Maximum Allowable Operating Pressure Research Articles

Numerical analysis for failure estimation of compositely rehabilitated corroded pipes under operational and ultimate states

The current study investigates numerically the rehabilitation of corroded steel pipes using specified CFRP properties to optimize the reduction in burst capacity under distinct corrosion parameters. Two literature testing were examined numerically to validate the generated FEM model. Two sensitivity analyses encountering 144 FEMs were carried out to explore the rehabilitation of corrosion parameters such as width, depth, and length. The results generated equations to predict the hoop stresses for specified burst pressure. Additionally, the study explores the serviceability state at specified minimum yield strength “SMYS” and the maximum allowable operating pressure “MAOP” proposed by “ASME/ANSI” code under two cases; narrow and wide defects. The results show that stresses concentrate near the edges and accumulate in the middle of the narrow and wide defective areas. Thus, the stiffness governs by integrating the steel and CFRP modulus until the steel yields; then, the CFRP stiffness governs reaching its ultimate strain. The results show that the CFRP delays the hoop stresses and generates the ultimate strength, pronounces the most for the deep defect. The burst capacity increases by 20%, 50%, and 80% for shallow, intermediate, and deep defects, handling more strain, about 78% at intermediate defects due to the CFRP confinement which reflects on increasing the “SMYS” by about 5 to 10%. Several recommendations for failure prevention were deduced and recorded. Finally, design equations show a good agreement with the FEM in comparison to the other equations proposed by standards and guidelines, predicting the hoop stress while rehabilitating the defective area.

Development of a diafiltration-nanofiltration-reverse osmosis (DiaNF-RO) process for ion fractionation towards resource recovery in seawater desalination

A diafiltration-nanofiltration-reverse osmosis (DiaNF-RO) process is introduced to achieve solutes fractionation of divalent/monovalent ions, i.e., Mg/Na, to enable resource recovery in seawater desalination and brine management. The diafiltration process is applied at the NF stage (i.e., DiaNF) to enhance the Mg/Na fractionation performance of NF (i.e., SF1Mg-Na), while the RO is incorporated to produce desalinated water as well as diluent required by the DiaNF. By initiating the ion fractionation at the pre-treatment rather than post-treatment (i.e., RO-NF), the DiaNF-RO mitigates challenges of high concentration in RO brine management, which includes limitation of maximum allowable operating pressure and high energy requirement. The semi-empirical model, with at least 77.4 % accuracy, is first applied to simulate the performance of DiaNF-RO at different operating conditions and configurations (i.e., multi-stage and recycling). The sensitivity analysis then suggests that dilution should only occur in the last NF stage and without any retentate recycling, while NF pressure and element number should be optimized. Using NF membrane with SFMg-Na of 1.28 at 10 bar and feed seawater of 35 g/L TDS, the optimal 4-stage DiaNF-RO design achieves maximum SF1Mg-Na of 12.19 at 5.72 kWh/m3, or a minimum energy consumption of 5.41 kWh/m3 at SF1Mg-Na of 7.04.

Estimating the line packing time for pipelines transporting carbon dioxide

During the operation of pressurised pipelines transporting compressible fluids, line packing is employed as an effective method that uses the pipeline itself as a buffer storage, compensating for fluctuations in the fluid supply or demand. While in large-capacity natural gas transmission systems, reaching maximum operating pressures during line packing is usually not of practical concern, in small capacity pipelines transporting low-compressibility fluids, such as liquid or dense-phase CO2, line packing can occur quickly, and therefore, estimating the line packing times becomes important to ensure avoiding exceeding the pipeline maximum allowable operating pressure. In this study, a correlation for estimating the line packing time is derived from the transient mass balance in the pipeline. The proposed correlation accounts for the pipeline overall dimensions, operating pressure and temperature, and the fluid properties, namely density and the expansion coefficient. The correlation is also adopted for the calculation of pipeline unpacking times caused by unbalanced discharge from a pipeline. A verification study on line packing in a dense-phase CO2 pipeline shows that within the ranges tested, the proposed correlation estimates conservatively the line packing times with ca. 15 % deviation from the results of simulations obtained using a rigorous transient pipeline flow model. The proposed correlation is also verified against predictions obtained using a parabolic flow model and is recommended for estimating line packing times for both dense-phase and gas-phase CO2 at pressures and temperatures in the ranges 2 - 12 MPa and 280 – 330 K, respectively. The limitations of the proposed line packing time correlation are discussed.

Designs of ultra-HPHT Electrical Component Packages for Downhole and Geothermal Wellbore Logging Tool Integrations

Conventional dielectric sealing materials (PEEK, glass and glass-ceramic) used for sealing electrical feedthroughs, connectors, interconnectors and bulkheads in electronic packages can provide reliable downhole wellbore long-term logging tool service up to 150C or short-term logging service for greater than/equal 200C, due primarily to low glass transition temperature of the used sealing materials. This paper will demonstrate that the maximum allowable operating pressure and temperature could be from 20KSI to 100KSI and from 200C to 400C with Borosilicate and Bismuth-Boron-Silica (XTS) sealing glasses. Borosilicate glass sealed Inconel-Kovar/Kovar electronic housing could maintain reliability up to the maximum pressures of ~35KSI at 200C or 25KSI at 400C. Similarly, a Bismuth-Boron-Silica XTS glass sealed stainless steel electronic package housing could have a maximum operating pressure of ~100KSI at 150C or ~50KSI at 300C temperature. It has been found that high glass transition temperatures of (440-560)C for Borosilicate glass and (44010)C for Bismuth-Boron-Silicate (XTS) glass are key for making highly reliable ultra-HPHT electronic component packages. It is shown that the tetrahedral diamond-like microstructures of these sealing glasses are keys to ensure water-repelling properties to maintain sufficient electrical insulation resistance regardless of their use in water or moisture-rich wellbores. Moreover, compressive pin stress is found to be additional key for mitigate frequently observed glass seal cracks during logging tool field services.

Effects of hydrostatic preload on strain hardening and strain aging of boiler tubes

Tests were conducted to identify the effects of existing defects on strain hardening and strain aging of boiler tubes. Electron backscatter diffraction (EBSD) and finite element analysis (FEA) were used to quantify the local plastic strain near the pre-existing defects. Strain hardening and strain aging effects depend on the degree of plastic deformation. Any existing defects in the boiler tubes can act as stress raisers during the room temperature hydrostatic test. For the morphology and orientations of the defects, a preload of 95 MPa which is equivalent to the hydrostatic test pressure was enough to induce local plasticity. When heated to boiler service temperature and tested to fracture, the mechanical properties of boiler tubes were affected. The test results justify a recommendation that the hydrostatic pressure to be kept near 110% of maximum allowable operating pressure (MAWP) to avoid significant alteration of mechanical properties at stress concentration points in defect-containing boiler membranes.

Designs for Reliability and Failure Mode Prevention of Electrical Feedthroughs in Integrated Downhole Logging Tools

Abstract To enable an electrical feedthrough integrated down-hole logging tool to maintain high reliability during its logging service in any hostile wellbores, it is critical to apply some guidelines for the electrical feedthrough designs. This paper introduces a safety factor-based design guideline to ensure an integrated electrical feedthrough has sufficient compression or thermomechanical stress amplitude in the stress well against potential logging failures. It is preferred to have a safety actor of 1.5–2.0 for an electrical feedthrough at lowest temperature, such as −60°C, and a safety actor of 2.5–5.0 at operating temperature range of 200–260°C. Moreover, the designed ambient pressure capability should be 1.5–2.0 times higher than the maximum downhole pressure, such as 25,000–30,000 PSI. To validate this thermomechanical stress model, several electrical feedthrough prototypes have been tested under simulated 200–260°C and 31,000–34,000 PSI downhole conditions. The observed testing data have demonstrated that there is a maximum allowable operating pressure for an electrical feedthrough operating at a specific downhole temperature. It is clearly demonstrated that an electrical feed-through may operate up to 60,000 PSI at ambient temperature in a real-life application, but it may actually operate up to 30,000–35,000 PSI at 200–260°C downhole temperatures.

Parametric study on tank integration for hydrogen civil aviation propulsion

Hydrogen powered gas turbine propulsion will play a central role in the decarbonisation of civil aviation. A key challenge is the integration of large liquid hydrogen tanks into the aircraft, given the low density of liquid hydrogen. Hydrogen offers a quarter of the energy content, per unit volume and one third of the fuel weight, when compared to a conventional fuel. Optimising tank weight is seen as key to aircraft usefulness. A detailed evaluation of tanks for civil aviation is presented here, covering a very wide range of sizes and design solutions.For passenger air transport, if the choice is made not to vent, dormancy time (the time the tank can be allowed to operate without vapour or important fuel extraction) becomes a key design parameter. This paper highlights the interdependence of Maximum Allowable Operating Pressure and the amount of insulation with heating and venting, considering the influence of dormancy time.The resulting tank gravimetric efficiency is presented for cylindrical tanks with hemispheric ends (a very likely choice for tank design). Notwithstanding conservative analysis, tank gravimetric efficiencies of 65–70% can be achieved. This permits combined fuel and tank weights that are less than half of those of current aircraft. The issue that then becomes critical is the resulting large tank and aircraft volume.

Methods of Carrying Out the Anticipative Maintenance of Fluid Hydrocarbons Transport Systems

Abstract The scientific knowledge, transposed into the engineering practice, requires the collection, by using the most state-of-the-art and complete means of the information necessary for the decision to initiate the most appropriate measures of predictive maintenance. In this context, the information provided as a result of the investigation of the pipelines intended for the transport of fluid hydrocarbons with smart pigging devices (cleaning, calibration, geometric, magnetic flux leakage) refers to those pre-existing in the questionnaire of the pipeline of the inspection operation. The values in the questionnaire are used to evaluate the anomalies in the inspection reports (preliminary and final). A quantitative assessment of anomalies is based on, and limited exclusively to the results of the inspection, and does not include any numerical parameters (corrosion growth rates, anodic potential etc.), other than those from In-Line Inspection such as values Estimated Repair Factor (ERF) of anomalies. The questionnaire (initial data provided) of the pipeline to be investigated with smart pigging devices includes at least: pipe diameter, wall thickness, pipe material, design pressure, Maximum Allowable Operating Pressure (MAOP), transported product, curve type, investigation history. The detection thresholds are applied in accordance with the manufacturing standards of the pipes. Generally, the calculation results, namely ERF and safe pressure, based on ASME B31G (Manual for Determining the Remaining Strength of Corroded Pipelines) are used to present the pipeline condition. There are several approaches that can be used to characterize the behavior of corrosion anomalies, both pierced and partial. ASME B31G is a very conservative criterion that helps operators avoid unnecessary cuts. It is based on an empirical adequacy to an extensive series of tests on a full scale on vessels with narrow ridges. Depth-based histograms show the distribution of all metal loss characteristics detected along the entire length of the pipe relative to their location and surface. The approach to the referred issue allows the collection of essential information about the pipeline, and presents summaries of any anomalies of the pipeline, having a comprehensive character.

Physical and Mechanical Properties of Hollow Fiber Membranes and Technological Parameters of the Gas Separation Process.

The porous layer of composite and asymmetric hollow fiber membranes acts as a support and is exposed to strong mechanical stresses. The effect of external pressure on the polymer structure and, as a consequence, the separation characteristics of the membrane remains unsolved. Based on the solution of the Lamé approach to the calculation of the stress state of a hollow cylinder, a method of calculation was proposed for hollow fiber membranes. Calculations were based on the approximation of the isotropic nature of the physical and mechanical characteristics of the selective layer and substrate. Permissible deformation of the membrane’s selective layer was determined from the linear sector of strain-on-stress dependence, where Hooke’s law was performed. For these calculations, commercial polyethersulfone membranes were chosen with an inner and/or outer selective layer and with the following values of Young’s modulus of 2650 and 72 MPa for the selective and porous layers, respectively. The results obtained indicate that the dependence of the maximum allowable operating pressure on the substrate thickness asymptotically trends to a certain maximum value for a given membrane. Presented data showed that membranes with outer selective layer can be operated at higher working pressure. Optimal parameters for hollow fiber gas separation membrane systems should be realized, solving the optimization problem and taking into account the influence of operating, physicochemical and physicomechanical parameters on each other.

Effects of Hydrogen Addition on Design, Maintenance and Surveillance of Gas Networks

Hydrogen, when is blended with natural gas over time, degrades the materials used for pipe transport. Degradation is dependent on the proportion of hydrogen added to the natural gas. The assessment is made according to hydrogen permeation, risk to the integrity of structures, adaptation of surveillance and maintenance of equipment. The paper gives a survey of HE and its consequence on the design and maintenance. It is presented in a logical sequence: the design before use; the hydrogen embrittlement (HE) effects on Maximum Allowable Operating Pressure (MAOP); maintenance and surveillance during use of smooth and damaged pipes; and, particularly, for crack-like defects, corrosion defects and dents.

Integrity and cost evaluation of natural fibers/HDPE composite tailored for piping applications

This paper focused on the establishment of performance level and cost of plantain fibers reinforced High Density Polyethylene (HDPE) matrixes as gas pipeline material using pressure containment of the new materials as performance criterion. The cost of modified plantain fibers, the cost of plantain fibers reinforced HDPE (PFRHDPE) and the cost of PFRHDPE master batch (HDPE resin + plantain fiber particles + stabilizer, plasticizer) for pipes extrusion production and pipelines fittings injection productions were established. The burst pressure evaluated for available standard outside diameter ratio (SDR) using the ultimate tensile strength of PFRHDE is very much greater than the standard SDR design pressures even when the temperature derating factors were applied. The Maximum Allowable Operating Pressure (MAOP) of PFRHDPE and induced stresses of pressurized pipes established indicated that the new material is suitable for pipeline design for natural gas and liquid petroleum (LPG) lines. The PFRHDPE developed has better specific properties than the conventional steel and HDPE pipe material in terms of yield strength, elastic modulus and density of the new material. But in terms of cost, steel and HDPE has approximate desirability for selection with PFRHDPE. The energy required to manufacture and process steel products is about 480 MJ/m2, while that of plastics is about 320 MJ/m2. The study further established that PFRHDPE can be applied in the design of oil and gas gathering, transportation and distribution lines.

Designs for reliability and failure mode prevention of electrical feedthroughs in integrated downhole logging tools

Abstract To enable an electrical feedthrough integrated downhole logging tool to maintain high reliability during its logging service in any hostile wellbores, it is critical to apply some guidelines for the electrical feedthrough designs. This paper introduces a safety factor based design guideline to ensure an integrated electrical feedthrough has sufficient compression or thermo-mechanical stress amplitude in the stress well against potential logging failures. It is preferred to have a safety actor of 1.5~2.0 for an electrical feedthrough at lowest temperature, such as −60°C, and a safety actor of 2.5~5.0 at operating temperature range of 200~260°C. Moreover, the designed ambient pressure capability should be 1.5~2.0 times higher than the maximum downhole pressure, such as 25,000~30,000PSI. To validate this thermo-mechanical stress model, several electrical feedthrough prototypes have been tested under simulated 200~260°C and 31,000~34,000PSI downhole conditions. The observed testing data have demonstrated that there is a maximum allowable operating pressure for an electrical feedthrough operating at a specific downhole temperature. It is clearly demonstrated that an electrical feedthrough may operate up to 60,000 PSI at ambient temperature in a real life application, but it may actually operate up to 30,000~35,000 PSI at 200~260°C downhole temperatures.

Finite Element Analysis of Composite Repair for Damaged Steel Pipeline

Carbon fiber reinforced polymer (CFRP) matrix composite overwrap repair systems have been introduced and accepted as an alternative repair system for steel pipeline. This paper aimed to evaluate the mechanical behavior of damaged steel pipeline with CFRP repair using finite element (FE) analysis. Two different repair strategies, namely wrap repair and patch repair, were considered. The mechanical responses of pipeline with the composite repair system under the maximum allowable operating pressure (MAOP) was analyzed using the validated FE models. The design parameters of the CFRP repair system were analyzed, including patch/wrap size and thickness, defect size, interface bonding, and the material properties of the infill material. The results show that both the stress in the pipe wall and CFRP could be reduced by using a thicker CFRP. With the increase in patch size in the hoop direction, the maximum von Mises stress in the pipe wall generally decreased as the maximum hoop stress in the CFRP increased. The reinforcement of the CFRP repair system could be enhanced by using infill material with a higher elastic modulus. The CFRP patch tended to cause higher interface shear stress than CFRP wrap, but the shear stress could be reduced by using a thicker CFRP. Compared with the fully bonded condition, the frictional interface causes a decrease in hoop stress in the CFRP but an increase in von Mises stress in the steel. The study results indicate the feasibility of composite repair for damaged steel pipeline.

Maximum Allowable Service Pressure for Steel Pipes Used for Transport of Hydrogen Pure or Blended with Natural Gas

The addition of hydrogen in natural gas could have an impact on the degradation over time of the materials currently used for the storage, transport, distribution and use of natural gas. The compatibility of these materials with natural gas including of hydrogen is dependent on the proportion of hydrogen added to the gas and is assessed with regard to several criteria: Permeation of hydrogen through metallic materials; loss of integrity of these materials and adaptation of follow-up actions in service, surveillance and maintenance of equipment. This paper is devoted to the effect of hydrogen embrittlement (HE) by adding hydrogen into natural gas network on design, maintenance, supervision and maximum allowable operating pressure (MAOP) for smooth and damaged pipes.

Crack Propagation and Burst Pressure of Pipeline with Restrained and Unrestrained Concentric Dent-Crack Defects Using Extended Finite Element Method

Mechanical damage in form of dents, cracks, gouges, and scratches are common in pipelines. Sometimes, these damages form in proximity of each other and act as one defect in the pipe wall. The combined defects have been found to be more injurious than individual defects. One of the combined defects in pipeline comprises of a crack in a dent, also known as dent-crack defect. This paper discusses the development of finite element models using extended finite element criterion (XFEM) in Abaqus to predict burst pressure of specimens of API X70 pipeline with restrained and unrestrained concentric dent-crack defects. The models are calibrated and validated using results of full-scale burst tests. The effects of crack length, crack depth, dent depth, and denting pressure on burst pressure are investigated. The results show that restrained dent-crack defects with shallow cracks (depth less than 50% wall thickness) inside dents do not affect pipeline operations at maximum allowable operating pressure if crack lengths are less than 200 mm. Releasing restrained dent-cracks when the pressure is at maximum allowable operating pressure can cause propagation of deep cracks (depth of 50% wall thickness or more) longer than 60 mm. However, only very long cracks (200 mm and higher) propagate to burst the pipe. Cracks of depth less than 20% of wall thickness inside dents formed at zero pressure are not propagated by the maximum allowable operating pressure. Dent-crack defects having dents of depth less than 2% outside diameter of pipe behave as plain cracks if the dents are formed at zero denting pressure but are more injurious than plain cracks if the dents are formed in pressurized pipes.

The Impact of Hydrostatic Pressure Test on the Interstitial Strength of Mild-Steel Pipeline Material

Objectives: This study examined the effect of hydrostatic test practice on the mechanical properties of steel pipeline used in the oil and gas industry. Method/analysis: The method involves subjecting a 76.2 mm (3-inch) and 101 mm (4-inch) pipeline spools to predetermined maximum allowable operating pressures and designed hydrostatic pressures at designated data points. Thereafter, the spools were cut and samples prepared for experimental tests and analysis. Findings: The results showed that there is a significant change in the mechanical properties like fatigue strength and ultimate tensile strength. The result also showed a progressive increase in the fatigue strength from the control specimens to the hydrostatic pressure-tested specimens. The control specimens also exhibited a reduced fatigue strength compared to the maximum allowable operating pressure (MAOP)-tested specimens. Thus, since the hydrostatic pressure-tested specimens exhibited the highest fatigue strength, this could be reasonably attributed to the strain-hardening behaviour. Novelty/improvement: The hydrostatic pressure-testing procedure, at least, is not detrimental to the integrity of the pipeline. At best, it is beneficial since it increases the strain-hardening of the material.Keywords: Hydrostatic Testing, Service Pressures, Near Point, Far Point, Mechanical Properties, Integrity

PREDICTION OF CORRODING PIPELINE REMAINING LIFE-TIME USING SEMI-PROBABILISTIC APPROACH

A semi-probabilistic methodology for predicting the remaining strength of submarine pipelines subjected to internal corrosion based on Recommended Practice RP-F101 by Det Norske Veritas (DNV) is described in this paper. It is used to estimate the maximum allowable operating pressure of the corroding pipelines based on series of pigging data, which represents the corrosion pit location and dimension. The introduction of partial safety factors in the DNV code to minimise the effect of uncertainties due to the defect sizing has improved the reliability of pipeline assessment methodology. Nevertheless, the code is still regarded as a fully deterministic approach due to its incapability of predicting the remaining life of corroded pipeline. Thus, we have added prediction capabilities to the capacity equation by introducing a standard deviation model of future defect depth. By doing so, the variation of safety factors of the capacity equation can be fully manipulated where prediction of future pipeline remaining life-time becomes feasible. The paper demonstrates calculation and prediction of pipeline remaining lifetime subjects to internal corrosion. The results shows the standard deviation of corrosion parameter affected the value of partial safety factor as corrosion progressing, hence amplify the conservatism of time to failure. In general, the prediction of pipeline remaining lifetime can effectively assist pipeline operators to evaluate future safe operating strategies including re-inspection and appropriate maintenance schedule. As a result it can minimize the possibility of pipeline failures until it reaches its designed lifetime.

Treatment on oil/water gel deposition behavior in non-heating gathering and transporting process with polymer flooding wells

Against a background of crude oil shortage and low-carbon economy, optimization and simplification of oil–gas gathering and transporting play an indispensable role in efficient development of oilfield. Profit from the high efficient utilization of the produced liquid self-energy, single-pipe non-heating gathering and transporting process has been recognized in polymer flooding wells of Daqing oilfield (China). However, it is also facing the challenges of deposition, partial blockage, high wellhead pressure, production fluctuation and environment management. A field investigation of the application for the non-heating process and the variation of polymer flooding wellhead pressure were recently carried out. The flow patterns of the oil, water and gas mixture in single-pipe process were identified, and the locations where the gel deposition was most likely to occur were estimated. Deposition inhibitions and removal processes were practiced, and the operation parameters under different working conditions were optimized. The results indicated that single-pipe non-heating process could reduce 20% of the investment and 30% of the running cost and could also make the wellhead pressure of some wells exceed the maximum allowable operating pressure of oil gathering pipelines. There appears to be a proportional relationship among water content, flow rate, residual polymer concentration and gel deposition behavior in a certain range of gathering radius. The gel deposition rate of the produced liquid with polymer concentration of higher than 600 mg/L and the water content of 90.5% reached 0.1154 mm/h in the coldest climate under the normal flow rate of 85 t/d, and the theoretical pigging period was <10 days. Gelation nucleation which was related to emulsification was induced by the transition and coexistence of separated flow and dispersed flow in non-heating gathering pipelines. The main deposition located on the beginning of pipelines, manifold, valve and elbow, and wellhead pressure of 350 psi was created in the test period of 20 days. Although using chemical inhibition method could still obtain a drag reduction rate of more than 25% under crude oil gelation temperature, the fact of the centralization disability of wellhead dosing facilities and the potential threat of chemical inhibitors to the environment could not be ignored. The noticeable energy consumption and potential risks of pipeline restarting may be encountered using facilities improvement and sphere pigging operation in gel deposition behavior treatment. A relation schema which could be used to predict deposition rate and extract thermal flush period according to the actual working condition was established. The successful application of the non-heating gathering and transporting process combated the traditional view that heat tracing is essential for maintaining the surface process in extremely cold area. Furthermore, the results contributed to the existing literature in establishing subsurface and surface parts integration idea for a green field development and accelerate further application of non-heating gathering and transporting process.

Lucius Subsea-Production-System Design and Installation

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 26016, “Lucius Subsea Design and Installation,” by Timothy Dean, Anadarko; Paul Haines, Wood Group Kenny; and Marsha Carlstrom, EXP Engineering International, prepared for the 2015 Offshore Technology Conference, Houston, 4–7 May. The paper has not been peer reviewed. This paper describes the architecture of the Lucius Gulf of Mexico subsea production system and the drivers behind it. Novel technologies are detailed, and innovative installation techniques and highlights are described, including a “strong-back” system for rigid jumpers. Difficulties and lessons learned are also shared. Introduction The Lucius field is located in water depths ranging from 6,800 to 7,100 ft. Lucius has been developed with six initial subsea wells split between two 8-in.-nominal production loops, each with a six-well manifold. The system is designed for a maximum-allowable operating pressure of 9,300 psi. An early discovery well is located away from the well clusters and is daisy chained into the west-manifold flowline loop. Two other delineation wells are produced back to the east manifold with short-stepout flowlines. The step-out wells add some flow-assurance complexity. Unfortunately, permitting restrictions drove the location of one of the step-out wells. The other was drilled by another operator and later was captured by the development with unitization. It is expected that all future wells will be located adjacent to one of the two manifolds. System Overview The system relies heavily on the operator’s subsea-hardware supply-chain alliances for standardized building blocks. A flow test was used to obtain additional reservoir information to help move the project forward to sanction. The discovery well was completed with a stock tree and controls for the flow test. This well and the equipment are now part of the completed system.

On the Burst Strength Capacity of an Aging Subsea Gas Pipeline

Precise evaluation of the performance of aging structures is particularly essential in the oil and gas industry, where inaccurate predictions of structural performance may lead to significantly hazardous consequences. It is also important to accurately predict the corrosion behavior of pipeline structures used in the production of gas in subsea areas. The effects of pipeline failure due to a significant reduction in burst strength make it hard for pipeline operators to maintain pipeline serviceability. Therefore, the serviceability of ongoing subsea gas pipelines should be assessed according to their burst strength capacities, which should not exceed the maximum allowable operating pressure (MAOP). In this study, the critical part of the corrosion along a 2.4 km pipeline was evaluated using two approaches: an empirical design codes formula and Ansys numerical analysis. The future integrity of the aging pipeline was then assessed to predict its remaining years of service. The results and outcomes of this study will be useful in evaluating pipeline integrity and predicting the remaining service life of aging pipeline structures.