Petroleum Production Industry Research Articles

Theoretical and Experimental Investigation of Liquid and Gas Flow Pressure Drop through Different Sections of A Partially Closed Piping system

Multiphase flow is found in various places in nature and practice. However, multiphase flow is prevalent in the petroleum production industry. This phenomenon gives rise to a significant issue of pressure loss within piping systems, resulting in a loss in production. Multiphase flow has been studied for decades; however, with the increase in unconventional engineering methods, there is now a greater need for its study. This study investigates phenomena related to multiphase flow, such as flow regimes and pressure loss produced by friction, pipe orientation, and various fluid phase properties. An experimental system was designed, and different fluid phases were used to represent varying situations in piping systems. The system included sections of horizontal, inclined, and vertical pipe orientations experienced during hydrocarbon migration from the reservoir to the surface. To replicate industry multiphase flow in the experimental system, we used water to represent the oil and compressed air to represent gas. The pressure differences throughout the system were calculated using the Beggs and Brill Correlation, the Lockhart-Martinelli Parameter, and the Chisholm Equation. Experimental pressure differences and the effect of the choke valve positions were also recorded for the different sections of the system while observing the flow regimes produced by multiphase fluid interaction. Through the research methods, we found that most pressure losses occurred in the elbows, and most frictional pressure loss occurred in the vertical 3ft pipe, while the 45° and 90° downhill pipes experienced increased pressure.

A New Energy-Aware Method for Gas Lift Allocation in IoT-Based Industries Using a Chemical Reaction-Based Optimization Algorithm

The Internet of Things (IoT) has recently developed opportunities for various industries, including the petrochemical industry, that allow for intelligent manufacturing with real-time management and the analysis of the produced big data. In oil production, extracting oil reduces reservoir demand, causing oil supply to fall below the economically viable level. Gas lift is a popular artificial lift system that is both efficient and cost-effective. If gas supplies in the gas lift process are not limited, a sufficient amount of gas may be injected into the reservoir to reach the highest feasible production rate. Because of the limited supply of gas, it is essential to achieve the sustainable utilization of our limited resources and manage the injection rate of the gas into each well in order to enhance oil output while reducing gas injection. This study describes a novel IoT-based chemical reaction optimization (CRO) technique to solve the gas lift allocation issue. The CRO algorithm is inspired by the interaction of molecules with each other and achieving the lowest possible state of free energy from an unstable state. The CRO algorithm has excellent flexibility, enabling various operators to modify solutions and a favorable trade-off between intensification and diversity. A reasonably fast convergence rate serves as a powerful motivator to use as a solution. The extensive simulation and computational study have presented that the proposed method using CRO based on IoT systems significantly improves the overall oil production rate and reduces gas injection, energy consumption and cost compared to traditional algorithms. Therefore, it provides a more efficient system for the petroleum production industry.

Numerical Investigation on Oil/Water Separation by Compact Nozzle- Axial Hydrocyclone

The separation of fluid-fluid mixtures is a major issue in various sectors. The liquid-liquid hydro-cyclone has a wide range of applications in various sectors due to its great efficiency in separating fluid mixtures, ease of installation, and low cost. In crude oil production, high water is consumed following the degrading of production quality, high processing costs, costs, and environmental impacts. Axial hydro cyclone is a tool for Downhole Oil/Water Separation (DOWS) in the petroleum production industry, but it has limitations. The main purpose of this work is to simulate the effect of compacting the conventional inline hydro cyclone with a converging-diverging nozzle on the oil/water dynamic flow and the separation process to resolve the high water cut problem. This study presents a three-dimensional simulation to compute fluid dynamics using the mixture multiphase and SST k-omega turbulence models for Reynolds numbers less than 66000. The operational flow variables are a mixture: flow rate (14, 28, and 56 m3/h) and oil/water ratio (15/85, 25/75, 30/70, and 35/65). Results indicate an enhancement in the axial and tangential velocity components by 15% and 50%, respectively, for the proposed design compared with the conventional cyclone. The oil separation efficiency for the new design is 89%, while for the conventional cyclone is 60%.

Flat-Probe Diagnostic Methods for Collisional Plasma Flowing from Technological Plasmatrons

Based on computational and full-scale experiments, several algorithms have been developed for processing current–voltage curves obtained for flat wall and remote probes in the case of a weakly ionized low-temperature collisional plasma. The proposed diagnostic methods could be useful for specialists employing technological plasmatrons in various sectors of the national economy such as plasma chemistry, plasma-enhanced deposition, plasma processing of materials, gas-extraction and petroleum-production industries, in aviation and rocket engineering, and in other fields.

Light beam reflectance measurement of droplets diameter distribution in crude oil emulsions

Stable oil field emulsions create challenging conditions in the petroleum production industry. One important characteristic affecting the stability and rheology of emulsions is the Droplet Diameter Distribution (DDD). A few techniques are available to determine the DDD in clear and dark liquid/liquid mixtures. Most of them, like the traditional light scattering techniques, require sampling and dilution. Dilution can affect the droplets coalescence rate, and consequently, change the DDD by altering the solubility state of components responsible for emulsion interface properties. Moreover, the samples obtained may not be representative of the actual process conditions once depressurized to ambient for observation.Focused Beam Reflectance Measurements (FBRMs) were conducted on suspensions mimicking the optical properties of emulsion systems, with the goal of optimizing the instrumental settings. Then, the same technique was applied to water-in-crude oil and crude oil-in-water emulsions to evaluate its accuracy.An algorithm was developed to compute the diameter distribution in populations of spherical droplets from the chord length distributions measurement data.The greatest advantage of this technique is the ability to perform a real-time, in situ measurement of DDD at actual process conditions. The method is capable of repeatable measurements of droplet diameter distributions; however, the measurements are limited within a range of droplet sizes, and the results are sensitive to the relative optical properties of the continuous and dispersed phases, making the calibration step a fundamental phase of the measurement protocol.

Assessing the Magnitude and Consequences of Reservoir Souring

Reservoir souring Reservoir souring, defined as the unplanned increase in hydrogen sulfide (H2S) in produced fluids during field life, is a growing concern for the petroleum production industry. H2S is a poisonous, dense gas with serious safety implications; it can lead to sudden catastrophic failure of nonresistant metallic materials from sulfide stress corrosion cracking or hydrogen-induced cracking, and it can enhance pitting corrosion rates. But how does reservoir souring develop, and how can its consequences for materials be anticipated? Consideration also needs to be given to the currently available options for souring control and their shortcomings. Despite the significant advances that have been made over the past 30 years or so in the understanding of H2S- related materials degradation mechanisms, H2S still causes many failures every year. While it may be understandable that such failures continue to occur in operating environments where reservoir souring is a new phenomenon, failures are also occurring where the industry is mature. For example, recently in the UK, a carbon steel pipeline transporting sour hydrocarbons onshore failed by sulfide stress cracking (SSC) after 6 weeks of operation, necessitating replacement at a cost of GBP 100 million. Over 2000–01, sour gas pipelines failures, including those affected by both microbial and chemically induced corrosion, accounted for 35 (4%) of the 952 pipeline failures in Alberta, Canada. The challenge of dealing with H2S is likely to rise in importance as an increasing number of high-temperature, high-pressure (HTHP) reservoirs are exploited in the future. This will require more widespread use of corrosion resistant alloys (CRAs), increasing the costs of wells and downstream equipment. Therefore, we need more corrosion data on a range of alloys when there are fewer materials engineers (particularly metallurgists) coming into the industry and fewer corrosion testing facilities in steel companies, meaning that operating companies and even fabrication contractors are having to take on the task of generating materials susceptibility data. H2S Generation and Mobility Reservoir souring is the production of increased concentrations of H2S in well-stream fluids from production wells subject to water injection for secondary recovery. It is generally acknowledged to be caused by the activity of a specialized group of microorganisms, the sulfate-reducing bacteria (SRB). Low populations of SRB cells are ubiquitous in seawater and many other natural waters that are used for secondary recovery. Biogenic H2S originates solely from SRB activity in the water phase and subsequently partitions between water, liquid hydrocarbon, and gas, dependent on temperature, pressure, the pH of the aqueous phase, fluid phase ratios, and a number of other factors. However, the progress of reservoir souring is routinely measured and expressed in terms of H2S concentrations in the gas phase at separator conditions and the corresponding partial pressures of gaseous H2S.

Thermo-Acoustic Water Analyzer in Hydrocarbon Emulsions with Kalman Filter

Problem statement: Water detection in hydrocarbon emulsions represents a serious challenge in petroleum production industry. The elemenation of measurment noises is also desired. Approach: In this study, a systematic and an applicable method of water detection in hydrocarbon emulsion is achieved using thermoacoustic effect. A Kalman filter is applied to correct measurement errors and to improve accuracy. Results: The study focused on sensing the presence of water in kerosene using the established correlation between the content of hydrocarbon emulsion and the characteristics of the acoustic wave generated by inundation of a heated rod in the emulsion. The implemented filteration enhanced the peromance of the measurment system. Conclusion: This approach was tested experimentally and showed that the produced acoustic signal can be utilized as an informative parameter in quality control schemes of petrochemical oil products.

Chapter 29 The potential for hydrocarbon resource development on the Russian Arctic Ocean Shelf

Abstract The dramatic rise in the world oil and gas demand has led to concerns about the energy future for mankind. In the twenty-first century the sedimentary basins of the Arctic Ocean will play a leading role as petroleum provinces, including its Russian shelf areas. This article deals with the characteristics and assessment of resources in the Russian sector of the Arctic Ocean offshore areas. One can predict with 0.90 probability that the Arctic Ocean initial in-place hydrocarbon resources exceed 90 billion tons oil equivalent (toe). The assessments lead to the conclusion that during these years a petroleum production industry will develop on the Arctic Ocean Shelf.

Novel Surfaces with Applicability for Preventing Wax Deposition: A Review

Paraffin wax deposition is a ubiquitous phenomenon in the petroleum production industry. Many types of internal pipe coating materials have previously been tested for preventing wax deposition, but none have demonstrated successful performance. It has become increasingly evident that an improved knowledge of the chemistry and physics of wax deposition will be required in order to develop new wax-repellent materials. In particular, it is important to understand the mechanisms used to inhibit similar deposition problems in outside industries. In order to achieve these objectives, a state-of-the-art literature survey was performed to identify the role and function of nonstick and anti-adhesive surfaces in the food, paint, marine, automotive, biomedical, tribological, optical, and petroleum industries. Information was derived from academic, industrial, and intellectual property sources. This review presents a comprehensive compilation of materials and surface modification techniques that show potential for inhibiting or eliminating paraffin wax deposition. A wide variety of metal surface treatments and synthesized polymers are discussed. It is established that nanotechnology surfaces based on fabricated microstructures are inapplicable for use in preventing solid-liquid deposition. On the other hand, self-assembled polymers and nanocomposite materials exhibiting smooth surfaces and low surface free energies may provide appropriate surface technologies for prevention of wax deposition. Based on current adhesion theory postulations, as well as analogies to similar deposition processes, promising new material classes include fluoro-siloxanes, fluoro-urethanes, oxazolane-based polymers, and DLC-polymer hybrids.

Measurement and Modelling of Gas Condensate Flow Around Rock Perforation

In the petroleum production industry wells are mostly cased and perforated in the producing formation. Perforation characteristics such as size, length, number of perforation tunnels and their arrangements as well as fluid and rock properties determine fluid flow behaviour in the wellbore region, hence, well productivity. Flow of gas and condensate around a perforation tunnel (including the damaged zone) has been studied by performing steady-state core experiments and simulating the results numerically, using a finite element modelling approach. The model allows for the changes in fluid properties and accounts for the coupling of the two phases and the inertial effect using a fractional flow based correlation. The results indicated that different sets of thickness-permeability (h−k) values obtained from matching single-phase flow performance could be assigned to the damaged zone around perforation to represent the two-phase flow performance. The status of the tip of the perforation for two extreme cases of totally closed and fully open was investigated and found to have a minimal effect on the performance of the system.

Corrosion inhibitors for the petroleum production industry

Corrosion inhibitors for the petroleum production industry

Hydrocarbon raw material resources

The scientific-research institutes of Minnefteprom and Minneftekhimprom SSSR [Ministries of the Petroleum Production Industry and of the Petroleum Refining and Petrochemical Industry of the USSR] have still not developed any unified procedure and have not carried out any calculations of the total resources of light hydrocarbons on the basis of the potential content in the crude oils being produced and the potential amounts to be obtained in the destructive processing of petroleum products in refineries and petrochemical plants.

Petroleum Production Industry and Engineering in Japan

Petroleum Production Industry and Engineering in Japan

Miscible Slug Flooding - A Review

Abstract Over the past several years the petroleum industry has become increasingly interested in the possibilities of miscible slug flooding as a means of increasing the nation's recoverable reserves. Preliminary studies of this recovery method have demonstrated that substantially complete displacement of oil is obtained in those portions of the reservoir contacted by the miscible slug. A large portion of the published research has been concerned with the volume of solvent slug required to maintain miscibility between the reservoir oil and the scavenging gas. In this paper laboratory results are reviewed with particular emphasis on the general conclusions of the studies as applied to field application of miscible flooding. The factors affecting the portion of the reservoir swept by the miscible slug and reservoir conditions believed desirable for successful operation are discussed. Possible methods for improving the sweep efficiency are considered. Introduction During its growth, the petroleum production industry has continually sought improved methods for recovery of oil from underground reservoirs. Gas and water injection have been used to flush additional oil from formations and to restore and maintain reservoir pressure. However, even with these injection operations generally from one-third to one-half of the oil originally in place remains unrecovered at the time that further production becomes uneconomical. This lack of complete oil recovery is due to the inability to obtain both complete sweep of all oil-bearing portions of the reservoir (100 per cent volumetric sweep efficiency) and complete displacement of oil from the swept regions (100 per cent displacement efficiency). The volumetric sweep efficiency during any injection operation depends uponthe nature and distribution of reservoir nonuniformities,well pattern effects, andgravity effects caused by the density difference between the oil and the injected fluid.