_ Hydraulic fracturing execution has historically relied on surface treating pressure as the primary information source for evaluating a stage. However, treating pressure is a composite signal that blends pipe friction and perforation friction, limiting its usefulness for diagnosing the underlying drivers of performance changes. As a result, operators can see that a change has occurred, but not why it occurred or how fluid is distributed across clusters. This lack of subsurface visibility means that inefficiencies in cluster utilization are often recognized only after the treatment (i.e., through production data or post-job diagnostics) when the opportunity to take corrective action has already passed. To address this limitation, high-frequency pressure data is used to deconvolute downhole effects in real time, enabling a closed-loop, measurement-driven fracturing workflow (Fig. 1). Acoustic friction analysis (AFA) uses high-frequency pressure during pumping to quantify key metrics, including perforation efficiency and uniformity index (UI) (URTEC 4044703). By separating and quantifying the friction components driving stage behavior, the workflow avoids relying on aggregate surface pressure trends as a proxy for subsurface response. These quantified outputs support a physics-based artificial intelligence (AI) approach that combines acoustic modeling with predefined decision logic to translate friction response into actionable stage-level recommendations, enabling operators to move beyond surface-based interpretation and make decisions based on measured subsurface behavior. In this context, physics-based AI is anchored to measurement rather than used as a substitute for it. High-frequency pressure response is used to quantify perforation friction, perforation efficiency, and flow distribution, while AI supports interpretation and decision logic. This distinction is important because purely data-driven models rely on historical patterns, which may not represent outlier stages or changing downhole conditions. Using Direct Measurements Because these outputs are available while pumping, decision criteria can be established to guide execution (Fig. 2). Perforation efficiency and UI thresholds are used to flag performance degradation or emerging issues in real time. These alerts trigger targeted adjustments, such as modifying rate, proppant concentration, or fluid system, deploying diverters, or reallocating volumes, which can be implemented immediately. This shifts fracturing operations from a reactive process to one where execution is continuously evaluated and optimized as each stage progresses (SPE 230647). Applying this in the field has shown that real-time insights can be used to identify optimal flow-velocity ranges, refine proppant ramp strategies, and dynamically redistribute volumes away from ineffective stages. Importantly, these improvements can be achieved without increasing total fluid or proppant volumes. Instead, resources can be deployed more effectively, based on immediate feedback. This represents a shift toward volume-neutral gains in stimulation efficacy and more consistent cluster utilization across stages. This case study describes the first field deployment of this workflow, where live AFA outputs were used to evaluate perforation efficiency and trigger logic-driven interventions based on predefined evaluation points and performance thresholds. The objective was to demonstrate how threshold-based responses can limit efficiency degradation within a stage and improve overall execution consistency, providing a scalable framework for measurement-driven fracturing.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 230941, “Establishing a Blueprint for Dynamic Reservoir Assessment in CCUS Projects,” by Mahmut Sarili, SPE, and Adam Donald, SLB, and Aurifullah Vantala, ADNOC, et al. The paper has not been peer-reviewed. _ The effectiveness of carbon capture, utilization, and storage (CCUS) operations relies on precise in‑situ rock and stress characterization for secure and efficient CO2 storage. Identifying, characterizing, and selecting suitable sites for CO2 geological storage necessitates comprehensive evaluation techniques to determine optimal locations for safe and long‑term carbon containment. By integrating petrophysics, geology, geomechanics, and reservoir engineering, precise in‑situ stress measurements were acquired for two of the operator’s wells, successfully characterizing caprock integrity and reservoir injectivity and creating a blueprint for future CCUS evaluations. Background The operator has drilled and evaluated two separate CCUS wells as part of the UAE’s strategic aim of having net‑zero emissions by 2050. These wells seek to describe the in‑situ geomechanical, petrophysical, and hydrodynamic features of potential storage deposits. In this study, the stress behavior and sealing efficiency of target formations were assessed through downhole testing integrated with formation pressure and fluid sampling. The resulting data set enabled robust calibration of a mechanical Earth model (MEM) and supported the development of operational frameworks for future CO2‑injection initiatives. The testing highlighted in this paper, which the authors refer to as MicroFrac, is a refined technique that induces and monitors local fractures within the subsurface, facilitating direct measurement of minimum in‑situ stress. It can be performed using wireline or pipe‑ conveyed modular formation dynamics testers (MDT), offering safe, quick, and cost‑effective acquisition of stress data at different depths. The MDT‑based MicroFrac platform provides real‑time monitoring of fracture events through comprehensive pressure diagnostics, maintains accurate pressure management using high‑ pressure pump modules, and isolates formation intervals using a dual‑packer system. The first well’s testing operations focused on the anhydrite caprock to assess its capacity for fracture initiation and sealing performance. The campaign involved two runs, one for formation‑fluid sampling and pressure measurement, and another dedicated to the featured testing. A total of three test sets were conducted wherein fracture initiation and closure were monitored; breakdown pressure data were recorded at two stations, while packer differential‑ pressure threshold was reached on one station without fracture occurrence. For closure‑pressure evaluation, a controlled forced‑closure‑flowback approach was used. Multiple injection and falloff cycles were conducted at each station. Formation microimager (FMI) logs were captured pre‑ and post‑test to validate induced fractures. In the second well, the scope was broadened to deliver a full mechanical profile across both 8.5‑ and 6‑in. borehole sections. Four MDT runs were completed in the 8.5‑in. section, including fluid sampling with an in‑situ fluid analyzer (IFA) for real‑time fluid analysis. The testing program encompassed 16 test stations, 10 in the 8.5‑in. and six in the 6‑in. section distributed over a several‑thousand‑foot vertical interval. This comprehensive spatial coverage enabled assessment of stress variation and lithological influence essential for future injection design and MEM refinement. The testing process for the 8.5‑in. section involved several injection/falloff cycles, combining natural and forced closures, and a step‑rate test that was performed to confirm stress parameters. Closure pressures obtained by G‑function and square‑root‑of‑time (SQRT) analyses showed good correlation across methods. Pre‑ and post‑test FMI imagery affirmed the creation of induced fractures, confirming method effectiveness.
_ The selected papers for this year’s feature collectively illustrate a clear industry transition toward subsea-centric architectures that decouple production performance from topside constraints, combining processing, boosting, and simplified system designs adapted to specific field conditions. Paper 231579 highlights the growing maturity of subsea seawater-treatment and -injection systems, enabling operators to relocate water processing to the seabed and significantly improve reservoir sweep efficiency. By ensuring consistent injection capacity and tailoring water chemistry, these systems unlock additional recovery while overcoming persistent topside limitations such as space, weight, and reliability constraints. Paper OTC 36841 demonstrates full-scale implementation of subsea boosting in a high-viscosity deepwater environment, providing compelling evidence that subsea multiphase pumping is now a proven enabler for both new developments and brownfield optimization. The reuse of existing infrastructure and the integration of digital monitoring mark a shift toward cost-efficient, modular subsea solutions with strong life-cycle performance. Paper OTC 36730 introduces a nontraditional subsea-application domain, where shallow-water constraints drive innovation in system miniaturization, cost optimization, and installation methodology. The successful deployment of compact wellhead and subsea production systems highlights the industry’s increasing ability to adapt subsea technologies beyond deepwater environments, opening new development opportunities. Together, these papers reflect an evolving paradigm wherein subsea systems are no longer supplementary but are central to field-development strategies, with emphasis on modularity, electrification readiness, and integration with reservoir-management objectives. The papers recommended for additional reading provide complementary perspectives, focusing on subsea processing integration, technology maturity, and the digitalization frontier. Paper OTC 36288 presents the next phase of subsea processing evolution: fully integrated oil/water separation and produced-water treatment at the seabed. The transition from component qualification to integrated testing demonstrates the industry’s progress toward industrial-scale deployment, particularly for brownfield optimization and long tieback developments, where reducing topside load is critical. Paper SPE 231738 offers a consolidated view of two decades of subsea separation development, capturing key lessons from projects such as Troll and Tordis. The analysis confirms that, while subsea separation has proven its capability to enhance recovery and reduce topside bottlenecks, system integration, reliability, and long-term operability remain critical success factors. This provides important context for ongoing innovation. Paper OTC 36761 expands the technology landscape into subsea digital infrastructure, integrating power harvesting, wireless communication, and autonomous systems. The concept of wave-powered subsea Internet of Things represents a significant shift toward wireless, autonomous subsea operations, addressing long-standing constraints related to umbilical dependency. While still emerging, the integration of energy, communication, and robotics signals a future where subsea assets will operate with greater autonomy and reduced human intervention. Collectively, these papers indicate that the subsea domain is evolving along two parallel paths: deepening core processing and boosting capabilities while advancing toward digitally enabled, autonomous subsea ecosystems. Summarized Papers in This August 2026 Issue SPE 231579 - Recovery Improved by Subsea Sulfate Removal and Low-Salinity Water Injection by Ojonimi S. Haruna, SPE, and Bruno C. Kahn, NOV OTC 36841 - Multiphase Pump Solution Deployed in World’s Deepest Subsea Heavy Oil Field by Marcelo Paulino and Henrique S. Cerqueira, SPE, Brava Energia, and Christophe Vielliard, SPE, SLB OneSubsea, et al. OTC 36730 - Novel Subsea Production System Reduces Costs, Heightens Efficiency in China’s Bohai Bay by Tao Xie, SPE, State Key Laboratory of Offshore Oil and Gas Exploitation, CNOOC, and China University of Petroleum-Beijing, and Lei Zhang and Qilong Zhang, State Key Laboratory of Offshore Oil and Gas Exploitation and CNOOC, et al. Recommended Additional Reading at OnePetro: www.onepetro.org. OTC 36288 - Demonstration of Integrated Subsea Separation and Produced-Water Treatment by F. Garcia, TotalEnergies, et al. SPE 231738 - Subsea Water/Oil Separation Systems: New Technology Perspectives, Consolidated Projects, and Lessons Learned by A.A. Ferreira, University of São Paulo, et al. OTC 36761 - Enabling Subsea Internet of Things Through Power Harvesting, Hybrid Communication, Integrated Sensing, and Resident Autonomous Underwater Vehicles by Hosam Abu Zeid, Independent Subsea Consultant, et al.
Once reserved for high-end deepwater wells, managed pressure drilling (MPD) has gained a dedicated following in the US land market. Now the same managed pressure techniques that made difficult wells possible and safer to drill are cascading into other aspects of the well-construction process. Managed pressure operations (MPO) enabled the completion of wells at Beacon Offshore Energy’s Shenandoah project, the first 20K-psi project in the Gulf to be operated by an independent, Joseph Leimkuhler, the company’s vice president for external affairs, said during a session at the recent Offshore Technology Conference in Houston. “The margin between the fracture gradient and the rock and pore pressure was so narrow that you could drill it, but getting a cement job is a challenge. We actually went to managed pressure operations,” he said. Applying MPO was “pretty simple in concept but pretty ingenious,” he added, highlighting how Beacon collaborated with the service company and drilling contractor to make it work. Zac Mahlum, Weatherford’s vice president for MPD, told JPT that MPD has historically been used to mitigate drilling risks, initially in complex wells, such as those with narrow pressure-margin windows, to access challenging reservoirs and improve wellbore stability. “Using managed pressure techniques allows us to get closer to that margin window without impacting the wellbore stability, etc. It allows us to get a much more accurate managed pressure cement job, allows us to do a much closer managed pressure gravel pack job. And using managed pressure techniques, you can avoid a lot of the overpressure so you can avoid those fluid losses,” he said. Since their introduction, managed pressure techniques have shifted from niche application to a critical piece of the overall well-construction life cycle, Mahlum said. “It’s still such a new technology that we’re seeing just wide-scale adoption” in both offshore and onshore environments, he said. “About 65%, 70% of all drillships have a deepwater MPD system installed. And with an incredible demand in this space, we’re expecting this to reach a saturation point of 80%, 85% over the next couple of years.” Operator mandates to use MPD in their drilling operations are the driver, he said. And more than 90% of US land operations are using a rotating control device (RCD), a critical component of MPD equipment. “We all know how ruthlessly efficient US land operations are. If there’s a penny to be cut, somebody finds a way to cut that penny,” Mahlum said. “It’s obviously drastically scaled different than a deepwater complex MPD system to a very simple RCD at the rigsite. But it just shows you the value of this technology, what even just an RCD provides to operations.” In short, he said, controlling pressure is critically important. The jackup market represents another opportunity for the uptake of conventional surface managed pressure techniques comprising an RCD, choke manifold, and pressure-control package, as compared to the more complex deepwater MPD, which incorporates riser-based and automated pressure-management technologies.
_ In July, Thailand’s PTTEP announced that it had redeployed a decommissioned wellhead platform, saving time and money while reducing greenhouse gas emissions. The national oil company said it was the first project of its kind in its portfolio and described it as an example of applying circular economy principles, an approach that encourages industrial companies to adopt novel ways to reduce their environmental footprint. The Jakrawan K wellhead platform was relocated to the Funan Field within the Gulf of Thailand, with the original topsides, jacket, and some of the pile sections reused as part of the project. By repurposing the existing platform, PTTEP reduced the combined construction and installation schedule to 6 months, compared with an estimated 20 months for a new platform of similar specifications, representing a 70% reduction in project time. PTTEP also reported that reusing the platform lowered construction costs by 35 to 50% compared with building a new structure from scratch. By avoiding the cutting of new steel, the company estimates the project prevented 3,270 metric tons of carbon dioxide equivalent emissions. Going forward, PTTEP said it expects to reuse up to 10 other wellhead platforms by 2029. All candidates are structurally sound and have passed safety assessments, the company said in a statement. Vestigo Petroleum Sdn Bhd, a wholly owned subsidiary of Petronas, did something very similar in 2019 offshore Malaysia (OTC 30668). The subsidiary created for marginal field developments removed an unmanned wellhead platform from a field where it had produced oil for 3 years and reinstalled it about 34 miles away at the Jitang Field in about 240 ft of water. The platform was then connected to a floating production, storage, and offloading (FPSO) unit located about 1,000 ft away. Vestigo reported that it reached first oil in early 2020, which was a little more than a year after it made a final investment decision, and that the reusable platform reduced development costs by about 40% compared with a newbuild installation. Notably, the facility was transported in a single piece and required only four new flowlines to connect its four new wells. As of 2025, the Jitang platform, which has a total expected service life of at least 15 years, was understood to still be producing oil and gas. US deepwater producer LLOG Exploration also opted to reuse an offshore asset in 2022 when it acquired the floating platform formerly known as the Independence Hub. The facility was originally deployed by Anadarko Petroleum and its partners to develop a gas field in the US Gulf of Mexico, with first production achieved in 2007. After producing 1.3 Tcf of natural gas, operations ceased in 2015, and the facility was decommissioned in 2019. The platform would receive a new lease on life when LLOG acquired the asset in 2022 as part of an initiative to reduce development costs of recently made discoveries in the Leon and Castile fields. After refurbishing work was done at shipyards in Texas and Louisiana, the production platform, renamed Salamanca, was once again put to work in late 2025 in the US Gulf. The operator said reuse of the facility reduced associated emissions by 87% while speeding up time to first production. Initial output from the Salamanca’s two fields was reported at a combined 14,000 BOE/D. LLOG was acquired by UK-based Harbour Energy later in 2025, and the new owner shared plans this year to boost Salamanca’s output by drilling new wells in the two fields it produces from. While the concept of reuse appears attractive for the capital-intensive offshore business, backed by the reported cost savings, shorter project timelines, and emissions reductions, examples of recycling offshore oil and gas infrastructure for greenfields remain few and far between. And there are plenty of reasons why. One of them comes down to timing. As a new offshore development prepares for sanctioning, there must be an idle or soon-to-be decommissioned platform available, and its bespoke specifications and structural condition must be compatible with those required by the untapped development. In the case of floating platforms in the US Gulf, this is often not the case because many older installations have benefited from life-extension programs. Newbuild facilities also offer advantages that often surpass those of older assets. In addition to incorporating designs that meet current regulatory requirements, they are typically equipped with more advanced and efficient technologies. Regulatory requirements regarding decommissioning, asset transfer, and reinstallation can further complicate efforts to relocate and reuse existing platforms. We have, of course, seen the reuse of offshore infrastructure for many years but primarily through rigs-to-reef programs. In these programs, shallow-water platforms are often toppled over on their side or have their topsides removed to a depth safe enough for ships to pass over. In the US Gulf alone there are more than 600 platforms that have been reefed in this manner since the 1980s. Then there are the more novel ideas that have come forward in recent years. Though they were not production platforms, two semisubmersible drilling rigs were bought by SpaceX a few years ago in a since scuttled plan to use them as floating platforms for the launch and retrieval of rockets. In 2021, Saudi Arabia’s Public Investment Fund launched a project called simply “The Rig” to turn a mix of decommissioned oil platforms and newbuild platforms into a sprawling tourism complex with 800 hotel rooms, 11 restaurants, and dozens of theme-park-inspired attractions. It’s unclear where the ambitious project stands today, and its website has not posted an update in 2 years. There has also been plenty of discussion about reusing offshore platforms for renewable energy projects. But these proposals have also gained little traction, and a recent study from the University of Houston-led Repurposing Offshore Infrastructure for Clean Energy (ROICE) program helps explain why. As outlined in a 2024 Offshore Technology Conference paper (OTC 35474), ROICE researchers evaluated whether aging oil and gas platforms could be repurposed for applications such as offshore wind, green hydrogen production, and carbon sequestration as an alternative to full decommissioning. While ultimately optimistic about the concept, the study’s principals also concluded that there are several challenges that must be ironed out. Among them are the aforementioned regulatory requirements governing asset transfers, questions over the allocation of long-term liability, and issues associated with insurance and financial assurance obligations. These are in addition to the technical work required to assess, recertify, and extend the service life of aging infrastructure. Circling back to the upstream arena, despite the apparent obstacles, some still believe opportunities remain to redeploy floating assets. In 2025, Singapore-based consultancy Energy Maritime Associates found 27 floating production assets were available globally. Most of these idle assets were FPSOs. The firm concluded that one-third of the total were unlikely to return to offshore service because of their age and limited capabilities. Another 30% were deemed suitable for redeployment because of their higher specifications and remaining design life, while the remaining 35% were viewed as suited only for marginal field development. The analysis and examples suggest that recycling fixed platforms along with floating units can help lower development costs, albeit on a limited scale. When location, timing, asset condition, and regulatory requirements align, the economic and environmental benefits appear to be a win-win scenario. But the relatively small number of successful projects also suggests that the industry’s ability to give offshore infrastructure a second life has been, and will likely continue to be, the exception rather than the rule. For Further Reading OTC 35474 - Repurposing Offshore Infrastructure for Clean Energy (ROICE) vs. Decommissioning—Regulatory Considerations by E. Keen; B. Gibbs; T. Matthews; L. Feijo; G. Legge; S. Tallavajhula; and R. Seetharam. OTC 30668 - The Reuse of Offshore Wellhead Platform To Facilitate a Marginal Field Development–Vestigo Experience by M.R. Jamil; M. Mustapha; M.G. Othman.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 229390, “Smart Liquid-Unloading IIoT Application for Gas Wells in the Haynesville Basin,” by Agustin Gambaretto, SPE, and Carl J. Kemp, SLB, and Rogelio M. Nunez, SPE, Consultant, et al. The paper has not been peer-reviewed. _ Intermittent wells, particularly in gas-producing basins such as Haynesville, traditionally are managed with manual or partially automated controls, requiring frequent operator intervention and relying on static supervisory-control and data-acquisition (SCADA) infrastructure. This approach limits production efficiency and responsiveness to changing well conditions, especially in the presence of liquid loading. To address these limitations, this paper presents an autonomous, data-driven solution deployed at the edge, designed specifically for intermittent well optimization. Introduction This paper introduces a field-proven Industrial Internet of Things application that manages the liquid-unloading cycle autonomously using a data-driven, edge-based control system. Running directly on a local gateway device at the well site, the application ingests real-time pressure, flow rate, and temperature data continuously. It applies embedded physics-based models and lightweight machine-learning (ML) algorithms to calculate key flow parameters and dynamically adjusts choke settings in a closed-loop manner without requiring cloud connectivity or operator intervention. Building on the architecture successfully deployed in artificial lift applications such as autonomous sucker-rod-pump optimization frameworks that leverage local intelligence to adapt rod-pump control logic without cloud reliance, this solution demonstrates how real-time control logic can be extended to intermittent gas wells to maximize production, minimize downtime, and enable scalable automation. Similar data-driven approaches have shown strong performance in gas lift optimization scenarios, where edge-deployed models adapt to variable flow regimes with minimal human tuning. Methodology Architecture Overview. The smart unloading solution is built around an edge-deployed application running on a rugged field gateway. This device integrates directly with existing wellhead instrumentation (casing pressure, tubing pressure, temperature, flowrate, and choke actuator), requiring no modifications to upstream SCADA or communications infrastructure. The edge application is composed of four tightly integrated layers: - Data-Acquisition Layer: Continuously collects and validates telemetry from the wellhead, including pressure, temperature, and flow-rate sensors. - Calculation Engine: This module computes flow parameters essential to understanding unloading behavior. It applies embedded physics-based models to derive gas velocity, critical velocity, and liquid-column height. These calculations are updated continuously to reflect changing wellbore conditions. - Autonomous Decision Logic: The core control algorithm replaces static calendar-based cycling with real-time, condition-driven logic. It uses calculated parameters to decide autonomously when to shut in the well. Specifically, it monitors gas velocity vs. critical velocity thresholds and estimated liquid level and liquid-accumulation rate. - ML-Based Shut-In Duration Estimation: Instead of applying a fixed shut-in time, the duration is computed dynamically by an ML model that could be deployed at the edge; however, to enhance scalability and agility, it was moved to the cloud. The model predicts the optimal shut-in duration to allow the required pressure recharge to resume effective flow.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 4213943, “Benefits of CO2 Fracturing: Analysis for Sustainable Shale Gas Exploitation in Mexico,” by Carlos Felipe Silva-Escalante, SPE, National Autonomous University of Mexico (UNAM) and the Mexican Petroleum Institute (IMP), and Rodolfo G. Camacho-Velázquez, SPE, and Ana P. Gómora-Figueroa, IMP, et al. The paper has not been peer-reviewed. _ The growing environmental concerns related to water usage in unconventional hydrocarbon extraction necessitate the development of alternative fracturing methods. This work evaluates CO2-based fracturing as a sustainable development approach for shale gas reservoirs in the Burgos Basin of Mexico. The results demonstrate that CO2 fracturing represents both an environmentally sustainable and economically viable alternative to conventional methods for shale reservoir development in water-stressed regions. Introduction The Burgos Basin represents Mexico’s most significant gas resource, with estimated reserves of 421 Tscf of wet gas and 348 Tscf of dry gas. To date, 27 wells have been drilled for unconventional resources in the basin, with estimated initial production rates of 6 MMscf/D and prolonged production decline curves. The typical well configurations include horizontal geometry, slickwater fracturing fluid, white sand 20/40 proppant at concentrations of 1–5 ppg, and between 10–18 fracturing stages. Investment costs range from $5–14 million per well, depending on complexity. A critical challenge facing development in this region is water scarcity in northeastern Mexico, which necessitates waterless fracturing approaches for sustainable exploitation of shale reservoirs. Numerous researchers have explored waterless fracturing alternatives, with CO2 fracturing emerging as a particularly promising option. Beyond addressing water scarcity concerns, CO2 fracturing offers the additional environmental benefit of reducing CO2 emissions through beneficial usage of captured carbon. This study provides an analysis of fracturing propagation and post-closure effectiveness for gas production in a representative Burgos Basin shale reservoir using pure CO2 and industrial CO2 with impurities (CO2-imp) compared with conventional slickwater. Effective geometry and conductive properties of fractures after closure (following flowback) are examined to identify performance-affecting properties and develop production scenarios with reservoir modeling. CO2 fracturing is evaluated as a waterless option for the Burgos Basin based on the proximity of fixed CO2 sources to development zones. Technoeconomic aspects also are examined to determine the viability of CO2 fracturing as an appropriate option for unconventional reservoir exploitation. Methodology Representative well and reservoir models were designed to simulate fracture propagation and post-closure fracture properties and to generate performance and production scenarios using compositional simulators. The simulations compare pure CO2, CO2-imp, and conventional slickwater as fracturing fluids. The CO2-imp composition consists of 95%-mol CO2 with 4% mol N₂ and 1% H₂O, approximating CO2 obtained from post-combustion technology while satisfying desired transportation criteria. This industrial fluid also contains solid impurities from the post-combustion process, which are incorporated into the fracture simulation as spherical proppant with a diameter of 10 μm and an overestimated concentration of 1 ppg for analysis purposes.
The hardest part of petroleum engineering is not the calculations or the inherent uncertainty. It is guarding against cognitive biases. Avoiding bias begins with reliable measurements of appropriate questions, and therein lies the first of two problems with understanding our industry’s methane emissions: The most common measure of methane emissions obscures poor gas-handling performance. The second-biggest problem—availability bias—builds on this misstep to compound our misunderstanding of our industry’s performance by ignoring the bulk of the independent evidence about our performance. Actionable insight—or misdirection—begins with the choice of measurement. Jim Collins’ bestseller, Good to Great, enshrined the now ubiquitous concept of key performance indicators. The measurement must be useful for discriminating better from worse in a way that can affect choices to achieve the goals. In this case, the objective is to reduce significantly methane emissions below historical levels. In Collins’ words, an appropriate measure must show the “brutal truth.” Of course, natural gas is a valuable and useful product with strong, inherent, long-standing incentives against waste. But still, both venting and flaring have persisted at levels detrimental to near-term climate deformation, regulatory risk, and industry credibility. An appropriate measure would highlight where improvements can be made on top of the existing economic and regulatory structures. A measurement of emissions should differentiate good operations from bad operations when comparing like to like, and it should lead to improvements over the baseline. Ironically, our industry of technical professionals often relies on a unit of measurement which obscures differences and conflates economic drivers with operational excellence: methane intensity. Although often expressed as a percentage, this unit compares energy vented (without regard to flaring) against energy captured, including crude oil and condensate. Adding liquids to the denominator always drives the measurement value down without saying anything about the excellence of gas handling. It may measure the overall loss of energy to society, but it does not highlight shortcomings and does not help guide improvement. Of course, what matters most directly for the climate is the mass of methane wasted. At a small scale, the mass of methane in 1 Mcf of natural gas is calculated by multiplying 19.2 kg/Mcf by the methane concentration. Working in the other direction, 1 kg/hr of methane converts to about 1.5 Mcf/D of natural gas at an 84% methane content. Because methane is so much more potent in the short term than CO2, that 1.5 Mcf of natural gas has the same pollution effect as 4,500 lb of CO2. That is, pollution equivalent to the mass of a light-duty truck can be released each day from a single, small oil well. At scale, emissions are measured by the benign-sounding unit of “terragram,” each of which can cause as much climate deformation over the next 20 years as 187 billion lb of CO2. The upstream industry in Texas alone emits six or more of these colossus units every year.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 229970, “Reducing Water in Gas Wells With Autonomous Inflow Control Technology,” by Tarjei T. Larsen, SPE, InflowControl; Kåre Langaas, SPE, Aker BP; and Tilak C. Dhital, SPE, InflowControl, et al. The paper has not been peer-reviewed. _ An autonomous inflow-control technology for gas wells (gas AICT) has been developed to autonomously detect and choke unwanted water production while allowing gas and condensate production, improving both economic and sustainability measures of gas wells. To the authors’ knowledge, this is the first published flow performance test of an AICT that autonomously detects and chokes water while allowing gas and light condensate at downhole conditions. Introduction Autonomous inflow-control technology (AICT), which operates without the need for electronics or other means of communication or control, has demonstrated its market value by efficiently choking back unwanted fluids in oil wells. Currently, no proven autonomous technology exists for gas wells with potential water problems, although it has been discussed as a potential application for density-based AICT. Using the same principles as the proven AICT concept for oil wells, this paper presents the development and testing of a novel AICT for gas wells. Hereafter, the featured technology will be referred to as gas AICT, or simply “the valve.” The valve’s autonomy is regulated by a secondary flow path, known as the pilot flow, that runs parallel to the main flow within the valve. The pilot flow comprises two constant flow resistances in series: the turbulent flow element (TFE) and the laminar flow element (LFE), as illustrated in Fig. 1. Depending on the viscosity and density of the incoming fluid, the pilot branch generates an intermediate pressure level between the two flow elements (P2), which is used to control the choking level in the valve. This effect is entirely based on fluid mechanical principles and is fully reversible. The valve can be adjusted to match the specific fluid conditions in a well. Test Rigs and Conditions Initial valve development used a dedicated test loop with model fluids such as water and compressed air. The facility is designed to closely replicate downhole fluid conditions by precisely controlling pressure and temperature. Configured for both single- and multiphase testing, the open-loop rig includes fluid mixing before the test section, which simulates a screen joint to capture realistic inflow conditions. Advanced instrumentation—Coriolis flowmeters, temperature and pressure sensors, and high-accuracy differential pressure transmitters—ensures comprehensive monitoring of all relevant parameters. The fluid properties of the model fluids were compared with the density and viscosity of the actual fluids used in the multiphase flow loop tests. The results indicated that model fluids can be adjusted by varying pressure and temperature to closely replicate the properties of real fluids.
In recent years, several of the oil and gas industry’s largest companies have decided to expand their portfolios to become lithium producers. In the US, where ramping up lithium production is increasingly seen as a domestic supply-chain priority, they have collectively spent or committed hundreds of millions of dollars to extract the battery metal from oilfield brines using technologies and lessons borrowed from the upstream industry. It is, however, early days. Whether those projects can generate consistent returns, or achieve meaningful scale, remains a key question. According to Wambui Mutoru, the answer should come within the next 3 to 5 years. “These projects have to be proved, and they are not there yet. But they are on the cusp of becoming commercially viable,” she said. Mutoru is the asset manager for Equinor’s Southwest Arkansas lithium project, which is one of the most closely watched efforts to commercialize direct lithium extraction (DLE) from subsurface brine. The first phase of the development, a joint venture with Standard Lithium, was expected to reach a final investment decision (FID) last year but is now targeting approval by the end of this year. Mutoru’s comment about the future of this emerging business came while speaking on an expert panel at the recent Unconventional Resources Technology Conference (URTeC) in Houston where she outlined the Arkansas project, along with earlier-stage developments in Texas. Equinor’s focus is on the Smackover Formation, a long-spent oil field that is now attracting industry investment for its large and most highly concentrated lithium-brine deposits known in the US. The white powder Equinor and others are looking to produce is a key feedstock used to make cathodes, which in turn are used to make the lithium-ion batteries found in electric vehicles, smartphones, military drones, and in industrial-sized battery storage systems that support strained grid networks and renewable energy projects. The US government is eager to see these new lithium projects succeed to wean the country off its dependence on China, which holds a dominating position in the global critical-minerals market. A 2025 analysis by the Center for Climate and Security found that the US imports nearly three-quarters of its lithium-ion batteries from China. To reduce what it considers to be vulnerabilities in critical-mineral supply chains, the US government is providing financial support through a growing number of programs focused on domestic mining, processing, and battery manufacturing. In addition to a $225 million grant awarded by the US Department of Energy to support Equinor’s Arkansas project, the US Department of Defense announced in July that it plans to purchase up to $300 million of battery-grade lithium carbonate over the next 5 years. The first-of-its-kind government initiative is intended to establish a strategic stockpile of more than 16,000 metric tons.
As I write this column, the last of my year as SPE President, I have naturally been reflecting on what I want to leave you with in this final communication. I’m not quite at the end of my journey; in fact, I still have 3 months left until I hand the gavel over to the most capable C. Susan Howes, the 2027 President, at the Annual Technical Conference and Exhibition (ATCE) in Houston in October (and there is a lot to do in these 3 months). But given that this is my final direct correspondence, please allow me some reflection, a few updates on where the Society is, and some extremely important thank-yous. When asked to introduce myself this past year, I have frequently done so with the words “I have the honor and privilege to serve as the 2026 SPE President.” I have never meant a statement more in my life. Students frequently ask, “Did you always want to be SPE President,” and my answer has been a solid “No, it was never on my radar.” This generally leads to a great conversation about volunteerism and the opportunities that it can provide. But my point is that it truly has been an honor and a privilege to serve in this role, and I want to thank each of you for the opportunity to so. I hope that I have done right by the office. I have shaped my presidency around SPE’s tagline, “Solutions. People. Energy.” My discussions with students, members, industry, government leaders, and any group that asked me to speak focused on the increasing need for energy and how SPE is made up of the people that can provide the solutions for that energy in safe, secure, and sustainable ways. We are the Society of Petroleum Engineers, but we are so much more than petroleum alone, and SPE membership consists of far more than just engineers. SPE is made up of professionals whose experience will help solve the world’s energy needs in our core areas of oil and gas, low-carbon technologies such as CCUS and emissions reduction, and emerging areas such as geothermal, hydrogen, and critical minerals. I have never been more convinced that SPE is the catalyst and platform to bring together the technical knowledge needed to solve the energy trilemma. When I started my presidency, I asked in a LinkedIn post what people might want to hear about in these columns, and I want to thank all of you who responded, both then and since, with comments and requests. I have tried to address as many of these topics as possible, covering topics such as SPE’s value proposition, transparency in SPE operations and the Board of Directors, supporting young professionals and students, rethinking membership needs, artificial intelligence, sections’ best practices, and how we can all have conversations with the general public about the importance of our industry. I’m sorry if I couldn’t get to everything asked, but hopefully, all found value in at least some of these topics.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 232736, “From Readiness to Response: Assuring Emergency-Response Competence Through Scenario-Based Virtual Plant Training,” by Jerry Ashok Jacob, SPE, and Mahir Al Wahaibi, PDO. The paper has not been peer-reviewed. _ While most organizations maintain structured emergency-response-management systems and conduct periodic drills, these activities often emphasize procedural compliance and awareness rather than provide objective assurance of response capability under realistic operating conditions. This paper presents a competency-based, data-driven approach implemented by the operator to strengthen control-room emergency-response capability through a cloud-hosted, scenario-based virtual plant simulator. Introduction Control rooms represent the operational nerve center during emergencies. Their actions in the initial minutes of an event, such as acknowledging alarms, diagnosing conditions, initiating protective actions, escalating appropriately, and communicating clearly can influence outcomes decisively. Industry investigations repeatedly identify gaps between procedural knowledge and performance under pressure. Personnel may understand emergency procedures yet struggle to apply them fluently in real time. Despite this reality, emergency-response training in many organizations continues to rely heavily on classroom-based instruction, online learning modules, and periodic drills or tabletop exercises. While these methods are effective for communicating procedures, roles, and expectations, they often fall short in replicating the cognitive load, uncertainty, and time compression experienced during real emergencies. The operator’s reviews of exercise outcomes, audit findings, and learning from near-miss events highlighted recurring variability in the quality and consistency of control-room response under complex scenarios. Observed gaps included delays in alarm prioritization, inconsistent escalation decisions, incomplete or unclear communication, and challenges in managing concurrent demands during high-workload situations. These observations pointed not to a lack of commitment, but rather to the limitations of conventional training and exercising methods in assuring performance under realistic emergency conditions. Addressing these challenges requires a shift from training for readiness toward assurance of response capability. Scenario-based simulation offers a means of bridging this gap. Advances in process simulation, computing power, and cloud-based delivery enable replication of complex operational environments with high fidelity, allowing personnel to practice responding to rare but severe scenarios in a safe and controlled setting. When combined with structured performance analytics, such simulations can provide objective evidence of how individuals and teams perform. Background Competency Assurance in High-Risk Operations. Competency-based approaches emphasize demonstrated ability rather than training attendance. Competency-based training systems must integrate learning with validation, requiring individuals to demonstrate mastery under realistic conditions. In high-risk roles, this distinction is critical for credible assurance. Value of Competency and Value of Competency Assessment, demonstrating that uncertainty in human performance represents a quantifiable risk contributor, was introduced in 2014. Reducing this uncertainty through assessment functions as a preventive safety barrier.
_ Perforation tunnel geometry is critical to well deliverability. While downhole performance is traditionally predicted using commercial simulators based on API RP 19B Section I, the industry is increasingly adopting Section II testing data for more-reliable simulation output. Historically, modified Section II testing has been preferred for complex, nonroutine cases where Section I- and Section II-based standard simulations are not reliable. The operator manages numerous offshore cement-packer completions, which involve through-tubing perforations across multiple tubulars and cement sheaths. These are typically used for shallower targets where workovers are cost prohibitive. However, these jobs have encountered high failure rates (SPE 220664). Detailed investigations identified poor perforation performance as one of the primary causes for many such poor-performing wells. Note that the small-diameter charges, which are suitable for 3½-in. and smaller tubing sizes, must penetrate two layers of steel and cement, often resulting in high skin values and, in some cases, failing to establish reservoir communication. To address this, the operator in this case study, Petronas, conducted modified API RP 19B Section II tests at a specialized facility, replicating the specific downhole completion, reservoir properties, and shaped charge types. A total of 10 charges were evaluated across various tubular and reservoir settings. The resulting data provided significant insights, which have now been integrated into the operator’s gun-selection guidelines to improve future completion success. This pioneering work represents the first exhaustive study to evaluate shaped-charge performance within such complex downhole configurations. Background A majority of clastic reservoirs offshore Malaysia consist of interbedded sandstone and shale layers, often requiring dual-string completions. However, even with dual strings, the smaller, shallower reservoirs located above the production packer are often not completed initially. A full workover is rarely economic for these low-reserve zones, hence requiring a cement-packer technique to monetize these zones. This rigless approach uses coiled tubing to place a cement barrier in the annulus, allowing the zone to be perforated through the existing tubing. Over the past 15 years, the operator has performed many such jobs, but over 70% underperformed, including 30% of jobs that failed to produce at all (SPE 220664). A 2024 study by the operator identified three main causes: - Subsurface uncertainty - Operational execution - Perforation performance While new workflows have improved subsurface and execution reliability, achieving robust perforations in cement-packer completions remains a significant technical challenge. Efficient perforation tunnels must bypass the drilling-damaged zone (i.e., greater than 6 in.) and provide a sufficient entry hole to minimize pressure drops. While large tubing-conveyed perforating guns easily achieve long tunnel lengths in standard wells, cement-packer completions are limited by small internal diameters, requiring small charges that struggle to penetrate through multiple strings. Predicting perforation performance in such challenging configurations has been historically difficult (SPE 193964). Commercial simulators, which rely on API RP 19B Section I & Section II data, can be overly optimistic for such cases. Considering these limitations, modified API RP 19B Section II perforating tests on actual rock under downhole stress and with multiple tubular configurations were planned to obtain realistic data. This case study details how the operator used these specialized tests to optimize gun selection and improve success rates for multitubular cement-packer completions.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 36841, “Atlanta: Boosting the World’s Deepest Subsea Heavy Oil Field,” by Marcelo Paulino and Henrique S. Cerqueira, SPE, Brava Energia, and Christophe Vielliard, SPE, SLB OneSubsea, et al. The paper has not been peer-reviewed. Copyright 2026 Offshore Technology Conference. _ The Atlanta Field is the world’s deepest subsea heavy oil development, producing 14° API crude with a viscosity of 250 cp at reservoir conditions. This paper details the design and implementation of the subsea multiphase pump solution that was deployed in Atlanta, including system design for high-viscosity boosting and engineering solutions to maximize reuse of existing subsea and topside equipment. This was key to ensure reliable, cost‑effective production. Introduction The Atlanta development was divided into two phases: an early production system (EPS) that entered operation in May 2018, and a full‑field development (FFD) that began in December 2024. The EPS was developed with a satellite well architecture, wherein each production well is tied back directly to a floating production, storage, and offloading vessel (FPSO) through a dedicated flowline and riser plus a dedicated electrohydraulic umbilical and one service line. The subsea tree thus required limited functionality, because production control is performed through a topside choke and flowmetering is achieved during periodic well tests through a topside test separator. This enabled an integrated approach comprising operational insights from the EPS combined with vendor expertise. Phase 1 of the Atlanta FFD comprises six wells, four of which have produced during the EPS and two wells newly drilled for the FFD. Based on the operating experience from the EPS, which consisted of in-well electric submersible pumps (ESPs) and horizontal seabed ESPs as a backup, the artificial lift method chosen for the FFD was subsea multiphase pumps (MPPs). This change in boosting technology required creative engineering solutions to work within existing infrastructure constraints, reusing topside systems, umbilicals, and trees that lacked subsea choking and metering capabilities. This approach has a significant effect in reducing the cost and carbon footprint of subsea development. System Design The subsea pump-station design included the following adaptations to enable implementation within the constraints of the existing equipment: - Existing subsea horizontal trees without flowmetering and flow-control functionality - Existing 6-in. flexible production flowlines - Existing power and control umbilicals with 150 mm2 medium-voltage (MV) power cables and existing topside variable speed drives (VSDs) sized for ESPs Subsea Station Design. The pump-station functionality includes the following key features: - Multiphase flowmeter and production choke valve on each inlet - Commingling of production from two wells - Boosting of two wells with a single MPP - Flow splitting downstream of the pump, producing through up to two 6-in. flexible flowlines and risers This arrangement allows for the boosting of the commingled production from two wells by incorporating the flowmetering and flow‑ control functionality that is not available on the existing X‑trees.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 230576, “Joule-Thomson CO2 Cooling Under Different Regime Heating by Adjacent Layers,” by Christina Chesnokov, SPE, University of Adelaide; Rouhi Farajzadeh, SPE, Shell and Delft University of Technology; and Konstantin M. Fedorov, SPE, University of Tyumen, et al. The paper has not been peer-reviewed. _ Heat exchange with surrounding formations and Joule-Thomson (JT) cooling during CO2 injection into deep saline aquifers and depleted hydrocarbon reservoirs can lead to substantial declines in well injectivity. This work introduces an analytical model for nonisothermal CO2 injection that accounts for both JT cooling and interformation heat exchange, assuming that heat transfer begins upon arrival of the temperature front rather than the gas/water front, as adopted in earlier models. Introduction Temperature and pressure profiles provide important information about reservoir behavior during CO2 injection. Analytical models can provide such information more quickly with less computational expense. Additionally, the analytical models yield significantly faster inverse solvers, where iterative procedures include forward runs; thus, the inverse solutions for interpretation of laboratory corefloods and improved reservoir characterization from field data are more effective under analytical modeling. Analytical solutions usually regularize the ill-posed inverse problem, resulting in well-posed inverse solutions. In the current work, an exact solution for a CO2-injection problem is derived wherein the heat exchange with adjacent layers starts at the moment of arrival of the temperature front. The solution accounts for JT effects and nonsteady-state (NSS) heat exchange between the reservoir and semi-infinite adjacent formations. The derived explicit formula allows for the analysis of temporal evolution of temperature profiles. Unlike the steady-state (SS) model, the NSS model reveals no profile stabilization over time. The explicit formulae determine the temperature and pressure profiles at a fixed time, which calculate the path of radial dependency in CO2-/water-phase diagrams; the path connects the well and the reservoir. The analytical model allows for the express method to plot temperature/pressure paths and diagnose hydrate formation. A method of 1D model validation using heat balance in the reservoir while comparing with 2D heat transfer problem has been developed. The method exhibits significantly higher accuracy of the derived analytical model if compared with previous models. Governing equations for this study are provided in the complete paper, as is a section discussing validation of the analytical model by comparison with 2D heat conductivity. Sensitivity Study The sensitivity analysis is performed over parameter ranges selected to capture the physical impact of each dimensionless group. The JT number varies from 10–8 to 10–3, representing changes in the magnitude of JT cooling and its resulting influence on the temperature decline near the injection well. The heat-exchange number spans from 10–4 to 1, reflecting the contribution of NSS heat transfer from the surrounding formations. Across all parameter combinations, the deviation between the reservoir and boundary temperature profiles remains negligible, demonstrating the high accuracy and broad validity of the proposed heat-exchange formulation.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 36730, “Novel Subsea Production System for Shallow-Water Oilfield Development in China Bohai Bay,” by Tao Xie, SPE, State Key Laboratory of Offshore Oil and Gas Exploitation, CNOOC, and China University of Petroleum-Beijing, and Lei Zhang and Qilong Zhang, State Key Laboratory of Offshore Oil and Gas Exploitation and CNOOC, et al. The paper has not been peer-reviewed. Copyright 2026 Offshore Technology Conference. _ The operator’s Bohai oilfield is its largest crude oil production base, with an annual production of 265 MMbbl. However, because Bohai Bay is an internal bay with an average water depth of 60 ft, commonly used jacket platforms are prohibited. This paper presents an engineering solution tailored for shallow-water oilfield development in Bohai Bay, addressing the confluence of spatial constraints, marginal economics, and environmental conditions that have rendered such reserves stranded. Technological Challenges Dimensional Specifications of Subsea Equipment. Subsea production equipment is deployed in water depths spanning hundreds to thousands of meters. Conventional subsea trees require heavy-lift-vessel deployment. However, shallow-water environments mandate compact optimization of equipment geometry to mitigate collision risks with surface vessels constrained by operational draft limitations. Protective Structural Configuration. In deepwater environments, subsea production equipment typically employs minimalist overhead shielding to mitigate dropped-object hazards, thereby imposing modest structural requirements. Conversely, shallow-water operations mandate robust protective architectures for critical components, including subsea trees and manifolds, to withstand threats from anchor deployments and fishing-trawl interactions. More stringently, navigation-restricted zones enforce absolute prohibition of any seabed-protruding installations. Operational Environmental Constraints. In contrast to deepwater conditions, shallow-water marine environments exhibit substantially elevated suspended sediment concentrations, resulting in severely degraded optical visibility, meaning that remotely-operated-vehicle (ROV)-based operations are impracticable. However, diving operations constitute high-risk activities subject to stringent environmental limitations, thereby yielding substantially reduced operational efficiency. Wellhead Layouts. A distinguishing characteristic of shallow-water subsea lies in disparate spacing requirements arising from operational methodologies and installation assets. Use of jackup drilling platforms necessitates critical consideration of cantilever beam reach as a primary design parameter, supplementing equipment dimensions and manifold spacing criteria. The governing design principle thus becomes the minimization of platform jacking cycles and repositioning events, thereby optimizing operational efficiency while reducing installation costs.
_ Natural gas is increasingly playing a critical role in supporting global energy demand, particularly as large-scale artificial-intelligence (AI) infrastructures and digital-transformation initiatives continue to accelerate worldwide. These trends are driving the need for reliable, scalable, and lower-carbon energy resources, placing renewed focus on both unconventional and mature gas developments. Unconventional shale gas, in particular, continues to gain momentum, supported by ongoing improvements in stimulation design, geomechanics workflows, and efforts to reduce completion cost per foot while still maintaining fracture effectiveness and long-term well productivity. Across gas assets, operators are under increasing pressure to improve recovery, enhance production efficiency, and maximize the value of existing infrastructure under tighter technical and economic constraints. In shale developments, this translates to optimizing stage and cluster design and, more importantly, leveraging data-driven approaches to better understand stimulation effectiveness and variability along the wellbore. At the same time, digital technologies, particularly AI, machine learning, and industrial Internet of things (IIoT) platforms, are beginning to fundamentally change how wells are monitored and operated, moving from reactive workflows to more real-time and, in some cases, autonomous decision-making. For mature gas fields, the challenges are equally well-recognized. Rising water/gas ratios, liquid loading, and condensate dropout often lead to declining performance and shortened economic life if not managed properly. In practice, this places greater emphasis on both improved diagnostics and more cost-effective intervention strategies. In parallel, advances in molecular-scale physics and nanoconfined fluid modeling are helping close long-standing gaps between pore-scale behavior and field-scale performance, which is becoming increasingly important for improving confidence in production forecasting and recovery estimation. The papers highlighted here reflect these developments from multiple perspectives. The featured papers demonstrate how CO2-based fracturing can provide a lower-water and lower-carbon stimulation pathway, how edge-based IIoT systems can enable more-autonomous well optimization, and how smart inflow-control technologies are starting to move operational intelligence downhole. The additional recommended papers reinforce these themes by advancing physics-informed modeling, improving condensate-aware diagnostics, and showing practical, cost-effective ways to sustain production in mature gas wells. These contributions highlight a clear industry shift toward gas-production systems that are increasingly integrated, data-driven, and capable of delivering both improved recovery and more-efficient, lower-carbon operations. Summarized Papers in This August 2026 Issue URTeC 4213943 - Study of Sustainable Gas Exploitation Reveals Benefits of CO2 Fracturing by Carlos Felipe Silva-Escalante, SPE, National Autonomous University of Mexico (UNAM) and the Mexican Petroleum Institute (IMP), and Rodolfo G. Camacho-Velázquez, SPE, and Ana P. Gómora-Figueroa, IMP, et al. SPE 229390 - Industrial Internet of Things Application Deployed for Liquid Unloading in Gas Wells by Agustin Gambaretto, SPE, and Carl J. Kemp, SLB, and Rogelio M. Nunez, SPE, Consultant, et al. SPE 229970 - Autonomous Inflow-Control Technology Reduces Water in Gas Wells by Tarjei T. Larsen, SPE, InflowControl; Kåre Langaas, SPE, Aker BP; and Tilak C. Dhital, SPE, InflowControl, et al. Recommended Additional Reading at OnePetro: www.onepetro.org. SPE 231561 - Predicting Nanoconfined Natural Gas Density Using Machine Learning and a New Correlation by Almat Saginbayev, The Pennsylvania State University, et al. SPE 224869 - Performance Prediction of Multifractured Horizontal Wells in Shale Gas Condensate Reservoirs Using Flowback Rate Transient Analysis by Chia-Hsin Yang, The Pennsylvania State University, et al. SPE 228800 - Restoring Value in Gas Production Through Successful Deployment of Foam-Assisted-Lift Technology for Gas-Well Deliquification by Nnamdi Louis Abuah, Renaissance Africa Energy Company, et al.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 229379, “Enhancing Safety in Ultrasour Offshore Environments: A Comprehensive Emergency-Response System,” by Diego Espin Tobar, ADNOC. The paper has not been peer-reviewed. _ The complete paper presents the emergency-response system implemented on the operator’s Hail and Ghasha (H&G) project during the execution phase. It integrates digital personnel-on-board (POB) accounts, real-time marine activity, and electronic tracking for personnel working in an ultrasour offshore environment. In combination with adequate training for the parties involved in drilling and facilities construction simultaneous operations (SIMOPS), these components are crucial for the safety of personnel when a short response time is essential. Introduction The H&G megaproject is a development in the Abu Dhabi offshore area within the Marawah Marine Biosphere Reserve. Artificial islands have been constructed to serve as drilling centers and to install the facilities required for the stabilization and transport of the ultrasour production of the G&H fields to onshore facilities for further processing. To achieve program targets, the drilling and construction of facilities is performed under SIMOPS guidelines. While constructing and drilling in this environment, evacuation could become challenging. Each island executes between 10–20 activities daily, with several teams involved. The workforce includes approximately 140 personnel per drilling area and 300 for facilities construction per island. The complete paper discusses the implementation of an organized emergency-response program using a coordinated approach for the safe evacuation of all personnel. The paper provides a discussion of the operator’s protocols for emergency response and crisis management, including Levels describing the criticality of response (where Level 1 represents an immediate tactical response, while Level 3 implies a more strategic response taken at higher levels of the organization, typically requiring external support coordination) and Tiers that describe a given response to specifically address loss of containment (where Tier 1 implies localized needs, while Tier 3 implies a broad response exceeding the local capacity of the project, typically requiring external support coordination). Description and Application of Equipment and Processes Emergency-Response Organization. The organization has three levels of response, each with a structure that oversees the appropriate response at each Level or Tier. Thus, the response to any incident is a tiered one. Well-Control Event. It is imperative that the early detection of an abnormal condition is achieved. When available time is critical, the possibility of secondary events is increased because of the stress associated with making rapid decisions. This is particularly important for personnel new to the operation. For the H&G project, this application solution is based on three pillars: - Use of available technology to monitor personnel in high-risk areas continuously and to ensure that other personnel at other locations are properly accounted for - Coordination of marine operations with real-time position access of local and foreign vessels, also distinguishing those vessels that are operator-run, to address the extensive range of zones that could potentially be affected by toxic dispersion - Continuous training of personnel on mustering and evacuation equipment and toxic gas refuges
_ The upstream oil and gas sector has entered a new phase of automation. The robots are here, and they’re here to stay. While the industry’s digital transformation has centered mostly on supervisory control and data acquisition, distributed control systems, and predictive analytics, robotics has emerged as a physical extension of these digital capabilities, enabling inspection and intervention that had depended on manual labor. “They can go into places that you really wouldn’t want to send people,” said Ian Peerless, the founder and director of ExRobotics. Far from the humanoid machines popularized by Hollywood, the new generation of industrial robotics includes drones, autonomous underwater vehicles (AUVs), and pipe-crawling inspection systems, all boosted by the inclusion of artificial intelligence (AI). “Robots exist and can be used now. They’re not science fiction,” Peerless said. “They are being used in the real world.” Amid the digital transformation in the energy sector, robotics has become a fast-growing investment. Operators are increasingly deploying machines that can withstand hazardous environments while collecting massive amounts of real-time operational data. The result is a safer, more efficient, and increasingly autonomous upstream industry. Historically, upstream operations depended heavily on manual inspections and labor-intensive maintenance, work that carries inherent risk. Robotic systems are changing that equation. Inspections and Beyond Modern inspection robots equipped with thermal imaging and light detection and ranging (LiDAR) cameras can perform inspections without exposing personnel to hazardous environments. “Overall, LiDAR provides highly accurate structural and 3D information of the surroundings, thereby enabling superior environmental perception and assessment,” said Ayon Dey, senior application engineer at MathWorks. Rather than shutting down production to inspect a storage tank or pressure vessel, operators can now deploy robotic crawlers or flying drones capable of collecting detailed inspection data while assets remain in service. This reduces downtime while significantly improving worker safety. The Abu Dhabi National Oil Company (ADNOC) recently deployed a heavy-duty robot at its Taweelah gas compression plant to perform routine inspections in hazardous environments. The company said it is also developing another heavy lifter, the Autonomous Robot for Gas and Oil Sites (ARGOS), which will carry several sensors, including 3D LiDAR and thermal cameras. It is designed to move beyond inspection to physical interaction with industrial equipment. ADNOC said ARGOS “will be strong enough to lift heavy equipment and precise enough to turn valves and operate gauges, tasks that would normally require people to enter high-risk areas.” ARGOS is being developed as part of a joint industry project with Equinor, Petrobras, and TotalEnergies, along with the Net Zero Technology Center, Saft, and Taurob. Unmanned aerial vehicles (UAVs), commonly known as drones, have been widely adopted across upstream operations. Initially used primarily for aerial photography, drones now perform a variety of missions, using a variety of mounted sensors. Thermal imaging cameras enable drones to identify overheating equipment before failures occur, and optical gas imaging sensors detect methane leaks invisible to the naked eye.
_ Our industry invests significant effort in preventing accidents. Despite continuous improvements in safety performance, however, incidents still occur. This illustrates that prevention alone is not sufficient to manage risk effectively. We must also be prepared to respond effectively when incidents do occur. Crisis and continuity management is fundamentally about preparedness. Its purpose is to ensure that an organization clearly understands what actions to take during an incident rather than having to define roles and processes under pressure. Effective crisis management begins with understanding risks, developing robust emergency-response plans, and building response capability through workforce training and exercises. When an incident occurs, the workforce should be fully prepared, equipped, and empowered to act. Business continuity is a critical component of crisis management. Organizations need to be able to sustain essential operations while protecting people, assets, and value. Depending on the scenario, this may include maintaining supply-chain, workforce, workplace, compliance, and digital continuity, managing stakeholder relationships, conducting crisis communications, and addressing reputational impacts. This capability is often described as organizational resilience: the ability not only to withstand disruption but also to adapt and recover quickly. Recent industry developments demonstrate significant progress in crisis and continuity management. Organizations increasingly plan for extreme-weather events, integrate emergency response into risk-management frameworks, and adopt bowtie methodologies that incorporate emergency-response elements. At the same time, advances in digital technologies—such as geographic-information-system based visualization, real-time personnel tracking (used appropriately), weather overlays, artificial-intelligence-driven predictive modeling, and adaptive simulation—are strengthening preparedness, improving decision-making, and reducing response and mobilization times. Modern multiuser, scenario-based simulators enhance training and exercises by enabling objective assessment of response effectiveness. In parallel, care-for-people programs are becoming more widespread, providing timely and compassionate support to employees and families affected by incidents. Crisis and continuity management supports mitigation barriers for major accident risks. Maintaining this capability—and strengthening it—therefore is core to protecting our people, safeguarding value, and sustaining global confidence in the energy industry. Summarized Papers in This August 2026 Issue SPE 229379 - Emergency-Response System Enhances Safety in Ultrasour Offshore Environments by Diego Espin Tobar, ADNOC SPE 232736 - Scenario-Based Virtual Plant Training Assures Emergency-Response Competence by Jerry Ashok Jacob, SPE, and Mahir Al Wahaibi, PDO SPE 229328 - AI, Digital Tools Can Operationalize Readiness for Crisis and Emergency Management by Ashish Chandrashekhar Kulkarni and Ashwina Das Kulkarni, The Bell Group Recommended Additional Reading at OnePetro: www.onepetro.org. SPE 230927 - Barrier-Based Environmental Risk Management of Accidents Leading to Major Oil Spills by Adriana Suarez, KAK-Lamor, et al. SPE 228069 - Infrastructure Resiliency and the United Nations Sustainable Development Goals: An Integrative Approach To Mitigating the Impact of Disasters by Hitesh Mohan, Cyberworx Energy, et al. SPE 229243 - Care Link for Supporting Families by F.O. Al Mehairbi, ADNOC, et al.
