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ABSTRACT ABSTRACT In this paper, solids deposition in 36 inch (0.914 m) x 47 km and 48 inch (1.219 m) x 19 km regions of a transmission oil pipeline are analyzed and several families-of-curves are generated to study the effect of solid particles’ average size; pipeline flow rate, diameter and fluid viscosity; and pipeline length on the deposition rate of solids with average density of 2500 kg/m3. To generate these curves only one variable is changed while other variables are held constant. Obtained family-of-curves may then be used to predict the amount of solids deposition inside the pipeline as a function time. Performed analysis is specifically focused on validating and optimizing the current maintenance pigging schedule under different pipeline operating conditions. INTRODUCTION Oil and Gas transmission pipelines are still the principal tool for transporting fossil fuel between distant locations. Despite all the advances recently achieved in exploiting new sources of energy such as wind, solar, thermal energy and fuel cells (Xiao et al., Bahrami et al. ), they are far from replacing the fossil fuel in an effective way. Therefore fossil fuel still remains the main provider of energy in many countries, and as a result, the effective maintenance and operation of current and future energy pipelines is broadly recognized as a strategic objective by most of the major energy producers and consumers. Internal metal loss or corrosion in the form of localized or pitting corrosion is one of the major threats to the integrity of oil and gas transmission pipelines. Solids deposition has long been known as a leading cause of under-deposit pitting corrosion (UDPC) in both sweet and sour pipelines. While predictive models to characterize the movement (or stagnation) of oil borne sediment exist, there has been little published work on the rate of solids accumulation in continuously operated.
- North America > Canada (1.00)
- North America > United States > Texas > Harris County > Houston (0.16)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Inhibitor-Testing By a New High Superficial Velocity Flow-Loop System
Vogl, Thomas (Christian Doppler Laboratory of Localized Corrosion, Montanuniversität Leoben) | Mori, Gregor (Christian Doppler Laboratory of Localized Corrosion, Montanuniversität Leoben) | Reisl, Thomas (Christian Doppler Laboratory of Localized Corrosion, Montanuniversität Leoben) | Havlik, Wolfgang (OMV Exploration & Production GmbH, Laboratory Materials & Corrosion) | Zehethofer, Gerald (OMV Exploration & Production GmbH, Laboratory Materials & Corrosion) | Hönig, Stefan (OMV Exploration & Production GmbH, Laboratory Materials & Corrosion)
ABSTRACT: A new erosion corrosion testing facility has been setup in cooperation with an Austrian oil and gas producing company. The test rig consists of a gas flow loop with fluid addition. The two distinctive features of this test rig are that the gas – liquid two phase is accelerated up to 35 m/s at 15 bars and a continuous, infinite inhibitor dosing is possible. Tube diameters between 10 and 20 mm can be investigated at different flow regimes. Gas is pumped in a loop by a Diaphragm-Compressor and liquids are only used once and are separated downstream of the specimens. Tube specimens are evaluated by gravimetry and 3D optical device to determine average depth of and deepest point of attack. After a detailed description of the experimental setup, experimental limits are described with respect to maximum and minimum flow rates of gas and fluid. Degradation rates are presented for material L 80 as function of testing time, flow velocity (tube diameter), tube position in test rig and inhibitor concentration. The long term goal is to determine limiting flow velocities for different inhibitors and to describe inhibitor performance as function of flow velocity. Results of two different inhibitors are presented. INTRODUCTION Nevertheless such tests are highly interesting for many oil and gas companies. Because of decreasing reservoir pressures, an increase of production velocities is necessary to get the same amount of gas from the reservoir. So the goal was to do the first investigations in that important field. First aim was to investigate the performance of an inhibitor under realistic wet gas conditions. To reach this goal a special, not standardized, combination between jet impingement and flow loop system has been constructed. Results of that experimental setup were shown at Eurocorr 2011 in Stockholm.
- Europe > Sweden > Stockholm > Stockholm (0.24)
- North America > United States > Texas > Harris County > Houston (0.17)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Experimental Research of Sand Erosion In Gas Dominant Flows
Fan, Chenliang (Tulsa University Sand Management Projects and The Erosion-Corrosion Research Center The University of Tulsa) | McLaury, Brenton S. (Tulsa University Sand Management Projects and The Erosion-Corrosion Research Center The University of Tulsa) | Shirazi, Siamack A. (Tulsa University Sand Management Projects and The Erosion-Corrosion Research Center The University of Tulsa) | Rybicki, Edmund F. (Tulsa University Sand Management Projects and The Erosion-Corrosion Research Center The University of Tulsa)
ABSTRACT: Sand produced from reservoirs during oil and gas production can remove corrosion inhibitors or passive layers of corrosion resistant alloys and cause erosion-corrosion damage to pipelines and equipment, which can lead to production shutdown and significant economic losses. Gas dominant flows are common flow patterns in gas production, and a firm understanding of sand erosion in these flow conditions is vital to ensure continuous production. Additionally, to predict solid particle erosion for these flow conditions, it is vital to have experimental data that is needed to validate and improve models that are being constructed. Therefore, experiments were conducted on a large scale multiphase 3-inch and 4-inch flow loop utilizing Electrical Resistance (ER) erosion probes to evaluate the effects of superficial gas and liquid velocity, pipe size, flow orientation and sand particle distribution on erosion. It is demonstrated that the placement location of these probes is very important to determine the amount of erosion.1 The experimental results indicate that the ER probes, when properly placed in the flow loop, can provide valuable data to examine effects of many variables on sand erosion. The data indicates that for a fixed gas velocity, the erosion measured by ER probes decreases substantially as small amounts of liquid are injected into the gas stream. Additionally, the entrainment of liquid droplets within the gas stream can significantly affect erosion results. INTRODUCTION When oil and gas are produced from reservoirs that have relatively low formation strength, sand particles can be detached from the reservoir and some of the sand can be produced with the fluids. Sand particles can erode pipelines and equipment leading to production shutdown, thus causing significant economic losses to the oil and gas producers.2 Several methods are commonly used to control sand production, such as sand screens and gravel packs.
- North America > United States > Texas (0.32)
- North America > United States > Oklahoma (0.28)
- Research Report > New Finding (0.82)
- Research Report > Experimental Study (0.50)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
Optimization Of A Microbial Control Program In An Aging Gulf Of Mexico Asset To Minimize The Risk Of Corrosion
De Paula, Renato M. (Nalco Company) | Keasler, Vic (Nalco Company) | Bennett, Brian (Nalco Company) | Keller, Carrie (Nalco Company) | Adams, Robert C. (Nalco Company) | Vaksman, Zalman (Department of Microbiology & Molecular Genetics UT Health Science Center) | Kaplan, Heidi C. (Department of Microbiology & Molecular Genetics UT Health Science Center)
ABSTRACT: An aging asset in the Gulf of Mexico handles production from platforms that converge at an onshore treatment facility for oil and water separation. The water cut in this system is currently greater than 80%. Associated with the high water cut is a significant build-up of solids that are believed to contain potentially problematic microbes. Consistent with this concern, recent in-line inspection results showed significant wall loss in one of the main lines coming to the onshore separation facility. Microbial characterization via quantitative PCR and DNA sequencing was performed on samples from two of the platforms and at the separation facility to more fully understand the microbes present throughout the system and the potential risk they pose. In addition, dynamic flow loop testing was performed using field production fluids to identify an optimized microbial control program. Biofilms grown in the flow loops were analyzed before and after treatment using 3-dimensional fluorescent microscopy that provided insight into the impact of the treatment program on the biofilm. Based on this testing, a chemical treatment program was identified that showed excellent laboratory results. The modified treatment was implemented based on the lab testing and has been monitored in the field in three ways: water quality, solids recovered following pig runs, and quantification of microbes from a sessile monitoring device that was placed downstream of the modified treatment. To date, the modified program has showed excellent success of minimizing biofilm build-up, reducing solids recovered by pigging, and improving water quality. INTRODUCTION Oil production facilities and oil reservoirs usually are populated by microbial communities including quite distinct taxa. The oil production process can directly affect the dynamics of microbial population in the oil field, depending on several factors that include injection of external water (waterflood), nutrients (from drilling muds) and nitrate.2,3
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.90)
- Facilities Design, Construction and Operation > Facilities Operations > Pipeline pigging (0.87)
- (2 more...)
ABSTRACT: Long distance multiphase flow lines are now the predominant trend in the deep water production of oil and gas. Economics still demand the use of carbon steel as the material of construction even though carbon steel is prone to corrosion from the flowing mixture of oil/water/ gas. The prediction of the onset of corrosion with increasing water cut is very important in the design and operation of the flow lines. In addition, the proper selection of corrosion inhibitor is essential. This paper presents the results obtained from a large diameter multiphase flow loop test involving the baseline corrosion and three commercial corrosion inhibitors in environments to simulate the expected conditions in closed to wellhead (flow line). Light condensate oil was used and water cut was 20%. The experiments were undertaken at pressures of 6 bar and temperatures of 58 oC with carbon dioxide as the gas. Electrical resistance (ER) probes for inhibitor screening tests and carbon steel weight-loss coupons for inhibitor validation tests were used for the measurement of corrosion rates. The results showed that the baseline corrosion rates (without inhibitors) at the bottom and top of the pipes were around 0.8 mm/yr and 0.25 mm/yr, respectively in both 0o and 3o inclinations. The tests discriminated between different inhibitors. Only one corrosion inhibitor achieved the target corrosion rate of less than 0.1 mm/yr under 100 ppm concentration. INTRODUCTION One of the frequent and major problems encountered in the oil and gas production is the internal corrosion of carbon steel pipelines. In production systems, the multiphase mixtures (e.g. oil/water/gas) are transported over long distances using carbon steel pipes which have poor resistance to corrosion. Change in inclinations can cause change in the flow regime and other characteristics affecting the pressure drop and corrosion.
ABSTRACT: A small-scale sensing technology can be used inside pipeline maintenance pigs of any size and configuration in order to measure fluid conditions, map pipeline features and identify potential wall buildup or defects. The tool can be used in pipelines where conventional in-line inspection tools cannot traverse, while significantly reducing deployment cost and risk. It can also be used to provide near real-time monitoring of critical pipeline characteristics. The pill-shaped housing containing the sensing elements can collect data on multiple variables, including but not limited to - pressure, temperature, 3-xis tilt and acceleration. Multiple tests were conducted using the technology mounted onto pigs in a 12-inch flow loop with single-phase gas and liquid media. Results from the sensing device consistently identified known bends and wall-thickness changes as small as 0.125 inches. The sensor pill device was also deployed in a free-floating arrangement without a carrier pig in the flow loop filled with water. This design enabled the sensing device to travel the length of the line without a pig, thus indicating a potential inspection solution for fully unpiggable pipelines. INTRODUCTION By its very nature, it is difficult to know exactly what is going on inside or outside a pipeline. The consequences of not knowing, however, can be catastrophic. The technologies available to measure the precise location of a pipe, the conditions inside it and the integrity of the pipe structure itself, have remarkably improved, including advances in instrumentation for inspecting, for example, the human body. Applied technologies for pipeline inspection For most pipeline inspection tasks, the pig remains the state of the art but the pigging of deepwater lines presents particular difficulties. Due to the economics of offshore exploration and production, many pipelines are being tied together, like branches on a tree, before being sent to the shore.
- North America > United States > Texas (0.20)
- North America > United States > Oklahoma > Tulsa County > Tulsa (0.15)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
- Facilities Design, Construction and Operation > Facilities Operations > Pipeline pigging (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Information Technology > Architecture > Real Time Systems (0.54)
- Information Technology > Communications > Networks (0.48)
UT Measurements to Determine Erosion Patterns In a Bend For Single And Multiphase Flows
Kesana, N.R. (Department of Mechanical Engineering University of Tulsa) | Grubb, S.A. (ConocoPhillips – Technology) | McLaury, B.S. (Department of Mechanical Engineering University of Tulsa) | Shirazi, S.A. (Department of Mechanical Engineering University of Tulsa)
ABSTRACT: Erosion is a common problem faced by oil and gas producers. The consequences of erosion may include unexpected equipment failure with process breaches resulting in production losses, cleanup, repair expenses and possible environmental damage with associated regulatory fines. Therefore, it is necessary to study erosion under different flow regimes to provide protective guidelines to the oil and gas industry. This work discusses measuring erosion in a horizontal standard 3-inch elbow using an ultrasonic technique and a newly developed process algorithm. The ultrasonic transducers are permanently mounted at 16 locations on the outside bend of the elbow which enables the measurement of erosion patterns under different operating conditions. Specifically, erosion experiments have been conducted for single-phase (gas) and multiphase flow patterns (slug and mist flows) in the horizontal orientation. The experiments were performed with air and water and using 150 and 300 micron particle sizes with 1 % concentration by weight. Results provide the magnitude of erosion as well as the location of the maximum erosion on the elbow for the flow patterns considered. Interestingly, the location of the maximum measured erosion for horizontal slug flow is near the top surface of the bend, but for the other flow patterns the location of maximum measured erosion is on the outer radius of the bend near the 45 degree position. INTRODUCTION Oil and gas producers can face a major asset integrity problem when sand production occurs during the extraction process. Erosion of production assets is highly undesirable and petroleum companies are investing significant amounts of money to understand the mechanism of solid particle erosion and develop procedures and designs to minimize its effects. Erosion damage to pipelines can result in unexpected shutdowns due to production line breaches or for preventative maintenance which may have an unacceptably high frequency.
- North America > United States > Gulf of Mexico > Eastern GOM (0.47)
- North America > United States > Oklahoma (0.29)
- North America > United States > Texas > Harris County > Houston (0.16)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)