There are many older offshore steel pipelines that have been damaged or exhibit excessive corrosion whereby dropping below minimum wall thickness requirements. Conventional rehabilitation or replacement of existing offhshore flow back lines often times has been cost prohibitive for older lower producing wells resulting in the premature abandonment or closing of wells. By pulling flexible reinforced thermoplastic pipes through the existing steel pipelines and multiple riser configurations, signifcant cost savings can be realized with minimal sea floor disturbance. The reduced capital costs allow wells to continue to be productive through their remaining lives without sacrificing pipeline integrity. This paper provides a detailed case study for a Petronas flow line in the Samarang Field describing the step by step processes required for a successful rehabilitation of a pipeline. This includes proper pipe sizing considerations to compensate for lower flow rates, material selection for the reinfoced thermoplastic pipe to withstand the pipleline flow environment, determination of pull force requirments, regulatory approvals, pre-installation preparation of the existing flow line, step by step installation procedures, testing and integrity requirements and how unforseen issues raised durning the process were addressed. The paper will conclude with lessons learned and what improvements were implemented for future projects as well as the cost benefits versus replaceing the steel lines
Flexible pipeline is a technically and economically viable solution for brownfield's EOR project, and with reference to one of PETRONAS Carigali's recent EOR projects, is the enabler for this EOR development. This paper provides a review of available pipeline solutions to fulfill EOR project's gas and water injection requirements which are vital to the success of the EOR technology implementation. A comprehensive technical assessment addressing the risk, advantages, limitations and also a brief overview on cost benefits have been performed on selected unconventional pipeline technologies, in comparison to rigid pipeline, using one of PETRONAS Carigali's recent EOR projects as the field case study. The EOR project case study key design drivers and constraints, mainly the ultra-shallow water depths ranging between 8m to 50m LAT, congested seabed with existing infrastructures, large areas of coral outcrops at multiple locations and the relatively high design pressures and design temperatures present great challenges in choosing the optimum pipeline solution. Feasibility of available unconventional pipeline technologies are evaluated against the project design drivers and the most viable solution is compared to the conventional rigid pipeline solution. Considerations are also given to design complexity, installation requirements, operation and integrity management. Complete selection criteria and matrixes are provided and supported with market information.
Operators around the world are reviewing their aging assets, and are coming to clench with the reality that some offshore fields are no longer economically viable. The North Sea and the Gulf of Mexico have seen numbers of decommissioning activities. In other regions, decommissioning activities had started to emerge, now and in the coming years. Decommissioning, an easy-look-but-massive-task come with unique challenges and cost ranging in the billions. Delivering an effective decommissioning especially when dealing with deep-water operations are paramount as to secure the economic value from the assets. Health, Safety and Environmental (HSE) concerns are always vital in any decommissioning process. The target is to effectively reduce the long term risks to other benefactors of the sea while the associated short term risks to those responsible for decommissioning operations are minimized. A major part of any decommissioning project is the decommissioning of subsea pipelines including the flowlines and risers. Referring to a field case example from one of PETRONAS's deepwater field decommissioning project in Atlantic Ocean, a numbers of techniques had been considered for decommissioning of subsea pipeline system which sited in 700m to 960m water depth, ranging from preservation for potential future use, leaving in-situ or full recovery. Noted that each subsea pipeline decommissioning technique should be considered on its own merit, thus the assessment of each decommissioning technique had been based on many parameters, amongst others, size of pipeline, type of pipeline (e.g. single pipe, pipe-in-pipe, flexible), type of fluid in the pipeline, operational environment (location), production history, Inspection, Repair and Maintenance (IRM) records, HSE considerations, connection to other facilities, technical feasibility (including potential use of advanced technologies), regulatory authorities requirements and socio-economic considerations. This paper covers only at specific of PETRONAS deepwater subsea flowlines and risers decommissioning experiences. It outlines the activities done starting from desk top activities (e.g. planning and concept) up to operational activities (e.g. pigging, flushing, cleaning, disconnection, retrieval or leaving in-situ). Different considered scenarios are discussed and potential advantages and disadvantages of each scenario are presented.
Towing of offshore pipelines can be heard during the mid-nineties, and it has been continuously improved with the advent of 2nd and third generation vessels. The operation poses a great challenge due to the dynamics and the instantaneous tension which the pipelines need to face. There is a high risk of flow line / pipeline getting damaged with potential increase in tension loads. It could also happen that the pipeline can get buckled with unexpected environmental loads. There can be a situation wherein the flow line gets damaged due to difference in tow speeds. In such situations the pipeline most likely touches the seabed for a shallow water depth. If a pipeline is in high tension in which greater than the allowable axial load, then there is likely pipeline can get damaged. If the pipeline is a flexible type, then there is a high chance for the outer sheath to get damaged. It is one of a most delicate operation which requires a focused interaction from different parties, viz. the Tow master, captain of the forward and trailing vessel and the monitoring vessel which have to move in a synchronized speed along with the Tow speed. There are in all three (3) major phases for a typical Towing Operation: a) Initiation and setup for Towing; b) start of Towing operation; and c) Tie-in or relocating the Pipeline / Riser to a new location. The seabed route selection and the bathymetry features are decided and firmed upfront. It should be as much as possible select the shortest route with minimum changes in the Vessel azimuth and bearing direction. The bathymetry should be free of any elevated obstruction, subsea anchor, mooring buoys and any mooring anchor chain from the nearby floating facility. This paper will be discussing flexible dynamic riser with near seabed tow at shallow water depth and high current. The flexible dynamic riser is an existing production line, which was required to be detached from a floating facility and then to be towed away to a safe distance. The facilities were temporarily shut down and during that time flexible riser was planned to be towed to a safe location and wet stored. The flexible riser was then again towed back to the same field after changes were made in the infrastructure facilities. The additional challenges faced were on manipulating the tensions around the bend stiffener and maintaining allowable Minimum Bend Radius (MBR) near the bend stiffener portion. It discusses about the sequence of operation, the initial planning preparation work, the simulated engineering activity, the offshore marine spread and its associated activities, and the monitoring systems in place.
A lateral buckling mitigation design solution had been proposed for PETRONAS project to control pipeline expansion along a proposed 28" gas pipeline. Unfortunately, the design which considers typical conservative approaches, had lead to excessive addition cost beyond the expected amount of Final Investment Decision (FID) and project sanction. Moreover, the mitigation scheme had been proposed without adequate study of alternative options by rationalization of various pipeline design parameters including design pressure and temperature profile, pipe WT, CWC thickness, soil data which may involve influencing other disciplines. The proposed solution also requires additional cost to offshore construction work. This paper provides insights on the assessment and design approaches carried out to optimize lateral buckling solution for the 28" offshore gas export pipeline. As the issue had come about when the carbon steel linepipe bidding process was almost completed, the pipeline project team had limited wall thickness available. With that in mind, PETRONAS’s pipeline in-house engineering team had performed probability assessment to identify the characteristic VAS along the pipeline. This approach was taken to reduce the previous conservative assumption whereby only single isolation buckling case has been introduced. For the purpose of lowering the pipeline temperature profile, an option of utilizing mother pipe for bend wall thickness at the hot end area without concrete coating was investigated. The study aimed to get a combination of wall thicknesses, with and without concrete weight coating that allow uncontrolled buckling formation within the safety limit so that additional offshore construction work can be eliminated. All the assessment was according to DNV-RP-F110 and DNV-OS-F101 limit state requirement. The characteristic VAS determined from probability assessment is much shorter compare to conservative assumption of isolated single buckle formation. The expansion issue along the proposed pipeline was achieved by removing concrete weight coating section along the first 10km of the pipeline with higher wall thickness to counterbalance the stability issue as well as providing higher resistance against local buckling, fracture and fatigue. Thinner wall thickness provided with concrete weight coating (CWC) was selected for the pipeline section between 10km to 20km when the effective force is lower. For cost effective design, the mitigation scheme needs to be rationalized with various parameters from design pressure and temperature profile, pipe WT, CWC thickness, soil data and offshore construction. Lesson learnt from multiple recent projects shows clear indication that global buckling of a pipeline needs to be investigated, confirmed and optimized prior to initiation of line pipe procurement or even prior to FID especially for a long distance pipeline. In order to avoid unnecessary additional cost impact, it is important to eliminate uncertainty, huge design tolerance and conservative assumption in the design as it could lead to a complex system arrangement.
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