is one of the most efficient, reliable and safer means of transporting petroleum products from the well sites to either the refineries or to the final destinations. Acetic acid (HAc), is formed in the formation water which also present in oil and gas production and transportation processes. Acetic acid aids corrosion in pipelines and in turn aids the formation and deposition of scales which may eventually choke off flow. Most times, Monethylene Glycol (MEG) is added into the pipeline as an antifreeze and anticorrosion agent. Some laboratory experiments have shown that the MEG needs to be separated from unwanted substance such as HAc that are present in the formation water to avoid critical conditions in the pipeline. Internal pipeline corrosion slows and decreases the production of oil and gas when associated with free water and reacts with CO2 and organic acid by lowering the integrity of the pipe. In this study, the effect of Mono-Ethylene Glycol (MEG) and Acetic acid (HAc) on the corrosion rate of X-80 grade carbon steel in CO2 saturated brine were evaluated at 25oC and 80oC using 3.5% NaCl solution in a semi-circulation flow loop set up. Weight loss and electrochemical measurements using the linear polarization resistance (LPR) and electrochemical impedance spectroscope (EIS) were used in measuring the corrosion rate as a function of HAc and MEG concentrations. The results obtained so far shows an average corrosion rate increases from 0.5 to 1.8 mm/yr at 25oC, and from 1.2 to 3.5 mm/yr at 80oC in the presence of HAc. However, there are decrease in corrosion rate from 1.8 to 0.95 mm/yr and from 3.5 to 1.6mm/yr respectively at 25oC and 80oC on addition of 20% and 80% MEG concentrations to the solution. It is also noted that the charge transfer with the electrochemical measurements (EIS) results is the main corrosion controlling mechanism under the test conditions. The higher temperature led to faster film dissolution and higher corrosion rate in the presence of HAc. The EIS results also indicate that the charge transfer controlled behaviour was as a result of iron carbonate layer accelerated by the addition of different concentrations of MEG to the system. Key words: CO2 corrosion, Carbon steel, MEG, HAc, Inhibition, Environment.

Corrosion and Wear Resistant Boronizing for Tubulars and Components Used Down-Hole

2021 ◽  
Author(s):  
Roger Machado ◽  
Paola Andrea de Sales Bastos ◽  
Danny Daniel Socorro Royero ◽  
Eugene Medvedovski
Keyword(s):  
Oil And Gas ◽  
Chemical Vapour ◽  
Protective Layer ◽  
Gas Production ◽  
Operating Conditions ◽  
Material Loss ◽  
Oil And Gas Production ◽  
Dimensional Changes ◽  
Wear And Corrosion ◽  
Service Conditions

Abstract Components and tubulars in down-hole applications for oil and gas production must withstand severe wear (e.g. erosion, abrasion, rod wear) and corrosion environments. These challenges can be addressed through boronizing of steels achieved employing chemical vapour deposition-based process. This process permits protection of the entire working surfaces of production tubulars up to 12m in length, as well as various sizes of complex shaped components. The performance of these tubulars and components have been evaluated in abrasion, erosion, and corrosion conditions simulating the environment and service conditions experienced in down-hole oil and gas production. Harsh service conditions are very common in the oil industry and the combination of abrasion, friction-induced wear, erosion, and corrosion environments can be quite normal in wells producing with the assistance of artificial lift methods. The boronized steel products demonstrated significantly higher performance in terms of material loss when exposed to harsh operating conditions granting a significant extension of the component service life in wear and corrosion environments. As opposed to many coating technologies, the boronizing process provides high integrity finished products without spalling or delamination on the working surface and minimal dimensional changes. Successful application of tubulars and components with the iron boride protective layer in oil and gas production will be discussed and presented.

An Experimental Study of Controlled Gas-Phase Combustion in Porous Media for Enhanced Recovery of Oil and Gas

2001 ◽  
Author(s):  
Javier E. Sanmiguel ◽  
S. A. (Raj) Mehta ◽  
R. Gordon Moore
Keyword(s):  
Experimental Study ◽  
Porous Media ◽  
Gas Phase ◽  
Oil Recovery ◽  
Gas Flow ◽  
Oil And Gas ◽  
Enhanced Recovery ◽  
Gas Production ◽  
Operating Conditions ◽  
Operating Pressure

Abstract Gas-phase combustion in porous media has many potential applications in the oil and gas industry. Some of these applications are associated with: air injection based improved oil recovery (IOR) processes, formation heat treatment for remediation of near well-bore formation damage, downhole steam generation for heavy oil recovery, in situ preheating of bitumen for improved pumping, increased temperatures in gas condensate reservoirs, and improved gas production from hydrate reservoirs. The available literature on gas-phase flame propagation in porous media is limited to applications at atmospheric pressure and ambient temperature, where the main application is in designing burners for combustion of gaseous fuels having low calorific value. The effect of pressure on gas-phase combustion in porous media is not well understood. Accordingly, this paper will describe an experimental study aimed at establishing fundamental information on the various processes and relevant controlling mechanisms associated with gas-phase combustion in porous media, especially at elevated pressures. A novel apparatus has been designed, constructed and commissioned in order to evaluate the effects of controlling parameters such as operating pressure, gas flow rate, type and size of porous media, and equivalence ratio on combustion characteristics. The results of this study, concerned with lean mixtures of natural gas and air and operational pressures from atmospheric (88.5 kPa or 12.8 psia) to 433.0 kPa (62.8 psia), will be presented. It will be shown that the velocity of the combustion front decreases as the operating pressure of the system increases, and during some test operating conditions, the apparent burning velocities are over 40 times higher than the open flame laminar burning velocities.

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