Front End Engineering Research Articles

The Role of Progressive Web Apps and WebGL in Modern Front-End Engineering

The Role of Progressive Web Apps and WebGL in Modern Front-End Engineering

Flow assurance analysis in Front End Engineering Design (FEED) of Subsea Flowline and Riser

Innovative subsea production systems (SPS) are required for deep-water oil and gas exploration in order to transport multiphase fluids—a complex mixture of water, gas, and oil—across long distances under challenging conditions. Significant technological challenges confront these systems, such as flow assurance, which ensures continuous fluid flow through pipelines, flowlines, and wells. Flow assurance issues can significantly impact production and incur costly downtime. This paper emphasizes the critical role of flow assurance analysis during the crucial Front-End Engineering Design (FEED) stage of SPS development. By utilizing industry-standard simulation tools like PIPESIM™, engineers can proactively identify and mitigate potential flow assurance problems that could hinder productivity. These analyses are crucial as FEED decisions significantly impact project cost-effectiveness. To illustrate the practical application of flow assurance principles, the paper presents a case study of a subsea architecture design for a specific manifold system. Considering operator requirements, flow assurance simulations were employed to guide critical decisions regarding material selection and optimal sizing of risers and flowlines. This demonstrates how flow assurance considerations during FEED directly influence cost-effective and optimized SPS design.

Digital Twin Approach Integrates Existing Facilities, Proposed Developments

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215074, “Digital Twin for Development and Subsurface Integration: A Window Into the Future,” by Thomas K.G. Gan, Elizabeth Sumadh, and Bhaminie Sagram, Shell. The paper has not been peer reviewed. _ The digital twin (DT) approach provides a virtual and digital representation of existing assets, spanning everything from onshore facilities to offshore platforms, pipelines, and subsurface data, all in one location. It has been used for the operator’s flagship Manatee project to develop three stacked reservoirs offshore Trinidad and Tobago. The DT was used to identify design modifications required at this onshore site and visualize proposed offshore assets. It integrates existing facilities and new design data, including site survey, subsurface, and well data to optimize well planning. Introduction The Manatee field lies within the East Coast Marine Area of Trinidad in approximately 92 m of water and consists of stacked reservoirs of clean and thin-bed unconsolidated sands. Production from these wells is expected to be processed through a new offshore platform and transported by the new pipeline to the Beachfield onshore facility. For a feasibility study and concept-selection stages, the DT platform played a crucial factor in visualizing and contextualizing development options and allowed front-end engineering contractors and operator teams to collaborate across multiple countries and inspect the location virtually. All engineering drawings, maps, design documents, and 3D models were powered by the DT platform. Key Challenges Traditionally, digital collaboration is performed through data and model export from different technical applications and results presented in slides and reporting documents. For oil and gas capital projects, typically 3–6 years elapse from feasibility stage to execution, deepening the issues caused by faulty corporate memory retention, staff movement, and project handover from different internal organizations. Manatee project teams were based in various locations in Trinidad, the US, the UK, the Netherlands, and India, thereby increasing the likelihood of error by using multiple sources of data. Furthermore, effective collaboration without a single source of truth of data can be an obstacle. Given that multiple software was used for model building, development-well planning, and satellite imagery, an inability exists to view 2D and 3D imagery of onshore and offshore facilities with the subsea and subsurface in one place. Furthermore, between 2020 and 2022, the COVID-19 pandemic led to imposed restrictions and limitations placed on site visits. In such scenarios, drone images and video data can prove useful to access facilities remotely. These challenges needed to be addressed by access to a centralized platform that collected, stored, and provided virtual representations to ensure continuous monitoring and efficient decision-making.

Impact of reservoir quality on the carbon storage potential of the Bunter Sandstone Formation, Southern North Sea

The Lower Triassic Bunter Sandstone Formation is a major prospective reservoir for carbon capture, utilization and storage in the UK Southern North Sea, and is likely to play a pivotal role in the UK reaching mid-century Net Zero targets. A knowledge gap in reservoir quality exists between previous detailed, but highly focused front-end engineering and development projects, and large-scale regional analysis. This study integrates a regional approach with locally derived reservoir characterization, offering a holistic analysis of the prospectivity of the Bunter Sandstone Formation for subsurface CO 2 storage. Petrophysical analysis of ninety-six wells across the UK Southern North Sea is coupled with seismic interpretation to understand spatial variations of reservoir thickness, facies and quality that underpin theoretical CO 2 storage capacity models. Electrofacies classification is employed to identify and correlate baffles and barriers to permeability over areas currently licensed for geological carbon storage. Our findings point to variable, but broadly favourable reservoir conditions, though identification and correlation of laterally extensive intraformational mudstones and halite-cemented horizons will likely present challenges to CO 2 injection. Within carbon storage license blocks CS001, CS006 and CS007, the Bunter Sandstone Formation has the potential to store 5700 MCO 2 t, the equivalent of seventy-nine years of the UK's 2022 business and industrial CO 2 emissions. A further 434 MCO 2 t is offered by Triassic closures within license CS005, with many neighbouring moderate (100–1000 MCO 2 t) and small (<100 MCO 2 t) closures forming part of newly awarded carbon storage licenses that will likely form part of the UK SNS CCUS portfolio in the future. Supplementary material: well-correlation panels and tabulated velocity and storage capacity modelling parameters are available at https://doi.org/10.6084/m9.figshare.c.7027450

Novel Exact Solution of Elastic Catenary and Applications on Floating Wind Turbine Mooring Systems

Abstract This research addresses the mathematical solution of the elastic catenary, a fundamental problem in offshore mooring engineering. A novel exact solution in a non-Lagrangian form is developed through rigorous mathematical derivation, distinguishing it from classical Lagrangian solutions. The procedure is reported in detail, and the resulting expressions are applied to analyze the mooring system of a reference floating turbine. A general approach is introduced to solve the transcendental equations associated with catenary mooring problems. The newly derived formulae exhibit greater applicability to geometry-to-force problems compared to existing Lagrangian expressions, making them particularly useful for conceptual designs and front-end engineering. In summary, this work provides valuable new insights into the exact solution of the elastic catenary, enhancing understanding and enabling practical applications in the field of floating wind turbines.

Cost details from front-end engineering design of piperazine with the advanced stripper

This Front-End Engineering Design (FEED) was funded by the U.S. Department of Energy (DOE) to estimate the cost to capture and compress 90 % of the CO2 from an existing natural gas combined cycle (NGCC) in Denver City, Texas, USA. The FEED used the PZAS (Piperazine with the Advanced Stripper) 2 G amine scrubbing technology developed and modeled by The University of Texas at Austin. This FEED is unique in providing more public cost details than other FEEDs funded by DOE. The primary objective of the FEED was to provide a comprehensive estimate for the total installed cost of the capture plant. The estimated capital cost of NGCC at the Mustang Station is $727 million for a capacity of 460 MW and 1.6 million tonnes CO2/yr. This includes a contingency of $104.6 million and a contractor's profit of $60.1 million. The total direct field cost is $384.1 million. With an optimistic fuel value of $3/MMBtu, the estimated cost of capture varies from $85/t at 4 % IRR/85 % load to $170/t at 10 % IRR/52 % load. Air cooling is technically feasible but expensive. The air cooling systems for the water wash and pump-around intercooling account for 23.4 % of the direct cost. The gas-fired boilers represent only 4 % of the direct costs, but steam extraction would reduce energy cost, free up cooling water, and reduce the direct costs of processing additional flue gas and CO2 from the boilers. The absorbers represent 9.6 % of the direct cost in this FEED with no direct contact cooler and only 7.6 m of packing. The solvent cross exchangers are less expensive than expected (2.5 % of direct costs). Doubling the number of these exchangers could reduce the heat duty from 3.0 to 2.5 GJ/t CO2.

Building the world's largest Chemical Looping Combustion (CLC) unit

The world's largest Chemical Looping Combustion (CLC) demonstration unit is being built close to the city of Chengdu in China. The design and construction of the unit, as well as the coming testing, is done within the CHEERS project, which is a collaborative project between Europe and China. The funding (∼25M€) comes from several of the project partners, in addition to EU's Horizon2020 and China's Ministry of Science and Technology (MOST). TotalEnergies has been responsible for the Front-End Engineering Design (FEED) study. The investment decision from December 2021 marks the transition from the R&D studies and design phases to Engineering, Procurement, Construction (EPC) and testing phase. The EPC phase has been led by Dongfang Boiler Co.,Ltd, and the demonstration unit is located at their technology development site in Deyang City, outside Chengdu in China. It is designed for a thermal input of 2–4 MW and includes two different reactor configurations. The first configuration is optimized for conversion of pet-coke, while the second one is tuned towards conversion of lignite. The oxygen carrier (OC) that will be used for the demonstration unit (ilmenite) will be presented, together with an overview of the various OC materials that were tested at various scales (up to 150 kWth) during the first part of the project. In addition, results from testing of a cold mock-up of the unit is presented. Finally, an overview of plans for the rest of the project is given, together with some thoughts related to intercontinental collaboration in highly collaborative projects, such as CHEERS.

Support for Sustainable Planning

: Intelligent energy management is getting increasingly important for the operation of industrial processes in a globalized world and this trend is expected to continue in the future. This article shows that energy management systems will also be increasingly important for sustainable investment planning such as building or extending a site or plant. Typical investment support methods range from simple spreadsheet-based tools to accurate but resource-intensive simulation studies. However, there is often a need to compare many alternative scenarios quickly to narrow the search space early. Hence, the expectation is not to achieve the level of accuracy of comprehensive studies. Instead, the task is to be as accurate as possible using the limited data available during preliminary frontend engineering and design (preFEED). To address this challenge, a framework was developed that provides more accurate investment decisions by integrating operational aspects in the planning phase. By this, a significant increase in accuracy can be achieved, while obtaining tangible recommendations within acceptabe time. We outline the principal functionality of this framework and share our insights by means of case studies in three different industrial application domains. Finally, we describe the faced challenges and share some lessons learned.

Wave Energy Converters Hold Key to Using Renewables for Subsea Power

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210910, “Innovative Industry Lead Project for Renewables for Subsea Power,” by Ian R. Crossland, SPE, Mocean Energy; Paul Slorach, Verlume; and Andrea Caio, Mocean Energy, et al. The paper has not been peer reviewed. _ The levels of power required to operate an offshore oil and gas field with 100% renewable energy are such that even offshore wind is unlikely to cost-effectively provide the levels of uptime needed to maintain reliable production without some form of energy storage. Providing a combination of technologies to maintain a balanced renewable energy supply system is key. In the complete paper, the authors focus on the use of wave energy converters (WECs), in combination with energy storage, to deliver benefits when powering offshore assets in situ, especially when continuous power requirements are in the 10–100 kW range. Introduction In 2020, a UK industry collaborative project, Renewables for Subsea Power (RSP), was launched and co-funded by the Net Zero Technology Centre. RSP is a phased demonstration project involving three technology developers (Mocean Energy, Verlume, and Modus), a first-tier international services company (Baker Hughes), and a major North Sea operator (Harbour Energy). Given the focus on ramping up the energy transition, in 2022 another major North Sea operator (Serica Energy) and an autonomous resident vehicle supplier (Transmark Subsea), who replaced Modus, also joined the project as part of the final phase (Phase 3) of activities. RSP aims to develop a complete, fully integrated system for the provision of the following: - Low-carbon remote power and communications using a WEC as the effective power source - A subsea energy-storage system for power conditioning - Smooth and uninterruptable power delivery to subsea production control systems - Residential underwater vehicles for a variety of monitoring or maintenance activities Throughout the three phases of RSP, project partners will design, build, and test all elements of the combined system. Phase 1 consisted of a front-end engineering design (FEED) successfully completed in 2021. Phase 2 involved the building and onshore commissioning of various subsystems. Phase 3 is planned to culminate in offshore full-system deployment and trials during 2023. Benefits of Wave Energy At a macro level, ocean waves are a highly abundant source of energy. Technically extractable wave energy resources amounted to 5–23% of 2017 global electricity demand, for instance, and approximately seven times that of available tidal resources worldwide. With approximately 40% of the world’s population inhabiting coastal regions, waves also provide a relatively local source of power for many coastal communities and densely populated areas. As well as being energy-dense and abundant, wave resource is predictable, often days in advance compared with solar and wind. In addition, its daily and seasonal complementarity with other renewables is crucial to achieving a more-balanced grid.

Steady-state Analytical Reservoir Pressure and Temperature Solutions during Hydrogen Refueling to Environment-friendly Ships from Offshore Underground Storage

As hydrogen (H2) conserves intermittent electricity from renewable energies, H2-fueled ships are overlooked for carbon emission reduction. H2-fueled ships require offshore refueling for long-distance shipping routes. At offshore refueling stations, H2 is expected to be generated by renewable energies, stored in depleted offshore reservoirs, and then extracted for refueling. Temperature and pressure variations near the wellbore during H2 extraction impact the severity of hydrogen-induced corrosion. Therefore, it is necessary to conduct hydrothermal analysis for offshore platforms’ front-end engineering design and operation strategy. This paper proposes an analytical reservoir pressure and temperature solution for steady-state offshore H2 extraction from depleted reservoirs for refueling. We derive the radial analytical solution for a two-phase flow (water-H2) and validate them with a numerical model. We apply the derived solution to sensitivity analysis with respect to water depth, reservoir depth, H2 saturation, permeability, reservoir thickness, and total extraction rate. Due to the negative water thermal gradient, deep water depth leads to pressurization and cooling near the wellbore. Critical H2 saturation is derived as a criterion of transition between Joule-Thomson heating and cooling. The higher flow mobility of H2 ensures less depressurization during extraction than water. Higher H2 saturation over the critical saturation causes less cooling due to the decreasing pressure gradient.

Lessons Learned: Comparing Two Detailed Capital Cost Estimates for Carbon Capture by Amine Scrubbing

Two front-end engineering designs (FEED) for commercial-scale carbon capture from natural gas combined-cycle (NGCC) power plants have been published in full, including detailed capital cost estimates. The two studies are the Piperazine with the Advanced Stripper (PZAS) FEED at Mustang Station in Denver City, TX, U.S.A. (“Mustang FEED”) and the FEED at Panda Sherman Power Station in Sherman, TX, U.S.A. (“Panda FEED”). The design capacities are 197 tonne/h of CO2 captured in the Mustang FEED and 129 tonne/h in the Panda FEED. This work compares both designs with the aim of gaining insight about the cost of carbon capture processes. Direct field costs for each process are adjusted to account for differences in the estimating methodology in each FEED. This adjustment results in estimated direct field costs of $574MM for Mustang and $411MM for Panda. The breakdowns of capital costs for each process area are compared, to highlight differences in costs due to the respective processes or particular requirements of each host power plant. A key finding is that site-specific factors not typically represented in less rigorous cost estimates are observed to have a significant impact on cost. To compare both estimates on a similar design basis, the Mustang unit was scaled to the Panda FEED design capacity, resulting in direct field costs of $489MM for Mustang and $411MM for Panda. Additionally, the cost estimates of the CO2 absorbers are analyzed in greater detail to directly compare three equivalent designs that include rectangular and cylindrical absorber columns. Adjusting the absorber estimates to the same scope and scaling to the same size results in estimated costs of $19.7MM, $18.2MM, and $14.9MM, with the rectangular absorber being approximately 10% to 30% more expensive than the cylindrical designs.

Comments: Pore Space Dealmaking Picks Up Momentum

Since my column in the September 2022 JPT about the regulation of ownership and leasing of pore space, dealmaking has picked up steam, especially by Oxy. Many of the announced deals by Oxy and others are in Texas and in the Gulf Coast region. Oxy Low Carbon Ventures (OLCV) signed an agreement in October with Natural Resource Partners LP for the evaluation of a potential CO2 sequestration hub in Texas. OLCV, a subsidiary of Occidental, would gain rights to about 65,000 acres of pore space for its development, with the potential to store a minimum of 500 million metric tons of CO2. The proposed site is in proximity to industrial greenhouse-gas emitters and a prime location for Oxy’s 1PointFive’s plans to build a carbon capture and sequestration (CCS) hub, possibly connected to direct air capture (DAC) facilities. Also, in October, Occidental and 1PointFive signed a lease agreement with King Ranch, a privately held agricultural production and resource management company, to support large-scale DAC projects on 106,000 acres in Kleberg County, Texas, with the potential to remove up to 30 million metric tons of CO2 per year. The pores space is estimated to store up to 3 billion metric tons of CO2. In addition to DAC emissions capture, the King Ranch acreage is located near industrial emitters in the Gulf Coast region, including Corpus Christi, where emissions can be captured, transported, and sequestered in the pore space. Each DAC plant in the site is expected to be capable of removing up to 1 million metric tons of CO2 per year, yielding a total capacity of up to 30 million metric tons per year when all facilities are operational. Carbon Engineering (CE) began front-end planning and engineering for the DAC facilities in Kleberg County in October. The first 1-megatonne facility is intended to be replicated into multimillion-tonne deployments. The design is being adapted from the first large-scale, commercial facility to use CE’s DAC technology, which is already under construction in the Texas Permian Basin and is expected to start up in 2024. Founded in the 1853, the 825,000-acre King Ranch holds an iconic legacy in Texas. Now, 170 years later, it may build upon that legacy with technological advances not foreseen in its earlier years. In another Oxy deal in 2022, this one with Weyerhaeuser Co., more than 30,000 acres of pore space will be evaluated and potentially developed for CCS in Livingston Parish, Louisiana. Weyerhaeuser will continue to manage the aboveground acreage as a working forest. Also in Louisiana, Lapis Energy, a CCS developer and operator based in Dallas, completed the lease of over 14,000 acres of carbon pore space rights with a private landowner 20 miles west of New Orleans. Lapis believes the pore space in the area has the potential to store more than 500 million tonnes of industrial CO2 and has begun technical studies to progress a Class VI permit for the area. Lapis plans to be ready to begin injection by 2025. San Antonio-based Ozona CCS LLC has reached a definitive agreement in January with Texas Pacific Land Corp. to lease approximately 5,173 contiguous acres of land to drill one of the first commercial CO2 sequestration wells in the Permian Basin. The company will initially focus on the Permian Basin and the Texas Gulf Coast for CCS projects. Initial anchor customers will include natural gas processing plants and oil and gas operators in the region. The acreage has an estimated initial injection rate of up to 25,000 B/D and an estimated total storage capacity of at least 40 million metric tons of CO2. The target in-service date is in the third quarter of 2024. Rystad Energy’s Audun Martinsen, head of supply chain research, forecast a rise in low-carbon investments by $60 billion in 2023, 10% higher than 2022. Hydrogen and CCUS are expected to see the most significant annual increase, growing 149% and 136%, respectively. Total hydrogen spending will approach $7.8 billion in 2023, while CCUS investments will total about $7.4 billion. She wrote, “The new and relatively tiny market of suppliers exposed to low-carbon, well-related services is forecast to climb 33% this year, driven by geothermal drilling and CO2 injection. Despite the significant increase, investments in this market will only total about $3.7 billion.”

Reimagining Infrastructure Megaproject Delivery: An Australia—New Zealand Perspective

Infrastructure megaprojects are increasing in size and number worldwide. Widespread shortcomings such as cost overruns, delays, litigious threats, and community opposition are now so pervasive there is a clear mandate to rethink the way we plan, deliver, and operate our infrastructure. In this context, we situate this research to understand how megaprojects can be set up for success. Data were collected from responses to a questionnaire survey, interviews, and case studies. The questionnaire was fielded by multiple agencies involved in infrastructure projects, such as engineers, construction organizations, and government delivery agencies. For qualitative insights, we conducted 30 interviews with participants from these agencies and studied cases that successfully implemented the themes identified. The results highlight the three themes with the highest impact in delivering projects successfully: (1) Improved integrated planning, business cases, and front-end engineering design; (2) efficient use of contracts; and (3) strengthening government and political engagement. This research contrasts the literature on megaproject success with data collected from questionnaires, case studies, and interviews. Collecting solutions that have solved issues effectively is an innovative aspect of our methodology, with these findings holding considerable value for ecosystem practitioners. Thus, we contribute by highlighting eight cost-effective, relevant, and efficient ways for reimagining infrastructure megaproject delivery.

ExxonMobil advances Texas hydrogen project

ExxonMobil has awarded the front-end engineering and design contract for a low-carbon hydrogen plant at its Baytown, Texas, petrochemical complex to Technip Energies. The plant will make about 30 million m 3 per day of hydrogen from natural gas. It will capture and store 7 million metric tons (t) per year of carbon dioxide associated with the hydrogen production. Using this low-carbon hydrogen at the complex as fuel will reduce emissions there by 30%. ExxonMobil also aims to make any capture and storage infrastructure it builds available for other local emitters. In 2021, the company unveiled an ambitious plan to build a system in the Houston area to capture and store 100 million t per year of CO 2 from local industrial sites. It expects to make a final investment decision for the Baytown project in 2024 and complete it in 2027 or 2028.

E&P Notes (August 2022)

E&P Notes (August 2022)

Analysing Front-End Engineering and its Libraries and Frameworks in Web

In this period of rapid development, technology and their patterns change on a daily basis and evolve on their own. The Web Consortium has taken the lead in the history of the internet with this evolution. The use of the web platform improves the engagement between the media and the public, and this participatory culture is the ideal method for cultural communication to develop in the future. The transition from a display-type online to an application-type web, as well as the larger contents of public cultural services, will undoubtedly lead to the growth of front-end engineering. Front-end development and libraries such as React, Vue, and Angular, to mention a few, have exploded in popularity as the internet has grown over the previous few decades. Front-end and its frameworks, such as React, Vue, and Angular, to name a few, have undoubtedly made their way into the field of online performance measurement services as the internet has grown over the previous several decades. The conclusions of the study are examined from many angles in this publication. This study will examine the benefits and drawbacks of each framework, and it will conclude with a summary, contributions, and a prediction about the future of front-end development.

Concurrent 10. Presentation for: Unlocking Gippsland reserves with a minimum kit solution – West Barracouta

Presented on Wednesday 18 May: Session 10 The West Barracouta (BTW), field one of the largest proven undeveloped gas fields off the south-eastern Australian coast, commenced production in April 2021. The project was developed by Esso-BHP Gippsland Basin Joint Venture (JV), a 50–50 JV between ExxonMobil’s subsidiary Esso Australia and BHP Petroleum. The BTW gas field is situated ~6 km south west of the existing Barracouta gas field and platform, the first Gippsland Basin Joint Venture platform in Bass Strait. The BTW development involved drilling two subsea production wells, installation of umbilical controls from the existing platform and installation of a ~6 km subsea flowline to connect to existing gas pipeline via a hot tap. The BTW team will share insights on how it: (1) utilised minimum kit solution and verification of existing asset condition; subsea hot tap into operational gas pipeline and re-use of existing platform J-tube to minimise works on and around the Barracouta Platform (including diving work). (2) Managed an Operator first – co-mingled wet gas subsea pipelines while operating in hydrate regions; via detailed water detection metre/software solution, downhole zone isolation and systematic operating guidelines. (3) Leveraged Installation Contractor competitive Front End Engineering and Design (FEED) enabling optimisation of facilities design/execution strategies to align with strengths and maximise overall project value. (4) Leveraged the OneSubsea/Subsea 7 Subsea Integration Alliance and global worldwide network to execute the subsea design (including qualification), manufacture and installation. (5) Utilised the incumbent Engineering, Procurement and Construction (EPC) contractor to integrate the subsea and topsides control systems to support a single operation system linked to the existing to Distributed Control System (DCS). To access the presentation click the link on the right. To read the full paper click here

Unlocking Gippsland reserves with a minimum kit solution – West Barracouta

The West Barracouta (BTW), field one of the largest proven undeveloped gas fields off the south-eastern Australian coast, commenced production in April 2021. The project was developed by Esso-BHP Gippsland Basin Joint Venture (JV), a 50–50 JV between ExxonMobil’s subsidiary Esso Australia and BHP Petroleum. The BTW gas field is situated ~6 km south west of the existing Barracouta gas field and platform, the first Gippsland Basin Joint Venture platform in Bass Strait. The BTW development involved drilling two subsea production wells, installation of umbilical controls from the existing platform and installation of a ~6 km subsea flowline to connect to existing gas pipeline via a hot tap. The BTW team will share insights on how it: (1) utilised minimum kit solution and verification of existing asset condition; subsea hot tap into operational gas pipeline and re-use of existing platform J-tube to minimise works on and around the Barracouta Platform (including diving work). (2) Managed an Operator first – co-mingled wet gas subsea pipelines while operating in hydrate regions; via detailed water detection metre/software solution, downhole zone isolation and systematic operating guidelines. (3) Leveraged Installation Contractor competitive Front End Engineering and Design (FEED) enabling optimisation of facilities design/execution strategies to align with strengths and maximise overall project value. (4) Leveraged the OneSubsea/Subsea 7 Subsea Integration Alliance and global worldwide network to execute the subsea design (including qualification), manufacture and installation. (5) Utilised the incumbent Engineering, Procurement and Construction (EPC) contractor to integrate the subsea and topsides control systems to support a single operation system linked to the existing to Distributed Control System (DCS).

Front-end engineering practice of in-situ MEOR applications

In this paper, the operational experience from an in-situ MEOR application is presented including a general evaluation leading to lessons learned and guidelines for supporting front-end engineering (FEE) of similar applications. The importance of working in a well-integrated team covering various aspects on microbiology, reservoir and operation engineering in all work packages is obvious. Considerable time is needed to align on the terminology and working interaction between science and engineering of various disciplines. A general breakdown structure that can be applied in MEOR projects is presented. An update of screening criteria is proposed and emphasis on minimum sulfate content in formation water and on the coexistence of carbonates in reservoir rock is suggested as requirements for successful application of in-situ MEOR. The major risks determined prior to operational phase of the project and their mitigations are discussed in detail. Due to its relevance, higher probability and time-consuming mitigation efforts, the risk of souring is discussed separately and its assessment is summarized based on field data. The details of a surface set-up as well as a logistic concept that can be used in in-situ MEOR operations is presented confirming the easy-to-apply characteristic. A list of the measurements and analyses that can be applied for monitoring of MEOR applications is also provided. MEOR is in general perceived to be a cost-effective EOR method but field experience shows that this impression can be delusive when considering all potential expenses, including R&D and risk mitigation costs in mature/brown fields.

Process design of the piperazine advanced stripper for a 460 MW NGCC

The Texas Carbon Management Program is conducting a Front-End Engineering Design (FEED) for Piperazine with the Advanced Stripper™ (PZAS™) at a natural gas combined cycle power plant in west Texas. This paper presents the design of the advanced stripper system with an emphasis on the selection of packing type, packing height, column diameter, and heat exchanger size, demonstrates the effect of ambient temperature swing on the regeneration energy requirement, and investigates two alternate process configurations that provide better energy performance than PZAS™. The design uses 2 stripper trains, and each train uses two cold cross exchangers, one hot cross exchanger, a stripper column, a CO2 exchanger, and a condenser. Each column consists of two sections of random packing with RSR 2 packing at the top and RSR 3 packing at the bottom, with a total packed height of 7.5 m. The cold exchanger was designed with an NTU of 6, the hot exchanger with an NTU of 2, and the CO2 exchanger with an NTU of 5. At 0.4 rich loading and 0.2 lean loading, this design resulted in a heat duty of 2.85 GJ/tonne CO2. The heat duty can vary up to 3.1 GJ/tonne CO2 due to lower rich loading at higher summer temperature, but the absolute steam requirement is 8–15% lower in the summer.An alternate design, PZAS with hot rich bypass, is proposed, which can reduce the equivalent work of stripping by 1.5–3.5% compared to PZAS at low heat exchanger size, due to a reduction in stripper driving force. Using a hot rich bypass increases the vapor fraction of the total rich bypass stream from 0.3 to 1 mol% compared to using the warm rich bypass, which also contributes to a reduction in lost work in the column. PZAS with hot rich bypass outperforms PZAS in energy requirement below a packing height of 15 m, but fails to do so above 15 m of packing due to a column pinch that results in little change in LMTD of the column. PZAS with hot rich bypass has the potential to minimize capital cost in addition to reducing energy requirement as it requires less packing to strip CO2 than PZAS and requires only one cross exchanger with 8 heat transfer units.