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Chemical treatment with demulsifiers is used to counteract the natural surfactants present, and wetting agents or other chemicals sometimes are used to carry the suspended solids into the water layer. The presence of a band of emulsion in centrifuged samples indicates that further chemical treatment might be needed.
As exploration and production (E&P) projects move into more unique territories, operating companies must evaluate their projects' infrastructures and devise strategies to sufficiently prepare for a growing energy demand. These strategies may take the form of significant upgrades to existing facilities or the construction of new facilities altogether. At the 2015 SPE Annual Technical Conference and Exhibition, representatives from small private and state-owned operating companies discussed the challenges they faced with facilities design and construction, both onshore and offshore. This feature examines some of the strategies that were taken to handle those challenges. Last year, Pacific E&P finished work on a pilot for the first in-situ combustion project in Colombia, at the Quifa oil field located in the eastern part of the Llanos basin. Pacific E&P had five main objectives with the pilot.
This review of technical challenges facing oil and gas producers in the Gulf of Thailand arose from last month's meeting in Bangkok, Thailand, of the SPE Board of Directors with the SPE Asia Pacific Advisory Council, which is represented by senior executives from across the Asia Pacific region and industry value chain. It was an opportunity for Board members to meet with the leadership of the major oil and service companies and discuss how best the SPE can serve its membership in the region. The SPE Board of Directors meets three times per year. One meeting is held in conjunction with the SPE Annual Technical Conference and Exhibition (ATCE), usually during September or October; the other meetings are held in locations around the world chosen for strategic reasons by the SPE President. Thailand is an oil and natural gas producer.
Kuang, Wenyu (National University of Singapore) | Ong, Paul, Pang Awn (National University of Singapore) | Quek, Ser Tong (National University of Singapore) | Kuang, Kevin, Sze Chiang (National University of Singapore)
Pipelines are critical for transportation of oil and gas. A Steel Strip Reinforced Thermoplastic Pipe (SSRTP) is applied in the offshore environment because of its superior mechanical performance. Due to the complex subsea conditions, SSRTP is subject to severe loading and may be damaged during its design life. The failure modes of SSRTP, related to four principle loading cases, are investigated in the FE models. The preliminary results will reveal the mechanical behavior of the critical layer of SSRTP prior to damage. An optical fiber sensor is then introduced within the SSRTP as a novel system to monitor the strain of the critical layer.
Ramachandran, Sunder (Baker Hughes, a GE Company) | Lehrer, Scott (Baker Hughes, a GE Company) | Chakraborty, Soma (Baker Hughes, a GE Company) | Leidensdorf, Jeremy (Baker Hughes, a GE Company) | Panchalingam, Vaithilingam (Baker Hughes, a GE Company) | Ahroor, Danika (Baker Hughes, a GE Company)
Hydrogen sulfide (H2S) is often present in oil and gas production fluids. The gas is toxic, corrosive to mild steel and induces localized sulfide corrosion cracking (SCC) in materials with susceptible metallurgical properties Treatment with H2S scavengers can enable the use of less-expensive low alloy carbon steel materials.
Triazines and glyoxal are commonly used H2S scavengers in oil and gas production. In some instances they are used to reduce H2S levels to safe values and make the installation safer. There are problems with the use of trazine and glyoxal.
Triazines especially Monoethanol amine Triazines (MEA-Triazine) are well used but have some problems with solid formation and creation of corrosion problems in refineries MEA-triazine reacts with H2S to create an insoluble reaction product known as amorphous diathiazine that is difficult to remove.
Sometimes refineries ban or discount crude oil that contains triazine. The reason they do this is that the presence of triazine in crude can cause downstream corrosion problems in crude distillation overhead lines and crude unit.
Glyoxal is a hydrogen sulfide scavenger that does not contain nitrogen. This product does not cause corrosion problems in refineries due to formation of amine salts. Glyoxal though has a low pH that can result in corrosion at any location where oil and water can separate and glyoxal causes the water phase to have a low pH..
Due to the problems with nitrogen containing H2S scavengers, and glyoxal, some customers have asked for non-nitrogen containing, non-corrosive H2S scavengers. This paper presents laboratory results on a new, non-corrosive, non-Nitrogen containing H2S scavenger. The new scavenger has a pH in the range of 7.5 to 8.5 that does not form problematic solids on reaction with H2S. The product has been used in towers and direct injection in wet gas systemsThe product is not water-based and can be used in dry oil and dry gas and condensate systems.
The successful use of this product in wet systems has been described in previous work but is included for completeness in this paper. Some of the more successful field results include application of the product to a dry oil system and a dry gas and condensate system. This is useful for cases where the operator wishes to decrease the H2S content of a dry oil and dry gas and condensate pipeline without introducing water in the application. This is not possible with products that contain water.
Copyright 2020, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Dhahran, Saudi Arabia, 13 - 15 January 2020. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.
Abstract In the case of coated materials, any mechanical erosion at a specified location in a flow system will lead to chemical corrosion if the fluids are in contact with the eroded zone, which presents a favorable condition for corrosion growth. In contrast, corrosion of materials can worsen by mechanical erosion when corrosion has started destroying the texture of the subject material. In the present paper, we will review erosion-corrosion aspects of metallic systems based on particle impingement mechanisms’ Finnie model and its implication of different metallic materials. The paper summarizes the effects of fine particle impingement with regard to different flow situations that can lead to mechanical erosion that will affect the chemical reliability of the metal leading to potential harmful corrosion. The paper will provide a few recommendations to avoid such situations and achieve a sound mechanical and chemical reliability of the material system in use.
Siddiqui, Muhammad Ali (OMV Pakistan, Subsidiary of United Energy Group – UEG) | Hassan, Syed Saadat (OMV Pakistan, Subsidiary of United Energy Group – UEG) | Mubasher, Muhammad (OMV Pakistan, Subsidiary of United Energy Group – UEG) | Latif, Saqib (OMV Petrom) | Dar, Usman Anjum (Schlumberger)
Abstract The objective of writing this success story is to demonstrate how technology, in particular low cost solutions, are key to economically sustain and secure production from mature fields. Tubing Patch technology has been successfully utilized in Pakistan for the first time to restore the well integrity and saved huge CAPEX by avoiding expensive rig workover. Tubing-Annulus pressure suddenly increased in one of water disposal well (WDW). Annulus pressure varied directly with variations in Injection rates which were the clear evidence that tubing-annulus communication had been established and basic check ascertains that well had integrity issue. Being the only injector in area all production and processing of gas is majorly dependent on its injection reliability and integrity. After detailed in-house working it was decided to run diagnostic logging with spinner (quantitative) & temperature log (qualitative) to identify the leakage points precisely. All potential leakage paths (packer, tubing, tool joints) were considered while selecting the diagnostic techniques to have conclusive results. Based on diagnostic logging three leakage points were identified. Before proceeding for remedial measures to restore the well integrity, it was mandatory to check health of old carbon steel tubing string therefore it was planned to acquire corrosion log. Based on corrosion logging results, completion tubular was established in good condition which steered to install tubing patches best Techno-Economical solution across the leaks to restore well integrity instead of rig workover for re-completion. Consequently, three tubing patches, were successfully applied using wireline in water disposal well and integrity of well was restored. C-Annulus was pressure tested even after six months of installation and no pressure drop was observed during this interval.
Abstract ISO 15663 Lifecycle cost (LCC) analysis principles are commonly applied to evaluate the viability of downhole tubing materials. This includes the initial CAPEX, operating or maintenance OPEX, Replacement costs and Revenue impact of tubing failure. Increased implementation of Glass Re-informed Epoxy (GRE) Lined tubing has provided significant evidence of flow assurance benefits of the system. This paper will present a modern adaptation of LCC analysis based on operator data and quantification of these benefits and savings. With over 100,000 GRE Lined completions worldwide there are numerous reported cases of flow enhancements and savings besides corrosion mitigation. The paper is based on extensive research of data collected with agreement from operators representing cost savings or additional revenue that can be factored into LCC analyses with a fair degree of accuracy. Overall operational savings that operators have derived from flow assurance benefits of GRE Lined Tubing, such as improved thermodynamics, scale mitigation, reduced pressure drop, etc. are substantiated using field data from downhole logs, analysis of produced fluids and inspection of retrieved GRE Lined tubing. Operators have reported higher temperature at well head in Oil Producers after steel tubing was replaced using GRE Lined Steel tubing. This has been associated with savings in separation costs at the surface. There are several reports of higher flow rates and reduced pressure drop across GRE lined tubing which translates to higher injectivity or production. Operators have numerous references of improved and stable flow rates for longer durations when compared to bare steel tubing due to the mitigation of carbonate scale deposition which would impact flow dynamics. Such cases represent significant improvements to production efficiency and, consequently, the overall return on investment in the asset. The findings of research on multiple operator flow enhancement case references, while implementing GRE Lined Tubing, are illustrated graphically to represent savings and/or additional revenue in comparison with graphical representations of traditional LCC calculations models based on ISO 15663 key drivers i.e. CAPEX, OPEX, Revenue Impact and Replacement Costs. It is anticipated that this paper will influence a paradigm shift that guides operators to consider the impact of flow enhancement, improved thermodynamics, improved injectivity and/or production, simplification of surface facility requirements and other fringe benefits, in addition to CAPEX, OPEX and Revenue, while evaluating the LCC of tubing material alternatives.
Abstract The impact of corrosion on the oil, gas and geothermal industry is big and affects both capital and operational expenditures (CAPEX and OPEX). There is a growing public awareness and rising concerns with well integrity and health, safety and the environment (HSE). One of the first steps for corrosion mitigation is to evaluate downhole tubular. The reduction of metal thickness leads to a loss of mechanical strength and structural failure. When metal pitting accelerates in localized zones, very considerable structural weakening may result from a relatively small amount of metal loss. Additionally, the alteration or loss of surface properties including erosion, increased fluid flow friction at the pipe surface, surface reflectivity or heat transfer across a surface, cause such weakness. Corrosion evaluation using electric-line logging is of growing importance in the industry. Technologies that can evaluate multiple barriers are vital for cost-effective evaluations as rig time is saved by not having to retrieve the completion to evaluate production casings. This is the case especially in the offshore environment where the casing design is generally more complicated and consists of extra number of casing strings. Current technologies available include magnetic flux leakage or eddy current, or to some extent ultrasonic which has some limited capability of multi-barrier evaluation. A multi-sensor electromagnetic corrosion tool (EM) has been developed especially for multi-barrier evaluations; the technology is based on pulsed eddy current physics. When combined with conventional multi-finger calipers and other tools such as radial cement bond logs or noise detection technologies, it offers a better understanding of well integrity.