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Corrosion of metal in the presence of water is a common problem across many industries. The fact that most oil and gas production includes co-produced water makes corrosion a pervasive issue across the industry. Age and presence of corrosive materials such as carbon dioxide (CO2) and hydrogen sulfide (H2S) exacerbate the problem. Corrosion control in oil and gas production is reviewed in depth in Treseder and Tuttle, Brondel, et al., and NACE, from which some of the following material is abstracted. Iron is inherently (thermodynamically) sufficiently active to react spontaneously with water (corrosion), generating soluble iron ions and hydrogen gas. The utility of iron alloys depends on minimizing the corrosion rate. Corrosion of steel is an "electrochemical process," involving the transfer of electrons from iron atoms in the metal to hydrogen ions or oxygen in water. This separation of the overall corrosion process into two reactions is not an electrochemical nuance; these processes generally do take place at separate locations on the same piece of metal. This separation requires the presence of a medium to complete the electrical circuit between anode (site of iron dissolution) and cathode (site for corrodant reduction). Electrons travel in the metal phase, but the ions involved in the corrosion process cannot. Ions require the presence of water; hence, corrosion requires the presence of water.
Oil and gas wells produce a mixture of hydrocarbon gas, condensate or oil; water with dissolved minerals, usually including a large amount of salt; other gases, including nitrogen, carbon dioxide (CO2), and possibly hydrogen sulfide (H2S); and solids, including sand from the reservoir, dirt, scale, and corrosion products from the tubing. The purpose of oil and gas processing is to separate, remove, or transform these various components to make the hydrocarbons ready for sale. The goal is to produce oil that meets the purchaser's specifications that define the maximum allowable amounts of the following: Similarly, the gas must be processed to meet purchaser's water vapor and hydrocarbon dewpoint specifications to limit condensation during transportation. The equipment between the wells and the pipeline, or other transportation system, is called an oilfield facility. An oilfield facility is different from a refinery or chemical plant in a number of ways.
Oil or gas wells produce a mixture of hydrocarbon gas, condensate, or oil; water with dissolved minerals, usually including a large amount of salt; other gases, including nitrogen, carbon dioxide (CO2), and possibly hydrogen sulfide (H2S); and solids, including sand from the reservoir, dirt, scale, and corrosion products from the tubing. For the hydrocarbons (gas or liquid) to be sold, they must be separated from the water and solids, measured, sold, and transported by pipeline, truck, rail, or ocean tanker to the user. Gas is usually restricted to pipeline transportation but can also be shipped in pressure vessels on ships, trucks, or railroad cars as compressed natural gas or converted to a liquid and sent as a liquefied natural gas (LNG). This chapter discusses the field processing required before oil and gas can be sold. The goal is to produce oil that meets the purchaser's specifications that define the maximum allowable water, salt, or other impurities. Similarly, the gas must be processed to meet purchaser's water vapor and hydrocarbon dewpoint specifications to limit condensation during transportation. The produced water must meet regulatory requirements for disposal in the ocean if the wells are offshore, reservoir requirements for injection into an underground reservoir to avoid plugging the reservoir, and technical requirements for other uses, such as feed to steam boilers in thermal-flood operations, or in special cases, for irrigation. The equipment between the wells and the pipeline, or other transportation system, is called an oilfield facility. An oilfield facility is different from a refinery or chemical plant in a number of ways.
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.
Abstract This work presents a matrix acidizing formulation which comprises a salt of monochloroacetic acid giving a delayed acidification and a chelating agent to prevent precipitation of a calcium salt. Results of dissolution capacity, core flood test and corrosion inhibition are presented and are compared to performance of 15 wt% emulsified HCl. Dissolution capacity tests were performed in a stirred reactor at atmospheric pressure using equimolar amounts of the crushed limestone and dolomites. Four different chelating agents were added to test the calcium ion sequestering power. Corrosion tests were executed using an autoclave reactor under nitrogen atmosphere at 10 barg. Core flood tests were performed to simulate carbonate matrix stimulation using limestone cores. It was found that the half-life time of the hydrolysis reaction is 77 min at a temperature of 100 °C. Sodium gluconate and the sodium salt of D-glucoheptonic acid were identified to successfully prevent the precipitation of the reaction product calcium glycolate at a temperature of 40 °C. Computed Tomography (CT) scans of the treated cores at optimum injection rate showed a single wormhole formed. At 150 °C an optimum injection rate of 1 ml/min was found which corresponds to a minimum PVBT of 6. In addition, no face dissolution was observed after coreflooding. Furthermore, the corrosion rates of different metallurgies (L80 and J55) were measured which are significantly less than data reported in literature for 15wt% emulsified HCl. The novelty of this formulation is that it slowly releases an organic acid in the well allowing deeper penetration in the formation and sodium gluconate prevents precipitation of the reaction product. The corrosivity of this formulation is relatively low saving maintenance costs to installations and pipe work. The active ingredient in the formulation is a solid, allowing onsite preparation of the acidizing fluid.
Romer, Michael Christopher (ExxonMobil Upstream Research Company) | Spiecker, Matt (ExxonMobil Upstream Research Company) | Hall, Tim James (ExxonMobil Upstream Research Company) | Dieudonne, Raphaël (Hydro Leduc) | Porel, François (Hydro Leduc) | Jerzak, Laurent (Hydro Leduc) | Ortiz, Santos Daniel (KSWC Engineering & Machining) | King, George Randall (KSWC Engineering & Machining) | Gohil, Kartikkumar Jaysingbhai (KSWC Engineering & Machining) | Tapie, William (Deteq Services) | Peters, Michael (MTI) | Curkan, Brandon Alexander (C-FER Technologies)
Summary What do you do after plunger lifting? What if lift gas is not readily available or your liquid level is around a bend? What can you do with a well that has low reservoir pressure, liquid-loading trouble, and fragile economics? Do you give up on the remaining reserves and advance to plugging and abandonment? These questions were considered, and the answers were found to be unsatisfactory. This paper will describe the development and testing of a novel wireline-deployed positive-displacement pump (WLPDP) that was invented to address these challenges. Artificial-lift (AL) pumps have historically been developed with high-producing oil wells in mind. Pumps for late-life wells have mostly been repurposed from these applications and optimized for reduced liquids production. The WLPDP development began with the constraints of late-life wells with the goal of addressing reserves that conventional AL methods would struggle to produce profitably. Internal and industry-wide data were first reviewed to determine what WLPDP specifications would address the majority of late-life wells. The primary target was gas wells, although “stripper” oil wells were also considered. The resulting goal was a pump that could deliver 30 BFPD from 10,000-ft true vertical depth (TVD). The pumping system must be cost-effective to be a viable solution, which led to several design boundaries. Pumps fail and replacement costs can drive economics, so the system must be deployable/retrievable through tubing. The majority of new onshore wells have tortuous geometries, so the system must be able to function at the desired depth despite them—without damaging associated downhole components. The system should use as many off-the-shelf components and known technologies as possible to reduce development costs and encourage integration. Finally, the pump should be able to handle a variety of wellbore liquids, produced gases, and limited solids. The WLPDP was designed to meet the established specifications and boundary conditions. The 2.25-in.-outer-diameter (OD) pump is deployed through tubing. and powered with a standard wireline (WL) logging cable. The cable powers a direct-current (DC) motor that drives an axial piston pump. The piston pump circulates a dielectric oil between two bladders by means of a switching valve. When each bladder expands, it pressurizes inlet-wellbore liquids, pushing them out of the well. Produced gas flows in the annulus between the tubing and production casing. The intake/discharge check valves and bladders are the only internal pump components that contact the wellbore fluids. The WLPDP system was able to meet the design-volume/pressure specifications in all orientations, as confirmed through laboratory and integration testing. Targeted studies were conducted to verify/improve check-valve reliability, gas handling, elastomer suitability, and cable-corrosion resistance. The results of these and related studies will be discussed in the paper.
The main aim of present study was to determine the ultimate strength of cracked and corroded plates under uniform in-plane compression. Corrosion is considered as pitting-type corrosion at one side of the plate with a central longitudinal crack. Nonlinear finite element analysis using commercial computer code, ANSYS, is used to determine the ultimate strength of deteriorated plates. Different geometrical parameters, including the aspect ratio (AR) and thickness of the plate, number of pits, pit depth-to-thickness ratio, and crack length, are considered. It is found that the AR of plates have great influence on the ultimate strength of cracked-pitted plates. Because of the position and orientation of the crack, the length of central longitudinal crack has no influence on ultimate strength reduction of cracked and cracked-pitted plates. The results show that regardless of the number of pits and crack length, in thin plates where buckling controls failure modes at ultimate strength, the number of pits has less influence on reduction of the ultimate strength than thick plates where yielding controls failure mode. Also it is concluded that in rectangular plates, arrangements of pits has more effect on reduction of the ultimate strength of cracked-pitted plates than the number of pits.
Galoni, Myrto K. (National Technical University of Athens) | Gougoulidis, George (Salamis Naval Base Research Department) | Pantelis, Dimitrios (National Technical University of Athens) | Papaefthymiou, Spyors (National Technical University of Athens)
Al - Mg alloys are extensively used as structural materials in marine applications. Sensitization has emerged as a severe concern during the operation of aluminum vessels, due to the consequent high susceptibility to Intergranular Corrosion - IGC. Herein, a detailed study of sensitization on naturally sensitized, field retrieved, Al-Mg alloy samples, is presented. Specifically, samples from four Hellenic Navy - HN high speed vessels were tested according to ASTM G67 in order to quantify their Degree of Sensitization - DoS and qualified, in terms of grain boundaries (GBs) coverage with β phase with microstructural observation using Scanning Electron Microscopy - SEM and light optical microscopy. Consequently, the correlation of DoS value to the external factors that affect it becomes possible. Remarkably, material under investigation has significantly diverse chemical composition, compared to common marine grade aluminum alloys. Ultimately, correlation of Stress Corrosion Cracking behavior with the microstructure is discussed.
Noordin, M. Farriz (PETRONAS) | James Berok, Sylvia Mavis (PETRONAS) | Sinanan, Haydn Brent (PETRONAS) | Suratman, M. Farhan (PETRONAS) | Fabian, Oka (PETRONAS) | Mohammad, M. Afzan (PETRONAS) | Johari, M. Raimi (Marubeni-Itochu Tubulars Asia Pte Ltd)
Abstract PETRONAS has undertaken a large EOR project offshore Malaysia involving the use of Immiscible Water-Alternating-Gas (iWAG) wells for fluid injection. These iWAG injection wells will allow the alternate injection of both treated seawater and hydrocarbon gas. A significant concern for these wells is tubing corrosion resistance and integrity for over a 25-year injection life. The initial conceptual design for the iWAG injection tubing utilized Glass Reinforced Epoxy (GRE) & 25Cr tubing material due to the presence of dissolved oxygen in the injected water. The use of these materials present challenges due to limitations in downhole flow device installation with the GRE tubing and high cost of 25Cr tubing. The project team searched for alternative, fit for purpose materials to meet the project's requirements. Based on the recent PETRONAS success case of 17Cr utilization, the team examined the possibility of using 17Cr or lower grade CRA material for injection purposes. By pioneering the first application of 15Cr OCTG as an iWAG injection tubing material in the world, several risks had to be considered. Additionally, all risks had to be mitigated via various approaches ranging from detailed engineering planning to field execution and operation. The process of selecting this metallurgy involved criteria such as cost, performance, manufacturability and operational execution. The selection methodology included a comprehensive evaluation and recommendation process that consisted of: Evaluation of currently used metallurgical properties and limitations Identification of alternatives based on operating conditions, cost and manufacturing constraints Metallurgy qualification through comprehensive laboratory testing. Conducting tubing installation risk analysis Reviewing tubing operational, intervention and abandonment scenarios throughout the well life cycle The successful selection and installation of 15Cr was attributed to: The metallurgy selection, tubing procurement and installation process involving multidisciplinary and multifunctional groups both internal and external to PETRONAS. Rigorous testing at two separate laboratory facilities yielding test results which met and exceeded the required performance criteria. A 15Cr tubing make up efficiency of 100%. Impressive performance during operations resulting in a gross running speed of 371 ft/hr versus an average pipe running speed of 810 ft/hr. Use of low penetration dies to prevent slippage during tubing connection make up. This was critical since CRA material is very sensitive to scratching during contact with metal equipment. This potential metal scratching can lead to corrosion. On time delivery of 15Cr tubing from the OCTG provider ensuring sufficient time for preparation of completion accessories prior to offshore load out. Utilization of 15Cr as an alternative to Duplex and Glass Reinforced Epoxy (GRE) materials has also contributed a direct cost saving of 27% to the project.
Gupta, M K (Oil and Natural Gas Corporation India Limited) | Singh, V K (Oil and Natural Gas Corporation India Limited) | Sharma, MSK (Oil and Natural Gas Corporation India Limited) | Katre, N V (Oil and Natural Gas Corporation India Limited) | Boddu, V (Oil and Natural Gas Corporation India Limited) | Nath, Siddharth Priya (Oil and Natural Gas Corporation India Limited) | Reddy, Rajesh (Oil and Natural Gas Corporation India Limited) | Raman, Ravi (Oil and Natural Gas Corporation India Limited)
Abstract In a producing field of western offshore, H2S content in oil was found to be in the range of 3000-5000 ppm against the desired level of 200ppm. High H2S concentration posed a serious threat to pipelines integrity and downstream equipment. Mitigation by conventional means such as chemical injection is generally avoided at offshore due to constraint like continuous pumping, storage of chemicals, frequent monitoring, logistical impediments and disposing off by-products in compliance with statutory requirements. Considering many limitations at offshore, an approach was adopted for reduction of H2S utilizing Henry's principle which states that the amount of dissolved gas in a liquid is proportional to its partial pressure. Reducing the partial pressure by utilizing sweet natural gas or some other inert gas, H2S can be removed. Same principle was applied to conceptualize a processing system wherein sour crude can be sweetened to the desired level utilizing sweet gas as stripping gas. Processing System was designed considering many downstream and upstream constraints in the existing system and without any rotating and heating requirement. Unlike conventional way of sweetening such as chemical injection which requires continuous dosing of chemical and disposing off by-products in compliance with statutory requirements and hence, found not feasible at offshore to sweet enormous amount of crude. The designed processing system, a first in Indian offshore environment, is commissioned at one of the offshore complex and has proved it efficacy wherein H2S content of around 3000 ppm in around 6000 barrel/day of crude is being reduced to less than 10 ppm level without use of any hazardous chemicals and without any need of rotating and heating equipment's and with minimum maintenance and manual intervention requirement. The system has lowest operating cost, low maintenance and without use of any rotating and heating equipment's and hence can be emerged as an ideal solution for crude oil sweetening at offshore environment or in an environment where bare manual intervention is required.