A Novel IoT-Based Method for Real-Time Detection of Spontaneous Leaks in Pipelines, Gathering Systems, and Offshore Risers

This paper presents on a non-invasive, IoT-based method for rapidly determining the presence and location of spontaneous leaks in pressurized lines transporting any type of product (e.g., oil, gas, water, etc.). Specific applications include long-distance transmission lines, gathering networks at well sites, and offshore production risers. The methodology combines proven negative pressure wave (NPW) sensing with advanced signal processing to minimize false positives and accurately identify the presence of small spontaneous leaks within seconds of their occurrence. In the case of long-distance transmission pipelines, the location of the leak can be localized to within 20-50 feet. The solution was commercialized in 2020 and has undergone extensive testing to verify its capabilities. It is currently in use by several operators, both onshore and offshore.

Plastic Liners for Offshore Production Lines: A Cost Effective Alternative Solution to Corrosion Resistant Alloys?

This paper presents the investigations performed by TotalEnergies and Saipem on the cost effectiveness potential of internal plastic lining for corrosion protection of offshore production lines. Objective was to better understand for a complete EPCI cost comparison the various parameters that could have a significant impact on the potential savings associated with the use of plastic lining instead of CRAs (Corrosion Resistant Alloys) for very corrosive production fluids such as sour gases. An extensive cost comparison study between CRA lining and plastic lining for offshore production lines was performed considering sensitivity on several parameters: 3 pipe diameters, S-Lay, Reel-Lay and J-Lay installation, sensitivity to external thermal insulation requirements, mechanical and design requirements, to pipe length and fixed costs (technologies and vessels). A dedicated calculation tool for system design and cost assessment was built on purpose for this sensitivity study. Costs were assessed for the various cases, starting from pipe design, then assessing procurement costs, fabrication costs then installation costs with preliminary cycle time assessment. Project management and engineering costs have been considered to obtain comparative EPCI (as installed) cost assessments for the various study cases. Plastic lining appears to be a cost-effective solution installed in J-Lay or S-Lay in addition to reeling (up to 45% of potential cost savings on installed line compared to CRA lining). The main driver for the cost savings is associated to the procurement of the pipes and associated lining, including pipe manufacturing. Some smaller savings can also be obtained from the offshore cycle times in J-Lay and S-Lay as the CRA welding add a significant operation time in comparison with standard CS welds. The fixed additional costs associated to the plastic lining (specific tooling for example) can be quickly amortized after a few kilometers thanks to the material cost savings. Integrating them as a company investment allows to unlock costs savings even for shorter lines. The thermal contribution of the plastic liner is also interesting regarding the overall pipe insulation design. This study completes the works already performed by the industry on the offshore costs of plastic lining as it considers the whole EPCI CAPEX costs from the Contractor and Operator points of view and offshore experience. The study integrates the S-Lay and J-Lay installation methods (while previous studies mainly focused on Reel-Lay) and includes an extensive sensitivity study with various key parameters such as pipe sizes, pipe design requirements, material costs and offshore operation times to get a general overview of potential benefits associated with plastic linings for offshore production lines transporting corrosive fluids such as sour gases.

Ultra-Low Dose Asphaltene Inhibitors for Offshore Applications: Myth or Reality

In recent years, long-distance subsea tiebacks have become a preferred field development option for deep and ultra-deepwater production. However, conditions such as lengthy umbilical systems, high pressures and variable temperatures conditions pose challenges for the continuous injection of various flow assurance chemicals. Severe operating conditions often require relatively high volumes of diluted inhibitors to be stored and injected offshore, resulting in high CAPEX costs for the installation of large topsides chemical storage tanks and their associated weight increases. Alliance Engineering estimates a deepwater platform's topsides installed costs are within the range of $35,000-$50,000/ton. It is possible to achieve significant capital cost savings on new platform designs if the dosage rates and subsequently offshore storage volumes of the highest usage production chemicals such as asphaltene inhibitors could be significantly reduced. This paper presents information on a new class of biosurfactants that are bio-based and eco-acceptable with potentials for development of ultra-low dose asphaltene inhibitors for offshore applications. Asphaltenes were extracted from chemical free crude oil samples and a curve of solubility with different ratios of heptane was obtained for each sample in order to determine the best conditions to perform the screening tests. A new class of glycolipid biosurfactants (GLP-U) was developed as an asphaltene dispersants effective at low concentrations for use in offshore applications. The new GLP-U biosurfactants are eco-acceptable and soluble in the organic solvents commonly used in offshore production chemicals. GLP-U were proved to be effective in dispersing and preventing precipitation of isolated asphaltenes at dosage rates as low as 25 mg/L (active substance), while for comparison a dodecylbenzesulfonic acid-based inhibitor provided inhibition at significantly higher concentrations (at least 40 times more).

Integrated computer digital decision for Offshore production automated management

Rising requirements for the hydrocarbons production management system state are based on the industrial situation control necessity according to the environmental conditions. Development of the system construction and complexity indicates the integrative approach implementation reasonability for the producing capacity main indexes estimation and regularity of pace parameters evaluation as well as the layer productiveness level identification. Data processing and management tasks are the waymarks for the industrial multilevel structures models creation. Computer integrated model includes the estimated analytical tool for the extended operational functional support for the production parameters evaluation and technological process state diagnostics in changeable conditions and productive region origin and features traceability. Based on the well observations it is possible to apply the systematic approach for the trends occurrence and dynamics evaluation of the reservoir development time series data. And integrated decision includes the information value degree identification tool for the hydrocarbons production digital model updating.

Rekayasa Nilai Kriteria Desain Fasilitas Produksi Gas Alam

Natural gas is one of the primary hydrocarbon energies in Indonesia. The construction of natural gas production facilities is essential to accommodate domestic energy needs. These facilities include production, pipelines, and processing facilities in an integrated manner. This study used the hydrocarbon composition of Field-X with an average of 7.62% CO2 and 0.06% H2S. The alternative design uses a fixed platform (fixed platform), MOPU (Mobile Offshore Production Unit), and a Semi-Submersible platform. The design comparison criteria are capital expenditure (CapEx), net present value (NPV), internal rate of return (IRR), work completion time, safety risk, and flexibility of future facility development. Through the comparison method, it is found that Option A is the best option, which has a design criterion value of 57%, a higher NPV of $43,537,469.58 than the smallest NPV option, an IRR of 19%, and a payout time (POT) of 5 years. Option A uses a fixed platform with a pipeline to the north, the hydrocarbon separation process is carried out on an offshore platform, and the processing is carried out onshore. ABSTRAKGas alam merupakan salah satu energi hidrokarbon utama di Indonesia. Pembangunan fasilitas produksinya sangat penting untuk mengakomodasi kebutuhan energi dalam negeri. Fasilitas ini meliputi produksi, jalur pemipaan, dan fasilitas pengolahan hidrokarbon secara terintegrasi. Penelitian ini menggunakan komposisi hidrokarbon dari Lapangan-X dengan rata-rata CO2 7.62% dan H2S 0.06%. Alternatif desain menggunakan anjungan tetap (fix platform), MOPU (Mobile Offshore Production Unit), dan anjungan Semi-Submersible. Kriteria perbandingan desain adalah modal awal, nilai bersih saat ini (NPV), tingkat pengembalian internal (IRR), waktu penyelesaian pekerjaan, resiko keselamatan, dan flexibilitas pengembangan fasilitas kedepan. Melalui metode perbandingan yang dipadankan didapatkan Opsi A adalah opsi terbaik, yang memiliki nilai kriteria desain 57%, NPV lebih tinggi $43,537,469.58 dibanding opsi NPV terkecil, IRR 19% dan waktu pembayaran (payout time/POT) 5 tahun. Opsi A menggunakan anjungan tetap dengan jalur pemipaan ke arah Utara, proses separasi hidrokarbon dilakukan pada anjungan lepas pantai (offshore) dan pengolahannya dilakukan di darat (onshore).

First Full-Electric Shared-Actuation Control for Subsea Manifolds in Brazilian Ultra-Deep Waters: A Discussion of the Technological Development up to Field Commissioning

In projects to develop offshore production in Brazilian pre-salt fields, an innovative model of subsea manifolds is being used, based on shared-actuation control (SAC) for the remote operation of valves. The control solution, which comprises the first full-electric robotic tool designed to operate in ultra-deep waters, has achieved an important mark in 2020, with the commissioning and start-of-operation of the first fabricated unit. In this article, we present lessons learned and discuss relevant specifications and programs of the technological development that contributed for the results obtained so far. Considering aspects on conception, technology, and environment of application, the pre-salt SAC required the adoption of new solutions on several disciplines of subsea engineering. As a typical case of technological development, the design process comprised decisions on engineering requirements and the establishment of a comprehensive qualification program. Now, after the first robot completing critical stages at field, such as subsea deployment, functional testing, and integration with the subsea system, we obtain a set of performance results that serve us to evaluate e.g. how effective were the selected technical specifications and testing routines, used throughout the engineering program. This discussion also provides possible adjustments in the overall development plan, considering its application as new generations of SAC arise. The commissioning in 2020 of the first robot resulted in its full integration with the subsea manifold and the correspondent production system, contributing to water-alternating-gas injection in the pre-salt field Tupi Extremo Sul. A second subsea system featuring the same model of robotic tool, for manifold control, is in advanced schedule in 2021 for integration in Búzios II, another pre-salt field in Brazil. Confirming the advantages that we could expect with the adoption of SAC in subsea equipment, the pre-salt SAC allowed a series of optimizations on design of the robot-controlled manifold. The robot tool replaced all the hydraulic actuators that traditional control systems, based on electric-hydraulic multiplexing, would require to implement remote controlling of the manifold valves. This led to a significant reduction on sizes and weight of the manifold structure.

Digitally Transforming Offshore Production: Making Low-Manned Brownfield Installations a Reality

This paper outlines an approach for de-manning brownfield offshore production installations. It discusses how the latest advancements in rotating equipment, electrical & automation systems, and digitalization can be applied to reduce operating costs, lower breakeven prices, and extend the lifetime of existing/aging fields. The approach is value-rather than technology-driven and focuses on prioritizing investments based on return on investment (ROI) to enable low-manned operations as a stepping-stone towards unmanned installations. The paper discusses key facets of a holistic de-manning strategy, including: Remotely controlled production operations Predictive analytics to reduce unplanned downtime and extend mean time between overhauls (MTBO) Automated inspections Remote collaboration Unified data management Change management The concepts presented in the paper are derived from the authors’ company's work implementing digital solutions for customers in both onshore and offshore oil and gas, and power generation industries. It also draws on the results of an in-depth onshore field de-manning study that was conducted for a major Middle East national oil company (NOC).

Analysis of Carbon Footprint Applied to Conceptual Engineering of Offshore Production Units

As the environmental impact is critical for industry sustainability, early quantifying Greenhouse Gas (GHG) emissions of offshore units represents a central role and step-change improvement across the O&G value chain. Developing an overarching realistic model to estimate GHG emissions is a challenge due to the different methodologies available, the complexity of offshore installations, and the degree of uncertainty in the estimation of emission factors. The present work focuses on the earlier stages of new development, notably in Front End Loading-1 (FEL-1) and FEL-2, i.e., opportunity identification and conceptual engineering studies, respectively. The primary objective of this study is to propose an innovative modeling methodology to quantify Greenhouse Gas (GHG) emissions in offshore production facilities. Since E&P companies consider current and future carbon dioxide equivalents (CO2e) emissions as a factor into capital projects economics, this study additionally proposes a semi-empirical model for OPEX calculation considering the impact related to emissions (on a CO2e basis). Emissions of GHG in the O&G industry typically occur from one of the following general source classes: (i) combustion sources, including both stationary devices and mobile equipment; (ii) process emissions and vented sources; (iii) fugitive sources; and (iv) indirect sources. The projection of carbon emission costs along the asset life cycle is performed to simulate the economic impact of such emission on an OPEX perspective. After estimating the CO2e emissions, the procedure consists of using the "Carbon Emission Cost Projection" to calculate the cost of the CO2 emitted and penalize the OPEX of the evaluated alternative. The proposed model can be used to estimate Carbon Footprint for each one of the several conceptual engineering alternatives evaluated during the conceptual phase of the project, improving not only the techno-economic analysis but also the decision-making process of Capital Projects in the O&G Industry.

A Model-Based System Metaheuristic Engineering MBSME Approach in the Conceptual Selection of Offshore Production Units

The objective of this paper is to present and discuss the philosophy behind the integration of "Model-Based Systems Engineering" (MBSE) with metaheuristic algorithms, referred to as "Model-Based Systems Metaheuristic Engineering" (MBSME), which has demonstrated high potential of techno-economic optimization of large capital projects in oil and gas industry, notably in the automatic and integrated conceptual design and selection of offshore systems architectures. Virtual modeling has always been an important part of systems engineering to support functional, performance and other engineering analysis. The so-called MBSME allows the simulation of several specific System-of-Systems physically addressed in offshore field development, bringing all the benefits of the traditional MBSE approach, and set a stochastic characteristic in the analysis, allowing the project team to focus on a Model-Centric approach, as well as to quickly understand the influence of several combined project strategies and application of different technologies, communicated through a Tradespace exploration map. Due to the characteristics associated with and the countless number of variables of the multidimensional problem addressed in an offshore field development, the integration of "Meta-Heuristic" algorithms with "Model-Based Systems Engineering" has demonstrated a remarkable efficiency and powerful applicability in the search for optimized design solutions in oil and gas industry, especially considering the processes of generation of conceptual alternatives of offshore production systems. This method leads to a reduction of more than 2/3 of the average time currently observed, with an increase in the number of conceptual alternatives evaluated in the order of tens to an order of thousands of options, in an automatic and integrated approach. Although the digital MBSME already developed addresses the combination of all technical disciplines associated with a complete offshore field development, the current work emphasizes the latest R&D achievements, addressing the automatic design and specification of Topside Facilities architecture, combined with the automatic selection of fitting for purpose Production Unit, based on internal requirements, such as the required capacity to support total weight and footprint imposed by the topside facilities’ modules, as well as external requirements, like water depth, surface metocean, type of well completion and oil storage requirements. An example of the MBSME application is presented, demonstrating a three-dimensional Tradespace exploration, relating Net Present Value (NPV), Capital Expenditure (CAPEX) and Breakeven Oil Price, through the application of a computational package in a hypothetical project, reflecting the design conditions of an offshore development in the Brazilian Pre-Salt region. The paper communicates an efficient method to increase the scope and accuracy of conceptual analyses, leading to the identification of the most favorable techno-economic conditions to the particularities of each project, supporting significant increases of return on investments.