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ABSTRACT Experiments studying oil-water flows were conducted in a 10-cm diameter, 40-m long, horizontal pipeline. Oil (viscosity 3 cP at 25ยฐC) and ASTM substitute seawater were used at superficial mixture velocities ranging from 0.4 to 3.0m/s. in situ water cut and in situ velocity along the pipe across section have been measured at a temperature of 25ยฐC and a carbon dioxide partial pressure of 0.13 MPa for a whole range of water cut. A novel mathematical segregated flow model, four-layer/phase was then developed for intermediate oil-water flow patterns of semi-segregated, semi-mixed and mixed as a three-phase model by incorporating experimental data. The mixed layer in the three-layer/phase model is further divided into water-in-oil (oil-continuous) and oil-in-water (water-continuous) layers by the phase inversion point. The experimental data are in good agreement with the predicted water film height from the model. INTRODUCTION The simultaneous flow of oil and water in pipelines is a common occurrence in oil production systems, and occurs from the well perforations to the final stage of separation. As the well ages, the reservoir pressure decreases. To enhance oil recovery, water injection is commonly used to maintain reservoir pressure. Meanwhile, as the oil saturation decreases, an increasing amount of water seeps into the well from the surroundings. Thus, the water fraction will tend to increase over the productive life of the well and the water cuts can be up to 99%, and many wells are now operated at water cuts as high as 80%. Therefore, the possibility of corrosion in oil-water flows is very high. It is well known that injection of corrosion inhibitors is most widely used of all the methods of curbing corrosion in multiphase. The effectiveness of the inhibitor depends on the pipeline material, the inhibitor composition and flow conditions. To be effective, the inhibitor must be introduced into the phase in contact with the pipe wall. The decision on whether to use oil or water soluble inhibitors, amount of inhibitor can be made effectively, only if flow patterns and phase distributions under different flow conditions are known. Gas-liquid flows have been extensively studied. Even in the studies of gas-oil-water systems, the two liquid phases are almost always treated as a single mixed fluid. Research works have shown that the flow characteristics of oil-water mixtures are significantly different from the gas-liquid systems. These differences arise mainly from the much smaller differences in density and viscosity, compared to the gas-liquid flows. The density ratio of the fluids is typically in the range of 0.7--1.1, compared with values of 0.001--0.2 for gas-liquid systems l. The flow of oil-water mixtures within a pipeline is highly complex due to the slip between oil and water, similar to the slip between gas and liquid, and the formation of dispersions or emulsions, different from gas-liquid flows. Understanding the distinctive features in oil-water flows is extremely important for predicting corrosion in oil-water pipelines. However, very few studies have been performed on pipeline flows of two immiscible liquid phases. The research work on corrosion in oil-water flows has been even sparser.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT As part of a recent planning stage for a new oil and gas field development in North East Abu Dhabi (NEAD) a major corrosion risk assessment and material selection review has been carried out. This review covered corrosion predictions, material selection and corrosion control planning for production tubulars, flow lines and trunklines as well as corrosion risk assessment for the downhole injection tubulars. This oil and gas field is somewhat unique in being designed for secondary recovery based on water alternating gas (WAG) injection. The corrosion review used two different corrosion modeling systems as well as flow prediction software. The differences in the outcome of the two packages and the overall conclusions for the corrosion risk assessment are outlined in this paper. INTRODUCTION & BACKGROUND The new field will comprise two separate producing systems (Zone ?B? and Zone ?F?) and will incorporate Water-Alternating-Gas (WAG) for enhanced recovery. The injected gas will be dehydrated prior to WAG injection and gas lift injection. The details of the WAG process were not yet finalized at the time of the corrosion risk assessment. However, for this exercise a general cycle of 4 years of gas injection, then 14 years of alternating of water and gas, then water only for remainder of field life has been assumed.
- Europe (0.46)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.25)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT Several prediction models for CO2 corrosion of oil and gas pipelines have been developed. Some of the models are based on mechanistic modeling of the different processes involved in CO2 corrosion of carbon steel, while other models are mainly based on empirical correlations with laboratory or field data. The models differ considerably in how they predict the effect of protective corrosion films and the effect of oil wetting on CO2 corrosion, and these two factors account for the most pronounced differences between the various models. The paper gives an overview of prediction models used in the oil and gas industry for evaluation of CO2 corrosion of carbon steel. INTRODUCTION Different oil companies and research institutions have developed a large number of prediction models for CO2 corrosion of carbon steel. Very different results can be obtained when the models are run for the same cases due to the different philosophies used in the development of the models. Some of the models predict corrosion rates based on full water wetting and little protection from corrosion product films. These models have a built-in conservatism and can overpredict the corrosion attack significantly for many cases. On the other hand, there is little risk that they would predict low corrosion rates for situations where corrosion problems were actually encountered in the field. Other models assume protection from oil wetting or formation of protective corrosion films and predict generally much lower corrosion rates. These models often rely to a larger degree on the company's field experience of conditions where the corrosion rates have been at an acceptably low level. Some of the models are based on mechanistic modeling of the different chemical, electrochemical and transport processes involved in CO2 corrosion of carbon steel. Other models are mainly based on empirical correlations with laboratory or field data. However, the mechanistic models are usually tuned against lab data to some degree, while the laboratory and field data models often have some mechanistic equations as a starting point. The differences in predicting the effects of oil wetting and corrosion product films represent the most important differences between the various CO2 corrosion models. Some of the models have a very strong effect of oil wetting for some flow conditions, while other models do not consider oil wetting effects at all. Some models include strong effects of protective iron carbonate films especially at high pH or high temperature, some include a qualitative risk for localized corrosion attack and some do not take any account for protective corrosion films for formation water cases due to risk for localized attack. Several models take production rates as input and uses more or less simplified flow models to calculate the flow parameters, while other models take liquid flow velocity or shear stress as input without incorporating any flow modeling. Some of the models consider top-of-line corrosion for wet gas pipelines with condensation of water. There are also large differences in the type of water chemistry input required for the different models. All of the models are basically CO2 corrosion models. Several of the models take the effect of H2S or organic acid on the pH calculation into account, but most of the models are not intended for use in situations where H2S or organic acids dominates the corrosion process.
- Europe (0.93)
- Asia > Middle East > Israel > Mediterranean Sea (0.44)
- North America > United States > Texas > Harris County > Houston (0.17)
ABSTRACT Water-wetting is a crucial issue in CO2 corrosion of multi-phase flow pipelines made from mild steel. This study demonstrates the use of a novel benchtop apparatus, a horizontal rotating cylinder, for study of the effect of water wetting on COa corrosion of mild steel in two-phase flow. The setup is similar to a standard rotating cylinder except for its horizontal orientation and the presence of two phases - typically water and oil. The apparatus has been tested by using mass transfer measurements and CO2 corrosion measurements in single-phase water flow. CO2 corrosion measurements were subsequently performed using a water/hexane mixture with water cuts varying between 5 and 50%. While the metal surface was primarily hydrophilic under stagnant conditions a variety of dynamic water wetting situations was encountered as the water cut and fluid velocity were altered. Threshold velocities were identified at various water cuts when the surface became oil-wet and corrosion stopped. INTRODUCTION In the open literature, there is only a handful of studies related to the effect of water wetting on CO2 corrosion. In a widely used model of CO2 corrosion 1 the water wetting effect is accounted for by a binary (0/1) correction factor. This approach is based on two key studies" the work of Wicks and Fraser a who identified 1 m/s as the minimal velocity for many crude oils to entrain a water phase and the study of Lotz et al. 3 who have found that in most cases the water cut has to exceed 30 % before Current address" Director, NSF I/U CRC Corrosion and Multiphase Flow, Ohio University, Stocker Center, Athens, OH 45701-2979, USA. any water separates out from the oil and wets the steel surface. On the other hand there is almost a consensus in the industry that this simple rule-of-thumb is too restrictive and often wrong. It is worth while mentioning some extreme cases in order to illustrate the point. On one hand anecdotal evidence suggests that serious CO2 corrosion was observed in some pipelines with as low as 1% water cut. On the other hand it has also been reported that in some cases pipelines carrying more up to 40% water exhibited little or no corrosion. Flow regime, temperature, crude oil composition, additives, etc. all affect the water wetting in the field and clearly at the present there is no simple universal way of accounting for all these factors. The most reliable approach is still experimentation under conditions which resemble the field as closely as possible. While accurate field measurements are very difficult and almost prohibitively expensive, even laboratory studies of CO2 corrosion under multi-phase flow conditions are complicated and very costly. They typically involve large-scale multi-phase flow corrosion loops and large quantities of working fluids 4. In such large systems, it is not easy to isolate the effect of water wetting and identify its contribution to the overall corrosion rate which is affected by numerous other factors such as water chemistry, temperature and the presence of inhibitors, to name just a few key ones.
- Research Report > New Finding (0.54)
- Research Report > Experimental Study (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.37)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)