High Temperature Combinational Foamer-Corrosion Inhibitor Product for Maturing Gas Wells

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 106699, "An Improved Model for the Liquid-Loading Process in Gas Wells," by Frank van Gool, SPE, and Peter K. Currie, SPE, Delft University of Technology, prepared for the 2007 SPE Production and Operations Symposium, Oklahoma City, Oklahoma, 31 March–3 April. An improved model for describing the liquid-loading process in gas wells has been introduced. The new model improves how the Dousi model handles the downhole inflow and outflow between the well and the reservoir and makes more-realistic and -detailed assumptions with respect to the production and injection interval. Also, the new model can be used to predict future behavior of the well in a more realistic fashion. The difference between the new model and the Dousi model is that flow-rate changes occur slower when liquid loading begins, reflecting realistic inflow-performance assumptions. Introduction Liquid loading is a serious problem in maturing gas fields. The liquid-loading process occurs when the gas velocity within the well drops below a certain critical gas velocity. The gas then is unable to lift the water that is coproduced with the gas (either condensed or formation water) to surface. The water will fall back and accumulate downhole. A column is formed that imposes a backpressure on the reservoir and reduces gas production. The process eventually results in intermit-tent gas production, and the well dies. Methods of reducing liquid loading include production-string resizing in which a smaller tubing size is chosen to increase the gas velocity above the critical Turner rate, compressor installation to lower the tubinghead pressure thereby increasing the gas velocity above the critical Turner rate, plunger lift to lift all the liquids by use of the gas pressure during shutdown of the well, pump installation to pump the liquids during production, foaming the liquids so that it is easier for the gas to lift all the fluids thus reducing the critical Turner rate, and gas lifting with gas from other wells to decrease the pressure loss in the tubing and increase the velocity. The best solution for a given well depends on the properties of that particular well. Metastable Flow During the liquid loading of a mature gas well, the gas velocity in the tubing drops when the reservoir pressure drops, and, in time, the gas velocity may fall below the critical Turner rate. At that time, the produced liquids fall back down the wellbore and accumulate at the bottom of the well. This liquid column forms a backpressure on the reservoir, thus slowing the production rate and accelerating the problem. However, in parts of the well, the pressure can be lower than in the reservoir such that production still occurs even though at the bottom of the well the pressure from the liquid column is high enough that liquid injection can take place. If the liquid-injection rate equals the rate of liquid coproduction with the gas, metastable production occurs. This metastable flow rate is observed in the field. Data analyzed from gas wells in The Netherlands, including production profiles, temperature, and pressure, showed several examples indicating the existence of a metastable flow rate.

Investigation on the efficiency of corrosion inhibitor in CO2 corrosion of carbon steel in the presence of iron carbonate scale

Liquid load or condensate banking is a common well health issue in gas/gas-condensate reservoirs that decreases well productivity by a factor of two to four. Due to the depletion of bottom-hole pressure, the produced liquid accumulates around the wellbore and creates a static column of liquid that reduces gas production until well production ceases. Enhancing gas recovery by CO2 injection is a promising technology because it reduces greenhouse gas emissions and improves CO2 storage. More investigation needs to be conducted to understand the role of supercritical CO2 (SCCO2) in minimising liquid loading. The aim of this research is to examine the impact of SCCO2 in surface tension, condensate viscosity and well productivity. This study consists of simulation and laboratory experiments. Eclipse 300 was used to develop a model that examines the effect of SCCO2 injection on reducing liquid loading issues by varying the well parameters. We found that injecting SCCO2 improved the microscopic displacement efficiency and minimised liquid loading by decreasing the condensate viscosity and the surface tension. The model shows that (1) condensate recovery increases when the injection rate increases up to a limit after which there is no change of production and (2) condensate recovery improves with decreasing production rate.

Surface tension plays a very important role in the stimulation of gas wells. A low surface tension is required to reduce capillary forces that trap the aqueous phase in the formation. Accumulation of the aqueous phase near the wellbore area, known as water blockage, leads to a significant reduction in gas production. An experimental study was conducted to examine the effects of various acids and stimulation additives on surface tension. A Krüss tensiometer (Model K-12) was used to conduct surface tension measurements. Acids examined included: HCl, acetic, citric, formic, and combinations of these acids. Stimulation additives tested included: mutual solvent, short-chain alcohols, corrosion inhibitors, hydrogen sulfide scavengers, iron-control agents, and clay stabilizers. In addition, the effects of three classes of surfactants (nonionic, cationic and anionic) on surface tension of acid solutions were investigated. The surface tension of acid stimulating fluids is a complex function of acid type, concentration, and additive type and concentration. Acetic and formic acids had lower surface tension values than HCl, especially at high acid concentrations. The surface tension of the organic acids examined depended on the pKa value of the acid. Organic acids with high pKa values had low surface tension values. The surface tension of hydrochloric acid can be reduced by mixing with acetic acid. EGMBE lowered the surface tension of acetic, formic and hydrochloric acids up to 10 wt%. Increasing the concentration of EGMBE above 10 wt% had no significant effect on the surface tension of these acids. The effect of organic acid strength on surface tension diminished in the presence of EGMBE. Short-chain alcohols reduced the surface tension of 15 wt% HCl with the greatest reduction obtained with n-butanol. Citric and erythorbic acids, which are usually used as iron control agents significantly reduced the surface tension of 15 wt% HCl. Ionic surfactants reduced the surface tension of hydrochloric acid more than the two nonionic surfactants tested. The three corrosion inhibitors examined reduced surface tension up to a critical concentration beyond which they had no effect on surface tension. An aldehyde-based H2S scavenger lowered the surface tension of 15 wt% acid solutions at very low concentrations. Clay stabilizers (cationic polymers) did not significantly affect the surface tension of 15 wt% HCl. Addition of a hydrogen sulfide scavenger, a nonionic surfactant or a corrosion inhibitor into solutions of 15 wt% HCl and EGMBE had a small effect on the surface tension of the acid.

The inhibition efficiency of Zn2+, 3-phosphonopropionic acid (3-PPA), benzotriazole (BTA) and two synthesized benzotriazole derivatives namely 1-(2-pyrrole carbonyl) benzotriazole (PCBT) and 1-(2-thienylcarbonyl) benzotriazole (TCBT) were evaluated as inhibitors for the corrosion of mild steel in ground water. The inhibition efficiencies of PCBT and TCBT in combination with Zn2+ and 3-PPA were also investigated and the results were compared with BTA. In order to study the corrosion rate and inhibition efficiency we employed potentiodynamic polarization and electrochemical impedance spectroscopy (EIS). Further characterization using Fourier transform infrared spectroscopy (FT-IR) and X-ray diffraction (XRD) demonstrates the adsorption of inhibitor and the formation of corrosion products on the mild steel surface, respectively. Combination of PCBT along with Zn2+ and 3-PPA shows better corrosion inhibition efficiency than other inhibitor combinations and the individual inhibitors.

Plant extracts and bacterial biofilm are acknowledged to offer impressive corrosion-inhibitory activities. However, anticorrosive properties of their combination are still less reported. Thus, in the present study, we aimed to evaluate the corrosion inhibition efficiency of Saccharum officinarum bagasse (SOB) plant extract, Pseudomonas chlororaphis (P. chlororaphis), and Bacillus coagulans (B. coagulans) individually and in combination (SOB+P. chlororaphis) and (SOB+B. coagulans) using copper sheets in different acidic solutions (pH 5.5) and at three different temperatures (300 K, 305 K, and 310 K). The weight loss and electrochemical measurements were carried out to evaluate the corrosion rate and inhibition efficiencies. Alteration in the surface morphology of copper sheets was analyzed employing Fourier transform infrared (FTIR) spectroscopy, UV visible spectroscopy, scanning electron microscope (SEM), X-ray diffraction (XRD), energy dispersive X-ray (EDX), and X-ray photoelectron spectroscopy (XPS). Amongst all, SOB extract alone exhibited the highest anticorrosive efficiency, whereas the combination of SOB with P. chlororaphis revealed excellent inhibition efficiency. Weight loss studies indicated that at 300 K, the combination of SOB extract with P. chlororaphis significantly reduces the corrosion rate up to 11.90% with the highest inhibition efficiency of 88.09%. However, with an increase in temperature, i.e. 310 K, the corrosion rate diminishes to 13.04% with inhibition efficiency of 86.95% for 500 µL concentration in HNO3 solution. The combination of an SOB extract with P. chlororaphis displayed a maximum corrosion inhibition efficiency of 85.11% in the potentiodynamic polarization (PP) study and 88.23% in the electrochemical impedance spectroscopy (EIS), respectively and found in agreement with the efficiency obtained in the weight loss study. Later, the synergistic parameter (SƟ) advocated that the SOB extract and P. chlororaphis do not interact mutually whereas ∆G°ads values suggested the physisorption of these agents on the copper plates follows Langmuir adsorption isotherm. The spectral analysis and SEM images of the copper plate revealed that the combination of SOB extract with P. chlororaphis forms a strong protective layer over its surface and prevents corrosion. In conclusion, the combination of SOB extract with P. chlororaphis holds impressive anticorrosive properties and may be explored further to attain their industrial utility.

Gas production in sanitary landfills is a subject of much concern because of the potential hazards of CH4 combustion and of groundwater contamination by CO2. This study investigated the pattern of sanitary landfill gas production and the factors which affect it. A basis for study was prepared by examining factors which influence gas production in soil and sewage sludge digesters. The factors studied included moisture content, temperature, pH, alkalinity, Eh, and nutrition. It was then undertaken to determine whether or not this information was applicable to the landfill. A pattern for landfill gas production was proposed based on the assumption that an anaerobic environment would be achieved and maintained after refuse placement. Four phases were identified: I. Aerobic; II. Anaerobic Non-Methanogenic; III. Anaerobic Methanogenic Unsteady; and IV. Anaerobic Methanogenic Steady. The duration of these phase and the relative amounts of gases produced within each phase were studied. An investigation of information available on factors affecting gas production in sanitary landfills also was made. It was found that, in general, the principles developed from the study of gas production in other media were applicable to the landfill environment. It was found that gas production increases with increased moisture content but that conditions of high infiltration are often conducive to reduction in gas production apparently caused by modifications to the microbial environment. There appears to exist a typical pattern of temperature variation within the landfill with a peak temperature being reached during the initial phase of aerobic decomposition. The magnitude of this peak is related to the refuse temperature at placement. Subsequent temperatures are lower and tend to fluctuate with season. Optimum temperatures for gas production are in the range of from 30°C to 35°C, however, landfill temperatures are often lower than this. Optimum levels of pH and alkalinity exist which maximize gas production rates. The types and amounts of gas produced are influenced by refuse composition. A scheme was proposed to illustrate how the various factors influence landfill gas production and how these may interact. Those factors over which some control may be exerted during landfill design and operation were identified.

Free base phthalocyanine coating as a superior corrosion inhibitor for copper surfaces: A combined experimental and theoretical study

Corrosion inhibitors used in the petroleum industry are a necessity to include in any acid job. When corrosion occurs to downhole tubulars and equipment, huge expenses are required to maintain the integrity and performance of the well. Unfortunately, commonly used corrosion inhibitors are accompanied with extreme environmental concerns and risk to human health. The recent developments in corrosion inhibitors have resolved the environmental aspect by focusing on biodegradability of these compounds, however, these inhibitors still struggle with issues of toxicity and high temperature stability. The project aims to develop new green, non-toxic, environmentally friendly corrosion inhibitors capable of performing well at high temperature conditions faced in the oil and gas industry. To achieve this goal, 13 commonly available flowers were screened for corrosion inhibition properties. The tests involved using low carbon steel (N-80) coupons and exposing them to 15 wt.% HCl solutions at temperatures between room temperature and 250 °F using a HPHT corrosion reactor to imitate oilfield conditions. A concentration of 0.2-2 wt.% grounded flowers were used to prevent corrosion. Moreover, a control solution containing no corrosion inhibitor was used to establish a corrosion rate for a base case. Upon identifying high performing flowers, extracts of these flowers were subsequently tested to save cost by minimizing quantity needed while achieving acceptable performance. The corrosion inhibition efficiency of the different flowers was compared at various concentrations and temperatures as well as the effect of adding corrosion inhibitor intensifiers. The results revealed that one new inhibitor can be developed from the 13 flower samples tested. The corrosion rate of the flower extract after 6 hours at 150°F was 0.0398 lb/ft2. Additionally, this flower extract was assessed at 200°F and 250°F with the addition of 1 wt.% corrosion inhibitor intensifier and exhibited a corrosion rate of 0.00823 lb/ft2 and 0.0141 lb/ft2, respectively. The results in this work share one new naturally occurring, green, non-toxic, high-temperature stable corrosion inhibitors that can be developed from flowers and can successfully protect the tubular during acid treatments achieving rates below the industry standard of 0.05 lb/ft2 for 6 hours at temperatures up to 250°F.

In an effort to improve the practical application of benzimidazoles as corrosion inhibitors, hydrophilic groups were introduced through the attachment of aldoses to the benzimidazole ring. In this study, computational techniques, including DFT calculations and Monte Carlo simulations were used to predict the potentials of new aldo-benzimidazoles (benzimidazolyl-pentane-1,2,3,4,5-pentaol) as corrosion inhibitors for mild steel in aqueous acid media. The results showed that the compounds, which are inherently more hydrophilic than native benzimidazoles promise to exhibit higher corrosion inhibition efficiencies than conventional benzimidazole derivatives. Highly electron-donating (e.g. -OCH3) and electron-withdrawing (e.g. -NO2) substituents increased the corrosion inhibition efficiencies, making g-bzm-methoxy and g-bzm-nitro to have the highest corrosion inhibition efficiencies as predicted from the QSAR model. All the compounds showed appreciable adsorption energies on Fe(1 1 0) surface with bond distances that suggest non-covalent interactions between the N-atom of the benzimidazole ring and Fe. All the compounds showed lower toxicity to fathead minnow than benzimidazole except g-bzm-benzophenone, g-bzm-diCl, and g-bzm-dimethyl. The compounds also exhibited lower toxicity to Daphnia magna and T. pyriformis, suggesting their eco-friendly attributes. The study provides insights into the sustainability of benzimidazolyl-pentane-1,2,3,4,5-pentaol derivatives as corrosion inhibitors and recommends complementary experimental studies on the compounds.

Determining optimum well locations is a crucial step in field development. Often, broad possibilities and constrains on computational resources limit the scenarios that can be considered. When dealing with heterogeneities, the intuitive engineering judgment may not be sufficient, and use of optimization algorithms becomes necessary in finding a favorable production plan. Although there have been extensive publications on optimization algorithms for oil reservoirs, there is little research aimed at gas or gas condensate reservoirs. In this work, we studied optimization of horizontal well placement in gas condensate reservoirs. One of the current challenges in development of gas condensate fields is condensate blockage. As pressure decreases condensate accumulates around the wellbore, leading to significant reduction in gas production. Horizontal wells can effectively solve this problem. However, due to their high cost, and complex phase behavior determining optimum locations cannot be based only on intuitive judgments. Here we present a horizontal well-placement optimization method for gas condensate reservoirs based on a modified genetic algorithm. Unlike oil reservoirs, the cumulative production in gas reservoirs does not vary significantly (although the variation is not economically negligible) and there are possibly more local optimums. Therefore the possibility of finding better production scenarios in subsequent optimization steps is not much higher than the worse case scenarios, which delays finding the best production plan. In this work, we use a cumulative distribution function to magnify the difference between production scenarios. As a result of this change we were able to find the best scenario with considerably fewer simulations. We apply the modified algorithm to a section of Qatar's North Field, a gas condensate field with the world's largest gas reserves. Our results show that this method can efficiently find the optimum horizontal well locations and can lead to valuable increase in gas and condensate production.

Genetic function approximation (GFA) algorithm was used to model the quantitative structure–activity relationship (QSAR) among corrosion inhibition efficiency, friction coefficient and oil film strength of the thiadiazole derivatives as corrosion inhibitor and antiwear and friction-reducing agent. Corrosion inhibition efficiency, friction coefficient and oil film strength of these compounds on the steel surface contained in the emulsion were studied by weight loss test and a fourball friction and wear test. The results show that quantum descriptors are a better choice for predicting the corrosion inhibition efficiency, friction coefficient and oil film strength of lubricants. For the thiadiazole derivatives, friction coefficient of the lubricants is inversely proportional to their inhibition efficiency and oil film strength.

Biodegradation of corrosion inhibitors and their influence on petroleum product pipeline

The presence of salts and dissolved gas like CO2 that is carried with natural gas and crude oil along the pipeline is the main reason for corrosion and scale formation. These problems are usually resolved separately by corrosion inhibitors and scale inhibitors or acidification. Meanwhile, utilizing a compound to resolve both corrosion and scale formation has an advantage in the economic side and working time. N,O-carboxymethyl chitosan or N,O-CMCs is one of the chitosan's derivates. It is water-soluble and has different functional groups. Those properties support its capability as a complexing agent on corrosion and scale inhibitors. Synthesis of N,O-CMCs was carried out by chemical reactions between chitosan and chloroacetic acid under alkaline circumstances. N,O-CMCs product was characterized using FT-IR and 1H-NMR spectroscopy. The inhibition efficiency was analyzed by electrochemical impedance spectroscopy (EIS) and potentiodynamic polarization techniques. The measurements showed that the highest efficiency of corrosion inhibition reached 63.54% when the concentration and temperature were 30 ppm and 35 °C, respectively. N,O-CMCs was classified as a mixed-type inhibitor. The adsorption mechanism of the inhibitor followed Langmuir adsorption isotherm. The static scale inhibition test informed that the optimum inhibition efficiency of N,O-CMCs reached 60.00%.

Liquid loading in horizontal gas wells impairs gas production and if not diagnosed in a timely manner can kill the well. Liquid loading occurs when the gas production rate declines and gas velocity drops below the critical velocity required to carry liquid to surface. Different models used in conventional reservoirs such as droplet, film or transient multiphase flow models are also applied with modifications in unconventional gas reservoirs. However, none of these models show great success when applied to inclined and horizontal wells in shale gas reservoirs. This is due to the fact that these models are developed for vertical wells and cannot identify the right multiphase flow regime in inclined and horizontal sections of the well. It is also extremely hard defining the right liquid droplet size and shape or liquid film thickness as well trajectory changes. Furthermore, these models cannot accurately predict the transient between annular and slug flow regimes in horizontal wells. As more wells are produced in shale gas reservoirs, a great amount of information from production control and monitoring becomes available which can be used to build a data-based smart model for real time diagnostics of liquid loading in new wells. In this new approach, data (pressure, completion, and productions) from many wells which have experienced or not experienced liquid loading problems in the same area will be the basis for developing the smart model. What is being proposed here is a unique approach that includes developing a data-based technology for the training of neural networks that can be used as a smart model in real time to identify the start of liquid loading in unconventional gas wells. This innovative technique incorporates a unique fuzzy pattern recognition algorithm and unsupervised analysis technique to identify the most influential parameters impacting liquid loading in unconventional gas wells. The main objective for this manuscript is to develop a smart model that can predict the dynamics of liquid-gas interface and identify the start of liquid loading. Finally, the minimum gas velocity/rate to avoid the liquid loading can be determined. For this study, a Marcellus Shale reservoir is selected. Production and completions history of 160 wells are collected. First the study is performed on a single well where 70 percent of the information is used for neural network training purposes, 15% for calibration, and 15% for validation of the model. The results show that the smart model is able to precisely predict the start of the liquid loading in the well and raise a warning flag when the possibility of liquid loading is high. Next, series of wells in the region is picked and smart model is built based on the 70% training, 15% calibration, and 15% validation. This model is then used to predict the liquid loading in a different well in the same region as a completely blind well. The results show high accuracy and reliability in predicting the start of liquid loading. To overcome the implicit dependency of the model to Turner et al. critical velocity criteria during the training, unsupervised learning algorithm is used to predict the loading and unloading status of the wells. The technique showed great success in predicting the well status and confirmed with field observations. The new smart model developed for Marcellus Shale shows great promise that this approach can be applied in other areas where limited history of production and liquid loading exists.