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Collaborating Authors
Well & Reservoir Surveillance and Monitoring
Abstract Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) measurements are technologies which are adding some benefits in the aim to replace or complete traditional logging measurements like noise logging tools (NLT) or production logging tools (PLT). The aim of well integrity interventions using distributed fiber optic sensing (DFOS) is to significantly reduce the duration and the cost of these operations, and to provide additional information in comparison to traditional logging tool. The combination of DAS and DTS can offer both qualitative and quantitative information regarding fluid dynamics in the context of well integrity investigation, as the flow characteristics (intensity of turbulences). In addition to acoustic (high frequency DAS) and temperature (DTS) monitoring for leak detection, we propose to use DTGS (Distributed Temperature Gradient Sensing) with low frequency DAS (< 1 Hz) to monitor leaks on the completion tubing of a well. The main advantage of using DTGS with DAS is its sensitivity to small leaks, including the direction of propagation of the leak.
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying (0.68)
- Well Completion (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract The emergence of "big data" has encouraged the utilization of data from various origins to enhance the decision-making process. Unfortunately, multiphase flow studies are often performed in "silos" – within which specific experiments were performed and based on which certain model improvements were proposed. As such, it is easy to lose sight of the big picture of where we are in terms of our understanding and modeling capability. This disconnected approach has also produced an ever-growing, potentially unmanageable list of closure relationships, which can be counter-productive for model development. In this paper, we present exploratory data analyses to comprehensively evaluate the performance of a steady-state multiphase flow point model in predicting high-pressure near-horizontal data from independent experiments. This effort provides wide-ranging hindsight that can reflect the current state-of-the-art of multiphase flow modeling and pinpoint areas where improvements are needed. First, relevant multiphase flow datasets from the literature are collected. In this paper, we limited the scope to near-horizontal and high-pressure data (gas density of 5 kg/m or higher). Then, we run a state-of-the-art model and compare its prediction against these datasets. Multidimensional discrepancy plots are presented to map the models’ performance for pressure drop and holdup predictions across the selected scaling variables. Violin plots are used to identify and analyze the outliers with respect to modeling errors. Confusion matrices are used to quantitatively analyze the model performance in predicting flow patterns, eliminating the restriction of traditional flow pattern map analysis that is limited to qualitative assessment at constant pipe and fluid properties. Finally, the accuracies of key closure relationships are also evaluated. The multidimensional discrepancy plots highlight the conditions where the model performs poorly: low-liquid loading upward flow, downward flow, and high gas flow rates. The violin plots enable quick identification of outliers, which can represent both model and measurement deficiencies. The confusion matrix indicates that the transition between stratified and annular flow is very poorly predicted. The misclassification between stratified and intermittent flow comes at a distant second in terms of occurrence frequency; however, it contributes more significantly to the bulk parameters prediction errors. Except for the slug translational velocity, most closure parameters are still poorly predicted. Entrainment fraction deserves special attention given the expected importance of it on the stratified flow model accuracy. The closure relationships for slug characteristics are unable to predict pseudo-slug flow data accurately. This paper presents several Exploratory Data Analysis (EDA) techniques that enable comprehensive analyses of several independent datasets from various origins. The analyses provide actionable and more general insights that would be otherwise obscured if individual datasets are analyzed in silos, such as operating conditions where higher uncertainty margins need to be applied and where further modeling improvements are desirable.
- Europe (1.00)
- North America > United States > Texas (0.67)
- Overview > Innovation (0.48)
- Research Report > New Finding (0.46)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
A New Hybrid Data-Driven and Model-Based Methodology for Improved Short-Term Production Forecasting
Ferreira, Vitor Hugo de Sousa (Unicamp) | Castro, Manuel (Unicamp) | Moura, Renato (Unicamp) | Werneck, Rafael de Oliveira (Unicamp) | Zampieri, Marcelo Ferreira (Unicamp) | Gonçalves, Maiara Moreira (Unicamp) | Linares, Oscar (Unicamp) | Salavati, Soroor (Unicamp) | Lusquino Filho, Leopoldo Andre Dutra (Unesp/Unicamp) | Ribeiro Mendes Júnior, Pedro (Unicamp) | Mello Ferreira, Alexandre (Unicamp) | Davolio, Alessandra (Unicamp) | Schiozer, Denis Jose (Unicamp) | Rocha, Anderson (Unicamp)
Abstract Model-based (MB) solutions are widely used in reservoir management and production forecasting throughout the life-cycle of oil fields. However, such approaches are not often used for short-term (up to six months) forecasting due to the immediate-term productivity missmatch and the large number of models required to honor uncertainties. Recently developed data-driven (DD) techniques have shown promising performance in immediate term forecasting (from days to months) while losing performance as the timeframe increases. This work, proposes and investigates a hybrid methodology (HM) that combines MB and DD techniques focusing on improving the short-term production forecast. A common practice in reservoir management to understand the impact of uncertainties, is to build an ensemble of simulation model scenarios to assess the impact of these uncertainties on production forecasts. The proposed HM relies on the DD-assisted selection of a subset of models from the set of assimilated (posterior) models. Specifically, the pool of MB models is ranked based on their similarities to the DD production forecasts in the immediate term (e.g., one month), followed by the selection of the top models. The selected MB models are then used in the short-term forecasting task. In a case study for an offshore pre-salt reservoir benchmark, the proposed HM is compared to two baselines: one purely DD and another fully MB. The case study considered two forecasting conditions: human intervention-free with restrictions (HIF-R), with no intervention in the controls except to follow physical restrictions, and with human interventions (WHI), following optimization rules. Our results showed that the HM significantly outperformed the MB baseline, regardless of forecasting condition (HIF-R and WHI) or variables (pressure and oil/water/gas rates) for all evaluation metrics (time series similarity and rank-based) and top-selected models tested. The hybrid approach also helped improve the well productivity uncertainty that emerged from the data assimilation. Such results indicate that the performance of MB short-term forecasts can be enhanced when assisted by DD techniques, such as in our proposed HM. Comparing these two approaches, the best forecasts were split between the HM and the DD baseline. In the partially idealized HIF-R conditions, the DD baseline was best when the forecast trend was steady. However, the HM was superior for the more complex production behaviors. In the more realistic WHI conditions, the HM outperformed the DD baseline in almost every aspect tested given the inability of the chosen DD technique to leverage known interventions. This work is the first effort to improve MB short-term production forecasts, using production data, with a machine learning technique through a proposed HM. The proposed DD-assisted selection of models proved successful in a benchmark case study, which means it is promising for application in other fields and for further development.
- Europe (1.00)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Geology > Geological Subdiscipline (0.46)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Abstract The King's Quay facility was fabricated and commissioned in South Korea and installed in the Gulf of Mexico to receive production from the Khaleesi, Mormont and Samurai fields. A mixture of project and operations personnel were tasked with executing deliverables to ensure a successful progression from engineering, construction, commissioning and operations to ultimately achieve first oil in April 2022. The facility design was based on an existing design already under operation, with modifications limited to improving safety and reliability and reducing emissions. The subsea umbilicals, risers and flowlines (SURF) contract was awarded to include mooring and installation work, minimizing interfaces and reducing risk exposure to the operator. Technical functions fell under one project delivery team, ensuring decisions were made based on the overall benefit to the project rather than individual disciplines. Operations were involved early on during the construction phase in South Korea, and took ownership to integrate improvements throughout the project lifecycle. Subsurface design allowed for a shift from single zone to commingled production to maximize net present value (NPV) and reduce well design complexity. SURF components were standardized as much as possible across all three fields to allow for flexibility during the installation phase. Between the on-site construction team and a strong cohort of local inspectors, the facility left the shipyard on schedule and 97% complete, with minimal carry-over work in the Gulf of Mexico, and over 3.5 million work hours without a lost time incident. With the project team relying on industry-standard designs and best practices, they were able to optimize cost, schedule and functionality based on fit-for-purpose equipment designs. The flexibility of installation allowed the minimizing of simultaneous operations (SIMOPS) between pipelay and drilling activities. In the event of SIMOPS, communication protocols were established and strictly followed, minimizing non-productive time. Murphy's King's Quay development achieved first oil in April 2022, less than three years after the project's final investment decision (FID). This paper will highlight the execution plan and lessons learned to maintain continuity through all phases of the project to deliver a facility and subsea infrastructure ahead of schedule while achieving 97% uptime, with production rates exceeding expectations within six months of start-up.
- North America > United States > Gulf of Mexico > Central GOM (0.66)
- North America > United States > Texas (0.46)
- Transportation (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.47)
- North America > United States > Texas > Permian Basin > Fields Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 478 > Mormont Field (0.94)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 432 > Samuri Field (0.94)
- (2 more...)
- Well Completion > Completion Installation and Operations (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Management > Strategic Planning and Management > Project management (1.00)
- (7 more...)
Abstract This paper describes the implementation of phased start-up and operating strategies to achieve safe and expedited production resumption from Field B after an incident that caused damaged production facilities due to the collision of a marine vessel with an interconnecting bridge between platforms. Phased facility modification plans were implemented to gradually remove constraints and bring production facilities back online. The start-up and operating strategy were tailored to constraints and available production facilities at each phase. Phase 1, achieved through minimal facilities modification, leveraged on the availability of natural-flowing high-pressure gas wells as gaslift source to gas-lifted wells. Phase 2, with further facilities modification, resumed normal gaslift supply from gaslift compressor. Installation of flexible pipes in place of damaged piping brought about the flexibility of gas tapping from vicinity field for start-up purpose. The same flexible pipes were used to enable gas and additional liquid export. Utilization of pipeline line-pack volume as gaslift compressor start-up feed and fuel gas source was available as alternative Phase 2 start-up strategy. Phase 1 start-up was achieved within 45 days and operational for 120 days, recovering on average 1.3KBD of oil production. The introduction of a warm-up sequence effectively mitigated hydrate formation risk. Formulation of a robust crude oil transfer pump control strategy allowed the pump to operate in stable region despite low flow. Subsequent implementation of Phase 2 concept, which was operational for 490days, brought online 3MMSCFD of gas sales and 8.9KBD (a further 54% of Field B nominal oil production rate). Implementation of enhanced process monitoring, control, and safeguarding measures mitigated risk with high flowrate of HP gas through flexible pipe. Flexible pipes were also successfully deployed to evacuate crude production and process drain liquid to export lines. Through comprehensive hazard analysis and Management-of-Change (MOC) program, execution of facilities modification work, start-up, and operating the facilities under abnormal condition were safely accomplished, alleviating production deferment impact due to the incident. The approach as described in this paper would provide a good case study for other facilities constrained by similar issues and how the associated risk can be effectively mitigated.
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design (1.00)
Integration of Petroleum Technologies for the Economic Monetization of Small Offshore Fields
Yan, Lai Wai (Petronas Malaysia Petroleum Management) | Gupta, Mukesh (Petronas Malaysia Petroleum Management) | Tajuddin, Nazim Musani (Petronas Malaysia Petroleum Management) | M Diah, M Amri B (Petronas Malaysia Petroleum Management) | Shah, Jamari M (Petronas Malaysia Petroleum Management) | Masoudi, Rahim (Petronas Malaysia Petroleum Management) | Mokhtar, Syahrini Bt (Petronas Malaysia Petroleum Management)
Abstract This paper entails the profitable development of an offshore small oil reservoir. Offshore technologies are expensive and require higher capital expenditures (CAPEX) and operating expenses (OPEX) due to the need for advanced technologies for drilling, production, and environmental protection. Generally, reservoirs with large reserves are considered for large capital investments. However, this paper demonstrates how accurate reservoir description in conjunction with advanced offshore technologies can help to develop small offshore fields economically. These technologies are deployed in an integrated manner (surface and subsurface) to develop such fields. Offshore logistics for production facility maintenance increases the OPEX due to the transportation of personnel and equipment to and from the site. Offshore production systems have higher CAPEX due to specialised offshore equipment, including sub-sea equipment. Other than higher costs, the oil price volatility makes it difficult to plan for long-term production to recover the cost. Therefore, offshore fields have several challenges, e.g., logistical, technical, environmental, economic, and safety. However, collaborations and partnerships between industry and government help to share the project's economic risk. Cost can be further reduced through new development, production, and reservoir characterisation technologies to manage offshore development and operations costs. Production is enhanced through advancement in well construction and production systems to support high OPEX of floating production, storage, and offloading system.
- Asia (0.71)
- North America > United States (0.29)
- Oceania > Australia (0.28)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Europe > Norway > North Sea > Central North Sea > Egersund Basin > PL 407 > Block 17/12 > Vette Field > Zechstein Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Egersund Basin > PL 407 > Block 17/12 > Vette Field > Skagerrak Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Egersund Basin > PL 407 > Block 17/12 > Vette Field > Sandnes Formation (0.99)
- (8 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (4 more...)
Injection Enhancement in a Deep-Water Gulf of Mexico Multi Zone Completion Enabled by Downhole Multi-Position Flow Valves
Smith, Kevin (Talos Energy) | Esquitin, Yosafat (Welltec Inc) | Cone, Ryan (Talos Energy) | Fürstnow, Mette (Welltec A/S) | Hazel, Paul (Welltec A/S) | Kumar, Satish (Welltec A/S)
Abstract The Deep-Water (DW) Gulf of Mexico (GOM) fields have a complex mix of multi-layered reservoirs, with thicknesses and rock properties which can widely differ from layer to layer within the same reservoir. Injection of 25,000 bpd of water from a shallower aquifer B4 sand via a dump flood technique, benefited from a variable and controlled zonal distribution of the injection into two separate layers connected to the producer B6 Sands over life of well. This paper presents the modelling performed to achieve optimal choke selection, specified distributions, job execution and results of utilizing multi-position flow valves as part of the 3 ½" completion with the objective of achieving the optimal injection rates in the upper and lower layers of the BB Sands. Design parameters considered critical by Talos included a controlled and variable distribution of the injection via dump flood of 50%/50% or 25%/75% respectively for the upper and lower layer of the producer B6 Sands, with the option to selective shut-off one of the layers over time, while maintaining the 3 ½" full-bore inner diameter for future interventions. Discussed within this paper : The selection process to meet the required distribution rates with the extensive modelling performed using modeling software for the choke size selection, quantity, and distribution in each of the three open positions of the multi-position flow valve to achieve the total flow area required to distribute the injection at the desired rate in each layer of the producer sand, and CFD (Computational Fluid Dynamics) for the choke design. Field data from the first installment of two multi-position flow valves in a well located in the Tornado project, operational considerations that enabled the manipulation of the flow valves and a summary of the achieved results will be presented and explained. This is the first deployment for the multi-position flow valve with variable chokes in the deep-water Gulf of Mexico well environment. The solution provided controlled injection with variable rates into the two upper and lower producer sands, this technique enables a cost-effective and reliable proven solution which can be applicable to any type of injector well, with the goal to increase the overall NPV of the field, through the increased recoverable using a predictable and safer method of downhole flow control.
- North America > United States (1.00)
- North America > Mexico (0.81)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.33)
Abstract The paper focuses on the field life cycle and how new technology (including digital) and proactive, collaborative workflows can significantly optimize a field's production, with a focus on Brazil. Specifically, we discuss how, in the presalt, it is important to monitor casing integrity to identify salt creep and deformation as soon as possible. Proactive early identification of issues can accelerate the plugging and abandonment (P&A) decision at a stage where costs are reduced by avoidance of a more complex P&A caused by deformation of major completion components. Considering the complexity of a deepwater intervention, an innovative approach of through-tubing well surveillance was implemented, based on the third interface echo measurement provided by an advanced ultrasonic tool. The technique was deployed in some wells where the casing stress analysis indicated there was a risk of collapse, providing valuable information about casing and tubing integrity, as well as precise identification of annulus content. The paper intends to present local examples of the logs run, collaboration among technical experts, and the decisions made. The scope extends beyond the initial production period to maximizing production, when it is necessary to consider production issues as well as well integrity issues. The paper proposes that conventional KPIs may not measure the real intervention performance and can indeed detract from an optimal outcome. Most of the wells assessed were found with their integrity preserved, and therefore the production and/or injection, could continue. Where integrity issues were identified, the data gathered were used to redefine the intervention, allowing a safe temporary well suspension, assertive P&A planning, reducing the uncertainties, and facilitating communication with the regulatory agency. The paper will then discuss, during the barrel chasing phase of the field's life, how a better, collaborative alignment of the interests of all shareholders to the outcome of increased production can be achieved. Case studies reflect application of the technique in Brazil. The study demonstrates how to achieve the optimized field life cycle. New technology, including advanced digital workflows, has been applied to the challenge of well integrity assessment to examine casing deformation in Brazil. This has proven extremely important in early identification of issues to enable the most cost-effective remediation. New collaborative workflows initiated after well integrity optimization optimize production from existing well infrastructure to extend the field life cycle.
- South America > Brazil (0.75)
- North America > United States > Texas (0.46)
- Overview > Innovation (0.74)
- Research Report (0.48)
Key Takeaways from Integrated Production Modelling of an Indian Offshore Field Entirely Operating On Electric Submersible Pumps
Devshali, Sagun (Oil & Natural Gas Corporation Ltd.) | Nischal, Rajiv (Oil & Natural Gas Corporation Ltd.) | Prasad, BVRV (Oil & Natural Gas Corporation Ltd.) | Yadav, M (Oil & Natural Gas Corporation Ltd.) | Vamsi, Paipuri (Oil & Natural Gas Corporation Ltd.) | Uniyal, Rishabh (Oil & Natural Gas Corporation Ltd.) | Kumar, Manish (Oil & Natural Gas Corporation Ltd.)
Abstract Field Alpha is situated about 200 km West of Mumbai city in a Deep Continental Shelf at the water depth of 85 - 90 m. The existing facilities consists of 5 Well Head Platforms (WHP) connected to FPSO through a subsea PLEM and riser system. A total of 36 wells from 5 well head platforms in the field are producing 61348 blpd with an average water cut of 68%. All these 36 wells are producing through Electric Submersible Pump which is one of the most effective and economical means of lifting large volumes of liquid. The current paper is an attempt to address various issues pertaining to Electrical Submersible Pumps in the offshore field using well wise Nodal Analysis and Integrated Production Modelling. In the field under study, as the production volumes per well are high, failure of even one ESP leads to substantial production loss till the system is replaced by work over operation. Failure in the ESP system generally occurs due to one or a combination of issues related to reservoir inflow, fluid properties, design, completion, electrical components and experience of manpower. On the basis of system analysis, requisite optimization/ intervention measures proposed to improve performance of ESPs along with network debottlenecking results have been discussed in the paper. As per the analysis, scope exists in 7 wells for production enhancement. The envisaged incremental production from these wells has been found to be 1653 blpd considering current reservoir pressure and water cut. In 7 wells, ESPs have been found to be operating either in upthrust or are tending towards upthrust. These wells have potential to produce more but due to limitations of the existing pump capacities, the maximum drawdown is restricted. In 6 wells, ESPs have been found to be operating in downthrust. These wells have separately been assessed for wellbore performance. Additionally, Integrated Production Modelling indicated that the node pressure at each Well Head Platform are within the ESP design pressure limits. On the basis of the study, few of the recommended measures have already been implemented in the field and have resulted in a liquid gain of 335 blpd (139 bopd).
- North America > United States > Louisiana (0.35)
- Europe > United Kingdom > North Sea > Central North Sea (0.35)
- Europe > Norway > North Sea > Central North Sea (0.35)
- (2 more...)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/18a > Alpha Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 15/8 > Alpha Field (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > Block 16/18a > Alpha Field (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > Block 15/8 > Alpha Field (0.99)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
Abstract Subsea control systems utilize electric and/or optical communication channels within subsea optical distribution systems for redundant, duplex telemetry between topside facilities and subsea control systems. Downhole fiber optic sensing (DFOS) systems utilize the same subsea optical distribution systems for establishing transmission paths between the same topside facilities and downhole sensing fibers. To date, subsea fiber optic control and sensing systems have been operated on independent subsea optical distribution systems. This redundancy introduces complexity and cost into the overall subsea optical distribution system required for subsea developments. We describe the systems that combine fiber optic communications for subsea control systems and downhole fiber optic sensing systems into the same subsea optical distribution system. This enables simultaneous operation of communications between the topsides and subsea control module, and the topside interrogation of multiple downhole fiber optic sensors while preserving dry-tree equivalent sensing performance.
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Controls and umbilicals (1.00)