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Take Back Control of Your Capital Project with an EPC 4.0 Strategy Stratigraphical - Sedimentological Framework For The Thamama Group Development In The Western Uae Based On The Legacy Core Data: How The Key To The Future Is Found In The Past. Performance Comparison Of Two Different In-house Built Virtual Metering Systems For Production Back Allocation. Innovation In A Time Of Crisis: How Can The Upstream Industry Develop New, Fit-for-purpose Technology? How To Meet Operational Challenges In An Extreme VUCA Environment By Adaptive Process Control. Challenges In Drilling & Completion Of Extended Reach Drilling Wells With Landing Point Departure More Than 10,000ft In Light/ Slim Casing Design.
Early U.S. settlements commonly were located near salt lakes that supplied salt to the population. These salt springs were often contaminated with petroleum, and many of the early efforts to acquire salt by digging wells were rewarded by finding unwanted amounts of oil and gas associated with the saline waters. In the Appalachian Mountains, saline water springs commonly occur along the crests of anticlines. In 1855, it was found that petroleum distillation produced light oil that was, as an illuminant, similar to coal oil and better than whale oil. This knowledge spurred the search for saline waters containing oil. With the methods of the salt producers, Colonel Edward Drake drilled a well on Oil Creek, near Titusville, Pennsylvania, in 1859. He struck oil at a depth of 70 ft, and this first oil well produced approximately 35 B/D. Early oil producers did not realize the significance of the oil and saline waters occurring together. In fact, it was not until 1938 that the existence of interstitial water in oil reservoirs was generally recognized. Torrey was convinced by 1928 that dispersed interstitial water existed in oil reservoirs, but his colleagues rejected his belief because most of the producing wells did not produce any water on completion. Occurrences of mixtures of oil and gas with water were recognized by Griswold and Munn, but they believed that there was a definite separation of the oil and water, and that oil, gas, and water mixtures did not occur in the sand before a well tapped a reservoir. It was not until 1928 that the first commercial laboratory for the analysis of rock cores was established, and the first core tested was from the Bradford third sand (Bradford field, McKean County, Pennsylvania). The percent saturation and percent porosity of this core were plotted vs. depth to construct a graphic representation of the oil and water saturation. The soluble mineral salts that were extracted from the core led Torrey to suspect that water was indigenous to the oil-productive sand. Shortly thereafter, a test well was drilled near Custer City, Pennsylvania, that encountered greater than average oil saturation in the lower part of the Bradford sand. This high oil saturation resulted from the action of an unsuspected flood, the existence of which was not known when the location for the test well had been selected. The upper part of the sand was not cored. Toward the end of the cutting of the first core with a cable tool, core barrel oil began to come into the hole so fast that it was not necessary to add water for the cutting of the second section of the sand. Therefore, the lower 3 ft of the Bradford sand was cut with oil in a hole free from water.
Willhite, J. (Applied Graphene Materials UK Ltd.) | Sharp, M. (Applied Graphene Materials UK Ltd.) | Chikosha, L. (Applied Graphene Materials UK Ltd.) | Weaver, W. (Applied Graphene Materials UK Ltd.)
Applied Graphene Materials UK Ltd. produces a number of graphene nanoplatelet (GNP) dispersions, enabling enhanced electrical/thermal conductivity, improved mechanical properties, and reduced water permeability/barrier properties within host systems. It has been demonstrated that GNPs, when incorporated into an organic coating, provide a highly tortuous pathway which acts to impede the movement of corrosive species towards the metal surface, rendering them highly beneficial in barrier coatings.
Current organic coating systems for C4/C5 environments (high and very high risk environmental categories) are typically comprised of a number of different coating layers, usually consisting of three layers, including a primer coat, an intermediate coat and a final topcoat. In this work we discuss the options available for GNP incorporation into full systems e.g. within the [zinc rich] primer, intermediate coat or top coat, including the merits and drawbacks associated with each approach.
We present our work on the incorporation of GNPs into the tiecoats of fully formulated C4/C5 systems (high and very high risk environmental categories), demonstrating clear anti-corrosion performance improvements using a combined neutral salt spray (NSS) and electrochemical AC impedance spectroscopy (EIS) test method.
Applied Graphene Materials UK Ltd. (AGM) produces a range of dispersions of graphene nanoplatelets (GNPs), enabling property introductions/enhancements such as electrical/thermal conductivity, mechanical e.g. fracture toughness, gas permeability and barrier type to be achieved. GNPs are manufactured using the company's patented proprietary "bottom up" process, yielding high specification graphene materials.
Coatings of various types such as inorganic1, organic2, hybrid3, nano4 and green5 have been widely employed in the corrosion protection of metallic materials under high and very high risk environmental categories for corrosion. Such categories, as referred to in BS EN ISO 12944-26, range from C4/C5 (high and very high risk environmental categories) with exterior examples of these categories including industrial and coastal areas of moderate to high salinity. Due to growth within the offshore industry in emerging economies and an increased rate of shipbuilding, the marine coatings market is estimated to be worth USD 15 billion by 20247.
Splash and immersion zones on offshore installations are areas that are exposed to extremely aggressive environments due to the effects of sea water, tides, wind, waves, and/or ultraviolet radiation. Various certifications such as NORSOK(1) exist to help guide customers select a coating based on its corrosion resistance performance. Despite the necessity of these standards, it is helpful to understand that other properties such as substrate surface and cure conditions can greatly effect performance of the coatings. In this paper, we will compare adhesion of two coatings to different substrate surface conditions while both coatings will be cured in two different environments. Our goal is to investigate the effect of curing environment of coatings on adhesion to the substrate.
Various challenging environments exist where structures are exposed to continuous or periodic water immersion. This is often found in the offshore industries. Over the years, coatings have been developed to protect structures like pylons, walkways, and pipework that make up larger offshore structures including oil drill rigs and platforms.4 The coating must provide superior protection against corrosion and reduce the need for maintenance while addressing complex applications and providing minimal environmental impact.
Specifically considering the coating application, applicators are often subject to short timeframes and non-ideal environmental conditions. Coatings will often need to be applied on damp and wet substrates or submerged shortly after the coating is applied.4 Over the years, new coatings are being developed to meet these challenging requirements, providing better surface tolerance and underwater curing while maintaining protective and aesthetic properties. Coatings are typically made up of binder resin, pigment, filler, solvent (or water), and various additives for specific and unique coating properties. Historically, the coatings used to protect splash and tidal zones as well as immersion zones are comprised of epoxy amine resin. Once the coating is applied, the epoxy can form polar bonds with the substrate, allowing it to adhere to the substrate and cure underwater. Special attention should be given to the selection of the epoxy and amine resin for coatings cured under water that are subject to cathodic protection systems or other generated electrical currents. These electrical fields can disrupt coating adhesion when hydroxides are subsequently produced and can participate in electrophilic attack of the epoxide groups during cure.5 The choice of curing agent is also important. Amines are hygroscopic and may leach from the coating (amine blooming) or react with water and carbon dioxide to form a waxy or oily film mainly due to ammonium bicarbonate salts (amine blushing).6 Additionally, the polyamide/amine could separate and cause discoloration of the coating.7 Once the coating is cured, there is still potential for degradation due to water absorption into the coating from attraction to the polar groups on the epoxy resin, breaking hydrogen bonds, and swelling the polymer. Additionally, water could possibly degrade the resin by hydrolyzing epoxy ether linkages.8 Both the epoxy resin and amine curing agent should be carefully chosen to maintain durability and chemical and corrosion resistance while avoiding unwanted side reactions.
Carbon capture and storage or carbon capture and utilisation (CCS or CCU) are being considered in order to facilitate the extended use of both fossil-fuel power stations and high carbon dioxide (CO2) emitting industrial facilities such as steel, cement and petrochemical plants. In order to realise such anthropogenic CO2 abatement strategies, it is vital to ensure that the CCS/CCU chain provides solutions for the transmission of CO2 from the point of capture to the location of permanent storage or transformation. Provision of a safe, reliable and cost-effective transportation network for CO2 is a key pre-requisite of all CSS innovations. The research into materials selection is important as a cheaper, yet satisfactory material could make the difference between technology acceptance and failure. The test protocols are also important as incorrect simulation of environment could lead to the selection of unsuitable material. The paper focuses on these aspects and brings to light some understanding gained during the material selection process. The important aspect related to the test protocol is discussed and results on some selected materials are also presented.
Research into materials for handling supercritical (sc-CO2) or ‘dense phase’ carbon dioxide especially in the presence of impurities, has recently gained interest due to the introduction of carbon capture and/or storage or utilisation (CCS and CCU respectively) as a CO2 emission reduction tool. The supercritical phase is defined by the region in the phase diagram where the temperature (T) and pressure (P) exceed the critical values Tcrit and Pcrit (Figure 1). For CO2, the critical point beyond which the supercritical phase is formed is 31.1 °C and 7.39 MPa. At elevated pressure, CO2 may exist as a liquid if the temperature is below the critical temperature. When liquid CO2 is present under conditions above the critical pressure, it is often termed ‘dense phase’ fluid. Handling and transportation of anhydrous CO2 is a mature technology, in which compression to a high pressure state (dense/supercritical) in order to increase density has practical and economic benefits.1
The Eni Nikaitchuq field development on the North Slope of Alaska consists of the Spy Island Drillsite (SID) artificial island, tied back to shore at the Oliktok Point Pad (OPP) production facility via a 3.6-milelong buried offshore flowline bundle which contains a 14x18-in pipe-in-pipe (PIP) production flowline. In late 2017, the presence of internal corrosion was detected in the 14-in production flowline, and a repair of the line was performed. This paper presents the work performed to complete the repair, and the engineering and construction challenges overcome by the project team to ensure a timely and reliable repair was executed. The engineering work was initiated in early 2018 and included initial integrity checks of the 14-in flowline, followed by an evaluation of feasible repair options, and the selection of the preferred repair option, which was to install a 10-in steel linepipe inside of the original 14-in flowline to create a pipe-inpipe-in-pipe (PIPIP). The selected repair methodology allowed the total repair project to be undertaken in six months, from the time of repair concept definition to restart of production. Actual production downtime was limited to only seven weeks, with the insertion of the 10-in repair pipe itself taking only ten days. Production has been successfully ongoing since completion of the repair and resumption of operations at Nikaitchuq. It is believed that this is the first time such a repair has been successfully undertaken, where a steel flowline several miles long has been installed inside of an existing flowline and serves as a good example of how innovative engineering and construction methodologies can be reliably implemented in the Arctic.
Corrosion in oil and gas operations is generally caused by water, carbon dioxide (CO2) and hydrogen sulfide (H2S), and can be aggravated in downhole applications where high temperatures combination with H2S introduce other challenges related to corrosion and iron sulfide (FeS) scale formation. The repair costs from corrosion attacks are very high and associated failures have effects on plant production rates and process integrity. To overcome this existing problem in upstream, nonmetallic composite materials were introduced for drilling, tubular and completions in high risk, corrosive environments. The goal being to increase the well life cycle and minimize the effect of corrosion, scale and friction in carbon steel tubulars. The new proposed materials have light weight, high strength, and superior fatigue resistance in addition to an outstanding corrosion resistance that is able to surpass many metallic materials.
The economic analysis shows that utilization of nonmetallic tubulars and internal linings will yield substantial life cycle cost saving per well mainly due to the elimination of workover operations. However, with these advantages, composite materials pose several challenges such as single source provision, high initial cost of raw materials, the manufacturing process and the limitation of standards. As results, the polymer and composite solutions for upstream oil and gas are still very limited even in targeting low risk applications such as low temperature and pressure scenarios. Therefore, research & development (R&D) efforts are ongoing to increase the operation envelope and introduce cost effective raw materials for high-pressure, high temperature (HPHT) subsurface applications.
The present paper highlights practical examples of nonmetallic materials selection and qualification for upstream water injection/producer and hydrocarbon wells. Several future NM applications in upstream will be summarized. Challenges and R&D forward strategies are presented in order to expand the operation envelope of current materials and increase NM deployment to more complex wells, i.e., extended reach drilling (ERD).
Review our data policy for information about these graphics and how they may be used. The formation of scale deposits upon tubing, casing, perforations, and even on the formation face itself, can severely constrict fluid flow and reduce the production rate of oil and gas wells. In addition to lost production, a considerable portion of the workover budget is expended in efforts to remove these deposits and prevent their recurrence. As a consequence, scale prevention has been and continues to be a common exercise and is successfully applied in many areas. Although the principles behind scale formation and prevention are generally well understood, there are many new forms of scale prevention and new scale inhibitor application technologies. Some people consider scale prevention a mature subject matter area with “nothing new under the sun,” but in fact there are many new developments, some of which will be highlighted in this presentation. This presentation will review the major elements ...
The effectiveness of poly (2-acrylamido-2-methylpropane sulfonic acid) (PAMPS) and copolymers with acrylic acid (AA) and acrylamide (AM) magnetic nanogels as protective corrosion of CS in reaction with water by (EIS), (EFM) and tafel polarization method. Polarization method demonstrated that all the polymers are mixed inhibitor type. (EIS) Electrochemical impedance given that the attendance of these investigated polymers declines the double layer capacitance and improvement the charge transfer resistance. The polymers adsorption on surface of steel was follow isotherm Temkin. The morphology of the CS surface was examining by (EDX) energy dispersive X-ray and (SEM) scanning electron microscope. The data obtain showed improvement in efficiencies for inhibition with raising the dose of inhibitor.
CS is the common regularly utilized pipeline materials as a part of petroleum creation. In any case, it is exceptionally inclined to corrosion in environments include sulphur . Corrosion of sulfur has been one of the corrosion sorts in gas/oil manufacture, offering ascend to the pipelines failure and equipment's and utilized in biggest economic reduction and accidents. Likewise, spillage of raw petroleum because of endures consumption of pipelines would actuate fire accident, and natural contamination [2-4]. Explored to comprehend its mechanism, decrease the corrosion rate, additionally create experimental models to survey and foresee the parametric effects and the states-of the-art of internal corrosion of pipelines [5-12]. Theoretical approaches provide means of experimental of these reactions and there are many reports connection with this area . Last papers have study the connection between the efficiency and structure of the inhibitor molecule, but low attention has been paid to the reliance of the protection efficiency on the size and electronic distribution of the protective molecule, Relation between chemical structure and inhibition efficiency was not research, The super paramagnetic Fe3O4 nanoparticles covered with polymers are usually connected to the magnetic cores to ensure a strong magnetic . Attractive nanogels of regular interest are ferromagnetic magnetite (Fe3O4) covered with cross-connected polymer nanogels. The Fe3O4 center has solid attractive characteristic and super paramagnetic conduct, is of generally declines danger to the human body when epitomized in the defensive shell of polymer, which is cross-connected hydrogels polymer. The shell keeps the Fe3O4 center from total oxidation. In this appreciation, the utilizing of nanogels particles as a part of the field of consumption hindrance insurance for steel rather than ordinary natural inhibitors can deliver uniform flimsy film (with no pine opening because of cross-connected polymers) on the surface of CS to coat all surface with no deformities which give focal points over typical natural inhibitors. A few strategies have been produced to get ready attractive miniaturized scale and nanogels, for example, reverse microemulsion polymerization and emulsion polymerization [15-18]. The target of this paper is to calculation the inhibitive effect of these polymers on carbon steel in formation water by various electrochemical methods.
Predicting corrosion risks and developing inspection and mitigation plans form a vital part of any Integrity Management System (IMS). Most of the emphasis from operators is given to upstream and processing facilities, however, the facilities installed downstream, in particular the storage and transport of refined hydrocarbon products, are often considered in the “fit and forget” philosophy.
Refined hydrocarbon products such as Jet A1, LPG and ULG etc. are not generally corrosive to metals and alloys which are used for their storage and transport; however, they do contain dissolved water, organic sulphides and oxygen containing compounds that can cause corrosion over time. Conventional corrosion prediction models are not relevant since hydrogen sulphide and significant carbon dioxide are not present. In order to overcome this limitation and to allow corrosion risk assessment of both existing and aging facilities, an alternative in-house corrosion risk assessment methodology has been developed. This methodology helps to dilute the corrosion risks associated with these facilities in a well-structured process as practiced for one of the major operators in the Middle East. This paper discusses the methodology adopted to model the corrosion rates and risk assessment involving both probability and consequences within these product streams.
Refined hydrocarbons or fuels are the backbone of modern day industries whether it’s aviation, automobile, shipping, power, agriculture, fertilizer, textiles or any other sector. Crude oil which is a mixture of different liquid hydrocarbons undergoes distillation and treating operations, yielding refined hydrocarbons that include unleaded gasoline (ULG), liquified petroleum gas (LPG), Jet A1, Gasoil and JP8 (military grade aviation fuel). Since these products are refined, it is misunderstood that they cannot corrode the equipment and pipelines that handle them. Vice versa, the quality of these fuels can be compromised by the equipment they are contained in, whether metallic or non-metallic once degraded or corroded. This is one of the reasons there are sets of filters installed to maintain cleanliness of the fuels at locations along the transportation route of these products. Thus, performing corrosion risk assessments for these assets is vital for their reliability, personnel safety and the environment in which they are contained.